PJM Generator Interconnection Request Queue #V4-019 Bergen #2 230kV Impact Study 611079 September 2010 1
V4-019 Bergen #2 230kV Impact Study Report General PSEG Fossil, L.L.C. proposes an increase of 60 MW to the Bergen #2 combined cycle facility connected to the Bergen 230kV bus. The project is to add humidification to each of the combustion turbines, increasing the output by 30 MW each. The Bergen station is located in Ridgefield Park, Bergen County, New Jersey. The modification is anticipated to be in-service by June 1, 2013. The total output from Bergen 2 will be increased from 550 MW to 610 MW. The intent of the Impact study is to determine system reinforcements and associated costs and construction time estimates required to facilitate the addition of the new generating plant to the transmission system. The reinforcements include the direct connection of the generator to the system and any network upgrades necessary to maintain the reliability of the transmission system. Attachment Facilities No additional attachment facilities are required. The existing attachment facilities have a summer (normal) rating of 724 MVA. That is sufficient capability to accommodate the additional output of the combined cycle facility. 2
Reactive Capability V4-019 is a request to obtain an additional 60 MW of interconnection rights at the Bergen 2 combined cycle unit for a total of 610 MW. This increase is based on humid air injection into the two combustion turbines resulting in a 30 MW increase for each generator (above the 160 MW base). Summer values were used in the reactive power assessment since the 60 MW increase only applies during the summer period. Reactive power requirement For compliance with PJM Manual 14A generators requesting a capacity or energy increase must meet the following requirements: Existing PJM Tariff provisions require generators to be designed to operate at a power factor range of 0.95 leading to 0.90 lagging as measured at the generator terminals. The above requirement also applies to increases to existing generation. PJM will provide for certain exceptions to existing generators that apply for increases of less than 20 MW. Increases of more than 20 MW to existing generators must be designed to maintain the original power factor capability for grandfathered MWs and a power factor range of at least 1.0 (unity) to 0.90 lagging for all incremental MW increases. Reactive power assessment The V4-019 queue project was evaluated for compliance with the reactive power requirements of the OATT. Each combustion turbine has a new MW rating of 190 MW (160 plus 30) and it was found to be within the requirement. The project was found to be compliant based on the suggested operating point and the project design capability. Specific requirements are detailed below and summarized in Table II. The design capability curve is shown in Figure 1. 3
Table I. Reactive power requirement with V4-019 request MAX MVAR MIN MVAR Reactive power requirement for 160 MW 77.49-52.59 Reactive power requirement for 30 MW increase 14.53 0 Total requirements 92.02-52.59 Available reactive power at 190 MW Winter Gross* 100-75 Total deficiency in MVAR None None *The available reactive power capability is determined using the design capability curve of the machine at the machine winter gross active power output. Note: The lagging and leading PF, follow the generator convention: Lagging MVARs are those being supplied to the system while leading MVARs are those being absorbed from the system. For simplicity of notation, plus and minus signs are used to indicate respectively, MVAR being supplied to or absorbed from the system. 4
Figure I. V4-019 design capability curve 5
Network Impacts The Queue Project #V4-019 was studied as a(n) 60.0MW(Capacity60.0MW) injection at Bergen 230kV substation in the PSEG area. Project #V4-019 was evaluated for compliance with reliability criteria for summer peak conditions in 2014. Potential network impacts were as follows: Generator Deliverability (Single or N-1 contingencies for the Capacity portion only of the interconnection) No problems identified. Multiple Facility Contingency (Double Circuit Tower Line, Line with Failed Breaker and Bus Fault contingencies for the full energy output) No problems identified Short Circuit (Summary form of Cost allocation for breakers will be inserted here if any) No problems identified. Stability Stability analysis does not need to be done because the machine parameters have not changed. Contribution to Previously Identified Overloads (This project contributes to the following contingency overloads, i.e. "Network Impacts", identified for earlier generation or transmission interconnection projects in the PJM Queue) None New System Reinforcements (Upgrades required to mitigate reliability criteria violations, i.e. Network Impacts, initially caused by the addition of this project generation) None 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) (Summary form of Cost allocation for transmission lines and transformers will be inserted here if any) 6
None Cost The V4-019 project is has no cost to increase the outpyt by 60 MW from 550 MW to 610 MW. 7
Attachment #2 Attachment A: 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: Queue V4-019/G10/ST Primary Fuel Type: Natural Gas Maximum Summer (92º F ambient air temp.) Net MW Output**: 293 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): Individual Unit Auxiliary Load at Maximum Summer MW Output (MW/MVAR): Individual Unit Auxiliary Load at Minimum Summer MW Output (MW/MVAR): Individual Unit Auxiliary Load at Maximum Winter MW Output (MW/MVAR): Individual Unit Auxiliary Load at Minimum Winter MW Output (MW/MVAR): Station Service Load (MW/MVAR): Please provide any comments on the expected capability of the unit: * 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. 8
Attachment B: Unit Generator Dynamics Data Queue Letter/Position/Unit ID: V4-019/G10 MVA Base (upon which all reactances, resistance and inertia are calculated): 304 Nominal Power Factor: 0.85 Terminal Voltage (kv): 18 Unsaturated Reactances (on MVA Base) Direct Axis Synchronous Reactance, X d(i) : 1.83 Direct Axis Transient Reactance, X d(i) : 0.265 Direct Axis Sub-transient Reactance, X d(i) : 0.205 Quadrature Axis Synchronous Reactance, X q(i) : 1.76 Quadrature Axis Transient Reactance, X q(i) : 0.467 Quadrature Axis Sub-transient Reactance, X q(i) : 0.206 Stator Leakage Reactance, X l : 0.155 Negative Sequence Reactance, X 2(i) : 0.165 Zero Sequence Reactance, X 0 : 0.155 Saturated Sub-transient Reactance, X d(v) (on MVA Base): 0.165 Armature Resistance, R a (on MVA Base): 0.00108 Time Constants (seconds) Direct Axis Transient Open Circuit, T do : 4.676 Direct Axis Sub-transient Open Circuit, T do : 0.032 Quadrature Axis Transient Open Circuit, T qo : 0.517 Quadrature Axis Sub-transient Open Circuit, T qo : 0.063 Shaft Inertia, (Combined Generator/Prime Mar) H (kw-sec/kva, on KVA Base): 3.58 Speed Damping, D (typically 0 to 2): 0 Saturation Values at Per-Unit Field Voltage [S(1.0), S(1.2); typically 0.##, 0.##]: 0.09, 0.36 In addition, if available please supply the following: Exciter/Governor/Other Models and Block Diagrams Generator Performance Curves Schematic One-line Diagram showing Unit/GSU/Breakers/Interconnection Operating Restrictions and/or Procedures 9
Attachment C: Unit GSU Data Queue Letter/Position/Unit ID: V4-019/G10 Generator Step-up Transformer MVA Base: 200 Generator Step-up Transformer Impedance (R+jX, on transformer MVA Base): 8.5% Generator Step-up Transformer Reactance-to-Resistance Ratio(X/R): 80 Generator Step-up Transformer Rating (MVA): 333 Generator Step-up Transformer Low-side Voltage (kv): 18 Generator Step-up Transformer High-side Voltage (kv): 230 Generator Step-up Transformer Off-nominal Turns Ratio: 1.0 Generator Step-up Transformer Number of Taps and Step Size: : 5@±2.5% 10