PJM Generator Interconnection R81 Emilie (Fords Mill) MW Impact Study Re-Study

Transcription

1 PJM Generator Interconnection R81 Emilie (Fords Mill) MW Impact Study Re-Study August 2008 DMS #

2 General Queue R81 Emilie (Fords Mills) is a Fairless Energy, LLC request to obtain an additional MWs 1 of Capacity Interconnection Rights ( to MW) at Emilie 230 kv substation for generator uprates (add chillers) planned for each of the existing six generators (configured as two 2 x 1 combined cycle plants). All generator uprates are scheduled to be completed by June Note 1: Queue R81 reduced its request size from 180 MW to MW after the Feasibility Study was completed and as a result of FERC Docket no.el08-36 R81 Settlement Agreement. Direct Connection The R81 is connected as shown on Figure 1 below. No additional Direct Connection facilities are required. Figure 1 2

3 Network Impacts The Queue R81 project was studied as a MW increase in Capacity Interconnection Rights at Emilie 230 kv substation for the existing Fords Mills (Fairless) generation. Project R81 was evaluated for compliance with reliability criteria for summer peak conditions in Potential network impacts were as follows: NETWORK IMPACTS Generator Deliverability (Normal System and Single or N-1 contingencies for the Capacity portion only of the interconnection) 1. The Richmond to Holmesburg Tap 230 kv line reactor at Richmond (from bus 4024 to bus 4269 ckt 1) loads from 97.6% to 107.9% of its emergency rating (374MVA) for the single line contingency outage of Croydon Burlington Mt. Laurel Cox s Corner 230 kv line (PS59). This project contributes approximately 38.5 MW to cause this thermal violation. 2. The Richmond to Holmesburg Tap 230 kv line (from bus 4145 to bus 4024 ckt 1) loads from 97.8% to 108.1% of its emergency rating (374MVA) for the single line contingency outage of Croydon Burlington Mt. Laurel Cox s Corner 230 kv line (PS59). This project contributes approximately 38.5 MW to cause this thermal violation. 3. The Emilie Neshaminy 138kV line (from bus 4667 to bus 4218 ckt 1) loads from 96.8% to 102.2% of its normal rating (550MVA) for non-contingency (normal) condition. This project contributes approximately 23.5 MW to cause this thermal violation. Multiple Facility Contingency (Double Circuit Tower Line contingencies only for the full energy output. Stuck breaker and bus fault contingencies will be performed for the Impact Study) No problems identified. Short Circuit Short circuit analysis is not required since there is no change to the impedance of the generating units or the generator step-up transformers. Stability Analysis (MAAC Stability Criteria Stability analysis was performed by PJM at 2011 light load conditions with Queue R81 at maximum generation output. The range of contingencies evaluated was limited to that necessary to assess expected compliance with MAAC criteria (see attachment #2). No stability problems were identified. 3

4 Note: While the stability analysis has been performed at expected extreme system conditions, there is a potential that evaluation at a different level of generator MW and/or MVAR output at different system load levels and operating conditions would disclose unforeseen stability problems. The regional reliability analysis routinely performed to test all system changes will include one such evaluation. Any problems uncovered in that or other operating or planning studies will need to be resolved. Moreover, when the proposed generating station is designed and plant specific dynamics data for the plant and its controls are available, and if it is different than the data provided for this study, a transient stability analysis at a variety of expected operating conditions using the more accurate data shall be performed to verify impact on the dynamic performance of the system. As more accurate or unit specific dynamics data for the proposed facility, as well as Plant layout become available, it must be forwarded to PJM. Evaluation for Compliance to the PJM Power Factor Requirements Queue R81 meets or exceeds the Power Factor requirement of 0.90 lag to 0.95 lead at the generator s terminals for a total aggregate Max Facility Output of 1095 MW. Also see Attachment #1. Contribution to Previously Identified Overloads (R81 contributes to the following contingency overloads, i.e. Network Impacts, identified for earlier generation or transmission interconnection projects in the PJM Queue) None identified. NETWORK UPGRADE REQUIREMENTS New System Reinforcements (Upgrades required to mitigate reliability criteria violations, i.e. Network Impacts, initially caused by the addition of this project generation) 1. Richmond to Holmesurg Tap 230 kv line reactor at Richmond at 107.9% of its emergency rating. Upgrade requirement (Network Upgrade number n0887): Replace the reactor with a higher rated reactor at an estimated cost of $200,000. Lead time required for replacement is 18 months. 2. Richmond to Holmesburg Tap 230 kv line at 108.1% of its contingency rating. Upgrade requirement (Network Upgrade number n0888):: 4

5 Replace terminal equipment at Richmond at an estimated cost of $2,000,000. Also, perform a Railroad induction study and perform required mitigation to reduce induction impacts at an estimated cost of an additional $2,000,000. Total cost estimate is $4,000,000. Lead time required for this upgrade is 30 months. The new line rating will be 457 MVA normal / 574 MVA emergency. 3. Emilie Neshaminy 138kV line at 102.2% of its normal rating. Upgrade requirement (Network Upgrade number n0889): Replace terminal equipment at Neshaminy and Emilie at an estimated cost of $500,000. Lead time required for replacement is 24 months. Contribution to Previously Identified System Reinforcements (Overloads initially caused by prior Queue positions with additional contribution to overloading by this project. This project may have a % allocation cost responsibility which will be calculated and reported for the Impact Study) None identified. 5

6 ATTACHMENT #1 (Evaluation for Compliance to the PJM Tariff Power Factor Requirement) 6

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9 ATTACHMENT #2 (Stabillity Analysis contingency cases evaluated) 9

10 R81 (Emile 230KV) BREAKER CLEARING TIMES (CYCLES) Station Primary (3ph/slg) Stuck Breaker (total) Zone 2 (total) re-closing 230 kv kv Less than 138 kv ALL FAULTS ARE STABLE CRITERIA FAULTS R81-1a R81-1b R81-2a R81-3a R81-4a R81-4b 230/138 kv Emilie 230 kv on North Bus Emilie 230 kv on Emilie 230 kv north bus, stuck at Emilie (L/O Emilie 230/138 kv Circuit 1) Emilie 230 kv on Emilie Croydon 230 kv Emilie 230 kv on Emilie Eddington Tap 230 kv Emilie 230 kv on South Bus Emilie 230 kv on Emilie 230 kv south bus, stuck at Emilie (L/O Emilie Circuit 2) R81-5a Emilie 230 kv on Emilie 230/138 kv Circuit 2 R81-5b Emilie 230 kv on Emilie 230/138 kv Circuit 2, stuck at Emilie (L/O Emilie 230 kv south bus) R81-6a R81-6b Croydon 230 kv on Croydon Cox s Corner 230 kv Croydon 230 kv on Croydon Cox s Corner 230 kv, stuck at Croydon (L/O Croydon-Emilie 230 KV Circuit 1) R81-7a R81-7b Croydon 230 kv on Croydon Eddington Tap 230 kv Corner Eddington 230 kv on Eddington Eddington Tap 230 kv, stuck at Eddington (L/O Edding-Holmes Circuit 1) R81-8a R81-9a Emilie 138 kv on North Bus Emilie 138 kv on South bus 10

11 ATTACHMENT #3 (Queue R81 Generator and Generator Step-up Transformer Data) 11

12 Unit Capability Data Gross MW Output GSU MW Losses Unit Auxiliary Load MW Station Service Load MW Net MW Capacity Net MW Capacity = (Gross MW Output - GSU MW Losses* Unit Auxiliary Load MW - Station Service Load MW) Queue Letter/Position/Unit ID: R81 Primary Fuel Type: STEAM Maximum Summer (92º F ambient air temp.) Net MW Output**: Maximum Summer (92º F ambient air temp.) Gross MW Output: Minimum Summer (92º F ambient air temp.) Gross MW Output: Maximum Winter (30º F ambient air temp.) Gross MW Output: Minimum Winter (30º F ambient air temp.) Gross MW Output: Gross Reactive Power Capability at Maximum Gross MW Output Please include Reactive Capability Curve (Leading and Lagging): [-80,150] Individual Unit Auxiliary Load at Maximum Summer MW Output (MW/MVAR): N/A Individual Unit Auxiliary Load at Minimum Summer MW Output (MW/MVAR): N/A Individual Unit Auxiliary Load at Maximum Winter MW Output (MW/MVAR): N/A Individual Unit Auxiliary Load at Minimum Winter MW Output (MW/MVAR): N/A Station Service Load (MW/MVAR): N/A * GSU losses are expected to be minimal. ** Your project s declared MW, as first submitted in Attachment N, and later confirmed or modified by the Impact Study Agreement, should be based on either the 92 o F Ambient Air Temperature rating of the unit(s) or, if less, the declared Capacity rating of your project. 12

13 Unit Generator Dynamics Data Queue Letter/Position/Unit ID: R81 MVA Base (upon which all reactances, resistance and inertia are calculated): 319 Nominal Power Factor: 0.85 Terminal Voltage (kv): 18 Unsaturated Reactances (on MVA Base) Direct Axis Synchronous Reactance, X d(i) : Direct Axis Transient Reactance, X d(i): Direct Axis Sub-transient Reactance, X d(i): Quadrature Axis Synchronous Reactance, Xq(i): Quadrature Axis Transient Reactance, X q(i): Quadrature Axis Sub-transient Reactance, X q(i): Stator Leakage Reactance, Xl: Negative Sequence Reactance, X2(i): Zero Sequence Reactance, X0: Saturated Sub-transient Reactance, X d(v) (on MVA Base): Armature Resistance, Ra (on MVA Base): Time Constants (seconds) Direct Axis Transient Open Circuit, T do : 6.31 Direct Axis Sub-transient Open Circuit, T do : Quadrature Axis Transient Open Circuit, T qo : Quadrature Axis Sub-transient Open Circuit, T qo : Inertia, H (kw-sec/kva, on KVA Base): Speed Damping, D: 0.0 Saturation Values at Per-Unit Voltage [S(1.0), S(1.2)]: [0.0572/0.4604] Units utilize a Generator model. 13

14 Unit GSU 1 Data Queue Letter/Position/Unit ID: R81 Generator Step-up Transformer MVA Base: 192 Generator Step-up Transformer Impedance (R+jX, or %, on transformer MVA Base): _j Generator Step-up Transformer Reactance-to-Resistance Ration (X/R): Generator Step-up Transformer Rating (MVA): 192 Generator Step-up Transformer Low-side Voltage (kv): 18 Generator Step-up Transformer High-side Voltage (kv): 242 Generator Step-up Transformer Off-nominal Turns Ratio: 1.0 Generator Step-up Transformer Number of Taps and Step Size: 1/2% each 14

15 Unit Capability Data Gross MW Output GSU MW Losses Unit Auxiliary Load MW Station Service Load MW Net MW Capacity Net MW Capacity = (Gross MW Output - GSU MW Losses* Unit Auxiliary Load MW - Station Service Load MW) Queue Letter/Position/Unit ID: R81 Primary Fuel Type: GAS Maximum Summer (92º F ambient air temp.) Net MW Output**: Maximum Summer (92º F ambient air temp.) Gross MW Output: Minimum Summer (92º F ambient air temp.) Gross MW Output: 73.8 Maximum Winter (30º F ambient air temp.) Gross MW Output: Minimum Winter (30º F ambient air temp.) Gross MW Output: 90 Gross Reactive Power Capability at Maximum Gross MW Output Please include Reactive Capability Curve (Leading and Lagging): [-50,85] Individual Unit Auxiliary Load at Maximum Summer MW Output MW/MVAR):15.1/9.3 Individual Unit Auxiliary Load at Minimum Summer MW Output (MW/MVAR):6.8/4.2 Individual Unit Auxiliary Load at Maximum Winter MW Output (MW/MVAR):7.1/4.4 Individual Unit Auxiliary Load at Minimum Winter MW Output (MW/MVAR):7.2/4.4 Station Service Load (MW/MVAR): 0.15/073 * GSU losses are expected to be minimal. ** Your project s declared MW, as first submitted in Attachment N, and later confirmed or modified by the Impact Study Agreement, should be based on either the 92 o F Ambient Air Temperature rating of the unit(s) or, if less, the declared Capacity rating of your project. 15

16 Unit Generator Dynamics Data Queue Letter/Position/Unit ID: R81 MVA Base (upon which all reactances, resistance and inertia are calculated): 234 Nominal Power Factor: 0.85 Terminal Voltage (kv): 18 Unsaturated Reactances (on MVA Base) Direct Axis Synchronous Reactance, X d(i) : Direct Axis Transient Reactance, X d(i): Direct Axis Sub-transient Reactance, X d(i): Quadrature Axis Synchronous Reactance, Xq(i): Quadrature Axis Transient Reactance, X q(i): Quadrature Axis Sub-transient Reactance, X q(i): Stator Leakage Reactance, Xl: Negative Sequence Reactance, X2(i): Zero Sequence Reactance, X0: Saturated Sub-transient Reactance, X d(v) (on MVA Base): Armature Resistance, Ra (on MVA Base): Time Constants (seconds) Direct Axis Transient Open Circuit, T do : Direct Axis Sub-transient Open Circuit, T do : Quadrature Axis Transient Open Circuit, T qo : Quadrature Axis Sub-transient Open Circuit, T qo : Inertia, H (kw-sec/kva, on KVA Base): Speed Damping, D: 0.0 Saturation Values at Per-Unit Voltage [S(1.0), S(1.2)]: [0.0575/0.4411] Units utilize a Generator model. 16

17 Unit GSU Data Queue Letter/Position/Unit ID: R81 Generator Step-up Transformer MVA Base: 114 Generator Step-up Transformer Impedance (R+jX, or %, on transformer MVA Base): _j Generator Step-up Transformer Reactance-to-Resistance Ration (X/R): 48 Generator Step-up Transformer Rating (MVA): 114 Generator Step-up Transformer Low-side Voltage (kv): 18 Generator Step-up Transformer High-side Voltage (kv): 242 Generator Step-up Transformer Off-nominal Turns Ratio: 1.0 Generator Step-up Transformer Number of Taps and Step Size: 1/2% each 17

18 PJM Generator Interconnection R81 Emilie (Fords Mill) MW Impact Study April 2008 DMS #

19 General Queue R81 Emilie (Fords Mills) is a Fairless Energy, LLC request to obtain an additional MWs 1 of Capacity Interconnection Rights ( to MW) at Emilie 230 kv substation for generator uprates (add chillers) planned for each of the existing six generators (configured as two 2 x 1 combined cycle plants). All generator uprates are scheduled to be completed by June Note 1: Queue R81 reduced its request size from 180 MW to MW after the Feasibility Study was completed and as a result of FERC Docket no.el08-36 R81 Settlement Agreement. Direct Connection The R81 is connected as shown on Figure 1 below. No additional Direct Connection facilities are required. 2

20 Network Impacts The Queue R81 project was studied as a MW increase in Capacity Interconnection Rights at Emilie 230 kv substation for the existing Fords Mills (Fairless) generation. Project R81 was evaluated for compliance with reliability criteria for summer peak conditions in Potential network impacts were as follows: NETWORK IMPACTS Generator Deliverability (Single or N-1 contingencies for the Capacity portion only of the interconnection) 1. The Richmond to Holmesurg Tap 230 kv line reactor at Richmond (from bus 4024 to bus 4269 ckt 1) loads from 98.2% to 109.0% of its emergency rating (374MVA) for the single line contingency outage of Croydon Burlington Mt. Laurel Cox s Corner 230 kv line (PS59). This project contributes approximately 40.7 MW to cause this thermal violation. 2. The Richmond to Holmesburg Tap 230 kv line (from bus 4145 to bus 4024 ckt 1) loads from 98.4% to 109.2% of its emergency rating (374MVA) for the single line contingency outage of Croydon Burlington Mt. Laurel Cox s Corner 230 kv line (PS59). This project contributes approximately 40.7MW to cause this thermal violation. 3. The Emilie Neshaminy 138kV line (from bus 4667 to bus 4218 ckt 1) loads from 97.5% to 102.1% of its normal rating (550MVA) for non-contingency (normal) condition. This project contributes approximately 25.0 MW to cause this thermal violation. Multiple Facility Contingency (Double Circuit Tower Line contingencies only for the full energy output. Stuck breaker and bus fault contingencies will be performed for the Impact Study) No problems identified. Short Circuit Short circuit analysis is not required since there is no change to the impedance of the generating units or the generator step-up transformers.. Stability Analysis Will be performed for the R81Facilities Study. Evaluation for Compliance to the PJM Power Factor Requirements Queue R81 meets or exceeds the Power Factor requirement of 0.90 lag to 0.95 lead at the generator s terminals for a total aggregate Max Facility Output of 1095 MW. Also see Attachment #1. 3

21 Contribution to Previously Identified Overloads (R81 contributes to the following contingency overloads, i.e. Network Impacts, identified for earlier generation or transmission interconnection projects in the PJM Queue) General Notes pertaining to cost allocation rules for overloads: (also see the PJM Tariff and Manual 14) The first project to cause an overload has cost responsibility. If this Queue is not the first project to cause the overload, a threshold of; a) 1% increase in overloaded facility loading must be caused by the this Queue generation, and b) This Queue s MW contribution of 5.0 MW or greater are both required for cost allocation responsibility. And If not the first project to cause the overload but both conditions above are met, then a threshold of Either of the following are also required for cost allocation responsibility; a) a 5% generator DFAX* (5 MW for a generation request size of 100 MW), or (b) This Queue s generation must cause an increase of 5% to the overloaded facility loading * DFAX may not be equal to this Queue s contribution divided by generator MW size in some cases. 4. This project contributes approximately 32.5 MW to the contingency loading of the Peach Bottom to Conastone 500kV line (from bus 13 to bus 4 ckt 1) previously loaded above its emergency rating (2598 MVA) for the single line contingency outage of the Hunterstown Conastone 500 kv line. 5. This project contributes 9.5 MW to the contingency loading of the Nottingham Graceton 230 kv line # reactor, at Nottingham, previously overloaded above its emergency rating (627MVA) by earlier queued project R39 for the outage of the Conastone Peach Bottom 500 kv line with a stuck breaker at Conastone. 6. This project contributes 9.5MW to the contingency loading of the Nottingham Peach Bottom Tap section of the Notingham Graceton 230kV line # previously overloaded above its emergency rating (627MVA) by earlier queued projects for the outage of Conastone Peach Bottom 500 kv line with a stuck breaker at Conastone. 7. This project contributes 9.5MW to the contingency loading of the Peach Bottom Tap to Graceton section of the Notingham Graceton 230kV line # previously overloaded above its emergency rating (627MVA) by earlier queued projects for the outage of Conastone Peach Bottom 500 kv line with a stuck breaker at Conastone. 4

22 NETWORK UPGRADE REQUIREMENTS New System Reinforcements (Upgrades required to mitigate reliability criteria violations, i.e. Network Impacts, initially caused by the addition of this project generation) 1. Richmond to Holmesurg Tap 230 kv line reactor at Richmond at 109.0% of its emergency rating. Upgrade requirement (Network Upgrade number n0887): Replace the reactor with a higher rated reactor at an estimated cost of $200,000. Lead time required for replacement is 18 months. 2. Richmond to Holmesburg Tap 230 kv line at 109.2% of its contingency rating. Upgrade requirement (Network Upgrade number n0888):: Replace terminal equipment at Richmond at an estimated cost of $2,000,000. Also, perform a Railroad induction study and perform required mitigation to reduce induction impacts at an estimated cost of an additional $2,000,000. Total cost estimate is $4,000,000. Lead time required for this upgrade is 30 months. The new line rating will be 457 MVA normal / 574 MVA emergency. 3. Emilie Neshaminy 138kV line at 102.1% of its normal rating. Upgrade requirement (Network Upgrade number n0889): Replace terminal equipment at Neshaminy and Emilie at an estimated cost of $500,000. Lead time required for replacement is 24 months. Contribution to Previously Identified System Reinforcements (Overloads initially caused by prior Queue positions with additional contribution to overloading by this project. This project may have a % allocation cost responsibility which will be calculated and reported for the Impact Study) 4. Peach Bottom to Conastone 500 kv line upgrade. BG&E portion of the Peach Bottom to Conastone #5012 line (MD/PA state line to Conastone): The BG&E portion to Peach Bottom to Conastone 500 kv line is rated at 3734 MVA. The contingency overload is approximately 3455 MVA, therefore the BG&E portion of the line itself does not require upgrade. However, three 500kV breakers at Conastone will exceed their emergency rating of 3000 amps. 5

23 BG&E Upgrade requirement (Network Upgrade number n0890): Rebuild or upgrade the three Conastone circuit breakers at an estimated cost of $1,500,000 ($500,000 per breaker) with a required lead time of 6-12 months. Queue R81 cost allocation is 2.6% or an estimated cost of $38,450. The cost allocation breakdown for the above upgrade is as follows: Queue MW Percentage Cost $K (total cost = 1500K) Q % R % R % R % R % R % R % R % R % R % R % R % PECO Energy portion of the Peach Bottom to Conastone #5012 line (MD/PA state line to Peach Bottom): #1 PECO Upgrade Requirement (Network Upgrade number n0891):: Replace metering equipment at the Peach Bottom Terminal at an estimated total cost of $100,000. Queue R81 s cost allocation is 2.6% or an estimated cost of $2,560. Lead time required for metering equipment replacement is 24 months. The estimated new rating (PECO) is 2707 MVA normal / 3112 MVA emergency. Cost allocation breakdown for the above upgrade is as follows: Queue MW Percentage Cost $K (total cost = 100K) Q % R % 8.81 R % 4.53 R % 9.64 R % 4.57 R % R % 4.94 R % 5.95 R %

24 R % 2.72 R % 7.15 R % 2.56 #2 PECO Upgrade Requirement (Network Upgrade number n0892):: Replace two circuit breakers at Peach Bottom 500 kv substation at an estimated total cost of $1,300,000 ($650,000 per breaker). Queue R81 cost allocation is 11.8% or $153,470. Estimated lead time for the breaker replacements is 30 months. The new estimated rating is 3365 MVA normal / 3463 MVA emergency. Cost allocation breakdown for the above upgrade is as follows: Queue MW Percentage Cost $K (total cost = 1300K) R % R % R % R % R % Nottingham Graceton 230 kv line # reactor overload. Upgrade Requirement (Network Upgrade n0896) Relocate the Peach Bottom Conastone 500 kv line (#5012) into a new two breaker bay at Conastone 500 kv substation. The total estimated cost is $7,000,000. Queue R81 s allocated cost is % or an estimated cost of $1,528,700. Estimated lead time for the reactor replacement is months. This upgrade also satisfies upgrade requirements for 6 and 7. Cost allocation breakdown for the above upgrade is as follows: Cost ($M Queue MW Contribution Percentage )total cost = $7M R % R % R % Nottingham Peach Bottom Tap section of the Notingham Graceton 230kV line # overload. See upgrade 5 (Network Upgrade number n0896) on the previous page, this upgrade also satisfies upgrade requirement number 6. 7

25 7. Peach Bottom Tap to Graceton section of the Notingham Graceton 230kV line # overload. See upgrade 5 (Network Upgrade number n0896) on the previous page, this upgrade also satisfies upgrade requirement number 7. 8

26 ATTACHMENT #1 (Evaluation for Compliance to the PJM Tariff Power Factor Requirement) 9

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