system impact study for def gisrs, queue positions 125 & 126 · 2019-12-23 · to-ground faults...

System Impact Study

for DEF GISRs, Queue Positions 125 & 126

May 2014

Transmission Planning, Florida

Jeffrey Van Dyke

Michael Alexander, P.E.

This document and any attachments hereto (“document”) is made available by Duke Energy Company upon and subject to the express understanding that: (a) neither Duke Energy Company nor any of its officers, directors, affiliates, agents, or employees makes any warranty, assurance, guarantee, or representation with respect to the contents of the document or the accuracy or completeness of the information contained or referenced in the document, and (b) Duke Energy Company, its officers, directors, affiliates, agents, and employees shall not have any liability or responsibility for inaccuracies, errors , or omission in, or any business or policy decisions made by any direct or indirect recipient in reliance on, this document or the information contained or referenced therein; all such liability is expressly disclaimed.

Table of Contents Summary 1 Interconnection Points Evaluated 1 Criteria for Determining Transmission Impact 3 Model Development 4 Analyses Performed 5 Screening Criteria 5 Study Results & Costs 6 Feasibility of In-Service Date 10 Appendix A, Most Significant Thermal Analysis Results 11 Appendix B, Most Significant Voltage Analysis Results 13 Appendix C, Short Circuit Analysis Results 14 Appendix D, Stability Analysis Results 16 Appendix E, P-V Analysis Results 18


Summary These two GISRs (Generator Interconnection Service Requests) are each for a new CT (Combustion Turbine) generator, with 167 MW summer net output and 187 MW winter net output. The anticipated commercial operation date is June 1, 2016. The points of interconnection will be at Duke Energy Florida’s (DEF’s) Suwannee River 230 kV substation, with one unit interconnecting to the 230 kV and the other unit interconnecting to the 115 kV. The type of interconnection services being requested is NRIS (Network Resource Interconnection Service). This study showed several thermal impacts to DEF’s transmission system in the surrounding area and marginal impacts to third parties in the area. Several third-party voltage impacts were found, though slight. In addition to analysis performed using the FRCC 2013 Databank Rev2d cases, a stressed generation case involving maximum FRCC imports from Southern Company was performed. There were no transmission breakers identified on the DEF system that will be pushed above their interrupting rating by the addition of these units. Lastly, the new CTs and their associated transmission upgrades will not have an adverse impact on the transient stability response of the bulk electric system.

Interconnection Points Evaluated Point of interconnection requested for study by interconnection customer for the 115kV unit:

• Connection to DEF’s existing 115 kV Suwannee River Substation.

Alternative point of interconnection considered by DEF for the 115 kV unit: • No other options were considered reasonable or necessary.

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Point of interconnection requested for study by interconnection customer for the 230kV unit: • Connection to DEF’s existing Suwannee Peakers 230 kV switchyard.

Alternative point of interconnection considered by DEF for the 230 kV unit:

• No other options were considered reasonable or necessary.

Aerial Diagram showing location of new CTs

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Criteria for Determining Transmission Impact DEF’s criteria for identifying transmission facilities impacted by the interconnection of new generation facilities are as follows: Thermal Impact

• System-intact loading over 100% Rate A. • B/C1/C2/C5 post-contingency loading over 100% Rate B. • C3 or C3-gen post-contingency loading over 100% Rate C. • Minimum loading increase from Base Case to Interconnection Case of 3%.

Voltage Impact

• System-intact bus voltages lower than 0.95 p.u. or higher than 1.05 p.u. • B/C1/C2/C5 post-contingency bus voltages lower than 0.90 p.u. or higher than 1.05 p.u. • Minimum voltage change from Base Case to Interconnection Case of 0.02 p.u.

Short-circuit Impact

• Three-phase and single line-to-ground fault current over 100% breaker fault duty capability. • Minimum fault current increase from Base Case to Interconnection Case of 3%.

Dynamics Impact

• The new Suwannee CTs must remain connected and synchronized with the transmission system for a normally clearing 3φ fault.

• The new Suwannee CTs must remain connected and synchronized with the transmission system for a delayed clearing single line-to-ground fault.

• The addition of the new Suwannee CTs cannot create a transient unstable response resulting in widespread system collapse.

• The addition of the new Suwannee CTs cannot create a transiently stable response with undamped power system oscillations.

• The addition of the new Suwannee CTs cannot cause the activation of automatic under-frequency load shedding schemes.

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Model Development Power Flow Models Power flow models were built using the Siemens PSS/E power system simulation program (PSS/E) and were based on the FRCC 2013 series (Revision 2d, February 2014) cases, which were the most recent models available at the time of the study. The model seasons studied for power flow impacts were 2016 summer, 2016/17 winter, 2019 summer, and 2019/20 winter. These FRCC models were updated with relevant new information from the study area, including updated thermal ratings and the dispatch of Crystal River & Citrus generation. After these adjustments, FRCC Block & Priority Economic Dispatch was used to reallocate generation within Duke Energy Florida. Finally, an erroneous MVAR load model at PCS/Occidental was corrected, a capacitor bank at Jasper was installed, and several upcoming transmission improvement projects in the area were included. In addition to developing standard 2,400 MW FRCC import cases, high-import sensitivity cases were created assuming a 3,700 MW generation import from the Southern Company. The differential between base and study cases was to turn off all three Suwannee Steam 115kV units and then turn on the new 115 & 230 kV CTs. Short Circuit Models Short circuit models were built using the PSS/E power system simulation program and were based on the FRCC 2013 series (Revision 1, December 2013) short circuit cases, which were the most recent models available at the time of the study. The model year studied for short circuit impacts was 2016. In addition to the primary analysis using data provided by the customer in the system impact study agreement, a sensitivity was performed using an alternative 7.5% impedance generator step-up transformer (GSU) for each combustion turbine. Dynamics Models Dynamics analyses were performed using the FRCC 2013 series (Revision 1, April 2014) 2014 summer peak load and 50% summer peak load models, modified for 2016 load levels and anticipated local transmission projects, to determine the impact of the Suwannee 115 and 230 kV combustion turbines on the dynamic stability of the transmission system. The customer provided generator, exciter, governor, and power system stabilizer data for use with models within the PSS/E dynamics model library. In addition to the primary analysis using data provided by the customer in the system impact study agreement, a sensitivity was performed using an alternative 7.5% impedance generator step-up transformer (GSU) for each combustion turbine. Generation Interconnection Queue Considerations The DEF Generation Interconnection Queue was reviewed, and thus a prior-queued item was included in both the base and the study cases. That item is Queue #s 123&124, a new Combined Cycle plant proposed for interconnection in Citrus County. No other prior-queued requests were deemed relevant to this study. Transmission Service Request Priority List Considerations A review of transmission service requests in the FRCC coordinated priority list was performed and no relevant transmission service requests were identified in the study area that were not already built into the FRCC cases.

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Analyses Performed Power flow analyses of the base cases and Suwannee CT study cases were performed using PowerGEM TARA software (TARA) to determine the impact of interconnecting the queued generation to the transmission system in the Suwannee River Plant area. The base cases and the interconnection study cases were compared to determine if the interconnection option created thermal overloads or voltage violations, or exacerbated existing thermal overloads or voltage violations. All single element transmission contingencies (69 kV and above) were analyzed as well as NERC Category C3 (N-1-1) contingencies resulting in Rate C overloads. All branch flows and bus voltages were monitored (69 kV and above) in the FRCC region. The FRCC reliability region consists of peninsular Florida east of the Apalachicola River. The State of Georgia (to the north) and the panhandle area of Florida west of the Apalachicola River in the State of Florida are within the SERC reliability region. PSS/E short circuit analyses were performed using PSS/E activity ASCC. Three phase and single line-to-ground faults were applied up to three breakered buses away from the DEF Suwannee River 230 kV substation in both the base case and the study case to measure short circuit impacts. Fault analysis was performed with all nearby generation in service.

Dynamic analyses were performed for this generation using the PSS/E dynamic simulation tool. Analyses were run for NERC category C delayed-clearing single line-to-ground (SLG) faults and NERC category D delayed-clearing 3φ faults. Clearing times for faults at the Suwannee River and Suwannee Plant substations were obtained from DEF’s Protection & Control Department. Typical “worst-case” clearing times were used for faults at neighboring substations and transmission lines.

Screening Criteria The following criteria were used for screening TARA power flow thermal results.

• GSU transformers were excluded from consideration. • Transmission system elements operated at less than 69 kV nominal voltage were excluded. • System-intact overloads greater than 100 percent of rate A were reported • Post-contingency (N-1) overloads greater than 85 percent of rate B were reported • Post-contingency (N-1-1) overloads greater than 85 percent of rate C were reported • Post-contingency loadings with changes of at least 5 MW were reported

*It is important to note that even though DEF’s new ratings methodology was applied before analyzing, since this GISR was queued prior to the implementation of DEF’s new ratings, this GISR will be grandfathered with the old ratings if there are any impacts that only occur with the new ratings. The following criteria were used for screening TARA power flow voltage results.

• Transmission system buses operated at less than 69 kV nominal voltage were excluded. • System-intact bus voltages outside the range 0.95–1.05 p.u were reported • Post-contingency bus voltages outside the range 0.95–1.05 p.u were reported • Post-contingency bus voltages with changes of at least 0.005 p.u. were reported.

The following screening criteria were used for screening the PSS/E short circuit results.

• All results within three breakered buses of the proposed interconnection point were examined.

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Study Results Thermal:

System impacts identified by the addition of these queued resources:

• Rebuild of the 0.9 mile 115kV line between the Suwannee 230/115 kV Substation and the Suwannee Plant 115kV Substation (limited by the sag-limited conductor and line jumpers)… this is a Rate C overload caused by a NERC Category B (N-1) contingency: loss of the Fort White to Suwannee 230kV line.

• Upgrade limiting elements on the 0.65 mile 230kV line between Suwannee Peakers 230kV collector bus and the Suwannee River 230 kV substation (limited by relay protection equipment at the Suwannee River 230kV substation)… this is a NERC Category A (N-0) Base Case overload that occurs even when no contingencies occur.

• Customer will be subject to redispatch to remedy a rare overload on the Suwannee 230/115 kV Transformer #2… this is a Rate B overload caused by a NERC Category C breaker failure contingency scenario due to the existing 230kV yard configuration. As an alternative, a $0.5 million project could be assigned to the customer to perform a terminal-swap.

System impacts identified for which there is already an existing DEF project with a compatible need date to remediate the impact and thus no project assigned: • Upgrade of the Ft White 115/69kV transformer (impacts are Rate C overloads caused by

NERC Category C3 contingency scenarios). DEF has an internal need for this upgrade in June 2016, but has scheduled the upgrade for December 2016, based on normal project pacing. DEF will accelerate this project with no costs assigned to the customer.

• Rebuild of the Alachua Tap to Alachua, Alachua to GE Alachua, and GE Alachua to Hull Road 69kV line segments. DEF has an internal need for these rebuilds in 2016, but has scheduled the rebuild for 2017, based on normal project pacing. However, since these are non-Bulk-Electric overloads that occur only under high FRCC import scenarios, DEF will not accelerate the project and will continue targeting 2017. No costs will be assigned.

• Rebuild of Hanson – Greenville 115kV. DEF has an internal need for this rebuild in 2016, but has scheduled the rebuild for 2018, based on normal project pacing. A system impact was found in this study for a different scenario , but that scenario is not significant enough to warrant a project since the overloads are less than 104% and only occur in an extremely rare system condition. Therefore, the DEF will not accelerate the project and will continue targeting 2018. No costs will be assigned to the customer.

System impacts identified for which there is an existing DEF project planned which has a later need date that will require acceleration in order to remediate the impact: • None

DEF internally-planned projects that were in-service in the study model that DEF must not defer or delay beyond the customer’s in-service date of June 2016: • new Drifton – Perry 115kV circuit • rebuild of Wrights Chapel to Jasper 115kV • Suwannee Capacitor Banks to increase total MVARs at Suwannee to 150MVAR

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Narrative Summary of Thermal Impacts The 0.9 mile 115kV line between the Suwannee 230/115 kV Substation and the Suwannee Plant 115kV Substation will need to be rebuilt with a recommended conductor of 1272 ACSS/TW, due to overloading under various contingency scenarios. This cost is estimated to be $1.3 million. All impacts to the 230kV line between Suwannee Peakers and the Suwannee River 230kV (N-0 and post-contingency) can be resolved by upgrading relay protection components at the Suwannee River 230kV sub. Estimated cost: $0.3 million. The impact to the 230/115kV transformer #2 at Suwannee, caused by a rare breaker-failure of breaker 900, can be resolved with a post-contingency redispatch of Suwannee generation. Alternatively, the customer can elect to fund a project to swap the Ft White 230 kV terminal and the Suwannee Peakers 230 kV terminal. The estimated cost for this work is $0.5 million (optional). Please note that DEF Transmission may elect to apply the cost for the aforementioned 115 kV substation rebuilds as credit toward a more expensive but more prudent alternative to instead create a new 115kV switchyard. DEF Transmission currently does not have internal drivers of its own to create this new yard, but a new yard offers more flexibility for the future versus doing the bare minimum upgrades and changeouts to the existing ring.

Please see the electronic appendices for the full thermal analysis results in Microsoft Excel format. All other impacts shown in the results were deemed pre-existing issues or were NERC Category C3 impacts for which there were adequate pre-2nd-contingency solutions which did not cause real-time issues and did not set up more potential Rate C overloads. In particular, issues south of Crystal River were deemed pre-existing when considering projects Duke Energy would need to perform in order to preserve its full existing transmission rights for the maximum output of Crystal River generation.

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Voltage: The quantitative analysis showed numerous voltage impacts. However, upon applying qualitative analysis and engineering judgment, the only impacts clearly attributable to the customer are 3rd-party impacts (see below) Please see the electronic Appendices for the complete results of voltage analysis.

Third Party Impacts: The screening criteria revealed many small third-party thermal impacts throughout the FRCC, none of which were deemed significant. These impacts will be investigated in a future coordinated study, and it is possible that more impacts will be revealed, in particular given the complexity of interconnecting generation in close proximity to the Florida-Southern Interface. The only voltage impacts clearly attributable to the customer are 3rd-party impacts to the Florida-Southern Transfer Import Capability. These impacts are slight, but it is possible that a 3rd party will demand compensation for some new capacitor banks. These impacts will be investigated in a future coordinated study, and it is possible that more impacts will be revealed, in particular given the complexity of interconnecting generation in close proximity to the Florida-Southern Interface.

Short Circuit: Short circuit analyses revealed that the interconnection of the Suwannee 115 and 230 kV facilities would cause impacts greater than 3% at the Suwannee, Fort White, and Perry substations. However, the magnitude of the fault current revealed in the system impact analysis does not exceed the fault capability of existing components at the substation. The 7.5% GSU Sensitivity revealed additional impacts at these same substations, none of which exceeded the fault capability of existing substation components.

See Appendix C for a summary of short circuit analysis results.

System Stability: Based on the dynamics modeling data provided by the customer, the Suwannee 115 and 230 kV combustion turbine units will not jeopardize system stability.

For a tabulation of disturbances and their respective simulation results, refer to Appendix D.

P-V Analysis The results of the analysis indicate that in order to maintain the existing transfer capability of the SOCO-FLA interface, a 75 MVar cap bank should be installed at the 230 kV Perry substation. Appendix E shows that the transfer capability margin of the interconnection in the base case is maintained by using 7.5% impedance GSUs for the new units.

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Costs

The “Zero MVA” Interconnection Facility costs to interconnect the units are $0.8 million for the expansion of the existing 115kV ring at the Suwannee River 230kV substation from five positions to six.

As for Network Upgrades, based on this System Impact Study, the additional costs for “Full MVA Output” are estimated to be approximately $8.6 million. This includes a conservative estimate of $5 million in Protection & Control projects that are anticipated to be identified in Facility Study.

A table of all estimated costs is below.

The overall total is estimated to be $9.4 million.

If the option is elected for reduced risk of redispatch upon a breaker failure, the new total cost would be estimated at $9.9 million.

*Please note these costs do not include 3rd party impacts, which could be significant in additional scope and cost and will be fully determined in an independent study performed by the FRCC.

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Feasibility of In-Service Date Based on the identified projects for interconnection and network upgrades, the feasibility of completing these projects in time for the customer’s requested in-service date of June 2016 (two years from the publication of this report) will be challenging with normal project pacing and normal engineering & construction resources. Considerable efforts will be made to achieve the customer’s date, but that date cannot be guaranteed.

It is advised that the customer enter into the Facility Study stage at once.

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Appendix A - Most significant results from thermal contingency analysis:

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Appendix B - Most significant results from voltage contingency analysis:

*Note: These voltage violations are 3rd-party impacts

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Appendix C - Short Circuit Analysis Results:

Primary Analysis

BASE STUDY Delta Capacity DutyBus Number Bus Name Bus kV Fault Type (Amps) (Amps) (%) (Amps) (%)

3-Phase to Ground 5,710 5,716 0.11% --- ---Single Line to Ground 3,846 3,858 0.31% --- ---

3-Phase to Ground 6,074 6,616 8.18% 25000 26.46%Single Line to Ground 4,858 4,874 0.32% 25000 19.49%


3-Phase to Ground 7,365 7,234 -1.81% 40000 18.09%Single Line to Ground 4,523 4,520 -0.06% 40000 11.30%

3-Phase to Ground 18,954 17,913 -5.81% 25000 71.65%Single Line to Ground 18,365 18,464 0.54% 25000 73.86%















317205 6N TIFTON 230

316109 3TWINLAKS 115

317203 6PINEGRVE 230

3172 ST MARKS 230

3174 GINNIE 230

3168 SUWANNEE PKR 230

3169 SUWANNEE RV 230

3165 NEWBERRY 230

3167 PERRY 230

3160 CRAWFORDVLLE 230

3162 FT WHITE N 230

3134 OCC SWIFTCK1 115

3158 SUWAN PLT B 115

3132 SUWANNEE PLT 115


3113 JASPER 115

3116 MADISON 115

384 COLUMBIA 115

3108 FT WHITE 115

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7.5% Generator Step-Up Transformer Sensitivity

BASE STUDY Delta Capacity DutyBus Number Bus Name Bus kV Fault Type (Amps) (Amps) (%) (Amps) (%)




















317205 6N TIFTON 230

316109 3TWINLAKS 115

317203 6PINEGRVE 230

3172 ST MARKS 230

3174 GINNIE 230

3168 SUWANNEE PKR 230


3165 NEWBERRY 230

3167 PERRY 230

3160 CRAWFORDVLLE 230

3162 FT WHITE N 230

3134 OCC SWIFTCK1 115

3158 SUWAN PLT B 115

3132 SUWANNEE PLT 115


3113 JASPER 115

3116 MADISON 115

384 COLUMBIA 115

3108 FT WHITE 115

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Appendix D – Dynamic Analysis Results

Tabulation of Disturbances Tested in Stability Analyses Contingency

Name Description Sequence of events Timing in

Cycles SUW115_3PH 3-PHASE FAULT ON THE SUWANNEE RIVER

115KV BUS

Clear remote end Columbia FPL 115 Clear remote end Suwannee Plant 115 Clear remote end Occidental Swift Creek 115 Clear remote end Pine Grove 230 Clear remote end Fort White 230 Clear remote end Perry 230 Trip Suwannee 115 kV CT on overspeed Trip Suwannee 230 kV CT on overspeed Trip Suwannee 230 kV P1-3 on overspeed

35.0 35.0 35.0 80.0

130.0 180.0 180.0 180.0 180.0

SUW115_SLG SINGLE LINE TO GROUND FAULT ON THE SUWANNEE RIVER 115KV BUS

Clear remote end Suwannee Plant 115 Clear remote end Occidental Swift Creek 115 Clear remote end Fort White 230 Clear remote end Pine Grove 230 Clear remote end Perry 230 Clear remote end Columbia FPL 115 Trip Suwannee 115 kV CT on overspeed Trip Suwannee 230 kV CT on overspeed Trip Suwannee 230 kV P1-3 on overspeed

35.0 35.0 55.0 69.0

119.0 119.0 119.0 119.0 119.0

SUW230_3PH 3-PHASE FAULT ON THE SUWANNEE RIVER 230 KV BUS

Clear remote end Columbia FPL 115 Clear remote end Pine Grove 230 Clear remote end Fort White 230 Clear remote end Perry 230 Trip Suwannee 230 kV CT Trip Suwannee 230 kV P1-3 Clear remote end Suwannee Plant 115 Clear remote end Occidental Swift Creek 115 Trip Suwannee 115 kV CT on overspeed

29.0 29.0 30.0 30.0 55.0 55.0 95.0

185.0 185.0

SUW230_SLG SINGLE LINE TO GROUND FAULT ON THE SUWANNEE RIVER 230 KV BUS

Clear remote end Pine Grove 230 Clear remote end FTW230 Clear remote end Perry 230 Clear remote end Suwannee Plant 115 Clear remote end Occidental Swift Creek 115 Trip Suwannee 115 kV CT on overspeed Trip Suwannee 230 kV CT on overspeed Trip Suwannee 230 kV P1-3 on overspeed

29.0 30.0 30.0 95.0

185.0 185.0 185.0 185.0

SUWPLT_3PH 3-PHASE FAULT ON THE SUWANNEE PLANT 115 KV BUS

Clear remote end Suwannee Plant 115 Clear remote end Madison 115 Clear remote end Twin Lakes 115 Clear remote end Fort White 115 Clear remote end Jasper 115 Clear remote end Hanson 115

29.0 35.0 35.0 35.0 35.0 35.0

SUWPLT_SLG SINGLE LINE TO GROUND FAULT ON THE SUWANNEE PLANT 115 KV BUS

Clear remote end Suwannee Plant 115 Clear remote end Madison 115 Clear remote end Fort White 115 Clear remote end Jasper 115 Clear remote end Twin Lakes 115 Clear remote end Hanson 115

34.0 35.0 35.0 35.0 59.0 65.0

OSC115_3PH 3-PHASE FAULT ON THE OCCIDENTAL SWIFT CREEK 115 KV BUS WITH DELAYED CLEARING

Clear remote end Suwannee 115 kV Clear remote end Jasper 115 kV

95.0 95.0

LVO115_3PH 3-PHASE FAULT ON THE LIVE OAK (FPL) 115 KV BUS WITH DELAYED CLEARING

Clear remote end Suwannee 115 kV Clear remote end WELBRN 115 kV

95.0 95.0

FTW230_3PH 3-PHASE FAULT ON THE FORT WHITE 230 KV BUS WITH DELAYED CLEARING

Clear remote end Suwannee 230 kV Clear remote end Newberry 230 kV Clear remote end Ginnie 230 kV Clear Ft White 230/69 kV Transformers

55.0 55.0 55.0 55.0

PER230_3PH 3-PHASE FAULT ON THE PERRY 230 KV BUS WITH DELAYED CLEARING

Clear remote end Suwannee 230 kV Clear remote end Fl Gas Trsmsn 230 kV Clear Perry 230/115 kV Transformers

55.0 55.0 55.0

PGV230_3PH 3-PHASE FAULT ON THE PINE GROVE (SOCO) 230 KV BUS WITH DELAYED CLEARING

Clear remote end Suwannee 230 kV Clear Pine Grove 230/115 kV Transformers Clear remote end Valdosta 230 kV Clear remote end Tifton 230 kV

55.0 55.0 55.0 55.0

SUW115-SUWPLT_3PH

3-PHASE FAULT ON THE SUWANNEE RIVER TO SUWANNEE PLANT 115 KV LINE

Clear remote ends on the Suwannee River to Suwannee Plant 115 kV Line

95.0

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SUW115-OSC115_3PH

3-PHASE FAULT ON THE SUWANNEE RIVER TO OCCIDENTAL SWIFT CREEK 115 KV LINE

Clear remote ends on the Suwannee River to Occidental Swift Creek 115 kV Line

95.0

SUW115-LVO115_3PH

3-PHASE FAULT ON THE SUWANNEE RIVER TO LIVE OAK (FPL) 115 KV LINE

Clear remote ends on the Suwannee River to Live Oak (FPL) 115 kV Line

95.0

SUW230-FTW230_3PH

3-PHASE FAULT ON THE SUWANNEE RIVER TO FORT WHITE 230 KV LINE

Clear remote ends on the Suwannee River to Fort White 230 kV Line

55.0

SUW230-PER230_3PH

3-PHASE FAULT ON THE SUWANNEE RIVER TO PERRY 230 KV LINE

Clear remote ends on the Suwannee River to Perry 230 kV Line

55.0

SUW230-PGV230_3PH

3-PHASE FAULT ON THE SUWANNEE RIVER TO PINE GROVE (SOCO) 230 KV LINE

Clear remote ends on the Suwannee River to Pine Grove (SoCo) 230 kV Line

55.0

Tabulation of Stability Analyses Results

Contingency Name

2016 Peak Load Case Results

2016 50% Load Case Results

2016 Peak Load Case Results

(7.5% GSU Sensitivity)

2016 50% Load Case Results

(7.5% GSU Sensitivity) SUW115_3PH Damped response;

Suwannee Units tripped on overspeed; 489MW of generation lost; no UFLS activated

Damped response; Suwannee Units tripped on overspeed; 334MW of generation lost; no UFLS activated



SUW115_SLG Damped response; Suwannee Units tripped on overspeed; 489MW of generation lost; no UFLS activated




SUW230_3PH Damped response; Suwannee Units tripped on overspeed; 489MW of generation lost; no UFLS activated




SUW230_SLG Damped response; FPL Columbia line relay tripped at 110 cyc; Suwannee Units tripped on overspeed; 489MW of generation lost; no UFLS activated

Damped response; FPL Columbia line relay tripped at 29 cyc; Suwannee Units tripped on overspeed; 334MW of generation lost; no UFLS activated



SUWPLT_3PH Damped response; no units tripped; no UFLS activated

Damped response; no units tripped; no UFLS activated



SUWPLT_SLG Damped response; no units tripped; no UFLS activated




OSC115_3PH Damped response; no units tripped; no UFLS activated




LVO115_3PH Damped response; no units tripped; no UFLS activated




FTW230_3PH Damped response; no units tripped; no UFLS activated




PER230_3PH Damped response; no units tripped; no UFLS activated




PGV230_3PH Damped response; no units tripped; no UFLS activated

Damped response; FPL Columbia line relay tripped at 55 cyc; no units tripped; no UFLS activated



SUW115-SUWPLT_3PH





SUW115-OSC115_3PH





SUW115-LVO115_3PH





SUW230-FTW230_3PH





SUW230-PER230_3PH





SUW230-PGV230_3PH





Note: Detailed stability analysis results are available upon request.

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Appendix E – P-V Analysis Results:

SOCO-FLA Interface Transfer Capability Margin (MW) Summer 2017

Perry 75 MVar Contingency Base 16.6% 7.5%

Duval 76 91 84 91 Duval 82 131 113 125 Thalmann 80 103 109 118 Sanford #5 203 200 206 Sanford #4 216 212 222

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system impact study for def gisrs, queue positions 125 & 126 · 2019-12-23 · to-ground faults...

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