ML23286A037

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

ML23286A037
Person / Time
Site:	Surry
Issue date:	10/13/2023
From:	Grady C Virginia Electric & Power Co (VEPCO)
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
23-273
Download: ML23286A037 (1)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 October 13, 2023 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555 VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNITS 1 AND 2 Serial No.:

23-273 SPS-LIC/SCN: RO Docket Nos.:

50-280 50-281 License Nos.: DPR-32 DPR-37 ANNUAL SUBMITTAL OF TECHNICAL SPECIFICATIONS BASES CHANGES PURSUANT TO TECHNICAL SPECIFICATION 6.4.J Pursuant to Technical Specification 6.4.J, "Technical Specifications (TS) Bases Control Program," Dominion Energy Virginia hereby submits changes to the Bases of the Surry Power Station (SPS) TS implemented between October 1, 2022, and September 30, 2023.

Bases changes to the TS that were not previously submitted to the NRC as part of a License Amendment Request were reviewed and approved by the Facility Safety Review Committee (FSRC).

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 Updated Final Safety Analysis Report (UFSAR) or Bases that required Nuclear Regulatory Commission (NRC) prior approval pursuant to 10 CFR 50.59.

These changes have been incorporated into the SPS 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 0CFR50.90, were also reviewed and approved by the FSRC. 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 Attachment 3.

Serial No.23-273 Docket Nos. 50-280, 50-281 Page 2 of 3 If you have any questions regarding this transmittal, please contact Stephen C. Newman, Surry Power Station Licensing Group at {757) 365-3397.

Cathy Grady 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. Changed/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, GA 30303-1257 State Health Commissioner Virginia Department of Health James Madison Building - 7th Floor 109 Governor Street Room 730 Richmond, VA 23219 Mr. J. Klos NRC Project Manager-Surry Power Station U.S. Nuclear Regulatory Commission Mail Stop O 9E 3 One White Flint North 11555 Rockville Pike Rockville, MD 20852-2738 Mr. G. E. Miller NRC Senior Project Manager-North Anna Power Station U. S. Nuclear Regulatory Commission Mail Stop O 9E 3 One White Flint North 11555 Rockville Pike Rockville, MD 20852-2738 NRC Senior Resident Inspector Surry Power Station Serial No.23-273 Docket Nos. 50-280, 50-281 Page 3 of 3 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.23-273 Docket Nos. 50-280, 50-281 Page 2 of 2 Technical Specifications Basis (TSB)

Change Request Number 475 This TS Basis (TSB) change revised the Basis for TS 3.1.E to allow analytical verification of the Beginning of Life - Technical Specifications Moderator Temperature Coefficient (BOL-TS MTC) acceptance limit.

Summary of TS Bases Changes Associated with License Amendments Surry Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion Energy Virginia)

Amendment 309/309 Change Request Number 471 Serial No.23-273 Docket Nos. 50-280, 50-281 Page 2 of 2 The amendments and associated Bases changes revised TSs Section 3.6.1.2 by permanently extending the allowed outage time (i.e., completion time) from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 10 days for the opposite unit Auxiliary Feedwater (AFW) pump cross-connect capability specific to repair/replacement activities and when maintenance that would result in the inoperability of all three of the opposite unit's AFW pumps is being performed.

Amendment 311/311 Change Request Number 469 These amendments and associated Bases changes: 1) Revised the 1.0.X LEAKAGE Definition to no longer exclude pressure boundary leakage from identified leakage and delete the word "nonisolable," 2) Revised TS Section 3.1.C, "RCS Operational LEAKAGE/' to add a new condition to isolate pressure boundary leakage within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and, 3) Revised the associated TS Bases to incorporate conforming changes. These changes were consistent with TSTF-554.

Amendment 312/312 Change Request Number 443 These amendments and associated Bases changes revised Surry Technical Specifications (TS) 3.12E, "Rod Position Indication System and Bank Demand Position Indication System," to provide an alternative to frequent verification of rod position using the movable incore detectors.

Amendment 313/313 Change Request Number 411 These amendments and associated Bases changes deleted expired license conditions and TS that were previously included in the Surry Units 1 and 2 OLs and TS to support one-time plant modifications or initial implementation of plant programs. Administrative changes and correction of editorial errors were also addressed.

Changed/Current TS Bases Pages

[TS Bases pages 3.1-18, 3.6-5a, 3.6-5b, 3.6-5c, 3.1-13, 3.1-13a, 3.12-14, 3.12-14a, 3.16-7]

Surry Power Station Units 1 and 2 Virginia Electric and Power Company (Dominion Energy Virginia)

E.

Mininuun Temperature for Criticality Specifications Serial No.23-273 Docket Nos. 50-280, 50-281 Page 2 of 10 TS 3.1-18 11-16-22

1.

Except during LOW POWER PHYSICS TESTS, the reactor shall not be made critical at any Reactor Coolant System temperature above which the moderator temperature coefficient is more positive than the limit specified in the CORE OPERATING LHvllTS REPORT. The maximum upper limit for the moderator temperanue coefficient shall be:

a.

+ 6 pcm/°F at less than 50% of RATED POWER, or

b.

+ 6 pcm/°F at 50% of RATED POWER and linearly decreasing to O pcm/°F at RATED POWER

2.

In no case shall the reactor be made critical with die Reactor Coolant System temperature below the limiting value ofRTNDT + 10°F, where the limiting value of RT NDT is as detemiined in Part B of this specification.

3.

When the Reactor Coolant System temperanue is below the miui.tmuu temperature a.s specified in E-2 above, the reactor shall be subcritical by au amount equal to or greater than the potential reactivity i.t1sertion due to pri.tuary coolant depressurization.

4.

TI1e reactor shall not be made critical when the Reactor Coolant System temperature is below 538°F.

Basis During the early part of a fuel cycle, the moderator temperature coefficient may be calculated to be slightly positive at coolant temperatures in die power operating range. TI1e moderator temperan1re coefficient will be most positive near the beginni.t1g of cycle life, generally corresponding to when the boron concentration in the coolant is the greatest.

Later in the cycle, the boron concentration i.t1 the coolant will generally be lower and the moderator temperarure coefficient will be less positive or will be negative in the power operating range. At the beginning of cycle life, during pre-operational physics tests, measurements or analytical checks are used to verify that the moderator temperature coefficient is less than the limit specified in the CORE OPERATING LitvflTS REPORT.

Amendment Nos. Bases

Serial No.23-273 Docket Nos. 50-280, 50-281 Page 3 of 10 TS 3.6-5a 03-10-23 restore operability of one inoperable pump or of the inoperable component or instrumentati011 in one flowpath. With such a loss of auxiliary feedwater capability, the unit is in a seriously degraded conditi011. In this condition, the unit should not be perturbed by any action, including a power change, which could result in a plant transient or trip. The seriousness of this condition requires that action be taken immediately to restore operability, where immediately means the required action should be pursued without delay and in a controlled maw1er. Under these circU111Stances, Specification 3.0.1 and all other required actions directing mode changes are suspended m1til one inoperable pump or the inoperable component or instmmentation in one flowpath is restored to operable status, because taking those actions could place the rnut in a less safe condition.

Due to the occasional need to perfonu n1.1intenance on common AFW components that would render all three AFW pumps on the opposite 1u1it inoperable, e.g., the AFW pumps' full flow recirculation piping or the protected condensate storage ta1uc, a 10-day allowed outage time is provided for opposite unit AFW cross-connect capability. The 10-day allowed outage time is supported by a risk analysis that demonstrates the associated risk is acceptably small for both CDF and LERF with considerable 111.,rgin remaining. When entering the 10-day allowed outage time for the specific purpose of perfomung maintenance related to the operability of all three of the opposite rnut's auxiliary feedwater pumps, the following compe11satory measures are required to be in place:

• Additional AFW system 111.1it1tenance, including associated water sources, or changes in plant configuration d1at would result it1 a risk sigiuficant configuration will be precluded;

• Weather conditions will be monitored and AFW mait1tenance affecting operability of the opposite 1uut cross-com1ect will not be scheduled if severe weather conditions are anticipated;

• TI1e steam-driven AFW pump will be c011trolled as "Protected Equipment";

• The Technical Requirements M1nual compensatory actions to address 10 CFR 50.65 (a)(4) fire risk related to AFW cross-cow1ect ooavailability, which include periodic walkdowns in relevant fire areas, will be taken; and

• The BDBIFLEX AFW pwup will be pre-staged to provide AFW defense-in-depth comparable to the AFW cross-connect.

Amendment Nos. 309 and 309

Serial No.23-273 Docket Nos. 50-280, 50-281 Page 4 of 10 TS 3.6-Sb 03-10-23 In the event of complete loss of electrical power to the station, residual heat removal would continue to be assured by the availability of either the turbine driven :.mxiliary feemvater pmup or one of the motor driven auxiliary feedwater pumps and the 110,000-gallon protected condensate storage tank.

In the event of a fire or high energy line break which would render the auxiliary feedwater pumps inoperable on the affected unit, residual heat removal would continue to be assured by the availability of either the turbine driven auxiliary feedwater pump or one of the motor driven auxiliary feedwater pmnps from the opposite tuut. A mi.tummu of two auxiliary feedwater pumps are required to be operable* on the opposite m1it to em,ure compliance with the design basis accident analysis asstuuptions, in that auxiliary feedwater can be delivered via the cross-connect, even if a single active failure results in the loss of one of the two pumps. In addition, the requirement for operability of the opposite unit's emergency power system is to ensure that auxiliary feedwater from the opposite unit can be supplied via the cross-connect in the event of a common-mode failure of all auxiliary feedwater ptuups in the affected 1uut due to a high energy line break in the main steam valve house. Without tlus requirement, a single failure (such as loss of the shared backup diesel generator) could result in loss of power to the opposite unit's emergency buses in the event of a loss of offsite power, thereby rendering the cross-connect inoperable. TI1e longer allowed outage time for the opposite 1uut's emergency power system is based on the low probability of a high energy line break in the n1.'lit1 steam valve house coincident with a loss of oflsite power.

The specified nunitmuu water volume in tl1e 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 Mait1 in the auxiliary feedwater ptuup cubicle.

• excluding automatic initiation instnunentation Amendment Nos. 309 and 309

Serial No.23-273 Docket Nos. 50-280, 50-281 Page 5 of 10 TS 3.6-5c 03-10-23 The five main steam code safety vah es associated with each steam generator have a total combined capacity of 3,842,454 pom1ds per hour at their individual relieving pressure; the total combined capacity of all fifteen main steam code safety valves is 11,527,362 pom1ds 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.

TI1e 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.

TI1e 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 assmnes the release of the entire contents of the faulted steam generator to the atmosphere.

Amendment os. 309 and 309

C.

RCS Operational LEAKAGE Applicability Serial No.23-273 Docket Nos. 50-280, 50-281 Page 6 of 10 TS 3.1-13 05-01-23 The following specifications are applicable to RCS operational LEAKAGE whenever Tavg (average RCS temperature) exceeds 200°F (200 degrees Fahrenheit).

Specifications

1.

RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE,

b. 1 gpm unidentified LEAKAGE,

c. 10 gpm identified LEAKAGE, and

d. 150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG).

2.a. If pressure bowtdary LEAKAGE exists, isolate affected component, pipe, or vessel from the RCS by u.c,e of a closed manual valve, closed and de-activated automatic valve, blind flange, or check valve with.in 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

b. If the pressure. boundary LEAKAGE is not isolated as specified within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the unit shall be brought to 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 /> and COLD SHU1DOWN widiin the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

3.a. If RCS operational LEAKAGE is not within the limitc, of 3.1.C. l for reasons other than pressure bmmdary LEAKAGE or primary to secondary LEAKAGE, reduce LEAKAGE to witliin the specified limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

b. If the LEAKAGE is not reduced to within the specified limits witliin 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the tuut shall be brought to 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 /> and COLD SHU1DOWN witliin the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

4.

If primary to secondary LEAKAGE is not witliin the limit specified in 3.1.C. l.d, the unit shall be brought to HOT SHUTDOWN witliin 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and 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 />.

Amendment Nos. 311 and 311

Serial No.23-273 Docket Nos. 50-280, 50-281 Page 7 of 10 TS 3.1-13a 05-01-23

5.

Detected or suspected leakage. from the Reactor Coolant System shall be investigated and evaluated. At least two means shall be available to detect reactor coolaut system leakage. One of these means must depend on the detection of radionudides in the containment.

6.a. Prior to going critical all primary coolant system pressure isolation valves listed below shall be functional as a pressure isolation device, except as specified in 3.1.C.6.b. Valve leakage shall not exceed the amotwts indicated.

Loop A, Cold Leg Loop B, Cold Leg Loop C, Cold Leg Unit 1 l-SI-79, 1-SI-241 l-SI-82, l-SI-242 l-Sl-85, 1-$1-243 Unit 2 2-Sl-79, 2-SI-241 2-S1-82, 2-Sl-242 2-S1-85, 2-Sl-243 M.,x. Allowable Leakage (see note (a) below)

S 5.0 gpm for each valve

b. If Specification 3.1.C.6.a catlllot be met, an orderly shutdown shall be initiated and the reactor shall be in HOT SHUTDOWN widtin 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in COLD SHUIDOWN within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

(a)

1.

Leakage rates less than or equal to 1.0 gpm are considered acceptable.

2.

Leakage rates greater than 1.0 gpm but less d1au or equal to 5.0 gpm are considered acceptable if the latest measured rate has not exceeded the rate determined by d1e previous test by an amount that reduces the margin between measured leakage rate and die maximum pemussible rate of 5.0 gpm by 50% or greater.

3.

Leakage rates greater than 1.0 gpm but less dlall or equal to 5.0 gpm are considered unacceptable if the latest measured rate exceeded the rate determined by the previous test by au amount that reduces the margin between measured leakage rate and the maximum pernussible rate of 5.0 gpm by 50% or greater.

4.

Leakage rates greater than 5.0 gpm are considered unacceptable.

Amendment Nos. 311 and 311

Serial No.23-273 Docket Nos. 50-280, 50-281 Page 8 of 10 TS 3.12-14 05-09-23 rods i..11 a group all receive the same signal to move and should, therefore, all be at the same position indicated by the group step demand counter for that group. Tue Bank Demand Position Indication System is considered highly precise (+/- 2 steps).

Tue Rod Position Indication System provides an accurate indication of actual rod position, but at a lower precision than the group step demand counters. lb.is system is based on inductive analog signals from a series of coils spaced along a hollow tube. The Rod Position h1dication System is capable of monitoring rod position within at least +/- 12 steps during steady state temperature conditions and within +/- 24 steps during transient temperature conditions. Below 50% RATED POWER, a wider tolerance on indicated rod position for a maximum of one hour in every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is permitted to allow the system to reach the:nual equilibriUDL 1his thennal soak time is available both for a continuous one hour period or several discrete intervals as long as the total time does not exceed 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> in any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period and the indicated rod position does not exceed 24 steps from the group step demand counter position.

When a rod position indicator fails, the position of the rod can be verified by use of the movable incore detectors once every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> (TS 3.12.E.2.a). TS 3.12.E.2.b allows au alternate method of monitoring control rod position using the movable incore detector system on a less frequent periodicity (i.e., initial position verification within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and every 31 effective full power days (EFPDs) thereafter) and with additional verification perforn1ed following circumstances in which rod position may have changed or after significant changes in power level have occurred. One of these circumstances is unintended rod movement, which is defined as the release of a rod's stationary gripper when no action was demanded either manually or automatically from the rod control system. Verification that no unintended rod movement occurred is perfonned by monitoring the rod control system stationary gripper coil current for indications of rod movement.

The 31 EFPDs verification frequency 1:u.inintizes excessive use of and increased wear on the movable incore monitoring system and accommodates concurrent performance with the existing TS 4.10 surveillance requirement for determination of hot channel factors. TS 3.12.E.2.c provides the alternative of reducing power to less than 50% of RA TED POWER within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

Amendment Nos. 312 and 312

Serial No.23-273 Docket Nos. 50-280, 50-281 Page 9 of 10 TS 3.12-14a 05-09-23 The requirements on the rod position indicators and the group step demand counters are only applicable from the movement of control banks to achieve criticality and with the REACTOR CRITICAL, because these are the only conditions in which the rods can affect core power distribution and in which the rods are relied upon to provide required shutdown margin. The various action statement time requirements are based on operating experience and reflect the significance of the circumstances with respect to verification of rod position and potential rod misaligmuent. Reduction of RATED POWER to less than or equal to 50% puts the core into a condition where rod position is not significantly affecting core peaking factors. TI1erefore. during operation below 50% RATED POWER., no special monitoring is required. In the shutdown conditions, the operability of the shutdown banks and control banks has the potential to affect the required shutdmvn macgin, but this effect can be compensated for by an increase in the boron concentration of the Reactor Coolant System.

The specified control rod assembly dcop tin1e is conc,istent with safety analyses that have been perfonned.

An inoperable control rod assembly imposes additional demands on the operators. The pemussible number of inoperable control rod assemblies is linuted to one in order to linut the magnitude of the operating burden. but such a failure would not prevent dropping of the OPERABLE control rod assemblies upon reactor trip.

Amendment Nos. 312 and312

Serial No.23-273 Docket Nos. 50-280, 50-281 Page 10 of 10 TS 3.16-7 06-29-23 TS action statement 3.16.B.1.a.2 provides an allowance to avoid unnecessary testing of an OPERABLE EDG(s). If it can be detennined that the cause of an inoperable EDG does not exist on the OPERABLE EDG(s), operability testing doe..s not have to be perfonned. If the cause of the inoperability exists on the other EDG(s), d1en the other EDG(s) would be declared inoperable upon discovery, and the applicable required action(s) would be entered. Once the failure is repaired, the common cau.c,e failure no longer exists and the operability testing requirement for the OPERABLE EDG{s) is satisfied. If the cause of the initial inoperable EDG cannot be confim1ed not to exist on the remaining EDG(s),

performance of the operability test within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> provides assurance of continued operability of those EDG(s).

In the event the inoperable EDG is restored to OPERABLE status prior to completing the operability testing requirement for the OPERABLE EDG(s), the corrective action program will continue to evaluate the common cause possibility, including the od1er unit's EDG or the shared EDG. This continued evaluation, however, is no longer under the 24-hour constraint inlposed by the action statement.

According to Generic Letter 84-15 (Ref. 6), 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is reasonable to confirm that the OPERABLE EDG(s) is not affected by the same problem as the inoperable EDG.

References (1)

UFSAR Section 8.5 Emergency Power System (2)

UFSAR Section 9.3 Residual He.at Ren1oval System (3)

UFSAR Section 9.4 Component Cooling Systen1 (4)

UFSAR Section 10.3.2 Auxiliary Steam System (5)

UFSAR Section 10.3.5 Condensate and Feedwater System (6)

Generic Letter 84-15, "Proposed Staff Actions to lnlpfove and M-.intai.t1 Diesel Generator Reliability," elated July 2, 1984 Amendment Nos. 313 and 313