Text

Transmittal of Technical Specifications Bases Revisions
	ML15281A187
Person / Time
Site:	Robinson
Issue date:	10/08/2015
From:	Hoffman D; Duke Energy Progress
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RNP-RA/15-0086
	Download: ML15281A187 (21)
	v • d • e

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PROGRESS Serial: RNP-RA/15-0086 OCT 0 8 2015 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555 H.B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 DOCKET NO. 50-261/RENEWED LICENSE NO. DPR-23 Transmittal of Technical Specifications Bases Revisions Ladies and Gentlemen:

David S. Hoffman H B Robinson Steam Electric Plant Unff 2 Dr - Nuc Org Effectiveness Duke Energy Progress 3581 West Entrance Road HartsvHte, SC 29550 0 843 857 5239 F. 843 857 1319 David.Hoffn1an@duke~nergJ '. C01 TS 5.5.14 In accordance with Technical Specifications 5.5.14.d, Duke Energy Progress, Inc., is transmitting revisions to the H. B. Robinson Steam Electric Plant, Unit No. 2 (HBRSEP2),

Technical Specifications Bases. The attachment to this letter provides Technical Specifications Bases pages for Revisions 62 through 66.

This letter contains no new Regulatory Commitments and no revision to existing Regulatory Commitments.

If you have any questions concerning this matter, please contact Richard Hightower, Manager -

Nuclear Regulatory Affairs at (843) 857-1329.

DSH/jmw Attachment cc:

K. M. Ellis, NRC Senior Resident Inspector M. Barillas, NRC Project Manager, NRR V. M. Mccree, NRC Region II Administrator David S. Hoffman Director - Nuc Org Effectiveness

U.S. Nuclear Regulatory Commission Attachment to Serial: RNP-RA/15-0086 Page 1 of 20 H. B. Robinson Steam Electric Plant, Unit No. 2 Technical Specifications Bases Pages For Revisions 62 Through 66

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BASES ACTIONS (continued)

Rod Position Indication B 3.1.7 until power has been reduced to s 50%, at which time the Required Action C.2 would be met.

With one demand position indicator per bank inoperable, the rod positions can be determined by the ARPI System. Since normal power operation does not require excessive movement of rods, verification by administrative means that the rod position indicators are OPERABLE, that the position of each rod in the affected bank(s) is within 7.5 inches of the average of the individual rod positions in the affected bank(s), for bank positions < 200 steps and that the position of each rod in the affected bank(s) is within 15 inches of the bank demand position for bank positions ::2: 200 steps within the allowed Completion Time of once every 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is adequate.

Reduction of THERMAL POWER to s 50% RTP puts the core into a condition where rod position is not significantly affecting core peaking factors. The allowed Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months provides an acceptable period of time to verify the rod positions per Required Actions C.1.1 and C.1.2 or reduce power to s 50% RTP.

If the Required Actions cannot be completed within the associated Completion Time, the plant must be brought to a MODE in which the requirement does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Time is reasonable, based on operating experience, for reaching the required MODE from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.1.7.1 REQUIREMENTS HBRSEP Unit No. 2 A CHANNEL CALIBRATION of the ARPI System is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to the measured parameter with the necessary range and accuracy. The 18 month Frequency is based on the need to perform this Surveillance under conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

(continued)

B 3.1-47 Revision No. 66

BASES REFERENCES HBRSEP Unit No. 2

1.

UFSAR Section 3.1.2.

Rod Position Indication B 3.1.7

2.

CP&L Letter, E. E. Utley to NRC, "Rod Position Indication System,"

dated 12/14/79.

3.

UFSAR, Chapter 15.

(continued)

B 3.1-48 Revision No. 66

BASES PAGE INTENTIONALLY LEFT BLANK HBRSEP Unit No. 2 B 3.1-49 Rod Position Indication B 3.1.7 Revision No. 66

BASES LTOP System B 3.4.12 SURVEILLANCE SR 3.4.12.4 (continued)

REQUIREMENTS HBRSEP Unit No. 2

b.

Once every 31 days for a valve that is locked, sealed, or secured in position. A removed pressurizer safety valve fits this category.

The passive vent arrangement must only be open to be OPERABLE.

This Surveillance is required to be met if the vent is being used to satisfy the pressure relief requirements of the LCO 3.4.12.b.

SR 3.4.12.5 The PORV block valve must be verified open every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to provide the flow path for each required PORV to perform its function when actuated. The valve must be remotely verified open in the main control room. This Surveillance is performed if the PORV satisfies the LCO.

The block valve is a remotely controlled, motor operated valve. The power to the valve operator is not required removed, and the manual operator is not required locked in the inactive position. Thus, the block valve can be closed in the event the PORV develops excessive leakage or does not close (sticks open) after relieving an overpressure situation.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is considered adequate in view of other administrative controls available to the operator in the control room, such as valve position indication, that verify that the PORV block valve remains open.

SR 3.4.12.6 Performance of a COT is required within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after decreasing RCS cold leg temperature to:$ 350°F and every 31 days on each required PORV to verify and, as necessary, adjust its lift setpoint. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable COT of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. The COT will verify the setpoint is within the allowed maximum limits in the L TOP analysis. PORV actuation could depressurize the RCS and is not required.

(continued)

B 3.4-73 Revision No. 64

BASES LTOP System B 3.4.12 SURVEILLANCE SR 3.4.12.6 (continued)

REQUIREMENTS REFERENCES HBRSEP Unit No. 2 To provide operators flexibility during MODE 4 transition activities a note has been added indicating that this SR is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after decreasing RCS cold leg temperature to ~ 350°F.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months FREQUENCY considers the unlikelihood of a low temperature overpressure event during this time. The COT is required to be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering the LTOP MODES when the PORV lift setpoint is reduced to the LTOP setting. The 31 day FREQUENCY considers experience with equipment reliability.

SR 3.4.12.7 Performance of a CHANNEL CALIBRATION on each required PORV actuation channel is required every 18 months to adjust the whole channel so that it responds and the valve opens within the required range and accuracy to known input.

1.

10 CFR 50, Appendix G.

2.

Generic Letter 88-11.

3.

UFSAR, Chapter 5.

4.

Letter, RNP-RA/96-0141, CP&L (R. M. Krich) to NRC, "Request for Technical Specifications Change, Conversion to Improved Standard Technical Specifications Consistent with NUREG-1431,

'Standard Technical Specifications-Westinghouse Plants,'

Revision 1," August 30, 1996, Enclosure 5.

5.

Letter, NG-77-1215, CP&L (B. J. Furr) to NRC (R. W. Reid),

"Reactor Vessel Overpressurization Protection," October 31, 1977.

6.

Letter, NG-77-1426, CP&L (E. E. Utley) to NRC (R. W. Reid),

"Response to Overpressure Protection System Questions,"

December 15, 1977.

(continued)

B 3.4-74 Revision No. 64

BASES REFERENCES (continued)

HBRSEP Unit No. 2

7.

LTOP System B 3.4.12 Report, "Pressure Mitigating Systems Transient Analysis Results,"

prepared by Westinghouse Electric Corporation for the Westinghouse Owners Group on Reactor Coolant System Overpressurization, July 1977, and Supplement, September 1977.

8.

1 O CFR 50, Section 50.46

9.

10 CFR 50, Appendix K.

10.

Generic Letter 90-06.

11.

EGR-NGGC-0153, Engineering Instrument Setpoints B 3.4-75 Revision No. 64

BASES Containment Air Temperature B 3.6.5 APPLICABLE No two OBAs are assumed to occur simultaneously or SAFETY ANALYSES consecutively. The postulated OBAs are analyzed with regard (continued) to Engineered Safety Feature (ESF) systems, assuming the loss of HBRSEP Unit No. 2 one ESF bus, which is the worst case single active failure, resulting in one train each of the Containment Spray System, Residual Heat Removal System, and Containment Cooling System being rendered inoperable.

The limiting OBA for the maximum peak containment air temperature is an SLB. The initial containment average air temperature assumed in the design basis analyses (Ref. 1) is 130°F. This resulted in a maximum containment air temperature of approximately 322.6°F. The maximum containment air temperature from a LOCA is approximately 265.8°F. The environmental qualification temperature limit bounds the maximum SLB and LOCA temperature responses. The containment structural design temperature is 263°F.

The temperature limit is used to establish the environmental qualification operating envelope for containment. The maximum peak containment air temperature was calculated to exceed the containment design temperature briefly during the transient. The basis of the containment design temperature, however, is to ensure the performance of safety related equipment inside containment (Ref. 2). Thermal analyses showed that the time interval during which the containment air temperature exceeded the containment design temperature was short enough that the equipment surface temperatures remained below the design temperature.

Therefore, it is concluded that the calculated transient containment air temperature is acceptable for the OBA SLB.

The temperature limit is also used in the depressurization analyses to ensure that the minimum pressure limit is maintained following an inadvertent actuation of the Containment Spray System (Ref. 1 ).

The containment pressure transient is sensitive to the initial air mass in containment and, therefore, to the initial containment air temperature.

The limiting OBA for establishing the maximum peak containment internal pressure is a LOCA. The temperature limit is used in this analysis to ensure that in the event of an accident ttie maximum containment internal pressure will not be exceeded.

(continued)

B 3.6-30 Revision No. 62

BASES BACKGROUND Containment Spray and Cooling Systems B 3.6.6 Containment Cooling System (continued) and incore detector raceway, and outside the secondary shield in the lower areas of containment.

During normal operation, all four fan units may be operating. The fans are normally operated with SW supplied to the cooling coils. The Containment Cooling System, operating in conjunction with the Containment Ventilation system, is designed to limit the ambient containment air temperature during normal unit operation to less than the limit specified in LCO 3.6.5, "Containment Air Temperature." This temperature limitation ensures that the containment temperature does not exceed the initial temperature conditions assumed for the DBAs.

In post accident operation following an actuation signal, the Containment Cooling System fans are designed to start automatically if not already running. The temperature of the SW is an important factor in the heat removal capability of the fan units.

APPLICABLE The Containment Spray System and Containment Cooling System SAFETY ANALYSES limit the temperature and pressure that could be experienced following a OBA. The limiting DBAs considered are the loss of coolant accident (LOCA) and the steam line break (SLB). The LOCA and SLB are analyzed using computer codes designed to predict the resultant containment pressure and temperature transients. No DBAs are assumed to occur simultaneously or consecutively. The postulated DBAs are analyzed with regard to containment ESF systems, assuming the loss of one ESF bus, which is the worst case single active failure and results in one train of the Containment Spray System and Containment Cooling System being rendered inoperable.

HBRSEP Unit No. 2 The analysis and evaluation show that under the worst case scenario, the highest peak containment pressure is 41.8 psig (experienced during a LOCA). The analysis shows that the peak containment temperature is approximately 322.6°F (experienced during an SLB). Both results meet the intent of the design basis. (See the Bases for LCO 3.6.4, "Containment Pressure," and LCO 3.6.5 for a detailed discussion.) The limiting SLB analysis for pressure response assumes a power level of 0%

with the single failure of an emergency bus. The limiting analysis for temperature response assumes a SLB with a power level of 0% and a single failure of a steam line check valve. The limiting pressure response B 3.6-35 (continued)

Revision No. G, 62 Amendment No. 187

BASES Containment Spray and Cooling Systems B 3.6.6 APPLICABLE is the Double Ended Pump Suction (DEPS) LOCA with minimum SAFETY ANALYSES safety injection. The analyses assume the limiting initial conditions (continued) for pressure (-0.8 to 1.0 psig) and temperature (75 F to 130 F) as applicable. The analyses also assume a response time delayed initiation to provide conservative peak calculated containment pressure and temperature responses.

HBRSEP Unit No. 2 For certain aspects of transient accident analyses, maximizing the calculated containment pressure is not conservative. In particular, the effectiveness of the Emergency Core Cooling System during the core reflood phase of a LOCA analysis increases with increasing containment backpressure. For these calculations, the containment backpressure is calculated in a manner designed to conservatively minimize, rather than maximize, the calculated transient containment pressures in accordance with 10 CFR 50, Appendix K (Ref. 2).

The effect of an inadvertent containment spray actuation has been analyzed. An inadvertent spray actuation is limited to a -3.0 psig containment pressure and is associated with the sudden cooling effect in the interior of the leak tight containment. Additional discussion is provided in the Bases for LCO 3.6.4.

The modeled Containment Spray System actuation from the containment analysis is based on a response time associated with exceeding the containment High - High pressure setpoint to achieving full flow through the containment spray nozzles.

Containment cooling train performance for post accident conditions is given in Reference 3. The result of the analysis is that each train can provide 100% of the required peak cooling capacity during the post accident condition. The train post accident cooling capacity under varying containment ambient conditions, is also shown in Reference 4. The modeled Containment Cooling System actuation from the containment analysis is based on a response time associated with exceeding the containment high pressure setpoint to achieving full Containment Cooling System air and cooling water flow.

The Containment Spray System and the Containment Cooling System satisfy Criterion 3 of the NRC Policy Statement.

(continued)

B 3.6-36 Revision No. 62

BASES ACTIONS (continued)

C.1 and C.2 MSIVs B 3.7.2 Condition C is modified by a Note indicating that separate Condition entry is allowed for each MSIV.

Since the MSIVs are required to be OPERABLE in MODES 2 and 3, the inoperable MSIVs may either be restored to OPERABLE status or closed.

When closed, the MSIVs are already in the position required by the assumptions in the safety analysis.

The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable, considering the low probability of an accident occurring during this time period that would require a closure of the MS IVs.

For inoperable MSIVs that cannot be restored to OPERABLE status within the specified Completion Time, but are closed, the inoperable MSIVs must be verified on a periodic basis to be closed. This is necessary to ensure that the assumptions in the safety analysis remain valid. The 7 day Completion Time is reasonable, based on engineering judgment, in view of MSIV status indications available in the control room, and other administrative controls, to ensure that these valves are in the closed position.

D.1 and D.2 If the MS IVs cannot be restored to OPERABLE status or are not closed within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed at least in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from MODE 2 conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.2.1 REQUIREMENTS HBRSEP Unit No. 2 This SR verifies that MSIV closure time is within limits (Ref.4) on an actual or simulated actuation signal. The maximum MSIV closure time is less than that assumed in the accident and (continued)

B 3.7-12 Revision No. 63

BASES SURVEILLANCE REQUIREMENTS (continued)

REFERENCES HBRSEP Unit No. 2 SR 3.7.2.1 (continued)

MS I Vs B 3.7.2 containment analyses with the exception of closure of the MS IVs for a MSLB at 100% RTP, in which case MSIV closure in 2 seconds is assumed for MSIVs which close in the forward flow direction. The MSIVs should not be tested at power, since even a part stroke exercise increases the risk of a valve closure when the unit is generating power.

As the MSIVs are not tested at power, they are exempt from the ASME Code,Section XI (Ref. 5), requirements during operation in MODE 1 or 2.

The Frequency is in accordance with the lnservice Testing Program. The specified Frequency for valve closure time is based on the refueling cycle. Operating experience has shown that these components usually pass the Surveillance when performed at the specified Frequency.

Therefore, the Frequency is acceptable from a reliability standpoint.

This test is conducted in MODE 3 with the unit at operating temperature and pressure, as discussed in Reference 5 exercising requirements. This SR is modified by a Note that allows entry into and operation in MODE 3 prior to performing the SR. This allows a delay of testing until MODE 3, to establish conditions consistent with those under which the acceptance criterion was generated.

1.

UFSAR, Section 10.3.

2.

UFSAR, Section 6.2.

3.

UFSAR, Section 15.1.5.

4.

TRM, Section 4.0

5.

ASME, Boiler and Pressure Vessel Code,Section XI.

B 3.7-13 Revision No. 63

BASES (continued)

MFIVs, MFRVs, and Bypass Valves B 3.7.3 SURVEILLANCE SR 3.7.3.1 REQUIREMENTS HBRSEP Unit No. 2 This SR verifies that the closure time of each MFRV and bypass valve is within limits (Ref. 4) on an actual or simulated actuation signal. The MFRV, and bypass valve closure times are assumed in the accident and containment analyses (Ref. 2). This Surveillance is normally performed upon returning the unit to operation following a refueling outage. These valves should not be tested at power since even a part stroke exercise increases the risk of a valve closure with the unit generating power. This is consistent with the ASME Code,Section XI (Ref. 3).

The Frequency for this SR is in accordance with the lnservice Testing Program. The specified Frequency for valve closure is based on the refueling cycle. Operating experience has shown that these components usually pass the Surveillance when performed at the specified Frequency.

SR 3.7.3.2 This SR verifies that the closure time of each MFIV is within limits (Ref. 4) on an actual or simulated actuation signal. The MFIV closure times are assumed in the accident and containment analyses (Ref. 2). This Surveillance is normally performed upon returning the unit to operation following a refueling outage. These valves should not be tested at power since even a part stroke exercise increases the risk of a valve closure with the unit generating power. This is consistent with the ASME Code,Section XI (Ref. 3).

The Frequency for this SR is in accordance with the lnservice Testing Program. The specified Frequency for valve closure is based on the refueling cycle. Operating experience has shown that these components usually pass the Surveillance when performed at the specified Frequency.

(continued)

B 3.7-19 Revision No. 63

BASES (continued)

REFERENCES HBRSEP Unit No. 2

1.

UFSAR, Section 10.4.6.

2.

UFSAR, Chapter 15.

MFIVs, MFRVs, and Bypass Valves B 3.7.3

3.

ASME, Boiler and Pressure Vessel Code,Section XI.

4.

TRM, Section 4.0 B 3.7-20 Revision No. 63

BASES Diesel Fuel Oil and Starting Air B 3.8.3 SURVEILLANCE SR 3.8.3.1 (continued)

REQURIEMENTS HBRSEP Unit No. 2 The 7 day Frequency is adequate to ensure that a sufficient supply of fuel oil is available, since low level alarms are provided for the U2 DG fuel oil tank and unit operators would be aware of any large uses of fuel oil during this period.

SR 3.8.3.2 The tests listed in the Diesel Fuel Oil Testing Program (API or Specific Gravity, Cloud Point, Water and Sediment, and Viscosity) are a means of determining whether fuel oil is of the appropriate grade and has not been contaminated with substances that would have an immediate, detrimental impact on diesel engine combustion. If results from these tests are within acceptable limits, the fuel oil is acceptable for use. New fuel oil received for storage in the Unit 1 1-C turbine fuel oil storage tank and subsequently transferred to the Unit 2 DG fuel oil storage tank is verified to meet the limits below prior to adding to the Unit 1 1-C storage tanks either by verifying the integrity of the seal on the tank truck against the certificate of compliance or by testing of the fuel oil on the truck prior to transfer.

Additionally, stored fuel in the Unit 1 1-C storage tank and in the Unit 2 DG fuel oil storage tank is tested every 31 days. The sampling methodology, tests, and limits are as follows:

a.

Sampling of three vertical IC Turbine tanks is performed as a single entity by recirculating the tanks and sampling at the Unit 1 transfer pump discharge. Sampling of the remaining vertical Unit 1 tank is performed independently from the bottom drain connection. Sampling of the Unit 2 DG fuel oil storage tank is performed from the discharge from the fuel oil storage tank transfer pump (Ref.3); and

b.

Verify in accordance with applicable ASTM standards that the sample has an API gravity of~ 28, a Saybolt viscosity at 100°F of

~ 32 SUS and s 50 SUS, water and sediment s 0.10%, and cloud point s 10°F.

Failure to meet any of the limits except cloud point is cause for rejecting the fuel oil. Cloud point will be managed by the Diesel Fuel Oil Testing Program.

(continued)

B 3.8-36 Revision No. 65