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PV System Operations and Maintenance

Fundamentals

Solar America Board for Codes and Standards www.solarabcs.org

Prepared by

Josh Haney Adam Burstein Next Phase Solar. Inc.

August 2013

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DISCLAIMER

This report was prepared as an account of work sponsored by an agency of the United States government. Neither the United States government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any infor-mation, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States government or any agency thereof.

Download a copy of the report:

www.solarabcs.org/O&M

EXECUTIVE SUMMARY

Until recently, the U.S. photovoltaics (PV) Industry has focused on the development of PV module technology, inverters, components, and manufacturing. The United States now has more than 7.4 gigawatts (GW) of installed capacity, comprising more than 300,000 systems (Sherwood, 2013).

In light of this growth and the continued maturation of the PV market, the industry must focus on operating and maintaining systems. PV installation lifetimes are expected to be 25 years or more, so safe and proper maintenance is an integral part of successful and reliable operation. System operations and maintenance (O&M) is a broad area, and is the continuing focus of several industry/ government/national laboratory working groups that are working to better define the issues and develop consensus approaches. In the interim, the Solar America Board for Codes and Standards (Solar ABCs) has prepared an O&M introductory report that includes practical guidelines for PV system maintenance and options for inspection practices for grounded PV systems. This report does not cover bi-polar, ungrounded, stand-alone, or battery backup systems.

With the understandable focus on maximizing return on investment (ROI) and system production, system uptime is a key O&M objective. For example, inverters that are offline can have a dramatic negative impact on the ROI of a PV system.

Inverter failure rates are important to ROI, but equally or even more important than how often an inverter goes offline is how quickly it can be placed back into service. Diagnosing and correcting power production deficiencies is also important to maximizing availability of system components and ROI. This report includes the current, commonly used diagnostic and troubleshooting procedures for inverter malfunctions or failures and associated reduced power production.

The intent of this report is to help qualified individuals maintain and inspect PV systems safely. Qualification to conduct such inspections is earned by direct on-the-job training under qualified supervision or through training programs offered by accredited educational institutions or manufacturers. It should be noted that many testing and maintenance activities require two people to be performed safely and efficiently. Currently, an employee who is being trained for a task, demonstrates the ability to perform duties related to that task safely, and is under the direct supervision of a qualified person is usually considered to be a qualified person.

This report also addresses currently known major safety requirements during PV servicing and repair, including the proper use of lockout/tagout procedures, the use of personal protective equipment, procedures for safely disconnecting live circuits, and appropriate observation of and compliance with all PV-specific system signage and warnings. In addition, it includes information about routine preventive maintenance and emergency shutdown procedures.

Newer PV systems may use devices that are not covered in this document, and technicians should contact the manufacturer for instructions on operating and maintaining such devices. This report also does not cover all the variations in equipment and measurement techniques that are available to qualified personnel, and there are suitable substitutes available for the equipment listed here.

Readers should also be aware that PV systems are evolving to higher voltages, and voltmeters and other devices must be rated for use at the higher 1,000-volt level.

PV System Operations and Maintenance Fundamentals

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Conclusions

The conclusions of this introductory report include:

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AUTHOR BIOGRAPHIES

Josh Haney Next Phase Solar, Inc.

Josh Haney is director of technical services at Next Phase Solar, Inc., which provides post-installation solar services focusing on operations and maintenance of existing photovoltaic (PV) arrays. He has more than two decades experience in the renewable energy field, and has installed, serviced, and managed the installation and maintenance of both small- and large-scale solar systems total-ing more than 100 megawatts. He has also overseen the daily monitoring and operations of commercial projects through data acquisition systems. In addition to being a North American Board of Certified Energy Practitioners (NABCEP) certified solar PV installer and a certified California journeyman electrician, he holds a Master of Business Administration with an emphasis in management from San Diego State University.

Adam Burstein Next Phase Solar, Inc.

Adam Burstein is the president of Next Phase Solar, which he founded in September 2009 to bring technical know-how and strong customer service to the photovoltaic operations and maintenance (O&M) industry. Next Phase provides O&M on more than 150 megawatts of commercial PV arrays and more than 10,000 residential systems across the country. Prior to his work at Next Phase Solar, Adam spent eight years leading PowerLight’s and then SunPower’s O&M efforts.

Acknowledgments

This material is based upon work supported by the U.S. Department of Energy under Award Number DE-FC36-07GO17034. The authors sincerely thank the following individuals who have provided helpful reviews and comments for this report: Greg Ball (DNV), Ward Bower (Ward Bower Innovations LLC), Bill Brooks (Brooks Engineering), Dave Click (Florida Solar Energy Center), Marv Dargatz, and Andrew Rosenthal (New Mexico State University).

Solar America Board for Codes and Standards

The Solar America Board for Codes and Standards (Solar ABCs) provides an effective venue for all solar stakeholders. It consists of a collaboration of experts who formally gather and prioritize input from groups such as policy makers, manufacturers, installers, and large and small-scale consumers. Together, these entities make balanced recommendations to codes and standards organizations for existing and new solar technologies. The U.S. Department of Energy funds Solar ABCs as part of its commitment to facilitate widespread adoption of safe, reliable, and cost-effective solar technologies.

For more information, visit the Solar ABCs website:

www.solarabcs.org

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DISCLAIMER

EXECUTIVE SUMMARY

AUTHOR BIOGRAPHIES

SOLAR ABCS

ACKNOWLEDGMENTS

INTRODUCTION

Qualified Personnel

SAFETY REQUIREMENTS

Lockout/Tagout PPE and Other Safety Equipment Safe Operation of Electrical Disconnects PV-Specific Signage and Warnings

ROUTINE SCHEDULED PREVENTIVE MAINTENANCE

General Site Annual Inspection Detailed Visual Inspection Manufacturer-Specific Inverter Inspection Manufacturer-Specific Tracker Inspection Manufacturer-Specific Data Acquisition System Inspection

GENERAL ISOLATION PROCEDURES

Energized Components Inverter Pad Equipment Transformer Isolation

FAILURE RESPONSE

Emergency Shutdown Isolation Procedure—Inverter Pad Equipment Isolation Procedure—Field Combiner Box Isolation Procedure—Modules and String Wiring

INVERTER TROUBLESHOOTING AND SERVICE

Inverter Troubleshooting Inverter Service Procedures

DIAGNOSING AND TESTING FOR LOW POWER PRODUCTION

Diagnostic Overview Diagnostic Testing Infrared (IR) Image Procedure Megohmmeter Testing Fuse Checks DC System Voc Checks DC System Imp Checks Grounding System Integrity Checks DAS Check Ground Fault Troubleshooting Array Washing Procedure Vegetation Management System Warranties

CONCLUSIONS

ACRONYMS

GLOSSARY

REFERENCES

TABLE OF CONTENTS

7 PV System Operations and Maintenance Fundamentals

Introduction

For most of its history, the U.S. photovoltaics (PV) Industry has focused on the development of PV module technology, inverters, components, and manufacturing.

These efforts have helped to advance the state of the art for PV systems worldwide.

The United States now has more than 7.4 gigawatts (GW) of installed capacity, comprising more than 300,000 systems (Sherwood, 2013).

In light of this growth and the continued maturation of the PV market, the industry must focus on operating and maintaining systems. PV installation life-times are expected to be 25 years or more, so safe and proper maintenance is an integral part of successful and reliable operation. System operations and main-tenance (O&M) is a broad area, and is the continuing focus of several industry/ government/national laboratory working groups. These groups will better define the issues and develop consensus O&M approaches over the next few years. In the interim, Solar ABCs has prepared an O&M introductory report that includes practical guidelines for PV system maintenance and options for inspection prac-tices for grounded PV systems. It is intended for mono-polar, grid-connected PV systems, and does not explicitly cover bi-polar, ungrounded, stand-alone, or battery backup systems. Off-grid systems have many of the same components, however, and portions of the guidelines can be used for inspection or maintenance of off-grid systems.

Qualified Personnel

This report is intended to help qualified individuals maintain and inspect PV systems safely. The U.S. Department of Labor’s Occupational Safety and Health Administration (OSHA) defines a qualified person as one who has received training and has demonstrated skills and knowledge in the construction and operation of electrical equipment and installations and the hazards involved.

The definition supplied in Article 100 of the National Electrical Code® (NEC) is very similar (NFPA, 2011a): “One who has skills and knowledge related to the construction and operation of the electrical equipment and installations and has received safety training to recognize and avoid the hazards involved.”

Technicians can be qualified for some maintenance and service tasks but still be unqualified for others. Whether someone is a “qualified person” often depends on the specifics of the task at hand.

Qualification is earned by either direct on-the-job training under qualified supervision or through training programs offered by accredited educational institutions or manufacturers. Many testing and maintenance activities require two people to be completed safely and efficiently. An employee who is being trained for a task, demonstrates the ability to perform duties related to that task safely, and is under the direct supervision of a qualified person is usually considered to be a qualified person.

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• the skills and techniques necessary to identify exposed live parts from other parts of electrical equipment,

• the skills and techniques necessary to determine the nominal voltage of exposed live parts,

• the clearance distances specified by OSHA in the Code of Federal Regulations (CFR) Part 1910.333(c) (“Working on or near energized parts”) and the corresponding voltages to which the qualified person will be exposed,

• the pertinent sections of the NEC,

• the characteristics of PV sources and hardware typically used in PV systems, and

• the characteristics of the hardware used in the PV system the person is working on.

It is strongly recommended that anyone working around energized PV systems complete a minimum of the 10-hour OSHA-10 Construction Industry Training Program. Local jurisdictions may specify the necessary training, skills, certifications, or licenses required to perform the work discussed in this report.

One indicator that a person may be qualified to work on many types of PV systems is to confirm that the person is a certified energy practitioner who has met the qualifications for and passed a certification exam.

Additionally, in order to be considered a qualified person for PV service and maintenance, a person must be trained in and familiar with:

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SAFETY REQUIREMENTS

Safety begins with adequate planning and preparation. Effective safety policies must be in place and employees and contractors must be familiar with—and committed to following—safety procedures in order to prevent accident or injury.

Major safety requirements during PV servicing include the proper use of lockout/ tagout procedures, the use of personal protective equipment (PPE), procedures for safely disconnecting live circuits, and appropriate observation of and compliance with all PV-specific system signage and warnings.

Lockout/Tagout

Lockout/tagout (LOTO) procedures are designed to ensure safe working practices and must be strictly followed whenever systems are de-energized prior to servicing. LOTO is covered by CFR, under 29 CFR 1910.147.

LOTO is required when energized equipment is serviced or maintained, safety guards are removed or bypassed, a worker has to place any part of his or her body in the equipment’s point of operation, or hazardous energy sources are present.

Lockout/tagout steps include:

• notify others that the equipment will be shut down,

• perform a controlled shutdown to power down the equipment,

• open all of the energy isolating devices identified on the equipment’s specific LOTO procedure,

• lock and tag all energy isolating devices,

• dissipate or restrain stored or residual energy,

• verify that the equipment is completely de-energized by attempting to cycle it, and

• verify that the equipment is completely de-energized by testing for voltage with a voltmeter.

Proper LOTO labeling includes:

• name of the person placing the LOTO and the date placed,

• details regarding the shutdown procedure for specific equipment,

• a list of all of the energy sources and isolating devices, and

• labels indicating the nature and magnitude of stored potential or residual energy within the equipment.

The lock placed on equipment during servicing should be removed only by the person who placed it. The lockout devices, such as padlocks, shall be approved for LOTO applications. OSHA provides variations of LOTO that may be used depending on an approved energy control program. Safety protocols need to be followed when re-energizing equipment, including notifying others that the system is about to be energized.

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PPE and Other Safety Equipment

Service personnel must know what PPE is required for a specific task and wear it while completing the task. PPE includes fall protection, arc flash protection, fire-rated clothing, hot gloves, boots, and protective eyewear, among other items. PPE is designed to help minimize exposure to inherent system hazards. Identification of potential hazards is crucial to the process of selecting the appropriate PPE for the task at hand. All personnel working on or near PV systems should be trained to recognize hazards and choose the appropriate PPE to eliminate or reduce those hazards.

Rubber-insulating gloves, often referred to as “hot gloves,” are the first line of defense against electric shock. They should always be worn with protective leather gloves over them and inspected before each use. Additionally, OSHA requires the gloves to be re-certified or replaced at regular intervals, beginning six months after they are placed in service. Insulated hand tools provide an additional layer of shock protection.

As PV systems get larger and direct current (dc) operating voltages up to 1,000 volts (V) become increasingly common, arc flash requirements are a growing concern and it is more common to see arc flash warning labels on combiner boxes and disconnects. Unfortunately for maintenance personnel, many existing PV systems have been installed without labels warning of arc flash hazard. Service per-sonnel need to be able to perform on-site evaluations to determine when a higher category of PPE is required to perform the work. Tasks such as performing thermal imaging on operating inverters with opened coverings or doors or verifying volt-ages in switchgear commonly require arc flash rated PPE.

Even when not required by statute or regulations, general industrial safety equip-ment such as hardhats, safety glasses, boots, fire-rated clothing, and safety vests are strongly recommended when working on construction sites or around live electrical equipment. The jobsite also must be equipped with appropriate fire extin-guishers and first aid supplies and all personnel must have proper training in their use. Lastly, at least two qualified people trained in cardiopulmonary resuscitation (CPR) should be on site at all times.

Safe Operation of Electrical Disconnects

Switching on or off an electrical contactor or disconnect is a process often taken for granted as safe but it can be one of the more dangerous tasks involved in main-taining a PV system. Workers must wear proper PPE when operating disconnects, and care should be taken to use the proper technique for throwing switches.

Some of the switches used to control the dc circuits of PV systems are not rated for load-break operation. Non-load-break-rated switches, which must be labeled as non-load-break-rated, must never be opened while the system is operating. Before opening a dc switch that is not rated for load break, the system should be shut down by turning off the connected inverter.

The hinges of most disconnect switches are on the left side of the switch and the handles are on the right. A recommended safety protocol is to follow the left hand rule, which involves standing to the right side of the switch and using the left hand to throw the switch. This ensures that the worker’s body is not in front of the switch should an arc flash occur.

11PV System Operations and Maintenance Fundamentals

The proper technique for safely throwing an electrical disconnect includes:

• wear proper PPE,

• shut the system off at the inverter,

• stand to the right of the switch,

• grab the handle with the left hand,

• turn body and face away from the switch,

• close eyes,

• take a deep breath and hold it (to avoid breathing in flames if an arc flash occurs),

• throw (operate) the disconnect lever,

• use a properly rated voltmeter to confirm that no voltage is present on the disconnected circuit, and

• use LOTO methods to ensure the switch remains off.

PV-Specific Signage and Warnings

Article 690 of the NEC (NFPA, 2011b) covers the requirements for PV-specific signage and warnings that must be present on every PV system. Additional signage may also be required by the local jurisdiction or utility. These placards and warnings need to be visible to those working on or near the systems and should never be covered or painted over.

Early PV systems often operated with maximum system voltages less than 50 Vdc.

Today, 600 Vdc systems are common and 1,000 Vdc systems are allowed by code in commercial and large-scale installations. Qualified personnel must use properly rated equipment and be trained for servicing the higher voltage systems.

Particular care must be taken to observe and follow warning labels reading “DO NOT DISCONNECT UNDER LOAD” located on module connections, combiner boxes, disconnects, and some inverter switches not designed as a load-break switch. Failure to heed these warning labels can lead to instrument malfunction, arcing, fires, and personnel injuries.

Although it is impossible to compile a list of universally applicable safety guidelines, the authors suggest the following steps as crucial to safe work:

• Before operating the PV system, read all instructions for each product.

• All system components must be assumed to be energized with maximum dc voltages (up to 1,000 V) until personnel verify that the voltage has been removed.

• All enclosure doors should remain closed with latches tightened, except when they must be open for maintenance or testing.

• Only qualified personnel who meet all local and governmental code requirements for licensing and training for the installation of electrical power systems with alternating current (ac) and dc voltages up to 1,000 V (or 600 V, when applicable) should perform PV system servicing.

• To reduce the risk of electric shock, only qualified persons should perform ser vicing other than that specified in the installation instructions.

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• In order to remove all sources of voltage from the inverter, the incoming power must be de-energized at the source. This may be done by opening the ac disconnect and the dc disconnect. Follow manufacturer guidelines for specifics of how to de-energize the inverter. In addition, allow a minimum of five minutes for the dc bus capacitors to discharge after disconnecting the power, always testing that voltage is reduced to touch-safe levels (30 Vdc) before working on the system.

• Always follow LOTO procedures.

• Always check for ground faults. If there is a ground fault, there may be a voltage potential between the inverter and ground. Further, check that the normally grounded pole is properly grounded and has not been energized by a fault.

• Do not work alone when servicing PV equipment. A team of two is required until the equipment is properly de-energized, locked-out, and tagged-out.

Verify with a meter that the equipment is de-energized.

• Do not open a string (also known as a source circuit) combiner fuse holder without first confirming that there is no current flowing on the circuit.

• Do not disconnect (unplug) module leads, jumpers, or homerun wires under load.

ROUTINE SCHEDULED

PREVENTIVE MAINTENANCE

One of the most valuable techniques for identifying existing problems and preventing future problems is to walk the site and conduct a thorough visual and hands-on inspection of the PV system components. These inspections should be conducted at regular intervals, and personnel should use checklists developed for these periodic maintenance activities to ensure that the inspections are thorough and complete.

General Site Annual Inspection

At least once a year, O&M personnel should conduct a general inspection of the PV installation site. During this inspection, technicians should:

• ensure roof penetrations are watertight, if applicable;

• check for ground erosion near the footings of a ground mount system;

• confirm proper system signage is in place;

• confirm electrical enclosures are only accessible to authorized personnel, are secured with padlocks or combination locks, and have restricted access signage;

• check for corrosion on the outside of enclosures and the racking system;

• check for loose hanging wires in the array; and

• check for signs of animal infestation under the array.

Detailed Visual Inspection

The installation should be inspected regularly for issues that impact the physical integrity or performance of the PV system. A visual inspection should include the following actions:

• Inspect the inverter/electrical pad to make sure it does not show excessive cracking or signs of wear. The inverter should be bolted to the pad at all mounting points per the manufacturer installation requirements. Depending on the size, location, and accessibility of the system to unqualified personnel, the inverters, combiner boxes, and disconnect switches should require tools or have locks to prevent unauthorized access to the equipment.

• Look for warning placards including arc flash or PPE requirements for accessing equipment. Be sure to comply with all warning placards. If no placards are present, or if some placards are missing, make a note of it and install the missing placards during the maintenance visit. Consult the NEC and Underwriters Laboratories (UL) standards as well as the site host to determine signage requirements.

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• Inspect PV modules for defects that can appear in the form of burn marks, discoloration, delamination, or broken glass.

• Check modules for excessive soiling from dirt buildup or animal droppings.

(See Array Washing Procedure for proper procedures for cleaning an array.)

• Ensure that the module wiring is secure and not resting on the roof, hanging loose and exposed to potential damage, bent to an unapproved radius, or stretched across sharp or abrasive surfaces.

• Inspect racking system for defects including rust, corrosion, sagging, and missing or broken clips or bolts.

• If sprinklers are used to spray the array, check that the water is free of minerals (demineralized) as these minerals can cause gradual performance degradation.

• Inspect conduits for proper support, bushings, and expansion joints, where needed.

• In roof-mounted systems, check the integrity of the penetrations.

• In ground-mounted systems, look for signs of corrosion near the supports.

• Open combiner boxes and check for torque marks on the connections. Torque marks are made when lugs have been tightened to the proper torque value.

Ideally they are applied during initial installation, but if not, the technician can mark the lug after torquing during a maintenance visit. A proper torque mark is made with a specialized torque marking pen. The mark is a straight line through the lug and the housing. Over time, if the line separates between the lug and the housing, it shows that the lug has moved and needs to be re-torqued. Look for debris inside the boxes and any evidence of damaging water intrusion. Look for discoloration on the terminals, boards, and fuse holders.

• Open the door to the disconnect(s) and look for signs of corrosion or damage.

Check to make sure the cabinet penetrations are properly sealed and there is no evidence of water ingress. Check for torque marks on the terminals.

• Perform a visual inspection of the interior and exterior of the inverter. Look for signs of water, rodent, or dust intrusion into the inverter. Check for torque marks on the field terminations.

• If a weather station is present, ensure that the sensors are in the correct location and at the correct tilt and azimuth. A global horizontal irradiance sensor should be flat, and a plane of array irradiance sensor should be installed to the same pitch and orientation as the array. Irradiance sensors should be cleaned to remove dirt and bird droppings.

Manufacturer-Specific Inverter Inspection

Each inverter manufacturer will have specific requirements for inspection, testing, services, and documentation to meet its warranty obligations. Typical requirements for inverter inspections include:

• Record and validate all voltages and production values from the human-machine interface (HMI) display.

• Record last logged system error.

• Clean filters.

• Clean the inside of the cabinet.

• Test fans for proper operation.

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• Check fuses.

• Check torque on terminations.

• Check gasket seal.

• Confirm warning labels are in place.

• Look for discoloration from excessive heat buildup.

• Check integrity of lightning arrestors.

• Check continuity of system ground and equipment grounding.

• Check mechanical connection of the inverter to the wall or ground.

• Check internal disconnect operation.

• Verify that current software is installed.

• Contact installer and/or manufacturer about any issues found.

• Document findings for all work performed.

Manufacturer-Specific Tracker Inspection

Tracker manufacturers will have specific requirements for inspections, testing, ser-vice, and documentation to meet their warranty obligations. Typical maintenance or startup requirements for tracker systems include:

• Lubricate tracker by inserting grease with grease gun into appropriate grease caps per manufacturer maintenance recommendation.

• Check voltages inside the controller box.

• Use a digital level to check the calibration and positioning of the inclinometers.

• Check array for signs of parts hitting or rubbing other parts.

• Remove vegetation that is near the drive shaft or moving components.

• Check wind-stow operation.

Use appropriate (volt, ohm, dc clamp-on) meters to test:

• open-circuit voltage (Voc) of all strings with the inverter off; and

• maximum power current (Imp) of all strings with the inverter on and at specified or recorded levels of power.

Additional testing (used when problems are identified or required by contract terms) may include:

• thermal images of combiner boxes (opened and closed), disconnects, inverters (external and internal at a specified operating point for a specified period of time), and modules;

• short circuit (Isc) testing of strings;

• current-voltage (IV) curve testing of strings;

• comparison of a weather-corrected performance calculation of expected output to actual output of the system.

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Manufacturer-Specific Data Acquisition System Inspection

Data acquisition system (DAS) manufacturers will have specific requirements for inspections, testing, service, and documentation to meet their warranty obligations. Typical maintenance or startup requirements for DASs include:

• taking voltage readings of power supplies,

• validating current transducer readings by comparing to calibrated equipment, and

• validating sensor reading by comparing to calibrated equipment.

To confirm proper functionality of the DAS, the values measured by the DAS must be verified against values from devices with traceable calibration records.

Comparing the irradiance, temperature, and power measurements recorded by the DAS to values obtained from calibrated instruments will help identify sensor calibration issues that could result in the DAS data being incorrect.

The PV industry as a whole is getting better at DAS installation and documenta-tion, but it is still typical for DAS plans to be omitted or insufficiently detailed. As a result of such an omission, plan checkers often do not check for errors in the DAS design and inspectors have nothing to compare the as-built with for compliance .

If the DAS will be tied into the building information technology system, O&M personnel should be aware that building networking upgrades or routine maintenance can cause connectivity issues.

17PV System Operations and Maintenance Fundamentals

GENERAL ISOLATION PROCEDURES

Energized Components Some testing and maintenance activities may require the system to be energized while workers are working on or near the equipment—string current testing is one example. Another common testing practice discussed in Megohmmeter Testing (megger testing) is to use an insulation resistance meter to induce voltage to wiring or other components in an effort to identify signs of damage to insulation or resistance/leakage from other sources such as loose connections.

OSHA provides guidance for what must be done in order to work safely on energized systems:

• Only qualified employees can work on electric circuits or equipment that has not been de-energized using LOTO procedures.

• Qualified employees must be able to work safely on energized circuits.

• The qualified employee must be familiar with the proper use of special precautionary techniques, PPE, insulating and shielding materials, and insulated tools.

• Employees working in areas where there are potential electrical hazards must be provided with and use electrical protective equipment that is appropriate for the specific parts of the body to be protected and for the work to be performed.

Inverter Pad Equipment Use the following procedures for disconnecting a single inverter from the grid:

• If applicable, follow the inverter manufacturer guidelines for a controlled shutdown using the HMI keypad to navigate and select a shutdown.

• If the inverter has an on/off switch, turn it to off.

• Turn the ac disconnect switch on the inverter off.

• Turn the dc disconnect switch on the inverter off.

• Turn any remaining external disconnect switches connected to the inverter off.

• Install lockout devices on all disconnects, locking them in the open or off position.

• Repeat for all inverters and switches to completely isolate the entire PV system from the grid and the inverters from the PV power source.

Transformer Isolation Use the following procedures for transformer shutdown:

• For inverters connected to the transformer, turn the on/off switch to off.

• Turn the ac disconnect off for the inverters connected to the tranformer.

• Turn the dc disconnect off for the inverters connected to the transformer.

• Install lockout devices on the disconnects.

• Turn off the transformer switch, which is either a dedicated stand-alone switch or is located in the switchgear.

• Install a lockout device on the transformer switch.

• Repeat for all transformers to completely isolate them from the switchgear.

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FAILURE RESPONSE

Emergency Shutdown In an emergency situation:

• If the inverters have Emergency Stop buttons, push them in on each inverter.

• If the inverter has an on/off switch, turn it to the off position (this may require a key). Each inverter should be manually turned to the off position. This will immediately open the internal ac and dc contactors (if present) inside the inverter.

Note that some inverters do not have an on/off switch or an Emergency Stop button. For these inverters, it will be necessary to turn the systems off using the disconnect switches attached to or located near the inverters. Do not open switches that are specifically labeled “Do not disconnect under load” until a load-break switch has been opened and current flow is stopped. Generally, the first available upstream load-break ac switch or circuit breaker is safer to operate first (before the dc switch), because the inverter instantly shuts down the transistor bridge when ac voltage is removed. Once the system is off, the remaining switches can be opened and the system can be locked out until the fault condition is repaired or it is safe to turn it back on.

Isolation Procedure—Inverter Pad Equipment To isolate the inverter pad safely:

• Shut the inverters off through a controlled shutdown.

• Turn off all dc and ac disconnects that feed the pad. Follow the procedure in the LOTO section for opening electrical disconnects.

• Use LOTO procedures to ensure the system remains off.

• Always wear appropriate PPE and test for voltages with a properly rated meter to confirm the system is completely isolated.

Isolation Procedure—Field Combiner Box To isolate field combiner boxes:

• Turn off the inverters as described above.

• Operate the switch of the combiner (if applicable) by turning the handle to the off position.

• Use a dc clamp on the meter to confirm there is no current passing through the ungrounded conductors in the combiner box, and then open all of the fuses.

• If further isolation of the box is needed, use the string diagrams to locate the homeruns (end connectors of the PV strings).

• Use a clamp-on dc current meter to confirm that the homerun does not have any current passing through it, and then disconnect the string by opening the homerun positive and negative connectors and putting caps on the source circuit connectors.

• Go back to the combiner box and use a voltmeter to confirm that each string has been successfully disconnected.

19PV System Operations and Maintenance Fundamentals

Isolation Procedure—Modules and String Wiring After turning off the inverter, switches, and combiner boxes and isolating the com-biner boxes from the array, disconnect individual modules from the string:

• Before disconnecting any string, use a dc clamp-on meter to confirm there is no current passing through the string.

• Use the appropriate connector unlocking tool to disengage the module connector.

• Repeat for each module to be isolated from the system.

• If modules are removed from a system, even temporarily, technicians must ensure that the equipment grounding system remains intact for the remaining modules.

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INVERTER TROUBLESHOOTING AND SERVICE

There is an understandable focus on maximizing ROI and system production.

System uptime and availability is a key objective of O&M. Inverters that are offline can have a dramatic negative impact on the ROI of a PV system. Inverter failure rates are important to ROI, but even more important than how often an inverter goes offline is how quickly it can be placed back into service. The type of inverter fault often dictates how quickly it can be placed back into service. Inverters with known failure modes need a failure response procedure. This may include stocking critical parts that have long supply lead times so that the system is not left offline because of a lack of spare parts.

Inverter Troubleshooting

When an inverter goes offline, technicians must determine why and correct the error as quickly as possible. They can check the HMI for reported errors, and then follow the actions noted in the table below.

Common Reported Inverter Errors

Dc undervoltage Steps to diagnosing underperforming systems Dc overvoltage Voc string testing Dc ground fault Ground fault detection procedure

Gating fault Check connections Contact manufacturer

Ac undervoltage

Confirm all breakers are on Check ac voltage with voltmeter If within range, perform a manual restart If outside of range, contact utility

Ac overvoltage

Check ac voltage with voltmeter If within range, perform a manual restart If outside of range, contact utility

Low power

System is likely just shutting down because of lack of sun;

if it is sunny, perform steps to diagnose underperforming systems

Over temperature—fan not operating

Check power supply to fan—if good, replace fan; if bad, replace power supply

Over temperature—fan is operating

Check to confirm sensor readings—if bad, replace sensor;

if good, investigate further

Over temperature—fan is operating, sensors are accurate

Check intake and exhaust filters for excessive buildup, and clean or replace if necessary

Software fault Contact manufacturer

Inverter Error Action

21PV System Operations and Maintenance Fundamentals

Some inverter faults will clear automatically when the fault condition returns to normal, but some fault conditions require a manual reset of the inverter. The ground fault fuse and even ac fuses can be non-standard items that are difficult to purchase. Keep replacements on hand, especially if there are multiple inverters of the same size on site or in the portfolio. Having qualified technicians available and properly equipped with common replacement parts helps maximize system uptime.

Inverter Service Procedures

Some inverter service actions require that the system be shut down for safe inspection. Always begin with an examination of the equipment as described in the ROUTINE SCHEDULED PREVENTIVE MAINTENANCE chapter, and further inspect subassemblies, wiring harnesses, contacts, and major components.

The following sample inverter service checklist applies to larger inverters (not residential scale) and is not intended to be complete for all models from all manufacturers:

• Check insulated gate bi-polar transistors and inverter boards for discoloration.

Use inspection mirror if necessary.

• Check input dc and output ac capacitors for signs of damage from overheating.

• Record all voltage and current readings from the front display panel.

• Check appearance/cleanliness of the cabinet, ventilation system, and insulated surfaces.

• Check for corrosion/overheating on terminals and cables.

• Torque terminals, connectors, and bolts as needed.

• Record ambient weather conditions, including the temperature and whether the day is cloudy or sunny.

• Check the appearance of both the ac and dc surge suppressors for damage or burn marks.

• Check the operation of all safety devices (emergency stop devices, door switches, ground fault detector interrupter).

• Inspect (clean or replace) air filter elements.

• Correct any detected deficiencies.

• Complete maintenance schedule card.

• Complete written inspection report.

• If manufacturer-trained personnel are available on-site, install and perform any recommended engineering field modifications, including software upgrades.

22 Solar America Board for Codes and Standards Report

DIAGNOSING AND TESTING FOR

LOW POWER PRODUCTION

Low power production also impacts ROI, and O&M personnel need effective strategies for identifying and correcting problems quickly. System operators or owners may become aware of a PV installation’s underperformance through one of the following means:

• a predefined DAS alert, which may be weather-related, a result of comparison with other systems in the portfolio, or a result of comparison with other monitored parts of the system at a site with multiple inverters;

• customer or external entity reports of a potential problem, often because of an unexpected increase in a monthly bill.

Diagnostic Overview

Once the underperformance is confirmed, personnel must determine what is caus-ing it. Steps to diagnosing power production deficiencies include:

• During routine maintenance and when diagnosing an underperforming system, the first and most important components to check are the fuses.

Fuses generally must be removed from their holders to determine whether they have blown.

• Perform a system performance data review using the DAS or a program such as the PVWatts calculator (NREL, 2012) to calculate the expected system output based on weather conditions and system size to compare actual to modeled systems production.

• Dispatch a field technician to the site to do the following:

o Check that on-site performance meters have similar values. Often systems will have revenue grade performance monitoring that can be compared against the inverter display totals.

o If there is a difference in the values, then ideally the technician can log into the DAS system (when available) to investigate.

• A phase that has a different output than the others could be the result of a bad current transformer (CT) or a blown fuse in the CT circuit (i.e., an instrumentation problem).

o If there is no difference in recorded values, then use the inverter operator display/interface (if applicable) to identify the inverter error log. See inverter diagnostics for errors that may have caused the inverter to perform at less than 100% power.

o Verify that the array maximum power point voltage is in the maximum power point tracking window of the inverter, using an IV curve tracer on a sample string or group of strings. Modules will degrade over time and an array that begins service at the lower end of the inverter maximum power voltage window may degrade until its maximum power voltage no longer falls within this range, further compounding the effects of module degradation.

23PV System Operations and Maintenance Fundamentals o Look for external causes of the production drop, such as unexpected shade on the array. Vegetation growth is the most common form of shading, but it is not unusual to find a satellite dish or other object shading the array that was not present when the system was built. Take photographs of the installation during commissioning and keep a visual record of any noticeable differences during maintenance visits.

o Perform general system checks as necessary to identify problems:

• Check all fuses at the inverter and work out to the combiner boxes.

• Perform Voc string testing.

• Perform Imp string testing.

• Validate weather sensors.

• Look for soiling. If soiling might be the problem, test an individual string (Voc, Imp, IV curve) and then clean the string and retest.

• Perform IV curve tracing.

• Take infrared (IR) images of the PV cells.

Diagnostic Testing

O&M personnel can use a number of diagnostic procedures to determine the cause(s) of power deficiencies in a PV installation. The following sections describe these tests in detail.

Infrared (IR) Image Procedure

This procedure describes how to properly perform field diagnostics of a PV installation using an IR camera to detect abnormal heat signatures. Topics include correct camera settings and proper conditions for field inspection.

Test conditions

• IR imaging should be completed with the system operating at peak levels if possible.

• Do not open or work in electrical boxes, particularly those with NEMA 4 rating, during rainy or wet conditions.

Tools include:

• IR Camera, such as Fluke Ti10, Fluke Ti32, FLIR i40, or FLIR i7; and

• clamp-on ammeter.

Safety considerations

• Ensure all OSHA and environmental health and safety requirements are met, especially if working on angled roofs and/or at heights greater than six feet.

• Safety precautions should also be taken when working near active high voltage systems or near surfaces that may be very hot to the touch.

• Contact local health, security, safety, and environment personnel for questions and access to pertinent documentation.

24 Solar America Board for Codes and Standards Report

IR imaging procedure

• Before starting the IR scan, verify that the PV array is operating, because temperature differences in modules are not apparent when the system is not operational.

o Check inverter display for instantaneous kilowatt output.

o Check current on each string in combiner box to ensure that it is operational.

o If the inverter or any of the strings are not operational, these must be corrected before the test can be conducted.

IR camera settings

• Set the IR camera to “auto-scaling” rather than manual scaling. This will allow for automatic adjustment of the temperature scale.

• Set emissivity value to 0.95 (usually the camera default). The IR camera does not capture shiny surfaces such as polished metals well due to their low emissivity value. However, for most active components on a solar module such as cells, J-Box, and cables, a value of 0.95 will be sufficient.

• Set temperature units to Celsius.

• Set color palette to Iron or Rainbow. “A thermal imager interprets IR radiated or reflected heat by assigning a visible graduated color or gray scale to a radiated portrait of the scene. The color palette displays hot spots as white with diminishing temperatures through red-orange-yellow-green-blue-indigo-violet to black being cold” (Fluke Corporation, 2006, 2008).

IR inspection

• When sunlight is present and camera settings are properly set, point the lens at the object of interest. In the case of solar modules in operation, looking through the glass onto the active cells is the most common inspection technique.

• Ensure that the picture is focused, either manually or automatically. For best results, position the camera as close to the module as possible without shading it or creating a reflection in the glass surface. If possible, the distance between the camera and the surface to be measured should not exceed three meters or 10 feet. This will depend on the camera’s minimum focal distance and other specifications. Some temperature differences will not be picked up if the camera is too far away from the module.

• For best results, position the camera as perpendicular as possible to the object being measured. Hot spots will be easier to see if the image is taken perpendicular to the module surface. Image quality will degrade at camera angles other than normal (i.e. perpendicular) incidence.

• Care should be taken to avoid shading any part of the…