ML17293A028

Annual Submittal of Technical Specifications Bases Changes Pursuant to Technical Specification 6.4.J

ML17293A028
Person / Time
Site:	Surry
Issue date:	10/16/2017
From:	Rosenberger J Dominion Energy Virginia, Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
17-405
Download: ML17293A028 (20)

Text

. VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 October 1 $. 2017.,

• . :: ~

U.S. Nu~lear Regulatory.Commission Attention: Document 'control Desk Washington, D.C. 20555

':Serial Nfr

• 17-405 *.

. *'sf>s-LIC/CGL RO.

Docket Nos.

50-280 50-281

• • License Nos.

• DPR-32 DPR-37 VIRGINIA ELECTRIC AND POWER COMPANY.**

SURRY POWER STATION UNITS 1 AND 2.

• • ~.

ANNUAL SUBMITTAL OF TECHNICAL SPECIFICATIONS BASES CHANGES PURSUANT TO TECHNICAL SPECIFICATION 6.4.J Pursuant to Technical Specification 6.4.J; j'Technical Specificati~~s (TS) Bases Controi Program;';

Dominion Energy Virginia hereby. submits' changes to' the. ~ases: of the Su'rry TS, i.mplemerited between October 1, 2015 and September 30, 2017.' When i~itiatirlg this'letfer.. fcir the*2*01TAnnual Submittal of TS Bases Changes, it was discovered that the 2016 Annual Submittal of TS Bases Changes had n6tbeen transmitted to the NRG. Thus; the TS Bases*ch*~nges.implemented in 2016 (from 10/1i2015 to 9/30/2016) and in 2017 (from 10/1/2016 to 9/30/2017) are being reported in this letter. Appropriate corrective action is being taken to preclude recurrence.

~

Bases changes to the TS that were not previously submitted to the NRC as part of a License Amend~ent Request were reviewed and approved by the Facility Safety Review Committee. It was determined that the changes did not require a revision to the TS or operating licenses, nor did the changes involve a revision to the UFSAR or Bases that required NRC prior approval pursuant to 1 OCFR50.59. These changes have been incorporated into the TS Bases. A summary of these changes is provided in Attachment 1.

TS Bases changes that were submitted to the NRC for information along with associated License Amendment Request transmittals, submitted pursuant to 1 OCFR50.90, were also reviewed and approved by the Facility Safety Review Committee. These changes have been implemented with the respective License Amendments. A summary of these changes is provided in Attachment 2.

Current TS Bases pages reflecting the changes discussed in Attachments 1 and 2 are provided in.

If you have any questions regarding this transmittal, please contact Mrs. Candee G. Lovett at (757) 365-2178.

Very truly yours,

~~~~

Director Station Safety and Licensing Surry Power Station

Attachments:

1. Summary of TS Bases Changes Not Previously Submitted to the NRC

2. Summary of TS Bases Changes Associated with License Amendments

3. Current TS Bases Pages Commitments made in this letter: None.

cc:

U.S. Nuclear Regulatory Commission Region II Marquis One Tower 245 Peachtree Center Avenue NE Suite 1200 Atlanta, Georgia 30303-1257 State Health Commissioner Virginia Department of Health James Madison Building - ?1h Floor 109 Governor Street Room 730 Richmond, Virginia 23219 Ms. K. R. Cotton-Gross NRC Project Manager - Surry U. S. Nuclear Regulatory Commission Mail Stop 08 G-9A One White Flint North 11555 Rockville Pike Rockville, Maryland 20852-2738 Mr. James R. Hall NRC Senior Project Manager - North Anna U.S. Nuclear Regulatory Commission Mail Stop 08 G-9A One White Flint North 11555 Rockville Pike Rockville, Maryland 20852-2738 NRC Senior Resident Inspector Surry Power Station Serial No.17-405 Docket Nos. 50-280, 50-281 Page 2 of 2 Serial No.17-405 Summary of TS Bases Changes Not Previously Submitted to the NRC Surry Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion Energy Virginia)

Serial No.17-405 Docket Nos. 50-280, 50-281

SUMMARY

OF TS BASES CHANGES NOT PREVIOUSLY SUBMITTED TO THE NRC TS 3.6 and 4.1 Bases Revisions (TS Basis Pages TS 3.6-5b and TS 4.1-5a)

Revisions were made in the TS 3.6 and 4.1 Bases. The TS 3.6 Basis revision corrected an administrative error regarding a source term reference. The TS 4.1 Basis revision clarified conditions under which RCS flow testing shall be performed.

These Bases changes were approved on August 10, 2016 and implemented on September 14, 2016.

TS 3.0.1 Basis Revision (TS Basis Page TS 3.0-2)

A revision was made in the TS 3.0.1 Basis. The TS 3.0.1 Basis revision adopted wording from the Bases for Limiting Condition of Operation (LCO) 3.0.3 from NUREG-1431, (Improved) Standard Technical Specifications (ITS) for Westinghouse Plants, addressing entry into LCO 3.0.3 not being intended for operational convenience.

This Basis change was approved on February 24, 2017 and implemented on March 8, 2017.

TS 3.14 Basis Revision (TS Basis Pages TS 3.14-4 and TS 3.14-4a)

A revision was made in the TS 3.14 Basis. The TS 3.14 Basis revision defines the Service Water flow paths, the Charging Pump Service Water subsystem, and the Main Control Room/Emergency Switchgear Room Air Conditioning subsystem.

This TS 3.14 Basis revision is related to the TS 3.14 revision approved by TS Amendments 289/289 implemented on June 28, 2017.

These Bases changes were approved on July 14, 2017 and implemented on August 9, 2017.

Page 1 of 1 Serial No.17-405 Summary of TS Bases Changes Associated with License Amendments Surry Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion Energy Virginia)

Serial No.17-405 Docket Nos. 50-280, 50-281

SUMMARY

OF TS BASES CHANGES ASSOCIATED WITH LICENSE AMENDMENTS Addition of a Technical Specification Surveillance Requirement Related to Gas Accumulation (Generic Letter 2008-01) (TS Bases Pages TS 3.3-3, TS 3.4-4, TS 3.5-2, TS 4.11-4, and TS 4.11-4a)

These amendments revised the TSs by adding a TS surveillance requirement to verify the Safety Injection System locations susceptible to gas accumulation are sufficiently filled with water and to provide allowances which permit performance of the verification. This revision was made to address the concerns in Generic Letter 2008-01.

The associated Bases changes were included for information in a January 14, 2015 letter (Serial No.14-485).

These changes were incorporated into the Bases as part of the April 13, 2016 implementation of License Amendments 287/287 issued on February 29, 2016.

Expansion of Primary Grade Water Lockout Requirements in TS 3.2.E (TS Basis Page TS 3.2-5)

These amendments expanded the primary grade lockout requirements in TS 3.2.E from being applicable in refueling shutdown (RSD) and cold shutdown (CSD) modes to being applicable in RSD, CSD, intermediate shutdown, and hot shutdown modes, except during the approach to critical and within one hour following reactor shutdown from reactor critical or power operation.

The associated Basis change was included for information in a May 10, 2016 letter (Serial No.16-181 ).

These changes were incorporated into the Basis as part of the June 28, 2017 implementation of License Amendments 288/288 issued on May 10, 2017.

Extension of Allowed Outage Times in TS 3.14 (TS Basis Pages TS 3.14-3 and TS 3.14-4; TS Basis Page TS 3.14-4 was superseded by TS 3.14 Basis change implemented on August 9, 2017 - refer to Attachment 1)

These amendments revised TS 3.14 to extend the Allowed Outage Time for only one operable service water flow path to the Charging Pump Service Water subsystem and to the Main Control Room/Emergency Switchgear Room Air Conditioning subsystem from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The amendments also deleted the Operating License conditions and TS requirements for the expired temporary Service Water jumper to the Component Cooling Heat Exchangers.

Page 1 of 2

Serial No.17-405 Docket Nos. 50-280, 50-281 The associated Bases changes were included for information in a May 8, 2016 letter (Serial No.16-180).

These changes were incorporated into the Bases as part of the June 28, 2017 implementation of License Amendments 289/289 issued on May 31, 2017.

Extension of Allowed Outage Times for Emergency Service Water Pump lnoperability (TS Basis Page TS 3.14-3)

These amendments revised TS 3.14 to extend the Allowed Outage Time from 7 days to 14 days for one inoperable Emergency Service Water Pump (ESWP) to provide operational flexibility for ESWP maintenance and repairs.

The associated Basis change was included for information in a July 14, 2016 letter (Serial No.16-263).

This change was incorporated into the Basis as part of the September 20, 2017 implementation of License Amendments 290/290 issued on July 28, 2017.

Page 2 of 2 Serial No.17-405 Current TS Bases Pages Surry Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion Energy Virginia)

TS 3.0-2 02-24-17 violate the intent of the specification. For example, Specification 3.3 requires each Reactor Coolant System accumulator to be operable and provides explicit action requirements if one accumulator is inoperable. Under the terms of Specification 3.0.1, if more than one accumulator is inoperable, the unit is required to be in at least hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. As a further example, Specification 3.4 requires two Containment Spray Subsystems to be operable and provides explicit action requirements if one spray system is inoperable. Under the terms of Specification 3.0.1, if both of the required Containment Spray Subsystems are inoperable, the unit is required to be in at least hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in at least cold shutdown in the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. It is assumed that the unit is brought to the required condition within the required times by promptly initiating and carrying out the appropriate action.

Regarding action statements structured in the manner of TS 3.0.1 (i.e., in at least hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in at least cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />), the following application guidance is provided. The application of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to hot shutdown plus the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> to cold shutdown for a total of 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> from initial action statement entry is appropriate; thus, if 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> are used to attain hot shutdown, 33 hours3.819444e-4 days <br />0.00917 hours <br />5.456349e-5 weeks <br />1.25565e-5 months <br /> remain to attain cold shutdown. In addition, the time provided for achieving a reduction in operational mode is not applied if the inoperability is discovered in a lower operational mode; therefore, if an inoperable condition is discovered in hot shutdown, the 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided to achieve hot shutdown is not included in the total time to achieve cold shutdown (30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />).

Entry into Specification 3.0.1 is not intended to be used as an operational convenience that permits routine voluntary removal of redundant systems or components from service in lieu of other alternatives that would not result in redundant systems or components being inoperable.

3.0.2 This specification delineates what additional conditions must be satisfied to permit operation to continue, consistent with the actions for power sources, when a normal or emergency power source is not operable. It specifically prohibits operation when one division is inoperable because its normal or emergency power source is inoperable and a system, subsystem, train, component or device in another division is inoperable for another reason.

The provisions of this specification permits the action statements associated with individual systems, subsystems, trains, components and devices to be consistent with the action statements of the associated electrical power source. It allows operation to be governed by the time limits of the action statement associated with the Limiting Condition for Operation for the normal or emergency power source, not the individual action Amendment Nos. Bases

L___

TS 3.2-5 05-10-17 For one-unit operation, it is required to maintain available one charging pump with a source of borated water on the opposite unit, the associated piping and valving, and the associated instrumentation and controls in order to maintain the capability to cross-connect the two unit's charging pump discharge headers. In the event the operating unit's charging pumps become inoperable, this permits the opposite unit's charging pump to be used to bring the disabled unit to COLD SHUTDOWN conditions. Initially, the need for the charging pump cross-connect was identified during fire protection reviews.

The requirement that certain valves remain closed during REFUELING SHUTDOWN, COLD SHUTDOWN, INTERMEDIATE SHUTDOWN, and HOT SHUTDOWN conditions, except for planned boron dilution or makeup activities, provides assurance that a high flow rate inadvertent boron dilution will not occur. The lockout requirement is relaxed in HOT SHUTDOWN (TS 3.2.F) during the approach to critical and within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after reactor shutdown. This allows startup and shutdown activities to proceed without undue operator burden. This specification is not applicable in REACTOR CRITICAL or POWER OPERATION.

For purposes of Specification 3.2.F, 'approach to critical' is defined to be the operator controlled adjustment of RCS boron concentration or rod position with the intention of bringing the reactor critical.

References (1) UFSAR Section 9.1 Chemical and Volume Control System (2) UFSAR Section 14.2.5, Chemical and Volume Control System Malfunction Amendment Nos. 288 and 288

TS 3.3-3 02-29-16 maintenance provided that not more than one valve has power restored, and the testing and maintenance is completed and power removed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

3.

With one safety injection subsystem inoperable, restore the inoperable sub-system to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or place the reactor in HOT SHUTDOWN within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

C.

If the requirements of Specification 3.3.A are not satisfied as allowed by Specification 3.3.B, the reactor shall be placed in COLD SHUTDOWN in the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

Basis The normal procedure for starting the reactor is, first, to heat the reactor coolant to near operating temperature by running the reactor coolant pumps. The reactor is then made critical by withdrawing control rods and/or diluting boron in the coolant. With this mode of startup the Safety lh'jection System is required to be OPERABLE as specified. During LOW POWER PHYSICS TESTS there is a negligible amount of energy stored in the system. Therefore, an accident comparable in severity to the Design Basis Accident is not possible, and the full capacity of the Safety Injection System would not be necessary.

Management of gas voids is important to Safety Injection System operability. The OPERABLE status of the subsystems is to be demonstrated by periodic tests, detailed in TS Section 4.11. A large fraction of these tests are performed while the reactor is operating in the power range. If a subsystem is found to be inoperable, it will be possible in most cases to effect repairs and restore the subsystem to full operability within a relatively short time. A subsystem being inoperable does not negate the ability of the system to perform its function, but it reduces the redundancy provided in the reactor design and thereby limits the ability to tolerate additional subsystem failures. In some cases, additional components (i.e., charging pumps) are installed to allow a component to be inoperable without affecting system redundancy.

Amendment Nos. 287 and 287

TS 3.4-4 02-29-16 In addition to supplying water to the Containment Spray System, the refueling water storage tank is also a source of water for safety injection following an accident. This water is borated to a concentration which assures reactor shutdown by approximately 5 percent Lik/k when all control rods assemblies are inserted and when the reactor is cooled down for refueling.

Management of gas voids is important to the operability of the Spray Systems. Based on a review of system design information, including piping ancf instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations, as supplemented by system walk downs, the Containment Spray Subsystem, Inside Recirculation Spray Subsystem, and Outside Recirculation Spray Subsystem are not susceptible to gas intrusion. Once the piping in the Spray Systems is procedurally filled and placed in service for normal operation, no external sources of gas accumulation or intrusion have been identified for these systems that would affect spray system operation or performance.

Thus, the piping in the Spray Systems will remain sufficiently full during normal operation, and periodic monitoring for gas accumulation or intrusion is not required.

References (1)

UFSAR Section 4 (2)

UFSAR Section 5.4 (3)

UFSAR Section 6.3.1 (4)

UFSAR Section 14.5 Reactor Coolant System Containment Design Evaluation Spray System Loss of Coolant Accident Amendment Nos. 287 and 287

TS 3.5-2 02-29-16

1. One residual heat removal pump may be out of service, provided immediate attention is directed to making repairs.

2. One residual heat removal heat exchanger may be out of service, provided immediate attention is directed to making repairs.

Basis The Residual Heat Removal System is required to bring the Reactor Coolant System from conditions of approximately 350°F and pressures between 400 and 450 psig to cold shutdown conditions. Heat removal at greater temperatures is by the Steam and Power Conversion System.

The Residual Heat Removal System is provided with two pumps and two heat exchangers. If one of the two pumps and/or one of the two heat exchangers is not operative, safe operation of the unit is not affected; however, the time for cooldown to cold shutdown conditions is extended.

The NRC requires that the series motorized valves in the line connecting the RHRS and RCS be provided with pressure interlocks to prevent them from opening when the reactor coolant system is at pressure.

Management of gas voids is important to RHR System operability. Based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations, as supplemented by system walk downs, the RHR System is not susceptible to gas intrusion, except primarily from Safety Injection Accumulator line back leakage through the RHR discharge motor operated valves. If this condition were to occur, it would be identified and mitigated prior to placing the system in service. Once placed in service, RHR System velocities during normal cooldown are sufficient to sweep any gas voids that may have remained in local high points. Controlling RHR System operating flow rates, with the consideration to limiting inlet conditions and RCS level, prevents vortexing and air ingestion into the operating RHR pump and piping. Thus, the piping in the RHR System will remain sufficiently full of water during standby and normal system operation, and periodic monitoring for gas accumulation or intrusion is not required.

References FSAR Section 9.3 - Residual Heat Removal System Amendments Nos. 287 and 287

TS 3.6-5b 08-10-16 The specified minimum water volume in the 110,000-gallon protected condensate storage tank is sufficient for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of residual heat removal following a reactor trip and loss of all offsite electrical power. If the protected condensate storage tank level is reduced to 60,000 gallons, the immediately available replenishment water in the 300,000-gallon condensate tank can be gravity-fed to the protected tank if required for residual heat removal. An alternate supply of feedwater to the auxiliary feedwater pump suctions is also available from the Fire Protection System Main in the auxiliary feed water pump cubicle.

The five main steam code safety valves associated with each steam generator have a total combined capacity of 3,842,454 pounds per hour at their individual relieving pressure; the total combined capacity of all fifteen main steam code safety valves is 11,527,362 pounds per hour.

The maximum steam flow at full power is approximately 11,444,000 pounds per hour. The combined capacity of the safety valves required by Specification 3.6 always exceeds the total steam flow corresponding to the maximum steady state power than can be obtained during three reactor coolant loop operation.

The availability of the auxiliary feedwater pumps, the protected condensate storage tank, and the main steam line safety valves adequately assures that sufficient residual heat removal capability will be available when required.

The limit on steam generator secondary side iodine-131 activity is based on limiting the dose at the site boundary following a postulated steam line break accident to the Regulatory Guide 1.183 limits. The accident analysis assumes the release of the entire contents of the faulted steam generator to the atmosphere.

Amendment Nos. Bases

Basis TS 3.14-3 07-28-17 The Circulating and Service Water Systems are designed for the removal of heat resulting from the operation of various systems and components of either or both of the units.

Untreated water, supplied from the James River and stored in the high level intake canal is circulated by gravity through the recirculation spray coolers and the bearing cooling water heat exchangers and to the charging pumps lubricating oil cooler service water pumps which supply service water to the charging pump lube oil coolers.

In addition, the Circulating and Service Water Systems supply cooling water to the component cooling water heat exchangers and to the main control and emergency switchgear rooms air conditioning condensers. The Component Cooling heat exchangers are used during normal plant operations to cool various station components and when in shutdown to remove residual heat from the reactor. Component Cooling is not required on the accident unit during a loss-of-coolant accident. If the loss-of-coolant accident is coincident with a loss of off-site power, the nonaccident unit will be maintained at HOT SHUTDOWN with the ability to reach COLD SHUTDOWN.

The long term Service Water requirement for a loss-of-coolant accident in one unit with simultaneous loss-of-station power and the second unit being brought to HOT SHUTDOWN is greater than 15,000 gpm. Additional Service Water is necessary to bring the nonaccident unit to COLD SHUTDOWN. Three diesel driven Emergency Service Water pumps with a design capacity of 15,000 gpm each, are provided to supply water to the High Level Intake canal during a loss-of-station power incident. Thus, considering the single active failure of one pump, three Emergency Service Water pumps are required to be OPERABLE. The allowed outage time of 14 days provides operational flexibility to allow for repairs up to and Amendment Nos. 290 and 290

TS 3.14-4 07-14-17 including replacement of an Emergency Service Water pump without forcing dual unit outages, yet limits the amount of operating time without the specified number of pumps.

When one Unit is in Cold Shutdown and the heat load from the shutdown unit and spent fuel pool drops to less than 25 million BTU/HR, then one Emergency Service Water pump may be removed from service for the subsequent time that the unit remains in Cold Shutdown due to the reduced residual heat removal and hence component cooling requirements.

A minimum level of+ 17.2 feet in the High Level Intake canal is required to provide design flow of Service Water through the Recirculation Spray heat exchangers during a loss-of-coolant accident for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If the water level falls below +23' 6",

signals are generated to trip both unit's turbines and to close the nonessential Circulating and Service Water valves. A High Level Intake canal level of +23' 6" ensures actuation prior to canal level falling to elevation +23'. The Circulating Water and Service Water isolation valves which are required to close to conserve Intake Canal inventory are periodically verified to limit total leakage flow out of the Intake Canal. In addition, passive vacuum breakers are installed on the Circulating Water pump discharge lines to assure that a reverse siphon is not continued for canal levels less than +23 feet when Circulating Water pumps are de-energized. The remaining six feet of canal level is provided coincident with ESW pump operation as the required source of Service Water for heat loads following the Design Basis Accident.

Service Water Flow Paths to the Charging Pump Service Water Subsystem and to the Main Control Room/Emergency Switchgear Room Air Conditioning Subsystem As stated in Surry UFSAR Section 9.9.2, "Service water is supplied to the cooling water subsystem of the control room and relay room air conditioning system chiller condensers and to the charging pump service water subsystem from three separate circulating water lines through three independent flow paths. The three flow paths provide the operating flexibility to remove a flow path from service for cleaning without entering into a Technical Specification limiting condition for operation."

Charging Pump Service Water (CH SW) Subsystem - Service water is supplied to the CH SW subsystem located in Mechanical Equipment Room (MER) 3 and MER 4. The three 8-inch SW flow paths to the CH SW subsystem (referred to in UFSAR Section 9.9.2) are the lD, 2A, and 2C SW supply headers; two of the three 8-inch SW headers are normally in service. The three 8-inch headers supply SW to two 6-inch headers to MER 3 and. MER 4. The CH SW subsystem is comprised of the 6-inch piping and components Amendment Nos. Bases

TS 3.14-4a 07-14-17 downstream of the 8-inch SW header isolation valves supplying the CH SW pumps. The CH SW pumps provide cooling to the charging pump intermediate seal coolers and to the charging pump lubricating oil coolers.

Consistent with UFSAR Section 9.9.2, if one of the 8-inch SW headers is inoperable, no TS action statement is entered. If two of the 8-inch SW headers are inoperable, TS 3.14.C will be entered. If one of the two 6-inch headers to MER 3 or MER 4 is inoperable, TS 3.14.C will be entered for the CH SW subsystem because two of the three 8-inch headers are effectively rendered incapable of providing the required flow (without manual action).

Main Control Room/Emergency Switchgear Room Air Conditioning (MCR/ESGR AC)

Subsystem - Service water is supplied to the MCR/ESGR AC subsystem located in MER 3 and MER 5. The three 8-inch SW flow paths to the MCR/ESGR AC subsystem (referred to in UFSAR Section 9.9.2) are the ID, 2A, and 2C SW supply headers; two of the three 8-inch SW headers are normally in service. The three 8-inch headers supply SW to two 6-inch/4-inch headers to MER 3 and to two 6-inch lines to MER 5. The MCR/ESGR AC subsystem is comprised of the 6-inch piping, 4-inch piping, and components downstream of the 8-inch SW header isolation valves and downstream of the 6-inch MER 5 SW supply isolation valves. This SW supply is to the chiller pumps and chiller condensers.

Consistent with UFSAR Section 9.9.2, if one of the 8-inch SW headers is inoperable, no TS action statement is entered. If two of the 8-inch SW headers are inoperable, TS 3.14.C will be entered. If any of the 6-inch headers to MER*3 is inoperable, TS 3.23 will be reviewed to evaluate if an operable chiller combination exists. If one of the 6-inch lines to MER 5 is inoperable, no TS action statement is entered. If both of the 6-inch lines to MER 5 are inoperable, a TS 3.23.A.l.c 7-day TS action statement will be entered at a minimum, and TS 3.23 will be further reviewed. Significant defense in depth for the chillers and the flow paths to supply SW to the MER 3 and MER 5 chillers is available; however, manual action would be required to restore chiller operability.

References:

UFSAR Section 9.9 UFSAR Section 10.3.4 UFSAR Section 14.5 Service Water System Circulating Water System Loss-of-Coolant Accidents, Including the Design Basis Accident Amendment Nos. Bases

RCS Flow TS 4.1-Sa 08-10-16 This surveillance requirement in Table 4. l-2A is modified by a note that allows entry into POWER OPERATION, without having performed the surveillance, and placement of the unit in the best condition for performing the surveillance. The note states that the surveillance requirement is not required to be performed until 7 days after reaching a THERMAL POWER of_;::: 90% of RATED POWER (i.e.,

shall be performed within 7 days after reaching 90% of RATED POWER).

[

Reference:

NRC Safety Evaluation for License Amendments 270/269, issued October 19, 2010] The 7 day period after reaching 90% of RATED POWER is reasonable to establish stable operating conditions, install the test equipment, perform the test, and analyze the results. If reactor power is reduced below 90% of RATED POWER before completion of the RCS flow surveillance, the 7 day period shall be exited, and a separate 7 day period shall be entered when the required condition of reaching 90% of RATED POWER is subsequently achieved. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Amendment Nos. Bases

TS 4.11-4 02-29-16 The system tests demonstrate proper automatic op_eration of the Safety Injection (SI) System. A test signal is applied to initiate automatic operation action and verification is made that the components receive the safety injection signal in the proper sequence. The test may be performed with the pumps blocked from starting.

The test demonstrates the operation of the valves, pump circuit breakers, and automatic circuitry.

During reactor operation, the instrumentation which is depended on to initiate safety injection is checked periodically, and the initiating circuits are tested in accordance with Specification 4.1. In addition, the active components (pumps and valves) are to be periodically tested to check the operation of the starting circuits and to verify that the pumps are in satisfactory running order. The test interval is determined in accordance with the Inservice Testing Program. The accumulators are a passive safeguard.

ECCS piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation are necessary for proper operation of the ECCS and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.

Selection of SI System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review was supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configurations, such as stand-by versus operating conditions.

The SI System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations.

If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criterion for gas volume at the suction or discharge of a pump), the surveillance is not met. If it is determined by subsequent evaluation Amendment Nos. 287 and 287

TS 4.11-4a 02-29-16 that the SI System is not rendered inoperable by the accumulated gas (i.e., the system is sufficiently filled with water), the surveillance may be declared met.

Accumulated gas should be eliminated or brought within the acceptance criteria limits.

SI System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location.

Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations, alternative methods (e.g.,

operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system operability. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system operability during the surveillance interval.

System vent flow paths opened under administrative control are permitted to perform the surveillance. The administrative control will be appropriately documented (e.g., proceduralized) and will include stationing a dedicated individual at the system vent flow path who is in continuous communication with the operators in the control room. This individual will have a method to rapidly close the system vent flow path if directed.

The monitoring frequency takes into consideration the gradual nature of gas accumulation in the SI Subsystem piping and the procedural controls governing system operation and is controlled by the Surveillance Frequency Control Program.

The surveillance frequency may vary by each location's susceptibility to gas accumulation.

Periodic inspections of containment sump components ensure that the components are unrestricted and stay in proper operating condition. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

References UFSAR Section 6.2, Safety Injection System Amendment Nos. 287 and 287