By Trishia Swayne, Leidos Engineering
Large, utility-scale solar and wind generation interconnections have traditionally been interconnected to the transmission grid. But that’s now changing.
The discussion isn’t just around distributed residential rooftop solar impacting the distribution grid anymore. With incentives at the state and utility level and renewable portfolio requirements, utility-scale distributed generation (DG) interconnections in the 500 kW to 10 MW range are becoming the norm on the distribution system. Utilities have streamlined processes to help power plants and other generation sources connect to the transmission grid.
With the newness of large interconnections at the distribution level, however, some utilities across the globe are still struggling to define the process and understand the real impacts of utility-scale DG. These interconnections require utilities to plan for the sources’ intermittent nature and the impacts on their systems. The planning process can be streamlined in many ways, and can be similar to those used for power plants and other generation sources.
It’s important for utilities to study, understand, keep up to date with and follow existing and upcoming revisions to relevant documents and standards, like the IEEE 1547, keeping in mind that each utility has unique requirements, facility specifications, protection philosophies and planning criteria. To make things more complicated, each distributed generation site may have its own requirements as well.
An assessment of the overall system impacts of DG can help address each of these components. One approach is to let the DG site dictate how in-depth the evaluation needs to be based on size, site specifications and initial screenings to determine if a full, detailed impact study is required. Some sites may require a high-level overview, while others will need a detailed study so that decision makers understand the full impact. A detailed study would include performing an analysis, generally with engineering analysis software, and comparing system performance pre- and post-DG project while following guidelines from the IEEE 1547 standard.
Basic Data and Assumptions
An initial step in the process, after a distributed generation developer submits an application and fee, is to determine the feeder of interconnection, gather data and determine if a detailed study is required. Various data sources will provide the broadest view of the impact. Sources to consider are:
- Current load data at the substation and feeder level
- Source and line impedance information for the substation and feeder selected
- Substation transformer specifications, including load tap changer or regulator settings
- Line regulator and capacitor specifications and settings
- Protective device locations and settings
- Engineering analysis models
- Distributed generation site specifications including location, step-up transformers, inverters/turbines, protection, cable sizes, etc.
- Fault current contribution from the inverter/turbine manufacturer
Some of this data can be difficult to gather, and often a utility may have to make estimates and assumptions for certain data points. During this process, however, it is important to document actual data vs. assumptions because some will have greater impact than others. For example, assumptions on transformer impedance or conductor sizes, based on industry standards, shouldn’t heavily impact the results of the study. On the other hand, assumptions on substation source impedance, inverter specifications or protective device settings can lead to much larger implications.
With data in hand, some utilities run a quick screening to determine whether a detailed study is required or the site can move forward with interconnection. The screenings include evaluations such as calculating DG size to minimum feeder load ratio; determining inverter/turbine fault contribution to maximum available fault on the distribution system at various locations; checking if inverter/turbine certifications are based on utility requirements; confirming effective grounding; and calculating DG size to maximum available fault current. While other factors exist, these criteria are most prevalent in utility interconnection standards. Each of the evaluations noted should have limits set, similar to planning criteria, so that it is easy to determine if violations require an in-depth impact study.
Initial screenings don’t necessarily require the DG site to be modeled in engineering analysis software. In a detailed study analysis, however, having a distribution model to perform load flow and short circuit analysis is important to help determine the impacts of interconnection more quickly and easily.
Depending on modeling software, a variety of modeling components are used to represent DG. Some software includes more detail while others have a more simplistic representation. Having knowledge of available software options is important.
In addition to evaluating traditional generation conditions, other DG interconnections, whether currently online or in the queue to be interconnected, should be considered as they could impact the results of another proposed DG site. Many utilities include known DG in an area where a new site is being proposed when performing an impact study.
Short Circuit Analysis
A short circuit analysis will identify whether the additional fault current introduced by the DG site would exceed interrupting ratings of existing protection equipment. Although this isn’t typically an issue, it is an important safety check. Fault contribution from inverters generally consists of a slightly higher continuous current output of the inverter until it responds to an abnormal system condition and shuts off. Contributing to faults on the distribution system can desensitize relays at the substation. The utility also should check to see that the contribution in fault current doesn’t cause the feeder relay to over-reach some other mid-stream protective device or interfere with fuse-saving schemes. Fault current calculations at the point of interconnection, at the feeder breaker and at the high side of the distribution substation are relevant check points in short circuit analysis.
Voltage and capacity Reviews
Studying the steady state voltage and capacity as well as voltage flicker will determine if the proposed DG interconnections allow the system to remain inside industry operating standards. Steady state voltage and capacity reviews can be considered separate from voltage flicker. One way to evaluate voltage and capacity is to analyze minimum and maximum daytime loading scenarios with and without the DG online, noting voltage, reactive demand (kilo-VAR), kilowatts and power factor at the point of interconnection, feeder breaker location and substation. This analysis will reveal if voltage falls outside of the American National Standards Institute (ANSI) standard and if there is possible reverse flow through the feeder, substation transformer or voltage regulators. In this analysis, utilities can also determine if there is conductor or other equipment loading issues in each scenario.
In addition to analyzing a couple of snapshots in time, hourly analysis may be considered. Hourly analysis provides a clearer picture of the impact of DG on switchable devices such as load tap changers, regulators and capacitors. If the review of a few snapshots in time show that load tap changers, voltage regulators and/or switched capacitors have movement, an hourly evaluation might be important (see Figure 1). The number of switched capacitor changes and/or voltage regulator tap movements can be calculated in this analysis too.
Examples of calculations, pre and post photovoltaic solar installation, on a distribution feeder for a 24-hour view of a peak load day.
For sites that expect voltage flicker violations based on applicable industry standards, utilities can review moving the site closer to the source, serving the site from a stronger source, upgrading conductor size to the DG site, reducing the DG site size or using a dynamic reactive device such as a STATCOM, inverter VAR controls or other load management tools including energy storage.
Stability analysis is generally reserved for DG sites larger than 5 MW or for a large queue of DG sites where cumulative impact should be reviewed. Using positive sequence load flow or power system simulation, utilities can test fault ride-through characteristics, voltage transients, regulating device behavior, islanding, critical clearing time and evaluation of power swings for out-of-step protection.
The model will largely impact the complexity of this analysis, along with the time needed to finish it. Many times, model updates need to be made to make sure the model has the properties needed for this analysis.
A review of in-line protective devices will determine if they are overloaded with the DG online or if the DG interferes with existing settings. Some utilities replace in-line fuses with reclosers to avoid possible nuisance outages. They may also require a readily available, visible break isolation device at the point of common coupling (PCC), such as a recloser or gang operated air break switch.
The utility often requires some protection to be owned by the developer but controlled and operated by the utility. This is for safety and protection of utility equipment. Not all developers, however, propose additional protection beyond what is required at the point of interconnection for the utility protection. They have fusing for transformer protection alone.
A review of the feeder breaker/relay settings with DG online can help determine whether the DG is offline before the feeder recloses. DG shouldn’t interfere with the existing system protection scheme. It should shut off before the feeder recloses. In some cases, voltage monitors can be put in place to block reclosing until it has cleared.
Islanding and de-energizing also can be a safety concern. Inadvertently energizing the electric system during line maintenance or service restoration activities could have severe consequences. It is important, therefore, for utilities to have positive indication that the potential generation sources have been isolated from the system prior to any work being performed during system outages.
With DG online during a system fault condition the utility feeder-reclosing scheme could be impacted. Utility reclosing is designed to allow arcs associated with temporary line faults to dissipate and the surrounding air to de-ionize. If the DG isn’t cleared during a temporary fault, this generation will continue to feed the fault, which decreases the effectiveness of the reclosing scheme. While typically being responsible for just a small amount of fault contribution, DG can act to sustain an arc for a longer time.
In addition, if an unintended island forms with DG online, customers connected with the generation in the island will experience poor power quality, including voltage and frequency fluctuations, which could cause problems for customer loads as well as drive customer complaints. DG, as in solar and wind resources, isn’t designed to be a primary source of frequency. The combination of mismatches with load and generation capacity/magnitude, impedance serving the loads, and frequency variations also will drive voltage fluctuations.
From the IEEE 1547, utilities may be concerned with islanding when a range of factors are present. The IEEE standard specifies how quickly DG should shut off in response to certain voltage and frequency conditions on the electric system. Additional generation in the area can impact how quickly a particular DG interconnection may respond to system conditions as well. IEEE 1547 specifies that DG must be off for five minutes before attempting to reconnect. This should provide sufficient time for a fault to be cleared and for other DG in the impacted area to go offline.
If islanding is a concern, a direct transfer trip or recloser/relay protection at the point of interconnection may be sufficient. Transient software programs can perform additional islanding analysis to determine how quickly the DG responds to faulted conditions on the electric system. In addition, transient software programs can evaluate if transient overvoltage issues on the electric system could exist with DG systems interconnected.
Effective Grounding Requirements
The IEEE 1547 standard also covers effective grounding, and the impacts of DG site transformer windings and configuration. Ungrounded neutral and non”effectively grounded neutral generation sources feeding into four”wire, multi-grounded neutral distribution systems can cause potentially damaging ground fault overvoltage on the unfaulted phases under certain conditions.
Upon receiving an application package, utilities can do a quick check on effective grounding by inspecting the transformer windings and identifying any grounding banks or reactors. It is also important to check the inverters or turbines proposed. By maintaining an actual load to generation ratio of at least three or more for solar or wind, effective grounding might not be necessary to limit damage fault current overvoltages. This isn’t always achievable, however, especially at minimum daytime loading. In addition, utilities can wait to separate the feeder from the substation grounding source transformer until all non-effectively grounded DG has been cleared.
When reviewing and planning the integration of DG, utilities might not need to perform all these steps for every project. When evaluating a complex renewables interconnection and the deliverables, however, an in-depth study covering each of these aspects will help answer questions, mitigate risk and prepare the utility for success. Streamlining the process of studying DG can be beneficial to the utility industry. Other than the IEEE 1547 standard, state and utility interconnection requirements vary or do not exist at all in some cases. As utilities continue to face larger-scale DG interconnections, keeping up to date with relevant industry standards and sharing knowledge with industry peers, developers and DG equipment manufacturers is a step in the right direction toward streamlining the planning process to understand the real impacts of DG on the distribution system.
Trishia Swayne is a senior consultant at Leidos with more than 11 years of experience in electric utility system planning. She has extensive experience performing distributed generation impact studies for utility clients across the country. Reach her at firstname.lastname@example.org.