AF1-207 System Impact Study Report

This project is eligible for the Expedited Study process per PJM Tariff Part VII, Subpart B, section 304 and will follow the Expedited Study Process rules outlined in PJM Manual 14H, Attachment I.3.4.

Projects in the Expedited Process will receive a retooled System Impact Study report with the Transition Cycle #1 projects (AE1-AG1) removed from the base case model used for their study. This System Impact Study (SIS) report has been prepared for the AF1-207 project using the updated case model. PJM performed reliability analysis for the project based on the serial study approach using the legacy Generator Deliverability Study method outlined in Manual 14B, Attachment C.3 (Revision 51 of M14B). Summer peak and light load load flow analysis was performed. Short circuit and dynamic stability impacts were also analyzed.

The interconnected Transmission Owner (TO) for this project is American Electric Power. The TO has provided their updated TO analysis results on the lower voltage system based on their own criteria.

This System Impact Study report summarizes both the PJM and TO analysis results for your project.

Note: This updated SIS report does not include any Physical Interconnection Facilities scope or cost estimates from the TO. As this project is in the Expedited Process, a Facilities Study will be conducted by the TO (and any affected Transmission Owner(s)) for updated Physical Interconnection Facilities and System Reinforcement (Network Upgrade) costs. The Facilities Study will be issued to the Project Developers along with the Generator Interconnection Agreement (GIA) as part of the Expedited Process.

The developer has proposed a Solar generating facility located in the American Electric Power zone — White County, Indiana. The installed facilities will have a total capability of 180.0 MW with 34.0 MW of this output being recognized by PJM as Capacity.

AF1-207 will interconnect with the AEP transmission system via a new station cut in to Olive (AEP) – Reynolds (NIPSCO) 345 kV circuit #1.

To accommodate the interconnection on the Olive – Reynolds (NIPSCO) 345 kV circuit #1, a new three (3) circuit breaker 345 kV switching station physically configured and operated as a ring-bus will be constructed. Installation of associated protection and control equipment, 345 kV line risers, SCADA, and 345 kV revenue metering will also be required. AEP reserves the right to specify the final acceptable configuration considering design practices, future expansion, and compliance requirements.

Installation of the generator lead first span exiting the POI station, including the first structure outside the AEP fence, will also be included in AEP's scope. In the case where the generator lead is a single span, the structure in the customer station will be the customer's responsibility.

No violations.

PJM Short Circuit Analysis did not identify any new overduty breakers or >3% contribution to previously identified overduty breakers.

Executive Summary

Generator Interconnection Request AF1-207 is for a 180.0 MW Maximum Facility Output (MFO) solar generation plant. AF1-207 consists of 57 x 3.1867 MW, Sungrow SG3600UD inverters rated at 3.2088 MW each. AF1-207 has a Point of Interconnection (POI) at the tap between Reynolds 345 kV and AE2-045 POI 345 kV station, in the White County, Indiana. 

This report describes a dynamic simulation analysis of AF1-207 as part of the overall system impact study.

The load flow scenario for the analysis was based on the RTEP 2023 peak load case, modified to include applicable new service request projects. AF1-207 has been dispatched online at maximum power output, with 1.0 p.u. voltage at the generator bus.

AF1-207 was tested for compliance with NERC, PJM, Transmission Owner and other applicable criteria. Steady-state condition and 127 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

       a)       Steady-state operation (20 second run);

       b)       Three-phase faults with normal clearing time, and with unsuccessful high-speed reclosing;

       c)       Single-phase bus faults with normal clearing time;

       d)       Single-phase faults with stuck breaker;

       e)       Three-phase faults with loss of multiple-circuit tower line.

There are no delayed (Zone 2) clearing faults due to dual primary relays being employed in the AEP 345 kV transmission system.

For all simulations, the new service request project under study along with the rest of the PJM system were required to maintain synchronism and with all states returning to an acceptable new condition following the disturbance.

For all of the fault contingencies tested on the 2023 peak load case:

       a)       AF1-207 was able to ride through the faults (except for faults where protective action trips a generator(s)).

       b)       The system with AF1-207 included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for local and interarea modes.

       c)       Following fault clearing, all bus voltages recovered to a minimum of 0.7 per unit after 2.5 seconds (except where protective action isolates that bus).

       d)       No transmission element tripped, other than those either directly connected or designed to trip as a consequence of that fault.

The reactive power capability of AF1-207 meets the 0.95 lagging and leading PF requirement at the high side of the main transformer.

The rotor angle of Cook Unit 1 did not achieve a flat response within the 20 second simulation window for several contingencies. This issue did not cause instability in the system. The selected contingencies were run for 30 seconds, and the rotor angles of Cook Unit 1 achieved a flat response at the end of the 30 second simulation time period for most of the contingencies. The same issue was observed in the AF1-046 dynamic analysis, therefore, this response was not caused by the addition of AF1-207. No mitigation is required due to instability.

The IPCMD and IQCMD states in the REGCAU model of AF1-207 showed erratic behavior for some contingencies in which AF1-207 has been disconnected as part of the contingency event. Since the machine is disconnected and no active or reactive power is injected into the system, this behavior is likely fictitious and a limitation of the software. This does not cause instability in the system.

No mitigations were found to be required.

The reactive power capability of AF1-207 meets the 0.95 lagging and leading PF requirement at the high side of the main transformer.

Steady State Voltage analysis is not required for this project at this time.

The Projects below are listed in one or more dispatch for the overloads identified in your report. These projects contribute to the loading of the overloaded facilities identified in your report. The percent overload of a facility and cost allocation you may have towards a particular reinforcement could vary depending on the action of these earlier projects. The status of each project at the time of the analysis is presented in the table. This list may change if any earlier projects withdraw. This table is valid for load flow analyses only.

Midcontinent Independent System Operator (MISO) Final Results - Impacts

New York Independent System Operator (NYISO) Not required
Tennessee Valley Authority (TVA) Not required
Louisville Gas & Electric (LG&E) Not required
Duke Progress Energy (DUKE) Not required
Carolina Power & Light East (CPLE) Not required
Carolina Power & Light West (CPLW) Not required

The AF1-207 project may be responsible for a contribution to the following estimated System Reinforcement (Network Upgrade) costs as shown below. The Network Upgrades listed below are required to alleviate a reliability criteria violation identified in the Network Impact analysis that PJM has performed for this System Impact Study. No physical Interconnection Facilities costs are included in this cost table.

Note 1: PJM Open Access Transmission Tariff (OATT) Part VI, section 217.3A outlines cost allocation rules for the Expedited Process projects. These rules are further clarified in PJM Manual 14A, Attachment B.

Note 2: To Project Developers with System Reinforcements listed: If your present cost allocation to a System Reinforcement indicates $0, then please be aware that if a prior project in the Expedited Process withdraws from the cycle, the cost responsibilities can change and a cost allocation may be assigned to your project. In addition, although the cost allocation to a System Reinforcement is presently $0, your project may need this system reinforcement completed to be deliverable to the PJM system. If your project desires to possibly come into service prior to completion of the system reinforcement, you would need to request an interim deliverability study to determine if all or a portion of your project would be deliverable.

The one line included in this refreshed System Impact Study report was originally developed prior to the Transition Date. Therefore, not all verbiage on the one line may align with the current Tariff definitions. An updated one line diagram will be provided in the Facilities Study report for the Expedited Process projects.

Files

• AF1-207 SLD and POI.pdf -- AF1-207 SLD and POI Map

Download all tables in report