PSC: DER Modeling (20230927)

Item Expired
Related Entity(s):
Topic(s):
MTEP, Transmission Planning

In the September 27 meeting of the Planning Subcommittee, MISO discussed DER modeling items as they pertain to the pending MOD-032-2 revision. As a part of this conversation, MISO is requesting feedback on challenges that stakeholders anticipate having in getting DER information submitted to MISO. 

Feedback due date extended to November 15.


Submitted Feedback

DTE would like to thank MISO for the opportunity to provide comments. DTE strongly encourages MISO to establish a threshold at which specific dynamic data and or steady state data should be required even with the phased in approach. Perhaps 550 kW or greater could be the threshold. Anything smaller perhaps MISO can just assign a generic model that it finds suitable. Another concern is legacy installations; for those, the utility would need to collect the information up to including site visits to verify configuration, settings and nameplates. There is likely substantial cost to do this task. Perhaps there could be an exemption for legacy systems where all this data may not be required. DTE would also welcome some guidance from MISO on how to calculate some of the parameters for aggregate installations where the POI's are at distribution voltage level, but at different EP nodes. How should the models reflect temporary changes of the POI due to load transfers both at the substation and on the overhead circuits? Thanks for the support, Raluca Lascu

Since MISO wants to base its MTEP models on coincident load forecasts, MISO should specify a date and time on which each model should be based, e. g. July 15th at 1600 EDT for Summer Peak.  In that way, data submitters can adjust both their own load forecasts and DER solar outputs accordingly.  This will be helpful in all MTEP models, but especially in summer shoulder models where the date and time of the summer shoulder was not defined relative to the summer peak.

Transmission Owners Feedback on MISO’s proposed approach for advancing DER modeling in planning reliability models

November 15, 2023

The MISO Transmission Owners (TOs) submit the following feedback in response to MISO’s presentation at the September 27, 2023 Planning Subcommittee meeting, regarding DER modeling relative to the pending MOD-032-2 revision, and to MISO’s request for feedback on challenges stakeholders anticipate having in getting DER information submitted to MISO.  

The Owners recognize that the lack of DER modeling will become more impactful to BES reliability as these resources increase in penetration installation across the footprint, and without accurate modelling for these resources, other generation assets will likely have to respond in ways not yet contemplated by modeling.

In response to feedback requested by MISO:

MISO’s draft framework for timing and thresholds of recommendations for DER inclusion in the MISO Series models.

MISO has proposed thresholds for the inclusion of DER modeling data in MISOs MTEP models.  For existing generation, a size-based approach makes sense, but may create re-work if records review is needed to get the initial data set.  However, these thresholds should not apply to newly interconnecting DER; the information should be collected when the DER interconnects, and new DER should all be modeled. 

Generally, the timeline appears to be achievable, but as described in more detail below, there are many complexities that must be resolved in the interim in order to realize this goal.  Additionally, Owners would have concerns with the liability associated with submission of data that they do not own.  For perspective, Owners do not submit generator data to MISO for facilities that they do not own.

Challenges with access to and submission of required modeling data for DERs

  • A primary challenge with Owners accessing or submitting required modeling data for DERs is that today DERs are not usually modeled in dynamics using distribution software, so this data has not been required in distribution interconnection processes.
    • Many state DER interconnection rules (e.g. Illinois, Iowa, and South Dakota), do not require the evaluation of transient stability during the interconnection process, so the Distribution Provider (DP) does not have a requirement for the Interconnection Customer (IC) to submit transient stability models during the interconnection study.
    • While select large DER installations may have verified models that the DP and TO are comfortable explicitly modeling these units in the power flow models, similar to transmission connected generators interconnecting through the MISO GI process, many DER developers do not have technical staff with the background and experience necessary to provide site specific, verified, accurately parameterized transient stability models. An unverified incorrectly parameterized model is not useful to MISO or the TO.
  • MISO should assume that most DER will need to be aggregated together at the transmission bus level in the power flow models and that a generic DER transient stability model will need to be used. MISO should focus on understanding what are the important parameters for constructing these aggregate DER representations to achieve a reasonable representation of the DER response during transient stability simulations.
  • For non-integrated utilities, it will be difficult for TOs to have visibility into how DERs are modeled by the DP and the interconnection arrangements on the Distribution System that are necessary to produce accurate dynamics study results.
  • Accurate modeling of impacts on T System will depend on how the DP is modeling the resources, so the Owners and MISO need this information from the DP.  The data exchange form they are putting together includes this information.
    • It will be difficult for the TO to have the visibility in how (resource or where the DER is modeled on the Distribution System (interconnection arrangements) that is necessary to produce accurate study results.
    • Site specific dynamics data for transient stability simulations will not be available for most DER installations.
  • Owners would have concerns with assuming liability for the accuracy of data submitted that is not their own and note that the referenced draft NERC Standard revision to MOD-032-2, out for balloting now, would require DPs to submit this data.
  • As described in more detail below, given the complexities noted above, additional direction will be needed from MISO on certain modeling details, for example, how DER at substations with multiple transformers and DER on each transformer should be modeled.

Owners Feedback on MISO’s Guiding Principles:

Work to align visibility in both the Planning and Operations Models:

  • This concept needs to be fleshed out more regarding the data that is to be aligned and what is meant by “alignment.” 
    • What is meant by alignment?  Is it the same data (i.e. knowledge of the DER on the system) or having the data that is relevant to that purpose?
    • Achieving alignment will require reconciling how to model a load in PSSE for each load in the EMS model.  EMS has separate loads for each transformer, and in the past, these have been modeled as a single bus load in PSSE.
      • Including separate DER load devices results in having two loads in PSSE that map to a single load in EMS, breaking the 1:1 mapping MISO has previously requested.   
  • The modeling data being requested by MISO will begin to add DER generation to Planning models, but for Operations models, if the generator data are added in the same format, Operations will have visibility into where on the system significant DER is interconnected, but no output data will be available. 
    • Relevant real time data is how much output is occurring, not just that there is a DER on the system.  There is value in RTO having the data, but the cost will be prohibitive for a lot of the data that is out there.
    • Owners do not uniformly haveReal Time SCADA, they only have transformer data at the substation. 
      • Some state distribution interconnection rules apply MW thresholds for requiring RT metering.
    • MISO models include D substations, but only net flow is visible.
    • Planning information is limited to MW installed vs. output; planning info combined with weather forecasts can fairly accurately predict DER output.
    •  It is not clear that actual operating data is needed for transmission system monitoring because tools are available to develop forecasts for System Operators for certain DER fuel types like wind and solar.
      • If the aggregate DER nameplate size connecting to each substation was mapped to that substation's physical location using GPS coordinates, then MISO could use their existing processes to forecast wind and solar generation output for transmission connected installations to estimate the DER output at each substation. 

Align with current and evolving State-jurisdictional processes and utility practices:

  • For many entities there is not a process currently in place necessary for the transfer of DER information from the Distribution Provider to the Transmission Owner/Transmission Planner.  These are all new processes that are having to be developed between the DP and the TO/TP.

Align DER modeling granularity with existing MISO modeling practices:

  • The existing process currently requests DP to include DER information when the enter their load data.  It has not been clearly identified that the DP needs to back out their generation from their net load information for each bus so that they are submitting gross load.  If this is not done it will double count the generation.  For some entities that had added DER generation to the MISO planning model, the generation was modelled as either negative load or as a generator.  They however were entering net load for this value.  Both need to happen to get the correct answer.
  • Additional guidance may be needed to identify the best mechanism to determine gross load.

Target cumulative effects for steady state data exchange:

  • While the cumulative effects for DER generation may be MISO’s goal, the goal for TP/TOs needs to be in getting the correct representation for all DER generation.  This is due to the proposed changes in not only MOD-032 but also proposed changes to TPL-001 and FAC-001/002.
  • Type and location (on the distribution system) is the relevant information in steady state analysis.  MISO process requires input of DER data in models; steady state analysis requires locational information to determine how it will respond.  Accurate operating expectations is needed vs. modeling as negative load.

Consider individual threshold sizes (i.e., large DER) for dynamics data initially:

  • The proposed size threshold should not be applied to new DER; the information should be collected when the DER interconnects.  This is the best time to request and receive modeling information.  New DER should all be modeled.  For existing generation, taking a size based approach makes some sense, but may create re-work if records review is needed to get the initial data set.  It might be better to request all DER at a substation as this is the only way to know which are at the loading levels MISO has identified.  

 

 American Municipal Power (AMP) appreciates the opportunity to provide feedback on MISO DER Modeling and offers the following comments.

  • MISO's draft framework for timing and thresholds of recommendations for DER inclusion in the MISO Series models:
    • AMP appreciates MISO's efforts toward drafting principles and a framework for ramping up to potential outcomes from the MOD-032-2 standard revision. However, before developing definitive DER modeling requirements, AMP encourages MISO to wait for the revised standards and effective date to ensure appropriate principles are developed.
  • Challenges with access to and submission of required modeling data for DERs:
    • Without knowing the MOD-032-2 standard revisions, the challenges with access to and submission of required modeling data for DERs are hard to quantify. However, depending on the information required, it could be burdensome for Market Participants and members to provide certain data. Additionally, it is unclear what benefits, if any, beyond any MOD-032-2 requirements may be realized by MISO. AMP encourages MISO to use discretion in determining the type and amount of data needed for DER modeling.

Consumers Energy would like MISO to consider using a hybrid approach of discretely modeling larger DER generators while aggregating smaller DER generators. We would propose a discrete modeling threshold of 550 KW and allow smaller DER to be aggregated to a gross nameplate value where MISO uses industry expertise to assign generic DER performance for steady state and dynamic models. Requiring TO’s or DP’s to provide dynamic models for these smaller aggregated units presents compliance issues because these DER interconnections and the information provided in the applications are regulated by RERRA’s and not the utility.

Consumers Energy requests MISO consider a grandfathering clause on certain modeling data for DER already installed. DP’s and TO’s would have nameplate data and could make assumptions of steady state modeling based on the settings required at the time of interconnection, but dynamic data may not have been captured. This would induce significant cost and take considerable time for utilities to attempt to coordinate with existing DER owners, especially if a minimum threshold is not established.

Different sizes of DER may have different settings requirements established by a utility. Creating an accurate aggregated model would prove difficult. DP’s also may not have the in-house expertise for dynamic modeling of this nature. Consumers Energy welcomes MISO’s guidance in making assumptions and the modeling parameters MISO may want to see used.

Consumers Energy is interested in how MISO intends to use/adjust the DER modeling provided. If MISO will be scaling the DER dispatch, or intends to in the future, would DP’s need to split out aggregated modeling by fuel type? Load forecasts are also closely related to DER penetration. MISO should allow DP’s to dispatch the DER as the DP’s see fit to align with company load forecasts and these values should not be changed unless similar consideration for why the DER is being adjusted is also applied to the load values. The DP’s should control the net injection/consumption modeling at each load bus.

James McCormick

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