LR-N06-0437, License Amendment Request to Relocate Component Lists for Primary Containment Isolation Valves from Technical Specifications

License Amendment Request to Relocate Component Lists for Primary Containment Isolation Valves from Technical Specifications

ML063260285
Person / Time
Site:	Hope Creek
Issue date:	11/15/2006
From:	Barnes G Public Service Enterprise Group
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
LCR-H06-02, LR-N06-0437
Download: ML063260285 (77)

Text

PSEG Nuclear LLC P.O. Box 236, Hancocks Bridge, New Jersey 08038-0236 Q PSEG Nuclear LLC 10 CFR 50.90 LR-N06-0437 LCR H06-02 November 15, 2006 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:

License Amendment Request to Relocate Component Lists for Primary Containment Isolation Valves from Technical Specifications Pursuant to 10 CFR 50.90, PSEG Nuclear LLC hereby requests a change to the Technical Specifications (TS) for Hope Creek Generating Station (HCGS).The proposed change would remove valve component lists and references to the lists from the Technical Specifications (TS). The information contained in the deleted tables would be relocated to the HCGS Technical Requirements Manual (TRM).The proposed change is consistent with Generic Letter 91-08, "Removal of Component Lists from Technical Specifications," which provides guidance for preparing license amendment requests to remove component lists from the TS. This request meets all conditions outlined in the Generic Letter. Additionally, the revision does not alter the requirements for component operability currently in the Technical Specifications.

The Limiting Conditions for Operation (LCOs) and Surveillance Requirements will be retained in the revised Technical Specifications and the proposed change will not affect the meaning, application, and function of the current Technical Specification requirements for the components.

The approach for this revision is consistent with the Improved Standard Technical Specifications (STS) described in NUREG-1433, "Standard Technical Specifications, General Electric Plants (BWR/4)," and changes previously approved by the NRC for other licensees, including the Limerick Generating Station.A4cw'95-2168 REV. 7/99 LR-N06-0437 LCR H06-02 November 15, 2006 Page 2 Attachment 1 to this letter describes the proposed changes and provides justification for the changes. PSEG has concluded that the proposed changes present no significant hazards consideration under the standards set forth in 10CFR 50.92. Attachment 2 provides the marked up Technical Specification pages. Attachment 3 provides the marked up Technical Specifications Bases pages. These Bases pages are being submitted for information only and do not require issuance by the NRC.To support the RF14 refueling outage, PSEG requests approval of the proposed amendment by September 3, 2007, with implementation to be completed within 90 days.There are no commitments in this letter.These proposed changes have been reviewed by the Plant Operations Review Committee, and approved by the Nuclear Review Board. We are notifying the State of New Jersey of this application for changes to the TS by transmitting a copy of this letter and its attachments to the designated State Official.If you have any questions or require additional information, please contact Mr. Paul Duke at 856-339-1466.

I declare under penalty of perjury that the foregoing is true and correct.Executed on 1/ ///5 /i ._____, _____(date) George P. Barnes Site Vice President

-Hope Creek Attachments:

1. Description of Proposed Changes, Technical Analysis, and Regulatory Analysis 2. Markup of Technical Specification pages 3. Markup of Technical Specification Bases pages (for information only)cc: S. Collins, Regional Administrator

-NRC Region I S. Bailey, Project Manager -Hope Creek, USNRC NRC Senior Resident Inspector

-Hope Creek K. Tosch, Manager IV, NJBNE ATTACHMENT 1 License Amendment Request Hope Creek Generating Station NRC Docket No. 50-354 Description of Proposed Changes, Technical Analysis, and Regulatory Analysis

Subject:

Relocation of Valve Component Lists From Technical Specifications

3.0 BACKGROUND

4.0 TECHNICAL ANALYSIS 5.0 REGULATORY ANALYSIS 5.1 No Significant Hazards Consideration 5.2 Applicable Regulatory Requirements/Criteria 6.0 ENVIRONMENTAL CONSIDERATION

7.0 REFERENCES

ATTACHMENT 1 DESCRIPTION OF PROPOSED CHANGES, TECHNICAL ANALYSIS, AND REGULATORY ANALYSIS

1.0 DESCRIPTION

This letter is a request to amend Operating License NPF-57 for Hope Creek Generating Station.The proposed changes would remove valve component lists for primary containment isolation valves and references to the lists from the Technical Specifications (TS) and relocate the information to a Technical Requirements Manual (TRM), a licensee controlled document, in accordance with Generic Letter 91-08, "Removal of Component Lists from Technical Specifications" (Reference 1).

2.0 PROPOSED CHANGE

TS Table 3.6.3-1, "Primary Containment Isolation Valves," would be removed from the TS and relocated to the TRM. The following additional changes are proposed to support relocation of TS Table 3.6.3-1: 1. The TS Index will be revised to delete the reference to Table 3.6.3-1.2. TS Definition 1.32, "Primary Containment Integrity," will be revised to state the exception to closure of primary containment penetrations in more general terms rather than making a specific reference to TS Table 3.6.3-1 by replacing the words "as provided in Table 3.6.3-1 of" with the words "for valves that are opened under administrative control as permitted by." 3. TS Table 3.3.2-1, "Isolation Actuation Instrumentation," will be revised to reflect the removal of Table 3.6.3-1 by deleting Note (d). Table Notations for TS Table 3.3.2-1 identifying valves closed by a particular trip signal will be relocated to the TRM.4. SR 4.6.1.1.b will be revised to state the exception to closure of primary containment penetrations in more general terms rather than making a specific reference to TS Table 3.6.3-1 by replacing the words "as provided in Table 3.6.3-1 of' with the words "for valves that are opened under administrative control as permitted by." 5. LCO 3.6.1.2.b, "Primary Containment Leakage," will be revised to delete the references to Table 3.6.3-1. LCO 3.6.2.1.b will be reworded in its entirety for clarity regarding the exceptions to the combined leakage rate. The proposed wording is as follows:

LR-N06-0437 Attachment 1 Page 2 A combined leakage rate in accordance with the Primary Containment Leakage Rate Testing Program for all primary containment penetrations and all primary containment isolation valves that are subject to Type B and C tests, except for: main steam line isolation valves*, valves which form the boundary for the long-term seal of the feedwater lines, other valves which are hydrostatically tested, and those valves where an exemption to Appendix J of 10 CFR 50 has been granted.6. LCOs 3.6.1.2.d and 3.6.1.2.e will be revised to delete the reference to TS Table 3.6.3-1.7. TS Action 3.6.1.2.b will be revised to delete the references to Table 3.6.3-1.Action 3.6.1.2.b will be reworded in its entirety for clarity regarding the exceptions to the combined leakage rate. The proposed wording is as follows: The measured combined leakage rate exceeding the leakage rate specified in the Primary Containment Leakage Rate Testing Program for all primary containment penetrations and all primary containment isolation valves that are subject to Type B and C tests, except for: main steam line isolation valves*, valves which form the boundary for the long-term seal of the feedwater lines, valves which are hydrostatically tested, and those valves where an exemption to Appendix J of 10 CFR 50 has been granted, or 8. TS restoration Action 3.6.1.2.b will be revised to delete the references to Table 3.6.3-1. Restoration Action 3.6.1.2.b is being reworded in its entirety for clarity regarding the exceptions to the combined leakage rate. The proposed wording is as follows: The combined leakage rate to be in accordance with the Primary Containment Leakage Rate Testing Program for all primary containment penetrations and all primary containment isolation valves that are subject to Type B and C tests, except for: main steam line isolation valves*, valves which form the boundary for the long-term seal of the feedwater lines, valves which are hydrostatically tested, and those valves where an exemption to Appendix J of 10 CFR 50 has been granted, and 9. SRs 4.6.1.2.g and 4.6.1.2.h will be revised to delete the reference to TS Table 3.6.3-1.10. LCO 3.6.3, "Primary Containment Isolation Valves," will be revised as follows to delete the references to Table 3.6.3-1: Each primary containment isolation valve and each reactor instrumentation line excess flow check valve shall be OPERABLE.

LR-N06-0437 Attachment 1 Page 3 11 .TS Actions 3.6.3.a and 3.6.3.b, and SRs 4.6.3.1, 4.6.3.2, 4.6.3.3, and 4.6.3.4 will be revised to delete the references to Table 3.6.3-1.12.A note will be added to SR 4.6.3.4 stating "the reactor vessel head seal leak detection line (penetration J5C) excess flow check valve is not required to be tested pursuant to this requirement." 13.TS Bases section 3/4.3.2, "Isolation Actuation Instrumentation," will be revised to refer to the TRM for identification of valve groups actuated by isolation trip functions.

14.TS Bases section 3/4.6.3 will be revised to refer to the TRM for the list of primary containment isolation valves covered by LCO 3.6.3.15. TS Bases section 3/4.6.3 will be revised to add a description of administrative controls to be used when opening a valve that was locked or sealed closed to satisfy LCO 3.6.3 Action requirements, consistent with the guidance in GL 91-08 and with NUREG-1433:

The ACTIONS are modified by a Note allowing isolation valves closed to satisfy ACTION requirements to be reopened on an intermittent basis under administrative 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 rapidly isolated when a need for primary containment isolation is indicated.

Marked up TS pages are provided in Attachment

2. Marked up TS Bases pages are provided in Attachment

3. These Bases pages are being submitted for information only and do not require issuance by the NRC.

3.0 BACKGROUND

In May 1991, the NRC issued Generic Letter 91-08 to provide guidance on removing component lists from TS. As an alternative to identifying components by their plant identification number in tables of TS components, specifications may be stated in general terms that describe the types of components to which the requirements apply.The NRC staff concluded that the removal of component lists is acceptable because it does not alter existing TS requirements or those components to which they apply.The removal of component lists from TS permits administrative control of changes to these lists without processing a license amendment, as is required to update TS component lists. Any change to component lists contained in plant procedures is subject to the requirements specified in the Administrative Controls Section of the TS on changes to plant procedures.

Therefore, the change control provisions of the TS LR-N06-0437 Attachment 1 Page 4 provide an adequate means to control changes to these component lists, when they have been incorporated into plant procedures, without including them in TS.Enclosure 1 to GL 91-08 identified specific issues to be addressed in a request to remove component lists: A. Each TS should include an appropriate description of the scope of the components to which the TS requirements apply. Components that are defined by regulatory requirements or guidance need not be clarified further. However, the Bases Section of the TS should reference the applicable requirements or guidance.B. If the removal of a component list results in the loss of notes that modify or provide an exception to the TS requirements, the specification should be revised to incorporate that modification or exception.

The modification or exception should be stated in terms that identify any group of components by function rather than by plant identification number, if practical.

C. Licensees should confirm that the lists of components removed from the TS are located in appropriately controlled plant procedures.

The list of components may be included in the next update of the FSAR. The Bases Section of individual specifications also may reference the plant procedures or other documents that identify each component list. The Bases Section for the containment isolation valve TS should be updated to describe the intent of opening valves under administrative control.4.0 TECHNICAL ANALYSIS The proposed change would remove TS Table 3.6.3-1, "Primary Containment Isolation Valves," the associated Notations for TS Table 3.3.2-1 identifying valves closed by a particular isolation trip signal, and any references thereto from the TS. The lists would be relocated to the TRM. Changes to the TRM will be reviewed pursuant to 10 CFR 50.59, and summaries of changes will be provided to the NRC in the periodic 10 CFR 50.59 report. Relocating the tables from the TS will eliminate the burden of processing license amendments when changes are made to the tables and will facilitate the more effective utilization of NRC and PSEG resources.

With regard to the specific items to be addressed in accordance with the guidance in Enclosure 1 to GL 91-08: A. LCO 3.6.3 will apply to "each primary containment isolation valve." Operability requirements for the reactor building-to-suppression chamber vacuum breakers are stated separately in LCO 3.6.4.2. Therefore, removal of TS Table 3.6.3-1, the associated Notations to Table 3.3.2-1, and all references thereto does not affect the scope of components to which the TS requirements apply.

LR-N06-0437 Attachment 1 Page 5 B. The Notes to Table 3.6.3-1 will be incorporated as discussed below to preserve existing approved modifications or exceptions to the TS requirements:

1. Note 1 states that main steam isolation valve leakage is not added to 0.60 La allowable leakage. This represents an exemption to the requirements of Appendix J to 10 CFR 50 and is already incorporated into LCO 3.6.1.2.b.

2. Note 2 identifies valves sealed with a water seal from the HPCI and/or RCIC system to form the long-term seal boundary of the feedwater lines. Limits on the leakage rate for these valves are already incorporated into LCO 3.6.1.2.d.

3. Note 3 identifies valves subject to Type C gas testing and leakage limits for those valves. Limits on the combined leakage rate for these valves are already incorporated into LCO 3.6.1.2.b and TS 6.8.4.f.4. Note 4 identifies valves subject to Type C water testing and leakage limits for those valves. Limits on the combined leakage rate for these valves are already incorporated into LCO 3.6.1.2.e.

5. Note 5 identifies RHR and core spray system thermal relief valves that form part of the containment boundary.

Leakage through these valves is determined during the overall integrated (Type A) test in accordance with the Primary Containment Leakage Rate Testing Program. This represents an exemption to the requirements of Appendix J to 10 CFR 50 and is incorporated into the proposed rewording of LCO 3.6.1.2.b.

6. Note 6 identifies drywell and suppression chamber pressure and level instrument root valves and excess flow check valves which are leakage tested during the Type A test. This represents an exemption to the requirements of Appendix J to 10 CFR 50 and is incorporated into the proposed rewording of LCO 3.6.1.2.b.

7. Note 7 states that explosive shear valves (SE-V021 through SE-V025) are not Type C tested. This represents an exemption to the requirements of Appendix J to 10 CFR 50 and is incorporated into the proposed rewording of LCO 3.6.1.2.b.

8. Note 8 states that surveillances for valves in the containment purge supply and exhaust lines are to be performed per Specification 3.6.1.8. SR 4.6.1.8.2 states that the containment purge supply and exhaust valves shall be demonstrated OPERABLE in accordance with the Primary Containment Leakage Rate Testing Program. Note 8 does not modify or provide an exception to the TS requirements and need not be incorporated into the TS.

LR-N06-0437 Attachment 1 Page 6 9. Note 9 describes the numbering convention for valves. It does not modify or provide an exception to the TS requirements and need not be incorporated into the TS.10. Note 10 states that the reactor vessel head seal leak detection line (penetration J5C) excess flow check valve (BB-XV-3649) is not subject to OPERABILITY testing. A note will be added to SR 4.6.3.4 to preserve this existing approved modification to the TS requirements.

11. Note 11 identifies containment isolation valves that are not Type C tested because the lines penetrating the containment terminate below the minimum water level in the suppression chamber and the systems are closed systems outside Primary Containment.

As noted in Reference 2, leak rate testing these valves is not required to satisfy Appendix J requirements for Type C testing. The proposed changes to LCO 3.6.1.2.b, TS Action 3.6.1.2.b and TS restoration Action 3.6.1.2.b make it clear that the leakage rate requirements do not apply to valves that are not subject to Type B and C tests. Note 11 does not modify or provide an exception to the TS requirements and need not be incorporated into the TS.Note (d) to TS Table 3.3.2-1, "Isolation Actuation Instrumentation," will be deleted to reflect the removal of Table 3.6.3-1 and the Table Notations for TS Table 3.3.2-1 identifying valves closed by a particular trip signal will be relocated to the TRM. Note (d) and the Table Notations provide system design information.

The proposed change does not affect the TS requirements for the isolation actuation trip functions listed in TS Table 3.3.2-1 and is consistent NUREG-1433,"Standard Technical Specifications, General Electric Plants (BWR/4)," which does not list the valve actuation groups in STS Table 3.3.6.1-1, "Primary Containment Isolation Instrumentation," or STS Table 3.3.6.2-1, "Secondary Containment Isolation Instrumentation." C. Before implementing the proposed changes, PSEG will confirm that the list of CIVs is located in the Technical Requirements Manual, which will be an appropriately controlled plant procedure.

The proposed changes to TS Tables 3.3.2-1 and 3.6.3-1, "Primary Containment Isolation Valves," and the associated Notations for TS Table are administrative in that they merely relocate the CIV Tables from the TS to the TRM and maintain the requirements for CIV testing and the acceptance criteria for the testing in the Limiting Condition for Operation 3.6.3. Equipment test methods, frequencies, and acceptance criteria are not affected by the proposed changes.The proposed changes are consistent with NUREG-1433, "Standard Technical Specifications, General Electric Plants (BWR/4)," which does not contain a list of CIVs.

LR-N06-0437 Attachment 1 Page 7 The list of CIVs is not included in STS section 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)." Relocating Table 3.6.3-1 from the TS to the TRM does not affect the TS requirements for CIVs or the components to which they apply. Changes to the TRM will be controlled in accordance with 10 CFR 50.59.The proposed change is consistent with TS changes previously approved by the NRC for the Limerick Generating Station (Reference 3).5.0 REGULATORY ANALYSIS 5.1 No Significant Hazards Consideration PSEG has evaluated whether or not a significant hazards consideration is involved with the proposed amendment(s) by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below: 1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response:

No.The proposed relocation of Technical Specification component lists of primary containment isolation valves does not alter the requirements for component operability or surveillance currently in the Technical Specifications.

The proposed change to remove the component lists from TS and relocate the information to an administratively controlled document will have no impact on any safety related structures, systems or components.

The probability of occurrence of a previously evaluated accident is not increased because this change does not introduce any new potential accident initiating conditions.

The consequences of accidents previously evaluated in the UFSAR are not affected because the ability of the components to perform their required function is not affected.Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

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

Response:

No.

LR-N06-0437 Attachment 1 Page 8 The proposed changes are administrative in nature, conform to the guidance in Generic Letter 91-08 and do not result in physical alterations or changes in the method by which any safety related system performs its intended function.

The proposed changes do not affect any safety analysis assumptions.

The proposed changes do not create any new accident initiators or involve an activity that could be an initiator of an accident of a different type.All components will continue to be tested to the same requirements as defined in the Technical Specification Surveillance Requirements.

The proposed revision does not make changes in any method of testing or how any safety related system performs its safety functions.

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

3. Does the proposed amendment involve a significant reduction in a margin of safety?Response:

No.The proposed change to remove Technical Specification Table 3.6.3-1 from the Technical Specifications and relocate it to the Technical Requirements Manual does not alter the Technical Specification requirements for containment integrity and containment isolation and will not affect the containment isolation capability.

Future revisions to the Technical Requirements Manual Table will be subject to evaluation pursuant to 10 CFR 50.59.The proposed change will not affect the current Technical Specification requirements or the components to which they apply.Therefore, the proposed change does not involve a significant reduction in a margin of safety.Based on the above, PSEG concludes that 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.

5.2 Applicable Regulatory Requirements/Criteria 10 CFR 50.36 specifies the criteria for including limiting conditions for operation (LCOs) in the TSs for commercial nuclear power reactors.

According to 10 CFR LR-N06-0437 Attachment 1 Page 9 50.36, an LCO must be established for items that meet one or more of the following criteria: Criterion 1: Installed instrumentation that is used to detect, and indicate in the control room, a significant degradation of the reactor coolant pressure boundary.Criterion 2: A process variable, design feature, or operating restriction that is an initial condition of a design basis accident or transient analysis that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.Criterion 3: A structure, system, or component that is part of the primary success path and which functions or actuates to mitigate a design basis accident or transient that either assumes the failure of or presents a challenge to the integrity of a fission product barrier.Criterion 4: A structure, system, or component which operating experience or probabilistic risk assessment has shown to be significant to public health and safety.On May 6, 1991, the NRC issued Generic Letter (GL) 91-08, "Removal of Component Lists from Technical Specifications," which stated that the removal of component lists is acceptable because it does not alter existing TS requirements or those components to which they apply. The GL contains guidance on removing component lists from plant TSs and relocating them to other licensee-controlled documents.

In June 2004, the NRC issued Revision 3 to NUREG-1433, "Standard Technical Specifications, General Electric Plants (BWR/4)." Removal of the TS component tables described above is consistent with NUREG-1433.

In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the 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.6.0 ENVIRONMENTAL CONSIDERATION A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement.

However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the LR-N06-0437 Attachment 1 Page 10 amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.

Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

7.0 REFERENCES

1. Generic Letter 91-08, "Removal of Component Lists from Technical Specifications" 2. NRC Safety Evaluation Related to Amendment No. 76, Hope Creek Generating Station (TAC NO. M89426), dated August 1, 1995 3. NRC Safety Evaluation Related to Amendment Nos. 146 and 107, Limerick Generating Station, Unit Nos. 1 and 2 (TAC Nos. MA8101 and MA8102), October 18, 2000 ATTACHMENT 2 Hope Creek Generating Station Facility Operating License No. NPF-57 NRC Docket No. 50-354 Relocation of Valve Component Lists From Technical Specifications Markup of Proposed Technical Specification Page Changes TS Pages xii 1-5 3/4 3-11 3/4 3-12 3/4 3-13 3/4 3-14 3/4 3-15 3/4 3-16a 3/4 3-17 3/4 3-18 3/4 3-19 3/4 3-20 3/4 3-21 3/4 6-1 3/4 6-2 3/4 6-3 3/4 6-4 3/4 6-17 3/4 6-18 3/4 6-19 through 3/4 6-42 LR-N06-0437 Attachment 2 Page 2[Insert A A combined leakage rate in accordance with the Primary Containment Leakage Rate Testing Program for all primary containment penetrations and all primary containment isolation valves that are subject to Type B and C tests, except for: main steam line isolation valves*, valves which form the boundary for the long-term seal of the feedwater lines, other valves which are hydrostatically tested, and those valves where an exemption to Appendix J of 10 CFR 50 has been granted.[Insert B The measured combined leakage rate exceeding the leakage rate specified in the Primary Containment Leakage Rate Testing Program for all primary containment penetrations and all primary containment isolation valves that are subject to Type B and C tests, except for: main steam line isolation valves*, valves which form the boundary for the long-term seal of the feedwater lines, valves which are hydrostatically tested, and those valves where an exemption to Appendix J of 10 CFR 50 has been granted, or[Insert C The combined leakage rate to be in accordance with the Primary Containment Leakage Rate Testing Program for all primary containment penetrations and all primary containment isolation valves that are subject to Type B and C tests, except for: main steam line isolation valves*, valves which form the boundary for the long-term seal of the feedwater lines, valves which are hydrostatically tested, and those valves where an exemption to Appendix J of 10 CFR 50 has been granted, and INDEX LIMITING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE Drywell Average Air Temperature

........................

3/4 6-10 Drywell and Suppression Chamber Purge System ...........

3/4 6-11 3/4.6.2 DEPRESSURIZATION SYSTEMS Suppression-Chamber

....................................

3/4 6-12 Suppression Pool Spray...................................

3/4 6-15 Suppression Pool Cooling ...............................

3/4 6-16 3/4.6.3 PRIMARY CONTAINMENT

ISLATION VALVES...................

3/4 6-17 Table 3.6.3-i 4 -selatI'i V 3/4C ...3/4.6.4 VACUUM RELIEF Suppression Chamber -Drywell Vacuum Breakers ..........

3/4 6-43 Reactor Building -Suppression Chamber Vacuum Breakers ..............................................

3/4 6-45 3/4.6.5 SECONDARY CONTAINMENT Secondary Containment Integrity

........................

3/4 6-47 Secondary Containment Automatic Isolation Dampers ...... 3/4 6-49 Table 3.6.5.2-1 Secondary Containment Ventilation System Automatic Isolation Dampers Isolation Group No. 19 ...............

3/4 6-50 Filtration, Recirculation and Ventilation System ....... 3/4 6-51 3/4.6.6 PRIMARY CONTAINMENT ATMOSPHERE CONTROL Containment Hydrogen Recombiner Systems (Deleted)

...... 3/4 6-54 Drywell and Suppression .Chamber Oxygen Concentration...

3/4 6-55 3/4.7 PLANT SYSTEMS 3/4.7.1 SERVICE WATER SYSTEMS Safety Auxiliaries Cooling System ......................

3/4 7-1 Station Service Water System .............................

3/4 7-3 Ultimate Heat Sink .....................................

3/4 7-5 3/4.7.2 CONTROL ROOM EMERGENCY FILTRATION SYSTEM ...............

3/4 7-6 HOPE CREEK xii Amendment N6' 160

... %': .,:.OEF7NITIONS OPERABLE -OPERABILITY 1.28 A system, subsystem, train, component or device shall be OPERABLE or nave OPERABILITY wken it is capable of performing its specified function(s) ano when all necessary attendant instrumentation, controls, electrical Dower, cooling or seal water, lubrication or other auxiliary equipment tnat are required for the system, subsystem, train, component or device to oerform its function(s) are also capable of performing their related support function(s).

OPERATIONAL CONDITION

-CONDITION 1.29 An OPERATIONAL CONDITION, i.e., CONDITION, shall be any combination of mode switch position and average reactor temperature as specified in Table 1.2.one inclusive coolant PHYSICS TESTS 1.30 PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation and 1) described in Chapter 14 of the FSAR, 2) authorized under the provisions of 10 CFR 50.59, or 3) otherwise approved by the Commission.

PRESSURE BOUNDARY LEAKAGE 1.31 PRESSURE BOUNDARY LEAKAGE shall be leakage through a non-isolable fault in a reactor coolant system component body, pipe wall or vessel wall.PRIMARY CONTAINMENT INTEGRITY 1.32 PRIMARY CONTAINMENT INTEGRITY shall exist when: a. All primary containment penetrations required to be closed during accident conditions are either: 1. Capable of being closed by an OPERABLE primary containment automatic is6[ation system, or 2. Closed by at least one manual valve, blind flange, or deactivated automatic valv secured in its closed position, except 4.e a. pecification 3.6.3.b. All primary containment equipment hatches re closed andsealed.

C. Each primary containment air lock is in ompliance with the requirements of Specification 3.6.1.3.d. The primary containment leakage rates re within the limits of Specification 3.6.1.2.e. The suppression chamber is in compli ce with the requirements of Specification 3.6.2.1.f. The sealing mechanism associated wit each primary containment penetration;.

e.g., welds, bellows or O-rings, is OPERABLE.r- -Y -a UN A y"Q TABLE 3.3.2-1 ISOLATION ACTUATION INSTRUMENTATION 0 P4 VALVE ACTUA-TION GROUPS MINIMUM O1 PERABTRLE SYSTEM SIG .PER TRIP SYSTEMa_TRIP FUNCT14ON 1. pRIMAY CONTAIMENT ISOLATION a. Reactor Vessel Water Level 1) Low Low, level 2 2) Low low Low, Level 1 b. Drywell Pressure -High 1, 2, 8, 9, 12, 13, 14, 15, 17, 18 10, 11, 15, 16 1, 8, 9i 10, 11, 12, 13, 14, 15, 16, 17, 18 1, 8, 9, 12 13, 14, 15, 17, 18 1, 8, 9i 10 11, 12, 13, 14, 15, 16, 17, 18 2 2 2 (j)APPLICABLE OPERATIONAL CONDITION 1, 2, 3 1, 2, 3 1, 2, 3 ACTION 20 20 I 20 c. Reactor Building Exhaust Radiation

-digh 3 1 1, 2, 3 28 LO 1.d. Manual Initiation

2. SECONDARY CONTAINMENT ISOLATION a. Reactor Vessel Water Level -Low Low, Level 2 b. Drywell Pressure -High 2 1 9 (c)1, 2, 3 1, 2, 3 and *1, 2, 3 1, 2, 3 and *1, 2, 3 and *1, 2, 3 and *I 24 26 0-rt m--4 0: C. Refueling Floor Exhaust Radiation

-High d. Reactor Building Exhaust Radiation

-High e. Manual Initiation 3 3 1 26 29 28 26 1 9 (c)1 9 (C)

TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION TRIP FUNCTION 3. MAIN STEAM LINE ISOLATION a. Reactor Vessel Water Level -Low Low Low, Level 1 b. Main Steam Line Radiation

-High, High c. Main Steam Line Pressure -Low d. Main Steam Line Flow -High e. Condenser Vacuum -Low f. Main Steam Line Tunnel Temperature

-High g. Manual Initiation

4. REACTOR WATER CLEANUP SYSTEM ISOLATION a. RWCU A Flow -High b. RWCU A Flow -High, Timer c. RWCU Area Temperature

-High d. RWCU Area Ventilation A Temperature-High

e. SLCS Initiation

f. Reactor Vessel Water Level -Low Low, Level 2 g. Manual Initiation VALVE ACTUA-TION GROUPS MINIMUM OPERATE __B ERABLE CHANNELS SIGNALN." PER TRIP SYSTEM(a)1 2 (b)2 2 2 APPLICABLE OPERATIONAL CONDITION 1, 2, 3 1, 2, 30#1 ACTION 21 28 22 20 21 21 1 1 1 1 2/line 2 2/line 1, 1, 1, 2, 3 2**, 3**2, 3 1, 2, 17 2 1, 2, 3 7 7 7 7 I/Valve(e) 1/Valve (e)6/Valve (e)6/Valve (e)1/Valve (e)2/Valve (e)1, 1, 1, 1, 1, i, 2, 2, 2, 2, 3 3 3 3 25 23 23 23 23 23 23 25 7 (f)7 2 2, 3 I 7 1/Valve (e)3/4 3-12 1, 2, 3 HOPE CREEK Amendment No. 166

-r C)r-a W M 4M TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION VALVE ACTUA-TION GROUPS MINIMUM OPERATO PERABLE CHANNEýJ)TRIP FUNCTION SIGNAL' PER TRIP SYSTEM"'5. REACTOR CORE ISOLATION COOLING SYSTEM ISOLATION a. RCIC Steam Line A Pressure 6 I/Valve(e)(Flow) -High b. RCIC Steam Line A Pressure 6 i/Valve(e)(Flow) -High, Timer c. RCIC Steam Supply 6 2/Valve(e)

Pressure -Low d. RCIC Turbine Exhaust 6 2/Valve(e)

Diaphragm Pressure -High e. RCIC Pump Room 6 I/Valve(e)

Temperature

-High f. RCIC Pump Room Ventilation Ducts 6 ]iValve(e)

A Temperature

-High g. RCIC Pipe Routing Area 6 I/Valve(e)

Temperature

-High h. RCIC Torus Compartment 6 3/Valve(e)

Temperature-High

i. Drywell Pressure -High(g) 6 2/Valve(e)

j. Manual Initiation 6 (h) 1/RCIC System APPLICABLE OPERATIONAL CONDITION 1, 2, 3 1, 2, 3 ACTION 23 23 1, 1, 1, 1, 1, 1, 1, 1, 2, 2, 2, 2, 2, 2, 2, 2, 23 23 23 23 23 23 23 25 TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION INSTRUMENTATION VALVE ACTUA-TION GROUPS MINIMUM OPERAT EPERABLE CHANNEj§)TRIP FUNCTION SIGNALFU PER TRIP SYSTEM 6. HIGH PRESSURE COOLANT INJECTION SYSTEM ISOLATION a. HPCI Steam Line A Pressure 5 I/Valve(e)(Flow) -High b. HPCI Steam Line A Pressure 5 I/Valve(e)(Flow) -High, Timer c. HPCI Steam Supply Pressure-Low 5 2/Valve(e)

d. HPCI Turbine Exhaust Diaphragm 5 2/Valve(e)

Pressure.-

High e. HPCI Pump Room 5 1/Valve.e)

Temperature

-High f. HPCI Pump Room Ventilation 5 1/Valve(e)

Ducts A Temperature

-High g. HPCI Pipe Routing Area 5 l/Valve(e)

Temperature

-High h. HPCI Torus Compartment 5 3/Valve(e)

Temperature

-High i. Drywell Pressure -High(g) 5 2/Valve(e)Manual Initiation 5 (i) .I/HPCI system I-APPLICABLE OPERATIONAL CONDITION 1, 2, 3 1, 2, 3 1, 2, 3 1, 2, 3 1, 2, 3 1, 2, 3 1, 2, 3 1, 2, 3 1, 2, 3 1, 2, 3 ACTION 23 23 23 23 23 23 23 23 23 25 0 0 0 Iqq 0 TABLE 3.3.2-1 (Continued)

ISOLATION ACTUATION.

INSTRUMENTATION 0 0z W1 VALVE ACTUA-TION GROUPS -MINIMUM OPERATL9-

'OPERABLE CHANNSTEa TRIP FUNCTIONPER TRIP SYSTEM APPLICABLE OPERATIONAL CONDITION ACTION 7.-l SYSTEM SHUTDOWN COOLING MODE ISOLATION a. Reactor Vessel Water Level -Low, Level 3 b. Reactor Vessel (RHR Cut-in Permissive)

Pressure.-

High c. Manual Initiation 3 (j)3 (J)2/Valve(e) 2/Valve(e) l/Valve(e).

1, 2, 3 1, 2, 3 1, 2, 3 27 27 25 I.0-C)

TABLE 3.3.2-1 (Continued)

NOTES 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 key-locked bypass switch is in the Norm position.The hydrogen water chemistry (HWC) system shall not be placed in service until reactor power reaches 20% of RATED THERMAL POWER.After reaching 20% of RATED THERMAL POWER, and prior to operating the HWC system, the normal full power background radiation level and associated trip setpoints may be increased to levels previously measured during full power operation with hydrogen injection.

Prior to decreasing below 20% of RATED THERMAL POWER and after the HWC system has been shutoff, the background level and associated setpoint shall be returned to the normal full power values. If a power reduction event occurs so that the reactor power is below 20% of RATED THERMAL POWER without the required setpoint change, control rod motion shall be suspended (except for scram or other emergency actions) until the necessary setpoint adjustment is made.(a) A channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required surveillance without placing the trip system in the tripped condition provided at least one other OPERABLE channel in the same trip system is monitoring that parameter.(b) Also trips and isolates the mechanical vacuum pumps.(c) Also starts the Filtration, Recirculation and Ventilation System (FRVS).(d) .. .....V Tcfle 5.5.2-1 Lab.e. .. ta.... fo..t...ist ng Of (e) Sensors arrange per a ve group, not per trip system.(f) Closes only RWCU system isolation valve(s) HV-FO01 and HV-F004.(g) Requires system steam supply pressure-low coincident with drywell pressure-high to close turbine exhaust vacuum breaker valves.(h) Manual isolation closes HV-F008 only, and only following manual or automatic initiation of the RCIC system.(i) Manual isolation closes HV-F003 and HV-F042 only, and only following manual or automatic initiation of the HPCI system.(j) Trip functions common to RPS instrumentation.

HOPE CREEK 3/4 3-16a Amendment No. 166

' TABLE 3.-1.'2-1 (conitinued)

..] ~SOLATWIN ACTUAT ION I NSTRUMENTATION

• " " " " .. TABLE NOTATION" "" is table notation identifies which valves, i.n an actuation groupi, are closed by a particular trip si If 1 valves in the aroup are closed by the trip signal, only the valve group .number will be liste If only c tam valves ir *.he group are closed by the trip signali the valve group number w Il be 1 ed followed in parent.-..ses, a listing of which valves are closed by the trip signal.( " TRIP FUNCTION VALVES CLOSED BY SIGNAL 1. PRIMARY CONTAINM ISOLATION a. Reactor Vessel Wat Level -1) Low Low, Level 2, 8, 9, 12, 1 14, 15 (IIV-5154, HV-5155), 17, 18 2) Low Low LOW, Level 10, 11, 15 -5126 A&B, HV-5152 A&B, IIV-5147, IVIV-5148 V-5162), 16' b. Drywell Pressure -Hgh 10, 1i, 12, 13, 14, h5, 16,q 1h, 18 c. Reactor Building Exhaust Radiation 8, 9, 12, 13, 14, 15, 17 (fIV-5161), 18" 4 k d. Manual Initiation 8, 10; 11, 12, 13, 14, 15,..16, 17 (HV-5161), 18 2. SECONDARY CONTAINMENT ISOLAT> a. Reactor Vessel r Level-fC Low Low, Leve 19 r b. Drywe ressure. -High 19 L4 C. efueling Floor Exhaust Radiation

-High 19 d. Reactor Building Exhaust Radiation

-High 19 O.ECREEe.

• Manual .Initiation 19" HOPE CREEK 3/4 3 1J7 ,,,,,,.,.r,.134

• ~~TABLE 3.-3'1" ýCont inued)ISOL.ATION ACTUATION INSTRUMENTATION TABLE NOTATION TRIP FUNCTION VALVES CLOSED BY SIGNAL 3. MAIN STEAM LINE ISOLATION.a. Reactor Vessel Water Level 1 (HV-F022A, B, C & D, HV-F02f3 B, C & D, L Low Low, Level 1 IIV-F016, HV-FO19)b. Main Stea -e Radiation

-iligh, High 2 c. Main Steam Line P sure -Low I (as above)d. Main Steam Line Flow -H~i( as o e. Condenser Vacuum -Low (as above)f. Main Steam Line Tunnel I (as above)Temperature

-High g. Manual Initiation I (as abo 2, 17 (SV-J004A-1, 2, 3, 4 & 5)4. REACTOR WATER CI £-NUP ISOLATION a. RWCU A Flo Higgh b. RW Flow- High, Timer RWCU Area Temperature

-High 7 H OPE CREEK 3/4 3-18 Amendment No. 134 0* 0.

TABLE 3.3.2-1 .(Continued)."ISOLATION ACTUATION*

INSTRUMENTATION r n\ TABLE NOTATION TRIP VALVES CLOSE Y SIGNAL d. RWCU Ar aVentilation" 7 A.Temp~erat e'- High*e. SLCS Initiatio

" f. Reactor Vessel Wate evel 7 Low Low, Level 2 g. Manual Initiation

-7 5. REACTOR CORE ISOLATION COOLING SYS ISOL ON a. RCIC Steam Line A Pressure (Flow,/- IH.qh 6 (HV-F007, HV-F076, HV-FO08)b. RCIC Steam Line A PressUre w) -High,>Kimer 6 (HV-FO07, HV-F076, HV-F008)c. RCIC Steam Supply Pressure/-

Low 6 d. RCIC Turbine Exhaus 6HV-FOO7, HV076, HVF008)Diaphragm Pressur- High F, e. RCIC Pump Roo Temperature-High 6 (HV-FbO7 HV-F076, HV-FO08)f. RCIC Pum /Room Ventilation-Ducts 6 (HV4F007, HVzF076, HV-FO08)A Tenipefature -HighN g. RW Pipe Routing Area 6 (HV-FO07, HV-F0768 V-FOOB)Tlemperature

-High RCIC Torus Compartment Temperature -High 6 (HV-F007, HV-FO76, FIV-FOO M TABLE NOTATION TRIP FUNCTION VALVES CLOSED BY SIGNAL i. Dry1e1 Pr ure -High 6 (WV-F062, HV-F084)j. MnualInitatio6 (HV-F008)6. HIGH PRESSURE COOLANT INJECT a. HPCI Steam Line A Pressure (Flo -High 5 (HV-F 2,HV-FIOO, HV-F003, HV-F042)Cab. HPCI Steam Line A Pressure (Flow) -,Timer 5 V-F002, HV-F100, HV- .F003, HV-F042)-S.C. HPCI Steam Supply Pressure -Low5 d. HPCI Turbine Exhaust (HV-F002, HV-F100, HV-F003, HV-F042)Diaphragm Pressure -High e. HPCI Pump Room Temperature

-5 (HV-FOOk HV-F100, HV-F003, HV-F042)oN f. HPCI Pump Room Ventilatio.

Ducts 5 (HV-F002, HV~- 10,HV-F003, HV-F042)a Temperature

-.High g. HPCI Pipe Routi Area 5 (HV-F002, HV-F100, HV,' 003, HV-F042)Temperature igh ii. HPCI T us Compartment Temperature -High 5 (HV-F002, HV-F100, HV-F003, Hi 042)1. yell Pressure -High 5 (HV-F075j HV-F079)Manual Initiation 5 (HV-F003, HV-F042)0 HOPE CREEK 3/4 3-21 Amendment No. 15 2 3/4.6 CONTAINMENT SYSTEMS W- 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 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.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 Leakage Rate Testing Program.b. At least once per 31 days by verifying that all primary containment penetrations**

not capable 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, excep -.- -3 1 o Specification 3.6.3.C. By verifying each primary containment air lock is in ompliance with the requirements of Specification 3.6.1.3.d. By verifying the suppression chamber is in complianc with the~requi ements 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.

Thesepenetrations 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.e HOPE CREEK 3/4 6-1 Amendment No. 104 CONTAINMENT SYSTEMS PRIMARY CONTAINMENT LEAKAGE LIMITING CONDITION FOR OPERATION 3.6.1.2 Primary containment leakage rates shall be lizite to: a. An overall integrated leakage rate "Type A test- in accor' nce wi~: ::-e Primary Containment Leakage Rate Testing ?rogram.c. *Less than or equal to 150 scfh per mai.n steam line and less thana. or equal to 250 scfh combined through all four main steam lines when tested at 5 psig (leakage rate corrected to 1 Pat, 48.2 psig)d. A combined leakage rate of less than or equal to a0 gpm for all containment isolation valves which form the boundary for the long-term seal of the feedwater f mness ma.n s, when tested at 1.10 Pa, 52.9 psig.e. A combined leakage rate of less than or equal to 10 gpm for all other penetrations and containment isolation valves in hydrostatically tested lines .... .which penetrate the primary containment, when 6 tested at 1.10 Pa, 52.9 psi g Ap.AP.....CA...

W.en PRI-A.RY CONTA'MENT IN:EGRT:Y is required per Specification 3.6.1.1.ACTION1ý: With: a. The measured overall integrated primary containment leakage rate (Type A test) not in accordance with the Primary Containment Leakage Rate Testing Program, c b. -M asured ýcoirmbi~ned leaekage rate for all penetrations and all valves listed in..-,ecept frmain steam line isolation v 'valives which for. the ry for the long-tr elo h e.e lines, and other valves which areny,ý,a~t:ica tested per Table 36 1, subject -to Type B and C tests not in accor an '~h ýthe Primary Containment Leakage Rate Testing Program, or C.The measured leakage rate exceeding 150 scffh per main steam line or exceeding 250 scfh combined through all four main steam lines, or*Exemption to Appendix "Y of 10 CFR 50.,%HOPE CREEK 3/4 6-2 6Amendment No. 134 CONTAINMENT SYSTEMS LIMITING CONDITION FOR OPERATION ACTION (Continued)

d. The measured combined leakage rate for all c~n:ginment isolation valves which form the boundary for the long-tern seal of the feedwater lines in Table 3.6.3-1 exceeding 10 gpm, or e. The measured combined leakage rate for all ocher pene:rations and containment isolation valves in hydrostatically tested lines in Table 3.6.3-1 which penetrate the primary containment exceeding i0 gpm, restore: C a. The overall integrated leakage rate(s) (Type A test) be in accordance with the Primary Containment Leakage Rate Testing Prog am, and b.

rate for all penetrations and all valves listed in oher valves which are hydrostatical'ly st.ed-perTable 3.6.3-1, subject Leakage Rate Testing Program, and C. The leakage rate to less than or equal to 150 scfh per main steam line and less than or equal to 250 scfh combined through all four main steam'lines, and d. The combined leakage rate for all containment isolation valves which form the boundary for the long-term seal of the feedwater lines in Table 3.6.3-1 to less than or equal to 10 gpm, and e. The combined leakage rate for all other penetrations and containment isolation valves in hydrostatically tested lines in Table 3.6.3-1 wnhch penetrate the primary containment to less than or equal to 10 gpm., prior to increasing reactor coolant system temperature above 200 0 F.SURVEILLANCE REQUIREMENTS 4.6.1.2.a The primary containment leakage rates shall be demonstrated in accordance with the Primary Containment Leakage Rate Testing Program for the following:

1. Type A test.2. Type B and C tests (including air locks).b. DELETED.c. DELETED.*

• Exemption to Appendix "J" of 10 CFR 50.HOPE CREEK 3/4 6-3 Amendment No. 134 SURVEILLANCE REQUIREMENTS (Continued)

d. DELETED.d. DELETED.e. DELETED.f. Main steam line isolation valves shall be leak tested at least once per 18 months.g. Containment isolation valves which f kksboundry for the long-term seal of the feedwater lines. a.9.0- --,hall be hydrostatically tested at 1.10 Pa, 52.9 at least once per 18 months.h. All containment isolation valves in hydrostatically tested lines () vhich penetrate the primary containment shall be leak tested at least once per 18 months.i. DELETED.DELETED.I HOPE CREEK 3/4 6-4 Amendment No. 104 CONTAINMENT SYSTEMS 3/4,6.3 PRIMARY CONTAINMENT ISOLATION VALVES LIMITIN-CNDITIONi FOR OPERATION.. a _.._.. " 3.6.3 a& rlmary; containment iso tia I $tte actor instrumentation APPLICABILITY:

OPERATIONAL CONDITIONS 1, 2 and 3.ACTION: a. 4o e..omre of the primary containment isolation valves c , inoper maintain at least one isolation valve-OFBLE nsac aTected penetration that is open and within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either: 1. Restore the inoperable valve(s) to OPERABLE status, or 2. Isolate each affected penetration by'use of at least one deactivated automatic valve secured in the. Isolated posi ti on,* or 3. Isolate each.:affected'penetration by use of at least one closed manual valve oriblind flange.*4. The provisions of Specification 3.0.4 are not applicable provided that within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> the 'affected penetration is isolated in accordance with ACTION a.2. or a.3. above, and provided that the associated system, if applicable, is declared inoperable and the appropriate ACTION statements for that system are performed.

Otherwise, be in at least.HOT SHUTDOWN within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.'b. With one-or rInstrumentation line excess flow check valves 6..-li inoperable, operation may continue and the provisions of SpecifiiatonWs 3.0.3 and 3.0.4 are not applicable provided that within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> either: 1. Tk^ inoperable valve is returned to OPERABLE status, or 2. The instrument line is isolated and the associated instrument is declared inoperable.

OtherOWise, be in at least HOT SHUTDOWN within the next 1.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and in COLD SHUTDOWN within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.W*solahton'valves closed to satisfy these requirements may be reopened on an intermittent basis under administrative control..HOPE CREEK 3/4 6-17 L_ _. .

CONTAINMENT SYSTEMS SURVEILLANCE REQUIURENTS 4.6.3.1 Each primary containment isolation valve I.shall be demonstrated OPERABLE prior to returning to Be ce-after maintenance, repair 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.,kj4 j Each primary containment automatic isolation valve l ehall be demonstrated OPERABLE at least once per 18 monthi-b v :ing that on a containment isolation test signal each automatic isolation valve actuates to its isolation position.4.6.3.3 The isolation time of eac imary containment power operated or automattic valve shall be detepmined to be within its limit when teste pursuan o pec fication 4.0.5.4.6.3.4 At least once per 18 months, verify that a _r esentative reactor instrumentation line excess flow check valve .i l- ..-actuates to the isolation position on a simulated instrument linebrea signal.4.6.3.5 Each traversing in-core probe system explosive isolation valve shall be demonstrated OPERABZE*:

L. At least once per 31 days by verifying the continuity of the explosive charge.b. At least once per 18 months by removing the explosive squib from at least one :explosive valve such that each explosive squib in each explosive valve will be tested at least once per 90 months, and initiating the explosive squib. The replacement charge 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 applicable.

Exemption to Appendix J of 10 CFR Part 50.HOPE CREEK 3/4 6-18 Amendment No. 155 TABLE 3.6.PRIMARY CONTAINMENT ISOLATION VALVES PENETrRATION NUMBER MAXIMUM ISOLATION TIME (Seconds)P&ID 1. Group (a)(H::? '," )M-4 1-1 Inside: Line Line Line Line A B C D 11V- EO2YA P-tIýh flV-FOY2FI1 (A r-4 IIV-F02.2C (AIl-VOr)6, IIV-F022D (AB-VO.31)

P1 5 5 5 5 1 I 1 Outside: Line Line Line Line A B C D FIV-F028B

(, IIV-F028C L~5 5 5 5 I 1 PIC PID (b)Irain Isolation M-41-1 Inside: P12 30 3 I HIV-F019 (AB-V040)P12 30 TA (,iE5 -3 /4 3/c4 (a ..c4- ýrk A -1 k 0 0 A 3/4 6-19 A~~~l~r~(~I~14

.134 hOPE CREEK TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM PFNETRATION ISOLATION TIME VALVE ANDNU NUMBER (Seconds)

NOTE(S) P&_1)2. Group 2 -Reactor Recirculation Water- mple System (a) Reactor Recirculation Water Sample Line ation Valves M-43 Inside;1 B-SV-4310 P17 1 3 Outside: BB-SV-4311 1 15 3 3. Group 3 -Residual Heat Removal (UIIR) System (a) RJIR Suppression Pool Cooling Water & System Test Isolation Valves M-5]Outside: Loop A: HV-Is -4A (BC-V124)

P212B 180 HV-11 OA (BC-V125)

P212B 180 Outside: Loop B: HV-F024B (BC-V028)

P212A 180 1]HV-F010B (BC-V027)

P212A 180 1](b) RHR to Suppression Chamber Spray fleader Isolation Valves M-5 Outside: Loop A: HV-F027A (BC-Vll2)

P214B 75 3 Loop B: HV-F0278 (BC-V015)

P214A 75 3 HOPE CREEK 3/4 6-20A-I-1 No. 134 0 TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT (c) RHR Shutdown Co Suction Isolation Valve Outside: HV-F7008 (BC-VI (d) RHR Shutdown Cooling Return Isolation Valves Outside: Loop A: HV-FO15A (BC-V110)Loop B: HV-F01 5B (BC-V01 3)4. Group 4 -Core Spray System Outside: (a) Core Spray Test to Suppression Pool Isolation Valves Loop A: HV-FO15A (BE-V025)Loop B: HV-F015B (BE-V026)5. Group 5 -High Pressure Coolant Injection (HPCI) System (a) HPCI Turbine Steam Supply Isolation Valves Inside: HV-F002 (FD-V001)HV-F100 (FD-V051)Outside: HV-F003 (FD-V002)(b) HPCI Pump Suction Isolation Valve Outside: HV-F042 (BJ-V009)SOLATION VALVES PENETRATION NUMBER MAXIMUM ISOLATION TIME (Seconds)45 NOTE(S) P&ID M-51-1 3 M-51-1 J P4B 45 3 P4A 45 3 M-52-1 P217B 80 11 P217A 80 11 M-55-1 PT NA 3 P7 NA 3 P7i NA 3 M-55-1 P292 NA 11 Amendment No. 152 1 HOPE CREEK 314 6-21 TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES PENETRATION Np ri VALVE FUNCTION ANDNUR NUMBER (c) HPCI Turbine Exhaust Isolation Valve to Vacuum Breaker Network Outside: HV-F075- (FD-VO07)

P201/P204 (d) HPCI nd RCIC Vacuum Network Isolation Valve Outside: HV-F079 (FD- 204/P201 6. Group 6 -Reactor Core Iso Cooling (RCI System (a) RCIC Turbine Steam Supply Isolati yes Inside: HV-F007 (FC-VO01)HV-F076 (FC-V048)

Pl1 Outside: HV-FO08 (FC-VO02)

P11 (b) RCIC Turbine Exhaust Isolation Valve to Vacuum Breaker Network Outside: HV-F062 (FC-VO06)

P207/P204 (c) HPCI and RCIC Vacuum Network Isolation Valve Outside: HV-F084 (FC-VO07)

P204/P207 7. Group 7 -Reactor Water Cleanup (RWCU) System (a) RWCIU Supply Isolation Valves Inside: HV-FOO1 (BG-VO01)

P9 Outside: HV-F004 (BG-VO02)

P9 MAXIMUM ISOLATION TIME (Seconds)NA M-55-1 NA 3 M-49-1 NA 3 NA 3 NA 3 M-49-1 NA 4 M-49-1 NA 4-1 NOTE(S) P&ID M-55-1 4 45 45 3 3 S TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM ISOLATION PENETRATION TIME VALVE ON AND NUMBER NUMBER (Seconds)

NOTE(S) P&ID 8. Group a rus Water Cleanup (TWC) System (a) THC Suction tion Valves M4-53 Outside: KV-4680 (EE-V003)

P223 45 4 HV-4681 (EE-V004)

P223 45 4 (b) THC Return Isolation Valves M-53 Outside: KV-4652 (EE-V002)

P222 45 4 HV-4679 (EE-V001)

P222 45 4 9. Group 9 -Drywell Sumps (a) Drywell Floor Drain Sump Discharge Isolation Valves M-61 Inside: HV-F003 (HB-VO05) 3023 Outside: HV-F004 (HB-V006)

P25 30 3 Inside: IBBPSV-11701 P25 MA 3 (b) Drywell Equipment Drain Sump Discharge Isolation Valves M-61 Inside: HV-F019 (HB-V045)

P26 Outside: HV-F020 (HB-V046)

P26 3 Inside, 1HBPSV-11702 P26 A 3 10. Group 10 -Drywell Coolers (a) Chilled Water to Drywell Coolers Isolation Valves M-87 Inside: Loop A: KV-9531BI (GB-V081)

PSB 60 3 Loop B: HV-9531B3 (GB-V083)

P38A 60 3-1-l-1 I-1 I.-1 HOPE CREEK 3/4 6-23 Amendment No. 102 TABLE 3.6.3-1 (Continued) iii PRIMARY CONTAINMENT ISOLATION VALVES M MAXIMUM PENETRATION ISOLATION TIME VALVE FINCTION AND NUMBER (Seconds)

NOTE(S) P&ID Outside: Loop A: N- (GB-V048)

PBB 60 3 Loop B: WV-953 P36A 60 3 (b) Chilled Water from Drywell Cooler n Valves N-87-1 Inside: Loop A: NV-9531B2 (Ga-V082)

P-A 60 3 Loop B: HV-9531B4 (GB-V084) 380 60 3 Outside:.0 Loop A: HW-9531A2 (Ga-V046)

PSA 60 3 4" Loop B: HV-9531M (GB-V071)

P388 60 3 11. Group 11 -Recirculation Pump System (a) Recirculation Pup Seal Water Isolation Valves N-43-1 Outside: Loop A: HV-3800A (BF-V098)

P39 3 Loop B: WV-380OB (SF-V099)

P20 45 3 12. Group 12 -Containment Atmosphere Control System (a) Drywall Purge Supply Isolation Valves M-57-1I Outside: WV-4956 (GS-VO09)

P21 5 3, 8 WV-4979 (GS-V021)

P22/220 5 3. 8 (b) Orywall Purge Exhaust Isolation Valves M -1 Outside: MV-4951 (GS-V025)

P23 15 3 HV-4950 (GS-V026)

P23 5 3, 8 NV-4952 (GS-V024)

P23 5 3, 8 A. a 10 I , I .TABLE 3.6.3-1 (Continued)"o a rn in S I-ob PRIMARY CONTAINMENT ISOLATION VALVES PENETRATION VALVE FUNTION AND ___ ___ __BER (c) Suppression C Purge Supply Isolation Valves Outside: HV-4980 (GS-V020) 2/PO HV-4958 (GS-V022)(d) Suppression Chamber Purge Exhaust Isola Outside: HV-4963 (GS-V076)HV-4962 (GS-V027)NV-4964 (GS-V028)

P219 (e) Nitrogen Purge Isolation Valves Outside: HV-4974 (GS-VO53)

J70/J202 HV-4978 (GS-V023)

P22/P220 13. Group 13 -Hydrogen/Oxygen (112/02) Analyzer System (a) Drywell H2/02 Analyzer Inlet Isolation Valves Outside: Loop A: HV-4955A (GS-V045)

JBE HV-4983A (GS-V046)

J9E HV-4984A (GS-V048)

JlOC HV-5019A (GS-V047)

JiOC Outside: Loop B: HV-4955B (GS-V031)

J38 HV-4983B (GS-V032)

J3B HV-4984B (GS-V034)

J7D/J202 HV-5019B (GS-V033)

J7D MAXItMU ISOLATION TIME (Seconds)5 5 NOTE(S) P&ID N-57-1 3, 8 3, 8 I M-57-1 15 3 5 3, 8 5 3,8 14-57-1 45 3 5 3, 8 M-57-1 45 3 45 3 45 "3 45 45 3 45 3 45 3 45 3 ai TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES 4*05 N IMAX I PJM PENETRATION ISOLATION TIME FUNCTION NUMBER VALVE (Seconds)

NOTE(S) P&(b) Suppres Chamber 112/02 Analyzer Inlet Isolation es M-!Outside: Loop A: HV-4965A OS-V0J212 45 3 HV-4959A (GS-VJ212 45 3 Outside: Loop A: (V-49650 (GS-VO41) 45 3 HV-4950" (GS-V040) 210 45 3 ()112102 Analyzer Return to Suppressoion Chamber Isolation Valves kM-Outside: Loop A: HV-4966A (GS-V041) 45 3 WV-5022A (GS-VOS2)

J201 45 3 Outside: Loop A: HV-4965 8 (GS-V002)

J202 45 3 HV-502A (GS-V043)

J202/J73 45 3 14. Group 14 -Containment Hydrogen Recombination (CHR) System (a) CHIR Supply Isolation Valves -Outside: Loop A: NV-SOSOA (GS-VO02)

P23 45 3 WV-5052A (GS-V003)

P23 45 3 Outside: Loop B: WV-SOS (GS-VO04)

P22 45 3 WI*S52Bn (GS-VOO5)

P22 45 3 (b) CHR Return Isolation Valves H-'Outside: Loop A: HV-5053A (GS-VO08)

P220 45 HV-5054A (GS-V01O)

P220 45 3 ID 57,1I 57- 1 18-1 58-1l x C, a PI TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES PENETRATION MAXIMUM ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds)

NOTE(Outside: 8: HV-5053B (GS-VO06)

P219 45 3 HV-5054B (GS-VO07)

P219 45 3 15. Group 15 -Prima tainment Instr t Gas System (PCIGS)(a) PCIGS Drywell Supply Header ti Valves Inside: Lotp A: HV-5152A (KL-V028)

P288 45 3 Loop B: HV-5152B (KL-V026)

P28A 45 3 Outside: Loop A: HV-5126A (KL-V027) 45 3 Loop B: HV-5126B (KL-V025) 45 3 (b) PCIGS Drywell Suction Isolation Valves Inside: HV-5148 (KL-VOO1)

P39 453 Outside: Loop A: HV-5147 (KL-VO02)

P39 3 Loop B: HV-5162 (KL-V049)

P39 45 3 (c) PCIGS Suppression Chamber Supply Isolation Valves Outside: HV-5154 (KL-VO18)

J211 15 3 HV-5155 (KL-VO19)

J211 15 3 S) P&ID M-58-1 M-59-1 M-59-1 M-59-1 TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM ISOLATION PENETRATION TIME_VLVE FUNCTION AND NUMBER NUMBER (Seconds)

NOTE(SW P&ID 16. Group 6 -Reactor Auxiliaries Cooling System (RACS)(a) RACS S ly Isolation Valves M-13-1 Inside: -2554 (ED-V020)

P29 45 3 Outside: HV- 3 (ED-V019)

P29 45 3 Inside: iEDPS 1699 P29 NA 3 (b) RACS Return Isolat lves M-13-1 Inside: HV-2556 (ED- P30 45 3 Outside: HV-2555 (ED-V021)

P30 45 3 Inside: IEDPSV-11700 P30 NA 3 17. Group 17 -Traversing In-core Probe (TIP) m (a) TIP Probe Guide Tube Isolation Valves KM-59-1 Outside: SV-JO04A-l (SE-V026)

P34A 15 3 SV-JO04A-2 (SE-V027)3 P34B i 3 SV-JO04A-3 (SE-V028) 334C i 3 SV-JO04A-4 (SE-V029)

D 15 3 SV-JO04A-5 (SE-V030) 15 3 (b) TIP Purge System Isolation Valve M-59-1 Outside: HV-5161 (SE-V004)

P34F 15 3 18. Group 18 -Reactor Coolant Pressure Boundary (RCPB)Leakage Detection System (a) Drywell Leak Detection Radiation Monitoring System (DLD-RMS)Inlet Isolation Valves M-25-1 Outside: HV-5018 (SK-V005)

JBC 45 HV-4953 (SK-V006)

JaC 45 3 HOPE CREEK 3/4 6-28 No. 102 S 0 TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM PENETRATION ISOLATION TIME NUMBER (Seconds)

NOTEW(S VALVE FUNCTION AND NUMBER (b) DLD-RMS Return Isolation Valves-497.(SK-V00S)

B. Remote Manual Isolat lves 1. Group 21 -Feedwater Sys.(a) Feedwater Isolation Valves Outside Check Valves HV-F032B (AE-VO01)HV-F032A (AE-V005)(b) Reactor Water Cleanup System Return Outside: HV-F039 (AE-V021)2. Group 22 -High Pressure Coolant Injection (HPCI) Syc (a) Core Spray Discharge Valve Outside: HV-F006 (BJ-V001)(b) Turbine Exhaust Valve Outside:'HV-F071 (ED-VO06)(c). HPCI Minimum Return Line Valve Outside: HV-F0i2 (BJ-V016)(d) Feedwater Line Discharge valve Outside: HV-8278 (BJ-V059)3. Group 23 -Reactor Core isolation Cooling (RCIC) System (a) RCIC Turbine Exhaust Valve Outside: HV-F059 (FC-V005)M-25-1 J5A J5A 45 45 3 3 M-4i-I P2A P2B NA NA 2 2 P2A&B NA 2 M-44-1I item .P5B NA 3 M-55-rýP201 M-55-1 P207 NA 4 M- -1 Amendment No.HOPE CREEK 3/4 6-29 I TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM ISOLATION PENETRATION TIME VALVE AND NMBE NUMBER (Seconds)

NOTE(S) P&ID Wc) RCIC Mimum Reton Isolatione aIv HV-F031 (BD- P208 NA 11 M-49-1 Outside: (c) RCIC Minimum Return Line Valve SV- F019 P209 NA 11 M- 49 -1 outside : (d) RCIC Vacuum Pump Discharge HV-F060 (PC-V011)

P210 NA 4 M-49-1 (e) Feedwater Line Discharge Valve Outside: HV-F013 (BD-VO05)

P2A NA 2 M-49-1 4. Group 25 -Core Spray System (a) Core Spray injection Valves 1M-52-1 Outside: Loop A&C HV-FOO5A (BE-VO07) p5- N 3 Loop B&D MV-0o5B (BE-Vo03)

P5A N (b) core Spray Suppression Pool Suction Valves M-52-1 Outside: Loop A HV-FO0lA. (BE-VOl?)

P216D NA 11 Loop B 9V-PO0lS (BE-V019)P26NA1 Loop C HV-FO0lC (BE-Vole)

P216C NA Loop D HEV-FO0lD (BE-V020)

P216D N (c) Cre Spray Minimum Flow ValvesM Outside: Loop A&C KV-PO31A (BE-V035)P27NA 1 Loop R&D HV-FO31B (BE-V036)

P217A NA 11 HOPE CREEK 3/4 6-30 AMENDMENT NO. 93 I 0 0 0 TABLE 3.6.3-I (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM ISOLATION PENETRATION TIME VALVE FUNCTION AND NUBEg. NUMBER (seconds)

NOTE(S) P&ID 5. Group 26 -Resid 1 eat Removal System (a) Low Pressure ant Injection Valve N-51-1 Outside: Loop A.- V-FO17A V113) PSC NA 3 Loop B: HV-F017B (BC- P6B NA 3 Loop C: KV-FO17C (BC-Vo1l P6D NA 3 Loop D; HV-FO17D (BC-V004)

P6A NA 3 (b) RHR Containment Spray M-51-1 Outside: Loop A: HV-F021A (BC-V116)

P24B NA 3 Loop B: HV-F021B (BC-V019)

P24A NA 3 (c) RHR Suppression Pool Suction M-51-1 Outside: Loop A: HV-F004A (BC-V103)

P2 NA i1 Loop B: HV-FO04B (BC-V006)

P21 NA 11 Loop C: HV-F004C (BC-V098)

P211D NA 11 Loop D: HV-FO04D (BC-V001)

P211A NA 11 (d) RHR Minimum Flow Isolation Valves KM-51-1 Outside: Loop A: HV-FO07A (BC-V128)

P212B NA Zl Loop B: HV-FO07B (BC-V031)

P212A NA 1.Loop C: HV-FO07C (BC-Vl31)

P212B NA 11 Loop D. HV-PO07D (BC-V034)

P212A NA HOPE CREEK 3/4 6-31 AMENDMENT NO. 93 TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM ISOLATION TIME (Seconds)PENETRATION NUMBER VALVE FUNCTION AND NUMBEF 6. Group 27 -St y Liqu Outside: NOTE (S)P&ID M-48-1 I d Control HV-FO06B (BH-V054)7. Group 28 -Containment.

Atmosphe Suppression Chamber Vacuum Relief Outside: HV-5031 (GS-V038)HV-5029 (GS-V080)8. Group 69 -TIP System Explosive Shear Valves Outside: SE-XV-J004Bl (SE-V021)SE-XV-J004B2 (SE-V022)SE-XV-J004B3 (SE-V023)SE-XV-J004B4 (SE-V024)SE-XV-J004B5 (SE-V025)P18 NA 3 PIS NA 3 M-57-1 P220 NA 3 P219 NA 3 M-59-1 P34A NA 7 P34B NA 7 P34C 7 P34D 7 P34E NA 7 HOPE CREEK 3/4 6-32 0 AMENDMENT o.09 3 I TABLE 3.6.3-1 (Continued) a PRIMARY CONTAINMENT ISOLATION VALVES m MMAXIMUM rn PENETRATION ISOLATION TIME VALVE FUNCTION NUMBER (Seconds)

NOTE(S) P&ID 9. Group 29 -HC tem Suppression Pool Instrumentation Isolation M-55-1HV-4803 (BJ-VSO0)

NA 6 HV-4804 (BJ-VS01)

NA 6 HV-4865 (BJ-VS02)

J2 NA 6 HV-4866 (BJ-V503)

J21 NA 6 10. Group 30 -Post-Accident Sampling System Liquid Sampling M-38-0 Outside: C RC-SV-0643A P227 NA 3 RC-SV-0643B P227 NA 3 RC-SV-8903A J50 3 RC-SV-8903B J50 3 Gas Sampling M-38-0 Outside: RC-SV-0730A J7E NA 3 RC-SV-0730B J7E NA 3 RC-SV-0731A JIOE NA 3 RC-SV-0731B J1OE NA 3 RC-SV-0728A J206 NA 3 RC-SV-0728B J206 NA RC-SV-0729A J221 NA RC-SV-0729B J221 NA 3 RC-SV-0707A J220 NA 3 RC-SV-0707B J220 NA 3 0-o m1 TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES PENETRATION MAXIMUM ISOLATION TIME (Seconds)VALVE FUNCTION AND NUMBER NUMBER C. Primary Containment O-ther isolation Valve 1. Group 31 -Feedwater em (a) Feedwater Isolation Valv Inside Check Valves AE-VO03 AE-VO07 Outside Check Valves (Air Assisted)MV-F074B (AE-VO02)

P2A HV-F074A (AE-VO06)

P2B 2. Group 32 -Standby Liquid Control System Inside Check Valve BH-V029 P18 3. Group 33 -Primary Containment Atmosphere Control System Containment Vacuum Breakers Outside: GS-PSV-5032 P220 GS-PSV-5030 P219 4. Group 34 -Service Air System Outside KA-V038 P27 Inside KA-V039 P27 NOTE(S) P&ID M-41-1 NA 3 NA 3 NA 3 NA 3 3 NA 3 NA 3 NA NA 3 M-48-1 M-57-1 M-15--0 TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds)

NOTE(S) P&ID 5. Group 35 -Meathing Air System M-15-1 Inside -V016 P31 NA 3 outside V034 P31 NA 3 6. Group 36 -TIP P System Inside : Check Valve: _V006 P34F NA 3 M-59-1 7. Group 37 -HPCI System Outside: HPCI Turbine Exhaust: 4 P201 NA 4 M-55-1 8. Group 38 -RCIC System Outside: RCIC Turbine Exhaust: FC-V003 P207 NA 4 M-49-1 Vacuum Pump Discharge:

FC-V010- P210 NA 4 M-49-1 9. Group 39 -RHR System (a) Thermal Relief Valves 14-51_1'Outside: -Loop A: BC-PSV-F025A P212B NA 5 Loop B: BC-PSV-F025B P212A- NA 5 Loop C: BC-PSV-F025C P212B NA 5 Loop D: BC-PSV-F025D P212A NA 5 (b) Jockey Pump Discharge Check Valves M-51-4 Outside: Loops A &C: (BC-V206)Loops B & D: (BC-V260)(c) RHR Heat Exchanger Thermal Relief Valves M--Outside: BC-PSV-4431A EC-PSV-4431B3 P23 No HOPE CREEK 3/4-3 Amendment No. 76 i TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM ISOLATION TIME (seconds)VALVE 1CIN UMBmERR (d) RHR SUP ssion Pool Return Valves i0. Group 40 -Core Spray System Thermal Relief Valves Outside: Loop A&C: HE-PSV-F112A Loop B&D: BE-PSV-F012B

11. Group 41 -Drywell Pressure Instrumentation Outside: BB-V563 BB-V564 BB-V565 BB-VS66 PENETRATION NUMBER P212B P212A NOTE (SI P&ID M-51-1 I NA 11 NA 11 M-52-1 I P217B NA 5 P217A NA 5 M-42-1 NA 6 JýD NA 6 J7A NA 6 J10D NA 6 HOPE CREEK 0 3/4 6-36 0 AMENDMENT NO: 93 I 0 TABLE 3.6.3-1 (Continued)

C-rlq m m PRIMARY CONTAINMENT ISOLATION VALVES VALVE FUNCTION AND NUMBER 12. Group -Intergrated Leak Rate Testing System PENETRATION NUMBER MAXIMUM ISOLATION TIME (Seconds)NOTE(S) P&ID M-60-1 Outside GP-V Inside GP-V120 Outside GP-V122 Outside GP-V104 Outside GP-VO05 13. Group 43 -Suppression Chamber Pressure Outside GS-V044 GS-V087 J360 J36D J36C J 36C.J209 NA NA NA NA NA NA NA NA 3 3 3 3 3 3 6 6 M-57-1 CA)14. Group 44 -Chilled Water System Thermal Relief Valves Inside GB-PSV-9522A P88 GB-PSV-9522B P38A GB-PSV-9523A P8A GB-PSV-9523B P38B 15. Group 45 -Recirculation Pump Seal Purge Line Check Valves Inside BB-V043 P19 BB-V047 P20 D. Excess Flow Check Valves NA 3 NA 3 NA 3 NA 3 NA 3 NA 3 NA 10 NA 6 NA 6 NA 6 NA 6 M-87-1 M-43-1 M-41-1 1. Group 46 -Nuclear Boiler Outside BB-XV-3649 AB-XV-3666A AB-XV-3666B AB-XV-3666C AB-XV-3666D J5C J25A J26A J27A J28A TABLE 3.6.3-1 (Continued) 0 PRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM M m PENETRATION ISOLATION TIME VALVE FUNCTION A UMBER NUMBER (Seconds)_

NOTE(S) P&ID Outside M-41-1 AB-XV-3667A J22A NA 6 AB-XV-3667B J22C NA 6 AB-XV-3667C J21A NA 6 AB-XV-3667D 21 NA 6 AB-XV-3668A 2B NA 6 AB-XV-3668B NA 6 AB-XV-3668C E NA 6 AB-XV-36680 NA 6 AB-XV-3669A NA 6 AB-XV-3669B J26 NA 6 AB-XV-3669C J27D NA 6 AB-XV-36690 J28D NA 6 C2. Group 47 -Nuclear Boiler Vessel Instrumentation M-42-1 Outside BB-XV-3621 J3A NA 6 BB-XV-3725 J2C 6 BB-XV-3726A J1350 6 BB-XV-3726B J1353 6 BB-XV-3727A J44 NA 6 BB-XV-3727B J41 NA 6 BB-XV-3728A J1351 NA 6 BB-XV-3728B J1354 NA 6 BB-XV-3729A J51 NA 6 BB-XV-3729B J42 NA 6 BB-XV-3730A J52 NA 6 BB-XV-3730B J43 NA BB-XV-3731A J1352 NA BB-XV-3731B J1355 NA 6 BB-XV-3732A J37A NA 6 BB-XV-3732B J11A NA 6 BB-XV-3732C J24E NA 6 0 TABLE 3.6.3-1 (Continued) 0 mPRIMARY CONTAINMENT ISOLATION VALVES mMAXIMUM m PENETRATION ISOLATION TIME VALVE FUNCTIONANNUMBER NUMBER (Seconds)

NOTE(S) P&ID Outsi M-42-1 BB-XV-373 J11B NA 6 BB-XV-3732E J37C NA 6 BB-XV-3732F J40C NA 6 BB-XV-3732G 7D NA 6 BB-XV-3732H NA 6 BB-XV-3732J NA 6 BB-XV-3732K NA 6 BB-XV-3732L NA 6 BB-XV-3732M NA 6 BB-XV-3732N NA 6 BB-XV-3732P J12B NA 6 BB-XV-3732R J14C NA 6 BB-XV-3732S J12C NA 6 BB-XV-3732T J14D NA 6 BB-XV-3732U J40D NA 6 BB-XV-3732V J14E NA 6 BB-XV-3732W J12E NA 6 BB-XV-3734A J50 6 BB-XV-3734B J47 6 BB-XV-3734C J14F 6 BB-XV-37340 J12F NA 6 BB-XV-3737A J38A NA 6 BB-XV-3737B J16C NA 6 BB-XV-3738A J13D NA 6 BB-XV-3738B J38B NA 6 3_ Group 48 -Reactor Recirculation System M-43-1 Outside BB-XV-3783 J32B NA 6 BB-XV-3785 J32C NA 6 BB-XV-3787 J30C NA 6 BB-XV-3789 J308 NA 6 BB-XV-3801A J18B NA 6 TABLE 3.6.3-1 (Continued) nPRIMARY CONTAINMENT ISOLATION VALVES MAXIMUM m PENETRATION ISOLATION TIME VALVE FUNCTION AND NUMBER NUMBER (Seconds)

NOTE() P&ID Outside M-43-1 BB-XV-38018 J28B NA 6 BB-XV-3801C J16E NA 6 BB-XV-3801D J36E NA 6 BB-XV-3802A J18F NA 6 BB-XV-3802B 28F NA 6 BB-XV-3802C NA 6 BB-XV-3802D NA 6 BB-XV-3803A J29F NA 6 BB-XV-3803B 4A NA 6 BB-XV-3803C NA 6 BB-XV-3803D J34 NA 6 BB-XV-3804A J2NA 6 BB-XV-38048 J2F NA 6 BB-XV-3804C J38 NA 6 BB-XV-3804 J23C NA 6 4. Group 49 -Reactor RecirculationuSystem Cont'd. M-43-1 Outside B8-XV-3820 J32E NA6 BB-XV-3821 J32F NA6 BB-XV-3826 J34B NA 6 BB-XV-3827 J23C NA6 5. Group 50 -Reactor Water Cleanup M-44-1 Outside BG-XV-3882 J24C NA BG-XV-3884A J19D NA BG-XV- 3884B J34A NA6 BG-XV- 3884C J19E NA6 BG-XV-38840 J34C NA 6 S TABLE 3.6.3-1 (Continued)

PRIMARY CONTAINMENT ISOLATION VALVES C1 a m m m.M M Mb PE 6. Group 51 -Core Isolation olin stem Outside FC-XV-4150A FC-XV-41508 FC-XV-4150C FC-XV-41500

7. Group 52 -Rr"dual Heat Removal System Outside BC-XV-4412A BC-XV-4411B BC-XV-4411C BC-XV-4411D BC-XV-4429A BC-XV-4429B

• BC-XV-4429C BC-XV-4429D

8. Group 53 -Core Spray System Outside BE-XV-FO18A BE-XV-FO188

9. Group 54 -High Pressure Coolant Injection System.MAXIMUM NETRATION ISOLATION TIME NUMBER (Seconds)J20A NA J40B NA J208 NA J40A NA J33 NA J238 NA J35A NA J368 NA j330 NA J23A NA J35C NA NOTE(S) MID N-49-1 6 6 6 6 M-51-1 6 6 6 6 6 6 6 6 N-52-1 J36A J19C J30F NA NA 6 6 M-55-1 Outside FD-XV-4800A J19A NA FD-XV-4800B J29A NA FD-XV-4800C J19B NA FD-XV-4800D J29B NA 6 6 6 6 TABLE 3.6.3-1 PRIMARY CONTAINMENT ISOLATION VALVES NOTES NOT.ATION 1. Main Steam Isolation Valve leakage is no: added :o '.60 La allowable leakage.-2. Containment Isolation Valves are sealed with a water s Z fr t.e and/or RCIC system to form the long-term sea! bounda of the feedwater lines. The valves are tested with water at- 1.0 Pa 52.9 psig, ensure the seal boundarywil!

prevent by-pass leakage. a boundarv iiu leakage will be limited to 10 gprn.3. Containment Isolation Valve, Type C gas test / Pa, 48." psig. Leakage added to entire system leakage. Allowable.eakage for entire system limited to 0.6OLa.4. Containment Isolation Valve, Ty wa r test at 1.10 Pa, 52.9 osi.delta P. Leakage added to entire s m leakage. Allowable leakage fo: entire system limited to 10 M.5. Containment boundary is d charge ozzle of relief valve, leakage tested during Type A test.*6. Drywell and suppressio, chan ressure and level instrument root valves and excess flo chec ye es, leakage tested during Type A.*7. Explosive shear valv s _-V02 through SE-V025) not Type C tested.-8. Surveillances to be performed er Specification 3.6.1.8.9. All valve 1.D. numbers are p ceded by a numeral I which represents a Unit 1 valve.10. The reactor vessel head sea leak detection line (penetration 1150),excess flow check valve (2 XV-3649) is not subject to OPERABIL7TY testing. This valve will t be exposed to primary system pressure except under the unlikely onditions of a seal failure where it could be partially pressurized to eactor pressure.

Any leakage path is restricted at the source therefore, this valve need not be OPERABILITY tested.11. Containment Isolation lve(s) are not Type C tested. Containment by-pass leakage is preve. ed since the line terminates below the minimum water level in the s pression chamber and the system is a closed system outside Primary Con inment. Refer to Specification 4.0.5.*Exemption to Appendix J of 10 CFR Part 50.HOPE CREEK 3/4 6-42 Amendment N.o. 134 ATTACHMENT 3 Hope Creek Generating Station Facility Operating License No. NPF-57 NRC Docket No. 50-354 Relocation of Valve Component Lists From Technical Specifications Markup of Proposed Technical Specification Bases Page Changes (for information only)TS Bases Pages B 3/4 3-2a B 3/4 3-2b B 3/4 3-2c B 3/4 3-2d B 3/4 3-2e B 3/4 3-2f B 3/4 3-2g B 3/4 3-2h B 3/4 3-2i B 3/4 3-2j B 3/4 3-2k B 3/4 3-21 B 3/4 3-2m B 3/4 3-2n B 3/4 3-2o B 3/4 3-2p B 3/4 6-5 LR-N06-0437 Attachment 3 Page 2 Insert D1 Primary containment isolation valves covered by this LCO are listed in the Technical Requirements Manual.The ACTIONS are modified by a Note allowing isolation valves closed to satisfy ACTION requirements to be reopened on an intermittent basis under administrative 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 rapidly isolated when a need for primary containment isolation is indicated.

0 S INSTRUMENTATION BASES the Technical Requirements Manual 3/4.3.2 ISOLATION ACTUATION BACKGROUND (continued) initiation of isolation.

In addition, manual is lation of the 'logics is provided.The isolation actuation instrumentation h s inputs to the trip logic of the isolation functions listed below.1. Primary Containment Isolation Most Primary Containment Isolation Funct ns receive inputs from eight sensors in four channels.

These inputs are ar anged into four two-out-of-two logic PCIS channels.

Each one of the two valv s on each penetration is closed by one of the four PCIS logics, arrange- so that operation of any three logics isolates all of the associated p etrations.

The exception-to this arrangement is th Reactor Building Exhaust Radiation

-High Function.

For this trip fun tion, three radiation-monitoring channels ,input to four two-out-of-hree PCIS initiation logics.The valve groups actuated b the Prima Containment isolation Trip Function are 2. Secondary Containment Isolation The outputs of the logic channels in trip system are arranged into four two-out-of-two-trip system logics for eactor Vessel Water Level.- Low Low, Level 2 and 'for Drywall Pressure -Hi .'The Reactor -Building and Refueling Floor Exhaust Radiation

-High-'tr p functions each have three radiation monitoring channels -that input t four two-out-of-three initiation logics. Each one of the two valves on sac penetration and each FRVS unit is actuated by one of the :rour trip logics, s that operation of any three logics isolates the secondary containment id provides for the necessary filtration of fission products.The valve groups actuared b the Se ondary Containment isolation Trip Function are listed inQ 3'. Main Steam Line Isolation Most MSL Isolation Functions receive inputs .from -four channels.

The outputs from these channels are combined in a one-out-of-two taken twice logic to initiate isolation of all main steam isolation valves (MSIVs). The outputs from the same channels are arranged into two two-out-of-two logic trip systems to isolate all MSL drain valves. The MSL drain line has two isolation valves with one two-out-of-two logic system associated with each valve.The exceptions to this arrangement are the Main Steam Line Flow- High Function and Main 'Steam Line Tunnel Temperature

-- High Function.

The Main Steam Line Flow- High.Function uses 16 flow channels, :four :for each steam line. One channel from each steam line inputs to one of the four trip strings. Two'trip strings make up each trip system and both trip systems must trip to cause an MSL isolation.

Each trip string has four inputs (one'per MSL), any one of which will trip the trip string. The-trip strings are Hope Creek B3/4 3-2a Revised ?by letter dated.April .29.,- 2002 INSTRUMENTATION BASES I the'Technical Requirements Manual 3/L4.3.2 ISOLATION

ýACTUATION INSTRUMENTAT]

3[4.3,2 ISOLATZON ACTUATION INSTRUMENTAT:

ON 0 BACKGROUND (continued) arranged in a one-out-of-two taken twice out-of-eight taken twice logic arrangemen MSIVs. similarly, the 16 flow channels a logic trip systems (effectively, two one-trip system isolating one of the two MSL The Main Steam Tunnel Temperature

-16 channels.

The logic is arranged simil1 High Function.The valv gxoup actuated by the MS]listed in ! 2.: Logic. This is effectively a one-: to initiate isolation of the*e connected into two two-out-of-two)ut-of-four twice logic), with each Lrain valves.High Function receives input from r to the Main Steam Line Flow -Isolation Trip Functions are 4.Reactor Water Cleanup System Isolatl on 1 I I The Reactor Vessel Water Level -Lou receives input from four reactor -vessel wi from the reactor vessel water level channe of-two trip systems. The Differential Fl Functions receive input from two channels, system using a one-out-of-one .logic. The receives input from twelve temperature mon The Area Ventilation Differential Temperat from twelve differential temperature monito These are configured -so that any one input system. Each of the two trip systems is c4 on each RWCU penetration.

The actuated by the RWCL listed inQ !Low, Level .2 Isolation Function=er level channels.

The outputs L are connected into two two-out--High and SLC System Initiation with each channel in one tripýrea Temperature

-High Function Itors, six to each trip-system.

zre -High Function receives input ,rs, six in each trip system.will trip the associated trip ,nnected to one of-the two valves Isolation Trip Functions are i 5, 6. High Pressure Coolant Injection Systen Isolation and Reactor Core Isolation Cooling System Isolation IlMost Functions that isolate RCIC and.I channels, with each channel in one trip sys Each of the two trip systems in each isolat the two-valves on each associated penetrati The exceptions are -the RCIC and HPCI-High and Steam Supply Line Pressure -Low receive inputs from four turbine exhaust dii supply pressure channels for each system.exhaust diaphragm pressure and steam supply connected to two -two-out-of-two trip systemi valve per associated-penetration.

The valve groups actuated b the RCIC Functions are listed in -._J IPCI receive :input from two em using -a one-out-of-one logic.on group is connected to one of.rbine Exhaust Diaphragm Pressure Functions.

These Functions phragm pressure and four steam'he outputs from the turbine pressure channels are each ,. Each trip system isolates one and HPCI System Isolation Trip Hope Creek B3/4 3-2b Revised by letter dated April 29, 2002-INSTRU14ENTATION I the Technical Requirements Manual I 3/4.3.2 ISOLATION ACTUATION INST1LUMENTATIOk

7. Shutdown Cooling System Isolation The Reactor Vessel Water.Level h- Low, L el 3 Function receives input from four .reactor vessel water'level channels The outputs from the reactor.vessel waterlevel channels are connected to wo two-out-of-two tripsystems.

The Reactor Vessel Pressure -High Function 'r ceives input from four channels, with each channel in one trip syste using a one-out-of-two trip logic. Each of the two trip systems is conn ted to one of the two valves on each shutdown cooling penetration.

The valve groups actuated b the Bhutd wn Cooling System Isolation Trip Functions are listed APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY The isolation signals generated by the isolation instrumentation are implicitly assumed in the safety analyses of References 1 and 2 to initiate closure of valves to 'limit offiite doses. Refer to Bases Sections 3/4.6.3,"Primary Containment isolation Valves," and'3/4.6.5, "Secondary Containment," for more detail of the safety analyses.Isolation actuation instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.

The OPERABILITY of the isolation actuation instrumentation is dependent on the OPERABILITY of the -individual instrumentation channel Functions specified in Table 3.3.2-1. Each :Function

'must have a required number of OPERABLE channels, with their setpoints within the specified Allowable Values, where appropriate.

A channel s .inoperabhaý.

if its-actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.

Table 3.3.2-1 is modified by Note (a) to indicate that a channel may be placed in an inoperable status for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for required surveillance without'placing the-trip system in the tripped condition-provided at least one OPERABLE channel in the same trip system is monitoring that parameter.

Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channel must be returned to OPERABLE status or the applicable Action must be taken. This Note is based on the reliability analysis (Refs. 5 and 6)assumption of the average time:required to perform channel surveillance.

That anal sis demonstrated that the.6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> testing allowance does not significantlyreduce the probability that the isolation valves will isolate the penetration flow-path(s) when necessary.

Allowable

'Values are specified

for each isolation actuation

'Function specified in the Table. Operation witha atrip setpoint less conservative than its Trip Setpoint, .but within :its '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 B3/4 3-2c Revised by'letter dated"April .29, 2002"'

N STRUMENTAT ION BASES the Technical Requirements Manual 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATIOA APPLICABLE SAFETY ANALYSES, LCO, and APPLICLILITY (continued)

In general, the individual Functions a e required to be OPERABLE in OPERATIONAL CONDITIONS 1,-2, and 3 consisten with the Applicability for TS 3.6.1.1, "Primary Containment Integrity." Fu ctions that have different Applicabilities are discussed below in the in ividual Functions discussion.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by nction basis.Primary containment Isolation l.a. Reactor Vessel Water Level Low RPV water level indicates that the cap bility to cool the fuel may be threatened.

The valves whose penetrations co unicate with the primary containment are isolated to limit the release of -ission products.

The isolation oý the p:imary containment on Level 2 ( rip Function 1.a.1) and Level 1 (Trip Function l.a.2) supports actions to nsure that offsite dose limits of 10 CFR 100 are .not exceeded.

The Reacto Vessel Water Level -Low Low, Level -2 and Low Low Low, Level 1 Trip Punctio s associated with isolation are implicitly assumed in the UFSAR anal is as these leakage paths are assumed to be isolated post LOCA.Reactor Vessel Water Level :signals are initia d from level transmitters that sense the difference between the p essure due to a constant column of water (reference leg) and thepressure due to-the actual water level (variable leg).in the vessel. Two channels of eactor Vessel Water Level -.Low Low, Level 2 and Low Low Low, Level 1 Tri Functions are available and are .required .to be OPERABLE for each.PC S channel to ensure-that no single :instrument

failure .can-preclude-the is ation function.The valve groups actuated by these Functions are listed inc*l.b. Drywell Pressure -High High drywell pressure can indicate.a:break.in the -CPB inside-the primary containment.

The isolation of .some of the prima containment isolation valves on high drywell-pressure supports actio to ensure that offsite dose limits of 10 CFR 100 are not exceeded.

The rywell Pressure-High Function, associated with .isolation of the primary c ntainment, is implicitly-assumed in the UFSAR accident analysis as thes leakage -paths are assumed to -be isolated post LOCA.High drywell pressure-signals are initiated from pre ure transmitters that sense the pressure in the drywell. Two channels of.D Pressure --High Function are available and :are required to be OPERABLE for each PCIS channel to-ensure that .no single .instrument failure can pre ude the isolation-function.

The valve groups actuated by this Function are listed .Hope Creek B3/4 3-2d Revised by letter dated'Apri-i -29_,_q0 02 0 INSTRUMENTATION BASES the Technical Requirements Manual 3/4.3.:2 ISOLATION ACTUATION INSThUMENTAT0N APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (c ntinued)ic. Reactor Building Exhaust Radiation

-High High Reactor Building exhaust radiation is an indi tion of possible gross failure of the -fuel cladding.

The release may have originated from the primary containment due to a break in the RCPB. When Exha St Radiation

-High iS detected, valves whose penetrations communicate wi the primary containment atmosphere-are isolated to limit the xrelease of ission products.The Exhaust Radiation

-High signals are initiated from radiation detectors that are located on the ventilation exhaust piping ming from the reactor building.

The system consists of three channels.

Fou high radiation alarms, one from each channel through Class aE to Cla s 1E isolation, are supplied to each channel of the Primary Containme t Isolation System (PCIS), where two out of three logic is used to initiate c osure of primary containment isolation valves and dampers. Three channels f Reactor Building Exhaust -High Function .are available and are required to e OPERABLE to ensure that no single instrument failure can preclude t e isolation -function.

The-valve groups actuated by this Function are listed n1, 1.l.d. Manual Initiation The Manual Initiation push button channels introduce signals into the isolation actuation logic that are redundant to -the automatic protective instrumentation andprovide manual isolation capability.

There is no specific UPSAR safety analysis that takes credit for this Function.

It is retained :for overall redundancy and diversity of the isolation function as-required:by-the NRC in the plant licensing basis.There are four push buttons for the logic, one manual initiation push button per.PCIS channel..Four channels of the Manual Initiation Function are available and are required to be OPERABLE in OPERATIONAL CONDITIONS 1, 2, and .3, since these are -the OPERATIONAL CONDITIONS in which the Isolation Actuation automatic Trip Functions are required to -be OPERABLE.Secondary Containment Isolation 2.a Reactor Vessel Water Level -Low Low, Level 2-Low-reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may-be threatened.

Should RPV water level decrease -too.far, fuel damage could result. An isolation of the secondary-containment sand:actuation of the 7RVS are initiated in order to minimize the potential of an offaite dose release. The Reactor Vessel Water Level -.Low Low, Level 2 :Function is one of the Functions assumed to be OPERABLE and capable of providing Isolation and initiation signals. The isolation and initiation systems on Reactor Vessel Water Level-- Low Low, Level :2 support actions to ensure thatany offaite releases are within the limits -calculated in the safety analysis.Hope Creek B3/4 3-2e Revised by letter dated April .29, 20021 INSTRUMENTATION BASES APPLICABLE SAFETY ANALYSES, LCO, and API Reactor Vessel Water Level -Low Low.Level "2 signals are initiated from level transmitters that sense the diff ence between the pressure due to a constant column of water (reference leg) a d the pressure due to the actual water level (variable leg) in the vessel, channels of Reactor Vessel Water Level -Low Low, Level 2 Function are a ailable and are required to be OPERABLE for each PCIS channel to ensure that o single instrument failure can preclude the isolation function.The Reactor Vessel Water Level -Low Low, evel 2 Function is required to be OPERABLE in OPERATIONAL CONDITIONS 1, 2, a d 3 where considerable energy exists in the Reactor Coolant System (RCS)- thus, there is a probability of pipe breaks resulting in signific t releases of radioactive steam and gas. In OPERATIONAL CONDITIONS 4 and 5, the probability -and consequences of these events are low due to the RC pressure and temperature limitations of theme OPERATIONAL CONDITIONS; thus, his Function is not required.

In addition, the Function is also requir to be OPERABLE during operations with a potential for draining the reactor vessel (OPDRVs), when handling irradiated fuel in the secondary containmen and during CORE ALTERATIONS, because the capability of .isolating pote tial sources of leakage must be provided to ensure that offsite dose limits a not exceeded if core damage occurs.-The valve groups actuated by this Function are li ted in 2.b'Drywell-Pressure

-High High drywell pressure can indicate a break in the r ctor coolant pressure boundary (RCPB). An isolation of the secondary c ntainment eand actuation of the FRVS are ' 'tiated in order to minifize th potential of an offsite dose release. The isolation on high drywell pressu e-supports actions to ensure that any offsite releases are within the I'mits calculated in the safety analysis.

High drywell pressure signals are i itiated from pressure transmitters that sense the pressure in the drywell. -Two channels of Drywell -Pressure

-High Functions are available and .are re ired to be OPERABLE for each PCIS channel to ensure that no single inst nt failure can preclude performance of' the isolation function.The Drywell Pressure -High Function is required to be OP LE in OPERATIONAL CONDITIONS 1, 2, and '3 where considerable energy exi ts in -the RCS; thus, there is a probability of pipe breaks resulting in sig ificant:releases of radioactive -steam and gas. This Function is not .requ red in OPERATIONAL CONDITIONS 4 and 5 because the-probability and consequ ces of these events are low due to the RCS pressure and temperature

limit tions of these OPERATIONAL CONDITIONS.

The valve groups actuated by -this Function are listed in 2.c, 2.d. Refueling Floor and Reactor Building Exhaust Radiation--

High High Refueling Floor or Reactor Building exhaust radiation

is an indication of possible gross 'failure of the fuel cladding.

The release may have originated

from the primary containment due to -a break in the RCPB or.Hope Creek B3/4 3-2f Revised by letter dated:'April 2.9, .2002" INSTRUMENTATION 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION APPLICABLE SAFETY ANALYSES, LCO, and APPL-ICABILIT (continued) the refueling floor due to a fuel handling accident When Exhaust Radiation

-High is detected, secondary containment isolation a actuation of the FRVS are initiated to limit the release of fission produc s as assumed in the UFSAR safety analyses (Ref. 4).The Exhaust Radiation

-High signals are initiated fro radiation detectors that are located on the ventilation exhaust ducts comin from the reactor building and the refueling floor zones, respectively.

ree channels of Reactor Building Exhaust Radiation

-High Function and t ree channels of Refueling Floor Exhaust. Radiation--

High Function are ava'lable and are required to be OPERABLE to ensure that no single instrume t failure can preclude the isolation function.The Refueling Floor and Reactor Building Exhaust Radiation High Functions are required to be OPERABLE in OPERATIONAL CONDITIONS 1, .2, nd 3 where considerable energy exists, thus, there is a probability of 'pe breaks resulting in significant releases of radioactive steam and ga .In OPERATIONAL CONDITIONS 4 and 5, the probability and consequenc s of these events are low due to the RCS pressure and temperature limitati ns of these OPERATIONAL CONDITIONS; thus, these Functions are not required.

In addition, the Functions are also required to be OPERABLE during OPDRVs, wh n handling.recently irradiated fuel in the secondary containment, because t e capability of detecting-radiation releases due to fuel failures (due to fuel uncovery or dropped fuel assemblies) must be provided to ensure that offsite se limits are not exceeded.The valve groups actuated by this Function are listed in , .2.e. Manual Initiation The Manual 'Initiation for secondary containment isolation can be performed by manually initiating a primary containment isolation.

There is no specific UFSAR safety analysis that takes credit for this Function.

it is retained for the overall redundancy and diversity of the secondary containment isolation.instrumentation as required by the NRC approved licensing basis.There are four push buttons for the logic, one manual initiation push button per PCIS channel. There is no Allowable Value for -this Function, since the channels are mechanically actuated based solely on the position of the push buttons.Four channels of Manual Initiation Function are available and are required to be OPERABLE in OPERATIONAL CONDITIONS 1, 2, and 3 and during OPDRVs, when handling recently irradiated fuel in the secondary containment.

These are the OPERATIONAL CONDITIONS and other specified conditions in which the Secondary Containment Isolation automatic Functions are required to be OPERABLE.Hope Creek B3/4 3-2g Amendment No- 146 1 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION E APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY continued)

Main Steam Line Isolation 3.a. Reactor Vessel Water Level -Low Low Low, Level 1 Low reactor pressure vessel (RPV) water level 'idi ates that the capability to cool the fuel may be threatened.

Should R V water level decrease too far, fuel damage could result. Therefore, i olation of the MSIVs and other interfaces with the reactor vessel occurs o prevent offsite dose limits from being exceeded.

The Reactor Vessel Water Level -Low Low Low, Level 1 Function is one of the many Functions assumed ao be OPERABLE and capable of providing isolation signals. The Reactor Vessel ater Level -Low Low Low, Level 1 Function associated with isolation is assum d in the analysis of the recirculation line break (Ref. 1). The isola ion of the MSLs on Level 1 supports actions to ensure that offsite dose limits are not exceeded for a DBA.Reactor vessel water level signals are initiated from four level transmitters that sense the difference between the pressure due a constant column of water (reference leg) and the pressure due to the actua water level (variable leg) in the vessel. Four channels of Reactor Vess 1 Water Level -Low Low Low, Level 1 Function are available and are requir to be OPERABLE to ensure that no single instrument failure can preclude t e isolation function.The valve groups actuated by this Function are listed in e-z3. .6 3.b. Main Steam Line Radiation

-High, High The Main Steam Line Radiation

-High, High Function is provided to detect gross release of fission products from the fuel and to initiate closure of the reactor recirculation water sample line isolation valves.Four detectors, one for each main steam line, monitor the gross gamma radiation.

Each detector provides an input to one of the four, trip logic channels.3.c. Main Steam Line Pressure -Low Low MSL pressure indicates that there may be a problem with the turbine pressure regulation, which could result in a low reactor vessel water level condition and the RPV cooling down more than 100 0 F/hr if the pressure loss is allowed to continue.

The Main Steam Line Pressure -Low Function is directly assumed in the analysis of the pressure regulator failure (Ref. 2). For this event, the closure of the MSIVs ensures that the RPV temperature change limit (100 0 F/hr) is not reached.The MSL low pressure signals are initiated from four transmitters that are connected to the MSL header. Four channels of Main Steam Line Pressure -Low Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.0 Hope Creek B3/4 3-2h August 15, 2005 INSTRUMENTATION BASES the Technical Requirements Manual-3/4.3.2 ISOLATION ACTUATION TLSL RUMNCTAnA I I ('The Main Steam Line Pressure -Low Fun tion is only required to be OPERABLE in OPERATIONAL CONDITION 1 since th' is when the assumed transient can occur (Ref. 2).The valve groups actuated by this Functi n are listed in Table 3.3.2-1.3.d. Main Steam Line Flow -High Main Steam Line Flow -High is provided t detect a break of the MSL and to-initiate closure of the MSIVs. If the st am were allowed to continue flowing out of the break, the reactor would depr surize and the core could uncover, If the RPV water level decreases too fa , fuel damage could occur..Therefore, the isolation is initiated on high flo to prevent or minimize core damage. The Main Steam Line Flow -High Func ion is directly assumed in the analysis of the main steam line break (MSLB) ( ef. 1). The isolation action, along with the scram function of the Reacto Protection System (RPS), ensures that the fuel peak cladding temperature rem ins below the limits of 10 CFR 50..46 and offeite doses do not exceed the 10 FR 100 limits.The MSL flow signals are initiated from 16 tran mitters that are connected to the four*MSLs.

Four channels of Main .St am Line Flow -High Function for each MSL (two channels per trip system) e available and are required to be OPERABLE so that no single instrument f ilure will preclude detecting.a-break in any individual MSL.-The valve groups actuated by this Function are i1 ted in Ta a 3.-e. Condenser Vacuum -Low The Condenser Vacuum -'Low Function is provided to revent overpressurization of the main condenser in the event of a lose of the main condenser vacuum. Since the integrity of the condenser is an assumption in offaite dose calculations, the Condenser Vacuum -Low Func on is assumed to be OPERABLE-and capable of initiating closure of the MSIVs. The closure of the MSIVs is initiated to prevent the addition of steam tha would lead to additionalcondenser pressurization and possible rupture of he diaphragm installed to protect the turbine exhaust hood, thereby preve ting a potential radiation leakage path following an accident.Condenser vacuum pressure signals are derived from four ýressure transmitters that sense the pressure in the condenser.

Four c annels of Condenser Vacuum -Low Function are available and are required o be OPERABLE to ensure that .no single instrument failure can preclude the is lation function.-As noted in the footnote Table '3.3.2-1, -he -hannels are n t required to be OPERABLE in OPERATIONAL CONDITIONS 2 and 3 when all turbine stop valves (TSVs) are less than 90% open, since the potential for condenser overpressurization is minimized.

Switches are-provided to manual. bypass the channels when all TSVs are closed.The valve groups actuated by this Function are listed ini Hope Creek .B3/4 3-2i Revised by letter dated April 29, 2002" INSTRUMENTATION K BASES theTechnical Requirements Manual 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION APPLICABLE SAFETY ANALYSES, LCO, and APPLICABrLITY (continued) 3.f. Main Steam Line Tunnel Temperature

-High The Main Steam Line Tunnel Temperature

-High is to detect a Leak in the RCPB and provides diversity to the high flow instrumentation.

The isol~ation occurs when a very small leak has occurred.

If the small *leak is aIJlowed to continue without isolation, offsite dose iurn temay be reached.However, credit for these instruments is not -taken in any t nsient or accident analysis in the UFSAR, since bounding analyses are for large breaks, such as MSLBs. ... :..Area temperature signals are initiated frd~ensors locate in temi mai steam tunnel. Sixteen channels of Main Steam Tunnel Temperature -High Function are available and are required to be OPERABLE to ensure t t no single instrument failure can preclude the isolation uncstion.The valve groups actuated by this Function are listed inl3 3.g. Manual Initiation The Manual Initiation push button channels introdu~ce signals into the MSL isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability..

There is no specific UPSAR safety analysis that takes credit for this Function.

It is retained for the overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.There are four push buttons for the b logi, wo manual initiation push buttons per trip system.Four channels of Manual Initiation Function are -aalable and are required to be OPERABLE in OPERATIONAL CONDITIONS 1, 2, and 3, since these are the OPERATIONAL CONDITIONS in which the MSL isolation automatic Functions are required to be OPERABLE.Reactor Water Cleanup System Isolation 4.a, 4.b. RWCU Differential Flow --High The high differential flow signal is provided to detect a break in the RWCU Bystem. This will detect leaks in the RWCU System when area or differential temperature -would not provide detection (i.e., a cold leg break). Should the reactor coolant continue to -flow out of the break, offsin e dose limits mayibe exceeded.

Therefore, isolation of the RWCU System is initiated when hgh differential-flow is sensed to prevent exceeding offaite doses.. A time aelay is provided to prevent spurious trips during most RCm operational -transients.

This -Funtion is not -assumed in any UPSAR transient or accident analysis, taince -boundinganalyses are performed for large breaks such as M4SLBs.The high differential flow signals are initiated ffrom-transmitters that are connected o e the inee reactor vesiel) anbsouuieus-.o condenser arid feedwater) of the RWCU System. Two channels of RWCU Differential Flowf- High Function are available and are required to be Hope Creek q r3/4 3-2j Revisedby letterOdated April 29, 200'2ý INSTRUMENTATION 3/4.3.2 ISOLATION ACTUATION INSTRUMENTATION APPLICABLE SAFETY ANALYSES LCO and APPLICABILITY

(\ontinued)

OPERABLE to ensure that no single instrument failure n preclude the isolation function.The valve groups actuated by this Function are li tdi 4 .c, 4.d. RWCU Area Temperature and Area Ventilation Dif Temperature RWCU area temperatures and area ventilation differen ial temperatures are provided to detect a leak from the RWCU System. The is lation occurs even when very small leaks have occurred and is diverse to t e high differential flow instrumentation for the hot portions of th RWCU System.If the small leak continues without isolation, offsite dose 1 mits may be reached. Credit for these instruments is not taken in any tr sient or accident analysis in the UFSAR, since bounding analyses are pe formed for large breaks such as recirculation or MSL breaks.Area temperature and area ventilation differential tempera ure signals are initiated from temperature elements that are located in the r that is being monitored.

Twelve ambient temperature sensor/monitors prov de input to the RWCU Area Temperature

-High Function.

Twelve channels are re ired to be OPERABLE to ensure that no single instrument failure can preclu the isolation function.Twelve differential temperature sensor/monitors provide input the RWCU Area Ventilation Differential Temperature

-High Function.

Twel e channels are required to be OPERABLE to ensure that no single instrume failure can preclude the isolation function.The valve groups actuated by this Function are listed in6--4.e. SLC System Initiation The isolation of the RWCU System is required when the SLC System has been initiated to prevent dilution and removal of the boron solution by the RWCU System. SLC System initiation signals are initiated from the two SLC pump start signals.Two channels (one from each pump) of the SLC System Initiation Function are available and are required to be OPERABLE only in OPERATIONAL CONDITIONS 1 and 2 (when the SLC system is required to be OPERABLE), since these OPERATIONAL CONDITIONS are consistent with the Applicability for the SLC System (TS 3.1.5).4. f. Reactor Vessel Water Level -Low Low, Level 2 Low RPV water level indicates that the capability to cool the fuel may be threatened.

Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of some interfaces with the reactor vessel occurs to isolate the potential sources of a break. 'The isolation of the RWCU System on Level 2 supports actions to ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. The Reactor Vessel Water Level -Low 'Low, Level 2 Function associated with RWCU isolation is not Hope CreekýB 3/4 3-2k Amendment No. 166

.INSTRUMENTATrION 3/4.3 .2 ISOLILTION ACTUATION SAFETY ANALYSES,.

LCO, and-ýAPPLICABILJITY

(\cont inued)directly"assuwed in the UPSAR safety analyses because the'RWCU System line break is bounded by breaks of larger systems (recirculatio and MSL breaks are more limiting).

Reactor Vessel Water Level -Low Low, Level 2 signals a ee initiated from four level transmitters that sense the difference between the pressure due to a.constant column of water (reference leg) and the press re due to the actual water level (variable leg) in the vessel. Four channels f Reactor Vessel Water Level -Low Low, Level 2 Function, are available and re required to be OPERABLE to -ensure that no single instrument failure can pre lude the isolation funotion.The valve groups actuated by this Function are listed in6.j: 4 .9. Manual "Initiation The Manual Initiation push button channels introduce signals into the RWCU System isolation logic -that are redundant to the automatic protective instrumentation-and provide manual-isolation capability.

There is no specific UPSAR safety analysis that takes credit for this Tunction.

It is retained ifor overall redundancy and diversity of the isolation function as required-by the NRC .in the -pl-ant licensing basis.There .are two push buttons for the logic, one manual initiation push button per trip system..Two channels of 'the Manual initiation Function are -available and. are required to be OPERABLE in OPERATIONAL CONDITIONS 1, 2, and 3 since these are the OPERATIONAL CONDITIONS in which the RWCU System Isolation automatic'lunctione are required to be OPERABLE.Reactor Core Isolation Cooling and High Pressure Coolant Injection stems Isolation 5.a, 6.a, 5.b, 6.b. RCIC and HPCI Steam-Line A Pressure (Flow) -High Steam 'Line A .Pressure (Flow) -'High Functions

ýare pr&Aided to detect a break of the RCIC or 'HPCI steam lines and initiate closure of the steam line isolation valves of -the 'appropriate system. if the steam le'-allowed to continue flowing out of the break, the reactor will depressurize and the core can uncover. 'Therefore, the isolations are initiated on high flow to prevent or minimize-core damage. The .isolation action, along with the scram-function of -the RPS, ensures that :the fuel peak cladding temperature rdrdhins below the limits of 10 CFR '50.46. Specific credit for these 'Functions is not assumed in any UPSAR -accident analyses since -the bounding analysis.

is. performed for'large breaks such as 'recirculation and MSL breaks. 'However, these instruments prevent the RCIC -.-or .HPCI ;steam 'i.e breaks 'froam becoming-bounding.

'The RCIC and :HPCI Steam 'Line A Pressure (Flow) -High signals are initiated from transmitters (two for HPCI and two for RCIC) that are.connected to the system 'steam .lines. Two -channels of both RCIC and HPCI Hope .Creek B3/4 '3-21 Revised by letter dated"April .29, '2002'0-1 INSTRUMENTATION the Technical Requirements Manual I:BASES, ...-APPLICABLE ,SAFETY AN.ALYSES, LCO, and APPA I ILITY (continued)

Steam -Line A Pressure (Flow) -High Functio a are available and are required to be OPERABLE to ensure that no single inst ument failure can preclude the isolation function.To eliminate the possibility of spuriou -system isolations, the RCIC and HPC1 systems incorporate a time delay, whi h will prevent short term .flow peaks from initiating a system isolation but w 11 not interfere with the leak detection and isolation function.\.The valve group, actuated by this Function are oliste.5.*, 6.c. RCIC and HPCI Steam Su22,!y Pressure -Low steam supply pressure indicates that the pressure of the steam in the HPCI or RCXC turbine may be too low to continu operation of -the associated system's-turbine.

These isolations are or equipment protection and are not assumed in any transient or accident an lysis in the UPsAR. .However, -they also provide a diverse signal to indi te a possible system break. These instruments are included in Technical pecifications (TS)because of the potential for risk due to possible fai ure of the instruments preventing RCIC and HPCI initiations (Ref. 3).The RCIC and HPCI Steam Supply Pressure -Low si nals are-initiated from transmitters (four for HPCI-and -four for RCIC) th are connected to the system steam line. Four channels of both RCIC and HPCI Steam Supply Line Pressure -'Low Functions are available and are required to be OPERABLE to ,ensure that no single instrument-failure can preclude th isolationfunction.-High turbine exhaust diaphragm pressure indicates tha the pressure may be -too high to continue operation of the associated -system' turbine. -That.is, one of -two exhaust diaphragms has .ruptured -and pressure s reaching turbine casing pressure limits. These isolations-are for -eq ipment protection -and are not assumed in any transient or accident aalysis in the UPSAR. These instruments are -included in the TS because of the potential for risk due to possible failure of the instruments preventing RC and HPCI initiations (Ref. 3)'.The RCIC and EPCI Turbine Exhaust Diaphragm Pressure -Hi h signals are initiated from transmitters (four for HPCI and four for RCIC) t t are connected to the area between the rupture diaphragms on each sys sem's-turbine exhaust line. Pour channels of !both RCIC and HPCI Turbine Exhaut Diaphragm Pressure -High .Functions are -available and are xrequired to be OP RABLE to ensure .that no :single instrument 1failure -can .preclude -the lsolati Lfunction.

The valve groups -actuated by this Function are listed -in -Hope Creek :93/4 "3-2m Revised by letter -dated"April -29, .2002-INSTRUMENTATION BASES the Technical Requirements Manual 3/4.3-2 ISOLATION ACTUATION INSTRUMENTATIO APPLICABLE SAFETY ANALYSES LCO, and APPLI ILITY (continued) 5.e, 5.f, 5.g, 5.h, 6.e, 6.f, 6.g. 6.h. RCIC \and HPCI Area and Differential Temperature

-High Area ambient and differential temperatur s are provided -to detect,a leak from the associated system steam-piping.

The isolation occurs when a very small leak has occurred and is diverse to he high -flow instrumentation.

If the small leak is allowed to continue withou isolation, offsite dose limits may be reached. These Functions are not asumed in any UFSAR transient or accident analysis, since bounding an lyses are performed for large breaks such as recirculation or MSL breaks.PumpRoom Area and Differential Temperature High signals are initiated from sensor/switchqs that are appropriat y located to protect the system that is being monitored.

Two channels for e ch RCIC and HPCI Pump Room Temperature-High and Pump Room VentilationDu to A Temperature

-High Function are available and-are required to be OPERAB E to ensure that no single instrument failure can preclude the isolation unction.Ambient temperature sensor/switches detect tempe ature increases in the steam supply piping areas. Two channels for each RCIC and HPCI Pipe Routing Area Temperature

-High Function and six channels for e ch RCIC and HPCI Torus Compartment Temperature

-High Function are avail le and are required to be OPERABLE to ensure that no single instrument failu e can preclude the isolation function.The valve groups actuated by this Function are list d 5.i, 6.i. Drywell Pressure -High High drywell -pressure can indicate a break in the RCP .The RCIC and HPCI isolation of the turbine exhaust is provided to prevent communication with the drywall when high drywall pressure exists. A poten ial leakage path exists via the turbine exhaust. The isolation is delayed unt 1 the-system becomes unavailable for injection (i.e., low steam linepress e). The isolation of the RCIC and HPCI turbine exhaust by.Drywell Pres ure -'High is indirectly assumed in the UPSAR accident analysis because the urbine exhaust leakage.-path is not assumed to contribute to offsite doses.High drywell pressure signals are initiated frompressure ransmitters that sense thepressure in -the drywall. -Four channels of both R IC and HPCI Drywell Pressure -High Functions are-available and are -required o be OPERABLE to ensure that no single instrument failure can preclude t isolation function.'The valve groups actuated by -this Function are listed -in s.-J, 6.j. Manual Initiation The Manual Initiation push ,button channels introduce signals into the RCIC and HPCI systems' isolation logics that are redundant to the automatic protective instrumentation and provide manual -isolation capability.

There is Hope Creek B3/4 3-w2n Revised by letter dated April .29., 2002' INSTRUMENTATION the Technical Requirements Manual BASES 3/4.3.2 ISOLATION

'ACTUATION I9rTkMENTATTON APPLICABLE SAFETY:ANALYSES LCO and APPLICABILTY (continued) no specific UPSAR safety analysis that takes cre it for these Functions.

They are retained for overall redundancy and dive sity of the isolation function as required by the NRC in the plant lice ing basis.There is one manual initiation push button :f each of the HPCI and RCIC systems.One channel of both RCIC and HPCI Manual Initi tion Functions is available and is required to be OPERABLE in OPERATIO CONDITIONS 1, 2, and 3 since these are the OPERATIONAL CONDITIONS in which the RCIC and HPCI systems' Isolation automatic Functions are required to be OPERABLE.Shutdown Cooling System Isolation 7.a. Reactor Vessel Water-Level-Low, Level 3 Low RPV water level indicates that the capability t cool the fuel may be threatened.

Should RPV water level decrease-too far, el damage could result. Therefore, .isolation-of some reactor vessel inter aces occurs to begin isolating the potential .sources of a break. The Rea or Vessel Water Level --ýLow, Level 3 Function -associated with RHR.Shutdownooling System isolation is not directly-assumed in safety analyses beuse a break of the RHR Shutdown Cooling System is bounded by breaks of the reci culation and MSL. The RHR Shutdown Cooling System isolation on-Level 3 su ports actions to ensure that the RPV water level does not.drop below-the to of the active fuel during a vessel draindown event caused by a leak (e.g.,p pe break or inadvertent valve opening)-in the RHR Shutdown Cooling System.ReactorVessel Water Level --Low, Level -3 signals are init ated from four level transmitters -that .sense the difference between the pr ssure due to a constant column of water (reference leg) and the pressure duee.t the actual water level (variable leg) in the vessel. Pour channels (two cha els per trip system) of the Reactor. Vessel Water Level -Low, Level 3 :Func ion are available and are required to be OPERABLE-to ensure that no single instrument failure can-preclude the isolation -function.

The Reactor Vessel Water Level -Low, Level 3 Function is requ red to be OPERABLE in OPERATIONAL CONDITIONS 1, 2, and 3 to prevent this po ntial flow path from lowering the reactor vessel level to the top of -the.fu The -valve groups actuated by this Function -are listed in 7.b. Reactor Vessel (RHR Cut-in Permissive)

Pressure -High The Reactor Vessel (RHR Cut-in Permissive)

Pressure -High Function -is provided to isolate-the shutdown codling portion of the -Residual HeatRemoval (RHR) :System. This interlock s.-provided only for equipment protection to prevent an intersystem LOCA :scenario, and credit for -the -interlock -is not assumed in the accident or transientýanialyis -in the UPSAR.Hope Creek 334' 3-2o Revised by'letter dated"April 29, 2002" 314.3.2 ISOLATION ACTUATION INSTRUMENTATION APPLICABLE SAFETY 'ANALYSES, LCO, and APPLICABILITY (con nued) 0'The Reactor Vessel (RHR Cut-in Permissive)

Pressure -High signals are initiated from four transmitters.

Four channels of Reactor Vessel CRHR Cut-in Permissive)

Pressure -High-Function are available and ar required to be OPERABLE.

The .Function is only required to be OPERABLE in OP TIONAL CONDITIONS 1, .2, and 3, since these are the only OPERATIONAL C ITIONS in which the reactor can be pressurized; thus, equipment protectio s needed.The valve groups actuated by this Function are listed in(7.c. Manual Initiation-The Manual Initiation push button channels introduce signals into the RHR shutdown cooling isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability.

There is no specific UFSAR safety analysis that takes credit for this Function.

it is retained fo. overall redundancy and diversity of the isolation function as:required by the NRC-in the plant licensing basis.There are .two push buttons for the logic, one manual initiation push button per trip system.-Two channels of the Manual Initiation Function are available and are'required to be OPERABLE in OPERATIONAL CONDITIONS 1, 2, and 3 since these are the OPERATIONAL CONDITIONS in which the RHR System Shutdown Cooling Mode Isolation automatic Functions are required to be OPERABLE.ACTIONS 3.'3.2 .b Because 1,i the diversity of sensors available to provide isolation signals and the redundancy of the isolation design, an allowable out of service time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for Punctions l.b, 2.b, 7.a and 7.b and 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for Functions other than .Functions l.b, 2.b, 7.a and 7.b has been shown to be acceptable (Refs. 5 and 6) to permit restoration of any inoperable channel to OPBRABLE status. If the :inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in 'the tripped condition per Action 3.3.2.b.l.b or 3.3.2.b.lI.c.

Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore -capability to accommodate .a single failure, and allow operation to continue with no further restrictions.

Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an isolation), the Action required by Table 3.3.2-I must be taken.'If 'there are .no OPERABLE channels for :a trip function in one -trip system, and the inoperable channels cannot be-"restored to OPERABLE status within one hour, the inoperable channels must be placed in the 'tripped condition per Action 3.3.2.b.l.a." Alternately, if it is not desired to place the channels 'in-trip, the Action required by Table :3..3.2-1 must be taken.Hope Creek B3/4 3-2p Revised by letter dated Anri.f 1. 2Q 2.002.

CONTAINMENT SYSTEMS BASES 3/4.6.3 PRIMARY CONTAINMENT ISOLATION VALVES The OPERABILITY of the primary containment isolation valves ensures that the containment atmosphere will be isolated from the outside environment in the event of a release of radioactive material to the containment atmosphere or pressurization of the containment and is consistent with the requirements of GDC 54 through 57 of Appendix A of 10 CFR 50. Containment isolation within the time limits specified for those isolation valves designed to close automatically.

ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a LOCA. 'I--0s KTI Surveillance 4.6.3.4 requires demonstration that a representative sample of reactor instrumentation line excess flow check valves are tested to demonstrate'that the valve actuates to check flow on a simulated instrument line break. This surveillance requirement provides assurance that the instrument line EFCV's will perform so that the predicted radiological consequences will not be exceeded during a postulated instrument line break event as evaluated in the UFSAR. The 18-month frequency is based on the need to perform this surveillance under the conditions that apply immediately prior to and during the plant outage and the potential for an unplanned transient if the surveillance were performed with the reactor at power. The representative sample consists of an approximately equal number of EFCV's, such that each EFCV is tested at least once every ten years (nominal).

In addition, the EFCV's in the sample are representative of the various plant configurations, models, sizes and operating environments.

This ensures that any potentially common problem with a specific type or application of EFCV is detected at the earliest possible time. The nominal 10 year interval is based on performance testing as discussed in NEDO 32977-A, "Excess Check Valve Testing Relaxation." Furthermore, any EFCV failures will be evaluated to determine if additional testing in that test interval is warranted to ensure overall reliability is maintained.

Operating experience has demonstrated that these components are highly reliable and that, failures to isolate are very infrequent.

Therefore, testing of a representative sample was concluded to be acceptable from a reliability standpoint.

3/4.6.4 VACUUM RELIEF Suppression Chamber-to-Drywell Vacuum Breakers BACKGROUND; The function of the suppression-chamber-to-drywell vacuum breakers is to relieve vacuum in the drywell. There are eight internal vacuum breakers located on the vent header of the vent system between the drywell and the suppression chamber that allow air and steam flow from the suppression chamber to the drywell when the drywell is at a negative pressure with respect to the suppression chamber. Therefore, suppression chamber-to-drywell vacuum breakers prevent an excessive negative differential pressure across the wetwell-drywell boundary.

Each vacuum breaker is a self-actuating valve, similar to a check valve, which can be remotely operated for testing purposes.0 ...HOPE CREEK B 3/4 6-5 Amendment No. 133