Text

Application to Revise Technical Specifications to Adopt TSTF-582, 'Reactor Pressure Vessel Water Inventory Control (RPV WIC) Enhancements
	ML20268B348
Person / Time
Site:	Columbia
Issue date:	09/24/2020
From:	Schuetz R; Energy Northwest
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	GO2-20-095
	Download: ML20268B348 (73)
	v • d • e

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ENERGY R. E. Schuetz Columbia Generating Station P.O. Box 968, PE23 NORTHWEST Richland, WA 99352-0968 Ph. 509.377.2425 l F. 509.377.4150 reschuetz@energy-northwest.com September 24, 2020 GO2-20-095 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

COLUMBIA GENERATING STATION, DOCKET NO. 50-397 APPLICATION TO R EVISE TECHNICAL SPECIFICATIONS TO ADOPT TSTF-582, "REACTOR PRESSURE VESSEL WATER INVENTORY CONTROL (RPV WIC) ENHANCEMENTS"

Dear Sir or Madam:

Pursuant to 10 CFR 50.90, Energy Northwest is submitting a request for an amendment to the Technical Specifications (TS) for Columbia Generating Station (Columbia).

Energy Northwest requests adoption of TSTF 582, "Reactor Pressure Vessel Water Inventory Control (RPV WIC) Enhancements." The Technical Specifications (TS) related to RPV WIC are revised to incorporate operating experience and to correct errors and omissions in TSTF-542, Revision 2, "Reactor Pressure Vessel Water Inventory Control." Additionally, this Energy Northwest submittal includes removal of an expired note associated with the completion time of Required Action 3.5.1.A.1.

The enclosure provides a description and assessment of the proposed changes.

Attachment 1 provides the existing TS pages marked to show the proposed changes.

Attachment 2 provides revised (clean) TS pages. Attachment 3 provides the existing TS Bases pages marked to show revised text associated with the proposed TS changes and is provided for information only.

Energy Northwest requests that the amendment be reviewed under the Consolidated Line Item Improvement Process (CLIIP). Approval of the proposed amendment is requested by March 1, 2021. Once approved, the amendment shall be implemented at the beginning of the next refueling outage scheduled for May 2021.

There are no regulatory commitments made in this submittal.

In accordance with 10 CFR 50.91, a copy of this application, with attachments, is being provided to the designated Washington State Official.

If there are any questions or if additional information is needed, please contact Mr. R.

M. Garcia, Licensing Supervisor, at 509-377-8463.

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GO2-20-095 Page 2 of 2 I declare under penalty of perjury that the foregoing is true and correct.

Executed this ______ day of ___________,

2020.

Respectfully, R. E. Schuetz Site Vice President

Enclosure:

Description and Assessment Attachments: 1. Proposed Columbia Technical Specification Changes (Mark-Up)

2. Proposed Technical Specification Bases Markup Pages - For Information Only

3. Proposed Columbia Technical Specification Changes (Re-Typed) cc: NRC RIV Regional Administrator NRC NRR Project Manager NRC Senior Resident Inspector/988C CD Sonoda - BPA/1399 (email)

EFSECutc.wa.gov - EFSEC (email)

E Fordham - WDOH (email)

R Brice - WDOH (email)

L Albin - WDOH (email)

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GO2-20-095 Enclosure Page 1 of 10 DESCRIPTION AND ASSESSMENT

1.0 DESCRIPTION

Energy Northwest requests adoption of TSTF 582, "Reactor Pressure Vessel Water Inventory Control (RPV WIC) Enhancements." The Technical Specifications (TS) related to RPV WIC are revised to incorporate operating experience and to correct errors and omissions in TSTF-542, Revision 2, "Reactor Pressure Vessel Water Inventory Control."

2.0 ASSESSMENT 2.1 Applicability of Safety Evaluation Energy Northwest has reviewed the safety evaluation for TSTF-582 provided to the Technical Specifications Task Force in a letter dated August 13, 2020 (ADAMS Accession No. ML20219A333 and ML20219A317). This review included a review of the Nuclear Regulatory Commission (NRC) staffs evaluation, as well as the information provided in TSTF-582. As described herein, Energy Northwest has concluded that the justifications presented in TSTF-582 and the safety evaluation prepared by the NRC staff are applicable to Columbia Generating Station (Columbia) and justify this amendment for the incorporation of the changes to the Columbia Technical Specification (TS).

Energy Northwest verifies that the required emergency core cooling system (ECCS) injection/spray subsystem can be aligned and the pump started using relatively simple evolutions involving the manipulation of a small number of components. These actions can be performed in a short time (less than the minimum Drain Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ) from the control room following plant procedures.

2.2 Optional Changes and Variations 2.2.1 Administrative This section provides the administrative variations in either a table form or by specific TS section.

2.2.1.a The Columbia TS utilize different numbering and titles than the Standard Technical Specifications (STS) on which TSTF-582 was based. These differences are administrative and do not affect the applicability of TSTF-582 to the Columbia TS. See table below for a comparison of the Columbia nomenclature to that in NUREG-1434 and TSTF-582.

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GO2-20-095 Enclosure Page 2 of 10 NUREG-1434 / NUREG-1434 / Columbia Columbia TSTF-582 TSTF-582 Number Nomenclature Number Nomenclature TS Table 3.3.5.2-1 Reactor Steam Dome TS Table 3.3.5.2-1 Reactor Vessel Function 1.a Pressure - Low Function 1.a Pressure - Low (Injection Permissive) (Injection Permissive)

TS Table 3.3.5.2-1 [ LPCS Pump TS Table 3.3.5.2-1 LPCS Pump Function 1.b Discharge Flow - Low Function 1.b Discharge Flow - Low (Bypass) ] (Minimum Flow)

TS Table 3.3.5.2-1 [ LPCI Pump A TS Table 3.3.5.2-1 LPCI Pump A Function 1.c Discharge Flow - Low Function 1.c Discharge Flow - Low (Bypass) ] (Minimum Flow)

TS Table 3.3.5.2-1 Reactor Steam Dome TS Table 3.3.5.2-1 Reactor Vessel Function 2.a Pressure - Low Function 2.a Pressure - Low (Injection Permissive) (Injection Permissive)

TS Table 3.3.5.2-1 [ LPCI Pump B and TS Table 3.3.5.2-1 LPCI Pumps B & C Function 2.b LPCI Pump C Function 2.b Discharge Flow - Low Discharge Flow - Low (Minimum flow)

(Bypass) ]

TS Table 3.3.5.2-1 Reactor Vessel Water - Not Applicable n/a Function 3.a High, Level 8 (n/a)

TS Table 3.3.5.2-1 Condensate Storage TS Table 3.3.5.2-1 Condensate Storage Function 3.b Tank Level - Low Function 3.a Tank Level - Low TS Table 3.3.5.2-1 [ HPCS Pump n/a n/a Function 3.c Discharge Pressure -

High (Bypass) ]

TS Table 3.3.5.2-1 [ HPCS System Flow TS Table 3.3.5.2-1 HPCS System Flow Function 3.d Rate - Low (Bypass) ] Function 3.b Rate - Low (Minimum Flow)

TS Table 3.3.5.2-1 Manual Initiation n/a n/a Function 3.e TS Table 3.3.5.2-1 RHR System Isolation TS Table 3.3.5.2-1 Residual Heat Function 4 Function 4 Removal (RHR)

Shutdown Cooling (SDC) System Isolation 2.2.1.b TS 3.3.5.2

1) In NUREG-1434, Condition E is for Table 3.3.5.2-1 Function 3.a Reactor Vessel Water - High, Level 8. Columbia TS Table 3.3.5.2-1 does not contain this Function or the NUREG-1434 Condition E. This is an acceptable variation.

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GO2-20-095 Enclosure Page 3 of 10

2) NUREG-1434 Condition F is equivalent to Columbia TS Condition E. This is an acceptable variation.

3) NUREG-1434 Condition G is equivalent to Columbia TS Condition F. This is an acceptable variation.

4) The NUREG-1434 markup of note prior to the Surveillance Requirements (SRs) is being modified to exclude applicability of SR 3.3.5.2.1 for Function 2.a. The approved Columbia TSTF-542 license amendment identified under its technical variations that current plant design does not include indication to perform a channel check on Function 5.a (Function 2.a in TSTF-582 markup), Reactor Vessel Water Level - Low Low, Level 2.

This is an acceptable variation.

2.2.1.c TS 3.5.1

1) Columbia TS note already defined the acronym HPCS. This is an acceptable variation.

2) Columbia TS contains an expired note associated with Required Action A.1 completion time which is being deleted. This is an acceptable variation.

2.2.1.d TS 3.5.2

1) Columbia TS SR 3.5.2.6 contains a note Injection into the vessel is not required, which is not in the NUREG-1434 markup for TSTF-582. This note is being deleted as part of the Columbia markup and the TSTF-582 notes adopted which are more specific for not injecting into the vessel. This is an acceptable variation.

2) Columbia TS SR 3.5.2.6 does not contain the words through the recirculation line which is deleted in the NUREG-1434 markup for TSTF-582. This is an acceptable variation.

3) Columbia TS SR 3.5.2.8 wording Verify the required [low pressure core injection] LPCI or [low pressure core spray] LPCS subsystem actuates on a manual signal or the required HPCS subsystem can be manually operated, differs from NUREG-1434 wording Verify the required ECCS injection/spray subsystem actuates on a manual signal. The Columbia TSTF-582 markup will reflect the TSTF-582 markup wording. This is an acceptable variation.

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GO2-20-095 Enclosure Page 4 of 10 2.2.1.e TS 3.8.2

1) Columbia TS SR 3.8.2.1 does not contain the second note shown in the NUREG-1434 markup for TSTF-582. This is an acceptable variation.

2.2.2 Technical 2.2.2.a. TSTF-582, "RPV WIC Enhancements," states:

The ECCS injection/spray subsystem required to be operable by [limiting condition for operation] LCO 3.5.2 must be capable of being manually started as defense-in-depth against an unexpected draining event. The changes in TSTF-542 did not assume automatic actuation of the ECCS subsystem. TS 3.5.2, Required Action D.1 requires an additional method of water injection and that the required ECCS injection/spray subsystem or additional method of water injection shall be capable of operating without offsite electrical power. However, LCO 3.5.2 does not assume that the onsite electrical power source will start automatically on an ECCS or loss of power signal.

LCO 3.8.2, "AC Sources - Shutdown," requires one offsite circuit and one diesel generator to be operable in Modes 4 and 5. SR 3.8.2.1 lists the TS 3.8.1, "AC Sources - Operating," SRs that are applicable in Modes 4 and

5. In an oversight in TSTF-542, the TS 3.8.1 SRs that test automatic start and loading of a diesel generator on an ECCS or loss of offsite power signal were not excluded from SR 3.8.2.1.

TSTF-582 revises Technical Specification (TS) 3.8.2, "AC Sources -

Shutdown," Surveillance Requirement (SR) 3.8.2.1, to exclude SRs that verify the ability of the diesel generators to automatically start and load on an ECCS initiation signal or loss of offsite power signal.

The NRC Safety Evaluation for TSTF-582 (ADAMS Accession No. ML2021A9A333 and ML20219A317, dated, August 13, 2020), Section 3.6, "Alternating Current Sources - Shutdown, STS 3.8.2," states:

STS 3.5.2, Reactor Pressure Vessel Water Inventory Control (RPV WIC), does not require automatic ECCS initiation to mitigate a draining event in Modes 4 and 5, and the ECCS initiation signal related to the automatic ECCS initiation is removed from the STS. Because the automatic ECCS initiation and related ECCS initial signal in Modes 4 and 5 are eliminated, the automatic start of the DG on an ECCS initiation signal is not required in Modes 4 and 5. [T]he NRC staff finds that STS 3.5.2 provides enough time from the onset of the [loss of offsite power]

LOOP event for the operator to manually start the DG required to supply

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GO2-20-095 Enclosure Page 5 of 10 power to the water injection equipment to mitigate the draining event in Modes 4 and 5. In addition, STS 3.5.2 does not require the automatic initiation of the ECCS injection/spray subsystem or the additional method of water injection. Therefore, since STS 3.5.2 allows enough time to manually start the DG and the equipment for water injection, the NRC staff finds that the automatic start and loading of the DG are not necessary on a LOOP signal or LOOP concurrent with an ECCS initiation signal to mitigate a draining event in Modes 4 and 5.

Furthermore, the NRC staff notes that other events postulated in Modes 4 and 5 (e.g., fuel handling accident, waste gas tank rupture) and during movement of [recently] irradiated fuel assemblies in the [primary and secondary containment] do not assume a LOOP event or an automatic ECCS initiation.

TSTF-582 did not include all of the TS changes needed to reflect that TS 3.8.2 should not require automatic start and loading of a diesel generator within 15 seconds on an ECCS initiation signal or a loss of offsite power signal.

TS 3.3.8.1, "Loss of Power (LOP) Instrumentation," is applicable in Modes 1, 2, and 3, and when the associated diesel generator is required to be operable by TS 3.8.2. TSTF-582 revised TS 3.8.2 to no longer require automatic start and loading of a diesel generator on a loss of offsite power signal. Consequently, the LOP instrumentation that generates the loss of offsite power signal should not be required to be operable when the diesel generator is required to be operable by TS 3.8.2. The Applicability of LCO 3.3.8.1 is revised to not include the specified condition "When the associated diesel generator is required to be OPERABLE by LCO 3.8.2,

'[Alternating Current] AC Sources - Shutdown'."

TS SR 3.8.1.7 and SR 3.8.1.15 require that the DG starts from standby or hot conditions, respectively, and achieve required voltage and frequency within 15 seconds. The 15 second start requirement supports the assumptions in the design basis loss of coolant accident (LOCA) analysis.

This capability is not required during a manual diesel generator start to respond to a draining event, which has a minimum Drain Time of one hour. Therefore, SR 3.8.1.7 and SR 3.8.1.15 are added to the list of TS 3.8.1 SRs that are not applicable under SR 3.8.2.1.

TS SR 3.8.1.18 states, "Verify interval between each sequenced load block is within +/- 10% of design interval for time delay relay." TSTF-582 retained SR 3.8.1.18 as a test that must be met but not performed. The relay logic schemes that perform a function equivalent to a load sequencer are only used for the automatic start and loading of the diesel generator

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GO2-20-095 Enclosure Page 6 of 10 and are not used during a manual diesel generator start. Therefore, SR 3.8.1.18 is added to the list of TS 3.8.1 SRs that are not applicable under SR 3.8.2.1.

The TS 3.8.2 LCO Bases were not updated by TSTF-542 or TSTF-582 to reflect that automatic start and loading of a diesel generator is not required.

The LCO 3.8.2 and SR 3.8.2.1 Bases are revised to reflect the TS requirements. This variation provides consistency within the TS after incorporating the TSTF-582 changes to SR 3.8.2.1.

As an editorial improvement, SR 3.8.2.1 is revised to list the TS 3.8.1 SRs that are applicable instead of listing the TS 3.8.1 SRs that are not applicable. The SR 3.8.2.1 Bases are not affected and explain why the omitted TS 3.8.1 SRs are not applicable to TS 3.8.2.

These are acceptable variations.

2.3 Impact on Submittals under Review by NRC The NRC is presently reviewing the following Energy Northwests license amendment requests (LARs):

LAR to adopt TSTF-564 Safety Limit MCPR

LAR to adopt TSTF-566 Revise Actions for Inoperable RHR Shutdown Cooling Subsystems There is no impact on any of these LARs.

3.0 REGULATORY ANALYSIS

3.1 No Significant Hazards Consideration Analysis Energy Northwest requests adoption of Technical Specification Task Force (TSTF)-582, "Reactor Pressure Vessel Water Inventory Control (RPV WIC) Enhancements. The Technical Specifications (TS) related to RPV WIC are revised to incorporate operating experience and to correct errors and omissions that were incorporated into the plant TS when adopting TSTF-542, Revision 2, "Reactor Pressure Vessel Water Inventory Control." Energy Northwest submittal includes the following TSTF-582 changes to the TS:

1. The TS 3.3.5.2 is revised to eliminate the requirement for a manual Emergency Core Cooling System (ECCS) initiation signal to start the required ECCS injection/spray subsystem, and to instead rely on manual valve alignment and pump start.

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GO2-20-095 Enclosure Page 7 of 10

2. The Drain Time definition is revised to move the examples of common mode failure mechanisms to the TS Bases and eliminate seismic as a common mode failure mechanism.

3. The Drain Time definition exception from considering the Drain Time for penetration flow paths isolated with manual or automatic valves that are that are "locked, sealed, or otherwise secured" is revised to apply the exception for manual or automatic valves that are "closed and administratively controlled."

4. The TS 3.3.5.2 is revised to permit placing an inoperable isolation channel in trip as an alternative to declaring the associated penetration flow path incapable of automatic isolation.

5. The Applicability of LCO 3.3.8.1 is revised to not include the specified condition "When the associated diesel generator is required to be OPERABLE by LCO 3.8.2, '[Alternating Current] AC Sources - Shutdown'."

6. TS Surveillance Requirement (SR) 3.5.2.5 that requires operating the required ECCS injection/spray subsystem for at least 10 minutes through the recirculation line, is modified to permit crediting normal operation of the system to satisfy the SR and to permit operation through the test return line.

7. TS 3.8.2, "[Alternating Current] AC Sources - Shutdown," SR 3.8.2.1, is revised to not require SRs that test the ability of the automatic diesel generator to start in Modes 4 and 5. Automatic ECCS initiation in Modes 4 and 5 was eliminated in TSTF-542.

8. TS SR 3.8.2.1 is revised to exclude SRs that verify the ability of the diesel generators to automatically start and load on an ECCS initiation signal or loss of offsite power signal.

9. TS 3.3.6.1, "Primary Containment Isolation Instrumentation," Required Action J.2 is deleted. This action is no longer applicable after adoption of TSTF-542. This was an accidental omission in TSTF-542. This change is made for clarity and has no effect on the application of the TS.

10. The TS are revised to use wording and to define acronyms in a manner consistent with the remainder of the TS. These changes are made for consistency and have no effect on the application of the TS.

Additionally, this Energy Northwest submittal includes removal of an expired note associated with the completion time of Required Action 3.5.1.A.1 which is an administrative activity and has no effect on the application of the TS.

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GO2-20-095 Enclosure Page 8 of 10 Energy Northwest has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below.

1) Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed change incorporates operating experience and corrects errors and omissions that were incorporated into the plant TS when adopting TSTF-542, Revision 2, "Reactor Pressure Vessel Water Inventory Control." As well as deletes an expired note associated with the completion time of Required Action 3.5.1.A.1 which is an administrative activity which does not affect any accidents previously evaluated in any way. Draining of RPV water inventory in Mode 4 (i.e., cold shutdown) and Mode 5 (i.e., refueling) is not an accident previously evaluated and, therefore, revising the existing TS controls to prevent or mitigate such an event has no effect on any accident previously evaluated. RPV water inventory control in Mode 4 or Mode 5 is not an initiator of any accident previously evaluated. The existing and revised TS controls are not mitigating actions assumed in any accident 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 amendment create the possibility of a new or different kind of accident from any accident previously analyzed?

Response: No.

The proposed change incorporates operating experience and corrects errors and omissions that were incorporated into the plant TS when adopting TSTF-542, Revision 2, "Reactor Pressure Vessel Water Inventory Control." As well as deletes an expired note associated with the completion time of Required Action 3.5.1.A.1 which is an administrative activity only. The event of concern under the current requirements and the proposed change is an unexpected draining event. The TS have contained requirements related to an unexpected draining event during shutdown for over 40 years and this event does not appear as an analyzed event in the Updated Final Safety Analysis Report (UFSAR) for any plant or in the NRC's Standard Review Plan (NUREG-0800). Therefore, an unexpected draining event is not a new or different kind of accident not considered in the design and licensing bases that would have been considered a design basis accident in the UFSAR had it been previously identified.

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GO2-20-095 Enclosure Page 9 of 10 None of the equipment affected by the proposed change has a design function described in the UFSAR to mitigate an unexpected draining event in Modes 4 or 5, although the equipment may be used for that purpose. Therefore, the proposed amendment will not change the design function of the affected equipment. The proposed change will affect the operation of certain equipment, such as the manual initiation function and related instrumentation to permit initiation of the required ECCS injection/spray subsystem, and the control of valves credited for preventing a draining event. However, these changes provide adequate protection to prevent or mitigate an unexpected draining event and do not create the possibility of a new or different kind of accident due to credible new failure mechanisms, malfunctions, or accident initiators not considered in the design and licensing bases.

Therefore, the proposed change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3) Does the proposed amendment involve a significant reduction in a margin of safety?

Response: No.

The proposed change incorporates operating experience and corrects errors and omissions that were incorporated into the plant TS when adopting TSTF-542, Revision 2, "Reactor Pressure Vessel Water Inventory Control." As well as deletes an expired note associated with the completion time of Required Action 3.5.1.A.1 which is an administrative activity only which does not involve any reduction in safety margin. The safety basis for the RPV WIC requirements is to protect Safety Limit 2.1.1.3. The proposed change does not affect any specific values that define a safety margin as established in the licensing basis. The proposed change does not affect a design basis or safety limit, or any controlling value for a parameter established in the UFSAR or the license. Therefore, the proposed change does not significantly reduce the margin of safety.

Therefore, the proposed change does not involve a significant reduction in the margin of safety.

Based on the above, Energy Northwest concludes that the proposed amendment does not involve a 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.

4.0 CONCLUSION

S Based on the considerations discussed above: (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 applicable

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GO2-20-095 Enclosure Page 10 of 10 regulations as identified herein, 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.

5.0 ENVIRONMENTAL CONSIDERATION

The proposed change would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, would change an inspection or surveillance requirement. The proposed change 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 individual or cumulative occupational radiation exposure.

Accordingly, the proposed change meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed change.

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GO2-20-095 Attachment 1 Proposed Columbia Technical Specification Changes (Mark-Up)

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Definitions 1.1 1.1 Definitions Drain Time b) The limiting drain rate is the larger of the drain rate (Continued) through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure (e.g., seismic event, loss of normal power, single human error), for all penetration flow paths below the TAF except:

1. Penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are closed and administratively controlledlocked, sealed, or otherwise secured in the closed position, blank flanges, or other devices that prevent flow of reactor coolant through the penetration flow paths;

2. Penetration flow paths capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation; or

3. Penetration flow paths with isolation devices that can be closed prior to the RPV water level being equal to the TAF by a dedicated operator trained in the task, who is in continuous communication with the control room, is stationed at the controls, and is capable of closing the penetration flow path isolation devices without offsite power.

c) The penetration flow paths required to be evaluated per paragraph b) are assumed to open instantaneously and are not subsequently isolated, and no water is assumed to be subsequently added to the RPV water inventory; d) No additional draining events occur; and e) Realistic cross-sectional areas and drain rates are used.

A bounding DRAIN TIME may be used in lieu of a calculated value.

EMERGENCY CORE The ECCS RESPONSE TIME shall be that time interval from COOLING SYSTEM (ECCS) when the monitored parameter exceeds its ECCS initiation RESPONSE TIME setpoint at the channel sensor until the ECCS equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach Columbia Generating Station 1.1-4 Amendment No. 149,169 225 243 251

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RPV Water Inventory Control Instrumentation 3.3.5.2 3.3 INSTRUMENTATION 3.3.5.2 Reactor Pressure Vessel (RPV) Water Inventory Control Instrumentation LCO 3.3.5.2 The RPV Water Inventory Control instrumentation for each Function in Table 3.3.5.2-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.5.2-1.

ACTIONS

NOTE-----------------------------------------------------------

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Enter the Condition Immediately inoperable. referenced in Table 3.3.5.2-1 for the channel.

BA. One or more channels A.1 Initiate action to place Immediately inoperableAs required channel in trip.

by Required Action A.1 and referenced in OR Table 3.3.5.2-1.

BA.2.1 Declare associated Immediately penetration flow path(s) incapable of automatic isolation.

AND BA.2.2 Initiate action to Ccalculate Immediately DRAIN TIME.

C. As required by Required C.1 Place channel in trip. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Action A.1 and referenced in Table 3.3.5.2-1.

Columbia Generating Station 3.3.5.2-1 Amendment No. 149,169 225 251

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RPV Water Inventory Control Instrumentation 3.3.5.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. As required by Required D.1 Declare HPCS system 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Action A.1 and inoperable.

referenced in Table 3.3.5.2-1. OR D.2 Align the HPCS pump 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months suction to the suppression pool.

E. As required by Required E.1 Restore channel to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Action A.1 and OPERABLE status.

referenced in Table 3.3.5.2-1.

F. Required Action and F.1 Declare associated ECCS Immediately associated Completion injection/spray subsystem Time of Condition C, D, inoperable.

or E not met.

Columbia Generating Station 3.3.5.2-2 Amendment No. 149,169 225 251

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RPV Water Inventory Control Instrumentation 3.3.5.2 SURVEILLANCE REQUIREMENTS

NOTE-----------------------------------------------------------

These SRs apply to each Function in Refer to Table 3.3.5.2-1, except SR 3.3.5.2.1 is not applicable to Function 2.a to determine which SRs apply for each ECCS Function.

SURVEILLANCE FREQUENCY SR 3.3.5.2.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.5.2.2 Perform CHANNEL FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program SR 3.3.5.2.3 Perform LOGIC SYSTEM FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program Columbia Generating Station 3.3.5.2-3 Amendment No. 149,169 225 238 251

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RPV Water Inventory Control Instrumentation 3.3.5.2 Table 3.3.5.2-1 (page 1 of 21)

RPV Water Inventory Control Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS PER FROM SPECIFIED FUNCTION REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS ACTION A.1 REQUIREMENTS VALUE

1. Low Pressure Coolant Injection-A (LPCI) and Low Pressure Core Spray (LPCS)

Subsystems

a. Reactor Vessel 4, 5 1 per valve(a) C SR 3.3.5.2.2 492 psig Pressure - Low (Injection Permissive)

b. LPCS Pump Discharge Flow - 4, 5 1(a) E SR 3.3.5.2.2 668 gpm Low (Minimum Flow) and 1067 gpm

c. LPCI Pump A 4, 5 1(a) E SR 3.3.5.2.2 605 gpm Discharge Flow - and Low (Minimum Flow) 984 gpm

d. Manual Initiation 4, 5 2(a) E SR 3.3.5.2.3 NA

2. LPCI B and LPCI C Subsystems

a. Reactor Vessel 4, 5 1 per valve(a) C SR 3.3.5.2.2 492 psig Pressure - Low (Injection Permissive)

b. LPCI Pumps B & C 4, 5 1 per pump(a) E SR 3.3.5.2.2 605 gpm Discharge Flow - and Low (Minimum Flow) 984 gpm

c. Manual Initiation 4, 5 2(a) E SR 3.3.5.2.3 NA (a) Associated with an ECCS subsystem required to be OPERABLE by LCO 3.5.2, "Reactor Pressure Vessel (RPV) Water Inventory Control."

Columbia Generating Station 3.3.5.2-4 Amendment No. 149,210 225 251

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RPV Water Inventory Control Instrumentation 3.3.5.2 Table 3.3.5.2-1 (page 2 of 2)

RPV Water Inventory Control Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE

3. High Pressure Core Spray (HPCS) System

a. Condensate 4(b), 5(b) 1(a) D SR 3.3.5.2.2 448 ft 1 inch Storage Tank elevation Level - Low

b. HPCS System 4, 5 1(a) E SR 3.3.5.2.2 1200 gpm Flow Rate - Low and (Minimum Flow) 1512 gpm

41. Residual Heat Removal (RHR) Shutdown Cooling (SDC) System Isolation

a. Reactor Vessel (ca) 2 in one B SR 3.3.5.2.1 9.5 inches Water Level - Low, trip system SR 3.3.5.2.2 Level 3

52. Reactor Water Cleanup (RWCU) System Isolation

a. Reactor Vessel (ca) 2 in one B SR 3.3.5.2.2 -58 inches Water Level - Low trip system Low, Level 2 (a) Associated with an ECCS subsystem required to be OPERABLE by LCO 3.5.2, "Reactor Pressure Vessel (RPV) Water Inventory Control."

(b) When HPCS is OPERABLE for compliance with LCO 3.5.2, "Reactor Pressure Vessel (RPV) Water Inventory Control," and aligned to the condensate storage tank.

(ca) When automatic isolation of the associated penetration flow path(s) is credited in calculating DRAIN TIME.

Columbia Generating Station 3.3.5.2-5 Amendment No. 251

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Primary Containment Isolation Instrumentation 3.3.6.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME I. As required by Required I.1 Declare associated standby 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Action C.1 and liquid control (SLC) referenced in subsystem inoperable.

Table 3.3.6.1-1.

OR I.2 Isolate the Reactor Water 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Cleanup (RWCU) System.

J. As required by Required J.1 Initiate action to restore Immediately Action C.1 and channel to OPERABLE referenced in status.

Table 3.3.6.1-1.

OR J.2 Initiate action to isolate the Immediately Residual Heat Removal (RHR) Shutdown Cooling (SDC) System.

SURVEILLANCE REQUIREMENTS

NOTES----------------------------------------------------------

1. Refer to Table 3.3.6.1-1 to determine which SRs apply for each Primary Containment Isolation Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains isolation capability.

SURVEILLANCE FREQUENCY SR 3.3.6.1.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program Columbia Generating Station 3.3.6.1-3 Amendment No. 149,169 225 238

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LOP Instrumentation 3.3.8.1 3.3 INSTRUMENTATION 3.3.8.1 Loss of Power (LOP) Instrumentation LCO 3.3.8.1 The LOP instrumentation for each Function in Table 3.3.8.1-1 shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3, When the associated diesel generator (DG) is required to be OPERABLE by LCO 3.8.2, "AC Sources - Shutdown."

ACTIONS

NOTE-----------------------------------------------------------

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Enter the Condition Immediately channels inoperable. referenced in Table 3.3.8.1-1 for the channel.

B. As required by Required B.1 Declare associated DG 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery Action A.1 and inoperable. of loss of initiation referenced in capability for the Table 3.3.8.1-1. associated DG AND B.2 Restore channel to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

C. As required by Required C.1 Place channel in trip. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Action A.1 and referenced in Table 3.3.8.1-1.

Columbia Generating Station 3.3.8.1-1 ---

Amendment No. 149,169 225 I

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ECCS - Operating 3.5.1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM 3.5.1 ECCS - Operating LCO 3.5.1 Each ECCS injection/spray subsystem and the Automatic Depressurization System (ADS) function of six safety/relief valves shall be OPERABLE.

APPLICABILITY: MODE 1, MODES 2 and 3, except ADS valves are not required to be OPERABLE with reactor steam dome pressure 150 psig.

ACTIONS

NOTE-----------------------------------------------------------

LCO 3.0.4.b is not applicable to High Pressure Core Spray (HPCS).

CONDITION REQUIRED ACTION COMPLETION TIME A. One low pressure ECCS A.1 Restore low pressure 7 days(1) injection/spray ECCS injection/spray subsystem inoperable. subsystem to OPERABLE status.

B High Pressure Core B.1 Verify by administrative Immediately Spray (HPCS) System means RCIC System is inoperable. OPERABLE when RCIC System is required to be OPERABLE.

AND B.2 Restore HPCS System to 14 days OPERABLE status.

(1)

The Completion Time that one train of RHR (RHR-A) can be inoperable as specified by Required Action A.1 may be extended beyond the 7 day completion time up to 7 days to support restoration of RHR-A following pump and motor replacement. This footnote will expire at 23:59 PST February 28, 2019.

Columbia Generating Station 3.5.1-1 Amendment No. 187 225 230 245 251 253

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RPV Water Inventory Control 3.5.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. DRAIN TIME < 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months C.1 Verify secondary 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . containment boundary is capable of being established in less than the DRAIN TIME.

AND C.2 Verify each secondary 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months containment penetration flow path is capable of being isolated in less than the DRAIN TIME.

AND C.3 Verify one standby gas 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months treatment (SGT) subsystem is capable of being placed in operation in less than the DRAIN TIME.

Columbia Generating Station 3.5.2-3 Amendment No. 169,210 225 238 251

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RPV Water Inventory Control 3.5.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. DRAIN TIME < 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . D.1 ----------- NOTE ---------------

Required ECCS injection/spray subsystem or additional method of water injection shall be capable of operating without offsite electrical power.

Initiate action to establish Immediately an additional method of water injection with water sources capable of maintaining RPV water level > TAF for 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

AND D.2 Initiate action to establish Immediately secondary containment boundary.

AND D.3 Initiate action to isolate Immediately each secondary containment penetration flow path or verify it can be automatically or manually isolated from the control room.

AND Immediately D.4 Initiate action to verify one standby gas treatmentSGT subsystem is capable of being placed in operation.

Columbia Generating Station 3.5.2-4 Amendment No. 169,205 225 229 238 243 246 251

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RPV Water Inventory Control 3.5.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.4 Verify, for the required ECCS injection/spray In accordance subsystem, locations susceptible to gas with the accumulation are sufficiently filled with water. Surveillance Frequency Control Program SR 3.5.2.5 ------------------------------NOTE-------------------------------

Not required to be met for system vent flow paths opened under administrative controls.

Verify for the required ECCS injection/spray In accordance subsystem, each manual, power operated, and with the automatic valve in the flow path, that is not locked, Surveillance sealed, or otherwise secured in position, is in the Frequency correct position. Control Program SR 3.5.2.65 -------------------------------NOTE------------------------------

Injection into the vessel is not required.1.

Operation may be through the test return line.

2. Credit may be taken for normal system operation to satisfy this SR.

Operate the required ECCS injection/spray In accordance subsystem for 10 minutes. with the Surveillance Frequency Control Program SR 3.5.2.76 Verify each valve credited for automatically isolating In accordance a penetration flow path actuates to the isolation with the position on an actual or simulated isolation signal. Surveillance Frequency Control Program Columbia Generating Station 3.5.2-6 Amendment No. 251

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RPV Water Inventory Control 3.5.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.87 -------------------------------NOTE------------------------------

Vessel injection/spray may be excluded.

Verify the required LPCI or LPCSECCS injection/spray In accordance subsystem actuates on a manual initiation signal or the with the required HPCS subsystem can be manually operated. Surveillance Frequency Control Program Columbia Generating Station 3.5.2-7 Amendment No. 251

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AC Sources - Shutdown 3.8.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.2.1 -------------------------------NOTE------------------------------

The following SRs are not required to be performed:

SR 3.8.1.3, SR 3.8.1.9, through SR 3.8.1.110, SR 3.8.1.134 through and SR 3.8.1.16, SR 3.8.1.18, and SR 3.8.1.19.

For The following SRs are applicable for AC sources In accordance required to be OPERABLE: with applicable SRs SR 3.8.1.1 SR 3.8.1.6 SR 3.8.1.2 SR 3.8.1.9 SR 3.8.1.3 SR 3.8.1.10 SR 3.8.1.4 SR 3.8.1.14 SR 3.8.1.5 SR 3.8.1.16

, the SRs for Specification 3.8.1, except SR 3.8.1.8, SR 3.8.1.17, and SR 3.8.1.20, are applicable.

Columbia Generating Station 3.8.2-3 Amendment No. 199,205 225

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GO2-20-095 Attachment 2 Proposed Technical Specification Bases Markup Pages For information Only

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ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) sources (DG). However, since the LOCA/LOOP time delay does not degrade ECCS operation, it remains in the pump start logic at all times.

The Pump Start - LOCA and LOCA/LOOP Time Delay Relays are assumed to be OPERABLE in the accident and transient analyses requiring ECCS initiation. That is, the analysis assumes that the pumps will initiate when required and excess loading will not cause failure of the power sources due to a degraded voltage condition (see Table 3.3.8.1-1).

There are four Pump Start - LOCA Time Delay Relay channels, one in each of the low pressure ECCS pump start logic circuits. Each of the LOCA Time Delay Relay channels consists of a Drywell Pressure - High and Reactor Level 2 sensor, auxiliary relay logic, and circuit breaker position switches to initiate the LOCA time delay relay when on TR-S.

The LOCA Time Delay Relay channel sensors also provide Drywell Pressure - High RPS Trip (Table 3.3.1.1-1 Function 6) and Drywell Pressure/Level 2 Primary Containment and RWCU Isolation (Table 3.3.6.1-1 Functions 2.b, 2.c, and 4.j) and Secondary Containment Isolation (Table 3.3.6.2-1 Functions 1 and 2) channel signals. A Drywell Pressure - High and a Level 2 sensor are in series and deenergize (either instrument) to initiate a LOCA Time Delay Relay channel. Two LOCA Time Delay Relay channels are provided for each division low pressure ECCS Function. Initiation of one LOCA Time Delay Relay channel will result in the other LOCA Time Delay Relay channel in the division initiating simultaneously to assure a nominal 9.9 second difference in low pressure ECCS subsystem starts within each ECCS function (LPCS/LPCI-C are set at 9.5 seconds and LPCI-A/LPCI-B are set at 19.4 seconds with appropriate allowable values.) While each channel is dedicated to a single pump start logic, a single failure of an instrument sensor or logic relay could potentially result in failure of the offsite 230 kV supply. One low pressure ECCS pump on either ESF bus could start simultaneously with the HPCS pump followed shortly by a second low pressure ECCS pump start while powered from the 230 kV offsite supply and potentially trip the 230 kV circuit supply to both ESF buses and HPCS. The transfer would occur due to degraded voltage relay operation. If loss of the 230 kV source occurs, transfer to the 115 kV or DGs will occur within the ECCS RESPONSE TIME (for MODE 1, 2, or 3).

Thus, single failure criteria is met for this condition. However, the supported ECCS features are impacted and appropriate Actions and Completion Times have been established in LCO 3.3.5.1, Action C.

Additionally, the 230 kV offsite supply is a supported feature by the LOCA Time Delay Relay channels for use in meeting LCO 3.8.1 or LCO 3.8.2. A Note (e) has been provided to Table 3.3.5.1-1 that identifies Functions 1c, 1d, 2c, and 2d as supporting OPERABILITY of the 230 kV offsite power source. This assumes HPCS or the low pressure ECCS pumps on the Columbia Generating Station B 3.3.5.1-10 Revision 73

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ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Four channels of Reactor Vessel Water Level - Low Low, Level 2 Function are only required to be OPERABLE when HPCS is required to be OPERABLE to ensure that no single instrument failure can preclude HPCS initiation. Refer to LCO 3.5.1 and LCO 3.5.2 for HPCS Applicability Bases.

3.b. Drywell Pressure - High High pressure in the drywell could indicate a break in the RCPB. The HPCS System and associated DG are initiated upon receipt of the Drywell Pressure - High Function in order to minimize the possibility of fuel damage. However, no credit is taken for the Drywell Pressure - High Function to start the HPCS System in any DBA or transient analyses; that is, HPCS is assumed to be initiated on Reactor Water Level - Low Low, Level 2. It is retained for overall redundancy and diversity of the HPCS function as required by the NRC in the plant licensing basis. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

Drywell Pressure - High signals are initiated from four pressure switches that sense drywell pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside primary containment.

The Drywell Pressure - High Function is required to be OPERABLE when HPCS is required to be OPERABLE in conjunction with times when the primary containment is required to be OPERABLE. Thus, four channels of the HPCS Drywell Pressure - High Function are required to be OPERABLE in MODES 1, 2, and 3, to ensure that no single instrument failure can preclude ECCS initiation. In MODES 4 and 5, the Drywell Pressure - High Function is not required since there is insufficient energy in the reactor to pressurize the drywell to the Drywell Pressure - High Function's setpoint. Refer to LCO 3.5.1 for the Applicability Bases for the HPCS System.

3.c Reactor Vessel Water Level - High, Level 8 High RPV water level indicates that sufficient cooling water inventory exists in the reactor vessel such that there is no danger to the fuel.

Therefore, the Level 8 signal is used to close the HPCS injection valve to prevent overflow into the main steam lines (MSLs). The Reactor Vessel Water Level - High, Level 8 Function is not assumed in the accident and transient analyses. It was retained since it is a potentially significant contributor to risk, thus it meets Criterion 4 of Reference 4.

Columbia Generating Station B 3.3.5.1-15 Revision 73

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ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

One flow switch is used to detect the HPCS Systems flow rate. The logic is arranged such that the flow switch causes the minimum flow valve to open when flow is low with the pump running. The logic will close the minimum flow valve once the closure setpoint is exceeded.

The HPCS System Flow Rate - Low Allowable Value is high enough to ensure that pump flow rate is sufficient to protect the pump, yet low enough to ensure that the closure of the minimum flow valve is initiated to allow full flow into the core.

One channel of HPCS System Flow Rate - Low Function is required to be OPERABLE when the HPCS is required to be OPERABLE. Refer to LCO 3.5.1 and LCO 3.5.2 for HPCS Applicability Bases.

3.g. Manual Initiation The Manual Initiation switch and push button channels introduce a signal into the HPCS logic to provide manual initiation capability and is redundant to the automatic protective instrumentation. There is one switch and push button (with two channels) for the HPCS System.

The Manual Initiation Function is not assumed in any accident or transient analyses in the FSAR. However, the Function is retained for overall redundancy and diversity of the HPCS function as required by the NRC in the plant licensing basis.

There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the switch and push button. Two channels of the Manual Initiation Function are only required to be OPERABLE when the HPCS System are required to be OPERABLE. Refer to LCO 3.5.1 and LCO 3.5.2 for HPCS Applicability Bases.

Automatic Depressurization System 4.a, 5.a. Reactor Vessel Water Level - Low Low Low, Level 1 Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, ADS receives one of the signals necessary for initiation from this Function. The Reactor Vessel Water Level - Low Low Low, Columbia Generating Station B 3.3.5.1-18 Revision 73

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ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.5.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.5.1.3, SR 3.3.5.1.4, and SR 3.3.5.1.5 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

The Surveillance Frequencies are controlled under the Surveillance Frequency Control Program.

SR 3.3.5.1.6 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.5.1and, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety function.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Columbia Generating Station B 3.3.5.1-32 Revision 93

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RPV Water Inventory Control Instrumentation B 3.3.5.2 B 3.3 INSTRUMENTATION B 3.3.5.2 Reactor Pressure Vessel (RPV) Water Inventory Control Instrumentation BASES BACKGROUND The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF.

If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.

Technical Specifications are required by 10 CFR 50.36 to include limiting safety system settings (LSSS) for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the process variable at which a safety action is initiated to ensure that a SL is not exceeded. Any automatic protection action that occurs on reaching the Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur. The actual settings for the automatic isolation channels are the same as those established for the same functions in MODES 1, 2, and 3 in LCO 3.3.5.1, "Emergency Core Cooling System (ECCS)

Instrumentation," or LCO 3.3.6.1, "Primary Containment Isolation instrumentation".

With the unit in MODE 4 or 5, RPV water inventory control is not required to mitigate any events or accidents evaluated in the safety analyses.

RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur. Under the definition of DRAIN TIME, some penetration flow paths may be excluded from the DRAIN TIME calculation if they will be isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation.

Columbia Generating Station B 3.3.5.2-1 Revision 111

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RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES BACKGROUND (continued)

The purpose of the RPV Water Inventory Control Instrumentation is to support the requirements of LCO 3.5.2, Reactor Pressure Vessel (RPV)

Water Inventory Control, and the definition of DRAIN TIME. There are functions that are required for manual initiation or operation of the ECCS injection/spray subsystem required to be OPERABLE by LCO 3.5.2 and other functions that support automatic isolation of Residual Heat Removal subsystem and Reactor Water Cleanup system penetration flow path(s) on low RPV water level.

The RPV Water Inventory Control Instrumentation supports operation of low pressure core spray (LPCS), low pressure coolant injection (LPCI),

and high pressure core spray (HPCS). The equipment involved with each of these systems is described in the Bases for LCO 3.5.2.

APPLICABLE With the unit in MODE 4 or 5, RPV water inventory control is not required SAFETY to mitigate any events or accidents evaluated in the safety analyses. RPV ANALYSES, LCO, water inventory control is required in MODES 4 and 5 to protect and APPLICABILITY Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not postulated considered in MODES 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is postulated considered in which an single operator error or initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure (e.g., seismic event, loss of normal power, single human error). It is assumed, based on engineering judgment, that while in MODES 4 and 5, one ECCS injection/spray subsystem can be manually initiated to maintain adequate reactor vessel water level.

As discussed in References 1, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety.

Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).

Permissive and interlock setpoints are generally considered as nominal values without regard to measurement accuracy.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

Columbia Generating Station B 3.3.5.2-2 Revision 111

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RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Low Pressure Core Spray and Low Pressure Coolant Injection Systems 1.a, 2.a. Reactor Vessel Pressure - Low (Injection Permissive)

Low reactor vessel pressure signals are used as permissives for the low pressure ECCS subsystems. This ensures that, prior to opening the injection valves of the low pressure ECCS subsystems, the reactor pressure has fallen to a value below these subsystems' maximum design pressure. While it is assured during Modes 4 and 5 that the reactor vessel pressure will be below the ECCS maximum design pressure, the Reactor Vessel Pressure - Low signals are assumed to be operable and capable of permitting initiation of the ECCS.

The Reactor Vessel Pressure - Low signals are initiated from four pressure switches that sense the reactor dome pressure (one pressure switch for each low pressure ECCS injection valve).

The Allowable Value is low enough to prevent overpressuring the equipment in the low pressure ECCS.

Three channels of Reactor Vessel Pressure - Low Function (one per valve) are only required to be OPERABLE in MODES 4 and 5 when ECCS Manual Initiation is required to be OPERABLE, since these channels support the manual initiation Function. In addition, the channels are only required when the associated ECCS subsystem is required to be OPERABLE by LCO 3.5.2.

1.b, 1.c, 2.b. Low Pressure Coolant Injection and Low Pressure Core Spray Pump Discharge Flow - Low (Minimum Flow)

The minimum flow instruments are provided to protect the associated low pressure ECCS pump from overheating when the pump is operating and the associated injection valve is not fully open. The minimum flow line valve is opened when low flow is sensed, and the valve is automatically closed when the flow rate is adequate to protect the pump.

One flow indicating switch per ECCS pump is used to detect the associated subsystems' flow rates. The logic is arranged such that each indicating switch causes its associated minimum flow valve to open when flow is low with the pump running. The logic will close Columbia Generating Station B 3.3.5.2-3 Revision 111

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RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) the minimum flow valve once the closure setpoint is exceeded. The LPCI minimum flow valves are time delayed such that the valves will not open for 8 seconds after the switches detect low flow. The time delay is provided to limit reactor vessel inventory loss during the startup of the Residual Heat Removal (RHR) shutdown cooling mode (for RHR A and RHR B).

The Pump Discharge Flow - Low Allowable Values are high enough to ensure that the pump flow rate is sufficient to protect the pump, yet low enough to ensure that the closure of the minimum flow valve is initiated to allow full flow into the core.

One channel of the Pump Discharge Flow - Low Function is required to be OPERABLE in MODES 4 and 5 when the associated LPCS or LPCI pump is required to be OPERABLE by LCO 3.5.2 to ensure the pumps are capable of injecting into the Reactor Pressure Vessel when manually initiated.

1.d, 2.c. Manual Initiation The Manual Initiation switch and push button channels introduce signals into the appropriate ECCS logic to provide manual initiation capability and are redundant to the automatic protective instrumentation. There is one switch and push button (with two channels per switch and push button) for each of the two Divisions of low pressure ECCS (i.e., Division 1 ECCS, LPCS and LPCI A; Division 2 ECCS, LPCI B and LPCI C). Only the manual initiation function required to be OPERABLE is that associated with the ECCS subsystem required to be OPERABLE by LCO 3.5.2.

There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.

If SM-7 or SM-8 is powered from TR-S, then the LPCS, LPCI A/B/C pump will not start unless there is an associated valid Drywell Pressure - High or Reactor Vessel Water Level - Low Low, Level 2 signal. Only the Reactor Vessel Water Level - Low Low, Level 2 input to the Manual Initiation logic is required when SM-7 or SM-8 is powered from TR-S.

The Drywell Pressure - High Function is not required since there is insufficient energy in the reactor to pressurize the primary containment to the Drywell Pressure - High setpoint.

Columbia Generating Station B 3.3.5.2-4 Revision 111

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RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

High Pressure Core Spray System 3.a. Condensate Storage Tank Level - Low Low level in the CST indicates the unavailability of an adequate supply of makeup water from this normal source. Normally the suction valves between HPCS and the CST are open and water for HPCS injection would be taken from the CST. However, if the water level in the CST falls below a preselected level, first the suppression pool suction valve automatically opens, and then the CST suction valve automatically closes. This ensures that an adequate supply of makeup water is available to the HPCS pump. To prevent losing suction to the pump, the suction valves are interlocked so that the suppression pool suction valve must be open before the CST suction valve automatically closes.

Condensate Storage Tank Level - Low signals are initiated from two level switches mounted on a Seismic Category I standpipe in the reactor building (the two switches mounted on the CST cannot be credited since they are not Seismic Category I). Only one of the two switches is required to be OPERABLE in MODES 4 and 5.

The Condensate Storage Tank Level - Low Function Allowable Value is high enough to ensure adequate pump suction head while water is being taken from the CST. The low water level limit in the CST is based on vortexing and potential air ingestion by the pump.

One channel of the Condensate Storage Tank Level - Low Function is only required to be OPERABLE when HPCS is required to be OPERABLE to fulfill the requirements of LCO 3.5.2 and HPCS is aligned to the CST.

3.b, HPCS System Flow Rate - Low (Minimum flow)

The minimum flow instrument is provided to protect the HPCS pump from overheating when the pump is operating and the associated injection valve is not fully open. The minimum flow line valve is opened when low flow is sensed, and the valve is automatically closed when the flow rate is adequate to protect the pump.

One flow switch is used to detect the HPCS System's flow rate. The logic is arranged such that the flow switch causes the minimum flow valve to open when flow is low with the pump running. The logic will close the minimum flow valve once the closure setpoint is exceeded.

The HPCS System Flow Rate - Low is high enough to ensure that pump flow rate is sufficient to protect the pump, yet low enough to ensure that Columbia Generating Station B 3.3.5.2-5 Revision 111

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RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) the closure of the minimum flow valve is initiated to allow full flow into the core.

One channel of HPCS System Flow Rate - Low is required to be OPERABLE when HPCS is required to be OPERABLE by LCO 3.5.2 in MODES 4 and 5.

RHR System Isolation 41.a - Reactor Vessel Water Level - Low, Level 3 The definition of DRAIN TIME allows crediting the closing of penetration flow paths that are capable of being automatically isolated by RPV water level isolation instrumentation prior to the RPV water level being equal to the TAF. The Reactor Vessel Water Level - Low, Level 3 Function is only required to be OPERABLE when automatic isolation of the associated RHR penetration flow path is credited in calculating DRAIN TIME.

Reactor Vessel Water Level - Low, Level 3 signals are initiated from differential pressure switches that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.

While four channels (two channels per trip system) of the Reactor Vessel Water Level - Low, Level 3 Function are available, only two channels (all in the same trip system) are required to be OPERABLE.

The Reactor Vessel Water Level - Low, Level 3 Allowable Value was chosen to be the same as the RPS Reactor Vessel Water Level - Low, Level 3 Allowable Value (LCO 3.3.1.1), since the capability to cool the fuel may be threatened.

This Function isolates Group 5 and Group 6 valves.

Reactor Water Cleanup (RWCU) System Isolation 52.a - Reactor Vessel Water level - Low Low, Level 2 The definition of DRAIN TIME allows crediting the closing of penetration flow paths that are capable of being automatically isolated by RPV water level isolation instrumentation prior to the RPV water level being equal to the TAF. The Reactor Vessel Water Level - Low Low, Level 2 Function associated with RWCU System isolation may be credited for automatic isolation of penetration flow paths associated with the RWCU System.

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RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Reactor Vessel Water Level - Low Low, Level 2 are initiated from differential pressure transmitters with trip units that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.

While four channels (two channels per trip system) of the Reactor Vessel Water Level - Low, Level 2 Function are available, only two channels (all in the same trip system) are required to be OPERABLE.

The Reactor Vessel Water Level - Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Reactor Vessel Water Level - Low Low, Level 2 Allowable Value (LCO 3.3.5.1), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level - Low Low, Level 2 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME.

This Function isolates the Group 7 valves.

A Note has been provided to modify the ACTIONS related to RPV Water Inventory Control instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable RPV Water Inventory Control instrumentation channels provide appropriate compensatory measures for separate inoperable Condition entry for each inoperable RPV Water Inventory Control instrumentation channel.

ACTIONS A.1 Required Action A.1 directs entry into the appropriate Condition referenced in Table 3.3.5.2-1. The applicable Condition referenced in the Table is Function dependent. Each time a channel is discovered inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition.

BA.1, A.2.1 and BA.2.2 RHR System Isolation, Reactor Vessel Water Level - Low, Level 3, and Reactor Water Cleanup System, Reactor Vessel Water Level - Low Low, Columbia Generating Station B 3.3.5.2-7 Revision 111

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RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES ACTIONS (continued)

Level 2 functions are applicable when automatic isolation of the associated penetration flow path is credited in calculating Drain Time. If the instrumentation is inoperable, Required Action BA.1 directs an immediate action to place the channel in trip. With the inoperable channel in the tripped condition, the remaining channel will isolate the penetration flow path on low water level. If both channels are inoperable and placed in trip, the penetration flow path will be isolated. Alternately, Required Action 2.1 requires declaration that the associated penetration flow path(s) to be immediately declared are incapable of automatic isolation.

Required Action BA.2.2 directs initiating action to calculatione of DRAIN TIME. The calculation cannot credit automatic isolation of the affected penetration flow paths.

C.1 Low reactor vessel pressure signals are used as permissives for the low pressure ECCS injection/spray subsystem manual initiation functions. If this permissive is inoperable, manual initiation of ECCS is prohibited.

Therefore, the permissive must be placed in the trip condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . With the permissive in the trip condition, manual initiation may be performed. Prior to placing the permissive in the tripped condition, the operator can take manual control of the pump and the injection valve to inject water into the RPV.

The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is intended to allow the operator time to evaluate any discovered inoperabilities and to place the channel in trip.

D.1 and D.2 Required Actions D.1 and D.2 are intended to ensure that appropriate actions are taken if multiple, inoperable channels within the same Function result in a loss of automatic suction swap for the HPCS system from the condensate storage tank to the suppression pool. The HPCS system must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or the HPCS pump suction must be aligned to the suppression pool, since, if aligned, the function is already performed.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is acceptable because it minimizes the risk of HPCS being needed without an adequate water source while allowing time for restoration or alignment of HPCS pump suction to the suppression pool.

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RPV Water Inventory Control Instrumentation B 3.3.5.2 If an LPCI or LPCS Discharge Flow - Low (Minimum Flow) function is inoperable, there is a risk that the associated ECCS pump could overheat when the pump is operating and the associated injection valve is not fully open. In this condition, the operator can take manual control of the pump and the injection valve to ensure the pump does not overheat. If a Columbia Generating Station B 3.3.5.2-9 Revision 111

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RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES ACTIONS (continued) manual initiation function is inoperable, the ECCS subsystem pumps can be started manually and the valves can be opened manually, but this is not the preferred condition.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time was chosen to allow time for the operator to evaluate and repair any discovered inoperabilities. The Completion Time is appropriate given the ability to manually start the ECCS pumps and open the injection valves and to manually ensure the pump does not overheat F.1 With the Required Action and associated Completion Time of Conditions C, D, or E not met, the associated ECCS injection/spray subsystem may be incapable of performing the intended function, and must be declared inoperable immediately.

SURVEILLANCE As noted in the beginning of the SRs, the SRs forthe following SRs apply to each RPV Water REQUIREMENTS Inventory Control instrument Functions are found in the SRs column of Table 3.3.5.2-1, except SR 3.3.5.2.1 does not apply to Function 2.a.

SR 3.3.5.2.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK guarantees that undetected outright channel failure is limited; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL FUNCTIONAL TEST.

Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)

The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.

SR 3.3.5.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.5.2.3 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.5.2 overlaps this Surveillance to complete testing of the assumed safety function.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. Information Notice 84-81 "Inadvertent Reduction in Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup,"

November 1984.

2. Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.

3. Generic Letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(F), " August 1992.

4. NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," May 1993.

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Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS (continued)

I.1 and I.2 If the channel is not restored to OPERABLE status within the allowed Completion Time, the associated SLC subsystem is declared inoperable or the RWCU System is isolated. Since this Function is required to ensure that the SLC System performs its intended function, sufficient remedial measures are provided by declaring the associated SLC subsystem inoperable or isolating the RWCU System.

The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is acceptable because it minimizes risk while allowing sufficient time for personnel to isolate the RWCU System.

J.1 and J.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated penetration flow path should be closed. However, if the shutdown cooling function is needed to provide core cooling, these Required Actions allow the penetration flow path to remain unisolated provided action is immediately initiated to restore the channel to OPERABLE status or to isolate the RHR Shutdown Cooling System (i.e., provide alternate decay heat removal capabilities so the penetration flow path can be isolated). Actions must continue until the channel is restored to OPERABLE status or the RHR Shutdown Cooling System is isolated.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each Primary REQUIREMENTS Containment Isolation Instrumentation Function are found in the SRs column of Table 3.3.6.1-1.

The Surveillances are also modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains isolation capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 10 and 11) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the PCIVs will isolate the penetration flow path(s) when necessary.

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LOP Instrumentation B 3.3.8.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) analytic limit that must be evaluated. The Allowable Values and the trip setpoints are derived from both an upper and lower analytic limit using the methodology described above. Due to the upper and lower analytic limits, Allowable Values of these Functions appear to incorporate a range.

However, the upper and lower Allowable Values are unique, with each Allowable Value associated with one unique analytic limit and trip setpoint.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis 1.a, 1.b, 1.c, 1.d, 2.a, 2.b. 4.16 kV Emergency Bus Undervoltage (Loss of Voltage)

Loss of voltage on a 4.16 kV emergency bus indicates that offsite power may be completely lost to the respective emergency bus and is unable to supply sufficient power for proper operation of the applicable equipment.

Therefore, the power supply to the bus is transferred from offsite power to DG power when the voltage on the bus drops below the Loss of Voltage Function Allowable Values (loss of voltage with a short time delay). This ensures that adequate power will be available to the required equipment.

The Bus Undervoltage Allowable Values are low enough to prevent inadvertent power supply transfer, but high enough to ensure power is available to the required equipment. The Time Delay Allowable Values are long enough to provide time for the offsite power supply to recover to normal voltages, shed certain loads, and coordinate with overcurrent protection relays, but short enough to ensure that power is available to the required equipment.

Two channels of Division 1 and 2 TR-S and Division 3 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) Function and Time Delay Function per associated emergency bus are available and are required to be OPERABLE when the associated DG is required to be OPERABLE.

One channel of Division 1 and 2 TR-B 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) Function and Time Delay Function per associated emergency bus is available and is required to be OPERABLE when the associated DG is required to be OPERABLE. Refer to LCO 3.8.1, and LCO 3.8.2, for Applicability Bases for the DGs.

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LOP Instrumentation B 3.3.8.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 1.e, 1.f, 1.g, 2.c, 2.d. 4.16 kV Emergency Bus Undervoltage (Degraded Voltage)

A reduced voltage condition on a 4.16 kV emergency bus indicates that while offsite power may not be completely lost to the respective emergency bus, power may be insufficient for starting large motors without risking damage to the motors that could disable the ECCS function. Therefore, power supply to the bus is transferred from offsite power to onsite DG power when the voltage on the bus drops below the Degraded Voltage Function Allowable Values (degraded voltage with a time delay). This ensures that adequate power will be available to the required equipment.

The Bus Undervoltage Allowable Values are low enough to prevent inadvertent power supply transfer, but high enough to ensure that sufficient power is available to the required equipment. The Time Delay Allowable Values are long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that sufficient power is available to the required equipment.

Three channels of the Division 1 and 2 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) - 4.16 kV Basis and - Primary Time Delay Functions per associated emergency bus are available, but only two channels of Division 1 and 2 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) - 4.16 kV Basis and - Primary Time Delay Functions per associated emergency bus are required to be OPERABLE when the associated DG is required to be OPERABLE. One channel of Division 1 and 2 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) -

Secondary Time Delay Function per associated emergency bus is available and required to be OPERABLE when the associated DG is required to be OPERABLE. Three channels of Division 3 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) Function and Time Delay Function are available but only two are required to be OPERABLE when the associated DG is required to be OPERABLE. Note (a) has been added for the Division 1 and 2 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) protection requirements to ensure the required Degraded Voltage - 4.16 kV Basis and - Primary Time Delay Functions are associated with one another, since only two of the available channels for each Function are required to be OPERABLE. Refer to LCO 3.8.1 and LCO 3.8.2 for Applicability Bases for the DGs.

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LOP Instrumentation B 3.3.8.1 BASES ACTIONS (continued)

Because of the redundancy of sensors available to provide initiation signals and the redundancy of the onsite AC power source design, an allowable out of service time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is provided to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition D must be entered and its Required Action taken. The Required Actions do not allow placing the channel in trip since this action would cause the initiation.

C.1 With one or more channels of a Function inoperable, the Function is not capable of performing the intended function. Therefore, only 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to restore the inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action C.1. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.

Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the channel in trip would result in a bus transfer and DG initiation), Condition D must be entered and its Required Action taken.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

D.1, D.2.1, and D.2.2 If any Required Action and associated Completion Time of Condition B or C is not met, the associated Function may not be capable of performing the intended function. Therefore, the associated DG(s) are declared inoperable immediately (Required Action D.1). This requires entry into applicable Conditions and Required Actions of LCO 3.8.1 and LCO 3.8.2, which provide appropriate actions for the inoperable DG(s). - I Alternately, for Functions 1.c and 1.d only, the TR-B loss of voltage instrumentation, the offsite circuit supply breaker to the associated 4.16 kV ESF bus must be opened immediately (Required Action D.2.1) and the associated offsite circuit declared inoperable immediately (Required Action D.2.2). These alternate Required Actions also provide appropriate compensatory measures since the TR-B loss of voltage instrumentation only affects the loss of voltage trip capability of the alternate offsite circuit.

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LOP Instrumentation B 3.3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.8.1.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specific channel. The system functional testing performed in LCO 3.8.1 and LCO 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety functions.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. FSAR, Section 8.3.1.1.1.

2. FSAR, Section 5.2.

3. FSAR, Section 6.3.

4. FSAR, Chapter 15.

5. 10 CFR 50.36(c)(2)(ii).

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RPV Water Inventory Control B 3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEM (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.2 Reactor Pressure Vessel (RPV) Water Inventory Control BASES BACKGROUND The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF.

If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.

APPLICABLE With the unit in MODE 4 or 5, RPV water inventory control is not SAFETY required to mitigate any events or accidents evaluated in the safety ANALYSES analyses. RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material to the environment should an unexpected draining event occur.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not postulated considered in MODES 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is considered in which single operator error oran initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure (an event that creates a drain path through multiple vessel penetrations located below top of active fuel, such as e.g., seismic event, loss of normal power, or a single human error). It is assumed, based on engineering judgment, that while in MODES 4 and 5, one low pressure ECCS injection/spray subsystem can maintain adequate reactor vessel water level.

As discussed in References 1, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety.

Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).

LCO The RPV water level must be controlled in MODES 4 and 5 to ensure that if an unexpected draining event should occur, the reactor coolant water level remains above the top of the active irradiated fuel as required by Safety Limit 2.1.1.3.

The Limiting Condition for Operation (LCO) requires the DRAIN TIME of RPV water inventory to the TAF to be 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . A DRAIN TIME of 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months is considered reasonable to identify and initiate action to mitigate Columbia Generating Station B 3.5.2-1 Revision 111

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RPV Water Inventory Control B 3.5.2 unexpected draining of reactor coolant. An event that could cause loss of RPV water inventory and result in the RPV water level reaching the TAF Columbia Generating Station B 3.5.2-2 Revision 111

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RPV Water Inventory Control B 3.5.2 BASES LCO (continued) in greater than 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months does not represent a significant challenge to Safety Limit 2.1.1.3 and can be managed as part of normal plant operation.

One ECCS injection/spray subsystem is required to be OPERABLE and capable of being manually aligned and started from the control room to provide defense-in-depth should an unexpected draining event occur.

OPERABILITY of the ECCS injection/spray subsystem includes any necessary valves, instrumentation, or controls needed to manually align and start the subsystem from the control room. An ECCS injection/spray subsystem is defined as either one of the three Low Pressure Coolant Injection (LPCI) subsystems, one Low Pressure Core spray (LPCS)

System, or one High Pressure Core Spray (HPCS) System. The LPCS System and each LPCI subsystem consist of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV.

The HPCS System consists of one motor driven pump, piping, and valves to transfer water from the suppression pool or condensate storage tank (CST) to the RPV. The necessary portions of the Standby Service Water and HPCS Service Water Systems, as applicable, are also required to provide appropriate cooling to each required ECCS injection/spray subsystem.

The LCO is modified by a Note which allows a required LPCI subsystem (A or B) to be considered OPERABLE during alignment and operation for decay heat removal, if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable. Alignment and operation for decay heat removal includes when the RHR pump is not operating or when the system is being realigned from or to the RHR shutdown cooling mode. This allowance is necessary since the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Because of the restrictions on DRAIN TIME, sufficient time will be available following an unexpected draining event to manually align and initiate LPCI subsystem operation to maintain RPV water inventory prior to the RPV water level reaching the TAF.

APPLICABILITY RPV water inventory control is required in MODES 4 and 5.

Requirements on water inventory control in other MODES are contained in LCOs in Section 3.3, Instrumentation, and other LCOs in Section 3.5, ECCS, RPV Water Inventory Control and RCIC, and RPV Water Inventory Control. RPV water inventory control is required to protect Safety Limit 2.1.1.3 which is applicable whenever irradiated fuel is in the reactor vessel.

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RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE SR 3.5.2.1 REQUIREMENTS This Surveillance verifies that the DRAIN TIME of RPV water inventory to the TAF is 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The period of 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months is considered reasonable to identify and initiate action to mitigate draining of reactor coolant. Loss of RPV water inventory that would result in the RPV water level reaching the TAF in greater than 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months does not represent a significant challenge to Safety Limit 2.1.1.3 and can be managed as part of normal plant operation.

The definition of DRAIN TIME states that realistic cross-sectional areas and drain rates are used in the calculation. A realistic drain rate may be determined using a single, step-wise, or integrated calculation considering the changing RPV water level during a draining event. For a Control Rod RPV penetration flow path with the Control Rod Drive Mechanism removed and not replaced with a blank flange, the realistic cross-sectional area is based on the control rod blade seated in the control rod guide tube. If the control rod blade will be raised from the penetration to adjust or verify seating of the blade, the exposed cross-sectional area of the RPV penetration flow path is used.

The definition of DRAIN TIME excludes from the calculation those penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are locked, sealed, or otherwise secured in the closed positionclosed and administratively controlled, blank flanges, or other devices that prevent flow of reactor coolant through the penetration flow paths. A blank flange or other bolted device must be connected with a sufficient number of bolts to prevent draining in the event of an Operating Basis Earthquake. Normal or expected - I leakage from closed systems or past isolation devices is permitted.

Determination that a system is intact and closed or isolated must consider the status of branch lines and ongoing plant maintenance and testing activities.

The Residual Heat Removal (RHR) Shutdown Cooling System is only considered an intact closed system when misalignment issues (Reference 6) have been precluded by functional valve interlocks or by isolation devices, such that redirection of RPV water out of an RHR subsystem is precluded. Further, RHR Shutdown Cooling System is only considered an intact closed system if its controls have not been transferred to Remote Shutdown, which disables the interlocks and isolation signals.

The exclusion of single penetration flow paths, or multiple penetration flow paths susceptible to a common mode failure, from the determination of DRAIN TIME must should consider the potential effects of a single operator error or initiating event on items supportingtemporary alterations in support of maintenance maintenance and testing (rigging, scaffolding, Columbia Generating Station B 3.5.2-9 Revision 111

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RPV Water Inventory Control B 3.5.2 temporary shielding, piping plugs, snubber removal, freeze seals, etc.). If failure ofreasonable controls are implemented to prevent such items temporary alterations from could result and would causeing a draining event from a closed system, or between the RPV and the Columbia Generating Station B 3.5.2-10 Revision 111

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RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued) isolation device, the effect of the temporary alterations on DRAIN TIME need not be considered the penetration flow path may not be excluded from the DRAIN TIME calculation. Reasonable controls include, but are not limited to controls, consistent with the guidance of NUMARC 93-01, Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plans, Revision 4, NUMARC 91-06, Guidelines for Industry Actions to Assess Shutdown Management, or commitments to NUREG-0612, Control of Heavy Loads at Nuclear Power Plants.

Surveillance Requirement 3.0.1 requires SRs to be met between performances. Therefore, any changes in plant conditions that would change the DRAIN TIME requires that a new DRAIN TIME be determined.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.2 and SR 3.5.2.3 The minimum water level of 18 ft 6 inches required for the suppression pool is periodically verified to ensure that the suppression pool will provide adequate net positive suction head (NPSH) for the ECCS pump, recirculation volume (135,000 gallons consistent with the CST volume requirements described below), and vortex prevention. With the suppression pool water level less than the required limit, the required ECCS injection/spray subsystem is inoperable unless aligned to an OPERABLE CST (Ref. 9).

When the suppression pool level is < 18 ft 6 inches, the HPCS System is considered OPERABLE only if it can take suction from the CST and the CST water level is sufficient to provide the required NPSH for the HPCS pump. Therefore, a verification that either the suppression pool water level is 18 ft 6 inches or the HPCS System is aligned to take suction from the CST and the CST contains 135,000 gallons of water. This volume of water is equivalent to a level of 16.5 ft in a single CST or 10.5 ft in each CST above the top of the suction line. This ensures that the HPCS System can supply makeup water to the RPV. Calculations that determine this water level are listed as References 7 and 8.

The Surveillance Frequencies are controlled under the Surveillance Frequency Control Program.

SR 3.5.2.4 Columbia Generating Station B 3.5.2-11 Revision 111

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RPV Water Inventory Control B 3.5.2 The flow path piping has the potential to develop voids and pockets of entrained air. Maintaining the pump discharge lines of the required ECCS injection/spray subsystems full of water ensures that the ECCS subsystem will perform properly. This may also prevent a water hammer following an ECCS initiation signalactuation. One acceptable method of ensuring that the lines are full is to vent at the high points.

Columbia Generating Station B 3.5.2-12 Revision 111

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RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.5 Verifying the correct alignment for manual, power operated, and automatic valves in the required ECCS subsystem flow path provides assurance that the proper flow path will be available for ECCS operation.

This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.65 Verifying that the required ECCS injection/spray subsystem can be manuallymanually aligned, and the pump started and operated for at least 10 minutes demonstrates that the subsystem is available to mitigate a draining event. This SR is modified by two Notes. Note 1 states that Ttesting the ECCS injection/spray subsystem must may be done in such a waythrough the test return line to avoid overfilling the refueling cavity.

Note 2 states that credit for meeting the SR may be taken for normal system operation that satisfies the SR such as using the RHR mode of LPCI for 10 minutes.Thus, this SR is modified by a Note that states that injection into the vessel is not required. The minimum operating time of 10 minutes was based on engineering judgement.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.76 Verifying that each valve credited for automatically isolating a penetration flow path actuates to the isolation position on an actual or simulated RPV water level isolation signal is required to prevent RPV water inventory from dropping below the TAF should an unexpected draining event occur.

Columbia Generating Station B 3.5.2-13 Revision 111

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RPV Water Inventory Control B 3.5.2 The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Columbia Generating Station B 3.5.2-14 Revision 111

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RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.5.2.87 The required ECCS subsystem is required to have a manual start capability. This Surveillance verifies that a manual initiation signal will cause the required LPCI subsystem or LPCS System, or HPCS System to start and operate as designed, including pump startup and actuation of all automatic valves to their required positions. The HPCS system is verified to start manually from a standby configuration, and includes the ability to override the RPV Level 8 injection valve isolation can be manually aligned and started from the control room, including any necessary valve alignment, instrumentation, or controls, to transfer water from the suppression pool or CST to the RPV.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note that excludes vessel injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.

REFERENCES 1. Information Notice 84-81 "Inadvertent Reduction in Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup,"

November 1984.

2. Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.

3. Generic Letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(f), " August 1992.

4. NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," May 1993.

5. Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994.

6. General Electric Service Information Letter No. 388, "RHR Valve Misalignment During Shutdown Cooling Operation for BWR 3/4/5/6,"

February 1983.

7. E/I-02-91-1011.

8. E/I-02-98-1002.

Columbia Generating Station B 3.5.2-15 Revision 111

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AC Sources - Shutdown B 3.8.2 BASES APPLICABLE SAFETY ANALYSES (continued)

a. The fact that time in an outage is limited. This is a risk prudent goal as well as utility economic consideration.

b. Requiring appropriate compensatory measures for certain conditions.

These may include administrative controls, reliance on systems that do not necessarily meet typical design requirements applied to systems credited in operating MODE analyses, or both.

c. Prudent utility consideration of the risk associated with multiple activities that could affect multiple systems.

d. Maintaining, to the extent practicable, the ability to perform required functions (even if not meeting MODE 1, 2, and 3 OPERABILITY requirements) with systems assumed to function during an event.

In the event of an accident during shutdown, this LCO ensures the capability of supporting systems necessary to avoid immediate difficulty, assuming either a loss of all offsite power or a loss of all onsite (diesel generator (DG)) power.

The AC sources satisfy Criterion 3 of Reference 1.

LCO One offsite circuit supplying onsite Class 1E power distribution subsystem(s) of LCO 3.8.8, "Distribution Systems - Shutdown," ensures that all required loads are powered from offsite power. An OPERABLE DG, associated with a Division 1 or Division 2 Distribution System Engineered Safety Feature (ESF) bus required OPERABLE by LCO 3.8.8, ensures a diverse power source is available to provide electrical power support, assuming a loss of the offsite circuit. Similarly, when the high pressure core spray (HPCS) is required to be OPERABLE, an OPERABLE Division 3 DG ensures an additional source of power for the HPCS. Together, OPERABILITY of the required offsite circuit(s) and the ability to manually start a DG(s) ensures the availability of sufficient AC sources to operate the plant in a safe manner and to mitigate the consequences of postulated events during shutdown.

The qualified offsite circuit(s) must be capable of maintaining rated frequency and voltage while connected to their respective ESF bus(es),

and accepting required loads during an accident. Qualified offsite circuits are those that are described in the FSAR and are part of the licensing basis for the plant. The qualified offsite circuit includes the circuit path and disconnect to the respective transformer, the circuit path and breakers to the respective non-Class 1E 4.16 kV switchgear, SM-1, SM-2, and SM-3 (for the TR-S offsite circuit only), and the circuit path and breakers to the respective Class 1E switchgear (SM-4, SM-7, and SM-8) required by LCO 3.8.8.

Columbia Generating Station B 3.8.2-2 Revision 111

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AC Sources - Shutdown B 3.8.2 BASES LCO (continued)

The required DG must be capable of being manually starteding, accelerating to rated speed and voltage, and connecting to its respective ESF bus on detection of bus undervoltage, and accepting required loads.

This sequence must be accomplished within 15 seconds for Divisions 1 and 2, and 18 seconds for Division 3. The DG-3 18 second start time includes the Loss of Voltage - Time Delay Function specified in LCO 3.3.8.1, "Loss of Power (LOP) Instrumentation." Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and must continue to operate until offsite power can be restored to the ESF buses. These capabilities are required to be met from a variety of initial conditions such as: DG in standby with the engine hot and DG in standby with the engine at ambient conditions. Additional DG capabilities must be demonstrated to meet required Surveillances, e.g., capability of the DG to revert to standby status on an ECCS signal while operating in parallel test mode.

Proper sequencing of loads, including tripping of nonessential loads, is a required function for DG OPERABILITY. The necessary portions of the Standby Service Water and HPCS Service Water systems are also required to provide appropriate cooling to each required DG.

It is acceptable for divisions to be cross tied during shutdown conditions, permitting a single offsite power circuit to supply all required divisions. No fast transfer capability is required for offsite circuits to be considered OPERABLE.

APPLICABILITY The AC sources required to be OPERABLE in MODES 4 and 5 provide assurance that:

a. Systems that provide core cooling are available;

b. Systems necessary to mitigate the effects of events that can lead to core damage during shutdown are available; and

c. Instrumentation and control capability is available for monitoring and maintaining the unit in a cold shutdown condition or refueling condition.

The AC power requirements for MODES 1, 2, and 3 are covered in LCO 3.8.1.

Columbia Generating Station B 3.8.2-3 Revision 111

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AC Sources - Shutdown B 3.8.2 BASES ACTIONS (continued)

C.1 When the HPCS is required to be OPERABLE, and the Division 3 DG is inoperable, the required diversity of AC power sources to the HPCS is not available. Since these sources only affect the HPCS, the HPCS is declared inoperable and the Required Actions of LCO 3.5.2, "RPV Water Inventory Control" entered.

In the event all sources of power to Division 3 are lost, Condition A will also be entered and direct that the ACTIONS of LCO 3.8.8 be taken. If only the Division 3 DG is inoperable, and power is still supplied to HPCS, 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is allowed to restore the DG to OPERABLE. This is reasonable considering HPCS will still perform its function, absent an additional single failure.

SURVEILLANCE SR 3.8.2.1 REQUIREMENTS SR 3.8.2.1 requires the SRs from LCO 3.8.1 that are necessary for ensuring the OPERABILITY of the AC sources in other than MODES 1, 2, and 3. SR 3.8.1.8 is not required to be met since only one offsite circuit is required to be OPERABLE. SR 3.8.1.7, SR 3.8.1.11, SR 3.8.1.12, SR 3.8.1.13, SR 3.8.1.15, SR 3.8.1.18, and SR 3.8.1.19 are not required to be met because DG response on an offsite power or ECCS initiation signal is not required. SR 3.8.1.17 is not required to be met because the required OPERABLE DG(s) is not required to undergo periods of being synchronized to the offsite circuit. SR 3.8.1.20 is excepted because starting independence is not required with the DG(s) that is not required to be OPERABLE. Refer to the corresponding Bases for LCO 3.8.1 for a discussion of each SR.

This SR is modified by a Note which . The reason for the Note is to precludes requiring the OPERABLE DG(s) from being paralleled with the offsite power network or otherwise rendered inoperable during the performance of SRs, and to preclude de-energizing a required 4160 V ESF bus or disconnecting a required offsite circuit during performance of SRs. With limited AC sources available, a single event could compromise both the required circuit and the DG. It is the intent that these SRs must still be capable of being met, but actual performance is not required during periods when the DG and offsite circuit are required to be OPERABLE.

REFERENCES 1. 10 CFR 50.36(c)(2)(ii).

Columbia Generating Station B 3.8.2-6 Revision 111

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GO2-20-095 Attachment 3 Proposed Columbia Technical Specification Changes (Re-Typed)

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Definitions 1.1 1.1 Definitions Drain Time b) The limiting drain rate is the larger of the drain rate (Continued) through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure, for all penetration flow paths below the TAF except:

1. Penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are closed and administratively controlled in the closed position, blank flanges, or other devices that prevent flow of reactor coolant through the penetration flow paths;

2. Penetration flow paths capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation; or

3. Penetration flow paths with isolation devices that can be closed prior to the RPV water level being equal to the TAF by a dedicated operator trained in the task, who is in continuous communication with the control room, is stationed at the controls, and is capable of closing the penetration flow path isolation devices without offsite power.

c) The penetration flow paths required to be evaluated per paragraph b) are assumed to open instantaneously and are not subsequently isolated, and no water is assumed to be subsequently added to the RPV water inventory; d) No additional draining events occur; and e) Realistic cross-sectional areas and drain rates are used.

A bounding DRAIN TIME may be used in lieu of a calculated value.

EMERGENCY CORE The ECCS RESPONSE TIME shall be that time interval from COOLING SYSTEM (ECCS) when the monitored parameter exceeds its ECCS initiation RESPONSE TIME setpoint at the channel sensor until the ECCS equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where Columbia Generating Station 1.1-3 Amendment No. 149,169 225 243 251 260

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RPV Water Inventory Control Instrumentation 3.3.5.2 3.3 INSTRUMENTATION 3.3.5.2 Reactor Pressure Vessel (RPV) Water Inventory Control Instrumentation LCO 3.3.5.2 The RPV Water Inventory Control instrumentation for each Function in Table 3.3.5.2-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.5.2-1.

ACTIONS

NOTE-----------------------------------------------------------

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more channels A.1 Initiate action to place Immediately inoperable. channel in trip.

OR A.2.1 Declare associated Immediately penetration flow path(s) incapable of automatic isolation.

AND A.2.2 Initiate action to calculate Immediately DRAIN TIME.

Columbia Generating Station 3.3.5.2-1 Amendment No. 149,169 225 251

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RPV Water Inventory Control Instrumentation 3.3.5.2 SURVEILLANCE REQUIREMENTS

NOTE-----------------------------------------------------------

These SRs apply to each Function in Table 3.3.5.2-1, except SR 3.3.5.2.1 is not applicable to Function 2.a.

SURVEILLANCE FREQUENCY SR 3.3.5.2.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program SR 3.3.5.2.2 Perform CHANNEL FUNCTIONAL TEST. In accordance with the Surveillance Frequency Control Program Columbia Generating Station 3.3.5.2-2 Amendment No. 149,169 225 251

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RPV Water Inventory Control Instrumentation 3.3.5.2 Table 3.3.5.2-1 (page 1 of 1)

RPV Water Inventory Control Instrumentation APPLICABLE MODES OR REQUIRED OTHER CHANNELS SPECIFIED PER ALLOWABLE FUNCTION CONDITIONS FUNCTION VALUE

1. Residual Heat Removal (RHR) Shutdown Cooling (SDC) System Isolation

a. Reactor Vessel (a) 2 in one 9.5 inches Water Level - Low, trip system Level 3

2. Reactor Water Cleanup (RWCU) System Isolation

a. Reactor Vessel (a) 2 in one -58 inches Water Level - Low trip system Low, Level 2 (a) When automatic isolation of the associated penetration flow path(s) is credited in calculating DRAIN TIME.

Columbia Generating Station 3.3.5.2-3 Amendment No. 149,169 225 238 251

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Primary Containment Isolation Instrumentation 3.3.6.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME I. As required by Required I.1 Declare associated standby 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Action C.1 and liquid control (SLC) referenced in subsystem inoperable.

Table 3.3.6.1-1.

OR I.2 Isolate the Reactor Water 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Cleanup (RWCU) System.

J. As required by Required J.1 Initiate action to restore Immediately Action C.1 and channel to OPERABLE referenced in status.

Table 3.3.6.1-1.

SURVEILLANCE REQUIREMENTS

NOTES----------------------------------------------------------

1. Refer to Table 3.3.6.1-1 to determine which SRs apply for each Primary Containment Isolation Function.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the associated Function maintains isolation capability.

SURVEILLANCE FREQUENCY SR 3.3.6.1.1 Perform CHANNEL CHECK. In accordance with the Surveillance Frequency Control Program Columbia Generating Station 3.3.6.1-3 Amendment No. 149,169 225 238

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LOP Instrumentation 3.3.8.1 3.3 INSTRUMENTATION 3.3.8.1 Loss of Power (LOP) Instrumentation LCO 3.3.8.1 The LOP instrumentation for each Function in Table 3.3.8.1-1 shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3 ACTIONS

NOTE-----------------------------------------------------------

Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Enter the Condition Immediately channels inoperable. referenced in Table 3.3.8.1-1 for the channel.

B. As required by Required B.1 Declare associated DG 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months from discovery Action A.1 and inoperable. of loss of initiation referenced in capability for the Table 3.3.8.1-1. associated DG AND B.2 Restore channel to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months OPERABLE status.

C. As required by Required C.1 Place channel in trip. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Action A.1 and referenced in Table 3.3.8.1-1.

Columbia Generating Station 3.3.8.1-1 ---

Amendment No. 149,169 225 I

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ECCS - Operating 3.5.1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM 3.5.1 ECCS - Operating LCO 3.5.1 Each ECCS injection/spray subsystem and the Automatic Depressurization System (ADS) function of six safety/relief valves shall be OPERABLE.

APPLICABILITY: MODE 1, MODES 2 and 3, except ADS valves are not required to be OPERABLE with reactor steam dome pressure 150 psig.

ACTIONS

NOTE-----------------------------------------------------------

LCO 3.0.4.b is not applicable to High Pressure Core Spray (HPCS).

CONDITION REQUIRED ACTION COMPLETION TIME A. One low pressure ECCS A.1 Restore low pressure 7 days injection/spray ECCS injection/spray subsystem inoperable. subsystem to OPERABLE status.

B HPCS System B.1 Verify by administrative Immediately inoperable. means RCIC System is OPERABLE when RCIC System is required to be OPERABLE.

AND B.2 Restore HPCS System to 14 days OPERABLE status.

Columbia Generating Station 3.5.1-1 Amendment No. 187 225 230 245 251 253

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RPV Water Inventory Control 3.5.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C. DRAIN TIME < 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months C.1 Verify secondary 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . containment boundary is capable of being established in less than the DRAIN TIME.

AND C.2 Verify each secondary 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months containment penetration flow path is capable of being isolated in less than the DRAIN TIME.

AND C.3 Verify one standby gas 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months treatment (SGT) subsystem is capable of being placed in operation in less than the DRAIN TIME.

Columbia Generating Station 3.5.2-2 Amendment No. 169,210 225 238 251

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RPV Water Inventory Control 3.5.2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D. DRAIN TIME < 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . D.1 ----------- NOTE ---------------

Required ECCS injection/spray subsystem or additional method of water injection shall be capable of operating without offsite electrical power.

Initiate action to establish Immediately an additional method of water injection with water sources capable of maintaining RPV water level > TAF for 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

AND D.2 Initiate action to establish Immediately secondary containment boundary.

AND D.3 Initiate action to isolate Immediately each secondary containment penetration flow path or verify it can be automatically or manually isolated from the control room.

AND Immediately D.4 Initiate action to verify one SGT subsystem is capable of being placed in operation.

Columbia Generating Station 3.5.2-3 Amendment No. 169,205 225 229 238 243 246 251

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RPV Water Inventory Control 3.5.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.2.4 Verify, for the required ECCS injection/spray In accordance subsystem, locations susceptible to gas with the accumulation are sufficiently filled with water. Surveillance Frequency Control Program SR 3.5.2.5 -------------------------------NOTE------------------------------

1. Operation may be through the test return line.

2. Credit may be taken for normal system operation to satisfy this SR.

Operate the required ECCS injection/spray subsystem for 10 minutes. In accordance with the Surveillance Frequency Control Program SR 3.5.2.6 Verify each valve credited for automatically isolating In accordance a penetration flow path actuates to the isolation with the position on an actual or simulated isolation signal. Surveillance Frequency Control Program SR 3.5.2.7 -------------------------------NOTE------------------------------

Vessel injection/spray may be excluded.

Verify the required ECCS injection/spray subsystem can In accordance be manually operated. with the Surveillance Frequency Control Program Columbia Generating Station 3.5.2-5 Amendment No. 251

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AC Sources - Shutdown 3.8.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.2.1 -------------------------------NOTE------------------------------

The following SRs are not required to be performed:

SR 3.8.1.3, SR 3.8.1.9, SR 3.8.1.10, SR 3.8.1.14 and SR 3.8.1.16.

The following SRs are applicable for AC sources required to be OPERABLE: In accordance with applicable SR 3.8.1.1 SR 3.8.1.6 SRs SR 3.8.1.2 SR 3.8.1.9 SR 3.8.1.3 SR 3.8.1.10 SR 3.8.1.4 SR 3.8.1.14 SR 3.8.1.5 SR 3.8.1.16 Columbia Generating Station 3.8.2-3 Amendment No. 199,205 225

v t e Letter Sequence Request
EPID:L-2020-LLA-0212, TSTF-582 (Approved, Closed)
Initiation Request Acceptance Administration Questions Answers Results Approval Other:
MONTHYEAR2020-09-24 [Table View]

GO2-20-095, Application to Revise Technical Specifications to Adopt TSTF-582, 'Reactor Pressure Vessel Water Inventory Control (RPV WIC) Enhancements

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Subject:

Dear Sir or Madam:

Enclosure:

1.0 DESCRIPTION

3.0 REGULATORY ANALYSIS

4.0 CONCLUSION

5.0 ENVIRONMENTAL CONSIDERATION

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GO2-20-095, Application to Revise Technical Specifications to Adopt TSTF-582, 'Reactor Pressure Vessel Water Inventory Control (RPV WIC) Enhancements

Text

Subject:

Dear Sir or Madam:

Enclosure:

1.0 DESCRIPTION

3.0 REGULATORY ANALYSIS

4.0 CONCLUSION

5.0 ENVIRONMENTAL CONSIDERATION

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