AF2-132 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 AF2-132 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 — Pulaski County, Indiana. The installed facilities will have a total capability of 300.0 MW with 180.0 MW of this output being recognized by PJM as Capacity.

AAF2-132 will interconnect with the AEP transmission system by tapping the Olive proposed AE2-045 345 kV Station portion of the Olive – Reynolds (NIPSCO) –  #1 345 kV Line with a three-breaker ring bus interconnection substation and loop the Olive – Reynolds kV Line into the proposed substation. The transmission line tap will be located approximately 44 miles from Olive 345 kV Substation and 12.2 miles from the proposed AE2-045 345 kV Substation.

AAttachment 1 shows a one-line diagram of the proposed interconnection of the AF2-132 generation project to the AEP transmission system.

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

Executive Summary

Generator Interconnection Request AF2-132 is for a 300.00 MW Maximum Facility Output (MFO) solar generation plant. AF2-132 consists of 96 × 3.1413 MW, Power Electronics FS3430M solar PV inverters with a total capacity of 301.5645 MW. The Point of Interconnection (POI) is at a tap on Olive – Reynolds 345 kV circuit 1 in the American Electric Power (AEP) transmission system, Pulaski, Indiana.

Generator Interconnection Request AF2-133 is for a 300.0 MW Maximum Facility Output (MFO) solar generation plant. AF2-133 consists of 96 × 3.1414 MW, Power Electronics FS3430M solar PV inverters with a total capacity of 301.5702 MW. The Point of Interconnection (POI) is at a tap on Reynolds – Olive 345 kV circuit No. 2 in the American Electric Power (AEP) transmission system, Pulaski, Indiana.

This report describes a dynamic simulation analysis of AF2-132 and AF2-133 as part of the overall system impact study.

The load flow scenario for the analysis was based on the RTEP 2022 peak load case, modified to include applicable new service request projects. AF2-132 and AF2-133 have been dispatched online at maximum power output, with 1.0 p.u. voltage at the generator bus.

AF2-132 and AF2-133 was tested for compliance with NERC, PJM, Transmission Owner, and other applicable criteria. Steady-state condition and 92 contingencies were studied, each with a 20 second simulation time period. Studied faults included:

       a) Steady state operation (20 second);

       b) Three-phase faults with normal clearing time;

       c) Single-phase faults with stuck breaker;

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

No relevant high-speed reclosing (HSR) contingencies were identified for this study.

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) AF2-132 and AF2-133 was able to ride through the faults (except for faults where protective action trips a generator(s)),

       b) The system with AF2-132 and AF2-133 included is transiently stable and post-contingency oscillations were positively damped with a damping margin of at least 3% for interarea modes and 4% for local 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 AF2-132 and AF2-133 meet the 0.95 lagging and leading PF requirement at the high side of the main transformer.

The composite short-circuit ratio (CSCR) assessment was performed for inverter-based renewable generation units which are within one (1) substation away of AF2-132 and AF2-133. The CSCR results are summarized in Table 10 through Table 13 and revealed a minimum and maximum CSCR values of 2.892 for P7.03 and 4.780 for P1.10, respectively.

Fictitious frequency response at AF2-132, AF2-133, AF2-078 and J968, J1069 generators bus tripped the new service request project due to the action of instantaneous under and over-frequency relays during several contingencies. Therefore, the frequency relay pickup times for instantaneous tripping were set to 20 seconds to avoid fictitious frequency tripping of the unit.

AF2-132 and AF2-133 exhibited slow reactive power recovery for several contingencies. This issue did not cause instability in the system and the models were tuned to have faster reactive power output post-fault recovery and response.

The IPCMD and IQCMD states in the REGCAU model of AF2-132 and AF2-133 showed erratic behavior for some contingencies in which AF2-132 and AF2-133 have been disconnected as part of the contingency event. Since the machines are 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 AF2-132 and AF2-133 meet 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.

The AF2-132 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.

An updated one line diagram will be provided in the Facilities Study report for the Expedited Process projects.

Download all tables in report