You are working on the electrical design for the same PV system as you did in Lesson 8. As you complete the NEC design for the PV array, you reach the point of interconnection with the utility grid at the meter side. You ask yourself, "What are the requirements and methods to hook the PV system up to the grid? Is it as simple as connecting the power terminals to the utility meter? Or does it require a detailed study of the existing electrical service?"
In case the site evaluation documents provided by the sales team are missing the information regarding the main service distribution panel, what information do you need to gather from the site to be able to proceed with the electrical design? Do you need to consult with the utility plan reviewers to check on any additional requirements for interconnection? How can the customer sell back the produced energy from the PV system?
In this lesson, we will discuss issues related to the interconnection requirements and methods according to the NEC that will answer these questions. In addition, you will be prepared to complete the electrical permitting documents required before the installation process. PV designers and installers need to comply with the interconnection requirements referenced in the National Electrical Code (NEC) and IEEE standards to ensure the systems function properly and avoid safety hazards.
At the successful completion of this lesson, students should be able to:
Lesson 9 will take us two weeks to complete. Please refer to the Calendar in Canvas for specific timeframes and due dates. Specific directions for the assignments below can be found within this lesson and/or in Canvas.
If you have lesson specific questions, please feel free to post to the Lesson 9 Questions discussion forum in Canvas. While you are there, feel free to post your own responses if you, too, are able to help a classmate with a question. If you have questions about the overall course or wish to share and discuss any "extra" course related commentary (interesting articles, etc.), please feel free to post to the General Questions and Discussion forum.
Some of the content in AE 868 is directly related to topics that are already discussed in other courses. However, these topics are essential building blocks on what we will cover in AE 868. Please take the time to review the topics here or where noted throughout the lesson.
We discussed earlier the value of the utility grid and how it serves as the energy reservoir. Most traditional utility grids are built based on the central generation strategy that entails that the power plant is located somewhere with high capacity to supply loads at different locations through transmission and distribution lines.
For more information about the central power generation, please refer to EME 810 (The Power Grid System) [2]. This link is also provided in the review section of this lesson.
On the other hand, Distributed Generation (DG) is a system that generates power near the point of consumption, which is also referred to as the end user. Whether it is a diesel generator or PV array, all power will be injected into the grid system. DG can also be fuel cells, wind turbines, and other sources.
DG systems are becoming a more common supplement to the traditional central power generation. DGs have the advantages of lower power losses since the generation is close to the load, so both customers and utility can benefit from it. Customers can benefit from DG when there are power outages if the DG contains backup storage. Utilities can benefit from DG by expanding its capacity without physically adding new central plants. With these advantages also come some challenges, since the DG can be installed anywhere on the utility grid. Most utilities noticed the importance of assuring a safe and reliable DG interconnection without having any negative impacts on the utility grid - especially the distribution power system. This lesson will discuss some related codes and standards that are important to interconnect DG sources to the utility grid in the United States.
As we have discussed, most PV systems contain power conditioning units or inverters. In addition, in order for any PV system to be connected to the utility grid, there has to be a set of test standards and codes to govern the interconnection process for a safe and reliable power delivery. In this section, we will discuss main interconnection standards that relate to PV systems such as IEEE, UL, and NEC standards. Solar professionals and designers should always look for the most up-to-date standards in this regard and consult with the local AHJ for any additional legislation.
IEEE 1547 [3] is a standard for interconnecting distributed resources with electric power systems. IEEE 1547 contains a family of standards, guides, and recommended practices. Solar professionals and designers should consult with all series of IEEE 1547 standards.
UL 1741 [4] is the testing standard related to DG equipment such as inverters and charge controllers. It is considered a supplemental standard to IEEE 1547. UL 1741 is important because it is listed in NEC article 690.
In addition to the sizing requirements we discussed in Lesson 8, NEC Article 690 requires that all inverters be listed and identified for interactive operation. Most requirements are based on equipment testing under UL 1741. Inverters must meet anti-islanding and disconnect from the grid when voltage is lost, and must remain disconnected until grid voltage is restored to the accepted measure.
All DG, including PV systems, introduces additional power at the customer location that has not been planned to exist when it was first designed. With this new addition, some technical issues and difficulties face the utility companies at the interconnection side. Some of these technical issues can be overcome by early adoption of standards, and some are enforced after the systems are installed.
Islanding is the undesired condition when the DG source, such as a PV system, continues to supply power to the grid during a utility outage. This may cause a serious safety hazard to utility workers who are exposed to unexpected energized power lines. To prevent damage to personnel and equipment, all grid-bound inverters must be able to detect outages and block power transfer to meet UL 1741 equipment testing standard. Inverters with such capability are referred to as anti-islanding inverters. However, Bimodal inverters may function in stand-alone mode of operation while being disconnected from the utility grid line during outages.
Power quality is a topic that discusses several electrical performance parameters, such as voltage, frequency, and harmonic distortion. Power quality of a grid can be affected by loads and equipment connected to the grid, such as power electronics equipment that operates on discrete modes and causes quality issues, which may damage sensitive equipment or create hotspots in transformers. Since DG sources including PV inverters contain switching devices, most utilities are concerned about the interconnection of PV systems and power quality issues associated with it. For that reason, utilities mandate that all DG interconnected equipment must meet certain power quality limits such as current harmonics, voltage flickers, and other parameters and utilities must continuously monitor these parameters to insure a reliable grid operation.
A particular over current problem arises when one stand-alone inverter with a 120 V output supplies a 120/240 V distribution panel. A similar problem can occur with interactive systems of single-phase 3-wire or 3-phase, 4-wire wye configuration when loads are concentrated on one phase more than the other. The single grounded (neutral) conductor can become dangerously overloaded. Therefore, the grounded conductor may carry twice its rated circuit current, and this is a serious concern discussed on NEC 705.95 that requires the sum of the maximum load between the neutral and ungrounded conductor and the inverter’s output rating not to exceed the ampacity of the neutral conductor.
In AC electricity, there are two main configurations for the 3-phase systems "WYE," or "Star," and "Delta." Please look over this article regarding Three-phase electric power [5] for more information.
Phase voltage imbalance can occur if a single-phase inverter is connected to a three-phase power system. NEC 690.63 (705.10) doesn’t allow this type of connection unless the voltage imbalance between phases is minimized, not to exceed 3 percent. Another solution is to use three similar single-phase inverters (one for each phase) that are equally loaded.
The point of connection is the location at which the DG source including a PV system can be interconnected with the electric utility grid. Since adding power at that point is beyond the initial intended design of the existing electric system at the point of connection, all service equipment, such as main power distribution panel disconnects and conductors, must be sized and rated to allow this addition according to NEC 690.64.
NEC 690.64 [6] permits the output of the inverter to be connected to either load side (customer side) or supply side (utility side) service points, depending on the size of the PV system and marginal power available at that point. In large a PV system, the available service might not have enough capacity to handle the added power and, in this case, a separate service may need to be installed. A backfeed circuit breaker is a circuit breaker that allows current flow in either direction. The backfeed circuit breaker provides overcurrent protection of the branch circuits from the inverter, and the panel’s main service circuit breaker provides protection of the entire PV and load system from the utility. Regardless of the interconnection type, NEC 705 [6] requires that a permanent directory be placed at each service location showing all power sources for a building.
Common in small PV systems, the main service disconnect at the customer facility has enough margin to handle the extra capacity added by the PV system, and that allowed an interconnection at the load side.
NEC permits that type of interconnection providing the following conditions (we will only mention the technical-related issues):
In the 2011 National Electrical Code (NEC), the language in 705.12(D)(2) is straightforward. Fulfillment of the 120% rule that states that the sum of the rating of the OCPD in all circuits supplying power to a busbar or conductor must not exceed 120% of the rating of the busbar or conductor to prevent overloading conditions. This only applies to breakers that supply the load center with power, including the main utility fed circuit breakers and any back-fed circuit breakers from PV sources (load circuit breakers are not considered)
Here is what NEC 2014 - Article 705.12(D)(2) code states:
“Bus or Conductor Rating. The sum of the ampere ratings of overcurrent devices in circuits supplying power to a busbar or conductor shall not exceed 120% of the rating of the busbar or conductor.”
In the 2014 code, this straightforward sentence has been revised to include several paragraphs with different scenarios. The meaning might look the same, however, and once you understand the philosophy of the simpler 2011 version of 705.12(D)(2) you will be able to understand NEC 2014’s more sophisticated version. It really is the designer’s knowledge to correctly interpret the code, since NEC 2014 provides more flexibility to allow more PV capacity for the same circuit size.
Here is what NEC 2014 - Article 705.12(D)(2) states:
More requirements are listed on NEC 690 through the NFPA free access page [6], and designers are encouraged to read further.
Assuming you have a service panel rated at 200A (maximum current) and the main circuit breaker is rated at 200A, what is the maximum allowable current that can be back-fed to this panel?
ANSWER: Applying the 120% rule, the 200A panel can only handle 240A current (1.2 x 200= 240A). Given the main circuit breaker is 200A and considering the rule that states that the sum of the current supplying power to the service panel cannot exceed 120% of the panel rating, or 240A. Then the allowable current from the additional current is the 40A (240 - 200= 40A). In other words: The maximum allowable back-fed current = 1.2 x 200A (panel rating) - 200A (main breaker rating) = 40A.
In some cases and based on load electrical study done by professional engineers, the main breaker can be taken down to a lower rating that will in return allow additional current to be back-fed to the panel.
For larger installation or in case the load-side strategy doesn’t provide the required capacity, a supply-side interconnection is the second resort for PV systems. NEC article 230 [6] requires any additional new service to have disconnect and OCPD. That said, the supply-side interconnection must include another service in parallel to the existing one with an additional OCPD and disconnect. The equipment and conductors must be rated to accommodate for that additional power coming from the PV system. The interconnection requires tapping the service entrance conductors, and that is done between the existing service panel and utility meter. A new meter might be needed when the service type cannot establish the tapping strategy. The added disconnect must meet local utility standards in terms of accessibility, interrupting rating, and visibility. The service conductor must be sized for at least 125% of the continuous load current, as stated in NEC article 230.
Metering is required by the utility to measure how much electricity is used by the customers, and it is referred to as revenue meter. These meters are usually installed at service entrances of properties. Since the addition of DG sources will introduce another energy source, it is required to accommodate for that addition by measuring the added electricity based on the facility and DG system size and interconnection policies at the location of installation. This can be accomplished using one of the following methods:
Using one meter that can operate in both directions (spins forwards and backwards) to measure the exported energy and subtract it from the imported energy. Some existing meters are capable of operating in both directions without any modifications, while other old meters need to be upgraded by the utility company. Designers and customers should consult with their state rules for the eligibility of the net metering.
In this case and as the name entails, two-meters (unidirectional meters) are required to be present at the facility. This is usually common for larger PV systems. In this case and due to what is referred to as “net purchase and sale” in most places, excess energy produced at the customer location from any DG source can be purchased by the utility at a different rate from the customer rate when the customer buys the electricity. The rate is agreed upon when signing the contract.
One of the main barriers to the expansion and adoption of PV systems is the utility interconnection policies that are established by federal, state, and local governments. Local utility companies may enforce interconnection policies where other governmental policies are absent.
A number of policies have been developed over the past 30 years that impacted the interconnection of privately owned power generation systems at the state and federal levels. In general, PURPA specifies the qualifying facility and agreements to meet certain technical and procedural requirements to be interconnected to the utility grid. PURPA practices are overseen by the Federal Electric Regulatory Commission (FERC), which is responsible for overseeing the electric utility industry in the US.
Interconnection agreement is a contract between a distributed power producer and electric utility under specific interconnection terms and conditions. Interconnection of PV systems must be approved by the local utility with cooperation of the local AHJ.
The interconnection process begins after submitting an interconnection plan to the local utility along with the system design application for a permit with the local AHJ.
After the permit is granted, PV installation can be completed and then inspected by the AHJ, and utilities in some cases, to approve the interconnection based on national codes and standards. Interconnection documents must include a conceptual system design showing the location of main parts of the systems with distances and the electrical one-line diagrams that show the main electrical calculations for PV system components and interconnection methods, protection devices, and disconnects used. Finally, the system can be interconnected, commissioned, and operated.
Interconnection agreement by utility in most cases mandates that any interconnected DG source including a PV system have liability insurance, system inspection and monitoring, system maintenance, and disconnects on the outside of the facility, so the utility can have access to it at any time.
Activity | Details |
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Assignment | Post original entry: We talked in class about applicable codes that govern the PV systems interconnection to the utility grid. Based on previous discussions, we learned that PV systems classification can include more specific market sector such as:
Discuss specific grid interconnection considerations for one of the options. Support your discussion with facts (you may research the same solar installation example you selected for previous discussions). Hint: the point of connection of the grid might have limitations. Post comments: Respond to two different opinions of others' posts. (For example, if you choose Option 1, you need to respond to one post for Option 2 and another post for Option 3 or 4.) |
Requirements, Submission Instructions, and Grading | For more detailed instructions about the discussion component of this course, including how you will be graded, please visit the Discussion Activity [7] page. |
This week, you will finish up and submit your PV System Electrical Design Project.
Activity | Details |
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Assignment | Visit the PV System Electricial Design Project [8] page for details on this overall assignment. You will be submitting your Project at the end of this lesson. |
Going back to the scenario we started in this lesson, you are working on the electrical design for the same PV system as in Lesson 8. As you complete the NEC design for the PV array, you reach the point of interconnection with the utility grid at the meter side. By now, you know the requirements and methods to interconnecting the PV system to the utility grid. You can review the site evaluation documents provided by the sales team to decide it they are missing any information about the main service distribution panel in terms of location, type, and size (voltage and current ratings).
Upon the completion of this lesson, your next step is to decide on the interconnection strategy and recommend any service upgrade if needed. Furthermore, you may need to consult with the utility plan reviewers to check on any additional requirements they enforce in that location, such as additional metering or disconnects.
In the next lesson, we will combine all efforts to take it a step further to submit the permitting documents, and we will discuss project management strategies and safety issues associated with the interconnection process.
You have reached the end of this lesson. Before you move to the next lesson, double-check the list on the first page of the lesson to make sure you have completed all of the requirements listed there.
Links
[1] http://www.solarabcs.org/about/publications/reports/expedited-permit/pdfs/Expermitprocess.pdf
[2] https://www.e-education.psu.edu/eme810/node/592
[3] http://grouper.ieee.org/groups/scc21/1547/1547_index.html
[4] http://ulstandards.ul.com/standard/?id=1741_2
[5] https://en.wikipedia.org/wiki/Three-phase_electric_power
[6] http://www.nfpa.org/freeaccess
[7] https://www.e-education.psu.edu/ae868/node/890
[8] https://www.e-education.psu.edu/ae868/node/987