Products & Equipment : Solar Heating

Primary Category: 

The installers of solar water heating systems have to navigate a range of plumbing and mechanical codes, which sometimes seem to be at odds with each other.

Installation of solar water heating (SWH) systems requires significant expertise in a number of trades. Installers need to know carpentry—critical for mounting solar collectors—as well as electrical systems, necessary for installing system controls. They also need a thorough grounding in plumbing and heating systems to properly integrate SWH equipment with standard water and space heating systems.

Each of these trades has a set of requirements that installers must follow to ensure code compliance. In many jurisdictions, this requires SWH installers to be knowledgeable about specific portions of the local building, plumbing, mechanical, energy conservation and electrical codes.

Among jurisdictions in the US, some code adoption is relatively uniform. The International Residential Code (IRC), International Building Code (IBC), International Energy Conservation Code (IECC) and National Electrical Code, for instance, are dominant. Some variation exists because each jurisdiction decides which edition of a code to adopt, but the contrast in requirements for these codes is not as stark as it is for plumbing and mechanical codes.

There are two primary plumbing codes in the US: the Uniform Plumbing Code (UPC) and the International Plumbing Code (IPC). Most jurisdictions have adopted the UPC or IPC. Exceptions include states that have adopted unique state plumbing codes, including Louisiana and Massachusetts, and states that have adopted the National Standard Plumbing Code (NSPC), such as Maryland and New Jersey.

While the International Mechanical Code (IMC) and the Uniform Mechanical Code (UMC) share some similarities, they differ significantly in their treatment of SWH systems. In addition, the national mechanical codes have variations that can create confusion and inconsistency in local requirements.

In this article, I explore differences among the plumbing and mechanical codes, and clarify some of the more confusing code requirements that impact SWH integration professionals. I also explore and explain portions of the international codes and the Uniform Solar Energy Code (USEC) that have posed a challenge for installers, designers and building inspectors.

Unique Characteristics of Solar Heating Systems

Plumbing and mechanical codes must be broad enough to accommodate all types of heating systems, including gas and oil boilers, ground-source heat pumps, radiant heating distribution, electric water heaters and solar heating systems. Sometimes the industry introduces new techniques or technologies faster than the code organizations can respond. For instance, some SWH system installers have begun to use corrugated stainless steel tubing (CSST), a material that the major mechanical codes have yet to address.

Committees of volunteers, each with specific expertise, create the plumbing and mechanical codes. A plumbing code committee must have members who are knowledgeable in topics such as water supply, sanitary drainage and plumbing fixtures. The code reflects the expertise and foresight of these individuals. If committee members have limited experience with a particular technology, they may approve requirements without full consideration of whether they apply to all the technologies that the specific code governs. The resulting code requirements may be too restrictive or may be irrelevant for systems that operate differently from the norm. This has been the case in several US jurisdictions, where applying requirements for standard hydronic systems to SWH systems has created onerous installation procedures.

There are two significant differences between antifreeze solar heating systems and the majority of standard hydronic systems: First, most hydronic systems have an automatic fill valve that adds water to the system to maintain its pressure, while many SWH systems do not. Second, unlike solar heating systems, most standard hydronic heating systems automatically shut off the heat sources when temperatures exceed design parameters.

Without an automatic fill valve, antifreeze and drainback solar heating systems contain a fixed amount of liquid. If a component fails or if an overpressure situation occurs, it is a singular occurrence that the introduction of more fluid into the system does not exacerbate. This is an important difference, as hydronic heating systems with make-up water supplied via an automatic fill valve can experience numerous overpressure events if they are not immediately identified.

In addition, when gas, oil or electric appliances serve as a heat source for a hydronic system, thermostatic controls can regulate fuel or power delivery. These controls can turn the energy source off once the system reaches the design’s target temperature. However, because it is not possible to turn off the energy source for antifreeze solar heating systems, the design needs to build in measures for alleviating overheating. Certain equipment may require higher temperature ratings than standard hydronic systems would call for. Also, solar heating systems may allow for higher operating pressures.

To address these variations, some code organizations have developed subcommittees or stand-alone codes for solar technologies. For example, the International Association of Plumbing and Mechanical Officials (IAPMO), which issues the UPC and UMC, developed the USEC to specify requirements for SWH system installation.

Heat Exchangers and Backflow Prevention

The most controversial code requirements related to solar heating systems—and those that have had the most impact on the industry—concern cross connection. Cross connection occurs when you connect a potable water system to piping containing a fluid that is not potable or that may contain contaminants. A common example of cross connection occurs in hydronic heating systems that pipe an automatic fill valve into the mechanical loop to provide make-up water. In this case, code requirements ensure that water from the hydronic heating system does not contaminate the potable water supply through backsiphonage or backflow.

Backsiphonage. When the water supply is under negative pressure, suction-—or backsiphonage-—can pull fluid back into the water supply. For example, the opening of a fire hydrant can cause nearby homes and buildings to experience back-siphonage. Installers can prevent backsiphonage by installing a vacuum relief valve or an approved dip tube on the cold water supply to the storage tank. These measures provide an air gap that prevents suctioning of the tank’s contents into the potable water supply.

Backflow. Differential pressure between the potable water system and the water supply causes backflow. It occurs when the pressure in the nonpotable system is higher than that of the potable system to which it connects. Unless the installer takes preventative measures, nonpotable fluid can push into the potable water supply. For this reason, standard hydronic heating systems in which potable water connects directly to a system with nonpotable fluid require backflow prevention devices. Indirect SWH systems, however, do not connect directly to the potable water supply. Instead, the interface between the mechanical piping and the potable water supply occurs at the heat exchanger.

If the heat exchanger fails in a standard hydronic or SWH system, under certain conditions heat transfer fluid could enter the potable water system at an indirect water heater. The fluid behavior depends upon the operating pressures on either side of the heat exchanger. For example, hydronic heating systems typically use pressure relief valves that are rated for discharge at 30 psi and operate at pressures of 15–20 psi. These pressures are commonly below the standard street pressure for a public water supply. If a heat exchanger leaks under these circumstances, the potable water will push into the hydronic piping and likely activate the pressure relief valve.

In contrast, antifreeze SWH systems typically utilize pressure relief valves rated to discharge at 75–150 psi, depending upon system design. These higher relief valve ratings are due primarily to the possibility of stagnation, which can significantly increase system temperature and pressure. Stagnation occurs when there is sufficient solar radiation and the fluid in the system does not circulate due to factors such as a power outage or a pump failure, or when the tank has reached the maximum temperature and the pump turns off to protect the tank from overheating. System designers can use relief valves rated at higher pressures, such as 150 psi, to permit larger pressure fluctuations in the system and reduce the required expansion tank volume. For most systems, these high system pressures are infrequent or may not occur at all. For a majority of the system’s lifespan, the standard operating pressure stays below the potable water pressure.

The differences between SWH systems and standard hydronic heating systems make it challenging to develop effective code requirements, since codes provide an overarching set of requirements for all systems, while the pressure conditions that occur during stagnation are unique to solar heating technologies. In light of this issue, code committees and local jurisdictions should make an effort to adapt code requirements in a flexible manner that promotes public health without putting an unnecessary burden on a particular product or technology, including solar heating.

Code developments in Louisiana over the last few years illustrate this challenge. In 2010, Louisiana’s Department of Health and Hospitals issued a letter of intent that required all SWH systems in the state to utilize double-wall heat exchangers, nontoxic heat transfer fluid and a reduced-pressure backflow preventer that needed at least annual testing. This decision increased the cost of systems so significantly that it limited the growth of the state’s SWH industry. Recognizing that the use of a double-wall heat exchanger and nontoxic heat transfer fluid adequately protects the public water supply, the department issued a revised letter of intent in 2011 that revoked the backflow preventer requirement. The current code requires the use of a double-wall heat exchanger regardless of the type of heat transfer fluid used. This requirement includes drainback systems, which typically use water as a heat transfer fluid and have less risk of causing cross contamination than any conventional heating system that utilizes an indirect water heater.

US code organizations take varied approaches to the cross-contamination issue. The major plumbing and mechanical codes include installation requirements related to the type of heat transfer fluid, the type of heat exchanger and the operating pressure of the solar loop to minimize any cross contamination that might occur if a heat exchanger were to fail.

IPC 608.16.3 (2015) and USEC 406.1.1 (2012) require the use of essentially nontoxic heat transfer fluid with single-wall heat exchangers. If a system uses a toxic heat transfer fluid such as ethylene glycol, these codes require a double-wall heat exchanger with an air gap. The air gap ensures that the toxic fluid leaks onto the floor below the heat exchanger rather than into the potable water supply. Since a pool of toxic fluid in a residential or commercial setting presents another health hazard, it is best to avoid the use of toxic heat transfer fluids in SWH systems.

The IPC and the UPC define essentially nontoxic differently. The 2012 IPC definition refers to “fluids having a Gosselin rating of 1,” while the 2012 UPC definition refers to “fluid having a toxic rating or Class of 1.” Propylene glycol meets both definitions (per 21 CFR 184.1666). The corrosion inhibitors commonly used in solar heat transfer fluid also meet the definitions of essentially nontoxic. Since mixing several nontoxic ingredients does not ensure that the final solution will be essentially nontoxic, manufacturers, public health officials and code officials are developing mechanisms that can better assess the nontoxicity of heat transfer fluids.

USEC 406.1.1 (2012) allows the use of single-wall heat exchangers only if the FDA has recognized the heat transfer fluid as safe and the maximum pressure in the solar loop does not exceed the maximum pressure of the potable water supply. The intent here is to ensure that a heat exchanger leak causes the potable water to push into the solar loop rather than vice versa. To comply with this requirement, the installer must know the potable water pressure, which can vary significantly by jurisdiction and even within the same jurisdiction. For example, a facility located near a public water supply pump house may see higher pressures than a facility located at the end of a distribution branch. Additionally, homes on a private water supply such as a well may have water pressures that would necessitate the use of a double-wall heat exchanger.

Though these requirements have evolved over several code cycles, challenges continue to arise when common industry practices conflict with existing code requirements. For example, in Oregon, code requirements formerly dictated the use of a double-wall heat exchanger when the pressure relief valve on a SWH system exceeded 30 psi. In 2008 the Oregon Building Codes Division issued an alternate method ruling that allows installers to use pressure relief valves rated up to 150 psi with single-wall heat exchangers as long as the operating pressure of the system remains “below the normal minimum operating pressure of the potable water system in the building.” The state made this determination after considering common industry practices, including the fact that standard system operating pressures are below 30 psi.

The major codes grant local jurisdictions considerable responsibility for interpretation, allowing the AHJ (commonly represented by the local code official) to accept alternate designs. For example, Appendix C of the 2012 UPC and Appendix A of the 2012 USEC detail local control for heat exchanger designs.

However, some requirements confuse even code officials and solar professionals. For example, IMC 1401.2 (2012) stated that “potable water supplies to solar systems shall be protected against contamination in accordance with the International Plumbing Code.” The 2012 IRC had a detailed requirement stating that “the potable water supply to a solar system shall be equipped with a backflow preventer with intermediate atmospheric vent complying with ASSE 1012 or a reduced pressure principle backflow preventer complying with ASSE 1013” (2012 IRC P2902.5.5). However, this requirement was ambiguous because it does not clearly define what constitutes the potable water supply to a system.

The IPC definition of cross connection refers to a physical connection between two piping systems where a pressure differential could initiate cross contamination. In addition, the devices certified under ASSE 1012 are required when you install an automatic fill device in a standard hydronic system. This requirement does not distinguish between systems that utilize single-wall or double-wall heat exchangers, nor does it specify the type of heat transfer fluid used in the system. It is unclear whether this section applies to standard SWH installations.

Requiring an ASSE 1013 device on the potable water supply to a solar indirect water heater would support public health only if you used an essentially toxic heat transfer fluid, such as ethylene glycol, with a single-wall heat exchanger. Considering that the code already prohibits such an installation, this portion is superfluous. Industry practice supports that interpretation, and the 2015 International Codes clarify this issue by specifying that “water supplies of any type shall not be connected to the solar heating loop of an indirect solar thermal hot water heating system.” As a result, indirect SWH systems do not require backflow preventers, nor do most direct systems.

With each code adoption cycle, committees review the public health risks associated with the use of a single-wall heat exchanger with an antifreeze SWH system. For a code-compliant SWH system to contaminate the potable water supply, the following combination of events would have to occur: the heat exchanger leaks, the solar loop stagnates, and the expansion tank(s) cannot protect the system from exceeding the water supply pressure to the building.

Under these conditions, the antifreeze solution could potentially push back into the public water supply. The probability of such an occurrence is low, considering that the potable water in the indirect water heater, and any water consumed at hot water fixtures in the building located after the heat exchanger breach, would dilute the solution. Stakeholders are considering proposals for the 2015 code cycle that would provide further clarification of this issue and of what constitutes an essentially nontoxic fluid.

ASME Certification for Tanks

In many residential SWH systems, designers and installers work with 80–120-gallon tanks. Commercial applications or residential combination, or “combi,” systems that also provide space heating often utilize much larger tanks. However, although larger volumes can increase a system’s heat storage capacity, they also increase the risks associated with storing pressurized water. Code requirements are much more stringent for pressurized vessels that exceed a certain volume threshold.

Both IMC 1003.1 (2015) and USEC 603.7 (2012) require the construction of pressure vessels in accordance with the ASME Boiler and Pressure Vessel (B&PV) Code, Section VIII. The B&PV Code specifies requirements for the design, construction and installation of containers for pressurized water. For solar heating systems, this includes water heaters and expansion tanks. ASME must certify pressure vessels that fall within the scope of the B&PV Code. That means the manufacturer must construct the tank in accordance with specifications detailed in the B&PV Code, and an ASME-recognized inspector must verify the manufacturing of each pressure vessel. An ASME certification may double the cost of a storage tank and increase the cost of an expansion tank by a factor of 20.

Water heaters that exceed 120 gallons require ASME certification unless their operating pressure does not exceed 15 psi. Since the water pressure from a public water supply and from most private water supplies does exceed 15 psi, a pressurized water heater that is greater than 120 gallons in volume needs an ASME stamp if it contains potable water.

When a system requires more than 120 gallons of storage, designers can avoid the costs associated with ASME certification and remain code compliant by using multiple 120-gallon tanks or by using an unpressurized storage tank, which contains water at atmospheric pressure. Heat exchangers transfer heat to the potable water and heating distribution system. According to USEC 302.1 (2012) and IMC 301.7 (2015), an approved agency must list and label these tanks. However, USEC also recognizes third-party certification.

Thermal accumulators. The introduction of thermal accumulators into the US market provides opportunities and challenges for designers, installers and the code enforcement community. Thermal accumulators are buffer tanks that contain the nonpotable water used to distribute heat in a hydronic heating system. These tanks typically have either an immersed heat exchanger at the bottom of the tank or a sidearm heat exchanger that transfers heat from the solar collectors to the buffer water. Ports at various heights in the tank supply heat to the distribution system and provide auxiliary heating from high-efficiency boilers. A large heat exchange coil or an immersed tank in the buffer tank transfers heat to the potable water.

Since combi systems need to supplement larger heating demands than a simple residential SWH system handles, they require larger storage capacities. Thermal accumulator tanks provide a simple solution for integrating solar with auxiliary heating sources for domestic water and space heating. One of the thermal accumulators available in the US market, Lochinvar’s Strato-Therm+, offers 125–900-gallon capacities. Each tank has an ASME Section VIII stamp to comply with the B&PV Code. Any application requiring storage tank volumes of 125–900 gallons can use these tanks.

Triangle Tube offers storage capacities of greater than 120 gallons without ASME certification due to the unique tank-in-tank design of its Smart Multi Energy line of storage tanks. These models meet compliance since neither the stainless steel potable water tank nor the surrounding buffer tank contains a volume greater than 120 gallons. One of the models achieves a total storage volume of 171 gallons by surrounding a 105-gallon inner tank with 66 gallons of buffer water in the outer tank.

Several other companies offer thermal accumulators that exceed 120 gallons but are not ASME certified. ASME B&PV Code Section VIII, U-1(C)(2)(h), requires that the “internal operating pressure must not exceed 15 psi.” The only way to ensure that the operating pressure does not exceed this level is to utilize a pressure-relief valve rated at 15 psi, but this may cause complications. The modulating, condensing gas-fired boilers that are most appropriate for integrating with these tanks often require a minimum hydronic system pressure of 15 psi or higher. As a result, it is critical to confirm that all of the equipment operates properly under the design conditions that B&PV Code requires when a system installation includes large non–ASME-certified tanks.

Expansion tanks. ASME has separate requirements for expansion tanks in solar heating systems. B&PV Code Section VIII states that an expansion tank must be ASME certified if the design pressure exceeds 300 psi or the design temperature exceeds 210°F. Expansion tanks that buffer the system from pressure fluctuations are designed to operate below these limits. As a result, the B&PV Code does not require ASME certification of thermal expansion tanks.

The requirements relating to expansion tanks in antifreeze SWH systems require further interpretation, however. While the B&PV Code does not have an explicit definition for design temperature, other codes do. The 2012 USEC, for example, defines the design temperature as “the maximum allowable continuous or intermittent temperature for which a specific part of a solar energy system is designed to operate safely and reliably.” Based on this definition and considering that collector temperatures in antifreeze systems may reach 340°F–420°F during stagnation, a strict interpretation of the code indicates that you must either use an ASME-certified solar expansion tank or install the tank in a location within the system that ensures antifreeze temperatures do not exceed 210°F. During normal operation, the fluid temperature in an SWH system does not exceed 210°F. Since designers commonly position a solar expansion tank on branch piping from the main collector loop, fluid contained in the expansion tank generally remains at a much lower temperature than the rest of the system fluid.

Stagnation events, when the fluid in the collector turns to steam and forces the liquid contents of the collector array into the system piping, pose a design challenge. When stagnation occurs, the membrane in the expansion tank stretches to accommodate expansion. In a properly designed system, the steam should remain in the collector array and adjacent piping. The volume of fluid between the collector array and the expansion tank determines the maximum fluid temperatures in the expansion tank. If this volume is less than the volume of the collector array, temperatures in the expansion tank may exceed 210°F. To alleviate this situation, designers can use heat dissipation strategies on the piping between the primary solar circuit and the expansion tank. For example, they could add heat dissipation fins like those used in standard baseboard radiators or install a prevessel on the piping that contains enough fluid to maintain temperatures below 210°F in the solar expansion tank.

The ASME requirements for expansion tanks in SWH systems illustrate how the traditional categories within the codes do not reflect the unique nature of solar heating systems. For example, the B&PV Code assumes that expansion tanks that experience temperatures exceeding 210°F are connected to power boilers. ASME defines a power boiler as “a boiler in which steam or other vapor is generated at a pressure of more than 15 psi (100 kPa) for use external to itself.” A standard SWH system does not produce steam for the purposes of providing heat to another source. In fact, when a SWH system does produce steam, it is not operational. This contrast is a significant one.

Corrugated Stainless Steel Tubing (CSST)

In recent years, several manufacturers have introduced insulated CSST linesets for use in the collector loop of antifreeze solar heating systems. Manufacturers typically sell these products in coils that include two lengths of CSST encased in pipe insulation, which also contains a two-wire sensor cable for connecting the collector sensor to the system’s differential controller. The insulation generally has a coating to protect it from degradation due to UV radiation when used in outdoor applications.

The fittings used to transition from CSST to copper tubing and other components comprise several parts: a union nut, a clamping washer installed between the CSST corrugations to secure the union nut to the CSST, an adapter that links the CSST and the copper tubing, and a washer or sealing ring between the union nut and the adapter. These fittings, unique to each manufacturer, may target a particular application. For example, some manufacturers utilize the same CSST product for both potable water and solar applications. In this case, the fittings for each application may differ significantly. Since the temperatures in solar heating systems may exceed 400°F, you may need to employ a different material for the washer or sealing ring.

Though CSST is a well-established product in the fuel piping trade, it is fairly uncommon in plumbing and hydronic piping applications. As a result, the major mechanical codes have yet to include CSST as one of the allowable piping materials, and neither IMC 1202.4 (2015) nor USEC 407.1 (2012) allows its use.

Since CSST sizes vary by manufacturer, there is no listed standard for this type of tubing. As the code organizations incorporate CSST for hydronic applications into their mechanical codes, they will face the challenge of identifying a standard for use of these products in solar applications.

The fact that the mechanical codes exclude CSST does not necessarily prevent its use in solar heating systems. Both the IMC and the USEC include provisions designed to address situations in which technology responds more quickly to change than the 3-year code cycles do. IMC 105.2 (2015) and USEC 302.2 (2012) allow the AHJ discretion for such cases. A code official can review technical documentation specifying that the particular brand of CSST and its fittings are compatible with the fluid in the system and are rated for the design temperatures and pressures. If satisfied, the official can approve its use.

Many solar CSST manufacturers have chosen to have their products tested to ASTM A240, which is useful if a code official requires conformance to a recognized standard. ASTM A24 specifies the required chemical composition for stainless steel in pressure vessels and general applications.

If the code official approves CSST for a project, the installer must support the tubing in accordance with the manufacturer’s installation instructions, per IMC 304.1 (2015) and USEC 307.1 (2012). If the instructions do not include the maximum support intervals and method of support, it is the installer’s responsibility to ask the manufacturer. The manufacturer’s instructions may provide guidance on the minimum allowable bend radius for its style of CSST. This guidance is important because too tight a bend radius could weaken the tubing wall, ultimately causing it to fail.

SWH designers and installers who are looking to incorporate CSST must carefully consider flashing and penetration sealing details where the CSST enters a building. Manufacturers design most conventional pipe flashing products for use with smooth rather than corrugated tubing. It is important to use flashing designed specifically for use with CSST to ensure code compliance.

Becoming Part of the Process

The evolution and clarification of code requirements is important to the growth of the solar heating industry. Developing clear expectations provides a level of uniformity and predictability that is helpful when training new design, installation and inspection professionals and empowers those already working in the field.

While it is unlikely that the solar heating industry will reach the same level of uniformity in code adoption as the PV industry, it is still important for industry professionals to engage and educate local building officials and get involved with the code-making process. Consistent and standardized plumbing and mechanical code requirements make it easier for SWH system installers to work in multiple jurisdictions, and ultimately drive down the cost of deploying SWH.


Vaughan Woodruff / Insource Renewables / Pittsfield, ME /

Primary Category: 

Thermal imaging cameras, also referred to as infrared (IR) cameras, are becoming common tools for PV system troubleshooting. The devices are also very well suited for diagnosing performance issues in solar water heating (SWH) systems. After all, SWH systems collect, transport and store heat. The ability to accurately determine temperature differentials between points in the system provides crucial visibility into an installation’s performance. In the past, I relied on noncontact infrared thermometers for recording equipment temperatures during system commissioning and troubleshooting.  IR thermometers are limited, however: You measure the temperature of the specific point you are aiming at, and it is easy to miss hot spots. An IR camera allows you to capture a thermal image of a larger area and visually displays the temperature and temperature gradients of objects in the image.

While several good IR cameras are available, I use a Fluke TiR32. With a list price of approximately $8,000, it is expensive, but it provides information that is otherwise impossible to capture in the field. The TiR32 has a 2% accuracy range, which is more than adequate for measuring temperatures in solar heating systems. The following case study illustrates the effectiveness of using a thermal imaging camera for SWH system troubleshooting.

System Configuration

The Ramsey County Law Enforcement Center is a pretrial holding center for approximately 400 inmates in downtown St. Paul, Minnesota. A 35-collector solar heating array was installed on the facility’s roof in October 2012. The project was one of several SWH installations completed by the City of St. Paul and funded in part with an American Recovery and Reinvestment Act (ARRA) grant. Prior to the system’s installation, the center’s potable water was heated by a hot water loop supplied by District Energy, a nonprofit company that operates the largest biomass-fueled hot water district heating system in North America. It supplies heat for more than 185 buildings and cooling for 100 more in downtown St. Paul.

Westwood Professional Systems managed and Karges-Faulconbridge engineered the construction of the Ramsey County Law Enforcement Center installation. With an estimated peak production of approximately 75 kW (93 MWh annually), the solar heating project was expected to reduce the center’s dependency on the city’s hot water system and the related monthly expense by 40% to 50%. The array’s 35 Solar Skies NSC-40 collectors and array-side piping are filled with a 50% glycol solution to withstand St. Paul’s frigid winters. Each collector has an absorber plate area of 36.9 ft2 and holds 1.21 gallons of glycol solution. The system uses two Sondex A/S PHE heat exchangers. The SWH system transfers heat to a branch of the District Energy hot water line, and that branch then flows through a second heat exchanger to heat the correctional facility’s domestic water.

A LI-COR LI-200SA pyranometer mounted at the array measures solar irradiance. An Alerton BACtalk controller continuously calculates the amount of heat that the system should produce based on the current level of irradiance and compares it to the expected heat loss within the collectors due to the ambient temperature at the array. As soon as this number is greater than 0, a pump turns on to circulate glycol through the collectors. The heated fluid flows through the first heat exchanger that is installed in line with the District Energy heat system. A temperature sensor in this line activates a second pump when the temperature reaches 100° F, allowing domestic water to flow through the second heat exchanger. A temperature sensor on the domestic side of the second heat exchanger signals the controller to stop circulation of the domestic hot water when temperatures reach 140°F and allows the District Energy heat line to absorb the heat from the glycol. Because the building is located on the farthest end of the City’s hot water line, it should always be able to absorb any excess heat. In case it does not, an alarm signals the hot water on the secondary side of the first heat exchanger to flow directly from the District Energy return header if the glycol system exceeds 200°F.

Commissioning and Troubleshooting

During the system’s initial testing and commissioning, the commissioning agent raised concerns about the circulating pumps: They were allowing the domestic water system to heat to approximately 129°F rather than the 140°F design temperature. The source of the problem was difficult to track. All gauges and sensors on the new system appeared to be operating at the preset 140°F, but the existing water storage tank was reaching only 129°F. An extremely congested mechanical room and a lack of labeling on the piping (custom labels had not yet been applied) complicated troubleshooting.

During the troubleshooting process, I used the Fluke thermal imaging camera to verify that the solar collectors were operating correctly, with no impedance to fluid flow. I did not identify any problems, which pointed to an issue elsewhere in the system. Using the camera, I was able to quickly trace which of the two pump systems was running at a specific time and identify the subsystem’s associated piping. Heat loss was evident around valves that could not be fully insulated and several pipe joints that still needed insulation. Using the IR camera, I verified that the temperature of the piping near the point of the control sensor for the domestic water loop was 129°F. However, the sensor was reading 140°F and signaling the system to divert heat to the District Energy hot water system, away from the domestic system. The IR camera allowed me to quickly identify this faulty sensor and then document the issue.

With the faulty temperature sensor replaced, on mostly clear days the system now produces hot water at the expected design temperature of 140°F.

—Cari Williamette / EcoVision Electric / Minneapolis, MN /

Primary Category: 

The influence of power purchase agreements and leases in the PV market illustrates how financing plays a pivotal role in the growth of the US solar industry. A fundamental challenge with implementing these financing models in the solar water heating (SWH) market segment is quantifying the energy a given system produces or offsets. For billing purposes, developers of third-party ownership models and utilities must be able to accurately account for the value of energy delivered by solar heating systems.

The inclusion of solar heating systems in a state’s renewable portfolio standard also creates a need for accurate heat metering. To meet requirements for renewable portfolio standards, utilities use renewable energy credits to quantify renewable energy production. Where they are basing these credits upon actual solar heating system output, a heat meter is required.

Unfortunately, measuring the energy residential and commercial SWH systems produce is not always a straightforward exercise. The cost of heat metering equipment can be prohibitive in small systems, and proper equipment selection and installation are essential to obtaining accurate heat production data. To complicate matters, the US currently lacks a standard for solar heating system metering. Policy makers, utilities and system integrators must rely on European standards that often result in some confusion in the US market.

This article introduces solar heating contractors to the components used in heat metering systems and provides information on component selection and installation. It also includes perspectives from industry stakeholders who oversee utility incentive programs, are active in developing a US standard for heat metering or have experience with these systems as equipment manufacturers or installers.

Solar Heat Meter Subassemblies

Heat meters often require three measurements, including flow rate and two reference temperatures to quantify heat. Current international heat metering standards refer to the equipment used to measure these data as subassemblies. A complete heat meter consists of a calculator subassembly, a temperature-sensor pair subassembly and a flow sensor subassembly.


A calculator utilizes the system flow rate, two temperature readings and the characteristics of the heated fluid to determine the amount of heat a solar heating system produces. The calculator uses the flow rate to determine the volume of the heated fluid, and the density and specific heat to quantify the heat-carrying capacity of this volume of fluid at an observed temperature difference.

This relationship can be described as follows:

Q = V γ c ΔT

where Q is the heat flow in BTU, V is the volume of fluid in gallons, γ is the density of the fluid in pounds per gallon, c is the specific heat of the fluid in BTU per pounds per °F and ΔT is the change in temperature of the fluid in °F.

The calculator must account for the variation of density and specific heat based on the type of fluid in the system and the temperature of the fluid. A database within the heat meter’s calculator subassembly contains these properties.

The calculator also provides an interface for viewing or transmitting system data. Some meters accumulate data and store the information in their internal memory. Others use an SD card or can be networked to allow remote monitoring and data storage. Advanced differential controllers may include a calculator subassembly within their programming and can be connected directly to temperature and flow sensors.


Resistance temperature detectors (RTDs) are commonly used with heat meters due to their accuracy and long-term stability. Two common RTDs used in heat meters are PT100 and PT500 sensors. Silicone and solid-state semiconductor-based sensors may also be used.

The temperature-sensor pair must accurately measure the temperature differential between two points in the system. This requires accuracy specifications for the individual sensors and specifications that quantify how the accuracy of the paired sensors varies based on the temperature differential between the two reference points.

The electrical resistance of RTDs varies in response to temperature. As temperature increases, so does the electrical resistance. RTD resistance outputs are expected to correspond with a specific equation that defines this relationship. Individual sensors are rated and classified based on the sensors’ performance in relation to this equation. The sensor manufacturer typically provides a specification for the level of measurement accuracy. Standards-compliant heat meters utilize calibrated and tested temperature-sensor pairs.


Measuring flow in a solar heating system is a difficult endeavor because the flow rate of a fluid varies based on its temperature. For example, water and glycol solutions have a higher viscosity at colder temperatures. Thus a fixed-speed pump sees fluctuations in the flow rate depending upon fluid temperature. Meters installed on systems with variable speed pumps or on the cold-water service to a tank see greater variations in flow.

Flow also varies across a cross-section of tubing. The walls of the tubing resist flow, which leads to larger fluid velocities in the center of the tubing than along the edges. The proximity of fittings and valves can have a significant impact on the variability of flow across a section of tubing, as can the type of flow.

For purposes of heat metering, the flow sensor must be capable of accurately measuring the average flow rate through the system. SWH systems use several types of flow sensors for this purpose.

Vortex-shedding flow sensors. A vortex-shedding flow sensor features a bluff body, which is typically a post in the center of the flow channel, to create turbulence. The turbulence in turn creates a series of vortices that move past the flow sensor, which utilizes a proprietary membrane that deflects with changes in pressure. A circuit board in the flow sensor measures the frequency of these deflections to determine the system flow rate.

Impeller flow sensors. These flow sensors utilize an impeller driven by the fluid in the body of the flow channel. Much as with a standard water meter or an odometer, the rotation of the impeller drives a gear train that turns dials to register the volume of fluid that passes through the device. The dials can be configured with a magnet that allows the device to send a digital signal to a calculator, which translates these pulses into a flow rate. The design of the flow sensor’s body varies depending upon the manufacturer and model. Some impeller flow sensors utilize a fully open flow chamber, while others redirect the flow through a series of chambers to stabilize the flow for more accurate measurement.

Ultrasonic flow sensors. An ultrasonic flow sensor measures the speed at which a fluid transmits sound energy between two points in a piping path. Two transducers send and receive the ultrasonic wave between one another. The sensor determines system flow based upon a comparison of the speed at which the sound energy travels from one transducer to the other. It uses the difference in transit times between these two waves to calculate the system flow rate.

Electromagnetic flow sensors. An electromagnetic flow sensor creates a constant magnetic field across the cross-section of a flow channel. Electrodes installed on the inner wall of the flow channel measure the voltage that the fluid induces as it passes through this magnetic field. As the fluid flows through the magnetic field, the electrically charged particles separate in the flow channel and form a voltage between the electrodes. The sensor measures this voltage to determine the system flow rate.

You must consider three primary ratings when selecting an appropriate flow meter for a given application. The upper limit defines the highest flow rate the sensor can measure without exceeding its maximum tolerance for accuracy. For accurate measurement, the system flow rate should reach this upper limit for less than 1 hour per day and less than 200 hours total per year. The permanent flow rating is the highest continuous flow rate at which a flow sensor maintains its rated accuracy. The lower limit defines the minimum flow rate at which the flow sensor maintains its rated accuracy.

The ratio of the permanent flow rating to the lower limit is referred to as the turndown ratio. For example, a flow sensor with a 10:1 turndown ratio and a permanent flow rating of 20 gpm can measure flows as low as 2 gpm within its rated accuracy. The turndown ratio is a significant consideration when selecting a flow sensor. Flow sensors are most accurate when the system flow rates approach the permanent flow rating for the sensor. As the flow rate approaches the lower limit, the flow sensor’s accuracy decreases.

Selecting a Heat Meter

Cost is a significant consideration when selecting a heat meter. The use of an electromagnetic flow sensor for a residential SWH system could add 30% to the cost of the system. In comparison, for a large commercial sale-of-energy project, an electromagnetic flow sensor might represent less than 5% of the installed system cost. Depending upon the level of accuracy required, using an electromagnetic flow sensor could be appropriate for large commercial applications.

Due to their relative cost and varying degrees  continued on page 50 of accuracy, flow sensors tend to drive heat meter selection. The European Solar Thermal Industry Federation recommends the levels of heat meter accuracy shown in Table 1 based on the size of the collector array.

In many cases, industry professionals can use current international heat meter standards to verify the accuracy of heat meters in the US market. In some markets outside the US, heat meter manufacturers classify their products as Class 1, 2 or 3 (from most accurate to least accurate) based on the cumulative errors of the calculator, flow sensor and temperature-sensor pair within specified ranges of temperature and flow. However, determining the classification of meters available in the US is not always possible. Table 2 lists a range of specific details for five commonly used heat meters, including flow sensor type, pipe size, paired sensor type, recommended application, data and networking details, and estimated retail cost.

A recent development in SWH system metering is Sunnovations’ Ohm Monitoring System, which uses a single resistance-type temperature sensor. This sensor measures fluctuations in the average tank temperature and uses an advanced algorithm in the calculator’s software to translate these fluctuations into the quantity of energy delivered to or extracted from a storage tank. The sensor accounts for temperatures throughout the full height of the storage vessel. By eliminating a flow sensor and matched temperature sensor, Sunnovations intends for this new product to provide increased measurement accuracy at a lower cost. Due to its unique design, the Ohm Monitoring System may require a different heat metering standard to certify its accuracy.

Installation and Configuration Considerations

The rated accuracy of a particular heat meter is valid only if the meter is correctly installed and configured. A minor mistake in sensor placement or calculator configuration can have significant consequences on measurement accuracy.


The calculator must be properly configured to reflect the type of fluid in the system, the type of temperature-sensor pair and flow sensor, and the interval at which data from the system is recorded. Calculators that utilize SD cards for data storage do not add significant complexity to the installation. Using networked calculators requires a basic knowledge of working with IT systems.  continued on page 52 Some calculators may require adapters for connecting to the local network, while others require configuration of the device’s IP address. Limitations in the allowable length of wiring between the calculator and temperature-sensor pair and flow sensor may affect the location of the calculator.


The placement and configuration of temperature sensors has a significant impact on the value of the data the heat meter collects. Since the temperature difference between the sensors is the critical data collected, installers must maintain consistency with the installation of each sensor. If they immerse one sensor in the system fluid using a compression fitting, they must immerse the other in the fluid as well. Putting one sensor in the fluid and placing another in an immersion well or strapping it to the piping can have a significant impact on the measured temperature differential.

Manufacturers of complete heat meters should provide detailed instructions on proper temperature-sensor installation, which should include:

  • Orientation in the fluid path
  • Depth of immersion
  • Maximum length of the lead wire between the sensor and the calculator
  • Minimum size of the lead wire

Electrical interference can impact the voltage readings from the sensors, which will in turn affect the accuracy of the temperature readings. Installers should use shielded wire to connect the sensors to the calculator to avoid unwanted electrical interference.

The system flow rate also has significant influence on the accuracy of temperature-sensor pairs. At lower flow rates, the temperature difference between the reference points in the system is greater than at higher flow rates. When the temperature difference between the sensors is greater, the accuracy of temperature-sensor pairs is greater. For instance, when the temperature difference is 25°F, the maximum margin of error for two paired sensors with a maximum permissible deviation of 0.2°F per sensor would be 1.6% (0.4°F versus 25°F). At a temperature differential of 10°F, the same sensors would have a margin of error of 4% (0.4°F versus 10°F).


Flow sensors may introduce constrictions into the flow path of the fluid. Bluff bodies and impellers impede flow, as do the flow channels through various sensors. When the flow channel has a smaller diameter than the system piping or the flow channel utilizes multiple chambers to stabilize flow, the drop also requires consideration.

Fittings, pumps and valves affect the distribution of flow within a pipe. For accurate measurement, the flow needs to be stabilized before it enters the sensor’s flow channel, or the flow channel itself must stabilize the flow. For example, certain types of impeller flow sensors do not require a straight length of upstream pipe prior to the sensor’s flow channel because the flow channel is constructed of multiple ports to stabilize the flow as it strikes the impeller. Table 3 provides installation and placement recommendations for four flow sensors commonly used in metered SWH systems.

Like other SWH components, flow sensors must be able to withstand the design temperatures and pressures for the system. This is of particular importance in antifreeze systems, where the flow sensor could be subjected to steam and high pressures during stagnation. Flow sensors used in antifreeze systems must also be compatible with glycol. The documentation for some flow sensors specifies the maximum concentration of glycol in the solution or even goes as far as specifying the exact type of propylene glycol the sensor manufacturer allows.

Certain types of flow sensors are sensitive to air and particulates. As a result, some flow sensors have an integrated screen or require the installation of a separate screen or dirt trap. To alleviate issues with air, installers should not place flow sensors at high points in system piping. Some manufacturers suggest installing the flow sensor at a dip in system piping to reduce the sensor’s exposure to air. In all cases, thoroughly reading and understanding the installation details in the sensor’s product manual goes a long way toward ensuring proper sensor function and the accuracy of the collected data.

The Benefits of Heat Metering

For those solar heating contractors who have yet to work with heat meters, the learning curve may be challenging. It is important to recognize the nuances of calculators, flow sensors and temperature-sensor pairings in the design and installation of solar heating systems. Without proper consideration of equipment accuracy, installation requirements and the limitations of specific heat meter designs, the meter may produce flawed energy production data. In addition, familiarity with current international heat metering standards, working with reputable meter manufacturers, and meeting the requirements of funding entities such as utilities are key components to a successful installation.

As the demand for heat metering increases within the solar heating industry and more meters become available in the US market, designers, developers and installers will need to stay up-to-date with the latest product offerings and advancements. Existing international heat metering standards and the developing US standard will be instrumental in clarifying the field for solar heating professionals involved in projects that require metering.

Some solar heating contractors may see heat metering as an unnecessary burden. While the inclusion of heat meters does add some complexity, it can provide the assurance policy makers and investors require to implement financial instruments capable of expanding the solar heating industry. By quantifying the benefits of SWH systems, heat meters may play a key role in the expansion of the US solar heating market.


Vaughan Woodruff / Insource Renewables / Pittsfield, ME /


Alpha Thermal Systems (authorized RESOL US dealer) / 508.943.6000 /

flowIQ (Kamstrup US affiliate) / 404.835.6716 /

Grundfos Direct Sensors /

IMC Instruments / 715.253.2801 /

ONICON / 727.447.6140 /

Solar Hot USA / 919.439.2387 /

Steca /

Sunnovations /

Primary Category: 

According to conference organizers the Solar Energy Industries Association and the Solar Electric Power Association, more than 1,100 exhibitors are expected to showcase their goods and services at Solar Power International 2012 in Orlando, Florida. This presents a familiar challenge for the 20,000-plus conference attendees. In 2009, the number of exhibitors at SPI more than doubled over the previous year’s total—increasing from 425 to 929—and that number has exceeded 1,100 each year since then. This means it is impossible to visit every booth and very difficult to canvass every aisle in the exhibit halls.

With this in mind, SolarPro technical editors have compiled a short-list of exhibitors with particularly interesting products and services that will be on display in Orlando. This list includes some equipment that was showcased at Intersolar North America in July, as well as products that will be launched at SPI 2012. The list is by no means comprehensive, as many announcements and releases scheduled for Orlando are under embargo until the conference starts. However, some companies were willing to share embargoed news items with us before the conference, in part because of some fortuitous scheduling: SPI 2012 coincides with the advanced ship date for the October/November issue of SolarPro magazine.

So for those of you reading this article at the conference, we have included booth numbers for each of the companies profiled. If the product or service described here looks like it could solve problems for you, you can walk on over to the company’s booth and learn more about it. For those of you reading the article after the conference, this article can serve as a recap of equipment highlights.

In either case, look for additional post-conference coverage in “The Wire,” our department featuring new and noteworthy items, in the December/January 2013 issue of SolarPro magazine. In fact, if you attend the conference and see something that you think is a game changer or a time-saver, email us at If you are excited about a product or service, chances are other readers will be as well.


Advanced Energy has added a new central inverter and four non-isolated (transformerless) string inverter models to its product lineup. The AE 500, a 500 kW inverter developed for utility-scale solar plants, features an integrated dc circuit breaker subcombiner, a CEC-weighted efficiency of 97%, and a full power rating up to 55°C. The inverter includes an integrated gateway compatible with monitoring software from providers including AlsoEnergy, ArgusON, DECK Monitoring, Draker, ESA Renewables, Locus Energy, meteocontrol and Noveda Technologies. Advanced Energy’s recently released non-isolated string inverter line includes 3.8–7.0 kW models with field-configurable output voltages of 208, 240 or 277 Vac.

Advanced Energy / 800.446.9167 /

DPW SOLAR  Booth 1133

DPW Solar has added a new ground-mount racking solution to its product suite and has made significant improvements to its CRS ballasted system. The Power Peak ground mount is designed to reduce installation time and allow the racking system to conform to site-specific requirements. The structures are specified to match string layouts, and the module rails include wire channels to protect source-circuit conductors and speed the overall installation. The new CRS G2 ballasted racking system improves on the previous design with integrated grounding that meets the UL 467 standard, a reduced parts count to cut down on installation time, and a modular design that simplifies the roof layout.

DPW Solar / 505.889.3585 /

EATON  Booth 3701

As the new fuse-servicing disconnect requirements in Section 690.16(B) of NEC 2011 take effect, combiner and inverter manufacturers are more likely to utilize circuit breakers in place of fuses in products designed for commercial and utility applications. With the introduction of the PVGard line of circuit breakers, Eaton is the first manufacturer to meet the requirements contained in UL 489B, a new product standard developed specifically for molded-case circuit breakers and switches intended for use in PV systems. Products in the PVGard family are rated for 100% continuous current at 50°C and for use at up to 1,000 Vdc. The product line will include current ratings from 30 A to 600 A.

Eaton / 800.386.1911 /


Ecolibrium Solar has launched a fully redesigned polymer-based mounting solution for ballasted and hybrid ballasted and mechanically attached arrays deployed on commercial low-slope rooftops. The Ecofoot2 product utilizes an acrylonitrile styrene acrylate (ASA) Luran material manufactured by Styrolution, a BASF company. The total installed system weight ranges from 3 to 5 psf. Array tilt angle is 5° when modules are installed in portrait configuration and 10° with modules in landscape format. The product includes integrated module grounding and wire management. Interior wind deflectors minimize uplift forces and reduce overall ballast requirements. The product carries a 25-year warranty and is suitable for roofs with pitches of 0°–5°.

Ecolibrium Solar / 740.249.1877 /

FRONIUS USA  Booth 1957

In addition to its 3.0–11.4 kW single-phase string inverters, Fronius USA offers several solutions for small and large commercial-scale projects. Its 3-phase string inverter line includes three models. The 10.0-3 and 11.4-3 units have ac output voltages of 208/240 delta and are rated at 10 kW and 11.4 kW, respectively. The 12 kW 12.0-3 product is configured for 277 Vac wye output. Fronius’ 3-phase CL inverter line is based on the company’s MIX Concept, which offers a modular design based on up to 15 identical power stages. Models include 33.3, 44.4 and 55.5 kW units with 208/240 Vac delta output and 36, 48 and 60 kW units with 277 Vac wye ac output configurations.

Fronius USA / 810.220.4414 /


The newest addition to the KACO blueplanet inverter line is the 10 kW non-isolated (transformerless) XP10U-H4. The inverter’s non-isolated design results in a lightweight product that weighs in at 88 pounds. The CEC-weighted efficiency of the XP10U-H4 is 97%, and ac and dc surge protection is standard. Dual MPPT channels that operate between 200 and 600 Vdc allow integrators to maximize available roof space by utilizing asymmetrical string lengths or by installing modules with varying tilt and orientation values. The inverter’s integrated web server includes multiple data-interface options for access to the easyLINK monitoring services offered by KACO. A graphical user interface facilitates inverter commissioning and provides user-friendly access to inverter data.

KACO new energy / 415.931.2046 /


Drawing on the company’s experience as a manufacturer and distributor of specialty fasteners for the commercial roofing industry, OMG Roofing Products has developed the PowerGrip roofmount system for solar mounting on low-slope roofs. The PowerGrip solution is compatible with thermoplastic roofing membranes, such as TPO and PVC, and supports many membrane types, thicknesses and brands. Mechanical connection to the roof deck or structure is accomplished using an appropriate fastener. The PowerGrip assembly then slides over the head of the fastener. Afterward, the integrated manufacturer-specific flange is heat-welded to the roof membrane. These mechanical connections are rated for 305 pounds each and reduce ballast material needs.

OMG Roofing Products / 800.633.3800 /


The Radian Series GS8048 inverter/charger from OutBack Power provides system integrators with a powerful and scalable platform for off-grid and utility-interactive battery backup systems. Each Radian GS8048 supplies 120/240 Vac and is capable of providing 8,000 watts of continuous power and supporting high surge loads for shorter durations. For larger systems, up to 80 kW continuous, the ac inputs and outputs of up to 10 GS8048 inverter/ chargers can be connected in parallel using standard ac distribution panels. Each unit supports dual ac inputs—for the utility grid and a backup generator— and will accommodate an integrated BOS load center. Prewired options are available.

OutBack Power / 360.435.6030 /

PANELCLAW  Booth 3331

PanelClaw has added the Kodiak Bear mounting system to its portfolio of ballasted racking products. The new system is available in 10° and 15° tilt angles and utilizes proprietary, hydraulically compressed ballast that integrates with the racking system. The total array platform load, including racking, ballast and modules, ranges from approximately 3.5 to 9 psf. Modules are installed in landscape format. The Kodiak Bear product includes wind deflectors, rubber roof-membrane protection pads and integrated wire management. The solution is suitable for low-slope roof applications with a maximum pitch of 5° and is covered by a 10-year standard warranty.

PanelClaw / 978.688.4900 /

POWER-ONE  Booth 1749

Power-One is releasing two microinverters targeted for the US market rated at 250 W and 300 W. Both models are designed to connect to 240 Vac or 208 Vac electrical circuits. The inverters’ high-frequency transformer allows installations with modules that require grounding of either pole on the dc input side. Power-One offers a wireless communication hub, the Aurora CDD, which can support up to 30 microinverters. New string inverters from Power-One include the Aurora Uno, designed for residential and small commercial installations, and the Trio line, with 3-phase ac output for connection to commercial services. Both string inverter lines include models with or without isolation transformers.

Power-One / 805.987.8741 /

QUICK MOUNT PV  Booth 3062

Roof-mount manufacturer Quick Mount PV has launched two products for tile roof applications. The Quick Hook Curved Tile Mount and Quick Hook Flat Tile Mount are the first fully flashed tile-hook mounts on the market. Engineered for code-compliant, watertight mounting, both the curved and flat tile models use the same tile hook, which mates with the product’s base. The Quick Hook Curved Tile Mount has an extrawide base, allowing the installer to choose from multiple clearance holes to attach two lag screws to the rafter. A slot in the base enables the hook to slide into position to match the curve of the tile.

Quick Mount PV / 925.478.8269 /

REFUSOL  Booth 1721

REFUsol offers four UL-listed and CEC-eligible nonisolated 3-phase string inverters developed for small and large commercial projects and designed for 480 Vac grid interconnection. The inverters are manufactured in Greenville, South Carolina, and are Buy American Act compliant. The 12, 16, 20 and 23.2 kW units feature a wide MPPT range of 125 to 450 Vdc, CEC-weighted efficiencies of up to 98% and weigh in at 108 pounds. REFUsol partnered with Obvius to develop a Modbus monitoring solution that allows integration with third-party software provided by Also-Energy, ArgusON, DECK Monitoring, Draker, Locus Energy and Noveda Technologies, in addition to the company’s standard REFUlog monitoring platform.

REFUsol / 866.774.6643 /


Renusol America has added to the CS60 product line with the introduction of the 10° mounting system. The CS60 ballasted rack is a one-piece mounting solution where each module is mounted directly to a single CS60 base. The universal base is compatible with all common module dimensions. The system is made of nonconductive high-molecular-weight polyethylene, eliminating the need for equipment grounding associated with the racking system. The new 10° tilt angle allows integrators to achieve a greater power density on commercial rooftops. Other new features for the CS60 10° tilt include integral wire management, multiple east and west settings to better accommodate different module string lengths, and improved access for module installation.

Renusol America / 877.847.8919 /

S-5!  Booth 1277

Well known for its nonpenetrating metal roof-attachment solutions, S-5! recently introduced the VarioBracket, an adjustable attachment solution for trapezoidal metal roof systems. In addition to accommodating any trapezoidal ridge profile, the mounting bracket is also adjustable in height. Self-drilling bi-metal screws attach the stainless steel VarioBracket to the trapezoidal ridges of the roofing system; factory-applied sealant at the connection points ensures seal integrity. The company offers an ever-expanding line of S-5! clamps and brackets for different standing-seam metal roof profiles, as well as a new version of its S-5-PV Kit.

S-5! / 888.825.3432 /

SCHLETTER  Booth 1323

Perhaps best known for its utility-scale groundmounting systems, Schletter also offers the Park@Sol, a modular PV carport solution. The Park@Sol is available in three standard options: single row, double row, and a north-south configuration. It will accommodate residential arrays of just a few kilowatts or can be scaled up to accommodate multimegawatt parking structures. The Park@Sol is engineered for IBC compliance and can attach to a variety of foundation types. If desired, the system can include an optional waterproof covering below the modules. Schletter is also showcasing FS ECO, an affordable all-steel ground-mounting solution, as well as AluGrid, a low-slope commercial roof-mounting system.

Schletter / 520.289.8700 /

SMA AMERICA  Booth 2010

SMA is expanding the Sunny Boy line with the SB 240-US microinverter. The communication protocol for the SB 240 allows for hybrid installations that utilize micro and string inverters. SMA is also updating the Sunny Island line with a new 6 kW SI 6048 inverter and Smartformer. The Smartformer features a 120/240 V autoformer, ac distribution board and prewired bypass switch, and includes a load-shedding relay. Other new SMA products include the nonisolated Sunny Boy string inverter line and the mediumvoltage products for utility-scale installations.

SMA America / 888.476.2872 /

SNAPNRACK  Booth 2737

Both the commercial Series 350 ground mount and the Series 450 flat-roof mount from SnapNrack are now available with a new steel rail that lowers mounting structure costs by as much as 20%. The steel rail is designed to match the strength of the existing aluminum rail, but is stiffer and costs less. Like the aluminum rail, the roll-formed steel rail allows for the use of proprietary snap-in channel nuts for improved installation efficiency. Additional features on the bottom of the steel rail profile allow for a faster connection to a ground-mount substructure. The solution is field tested, supporting more than 10 MW of installed PV capacity. A video that details the steel rail is on display at the SnapNrack booth.

SnapNrack / 877.732.2860 /


SolarBridge Technologies has released the next generation of its ac module solutions, along with an enhanced communication and control system. SolarBridge partners with module manufacturers and integrates the Pantheon II microinverter to deliver listed ac modules. The Pantheon II is a higher-poweroutput version of its predecessor, with a higher efficiency and a smaller footprint. The updated SolarBridge Management System enables integrators to remotely access and control their PV systems. SolarBridge has announced new partnerships with ET Solar, MAGE Solar, NESL and Talesun Solar to add to the manufacturers that already offer the SolarBridge solution: BenQ Solar, Solartec and SunPower.

SolarBridge Technologies / 877.848.0708 /


The Solar-Log family of products from Solar Data Systems offers monitoring, data logging and plant visualization solutions for PV systems of all sizes. The Solar-Log200 is designed for residential PV systems with a single inverter under 15 kW in capacity; the Solar-Log500 accommodates up to 10 inverters and a total plant capacity of 50 kW; the Solar-Log1000 can monitor up to 100 inverters and a total inverter capacity of 1 MW. All models support local PC and Internet viewing, as well as remote viewing via the Solar-Log WEB interface. Solar-Log inverterdirect monitoring complies with CSI requirements for performance monitoring and reporting. The system also supports optional revenue-grade energy reporting.

Solar Data Systems / 203.702.7189 /

SOLAREDGE  Booth 3901

The newest generation of SolarEdge power optimizers does not require additional interface hardware and has the ability to operate directly with any grid-direct inverter. The new power optimizers offer the same benefits as the previous SolarEdge products—module-level MPPT and monitoring, and enhanced safety features— as well as improved design flexibility. The addition of the IndOP technology allows installation of the power optimizer in new installations regardless of the inverter technology, as well as integration with existing installations to increase energy yields.

SolarEdge / 530.273.3096 /

SOLARWORLD  Booth 1301

SolarWorld has diversified the scope of its manufacturing with the addition of fixed- and tracked-racking products. The Suntrac single-axis tracker can drive 250 kW to 1,000 kW of PV per motor. SolarWorld provides custom Suntrac configurations based on individual sites to accommodate grade variations and nonrectangular array boundaries. The Sunfix ground mount is designed to support arrays that range from 3.4 kW to multi MW and is compatible with driven pile, earth screws and ballast foundations. For residential-scale applications, the Sunfix plus pitchedroof racking system features preassembled top and end clamps, precut rail lengths and single-tool installation.

SolarWorld / 855.467.6527 /


Solectria Renewables recently released the newest Smart Grid 500 kW inverter, the SGI500XT, as an addition to its line of utility-scale inverters. The SGI line, including the new 500XT, is designed to work with the utility by offering real power curtailment, reactive power control, low voltage and frequency ride-through, and remote power control. The 98% CEC-efficient inverter offers integrators a number of features to aid installation and O&M. The non-isolated (transformerless) inverter has a 208 Vac output for direct to medium voltage system configurations. A Modbus communications platform allows for data collection with Solectria’s SolrenView or with third-party options.

Solectria Renewables / 978.683.9700 /


Stiebel Eltron offers a range of water-heating products that includes flat-plate solar collectors, pump stations and storage tanks; tankless electric water heaters; and heat-pump water heaters. The company’s 30-year background in heat-pump technology has led to the introduction of the Accelera 300 heat-pump water heater to the North American market. The Accelera 300 has an 80-gallon storage capacity and is backed by a 10-year warranty. The unit’s maximum rated power draw is 2,200 W (500 W for the compressor and fan, and 1,700 W for the backup electric heating element).

Stiebel Eltron / 800.582.8423 /

SUNLINK  Booth 2435

Precision RMS is the latest roof-mounting system from SunLink. Preassembled long-beam units run northsouth atop recycled rubber feet that may eliminate the need for slip sheets. For improved workflow, groups of two to four modules can be prepanelized, off-site or off-roof. The south edge of the panelized assemblies connects to the long beam using a pivot block, which allows for tilt access to the rear of the modules or the roof system underneath; the north edge is tilted up on strut brackets, allowing for tilt angles of 5°, 10°, 15°, 20°, 25° or 30°. The aluminum extrusions and stainless hardware are designed to provide integrated grounding per UL 2703, and the system includes wire-management trays and clips.

SunLink / 415.925.9650 /

TIGO ENERGY  Booth 3133

The newest offering from Tigo Energy is the MM-2ES, a dual Module Maximizer that can be used with one or two PV modules, reducing optimizer part count and increasing design flexibility. The endgame for Tigo Energy, of course, is to facilitate “smart module” solutions by providing optimized junction boxes to module manufacturers. Certification testing for the company’s junction-box– integrated Module Maximizer is under way, and completion may be announced at SPI 2012. The company will definitely announce that BEW Engineering—an independent, bank-approved engineering firm—has completed a positive bankability report regarding Tigo Energy’s products, practices and processes.

Tigo Energy / 408.402.0802 /

TMEIC  Booth 4025

The industrial systems departments of Toshiba and Mitsubishi Electric merged in 2003 to form TMEIC. The manufacturer’s line of utility-scale PV inverters for the North American market currently includes three models. The SOLAR WARE 630, SOLAR WARE 500 and SOLAR WARE 250 have rated power outputs of 630, 500 and 250 kW, respectively. TMEIC also offers the prepackaged SOLAR WARE station, available in 1.0 and 2.5 MW power blocks that include inverters, dc recombiners and pad-mounted transformers. The 1,000 Vdc inverters feature a 540–950 Vdc MPPT operating range and grid assistance modes that include reactive and active power control, fault ridethrough and power factor control.

TMEIC / 540.283.2000 /


Trojan Battery Company’s new 2-volt deep-cycle, highcapacity battery additions to its Industrial Line are engineered to offer increased design flexibility for solar applications. The recently released IND27-2V battery has a capacity of 1,457 amp-hours at the C20 rate, and the IND33-2V battery has a capacity of 1,794 amp-hours at the C20 rate. Trojan’s Industrial Line is designed to support large daily loads where the batteries are cycled regularly in standalone PV applications such as off-grid homes, micro-grids and telecom applications. The company also released a new “Made in the USA” 12-volt AGM battery with a capacity of 140 amphours at the C20 rate.

Trojan Battery / 800.423.6569 /


The Instant Connect product line from Westinghouse Solar integrates racking, equipment grounding and electrical connections into the design of the PV module in an effort to reduce installation time and improve installation quality. The grooved frame accommodates mounting systems deployed on pitched residential roofs and low-slope commercial buildings. The mechanical splice integrated into each module electrically bonds the modules together and provides mechanical support. During installation, the splice also aligns the modules’ integrated electrical connections, engaging the module-to-module plug. The Instant Connect modules are available in dc versions , as well as ac versions that employ Enphase microinverters.

Westinghouse Solar / 888.395.2248 /


Primary Category: 

The solar thermal system integrates seamlessly with the 2,500-squarefoot home’s radiant heating system. Utilizing the STSS proprietary submerged coil design, the 415-gallon tank serves as the main heat source for space heating and as a preheat source for domestic hot water. A high-efficiency boiler serves as backup for the solar water heating system. In any space heating installation, introducing new controls is one of the biggest design challenges. Therefore, Alternative Power Solutions (APS) selected the STSS Energy Management Control (EMC) as the multisystem interface. The EMC wires directly to the boiler system controls and measures solar storage-tank temperature compared to thermostat set point, automatically switching to the boiler when the tank is unable to maintain the desired room temperature.

APS worked closely with the homeowners to orient the garage to true south and allocate the necessary rooftop collector area. SunMaxx racking eliminated the need for a custom-mount system, reducing material costs and installation time. The six SunMaxx collectors are mounted at a 65° tilt to optimize energy production in the winter heating months. If surplus heat is gained, a diverting valve directs fluid through a 150 K/Btu heat dump before returning it to the tank. An inline 500-gallon hot tub absorbs any additional heat produced in the summer, nearly eliminating the need for the heat dump. To maximize the R-value and avoid groundwater damage along the 70-foot underground pipe run from the array to the storage tank, the 1-inch Type K copper pipe was insulated with HT/Armaflex and sleeved in corrugated plastic tubing.

“The challenge of solar thermal is one of the main reasons we do it. The overall outcome here was fantastic. There is nothing more rewarding than helping someone reduce heating bills with the sun. With the new technology, solar thermal has caught right up to PV panels in life expectancy and system longevity.”

— Owen Pugh, Alternative Power Solutions


DESIGNER: Timothy Pugh, senior design engineer, Alternative Power Solutions,
LEAD INSTALLER: Owen Pugh, president, Alternative Power Solutions
LOCATION: Clayton, NY, 44°N
SOLAR RESOURCE: 4.2 kWh/m2/day
COLLECTOR ARRAY AREA: 332 square feet

Equipment Specifications

COLLECTORS: Six Silicon Solar Sun- Maxx SM-30 evacuated tube
HEAT EXCHANGERS: One 0.75-in.- by-120-ft. copper coil for solar input, one 0.75-in.-by-120-ft. copper coil for domestic hot water, two 0.75-in.-by- 120-ft. copper coils for space heating; all exchangers manufactured by STSS
PUMP: Grundfos UP26-99BF STORAGE: STSS 415-gallon tank with multiple submerged coils
CONTROLS: Caleffi iSolar-3 differential controller, STSS Energy Management Control
FREEZE CONTROL: Closed loop, propylene glycol
COLLECTOR INSTALLATION: Pitched roof, composition roofing material, SunMaxx racking system, 196° azimuth, 65° tilt

Primary Category: 

My company is beginning to get calls for radiant solar thermal space heating systems, which is a new application for us. Any related design advice for collector, storage and system control approaches would be appreciated.

Radiant floor heating systems are a good fit with solar energy for two reasons. First, the temperature needed for radiant heating is relatively low, and solar collectors work more efficiently for lower temperature applications. Second, if the tubing that circulates the heated fluid from the collectors is embedded in a floor with high thermal mass, such as a concrete slab, the storage for nighttime heating is already built in.

System sizing basics. Every solar thermal space heating system is unique, and sizing is extremely dependent on the project’s location and the building’s construction. In space heating applications, collector surface area in square feet will typically range from 8% to 15% of the building’s square footage of conditioned space. The collector area of systems installed in milder climates with sunny winters will fall on the lower end of the approximation. Where required, storage tanks in locations with higher winter irradiance are sized at approximately two gallons for every square foot of collector surface area. In climates with lower irradiance, the tank should be downsized to about one and half gallons per square foot of collector.

Solar assisted radiant floor systems can provide up to 80% of a building’s heating load, but more often they are designed to offset 50% to 60% of the fuel usage. The solar thermal system displaces some of the heating load by circulating the floor loop fluid through the solar collectors.

System design options. Solar thermal space heating systems can be configured as either drainback or antifreeze designs. Some system designers prefer a closed loop design that uses an antifreeze solution of propylene glycol and water, since the pumps required for its circulation can be smaller. Summer overheating is an issue with antifreeze designs for space heating due to seasonal load imbalance. (See "Thermal Balance" in SolarPro, Feb/Mar 2009 for overheating solutions.) Most installers prefer drainback designs because of the inherent over-temperature protection against high stagnation temperatures.

The simplest space heating design involves integrating the solar collectors directly with the cross-linked polyethylene (PEX) circulation loops. The PEX, in turn, serves as the exchange mechanism to deliver heat to the slab. This approach eliminates components—the storage tank and heat exchanger—but comes with a caveat: A buffer tank is needed to protect the PEX tubing from high collector fluid temperatures.

For heating applications, PEX is rated for service temperatures up to approximately 200°F, depending on system pressure. Any interruption of the pump, including power outages or thermostat controls, that circulates fluid through the collector array during hours of good solar irradiance will soon heat the collector fluid to stagnation temperatures (~ 350°F). When the pump or pumps come back on, the first few gallons of fluid returning to the tubing in the floor are considerably above the PEX service temperature and can cause permanent damage. Including a buffer tank in slab-direct heating systems is imperative. A good example of a buffer tank for this type of system is a drainback tank of sufficient size placed on the hot return piping. The extremely hot collector loop fluid will mix with the cooler fluid in the drainback tank prior to being introduced into the PEX loops.

Most existing radiant floor systems use a simple zone valve to control the flow to separate parts of a floor. A newer type of system gaining popularity uses very small individual pumps instead of traditional valves to control the flow in each zone.

Additional storage approaches. The decision to add a high volume storage tank to a radiant system is primarily based on the tubing installation. If the tubing is embedded in high thermal mass, an additional storage tank is not always required. The minimum thermal mass considered adequate for storage is a 4-inch concrete slab or equivalent, insulated from the ground surface with high-density rigid foam board. Solar assisted heating systems are also being integrated with PEX tubing embedded in up to 2 feet of sand topped with concrete, bricks or stone. Floors made with large amounts of thermal mass can have a heating lag time issue, however. Heat is lost through solids like concrete, brick and sand in all directions, resulting in a lag time of up to several hours from the point of calling for heat at a thermostat to the time the indoor temperature reaches the thermostat setpoint.

A radiant system installed under a wood subfloor or in a thin layer of lightweight concrete needs a large tank to provide heat storage—otherwise the solar assist is just a daytime heating system. Water is an excellent storage medium because it is free and has an exceptional specific heat of 1. Brick, sand and concrete have specific heats of about 0.2. Although water has a specific heat about five times that of concrete, concrete weighs water. Since heat capacity is based on the specific heat and the weight of the material, water has about twice the heat capacity of an equal volume of concrete. Large storage tanks may add to the plumbing complexity, but they are easy to control. Retrofit solar assisted systems with the minimum 4-inch concrete slab are often designed with storage tanks to increase the heat load displacement.

Solar assisted radiant space heating systems that include a storage tank offer more design options and often more precise temperature control than slab-direct designs. Systems with large tanks for nighttime storage typically use coiled copper tubing as the heat exchanger. An additional benefit to this approach is that the heat exchanger acts as a temperature buffer between the collectors and the floor tubing loops. Stainless steel plate heat exchangers are another option to consider in systems that include a high mass floor.

Control strategies. The many options for system design make control standardization for solar assisted space heating systems difficult if not impossible. Some designs are simple, but complete automation requires complex controls. Control logic starts with a good understanding of the system operation. Solar assisted radiant systems can be designed to preheat the hot water boiler or bypass it. This can be accomplished with a motorized three-port valve. If the design calls for preheating a cast iron boiler, the heat exchanger in the storage tank will act as a buffer against high stagnation fluid temperatures and prevent possible thermal shock damage to the boiler.

A common retrofit is a drainback system that is piped to bypass the existing boiler. A motorized valve is placed downstream from the boiler pump but before the floor heating fluid enters the boiler. The valve has the pump outlet. The normally closed port is connected to the boiler. The normally open port is connected to a coiled heat exchanger in the storage tank. The system controls actuate the valve when the tank water temperature is high enough to heat the floor. In order for the system to operate efficiently, the circuit to the gas valve in the boiler must be opened via a relay when the solar storage tank is heating the floor. This can be done with an off the shelf relay with the 120 V relay coil wired in parallel with the valve.

With this control strategy, the existing room thermostat controls the system. When the thermostat calls for heat and a floor zone valve opens, the pump is energized. An Aquastat that monitors the tank temperature also controls the motorized valve and a relay. If the storage tank temperature is lower than the tank Aquastat setpoint (90° to 120°F), the system operates as it did prior to the solar integration. The setpoint for the Aquastat is dependent on each radiant floor system and is set at a temperature that is usually determined by owner preferences. A lower temperature will save energy but might produce a lag in heating the floor. A higher setting lessens the chance of any inconvenience. When the tank temperature is above the setpoint, the motorized valve and relay are energized. The floor water is then directed to the coiled heat exchanger and back into the floor.

The bypass design can also be used with baseboard heating where a boiler preheat design is normally not a good option. The high boiler temperature setting associated with baseboard heaters (~ 170°F) is above the efficient operating temperature of medium temperature collectors. This design also eliminates concerns of some high efficiency boiler manufacturers who specifically discourage preheating boiler water. Additionally, when the motorized valve is not energized, it prevents the boiler from heating the storage tank.

Finally, most solar assisted radiant systems that include a storage tank incorporate a second heat exchanger, typically a coil of copper tubing that heats the domestic hot water. The DHW pump for this loop is controlled by a standard differential control with sensors measuring the water at the top of the storage tank and the bottom of the water heater.

Chuck Marken / SolarPro magazine / Ashland, OR /

Primary Category: 

[Eugene, OR] DECK Monitoring has added two commercial solar thermal system monitoring packages to its existing suite of PV monitoring solutions. The new web-based products are configured for systems with either 2-inch or smaller inlet and outlet piping or with 2.5-inch or larger piping. Both packages include a BTU meter and revenue-grade monitoring of six data points: two temperature probes (cold water inlet and hot water storage tank outlet), one flow-rate meter (cold water inlet), and three current transformers (CTs) for monitoring energy use for up to two pumps and one backup electric water heater. A data acquisition and logging gateway comes standard with each package. Optional add-on components consist of energy monitoring equipment for natural gas and fuel oil backup water heaters, weather stations, display devices and interactive kiosks. Data point monitoring for additional CTs and temperature probes is also available.

DECK Monitoring / 503.224.5546 /

Primary Category: 

Flat-plate solar heat collectors are typically mounted at a fixed tilt with a true south orientation. The tilt angle must take advantage of the most useful altitude angles of the sun, while the orientation allows good exposure to the solar azimuth angles—the sun’s path from east to west. The optimal choices depend on design considerations that are often in conflict.

The ideal collector tilt angle maximizes the solar heat available to heating loads throughout the year. The roof pitch and profile, the space available and shading factors often complicate reaching this goal. If there is more than one load, such as space heat and domestic hot water (DHW), the collectors may require a tilt that favors the larger space-heating load over the smaller domestic water heating load. The final choice for a fixed mounting system may be a compromise.

Azimuth Orientation

For most common heating loads in northern latitudes, the best orientation angle is true south. Fixed collectors that face true south collect the most solar energy possible on a clear day at a given tilt. Small variations to the east or west of +/-20° have little effect on the annual solar heat delivery. The curves shown in Graph 1 prove this point. Solar energy incident on a flat-plate solar collector has been plotted for the average annual clear day in Los Alamos, New Mexico. The top curve shows a collector tilted at 45° (typical for this climate), and the curve below it shows clear-day data for a collector tilted at 75°. Steeper tilts are often used for larger banks of collectors dedicated mostly to winter space heating in this region. You can see that as the collector is rotated away from true south, the annual solar energy available drops off very gradually.

There is a difference between clear-day insolation and available incident solar energy. Given that local cloud patterns might occur more often at a certain time of day, the solar energy delivered can differ from what the clear-day data suggests. In Graph 1, the available annual solar radiation profile is plotted on the lower two curves, taking into account the local weather data. You can see that these curves are not symmetrical the way the clear-day curves are. The available solar energy in Los Alamos typically drops off in the afternoon due to high-mountain cloud formations. This happens with such regularity that the optimum solar heat is captured by facing the collectors 15° east of true south. The east-of-south orientation provides a small amount of additional solar heat annually in this distinct location.

Solar heating installers commonly hold that collectors placed within 20° of true south will perform as intended. Graph 1 confirms this rule of thumb, showing that annual performance does not drop off drastically with minor changes in orientation. The collector tilt angle has a more critical effect on annual solar heat production. Different tilt angles can produce widely differing solar heating results, both annually and seasonally. The optimum tilt angle is largely dictated by the location (longitude) and the climate (cloudiness and temperature range). Before evaluating the consequences of collector tilt, however, you need localized solar and climate data.

NREL Monthly Solar Climate Data

You would be wise to inspect solar heating climate data month by month. A good resource for this data is the National Renewable Energy Laboratory (NREL) website. Its “Solar Radiation Data Manual for Flat-Plate and Concentrating Collectors” contains data for 239 locations across the US and can be obtained free on the web at Comma-delimited ASCII data files can be downloaded into your own spreadsheets for use in solar calculations.

Each data page describes the location, presents average solar radiation values month-by-month for flat-plate and concentrating collectors and gives average conditions, such as temperature, heating-degree days and humidity. Data are presented by NREL for five tilt angles from the horizontal: 0°, latitude minus 15°, latitude, latitude plus 15°, and 90°. Data for a tilt of 0° (referred to as global horizontal solar radiation) show how much solar radiation is received by a horizontal surface, such as a solar swimming pool cover.

According to the NREL manual, maximum yearly solar radiation can be achieved using a tilt angle approximately equal to a site’s latitude. To optimize performance in the winter, the collector can be tilted 15° greater than the latitude; for best performance in the summer, the tilt can be 15° less than the latitude. Data for a tilt of 90° apply to collectors mounted vertically on south-facing walls (primarily for winter space heating) and to south-facing windows for passive solar-heated designs.

System Design Software Tools

Solar heating system design software is becoming more popular. The most sophisticated simulations employ hour-by-hour weather data to calculate solar energy availability and heating needs in a particular location. The weather data are processed to produce hourly, monthly and annual calculations. Popular programs include Energy-10, Energy Plus, Tsol, PolySun and Retscreen.

The Climate Consultant weather data visualization program is free from the UCLA Energy Design Tools web page at This program displays the contents of Energy Plus Weather files that are available free from the EnergyPlus website. You can inspect the latitude, longitude, global horizontal and direct normal solar radiation, air temperature, dew point, ground temperature, wind speed, sun path, sun hours, and a multitude of other climate variables for more than 2,000 locations, based on historical weather records.

Heat Load Profile Considerations

Residential DHW usage is often a constant load each month when the residence is continuously occupied. It is typical for occupants to consume 15 to 20 gallons of hot water per person per day all year round. If 80 gallons per day are consumed with a 70° temperature rise required from the water heater, then around 46,000 Btu are needed per day. This idealized hot water load is shown for a sample retrofit project near Sterling, Virginia, in Graph 2 as a horizontal line.

Residential space heating loads are another matter. The example 2,000-square-foot house near Sterling requires 400 Btu per hour per °F of difference (delta T) between indoors and outdoors, plus extra production for heat loss due to air infiltration. The space heating load rises dramatically in winter and drops to nothing in summer, fluctuating greatly over the year as shown in Graph 3. To make things even more challenging, if you choose the wrong collector tilt, the need for space heat can be out of phase with the solar heat available by as much as 6 months.

Matching Heat Load to Solar Heat Source

Graphs 2 and 3 show NREL solar climate data for the Sterling, Virginia, project. Latitude minus 15° was omitted and a steep tilt of 72° was added. These curves show how much solar heat is available to collectors on a typical day each month at different tilts. This can be compared to the heat load on a typical day each month, plotted as a red line.

In the case of a solar water heater in Graph 2, the comparison is straightforward. The typical daily DHW heating load is a horizontal line. The optimal collector tilt provides solar heat that most closely follows the load. Just as NREL predicts, the latitude plus 15° collector tilt tends to better match the load year-round than the latitude tilt curve, which produces excess heat in summer and less heat in winter. In this example, the 64 square feet of collectors could be installed with a 100–120 gallon DHW storage tank to absorb the extra heat in summer while providing 80 gallons of hot water each day.

The same choices are compared in Graph 3, but this time applied to a collector array of 320 square feet, which is big enough to make a significant contribution to the space heating as well as DHW. The DHW is a constant load. The area above this horizontal line and below the solar collector tilt line is summer heat that is not really needed, but is available for pool heating. The sample project has no pool, so the design becomes a balancing act of reducing excess heat in the summer while maintaining the heat available in winter. Graph 3 shows that a vertical (90°) tilt best fits the profile of the annual heating load, but the latitude plus 15° tilt works much better in the spring. A happy medium is around 72°, which does not cut off heat too drastically in the spring but does cut off pretty well in the summer.

A perfect match is not always easy or economical, which is why solar heating systems are commonly designed to offset a significant amount of the annual heating load, but not all of it. In this example, 320 square feet of collectors provide approximately half of the annual heating load. The solar heat contribution shown here is typical of retrofits, but systems can be designed for higher or lower solar contributions depending on factors such as the climate, economics and heat storage approaches.

Practical Considerations

When mounting collectors at a fixed tilt, some of the most important considerations have little to do with sun angles. Some of the practical issues I have run into include the following.

  • Solar tax credits and other related financial incentives might alter the economics in favor of more collectors. When this is the case, the designer must take more care to avoid overheating during the warm season. Often the final tilt angle is steeper.
  • When packing more collectors into a limited area, shading becomes more of an issue. As the number of collectors increases, the required tilt angle changes, the number of rows may increase and the time spent on shading analysis should increase accordingly.
  • Some vacuum-tube collectors may not function properly if they are tilted too close to vertical or too close to horizontal. Consult the installation manuals to be sure the solar collectors are appropriate to the job.
  • Drainback collectors must be installed to drain properly by gravity, so creative piping and unconventional tilts may be problematic. Some vacuum-tube collectors can drain back and some cannot, and flat-plate collectors using serpentine risers cannot be used in drainback systems.
  • Snow shedding takes longer at a shallow tilt. Vacuum-tube collectors tend to hold onto snow that clings to their glass covers. In snowy climates, access for snow removal should be a consideration.
  • When a steep tilt is required, a low-profile collector may be preferable. One solution, for example, is using collectors manufactured by Solar Skies and Viessmann that incorporate low-mount collectors with internal horizontal headers.

Special thanks to Dr. Fred Milder at SolarLogic for the solar climate data graphs presented here.

Bristol Stickney / SolarLogic / Santa Fe, NM /

Primary Category: 

What is the Uniform Solar Energy Code and how does it impact professional solar thermal system designers and installers?

The International Association of Plumbing and Mechanical Officials (IAPMO) published the Uniform Solar Energy Code (USEC) in 1976. The USEC is a set of regulations that relates to solar energy in plumbing and mechanical systems installed in the US. The most recent edition of the USEC was published in 2006 and is 86 pages in length. The bulk of the USEC refers to the Uniform Plumbing Code or Uniform Mechanical Code. These latter two more established codes cover plumbing and HVACR installations. All three books are published by the IAPMO - aka plumbing inspectors.

While the USEC has been around since the ‘70s, it never developed much of a following. However, this is changing. Many cities and counties in California have recently adopted the code; Austin, Texas has published adoption papers; and New Mexico recently became the first state to adopt the USEC statewide. When a code is adopted, it becomes the standard that inspectors use to evaluate the health and safety aspects of any applicable system installation.

Controversial requirements.

The USEC has some unique requirements, and some of them are controversial. Codebooks tend to have many stipulations—with and without exceptions—without meaning that there is only one way to comply or suffer a red tag. In other cases, exceptions to rules are an alternate standard. For example Section 406 of the USEC states: “Copper tube for water piping shall have a weight of not less than Type L.” An exception follows that allows thinner walled Type M tubing for water piping above ground in or on a building or underground when outside the building.

The most controversial stipulation comes in Section 701.5 of the USEC: “Glass used in collector construction shall be of the tempered type.” There are no exceptions. Many evacuated tube collectors are constructed with non-tempered borosilicate glass, better known by the trade name Pyrex®. This would seem to leave borosilicate evacuated tube collectors in questionable territory where the USEC has been adopted. The local inspector or building official - the Authority Having Jurisdiction (AHJ) - would have the final say on the matter.

Another provision that might cause an installer some concern involves insulation. The USEC has some specific rules for collector, duct and pipe insulation. In “Large Thermal Arrays,” SolarPro1.1, we covered some pipe insulation rules, but the USEC also describes stipulations for insulation in air collectors and ductwork insulation based on heating degree days. In addition, pipe, duct and air collector insulation must have fairly stringent flame spread and smoke developed ratings of 25 and 50 respectively. For some types of insulation, this is not a problem; but others might get you a red tag if the inspector is savvy.

Make yourself heard.

If the USEC comes knocking at your local energy office or council, and you think some of the provisions are onerous and could be harmful, speak up—loud and early. In many cases, codes are not adopted in full. Sometimes provisions and occasionally entire chapters are not included in the adoption. What rules are followed is up to the governing authority of each location: the council, commission or assembly in cities and counties, and usually the state energy office on a state level. Industry associations, both existing and new, are needed to educate and influence these public officials.

What if the USEC has already been adopted in your area, and it will affect a present or future installation? Your best defense is a set of plans or drawings that have been approved and stamped by the local building department. Unless the local inspectors are current on the rules, getting a plan approved with design or materials elements that contradict some obscure details in a new code happens all the time. Be aware that even if a drawing is approved, inspectors can always slap a correction notice on something they find objectionable. If a planning department official or an inspector pulls out the codebook, the responsibility to educate the AHJ falls on your shoulders.

The USEC currently is not well known, but that is changing and will probably change faster with the rapid growth in solar thermal installations. Knowing the contents of the USEC may well save you some grief on an upcoming project.

Chuck Marken / SolarPro magazine / Ashland, OR /

Primary Category: 

To provide students with the opportunity to compare technologies and relative system performance, Okanagan College’s solar water-heating system utilizes both flat-plate and evacuated-tube collector technologies. The hot water generated is used for domestic water and space heating. At the time of publication, Swiss Solar Tech had installed and commissioned Phase One of the system, composed of 18 flat-plate collectors. Phase Two will include the addition of eleven 30-tube evacuatedtube collectors. A direct digital control system transfers data such as collector temperatures, storage tank input and output temperatures, and energy production to a website for performance evaluation.

Swiss Solar Tech installed the collectors on custom-engineered racking. Unlike the PV arrays, the thermal collectors were installed at a more traditional 45° tilt angle to maximize energy production during the seasons of highest hotwater demand. Roof curbs were specified by the engineers and incorporated into the building and racking design. Because the system’s storage tanks are located in the building’s central mechanical room, the pipe run between the collectors and the tanks needed to be 148 feet. To minimize heating losses, this design required special consideration during the thermal system installation.

“Given that the PV and thermal systems were included in the original building design and all the various trades worked together, our installation was fairly smooth. The biggest challenge was coordinating all the aspects of construction to meet the federal government’s deadline for the incentives.”

—Tim Schulhauser, P. Eng., SkyFire Energy

Thermal Overview

DESIGNER: Roger Huber, CEO, Swiss Solar Tech,
LEAD INSTALLER: Richard Steuble, Swiss Solar Tech
COLLECTOR ARRAY AREA: 450 sq. ft. (flat-plate collectors), 512 sq. ft. (evacuated-tube collectors, gross area)

Thermal Equipment Specifications

COLLECTORS: 18 Viessmann Vitosol 200-F flat-plate, 11 Viessmann Vitosol 200-T evacuated-tube
HEAT EXCHANGERS: Two Advanced Industrial Components (AIC) LB3120DW
PUMPS: Grundfos UPS26-150
STORAGE: Eight Bradford White 120-gallon tanks
FREEZE CONTROL: Closed-loop glycol
COLLECTOR INSTALLATION: Lowslope roof, single-ply membrane, custom collector array mounts, 180° azimuth, 45° tilt
SYSTEM MONITORING: Direct digital control (DDC) with web-based data transfer


Subscribe to Solar Heating