ML23226A186
| ML23226A186 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 08/10/2023 |
| From: | James Holloway Virginia Electric & Power Co (VEPCO) |
| To: | Office of Nuclear Reactor Regulation, Document Control Desk |
| References | |
| 23-154 | |
| Download: ML23226A186 (1) | |
Text
VIRGINIA ELECTRIC AND P OWER COMPANY RICH M O ND, V IRGIN IA 23261 August10,2023 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION UNITS 1 AND 2 PROPOSED LICENSE AMENDMENT REQUEST 10 CFR 50.90 Serial No.:
NRA/GDM:
Docket Nos.:
License Nos.:
23-154 RO 50-280 50-281 DPR-32 DPR-37 RECLASSIFICATION OF REGULATORY GUIDE 1.97 VARIABLE FOR LOW HEAD SAFETY INJECTION FLOW INSTRUMENTATION Pursuant to 10 CFR 50.90, Virginia Electric and Power Company (Dominion Energy Virginia) requests a change to the Technical Specifications (TS) for Surry Power Station (SPS) Units 1 and 2. The proposed change revises the SPS TS to add Low Head Safety Injection (LHSI) flow indication as required accident monitoring instrumentation. The addition of LHSI flow instrumentation to the TS is due to reclassification of the Regulatory Guide (RG) 1.97, Revision 3, "Criteria for Accident Monitoring Instrumentation for Nuclear Power Plants," variable from a Type D Category 2 variable to a Type A Category 1 variable. The reclassification of the LHSI flow instrumentation resulted from a reanalysis of the LHSI pumps' net positive suction head (NPSH) requirements that was performed to obtain additional operating margin. The reanalysis identified the need for manual operator action to throttle LHSI pump flow when only a single pump is in operation for a short period of time under certain accident conditions. This operating scenario identified the commensurate need to reclassify the existing RG 1.97 flow instrumentation and to incorporate the instrumentation into the Accident Monitoring TS. A conforming TS Basis change is also being made.
Dominion Energy Virginia has evaluated the proposed change and has determined it does not involve a significant hazards consideration as defined in 10 CFR 50.92. The basis for this determination is provided in Attachment 1. We have also determined that operation with the proposed change will not result in any significant increase in the amount of effluents that may be released off-site or any significant increase in individual or cumulative occupational radiation exposure. Therefore, the proposed amendment is eligible for categorical exclusion from an environmental assessment as set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment is needed in connection with the approval of the proposed change.
Serial No.23-154 Docket Nos. 50-280/281 Page 2 of 3 The proposed change has been reviewed and approved by the Facility Safety Review Committee. Dominion Energy Virginia requests approval of the proposed change by July 31, 2024, with a 60-day implementation period.
Should you have any questions or require additional information, please contact Mr. Gary D. Miller at (804) 273-2771.
Respectfully, James E. Holloway Vice President - Nuclear Engineering and Fleet Support Commitments contained in this letter: None Attachments:
- 1. Description and Assessment
- 2. Proposed Technical Specifications and Basis Pages (Marked-up)
- 3. Proposed Technical Specifications and Basis Pages (Typed)
COMMONWEAL TH OF VIRGINIA
)
)
COUNTY OF HENRICO
)
The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Mr. James E. Holloway, who is Vice President - Nuclear Engineering and Fleet Support, of Virginia Electric and Power Company. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that company, and that the statements in the document are true to the best of his knowledge and belief.
Acknowledged before me this Jo.f'h day of A:£,<Jt<,St
, 2023.
My Commission Expires:
12..{ "31 I z.y-CRAIG D SLY Notary Public...
Commonwealth of V1rgm1a Reg. # 7518653
~'I My Commission Expires December 31, 20-
cc:
U.S. Nuclear Regulatory Commission - Region II Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, GA 30303-1257 NRC Senior Resident Inspector Surry Power Station Mr. L. John Klos NRC Project Manager - Surry U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 09 E-3 11555 Rockville Pike Rockville, MD 20852-2738 Mr. G. Edward Miller NRC Senior Project Manager - North Anna U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 09 E-3 11555 Rockville Pike Rockville, MD 20852-2738 State Health Commissioner Virginia Department of Health James Madison Building - 7th floor 109 Governor Street Suite 730 Richmond, VA 23219 Serial No.23-154 Docket Nos. 50-280/281 Page 3 of 3 DESCRIPTION AND ASSESSMENT Virginia Electric and Power Company (Dominion Energy Virginia)
Surry Power Station Units 1 and 2 Serial No.23-154 Docket Nos. 50-280/281
DESCRIPTION AND ASSESSMENT 1.0
SUMMARY
DESCRIPTION Serial No.23-154 Docket Nos. 50-280/281 Pursuant to 10 CFR 50.90, Virginia Electric and Power Company (Dominion Energy Virginia) requests a change to the Technical Specifications (TS) for Surry Power Station (SPS) Units 1 and 2. The proposed change revises the SPS TS to add Low Head Safety Injection (LHSI) flow indication as required accident monitoring instrumentation. The addition of LHSI flow instrumentation to the TS is due to reclassification of the Regulatory Guide (RG) 1.97, Revision 3, "Criteria for Accident Monitoring Instrumentation for Nuclear Power Plants," variable from a Type D Category 2 variable to a Type A Category 1 variable. The reclassification of the LHSI flow instrumentation resulted from a reanalysis of the LHSI pumps' net positive suction head (NPSH) requirements that was performed to obtain additional operating margin. The reanalysis identified the need for manual operator action to throttle LHSI pump flow when only a single pump is in operation for a short period of time under certain accident conditions. This operating scenario identified the commensurate need to reclassify the existing RG 1.97 flow instrumentation and to incorporate the instrumentation into TS 3.7.E and Tables 3.7-6 and 4.1-2. A conforming TS 3.7 Basis change is also being made.
The proposed change has been reviewed with respect to 10 CFR 50.92, and it has been determined that no significant hazards consideration exists. In addition, it has been determined that the change qualifies for categorical exclusion from an environmental assessment as set forth in 10 CFR 51.22(c)(9); therefore, no environmental impact statement or environmental assessment is needed in connection with the approval of the proposed change.
2.0 DETAILED DESCRIPTION 2.1 System Design and Operation 2.1.1 Accident Monitoring Instrumentation The primary purpose of accident monitoring instrumentation is to display unit parameters that provide information required by the control room operators during and following accident conditions.
In response to NUREG-0737, "Clarification of TMI Action Plan Requirements," and RG 1.97, Revision 3, a programmatic approach was developed in defining the RG 1.97 required equipment for SPS. An SPS RG 1.97 program review examined existing instrumentation with respect to the RG 1.97 design and qualification requirements. The operability of RG 1.97 instrumentation ensures sufficient information is available on selected unit parameters to monitor and assess unit status and response during and following an accident. The availability of accident monitoring instrumentation Page 1 of 15
Serial No.23-154 Docket Nos. 50-280/281 ensures the results of corrective actions can be observed, and the need for any further actions can be determined.
RG 1.97 applies a graded approach to post-accident indication by using a matrix of variable types verses variable categories and delineating design and qualification criteria for the instrumentation used to measure five variable types (Types A, B, C, D, and E).
These criteria are divided into three separate categories (Categories 1, 2, and 3) providing a graded approach that depends on the importance to safety of the measurement of a specific variable.
RG 1.97 Variable Types Type A variables provide information essential for the direct accomplishment of specific safety functions that require manual action during design basis events (DBEs).
Specifically, Type A variables are those variables that provide the primary information required to permit the operating staff to:
Take specific planned manually-controlled actions for which no automatic control is provided and that are required for safety systems to perform their safety functions as assumed in the plant accident analysis licensing basis.
Take specific planned manually-controlled actions for which no automatic control is provided and that are required to mitigate the consequences of an anticipated operational occurrence (AOO) as assumed in the plant accident analysis licensing basis.
Type B variables are those variables that indicate whether plant safety functions are being accomplished.
Plant safety functions are: (1) reactivity control, (2) core cooling, (3) maintaining reactor coolant system integrity, and (4) maintaining containment integrity (including radioactive effluent control).
Type C variables provide indication of the potential for, or the actual breach of, the barriers to fission product release. These barriers are: (1) fuel cladding, (2) primary coolant pressure boundary, and (3) containment.
Type D variables provide indication of the operation of individual safety systems and other systems important to safety.
Type E variables are used for monitoring and determining the magnitude of the release of radioactive materials and for continuously assessing such releases.
RG 1.97 Variable Categories Consistent with NUREG-1431, "Improved Standard Technical Specifications -
Westinghouse Plants," (Specification 3.3.3 Bases addressing Post-Accident Monitoring Page 2 of 15
Serial No.23-154 Docket Nos. 50-280/281 Instrumentation), Category 1 variables are defined as the key variables deemed risk significant because they are needed to:
Determine whether other systems important to safety are performing their intended functions, Provide information to the operators that will enable them to determine the likelihood of a gross breach of the barriers to radioactivity release, and Provide information regarding the release of radioactive materials to allow early indication of the need to initiate action necessary to protect the public and to estimate the magnitude of any impending threat.
The RG 1.97 criteria on redundancy requirements only apply to Category 1 variables and address single-failure criteria and supporting features, including power sources. RG 1.97 also allows that "Within each redundant division of a safety system, redundant monitoring channels are not needed except for steam generator level instrumentation in two-loop plants." Failure of the instrumentation, its supporting features, and/or its power source resulting in less than the required number of channels, requires entry into the required actions.
RG 1.97 Categories 2 and 3 variables are addressed in a licensee-controlled document and are defined as follows:
Category 2 variables provide less stringent requirements and generally apply to instrumentation designated for indicating system operating status.
Category 3 variables are the least stringent and are applied to backup and diagnostic instrumentation.
2.1.2 Low Head Safety Injection System The operation of the Safety Injection (SI) system during a loss of coolant accident (LOCA) can be divided into two distinct modes:
- 1. The injection mode - in which any reactivity increase following the postulated accident is terminated, initial cooling of the core is accomplished, and coolant lost from the primary system is replenished.
- 2. The recirculation mode - in which long-term core cooling is provided during the accident recovery period.
Two LHSI pumps are provided to deliver large quantities of borated water from the Refueling Water Storage Tank (RWST) to the Reactor Coolant System (RCS) when the RCS pressure falls below their shutoff head. These pumps are also used to recirculate Page 3 of 15
Serial No.23-154 Docket Nos. 50-280/281 water from the containment sump during the recirculation mode to the RCS to provide long-term core cooling. They also direct water to the suction of the High Head SI (HHSI) pumps during the recirculation mode of accident recovery to provide NPSH to the HHSI pumps.
2.2 Current Technical Specifications Requirements TS 3.7, "Instrumentation Systems," Item E, provides the requirements for accident instrumentation monitoring as follows:
E. Prior to the Reactor Coolant System temperature and pressure exceeding 350°F and 450 psig, respectively, the accident monitoring instrumentation listed in Table
- 3. 7-6 shall be OPERABLE in accordance with the following:
- 1. With one required channel inoperable, either restore the inoperable channel to OPERABLE status within 30 days or submit a report to the NRG within the next 14 days. The report shall outline the cause of inoperability and the plans and schedule for restoring the inoperable channel to OPERABLE status.
- 2. With two required channels inoperable, either:
- a. Restore an inoperable channel(s) to OPERABLE status within 7 days or initiate the preplanned alternate method of monitoring the appropriate function and submit a report to the NRG within the next 14 days. The report shall outline the preplanned alternate method of monitoring the function, the cause of inoperability, and the plans and schedule for restoring an inoperable channel to OPERABLE status.
- b. If no preplanned alternate method of monitoring the function is available, restore an inoperable channel(s) to OPERABLE status within 7 days or be 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 /> and be Jess than 350°F and 450 psig within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Accident Monitoring Instrumentation is included in TS Table 3.7-6, which lists each monitored function and its required number of operable channels.
Table 3.7-6 also includes a note stating that separate entry into Specification 3.7.E is allowed for each Function.
The surveillance requirements for Accident Monitoring Instrumentation are provided in TS 4.1, "Operational Safety Review," Table 4.1-2, "Accident Monitoring Instrumentation Surveillance Requirements."
Page 4 of 15
2.3 Reason for the Proposed Change Serial No.23-154 Docket Nos. 50-280/281 A reanalysis of LHSI pumps' (1/2-SI-P-1A/B) performance was performed to obtain additional NPSH margin for a brief period when Recirculation Mode Transfer (RMT) actuates IF only one LHSI pump is running. With only one pump running, when RMT occurs, pump flow increases to a point where the NPSH required is equal to or slightly exceeds NPSH available. With two pumps running, total SI flow is greater but individual LHSI pump flow is lower so the NPSH margin issue does not exist.
To resolve this issue, operator actions were developed to throttle the running LHSI pump's discharge motor operated valve (1/2-SI-MOV-X864A/X864B - See Figure 1) prior to RMT. This action increases the NPSH margin during the most limiting time. To perform this action, LHSI pump flow indication (1/2-SI-FT-X945/X946 - See Figure 1) is required since the operators would throttle to a pre-designated flow band. After verification that recirculation has been properly established, the LHSI discharge valve will be restored to its fully open position thus providing full pump flow to the core. During development of the design change to implement this change, it was identified that, since LHSI flow indication is now required in support of a manual operator action, the RG 1.97 designation of the installed flow instrumentation must be reclassified from a Type D Category 2 variable to a Type A Category 1 variable consistent with RG 1.97 guidance.
Accordingly, since RG 1.97 Type A Category 1 instrumentation is required to be included in the TS, the reclassified LHSI flow instrumentation must be addressed by TS 3. 7. E and added to TS Tables 3.7-6 and 4.1-2.
2.4 Description of the Proposed Change The TS associated with Accident Monitoring Instrumentation are included in TS Section 3.7, "Instrumentation Systems," and are specifically addressed in TS 3.7.E and TS Table 3.7-6, "Accident Monitoring Instrumentation. The surveillance requirements for Accident Monitoring Instrumentation are provided in TS 4.1, "Operational Safety Review,"
Table 4.1-2, "Accident Monitoring Instrumentation Surveillance Requirements."
The proposed change revises TS 3.7.E to specifically address LHSI flow instrumentation operability requirements and expands the accident monitoring instrumentation listed in TS Tables 3.7-6 and 4.1-2 to include a RG 1.97 Type A Category 1 variable for LHSI flow.
The following specific changes will be incorporated into the SPS Units 1 and 2 TS to reflect the reclassification of the LHSI flow indication from a Type D Category 2 variable to a Type A Category 1 variable consistent with RG 1.97 guidance.
The following note will be added to TS 3.7.E.1 to state the actions required by the TS are not applicable to an inoperable LHSI flow indication channel:
Note: The required action of 3. 7.E. 1 is not applicable to Low Head Safety Injection flow indication instrumentation.
Page 5 of 15
Serial No.23-154 Docket Nos. 50-280/281 A new TS 3.7.E.2 will be added that is only applicable to Low Head Safety Injection flow indication instrumentation as follows:
- 2. With one required Low Head Safety Injection flow indication channel inoperable, either restore the inoperable channel to OPERABLE status within 7 days or be 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 /> and be less than 350°F and 450 psig within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Existing TS 3.7.E.2 will be renumbered as 3.7.E.3.
Item 19, Low Head Safety Injection Flow, will be added to TS Table 3.7-6, "Accident Monitoring Instrumentation," with the required channels of "1 per train (e)."
Note (e) will be added to the table for Item 19 stating the following:
(e) One functional channel is required for an OPERABLE subsystem of Low Head Safety Injection.
The TS 3. 7 Basis will also be revised to add the following discussion associated with the LHSI flow indication instrumentation:
If a Low Head Safety Injection train is not OPERABLE, and the instrumentation for Low Head Safety Injection Flow for the opposite train is also not OPERABLE, then the opposite Low Head Safety Injection subsystem is no longer capable of performing its design function of requiring the pump discharge valve to be manually throttled based on flow indication and must therefore be declared INOPERABLE. This only applies if a redundant train of Low Head Safety Injection is INOPERABLE since the safety analyses only credit manual operator throttling of Low Head Safety Injection flow when one train is in operation prior to recirculation mode transfer. If throttling is not possible for the sole OPERABLE train, adequate Net Positive Suction Head cannot be guaranteed at the time of recirculation mode transfer. If two trains of Low Head Safety Injection are OPERABLE, then throttling is not necessary and flow indication is not required to meet the design functions of the Low Head Safety Injection system.
TS Table 4.1-2, "Accident Monitoring Instrumentation Surveillance Requirements," will be revised to add Item 19, "Low Head Safety Injection Flow."
The 7-day allowed outage time to restore an inoperable required LHSI flow indication channel to OPERABLE status is appropriate based on providing a reasonable time for the repair and the low probability of an event requiring accident monitoring instrument operation.
Page 6 of 15
Openll st.a Signal RWST 1i:uFrom LCV 1£\\f 11SC 1tSE SVC Sll'C BSSA ease 370 Serial No.23-154 Docket Nos. 50-280/281 Kot tags A
B C
Cavalin9 Venurio Co!di Lag*
,-;~::--1::ot---"T""""-Dt---l "
V I~
Cdcl 867D I A
- Sl/0 Legs
~
A I
865A I
B Sl/0 I
B65IC
!'tom AHR 8,
FIGURE 1 - SAFETY INJECTION SYSTEM Page 7 of 15
3.0 TECHNICAL EVALUATION
Serial No.23-154 Docket Nos. 50-280/281 Currently, the LHSI pump flow instruments are categorized as Type D Category 2 RG 1.97 variables. Type D variables are those variables that provide information to indicate the operation of individual safety systems and other systems important to safety.
Category 2 variables require less stringent instrument qualification requirements than Category 1 variables and don't require seismic qualification, redundancy, continuous display or a standby power source.
As previously discussed, reanalysis of LHSI pumps' performance was performed to obtain additional NPSH margin for a brief period when RMT actuates if only one LHSI pump is running. With only one pump running, when RMT occurs, pump flow increases to a point where the NPSH required is equal to or slightly exceeds NPSH available. With two pumps running, total SI flow is greater but individual LHSI pump flow is lower so the NPSH margin issue does not exist. Restoring NPSH margin to the LHSI pump requires throttling the operating LHSI pump discharge valve assuming a single-failure of the other train of LHSI. After verification that recirculation has been properly established, the LHSI discharge valve is restored to its fully open position thus providing full pump flow to the core. The methodology used to calculate NPSH is an NRG-approved methodology and qualifies as a safety analysis. While the manual operator action would only be necessary after a single-failure, the sequence is within the licensing and design basis of the plant and will be a planned, manually-controlled action for which no automatic control is provided. Therefore, following implementation of procedure changes to incorporate manual operator actions for throttling LHSI pump flow, the existing LHSI flow instrumentation will be reclassified from a Type D Category 2 variable to a Type A Category 1 variable.
The SPS RG 1.97 program references standard technical specifications (NUREG-1431) for the definition of category types. Per Volume 2 (Bases) of NUREG-1431, Category 1 variables are the key variables deemed risk significant because they are needed to:
Determine whether other systems important to safety are performing their intended functions, Provide information to the operators that will enable them to determine the likelihood of a gross breach of the barriers to radioactivity release, and Provide information regarding the release of radioactive materials to allow for early indication of the need to initiate action necessary to protect the public, and to estimate the magnitude of any impending threat.
In this case, the first bullet is met since flow indication is necessary to ensure the throttling action has been completed and the running LHSI pump continues to perform its intended function.
Page 8 of 15
Serial No.23-154 Docket Nos. 50-280/281 Per the requirements of RG 1.97, a Type A Category 1 component requires redundant or diverse indication. However, as noted above, RG 1.97 states that "Within each redundant division of a safety system, redundant monitoring channels are not needed except for steam generator level instrumentation in two-loop plants."
The existing LHSI instrumentation satisfies this requirement since a flow instrument is currently provided for each LHSI subsystem. Therefore, the redundancy requirement of RG 1.97 can be met with the existing instrumentation. Furthermore, when the need for the instrumentation
- arises, a single-failure has already
- occurred, i.e.,
one train of LHSI is inoperable. Consequently, a second failure of the redundant LHSI train does not have to be considered, and the flow instrument can be assumed available for the licensing basis action to throttle LHSI flow after a failure of the other LHSI train.
Nevertheless, since the LHSI flow instrumentation is required to be reclassified from a RG 1.97 Type D Category 2 variable to a Type A Category 1 variable based upon its importance in performing a manual operator action, it must be included in the TS with the commensurate operability and surveillance requirements. Therefore, the reclassified RG 1.97 Type A Category 1 LHSI flow instrumentation is being addressed in TS 3.7.E and included in TS Table 3.7-6, "Accident Monitoring Instrumentation," and TS Table 4.1 -2, "Accident Monitoring Instrumentation Surveillance Requirements," accordingly.
4.0 REGULATORY EVALUATION
4.1 Applicable Regulatory Requirements and Criteria Section 182a of the Atomic Energy Act requires applicants for nuclear power plant operating licenses to include Technical Specifications (TS) as part of the operating license.
The TS ensure the operational capability of structures, systems, and components that are required to protect the health and safety of the public.
10 CFR 50.36, Technical Specifications. requires TS to include items in the following specific categories: (1) safety limits, limiting safety system settings, and limiting control settings; (2) limiting conditions for operation; (3) surveillance requirements per 10 CFR 50.36(c)(3); (4) design features; and (5) administrative controls. Section (c)(2)(ii)(C) requires that "A structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier
have a "technical specification limiting condition for operation." Operability requirements for Accident Monitoring Instrumentation are prescribed in SPS Units 1 and 2 TS Section 3.7, "Instrumentation Systems," and are specifically addressed in TS 3.7.E and TS Table
- 3. 7-6, "Accident Monitoring Instrumentation.
Surveillance requirements for Accident Monitoring Instrumentation are contained in TS Section 4.1, "Operational Safety Review,"
Table 4.1-2, "Accident Monitoring Instrumentation Surveillance Requirements."
Page 9 of 15
Serial No.23-154 Docket Nos. 50-280/281 1 O CFR 50.90 requires NRC approval for any modification to, addition to, or deletion from the plant TS. Therefore, this activity requires NRC approval prior to making the proposed plant-specific change included in this license amendment request.
10 CFR 50 Appendix A, General Design Criteria - The regulations in Appendix A to Title 10 of the Code of Federal Regulations (10 CFR) Part 50 establish minimum principal design criteria for water-cooled nuclear power plants. The General Design Criteria (GDC) included in Appendix A to 10 CFR Part 50 did not become effective until May 21, 1971.
The Construction Permits for SPS Units 1 and 2 were issued prior to May 21, 1971; consequently, SPS Units 1 and 2 were not subject to GDC requirements. (Reference SECY-92-223 dated September 18, 1992.) Regardless, GDC 35 reflects the design basis for the LHSI system with respect to decay heat removal. GDC 35 specifies, in part, that the system safety function shall be to transfer heat from the reactor core following any loss of reactor coolant at a rate such that (1) fuel and clad damage that could interfere with continued effective core cooling is prevented and (2) clad metal-water reaction is limited to negligible amounts. GDC 35 specifies that suitable redundancy in components and features, interconnections, and isolation capabilities shall be provided. The SPS Units 1 and 2 LHSI system, including flow instrumentation, effectively implements these requirements.
10 CFR 50 Appendix B and the licensee quality assurance program establish quality assurance requirements for the design, manufacture, construction, and operation of structures, systems, and components. Quality assurance criteria provided in 10 CFR Part 50, Appendix B, that apply to the systems and components pertinent to the proposed change include: Criteria Ill, V, XI, XVI, and XVII. Criteria Ill and V require measures to ensure that applicable regulatory requirements and the design basis, as defined in 10 CFR 50.2, "Definitions," and as specified in the license application, are correctly translated into controlled specifications, drawings, procedures, and instructions. Criterion XI requires a test program to ensure that the subject systems will perform satisfactorily in service and requires that test results shall be documented and evaluated to ensure that test requirements have been satisfied. Criterion XVI requires measures to ensure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances, are promptly identified and corrected, and that significant conditions adverse to quality are documented and reported to management. Criterion XVII requires maintenance of records of activities affecting quality.
The Dominion Energy Quality Assurance Program is described in Topical Report DOM-QA-1, "Dominion Nuclear Facility Quality Assurance Program Description (QAPD)." This topical report provides the QAPD for SPS Units 1 and 2. The Dominion QAPD conforms to applicable regulatory requirements, such as 10 CFR 50, Appendix B, and approved industry standards, including equivalent alternatives, where identified. This program applies to activities during design, construction, and operation, as well as siting. The Dominion QAPD describes how 10 CFR 50, Appendix B, requirements are met.
Page 10 of 15
Serial No.23-154 Docket Nos. 50-280/281 Regulatory Guide (RG) 1.97, Revision 3, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," gives criteria for Type A variables as "... those variables that provide primary information needed to permit the control room operating personnel to take the specified manually controlled actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for design basis accident events." LHSI flow indication will meet the definition of Type A to address the need for manual operator action to throttle LHSI pump flow when only a single pump is in operation for a short period of time under certain accident conditions.
4.2 No Significant Hazards Consideration In accordance with 10 CFR 50.90, Virginia Electric and Power Company (Dominion Energy Virginia) proposes a change to the Technical Specifications (TS) for Surry Power Station (SPS) Units 1 and 2. The proposed change revises the SPS TS to add Low Head Safety Injection (LHSI) flow indication as required accident monitoring instrumentation.
The addition of LHSI flow instrumentation to the TS is due to reclassification of the Regulatory Guide (RG) 1.97, Revision 3, "Criteria for Accident Monitoring Instrumentation for Nuclear Power Plants," variable from a Type D Category 2 variable to a Type A Category 1 variable. The reclassification of the LHSI flow instrumentation resulted from a reanalysis of the LHSI pumps' net positive suction head (NPSH) requirements that was performed to obtain additional operating margin. The reanalysis identified the need for manual operator action to throttle LHSI pump flow when only a single pump is in operation for a short period of time under certain accident conditions. This operating scenario identified the commensurate need to reclassify the existing RG 1.97 flow instrumentation and to incorporate it into the accident monitoring instrumentation TS.
In accordance with the criteria set forth in 10 CFR 50.92, Virginia Electric and Power Company (Dominion Energy Virginia) has performed an analysis of the proposed TS change and concluded that it does not represent a significant hazards consideration. The following discussion is provided in support of this conclusion:
- 1. Does the proposed license amendment involve a significant increase in the probability or consequences of an accident previously evaluated?
Response: No.
The proposed change adds operability requirements and expands the instrumentation listings in the TS to include a RG 1.97 Type A Category 1 variable for LHSI flow. The requirement for LHSI flow instrumentation to be operable will continue to ensure that sufficient information is available to plant operators to monitor and assess LHSI status and response during and following an accident. Accident monitoring instrumentation is not an initiator of any accident previously evaluated and will not affect accident initiators or precursors or alter the design, conditions, or configuration of the facility Page 11 of 15
Serial No.23-154 Docket Nos. 50-280/281 with respect to such initiators or precursors. Consequently, the proposed change does not involve a significant increase in the probability of an accident previously evaluated.
The proposed change does not significantly change how the plant would mitigate an accident previously evaluated, and no physical plant modifications are being made.
With the changes to TS 3.7 and 4.1, the consequences of an accident would be the same since adequate and monitored LHSI cooling flow continues to be provided for accidents previously evaluated.
Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.
- 2. Does the proposed license amendment create the possibility of a new or different kind of accident from any accident previously evaluated?
Response: No.
The proposed change adds operability requirements and expands the instrumentation listings in the TS to include a RG 1.97 Type A Category 1 variable for LHSI flow. The proposed change enhances the capability of the LHSI flow instrumentation to provide post-accident data for plant operator use. The accident monitoring instrumentation initiates no automatic action, and there is no change in the likelihood that the instrumentation will fail since surveillance tests will be performed. The proposed change will not affect the normal method of plant operation or change any operating parameters. In addition, no equipment performance requirements will be affected, and no physical plant modifications are being made. Also, no new accident scenarios, transient precursors, failure mechanisms, or limiting single failures will be introduced by this amendment. There will be no adverse effect or challenges imposed on any safety-related system because of the proposed change.
Therefore, the proposed change does not introduce any new failures that could create the possibility of a new or different kind of accident from any accident previously identified.
- 3. Does the proposed amendment involve a significant reduction in a margin of safety?
Response: No.
The proposed change does not adversely affect any current plant safety margins or the reliability of the equipment assumed in the safety analysis. Safety limits, limiting safety system settings, and limiting conditions for operation are not being altered in a manner that would adversely affect plant safety as a result of the proposed change.
Accident monitoring instrumentation has been screened out of the probabilistic risk analysis (PRA) model due to its low risk significance, so the proposed change has no Page 12 of 15
Serial No.23-154 Docket Nos. 50-280/281 risk impact from a PRA perspective. The proposed change does not alter the condition or performance of equipment or systems used in accident mitigation or assumed in any accident analysis, and the safety analysis acceptance criteria are not impacted by this change.
Therefore, this proposed change does not involve a significant reduction in the margin of safety.
Based on the above, Dominion Energy Virginia concludes the proposed change presents no significant hazards consideration under the standards set forth in 10 CFR 50.92( c),
and, accordingly, a finding of "no significant hazards consideration" is justified.
4.3 Environmental Assessment The proposed change adds operability requirements to TS 3.7.E and revises TS Table 3.7-6, "Accident Monitoring Instrumentation," and TS Table 4.1-2, "Accident Monitoring Instrumentation Surveillance Requirements," to add Low Head Safety Injection (LHSI) flow indication due to reclassification of the Regulatory Guide (RG) 1.97, Revision 3, variable from a Type D Category 2 variable to a Type A Category 1 variable.
A review of the anticipated effects of the requested amendment has determined the requested amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9), in that:
(i)
The amendment involves no significant hazards consideration.
As described above, the proposed change to TS 3.7.E and Tables 3.7-6 and 4.1-2 does not involve a significant hazards consideration.
(ii)
There is no significant change in the types or significant increase in the amounts of any effluents that may be released offsite.
The proposed change is unrelated to any aspects of plant construction or operation that would introduce any changes to effluent types (e.g., effluents containing chemicals or biocides, sanitary system effluents, and other effluents) or affect any plant radiological or non-radiological effluent release quantities. The proposed amendment does not adversely impact any functions associated with containing, controlling, channeling, monitoring, or processing radioactive or non-radioactive materials, nor does it diminish the functionality of any design or operational features that are credited with controlling the release of effluents during plantoperation.
The types and quantities of expected plant effluents are not changed. No effluent release path is associated with this amendment. Neither radioactive nor non-radioactive material effluents are affected by this activity.
Furthermore, the proposed amendment does not diminish the functionality of any design or operational features that are credited with controlling the release of effluents during Page 13 of 15
Serial No.23-154 Docket Nos. 50-280/281 plant operation and no physical plant modifications are being made. Therefore, it is concluded that the proposed amendment does not involve a significant change in the types or a significant increase in the amounts of any effluents that may be released offsite.
(iii)
There is no significant increase in individual or cumulative occupation radiation exposure.
The proposed change addresses the reclassification of existing accident monitoring instrumentation and its incorporation into the TS for LHSI flow indication. As such, the proposed amendment does not affect plant radiation zones described in UFSAR Section 11 and controls under 10 CFR Part 20 preclude a significant increase in occupational radiation exposure. The proposed amendment does not adversely impact radiologically controlled zones.
Plant radiation zones, radiation controls established to satisfy 10 CFR Part 20 requirements, and expected amounts and types of radioactive materials are not affected by the proposed amendment. Therefore, individual and cumulative radiation exposures are not significantly affected by this change. Therefore, the proposed amendment does not involve a significant increase in individual or cumulative occupational radiation exposure.
Based on the above review of the proposed amendment, Dominion Energy Virginia has determined the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluents that may be released offsite, or (iii) a significant increase in the individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9).
Therefore, pursuant to 10 CFR 51.22(b), an environmental impact statement or environmental assessment of the proposed amendment is not required.
5.0 CONCLUSION
The proposed change revises TS 3.7.E, TS Table 3.7-6, "Accident Monitoring Instrumentation," and TS Table 4.1-2, "Accident Monitoring Instrumentation Surveillance Requirements," to add Low Head Safety Injection (LHSI) flow indication due to the reclassification of the Regulatory Guide (RG) 1.97, Revision 3, variable from a Type D Category 2 variable to a Type A Category 1 variable. The reclassification of the LHSI flow indication resulted from a reanalysis of the LHSI pumps' net positive suction head (NPSH) requirements that was performed to obtain additional operating margin. The reanalysis identified the need for manual operator action to throttle LHSI pump flow when only a single pump is in operation for a brief period under certain accident conditions.
This operating scenario identified the commensurate need to reclassify the existing RG 1.97 LHSI flow instruments from Type D Category 2 to Type A Category 1 and to incorporate the instrumentation into TS 3.7.E, and Tables 3.7-6 and 4.1-2.
Page 14 of 15
Serial No.23-154 Docket Nos. 50-280/281 Based on the above discussion, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.
Page 15 of 15 Serial No.23-154 Docket Nos. 50-280/281 PROPOSED TECHNICAL SPECIFICATIONS AND BASIS PAGES (MARKED-UP)
Virginia Electric and Power Company (Dominion Energy Virginia)
Surry Power Station Units 1 and 2
TS 3.7-2 10 29 09
- 2. With less than the minimum number of explosive gas monitoring instrumentation channels OPERABLE, take the action shown in Table 3.7-5(a). Exert best efforts to return the instruments to operable status within 30 days and, if unsuccessful, prepare and submit a Special Report to the Commission (Region II) to explain why the inoperability was not corrected in a timely manner.
E. Prior to the Reactor Coolant System temperature and pressure exceeding 350°F and 450 psig, respectively, the accident monitoring instrumentation listed in Table 3.7-6 shall be OPERABLE in accordance with the following:
- 1. With one required channel inoperable, either restore the inoperable channel to OPERABLE status within 30 days or submit a report to the NRC within the next 14 days. The report shall outline the cause of inoperability and the plans and schedule for restoring the inoperable channel to OPERABLE status.
!Insert 1 ~
- ~itbR:::q::n::::: i::::::;:; :~tb:~ERABLE status Mtbin 7 days or t.Jj initiate the preplanned alternate method of monitoring the appropriate function and submit a report to the NRC within the next 14 days. The report shall outline the preplanned alternate method of monitoring the function, the cause of inoperability, and the plans and schedule for restoring an inoperable channel to OPERABLE status.
- b.
If no preplanned alternate method of monitoring the function is available, restore an inoperable channel(s) to OPERABLE status within 7 days or be 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 /> and be less than 350°F and 450 psig within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
F. Two manual actuation trains of the Main Control Room/Emergency Switchgear Room (MCR/ESGR) Envelope Isolation Actuation Instrumentation shall be OPERABLE whenever:
Tavg (average Reactor Coolant System (RCS) temperature) exceeds 200°F, or During movement of irradiated fuel.
Note: Automatic actuation of the MCR/ESGR Envelope Isolation Actuation Instrumentation is addressed as part of the Safety Injection Instrument Operating Conditions included in TS Table 3.7-2, "Engineered Safeguards Action Instrument Operating Conditions," Functional Unit No. 1.
- 1. For unit operation when T avg exceeds 200°F:
- a.
With one train inoperable, isolate the MCR/ESGR envelope normal ventilation within seven (7) days or be in at least HOT SHUTDOWN within the next six (6) hours and be in 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. 266 llHd 265
INSERT 1 (TS 3.7.E)
Note: The required action of 3. 7. E. 1 is not applicable to Low Head Safety Injection flow indication instrumentation.
- 2. With one required Low Head Safety Injection flow indication channel inoperable, either restore the inoperable channel to OPERABLE status within 7 days or be 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 /> and be less than 350°F and 450 psig within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
- 1.
- 2.
- 3.
- 4.
- 5.
- 6.
- 7.
- 8.
- 9.
- 10.
- 11.
- 12.
- 13.
- 14.
- 15.
- 16.
TABLE3.7-6 ACCIDENT MONITORING INSTRUMENTATION TS 3.7-29 05 31 06 NOTE: Separate entry into Specification 3.7.Eis allowed for each Function.
Function Required Channels Auxiliary Feedwater Flow Inadequate Core Cooling
- a. Reactor Vessel Coolant Level
- b. Reactor Coolant System Subcooling Margin
- c. Core Exit Temperature Containment Pressure (Wide Range)
Containment Pressure Containment Sump Water Level (Wide Range)
Containment Area Radiation (High Range)
Power Range Neutron Flux Source Range Neutron Flux Reactor Coolant System (RCS) Hot Leg Temperature (Wide Range)
RCS Cold Leg Temperature (Wide Range)
RCS Pressure (Wide Range)
Penetration Flow Path Containment Isolation Valve Position Pressurizer Level Steam Generator (SG) Water Level (Wide Range)
SG Water Level (Narrow Range)
SG Pressure 2
2 2
2 (a) 2 2
2 2
2 (b) 2 (b) 2 2
2 2 per penetration flow path (c)(d) 2 2
2perSG
- 17. Emergency Condensate Storage Tank Level 2 perSG 2
- 19. Low Head Safety Injection Flow (a) A minimum of 2 core exit thermocouples per quadrant are required for the channel to be OPERABLE.
(b) This indication is provided by the Gammametric channels.
(c) Not required for isolation valves whose associated penetration is isolated by at least one closed and deactivated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured.
( d) Only one position indication channel is required for penetration flow paths with only one installed control room One functional channel is required for an OPERABLE subsystem of Low Head Safety Injection.
Amendment Nos. 247 tlfld 246
TS 3.7-8 05 31 06 The 30 day allowed outage time applies when one (or more) function(s) in Table 3.7-6 has one required channel that is inoperable. The 30 day allowed outage time to restore one inoperable required channel to OPERABLE status is appropriate considering the remaining channel is OPERABLE, the passive nature of the instrument (i.e., no automatic action is assumed to occur from this instrumentation), and the low probability of an event requiring accident monitoring instrumentation during this interval. The 7 day allowed outage time applies when one (or more) function(s) in Table 3.7-6 has two required channels that are inoperable. The 7 day allowed outage time to restore one of the two inoperable required channels to OPERABLE status is appropriate based on providing a reasonable time for the repair and the low probability of an event requiring accident monitoring instrument operation. Long-term operation with two required channels inoperable in a function and with an alternate indication is not acceptable because the alternate indication may not fully meet the performance qualification requirements applied to the accident monitoring instrumentation. Requiring restoration of one of the two inoperable channels limits the risk that the accident monitoring instrumentation function could be in a degraded condition should an accident occur. If there is no preplanned alternate, the 7 day allowed outage time is followed by a requirement to be 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 /> and be less than 350°F and 450 psig within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. If the 30 day allowed outage time or 7 day allowed outage time to restore an inoperable channel to OPERABLE status is exceeded and either a redundant channel or a preplanned alternate method of monitoring is OPERABLE, a report to the NRC within the next 14 days is required. The report to the NRC in lieu of a shutdown is appropriate because the instrument functional capability has not been lost and given the low likelihood of unit conditions that would require the information provided by the accident monitoring instrumentation.
Note that the Categories 2 and 3 RG 1.97 variables are addressed in a licensee controlled document and are defined as follows:
Category 2 - provides less stringent requirements and generally applies to instrumentation designated for indicating system operating status.
Category 3 - is the least stringent and is applied to backup and diagnostic
~
instrumentation.
Explosive Gas Monitoring Instrumentation is provided for monitoring (and controlling) the concentrations of potentially explosive gas mixtures in the Waste Gas Holdup System. The operability and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63 and 64 of Appendix A to 10 CPR Part 50.
Amendment Nos. 247 ftftcl 246 I
INSERT 2 (TS BASIS 3.7)
If a Low Head Safety Injection train is not OPERABLE, and the instrumentation for Low Head Safety Injection Flow for the opposite train is also not OPERABLE, then the opposite Low Head Safety Injection subsystem is no longer capable of performing its design function of requiring the pump discharge valve to be manually throttled based on flow indication and must therefore be declared INOPERABLE. This only applies if a redundant train of Low Head Safety Injection is INOPERABLE since the safety analyses only credit manual operator throttling of Low Head Safety Injection flow when one train is in operation prior to recirculation mode transfer. If throttling is not possible for the sole OPERABLE train, adequate Net Positive Suction Head cannot be guaranteed at the time of recirculation mode transfer. If two trains of Low Head Safety Injection are OPERABLE, then throttling is not necessary and flow indication is not required to meet the design functions of the Low Head Safety Injection system.
TABLE4.1-2 TS 4.1-9a 04 29 11 ACCIDENT MONITORJNG INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL INSTRUMENT CHECK(l) CALIBRATION
- 1.
Auxiliary Feedwater Flow SFCP SFCP
- 2.
Inadequate Core Cooling SFCP SFCP
- 3.
Containment Pressure (Wide Range)
SFCP SFCP
- 4.
Containment Pressure SFCP SFCP
- 5.
Containment Sump Water Level (Wide Range)
SFCP SFCP
- 6.
Containment Area Radiation (High Range)
SFCP SFCP
- 7.
Power Range Neutron Flux SFCP SFCP (2)
- 8.
Source Range Neutron Flux SFCP SFCP (2)
- 9.
Reactor Coolant System (RCS) Hot Leg Temperature (Wide SFCP SFCP Range)
- 10. RCS Cold Leg Temperature (Wide Range)
SFCP SFCP
- 11. RCS Pressure (Wide Range)
SFCP SFCP
- 12. Penetration Flow Path Containment Isolation Valve Position SFCP SFCP (3)
- 13. Pressurizer Level SFCP SFCP
- 14. Steam Generator (SG) Water Level (Wide Range)
SFCP SFCP
- 15. SG Water Level (Narrow Range)
SFCP SFCP
- 17. Emergency Condensate Storage Tank Level SFCP SFCP
- 19. Low Head Safety Injection Flow SFCP - Surveillance frequencies are specified in the Surveillance Frequency Control Program.
(1) Perform CHANNEL CHECK for each required instrumentation channel that is normally energized.
(2) Neutron detectors are excluded from CHANNEL CALIBRATION.
(3) Rather than CHANNEL CALIBRATION, this surveillance shall be an operational test, consisting of verification of operability of all devices in the channel.
Amendment Nos. 273 tmcl 272 Serial No.23-154 Docket Nos. 50-280/281 PROPOSED TECHNICAL SPECIFICATIONS AND BASIS PAGES (TYPED)
Virginia Electric and Power Company (Dominion Energy Virginia)
Surry Power Station Units 1 and 2
TS 3.7-2
- 2. With less than the minimum number of explosive gas monitoring instrumentation channels OPERABLE, take the action shown in Table 3.7-5(a). Exert best efforts to return the instruments to operable status within 30 days and, if unsuccessful, prepare and submit a Special Report to the Commission (Region II) to explain why the inoperability was not corrected in a timely manner.
E. Prior to the Reactor Coolant System temperature and pressure exceeding 350°F and 450 psig, respectively, the accident monitoring instrumentation listed in Table 3.7-6 shall be OPERABLE in accordance with the following:
- 1. With one required channel inoperable, either restore the inoperable channel to OPERABLE status within 30 days or submit a report to the NRC within the next 14 days. The report shall outline the cause of inoperability and the plans and schedule for restoring the inoperable channel to OPERABLE status.
Note: The required action of 3.7.E.l is not applicable to Low Head Safety Injection flow indication instrumentation.
- 2. With one required Low Head Safety Injection flow indication channel inoperable, either restore the inoperable channel to OPERABLE status within 7 days or be 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 /> and be less than 350°F and 450 psig within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
- 3. With two required channels inoperable, either:
- a.
Restore an inoperable channel(s) to OPERABLE status within 7 days or initiate the preplanned alternate method of monitoring the appropriate function and submit a report to the NRC within the next 14 days. The report shall outline the preplanned alternate method of monitoring the function, the cause of in operability, and the plans and schedule for restoring an inoperable channel to OPERABLE status.
- b.
If no preplanned alternate method of monitoring the function is available, restore an inoperable channel(s) to OPERABLE status within 7 days or be 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 /> and be less than 350°F and 450 psig within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
F. Two manual actuation trains of the Main Control Room/Emergency Switchgear Room (MCR/ESGR) Envelope Isolation Actuation Instrumentation shall be OPERABLE whenever:
Tavg (average Reactor Coolant System (RCS) temperature) exceeds 200°F, or During movement of irradiated fuel.
Amendment Nos.
TS 3.7-2a Note: Automatic actuation of the MCR/ESGR Envelope Isolation Actuation Instrumentation is addressed as part of the Safety Injection Instrument Operating Conditions included in TS Table 3.7-2, "Engineered Safeguards Action Instrument Operating Conditions," Functional Unit No. 1.
- 1. For unit operation when T avg exceeds 200°F:
- a.
With one train inoperable, isolate the MCR/ESGR envelope normal ventilation within seven (7) days or be in at least HOT SHUTDOWN within the next six (6) hours and be in 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.
TS 3.7-8 The 30 day allowed outage time applies when one (or more) function(s) in Table 3.7-6 has one required channel that is inoperable. The 30 day allowed outage time to restore one inoperable required channel to OPERABLE status is appropriate considering the remaining channel is OPERABLE, the passive nature of the instrument (i.e., no automatic action is assumed to occur from this instrumentation), and the low probability of an event requiring accident monitoring instrumentation during this interval. The 7 day allowed outage time applies when one (or more) function(s) in Table 3.7-6 has two required channels that are inoperable. The 7 day allowed outage time to restore one of the two inoperable required channels to OPERABLE status is appropriate based on providing a reasonable time for the repair and the low probability of an event requiring accident monitoring instrument operation. Long-term operation with two required channels inoperable in a function and with an alternate indication is not acceptable because the alternate indication may not fully meet the performance qualification requirements applied to the accident monitoring instrumentation. Requiring restoration of one of the two inoperable channels limits the risk that the accident monitoring instrumentation function could be in a degraded condition should an accident occur. If there is no preplanned alternate, the 7 day allowed outage time is followed by a requirement to be 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 /> and be less than 350°F and 450 psig within the following 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. If the 30 day allowed outage time or 7 day allowed outage time to restore an inoperable channel to OPERABLE status is exceeded and either a redundant channel or a preplanned alternate method of monitoring is OPERABLE, a report to the NRC within the next 14 days is required. The report to the NRC in lieu of a shutdown is appropriate because the instrument functional capability has not been lost and given the low likelihood of unit conditions that would require the information provided by the accident monitoring instrumentation.
Note that the Categories 2 and 3 RG 1.97 variables are addressed in a licensee controlled document and are defined as follows:
Category 2 - provides less stringent requirements and generally applies to instrumentation designated for indicating system operating status.
Category 3 - is the least stringent and is applied to backup and diagnostic instrumentation.
If a Low Head Safety Injection train is not OPERABLE, and the instrumentation for Low Head Safety Injection Flow for the opposite train is also not OPERABLE, then the opposite Low Head Safety Injection subsystem is no longer capable of performing its design function of requiring the pump discharge valve to be manually throttled based on flow indication and must therefore be declared INOPERABLE. This only applies if a redundant train of Low Head Safety Injection is INOPERABLE since the safety analyses only credit manual operator throttling of Low Head Safety Injection flow when one train Amendment Nos.
TS 3.7-8a is in operation prior to recirculation mode transfer. If throttling is not possible for the sole OPERABLE train, adequate Net Positive Suction Head cannot be guaranteed at the time of recirculation mode transfer. If two trains of Low Head Safety Injection are OPERABLE, then throttling is not necessary and flow indication is not required to meet the design functions of the Low Head Safety Injection system.
Explosive Gas Monitoring Instrumentation is provided for monitoring (and controlling) the concentrations of potentially explosive gas mixtures in the Waste Gas Holdup System. The operability and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63 and 64 of Appendix A to 10 CPR Part 50.
Amendment Nos.
TS 3.7-29 TABLE3.7-6 ACCIDENT MONITORING INSTRUMENTATION NOTE: Separate entry into Specification 3.7.E is allowed for each Function.
Function Required Channels
- 1.
- 2.
- 3.
Auxiliary Feedwater Flow Inadequate Core Cooling
- a. Reactor Vessel Coolant Level
- b. Reactor Coolant System Subcooling Margin
- c. Core Exit Temperature Containment Pressure (Wide Range)
- 4.
Containment Pressure
- 5.
Containment Sump Water Level (Wide Range)
- 6.
Containment Area Radiation (High Range)
- 7.
Power Range Neutron Flux
- 8.
Source Range Neutron Flux
- 9.
Reactor Coolant System (RCS) Hot Leg Temperature (Wide Range)
- 10. RCS Cold Leg Temperature (Wide Range)
- 11. RCS Pressure (Wide Range)
- 12. Penetration Flow Path Containment Isolation Valve Position
- 13. Pressurizer Level
- 14. Steam Generator (SG) Water Level (Wide Range)
- 15. SG Water Level (Narrow Range)
- 16. SG Pressure
- 17. Emergency Condensate Storage Tank Level
- 18. High Head Safety Injection Flow to Cold Leg
- 19. Low Head Safety Injection Flow 2
2 2
2 (a) 2 2
2 2
2 (b) 2 (b) 2 2
2 2 per penetration flow path ( c )( d) 2 2
2perSG 2perSG 2
2 1 per train (e)
(a) A minimum of 2 core ex.it thermocouples per quadrant are required for the channel to be OPERABLE.
(b) This indication is provided by the Gammametric channels.
(c) Not required for isolation valves whose associated penetration is isolated by at least one closed and deactivated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured.
(d) Only one position indication channel is required for penetration flow paths with only one installed control room indication channel.(e)
( e) One functional channel is required for an OPERABLE subsystem of Low Head Safety Injection.
Amendment Nos.
TS 3.7-29 TABLE3.7-6 ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL INSTRUMENT CHECK(l)
CALIBRATION
- 1.
Auxiliary Feedwater Flow SFCP SFCP
- 2.
Inadequate Core Cooling SFCP SFCP
- 3.
Containment Pressure (Wide Range)
SFCP SFCP
- 4.
Containment Pressure SFCP SFCP
- 5.
Containment Sump Water Level (Wide Range)
SFCP SFCP
- 6.
Containment Area Radiation (High Range)
SFCP SFCP
- 7.
Power Range Neutron Flux SFCP SFCP (2)
- 8.
Source Range Neutron Flux SFCP SFCP (2)
- 9.
Reactor Coolant System (RCS) Hot Leg Temperature (Wide SFCP SFCP Range)
- 10. RCS Cold Leg Temperature (Wide Range)
SFCP SFCP
- 11. RCS Pressure (Wide Range)
SFCP SFCP
- 12. Penetration Flow Path Containment Isolation Valve Position SFCP SFCP (3)
- 13. Pressurizer Level SFCP SFCP
- 14. Steam Generator (SG) Water Level (Wide Range)
SFCP SFCP
- 15. SG Water Level (Narrow Range)
SFCP SFCP
- 17. Emergency Condensate Storage Tank Level SFCP SFCP
- 18. High Head Safety Injection Flow to Cold Leg SFCP SFCP
- 19. Low Head Safety Injection Flow SFCP SFCP SFCP - Surveillance frequencies are specified in the Surveillance Frequency Control Program.
(1) Perform CHANNEL CHECK for each required instrumentation channel that is normally energized.
(2) Neutron detectors are excluded from CHANNEL CALIBRATION.
(3) Rather than CHANNEL CALIBRATION, this surveillance shall be an operational test, consisting of verification of operability of all devices in the channel.
Amendment Nos.