PLA-7619, Response to Request for Additional Information Regarding License Amendment Request to Revise Diesel Generator Surveillance Requirements with New Steady State Voltage and Frequency Limits
| ML17216A283 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 08/04/2017 |
| From: | Berryman B Susquehanna, Talen Energy |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| CAC MF9131, CAC MF9132, PLA-7619 | |
| Download: ML17216A283 (12) | |
Text
AUG 0 4 2017 Brad Berryman Site Vice President U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001 Susquehanna Nuclear, LLC 769 Salem Boulevard Berwick, PA 18603 Tel. 570.542.2904 Fax 570.542.1504 Brad.Berryman@TalenEnergy.com SUSQUEHANNA STEAM ELECTRIC STATION RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION, (CAC NOS. MF9131 AND MF9132)
PLA-7619 TALEN~
ENERGY 10 CFR 50.90 Docket Nos. 50-387 and 50-388
References:
- 1. Letter PLA-7471, Susquehanna Nuclear, LLC to U.S. NRC, "Proposed License Amendments to Revise Diesel Generator Surveillance Requirements with new Steady State Voltage and Frequency Limits, " dated January 25, 201 7, (ML17044A149).
- 2. Letter PLA-7583, Susquehanna Nuclear, LLC to U.S. NRC, "Response to NRC Request for Supplemental Information for License Amendment Request to Revise Diesel Generator Surveillance Requirements with new Steady State Voltage and Frequency Limits," March 21, 2017, (ML17080A405).
- 3. NRC letter, "Request for Additional Information Regarding License Amendment Request to Revise Diesel Generator Surveillance Requirements with new Steady State Voltage and Frequency Limits (CAC Nos. MF9131 and MF9132), "July 7, 2017 (ML17180A200).
By letter dated January 25,2017 (Reference 1), Susquehanna Nuclear, LLC
("Susquehanna Nuclear") submitted a license amendment request for Facility Operating License Nos. NPF-14 and NPF-22 for the Susquehanna Steam Electric Station ("SSES")
Units 1 and 2. That proposal requests revised Surveillance Requirements (SRs) in Technical Specification (TS) 3.8.1, "AC [Alternating Current] Sources-Operating" for the use of new and more restrictive steady state voltage and frequency limits.
Susquehanna Nuclear provided supplemental information on this proposal on March 21, 2017, (Reference 2). The purpose of this letter is to respond to your request for additional information (RAI, Reference 3) on the requested licensing action. That response is provided in Attachment to this letter.
Susquehanna Nuclear has reviewed the information suppmiing a finding of no significant hazards consideration and the environmental consideration provided to the NRC in Reference 1. The additional information provided by this submittal does not affect those bases that support a conclusion that the proposed license amendment does not involve a significant hazards consideration, and that neither an environmental impact statement nor an environmental assessment needs to be prepared in connection with the proposed amendment. PLA-7619 There are no new regulatory commitments associated with this response.
In the event that the NRC has any question concerning this response, please contact Mr. Jason Jennings at (570) 542-3155.
I declare under penalty of pe1jury that the infonnation provided in this submittal is true and correct.
Executed on:
Brad Berryman
Attachment:
Response to Request for Additional Information cc:
NRC Region I Ms. L. H. Micewski, NRC Sr. Resident Inspector Ms. T. E. Hood, NRC Project Manager Mr. M. Shields, PA DEP/BRP Attachment to PLA-7619 Response to Request for Additional Information Request for Additional Information (RAI-l):
Attachment to PLA-7619 Response to Request for Additional Information Page 1 of9 The analysis of record (AOR) in the Final Safety Analysis Repmi [FSAR] indicates that the limiting case of the loss-of-coolant accident (LOCA) is the double-ended guillotine break of the recirculation suction line concurrent with a loss of offsite power, assuming a single low pressure core injection valve failure. The proposed TS related to the voltage and frequency limits for DG SRs [Surveillance Requirements] may result in flow rates of the emergency core cooling system lower than that assumed in the LOCA analysis.
Show that for the proposed TS conditions, the non-limiting LOCA cases will not become the limiting case and the LOCA AOR remains unchanged.
Response to RAI-l:
There has been no need to modify the AOR in the FSAR to provide a basis for the requested changes of this proposal. As described within the letter of March 21, 2017,Cl) the Residual Heat Removal (RHR) flow rate to the vessel under degraded Diesel Generator (DG) voltage/frequency conditions is slightly below the values assumed in the accident analysis until approximately 200 psig. This yields a range ofRHR flow rates being slightly non conservative from 270 psig to 200 psig. At pressures below 200 psig, the RHR flow rate under degraded DG voltage/frequency conditions is greater than that assumed in the LOCA analysis. For non-limiting LOCA cases that undergo a rapid pressure transient, the same argument that applied to the limiting LOCA will apply to these transients. For relatively slower depressurization LOCAs, the Automatic Depressurization System (ADS) will rapidly depressurize the vessel resulting in the same conclusion for these non-limiting LOCAs.
The LOCA analysis for both non-limiting and the limiting case include numerous conservative assumptions which also suppmi the conclusion that the cunent maximum calculated Peak Clad Temperature (PCT) will not be exceeded. First, the analyses assume that the RHR minimum flow bypass valve fails open. This additional single failure is not required to be assumed and dive1is additional RHR flow from the vessel. Second, the effect of suppression pool pressurization on RHR flow rate is neglected. RHR flow rate will be increased due to the increase in suppression chamber pressure. Finally, the Peak Clad Temperatures for the non-limiting events are at least 65F lower than the limiting LOCA.
The above discussion provides assurance that the non-limiting LOCA cases will remain non-limiting and that additional margin is available to the cunent limiting PCT.
(1) Letter PLA-7583, Susquehanna Nuclear, LLC to U.S. NRC, "Response to NRC Request for Supplemental Information for License Amendment Request to Revise Diesel Generator Surveillance Requirements with new Steady State Voltage and Frequency Limits," March 21, 2017, (ML17080A405)
RAI-2
Attachment to PLA-7619 Response to Request for Additional Infotmation Page 2 of9 When the DG is operating at a steady state frequency of 60.5 hetiz (Hz), the pump flow rate increases and the pump suction side pressure losses increase. This will decrease the available net positive suction head (NPSH). Additionally, the required NPSH for the pump increases as the flow rate increases.
Discuss the change in NPSH margin for each pump affected by the LAR when the DG operates at a steady state frequency of 60.5 Hz.
Response to RAI-2:
While the DG is operating at a steady state frequency of 60.5 Hz, any pumps supplied by the diesel will have an increase in flow rate. Based on the pump affinity laws, the change in pump flow will be directly propotiional to the frequency increase. The previous analyses were perfotmed at a frequency of 60Hz and the new frequency limit is 60.5 Hz, so the pump flow will increase by a factor of 1.008. The suction line losses will be propotiional to the square of the frequency increase or by a factor of 1.017. The following table provides the change in suction loss and pump flow rates of non-closed loop pumps affected by the change:
Pump Suction Losses Suction losses Flow Rate Flow Rate
@60Hz (feet)
@ 60.5 Hz (feet)
@60Hz (gpm)
@ 60.5 Hz (gpm)
RHR 11.1 11.3 13,800 13,910 Core Spray 14.7 14.9 7,900 7,965 ESW NIA pump NIA pump 7,500 7,560 submerged submerged RHRSW N/Apump N/Apump 11,250 11,340 submerged submerged This infotmation was then used to dete1mine the required NPSH at the new flow conditions and the margin at a steady state frequency of 60.5 Hz.
Pump NPSHr NPSHr NPSHa NPSHa
@ 60 Hz (feet)
@ 60.5 Hz (feet)
@ 60 Hz (feet)
@ 60.5 Hz (feet)
RHR 5.0 5.1 8.2 8.0 Core Spray 4.0 4.1 5.75 5.55 ESW 37.0 37.5 39.4 39.4 RHRSW 37.0 37.7 38.4 38.4 The above NPSHa (available) values for the Core Spray and RHR neglect any effect from suppression chamber pressurization during accident conditions, as required by
Attachment to PLA-7619 Response to Request for Additional Information Page 3 of9 Regulatory Guide 1.1. (2) Plant operating procedures limit the RHRSW water flow rate to 8000 -
9000 gpm, which significantly increases the available NPSH margin for this system. As can be seen from the table, all systems have margin to NPSHr (required), even at a steady state frequency of 60.5 Hz.
RAI-3
In Section 4.3.2, "DG Jacket Water," of the LAR, it states:
Under normal operation, the engine-driven jacket water pump pressure for DG A and E is 30 psig [pounds per square inch gauge], and its low-pressure almm is 12 psig and 10 psig for DGs A and E, respectively.
Provide the engine-driven jacket water pump pressures and low-pressure almm settings for DG B through D.
Response to RAI-3:
The A thru D diesel generators are identical models and have the same nameplate rating. The
'E' diesel generator is a different model and has a different rating. The A thru D engine driven jacket water pressure pump is 30 psig and the low pressure alarm for the jacket water system on the A thru D diesel generators is 12 psig.
RAI-4
Discuss whether or not any relief valves on the pumps' discharge piping will lift due to the higher discharge pressure when the DG is operating at 60.5 Hz.
Response to RAI-4:
No relief valves on the pumps' discharge piping will lift due to the higher pressure when the DG is operating at 60.5 Hz. The increase in operating pressure due to the higher DG frequency is small and system pressures do not operate that close to the relief valve settings. For example, the RHR pressure is approximately 380 psig under accident conditions. Using the relationship presented in RAI-2 the pressure increase due to the higher frequency is 6.5 psig. The discharge relief valve setting is 450 psig. This is a typical example, so all systems have sufficient margin to accommodate any slight pressure increase due to operating at a frequency of 60.5 Hz.
(2)
Regulatory Guide 1.1, Net Positive Suction Head for Emergency Core Cooling and Containment Heat Removal System Pumps (Safety Guide 1), November 2, 1970
RAI-5
Attachment to PLA-7619 Response to Request for Additional Information Page 4 of9 In Section 4.3.4, "DG Loading," of the LAR, it states, in part:
The non-ESF [engineered safety feature] loads are not required for mitigating the effects of a design basis event of LOCA/LOOP [loss-of-coolant accident/loss of offsite power] on one unit and forced shutdown of the second unit, and their ultimate operation status is at plant operations discretion. The subject non-ESF loads account for more than 620 kW
[kilowatts] ofDG A loading beyond one hour of operation under the considered DBA
[design-basis accident] scenario....
Thus, without the non-ESF loads, analysis shows that for the most severe design basis event, DGs A and E total loadings under limiting voltage and frequency variations within acceptable steady state ranges are within their respective continuous rating of 4000 kW and 5000 kW, with at least approximately 9.8% and 22.5% additional margins for DG A and E, respectively.
The NRC staff notes that the LAR does not provide sufficient infmmation to suppmi the conclusion for the above-mentioned analysis regarding the total loading ofDG A and DG E.
Provide a discussion including a tabulated summary of the analysis that demonstrates DG A and DG E tota'lloadings with and without non-ESF loads required for mitigating the worst case design-basis event when the DGs operate at the extremes of the proposed steady state voltage and frequency ranges.
Response to RAI-5:
Section 4.3.4 of the License Amendment Request (LAR) provides a summary of the detailed analysis used in detennining the total loading on the DGs A and E. For a comprehensive explanation of the loading analysis, excerpts of calculation EC-024-1035 were attached to the LAR, (e.g,. as Attachment 3-3) for inspection and reference to show this evaluation of the impact of DG steady state fi*equency and voltage variations. This calculation provides detailed analysis showing how the total loadings on DGs A and E, that are required to mitigate the worst case design basis event when the DGs are operating at the extremes of their proposed steady state voltage and frequency ranges, were derived.
The cumulative impact of the voltage and frequency variations on the DG loading was evaluated for its worst case loading scenario (Unit 1 LOCA-LOOP and Unit 2 forced shutdown when DG B is unavailable). The loading analysis was limited to DGs A and E. DG A was selected due to it being the most loaded DG 60 minutes and beyond the inception of the event. DG E was analyzed for its substitute ability for DG A. The results of voltage and frequency variations on DG A and E, when DG E is substituted for DG A, are considered bounding for all diesels.
The methodology used in dete1mining the percent loading margin of DG A and E under the described conditions above are presented in table formats within calculation EC-024-1035 and are summarized in the balance of this response to RAI-5.
Impacted tables of calculation EC-024-1035:
Attachment to PLA-7619 Response to Request for Additional Information Page 5 of9 Table 1 -
DGs A and E Loading per FSAR Tables 8.3-3 and 8.3-3a Table 4 -
Diesel Generators A and E Total Estimated Loading when Unit 1 LOCA/LOOP and Unit 2 Forced Shutdown with DG B Unavailable (at 60 Min and Beyond)- All ESF and Non-ESF Loads Considered Table 5 -
DG A ESF and Non-ESF Manually Initiated Loads per FSAR Table 8.3-1 Table 6 -
DG A Lumped Loads per Category Table 7 -
DGs A and E Loading per FSAR Tables 8.3-3 & 8.3-3a, When Manually Initiated Non-ESF Loads Not Considered Table 8 -
DG A and E Total Estimated Loading when Unit 1 DNA and Unit 2 Forced Shutdown with DG Unavailable (at 60 Min and Beyond)-
Without Non-ESF Loads Manually Initiated)
Methodology:
- 1.
Table 1 provides a condensed version of DGs A and E loading as per FSAR Tables 8.3-3 and 8.3-3a. A power factor of0.9 was used in determining the KV AR values.
- 2.
The total loading on DG A and E at rated voltage and frequency is dete1mined thru tabulation of Table 1. The first column of Table 4 (Vrated I frated) represents this load.
- 3.
The loading of DGs A and E under limiting voltage and frequency variations is also provided in Table 4. The methodology in determining these values is presented in exhibit 9 (Description of Methodology Used in Deriving Table 4) of the calculation.
- 4.
The loadings presented in Table 4 represent all ESF and non-ESF loads for DG A and E for 60 minutes and beyond the DBA event. These loads are further evaluated, refining the loads to remove the non-ESF loads that are manually initiated during the design bases event in order to better represent the allowable margin of the DGs.
- 5.
A review ofFSAR Table 8.3-1, in conjunction with the DG loading table of FSAR Table 8.3-3, will provide both the ESF and non-ESF manually initiated loads, shown in Table 5 of the calculation.
- 6.
The loading on DG A, as provided in FSAR Table 8.3-3 and Table 5, are lumped and categorized into Table 6.
RAI-6
Attachment to PLA-7619 Response to Request for Additional Infmmation Page 6 of9
- 7.
The results of Table 6 are then used to generate Table 7, which represents the loading on DGs A and E when the manually initiated non-ESF loads are not considered.
- 8.
Without the inclusion of the manually initiated non-ESF loads, Table 8 is developed under the same methodology as Table 4, (using exhibit 9 of the calculation).
- 9.
The data can then be extrapolated from Table 8 to show that under the most severe design bases event, DGs A and E total loadings, under limiting voltage and frequency variations within the listed acceptable steady state ranges, are within the DGs' respective continuous ratings of 4000kW and 5000kW. These values, the highest of all DGs A and E total loadings, represent the approximate 9.8 percent and 22.5 percent margins that are available for DG A and E, respectively.
In Section 4.2, "DG Steady State Frequency," of the LAR it states that the proposed minimum steady state frequency limit of 59.3 Hz produces the minimum transient frequency recommended for DG E under Regulatory Guide 1.9, Revision 2, "Selection, Design, and Qualification of Diesel-Generator Units Used as Standby (Onsite) Electric Power Systems at Nuclear Power Plants." The LAR also stated that the design ofDGs A thru D conforms to Regulatory Guide 1.9, Revision 0 (Safety Guide 9), "Selection of Diesel Generator Set Capacity for Standby Power Supplies, and takes exception to the 95 percent of nominal (i.e., 57 Hz) minimum frequency recommendation during transient periods. In addition, the LAR stated that the maximum frequency transient occurs during the start of residual heat removal (RHR) pump motor, which is the first major and the largest load applied to the DGs during a LOOP concmTent with a DBA test.
The NRC staff notes that, according to Tables 8.3.1 and 8.3.3 ofthe Susquehanna Updated Final Safety Analysis Report (UFSAR), Revision 67, an RHR pump motor is the first largest load applied to a DG (e.g., DG A) 13 seconds from the DBA for the unit in an accident condition, and an RHR pump is also loaded on another DG (e.g., DG D) 30 minutes later (after other loads have sequenced onto DG D) to suppmi shutdown of the non-accident unit. DG E can be used to substitute for any of the DGs A, B, C, and D.
Since the maximum frequency transient occurs during the sta1i of an RHR pump motor, provide the following:
a)
Discuss the impacts of the frequency and voltage deviations when the RHR pump is stmied after 30 minutes with the DGs loaded as postulated for all the DGs. In the discussion, specifically address how the deviations affect RHR pump and RHR train perfmmance, considering the DGs' frequency and voltage vm*iations during load sequencing, as specified in Regulatory Guide 1.9, Revision 0 and Revision 2, and UFSAR Section 8.1.6.l.b.6.
Attachment to PLA-7 619 Response to Request for Additional Information Page 7 of9 b)
Confirm that the voltage and frequency transient variations discussed above will not adversely impact accident mitigation loads that have been sequentially loaded prior to the RHR pump.
Response to RAI-6:
FSAR sections 8.1.6.l.b, 8.1.6.l.c describe the continuing design basis applicability of Regulatory Guide (RG) 1.9, revisions 0 and 2, for the station's use of the DGs. At no time during the loading sequence of the diesel generators will the frequency, voltage or a combination thereof, drop to a level that will degrade the performance of the DG or any of the DG loads below their minimum requirements. The voltage and frequency variations as experienced by the DGs when the RHR motor is loaded onto the diesels will not adversely impact accident mitigation loads that have been sequentially loaded prior to the RHR pump motor.
With the proposed change to the frequency limits of the DGs, the new minimum steady state frequency limit of 59.3Hz will produce a 2.3 Hz drop between the DG's minimum steady state frequency and the allowable minimum transient frequency of 57 Hz, as required for DG E under RG 1.9 revision 2. Recent perf01mance of LOCA/LOOP surveillances have shown a maximum frequency dip of 2.0 Hz during the transient period of an RHR pump motor start. With the new minimum steady state frequency setpoint of 59.3 Hz, the minimum frequency experienced by the DGs during transient conditions will be 57.3 Hz. This provides a 0.3 Hz or a 15 percent margin to the allowable minimum transient frequency of 57 Hz.
The design of A thru D DGs provide that under loading conditions, the engine, generator and excitation system in combination shall maintain a generator voltage following each loading step, a value not less than 75 percent of rated (4160V). The inrush of the load center transf01mers may reduce the generator voltage to below 75 percent of rated for one or two cycles. This deviation is acceptable. Following the initial drop, the voltage shall be restored to not less than 90 percent of rated in less than 60 percent of each load sequence time interval.
Simulation studies were performed using ETAP, (e.g., a Power Systems Modeling, Analysis and Optimization Software) where the transient stability models of DGs A and E were used to determine the worst voltage drop experienced by DGs A and E under cettain loading conditions.
Each case study represented different steady state voltage and frequency values as set f01th by the LAR, (i.e. Voltage: 4000V-4400V and Frequency: 59.3Hz-60.5Hz). In all cases, the worst voltage drop had occmTed during the start of the RHR pump motor. For DG A, the worst voltage drop of76.4 percent occurred when the DG voltage was operating at 4400V and the frequency at 60Hz_, DG E experienced the worst voltage drop of76.9 percent when the DG was at a voltage of 4400V and frequency at 60 Hz. This simulation study confi1ms the DGs are within their design specifications, as stated above.
Attachment to PLA-7619 Response to Request for Additional Infmmation Page 8 of9 The voltage drop, as experienced by the DG resulting from the start of the RHR motor is shown to not adversely affect the critical functions of class IE equipment. The variations in loadings associated with steady state frequency and voltage changes within the aforementioned ranges are shown to not subject the equipment to perfmm beyond their ratings. The equipment is designed to meet the following design criteria:
The steady state design for all electrical equipment essential to safety is designed to accept a voltage between 90 and 110 percent of the equipment ratings, per FSAR 1.2.2.6.2.
The electrical system is designed so that the total voltage drop on the class 1 E motor circuits is less than 20 percent of the nominal motor voltage. The class 1 E motors are specified with accelerating capability at 80 percent nominal voltage at their terminals, per FSAR 8.3.1.9.
The voltages at the busses shall not dip below 70 percent of rated voltage during the start of a remote motor.
RAI-7
In Section 4.3.6, "Motor Impact," of the LAR it states:
Per NEMA [National Electrical Manufacturers Association] standard MG-2, a frequency allowance of up to 5% is pe1missible, provided the arithmetic sum ofthe frequency variation and the voltage frequency does not exceed 10% [of the rated values].
The NEMA MG-2 also allows a combined variation in voltage and frequency of -10 percent provided that the frequency variation is limited to -5 percent. The NRC staff notes that in the event that the DG steady state voltage and frequency are at their maximum values [i.e., 4,400V
[voltage] and 60.5 Hz) simultaneously, the combined variation would exceed the NEMA MG-2 limit of+ 10 percent. The NRC staff also notes that if the DG steady state voltage and frequency were at their respective maximum value (4,400V) and minimum value (59.3 Hz), the combined variation would exceed the NEMA MG-2limit of -10 percent.
Since the combination of the proposed DG voltage and frequency variations may exceed the NEMA recommended limits for motors in some cases, provide the following:
a)
A discussion regarding the net effect of the proposed voltage and frequency variations on the motors and loads that have minimum design margins between nominal rating and maximum postulated load.
b)
A discussion about the impact of the proposed DG frequency and voltage variations on the protective devices associated with the motor loads.
c)
A discussion about motor capability if the associated pump is operating under run out conditions.
Response to RAI-7:
Attachment to PLA-7619 Response to Request for Additional Infmmation Page 9 of9 The standards for performance of the DGs, including voltage and frequency variations are described in FSAR sections 8.1.6.l.b and 8.1.6.l.c. The DGs are governed by the guidance of RG 1.9 revision 0 and 2 whereas each DG shall be designed such that at no time during the loading sequence should the frequency and voltage decrease to less than 95 percent on nominal and 75 percent on nominal, respectively. The restoration of frequency shall be within 2 percent of nominal and voltage within 10 percent of nominal within 60 percent of each load-sequence time interval.
The performance of induction motors are governed by the NEMA MG-1 standard. AC induction motors shall operate successfully under running conditions at rated load with a variation in the voltage or frequency up to the following:
Plus or minus 10 percent of rated voltage with rated frequency Plus or minus 5 percent of rated frequency with rated voltage A combined variation in voltage and frequency of 1 0 percent (sum of absolute values) of the rated values, provided the frequency variation does not exceed plus or minus 5 percent of rated frequency The impact to motors and other plant equipment as a result of voltage and frequency variations are discussed within section 4.3 of the LAR, with a more detailed explanation provided in the Calculation EC-024-1035 Section 7.0, (Attachment 3-3 ofthe LAR).
With the potential variations in DG frequency and voltage, the protective relays associated with motor loads will not be impacted. The settings of these relays are based on a standard design criteria developed for the protection of 4kV and 460V motors. This criteria incorporates the requirements ofFSAR 8.3.1.9, where a minimum operating voltage of80 percent of rated voltage was chosen to avoid tripping during transient voltage conditions. Current overload settings are also based on a standard design criteria with a minimum setting based on a percentage of full load cunent or locked rotor cunent with the tripping time selected to ovenide motor statiing conditions of 100 percent and 80 percent rated tetminal voltage. This design criteria incorporates a margin into the minimum setting of the relay that will envelope the small changes experienced by the motors during variations of the DG frequency and voltage.
Centrifugal pumps are designed and operated to be protected from the conditions of pump runout. The affinitiy laws tell us as discharge head decreases, flow increases, and so does power draw. As the DG frequency and voltage varies, so does the motor speed and horsepower. As a pump approaches runout conditions, an overload condition is approached when the required horsepower exceeds the motor capacity, causing the motor to trip its overload if not sized properly. The overload trip devices are designed per a standard design specification to have a minimum pick-up setting that encompasses a minimum tolerance of +/-10%. This added tolerance will envelope the added overload condition experienced by a motor under pump runout conditions during variations of DG frequency and voltage.