I am often asked, “what threshold should the industry use for defining when distributed energy resources (DERs) have an impact on the bulk power system (BPS)?” This usually has a trailing explanation about how defining a threshold for impact will help entities know when to require data collection for modeling DERs in reliability studies and when studies should include those models. After lengthy discussions in the North American Electric Reliability Corporation (NERC) System Planning Impacts from Distributed Energy Resources Working Group (SPIDERWG), I realized that this question is backwards. It does not help us collectively get to where we need to be going, namely, reliable operation of the BPS with increasing instantaneous penetrations of DERs. So, I present this post as an explanation of a simple argument—studies require models, which require data. In other words, without data, one cannot create models, and without models, one cannot execute studies. Everything revolves around the availability of data that are suitable and useable by entities required to develop BPS models and execute reliability studies.
Gathering and Utilizing DER Data for Transmission Planning Studies
Distribution providers (DPs) developing interconnection requirements and authorities governing interconnection requirements (AGIRs) should ensure that the connection of DERs can be properly accounted for and tracked by DPs in order to facilitate DER data transfer to entities tasked with performing BPS reliability studies. Various entities have stressed the importance of implementing DER data requirements, even prior to significant levels of DERs entering their system. The implementation of these requirements ensures that roadblocks are eliminated early rather than DPs facing insurmountable or costly challenges down the road. As transmission planners refine their DER modeling practices, having clear data requirements is the first step in ensuring that sufficient data are available to apply engineering judgment and develop reasonable representations of aggregate amounts of DERs on their system.
At the time of writing this blog, the SPIDERWG is in the process of finalizing the NERC Reliability Guideline: DER Data Collection for Modeling in Transmission Planning Studies. This guideline is intended to help bridge the language barrier between DPs with a limited amount of data available for their DER interconnections, and transmission planners who are seeking suitable information that can help them create aggregate DER steady-state and dynamic models. As the guideline describes, with some limited information about the expected vintage (and therefore default settings) of DERs and any relevant distribution interconnection requirements that may be in place, planners can make reasonable judgments to develop DER models. But it is paramount that these entities communicate with one another to enable this process. SPIDERWG has also submitted a Standard Authorization Request (SAR), endorsed by the NERC Planning Committee, to modify NERC Reliability Standard MOD-032-1 to explicitly include collection of aggregate DER data for the purposes of developing planning models.
When to Consider DER Models? Always.
Each transmission planning entity will need to weigh the importance of modeling DERs in its reliability studies, and should perform its due diligence to ensure that not modeling aggregate DERs will not have a notable impact on the outcomes of these studies. A technical basis (i.e., a study) is needed to prove that—an assumption or “past experience” is not adequate these days. Developing an industry-wide or continent-wide threshold for when DERs should be modeled is not practical nor is it recommended. Modeling DERs in one area of the BPS may be critical while in other areas it may not be. Careful consideration of all possible assumptions is required in areas with low short circuit strength, high generation dispatch variability, high or rapidly changing transfers, low reactive power margins, strict stability limits, high rate of change of frequency (ROCOF), and many other factors. This includes considering the impacts of aggregate amounts of DERs. Further, the likelihood of these issues within a planner’s footprint is becoming significantly higher.
Therefore, it is important for DERs to be tracked by appropriate entities, for information to be provided to transmission planners, and for aggregate amounts of DERs to be reasonably modeled in planning assessments. Ignoring DERs in simulations degrades the assurance that reliability studies are providing planners with a clear understanding of potential reliability risks. As stated in multiple NERC Reliability Guidelines, all DERs should be accounted for in some aggregate manner in planning assessments; detailed modeling considerations should be left to individual planning entities to make proper study assumptions.
Developing DER Models
Planning assessments rely on reasonable and accurate steady-state, dynamics, short-circuit, and other types of models to represent the overall interconnected electrical grid. Elements of the BPS are represented explicitly and other elements are represented in aggregate. As with end-use loads, DERs are aggregated to a reasonable point in planning models. Most commonly, there is one modeled end-use load element to represent each transformation across the T-D interface. For example, a load record in the power flow base case will represent one T-D transformer bank, which may be a collection of multiple distribution circuits within a distribution substation. In the power flow base case, DERs can be accounted for in different ways: either as a component of the load record or as a stand-alone generator record modeled at the distribution bus. The data needed to create these models are fairly straightforward—total capacity, general dispatch behavior, assumptions on reactive power control (if relevant), etc.
In the dynamics realm, the models get much more complicated; fortunately, industry is rapidly developing new modeling techniques to account for DERs in planning studies. NERC SPIDERWG published Reliability Guideline: Parameterization of the DER_A Model, providing clear guidance on default model parameters that can be used in the DER_A dynamic model for different vintages (or mixture of vintages) of IEEE 1547. The goal of this guideline is not to provide exact default values that should be used everywhere; rather, the goal is to help inform industry how these model parameters relate to the various performance requirements specified in IEEE 1547.
The DER_A dynamic model is fairly complex. But when you break it down to its various control loops, it becomes much more palatable. The major blocks include:
- Active power-frequency controls
- Reactive power-voltage controls
- Frequency tripping logic
- Active-reactive current priority
- Fractional tripping logic
- Voltage source representation
Many of the parameter values for this model generally do not change across vintages of IEEE 1547; however, a handful of parameters do change significantly and warrant close attention by grid planners when developing these models. Understanding how DERs are expected to operate, and what vintage of IEEE 1547 (where applicable) these resources are, can get a modeler very far in this process of DER model creation. For example, asking the vintage of DERs and whether the DERs are primarily retail-scale rooftop solar photovoltaic (PV) or are utility-scale solar PV resources participating in a market and providing essential reliability services can provide many different answers to assumptions needed to develop models.
The level of verification of model parameters and the accuracy of aggregate models will hopefully improve over time as more experience is gained by transmission planners with increasing levels of DERs. Future systems with high penetrations of DERs may need to explore more in-depth studies using detailed models of DERs. ISO New England has even conducted studies of high-penetration DER areas using detailed electromagnetic transient simulations to explore any potential reliability issues that could arise that may not be picked up with conventional positive sequence, fundamental frequency simulation tools.
This blog will continue in Part 2 with the impacts of DER on the bulk power system.
Senior Manager, BPS Security and Grid Transformation, NERC
 Defined in IEEE 1547-2018, the AGIR is the entity that “defines, codifies, communicates, administers, and enforces the policies and procedures for allowing electrical interconnection of DER…This may be a regulatory agency, public utility commission, municipality, cooperative board of directors, etc.”