peach bottom, units 2 & 3 license amendment request ... · pbaps incorporation of generic...

Exekanm.Exelon Nuclear www.exeloncorp.com Nuclear200 Exelon WayKennett Square, PA 19348

10 CFR 50.90

June 24, 2004

United States Nuclear Regulatory CommissionATTN: Document Control DeskWashington, D.C. 20555-0001

Peach Bottom Atomic Power Station, Units 2 and 3Facility Operating License Nos. DPR-44 and DPR-56NRC Docket Nos. 50-277 and 50-278

Subject: License Amendment RequestIncorporation of Previously NRC-Approved Generic TechnicalSpecification Changes

Pursuant to 10 CFR 50.90, Exelon Generation Company, LLC (EGC) hereby requestsproposed changes to incorporate various previously NRC-approved Technical SpecificationTask Force travelers (TSTFs). These pre-approved TSTFs were chosen due to their relativelysimple content and the ability of PBAPS to easily conform to the pre-approved TSTF wordingwithout changes. A listing of the proposed TSTFs is contained in Attachment 1.

EGC requests approval of the proposed amendment by June 24, 2005. Once approved, theamendment shall be implemented within 90 days.

No additional regulatory commitments are contained in this request.

The proposed changes have been reviewed by the Plant Operations Review Committee andapproved by the Nuclear Safety Review Board. This information is being submitted underunsworn declaration.

We are notifying the State of Pennsylvania of this application for changes to the TS andOperating Licenses by transmitting a copy of this letter and its attachments to the designatedstate official.

PBAPS Incorporation of Generic Technical Specifications ChangesJune 24, 2004

Upon approval, we request 90 days to implement this change. Due to the size of this changeand the potential impact on other pages currently in revision, camera ready pages will besupplied prior to approval.

If you have any questions or require additional information, please contact Tom Loomis at(610) 765- 5510.

I declare under penalty of perjury that the foregoing is true and correct.

Respectfully,

I I/M/OiExecuted onMichael P. GallagherDirector, Licensing and Regulatory Affairs

Enclosures: Attachment A - Description of Proposed Changes, Technical Analysis,and No Significant Hazards ConsiderationAttachment B - Marked up Technical Specifications and Bases Pages(Units 2 and 3)

cc: H. J. Miller, Administrator, Region I, USNRCC. L. Smith, USNRC Senior Resident Inspector, PBAPSG. Wunder, Senior Project Manager, USNRCR. R. Janati, Commonwealth of Pennsylvania

ATTACHMENT A

PBAPS Incorporation of Generic NRC-ApprovedTechnical Specification Task Force Travelers (TSTFs)

Description of Proposed Changes, Technical Analysis,and No Significant Hazards Consideration

Topic Page

1.0 DESCRIPTION 2

2.0 PROPOSED CHANGES, TECHNICAL ANALYSIS, AND NO 3SIGNIFICANT HAZARDS CONSIDERATION

2.1 TSTF-5, Rev. 1 - Safety Limit Reporting Requirements 32.2 TSTF-208, Rev. 0 - Mode 2 Entry Time Limits 52.3 TSTF-222, Rev. 1 - Post-refuel Scram Time Testing & TSTF-229, Rev. 0

- MCPR Surveillance after Scram Time Testing 82.4 TSTF-297, Rev.1 & TSTF-227, Rev. 0 - Enhancements to Feedwater /

Main Turbine High Water Level Trip, EOC-RPT, and ATWS RPTSpecifications 10

2.5 TSTF-295, Rev. 0 - Post Accident Monitoring Clarifications 142.6 TSTF-275, Rev. 0 - ECCS Instrumentation Clarifications 162.7 TSTF-306, Rev. 2 - Traversing In-core Probe Instrumentation

Specifications Requirements 182.8 TSTF-416, Rev. 0 - Clarification of LPCI Operability during Decay Heat

Removal Operations 212.9 TSTF-17, Rev. 2 - Containment Airlock Testing Frequency 242.10 TSTF-30, Rev. 3, TSTF-323, Rev. 0, TSTF-45, Rev. 2, TSTF-46, Rev. 1,

TSTF-269, Rev. 2 - Containment Isolation Valve Specifications Changes 262.11 TSTF-322, Rev. 2 - Secondary Containment Operability Clarification 302.12 TSTF-276, Rev. 2- Power Factor for Diesel Surveillances 322.13 TSTF-404, Rev. 0 - Scram Discharge Volume Vent and Drain Valves 342.14 Technical Specification 5.0, Administrative Controls Proposed Revisions

* TSTF-65, Rev. 1 - Generic Organizational Titles* TSTF-299, Rev. 0 - Primary Coolant Sources Inspection Requirements* TSTF-279, Rev. 0 - In-service Testing Program Clarifications* TSTF-1 18, Rev. 0 & TSTF-1 06, Rev. 1 - Diesel Generator Fuel Oil

Testing Program Clarifications* TSTF-1 52, Rev. 0- Routine Reporting Requirements Upgrade 35

3.0 ENVIRONMENTAL CONSIDERATIONS' 41

4.0 REFERENCES 42

1

PBAPS Incorporation of Generic NRC-ApprovedTechnical Specification Task Force Travelers (TSTFs )

Attachment 1Page 2 of 42

Description of Proposed Changes, Technical Analysis,and No Significant Hazards Consideration

1.0 DESCRIPTION

This letter is a request to amend Operating License(s) DPR-44 and DPR-56 for Peach BottomAtomic Power Station (PBAPS), Units 2 and 3.

The proposed changes would revise the Operating Licenses to incorporate certain TSTFs thathave been previously reviewed and approved by the NRC. These TSTFs were selected, in part,based on their simplicity of review and ease of implementation. Exelon Generation Company,LLC (EGC) believes that the extent of compliance to the previously approved TSTFs outlined inthis submittal should make NRC review straightforward.

The following table identifies the TSTFs sought for approval and the corresponding affectedsections of the PBAPS Technical Specifications. Also, associated Bases changes are involvedas indicated on the table.

TSTF Impact on PBAPS Technical Specifications

TSTF # TSTF Short Title PBAPS Tech Spec Change_____ _____ ____R e g'd?

TSTF-5, Rev. 1 Safety Limit Reporting Requirements 2.2 YesTSTF-17, Rev. 2 Containment Airlock Testing Frequency 3.6.1.2 YesTSTF-30, Rev. 3 Closed system isolation valves 3.6.1.3 YesTSTF-45, Rev. 2 Exempt verification of CIVs not locked, 3.6.1.3, 3.6.4.2 Yes

sealed or securedTSTF-46, Rev. 1 Clarify CIV surveillance for automatic 3.6.1.3, 3.6.4.2 Yes

valvesTSTF-65, Rev. 1 Generic Organizational Titles 5.1, 5.2, 5.5.1 NoTSTF-106, Rev. 1 Diesel Generator Fuel Oil Testing Program 5.5.9 No

ClarificationsTSTF-1 18, Rev. 0 Diesel Generator Fuel Oil Testing Program 5.5.9 No

ClarificationsTSTR-152, Rev. 0 Routine Reporting Requirements Upgrade 5.6.1, 5.6.3 NoTSTF-208, Rev. 0 Mode 2 Entry Time Limits 3.0.3 NoTSTF-222, Rev. 1 Post-refuel Scram Time Testing 3.1.4 YesTSTF-227, Rev. 0 EOC-RPT actions only applicable if 3.3.4.2 Yes

required channels are inoperableTSTF-229, Rev. 0 MCPR Surveillance after Scram Time 3.2.2 Yes

____ ___ ____ ___ T esting _ _ _ _

TSTF-269, Rev. 2 Locked, sealed or secured valves may be 3.6.4.2 Yesverified administratively

TSTF-275, Rev. 0 ECCS Instrumentation Clarifications 3.3.5.1 YesTSTF-276, Rev. 2 Diesel Surveillance Power Factors 3.8.1 YesTSTF-279, Rev. 0 In-service Testing Program Clarifications 5.5.6 NoTSTF-295, Rev. 0 Post Accident Monitoring Clarifications 3.3.3.1 YesTSTF-297, Rev. 1 Enhancements to Feedwater/Main Turbine 3.3.2.2, 3.3.4.1, Yes

High Water Level Trip, EOC-RPT, and 3.3.4.2ATWS RPT Specifications



PBAPS Tech Spec BasesTSTF # TSTF Short Title Sections Affected Change

Rq'dTSTF-299, Rev. 0 Primary Coolant Sources Inspection 5.5.2 No

RequirementsTSTF-306, Rev. 2 Traversing In-core Probe Instrumentation 3.3.6.1 Yes

Specifications RequirementsTSTF-322, Rev. 2 Secondary Containment Operability 3.6.4.1 Yes

ClarificationTSTF-323, Rev. 0 Inoperable EFCVs Completion Time 3.6.1.3 Yes

ExtensionTSTF-404, Rev. 0 Scram Discharge Volume Vent and Drain 3.1.8 Yes

Valves I ITSTF-416, Rev. 0 Clarification of LPCI Operability during 3.5.1, 3.5.2 Yes

Decay Heat Removal Operations I I

The TSTFs are grouped into 14 individual analyses as provided in sections 2.1 through 2.14 ofthis request. This grouping reflects changes made to common pages and/or sections of thePBAPS Technical Specifications or are otherwise related to each other. Each analysisdescribes the impact on the PBAPS Technical Specifications, an assessment of the TSTF onthe PBAPS Technical Specifications including any deviations taken to the approved TSTF, anda determination that no significant hazards exist as a result of the activity.

2.0 PROPOSED CHANGES, TECHNICAL ANALYSIS, AND NO SIGNIFICANT HAZARDSCONSIDERATION

2.1 TSTF-5, Rev. 1 - Delete Safety Limit Violation Notification Requirement

Proposes Changes:

TSTF-5, Rev.1 modifies Improved Technical Specifications (NUREG-1433) section 2.2 toremove the requirements to report safety limit violations. Associated references to 10 CFR50.72 and 10 CFR 50.73 are also removed.

EGC proposes to revise PBAPS Technical Specification section 2.2 to remove the requirementto perform certain notifications in the event of a Safety Limit violation. Specifically beingremoved are the requirements to notify the NRC Operations Center within 1 hour, to notify thePBAPS Plant Manager and Vice President within 24 hours, and to submit a Licensee EventReport (LER) within 30 days. Also, the requirement to not resume unit operation until authorizedby the NRC is being removed from the Technical Specifications.

The associated Technical Specification Bases wording concerning these reporting requirementswill be removed as part of this licensing action.

See the attached marked up pages for PBAPS Units 2 and 3 included in Attachment B for thedetails concerning the specific changes.

PBAPS Incorporation of Generic NRC-Approved Attachment 1Technical Specification Task Force Travelers (TSTFs ) Page 4 of 42

List of Affected Pages Unit ApplicabilityUnit 2 Unit 3

2.0-1 X X2.0-2 X XB 2.0-5 X XB 2.0-6 X XB 2.0-8 X XB 2.0-9 X XB 2.0-10 X X

Technical Analysis:

The removal of these reporting requirements from Technical Specifications is considered anadministrative action. These reporting requirements are duplicative of what is already containedin the regulations (i.e., 10 CFR 50.36). The reporting requirements in 10 CFR 50.36 require thatappropriate prompt notifications are made to the NRC and that LERs are submitted to the NRC.10 CFR 50.36 requires that these reports be performed in accordance with the requirements of10 CFR 50.72 and 10 CFR 50.73. Therefore, if a Technical Specification safety limit is violated,appropriate reporting will be made to the NRC in accordance with the regulations. Removal ofduplicative reporting requirements from the Technical Specifications results in simplification ofthe Technical Specifications and Bases and less administrative burden to track duplicativereporting requirements. Adequate administrative controls exist in administrative programs atPBAPS for the identification and necessary reporting of safety limit violations in accordancewith 10 CFR 50.36, 10 CFR 50.72 and 10 CFR 50.73.

There are no deviations in the proposed PBAPS Technical Specifications or Bases from thepre-approved TSTF.

As precedence, the following Safety Evaluation Report was approved by the NRC for thisTSTF:

NRC Safety Evaluation Report for Grand Gulf, 6/30/00, Technical SpecificationAmendment 142

No Significant Hazards Consideration:

EGC has evaluated whether or not a significant hazards consideration is involved with theproposed amendment(s) by focusing on the three standards set forth in 10 CFR 50.92,"Issuance of Amendment," as discussed below:

1. Does the proposed change involve a significant increase in the probability orconsequences of an accident previously evaluated?

Response: No.

This action does not affect the plant or operation of the plant. The change simplyremoves duplicative information from the Technical Specifications that is covered in theNRC regulations. Therefore, the proposed change does not involve a significantincrease in the probability or consequences of an accident previously evaluated.

PBAPS Incorporation of Generic NRC-Approved Attachment 1Technical Specification Task Force Travelers (TSTFs) Page 5 of 42

2. Does the proposed change create the possibility of a new or different kind of accidentfrom any accident previously evaluated?

Response: No.

No new accident scenarios, failure mechanisms, or limiting single failures are introducedas a result of the proposed changes. All systems, structures, and componentspreviously required for the mitigation of a transient remain capable of fulfilling theirintended design functions. The proposed changes have no adverse effects on anysafety-related system or component and do not challenge the performance or integrityof any safety related system. This change is considered an administrative action toremove duplicative reporting requirements.

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

3. Does the proposed change involve a significant reduction in a margin of safety?

Response: No.

This administrative action does not involve any reduction in a margin of safety. Removalof duplicative information does not affect compliance with the regulations. Therefore, theproposed change does not involve a significant reduction in a margin of safety.

Conclusion:

Based on the above, EGC concludes that the proposed amendment(s) present no significanthazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, afinding of "no significant hazards consideration" is justified.

2.2 TSTF-208, Rev. 0 - Extension of Time to Reach Mode 2 In LCO 3.0.3

Proposed Changes:

TSTF-208, Rev. 0 modifies Improved Technical Specification (NUREG-1433) section LCO 3.0.3to revise the time to be in Mode 2 once LCO 3.0.3 is entered from 7 hours to a bracketed sitespecific time depending on the individual plant's ability to reach Mode 2 in a controlledshutdown.

EGC proposes to revise PBAPS Technical Specification section LCO 3.0.3 to state that onceLCO 3.0.3 is entered, 10 hours are required to reach Mode 2. The current TechnicalSpecification requires 7 hours to reach Mode 2. The associated Technical Specification Basesdo not require revision.



.Unit ApplicabilityList of Affected Pages UnitA

Unit 2 Unit 3

3.0-1 X X

Technical Analysis:

It has been determined that 10 hours is a more appropriate time to reach Mode 2 in a controlledshutdown. This is based on site-specific considerations. Technical Specifications require actionto be initiated within 1 hour to place the unit in Mode 2 within 7 hours. Therefore, 6 hours iscurrently available for the plant to be brought to Mode 2 in a controlled shutdown. PBAPS is alarge BWR/4 with 185 control rods. PBAPS, Unit 3 operating experience reveals that 6 hours (inaddition to the 1 hour to initiate shutdown actions) would not be sufficient time to reach Mode 2by performing a shutdown with control rods. The intent of the NUREG-1433 LCO 3.0.3 actiontime to reach Mode 2 is to require an expeditious yet orderly shutdown. This ensures that thereactor shutdown would be done in a prompt manner while not unduly increasing the likelihoodof plant transients. This is especially important since the plant, by being in LCO 3.0.3, is alreadyin a degraded condition.

In accordance with TSTF-208, it has been determined that at older BWRs, it can take longerthan the available 6 hours to reach Conditions where the plant can be placed in Mode 2. AtPBAPS, it has been determined that approximately 9 hours is required to reach Mode 2 in acontrolled manner. Assuming one hour is provided to initiate actions, this would result in 10hours as being an appropriate time for reaching Mode 2 in LCO 3.0.3. Based on actualshutdown data at PBAPS, Unit 3 resulting in placing the plant in Mode 2 prior to inserting ascram, a shutdown using control rods and performing all required surveillances tookapproximately 18 hours (based on an actual 5/4/92 shutdown). During the shutdown for therefuel outage (2R14), it took approximately 6 and Y/2 hours to go from 85% power toapproximately 18% power at which time a manual scram was inserted. Had the shutdowncontinued using control rods, it is estimated that another 2 and 1/2 hours would have beenrequired to perform control rod insertions and other actions (e.g., pre-job briefs) prior to movingthe Mode switch to Startup / Hot Standby and entering Mode 2. This would result inapproximately 9 hours to perform a controlled shutdown from 100% down to a power level atwhich the Mode switch could be moved such that Mode 2 was entered. Therefore, adding the 1hour to initiate actions, a total of 10 hours is appropriate for the time necessary to be in Mode 2.

Moreover, the proposed 10 hour requirement is similar to a Browns Ferry submittal by theTennessee Valley Authority (see Letter, TVA to NRC dated 8/28/00). Since Brown Ferry is verysimilar in design and operation to Peach Bottom, additional confirmation is provided that 10hours is the appropriate time frame for reaching Mode 2 in LCO 3.0.3.

There are no deviations in the proposed PBAPS Technical Specifications from the pre-approved TSTF.

NRC Precedents:

As precedence, the following Safety Evaluation Report was approved by the NRC for thisTSTF:

* NRC Safety Evaluation Report for Browns Ferry, 11/21/00, Technical SpecificationAmendments 239, 266, 226





Response: No.

The time frame to take response action in accordance with LCO 3.0.3 is not an initiatingcondition for any accident previously evaluated and the accident analyses do notassume that any equipment is out of service such that LCO 3.0.3 is entered. The smallincrease in the time allowed to reach Mode 2 would not place the plant in anysignificantly increased probability of an accident occurring. The plant would already beproceeding to a plant shutdown condition because of the 1 hour requirement to initiateshutdown actions. There is no change in the time period to reach Mode 3. The Mode 3Condition is the point where the plant is shutdown. Therefore, since there is no changeto the 1 hour requirement to initiate the shutdown nor any change to the time period toreach the shutdown Condition, the small change in the time to reach the Mode 2 statusdoes not involve a significant increase in the probability or consequences of an accidentpreviously evaluated.


Response: No.

No new accident scenarios, failure mechanisms, or limiting single failures are introducedas a result of the proposed changes. There are no plant physical alterations proposed.The proposed changes have no adverse effects on any safety-related system orcomponent and do not challenge the performance or integrity of any safety relatedsystem. Therefore, the proposed change does not create the possibility of a new ordifferent kind of accident from any previously evaluated.


Response: No.

The time period to reach Mode 3 and Mode 4 are unaffected by this activity. Thischange simply provides a plant specific value for reaching Mode 2 if LCO 3.0.3 isentered which is within the intent of LCO 3.0.3 for performing a controlled plantshutdown. Therefore, the proposed change does not involve a significant reduction in amargin of safety.

Conclusion:



2.3 TSTF-222, Rev. 1 - Control Rod Scram Time Testing & TSTF-229, Rev. 0 - ReviseS.R. 3.2.2.2 for Consistency With 3.1.4.4

Proposed Changes:

TSTF-222, Rev. 1:

This TSTF modifies Improved Technical Specifications (NUREG-1433) to clarify the frequencyof performing control rod scram time testing subsequent to performance of an outage thatinvolved the movement of fuel. The current wording of SR 3.1.4.1 could be interpreted that allcontrol rods need to be scram time tested even if the shutdown was for a brief amount of timeand only a limited amount of fuel was moved in the reactor (e.g., if only one bundle is moved ina mid-cycle fuel replacement). This change clarifies the intent of the Technical Specifications.

TSTF-229, Rev. 0:

This TSTF modifies Improved Technical Specifications to determine (Minimum Critical PowerRatio) MCPR limits after performance of scram time testing under SR 3.1.4.4 by adding a newrequirement to SR 3.2.2.2.

It is proposed to revise PBAPS Technical Specification section 3.1.4 to remove the surveillancetest requirement to scram time test all control rods after each refueling outage. Only thosecontrol rods that reside in core cells that were affected by the refueling outage need will need tobe scram time tested after the refueling outage prior to reaching 40% rated thermal power(RTP). To affect this change, the frequency statements in SR 3.1.4.1 and SR 3.1.4.4 will berevised.

The associated Technical Specification 3.1.4 Bases will also be revised to reflect thesechanges. The Bases will be clarified, in accordance with the approved TSTF, to discuss thatcontrol rods located in core cells affected by moved fuel will be scram time tested. Also, aclarifying statement will be made that explains that for normal refueling outages, all control rodswould be affected and require the testing.

It is also proposed to add an additional requirement in Technical Specification section 3.2.2 torequire Minimum Critical Power Ratio (MCPR) to be determined subsequent to scram timetesting required by SR 3.1.4.4. This change includes adding an additional reference to SR3.1.4.4 in the frequency statement in SR 3.2.2.2.

The Technical Specification Bases for SR 3.2.2.2 will also be revised to reflect the additionalrequirement for a determination of MCPR.

See the attached marked up pages for PBAPS Units 2 and 3 included in Attachment B.

Unit ApplicabilityList of Affected Pages Unit 2 p Unit3

Unit 2 Unit 33.1-12 X X3.1-13 X XB 3.1-25 X XB 3.1-27 X X3.2-3 X XB 3.2-9 X X


Technical Analysis:

TSTF-222, Rev. 1:

The current wording of SR 3.1.4.1 could be interpreted that all control rods need to be scramtime tested even if the shutdown was for a brief amount of time and only a limited amount offuel was moved in the reactor (e.g., if only one bundle is moved in a mid-cycle fuelreplacement). The current SR 3.1.4.1 requires that control rod scram time testing be performed"prior to exceeding 40% RTP after each refueling outage". If a mid-cycle outage occurredwhere, for example, a single fuel assembly was changed out, the Technical Specificationswould require scram time testing on all 185 control rods, rather than only the one that wasaffected by replacing one fuel assembly. The SR 3.1.4.1 requirement to scram time test controlrods for plant shutdowns in excess of 120 days is unaffected by this activity. The control rodscram time testing requirement in SR 3.1.4.1, "prior to exceeding 40% RTP after each refuelingoutage" is being removed. SR 3.1.4.4 control rod scram time testing is being clarified to requirecontrol rod scram time testing after fuel movement within the affected core cell. This ensuresthat all control rods that exist in core cells that were involved with fuel movements are scramtime tested. Therefore, the requirement to scram time test all control rods during a normalrefuel outage where all reactor fuel cells are typically affected is not changed by this activity.


TSTF-229, Rev. 0:

Existing surveillance requirements only specify determining the scram time parameter whencontrol rods are scram time tested after refueling and extended outages (SR 3.1.4.1) and afterthe periodic on-line scram time testing (SR 3.1.4.2). However, there is currently no requirementto evaluate the impact of the scram time parameter after performing scram time testing aftermaintenance on individual control rods or the CRD system as required by SR 3.1.4.4. While it isnot likely that the scram time parameter will be affected as, generally, not many control rods arerequired to be tested under SR 3.1.4.4 at any one time, there is no limit to the number of controlrods that could be potentially tested, such that the scram time parameter might be affected.Therefore, the proposed change is conservative to include this MCPR determinationrequirement.

The proposed change will introduce consistency of application of SR 3.2.2.2 between the scramtime requirements of SRs 3.1.4.1, 3.1.4.2, and 3.1.4.4. There are no deviations in the proposedPBAPS Technical Specifications from the pre-approved TSTF.

As precedence, the following Safety Evaluation Report was approved by the NRC for TSTF-222:

NRC Safety Evaluation Report for Browns Ferry,11/21/00, Technical SpecificationAmendments 239, 266, 226





Response: No.

These changes are considered clarifications to the original intent of the TechnicalSpecifications. Adequate testing of control rods is ensured by this change. Control rodoperability is not affected by these changes. Therefore, the proposed change does notinvolve a significant increase in the probability or consequences of an accidentpreviously evaluated.


Response: No.

No new accident scenarios, failure mechanisms, or limiting single failures are introducedas a result of the proposed changes. All systems, structures, and componentspreviously required for the mitigation of a transient remain capable of fulfilling theirintended design functions. The proposed changes have no adverse effects on anysafety-related system or component and do not challenge the performance or integrityof any safety related system. Therefore, the proposed change does not create thepossibility of a new or different kind of accident from any previously evaluated.


Response: No.

This change is administrative in nature and does not affect any safety analysesassumptions. Adequate control rod testing continues to be maintained withimplementation of this activity. Therefore, the proposed change does not involve asignificant reduction in a margin of safety.

Conclusion:


2.4 TSTF-297, Rev.1 & TSTF-227, Rev. 0 - Enhancements to Feedwater / Main TurbineHigh Water Level Trip, EOC-RPT, and ATWS RPT Specifications

Proposed Changes:

These two TSTFs affect the following three PBAPS Technical Specification Sections:

* 3.3.2.2 - Feedwater and Main Turbine High Water Level Trip Instrumentation* 3.3.4.1 - Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT)

Instrumentation* 3.3.4.2 - End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation


TSTF-297, Rev. 1:

TSTF-297, Rev. 1 modifies Improved Technical Specifications (NUREG-1433) to add a newRequired Action and corresponding note to allow affected feedwater pump(s) and main turbinevalve(s) to be removed from service. This change is necessary to allow components to beremoved from service to fulfill the safety function without a reduction in power to less than 25%rated thermal power. A similar note is added to Technical Specification sections 3.3.4.1 and3.3.4.2 to provide the same clarification for when the associated Required Action is theappropriate action.

TSTF-227, Rev. 0:

This TSTF modifies Improved Technical Specifications (NUREG-1433) to eliminate ambiguity inthe EOC-RPT Instrumentation Condition A. Since the LCO allows for having EOC-RPTinstrumentation OPERABLE or certain fuel thermal limits are met, Condition A wasinappropriately worded. The wording of Condition A is revised to add the word 'required' if oneor more channels are inoperable. Without the word 'required', one could interpret Condition Aas needing entry even if the fuel thermal limits were being applied instead of applying theoperability requirements to the EOC-RPT instrumentation.

It is proposed to revise Technical Specification 3.3.2.2, Feedwater and Main Turbine HighWater Level Trip Instrumentation to add an additional Required Action to allow for removal fromservice of the affected reactor feedwater pump turbine or main turbine stop valve if theinoperable trip instrumentation channel is the result of an inoperable reactor feedwater pumpturbine or main turbine stop valve.

The associated Technical Specification 3.3.2.2 Bases will also be revised to reflect thisadditional Required Action. The Bases will state that the removal from service of the affectedmain turbine stop valve or reactor feedpump turbine will ensure that the intended function of theinstrumentation is performed.

It is proposed to revise Technical Specification 3.3.4.1, ATWS-RPT Instrumentation, to add anote and make one word change to Required Action D.1. Currently, Required Action D.1 allowsfor the associated recirculation pump to be removed from service if the trip instrumentation cannot be returned to an OPERABLE status. The proposed change involves changing the word'associated' to 'affected' and adding a note that says that the Required Action (D.1) of removingthe recirculation pump from service only applies if the inoperable channel is the result of aninoperable recirculation pump trip (RPT) breaker.

The associated Technical Specification 3.3.4.1 Bases will also be revised to reflect the additionof the note to Required Action D.1. This note clarifies situations under which the associatedRequired Action would be the appropriate Required Action.

It is proposed to revise Technical Specification 3.3.4.2, EOC-RPT Instrumentation, to add anote and make one word change to Required Action C.1. Currently, Required Action C.1 allowsfor the associated recirculation pump to be removed from service if the trip instrumentation cannot be returned to an OPERABLE status. The proposed change involves changing the word'associated' to 'affected' and adding a note that says that the Required Action (C.1) of removingthe recirculation pump from service only applies if the inoperable channel is the result of aninoperable recirculation pump trip (RPT) breaker. Also, the word 'required' is being added to



Condition A of this Technical Specification to clarify that the Condition refers to a channel thatwould be required if the instrumentation option of LCO 3.3.4.2 is being used.

The associated Technical Specification 3.3.4.2 Bases will also be revised to reflect the additionof the note to Required Action C.1. This note clarifies situations under which the associatedRequired Action would be the appropriate Required Action. Also, the Bases will be revised toadd references to actions to be taken for 'required' instrumentation with regards to entry intoCondition A.


Unit ApplicabilityList of Affected Pages

Unit 2 Unit 33.3-22 X XB 3.3-62 XB 3.3-63 X3.3-30 X XB 3.3-89 XB 3.3-90 X3.3-31 a X X3.3-31 b X XB 3.3-91f XB 3.3-91g gB 3.3-92f_ XB 3.3-92g X

Technical Analysis:

TSTF-297, Rev. 1:

This change allows for operational flexibility that could prevent an unnecessary plant powerreduction to below 25% rated thermal power. For example, if an individual reactor feedwaterpump lost its trip capability, plant power may be required to be reduced to below 25% ratedthermal power if repairs could not be promptly made. This could be an unnecessary plant powerreduction if the affected reactor feedwater pump turbine can be removed from service, therebyfulfilling the intended function. The current wording of the Technical Specification 3.3.2.2Required Actions does not allow for this option. Currently, the Technical Specifications wouldrequire a power reduction below 25% even if the reactor feedwater pump could be removedfrom service. This proposed change would allow for the removal of the inoperable equipmentfrom service, thereby ensuring its function is performed while not requiring the plant toexperience an unnecessary transient. In this Condition, the safety function has beenimplemented and therefore, no additional compensatory measures are required.


Technical Specifications 3.3.4.1 and 3.3.4.2 already have provisions to remove the associatedrecirculation pump from service if the trip function is lost. However, modified wording and a noteare added to the Technical Specifications to ensure clarity exists. The changing of the word'associated' to 'affected' is considered administrative and provides better clarity. The addition ofthe note does not actually change the Technical Specification requirements, but the additionprovides clarity that the Required Action to remove the affected recirculation pump from serviceis only applicable if the inoperable channel is the result of an inoperable RPT breaker. Theassociated Required Action to which the note is being added should only apply if there is a lossof the ability for the RPT breaker to trip. A separate Required Action (A.2) exists to directplacing the inoperable channel in trip if required. Therefore, the addition of the note providesgreater clarity that Required Action D.1 for Technical Specification 3.3.4.1 and Required ActionC.1 for Technical Specification 3.3.4.2 only applies for an inoperable RPT breaker.

There are no deviations in the proposed PBAPS Technical Specifications from the pre-approved TSTF. The plant specific terminology for the actuated equipment in the Note forRequired Action C.1 for Technical Specification 3.3.2.2 is inserted in the bracketed position.

TSTF-227:

This TSTF only affects Technical Specification 3.3.4.2, EOC-RPT. It is intended to eliminateambiguity in the EOC-RPT Technical Specification. The LCO currently allows for the option ofhaving the EOC-RPT pump trip instrumentation OPERABLE or applying appropriate thermallimits. The proposed change revises Condition A to be applicable whenever one or more'required' channels of EOC-RPT pump trip instrumentation is not OPERABLE. This clarifies thatif the LCO option of making the Average Planar Linear Heat Generation Rate or MinimumCritical Power Ratio limits applicable, then the EOC-RPT instrumentation would not be requiredand the Condition A would not need to be entered. This change is considered as administrativeclarifications only.



Exelon has evaluated whether or not a significant hazards consideration is involved with theproposed amendment(s) by focusing on the three standards set forth in 10 CFR 50.92,"Issuance of Amendment," as discussed below:


Response: No.

There are no changes to the plant configuration assumed for any accident. The removalfrom service of equipment that results in its safety function being met can not adverselyaffect the consequences of accidents previously evaluated. Other changes areadministrative clarifications that have no affect on accidents. Therefore, the proposedchange does not involve a significant increase in the probability or consequences of anaccident previously evaluated.



Response: No.



Response: No.

The actions involved with this activity ensure that safety functions are met. There are nochanges in the overall requirements of having trip instrumentation available for eventmitigation. There are no affects on the plant safety analyses. Therefore, the proposedchange does not involve a significant reduction in a margin of safety.

Conclusion:


2.5 TSTF-295, Rev. 0- Post Accident Monitoring Clarifications

Proposed Changes:

TSTF-295 modifies Improved Technical Specifications (NUREG-1433) to clarify that a separateCondition entry is allowed for each penetration flow path for the Post Accident Monitoring (PAM)instrumentation Primary Containment Isolation Valve (PCIV) indication function.

It is proposed to revise Technical Specification Table 3.3.3.1-1, Post Accident MonitoringInstrumentation, to clarify that function 8, PCIV Position, should actually be applied to eachpenetration flow path. Currently, the Technical Specifications simply state 'PCIV position'. It isproposed to change the function title to 'Penetration Flow Path PCIV Position'. The TechnicalSpecification requirement for this function is that there will be 2 channels per penetration flowpath as stated in Table 3.3.3.1-1. Clarifying the function title will make the specification clearer.

The associated Technical Specification 3.3.3.1 Bases will also be revised to reflect thisclarification. Clarifying words will be added that each penetration flow path is considered as aseparate function and therefore, a separate Condition entry is allowed for each inoperablepenetration flow path instrument.




Unit 2 Unit 3

3.3-26 X XB 3.3-69 X _ _

B 3.3-70 1 1 X

Technical Analysis:

This proposed change does not actually make any technical changes. The revision to the PCIVposition function title provides greater clarity and therefore provides overall improvement to thespecifications. This change will also ensure consistency between the PCIV position indicationfunction of the PAM specification and the allowance in the containment penetrationSpecification for PCIVs. Similar to the specification for PCIVs, each penetration flow pathshould be evaluated separately for Operability of the PAM function. The PAM specificationrequires a minimum of one channel of PCIV position indication in the control room to beOPERABLE for each active PCIV in a containment penetration flow path. Current actionsprovide appropriate compensatory actions for each inoperable indication channel. The changereduces the potential for a shutdown of the unit due to misinterpretation of the requirements.

The TSTF-295 change for adding clarity to the suppression pool water temperature function byadding the term 'relief valve discharge location' to the function description is not applicable toPBAPS. In the TSTF, this is 'bracketed' information and therefore, is not required to beimplemented at all plants due to plant specific design differences in this monitoring equipment.As licensed in the PBAPS Technical Specifications, the requirement for suppression chamberwater temperature is that 10 resistance temperature detectors (RTDs) be OPERABLE with notwo adjacent RTDs inoperable. This applies to each required channel. Therefore, the bracketedTSTF-295 information for the suppression chamber water temperature function is not required.

Otherwise, there are no deviations in the proposed PBAPS Technical Specifications from thepre-approved TSTF.




Response: No.

The equipment involved with the revised Technical Specifications are for post accidentmonitoring. This equipment has no possibility of increasing the probability of occurrenceof the accident since it is monitoring equipment only. The consequences of an accidentare not affected since this change maintains the original intent of the TechnicalSpecifications in having available monitoring information for each PCIV penetrationpath. Therefore, the proposed change does not involve a significant increase in theprobability or consequences of an accident previously evaluated.



Response: No.



Response: No.

The Technical Specifications continue to require appropriate post accident monitoringequipment to be OPERABLE. Adequate instrumentation for post accident monitoring willbe ensured by the Technical Specification requirements. There are no changes to theplant safety analyses involved with this change. Therefore, the proposed change doesnot involve a significant reduction in a margin of safety.

Conclusion:


2.6 TSTF-275, Rev. 0 - ECCS Instrumentation Clarifications

Proposed Changes:

TSTF-275, Rev. 0 modifies Improved Technical Specifications (NUREG-1433) to clarify whichEmergency Core Cooling System (ECCS) instrumentation is required to be OPERABLE tosupport Emergency Diesel Generator (EDG) operability. Footnote (a) to Table 3.3.5.1-1 hasbeen changed to only require the affected functions to be OPERABLE in Modes 4 and 5 whenthe associated ECCS is required to be OPERABLE per LCO 3.5.2.

It is proposed to revise Technical Specification Table 3.3.5.1-1, Emergency Core CoolingSystem Instrumentation, to clarify operability requirements of ECCS instrumentation while theshutdown plant is in Modes 4 and 5. Specifically, footnote 'a' to the table is proposed to berevised to require operability 'when associated ECCS subsystem(s) are required to beOPERABLE per LCO 3.5.2, ECCS - Shutdown.'

The associated Technical Specifications 3.3.5.1 and 3.8.2 Bases will be revised to provideadditional information concerning footnote 'a' to Table 3.3.5.1-1 to clarify that the ECCSinstrumentation is only required to be OPERABLE in Modes 4 and 5 when their supportedECCS equipment are required to be OPERABLE per LCO 3.5.2, ECCS Shutdown.

See the attached marked up pages for PBAPS Units 2 and 3 included in Attachment A for thedetails concerning the specific changes.



Unit 2 Unit 33.3-39 X X3.3-40 X XB 3.3-99 XB 3.3-100 . X XB 3.3-101 X XB 3.3-102 X XB 3.3-103 X XB 3.3-104 X XB 3.3-105 XB 3.3-106 XB 3.3-107 XB 3.8-42 X X

Technical Analysis:

The proposed change provides consistency between the LCO 3.5.2 and LCO 3.8.2requirements for operability of ECCS instrumentation. Consistent with the operabilityrequirements in LCO 3.5.2, ECCS-Shutdown, ECCS is not required to be OPERABLE duringrefuel Conditions when the reactor vessel is flooded up and there are no activities in progresswith the potential for draining the reactor vessel. If the ECCS is not required, then theinstrument whose function is to initiate ECCS should not be required. However, the currentfootnote 'a' in Technical Specification Table 3.3.5.1-1 implies that the ECCS instrumentation isrequired to be OPERABLE not only when the associated ECCS is required to be OPERABLEbut, also when the associated ECCS support systems are required to be OPERABLE (e.g.,Emergency Diesel Generators (EDGs)). This is incorrect since these support systems alsosupport other functions that are required at times when the ECCS system and associatedinitiation instrumentation is not needed (e.g., the EDGs are required during fuel handling).PBAPS Technical Specification 3.8.2, AC Sources - Shutdown already contains appropriatenotes that certain surveillances for EDGs that are related to ECCS are not required to be met ifthe ECCS is not required at the time. It is concluded that the proposed changes to TechnicalSpecification Table 3.3.5.1-1 are acceptable to clarify that the purpose of the ECCSinstrumentation table footnote 'a' is to support ECCS systems required during shutdown inModes 4 and 5 and are not appropriate to support EDG operability requirements when ECCS isnot required.

There are no deviations in the proposed PBAPS Technical Specifications from the pre-approved TSTF. The Bases are also marked up with the appropriate wording indicated in theTSTF.


Exelon has evaluated whether or not a significant hazards consideration is involved with theproposed amendment(s) by focusing on the three standards set forth in 10CFR50.92, "Issuanceof Amendment," as discussed below:



Response: No.

The equipment involved is for mitigative purposes and will not affect the probability ofoccurrence of an accident. Technical Specifications ensures that adequate mitigativeequipment continues to be OPERABLE for any event that may occur in Modes 4 and 5.This change is considered an upgrade to the specifications that will provide moreconsistency within the Technical Specifications. There are no changes to requirementsthat ensure appropriate Emergency Core Cooling Systems are OPERABLE. Therefore,the proposed change does not involve a significant increase in the probability orconsequences of an accident previously evaluated.


Response: No.

No new accident scenarios, failure mechanisms, or limiting single failures are introducedas a result of the proposed changes. All systems, structures, and componentspreviously required for the mitigation of a transient remain capable of fulfilling theirintended design functions. The proposed changes have no adverse effects on anysafety-related system or component and do not challenge the performance or integrityof any safety related system.



Response: No.

There is no impact on mitigative equipment that is required to respond to events while inModes 4 and 5. There is no impact on the plant safety analyses. This change isconsidered as an upgrade to Technical Specifications that will improve consistencywithin the Technical Specifications. Therefore, the proposed change does not involve asignificant reduction in a margin of safety.

Conclusion:


2.7 TSTF-306, Rev. 2- Traversing In-core Probe Instrumentation SpecificationsRequirements

Proposed Changes:

TSTF-306, Rev. 0 modifies Improved Technical Specifications (NUREG-1433) by adding a notethat penetration flow path may be unisolated intermittently under administrative control to


conform to what is already allowed for similar specifications for Primary Containment IsolationValves (PCIVs). Also, the Traversing In-core Probe (TIP) system isolation is set apart as aseparate function including the allowance of isolating the penetration instead of requiring aplant shutdown.

It is proposed to revise Technical Specification 3.3.6.1 to allow for intermittently un-isolatingprimary containment penetration flow paths under administrative controls. It is proposed thatthis be accomplished by adding a note to the existing Note box for the Technical SpecificationActions.

Additionally, it is proposed to revise Technical Specification 3.3.6.1 and the associated Table3.3.6.1-1 to separate the Traversing Incore Probe isolation function into a separate functionnumbered 8. Currently, it is included within the larger 'Primary Containment Isolation' functionnumbered 2. It is proposed to add a new Condition J that would require isolation of thepenetration within 24 hours if an inoperable channel could not be tripped instead of the previousrequirement of Condition G to be in Mode 3 in 12 hours and Mode 4 in 36 hours. The Table3.3.6.1-1 would reference the new condition J and add Function 8, Traversing Incore Probe(TIP) Isolation. The sub-functions associated with Function 8 are Reactor Vessel Water level -Low (Level 3) and Drywell Pressure - High. These sub-functions are the same as what iscurrently required in Function 2.a and 2.b.

The associated Technical Specification 3.3.6.1 Bases will be revised to add a description of theTIP system isolation functions to the Background and Applicable Safety Analyses, LCO andApplicability sections of the Bases. The additional note added to the Technical Specification3.3.6.1 Actions note box will also be discussed in the Bases.


List of Affected Pages Unit Applicability

Unit 2 Unit 33.3-48 X X3.3-49 X X3.3-50 X X3.3-54 X XB 3.3-144 XB 3.3-145 XB 3.3-159 XB 3.3-160 X XB 3.3-161 X

Technical Analysis:

The addition of the note that the penetration flow path may be un-isolated under administrativecontrol is appropriate since the instrumentation is a support system for PCIVs that already havethis allowance in Technical Specification 3.6.1.3, PCIVs. Therefore, the addition of the note toTechnical Specification 3.3.6.1 provides a consistency with Technical Specification 3.6.1.3. Thisaddition is viewed as a correction of an inconsistency within the Technical Specifications.


Additionally, the Actions for inoperable primary containment isolation instrumentation thatrequire a unit shutdown is overly restrictive in the event the inoperability would only affect theTraversing In-core Probe (TIP) system isolation instrumentation. Therefore, the separateisolation instrumentation Function is appropriate for this isolation. The Action selected forinoperability of this Function is the same as for inoperable manual isolation Functions for thePrimary Containment Isolation System discussed in NUREG-1433 (i.e., isolate the penetrationin 24 hours). The TIP system penetration is small bore piping and is isolated using isolation ballvalves. The redundant TIP system isolation valves are manually initiated shear valves. Theability to manually isolate the TIP system by either the normal isolation valve or the shear valvewould be unaffected by the inoperable instrumentation. Therefore, the same action as formanual isolation Functions for the primary containment isolation system found in NUREG-1433provides an appropriate level of safety.

There are no significant deviations in the proposed PBAPS Technical Specifications from thepre-approved TSTF. The numbering of the TIP isolation Function and the lettering of the newCondition are different than what is in the TSTF-306, Rev. 2 documentation. However, thesedifferences are administrative and nave no technical substance.




Response: No.

The addition of a note that the penetration flow path may be un-isolated underadministrative control simply provides consistency with what is already allowedelsewhere in Technical Specifications. The isolation function of the TIP valves aremitigative equipment. They do not create any increased possibility of an accident sincethey are mitigative. Also, the operation of the manual shear valves is unaffected by thisactivity. The ability to manually isolate the TIP system by either the normal isolationvalve or the shear valve would be unaffected by the inoperable instrumentation.Therefore, the same action as for manual isolation Functions provides an appropriatelevel of safety. Therefore, the proposed change does not involve a significant increasein the probability or consequences of an accident previously evaluated.


Response: No.





Response: No.

The addition of a note that the penetration flow path may be un-isolated underadministrative control simply provides consistency with what is already allowedelsewhere in Technical Specifications. The ability to manually isolate the TIP system byeither the normal isolation valve or the shear valve would be unaffected by theinoperable instrumentation. Therefore, the same action as for manual isolationFunctions provides an appropriate level of safety. Therefore, the proposed change doesnot involve a significant reduction in a margin of safety.

Conclusion:


2.8 TSTF-416, Rev. 0 - Clarification of LPCI Operability during Decay Heat RemovalOperations

Proposed Changes:

TSTF-416, Rev. 0 modifies Improved Technical Specifications (NUREG-1433) by moving thenote that modifies Low Pressure Coolant Injection (LPCI) surveillances to the LCO in LCO 3.5.1and LCO 3.5.2. These notes provide clarity that the LPCI may be considered OPERABLEduring alignment and operation in the decay heat removal Mode.

It is proposed to revise Technical Specification section 3.5.1, ECCS - Operating, to move anote from SR 3.5.1.2 to just before the Applicability statement. This note allows for LPCIsubsystems to be considered OPERABLE during alignment and operation for decay heatremoval with reactor steam dome pressure less than the Residual Heat Removal (RHR)shutdown cooling isolation pressure in Mode 3, if capable of being manually realigned and nototherwise inoperable.

Additionally, it is proposed to revise Technical Specification section 3.5.2, ECCS - Shutdown tomove a note from SR 3.5.2.4 to just before the Applicability statement. This note allows thatone LPCI subsystem may be considered OPERABLE during alignment and operation for decayheat removal if capable of being manually realigned and not otherwise inoperable.

The associated Technical Specification 3.5.1 and 3.5.2 Bases will be revised to reflect therelocation of the note.



Unit ApplicabilityList of Affected Pages Unit 2p[cUnit3

Unit 2 1 Unit 33.5-1 X X3.5-4 X XB 3.5-5 X XB 3.5-6 X XB 3.5-1 1 X X3.5-8 X X3.5-10 X XB 3.5-19 X XB 3.5-22 X I XB 3.5-23 X X

Technical Analysis:

SR 3.5.1.2 and SR 3.5.2.4, the verification of proper valve alignment SurveillanceRequirements, have a Note that allows both LPCI subsystems (SR 3.5.1.2 Note) or one LPCIsubsystem (SR 3.5.2.4 Note) to be considered OPERABLE during alignment and operation fordecay heat removal, if capable of being manually realigned and not otherwise inoperable. TheNote to SR 3.5.1.2 also has a restriction that the Note is only applicable with reactor steamdome pressure less than the residual heat removal cut-in permissive pressure in Mode 3.These Notes were added to allow the LPCI subsystems to be considered OPERABLE when theRHR System is being used for shutdown cooling. Also, the Bases for LCO 3.5.1 and LCO 3.5.2state that an LPCI subsystem is considered OPERABLE during alignment or during operationfor decay heat removal.

However, similar Notes as to what currently exists are not placed above other SurveillanceRequirements that are not met when an RHR subsystem is aligned in the shutdown coolingMode; specifically SR 3.5.1.5 and SR 3.5.2.6, the automatic actuation tests, and SR 3.3.5.1.7,the ECCS Response Time test. Without this change, it could be interpreted that, even thoughthe Notes to SR 3.5.1.2 and SR 3.5.2.4 allow LPCI subsystems to be considered OPERABLEduring alignment, the other Surveillance Requirements do not have similar Notes. Therefore,the affected LPCI subsystems would have to be declared inoperable due to failure to meet theother Surveillance Requirements.

Therefore, it is proposed to move the Notes to a more appropriate location that would apply tothe entire specification and not just during performance of certain surveillances. This change isviewed as a significant improvement to the clarity of the Technical Specifications for ECCS.






Response: No.

The proposed change makes the Technical Specifications and their Bases consistent intheir consideration of an LPCI subsystem aligned for decay heat removal beingconsidered OPERABLE for ECCS. The LCO 3.5.1 and LCO 3.5.2 Bases state that aLPCI subsystem may be considered OPERABLE during alignment and operation fordecay heat removal. As a result, no initiators to accidents previously evaluated areaffected and no mitigating equipment assumed in the accidents previously evaluated areaffected since the allowance for LPCI being considered operable during these type ofshutdown cooling alignments or operations was the intent of the current technicalSpecifications. Consequently, the probability or consequences of an accident previousevaluated is not significantly increased.


Response: No.




Response: No.

The proposed change makes the Technical Specifications and their Bases consistent intheir consideration of an LPCI subsystem aligned for decay heat removal beingconsidered OPERABLE for ECCS. The LCO 3.5.1 and LCO 3.5.2 Bases state that anLPCI subsystem may be considered OPERABLE during alignment and operation fordecay heat removal. As the operability requirements of the LPCI subsystem areunaffected, the margin of safety is unaffected. Therefore, the proposed change does notinvolve a significant reduction in a margin of safety.

Conclusion:



2.9 TSTF-17, Rev. 2 - Containment Airlock Testing Frequency

Proposed Changes:

TSTF-17, Rev. 0 modifies Improved Technical Specifications (NUREG-1433) to extend thetesting frequency of containment interlock mechanism from 184 days to 24 months. Also, thecorresponding note for this surveillance is no longer required due to the longer surveillancefrequency.

It is proposed to revise Technical Specification section 3.6.1.2, Primary Containment Airlock, tochange the frequency of performing SR 3.6.1.2.2 from 184 days to 24 months. This SR verifiesthat only one door in the primary containment air lock can be opened at a time. It is proposed toremove the associated note for SR 3.6.1.2.2 to only require the test to be performed upon entryinto primary containment when the primary containment is de-inerted since it will no longer beneeded if the frequency is 24 months instead of 184 days.

The associated Technical Specification 3.6.1.2 Bases will be revised in accordance with theTSTF. The addition to the Bases provides the basis to why the surveillance only needs to beperformed every 24 months instead of 184 days.



Unit 2 Unit 3__~3.

3.6-7 X XB 3.6-12 X X

Technical Analysis:

Typically, the interlock is installed after each refueling outage, verified OPERABLE with SR3.6.1.2.2, and not disturbed until the next refueling outage. If the need for maintenance ariseswhen the interlock is required, the performance of interlock surveillance would be requiredfollowing the maintenance. In addition, when an airlock is opened during times the interlock isrequired, the operator first ensures that one door is completely shut before attempting to openthe other door. Therefore the interlock is not challenged except during actual testing of theinterlock. Consequently, it is sufficient to ensure proper operation of the interlock by testing theinterlock on a 24 month frequency.

Testing of the airlock interlock mechanism is accomplished through having one door notcompletely engaged in the closed position, while attempting to open the second door. Failure ofthis surveillance effectively results in a loss of the containment integrity. Procedures andtraining do not allow this interlock to be challenged for ingress and egress. One door is opened,personnel and equipment as necessary are placed into the airlock and then the door iscompletely closed prior to attempting to open the second door. This surveillance is contrary tothe processes and training, which are intended to ensure conservative operation when theairlock function is required. The door interlock mechanism cannot be readily bypassed.Linkages must be removed which are under the control of station processes such as temporarymodifications, containment closure procedures, and out of service practices. Failure rate of thisphysical device is very low based on the design of the interlock.


Historically, this interlock verification has had its frequency chosen to coincide with thefrequency of the overall airlock leakage test. According to 10 CFR 50, Appendix J, Option A,this frequency is once per 6 months. However, Appendix J, Option B, allows for an extension ofthe overall airlock leakage test frequency to a maximum of 30 months. The 24 month frequencyallows the surveillance to be performed in a plant Mode where the interlock is not required. TheAppendix J, Option B allowance was approved for PBAPS as part of a previous licensing action(refer to NRC letter to PECO dated 10/1/98 associated with Technical Specification Amendment223/227 for PBAPS Units 2 and 3). Therefore, the proposed change is appropriate andconsistent with previous licensing actions.

With this change to the frequency, the need for the SR Note is eliminated. Testing would bedone during a plant shutdown and would not be required until the following plant shutdown.


As precedence, the following Safety Evaluation Report was approved by the NRC for TSTF-1 7:

NRC Safety Evaluation Report for Turkey Point Units 3 and 4, 4/26/01, TechnicalSpecification Amendments 213, 207




Response: No.

The containment airlock is considered as mitigative equipment. Therefore, there are noimpacts on the probability of accidents. The proposed surveillance frequency assuresthat the interlock is working such that there is no unintentional opening of both airlockdoors when containment is required. Because the interlock is assured to be working,there will be no significant increase in the consequences of an accident. There is nodegradation in the ability of the interlock to assure the containment integrity function ismaintained. Therefore, the proposed change does not involve a significant increase inthe probability or consequences of an accident previously evaluated.


Response: No.


PSAPS Incorporation of Generic NRC-Approved Attachment 1Technical Specification Task Force Travelers (TSTFs) Page 26 of 42



Response: No.

The frequency of 24 months for the interlock testing has been demonstrated to beadequate with regards to the reliability of the airlock. There is no impact on the leaktesting requirements. There is no affect on the plant safety analyses. Therefore, theproposed change does not involve a significant reduction in a margin of safety.

Conclusion:


2.10 TSTF-30, Rev. 3, TSTF-323, Rev. 0, TSTF-45, Rev. 2, TSTF-46, Rev. 1, TSTF-269,Rev. 2- Containment Isolation Valve Specifications Changes

Proposed Changes:

TSTF-30, Rev. 3, TSTF-323, Rev. 0, TSTF-45, Rev. 2, TSTF-46, Rev. 1, and TSTF-269, Rev. 2modify Improved Technical Specifications (NUREG-1433, Rev. 2) sections 3.6.1.3 concerningPrimary Containment Isolation Valves (PCIVs) and 3.6.4.2 concerning Secondary ContainmentIsolation Valves (SCIVs).

TSTF-30, Rev. 3 & TSTF-323, Rev. 0:

These TSTFs revise Technical Specification 3.6.1.3 to allow for a 72 hour completion time for aclosed system flow path with an inoperable isolation valve and allows for a 72 hour completiontime for a penetration flow path with an inoperable Excess Flow Check Valve (EFCV).

TSTF-45, Rev. 2:

This TSTF revises Technical Specification 3.6.1.3 and 3.6.4.2 to revise surveillancerequirements for valve line-ups. Specifically, if a containment isolation valve is locked, sealed,or otherwise secured, they are not required to be verified to be closed during the performanceof the surveillance test.

TSTF-46, Rev. 1:

This TSTF revises containment isolation valve surveillances to delete the reference to verifyingthe isolation time of 'each power operated' containment isolation valve and only requireverification of each 'automatic isolation valve'.

TSTF-269, Rev. 2:

This TSTF allows for verification of valve status by administrative means for repetitiveverification of locked, sealed or secured valves.


It is proposed to revise Technical Specification section 3.6.1.3, Primary Containment IsolationValves (PCIVs) and 3.6.4.2, Secondary Containment Isolation Valves (SCIVs) to allow for theverification of the isolated status of a penetration flow path by administrative means for isolationdevices that are locked sealed or otherwise secured when a PCIV or SCIV is inoperable. It isproposed to implement the change by adding a second Note to the Note box associated withTechnical Specification 3.6.1.3 Required Actions A.2 and C.2 and Technical Specification3.6.4.2 Required Action A.2 that allows for verification of locked, sealed or otherwise securedpenetration flow paths by administrative means. The associated Technical Specification Basesfor these changes will also be revised to describe the changes made in the TechnicalSpecifications.

In addition, it is proposed to revise Technical Specification sections 3.6.1.3, PrimaryContainment Isolation Valves (PCIVs) to allow for a Completion Time of 72 hours to isolate apenetration with an inoperable PCIV if the penetration is associated with Excess Flow CheckValves (EFCVs) or is a penetration with a closed system. It is proposed to revise theCompletion Time associated with Required Action C.1 to implement this change. Specifically,the Completion Time for EFCVs is proposed to be revised from 12 to 72 hours and theCompletion Time for inoperable PCIVs in a closed penetration is proposed to be revised from 4hours to 72 hours.

In addition, it is proposed to revise Technical Specification Surveillance Requirements (SRs)3.6.1.3.4, 3.6.1.3.5, and 3.6.4.2.1 to eliminate the requirement to periodically verify that PCIVand SCIV manual valves and blind flanges that are locked, sealed or otherwise.secured valvesare closed. The associated technical Specification Bases for these changes will also be revisedto reflect these changes.

Finally, it is proposed to revise Technical Specification Surveillance Requirement (SR) 3.6.1.3.8to clarify that the PCIV isolation time surveillance only applies to 'automatic power operated'valves. The current wording states that the surveillance applies to power operated andautomatic PCIVs. The current wording could result in an interpretation that power operatedvalves that do not receive an automatic closure signal for design events are required to have aclosure time associated with them. The revised wording will clarify that it is only PCIVs thatreceive an automatic isolation signal that are in the scope of the SR. The associated TechnicalSpecification Bases will also be revised to reflect these changes.



Unit 2 Unit 33.6-9 X X3.6-10 X X3.6-11 X X3.6-13 X X3.6-14 X X3.6-15 X XB 3.6-20 X XB 3.6-21 X XB 3.6-22 X X



Unit 2 Unit 3B 3.6-25 X XB 3.6-26 X XB 3.6-27 X XB 3.6-30 X X3.6-37 X X3.6-39 X XB 3.6-79 X XB 3.6-81 X XB 3.6-82 X XB 3.6-83 X X

There are no deviations in the proposed PBAPS Technical Specifications from the pre-approved TSTFs below.

Technical Analysis:

TSTF-30, Rev. 3 & TSTF-323, Rev. 0:

General Design Criteria (GDC) 57 allows the use of a closed system in combination with acontainment isolation valve to provide two containment barriers against the release ofradioactive material following an accident. Currently, LCO 3.6.1.3 does not allow the use of aclosed system to isolate a failed containment isolation valve even though a closed system issubjected to a Type A containment leakage test, is missile protected and seismic category Ipiping. A closed system also typically has flow through it during normal operation such that anyloss of integrity could be continually observed through leakage detection systems withincontainment and system walkdowns for closed systems outside of containment. As such, use ofa closed system is no different from isolating a failed containment isolation valve by use of asingle valve as specified in Required Action A.1. Therefore, LCO 3.6.1.3, Required Action C.1 isproposed to be revised to allow 72 hours to isolate a failed containment isolation valveassociated with a closed system. This 72 hour period provides the necessary time to performrepairs on a failed containment isolation valve when relying on an intact closed system. ACompletion Time of 72 hours is considered appropriate given that certain valves may belocated inside containment, the reliability of the closed system, and that 72 hours is typicallyprovided for losing one train of redundancy throughout the Technical Specifications. If theclosed system and associated containment isolation valve were both inoperable, the plantwould be in LCO 3.0.3 since there is no specific Condition specified.

Similarly, the allowance for EFCV penetrations to allow 72 hours for a failed EFCV isappropriate. This is based on the fact that EFCVs are used on instrumentation piping that isvery small in size and is dead-ended at the instrumentation. In addition, restricting orifices areinstalled on these lines inside of containment which significantly limits leakage flow outside ofprimary containment if an instrument line break were to occur and the EFCV could not isolatethe flow. This postulated leakage has previously been analyzed in the Final Safety AnalysisReport resulting in assurance that regulatory dose limits will be complied with. Therefore,extending the EFCV Completion Time to 72 hours is not significant.


TSTF-45, Rev. 2:

This change is consistent with other surveillance requirements in Technical Specifications (e.g.SR 3.5.2.2) that ensure that valves are in their correctly lined-up position. These othersurveillances exclude valves that are locked, sealed or otherwise secured. This is acceptablesince plant administrative processes for locked, sealed, or other wise secured valves areadequate to ensure that the valves are maintained in the correct positions.

TSTF-46, Rev. 1:

The current Technical Specification Bases for these surveillances state that isolation timetesting ensures that the valve will isolate in a time period less than or equal to that assumed inthe safety analysis. However, there are valves credited as containment isolation valves that arepower operated (i.e., can be remotely operated), but do not receive a containment isolationsignal. These power-operated valves do not have an isolation time as assumed in the accidentanalyses since they require operator action. Therefore, deleting reference to power operatedisolation valve time testing reduces the potential for misinterpreting the requirements of thesesurveillances while maintaining assumptions of the accident analyses.

TSTF-269, Rev. 2:

It is sufficient to assume that the initial establishment of component status (e.g. isolation valvesclosed) was performed correctly. Subsequent verification is intended to ensure that thecomponent has not been inadvertently repositioned. Given that the function of locking, sealing,or securing components is to ensure the same avoidance of inadvertent repositioning, theperiodic re-verification should only be a verification of the administrative control that ensuresthat the component remains in the required state. It would be inappropriate to remove the lock,seal, or other means of securing the component solely to perform an active verification of therequired state.

As precedence, the following Safety Evaluation Report was approved by the NRC for TSTF-323:

* NRC Safety Evaluation Report for Duane Arnold Energy Center, 10/3/00, TechnicalSpecification Amendment 234

The following Safety Evaluation Report was approved by the NRC for TSTF-45:

* NRC Safety Evaluation Report for Sequoyah Nuclear Plants, 10/24/01, TechnicalSpecification Amendments 271, 260




Response: No.


The equipment affected by these changes is for mitigative purposes. Therefore, therecannot be an increase in the probability of occurrence of an accident. The controlsrequired in the Technical Specifications are adequate to ensure that the containmentbarriers are ensured. Isolation valves will be assured to be in their correct positions.Also, inoperable isolation valves in closed systems and inoperable EFCVs have beenevaluated to not have any significant impact to the consequences of an accident due tothe closed system providing a barrier for the inoperable closed system isolation valveand bounding analyses have been performed for EFCV instrument line failures.Therefore, the proposed change does not involve a significant increase in the probabilityor consequences of an accident previously evaluated.


Response: No.




Response: No.

The equipment affected by these changes is for mitigative purposes. The controlsrequired in the Technical Specifications are adequate to ensure that the containmentbarriers are ensured. There is no affect on the plant safety analyses. Therefore, theproposed change does not involve a significant reduction in a margin of safety.

Conclusion:


2.11 TSTF-322, Rev. 2 - Secondary Containment Operability Clarification

Proposed Changes:

TSTF-322, Rev. 2 modifies Improved Technical Specifications (NUREG-1433) to clarify theintent of the secondary containment boundary integrity. Associated surveillances currently implythat secondary containment would be inoperable if a Standby Gas Treatment (SGT) subsystemwas inoperable.


It is proposed to revise Technical Specification Surveillance Requirements (SRs) 3.6.4.1.3 and3.6.4.1.4 to clarify the intent of the Secondary Containment draw down tests. Currently the SRsimply that each Standby Gas Treatment (SGT) subsystem must be able to draw downSecondary Containment to greater than or equal to 0.25 inches of vacuum water gauge in lessthan 120 seconds and that this vacuum can be maintained for at least 1 hour at a flow rate lessthan or equal to 10,500 cfm. Because the current SRs state that these performance objectivesmust be met for 'each' SGT subsystem, then if a SGT subsystem became inoperable, this couldcause the mis-interpretation that Secondary Containment must also be declared inoperableeven though the redundant SGT subsystem could fulfill the performance measures. Therefore,it is proposed to revise the SRs to state that the performance measures are to be met usingone SGT subsystem. Also, the SR Frequency for SR 3.6.4.1.3 and 3.6.4.1.4 are proposed to berevised to state that the frequency is on a staggered test basis for each subsystem. Theassociated Technical Specification Bases will also be revised to clarify the intent of theSurveillances and Frequencies.



Unit 2 Unit 33.6-35 X XB 3.6-76 X XB 3.6-77 X X

Technical Analysis:

The secondary containment integrity surveillance requirements ensure that secondarycontainment is OPERABLE and that the leak tightness of the boundary is within theassumptions of the accident analysis. However, they are currently written in such a mannerthat they imply that if a SGT subsystem is inoperable, the surveillance requirements becomefailed. This is not the intent of the Technical Specifications. Therefore, to ensure thismisinterpretation does not occur, the SRs have been rephrased to more clearly convey theoriginal intent of the SRs, to verify secondary containment is OPERABLE. With the revisedwording, if a SGT is inoperable, the SRs can still be met and only the SGT system isinoperable. The SRs will still ensure each SGT subsystem is used (on a staggered test basis) toperform the SRs as described in the Bases. Therefore, this proposed change is viewed as anadministrative change to clarify the intent of the Technical Specification 3.6.4.1 surveillances.





Response: No.


This change involves an administrative clarification to reflect the original intent of theTechnical Specifications. There is no impact on the availability of the secondarycontainment. Additionally, secondary containment is mitigative equipment. Therefore,the proposed change does not involve a significant increase in the probability orconsequences of an accident previously evaluated.


Response: No.




Response: No.

This change involves an administrative clarification to reflect the original intent of theTechnical Specifications. There is no impact on the availability of the secondarycontainment. There is no impact on the plant safety analyses. Therefore, the proposedchange does not involve a significant reduction in a margin of safety.

Conclusion:


2.12 TSTF-276, Rev. 2 - Power Factor for Emergency Diesel Generator (EDG)Surveillances

Proposed Changes:

TSTF-276, Rev. 2:

This TSTF modifies Improved Technical Specifications (NUREG-1433) to allow for certain EDGtesting to be performed even if the specified power factor cannot be achieved.

It is proposed to revise Technical Specification section 3.8.1 to allow for an exception for notmeeting power factor requirements when an Emergency Diesel Generator is being paralleled tothe grid during surveillances. Due to grid conditions, it may not always be possible to meet agreater than or equal to 0.89 power factor. Therefore, it is proposed to modify SurveillanceRequirement (SR) 3.8.1.9, 3.8.1.10, and 3.8.1.14 notes to allow for the surveillances to proceed


if the 0.89 power factor requirement cannot be met. In these cases, the note requires that thepower factor be maintained as close to the limit as possible. The associated TechnicalSpecification Bases for these SRs will be revised to discuss this change as well.



Unit 2 Unit 33.8-10 X X3.8-14 X XB 3.8-26 X XB 3.8-27 X XB 3.8-31 X XB 3.8-32 X X

Technical Analysis:

TSTF-276, Rev. 2:

While the EDG is not paralleled to the grid, the power factor is determined by plant load andcannot be adjusted. Therefore, power factor requirements are applicable only when the test isperformed with the EDG paralleled to the grid. This change provides the allowance to proceedwith the surveillance even if the specified power factor is not achieved. This change adds detailand is intended to improve clarity and ensure requirements are fully understood andconsistently applied. This change does not result in a significant impact on proving EDGoperability.





Response: No.

These changes only affect mitigative equipment and therefore, would not have animpact on the probability of an accident. Also, the performance of the surveillancesensures that mitigative equipment is capable of performing its intended function.Therefore, the proposed change does not involve a significant increase in the probabilityor consequences of an accident previously evaluated.



Response: No.




Response: No.

The performance of the surveillances ensures that mitigative equipment is capable ofperforming its intended function. There are no degradations in equipment readiness tomitigate design events. There is no adverse affect on the plant safety analysis.Therefore, the proposed change does not involve a significant increase in the probabilityor consequences of an accident previously evaluated.

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

Conclusion:


2.13 TSTF-404, Rev. 0 - Scram Discharge Volume Vent and Drain Valves

Proposed Changes:

The proposed changes would revise the required action within TS (3.1.8, "Scram DischargeVolume (SDV) Vent and Drain Valves") for the condition of having one or more SDV vent ordrain lines with one valve inoperable.

The proposed changes would revise the required action within TS (3.1.8, "Scram DischargeVolume (SDV) Vent and Drain Valves') for the condition of having one or more SDV vent ordrain lines with one valve inoperable. These changes are based on Technical SpecificationsTask Force (TSTF) change traveler TSTF-404 (Revision 0) that has been approved genericallyfor the BWR/4 Standard Technical Specifications (STS), NUREG-1433, Revision 2. Theavailability of this technical specification improvement was announced in the Federal Registeron April 15, 2003 as part of the consolidated line item improvement process (CLIIP).



Unit 2 Unit 33.1-26 X XB 3.1-49 X XB 3.1-50 X X

Technical Analysis:

EGC has reviewed the safety evaluation published on April 15, 2003 (68 FR 18294) as part ofthe CLIIP. This verification included a review of the NRC staff's evaluation as well as thesupporting information provided to support TSTF-404. EGC has concluded that the justificationspresented in the TSTF proposal and the safety evaluation prepared by the NRC staff areapplicable to Peach Bottom Atomic Power Station, Units 2 and 3 and justify this amendment forthe incorporation of the changes to the Peach Bottom Atomic Power Station, Units 2 and 3Technical Specifications.

EGC is not proposing any variations or deviations from the technical specification changesdescribed in TSTF-404 or the NRC staff's model safety evaluation published on April 15, 2003.

There are no new regulatory commitments associated with this proposed change.

No Significant Hazards Determination

EGC has reviewed the proposed no significant hazards consideration determination publishedon April 15, 2003 as part of the CLIIP. EGC has concluded that the proposed determinationpresented in the notice is applicable to Peach Bottom Atomic Power Station, Units 2 and 3 andthe determination is hereby incorporated by reference to satisfy the requirements of 10 CFR50.91 (a).

Conclusion:

Based on the above, EGC concludes that the proposed amendment(s) present no significanthazards consideration as discussed in the NRC staff's model safety evaluation published onApril 15, 2003 under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of"no significant hazards consideration" is justified.

2.14 Technical Specification 5.0, Administrative Controls Proposed Revisions

TSTF-65, Rev. 1 - Generic Organizational TitlesTSTF-299, Rev. 0- Primary Coolant Sources Inspection RequirementsTSTF-279, Rev. 0 - In-service Testing Program ClarificationsTSTF-118, Rev. 0 & TSTF-1 06, Rev. 1 - Diesel Generator Fuel Oil Testing ProgramClarificationsTSTF-152, Rev. 0 - Routine Reporting Requirements Upgrade


Proposed Changes:

TSTF-65, Rev.1:

This TSTF modifies Improved Technical Specifications (NUREG-1 433) to allow the use ofgeneric organizational titles in lieu of plant specific titles. Therefore, for the PBAPS TechnicalSpecifications, a change is requested to replace plant specific titles with generic titles.

TSTF-299, Rev. 0:

This TSTF modifies Improved Technical Specifications (NUREG-1433) section 5.2.2, 'PrimaryCoolant Sources Outside Containment' to clarify the intent of refueling cycle intervals withrespect to the system leak test requirements and adds a sentence that the leak test is subjectto the provisions of SR 3.0.2.

TSTF-279, Rev. 0:

This TSTF modifies Improved Technical Specifications (NUREG-1 433) section 5.5.8, 'InserviceTesting Program' to delete the reference to 'applicable supports' as part of the description forthe Inservice Testing Program. The PBAPS applicable Technical Specification section is 5.5.6.

TSTF-1 18, Rev. 0:

This TSTF modifies Improved Technical Specifications (NUREG-1433) section 5.5.13, 'DieselFuel Oil Testing Program', to allow for the provisions of SR 3.0.2 (25% extension) and SR 3.0.3(missed surveillance actions) to apply to surveillances. The PBAPS applicable TechnicalSpecification section is 5.5.9.

TSTF-106, Rev. 1:

This TSTF modifies Improved Technical Specifications (NUREG-1433) to clarify that section5.5.10.b, concerning verification of the diesel fuel oil that was sampled meets the requiredASTM properties, only applies to new fuel. As written, it could be interpreted that this testing isrequired for existing fuel that is routinely sampled. The applicable PBAPS TechnicalSpecification section is 5.5.9.b.

TSTF-152, Rev. 0:

This TSTF modifies Improved Technical Specifications (NUREG-1433) to revise theOccupational Radiation Exposure Report and the Radioactive Effluent Release Reportrequirements to be consistent with other regulatory changes that have occurred.

It is proposed to revise Technical Specification section 5.0 to make various administrativeimprovements.

It is proposed to revise Technical Specification section 5.0 to make organizational titles genericinstead of titles being plant-specific organizational titles. Therefore, it is proposed to revisesection 5.2.1.a to add a requirement to ensure that specific titles are controlled in the UFSAR.Additionally, it is proposed to revise Technical Specification sections 5.1.1, 5.2.1.b, 5.2.2.d and5.5.1.c.2 to change the title Plant Manager to plant manager. Similarly, the title in TechnicalSpecification section 5.2.2.e 'Senior Manager - Operations or an Operations Manager' is beingchanged to be in lower case letters. Additionally, the title, Vice President - Peach Bottom


Atomic Power Station is being replaced with 'specified corporate officer' in TechnicalSpecification section 5.2.1.c. These changes allow for flexibility in that a Technical Specificationchange would not be required for simple changes in organizational titles.

It is proposed to revise Technical Specification section 5.5.2 to standardize the terminologyreferring to the performance of system leak test requirements for systems outside ofcontainment that could contain highly radioactive fluids during serious transients or accidents.Specifically, it is proposed to revise Technical Specification 5.5.2 to state that these system leaktests will be performed at least once per 24 months. Currently, the requirement is to perform thetest every refueling cycle or less. Refueling cycles at PBAPS are 24 months. Also, a statementthat the provisions of SR 3.0.2 (25% grace) are applicable is proposed.

It is proposed to revise Technical Specification section 5.5.6, Inservice Testing Program, toeliminate the reference to 'applicable supports' from the scope of this Technical Specification.

It is proposed to revise Technical Specification section 5.5.9, Diesel Fuel Oil Testing Program toclarify the requirements for performing oil testing. Specifically, Technical Specification section5.5.9.b is proposed to be revised to clarify that the properties of new fuel oil be within ASTM 2Dlimits. The previous wording was confusing in that it could be interpreted that existingpreviously-sampled fuel oil would require the ASTM 2D testing in addition to any new fueladded. Also, a statement that the provisions of SR 3.0.2 (25% grace) and SR 3.0.3 (missedsurveillance actions) are applicable is proposed.

It is proposed to revise Technical Specification section 5.6.1, Occupational Radiation ExposureReport, to be consistent with other regulatory changes that have been made. This reportsupplements the requirements of 10 CFR 20.2206 and ensures appropriate occupationalradioactive exposure information is submitted to the NRC by April 30th of each year for datacovering the previous calendar year. Additionally, it is proposed to revise TechnicalSpecification section 5.6.3, Radioactive Effluent Release Report to make minor enhancements.The Note is revised to ensure that if a common report is submitted for both units at a multipleunit station (applicable to PBAPS), then the submittal shall combine sections common to allunits at the station. This Note previously stated that combining sections 'should' be done. Thechange makes the 'should' a 'shall' statement. Additionally, a reference to '1 OCFR 50' ischanged to '10 CFR Part 50'.



Unit 2 Unit 35.0-1 (TSTF-65, Rev.1) X X5.0-2 (TSTF-65, Rev.1) X X5.0-4 (TSTF-65, Rev.1) X X5.0-7 (TSTF-65, Rev.1) X X5.0-8 (TSTF-299, Rev. 0) X X5.0-11 (TSTF-279, Rev. 0) X X5.0-15 (TSTF-118, Rev. 0 & X X

TSTF-106, Rev. 1)5.0-19 (TSTF-1 52, Rev. 0) X X5.0-20 (TSTF-152, Rev. 0) X X


Technical Analysis:

TSTF-65, Rev. 1:

The change from plant specific to generic organization titles in the PBAPS TechnicalSpecifications is acceptable since the plant specific titles are and will continue to be controlledin the UFSAR. This change does not eliminate any qualifications, responsibilities orrequirements for these positions.

Because there have been other TSTFs already approved and incorporated into the PBAPSTechnical Specifications (e.g., TSTF-258, Rev. 4), some of the generic titles identified in TSTF-65, Rev. 1 have already been incorporated into the PBAPS Technical Specifications. Also,TSTF-5, Rev. 1 is requested within this submittal to remove the safety limit reportingrequirements. This TSTF would also supersede portions of what is identified in TSTF-65, Rev.1. The only remaining titles in the PBAPS Technical Specifications that have not beenconverted are the 'Plant Manager', 'Vice President - Peach Bottom Atomic Power Station' andthe 'Senior Manager - Operations or an Operations Manager'. The current title 'Plant Manager'is simply being changed in accordance with the TSTF to 'plant manager'. The current title 'VicePresident - Peach Bottom Atomic Power Station' will be changed in accordance with the TSTFto the 'specified corporate officer'. The current title 'Senior Manager - Operations or anOperations Manager' discussed in Technical Specification 5.2.2 will simply be changed to'senior operations manager or an operations manager'. This meets the intent of the TSTF-65,Rev. 1 document while continuing to reflect site specific commitments. Therefore, there are nosignificant deviations in the proposed PBAPS Technical Specifications from the pre-approvedTSTF.

TSTF-299, Rev. 0:

PBAPS Technical Specification section 5.2.2 requires system leak tests for each system atrefueling cycle intervals or less. This Technical Specification is revised to require these tests atleast once per 24 months. This is equivalent to performing the tests at refuel cycle intervals.Since normal refueling cycle intervals are 24 months, presenting this requirement in thismanner achieves consistency with similar requirements in the Technical Specifications. Thischange is conservative in that it sets an end limit of 24 months for the test frequency asopposed to refueling outage intervals (which could go beyond 24 months due to mid-cycleshutdowns, etc). Additionally, to be consistent with normal surveillance requirements that allowfor a 25% extension of the frequency (SR 3.0.2), the SR 3.0.2 allowance is applied to TechnicalSpecification 5.2.2. This is acceptable since Technical Specification 5.2.2 testing is consideredas a surveillance. Since SR 3.0.2 technically only would normally apply to TechnicalSpecification LCO sections, it is appropriate to add the SR 3.0.2 statement to TechnicalSpecification 5.2.2.


TSTF-279, Rev. 0:

The Inservice Testing Program (IST) provides controls for testing Code Class 1, 2 and 3components. The discussion of the IST program in standard technical specifications wasrevised by the NRC to include 'applicable supports' in February, 1992 due to concerns relatedto the relocation of the Snubber LCO from the Improved Technical Specifications. However, this


is not appropriate since supports are addressed in the Inservice Inspection (ISI) program, notthe IST program. Appropriate guidance and testing concerning snubbers and supports arecaptured and do not need to be identified with the IST program. There are no deviations in theproposed PBAPS Technical Specifications from the pre-approved TSTF.

TSTF-1 18, Rev. 0:

The addition of the SR 3.0.2 and SR 3.0.3 applicability statements to PBAPS TechnicalSpecification 5.5.9, Diesel Fuel Oil Testing Program provides consistency with other similarTechnical Specification testing requirements within section 5.5 (e.g., PBAPS TechnicalSpecifications 5.5.8, 'Explosive Gas Monitoring Program', 5.5.4, Radioactive Effluent ControlsProgram, 5.5.6 'Inservice Testing Program', 5.5.7 'Ventilation Filter Testing Program' and inpart, 5.5.12 'Primary Containment Leakage Rate Testing Program'). SR 3.0.2 and SR 3.0.3 areapplicable in these other Technical Specification programs (except SR 3.0.2 for the 'PrimaryContainment Leakage Rate Testing Program') and therefore the lack of an applicabilitystatement in the Diesel Fuel Oil Testing Program introduces confusion. Further, the applicabilityof SR 3.0.2 and SR 3.0.3 to the program surveillances is consistent with the current licensingbasis. There are no deviations in the proposed PBAPS Technical Specifications from the pre-approved TSTF.

TSTF-106, Rev. 1:

This change is acceptable since the new wording is provided to clarify what the TechnicalSpecifications originally intended. As currently worded, it could be interpreted that this testing isrequired for existing fuel that is routinely sampled. The requirements for 5.5.9.b were originallyintended to mean that other chemical properties of the new fuel added to a storage tank wouldneed this additional testing within 31 days after addition to the storage tank. TechnicalSpecification 5.5.9.c was originally intended to govern on-going testing of the fuel oil. Thischange is purely administrative in that it clarifies the intent of Technical Specifications. Thereare no deviations in the proposed PBAPS Technical Specifications from the pre-approvedTSTF.

TSTF-152, Rev. 0:

The revisions to the Occupational Radiation Exposure Report and the Radioactive EffluentRelease Report requirements are made to be consistent with other regulatory changes thathave occurred. These changes are considered administrative and do not significantly affect thereporting requirements. There are no deviations in the proposed PBAPS TechnicalSpecifications from the pre-approved TSTF.

Precedence for the above changes are discussed below:


* NRC Safety Evaluation Report for Diablo Canyon Nuclear Power Plant, 3/7/01,Technical Specification Amendments 146, 145


* NRC Safety Evaluation Report for Monticello Nuclear Generating Station, 7/24/01,Technical Specification Amendment 120


The following Safety Evaluation Reports were approved by the NRC for TSTF-279:



* NRC Safety Evaluation Report for Grand Gulf Nuclear Station, 6/30/00, TechnicalSpecification Amendment 142

The following Safety Evaluation Report was approved by the NRC for TSTF-1 18:

* NRC Safety Evaluation Report for Grand Gulf Nuclear Station, 6/30/00, TechnicalSpecification Amendment 142

The following Safety Evaluation Reports were approved by the NRC for TSTF-152:



* NRC Safety Evaluation Report for Brunswick Steam Electric Plant, 3/21/01 TechnicalSpecification Amendments 212, 239


EGC has evaluated whether or not a significant hazards consideration is involved with theproposed amendment(s) by focusing on the three standards set forth in 1 OCFR50.92, "Issuanceof Amendment," as discussed below:


Response: No.

The changes to Technical Specification 5.0, Administrative Controls, are consideredadministrative changes. There are no changes to plant structures, systems orcomponents involved with this change. There are no degradations in the availability ofmitigative plant equipment. The proposed changes provide enhancements to theadministrative controls in Technical Specifications, therefore, there is no affect on anyplant safety analyses; therefore, the proposed change does not involve a significantincrease in the probability or consequences of an accident previously evaluated.


Response: No.





Response: No.

The changes to Technical Specification 5.0, Administrative Controls, are consideredadministrative changes. There are no changes to plant structures, systems orcomponents involved with this change. There are no degradations in the availability ofmitigative plant equipment. The proposed changes provide enhancements to theadministrative controls in Technical Specifications; therefore, there is no affect on anyplant safety analyses. Therefore, the proposed change does not involve a significantreduction in a margin of safety.

Conclusion:


3.0 ENVIRONMENTAL CONSIDERATION

An Environmental Impact Assessment is not required for the changes proposed because thechanges conform to the criteria for "actions eligible for categorical exclusion," as specified in 10CFR51.22 (c)(9). The requested changes will have no impact on the environment. Theproposed changes do not involve a Significant Hazards Consideration as discussed in thepreceding section. The proposed changes do not involve a significant change in the type orsignificant increase in the amounts of any effluent that may be released offsite. The proposedchanges would not authorize any change in the authorized power level of the facility. Inaddition, the proposed changes do not involve a significant increase in individual or cumulativeoccupational radiation exposure.

For TSTF-404, Revision 0, EGC has reviewed the environmental evaluation included in themodel safety evaluation published on February 24, 2003 as part of the CLIIP. EGC hasconcluded that the NRC staff's findings presented in that evaluation are applicable to PeachBottom Atomic Power Station, Units 2 and 3 and the evaluation is hereby incorporated byreference for this application.


4.0 REFERENCES

4.1 NUREG-1433, Rev. 2, Standard Technical Specifications, General Electric Plants,BWR/4

4.2 NRC Safety Evaluation Report for Grand Gulf Nuclear Station, 6/30/00, TechnicalSpecification Amendment 142

4.3 Letter, TVA to NRC, 8/28/00, Mode Switch Restraints (TSTF-208)

4.4 NRC Safety Evaluation Report for Browns Ferry, 11/21/00, Technical SpecificationAmendments 239, 266, 226

4.5 NRC Safety Evaluation Report for Duane Arnold Energy Center, 10/3/00, TechnicalSpecification Amendment 234

4.6 NRC Safety Evaluation Report for Sequoyah Nuclear Plants, 10/24/01, TechnicalSpecification Amendments 271, 260

4.7 NRC Safety Evaluation Report for Diablo Canyon Nuclear Power Plant, 3/7/01,Technical Specification Amendments 146, 145

4.8 NRC Safety Evaluation Report for Monticello Nuclear Generating Station, 7/24/01,Technical Specification Amendment 120

4.9 NRC Safety Evaluation Report for Monticello Nuclear Generating Station, 8/1/01,Technical Specification Amendment 122

4.10 NRC Safety Evaluation Report for Brunswick Steam Electric Plant, 3/21/01 TechnicalSpecification Amendments 212, 239

4.11 NRC Safety Evaluation Report for Turkey Point Units 3 and 4, 4/26/01, TechnicalSpecification Amendments 213, 207

4.12 NRC letter to PECO dated 10/1/98 associated with Technical Specification Amendment223/227 for PBAPS Units 2 /3

Attachment B

Peach Bottom Atomic Power Station

Docket Nos. 50-277 & 50-278

License Nos. DPR-44 & DPR-56

Marked-up Technical Specifications and Bases Pages (Units 2 and 3)

List of Affected Pages(page 1 of 3)

Note: All Affected Pages apply to both PBAPS Units 2 and 3

Tech List of Affected Pages TSTF(s) SubmittalSpec SectionSection Unit 2 Unit 3 Number

2.0-1 2.0-1 5 2.12.0-2 2.0-2 5 2.1B 2.0-5 B 2.0-5 5 2.1

2.2 B 2.0-6 B 2.0-6 5 2.1B 2.0-8 B 2.0-8 5 2.1B 2.0-9 B 2.0-9 5 2.1B 2.0-10 B 2.0-10 5 2.1

3.0.3 3.0-1 3.0-1 208 2.23.1-12 3.1-12 222 2.3

3.1.4 3.1-13 3.1-13 222 2.3

B 3.1-25 B 3.1-25 222 2.3B 3.1-27 B 3.1-27 222 2.3

3.1.8 3.1-26 3.1-26 404 2.13B 3.1-49 B 3.1-49 404 2.13B 3.1-50 B 3.1-50 404 2.13

3.2.2 3.2-3 3.2-3 229 2.3B 3.2-9 B 3.2-9 229 2.3

3.3.2.2 3.3-22 3.3-22 297 2.4B 3.3-62 B 3.3-63 297 2.4

3.3.3.1 3.3-26 3.3-26 295 2.5B 3.3-69 B 3.3-70 295 2.5

3.3.4.1 3.3-30 3.3-30 297 2.4B 3.3-89 B 3.3-90 297 2.43.3-31 a 3.3-31 a 227 2.4

3.3.4.2 3.3-31 b 3.3-31 b 297 2.4B 3.3-91f B 3.3-92f 227 2.4B 3.3-91 g B 3.3-92g 297 2.43.3-39 3.3-39 275 2.63.3-40 3.3-40 275 2.6B 3.3-99 B 3.3-100 275 2.6B 3.3-1 00 B 3.3-1 01 275 2.6

3.3.5.1 B 3.3-101 B 3.3-102 275 2.6B 3.3-102 B 3.3-103 275 2.6B 3.3-103 B 3.3-104 275 2.6B 3.3-104 B 3.3-105 275 2.6B 3.3-106 B 3.3-107 275 2.6



Tech List of Affected Pages TSTF(s) SubmittalSpec SectionSection Unit 2 Unit 3 Number

3.3-48 3.3-48 306 2.73.3-49 3.3-49 306 2.73.3-50 3.3-50 306 2.7

3.3.6.1 3.3-54 3.3-54 306 2.7B 3.3-144 B 3.3-145 306 2.7B 3.3-159 B 3.3-160 306 2.7B 3.3-160 B 3.3-161 306 2.73.5-1 3.5-1 416 2.83.5-4 3.5-4 416 2.8

3.5.1 B 3.5-5 B 3.5-5 416 2.8B 3.5-6 B 3.5-6 416 2.8B 3.5-11 B 3.5-11 416 2.83.5-8 3.5-8 416 2.83.5-10 3.5-10 416 2.8

3.5.2 B 3.5-19 B 3.5-19 416 2.8B 3.5-22 B 3.5-22 416 2.8B 3.5-23 B 3.5-23 416 2.8

3.6.1.2 3.6-7 3.6-7 17 2.9B 3.6-12 B 3.6-12 17 2.93.6-9 3.6-9 269 2.103.6-10 3.6-10 30,323 2.103.6-11 3.6-11 269 2.103.6-13 3.6-13 45 2.103.6-14 3.6-14 45 2.103.6-15 3.6-15 46 2.10

3.6.1.3 B 3.6-20 B 3.6-20 269 2.10B 3.6-21 B 3.6-21 30, 323 2.10B 3.6-22 B 3.6-22 269 2.10B 3.6-25 B 3.6-25 45 2.10B 3.6-26 B 3.6-26 45 2.10B 3.6-27 B 3.6-27 46 2.10B 3.6-30 B 3.6-30 30 2.103.6-35 3.6-35 322 2.11

3.6.4.1 B 3.6-76 B 3.6-76 322 2.11B 3.6-77 B 3.6-77 322 2.11



Tech List of Affected Pages TSTF(s) SubmittalSpec Unit2 Unit 3 SectionSection Number

3.6-37 3.6-37 269 2.103.6-39 3.6-39 45, 46 2.10B 3.6-79 B 3.6-79 46 2.10

3.6.4.2 B 3.6-81 B 3.6-81 269 2.10B 3.6-82 B 3.6-82 45 2.10B 3.6-83 B 3.6-83 45, 46 2.103.8-10 3.8-10 276 2.123.8-14 3.8-14 276 2.12

3.8.1 B 3.8-26 B 3.8-26 276 2.12B 3.8-27 B 3.8-27 276 2.12B 3.8-31 B 3.8-31 276 2.12B 3.8-32 B 3.8-32 276 2.12

3.8.2 B 3.8-42 B 3.8-42 275 2.65.0-1 5.0-1 65 2.135.0-2 5.0-2 65 2.135.0-4 5.0-4 65 2.135.0-7 5.0-7 65 2.13

5.0 5.0-8 5.0-8 299 2.135.0-11 5.0-11 279 2.135.0-15 5.0-15 118,106 2.135.0-19 5.0-19 152 2.13

5.0-20 5.0-20 152 2.13

SLs 7

2.0

2.0 SAFETY LIMITS (SLs)

2.1 SLs

2.1 .1 Reactor Core SLs

2.1.1.1 With the reactor steam dome pressure < 785 psig or coreflow < 16% rated core flow:

THERMAL POWER shall be s 25% RTP.

2.1.1.2 With the reactor steam dome pressure 2 785 psig and coreflow 2 10% rated core flow:

MCPR shall be 2 1.07 for two recirculation loop operationor 2 1.09 for single recirculation loop operation.

2.1.1.3 Reactor' vessel water level shall be greater than the topof active irradiated fuel.

I

2.1.2 Reactor Coolant System Pressure SL

Reactor steam dome pressure shall be • 1325 psig.

2.2 SL Violations

With any SL violation, the following actions shall be completed J

5F9>-.1 ~Witi zhu, Aotif, the 0lAt prtoi codne

2.2 1 Restore compliance with all SLs; and

2.2 02 2 Insert all insertable control rods.

n urs, no the Plant- Manager and thc Vic ud )

AtBFR-r- Pcontinued)n

PBAPS UNIT 2 -2.0- 1 Amendment No. .-6,246

SLs2.0

2.0 SLs

c'

PBAPS UNIT 2 2.0-2 Anendment No. 210

LCO Applicability3.0

3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY

LCO 3.0.1 LCOs shall be met during the MODES or other specifiedconditions in the Applicability, except as provided inLCO 3.0.2 and LCO 3.0.7.

LCO 3.0.2 Upon discovery of a failure to meet an LCO, the RequiredActions of the associated Conditions shall be met, except asprovided in LCO 3.0.5 and LCO 3.0.6.

If the LCO is met or is no longer applicable prior toexpiration of the specified-Completion Time(s), completionof the Required Action(s) is not required, unless otherwisestated.

LCO 3.0.3 When an LCO is not met and the associated ACTIONS are notmet, an associated ACTION is not provided, or if directed bythe associated ACTIONS, the unit shall be placed in a MODEor other specified condition in which the LCO is notapplicable. Action shall be initiated within 1 hour toplace the unit, as applicable, in:

a. MODE 2 withi

b. MODE 3 within 13 hours; and

c. MODE 4 within 37 hours.

Exceptions to this Specification are stated in theindividual Specifications.

Where corrective measures are completed that permitoperation in accordance with the LCO or ACTIONS, completionof the actions required by LCO 3.0.3 is not required.

LCO 3.0.3 is only applicable in MODES 1, 2, and 3.

LCO .3.0.4 When an LCO is not met, entry into a MODE or other specifiedcondition in the Applicability shall not be made except whenthe associated ACTIONS to be entered permit continuedoperation in the MODE or. other specified condition in theApplicability for an unlimited period of time. ThisSpecification shall not prevent changes in MODES or otherspecified conditions in the Applicability that are requiredto comply with ACTIONS, or that are part of a shutdown ofthe unit.

(continued))

RBAPS UNIT 2 3.0-1 Amendment No. 210

Control Rod Scram Times3.1.4

3.1 REACTIVITY CONTROL SYSTEMS

3.1.4 Control Rod Scram Times

LCO 3.1.4 a. No more than 13 OPERABLE control rods shall be 'slow,'in accordance with Table 3.1.4-1; and

b. No more thanshall occupy

2 OPERABLE control rods that are "slow'adjacent locations.

APPLICABILITY: MODES 1 and 2.

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME

A. Requirements of the A.1 Be in MODE 3. 12 hoursLCO not met.

SURVEILLANCE REQUIREMENTS

- -------------------------------- NOTE----------------_ -__-_-___During single control rod scram time Surveillances, the control rod drive(CRD) pumps shall be isolated from the associated scram accumulator.

SURVEILLANCE FREQUENCY

SR 3.1.4.1 Verify each control rod scram time iswithin the limits of Table 3.1.4-1 with xxu4ng ireactor steam dome pressure > 800 psig. aOX RTP -fter

(continued)

)1

PBAPS UNIT 2 3.1-12 Amendment No. 210




SR 3.1.4.1 (continued) Prior toexceeding40% RTP aftereach reactorshutdown. 120 days

SR 3.1.4.2 Verify, for a representative sample, each 120 daystested control rod scram time is within the cumulativelimits of Table 3.1.4-1 with reactor steam operation indome-pressure ? 800 psig. MODE 1

SR 3.1.4.3 Verify each affected control rod scram time Prior-tois within the limits of Table 3.1.4-1 with declaringany reactor steam dome pressure. control rod

OPERABLE afterwork on controlrod or CRDSystem thatcould affectscram time

SR 3.1.4.4 Verify each affected control rod scram time Prior tois within the limits of Table 3.1.4-1 with exceedingreactor steam dome pressure 2 800 psig. 40% RTP after

work on controlrod or CRDSystem thatcould affectscram time

AND

Prior toexceeding 40%RTP after fuelmovement within

PBAPS UNIT 2 3.1-13 U 2Amendment No. 210

SDV Vent and Drain Valves .3.1.8


3.1.8 Scram Discharge Volume (SOY) Vent and Drain Valves

LCO 3.1.8 Each SDV vent and drain valve shal Ibe OPERABLE.

I


ACTIONS S-wrrr- --NOTEZ--- --- -- -__________________

e "Separate Condition entry is allowed for each SDY vent and drain line.


nno mrnnrP l n A hent l 7 klav eor drain lines withone valve inoperable.

Iuay.Y~

I

B. One or more SDV ventor- drain linae withboth valvesinoperable.

't2.An i solIated'1Tme W.be unisolated underadministrativecontrol to allowdraining and venting

. of the SOV.

Isolate theassociated line.

8 hours

C. Required Action and C.1 Be in MODE 3. 12 hoursassociated CompletionTime not met.


MCPR3.2.2

SURVEILLANCE REQUIREMENTS (continued)


SR 3.2.2.2 Determine the MCPR limits. Once within72 hours aftereach completionof SR 3.1.4.1

AND

Once within72 hours aftereach completionof SR 3.1.4.2

e~Pc~k co-pe4.

, f- 3AS, f-

.

PBP NT - Amnmn No. 1


Feedwater and Main Turbine High Water Level Trip Instrumentation3.3.2.2

3.3 INSTRUMENTATION ;

.3.3.2.2 Feedwater and Main Turbine High Water Level Trip Instrumentation

I

)

LCO 3.3.2.2

APPLICABILITY:

Two channels per trip system of the Digital FeedwaterControl System (DFCS) high water level trip instrumentationFunction shall be OPERABLE.

THERMAL POWER 2 25% RTP.

ACTIONS

-------------------------------------NOTE--------------__ -_-_-__ -_Separate Condition entry is allowed for each channel.


A. One or more DFCS high A.1 Place channel in 72 hourswater level trip trip.channels inoperable.

B. DFCS high water level B.1 Restore DFCS high 2 hourstrip capability not water level tripmaintained. capability.

C. Required Action andassociated CompletionTime not met.

(f4CZ

m:niReduce THERMAL POWERto < 25% RTP.

4 hours

Sxi+Aie > no erwb(e &ciaps

fief .J1,r~iir.e~t hA¢^.^AC. af f.* A.fw6;t_ 5 l-v E - - 4

-h4- r;e stsVlo 14 _fe

te Q C ; C_ :. AtV!

~e~ove~ 4 ~ 'AC &,Li,

PBPS UNI 2medetN.) 210

3.3-22Amendment No. 210PBAPS UNIT 2

PAM Instrumentation3.3.3.1

Table 3.3.3.1-1 Cpage 1 of 1)Post Accident honitorinq Instrumentation

CONDITIONSREFERENCED

REWIRED FROM REWIREDFUNCTION CHANNELS ACTION D.1

1. Reactor Pressure 2 E

2. Reactor Vessel Vater Level CMlde Rune) 2 E

3. Reactor Vessel Later Level CFuel Zone) 2 E

4. Suppression Chamber Yater Level (Wide Range) 2 E

5. Drywell Pressure (Uide Rwnge) 2 E

6. Drywelt Pressure CSotat ospheric Runse) 2 E

7. Drywell High Range Radiation .2 F

8. PCIV Position 2 per peneftf M fbiw Epath

9. Drywell 112 & 02 Analyzer 2 E

10. Suppression Chamber N2 & 02 Analyzer 2 E

11. Suppression Chacter Water Te per ture 2C0) E

Ca) Not required for isolation valves whose associated penetration flow path is isolated by at least cneclosed and deactivated autoiatic valve, closed *eual valve, blind flange, or check valve ilth flowthrough the valve secured.

(b) Only one position indication channel is required for penetration flow paths with only one installedcontrol roon indication channet.

(c) Each charnel requires 10 resistance temperature detectorts CRTDs) to be OPERAOi. with no two adjacentRTDs inoperable.

i

I

ii

I

I

f


ATWS-RPT Instrumentation3.3.4.1

ACTIONS (continued)


B. One Function with B.1 Restore ATWS-RPT trip 72 hoursATWS-RPT trip capability.capability notmaintained.

C. Both Functions with C.1 Restore ATWS-RPT trip 1 hourATWS-RPT trip capability for onecapability not Function.maintained.

D. Required Action and . Remove the 6 hoursassociated Completion recirculation pumpTime not met. from service.

OR

D.2 Be in MODE 2. 6 hours

SURVEILLANCE REQUIREMENTS R PT bred'rP

------------------------ NOTE----_--________-______When a channel is placed in an inoperable status solely for performance ofrequired Surveillances, entry into associated Conditions and Required Actionsmay be delayed for up to 6 hours provided the associated Function maintainsATWS-RPT trip capability.


SR 3.3.4.1.1 Perform CHANNEL CHECK. 12 hours

(continued)

I


EOC-RPT Instrumentation3.3.4.2

3.3 INSTRUMENTATION'

3.3.4.2 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation

LCO 3.3.4.2 * a. Two channels per trip system for each EOC-RPTinstrumentation Function listed below shall be OPERABLE:

1. Turbine Stop Valve (TSV)-Closure; and

2. Turbine Control Valve (TCV) Fast Closure, TripOil Pressure-Low.

b. The following limits are made applicable:

1. LCO'3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATIONRATE (APLHGR)," limits for inoperable EOC-RPT asspecified in the COLR; and

2. LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR),"limits for inoperable EOC-RPT as specified in theCOLR.

APPLICABILITY: THERMAL POWER 2 29.5X RTP. I

ACTIONS

-------------------------------- NOTE------------Separate Condition entry is allowed for each channel.


A. One or more channels A.1 Restore channel to 72 hoursinoperable. OPERABLE status.

( DRA.2 -------- NOTE---------

Not applicable ifinoperable channel isthe result of aninoperable breaker.

Place channel in 72 hourstrip.

(continued))

PBAPS UNIT 2 3.3-31a Amendment No. 247


r

ACTIONS (continued)


B. One or more Functions B.1 Restore EOC-RPT trip 2 hourswith EOC-RPT trip capability.capability notmaintained.

C. Required Action and e Remove the 4 hoursassociated Completion recirculation pumpTime not met. from service.

C.2 Reduce THERMAL POWER 4 hoursto < 29.5X RTP. I

)/,(


--------------------------------------NOTE------------------------------------When a channel is placed in an inoperable status solely for performance ofrequired Surveillances, entry into associated Conditions and Required Actionsmay be delayed for up to 6 hours provided the associated Function maintainsEOC-RPT trip capability.


SR 3.3.4.2.1 Perform CHANNEL FUNCTIONAL TEST. 92 days

(continued)

k�.(

AR.I - - /06 __^

b. Ohlr liffica1e ;-Pi%Aolemue C 6^K i's 4-ke

(-t A re% k%- - - -

PBAPS UNIT 2 3.3-31b Amendment No. 247

I -

ECCS Instrumentation3.3.5.1

Table 3.3.5.1-1 (page 1 of 5)Emergency Core Cooling System Instrumentation

APPLICABLE CONDITIONSlODES REQUIRED REFERENCED

OR OTHER CHWOIELS FROMSPECIFIED PER REOUIRED SURVEILLANCE ALLOJABLE

FUNCTION CONDITIONS RFiCTION ACTIOU A.1 REOUIREMENTS VALUE

1. Core Spray System

a. Reactor Vessel Water 1,2,3, 4Cb) B SR 3.3.5.1.1 2 -160.0Level -Low Low Low SR 3.3.5.1.2 inchesCLevet 1) 4t), S) SR 3.3.5.1.4

SR 3.3.5.1.5

b. Drywell 1,2,3 4 tb) B SR 3.3.5.1.1 S 2.0 psigPressure -High SR 3.3.5.1.2

SR 3.3.5.1.4SR 3.3.5.1.5

c. Reactor Pressure-Low 1,2,3 4 C SR 3.3.5.1.1 2 425.0 psig(Injection Permissive) SR 3.3.5.1.2 and

SR 3.3.5.1.4 s 475.0 psigSR 3.3.5.1.5

4 t), 5 Ca) B SR 3.3.5.1.1 2 425.0 psigSR 3.3.5.1.2 andSR 3.3.5.1.4 5 475.0 psigSR 3.3.5.1.5

d. Core Spray Puip 1,2.3. 4 E SR 3.3.5.1.2 2 319.0 psidDischarge Flow-Low C1 per SR 3.3.5.1.4 and(Bypass) 4 (a). 5 Ca) W) S 351.0 psid

e. Core Spray Pump Start- 1,2,3 4 C SR 3.3.5.1.4 2 5.0 secondsTime Delay Relay (loss C1 per SR 3.3.5.1.5 andof offsite power) 4 Ca), 5Ca) p.p) E 7.0 seconds

f. Core Spray Punp Start-Time Delay RelayCoffsite poweravailable)

Pumps A,C 1,2,3 2 C SR 3.3.5.1.4 2 12.1Ca per SR 3.3.5.1.5 seconds and

4 Ca) 5 SCa) PACO 5 13.9seconds

Pumps B.D 1.2,3 2. C SR 3.3.5.1.4 : 21.4Cl per SR 3.3.5.1.5 seconds and

4 Ca), 5 Ca) PM) t1 24.6seconds

Ca) Mien associateosubsystemas) are required to be OOERABIvW . O I ; 3

Cb) Also required to initiate the associated diesel generator CDOG).



Table 3.3.5.1-1 (page 2 of 5)Emergency Core Cooling System Instrunentation

APPLICABLE CONDITIONSWODES REmJIRED REFERENCED

OR OTHER CNAMMELS FROMSPECIFIED PER REWUIRED SURVEILLANCE ALLOIMBLE

FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE

2. Low Pressure CoolantInjection CLPCI) System

a. Reactor Vessel Water 1,2,3, 4 B SR 3.3.5.1.1 2 -160 inchesLevel -Low Low Low SR 3.3.5.1.2(Level 1) 4Cm), 5(3) SR 3.3.5.1.4

SR 3.3.5.1.5

b. Drywell l,2;3 4 8 SR 3.3.5.1.1 £ 2.0 psigPressure -High SR 3.3.5.1.2

SR 3.3.5.1.4SR 3.3.5.1.5

c. Reactor Pressure-Low 1,2,3 4 C SR 3.3.5.1.1 Z 425.0 psig(Injection Permissive) SR 3.3.5.1.2 and

SR 3.3.5.1.4 £ 475.0 psi9SR 3.3.5.1.5

4'a), 5'a) B SR 3.3.5.1.1 2 425.0 psigSR 3.3.5.1.2 andSR 3.3.5.1.4 * 475.0 psigSR 33.5.1.5

d. Reactor Pressure-Low 1 c),2 Cc), 4 C SR 33.5.1.1 2 211.0 psigLow (Recirculation SR 3.3.5.1.2Discharge Valve 3 (c" SR 3.3.5.1.4Permissive) SR 3.3.5.1.5

e. Reactor Vessel Shroud 1,2,3 2 B SR 33.5.1.1 t -226.0Level -Level 0 SR 33.5.1.2 inches

SR 33.5.1.4SR 33.5.1.5

f. Low Pressure Coolant 1,2,3, 8 C SR 3.3.5.1.4Injection Pump C2 per SR 33.5.1.5Start -Time Delay 40), 5(a) p )Relay (offsite poweravatable)

Pu A,o t 1.9 seconds_d S 2.1seconds

Puns C.0 t 7.5 secmxismid S 8.5seconds

g. Low Pressure Coolant 1,2,3 4 E SR 3.3.5.1.2 > 299.0 psidInjection Pump t per SR 3.3.5.1.4 andDischarge Flow-Low 4tM), 5(a) pulp) SR 3.3.5.1.5 S 331.0 psid(Bypess)

I

I

e-.- ft(contimsied)

Ca) When ssociated bytemts) are required to be OPERABLF v LC9> 3'64/- L-CCS J7ov

tc) With associated recirculation pump discharge valve open.

PBAPS UNIT 2 3.3-40 Ambndment No. 210

Primary Containment Isolation Instrumentation3.3.6.1

3.3 INSTRUMENTATION

3.3.6.1 Primary Containment Isolation Instrumentation)

LCO -3.3.6.1 The primary containment isolation instrumentation for eachFunction in Table 3.3.6.1-1 shall be OPERABLE.

APPLICABILITY- According to Table 3.3.6.1-1.

''ACTION V d > ti-S+C 085, ---

Coi-----------------------------------s allowed foreac cam '~Separate Condition entry is 'allowed for each channel.

___ ___ __ --- ---------- ------------ ------------ --- --- _--_-- ----- ------ - ------ ------

CONDITION REQUIRED ACTION [_COMPLETION TIME

A. One or more requiredchannels inoperable.

A.1 Placetrip.

channel in 12 hours forFunctions 1.2.a, e 2.

AND

24 hours forFunctions otherthan Functions1.d, 2.abdcEZZ2. b Z, _

B. One or more Functions B.1 Restore isolation 1 hourwith isolation capability.capability notmaintained.

C. Required Action and C.1 Enter the Condition Immediatelyassociated Completion referenced inTime of Condition A or Table 3.3.6.1-1 forB not met. the channel.

(continued)



) ACTIONS (continued)CONDITION REQUIRED ACTION COMPLETION TIME

D. *As required by D.1 Isolate associated 12 hoursRequired Action C.1 main steam lineand referenced in (MSL).Table 3.3.6.1-1.

OR

D.2.1 Be in MODE 3. 12 hours

AND

D.2.2 Be in MODE 4. 36 hours

E. As required by E.1 Be in MODE 2. 6 hoursRequired Action C.1and referenced inTable 3.3.6.1-1.

F. As required by F.1 Isolate the affected 1 hourRequired Action C.1 penetration flowand referenced in path(s).Table 3.3.6.1-1.

G. As required by G.1 Be in MODE 3. 12 hoursRequired Action C.1and referenced in ANDTable 3.3.6.1-1.

6.2 Be in MODE 4. 36 hoursOR

Required Action andassociated CompletionTime of Condition Fnot met. 2

�or T

(continued)

_i

PBAPS UNIT 2 3 .3-49 Amendment No. 210

Primary Containment Isolation Instrumentation- 3.3.6.1

ACTIONS frnntintiedI


H. As required by H.1 Declare associated 1 hourRequired Action C.1 standby liquidand referenced in control (SLC)Table 3.3.6.1-1. subsystem inoperable.

OR

H.2 Isolate the Reactor 1 hourWater Cleanup System.

I. As required by I.1 Initiate action to ImmediatelyRequired Action C.1 restore channel toand referenced in OPERABLE status.Table. 3.3.6.1-1.

OR

I.2 Initiate action to Immediatelyisolate the ResidualHeat Removal (RHR)Shutdown CoolingSystem.

T As becd J- 1 >4-e 4f ecg |24 ho)J 12ej,,i4 An - C. ( F4,.i 2-t hookzer rCkffs@Cq & plIs).

-FOsable- 303 6.1I- I PA

i

!



Table 3.3.6.1-1 Cpage 3 of 3)Primary Containment Isolation Instrimentation

APPLICABLE CONDITIONSVDES OR REQUIRED REFERENCED

OTHER CHAXNELS FROCSPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOUABLE

FUNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE

5. Reactor Water Cleanuip(RYCU) System Isolation

a. RYCU Flow-High 1,23 1 F SR 3.3.6.1.1 125X ratedSR 3.3.6.1.3 flow (23.0SR 3.3.6.1.7 in-wc)

b. SLC System Initiation 1,2 1 H SR 3.3.6.1.7 NA

c. Reactor Vessel Water 1,2,3 2 F SR 3.3.6.1.1 2 1.0 inchesLevel -Low (Level 3) SR 3.3.6.1.2

SR 3.3.6.1.5SR 3.3.6.1.7

6. RHR Shutdown Cooling SystemIsolation

a. Reactor Pressure-High 1,2,3 1 F SR 3.3.6.1.3 < 70.0 psigSR 3.3.6.1.7

b. Reactor Vessel Water 3,4,5 2Ca) I SR 3.3.6.1.1 2 1.0 inchesLevel - Low (Level 3) SR 3.3.6.1.2

SR 3.3.6.1.5SR 3.3.6.1.7

7. Feedoater RecirculationIsolation

a. Reactor Pressure-High 1t2.3 2 F SR 3.3.6.1.1 t 600 psigSR 3.3.6.1.2SR 3.3.6.1.5SR 3.3.6.1.7

,.

4

i

(a) In aD(S I *nd 5, provided RHR Shutdown Cooling system integrity is maintained, only one channel pertrip system with an isolation signal available to one shutdown cooling pump suction isolation valve isrequired.

Yu in-L 0C~vc 3)e PV~ -S(44 V 55f VJ-Ac ItsJ R H11 1, se 4 A>I

( %<tLO6tULerc(3) 5F ,3,. 6.t; ;,ce z

Sv9- s3 . b .'I

sAUPtN2.23.d .1. 7

1 U N s #1.,13 2 T s5L, 3 *. -1 I ,0

PBAPSAme=dme n t No. 210

*'1t a .,

ECCS -Operating3.5.1

..5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING(RCIC) SYSTEM

3.5.1 ECCS-Operating

LCO 3.5.1

APPLICABILITY:

Each ECCS injection/spray subsystem and the AutomaticDepressurization System (ADS) function of five safety/reliefvalves shall be OPERABLE.

MODE 1,MODES 2 and 3, except high pressure coolant injection (HPCI)

is not required to be OPERABLE with reactor steam domepressure s 150 psig and ADS valves are not required tobe OPERABLE with reactor steam dome pressure s 100 psig.

ACTIONS


A. One low pressure ECCS A.1 Restore low pressure 7 daysinjection/spray ECCS injection/spraysubsystem inoperable. subsystem(s) to

OPERABLE status.OR

One low pressurecoolant injection(LPCI) pump in eachsubsystem inoperable.

B. Required Action and B.1 Be in MODE 3. 12 hoursassociated CompletionTime of Condition A ANDnot met.

B.2 Be in MODE 4. 36 hours

. /s1 OT E -Loe s vs5 cvvfsi4-At~jP4 I",Cf ft~f~ agm l

CAAS4dt OrFRABqLE ewtz tlymof7Z 01K/ o,711

ckchi 4- eom( l t,1 4 2M roxi$lA °L 3'

lieo tv-k 4sb~ V- 3 -

r >4qcusc;\?#ti4, 3.5-1 2

(continued)

Amendment No. 210

,)

PBAPS UNIT

ECCS-Operating3.5.1



SR 3.5.1.1 Verify, for each ECCS injection/spray 31 dayssubsystem, the piping is filled with waterfrom the pump discharge valve to theinjection valve.

/ V

SR 3.5.1.2 -----------------NOTE----------Q~wprsue coolant injection (LPCU e

subsystes~yb consideredOREULduring alignm'ent'*d oeriffo decay2 eat removal wit reixisteam dome

4 pressure less th e Resi Heatj~e oRemoval 'RHR ~t~tow cooling iD~ton

e pressure E 3, if capable of being1-manu realigned and not otherwise

Verify each ECCS injection/spray subsystemmanual, power operated, and :automatic valvein the flow path, that is not locked,sealed, or otherwise secured in position,is in the correct position.

31 days

I

SR 3.5.1.3 Verify ADS nitrogen supply header pressure 31 daysis 2 85 psig.

SR 3.5.1.4 Verify the LPCI cross tie valve 31 daysis closed and power is removed from thevalve operator.

I

(continued)

!PBAPS UNIT 2 3.5-4 Amendment No. 210

-TST-F 'H 6, ECCS-Shutdown3.5.2

3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATIONCOOLING (RCIC) SYSTEM

3.5.2 ECCS-Shutdown

LCO 3.5.2

|APPLICABILITY :

Two low pressure ECCS injection/spray subsystems shall beOPERABLE.

MODE 4,MODE 5, except with the spent fuel storage pool gates

removed, water level 2 458 inches above reactor, pressurevessel instrument zero, and no operations with a

- potential for draining the reactor vessel (OPDRVs) inprogress.

ACTIONS


A. One required ECCS A.1 Restore required ECCS 4 hoursinjection/spray injection/spraysubsystem inoperable. subsystem to OPERABLE

status.

B. Required Action and B.1 Initiate action to Immediatelyassociated Completion suspend OPDRVs.Time of Condition Anot met.

C. TvifSt

io required ECCSijection/sprayibsystems inoperable.

C.1

AND

C.2

Initiate action tosuspend OPDRVs:

Restore one ECCSinjection/spraysubsystem to OPERABLEstatus.

Immediately

4 hours

)

ted)

. 210PBAPS UNIT 2SV- a Ir a -

A - . . _ - - , - -

ECCS-Shutdown3.5.2


SURVEILLANCE FREQUENCY.

SR. -3.5.2.2 Verify, for each required core spray (CS) 12 hourssubsystem, the:

a. Suppression pool water level is2 11.0 ft; or

b. -------------- NOTE-----------------Only one required CS subsystem maytake credit for this option duringOPDRVs.

Condensate storage tank water level is> 17.3 ft.

SR 3.5.2.3 .Verify, for each required ECCS injection/ 31 daysspray subsystem, the piping is filled withwater from the pump discharge valve to theinjection valve.

SR 3.5.2.4- ---- =NOTE-

Z V-A ovtlI-')

% One LPI bsystem may be cci~ h Cr OPERABLE du alig nd operation for

decay heat rcapable of being>- manually e and nr utQherwise

gwrre.

Verify each required ECCS injection/spraysubsystem manual, power operated, andautomatic valve in the flow path, that isnot locked, sealed, or otherwise secured inposition, is in the correct position.

31 days

(continued) .

)PBAPS UNIT 2 3 .5-10 Amendment No. 210

Primary Containment Air Lock3.6.1.2


SURVEILLANCE [ FREQUENCY

11 �-SR 3.6.].2.2

I ̂B; ^e ^ ont rnon It do inr ..+~~h * pleJ ;a

Verify only one door in the primarycontainment air lock can be opened at atime.

I

L ____________________________

)


PCIVs3.6.1.3

ACTIONS


A. -(continued) A.2 - NOTEP ------n Isolation devices in

high radiation areas.may be verified byuse of administrativemeans.

Verify the affected Once per 31 days.penetration flow path for isolationis isolated. devices outside

^t_>( BRn4tt 0 .~3 primary. containment

6e C'L' vsPrior-to,Pe? entering MODE 2

XQ Vrb or 3 fromMODE. 4, ifprimarycontainment wasde-inerted whilein MODE 4, ifnot performedwithin theprevious92 days, forisolationdevices insideprimarycontainment

(continued)

PBAPS UNIT 2 3 .6-9 Amendment-No. 210

PCIVs3.6.1.3

ACTIONS (continued)


B. ----- NOTE--------- B.1 Isolate the affected 1 hourOnly applicable to penetration flow pathpenetration flow paths by use of at leastwith two PCIVs. one closed and--_ - - ._ de-activated

automatic valve,One or more closed manual valve,penetration flow paths or blind flange.with two PCIVsinoperable except forMSIV leakage notwithin limit.

I

t

C. ---------NOTE-------Only applicable topenetration flow pathswith only one PCIV.

C.1 Isolate the affectedpenetration flow pathby use of at leastone closed andde-activatedautomatic valve,closed manual valve,or blind flange.

.. 9.;B; a

4 hours e-xc4Af4.excess..aow ,/;GheBck-va.1,(EFCVs)

. ....One or morepenetration flow pathswith one PCIVinoperable.

/(

i


-

PCIVs3.6.1.3

ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIMEI.

C. -(continued) C.2 ---- NOT C -------!.2Isolation devices in01--high radiation areas.

may be verified byuse of administrative

-,means. .

1211

Verify the affectedpenetration flow pathis isolated.

I .

Once per 31 days.for isolationdevices outsideprimarycontainment

AND

Prior.toentering MODE 2or 3 fromMODE 4, ifprimarycontainment wasde-inerted whilein MODE 4, ifnot performedwithin theprevious92 days, forisolationdevices insideprimarycontainment

D. One or more D.1 Restore leakage rate 8 hourspenetration flow paths to within limit.with one or more KSIVsnot within MSIVleakage rate limits.

(continued)


PCIVs3.6.1.3

.

rIMUCTI I Aulrr nrntlTDnrUCLTC I--- ;n4n-llQWFVLLLLl'.HL.L~fLUfLII . LII IUU _________


SR 3.6.1.3.3 ------------------NOTE-------------------Not required to be met when the 6 inch or18 inch primary containment purge and 18inch primary containment exhaust valvesare open for inerting, de-inerting,pressure control, ALARA or air qualityconsiderations for personnel entry, orSurveillances. that require the valves to'.be open.

Verify each 6 inch and 18 inch primary 31 dayscontainment purge valve and each 18 inchprimary containment exhaust valve isclosed.

SR 3.6.1.3.4 ------------------ NOTES------------------1. Valves and blind flanges in high

radiation areas may be verified byuse of administrative means.

2. Not required to be met for PCIVs thatare open under administrativecontrols.

3. Not required to be performed for testtaps with a diameter < 1 inch.

Verify each primary containment isolationmanual valve and blind flange that islocated outside primary containmenthandis required to be closed during accidentconditions is closed. /

31 days

(continued)

c~r~cl~4 lOI~ I leoo1 r I 4e~SeSc-


PCIVs3.6.1.3



SR -3.6.1.3.5 ------------------NOTES------------------1. Valves and blind flanges in high



Verify each primary containment manualisolation valve and blind flange that islocated inside primary containmen'and isrequired to be closed during acci ntconditions is closed.

0 e C

Prior toentering MODE 2or 3 fromMODE 4 ifprimarycontainment wasde-inertedwhile inMODE 4, if notperformedwithin theprevious92 days

SR 3.6.1.3.6 Verify continuity of the traversing 31 daysincore probe (TIP) shear isolation valveexplosive charge.

SR 3.6.1.3.7 Verify each SGIG System manual valve in 31 daysthe flow paths servicing the 6 and18 inch primary containment purge valvesand the 18 inch primary containmentexhaust valves, that is not locked,sealed, or otherwise secured in position,is in the correct position.

(continued)

PBA.PS UNIT 2 3.6-14 Amendment No. 210

a

PCIVs3.6.1.3



SR 3.6.1.3.8 Verify the isolation time o each In accordance__ IF W each automatic PCIV, except with the

Torl S Vs, is within limits. InserviceTesting Program

SR 3.6.1.3.9 Verify the isolation time of each MSIV is In accordance2 3 seconds and & 5 seconds. with the

InserviceTesting Program

SR 3.6.1.3.10 Verify each automatic PCIV actuates to 24 monthsthe isolation position on an actual orsimulated isolation signal.

SR 3.6.1.3.11 Verify e representative sample of reactor 24 monthsinstrumentation line EFCVs actuates tothe isolation position on a simulatedinstrument line break signal.

SR 3.6.1.3.12 Remove and test the explosive squib from 24 months on aeach shear isolation valve of the TIP STAGGERED TESTSystem. BASIS

SR 3.6.1.3.13 Verify the CAD System supplies nitrogen 24 monthsto the SGIG System upon loss of thenormal air supply.

(continued)

I


Secondary Containment3.6.4.1

ACTIONS


C. (continued) C.2 Suspend CORE ImmediatelyALTERATIONS.

AND

C.3 Initiate action to Immediatelysuspend OPDRVs.

I

I.

Verify h 'IT 3fi :&i. r2 0.25 inch of vacuum water gaugei j

oM Tor 1 hour at aWasiate s lus cfm. 1

I


SCIVs3.6.4.2

ACTIONS


A. (continued) A.2 - ---- NOTEr -------OIsolation devices in

high radiation areasmay be verified byuse of administrative

,,4,b, AtSameans.,fz St~ e trCSty/---~----~------------

v Verify the affected Once per 31 dayspenetration flow path

Or 0 is isolated.

B. ---------NOTE--------- B.1 Isolate the affected 4 hoursOnly applicable to penetration flow pathpenetration flow paths by use of at leastwith two isolation one closed andvalves. de-activated___ _ _ _ ____ ___ -automatic valve,

closed manual valve,One or more or blind flange.penetration flow pathswith two SCIVsinoperable.

C. Required Action and C.1 Be in MODE 3. 12 hoursassociated CompletionTime of Condition A ANDor B not met inMODE 1, 2, or 3. C.2 Be in MODE 4. 36 hours

(continued)


SCIVs3.6.4.2


* SURVEILLANCE FREQUENCY

SR *3.6.4.2.1 ------------------NOTES------------------1. Valves and blind flanges in high,

radiation areas may be verified by* *use of administrative means.

2. Not required to be met for SCIVs that'are open under administrativecontrols.

Verify each secondary containmentisolation manual valve and blind flangethat J;Arequired to be closed duringiEfid-ent conditions is closed.

31 days

SR 3.6.4.2.2 Verify the isolation time of each power In accordanceoperated automatic SCIV is with thewithin limi ts. Inservice

Testing Program

SR 3.6.4.2.3 Verify each automatic SCIV actuates to 24 monthsthe isolation position on an actual orsimulated actuation signal.


AC Sources-Operating3.8.1 I


- SURVEILLANCE FREQUENCY

I

A single test at the specifiedFrequency will satisfy thisSurveillance for both units.

Verify each DG rejects a load greater thanor equal to its associated single largestpost-accident load, and:

24 months

a. Followingfrequency

load rejection, theis - 66.75 Hz;

b. Within 1.8 seconds following loadrejection, the voltage is 2 3750 V ands 4570 V, and after steady stateconditions are reached, maintainsvoltage ; 4160 V and < 4400 V; and

c. Within 2.4rejection,and s 61.2

seconds following loadthe frequency is > 58.8 HzHz.

-- --- --------- NOTL -----------------single test at the specified Frequency

will satisfy this Surveillance for bothunits.

Verify each DG .triG pdoes not trip an vmaintained z 5230 V during and following aload rejection of 2 2400 kW and < 2600 kW.

24 months

(continued)

PBAPS.UNIT 2. 3.8-10 Amendment No. 210

TSTF-276, Rev. 2

3. If performed with DG synchronized with site.powt it shall beperformed at a power factors [

However, if grid conditions do not permit, powerfactor limit is not required to be met. Under thiscondition the powe factor shall be maintained as closeto the limit as practicable.

INSER 23

3. If penred with DG synchronized with offsitein tpit shall Wen ynchrned att a power factor < [0.9].Hoewever, is aid conditions do not permit, dtn hN a enfactor limit i powequired to be met. Unde cgcondition the powe fctor shall be maintained asto the limit as practio . w

INSERT3

Note 2 ensures that the DG is teste load conditions that are as close to design basis conditionsas possible. When synchronized * fseoetesting should be performed at a power factor of< [0.9]. This power factor is re snttve o e actual 'inductive loading a DG would see underdesign basis acciden cnthe gri er certay s that however, Note 2 allows the surveillance tobe conducted at a pwrfc ohrthan < [09.Iecnditions occur when grid volt age is high,and the additional fedxuai needed to ge th o4fcor to < 10.9] results in voltages on theemergency. busses ta ,o hgh. Under theecnionh power factor should be maintained asclose as practicable to .9] while still maintaining acce tbeQtage limits on the emergency busses.-In other cicmtne the grid voltage may be such that the D ~itation levels needed to obtain apower factor of [0 may not cause unacceptable voltages on the e gency busses, but the excitationlevels are in exc s of those recommended for the DG. In such cases, power factor shall bemaintained as ose as practicable to [0.9] without exceeding the DG exc in limits.

AC Sources-Operating3.8.1

SURVEILLANCE REQUIREMENTS (continued) .


SR *3.8.1.14 -------------------NOTES-------------------1. Momentary transients outside the load

and power factor ranges do -notinvalidate this test.

power factor limit as not requiredf be-met. Under this condition the~r power factor shall be maintained as

3. A single test at the specifiedFrequency will satisfy this

_ _ Surveillance for both units.L \-------a ------------ _---------

'f each DG r- ~~~~~~~operates o 79hus ~~~

a. For 2 2 hours loaded > 2800 kW and_ 3000 kW; and

24 months

b. For the remaining hours of the testloaded z 2400 kW and s 2600 kW.

(continued)

PBAPS UNIT 2. 3.8-14 Amendment No. 210

TSTF-276, Rev. 2

INSERT 1

2. If performed with synmonized with offsitehpower,it shall beperformed aower factor < [0.9].However; if grid co tion not permit, the powerfactor limit is n equired to be t. Under thiscondition th wer factor shall be *ntained as closeto the ii practicable.

___ERT2

If performed with DG synchronized with offsite wer,it shall be performed at a power factor e

However, if grid conditions do'not permit, the poweri '.factor limit is not required to be met. Under this\ condition the power factor shall be maintained as close

to the limit as practicable./

Note 2 ensures that the is tested under load co itions that are as close to design basis conditionsas possible. When synchro ed with offsite pour, testing should be performed at a power factor of< [0.9]. This power factor is re sentative of e actual inductive loading a DG would see underdesign basis accident conditions. der c conditions, however, Note 2 allows the surveillance tobe conducted at a power factor.other 0.9]. These conditions occur when grid voltage is high,and the additional field excitation neede get the power factor to < [0.9] results in voltages on theemergency busses that are too high. der conditions, the power factor should be maintained asclose as practicable to [0.9] while maintaini acceptable voltage limits on the emergency busses.In other circumstances, the grid tage may be suc at the DG excitation levels needed to obtain apower factor of [0.9] may not unacceptable volta on the emergency busses, but the excitationlevels are in excess of those commended for the DG. In ch cases, the power factor shall bemaintained as close as or cable to r0.91 without exceeding DG excitation limits.

. I

Responsibility5.1

5.0 ADMINISTRATIVE CONTROLS

5.1 Responsibilit //

5. 1. 1 r shall be responsible for overall unit operationan e in writing the succession to thisresffponsi iity during his absence.

T or his designee shall approve, prior toiupil on,-each proposed test, experiment, or modification tosystems or equipment that affect nuclear safety.

5.1.2 The Shift Supervisor shall be responsible for the, control roomcommand function. During any absence of the Shift Supervisor fromthe control room while the unit is in MODE 1, 2, or 3, anindividual with an active Senior Reactor Operator (SRO) licenseshall be designated to assume the control room command function.During any absence of the Shift Supervisor from the control roomwhile the unit is in MODE 4 or 5, an individual with an active SROlicense or Reactor Operator license shall be designated to assumethe control room command function.


Organization5.2


5.2 Organization

5.2.1 Onsite and Offsite Organizations

Onsite and offsite organizations shall be established for unitoperation and corporate management, respectively. The onsite andoffsite organizations shall include the positions for activitiesaffecting safety of the nuclear power plant.

Lines of authority, responsibility, and communication shallbe defined and established throughout highest managementlevels, intermediate levels, and all operating organization

41- l.positions. These relationships shall be documented and4-ce * s updated, as appropriate, in organization charts, functional

\ef oS, He descriptions of departmental responsibilities and,aSoI~' 11|,.\An ,œk I 5 relationships, and job descriptions for key personnel

'Or's % c _positinnas. or in equivalent forms of documentation. Thesef ^X^5 Vgber' > - requirementshall be documented in the UFSAR;

v5 tt ,^v I af¢shall be responsible for overall safe

operation of the plant and shall have control over thoseonsite activities necessary for safe operation and

-. maintenance of the plant;

) . shallhave corpor respon ili y or overa p nuclearsafety and shall take any measures needed.to ensure

Tpec Re +acceptable performance of the staff in operating,)maintaining, and providing technical support to the plant to

ensure nuclear safety; and

d. The individuals who train the operating staff, carry outhealth physics, or perform quality assurance functions mayreport to the appropriate onsite manager; however, theseindividuals shall have sufficient organizational freedom toensure their independence from operating pressures.

5.2.2 Unit Staff

The unit staff organization shall also include the following:

(continued)


Organization5.2

) 5.2 Organization

5.2.2 Unit Staff (continued)' '/

The controls shall include guidel es or working hours thatensure adequate shift coverage s all be aintained withoutroutine heavy use of overtime.

Any deviation from the abov uidelines all be authorizedin advance by th or the asdesignee, in accor ance wit approved administrativeprocedures, and with documentation of the basis for grantingthe deviation. Routine deviation from the working hourguidelines shall not be authorized.

Controls shall be included in the procedures to require aperiodic independent review be conducted to ensure thatexcessive hours have not been assigned.

e nir Mnger- peratio shallhold a Icn

f. An individual shall provide advisory technical support to the.. unit operations shift crew in the areas of thermal

hydraulics, reactor engineering, and plant analysis with- Jregard to the safe operation of the unit. This individual

shall meet the qualifications specified by the CommissionPolicy Statement on Engineering Expertise on Shift.

I~I . . .


Programs and Manuals5.5


5.5 Programs and Manuals

The following programs shall be established, implemented, and maintained.

5.5.1 Offsite Dose Calculation Manual (ODCM)

a.. The ODCM shall contain the methodology and parameters usedin the calculation of offsite doses resulting fromradioactive gaseous and liquid effluents, in the calculationof gaseous and liquid effluent monitoring alarm and tripsetpoints, and in the conduct of the radiologicalenvironmental monitoring program; and

b. The ODCN shall also contain the radioactive effluentcontrols and radiological environmental monitoringactivities, and descriptions of the information that shouldbe included in the Annual Radiological EnvironmentalOperating, and Radioactive Effluent Release reports requiredby Specification 5.6.2 and Specification 5.6.3.

c. Licensee initiated changes to the ODCM:

1. Shall be documented and records of reviews performed) shall be retained. This documentation shall contain:

Sufficient information to support the change(s)together with the appropriate analyses or evaluationsjustifying the change(s), and

A determination that the change(s) maintain the levelsof radioactive effluent control required by10 CFR 20.1302, 40 CFR 190, 10 CFR 50.36a, and10 CFR 50, Appendix I, and not adversely impact theaccuracy or reliability of effluent, dose, or setpointcalculations;

2. Shall become effective after review and acceptance bythe Pla t 0 erations Review Committee and the approvalof th and

(continued)




5.5.1 Offsite Dose Calculation Manual (ODCM) (continued)

3. Shall be submitted to the NRC in the form of acomplete, legible copy of the entire ODCM as a part ofor concurrent with the Radioactive Effluent ReleaseReport for the period of the report in which any changein the ODCM was made. Each change shall be identifiedby markings in the margin of the affected pages,clearly indicating the area of the page that waschanged, and shall indicate the date (i.e., month andyear) the change was implemented.

5.5.2 Primary Coolant Sources Outside Containment

This program provides controls to minimize leakage from thoseportions of systems outside containment that could contain highlyradioactive fluids during a serious transient or accident tolevels as low as practicable. The systems include Core Spray,High Pressure Coolant Injection, Residual Heat Removal, ReactorCore Isolation Cooling, and Reactor Water Cleanup. The programshall include.the following:

a. Preventive maintenance and periodic visual inspectionrequirements; and

b. System leak test requirements for each system, to the extent_permitted by system design and radiolog ; Jw,* _

5.5.3, DELET|

(continued)

)


iPrograms and Manuals

5.5

5.5 Programs and Manuals (continued)

5.5.6 Inservice Testina Proaram

This program provides controls for inservice testie of ASME CodeClass 1, 2, and 3 co...et Is Theprogram shall include the fo

a. Testing frequencies specified in Section XI of the ASMEBoiler and Pressure Vessel Code and applicable Addenda areas follows:

ASME Boiler and PressureVessel Code andapplicable Addendaterminology for.inservice testingactivities

Required Frequenciesfor performing inservicetesting activities

WeeklyMonthlyQuarterly or every3 months

Semiannually orevery 6 months

Every 9 monthsYearly or annuallyBiennially or every2 years

At least once per 7 daysAt least once per 3.1 days

At least once per 92 days

AtAtAt

leastleastleast

onceonceonce

per 184 daysper 276 daysper 366 days

At least once per 732 days

b. The provisions of SR 3.0.2 are applicable tofor performing inservice testing activities;

c. The provisions of SR 3.0.3 are applicable totesting activities; and

the Frequencies

inservice

d. Nothing in the ASME Boiler and Pressure Vessel Code shall beconstrued to supersede the requirements of any TS.

5.5.7 Ventilation Filter Testing Program (VFTP)

The VFTP shall establish the required testing of Engineered SafetyFeature (ESF) filter ventilation systems.

Tests described in Specifications 5.5.7.a, 5.5.7.b, and 5.5.7.cshall be performed:

(continued)

)


-------- --.. --

0


! 5.5 Programs and Manuals

5.5.9 Diesel Fuel Oil Testing Program (continued)

a. Acceptability of new fuel oil for use prior to addition tostorage tanks by determining that the fuel oil has:

1. an API gravity or an absolute specific gravity withinlimits,

2. kinematic viscosity, when required, and. a flash pointwithin limits for ASTM 2-D fuel oil, and

3. a clear and bright appearance with proper color or awater and sediment content within limits;

and

Total particulate concentration of the fuel oil mg/lwhen tested-every 31 days in accordance with ASTM 02276,Method A, except.that the filters specified in the ASTMmethod may have a nominal pore size of up to three (3)microns.

5-105.5.10 eis

_. .'

-hniral SnPrifiratfinns (T,) Raspe rCntrnl Prnnram

This program provides a means for processing changes to the Basesof these Technical Specifications.

a. Changes to the Bases of the TS shall be made underappropriate administrative controls and reviews.

b. Licensees may make changes to Bases without prior NRCapproval provided the changes do not involve either of thefollowing:

A change in the TS incorporated in the license; or

A change to the UFSAR or Bases that requires NRC approvalpursuant to 10 CFR 50.59.

c. The Bases Control Program shall contain provisions to ensurethat the Bases are maintained consistent with the UFSAR.

3,e-an S) S ,ZO' St 3,0.1 4- `spewi Cc6 4

( '7 Tt'1 p:'y-e - L t' =

I

PBAPS UNIT 2 5.0 -15 Amendment No. 2410, 242

Reporting Requirements5.6


5.6 Reporting Requirements

The following reports shall be submitted in accordance with 10 CFR 50.4.

5.6.1 Occupational Radiation Exposure Reoort

…----------- -------NOTE…----A single submittal may be made for a multiple unit station. Thesubmittal.should combine sections common to all units at thestation.

,5.ta u aiojn an annualsbasis of the number of station, itilty,-A-* nd otheJEsne (7jtinuding con rqors) reredig an annua

deep.dos equivalent 100 mrem and e assocaI collective deepdose ivalent (reorted in.per -rem) acc ing to work and jobfun ons (e.g% eactor oper ons and s illance, i rvice0i ection,r tine m'ainte ce, specia aintenance iscribeintenanc , waste procing, and r ueling). T tabulation

supplemets the requir ents of 10 R 20.2206. e doseassign nts to varin duty func ons may be imated ba onpocke dosimeter, ermolumin ence dosier (LD), oT ilmbadge measureme s. Small osures tos ling < 20% the

) individual to dose nee ot be ac nted for. theaggregate, ayleast 80%,V te tot>F dee dose Abvalent receivesfrom extera sources shudbe ' igned to sp cific major workfunctions. The report shall be submitted by March 31 of each

5.6.2 Annual Radiological Environmental Operating Report

…_______ _ -…----- …NOTE …------ ----------------…

A single submittal may be made for a multiple unit station. Thesubmittal should combine sections common to all units at thestation.

…- ------- ------ ------ --- -…-- -- -

The Annual Rauiological Environmental Operating Report coveringthe operation of the unit during the previous calendar year shallbe submitted by May 31 of each year. The report shall includesummaries, interpretations, and analyses of trends of the resultsof the radiological environmental monitoring activities for thereporting period. The material provided shall be consistent withthe objectives outlined in the Offsite Dose Calculation Manual(ODCM), and in 10 CFR 50, Appendix 1, Sections IV.B.2, IV.B.3,and IV.C.

(continued)

PBAPS UNIT 2 AS.0-19 Amendment No. -hozil'i

.4

7'.TF-/s-

A tabulation on an annual basis ofthe number of station, utilityoandhotherrpersonnel(including contractors), for.whom monitoring was performed, receving an annual deepdose equivalent> 100 mrems and the associated collective deep dose equivalent (reportedin person - rem) according to work and job functions (e.g. reactor operations andsurvllansce inservice, inspection, routine maintenance special maintenance [describe

maintenanc], waste processgi and refuelhing).This tabulation supplements therequirements .of 0 CF 20.2206. The dose assignments to various duty functions may bee~ii ba d on pockcet ioniation chamber, thermoluminescence dosimeter (Th)),electronic dosneter,, or film badge measurements. Small exposures totaling < 20 percent

j iof the iudviual total dose ned not be accounted for. In 'the aggregateX at least 80perceint of. the total deep dose equivalent received from external sources should beassig~edtio specific maor workc functions. The report covering the previous calendar yearshallbe'submittedbyApril30of eachyear. [_th.n.d )e L. it...1

::, .. . f . , I L .. b t . ' _,_1 ;. J

i . ;

., I

il

.


! 5.6 Reporting Requirements

5.6.2 Annual Radioloaical Environmental Operating Report (continued)

The Annual Radiological Environmental Operating Report shallinclude the results of-analyses of all radiological environmentalsamples and of all environmental radiation measurements takenduring-the period pursuant to the locations specified in the tableand figures in the ODCH, as well as summarized and tabulatedresults of these analyses and measurements in the format of thetable in the Radiological Assessment Branch Technical Position,Revision 1, November 1979. In the event.that some individualresults are not available for inclusion with the report, thereport shall be submitted noting and explaining the reasons forthe missing results. The missing data shall be submitted in asupplementary report as soon as possible.

Radioactive Effluent Release Report

I

5.6.3

')

5.6.4

-----------------------------NOTE------------------------------A single submittal may be made for a multiple unit station. Thesubmittal combine sections common to all units at thestation. Cs'___ _____ ______ __ ___ ______ ______ ____ ______ ______ _____ _____ _____

The Radibactive Effluent.Release Report covering the operation ofthe unit-during the previous year shall be submitted prior toMay 1 of each year in accordance with 10 CFR 50.36a. The reportshall include a summary of the quantities of radioactive liquidand gaseous effluents and solid waste released from the unit. Thematerial provided shall be consistent with the objectives outlinedin the ODCM and Process Control Program and in.conformance'with10 CFR 50.36a and 10 CFR*50, Appendix I, Section IV.B.1.

Monthly Operating Reports

Routine reports of operating statistics and shutdown experienceshall be submitted on a monthly basis no later than the 15th of

' each month following the calendar month covered by the report.

(continued)

PBAPS UNIT 2 5.0-20 Amendment No. - 14|-

;

Reactor Core SLsB 2.1.1

) BASES (continued)

SAFETY LIMITS The reactor core SLs are established to protect theintegrity of the fuel clad barrier to the release ofradioactive materials to the environs. SL 2.1.1.1 andSL 2.1.1.2 ensure that the core operates within the fueldesign criteria. SL .2.1.1.3 ensures that the reactor vesselwater level is greater than the top of the active irradiatedfuel in order to prevent elevated clad temperatures andresultant clad perforations.

APPLICABILITY SLs 2.1.1.1, 2.1.1.2, and 2.1.1.3 are applicable in allMODES.

* SAFETY LIMITVIOLATIONS

Exceeding-an SL may cause fuel damage and create a potentialfor radioactive releases ine e'ess of 10 CFR 100, 'ReactorSite Criteria,' limits (Ref. '. Therefore, it is requiredto insert all insertable control rods and restore compliancewith the SLs within 2 hours. The 2 hour Completion Timeensures that the operators take prompt remedial action andalso ensures that the probability of an accident occurringduring this period is minimal.

(If any SL is v ed, the seni o nt of the nuclearplant and the utilif9ss bn~tfed within 24 hours.The 24 hour period ;s"xltaefr plant operators andstaff to take appropriate imme *ac ion and assessthe con of the unit before reportin to the senior

agement. __._, _ ,, -I,

i

PBAPS UNIT 2 B 2.0-5 Revision No. 0


BASES

LAfiFETY LIMIT .2.I VOTIONS(con ed) If any SL is violated, a Licensee Evenl port shall be. ~ ^ss^_ prepared and submitted within 30 s~Awf1o the NRC -in< ~ ^^syacordance with 10 CFR 5:0.73_5~F 7).. A copy of the report

>~ sdU^1o be providedt 't FrSsenior management of thenuclear- ility.

If y S is violated, restart of the un 1 otninence until authorized by the NRC. This req ement

ensures the NRC that all necessary reviews, analyses, andactions are completed before the unit begins its restart to

a eration.

REFERENCES 1. GE Nuclear Energy 23A7188, Revision 1, September 1992.

2. ABB Atom Report BR 90-004, October 1990.

3. ANF-90-133 (P), Revision 2, August 1992.

4. NEDE-24011-P-A-10, February 1991.

~ 10 CFR 100.


RCS Pressure SLB 2.1.2

BASES

APPLICABLESAFETY ANALYSES

(continued)

The RCS pressure SL has been selected such that it is at apressure below which it can be shown that the integrity ofthe system is not endangered. The reactor pressure vesselis designed to Section III, 1965 Edition of the ASME, Boilerand Pressure Vessel Code, including Addenda through thewinter of 1965 (Ref. 5), which permits a maximum pressuretransient of 110%, 1375 psig,'of design pressure 1250 psig.The SL of 1325 psig, as measured in the reactor steam dome,is-equivalent to 1375 psig at the lowest elevation of theRCS.- -The RCS is.designed to the ASME Section III, 1980Edition, including Addenda through winter of 1981 (Ref. 6),for the reactor recirculation piping, which permits amaximum pressure transient of 110% of design pressures of1250 psig for suction piping and 1500 psig for dischargepiping. The. RCS pressure SL is selected to be the lowest'transient overpressure allowed by the applicable codes.

SAFETY LIMITS

9

The maximum transient pressure allowable in the RCS pressurevessel under the ASME Code, Section III, is 110% of designpressure. The maximum transient pressure allowable in theRCS piping, valves, and fittings is 110% of design pressuresof 1250 psig for suction piping and 1500 psig for dischargepiping. The most limiting of these allowances is the 110%of design pressures of 1250 psig; therefore, the SL onmaximum allowable RCS pressure is established at 1325 psig,as measured at the reactor steam dome.

iAPPLICABILITY SL 2.1.2 applies in all MODES.

PRAPS UNIT 2 .H 2.0-8 Revision No. 0


BASES

SAFETY LIMITVIOLATIONS

(continued) Exceeding the RCS pressure SL may cause immediate RCSfailure and create a potential for radioactive releases inexcess of 10 CFR 100, tReactor Site Criteria,* limits(Ref. 4). Therefore, it is required to insert allinsertable control rods and restore compliance with the. SLwithin-2 hours. The.2 hour Completion Time ensures that theoperators take prompt remedial action and also assures thatthe probability of an accident occurring during the periodis minimal.

L

. .3

ji If < SL is violated, the senior management of the nuclearplant nd the utility, shall be notified within hours.The 2 lor period provides time for plant otrtors andstaff to ke the appropriate immediate a on and assessthe conditi of the unit before repo g to the seniormanagement.

/ ~~2.2.4\/

If any SL is violated, icensee Event Report shall beprepared and submitt wit 30 days to the NRC inaccordance with 1 FR 50.73 ef. 8). A copy of the reportshall also be vided to the ior management of the

/ nuclear plan- nd the uility. \

Lany S is violated, restart of the unit all notcommence until authorized by the NRC. This r irementensures the NRC that all necessary reviews, ana es, andactions are completed before the unit begins its r tart

REFERENCES 1. UFSAR, Section 1.5.2.2.

2. ASME, Boiler and Pressure Vessel Code, Section III,Article NB-7000.

(continuedl

II

*1



) BASES

REFERENCES(continued)

3. ASME, Boiler and Pressure Vessel Code, Section XI,Article IW-5000.

4. 10 CFR 100.

5. ASME, Boiler and Pressure Vessel Code, Section III,1965 Edition, including Addenda to-winter of 1965.

6.' ASME, Boiler and Pressure Vessel Code, Section III,1980 Edition, Addenda to winter of 1981. - --

3crR- -0..

A . .F se. . w

)


Control Rod Scram TimesB 3.1.4

) BASES (continued)

SURVEILLANCE The four SRs of this LCO are modified by a Note stating thatREQUIREMENTS during a single control rod scram time surveillance, the CRD

pumps shall be isolated from the associated scramaccumulator. With the CRD pump isolated, (i.e.; chargingvalve closed) the influence of the CRD pump head does notaffect the single control rod scram times. During a fullcore scram, the CRD pump head would be seen by all controlrods and would have a negligible effect on the scraminsertion times.

SR 3.1.4.1

The scram reactivity used in DBA and transient analyses isbased on an assumed control rod scram time. Measurement ofthe scram times with reactor steam dome pressure 2 800 psigdemonstrates acceptable scram times for the transientsanalyzed in References 3 and 4.

Maximum scram insertion times occur at a reactor steam domepressure of approximately'800 psig because of the competingeffects of reactor steam dome pressure and storedaccumulator energy. Therefore, demonstration of adequate

) scram times at reactor steam dome pressure .800 psigensures that the measured scram times will be within thespecified limits at higher pressures. Limits are specifiedas a function of reactor pressure to account for the

\ sensitivity of the scram insertion times with pressure andto allow a range of pressures over which scram time testingcan be performed. To. ensure that-scram time j eing is

days-or longer, all control ro s required to betested before exceeding 40% RTP. This Frequency isacceptable-considering the additional surveillancesperformed for control rod OPERABILITY, the frequentverification of adequate accumulator pressure, and therequired testing of control rods affected by- ork on controlrods or the CRD System.

SR 3.1.4.2

Additional testing of a sample of control rods is requiredto verify the continued performance of the scram functionduring the cycle. A representative sample contains at least10% of the control rods.' The sample remains representative

(continued)


.


BASES

SURVEILLANCE SR '3.1.4.3 (continued)REQUIREMENTS

Specific examples of work that could affect the scram timesare (but are not limited to) the following: removal of anyCRD for maintenance or modification; replacement of acontrol rod; and maintenance or modification of a scramsolenoid pilot valve, scram valve, accumulator, isolationvalve or check valve in the piping required for scram.

The Frequency of once prior to declaring-the affectedcontrol rod OPERABLE is acceptable because of the capabilityto test'the control rod over a range of operating conditionsand the more frequent surveillances on other aspects ofcontrol rod OPERABILITY.

SR 3.1.4.4

When work that could affect the scram insertion time isperformed on a control rod or CRD System, or when fuelmovement within the reactor vessel occurs testing must bedone to demonstrate each affected control rod is stillwithin the limits of Table 3.1.4-1 with the reactor steamdome pressure k 800 psig. Where work has been performed athigh reactor pressure, the requirements of SR 3.1.4.3 andSR 3.1.4.4 can be satisfied with one test. For a controlrod affected by work performed while shut down, however, azero pressure and.high pressure test may be required. Thistesting ensures that, prior to withdrawing the control rodfor continued operation, the control rod scram performance

, > ov . is acceptable for operating reactor pressure conditions.1t2 te5SJ tAlternatively, a control rod scram test during hydrostatic

pr-essure testing could also atisfy both criteria. Whenj4?33Dfuel movementftccurs, efto only those control rods'associated with the' core cells affected-by thents

arerewred jo IS cram- imete -S OGtrrCir

d t t°J 1 tI "b cT4et dThe F requency of nepir nacceptable because of the capability to test the control rodover a range of operating conditions and.the more frequentsurveillances on other aspects of control rod OPERABILITY;

REFERENCES 1. UFSAR, Sections 1.5.1.3 and 1.5.2.2.

2. UFSAR, Section 14.6.2.

(continued)

PHAPS UN17 2 R 3.1-27 Revision No. 9

SDV Vent and Drain ValvesB 3.1.8

a BASES

APPLICABLE instrument volume exceeds a specified setpoint. TheSAFETY ANALYSES setpoint is chosen so that all control rods are inserted.

(continued) before the SDV has insufficient volume to accept a fullscram.

SDY vent and drain valves satisfy Criterion 3 of the NRCPolicy Statement.

LCO The OPERABILITY of all SDV vent and drain valves ensuresthat the SDY vent and drain valves will close during a scramto contain'reactor water discharged to the SDV piping.Since the vent and drain lines are provided with two valvesin series, the single failure of one valve in the openposition will not impair the isolation function of thesystem. Additionally, the valves are required to be *openedfollowing scram reset to ensure that a path is available forthe SDV piping to drain freely at other times.

APPLICABILITY In HODES 1 and 2, scram may be required; therefore, the SDVvent and drain valves must be OPERABLE. In MODES 3 and 4,control rods are not able to be withdrawn since the reactormode switch is in shutdown and a control rod block isapplied. This provides adequate controls to ensure thatonly a single control rod can be withdrawn. Also, duringMODE 5, only a single control rod can be withdrawn from acore cell containing fuel assemblies. Therefore, the SDVvent and drain valves are not required to be OPERABLE inthese MODES since the reactor is subcritical and only onerod may be withdrawn and subject to scram.

ACTIONS

nevxt PAOL

The ACTIONS Table is modified by ,Note5indlcating that aseparate Condition entry is allowed for each SDV vent anddrain line. This is acceptable, since the Required Actionsfor each Condition provide appropriate compensatory actionsfor each inoperable SOY line. Complying with the RequiredActions may allow for continued operation, and subsequentinoperable SDY lines are governed by subsequent Conditionentry and application of associated Required Actions.

(continued)


SDV Vent and Drain Val vesB 3.1.8

BASES

ACTIONS A.1(continued)

When-one SDV vent or drain valve is ino perab n one orM~OGR4 M X mre tInestetlea~b reI 0"aOh6RBES~3f rn jt abe mpletion Taime Is reasoa ei given the

f to contain' -be an o e rin the lines and the low probability ofscram occurring during the time the valves are inoperabl

refbtor 'covCoD> The SDV.is still isolable since the redundant valve in thed4Urn - & affected line is OPERABLE. During these periods, the single

failure criterion may not be-preserved, and a higher risk7 AJ 4IA exists to allow reactor water out of the primary system

during a scram.

If both valves in a line are inoperable, the line must be_isaatied to contain the reactor coolant during a scram.

nowi t When line to bedraied, toe prenludet a c r ntt vioL6 scram due to high hSDV level isaanble se t i strative

* zaen ,ctrols esur the valve can be a- cle quickly, bya

decra and venting o f tha s oc wphnen occur w it v alv oThe_ 8 hour CmpletionTie t oisneolay te unisolate ibaerd o

thein lo es probbiityof ca ocrigshl h linei

I administrative control. This allows any accumulated watermein the line to be drained, to preclude a reactor scram on\SDV hnth levly. This is acceptable since the administrativecontrols ensure the valve can be closedhquickly, by alwas__ dedcate oprato,.i a sramoccurs with the valve opn /

The 8 hour Completion Time to isolate the line is based onthe low probability of a scram occurrong while the line isnot isolated and ounikelmhood of significant CRD seallgleakage..

C .

If any Required Action and associated Completion Time is notpet,-the plant must be brought to a .ODE in which the LCO-

(does not apply. To achieve this status, the plant iust bebrought to at least MODE 3 within 12 hours. The allowedCompletion Time of 12 hours is reasonable, based onoperating experience, to reach NODE 3 from full powerconditions in an orderly manner and without challengingplant systems.

(continued)


MCPRB 3.2.2

BASES

SURVEILLANCEREQUIREMENTS

SR 3.2.2.1 (continued)

in the COLR to ensure that the reactor is operating withinthe assumptions of the safety analysis. The 24 hourFrequency is based on both engineering judgment andrecognition of the slowness of changes in power distributionduring normal operation. The 12 hour allowance afterTHERMAL POWER 2 25% RTP is achieved is acceptable given thelarge inherent margin to operating limits at low powerlevels.

I

SR 3.2.2.2

Because the transient analysis takes credit for conservatismin the scram speed performance, it must be demonstrated thatthe specific scram speed distribution is consistent withthat used in the transient analysis. SR 3.2.2.2 determinesthe value of 7, which is a measure of the actual scram speeddistribution compared with the assumed distribution. TheMCPR operating limit is then determined based on aninterpolation between the applicable limits for Option Ay (scram times of LCO 3.1.4,*Control Rod Scram Times") andOption B (realistic scram times) analyses. The parameter Trmust be determined once within 72 hours after each setscram time tests required by SR 3.1.4.14aX SR 3.1.4.2because the effective scram speed distribution may changeCariiizLt cyc The 72 hour Completion Time is acceptabledue to the relatively minor changes in T expected during thefuel cycle.

REFERENCES 1. NUREG-0562, June 1979.

2. NEDO-24011-P-A-10, 'General Electric StandardApplication for Reactor Fuel," February 1991.

3. UFSAR, Chapter 3.


S. UFSAR, Chapter 14.

6. NEDO-24229-1, "Peach Bottom Atomic Power Station Units2 and 3, Single Loop Operation," May 1980.

(continued)

PBAPS UNIT 2 8 3.2-9 Revision No. 0

Feedwater and Main Turbine High Water Level Trip InstrumentationB 3.3.2.2

*I

) BASES

ACTIONS B.1 (continued)

signal on a valid signal. This requires one channel pertrip-system to be OPERABLE or in trip. If the requiredchannels cannot be restored to OPERABLE status or placed intrip, Condition C must be entered and its Required Actiontaken.

, I X" The 2 hour Completion Time is sufficient for the operator tooC is take corrective action, and takes into account thePi et oe Srct likelihood of an event requiring actuation of feedwater and

main turbine high water level trip instrumentation occurringk 44- sL Xduring this period. It is also consistent with the 2 hour

%>, o 'A le t4 +k Completion Time provided in LCO 3.2.2 for RequiredS 4T41&e Action A.1, since this instrumentation's purpose is

Opvet r~~~eclude a HCPR violat'1 e&q~e

0 ff VAC K j"O,.

k 4-f-C With any Requi d Acti notuA AA9 met, the via must be brought to a MODE or other specified

lee, "~' cbndition i/which the LCO does not apply. To achieve thisstatus, THERMAL POWER must be reduced to < 25% RTP within4 hours. eAs discussed in the Applicability section of theBases, operation below 25% RTP results in sufficient marginto the required limits, and the feedwater and main turbinehigh water level trip instrumentation is not required toprotect fuel integrity during the feedwater controllerfailure, maximum demand event. The allowed Completion Timeof 4 hours is based on operating experience to reduceTHERMAL POWER to <'25% RTP from full power conditions in anorderly manner and without challenging plant systems.


The Surveillances are modified by a Note to indicate thatwhen a channel is placed in an inoperable status solely forperformance of required Surveillances, entry into associatedConditions'.and Required Actions may be delayed .for up to6 hours provided'the associated Function maintains feedwaterand 'main turbine high water level trip capability. Uponcompletion of the Surveillance, or expiration of the 6 hourallowance, the channel must be returned to OPERABLE statusor the applicable Condition entered and Required Actionstaken. This Note is based on the reliability analysis(Ref. 2) assumption of the average time required to perform

(continued)


PAM InstrumentationB 3.3.3.1

BASES

LCO 7. Drywell' High Range Radiation(continued)

Instruments: RR-8103 A, B

Drywell high range radiation is a Category.I variableprovided to monitor the potential of significant radiationreleases and .to provide release assessment for.use byoperators in determining the need to invoke-site emergencyplans. Post accident drywell radiation levels are monitoredby four instrument channels each with a ran'ge of 1 to1xlOHR/hr. These radiation monitors drive two dual channelrecorders located in the control room.. Each recorder andthe two associated channels are in a separate-division.. Assuch, two recorders and two channels of radiation-monitoringinstrumentation (one per recorder) are required to beOPERABLE for compliance with this LCO. Therefore, the PAMSpecification deals specifically with these portions of theinstrument channels.

8. Primary Containment Isolation Valve (PCIV) Position

PCIV position is a Category I variable provided forverification of containment integrity. In the case of PCIVposition, the important information is the isolation statusof the containment penetration.. The LCO requires onechannel of valve position indication in the control room tobe OPERABLE for.each active PCIV in a containment.penetration flow path, i.e., two total channels of PCIVposition indication for a penetration flow path with twoactive valves. For containment penetrations with only oneactive PCIV having control room indication, Note (b)requires a single channel of valve position indication to beOPERABLE. This is sufficient to redundantly verify theisolation status of each isolable penetration via indicatedstatus of the active valve, as applicable, and priorknowledge of passive valve or system boundary.status. If apenetration flow path is isolated, position indication forthe PCIV(s).in the associated penetration flow path is notneeded to determine status. Therefore, the positionindication for valves in an isolated penetration flow pathis not required to be OPERABLE. The PCIV position PAMinstrumentation consists of position switches,.associatedwiring and control room indicating lamps for active'PCIVs(check valves and manual valves are not required to haveposition indication). Therefore, the PAM Specificationdeals specifically with these instrument channels.

ATWS-RPT InstrumentationB 3.3.4.1

BASES

ACTIONS Di1 and D.2 (continued)

6 hours is reasonable, based on operating experience, bothto reach MODE 2 from full power conditions and to remove arecirculation pump from service in an orderly manner andwithout challenging plant systems. F

SURVEILLANCE The Surveillances are -modified by a Note to indicate thatREQUIREMENTS when a channel-is placed in an inoperable statu's solely for

performance of required Surveillances, entry into theassociated Conditions and Required Actions may be delayedfor up to 6 hours provided the associated Function maintains.

uIwg i <ATWS-RPT trip capability. Upon completion of thej bta w ) ) Surveillance, or expiration of the 6 hour allowance, the

1eJ .f~ I~@ ^ channel must be returned to OPERABLE status or theX,~w ^l#c~ pplicable Condition entered and Required Actions taken.

OW5 o r t' his Note is based on the reliability analysis (Ref. 1)umption of :the average time required to perform channel

sA d z Sirveillance. That analysis demonstrated that the 6 hourIV sting allowance does not significantly reduce the

Icrf. Zobability that the recirculation pumps will trip whenr 4 vAf SAcessary.

Reps S40ASC14$

erformance of the CHANNEL CHECK once every 12 hours ensuresthat a gross failure of instrumentation has not occurred. ACHANNEL CHECK is normally a comparison of the parameterindicated on one channel to a-similar parameter on otherchannels. It is based on the assumption that instrumentchannels monitoring the same parameter should readapproximately the same value. Significant deviations.between the instrument channels could be an indication ofexcessive instrument drift in one of the channels orsomething even more serious. A CHANNEL CHECK will detectgross channel failure; thus, it is key to verifying theinstrumentation continues to operate properly between eachCHANNEL CALIBRATION.

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

(continued)

PBAPS UNIT 2 *B 3.3-89 Revision No. 0

EOC-RPT Instrumentation

)

EOC-RPT InstrumentationB 3.3.4.2

BASES

ACTIONS(continued)

With one or morecthannels inoperable, but with EOC-RPt tripcapability maintained (refer to Required Action B.1 Bases),the EOC-RPT System is capable of performing the intendedfunction. However, the reliability and redundancy of theEOC-RPT instrumentation is reduced such that a singlefailure in the remaining trip system could result in theinability of the EOC-RPT System to perform the intendedfunction. Therefore, only a limited time is allowed-torestore compliance with the LCO. Because of the diversityof sensors available to provide trip signals, the lowprobability of extensive numbers of inoperabilitiesaffecting all diverse Functions, and the low probability ofan event requiring the initiation of an EOC-RPT, 72 hours isprovided to restore the inoperable channels (RequiredAction A.1). Alternately, the inoperable channels may beplaced in trip (Required Action A.2) since this wouldconservatively compensate for the inoperability, restore

/ capability to accommodate a single failure, and allowf^.. ' operaLlon to continue. ~~iEotedplacing the channel in

trip with no further restrictions is not allowed if theinoperable channel is the result of an inoperable breaker,since this may not adequately compensate for the inoperablebreaker (e.g., the breaker may be inoperable such that itwill not open). If it is not desired to place the channelin trip (e.g., as in the case where placing the inoperablechannel in trip would result in an RPT, or if the inoperablechannel is the result of an inoperable breaker), Condition Cmust be entered and its Required Actions taken.

B.1

Required Action B.1 is intended to ensure that appropriateactions are taken if multiple, inoperable, untrippedchannels within the same Function result in the Function notmaintaining EOC-RPT trip capability. A Function isconsidered to be maintaining EOC-RPT trip capability whensufficient channels are OPERABLE or in trip, such that theEOC-RPT System will generate a trip signal from the givenFunction on a valid signal and both recirculation pumps canbe tripped. This requires two channels of the Function inthe same trip system, to each be OPERABLE or in trip, andthe associated EOC-RPT breakers to be OPERABLE.

(continued)

PBAPS UNIT 2 B 3.3-91f Revision No. 25


BASES

ACTIONS L.d (continued)

The 2 hour Completion Time is sufficient time for theoperator to take corrective action, and takes-into accountthe likelihood of an event requiring actuation of theEOC-RPT instrumentation during this period. It is alsoconsistent with the 2 hour Completion Time provided inLCO 3.2.1 and 3.2.2 for Required Action A.1, since thisinstrumentation's purpose is to preclude a thermal limit- -

violation.

C.1 and C.2

With any Required Action and associated Completion Time notmet, THERMAL POWER must be reduced to < 29.5X RTP within4 hours. Alternately, for an inoperable breaker (e.g., thebreaker may be inoperable such that it will not open) theassociated recirculation pump may be removed from service,since this performs the intended function of theinstrumentation. The allowed Completion Time of 4 hours isreasonable, based on operating experience, to reduce THERMALPOWER to < 29.5X RTP from full-power conditions in an

) orderly manner and without challenging plant systems.

SURVEILLANCE The Surveillances are modified by a Note to indicate thatREQUIREMENTS when a channel is placed in an inoperable status solely for

performance of required Surveillances, entry into associatedConditions and Required Actions may be delayed for up to6 hours provided the associated Function maintains EOC-RPTtrip capability. Upon completion of the Surveillance, orexpiration of the 6 hour allowance, the channel must bereturned to OPERABLE status or the applicable Conditionentered and Required Actions taken. This Note is based onthe reliability analysis (Ref. 5) assumption of the averagetime required to perform channel Surveillance. Thatanalysis demonstrated that the.6 hour testing allowance does

| not'significantly reduce the probability that thet recirculation pumps will trip when necessary.

a =4eWs 4; L* Irf) An&" UP Mb -g~ FX A0 pw 6Ve CakIte ;is Ate resold 0a AA at ;ir"Gle- gyps

b r-Clkee. TI- AMife ", hy4Rs 4te si4v-AoutS dour fAs e scneS VC1C1-e ,p'la Jdcfao world be tif 9y¢ri-qk

PBAPS UNIT 2 :5 3g1 Revision No. 43

ECCS InstrumentationB 3.3.5.1

) BASES

APPLICABLE with their setpoints within the specified AllowableSAFETY ANALYSES, Values, where appropriate. The actual setpoint isLCO, and calibrated consistent with a ljjpble setpoint methodologyAPPLICABILITY tion tnote (b)Zis added to(continued) inshow th strumentation Functions<if& also

''perf rm DG initiation.

fjo4ndfeS. RnOf c A lowable Values are specified for each ECCS Function- c -kq Secified in the Table.' Trip setpoints are specified in

im >) J lhe setpoint calculations.'The'trip setpoints are selected-1k -age A t vc{"'S 4to ensure that the settings do not exceed the Allowable

, ) -10 4 Value between CHANNEL CALIBRATIONS. Operation with a tripp twt YS A + setting less conservative than the trip setpoint, but withinOt&P.It;E "' its Allowable Value, is acceptable. A channel is inoperable

if its actual trip setpoint is not within its requiredO2 '$ oAllowable Value. Trip setpoints are those predetermined

o cLs AC alues of output at which an action should take place. The1 f, 6e dRL V F setpoints are compared to the actual process parameter

r~p-) LP rb Ve (e.g., reactor vessel water level), and when the measuredpeu L ,2 , rsJoutput value of the process parameter exceeds the setpoint,Per L_, the associated device (e.g., trip unit) changes state. The

t5 h kt(e~tV. n analytic or design limits are derived from the limitingvalues of the process parameters obtained from the safetyanalysis or other appropriate documents. The AllowableValues are derived from the analytic or design limits,corrected for calibration, process, and instrument errors.The trip setpoints are determined from analytical or designlimits, corrected for calibration, process, and instrumenterrors, as well as, instrument drift. In selected cases,the Allowable Values and trip setpoints are determined fromengineering judgement or historically accepted practicerelative to the intended functions of the channel. The tripsetpoints determined in this manner provide adequateprotection by assuming instrument and process uncertaintiesexpected for the environments during the operating time ofthe associated channels are accounted for. For the CoreSpray and LPCI Pump Start-Time Delay Relays, adequatemargins for applicable setpoint methodologies areincorporated into the Allowable Values and actual setpoints.

In general, the individual Functions are required to beOPERABLE in the MODES or other specified conditions that mayrequire ECCS (or DG) initiation to mitigate the consequencesof a design basis transient or accident. To ensure reliableECCS and DG function, a combination of Functions is requiredto provide primary and secondary initiation signals.

(continued)

PBAPS UNIT 2 B 3.3-99 Revision No. I


) BASES

APPLICABLE The specific Applicable Safety Analyses, LCO, andSAFETY ANALYSES, Applicability discussions are listed below on a Function byLCO, and Function basis.APPLICABILITY

(continued)*Core Spray and Low Pressure Coolant Iniection Systems

I.a. 2.a. Reactor Vessel Water Level-Low Low Low (Level 1)

Low reactor pressure vessel (RPV) water level indicates thatthe capability to cool the fuel may be threatened. ShouldRPV water level decrease too far, fuel damage could result.The low pressure ECCS and associated DGs are initiated atReactor Vessel Water Level-Low Low Low (Level 1) to ensurethat core spray and flooding functions are available toprevent or minimize fuel damage. The DGs are initiated fromFunction l.a signals. This Function, in conjunction with aReactor Pressure- Low (Injection Permissive) signal, alsoinitiates the closure of the Recirculation Discharge Valvesto ensure the LPCI subsystems inject into the proper RPVlocation. The Reactor Vessel Water Level-Low Low Low(Level 1) is one of the'Functions assumed to be OPERABLE andcapable of initiating the ECCS during the transients

) analyzed in References 1 and 3. In addition, the ReactorVessel Water Level-Low Low Low (Level 1) Function isdirectly assumed in the analysis of the recirculation linebreak (Ref. 4) and the control rod drop accident (CRDA)analysis. The core cooling function of the ECCS, along withthe scram action of the Reactor Protection System (RPS),ensures that the fuel peak cladding temperature remainsbelow the limits of 10 CFR 50.46.

Reactor Vessel Water Level-Low Low Low (Level 1) signalsare initiated from four level transmitters that sense the,difference between the pressure due to a constant column ofwater (reference leg) and the pressure due to the actualwater level (variable leg) in the vessel.

The Reactor Vessel Water Level-Low Low Low (Level 1)Allowable Value is chosen to allow time for the low pressurecore flooding systems to activate and provide adequatecooling.

Four channels of Reactor Vessel Water Level-Low Low Low(Level Function are only required to be OPERABLE when theECCS are required to be OPERABLE to ensure that nosingle instrument failure can preclude ECCS fieti

(continued)


5_ frv ej eJ) 4v te opEl E ECCumentation( CJ f J 41 % W 5 In at44^X 3.3.5.-1.-

4- ovLeo 3~,a)BASES

APPLICABLE 1.a. 2.a. Relctor Vessel Water Level -Low Low Low -(Level 1)SAFETY ANALYSES, (continued)/LCO,'and/APPLICABILITY initiation. Refer to LCO 3.5.1 and LCO 3.5.2, "ECCS-

Shutdown," for Applicability Bases for the low pressure ECCSsubsystems; LCO 3.8.1, "AC Sources-Operating'; andLCO 3.8.2, "AC Sources-Shutdown," for Applicability Basesfor the DGs.

*.b. 2.b. Drvwell Pressure-Highb

High pressure in the drywell could indicate a break in thereactor coolant pressure boundary (RCPB). The low pressureECCS and associated DGs are initiated upon receipt-of theDrywell Pressure-High Function with a Reactor-Pressure-Low(Injection Permissive) in.order to minimize the'possibilityof fuel damage. The DGs are initiated from: Function 1.bsignals. This Function also initiates the closure of therecirculation discharge valves to ensure the LPCI subsystemsinject into the proper RPV location. The DrywellPressure-High Function with a Reactor Pressure-Low(Injection Permissive), along with the Reactor WaterLevel-Low Low Low (Level 1) Function, is directly assumed

) in the analysis of the recirculation line break (Ref. 4).The core cooling function of the ECCS, along with the scramaction of the RPS, ensures that the fuel peak claddingtemperature remains below the limits of 10 CFR 50.46.

High drywell pressure signals are initiated from fourpressure transmitters that sense drywell pressure. TheAllowable Value was selected to be as low as possible and beindicative of a LOCA inside primary containment.

The Drywell Pressure-High Function is required to beOPERABLE when'the ECCS or DG is required to be OPERABLE inconjunction with times when the primary containment isrequired to be.OPERABLE.. Thus, four channels of the CS andLPCI Drywell Pressure-High Function are required to beOPERABLE in MODES 1, 2, and 3 to ensure that no singleinstrument failure can preclude ECCS and DG initiation. InMODES 4 and 5, the Drywell Pressure-High Function is notrequired, since there is insufficient energy in the reactorto pressurize the primary containment to Drywell Pressure-High setpoint. Refer to LCO 3.5.1 for Applicability Basesfor the low pressure ECCS subsystems and to LCO 3.8.1 forApplicability Bases for the DGs.

(continued)



BASES

APPLICABLESAFETY ANALYSES,LCO, 'andAPPLICABILITY

(continued)

I.c. 2.c. Reactor Pressure-Low (Injection Permissive)

Low reactor pressure signals are used as permissives for thelow pressure ECCS subsystems. This ensures that, prior toopening the injection valves of the low pressure ECCSsubsystems or initiating the low pressure ECCS subsystems ona Drywell Pressure-High signal, the reactor pressure hasfallen to a value below these subsystems' maximum designpressure and a break inside the RCPB has occurredrespectively. This Function also provides permissive forthe closure of the recirculation discharge valves to ensurethe LPCI subsystems inject into the proper RPV location.The Reactor Pressure-Low is one of the Functions assumed tobe OPERABLE and capable of permitting initiation of the ECCSduring the transients analyzed in References 1 and 3. Inaddition, the Reactor Pressure-Low Function is directlyassumed in the analysis of the recirculation line break(Ref. 4). The core cooling function of the ECCS, along withthe scram action of the RPS, ensures that the fuel peakcladding temperature remains below the limits of10 CFR 50.46.

The Reactor Pressure-Low signals are initiated from fourpressure transmitters that sense the reactor dome pressure.

The Allowable Value is low enough to prevent overpressuringthe equipment in the low pressure ECCS, but high enough toensure that the ECCS injection prevents the fuel peakcladding temperature from exceeding the limits of10 CFR 50.46.

Four channels of Reactor Pressure-Low Function are onlyrequired to be OPERABLE when the ECCS is required to beOPERABLE to ensure that no single instrument failure canpreclude ECCS initiation. v;Refer to LCO 3.5.1 and LCO 3.5.2for Applicability Bases for)the low pressure ECCSsubsystems. _ '

i.d. 2.Q.- Core Spray and Low Pressure Coolant IniectionPump Discharge Flow-Low (BVyass)

The minimum flow instruments are provided to protect theassociated low pressure ECCS pump from overheating when thepump is operating and the associated injection valve is notfully open. The minimum flow line valve is opened when lowflow is sensed, and the valve is automatically closed whenthe flow rate is adequate to protect the pump. The LPCI and

I (continued)



BASES

APPLICABLESAFETY ANALYtLCO, andAPPLICABILIT

SESI.d. 2.o. Core SDrav and Low Pressure Coolant IniectionPumi Discharce Flow-Low (Byvassl (continued)

Y CS Pump Discharge Flow-Low Functions are assumed to beOPERABLE and capable of closing the minimum flow valves toensure that the low pressure ECCS flows assumed during thetransients and accidents analyzed in References 1, 2, and 3are met. The core cooling function of the ECCS, along withthe scram action of the RPS, ensures that the fuel peakcladding temperature remains below the limits of10 CFR 50.46.

One differential pressure switch per ECCS pump is used todetect the associated subsystems' flow rates. The logic isarranged such that each switch causes its associated minimumflow valve to open. The logic will close the minimum flowvalve once the closure setpoint is exceeded. The LPCIminimum flow valves are time delayed such that the valveswill not open for 10 seconds after the switches detect lowflow. The time delay is provided to limit reactor vesselinventory loss during the startup of the RHR shutdowncooling mode. The Pump Discharge Flow-Low Allowable Valuesare high enough to ensure that the pump flow rate issufficient to protect the pump, yet low enough to ensurethat the closure of the minimum flow valve is initiated toallow full flow into the core.

Each channel of Pump Discharge Flow-Low Function (four CSchannels and four LPCI channels) is only required to beOPERABLE when the associated ECCS is required to be OPERABLE

*v to ensure that no single instrument failure can preclude theaECCS function.1%Refer to LCO 3.5.1 and LCO 3.5.2 for

Applicability jases for the low pressure ECCS subsystems.

I.e. l.f. Core Spray Pura, Start-Time Delay Relay

The purpose of this time delay is to stagger the start ofthe CS pumps that are in each of Divisions I and II toprevent overloading the power source. This Function isnecessary when power is being supplied from the offsitesources or the standby power sources (DG). The CS PumpStart-Time Delay Relays are assumed to be OPERABLE in theaccident and transient analyses requiring ECCS initiation.That is, the analyses assume that the pumps will initiatewhen required and excess loading will not cause failure ofthe power sources.

_~ - .~l . . - .U I

I

PBAPS UJNIT 2 B 3.3-103 Revision No. 0


BASES

APPLICABLE I.e. 1.f. Core Spray Pumn Start -Time Delay RelaySAFETY ANALYSES, (continued)LCO, and

ABILITY There are eight Core Spray Pump Start-Time Delay Relays,two in each of the CS pump start logic circuits (one for

; }when offsite power is available and one for when offsitepower is not available). One of each type of time delay

3S 4 : relay. is dedicated to a single pump start logic, such that aPi single failure of a Core Spray Pump Start-Time Delay Relay

o will not result in the failure of more than one CS pump; In5 Qthis condition, three of the four CS pumps will remain

OPERABLE; thus, the single failure criterion is met (i.e.,.0 t loss of one instrument does not preclude ECCS initiation).

The Allowable Value for the Core Spray Pump Start-TimeDelay Relays is chosen to be long enough so that the powersource will not be overloaded and short enough so that ECCS

- ioperation is not degraded.

Each channel of Core Spray Pump Start-Time Delay RelayFunction is required to be OPERABLE only when the associatedCS subsystem is required to be OPERABLE. Refer to LCO 3.5.1and LCO 3.5.2 for Applicability Basesfo the CS subsystems.

2.d. Reactor Pressure-Low Low (Recirculation DischargeValve Permissive)

U L Low reactor pressure signals are used as permissives forrecirculation discharge valve closure. This ensures that

X~ M the LPCI subsystems inject into the proper RPV location. assumed in the safety analysis. The Reactor Pressure-Low

Low is one of the Functions assumed to be OPERABLE andcapable of closing the valve during the transients analyzedin References 1 and 3. The core cooling function of theECCS, along with the scram action of the RPS, ensures thatthe fuel peak cladding temperature remains below the limits

h ] Iof 10 CFR 50.46. The Reactor Pressure-Low Low Function is° S /directly assumed in the analysis of the recirculation line

Cm break (Ref. 4).

ot The Reactor Pressure-Low Low signals are initiated fromfour pressure transmitters that sense the reactor pressure.

The Allowable Value is chosen to ensure that the valvesclose prior to commencement of LPCI injection flow into thecore, as assumed in the safety analysis.

A (continued)

.I



) BASES

APPLICABLESAFETY ANALYSES,LCO, andAPPLICABILITY

I W

('.

.3

I. X10

.. ;C

C

( '...'

,.'' _

U ;I ,

'I

2.e. Reactor Vessel Shroud Level-Level 0 (continued)

Two channels of the Reactor Vessel Shroud Level -Level 0Function are only required to be OPERABLE in MODES 1, 2,and 3. In MODES 4 and 5, the specified initiation time ofthe LPCI subsystems is not assumed, and other administrativecontrols are adequate to control the valves associated withthis Function (since the systems that the valves are openedfor are not required to be OPERABLE in MODES 4 and 5 and arenormally not used).u

2.f. Low Pressure Coolant Iniection Pump Start-Time DelayRelay

The purpose of this time delay is to stagger the start ofthe LPCI pumps that are in each of Divisions I and II, toprevent overloading the power source. This Function is onlynecessary when power is being supplied from offsite sources.The LPCI pumps start simultaneously with no time delay assoon as the standby source is available. The LPCI PumpStart-Time Delay Relays are assumed to be OPERABLE in theaccident and transient analyses requiring ECCS initiation.That is, the analyses assume that the pumps will initiatewhen required and excess loading will not cause failure ofthe power sources.

There are eight LPCI Pump Start-Time Delay Relays, two ineach of the RHR pump start logic circuits. Two time delayrelays are dedicated to a single pump start logic. Bothtimers in the RHR pump start logic would have to fail toprevent an RHR pump from starting within the required time;therefore, the low pressure ECCS pumps will remain OPERABLE;thus, the single failure criterion is met (i.e., loss of oneinstrument does not preclude ECCS initiation). TheAllowable Values for the LPCI Pump Start-Time Delay Relaysare chosen to be long enough so that most of the startingtransient of the first pump is complete before starting thesecond pump on the same 4 kY emergency bus and short enoughso that ECCS operation is not degraded.

uW,lm

iW

) Each channel of LPCI Pump Start-Time Delay Relay Functionis required to be OPERABLE only when the associated LPCIsubsystem is required to be OPERABLE.4 Refer to LCO 3.5.1and LCO 3.5.2 for Applicability Bases for the LPCIsubsystems.

fcontinueoi-

!


Primary Containment Isolation InstrumentationB 3.3.6.1

BASES

* BACKGROUND 5. Reactor Water Cleanup System Isolation (continued)

* System Isolation Function receives input from-two channelswith each' channel in one trip system using a one-out-of-onelogic. When either SLC pump is started remotely, onechannel trips the inboard isolation valve and one channelisolates 'the outboard-isolation valves.

.The RWCU Isolation Function isolates the inboard andoutboard RWCU pump suction penetration and the outboardvalve'at the RWCU 'connection to reactor feedwater.

6. Shutdown Cooling System Isolation

The Reactor Vessel Water Level-Low (Level 3) Functionreceives'input from four reactor vessel water levelchannels. The outputs from the channels are connected to a.one-out-of-two taken twice logic, which isolates both 'valveson the RHR shutdown cooling pump suction penetration. TheReactor Pressure-High Function receives input from twochannels,-with each channel in one trip system using aone-out-of-one logic. Each'trip system is connected to bothvalves on the RHR shutdown cooling pump suction penetration.

' 7._ Feedwater Recirculation Isolation

'The Reactor Pressure-High Function receives inputs fromfour channels. The outputs from the four channels.are.connected into i one-out-of-two taken twice logic whichisolates the feedwater recirculation valves.

APPLICABLESAFETY ANALYSES,LCO, andAPPLICABILITY

The isolation signals generated by the primary containmentisolation instrumentation are implicitly assumed in thesafety analyses of References 1 and 3 to initiate closureof valves to limit offsite doses. Refer to LCO 3.6.1.3,'Primary Containment Isolation Valves (PCIVs)," Applicable-Safety.Analyses Bases for more detail of the safetyanalyses.

Primary containment isolation instrumentation satisfiesCriterion 3 of the NRC Policy Statement. Certaininstrumentation Functions are retained for other reasons andare described below in the individual Functions discussion.

* t I n I v .,Ouch I


-. 0.

The Reactor Vessel Water Level - Low, Level 3 Isolation Function receives input from two reactorvessel watei level channels. The outputs from the reactor vessel water level channels are connectedinto one two-out-of-two logic trip system. The Drywell Pressure - High Isolation function receivesinput from two drywell pressure channels. The outputs from the drywell pressure channels areconnected into one two-out-of-two logic trip system. .

When either liotltion Function actuates, the'TI-iv niechanisms will Withdfw the TIPs, if)wand close the TIP system isolation ball valves when the TIPs are fully withdrawn The( TIP system isolation valves are manual shear valves.

TIP System Isolation Functions isolate the Group tves isolation ball valves).


BASES

APPLICABLE 6.b. Reactor Vessel Water Level-Low (Level 3) (continued)SAFETY ANALYSES,LCO, and The Reactor Vessel Water Level-Low. (Level 3).AllowableAPPLICABILITY 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.

The Reactor Vessel Water Level -Low (Level 3) Function isonly required to be OPERABLE in NODES 3, 4, and 5 to preventthis potential flow.path-from lowering the reactor vessellevel to the top of the fuel'. In NODES 1 and 2, anotherisolation (i.e., Reactor Pressure-High) and administrativecontrols ensure that this flow path remains isolated toprevent unexpected loss of inventory via this flow path.

This' Function isolates both RHR shutdown cooling pumpsuction valves.

Feedwater Recirculation Isolation

7.a. Reactor Pressure -High

The Reactor Pressure-High Function is provided to isolatethe feedwater recirculation line. This interlock isprovided only.for equipment protection to'prevent anintersystem LOCA scenario, and credit for the interlock isnot assumed in the accident or transient analysis in theUFSAR.

The Reactor Pressure-High.signals are initiated from fourtransmitters that are connected to different taps on theRPV. Four channels of Reactor Pressure-High Function areavailable and are required to be-OPERABLE to ensure that no

* single instrument failure can preclude the isolationfunction. The Function is.only required to be OPERABLE inMODES 1, 2, and 3, since these are-the only MODES in whichthe reactor can be pressurized; thus, equipment protectionis needed. The Allowable Value was chosen-to be low enoughto'protect the system equipment from overpressurization.

- This Function isolates the feedwater recirculation valves'.

I' (continued)


TSTF-30; Rev. 2

Traversing Incore Probe System Isolation

4 a. Reactor Vessel Water Level=Low. Level 3

Low RPV water level indicates that the capability to cool the fuel may be threatened. The valves* whose penetrations communicate with the primary containment are isolated to limit the release offission products.. The isolation of the primary containment on Level 3 supports actions to ensure that

'bffsite dose limits of 10 CFR 100 are not exceeded. The Reactor VesselWaterLevel-Low, Level 3Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage pathsare assumed to be isolated post LOCA.

. Reactor Vessel Water Level -Low, Level 3 signals are initiated from level transmitters that sense thedifference between the pressure due to a constant column of water (reference leg) and the pressure dueto the actual water level (variable leg) in the vessel. Two channels of Reactor Vessel Water Level-Low, Level 3 Function are available and are required to be OPERABLE to ensure that no singleinstrument failure can initiate an inadvertent isolation actuation. The isolation function is ensured bythe manual shear valve in each penetration.

The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the same as theRPS Level 3 scram Allowable Value (LCO 3.3.1.1), since isolation of these valves is not critical toorderly plant shutdown.

This Function isolates the Gro up

&.b. Drywell Pressure=High

IHigh drywell pressure can indicate a break in the RCPB inside the primary containment The isolationof some of the primary containment isolation valves on high drywell pressure supports actions toensure that offsite dose limits of 10 CFR 100 are'not exceeded. The Drywell Pressure-HighFunction, associated with isolation of the primary containment, is implicitly assumed in the FSARaccident analysis as these leakage paths are assumed to be isolated post LOCK

High drywell pressure signals are initiated from pressure transmitters that sense the pressure in thedrywell. Two channels of Drywell Pressure -High per Function are available and are required to beOPERABLE to ensure that no single instrument failure can initiate an inadvertent actuation. Theisolation finction is ensured by the manual shear valve in each penetration.

The Allowable Value was selected to be the same as the ECCS Drywell Pressure -High AllowableValue (LCO 3.3.5.1), since this ma tive of a LOCA inside primary containment.

*s Function isolates the Grouj t /


BASES (continued)

ACTIONS 9Note a been provided to modify the ACTIONS related toprimary containment isolation instrumentation channels.Section 1.3, Completion Times, specifies that once aCondition has been entered, subsequent divisions,subsystems, components, or variables expressed in theCondition, 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 of theCondition continue to apply for each additional failure,with--Completion Times based on initial entry into theCondition. However,'the Required Actions for inoperableprimary containment isolation instrumentation channelsprovide appropriate compensatory measures for separateinoperable channels. As such, a Note has been provided thatallows separate Condition entry for each inoperable primarycontainment isolation instrumentation channel.

A 1Li

Because of the diversity of sensors available to provideisolation signals and the redundancy of the isolationdesign'; an" allowable out,-of -service time of 12 hours forFunctions 1.d, 2.a, and 2.b and 24 hours for Functions otherthan Functions 1.d, 2.a, and 2.b has been shown to beacceptable (Refs. 6 and 7) to permit restoration of anyinoperable channel to OPERABLE status. This out of servicetime is only acceptable'provided the associated Function isstill'maintaining isolation capability (refer to RequiredAction B.1 Bases). If the inoperable channel cannot berestored to OPERABLE status within the allowable out ofservice time, the channel must be placed in the'trippedcondition per Required Action A.1. Placing the inoperablechannel in trip would conservatively compensate for theinoperability, restore capability to accommodate a singlefailure, and allow operation to continue with no furtherrestrictions. 'Alternately, if it 'is not desired to placethe channel in trip (e.g., as in the case where placing theinoperable channel in trip would result in an isolation),Condition C must be entered and its Required Action taken.

.(continued)

PBAPS UNIT 2 8 3.3-160 Revision No. 0

Priary Contairnent Isolation Instrumentat-tB 3.3.6.1

F - ,7 ,- , P , .

h OS ar mxodfled by two Notes. ote 1 al Io 4penetration fW path(s) to be unisolated intrmittently mnderbadministrative controls. Thee cotrols consist of stationing'adedicated operator at the controls of the valve. who is incontinuous comunication with the control room. In this way,the pe ion can be rapidly isolated when a need for primarycontal isolaton is-

ECCS-OperatingB 3.5.1

BASES

APPLICABLESAFETY ANALYSES

(continued)

This LCO helps to ensure that the following acceptancecriteria for the ECCS, established by 10 CFR 50.46 (Ref. 8),will be met following a LOCA, assuming the worst case singleactive component failure in the ECCS:

a. Maximum fuel element cladding temperature is s 2200F;

b. Maximum cladding oxidation is s 0.17 times the totalcladding thickness before oxidation;

c. Maximum hydrogen generation from a zirconium waterreaction is z 0.01 times the hypothetical amount thatwould be generated if all of the metal in the claddingsurrounding the fuel, excluding the claddingsurrounding the plenum volume, were to react;

d. The core is maintained in a coolable geometry; and

e. Adequate long term cooling capability is maintained.

The limiting single failures are discussed in Reference 7.The remaining OPERABLE .ECCS subsystems provide thecapability to adequately cool the core and prevent excessivefuel damage.

The ECCS satisfy Criterion 3 of the NRC Policy Statement.

P

LCO Each ECCS injection/spray subsystem and five ADS valves arerequired to be OPERABLE. The ECCS injection/spraysubsystems 'are defined as the two CS subsystems, the twoLPCI subsystems, and one HPCI System. The low pressure ECCSinjection/spray subsystems are defined as the two CSsubsystems and the two LPCI subsystems.

With less than the required number of ECCS subsystemsOPERABLE, the potential exists that during a limiting designbasis LOCA concurrent with the worst case single failure,the limits specified-in Reference 8 could be exceeded. All

- ECCS subsystems must therefore be OPERABLE to satisfy thesingle failure criterion required by Reference 8.

LPCI subsystems may be considered OPERABLE during alignmentand operation for decay heat removal when below the actualRHR shutdown cooling isolation pressure in MODE 3, ifcapable of being manually realigned (remote or local) to the

(continued).1


Alignment and operation for decay heat removal includes when the required R-R pump is not CCSoperating or when the system is realigned from or to the RMR shutdown coolirkg mode. This CS-Operatingallowance is necessary since the RHR System may be requiie -o operate in t; shutdown B 3.5.1. t coaling mode to remove heat and sensible heat from the reactor. - a

LCO LPCI mode and not otherwise inoperable. At these low(continued) pressures and decay heat levels, a reduced complement of

ECCS subsystems should provide the required core cooling,thereby allowing operation of RHR shutdown cooling whennecessary.

APPLICABILITY All ECCS subsystems are required to be OPERABLE duringMODES 1, 2, and 3, when there is considerable energy in thereactor core and-core cooling would be required to preventfuel damage in the event of a break in the primary systempiping. In MODES 2 and 3, when reactor steam dome pressureis s 150 psig, HPCI is not required-to be OPERABLE becausethe low pressure ECCS subsystems can provide sufficient flowbelow this pressure. In MODES 2 and 3, when reactor steamdome pressure is s 100 psig, ADS is not required to beOPERABLE because the low pressure ECCS subsystems canprovide sufficient flow below this pressure. ECCSrequirements for MODES 4 and 5 are specified in LCO 3.5.2,'ECCS-Shutdown."

- ACTIONS A.1

- If any one low pressure ECCS injection/spray subsystem isinoperable, or if one LPCI pump in each subsystem isinoperable, all inoperable subsystems must be restored toOPERABLE status within 7 days (e.g., if one LPCI pump ineach subsystem is inoperable, both must be restored within7 days). In this Condition, the remaining OPERABLEsubsystems provide adequate core cooling during a LOCA.HQwever, overall ECCS reliability is reduced, because asingle failure in one of the remaining OPERABLE subsystems,concurrent with a LOCA, may result in the ECCS not beingable to perform its intended safety function. The 7 dayCompletion Time is based on a reliability study (Ref. 9)that evaluated the impact on ECCS availability, assumingvarious components and subsystems were taken out of service.The results were used to calculate the average availabilityof ECCS equipment needed to mitigate the consequences of aLOCA as a function of allowed outage times (i.e., CompletionTimes).

(continued)

.)



BASES

SURVEILLANCE nued)REQUIREMENTS

This SR is modi by a Note that allows subsystems to( be consiee OPRB2wi ng alignmenlfd operation for:>decay heat removal with reatFaeide pressure lessthan the RHR shutdown coolisJfo]Su pressure in MODE 3,if capable of being ma y realigned e or local) to

§pk~e7 the LPCI mode and otherwise inoperable.realignment to e LPCI mode may also include openin

~-- b dragva vz~fetblish the required-LPCI subsystemfof raes~ffii alowsoperation in the 'H hutdown cooln -

SR 3.5.1.3

Verification every 31 days that ADS nitrogen supply headerpressure is 2 85 psig ensures adequate air pressure forreliable ADS operation. The accumulator on each ADS valveprovides pneumatic pressure for valve actuation. The designpneumatic supply pressure requirements for the accumulatorare such that, following a failure of the pneumatic supplyto the accumulator, at least two valve actuations can occur

) with the drywell at 70% of design pressure (Ref. 10). TheECCS safety analysis assumes only one actuation to achievethe depressurization required for operation of the lowpressure ECCS. This minimum required pressure of ; 85 psigis provided by the ADS instrument air supply. The 31 dayFrequency takes into consideration administrative controlsover operation of the air system and alarms for low airpressure.

SR 3.5.1.4

Verification every 31 days that the LPCI cross tie valve isclosed and power to its operator is disconnected ensuresthat each LPCI subsystem remains independent and a failureof the flow path in one subsystem will not affect the-flowpath of the other LPCI subsystem. Acceptable methods ofremoving power to the operator include de-energizing breakercontrol power or racking out or removing the breaker. Ifthe LPCI cross tie valve is open or power has not beenremoved from the valve operator, both LPCI subsystems mustbe considered inoperable. The 31 day Frequency has been

(continued)


- -

| -r Alignment and operation for decay heat removal includes when the required RHR pump is not* operating or when the system is realigned from or to the RHR shutdown cooling mode. This

allow'ance is necessary since the 1 Systent may be required to operate in the shutdowncooling mode to remove decay heat ainsensible heat from the reactor.

.,

I

tOne LPCI subsystem may beco n ERABL ifma-nually realigne '(remote or ocal) to the LPCI mode andis not otherwise inoperable. Because of low pressure andlow temperature conditions in MODES 4 and 5, sufficient timewill be available to manually align and initiate LPCIsubsystem operation to provide core cooling prior topostulated fuel uncovery.

APPLICABILITY OPERABILITY of the low pressure ECCS injection/spraysubsystems is required in MODES 4 and 5 to ensure adequatecoolant inventory and sufficient heat removal capability forthe irradiated fuel in the core in case of an inadvertentdraindown of the vessel. Requirements for ECCS OPERABILITYduring.MODES 1, 2, and 3 are discussed in the Applicabilitysection of the Bases for LCO 3.5.1. ECCS subsystems are notrequired to be OPERABLE during MODE 5 with the spent fuelstorage pool gates removed, the water level maintained atm: 458 inches above reactor pressure vessel instrument zero(20 ft 11 inches above the RPV flange), and no operationswith a potential for draining the reactor vessel (OPDRVs) inprogress. This provides sufficient coolant inventory toallow operator action to terminate the inventory loss priorto fuel uncovery in case of an inadvertent draindown.

The Automatic Depressurization System is not required to beOPERABLE during MODES 4 and 5 because the RPV pressure is< 100 psig, and the CS System and the LPCI subsystems canprovide core cooling without any depressurization of theprimary system.

The High Pressure Coolant Injection System is not requiredto be OPERABLE during MODES 4 and 5 since the low pressureECCS injection/spray subsystems can provide sufficient flowto the vessel.

ACTIONS A.1 and B.1

If any one required low pressure ECCS injection/spraysubsystem is inoperable, an inoperable subsystem must berestored to OPERABLE status in 4 hours. In this Condition,the remaining OPERABLE subsystem can provide sufficientvessel flooding capability to recover from an inadvertentvessel draindown. However, overall system reliability isreduced because a single failure in the remaining OPERABLE

(continued),)


ECCS-ShutdownB 3.5.2

) BASES

SURVEILLANCE SR 3.5.2.1 and SR 3.5.2.2 (continued)REQUIREMENTS

The 12 hour Frequency of these SRs was developed consideringoperating experience related to suppression pool water leveland CST water level variations and instrument drift duringthe applicable MODES. Furthermore, the 12 hour Frequency isconsidered adequate in view of other indications availablein the control room to alert the operator to an abnormalsuppression pool or CST water level condition.

SR 3.5.2.3. SR 3.5.2.5. and SR 3.5.2.6

The Bases provided for SR 3.5.1.1, SR 3.5.1.7, andSR 3.5.1.10 are applicable to SR 3.5.2.3, SR 3.5.2.5, andSR 3.5.2.6, respectively.

SR 3.5.2.4

Verifying the correct alignment for manual, power operated,and automatic valves in the ECCS flow paths providesassurance that the proper flow paths will exist for ECCSoperation. This SR does not apply to valves that arelocked, sealed, or otherwise secured in position, sincethese valves were verified to be in the correct positionprior to locking, sealing, or securing. A valve thatreceives an initiation signal is allowed to be in anonaccident position provided the valve will automaticallyreposition in the proper stroke time: This SR does notrequire any testing or valve manipulation; rather, itinvolves verification that those valves capable ofpotentially being mispositioned are in the correct position.This SR does not apply to valves that cannot beinadvertently'misaligned, such as check valves. The 31 dayFrequency is appropriate because the valves are operatedunder procedural control and the probability of their beingmispositioned during this time period is low.

In KD d, te RSystem may operate in the 'shutdowncooling mode o decay heat a t from thereactor. Therefore, RH t re required for LPCIsubsystem operatioe aligned forremoval.{ Therefore,2Shksl is modified by a Note that allows one_LPCI s ys§tem of the RHR System to be considered OPE

(continued)



BASES


SR 3.5.2.4 (continued)

fow path ca AlD^$gly realigned (remote oj 1c~)-to)allow injection into liJYand th sytg~sno'{ therwise inoperable. Man i~stinment to allow injectioninto the RPV in tl¢Ut~oemya~r~iueopening thedrag valve ablish the required LPCI sub-sys flowrate - s will ensure adequate core cooling if aninadvertent RPV draLow ould occur

REFERENCES 1. NEDO-20566A, "General Electric Company AnalyticalModel for Loss-of-Coolant Accident Analysis inAccordance with 10 CFR 50 Appendix K,' September 1986.

7


Primary Containment Air LockB 3.6.1.2

BASES


I

SR 3.6.1.2.1 (continued)

testing. The periodic testing requirements verify that theair lock leakage does not exceed the allowed fraction of theoverall primary containment leakage rate. The Frequency isrequired by the Primary Containment Leakage Rate TestingProgram.

The SR has been modified by two Notes. Note.1 states thatan inoperable air lock door does not invalidate the previoussuccessful performance of the overall air lock leakage test.This is considered reasonable since either air lock door iscapable of providing a fission product barrier in the eventof a DBA. Note 2 requires the results of air lock leakagetests to be evaluated against the acceptance criteria of the'Primary Containment Leakage Rate Testing Program, 5.5.12..This ensures that the air lock leakage is properly accountedfor in determining the combined Type B and C primarycontainment leakage. Vs

5refjlre - cere&tce sin

SR 3.6.1.2.2 O

The air lock interlock mechanism is designed to preventimnultanpnou nnpninn nf both donnrs in the air lock. Since

l

both the inner and outer doors of an air lock are designedto withstand the maximum expected post accident primarycontainment pressure, closure of either door will supportprimary containment OPERABILITY. Thus, the interlockfeature supports primary containment OPERABILITY while theair lock is being used for personnel transit in and out ofthe containment. Periodic testing of this interlockdemonstrates that the interlock will function as designedand that simultaneous inner and outer door opening will notinadvertently occur. Due to the purely mechanical nature ofthis interlock, and given that the interlock mechanism is

challenged when primary containment is is,teitis only-agjuired-o be Perfo

I-n _ _ _ ~ -

er rSlv t 4 #4u CA c .er

/eE co701i{Ia SLvre et OW At@*:

9 pl~~1 ~A44n *t ov^ " + po~'JcDef"I

i loss o A;t;co;oct > x

eetovr-,A4 Kezfor*n)f ower'peyerleod jktDs FCk,.C% 4kese SE

I 44CAe fuV(tIbl kPA Pmrec b :PBAP

)

PCIVsB 3.6.1.3

BASES

ACTIONS A.1 and A.2 (continued)

allows a period of time to restore the KSIVs to OPERABLEstatus given the fact that MSIV closure will result inisolation of the main steam line(s) and a potential forplant shutdown.

For affected penetrations that have'been isolated inaccordance with Required Action A.1, the affectedpenetration flow path'(s) must be verified 'to be isolated ona periodic'basis. This is necessary to ensure that primarycontainment penetrations required to be isolated followingan accident, and no longer capable of being automaticallyisolated, will be in the isolation position should an eventoccur. This Required Action does not require any testing ordevice manipulation. Rather, it involves verification thatthose devices outside containment and capable of potentiallybeing mispositioned are in the correct position. TheCompletion Time of 'once per 31 days for isolation devicesoutside primary containment' is appropriate because thedevices are operated under administrative controls and theprobability of their misalignment is low. For the devicesinside primary containment, the time period specified "priorto entering MODE 2 or 3 from MODE 4, if primary containmentwas de-inerted while in MODE 4, if not performed within theprevious 92 days' is based on engineering judgment and is.considered reasonable in view of the inaccessibility of thedevices and other administrative controls ensuring thatdevice misalignment is an unlikely pos V it

Condition A is modified by a Note mnd catin at Is*Condition is only applicable to those penetratlon f1ow pathswith two PCIVs. For penetration floV pathA ithone PCIV,Condition C provides the appropriate Requ red A ions.Required Action A.2 is modified b ote' ipplies toisolation devices located in high Yadiation areas, andallows them to be verified by use of administrative means.Allowing verification by administrative means is consideredacceptable, since'access to these areas is typicallyrestricted. Therefore, the probability of misalignment,once they b ve been verified to be in the proper position,is low.

-(continued)


-TS-T e - ZGO I 2-

2. Isojvices that arecked, sea rotherwise

securedmaybe by/ use of admistative means.

Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and -allows these devices to be verified closed by use of adminstaive means. Allowing verification }

by adnistive means is considered acceptable, since the function of locking, sealing, orsecung ompoent isto ensure that these devices are not inadvertently repositione J

Inser(WOO, CEOG, BWR4, BWR6)

Requird on E.2 is modified by two Notes. Note applies to isolation devices located in highradiation areas allows these devices to be ve ilosed by use of administrative means.Allowing veriflc& n by administrative means nsidered acceptable, since access to these areasis typically restrict ote 2 applies to ison devices that are locked, sealed, or otherwisesecured in position and ws these dcvi to be verified closed by use of administrative means.Allowing verification by tive is considered acceptable, since the function oflocking, sealing, or secuig cMts is to ensue that these devices are not inadvertentlyrepositioned.

Insert 4 (BWOG)

Required Action D.2 is ifled by two Not Note I applies to isolation devices located inhigh radiation areas allows these devices to verified closed by use of administrive means.Allowing verifi n by administrative means is co ered acceptable, since access to these areasis typically ted. Note 2 applies to isolation devicehat are locked, sealed, or otherwisesecured in Ition and allows these devices to be verified c by use of administrative means.Allowin erification by administrative means is considered table, since the function ofJo sealing, or securing components is to ensure that these de are not inadvertentlyr psitioned.

PCIVsB 3.6.1.3

S BASES

ACTIONS B.1(continued)

With one or more penetration flow paths with two PCIVsinoperable except due to KSIV leakage not.within limit,either the inoperable PCIVs must be restored to OPERABLEstatus or the affected penetration flow path must beisolated within 1 hour. The method of isolation mustinclude the use of at least one isolation barrier thatcannot be adversely affected by a single active failure.Isolation barriers that meet this criterion are a closed andde-activated automatic valve, a closed manual valve, and ablind flange. The 1 hour Completion Time is consistent withthe ACTIONS of LCO 3.6.1.1.'

Condition B is modified by a Note indicating this :Conditionis only applicable to penetration flow paths with two PCIVs.For penetration flow paths wiith one PCIV, Condition Cprovides the appropriate Required Actions.

C.1 and C.2

With one or more penetration flow paths with one PCIV0 /°inoperable, the inoperable valve must be restored to

k c" L OPERABLE status or the affected penetration flow path muste t as Ar I be isolated.. The'method of isolation must include the use

< 05 D ex And V g 1) of at least one isolation barrier that cannot be adverselyvirffe ( affected by a single active failure. Isolation barriers

Idlt 4 h ~o ~ . Jthat meet this criterion are a closed and de-activatedj e/. ~automatic valve, a closed manual valve, and a blind flange.

V taa loA check valve t be used to is oatJ COf b-\ fw__hPrir __E)J(

8~~~~~~~~F~s l enna _fliou'7stlfiEber MriTEng the relative stability ofc osed system'(hence, reliability). to act as a

penetration isolation boundary and the relative importance,of supporting primary containment OPERABIL duri nMODES 1, 2, and 3.AThe Completion Time of ours

ireasona ering the instrument and the small pipe+ '/ diameter of penetration (hence, reliability) to act as a

penetration isolation boundary and the small pipe diameterof the affected penetrations.

( 5~'A E c For affected penetrations that have been isolated inf vit 5 eb accordance with Required Action C.1, the affected

penetration flow path(s) must be verified to be isolated on

(continued)


PCIVsB 3.6.1.3

BASES

ACTIONS' C.1 and C.2 (continued)

a periodic basis. This is necessary to ensure that primarycontainment penetrations required to be isolated followingan accident, and no longer capable of being automaticallyisolated, will be in the isolation position should an eventoccur. This Required Action does not require any testing orvalve manipulation. Rather, it involves verification,' through a system walkdown, that those valves outsidecontainment and capable of potentially being mispositionedare in the correct position. The Completion Time of 'onceper 31 days for isolation.-devices outside primarycontainment' is appropriate because the valves, are operatedunder administrative controls and the probability of theirmisalignment is low. For the valves inside primarycontainment, the time period specified 'prior to enteringMODE 2 or 3 from MODE 4, if primary containment wasde-inerted while in MODE 4, if not performed within theprevious 92 days' is based on engineering judgment and isconsidered reasonable in view of the inaccessibility of thevalves and other administrative controls ensuring that valvemisalignment is an unlikely possibility.

Condition C is modified by a Note indicating that thisCondition is only applicable to penetration flow paths withonly one PCIV. For penetration flow paths-with two PCIVs,Conditions A and B provide the appropjztee quire d ns.

Required Action C.2 is modified byANote'41 pplies tovalves and blind flanges located in high radiation areas andallows them to be verified by use of administrative means.Allowing verification by administrative means is consideredacceptable, since access to these areas is typicallyrestricted Therefore, the probability of misalignment ofthese valv , once they have been verified to be in the

ition, is low..

With any MSIV leakage rate not within limit, the assumptionsof the safety analysis are not met. Therefore, the leakagemust be restored to within limit within 8 hours.Restoration can be accomplished by isolating the penetrationthat caused the limit to be exceeded by use of one closedand de-activated automatic valve, closed manual valve, orblind flange. When a penetration is isolated, the leakage

(continued)


-TSTF -z< #GO I 0 2-

2. lis n ces tha arclocked, ed, or otherwise

MYcre m rifted byuy~fadmistai~cmeans.

Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and/allows these devices to be verified closed by use of admiitrative means. Allowing verification

by administrative means is considere d acceptable, since the function of locking, sealing, orAdsecuring components is to ensure that these devices are not inadvertently repositioned.

Insert 3 (W CEOG, BWR4, BWR6)

Requred Action is modified by two Notes. Note applies to isolation devices located in highradiation areas and ws these devices to be v closed by use of administrative means.Allowing verification dininistrative means is nsidered acceptable, since access to these areasis typically restricted. Not applies to isola n devices that are locked, sealed, or otherwisesecured in position and silo devi o be verified closed by use of administrative means.Allowing verification by tive is considered acceptable, since the function oflocking, sealing, or secug co is to ensure that these devices are not inadvertentlyrepositioned.

Insert 4 (BWOG)

Required Action D.2 is ed by two Notes. te 1 applies to isolation devices located inhigh radiation areas and ows these devices to be *fled closed by use of administrative means.Allowing verification administtive means is consi acceptable, since access to these areasis typically restricted ote 2 applies to isolation devi t are locked, sealed, or otherwisesecured in positio allows these devices to be verified by use of administrative means.Allowing verifi on by administrative means is considered tabl; since the function oflocking, , or securing components is to ensure that these are not inadvertentlyrepositioned.

PCIVsB 3.6.1.3

BASES

SURVEILLANCE SR 3.6.1.3.3 (continued)REQUIREMENTS

valves are capable of closing in the environment following aLOCA. Therefore, these valves are allowed to be open forlimited periods of time. The 31 day Frequency is consistentwith other PCIV requirements discussed in SR 3.6.1.3.4.

SR 3.6.1.3.4

This SR verifies that each primary containment isolationmanual valve and blind flange that is located outsideprimary containmen nd is required to be closed during.

| cko I W vccdcnt coitiLs is closed. The.SR helps to ensure thatpost accident leakage of radioactive fluids or gases outside

&k a~pew'%s the primary containment boundary is within design limits.

This SR does not require any testing or valve manipulation.Rather, it involves verification that those PCIVs outsideprimary containment, and capable of being mispositioned, arein the correct position. Since verification of valveposition for PCIVs outside primary containment is relativelyeasy, the 31 day Frequency was chosen to provide addedassurance that the PCIVs are in the correct positions. a

IL a Three Notes have been added to this SR. The first Note(~ St allows valves and blind flanges located in high radiation

.0 8 reas to be verified by use of administrative controls.(e °llowing verification by administrative controls is

x VA, [onsidered acceptable since the primary containment is+0 0kst inerted and access to these areas is typically restricted

nduring MODES 1, 2, and 3 for ALARA reasons. Therefore; the1V be " probability of misalignment of these PCIVs, once they have

v # so been verified to be in the proper position; is low. AJ f Isecond Note has been included-to clarify that.PCIVs that are

Ago open under administrative controls are not required to meetthe SR during the time that the PCIVs are open. A third

l*(a' Note states that performance of the SR is not required fortest taps with a diameter < 1 inch. It is the intent that

5' /this SR must still be met, but actual performance is notrequired for test taps with a diameter < 1 inch. The Note 3-allowance is consistent with the original plant licensingbasis.

(continued)


PCIVsB 3.6.1.3

BASES


SR 3.6.1.3.5

(conti nued) This SR verifies that each primary containment manualisolation valve and blind flange that is located insideprimary containmen jand is required to be closed during

co f S is closed. The SR helps to ensure thatpost accident leakage of radioactive fluids or gases outsidethe primary containment boundary is within design limits.

' For PCIVs inside primary containment, the Frequency-definedas uprior.to entering MODE 2 or 3 from'MODE'4 if primarycontainment was de-inerted while in MODE 4, if not performedwithin the previous 92 days" is appropriate since thesePCIVs are operated under administrative controls and theprobability of their misalignment is low. , '

Two Notes have been added to this SR. The first Note allowsvalves and blind flanges located in high radiation areas to

1F..tobe verified by use of administrative controls. Allowingverification by administrative controls is consideredacceptable'since the primary containment is inerted andaccess to these areas is typically restricted duringDES 1, 2, and 3 for ALARA reasons. Therefore, therobability of misalignment of these PCIVs, once they have

Lturd Ieen verified to be in their proper position, is low. Asecond Note has been included to clarify that PCIVs that are

p pen under administrative controls are not required to meethe SR during the time that the PCIVs are open.

SR 3.6.1.3.6

|' /The traversing incore probe (TIP) shear isolation valves areactuated by explosive charges. Surveillance of explosivecharge continuity provides assurance that TIP valves willactuate when required. Other administrative controls, suchas those that limit the shelf life of'the explosive charges,must be followed. The 31 day Frequency is based onoperating experience that has demonstrated the reliabilityof the explosive charge continuity.

SR 3.6.1.3.7

Verifying the correct alignment for each manual valve in theSGIG System required flow paths provides assurance that theproper flow paths exist for system operation. This SR doesnot apply to valves that are locked or otherwise secured in

(continued)

PBAPS UNIT 2 B 3.-6-26 Revision No. 0

PCIVsB 3.6.1.3

BASES


position, since these valves were verified to be in thecorrect position prior to locking or securing. This SR'doesnot require any testing or valve manipulation; rather, itinvolves verification that those valves capable of beingmispos'itioned are in the correct position. 'This SR does notapply to valves that cannot be inadvertently misaligned,such as'check valves. The 31 day Frequency. is based onengineering judgment, is consistent with the proceduralcontrols governing valve operation, and ensures correctvalve positions.

SR 3.6.1.3.8

Verifying the isolation time of each :pwer--operateautomatic PCIV is within limits is required to demonstrateOPERABILITY. MSIVs may be excluded from this-SR since MSIVfull closure isolation time is demonstrated by SR 3.6.1.3.9.The isolation time test ensures that the valve will isolatein a time period less than or equal to that assumed in thesafety analyses. The isolation time is in accordance withReference 2 or the requirements of the Inservice TestingProgram which ever is more conservative. The Frequency ofthis SR is in accordance with the requirements of theInservice Testing Program.''

SR 3.6.1.3.9

Verifying that the isolation time of each'MSIV is within thespecified limits is required to demonstrate OPERABILITY.The isolation time test ensures that the MSIV will isolatein a time period that does not exceed the times assumed inthe DBA analyses. This ensures that the calculatedradiological consequences of these events remain within10 CFR 100 limits. The Frequency of this SR is in-accordance with the requirements of the Inservice TestingProgram.

SR 3.6.1.3.10

Automatic PCIVs close on a primary containment isolationsignal to prevent leakage of radioactive material fromprimary containment following a DBA.' This SR ensures thateach automatic PCIV will actuate to its isolation positionon a primary containment isolation signal. The LOGIC SYSTEM

(continued)


PCIVsB 3.6.1.3

) BASES

I

SURVEILLANCE SR 3.6.1.3.16REQUIREMENTS

(continued) The inflatable seal of each 6 inch and 18 inch primarycontainment purge valve and each 18 inch primary containment.exhaust valve must be replaced every 96 months. This willallow the opportunity for replacement before gross leakagefailure occurs.

REFERENCES 1. UFSAR, Chapter 14.

2. UFSAR, Table 7.3.1.

3. 10 CFR 50, Appendix J, Option B.

4. UFSAR, Table 7.3.1, Note 17.

5. UFSAR, Table 5.2.2.

)

PBAPS UNIT 2 B 3.6-30 Revision No. I5Amendment No. 220

Secondary ContainmentB 3.6.4.1

BASES (continued)

SURVEILLANCE SR 3.6.4.1.1 and SR 3.6.4.1.2REQUIREMENTS

Verifying that secondary containment equipment hatches andone access door in each access opening are closed ensuresthat the infiltration of outside air of such a magnitude asto prevent maintaining the desired negative pressure doesnot occur. Verifying that all such openings are closedprovides adequate assurance that exfiltration from thesecondary containment will not occur. In this application,the term 'sealed' has no connotation of leak tightness.Maintaining secondary containment OPERABILITY requiresverifying one door in the access opening is closed. Anaccess opening contains one inner and one outer door. Insome cases, secondary containment access openings are sharedsuch that a secondary containment barrier may have multipleinner or multiple outer doors. The intent is to not breachsecondary containment at any time when secondary containmentis required. This is achieved by maintaining the inner orouter portion of the barrier closed at all times: However,all secondary containment access doors are normally keptclosed, except when the access opening is being used forentry and exit or when maintenance is being performed on anaccess opening. The 31 day Frequency for these SRs has beenshown to be adequate, based on operating experience, and isconsidered adequate in view of the other indications of doorand hatch status that are available to the operator.

SR 3.6.4.1.3 and SR 3.6.4.1.4

,i~<GT System exineCh eodary containmn amsphereA0 o environment through appropriate treatmn m ipet.

To ensre at fission products are treat 5 3...1.3 \verifies thali e SGT System will rapidl ~sablish and)maintain a pres e in the secondary ainment that isless than the pres e external to e secondary containmentboundary. This is co irmed by onstrating that one SGTsubsystem will draw down e condary containment to( 0.25 inches of vacuum wa gauge in s 120 seconds. Thiscannot be accomplished jthe condary containment boundary

Mk c _I is not intact.

SR 3.6.4.1.4 d onstrates that one SG bsystem canmaintain 2 . 5 inches of vacuum water ga for 1 hour at a

' w rat 10,500 cfm. The 1 hour test per allowssecondy containment to be in thermal equilibr at stead

) c nued)



BASES


SR 3.6.4.1.3 and SR 3.6.4.1.4 continued)

. Th~~erefore, these tp>tssa/e~nsure sl;n ary containment bound~a6 integrity. SinceJ these SRs al>econdar'y contaipu~nt tests, they need not b/ performed with GfNST sub 9rtem. The SGT subsystems are

tested on a STAGGER BASIS, however, to ensure that inaddition to the requ s of LCO 3.6.4.3, either SGTsubsystem will pe rm this t.. Operating experience hasshown these co nents will usua pass the Surveillancewhen perfo at the 24 month Freq . Therefore, theFrequency as concluded to be acceptable a reliab

REFERENCES 1. UFSAR, Section 14.6.3.


)


TSTF-322, Rev. 2'

The SGT Systef exhausts themecondar ntai ent atmosp re to the environment throughappropriate tre tment equipment. Each SGT sub stem is design to draw down pressure in the[secondary] c tainment to 240.25^ inches of va um water gauge i < [120] seconds and maintainpressure in t secondary] containment at nches of vacuu water gauge for 1 hour at aflow rate t F M lo ensure that a ission products released t the [secondary] containmentare treated, SR3.6.4.1 .and SR 3.6.4.1 erify that a pressure in the [secondary] containment thatis less than the lowest lptulated press'urextemal to the [secondary] ontainment boundary canrapidly be established .and maintained. When the SGT. System is oper ting as designed, theestablishment and maintenance. of [secondary] containment pressure nnot be accomplished if the[secondary] containment boundary is.not intact. Establishment of this p essure is confirmed by SR3.6.4.1 , which demonstrates that the [secondary] containment can be rawn down to 2 10.25] inchesof vacufd6, water gauge in s,#$ 20seconds using one SGT subsystem. R 3.6.4.1 Oemonstratesthat the pressure in thegkecondarycontainment can be mai d 2 Hi ] inche6ff vacuum wategauge for 1 hour using one SGT subsystem at a flow rate s QtJcfm. The 1 hour test period allows[secondary] containment to be in thermal equilibrium at steady.state conditions. The primary. purposeof these SRs is to ensure [secondary] containment boundary integrity. The secondary purpose ofthese SRs is to ensure that the SGT subsystem being tested functions as.designed. There is aseparate LCO with Surveillance Requirements which serves the primary purpose of ensuringOPERABILITY of the SGT.System.... These :SRs.need not be performed with each SGT subsystem.The SGT subsystem used fortliese Surveillances.is staggered to ensure that in addition'to therequirements of LCO 3.6.4.3, either SGT subsystem will perform this test. The inoperability of theSGT System does not necessarily constitute a failure of these Surveillances relative to the[secondary] containment OPERABILITY. Operating experience has shown the [secondary]containment boundary usually passes these Surveillances when performed at the month.Frequency. Therefore, the Frequency was concluded tobe acceptable from a reliab/lity standpoint.

SCIVsB 3.6.4.2

BASES

APPLICABLE established by SCIVs is required to ensure that leakage fromSAFETY ANALYSES the primary containment is processed by the Standby. Gas

(continued) Treatment (SGT) System before being released to theenvironment.

Maintaining SCIVs OPERABLE with isolation times withinlimits ensures that fission products will remain trappedinside secondary'containment so that they can be treated bythe SGT System prior to discharge to the environment.

SCIVs satisfy Criterion 3 of the NRC Policy Statement.

LCO SCIVs form a part of the secondary containment boundary.The SCIV safety function'is related to control of offsiteradiation releases res from DBAs.

The power operated tion valves are considered OPERABLEwhen their isolation times are within limits and the valvesactuate on an automatic isolation signal. The-valvescovered by this LCO, along with their associated stroketimes, are listed in Reference 3.

The normally closed isolation valves or blind flanges areconsidered OPERABLE when manual valves are closed or open inaccordance with appropriate administrative controls,automatic SCIVs are de-activated and secured in their closedposition, and blind flanges are in place. These passiveisolation valves or devices are listed in Reference 3.

APPLICABILITY In MODES 1, 2, and 3, a DBA could lead to a fission productrelease to the primary containment that leaks to thesecondary containment. Therefore, the OPERABILITY of SCIVsis required.

In MODES 4 and 5, the probability and consequences of theseevents are reduced due to pressure and temperaturelimitations in these MODES. Therefore, maintaining SCIVsOPERABLE is not required in MODE 4 or 5, except for othersituations under which significant radioactive releases canbe postulated, such as during operations with a potentialfor draining the reactor vessel (OPDRVs), during COREALTERATIONS, or during'movement of. irradiated fuelassemblies in the secondary containment. Moving irradiatedfuel assemblies in the secondary containment may also occurin MODES 1, 2, and 3.

(continued)


SCIVsB 3.6.4.2

BASES

ACTIONS A.1 and A.2 (continued)

containment penetrations required to be isolated followingan accident, but no longer capable of being automaticallyisolated, will be in the isolation position should an eventoccur. The Completion Time of once per 31 days is.appropriate because the isolation devices are operated underadministrative controls and the probability of theirmisalignment is low. This Required Action does not requireany testing or device manipulation. Rather, it involvesverification that the affected penetratio i ated.

Required Action A.2 is modified bya-iFNot eap es todevices located in high radiation areas and allows them tobe verified closed by use of administrative controls.Allowing verification by administrative controls isconsidered acceptable, since access to.these areas istypically restricted. Therefore, the probability ofmisalignment, once they have been verified to be in theproper position, is]l

B.1

With two SCIVs in one or more penetration flow pathsinoperable, the affected penetration flow path must beisolated within 4 hours. The method of isolation mustinclude the use of at least one isolation'barrier thatcannot be adversely affected by a single active failure.Isolation barriers that meet this criterion are a closed andde-activated automatic valve, a closed manual valve, and ablind flange. The 4 hour Completion Time is reasonable'considering the time required to isolate the penetration andthe probability of a DBA, which requires the SCIVs to close,occurring during this short time, is very low.

The Condition has been modified by a Note stating thatCondition B is only applicable to penetration flow pathswith two isolation valves. This clarifies that onlyCondition A is entered if one SCIV is' inoperable in each of.two penetrations.

(continued)


T -r-ZGC 1 £, 2.

Insert I

2. Isolat ithat arelock ,sealed, orherwise

srdmay b eib-eof administrative mba

Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position andallows these devices to be verified closed by use of adminsrtive meas. Allowing verificat ionby admiisrave means is considered acceptable, since the fimction of locking, sealingsecrn components. is to ensure that these devices are not inadvertently repositioned.j

Insert 3 (W , CEOG, BWR4, BWR6)

Required Action .2 is modified by two Notes. Note ppliesto isolation devices located in highradiation areas and ows these devices to be ve closed by use of administrative means.Allowing verification administative means is co *dered acceptable, since access to these areasis typically restricted. No 2 applies to isolation vices that are locked, sealed, or otherwisesecured in position and allo these devices to verifed closed by use of administrative means.Allowing verification by tive means considered acceptable, since the function oflocking, sealing, or securing corn ts is ensure that these devices are not inadvertentlyrepositioned.

Insert 4 (BWOG)

Required Action D.2 is modified b o Notes. te 1 applies to isolation devices located inhigh radiation areas and allows th devices to be v fied closed by use of administrative means.Allowing verification by tive means is cons acceptable, since access to these areasis typically restricted. Note 2 lies to isolation devices t are locked, sealed, or otherwisesecured in position and allo these devices to be verified c by use of administrative means.Allowing verification by tive means is considered a table, since the function oflocking, sealing, or components is to ensure that these are not inadvertentlyrepositioned.

SCIVsB 3.6.4.2

BASES

-ACTIONS C.1 and C.2(continued)

If any Required Action and associated Completion Time cannotbe met, the plant must be brought to a MODE in which the LCO-does not apply. To achieve-this status, the plant must-bebrought to at least MODE.3 within 12 hours and to MODE 4within 36 hours. The allowed Completion Times arereasonable, based on operating experience, to reach the ;required plant conditions from full power conditions in anorderly-manner and without challenging plant systems. 'I

D.1. D.2. and D.3

If any Required Action and associated Completion Time arenot'met, the plant must be placed in a condition in-whichthe LCO does not apply. If applicable, CORE-ALTERATIONS andthe movement of irradiated fuel assemblies in the secondarycontainment must be immediately suspended. Suspension ofthese activities shall not preclude completion of movementof a component to a safe position. Also, if applicable,actions must be immediately initiated to suspend OPDRVs inorder to minimize the probability of a vessel draindown andthe subsequent potential for fission product release.Actions must continue until OPDRVs'are suspended.

Required Action D.1 has been modified by. a Note stating-thatLCO 3.0.3 is not applicable. If moving irradiated fuel -assemblies while in MODE 4 or 5, LCO 3.0.3 would not-specifyany action. If moving fuel. while in MODE 1, 2, or 3, thefuel movement is independent of reactor operations.Therefore, in either case, inability to suspend movement ofirradiated fuel assemblies would not be a sufficient reason

.to require a reactor shutdown.

SURVEILLANCE SR- 3.6.4.2.1' y+rscSul@edtBJREQUIREMENTS--- ~ '_ ,,__

This SR verifies that each secondary con a nment manualisolation valve and blind flange that i required to beclosed during'accident conditions is closed. The SR helpsto ensure that post accident leakage of radioactive fluidsor. gases outside of the secondary containment boundary iswithin design limits. This SR does not require any testingor valve manipulation. Rather, it involves verificationthat those SCIVs in secondary containment that are capableof being mispositioned are in the correct position.

(continued)

PBAPS UNIT 2 .B 3.6-82 Revision No. 0

SCIVsB 3.6.4.2

BASES


Since these SCIVs are readily accessible to personnel during" -normal operation and verification of their position is

relatively easy, the 31 day Frequency was chosen toprovide added assurance that the SCIVs are in the correct

Apts positions.i.

Two Notes have been added to this SR. The first Notec l'a 9applies to valves and blind-flanges located in high

c radiation areas and allows them to be verified by use ofst administrative controls. Allowing verification by\ * 0 Sh'' E dministrative controls is considered acceptable, since0 ( access to these areas is typically restricted during

fvn N MODES 1, 2, and.3 for ALARA reasons. Therefore, theprobability of misalignment of these SCIVs, once they have

r been verified to be in the proper position, is low.

1ot'ii - A second Note has been included to clarify that SCIYs thatare open under administrative controls are not required tomeet the SR during the time the SCIVs are open.

SR 3.6.4.2.2

Verifying that the isolation time of each power operatedwJ.automatic SCIV is within limits is required to

Rtonstrate OPERABILITY. The isolation time test ensuresthat the SCIV will isolate in a time period less than orequal to that assumed in the safety analyses. The Frequencyof this SR is in accordance with the Inservice TestingProgram.

SR 3.6.4.2.3

Verifying that each automatic SCIV closes on a secondarycontainment isolation signal is required to prevent leakageof radioactive material from secondary containment followinga DBA or other accidents. This SR ensures that eachautomatic SCIV will actuate to the isolation position on asecondary containment isolation signal. The LOGIC SYSTEMFUNCTIONAL TEST in LCO 3.3.6.2, 'Secondary. ContainmentIsolation Instrumentation," overlaps this SR to providecomplete testing of the safety function. The 24 monthFrequency is based on the need to perform this Surveillance

(continued)


AC Sources- OperatingB 3.8.1

. BASES

SURVEILLANCE SR 3.8.1.9 (continued)REQUIREMENTS

equipment powered by the DG. SR 3.8.1.9.a corresponds tothe maximum frequency excursion, while SR 3.8.1.9.b andSR 3.8.1.9.c provide steady state voltage and frequencyvalues to which the system must recover following loadrejection. The 24 month Frequency takes into considerationplant conditions required to perform the Surveillance, and

--is-intended to be consistent with expected fuel cyclelengths.

This SR is modified by two NoU or er to ensure thate r-sun- er o-Toad Ionditions that are as close to

esign basis conditions as possible, Note 1 requires that ifsynchronized to offsite power, testing must be performedusing a power factor S 0.89. This power factor is chosen tobe representative of the actual design basis inductive

To minimize testing of the DGs, Note 2 allows a single test(instead of two tests, one for each unit) to satisfy therequirements for both units. This is allowed since the mainpurpose of the Surveillance can be met by performing thetest on either unit. If theDG fails one of theseSurveillances, the DG should be considered inoperable onboth units, unless the cause of the failure can be directlyrelated to only one unit.

SR 3.8.1.10

Consistent with Regulatory Guide 1.9 (Ref. 3),- paragraph C.2.2.8, this Surveillance demonstrates the DG

capability to reject a full load without overspeed trippingor exceeding the predetermined voltage limits. The DG fullload rejection may occur because of a system fault orinadvertent breaker tripping. This Surveillance ensuresproper engine generator load response under the simulatedtest conditions. This test simulates the loss of the totalconnected load that the DG experiences following a full loadrejection and verifies that the DG does not trip upon lossof the load. These acceptance criteria provide DG damageprotection. While the DG is not expected to experience thistransient during an event, and continue to be available,this response ensures that the DG is not degraded for futureapplication, including reconnection to the bus if the tripinitiator can be corrected or isolated.

(continued)


TSTF-276, Rev. 2

INSERT 1

2. If performed with DG nchronized with offsite er,it shall beperformed at a wer factor < [0.9].However, if grid conditions not permit, powerfactor limit is not required to et. Un thiscondition the power factor shall ai ained as closeto the limit as practicable.

INSERT 2

3. If performed with DG chronized with offsite ,wer,it shall be performed .a power factor < [0.9].However, if grid co itions do not permit, the powerfactor limit is no equired to be met. Under this \condition the wer factor shall be maintained as closeto the limi

N Nt grs that the DG is tested under load conditions that are as close to design basis conditionstas p le. When synchronized with offsite power, testing should be perfortned at a power factor of

l < D This power factor is representative of the actual inductive loading a/G would see under/design basis accident conditions. Under certain conditions, however, Note lows the surveillance tobe conducted at a power factor other than < These conditions occur when grid voltage is high,and the additional field excitation needed to the power factor to results in voltages on theemergency busses that are too high. Under th se conditions, the er factor should be maintained asclose as practicable t hile still main ning acceptable v ge limits on the emergency busses.In other circumstances, eid voltage may such that the G excitation levels needed to obtain apower factor of ay n cause unaccept ble voltages n the emergency busses, but the excitationlevels are in exc fthose rommended f the DG. such cases, the power factor shall bemaintained as cbs as practica e to [0.9] out ex eding the DG excitation limits.

>f

AC Sources -OperatingB 3.8.1

BASES


conditions that a as asis conditionspossible, testing mi p ing a power factor( .89. -Thi ~nEfcto iscoe ilrrgeetative of

XKte czka~sinbasis inductive lo ading that Ih owud7:

The 24 month Frequency takes into consideration plantconditions required to perform the Surveillance, and is'intended to be consistenwith expected fuel cycle lengths.

This SR is mofied byoNoteJ. a minimize testing of theO~s, c NotW allows a single test (instead of two tests,one for each unit) to satisfy the requirements.for bothunits. This is allowed since the main purpose of theSurveillance can be met by performing the test on either.unit. If the DG fails one of these Surveillances, the DGshould be considered inoperable on both units, unless thecause of the failure can.be directly related to only oneunit.

SR 3.8.1.11

Consistent with Regulatory Guide 1.9 (Ref. 3),paragraph C.2.2.4, this Surveillance demonstrates the asdesigned operation of the standby power sources during lossof the offsite source. This test verifies all-actionsencountered from the loss of offsite power, includingshedding of all loads and energization of the emergencybuses and respective loads from the DG. It furtherdemonstrates the capability of the DG to automaticallyachieve the required voltage and frequency within the,specified time.

The DG auto-start and energization of the associated 4 kVemergency bus time of 10 seconds is derived fromrequirements of the accident analysis for.responding to adesign basis large break LOCA. The Surveillance should becontinued for a minimum of 5 minutes in order to demonstratethat all starting transients have decayed and stability hasbeen achieved.

(continued)

PBAPS UNIT 2 B 3.8-27 Revision No. I

TSTF-276, Rev. 2

INSERT lI \

2. If performed with G synchronize *th offsite power,it shall be performe a power ctor < [0.9].However, if grid condi d not permit, the powerfactor limit is not require be met. Under thiscondition the power fac s be maintained as closeto the limit as practi e.

INSERT 2

3. If perfo d with DG synchronized with offsite. er,

NoteZ~ensures that the DG is tested under load conditions that are as close to ~esign basis conditionas ible. When synchronized with offsite power, testing should be performee at a power factor of

- .This power factor is representative of the actual inductive loading a~ would see underesign basis accident conditions. Under certain conditions, however, Not\alow the surveillance tobeconducted at a power factor other than < These conditions occur when grid voltage is high,

and the additional field excitation needed to g power factor to < results in voltages on theemergency busses that are too high. Under th se conditions, the PO fac should-be maintained asclose as practicable t . ile still mai nigacceptable volt ge Imit on the emergency busses.In other circumstances the gevoltage may such that the excitation levels needed to obtain apower factor o n unacce e voltageso the emergency busses, but the excitationlevels are in excess o ose reco ended f the DG. I uch cases, the power factor shall bemaintained as close as c ble t [ hout exce ing the DG excitation limits.

AC Sources-OperatingB 3.8.1

BASES


(continued)

SR 3.8.1.14

Consistent with Regulatory Guide 1.9 (Ref. 3),

paragraph C.2.2.9, this Surveillance requires demonstration

that the DGs can start and run continuously at full load

capability for an interval of not less than 24 hours-

22 hours of which is at a load equivalent to 90% to 100% of

the continuous duty rating of the DG, and 2 hours of which

is-at a load equivalent to 105% to 110% of the continuous

duty rating of the DG. The DGstarts-for this Surveillance

can be performed either from standby or hot conditions. *The

provisions for prelube and warmup, discussed in SR 3.8.1.2,

and for-gradual loading, discussed in SR 3.8.1.3, are

applicable to this SR.

This Surveillance verifies, indirectly, that the DGs are.

capable of synchronizing and accepting loads equivalent to

post accident loads. The D~s are tested at a loadapproximately equivalent to their continuous duty-rating,

even though the post accident loads exceed the continuous

rating. This is acceptable because regular surveillancetesting at post accident loads is injurious to the DG, and

imprudent because the same level of assurance in the ability

of the DG to provide post accident loads can be developed by

monitoring engine parameters during surveillance testing.

The values of the testing parameters can then bequalitatively compared to expected values at post accident

engine loads. In making this comparison it is necessary to

consider the engine parameters as interrelated indicators of

remaining DG capacity, rather than independent indicators.

The important engine parameters to be considered in makingthis comparison include, fuel rack position, scavenging air

pressure, exhaust temperature and pressure, engine output,

jacket water temperature, and lube oil temperature. With

-the DG operating at or near continuous rating and the

observed values of the above parameters less than expectedpost accident values, a qualitative extrapolation which

shows the DG is capable of accepting post accident loads'can

be made without requiring detrimental testing.

conditionas c hF toldsign conditions a

possible, testin erformed using a power factor

s 0.89. Thil wer factor osen to be representative of

_4the actua esign basis inductive ng that the DG could



BASES

SURVEILLANCE SR 3.8.1.14 (continued)REQUIREMENTS ___,_,_

*EQUIcEMENe In A load band is provided to avoid routine'-V're ¶ading of the DG. Routine overloading may result in

more frequent teardown inspections in accordance with vendorrecommendations in order to maintain DG OPERABILITY.

The 24 month Frequency takes into consideration plantconditions required to perform the Surveillance; and is*intended-to..be consistent with expected fuel cycle lengths.

This Surveillance has been modified by three Notes. Note 1states that momentary transients due to changing bus loadsdo not invalidate this test. Similarly, momentary powerfacto ,gud~t~boveAhseUimt do nBaL~invalidate the

felcticasqowr distribution system voltage 9~~igh it maynot be possi to raise DG output volta ithout creatingan overvoltage ition on the eme y bus. Therefore,.to ensure the bus v e and s ed loads, and DG are notplaced in an unsafe con H oring this test,.the power

lfactor limit does not h 4'lsk met if grid voltage or. emergency bus loadi ~rS es notwCrot the power factor limit!to be met when is tied to the`grid. When thisoccurs, the er factor should be oaint ed s cloe o

v~ts+BMt ite linitS Pr tic bei -Tof Tiniizee~sting o 1Xe-b3o a lows ai- sing e est (instead of two tests, one for

each unit) to satisfy the requirements for both units. Thisis allowed since the main purpose of the Surveillance can bemet by performing the test on either unit. If the DG failsone of these Surveillances, the DG should be consideredinoperable on both units, unless the cause of the failurecan be directly related to only one unit.

SR 3.8.1.15

This Surveillance demonstrates that the diesel engine.canrestart from a hot condition, such as subsequent to shutdownfrom normal Surveillances, and achieve the required voltageand frequency within 10 seconds. The minimum voltage andfrequency stated in the SR are those necessary to ensure theDG can accept DBA loading while maintaining acceptablevoltage and frequency levels. Stable operation at thenominal voltage and frequency values is also essential toestablishing DG OPERABILITY, but a time constraint is notimposed. This is because a typical DG will experience a


TSTF-276, Rev. 2 u

INSERT 1

2. If performed with G synchronized wi site power,it shall be performe a power fac d 1Q9].However, if grid condi ns do permit, the powerfactor limit is not require met. Under thiscondition the power fact s II be maintained as closetothe limit as practi e.

INSERT 2

3. If perfo ed with DG synchronized with o ite power,it sh be performed at a power factor< [0.9].H ever, if grid conditions do not permit, the power

ctor limit is not required to be met. Under this{condition the power factor shall be maintained as cto the limit as practicable.

hie.

INSERI

Note 2 ensures that the DG is tested under load conditions that are as close to design basis conditionsas possible. When synchronized with offsite power, testing should be performed at a power factor of< This power factor is representative of the actual inductive loading a DG would see under

esign basis accident conditions. Under certain conditions, however, Note2 allows the surveillance tobe conducted at a power factor other than < These conditions occur when grid voltage is high,and the additional field excitation needed to g the power factor to < g results in voltages on theemergency busses that are too high. Under se conditions, the factor should be maintained asclose as practicable to hile still main ning acceptable v ge limits on the emergency busses.In other circumstances, th id voltage may such that th G excitation levels needed to obtain apower factor o ay n t cause unaccep ble voltages n the emergency busses, but the excitationlevels are in exces of those commended f r the DG. such cases, the power factor shall bemaintained as c a ile t ex ing the DG excitation limits.

AC Sources - ShutdownB 3.8.2

BASES '

LCO(continued)

offsite circuit. In addition, some equipment that may berequired by Unit 2 is powered from Unit 3 sources (e.g.,Standby Gas Treatment (SGT) System). Therefore, onequalified circuit between.the offsite transmission networkand the Unit 3 onsite Class IE AC electrical powerdistribution subsystem(s), and one DG (not necessarily adifferent DG than those being used to meet LCO 3.8.2.brequirements) capable of'supplying power to one of therequired Unit 3 subsystems of each of the requiredcomponents must also be OPERABLE. Together, OPERABILITY ofthe 'required offsite -circuit(s) and required DG(s) ensuresthe availability of sufficient AC sources to operate theplant in a safe manner and to mitigate the consequences ofpostulated events during shutdown (e.g., fuel handlingaccidents and reactor vessel draindown).

The qualified Unit 2 offsite circuit must be capable ofmaintaining rated frequency and voltage while connected tothe respective Unit 2 4 kV emergency bus(es), and ofaccepting required loads during an accident. Qualifiedoffsite circuits are those that are described in the UFSAR,Technical Specification Bases Section 3.8.1 and are part ofthe licensing basis for the unit. A Unit 2 offsite circuitconsists of the incoming breaker and disconnect to thestartup 'and emergency auxiliary transformer, the respectivecircuit path to the emergency auxiliary transformer, and thecircuit path to the Unit 2 4 kV emergency buses required byLCO 3.8.8, including feeder breakers to the required Unit 24 kV emergency buses. A qualified Unit 3 offsite circuit'srequirements are the same as the Unit 2 circuit'srequirements, except that the circuit path, including thefeeder breakers, is to the Unit 3 4 kV emergency busesrequired to be OPERABLE by LCO 3.8.8.

The required DGs must be capable -of starting, acceleratingto rated speed and voltage, and connecting to theirrespective Unit 2 emergency bus on detection of busundervoltage. This sequence must be accomplished within10 seconds. Each DG must also be capable of acceptingrequired loads within the assumed loading sequenceintervals, and must continue to operate until offsite powercan be restored to the 4 kV emergency buses. Thesecapabilities are required to be met from a variety ofinitial conditions such as DG in standby with engine hot andDG in standby with engine at ambient conditions. Additional

(continued)


SLs2.0

2.0 SAFETY LIMITS (SLs)

2.1 SLs

2.1.1 Reactor Core SLs

*2.1.1.1 With the reactor steam dome pressure <.785 ps's qor coreflow <-10Z rated core flow:.

- THERMAL POWER shall be S 25% RTP.

2.1.1.2 :With tUb reactor steam dome pressure 2 785 psig and coreflow 2 1oZ rated core flow:

* MCPR. shall be 2 1.07 for two recirculation loop operation.or >'1.09 for. sing'le recirculation loop operation.

2.1.1.3 Reactor vessel water level shall be greater than the topof active irradiated fuel.

2.1.2, Reactor Cooiant Svstem Pre'ssure SL

Reactor steam dome pressure shall be s 1325 pS;g.

2.2 SL Violations.

With any SL violation, the following actions shall be complete d(' ;

* .2 -Within A1 h, notifik thbe ,NRC opecations Cgr't, in no: with 10 CFPR 50.72.-

2.2.'2 Within 2 hours:.

2.2.0.1 Restore conpliance with all SLs; and

2.2 #2 Insert all insertable control rods.

r- t9.3Within 21'hours', notify the Plant Manager and thF ie Irsdn

PBAPS UNIT 3 2.0-1 Amendmen, No. 252

......

SLs2.0

2.0 SLs

2.2 Volations (continued)

2.2.4 Wi s, a Licensee Eve ort (LER) shall be preparedpursuant to 05.73. LER shall be submitted to the NRC,the-Plant Manager, an Vice President-Peach Bottom Atomic

2.. Power Statizd -

2 2 p 5 f the unit shall _otbe thisue u iz'ed by- *th'


LCO Applicability3.0

3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY

LCO 3.0.1 LCOs shall be met during the MODES or other specifiedconditions in the Applicability, except. as provided inLCO 3.0.2 and LCO 3.0.7.

ICO 3.0.2 Upon discovery of a.failure to meet an LCO, the RequiredActions of the associated Conditions shall be met, except asprovided in LCO 3.0.5.and LCO 3.0.6.

If the LCO is met or is no longer applicable prior toexpiration of the specified Completion Time(s), completionof the Required Action(s) is not required, unless otherwise'stated.

LCO 3.0.3 When an LCO is not met and the associated ACTIONS are notmet, an associated ACTION is not provided, or if directed bythe associated ACTIONS, the unit shall be placed in a MODEor other specified condition in which the LCO is not .applicable. Action shall. be initiated within 1 hour-toplace the unit, as applicale, in:

a. MODE.2 within hours;

b. MODE 3 within 13 hours; and

c. MODE 4 within 37 hours.

Exceptions to this Specification are stated in theindividual Specifications.

Where corrective measures are completed that permitoperation in accordance with the LCO or ACTIONS, completion

* of the actions required by LCO 3.0.3 is not required.

LCO 3.0.3 is only applicable in MODES 1, 2, and 3.

LCO 3.0.4 When an LCO is not met, entry into a MODE or other specifiedcondition in the Applicability shall not be made except whenthe associated ACTIONS to be entered permit continuedoperation in the MODE or other specified condition in theApplicability for an unlimited period of time. ThisSpecification shall not prevent changes in MODES or otherspecified conditions in the Applicability that are requiredto comply with-ACTIONS, or that are part of a shutdown ofthe unit.

(continued)




3.1.4 Control Rod Scram Times

LCO .3.1.4 a. No more than 13 OPERABLE control rods shall be "slow,"in accordance with Table 3.1.4-1; and

b. No more than 2 OPERABLE control rods'that are -slow'shall occupy adjacent locations.

MODES 1 and 2.APPLICABILITY:

ACTIONS .


A. Requirements of the A.1 Be in MODE 3. 12 hoursLCO not met.


------------------------ N-------------NOTE --------- _ -_-___ -_During single control'rod scram time Surveillances, the control rod drive(CRD) pumps shall be isolated from the associated scram accumulator.


SR 3.1.4.1 Verify each control rod scram time iswithin the limits.of Table 3.1.4-1 withreactor steam dome pressure > 800 psig.

(continued)



.. r..lr.I M Clr rrn,,httnr-.rar,-bUKVt1LL RL.Lt KtU1 l KtMt__Ib

SURVEILLANCE.' FREQUENCY

SR 3.1.4.1 (continued) Prior toexceeding40% RTP aftereach reactorshutdown. 120 days

SR 3.1.4.2 Verify,' for.a representative sample, each 120 daystested control rod scram time is within the cumulativelimits.of Table 3.1.4-1 with reactor steam operation indome pressure 2 800 psig.. MODE 1

SR 3.1.4.3 Verify each affected control rod scram time Prior to* is within the limits of Table 3.1.4-1 with declaringany reactor steam dome pressure.' control rod,

OPERABLE afterwork on controlrod or CRDSystem that.could affectscram time

SR 3.1.4.4 Verify each affected control rod.scram time Prior tois within the limits of Table 3.1.4-1 with exceedingreactor steam dome pressure ; 800 psig. 40% RTP after

work on control. rod or CRD

System thatcould affectscram time

i

Prior toexceeding 40%RTP after fuelmovementithin


SDV Vent and Drain Valves3.1.8


3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves

LCO 3.1.8 Each SDV vent and drain valve shall be OPERABLE.


ACTIONS

--------------------- …Q Jepa trae Condition eni is alI Noer'ax& ShY en ad din a ine

., I - .'. . . ..CODIIO . ... *IE ED:.ACTi X1 OMPLETJUN T

A. One or more SDV vent .A.1 7 daysor drain lines. withone valve inopeiable.

B. One or more SDV-vent B.1 i -

or drain lines with . atedleboth valves be unibol ated under.

\ inperale.admrinistrattive'_v1 ontrl~6 to allow

I____\ drining- and venting/\ fthe SDY.

Isolate the 8 hoursassociated line.

C. Required Action and C.1 Be in MODE 3. 12 hoursassociated CompletionTime not met.


* MCPR3.2.2

SURVEILLANCE REQUIREMENTS (continued) -


SR 3.2.2.2 Determine the MCPR limits. . Once within72 hours aftereach completion

. . .of SR 3.1.4.1

AND

Once within72 hours after

. each completionof SR 3.1.4.2

1 -. hou-s at iR 9. er

* * * /


Feedwater and Main Turbine High Water Level Trip Instrumentation3.3.2.2

3.3 INSTRUMENTATION

3.3.2.2 Feedwater and Main Turbine High Water Level Trip Instrumentation

LCO 3.3.2.2 Two channels per trip system of the Digital FeedwaterControl System (DFCS) high water level trip instrumentationFunction shall be OPERABLE.

APPLICABILITY: THERMAL POWER 2 25% RTP.

ACTIONS

-------------------------------------NOTE---------------Separate Condition entry is allowed for each channel.


A. One or more DFCS high A.1 Place channel in 72 hourswater level trip trip.channels inoperable.

B. DFCS high water level B.1 Restore DFCS high 2 hourstrip capability not water level trip.maintained. capability.

C. Required Action andassociated CompletiiTime not met.

Reduce THERMAL POWERto < 25% RTP.

4 hours

1; C"4 IT I1 _- ow( o ~n¢Wtef IY-;^Xf~eGqhW Is #-, c- J.of of wd-,6tz6e FieeP~j4 By? ~~Hfne or -An o6n )bl

3.3 2Amendment No. 214_

p)

PBAPS UNIT 3

PAM Instrumentation3.3.3.1

Aft

Table 3.3.3.1-1 (page 1 of 1)Post Accident honitoring Instrumentation

CONDITIONSREFERENCED

REQUIRED FROM REQUIREDFUNCTION CHAUMELS ACTION D.1

1. Reactor Pressure 2 E

2. Reactor Vessel Water Level (Wide Range) 2 E

3. Reactor Vessel Water Level MFuel Zone) 2 E

4. Suppression Chasber Water Level (Wide Range) 2 E

5. Drywelt Pressure lWide Range) 2 E

6. Dryiell Pressure tSubetmospheric Range) 2 E

7. Drywell High Range Radiation 2 F

t. PCIV Position 2 per pener flow EpathYA

Drywell H2 & OA lyzer 2 ' E

1i. Suppression Chambe. K2 & °2 Analyzer 2 E

11. Suppression Chamber Water Temperature 2 Ec)

, . E

W I (a)

(b)

cc)

Uot required for isolation valves whose associated penetration flow path is isolated by at least oneclosed and deactivated automatic valve, closed manual valve, blind fLange, or check valve with flowthrough the valve secured.

Only one position indication charnel is required for penetration flow paths with only one installedcontrol room indication channel.

Each channel -requires 10 resistance terperature detectors (RTDs) to be OPERABLE with no two adjacentRTDs inoperable.

' ............. L''


ATWS-RPT Instrumentation. 3.3.4.1

ACTIONS (cnntinued)

CONDITION REQUIRED ACTION' COMPLETION TIME'

B. One Function with B.1 Restore ATWS-RPT trip 72 hoursATWS-RPT trip . capability.capability notmaintained.

C. Both Functions with C.1 Restore ATWS-RPT trip 1 hourATWS-RPT trip capability for. onecapability not - Function.maintained.

D. Required Action-andassociated CompletioTime'not met.

Remove therecirculation pumpfrom service.

Be in MODE 2.

6 hours

6 hours

+ cLWet s 04eusJx 6


-------------------------------------NOTE----------------- _ -_ -__When a channel is placed in an inoperable status solely for performance ofrequired Surveillances; entry into associated Conditions and Required Actionsmaybe delayed for up to 6 hours provided the associated Function maintainsATWS-RPT trip capability..


SR 3.3.4.1.1 . Perform CHANNEL CHECK. 12 hours

(continued)


*EOC-RPT Instrumentation3.3.4.2

3.3 INSTRUMENTATION

3.3.4.2 End of Cycle Recirculation Pump Trip CEOC-RPT) Instrumentation

LCO 3.3.4.2 a. Two channels per trip system for eachbEOC-RPTinstrumentation. Function listed 'below shall be OPERABLE:

1. Turbine Stop Valve (TSV)-Closure; and'

2. Turbine.Control 'Valve (TCV) Fast Closure, TripOil Pressure- Low.

b. The following limits are made applicable:

1. LCO 3.2.1, "AVERAGE PLANAR.LINEAR HEAT GENERATIONRATE (APLHGR),"' limits fo'~ inoperable EOC-RPT as'specified in the COLR; and I

2. LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR),"limits for -inoperable EOC-RPT as specified in theCOLR.

APPLICABILITY: THERMAL POWER 2:29.5% RTP. iI.

ACTIONS

--------------------------------- NOTE-----------------------------------Separate Condition entry is allowed-for.each channel.

- ---- ---- ---- ----- - - - - -........ - -. - ., . . - ------ ----------------

CONDITIOI. REQUIRED'ACTION -COMPLETION TIME

A. One or more channels A.1 Restore'.channel to 72 hoursinoperable. OPERABLE-status.

A.2 -------- NOTE---------Not applicable ifinoperable channel isthe result of aninoperable breaker.

. . Place channel in 72 hourstrip.

(continued)

PBAPS UNIT 3 3.3-31a Amendment No. 250


.... x

. ) ACTIONS (continued)

CONDITION REQUIRED ACTION. COMPLETION TIME

B. One or more Functions B.1 Restore EOC-RPT trip 2 hourswith EOC-RPT trip capability.capability, notmaintained.

C. Required Action and 'Remove the 4 hoursassociated Completion recirculation pumpTime not met. from service.

C.2 Reduce THERMAL POWER 4 hoursto < 29.5% RTP. I .


When a channel is placed inrequired Surveillances, entr,may be delayed for up to 6 hEOC-RPT trip capability.

SURV

SR 3.3.4.2.1 Perform CH)

.\I

---NOTE-----:-------- -an inoperable status solely for performance ofy into associated Conditions and Required Actionsours provided the:associated Function maintains

EEILLANCE FREQUENCY

ANNEL FUNCTIONAL TEST. 92 days

14) It'I

t h~ res5t 4t or) anLV) Xl

efr bes6r -

_ -Al

3'~.3-31b Amendm

PBAPS UNIT 3aent No.e25

t.%VI II.II rluej

I

PBAPS UNIT 3 nent No. 250

ECCS Instrumentati on3.3.5.1

Table 3.3.5.1-1 (page 1 of 5)Emergency Core Cooling System Instrunentation

APPLICABLE CONDITIONS1NODES REQUIRED REFERENCED

O2 OTHER CHANNELS -FROM _SPECIFIED. PER REWIRED SURVEILLANCE ALLOUABLE

FUNCTION CONDITIONS FUNCTION ACTION A.1 REQUIREMENTS VALUE

1. - Core Spray System

a. Reactor Vessel taterLevel -Low Low Low(Level 1)

b. DrywellPressure -ligh

c. Reactor Pressure -Low(Injection Permissive)

d. Core Spray PuipDischarge Flow -Low(Bypass)

e. Core Spray Pup Start-Time Delay Relay Clossof offsfte power)

1,2,3,

4 "a), Sa)

1,2,3

4 (b)

4 (b)

1,2,3

B. SRSRSRSR

B *SR8 SR

SRSR

C SRSRSRSR

B SRSRSRSR

E SRSR

3.3.5.1.1 2-160.03.3.5.1.2 inches3.3.5.1.43.3.5.1.5

3.3.5.1.1 S 2.0 psig3.3.5.1.23.3.5.1.4 63.3.5.1.5j

3.3.5.1.1 2 425.0 psi3.3.5.1.2 and3.3.5.1.4 < 475.0 psi3.3.5.1.5

3.3.5.1.1 2 425.0 psi3.3.5.1.2 and3.3.5.1.4 s 475.0 psR3.3.5.1.5

3.3.5.1.2 2 319.0 psi3.3.5.1.4 and

4C), 5(a)

1,2,3,

4 "'), 5 (a)

1.2,3

4C), 5 (a)

4

4Cl1 per

C1 perpup)

Ig

Is

I5

id

C . SR 3.3.5.1.4SR 3.3.5.1.5

5 351.0 psid

2 5.0 seconds

! 7.0 seconds

f. Core Spray Pum Start-Time Delay Relaytoffsite poweravailable)

PFps AC 1,2,3 2 C SR 3.3.5.1.4 z 12.1(1 per SR 3.3.5.1.5 secondAsad

4/(a) 5 "a) FPA.) s 13.9seconds

.Puts BD 1,2,3 2 C SR 3.3.5.1.4 2 21.4(1I per SR 3.3.5.1.5 seconds and

4Ca)" 5"') P ) s 24.6seconds

(a) Vhen associatedes'bsystem(s) are required to be OPERABLP E

Cb) Also required to initiate the associated diesel generator CD6



Table 3.3.5.1-1 (page 2'of 5)Emergency Core Cooling System Instruentation

APPLICABLE CONDITIOlSNODES REQUIRED REFERENCED

OR OTHER CHANNELS FROMSPECIFIED PER REQUIRED SURVEILLANCE ALLOWBLE

FUNCTION CONDITIONS FUNCTION ACTION A.1 REWUIREMIENTS VALUE

2. Lou Pressure CoolantInjection .CLPCI) Systen

a. Reactor Vessel iater 1,2,3, 4 B SR 3.3.5.1.1. -160 inchesLevel -Low Low Low SR 3.3.5.1.2.(Level 1) 'a), 5 "a) SR 3.3.5.1.4

SR 3.3.5.1.5

b. Drywell 1.2,3 4 a SR 3.3.5.1.1 S2.0 psigPressure -High SR 3.3.5.1.2

SR 3.3.5.1.4SR 3.3.5.1.5

c. Reactor Pressure-Low 1,2.3 4 C SR 3.3.5.1.1 2 425.0 psigtInjection Permissive) SR 3.3.5.1.2 and

SR 3.3.5.1.4' s 475.0 psigSR 3.3.5.1.5

4 "', 5Ca) 3 SR 3.3.5.1.1 2 425.0 psigSR 3.3.5.1.2 andSR 3.3.5.1.4 S 475.0 psigSR 3.3.5.1.5

d. Reactor Pressure-Low 1 Cc), 2 ¢C), 4 C SR 3.3.5.1.1 2 211.0 psigLow (Recirculatirn SR 3.3.5.1.2Discharge Valve 3"' SR 3.3.5.1.4Permissive) SR 3.3.5.1.5

e. Reactor Vessel Shroud 1,2,3 2 B SR 3.3.5.1.1 X -226.DLevel -Level 0 SR 3.3.5.1.2 inches

SR 3.3.5.1.4SR 3.3.5.1.5

f. Low Pressure Coolant 1,2,3, 8 C SR 3.3.5.1.4Injection Pupi' t2 per SR 3.3.5.1.5Start-Time Delay 4 "', 5 a) W'Relay (offsite poweravailable)

Punps A,B 2 1.9 secondsand < 2.1seconds

Purps C,D 2 7.5 secondsand S 8.5seconds

g. Lou Pressure Coolant 1,2,3 4 E SR 3.3.5.1.2 2 299.0 peidInjection Pup -(1 per SR 3.3.5.1.4 andDischarge Flow-Lo 4 5 a) pp) SR 3.3.5.1.5 S 331.0 psid(Bypass)

I

(a)

tC)

When associatecv'z rstn s) are required to be OPERABLE,

With associated recirculation pUwp discharge valve open.

PBAPS UNIT 3 3. 3-40 Amendment No. 214

..


3.3 INSTRUMENTATION

3.3.6.1 Primary Containment Isolation Instrumentation

LCO 3.3.6.1 The primary containment isolation instrumentation for eachFunction in Table'3.3.6.1-1 shall be OPERABLE.

APPLICABILITY; According to Table 3.3.6.1-1. _

ACTIONS .AI uck4e 4SW" SI'e c4,fbds. . OTE--5

S---C------------Codtn nf---------------oh----n---------Separate Condition 'entry is alowed for eachchannel.____--_____-_________________________________ ----------------- _---------------

CONDITION REQUIRED ACTION- | COMPLETION TIME

A. One or more requiredchannels inoperable.

A.1 Place' trip.

channel in 12 hours for -Functions 1.2-.a, et 2. dA

AND

24 hours forFunctions otherthan Functions1.d, 2.a, b2. b jJ ~ I, ~

B. One or more Functions B.1 Restore isolation 1 hourwith isolation capability.capability not.maintained.

C. Required Action and C.1 Enter the Condition Immediatelyassociated Completion referenced inTime of Condition A or Table 3.3.6.1-1 forB not met. , the channel.

(continued)

PBAPS UNIT 3 3.3-48 Amendment No.'214


ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION'TIME'

D. As required by D.1 Isolate associated 12 hoursRequired Action C.1 main steam lineand referenced in (MSL).Table 3.3.6.1-1.

' ; , . . OR,

D.2.1' Be in MODE 3. 12 hours

AND

D.2.2. Be in MODE 4. 36 hours

E. As required by E.1 Be in MODE 2. 6 hoursRequired Action C.1

. and referenced in -

Table 3.3.6.1-1.

F. As required by F.1. Isolate the affected .1 hourRequired Action C.1 penetration flowand referenced in path(s).Table 3.3.6.1-1.

G. As required byRequired Action C.1and referenced inTable.3.3.6.1-1.

OR

G.1

AND

G.2

Be in MODE.3.

Be in MODE 4.

12 hours

36 hours

Required Action-andassociated CompletionTime-of Condition Fnot met. ' , \

(continued)



ACTIONS ...nntinud,

CONDITION REQUIRED ACTION COMPLETION TIME.. . I . .

H. *As required byRequired Action C.1and referenced inTable 3.3.6.1-1.

H.I Declare associatedstandby liquidcontrol (SLC)subsystem inoperable..

1 hour

.1 hour

OR

H.2.. Isolate the ReactorWater Cleanup System.

.-

I. As required byRequired Action C.1and referenced inTable. 3.3.6.1-1.

1.1

OR

1.2

Initiate action torestore channel toOPERABLE status.

Immediately

ImmediatelyInitiate action toisolate the ResidualHeat Removal (RHR)Shutdown CoolingSystem.

)

/Th .4sregard b2 \ 3 x

Aci_. Cig '.

~s~ A - 4 e - le o 4 e c k~2 .4 h o#z.o-j k

PBAPS UNIT 3 3.3-50 U 3Amendment No. 214

Primary Containment Isolatio6n Instrumentation3.3.6.1

Table 3.3.6.1-1 (page 3 of 3)Primary Containsent Isolation Instruaentation

APPLICABLE CONDITIONSMODES OR REQUIRED REFERENCED

OTHER CHANNELS FROMSPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE

FLNCTION CONDITIONS SYSTEM ACTION C.1 REQUIREMENTS VALUE

5. Reactor Water Cleanup(RWCU) System Isolation

a. RYCU Flow- High 1,2,3 1 F SR 3.3.6.1.1 < 125X ratedSR 3.3.6.1.3. flowu(23.0SR 3.3.6.1.7 in-Wc)

b. SLC System Initiation 1,2 1 N SR 3.3.6.1.7 MA

c. Reactor Vessel Water . 1,2,3 2 F SR 3.3.6.1.1 t 1.0 InchesLevel -Low (Level .3) SR 3.3.6..2

SR 3.3.6.1.5SR 3.3.6.1.7

6. RHR Shutdown Cooling SystemIsolation

a. Reactor Pressure-High 1,2,3 1 F SR 3.3.6.1.3 S 70.0 psigSR 3.3.6.1.7

b. Reactor Vessel Water 3,4,5 2 (a) I SR 3.3.6.1.1 Z 1.0 inchesLevel -'Low (Level 3) SR 3.3.6.1.2

SR 3.3.6.1.5SR 3.3.6.1.7

7. Feedwater RecirculationIsolation

a. Reactor Pressure -Nigh 1,2,3 2 F SR 3.3.6.1.1 600 psigSR 3.3.6.1.2SR 3.3.6.1.5SR 3.3.6.1.7.

)

I

(a) In WDES IL and 5, provided RHR Shutdown Cooling System integrity is maintained, only one channel pertrip systen with an isolation signal available to one shutdown cooling p.p suction isolation valve isrewired.

* T I'A ,er5'In7 4(0ore Pri- (k

K., . .;S5 I^ ,t e3 .,11 > 1{i, vmg 11- 20"C.te(

* ..

PBAPS 214

ECCS-Operating3.5.1

-.. EMERGENCY CORE COOLING SYSTEMS (ECCS)!(RCIC) SYSTEM

AND REACTOR CORE ISOLATION COOLING

3.5.1 ECCS-Operating

LCO 3.S.1 Each ECCS injection/spray subsystem and the AutomaticDepressurization System (ADS) function of five safety/reliefvalves shall be OPERABLE.

APPLICABILTT.

MODE 1,MODES 2 and 3, except high pressure coolant injection (HPCI)

is not required to be OPERABLE with reactor steam domepressure s. 150 psig and ADS valves are not required tobe OPERABLE with reactor steam dome pressure s 100 psig.

ACTIONS

CONDITION | REQUIRED ACTION COMPLETION TIME

A. One low pressure ECCS A.1 Restore low pressure 7 daysinjection/spray - ECCS injection/spraysubsystem inoperable. subsystem(s) to

OPERABLE status..OR

One low pressurecoolant injection(LPCI) pump in eachsubsystem inoperable.

B. Required Action and B.1 Be in MODE 3. 12 hoursassociated CompletionTime of Condition A ANDnot met.

B.2 Be in MODE 4. 36 hours. ,'' 8, . _ _ ,....

ivif E . ....... e.

Ps UNIlt* 73.-- - 4- = _ -

(continued)

PBA Amendment No. 214

ECCS-Operating3.5.1

,..,..,..... - , .",^..,,._.|_ -

bUKVtiLLAhLt KtQUiKUt.N_ _

SURVEILLANCE' FREQUENCY

' SR 3.5.1.1 Verify, for each ECCS injection/spraysubsystem, the.piping is filled with waterfrom the pump discharge valve to theinjection valve.

31 days

SR 3

.M w-co

Ad-4

_ hea't-removal Witht4co steam dome ."-pressure less tWSlu Rsdual Heat> -Removal (Hthudw'soing isolation

pres'ur~i"MOD..3 ifcapizeof being-ma'uaJb~ralinedand not of2ws

___________- - - - - - - - - - - - - - - - -____

* Verify each ECCS injection/spray subsystem'manual, power operated, and automatic valvein' the flow path, that is 'not locked,sealed, or otherwise secured in position,is in the correct position.

31 days

SR 3.5.1.3 Verify ADS nitrogen supply header pressure 31 days-is 28 5 psig.

SR-3.5.1.4 Verify the LPCI cross tie valve 31 days*is closed and power is removed from thevalve.operator.

(continued)

PBAPS UNIT 3 .3.5-4 Amendment No. 214

-i t .* ECCS-Shutdown3.5.2

3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATIONCOOLING (RCIC) SYSTEM

'3.5.2 ECCS-Shutdown .

*LCO 3.5.2. Two low. pressure ECCS injection/spray subsystems shall beOPERABLE. .

AP LICABILITY: .

..

MODE 4,.MODE 5, except with the spent fuel storage pool gates* removed, water level 2 458 inches above reactor pressure

vessel instrument zeros and no operations with a- potential for draining the reactor vessel (OPDRVs) in

progress.

ACTIONS'

CONDITION.. REQUIRED ACTION COMPLETION TIME

A. One required.ECCS A.1 Restore required ECCS 4 hoursinjection/spray . injection/spraysubsystem inoperable. subsystem to OPERABLE

status.

B. Required Action'and B.1 Initiate action to Immediatelyassociated Completion suspend OPDRVs.Time of-Condition A.not met.

C. Two required ECCS C.1 Initiate action to Immediatelyinjection/spray . suspend OPDRVs:subsystems inoperable. :

AN.

C.2 Restore one ECCS 4 hoursinjection/spraysubsystem to OPERABLEstatus.

0I T . (continued)

- o Ye - °~~~ ve{ OF c^¢leat tke-7 wf~e!salhPBAPS UNIT 3 3 ,f' gdooie -8 A %mendment No. 21

_- -. *.

14

-.f _ .1�

I- . .... _

ECCS -Shutdown3.5.2

rEt~nsIrr- I AllI'r, nrnm~nriuraWre. I- - &2-.ZUK~t1LLBI1L.t rLt1UlfLFlIa CUfnlL1nUt1UJ


SR 3.,5.2.2 Verify, for each required core spray (CS) 12 hourssubsystem, the:

.a. Suppression pool water level, is211.0 ft; or

*b. . ----------- NOTE------------------Only one required CS subsystem maytake credit for this option duringOPDRVs.

.,- - -- - - ---- --- --- --- --- ---

Condensate storage tank water level is*17.3 ft.

SR 3.5.2.3. Verify, for each required ECCS injection/ 31 daysspray subsystem, the piping is-filled withwater from the pump discharge valve to theinjection'valve.

NOTE--n LPCI sub em may be co dered .

OPERABLE during.a m and operation fodecay heat remov ble of being)Ranually real ed and not seinoperabl .C

31 daysVerify each required ECCS injection/spray* subsystem manual, power operated, andautomatic valve in the flow path, that isnot locked, sealed, or otherwise securedposition, is in the correct position.

in

.(continued)

P.BAPS UNIT 3 .3.5-10 Amendment No. 214

Primary Containment Air Lock3.6.1.2

PBAPS UNIT 3 3.6-7.- Amendment No. 214

PCIVs3.6.1.3 . .

ACTIONS

CONDITION REQUIRED ACTION . COMPLETION TIME-- -1

*A. (continued) A.2 - NOTE----n4 Isolation devices in

high radiation areasmay be verified byuse of administrativemeans.

7 ---------- _ __

Verify the affectedpenetration flow pathis isolated.

)

,

W MO a a .- A,

Once per 31 daysfor isolationdevices outsideprimarycontainment

AND

Prior.toentering MODE 2or.3 fromMODE 4, if.primarycontainment wasde-inerted whilein MODE 4, ifnot performedwithin theprevious92 days, forisolationdevices insideprimarycontainment

- J

(continued)

PBAPS UNIT 3 3 .6-9 Amendmen't No. 214

PCIVs3.6.1.3

ACTIONS (continued)


B. --------- 'NOTE---------B.1 Isolate the affected 1 hourOnlyapplicable to penetration flow pathpenetration flow paths by use of at leastwith twoPCIVs. one closed and________ ___ _____ ---- de-activated.

automatic valve,One or more. closed.manual .valve,penetration'flow paths or blind flange.with two PCIVs.inoperable except forMSIV leakage notWithin limit.

C. -- -NOTE------Only applicable' to .penetration flow'pathswithonly one PCIV.

C.1 Isolate the affectedpenetration flow pathby use of at'leastone closed andde-activatedautomatic valve,closed manual valve,or blind flange. '

A'hours except;for' excess.f1 owcheck valve(EFCVs) e

.'AND* One or more

penetration flowwith one PCIVinoperable. '

.1paths

(


.PCIVs3.6.1.3

ACTIONS (continued)

CONDITION REQUIRED ACTION | COMPLETION TIME ..: I. '

C. (continued) .2 --- NOT----C. @ Isolation devices in

O high radiation areasmay be verified byuse of administrativemeans.

9/ Verify the affected

• 7penetration flow pathis isolated.

Once per 31 daysfor isolationdevices outsideprimarycontainment

AND

Prior.toentering MODE 2or. 3 from.MODE 4, ifprimarycontainment wasde-inerted whilein MODE 4, ifnot performedwithin theprevious92 days, forisolationdevices insideprimarycontainment

D. One or more D.1 Restore leakage rate 8 hourspenetration flow paths . to within limit.with one or more MSIVsnot within MSIV'leakage rate limits.

(continued)

Amendment No. 214PBAPS UNIT 3 . 3.6-11

* PCIVs3.6.1.3

CIvrTi i A~Irr Drnl ITDCUrUITC r


SR 3.6.1.3.3 ------------ NOTE-------------------* Not required to be met when the 6 inch or

18.inch primary containment purge and 18inch primary containment exhaust valvesare open for inerting, de-inerting,pressure control, ALARA or air qualityconsiderations for personnel entry, orSurveillances that require the valves tobe open.

Verify each 6 inch-and 18 inch primary. 31 dayscontainment purge valve and each 18 inchprimary containment exhaust valve is'closed..

SR 3.6.1.3.4 . ------------------NOTES--------------' 1. Valves and blind flanges in high

.' radiation areas maybe verified byuse of administrative means.

* 2. Not required to be met for PCIVs that.are open under administrativecontrols.

* 3. Not required to be performed for test. taps with a diameter s 1 inch.

Verify each primary containment isolation 31 daysmanual'valve and blind flange'that islocated-outside primary.containment andis required.to be closed during ac dentconditions is closed. '

/~(coI

se (,

Bnti nued)

PBAPS UNIT 3 3.6-13 .Amendment No. 214

PCIVs*3.6.1.3

0- CIDVCTI I ANirF rnilTvflflTc Irnntinatrill.Ju Iv I L; LL rnl II- *Svo &*uar j L Us L IP .J j, .W U I - I Luau J __ _ _ __ _ _ ___._

SURVEILLANCE. FREQUENCY

SR 3.6.1.3.5 ------------------------------ 1. Valves and blind flanges in high



Verify each primary containment manual Prior toisolation valve and blind flange that is entering MODE 2located inside primary containment and is or 3 from*required to be closed during accid nt MODE 4 ifconditions is closed. primary

containment-wasde-inerted

(~pc9 while -in-OiAC 'k A MODE 4, if not

performed-O 5C ur-t7 within-the )previous92 days

SR 3.6.1.3.6 Verify continuity of the traversing 31 daysincore probe (TIP) shear isolation valveexplosive charge.

SR 3.6.1.3.7 Verify each SGIG System manual valve in 31 daysthe flow paths servicing the 6 and18 inch primary containment purge valvesand the 18 inch.primary containmentexhaust valves, that is not locked,sealed, or otherwise secured in position,

* is in the correct position;

(continued)

PBAPS UNIT 3 3.6-14. Amendment No. 214

* PCIVs3.6.1.3

SURVEILLANCE REQUIREMENTS (continued) I .

SURVEILLANCE

SR 3.6.1.3.8 Verj the isolation time of eachc--- In accordanceeach 'automatic bCIV, except with the

for MSTV§s, is within limits. InserviceTesting Program

.SR 3.6.1.3.9 Verify the isolation time of each MSIV is In accordance2 3.seconds and s 5 seconds. with the

InserviceTesting Program

SR 3.6.1.3.10 Verifyeach automatic PCIV actuates to 24 months' the isolation'position on an actual or'simulated isolation signal.'

SR 3.6.1.3.11 Verify a representative sample of reactor 24 monthsinstrumentation line EFCVs actuates tothe isolation position on a simulated'instrument line break signal.

SR 3.6.1.3.12 Remove and test the explosive squib from 24 months on aeach shear isolation valve of the TIP STAGGERED TESTSystem. BASIS

SR 3.6.1.3.13 Verify the CAD System supplies nitrogen 24,monthsto the SGIG System upon loss of the .normal air supply.

(continued)

-I


IISecondary Containment

3.6.4.1

ACTIONS


C. (continued) C.2 Suspend CORE ImmediatelyALTERATIONS.

AND

C.3 Initiate action to Immediatelysuspend OPDRVs.


I

PBAPS UNIT 3 .3.6-35 Amendment No. 230

-SCIVs3.6.4.2

ACTrANS

CONDITION .1REQUIRED ACTION COMPLETION TIME-

-NO ---@DIsolation devices in

high radiation areasmay be 'verified byuse of administrativemeans.

__________________------

Verify the affected.penetration flow pathis isolated. -

Once per 31 days

t

*B. ------ NOTE---------Only -applicable topenetration flow paths.with two isolationvalves. .

B.I Isolate the affectedpenetration flow path

.by use.of at leastone closed and*de-activatedautomatic valve,closed manual valve,or. blind.flange.

4 hours

One or morepenetration flowwith two SCIVsinoperable.

paths

C. Required Action and C.1 Be in MODE 3. - 12 hoursassociated CompletionTime of Condition A ANDor B not met inMODE 1, 2, or:3.. C.2 Be in MODE 4. 36 hours

(continued)


. SCIVs3.6.4.2

vIIDurtI SAMrr nrnttTDrUr&TM

SURVEILLANCE '.FREQUENCY .

SR '3.6.4.2.1 ----------------NOTES------------------1. Valves and blind.flanges in high

radiation areas may be verified by*use of administrative means.

*2. Not required to be met for SCIVs thatare open under administrative.

'controls. .

Verify each. secondary containmentisolation'manual valve and blind flangethat u required to be closed during-IEcident conditions.is closed.

31 days

SR 3.6.4.2.2 . Verify the isolation time of each power In accordanceoperated <rautomatic SCIV is with thewithin limits.l- Inservice

Testing Program

SR 3.6.4..2.3 - Verify each automatic SCIV actuatesthe isolation position on. an actualsimulated actuation signal.

toor

24 months


* -AC Sources-Operating3.8.1

SURVEILLANCE REQUIREMENTS (continued). __._._._

SURVEILLANCE . FREQUENCY

2. A single test at the specifiedFrequency will satisfy thisSurveillance for both units.

Verify each DG rejects a load greater thanor equal to its associated single largestpost-accident load,.and:

*a. Following load rejection, thefrequency is s 66.75 Hz;

b. Within 1.8 seconds-following loadrejection, the voltage is : 3750 V and

* s 4570 V, and after steady stateconditions are. reached,.!aaintainsvoltage 2 4160 V and s 4400 V; and

c. Within 2.4 seconds following loadrejection, the frequency is x 58.8 Hzand s 61.2 Hz.;

24 months

4

.,SR 8 --- Th single test at the specified Frequency

will satisfy this Surveillance for bothunits. -

* ]atjfyx each DG.* .- does not trip an vo ge ismaintained s 5230 V during and following a

* .load rejection of 2 2400 kWand s 2600 ki.

24 months

(continued)

PBAPS UNIT 3 -3.8-10. Amendment No. 214

---

TSTF-276, Rev. 2

If performed with DG synchronized with o site power,-A it shall be performed at a power factor <-However, -if grid conditions do not permnt, power)''

*factor limit is not required to be met. 'Under thiscondition the power factor shall be maintained as close

INS 2

3. If perfo ed with DG synchronized with offsite powit shall be ormed at.a power factor< [0.9].However, if *d conditions do not permit, the erfactor limit is nequired to be met. Undercondition the powe actor shall be maintai as closeto the limit as practica

INSERT 3

Note 2 ensures that the DG is tested r load conditions that are as close to design basis conditionsas possible. When synchronized offs ower, testing should be performed at a power factor ofc (0.9]. This power factor is re sentative ode actual inductive loading a.DG would see underdesign basis accident conditio . Under certain Editions, however, Note 2 allows the surveillance tobe conducted at a power fac other than < [0.9]. e conditions occur when grid voltage is high,and the additional field ex ation needed to get the po factor to < [0.9] results in voltages on theemergency busses that too high. Under these conditio the power factor should be maintained asclose as practicable to .9] while still maintaining acceptable Itage limits on the emergency busses.In other circuinsanc , the grid voltage may be such that the D citation levels needed to obtain apower factor of [0 may not cause unacceptable voltages on the e gency busses, but the excitationlevels are in cxcs of those recommended for the DDG In such cases, power factor shall bemaintained as'ose as practicable to [0.9] without exceeding the DG exc on limits.

AC Sources-Operating-. 3.8.1

CIMICTI I Amrr DrnijTDrurMTC to-nn+4noonAl/un SUVELLIn1c nc6uAg% a Lul lluAuC F

* !. SURVEILLANCE. FREQUENCY-

SR .3.8.1.14 -------------------NOTES------------------1. Momentary transients outside the load

*and power factor ranges do notinvalidate this test.

power fa Ms~~i ~snerequired tobe met. U drfl-adition the. -.

<5 pwr~iM~r shall b ihRned as

3.. A single test at the specifiedFrequency will satisfy thisSurveillance for both units.

Veifyg each DGe perates or >24 hours: .

.a. For z 2 hours.loaded Z 2800 kW and* 3000 kW; and

24 months

b. For the remaining hours of the testloaded x 2400 kW and s 2600 kW.

(continued)


TSTF-276, Rev. 2

INSERT I

2. If performed with syn onized with offsite power,-it shall be performed a ower factor < [0.9].However, if grid co tion not permit, the powerfactor limit is nquired to b t. Under thiscondition th wer factor shall be ntained as closeto the li practicable.

,4ERT 2

A If performed with DG synchronized with offsitepower,it shall be performed at.a power factor_

* However, if grid conditions do not permit, the powerfactor limit is not required to be met. Under thiscondition the power factor shall be maintained as closeto the limit as practicable.

INSERT 3

Note 2 ensures.that the is tested under load co itions that are as close to design basis conditionsas possible. When syncbro ed with offsite po r, testing should be performed at a power factor of< [0.9]. This power factor is re esentative of actual inductive loading a DG would see underdesign basis accident conditions. der c conditions, however, Note 2 allows the surveillance tobe conducted at a power factor other .9]. These conditions occur when grid voltage is high,and the additional field excitation neede get the power factor to < [0.9] results in voltages on theemergency busses that are too high. der conditions, the power factor should be maintained asclose as practicable to [0.9] while emaintainiacceptable voltage limits on the emergency busses.in other circumstances, the grid tage may be suc hat the DG excitation levels needed to obtain apower factor.of [0.9] may not unacceptable volta on the emergency busses, but the excitationlevels are in excess of those commended for the DG. In ch cases, the power factor shall bemaintained as close as pr cable to [0.9] without exceeding DG excitation limits.

Responsibility- 5.1 ':


.' .1 'Responsibility / ''. . ..- '-

5.1I.1 shall-be responsible for overall unit operation.adsein w rtn h uccession to this'.

responsibility during his absence.. -. :

Th or his designee shall approve, prior topi pll i n, each proposed test, experiment; or modification to

systems or equipment.that affect nuclear safety.

5.1.2 The-Shift Supervisor shall be-responsible for the control roomcommand-function. During any absence of the Shift Supervisor from.the control room while the unit is in-MODE 1,'2, or 3, anindividual with an active Senior Reactor Operator (SRO) licenseshall. be designated to'assume'the control room-command function.During 'any absence of the-Shift Supervisor from the control room

* while the unit is in MODE 4 or 5, an individual with an active SRO'license or Reactor Operator license shall be designated to assumethe control room command function.


- Organization5.2


5.2 Organization

5.2.1 Onsite and Offsite Organizations

Onsite and offsite organizations shall be established for unitoperation and'corporate management, respectively. The onsite and.offsite organizations shall include the positions for activities-.affecting safety of the nuclear power plant.

'. ..' Linei.of authority, responsibility, 'and communication shall.4 Atkoseu be defined and established throughout highest management

levels,l'intermediate.levels, -and all operating organizationpositions. These relationships shall be documented and

eS updated, as appropriate, in organization charts, functionalo p,. of d escriptions' of departmental responsibilities and.* VA ff; a- relationships, and job descriptions: for key personnel

1woeJasA or in equivalent forms of documentation. TheseI fig e " requirements hall be documented in the UFSAR;

_shallbe responsible for overall safeoperation of the plant and shall have control over thoseonsite activities necessary for safe operation and

*) maintenance of the plant;

.. . _shallIhave corpor respon iiy for overall uInh nuclearsafety and shall.take any measures needed to ensureacceptable performance of the staff in operating,maintaining, and providing technical support to the plant toensure nuclear safety; and

.d. The individuals who train the operating staff, carry outhealth physics, or perform'quality assurance functions mayreport-to the appropriate onsite manager; however, these'individuals shall have sufficient organizational 'freedom toensure their independence from operating pressures.

5.2.2 Unit Staff,

The unit staff organization'shall also include the following:

(continued)

PB.APS UNIT 3 5.0-2 Amendment No. 214

Organization5.2

5.2 Organization

5.2.2 Unit Sta'ff. (continued) . . ./ |.

- The controls shall include guideV es o working hours thatensure adequate shift coverage s all be aintained withoutroutine heavy use of overtime.

Any deviation from the abov guidelines all be authorizedin advance by th lan a a e or the lanta-n a sdesignee, in accor approved admins rativeprocedures, and with documentation of the basis for grantingthe deviation. Routine deviation from the working hourguidelines shall not' be authorized.

-Controls shall be included in the procedures to require aperiodic independent review be conducted to ensure thatexcessive hours have not been assigned.

hS o i an r is 't7a shall |hold an 0licnse

f. An individual. shall provide advisory technical support to theunit operations shift crew.in the areas of thermalhydraulics, reactor engineering,, and plant analysis with

'regard to the safe operation of the unit. This individual* shall meet the qualifications specified by the Commission'' Policy Statement on Engineering Expertise on Shift.

*, A- .


Programs and Manuals' ' ' ' '' 5.5



The following programs shall be established, implemented, and maintained.

5.5.1 Offsite Dose Calculation Manual (ODCM :

a. The ODCM shall contain the methodology-and parameters usedin the calculation of offsite doses resulting fromradioactive gaseous and liquid.effluents, in the calculationof gaseous and liquid effluent monitoring alarm'and tripsetpoints, and in the conduct of the radiologicalenvironmental monitoring program; and

b. The ODCM shall also contain the radioactive effluent* controls and radiological environmental monitoring

activities, and descriptions of the information that'shouldbe included in the Annual Radiological Environmental

* Operating, and Radioactive.Effluent Release reports required.by Specification 5.6.2 and Specification 5.6.3.

* c. Licensee initiated changes to the ODCM:

1. Shall be documented and records of reviews performedshall be retained. This documentation shall contain:

Sufficient information to support the change(s)together with the appropriate analyses or evaluationsjustifying the change(s), and

A determination that the change'(s) maintain the levelsof radioactive effluent control required by10 CFR 20.1302, 40 CFR 190, 10 CFR 50.36a, and10 CFR 50, Appendix I, and not adversely impact theaccuracy or reliability of effluent, dose, or setpointcalculations;.

2. Shall become effective after review and acceptance bythe PlaJt r tons Review Committee and the approvalof the lanO'N anaesF and .

PBAPS UNIT 3 ' 5.0-7 Amendment No. 214

iI

0 1

.Programs and Manuals. 5.5E

5.5 Programs and.Manuals . '

:. : -5.5.1

5.5.2

5..

* Offsite Dose Calc ulation Manual(0CM) .:(contInued),.' e , .Dl '" 6 c

3.- Shaillbe submitted t t SheoriRh of a' complete , eg ble copy'of'the entireXODtM'sa-.a.part of

or. concurrent with the':Radoactive'Effluent ReleaseReport for the period of the report0 in which any change'nthe.ODCM.was made. Each change shall *be identified.by..markings, inthe argin of. the affect'ed'?pages..cleariyHindi'6ating the-.area ofthe. page that'.was. .:changed,:*and.'shallindicate.,the date (i.e4 month 'ahdyear) the change was implemented.

Primary Coolant Sources Outside Containment .

This program:provides controls.'to mini.mize leakage from -thoseportions'.of systems -outside containment that could. contain:,highlyradioactive fluids duringp a serious transient -or accident,to

: leveis':'as low 'practicab'te... The systemsi nciude: "ore:Spray,.-High Pre sure"Coolant-nctuon, Resiual. Heat Removal' Reactor 'Core.Isolatiobn oollng,;,andReactor Water Cleanup. The pro mshal 1include''the'.6folloW.ing:''

a. 'Prevent'ive rmaintenance. and.per.i6dic.,visual inspectionrequirements;.and : ' .:- . . . .. ' . '

b. System leak test requirements for each system, to the extent.:ermitted bysyste desi n di gc cs

r~~~1 ag z.4oR

I

(continued)

PBAPS UNIT 3 5.0- 8 Amendment No. 251


5.5 Programs and Manuals (continued)

5.5.6 Inservice Testing Program

This program provides controls for i Df EClass 1, 2, and 3 components ~program shall include the fol owing:

CodeThe

a. Testing frequencies specified in Section XI 'of the ASMEBoiler and Pressure Vessel Code and applicable Addenda areas follows:

ASME Boiler and PressureVessel Code andapplicable'Addenda.terminology forinservice testingactivities

Required Frequenciesfor performing'inservicetesting activities

WeeklyMonthlyQuarterly or every3 months

Semiannually or 'every 6 months

Every 9 monthsYearly or annuallyBiennially or every.*2 years

At least once per 7 daysAt leastronce per. 31 days

At least once per 92 days.

* AtAtAt

least onceleast onceleast once

per 184 daysper 276 daysper 366 days

per 732 days

the Frequencies

At least once

b. The provisions-of SR 3.0.2 are applicable tofor performing inservice testing activities;

c. The provisions of SR 3.0.3 are applicable to inservicetesting activities; and

d. Nothing in the ASME Boiler and Pressure Vessel Code shall beconstrued to supersede the requirements of any TS.

Ventilation Filter Testino Prooram (VFTP)5.5.7

The VFTP shall establish the required testing of Engineered SafetyFeature (ESF) filter ventilation systems.

Tests described in Specifications 5.5.7.a, 5.5.7.b, and 5.5.7.cshall'be performed:

(continued)




.5.5.9 Diesel Fuel Oil Testing Proaram (continued)

* a. Acceptability of new fuel oil for use prior tostorage tanks by determining that the fuel oil

addition tohas:

1. ..an API gravity or an absolute specific gravity withinlimits,

2. kinematic viscosity, when required, and awithin limits for ASTM 2-D fuel. oil, and

flash point

3. a clear and bright appearance with proper ccwater and sediment content within limits; '

olor or a

t and

Total particulate concentration of the fuel. oil irtDfiwhen'tested.every 31 days in accordance with ASTM.D2276,Method A, except that the filters specified in the ASTMmethod may'have a nominal pore size of up to three (3)microns._1_j -

I =. : -. ,-

5.5.10Techni

This pof the

cal Specifications (TS) Bases Control Proaram

program provides a means for processing changes to the Bases!se Technical Specifications.

* a. Changes to the Bases of the TS shall 'be made underappropriate administrative controls and reviews.

-b. Licensees may make changes to Bases without prior NRCapproval provided the changes do not involve either of the

, following:

* A change in the TS incorporated in the license; or

A change to the UFSAR or Bases that requires NRC approvalpursuant to' 10 CFR 50.59.

c. The Bases Control Program shall contain provisions to ensurethat the Bases are maintained consistent with the UFSAR.

1 -- 4 -a -s-- -- ~ AD- ' - JcJSipnued)

X pvovis;p 4 , S - 3O-zo7. st 30.3 4b ki 6" -O"r a/ 7_061V P100 kb eis) 79d Pers

PBAPS UNIT 3 5.0-15 Amendment No. .-4, 246


5.0 ADMINISTRATIVE CONTROLS'


The following reports shall be submitted in accordance with 10 CFR 50.4.

5.6.1 OccuDational Radiation Exposure Report

. ____________ ------… NOTE-------------------------------A. single, submittal may be made .for a multiple unit station. Thesubmittal should combine sections common to all units at the

* :station.

.. adother ppfnnel (incl m contr; tors')_peiving j-a'' ual* deep dose quivalent > 0 mrem and the ociated coll ive deep

,-~ -~../ dose e tialent (r Dfed-i~n-person--r~aDacording t ~rk'and job^,acrd/ fun tins (e.g., fator operatioprfand surveillaJHE inservice

c pection, ro me maintenan , special maint ance (descri eC C maintenance , waste proces g, and refueli . This tabu on

suppleme the requirepe ts of 10 CFR 2 . 206' The dassign nts to vario W duty functions ay be estima based onpock dosimeter, ermoluminescen dosimeter ), or filmb e measureme s. Small exposres totalli • 20% of the_ndividual tt1 dose need n be accounte for. In theaggregate, t least 80% of he total de dose equivale receivedfrom-ext nal sources shuld be assi edto specific 0jor workfunctions. The repor shall be su itted by Marc1 of each

5.6.2 Annual Radiological Environmental Operating Revort .

- -.- NOTE…-------------- ------- …NOTE ---------------------------…A single submittal may be made for a multiple unit station'. Thesubmittal should combine sections common to all units at the

* station.

The Annual Radiological Environmental Operating Report coveringthe operation of the unit during the previous calendar year shallbe submitted by May .31 of each year. The report shall includesummaries, interpretations,. and analyses of trends of. the resultsof the radiological environmental monitoring activities. for the.reporting period. The material provided shall be consistent withthe objectives outlined in the Offsite Dose Calculation Manual(ODCM), and in 10 CFR.50, Appendix 1, Sections IV.B.2, IV.B.3,and IV.C.

(continued)

.. PBAPS UNIT 3 * 5.0-19 UAmendment No. 2i4 219

A tabulation onan annual basis ofthe numberof stationudlWtyand other personnelI(inchiding contractors), for whom monitoring was performed, receivnng an annual deepLdose equivalent >~ 100 mrems and the associated collective deep" dose eqialent (reportedin person - rem) according to work and job functions (e.g., reactor operations andsurveillance inservice inspection, routine maintenrance, special maintenance [descnbemaintenanc], waste processing. and refueling). This tabulation supplenents therequirements of 1O CFR20.2206. The dosc assignments to various dutyfinctions may beestaite~d based on pocket ionization chamber, thermoluminescence dosimeter (TLD),electronic dosimeter, or film badge measurements. Small ekposures totaling < 20 percentof the individuil total dose need Dot be accounted for. In the aggregate, at least 80 :perceit of the total deep dose equivalent received from external sources should becassined to specific myijor work functions. The report covering the previous calendar year. .shall bsubmitted by Apr30ofcachyear. _ r.

.-I. 7,

4

I. , -

i ..

* Reporting Requirements5.6


5.6.2 Annual Radiological Environmental Operating Revort (continued)

The Annual Radiological Environmental Operating Report shall. include the results of analyses of all radiological environmental

samples and of all environmental radiation measurements takenduring the period pursuant to thelocatlons'specified in the tableand figures in the ODCK, is well 'as summarized and tabulatedresults of these analyses and measurements in the format of. thetable in the Radiologicl 'Assessment Branch Technical Position,

* Revision 1, November 1979. . In the event that some individualresults are not available for inclusion'with the report, thereport shall'be submitted noting and explaining the reasons forthe missing results... The missing data shall be submitted in asupplementary report as soon as possible.

5.6.3 Radioactive Effluent Release Report

…-----…-----------------------…---NOTE----------- ------ -------------A single submittal may 'be made for a multiple unit station. Thesubmittal cbmbine sections common to all units at thestation. 'A5:)

* The Radioactive Effluent Release Report covering the operation ofthe unit' during the previous year shall be submitted prior to ..Kay 1 of each year in accordance with 10 CFR 50.36a. The reportshall include a summary of the quantities of radioactive liquidand gaseous effluents and-solid.waste'released from the-unit. Thematerial provided shall be consistent with the objectives outlinedin the ODCM and Process Control Program and in cohformance with10 CFR 50.36a and 10 CFR O, Appendix I, Section IV.B.1.

:~~1 . .

5.6.4 Monthly Operiting Reports

Routine reports of operating statistics and shutdown experienceshall be submitted on a monthly basis no later than the 15th ofeach month following' the calendar month covered by the report.

(continued)

.PBAPS UNIT 3 .5.0-20 Amendment No. li\4219


BASES (continued)

SAFETY LIMITS The reactor core SLs are established to protect theintegrity of the fuel clad barrier to the release ofradioactive materials to the environs. SL 2.1.1.1 andSL 2.1.1.2 ensure that the core operates within the fueldesign criteria. SL 2.1.1.3 ensures that the reactor vesselwater level is greater. than the -top of the active irradiatedfuel' in order to prevent elevated clad temperatures andresultant clad perforations.

APPLICABILITY ' SLs 2.1.1.1, 2.1.1.2, and 2.1.1.3 are applicable in allMODES.


Exceeding an SL may cause fuel amage and create a potentialfor radioactive releases'in'ess of 10 CFR 100, OReactorSite Criteria," limits (Ref. Therefore, it is requiredto insert all insertable control rods -and restore compliancewith the SLs within 2 hours. The 2 hour Completion Timeensures that the operators take prompt remedial action andalso ensures that the probability of an accident occurringduring this period is minimal..

* If any SL is violated, the senior manaqement of the nucleaI plant and the utility sh be not ed within 24 hours.''

The 24 hour period provides or plant operators andstaff to take the appro e iiate action and assessthe condition of nit before repo ng to the seni r

. anagement.

(continued)

PBAPS UNIT 3 B 2.0-5 A N5Revision No. 0

* Reactor Core SLs.B 2.1.1

BASES

VIOLATIONS . . ,- .X(continued) If SL is violated, a LicenseeE ReportEshall

prepar and submitted-within 30 ys to the NRC inaccordance th 10.CFR 50.73 f. 5). A copy.of the reportshall also be. vided to e senior management of theLnuclear plant and ity.

If any SL violated, restart of the tshall notcommenc ntil authorized by the NRC. Thi equirementensur the NRC that all necessary reviews, an ses, andac ns are completed before the unit begins its restart to

REFERENCES. 1. EIEF-93-115 (P), July 1993.

2. NEDE-24011-P-A-10, February 1991.

7 10 CFR 100.

ffl3!

PBAPS UNIT 3 B 2.0-6 URevision No. 0

I

RCS Pressure SL. -B 2.1.2

j . . ..BASES

APPLICABLE The RCS pressure SL has been selected such that it is at aSAFETY ANALYSES pressure below which it can be shown that the. integrity of

(continued) the system is not endangered. The reactor pressure vessel' is designated to Section III, 1965 Edition of the ASME,

Boiler.and Pressure Vessel Code, including'Addenda through- the summer of 1966 (Ref. .5), which permits a maximum''r'essure transient of 110%, 1375 psig, .of design pressure.I' 1250 psig.. The:SL of^1325 psigg as measured in the reactor

m wr;~ a<steeam .dome, is-equ'ivalent to 1375'psig'at the lowest- elevation of the RCS. The RCS is'designed to ASME Section

III, including.Addenda through the winter of 1981.'(Ref. 6),for the reactor recirculation piping, which permits amaximdm pressure transient of110%.of design-pressures of .

1250 psig for-suction.piping and 1500 psig for dischargepiping. The RCS pressure SL is selected'to be the lowesttransient overpressure 'allowed by' the applicable codes.

V7

I

. . .. F

I

t

II

t

SAFETY LIMITS The maximum transient pressure allowable in the RCS pressurevessel under the ASME Code, Section III, is 110% of design

* pressure. The maximum transient pressure allowable .in the' ' RCS piping, valves, and'fittings is 110% of'design pressures

of 1250 psig for suction piping and 1500 psig for dischargepiping. The most limiting of these allowances is the 110%of design pressures of 1250 psig; therefore, the SL onmaximum allowable RCS' pressure is established at 1325 psig* s measured at the reactor steam dome.

APPLICABILITY SL`2.1.2 applies in all MODES.


* fany -Ts Ji o athe ORC iat'ion ~inter matt be cno ed witi Ur., c'a ih 10 50o.72

(continued). I.

PBAPS UNIT 3 B.2.0-8 Revision No. 0


BASES


(continued) Exceeding the RCS pressure SL may cause immediate RCSfailure and create a potential for radioactive releases inexcess of 10 CFR 100, "Reactor Site Criteria," limits(Ref. 4). Therefore, it-is required.to insert all

* insertable control rods and restore compliance with the SL*within 2 hours. The 2 hour Completion Time ensures that theoperators take prompt remedial action and also assures that.the probability of an accident occurring during the periodis minimal.

If a K L is violated, the senior managemenZt ofofhe nucl 6a( plantad the utility shall be notifiedi wihiJ24 hours. .A

* \WrThe 24 h period provides' time for plant Xerators and. .staff to t ethe-appropriate immediate ac1_o and assess,the conditio f the unit before reporti *to the seniormanagement.

If any SL is violated, Lice ee Event Report shall beprepared and submitted wi 30 days to the NRC inaccordance with 10'CFR50 (Ref. 8).. A copy of the reporshall also be provided th senior management of thenuclear plant and the tility.

* If any SL i violated, restart of the u t shall not(. commence @hil. authorized by the NRC . Ths requirement

ensure he NRC that all necessary reviews nalyses, and'acti s are completed before the unit begins its restart to

REFERENCES 1. UFSAR, Sectionc.

.2. ASME, Boiler and Pressure Vessel Code, Section III,Article NB-7000.

(continuedl

PBAPS UNIT 3 a 2.0-g Revision No. 0

RCS Pressure SL. B 2.1.2

BASES

REFERENCES(continued)

3. ASME, Boiler and Pressure Vessel Code, Section XI,Article IW-5000..

4. 10 CFR 100.

5. ASME, Boiler and Pressure Vessel Code, Section III,1965 Edition, including Addenda .to summier of .1966.

6. ASME, Boiler and Pressure Vessel Codej Section III,1980 Edition, Addenda to winter of 1981.

f0I

PBAPS UNIT 3 B. 2.0-10 IRevision No. 0


BASES (continued)

SURVEILLANCE. The four SRs of this LCO are modified by a Note stating thatREQUIREMENTS during a single control rod scram time surveillance, the CRD

pumps shall be isolated from the associated scramaccumulator. With the 'CRD pump isolated, (i.e., chargingvalve closed) the.influence of the CRD pump head does notaffect the single control rod scram.times. During a fullcore scram, the CRD pump head would be seen by all controlrods-and would have a negligible effect on the scram.

- .insertion times;

SR 3.1.4.1

* The scram reactivity used in DBA and transient analyses. isbased on an assumed control rod scram time. Measurement of

* the scram times with reactor steam dome pressure * 800 psigdemonstrates acceptable scram times for the transients-analyzed in References 3 and 4.

Maximum scram insertion times occur at a reactor steam domepressure of approximately 800 psig because of the competingeffects'of reactor steam dome pressure and storedaccumulator energy. Therefore, demonstration of adequatescram times at reactor steam dome pressure > 800 psigensures that the measured scram times will be within thespecified limits at higher pressures. Limits are specifiedas a fuhction of reactor pressure to account for the

* sensitivity of the scram insertion times with pressure andto allow a range of pressures over which scram-time testingcan be performed. To ensure that scram time testing is

~d w ii a reasoQnab Jim after.

120 drays or longer, al conol rods are required to betested before exceeding 40% RTP. This Frequency isacceptable considering the additional surveillances.

* performed for control rod OPERABILITY, the frequent* .verification of adequate accumulator pressure,:and the

required testing of control rods affected by work on conrods or the CR0.System.

SR 3.1.4.2

Additional testing of a sample of control rods is requiredto verify the continued performance of the scram functionduring the cycle. .A representative sample contains at least10% of the control rods. The sample remains representative

(continuedl



BASES

SURVEILLANCE' SR 3.1.4.3 (continued)REQUIREMENTS

Specific examples of work that could affect the scram timesare (but are not limited to) the following: "removal of any.CRD for maintenance or modification, replacement of 'acontrol rod; and maintenance. or modification of a scramsolenoid pilot valve, scram valve, accumulator, isolationvalve or check valve in the piping required for scram.

The Frequency of once prior to declaring the affectedcontrol rod OPERABLE is acceptable because of the capabilityto test the control rod over a range of operating conditionsand the more frequent surveillances on other aspects ofcontrol rod OPERABILITY.

SR 3.1.4.4:'

When work that could affect the scram insertion time isperformed on a control rod or CRD System, or when fuelmovement within the reactor vessel occurs testing must bedone to demonstrate each affected control rod is stillwithin the limits of Table 3.1.4-1 with the reactor steamdome pressure k 800 psig. Where work has been performed athigh reactor pressure, the requirements of SR 3.1.4.3 and*SR 3.1.4.4 can be satisfied with one test. For a controlrod affected by work performed 'while shut down, however, azero pressure and high pressure test-may be required. Thistesting ensures that, prior to withdrawing the control rod'for continued operation, the control rod scram performanceis acceptable for operating reactor pressure conditions.Alternatively, a. control rod. scram test.during hydrostaticressure testing could al o atisfy both criteria' When.

nr4 54tsst (tfue- movemient occur4C I only those control rods* 4~associated with the.core.cel*s ae d wh e &f4ved-ea

- tr)- tacceptable because of the capability to test the control rodover a range of operating conditions and the more frequent

* surveillances on other aspects of control rod OPERABILITY.

REFERENCES 1. . UFSAR, Sections 1.5.1.3 and 1.5.2.2.


(continued)


SDV Vent and Drain Valves.B 3.1.8

BASES

APPLICABLE . initrument vol ume exceeds .. specified setpoint-,. TheSAFETY 'ANALYSES setp6ionti..,s.-hosenso 'that' all control *-ods are .i serted

(continiued) beffre the.SWV ha s insutf-icie't volume to accejt a fu11scram.

SDV.vent and..drain valves satisfy Criterion 3 of the NRCPolicy Statement..

LCO The OPERABILITY if l SDY. vefitaid drain valves eniuresthat 1 Sra:

te- O-* 'pip 3t6 it'Y.

.. . , .~ * . . 4 '. ,* ;:'-. ; -;'.;

APPLICABILITY In MODES 1 and 2, s rtm-ay p be ei d;. thef , the-.SDVventaind drainb vah'I i s: t be OPERB LE.. In MO(ES 3 a dA4,contrt rods..,are.t nbk. *to bp *i$thdrawn since thereactor* i~de svit~h is in iiutd trand a control rod block.isc :applied.. 'This pa.JE-4dequate Controls t6 ensure thatonly a singlp contcrqid tan be withdrawn. Also, duringMODE 5, only- i sinle controlFiod can be withdia"n from acore .cell -contafhI*n. fuel. asieiblies. .TherWeor th SDV*Vent and dra~in valvs tare no requbi'ed to bE OPERABLE inthese- ODES sinc&-the r6_1ir is. subcri'tical and only one*. rod nay ie wltidrawb and subject 'to scram.

.. , ... - ... . . . J

ACTIONS The ACTIONS Table is modified by f~otefindicating that. .aseparate Condition entry is allowed for each SDV vent anddrain line. This is acceptable, since the Required Actionsfor each Condition provide appropriate compensatory actionsfor each inoperable SDV line. Complying with the Required'Actions may allow for continued operation, and subsequentinoperable SDV lines are governed by subsequent Condition

7T N55?Tfrfbr en try and application of associated'Required Actions.

(continued)

PBAPS UNIT 3 B 3.1-49 Revision No. O

SDV Vent and Drain. ValvesB 3.1.8 '

) BASES . . . . . .

exis sto a 'floit re act or- wato r .6 ut ' 6 t h e p m ry te.duir'i 9Ig~a' S-64.:.'..

If ~ th alv s2I ,~ a h u e '~k e nope ra7V~ th b~ ltnre '-m u st b .0 6~td ' t o sdt lo l it : tr nttb 11 - 0u 1 t-c k -J .0 -..a -t '

adiiiist -t'$veac&ntrol This allows any actmu'lated waterJn:the'lifieto b64d'ained, to preclude a reactor scrnam onSDV high l'ev41.; This is.Acceptable since the .administritivecontrols ensure the'valve can.be closed quickly', by adedicated operatoi.if a scram occurs rIth;the val-ve.open

The..8 hour C otpletion Time to.isolate the line is based. on.the lowprobabillty of a scram occurring while the"line isnot isolated and unlikelihood of significant CRD'seal''leakage.

C.1I

If -any Required Action and associated Completion Time is notmet, the plant must be brought to a MODE in which the LCOdoes not apply. To achieve this status, the plant must bebrought to at least MODE 3 within 12 hours. The allowedCompletion Time of 12 hours is reasonable, based onoperating experience, to reach MODE 3 from full powerconditions in an orderly manner and without challengingplant systems.

(continued)


MCPR'B 3.2.2

BASES

.SURVEILLANCE:REQUIREMENTS

SR 3.2.2.1 (continued)''

in the COLR to ensure that the reactor is operating withinthe assumptions of the safety analysis. The 24 hourFrequency is based on both engineering judgment andrecognition of the slowness of changes in power distributionduring normal operation'. The 12 hour allowance afterTHERMAL POWER ; 25% RTP is achieved is acceptable given thelarge inherent margin to operating limits at low powerlevels.

'SR 3.2.2.2

Because the transient analysis takes credit for conservatismin the scram speed performance, it must be demonstrated thatthe specific scram speed distribution is consistent withthat used in. the transient analysis. SR 3.2.2.2 determinesthe value of r, which is'a measure of the actual scram speeddistribution compared with the assumed distribution. "TheMCPR operating limit is then determined based on aninterpolation between the applicable limits for Option A(scram times of LCO 3.1.4,'Control Rod Scram Times') andOption B (realistic scram times)' analyses. The parameter rmust be determined once within 72 hours aft setscram time tests required by SR 3.1.4.1 6jYSR3.1.4.2 t.._because'te ective scram speed distribution may change N

during thecycle The'72 hour Completion Time is acceptabledue to the relatively minor changes in r expected during thefuel cycle.

REFERENCES 1. NUREG-0562, June 1979.

2. NEDO-24011-P-A-10, 'General Electric StandardApplication for'Reactor Fuel,' February 1991.




6. NEDO-24229-1, Peach Bottom Atomic Power Station Units2 and 3, Single Loop Operation," May 1980.

(continued)


Feedwater and Main Turbine High Water Level Trip InstrumentationB 3.3.2.2

BASES

ACTIONS B.!. (continued)

signal on a valid signal. This requires-one channel pertrip system to be OPERABLE.or in trip. If the required-channels cannot be restored to OPERABLE status or placed intrip, Condition C must be entered and itsRequired Actiontaken.

' The 2 hour Completion Time is sufficient for the operator too>f; g Ca i take corrective'action, and takes into account the

c.. Atofe SJie likelihood of an event requIring actuation of feedwater andV main turbine high water. level trip instrumentation occurring.

* during this period. It is also consistent-with the 2 hourw1$ t ti +@C '4 JCompletion Time provided in LCO.3.2.2 for Required

E tf wk Action A.1, since this instrumentation's purpose is _-Fed--,t reclude a MCPR violat ( .e

e 44-c. With any Requi ed Act ssocil etion Time notV u A 4Y0 met, the pla must brought to a MODE or other specified

0oc Rce, 0 k) condition i which the LCD does not apply. To achieve thisbc status, THI L POWER.must be reduced:to < 25% RTP within

A -'O 4 hours. As discussed in the Applicability section of theh v Acw oi 2 Bases, operation below 25% RTP results in sufficient margin

to the required limits, and the feedwater and main turbinehigh water level .trip instrumentation is not required toprotect, fuel integrity during the feedwater controllerfailure, maximum demand event. The'.allowed Completion Timeof 4 hours is based on operating experience to reduceTHERMAL POWER to < 25% RTP from full power conditions in anorderly manner and without challenging plant systems.

SURVEILLANCE The Surveillances are modified by a Note to indicate. thatREQUIREMENTS when a channel is placed in an inoperable status solely for

' performance of required Surveillances; entry into associatedConditions and Required Actions may be delayed for up to6 hours provided the associated Function maintains feedwaterand.main'turbine high water level trip capability. Uponcompletion of the Surveillance, or expiration of the 6 hourallowance, the channel must be returned to OPERABLE statusor the applicable Condition' entered and Required Actionstaken. This Note is based on the reliability analysis(Ref. 2) assumption of the average time required to.perform

(continuied)..-..-


PAM InstrumentationB 3.3.3.1

BASES

LCO 7. Drvwell High Range Radiation(continued)

Instruments: RR-9103 A, B (Green Pen)

Drywell high range radiation is a Category I variableprovided to monitor the potential of significant radiationreleases and to provide release assessment for use byoperators in determining the need to invoke site emergencyplans'. Post accident drywell radiation levels are monitoredby four instrument channels each with a range of 1 to 1xI0R/hr. These radiation monitors drive two dual channelrecorders located in the control room. Each recorder andthe two associated channels are in a separate division. Assuch, two recorders and two channels of radiation monitoringinstrumentation (one per recorder) are required to beOPERABLE for compliance with this LCO. Therefore, the PAMSpecification deals specifically with these portions of theinstrument channels.

8. Primary Containment Isolation Valve (PCIV) Position

PCIV position is a Category I variable provided forverification of containment integrity. In the case of PCIVposition, the important information is the isolation statusof the containment penetration. The LCO requires onechannel of valve position indication in the control room tobe OPERABLE for each active PCIV in a containment.penetration flow path, i.e., two total channels of PCIVposition indication for a penetration flow path with 'twoactive valves. For containment penetrations with only oneactive PCIV having control room indication, Note (b)requires a single channel of valve position indication to beOPERABLE. This is sufficient to redundantly verify theisolation status of each isolable penetration via indicatedstatus of the active valve, as applicable, and priorknowledge of passive valve or system boundary status. If apenetration flow path is isolated, position indication forthe PCIV(s) in the associated'penetration flow path is notneeded to determine status. Therefore, the positionindication for valves in an isolated penetration flow pathis not required to be OPERABLE. The PCIV position PAMinstrumentation consists of position switches, associatedwiring and control room indicating lamps for active PCIVs(check valves and manual valves are not required to haveposition indication). Therefore, the PAM Specificationdeal:s specifically with these instrument channels.

~ontizued)

PBAPS UNIT

ATWS-RPT InstrumentationB 3.3.4.1

BASES

ACTIONS D.1 and D.2 (continued)

6 hours is reasonable, based on operating experience, bothto reach MODE 2 from full power conditions and to remove arecirculation pump from service in an orderly manner and-without challenging plant systems.

(SURVEILLANCE The Surveillances are modified by a Note to indicate thatREQUIREMENTS when a channel is'placed in an inoperable status solely for

performance of required Surveillances, )entry.into the. -associated Condition's and Required Actions may be delayed

A a , .1 IO for up to 6 hours provided the associated Function maintains'i, g r ATWS-RPT trip capability. Upon completion of the.dbej A v Surveillance, or expiration of the 6 hour allowance, the

fe 491Y9lI rchannel must be returned to OPERABLE status' or thepplicable Condition entered and Required Actions taken.

9 < 'flf nC(. his Note is based on the reliability analysis (Ref. 1):el V s umption of the average time required to perform.channel

v S rveillance. That analysis demonstrated that'the 6 hourM'44 te sting allowance does not significantly reduce the

break< obability that the recirculation pumps will trip' whenecessary.

SR 3.3.4.1.1

An + Performance of the CHANNEL CHECK once every 12 hours . ensures./ that a gross failure of instrumentation has not occurred. A

CHANNEL CHECK is normally a comparison of the parameterindicated on one channel to a similar parameter on otherchannels. It is based on the assumption'that instrumentchannels monitoring the same parameter should readapproximately the.same value. Significant deviationsbetween the instrument channels could be an indication bf'excessive instrument drift.in one of-the channels orsomething even.more serious. A CHANNEL CHECK will detectgross channel failure; thus, it is key to verifying theinstrumentation continues to operate properly between eachCHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff basedon.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.

' . (continued}

PBAPS UNIT 3 B' 3.3-90- Revision No. 3


BASES

ACTIONS

With one or more channels inoperable, but with EOC-RPT tripcapability maintained (refer to Required Action B.1 Bases),the EOC-RPT System is capable of performing the intendedfunction. However, the reliability and redundancy of. theEOC-RPT instrumentation is reduced such that a singlefailure in the remaining trip system could result in theinability of the EOC-RPT System to perform the intendedfunction. Therefore, only a limited-time is' allowed torestore compliance .with the LCO. Because of the diversityof sensors available to provide trip signals, the lowprobability of extensive numbers of inoperabilitiesaffecting all diverse Functions,.and the low probability ofan event requiring the initiation of an EOC-RPT, 72 hours isprovided to restore the inoperable channels (RequiredAction A.1). Alternately, the inoperable channels may beplaced in trip (Required Action A.2) since this wouldconservatively compensate for the inoperability, restore

,W 1 29JtI capability to accommodate a sin le failure, and allowoperation to continue. As note ~placing the channel in

,d I) _ trip with no further restrictions is not allowed if theinoperable channel is the result of an inoperable breaker,since this may not adequately compensate for the inoperablebreaker (e.g., the breaker may be inoperable such that itwill not open). If it is not desired to place the channelin trip (e.g., as in the"case where placing the inoperablechannel in trip would result in an RPT, or if the inoperablechannel is the result of an inoperable breaker), Condition Cmust be entered and its Required Actions taken.

B.1

Required Action B.1 is intended to ensure that appropriateactions are taken if multiple, inoperable, untrippedchannels within the same Function result in the Function notmaintaining EOC-RPT trip capability. A Function isconsidered to be maintaining EOC-RPT trip capability whensufficient channels are OPERABLE or in trip, such that theEOC-RPT System will generate a trip signal from the givenFunction on a valid signal and both recirculation pumps canbe tripped. This requires two channels of the Function inthe same trip system, to each be OPERABLE or in trip, andthe associated EOC-RPT breakers to be OPERABLE.

(continued)

PBAPS UNIT 3 B 3.3-92f Revision No. 28

**' . .

EOC-RPT Instrumentation

* .. . . . ; , .; ,' -. 'EOC-RPT.In~strument'ati on'. B 3.3.4.2

*K' ) BASES ... .':

-ACTIONS - .continued3.:

The 2 hour Completion i;..ime is suf~ficie'nt':time for the",* 'perator-,t otake cor'rective' action', andtakes into .accountbtte likelihood of.an'event ..reqUi ring -actuation'.of.the' .EOC-RPT instrumentation durirgnthis period..It :is aso'.con'sistbent .wththe2'hour, CompletionT-i'm 'provided inLCO 3.2: ' and..2.2:for Requi'red'Action A.i, since:. thisinstrumenta io'n's 'purpose '.' '' ei. c de a.,'h.the r'mal 1i t.

....With 'any Requir~ d jAction and associatedi ompletibn Time ot*. .' ' : -. me't, THERMAL.POWERiimust'be'bredLcecf to,<'29.5Z Twi;"i h :-4 -'. .. '. . . . : hours. Al a -for, anoerblebreaker'.e.g', :the'';.breker rmayIb sii'npu'rh-ble'suchthatit willendtoeop the

*.-'associatd r.eti~ulatep rpcay',-be .rern~ved-from service,.:-sice ths -per~t r iXt~e. nt'eiid; ti0 'fte : : o:. -

: Th Wed Ccdrpi eti oh','-Timeto'f: '4 hour"s's :' '.'reason'abie'6bei W'Xprati' ng, ipe'ien c'e .'reduce';.THERMAL'...' . . - POWER:t'oc29 5ZP f'rom- full power-co iditions ' ah: orderly'imanner 'nd withoti' llenging-pla ystem'

.I - Ib.-. . .. - ;:0 1 :: : a. t.-t s - em ' :- - . . .: - .*

SURVEILLANCE'. -The Sur.veillances.-are.modif-ied by a -Note to-indicate thate-REQUIREMENTS . wh~epachnnel, is eid v an*- '...v:':r... ormtins-anc~ie f-direqu Ir ios~ay e delayed or-; '..t -;' ;.' :. ' . :.6h-r.*ro:.dee';h'nasciatdFun ti'o. 9ai'nitoais'Eoc- Pa .'..::

s-and l nore'upe-'to

'. , ., - .. ,.'' .:' -trip' ca'pabili~ty' sUp' compie~ti~ono'f .t'e''Sur~veillan'c, -or. '''''-, .' '' .', -. ex~pirati,'cin-of 't1~he,'.odr,' alflaowance,'rthe :ch~anel mus't .be^'' ' ..'' ' - ' returned to,'OPERABLE.'status':or .the 'applicable'Con'dition ' --..''enteredand RequiredActionstaken.,This.'oteis based on- '~the reliability'analysis .(Ref.''5) assumnption'of. the average..'time req'uired tope'rfbrmch'annel Su'r'eilane. 1 .Tat''.. . ,~~~analysis demonstrated.'that the6 6hour testing allowance'does ............................"'not significantlyreducethe probabi'lity thatthe ,

* .'recirculation'pumps-'will tr ' csal)o(cntiued

B..APS UNIT 3B -3.39i- ' Re ision N 4r5

' -expra io,,<,o4 C>ro a e,.c anne 6rus e4 .:returned 6sPRA~t-t atues e s;7q4" orhCthe ap;l a ffi c25Soondiii' g

)t- ---n a --- ,jef-S -a.s'(cotinuedth _eib~l . of t

PBAP UNIT 3nn B a2 Reviio at 4


BASES-

APPLICABLE with.their setpoints within the specified AllowableSAFETY ANALYSES, Values, where appropriate. The actual setpoint isLCO, and calibrated consistent with applicable setpoint methodologyAPPLICABILITY agsimpjl on . otnote.(b),Zis added to(continued) ,--"show that certitrumentation Functi ons (gfi also

perform DG initiation.

b 41,. fj Is. E~ve OCA lowable Values are specified for each ECCS Functionecified in.the Table. Trip setpoints are specified in'

{ o) , ?)e -odat - he setpoint calculations. The trip setpoints are selectedTwssuc-to ensure that the settings do not'exceed the Allowable

* ) d e. tValue between CHANNEL CALIBRATIONS. Operation with a trip.cre yvL'tr A setting less conservative than the trip setpoint, but withinort-- p LE Vo its Allowable Value, is acceptable. A channel is inoperable

. *' A cif its actual trip.setpoint is not within its required'Allowable Value. 'Trip 'setpoints are those predetermined

r'>aOtrpec art nalues'of output at which an action should take place. The1' osetpoints are compared to the actual.-process parameter.b - ' , (e:g., reactor vessel water level), and when the'measured

* L UO g*:. , 1C h . output.value of the process parameter exceeds the setpolnt,the associated device (e.g., trip unit) changes state. ' The

s 3A r1 a no * . analytic or design limits are derived from the limiting'values of-the process-parameters obtained from the safetyanalysis or other appropriate documents. The Allowablevalues are derived from the analytic or design limits,'.corrected for calibration, process, and instrument errors.The trio setpoints are determined from analytical or designlimits, corrected for calibration, process, and instrumenterrors, as well as, instrument drift; In selected cases,the Allowable Values and trip setpoints are determined fromengineering judgement.or historically accepted practicerelative to the intended functions of the-channel. The trip'setpoints determined in this manner provide adequateprotection by assuming instrument and process uncertainties

* expected for the environments during the operating time ofthe associated channels are accounted tor. For the CoreSpray and LPCI Pump Start-Time Delay Relays, adequatemargins for applicable setpoint methodologies are

' incorporated into the Allowable Values and actual setpoints.

In general, the individual Functions are required to beOPERABLE'in the MODES or other'specified conditions that mayrequire ECCS (or DG) initiation to mitigate the consequences-of.a design basis transient or accident. To ensure reliable,ECCS and DG function, a combination of Functions is requiredto provide primary and secondary initiation signals.

(continued)

.PBAPS UNIT 3 -B 3.3--100 Revision No. 3

. ECCS InstrumentationB 3.3.5.1

BASES

APPLICABLE The specific Applicable Saifety Analyses, LCO, andSAFETY ANALYSES, Applicability discussions are listed below on a Function byLCO,' and Function basis.APPLICABILITY

(continued)* Core SDray and Low Pressure Coolant Iniection Systems

I.a. 2.a. Reactor Vessel Water Level- Low Low Low (Level 1)

*Low reactor pressure vessel (RPV) water level indicates thatthe capability to cool the fuel may be threatened. Should

* - RPV water level decrease too far, fuel damage could result.The low press'ure ECCS and associated DGs are initiated atReactor Vessel' Water Level -Low Low Low (Level 1) to ensurethat core spray and flooding functions are available toprevent or minimize.fuel damage. The DGs are initiated fromFunction 1.a signals. This Function, in conjunction with aReactor Pressure-Low (Injection Permissive) signal, alsoinitiates the closure of the Recirculation Discharge Valvesto ensure the LPCI subsystems inject into the proper' RPVlocation.' The Reactor Vessel Water Level-rLow Low-Low(Level 1) is one of the Functions assumed to be OPERABLE andcapable of initiating the .ECCS during the transientsanalyzed in References 1 and 3. In addition, the ReactorVessel Water Level - Low Low Low (Level 1) Function isdirectly assumed in the analysis of the recirculation linebreak (Ref. 4) and the control rod'drop accident (CRDA)analysis. The core cooling function of the ECCS, along withthe scram action of the Reactor Protection System (RPS),'ensures that the fuel peak cladding temperature remainsbelow the limits of 10 CFR 50.46,

Reactor Vessel Water Level -Low Low Low (Level 1) signalsare initiated.from four level transmitters that sense thedifference between the pressure due to a constant column ofwater (reference leg) and the pressure due to the actual:water level (variable leg) in the vessel.

The Reactor Vessel Water Level -Low Low Low (Level.1)Allowable.Value is chosen to allow time for the low pressurecore flooding systems to activate and provide adequatecooling.,

Four channels of Reactor Vessel Water Level -Low Low Low(Level 1) Function are only required to be OPERABLE when theECCS are required to be OPERABLE to ensure that nosingle instrument failure can preclude ECCS

(continued)


4adre d 4t 6e'orF W. E ECCS umentation

*O , (fc up ; 5 t vs¢^t 3..-3..1s tJ 4SC L4

BASES.'

APPLICABLE- l.a. 2.a. Re ctor Vessel Water Level -Low Low Low (Level 1)SAFETY ANALYSES, (continued)LCO, 'and . ... .APPLICABILITY initiation. Refer-to LCO 3.5.1 and LCO 3.5.2, 'ECCS-

Shutdown," for Applicability Bases for the low pressure ECCSsubsystems; LCO 3.8.1, "AC Sources-Operating'; andLCO 3.8.2, 'AC Sources-Shutdown," for Applicability Bases

* for the DGs.

1.bi.2.b. Drvwell Pressure-High

High pressure in the drywell could indicate a break in the* reactor coolant pressure boundary (RCPB). The low pressure

ECCS and associated DGs are initiated upon receipt of the'*Drywell Pressure-High Function with a Reactor Pressure-Low(Injection Permissive) in order to minimize the possibilityof fuel damage. The DGs are initiated from Function'1.bsignals. This Function also initiates the closure of therecirculation discharge valves to ensure the LPCI subsystemsinject into the proper RPV location. The Drywell

* Pressure-High .Function with a Reactor Pressure-Low*. (Injection Permissive), along with the ieactor Water

* Level-Low Low Low (Level 1) Function, is directly assumedin the analysis of the recirculation line.break (Ref. 4).'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.

High drywell pressure signals are initiated from four* pressure transmitters that sense drywell pressure. The

Allowable Value was selected to be as low as possible and beindicative of a LOCA inside 'primary containment.'

- The Drywell-Pressure-High Function-is required to beOPERABLE when the ECCS or [G. is required to be OPERABLE inconjunction with times when the primary containment is

* required to be OPERABLE. Thus, four channels of the CS andLPCI Drywell Pressure -High Function are required to'be

* OPERABLE in MODES 1, 2, and 3 to ensure that no singleinstrument failure can preclude ECCS and DOGinitiation. InMODES'4.and 5, the Drywell Pressure-High'Function is notrequired, since there is insufficient energy in the reactorto pressurize the primary containment to Drywell.Pressure-High setpoint. Refer to LCO 3.5.1 for Applicability Bases*for the low pressure ECCS subsystems and to LCO'3.8.1 forApplicability Bases for the DGs.

(continued)

.PBAPS UNIT 3 * B 3.3-102 Revision No. 3

ECCS Instrumentation*B 3.3.5.1

I BASES - . .

*APPLICABLE .SAFETY ANALYSLCO, -and.APPLICABILITY

(continued)

PizFSI.c. 2.c. Reactor Pressure-Low (Injection Permissive)

Low reactor pressure signals are used as permissives for thelow pressure ECCS subsystems. This ensures that:, prior toopening the injection valves of the-low.pressure ECCSsubsystems or initiating.the low pressure ECCS subsystems on

* a Drywell Pressure-High signal, 'the reactor pressure has'fallen to a value below these subsystems' maximum designpressure and a break inside the- RCPB has occurredrespectively. This Function also provides permissive forthe closure of the recirculation discharge 'valves to ensurethe LPCI subsystems'inject into the proper RPV location.The Reactor Pressure-Low is'one'of the Functions assumed to.be OPERABLE and capable'of permitting initiation of.the ECCS

* during.the transients analyzed in References 1 and 3.- Inaddition, the Reactor Pressure-Low Function is directlyassumed in the analysis of the recirculation line break

* .(Ref. 4). The core cooling function .of the ECCS, along withthe scram action of the RPS, ensures that the fuel peakcladding temperature remains below the limits of10 CFR 50.46.

The Reactor Pressure-Low signals are initiated from fourpressure transmitters that-sense the reactor dome pressure.

- The Allowable Value is low enough to prevent overpressuringthe equipment in the low pressure ECCS, but high enough toensure that the ECCS injection prevents the fuel peakcladding temperature from exceeding the limits of

>J- 10 CFR 50.46.

Four channels of Reactor Pressure-Low Function are onlyrequired to be OPERABLE when the ECCS is required'to beDPERABLE to ensure that no'single instrument failure. can

spdek preclude ECCS initiation. w efer-to LCO 3.5.1 and LCO 3.5.2for Applicability Bases forthe low pressure ECCS

g' 1.d. 2.a. Core Spray and Low Pressure Coolant Iniection. Pumo Discharie Flow-Low (Bvnass)-

The minimum flow instruments are provided to protect theassociated low pressure ECCS'pump from overheating when thepump is operating and the associated injection valve is notfully open. The minimum flow line valve .is opened when lowflow' is sensed, and the valve is automatically closed whenthe flow rate is adequate to protect the pump. The LPCI and

(continued)


ECCS'InstrumentationB 3.3.5.1

BASES

APPLICABLESAFETY ANAILCO, andAPPLICABIL]

.YSES1.d. 2.p. Core Spray and Low Pressure Coolant InlectionPump Discharce Flow-Low (Bypass) (continued)

[TY. CS Pump Discharge Flow-Low Functions are assumed to beOPERABLE and capable of closing the minimum flow valves toensure that the low pressure ECCS flows assumed during the.transients and accidents'analyzed in References 1,'2, and 3'

*ire met. The core cooling function of the ECCS, along withthe scram action of the RPS, ensures that the fuel peak

' cladding temperature remains below the limits of10 CFR 50.46.

One differential pressure switch per ECCS pump is used todetect the associated subsystems' flow rates. The logic isarranged such that each switch causes its associated minimumflow valve to open. The logic will close the minimum flowvalve once the closure setpoint is exceeded. The LPCIminimum flow valves are time delayed such that the valveswill not open for .10 seconds'after the switches detect lowflow. The time delay-is provided to limit reactor vesselinventory loss during the startup of the RHR shutdowncooling mode. The Pump Discharge Flow-Low Allowable Values'are high enough to ensure that the pump flow rate issufficient to protect the pump, yet low enough to ensurethat the closure of the minimum flow valve is initiated toallow full flow into the core.

Each channel of Pump Discharge Flow-Low Function '(four CSchannels and four LPCI channels) is only required to be

t OPERABLE when the associated ECCS is required to be OPERABLEj f*v to ensure that .no single instrument failure can preclude the:A ECCS function. NRefer to LCO 3.5.1 and LCO 3.5.2 for

Apcbi Xases for the low pressure ECCS subsystems.

I.e. I.f. Core Spray Pump Start-Time Delay Relay

* The purpose of this time, delay is to stagger the start ofthe CS pumps.that are in each of Divisions I and 11 to

* prevent overloading the power source. This Function isnecessary when power is being supplied from the offsitesources or the standby power sources (DG). The, CS PumpStart -Time Delay Relays are assumed to be OPERABLE in theaccident and transient analyses requiring ECCS initiation.That'is, the analyses assume that the pumps will initiatewhen required and excess loading will not cause failure ofthe power sources.

(continued)


-


BASES

APPLICABLE i.e. 1.f. Core Sprav Pumi Start-Time Delay RelaySAFETY ANALYSES, (continued)LCO, and -.'A JL-ICABILITY There are eight Core Spray Pump Start-Time -Delay Relays,

two in each of the CS pump start logic circuits (one for.when offsite power is available.aand one for when offsitepower is not available). One of each type of time delay'.

..q e4 -relay is dedicated to a single pump start logic,.such that a4 In J single failure of a Core Spray Pump Start-Time Delay Relay

mo will not result in the failure-of =ore than one CS pump. In.this condition, three of the four CS pumps will remain.@ K t OPERABLE; thus, the single failure criterion is met (i.e.,

o *. loss of one instrument does not preclude ECCS initiation)... The Allowable Value for the Core Spray Pump.Start- Time

o Delay Relays is. chosen to be long enough so that the powersource will not be overloaded and short enough so that ECCSoperation is not degraded.

Each channel of Core Spray Pump Start- Time-Delay Relay3':.. 1 Function is required to be OPERABLE.only when the. associatedCS subsystem is required to be OPERABLE. Refer to LCO.3.5.1and LCO3.5.2 for Applicability Bases fo the CS subsystems.

2.d. Reactor Pressure-Low Low.(Recirculation DischarqeValve Permissive)

1 \Low reactor pressure signals are used as permissives form erecirculation discharge valve closure. This ensures thatt M~ I .the LPCI subsystems inject into the proper RPV location

U assumed in the safety analysis. The Reactor Pressure- LowLow is one of the Functions assumed to be OPERABLE andcapable of closing the valve during the transients analyzed

* in References 1 and 3. The core cooling function of the^ l 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. The Reactor Pressure-Low Low Function is°directly assumed in the analysis of the recirculation line

break (Ref. 4).

o |The Reactor Pressure-Low Low signals are initiated from.8 @ . four pressure transmitters that sense the reactor pressure.

X i } The Allowable Value is chosen to ensure that the-valvesclose prior to commencement of LPCI injection flow into thecore, as assumed in the safety analysis.

Xcontinued)

PBAPS UNIT 3 * B 3.3-105 Revision No. 3

* ECCS InstrumentationB'3.3.5.1

BASES

APPLICABLESAFETY ANALYSES,LCO, andAPPLICABILITY.

O~i

U1,

A. ,

*) W 't)'g'

c ul JB

* / ' 4 .I

j i

2.e. Reactor Vessel Shroud Level -Level 0 (continued) .

Two'channels of the Reactor Vessel Shroud Level -Level 0Function are only required to be OPERABLE in MODES 1, 2,and 3. In MODES 4 and 5, the specified initiation time of.the LPCI subsystems is not assumed, and other administrative*controls are'adequate to.control the valves associated withthis Function. (since the systems that the'valves are openedfor are'not required to be OPERABLE in-MODES 4 and 5 and arenormally not used).

2.f. Low Pressure Coolant 'Iniection Pumn Start-Time Delay.Relay

The purpose of this time delay is to stagger.the start ofthe LPCI pumps that are in each of Divisions 'I and II, to-prevent overloading the power source.' This Function is onlynecessary when power is being supplied from offsite sources.The LPCI pumps start simultaneously with no time-delay assoon as the standby source is available. The LPCI Pump'Start Time Delay Relays are assumed to be OPERABLE in theaccident'and transient analyses requiring ECCS initiation.That is, the analyses assume that the pumps will initiatewhen required and excess loading will not cause.failure ofthe power sources.

There are eight LPCI Pump Start-Time Delay Relays, two ineach of the RHR pump start logic circuits. Two time delayrelays are dedicated to a single pump start logic. Bothtimers in the RHR pump start logic would have to fail toprevent an RHR pump from starting within the required time;therefore, the low pressure ECCS pumps'will remain OPERABLE;thus, the single failure criterion is met (i.e.,' loss ofoneinstrument does not preclude ECCS initiation). The'Allowable Va lues for the LPCI Pump Start-Time Delay Relaysare chosen to be long .enough'so that most of the startingtransient of the first pump is complete before starting thesecond-pump on-the same 4 kY emergency bus and short enoughso that ECCS'operation is not degraded.

Each channel of LPCI Pump Start-Time Delay Relay Functionis required to be OPERABLE only when the associated LPCI.subsystem is required to be OPERABLE. Refer to LCO 3.5.1*and LCO 3.5.2 for Applicability Bases r the LPCI 'subsystems.

(continued),,



BASES

BACKGROUND 5.; Reactor Water Cleanup System Isolation (continued)

System Isolation Function receives input from two channelswith each channel 'in one trip system using a one-out-of-onelogic.' When either SLC pump is started remotely, one 'channel trips the inboard isolation valve and one'channelisolates the outboard isolation valves.

t

The RWCUoutboard

* valve at

Isolation Function isolates the inboard andRWCU pump suction penetration and the outboardthe RWCU connection to reactor feedwater.

6. Shutdown Cooling System Isolation

The Reactor Vessel Water Level -Low (Level 3) Functionreceives input from four reactor vessel water levelchannels. The.outputs from the channels are connected to'aone-out-of-two taken. twice logic, which isolates both valveson the RHR shutdown.cooling pump suction penetration.. TheReactor Pressure-High Function receives input from twochannels, with each channel in one trip system using aone-out-of-one logic. Each trip 'system is connected to bothvalves on the RHR shutdown cooling pump suction penetration.

7. Feedwater Recirculation Isolation

The Reactor Pressure -High Function receives inputs from.-four channels.. The outputs from the four channels areconnected into a one-out-of-two taken twice logic whichisolates the feedwater recirculation valves.

APPLICABLE,SAFETY ANALYSES,LCO, .andAPPLICABILITY

The isolation signals generated by the primary containmentisolation instrumentation are implicitly assumed in thesafety analyses of References 1 and 3 to initiate closureof-valves to limit offsite doses. Refer to LCO 3.6.1.3,'"Primary Containment Isolation Valves (PCIVs)," ApplicableSafety Analyses Bases for more detail of.the safetyanalyses.

Primary containment isolation instrumentation satisfiesCriterion 3 of-the NRC Policy Statement. Certaininstrumentation Functions are retained for other reasons andare described below in the individual.Functions discussion.

(continued)

PBAPS UNIT 3 B 3.3-145 .Revision No. 3

vv veoi.2

The Reactor Vessel Water Level - Low, Level 3 Isolation Function receives input from oretrvessel water level channels. The outputs from the reactor vessel w~ater level channels arecnnmeinto one two-out-of-two logic tripmsstem- The Dry well Presture -- H1igh Isolation functio'n receives

inpu frm to dywel prssue cannls.Theoutputs. from the dry~ell pressure channelsarconnected into one two-out-of-two logic trip system. 7

When either Isolation Function' actuates, the TgP~rWiaiec = s-ill VMidiW tlieTIMs~anddo~. - TIPsystem isolation ballvalves .hei~.he TiPs-are fully wi*thrwn. The v

TIP ystm iolaionvalves are manual shear vaves.

TI Sstmislain untons iSOlate fth Group. !(4es ( isolation ball valves).


BASES.

APPLICABLE 6.b. Reactor Vessel Water Level'- Low (Lievel 3) (continued)SAFETY ANALYSES,LCO, and The Reactor Vessel Water Level - Low (Level 3) AllowableAPPLICABILITY 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.

* ' The Reactor Vessel Water Level-Low (Level 3) Function isonly required to be OPERABLE in MODES 3, 4, and 5 to prevent :this potential-flow path from lowering the reactor vessellevel to the top of the fuel. In MODES Land 2, anotherisolation (ibe., Reactor Pressure-High) and administrativecontrols ensure that this flow path remains isolated to

. .prevent unexpected loss of inventory via this flow path.

This Function isolates both RHR shutdown cooling pumpsuction valves.

Feedwater Recirculation Isolation

* 7.a. Reactor Pressure -High

The Reactor Pressure-High Function is provided to isolatethe feedwater recirculation line. This interlock-isprovided only. for equipment protection to prevent anintersystem LOCA scenario, and credit for the' interlock is

* not assumed in the accident or transient analysis in theUFSAR.

The Reactor Pressure-High' signals are initiated from four.:* transmitters that are connected to different taps on the

RPV. Four channels of Reactor Pressure-High Function areavailable and are required to be OPERABLE to ensure that nosingle instrument failure can preclude the isolation

. function. The Function is only required to be OPERABLE inMODES 1, 2, and 3, since these are the only MODES in whichthe reactor can be pressurized; thus, equipment protection

- is needed. The Allowable Value was chosen to be low enoughto protect the system equipment from overpressurization.

* This Function isolates the feedwater recirculation valves.

( t/ __<S ~s_ .(continued)


_ri TSTF-306; Rev. 2

Traversing Incore Probe System Isolation

. Reactor Vessel Water Level-Low. Level 3

Low RPV water level indicates that the capability to cool the fuel may be threatenedL The valveswhose penetrations communicate with the primary containment are isolated to limit the release offission products. The isolation of the primary containment on Level 3 supports actions to ensure thatoffsitedose limits of 10 CFR 100 are not exceeded. The ReactorVessel WaterLevel-Low, Level 3Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage pathsare assumed to be isolated post LOCA.

Reactor Vessel Water Level -Low, Level 3 signals are initiated from level transmitters that sense thedifference 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. Two channels of Reactor Vessel Water Level -Low, Level 3 Function are available and are required to be OPERABLE to ensure that no singleinstrument failure can initiate an inadvertent isolation actuation. The isolation function is ensured bythe manual shear valve in each penetration.

The Reactor Vessel Water Level-Low, Level 3 Allowable Value was chosen to be the same as theRPS Level 3 scram Allowable Value (LCO 3.3.1.1), since isolation of these valves is not critical toorderly plant shutdown.

TIis Function isolates the Group veif

High drywell pressure can indicate a break in the RCPB inside the primary containment The isolationof some of the primary containment isolation valves on high drywell pressure supports actions toensure that offsite dose limits of 10 CFR 100. are not exceeded. The Drywell Pressure-High

j Function, associated with isolation of the primary containment, is implicitly assumed in the PSARaccident analysis as these leakage paths are assumed to be isolated post LOCA.

High drywell pressure signals are initiated from pressure transmitters that sense the pressure in thedrywell. Two channels of Drywel Pressure-High perFunction are available and are requiredto beOPERABLE to ensure that no single instrument failure can initiate an inadvertent actuation. Theisolation function is ensured by the manual shear valve in each penetration.

The Allowable Value was selected to be the same as the ECCS Drywell Pressure-High AllowableValue (LCO 3.3.5.1), since this mai ve of a LOCA inside primary containment

s Function isolates the GrouvalV

< _ k-" -

. 'Primary Containment Isolation InstrumentationB 3.3.6.1

BASES (continued)

ACTIONS Notekias been provided to modify the ACTIONS related toprimary containment isolation instrumentation channels.Section 1.3, Completion Times, specifies that once aCondition has been entered, subsequent divisions,subsystems, components, or variables expressed.in theCondition,.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 of theCondition continue.to apply for each additional failure,with Completion Times based on initial entry into theCondition. However, the Required Actions for inoperable

-primary containment isolation instrumentation channelsprovide appropriate compensatory measures for separateinoperable.channels. As such, a Note has been provided thatallows separate Condition entry for each inoperable primarycontainment isolation instrumentation channel..

A.1

Because of the diversity of sensors available to provideisolation slignals and the redundancy of the isolationdesign, an allowable out of service time of 12 hours forFunctions 1.d, 2.a, and 2.b and 24 hours for Functions otherthan Functions I.d, 2.a, and 2.b has been shown to beacceptable (Refs. 6 and 7) to permit restoration of anyinoperable channel to OPERABLE status. This out of servicetime-is only acceptable provided the associated Function isstill maintaining isolation capability.(refer to Required.Action B.1 Bases). If the inoperable channel cannot berestored to OPERABLE status within the allowable out of.service time, the channel must be placed in the tripped.condition per Required Action A.1. Placing the inoperablechannel in trip would conservatively compensate for theinoperability, restore capability to accommodate a-single

* failure, and-allow operation to continue with no further' restrictions. Alternately, if it is not desired to place

'the channel in trip (e.g., as in the case where placing theinoperable channel in trip would result in an isolation),Condition C must be entered and its Required Action taken.

* (continued)


Primary Containment Isolation Instrumentation A

.83.3.6.1'

The ACTIONS are modified by two Notes. Note 1 allows

pentratlin flow path(s) to bd unisolated intermltteitly under

m inistrative controls. These controls corisist of stationinga.

dedicated operator at the controls of the valve. who isA n )

continuous camunication with the control room. In this way,Y the pertion can be rapidly Isolated when a need for primary:

containrent isolition is indicated..

.

F

III

I


BASES

-APPLICABLE This LCO helps to ensure that the following acceptanceSAFETY ANALYSES criteria for the ECCS, established by 10-CFR 50.46 (Ref. 8),

(continued) will be met following a LOCA, assuming the worst case singleactive component failure in the ECCS:

a. Maximum fuel element cladding temperature is s 2200*F;

* b. Maximum cladding oxidation is 5 0.17 times the total* .cladding thickness before oxidation;

.c. Maximum hydrogen generation from a zirconium waterreaction is S 0.01 times the hypothetical amount thatwould. be.generated if all of the metal in the claddingsurrounding the fuel, excluding the claddingsurrounding the plenum volume, were to react;

d. The core is maintained in a coolable geometry; and

e. Adequate long term cooling capability is maintained.

The limiting single failures are discussed in Reference 7.The remaining OPERABLE ECCS subsystems provide thecapability to adequately cool the core and prevent excessivefuel damage.

The ECCS satisfy Criterion 3 of the NRC Policy Statement.

LCO Each ECCS injection/spray subsystem and five ADS valves arerequired to be OPERABLE. The ECCS injection/spraysubsystems are defined as the two CS subsystems, the twoLPCI subsystems, and one HPCI System. The low pressure ECCSinjection/spray subsystems are defined as the two CS* subsystems and the two LPCI subsystems.

With less than the required number of ECCS subsystems'OPERABLE, the potential exists that during.a limiting designbasis LOCA concurrent with the worst case single failure,the limits specified in Reference8 could be exceeded. AllECCS subsystems must therefore be OPERABLE to satisfy thesingle failure criterion required by Reference 8.

LPCI subsystems may be considered OPERABLE during alignmentand operation for decay heat removal when below the actualRHR shutdown cooling isolation pressure in MODE 3, if.capable of being manually realigned (remote or local) to the

(continued)


Alignment and operation for decay heat removal i es when the required RHR pump is notECS-Ooperating or when the system is realigned from or to the RHR shutdown cooling mode. This B 3.5.1allowance 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.

LCO LPCI mode and not otherwise inoperable.\ At these low(continued) pressures and decay heat levels, a reduced complement of

ECCS subsystems should provide the required core cooling,thereby allowing'operation'of RHR shutdown cooling whennecessary. '

APPLICABILITY All ECCS subsystems are required to be OPERABLE during* MODES 1,2, and 3, when there is considerable energy in thereactor core and core cooling would be required to prevent

-fuel damage' in the event of a break in the primary systempiping. In MODES 2 and 3,'when reactor steam dome pressureis s 150 psig, HPCI is not required to be OPERABLE becausethe low pressure .ECCS subsystems can provide sufficient flowbelow this pressure.. In MODES 2 and 3, when reactor steam'dome pressure is 100 psig, ADS.is not required to be

' ' .OPERABLE because.the low pressure ECCS subsystems canprovide sufficient flow below this pressure. ECCS

* . requirements for MODES 4 and5 are specified in ICO 3.5.2,"ECCS-Shutdown."..

ACTIONS

If any-one low pressure ECCS injection/spray subsystem isinoperable, or if one LPCI pump in each subsystem isinoperable, all inoperable subsystems must be restored tobPERABLE status within 7 days (e.g., if one LPCI pump ineach subsystem is inoperable, both must be restored within7 days). In this Condition, the remaining OPERABLEsubsystems provide adequate core cooling during a LOCA.HQwever, overall ECCS reliability is reduced, because asingle failure in one of the remaining OPERABLE subsystems,concurrent with a LOCA, may result in the ECCS not beingable to perform its intended safety. function. The 7 day.Completion Time is based on a reliability study (Ref. 9)that evaluated the impact on ECCS availability, assuming.various components and subsystems were taken out of service.The results were used to calculate the average availabilityof.ECCS equipment needed to mitigate the consequences of aLOCA as a function of-allowed outage times. (i.e., CompletionTimes).

(continued)

'B 3.5-6PBAPS UNIT 3 Revision No. 0

ECCS-Operating* B 3.5.1

BASES

SURVEILLANCE"REQUIREMENTS

is SR is mo ed by a Note that a LPCI subsystems jbe considered OP LE during al ment and operation fordecay heat removal wi rea steam dome pressure lessthan the RHR shutdown co ng isolation pressure in MODE 3,if capable of being uall aligned (remote or local)-to

7 the LPCI mode an ot otherwise erable. Manualrealignment t e LPCI.mode may als dlude opening the

ag valve :establish the required LPC bsystem.flowrates, is allows operation in the RHR shut cooling

rin MODE if necessary

Z. el

SR 3.5.1.3

-Verification every 31 days that ADS nitrogen supply headerpressure is , 85 psig ensures adequate air pressure for,reliable ADS operation. The accumulator on each ADS valveprovides pneumatic pressure for valve actuation. . The'designpneumatic supply pressure requirements for the accumulatorare such that, following a failure of the pneumatic supplyto the accumulator, at least two.valve'actuations can occurwith the drywell at 70% of design pressure (Ref. 10). TheECCS safety analysis. assumes only one actuation to achievethe depressurization required for operation of the lowpressure ECCS. This minimum required pressure of 2 85 psig.is provided by the ADS instrument air supply. The 31 dayFrequency takes into consideration administrative controlsover'operation of the air system and alarms for low airpressure.

SR 3.5.1.4

Verification every 31 days that the LPCI cross tie valve is-closed and power.to its operator is disconnected ensuresthat each LPCI subsystem remains independent and a-failureof the flow path in one subsystem will not affect the flowpath of the other LPCI subsystem. Acceptable methods ofremoving power to the operator include de-energizing breakercontrol power or racking out or removing the breaker. Ifthe LPCI cross tie valve is open or power has not beenremoved from the valve operator, both LPCI subsystems mustbe considered inoperable. The 31 day Frequency has been

(continued)

.PBAPS UNIT 3 B 3.5-11 Revision No. 0

, ). . A-.. .

Alignment and operation for decay beat removal includes when the required RHR pump is not CCS-Shutdownoperating or when the system is realigned from or to the RHR shutdown cooling mode. This B 3S.5.t 2allowance is necessary since the RHR System may be required to operate in the shutdowncooling mode to remove decay heat and sensible heat from the reactor.

LCO One LPCI subsystem may be(continued) co :dPERABL !%±MJ, if F.oeO

manually realign (remote or ocal) to the LPCI mode andI c-A dis not otherwise inoperable. Because of low pressure and

R8DP nlow temperature conditions in MODES 4 and 5, sufficient time4 A will be available to manually align and initiate LPCI

subsystem operation to provide core cooling prior topostulated fuel uncovery.

APPLICABILITY OPERABILITY of the low pressure ECCS injection/spraysubsystems is required in MODES 4 and 5 to ensure adequatecoolant inventory and sufficient heat removal capability for-the irradiated fuel in the core in case of an inadvertentdraindown of the vessel. Requirements for ECCS OPERABILITYduring.MODES 1, 2, and 3 are discussed in the Applicabilitysection of the Bases for LCO 3.5.1. ECCS subsystems are notrequired to be'OPERABLE during MODE 5 with the spent fuelstorage pool gates removed, the water level maintained at2 458 inches above reactor pressure vessel instrument zero(20 ft 11 inches above the RPV flange), and no operationswith a potential for draining the reactor vessel (OPDRVs) inprogress. This provides sufficient coolant inventory toallow operator action to terminate the inventory loss priorto fuel uncovery in case of an inadvertent draindown.

The Automatic Depressurization System is not required to beOPERABLE during MODES 4 and 5 because the RPV pressure iss 100 psig, and the CS System and the LPCI subsystems canprovide core cooling without any depressurization of theprimary system.

The High Pressure Coolant Injection System is not requiredto be OPERABLE during MODES 4 and 5 since the low pressureECCS injection/spray subsystems can provide sufficient flowto the vessel.

ACTIONS A.1 and B.1

If any one required low pressure ECCS injection/spraysubsystem is inoperable, an inoperable subsystem must berestored to OPERABLE status in 4 hours. In this Condition,the remaining OPERABLE subsystem can provide sufficientvessel flooding capability to recover from an inadvertentvessel draindown. However, overall system reliability isreduced because a single failure in the remaining OPERABLE

(continued).} .1,

PBAPS UNIT 3;: B 3.5-19 Revision No. 0


BASES

SURVEILLANCE SR 3.5.2.1 and SR 3.5.2.2 (continued)'REQUIREMENTS..

The 12 hour Frequency of these SRs was developed consideringoperating experience related to suppression pool water'leveland CST water level variations and instrument drift'during*the applicable MODES. Furthermore, the 12 hour Frequency isconsidered adequate in view of other indications availablein the control room to alert the operator to an abnormalsuppression pool or CST water level condition.

SR 3.5.2.3. SR 3.5.2.5.' and SR 3.5.2.6

The Bases provided for SR 3.5.1.1, SR 3'.5.1.7, andSR 3.5.1.10 are applicable to SR 3.5.2.3, SR 3.5.2.5, andSR 3.5.2.6, respectively.

SR 3.5.2.4

Verifying the correct alignment for manual, power operated,and automatic valves in the ECCS flow.paths providesassurance that the proper flow paths will exist for ECCSoperation. This SR does not apply to valves that are.locked, sealed, or otherwise secured in position, sincethese valves were verified to be in the correct positionprior to locking, sealing, or securing. A'valve thatreceives 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, itinvolves verification that those valves capable ofpotentially being'mispositioned are in the correct position.This SR does not apply to valves that cannot beinadvertently misaligned, fuch as check valves. The 31 dayFrequency is appropriate because the valves are operatedunder procedural control and the probability of their beingmispositioned during this time period is low.

M n , h fR System ma oert 2 7 tdheoling mo e emove decay heat and sensibl *et from the

reactor. Therefore, valves t required for LPCIsubsystem operation may ned for decay heat removal.Therefore, this S . modified ote that allows oneLP I subsys of the RUAP System to b deredOPERABLtE--.



BASES

SURVEILLANCE'REQUIREMENTS'

pf r the EM i- functio ifal the required vaN;n te LPI(flow path can - nnuallyarealig rlcal) toallow injection intituUkW h sytem is not- , .otherwise inoperab . anu . i nment to allow. injectioninto the R he LPCI mode may s opening the'dr ~ e to establish the required LPCI subs em flow(rate. This will ensure adequate core'cooling if an

* dv tRP dr dow sh cr

REFERENCES 1. NEDO-20566A, 'General Electric Company Analytical.Model for Loss-of-Coolant Accident.Analysis in.Accordance with 10 CFR 50 Appendix K," September 1986.


' Primary C;;ntainment Air LockB 3.6.1.2

BASES

SURVEILLANCE*REQUIREMENTS.

SR .3.6.1.2.1 (continued)

testing. The periodic testing requirements verify that'.theair lock leakage-does not exceed the allowed fraction of theoverall primary containment leakage rate. The.Frequency isrequired by .the Primary Containment Leakage Rate TestingProgram.I

.

)

The-SR has been modified.by two Notes. Note 1 states thatan inoperable air lock door does not invalidate the previoussuccessful performance' of the overall air lock leakage test.This is considered reasonable since either air lock door is'capable of providing a. fission product barrier in the eventof. a DBA.. Note 2 requires the results of air lock leakage

-.tests to be evaluated against the acceptance'criteria of thePrimary Containment Leakage Rate Testing.Program, 5.5.12.This ensures that the.air lock leakage is properly accountedfor in determining the combined Type B and.C primarycontainment leakage. L'S- p

SR 3.6.1.2.2

The air-lock interlock mechanism is designed to pieventsimultaneous opening of both doors in the air lock. Sinceboth the inner and outer doors of an air lock are designed

* to withstand the maximum expected post accident primarycontainment pressure, closure of either door will supportprimary containment OPERABILITY. Thus, the interlockfeature supports primary containment OPERABILITY while theair lock is being used for personnel transit in and out ofthe containment. Periodic testing of this interlockdemonstrates that the interlock will function as designedand that simultaneous inner and outer door openin'g will notinadvertently occur. Due to the purely mechanical nature ofthis interlock, and given that the interlock'mechani m is->epchallenged when primary-containment isB S

Z-:.test_is -only renuired-to be perfo- __ - _r �_

gVer '4ovhc t 4ef,fro V( se7 Kb4Se) o.. 4Cf neel

f o perforM '14>;a S~veLvjlie4Itt1 UYJ

tke c0o dli 0Va -f-.q~ ofIj /vr4'naI(X c IA6

fne? f i' r-t ' he Z4 &

Waveg~tt.'PBAPlUVI' 3 2~ '

%C " Cj4z 'Ldr i464 o f . t /

, a/ck. .

PCIVsB 3.6.1.3

BASES

ACTIONS A.I and A.2 (continued)

allows a period of. time to restore the MSIVs to OPERABLEstatus given the fact that MSIV closure will result inisolation of the main steam line(s) and a potential forplant shutdown.

For affected penetrations that have been isolated' inaccordance with Required Action A.1, the affectedpenetration flow path(s) must be verified to-be isolated ona periodic basis. This is necessary to ensure that primarycontainment penetrations required to be isolated followingan accident, and no longer capable of being.automaticallyisolated, will be' in the isolation position-should an eventoccur. This Required Action does not require any'testing ordevice manipulation. Rather, it involves verification thatthose devices outside containment and capable of potentially-being mispositioned arelin the correct position. TheCompletion Time of toonce per 31 days for isolation devicesoutside primary containment" is appropriate because thedevices are operated under administrative controls and the

' probability of their misalignment is low. For the devices* 'inside primary containment, the time period specified 'prior

to entering MODE 2 or 3. from MODE 4, if primary containmentwas de-inerted while in MODE 4, 'if not performed within theprevious 92 days' is based on engineering judgment'and isconsidered reasonable in view of the inaccessibility of thedevices and other administrative controls ensuring thatdevice misalignment is an unlikely ibilit 7

Condition A is modified by a Note i dicating that hisCondition is only.applicable to tho e penet atio flow paths*^with two PCIYs. For penetration fl w-paths wit one PCIV,.Condition C provides the appropriat Requijed tions.Required Action A.2 is modified.by Noteh applies toisolation devices located in high radiation areas, andallows them to be verified by use of administrative means.Allowing verification by administrative means is consideredacceptable, since access to these areas 'is typicallyrestricted. Therefore, the probability of misalignment,once they h e been'verified to be in the.'proper position,is low.

: (continued)

PBAPS UNIT 3 B 3.6-20 Revision No..O

rSTrF-ZGcI tIOv 2-

2. Iso evices that areAcked, e r otherwise

securedniaybe byuse of administrative means.

)Nte 2 applies to isolation devices that. arc locked, sealed, or otherwise secured in position aid 'allows these -devices to be~ verified closed by use of adniinistrative means. Allowing verification )

* by administrative mrans is considered acceptable, since the function of locking, sealing, or(JOBcompnent isto ensure that thes devices arc not inadvertentl mepositioned. .

I (WOO, CEOG, BWR4, BWR6)

equired i on E.2 is modified by two Notes. Note pplies to isolation devices located in highradiation areas allows these devices to be ve closed by use of administrative means.

* Allowing verifica n by administrative means nsidered acceptable, since access to these areasis typically retrict ote 2 applies to iso a devices that are locked, sealed, or otherwisesecured in position andws these dcvi to be verified closed by use of administrative means.Allowing verification by tive is considered acceptable, since the function oflocking, sealing, or securing ts is to ensure that these devices are not inadvertentlyrepositioned.X

Insert4 (BWOG)

Required Action D.2 is dified by two Not Note I applies to isolation devices located inhigh radiation areas allows these devices to verfied closed by use of administrative means.Allowing verifi y administrative means is co ered acceptable, since access to these areasis typically cted. Note 2 applies to isolation device hat are locked, sealed, or otherwisesecured in ition and allows these devices to be verified e by use of administrative means.Allowin erification by administrative means is considered a table, since the function ofJo , sealing, or securing components is to ensure that these de are not inadvertentlyre sitioned.

PCIVsB 3.6.1.3

BASES

ACTIONS(continuedi.

B.1

With one or more penetration flow paths with two PCIVsinoperable except due to MSIV leakage not within'limit,either the inoperable PCIVs must be restored to OPERABLEstatus or the. affected penetration'flow path must beisolated within 1 hour. The method of isolation mustinclude the use of at least one isolation barrier thatcannot be adversely affected by a single active failure.Isolation barriers that meet this-criterion are a closed andde-activated automatic valve, a closed manual valve, and ablind flange. The '1 hour Completion Time is consistent with'the ACTIONS of LCO .3.6.1.1.

* Condition B is-modified by a Note indicating this Conditionis only applicable to penetration flow-paths with two PCIVs.For penetration flow paths with one PCIV, Condition Cprovides the appropriate Required Actions.

C.] and C.2

With one or more penetration flow paths with one PCIV*~ / .inoperable, the inoperable valve must be restored to

,-6sd ¢k { OPERABLE status or the affected penetration flow path muste CD -0 r .e.) be isolated. The method of isolation must include the useOV 5 .{el VI t of at least one'isolation barrier that cannot be adversely

4j t°. +Oy v tfr (e affected by a single active failure. Isolation barriers.jA Pt". 6> , thiat meet this criterion are a closed and de-activated

. - automatic valve, a closed manual 'valve, and a blind flange'..[V Ia O f fa' A check valve t nbe used to ISot a fete-o

.f 'ene r}4 S nwr oil llV2~s fssi

woe i asonarle cons l- he relative stability ofta ' P -~' . 1at ystcloed ystm (enc, reliability) to act as a

-penetration isolationboundaryand the relative importance; of supporting primary containment OPERABILIT dun

.<evc~ ,) / MODES-1, 2, and 3A The Completion Time of oursreasonalll:onSTkering the'instrument and the small pipediameter of penetration (hence, reliability) to.act as 'apenetration isolation boundary and the small pipe diameterof the affected:penetrations.

* liAV For affected penetrations that have been isolated in/. accordance with Required Action C.1, the affected( - penetration flow path(s) must be verified to be 'isolated on

*-K At _ (continued1 -1

.. I

I

PBAPS UNIT 3 B 3.6-21' Revision No. .U. J.

PCI Vs

PCIVsB 3.6.1.3

BASES

ACTIONS C.1 and C.2 (continued)

a periodic b'asis. This is necessary to ensure that primarycontainment penetrations.required to be isolated followingan accident,.and no longer capable of being automaticallyisolated, will be in the isolation position should an event- ' occur. This Required Action does not require any testing orvalve manipulation. Rather, it involves verification,

'' through a system walkdown, that those'valves outsidecontainment' and capable of potentially being mispositioned-are in the correct position. The Completion Time of onrceper 31 days for isolation'devices outside primarycontainment' is appropriate because the valves are operatedunder administrative controls and the probability of theirmisalignment is low.' For the valves inside primarycontainment; the time period specified 'prior to enteringMODE 2 or 3 from MODE 4, if primary containment wasde-inerted while in MODE 4, if not performed within the

. previous 92 days' is based on engineering judgment and isconsidered reasonable in view of the inaccessibility of thevalves and other administrative controls'ensuring that valve'

* misalignment is an unlikely possibility.

Condition C is modified by a Note indicating that this* ' Condition is only applicable to penetration flow paths with

only one PCIV. For penetration flow paths with two PCIVs,-Conditions A and B provide the app r ate quir ions.

Required Action C.2 is modified by Note' ppTIs tovalves and blind'flanges-located in high radiation areas and

* allows them to be verified by use of administrative means.Allowing verification by administrative means is consideredacceptable, since. access to these areas is typicallyrestricted..ATherefore, the'probability of misalignment of

. . these valves once they have been verified to be in theproper posi on, is low.

* * D.V

With any MSIV leakage rate not within limit, the assumptionsof the safety analysis are not met. Therefore, the leakagemust be restored to within limit within 8 hours..Restoration can be accomplished by isolating the penetrationthat caused the limit to be exceeded by use of one closedand de-activated automatic valve, closed manual valve, orblind flange. When a penetration is isolated, the'leakage

(continued)

PBAPS UNIT 3 B 3.6-22 PRevision No. 0

1STF-Z6Q, dIa 2

2. Is~on icesthat arelocked, ld, or otherwise

secufl ayrii~dby . .

insertti .5ens

Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position andallows these devices to be verified closed by use of ad iinistrative means. Allowing verificationby administrative molans is considered acceptable, since the function' of locking, sealing, or

.t securing components is to ensure that these devices are not inadvertently repositioned.

Insert 3 (W CEOG, BWR4, BWR6)

Required Action is modified by two Notes. Note applies to isolation devices located in highradiation areas and ws these devices to be v closed by use of adrn~istrative means.Allowing verification dmi ive means is nsidered acceptable, since access to these areasis typically restricted. Not applies to isolan 1 devices that are locked, sealed, or otherwisesecured in position and nib de o be verified closed by use of adinistrative means.Allowing verification by tive is considered acceptable, since the fiction oflocking, sealing, or securing co is to ensure that these devices are not inadvertentlyrepositioned.

Insert 4 (BWOG)

Required Action D.2 is edby two Notes. ote I applies to isolation devices located inhigh radiation areas and lbws these devices to be fled closed by use of administrative means.Allowing verification adminitive mean is cons red acceptabl, since access to these areasis typically restrict ote 2 applies to isolation devi t are locked, sealed, or otherwisesecured in positio' d alows these devices to be verified sed by use of administrative means.Allowing verif on by adminisftrive meam is considered table, since the function oflocking, , or securing components is to ensure that these are not inadvertentlyrepositioned.

PCIVsB 3.6.1.3

BASES

..SURVEILLANCE SR 3.6.1.3.3 (continued)REQUIREMENTS

valves are capable of closing in.the 'environment following aLOCA. Therefore, these valves are allowed to be open'for -limited periods of time. The 31 day Frequency is- consistentwith other PCIV requirements discussed'in SR'3.6.1.3.4.

SR 3.6.1.3.4-

This SR verifies that each primary containment isolation' manual valve and blind flange that is located.outside

'primary containmenj *-nd is required to be closed during,s is closed. The.SR helps to ensure that

. Cb I 5< post accident leakage of radioactive fluids or gases outside)t .*the primary containment boundary is within design limits.

- This SR does not require any testing or valve manipulation.Rather, it involves verification that those PCIVs outsideprimary containment, and capable of being mispositioned, arein the correct position. Since verification of valveposition for PCIVs outside primary.containment is relativelyeasy, the 31 day Frequency was chosen to provide addedassurance that the PCIVs are in the correct position

r' t a Three Notes have been added to this SR. The first Noteallows valves and blind flanges.locateddin high radiation

1 .v reas to be verified 'by use.of administrative controls.l llowing verification by administrative controls is

e\ onsidered acceptable since the primary containment isv St inerted and access to these areas is typically.restricted* P during MODES 1, 2, and 3 for ALARA reasons.'. Therefore; the* e .t probability of misalignment of these PCIVs, once'they have

been verified to be in the proper position; is low. Ad second.Note has been included to clarify that.PCIVs that are

open under administrative controls are not required to meet6 * the'SR during the time that the PCIVs are open. A third

Note states that performance of.the SR is not required fortest taps with a diameter e 1 inch. It is the intent that

5' /this SR must still be met, but actual performance is nott / . required for test taps with a diameter s 1 inch. The Note 3

allowance is consistent with the original plant licensingbasis.

(continued)

PBAPS UNIT 3 B 3.6-25 Revision No. 0:

PCIVs.B 3.6.1.3

BASES


(continued)

SR 3.6.1.3.5

This SR verifies that each primary containment manualisolation valve and blind flange that is located insideprimary contalnment1'and is required to be'closed during

S is closed. The SR helps to ensure thatpost accident leakage of radioactive fluids or.gases outsidethe primary containment boundary is within design limits.For'PCIVs inside primary containment, the Frequency definedas "prior.to entering MODE 2 or 3.from MODE 4 if primary .containment was de-inerted while-in MODE 4, if not.performedwithin the previous 92 days' is appropriate since thesePCIVs are operated under administrative.:controls and theprobability of their misalignment is low.

Two Notes have been added to this SR. The first Note allowsvalves and blind flange's located in high radiation areas tobe verified by.use of administrative controls. Allowingverification by administrative controls is considered

* acceptable since the.primary containment is inerted-andaccess to these areas is typically restricted during

* ODES 1, 2,.aid 3 for ALARA reasons. Therefore, therobability of misalignment of these PCIVs, once.they haveeen Verified to-be in their proper position, is low.. A

second Note has been included to clarify that.PCIVs that arepen under administrative controls are not required to meethe SR during the time'that-the PCIVs are open.

SR 3.6.1.3.6

The traversing incore probe (TIP) shear isolation.valves areactuated'by explosive charges. Surveillance of explosivecharge continuity provides assurance that'TIP valves.willactuate when required. Other..administrative controls, such.as those that limit the shelf life of the explosive charges,must be followed. The 31 day Frequency is based onoperating experience that has demonstrated the reliabilityof the explosive charge.continuity'.

SR 3.6.1;3.7'

Verifying the correct alignment for each manual.valve in theSGIG System required flow paths provides assurance that theproper flow paths exist-for.system operation. This SR doesnot apply to valves That are locked or otherwise secured in

(continued)

PBAPS UNIT 3 B .3.6-26 Revision No. 0

PCIVsB 3.6.1.3

BASES


position, since these valves were verified to be in thecorrect position prior to locking'or securing. This SR doesnot require any testing or valve-manipul'ation;.rather, itinvolves verification that those valves capable of being'

.mispositioned are in the correct position. This SR does notapply'to valves that cannot be inadvertently misaligned,such as check.valves. The 31 day Frequency is based onengineering judgment, is consistent with the proceduralcontrols governing valve operation, and ensures correct

* -valve positions.

SR 3.6.1.3.8

Verifying the isolation time of each power operatedautomatic PCIV is within.limits is required to demonstratioOPERABILITY. MSIVs may be excluded from this SR since MSIVfull closure isolation time is demonstrated by SR 3.6.1.3.9.The isolation time test ensures that the valve will isolatein a time period less than or equal to that'assumed in thesafety analyses. The isolation time-is in accordance withReference 2 or the requirements of the Inservice Testing.Program which ever is more conservative'. The Fr'equency ofthis SR is in accordance with.the requirements of theInservice Testing Program.

SR 3.6.1.3.9

Verifying that the isolation time of each MSIV is within thespecified limits. is required to demonstrate OPERABILITY.,.* The isolation time test ensures that the MSIV will isolatein a time period that does not exceed the times assumed 'inthe DBA analyses. This ensures that the. calculated.-radiological consequences of these events remain within'10 CFR 100 limits. The Frequency of this SR is inaccordance with the requirements of the Inservice Testing.Program.

SR 3.6.1.3.10

Automatic PCIVs close on a primary containment Isolationsignal to prevent leakage of radioactive material from

* .primary containment following a DBA. This SR ensures thateach automatic PCIV will actuate to its isolation positionon a primary containment isolation signal. The LOGIC SYSTEM

(continued)


* PCIV Vs-B 3.6.1.3

1I.

BASES

SURVEILLANCE SR 3.6.1.3.16REQUIREMENTS

(continued) The inflatable seal of each 6 inch and 16 inch primarycontainment purge valve and each 18 inch primary containmentexhaust 'valve must be replaced every 96 months. 'This willallow the.opportunity -for replacement- before gross leakagefailure occurs.

REFERENCES. 1. UFSAR, .Chapter 14.

2. UFSAR, .Table 7.3.1.

3. 10 CFR 50, Appendix 3, Option B.

4. UFSAR, Table 7.3. 1, Note 17.

S . UFSAR, Table 5.2.2.

PBAPS UNIT 3 B 3.6-30 Revision No. 16opnmedment 'No. 223


BASES (continued)


I

SR 3.6.4.1.1 and SR 3.6.4.1.2

Verifying that secondary containment equipment hatches andone access door in each access opening are closed ensuresthat the infiltration of outside air of such a magnitude asto prevent maintaining the desired negative pressure does-not 'occur. Verifying that all such openings are closedprovides adequate assurance that exfiltration from thesecondary containment will not occur. In this application,the term "sealed" has no connotation of leak tightness.Maintaining secondary containment OPERABILITY requires.verifying one door in the access-opening is closed.. Anaccess opening contains one inner and one outer door. 'Insome cases, secondary containment access openings are sharedsuch that a secondary'containment barrier may have multipleinner or multiple outer doors. The intent is to not breachsecondary containment at any time when secondary containmentis required. This is achieved by maintaining the inner orouter portion of the barrier closed at all times. However,all secondary containment'access doors are normally keptclosed,, except when the access opening is being used forentry and exit or when maintenance is being performed on anaccess opening. The 31 day Frequency for these SRs' has beenshown to be adequate, based on operating experience, and isconsidered adequate in view of the other indications of doorand hatch status that are available to the operator.

SR 3.6.4.1.3 and SR 3.6.4.1.4

T GSystem ex( to en9vironmenttruhaporaeteteteP et

To ensure fsinpout r rae,....verifies that thiYi Sstem will rap'dl ~itbl'ish andI-maintain a pressure i he secondary ;on ainment that is.less than the pressure ext al t e secondary containmentboundary. This is confirmed emonstrating that one SGTsubsystem will draw.down t secon containment tok 0.25 inches of vacuu ater gauge i 120 seconds. Thiscannot be accomplis if the secondary c tainment boundaryis not intact.

SR 3.c4.osrates that one SGT subsystemEemainta 2: 0.25 inches of vacuum water gauge for 1 hou ta

{ flqw~te s 10,500 cfm. The I hour test period allows

(continued)


Secondary Containment. B 3.6.4.1

BASES

SURVEILLANCE.REQUIREMENTS

* SR 3.6.4.1.3 and SR 3.6.4 1.4 (continued)

{ enuresecondary containment boundary 151agrTtY. -Sincethese e secondary containmenqt'sts, they need not beperformed wit GT subsy The SGT subsystems aretested on a STAGGERED owever, to ensure that inaddition to the requ ents of LCO . . . either. SGTsubsystem will arm this test. Operating e ence hasshown thes mponents will usually pass the Surveilwhen armed at the 24 month Frequency. Therefore, theF gency'was concluded to be acceptable from a reliability"

REFERENCES I. UFSAR, Section 14.6.3. .



_ ... . f . ~.. TSTF-322, Rev. 2

The SGT Syste exhausts thefecondar*ontai ent atmosp re to the environment through.appropriate tre tment equipment. Each SGT sub stem is design to draw down pressure in the/[secondary] c tainment to 40.25M inches of va um water gauge i s [120] seconds and maintainpressure in. [secondary] containment at inches of vacuu water gauge for 1 hour at aflow rate sF M. to ensure that a ission products released t the secondary] containmentare treatedSR 3.6.4.1.and SR 3.6.4.1 rify.that a pressure. in the [secondary] containment that

* is less than the lowest ,stulated pressur extemal to the [secondary] ontainment boundary can* rapidly be established and maintained. When the SGT System is ope ing as designed, thei

establishment and maintenance~bf [secondary] cQntainment pressure c nnot.be.accomplished if the[secondary] containment boundary is not intact. Establishment of this p assure is confirmed by SR

> 3.6.4.1 which demonstrates that the [secondary].containment can be rawn down to 2 [0.25] inchesof vacf water gauge in •,p 20seconds using one SGT subsystem. R 3.6 4.1 'emonstratesthat the pressure in thegkecondarlontainment can be mainta 2 [ed ] inchef vacuum wate

, 'gauge for.1 hour using one SGT subsystem at a flow rate • Wipcfm. The I hour test period allows[secondary] containment to.be in thermal equilibrium at steady state conditions, The primary purposeof these SRs isto ensure [secondary] containment boundary.integrity. The secondary purpose ofthese SRs is to ensure that the SGT subsystem being tested functions as designed. There is a

) separ-ate LCO with Surveillance Requirements which serves the primary purpose of ensuringOPERABILITY of the SGT System.' These.SRsneed not be performed with each SGT subsystem..The SGT subsystem used for-these Surveillances is staggered to ensure that in addition'to therequirements of LCO 3.6.4.3, either SGT subsystem will perform this test. The inoperability of theSGT System does not necessarily constitute a failure of these Surveillances relative to the[secondary] containment OPERABILITY. Operating experience has shown the'[secondary].containment boundary usually passes these Surveillances when performed at the oronth'Frequency. Therefore, the Frequefiny was concluded to be acceptable from a reliab/lity standpoint.

SCIVsB 3.6.4.2

BASES

APPLICABLE established by SCIVs is required to ensure that leakage fromSAFETY ANALYSES the primary containment is processed by the Standby Gas

(continued) Treatment (SGT) System before being released to the. . environment.

Maintaining SCIVs OPERABLE with isolation times withinlimits ensures that fission products will remain trappedinside secondary containment so that they can be treated by*the.'SGT System prior to.discharge to the environment.

SCIVs satisfy Criterion 3.of the NRC Policy Statement.

LCO .SCIVs form a part of the secondary containment boundary.The.SCIV safety function is related'to control .of:offsiteradiation releases re from WBAs.

* The power operated on valves are considered OPERABLEwhen their isolation times are within limits and the valves

. actuate on an automatic isolation signal. The' valvescovered by this LCO, along with their associated stroketimes, are listed in Reference3.'

The normally closed isolation valves or blind flinges.areconsidered OPERABLE when manual valves are closed or open inaccordance with appropriate administrative controls,automatic SCIVs are de-activated and secured in their closedposition, and.blind flanges are in place. These passiveisolation valves or'devices are listed in Reference 3.

APPLICABILITY In MODES 1, 2, and 3, a DBA could lead to a fission productrelease to the primary containment that leaks to thesecondary containment. Therefore, the OPERABILITY of SCIVsis required..

* In MODES 4 and 5, the probability and consequences.of theseevents are reduced due to pressure and temperaturelimitations in these MODES. Therefore, maintaining SCIVsOPERABLE is not required in MODE 4 or 5, except for othersituations 'under which significant radioactive-releases can

* be postulated, such as during operations with a potentialfor draining. the reactor vessel (OPDRVs), during CORE'ALTERATIONS, or during movement of irradiated fuel

* assemblies in the secondary containment. Moving irradiatedfuel assemblies in the secondary containment may also occurin MODES 1, 2, and 3.

(continued)

P.BAPS UNIT 3 B 3.6-79 B Revision No. 0

SCIVsB 3.6.4.2

BASES.

ACTIONS A.1 and A.2 (continued).

containment penetrations required to be isolated followingan accident,. but no longer capable of being automaticallyisolated, will be. in the isolation position should an eventoccur. The. Completion Time of once per 31 days is

* appropriate because the isolation devices are operated underadministrative controls and the probability of'.theirmisalignment is low. .This Required Action does not requireany-testing or device manipulation. Rather', it involvesverification 'that the affected penetration remains lated.

-Required Acti-on.A.2 is modified bAvrNte7iDN'Wipplies todevices located in high radiation areas'and allows them tobe verified closed by use, of administrative controls.Allowing verification by administrative controls isconsidered acceptable, since access to these areas is.,typically restricted. herefore4 the probability of*misalignment, once they have been verified to be in the

* .proper position, is low.

B.1

With two SCIVs in one or more penetration flow pathsinoperable, the affected penetration flow path must beisolated within.4 hours. The method of isolation must.include the use of-at least one isolation barrier thatcannot be adversely affected by a single active failure.*Isolation barriers.that meet this criterion are a closed andde-activated automatic valve, a closed manual valve, and ablind flange..:. The 4 hour Completion Time is reasonableconsidering the time required to isolate the penetration andthe probability of a DBA, which requires the SCIVs to close,occurring during this short. time, is very low..

The.Condition has been modified by a Note stating thatCondition B is only applicable to penetration flow paths.with two isolation valves. This clarifies.that only .Condition A is entered if one SCIV is inoperable in each oftwo penetrations.

(continued)

PBAPS UNIT 3 B 3.6-81 * Revision No. 0

2. Isolatio cvi that arelockssealed, orherwise

- Ad may be veri byWeof administrative m

Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and.allows these devices to be verified closed by use of adnistrative means. Allowing verificationby administrative means is considered acceptable, since the fimction of locking, scaling, orsecuring components is to ensure that these devices are not inadvertently repositioned.

aIx. 3 , CEOG, BWR4, BWR6)

Required Action .2 is modified by two Notes. Note applies to isolation devices located in highradiation areas and 'ws these devices to be ve closed by use of administrative means.Allowing verification tive means is co idered acceptable, since access to these areasis typically restricted. No2 applies to isolation evices that are locked, sealed, or otherwisesecured in position and alo these devices to verified closed by use of adminitrative means.Allowing verification by Mtve Ceans considered acceptable since the function oflocking, sealing, or securing co ts is ensure that these devices are not inadvertentlyrepositioned.'

Insr 4 (BWOG).

Required Action D.2 is modified b o Notes. te .1 applies to isolation devices located inhigh radiation areas and allows th devices to be closed by use of admnistrative means.Allowing verification by e means is consi acceptable since access to these areasis typically restricted. N6te 2 lies to isolation devices t are locked, sealed, or otherwisesecured in position and allo these devices to be verified c by use of administrative means.Allowing verification by a tive means is considered a table, since the function oflocking, sealing, or components is to ensure that these are not inadvertentlyrepositioned.

SCIVsB 3.6.4.2

BASES

ACTIONS C.1 and C.2(continued)

If any Required Action and associated Completion Time cannot. be met, the plant must be brought to a. MODE in which the LCO

does not apply. ' To achieve this status; the plant must bebrought to at leastHMODE 3 within 12 hours and to MODE 4within 36 hours. The allowed Completion-Times are

* reasonable, based on operating experience, to reach therequired plant conditions from full power conditions in an

. orderly manner and without challenging plant systems.

D.I. D.2. and D.3

If any Required Action and associated Completion Time arenot met, the plant must be placed in a condition in whichthe LCO does not apply. If applicable, CORE ALTERATIONS andthe movement of irradiated fuel assemblies in the secondary

* containment must be immediately suspended. Suspension ofthese activities shall not preclude completion'of movementof a component to a safe position. 'Also, if applicable,

' actions must be immediately initiated to suspend OPDRVs inorder.to minimize the probability of a vessel draindown and.the subsequent potential for fission product release ..Actions must continue until.OPDRVs are suspended.

* Required Action D.1 has been modified by a Note stating that.LCO.3.0.3 is not applicable. If moving irradiated fuelassemblies while in MODE 4 or 5, LCO 3.0.3 would not specifyany action. 'If moving fuel while in MODE 1, 2, or.3, thefuel movement is independent of reactor operations.

* Therefore, in .either case, inability to suspend movement ofirradiated fuel assemblies would not be a sufficient reason

* .- to require a reactor shutdown.

tC CSURVEILLANCE SR 3.6.4.2.1 .It. seREQUIREMENTS * * :.> 5_ -'>

* This SR verifies that each secondary con ainmen aisolation valve and blind flange that is required to beclosed during accident conditions is closed. The SR helps.

* to ensure that post accident leakage of radioactive fluidsor gases outside of the secondary containment boundary iswithin design limits. This SR does not require any testingor valve manipulation. Rather, it involves verificationthat those SCIVs in secondary containment that are capableof being'mispositioned are in the correct position. .

(continued)

PBAPS UNIT 3 B 3.6-82 BRevision No. 0

* SCIVs1B 3.6.4.2

BASES

SURVEILLANCE .REQUIREMENTS '

SR 3.6.4.2.1 (continued)

Since these SCIMs are readily accessible.to personnel during*normal operation and verification of their position'isrelatively easy, the 31 day Frequency was chosen toprovide added assurance that the SCIVs are in the correctpositions.1 ' ' '"

Two Notes have been added to this SR. The first Noteapplies to valves and blind flanges located in high'.radiation areas and allows them to be verified'by use ofadministrative controls. Allowing verification bydministrative controls is considered acceptable, since

access to these areas'is typically restricted duringMODES 1, 2, and 3 for ALARA reasons. Therefore, theprobability of misalignment of these SCIVs, once they havebeen verified to be in the proper position, is low.

A second Note has been included to clarify that SCIYs thatare open under administrative controls are not required tomeet the SR during the time the SCIYs are open.

SR 3.6.4.2.2

Verifying that the isolation time of each power operatedg JE~l automatic SCIV is within limits is required'toI ionstrate OPERABILITY.. The isolation time test ensuresthat the SCIV will isolate in a time period less than orequal to that assumed in the safety analyses. The Frequencyof this SR is in accordance with the Inservice TestingProgram.

* SR 3.6.4.2.3

Verifying that.each automatic SCIV closes on a secondary:containment isolation signal is required to prevent leakageof radioactive material from secondary containment followinga DBA or other accidents. This SR ensures that each

* automatic SCIV will actuate to the isolation position on asecondary containment.isolation signal. The LOGIC.SYSTEMFUNCTIONAL TEST in LCO 3.3.6.2, Secondary ContainmentIsolation Instrumentation,' overlaps this SR to providecomplete-testing of the safety function. The 24 month

* Frequency is based on the need to. perform this Surveillance

(continued)

PBAPS!UNIT 3 * B 3.6-83 Revision No. 0

AC Sources -OperatingB 3.8.1

BASES


equipment powered by the DG. SR 3t.8.1.9.a. corresponds tothe maximum frequency excursion, while SR 3.8.1.9.b andSR 3.8.1.9.c provide steady state voltage and frequencyvalues to which the system must recover following loadrejection. The 24 month Frequency takes into considerationplant conditions required to perform the Surveillance, andis intended to be consistent with expected fuel cyclelengths.

This SR is modified by two Notes. rertiqions thy~rrE cose tol

{deignba;3~xntA~Et as possibs lNe I requires that ifynchronized to offsite bt ts tlke 2erformed

4a t B sing a power fac ~~~l.9. This power factori-s-Z~hosen tesign basis inductiv

l ig tt Gwo ex nc>w

To minimize testing of the DGs, Note 2 allows a single test(instead of two tests, one for each unit) to satisfy therequirements for both units. This is allowed since the mainpurpose of the Surveillance can be met by performing thetest on either unit. If the DG fails one of theseSurveillances,'the DG should be considered inoperable onboth units, unless the cause of the failure can be directlyrelated to only one unit.

SR 3.8.1.10'

Consistent with Regulatory Guide 1.9 (Ref. 3),paragraph C.2.2.8, this Surveillance demonstrates the DGcapability to reject a full load without overspeed trippingor exceeding the predetermined voltage limits. The DG full:load rejection may occur because of a system fault orinadvertent breaker tripping. This Surveillance ensuresproper engine generator load response under the simulatedtest conditions. *This test simulates the loss of the totalconnected load that the.DG experiences following a full loadrejection and verifies that the DG does not trip upon lossof the load. These acceptance criteria provide DG damageprotection. While the DG is not expected to experience thistransient during an event, and continue to be available,this response ensures that the DG is not degraded for futureapplication, including reconnection to the bus if the trip'initiator can be corrected or isolated.

(continued)

PBAPS UNIT 3 B 3.8-26 ' Revision No. 1

TSTF-276, Rev. 2

INSERT I

2. If performed with DG chronized with offsite er,it shall be performed at a wer factor < [0.9].'However, if grid conditions t permit, power

* factor limit is not required to et. Un thiscondition the power factor shall al ed as closeto the limit as practicable.

INSERT 2

3. If performed with DG s chronized with offsite wer,. it shall be performed .a power factor < [0.9].

However, if gid co itions do not permit, the powerfactor limit is no equired to be met. Under thiscondition the wer factor shall be maintained as closeto the limit p ac b e.

Note rs that the DG is tested under load conditions that are as close todesign basis conditionsas pole. When synchronized with offsite power, testing should be perfor/ned at a power factor of_ This power factor is representative of the actual inductive loading a/DG would see underdesign basis accident conditions. Under certain conditions, however, Notes allows the surveillance tobe conducted at a power factor other than < These conditions occur when grid voltage is high,and the additional field excitation needed to g he power factor to results in voltages on the.emergency busses that are too high. Under th se conditions, the p r factor should be maintained asclose as practicable t hile still mainta ning acceptable v age limits on the emergency busses.]n other circumstanceseid voltage may such that the G excitation levels needed to obtain apower factor of ay n cause unaccept ble voltages n the emergency busses, but the excitationlevels are in exc f those ommended f the DG. such cases, the power factor shall bemaintained as pra a to [0.9] xeding the DG excitation limits.

AC Sources - OperatingB 3.8.1

BASES

SURVEILLANCE SR' 3.8.1.10 (continued)REQUIREMENTS

z~n mnir to ensure ta h 6is tested W~il~r-,* '. kQ~~~on itiofir-that are as close -to dEpl>>~zln3

* possible, testing ormed using a power factor< 0.89. This actor is c o representative

- h a esign basis inductive ng G wou

The 24 month Frequency takes into consideration plantconditions required to perform the Surveillance,.and isintended to bewinststep$wiltAppected fehs.

This SR is fled by :-Note'y Cominim i the. . D (s Note al I qws a single test (instead'of two tests,

. one for.'each unit) to satisfy the requirements for bothunits.. This.is allowed since the main purpose of theSurveillance can be met by performing the test on eitherunit.- If the DG. fails one of these Surveillances, the. DGshould be considered inoperable on both units, unless the

* cause:of the'failure can be directly related to only oneunit.

SR 3.8.1.11

Consistent with Regulatory Guide 1.9 (Ref.'3),paragraph.C.2.2.4, this Surveillance demonstrates the asdesigned operation of the standby power sources during loss

'' of the offsite source. This test verifies all actionsencountered from the loss of offsite power,.includingshedding of all loads and energization of the emergency.buses and respective loads from the DG. It furtherdemonstrates the capability of the DG to automaticallyachieve the required voltage and frequency within the

. specified time.

The DG auto-start and energization of the associated 4 kYemergency bus time of 10 seconds is derived fromrequirements of the accident analysis for responding to adesign basis large break LOCA. The Surveillance should becontinued for a minimum of 5 minutes in order to demonstratethat all starting transients have decayed and stability hasbeen achieved.

I �_Pvu I vlu�u I


TSTF-276, Rev. 2

INSERT 1 B.

2. If performed with G synchronize ith offsite power,'it shall be performed a power actor < [0.9].However, if grid condi d not permit, the power

* factor limit is not required be met. Under thiscondition the power fac s be maintained as closeto the limit as practi e. .

INSERT 2

3. If perfo d with DG synchronized with offsite p er,it shall performed at. a power factor < [0.9]..How er, if grid conditions do not perinit, the powerfac r limit is not required to be met. Under this

* ndition th'e pwer ifactor shal he maintained ascse ;e isra. ., '

9N

l NSERTE09 At(3{) N.

Note nsures that the DG is tested under load conditions that are as close to iesign basis conditionsas ssible. When synchronized with offsite power, testing should be perfored at a power factor of

This power factor is representative of the actual inductive loading apG would see underesgn basis accident conditions. Under certain conditions, however, Not allows the surveillance to

be conducted at a power factor other than < These conditions occur when grid voltage is high,and the additional field excitation needed to g t the power factor to < iresults in voltages on theemergency busses that are too high. Under thse conditions, the po factor should be maintained asclose as practicable t . hile still main ning acceptable vol ge limits on the emergency busses.In. other circumstances, the voltage may such that the D excitation levels needed to obtain a*

* * power factor of ay not unaccept ble voltageso the emergency busses, but the excitationlevels are in excesso ose reco ended f the DG. uch cases, the power factor shall be:maintained as close as cticable t (0.9] out ex ing the DG excitation limits.

l __ _ _ _ _ _ _

* AC Sources-OperatingB 3.8.1 .

BASES

SURVEILLANCE SR 3.8.1.14REQUIREMENTS

(continued) Consistent with Regulatory Guide 1.9 (Ref. 3),paragraph C.2.2.9, this Surveillance requires demonstrationthat the DGs. can start and run continuously at full loadcapability for an interval of not less than 24 hours-22 hours of which is at a load equivalent to 90% to 100% ofthe continuous duty rating of the DG, -and 2 hours' of whichis.at a load equivalent to 105%.to 110% of the continuousddty rating' of the DG. The DG starts for this Surveillancecan be performed either from standby or hot conditions. Theprovisions for prelube and warmup, discussed in SR 3.8.1.2,

* and for gradual loading, discussed in SR 3.8.1.3, areapplicable to this SR.

This Surveillance.verifies, indirectly, that the DGs arecapable of synchronizing and accepting loads equivalent topost accident loads. The DGs are tested at a load.'approximately equivalent to-their continuous duty rating,even though the post accident loads exceed the continuousrating. This is acceptable because.regular surveillancetesting at post accident loads is injurious to the DO, andimprudent because the same level of assurance in the abilityof the DG to provide post accident loads can be developed bymonitoring engine parameters during surveillance testing.The values of the testing parameters can then be

* qualitatively compared to expected values at post accidentengine loads. In making this comparison it' is necessary toconsider the.engine 'parameters as interrelated indicators ofremaining DG capacity, rather than independent indicators.The important engine parameters to be considered in makingthis comparison include, fuel rack position, scavenging airpressure, exhaust temperature and pressure, engine. output,jacket water temperature, and lube oil temperature. Withthe DG operating at or near continuous rating and theobserved values of the above parameters less 'than expectedpost accident values, a qualitative extrapolation whichshows the DG 'is capable of accepting post accident loads canbelmade without requiring det imental testing.

* esr-that the DG is tesd.ne o*(c lo s to desig C044:+ions as'-~~

7ossible, tsign apwr facto/c0.89. bi-:-rfcoiscoe ilc4Qsenta.ieo

asis inductiveloading thatoud

(continued)

.PBAPS UNIT 3 B 3.8-31 * Revision No. 0


BASES


- A load band is provided to' avoid routineov a of the DG. Routine overloading.may'result inmore frequent'teardown inspections:in accordance with vendorrecommendations in order to maintain DG.OPERABILITY.

The 24 month Frequency takes into consideration plantconditions required to perform the Surveillance; and is.intended to be consistent with expected fuel cyclellengths.

This Surveillance has been modified by three Notes. Note 1states that momentary transients due to changing bus loads'do not invalidate this test. Similarly, momentary powerfactor t an rins aboy -tbe 1imit do not. invalidate theote os2 i providedst (nrstetadof twoatsthIsofefoir-lectrhutl power distribution system voltage is high, it may

*not be powdsibe to raise DG output voltage witholtlnce canngmetan overvoltage cofitheteson eith erg nit S.If Thereforeasto ensure the bus voltagnces thDs huloadsb cond DGsi are not

oplaced in an unsafe conditns, uniesth is test, the pofierfactor limit doestly elt ve to be met itf.:rd-xoltage orTi Seergenuvelading does not permit the powersnactnor limit

o I > orto pertVet when the. DG i s ti ed to the gri d. When thi s-occurs, the power factor should be oaintasnedqas closehto

\<-- -~'~ -S~tf es (istea oftwo tests- one foreac .'unito to satisfyte requ irements for both units. oThisis allowed since the main purpose ol'the Surveillance can be'met qby performing the test on either unit. If the DG failsone of these Surveillances, the DGishould.be consideredvinoperable on bothfunits, unlesst.abthe cause of the failurecan be directly related to only one unit.s

SR 3.8.1.15..

This Surveillance demonstrates that the diesel engine canrestart from a hot condition, such as subseuent'to shutdownfrom normal Surveillances, and achieve-the required voltage

* and frequency within 10 seconds. The minimum voltage andfrequency stated in -the SR are those necessary to ensure theDG can accept DBA loading while maintaining acceptable

* . voltage and frequency levels. Stable operation at thenominal voltage-and frequency values is also essential to

* ~establishing DG OPERABILITY, but a time constraint -is not.imposed. This' is because a typical DG will experience a

* ' '(continued)

'PBAPS UNIT 3 B 3.8-32' Revision No. 0

TSTF-276, Rev. 2

INSERT I

2. If performed with G synchronized w site power,it shall beperforine t a power fac t0.9].However, if grid condi ns do permit, the powerfactor limit is not require met. Under thiscondition the power fact s 11 be maintained as closeto, the limit as practice.

INSERT 2

3. If perfo ed with DG synchronized with o ite power,it sh be performed at.a power factor < [0.9].Hg ever, if grid conditions do notpermit, the wer

ctor limit is not required to be met. Under this{condition the power factor shall be maintained as cto the limit as practicable.

INSERTWI 1 .

Note 2 ensures that the DG is tested under load conditions that are as close to design basis conditionsas possible. When synchronized with offsite power, testing should be performed at a power factor of.<@ This power factor is representative of the actual inductive loading a DG would see under

esign basis accident conditions. Under certain conditions, however, Note 2 allows the surveillance tobe conducted at a power factor other than < These conditions occur when grid voltage is high,and the additional field excitation needed to g the power factor to < results in voltages on theemergency busses that are too high. Under se conditions, the po factor should be maintained asclose as practicable to hue still main ning acceptable v ge limits on the emergency busses.In other circumstances, th id voltage may such that th G excitation levels needed to obtain apower factor o ay net cause unaccep ble voltages n the emergency busses, but the excitationlevels are in exces ofthose commended for the DG. such cases,the power factor shall bemaintained as cloas practicble t thout ex eding the DO excitation limits.

\ A . . ..

C-

AC Sources - ShutdownB 3.8.2

.j BASES'

LCO(continued)

A_.

0.

*14

offsite circuit. In addition, some equipment that may berequired by Unit 2 is powered from Unit 3 sources (e.g.,Standby Gas Treatment (SGT) System). Therefore, onequalified circuit between.the offsite. transmission networkand the Unit 3 onsite Class lE AC electrical. powerdistribution subsystem(s), and one DG.(not. necessarily adifferent DG than those being'used.to meet LCO 3.8.2.brequirements)' capable of supplying power to one of the

* required Unit 3'subsystems of each of the.requiredcomponents must also be OPERABLE. Together, OPERABILITY ofthe 'required offsite circult(s).and required DG(s) ensuresthe availability of sufficient AC sources to operate the :plant in' a'safe.manner and to mitigate the consequences .ofpostulated events during shutdown (e.g., fuel handlingaccidents and reactor vessel draindown).v

The qualified Unit 2 offsite circuit must be capable of* maintaining rated frequency and voltage while connected tothe respective Unit 2.4 kV.emergency bus(es),.and of-accepting required loads during an accident. Qualifiedoffsite circuits are those that are described in the'UFSARj,Technical Specification Bases Section 3.8.1 and are part ofthe licensing basis for the unit. A Unit 2 offsite.circuitconsists of the incoming breaker and disconnect to thestartup 'and emergency auxiliary transformer, the respectivecircuit path to the emergency auxiliary transformer, and thecircuit path to-the Unit 2.4 kV emergency'buses-required byLCO3.8.8, including feeder breakers to the required Unit 24 kV emergency buses. A qualified'Unit 3 offsite circuit'srequirements are the same as the Unit 2 circuit'srequirements, except that the circuit path, including thefeeder breakers, is to the Unit 3 4 kV emergency.busesrequired to be OPERABLE by LCO 3.8.8.

The required DGs must be capable.of starting,. acceleratingto rated speed and voltage,'and connecting to theirrespective Unit 2 emergency-bus on detection of busundervoltage. -This sequence must be accomplished within10 seconds. Each DG must also be capable of acceptingrequired loads within the assumed loading sequenceintervals, 'and. must continue to operate until offsite powercan be restored to the 4.kV emergency buses.' Thesecapabilities, are required to be met from a variety of'initial conditions such as DG in standby with engine hot andDG in standby with engine at ambient conditions. Additional

(continuedI

PBAPS .UNIT 3 B 3.8-42 Revision No. 35

peach bottom, units 2 & 3 license amendment request ... · pbaps incorporation of generic...

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