Text

Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program
	ML100900224
Person / Time
Site:	Hope Creek
Issue date:	03/19/2010
From:	Jamila Perry; Public Service Enterprise Group
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	LAR H10-01, LR-N10-0015
	Download: ML100900224 (179)
	v • d • e

PSEG RO. Box 236, Hancocks Bridge, NJ 08038-0236 MAR 19 201W 0 PSEG NuclearLLC 10 CFR 50.90 LR-N 10-0015 LAR H10-01 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Hope Creek Generating Station Facility Operating License No. NPF-57 NRC Docket No. 50-354

Subject:

APPLICATION FOR TECHNICAL SPECIFICATION CHANGE REGARDING RISK-INFORMED JUSTIFICATION FOR THE RELOCATION OF SPECIFIC SURVEILLANCE FREQUENCY REQUIREMENTS TO A LICENSEE CONTROLLED PROGRAM In accordance with the provisions of 10 CFR 50.90 of Title 10 of the Code of Federal Regulations, PSEG Nuclear, LLC (PSEG) requests an amendment to the facility operating license listed above for Hope Creek Generating Station (HCGS).

The proposed amendment would modify HCGS Technical Specifications (TS) by relocating specific surveillance frequencies to a licensee-controlled program, the Surveillance Frequency Control Program, with the implementation of Nuclear Energy Institute (NEI) 04-10, "Risk Informed Method for Control of Surveillance Frequencies."

The changes are consistent with NRC-approved Industry Technical Specifications Task Force Standard Technical Specification Change Traveler, TSTF-425, Revision 3 "Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5b." The availability of this TSTF was announced in the FederalRegisteron July 6, 2009 (74 FR 31996). provides a description of the proposed change,.the requested confirmation of applicability, and plant-specific verifications. Attachment 2 provides documentation of the Probabilistic Risk Assessment (PRA) technical adequacy. Attachment 3 provides the existing TS pages marked up to show the proposed changes. Attachment 4 provides the existing TS Bases pages marked up to reflect the proposed changes (for information only). Attachment 5 provides the proposed No Significant Hazards Consideration.

There are no regulatory commitments contained in this letter.

PSEG requests approval of the proposed license amendment by March 31, 2011 with implementation within 120 days. The proposed changes have been reviewed by the Plant Operations Review Committee. In accordance with the requirements of 10 CFR 50.91 (b)(1), a copy of this application, with attachments, has been sent to the State of New Jersey.

Document Control Desk Page 2 LR-NI0-0015 If you have any questions or require additional information, please contact Mr. Jeffrie Keenan at (856) 339-5429.

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

Executed on /0 /0 (Date)

Sincerely, John F. Perry Site Vice President Hope Creek Generating Station Attachments (5)

S. Collins, Regional Administrator - NRC Region I R. Ennis, Project Manager - USNRC NRC Senior Resident Inspector - Hope Creek P. Mulligan, Manager IV, NJBNE Commitment Coordinator- Hope Creek PSEG Commitment Coordinator - Corporate

ATTACHMENT 1 LAR H10-01 LR-N10-0015 ATTACHMENT 1 EVALUATION OF THE PROPOSED CHANGE:

LICENSE AMENDMENT TO ADOPT TSTF-425, REVISION 3.

"RELOCATE SURVEILLANCE FREQUENCIES TO LICENSEE CONTROL -

RITSTF INITIATIVE 5b" TABLE OF CONTENTS

1.0 DESCRIPTION

...................................................................................................... 2 2.0 A S S E S S ME NT ............................................................................................................ 2 2.1 Applicability of Published Safety Evaluation .................................................... 2 2.2 Optional Changes and Variations ..................................................................... 2

3.0 REGULATORY ANALYSIS

....................................................................................... 4 3.1 No Significant Hazards Consideration ............................................................ 4 3.2 Applicable Regulatory Requirements ............................................................... 4 3.3 Conclusions ............................................................................................... 4

4.0 ENVIRONMENTAL CONSIDERATION

...................................................................... 5 5.0 R E FER E NC ES .............................................................................................. .............. 5 1 of 5

ATTACHMENT 1 LAR H10-01 LR-N10-0015

1.0 DESCRIPTION

The proposed amendment would modify the Hope Creek Generating Station (HCGS)

Technical Specifications (TS) by relocating specific surveillance frequencies to a licensee controlled program with the adoption of Technical Specification Task Force (TSTF) - 425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control - Risk Informed Technical Specification Task Force (RITSTF) Initiative 5b." Additionally, the change would add a new program, the Surveillance Frequency Control Program (SFCP) to TS Section 6, Administrative Controls.

The changes are consistent with NRC-approved Industry/TSTF Standard Technical Specifications (STS) Change Traveler, TSTF-425, Revision 3 (ADAMS Accession No. ML090850642). The Federal Register notice published on July 6, 2009 (74 FR 31996) announced the availability of this TS improvement.

2.0 ASSESSMENT 2.1 Applicability of Published Safety Evaluation PSEG has reviewed the safety evaluation (SE) dated July 6, 2009. This review included a review of the NRC staffs evaluation, TSTF-425, Revision 3, and the requirements specified in NEI 04-10, Rev. 1 (ADAMS Accession No. ML071360456). includes PSEG's documentation with regard to Probabilistic Risk Assessment (PRA) technical adequacy consistent with the requirements of Regulatory Guide 1.200, Revision 1 (ADAMS Accession No. ML070240001), Section 4.2, and describes any PRA models without NRC-endorsed standards, including documentation of the quality characteristics of those models in accordance with Regulatory Guide 1.200.

PSEG has concluded that the justifications presented in the TSTF proposal and the safety evaluation prepared by the NRC staff are applicable to HCGS and justify this amendment to incorporate the changes to the HCGS TS.

2.2 Optional Changes and Variations The proposed amendment is consistent with STS changes described in TSTF-425, Rev

3. PSEG proposes the following variations or deviations from the NRC approved TSTF, as identified below.

1. Revised (clean) TS pages are not included in the amendment request because of the number of affected pages, the straightforward nature of the proposed changes, and the outstanding license amendment requests affecting the same pages. Providing only the mark ups satisfies the requirements of 10 CFR 50.90 in that the mark ups provide full descriptions of the proposed changes. This deviation from the NRC staff's model application (74 FR 31966) is administrative in nature and does not impact the NRC staff s model safety evaluation published in the same Federal Register Notice. As a result of this deviation, the contents 2 of 5

ATTACHMENT 1 LAR H10-01 LR-N10-0015 and numbering of the attachments for this amendment request differ from the attachments specified in the NRC staffs model application. HCGS TS mark ups and bases mark ups are provided in Attachments 3 and 4, respectively.

2. The definition of STAGGERED TEST BASIS is being retained in HCGS TS Definition Section 1.46 since this terminology is mentioned in Administrative TS Section 6.16, "Control Room Envelope Habitability Program," which is not the subject of this amendment request and is not proposed to be changed. This is an administrative deviation from TSTF-425 with no impact on the NRC staff's model safety evaluation dated July 6, 2009 (74 FR 31996). Additionally, HCGS TS also has test scheduling strategies for logic trains, channels and other components within systems that are also being relocated, consistent with guidance in NEI 04-10, Rev. 1 (Reference 3)1. Similar to a STAGGERED TEST BASIS requirement, these SRs require at least one logic train, channel or component to be tested within one interval and all logic trains, channels or components to be tested within N intervals, where N is the total number of logic trains, channels or components subject to the test requirement. The following SRs contain test scheduling requirements proposed for relocation:

" SR 4.3.1.3, Reactor Trip System Response Time

" SR 4.3.2.3, Isolation System Response Time

" SR 4.3.3.3, ECCS Response Time z SR 4.3.11.6, RPS Response Time Changes to these scheduling requirements will be controlled under the Surveillance Frequency Control Program (SFCP) which provides the necessary administrative controls for changes to test strategies.

3. Because HCGS has not adopted the NUREG-1433 improved Standard Technical Specifications (ISTS), there are a number of differences between the TSTF Surveillance numbers and HCGS Surveillance numbers. In addition, the Administrative Controls section of TS is Section 6.0 for HCGS versus Section 5.0 for ISTS. These are administrative deviations from TSTF-425 with no impact on the NRC staff's model safety evaluation (74 FR 31996).

For NUREG-1433 Surveillances that are not contained in HCGS TS, the corresponding NUREG-1433 mark-ups included in TSTF-425 for these Surveillances are not applicable to HCGS. This is also an administrative deviation from TSTF-425 with no impact on the NRC staffs model safety evaluation (74 FR 31996).

For the HCGS plant-specific Surveillances that are not contained in NUREG-1433 and therefore not included in the TSTF-425 mark ups, PSEG has determined that the relocation of the Frequencies for these HCGS plant-specific Surveillances is consistent with TSTF-425, Revision 3, and with the NRC staffs model safety evaluation dated July 6, 2009 (74 FR 31996), including the scope Revision 1 to NEI 04-10 is provided to address test strategy (e.g. Staggered Test Basis) in addition to frequency. Under the proposed change, the Frequencies of all Surveillance Requirements (except those that reference other programs for the specific interval or that are event driven) are relocated.

3 of 5

ATTACHMENT 1 LAR H10-01 LR-N10-0015 exclusions identified in Section 1.0, "Introduction," of the model safety evaluation.

In addition, many of these HCGS plant specific Surveillances are identical to Limerick Generating Station Surveillances that were approved by the NRC for relocation to the SFCP by Amendments 186 and 147 (ADAMS Accession No. ML062420049), Reference 5.

The HCGS plant-specific Surveillances involve fixed periodic frequencies.

Changes to the Frequencies for these plant-specific Surveillances would be controlled under the Surveillance Frequency Control Program (SFCP). The SFCP provides the necessary administrative controls to require that Surveillances related to testing, calibration and inspection are conducted at a frequency to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the Limiting Conditions for Operation will be met. Changes to Frequencies in the SFCP would be evaluated using the methodology and probabilistic risk guidelines contained in NEI 04-10, Revision 1, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies,"

(ADAMS Accession No. ML071360456), as approved by NRC letter dated September 19, 2007 (ADAMS Accession No. ML072570267). The NEI 04-10, Revision 1 methodology includes qualitative considerations, risk analyses, sensitivity studies and bounding analyses, as necessary, and recommended monitoring of the performance of systems, components, and structures (SSCs) for which Frequencies are changed to assure that reduced testing does not adversely impact the SSCs. In addition, the NEI 04-10, Revision 1 methodology satisfies the five key safety principles specified in Regulatory Guide 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," dated August 1998 (ADAMS Accession No. ML003740176) (Ref.

6), relative to changes in Surveillance Frequencies. Therefore, the proposed relocation of the HCGS plant-specific Surveillance Frequencies is consistent with TSTF-425 and with the NRC staff's model safety evaluation dated July 6, 2009 (74 FR 31996).

3.0 REGULATORY ANALYSIS

3.1 No Significant Hazards Consideration PSEG has reviewed the proposed no significant hazards consideration (NSHC) determination published in the Federal Register dated July 6, 2009 (74 FR 31996).

PSEG has concluded that the proposed NSHC presented in the Federal Register Notice is applicable to HCGS and is provided as Attachment 5 of the submittal, which satisfies the requirements of 10 CFR 50.91 (a).

3.2 Applicable Regulatory Requirements A description of the proposed changes and their relationship to applicable regulatory requirements is provided in TSTF-425, Revision 3 (ADAMS Accession No. ML090850642) and the NRC staffs model safety evaluation published in the Notice of Availability dated July 6, 2009 (74 FR 31996). PSEG has concluded that the relationship 4 of 5

ATTACHMENT 1 LAR H10-01 LR-N10-0015 of the proposed changes to the applicable regulatory requirements presented in the Federal Register notice is applicable to HCGS.

3.3 Conclusions In conclusion, based on the considerations above, PSEG has concluded that (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

4.0 ENVIRONMENTAL CONSIDERATION

PSEG has reviewed the environmental consideration included in the NRC staff's model safety evaluation published in the Federal Register on July 6, 2009 (74 FR 31996).

PSEG has concluded that the staffs findings presented therein are applicable to HCGS and the determination is hereby incorporated by reference for this application.

5.0 REFERENCES

1. TSTF-425, "Relocate Surveillance Frequencies to Licensee Control-RITSTF Initiative 5B," Revision 3.

2. Federal Notice of Availability published on July 6, 2009 (74FR31996)

3. NEI 04-10, Revision 1, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies," April 2007 (ADAMS Accession Number: ML071360456)

4. Regulatory Guide 1.200, Revision 1, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," January 2007 (ADAMS Accession Number:

ML070240001)

5. NRC Letter to Exelon, "LIMERICK GENERATING STATION, UNITS 1 AND 2- ISSUANCE OF AMENDMENT RE: RELOCATE SURVEILLANCE TEST INTERVALS TO LICENSEE-CONTROLLED PROGRAM (TAC NOS.

MC3567 AND MC3568), dated September 28, 2006 (ADAMS Accession No. ML062420049).

6. Regulatory Guide 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," dated August 1998 (ADAMS Accession No. ML003740176) 5 of 5

ATTACHMENT 2 LAR H10-01 LR-N10-0015 ATTACHMENT 2 Hope Creek PRA TECHNICAL ADEQUACY Assessment

Hope Creek PRA Technical Adequacy Assessment TABLE OF CONTENTS Section Page 2 .1 Ove rview ................................................................................................... .. ... 1 2.2 Technical Adequacy Of The PRA Model ........................................................... 3 2.2.1 Plant Changes Not Yet Incorporated Into The PRA Model .................... 5 2.2.2 Applicability Of Peer Review Findings And Observations ...................... 5 2.2.3 Consistency With Applicable PRA Standards ....................................... 6 2.2.4 Identification Of Key Assumptions ......................................................... 7 2.3 External Events Considerations ........................... 11 2.3.1 Discussion Of External Events Evaluations .......................................... 12 2.4 S um m ary .................................................... ........................... .................... . .. 1 4

-2.5 R efe re nce s ......................... ........................................................... ........... 5 i

Hope Creek PRA Technical Adequacy Assessment Attachment 2 - PRA Technical Adequacy 2.1 Overview The implementation of the Surveillance Frequency Control Program (also referred to as Tech Spec Initiative 5b) at Hope Creek will follow the guidance provided in NEI 04-10, Revision 1 [Ref. 1] in evaluating proposed surveillance test interval (STI) changes.

The following steps of the risk-informed STI revision process are common to proposed changes to all STIs within the proposed licensee-controlled program.

Each STI revision is reviewed to determine whether there are any commitments made to the NRC that may prohibit changing the interval. If there are no related commitments, or the commitments may be changed using a commitment change process based on NRC endorsed guidance, then evaluation of the. STI revision would proceed. If a commitment exists and the commitment change process' does not permit the change, then the STI revision would not-be implemented.

. A qualitative analysis is prformed'.,for each STI. revision that involves

<,, several considerations as explained in NEI 04-10 [Ref. 1].

. Each STI revision is reviewed by an Expert Panel, referred to as ýthe

. Integrated Decision-making Panel (IDP), which is normally the same panel as is used for Maintenance Rule implementation, but with the addition of specialists with experience in surveillance tests and system or component reliability. If the IDP approves the STI revision, the change is implemented and documented for future audits by the NRC. If the IDP does not approve the STI revision, the STI value is left unchanged.

Performance monitoring is conducted as recommended by the IDP. In some cases, no additional monitoring may be necessary beyond that already conducted under the Maintenance Rule. The performance monitoring helps to confirm that no failure mechanisms related to the revised test interval become important enough to alter the information provided for the justification of the interval changes.

The IDP is responsible for periodic review of performance monitoring results. If it is determined that the time interval between successive performances of a surveillance test is a factor in the unsatisfactory performances of the surveillance, the IDP returns the STI back to the previously acceptable STI.

In addition to the above steps, the PRA is used when possible to quantify the effect of a proposed individual STI revision compared to acceptance criteria in Figure 2 of NEI 04-10, Revision 1. Also, the cumulative impact 1

Hope Creek PRA Technical Adequacy Assessment of all risk-informed STI revisions on all PRAs (i.e., internal events, external events and shutdown) is also compared to the risk acceptance criteria as delineated in NEI 04-10, Revision 1.

For those cases where the STI can not be modeled in the plant PRA (or where a particular PRA model does not exist for a given hazard group), a qualitative or bounding analysis is performed to provide justification for the acceptability of the proposed test interval change.

The NEI 04-10, Revision 1 methodology endorses the guidance provided in Regulatory Guide 1.200, Revision 1 [Ref. 2], "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities." The guidance in

.RG-1.200 indicates that the following steps should be followed when performing PRA

"assessments:

1. Identify the parts of the PRA used to support the application

- SSCs, operational characteristics affected by.th'e'application and how these are' implemenied in the PRA model ."

A definition 6f the acceptance criteria used for the application

2. Identify the scopepof risk contributors addressed by the PRA model.

- If not full scope (i.e. internal and external), identify appropriate compensatory measures or provide bounding arguments to address the risk contributors not addressed by the model.

3. Summarize the risk assessment methodology used to assess the risk of the application

- Include how the PRA model was modified to appropriately model the risk impact of the change request.

4. Demonstrate the Technical Adequacy of the PRA

- Identify plant changes (design or operational practices) that have been incorporated at the site, but are not yet in the PRA model and justify why the change does not impact the PRA results used to support the application.

- Document peer review findings and observations that are applicable to the parts of the PRA required for the application, and for those that have not yet been addressed justify why the significant contributors would not be impacted.

- Document that the parts of the PRA used in the decision are consistent with applicable standards endorsed by the Regulatory Guide (currently, RG-1.200 2

Hope Creek PRA Technical Adequacy Assessment Revision 1 includes only internal events PRA standard). Provide justification to show that where specific requirements in the standard are not adequately met, it will not unduly impact the results.

- Identify key assumptions and approximations relevant to the results used in the decision-making process.

Given the broad scope of potential Initiative 5b applications and the fact that the impact of such assumptions differs from application to application, each of the issues encompassed in Items 1 through 3 will be covered with the preparation of each individual PRA assessment made in support of the individual STI interval requests. The purpose of the remaining portion of this appendix is to address the requirements identified in item 4 above.

2.2 `Technical Adequacy of the PRA Model .

The HC108B version of the Hope Creek PRA mnbdel is the most reerent evaluation of the Unit 1 riski,,profile at Hope Creek for internal event challenges:J.',,The Hope Creek PRA modeling is highly, detailed, incl'uiding ,a wide variety of initiating events, modeled systems, operator actions, and common ,cause events. The PRA model quantification process used for the Hope Creek PRA is based on the event tree / fault tree methodology, which is a well-known methodology in the industry.

PSEG employs a multi-faceted approach to establishing and maintaining the technical adequacy and plant fidelity of the PRA models for all PSEG nuclear generation sites.

This approach includes both a proceduralized PRA maintenance and update process, and the use of self-assessments and Hope Creek PRA.

PRA Maintenance and Update The PSEG risk management process ensures that the applicable PRA model remains an accurate reflection of the as-built and as-operated plants. This process is defined in the PSEG Risk Management program, which consists of a governing procedure (ER-AA-600, "Risk Management") and subordinate implementation procedures. PSEG procedure ER-AA-600-1015, "FPIE PRA Model Update" delineates the responsibilities and guidelines for updating the full power internal events PRA models at PSEG nuclear 3

Hope Creek PRA Technical Adequacy Assessment generation sites. The overall PSEG Risk Management program, including ER-AA-600-1015, defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models (e.g., due to changes in the plant, errors or limitations identified in the model, industry operating experience), and for controlling the model and associated computer files. To ensure that the current PRA model remains an accurate reflection of the as-built, as-operated plants, the following activities are routinely performed:

, Design changes and procedure changes are reviewed for their impact on the PRA model.

New engineering calculations and revisions to existing calculations are reviewed for their impact on the PRA model.

Maintenance unavailabilities are captured, and their impact on CDF is trended.

- Plant specific initiating event frequencies, failure rates ..and maintenance unavailabilities are updated approximately every four years:,

In addition to these activities, PSEG risk management procedures provide;the guidance for particular risk management and PRA quality and maintenance activities. This guidance includes:

Documentation of the PRA model, PRA products, and bases documents.

0 The approach for controlling electronic storage of Risk Management (RM) products including PRA update information, PRA models, and PRA applications.

0 Guidelines for updating the full power, internal events PRA models for PSEG nuclear generation sites.

Guidance for use of quantitative and qualitative risk models in support of the On-Line Work Control Process Program for risk evaluations for maintenance tasks (corrective maintenance, preventive maintenance, minor maintenance, surveillance tests and modifications) on systems, structures, and components (SSCs) within the scope of the Maintenance Rule (10CFR50.65 (a)(4)).

In accordance with this guidance, regularly scheduled PRA model updates nominally occur on an approximately 3-year cycle; longer intervals may be justified if it can be shown that the PRA continues to adequately represent the as-built, as-operated plant.

4

Hope Creek PRA Technical Adequacy Assessment PSEG completed the HC108A update to the Hope Creek PRA model in September 2008, which was the result of a regularly scheduled update of the PRA model. PSEG subsequently completed the HC108B update to the Hope Creek PRA model in November 2008 to incorporate a significant procedural change involving SSW/SACS system operation and to resolve notable comments from the Hope Creek PRA Peer Review performed in October 2008.

As indicated previously, RG-1.200 also requires that additional information be provided as part of the LAR submittal to demonstrate the technical adequacy of the PRA model used for the risk assessment. Each of these items (plant changes not yet incorporated in to the PRA model, relevant peer review findings, consistency with applicable PRA Standards, and the identification of key assumptions) will be discussed in turn.

.'.,2.211 Plant Changes Not Yet Incorporatedinto the PRA Model

'APRA updating requirements evaluation F(URE - PSEG PRA model update'tracking database) is created for all issues that are identified',that could impact the PRA-model.

The' URE database includes the identification of thos4Vplant changes that could impact the PRA model.

As part of the PRA evaluation for each STI change request, a review of open items in the URE database for Hope Creek will be performed and an assessment of the impact on the results of the application will be made prior to presenting the results of the risk analysis to the IDP. If a non-trivial impact is expected, then this may include the performance of additional sensitivity studies or model changes to confirm the impact on the risk analysis.

2.2.2 Applicability of Peer Review Findings and Observations Several assessments of technical capability have been made, for the Hope Creek Unit 1 PRA model. These assessments are as follows and further discussed in the paragraphs below.

An independent PRA peer review of the Hope Creek Rev. 0 PRA model (i.e., the Individual Plant Examination (IPE) model) was conducted as a 5

Hope Creek PRA Technical Adequacy Assessment pilot project under the auspices of the BWR Owners' Group in October 1996 following the DRAFT Industry PRA Peer Review process [Ref. 3].

This peer review included an assessment of the PRA model maintenance and update process.

A follow-up independent PRA peer review of the Hope Creek Rev. 1 PRA model was conducted under the auspices of the BWR Owners' Group in November 1999 following the revised Industry PRA Peer Review process

[Ref. 4]. This peer review included an assessment of the PRA model maintenance and update process.

During 2005 and 2006, the Hope Creek PRA model results were evaluated in the BWR Owners' Group PRA cross-comparisons study performed in support of implementation of the mitigating systems performance indicator (MSPI) process.

" A PRA Peer Review of the Hope Creek HC108A PRA was performed during October 2008. The peer review was performed against Addendum B of the ASME PRA Standard [Ref. 5]. The results of the PRA Peer Review indicated that a very small number of the supporting requirements

.(SRs) were "Not Met" for Capability Category II.

A summary of the disposition of the 1.999 Industry PRA Peer Review facts and observations (F&Os) for the Hope Creek PRA models was documented as part of the statement of PRA capability for MSPI in the Hope Creek MSPI Basis Document [Ref. 6].

As noted in that document, there were no open level A or level B F&Os from the 1999 peer review.

2.2.3 Consistency with Applicable PRA Standards As indicated above, a formal peer review was performed in October 2008 and the final peer review report was issued in March 2009 [Ref. 7]. This peer review was performed against Addendum B of the ASME PRA Standard [Ref. 5], the criteria in RG-1.200, Rev.

1 [Ref. 2] including the NRC positions stated in Appendix A of RG-1.200, Rev. 1 and further issue clarifications [Ref. 8]. The October 2008 peer review identified supporting requirements (SRs) not meeting Capability Category I1. Subsequent to the October 2008 peer review, the HC108B PRA model addressed and resolved many of the SRs that did not meet Capability Category II. The SRs that do not meet Capability Category 6

Hope Creek PRA Technical Adequacy Assessment II for the current HC108B PRA model are summarized in Table 2.2-1 along with an assessment of the impact on the base PRA and their current status.

All remaining gaps will be reviewed for consideration for the next periodic PRA model update, but are judged to have low impact on the PRA model or its ability to support a full range of PRA applications. The remaining gaps are documented in the URE database so that they can be tracked and their potential impacts accounted for in applications where appropriate.

Each item will be reviewed as part of each STI change assessment that is performed and an assessment of the impact on the results of the application will be made prior to presenting the results of the risk analysis to the IDP. If a non-trivial impact is expected, then this may include the perfoimance of additional sensitivity studies or model changes

'. to confirm the impact on the risk analysis.

2.2.4 Identification of Key Assumlptions The overall Initiative 5b process is a risk-informed p~ocess with 4th'e PRA model results providing one of the inputs to the IDP to determine if a'rYSTI change is warranted. The methodology recognizes that a key area of uncertainty for this application is the standby failure rate utilized in the determination of the STI extension impact. Therefore, the methodology requires the performance of selected sensitivity studies on the standby failure rate of the component(s) of interest for the STI assessment.

The results of the standby failure rate sensitivity study plus the results of any additional sensitivity studies identified during the performance of the reviews as outlined in 2.2.1 and 2.2.3 above (including a review of identified sources of uncertainty that were developed for Hope Creek based on the EPRI 1009652 guidance [Ref. 9]) for each STI change assessment will be documented and included in the results of the risk analysis that goes to the IDP.

7

Hope Creek PRA Technical Adequacy Assessment DA-D1 Plant specific data was not collected for the most recent The majority of the high importance update reliability data. The only plant specific information systems were updated with recent plant used was for systems that are monitored by the MSPI specifc data. The NEI 04-10 program. MSPI systems include the diesel generators- methodology requires failure rate HPCI, RCIC, RHR, SSWS and SACS. No other specific sensitivities as part of the analysis data was used for this update. Individual component which will address this gap.

random failure data is a vital input to the PSA. Therefore, special attention is paid to ensuring that the best available information is used as input to the PSA.

FINDING - As outlined in the Component Data.Notebook, "individual component random failure data is a vital input to the PSA. Therefore, special attention is paid to ensuring that the best available information is used as input to the PSA." Inadequate data collection and update could have an actual impact on the accuracy of the PRA.

8

Hope Creek PRA Technical Adequacy Assessment QU-E4 Section 3.4 and Appendix B and C of the PRA Summary IE-D3,AS-C3,SC- The NEI 04-10 methodology requires notebook (HC PSA-013) provide an evaluation of the C3,SY-C3,HR-13,DA- uncertainty assessments as applicable important model uncertainties and Section 4.5 and E3,IF-F3,LE-F2/G4 to the specific analysis. The identified Appendix E provide a set of structured sensitivity generic uncertainties and assumptions evaluations based on these uncertainties. Sensitivity will form a base for this assessment.

calculations were run, with seven cases being identified as:

important to model uncertainty. Table 4.5-1 of thePS,A-013 contains a summary of sensitivity cases to identify:risk metric changes associated with candidate modeling uncertainties. The uncertainties are identified based on generic sources of uncertainty provided in EPRI TR-10009652. However, no additional plant-specific sources of uncertainty are addressed. Initial clarification on sources of uncertainty was provided in a July 27, 2007'NRC memorandum, which specified that at a minimum for a base PRA the analyst must "identify the assumptions related to PRA scope and level of detail, and characterize the sources of model uncertainty and related assumptions, i.e., identify what in the PRA model could be impacted and how". In addition, 'While an evaluation of any source of model uncertainty or related assumption is not needed for the base PRA, the various sources of model uncertainty and related assumptions do need to be characterized'so that they can be addressed in the context of an application.

Therefore, the search for candidates needs to be fairly complete (regardless of capability category), because it is not known, a priori, which of the sources of model uncertainty or related assumptions could affect 6n application." So excluding plant-specific sources of.

uncertainty from characterization because they did not "rise to the level that they would be considered candidates for modeling uncertainty" is not appropriate.

FINDING - The information provided is incomplete;-the most recent industry guidance to address modeling uncertainty in order to meet Cat IIfor these SRs isnotmet.

______ I ________________________________ +/- ___________ J 9

Hope Creek PRA Technical Adequacy Assessment System components and boundaries are typically not This is a documentation issue not defined in the system notebooks but referred to the affecting the ability to perform Component Data Notebook. This is acceptable for Surveillance Test Interval analyses in components but the system boundaries should be defined accordance with the NEI 04-10 in the system notebook. methodology.

FINDING - The information provided is incomplete such that the SR is not met.

SY-C2 The documentation present in the system notebooks . SY-A14 This is a documentation issue not largely addresses the suggested topics from this SR. affecting the ability to perform However, there are several recommendations for improving Surveillance Test Interval analyses in Lhe documentation: accordance with the NEI 04-10

1. Section 4.4, Dependency Matrix, should have a legend "nethodology.

detailing what A and B represent, this was seen in the CRD notebook.

2. Section 2.10 has generic spatial dependencies for CRD.

For CS it states "No spatial dependencies other than those imposed by room cooling, internal flooding, and ,LOCA harsh environment." No details are provided. No details are provided on room location for the CRD and CS notebooks.

3. System walkdown checklist should be used to address Lhe topics in SY-C2. There are system walkdown checklists for the flooding but the questions and focus is not the same as required in SY-C2.

4. Ifonly going to list the basic events in the Quantification Notebook there should be a tie in each System notebook going to the respective systems.

FINDING - The information provided is incomplete such that the SR is not fully met; the information provided must be more readily defensible and traceable. .

It is noted that both SRs SY-C2 and SY-A14 meet Capability Category II. However, given that F&O SY-C2-01 is categorized as a Finding, these SRs are retained for further evaluation..

10

Hope Creek PRA Technical Adequacy Assessment 2.3 External Events Considerations External hazards were evaluated in the Hope Creek Individual Plant Examination for External Events (IPEEE) submittal in response to the NRC IPEEE Program (Generic Letter 88-20 Supplement 4) [Ref. 10]. The IPEEE Program was a one-time review of external hazard risk and was limited in its purpose to the identification of potential plant vulnerabilities and the understanding of associated severe accident risks.

The results of the Hope Creek IPEEE study are documented in the Hope Creek IPEEE

[Ref. 11]. Each of the Hope Creek external event evaluations were reviewed as part of the Submittal by the NRC and compared to the requirements of NUREG-1407 [Ref. 12].

The NRC transmitted to PSEG in 1999 their Staff Evaluation Report of the Hope Creek IPEEE Submittal [Ref..13].

Consistent with Generic Letter-88-20, the Hope Creek IPEEE Submittal does not screen out seismic or fire hazards, but provides quantitative analyses. The seismic risk analysis, provided in the Hope Creek Individual Plant Examination for ExternalEvents is

- based on a detailed Seismic Probabilistic Risk Assessment, or Seismic PRA. "

The Hope Creek Seismic PRA study is a detailed analysis that, like the internal fire analysis, uses quantification and model elements (e.g., system fault trees, event tree structures, random failure rates, common cause failures, etc.) consistent with those employed in the internal events portion of the Hope Creek IPE study. Hope Creek currently does not maintain a Seismic PRA.

The internal fire events were addressed by using a combination of the Fire Induced Vulnerability Evaluation (FIVE) methodology [Ref. 14] and industry accepted Fire PRA techniques. The Hope Creek Fire PRA study is a detailed analysis that, like the internal fire analysis, uses quantification and model elements (e.g., system fault trees, event tree structures, random failure rates, common cause failures, etc.) consistent with those employed in the internal events portion of the Hope Creek IPE study. Hope Creek currently does not maintain a Fire PRA.

11

Hope Creek PRA Technical Adequacy Assessment As such, there are no comprehensive CDF and LERF values available from the IPEEE to support the STI risk assessment.

In addition to internal fires and seismic events, the Hope Creek IPEEE analysis of high winds or tornados, external floods, transportation accidents, nearby facility accidents, release of onsite chemicals, detritus and other external hazards was accomplished by reviewing the plant environs against regulatory requirements regarding these hazards.

2.3.1 Discussion of External Events Evaluations Seismic PRA The Hope Creek IPEEE Seismic PRA was developed using a process as described in the IPEEE submittal and summarized below:

Seismic hazard analysis

Seismic fragility assessment

" Seismic systems analysis Quantification of Seismic CDF Some of the highlights of the Hope Creek Seismic PRA methodology include the following:

Seismic fragilities based on revised Lawrence Livermore National Laboratory (LLNL) seismic hazard estimates. The EPRI site specific seismic hazard study are used as input as a sensitivity case.

A seismic event is not assumed to result in a Loss of Offsite Power (LOOP). Seismic failure of offsite power is evaluated on a probabilistic basis according to component fragilities.

The Hope Creek IPEEE states that no plant unique or new vulnerabilities associated with the Seismic Analysis were identified. As identified above, the seismic PRA is not currently maintained for Hope Creek. Thus, quantitative insights can be derived based on the seismic PRA or a qualitative assessment can be performed.

12

Hope Creek PRA Technical Adequacy Assessment Fire PRA The Hope Creek IPEEE Fire PRA was developed using a multi-step process as described in the IPEEE submittal and summarized below:

Step 1 - Fire compartment interaction analysis

Step 2 - FIVE methodology quantitative screening

" Step 3 -- Develop fire PRA analysis in accordance with NUREG/CR-2300 and NUREG/CR-4840 Some of the highlights of the Hope Creek Fire IPEEE methodology include the following:

" Fire initiation frequencies based on the FIVE methodology.

" High hazard rooms (those~that contain a large amount of combustibles) were specifically analyzed' '

The Hope Creek IPEEE states that no fire induced v'ulnerabilities were identified'as a, result of the analysis. The IPEEE also states that the NRC Fire'Risk Scoping Study.

safety Issues were addressed during the fire analysis and it was found that each of the issues has been adequately addressed at Hope Creek. As identified above, the fire PRA is not currently maintained for Hope Creek. Thus, quantitative insights can be derived based on the IPEEE fire PRA or a qualitative assessment can be performed.

Other External Hazards The other external hazards are assessed to be non-significant contributors to plant risk:

" High Winds / Tornadoes: The probability of wind speeds exceeding 360 mph is calculated to be 1E-7. This is the design basis tornado wind speed for Hope Creek Generating Station. No issues were identified.

Transportation and Nearby Facility Hazards: The IPEEE identifies that the frequency of Transportation and Nearby Facility accidents is concluded to be acceptable low. Transportation and nearby 13

Hope Creek PRA Technical Adequacy Assessment hazards were screened from further consideration in the IPEEE.

Additionally, river traffic hazards were evaluated to be acceptably low.

External Floods: The Hope Creek site has a general grade elevation of 101.5' PSE&G datum. The Probable Maximum Hurricane (PMH) elevation at the site is 35.4' mean sea level (MSL). The plant design complies with the Standard review plan criteria and external floods were screened from further consideration in the IPEEE.

River Detritus was evaluated in the IPEEE because of plant issues that were resolved with changes to the plant and operating procedures. Detritus induced loss of all service water pumps has been shown to have a frequency that was less than the IPEEE screening criteria.

The NEI 04-1.0, Revision 1 methodology allows for STI change evaluations to be performed in the absence of quantifiable PRA, models*.for all external hazards. For those cases where the STI cannot be modeled in the plant PRA (or where a particular PRA m6del does not exist for a given hazard group), a qualitative or bounding analysis.

is performed to provide justification for the acceptability of the proposed test interval change.

Therefore, in performing the assessments for the other hazard groups, the qualitative or bounding approach will be utilized in most cases.

2.4 Summary The Hope Creek PRA maintenance and update processes and technical capability evaluations described above provide a robust basis for concluding that the PRA is suitable for use in risk-informed processes such as that proposed for the implementation of a Surveillance Frequency Control Program. As indicated above, in addition to the standard set of sensitivity studies required per the NEI 04-10, Revision 1 methodology, open items for changes at the site and remaining gaps to specific requirements in the PRA standard will be reviewed to determine which, if any, would merit application-specific sensitivity studies in the presentation of the application results.

14

Hope Creek PRA Technical Adequacy Assessment 2.5 References

[1] Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies, Industry Guidance Document, NEI 04-10, Revision 1, April 2007.

[2] Regulatory Guide 1.200, An Approach for Determining the Technical Adequacy of ProbabilisticRisk Assessment Results for Risk Informed Activities, Revision 1, January 2007.

[3] Boiling Water Reactors Owners' Group, BWROG PSA Peer Review Certification Implementation Guidelines (DRAFT) July 1996.

[4] Boiling Water Reactors Owners' Group, BWROG PSA Peer Review Certification Implementation Guidelines, Revision 3, January 1997.

[5] American Society of Mechanical Engineers, Standard for Probabilistic Risk Assessment for Nuclear Power Plant Applications, (ASME RA-S-2002), Addenda RA-Sa-2003, and Addenda RA-Sb-2005, December 2005.

[6] Hope Creek MSPI Basis Document, Rev.'5, March 2009.

[7] Hope Creek Generating Station PRA Peer Review Report Using ASME PRA Standard Requirements, March 2009.

[8] U.S. Ndclear. Regulatory Commission Memo'randum to'Michael T. Lesar from Farouk Eltawila, "Notice of Clarification to Revision 1 of Regulatory Guide 1.200,"

' July 27, 2007.

[9] Guideline for the Treatment of Uncertainty in Risk-Informed Applications, EPRI TR-1 009652, K. Canavan Project Manager, December 2004.

[10] NRC Generic Letter 88-20, Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 10 CFR 50.54(0, Supplement 4, June 28, 1991.

[11] PSEG, Hope Creek Generating Station Individual Plant Examination for External Events, July 1997.

[12] NUREG-1407, Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities, June 1991.

[13] NRC Staff Evaluation Report (SER) of Individual Plant Examination for External Events (IPEEE) Submittal for Hope Creek Generating Station, July 1999.

[14] Professional Loss Control, Inc., Fire-Induced Vulnerability Evaluation (FIVE)

Methodology Plant Screening Guide, EPRI TR-100370, Electric Power Research Institute, April 1992.

15

ATTACHMENT 3 LAR H10-01 LR-N 10-0015 ATTACHMENT 3 TECHNICAL SPECIFICATION PAGES WITH PROPOSED CHANGES:

LICENSE AMENDMENT TO ADOPT TSTF-425, REVISION 3, "RELOCATE SURVEILLANCE FREQUENCIES TO LICENSEE CONTROL" The following Technical Specifications for HCGS (Facility Operating License NPF-57) are affected by this change request:.

3/4 1-2 3/4 3-66 3/4 6-10 3/4 8-9 3/4 1-4 3/4 3-67 3/4 6-13 3/4 8-13 3/4 1-5 3/4 3-74 3/4 6-14 3/4 8-14 3/4 1-7 3/4 3-82 3/4 6-15 3/4 8-20 3/4 1-10 3/4 3-83 3/4 6-16 3/4 8-23 3/4 1-14 3/4 3-87 3/4 6-18 3/4 8-24 3/4 1-19 3/4 3-88 3/4 6-44 3/4 8-25 3/4 1-20 3/4 3-105 3/4 6-45 3/4 8-30 3/4 2-1 3/4 3-ý108 3/4 6-46 3/4 8-38 3/4 2-3 3/4 3-109 3/4 6-47 3/4 8-40 3/4 2 3/4 3-110 3/4 6-49 3/4 8-41

.3/4.3ý-1 3/4 4-2a 3/4 6-51 3/4 8-44 3/4 4-4 3/4 6-51a 3/4 9-2 3/4 3-8 3/4 4-5 3/4 6-52 3/4 9-3 3/4 3-10 3/4 4-8 3/4 6-52a 3/4 9-4 3/4 3-28 3/4 4-9 3/4 6-53 3/4 9-5' 3/4 3-29 3/4 4-10a 3/4 6-,53a 3/419-11 3/4 3-30 3/4 4-12 3/4 6-55 3/4 9-12 3/4 3-31 3/4 4-20 3/4 7-2 3/4 9-14 3/4 3-32 3/4 4-21 3/4 7-4 3/4 9-16 3/4 3-39 3/4 4-22 3/4 7-5 3/4 9-17 3/4 3-40 3/4 4-25 3/4 7-6a 3/4 9-18 3/4 3-41 3/4 4-28 3/4 7-7 3/4 10-1 3/4 3-44 3/4 4-29 3/47-11 3/4 10-3 3/4 3-46 3/4 5-4 3/4 7-12 3/4 10-4 3/4 3-50 3/4 5-5 3/4 7-19 3/4 10-6 3/4 3-51 3/4 5-7 3/4 7-21 3/4 11-2 3/4 3-55 3/4 5-9 3/4 8-4 3/4 11-17 3/4 3-60 3/4 6-1 3/4 8-5 6-16d 3/4 3-61 3/4 6-6 3/4 8-6 3/4 3-62 3/4 6-9 3/4 8-8 1 of 2

ATTACHMENT 3 LAR H10-01 LR-N 10-0015

[INSERT 1 In accordance with the Surveillance Frequency Control Program

[INSERT 3 6.8.4.j Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.

a. The Surveillance Frequency Control Program shall contain a list of Frequencies of those Surveillance Requirements for which the Frequency is controlled by the program.

b. Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1.

c. The provisions of Surveillance Requirements 4.0.2 and 4.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.

2 of 2

REACTIVITY CONTROL SYSTEMS 3/4.1.2 REACTIVITY ANOMALIES LIMITING CONDITION FOR OPERATION 3.1.2 The reactivity equivalence of the difference between the actual ROD DENSITY and the predicted ROD DENSITY shall not exceed 1% delta k/k.

APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2.

ACTION:

With the reactivity equivalence difference exceeding 1% delta k/k:

a. Within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months perform an analysis to determine and explain the cause of the reactivity difference; operation may continue if the difference is explained and corrected.

b. Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.1.2 The reactivity equivalence of the difference between the actual ROD DENSITY and the predicted ROD DENSITY shall be verified to be less than or equal to 1% delta k/k:

a. During the first startup following CORE ALTERATIONS, and

b. onc per 3\effecti'ý fullkower\4aysduring POWER OPERATION.

I ,vse~er*'-

HOPE CREEK 3/4 1-2

REACTIVITY CONTROL SYSTEMS This page reflects pending changes from LAR H09-06.

LIMITING CONDITION FOR OPERATION (Continued)

ACTION (Continued)

2. Within four hours disarm the associated control rod drive:

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

3. The provisions of Specification 3.0.4 are not applicable.

c. With two or more inoperable control rods not in compliance with banked position withdrawal sequence (BPWS) and not separated by two or more OPERABLE control rods*****:

1. Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , restore compliance with BPWS, or

2. Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , restore control rod(s) to OPERABLE status, or

3. Within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , verify control rod drop accident limits are met.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

d. One or more BPWS groups with four or more inoperable control rods*****, within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , restore control rod(s) to OPERABLE status.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

e. With more than 8 control 'rods. inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

f. zWith one scram discharge volume (SDV) vent-or drain lines***

with one valve inoperable, isolate the-assdbiated line within 7 days or

,be in at least HOT:SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .****

g. With one or more SDV vent or drain lines*** with both valves inoperable, isolate the associated line within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .***

SURVEILLANCE REQUIREMENTS 4.1.3.1.1 The scram discharge volume drain and vent valves shall be demonstrated OPERABLE in accordance >wieth t.u

e!*amYc e*u!c:*

by:

a. ..................... per 2. hei.r. Verifying each valve to be open,

and

b. Cycling each valve through at least one complete cycle of full travel.

4.1.3.1.2 When above the low power setpoint of the RWM, all withdrawn control rods not required to have their directional control valves disarmed

These valves may be closed intermittently for testing under administrative controls.

- May be rearmed intermittently, under administrative control, to permit testing associated with restoring the control rod to OPERABLE status.

- - Separate Action entry is allowed for each SDV vent and drain line.

- - - An isolated line may be unisolated under administrative control to allow draining and venting of the SDV.

Not applicable when THERMAL POWER is greater than 8.6% RATED THERMAL POWER.

HOPE CREEK 3/4 1-4 Amendment No.

The change to the frequency from 7 to 31 days REACTIVITY CONTROL SYSTEMS reflects pending changes under LAR H09-03.

Deletion of 4.1.3.4 from Surveillance 4.1.3.1.3 SURVEILLANCE REQUIREMENTS (Continued) reflects pending changes under LAR H09-06.

electrically or hydraulically shall be demonstrated OPERABLE by moving each control rod at least one notch:

a. A", ic&zt I~c1/2o da'lIn accordance with, the Surv,,ealiance Frequency_

C otiLro Progam, and

b. Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months when any control rod is immovable as a result of excessive friction or mechanical interference.

4.1.3.1.3 All control rods shall be demonstrated OPERABLE by performance of Surveillance Requirements 4.1.3.2, 4.1.3.3, 4.1.3.5, 4.1.3.6 and 4.1.3.7.

4.1.3.1.4 The scram discharge volume shall be determined OPERABLE by demonstrating:

a. The scram discharqe volume drain and vent valves OPERABLE at ibteonccp'or-

-tf in accor(3ance-ý ~wtthe Surveillanc CotoPorm by verifying that the drain and vent valves:

1. Close within 30 seconds after receipt of a signal for control rods to scram, and

2. Open when the scram signal is reset.

HOECRE 3/ 1-5AmndentNo

HOPE CREEK 3/4 1-5 Amendment No. ý.ý

REACTIVITIY CUON*OUL SYSYTEMS This page reflects pending CONTROL ROD SCRAM INSERTION TIMES changes to the LCO and Surveillance under LAR H09-06.

LIMITING CONDITION FOR OPERATION 3.1.3.3 No more than 13 OPERABLE control rods shall be "slow," in accordance with Table 3.1.3.3-1, and no more than 2 OPERABLE control rods that are "slow" shall occupy adjacent locations.

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

1. OPERABLE control rods with scram times not within the limits of this Table are considered "slow. "

2. Enter applicable Conditions and Required Actions of LCO 3.1.3.2, "Control Rod Maximum Scram Insertion Times," for control rods with scram times > 7.0 seconds to notch position

05. These control rods are inoperable in accordance with SR 4.1.3.2 and are not considered "slow."

Table 3.1.3.3-1 Position Inserted From Average Scram Insertion Fully Withdrawn Time(a)(b) (Seconds) 45 0.52 39 0.86 25 1.91 05 3.44 (a) Maximum scram time from fully withdrawn position, based on de-energization of scram pilot valve solenoids at time zero.

(b) Scram times as a function of reactor steam dome pressure,. when <- 800 psig are within established limits.

APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2.

ACTION:

With more than 13 OPERABLE control rods exceeding any of the above limits or more than 2 OPERABLE control rods that are "slow" occupy adjacent locations, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.1.3.3 During single control rod scram time surveillances with the control rod drive pumps isolated from the accumulators:

a. Verify each control rod scram time is within the limits of Table 3.1.3.3-1 with reactor steam dome pressure Ž 800 psig prior to THERMAL POWER exceeding 40% RATED THERMAL POWER after each reactor shutdown Ž 120 days.

b. Verify for a representative sample, each tested control rod scram time is within the limits of Table 3 - with reactor steam dome pssure Ž 800 psig 4ý>leas-

~rccpo 20 f;POE PEysIQ in acc-,rd ance wit,,he Surveillance Frequency Conro Pogam.

c. Verify each affected control rod scram time is within the limits of Table 3.1.3.3-1 with any reactor steam dome pressure prior to declaring control rod OPERABLE after work on control rod or CRD System that could affect scram time.

d. Verify each affected control rod scram time is within the limits of Table 3.1.3.3-1 with reactor steam dome pressure 2 800 psig prior to THERMAL POWER exceeding 40%

RATED THERMAL POWER after fuel movement within the affected core cell AND prior to exceeding 40% RTP after work on control rod or CRD System that could affect scram time.

HOPE CREEK 3/4 1-7

REACTIVITY CONTROL SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION (Continued)

3. With one or more control rod scram accumulators inoperable and reactor pressure < 900 psig, a) Immediately upon discovery of charging water header pressure < 940 psig, verify all control rods associated with inoperable accumulators are fully inserted otherwise place the mode switch in the shutdown position**, and b) Within one hour insert the associated control rod(s),

declare the associated control rod(s) inoperable and disarm the associated control valves either electrically or hydraulically by closing the drive water and exhaust water isolation valves.

Otherwise, be "in at least HOT SHUTDOWN within the

,next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. In OPERATIONAL CONDITION 5*: U 1l., :With one or more withdrawn control rods

.inoperable, upon discovery immediately initiate action to fully insert, inoperable withdrawn control rods.

SURVEILLANCE REQUIREMENTS 4.1.3.5 Each control rod scram accu be determined OPERABLE:

a. At eas ont per days )bhat the indicated pressure is greater than or equal to 940 psig unless the control rod is inserted and disarmed or scrammed.

At least the accumulator associated with each withdrawn control rod. Not applicable to control rods removed per Specification 3.9.10.1 or 3.9.10.2.

- Not applicable if all inoperable control rod scram accumulators are associated with fully inserted control rods.

HOPE CREEK 3/4 1-10 Amendment No. 180

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS 4.1.3.7 The control rod position indication system shall be determined OPERABLE by verifying: l&*- -r L-

a. 2tT easS once-e r &h sthat the position of each control rod is indicated,

b. That the indicated control rod position changes during the movement of the control rod drive when performing Surveillance Requirement 4.1.3.1.2, and

c. That the control rod position indicator corresponds to the control rod position indicated by the "Full Out" position indicator when performing Surveillance Requirement 4.1.3.6.b.

HOPE CREEK 3/4 1-14 II -F -

REACTIVITY CONTROL SYSTEMS 3/4.1 5 STANDBY LIQUID CONTROL SYSTEM LIMITING CONDITION FOR:OPERATION 3.1.5 The standby liquid control system consists of two redundant subsystems and shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, and 2 ACTION:

a. In OPERATIONAL CONDITION 1 or 2:

1. With: one system subsystem inoperable, restore the subsystem to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

2. With both system subsystems inoperable, restore at least one subsystem to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS

.l.5 The standby liquid hontrolsstenstrated OPERABLE: 'LV

a. :Atea* o rn p 2 urr by verifying that:

1. The temperat~ure of ,the s6diumpentaborate solution in the storage tank is greater than or equal to 70'F.

2. The available volume of sodium pentaborate solution is within the limits of Figure 3.1.5-1.

3. The heat tracing circuit is OPERABLE by determining the temperature of the pump suction piping to be greater than or equal to 70 0 F.

HOPE CREEK 3/4 1-19 Amendment No. 166

REACTIVITY CONTROL SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

b. (:~Sl tac er . by:.

I. Verifying the continuity of the explosive charge.

2. Determining that the available weight of sodium pentaborate is greater than or equal to 5,776 lbs and the concentration of boron in solution is within the limits of Figure 3.1.5-1 by chemical analysis.*

3. Verifying that each valve (manual, power operated or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct positicn.

c. Demonstrating that, when tested pursuant to Specification 4.0.5, the minimum flow requirement of 41.2 gpm, per pump, at a pressure of greater than or equal to 1255 psi

,I. Initiating one .of the standby liquid control system subsystem, including an explosive valve, and verifying that a flow path from the pumps to the reactor pressure ,vessel is *'available by pumping demineralized water into the reactor vessel and verifying that the relief valve does not actuate. The replacement'charge for the explosive valve shall be from 'the same manufactured batch as the one fir-ad or, from another -batch which has been certified by having oný of that batch successfully fired. Both injection subsystems shall be tse s.

2. **Demonstrating that all heat traced piping between the storage tank and the injection pumps is unblocked and then draining and flushing the piping with demineralized wate:=.

3. Demonstrating that the storage tank heaters are OPERABLE by verifying the expected temperature rise of the sodium pentaborate solution in the storage tank after the heaters are energized.

.his test shall also be performed anytime water or boron is added to the solution or when the solution temperature drops below 70 0 F.

- This test shall also be performed whenever both heat tracing circuits; have been found to be inoperable and may be performed by any series of sequential, overlapping or total flow path steps such that the entire flow path is included.

HOPE CR:EEK 3/4 1-20 Amendment No. 165

3/4.2 POWER DISTRIBUTION LIMITS 3/4.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE LIMITING CONDITION FOR OPERATION 3.2.1 All AVERAGE PLANAR LINEAR HEAT GENERATION RATES (APLHGRs) shall be less than or equal to the limits specified in the CORE OPERATING LIMITS REPORT.

APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 24% of RATED THERMAL POWER.

ACTION:

With an APLHGR exceeding the limits specified in the CORE OPERATING LIMITS REPORT, initiate corrective action within 15 minutes and restore APLHGR to within the required limits within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or reduce THERMAL POWER to less than 24% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

SURVEILLANCE REQUIREMENTS 4.2.1 All APLHGRs shall be verified to be equal to or less than the limits specified in'the'CORE OPERATING LIMITS REPORT:

a. Once Within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after- THERMAL POWER is greater than or equa to 24% of RATED THERMAL POWER2-thereafter. .7-A7_S T

b. Initially andc tN ontpj 2"qo when the reactor is operating with a LIMITING CONTROL ROD PATTERN for APLHGR.

HOPE CREEK 3/4 2-1 Amendment No. 174

POWER DISTRIBUTION LIMITS 3/4.2.3 MINIMUM CRITICAL POWER RATIO LIMITING CONDITION FOR OPERATION 3.2.3 The MINIMUM CRITICAL POWER RATIO (MCPR) shall be equal to or greater than the MCPR limit specified in the CORE OPERATING LIMITS REPORT.

APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 24% of RATED THERMAL POWER.

ACTION:

a. With the end-of-cycle recirculation pump trip system inoperable per Specification 3.3.4.2, operation may continue provided that, within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , MCPR is determined to be greater than or equal to the EOC-RPT inoperable limit specified in the CORE OPERATING LIMITS REPORT.

b. With MCPR less than the applicable MCPR limit specified in the CORE OPERATING LIMITS REPORT, initiate corrective action within 15 minutes and restore MCPR to within the required limit within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or reduce

.THERMAL POWER to less than 24% of RATED THERMAL POWER within the next hours.

SURVEILLANCE REQUIRE MENTS 4.2.3 MCPR, shall be.determined to be equal to or greater than the

applicable MCPR" limit specified in the CORE OPERATING LIMITS REPORT:,

a. Once within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is greate or equal to 24% of RATED THERMAL POWER and at aX o03e _rr ..

24-4oursD thereafter.

b. Initially and(at ea o ep iN.+/-io reactor is operating with a LIMITING CONTROL ROD PATTERN for MCPR.

HOPE CREEK 3/4 2-3 Amendment No. 180

O POWER DISTRIBUTION LIMITS 3/4.2.4 LINEAR HEAT GENERATION RATE LIMITING CONDITION FOR OPERATION 3.2.4 The LINEAR HEAT GENERATION RATE (LHGR) shall not exceed the limit specified in the CORE OPERATING LIMITS REPORT.

APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 24% of RATED THERMAL POWER.

ACTION:

With the LHGR of any fuel rod exceeding the limit specified in the CORE OPERATING LIMITS REPORT, initiate corrective action within 15 minutes and restore the LHGR to within the limit within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or reduce THERMAL POWER to less than 24% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

SURVEILLANCE REQUIREMENTS 4.2.4 LHGR's shall be determined to be equal to or less than the limit specified in the CORE OPERATING LIMITS REPORT:

a. Once within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months afteriŽTHERMAL POWER is greater than or equal to 24% of RATED'THERMAL POWER and t\leafNo *qe r 2 ho (1/S=-e -Z thereafter.

b,. Initially and Cat as n per5fr s ýhen the reactor is operating on a L MITING CONTROL ROD PATTERN for LHGR.

HOPE CREEK 3/4 2-5 Amendment No. 174

3/4.3 INSTRUMENTATION 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.1 As a minimum, the reactor protection system instrumentation channels shown in Table 3.3.1-1 shall be OPERABLE.

APPLICABILITY: As shown in Table 3.3.1-1.

ACTION:

a. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for one trip system, place the inoperable channel(s) and/or that trip system in the tripped condi-tion* within twelve hours.

b. With the number of OPERABLE channels less than required by the Minimum OPERABLE Channels per Trip System requirement for both trip systems, place at least one trip system** in the tripped condition within one hour and take the ACTION required by Table 3.3.1-1.

SURVEILLANCE REQUIREMENTS::

4.3.1.1 Each reactor protection system instrumentation channel shall be demonst'iated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION. operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.1.1-1.

4.3.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic o9Ar_ý ý all channels shall be performed on 4.3.1.3 The REACTOR PROTECTION SYSTEM RESPONSE TIME of each reactor trip functional unit shall be demonstrated to be within its limit at

< Neutron detectors are exempt from response tim e For the Reactor Vessel Steam Dome Pressure - High Functional Unit and the Reactor Vessel Water Level - Low, Level 3 Functional Unit, t _ rs eliminated 4.3.1.4 The provisions of Specification 4.0.4 are not applicable for entry into OPERATIONAL CONDITION 2 or 3 from OPERATIONAL CONDITION 1 for the Inter-mediate Range Monitors.

An inoperable channel need not be placed in the tripped condition where this would cause the Trip Function to occur. In these cases, the inoperable channel shall be restored to OPERABLE status within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or the ACTION required by Table 3.3.1-i for that Trip Function shall be taken.

- If more channels are inoperable in one trip systemthan in the other, place the trip system with more inoperable channels in the tripped condition, except when this would cause the Trip Function to occur.

HOPE CREEK 3/4 3-1 Amendment No. 180

C TABLE 4.3.1.1-1 REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL*-* FUNCTIOUcau CHANNEL CONDITIONS FOR WHICH FUNCTIONAL UNIT CHEAAM)-TE~(Ai )CALIBRATIOýN ( f SURVEILLANCE REQUIRED

1. Intermediate Range Monitors:

a. Neutron Flux - High 2 I 3, 4, 5

b. Inoperative NA NA 2, 3, 4, 5

2. Average Power Range Monitor(f):

a. Neutron Flux - 19b) ' (I) 2 Upscale, Setdown 9 3, 4, 5

b. Flow Biased Simulated Thermal Power-Upscale (e)fi!(h 1 I 9g)

c. Fixed Neutron Flux -

Upscale JN NA 1

1, 2, 3, 4, 5 I

d. Inoperative NA

3. Reactor Vessel Steam Dome Pressure - High 1, 2

4. Reactor Vessel Water Level -

Low, Level 3 9 jjýk) I 1, 2

5. Main Steam Line Isolation Valve - Closure NA

6. This item intentionally blank

7. Drywell Pressure - High (k) 1, 2 HOPE CREEK 3/4 3-7 Amencbnent No. 153

TABLE 4.3.1.1-1 (Continued)

REACTOR PROTECTION SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEI FUNCTIONA CHANNEL CONDITIONS FOR WHICH FUNCTIONAL UNIT *H4 )... TES CALIBRATTO ( SURVEILLANCE REQUIRED

8. Scram Discharge Volume Water Level - High

a. Float Switch NA 1, 2, 16 5 (J)

b. Level Transmitter/Trip Unit 7, 1k) 2, 5 (0)

9. Turbine Stop Valve - Closure NA I

10. Turbine Control Valve Fast Closure Valve Trip System Oil Pressure - Low NA 1K

11. Reactor Mode Switch Shutdown Position NA NA 1, 2, 3, 4, 5

12. Manual Scram NA *K NA 1, 2, 3, 4, 5 (a) Neutron detectors may be excluded from CHANNEL CALIBRATION.

(b) The IRM and SRM channels shall be determined to overlap for at least 1/2 decades during each startup after entering OPERATIONAL CONDITION 2 and the IRM and APRM channels shall be determined to overlap for at least 1/2 decades during each controlled shutdown, if not performed within the previous 7 days-(c) DELETED (d) This calibration shall consist of the adjustment of the APRM channel to conform to the power values calculated by a heat balance during OPERATIONAL CONDITION 1 when THERMAL POWER > 24% of RATED THERMAL POWER. Adjust the APRM channel if the absolute difference is greater than 2% of RATED THERMAL POWER.

(e) This calibration shall consist of the adjustment of the APRM flow biased channel to conform to a calibrated flow signal.

(f) The LPRMs shall be calibrated te e pox_.to (g) Verify measured core flow (total core flow) to be greater than or equal to established core flow at the existing recirculation loop flow (APRM % flow).

(h) This calibration shall consist of verifying the 6 +/- 0.6 second simulated thermal power time constant.

(i) This item intentionally blank (j) With any control rod withdrawn. Not applicable to control rods removed per Specification 3.9-10.1 or (k) Verify the tripset point of the trip unit a e-t"-,n (i) Not required to be performed when entering OPERATIONAL CONDITION 2 from OPERATIONAL CONDITION 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering OPERATIONAL CONDITION 2.-

HOPE CREEK -- / Amendment No. 174

INSTRUMENTATION SURVEILLANCE REQUIREMENTS 4.3.2.1 Each isolation actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.2.1-1.

4.3.2.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic o of all channels shall be performedat le t c pe'8onbs - /ýsJ*T3 4.3.2.3 The ISOLATION SYSTEM RESPONSE TIME of each isolation trip function shall be demonstrated to be within its limit e h~ e-* -mo~hs Radiation detectors are exempt from response time testing. The sensor is eliminated from response time testing for MSIV isolation logic circuits of the following trip functions: Reactor Vessel Water Level - Low Low Low, Level 1; Main Steam Line Pressure - Low; Main Steam Line Flow - High. 'Ea test ha nclude t least ne chan el per tr system uch tha all a h nels re te~ e a least ce everý times 18 months where N s the t tal num r of red dant ch nels in speci isola on trip tem.

HOPE CREEK 3/4 3-10 Amendment No. 101

TABLE 4.3.2.1-1 ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANN&E FUNCTION CHANNEL ,.-ONDITIONS FOR WHICH TRIP FUNCTION §CZEC e TEST ) ýCALIBRATIOWURVEILLANCE REQUIRED

1. PRIMARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level -

1) Low Low, Level 2 1, 2, 3

2) Low Low Low, Level 1 1, 2, 3

b. Drywell Pressure - High 1, 2, 3

c. Reactor Building Exhaust Radiation - High 7, 1, 2, 3

d. Manual Initiation NA (~a) NA 1, 2, 3

2. SECONDARY CONTAINMENT ISOLATION

a. Reactor Vessel Water Level -

Low Low, Level 2 1, 2, 3 and *

b. Drywell Pressure - High 1, 2, 3

c. Refueling Floor Exhaust 7N Radiation - High 1, 2, 3 and *

d. Reactor Building Exhaust Radiation - High 1, 2, 3 and *

e. Manual Initiation NA (a) NA 1, 2, 3 and *

3. MAIN STEAM LINE ISOLATION

a. Reactor Vessel Water Level -

Low Low Low, Level 1 1, 2, 3

b. Main Steam Line Radiation - High, High 1, 2, 3

c. Main Steam Line d.

Pressure - Low Main Steam Line y 1 Flow - High 1, 2, 3 HOPE CREEK 3/4 3-28 Amendment No. 70

TABLE 4.3.2.1-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL-,. FUNCTIO AIl CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION TEST (c CALIBRATIO URVEILLANCE REQUIRED MAIN STEAM LINE ISOLATION (Continued)

e. Condenser Vacuum - Low 911, 2*, 3**

f. Main Steam Line Tunnel Temperature - High NA 1, 2, 3

q. Manual Initiation NA ~ a) 1NA 1, 2, 3

4. REACTOR WATER CLEANUP SYSTEM ISOLATION

a. RWCU A Flow - High 1, 2, 3

b. RWCU A Flow - High, Timer NA 1, 2, 3

c. RWCU Area Temperature - High NA 2, 3

d. RWCU Area Ventilation A Temperature - High NA 1, 2, 3 e.

f.

SLCS Initiation Reactor Vessel Water NA ~b) NA 1, 2 I Level - Low Low, Level 2 1, 2, 3

g. Manual Initiation NA NA 1, 2, 3

5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION

a. RCIC Steam Line A Pressure (Flow) - High NA 1, 2, 3

b. RCIC Steam Line 6 Pressure (Flow) - High, Timer NA 1, 2, 3

c. RCIC Steam Supply Pressure -

Low NA 1, 2, 3

d. RCIC Turbine Exhaust Diaphragm Pressure - High NA 1, 2, 3 HOPE CREEK 3/4 3-29 Amendment No. 166

TABLE 4°3.2°1-1ý (Continued)

W ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS M~

PI -CHANNEL OPERATIONAL CHANNEk---, FUNCT16IO)IV CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION (m&) ES CALIBRATIO( SURVEILLANCE REQUIRED REACTOR CORE ISOLATION COOLING SYSTEM ISOLaTION (Continued)

e. RCIC Pump Room Temperature - High NA 1, 2, 3

f. RCIC Pump Room Ventilation Ducts A Temperature - High NA 1, 2, 3 RCIC Pipe Routing Area z r

g.

Temperature - High NA 1, 2, 3

h. RCIC Torus Compartment Temperature -High NA 1, 2, 3 i.. Drywell Pressure - High 1, 2, 3

j. Manual Initiation NA 1, 2, 3

6. HIGH PRESSURE COOMANT INJECTION SYSTEM ISOLATION 0 HPCI Steam Line A Pressure (Flow) - High NA 1, 2, 3

b. HPCI Steam Line A Pressure (Flow) - High, Timer NA 1, 2, 3

c. HPCI Steam Supply '.9-.**.

Pressure - Low _A 1, 2, 3

d. HPCI Turbine Exhaust Diaphragm Pressure - High NA 1, 2, 3

e. HPCI Pump Room Temperature - High NA 1, 2, 3

f. HPCI Pump Room Ventilation 1, 2, 3 g.

Ducts A Temperature - High HPCI Pipe Routing Area NA 'I*-

Temperature - High NA 1, 2, 3 O

0

- I TABLE 4.3.2.1-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL_ OPERATIONAL CHANNL FUNCTIP CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION CHEC& - T)) CAL IBRATIO SURVEILLANCE REQUIRED HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION (Continued)

h. HPCI Torus Compartment Temperature - High NA 1, 2, 3

i. Drywell Pressure - High NA 1, 2, 3

j. Manual Initiation NA NA 1, 2, 3

7. RHR SYSTEM SHUTDOWN COOLING MODE ISOLATION a a. Reactor Vessel Water Level -

Low, Level 3 1, 2, 3

b. Reactor Vessel (RHR Cut-in Permissive) Pressure - High NA 1, 2, 3

c. Manual Initiation NA (a) NA 1, 2, 3

When handling recently irradiated fuel in the secondary containment and during operations with a potential for draining the reactor vessel.

When any turbine stop valve is greater than 90% open and/or when the kee in the Norm position.

(a) Manual initiation switches shall be tested at eaab<_on p 18 nths uitry associated with manual initiation shall receive a CHANNEL ' NAL TEST(=eat, snas part of circuitry required to be tested for automatic system isolation.

(b) Each train or logic channel shall be tested at least every th2-HOPE CREEK 3/4 3-31 Amendment No. 166

- 1~*-

INSTRUMENTATION 3/4.3.3 EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3 The emergency core cooling system (ECCS) actuation instrumentation channels shown in Table 3.3.3-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.3-2.

APPLICABILITY: As shown in Table 3.3.3-1.

ACTION:

a. With an ECCS actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.3-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value.

b. With one or more ECCS actuation instrumentation channels inoperable, take the ACTION required by Table 3.3.3-1.

SURVEILLANCE REQUIREMENTS 4.3.3 .1 Each ECCS actuation instrumentation channe-P 'shall be?,'de'monstrated OPERABLE by the performance of the CHANNEL CHECK; CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations. for,.the OPERATIONAL CONDITIONS and at the frequencies shown in Table 4.3.3.1,1.

4.3.3.2., LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic o, n ofr*

all channels shall be performed e-s tnc-Le,-pe' o 7-4.3.3.3 The ECCS RESPONSE TIME of each ECCS trip function shall b demonstrated to be within the limitraN..,lea t nce-,ZerI8Poh. ECCS actuation instrumentation is e om response time testin . Eac; tet all i lude at east one ch nel pe trip s-tem su that 1 chaelsr e te ted at east on. every N ti es 18 nths w ere N i-he to number of

(!ed ant c isi ecii C t syste HOPE CREEK 3/4 3-32 Amendment No. 101

EMERGENCY CORE COOLING SYSTEM ACTUATI 4RUHENTATION SUR VEIl I ANf F AFAIIIRFMPJT~

.FuTc CHANNEL SURVFILLANCE UQUIRF N OPERATIONAL CHANNEL" FUNCTIO CHANNEL / CONDITIONS FOR WHICH 0 TRIP FUNCTION CA RTO~)SURVEILLANCE REQUIRED

1. CORE S.PRAY SYSTEM

a. Reactor Vessel Water Level -

Low Low Low, Level 1 1, 2, 3, 4* 5*

rvi b. Drywell Pressure -. High 1, 2, 3

c. Reactor Vessel Pressure - Low 2.,3, 4*, 5*

d. Core Spray Pump Discharge:

Flow - Low (Bypass) 1, 2, 3, 4*, 5*

e. Core Spray Pump Start Time

Delay - Normal Power . NA 1, 2, 3, 4*, 5*

f.. Core Spray Pump Start Time Delay - Emergency Power NA 1, 2, 3, 4*, 5*

g. Manual Initiation NA NA 1, 2, 3, 4*, 5*

2. LOW PRESSURE 'COOLANT INJECTION NODE OF RHR SYSTEM

a. Reactor Vessel Water Level - 1, 2, 3, 4*, 5*

Low Low Low, Level 1

b. Drywell Pressure - High 1, 2, 3 (I c. *Reactor (Permi Vessel ssive) Pressure - Low 1, 2, 3, 4*, 5*

%0

d. LPCI Pump Discharge Flow -

Low (Bypass) 1, 2, 3, 4*, 5*

e. LPCI Pump Start Time Delay -

Normal Power NA 1, 2, 3, 4*, 5*

f. Manual Initiation NA 9- NA 1, 2, 3, 4*, 5*

3. HIGH PRESSURE COOLANT INJECTION SYSTEM#

a. Reactor Vessel Water Level -

Low Low, Level 2 1, 2, 3

b. Drywell Pressure - High 1, 2, 3

c. Condensate Storage Tank Level -

Low 1, 2, 3 CL d. Suppression Pool Water Level -

High 1, 2, 3 C+ e. Reactor Vessel Water Level-High, Level 8 1, 2,+ 3

f. HPCI Pump Discharge FLow - Low (Bypass) 1, 2, 3 F\) g. Manual Initiation /NA NA N 1, 2, 3

TABLE 4.3.3.1-1 (Continued).

REQUIREMENTS C- EMERGENCY CORE COOLING SYSTEM ACTUATION INSTRUMENTATION SURVEILLANCE ni CHANNEL OPERATIONAL CHANNE) FUNCTIO , .-. CHANNEL CONDITIONS FOR WHICH n TRIP FUNCTION* C'C CALIBRAT-IOU, SURVEILLANE_ EQURED SYSTEM#UC

4. AUTOMATIC DEPRESSURIZATION

a. Reactor Vessel Water Level -

b. low Low Low, Level I 1, 2,3

b. Drywell Pressure - High 1, 2,.3

c. ADS Timer i A 1: 2,3

d. Core Spray Pump Discharge Pressure - High r. 1, 2, 3

e. RHR LPCI Mode Pump Discharge Pressure -High 1,2,3

f. Reactor Vessel Water Level - Low,$

Level 3 1 2, 3

g. ADS Dry*ell Pressure Bypass Timer NA 1, 2, 3

h. ADS Manual Inhibit Switch A f NA 1, 2, 3 J. Manual initiation NA NA 1, 2, 3

5. LOSS FPWVER

a. 4.16 kv Emergency Bus Under-voltage (Loss of Voltage) " NA- NA 1, 2, 3, 4"*, 5**

Under-.

(eradedBus Voltage) kv Emergency b.r- 4.16votae. .* ,,* **

5**

When the system Is required to be OPERABLE per Spec-ification 3.5.2.

W

- Required OPERABLE when ESF equipment is required tor*'be OPERABLE.

f Not required to be OPERABLE when reactor steam dome pressure is less than or equal to 200 psig.

ft Not required to.be OPERABLE when reactor steam dome pressure is less than or equal to 100 psig.

I 0="

(-90

3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION ATWS RECIRCULATION PUMP TRIP SYSTEM INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.4.1 The anticipated transient without scram recirculation pump trip (ATWS-RPT) system instrumentation channels shown in Table 3.3.4.1-1 shall be OPERABLE with their trip setpoints set consistent with values shown in the Trip Setpoint column of Table 3.3.4.1-2.

APPLICABILITY: OPERATIONAL CONDITION 1.

ACTION:

a. With an ATWS recirculation pump trip system instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.4.1-2, declare the channel inoperable until the channel is restored to OPERABLE status with the channel trip setpoint adjusted consistent with the Trip Setpoint value.

b. With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels per Trip System requirement for one or both trip systems,"place the inoperable channel(s) in the tripped condition within one ho'ur.

c. With the number of OPERABLE channels two or more less than required by the Minimum OPERABLE' Channels .periTrip System requirement for one trip. system,- and:

1. If the inoperable channels consist of one reactor vessel water level channel and one reactor vessel pressure channel, place both inoperable channels in the tripped condition within one hour, or if this action will initiate a pump trip, declare the trip system inoperable.

2. If the inoperable channels include two reactor vessel water level:

channels or two reactor vessel pressure channels, declare the trip system inoperable.

d. With one trip system inoperable, restore the inoperable trip system to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least STARTUP within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

e. With both trip systems inoperable, restore at least one trip system to OPERABLE status within one hour or be in at least STARTUP within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.3.4.1.1. Each ATWS recirculation pump trip system instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, C L FUNCTIONAL TEST an EL IBRATION operations at the frequenciesl 4.3.4.1.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic of all channels shall be performed r mea.oepdP, k18o-ls ý=9-( XT: 2.

HOPE CREEK 3/4 3-41

TABLE 4.3.4.1-1 ATWS REC.WCULATION PUMP TRIKACTUATION INSTRtENTATION SURVEI"CE REQUIREM TS m

n CHAN CHECK

FUNCTION TEST . HANNE IBRATION ]

T4 FUNCTION l-. eac tor Vessel aer Level- S" --. M* R*

2. Reac rVessel Pressu~e High S * ;i*~l' ' *R*

70

0. 0

INSTRUMENTATION SURVEILLANCE REQUIREMENTS 4.3.4.2.1 Each end-of-cycle recirculation pump trip system instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL FUNCTIONAL TEST and CHANN4'3_ BRATION operations at the frequencies 4.3.4.2.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic i of all channels shall be performeden -/5- _

{-4.3.4,2.3 The END-OF-CYCLE RECIRCULATION PUMP TRIP SYSTEM RESPONSE TIME of each trip function shown in T*ble 3.3.4.2-3 shall be demonstrated to be within its limit t iasf nc 8W8 m Each test shall include at least the logic of one ype of channel input, turbine control valve fast closure or turbine stop valve closure, suchtypes of channel inputs are tested 4.3.4.2.4 The time interval necessary for breaker arc suppression from energization of the recirculation pump ci i ker trip coil shall be measured"te....cpe 60o HOPE CREEK 3/4 3-46

TABLE 4.3.4.2.1-1 1,c7e/ 771,9 IV6 M/A1-W15 .)i1

Z HOPE CREEK 3/4 3-50 Amendment No. 148 0

INSTRUMENTATION 0 3/4.3.5 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.5 The reactor core isolation cooling (RCIC) system actuation instrumentation channels shown in Table 3.3.5-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.5-2.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3 with reactor steam dome pressure greater than 150 psig.

ACTION:

a. With a RCIC system actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.5-2, declare the channel inoperable until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value.

b. With one or more RCIC system actuation instrumentation channels inoperable, take the ACTION required by Table 3.3.5-1.

SURVEILLANCE REQUIREMENTS 4.3.5.1 Each RCIC system actuation instrumentation channel shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations at the frequencies shown in Table 4.3.5.1-1.

4.3.5.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulated automatic operation of all channels shall be performed ~ ~o HOPE CREEK 3/4 3-51

TABLE 4.3.5.1-1 REACTOR CORE ISOLATION COOLING SYSTEM ACTUATION INSTRUMENTATION SqTMVTLLrNCE REMMIRENEMVS CHANNEL CHANNEL FUNCTXO1L. CHANNEL FUNCTIOMAL UNITS TEST( CALIBRATI

a. Reactor Vessel w Water Level Low Low, Level 2

b. Reactor Vessel Water Level - High, Level 8

c. Condensate Storage Tank Level - Low NA

d. Manual Initiation NA (a1 NA (a) Manual initiation switches shall be tested at least once per 18 months. All other circuitry associated with manual initiation shall receive a CHANNEL FUNCTIONAL TEST at least once per 92 days as part of circuitry required to be tested for automatic system actuation.

HOPE CREEK 3/4 3-55 Amendment No. 165

.).

TABLE 4.3.6-1 CONTROL ROD BLOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL OPERATIONAL CHANNEL FUNCTIONAS-T CHANNEL CONDITIONS FOR WHICH TRIP FUNCTION sHZ ES CALIBRATION (a (F) SURVEILLANCE REQUIRED

1. ROD BLOCK MONITOR

a. Upscale

b. Inoperative c- Downscale NA NA NA ~c) 1*

i* I

2. APRM

a. Flow Biased Neutron Flux -

Upscale NA 1

b. Inoperative NA 1, 2, 5

c. Downscale NA 1

d. Neutron Flux - Upscale, Startup NA 2, 5

3. SOURCE RANGE MONITORS

a. Detector not full in NA NA 2, 5

b. Upscale NA 2, 5

c. Inoperative NA 2, 5

d. Downscale MA 2, 5

4. INTERMEDIATE RANGE MONITORS

a. Detector'not full in NA 2, 5

b. Upscale NA 2, 5

c. Inoperative NA 2, 5

d. Downscale NA 2, 5

5. SCRAM DISCHARGE VOLUME

a. Water Level-High (Float Switch) NA 1, 2, 5**

6. REACTOR COOLANT SYSTEM RECIRCULATION FLOW

a. Upscale NA 1

b. Inoperative NA NA 1

c. Comparator NA 1

7. REACTOR MODE SWITCH SHUTDOWN POSITION NA NA 3, 4

/Ie) 3/4 3-60 HOPE CREEK Amendment No. 153

TABLE 4.3.9-1 (Continued)

CONTROL ROD BLOCK INSTRUMENTATION SURVEILLANCE REQUIREMENTS NOTES:

a. Neutron detectors may be excluded from CHANNEL CALIBRATION.

b. DELETED

c. Includes reactor manual control multiplexing system input.

d. DELETED

e. Not required to be performed until I hour after reactor mode switch is in the shutdown position.

With THERMAL POWER k 30% of RATED THERMAL POWER.

With more than one control rod withdrawn. Not applicable to control rods removed per specification 3.9.10.1 or 3.9.10.2.

, . * . .,*, ,*,/-,*/-,,,e

o.[e " '

0.ne-Ye

.Iw ..... ew 4*1 !. .!

HOPE CREEK 3/4 3-61 Amendment No. 153

INSTRUMENTATION 3/4.3.7 MONITORING INSTRUMENTATION RADIATION MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.7.1 The radiation monitoring instrumentation channels shown in Table 3.3.7.1-1 shall be OPERABLE with their alarm/trip setpoints within the specified limits.

APPLICABILITY: As shown in Table 3.3.7.1-1.

ACTION:

a. With a radiation monitoring instrumentation channel alarm/trip setpoint exceeding the value shown in Table 3.3.7.1-1, adjust the setpoint to within the limit within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or declare the channel inoperable.

b. With one or more radiation monitoring channels inoperable, take the ACTION required by Table 3.3.7.1-1. "

'c. The provisionsof Specification 3.0.3'are not app~icable.

SURVEILLANCE REOUIREMENTS 4.3.7.1 Each of, the above required radiation monitoring instrumentation channels shall be demonstrated OPERABLE by the performance of the CHANNEL CHECK, CHANNEL FUNCTIONAL TEST and CHANNEL CALIBRATION operations for the conditions and at the frequencies Qg -*l -.- 3,,7 HOPE CREEK 3/4 3-62 Amendment No. 180

TABLE 4.3.7.1-1 RADIATION -MONITORING INSTRUMENTATION SURVEILLAINCE REQUIREMENTS OPERATION~iAL CCANNL C- IC TO FOgR CHANELTIONAL CHANN WHIC S VEILLAC INRENTA. ON CHECK . TEST CALXIBR[ N 2EQ 0

1. Control Roo Ventilation Radiation No *tor S -Q R 1, 2,3,aind Area Monitors

a. Criticality M itors

1) Mew Fuel Sto ge Vaul~t S R Spent FuelSto gePool SR.i

b. C trol Room.*Direct SQ .... At ali t S a a Monitor

3. Reactor iliaries Coolin S QR At all t' es Radiatio Monitor 4- Safety Au iaries; Cooling s R At all times HOPE CREEK 3/4 3-66 Amendment No. 156 11,RAM TDIV ON THIfS A~46-6 ý4A &&;AI D -T9

r TABME 4.3.7.A7-,4Contiriued)

RADIATION -MONITORING INSTRLUMENATION SbiURILANCE REQUIBEM~ENTS I

-7 16A)

HOPE CREEK 3/4 3-6 Amendment No. 156 I

INSTRUMENTATION REMOTE SHUTDOWN SYSTEM INSTRUMENTATION AND CONTROLS LIMITING CONDITION FOR OPERATION 3.3.7.4 The remote shutdown system instrumentation and controls shown in Table 3.3.7.4-1 and Table 3.3.7.4-2 shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2.

ACTION:

a. With the number of OPERABLE remote shutdown monitoring instrumentation channels less than required by Table 3.3.7.4-1, restore the inoperable channel(s) to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. With the number of OPERABLE remote shutdown system controls less than required in Table 3.3.7.4-2, restore the inoperable control(s) to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.3.7.4.1 Each of the above required remote shutdown monitoring instrumentation channels shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CH ,&6 LIBRATION operations at the frequencie S w rR.

4 .3.74 2 At least on mo e shutdown control switch(es) and control circuits shall be demonstrated OPERABLE by verifying its ato Prform its intended function(s)

HOPE CREEK 3/4 3-74 Amendment No. 180

TABLE 4.3.7.4-1 0 REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS C)'

CHANNE*l SCHANNEL INSTRUMENT :CALIBRATIO ()

1.

2.

Reactor Vessel Pressure Reactor Vessel Water Level 9/

3. Safety/Relief Valve Position (Energization) NA fri

4. Suppression Chamber Water Level

5. Suppression Chamber Water Temperature

6. RHR System Flow

7. Safety Auxiliaries Cooling System Flow

8. Safety Auxiliaries Cooling System Temperature

9. RCIC System Flow

10. RCIC Turbine Speed

11. RCIC Turbine Bearing Oil Pressure Low Indication

12. RCIC High Pressure/Low Pressure Turbine Bearing Temperature High Indication

/

0

TABLE 4.3.7.4-1 (Continued) rn REMOTE SHUTDOWN MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS m

rml CHANNEJ,,\ CHANNEL INSTRUMENT CHEq CALIBRATI (a)

13. Condensate Storage Tank Level Low-Low Indication 9?'

14. Standby Diesel Generator 1AG400 Breaker

ndication NA

15. Standby Diesel Generator 1BG400 Breaker Indication NA

16. Standby Diesel Generator 1CG400 Breaker Indication NA

17. Standby Diesel Generator 1DG400 Breaker Indication Au,,,NA

18. Switchgear Room Cooler 1AVH4O1 Status Indication NA 19 Switchgear Room Cooler 1BVH401 Status Indication NA

20. Switchgear Room Cooler 1CVH401 Status Indication NA

21. Switchgear Room Cooler 1DVH401 Status Indication NA e)we? A

TABLE 4.3.7.5-i ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREDCENTS APPLICABLE CHAN~NEL OPERATIONAL INSTRUMENT CALIB 14A3:I2 CONDITIONS

1. Reactor Vessel Pressure 1,2,3

2. Reactor Vessel Water Level 1,2,3

3. Suppression Chamber Water Level 1,2,3

4. Suppression Chamber Water Temperature 1,2,3 5.

6.

Suppression Chamber Pressure Drywell Pressure f 1,2,3.

1,2,3

7. Drywell Air Temperature 1,2,3

8. Deleted

9. Safety/Relief Valve Position Indicators 1,2,3 Drywell Atmosphere Post-Accident Radiation Monitor 10.

11. North Plant Vent Radiation Monitor#

f 1,2,3 1,2,3

12. South Plant Vent Radiation Monitor# 1,2,3

13. FRVS Vent Radiation Monitor# 1,2,3

14. Primary Containment Isolation Valve Position Indication /9 1,2,3

. (W,.e _2,9.4 e,

- CHANNEL CALIBRATION shall consist of an electronic calibration of the channel, not including the detector, for range decades above 10 R/hr and a one point calibration check of the detector below 10 R/hr with an installed or portable gamma source.

High range noble gas monitors.

HOPE CREEK 3/4 3-87, Amendment No- 160

INSTRUMENTATION SOURCE RANGE MONITORS LIMITING CONDITION FOR OPERATION 3.3.7.6 At least the following source range monitor channels shall be OPERABLE:

a. In OPERATIONAL CONDITION 2*, three.

b. In OPERATIONAL CONDITION 3 and 4, two.

APPLICABILITY: OPERATIONAL CONDITIONS 2*, 3 and 4.

ACTION:

a. In OPERATIONAL CONDITION 2* with one of the above required source range monitor channels inoperable, restore at least 3 source range monitor channels to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. In OPERATIONAL CONDITION 3 or 4 with one or more of the above required source range monitori channels inoperable, verify all -

insertable control rods to be .inserted in the core and lock the reactor mode switch in the Shutdo; position within one hour.

SURVEILLANCE REQUIREMENTS ; -

4.3.7.6. Each Of the above required source range monitor'channels shall be demonstrated OPERABLE by.

a. Performance of a:

1. CHANNEL CHC<ý~

~4<se a) in CONDITION 2*, and ~

b) h ýin*CONDITION 3 or 4.

.2. CHANNEL CLRAIN*iat ea " i '

b. Pelprmance of a CHANNEL FUNCTIONAL TEST C. Verifying, prior to withdrawal of control rods, that the SRM count rate is at least 3 cps with the detector fully inserted.

d. The provisions of Specification 4.0.4 are not applicable for entry into OPERATIONAL CONDITION 2* or 3 from OPERATIONAL CONDITION 1.

With IRM's on range 2 or below.

- Neutron detectors may be excluded from CHANNEL CALIBRATION.

HOPE CREEK 3/4 3-68 Amendment NO. 153

INSTRUMENTATION 3/4.3.9 FEEDWATER/MAIN TURBINE TRIP SYSTEM ACTUATION INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.9 The feedwater/main turbine trip system actuation instrumentation channels shown in Table 3.3.9-1 shall be OPERABLE with their trip setpoints set consistent with the values shown in the Trip Setpoint column of Table 3.3.9-2.

APPLICABILITY: As shown in Table 3.3.9-1.

ACTION:

a. With a feedwater/main turbine trip system actuation instrumentation channel trip setpoint less conservative than the value shown in the Allowable Values column of Table 3.3.9-2, declare the channel inoperable and either place the inoperable channel in the tripped condition until the channel is restored to OPERABLE status with its trip setpoint adjusted consistent with the Trip Setpoint value, or declare the associated system inoperable.

b. With the number of OPERABLE channels one less than required by the Minimum OPERABLE Channels requiremen*t, restore the inoperable channel to OPERABLE status within 7 days or be in at least STARTUP within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

c. With the number of OPERABLE channels two less than required by the Minimum OPERABLE Channels requirement, restore at least one of the inoperable channels to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least STARTUP within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.3.9.1 Each feedwater/main turbine trip system actuation instrumentation channel shall be demonstrated OPERABLE by the performance o e CHANNEL CHECK CEANEL FUNCTIONAL TEST and CHANNEL CALIBRATION oeratio 7r CONDt.

nce t own an&,,a~~r freq 3.. e 4.3.9.2 LOGIC SYSTEM FUNCTIONAL TESTS and simulte dLWL- erdll 1C1 channels shall be performed e t 4/$eer2.\1 HOPE CREEK 13/4 3-105

TAB.LE 41 3,9. 1-1 C) 0 FEIJA /MAIN :T I:NE T:R:I P STEM ACýT IOý NR NTAT ION VEILLAN .- EQUI ENT m

C~)

m m'

EL OPERA AL CALIBRA,,

CHA EL ON CONDITIONS FO-SURVEILLANCE REQU HICHD R

CD3 co- 9-

-IPVV (AlFAM4 49I 77lS pga7 I

INSTRUMENTATION 3/4.3.10 MECHANICAL VACUUM PUMP TRIP INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.10 Two channels of the Main Steam Line Radiation - High, High function for the mechanical vacuum pump trip shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2 with mechanical vacuum pump in service and any main steam line not isolated.

ACTION:

a. With one channel of the Main Steam Line Radiation - High, High function for the mechanical vacuum pump trip inoperable, restore the channel to OPERABLE status within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Otherwise, trip the mechanical vacuum pumps, or isolate the main steam lines or be in HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

b. With mechanical vacuum pump trip capability not maintained:

1. Trip the mechanical vacuum pumps within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ; or

2. Isolate the main steam lines within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ; or

3. Be in HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

c. When a channel is placed in an inoperable status solely for the performance of required Surveillances, entry into the associated ACTIONS may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the mechanical vacuum pump trip capability is maintained.

SURVEILLANCE REQUIREMENTS 4.3.10 Each channel of the Main Steam Line Radiation - High, High function for the mechanical vacuum pump trip shall be demonstrated OPERABLE by:

a. Performance of a CHANNEL CHECK ar

b. Performance of a CHANNEL FUNCTIONAL TEST se-e

c. Performance of a CHANNEL CALIBRATION .. _..................

The Allowable Value shall be

3.6 x normal background; and

d. Performance of a LOGIC SYSTEM FUNCTIONAL TEST, including mechanical vacuum pump trip breaker actuation, HOPE CREEK 3/4 3-109 Amendment No. 180

3/4.3 INSTRUMENTATION 3/4.3.11 OSCILLATION POWER RANGE MONITOR LIMITING CONDITION FOR OPERATION 3.3.11 Four channels of the OPRM instrumentation shall be OPERABLE*. Each OPRM channel period based algorithm amplitude trip setpoint (Sp) shall be less than or equal to the Allowable Value as specified in the CORE OPERATING LIMITS REPORT.

APPLICABILITY: OPERATIONAL CONDITION 1, when THERMAL POWER is greater than or equal to 24% of RATED THERMAL POWER.

ACTIONS

a. With one or more required channels inoperable:

1. Place the inoperable channels in trip within 30 days, or

2. Place associated RPS trip system in trip within 30 days, or

3. Initiate an alternate method to detect and suppress thermal hydraulic instability oscillations within 30 days.

b. With OPRM trip capability not maintained:

1. Initiate alternate method to detect and suppress thermal

[hydraulic instability oscillations within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , and

2. 'Restore OPRM trip capability within 120 days.

c. Otherwilse, reduce THERMAL POWER to less than 24% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

SURVEILLANCE REQUIREMENTS 4.3.11.1 Perform CHANNEL FUNCTIONAL TEsTe I Sa 'tc q-9,r aý 4.3.1-L2 Calibrate the local power range monito eD

f* I u uý ý in accordance with Note t, anle 4.-..1.I 4.3.11.3 Perform CHANNEL CALIBRATIONo -*r \%ts* Neutron detectors are excluded.

4.3.11.4 Perform LOGIC SYSTEM FUNCTIONAL TEST . \ceine 1

4.3.11.5 Verify OPRM is enabled when THERMAL POWER is > 26.1% RTP and recirculation drive flow - value corresponding to 60% of rated core flow 4.3.11.6 Verify the RP-R *PONS0E TIME is within limits ch Net -aN ,3(..__l__..7 nclue tat east on* chanl par rip sstem *uch at aXcnne* a*

Stted* le a t oncýeve ry *times 8 mo ths w re Ns th o*al d*mbe* \0 k dan* chan is in *speic reio p sy em. /'eutron detectors are excl-ude-d.

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

HOPE CREEK 3/4 3-110 Amendment No. 174

This page reflects changes REACTOR COOLANT SYSTEM proposed to 4.4.1.1.3 in LAR H09-02.

SURVEILLANCE REQUIREMENTS 4 .4 .1.1.1 With one reactor coolant system recirculation loop not in operation Cor-o_ verify that:

a. Reactor THERMAL POWER is

60.86% of RATED THERMAL POWER, and

b. The recirculation flow control system is in the Local Manual mode, and

c. The speed of the operating recirculation pump is less than or equal to 90% of rated pump speed.

4.4.1.1.2 With one reactor coolant system recirculation loop not in operation, within no more than 15 minutes prior to either THERMAL POWER increase or recirculation loop flow increase, verify that the following differential temperature requirements are met if THERMAL POWER is

38% of RATED THERMAL POWER or the recirculation loop flow in the operating recirculation loop is

50% of rated loop flow:

a.

145OF between reactor vessel steam space coolant and bottom head drain line coolant, and

b.

50'F between the reactor coolant within the loop not in

,operation and the coolant in the reactor pressure vessel, and

c. < 50OF between the reactor coolant within the loop not in L :operation and the operating loop.

The differential temperature requirements or'Speci'ficatiohs 4.4.1.1.2b and 4.4.1.1.2c do not apply when the loop not in operation is isolated from the reactor pressure vessel.

4.4.1.1.3 Deleted.

HOPE CREEK 3/4 4-2a Amendment No.

REACTOR COOLANT SYSTEM JET PUMPS LIMITING CONDITION FOR OPERATION 3.4.1.2 All jet pumps shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1 and 2.

ACTION:

With one or more jet pumps inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS*

4.4.1.2 All jet pumps shall be demonstrated OPERABLE as follows:

a. Each of the above required jet pumps shall be demonstrated OPERABLE prior to THERMAL POWER exceeding 24% of RATED THERMAL POWER and* s I c.- -- e o tc. by determining recirculation loop flow, total

~o~e %owandi user-to-lower plenum differential pressure for each jet pump and verifying that no two of the following conditions occur when the recirculation pumps are* operating in accordance with Specification 3.4.1.3.

'I. The indicated recirculation loop flow differs by more than 10% from I the established pump speed-loop flow characteristics.

2. The indicated total core flow differs by more than 10% from the established total core flow value derived from recirculation loop flow measurements.

3. The indicated diffuser-to-lower plenum differential pressure of any individual jet pump differs from the established patterns by more than 20%.

b. During single recirculation loop operation, each of the above required jet Rums in the operating loop shall be demonstrated OPERABLE&

0--!st&r by verifying that no two of the following conditions occur:

1. The indicated recirculation loop flow in the operating loop differs by more than 10% from the established* pump speed-loop flow characteristics.

2. The indicated total core flow differs by more than 10% from the established* total core flow value derived from single recirculation loop flow measurements.

3. The indicated diffuser-to-lower plenum differential pressure of any individual jet pump differs from established* single recirculation loop pattern by more than 20%.

c. The provisions of Specification 4.0.4 are not applicable provided that this surveillance is performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after exceeding 24% of RATED THERMAL POWER.

During startup following any refueling outage, baseline data shall be recorded for the parameters listed to provide a basis for establishing the specified relationships. Comparisons of the actual data in accordance with the criteria listed shall commence upon conclusion of the baseline data analysis. Single loop baseline data shall be recorded the first time the unit enters single loop operation during an operating cycle.

HOPE CREEK 3/4 4-4 Amendment No. 174

REACTOR COOLANT SYSTEM RECIRCULATION LOOP FLOW LIMITING CONDITION FOR OPERATION 3.4,1.3 Recirtulation loop flow mismatch shall be maintained within: I a, 5% of rated core flow with effective core flow** greater than or equal to 70% of rated core flow.

b. 10% of rated core flow with effective core flow** less than 70% of rated core flow.

APPLICABILITY: OPERATIONAL CONDITIONS 1* and 2* during two recirculation loop I

operation.

ACTION:

With the recirculation loop flows different by more than the specified limits, either:

a. Restore the recirculation l0oop flows to'within the specified limit within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , or I

ýb. Declare the recirculation l;oop of the pump with the slower flow not,._

in operation and take the ACTION required by Specification 3.4.1. 1.

SURVEILLANCE REQUIREMENTS 4.4,1.3 limits Recirculation I flow mfismatch shall be verified to be within the 7 __ I

See Special Test Exception 3.10.4.

- Effective core flow shall be the care flow that would result if both recir-culation loop flows were assumed to be at the smaller value of the two loop 0 flows.

HOPE CREEK 3/4 4-5 Amendment No. 3

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.2.1 The acoustic monitor for each safety/relief valve shall be demonstrated OPERABLE with the setpoint verified to be _< 30% of full open noise level by performance of a:

a. CHANNEL FUNCTIONAL TEST Se ,e* and a

b. CHANNEL CALIBRATION 4.4.2.2 At least 1/2 of the safety relief valve pilot stage assemblies shall be removed, set pressure tested and reinstalled or replaced with spares that have been previously set pressure tested and stored in accordance with ,4" manufacturer's recommendations a t -and they shall be rotated such that all 14 safety relief valve pilot stage assemblies are removed, set pressure tested and reinstalled or replaced with spares that have been previously set pressure tested and stored in accordance with AK-T2..

manufacturer's recommendations IeTa6s- nrtse 0 s All safety relief valves will be re-certified to meet a +/-1% tolerance prior to returning the valves to service after setpoint testing.

4.4.2.3 The safety relief valve main (mechanical) stage assemblies shall be set pressure tested, reinstalled or replaced with spares that have been previously set pressure teste~d and stored in accordance with manufacturer's recommendations on.

r- _ _

rN HOPE CREEK 3/4 4-8 Amendment No. 116

REACTOR COOLANT SYSTEM SAFETY/RELIEF VALVES LOW-LOW SET FUNCTION LIMITING CONDITION FOR OPERATION 3.4.2.2 The relief valve function and the low-low set function of the following reactor coolant system safety/relief valves shall be OPERABLE with the following settings:

Low-Low Set Function Setpoint* (psig) +/-2%

Valve No. Open Close F013H 1017 905 F013P 1047 935 APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With the relief valve function and/or the low-low set function of one of the above required reactor coolant system safety/relief valves inoperable, restore the inoperable relief valve function and low-low set function to OPERABLE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b. With the relief valve function' and/or the low-low set function of both of the above required reactor 'coolant system safety/relief valves inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD' SHUTDOWN within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS

'4.4.2.2.1 The relief valve function and the low-low set function pressure actuation instrumentation shall be demonstrated OPERABLE by performance of a:

a. CHANNEL FUNCTIONAL TEST a leeert o

b. CHANNEL CALIBRATION, LOGIC SYSTEM FUNCTIONAL TEST and simulated automatic operation of the entire system (excluding actual valve actuation) (

The lift setting pressure shall correspond to ambient conditions of the valves at nominal operating temperatures and pressures. '

HOPE CREEK 3/4 4-9

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.3.1 The reactor coolant system leakage detection systems shall be demonstrated OPERABLE by:

a. Drywell atmosphere gaseous radioactivit monitoring system-performance of a CHANNEL CHECK* *b~e1,-

Or,* r* a CHANNEL FUNCTO L JEST **leis*we* ,,1* rand a HANLCALI BRATION41( k&

b. The drywell pressure shall be ored t* at e r'ir2 ro

c. Drywell floor and equipment drain sump monitorina system-performance of a CHANNEL FUNCTIONAL TEST*,,*eM e.* 'Myand a CHANNEL CALIBRATION TEST a ce er ,

d. Drywell air coolers condensate itorin system-performance of a CHANNEL F TEST e and a CHANNEL CALIBRATION a3/

tk_4-en to HOPE CREEK 3/4 4-10a Amendment No. 51

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS 4.4.3.2.1 The reactor coolant system leakage shall be demonstrated to be within each of the above limits by:'

a. 'Monitorina-th-edryweil atmospheric gaseous radioactivity6K!ý (not a means of quantifying leakage),

b. Monitoring a *,et the dryw 11 floorandand equipment drain sump flow rate ac"*.**.o C. Mont j@the drywell air coolers odntaUwreqý

-anand

-bthM

d. Monitoring the drywel Ileakage),

pressurenot ano a means of quantifying

e. Monitoring the reactor vessel head flange leak detection systemnD

-)(not a means of quantifying leakage),

f. Monitoring the drywell temperature 6 kP .. (Astnot a means of quantifying leakage).

4.4.3.2.2 Each reactor coolant system pressure isolation valve specified in Table 3.4.3.2-1 shall be demonstrated, OPERABLE"'by 'leak testing pursuant to Specification 4.0.5 and verfy-n thek leakage odf, each valve to be wi'.thln the specified limlt.-

.a:.i and V-

"b Prior to returning the valve to service following maintenance, repaieor replacement work on the valve which could'affect its leakage rate.

The provisions of Specification 4.0.4 are not applicable for entry into OPERATIONAL CONDITION 3.

4.4.3.2.3 The high/low pressure interface valve leakage pressure monitors shall be demonstrated 0 E wh alar ,_..

by performance of a WW/A'V ACI8I4 2A1IA,7 rf. A6 ,I~

CINNE\FUNCT "AL T ST at least ncepetp 31 3 ,

b. ':E L1SR~rAi~ at eastod pe 18 mo t$s.

- P.L.V. leak test extension to the first refueling outage is permissible for each RCS P.I.V. listed in Table 3.4.3.2-1, that is identified in Public Ser-vice Electric & Gas Company's letter to the NRC (letter No. NLR-N87047),

dated April 3, 1987, 'as needing a plant outage to test. For this one time test interval, the requirements of Section 4.0.2 are not applicable.

HOPE CREEK 3/4 4-12 Amendment No. 51 I

TABLE 4.4.5-1 PRIMARY COOLANT SPECIFIC ACTIVITY SAMPLE AND ANALYSIS PROGRAM C)

a* OPERATIONAL CONDITIONS TYPE OF MEASUREMkNT SAMPLE AND ANALYsIS IN WHICH SAMPLE AND ANALYSIS FREQUENCY AND ANALYSIS REQUIRED

1. Gross Beta and Gamma Activity Q-n_7n_____ 1;ýhp 1, 2, 3 Determi nation

2. Isotopic Analysis for DOSE 1 EQUIVALENT 1-131 Concentration

3. Radiochemical for E Determination 1

4. Isotopic Analysis for Iodine a) At'least once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , 1#, 2#, 3#, 4#

whenever the specific activity exceeds a limit, 40- as required by ACTION b.

4CD b) At least one sample, between 1, 2 2 and6'hours following the change in'THERMAL POWER or off-gas level, as required by ACTION c. A

5. Isotopic Analysis of an Off- *!.e_*'*r* *

1 gas Sample Including Quantitative Measurements for at least Xe-133,

-Xe-135 and Kr-88

Sample to be taken after a minimum of 2 EFPD and 20 days of POWER OPERATION have elapsed since reactor was last subcritical for 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or longer.

Until the specific activity of the primary coolant system is restored to within its limits.

!£;*,*'*

REACTOR COOLANT SYSTEM 3/4.4.6 PRESSURE/TEMPERATURE LIMITS REACTOR COOLANT SYSTEM LIMITING CONDITION FOR OPERATION 3.4.6.1 The reactor coolant system temperature and pressure shall be limited in accordance with the limit lines shown on Figure 3.4.6.1-1 (hydrostatic or leak testing), and Figure 3.4.6.1-2 (heatup by non-nuclear means, cooldown following a nuclear shutdown and low power PHYSICS TESTS), and Figure 3.4.6.1-3 (operations with a critical core other than low power PHYSICS TESTS), with:

a. A maximum heatup of 100°F in any one hour period,

b. A maximum cooldown of 100OF in any one hour period,

c. A maximum temperature change of less than or equal to 20°F in any one hour period during inservice hydrostatic and leak testing operations above the heatup and cooldown limit curves, and

d. The reactor vessel flange and head flange metal temperature shall be maintained greater than or equal to 79 0 F when reactor vessel head bolting studs are under ten'sion.

APPLICABILITY: At ail times.

.ACTION:

With any of the above limits exceeded, restore the temperature and/or pressure to within the limits within 30 minutes; perform an engineering evaluation to determine the effects of the out-of-limit condition on the structural integrity of the reactor coolant system; determine that the reactor coolant system remains acceptable for continued operations or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.4.6.1.1 During system heatup, cooldown and inservice leak and hydrostatic testing operations, the reactor coolant system temperature and pressure shall be determined to be within the above required heatup and cooldown limits and to the right of the limit lines of Figures 3.4.6.1-1, 3.4.6.1-2,' and 3.4.6.1-3 as applicable, HOPE CREEK 3/4 4-21 Amendment No. 88

REACTOR COOLANT SYSTEM SURVEILLANCE REQUIREMENTS (Continued) 4.4.6.1.2 The reactor coolant system temperature and pressure shall be determined to be to the right of the criticality limit line of Figure 3.4.6.1-3 within 15 minutes prior the withdrawal of control rods. to bring the reactor to criticality and ýeak o jeeXsnyseteduring m heatup.

4.4.6.1.3 The reactor vessel material surveillance specimens shall be removed and examined, to determine changes in reactor pressure vessel material properties, as required by 10 CFR 50, Appendix H. The results of these examinations shall be used to update the curves of Figures 3.4.6.1-1, 3.4.6.1-2, and 3.4.6.1-3.

4.4.6.1.4 The reactor vessel flange and head flange temperature shall be verified to be greater than or equal to the limit specified in 3.4.6.1.d.

a. In OPERATIONAL CONDITION 4 when reactor coolant system temperature is:

1. ~*1100 F, ~t\-le-ý -,_ "a-c-. 0 ~7

2. *90 F, CX\eft Nc&3Ze-ues.

b. Within 30 minutes prior to 'and(nN s h I'si-u uring tensioning of the: reactor vesse'l head bolting studs.

HOPE CREEK ý3/4 4-22 Amendment No. 131 I

REACTOR COOLANT SYSTEM REACTOR STEAM DOME LIMITING CONDITION FOR OPERATION 3.4.6.2 The pressure in the reactor steam dome shall be less than 1020 psig.

APPLICABILITY: OPERATIONAL CONDITION 1* and 2*,

ACTION:

With the reactor steam dome pressure exceeding 1020 psig, reduce the pressure to less than 1020 psig within 15 minutes or be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.4.6.2 The reactorsteam dome shall eressure f ed to be less than 1020 Not applicable during anticipated transients.

HOPE CREEK 3/4 4-25

REACTOR COOLANT SYSTEM 3/4.4.9 RESIDUAL HEAT REMOVAL HOT SHUTDOWN LIMITING CONDITION FOR OPERATION 3.4.9.1 Twoo shutdown cooling mode loops of the residual heat removal (RHR) system shall be OPERABLE and, unless at least one recirculation pump is in operation, at least one shutdown cooling mode loop shall be in operation-04, with each loop consisting of:

a. One OPERABLE RHR pump, and

b. One OPERABLE RHR heat exchanger.

APPLICABILITY: OPERATIONAL CONDITION 3, with reactor vessel pressure less than the RHR cut-in permissive setpoint.

ACTION:

a. With less than the above required RHR shutdown cooling mode loops OPERABLE, immediately.initiate corrective action to return the required loops to OPERABLE!stat-us;.as soon as possible. Within one hour and at least once per 21ýhours thereafter, demonstrate the operability of at least one alternate method capable of decay heat removal for each inoperable RNR shutdown cooling m'ode loop. Be in at least COLD SHUTDOWN within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . *-'

b. With no RHR shutdown cooling mode loop or recirculation pump in operation, immediately initiate corrective action to return at least.onedloop to 6

operation as soon as possible. Within one hour establih. reacCo r coolant circulation by an alternate method and monitor reactor coolant temperature and pressure at least once per hour.

SURVEILLANCE REQUIREMENTS 4.4.9.1 At least one shutdown cooling mode loop of the residual heat removal system, one recirculation pump, or alternate method shall be determined to, in operation and circulating reactor coolant* o "-.!-Oa-_

One RHR shutdown cooling mode loop may be inoperable for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing provided the other loop is OPERABLE and in operation or at least one recirculation pump is in operation.

The shutdown cooling pump may be removed from operation for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period provided the other loop is OPERABLE.

1. The RHR shutdown cooling mode loop may be removed from operation during hydrostatic testing.

- Whenever two or more RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION., maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.

HOPE CREEK 3/4 4-28 Amendment No. 180

REACTOR COOLANT SYSTEM COLD SHUTDOWN LIMITING CONDITION FOR OPERATION 3.4.9.2 Two# shutdown cooling mode loops of the residual heat removal (RHR) system shall be OPERABLE and, unless at least one recirculation pump is in operation, at least one snutdown cooling mode loop shall be in operationA'*#

with each loop consisting of:

a. One OPERABLE RHR pump, and

b. One OPERABLE RHR heat exchanger.

APPLICA6ILITY: OPERATIONAL CONDITION 4 and heat losses to ambient" are -ct sufficient to maintain OPERATIONAL CONDITION 4.

ACTION:

a. With less than the above required RHR shutdown cooling mode loops OPERALE--,

within one hour and at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter, demonstrate the operability.)iof at least one alternate method capable of decay heat removal for'ieach inoperable RHR shutdown cooling mode loop.

b. With ho RHR ihutdown cooling mode loop or-recirculation pump in operatioil within one hour,,establish reactor coolant circulation by an alternate method and monitor reactor coolant temperature and pressure at least once per hour.

SURVEILLANCE REQUIREMENTS 4.4.9.2 At least one shutdown cooling mode loop of the residual heat removal system, recirculation pump or alternate method shall alamined to beJ.D._..n ...

operation and circulating reactor coolant S-tnte1 ,b* . , .

One RHR shutdown cooling mode loop may be inoperable for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing provided the other loop is OPERABLE and in operation or at least one recirculation pump is in operation.

The shutdown cooling pump may be removed from operation for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period provided the other loop is OPERABLE.

1. The shutdown cooling mode loop may be removed from operation during hydrostatic testing.

"*Ambient losses must be such that no increase in reactor vessel water temper-ature will occur (even though COLD SHUTDOWN conditions are being maintained).

HOPE .

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.1 The emergency core cooling systems shall be demonstrated OPERABLE by:

a. 1 ~ e.,

1. For the core spray system, the LPCI system, and the HPCI system:

a) Verifying by venting at the high point vents that the system piping from the pump discharge valve to the system isolation valve is filled with water.

b) Verifying that each valve, manual, power operated or automatic, in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct* position.

c) Verify the RHR System cross tie valves on the discharge side of the pumps are closed and power, if any, is removed from the valve operators.

2. For the HPCI system, verifying that the HPCI pump flow controller is in the correct posiition.

b. Verifying that, when tested pursuant to-S~ecification 4.0.5: -,

1. The two core spray system pumps in each~subsystem together develap-

a flow of at least 6150.gpm against a test line pressure corresponding t6 a reactor vessel pressure of >105 psi above -'

suppress'ion pool',pressure..

2. Each liCcI pump in each subsystem develops a flow ofEat least 10,000 gpm against a test line pressure corresponding to a reactor vessel to primary containment differential pressure of >20 psid.

3, The HPCI pump develops a flow of at least 5600 gpm against a test line pressure corresponding to a reactor vessel pressure of 1000 psig when steam is being supplied to the turbine at 1000, +20, -80 psig.**

1. For the core spray system, the LPCI system, and the HPCI system, performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence and verifying that each automatic valve in the flow path actuates to its correct position. Actual injection of coolant into the reactor vessel may be excluded from this test.

Except that an automatic valve capable of automatic return to its ECCS position when an ECCS signal is present may be in position for another mode of operation.

- The provisions of Specification 4.0.4 are not applicable provided the surveillance is performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure is adequate to perform the test.

HOPE CREEK 3/4 5-4 Amendment No. 136

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

2. For the HPCI system, verifying that:

a) The system develops a flow of at least 5600 gpm against a test line pressure corresponding to a reactor vessel pressure of k200 psig, when steam is being supplied to the turbine at 200 + 15, -0 psig.**

b) The suction is automatically transferred from the condensate storage tank to the suppression chamber on a condensate storage tank water level - low signal and on a suppression chamber - water level high signal.

3. Performing a CHANNEL CALIBRATION of the CSS, and LPCI system discharge line "keep filled" alarm instrumentation.

4. Performing a CHANNEL CALIBRATION of the CSS header AP instrumentation and verifying the setpoint to be s the allowable value of 4.4 psid.

5." Performing a CHANNEL CALIBRATION of the LPCI header AP instrumentation and verifying the setpoint to be s theýý allowable value of 1.0 psid.

d. For the ADS:

1. At. stj&.e.a>a performing a CHANNEL FUNCTIONAL TEST o the Primary Containment Instrument Gas System low-low pressure alarm systeem*ý 2.

a) Performing a system functional test which includes simulated automatic actuation of the system throughout its emergency operating sequence, but excluding actual valve actuation.

b) Verify that when tested pursuant to Specification 4.0.5, that each ADS valve is capable of being opened. I c) Performing a CHANNEL CALIBRATION of the Primary Containment Instrument Gas System low-low pressure alarm system and verifying an alarm setpoint of 85 t2 psig on decreasing pressure.

"*The provisions of Specification 4.0.4 are not applicable provided the surveillance is performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure is adequate to perform the test.

HOPE CREEK 3/4 5-5 Amendment No. 116 I

EERGE14CY CORE COOLING SYSTEMS

.SURVEILLAce REQUIREkENTS 4.5.2.1 At least the above required ECCS shall be demonstrated OPERABLE per Surveillance Requirement 4.5.1.

4.5.2.2 The core spray system shall be determine OPERABLE e (C& "e by verifying the condensate storage tank required vo-Iuiwhen the con -6 ate storage tank is required to be OPERABLE per Specification 3.5.2.a.2.b.

0 HOPE CREEK 3/4 5-7

EMERGENCY CORE COOLING SYSTEMS SURVEILLANCE REQUIREMENTS 4.5.3 .1 The suppression chamber shall be determined OPERABLE by verifying the w'ater level to be greater than or equal to

a. 74.5" tt as n OPERATIONAL CONDITIONS 1, 2, and 3. &-A7-

b. 5.0" in OPERATIONAL CONDITIONS 4 and 5*.

4.5.3 .2 With the suppression chamber level than th above limit or drain ed in OPERATIONAL CONDITION 4 or 5", c

_lest I* hr

a. Verify the required conditions of Specification 3.5.3.b to be satisfied, or

b. Verify footnote conditions

to,,be satisfied.

0 HOPE CREEK 3/4 5-9

3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT PRIMARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.1.1 PRIMARY CONTAINMENT INTEGRITY shall be maintained.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3.

ACTION:

Without PRIMARY CONTAINMENT INTEGRITY, restore PRIMARY CONTAINMENT INTEGRITY within I hour or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.1.1 PRIMARY CONTAINMENT INTEGRITY shall be demonstrated:

a. After each closing of each penetration subject to Type B testing, except the primary containment air locks, if opened following Type A or B test, by leak rate testing in accordance with the Primary Containment Lea sting Program.

b. 1e t Ncer*L by verifying that all primary containment n no capa le of being closed by OPERABLE containment automatic isolation valves and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated automatic valves secured in position, except for valves that are opened under administrative control as permitted by Specification 3.6.3.

c. By verifying each primary containment air lock is in compliance with the requirements of Specification 3.6.1.3.

d. By verifying the suppression chamber is in compliance with the requirements of Specification 3.6.2.1.

See Special Test Exception 3.10.1

- Except valves, blind flanges, and deactivated automatic valves which are located inside the primary containment, and are locked, sealed or otherwise secured in the closed position. These penetrations shall be verified closed during each COLD SHUTDOWN except such verification need not be performed when the primary containment has not been de-inerted since the last verification or more often than once per 92 days.

HOPE CREEK 3/4 6-1 Amendment No. 171

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.1.3 Each primary containment air lock shall be demonstrated OPERABLE:

a. By verifying seal leakage rate in accordance with the Primary Containment Leakage Rate Testing Program.

b. By conducting an overall air lock leakage test in accordance with the Primary Con t Leakage Rate Testing Program.

c. !t; t ce-p ~rmftn by verifying that only one door in each air lock can be opened at a time.**

01

"Except that the inner door need not be opened to verify interlock OPERABILITY when the primary containment is inerted, provided that the inner door interlock is tested within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months after the primary containment has been de-inerted.

0 HOPE CREEK 3/4 6-6 Amendment No. 104

CONTAINMENT SYSTEMS DRYWELL AND SUPPRESSION CHAMBER INTERNAL PRESSURE LIMITING CONDITION FOR OPERATION 3.6.1.6 Drywell and suppression chamber internal pressure shall be maintained between -0.5 and +1.5 psig.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

With the drywell and/or suppression chamber internal pressure outside of the specified limits, restore the internal pressure to within the limit within I hour or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.1.6 The drywell and suppression chamber tna3 pressre shal determined to be within the limits--.e tbnqc')e. h s 7-ý HOPE CREEK 3/4 6-9

CONTAINMENT SYSTEMS DRYWELL AVERAGE AIR TEMPERATURE LIMITING CONDITION FOR OPERATION 3.6.1.7 Drywell average air temperature shall not exceed 135 0 F.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

With the drywell average air temperature greater than 135*F, reduce the average air temperature to within the limit within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.1.7 The drywell average air temperature shall be the volumetric average of the temperatures at the following locations and ll ehdetermined to be within the limit ga e" n-b, 2,fu -3( / cT-*

Elevation Zone Approximate Azimuth*

a. 86'11"-112'8" -900, 2250, 900, 2700 (under vessel)

b. 86'11"-111'10" 1350, 3000, 1000, 1900 (outside of pedestal) 550, 2400, 1550, 3150

c. 111'10"-139'2" 450, 2150, 00, 900,

d. 139'2"-168'0" 1800, 2700

e. 168'0"-192'7" 950, 130*, 3000, 3550, 450, 2250

At least one reading from each elevation zone is required for a volumetric average calculation.

HOPE CREEK 3/4 6-10

CONTAINMENT SYSTEMS w LIMITING CONDITION FOR OPERATION (Continued)

ACTION: (Continued)

3. With the suppression chamber average water temperature greater than 120'F, depressurize the reactor pressure vessel to less than 200 psig within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

c. With one drywell-to-suppression chamber bypass leakage in excess of the limit, restore the bypass leakage to within the limit prior to increasing reactor coolant temperature above 200 0 F.

SURVEILLANCE REQUIREMENTS 4.6.2.1 The suppression chamber shall be demonstrated OPERABLE:

a. By verifying the suppression chamber wa r2 volume to be within the limits a-ooSZ*in OPERATIONAL CONDITION I or 2 by verifying tne suppression chamber average water temperature to be less than or equal to 95 0 F, except:

1. At least once per 5 minutes during testing which adds heat to the suppression chamber, by verifying the suppression chamber average water temperature less than or equal to 105 0 F.

2. At least once per hour when suppression chamber average water temperature is greater than 95 0 F, by verifying:

a) Suppression chamber average water temperature to be less than or equal to 1100F.

c. At least once per 30 minutes in OPERATIONAL CONDITION 3 following a scram with suppression chamber average water temperature greater than 95 0 F, by verifying suppression chamber average water temperature less than or equal to 120 0 F.

d. By an external visual examination of the suppression chamber after safety/relief valve operation with the suppression chamber average water temperature greater than or equal to 177OF and reactor coolant system pressure greater than 100 psig.

Se*. 'arn% by a visual inspection of the accessible interior an exterior o the suppression chamber.

HOPE CREEK 3/4 6-13 Amendment No. 150

CONTAINMENT SYSTEMS LIMITING CONDITION FOR OPERATION (Conti

f. t-. e a-'- b.Ce "mo

- by conducting a dryweil-to-suppression chamber bypass leak test at an initial differential pressure of 0.80 psi and verifying that the differential pressure does not decrease by more than 0.24 inch of water per minute for a period of 10 minutes. If any drywell-to-suppression chamber bypass leak test fails to meet the specified limit, the test schedule for subsequent tests shall be reviewed and approved by the Commission. If two consecutive tests fail to meet the specified limit, a test shall be performed at least every 9 months until two consecutive tests meet the specified limit, at which time the sct dschedule may be resumed.

"'eI alice 0[C.I 3/4 6-14 I

HOPE CREEK Amendment No. 133 0

CONTAINMENT SYSTEMS SUPPRESSION POOL SPRAY LIMITING CONDITION FOR OPERATION 3.6.2.2 The suppression pool spray mode of the residual heat removal (RHR) system shall be OPERABLE with two independent loops, each loop consisting of:

a. One OPERABLE RHR pump, and

b. An OPERABLE flow path capable of recirculating water from the suppression chamber through an RHR heat exchanger and the suppression pool spray sparger.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With one suppression pool spray loop inoperable, restore the inoperable loop to OPERABLE status within 7 days or be in at least.

HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b. With both suppression pool spray loops inoperable, restore at least one loop to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN* within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.2.2 The suppression pool spray mode of the RHR system shall be demonstrated OPERABLE:

ae.t c e* ,aty verifying that each valve, manual, poweor auomaic, in the flow path that is not locked, sealed or otherwise secured in position, is in its correct position.

b. By verifying that each of the required RHR pumps develops a flow I

of at least 540 gpm on recirculation flow through the RHR heat exchanger (after consideration of flow through the closed bypass valve) and suppression pool spray sparger when tested pursuant to Specification 4.0.5..

1~

Whenever both RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.

HOPE CREEK 3/4 6-15 .Amendment No.128 I

CONTAINMENT SYSTEMS SUPPRESSION POOL COOLING LIMITING CONDITION FOR OPERATION 3.6.2.3 The suppression pool cooling mode of the residual heat removal (RHR) system shall be OPERABLE with two independent loops, each loop consisting of:

a. One OPERABLE RHR pump, and

b. An OPERABLE flow path capable of recirculating water from the suppression chamber through an RHR heat exchanger.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With one suppression pool cooling loop inoperable, restore the inoperable loop to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b. With both suppression pool cooling loops inoperable, be in at least HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN* within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.2.3 The suppression pool cooling mode of the RHR system shall be demonstrated OPERABLE: 7

a. _etby verifying that each valve, manual, power?-oeFat-eao-rautomatic, in the flow path that is not locked, sealed or otherwise secured in position, is in its correct position.

b. By verifying that each of the required RHR pumps develops a flow of at least 10,160 gpm on recirculation flow through the RHR heat exchanger (after consideration of flow through the closed bypass valve) and the suppression pool when tested pursuant to Specification 4.0.5.

1

Whenever both RHR subsystems are inoperable, if unable to attain COLD SHUTDOWN as required by this ACTION, maintain reactor coolant temperature as low as practical by use of alternate heat removal methods.

HOPE CREEK 3/4 6-16 Amendment No. 128

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.3.1 Each primary containment isolation valve shall be demonstrated OPERABLE prior to returning the valve Lo service arter mincLtetance, repalz or replacement work is performed on the valve or its associated actuator, control or power circuit by cycling the valve through at least one complete cycle of full travel and verifying the specified isolation time.

4.6.3.2 Each primary containment automatic/6isolation valve shall be demonstrated OPERABLE atet ee ~Z n by verifying that on a containment isolation test isolation valve actuates o its isolation position.

4.6.3.3 The isolation time of each primary containment power operated or automatic valve shall be determined to be within its limit when tested pursuant to Specification 4.0.5. 14 *6 I 4.6.3.4 verify that a representative sample of reactor instrumentation line excess flow check valves actuates to the isolation position on a simulated instrument line break signal.

4.6.3.5 Each traversing in-core probe system explosive isolation valve shall be demonstrated OPERABLE*: -

a.. At p

a. oncharge.

exp- osive - by verifying the continuity of the

b. t .n De o s y removing the explosive squib from at least one explosive valv U;qhha *psi ~sq b.-

naitiating the explosive squib. The replacement c arge for the exploded squib shall be from the same manufactured batch as the one fired or from another batch which has been certified by having at least one of that batch successfully fired. No squib shall remain in use beyond the expiration of its shelf-life or operating life, as applicablc.

Exemption to Appendix J of 10 CFR Part 50.

The reactor vessel head seal leak detection line (penetration J5C) is not required to be tested pursuant to this requirement.

HOPE CREEK 3/4 6-18 Amendment 1o. 171

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS 4.6.4.1 Each suppression chamber - drywell vacuum aký_e: bbr

a. Verified closed le d e jýda .

b. Demonstrated OPERABLE: 7-3t

1. as on pb*JN1aŽ,3*a and within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after discharge oFs-team FE to e suppression chamber from the safety-relief valves, by performing a functional test of each vacuum breaker.

2. t eay verifying the opening setpoint of each vacuum breaker to be less than or equal to 0.20 psid.

Not required to be met for vacuum breaker assembly valves that are open during surveillances-or that are open when performing their intended functions.

H 0

HOPE CREEK 3/4 6-44 Amendment No. 133I

CONTAINMENT SYSTEMS REACTOR BUILDING - SUPPRESSIONCHAMBER VACUUMBREAKERS 0 LIMITING CONDITION FOR OPERATION 3.6.4.2 Each reactor building - suppression chamber vacuum breaker assembly shall be OPERABLE APPLICAnILITYr OPERATIONAL CONDITIONS 1, 2 and 3.

I ACTION:

a. With one reactor building - suppression chamber vacuum breaker assembly, with one or two valves inoperable for opening, restore the vacuum breaker assembly to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b. With two reactor building - suppression chamber vacuum breaker assemblies with one or two valves inoperable for opening, restore both valves in one vacuum breaker assembly to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

c. With one or two reactor building - suppression chamber vacuum breaker assemblies, with one valve not closed, close the open vacuum breaker assembly valve(s) within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

d. With two valves in one or two reactor building- suppression chamber vacuum breaker assemblies not closed, close one open vacuum breaker assembly valve in each affected assembly within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS I

4.6.4.2 Each reactor building - suppression chamber vacuum breaker assembly shall be:

a. verified closd<sýe Ro.

b. Demonstrated OPERABLE:

1. t 1 test erby:

a) Performing a functional test of each vacuum breaker assembly valve.

0 HOPE CREEK 3/4 6-45 Amendment No. 133 I

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) a) Verifying the opening setpoint of each vacuum breaker assembly valve to be less than or equal to 0.25 psid.

Not required to be met for vacuum breaker assembly valves that are open during surveillances or that are open when performing their intended functions.

HOPE CREEK 3/4 6-46 Amendment No. 133

. CONTAINMENT SYSTEMS 3/4.6.5 SECONDARY CONTAINMENT SECONDARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.6.5.1 SECONDARY CONTAINMENT INTEGRITY shall be maintained.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and

ACTION:

Without SECONDARY CONTAINMENT INTEGRITY:

a. In OPERATIONAL CONDITION 1, 2 or 3, restore SECONDARY CONTAINMENT INTEGRITY within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b. In Operational Condition *, suspend handling of recently irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.6.5.1 SECONDARY CONTAINMENT INTEGRITY shall be demonstrated by:

a. Verifying e~a n t ozth actor building is at a negative ressure.

Ob. Verifying -ftecg

e-- r 4*t h at * *

1. All secondary containment eq i ches and blowout panels are closed and sealed.

2. a. For double door arrangements, at least one door in each access to the secondary containment is closed.

b. For single door arrangements, the door in each access to the secondary containment is closed except for routine entry and exit.

3. All secondary containment penetrations not capable of being closed by OPERABLE secondary containment automatic isolation dampers/valves and required to be closed during accident conditions are closed by valves, blind flanges, or deactivated automatic dampers/valves secured in position.

1. Verifying that four filtration recirculation and ventilation system (FRVS) recirculation units and one ventilation unit of the filtration recirculation and ventilation system will draw down the secondary containment to greater than or equal to 0.25 inches of vacuum water gauge in less than or equal to 375 seconds, and

When recently irradiated fuel is being handled in the secondary containment and during operations with a potential for draining the reactor vessel.

HOPE CREEK 3/4 6-47 Amendment No. 146

CONTAINMENT SYSTEMS SECONDARY CONTAINMENT AUTOMATIC ISOLATION DAMPERS LIMITING CONDITION FOR OPERATION 3.6.5.2 The secondary containment ventilation system (RBVS) automatic isolation dampers shown in Table 3.6.5.2-1 shall be OPERABLE with isolatic.n times less than or equal to the times shown in Table 3.6.5.2-1.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *.

ACTION:

With one or more of the secondary containment ventilation system automatic isolation dampers shown in Table 3.6.5.2-1 inoperable, maintain at least cne isolation damper OPERABLE in each affected penetration that is open and within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months either:

a. Restore the inoperable dampers to OPERABLE status, or

b. Isolate each affected penetration by use of at least one deactivated damper secured in the isolation position, or

c. Isolate each affected penetration by use of at least one closed manual valve or blind flange.

Otherwise, in OPERATIONAL CONDITION 1, 2 or 3, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Otherwise, in Operational Condition *, suspend handling of recently irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

SURVE:LLANCE REQUIREMENTS 4.6.5.2 Each secondary containment ventilation system automatic isolation damper shown in Table 3.6.5.2-1 shall be demonstrated OPERABLE:

a. Prior to returning the damper to service after maintenance, repair or replacement work is performed on the damper or its associated actuator, control or power circuit by cycling the damper through at least one complete cycle of full travel and verifying the specified isolation t ime.#V S &R 7

b. o e *j beay verifying that on a containment by isolation test signal each isolation damper actuates to its isolation position.

c. B eivn the isolation time to be within its limitdg

When. recently irradiated fuel is being handled in the secondary containment andduring operations with a potential for draining the reactor vessel.

HOPE CREEK 3/4 6-49 Amendment No. 165

0 CONTAINMENT SYSTEMS 3.6.5.3 FILTRATION, RECIRCULATION AND VENTILATION SYSTEM (FRVS)

FRVS VENTILATION SUBSYSTEM LIMITING CONDITION FOR OPERATION 3.6.5.3.1 Two FRVS ventilation units shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and *.

ACTION:

a. With one of the above required FRVS ventilation units inoperable, restore the inoperable unit to OPERABLE status within 7 days, or:

1. In OPERATIONAL CONDITION 1, 2 or 3, be in at least HOT.

SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

2. In Operational Condition *, place the OPERABLE FRVS ventilation unit in operation or suspend handling of recently irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

b. With both ventilation units inoperable in Operational Condition

suspend handling of recently irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3. are.not I applicable.

SURVEILLANCE REQUIREMENTS 4.6.5.3.1 Each of the two ventilation units shall be demonstrated OPERABLE:

av a-

a.

e t ce er 4e aysby verifying that the water seal bucket traps have a'water sea and making up any evaporative losses by filling the traps to the overflow.

-b. p*e, y initiating, from the control room, flow through the i ters and charcoal adsorbers and verifying that the subsystem operates for at least 15 minutes.

When recently irradiated fuel is being handled in the secondary containment and during operations with a potential for draining the reactor vessel.

HOPE CREEK 3/4 6-51 Amendment No. 170

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) 0 C. e t nNe e'nJi o r upon determination** that the HEPA filters or charcoal adsor ent could have been damaged by structural maintenance or adversely affected by any chemicals, fumes or foreign materials (1) after any structural maintenance on the HEPA filter or charcoal adsorber housings, or (2) following painting, fire or chemical release in any ventilation zone communicating with the subsystem by:

1. Verifying that the subsystem satisfies the in-place penetration testing acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Positions C.5.a, C.5.c and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rates are 9,000 cfm +/- 10% for each FRVS ventilation unit.

2. Verifying within 31 days after removal from the FRVS ventilation units, that a laboratory test of a sample of the charcoal adsorber, when obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, shows the methyl iodide penetration less than 5% when tested in accordance with ASTM D3803-1989 at a temperature of 30 0 C and a relative humidity 95%.

3. Verifying a subsystem flow rate of 9,000 cfm +/- 10% for each FRVS ventilation unit during system operation when tested in accordance with ANSI N510-1980.

d. After every 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of charcoal adsorber operation by verifying within 31 days after removal from the FRVS ventilation units, that a laboratory analysis of a representative carbon sample, when obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, shows a methyl iodide penetration less than 5% when tested in accordance with ASTM D3803-1989 at a temperature of 30'C and a relative humidity of 95%.

- This determination shall consider the maintenance performed and/or the type, quantity, length of contact time, known effects and previous accumulation history for all contaminants which could reduce the system performance to less than that verified by the acceptance criteria in items c.l through c.3 below.

HOPE CREEK 3/4 6-51a Amendment No. 146

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

e. Ze c ecant~by:

1. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 5 inches Water Gauge in the ventilation unit while operating the filter train at a flow rate of 9,000 cfm +/- 10% for each FRVS ventilation unit.

2. Verifying that the filter train starts and isolation dampers open on each of the following test signals:

a. Manual initiation from the control room, and

b. Simulated automatic initiation signal.

f. After each complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter bank satisfies the inplace penetration testing acceptance criteria of less than 0.05% in accordance with Regulatory Position C.5.a and C.5.c of Regulatory Guide 1.52, Revision 2 March 1978, while operating the system at a flow rate of 9,000 cfm +/- 10%

for each FRVS ventilation unit.

g. After each complete or partial replacement of a charcoal adsorber bank by verifying that the charcoal adsorber bank satisfies the inplace penetration testing acceptance criteria of less than 0.05% in accordance with Regulatory Position C.5.a and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, for a halogenated hydrocarbon refrigerant test gas while operating the system at a flow rate of 9,000 cfm +/- 10% for each FRVS ventilation unit.

S HOPE CREEK 3/4 6-52 Amendment No. 146 I

CONTAINMENT SYSTEMS W 3.6.5.3 'FILTRATION, RECIRCULATION AND VENTILATION SYSTEM (FRVS)

FRVS.RECIRCULATION SUBSYSTEM LIMITING CONDITION FOR OPERATION 3.6.5.3.2 Six FRVS recirculation units shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3 and

ACTION:

a. With one or two of the above required FRVS recirculation units inoperable, restore all the inoperable unit(s) to OPERABLE status within 7 days, or:

1. In OPERATIONAL CONDITION 1, 2, or 3, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the'following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

2. In Operational Condition *, suspend handling of recently irradiated fuel in the secondary containment and operations with a potential for draining the Teactor vessel. The provisions of Specification 3.0.3 are not applicable.

b. With three or more of the above required FRVS recirculation units inoperable in Operational Condition.-, suspend handling of.recently irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel. The provisions of Specification 3.0.3 are not applicable.

c. With three or more of the above required FRVS recirculation units inoperable in OPERATIONAL CONDITION 1, 2, or .3, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.5.3.2 Each of the six FRVS recirculation units shall be demonstrated OPERABLE:'

a. verifying that the water seal bucket traps have a water seal and making up any evaporative losses by filling the traps to the overflow. w.

b. byi'&Dby

)e0a initiating, from the control room, flow through the HEPA fTiters and verifying that the subsystem operates for at least 15 minutes.

When recently irradiated fuel is being handled in the secondary containment and during operations with a potential.for draining the reactor vessel.

ROPE- CREEK 3/4 6-52a 3Amendment No. 170

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

c. ( ea -ac-&-Qe" mo§Z7s or upon determination** that the HEPA filtehrs coud have een amaged by structural maintenance or adversely affected by any foreign materials (1) after any structural maintenance on the HEPA filters or housings by:

1. Verifying that the subsystem satisfies the in-place penetration testing acceptance criteria of less than 0.05% and uses the test procedure'guidance in Regulatory Positions C.5.a and C.5.c of Regulatory Guide 1.52, Revision 2, March 1978, and the system flow rates are 30,000 cfm +/- 10% for each FRVS recirculation unit.

2. Verifying a subsystem flow rate of 30,000 cfm +/- 10% for each FRVS recirculation unit during system operation when tested in accordance with ANSI N510-1980.

d. not used

- This determination shall consider the maintenance performed and/or the type, quantity, length of contact time, known effects and previous accumulation history for all contaminants which could reduce the system performance to less than that verified by the acceptance criteria in items c.l and c.2 below.

0 HOPE CREEK 3/4 6-53 Amendment No. 146

CONTAINMENT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

e. t e b y

1. Verifying that the pressure drop across the exhaust duct is less I

than 8 inches Water Gauge in the recirculation filter train while operating the filter train at a flow rate of 30,000 cfm +/- 10% for each FRVS recirculation unit.

2. Verifying that the filter train starts and isolation dampers open on each of the following test signals:

a. Manual initiation from the control room, and

b. Simulated automatic initiation signal.

f. After each complete or partial replacement of a HEPA filter bank by verifying that the HEPA filter bank satisfies the inplace penetration testing acceptance criteria of less than 0.05% in accordance with Regulatory Position C.5.a and C.5.c of Regulatory Guide 1.52, Revision 2 March 1978, while operating the system at a flow rate of 30,000 cfm +/-

10% for each FRVS recirculation unit.

HOPE CREEK 3/4 6-53a Amendment No. 146 0

I

CONTAINMENT SYSTEMS DRYWELL AND SUPPRESSION CHAMBER OXYGEN CONCENTRATION LIMITING CONDITION FOR OPERATION 3.6.6.2 The drywell and suppression chamber atmosphere oxygen concentration shall be less than 4% by volume.

APPLICABILITY: OPERATIONAL CONDITION i*, during the time period:

a. Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is greater than 15% of RATED THERMAL POWER, following startup, to Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to reducing THERMAL POWER to less than 15% of RATED THERMAL POWER preliminary to a scheduled reactor shutdown.

ACTION:

With the drywell and/or suppression chamber oxygen concentration exceeding the limit, restore the oxygen concentration to within the limit within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or be in at least STARTUP within the next 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.6.2 The drywell and suppression chamber oxygen concentration shall be verified to be within the limit within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after THERMAL POWER is greater than 15% of RATED THERMAL POWER and ter.

See Special Test Exception 3.10.5.

HOPE CREEK 3/4 6-55

PLANT SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTIO:N: (Continued)

C. In OPERATIONAL CONDITION 4 or 5 with the SACS subsystem, which is associated with safety related equipment required OPERABLE by Specification 3.5.2, having two SACS pumps or one heat exchanger inoperable, declare the associated safety related equipment inoperable and take the ACTION required by Specification 3.5.2.

d. In OPERATIONAL CONDITION 5 with the SACS subsystem, which is associated with an RHR loop required OPERABLE by Specification 3.9.11.1 or 3.9.11.2, having two SACS pumps or one heat exchanger inoperable, declare the associated RHR system inoperable and take the ACTION required by Specification 3.9.11.1 or 3.9.11.2, as applicable.

0. In OPERATIONAL CONDITION 4, 5, or **, with one SACS subsystem, which is associated with safety related equipment required OPERABLE by Specification 3.8.1.2, inoperable, realign the associated diesel generators within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to the OPERABLE SAZS subsystem, or declare the associated diesel generators inoperable and take the ACTION required by Specification 3.8.1.2. The provisions of Specification 3.0.3 are not applicable.

f. In OPERATIONAL CONDITION 4, 5, or **, with only one SACS pump -and heat exchanger and its associated flowpath OPERABLE, restore at least two pumps and two heat exchangers and associated flowpaths to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or, declare the associated safety related equipment inoperable and take the associated ACTION requirements.

SURVEILLANCE REQUIREMENTS 4.7.1.1 At least the above required safety auxiliaries cooling system subsystems shall be demonstrated OPERABLE:

h by verifying that each valve in the flow path that is not IoCKe, sealed or otherwise secured in position..

is in its correct position.

b. a 1so%,on ie t aJby verifying that: 1) Each automatic valve servicing safety-related equipment actuates to its correct position on the appropriate test signal(s), and 2) Each pump star:ts automatically when its associated diesel generator automatically starts.

HOPE CREEK 3/4 7-2 Amendment No. 165

PLANT SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

ACTION: (Continued)

b. In OPERATIONAL CONDITION 4 or 5:

With only one station service water pump and its associated flowpath OPERABLE, restore at least two pumps with at least one flow path to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or declare the associated SACS subsystem inoperable and take the ACTION requited by Specification 3.7.1.1.

c. In OPERATIONAL CONDITION *;

With only one station service water pump and its associated flowpath OPERABLE, restore at least two pumps with at least one flow path to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or declare the associated SACS subsystem inoperable and take the ACTION required by Specification 3.7.1.1. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.7.1.2 At least the above required station service water system loops shall-be demonstrated OPERABLE:

a. a pda b y verifying that each valve (manual, power operate or au omatic),servicing safety related equipment that is not locked, sealed or otherwise secured in position, is in its correct position.

b. ý1 !c ýýer by verifying that:

1. Each automatic valve servicing non-safety related equipment actuates to its isolation position on an isolation test signal.

2. Each pump starts automatically when its associated diesel generator automatically starts.

When handling recently irradiated fuel in the secondary containment. I _

HOPE CREEK 3/4 7-4 Amendment No. 170

PLANT, SYSTEMS ULTIMATE HEAT SINK LIMITING CONDITION FOR OPEURATION 3.7.1.3 The ultimate heat sink (Delaware River) shall be OPERABLE with:

a. A minimum river water level at or above elevation -9'0 Mean Sea Level, USGS datum (80'0 PSE&G datum), and 0

b. An average river water temperature of less than or equal to 85.0 F.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, 3, 4, 5 and *.

ACTION:

With the river water temperature in excess of 85.0 0 F, continued plant operation is permitted provided that both emergency discharge valves are open and emergency discharge pathways are available. With the river water temperature in excess of 88.0F, continued plant operation is permitted provided that all of the following additional conditions are satisfied: all SSWS pumps are OPERABLE, all SACS pumps are OPERABLE, all EDGs are OPERABLE and the SACS -loops have no cross-connected loads (unless they are automatically isolated during a LOP" and/or LOCA); with ultimate heat sink temperature greater than B90 F and less than or equal to 91.4'F, verify once per hour that water temperature of the ultimate heat sink -is less -than or equal to 89'F averaged over the previouij 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period; otherwise, with the requirements of 'the above specificatior not satisfied; a..-. In OPERATI'ONAL CONDITIONS 1, 2 or 3, be in at least HOT SHUTDOWN within -12 hours and in COLD SHUTDOWN w'ithin the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

- b. In OPERATIONAL CONDITIONS 4 or 5,, decla2e -the -SACS -system and the station service water system inoperab~l&:and take;the ACTION required by Specification 3.7.1.1 and

c. In Operational Condition *, declare the plant service water system inoperable and take the ACTION required by Specification 3.7.1.2. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.7.1.3 The ultimate heat sink shall be determined OPERABLE:

a. By rifi theriver water level to be reater than or equal to the minimum limit ee.,n.-'

b. By verifying river water temperatu tjýithin its limit:

1) a eastdoxe-r 24 _ when the river water temperature is less than or equal to 82 .

2) at a on h rs when the river water temperature is greater than 82'F.

When handling recently irradiated fuel in the secondary containment.

HOPE CREEK 3/4 7-5 Amendment No. 168

PLANT SYSTEMS 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM LIMITING CONDITION FOR OPEPR.TION (continued)

2. With both control room emergency filtration subsystems inoperable for reasons other than Condition b.3, suspend handling of recently irradiated fuel in the secondary containment and operations with a potentia2 for draining the reactor vessel.

3. With one or more control room emergency filtration subsystems inoperable due to an inoperable CRE boundary , immediately suspend handling of recently irradiated fuel and operations with a potential for draining the vessel.

c. The provisions of Specification 3.0,3 are not applicable in Operational Condition *.

SUPRVEILLANCE REQUIREMENTS 4.7.2.1 Each control room emergency filtration subsystem shall be demonstrated OPEPABLE: '_'

a. a sy veri-fying that the cont olrom air temperature is less than or equal to 85OF #." (/1'RT_2 b.tea aN.kXA;R T' A y initiating, from the control room, the control area c i e water pump, flow through, the HEPA filters and charcoal adsorbers and verifying that the subsystem operates for at least 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months with the heaters on in order to reduce the buildup of moisture on the carbon adsorbers and HEPA filters.

When recently irradiated fuel is being handled in the secondary containment and during operations with a potential for draining the reactor vessel.

11 This does not require starting the non-running control emergency filtration subsystem.

INThe main control room envelope (CRE) boundary may be opened intermittently under administrative control.

HOPE CREEK 347-Ga Amendment No. 173

PLANT SYSTEM[

SURVEILLANCE REQUIREMENTS (Continued)

e

t. s e eý PnZs-r (I) after any structural maintenance on te iEP.A ýiter or charcoal adsorber housings, or (2) following painting, fire or chemical release in any ventilation zone communicating with the subsystem filter train by:

I. Verifying that the subsystem satisfies the in-place penetration testing acceptance criteria of less than 0.05% and uses the test procedure guidance in Regulatory Positions C.5.a, C.5.c and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and the system filter train flow rate is 4000 cfm + 10%.

2. Verifying within 31 days after removal, that a laboratory test of a sample of the charcoal adsorber, when obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, shows the methyl iodide penetration less than 0.5% when tested in accordance with ASTM D3803-1989 at.

a temperature of 30'C and a relative humidity 70%.

3. Verifying a subsystem filter train flow rate of 4000 cfm +

10% during subsystem operation when tested in accordance with ANSI N510-1980.

d. After every 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of charcoal adsorber operation by verifying within 31 days after removal from the Control Room Emergency Piltration units that a laboratory analysis of a representative carbon sample, when obtained in accordance with Regulatory Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, shows a methyl iodide penetration less than 0.5% when tested in accordance with ATSM D3803 -

1989 at a temperature of 30 0 C and a relative humidity of 70%.

e. le t e p i

1. Verifying that the pressure drop across the combined HEPA filters and charcoal adsorber banks is less than 7.5 inches Water Gauge while operating the filter train subsystem at a flow rate of 4000 cfm + 10%.

2. Verifying with the control room hand switch in the recirculation mode that on each of the below recirculation mode actuation test signals, the subsystem automatically switches to the isolation mode of operation and the isolation dampers close within 5 seconds:

HOPE CREEK 3/4 7-7 hmendment No. 173

PLANT SYSTEMS 3/4.7.3 FLOOD PROTECTION LIMITING CONDITION FOR OPERATION 3.7.3 Flood protection shall be provided for all safety related systems, components and structures when the water level of the Delaware River reaches 6.0 feet Mean Sea Level (MSL) USGS datum (95.0 feet PSE&G datum) at the Service Water Intake Structure.

APPLICABILITY: At all times.

ACTION:

a. With severe storm warnings from the National Weather Service which may impact Artificial Island in effect or with the water level at the service water intake structure above elevation 6.0 feet MSL USGS datum (95.0 feet PSE&G datum), initiate and complete:

1. The closing of all service water intake structure watertight perimeter flood doors identified in Table 3.7.3-1 within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , or declare affected service water system components inoperable and take the actions required by LCO 3.7.1.2;

- and -

2. The closing of all power block watertight perimeter flood doors identified in Table 3.7.3-1 within 1.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months .

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Once closed, all access through the doors shall be administratively controlled.

b. With the water level at the service water intake structure above elevation 10,5 feet MSL USGS datum (99.5 feet PSE&G datum), be in at least HOT.SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.7.3 The water level at the service water intake structure shall be determined to be within the limit by:

a. Measurement ttýeonýNper*%,t -)when the water level is below elevation 6.0 SL USGS datum (95.0 feet PSE&G datum), and

b. Measurement at least once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months when severe storm warnings from the National Weather Service which may impact Artificial island are in effect. 7

c. Measurement e when the water level is equal to or above elevation 6.0 MSL USGS datum (95.0 feet PSE&G datum).

HOPE CREEK 3/4 7-9 Amendment No. 122

PLANT SYSTEMS 3/4.7.4 REACTOR CORE ISOLATION COOLING SYSTEM LIMITING CONDITION FOR OPERATION 3.7.4 The reactor core isolation -cooling (RCIC) system shall be OPERABLE with an OPERABLE flow path capable of automatically taking suction from the suppression pool and transferring the water to the reactor pressure vessel.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2, and 3 with reactor steam dome pressure greater than 150 psig.

ACTION:

Note: LCO 3.0.4.b is not applicable to RCIC.

With the RCIC system inoperable, operation may continue provided the HPCI system is OPERABLE; restore the RCIC system to OPERABLE status within 14 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and reduce reactor steam dome pressure to less than or equal to 150 psig within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.7.4 The RCIC system shall be demonstr

a. as_ c 3 by:

1. Verifying by venting at the high point vents that the system piping from the pump discharge valve to the system isolation valve is filled with water.

2. Verifying that each valve, manual, power operated or automatic in the flow path that is not locked, sealed or otherwise secured in position, is in its correct position.

3. Verifying that the pump flow controller is in the correct position.

b. When tested pursuant to Specification 4.0.5 by verifying that the RCIC pump develops a flow of greater than or equal to 600 gpm in the test flow path with a system head corresponding to reactor vessel operating pressure when steam is being supplied to the turbine at 1000 + 20, - 80 psig.*

The provisions of Specification 4.0.4 are not applicable provided the surveillance is performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure is adequate to perform the test.

HOPE CREEK 3/4 7-11 Amendment No. 180

PLANT SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

C. by:

1. Performing a system functional test which includes simulated automatic actuation and restart# and verifying that each automatic valve in the flow path actuates to its correct position. Actual Injection of coolant into the reactor vessel may be excluded.

2. Verifying that the system will develop a flow of greater than or equal to 600 gpm in the test flow path when steam is supplied to the turbine at a pressure of 150 + 15, - 0 psig.*

3. Verifying that the suction for the*RCIC system is automatically transferred from the condensate storage ta,,'. to the suppression pool on a condensate storage tank water level-low signal.

"The provisions of Specification 4.0.4 are not applicable provided the surveillance is performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after reactor steam pressure is adequate to perform the tests.

Automatic restart on a low water level signal which is subsequent to a high water level trip.

HOPE CREEK 3/4 7-12

PLANT SYSTEMS 3/4.7.6 SEALED SOURCE CONTAMINATION LIMITING CONDITION FOR OPERATION 3.7.6 Each sealed source containing radioactive material either in excess of 100 microcuries of beta and/or gamma emitting material or 5 microcuries of a'--3 emitting material shall be free of greater than or equal to 0.005 microcuries of removable contamination.

APPLICABILITY: At all times.

ACTION:

a. With a sealed source having removable contamination in excess of the above limit, withdraw the sealed source from use and either:

1. Decontaminate and repair the sealed source, or

2. Dispose of the sealed source in accordance with Commission Regulations.

b. The pro% :ons of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.7.6.1 Test Requirements- Each sealed source shall be tested for leakage and/or contamination by:

a. The licensee, or

b. Other persons specifically authorized by the Commission or an Agreement State.

The test method shall have a detection sensitivity of at least 0.005 microcuries per test sample.

4.7.6.2 Test Frequencies - Each category of sealed sources, excluding startup sources an'Tfission detectors previously subjected to core flux, shall be tested at the frequency described below.

a. Sources in, use -* e*t*rr t for all sealed sources containing radioactive material:

1. With a half-life greater than 30 days, excluding Hydrogen 3, and

2. In any form other than gas.

0 HOPE CREEK 3/4 7-19 Amendmen.t No. . 19 .".-

PLANT SYSTEMS 3/4.7.'7 MAIN TURBINE BYPASS SYSTEM LIMITING CONDITION FOR OPERATION 3.7.7 The main turbine bypass system shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITION 1 when THERMAL POWER is greater than or equal to 24% of RATED THERMAL POWER.

ACTION: With the main turbine bypass system inoperable, restore the system to OPERABLE status within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or reduce THERMAL POWER to less than or equal to 24% of RATED THERMAL POWER within the next 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

SURVEILLANCE REQUIREMENTS The main turbine bypass system shall be demonstrated OPERABL< E

a. b by cycling each turbine bypass valve through at least one complete cycle full travel, and y :b . . ... .

b. : b

1. Performing a system functional test which includes simulated automatic actuation and verifying that each automatic valve actuates to its correct position.

2. Demonstrating TURBINE BYPASS SYSTEM RESPONSE TIME meets the following requirements when measured from the initial movement of the main turbine stop or control valve:

a) 80% of turbine bypass system capacity shall be established in less than or equal to 0.3 second.

b) Bypass valve opening shall start in less than or equal to 0.1 second.

HOPE CREEK 3/4 7-21 Amendment No. 174

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS 4.8.1.1.1 Each of the above required independent circuits between the offsite transmission network and the onsite Class 1E distribution system shall be:

a. Determined OPERABLE * '*ný-Q Pby verifying correct breaker alignments andinaicated power avail nd

b. Demonstrated OPERABLE t a shutdown by transferring, manua y and automatically, unit power supply from the normal circuit to the alternate circuit.

4.8.1.1.2 Each of the above required diesel generabe demonstrated OPERABLE: *7e 5

a. Aea scer y4 N A 6 by:

i. Verifying the fuel level in the fuel oil day tank.

2. Verifying the fuel level in the fuel oil storage tank.

3. Verifying the fuel transfer pump starts and transfers fuel from the storage system to the fuel oil day tank.

4. Verifying each diesel generator starts*- from standby conditions and achieves steady state voltage ! 3828 and

4580 volts and frequency of 60 + 1.2 Hz.

5. Verifying the diesel generator is synchronized, loaded to between 4000 and 4400*** kw and operates with this load for at least 60 minutes.

All engine starts and loading for the purpose of this surveillance testing may be preceded by an engine prelube period and/or other warmup procedures recommended by the manufacturer so that mechanical stress and wear on the diesel engine is minimized.

A modified diesel generator start involving idling and gradual acceleration to synchronous speed may be used for this surveillance.

Vhen modified start procedures are not used, the time, voltage, and frequency tolerances of Surveillance Requirement 4.8.1.1.2.g must be met.

momentary transients outside the load range do not invalidate this test.

HOPE CREEK 3/4 8-4 Amendment No.-+i,;h 144

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

6. verifying the diesel generator is aligned to provide standby power to the associated emergency busses.

7. Verifying the pressure in all diesel generator air start receivers to be greater than or equal to 325 psig.

8. Verifying the lube oil pressure, temperature and differential pressure across the lube oil filters to be within manufacturer's specifications.

b. ls visually examining a sample of lube oil from the diesel engine to verify absence of water.

/*-- c. and after each operation of the diesel where the period of operation was greater than or equal to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months by checking for and removing accumulated water from the fuel oil day tank.

d. -At st--e2t-by--

ý_- - removing accumulated water from the fuel oil storage tanks.

e. <!fý-Bý -by performing a functional test on the emergency load sequencer to verify operability.

f. In accordance with the surveillance interval specified in the Diesel Fuel Oil Testing Program and prior to the addition of new fuel oil to the storage tank, samples shall be taken to verify fuel oil quality. Sampling and testing of new and stored fuel oil shall be in accordance with the Diesel Fuel Oil Testing Program contained in Specification 6.8.4.e.

HOPE CREEK 3/ -5 Amendment No. 100

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

. a efbyylnm each diesel generator starts from standby conditions and achieves k 3950 volts and 58.8 Hz in 5 10 seconds after receipt of the start signal, and subsequently achieves steady state voltage k 3828 and 5 4580 volts and frequency of 60 +/- 1.2 Hz.

Jduring shutdown, by:

1. Deleted.

2. Verifying the diesel generator capability to reject a load of greater than or equal to that of the RHR pump motor for each diesel generator while maintaining voltage ? 3828 and 5 4580 volts and frequency at 60 +/- 1.2 Hz.

3. Verifying the diesel generator capability to reject a load of 4430 kW without tripping. The generator voltage shall not exceed 4785 volts during and following the load rejection.

4. Simulating a loss of offsite power by itself, and:

a) Verifying loss of power is detected and deenergization of the emergency busses and load shedding from the emergency busses.

b) Verifying the diesel generator starts on the auto-start signal, energizes the emergency busses with permanently connected loads within 10 seconds after receipt of the start signal, energizes the autoconnected shutdown loads through the load sequencer and operates for greater than or equal to 5 minutes while its generator is loaded with the shutdown loads. After energization, the steady state voltage and frequency of the emergency busses shall be maintained 2 3828 and 5 4580 volts and 60 +/- 1.2 Hz during this test.

For any start of a diesel generator, the diesel may be loaded in accordance with the manufacturer's recommendations.

HOPE CREEK 3/4 8-6 Amendment No. -9R,144

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued) i0. verifying the diesel generator's capability to:

a) Synchronize with the offsite power source while the generator is loaded with its emergency loads upon a simulated restoration of offsite power, b) Transfer its loads to the offsite power source, c) Be restored to its standby status, and d) Diesel generator circuit breaker is open.

11. Verifying that with the diesel generator operating in a test mode and connected to its bus, a simulated ECCS actuation signal overrides the test mode by (1) returning the diesel generator to standby operation, and (2) automatically energizes the emergency loads with offsite power.

12. Verifying that the fuel oil transfer pump .transfers fuel oil from each fuel, storage tank to the day tank of each diesel via the installed cross connection lines.

13. Verifying that the automatic load sequence timer is OPERABLE with the interval between each load block within +/- 10% of its design interval.

14. Deleted.

i. rr after any modifications which could affect diesel generator interdependence by starting all diesel generators simultaneously, during shutdown, and verifying that all diesel generators accelerate to at least 514 rpm in less than or equal to 10 seconds.

j. At ea eer'- by:

1. Draining each fuel oil storage tank, removing the accumulated sediment and cleaning the tank using a sodium hypochlorite solution or equivalent, and HOPE CREEK 3/4 8-8 Amendment No. 155

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS (Continued)

2. Performing a pressure test of those portions of the diesel fuel oil system designed to Section III, subsection ND of the ASME Code in accordance with ASME Code Section XI Article IWD-5000. 7'

k. lea ohce pI Cyr; by:

1. Verifying the diesel generator operates for at least 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . During the first 22 hours2.546296e-4 days 0.00611 hours 3.637566e-5 weeks 8.371e-6 months of this test, the diesel generator shall be loaded to between 4000 and 4400 kW" and during the remaining 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of this test, the diesel generator shall be loaded to between 4652 and 4873 kW. The diesel generator shall achieve a 3950 volts and a 58.8 Hz in 5 10 seconds following receipt of the start signal and subsequently achieve steady state voltage > 3828 and S 4580 volts and frequency of 60 +/- 1.2 Hz.

2. Within 5 minutes after completing 4.8.1.l.2.k.l, verify each diesel generator starts and achieves > 3950 volts and

> 58.8 Hz in < 10 seconds after receipt of the start signal, and subsequently achieves steady state voltage a 3828 and S 4580 volts and frequency of 60 +/- 1.2 Hz.

- OR -

Operate the diesel generator between 4000 kW and 4400 kW for two hours. Within 5 minutes of shutting down the diesel generator, verify each diesel generator starts and achieves a 3950 volts and a 58.8 Hz in < 10 seconds after receipt of the start signal, and subsequently achieves steady state voltage Z 3828 and !< 4580 volts and frequency of 60 t 1.2 Hz. This test shall continue for at least five minutes.

4.l.1...3 Reports - Not used.

4.8.1.1.4 The buried fuel oil transfer pipin 's cathodic protection system shall be demons tratedOPABjTestn pe--2*Dth ce e y subjecting the cathodic protec ion system to a performance test.

For any start of a diesel generator, the diesel may be loaded in accordance with manufacturer's recommendations.

1. Momentary transients outside the load range do not invalidate this test.

HOPE CREEK 3/4 8-9 Amendment No.++* 144

pp~t. pp~ ~ rnnL~ ~ *OU ni-no SURVEILLANCE REQUIREMENTS 4.8.2.1 Each of the above required batteries and charger. shall be demonstrated OPERABLE.

a. 7 y verifying that:

1. The parameters in Table 4.8.2.1-1 meet the Category A limits, and

2. Total battery terminal voltage for each 125-volt battery is greater than or equal to 129 volts on float charge and for each 250-volt battery the terminal voltage is greater than or equal to 258 volts on float charge.

d within 7 days after a battery discharge with battery terminal voltage below 108 volts for a 125-volt battery or 210 volts for a 250-volt battery, or battery overcharge with battery terminal voltage above 140 volts for a 125-volt battery or 280 volts for a 250-volt battery, by verifying that:

1. The parameters in Table 4.8.2.1-1 meet the Category B limits,

2. There is no visible corrosion at either terminals or connectors, or the connection resistance of these items is less than 150 x i0"6 ohms, excluding cable intercell connections, and

3. The average electrolyte temperature of each sixth cell of connected cells is above 72*?. I C. A t c-e by verifying that:

1. The cells, cell plates and battery racks show no visual indication of physical damage or abnormal deterioration,

2. The cell-to-cell and terminal connections are clean, tight, free of corrosion and coated with anti-corrosion material,

3. The resistance of each cell-to-cell and terminal connection is less than or equal to 150 x 10"6 ohms, excluding cable intercell connections, and

4. The battery charger will supply the current listed below at the voltage listed below for at least 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

CURRENT GMinimum Voltace (AM2ERZS)

=AD413, =AD414 129 200 IBD413, IBD414 ICD413, ICD414 ICD444, IDD414 IDD444, IDD413 10D423, 1OD433 258 50 HOPE CREEK 3/4 8-13 Amendment No. ?1, 118 I

ELECTRICAL POWER SYSTEMS SURVEILLANCE REQUIREMENTS Continued)

d. *eato sa3p -mft*4Ls* during shutdown, by verifying that the battery capacity is adequate to supply and maintain in OPERABLE status all of the actual or simulated emergency loads for the design duty cycle when t ery is subjected to a battery service test.

e. *e asoz pe r',G0 b during shutdown, by verifying that the battery capacity is at least 80% of the manufacturer's rating when subjected to a performance discharge test. ts p this performance discharge test may be performed in lieu of tR attery service test.

f. At least once per 18 months, during shutdown, performance discharge tests of battery capacity shall be given to any battery that shows signs of degradation or has reached 85% of the service life expected for the application. Degradation is indicated when the battery capacity drops more than 10% of rated capacity from its average on previous performance tests, or is below 90% of the manufacturer's rating. At this once per 18 months interval, this performance dis-charge test may be performed in lieu of the battery service test.

HOPE CREEK 3/4 8-14 Amendment No. 87

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With one of the above required A.C. distribution system channels not energized, re-energize the channel within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

b. with one of the above required 125 volt D.C. distribution system channels not energized, re-energize the division within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

c. With any one of the above required 250 volt D.C. distribution systems not energized, declare the associated HPCI or RCIC system inoperable and apply the appropriate ACTION required by the applicable Specifications.

d. With one or both inverters in one channel inoperable, energize the associated 120 volt A.C. distribution panel(s) within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , and restore the inverter(s) to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ; or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

SURVEILLANCE REQUIREMENTS 4.8.3.1 Each of the above required power distribution system channels shall be determined energizede"a* *e -*e7.. by verifying correct breaker/switch alignment and voltage on the buss.

HOPE CREEK 3/4 B-20 Amendment No. 175

ELECTRICAL POWER SYSTEMS LIMITING CONDITION FOR OPERATION (Continued)

APPLICABILITY: OPERATIONAL CONDITIONS 4, 5 and .

ACTIQON a,. With less than two channels of the above required A.C. distribution system energized, suspend CORE ALTERATIONS, handling of recently irradiated fuel in the secondary cont&inment and operations with a

.I potential for draining the reactor vessel.

b. With less than two channels of the above required D.C. distribution system energized, suspend CORE ALTERATIONS, handling of recently irradiated fuel in the secondary containment and operations with a potential for draining the reactor vessel.

C. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.8.3.2 At least the, above r~uired power distribution system channels shall be determined energized

eby verifying correct breaker/switch alignmenta' on t busses/MCCs/panels.

When handling recently irradiated fuel in the secondary containment.

HOPE CREEK 3/4 8-23 Amendment No. 170

ELECTRICAL POWER SYSTEMS PRIMARY CONTAINMENT PENETRATION CONDUCTOR OVERCURRENT- PROTECTIVE DEVICES LIMITING CONDITION FOR OPERATION 3.8.4.1 All primary containment penetration conductor overcurrent protective devices shown in Table 3.8.4.1-1 shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With one or more of the primary containment penetration conductor over-current protective devices shown in Table 3.8.4.1-1 inoperable, declare the affected system or component inoperable and apply the appropriate ACTION statement for the affected system, and

1. For 4.16 kV circuit breakers, de-energize the 4.16 kV circuit(s) by tripping the associated redundant circuit breaker(s) within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and verify the redundant circuit breaker to be tripped at least once per 7 days thereafter.

2. For 480 volt circuit breakers, remove the inoperable circuit breaker(s) from service by disconnecting* the breaker within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and verify the inoperable breaker(s) to be disconnected at least once per 7 days thereafter.

Otherwise, be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

I.

SURVEILLANCE REQUIREMENTS 4.8.4.1 Each of the primary containment penetration conductor overcurrent protective devices shown in Table 3.8.4.1-1 sall be demonstrated OPERABLE:

a. tAS T

1. By verifying that each of the medium voltage 4.16 kV circuit breakers are OPERABLE by performing:

a) A CHANNEL CALIBRATION of the associated protective relays, and b) An integrated system functional test which includes simulated automatic actuation of the system and verifying that each relay and associated circuit breakers and overcurrent control circuits function as designed.

After being disconnected, these breakers shall be maintained disconnected under administrative control.

HOPE CREEK 3/4 8-24 Amendment No. 180

ELECTRICAL POWER SYSTEMS SURVEILLANCE REqUIREMENTS (Conti nued)

2. By selecting and functionally testing a representative sample of at least .10% of each type of lower voltage circuit breakers.

Circuit breakers selected for functional testing shall be selected on a rotating basis. Testing of these, circuit breakers shall consist of injecting a current with a value between 150% and 300% of the pickup of the long time delay trip element and verifying that the circuit breaker operates within the time delay bandwijdth for that current specified by the manufacturer.

The' instantaneous element shall be tested by injecting a current in excess of 120% the pickup value of the element and verifying that the circuit breaker trips instantaneou.sly:with no inten-tional time delay. Molded case circuit breaker testing shall also follow this procedure except that generallyno impre than

two trip eleMents',"'tm'e delay and' instantaneous, will be involved. Circuit breakers found inoperable during functional testing shall be restored to OPERABLE status pri-r to resuming operation. For each circuit breaker found inoperable during these functional tests, an additional representative sample of at least 10% of all the circuit breakers-of the inoperable type shall also be functionally tested until no more failures are found or all circuit breakers of that type have been functionally tested.

b. t7ejj.o., by subjecting each circuit breaker to an inspecIon and preventive maintenance in accordance with procedures prepared in conjunction with its manufacturer's recommendations.

HOPE CREEK 3/4 8-25

ELECTRICALI POWER SYSTEMS MOTOR OPERATED VALVES - THERMAL OVERLOAD PROTECTION 0BYPASSED)

LIMITING CONDITION FOR OPERATION 3.8.4.2 The thermal overload protection bypass circuit of each motor operated valve (MOV) required to have thermal overload protection shall be OPERABLE.

APPLICABILITY: Whenever the MOV is required to be OPERABLE.

ACTION:

With the thermal overload protection bypass circuit for one or more of the above required MOVs inoperable, restore the inoperable thermal overload protection bypass circuit(s) to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or declare the affected MOV(s) inoperable and apply the appropriate ACTION statement(s) for the affected system(s).

SURVEILLANCE REQUIREMENTS 4,8.4.2.1 The thermal overload protection bypass circuit for each of the above required MOVs shall be demonstrated OPERABLE:

ýa t c'*,,pe-& bythe performance of a CH{ANNEL

~FtTNCTTONAr TEST-t0r:

1. Those thermal overload protection devices which are normally in force during plant operation and bypassed only under accident conditions.

,2. A representative sample of at least 25t of those thermal overload protection devices which are bypassed continuously and temporarily placed in force only when the M0V9 are underon periodic, or maintenance testin ý-,s>h'That t*

3. A representative sample of at least 25 of those N thermal overload protection devices which are in force during normal manual (momentary push button contact) MOV operation and bypassed during remote manual (push button held depressed)

MOV operation ýs'I Kh~th ba\s 'rN~ty*re~

b. Following maintenance on the motor starter.

4.8.4.2.2 The therm*.al. overload protection for -the above required mOVs which are continuously bypassed and temporarily placed in force only when the MOV is undergoing periodic or maintenance testing shall .be verified to be continuously bypassed following such testing.

HOPE CREEK 3/4 8-30 Amendment No. 103

ELECTRICAL POWER SYSTEMS MOTOR OPERATED VALVES - THERMAL OVERLOAD PROTECTION (NOT BYPASSED)

LIMITING CONOITION FOR OPERATION 3.8.4.3 The thermal overload protection of each motor operated valve (MOV) shown in Table 3.8.4.3-1 shall be OPERABLE.

APPLICABILITY: Whenever the MOV is required to be OPERABLE.

ACTION:

With the thermal overload protection for one or more of the above required MOVs inoperable, restore the inoperable thermal overload(s) to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months or declare the affected MOV(s) inoperable and apply the appro-priate ACTION statement(s) for the affected system(s).

SURVEILLANCE REQUIREMENTS 4.8.4.3 The thermal overload protectiofor each of above required MOVs shall be demonstrated OPERABLE ,Ji etj f nd following main-tenance on the motor starter by e periformance of a CHANNEL CALIBRATION.

HOPE CREEK 3/4 8-38

ELECTRICAL POWER SYSTEMS REACTOR PROTECTION SYSTEM ELECTRICAL POWER MONITORING LIMITING CONDITION FOR OPERATION 3.8.4.4 Two RPS electric power monitoring channels for each inservice RPS MG set or alternate power supply shall be OPERABLE.

APPLICABILITY: At all times.

ACTION:

a. With one RPS electric power monitoring channel for an inservice RPS MG set or alternate power supply inoperable, restore the inoperable power monitoring channel to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or remove the associated RPS MG set or alternate power supply from service.

b. With both RPS electric power monitoring channels for an inservice RPS MG set or alternate power supply inoperable, restore at least one electric power monitoring channel to OPERABLE status within 30 minutes or remove the associated RPS MG set or alternate power supply from service.

SURVEILLANCE REQUIREMENTS 4.8.4.4 The above specified RPS electric power monitoring channels shall be determined OPERABLE:

a. By performance of a CHANNEL FUNCTIONAL TEST each time the plant is in COLD SHUTDOWN for a period of more than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , unless performed in the previous 6 months.

b. -lea.oagj,* by demonstrating the OPERABILITY of 0 -og ner-vage, and under-frequency protective instrumentation by performance of a CHANNEL CALIBRATION including simulated automatic actuation of the protective relays, tripping logic and output circuit breakers and verifying the following setpoints.

2. Over-voltage < 132 VAC, (Bus A), 132 VAC (Bus B)

2. Under-voltage > 108 VAC, (Bus A), 108 VAC (Bus B)

3. Under-frequency > 57 Hz. (Bus A and Bus B)

HOPE CREEK 3/4 8-40 Amendment No. 44

ELECTRICAL POWER SYSTEMS CLASS 1E ISOLATION BREAKER OVERCURRENT PROTECTIVE DEVICES LIMITING CONDITION FOR OPERATION 3.8.4.5 All Class IE isolation breaker (tripped by a LOCA signal) overcurrent protective devices shown in Table 3.8.4.5-1 shall be OPERABLE.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2 and 3.

ACTION:

a. With one or more of the overcurrent protective devices shown in Table 3.8.4.5-1 inoperable, declare the affected isolation breaker inoperable and remove the inoperable circuit breaker(s) from service within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and verify the inoperable breaker(s) to be disconnected at least once per 7 days thereafter.

SURVEILLANCE REQUIREMENTS 4.8.4.5 Each of the Class 1E isolation breaker overcurrent protective devices shown in Table 3.8.4.5-1 shall be demonstE;

a. a oe r8 srý?

By selecting and functionally testing a representative sample of at least 10% of each type of lower voltage circuit breakers. Circuit breakers selected for functional testing shall be selected on a rotating basis. Testing of these circuit breakers shall consist of injecting a current with a value between 150% and 300% of the pickup of the long time delay trip element and a value between 150% and 250% of the pickup of the short time delay, and verifying that the circuit breaker operates within the time delay band width for that current specified by the manufacturer. The instantaneous element shall be tested by injecting a current in excess of 120% of the pickup value of the element and verifying that the circuit breaker trips instantaneously with no intentional time delay. Molded case circuit breaker testing shall also follow this procedure except that generally no more than two trip elements, time delay and instantaneous, will be involved. For circuit breakers equipped with solid state trip devices, the functional testing may be performed with use of portable instruments designed to verify the time-current characteristics and pickup calibration of the trip elements.

Circuit breakers found inoperable during functional testing shall be restored to OPERABLE status prior to resuming operation. For each circuit breaker found inoperable during these functional tests, an additional representative sample of at least 10% of all the circuit breakers of the inoperable type shall also be functionally tested until no more failures are found or all circuit breakers of that type have been functionally tested.

b. ntbeaes*bn e 6 by subjecting each circuit breaker to an inspection and preventive maintenance in accordance with procedures prepared in conjunction with its manufacturer's recommendations.

HOPE CREEK .3/4.8-41 Amendment No. 180

ELECTRICAL POWER SYSTEM POWER RANGE NEUTRON MONITORING SYSTEM ELECTRICAL POWER MONITORING LIMITING CONDITION FOR OPERATION 3.8.4.6 The power range neutron monitoring system (NMS) electric power monitoring channels for each inservice power range NMS power-supply shall be OPERABLE.

APPLICABILITY: At all times.

ACTION:

a. With one power range NMS electric power monitoring channel for an inservice power range NMS power supply inoperable, restore the in-operable power monitoring channel to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or deenergize the associated power range NMS power supply feeder circuit.

b. With both power range NMS electric power monitoring channels for an inservice power range NMS power supply inoperable, restore at least one electric power monitoring channel to OPERABLE status within 30 minutes or deenergize the associated power range NMS power supply feeder circuit. 4 SURVEILLANCE REQUIREMENTS 4.8.4.6 The above specified power range NMS electric power monitoring channels shall be determined OPERABLE:

a. By performance of a CHANNEL FUNCTIONAL TEST each time the plant is in COLD SHUTDOWN for a period of more than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ., unless performed in the previous 6 months.

b. by demonstrating the OPERABILITY of over-voltage, unaer-voltage, and under-frequency protective instrumentation by performance of a CHANNEL CALIBRATION including simulated automatic actuation of the protective relays, tripping logic and output circuit breakers and verifying the following setpoints.

1. Over-voltage < 132 VAC (BUS A), 132 VAC (BUS B)

2. Under-voltage > 108 VAC (BUS A), 108 VAC (BUS B)

3. Under-frequency > 57 Hz. -0, +2%

HOPE CREEK 3/4 8-44 Amendment No. 44

REFUELING OPERATIONS SURVEILLANCE REQUIREMENTS 4.9.1.1 The reactor mode switch shall be verified to be locked in the Shutdown or Refuel position as specified:

a. Within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months prior to:

1. Beginning CORE ALTERATIONS, and

2. Resuming CORE ALTERATIONS when the reactor mode switch has been unlocked.

b.

4.9.1.2 Each of the above required reactor mode switch Refuel position interlocks* shall be demonstrated OPERABLE by performance of a CHANNEL FUYN.LNAL TEST within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior 1othe start of and k

(:5 ý during control rod withdrawal or CORE ALTERATIONS, as applcae__

4.9.1.3 Each of the above required reactor mode switch Refuel position interlocks* that is affected shall be demonstrated OPERABLE by performance of a CHANNEL FUNCTIONAL TEST prior to resuming control rod withdrawal or CORE ALTERATIONS, as applicable, following repair, maintenance or replacement of any component that could affect the Refuel position interlock.

The reactor mode switch may be placed in-the Run or Startup/Hot Standby position to test the switch interlock functions provided that all control rods are verified to remain fully inserted by a second licensed operator or other technically qualified member of the unit technical staff.

HOPE CREEK 3/4 9-2

REFUELING OPERATIONS 3/4 .9.2 INSTRUMENTATION LIMITING CONDITION FOR OPERATION, 3.9.2 At least 2 source range monitor* (SRM) channels shall be OPERABLE and inserted to the normal operating level with:##

a. Annunciation and continuous visual indication in the control room,

b. One of the required SRM detectors located in the quadrant where CORE ALTERATIONS are being performed and the other required SRM detector located in an adjacent quadrant, and

c. Unless adequate shutdown margin has been demonstrated per Specifica-tion 3.1.1, the "shorting links" removed from the RPS circuitry prior to and during the time any control rod is withdrawn.#

d. During a SPIRAL UNLOAD, the count rate may drop below 3 cps when the number of assemblies remaining in the core drops to sixteen or less.

e. During a SPIRAL RELOAD, up to four fuel assemblies may be loaded in the four bundle locations immediately surrounding each of the four SRMs prior'to obtaining,3 cps. Until these assemblies have been loaded, the 3 cps count rate is not required.

APPLICABILITY: OPERATIONAL CONDITION'5. -4..

ACTION:

'zWith the'requirements of the above specificationi not satisfied, immediately' suspend all operations involving "CORE ALTERATIONS. and insert all insertable control rods. "

SURVEILLANCE REQUIREMENTS 4.9.2 Each of the above required SRM channels shall be demonstrated OPERABLE by:

a. lea ce e 2 -eipuit--o; - *

1. Performance oa CEL CHECK, The use of special movable detectors during CORE ALTERATIONS in place of the normal SRM nuclear detectors is permissible as long as these special detectors are connected to the normal SRM circuits.

Not required for control rods removed per Specification 3.9.10.1 and 3.9.10.2.

1. Three SRM channels shall be OPERABLE for critical shutdown margin demonstra-tions. An SRM detector may be retracted provided a channel indication of at least 100 cps is maintained.

HOPE CREEK 3/4 9-3 Amendment No. 14

REFUELING OPERATIONS SURVEILLANCE REQUIREMENTS (Continued)

2. Verifying the detectors are inserted to the normal operating level, and

3. During CORE ALTERATIONS, verifying that the detector of an OPERABLE SRM channel is located in the core quadrant where CORE ALTERATIONS are being performed and another is located in an adjacent quadrant.

b. Prr ncL FUNCTIONAL TES I

c. Verifying that the channel count rate is at least 3 cps.

1. Prior to control rod withdrawal,

2. Prior to and i an ýurg CORE ALTERATIONS***, and 3.. *

d. Unless adequate shutdown margin has been demonstrated per Specification 3.1.1, verifying that the RPS circuitry "shrting link" have been removed, within S hours prior to ande Q I ýwu during the time any control rod is witrawn.**

- Not required for control rods removed per Specification 3.9.10.1 or 3.9.10.2.

- - Except as noted in Specifications 3.9.2.d and 3.9.2.e.

HOPE CREEK 3/4 9-4 Amendment No. 153

REFUELING OPERATIONS 3/4.9.3 CONTROL ROD POSITION LIMITING CONDITION FOR OPERATION 3.9.3 All control rods shall be inserted.*

APPLICABILITY: OPERATIONAL CONDITION 5, during CORE ALTERATIONS.**

ACTION:

With all control rods not inserted, suspend all other CORE ALTERATIONS, except that one control rod may be withdrawn under control of the reactor mode switch Refuel position one-rod-out interlock.

SURVEILLANCE REQUIREMENTS 4.9.3 All control rods shall be verified to be inserted, except as above specified:

a. Within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months prior to:

1. The start of CORE ALTERATIONS.

2. The withdrawal of one control rod under the control of the reactor mode switch Refuel position one-rod-out interlock.

b. ý-týVe~ja ý

" Except control rods removed per Specification 3.9.10.1 or 3.9.10.2.

- See Special Test Exception 3.10.3.

HOPE CREEK 3/4 9-5

REFUELING OPERATIONS 3/4.9.8 WATER LEVEL - REACTOR VESSEL LIMITING CONDITION FOR OPERATION 3.9.8 At least 22 feet 2 inches of water shall be maintained over the top of the reactor pressure vessel flange.

APPLICABILITY: During handling of fuel assemblies or control rods within the reactor pressure vessel while in OPERATIONAL CONDITION 5 when the fuel assemblies being handled are irradiated or the fuel assemblies seated within the reactor vessel are irradiated.

ACTION:

With the requirements of the above specificat~ion not satisfied, suspend all operations involving handling of fuel assemblies or control rods within the reactor pressure vessel after placing all fuel assemblies and control rods in a safe condition.

SURVEILLANCE REQUIREMENTS 4.9.8 The reactor vessel water level shall be determined to be at least its minim re uired depth within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months prior to the start of and l-(tS'%",4* during handling of fuel assemblies or control rods with tie reactor pressure vessel.

0 HOPE CREEK 3/4 9-11

REFUELING OPERATIONS 3/4.9.9 WATER LEVEL - SPENT FUEL STORAGE POOL LIMITING CONDITION FOR OPERATION 3.9.9 At least 23 feet of water shall be maintained over the top of irradiated fuel assemblies seated in the spent fuel storage pool racks.

APPLICABILITY: Whenever irradiated fuel assemblies are in the spent fuel storage pool.

ACTION:

With the requirements of the above specification not satisfied, suspend all movement of fuel assemblies and crane operations with loads in the spent fuel storage pool area after placing the fuel assemblies and crane load in a safe condition. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.9.9 The water level in the spent fuel strg o hl-bedtrie o be at least at its minimum required depth HOPE CREEK 3491 3/4 9-12

REFUELING OPERATIONS 4 SURVEILLANCE REQUIREMENTS 4.9.10.1 Within 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months prior to the start of removal of a control rod and/or the associated control od drive mechanism from the core and/or reactor pressure vessel and e c s- Ythereafter until a control rod and associ-ated control rod-drive mecanism are reinstalled and the control rod is inserted in the core, verify that:

a. The reactor mode switch is OPERABLE per Surveillance Requirement 4.3.1.1 or 4.9.1.2, as applicable, and locked in the Shutdown position or in the Refuel position with the "one rod out" Refuel position interlock OPERABLE per Specification 3.9.1. 1

b. The SRM channels are OPERABLE per Specification 3.9.2.

c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied per Specification 3.9.10.1.c.

d. All other control rods in a five-by-five array centered on the control rod being removed are inserted and electrically or hydraulically disarmed or the four fuel assemblies surrounding the control rod or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell.

e. All other control rods are inserted.

f. All fuel loading operations are suspended.

HOPE CREEK 3/4 9-14

REFUELING OPERATIONS SURVEILLANCE REQUIREMENTS 4.9.10.2.1 Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months prior to the start of removal of control rods and/or control rod drive mechanisms from the core and/or reactor pressure vessel and d Ivs a e, jsýu thereafter until all control rods and control rod dri mec anisms are reinstalled and all control rods are inserted in the core, verify that:

a. The reactor mode switch is OPERABLE per Surveillance Requirement 4.3.1.1 or 4.9.1.2, as applicable, and locked in the Shutdown position or in the Refuel position per Specification 3.9.1.

b. The SRM channels are OPERABLE per Specification 3.9.2.

c. The SHUTDOWN MARGIN requirements of Specification 3.1.1 are satisfied.

d. All other control rods are either inserted or have the surrounding four fuel assemblies removed from the core cell.

e. The four fuel assemblies surrounding each control rod and/or control rod drive mechanism to be removed from the core and/or reactor vessel are removed from the core cell. s'

f. All fuel loading operations are suspended.

4.9.10.2.2 Following replacement of all control rods and/or control rod drive mechanisms removed in accordance with this specification, perform a functional test of the "one-rod-out" Refuel position interlock, if this function had been bypassed.

HOPE CREEK 3/4 9-16

REFUELING OPERATIONS 3/4.9.11 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION HIGH WATER LEVEL LIMITING CONDITION FOR OPERATION 3.9.11.1 At least one shutdown cooling mode loop of the residual heat removal (RHR) system shall be OPERABLE and in operation* with:

a. One OPERABLE RHR pump, and

b. One OPERABLE RHR heat exchanger.

APPLICABILITY: OPERATIONAL CONDITION 5, when irradiated fuel is in the reactor vessel and the water level is greater than or equal to 22 feet 2 inches above the top of the reactor pressure vessel flange and heat losses to ambient** are not sufficient to maintain OPERATIONAL CONDITION 5.

ACTION:

a. With no RHR shutdown cooling mode loop OPERABLE, within one hour and at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter, demonstrate the operability of at:

least one: *alternate method. capable of decay heat removal. Otherwise,,

suspend all operations involving an increase in the reactor decay heat l1ad and establish SECONDARY CONTAINMENT,INTEGRITY within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months '.

b. With no RHR shutdown cooling mode loop in0operation, within. one hour establish reactor coolant ýcirculation by 'an alterna te method and monitor reactor coolant temperature at least once per hour.

SURVEILLANCE REQUIREMENTS 4.9.11.1 At least one shutdown cooling mode loop of the residual heat removal system or alternate method shall be verified to be in operation and circulating reactor coolant a e t r .

The shutdown cooling pump may be removed from operation for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months per 8-hour period.

- Ambient losses must be such that no increase in reactor vessel water temper-ature will occur (even though REFUELING conditions are being maintained).

HOPE CREEK 3/4 9-17

REFUELING OPERATIONS LOW WATER LEVEL LIMITING CONOITION FOR OPERATION 3.9.11.2 Two shutdown cooling mode loops of the residual heat removal (RHR) system shall be OPERABLE and at least one loop shall be in operation,* with each loop consisting of:

a. One OPERABLE RHR pump, and

b. One OPERABLE RHR heat exchanger, APPLICABILITY: OPERATIONAL CONDITION 5, when irradiated fuel is in the reactor vessel and the water level is less than 22 feet 2 inches above the top of the reactor pressure vessel flange and heat losses to ambient*" are not sufficient to maintain OPERATIONAL CONDITION 5.

ACTION:

a. With less than the above required shutdown cooling mode loops of the RHR system OPERABLE, within one hour and at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months there-after, demonstrate the OPERABILITY of at least one alternate method capable of decay heat removal for each inoperable RHR shutdown cooling mode loop.

b. With no RHR shutdown cooling mode loop in operation, within one hour establish reactor coolant circulation by an alterpate method and monitor reactor coolant temperature at least once per hour.

SURVEILLANCE REQUIREMENTS 4.9.11.2 At least one shutdown cooling mode loop of the residual heat removal system or alternate method shal be verified to bA-io-weration and circulating reactor coolant ftQ'",;R,--I(JSS&"..T.-

The shutdown cooling pump may be removed from operation for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months per 8-hour period.

"*Ambient losses must be such that no increase in reactor vessel water temper-ature will occur (even though REFUELING conditions are being maintained).

HOPE CREEK 3/4 9-18 Amendment No. 1-q -7.

3/4.10 SPECIAL TEST EXCEPTIONS 3/4.10.1 PRIMARY CONTAINMENT INTEGRITY LIMITING CONDITION FOR OPERATION 3.10.1 The provisions of Specifications 3.6.1.1, 3.6.1.3 and 3.9.1 and Table 1.2 may be suspended to permit the reactor pressure vessel closure head and the drywell head to be removed and the primary containment air lock doors to be open when the reactor mode switch is in the Startup position during low power PHYSICS TESTS with THERMAL POWER less than 1% of RATED THERMAL POWER and reactor coolant temperature less than 2000F.

APPLICABILITY: OPERATIONAL CONDITION 2, during low power PHYSICS TESTS.

ACTION:

With THERMAL POWER greater than or equal to 1% of RATED THERMAL POWER or with the reactor coolant temperature greater than or equal to 2000F, immediately place the reactor mode switch in the Shutdown position.

SURVEILLANCE REQUIREMENTS 4.10.1 The THERMAL POWER and reactor coolant temperature shall be verified to be within the limits (Elt~ c* tSduring low power PHYSICS TESTS.

HOPE CREEK 3/4 10-1

SPEC:A L-EST EXCE~tiONS 3/4 10.3 SHUTOOWN MARGItN OEMONSTRATIONS L:MITING CONDITION FOR OPERATION 3.10.3 'he provisions of Specification 3.9.1, Specification 3.9.3 and TaD!e 1.2 may oe susoended to oermit the reactor mode switch to be in the Startuo position and to allow more than one control rod to be withdrawn for shutdown margin demonstration, provided that at least the following requirements are satisfied.

a. The source range monitors are OPERABLE with the RPS circuitry "snort' linKS" removed per Specification 3.9.2.

0. The rod worth minimizer is OPERABLE per Specification 3.1.4.1 anc i5 programmed for the shutdown margin demonstration, or conformance witm the shutdown margin demonstration procedure is verified by a seconc licensed operator or other technically qualified member of the unit technical staff.

c. The "rod-out-notch-override" control shall not be used during out-of-sequence movement of the control rods.

d. No other CORE ALTERATIONS are in progress.

APPLICABILITY: OPERATIONAL CONDITION 5, during shutdown margin demonstrations.

ACTION:

With the requirements of the above specification not satisfied, immediately place the reactor mode switch in the Shutdown or Refuel position.

SURVEILLANCE REQUIREMENTS 4.10.3 Within 30 minutes prior to and e $a during the performance of a shutdown margin demons

a. The source range monitors are OPERABLE per Specification 3.9.2,

b. The rod worth minimizer is OPERABLE with the required program per Specification 3.1.4.1 or a second licensed operator or other techni-cally qualified member of the unit technical staff is present and verifies compliance with the shutdown demonstration procedures, and

c. No other CORE ALTERATIONS are in progress.

HOPE CREEK 3/4 10-3

IPECIAL TEST EXCEPTIONS

/4.^0.14 qECIRCULATION LOOPS LIMITING CONDITION FOR OPERATION 3.10.4 The reauirements of Soecifications 3.4.1.1 and 3.4.1.3 that recirculation loops be in ooeration qith matchea oump soeed may be susoendea for up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for the performance of:

a. PHYSICS TESTS, provided that THERMAL POWER does not exceed 5% of RATED THERMAL POWER.

APOLICABILTTY: OPERATIONAL CONDITIONS I and 2, during PHYSICS TESTS.

ACTDON:

a. With the above soecified time limit exceeded, insert all control rods.

b. With the above specified THERMAL POWER limit exceeded during PHYSICS TESTS, immediately place the reactor mode switch in the Shutdown position.

SURVEILLANCE REQUIREMENTS 4.10.4.1 The time during which the above specified, requirement has been suspended shall be verified to be less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months a leýt \bNN- during PHYSICS TESTS.

4.10.4.2 THERMAL POWER shall be determined to be less than 5% of RATED THERMAL POWER <rduring PHYSICS TESTS.

HOPE CREEK 3/4 10-4 Amendment No. 35

SPEC:AL TEST ;XCEPTONS 3/4.10.6 'RAINING STARTUPS LIMITING CONDITION FOR OPERATION 3.10.5 The provisions of Specification 3.5.1 may be suspended to permit one RHR subsystem to be aligned in the shutdown cooling mode during training startups provided that the reactor vessel is not pressurized, THERMAL POWER is less than or equal to 1% of RATED THERMAL POWER and reactor coolant temoerature is less than 200*F.

APPLICABILITY: OPERATIONAL CONDITION 2, during training startups.

ACTION:

With the reouirements of the above specification not satisfied, immediately place the reactor mode switch in the Shutdown position.

SURVEILLANCE REQUIREMENTS 4.10.6 The reactor vessel shall be verified to be unpressurized and the THERMAL POWER and reactor coolant temperature shall be verified to be within the limits d during training startups.

HOPE CREEK 3/4 10-6

RADIOACTIVE EFFLUENTS LIQUID HOLDUP TANKS LIMITING CONDITION FOR OPERATION 3.11.1.4 The quantity of radioactive material contained in any outside temporary tank shall be limited to less than or equal to 10 curies, excluding tritium and dissolved or entrained noble gases.

APPLICABILITY: At all times.

ACTION:

a. With the quantity of radioactive material in any of the above tanks exceeding the above limit, immediately suspend all additions of radioactive material to the tank, within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months reduce the tank contents to within the limit, and describe the events leading to this condition in the next Radioactive Effluent Release Report, pursuant to Specification 6.9.1.7.

b. The provisions of Specification 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS 4.11.1.4 The quantity of radioactive material contained in each of the above tanks shall be determined to be within the above limit by analyzing a representative sample of the tank's contents when radioactive materials are being added to the tank.

HOPE CREEK 3/4 11-2 Amendment No. 121 I

RADIOACTIVE EFFLUENTS MAIN CONDENSER LIMITING CONDITION FOR. OPERATION 3.11.2.7 The radioactivity rate of noble gases measured at the recombiner after-condenser discharge shall be limited to less than or equal to 3.30 E+5 microcuries/sec after 30 minute decay.

APPLICABILITY: OPERATIONAL CONDITIONS 1, 2* and 3*.

With the radioactivity rate of noble gases at the recombiner after-condenser discharge exceeding 3.30 E+5 microcuries/sec after 30 minute decay, restore the radioactivity rate to within its limit within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.11.2.7.1 The radioactivity rate of noble gases at the recombiner after-condenser discharge shall be continuously monitored in accordance with Specification 3.3.7.1.

4.11.2.7.2 The radioactivity rate of noble gases from the recombiner after-condenser discharge shall be determined to be within the limits of Specification 3.11.2.7 at the following frequencies by performing an isotopic analysis of a representative sample of gases taken near the discharge of the main condenser air ejector:

a.

b. Within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months followir. an increase, as indicated by the Offgas Pretreatment Radiation Monitor, of greater than 50%, after factoring out increases due to changes in THERMAL POWER level, in the nominal steady-state fission gas release from the primary coolant.

c. The provisions of Specification 4.0.4 are not applicable.

When the main condenser air ejector is in operation.

HOPE CREEK 3/4 11-17 Amendment No. 66

ADMINISTRATIVE CONTROLS PROCEDURES AND PROGRAMS (Continued) 6.8.4.g. Radioactive Effluent Controls Program

8) Limitations on the annual and quarterly air doses resulting from noble gases released in gaseous effluents from the unit to.areas beyond the SITE BOUNDARY conforming to Appendix I to 10 CFR Part 50,

9) Limitations on the annual and quarterly doses to a MEMBER OF THE PUBLIC from Iodine-131, Iodine-133, tritium, and all radionuclides in particulate form with half-lives greater than 8 days in gaseous effluents released from the unit to areas beyond the SITE BOUNDARY conforming to Appendix I to 10 CFR Part 50,

10) Limitations on venting and purging of the containment through the Reactor Building Ventilation System, Hardened Torus Vent, or the FRVS to maintain releases as low as reaspnably achievable,, and l*)Limitations;on the annual dose or dose commitment to any

,.*MEMBER OFPTHE PUBLIC due to releases of radioactivity and to radiation from uranium fuel cycle sources conforming to 40 CFR Part 190..

h. Radiological Environmental Monitoring Program A program shall be provided to monitor the radiation and radionuclides in the environs of the plant. The program shall provide (1) representative measurements of radioactivity in the highest potential exposure pathways, and (2) verification of the accuracy of the effluents monitoring program and modeling of the environmental exposure pathways. The program shall (i) be contained in the ODCM, (2) conform to the guidance of Appendix I to 10 CFR Part 50, and (3) include the following:

1) Monitoring, sampling, analysis, and reporting of radiation and radionuclides in the environment in accordance with the methodology and parameters in the ODCM,

2) A Land Use Census to ensure that changes in the use of areas at and beyond the SITE BOUNDARY are identified and that modifications to the monitoring program are made if required by the results of this census, and

3) Participation in an Interlaboratory Comparison Program to ensure that independent checks on the precision and accuracy of the measurements of radioactive materials in environmental sample matrices are performed as part of the quality assurance program for environmental monitoring.

HOPE CREEK 6-16d Amendment No. 121

ATTACHMENT 4 LAR H10-01 LR-N10-0015 ATTACHMENT 4 (Information Only)

TECHNICAL SPECIFICATION BASES PAGES WITH PROPOSED CHANGES:LICENSE AMENDMENT TO ADOPT TSTF-425, REVISION 3, "RELOCATE SURVEILLANCE FREQUENCIES TO LICENSEE CONTROL" The following Technical Specification Bases Pages for HCGS (Facility Operating License NPF-57) are affected by this change request:

B 3/4 1-2 B 3/4 3-16 B 3/4 1-2a B 3/4 3-17 B 3/4 1-2b B 3/4 4-2 B 3/4 1-2c B 3/4 4-3 B 3/4 1-4 B 3/4 5-1 B 3/4 3-1 B 3/4 6-5 B 3/4 3-2q B 3/4 6-8 B 3/4 3-2r B 3/4 6-9 B 3/4 3-3 B 3/4 6-12 B 3/4 3-4 B 3/4 6-13 B 3/4 3-11 B 3/4 6-14 B 3/4 3-12 B 3/4 8-1d 1 of 2

ATTACHMENT 4 LAR H10-01 LR-N10-0015

{INSERT 11 In accordance with the Surveillance Frequency Control Program JINSERT 2 The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

2 of 2

Document Control Desk LAR H09-03 LR-N09-0 93

=EACIrCTY WIOTnECI SYSTEIIS 3/4.13 CONTTROL RODS The specifications of this section ensure that ti) the miniimum SRUTDZWN MIGUfT is maintained, ý2) the control rod insertion times are consistent -with those userl in the accident enal-'sis, and (3) limit the potential -ffects of the rod drop accident, The ACTION statements permit "-ariations from the basic requir-ements but at the same rime impose mre restrictive cr-iteria for continued operation. A limitation on inoperable rods is set such that th-e resultant.

effect on total rod worth and scram shape will be kept to a minlimum. The requir-ements for the various scram time measurements ensure thiat aniy indicat-ion of systematic problems with rod drives will be in.-astigated on a tial-v basis .

The op=rsbility of an individual control red is based on a corhkination of factors, primarily, the scram nsertion times, the control rod coupling integrity, and the ability to determine the control rod position, Accumulator operability is addressed by LCO S.1.3-5. The associated'scram accuTmulator status for a control rod only affects the scram inserhion times i-there-fore, an inoperable accumulator does not immadiately require declaring a. control rod inope-rable. A.lthouh not all control rods are required to be operable to

, satiefv tha intended reactivrity control requirements, control over the number of inoperable control r6ýds is required;

.Control roid.ins-rtion capability is demonestrated by sner-eillence 4.1.3.1.2 insexting ec13 ily or fully -withdraui -'control rod at least one notch and observingý that the-control rod moves. The control rod may th*n be. returned to stukandi reeo insert o2 xa ne wit this ontf ane-m lvsn perfo'eu -;-W`ideWER min a-tims -Amt as y a be- a EEC ,ýWbar diat-ed tat- ~

inO a: 3 I pen d- is le, a - a rods /wbnmove re w *1.LE ontr'ol rod drive uiecluaiim, =- dat'-tu~ativn zt that contzrol :rod'a trippability .Opef-ability) must be ma*de and appropriate act-ions taken. Ats an aenwple, if the control rod can be scramaed, but can not be moved due to a -ICS. failure, the rod (s) m.a continue to be consid-ered OP*ERBLB provided all other related surveillances are au-rrnt.

Damage within the control red drive mechanism could be a generic probl-m, therefore with a withdrawn control rod ibmm-able because of excessi-výe frictionx or amechzical interferenxce, operation of the reactor is limited 'to a time period

-which is reas.onable to deternine tha "cause of the inoperabill-t and at the same time prevent operation with a large numbar of inoperable control rods.

Con:trol rode that a-re inoperable for other reasons are pe-rmitted to be takel out of se=rvice provided that those in the nonfully--inse*t-ed position are consistent with the SHUOUNT BM-.I-I'T requirements, The number of control rods permitted to be_ inoperable could be_ more 'than the eight allowed by the specification, but the occurrence of eight inoperable.

rods could be indicative of 2 generic problem and the reactor must be shutdo-n for investigation and resolution of the problem.

C TSTEF CLIIP-4-5. Re-v-.l. Federal Recrister Note 72FR63PSS. dat-d Nov-ember 13, 2007, HOPE CP-F.NB B 3/4 1-2 Pm=endmant No.

Page I of 1

2Te scramdischtq volum is reuie to e1M5-ý hti ilb av~ailable, when neeMcd to accept. dichlrge, we from the'wonrit xcis during a ecor scranc an will inalt th e reacitor ccoolant system fro~m the containe Control rodsi with Gnopeyabie accumulators~ are de'1'c-Jy inoperablea SpeciicatiACTM1 týer1 applaes. This prevents Yvattern 4 of itnaerbl batWWld esul. in QQaa reat ivily cinert. on on a scram, than *as beevanayzed. ThRXOP"t. 'ABILA Tca oftecnrl ccmltki requi~red to ensrea'th~at ~a-ns1ertioni ciapabilit! exisats when need~ed ov~er the en~tire rangA- of. roei torypreksuzeS The OPE-RABIL17Y of the scrami accuulatrs i b.ased cr ma~N thyangia e-euate acI'mý;.1tor prehsure.ý O I~ ar\nd;',2, the scram r'otl cis require f'or pit t~gaticni no l n tranhon~~ts. And therefore the~ '-craMrcumulators mrist hieOPERABLE td ppor 0 ne

sr, fun"ction. lnIOPCOF 3 and 4, lonrol reds arl only all cv. C to w~itwah"'awn.

unswi limits iyosed, by the reactor maode swit :h be~'q in~ shut~own an'- -he

ý-znzcl odil bcn- ypI~el. This pivicen 4dyatn-tqutrecrents for cahtzcA rod scra aw=A-rii .r PERA32LITY durin theze 'cantoir~. In OPCON S.

withdawn ~control -z-4s art' nquired to have C ~~acc.1rnlators The actions of Specification .1.5 are modified by a note indicating that as~eprat Yonvdition entr isal.low~ed fro eac conto rod -scrami accuuatr is~ acetal This sinc Mh required Actions fir e~ach Condition provide-approoriate -ompensator action-s for eac-h affec-ted Accumulator. Complyinig with 1

t-he V'qvired Actions mayi allow for cnntinueci operation an-d subseqent affected, aiccumuliators governed by subsequent Condition entry anid applicaction of qssoiate Reuiretd Actions. srt prsu( ? tMpig, ýdqý-tat pressure mus~t be esipplie'd to the chatýqici water ThiOiE CREEK S 3/4 1-2a Amntcn:n No-

restoring compliance with BPWS or restoring the control rods to OPERABLE status, an evaluation of the postulated CRDA may be performed to verify that the maximum incremerital rod worth of an assumed dropped control rod would not result in exceeding the CRDA design irnit of 280 caligm fuel enthalpy and would not result in unacceptable dose consequences due to the number of fuel rods, exceeding 170 calfgm fuel enihalpy as described in the UFSAR. The allowed Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is acceptable, considering the lo-w probability ofta CRDA occurring.

In.addition to the separation requirements for.inoperable control rods, an assumption in the CRDA analysis is that no more than three inoperable control rodsare allowed in any one BPWS group. Therefore, with one or more BPWS groups having four or more inoperable control rods, the control rods must be ,restored to OPERABLE status. LCO 3.1.3.1,d is modified by a Note indicating that the Condition: is nbt applicable when THERMAL POWER is > 8,6% RTP since the BPWS is not required to be followed under these conditions, as described in the Basesfor LCO 3.1,.4. The allowedComplelion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is acceptable, considering the low probability of a CRDA occurring.

Insert 2 Verifying that the scrarm time for each control rod to nofch position 05 is s 7 seconds (SR 4;1,3.2).provides.reasnable assurance that the control rod will insert when required during a DBA Or transiren*th i4bb completing its'shutdown function. This SR it performed in conjunction witlhithe control ft isram.time testing of SR 411.33, The, scram times'specifid :in Table 3,1,33-1 (in the:;acco ipahying LCO) are'.required to ensure that the scram reactivity assumed in the Design Basis Accident (DBA),and transient anaflysis is met (Ref. 2). To account for single faitures and "slow" scramming controlrods, the scram times specified in Table 3.1.33-1 are faster-than thoseassumed inwthe designbasis analysis. The scram times have:a margin that: allows up to approximately 7% of the control rods (eqg., 185 x 7% = 13) to have scram times exceeding the specified limits (i.e., "slow" control rods) assuming a single stuck control rod (as allowed by LCO 3.1.311. "Control Rod OPERABILITY") and an additional control rod failing to scram per the'singlo faiiore'criterion* The scram times are specified as a function of reactor steam dome-pressure to account for the pressure dependence of thie scram times. The scram timeS~are specified relative to measurements based on reed switch positions, which provide the control rod position indication. The-reed switch closes

("pickup") when the index tube passes.aspecific location and then opens ("dropout") as the index tubeptravels upward, Verification of the specified scram times in Table 3,1.3.3-1 is accomplished through measurement of the "dropout" times. To ensure that local scram reactivity rates are maintained within acceptable limits, no more than two of the allowed "slow" control rods may occupy adjacent locations.

Table 3.1.3,3-1 is modified by two Notes which state that control rods with scram times not within the limits of !he Tab!e are considered "slow" and that control rods with scram times > 7 seconds are considered inoperable as required by SR 4,1.3.2.

This LCO (3.1.3.3) applies only to OPERABLE control rods since inoperable control rods will be inserted and disarmed (LCO 3.1,3.1). Slow scramming control rods may be conservatively declared inoperable and not accounted for as "slow" control rods.

I~~~ 2- IA il-~ .-O 06/jc Maximum scram insertion times occur at a re-actor steam dome pressure of appPaximately 800 psig because of the competing effects of reactor steam dome pressure and stored accumulator.

energy. Therefore, demonstration of adequate scram times at reactor steam dome pressure >

800 psig ensures that the measured scram times will be within the specified limits at higher pressures, Limits are specified as a function of reactor pressure to account for the sensitivity of the scram insertion timeswith pressure and to allow a range of pressures over which scram time testing can be performed. To ensure that.scramn time testing is performed within a reasonable lime following a shutdown 1120 days or longer, control rods are required to be tested before exceeding 40% RTP following the shutdownr This Frequency is acceptable cons~idering the additional surveillances performed for control rod OPERABILITY, the frequent verification of adequate accumulator pressure, and the required testing Of control rods affected byfuel movement within the associated core cel and by work on control rods or the CRD System.

Additional testing of a sample of control rods is required to verify the continued performance of the scram function during the cycle, A repriesentative'sample contains at least, 10% of the c-ontrol rods. The sample remains representative if no more than,7'5% of the control rods in the sample tested are determined to be "slow." With more than 775% of the sample declared to be slow' pr the criteria in Table 3,1,3,3-1, additional control rods are tested until this-7;5%

'crition,(e~g., 7.5% of the entire sample size) is satisfied, or until the total number 6f"slow.

.c~ntfol-rods (throughout the core,`frorn all surveillances):exceeds the LCO limit. For planned tesoorg"the control rods selected for the sample should be different for each test. Data from.

inadverterit~scrams should be used whenever `possible to avoid uiinecessary testin *

eef~the con~trol rods with data may have beent reviously testeinasn e Th 200ý.d y roency ased noer ting ex, rieCnce at has own trol rod drambI esdo t.

When work that could affect the scram insertion time is performed on a control rod or the. CRD System, testing must be done to demonstrate that each affected contirol rod retains adequate scram performance over the range of applicable reactor pressures from zero to the maximum permissible pressure. The scram testing must be performed once before declaring the control rod OPERABLE. The required scram time ltesting.must demonstrate the affected control rod is still within acceptable limits. The limits for reactor pressures <800 psig are established based on a high probability of meeting the acceptance criteria at reactor pressures Z 800 psig. Limits for 800 psig are found in Table 3.1.33-1, If testing demonstrates the affected control rod does not meet these limits, but is within the 7-second limit of Table 3.1.3.3-1 Note 2, the control rod can be declared OPERABLE and "slow."

Specific'examples of worX that could affect the scram times are (but are not limited to) the following: removal of any CRD for maintenance or modification; replacement of a control rod; and maintenance or modification of a scram solenoid pilot valve, scram valve, accumulator, isolation valve or check valve in the piping required for scram.

The Frequency of onzc prior to declaring the affected control rod OPERABLE is acceptable because of the capability to test the control rod over a range of operating conditions and the more frequent surveillances on other aspects of control rod OPERABILITY,

REACTIVIT? CON.TROL. ?STFMS, CONTR~OL ROL'S (Cacmlnud beone inoperable, 4-ntio

a. Potential degradation w' tho sram petozace. Theri'frc, .wi-hin' 20 mLnuto,, fron isc'eyof chargi'-ig wae heý-de: p re5je < 940 psiq cor7,,-z-,te.t -,,ith o .i in Actio-I 3-1. 3.5.a.2, adquate cnrg- witer 'e-ader ie~s~e mu t be restore:ý- 7ia all owi-Ccnnleti-,. T`Tae of 20 im'-;u is re.asonable, 'IO.Piace- a CCRDP=- irPtQ service to 4,ctore the chrqna ý h ead~er pfes5ure, if q I-rd'. This Com-pletion' Tim is bas'ed on th ~yOf t.o. ýector pzesso.re' alovne to fi-ztty i all control Wi th oreý o - moreonto rod scrr ccclula ozs inoperable anad the reactor LA2 ~es ~0 ~ trep.~e~<4' tho h ji water hea:!ýr must be 4 ~'~~~rt so'e c ~d o~s ce r a id.ith the prcoxoessure

< u0 d5~ the -~ozdn c'.v iiO n - eja,~s cra m fD rc e r.c're~'-' Cuc~o ~ pratcnetŽ~~ Crod become deraded auOi r etra o co esie The'orefe coctrrw 4ith in A~ o31,3Jt o'ol'daaoitd s Con~trol rods Wi~*h c ~~ il r ~o~sui ~~ e~

pesure conditions. a~ob `V~at~~ca do clare inopecrabl(o acd dl ,ý;rntdwit-hinI 'I hur 'Te llbowad crmpleziooiYce IOU -In r~asbl con- rI-

-- "~he o6wprbol oý DB ori -trnip-'l!

occrring durfv ,'io ta the. atcuiruL,.-,:r -s inoperable.

1he 'reactor moi wia u,%t be ŽvI.CO01a in 7!ta .6hu'duf 'w PO'itiocl-if ither e'd aooed o ol~o ize ~a~ociao"' with loss 'of blnet;' This entze

. tI 'tall -ýet~able control rods aaze --n,ýrted and th.ý h

'eactor Si r conr ta n, t r-t'doe s no -e i ' re he a ct -',,e f uan c~c e . ,srm o-4te cont.rol rods.Ti R"ea-`tred*- joer is rrodjficd by a note stating that the action is inot appicable if all cor't~-r rod associated with the incperablt scram aueum:0a0t Ae , .nscrted sinc~e 'h lr,ýtlon of the ';ýOicrol zods has beot%percrmed. j Surveillanc equirement 1 .35 requires that th acc;n~ulator pra!saura be Check.ed e ~ a o ensuer adeqvate acL lxulator preasure exists to pro-,,ide s

suffti.cren sram force, The primary indicator of actu-sumaLct OPERAMiLITY is the

~atcIU'aor 'ax.esuP A munimum accurouiatot o)reure Is, specified, below which the tapahility of the~ zccumu'ior to perfov-, iis intended fl-r'ct-on bcories deraded and the acu-mulpto- is.oaiae inoperable. Decie'rnq the acumulator inoper&abl whan them miininaUt- pressure is t I5Ffl ma n i t* I; Coit-rol ecu Covoling inte~rity is retuired to ensure covspiiance with the analysis of' the rod drop accident in. the ý'SAk. The ovettrat-el position HOPE CREEK R 2/4 1-2b ~0PEC.~tK 53/4-tbAmecndmsent No. )4&-

REACTIVITY CONTROL SYSTEMS BASES CONTROL RODS (Continued) feature provides the only positive means of determining that a rod is properly coupled and therefore this check must be performed prior to achieving criticality after completing CORE ALTERATIONS that could have affected the control rod coupling integrity. The subsequent check is performed as a backup to the initial demonstration.

In order to ensure that the control rod patterns can be followed and therefore that other parameters are within their limits, the control rod position indication system must be OPERABLE.

The control rod housing support restricts the outward movement of a control rod to less than 6 inches in the event of a housing failurer. The..-- , -...

amount of rod reactivity which could be added by this small amount of rod withdrawal is less than a normal withdrawal increment and will not contribute to any damage to the primary coolant system. The support is not required when there is no pressure to act as a driving force to rapidly eject a drive housing.

s; a tl~nc5 LE OPE itr I/*not 3so7requent./as s to arS2 c sewer te yse 0mpo n,'"

1-70PE CREEK B 3/4 1-2c CcAmendmer.: No. 98

REACTIVITY CONTROL SYSTEMS BASES 3/4.1.5 STANDBY LIQUID CONTROL SYSTEM The standby liquid control system provides a backup capability for bringing the reactor from full power to a cold, Xenon-free shutdown, assuming that the withdrawn control rods remain fixed in the rated power pattern.. To meet this objective it is nedessary to inject a quantity of boron which produces a concen-tration of 660 ppm in the reactor core and other piping systems connected to the reactor vessel. To allow for potential leakage and imperfect mixing, this con-centration is increased by 25%. The generic design basis of the standby liquid control system provides a specified cold shutdown boron concentration in the reactor core. The standby liquid control system was typically designed to in-ject the cold shutdown boron concentration in 90 to 120 minutes. The time re-quirement was selected to override the reactivity insertion rate due to cool down following the xenon poison peak. The pumping rate of 41.2 gpm meets the requirement.

The minimum storage volume of the solution is established to include the generic shutdown requirement and to allow for the portion below. the pump.suction nozzle that cannot 15e inserted. An additional allowance in the standby liquid control storage volume is provided to account for storage tank instrument inac-curacy and drift. Even with the maximum specified instrument :inaccuracy and drift, the required quantity of sodium pentaborate solution is- always available fo-iijection.

-A normal quantity of 4640 gallons of sadium pentaborate solution ,having

a. 14.0 percent concentration is required to meet* the shutdown requirements.

The temperature requirement for sodium pentaborate solution and the pump suc-tion piping is necessary to ensure -the sodium pentaborate remains in solution.

With redundant ;pumps and explosive injection valves and with a highly reliable control iod scram system, operation'of the reactor is permitted to continue for short periods of time with the system inoperable or for longer periods of time with one of the redundant components inoperable.

Surveillance requirements are established on a frequency that assures a high reliability of the system. Once the solution is established, boron con-centration will not vary unless more boron or water is added, -thus a check on the temperature and volume u e4 uassures that the solution is available for use.

Replacement of the explosive charges in the valves will assure that these valves will not fail because or deoeribration o the charges.

The ATWS Rule (10 CPR 50.62) requires the addition-of a new design require-ment to the generic standby liquid control system design basis. Changes to flow HOPE CREEK B 3/4 1-4 Amendment No. 11

3/4.3 INSTRUMENTATION BASES 3/4.3.1 REACTOR PROTECTION SYSTEM INSTRUMENTATION The reactor protection system autbmatically initiates a reactor scram to:

a. Preserve the integrity of the fuel cladding.

b. Preserve the integrity of the reactor coolant system.

c. Minimize the energy which must be adsorbed following a loss-of-coolant accident, and

d. Prevent inadvertent criticality.

This sp -cification provides the limiting conditions for operation necessary to preserve the ability of the system to perform its intended function even -during periods when instrument channels may be out of' servae because of maintenance. When necessary, one -channel may be made inoperable for brief intervals to conduct required surveillance.

The reactor protection system is made up of two independent trip systems. There are usually, four channels to monitor each parameter With two channels in each trip system. The loutputs of the channels in a trip system are combined in a logic so that e'ither channel will trip that trip system.

The, trijping of both. trip systems will produce a reactor scram. The system jNSV- e h~f IEEE-279 for nucder power plant. protection. systems.

Arvillance and maintenance outage :,

t mns have ,bean determieaX accordance with NEDC-30851P, "Technical specification Improveinert Analyses for BWR.ReactorProtection System,. as approved by.t-e NRC and documented in theSER (letter to T. A. *Pickens from A. Thadani 'dated July,15 ., 1987). The .bases for the trip settings of the RPS are discussed in the base's' for Specif ication 2.2. 1. _-.;- ....

The measurement of responsetie provides assurance that the protective functions as. -- a-ed-wth eah athainel are comL pleted within the time limit assumed in the safety analyses. No credit was taken for those channels with response times indicated as not applicable.

Response time may be demonstrated by any series of sequential, overlapping or total channel test measurement, provided-such -tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either (1) inplace, onsite or offsite test measurements, or (2) utilizing replacement sensors with certified response times. -Selected sensor response time testing requirements were -eliminated based upon RXEDO-32291, 4System Analyses for Elimination of Selected Response Time Testing Requirements," as approved by the NRC. and documented in the SER (letter to R.A. Pinelli from Bruce A. Boger, dated December 26, 1994). The Reactor Protection System Response Times' are located in UFSAR Table 7.2-3.

As noted, the SR for the APRM Neutron Flux - Upscale, Setdown channel functional test is not required to be performed when entering OPERATIONAL CONDITION 2 from OPERATIONAL CONDITION 1, since testing of the OPERATIONAL CONDITION 2 required APRM Function cannot be performed in OPERAT1ONAL 'j.- ..

CONDITION I without utilizing Jumpers, lifted lear- or movable links. This allows entry into OPERATIONAL CONDITION 2 if th4- zreqeniy is not met per SR 4.0.2. In this event, the SR must be per-hin 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after"'

' entering OPERATIONAL CONDITION 2 from OPERATIONAL CONDITION 1. Twelve-hourn O* is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

HOPE CREEK B 3/4 3-1 Amendment No. 153

IN'STRUHENTATI QN BASES 2/4.3.2 ISOLATION ACTUATION 1NzTRUJMENTATLON ACT ...... .conzrnnued.

inoperab-Ie cnannel in trip would conservazively compernsate for the inopen* r*i*-l , restore capability to accormodaze a single failure, and allow operation to continue with no further reszrictions. Alternately, if it j.s not desired to place the channel in :rip (e.g., as in the case where placinr the inoperable channel in trio_ would result in an isCation), the Action rez'cred by Table 3.3.2-2 mus: be taken.

If there are no OPERABLE channels for a trip function in ore r-ip syszen, and the inoperable channels cannot be restored 7o OPERABLE status within..o.ehour, the inoperable channels must be placed in the tripped condition oer Action 3.3.2.b. Ia. A-lternately- if It is hbt de s t a c-1.

.he channels in :rip, the Action required by Table 3.3.2-1 must be taken.

Footnoze ;e) to Table 3.3.-2-2 modifies the mirinium OPERABLE channels per tri4 function requirement to state that sensors are arranged pei valve grzup, not per trip system. Where'the trip function-actua:es a single valve group,. Action 3.3.2.b applies for 'all cases in which .,ess than the minimum req-uired number of channels are OPERABLE. .For tip functions annotated by footnote (e), Action 3.3.2.b.l.a applids when neia*her' isolation logic *

(inboard or outboard) meets the minimum OPEMABLE'channels requirement.

-or trip functions -c., 2.c and 2.d, a miminum ouofthree QPEPRABLE i'shane

_shnn p pere rip system are required.

,re For these trio functions, three radiat*on monoI t ng channels input to four two-out-of-three PCIS initiatio<'!

logical'{ When one -. FE-RPS or one RBE-R'MS channel is inoperable, Action 3.3. 2b. .c applies. When more than one RFE-RRMS or more than one RBE-RMS channel is inoperable, Action 3.3.2.b.l.a applies because a sufficient nurber of inputs would ýot be available to satisfy the actuation logic for any PCIS channael.

SURVE7LLANCE REQUTREMENTS S i d Sur -l nce in erval and urveillance and maintenance

cf ou~a~11 _ a ve veen determined in'a ccorcance with References 5 and 6.

When necessary, one channel may be inoperable for brief intervals to.

conduct required surveillance. Some of the trip settings may have tolerances explicizly stated where both the high and low values are critical and may nave a substantial effect on safety. The setpoints of other instrumentation, where only the high or low end of the setting have a direct bearing on safety, are established at a level away from the normal operating range to prevent inadvertent actuation of the systems involved.

Except for the MSIVs, the safety analysis does not, address individual

'sensor response tiimes or the response times of -he logic svstems to which the senscrs are connected. Selected sensor response time zest_`g nqu_. _~me..ts v;ere eiinaced based upon eferen-ce 7, NED"- 3 2 , "Ssem

'29 -Lra ves e -r E ntion of Response Timr' '*e Ts * ....

-s= a.*nd dico cuete n- :-he S E ,f I-te to F..

ine II fr OM B -Z'* .

. Tiesare s in i SR TatLs 7. -6.

'-'"-* Creek9 B3/4~ l-2 Z-e~~nt"] ~

sE e ISu

IIqSTRU:'/ENTAT i O BAE 314 .3.2 ISOLATION ACTUATION !NSTRUVJENTATION REFERENCES

1. UFSAR, Section 6.3.

2. OFSAR, Chapter 15.

3. NFDC-31466, "Technical Specification Screening Criteria Aoolicatior: and Risk Assessment," November 1987.

L 'SAR, Sec ion 15.7.4.

ME C ý,DC-6

.F-A, "Technical Specification imr)'ovement Analysis for BWR Isolation Actuation Instrumentation," as approved by the NRC arnd&

documeinted in-the. SER. (lettert.o.,SD. Floyd.from. C.E. Rossi dated rune18, 1990).

6. N7DC-30951P-A Supplement 2, "Technical Specifications lmprov*rrinrit Analysis for BWIR Isolation Instrumentation Common to RPS and ;427.CS Instrumentation," as approved by the !,RC1and documenr.od in -.he SES

{lette- to D.N. Grace fro' C.EL Rossi dated January 6, 199).

N-1 O 0'29] System na or E.im-nation 6f Seeczed Resp rs- *'.

-als-e, Tesz-n3 Require *as ents approved by the NRCOrand documented n- .

,.z!e.er to R A. Pinelfi from Bruce AX Boger, dated December 28, O949, 3/'4 ... ',ERGENCY CORE COOLING SYSTEM ACTUATION -NhSTRUMENTAT1/2N -

The emnergerncy core cool-ig system actuation instrumentation is c--r cyided to initiate actions to mitigate the consequences o.f accidents Uhat are,bervond the ability of the operazor to control. This specification provides the OPERABILITY requirements, trip setpoints and response time.s that will ens-re effectiveness of the systems to provide the design protection. ECC, s actuation instrumentation is eliminated from response time tes-ing reout-reinents based on NEDO-32292, "System Analyses for Elimination of Selected Response Time Testing Requirements," as approved by the N1,C ,,-

documenzed in the SER (letter to R.A. Pinelli from Bruce A. Boger, dat'u December 28, 1994). The Emergency Core Coolingose Times ere located in U:SSAR Table 7.3-27.

ifdsur/eill

1 nce i ervaA d urvei+/-lance and maintenanc:u outage imes nave been oefermlneo in accordance with NEDC-30936P-A, "BWR Owners' Group Technical Specification Improvement Methodology (With Demonstration for BWR ECCS Actuation Instrumentation)," Parts 1 and 2. The safety evaluation reports documenting NRC approval of NEDC-30936P-A are contained in letters to D. N. Grace from A. C. Thadani (Part 2) and C. E.

Rossi [Part 2),dated December 9, 1988. Although the instruments are listed by system, in some cases the same instrument may be used to send the actuation signal to more than one system at the same time.

Operation with a triop set less conservative than its Trip Setpoint but within its soecified Allowable Value is acceptable on the basis that tl-a difference between each Trir, Setpo~in t ynd the Allow,'able Value is ;n a]

for instrument drift snoci ~raP.ly a!locaed for eoth trio .:..n the sarnetv analyses.

Hope Creek P.3/4 3-2r AmendFment 1,wo. IrI (PSEC Issued)

INSTRUMENTATION BASES 3/4.3.4 RECIRCULATION PUMP TRIP ACTUATION INSTRUMENTATION The anticipated transient without scram (ATWS) recirculation pump trip system provides a means of limiting the consequences of the unlikely occurrence of a failure to scram during an anticipated transient. The response of the plant to this postulated event falls within the envelope of study events in General Electric Company Topical Report NEDO-10349, dated March 1971, NEDO-24222, dated December 1979, and Section 15.8 of the FSAR.

The end-of-cycle recirculation pump trip (EOC-RPT) system is an essential safety supplement to the reactor trip. The purpose of the EOC-RPT is to recover the loss of thermal margin which occurs at the end-of-cycle.

The physical phenomenon involved is that the void reactivity feedback due: to.

a pressurization transient can add positive reactivity to the reactor system at a faster rate than the control rods add negative scram reactivity. Each EOC-RPT system trips both recirculation pumps, reducing coolant. flow in order to reduce the void collapse in the core during two of the most limiting pressurization events'. The two events for which the EOC-RPT protective features: will function are closure of the turbine stop valves and fast closure

.of the.turbine control valves.

'-fast closure sensor.from each of two turbine control valves provides ',

inou t t4 the EOC-,RPT system; a fast, closure sehsor from each of the .ther two turbine control valves provides input to the second EOC-RPT system.,

Similarly, a position switch for eih4 of two turbine st'p]valves provides 1

input to one EOC-RPT system; a position switch from each'-f the other two stop valves provides input to the other EOC-RPT' system. For each EOC-RPT system, the sensor 'relay contacts arew arrangedato form a 2-out-of-2 logic for the fast closure of turbine control valves and a 2-out-of-2 logic for the turbine stop valves. The operation of either logic will actuate the EOC-RPT system and trip both recirculation pumps.

Each EOC-RPT system may be manually bypassed by use of a keyswitch which (I is administratively controlled. The manual bypasses and the automatic Operating Bypass at less than 24% of RATED THERMAL POWER are annunciated in the control room.

Ui The EOC-RPT system response time is the time assumed in the analysis VJ) between initiation of valve motion and complete suppression of the electric

- arc, i.e., 175 ms. Included in this time are: the response time of the sensor, the time allotted for breaker arc suppression (135 ms @ 100% RTP),

and the response time of the system logic, S cif/ed s vei ance ' te als nd)urveillance and maintenance outage times have been eermined in accordance with GENE-770-06-l-A, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," December 19.92.... ,

Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses.

HOPE CREEK B 3/4 3-3 Amendment No. 174 (PSEG Issued)

INSTRUMENTAT ION i~as~ ~-FZ BASES 3/4.3.5 REACTOR CORE ISOLATION/COOL,*NG SYSTEM ACTUATION INSTRUMMNTATION The reactor core isola ion cooling system actuation instrumentation is provided to initiate action o assure adequate core cooling in the event of reactor isolation from rimar heat sink and the loss oJ feedwater flow to the reactor vessel. Sp if d s rvei ana -nt val a Arveillance and maintenance outage t mes ave been determ ao or ande with NEDC-309361-A, "BWR Owners' Group Technical Specification Improvement Methodology (with Demonstration for BWR ECCS Actuation Instrumentation),," Parts 1 and 2 and GENE-770-06-2-A. "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications." The safety evaluation reports documenting NRC approval of NEDC-30936P-A and GENE-770-06-2-A are contained in letters to D.

N. Grace..from.A*. ... Thadani...ted December 9, 1988 (Part 1), D. N.-Grace.to C,

u. Rossi dated December 9, i988 (Part 2), and G. J. Beck from C. E. Rossi dated September 13, 1991.

Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value.is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance t fo" instrument drift 6pecifically allocated for each trip in the safety analyses.

3/4.3 .6 .CONTROL ROD BLOCK INSTRUMENTATION' Tbk control rod block functions are provided consistent with the requirements of the specifications in Section'_3/4:4, Control Rod Program Controls and Section 3/4.2 Power Distribution,ZLimitSd and Section 3/4.3 Instrumentation. The trip logic is: arranged so that' a trip in- any one of the inputs will result in a control rod block.

Operation with a trip set less conservative than its Trip Setpoint but within its specified Allowable Value is acceptable on the basis that the difference between each Trip Setpoint and the Allowable Value is an allowance for instrument drift specifically allocated for each trip in the safety analyses.

As noted, the SR for the Reactor Mode Switch Shutdown Position functional test is not required to be performed until I hour after the reactor mode switch is in the shutdown position, since testing of this interlock with the reactor mode switch in any other position cannot be performed without using Jumpers, lifted leads, or blinks. This allows entry into OPERATIONAL CONDITIONS 3 and 4 if the 4 po0 jfrequency is not met per SR 4.0.2. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months allowance is based on ope ng experience and in consideration of providing a reasonable time in which to complete the SR.

3/4.3.7 MONITORING INSTRUMENTATION 3...

.37*. .J RADIATION -MONITORING INSTRUMENTATION The OPERABILITY of the radiation monitoring instrumentation ensures that, (l) the radiation levels are continually measured in the areas served by the individual. channels, and (2) the alarm or automatic action is initiated when the radiation level trip setpoint is exceeded; and (3) sufficient information is available on selected plant parameters to monitor and assess these variables following an accident. This capability is consistent with 10 CFR Part 50, Appendix A, General DeSign Criteria .19, 41, 60, 61, 63 and 64.

HOPE CREEK B 3/4 3-4 Amendment No.153

INSTRUMENTATION BASES 3/4.3.10 1MECHANICAL VACUUM PUMP TRIP INSTRUMENTATION (continued)

The allowed completion time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach OPERATIONAL CONDITION 3-from full power conditions, or to remove the mechanical vacuum pump(s) from service, or to isolate the main, steam lines, in an orderly manner -and without challenging plant systems.

ACTION c.

ACTION c. allows that when a channel is placed -in an inoperable Status solely for performance iof required .Surveillances, .-entry -into :.the associated ACTIONs may. be de#yed :fOr up to 6. hour-s.-provided .mechanical vacuum pump .. rip.

capabili.y is maintained. Upon :completion .of t-he Surveillance, or expiration of the 6. hour allowance, the channel must 'be -returned rto OPERABLE.-statUs or.

the required ACTIONs taken.-. .This 'aliowance is: -based on-the reliability analysis :.(Ref.. 2). assumption of the average .time required to performchannel Surveillance... That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing ailowance .

does not. significantly reduce the probability that.ý the mechanical vacuum pump, will trip when necessary.

Surveillance Requirement 4.3.10.a /S 1: .

AgM6 Performance of the CHAMNL CHE ce, ye I. ho rs urea, that a gross failure, of. insrtrumentation hasenot occurre, 'A C HEL CHECK, is,'

normally a comparison "o cfr the 'parameiter -indicated on one channel to a similar parameter. on-other channels. - It is based ýon -th-assumption that instrument channels monitoring the. ..same panAmeter should"read 'approximately the 'same value. Significant ,deviations.between the:instrument channels could be an indication of excessive instrument drift in one-of the 'channels or something even more -serious.. :A ,CHANNEL.CHECK will .detect-,gross 'channel failure; thus, it is key to verifying 'the instrumentation :continues to -operate properly between 'each CHANNEL CALIBRATION.

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

canne fa ure .fs :r e. 1Ee. CHANNEL :CHECK supplements "less"-formal, more 4e0

-- , Aced o nanels during normal operational use of the displays associated with the required channels of this LC0.

Surveillance Requirement 4.3.10.b A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. Any setpoint adjustment ýshall -be conisstent -wIth the'assumptions of the current -plant<'

specific setpoint methodology.

HOPE CREEK B 3/4 3-11 Amendment No. 143

INSTRUMENTATION BASES I

3/4.3 .10 MECHANICAL VACUUM PUMP TRIP INSTRUMENTATION (continued)

Surveillarce Requirement 4.3.1.0.c A CHANNEL CALIBRATION is a. complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific se"no.nt 4F...e!yrs.osea iv i-thi ~esp t-e-.-

ý" t ons o1a clf ibra ion in nrvkln yt*hdte at on othe o gnit e survel2ilance, norimal background As the dose level experienced at 1.00 rated thermal power with hydrogen water chemistry at the maximum injection'rate.

The trip setpoint for the Main Ste= Line Radiation - High, High trip function ,and requirements for setpoint adjustment are .,pecified in Technical Specification*3.3.2.

surveillance .Requirement 4.3.10.d The LOGIC SYSTEM FUNCTIONAL TEST adlonmtrates the OPERABILITY of the required trip*logic for a specific channel. The'systemn:functional test of the mechanical vacuum pump breaker is,.icie asNpArt of this Surveillance an~d overlaps the LOGIC- SYSTEM. FUNCTIONAL TEST to provide complete testing of the assumed.safety function.,. Therefore,'jif the breaker is incapable of operati-g, the associated instrument, channel(s) would be inoperable.

REFERENCES

1. UFSAR, Section 15.4.9.5.1.2

2. NEDC-30851P-A, Supplement 2, "Technical Specification Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989 HOPE.CREEK B 3/,4 3-12 Amendment No. 143

1.7 INSTRU1th¶SAT IONJ 3i4.3ll OcilitionPowefr AanqC PMO~itit (OP)4 SURV~jACB QtfRSM4NTSý k$R4 3.11.1 A CHANL cn~tirý PUNCTIONAL TESTwilli ig pserfored on each reoquired c'ahe e to'en thhlit-he cbi:uiel ar Qom th- .iute~dedluf~ti*k ,A preý&n**

CY * ...',bi ,, i .of,,,*i e, ,el e .:. \

LpjPI4 gain E)&atijge' ar6 aeter-mineld fzr te osif p~roffies, ýneasured by te eraveraing !coinr alPsy*tem. Probe Ti .Otallisesthe aelative

-- cal- .flu ,*rPfilin g ' oo nate--er i to the ýORPRM2 iSyst-*'t aet~i7 Y Cha A.

esm -0. vilaci nacr~c waife it.h Mote The CXA)(PiM CA11MTTON Is a coolet~e chack of the in.Otr~u op '

'te , . enxl reresne to 'theaneaea roede.a n ecessary r,"ange aInd accuri !iecy -AWU Ierl.,ICALIMf TkIlo .e ,eth . chaTnel.

adjustae to ,ac ,count or intrmset drifts bewe-ueniv airto coniiaistent: With thi plant i spe,cific aet , iint ethodolo1gy; Cabatonofte h~ne poides il"checkto h n~ra eeec voltage ante internal: procepsopr cckqury.It aso comairedh C'>

trp et ntao jýIth thsea in pncoo eor.Snetki PNi di ital,

,system, the internal reference Vol ,tage .anti proceassor lock; frequezcy a~re, in turn_ Used toatiaia~ a rtbeth inii~xuil ainalog tio digital con~rtes. he AlowbleValuesare-apecified in the CbRB~OPA~Aln4GLMlTS RE~POR'T.

As. no ted, neutron detaectora are e-rluded f ~rom, CK U,. C AR*TTO*,4,-bcuse of the difficulty ofamltn amadgu ignalý. Chaiiges nq41cetron detector sensitivity are ;ompenvatcd for: by' perforting therl0/ HLPRM4 calibration us8ing, the Tt~a ORD 'C!.1.`l2)-

rye F~ei cA1 fon t~ta KmA bae thesý ,dag ctiv,7 thtW kpera e over a.co=p1 tecylaacýw Ah ut o ir xq Thýe: LOGIC SYSTS*M ?VWTI04)TL TXST deisont,riteft the 6OPBRABILItY Of tim tequired trp loi or, a specific channel. The fciolteigofotrol rd and ecram diachatrge itolume '(8Dvi 4ent and drain, 'Valves in spescificatilon 3.3l~~ontlRod oipm=ILr overlapsethis Surveillance to-ýprovide: .

amo~leteeteatlng o the easmumed safety function. 'The OM.? self-teat function

.ay'be.utfli'ed' to pe 'tform thina testing f~i~ those Co*,oneintt that it isl deasigned to monitor.

(The E'h '.c mownt Treilla nt V

.0 Opyrat is1 bed oft i '.

xerle e halp tast ha ~vik4ý iwhey perfo.'.d at tý e -19 =ayf Freq 7 ~y ineer 5 judgm amd r Aabiilit of wiitha' %heac: cnonants oually slops CREK B 3/4 3/ 3-16 BKFP-- -6 x*endment N*o.15~9 nnxnn aoi

INSTRUMENTATION EASEPS 3/4.3.11 Oscillation Power Ranae Monitor (OPRM)

SURVEILLANCE REQUIREMENTS (continued)

SR 4.3.11.5 This SR ensures that trips initiated from the OPRM system are not inadvertently bypassed when the capability of the OPRM system to initiate an RPS trip is required. The trip capability of the OPRM system is only required during operation under conditions susceptible to anticipated T-H instability oscillations. The region of anticipated oscillation is defined by THERMAL POWER > 26.1% RTP and recirculation drive flow *<the value corresponding to 60% of rated core flow.

The' trip capability of individual OPRM modules is automatically enabled based on the APRM power and flow signals associated with each OPRM channel during normal operation. These channel specific values 'f APRM power and recirculation drive flow are subject to surveillance requirements associated with other RPS functions such as APRM flux and flow biased simulated thermal power with respect.to the accuracy of. the; signal to the process'variable.

The OPRM is a digital.systiim with calibration and manually initiated tests to verify digital input including inpu'týt6.'ýt'he auto-enable calculations.

Periodic calibration confirmis. that the*-auto-enable function o0ccurs at "appropriate values of APRM?:N'ower and recirculation flow signal. Therefore, ver-ification that OPRM modutles are enabled"at any time that THERMAL POWER >

I%-RTP. -and -rcircul-at-i°on-drive--fi-ow--:- the--va-lue--corresoondi-ng--to -6&%*o-f-...-I-rated;'core, flow adequately ensures that trips initiated from the OPRMsystem are, not' inadvertently bypassed..

The trip capability of individual OPRM modules can also be enabled by placing the module in the non-bypass (Manual Enable) mode. If placed in the non-bypass or Manual Enable mode the trip capability of the module is enabled and hRe . quency o6 8 " *....

SR 4.3.11.6 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis (Ref. 8). The OPRM self-test function may be utilized to perform this testing for those components it is designed to monitor. The RPS RESPONSE TIME acceptance criteria are included in Reference 8. ý As noted, neutron detectors are excluded from RPS RESPONSE TIME test g because the principles of detector operation virtually ensure an instantaneous response time. RPS RESPONSE TIME tests are conducte such-. t , .-

a -hanne ested a east nce ev ry t- es no N is e to al n er of edundan channe s in arspeolfi reactor trip sys e is F quenc is ba ed upon operati g expe ience, hich sho s that m.

ndom ilure of in trument tion co ponent, causin serioustime deadatio , but ot ch. nnel f ilure, re infr quent.

a HOPE CREEK Amendment No. 174 B 3/4 3-17 (PSEG Issued)

3/4.4 REACTOR COOLANT SYSTEM BASES 3/4.4.1 RECIRCULATION SYSTEM (continued) at least once per operating cycle. These relationships should be periodically, trended during an operating cycle to determine if the surveillance needs to be performed more than once in an operating cycle.

Some of the phenomena to consider are: 1) The core flow resistance may decrease during the operating cycle, requiring lower recirculation pump speeds to achieve a given core flow at the end of the operating cycle versus the beginning, 2) Significant changes in fuel design can affect the relationship of recirculation drive flow to jet pump loop flow, 3)

Significant changes in recirculation loop hydraulic characteristics can affect the relationship of recirculation pump speed to recirculation drive**

flow, and 4) Recirculation system instrument calibrations can impact any of the relationships The MG set scoop tube mechanical and electrical settings should account. for the effects of such. phenomena so that the maximum core flow assumed in the establishment of the MCPR and LHGR operating limits is protected.

SAn inoperable jet pump is not in*-`itself a.:sifficient reason to declare a recirculation loop, inoperable, but it'does, ihi c*aseof a design-basis-<

accident, increase the blowdown area and.-reduce the -capability of reflooding the 56re, thusý, the requirement for shdtdown of the facility with a jet pump

.inoperable. Jet pump failure can be detected by xtonitoring jet pump perf mance on, a prescribed;schedule for significant -degradation.

Recircul'ation loop flow mismatch limits are in compliance with the ECCS LOCA analysis design criteria for two recirculation loop operation. The limits will ensure an adequate core flow coastdown from either recirculation loop following a LOCA. In the case where the mismatch limits cannot be maintained' during two loop operation, continued operation is permitted in a single recirculation loop mode.

In order to prevent undue stress on the vessel nozzles and bottom head region, the recirculation loop temperatures shall be within 50'F of each other prior to startup of an idle loop. The loop temperature must also be within 50OF of the reactor pressure vessel coolant temperature to prevent thermal shock to the recirculation pump and recirculation nozzles. Sudden equalization of a temperature difference > 145'F between the reactor vessel bottom head coolant and the coolant in the upper region of the reactor vessel by increasing core flow rate would cause undue stress in the reactor vessel bottom head.

3/4.4.2 SAFETY/RELIEF VALVES The safety valve function of the safety/relief valves operates to prevent the reactor coolant system from being pressurized above the Safety Limit of 1375 psig in accordance with the ASME Code. A total of :13 OPERABLE safety/relief valves is required to limit reactor pressure to within ASME III allowable values for the Worst case transient.

Demstr 'ion the *afety /elief v Iye lift /ettin ocr n (du ing s tdo . Th* safe* reli f valvepltsaeasibis* e p essur* test d in *ccord _ce wih thercoenaena Eeri/

HOPE CREEK B 3/4 4-2 .50.59 4 HC-09-056 (PSEG Issued)

L@R ACTOR COOLANT, SYS TEM-BASES 3/4.4.2 SAFETY/RELIEF VALVES (.continued)

SiL N~o.196, Supplement 14 (Apr11 ý23, 1984): 'Target, Pock 2i.Scage SRV Set7 Point Drift set Dtessure tests of the ;safety, alve iain (mechanical) stage are Conducted ire e yr The low-low set system ensures that safety/re.ief valve dtschargesare miniii'zed fqr a second opening of these, vales, fovlowing any .ovrpressure" transient. Thisisacheved by automatically lowering the closing ,setpoint of two valves and lo*eing the opening. setpoint of two rvalves o6llowing the*

initial opening. In this way, the, freqanYy and magnitud the"contanrent do'f 61owdow-n duty cycle:is substantially reduced. Suffitient redundancy is pr6vided for the. low-low set system such that,*01iure O0 aTny oe valve to, open or close at`its reduced setpoint does no*tviolate the design basis.

3/4.4. 3 REACTOR COOLANT SYSTEM LEAKAGE 3/4 .,4.%3-1 LEAKAGEDSTECCTION SYSTEMS Th6 kRCS:'leagi&gfdetrection systems requlr-d by this specification are :.

provided to,.monitor ald'.detect leakage, from the xreactor coolant pressure 1boutdaryr. Týhese detection saystems 'are consistent winh the 'recowaurndation$ of Requlatory~~d 1.45; "Reactor CoolatPesr BoundaryLeakagee~tectiofl Systems"V,NPay 1973 and G neic Lt t~er 8-1 R~stotnISCi W Austenitic Stainless Steel PipingA..

Proceduratized, manial quantitative monitoring and calculation' of leakage rates, found by the NRC staff, in ^L 8-01; Supp. !, to be An acceptable alternative during repair periods of tp to 30 days, should be demonstrated to have accuracy comparable to the installed drywell floor and equipment drain sump monitoring system'.

314.4.3.2 OPERATIONAL LEAKAGE The allowable leakage rates from the reactor coolant system have been based on the predicted and experimentally observed behavior of cracks In pipes. The normally 'expected background leakage due to aeqipmhnt designand the detection capabilittof the instrý' .... nttionl-for determining system leakage was-also considered. The .evidence obtained frtm experiments suggests that for leakatge .somewhat, greater. than that specified. for UNIDENTIFIED LEAKAGE the probabiliti is small that theimperfection or crack associated with-such leakage would grow rapidly. However, in all cases, if.the leakage' rates exceed the values speclfted or the leakage.is Located and known to be PRESSURE BOUNDARY LEAKAGE, the reactor will be shutdowtto allow further investigation and corrective, action.

The Surveillance ReqUirements for.'RCS pressure isolatio6.'valves provide added assurance of valve .integrity thereby reducing the:probability of gross valve failure and consequent intersystem LOCA. Leakage from the RCS pressure isolation valves is IDENTIFIED LEAKAGE and will be considered as a portion of the allowed limit.

HOPE CRqEK 8 3/4 4-3 50.59 # RC-09-056 (PSEG Issued)

314,. SMROMGCY C(ORE COOLING SYSTM.

BASES e... n. sf...c S. . . . . .. . . .

. . . .*.a VWs ............

U.4-

ýý AL- .a.Z a"b -, yrm *A AT-ILUU229nV%~

The core. spray, systIem (CSS), together with the LPCI mode of the RiR system, .is provided toassu~re~that -the core is adequately. cooled. following a:

losso-co10- ant accident and proviides adequate core cooling capacity. Er all break sizes up to and including the double-'ended reactor recirculation line break, and for smaller breaks followin deprssiztion by the AiDS.

The CSS is a' priaIry sourceof'e*mergexcy ccore co)inilg aftei the reactor vessel is depressuri.ed and &'source for, flooding of the-'corein case. of accidental draining.

The sunveillance requireents provide. adequate assurance that the .css will be: OPERABE when required. Althqugh :all active copobents are testable and fuAll flow, caný be demonstrated by. recirculation ,through a test loop during,

,reactor'. operation, a complete f,zniional tes* requires reactdr shutdown, The pUmp discharge -piping" is maintained full to prevent water.hammer damage to piping: and to 'star~t coo'linig-at thei earliest knoment.

The low pTessure coolant' injfcton (LPCI) mode of the RHO system is.

provided to assure that the core ii adeqately cooled following a loss-of-coolant accident. Pour-sUbsysteins, each:with one pump, provide adequate coreflcodtng for all break sizes up to and including the double-ended ýreacto'r recirculation line break, and" for smaill breaks. following

depressurizat~ion-,b9 the A08.,

surv~ifi~arnc&, requirement poieaequate assurance-`thýEt the LPC'I system will be .OP LE when required. Although all active components are testable "and full flow sh be"demonstrated by ,eciruationi ithorbgh a test loop during reactor operation, a: omplete fEntidnja..test tequire, reactb" 2- shutdoWn. Th*e p np.-udchixg piping. is maintained full to prevent water hkmmer damge to: piping and to, start cooling at the earliest moment.

verification.e ys that each RHRSystem cross tie valve'on the discharge'side of the .. is closed andpower to. its.operatbr, if any, is disconnected ensures .that each LPCI subsystem, remains independent and a failure in the flow-path in one subsystem will not affec.t the flow path of the other, LPCi subsystem. IAcc-eptable methods of removing power to. the-operator include de-energizing breaker :control power or. racking o-ut or* removing the breaker. 'ýor the valves: in high',radiation areas, verification hay consist. of verifying that no worki actlvity was performed in the:.area of the valve since th~e last verification was performed. If one of the RHR System Cross tie valves ia Open or power,'has riot been removed from the Ia t]O*h a' d I* sub at co n 1?

aIministrat-ve controls r-naL V*.* e1nsure. thart the valves conti nue to remain clo~se'd with either control, or motive Power removed.

The high.presuIre co*lant injection {HPCI) system.. is proded to assure that the reactor core is adequately cooled to limvit fuel clad. temperature in the event of a small break in. the'.reactor coolant system and loss of coolant which:.does not result in iapid depreisurizationo.:f the reactor vessel. The*

HPCI system permits the reactor:-to be shut down while maintaining sufficient, reactor ve'ssel water level inventoty until the-vessel is depzessutited. Thje PcI" system continues to operate-until reactor vessel pressure is beelow the pressure at which CSS operation"or ".PCI mode of the RHR system operation maintains core cooling.

HOPE CRteE B 3/4 5-;1 C8 5Aendmet N'O. 109

t 1T~lENT SYSTEMS

,/6.6.3 PRI-MARY CONTAINMENT ISOLA'"TON VALVES The OPERABILITY of the primary containment isolation valves ensures that the containment armosphere will be isoiaZed from the outside environment in the event of a release of radioactive material t-o the. containment atmosphere o- pressuri-zation of the containment and is consistent with the requzrement:s of GDC 54 through 57 of Anpendix A of 10 CFR. 50. Containment isola-tion within the time limirs soecified for those isolation valves designed to close

=utomatically ensures that the release of radioactive material to the environmen- will be consistent with zhe assumptions used in the analvses for a LOCA.

Primary containment isolation valves covered by this LCO are lis-ed in the Technical Requirements Manual.

The ACT.i0NS are.modified) by a' Note allOwing isolation valves closed to-

satisfy ACTION requirements to be reopened on an intermittent basis under adm.inistrative controls. These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. in this way, the penetration can be raptidly isolated when a need for orimary containment isolation is indicated.

".Su_'el nce 4. 6 3.4 requires demohstration "that a '- esenatie 07-",

reactor :i-istr\uentation line excess flow oceklowoa'e I check ves are tested to emonstrateýthat the valve actuates to chec w on a'simulated instrument line break T1h"-1 surveillance reouiremoe Provides hssuranice that the aL instrument lin*- EFCV's will Perform s hat .the predictedwo.radioJŽ.:ogicl "

onsequences will not be exceededm in1 a 5osrulated rqenyi instrument -ine-break s _o*dh0 th nee "event as evaluated in the UPSA.

-orILo -n dur n t e l nthe o n ; r 1 1 tamed trasthe rvei ance e aere ffmrepthewith t reac r t oweZ. he a-enti t ve achetce aml.ee set eo h a'n

hthe* C add Z th va.i ous C1en confi ationssz d and perai g envir nment . Thi ensure at any a sp ific t- e or applic -ion of r:

det cted ear iesatp ssble time. The no inal I year n-erva is ba ed on paoran e tests in N 0xcs nec Vlve Test ngRe ation. Fur rmor any CV falures be vai o ee ne if ditior 1 tes n hat te t val i warran ed to -

nsure- erall a bIt Is aintai ad. Operating experience has

-emonstrated that these components are highly reliable and that failures to

,so-ate are very infrequent. Therefore, testing of a-representative sample was concluded to be acceptable from a reliability standpoint.

'/4.6.4 VACUUM RELIEF Suppression Chamber-to-Drywell Vacuum Breakers ATC-KGROUND: The function of the suporession-chamber-to-drywell vacuumm.

br-eaPers iS to reaieve vacuum in the drywa!e . There are eight internal veacuum b.reakers loca:ed on vent heacder of -he vent sysvem be-waea the Tha

'ry1'an1d -he suppression chamber that allow aer an, steae flow zrom te upporession chaemoer - rywei%when nhe -,rvw*e__ - S t a necative tressure suppression chamber. Therefore, suppression lOPE CREEK S 3/4 E-5 Amendment No. 171 IpSECýZ SSze:ý)

CONTAINMENT SYSTEMS BASES An open vacuum breaker allows communication between the drywell and suppression chamber airspace,. and, as a result, there is the potential for suppression chamber overpressurization due to this .bypass leakage if a LOCA were to occur. Therefore, the open vacuum breaker must be closed. A short time is allowed to close the vacuum breaker due to the low probability of an event that would pressurize primary containment. If vacuum breaker position indication is not reliable, an alternate method of verifying that the vacuum breakers are closed is to verify that a differential pressure of 0.5 psid between the suppression chamber and drywell is maintained for I hour without makeup. The required 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is considered adequate to perform this test.

If the inoperable suppression chamber-to-drywell vacuum breaker cannot be closed or restored to OPERABLE status within the required Completion Time, the plant must be brought to an OPERATIONAL CONDITION in which theLCO does not apply. To achieve this status, the plant must be brought. to at least OPERATIONAL CONDITION 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to OPERATIONAL CONDITION 4 within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ., The.allpwed Completion Times are -reasonable, based -on

'p6rahing experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS: . Each vacuum breaker is verified closed to 'ensure that this potential large bypass leakage path is not present. This2 Surveillance is performed by observing the vacuum breaker position indication or by verifying that a differential pressure of 0.5 psid between, the-.

suppression chamber and drywell is -maintained forzK! hdur without makeup. The y *'r*]uecyki54ase on enIlneering/ judgmerA J[is-c ni*ere* eadeuae' in/

7.j ofohr

'iw i.ýdica tis f cutm breaicker 6Etst* `'Zs*va, able .t ,0 eat 0ns prsonne' ,And aý bee shown_ o be ac eptable thrnbcr oerat eeLn A*Note-is added.to this SR.that allows suppression chamýber-to-drywell vacuumý". VIV breake'rsL opened in c6njunctio6n with the performance of a Surveillance to not"""

be~considered as failing thi*-SR, These periods of opening vacuum-.breakers are coiitrolled by'!lant procedures and do not represent inoperable,vacuum

/ breakers' Each required vacuum breaker must be cycled to ensure that it opens adequately to perform its design function and returns to the fully closed position. T s ensures that the safety analysis assumptions are valid. e - ay F'-quenc S--/ I0* asugn prvd Ii diiL urce r h vacuu brea rs*

Mh pre/PE.RA*LEi. ce t ar1lc rey t1d/i= M~as eIvirnen "he su iress'Sn /

chmbr *irsaG), a 1tion,-tn u-nctiona! test-is required within 12 ours after a discharge of steam to the suppression chamber from the safety/relief valves.

HOPE CREEK B 3/4 6-8 Amendment No. 3 H

CONTAINMENT SYSTEMS BASES Verification of the vacuum breaker opening setpoint is necessary to-ensure that the safety analysis assumption regarding vacuum breaker full open differential pressurenof 0.20upsid is va l .. The 18onth F en base-oAKeOneD Th Cfnctio 1*o

e r e unr csrdition sthe that ably bduiing a./anut n thei7g ial forean unplrei

/athepioertent ti~ gnt.i;b the /

S uveilghte re pbruormed ith thn reacton cat oer. Fov this k fab iry, the

-monts FreqotncY hv s beenasho be a eptablea basedlon v raling /ai

!a~txperiance, Ws.re d dlis Equnfvurther rterF conv* thebecise htlusttifed is thoper eqen 7 offfctioni* status ofs perf o her sur eillanci eac rmed /

qLvac.n bre~er 5 ""

vacumbraker i t elev vauu whe priar cna nm entdepessries Reactor-Building-to-Suppression chamberVa Breake p=. bs BACKGROUND: The function of the reactor building-to-suppression chamber i -

vacusreum breakers is to relieve vacuum when primary containment..depres surizes.

below reactor building pressurea. if the drywell depressurizes.sedow reactor buiadp ng pressure_ tcoolhnge c.differential pressurey cotinmet .spray through the reactor building-co-suppression chamber vacuum breakers and through the suppression-chamber-to-drywoll vaduumabreakeys. The.design of the.

external (reactor building-to-suppressionschamber) vacuum reliefprovisions consists of two vacuum breakers -(a check type.iacuum relieo valveand ean air opInertedbutterfly valve t aonreds nseries) ia each of two lines fromthent reactor building to the suppression chamber airspace. The butterfiyovalve iss actuated by differential actu~t~on nd ste pressure.

.:.cndensationivhevn The vacuu'm breaker is self-actuating ahd fap~mr'ytmrpue -

can be remotely vauu series must be clsdt.*~n ereakners.d*rttng.purposes, The two ek tight primary contime vacuum. breakersbudr.- in ='

Angtv iek:nilpre'ssu~reý across the drywall wall is.-caused bY:.'rapid ,

depressurization" of the dryWeli'_.* Events that cause this ra~id " :::

/ *depr~es'surization"':are cooling cycles, inadver~tent primary con talinment-,spray . ,

.*atu io, ndsteam condensation in the event of a primary*'"S`ytem ruptu~e " *,-

acuain and. Sys*;

*. eact* uligt-upeso chamber vacu beks prevent an 'excessive. .

. *-.*ii negative differential pressuire across the prilmary containme-btC.b~oundarg*' ...

cooling cycles result in minor .pressure tranfsients in the drywall, which occur slowly and are normally controlled by heating and ventilation equipment.

Inadvertent spray actuation results in a more significant pressure transient and becomes important in sizing the external (reactor building-to-sup~pression chamber) vacuum breakers.

CREEKia~if~n ci1'OseE B 3/4 6amendment bo.nda3y HOPE CREEK B 3/4 6- 19 Amendment No. 133

CONTAINIMENT SYSTEMS BASES Action c: With one or more vacuum breaker assemblies with one valve not closed, the leak tight primary containment boundary may be threatened.

Therefore, the inoperable valves must be restored to OPERABLE status or the open vacuum breaker assembly valve closed within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is consistent with requirements for inoperable suppression-chamber-to-drywell vacuum breakers in LCO 3.6.4.1, "Suppression-Chamber-to-Drywell Vacuum Breakers." The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundant capability afforded by the remaining valves, the fact that an OPERABLE valve in each of the assemblies is closed, and the low probability of an event occurring that would require the valves to be OPERABLE during this period.

Action d: With one or more vacuum breaker assemblies with two valves not closed, primary containment integrity is not maintained. Therefore, one open valve in each affected assembly must be closed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . This Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, "Primary Containment,"

which requires that primary containment be restored to OPERABLE status within

. hour...

1 If all the valves in a vacuum breaker assembly cannot be closed:or restored to OPERABLE status within the required Compl'etion Time, the plant must-:be brought to.an OPERATIONAL CONDITION in which the LCO does not apply. To achieve this status, the plant must be brought to at least OPERATIONAL CONDITION.?3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to OPERATIONAL CONDITION 4 within the following 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The allowed completion Times are reas6nable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner.and without challenging plant systehis,.

SURVEILLANCE REQUIREMENTS: Each vacuum-,zbreaker is verified to be closed to ensur6 that a potential breach in the phimary contaii~iment boundary is' not present., This.Surveillanc&-is performed b o rvin local or control room*L-4 -

1ic tt1 s of'vacuum breaker position. Th 14 da E-req ency is ased o0 er*g*neerin )ud t, is , isi er a ua e in yew -of other itiscatio of.

va um$'r akerst us av lable operations pe sonne , and hi ben Town o

accep lth ough-op rating )xperien e.

A Note is added to this SR.. *The first part of the Note allows reactor-to-suppression chamber vacuum breakers opened in conjunction with the performance of a Sur'veillance to not be considered as failing this SR. These periods of opening vacuum breakers are controlled by plant procedures and do not represent inoperable vacuum breakers. The second part of the Note is included to clarify that vacuum breakers open due to an actual differential pressure are not considered as failing this SR.

HOPE CREEK B 3/4 6-12 Amendment No. 133 1

CONTAINMENT SYSTEMS BASES Each vacuum breaker must be cycled to ensure that it opens properly to perform its design function and returns to its fully closed-position. This. nsure that the safety analysis assumptions are valid.. e ay e uen y of tjis s mo con vative nan rninser ice e ing ogram equir ents.

Demonstration of-vacuum-breaker opening setpoint is necessary to ensure-that -

the safety analysis assumption re ar v er f n d ferential 31r.6.5 SECONDARY CONTAINMENT

-Seconidary contai~nment is- designed to Minimize any ground level release--of ....

radioactive-material which~may result from an accident*. The Reactor Building :

and associatedistructures provide secondary containment during normal operationwhen thedrywell fis sealed and in service.nAt other times thee we

- drywell may-be open and, when required, secondary-containment integrity is-i;specified. .

Establishing and maintaining a 0.25*-inch water gage ,vacuum in the reactor building with the filtration recirculation and ventat-on-- system a(FVS) once peji 18 months, along oith the surveillance of-rthe doorshoatches, dampers and valves, is adequate to--ensure that there are~no violations~ofrthe integrity of the secondary containment. i - -" eae--o a In MODES- 4 .andt5,the prov bility and consequences of theLOCA are opreducedriduewo the' presure .and t aiIperature limitations in these MODES. th Therefore, maintainingh.. secondary containment OPERABLE is not requiredi&nMODE 4 or 5 to ensure a .control volume, -except 'for other 'situations 'for which significant releases of radioactive material cang-be postulated, such as dutring movement of recently irradiated fuel assemblies in the secondary containment or during -operations with a potential for f.draining the reactor vessel-vOPDRVs).i -dDue to radioactive decay, handling of fuel only requires o OERABILITY of secondary containment when fuel being handled is-recently irradiated, -i.e., fuel5u that has occpiedapacofethe criticalf reactor core within the previous 2.4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . -

During handling of fuel and CORE ALTERATIONS, secondary containment and FRVS.actuation is not required. However, building ventilation will be operating during fuel handling and CORE ALTERATIONS and Will be capable of drawing air into the building and exhausting through a monitored pathway. To reduce doseseven further below thi atpride by24shurstofnaturac decay, a single normal or contingency method to promptly close secondary containment penetrations is -provided in-accordance :with RG.l83.. Such prompt methods need not completely block the penetration, or be capable of resisting pressure.

The purpose of the "prompt methods" (defined as within 30 minutes) is to enable ventilation systems to draw the release from a postulated fuel.handling co accident in the proper direction such that it can be treated and monitored.

aThese contingencies are to be utilized after a postulated fuel handling. To accident has occurred to reduce doses even further below that provided by.ythe natural decay.

HOPE CREER B 3/4 6-13 Amendment No. 146

CONTAINMENT SYSTEMS BASES 3/4.6.6 PRIMARY CONTAINMENT: ATMOSPHERE CONTROL.

The primary containment okygen concentration is maintained less than 4% by volume to ensure that an event that produces any amount of hydrogen does not result in a combustible mixture insideprimary containment.

The primary containment oxygen concentration must be less than 4% by volume when primary containment is inerted, except as allowed by the relaxations during startup and shutdown addressed below. The primary containment must be inert in OPERATIONAL CONDITION 1, since this is the condition with the highest probability of an event that could produce hydrogen.

Inerting the primary 'containment is an operational problem because it prevents containment, access without an appropriate breathing apparatus. Therefore, the primary containment is inerted as late as possible in the plait 'startul57 &nd-de-inerted as soon as possible in the plant shutdown. As.long as reactor power is less than 15% of RATED THERMAL POWER, the potential for an event that generates significant hydrogen is low, and the primary containment need not be inert. Furthermore, the probability of an event that generates hydrogen occurring within the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of a startup, or. within the last 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months before a shutdown, is low enough that these "windows', " when the primary, W- containment is.,not inerted, are also justified. The 24_hour time .period is a reasonable amount of time to allow plant personnel to peifori indi-.tlhg.r de-inerting.

If oxygen concentration is > 4% by volume at; any time while operating in.

OPERATIONAL CONDITION 1, with the exception *f_ the relaxitions allowedt'during startup and shutdown, oxygen concentration must be restored to < 4% by~volume within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months compl'tion time is allowed when oxygen concentration is ' 4% by volume because of the low probability and long durat'ion of an event that would generate significant amounts of hydrogen occurring during this period.

If oxygen concentration cannot be restored to within' limits within the required completion time, the plant must be brought to an OPERATIONAL CONDITION in which the LCO does not.apply. To achieve this status, plant must be in at least STARTUP within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months completion time is reasonable, based on operating experience, to reduce reactor power from full power conditions in an orderly manner and without challenging plant systems.

The primary containment must be determined to be inert by erifvi.

o n oncentration is less toh % vlume T I ya:Frequenq is base/

D.. he.,s. at...whiz p Pa.. and. on her .Xate.

/in 3i6atios of bnormal *onditi. s (whih would *ead to *ore f re ent chec ng opera ori accorda ce wit plant rooedure ). Als , this F/equency s ee sh a "

CREEK NOPE T B /--1-mnd7tNo)6

.-HOPE CREEK B 3/4 6-14 Amendment No. 160

3/4.8 ELECTRICAL POWER SYSTEMS BASES (Continued)

Particulate concentration should be determined in accordance with ASTM D2276, Method A, or ASTM D5452. This method involves a gravimetric determination of total particulate concentration in the fuel oil and has a limit of 10 mg/i.

The 0.8 micron filters specified in ASTM D2276 or ASTM .D5452 maybe replaced with membrane filters up to 3.0 microns. This is acceptable since the closest tolerance fuel filter in the RC EDGs is a five micron particle retention duplex filter on the engine driven fuel oil pump. It is acceptable to obtain a field sample for subsequent laboratory testing in lieu of field testing.

The total volume of stored fuel oil contained in two or more interconnected tanks must be considered and tested separately. The frequency of this test takes into consideration fuel oil degradation trends that indicate the particulate concentration is unlikely to change significantly between frequency intervals.

The OPERABILITY of the minimum specified A.C. and D.C. power sources and associated distribution systems during shutdown and refueling ensures that (1) the facility can be maintained in the shutdown or refueling condition for extended time periods and (2) sufficient instrumentation and control capability is available for monitoring and maintaining the unit status.

with exceptions as noted in the Hope Creek UFSAR-j,.the surveillahce requirements for demonstrating the OPERABILITY of..tbhe dieseI*' generators comply with the recommendations of Regulatory Guide i.9,>ý"Selection>,. Design, and Qualification of Diesel 'Generator Units Used as Standby (Onsite)' Electric'al Power Systems at Nuclear Power Plants", Revision:%2, December., 19.79, Regulatory Guide 1.108, "Periodic Testing of Diesel Generat6r Units Used as Onsite Electrical Power Systems at Nuclear*Pbwer Plants", Revision 1, 'August 1977 and Regulatory 4 Guide. 1.137 "Fuel-Oil Systems for Standby Diesel Generators",

Revision 1, October !979.asrmodified by plant specific analysis, diesel

-generator manufacturersý icbmmendations, and Amendment 59, to the Facility '

Operating License, issued November 22, 1993.

HOPE CREEK B 3/4 8-1d 50.59 # HC-07-002 (PSEG Issued)

ATTACHMENT 5 LAR H10-01 LR-N10-0015 ATTACHMENT 5 NO SIGNIFICANT HAZARDS CONSIDERATION:

LICENSE AMENDMENT TO ADOPT TSTF-425, REVISION 3.

"RELOCATE SURVEILLANCE FREQUENCIES TO LICENSEE CONTROL" Description of Amendment Request: The change requests the adoption of an approved change to the Standard Technical Specifications (STS) for General Electric Plants, BWR/4 (NUREG-1433), to allow relocation of specific TS surveillance frequencies to a licensee-controlled program. The proposed changes are described in Technical Specifications Task Force (TSTF) Traveler, TSTF-425, Revision 3 (ADAMS Accession No. ML090850642) related to the Relocation of Surveillance Frequencies to Licensee Control- RITSTF Initiative 5b and are described in the Notice of Availability published in the Federal Register on July 6, 2009 (74 FR 31996).

The proposed changes are consistent with NRC-approved industry/TSTF Traveler, TSTF-425, Revision 3, "Relocate Surveillance Frequencies to Licensee Control- RITSTF Initiative 5b." The proposed change relocates surveillance frequencies to a licensee-controlled program, the SFCP. The changes are applicable to licensees using probabilistic risk guidelines contained in NRC-approved NEI 04-10, "Risk-Informed Technical Specifications Initiative 5b, Risk-Informed Method for Control of Surveillance Frequencies," (ADAMS Accession No. 071360456).

Basis for proposed no significant hazards consideration: As required by 10 CFR 50.91(a), the PSEG analysis of the issue of no significant hazards consideration is presented below:

i) Does the proposed change involve a significant increase in the probability or consequences of any accident previously evaluated?

Response: No.

The proposed change relocates the specified frequencies for periodic surveillance requirements to licensee control under a new Surveillance Frequency Control Program.

Surveillance frequencies are not an initiator to any accident previously evaluated. As a result, the probability of any accident previously evaluated is not significantly increased.

The systems and components required by the Technical Specifications for which the surveillance frequencies are relocated are still required to be operable, meet the acceptance criteria for the surveillance requirements, and be capable of performing any mitigative function assumed in the accident analysis. As a result, the consequences of any accident previously evaluated are not significantly increased.

Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

ii) Does the proposed change create the possibility of a new or different kind of accident from any previously evaluated?

Response: No.

1 of 2

ATTACHMENT 5 LAR H10-01 LR-N10-0015 No new or different accidents result from utilizing the proposed change. The changes do not involve a physical alteration of the plant (i.e. no new or different type of equipment will be installed) or a change in the methods governing normal plant operation. In addition, the changes do not impose any new or different requirements. The changes do not alter assumptions made in the safety analysis. The proposed changes are consistent with the safety analysis assumptions and current plant operating practice.

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

iii) Does the proposed change involve a significant reduction in a margin of safety?

Response: No.

The design, operation, testing methods, and acceptance criteria for systems, structures, and components (SSCs), specified in applicable codes and standards (or alternatives approved for use by the NRC) will continue to be met as described in the plant licensing basis (including the final safety analysis report and bases to TS), since these are not affected by changes to the surveillance frequencies. Similarly, there is no impact to safety analysis acceptance criteria as described in the plant licensing basis. To evaluate a change in the relocated surveillance frequency, PSEG will perform a probabilistic risk evaluation using the guidance contained in NRC approved NEI 04-10, Rev. 1 in accordance with the TS SFCP. NEI 04-10, Rev. 1, methodology provides reasonable acceptance guidelines and methods for evaluating the risk increase of proposed changes to surveillance frequencies consistent with Regulatory Guide 1.177.

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

Based on the above, PSEG concludes the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c) and accordingly, a finding of "no significant hazards consideration" is justified.

2 of 2

v t e Letter Sequence Request
TAC:ME3545, Relocate Surveillance Frequencies to Licensee Control - RITSTF Initiative 5B (Approved, Closed)
Initiation Request, Request Acceptance Supplement Administration Questions 2 July 2010 Answers 28 July 2010 Results Approval Other: ML110980151
MONTHYEAR2010-07-28 [Table View]

LR-N10-0015, Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program

Text

Subject:

1.0 DESCRIPTION

3.0 REGULATORY ANALYSIS

4.0 ENVIRONMENTAL CONSIDERATION

1.0 DESCRIPTION

3.0 REGULATORY ANALYSIS

4.0 ENVIRONMENTAL CONSIDERATION

5.0 REFERENCES

Navigation menu

LR-N10-0015, Application for Technical Specification Change Regarding Risk-Informed Justification for the Relocation of Specific Surveillance Frequency Requirements to a Licensee Controlled Program

Text

Subject:

1.0 DESCRIPTION

3.0 REGULATORY ANALYSIS

4.0 ENVIRONMENTAL CONSIDERATION

1.0 DESCRIPTION

3.0 REGULATORY ANALYSIS

4.0 ENVIRONMENTAL CONSIDERATION

5.0 REFERENCES

Navigation menu

Search