Generator Interconnection Facilities Study For SCE&G Two Combustion Turbine Generators at Hagood Prepared for: SCE&G Fossil/Hydro June 30, 2008 Prepared by: SCE&G Transmission Planning
Table of Contents 1. Introduction... 3 2. General Discussion... 3 3. Generator Information... 4 4. Steady State Contingency Analysis... 5 5. Short Circuit Analysis... 8 6. Stability Analysis... 10 7. Cost Estimates and Completion Dates... 15 8. Recommendations and Conclusions... 16 9. Addendum... 16 Appendix: Generator Datasheet... 17
Generator Interconnection Facilities Study For SCE&G two gas turbine Generators at Hagood 1. Introduction A Generator Interconnection Facilities Study is normally performed after the Generation Interconnection Feasibility Study and System Impact Study. At the request of the customer, and because of the size of the generator units, the study process was expedited by consolidating the Feasibility and System Impact studies into the Facilities Study. The Facilities Study specifies and estimates the cost of the equipment, engineering, procurement and construction work needed to implement the conclusions of the Interconnection System Impact Study in accordance with good utility practice to physically and electrically connect the Interconnection Facility to the Transmission System. A Generator Interconnection Facilities Study also identifies the electrical switching configuration of the connection equipment, including, but not limited to: the transformer, switchgear, metering, and other station equipment. The Facilities Study also identifies the nature and estimated cost of any Transmission Provider's Interconnection Facilities and Network Upgrades necessary to accomplish the interconnection. In addition, the Facilities Study provides an estimate of the time required to complete the construction and installation of such facilities. 2. General Discussion This Generation Interconnection Facilities study was requested by SCE&G Fossil/Hydro. Due to the small size of the requested combustion turbines (CT s) which have a maximum capability of 32.872 MVA each, and the fact that the generation site is located in an existing generation station facility, any feasibility issues should be minimal. Also, the existing generation site is located in a special geographic region such that the amount of generation and load in this region is presently not balanced. Transmission Planning Engineers expect to identify minimal impacts to SCE&G s Transmission system. Transmission Planning therefore agrees with the customer s request to consolidate the System Feasibility and System Impact studies into this Facilities Study. In this study, SCE&G Fossil/Hydro requested a two gas turbine generation configuration at the Hagood 115kV bus. Each gas turbine has a maximum output of 27 MW, to be installed before May 30, 2008. SCE&G Generation Group requested this generation to be interconnected to the existing transmission grid at Hagood. Both generation units will be connected through a single generator step up transformer to the Hagood station 115 kv bus (refer to diagram 1 below). 3
Diagram 1. Hagood Substation showing arrangement of Hagood units 2 and 3 and equipment ratings NERC Reliability Standards require that SCE&G Fossil/Hydro consult with SCE&G Transmission Planning to determine the appropriate transformer tap position. For the purposes of this study it was assumed that the transformer tap position would be the same as for the similarly sized Bushy Park CT s. 3. Generator Information The gas turbine generator manufacturer s design data used in this study are included in the Appendix. 4
4. Steady State Contingency Analysis 4.1. Power Flow Model Assumptions Transmission Planning performed steady-state contingency analysis for the 2008 and 2010 summer peak load conditions. 2008 was selected for study as the in-service year for the generators. Additional analysis was performed for 2010 as well. There are several key assumptions made in the 2008 and 2010 base case that affect the results. Those assumptions are: 1. A.M. Williams is generating with a net output of 593 MW 2. Faber Place CT is not generating (it is scheduled to be retired before Hagood units 2 and 3 are in service) 3. Westvaco Cogen is generating with a net output of 90 MW 4. Bushy Park CT s are generating with a net output of 52 MW 5. Thomas Island-Hobcaw 115kV UG Cable is complete and energized. 6. All transmission capacitor banks in the Charleston area are in service and on voltage control. 7. The total net output from Hagood Station, including unit 1 as well as the two proposed units 2 and 3 is 134 MW. Also, in order to simulate a worse case MVA output of Hagood units 2 and 3, a power factor of 0.85 was simulated at Hagood units 2 and 3 by forcing 17 MVAR output from each unit. This assumes the following output schedule for the Hagood Units: Table 4.1.1. Output of Hagood Units for 2008 and 2010 peak Summer Power Flow Models Unit Net MW Output Net MVAR Net MVA Output Output Power Factor Hagood #1 88 Determined by Power Flow Solution Determined by Power Flow Solution Determined by Power Flow Solution Hagood #2 23 17 29 0.85 Hagood #3 23 17 29 0.85 8. The modeled highside tap ratio for the GSU for Hagood units 2 and 3 is: 1.073 Significant Network improvements are planned in the Charleston area that affect the power flow associated with the addition of Hagood units 2 and 3. These improvements are scheduled for completion before the summer of 2010, and are included in the 2010 summer peak model used for this study. These improvements are: 1. Rebuild the 115kV Line from Charleston Transmission to Charlotte Street Sub as a double circuit and a fold in one of these circuits at Hagood. 5
2. Construct a dedicated 115kV Circuit to the Savage Rd Sub. 4.2. 2008 Summer Peak Contingency Analysis Results 4.2.1. N-0 (Base case) Results No overloaded facilities were identified in the 2008 summer peak base case with the addition of the proposed units at Hagood. 4.2.2. N-1 Results Table 4.2.2.1. Overloaded Facilities with the Addition of Hagood Units 2&3 (N-1) 2008 Summer Contingency Overloaded Facility Loading without Hagood #2 and #3* Loading with addition of Hagood #2 and #3* Outage Church Creek Savage Rd 115 kv Line Hagood Grove St 115 kv Line 177 MVA (94%) 196 MVA (103%)** *Percent Loading based on 8 hour Emergency MVA Rating **This overloaded condition assumes that the Savage Rd load is served from the Bee St source post contingency. If the Savage Rd load is not served from the Bee St source post contingency, the Hagood Grove St 115 kv Line will not be overloaded. An operating procedure exists that should be executed after the operation of the Church Ck - St. Andrews 115kV Line due to a fault on the Church Ck Savage Rd section of this line. This operating procedure causes the Savage Rd load to be served from the Queensboro source. Table 4.2.2.2. Highly Loaded Facilities with the Addition of Hagood Units 2&3 (N-1) 2008 Summer Contingency Highly Loaded Facility Loading without Hagood #2 and #3* Loading with addition of Hagood #2 and #3* Outage Church Creek Savage Rd 115 kv Line Grove St Bee St 115 kv Line 161 MVA (85%) 179 MVA (94%) Outage Charleston Transmission Kinder Morgan Tap 115kV Line Outage Kinder Morgan Tap Meeting St Tap 115kV Line Hagood Grove St 115 kv Line 156 MVA (82%) 174 MVA (92%) Hagood Grove St 115 kv Line 154 MVA (81%) 172 MVA (91%) *Percent Loading based on 8 hour Emergency MVA Rating 6
4.2.3. N-2 Results: Table 4.2.3.1. Overloaded Facilities with the Addition of Hagood Units 2&3 (N-2) 2008 Summer Contingency Overloaded Facility Loading without Hagood #2 and #3* Loading with addition of Hagood #2 and #3* Outage: 1) Accabee Faber Place 115 kv Line #1 2) Accabee Faber Place 115 kv Line #2 Outage: 1) Charleston Transmission Kinder Morgan Tap 115kV 2) Church Creek Bee Street 115 kv Hagood Grove St 115 kv Line Hagood Grove St 115 kv Line 170 MVA (90%) 191 MVA (101%) 188 MVA (99%) 200 MVA (106%) 4.3. 2010 Summer Peak Contingency Analysis Results 4.3.1. N-0 (Base case) Results No overloaded or highly loaded facilities were identified in the 2010 summer peak basecase with the addition of the proposed units at Hagood. 4.3.2. N-1 Results Single contingency analysis identified no overloaded or highly loaded facilities due to the addition of Hagood units 2 and 3 in the 2010 summer peak model. 4.3.3. N-2 Results Double contingency analysis identified no overloaded or highly loaded facilities due to the addition of Hagood units 2 and 3 in the 2010 summer peak model. 7
5. Short Circuit Analysis 5.1. Short Circuit Model Assumptions Transmission Planning performed short circuit analyses based on 2008 and 2010 transmission system conditions. The 2008 base case was selected for study as the in-service year for the generators. Additional analysis was performed for 2010 as well. The 2010 base case was selected because of planned transmission improvements in and around Hagood that are scheduled to be completed in 2010. These improvements are: 1. Rebuild the 115kV Line from Charleston Transmission to Charlotte Street Sub as a double circuit and a fold in one of these circuits at Hagood. 2. Construct a dedicated 115kV Circuit to the Savage Rd Sub. 5.2. 2008 Short Circuit Analysis Results 5.2.1. System Impedance at point of Interconnection 2008 Conditions The short circuit system equivalent impedance from the SCE&G Transmission System that will be seen at the Hagood 115kV bus in 2008 is: Table 5.2.1.1. 2008 System Equivalent Impedances for Hagood units 2 & 3 Short Circuit Study Z positive (p.u.) X/R Z negative (p.u.) X/R Z zero (p.u.) X/R 0.00304+j0.022298 7.55 0.00305+j0.02298 7.54 0.00557+j0.04150 7.45 These values are calculated on a 100 MVA base. These values do not include the contribution of the Hagood units 2 and 3. 5.2.2. Overstressed Breaker Analysis 2008 Conditions An analysis of the effect of the increased fault current in the SCE&G area for 2008 conditions indicates that no breakers on the SCE&G transmission system will become overstressed in 2008 due to the addition of the two Hagood units 2 and 3. 8
5.3. 2010 Short Circuit Analysis Results The short circuit system equivalent impedance from the SCE&G Transmission System that will be seen at the Hagood 115kV bus in 2010 is: 5.3.1. System Impedance at point of Interconnection 2010 Conditions Table 5.3.1.1. 2010 System Equivalent Impedances for Hagood units 2 & 3 Short Circuit Study Z positive (p.u.) X/R Z negative (p.u.) X/R Z zero (p.u.) X/R 0.00212+j0.01771 8.34 0.00213+j0.01771 8.32 0.00461+j0.03136 6.80 These values are calculated on a 100 MVA base. These values do not include the contribution of the Hagood units 2 and 3. 5.3.2. Overstressed Breaker Analysis 2010 Conditions These values are calculated on a 100 MVA base. These values do not include the contribution of the Hagood units 2 and 3. An analysis of the effect of the increased fault current in the SCE&G area for 2010 conditions indicates that no breakers on the SCE&G transmission system will become overstressed in 2010 due to the addition of the two Hagood units 2 and 3. 9
6. Stability Analysis 6.1. Overview of Stability Analysis The stability study of the connection of the Hagood units 2 and 3 CT s to the SCE&G transmission system assessed the ability of these generators to remain in synchronism following selected transmission system contingencies. Also reviewed were the adequacy of damping of generation/transmission oscillations and the impact of the proposed generator on the stability performance of other system generators. System voltage responses were examined for indications of voltage instability. In addition, generator frequency responses and the effects of protective system performance were evaluated. The stability study used the higher winter peak capability of the CT s in order to verify that the winter capability would not result in stability issues. Rotor angle responses of SCE&G generators were simulated in order to determine if angular instability could result from likely contingencies. Generator frequency deviations were examined in order to determine if generator frequency protection could result in generator tripping. The results of the loss of the Hagood unit 2 and 3 CT s were examined in order to determine if any resulting underfrequency relay operations would lead to system load shedding. Also, the effects of each contingency were examined in order to determine if SCE&G voltages were adversely affected, particularly with respect to the V. C. Summer Nuclear Station offsite power supplies. SCE&G system responses were examined in order to identify any resulting voltage instability, transient stability limits, system operating limits, or interconnection reliability operating limits. Generator response plots are not included but are available for review upon request. An initial 30 second steady state simulation for the selected connection configuration was performed in order to establish that steady state conditions existed prior to fault conditions. The simulation of each contingency repeated the steady state condition for 1 second prior to introducing permanent fault conditions so that the responses could be compared to the initial steady state condition. In order to determine the effects on all system generators, contingencies were simulated under system peak load conditions. Contingencies were selected in order to satisfy each of four categories as specified by NERC Reliability Standards TPL-001 through TPL-004. The results of the stability analysis are described in the following sections and are summarized following the detailed results. 6.2. Results of Peak Summer Load Stability Analysis. A.1. Steady state conditions (NERC Category A condition) 10
The interconnection of the Hagood unit 2 and 3 generators was shown to result in system steady state conditions. Generator rotor angles and frequencies showed no deviations throughout the 30 second simulation. System voltages showed no deviations throughout the simulation period. There was no indication of generator or system voltage instability. No system stability limits were encountered. Nor were any transient stability limits, system operating limits (SOL s), or interconnection reliability operating limits (IROL s) found. This condition is compliant with NERC Reliability Standard TPL-001-1. A.2. Normal clearing of a three phase fault on the existing Hagood #1 generator 13.2kV terminals (NERC Category B-1 Contingency) Following a 1 second steady state period, a permanent fault was simulated at the Hagood #1 generator 13.2 kv terminals. This results in the opening of the generator step up transformer high side breaker 5 cycles after the appearance of the fault along with the dropping of the Hagood #1 generator. Rotor angle oscillations were moderate and well damped with no indication of angular instability. Likewise, system frequency responses were also moderate and well damped with no indication of system underfrequency load shedding or generator under/overfrequency operations. Local system voltages were initially depressed by the presence of the fault. However all voltages recovered once the fault was cleared and there was no indication of generator or system voltage instability. No system stability limits were encountered. Nor were any transient stability limits, system operating limits (SOL s), or interconnection reliability operating limits (IROL s) found. This contingency is compliant with NERC Reliability Standard TPL-002-1. Steady state conditions were reestablished with no further system operations. A.3. Normal clearing of a three phase fault in the Hagood units 2 & 3 generator step up transformer 13.8kV winding (NERC Category B-3 Contingency) Following a 1 second steady state period, a permanent fault was simulated at the Hagood units 2 and 3 generator step up transformer 13.8 kv windings. This results in the opening of the generator step up transformer high side breaker 5 cycles after the appearance of the fault along with the dropping of the Hagood units 2 and 3 CT s. Rotor angle oscillations were moderate and well damped with no indication of angular instability. Likewise, system frequency responses were also moderate and well damped with no indication of system underfrequency load shedding or generator under/overfrequency operations. Local system voltages were initially depressed by the presence of the fault. However all voltages recovered once the fault was cleared and there was no indication of generator or 11
system voltage instability. No system stability limits were encountered. Nor were any transient stability limits, system operating limits (SOL s), or interconnection reliability operating limits (IROL s) found. This contingency is compliant with NERC Reliability Standard TPL-002-1. Steady state conditions were reestablished with no further system operations. A.4. Normal clearing of a three phase fault on the Hagood-Bee St. 115kV transmission line (NERC Category B-2 contingency) Following a 1 second steady state period, a permanent fault was simulated at the Hagood end of the Hagood-Bee St. 115kV transmission line. This line was selected for a transmission line fault simulation because it is the more heavily loaded of the two Hagood 115kV transmission lines. This is a more severe disturbance than the two previous simulations in that the transmission line reclosed from the Bee St. end onto the fault after the initial fault clearing. The Hagood end of the transmission line did not reclose on the fault due to the time delay inherent in the hot line reclosing scheme. As in the previous cases, rotor angle oscillations were moderate and well damped with no indication of angular instability. Likewise, system frequency responses were also moderate and well damped with no indication of system underfrequency load shedding or generator under/overfrequency operations. However, the Hagood units 2 and 3 CT s did demonstrate a brief overfrequency excursion ranging from approximately 60.9Hz to 61.1 Hz for a period of 0.0333 seconds or 2 cycles. It is recommended that any generator overfrequency protection be calibrated to exclude this condition. The simulation continued with the assumption that the Hagood #2&3 CT s remained on line during this condition. Local system voltages were initially depressed by the presence of the fault. However all voltages recovered once the fault was cleared and there was no indication of generator or system voltage instability. No system stability limits were encountered. Nor were any transient stability limits, system operating limits (SOL s), or interconnection reliability operating limits (IROL s) found. This contingency is compliant with NERC Reliability Standard TPL-002-1. Steady state conditions were reestablished with no further system operations. A.5. Normal clearing of a single phase to ground fault on the Hagood 115kV bus (NERC Categories C-1 contingency) For this simulation, a single phase to ground fault was applied to the Hagood 115kV bus with normal bus differential relay clearing after 8 cycles. A single phase to ground fault is less severe than a three phase fault but can require a longer fault clearing time of 8 cycles as opposed to 6 cycles. Clearing of the fault is accomplished by opening all of the breakers connected to the bus with the result of tripping the existing Hagood CT along with the new Hagood units 2 and 3 CT s plus the connected transmission lines. 12
Rotor angle oscillations were moderate and well damped with no indication of angular instability. Likewise, system frequency responses were also moderate and well damped with no indication of system underfrequency load shedding or generator under/overfrequency operations. Local system voltages were initially depressed by the presence of the fault. However all voltages recovered once the fault was cleared and there was no indication of generator or system voltage instability. No system stability limits were encountered. Nor were any transient stability limits, system operating limits (SOL s), or interconnection reliability operating limits (IROL s) found. This contingency is compliant with NERC Reliability Standard TPL-003-1. Steady state conditions were reestablished with no further system operations. A.6. Delayed clearing of a three phase to due to breaker failure on the Hagood 115kV bus (NERC Categories D-4 and D-10 contingencies) In this simulation, a fault was applied to the Hagood 115kV bus with the failure of the bus differential lockout relay to operate. This resulted in a Zone 2 relay operation from the remote ends of the Hagood Bee St. and Hagood Faber Place 115kV transmission lines. In addition, the existing Hagood CT and the new Hagood 2 and 3 CT s were isolated from the SCE&G System by the initial operation of these breakers. The generator tripping would have been initiated as intended by turbine overspeed, generator overfrequency, or out of step protection. It is recommended that a review of the generator protection systems be reviewed with the results of this study to verify that adequate protection is in place for the Hagood units 2 and 3 as well as for the existing Hagood CT. Otherwise, a generator rotor out of step condition could result if these generators are not tripped quickly enough. The remaining SCE&G generator rotor angle oscillations were moderate and were adequately damped with no indication of angular instability. Local system voltages were initially depressed by the presence of the fault. All voltages recovered once the fault was cleared and there was no indication of generator or system voltage instability. However, due to the delayed clearing of the fault, local area voltages were depressed for an extended period of time. It is possible that station service loads at the A.M. Williams, Bushy Park, Faber Place CT, Westvaco, Canadys, Wateree, and Jasper generating stations could be adversely affected. This is due solely to the delayed clearing of the fault and does not result from the addition of the Hagood units2 and 3 generators. There was no indication of voltage instability. Likewise, system frequency responses were also moderate and adequately damped with no indication of system underfrequency load shedding or generator under/overfrequency operations. 13
No system stability limits were encountered. Nor were any transient stability limits, system operating limits (SOL s), or interconnection reliability operating limits (IROL s) found. This contingency is compliant with NERC Reliability Standard TPL-004-1. Steady state conditions were reestablished with no further system operations. 6.3. Hagood units 2 and 3 CT Stability Study Results Peak System Load Cases Summary A.1. Steady state conditions 1. Generator rotor angles demonstrate steady state condition. 2. Generator frequencies show no deviation. 3. There was no negative impact on V.C. Summer offsite power. 4. There were no resulting voltage instability, transient stability limits, SOL s, or IROL s. 5. NERC Reliability Standard TPL-001 compliance demonstrated. A.2. Normal clearing of a three phase fault on the existing Hagood #1 generator 13.2kV terminals (NERC Category B-1 contingency) 1. There was no indication of transient instability. 2. There was no indication of voltage instability. 3. There was no negative impact on V.C. Summer offsite power. 4. There was no indication of system UFLS or generator OFLS operation. 5. There were no resulting voltage instability, transient stability limits, SOL s, or IROL s. 6. NERC Reliability Standard TPL-002 compliance demonstrated. A.3. Normal clearing of a three phase fault in the Hagood 2 and 3 generator step up transformer 13.8kV winding (NERC Category B-3 contingency) 1. There was no indication of transient instability. 2. There was no indication of voltage instability. 3. No negative impact on V.C. Summer offsite power. 4. There was no indication of system UFLS or generator OFLS operation. 5. No resulting voltage instability, transient stability limits, SOL s, or IROL s. 6. NERC Reliability Standard TPL-002 compliance demonstrated. A.4. Normal clearing of a three phase fault on the most heavily loaded Hagood transmission line (NERC Category B-2 contingency) 1. There was no indication of transient instability. 2. There was no indication of voltage instability. 3. There was no negative impact on V.C. Summer offsite power. 14
4. There was no indication of system UFLS or generator OFLS operation. 5. The Hagood units 2 and 3 overfrequency protection settings should be reviewed. 6. There were no resulting voltage instability, transient stability limits, SOL s, or IROL s. 7. NERC Reliability Standard TPL-002 compliance demonstrated. A.5. Normal clearing of a single phase to ground fault on the Hagood 115kV bus (NERC Categories C-1 contingency) 1. There was no indication of transient instability. 2. There was no indication of voltage instability. 3. There was no negative impact on V.C. Summer Offsite power. 4. There was no indication of system UFLS or generator OFLS operation. 5. There were no resulting voltage instability, transient stability limits, SOL s or IROL s. 6. NERC Reliability Standard TPL-003 compliance demonstrated. A.6 Delayed clearing due to breaker failure of a three phase fault on the Hagood 115kV bus. (NERC Category D-4 and D-10 contingencies) 1. There was no indication of transient instability. 2. There was no indication of voltage instability. 3. There was no negative impact on V.C. Summer offsite power. 4. All Hagood CT s will intentionally trip on turbine overspeed, generator overfrequency, or out of step protection. It is recommended that the generator protection be reviewed for adequacy. 5. There was no indication of system UFLS or other generator OFLS operation. 6. Local generators may encounter station service low voltages due to the delayed clearing of the fault, not due to the addition of the Hagood units 2 and 3 generators. 7. There was no resulting voltage instability, transient stability limits, SOL s, or IROL s. 8. NERC Reliability Standard TPL-004 compliance demonstrated. 7. Cost Estimates and Completion Dates Power Delivery Engineering has provided the following cost estimates for the projects required for the interconnection of the proposed Hagood units 2 and 3 in 2008 dollars: Table 7.1. Cost Estimates for Interconnection Facilities One 115 kv Terminal with Gas Breaker $350,000 115 kv Bus Work (100 ft Extension) $200,000 Grounding and Other $200,000 Total $750,000 15
8. Recommendations and Conclusions Significant Network improvements are planned in the Charleston area that affect the power flow with the addition of Hagood units 2 and 3. These improvements are: 1. Rebuild the115kv Line from Charleston Transmission to Charlotte Street Sub as a double circuit and a fold in one of these circuits at Hagood 2. Construct a dedicated 115kV Circuit from Church Creek Transmission to the Savage Road Substation. These Improvements are scheduled for completion before the Summer of 2010. With these improvements, no overloaded or highly loaded facilities are indicated by the N-0, N-1 and N-2 steady-state analyses due to the addition of the proposed Hagood units 2 and 3. Before these projects are completed, however, the Hagood units 2 and 3 may have to reduce output following certain events to unload heavily loaded lines or to mitigate severe effects of a possible second contingency. These events include: 1. Loss of any section of the Charleston Transmission Charlotte Street 115kV Line 2. Loss of any section of the Church Creek St Andrews Rd. 115kV Line 3. Loss of either one of the two Faber Place Charleston Transmission 115kV Lines 4. Loss of any section of the Hagood Bee St 115kV Line It is recommended that the generator protection be reviewed for adequacy. Contingency events were identified that will require turbine overspeed, generator overfrequency, and/or generator out of step protection to be calibrated to trip the generators in the event of delayed clearing of local faults. In addition nearby generators may encounter station service low voltages due to the delayed clearing of fault. However, this condition is not due to the addition of the Hagood units 2 and 3 generators. No other stability or regulatory compliance related issues were identified in the study. 9. Addendum During the latter stages of this study, the in-service date of the Hagood units 2 and 3 was postponed until later in 2008 or early 2009. This postponement does not affect the results of this study. 16
Appendix Generator Datasheet 17