Energy is one of the hot topics today. The industry trend is moving toward switching from traditional fossil fuel sources to renewable sources that are cleaner and becoming more competitive in the global market. If you intend to build a coal plant to generate electricity, you would struggle to find the land, capital funds, and expertise and patience to build it. In contrast, electricity from solar is available at different scales with multiple incentives and simple and fast implementation processes.

This lesson will take you through a journey (in both time and space domains) to learn what you need in order to grasp main topics in the solar industry so that you can lead the solar department with confidence. Furthermore, you may be interested in starting your own solar business. Lesson 1 is the right place to learn the basics.

Learning Outcomes

At the successful completion of this lesson, students should be able to:

• Recognize main types of SECS and their applications for electricity generation including PV, CPV and STE/CSP.
• Identify PV market indicators and main factors driving the development of the PV technology.
• Categorize solar PV system as residential, non-residential and utility scale grid-tied PV systems and their share in the PV market.
• Discuss PV system configurations (grid-connected, stand-alone, bimodal, and hybrid) and their components and various types of energy sources that can be coupled with PV systems.
• Explain the roles of various segments of the PV industry and how they interact with one another.

Sun is an abundant source of energy that is capable of supplying sustainable energy to all of humanity. After you have familiarized yourself with the material in the "Review" section of this lesson, you can see that Solar energy can be used for different types of applications that range from a basic solar cooker to photovoltaic technology. A summary of the most common usages of solar energy is shown in Figure 1.1.

Solar Energy Technologies/usages

There are various applications of solar energy conversion systems. The first is seen in conjunction with photovoltaic technology and directly converts solar radiation into electricity. The second converts solar energy into heat for such applications as solar hot water, passive solar heating, solar space heating or cooling, and solar cooking. Finally, there is the conversion of heat into electricity, or solar thermal electricity, which utilizes concentrating solar power (CSP) devices such as reflectors and concentrators.

Since solar energy seems to be a valid option for most of our everyday needs, why don’t we use solar to electrify the entire world?

Although solar energy is abundant, a list of historical factors played a huge role in the development and implementation of solar conversion systems that are not the focus of this class. However, recently there has been exponential growth in research, development, and implementation of different SECS worldwide.

As can be seen from Figure 1.1, Photovoltaic (PV) and Solar Thermal Electricity (STE) are the main technologies that are widely used to generate electricity from the sun and which utilize receivers and concentrators, as discussed earlier in other classes found via the Review page in this course. STE uses Concentrating Solar Power technologies (CSP) to focus direct light and convert it into thermal energy and then finally convert it to a usable Electrical Energy, while Solar Photovoltaic systems (PV) directly convert solar radiation (both direct and indirect) into electricity. Finally, there is a new trend in PV utilizing lenses to concentrate solar radiation for higher efficiency while using more advanced PV technology to convert sunlight into electricity. That technology is referred to as Concentrating Photovoltaic, or CPV for short.

Let's return to the question, "Is solar energy considered a valid option for electricity generation?"

In order for us to answer that question, we need to take a look at some data gathered by the International Energy Agency (IEA). In their Photovoltaic roadmap and Solar Thermal Electricity roadmap in 2014 (links available under "Required Readings" on the first page of the lesson), IEA discussed the potential for electricity generation from solar energy in large scale. Recently there has been a significant increase in the share of solar electricity installations that contribute to the global electricity grid. Some countries are more progressive and others are trying to follow the lead. For the purpose of this class, we will start with some facts about one of the fast growing and emerging solar markets in the world, which is the US market, and the factors that affect the development of such new technology in the energy market. But why are we saying solar in the U.S. is a growing market?

Observing the added capacity percentage of different energy sources within the period from 2010 to 2024 in the US, we can see that Solar is gaining more of a percentage share (an increase from 4 percent in 2010 to 66 percent in 2024) when compared to traditional fossil fuel sources, such as coal or natural gas, as illustrated in Figure 1.2. The promising news about renewable energy and Solar in particular is that the majority of the recently added electricity comes from renewable resources, including Solar. Recently, most utilities are retiring their coal plants and more are interested in Solar power. As we can tell That said, the next few years will witness more solar installations, and the target expected by the IEA by 2050 can be achieved.

Readers are encouraged to read more about the market insights from the SEIA Research website linked below the figure. 

Tracking the recorded PV installation, the International Energy Agency (IEA) found that by 2014, the world had added PV with total global capacity that overtook 150 (GW). That is enough to power the entire country of Germany. To understand the bigger, global picture, it is enough to power over 50 developing countries the size of Costa Rica. More recently, the global installed capacity of PV solar exceeded 609 GW according to IEA 2019 solar energy report and the US. Let's move to the United States, according to an SEIA research market insight report in 2024, the total PV installations surpassed 248 GW. According to the "IEA PV roadmap published in 2014," by 2050, PV will provide 16 percent of the world’s global electricity production. We believe all these predictions will happen much sooner.

For most of us, the reasons behind the exponential growth in the PV capacity in the U.S. in the last decade is still not clear. In order for us to understand the reasons behind this fast implementation, we need to track the PV technology prices and investigate how the market is affected by price changes.

If we consider the time period between 1976 and 2035 on a logarithmic scale and draw the PV module prices versus the cumulative manufactured capacity in (GW), we can see that PV module prices have dropped significantly since the early 1970s. As illustrated in Figure 1.3, it can be seen that the price has dropped from close to 100 dollars per watt of handmade technology in the 1970s to less than 50 cents per watt these days. SEIA market insight report has the most up-to-date module and cell prices. Readers are encouraged to visit their website for more information.

Another factor that plays a large role in PV module prices is installation capacity. Observing the relationship between blended average PV price per watt and PV installed capacity in (MW) within the period between 2011 and 2024, we can see (in Figure 1.4) that PV prices are directly influenced by growth in installation capacity so that the installation cost dropped more than 70% since 2010. According to the IEA PV roadmap published in 2014, PV LCOE reached a level below retail electricity in some countries while it is approaching grid parity, and that makes perfect economical sense for investors.

Figure 1.3: Past module prices and projection to 2035 based on learning curve.

Credit: Based on IEA data from Technology Roadmap: Solar Photovoltaic Energy 2014 Edition, International Energy Agency (IEA) OECD/IEA ©2014, Technology Roadmap Solar Photovolaic Energy. License: IEA.

Figure 1.4: PV price per watt and PV installation capacity

Credit: SEIA Research U.S. Solar Market Insight Report

As we can all see, the global inflation and supply chain constraints caused prices volatility especially in the second half of last decade leading to price increase and uncertainty!

In addition to the technology being more affordable, in most countries, the incentives programs have a huge impact on pushing installations forward, which is thoroughly discussed in EME 810's Lesson 9 content -- Energy Portfolio Standards and Government Incentives. To highlight some initiatives as an example, the U.S. Department of Energy's "SunShot Initiative", launched in 2011, supports innovation in manufacturing to help attract new facilities to reduce system cost. In order to make solar electricity cost-competitive, the soft cost needs to reach the targets of the Sunshot Initiative by 2020: USD 0.65/W for residential systems and USD 0.44/W for commercial systems. When all system costs are reduced, SunShot's cost target was put to reach LCOE of $0.06 per kilowatt-hour for utility scale PV, and by the end of 2017, the goal was achieved. The U.S. Department of Energy Solar Energy Technologies Office (SETO) is working toward a levelized cost of $0.02 per kilowatt-hour (kWh) for utility-scale solar photovoltaics, $0.04 per kWh for commercial PV systems, and $0.05 per kWh for residential rooftop PV systems by 2030.

After we established that the predominant solar energy technology is mainly Photovoltaic (PV) technology, it is important to understand how PV installations are classified. PV can be classified into three main segments:

• Residential
• Non-residential (including Commercial and Community Shared solar)
• Utility scale

Each of these sectors has its targeted market, but it helps to understand the market share of each sector. If we track annual PV installation capacity for different solar PV sectors from 2010 to 2024, we can see, in Figure 1.5, that the PV utility scale sector has the biggest share in the PV market since 2012 and is second when it comes to the residential PV sector. We can see that the non-residential sector has leveled for several years, while both residential and utility scale installation demands are soaring.

Figure 1.5: US PV Installations by Segment, 2014-2030

Credit: SEIA Research US Solar Market Insight Report

Moving to the PV installations by state, you can see that some northeast states are big on Residential and Commercial (non-utility) PV while California, Texas, and Florida, for example, have mainly Utility scale PV installations. The question remains: why? Is utility scale solar better than residential?

If we compare turnkey-installed PV cost per watt for different market sectors, we can see that utility scale PV installations have the lowest cost. Due to economy of scale, non-residential installations are second lowest. It can also be seen that residential installations have the highest soft costs when compared to the rest of the sectors shown in Figure 1.6. This explains why utility scale PV is more attractive to utilities and investors; we can see that the installed cost for utility scale PV is much lower than both residential and non-residential systems.

Aside from the main PV segments we saw at the beginning of this section, where solar power has mostly been available to utilities as utility scale solar plants or to individual home and business owners as rooftop systems for both residential and non-residential sectors, there is a new stream that supports the development of shared solar in communities where homeowners, who are interested in solar but cannot afford it or don’t have space on the roof for PV installation, can share solar with their neighbors and communities to allow everyone to be part of the solar movement.

Shared solar usually consists of a small-scale (few hundreds of kW to few thousands of kW) solar installation that allows multiple individuals to divide their generated power and that allows customers to share ownership of a community-scale PV array, subscribe to the power output of such an array, or both. Of course, there is limitation to subscription systems because electricity markets are regulated in some places.

As for all other PV types, policies and incentive programs are the main market drivers for shared solar.

Market Status (source: NREL page for community solar)

As of December 2024:

• Community solar projects are located in 44 states, including the District of Columbia.
• Community solar projects represent greater than 10 GW-AC of total installed capacity.
• About 75% of the total market is concentrated in the top four states: Florida (3,873 MW-AC), New York (2,110 MW-AC), Massachusetts (1,049 MW-AC), and Minnesota (939 MW-AC).

So after this brief introduction about PV technology and application, it is about time to dig deeper into the components that form this PV system and learn more about the types of systems that can serve various applications.

We can easily observe that not all PV systems are alike in terms of system components, size, and type of application. For example, solar water pumping for rural application, where there is no access to an electricity grid, utilizes components that are slightly different from rooftop solar systems for residential application, where a grid already exists.

So what are these main types and components that form the PV system?

In Figure1. 7 we can see different types of PV configurations that work for both Grid-connected and Stand-alone applications. We can see that the main difference between these two main types is utility grid availability.

Stand-alone PV systems:

All stand-alone (AKA off-grid) systems work in general without the utility grid, as shown in Figure 1.8. It can be seen that we expect a perfect match between the supply and demand, or in other words between PV system size and load requirement. When this match is done perfectly for a single load, the PV system in this case can be called a "Direct-Coupled PV System," and very minimal components are needed without the need for storage systems.

Another type of stand-alone requires a storage system to allow excess energy to be stored when it is not needed by the load and can later be drawn when the sun is not available. This type can be connected directly to DC loads or to AC loads through an additional power conditioning component, or “Inverter,” as we will learn later.

The other common type of stand-alone system is the "Hybrid PV System," as illustrated in Figure 1.9, which uses other energy sources in parallel to the PV array to supply loads. These energy sources can be Wind Turbines, Hydro Turbines, Diesel Generators, or Fuel cells. Hybrid PV Systems can also use Batteries for energy storage.

Grid-Connected system:

This type of configuration is the most common type for applications where clients want to save energy on their utility bills and while the utility grid exists for use when the PV array is not generating any energy. The PV array can be directly coupled to the grid without any storage system and is called “Utility-Interactive PV System or Grid-Tied PV System,” as illustrated in Figure 1.10. Alternatively, it can store excess energy into battery banks for later use, and in this case, it is called a “Bimodal PV System or Battery Backup PV System,” as shown in Figure 1.11.

The following short video walks us through the basics of PV and how it works and shows an example of a grid-connected PV system and the components needed.

Video: How Solar Works (0:58)

Another example of a 100 percent off-grid system installed on an isolated island is illustrated in the following video.

Video: How Tokelau Switched to Solar Energy (4:21)

In order for each of the PV system types we discussed in this section to function and deliver usable energy to clients, a number of components are needed to allow energy to be generated, conditioned, stored, and transferred to end users. So what are these components, according to the classification: generation, storage, and conditioning?

Generation:

The main and only component in the PV system that converts solar radiation into electricity is the "Cell" or "Module." We will learn more about that in Lesson 2.

Storage:

Not all energy the PV system generates is used right away, especially when we talk about off-grid systems. So in order for us to maximize the usage of the system, we need some devices to store the energy for later uses, and that is easily done using "Storage devices such as Batteries." We will explain more in Lesson 3.

Conditioning:

Solar PV generates DC electricity, which is not the common form to be used for home appliances and the utility grid in general, which usually uses AC electricity. So in order for us to be able to connect the PV system to the grid we need to change the DC to AC, and that is done using a power conditioning units AKA "inverter." We will discuss this in more detail in Lesson 4.

In order for the PV system to be brought to the client as a final product, dozens of PV industry sectors should work together to achieve this goal. The PV industry is composed of several levels of businesses and organizations. The first level involves manufacturers that usually donors deal directly with clients, but they make the main parts of the PV system, such as Modules, Inverters, Batteries, Balance of Systems. The second level is the medium between the client and the manufacturer, which is referred to as an integrator. The integrator offers services such as engineering design, permitting requirements preparations, installations, monitoring, and operation and maintenance (O&M). Integrators work closely with architects, builders, contractors, and utilities to meet all standards, codes, and regulations. The third level is the installers, who can be either independent entities such as electrical contractors who specialize in PV installations or can also be directly hired by the integrators. Installers are the most visible members of the PV industry, as they are the ones who ensure safe and quality installations.

Finally, there are numerous not-for-profit organizations that advocate their mission to serve and promote the PV industry, such as research institutes, marketers, installer training institutes, and standards development.

With greater market share comes demand for a qualified workforce to help achieve goals, and therefore the U.S. solar job market has soared in the past few years and currently there are around 260,000 people who are qualified or are in training as solar professionals (SEIA press).

According to the International Renewable Energy Agency (IRENA) Annual Review 2024 [shown below and as Figure 1.12 in the recommended reading for this lesson], by the end of year 2024, there were 16.2 million workers in the field of renewable energy worldwide. The PV industry in on the top of the list with the highest number of employees, accounting for nearly 7.1 million workers worldwide who are involved in PV solar-related jobs. On the same list, the CSP workers were only around 118,000 workers worldwide. This proves the fact that solar PV is the still the predominant renewable energy technology, and the need for more qualified practitioner is strongly needed.

In Lesson 2 we will use simulation software. This exercise requires you to download NREL's System Advisor Model (SAM) and the NREL PVWatt tool for use in the next lesson. This Exercise is ungraded, but it is essential for you to become familiar with these tools to better follow along with the class topics and Lesson Activities.

Let's go back to our scenario from the beginning of this lesson. You go to the next general meeting for the new solar department lead position. Now that you are loaded with the right information about the solar market, you can easily suggest investing in the PV technology. Furthermore, you realize that depending on the market segment and the size of the utility company you work for, you may suggest considering Utility scale PV systems for large electricity generation. In addition, you are now fully equipped with knowledge and can suggest the industry sector your company can represent within the solar industry.

Even if you decide to start a small solar business, you may consider Residential or Non-residential PV installations or both. Having a design and installation team can help you tap into the right solar industry sector you wish to be part of.

The next lesson will introduce the building block to any PV system, which is the PV "module." We will cover a variety of topics from basic characteristics to factors that affect the performance of PV modules, and finally, the required tests and standards for approved PV module installations.

In this lesson, we will discuss topics that lead to answers to all the questions in the scenario above. We will enlighten PV designers to look for the best modules that fit their application.

Learning Outcomes

At the successful completion of this lesson, students should be able to:

• Identify PV terminology and key electrical characteristics of PV modules at various operating conditions.
• Interpret a PV module manufacturer's data specification sheet and key parameters for various test standards.
• Discuss factors affecting performance of PV devices and the impact of changing irradiance and temperature.
• Apply strategies to optimize production of PV systems using industrial tools such as Solar Advisor Model (SAM) and PVwatt software to simulate PV output.
• Identify shading effects on PV array and series and parallel connection of modules.

We recall from previous classes that in order for us to understand Photovoltaic technology, we need to understand its main properties at the cell level such as the Photovoltaic effect, the P-N Junction to simply convert light into electricity, and how PV performance is measured in terms of current and voltage (I-V) curve, Filling factor (FF), and efficiency.

In this section, we will revisit some of these performance characteristics, such as I-V, P-V, FF, and efficiency, at the module level.

Before we start, let us define some of the commonly used terminologies in solar at the system level.

Modules and Panels

In this lesson, we will focus on the centerpiece of any PV system, which is the PV module. Solar modules or solar panels are two commonly used terms in the solar industry. Many people use these terms interchangeably, but there is a small difference that should be discussed. A module is the series and/or parallel interconnection of solar cells in a circuit, on a panel. The term solar panel is more exclusive to the rectangular, rigid packaging frame. Most standard crystalline modules can be called solar panels. In general, all solar panels are solar modules, but the opposite is not always true. For example, a thin-film silicon solar cell that is packaged as a flexible laminate is a solar module, but it is not a panel.

Array

Another important term to consider is PV array. When modules are installed as a system, that layout is called an array. Arrays can also be connected in parallel or in series similar to modules and cells.

A Module's Main Parameters

Since a solar module is nothing but an interconnection of solar cells, similar parameters are defined such as module Efficiency, module Fill Factor, Maximum Power Point (MPP) Voltage and Current (Vmpp) and (Impp), Open Circuit Voltage (Voc), and Short Circuit Current (Isc).

Voltage and Current of a Module

As we can see, the total voltage of a PV module is nothing but a scale version of the cell voltage (multiplied by a number of cells connected in series), while the total current is a scaled version of the cell current (multiplied by a number of strings of cells connected in parallel).

Module I-V characteristics

Previously, we learned about the I-V (J-V in some references, “J” being the current density, current per unit area) curve at the solar cell level. However, in PV systems, we are more interested in the total current and voltage that the PV module can generate, so we define the Module I-V curve, or the current-voltage curve, as it is illustrated in Figure 2.1. The curve indicates the voltage and current at different operating conditions. For example, the highest current corresponds to the short-circuit condition (when a PV module's positive and negative terminals are connected without load, causing very high current to pass), while the highest voltage occurs at open-circuit condition (when a PV module's positive and negative terminals are not connected to any load, causing no current to pass). If we observe the current and voltage starting at the open-circuit condition (where voltage is maximum and current is zero), and as we increase the load of the circuit, the current starts increasing and the voltage falls down until it reaches the value of zero at short-circuit condition (where the current is maximum). The knee of the curve indicates the operating condition in which current and voltage result in maximum power point (MPP). The voltage and current values at MPP are referred to as "Vmpp” and “Impp,” respectively.

Figure 2.1: The I-V curve of PV module

Credit: Mohamed Amer Chaaban

Module P-V characteristics

Another way to visualize the I-V curve is to convert it to a relationship between power and voltage. In this case, we can call it (P-V) curve of PV module, as shown in Figure 2.2. Similar to an I-V curve, the highest voltage occurs at the open-circuit condition and the current is zero and the short-circuit voltage is zero at the origin of the curve, but the current is maximum. Since the power is nothing but the voltage times the current (P=VxI), the power at both the short-circuit and open-circuit conditions is equal to zero since either voltage or current equals zero at each of these points. If we observe the power and voltage starting at the open-circuit condition (where the voltage is maximum and power is zero), and as we increase the load of the circuit, the power starts increasing and the voltage falls down until it reaches the value at MPP (where power is maximum). If we increase the load further, the voltage keeps falling down. However, the power will decrease as well until it reaches the value of zero at short-circuit condition (where the both voltage and power are zero). It can be seen that it is much easier to find the peak power on the P-V curve in comparison to the I-V curve, as it resembles a hump. The power at MPP is referred to as "Pmpp."

Figure 2.2: the P-V curve of PV module

Credit: Mohamed Amer Chaaban

Other Parameters of PV Modules

But what about the other parameters, such as efficiency and fill factor of a solar module? 
Do they increase, decrease or stay the same in comparison to the cell values?
 Ideally, all cells have similar characteristics with no mismatching losses; in this case, we expect the efficiency and fill factor at both of the module and cell levels to be the same.
 But this is not true in practice due to various factors that play a role when cells are interconnected, such as the series resistance caused by contacts soldering between cells. Furthermore, there might be a small manufacturer mismatch in the characteristics of the cells that are interconnected. In this case, the cell with the lowest current in the string in series dictates the current of the module. Similarly, the cell with the lowest voltage in parallel dictates the voltage of the module. This mismatch in cells can be a result of the non-homogeneity of the cells due to mass production.

Another main cause of mismatch occurs when a module is:

1. partly shaded, or
2. has non-uniform irradiance, or
3. has non-uniform heating on the cell level.


Therefore, each module in practice performs a little different compared to the expected performance of the ideally matched solar cells.



So how does this affect the parameters of the Module?

Most module manufacturers list in their datasheets the difference between module and cell level efficiency. For example, the datasheet of the Sanyo HIT-N240SE10 module states that cell efficiency is 21.6% and that module level efficiency is around 19%.

Cells layout in a PV Module

PV modules consist of cells, which are sensitive to solar radiation. In order for us to maximize the solar utility of this module when it is installed, we should understand how these cells are wired inside the PV module. Furthermore, it is important to define the factors that contribute to the performance of these cells.

This section will discuss how shading affects the output of solar modules and will also discuss the available solutions to overcome that issue. First of all, let’s start with the wiring of PV cells inside a PV module as shown in Figure 2.3, where the cell connections for a typical commercial 250W panel with 60 cells is illustrated. The PV cells are divided into three groups, and each group of 20 cells has a dedicated bypass diode (illustrated with the triangular shape on top of each group that will be discussed in the next section). When all PV cells are wired in series (the positive of the first cell connects to the negative of the second cell) and then encapsulated within a frame, it forms a PV module with two terminals that are referred to as the positive and negative terminals.

Figure 2.3: Cells wiring with bypass diodes on PV module

Credit: Mohamed Amer Chaaban

As we expect, all cells are wired in series to get to the desired voltage level of the PV module. However, this series connection raises an issue that when one cell is not generating power due to shading, for example, it will not be able to generate the same amount of current that other similar (unshaded) cells generate. And due to series connection, the total current of the module will be dictated by the weakest cell (shaded). As a result, that will create power loss due to current restriction. In addition, when the higher current generated by unshaded cells tries to pass through the shaded cell, the shaded cell might act like a load and the temperature will increase, and that might lead to a phenomenon known as “hot spot.” Hot spots cause physical damage within the module, like melted cells, cracked glass, or changing characteristics of cells.

Bypass Diode

With this said, there should be a solution to protect the modules and cells from the hot spot and also improve the extracted output power when cells are shaded. This can be resolved by adding a “bypass diode” across the shaded cell. In this case, the diode will pass the current and no current will go through the shaded cell. This leads to another important question, how do manufacturers add bypass diodes? Do they add to each cell within the module?

A bypass diode to each cell is not an economical question, and due to the layout of the cells on the panel, the optimal way the bypass diodes are added is as illustrated in Figure 2.4. We can see that the module is divided into groups of cells and each group will have a single bypass diode. In our particular example, we have 3 bypass diodes for the 60 cells module so each 20 series connected cells are protected by one bypass diode.

Is there a difference when cells are shaded with different patterns across the module? Yes - there is a significant impact of the shading pattern, and that is due to the way the bypass diodes are physically connected. Let’s discuss this example: What if only one cell is shaded, as shown in Figure 2.4?

Figure 2.4: One shaded cell and bypass diodes on PV module

Credit: Mohamed Amer Chaaban

In this case, the string with the shaded cell will not contribute to the total voltage and power of the module; we can estimate that the module might lose 30% of its voltage and power.

Reflection

How does one partly shaded row that shades an equal number of cells from each group affect the voltage of the module?

Figure 2.5: One shaded row of cells and bypass diodes on PV module

Credit: Mohamed Amer Chaaban

Click for answer...

ANSWER: In this case, the module will not lose voltage since the groups are equal in voltage and none of the bypass diodes will be activated. However, the current flowing through each group will be limited to the lowest current of the weakest cell. The shading pattern is shown in Figure 2.5.

Connections at the Module Level

Now that we have covered the basics of series and parallel connections of PV cells when we discussed the I-V characteristics, it is time to understand the bigger picture by investigating the connections at the module level. In this lesson, we will define a new commonly used term in the solar PV industry, which is the PV string. We will look at how the total voltage and current characteristics change as a result of these formations. In addition, we will discuss how characteristics are affected by the pattern of shading applied to the PV system.

A PV string is formed when multiple modules are connected in series. In this case, the string I-V curve is the same as the individual I-V curve of each module, but it is scaled in voltage by the number of modules connected in series while the current stays similar to the individual module’s current. PV strings can be as small as one module, or can have multiple numbers of modules in series. When strings are combined in parallel form, that leads to a scaled current by the number of strings, while voltage equals the individual string’s voltage. A PV system can consist of a single string or multiple strings, depending on the size of the system.

Blocking Diode

Moving to the shading effect on PV systems, similar to the modules level effect, when one module is shaded within the string, the entire string can lose power by the restriction of current flowing through the string. As the modules solution suggested, the bypass diodes will clear the shading effect by bypassing the shaded module. As a result, that will have a voltage drop impact on the total string voltage that may interfere with the other parallel strings within the system, since equivalent array voltage is dictated by the string with the lowest voltage.

For that reason, some designers choose to add a blocking diode to prevent the current from flowing back to the weak string, and that will eliminate fire hazards as well. Figure 2.6 illustrates the bypass and blocking diodes at the system level and how the total voltage is affected by it. We can see nine PV modules wired to form a PV array. Each group of three modules is connected in series to form a string, for a total of three strings. Each module uses a dedicated bypass diode that only actives when the module is shaded. For example, in Figure 2.6, there is a green colored triangular shape that represents the bypass diode. That is associated with the shaded module illustrated in dark blue in the bottom left corner of Figure 2.6. We can also see red colored triangles that represent the blocking diodes in series with each group to protect the entire string. Assuming each module generates 1V, the unshaded strings generate a total of 3V while the shaded string can only generate 2V (due to the bypass diode effect ). In this case, the blocking diode will protect the shaded string from draining current from the unshaded strings.

Figure 2.6: The effect of bypass and blocking diodes with one module shaded in a PV array

Credit: Mohamed Amer Chaaban

Design Recommendations

Finally, as PV designers, we should avoid all types of shading that includes:

1. Inter-row shading: as discussed in EME 810 (Lesson 2: Applying Shading to a Solar Chart).
2. Soft shading: that can be caused by Trees and moving objects. A solution to that is Tree trimming.
3. Hard shading: such as chimneys or pipes, and this should be completely avoided for optimum design.

Performance at PV System Level

Improving module efficiency is only one way to extract more energy from the module. However, what matters ultimately is the energy yield of the PV at the system level.
 So the question is: What can we do at the system level to increase the yield of PV systems?

Besides the semiconductor material used for PV modules, there are only two parts that play roles in improving the performance of a PV system: electrical and mechanical. The electrical part is responsible for tracking the maximum PowerPoint (MPP), which is a tool to ensure that the PV module operates at the MPP on its I-V curve under a given set of irradiance and temperature. This unit is not something a designer can optimize or change to improve performance during the design phase of a PV system. For those who are not familiar with MPP tracker, you may refer to EME 812 (6.2 Main components of the PV systems) and EME 812 (11.3 DC/DC Conversion).


The other piece is the mechanical part of the PV system that indeed can be optimized by the designer to improve the amount of light falling on a PV array. 
The simplest way to maximize the solar utility is done by physically changing the orientation and tilt angle of the module, as discussed in EME 810 (Lesson 2: Collector Orientation) and EME 810 (Lesson 6: Project Locale).


As a result, we see the need for tracking the sun using a mechanical tracking system.
 You may refer to EME 812 (Lesson 3: Tracking Systems) for details about the types and technologies of tracking systems.

 As the majority of PV systems are fixed mounted, a single choice for orientation and tilt throughout the year changes depending on the geographical location, as discussed in EME 810 (Lesson 6: Project Locale).



Irradiance and PV output

The question remains, how does irradiance affect the PV output? We learned in our review of EME 812 how irradiance and temperature affect the output of a PV cell. A quick recap will tell us that when all parameters are constant, the higher the irradiance, the greater the output current, and as a result, the greater the power generated. Figure 2.7 shows the relationship between the PV module voltage and current at different solar irradiance levels. The image illustrates that as irradiance increases, the module generates higher current on the vertical axis. Similarly, we can observe the voltage and power relationship of a PV module at different irradiance levels. We can see that as irradiance increases, the module is able to generate more power, represented by higher peaks on the curves in Figure 2.8.

Figure 2.7: The effect of irradiance on I-V curve of PV module

Credit: Mohamed Amer Chaaban

Figure 2.8: The effect of irradiance on P-V curve of PV module

Credit: Mohamed Amer Chaaban

The relationship between irradiance and modules’ current and power can be expressed as the following:;

$$\frac{G1}{G2}=\frac{I2}{I1}=\frac{P2}{P1}$$

Where G1 and G2 are the irradiances (in W/m2), I1 and I2 are the modules' corresponding current (in A), and P1 and P2 are the resultant power when irradiance changes (in W).

Tilt and PV Output

The following example illustrates how to find the optimal tilt angle for a fixed mount PV system. 
If we go to State College, PA and use the chart that was developed in EME 810 (Lesson 2: Sky Dome and Projections) we can see that State College, PA has a latitude around 40.79° in the Northern Hemisphere. In this case, the lowest elevation angle of the sun at solar noontime is around 26° and the highest is around 75°. If we have a tilt tracker, it would vary the range of angles throughout the year between 26° to 75°.

How can we find the tilt corresponding to the maximum yield? This is done using tools developed to calculate the annual energy generation from a PV array given the design tilt and azimuth angles. Some references and designers prefer to set the tilt angle to match the latitude of the selected location as a rule of thumb. However, that does not necessarily maximize the annual energy production of the PV system, as discussed in EME 810 (Lesson 6: Project Locale).

In general, a lower tilt angle helps improve production in the summer months, whereas higher tilt angles favor lower irradiance conditions in the winter months. Designers should take into account the cost of racking and mounting hardware, which can be minimized by lower tilt angle and also minimize the risk of wind damage to the array. So without tedious mathematical calculations, and in order for us to find the optimal tilt and azimuth angles, solar designers can use simple tools developed by NREL. As you were exposed to in Lesson 1, PVWatts is a freely available online design tool and it helps designers calculate the annual energy production using simple parameters to maximize the solar utility for the location.

Going back to State College, PA, and since we have fixed panels oriented towards the South, the optimized tilt angle that will give the maximum energy yield is around 30-35 degrees.

Effect of Temperature on the Module's Behavior

In regard to the temperature, when all parameters are constant, the higher the temperature, the lower the voltage. This is considered a power loss. On the other hand, if the temperature decreases with respect to the original conditions, the PV output shows an increase in voltage and power. Figure 2.9 is a graph showing the relationship between the PV module voltage and current at different solar temperature values. The figure illustrates that as temperature increases, the voltage, on the horizontal axis, decreases. Similarly, the relationship between the PV module voltage and power at different solar irradiance levels is shown in Figure 2.10. We can see that the power decreases as temperature increases, as illustrated by lower power peaks on the curves in Figure 2.10.

Figure 2.9: The effect of Temperature on I-V curve

Credit: Mohamed Amer Chaaban

Figure 2.10: the effect of Temperature on P-V curve

Credit: Mohamed Amer Chaaban

The drop in open-circuit voltage with temperature is mainly related to the increase in the leakage current of the photodiode “I0” in the dark with temperature. The “I0” strongly depends on the temperature.

The magnitude of voltage reduction varies inversely with Voc. 
This means that cells with higher Voc are less affected by the temperature than cells with lower Voc, as can be seen when a c-Si based solar cell, with a Voc of 0.65 V, is more affected than the a-Si with a Voc of 0.85 V.
 If the temperature of the PV module is increased by 10°C, how will the output be affected? The PV module manufacturers specify the temperature coefficients in the datasheets.

Temperature Coefficient

Temperature coefficient is defined as the rate of change of a parameter with respect to the change in temperature. It can be current, voltage, or power temperature coefficient. 
For example, the temperature coefficient of voltage is the rate of change of the voltage with temperature change. 
Similarly, temperature coefficient of power is the rate of change of the output power with temperature change.
 A typical datasheet of a commercial PV module specifies temperature coefficients for the power,
 Voc, and Isc under STC conditions. (Note: we will discuss the STC test conditions in the next topic).


Temperature coefficient are usually provided by the manufacturers and can be measured in terms of voltage change per degree ( V/°C) or as a percentage per degree change (%/°C). The unit can also be given per cell (not the per module!). In the later case, we need to adjust for the number of cells in series per module to account for the total coefficient. 

Given these coefficients, how do we calculate the PV output with respect to the temperature change?

Effect of Temperature Change on Module's Parameters

In order for us to understand the numerical temperature effects on module, we need to define these two simple equations.


$$V=V_{STC}+V_{T-coeff}\times {(T_{Cell}-25)}^{o}C$$

$$P=P_{STC}+P_{T-coeff}\times {(T_{Cell}-25)}^{o}C$$

The terms Vstc and Pstc refer to the Voltage and Current taken at STC while the temperature coefficients of the voltage is represented by Vt-coeff and Pt-coeff, respectively.


It should be noted that the reference temperature taken for this calculation is the STC temperature (25°C
) as it appears on the equations.

Let's take an example.


If the maximum power output of a PV module under STC is 240 W, and the temperature coefficient of power is -2 W/°C, then the module's power output at a temperature of 30°C can be calculated as follows:

$$P=240 W+(-2 W/{°}^{}C)\times {(30-25)}^{°}C=230$$

As you can see, the sign of the temperature coefficient determines if the parameter is increasing or decreasing with temperature.

In the previous example, when we said that the temperature was 30°C, did we mean the PV modules temperature or the ambient temperature? Are they equal? The simple answer is that module temperature or the cell temperature can be quite different from the ambient temperature.

Then, how do we estimate the module temperature based on the ambient temperature if we have to account for so many factors? 
Researchers developed a model provided in literature that gives a reasonable estimate of the module temperature as a function of the ambient temperature.
This model is sometimes called the NOCT model, due to the use of the Nominal Operating Cell Temperature.
 The NOCT is a parameter defined for a particular PV module. 
NOCT is the temperature attained by the PV cell under an irradiance of 800 W/m², with
a nominal wind speed of 1 m/s and an ambient temperature of 20°C.

$$T_{\text{cell }}=T_{\text{ambient }}+G\times \frac{(NOCT-{20}^{\circ }\mathrm{C})}{800\frac{W}{m^2}}$$

Here, G is the irradiance at the instant when the ambient temperature is T_ambient.
The model gives the corresponding cell temperature as T_cell.
 As can be seen from this equation, the cell temperature is not only a function of the
 ambient temperature, but also of the irradiance.
 This makes things interesting, because if we consider the irradiance and temperature 
changes over a calendar year, we would see an effect of both irradiance and temperature 
across the seasons.

Temperature and Ideality Factor of PV Modules

So, how serious can temperature affect the performance of PV modules over the year?

 The difference between the expected PV yield with rated efficiency and the actual yield
 due to the temperature effect increases the module’s ideality factor, which is nothing but the ratio of the expected PV yield to the actually available, and taking into account the temperature effects.


When the ideality factor of a module is 80%, that means that the module has lost 20% of its annual energy yield due to temperature effects.
 If the module ideality factor is 100%, that means the module doesn’t change when temperature changes, and that is almost impossible.



Ideality Factor and PV module Type

As a result, we can see that the temperature effect on the module output is a function of the PV 
technology and the manufacturing process, which collectively decides the temperature 
coefficients of the PV module. The temperature effect is also a function of the ambient conditions.
 For the same technology, there could be a deviation in the temperature coefficients due to the manufacturing processes and other design modifications.

 The a-Si technology shows very low temperature coefficients due to their 
high open-circuit voltage.
This means it shows a better response under high temperatures.
 However, its efficiency is far lower compared to some of the best c-Si technologies.



According to IEA PV roadmap 2014, c-Si modules have the highest market share compared to other PV technologies such as a-Si. C-Si technologies dominate the global PV market with a share of 90%. In other words, every 9 of 10 PV installation is c-Si modules. If we look closer at the c-Si market, we can see that polycrystalline silicon is the most commonly used technology, according to an EPRI study, with a market share of 60%. This is due to the fact that it is the most efficient in terms of conversion efficiency and economics of scale that make it an affordable solution. 



Monocrystalline modules are more area-efficient, but are not the best economical solution. 
a-Si modules are more affordable, lighter, and sometimes even flexible, but give poorer yield and required more land area.



There is plenty of optimization to be done in order to choose an ideal PV module for your system. The optimum choice will depend on the location, ambient conditions, and of course, taking into account the budget of the client.

PV modules are the final commercial product that customers buy from manufacturers and that require some data provided from manufacturers to allow customers to evaluate the performance of these modules in terms of electrical power rating, safety, and reliability measures. For that purpose, the module’s performance is set by test standards. These standards vary according to the location where the modules are to be used. For the purpose of our class, we will focus on the US standards -- and some of these standards apply internationally.

Safety

PV modules should be approved/listed by Underwriter Laboratories (UL), which is a nationally recognized test laboratory accepted by OSHA that assures that manufacturers comply with electrical safety standards.

Reliability

PV modules are expected to meet certain quality measures that are set by the international Electrotechnical Commission (IEC). These standards are specific to the technology, e.g., IEC has different standards for Thin-film and Crystalline Silicon.

PV Module Datasheet Parameters

PV module manufacturers are required by NEC and IEC to provide their product with performance information such as the electrical characteristics measures that have to be labeled on nameplates. These parameters include maximum power, open-circuit voltage, short-circuit current, maximum overcurrent device rating, and maximum permissible system voltage. However, these numbers vary according to operating conditions such as temperature and irradiance. For that reason, test standards are needed to set reference operating conditions when taking the measurements at the laboratory.

PV Module and Test Standards

There are various test standards that differ mainly by the operating condition used when taking the measurement. For example, Standard Test Conditions (STC) is an international and most widely used test standard that rates PV modules at solar irradiance of 1000 W/m2, spectral conditions Am1.5, and cell temperature of 25 °C (77 °F). However, in practice, modules rarely operate in these conditions, and that's the main reason behind other test standards that try to simulate real-world operating conditions.

So to put everything we have learned so far together, let’s take a look at a PV modules’ datasheet for Trina Solar Allmax 250 W. As can be seen, most module manufacturers have series of modules with different power ratings, and they all appear in the same specification sheet. We can see the main electrical parameters and power ratings at STC and NOCT, efficiency, power tolerance, temperature coefficients, warranty, mechanical dimensions and testing certifications such as UL and ISO and more.

Some considerations when selecting PV modules

Since PV systems are large in size and consist of multiple panels, we expect these systems to be visible to clients, and there will be an aesthetic factor involved in the design process. For example, a client may have a color preference for the PV panels that should be taken into account when selecting the panels, since it might be affected by the availability of that color. Another aesthetic factor is the dimension of each panel and the layout on the roof, for example. A designer should discuss with clients all possible options for best design to maximize the solar utility at that location while keeping the system aesthetically acceptable. Other selection factors are more technical, such as the number of cells in each panel, protection fuses and bypass diodes, degradation, and warranty. All these factors should be taken into account when selecting the right module.

This week, you will begin preparing a multi-week Report of the available PV components in the market.

Let's go back to our scenario from the beginning of this lesson. You returned from the solar trade show, where you collected some datasheets for a series of PV modules from different manufacturers. Now that you are fully knowledgeable about the basic information of PV technology types, efficiency, power, voltage and current ratings of modules, you can work on the report needed for your director. In addition, you can confidently recommend the best PV module candidate for the solar firm you work for based on the module efficiency, color, dimensions, test standards and certifications.

As a solar designer, you are equipped with the right tools and software that can be used to learn more about the annual energy production of PV modules and the system at large. These tools help you understand the factors (such as orientation - tilt and azimuth - and ambient temperature) that affect the performance of these PV modules when they are installed. Finally, you can suggest methods to optimize the performance of the PV system.

The next lesson will discuss the bucket of stand-alone PV systems, which is the "Storage System." We will cover a variety of topics, starting from basic characteristics to factors that affect performance. Finally, we will cover the essential parameters and curves that lead to optimal design.

In this lesson, we will discuss topics that lead to answers to all the questions in the scenario above. We will provide PV designers with a basic understanding of batteries to help them choose the best battery to fit their application. Although the majority of PV applications are grid-connected, designers may encounter off-grid PV systems with storage systems if they are involved in that market sector. That said, participating in this lesson will put you in the right direction when selecting the right technology for your application and will help you perform basic assessments for optimal design.

Learning Outcomes

At the successful completion of this lesson, students should be able to:

• Identify types of electrical energy storage technologies and how they relate to (Energy or Power) responses.
• Identify battery parameters and specifications including capacity, efficiency, discharge rate, state of charge and depth of discharge.
• Interpret battery manufacturer datasheets to match PV system requirements.
• Describe factors that influence the lifetime of a battery, such as temperature and charge and discharge control.

Due to the advancement in the distributed generation systems for electricity, there is an increased demand for energy storage at both small and large scale applications. As we learned in lesson 1, PV is one of the fastest growing technologies in the electrical generation market, and in some cases it requires storage systems. In this lesson, we will focus on the complementary energy source that is usually coupled with a PV system, which is the storage system.

Storage is needed in PV systems to overcome the intermittency of the energy generated. These variations could be caused due to daily or monthly solar irradiance fluctuations. Daily fluctuation occurs as a result of the change of solar irradiance within the 24-hour period; while the seasonal (or monthly) fluctuations occur due to the change of solar irradiance across the summer and winter as seen in Figure 3.1. If we observe the monthly energy production of a 1 kW PV system installed in State College, PA, we can see that the generation increases during the summer months while the energy generation drops during the winter months. We can see that the PV system will not generate the same amount of energy each month. This means we need another complementary system to help even out the energy difference throughout the year.

Figure 3.1: Monthly Energy Production for 1kW PV system in State College, PA

Credit: Developed using SAM

In addition to solving the critical intermittency generations issue of solar PV, storage systems provide:

1. A potential resource for shifting energy from one time to another
2. A local source of energy to supply peak demand and potential enhancement for better reliability and resiliency.
3. A method to enable load shifting to improve asset utilization and defer other capital investment

How do we make an optimal choice of a storage system?

Depending on the desired application intended for a storage system, there are many factors that affect the selection decision. In general, each application requires either more power from the storage system or it may require more energy. In Figure 3.2, the Ragone plot illustrates the power/energy density of various storage technologies. It can be seen that some technologies, such as fuel cells, can generate higher energy density (in wh/kg) than technologies with lower energy density such as capacitors. In other words, fuel cells can supply energy for longer time periods than can capacitors. In contrast, capacitors have higher power density (W/kg) than fuel cells, which means capacitors supply higher power for short periods than do fuel cells. For example, a capacitor is a good choice for high power density requirements, but it is not the optimal choice for high energy density, as we can see in Figure 3.2.

Figure 3.2: Ragone plot representing the Energy density vs Power density of different storage systems

Credit: Stan Zurek (raster) [GFDL, CC-BY-SA-3.0], via Wikimedia Commons

For most solar applications, we need a good balance between both high energy density and a high power density.

Batteries are electrochemical devices that convert chemical energy into electrical energy. Batteries are classified as primary and secondary batteries.

Primary batteries

• Convert chemical energy to electrical energy and cannot be recharged.
• Examples include zinc carbon batteries and alkaline batteries.

Secondary batteries

• AKA rechargeable batteries, convert chemical energy to electrical energy and are rechargeable when the chemical reaction is reversed using forced electrical energy.
• Examples include lead-acid batteries and lithium-ion batteries.

There are several kinds of available secondary battery technologies that could be used for different applications, such as lead-acid and lithium-ion batteries. Lead-acid batteries use the oldest and most mature battery technology available, although lithium-ion batteries are being heavily researched and used recently (more work needs to be done regarding the costs! they may still not be competitive in some areas in the world).

So how do we compare batteries for best candidate for PV application?

Let's look at the Ragone plot specific to available batteries. This is slightly different from the Ragone plot shown earlier. Figure 3.3 illustrates the comparison between various battery technologies in terms of gravimetric energy density and volumetric energy density. If we compare battery technologies based on both the energy per volume and energy per weight, we can see that lead-acid batteries have less energy density than Li-Ion batteries. As you move on the "x" axis, the gravimetric energy density increases. In other words, the battery offers higher energy per unit of weight. On the "y" axis, the volumetric energy density increases as we go up. In other words, the amount of energy in higher per unit of volume.

Figure 3.3: Ragone plot showing the Volumetric energy vs Gravimetric energy of different battery types

Credit: Ragone Plot for diff Li batteries / Chem511grpThinLiBat / CC BY-SA 4.0

Volumetric energy density is the amount of energy stored per unit volume of battery. The typical unit of measurement is Wh/l. We can observe that the higher the volumetric energy density, the smaller the battery size.

Gravimetric energy density is the amount of energy stored per unit mass of the battery. The typical unit of measurement is Wh/kg. We can also observe that the greater the gravimetric energy density, the lighter the battery.

As shown in Figure 3.3, lead-acid shows the lowest volumetric and gravimetric energy densities among the batteries, while Li-ion exhibits the best combination.

That said, let's look a little bit more closely at the lead-acid battery.

Similar to most batteries, the lead-acid battery consists of several individual cells, each of which has a nominal voltage of around 2 V. Lead-acid batteries could have different types of assembly. For example, the common lead-acid battery pack voltage is 12 V, which means 6 cells are connected in series.

When the battery is recharged, the flow of electrons is reversed, as the external circuit doesn't have a load, but a source that has a higher voltage than the battery can enable the reverse reaction. In a PV system, this source is nothing but the PV module or array providing solar power and can charge the battery when the sun is available. As we learned previously in Lesson 1, the use of storage is more common in the stand-alone PV systems, because there is no other source of power to support the PV array when the sun is not available. In other words, the loads are at the mercy of the availability of the sun. In that case, an energy storage option such as batteries can be very useful. As an example, a typical daily solar irradiance profile is shown in Figure 3.4. If we observe the orange curve that represents the daily solar irradiance, we can see that a significant amount of energy is generated during the daytime while no energy is generated during the nighttime. On the other hand, the daily energy demand represented in the blue curve shows that energy is needed all day long, with higher demands at certain time periods. When we put the daily load demand curve (aka daily load profile) on the same figure, we see that a significant energy demand exists when there is no sun.

Figure 3.4: Daily solar irradiance (Orange) and daily load profile (Blue) for State College, PA.

Credit: Developed using SAM

For utility-interactive systems, the excess energy is fed back to the grid while the load demand can be supplied from the grid when the sun is not available.

As for a stand-alone system without storage, even though the sun has more than enough power during the day, the system fails to utilize this excess energy to power the loads when the sun is not available.

With the introduction of battery storage, the excess energy from the sun during the day can be stored in a battery and then used later to meet the load demand when the sun is not available. This is represented in highlighted areas A1 and A2 in Figure 3.5, below, for excess solar power and evening load demand respectively.

The perfect match occurs when area A1 equals to area A2 and that can be accomplished by perfectly sizing the solar PV system to meet the average daily load energy demand. Furthermore, excess solar energy can be stored using Battery systems.

Figure 3.5: Excess solar energy highlighted (green) and daily load highlighted (red) for State College, PA.

Credit: Developed using SAM

In summary, we have seen different types of battery technologies and discussed why lead-acid can be the battery of choice for PV systems globally but Li-ion has become the dominant technology recently. We will talk in detail about battery parameters in the next topic. We will also see how managing battery parameters is a whole new optimization challenge on its own.

Batteries are the final commercial product that are delivered to customers and that require some data provided from the manufacturers to allow customers to evaluate the performance of different battery types in terms of capacity rating, allowable DOD, and temperature operating ranges. Most datasheets come with some curves that a PV designer should be able to perfectly interpret for best design practices.

In this section, we will discuss basic parameters of batteries and main factors that affect the performance of the battery.

The first important parameters are the voltage and capacity ratings of the battery.

Every battery comes with a certain voltage and capacity rating. As briefly discussed earlier, there are cells inside each battery that form the voltage level, and that battery rated voltage is the nominal voltage at which the battery is supposed to operate.

The capacity refers to the amount of charge that the battery can deliver at the rated voltage, which is directly proportional to the amount of electrode material in the battery.

The unit for measuring battery capacity is ampere-hour or amp-hour, denoted as (Ah). The capacity can also be expressed in terms of energy capacity of the battery. The energy capacity is the rated battery voltage in volts multiplied by battery capacity in amp-hours, giving total battery energy capacity in watt-hours (wh). In general, it is the total amount of energy that the device can store.

You must be wondering what is the significance of amp-hours as the unit of battery capacity? The unit itself gives us some important clues about battery properties. A brand new battery with a 100 amp-hour capacity can theoretically deliver a 1 A current for 100 hours at room temperature. In practice, this is not the case due to several factors, as we will see later.

C-rate

Let's move to another important battery parameter, called the C-rate. C-rate is the discharge rate of the battery relative to its capacity. The C-rate "number" is nothing but the discharge current, at which the battery is being discharged, over the nominal battery capacity. It is calculated as the following:

Where

"I_dis" is the discharge current

"C_non" is the nominal battery capacity

The discharge rate is sometimes referred to as C/”number” and that number is the number of hours it takes the battery to be fully discharged. In other words, it is the inverse of the previous notation, and it is calculated as the following:

For example, a C-rate of 1C for 100 Ah capacity battery would correspond to a discharge current of 100 A over 1 hour. Or it can be represented as C/1. On the other hand, a C-rate of 2C for the same battery would correspond to a discharge current of 200 A over half an hour. Or it can be represented as C/0.5. Similarly, a C-rate of 0.05C implies a discharge current of 5 A over 20 hours. Or it can be represented as C/20. Finally, the same battery can be discharged at 1 A over 100 hours, and that corresponds to 0.01C or C/100. In general, C-rate depends on charging and discharging current.

Efficiency

Since there is no energy conversion system that is 100% efficient, the term efficiency represents the system capability to transfer energy from the input of the system to the output. Each battery type comes with different efficiency rating as discussed in EME 812 (9.3. Battery storage - Table 9.1), and usually we talk about efficiencies of both charge and discharge combined.

Battery efficiency is the ratio of total storage system input to the total storage system output. For example, if 10 kWh is pumped into the battery while charging, and you can effectively retrieve only 8 kWh while discharging, then the round trip efficiency of the storage system is 80%.

Let's discuss another important battery parameter, the state of charge or SOC. It is defined as the percentage of the battery capacity available for discharge, so thus, a 100 Ah rated battery that has been drained by 20 Ah had an SOC of 80%. Another parameter that complements the SOC is the depth of discharge or DOD, which is the percentage of the battery capacity that has been discharged. Thus, a 100 Ah battery that has been drained by 20 Ah has a DOD of 20%. In other words, the DOD and SOC are complementary to one another.

Now we come to a very important parameter: the cycle lifetime of the battery. Cycle lifetime is defined as the number of charging and discharging cycles after which the battery capacity drops below 80% of the nominal value. Usually, the cycle life is specified as an absolute number. However, to be more precise, cycle life and other battery parameters are affected by changing ambient condition such (temperature in this case).

So what is the relationship between the battery parameters? The cycle life depends heavily on the depth of discharge. This can be seen in Figure 3.6 for a typical flooded lead-acid battery. If we look at the effective capacity at different depth of discahrge (DOD) rates for a lead-acid battery, we can see that the cycle number diminishes as the DOD increases.

Figure 3.6: The effective capacity (%) vs cycle number at different DOD rates for a flooded lead-acid battery.

Credit: Developed using SAM

Cycle lifetime also depends on the temperature. The battery lasts longer under colder temperatures of operation. Furthermore, we can observe from Figure 3.6 that for a particular temperature, cycle lifetime depends non-linearly on the depth of discharge. The smaller the DOD, the higher the cycle lifetime. However, such a higher cycle life would also mean that those additional cycles you gain can only help you for a smaller depth of discharge. Thus, it could be said that the battery will last longer if the average DOD could be reduced over its normal operation. Also, battery overheating should be strictly controlled. Overheating could occur due to overcharging and subsequent overvoltage of the lead-acid battery. We will learn more about voltage and charge control of the battery in the next section.

While battery life is increased at lower temperatures, there is one more effect that needs to be considered. The temperature affects battery capacity during regular use, too. As seen in Figure 3.7, the lower the temperature, the lower the battery capacity. The Higher the temperature, the higher the battery capacity.

Figure 3.7: the effective capacity (%) vs temperature for a flooded lead-acid battery

Credit: Developed using SAM

Battery Aging Factors

It might not seem scientific, but it is even possible to reach an above rated capacity of the battery at high temperatures. However, such high temperatures are severely detrimental to battery health.

When we say that a battery has a limited cycle life, or that it has completely "run out of juice," what exactly does that mean? Is it related to the aging effect of the lead-acid battery?

There are several factors that contribute to the aging of any battery. Sulphation is one of the major causes of aging. And if the battery is not fully recharged after being heavily discharged, that causes sulphate crystals to grow, which cannot be completely transformed back into lead or lead oxide. As a result, the battery slowly loses the mass of active material and therefore discharge capacity will be lower. Corrosion of lead grid at the electrode is another common aging factor. This leads to increased grid resistance due to high positive potentials.

Moving further, when the battery loses moisture, it causes the electrolyte to dry out, which occurs at high charging voltages, resulting in loss of water. It is referred to as gassing effect and may limit battery lifetime. This should be taken care of with routine maintenance by adding distilled water to the battery.

Researchers have developed maintenance free lead-acid batteries for solar systems that exhibit very high lifetimes. However, these are also high-end products and can be more expensive.

After we covered all basic battery parameters and characteristic curves, a designer should be able to make the best selection for a product depending on the application. But how do designers put these batteries in place? Is there only one size for all batteries, and it is scalable? Or do they make a custom design battery for each project? We will answer these questions in the next section.

Batteries are usually installed in groups for PV applications. In this case, the parallel and series connection of batteries is referred to as the Battery Bank. Lead-acid batteries are usually rated at 12 V, 24 V or 48 V. This voltage is determined by the series and parallel interconnection of several batteries. The voltage needs to meet the load or inverter voltage level requirements.

The series and parallel connection principles are similar to PV modules where we add voltage when connected in series while current is added for parallel connections of batteries. Similar to PV, groups of batteries connected in parallel are called a Battery String. As for the capacity rating of a battery bank, it is similar to the current principle. When connecting batteries in series, the capacity is not added. As for a parallel connection, the capacities add up.

Figure 3.8 illustrates the series and parallel connections of batteries and the corresponding voltage and current. As can be seen, batteries can be connected in series, parallel, or both. In this case, each battery with "V" for voltage and "I" for current is connected either in series or parallel with other similar batteries. The total voltage and current depends on the wiring type. In case of series connection, the total voltage of three batteries will be 3V while the current is similar to the current of a single battery. When three batteries are connected in parallel, the voltage equals the voltage of a single battery, while the total current is the sum of the currents of all batteries for a total of 3I. When two strings of three batteries are connected in parallel, the total voltage will be 3V, while current is summed for the two strings for a total of 2I. 

Figure 3.8: Series and parallel connection of battery bank.

Credit: Mohamed Amer Chaaban

It is recommended to have as few battery strings as possible to avoid voltage differences that may create power loss. In larger PV installations where more battery banks are required, it is recommended to connect more batteries in series rather than parallel strings. An example of a mobile bus that is converted to a solar stand-alone system with batteries is shown in Figure 3.9.

Figure 3.9: Bus turned into a mobile demonstration of sustainable living. Its interior is powered with solar energy and batteries.

Credit: Ecological Bus Project, Solar battery bank below / ArtofCulturalEvolution / CC BY-SA 3.0

Design considerations

When designing a battery bank for a specific location, a good design will ensure that the battery bank is perfectly:

1. sized so the energy capacity matches the load requirements.
2. sized for maximum and minimum voltage requirements for the desired application.
3. ventilated to meet temperature requirements.
4. maintained to maximize the utilization of batteries.

This week, you will continue working on your Report on Part B.

Let's go back to our scenario from the beginning of this lesson. You came back from the solar trade show, and you collected some datasheets for battery types and technologies from different manufacturers. Now that you are fully knowledgeable about the basic information of battery technology types, efficiency, the capacity rating, and voltage and current ratings, you can work on the report needed by your director. In addition, you can confidently recommend the best battery candidate for the solar firm for which you work.

As a solar designer, you are equipped with the right information to choose battery technology based on the factors that affect performance of batteries when they are installed, such as rate of discharge and the ambient temperature. Finally, you can suggest methods to increase the cycle life of the battery bank.

The next lesson will discuss the heart of any PV system, which is the "Power Conditioning Unit." We will cover a variety of topics starting from basic characteristics to factors that affect performance, and finally, stringing tools considering inverter's parameters that lead to optimal PV system design.

In this lesson, we will discuss topics that lead to answers to all the questions in the scenario above. We will also introduce new tools that can be used to help PV designers make the optimum selection of the inverter. Whether you are a designer or a system owner, the knowledge presented in this lesson will help you understand the basics of the inverter.

Learning Outcomes

At the successful completion of this lesson, students should be able to:

• Identify common types and functions of inverters, converters, and power management technologies and selection methods to align with PV systems.
• Interpret inverter specification sheets and parameters to match PV and grid requirements.
• Discuss features of inverters, including the Maximum PowerPoint Tracker, anti-islanding detection.
• Describe factors influencing the lifetime of an inverter, such as temperature and environment.
• Identify an inverter’s voltage operating ranges and capacity factor and how to match them with PV module and string ranges.

Since we learned the difference between DC power and AC power and their properties in the “Basics of Electricity” section in the class Orientation, we know for sure that the power coming from the source needs to be shaped to match the property of the load.

In this lesson, we will focus on how Power Conditioning Units (PCUs) are used and what the main types and configurations are that exist for these PCUs in the solar industry.

PCUs for PV systems

To know what a PCU is, we must first understand we need it for PV systems. All topics on the PV electrical output current, voltage, and power we discussed were in DC form. And since most appliances (fridge, lighting, heating, etc) need AC power, we need a device that can simply convert the DC electric power into an AC power. And that device is called an inverter. Furthermore, since most PV systems are connected to the utility grid, the solar power produced needs to be converted to AC form. This allows solar power to move in and out of the electricity grids we have today.

PCU vs Inverter

Many people use the term inverter as a device that converts DC into AC power. However, the inverter can perform many tasks beyond that. Thanks to the advancements in power electronics, it is common to have inverters that implement an MPPT mechanism before inverting the voltage, thus ensuring that the PV modules or arrays are operating at their maximum power. Furthermore, the inverter can include a battery charger, a DC to DC converter for voltage step-up and step-down, and a transformer for grid isolation and voltage step-up. As we can see, the basic DC to AC conversion that is referred to as an inverter is better understood as the package and can be called a Power Conditioning Unit. It should be noted that the commonly used term for this device in the industry is “inverter.”

Now that we understand why we need an inverter for PV systems, it is time to introduce the different types of inverters that exist in the market and discover the advantages and disadvantages of each type. Inverters are classified based on their size, mode of operation, or configuration topology.

Inverters based on PV system type

Considering the classification based on the mode of operation, inverters can be classified into three broad categories:

1. Stand-alone inverters (supplies stable voltage and frequency to load)
2. Grid-connected inverters (the most commonly used option)
3. Bimodal inverters (usually more expensive and are used less often)

Types of Grid-connected Inverters

Aside from the modes of operation, grid-connected inverters are also classified according to configuration topology. There are four different categories under this classification.

1. Central inverters, which are usually around several kW to 100 MW range.
2. String inverters, typically rated around a few hundred Watts to a few kW.
3. Multi-string inverters, typically rated around 1 kW to 10 kW range.
4. And finally, Module Inverters or Micro Inverters, typically rated around 50 to 500 W.

Central Inverter

Let's start with the central inverter, as shown in Figure 4.1. This is a PV array that consists of three strings, where each string has three series connected modules. Before these strings are connected to the utility grid, a power conditioning unit is required as an interface between the array and the grid. Designers can use one central inverter as illustrated in Figure 4.1, where all strings are connected to the DC side of the inverter and the single AC output is connected to the utility grid.

Figure 4.1: Central Inverter Topology

Credit: Mohammed Amer Chaaban

Advantages of a Central Inverter

1. The most traditional inverter topology
2. Easy system design and implementation
3. Low cost per Watt
4. Easy accessibility for maintenance and troubleshooting

Disadvantages of a Central Inverter

1. High DC wiring costs and power loss due to Voltage Drop.
2. Single MPPT for the entire PV system
3. System output can be drastically reduced in case of partial shading and string mismatch
4. Difficult to add strings or arrays for future expansion
5. Single failure point for the entire system
6. Monitoring at array level
7. Huge size! (It is a disadvantage because the bigger size requires more land and creates a shading issue for the PV array.)

String Inverter

Now, we are moving to the String inverters as shown in Figure 4.2. Assuming the same PV array that consists of three strings, another way to connect it to the grid is using three string inverter as illustrated in Figure 4.2. In this case, each PV string is connected to a single string inverter at the DC side, and all AC outputs of inverters are combined and connected to the utility grid.

Figure 4.2: String Inverter Topology

Credit: Mohammed Amer Chaaban

As the name indicates, each string of PV modules has its own inverter. In this case, we are moving closer to the PV modules level.

Advantages of a String Inverter

1. Smaller in size when compared to central inverters
2. Better MPPT capability per string
3. Scalability for future expansion by adding parallel strings
4. Short DC wires
5. Monitoring at string level

Disadvantages of a String Inverter

1. The installation requires special racking for the inverter for each string
2. Poor flexibility at partial shading
3. Higher per Watt cost than central inverter

Micro Inverter

Finally, let's look at the micro inverters. These are also referred to as module inverters. In this case, each module has one dedicated inverter connected on the back of the module. The module DC terminals are connected to the DC side of the inverter and then all AC wires of all terminals are combined and then connected to the utility interconnection point as illustrated in Figure 4.3.

Figure 4.3: Micro Inverter Topology

Credit: Mohammed Amer Chaaban

As the name suggests, each module has a dedicated inverter with an MPP tracker.

Advantages of Micro Inverters

1. Resilience to partial shading effects as compared to the central and string inverters.
2. MPPT at module level
3. Highest system flexibility for future expansion
4. Minimum DC wiring costs
5. Monitoring at module level

Disadvantages of Micro Inverters

1. High per Watt cost
2. High maintenance costs
3. Difficult access for maintenance since the installation is under the PV modules

After this overview of the solar inverters and their topologies, it is important to look at the various parameters and characteristics of this technology. The choice of the inverters' topology for implementation depends entirely on the system needs, size, and the budget. While choosing an inverter for your PV system, what are the requirements for a good solar inverter?

Characteristics of Solar Inverters

Inverter Input voltage range and max voltage

Inverters are designed to operate within a voltage range, which is set by the manufacturer's specification datasheet. In addition, the datasheet specifies the maximum voltage value of the inverter. Both the maximum voltage value and operating voltage range of an inverter are two main parameters that should be taken into account when stringing the inverter and PV array. PV designers should choose the PV array maximum voltage in order not to exceed the maximum input voltage of the inverter. At the same time, PV array voltage should operate within the input voltage range on the inverter to ensure that the inverter functions properly.

Inverter Start-up voltage

Aside from the operating voltage range, another main parameter is the start-up voltage. It is the lowest acceptable voltage that is needed for the inverter to kick on. Each inverter has a minimum input voltage value that cannot trigger the inverter to operate if the PV voltage is lower than what is listed in the specification sheet.

Inverter and efficiency

As power is processed and converted from one shape to another, the solar inverters are expected to perform these tasks with the highest possible efficiency. This is because we wish to deliver maximum PV generated power to the load or the grid. Typical efficiencies are in the range of more than 95% at rated conditions specified in the datasheet.

Inverter and MPPT

Depending on the topology, most modern inverters have built-in MPP trackers to insure maximum power is extracted from the PV array. Each inverter comes with a voltage range that allows it to track the maximum power of the PV array.  It is recommended to match that range when selecting the inverter and the PV array parameters.

Inverter and ambient conditions

In most applications, the solar inverters are exposed to ambient conditions such as solar radiation, temperature, and humidity. Inverters must comply with the conditions of the location to make sure they can work under ambient conditions listed in the specification sheet.

Inverter and the utility grid

Since grid-tied inverters pump power into the grid, they are expected to maintain a very high quality of power to guarantee that the acceptable power flows into the grid. For that reason, inverters are expected to have a very low harmonic content on the line currents. Furthermore, grid-tied inverters are expected to have active islanding detection capability per IEEE 1547.

Islanding refers to the situation in which the inverters in a grid-tied setup continue to inject power from the PV system even though the power from the grid operator has been restricted due to fault of scheduled maintenance. Due to safety concerns, islanding needs to be prevented. Therefore, inverters are expected to detect and respond immediately by switching their output so that no more power flows into the grid. This is also referred to as anti-islanding capability.

Inverter lifetime

There is also ongoing work to increase the lifespan of the inverter. A good inverter will probably reach, under favorable conditions, around 10-12 years of lifetime. This is a bottleneck in the PV system lifetime, especially considering the fact that PV modules can last over 25 years.

DC to AC ratio

Each inverter comes with a maximum recommended PV power, or sometimes is referred to as "DC-AC Capacity factor," which is defined as the percentage of DC power over the inverter's max power. We will use "DC to AC ratio" when we refer to this specific term throughout this calss. 

We discussed the effect of cell temperature on the I-V curve and the operating voltage and current in Lesson 2. Now it is time to apply this knowledge to calculate minimum and maximum operating voltage of module or string.

The NOCT and % temperature coefficients from the modules datasheet can be used to determine the min and max voltage levels and the range of MPP corresponding to it. PV designers are interested in the lowest recorded temperature for a location to determine the highest possible Voc for the string and Vmp for MPP range. Furthermore, the average highest temperature is used to find the lowest voltage from the module or string.

We can also define the string voltage as the individual module’s voltage multiplied by the number of modules connected in series.

Assuming we are stringing the PV string shown in Figure 4.4, the I-V curves of the PV string vary depending on the temperature. When the temperature is higher than the standard 25ºC, both of the MPP voltage and the open circuit voltage Voc decrease. On the contrary, when the temperature is lower than 25ºC, both the MPP voltage and Voc increase, as illustrated in Figure 4.4. If we define operating ranges for both the MPP voltage and Voc, we can see that the inverter should be able to operate within the MPPT range at the lowest record and average highest MPP voltage of the PV string. Similarly, the inverter absolute maximum voltage should be at least equal to the maximum Voc of the string at the lowest record temperature and the minimum voltage of the inverter should not exceed the minimum Voc of the PV string at the highest temperature.

As PV designers, and when stringing the PV inverter with the PV string, we should make sure that the MPP voltage doesn't fall below the lowest voltage at the average high temperature and doesn't exceed the maximum voltage of the inverter.

Inverter stringing tool

As it seems, the math can get very tedious, so most Inverter manufacturers create their own sizing tools that are available online for free, where you can choose:

1. PV module brand and model
2. The desired inverter model
3. The average highest ambient temperature and lowest (record) ambient temperature ranges (some tools allow user to choose the location and these temperature values will be already available).

The tool will then give all possible configurations (series and parallel) and the capacity factor. An example of inverter stringing will be available in the Lesson Activity, where you can apply the knowledge to a real world example.

DC to AC ratio and inverter design

As a rule of thumb, designers choose DC to AC ratio (AKA capacity factor) range not to be less than 80% and not to exceed 125% depending on the location and the irradiance and type of inverter used. For example, for a system in Seattle, WA, it is recommended to oversize the PV array since it is very unlikely to overload the inverter since radiation is less than the STC power rating of the modules. In contrast, in Miami, FL you cannot exceed 110% since radiation there reaches the STC level and may exceed it. For best stringing choices, use the manufacturer's datasheet to determine the maximum and minimum allowed PV array sizes.

This week, you will continue working on your Report on Part C.

Let's go back to our scenario from the beginning of this lesson. Now that you have several datasheets for inverters from the solar trade show, you can easily prepare the report to your director about available inverter types, efficiency, the capacity factor, and voltage and current ranges. In addition, you can confidently recommend the best inverter for the solar firm depending on the PV system types they are involved in.

As a solar designer, you are equipped with the right tools to choose the inverter configuration based on the factors that affect performance, such as type of ventilation, size, and other features. Finally, you can suggest inverter configurations to optimize performance based on each specific installation's requirements.

The next lesson will discuss the pieces that are essential to put the PV systems together, which is the "Balance of System" or BOS. We will cover a variety of topics, starting from mounting structure types to mechanical and electrical components, and finally, how to find the main parameters that help designers to optimize the PV system design.

In this lesson, we will discuss topics that lead to answers to all the questions in the scenario above. We will teach PV designers basic BOS components they should look for to fit their applications. Learning the topics taught in this lesson will help a variety of audiences, ranging from system designers or installers to business owners.

Learning Outcomes

At the successful completion of this lesson, students should be able to:

• Identify main electrical and mechanical BOS.
• Identify main types of racking systems including rooftop, ground mount, and pole mount PV systems.
• Indicate factors that affect the decision to choose types of mounting systems and their requirements.
• Differentiate between various types of attachment methods.

We talked briefly about tracking systems and some design considerations for the tilt angles in Lesson 2. However, we didn’t elaborate on the mounting types available for PV systems. Each PV system is different from the rest in terms of racking structure and mounting types. This is due to the fact that PV systems are space constrained and the installation requirements vary from one place to another. For that reason, many structural holding solutions have been developed to accommodate different needs such as ground mount, pole mount, and roof mount. Each type comes with advantages and disadvantages that allow a good designer to make the optimal decision for each specific PV system.

Ground Mount

This type of mounting structure allows multiple rows of modules to be installed on the ground, as shown in Figure 5.1.

Figure 5.1: Ground Mount PV system

Credit: Ground Mount PV System / Sideka Solartechnik / CC BY-SA 3.0

Advantages

• Cooler module temperature
  • PV modules can get extremely hot during daytime due to the excessive heat generated from the modules and the ambient temperature. The best way to cool down the modules is natural convection using air, which is easily done when modules are elevated from the ground or roof so that air can carry out the heat and cool down the modules.
• Safe installation (no climbing required)
• Easy access for maintenance/troubleshooting
• No roof penetration/liability
• Flexible positioning for max production (potential use for single axis tracking). Ground mount is usually not restricted to be positioned at a certain tilt angle. That said, it is easier to choose the optimum tilt for maximum production.

Disadvantages

• Easy access (theft, vandalism, damage)
• Requires earth construction work (concrete, foundation, trenching)
• Space requirement
• Inter-row shading considerations
  • PV modules can shade one another when installed in rows. For example, the first row can shade the second row located behind it. For more information, please refer to the video (6:08) explanation below from EME 810.

Video: Shading Array Demo 1 - EME 810 (6:08)

Pole Mount

This structure is common in public areas where the system is space constrained, as seen in Figure 5.2.

Figure 5.2: Pole Mount PV System

Credit: Applied materials solar arrray / Larry D. Moore / CC BY-SA 3.0

Advantages

• Cooler module temperature
  • PV modules can get extremely hot during daytime due to the excessive heat generated from the modules and the ambient temperature. The best way to cool down the modules is the natural convection using air, which is easily done when modules are elevated from the ground or roof so that air can carry out the heat and cool down the modules.
• Easy access for maintenance/troubleshooting
• No roof penetration/liability
• Flexible positioning for max production
• Easy to adjust the tilt angle (potential use for dual axis tracking)
• Small footprint (one pole)

Disadvantages

• Easy access (theft, vandalism, damage)

• Requires construction (concrete, steel, foundation, trenching)

Roof Mount (without roof penetration)

There are various types of roof mounts that don’t require roof penetration especially when the roof is flat, as illustrated in Figure 5.3. Of these types, ballasted roof mount is one of the most used racking structure for PV systems installed on flat roofs. It utilizes the weight of concrete or sand to ensure the system stays still to stand all kinds of external forces such as pullout wind forces.

Figure 5.3: Ballasted Roof Mount PV System

Credit: Solar Panel / Ch-info.ch / CC BY-SA 3.0

Advantages

• Low material cost
• Utilizes unused spaces
• Provides secure access for authorized individuals only
• Flexible positioning for ideal production
• No roof penetration needed

Disadvantage

• May require structural engineering and/or roof reinforcement due to added weight

Roof mount (with roof penetration)

These mounting structures allow the system to be installed parallel to the roof for the best esthetic solution for pitched roofs, as seen in Figure 5.4.

Figure 5.4: Roof Mount PV System

Credit: Roof Mount PV System / Cethegus / CC BY-SA 3.0

Advantages

• Lower material cost
• Utilizes unused spaces
  • In most buildings, the roof is considered unused space. PV array can occupy these spaces and transfer them to useful spaces that can generate electricity for the building.
• Provides secure access for authorized individuals only

Disadvantages

• Requires roof penetration (roof leak liability or roof damage)
• Requires professional installers
• Higher module temperature (poor ventilation)
  • PV modules can get extremely hot during daytime due to the excessive heat generated from the modules and the ambient temperature. Since PV modules cannot be elevated from the roof for more than a couple of inches, air movement is restricted from carrying out the heat to cool down the modules.
• Difficult conduit runs
  • Most roofs have different gable shapes and sizes. In addition, the main electrical panel is usually located at the bottom of the building. That said, the PV array conduits have to run through the roof to the main panel and that route can be wiggly and require more attention to the details when installing the system.
• Fixed title and orientation
  • Most roofs come with single pitch that cannot be changed. When a PV array is installed on the roof, the orientation and tilt are restricted by the roof pitch and orientation, and that might affect the production of the PV system.
• Pullout forces
  • Wind speed flowing against the PV modules on the roof can cause forces that act similarly to pullout forces that try to remove the modules from the roof. That said, PV designers should ensure that the PV array is securely fastened to the roof using the right attachment mechanisms, such as screws and hooks.

Considerations

• Roof age
  • Roof age is a critical factor to installing a PV array. A weak and old roof may not be able to withstand the added weight from the PV array.
• Snow and wind loading
  • Snow and wind can add weight to the roof. If the roof is not designed to carry that additional weight, the roof might collapse.
• Fire issues
  • When PV arrays are installed on roofs, installers should work with the local fire department to ensure that there are no fire hazards or accessibility issues if fire occurs.

There are other mounting types that are beyond our discussion for this class and students are encouraged to look for different racking structures for their own benefit.

After reviewing different types of PV mounting structures, it is time to discuss the components that form these mounting structures. In this section, we will focus on the mechanical BOS components that help assemble the PV system components. These mechanical BOS components include fasteners, brackets, enclosures, racks, and other components that support the structure of the PV system.

Starting at the PV Array

PV modules need to be securely fastened to the racking structure, and that is done through rails, splices and clamps.

Rails

PV modules cannot be directly fastened to the roof of the building, for example. They require a structure that holds modules together that is later fastened to the roof or the ground. This structure is made of what is referred to as rails, which are rated to withstand heavy weights. Rails come in different shapes, profiles, lengths, and materials. Since rails manufacturers don’t make every desired possible length, the rails are tailored to fit each specific PV system.

Splices

When the PV system requires longer spans than the default length of the rails, splices are used to extend and connect rails to each other. Splices are usually provided by the same rail manufacturers.

Clamps

In order for the PV modules to be fastened to the rails, clamps are usually used to secure the connection between the rails and the modules. PV modules are usually installed adjacent to one another. As a result, some modules will be located in the middle and other modules will be installed on the edges. In this case, the middle modules will require what is referred to as mid-clamps to fasten the modules to each other and to the rails and end-clamps at the edge modules to lock the ends of the array.

Moving Away From the Rails

The rails need to be fastened to the mounting structure. This usually depends on the mounting type that can be roof mount, ground mount, or pole mount structures.

Roof mount (rooftop with penetration)

In case the PV system is installed on rooftops, designers should consider elevating the rails a couple of inches against the roof to allow for ventilation and lower temperature operating ranges. For that reason, there are multiple solutions in the solar industry to achieve that clearance. The rails can be fastened to the roof using one of the following options:

L-foot

L-foot utilizes screws that are fastened to the rafters or trusses from one side, and the other side will be attached to the rails. L-foot can be directly used to allow some roof ventilation; however, when the L-foot is not long enough to satisfy the ventilation requirements, Stand-offs are usually used to elevate the rails above the roof to allow proper ventilation to meet the design criteria. Stand-offs come in different lengths, and designers choose the best length based on the application and ambient temperature.

Tile Hooks

Roofs come in different shapes and materials. In the case of ceramic tile roofs, roof tile hooks can be directly used as roof attachment equipment that allows the rails to be fastened to the roof by going underneath the tiles. Tile hooks provide roof ventilation, as they are designed to be elevated from the tiles.

Roof Mount (without roof penetration)

PV systems can use S-5 clips or applied weight (i.e., sand or concrete) to fasten the rails to the roof. Let's elaborate on each type:

S-5 clips

In order for a PV array to be fastened to a metal roof (flat or tilted), manufacturers have developed solutions to allow rooftop installation without roof penetration. This solution includes an innovative clip that is called "S-5" and bites from one side of the metal roof. The other side will be fastened to the rails of the PV array. This solution minimizes the use of equipment grounding since the frame metals are directly connected to a metal structure. Designers should consult with the manufacturer's recommendations for grounding requirements when using these clips.

Applied Weight

Another solution to allow rooftop installation without roof penetration and is done using weight that holds the array to the roof. The applied weight can utilize sand or concrete, based on the design. Designers should take into account the roof age and the maximum allowed weight of the roof in order to accommodate the additional weight of the PV array. In some cases, the PV array's structural design needs to be reviewed by Professional Structural Engineers to ensure the structure can handle the additional weight.

Ground mount/Pole Mount

Reinforced concrete bases are usually used for ground and pole mount systems, with steel structure attached to the rails. In some cases, the PV array's structural design needs to be reviewed by Professional Engineers to ensure the structure can withstand dynamic loads based on the location and wind speed.

The main goal of the PV system is to deliver the energy generated from the sun to the load or the grid, depending on the application. This cannot be achieved without the use of complementary components to allow the current to pass through the circuit. There are multiple electrical BOS components such as conductors, conduits, combiner boxes, protection devices, disconnects, grounding conductors, monitoring devices, and other electrical needed components. These components should be chosen to minimize electrical system losses, and at the same time, to withstand the operating conditions.

In this section, we will focus on the electrical BOS components and their functions as part of the PV system.

In the Electricity Basics section (before we began the course), we learned that conductors are needed to allow current to flow in the circuit. Since we have DC and AC circuits in the PV system and outdoor and indoor installation, we need to consider different properties for each conductor we choose.

Conductors

The conductor insulation should be rated to withstand high temperature and sunlight, since modules are installed outdoors. The main goal is to protect the bare conductor from coming into contact with personnel or equipment.

There are two types of wiring for PV circuits.

1: PV source-circuit wiring

This refers to the wires connecting the PV modules all the way to the combiner box, where stringing of modules are combined. These wires are usually located outdoors and are exposed to UV sunlight, extremely high temperature (90℃ or 194℉), and in some cases, they are exposed to moisture. Examples of insulation types recommended for these installations include USE-2 and PV WIRE.

2: PV output-circuit wiring

This refers to the wires passing through conduits, and they connect the combiner box with the DC disconnect. These cables are still installed outdoors, but they don’t have to be rated to withstand the same extreme conditions that the PV source-circuit wiring experiences. Due to costs associated with PV source-circuit wiring, it is recommended to transition to lower rated wires such as RHW-2, THW-2, THWN-2, and XHHW-2 that still need to withstand the same high temperature without having to be sun resistant.

Interior wires:

When wires enter a space or a temperature controlled environment, it is better to transition to NM, NM-B, or UF types. It should be noted that all interior conductors need to be in metal conduits or enclosures and rated to withstand fire.

Battery wires:

These wires are rated to withstand moisture and must be listed for hard-service use. It is also recommended to have them flexible for easier use. USE, RHW, and THW are commonly used types for battery wiring.

PV Wires

Most modern PV modules come with wires that connect the semiconductor terminals to the outer circuit. This allows current to follow to loads through a protective enclosure, located on the back of the PV module, called the junction box, as illustrated in Figure 5.5. As we can see, the junction box is the interface between the module and the wires. It consists of an outdoor rated plastic box, bypass diodes, and screw terminals for the wires. The junction box is also rated for outdoor operating conditions and must be weather sealed to prevent dust and moisture from building up.

Figure 5.5: PV Module Junction Box

Credit: Junction Box of Solar Panel / Elvis untot / CC BY-SA 3.0

The wires coming out of the junction box are rated for outdoor conditions. Usually, they come with secured terminals, also known as module connectors, such as MC4, as shown in Figure 5.6. We can see that these plugs are weather sealed and also provide safety measures.

Figure 5.6: PV Module MC4

Credit: MC4 Connector / Multi-Contact AG / CC BY-SA 3.0

Combiner Box

The second main electrical BOS is the combiner box, which combines multiple PV strings into single circuit, as seen in Figure 5.7. Combiner boxes should be rated for outdoor applications and should withstand extreme weather conditions. There are usually screw terminals that apply compression force to secure wire terminals and ensure low resistance at the connection points, inside the combiner box. Lugs can be also used with compression force at the wire terminal. Lugs can have a ring or fork shape to make connections look much cleaner and to make them easier to manage. Protection devices such as Fuses can also be installed inside the combiner box for protection purposes.

Figure 5.7: Solar Combiner Box

Credit: Solar combiner box / cocreatr / CC BY-SA 2.0

Disconnects

At the entrance and exit of the power conditioning unit, we need to be able to disconnect the current for maintenance work or commissioning procedure. That is usually done using DC disconnect and AC disconnect. In some cases, either or both DC and AC disconnect come as part of the inverter in a built-in device, as shown in Figure 5.8. It can be seen that the inverter has a box attached to the bottom of it with a hand switch that represents the disconnects. In both cases, disconnects need to be rated for the extreme outdoor weather conditions. DC disconnected can also have protection devices such as Fuses or Overcurrent Protection Devices (OCPD). We can also see in Figure 5.8 that the utility requires a separate AC disconnect after the utility meter. This disconnect is a manual lever handle type.

Figure 5.8: PV Inverter, Meter, and Disconnect

Credit: Vermont Law School 9.36 kW solar panel array power panel / SayCheeeeeese / CC0 1.0

Conduits

Conductors are better protected if they are run through conduits, raceways, and wireways for damage protection and safety precautions. As can be also seen in Figure 5.8, all conductors between the combiner box and the utility disconnects are usually run through conduits.

Conduits can be made of different material types, including:

Metal

• Rigid metal conduit (RMC) is a thick-walled threaded tubing, usually made of coated steel, stainless steel or aluminum.
• Electrical metallic tubing (EMT), sometimes called thin-wall, is commonly used instead of galvanized rigid conduit (GRC), as it is less costly and lighter than GRC.
• Intermediate metal conduit (IMC) is a steel tubing heavier than EMT but lighter than RMC.

Non-Metal

• PVC conduit is the lightest in weight compared to other conduit materials, and usually lower in cost.
• Rigid nonmetallic conduit (RNC) is a non-metallic, unthreaded smooth-walled tubing.
• Electrical nonmetallic tubing (ENT) is a thin-walled, corrugated tubing that is moisture-resistant and flame retardant.

Grounding conductors

PV systems need to be grounded to protect people and equipment from electrical hazard and equipment damage. The equipment grounding conductors (EGC) and grounding electrode conductors (GEC) and rods are considered part of the electrical BOS. In special cases, PV systems need to be protected from lightning. That is also done through a special grounding electrode connected to the ground in order to drain the lightning current.

This week, you will complete the Peer Review portion of the Procurement Report assignment.

Wrapping up the trade show scenario we started, by now you can define and choose all types of mounting structures whether they are roof mount, pole mount, or ground mount system. You can also choose the required mechanical and electrical BOS for a perfect PV design and run the required load calculations for the racking structure based on the manufacturer's datasheets.

Whether you work for a solar firm or your own business, you can easily make the best selection of components for the entire PV system. Furthermore, you can suggest the optimal solutions for each PV system type based on the properties of the location of the system.

In the next lesson, we will take a detour to visit one of the main concepts when we design PV systems, which is system sizing for both grid-connected and stand-alone PV applications.

In this lesson, we will find answers to these questions, and we will discuss topics ranging from load analysis to PV system design. This lesson prepares solar professionals to become PV system designers. Sizing PV systems is similar to art, where using the right tools ensures the PV system is sized to function properly.

Learning Outcomes

At the successful completion of this lesson, students should be able to:

• Compare sizing strategies and methodologies for different PV system types.
• List factors that affect sizing a PV system.
• Calculate load requirements for different PV system types.
• Apply tools for sizing grid-connected and stand-alone PV systems.

In previous lessons, we learned about PV modules, batteries, and inverters in terms of performance characteristics and main parameters. At this point in the class, we will introduce the concept of sizing PV systems. System sizing involves the detailed calculations of the energy produced by the PV system and matches it with the desired energy demand. We will put the knowledge we learned together, in addition to introducing some sizing tools that can be used to determine the exact number of modules needed to form a PV array. The main parameter that PV designers name as a goal when designing a PV array is the load energy demand or energy usage in (kWh).

When describing a PV system in terms of components, it is logical to use the energy flow path from the array side to the load side. However, when sizing a PV system, it is necessary to consider the energy demand before considering the PV supply side. For that reason, PV system sizing starts at the load side and proceeds backward to the PV array side. For example, PV designers need to know the energy usage (kWh) before choosing the PV array size.

Limitations to sizing

Not all clients/sites are ready to accommodate PV arrays. That can be due to one or more of the following factors:

• Factor 1: Space availability for the PV array (roof square footage/meter)
• Factor 2: Owner’s budget
• Factor 3: Annual energy consumption (client's energy bill in kWh)

PV systems are generally sized to maximize the solar utility for a client within these aforementioned limits. For the purpose of this class, we will focus only on the last factors that influence the sizing of any PV system. Before diving into the energy demand, let's elaborate more on these factors.

Factor 1: Space availability for the PV array (roof square footage/meter)

Before installing a PV system, it is important to make sure that the site is suitable for installation by considering the following factors:

• Shade-free (Sites are best optimized when there is no shading on the PV array.)
• South-facing (In the Northern Hemisphere, the sun path is generally leaning towards the south. The opposite applies to the Southern Hemisphere where the sun appears to be towards the north of an observer.)
• No obstruction (Sites need to have minimum obstructions before installing PV arrays. Obstructions may include chimneys, gables, HVAC units on rooftops, and so on.)

Factor 2: Owner’s budget

Budget is an essential factor that plays a huge role in the design process. It varies with available rebates and incentives at each location. As we mentioned previously, this class will not consider the finances of PV systems, as it is covered in other RESS classes.

Factor 3: Annual energy consumption (client's energy bill)

When sizing a PV system, It is important to consider the following criteria:

• PV system size to meet 100% of client's annual energy usage kWh
• PV system size to be permissible by utility interconnection rules

In the next topic, we will discuss how annual energy demand is estimated and how to go about understanding the client’s energy bill.

As the name implies, the energy can be estimated at different levels, and that depends on the application intended.

For example, Grid-connected PV systems are more flexible to solar energy intermittence, since the utility grid is used as a backup source when more energy demand arises. With Stand-alone PV systems, since energy is delivered instantaneously to the load without utility grid backup, the load requirements are less flexible to energy supply. That is a consideration when sizing PV systems.

For all PV systems, the main sizing factor is energy consumption. That can be estimated or calculated depending on the energy data availability. The following scenarios summarize types of data provided to the PV designers before sizing the PV system:

1. If the client can provide 12-month energy bills, the designer can then evaluate these bills to come up with the average monthly energy consumption and total annual energy consumption.
2. If the client doesn’t have all 12 month bills but he/she can provide energy bills of some months, the designer should come up with a creative way to estimate the total annual energy based on the provided data.
3. If the client doesn’t have any energy bill records at all, the designer should then run the estimation based on the client’s energy loads to come up with the total annual energy consumption. That is referred to as load analysis, and it will be discussed in this topic.

Energy Estimation

As seen earlier, energy estimation can be as easy as reading an energy bill, or it can be as challenging as running a load analysis. How do we go about it in either case?

Analyzing Energy Bill:

The total energy consumed can be calculated by using all monthly energy bills (in kWh) for the entire year. This is considered the most accurate method to estimate the average monthly and total annual energy consumption based on real data provided by the client. However, this method doesn't provide consumption detail such as daily energy demand or hourly energy demand, since the energy readings on the monthly bill are usually taken once a month.

Load Analysis:

In order for a designer to learn more about the daily or hourly energy demand of a property, more detailed calculations are required to achieve that task, and that is typically done at the load level. The hourly and daily consumption can be measured for any property; however, this method requires using energy analyzing devices at the meter side for a significant period of time. This method will generate the most accurate energy consumption data. However, it requires more time and budget.

Since power demand is usually stated on the rating of each device/appliance individually, there should be an easier way to estimate daily energy demand. We learned in "Electricity Basics" in the Orientation that power is not the main sizing parameter. Since the same load can consume zero energy if it is turned-off, or it can consume a lot of energy when it is turned-on for a long period. Energy consumption is based on the power demand over a period of time.

Since most loads don’t run continuously for the entire day, operating time is another parameter that should be considered when estimating the total energy consumption of a device.

When running load analysis calculations, it should be noticed that there are two types of loads:

1. AC loads that requires AC power to run. (Note: this is what most of our loads are.)
2. DC loads that can be run directly from the PV system.

Power generated from the PV array is DC power, and in case there are AC loads, power conditioning units are used as described in previous lessons. Since PCU is not 100% efficient, it will consume some energy. That should be added to the load analysis as an additional energy usage. The energy consumption of an inverter is estimated by its conversion efficiency.

Grid connected systems, or utility interactive system design, is very straight forward. We saw an example of PV sizing when we did the basic simulation exercise in Lesson 1, when we learned about PVWatt and SAM software. As can be noticed, PV annual energy production varies according to the location of the system that is provided by the solar radiation resources of each specific location. These systems are usually designed to either meet 100% of the annual energy demand of the load, or only to offset a percentage of the energy usage that the client desires.

Sizing Considerations

Consideration 1: Module Selection

Modules can form strings, as we learned in Lesson 2. In this case and after we size the system, it is important to find the required number of modules as follows:

Array Watts / Module = Number of modules

Some array size may be slightly different from the calculated system size due to the availability of modules sizes:

Designers should consider the derate factors of the module when sizing a PV array, such as: modules’ power tolerance, power degradation with time, temperature coefficients that lower the power of the module, and array wiring mismatch.

Consideration 2: Inverter Selection

As discussed in Lesson 4, inverters vary by voltage ranges and efficiency. Designers should consider inverter efficiency and MPPT efficiency when sizing PV systems.

Consideration 3: Site

Designers should account for any environmental factors that may contribute to losses in the PV array when sizing the system, such as soil, snow factors, or shading losses.

Critical design analysis

A PV system cannot generate constant energy for the entire year, but a stand alone PV system should be able to supply loads during any month of the year, and since solar energy generation varies by month, a PV designer should take into account the critical design value for the PV system. For example, if the application requires more energy during the winter, where low insolation occurs, then the PV system should be sized to meet the load requirement of that specific month or season.

Critical design month:

When the PV system needs to meet different load requirements throughout the year, the month with the highest design ratio is referred to as the critical design month. It is taken into account the worst-case scenarios associated with the lowest insolation and highest load demand. We can analyze this design ratio at three tilt angles: Latitude, Latitude +15, and at Latitude -15 degrees. As we said, the highest ratio value will be the critical ratio and the month associated with it is the critical design month. 

Considerations:

Since array orientation has a significant impact on generated energy, the orientation should be chosen to match the critical design month. For example, if a 15° tile produces more energy during the critical design month when compared to a 25° tile, a designer should consider the 15° to optimize the system design as long as it doesn’t affect other design months' values. The cost associated with the lower tilt is another factor to take into account when selecting the racking materials.

System design voltage

PV system DC voltage link is determined by the battery bank in stand-alone systems. As we discussed earlier, battery voltage can be 12V, 24V, or 48V. The voltage level changes depending on system size. As a rule of thumb, small PV systems are usually 12V systems, and larger systems are preferred to be 48V to handle more current. Some very large systems can be 120V, but that is considered a special case.

System Availability

Since the solar irradiance is not always available, stand-alone systems need to be sized to meet load demand for the entire year, and that is expressed by system availability, which is the percentage of time that a stand-alone system can meet the load demand within the period of a year. It is determined by isolation and autonomy. Autonomy is the amount of time the load will be supplied from the battery bank by itself, and is expressed in days. For example, 95% availability (3 days of autonomy assuming PSH is around 5.0 for that location) means that the system cannot meet the load demand for 5% of the time.

Battery Sizing

After we learned in Lesson 3 about the main parameters of batteries, we established that batteries are used to store energy for later use. A stand-alone system is a perfect application.

Battery bank required output capacity

Considering the daily energy demand during critical design month and desired days of autonomy, the batteries should be able to provide energy to the load for all of the autonomy days.

Battery bank rated capacity

As we established in Lesson 3, no battery can be completely discharged, and that is referred to as allowable DOD that a battery cannot exceed. It ranges from 20%-80% depending on battery type. Also, the operating temperature affects the available capacity the battery can deliver. Low temperature with high DOD can reduce the available battery capacity. Finally, the discharge rate is a main factor that determines the available battery capacity at certain temperature. This is expressed as a derating factor to the available capacity.

Array sizing

A PV array should be sized to supply enough energy to meet the load demand at the critical design month while accounting for the system losses. This will ensure that system availability is high, and the battery bank is charged.

Rated array output

Similar to grid-connected systems, array size can be determined using the peak sun hours of the location. However, since we have different DC system voltage depending on the system, it is more desirable to calculate the array current. Furthermore, off-grid systems include batteries. These batteries are not 100% efficient, so this should be taken into account.

There are factors that reduce the output of any PV array.

In this lesson, we covered a variety of topics starting from different methods to estimate energy demand, including use of energy bills and detailed load analysis. By now you can assist your client in the scenario by providing an accurate PV system sizing taking into account factors that affect the energy output for both grid-connected and stand-alone systems. Furthermore, as a designer, you have the right tools to optimize your stand-alone system design by choosing the right critical design month and parameters.

In the next lesson, we will focus on the standards and regulations that govern PV system design and installation, such as building, fire, and electrical building codes.

In this lesson, we will discuss topics starting from building, fire, mechanical, and electrical codes, and then we will finish with the inspection requirements for PV systems. Whether you are a PV designer or installer, it is important to familiarize yourself with various codes and regulations to efficiently work on PV systems at different scales. We will also see that codes apply to all PV scales, starting from small residential systems to large scale PV plants.

Learning Outcomes

At the successful completion of this lesson, students should be able to:

• Identify relevant electrical and building codes that govern PV systems at various locations.
• Discuss standards and design qualification testing that help ensure the safety and reliability of PV system components such as UL, local, and national electrical code NEC articles.
• Identify important warning signs and equipment labeling, notes, and other safety requirements associated with PV systems.
• List design guidelines, drawing, and documentation requirements and methods.

In previous lessons, we briefly discussed applicable codes that apply to PV components such as Underwriters Laboratory (UL) and IEEE, which are the manufacturer's responsibility before they sell the final product.

In this lesson, we will elaborate more into different standards that are beyond the standards specific to PV components. If we zoom out a little to view the overall PV system, we see that there are various regulations and standards that need to be met before installing a PV system in the U.S. PV market.

There is a collaborative effort funded by international and local agencies (such as the U.S. Department of Energy) that dedicates experts to transforming solar markets by developing building codes, fire codes, electrical codes, utility interconnection procedures, product standards, reliability, and safety. In addition, a part of their overall strategy is to reduce barriers to the adoption of solar technologies and to stimulate growth in different marketplaces. There are various codes, standards and regulatory requirements applicable to PV installations. We will not address the content of most of these codes. However, we will help you become familiar with these organizations and main codes and standards that are most relevant to this course.

It is important to mention that most of the codes and standards, listed in this lesson, have been adopted in various states. However, some states are still working on adopting them, while others prefer to have a local city code. It is wise to consult with the city where the PV system will be installed to assure complying with the right local codes.

Building codes

The International Code Council (ICC)

ICC is an international organization that develops a set of comprehensive international model construction codes focused on building safety and fire prevention. Many ICC Codes (AKA I-Codes) have sections relevant to PV installations, including:

The International Building Code (IBC):

IBC covers all types of buildings, except the detached one and two family dwellings and townhouses that don’t exceed three stories in height. The IBC includes requirements for the fire class rating of PV systems, and it contains wind load calculations (as we briefly discussed in Lesson 5 when we talked about BOS structural calculations).

International Residential Code (IRC):

IRC establishes minimum regulations for one and two family dwellings and townhouses up to three stories in height that are not addressed in IBC. It brings together all building, plumbing, mechanical, fuel gas, and energy and electrical provisions, which include PV systems for one and two family residences.

International Fire Code (IFC):

IFC includes regulations governing the safeguarding of life and property from all types of fire and explosions hazards, which include PV systems. IFC addresses topics include general precautions against fire, fire department access, and fire safety requirements for new and existing buildings and premises. The IFC includes requirements for PV labeling, access and spacing, and the location of DC connectors and other. It is considered the most relevant to rooftop PV installations.

International Green Construction Code (IGCC):

IGCC is a model code focused on new and existing commercial buildings. It addresses green building design and performance to establish minimum green requirements for buildings. This code is related to the grading of buildings rather than safety regulations, as the previous ones do.

International Code Council Evaluation Services (ICC-ES)

ICC-ES involves technical evaluations of building products, components, methods, and materials. The evaluation process culminates with the issuance of technical reports that directly address the issue of code compliance and are useful to regulatory agencies and building-product manufacturers.

Mechanical Codes

IAPMO Codes and Standards

The International Association of Plumbing and Mechanical Officials (IAPMO) works with government and industry to implement comprehensive plumbing and mechanical systems all around the world. There are many IAPMO codes and standards that pertain to PV installations.

Electrical Codes

International Electrotechnical Commission (IEC)

The International Electrotechnical Commission (IEC) publishes international standards for all electrical, electronic and related technologies. The United States formed an IEC National Committee (USNC) to oversee the country's participation in IEC activities, and that is governed by the American National Standards Institute (ANSI). The IEC promotes international cooperation on all questions of standardization and the verification of complying to standards, and often serves as the basis for national standardization and as a reference when drafting international tenders and contracts. The IEC standards include all electrotechnologies, which also includes PV systems for energy production and distribution.

Institute of Electrical and Electronics Engineers (IEEE)

The Institute for Electrical and Electronics Engineering (IEEE) Standards Association publishes hundreds of industry-driven consensus standards in a broad range of technologies and applications, including photovoltaic (PV) systems and the integration with the utility grid. The IEEE global outreach drives the functionality, capabilities, and interoperability of a wide range of products and services.

National Fire Protection Association

The NPFA 70: National Electrical Code (NEC) developed by National Fire Protection Association (NFPA) issues the National Electrical Code® (NEC), the Uniform Fire Code, and other codes. The NEC is updated and published every three years and is considered to be the most comprehensive electrical safety installation requirements document in the world. Published by the National Fire Protection Association, the NEC is over 115 years old with 50+ editions and over 800 pages and articles. The first PV related article was added to the NEC in 1984 (Article 690) and is legislated into law by all states and most major cities in the US and some international places.

There are many articles of the NEC referenced in Article 690 that apply to PV installations. Whenever the requirements of Article 690 and other articles differ, the requirements of Article 690 apply.

Testing and Material Related Codes

ASTM International

ASTM International, also known as the American Society for Testing and Materials (ASTM), is an organization that develops international standards with a goal to improve product quality, enhance safety, facilitate market access and trade, and build consumer confidence. The ASTM has tens of standards that pertain to PV technology.

Underwriters Laboratories

As discussed earlier, Underwriters Laboratory (UL) develops safety standards, including standards for PV related products. UL's standards are essential to helping ensure public safety and confidence, reduce costs, improve quality, and market products and services. Most products in the U.S. undergo UL testing and listing credentials.

As we can see, finding the solar and PV related local and international codes can be a tedious task due to the variety of engineering disciplines involved in solar systems. Therefore, as a combined effort, ICC provisions coordinated and developed a model code to bring together all solar energy provisions found throughout the 2015 ICC (or I-Codes) that pertain to solar thermal and PV energy systems. As a result, ICC published the International Solar Energy Provisions (ISEP) that simplify the implementation of I-Codes in the jurisdiction where solar and PV systems are to be installed. Furthermore, since most PV system include electrical components and systems, NFPA 70 or NEC related articles are integrated into the ISEP 2015.

The ISEP is organized in chapters with related topics, and it differentiates between commercial and residential applications. You can also notice cross-references between I-Codes within the ISEP chapters. In additions, ISEP references other standards across the chapters, such as ASTM, IBC, IFC, IRC, NFPA 70 (NEC), and UL.

Let's look at an example:

If you are designing a PV system in a jurisdiction that approves international (I-codes), the ISEP 2015 will become handy to find related PV code sections such as LBC, IFC, and IRC code sections. Designers need to pay attention to the system installation type considerations to comply with these codes. For example, below we have two scenarios of PV systems:

We saw in the previous example that the ISEP adopted IFC 605 for electrical equipment, warning, and hazards. In addition, the National Fire Protection Association NFPA 70 (NEC 690) and International Fire Code (IFC 605) both require that marking is needed to provide emergency responders with appropriate warning and guidance with respect to isolating the solar PV system. This helps in identifying energized electrical lines that connect the solar modules to the inverter to prevent cutting these wires when venting for smoke removal.

Materials used for marking should be able to withstand extreme weather conditions. Different materials can be used for warning signs. Vinyl signs need to meet UL requirements, while plastic and metal engraved signs do not need to meet any UL standards.

In rare cases, fire can be caused by solar modules. An example of this occurred in a residential application in New Rochelle, NY. Complying to marking and labeling code requirements can help firefighters find the energized circuits in the property and disconnect the power to safely work on the property.

Labeling is required at certain locations in the electrical PV system, such as:

1. PV modules labels: usually provided by manufacturers and has main electrical parameters such as current, voltage, and power.
2. Disconnect labels: Either AC or DC sides, all disconnects need to be labels and visible. Labels must include maximum current and voltage. For PV systems, labels need to list the operating voltage as well. In addition, a warning sign needs to be placed on disconnect where terminals may remain energized in the open position.
3. Point of connection labels: This is specific to interactive systems. A label needs to be located at the point of interconnection and must identify the interconnection utility service.
4. Other energy source labels: For any other energy source, such as batteries, labels must indicate the maximum operating voltage and polarity of a DC system.
5. Grounding labels: Whether the system is grounded or ungrounded, labels must identify the ground-fault current and a warning signage stating the grounded system may be ungrounded and energized.

As mentioned in the overview of this lesson, in addition to the aforementioned codes, local jurisdictions and municipalities can amend and change some codes to some extent. Local municipalities have final jurisdiction and authority for projects, so communicating with your Authority Having Jurisdiction (AHJ) and understanding permit requirements is going to be an important element of your job as a PV designer and installer.

Permitting and inspection

For most PV systems, permits are required from the building department, electrical department and, perhaps, fire department in some cases. The permits are important to ensure code compliance for a functional PV system.

After the permits are granted, installers and integrators can start the installation process. Upon the completion, an inspection should be scheduled to ensure complying with the design and installation standards. Inspection is usually done for the structural and electrical parts of the systems. Integrators will need to verify with their AHJ.

Design Requirements

Any solar design needs to meet certain requirements to function properly. The city, utility, or AHJ might request a design package that complies with national and local standards. This may include:

1. The conceptual package showing the overhead of the location of the PV system and the utility interconnection point. 
2. The one-line and three-line electrical drawings showing how the electrical connection between components is done and check electrical code compliance, such as NEC.
3. The mechanical and structural design showing the load on the PV array and the holding structure.
4. Warning and signage that labels main parts of the PV system and provide guidance to utility personnel.
5. Bill of material showing quantity and type of components used for the project.
6. Official stamps by Professional Engineers (PE) for the electrical, mechanical, or structural documents (if needed).
7. The specification datasheets for the main PV components.

Let’s go back to the scenarios from the beginning of this lesson, where you need to prepare the required documents for permitting to get approval on your PV system design before you start the installation process. By now, you should understand that PV installations involve different building, fire, mechanical, and electrical codes and standards. Furthermore, you learned that your local city may adopt the national and international codes with slight variation. You need to consult with your local AHJ to insure you are complying with the requirements of the location.

In the next lesson, we will zoom into the NEC code and discuss the various articles that are in concern to us as PV designers to insure a safe and functional PV system.

In this lesson, we will train our PV designers to perfectly interpret the NEC articles that pertain to PV systems, and we will walk them through sizing and calculation processes to address the design issues mentioned earlier. Learning about NEC articles allows better understanding of the PV system as it integrates with other electrical systems. The knowledge available in this lesson is of interest to a wide range of audiences including designers, business owners, installers, or inspectors.

Learning Outcomes

At the successful completion of this lesson, students should be able to:

• Identify applicable fire and safety regulations affecting PV design and installation.
• Compare theories and practices for overcurrent protection and arc-fault protection.
• Calculate the voltage and current limits for various circuits of PV systems.
• Determine appropriate conductor ampacities and overcurrent protection ratings and types of conductors used for PV applications.
• Identify grounding requirements and electrical grounding methods.

We learned in the previous lesson the importance of the electrical codes, and of the NEC in specific, to govern PV design and installation processes. NEC articles cover installation regulations for all PV installations including systems with less than 50V, utility-interactive systems, and stand-alone systems including billboards, remote installations, and RVs.

Terminologies

There are specific terms used for PV system components and circuits. The NEC differentiates between a PV power source and a PV source circuit for PV systems.

A PV power source is an array or collection of arrays that generates DC power.

A PV source circuit is the circuit connecting a group of modules together and to the common connection point of the DC system. PV source circuits are usually a string of series-connected modules. For small systems, the PV power source is usually only one source circuit. For larger systems, the PV power source is usually composed of several paralleled PV source circuits.

A PV output circuit is the circuit connecting the PV power source to the rest of the system.

Figure 8.1 illustrates the proper use of these terminologies and how they relate to each other in the PV system. The three strings of nine total PV modules that form an array are referred to as a PV power source, while each string of three PV modules is referred to as a PV Source Circuit. In this case, the PV system has three PV Source Circuits. As the conductors exit the PV array and are joined together in a combiner box, they form a single power source that links the inverter with the combiner box at the DC side of the PV. This is the PV Output Circuit.

Figure 8.1: PV Power Source

Credit: Mohammed Amer Chaaban

As we learned earlier in previous lessons, the maximum possible voltage is the array’s open-circuit voltage measured at the lowest expected temperature for the specific location (the lowest record temperature). There are two main methods for PV professionals to determine the maximum voltage of a PV array.

Method 1

As we learned in Lesson 2, the voltage can be calculated using the PV module manufacturer’s temperature coefficient for voltage. Temperature information is usually gathered from weather stations for each location.

Method 2

The voltage can be easily identified using an NEC correction table, depending on the ambient temperature ranges of the location. The NEC provides a temperature correction factor found in table 690.7. The factors of the NEC table make calculations for estimating the maximum voltage as easy as multiplying the string voltage by a single number.

Conductor Sizes

Conductor sizes are expressed in American Wire Gauge (AWG). Usually, larger diameter conductors have smaller AWG numbers. There are two types of conductors, either solid or stranded. Solid conductors consist of one solid core metal conductor that is usually ridged. On the other hand, stranded conductors consist of multiple smaller conductors stranded together and are usually more flexible. Stranded conductors are ideal for PV source circuits, facilitating module removal for servicing, or junction box access.

Conductor Ampacity

Conductor sizing is based on a conductor’s ampacity rating.

Ampacity is the current that a conductor can carry continuously under the conditions of use without exceeding its temperature rating.

According to the NEC, nominal conductor ampacity at 30°C is determined by the conductor material (copper or aluminum), size, insulation type, and application (direct burial, conduit, or free air). In NEC, table 310.15(B)(16) (formerly 310.16) is used to look up the ampacity rating for any conductor.

Ambient Temperature Derating

Temperature affects conductor’s ampacity; nominal ampacity is derated (reduced) when ambient temperature is higher than the nominal 30°C. Temperature-based ampacity correction factors can be found in NEC table 310.15(B)(2)(a). The correction factor is then multiplied by the nominal ampacity (found in table 310.15(B)(16) to calculate the derated ampacity. Therefore, for a certain current-carrying capacity rating, the size of the required conductor must be increased to account for higher temperature deratings.

Number of Conductors Derating

Since most PV systems consist of multiple PV source circuits that run to the combiner box, more than three current-carrying conductors can be run together in a conduit or a raceway for longer than 24′′. In this case, conductor ampacities must be further derated by an additional correction factor that can be applied to the temperature-corrected ampacity using NEC table 310.15(B)(3)(a), where designers can look up the corresponding ampacity correction factor based on the number of current-carrying conductors.

For example, if USE-2 conductors are used for three PV source circuits and are run through a conduit, each with positive and negative conductors, the total is six current-carrying conductors. The correction factor from the NEC table is 0.80.

PV module electrical connections are usually installed with full exposure to extreme temperature, sunlight (UV), and precipitation. PV conductors need to be rated for outdoor applications with high temperature, moisture, and sunlight resistance. Insulation types UF, SE, USE, and USE-2 are permitted in PV source circuits, provided they have the necessary weather resistances. Single-conductor USE-2 is recommended because it has high temperature, moisture-resistance, and sunlight-resistance ratings, and is widely available. In the NEC, table 310.15(B)(2)(c) is used for ambient temperature increment due to conduits being exposed to sunlight on or above rooftops.

Conductors and color codes

Since a PV system is a mixture of both AC and DC systems, conductor color codes are similar to any other electrical system with each side of the system. For example, when we look at the DC side of the PV array, we should consider applying the DC color code. Once we exit the inverter, the color code of conductors should comply with the AC color code of electrical systems. Below are main considerations for the color codes of conductors.

• Grounded conductor must be white, gray or have three stripes, not green.
• Module frame ground must be bare or have green or green with striped insulation or identification.
• Grounded conductor is the negative conductor (white). No NEC requirement for ungrounded conductor. Use AC convention Black and Red.
• In two wire negative-grounded PV system, the positive conductor could be red or any color with red marking, except green or white.
• In a three-wire, center-tapped system, Positive conductor Red, center tap conductor must be white, and the negative conductor could be black

PV Circuit Current Requirements (sizing, protection)

As instructed in NEC 690.8 Circuit Sizing and Current, the wires from the PV modules to the inverter must be able to carry 156% of the short circuit current (I_sc). This 156% comes from multiplying 125% twice; the first 125% accounts for the continuous duty that is used as a safety factor, whereas the second 125% is a factor that accounts for the extra current that PV modules might deliver. This current, that is higher than the rated short-circuit current of PV modules, can be generated when the solar irradiance exceeds 1000 W/m². Therefore, the maximum output current is derated by a factor of 125% x 125% or 156%.

Circuit current is the sum of the parallel source circuit's maximum current, as calculated in 690.8(A)(1). This applies mostly for central inverter configuration.

PV Source Current [690.8(B)]

The maximum PV source circuit current is 125% in addition to 125% of the short circuit current. In our example, if a PV module has Isc of 8.60 A
$I_{\max }=I_{sc}\times 125\%\times 125\%=8.6\times 1.56=13.44A$

Conductor Sizing [690.8(B)(1)]

Conductor size is chosen to be the smallest size that can safely conduct the maximum conductor current of a circuit (Imax). As discussed previously, the maximum current that the PV system can generate is 156% of Isc. That means the conductor must carry this amount of current.

Definitions

Voltage drop is defined as the amount of voltage loss that occurs through all or part of a circuit due to conductor resistance.

Conductor resistance is determined by conductor material, size, and ambient temperature.

Voltage drop highly depends on the total length of conductors that carry the electrical current. In DC systems, the voltage drop length is the total (round-trip) distance that current travels in a circuit. So the total length used in calculations is usually twice the length of the conductor run. In some AC systems, the distance equals the length of the conductor.

Voltage drop from PV array to inverter

NEC doesn’t require the calculation of voltage drop because it’s not a safety issue. However, it does recommend a maximum voltage drop of 3%. It is recommended to have up to 2% voltage drop at the DC side while only 1% is accepted at the AC side of the system for a total of 3% in voltage drop for the entire system.

Wires should be sized to reduce resistive (heating) loss to less than 3%. This loss is a function of the SQUARE of the current times the resistance, which is another manifestation of Ohm’s law:

$V=I\times R$, or,

$I=V/R$.

And the resistive loss is $I\times I\times R$ in Watts.

Overcurrent Protection Devices (OCPD)

Overcurrent protection devices are classified by how quickly they activate. Overcurrent protection devices can include fuses and circuit breakers.

A non-current-limiting device operates slowly, allowing damaging short-circuit currents to build up to full values before opening. An example is a fuse, which is a link that melts when heated by current greater than its rating to provide overcurrent protection due to extra loading.

A current-limiting device opens the circuit in less than one-quarter cycle of short-circuit current, before the current reaches its highest value, limiting the amount of destructive energy allowed into the circuit.

Overcurrent protection devices must be listed and specifically rated for their intended use, such as DC. For example, automotive fuses may not be used in PV systems.

Sizing OCPD

OCPD are highly recommended for PV systems and are sized not to be less than the highest current.

• DC array side
  • Since the derate factor is 156% of the short circuit current of the PV module, the OCDP is sized not to be less than that value, since the 125% factor is included already as part of the calculation.
• AC side
  • At the output of the inverter, OCPD are usually sized to be at least 125% of the highest inverter current possible, provided from the manufacturer’s datasheet.

Disconnects

A disconnect must be provided to open all current-carrying conductors of a PV power source from all other conductors in a building or structure. This disconnect is also known as the DC disconnect or PV disconnect. Disconnects used in the PV output circuit must be rated for DC and identified as such. Equipment such as PV source-circuit isolating switches, overcurrent protection devices, and blocking diodes are permitted on the array side of the array disconnect.

Disconnects Sizing

• DC array disconnect

  • Since the derate factor is 156% of the short circuit current of the PV module, the DC is sized not to be less than that value, since the 125% factor is included already as part of the calculation.

• AC disconnect

  • At the output of the inverter, disconnects are usually sized to be at least 125% of the highest inverter current possible, provided from the manufacturer’s datasheet. In an interactive system, the PV system’s AC disconnect should be located near the main utility disconnect. This facilitates the quick removal of all power to a building or structure in an emergency.
    
    In stand-alone systems, the AC disconnect is typically located near the array disconnect or the AC power distribution panel. Disconnects must be provided to open all ungrounded conductors to every additional power source and each piece of PV system equipment. Other equipment that requires disconnecting means can be inverters, charge controllers, and other major components. If equipment is connected to more than one power source, each power source must have a designated disconnecting means. It is particularly important for battery bank circuits to include a specific DC disconnect.

Grounding

Grounding provides a path for fault current or lightning surges to flow through to protect people and equipment from electric shock hazards.

Equipment Grounding Conductor (EGC)

PV modules mounted to metal racks are effectively grounded when the module frames are secured to and in electrical contact with the rack, and the rack is grounded. However, since the integrity of the electrical contact between the module frames and mounting structure cannot always be assured, individual module frames are connected together with equipment grounding conductors (EGC). This can be accomplished with a few continuous runs of bare conductor that are secured to each module with a special connector, or with many short bonding jumpers between adjacent modules.

When ground-fault protection is used, PV circuit equipment grounding conductors are sized in accordance with Article 250, which establishes the minimum size for equipment grounding conductors based on the overcurrent protection rating in the circuit. NEC table 250.122 is used for sizing. For example, if the PV output circuit overcurrent protection device is 60 A, then a 10 AWG equipment grounding conductor is required. When the sizes of ungrounded conductors are increased above what is required (such as to decrease voltage drop), the equipment grounding conductors must be increased proportionally.

Grounding Electrode Conductor (GEC)

A grounding electrode is a conductor rod, plate, or wire buried in the ground to provide a low-resistance connection to the earth. NEC 690.47 establishes requirements for grounding electrodes used for PV systems. Most PV systems involve both AC and DC systems, and they are considered two separate systems according to NEC article 690 since the DC grounded conductor is not directly connected to the AC grounded conductor.

Array Grounding

Some AHJ may require an interpretation of some NEC editions to include an array grounding in addition to the DC grounding requirements. It is a grounding electrode that is buried in the ground as well.

Ground fault protection

Ground Fault is the undesirable situation where the current flows through grounding conductors. Ground Fault Protection is mentioned in NEC 690.5 and is not required for ground mounted arrays. It is required for PV systems mounted on roofs of dwellings. The ground-fault circuit breaker trips when current between the grounded and grounding conductors exceeds its rating and forces the other circuit breaker to open the ungrounded conductor. For low-voltage PV systems, a pair of circuit breakers can be used to provide array ground-fault protection. For interactive PV systems, ground-fault protection is usually built into the inverter, which includes a serviceable fuse. In order to fulfill the requirement to open the ungrounded conductor, the inverter is designed to immediately shut down if the fuse is opened.

A ground-fault circuit interrupter (GFCI) is a device that opens the ungrounded and grounded conductors when a ground fault exceeds a certain amount, typically 4 mA to 6 mA. It does this by sensing a difference between the current flowing out through the ungrounded conductor and returning through the grounded conductor.

A GFCI device is used in AC branch circuits to protect persons from electrical shock hazards. GFCI protection is often included in receptacles and is required in wet environments, such as bathrooms, with a greater potential for ground faults. Article 210, “Branch Circuits,” provides details and required locations for GFCI devices.

Lightning protection

Because PV arrays are mounted on elevated buildings and structures such as rooftops and poles, many PV systems are protected from potential lightning that can cause severe damage. Lightning protection system requirements are covered briefly in Article 250 and more extensively in NFPA 780 (Standard for the Installation of Lightning Protection Systems). Lightning protection is especially important in places where the probability is high, such as the southeastern United States.

Lightning protection systems consist of a low-impedance network of air terminals (lightning rods) connected to a special grounding electrode system and not connected to the DC or array electrode conductors.

This week, you will begin working on your PV System Electrical Design Project. This will be a two-lesson project.

After discussing PV system main components, system sizing strategies, and building and fire codes that govern the design and installation of any PV system, our design team is ready to dig deeper into the essential electrical code NEC articles to start preparing the required engineering design permitting documents to submit to the utility grid engineering reviewers. This process requires a detailed NEC interpretation of article 690 and 705 and other code articles that pertain to PV systems, as we saw in this lesson.

By now, our design team is one step away from being granted the permit. That missing part is the interconnection requirements by the utility grid where the system will be installed.

In the next lesson, we will discuss the interconnection requirements and methods where they apply to PV systems, and we will talk about some issue related to the interconnection of PV systems such as neutral loading, phase balance, and metering. See you next week!

In this lesson, we will discuss issues related to the interconnection requirements and methods according to the NEC that will answer these questions. In addition, you will be prepared to complete the electrical permitting documents required before the installation process. PV designers and installers need to comply with the interconnection requirements referenced in the National Electrical Code (NEC) and IEEE standards to ensure the systems function properly and avoid safety hazards.

Learning Outcomes

At the successful completion of this lesson, students should be able to:

• Identify grid interconnection codes and standards for distributed generations DG.
• Identify and compare types of grid interconnection methods according to NEC article 690.
• Compare utility requirements for PV System interconnection at different locations in the US and how they affect PV design and installation.

We discussed earlier the value of the utility grid and how it serves as the energy reservoir. Most traditional utility grids are built based on the central generation strategy that entails that the power plant is located somewhere with high capacity to supply loads at different locations through transmission and distribution lines.

On the other hand, Distributed Generation (DG) is a system that generates power near the point of consumption, which is also referred to as the end user. Whether it is a diesel generator or PV array, all power will be injected into the grid system. DG can also be fuel cells, wind turbines, and other sources.

DG systems are becoming a more common supplement to the traditional central power generation. DGs have the advantages of lower power losses since the generation is close to the load, so both customers and utility can benefit from it. Customers can benefit from DG when there are power outages if the DG contains backup storage. Utilities can benefit from DG by expanding its capacity without physically adding new central plants. With these advantages also come some challenges, since the DG can be installed anywhere on the utility grid. Most utilities noticed the importance of assuring a safe and reliable DG interconnection without having any negative impacts on the utility grid - especially the distribution power system. This lesson will discuss some related codes and standards that are important to interconnect DG sources to the utility grid in the United States.

As we have discussed, most PV systems contain power conditioning units or inverters. In addition, in order for any PV system to be connected to the utility grid, there has to be a set of test standards and codes to govern the interconnection process for a safe and reliable power delivery. In this section, we will discuss main interconnection standards that relate to PV systems such as IEEE, UL, and NEC standards. Solar professionals and designers should always look for the most up-to-date standards in this regard and consult with the local AHJ for any additional legislation.

Main Interconnection Standards

IEEE 1547

IEEE 1547 is a standard for interconnecting distributed resources with electric power systems. IEEE 1547 contains a family of standards, guides, and recommended practices. Solar professionals and designers should consult with all series of IEEE 1547 standards.

UL 1741

UL 1741 is the testing standard related to DG equipment such as inverters and charge controllers. It is considered a supplemental standard to IEEE 1547. UL 1741 is important because it is listed in NEC article 690.

NFPA 70 (NEC Article 690)

In addition to the sizing requirements we discussed in Lesson 8, NEC Article 690 requires that all inverters be listed and identified for interactive operation. Most requirements are based on equipment testing under UL 1741. Inverters must meet anti-islanding and disconnect from the grid when voltage is lost, and must remain disconnected until grid voltage is restored to the accepted measure.

Interconnection Technical issues

All DG, including PV systems, introduces additional power at the customer location that has not been planned to exist when it was first designed. With this new addition, some technical issues and difficulties face the utility companies at the interconnection side. Some of these technical issues can be overcome by early adoption of standards, and some are enforced after the systems are installed.

Islanding

Islanding is the undesired condition when the DG source, such as a PV system, continues to supply power to the grid during a utility outage. This may cause a serious safety hazard to utility workers who are exposed to unexpected energized power lines. To prevent damage to personnel and equipment, all grid-bound inverters must be able to detect outages and block power transfer to meet UL 1741 equipment testing standard. Inverters with such capability are referred to as anti-islanding inverters. However, Bimodal inverters may function in stand-alone mode of operation while being disconnected from the utility grid line during outages.

Power Quality

Power quality is a topic that discusses several electrical performance parameters, such as voltage, frequency, and harmonic distortion. Power quality of a grid can be affected by loads and equipment connected to the grid, such as power electronics equipment that operates on discrete modes and causes quality issues, which may damage sensitive equipment or create hotspots in transformers. Since DG sources including PV inverters contain switching devices, most utilities are concerned about the interconnection of PV systems and power quality issues associated with it. For that reason, utilities mandate that all DG interconnected equipment must meet certain power quality limits such as current harmonics, voltage flickers, and other parameters and utilities must continuously monitor these parameters to insure a reliable grid operation.

Neutral Loading

A particular over current problem arises when one stand-alone inverter with a 120 V output supplies a 120/240 V distribution panel. A similar problem can occur with interactive systems of single-phase 3-wire or 3-phase, 4-wire wye configuration when loads are concentrated on one phase more than the other. The single grounded (neutral) conductor can become dangerously overloaded. Therefore, the grounded conductor may carry twice its rated circuit current, and this is a serious concern discussed on NEC 705.95 that requires the sum of the maximum load between the neutral and ungrounded conductor and the inverter’s output rating not to exceed the ampacity of the neutral conductor.

Unbalanced phases

Phase voltage imbalance can occur if a single-phase inverter is connected to a three-phase power system. NEC 690.63 (705.10) doesn’t allow this type of connection unless the voltage imbalance between phases is minimized, not to exceed 3 percent. Another solution is to use three similar single-phase inverters (one for each phase) that are equally loaded.

The point of connection is the location at which the DG source including a PV system can be interconnected with the electric utility grid. Since adding power at that point is beyond the initial intended design of the existing electric system at the point of connection, all service equipment, such as main power distribution panel disconnects and conductors, must be sized and rated to allow this addition according to NEC 690.64.

NEC 690.64 permits the output of the inverter to be connected to either load side (customer side) or supply side (utility side) service points, depending on the size of the PV system and marginal power available at that point. In large a PV system, the available service might not have enough capacity to handle the added power and, in this case, a separate service may need to be installed. A backfeed circuit breaker is a circuit breaker that allows current flow in either direction. The backfeed circuit breaker provides overcurrent protection of the branch circuits from the inverter, and the panel’s main service circuit breaker provides protection of the entire PV and load system from the utility. Regardless of the interconnection type, NEC 705 requires that a permanent directory be placed at each service location showing all power sources for a building.

Load-side interconnection

Common in small PV systems, the main service disconnect at the customer facility has enough margin to handle the extra capacity added by the PV system, and that allowed an interconnection at the load side.

NEC permits that type of interconnection providing the following conditions (we will only mention the technical-related issues):

1. In case multiple power sources are to be interconnected, each added power source (inverter in PV case) must have a dedicated circuit breaker or fused disconnect unless their outputs are first combined at a sub-panel.

2. In the 2011 National Electrical Code (NEC), the language in 705.12(D)(2) is straightforward. Fulfillment of the 120% rule that states that the sum of the rating of the OCPD in all circuits supplying power to a busbar or conductor must not exceed 120% of the rating of the busbar or conductor to prevent overloading conditions. This only applies to breakers that supply the load center with power, including the main utility fed circuit breakers and any back-fed circuit breakers from PV sources (load circuit breakers are not considered)

   Here is what NEC 2014 - Article 705.12(D)(2) code states:

   “Bus or Conductor Rating. The sum of the ampere ratings of overcurrent devices in circuits supplying power to a busbar or conductor shall not exceed 120% of the rating of the busbar or conductor.”

   In the 2014 code, this straightforward sentence has been revised to include several paragraphs with different scenarios. The meaning might look the same, however, and once you understand the philosophy of the simpler 2011 version of 705.12(D)(2) you will be able to understand NEC 2014’s more sophisticated version. It really is the designer’s knowledge to correctly interpret the code, since NEC 2014 provides more flexibility to allow more PV capacity for the same circuit size.

   Here is what NEC 2014 - Article 705.12(D)(2) states:

   • The sum of 125 percent of the inverter(s) output circuit current and the rating of the overcurrent device protecting the busbar shall not exceed the ampacity of the busbar.
   • Where two sources, one a utility and the other an inverter, are located at the opposite ends of a busbar that contains loads, the sun of 125 percent of the inverter(s) output circuit current and the rating of the overcurrent device protecting the busbar shall not exceed 120 percent of the ampacity of the busbar. The busbar shall be sized for the loads connected in accordance with Article 220.
   • The sum of the ampere rating of all overcurrent devices on panelboards, both load and supply devices, excluding the rating of the overcurrent device protecting the busbar, shall not exceed the ampacity if the busbar. The rating of the overcurrent device protecting the busbar shall not exceed the rating of the busbar.
3. Interconnection point to be on the supply side of all ground fault protection equipment.
4. A back-fed circuit breakers in the panelboard shall be positioned at the opposite end from the main circuit breaker and marked with a warning label at the back-fed breaker from the PV system.

Supply-Side Interconnection

For larger installation or in case the load-side strategy doesn’t provide the required capacity, a supply-side interconnection is the second resort for PV systems. NEC article 230 requires any additional new service to have disconnect and OCPD. That said, the supply-side interconnection must include another service in parallel to the existing one with an additional OCPD and disconnect. The equipment and conductors must be rated to accommodate for that additional power coming from the PV system. The interconnection requires tapping the service entrance conductors, and that is done between the existing service panel and utility meter. A new meter might be needed when the service type cannot establish the tapping strategy. The added disconnect must meet local utility standards in terms of accessibility, interrupting rating, and visibility. The service conductor must be sized for at least 125% of the continuous load current, as stated in NEC article 230.

Metering

Metering is required by the utility to measure how much electricity is used by the customers, and it is referred to as revenue meter. These meters are usually installed at service entrances of properties. Since the addition of DG sources will introduce another energy source, it is required to accommodate for that addition by measuring the added electricity based on the facility and DG system size and interconnection policies at the location of installation. This can be accomplished using one of the following methods:

Net metering

Using one meter that can operate in both directions (spins forwards and backwards) to measure the exported energy and subtract it from the imported energy. Some existing meters are capable of operating in both directions without any modifications, while other old meters need to be upgraded by the utility company. Designers and customers should consult with their state rules for the eligibility of the net metering.

Dual metering

In this case and as the name entails, two-meters (unidirectional meters) are required to be present at the facility. This is usually common for larger PV systems. In this case and due to what is referred to as “net purchase and sale” in most places, excess energy produced at the customer location from any DG source can be purchased by the utility at a different rate from the customer rate when the customer buys the electricity. The rate is agreed upon when signing the contract.

Utility interconnection policies

One of the main barriers to the expansion and adoption of PV systems is the utility interconnection policies that are established by federal, state, and local governments. Local utility companies may enforce interconnection policies where other governmental policies are absent.

Public Utilities Regulatory Policy Act (PURPA)

A number of policies have been developed over the past 30 years that impacted the interconnection of privately owned power generation systems at the state and federal levels. In general, PURPA specifies the qualifying facility and agreements to meet certain technical and procedural requirements to be interconnected to the utility grid. PURPA practices are overseen by the Federal Electric Regulatory Commission (FERC), which is responsible for overseeing the electric utility industry in the US.

Interconnection Agreements

Interconnection agreement is a contract between a distributed power producer and electric utility under specific interconnection terms and conditions. Interconnection of PV systems must be approved by the local utility with cooperation of the local AHJ.

The interconnection process begins after submitting an interconnection plan to the local utility along with the system design application for a permit with the local AHJ.

After the permit is granted, PV installation can be completed and then inspected by the AHJ, and utilities in some cases, to approve the interconnection based on national codes and standards. Interconnection documents must include a conceptual system design showing the location of main parts of the systems with distances and the electrical one-line diagrams that show the main electrical calculations for PV system components and interconnection methods, protection devices, and disconnects used. Finally, the system can be interconnected, commissioned, and operated.

Interconnection agreement by utility in most cases mandates that any interconnected DG source including a PV system have liability insurance, system inspection and monitoring, system maintenance, and disconnects on the outside of the facility, so the utility can have access to it at any time.

This week, you will finish up and submit your PV System Electrical Design Project.

Going back to the scenario we started in this lesson, you are working on the electrical design for the same PV system as in Lesson 8. As you complete the NEC design for the PV array, you reach the point of interconnection with the utility grid at the meter side. By now, you know the requirements and methods to interconnecting the PV system to the utility grid. You can review the site evaluation documents provided by the sales team to decide it they are missing any information about the main service distribution panel in terms of location, type, and size (voltage and current ratings).

Upon the completion of this lesson, your next step is to decide on the interconnection strategy and recommend any service upgrade if needed. Furthermore, you may need to consult with the utility plan reviewers to check on any additional requirements they enforce in that location, such as additional metering or disconnects.

In the next lesson, we will combine all efforts to take it a step further to submit the permitting documents, and we will discuss project management strategies and safety issues associated with the interconnection process.

In this lesson, we will disclose some construction considerations for these different systems and, in addition, we will discuss with our solar professionals the OSHA safety issues related to PV systems. This lesson helps our solar professionals, employees, and business owners get prepared to manage any solar project and understand the bigger picture of the design and installation process.

Learning Outcomes

At the successful completion of this lesson, students should be able to:

• Identify procurement and contracting strategies for project teams
• Identify electrical safety hazards associated with operating and non-operating to PV systems and components.
• List types of Personal Protection Equipment (PPE) and how they relate to PV installations and maintenance.
• Demonstrate how to apply OSHA regulations as they relate to specific safety hazards.

Considered one of the most critical roles in the PV system design and installation process, project management ensures the system delivery in the best desired timeline, quality, and budget. This role involves attention to details and coordination between different teams in terms of what steps to take next in the process. Project management tackles the methodology required for planning, scheduling, and managing resources including manpower and materials. In order for a project manager (PM) to be able to achieve that task, he/she should be qualified to prepare a plan that meets the requirements as specified in the contract with the PV system owners. The PM is usually a person who fully understand the technical aspects of PV projects, which include procurement, planning, scheduling, engineering, integration, and commissioning.

Project Development Phases

Electric solar projects go through certain stages to be fully completed. This includes the following phases:

1. Project initiation
2. Project planning and design
3. Project installation
4. Project monitoring
5. Project completion

These stages can vary according to the system, type, and size. That will be discussed in the considerations later on this page.

Figure 10.1 illustrates an example of the workflow for a small residential/commercial PV system. The complete PV system process usually follows this order: prospective customer, site evaluation, proposal preparation, contract signed, design and engineering, permitting and plan review (utility and AHJ), installation, inspection, monitoring and commissioning, owner's manual.

The work starts once a new customer shows interest in installing a PV system. A team of analysts begins preparing a simple drawing and some calculations to estimate the size of the solar system and to prepare a proposal. Most utilities rely on “PVWatt,” the free online solar database and simulation tool published by The National Renewable Energy Laboratory (NREL), to predict the annual solar energy production for the site (as we learned in previous lessons). As can be seen, NREL tools give the user options to find potential locations for the solar systems and to estimate the size of the system without going to the actual site.

Once the proposal is generated and discussed with the customer, the company representative will conduct a brief survey to gather more information about the site, which is required in order to start the preliminary engineering design. Then, the project will be entered into the pipeline of projects, and it will be directed to the engineering department for a preliminary design. The role of project management is to oversee all the design and engineering progress on each potential PV system and then ensure the right coordination between the internal departments.

The first step in the design is to generate the three-dimensional model that matches the actual site dimensions. This preliminary design will then be sent back to the customer for any feedback or changes that he/she sees are essential for the PV system in terms of location selection, aesthetics, and finances. Once the customer approves the preliminary design and he/she signs the contract, the engineering team will finalize the structural and electrical diagrams and required calculations after a followup visit for final site evaluation, where more detailed information is gathered. These designs will be reviewed by other engineers to ensure design adherence to local and national engineering codes (NEC article 690 and any other local AHJ), as we discussed earlier. In some cases, the designs need to be reviewed by a third party, such as an independent engineering firm, and then sent to the utility and AHJ for permitting and interconnection. Upon acceptance of the design by the utility engineering department, the project will enter the last stage in the engineering department, which is construction documents preparation and installation.

The project manager should also pay attention to the review timeline for the permit to be issued. In some places, the utility review process may require a couple of months, depending on the workload and number of PV projects submitted.

Simultaneously, the project manager should coordinate with the procurement team to ensure system component availability and when these materials should be delivered to the site to be installed by the PV installers at a prescheduled time agreed upon by the customer. As can be seen, logistics coordination is essential for optimal performance of the teams and to guarantee timely delivery of the system.

The system can also be monitored remotely to ensure the real system meets production expectations through the Internet profile of this particular system, as illustrated in Figure 10.1. The system can also be monitored for any technical problems within the operation that may appear during the entire lifespan of the system.

Once the system is up and running, the solar firm usually provides the customer with an owner’s manual to ensure that the customer has enough basic information about the system (for small systems such as rooftop PV, the installer can prepare the manual).

Figure 10.1: Workflow for a solar PV project

Credit: Mohamed Amer Chaaban

Considerations

Construction strategy depends highly on system type, size, and mounting structure used. When the project manager is preparing for different system requirements, he/she should consider various strategies to accomplish the design goal while meeting the construction timeline.

Ground mount systems:

As we discussed previously, this system mounting structure requires land space, and depending on the system size, land preparation, such as leveling and base preparation, which could raise a challenge to the PV system. In this case, the project manager should consider a thorough site evaluation of the land requirements before going forward with the scheduling of the delivery time of components and installation dates.

Pole mount system:

We remember from previous lessons that this mounting type requires less land space. However, in some cases, digging a hole in the ground may require detailed information about the type of sand and rocks in that area to prepare installers for the size of work needed and also to ensure delivery of the correct excavation equipment for earthwork.

Roof mount system:

Whether it is a simple residential or complex commercial roof mount system, any installation on the roof requires special attention to the roof age, allowable structure load, and installers' skills. The main concern for roof mount systems is leakage and liability.

As we discussed earlier, PV systems consist of multiple mechanical and electrical components, and so safety practices and procedures are critical to reducing or eliminating installation errors, electrical hazards, or injury (or death) on job sites. We saw that NEC has guides for safety requirements for designing and installing PV systems such as voltage and current limits, OCPD and ground-fault devices, and disconnects.

Aside from the aforementioned regulations, this section describes safety practices and procedures that must be used to install PV systems. PV is an electrical system, and workers can get injured. Non-electrical hazards are usually caused by human error, due to carelessness or failure to adhere to safety requirements. Installers should be alerted to different non-electric hazards they may encounter on the installation site. Cuts, bumps, falls, and sprains can cause as much hazard and lost time as electrical shock and burn hazards.

Occupancy Safety and Health Administration (OSHA)

The Occupancy Safety and Health Administration (OSHA) creates a set of regulations that requires employers to provide a safe place for employees while reducing hazards. OSHA 29 CFR part 1926 applied to general construction practices includes several practices applicable to PV systems. OSHA 10 is a recommended basic training for all workers.

In order for PV installers to reduce/eliminate their number of injuries, an awareness of potential hazards and a program where safety rules are frequently reviewed are required. This can be accomplished based on safety training series' offered to workers. Construction sites contain a number of risks that we will discuss in this section. Installers should know that these risks are continuously changing based on new materials and technologies, so regular updates on these topics are recommended.

This lesson discussed one of the most essential duties of any PV project, which is project management. We learned that PV systems require planning and scheduling that ease the project development and installation processes. In addition, we talked about PV systems safety and OSHA regulations that pertain to construction sites. PV systems are green energy systems that contribute to the safety of our environment, therefore, we have to make sure that the work places comply with all safety regulations for our working personnel.

In the next lesson, we will talk about the final stages of PV projects. This includes PV System Commissioning, Operation and Maintenance (O&M), and Monitoring. Finally, we will introduce the final project, which will serve as the final evaluation for this class. See you next week!

This lesson is a guide for PV professionals and system owners. The lesson will walk you through the basic understanding of the commissioning, operation and maintenance, and monitoring topics that relate to PV systems. This lesson prepares solar professionals to become PV system operators. Similar to any other construction that exists, O&M and monitoring are pivotal aspects of PV systems, and they are key components in driving the PV system to succeed under different operating conditions. Understanding the main concepts of O&M and system monitoring prolong the operation of PV systems and guarantee expected energy production throughout the systems' lifetimes.

Learning Outcomes

At the successful completion of this lesson, students should be able to:

• Describe steps to commissioning a PV system.
• Identify operation and maintenance tasks involved to maximize PV system output and operation.
• Identify monitoring strategies of array, components, and warranty coverage.

After the installation of any PV system is completed and the inspection is done, the system will be ready to be plugged to the grid to transfer energy. That process is referred to as Commissioning the system. At the same time, the installer will hand the responsibilities to the owner or operator of the system.

There are steps and requirements to commissioning PV systems that vary depending on system size and complexity of design. However, there are general guidelines that apply to most systems.

Final checkout

The system should be checked thoroughly before the commissioning starts.

A highlight of the main electrical items to consider:

• All disconnects are in (OFF) position during the final checkout.

• Installation matches the design documentation.

• Conductors, OCPD, and disconnect are sized appropriately.

• Compliance with all local AHJ and national codes (including NEC) is met.

• Terminals connections and screws are securely tightened. 


A highlight of the main mechanical and structural items to consider:

• Equipment is securely mounted (such as modules, racking, inverters, panels, and disconnects and so on)  

• Roof penetrations are properly weather sealed

• Installations are matched to the manufacturer's specifications and recommendations. 


Other safety items to consider:

• Applicable warning signs and labels are posted appropriately

• The job site is clean and orderly

• The documentation package is complete

• Attention has been paid to details such as removing tools from the site before commissioning


Commissioning Procedure

When intending to start the PV system the first time, the procedure starts at the array and ends at the point of connection. This will reduce hazards and make the diagnostic and testing of subsystems easier in case there is a problem in the installation.

1: Connect power sources to systems (this includes connecting PV module wire runs)

• Considerations
  • AC and DC disconnects need to remain in “OFF” position 

  • Fuses are not connected

2: Test DC voltage and polarity

• Make sure to use proper meter settings for DC

• Test after connecting PV modules in series and measure

• Expected voltage (from calculation of modules)

• Voltage polarity

   
• Considerations
  • AC and DC disconnects need to remain in “OFF” position

  • Fuses not connected as well

  • Watch for negative sign on meter that means lead positions of meter is not correct or circuit is not wired properly!!!


3: Test AC voltage at inverter output

• Make sure to use proper meter settings for AC

• Test Line to Line and Line to Neutral 

• Compare with inverter AC voltage (specs sheet)
• If inverter has settings for more than one connection, match your service setting for voltage

• After this step, return fuses if applicable

4: Start-up procedure

• Lift AC disconnect lever (inverter to grid)

• Lift DC disconnect lever (PV to inverter) 

   
• Considerations
  • Check with manufacturer’s manual for specific startup procedure 

  • Most inverters have Delay to check on grid and synchronize before connecting 


Maximizing the performance of any PV system is one of the priorities of owners and integrators. This can be done with routine maintenance to ensure optimal operation conditions. Since PV systems can be owned by individuals, organizations, or utilities, there must be a set of practical guidelines to operate and maintain these systems to minimize downtimes and maximize the return on investment. The maintenance requirements vary depending on the system size, installation type, and locations. For example, stand-alone systems require more maintenance consideration due to the addition of batteries. Furthermore, manufacturers may provide maintenance guidance or procedure for components.

Maintenance Approaches

There are several major O&M approaches that exist in the market today, and each comes with tradeoffs. In simple words, each approach aims to achieve the three key goals of an effective O&M:

1. Reduce costs
2. Improve availability
3. Increase productivity

There are three main strategies for maintenance: Preventative Maintenance, Corrective or Reactive Maintenance, and Condition-based Maintenance.

Preventive Maintenance (PM)

This strategy includes routine inspection and servicing of equipment to prevent breakdowns and unnecessary production losses. PM strategies can lower the probability of unplanned PV system downtime. However, the upfront costs associated with PM programs are moderate and requires more labor time, and the increased inspection and maintenance activity contribute to site wear and tear and perversely expedite system malfunctions.

Corrective or reactive maintenance

This strategy addresses equipment breakdowns after their occurrence to mitigate unplanned downtime. This strategy allows for low upfront costs, but it brings with it a higher risk of component failure and higher costs on the back end ( negotiating warranty terms). A certain amount of reactive maintenance will be necessary over the system lifetime, but this strategy can be minimized if more proactive PM and condition-based maintenance (CBM) strategies are adopted.

Condition-based maintenance (CBM)

This strategy uses real-time data to prioritize and optimize maintenance and resources, and can be done through third party integrators and turnkey providers. Different CBM regimes have been developed by third parties to offer greater O&M efficiency. However, this comes with a high upfront cost due to communication and monitoring software and hardware requirements.

Routine maintenance Considerations

In general, most PV systems share basic maintenance elements such as modules, inverters, charge controllers, and batteries.

PV module

A thorough inspection of PV modules can be done visually by the owner or installers. Main signs to look for when inspecting a PV system include:

• Physical damage to frame and glass
• Delaminating or change in color of the module's outer layer due to separation of bonds between glass and frame that allow moisture or corrosion to seep into the modules

• Burned connections inside module (hot spots) 

• Grounding corrosion of wires or frame

• Array mount weakness or corrosion


Shading control

As we learned in lesson 2, shading can significantly reduce the electrical output of PV array. Even after a careful site evaluation is performed before installing the system, a routine maintenance is recommended to avoid:

• Soiling

• Tree growing

• Leaves and debris accumulation


Battery maintenance

Batteries are considered one of the most maintenance intensive components in the PV system. We discussed in lesson 4 that lead-acid batteries are still widely used in PV systems and a special maintenance attention is needed. A careful consideration and review of the manufacturer’s maintenance recommendations is important to ensure safety on the site.

Electrical Equipment Maintenance

Besides visual inspections of inverters, chargers, transformers, and all other electrical equipment; there are other industry tools that can be used to find the weak points of the system. An infrared (IR) thermometer can be used to find the points where higher temperatures occur, such as circuit breakers, terminals, wires, and others. 

Maintenance plan

A checklist of all required maintenance tasks and their recommended intervals to ensure the best economic scheduling is referred to as a maintenance plan. The intervals can vary according to the site condition and system type. For example, a PV array installed in the desert requires more frequent scheduled cleaning of modules due to dust and soil accumulation.

PV systems consist of different components to transfer energy. Measuring the electrical parameters at certain intervals can help gather more information about system operating status and alert users to possible problems. As we discussed earlier, measuring the output of the system is essential for production-based financial incentives offered by federal and local agencies. 

The traditional monitoring method entails simply comparing actual energy generation to that predicted from the simulation software. The advantage of this approach is simplicity, affordability, and reliability. There are multiple levels at which a PV system can be monitored. Depending on system size and type, they can be classified as:

Inverter Monitoring

Inverter-level AC and DC monitoring offers insights into an inverter’s status, given the strategic location of the inverter to monitor the performance of the PV system. Nowadays, most inverter manufacturers embed their devices with monitoring functionality.

Advantages

• Relatively low costs (for central inverter) 

• Monitoring of DC power being fed into the inverter

• Monitoring the level of AC power being produced on the back end

• The efficiency of power inversion 


Disadvantages

• Limited level of resolution

• Information gathering, which must be done either manually on-site or via remote Ethernet link established through the inverter’s communications port, can be time consuming and labor intensive.


Array Monitoring

Going a level deeper into the system, array monitoring involves information from DC circuits located in various sections of a PV array.

Advantages

• Provides an additional level of data with a relatively small upfront investment. 

• It can isolate array level problems to a more specific array segment


Disadvantages

• A single shaded or faulty panel is not easily recognized. Several panels will need to fail before a detecting a problem. 


String Monitoring

A little closer to the modules, string level monitoring narrows the focus even further to individual strings of modules.

Advantage

• Failure or shading of one panel in a string is easily located


Disadvantages

• Additional monitoring complexity
• Increases installation cost


Module Monitoring

Once we reach the module, Micro Inverter Level Monitoring is installed at the PV module level. They are more common in smaller systems than large commercial or utility scale.

Advantage

• Provides more information about each individual module in the PV system. 


Disadvantage

• Not very cost competitive due to the huge number of inverters


An example of monitoring is shown in the video produced by the Northern Mid-Atlantic Solar Education and Resource Center, part of The Pennsylvania State University.

Video: Monitoring Methods for PV Systems (22:47)

This week, you will begin working on your Final Project. This will be a two-week project.

Let's revisit the scenarios from the beginning of this lesson. By the end of this lesson, you should be able to communicate well with the utility personnel to ensure that safe commissioning steps and procedures are followed before starting the PV system. Furthermore, you should be able to address the main O&M and monitoring questions the client asked at the beginning of this lesson. At this point in the class, our solar professionals are loaded with all basic information for design and installation of any PV systems with different sizes and types.

Being a solar professional requires a broad understanding of technologies and strategies in addition to solar design and installation knowledge such as: project management, financial analysis, communication, maintenance scheduling, monitoring networks and communication for data acquisition systems, and the list goes on.

In the next lesson, we will wrap up our class by discussing the impact of PV systems on the utility grid. As more PV are being added to the grid, there must be technical challenges to consider and understand when dealing with utilities to better negotiate and understand their requirements. So stay tuned!! See you next week.

For many decades, the electricity demand has followed what can be considered as a predictable daily pattern. This pattern allows utilities to perfectly predict future demand so that they can prepare themselves for buying and selling the electricity as in the energy market.

As more electricity is being generated from renewable resources, with the largest share of solar technologies, this addition to the utility grid introduces changes to the traditional daily profile of the electricity demand. These changes bring challenges with them to utilities to address reliability issues. In this lesson, we will introduce the electricity demand profile and the challenges to utilities after adding solar systems in large capacities. In addition, we will introduce this effect by what is referred to as the "Duck Curve," and later in the lesson we will talk about a proposed solution to that effect.

Ultimately, this lesson helps our solar professionals understand the back-end effect on PV and other renewable energy resources in the utility grid. Whether you work for an electric utility or you are a PV designer at an engineering firm, understanding the bigger picture on deploying PV technology helps in analyzing how the industry is driven and how to adapt to these changes. 

Let’s get started!

Learning Outcomes

At the successful completion of this lesson, students should be able to:

• Describe predicted load profile viewed from the utility side.
• Discuss challenges of excessive PV interconnection on the utility grid.

As we learned previously, the demand for electricity varies throughout the day and year, and so does solar irradiance. For example, the residential electricity demand rises in the morning to peak just before noontime, and then it levels out up until the evening peak, when everyone gets home from work and starts using electricity. And that pattern repeats itself over and over with some variations between summer and winter seasons, as seen in the left curves on Figure 12.1. We can also see that this curve is location dependent. There are key characteristics to this daily demand profile, such as the two daily peaks and then a base load demand.

Figure 12.1: Daily demand profile for different sectors (household-left) (bakery) (offices) (supermarket-right) in Germany (IEA PV Roadmap).

Credit: Based on IEA data from Technology Roadmap: Solar Photovoltaic Energy 2014 Edition, International Energy Agency (IEA) OECD/IEA ©2014. License: IEA.

As we said earlier, utilities became experts at predicting these values to better trade their electricity, and also, more importantly, to plan the operating schedule for the power plants. This planning helps optimally and economically operate their power plants to meet the base loads (usually coal or nuclear) and the additional capacity to meet the peak demands (such as Natural gas).

The load demand had been under control up until the distributed generation sources got introduced to the grid, which are variable and unexpected. Although the idea of meeting the peak demand is very appealing and is actually beneficial, excessive addition of these resources such as solar will change the load profile in such a way that utilities have to get out of their comfort zones and address these changes by meeting the new demand profiles.

Since our class focuses on solar systems, let’s take the solar effect as an example: Integrating a small amount of PV capacity doesn’t raise any technical issues to the grid, as long as the PV capacity is not concentrated in areas where the grid is weak and demand is low. However, when adding PV capacity in larger scales, the main concern from the grid and utilities point of view will be the supply and demand balance. One of the main issues that the solar arrays have are the inability to schedule its operating as compared to traditional coal plants, for example. The sun may shine as predicted, or it might not shine at all. In addition, solar only contributed in the best scenario to the daytime demand profile rather than the daily profile, and that contribution lowers the base load on the utility demand, but it disappears in the evening time.

So what is that fundamental change that solar adds to the daily demand profile?

The effect that solar power has on the daily profile is referred to as the "Duck Curve" or "Duck Chart." This change in the load shape of the daily curve starts to look like a duck. If we look at solar from the grid point of view, the additional solar looks like a load reduction and that is at the same time unpredictable and uncontrollable. In other words, the solar disturbs the operation of the bulk power plants such as coal by lowering the base load demand, as seen in Figure 12.2.

As said earlier, there are key characteristics to this daily demand profile, such as the two daily peaks and then a base load demand. Usually loads don’t fall below a certain value, as we see on the 2012 curve provided by the California Independent System Operators (ISO) as shown in Figure 12.2.

Figure 12.2: Daily demand profile and the duck curve(IEA PV Roadmap).

Credit: Based on IEA data from Technology Roadmap: Solar Photovoltaic Energy 2014 Edition, International Energy Agency (IEA) OECD/IEA ©2014, License: IEA.

We can see some greater challenges as solar becomes larger in capacity. The load demand can fall down to closer to very small demand value, which means the massive base power plants need to shut down, and that is not an easy task since starting a traditional power plant requires hours, and the process is slow and might not meet the steep ramp demand in the evening after the solar is gone. This can result in a serious stability issue and power outages. For this reason, solar is sometimes viewed as a disruptive technology to the grid and utilities. A prediction of the duck effect on the daily demand curves can also be seen on the 2020 prediction for the daily profile in Figure 12.2.

Proposed Solutions to Duck Effect

Solar arrays may produce more solar energy than the grid needs. When such oversupply exists, there are two main scenarios to propose solutions from the grid point of view - the grid operator side and the load side.

Grid Operator Side

• Utility operators can manually "curtail" solar production, cutting some solar capacity off from the grid. As a result, this wastes the energy produced from the sun, but it saves the grid. This is considered a short term solution.  

• Another solution is interconnection with other electricity networks, such as the Texas and western interconnection at the transmission level to expand the capacity of the grid so it can handle more PV capacity. As it sounds, this is a long term solution and usually it takes a long time to expand the grid. 


Load Side or Demand Side Management (DSM)

• The first DSM strategy refers to Demand Response (DR) including storage systems. This can shift the peak to other times during the day, which is usually done either through incentivizing the customers to use electricity when it is cheaper or by storing the electricity for later use. However, this might require more capital investment at the customer side due to the additional storage systems cost. 

• The other type of DSM is the Energy Efficiency that lowers the total demand in general. This strategy has great potential, as our peak demand keeps growing due to additional appliances and devices connected to the grid.

This week, you will finish up and submit your Final Project.

In this lesson, we talked about the electricity demand and load profile changes due to the addition of solar into the grid. We also discussed the duck effect and the shape of the curve as a result of solar energy availability during the daytime and its absence during the nighttime.

Our class has reached its end, and we hope we covered all information needed to prepare you as a future solar professional and equipped you with the right tools. Our main goal as a solar option is to expose you to various scenarios you might face in the real-world when dealing with solar systems in terms of system main components, sizing and design, permitting, documentation, code compliance, interconnection methods, safety regulations, commissioning, operating and maintenance, monitoring, and most importantly the effect of PV on the grid.