Feasibility Study for the Q171 74.5 MW Solar Project August 2018 Bulk Transmission Planning, Florida i
This document and any attachments hereto ( document ) is made available by Duke Energy Florida, LLC ( DEF ) upon and subject to the express understanding that: (a) neither DEF, 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) DEF, 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. ii
Table of Contents 1. Executive Summary... 23 2. Point of Interconnection ( POI )... 34 3. Model Development... 34 3.1. Power Flow Models... 34 3.2. Interface Models... 34 3.3. Short Circuit Models... 34 3.4. Generator Interconnection Queue Considerations... 45 3.5. Transmission Service Request Priority List Considerations... 45 4. Analyses Performed... 45 4.1. Power flow analyses... 45 4.2. Short circuit analyses... 45 5. Screening Criteria... 56 6. Study Results... 67 6.1. Thermal Results... 67 6.2. Voltage... 67 6.3. Short Circuit... 67 6.4. Third party Impacts... 67 6.5. Costs... 67 Appendix A Summary of Thermal Analysis Results... 78 Scenario 2... 78 Appendix B Short Circuit Analysis Results... 89 Short Circuit Scenario 1... 89 Short Circuit Scenario 2... 910 1
1. Executive Summary The Q171 Interconnection Customer has submitted an interconnection request on DEF s system for a Solar PV station, capable of 74.5 MW ac net output. The facility will be located in Gilchrist County, Florida, connecting to a substation on the Ft. White Newberry 230 kv transmission line. The Interconnection Customer has requested that this generation facility be evaluated for Network Resource Interconnection Service ( NRIS ) with a requested Commercial Operating Date ( COD ) of December 31, 2018. Cost estimates in this report are based on the facilities that are identified as directly impacted by the generator under study, and do not take into account results that may indicate unrelated existing issues. Additional detailed study may result in changes to scope and cost. The estimates from this Feasibility Study are only Planning estimates (level 5) and may change significantly due to additional information determined from a more detailed System Impact and Facilities Studies to follow. This study included some facilities and network upgrades required for prior queued requests. If one or more of these prior queued requests are modified or withdrawn, Q171 may become responsible for these upgrades, in addition to those facilities identified in this report. A new 230 kv substation, approximately eight miles north of DEF s Newberry substation, was required for the prior queued Q154 project. Q171 was studied connected to a new 230 kv terminal at Q154 s substation. This evaluation did not identify any additional upgrades to DEF s transmission system to accommodate the full capacity (74.5 MW) of the Q171 Solar PV project. However, there are some potential regional impacts that will require further evaluation in the System Impact Study. No potential Third Party thermal Impacts were identified. The short circuit analysis revealed some increases in the fault current, but no DEF devices were found to be impacted by this increase. Additional in depth analysis for third party impacts will be performed in a future FRCC Transmission Technical Subcommittee evaluation following the System Impact Study if the Interconnection Customer moves to a Facilities Study. The conclusion of this Feasibility Study is that Q171 could be connected via an Interconnection Customer supplied generator tie line (approximately two miles in length) to the assumed Q154 230 kv interconnection substation on the Ft. White to Newberry 230 kv line. The estimated cost required for a new breakered terminal at the proposed Q154 s POI to accommodate the interconnection of the Q171 Solar Project is $1,050,000. In addition, the Interconnection Customer would be responsible for the construction, ownership, and maintenance of the generator tie line. 2
2. Point of Interconnection ( POI ) There is only one POI requested for study by Interconnection Customer: Add a 4 th breaker to the proposed Q154 Breaker Ring Bus Substation connecting to DEF s Ft. White Newberry 230 kv line Two mile long 230 kv Customer supplied Gen Tie Figure 1: Diagram of Q171 Interconnection 3. Model Development 3.1. Power Flow Models Power flow models were built using the Siemens PSS/E power system simulation program and were based on the FRCC 2017 series cases, which were the most recent models available at the time of the study. The model year studied for power flow impacts was 2020 Summer. The study case model utilized the adjusted base model with the addition of the Q171 Solar Project generation and the required basic interconnection facilities. 3.2. Interface Models No interface analyses were performed as part of this evaluation. 3.3. Short Circuit Models Short circuit analysis performed utilized the FRCC 2017 short circuit model (y17_20srls SCRls_rev1a_V34.sav). The model year studied for the short circuit analysis was 2020. Note: Customer did not provide adequate modeling data at the time of the study for the 3 winding transformer indicated on the Customer provided one line diagram. Short circuit case models were built using data from a similar sized solar PV s 3 winding transformer. 3
3.4. Generator Interconnection Queue Considerations Prior queued generation in the FRCC coordinated queue was reviewed, and it was determined that DEF would study two scenarios for prior queued requests. The first scenario primarily included only prior queued requests that were already in the cases used. A second scenario included the following list of prior queued requests: Q144A, Q148, Q151, Q152, Q153, Q154, Q155b, Q158, Q159, Q159b, Q160, Q166, & Q169. Generator Interconnect Studies for prior queued generation interconnection requests in the form of Feasibility and System Impact Studies are currently conducted in accordance with FERC rules and are prioritized by their queue positions to determine the assignment of required interconnection facilities and transmission upgrades to accommodate their requested interconnections. In the instances where these studies are not complete, the facilities and upgrades required for these earlier queued requests were not included in the base cases used in this study. To the extent that one or more of these requests are modified or withdrawn, the results presented in this analysis may no longer be valid and/or may change materially. DEF will advise the Customer of any changes associated with the preceding GIS requests that may require a re study of this GIS request. 3.5. Transmission Service Request Priority List Considerations A review of transmission service requests in the FRCC coordinated priority list was performed, and it was determined that there are no relevant transmission service requests in the study area that were not already built into the FRCC cases. 4. Analyses Performed 4.1. Power flow analyses Power flow analyses of the cases were performed using the PowerGEM TARA software ( TARA ) to determine the impact of interconnecting the queued generation to the transmission system in the area. The base and 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 69 kv and above branch flows and bus voltages in the FRCC region were monitored. The following contingencies were observed in this study: Selected Category P1, P2, P4, P5, and P7 contingencies within the FRCC region as previously defined by FRCC transmission owners. Selection variations include: o All single element contingencies (69 kv and above) in the FRCC region 4.2. Short circuit analyses Short circuit analyses were performed using PSS/E activity ASCC. All local generators were online for the analysis. Activity FLAT was used to set up the network conditions corresponding to classical fault analysis assumptions. Three phase and single line to ground faults were applied at all buses within FRCC and were analyzed using a 3% screening criterion. Devices that are installed to interrupt fault current (breakers, circuit switchers, etc.) that are connected to buses identified in the screened results will need to be evaluated to determine whether their fault current interrupting capabilities 4
are exceeded. This evaluation of the impact of increased fault current on DEF devices will be performed during the subsequent Facilities Study and the evaluation of the impact on third party devices will be performed separately during the FRCC process. The final results represent all buses within FRCC with a difference between the base case and study case greater than 3%, in addition to the next bus out in the affected area to capture the total impact. 5. Screening Criteria The following criteria were used for screening thermal results. Unrelated GSU transformers were excluded from results. Transmission system elements operated at less than 69 kv nominal voltage were excluded. System intact overloads must be greater than 100% of rate A. Post contingency overloads must be greater than 100% of rate A. Post contingency overloads that are improved by the interconnection were excluded. Post contingency overloads must have been made worse than the base case by 3% of the affected element s rating or greater. The following criteria were used for screening voltage results. Buses in DEF and SECI were monitored for values outside of the range 0.9 1.05 p.u. FPL 69, 115, 138, and 230 kv buses were monitored for values outside the range 0.95 1.07 p.u. FPL 500 kv buses were monitored for values outside the range 0.95 1.10 p.u. TECO 69 kv buses were monitored for values outside the range 0.925 1.05 p.u. TECO 138 and 230 kv buses were monitored for values outside the range 0.95 1.06 p.u. Turkey Point bus voltage was monitored for values outside the range of 1.01 1.06 p.u. St. Lucie bus voltage was monitored for values outside the range of 1.00 1.06 p.u. All other monitored areas were monitored for values outside of the range 0.95 1.05 p.u. Generator buses and buses with nominal voltage below 69 kv were excluded from consideration. Absolute change in bus voltage between base case and the interconnection case must have been greater than 0.02 p.u. The following screening criteria were used for screening the ASCC short circuit results. Three phase and single line to ground fault current on the DEF system had to exceed the interrupting rating of the breaker. Three phase and single line to ground fault current results are provided to third parties close to this area for their acceptance or rejection of the results based on their own breaker rating criteria. The table in Appendix B Short Circuit Analysis Results (below) reflects increases in fault current greater than 3%, in addition to the next bus out to represent the total impact. 5
6. Study Results 6.1. Thermal Results The evaluation did not identify any network upgrades to DEF s transmission network to accommodate the full capacity (74.5 MW) of the Q171 Solar Project. However, there are some potential impacts that might be aggravated due to the interconnection of Q171. If further analysis finds that these impacts cause current workable mitigations to no longer be valid, curtailing Q171 output might be necessary. The results for the analysis are shown in Appendix A. Additional analyses will be performed in the future System Impact Study. 6.2. Voltage There were no identified voltage violations that were attributable to the interconnection of the Q171 Solar Project interconnection. 6.3. Short Circuit Short circuit analysis was performed and the results were evaluated against the interrupting capability of potentially impacted devices in DEF s system. No devices were identified that would likely exceed their interrupting capability. The short circuit results are tabulated in Appendix B. 6.4. Third party Impacts The thermal analysis did not reveal any potential third party impacted facilities. The short circuit analysis revealed some increases in the fault current. The ultimate short circuit result to determine third party impact will be performed separately during the FRCC process. Additional in depth analysis for third party impacts will be performed in a future FRCC Transmission Technical Subcommittee evaluation following the System Impact Study, if the customer moves to a Facilities Study. 6.5. Costs Required upgrades for basic physical interconnection: Est. Costs New breaker as 4 th terminal on the greenfield 230 kv ring bus substation $1,050,000 Total Estimated NRIS Cost: $1,050,000 These estimates are preliminary planning estimates, and details specific to this project discovered in the System Impact Study and Facilities (design engineering) Study phases may significantly affect these estimates and projected in service dates. From a planning perspective, a reasonable projected in service date for a terminal and construction of a previously identified greenfield substation would be 2 to 3 years after project commitment or mid 2021 to mid 2022, if commitment was mid 2019. 6
Appendix A Summary of Thermal Analysis Results Scenario 2 Summer 2020 Results Meeting Impact Criteria % Loading Monitored Facility Contingency Name Base Study Delta 3452 HAMMOCK2 TP 115 3463 HAMMOCK TP 115 1 P7:DEF LECA BKRG 99.02 106.58 7.56 3452 HAMMOCK2 TP 115 3485 ROYAL HI TP 115 1 P7:DEF LECA BKRG 93.69 100.92 7.23 3463 HAMMOCK TP 115 3478 TWIN CO RNCH 115 1 P7:DEF LECA BKRG 95.5 102.73 7.23 3468 HOMOSASSA2TP 115 3478 TWIN CO RNCH 115 1 P7:DEF LECA BKRG 105.78 113.03 7.25 3468 HOMOSASSA2TP 115 3481 VILLA TER TP 115 1 P7:DEF HOLD ROSS 101.18 104.69 3.51 3468 HOMOSASSA2TP 115 3481 VILLA TER TP 115 1 P7:DEF LECA BKRG 116.12 123.35 7.23 3516 CITRUS ENRGY 230 3526 POWERLINE 230 1 P2 3:DEF_PWLN_3B 109.24 111.91 2.67 3516 CITRUS ENRGY 230 3526 POWERLINE 230 1 P4:DEF_PWLN_3B 109.24 111.91 2.67 3516 CITRUS ENRGY 230 3526 POWERLINE 230 1 P7:DEF PWRL CENG 109.24 111.91 2.67 3516 CITRUS ENRGY 230 3526 POWERLINE 230 2 P7:DEF PWRL CENG 109.24 111.91 2.67 3516 CITRUS ENRGY 230 3526 POWERLINE 230 3 P7:DEF CENG PWRL 109.24 111.91 2.67 3516 CITRUS ENRGY 230 3526 POWERLINE 230 4 P2 3:DEF_PWLN_3B 109.24 111.91 2.67 3516 CITRUS ENRGY 230 3526 POWERLINE 230 4 P4:DEF_PWLN_3B 109.24 111.91 2.67 3516 CITRUS ENRGY 230 3526 POWERLINE 230 4 P7:DEF CENG PWRL 109.24 111.91 2.67 Results potentially impacting 3rd parties to be resolved under the FRCC process. Summer 2020 Results Meeting Impact Criteria % Loading Monitored Facility Contingency Name Base Study Delta 8850 BELCRK 230 8852 BELCRK 69.0 1 P2 3:TEC Gannon_419 99.96 100.16 0.2 7
Appendix B Short Circuit Analysis Results Short Circuit Scenario 1 PSS E ASCC SHORT CIRCUIT CURRENTS (V @ 1.0 pu) Base Case Study Case SLG 3φ (I1) 3φ (I1) SLG (3I0) Bus # Bus Name kv (3I0) % 3 % SLG 171004 Q171_POI 230 DEF 7062.9 4349.2 7310.9 5360.6 3.51% 23.25% 3165 NEWBERRY 230 DEF 6911.9 4236.3 7092.1 4938.2 2.61% 16.57% 3163 FT WHITE S 230 DEF 8946.2 5595.5 9092.9 6132.5 1.64% 9.60% 3178 FT WHT S CAP 230 DEF 8946.2 5595.5 9092.9 6132.5 1.64% 9.60% 3162 FT WHITE N 230 DEF 8916.9 5587.5 9060.6 6121.6 1.61% 9.56% 3170 WILCOX 230 DEF 4215.3 2473.8 4278.6 2691 1.50% 8.78% 3173 BRONSON DUKE 230 DEF 7292 4527.7 7406.6 4921.7 1.57% 8.70% 3084 WILCOX 69 DEF 10122.9 6556.5 10225.6 6999.2 1.01% 6.75% 3050 NEWBERRY 69 DEF 7380.8 6140.1 7436.1 6539.7 0.75% 6.51% 3174 GINNIE 230 DEF 8212.8 4844.5 8288.7 5134.6 0.92% 5.99% 3055 OLD TOWN N 69 DEF 7686.4 4635 7743.8 4851.8 0.75% 4.68% 3013 BRONSON DUKE 69 DEF 8554.7 7046.8 8603.2 7329.2 0.57% 4.01% 3085 FT WHITE B 69 DEF 13842.4 9373 13888.7 9737.5 0.33% 3.89% 3027 FT WHITE A 69 DEF 13819 9358.4 13864.9 9721.6 0.33% 3.88% 3081 TRENTON 69 DEF 6281.6 3346.5 6319.6 3458.8 0.60% 3.36% 3003 GINNIE 69 DEF 12847.4 9570.3 12893.5 9888.5 0.36% 3.32% 3029 GA PACIFIC 69 DEF 6160.1 3457.5 6191.8 3558.1 0.51% 2.91% 7476 FMP NEWB 69 CFEC 7380.8 6140.1 7436.1 6539.7 0.75% 6.51% 6640 OLDTOWN 69 CFEC 6921.9 4284.7 6967.5 4469.7 0.66% 4.32% 6736 HAILEMIL 230 CEC 6959.5 4016.7 6990.8 4162.1 0.45% 3.62% 6647 NEWBERRY 69 CFEC 7120.1 3344 7171.2 3457.1 0.72% 3.38% 6642 TRENTON 69 CFEC 6243.5 3325.4 6281 3436.3 0.60% 3.33% 6632 BRONSON 69 CFEC 7302.7 5513.1 7337.2 5685 0.47% 3.12% Base Case: "y17_20srls SCRls_rev1a_V34.sav with prior queued Q103 & Q137 with all FRCC generation in service. Study Case: Base case plus Q171 PV generator. 8
Short Circuit Scenario 2 PSS E ASCC SHORT CIRCUIT CURRENTS (V @ 1.0 pu) Base Case Study Case Bus # Bus Name kv 3φ (I1) SLG (3I0) 3φ (I1) SLG (3I0) % 3 % SLG 154004 Q154_POI 230 DEF 7975.0 6279.6 8224.5 7032.8 3.13% 11.99% 3165 NEWBERRY 230 DEF 7762.5 5754.7 7936.6 6193.0 2.24% 7.62% 3173 BRONSON DUKE 230 DEF 7836.9 5355.8 7938.0 5546.7 1.29% 3.56% 3163 FT WHITE S 230 DEF 10212.4 8479.8 10348.7 8734.8 1.33% 3.01% 3178 FT WHT S CAP 230 DEF 10212.4 8479.8 10348.7 8734.8 1.33% 3.01% 3162 FT WHITE N 230 DEF 10161.7 8452.4 10294.6 8704.6 1.31% 2.98% 3170 WILCOX 230 DEF 4614.7 3212.5 4671.0 3313.3 1.22% 3.14% Base Case: "y17_20srls SCRls_rev1a_V34.sav with prior queued Q103, FLS06, Q137, Q148, 151, Q152, Q153, Q154, Q155b, Q158, Q159, Q159b, Q160, Q166, & Q169 with all FRCC generation in service. Study Case: Base case plus Q171 PV generator. 9