Project #94. Generation Interconnection System Impact Study Report Revision

Transcription

1 Project #94 Generation Interconnection System Impact Study Report Revision October 2, 2009 Electric Transmission Planning

2 Table of Contents Table of Contents...2 Executive Summary...3 Energy Resource Interconnection Service Results...3 Network Resource Interconnection Service Results...4 Definitions...6 Energy Resource Interconnection Service...6 Network Resource...6 Network Resource Interconnection Service...6 Generator and Interconnection Data...8 Study Parameters...9 Senior Queue Generator Assumptions...9 Steady State Power Flow Analysis...10 Method...10 Results...10 Mitigation...10 Transient Stability Analysis...11 Method...11 Results...11 PV Analysis...13 Method...13 Results...13 Mitigation...13 Fault Duty Analysis...14 Method...14 Results...14 Mitigation...14 Conclusions...15 N-0 Mitigation...15 N-1 Mitigation...15 N-2 Mitigation...15 Next Steps...15 Attachments

3 Executive Summary NorthWestern Energy ( NWE ) has completed the System Impact Study ( SIS ) for Project #94 ( Generation Project ) near Great Falls, MT. NWE studied your project both as a Network Resource Interconnection Service ( NRIS ) and an Energy Resource Interconnection Service ( ERIS ). The SIS is an in-depth analysis that examines the response of the transmission system to a variety of system operating conditions. NWE is responsible for maintaining acceptable system reliability, and must be certain that system reliability is maintained with the addition of the Generation Project. NWE uses tolerance levels outlined by FERC, NERC, and/or WECC. The SIS uses the following types of analyses: Steady-State Power Flow Post Transient Steady-State Power Flow Transient Stability Fault Duty Reactive Margin The results of the SIS confirm that the addition of 128 MW interconnected to NWE s Great Falls 230 kv Switchyard is feasible only with system improvements. The findings included in this study do not assure the Interconnection Customer that the planned Generation Project will be allowed to operate at full capacity under all operating conditions. NWE cannot guarantee that future analysis will not identify additional problems. Energy Resource Interconnection Service Results ERIS allows the Interconnection Customer to connect the Small Generating Facility to the Transmission System and be eligible to deliver the Small Generating Facility s output using the existing firm or nonfirm capacity of the Transmission System on an as available basis. ERIS does not in and of itself convey any right to deliver electricity to any specific customer or Point of Delivery. The ERIS study is designed to answer two questions: I. What is the maximum allowed output to interconnect without additional network upgrades? Answer: The maximum allowed output to interconnect and move power without additional network upgrades is 0 MW. The Generation Project s SIS high level, non-binding cost estimates for ERIS are the same as the costs presented in Table I of the Revised SIS for Project #53 that was provided to Project #94 on 05/13/2008, with the exception of the following additions: an additional $80k in substation upgrades for metering units; an additional $25k in EMS costs. These additional costs bring the total ERIS high level, non-binding cost estimate to $2.46 million (which includes the ERIS cost of $2.35 million for Project #53). II. What are the necessary upgrades to allow for full output of the Generation Project? Answer: The necessary upgrades are described in the NRIS Results section of this report. 3

4 Network Resource Interconnection Service Results NRIS allows the Interconnection Customer to be designated as a Network Resource, up to the Large Generating Facility s full output, on the same basis as existing Network Resources interconnected to the Transmission Provider s Transmission System. NRIS does not in and of itself convey reservation of transmission service. Any network customer under the Tariff can utilize its network service under the Tariff to obtain delivery of electricity from the Generation Project in the same manner as it accesses Network Resources. The NRIS SIS Study found that the Generation Project contributes to the flows on various line segments that have been required to be built, upgraded, or reconductored by senior queued projects. Senior queued project mitigation that the Generation Project s SIS determined are affected includes: a new 230 kv line from Great Falls to Three Rivers; reconductoring the 100 kv lines from Harlowton to Judith Gap Tap to Judith Gap; building a new 100 kv line from Harlowton to Broadview; upgrading the 230/100 kv transformer at Judith Gap. The Generation Project also triggers the need for: reconductoring the 100 kv line from East Helena to Continental Lime Tap; reconductoring the 100 kv line from Continental Lime Tap to Townsend; reconductoring the 100 kv line from Broadwater Tap to Crow Creek; reconductoring the 100 kv line from Crow Creek to Eustis; adding a 36 MVAr Dynamic VAR device at Ovando 230 kv Switchyard. A non-binding cost estimate to interconnect your project is summarized in Table I. Table I. High Level, Non-Binding Cost Estimates Mitigation and Substation $M Cost New 230 kv Great Falls to Three Rivers 1 $ kv Harlowton to Judith Gap Tap to Judith Gap Reconductor 2 $ kv Martinsdale to Two Dot to Harlowtwon 3 $ New 100 kv Harlowton to Broadview (Ckt 2) 100 kv 4 $ Upgrade the Judith Gap 230/100 kv Transformer 5 $ kv Continental Lime Tap to Townsend Reconductor 6 $ kv Broadwater Tap to Crow Creek Reconductor 7 $ kv Crow Creek to Eustis 8 $ kv Eustis to Trident 9 $ MVAr Dynamic VAR device at Ovando 230 kv Switchyard 10 $ Substation N/A Relay N/A Communications N/A Metering N/A EMS N/A Total $76.6 4

5 Table Notes: 1. The cost allocation for mitigation are based on NWE s Cost Allocation and Refund Methodology, new line is $106,765,086. The Generation Project s share of the new 230 kv line would be $41,277,208. Projects junior to the Generation Project in the queue that affect the MW flow on the line would have to contribute to the costs of the new line. 2. The cost allocation for mitigation are based on NWE s Cost Allocation and Refund Methodology, reconductoring is $5,151,000. The Generation Project s share of the reconductoring would be $1,872,421. Projects junior to the Generation Project in the queue that affect the MW flow on the lines would have to contribute to the costs of reconductoring the lines. 3. The cost allocation for mitigation are based on NWE s Cost Allocation and Refund Methodology, reconductoring is $7,211,400. The Generation Project s share of the reconductoring would be $1,547,692. Projects junior to the Generation Project in the queue that affect the MW flow on the lines would have to contribute to the costs of reconductoring the lines. 4. The cost allocation for mitigation are based on NWE s Cost Allocation and Refund Methodology, new line is $21,925,000. The Generation Project s share of the new line would be $20,097,917. Projects junior to the Generation Project in the queue that affect the MW flow on the new line would have to contribute to the costs of building the new line. 5. The cost allocation for mitigation are based on NWE s Cost Allocation and Refund Methodology, transformer upgrade is $1,700,000. The Generation Project s share of the upgrade would be $1,590,000. Projects junior to the Generation Project in the queue that affect the MW flow on the transformer would have to contribute to the costs of the transformer. 6. The cost allocation for mitigation are based on NWE s Cost Allocation and Refund Methodology, reconductoring is $303,000. Projects junior to the Generation Project in the queue that affect the MW flow on the line would have to contribute to the costs of the reconductoring. 7. The cost allocation for mitigation are based on NWE s Cost Allocation and Refund Methodology, reconductoring is $602,970. Projects junior to the Generation Project in the queue that affect the MW flow on the line would have to contribute to the costs of the reconductoring. 8. The cost allocation for mitigation are based on NWE s Cost Allocation and Refund Methodology, reconductoring is $2,908,800. Projects junior to the Generation Project in the queue that affect the MW flow on the line would have to contribute to the costs of the reconductoring. 9. The cost allocation for mitigation are based on NWE s Cost Allocation and Refund Methodology, reconductoring is $1,030,200. Projects junior to the Generation Project in the queue that affect the MW flow on the line would have to contribute to the costs of the reconductoring. 10. The cost allocation for mitigation are based on NWE s Cost Allocation and Refund Methodology, Dynamic VAR device is $5,400,000. 5

6 Definitions Energy Resource Interconnection Service Energy Resource Interconnection Service shall mean an interconnection service that allows the interconnection customer to connect its generating facility to the transmission provider's transmission system to be eligible to deliver the facility's electric output using the existing firm or nonfirm capacity of the transmission provider's transmission system on an as available basis. Energy Resource Interconnection Service in and of itself does not convey transmission service. Under Energy Resource Interconnection Service ( ERIS ), the Generation Project will be able to inject power from the facility into and deliver power across NWE s transmission system on an as available basis up to the amount of MW identified in the applicable stability and steady state studies to the extent the upgrades initially required to qualify for ERIS have been constructed. No transmission delivery service from the Generation Project is assured, but the Generation Project may obtain point-to-point transmission service, network integration transmission service, or be used for secondary network transmission service, pursuant to NWE s Tariff, up to the maximum output identified in the stability and steady state studies. In those instances, in order for the Generation Project to obtain the right to deliver or inject energy beyond the facility point of interconnection or to improve its ability to do so, transmission delivery service must be obtained pursuant to the provisions of NWE's Tariff. The Generation Project's ability to inject its output beyond the point of interconnection, therefore, will depend on the existing capacity of NWE's transmission system at such time as a Transmission Service Request ( TSR ) is made that would accommodate such delivery. The provision of firm point-to-point transmission service or network integration transmission service may require the construction of additional network upgrades. Network Resource Network Resource shall mean any designated generating resource owned, purchased, or leased by a network customer under the network integration transmission service tariff. Network Resources do not include any resource, or any portion thereof, that is committed for sale to third parties or otherwise cannot be called upon to meet the network customer's network load on a non-interruptible basis. Network Resource Interconnection Service NRIS shall mean an Interconnection Service that allows the Interconnection Customer to integrate its Large Generating Facility with the Transmission Provider s Transmission System (1) in a manner comparable to that in which the Transmission Provider integrates its generating facilities to serve native load customers; or (2) in an RTO or ISO with market based congestion management, in the same manner as all other Network Resources. Network Resource Interconnection Service in and of itself does not convey transmission service. NRIS allows the Generation Project to be designated by any network customer under the Tariff on NWE's Transmission System as a Network Resource, up to the Generation Project's full output, on the same basis as existing Network Resources interconnected to NWE's transmission system, and to be studied as a Network Resource on the assumption that such a designation will occur. Although NRIS does not convey a reservation of Transmission Service, any network customer under the Tariff can utilize its network service under the Tariff to obtain delivery of energy from the Generation Project in the same manner as it accesses Network Resources. A facility receiving NRIS may also be used to provide ancillary services after technical studies and/or periodic analyses are performed with respect to the Generation Project's 6

7 ability to provide any applicable ancillary services, provided that such studies and analyses have been or would be required in connection with the provision of such ancillary services by any existing Network Resource. However, if the Generation Project s facility has not been designated as a Network Resource by any load, it cannot be required to provide ancillary services except to the extent such requirements extend to all generating facilities that are similarly situated. The provision of network integration transmission service or firm point-to-point transmission service may require additional studies and the construction of additional upgrades. Because such studies and upgrades would be associated with a request for delivery service under the Tariff, cost responsibility for the studies and upgrades would be in accordance with the Federal Energy Regulatory Commission s ( FERC ) policy for pricing transmission delivery services. NRIS does not necessarily provide the Generation Project with the capability to physically deliver the output of its facility to any particular load on NWE's transmission system without incurring congestion costs. In the event of transmission constraints on NWE's transmission system, the Generation Project s facility shall be subject to the applicable congestion management procedures in NWE's transmission system in the same manner as Network Resources. NWE will follow regional and sub regional congestion management procedures as they are developed. Once the Generation Project satisfies the requirements for obtaining NRIS, any future transmission service request for delivery from the Generation Project s facility within NWE's transmission system of any amount of capacity and/or energy, up to the amount initially studied, will not require that any additional studies be performed or that any further upgrades associated with the Generation Project s facility be undertaken, regardless of whether or not the Generation Project s facility is ever designated by a network customer as a Network Resource and regardless of changes in ownership of the facility. However, the reduction or elimination of congestion or redispatch costs may require additional studies and the construction of additional upgrades. This philosophy is described in the FERC Order Nos. 2003, 2003-A, 2003-B and 2003-C, which govern interconnection of large generators to the transmission grid. The pro forma Large Generator Interconnection Procedures ( LGIP ) and Large Generator Interconnection Agreement ( LGIA ) required in those orders describe the philosophy that NWE used in performing the study work for the Generation Project. To the extent the Generation Project enters into an arrangement for long-term transmission service for deliveries from the facility outside of NWE's transmission system, such request may require additional studies and upgrades in order for NWE to grant the request. NorthWestern Energy is not required to provide certain ancillary services to transmission customers serving load outside of NorthWestern s control area. 7

8 Generator and Interconnection Data The proposed generator and interconnection data used in the studies was based on the information received from the Interconnection Customer. From the initial application, NWE identified the following project information. Project Name Project #94 Size (Rated) 128 MW total Location 230 kv Great Falls Switchyard Special Resources/Technology 2ea Trent 60 WLE Combustion Turbine Generators Proposed Commercial Operation Date June 10, 2010 Facilities Connection to the 230 kv Great Falls Switchyard using Project #53 s Point-of- Interconnection Assumptions o MW Output = 128 MW o Scheduled Voltage (pu) = 1.0 at the Point of Interconnection o The generator is assumed to have operational characteristics either through internal or external capabilities to operate throughout a power factor range of.95 leading to.95 lagging at the Point of Interconnection 8

9 Study Parameters In analyzing the Generation Project, NWE utilized PSS/E software to conduct the System Impact Study with the proposed Generation Project. These studies connected the Generation Project to NWE s Transmission System in a computer model to simulate the interaction of the Generation Project with other resources and loads. Two WECC base cases adjusted to include the NWE Transmission System detail representing 2010 light autumn and 2012 heavy summer loads were used for this study. Senior Queue Generator Assumptions Project Number Size (MW) Point of Interconnection Wilsall-Shorey Road 230 kv Line Great Falls 230 kv Switchyard Martinsdale Substation ERIS - Martinsdale Substation Billings Steam Plant Switchyard South Cut Bank - Conrad Auto 115 kv line Loweth - Two Dot 100 kv line kv line at Chester Rainbow Switchyard ERIS - Great Falls 230 kv Switchyard Wilsall-Shorey Road 230 kv Line Bradley Creek Substation Bradley Creek - Three Forks S. 100 kv line kv line between Phillipsburg and Anaconda ERIS - 69 kv line between Fairfield and Bole kv line near Sumatra Substation - (70-72 WITHDRAWN) kv line between Cut Bank and Shelby ASMI 161 kv Substation kv line near Bradley Creek Substation kv line near Bradley Creek Substation Millcreek 230 kv Switchyard ERIS kv line between South Cut Bank and Conrad North River Road Near Rainbow Switchyard 82 Efficiency Improv. Near Rainbow Switchyard ERIS - Cut Bank 115 kv Substation between Cut Bank & Shelby Near Livingston City Substation kv line between Loweth and Two Dot at Groveland 9

10 Steady State Power Flow Analysis The steady-state power flow analysis examines steady state, system normal, operating conditions with no lines out of service (i.e., N-0 Conditions) and with various lines out of service (i.e., N-1 and N-2 conditions). A power flow simulation is completed before and after the addition of the Generation Project to identify any unacceptable thermal overloads and voltage excursions the project may cause. Method NWE simulated an extensive set of 500 kv and non-500 kv N-1 and N-2 outages. Power flow contingencies were simulated for both operating conditions (2010 light autumn and 2012 heavy summer). The local area contingencies were the primary focus, but major transmission line outages around the NWE system were also studied. The list of contingencies is summarized in Attachment A. Results N-0: The addition of the Generation Project to NWE s Transmission System under N-0 conditions (all lines in-service) causes no adverse effects. N-1: The addition of the Generation Project to NWE s Transmission System under N-1 conditions (one line out-of-service) causes no adverse effects. N-2: The addition of the Generation Project to NWE s Transmission System under N-2 conditions (two elements out-of-service) causes thermal overloading on transmission lines in south-of-helena area (see Attachment A for results). Mitigation Assuming all senior queue projects connect to the system, the Generation Project must facilitate mitigation in order to operate at full capacity. The Generation Project contributes to the flows on various line segments that have been required to be built, upgraded, or reconductored by senior queued projects. Senior queued project mitigation that the Generation Project s SIS determined are affected will require the Generation Project be responsible for sharing the costs with senior queued projects. The following list summarizes the required mitigation that are shared costs with senior queued projects: a new 230 kv line from Great Falls to Three Rivers; reconductoring the 100 kv lines from Harlowton to Judith Gap Tap to Judith Gap; building a new 100 kv line from Harlowton to Broadview; upgrading the 230/100 kv transformer at Judith Gap; The following list summarizes the required mitigation triggered by this project: reconductoring the 100 kv line from East Helena to Continental Lime Tap; reconductoring the 100 kv line from Continental Lime Tap to Townsend; reconductoring the 100 kv line from Broadwater Tap to Crow Creek; reconductoring the 100 kv line from Crow Creek to Eustis; adding a 36 MVAr Dynamic VAR device at Ovando 230 kv Switchyard. 10

11 Transient Stability Analysis When a line fault occurs, the protective relaying must respond by opening circuit breakers to remove the affected transmission line from service. This can result in a system disturbance. The credible worst case fault events must be simulated to determine if the transmission system will recover to acceptable steady state operating conditions. Events that were studied include single-phase and three-phase faults causing either single or multiple line outages. The dynamic simulations performed for this project include an assortment of events that are intended to provide a thorough test of the feasibility and impact of the proposed generation facility. The results from the Transient Stability Analysis are designed to reveal: Whether or not regional electric transmission systems remain stable and satisfactory with each event; Whether or not WECC criteria are met for each outage condition; and Identify where problems are located on the Transmission System. The Colstrip generation employs generator tripping for critical outage events on the 500 kv electric transmission system. The generator-tripping scheme is a computer-based relay called the Acceleration Trend Relay (ATR). This device monitors the generator speed and acceleration (real time), and digitally analyzes these quantities to determine when an unstable event is in progress. If an unstable event is in progress, the device determines the amount of generator tripping that is required to protect the electric transmission system from instability and unacceptable low-voltage swings caused by the event. The ATR then proceeds to trip the necessary number of generating units at Colstrip before the event causes instability problems to occur. Method NWE simulated an extensive set of 500 kv and non-500 kv faults. The term fault refers to a shortcircuit between either a single-phase conductor to ground or all three phases. Various local area faults were also simulated to understand the generator performance during those faults. The breakers at this project facility were assumed to clear a fault within 4 cycles. The results are subject to change if the model for the project was changed. The entire set of faults was simulated on the 2010 Light Autumn case. All the senior queue projects and their mitigation were implemented during the simulations. The entire list of simulated events and its results is included in Attachment B. Results Detailed analysis of the simulation results has shown that all simulations meet the WECC and NWE performance criteria with additional system mitigation for transient stability. The Generation Project will have to install a 36 MVAr DVAR (Dynamic VAR) device at Ovando 230 kv switchyard in order to meet WECC and NWE performance for an N-2 outage (simultaneous outage of Garrison-Taft 500 kv lines). Attachment B shows the Generation Project s performance with and without the DVAR device under the N-2 outage. The high level non binding cost estimate of the DVAR device is shown in Table II. 11

12 Table II: Mitigation requirement due to Transient Stability Mitigation Cost($M) 36 MVAr Dynamic VAR device at Ovando 230 kv Switchyard $5.4 Total $5.4 This study implemented all the mitigations required by the senior queue interconnection projects and the mitigations required by this Generation Project due to powerflow studies. If either one of the senior queue project is withdrawn this study might have to be re-visited to understand the effect of this project on the system due to the withdrawal. List of the senior queue projects could be found on our OASIS website. The results of the simulations are listed in Attachment B. 12

13 PV Analysis The SIS examined the reactive margin at critical buses on NWE s Transmission System. In addition, the PV and identifies potential voltage collapse issues under maximum operating conditions. This analysis includes the addition of the Generation Project. Voltage security margins were evaluated using PV analysis. For this type of study, the security margin (distance to the voltage collapse) is defined by the amount of additional power transfer that can occur before voltage collapse is reached on a predefined bus. Voltage collapse occurs at the knee point of the PV curve where the voltage drops rapidly with an increase in the transfer power flow. Operation at or near the stability limit is impractical and a satisfactory operation condition must be ensured to prevent voltage collapse. Method The output of the Generation Project was increased to 5% of the nameplate rating. This increased power output was off-set by reducing the generation output at Colstrip. Results The Generation Project is modeled with all co-existing generation projects and their required mitigation. Results indicate with the Generation Project s output increased to 5% above the nameplate rating there is sufficient reactive power compensation to cope with the steady-state requirements for all scenarios and contingencies analyzed. Mitigation No mitigation is required. 13

14 Fault Duty Analysis When a fault occurs on a power line, protective relaying equipment detects the fault current flowing and signals the associated circuit breakers to open. When the circuit breakers open, they must be capable of interrupting the fault current. If the magnitude of the fault current exceeds the interrupt rating of the circuit breakers, the fault may not be cleared, and damage to system equipment and voltage collapse may result. Method To perform a fault duty analysis, busses at or near the point of interconnection of this project are faulted in a PSS/E model to determine the magnitude of fault current anticipated with the Generation Project in service. The results of this analysis determine whether standard circuit breaker fault duty ratings would be exceeded with the addition of the Generation Project. The events that were analyzed are listed below. 1) A three-phase fault at the Generation Project 230 kv bus. 2) A single-phase fault at the Generation Project 230 kv bus. Results The breakers in the area have sufficient interrupting capability to withstand the maximum short-circuit current with the addition of the Generation Project. A breaker interrupt rating of 40,000 amps was assumed. The highest fault current observed was less than 6,000 amps at the Generation Project 230 kv bus. The results for the analysis are included in Attachment C. Mitigation No mitigation required. 14

15 Conclusions The results of this analysis confirm that the addition of 128 MW of generation interconnected to the Great Falls 230 kv Switchyard is only feasible with system improvements. N-0 Mitigation No mitigation is required. N-1 Mitigation No mitigation is required. N-2 Mitigation The Generation Project triggers the need for: reconductoring the 100 kv line from East Helena to Continental Lime Tap; reconductoring the 100 kv line from Continental Lime Tap to Townsend; reconductoring the 100 kv line from Broadwater Tap to Crow Creek; reconductoring the 100 kv line from Crow Creek to Eustis; The Generation Project also triggers the need for the addition of a 36 MVAr Dynamic VAR device at Ovando 230 kv Switchyard for transient stability issues. The total cost for NRIS is $76.6 million including all steady state and transient study findings. The total cost for ERIS is $2.46 million (which includes the ERIS cost of $2.35 million for Project #53). Next Steps NWE will be scheduling a meeting to discuss the findings of the SIS with the Interconnection Customer. If, after the meeting, the Interconnection Customer wishes to continue with the project, the Generation Project must designate either ERIS or NRIS. A Facility Study specific to the project will then be carried out to determine the final details of the interconnection. This study does not constitute a request for transmission service. The study examined the physics of the electrical system and does not imply that you will receive any transmission required to deliver the generation output to load. You must follow the procedures described in the transmission tariff available on ( to request and/or receive transmission service. Attachments Attachment A Power Flow Analysis Results Attachment B Transient Stability Analysis Results Attachment C Fault Duty Analysis Results 15