XXXX. Kokish River Hydroelectric Project. Interconnection System Impact Study

Transcription

1 XXXX Kokish River Hydroelectric Project Report No. August 2010 British Columbia Hydro and Power Authority British Columbia Hydro and Power Authority All rights reserved..

2 DISCLAIMER OF WARRANTY, LIMITATION OF LIABILITY This report was prepared by the British Columbia Hydro And Power Authority ( BCH ) or, as the case may be, on behalf of BCH by persons or entities including, without limitation, persons or entities who are or were employees, agents, consultants, contractors, subcontractors, professional advisers or representatives of, or to, BCH (individually and collectively, BCH Personnel ). This report is to be read in the context of the methodology, procedures and techniques used, BCH s or BCH s Personnel s assumptions, and the circumstances and constraints under which BCH s mandate to prepare this report was performed. This report is written solely for the purpose expressly stated in this report, and for the sole and exclusive benefit of the person or entity who directly engaged BCH to prepare this report. Accordingly, this report is suitable only for such purpose, and is subject to any changes arising after the date of this report. This report is meant to be read as a whole, and accordingly no section or part of it should be read or relied upon out of context. Unless otherwise expressly agreed by BCH: 1. any assumption, data or information (whether embodied in tangible or electronic form) supplied by, or gathered from, any source (including, without limitation, any consultant, contractor or subcontractor, testing laboratory and equipment suppliers, etc.) upon which BCH s opinion or conclusion as set out in this report is based (individually and collectively, Information ) has not been verified by BCH or BCH s Personnel; BCH makes no representation as to its accuracy or completeness and disclaims all liability with respect to the Information; 2. except as expressly set out in this report, all terms, conditions, warranties, representations and statements (whether express, implied, written, oral, collateral, statutory or otherwise) are excluded to the maximum extent permitted by law and, to the extent they cannot be excluded, BCH disclaims all liability in relation to them to the maximum extent permitted by law; 3. BCH does not represent or warrant the accuracy, completeness, merchantability, fitness for purpose or usefulness of this report, or any information contained in this report, for use or consideration by any person or entity. In addition BCH does not accept any liability arising out of reliance by a person or entity on this report, or any information contained in this report, or for any errors or omissions in this report. Any use, reliance or publication by any person or entity of this report or any part of it is at their own risk; and 4. In no event will BCH or BCH s Personnel be liable to any recipient of this report for any damage, loss, cost, expense, injury or other liability that arises out of or in connection with this report including, without limitation, any indirect, special, incidental, punitive or consequential loss, liability or damage of any kind. British Columbia Hydro and Power Authority, All rights reserved ii

3 COPYRIGHT NOTICE Copyright and all other intellectual property rights in, and to, this report are the property of, and are expressly reserved to, BCH. Without the prior written approval of BCH, no part of this report may be reproduced, used or distributed in any manner or form whatsoever. British Columbia Hydro and Power Authority, All rights reserved. iii

4 Executive Summary The XXXX, the Interconnection Customer (IC), proposes to develop the Kokish River Hydroelectric Project to deliver electric energy to BC Hydro (BCH) through the 2008 Clean Power Call. The project is located on North Vancouver Island (NVI), British Columbia. This report identifies the system modifications and additions required to interconnect the proposed Kokish River Hydroelectric Project. The maximum power injection into the BCH system is 44.8 MW. The Point of Interconnection (POI) is the new Kokish Substation (KKS) to be constructed on 1L125 (GLD-KGH), approximately 0.5 km south of the tap to Beaver Cove Substation (BVC, a customer-owned substation). The proposed Commercial Operation Date (COD) is April 1, To interconnect the Kokish River Hydroelectric Project and its facilities to the BCH Transmission System at the POI, this System Impact Study (SIS) has identified the following issues and requirements: Construct a new 230kV switching station (Kokish Substation, KKS) at the POI, operated at 138 kv. Note: A review is currently underway to determine if 1L125 will be converted to 230 kv operation. Islanded operation is not allowed. Power quality protection is required to prevent/mitigate possible islanded operation. Out of step protection is required and should be provided by the Kokish River Hydroelectric Project. Direct transfer tripping schemes will be required to trip the Kokish River generating units during various system conditions. The voltage dip due to transformer inrush when energizing the IC transformer after the plant is out of service appears to exceed the limits stated in the BC Hydro s interconnection guide. Consequently, a transformer inrush control scheme may be required. The IC will be responsible for undertaking the studies required to determine the necessity of an inrush mitigation scheme. The non-binding good faith cost estimate for the Interconnection Network Upgrades required to interconnect the proposed project to the BC Hydro Transmission System is $20.8M based on 230 kv construction. The time to construct the Interconnection Network Upgrades required is estimated to be 18 months. The Interconnection Facilities Study report will provide greater details of the Interconnection Network Upgrade requirements and associated cost estimates and estimated construction timeline for this project. British Columbia Hydro and Power Authority, All rights reserved. iv

5 Table of Contents DISCLAIMER OF WARRANTY, LIMITATION OF LIABILITY... ii COPYRIGHT NOTICE... iii Executive Summary...iv 1.0 Introduction Purpose of Study Terms of Reference Assumptions System Studies Steady State Pre-outage Power Flows Power Flow Based First Contingency Study Transient Stability Study Islanding Fault Analysis Analytical Studies Protection and Control & Telecommunications & Circuit Breakers BCH System Black Start Capability Transmission Line Upgrade Requirements Additional BCH Station Upgrades/Additions Other Issues Cost Estimate and Schedule Conclusion & Discussion...10 Appendix A Transmission System Single-Line-Diagram...12 Appendix B Kokish River Hydroelectric Model and Data...13 Appendix C Typical post disturbance stability swings of the BCH- Kokish River Hydro interconnected systems...16 British Columbia Hydro and Power Authority, All rights reserved. v

6 1.0 Introduction The project reviewed in this SIS report is as described in Table 1 below. Table 1: Summary Project Information Project Name Kokish River Hydroelectric Project Interconnection Customer (IC) XXXX Point of Interconnection (POI) The new Kokish Substation (KKS) in 1L125 (GLD- KGH) approximately 0.5 km south of the tap to Beaver Cove Substation (BVC, a customer-owned substation) IC Proposed COD April 1, 2014 Type of Interconnection Service NRIS ERIS Maximum Power Injection (MW) 44.8 (Summer) 44.8 (Winter) Number of Generator Units 5 Plant Fuel Hydro The XXXX, the Interconnection Customer (IC), proposes to develop the Kokish River Hydroelectric Project to deliver electric energy to BC Hydro (BCH) through the 2008 Clean Power Call (CPC). The generating station will be connected directly to the 138kV transmission line 1L125 (GLD-KGH) at the new Kokish Substation (KKS) via a 0.5 km customer owned 138kV transmission line. The proposed maximum power to be injected into the BC Hydro system is 44.8MW. This project includes 5 generating units. Each unit has a 8.3 MW output based on their 9.2 MVA, 0.9 lagging power factor rating. However, since the maximum injection at the POI for the interconnection study is 44.8 MW, the maximum output of each unit has been raised to 9 MW in the study so as to achieve the 44.8 MW maximum injection at the POI. The proposed Commercial Operation Date (COD) is April 1, Figure 1 shows the connection of the Kokish River Project to the Transmission System. Appendix A shows the single line diagram for the NVI Transmission System. British Columbia Hydro and Power Authority, All rights reserved Page 1 of 21

7 Figure 1 A single line diagram showing connection of the KOKISH RIVER HYDRO PROJECT to the Transmission System. 2.0 Purpose of Study The purpose of this SIS is to assess the impact of the interconnection of the proposed project on the BCH Transmission System. This study will identify constraints and Network Upgrades required for the reliable operation of the Transmission System. 3.0 Terms of Reference The study investigates and addresses the voltage and overloading issues of the transmission networks in the vicinity of Kokish River generating station as a result of the proposed interconnection. Topics studied include equipment thermal loading and rating requirements, system transient stability and voltage stability, transient over-voltages, protection coordination, operation flexibility, telecom requirements and high level remedial action scheme requirements. BCH planning methodology and criteria are used in the studies. Upgrades that are required in common with other IPP projects selected for development in the NVI area under the 2008 Clean Power Call exceed the scope of the studies required for this Kokish River Hydro Project proposal and are not included in this report. The SIS does not investigate operating restrictions and other factors for possible second contingency outages. Subsequent internal network studies will determine the requirements for reinforcements or operating restrictions/instructions for those kinds of events. Impact to the bulk Transmission System is not included in the SIS and will be covered in a separate study. British Columbia Hydro and Power Authority, All rights reserved Page 2 of 21

8 The work necessary to implement the network improvements identified in this SIS report will be described in greater detail in the Interconnection Facilities Study report for this project. 4.0 Assumptions The power flow conditions studied are base cases that include generation, transmission facilities, and load forecast representing the queue position applicable to this project. Applicable seasonal conditions and the appropriate study years for the study horizon are also incorporated. The 2014 heavy winter, heavy summer and light summer load flow base cases were selected for this study. The study is based on the model and data information provided by the IC in the Generator Interconnection Data Form for this project. Reasonable assumptions are made to complete the study and the report, whenever such information is unavailable. Further system assumptions: The NVI 230/138 kv system presently has system constraints under N-1 conditions between JHT and DMR that are resolved via generation shedding/runback remedial action schemes (RAS). For study purposes, it has been assumed that these RAS will be retained and possibly expanded to resolve system constraints that could be exacerbated by the Kokish River and Knob Hill Projects. Generation interconnection projects with higher queue positions considered in the study include Green Island Energy (GIE) and Clint Creek Hydro (CLH). System upgrades required for these projects have also been considered in the study. The EFM industrial load is in operation and has been considered in this SIS although the load status may become uncertain in future. 5.0 System Studies Power flow, short circuit and transient stability studies were carried out to evaluate the impact of the proposed interconnection. Studies were also performed to determine the protection, control and communication requirements, and to evaluate possible over-voltage issues. 5.1 Steady State Pre-outage Power Flows Pre-outage power flows are prepared to assess the impact of the proposed interconnection using three load conditions (2014 winter peak load, 2014 summer light load and 2014 summer peak load). Table 2 provides the power flow study results for the Kokish River Project interconnection and the results are: No voltage violation is observed. Interconnection of the Kokish River plant results in a slight overload on a current transformer (CT) installed on 1L125 at GLD, which will be resolved by upgrading the CT, and a relatively insignificant overload on 1L102 as indicated in British Columbia Hydro and Power Authority, All rights reserved Page 3 of 21

9 the table below. This overload concern on 1L102 is to be addressed in a separate project. Table 2: Pre-outage Power Flow Results Base Case Contingency KKS injection at POI (MW) PHY 132 Volt. (pu) KKS POI Volt. (pu) GLD 132 Volt. (pu) 1L125 loading (%) 2L154 loading (%) 1L120 loading (%) 1L121 loading (%) 1L117 loading (%) 1L119 loading (%) 1L101 loading (%) 1L102 loading (%) 1L106 loading (%) 2014 LS None HS, None HW None Note: LS: light summer load; HW: heavy winter load; HS: heavy summer load 5.2 Power Flow Based First Contingency Study. Power flow based single contingency (N-1) studies have been conducted to check if the post-disturbance performance including bus voltage deviation and facility loading meets the planning criteria under different system load conditions including 2014 heavy winter, heavy summer and light summer conditions. Detailed results are provided in Table 3. The studies have indicated the following: During single contingency outages on 2L154 (DMR-GLD), generation shedding is required at the Kokish River Project to avoid overloading transmission lines 1L120 (GLD-SCA) and 1L121 (SCA-LDR). Direct transfer tripping schemes will be required from DMR and GLD to Kokish River to trip its generating units for a protection trip on 2L154, on the GLD 230/138 kv transformers (2L154 and the GLD transformers share a common protection tripping zone), or when the 2L154 circuit breakers at DMR - or the transformer circuit breakers at GLD are opened. (Note: If the NVI generating stations including Kokish River are operating at their seasonal Expected Load Carrying Capacity (ELCC), no generation shedding or curtailment will required as indicated in the tables below.) With the generation shedding mentioned above implemented, no voltage violation or new transmission equipment overload will be caused by interconnection of the Kokish River Hydro Project. However, overloads on the 138kV lines between JHT and DMR (i.e., 1L119/101/102) presently exist during outages on 2L154 or any of the JHT-DMR transmission lines and they will be exacerbated by the interconnection of the Kokish River Generation shedding or curtailment may be required to resolve these overloads. The JHT-DMR constraints are existing system deficiencies that will be resolved in a different project. The identification of a preferred option to resolve these constraints is outside the scope of this interconnection study and will be dealt with in a separate study. However, depending on the option selected and its completion date, the Kokish River British Columbia Hydro and Power Authority, All rights reserved Page 4 of 21

10 Project may be required to participate in area generation shedding schemes on either a temporary basis (i.e., assuming a system capacity upgrade is implemented) or on a permanent basis (i.e., assuming generation reduction is used to resolve the constraints). Table 3: Power Flow Results after Single Contingency with NVI ELCC Generation 5.3 Transient Stability Study A series of transient stability studies under various system operating conditions including the heavy winter case and the most severe light summer case have been performed. The model of the generating project was based on the IC s data submission plus additional assumptions where the IC s data was incomplete or inappropriate. The models and data values of the key components are shown in Appendix B. The Kokish River Project could become unstable for a total of 11 fault conditions out of 12 scenarios tested. Two of these disturbances faults on the KKS-GLD and the KKS- KGH lines will be resolved by direct transfer tripping schemes from GLD and KGH to the Kokish plant to trip its generators out of service. The other 9 disturbances will be resolved by out-of-step protection to be installed on the generators. Out-of-step relaying at the Kokish plant is the responsibility of the IC. The British Columbia Hydro and Power Authority, All rights reserved Page 5 of 21

11 swing centers for all these disturbances are located within the IC s facilities. BCH can provide apparent impedance versus time plots of stable and unstable swings if requested. The transient stability study results for 2014 summer light load are summarized in Table 4. Case Table 4: Transient Stability Study Results (Pre-outage condition: 2014 LS with 94 MW Injections from Knob Hill Wind Farm and 45 MW Injection from Kokish River) Transmission Circuits Knob Hill Port Hardy line 1L130 (JUL KGH) 1L134 (GLD GRP) 1L120 (GLD SCA) 2L154 (GLD DMR) T5 DMR230 /DMR132 T1 GLD230 /GLD132 1L131 (GLD TSV) 1L121 (SCA LDR) 1L106 (DMR PUN) 1L125 (GLD-KKS) 1L125 (KKS-KGH) 3 Fault Location Fault Clearing Time (Cycles) Close End Far End PHY T1 high side 24 9 JUL 8 32 GRP Not critical 25 GLD 8 9 GLD 8 7 DMR T5 HV side 8 N/A GLD TSV 8 23 SCA 8 9 DMR 8 9 GLD KGH Stability Performance Acceptable Both Knob Hill and Kokish Acceptable Knob Hill only Acceptable Knob Hill only Acceptable Knob Hill only Acceptable Knob Hill only Acceptable Knob Hill only Acceptable Knob Hill only Acceptable Knob Hill only Acceptable Knob Hill only Acceptable Knob Hill only Both Knob Hill and Kokish are islanded (Knob Hill islanded, Kokish Unstable Note 1: Unacceptable stability performance means unstable rotor angle results for conventional generators or violation of transient voltage dip according to BCH planning criteria Based on the dynamic models provided, though this study does not find any significant adverse impact on the system due to this proposed interconnection, the Kokish River Project s ability to recover and remain dynamically stable after various system disturbances is not ideal. The stability performance of the project itself should be improved. Aside from speeding up the fault clearing times on system side, Kokish British Columbia Hydro and Power Authority, All rights reserved Page 6 of 21

12 River s stability performance can be improved by various methods in isolation or in combination. These include using generators with high inertia and faster excitation systems. 5.4 Islanding Islanded operation is normally not an acceptable practice in BCH. Power quality protection will be required at the generating units to detect abnormal system conditions such as under/over voltage and under/over frequency and subsequently trip the units. The settings of these protective relays must conform to existing BCH practice for generating plants so that the generator will not trip for normal ranges of voltages and frequencies. 5.5 Fault Analysis The short circuit analysis for the CPC System Impact Studies are based upon the latest BCH system short circuit model, which includes project equipment and impedances provided by the successful CPC Interconnection Customers. The model included higher queued projects and planned system reinforcements but excluded the Northwest Transmission Line (NTL) and other lower queued projects. At this stage, the report does not provide Thevenin impedances at the POI due to uncertainties associated with the system reinforcement options identified for the CPC projects and the statuses of higher queued projects. However, these Thevenin impedances, including the ultimate fault levels at POI, will be made available to Interconnection Customers upon request. BCH will work with the IC to provide accurate data as required during the project design phase. 5.6 Analytical Studies The Clint Creek IPP generators should not be allowed to isolate with the GLD-KKS section of 1L125 for any type of line fault in this section to avoid potentially severe temporary overvoltage in the isolated system. A direct transfer trip from GLD and/or KKS will be required to trip the 25 kv breaker at the Clint Creek Substation (CLH) during GLD-KKS line faults. Also the opening of the last terminal in the GLD-KKS line will need to be delayed sufficiently to allow the CLH 25 kv breaker to open prior to opening the last line terminal. Studies based on a simplified model for the Knob Hill Wind Farm indicated that temporary overvoltage could occur in the isolated KKS-KGH-PHY-Knob Hill system due to non-protective opening (i.e., local or supervisory opening) of the KKS-KGH line terminal at KKS. Consequently, for non-protective opening of this line terminal, a direct transfer trip will be required from KKS to PHY to disconnect the Knob Hill from the system and the opening of the KKS line terminal must be delayed sufficiently to allow Knob Hill to be disconnected prior to opening the KKS line terminal. The need for this transfer trip should be reviewed when more accurate models are provided for the wind British Columbia Hydro and Power Authority, All rights reserved Page 7 of 21

13 farm. (Note: This DTT may replace a direct transfer trip from GLD to PHY installed in 2012 as part of the Knob Hill system upgrades if required at that time.) The voltage dip due to the transformer inrush when energizing the KKS IPP transformer will exceed the limits allowed in the BC Hydro Interconnection Guide. Consequently, a transformer inrush control scheme may be required, for example via the installation of a 138 kv entrance breaker with independent pole operation and a point-on-wave (POW) controller to control the timing and closing of the individual poles in order to minimize the transformer inrush. It is the responsibility of the IC to undertake the studies necessary to determine the requirements for an inrush investigation scheme and to identify a preferred scheme. 5.7 Protection and Control & Telecommunications & Circuit Breakers Protection, control and telecom requirements for the Kokish River Hydroelectric plant addition have been reviewed. The main items are summarized below: Provide primary and standby protection for the three line terminals at the new KKS substation including primary and standby differential protection at KKS for the IC s line using broadband Class 2 telecommunication facilities (i.e., power line carrier, or PLC) or better due to the short length of the line (the IC will be responsible for similar protection facilities at its end of the line). Direct transfer tripping using Class 2 telecommunication facilities will need to be installed from GLD and KKS to Clint Creek Substation (CLH) to trip the Clint Creek 25kV feeder breaker during GLD-KKS line faults or when one terminal of the line is open. Opening of the GLD and KKS line terminals will need to be delayed sufficiently to ensure the CLH feeder breaker is tripped prior to opening the last line terminal. Direct transfer tripping using Class 2 telecommunication facilities will need to be installed from KKS to JUL to disconnect the Raging River IPP during KKS-KGH line faults or when the KKS line terminal is opened. Opening of the KKS line terminal will need to be delayed sufficiently to ensure the Raging River Project is disconnected prior to opening the KKS line terminal. (Note: This will replace the existing transfer trip from GLD.) Direct transfer tripping using Class 2 telecommunication facilities may be required from KKS to PHY to disconnect the Knob Hill Wind Farm when opening the KKS terminal of the KKS-KGH line via non-protective means (i.e., opening via local or supervisory control) and the opening of the KKS terminal must be delayed sufficiently to ensure the Knob Hill Wind Farm is disconnected from the system prior to opening the KKS line terminal. (Note: This may replace a transfer trip from GLD to PHY if required and installed in 2012 as part of the Knob Hill system upgrades.) Direct transfer tripping using Class 2 telecommunication facilities will be required from GLD and DMR to the Kokish River Project to shed its generators when 2L154 or GLD 230/138 kv transformer protection trips (2L154 and the GLD transformers are in a common protection tripping zone) or when the DMR 230 kv line terminal or GLD 230/138kV transformer bus position is open. British Columbia Hydro and Power Authority, All rights reserved Page 8 of 21

14 Provide a RTU, SCADA and a dial-up link at KKS for remote data acquisition and control purposes. 5.8 BCH System Black Start Capability BCH does not require the proposed project to have black start (self-start) capability. However, if the IC desires their facilities to be energized from the BCH system, the IC is required to apply for an Electricity Supply Agreement. Upon receipt of this application, a plant pick-up study would be required to assess the impact of energizing the IC s facilities. A high level plant pick-up screening was performed as part of the SIS and any issues are identified in Section Transmission Line Upgrade Requirements Loop circuit 1L125 (GLD-KGH) into the new Kokish Substation (KKS) Additional BCH Station Upgrades/Additions A three-breaker ring switching station at the POI to terminate the IC s 138 kv line into the system. The station should be constructed to 230 kv standards to facilitate the potential conversion of 1L125 (constructed to 230 kv standards) to 230 kv operation if and/or when required Other Issues There is no other issue identified at this stage Cost Estimate and Schedule The non-binding good faith cost estimate for the Interconnection Network Upgrades is $20.8M based on 230kV construction. A review is currently underway to determine if 1L125 will be converted to 230 kv operation or remain at 138 kv. If 1L125 is to be converted to 230 kv operation BCH will negotiate security requirements for the Interconnection Network Upgrades with the IC. If the circuit remains at 138 kv, key components of this substation will change to reflect the lower voltage level and the cost estimate will be adjusted. British Columbia Hydro and Power Authority, All rights reserved Page 9 of 21

15 BCH expects to make a decision on 1L125 in time for the Facilities Study and this will not impact the IC s COD. The Interconnection Facilities Study report will provide more detailed information of the cost estimates. The estimated time to construct the Interconnection Network Upgrades is estimated at 18 months after the Standard Generation Interconnection Agreement is signed and BCH capital project is approved. A more detailed construction timeline will be provided in the Interconnection Facilities Study report. BCH system upgrades triggered by CPC projects are being determined and the IC may be required to post security to cover one or more upgrade. Further information will be provided over the next few months. 6.0 Conclusion & Discussion In order to interconnect the Kokish River Project to the BCH Transmission System at the POI, this SIS has identified the following issues and requirements: Construct a new 230kV switching station (Kokish Substation, KKS) at the POI, operated at 138 kv. Note: A review is currently underway to determine if 1L125 will be converted to 230 kv operation. Direct transfer trips will be required from KKS and GLD to the Clint Creek Substation (CLH) to trip the IC s 25 kv feeder breaker during KKS-GLD line faults or when one of the line terminals at KKS or GLD is open to avoid potentially severe temporary over-voltage conditions in the isolated KKS-CLH-GLD system. The opening of the GLD and KKS line breakers will need to be delayed sufficiently to ensure the CLH Project is cleared prior to opening the line terminals. Direct transfer trip schemes (DTT) are required from GLD and KGH to the Kokish River Project to shed its generation to avoid instability during faults on 1L125 between GLD and KKS and between KKS and KGH. These transfer trips are necessary due to the time required to transfer trip the Clint Creek Project from service during these outages in order to avoid severe temporary over-voltage in the isolated GLD-CLH-KKS system (see above). Direct transfer trip facilities will be required from KKS to JUL to trip the Raging River Project out of service at JUL during KKS-KGH line faults or when the KKS line terminal is opened (this will replace the existing GLD-JUL transfer trip scheme). The opening of the KKS line terminal will need to be delayed sufficiently to ensure the Raging River Project is disconnected prior to opening the line terminal. Direct transfer trip facilities may be required from KKS to PHY to disconnect the Knob Hill Wind Farm (in service in October, 2012) from the system when opening the KKS-KGH line at KKS via local or supervisory control (i.e., no fault opening) to avoid temporary overvoltages on the isolated KKS-KGH-PHY-Knob Hill system (this may replace a GLD-KGH transfer trip scheme if required and installed in 2012 as part of the Knob Hill Wind Farm system upgrade requirements). The opening of the KKS line terminal will need to be delayed British Columbia Hydro and Power Authority, All rights reserved Page 10 of 21

16 sufficiently to ensure the Knob Hill Wind Farm is disconnected prior to opening the line terminal. The Kokish River Project will require out-of-step protection to trip its generators out of service for nine fault conditions in order to avoid unit instability. The IC will be responsible for providing the out-of-step protection. Preliminary studies indicate that the voltage dip when energizing the Kokish River Project s transformer will exceed the limits stated in the BC Hydro interconnection guide. Consequently, a transformer inrush control scheme may be required. The IC will be responsible for undertaking the studies required to determine the necessity of an inrush mitigation scheme. No unacceptable voltage condition in the Transmission System was observed in the power flow due under normal and N-1 contingencies. No voltage instability has been observed in the Transmission System. Direct transfer trip schemes will be required from DMR and GLD to the Kokish River Project to trip its generating units out if service for a protection trip on 2L154 or on the GLD 230/138 kv transformers (2L125 and the GLD transformers share a common protection tripping zone) or when the 2L154 circuit breakers at DMR or the transformer circuit breakers at GLD are opened in order to avoid overloads on 1L120 (GLD-SCA) and 1L121 (SCA- LDR). Generation shedding/curtailment may also be required during outages on the JHT-DMR 132 kv circuits (i.e., 1L119, 101, 102 or 106) to avoid overloads on the remaining JHT-DMR transmission lines. This is due to an existing system deficiency that will be resolved by a system upgrade. However, depending on the system upgrade and its completion date, the generation shedding/curtailment required may be temporary (i.e., assuming a system capacity upgrade is implemented) or permanent (i.e., assuming generation reduction is used to resolve the constraints). Assuming the NVI generating stations are operating at their seasonal Expected Load Carrying Capacity (ELCC) including the Kokish River and Knob Hill Wind Farm projects, generation shedding/curtailment may only be required at JHT, LDR and SCA. Islanded operation is not allowed. Power quality protection is required to prevent/mitigate possible islanded operation. British Columbia Hydro and Power Authority, All rights reserved Page 11 of 21

17 Appendix A Transmission System Single-Line-Diagram British Columbia Hydro and Power Authority, All rights reserved Page 12 of 21

18 Appendix B Kokish River Hydroelectric Project Model and Data B.1. Generator Model The contents of this section have been removed due to the proprietary nature of the information. B.2 Excitation Control System Model The contents of this section have been removed due to the proprietary nature of the information. British Columbia Hydro and Power Authority, All rights reserved Page 13 of 21

19 B.3 Power System Stabilizer Model The contents of this section have been removed due to the proprietary nature of the information. British Columbia Hydro and Power Authority, All rights reserved Page 14 of 21

20 B.4 Turbine Governor Model The contents of this section have been removed due to the proprietary nature of the information. British Columbia Hydro and Power Authority, All rights reserved Page 15 of 21

21 Appendix C Typical post disturbance stability swings of the BCH- Kokish River Hydro interconnected systems KKS Rotor Angle, Fault on Knob Hill to Port Hardy 132 KV Line British Columbia Hydro and Power Authority, All rights reserved Page 16 of 21

22 NVI Bus Voltages, Fault on Knob Hill to Port Hardy 132 KV Line British Columbia Hydro and Power Authority, All rights reserved Page 17 of 21

23 KKS Rotor Angle, Fault on GLD-DMR 230 kv Line KKS unstable & tripped by OOS British Columbia Hydro and Power Authority, All rights reserved Page 18 of 21

24 NVI Bus Voltages, Fault on GLD-DMR 230 kv Line KKS unstable & tripped by OOS British Columbia Hydro and Power Authority, All rights reserved Page 19 of 21

25 KKS Rotor Angle, Fault on 1L134 GLD-GRP 132 kv Line KKS unstable & tripped by OOS British Columbia Hydro and Power Authority, All rights reserved Page 20 of 21

26 NVI Bus Voltages, Fault on Fault on 1L134 GLD-GRP 132 kv Line KKS unstable & tripped by OOS British Columbia Hydro and Power Authority, All rights reserved Page 21 of 21