ML17046A229: Difference between revisions

From kanterella
Jump to navigation Jump to search
(Created page by program invented by StriderTol)
(Created page by program invented by StriderTol)
Line 1: Line 1:
{{Adams
#REDIRECT [[LR-N17-0034, Salem Generating Station, Units 1 & 2, Submittal of Revision 29 to Updated Final Safety Analysis Report, and Technical Specification Bases Changes and Quality Assurance Topical Report, NO-AA-10, Rev. 85]]
| number = ML17046A229
| issue date = 01/30/2017
| title = Salem Generating Station, Units 1 & 2, Submittal of Revision 29 to Updated Final Safety Analysis Report, and Technical Specification Bases Changes and Quality Assurance Topical Report, NO-AA-10, Rev. 85
| author name = Duke P
| author affiliation = PSEG Nuclear, LLC
| addressee name =
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000272, 05000311
| license number = DPR-070, DPR-075
| contact person =
| case reference number = LR-N17-0034
| package number = ML17046A230
| document type = Letter, Quality Assurance Program, Technical Specification, Bases Change, Updated Final Safety Analysis Report (UFSAR)
| page count = 401
}}
 
=Text=
{{#Wiki_filter:Security Related Information
-Withhold Under 10 CFR 2.390 PSEG Nuclear LLC P;Q, Box. 236, Hancooks Bridge, NJ 08038:0236 LR-N17-0034 January 30, 2017 United States Nuclear Regulatory Commission Document Control Desk Washington.,
DC 20555-0001 Salem Generating Station -Unit 1 and Unit 2 0PSEG Nuclear IJ.,C 10 CFR 50.71(e) 10 CFR 50.54(a)(3) 10 CFR 54.37(b) 10 CFR 71.106(b)
TS 6 .. 17.d (Unit 1) TS 6.16.d (Unit 2) Renewed Facility Operating License Nos. DPR-70 and DPR-75 NRC Docket Nos. 50-272 and 50-311 Hope Creek Generating Station Renewed Facility Operating License No. NPF-57 NRC Docket No. 50-354
 
==Subject:==
 
Submittal of Salem Generating Station Updated F.inal Safety Analysis Report, Revision 29, Salem Units 1 & 2 Technical Specification Bases changes, 10 CFR 54.37(b) review results for Salem Units 1 & 2 and PSEG Nuclear LLC Quality Assurance Topical Report, NO-AA-10, Revision 85 PSEG Nuclear LLC (PSEG) hereby submits:
-*
* Revision No. 29 to the Salem Generating Station Units 1 and 2 Updated Final Safety Analysis Report (UFSAR) in accordance with the requirements 1 O CFR 50.71(e)(4) and 10 CFR 50.4(b)(6)
* Revision No. 85 to the PSEG Nuclear LLC Quality Assurance Topical Report f) b o Y (QATR), NO-AA-10, which documents a change to the Salem/Hope Creek L1' 1 (SHC) Quality Assurance Program (QAP) in accordance with the . fa j requirements of 1 o CFR 50.54(a)(3) and 1 o CFR 71.106(b)
* . /r D5 !:J CD Enclosure 1, CD-1, contains Security Related Information
-Withhold Under
* fZ 1 O CFR 2.390. When separated from CD-1, this document is decontrolled.
I
* I I , I I ; i i-i I l I 
.. .. . JAN 3 J>"l-017" Page2 LR-N 17-0034 10 CFR 50.71(e) 10 CFR 50.54(a)(3) 10 CFR 54.37{b) 10 CFR 71.106 TS 6.17.d (Unit 1) TS 6.18.d (Unit 2)
* Complete updated copies of the Salem Unit 1 and Unit 2 Technical Specification Bases, which incl"ude changes through January 30, 2017, in accordance with the requirements of Salem Generating
: Station, Units 1 and 2 Technical Specifications 6.17.d {Unit 1} and 6.16.d (Unit 2)
* The results of a review performed as required by 10 CFR 54.37(b) to identify any newly-identified Structure, System or Component (SSC) that would be subjected to an aging management review or evaluation of time-limited aging analyses (TLAAs) in accordance with 10 CFR 54.21 Revision No. 29 to the Salem UFSAR is being submitted in its entirety electronrcally*
via CD-ROM and contains identified text, table and figure changes required to reflect the plant configuration as of July 30, 2016, six months prior to this submittal.
In addition, there are general editorial changes.
In accordance with 10 CFR 50.71(e)(2)(ii),
a summary of changes made under the provisions of 10 CFR 50.59 but not previously submitted to the Commission is provided in Attachment
: 1. Hardcopy pages containing the revised material and associated insert/remove instructions will no longer be provided.
The previous revision to the Salem UFSAR was issued on May 22, 2015. Based on NRC Regulatory Issue Summary (RIS) 2015-17, "Review and Submission of Updates to Final Safety Analysis
: Reports, Emergency Preparedness Documents, and Fire Protection Documents,"
PSEG has reviewed Revision 29 of the UFSAR for security-related information (SRI). Consequentlyf Revision 29 of the UFSAR is being provided in its entirety as two separate versions each on its own CD. One version, on CD-1, contains SRI and should be withheld from public disclosure under 1 O CFR 2.390. The information that is SRI is designated by the statement "Security-Related Information
-Withhold Under 10 CFR 2.390" at the top of the page. The second version, on CD-2, redacts the infonnation that is SRI and designates it as Related Information
-Withheld Under 10 CFR 2.390." The version on CD-2 is* suitable for publtc disclosure.
A list of what material has been redacted is provided in Attachment
: 2. , PSEG has developed Revision 85of the SHC Quality Assurance Topical Report, which governs the QAP. This version of the SHC QATR, NO-AA-10, replaces the previous version submitted to you in PSEG letter LR-N15-01'12 dated May 22, 2015. The change to the QATR is being made in accordance with the requirements of 10 CFR 50.54(a)(3) and 10 CFR 71.106(b).
The change involved no reduction in commitments and therefore did not require prior NRG approval.
10 CFR 50.54(a)(3) requires that changes that do not reduce the commitments be submitted in JAN 3 @'2017 Page3 LR-N17-0034
. 10 CFR 50.71(e) 10 CFR 50.54(a)(3) 10 CFR 54.37(b) 10 CFR 71.106 TS 6.17.d (Unit 1) TS 6.16.d (Unit 2) accordance with 10 CFR 50.71(e).
Revision 85 is the current version of the QATR that is in use at PSEG, and became effective on December 14, 2016. A summary of the changes made to the QA TR in Revision 85 is provided in Enclosure 1 of this .letter.
Enclosure 2 of this letter provides a copy of Revision 85 of the QATR for information purposes.
Enclosure 3 contains complete updated copies of the Salem Unit 1 and Unit 2 Technical Specification Bases with changes through January 30, 2017. An evaluation was completed to determine whether any newly-identified SSCs existed in support of submitting Sal.em UFSAR Revision
: 29. This evaluation involved reviewing pertinent documentation for the period subsequent to the last Salem UFSAR revision.
The evaluation concluded that there were no newly-identified SSCs and no changes to the Salem current licensing basis that would have caused any newly-identified SSCs for which aging management reviews or time-limited aging analyses would apply. As required by 1 O CFR 50.71 (e)(2)(i),
I certify that to the best of my knowledge, the information contained in the CD Enclosures and Attachments to this letter, which pertain to the Salem UFSAR Revisron 29, accurately reflect information and analyses submitted to the NRC, or prepared pursuant to NRC requirements as described above. There are no regulatory commitments contained in this letter. If you have any questions or require additional information, please do not hesitate to contact Mr. Lee Marabella, at (856) 339*1208.
Sincerely, Paul Duke Manager, Licensing PSEG Nuclear, LLC Attachments:
: 1. Summary Report of UFSAR Changes 2. List of Redacted Material
" I .l-j I I i I I JAN 3 0 21H7 Page4 LR-N17-0034 CD
 
==Enclosures:==
: 1. CD-1, Salem UFSAR Rev. 29 (withhold from public disclosure) 10 CFR (e) 10 CFR 50.54(a)(3) 10 CFR 54.37(b) 10 CFR 71.106 TS 6.17.d (Unit 1) TS 6.16.d (Unit 2) 2. CD-2, Salem UFSAR Rev. 29 {Redacted version suitable for public disclosure)
Other
 
==Enclosures:==
: 1. Quality Assurance Topical Report, NO-AA-10, Revision 85 Summary Of Changes 2. Quality Assurance Topical Report, Revision 85 3. Salem Nuclear Generating Station Unit 1 & Unit 2 Technical Specification Bases as of January 30, 2017 CC (Cover letter. GD enclosures 1 and 2. Other Enclosures 1 and 2 and Attachments 1 and 2 only) Administrator
-Region I -USNRC Licensing Project Manager -Salem and Hope Creek -USNRC USNRC Senior Resident Inspector--
Salem
* Chief, New Jersey Bureau of Nuclear Engineering (Cover letter, Other Enclosures 1 and 2 only) Director, Division of Spent Fuel Management, Office of Nuclear Material Safety and Safeguards
-USNRC (Cover letter. Attachment
: 1. Other Enclosures 1 and 2 only) USNRC Senior Resident Inspector
-Hope Creek (Cover letter and Attachment 1 only) . Salem Commitment Coordinator Hope Creek Commitment Coordinator Corporate Commitment Coordinator
' ;
LR-N 17-0034 Attachment 1 Summary Report of UFSAR Changes i I I . t I '
LR-N17-0034 Summary Report of Changes Page 1of4 Attachment 1 Salem UFSAR Revision 29 CN# SECT AFFECTED PAGES, TABLES DESCRIPTION BASIS &FIGURES SCN 12-013 3.8 3.8-68 Changes reflect adding an opening Design Change package 80106408 statement to the Section to include fiber instituted.
Associated 50.59 Screenings optic conductors.
included in SCN 12-013 package.
SCN 14-007 15.2 15.2-43,-43b,-44,
-45,-46,-
Changes made to reflect Advanced Digital Design packages 80104782(U1) 62, T15.2*1sh6a, F15.2-29A Feedwater Control System updates to and 80104783(U2).instituted.
Associated thru-29F eliminate parts obsolescence is.Sues 50.59 Screening and Evaluation included including replacing all control system in SCN 14-007 package.
equipment, additional signal validation logic and revised algorithms.
Additionally, the Excessive Feedwater Malfunction analysis was revised.
SCN 14-009 9,5 9.5-28 Changes made to reflect the demand of the Design Change packages 80109927(1) new fire suppression configuration for the and 80109928(U2) instituted.
Associated replacement Main Power Transformers and Fire Protection Change Regulatory revise the hose stream demand. Reviews and 50.59 Screenings are included in the SCN 14-009 package.
SCN 15-006 12.1 12.1-8 Change reflects removal of unnecessary Change reviewed and approved by information, eliminate inconsistency with Radiation Protection; Attachment 5 for and improve clarity of a referenced Tech non-regulatory changes is included in the Spec. SCN 15-006 package.
SCN 15-007 11.3 11.3-15 Change reflects removal of a reference to Change reviewed and approved by previously removed Tech Specs that were Radiation Protection.
Attachment 5 for placed in the Offsite Dose Calculation non-regulatory changes is included in the Manual. SCN 15-007 package.
SCN 15-008 9.3 9.3-38 Change reflects correction of Tech Spec Change reviewed and approved by Reference Error introduced by previous Systems Engineering.
Attachment 5 for Cflange Notices.
non-regulatory changes is included in the SCN 15-008 package . . . .. ,,,, ____ , .. -_,,,,_, ____ ,,, -*---**-* *-.........
"'"*-1--_,,._,,,.
-..........
_ ....... __ ,,,, .. *--'* ___ , .. ,,,,_, .
LR-N17-0034 Summary Report of Chahges Page2of4 Attachment 1 Salem UFSAR Revision 29 CN# SECT AFFECTED PAGES, TABLES DESCRIPTION BASIS &FIGURES SCN 15-009 9,5 9.5-5, -31 Changes reflect correction of a typo and Change reviewed and approved by deletion of an incorrect statement about wet Engineering Programs.
Attachment 5 for pipe system above the Aux Feed Pumps. non-regulatory changes is included in the SCN 15-009 package.
SCN 15-010 10.3, 10.4 10.3-18,
-19, 10.4-25 Change reflects the addition of Polyacrylic Design Change package 80110854 Acid (PAA) to the chemicals that are part of instituted.
Associated 50.59 Screening the Chemical Feed System and include included in SCN 15-01 O package.
their description in the Secondary Water Chemistry Control Program.
SCN 15-011 10.3 10.3-12 Change reflects removal of a reference to a Change reviewed and approved by Tech Spec description of primary to Systems Engineering.
Attachment 5 for secondary leakage limit of 1,0 GPM which non-regulatory changes is included in the was removed by TS Amendments 268/262 SCN 15-011 package.
but missed during implementation by a previous Change Notice SCN 15-012 13.5 13.5-1 Change reflects the removal of reference to Change reviewed and approved by UFSAR Chapter 16 which is the Technical Operations.
Attachment 5 for non-to eliminate confusion.
regulatory changes is included in the SCN 15-012 package, SCN 15-013 7.7 7.7-9a, -9b, -10, F7.7-7, -8, -9 Change reflects the Unit 1 Advanced Digital Design Change package 80104782 Feedwater Control System being updated instituted.
Associated 50.59 Screening to eliminate parts obsolescence issues. included in SCN 15-013 package.
SCN 15-015 12.1 12.1-6 Change reflects the revision of the Oesign Chartge package 8011427 4 description of the containment equipment instituted.
Associated 50.59 Screening hatch shielding and deleting its functionality included in SCN 15-015 package.
as a part of accident shielding.
SCN 15-016 8.1, 9.5 9.5-2, -3, 13.1-9, -11 Changes reflect manual operation of the Design Change package 80115237 Deisel Generator area Cardox system. instituted.
Associated Fire Protection Change Regulatory Review is included in SCN 15-016 package.
****-*-*-**-**---****-**--**-**--***-***-
--* ** *** ..:.i .* ***'**. -. *---* .. **-*** ---*-...... -*. -** --i * *-***--... -* .. --*-*-*--
**-. ***-***--*****--.
**-***---*.
*--.... * .* ***--..... .
LR-N17-0034 Summary Report of Changes Page3 of4 Attachment 1 Salem UFSAR Revision 29 CN# SECT AFFECTED PAGES, TABLES DESCRIPTION BASIS &FIGURES SCN 15-017 3.6, 9.3 3.6-38, T9.3-6 sh1 Change reflects the revision of the CV141 Design Change package 80099537 relief valve iift setpoint from 2735 to 2825 instituted.
Associated 50.59 Screening psig. included in SCN 15-017 package.
SCN 16-001 6.3 6.3-16, -48 Change revises the description of Change reviewed and approved by how/when the High-Head Safety Injection Systems Engineering.
A 50.59 Screening Pump min-flow is used or secured.
is included in the SCN 16-001 package.
SCN 16-002 4.4 4.4-15, -66c Change reflects that the use of the WRB-2 Change reviewed and approved by correlation has been conservatively Reactor Engineering.
A 50.59 Screening modified to utilize a penalty above a certain is included in the SCN 16-002 package.
high quality threshold within approved ranges. SCN 16-003 6.2 6.2-78, -80 Change reflects the revision of ambiguous Change reviawed and approved by lan*guage regarding the hydrogen analyzers systems Engineering.
A 50.59 Screening is included in the SCN 16-003 package.
SCN 16-006 13.2 13.2-1 Change reflects the revision-of obsolete Change reviewed and approved by wording for description of Supervisory Training.
Attachment 5 for non-regulatory Training to reflect replacement of ACAD90-changes is included in the SCN 16-006 010with a new ACAD. package.
SCN 16-007 9.4 9.4-1b Change reflects the addition of a side Design Change package 80114075 stream demineralizerfor the chilled water instituted.
Associated 50.59 Screening system to meet a license renewal life included in SCN 16-007 package.
extension commitment for Unit 1. SCN 16-009 3.8 3.8-3 Change reflects the correction of a typo Change reviewed and approved by reference of building code ACl 381-63 to Design Engineering.
Attachment 5 for correct code ACl 318-63. non-regulatory changes is included in the SCN 16-009 package.
. **-*** ... 1-*-**-**-***--
.. . . . ...
LR-N17-0034 Attachment 1 CN# SECT SCN 16-010 5.5 SCN 16-012 7A, 9.5, 13 TOC, 13.1, . SCN 16-013 6.3 SCN 16-014 3A, 8.1, 9.5, 13,1 SCN 16-017 7.6 AFFECTED PAGES, TABLES &FIGURES 5.5-29 7A-4, 9,5-2, -3, 13-i, 13.1-1, -2, -3, -9, -10, -11, T13.1-1 sh1, F13.1-2,
-3 6.3-48 3A-5, 8.1-12, 9.5-4, 13.1-10, F13.1-3 7.6-7 Summary Report of Changes Salem UFSAR Revision 29
* D.ESCRJPTION Change corrects an inaccurate description of RHR HX tube wall leak to include a possible leakage flow from RHR to Component Cooling.
Changes reflect organization and job title changes.
Change reflects the correction of a typo introduced during processing of a previous change notice, Changes reflect organizational changes affectihg Nucleci.r Oversight, Change reflects a revision of the description of control air accumulator sizing from "the accumulators are sized to provide control air for up to 100 cycles of valve opening and clbsingn to "the accurnulators are sized to provide control air to cycle the POPS to ensure the RCS pressure transient does not exceed the limit of Appendix G of 10CFR50.
****-...... --*-*-*
**-*--*-**
-*-*-**-***
...........
-
.. *****-*-****** --.... :-*-*---*-*****-***
Page4 of 4 BASIS Change reviewed and approved by Systems Engineering.
A 50.59 Screening is included in the SCN 16-010 package.
Change reviewed and approved by Licensing and Human Resources.
A 50.59 Screening is included In the SCN 16-012 package.
Change reviewed and *approved by Systems En9ineering.
Attachment 5 for non-regulatory changes is included in the SCN 16-013 package.
Change reviewed and approved by Licensing, Systems Engineering, Programs Engineering and Human Resources.
A 50,54(a}
evaluation is included in the SCN 16-014 package.
Design Change package 80118856 instituted.
Associated 50.59 Screening included in SON 16-017 package.
LR-N17-0034 Attachment 2 List of Redacted Material i i ; I l LR-N17-0034 Attachment 2 UFSAR Chapter 2.4 3.4 3.4* 3.4 3.5 3.8 3.8 3.8 3.8 5.1 List Of Redacted Material Section 2.4.5.7 {Protective Structures) 3.4.3.1 (Hurricane)
Figure 3.4-2 (Protective Dike Cross Section)
Figure 3.4*3 (Protective*
Dike Cross Section) 3.5.2.2 (Missile Protection Methods) 3.8.1.1 (Containment Structure General Description)
* 3.8.1.6.8.2 (Concrete)
Table 3.8-11 (Summary of Foundations)
Figure 3.8-1 (Containment Building Cross Section)
Figure 5.1-12 (Auxiliary Building and Reactor Containment Elevation)
Page{s) 2.4-14 3.4-3 Sheet 1of1 Sheet 1of1 3.5-3, 3.5-4 .3.8-1 3.8-35, 3.8-47 Sheets 1 and 2 of 2 Sheet 1of1 Sheet 1of1 LR-N 17-0034 Enclosure 1 PSEG Nuclear, LLC Quality Assurance Topical Report, NO-AA-10, Revision 85 Summary Of Changes PSEG Nuclear LLC -Quality Assurance Topical Report NO-AAa10, REV. 85, REVISION SUMMARY Revision 85 Effective Date -December 14, 2016 The following is a description of the changes being made to the PSEG Nuclear Quality Assurance Topical Report (QATR} in revision
: 85. Some of the changes are a result of organizational changes that have taken place at PSEG Nuclear, while others are being made to clarify, update, or correct the content of PSEG Nuclear's QA Program document.
This revision to the QATR will be submitted to the NRC for post implementation review as tracked by Order 80095829 Operation 540. A review, in accordance with HU-AA-1101, determined that formal change management plans were required for the changes taking place to the Nuclear Oversight (NOS) organization.
These plans were implemented via Order 80118029.
The key changes to the QATR made in this revision include:
* A minor clarification in the policy statement; and changes to the Table of Contents
* Identification of numerous organizational changes made at PSEG, such as the elimination of the Senior Vice President
& COO position, as well as the Operations Support Vice President and the Emergency Services Director positions, and the creation of an Engineering Vice President
: position, in Chapter 1
* Added guidance to allow use of accreditation in lieu of surveys for procurement of laboratory calibration and testing services in Chapters 1, 4 and 12 *
* Changed the guidance to remove the NSRB as an independent review function by transferring their regulatory required review activities to the PORC and the NOS organization as described in Chapters 1, 16 and 18, and in Appendices B and C *
* Incorporated numerous context revisions based on changes that took place to the NOS organization structure in Chapters 1, 10, 16 and 18, and in Appendices B, C and D
* Incorporated additional quality criteria guidance to improve the clarity and expectations necessary to meet the Company's QA Program requirements in Chapters 1, 2, 10, 16 and 18, and Appendices A, B, C and D *
* Added text to fully address corrective action basic requirements in Chapter 16
* Added additional Fukushima augmented quality guidance in Appendix A *
* Clarified audit requirements, including frequencies, in Appendix B *
* Updated the standard for NOE certification in Appendix C *
* Some of the changes in these sections are centered on current NRC regulatory guidance or exemptions from previously approved NRC Safety Evaluation Reports (SERs). 1 NO-AA-10, REV. 85, QATR REVISION SUMMARY (CONT'D)
* Added new definitions in Appendix D
* Corrected the HI-STORM docket numbers in Appendix E Based on the results of 10 CFR 50.54(a)/1OCFR71.106(b) evaluations, the changes being made to the QATR in revision 85 do not represent reductions in commitment and thus do not require prior approval from the NRC before implementation.
A more detailed summary of the changes is provided on the following pages. 2 
. . NO-AA-10, REV. 85, QATR REVISION SUMMARY (CONT'D)
Revision details * [Revision bars in the QATR show where the actual changes took place.] 1. POLICY STATEMENT The Policy Statement was revised to clarify that the QAP is not a separate document from the QATR, i.e., they are one in the same. [Request
# 15-43] 2. TABLE OF CONTENTS The Table Of Contents was updated to coincide with the revisions in other sections of the QATR. Specifically, the page numbers in Chapter 1 and 2 were updated; a new Figure was added to Chapter 1; and the title of Section 2.11 of Appendix A was changed due to material content changes in the section.
[Request
# 15-43] 3. CHAPTER 1, ORGANIZATION Specific changes to this chapter included:
-In the first paragraph in Section 2.1, a reference was added regarding a simplified organizational chart that was also .added to this chapter as Figure 1-1 . [Request
# 15-43] -A fourth paragraph was added to Section 2.1 to delineate that the line organization is solely responsible for the direction of plant activities.
This is standard industry practice and ensures that non-authorized organizations, including independent review groups, do not perform or direct an activity they are not qualified or licensed to perform.
A fifth paragraph was added to delineate line management's responsibility to the QAP. [Request#
15-44] -The personnel and functional area descriptions in Sections 2.2 and 2.3 were updated based on organizational changes directed and approved by the President and Chief Operating Officer of PSEG Power LLC. Key changes involved the elimination of the positions for President of PSEG Fossil LLC, the Senior Vice President and Chief Operating Officer of PSEG Nuclear LLC, the Operations Support Vice President, and the Station NOS Manager; and the addition of positions such as the Vice President of Engineering and the Executive Director of Corporate Operations.
[Requests#
15-42, 15-43, and 16-47] -The off-site and on-site review committee text in the second bullet of Section 2.2.2, in Section 2.3.1 item 1., and in the third bullet of Section 2.4, was revised to reflect the adoption of an NRC approved Safety Evaluation Report (SER) that permits a change to the independent review process where the process requirements for the off-site review committee is transferred to the on-site review committee and the Nuclear Oversight 3 
 
REV. 85, QATR REVISION SUMMARY (CONT'D)
(NOS) organization.
This allows the off-site review committee to function without restrictions since it is no longer based on the requirements of ANSI N18.7/ANS-3.2-1976.
(Note -these exceptions to the off-site review committee were approved by the NRC in an SER dated January 13, 2005 issued to NMC -ADAMS Accession Number ML050210276; and recently recommended by NEI Efficiency Bulletin EB 16-23.) [Requests
# 15-44, 15-45 and 16-48] -A second paragraph was added in item 2., of Section 2.3.1 containing guidance associated with plant operation already contained*
in ANSI N18.7/ANS-3.2-1976, but is worth repeating in the QA TR. [Request#
15-44] -In Section 2.5, add additional text to clarify the responsibilities of department heads with regard to implementation of the OAP. This is similar to information contained in QAPs at peer utilities.
[Request#
15-44] -In Section 2.5, fourth paragraph, text was -changed for clarification purposes.
[Request
# 15-43] -In Section 2.5, last paragraph, add the following text to the end of the paragraph
-"Delegation of commercial grade services shall be controlled through procurement documents and purchasing requirements."
(Note -This change was made to incorporate guidance necessary to implement SER, ML 14322A535, regarding use of ILAC MRA Signatory Accreditations in lieu of performing on-site commercial grade surveys.)
[Request#
15-44] -In Section 2. 7, the text was updated in an editorial change needed to describe the current status of the project for the Company's Early Site Permit (ESP). The ESP has now been issued by the NRC. [Request
# 15-43] 4. CHAPTER 2, QUALITY ASSURANCE PROGRAM Specific changes to this chapter included:
-In the second paragraph of Section 2.1, the text "1 OCFR50.55(a)"
was corrected to "1 OCFR50.55a."
*[Request
# 15-43] -A fourth paragraph was added to Section 2.1 and text was revised in Section 2.3 to provide a better description of the guidance for performing quality work in a suitably controlled environment and with controlled planning.
[Request#
15-44] 4 NO-AA-10, REV. 85, QATR REVISION SUMMARY (CONT'D)
-Added a new paragraph to Section 2.5 to address physical abilities for qualification to complete the guidance needed to align with ANSI/ANS 3.1-1981 and ANSI N18.1-1971.
[Request#
15-44] -In Section 2.7, the text was updated in an editorial change needed to describe the current status of the project for the Company's Early Site Permit (ESP). The ESP has now been issued by the NRC. * [Request
# 15-43] 5. CHAPTER 4, PROCUREMENT DOCUMENT CONTROL Specific changes to this chapter included:
-Sections 2.2.3 and 2.2.5 were revised to incorporate additional guidance.
(Note -These changes were made to incorporate guidance necessary to implement SER, ML 14322A535, regarding use of ILAC MRA Signatory Accreditations in lieu of performing on-site commercial grade surveys.)
[Request#
15-44] 6. CHAPTER 5, INSTRUCTIONS; PROCEDURES AND DRAWINGS Specific changes to this chapter included:
-Section 2.1 was revised for clarification and grammatical purposes to ensure the context of procedure use and adherence is understood.
[Request
# 15-43] 7. CHAPTER 10, INSPECTION Specific changes to this chapter included:
-In Section 2.2, the text was changed from "as appropriate by NOS" to "as appropriate by quality verification personnel" to align with the new NOS organizational structure.
[Request#
16-47] -A fourth paragraph was added to Section 2.3 to add guidance regarding "supervisor" inspection hold points that can be used to review work quality, but that cannot be used in place of required independent inspection hold points. [Request#
15-44] -Text in the third bullet of Section 2.4 was revised to align with the new NOS organizational structure, including to clarify that this portion of guidance was intended to apply to "independent" inspection hold points. [Request#
16-47] 5 NO-AA-10, REV. 85, QATR REVISION SUMMARY (CONT'D)
-Guidance in the fourth bullet of Section 2.4 was revised to indicate that inspection documentation should also be contained in associated work packages.
[Request
# 15-43] 8. CHAPTER 12, CONTROL OF MEASURING AND TEST EQUIPMENT Specific changes to this chapter included: -A second paragraph was added to Section 2.8, that states; 'When the Company uses a vendor to calibrate M& TE, the procurement documents shall impose a requirement for the accredited laboratory to provide as-found calibration data when any item being calibrated is found to be out-of-tolerance.
Corrective actions are then taken by the Company based on this information."
(Note -This change was made to incorporate guidance necessary to implement SER, ML 14322A535, regarding use of ILAC MRA Signatory Accreditations in lieu of performing on-site commercial grade surveys.)
[Request
# 15-44] 9. CHAPTER 16, CORRECTIVE ACTION Specific changes to this chapter included:
-The last sentence in Section 2.1 was revised t.o correct a grammatical error. ; [Request
# 15-43] -Basic requirements from NQA-1 did not appear to be fully addressed, thus the text in the first paragraph of Section 2.2.1 was changed to indicate that a "root'; cause is determined for SCAQs and the following guidance was added; "The impact of such conditions on completed and related items and activities is evaluated.
Follow-up reviews are then performed to verify that the corrective actions taken were effective."
[Request#
15-44] -Added a new first paragraph to Section 2.3 which states "The Company screens identified issues to verify suitable categorization and moves those that are not found to be conditions adverse to quality out of the corrective action program.
Resources are then applied to resolve issues based on significance."
(This change was added to align with the NEI Efficiency Bulletin EB 16-10 on reducing the cumulative impact of the corrective action program.)
[Request#
16-48] -In the second paragraph of Section 2.3, the text was changed from "for independent assessment findings" to "for independent audit and assessment findings";
and in the third paragraph the text was changed from "assessment results" to "audit/assessment results";
to clarify and differentiate the Assessment function from the Audit function 6
NO-AA-10, REV. 85, QATR REVISION SUMMARY (CONT'D) based on the change in the Company's Nuclear Oversight organization.
[Request#
16-47] -Removed the reference to the "off-site review committee" in the first paragraph of Section 2.5, and added the following sentence "Independent reviews of the corrective actions for significant conditions adverse to quality are performed by the on-site review committee and the Nuclear Oversight organization."
(Note -these changes align with the NMC QA Program changes approved by the NRC in an SER dated January 13, 2005 -ML050210276; and recently recommended by NEI Efficiency Bulletin EB 16-23.) [Requests
# 15-45 and 16-48] -In the third paragraph of Section 2.5, the text was changed from "in assessment reports" to "in audit and assessment reports" to clarify and differentiate the Assessment function from the Audit function based on the change in the Company's Nuclear Oversight organization.
[Request#
16-47] 10. CHAPTER 18, AUDITS/ASSESSMENTS Specific changes to this chapter included:
-Due to organizational changes in the Nuclear Oversight Department's Assessment Group, numerous changes were made to this chapter.
Specifically, changes to clarify and differentiate the Assessment function from the Audit function were made in Sections 1, 2.1.1, 2.1.2, 2.1.3, 2.1.4, 2.1.5, 2.1.6, and 2.2. [Request
# 16-4 7] -In Section 2.1".1, the following teXt was added in the first paragraph; "Except for the Security and Emergency Preparedness Audits (items I., and m., of Appendix B), ... ",to ensure that the audit extension guidance provided in this section does not get applied to these two audits. Also .in this section, guidance was added centered on current practices for establishing audit frequencies by use of a calendar month basis. [Request
# 15-44] -In Section 2.1.4, beginning at the fifth paragraph, a full page of guidance was added regarding the Company's commitment to independent review. This information was added to support the change associated with the off-site review committee function.
* (Note -these changes align with the NMC QA Program changes approved by the NRC in an SER dated January 13, 2005 -ML050210276; and recommended by NEI Efficiency Bulletin EB 16-23.) [Requests
# 15-45 and 16-48] 7 NO-AA-10, REV. 85, QATR REVISION SUMMARY (CONT'D)
: 11. APPENDIX A, AUGMENTED QUALITY Specific changes to this appendix included:
-Added a paragraph in Section 2 containing information to clarify the applicability of augmented quality requirements.
[Request#
15-44] -In Section 2.5, the parenthesis was removed around the words "Station Blackout",
and guidance was added regarding the need to comply with 1 OCFR50.63.
[Request#
15-44] -Added guidance in Section 2.6 regarding the categories for ISFSI SSCs and which of these categories should be treated with augmented quality principles.
[Request#
15-44] -Added guidance in Section 2.7, Emergency
: Planning, and 2.8, Security, that clarifies which aspects or components of these programs should be treated with augmented quality principles.
[Request
# 15-44] -Changed the guidance in Section 2.9 to allow suppliers to establish a QAP based on Revision 1 or 2 of Regulatory Guide 4.15 since there were no new regulatory requirements in Revision 2 that would warrant having the suppliers change their QAPs to commit to Revision
: 2. [Request#
15-44] -Section 2.11 was expanded to add augmented quality considerations for a hardened Containment Venting System in addition to the Spent Fuel Pool instrumentation.
(Note the above guidance was provided by the NRC in Order EA-13-109 dated June 6, 2013-ML 13130A067.)
[Requests#
14-41and15-44]
: 12. APPENDIX B, AUDIT FREQUENCY Specific changes to this appendix included:
* -Revised the text in item f., from "An outside, independent fire protection consultant meeting Society of Fire Protection Engineer member grade (or equivalent) qualifications shall serve on the audit team." to "An independent fire protection specialist meeting Society of Fire Protection Engineer member grade (or equivalent) qualifications shall serve on the audit team.", since the individual that provides this support does not need to be a "consultant" as long as they are independent of the area being audited and 8 NO-AA-10, REV. 85, QATR REVISION SUMMARY (CONT'D) can fully meet the qualification requirements.
[Request
# 15-44] -Changed the audit frequency to 12 months for audits item I., Security, and m., Emergency Preparedness; and added clarification as to how their frequency could be extended to 24 months. This change was made due to the NOS organization restructuring that affected the Assessment group's ability to provide on-going review of these functional areas. [Request
# 15-44] -Changed the text in audit item n., from "Off-site review committee
... " to "Independent review/assessment
... " since the off-site review committee is no longer a commitment due to adoption of SER ML050210276.
[Request
# 15-45] -Added clarification regarding the conduct of audits item p., Access Authorization, item q., Personnel Access Data System, and item u., Cyber Security, to ensure appropriate regulatory requirements are being met. [Request
# 15-44] -Added new audit to the table as item v., Nuclear Repair Program, to be conducted every 12 months to meet ASME code requirements and the regulatory requirements of the State of New Jersey delineated in N.J.A.C.
12:90. [Request
# 15-44] 13. APPENDIX C, CODES, STANDARDS, AND GUIDES Specific changes to this appendix included:
-In Sections 1.1, 1.3.1item5.c.,
and 1.3.2 item 3.c., eliminated the ANSI N18.7-1976/ANS-3.2 requirements associated with the off-site review committee, i.e., for subjects to be reviewed and the committee composition, meeting frequency, quorum, and records.
(Note -these exceptions to the off-site review committee were approved by the NRG in an SER dated January 13, 2005 issued to NMC -ADAMS Accession Number ML050210276; and recommended by NEI Efficiency Bulletin EB 16-23.) [Request#
16-48] -In the bottom portion of Section 1.1, an exception to the guidance in NQA-1-1994 was added regarding the "industry standard" being used .to qualify NOE personnel.
[Request
# 15-44] -In Sections 1.3.1 item 5., and 1.3.2 item 3., text was changed to correct the statement about the ANSI standard that had similar quality assurance requirements to NQA-1-1994, 9
NO-AA-10, REV. 85, QATR REVISION SUMMARY (CONT'D) i.e., the "ANSI N45.2" series of standards contained the QA standards that are now contained in NQA-1, not "ANSI N18.7-1976/ANS-3.2."
[Request
# 15-43] 14. APPENDIX D, DEFINITIONS Specific changes to this appendix included:
-Removed the reference to "assessments" in definition 2.5, since not all NOS assessments will be led by a certified ATL. [Request#
16-47] -Changed text to add and use the acronym "AIA" in definitions 2.8 and 2.9. [Request
# 15-43] -Added two new definitions to this appendix for "Line Department" (2.62) and 11alone Document" (2.107).
[Request#
15-44] -Changed the text in the second bullet of definition 2.110 from "the NOS Manager''
to "NOSrnemagement" to align more closely to the new NOS organizational structure.
[Request#
16-47] 15. APPENDIX E, SUPPLEMENTAL APPLICATIONS (STATION SPECIFIC)
Specific changes made to this appendix included:
-Corrected the HI-STORM 100 docket numbers in sections 2.1.5 and 2.2.2 from "72-1014" to "72-0048".
[Request
# 15-43] NO-AA-10, Revision 85, Prepared By: Georae J. Reed Date: QA Programs Mana 10 LR-N17-0034'
** * -*.
* Enclosure 2 PSEG Nuclear, LLC Salem and Hope Creek Generating Stations QUALITY ASSURANCE TOPICAL REPORT (QATR) NO-AA-10 Revision 85 QATR Approval Form Page 1of1 PSEG Nuclear LLC NO-AA-10 Revision 85 NO-AA-400-001 Revision 9 QUALITY ASSURANCE TOPICAL REPORT (QATR) Effective:
12/14/16 Date Reviewed by: Approved for Implementation by: Peter P. Sena Ill Nft Pe£. tJ../tJ I It; President
& CNO, PSEG Nuclear (Print/Sign)
Date Salem and Hope Creek Generating Stations QUALITY ASSURANCE TOPICAL REPORT (QATR) NO-AA-10 Revision 85 Effective Date: 12/14/16 PSEG Nuclear, LLC Corporate Headquarters 80 Park Plaza Newark, New Jersey 07102 PSEG NUCLEAR POLICY 1. POLICY STATEMENT PSEG Nuclear, LLC, is responsible for assuring that the operation, maintenance, refueling, and modification of the Salem and Hope Creek Generating Stations are accomplished in a . manner that protects public health and safety and that it is in compliance with applicable regulatory requirements.
To carry out this responsibility, Public Service Electric and Gas (PSE&G) developed and implemented a comprehensive Quality Assurance Program (QAP) that was applicable to the design, construction, and testing phases and is now applied .to the operation phase of its nuclear units. On August 21, 2000, the operating licenses for the Salem and Hope Creek Generating Stations were transferred from PSE&G to PSEG Nuclear, LLC (hereafter "The Company").
The Quality Assurance Topical Report (QA TR) is the highest tiered document that assigns major quality assurance functional responsibilities for the nuclear plants owned or operated by the Company.
The QAP as detailed in the QATR provides measures to assure the control of activities affecting the quality of structures,
: systems, and components (SSCs) (that is, SSCs that provide reasonable assurance that facilities can be operated without undue risk to the health and safety of the public),
to an extent consistent with their importance to safety. Key management representatives, including the President and Chief Nuclear Officer (P&CNO),
issue Quality Assurance (QA) policy statements.
These policy statements are mandatory throughout the Company for nuclear facilities. policy elements, as they apply to nuclear safety, include the following:
: 1. Nuclear safety is of the highest priority and shall take precedence over matters concerning power production.
: 2. The public's health ?tnd safety is the prime consideration in the conduct and support of Company operations and shall not be compromised.
All decisions, which could affect the health and safety of the public, shall be made conservatively.
: 3. The QAP is an essential part of the Company's commitment to safe and reliable nuclear power operation.
Applicable program requirements shall be strictly adhered to in the performance of activities covered by the QAP. 2. APPLICABILITY Implementing documents assign more specific responsibilities and tasks i;lnd define the organizational interfaces involved in conducting activities and tasks within the scope of this plan. These requirements apply to those organizations and positions, which manage and perform activities within its scope. All Company perso.nnel who work directly, or indirectly, for the Company are responsible for the achievement of quality in their work. Accordingly, all Company personnel and its contractors engaged in supporting nuclear generation activities shall comply with the requirements of our QAP. Page 1 of 1 Revision 85 TABLE OF CONTENTS CHAPTER 1, ORGANIZATION 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 Organization
....................................................................................................
1 2.2 Corporate Organization
...................................................................................
2 2.3 Station Organization
........................................................................................
9 2.4 Oversight of Nuclear Safety ..........................................................................
12 2.5 Responsibility
.................................................................................
12 2.6 Authority
..........................................
* .............................................
13 2.7 New Nuclear Development.
...............................................................
14 Figure 1-1 Simplified Organizational Relationship Chart ................................................
15 CHAPTER 2, QUALITY ASSURANCE PROGRAM 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 General ...........................................................................................................
1 2.2 Supplier's Quality Assurance Program ...................................................
2 2.3 Planning
..........................................................................................................
2 2.4 Program Description
.......................................................................................
2 2.5 Indoctrination
& Training
.....................................................................
3 2.6 Program Review ..............................................................................................
4 2.7 Quality Assurance Manual ..............................................................................
4 CHAPTER 3, DESIGN CONTROL 1 SCOPE .................................................................................................................
1 2. REQUIREMENTS
.................................................................................................
1 2.1 General ...........................................................................................................
1 2.2 Design Input ....................................................................................................
1 2.3 Design Process ...............................................................................................
2 2.4 Design Analyses
.............................................................................................
3 2.5 Design Verification
..........................................................................................
3 2.6 Change Control ...............................................................................................
5 2. 7 Design Errors ..................................................................................................
6 2.8 Interface Control.
.............................................................................................
6 2.9 Vendor Design Control ............................................................
: .......................
6 2.10 Modifications
...................................................................................................
7 2.11 Documentation and Records ...........................................................................
7 CHAPTER4, PROCUREMENTDOCUMENTCONTROL 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 General ...........................................................................................................
1 2.2 Content of Procurement Documents
...............................................................
1 2.3 Procurement Document Review ......................................................................
3 2.4 Procurement Records .....................................................................................
3 Page 1 of 5 Revision 85 TABLE OF CONTENTS CHAPTER 5, INSTRUCTIONS, PROCEDURES, AND DRAWINGS 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 General .....................*....................
: ................................................................
1 2.2 Preparation and Review .......................................................................
, ..........
2 2.3 Procedures and Programs
.......................... ...................................................
2 CHAPTER 6, DOCUMENT CONTROL 1 SCOPE .................................*....................................................
,. ..........................
1 2 REQUIREMENTS
.................................
: *.... , .*........................................................
1 2.1 General ............................................................................................................
1 2.2 Reviews ........
: ................................................................................
, ..................
2 2.3 Controlled Documents
...... ********'************
............................................................
2 2.4 Control Measures
............................................................................................
3; 2.5 Document Changes ......................................*.*...
.' ...........................................
3 CHAPTER 7, CONTROL OF PURCHASED
: MATERIAL, EQUIPMENT, AND SERVICES 1 SCOPE ......................................................................*..............
;:, ...........................
1 2 REQUIREMENTS
................................................................................................*
1 2.1 Supplier Selection
...........................................................................................
1 2.2 Bid Evaluations
...................................
.............
: ....................................
, .. * ........
2 2.3 Supplier In-Process Control ................................ ...........................................
2 2.4 Acceptance of Purchased Items and Services
................................................
4 2.5 Presence of Documentary Evidence
................................
-...............................
9 2.6 Spare or Replacement Items ...........................................................................
9 CHAPTER 8, IDENTIFICATION AND CONTROL OF MATERIALS, PARTS, AND COMPONENTS 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
...............................
, .............*...........................*.......................
1 2.1 General ....................................................
,., .....................................................
1 2.2 Traceability
......................................................................................................
1 2.3 Identification Methods ..........................
: ..........................................................
2 2.4 Transfer of Markings
........................
: ..............................................................
2 2.5 Limited Life Items ... .-......................................
,. .............................
****************'****
2 2.6 Stored Items ....................................................................................................
2 2.7 Software Items .........................................................................................
, ....... 2 Page 2 of 5 Revision 85 TABLE OF CONTENTS CHAPTER 9, CONTROL OF SPECIAL PROCESSES 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 General ...........................................................................................................
1 2.2 Process Control.
......................................................................................
: ....... 1 2.3 Special Processes
...........................................................................................
2 2.4 Personnel Qualification
.. .................
: ..............................................................
3 2.5 Special Process Records ................................................................................
3 CHAPTER 10, INSPECTION 1 SCOPE ....................
, ............................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 General ...........................................................................................................
1 2.2 Inspection Plans ..............................................................................................
1 2.3 Inspection Personnel and Qualification
...........................................................
2 2.4 Inspection Process ..........................................................................................
2 2.5 In-Service Inspections
.....................................................................................
3 2.6 Independent Verification
.................................................................................
4 CHAPTER 11, TEST CONTROL 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 General .................................................................................................................
1 2.2 Instrumentation and Control ............................................................................
4 2.3 Electrical Tests ................................................................................................
5 2.4 Mechanical Tests ....................................
; .......................................................
5 2.5 Physical and Chemical Tests ..........................................................................
6 2.6 Surveillance Tests ...........................................................................................
6 2. 7 Maintenance or Major Procedure Change ......................................................
6 2.8 Software Tests ................................................................................................
6 CHAPTER 12, CONTROL OF MEASURING AND TEST EQUIPMENT 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
......................................................................................
: ..........
1 2.1 General ...........................................................................................................
1 2.2 Control.
............................................................................................................
1 2.3 Labeling
...........................................................................................................
2 2.4 Accuracy
.........................................................................................................
2 2.5 Traceability and Interval
..................................................................................
2 2.6 Certified M&TE ................................................................................................
2 2. 7 Corrective Actions ...........................................................................................
3 2.8 Vendor Control ................................................................................................
3 2.9 Commercial Devices .......................................................................................
3 2.10 Calibration Records ........................................................
, ................................
3 Page 3 of 5 Revision 85 TABLE OF CONTENTS CHAPTER 13, HANDLING,
: STORAGE, AND SHIPPING 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 General ...........................................................................................................
1 2.2 Special Equipment and Environments
............................................................
1 2.3 Classification of Items ......................................................................................
2 2.4 Special Handling Tools and Equipment
..........................................................
2
* 2.5 Marking and Labeling
......................................................................................
2 2.6 Storage ............................................................................................................
2 CHAPTER 14, INSPECTION, TEST, AND OPERATING STATUS 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 General ...........................................................................................................
1 2.2 Operating Status ..........................................
, ..................................................
2 CHAPTER 15, NONCONFORMING MATERIALS, PARTS, OR COMPONENTS 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 General ...........................................................................................................
1 2.2 Identification
....................................................................................................
2 2.3 Segregation
.....................................................................................................
2 2.4 Disposition
...................................................... ................................................ 2 CHAPTER 16, CORRECTIVE ACTION 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 General ...........................................................................................................
1 2.2 Conditions Adverse to Quality .........................................................................
1 2.3 Verification and Follow-up
...............................................................................
3 2.4 Evaluation and Qualification
............................................................................
3 2.5 Documentation and Reporting
.........................................................................
4 CHAPTER 17, QUALITY ASSURANCE RECORDS 1 SCOPE ... ; .............................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 Program ..........................................................................................................
1 2.2 Administration
.................................................................................................
1 2.3 Receipt and Transmittal
..................................................................................
2 2.4 Storage and Preservation
................................................................................
2 2.5 Safekeeping and Classification
.......................................................................
3 2.6 Retention and Disposition
....................................................................
, ..........
3 2.7 Plant Operating Records .................................................................................
3 Page 4 of 5 Revision 85 TABLE OF CONTENTS CHAPTER 18, AUDITS/ASSESSMENTS 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 Audits and Assessments
-General ..........
: .....................................................
1 2.2 Vendor Audits ..................................................................................................
4 2.3 Independent Management Assessment..
........................................................
4 APPENDIX A, AUGMENTED QUALITY 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 Health Physics and ALARA (As Low As Reasonably Achievable)
..................
1 2.2 Transport of Radioactive Waste ......................................................................
2 2.3 Fire Protection
.................................................................................................
2 2.4 Repairs and Alterations
...................................................................................
3 2.5 Station Blackout
..............................................................................................
3 2.6 Dry Cask Storage System ...............................................................................
3 2. 7 Emergency Planning
....................
* ...................................................................
3 2.8 Security
...........................................................................................................
4 2.9 Support Services
.............................................................................................
4 2.10 . Structures and Components Subject to an Aging Management..
....................
4 Program for License Renewal 2.11 Fukushima Dai-ichi Event Based Quality Requirements
.................................
5 APPENDIX B, AUDIT FREQUENCY 1 TABLE -Audit Frequency
....................................................................................
1 APPENDIX.C, CODES, STANDARDS, AND GUIDES 1 SCOPE .................................................................................................................
1 1 .1 Codes and Standards
..................................................................................... 1 . 1.2 Regulatory Guides ......................................................................................
: ... 2 1 .3 Station-Specific Clarifications and Exceptions
................................................
2 APPENDIX D, DEFINITIONS 1 SCOPE .................................................................................................................
1 2 GLOSSARY OF TERMS ..............................
: .......................................................
1 APPENDIX E, SUPPLEMENTAL APPLICATIONS (STATION SPECIFIC) 1 SCOPE .................................................................................................................
1 2 REQUIREMENTS
.................................................................................................
1 2.1 Hope Creek Generating Station (HCGS) ........................................................
1 2.2 Salem Generating Station (SGS) ....................................................................
4 Page 5 of 5 Revision 85 ORGANIZATION CHAPTER 1 1. 2. 2.1 Page 1 of 15 SCOPE This chapter identifies those portions of the Company organization as it applies to the Quality Assurance Program (QAP), and defines the responsibility and authority for establishing, executing, and verifying its implementation.
The responsibility for the program is retained and executed by the Company exclusively.
Organizational responsibilities are described for assuring that activities affecting quality are prescribed and implemented by documented instructions, procedures, and drawings.
The achievement of quality in the performance of quality related activities are the responsibility of each individual in support of nuclear operations.
The requirements and commitments contained in the QAP are mandatory and must be implemented,
: enforced, and adhered to by all individuals and organizations.
REQUIREMENTS Note: Minor variations may occur between the titles contained herein and those used in practice.
Specific position descriptions may be contained in approved Company documents.
Certain functions may be named differently at each site or location.
Organization The organizational structure of the Company consists of corporate functions, and the nuclear facilities.
Organizational titles for the quality assurance functions described are identified in Company policies and procedures.
(Refer to Figure 1-1 for a simplified organizational relationship chart.) Lines of authority and responsibility are established from the highest management level through intermediate levels to the implementing personnel.
The responsibility, authority, and relationships of the various personnel and organizations are documented and maintained current.
The authority to accomplish the quality assurance functions described herein may be delegated to the incumbent's staff as necessary to fulfill the identified responsibilities.
The line organization, consisting of corporate executives and station personnel, is the primary source of information and is the only source of direction for plant activities.
Revision 85 ORGANIZATION CHAPTER 1 2.2 2.2.1 2.2.2 Page 2of15 Line management is responsible for establishing the OAP requirements in appropriate instructions, procedures and drawings, and ensuring that the achievement of quality receives emphasis in the planning, implementing, verifying, and documenting of quality-related work activities.
Corporate Organization Chairman and Chief Executive Officer The Chairman and Chief Executive Officer (CEO) of Public Service Enterprise Group (PSEG) is responsible for overall corporate policy and provides executive direction and guidance for the corporation as well as promulgates corporate policy through the Company's executive management staff. President and Chief Operating Officer Reporting to the PSEG CEO is the President and Chief Operating Officer (P&COO) of PSEG Power LLC who is responsible for PSEG Power policy, providing executive direction and guidance for the company, and promulgating corporate policy through Power's senior management staff. Reporting to the P&COO are executives in charge of three subsidiaries, including PSEG Nuclear LLC, PSEG Fossil LLC, and Energy Resources and Trading LLC. Overall responsibility for the implementation of the OAP as described in this document is delegated to the President and Chief Nuclear Officer (P&CNO) of PSEG Nuclear LLC. The P&COO participates in the formulation of nuclear group strategy and policy, and remains cognizant of the performance of the nuclear stations through:
-Periodic attendance at station meetings, receipt of Nuclear Oversight (NOS) audit and assessment
: reports, station reports, and I
* business-related performance indicators.
-An off-site review committee reports to and advises the P&COO of the results of their oversight of plant operations related to safe operation of the station and the Company's nuclear program relative to nuclear safety. In lieu of ANSI N18.7-1976/ANS-3.2 requirements, the committee operates in accordance with the Company's written procedures and instructions which delineate committee composition, responsibility, authority, member qualifications, meeting frequency, subjects to be reviewed, reporting requirements, and administrative controls under which the board operates.
The off-site review committee is responsible for notifying the P&CNO of any issues identified by the committee related to the safe and reliable operation of the nuclear facilities.
This committee is referred to as the Nuclear Safety Review Board. Revision 85 ORGANIZATION CHAPTER 1 2.2.3 Page 3of15 President and Chief Nuclear Officer The P&CNO of PSEG Nuclear LLC is responsible the safe and reliable operation of the Company's nuclear facilities.
This position provides executive direction and guidance and is responsible for setting and implementing
: policies, objectives, expectations and priorities to ensure activities are performed in accordance with the OAP and other requirements.
Reporting to the P&CNO is corporate level management that includes the Station Vice Presidents, the Vice President of Engineering, the Executive Director Corporate Operations, the Regulatory Operations
: Director, the Nuclear Training
: Director, and the Nuclear Oversight (NOS) Director.
Also reporting to the'P&CNO are select matrixed personnel providing business
: support, human resources
: support, legal, procurement, and communications support.
The P&CNO regularly assesses the scope, status, adequacy, and compliance of the QA Program to 1 OCFR50, Appendix B; in support of the nuclear operating units and independent spent fuel storage installation through:
-Frequent attendance at meetings, receipt of NOS audit and
* assessment
: reports, audits by independent
: auditors, NRC inspection
: reports, and department status reports.
-Periodic audits and assessments of the QA program are preplanned, documented, and disseminated to the senior management team. These independent reviews address the scope, status, and adequacy of the QA program at each of the nuclear facilities.
: 1. The Station Vice Presidents are responsible for overall plant operation and make recommendations for performance improvement, as appropriate.
Reporting to this position are management positions responsible for day-to-day activities at the stations
. .Refer to section 2.3 for the responsibilities and authorities of the station level managers.
: 2. The Vice President of Engineering reports to the P&CNO and is responsible for executive oversight of the engineering, fuels, and projects organizations in support of the nuclear units. The Director of Engineering Services reports to the Vice President of Engineering and is responsible for providing engineering governance and oversight, as well as in some cases providing direct engineering support and perform functions.
This organization oversees all engineering tasks, such as procurement engineering, Revision 85 ORGANIZATION Page 4of15 CHAPTER 1 design control, and system, component, and reactor engineering activities at the stations; maintains the plant design basis drawings and documentation;-provides direction and control of the implementation of the required ASME code-based plant repair program; oversees implementation and control of special processes required to maintain the nuclear units; facilitates component maintenance optimization and monitors system health to improve overall equipment reliability; and oversees the records management
: program, ensuring the station's quality assurance records are properly processed,
: approved, and stored. The Nuclear Fuels Director reports to the Vice President of Engineering and is responsible for providing governance and oversight of the purchase and use of the nuclear fuels required to operate the nuclear units. The Fuels organization is responsible for providing direction and control of the nuclear fuel processes including new fuel receipt inspections, fuel reliability, and spent fuel management; for the plant's reactivity management processes; and for the special nuclear material control processes at the stations.
The Nuclear Projects Director reports to the Vice President of Engineering and is responsible for and control of unique activities such as a plant system, structure, or component modification or replacement project.
The Projects organization is responsible for ensuring that each project is appropriately
: planned, monitored, controlled,
: executed, and closed in accordance with approved processes that support long term asset management and continuous improvement in plant safety and reliability.
In order to centralize and improve the efficiency within the Company's Engineering
: function, the Station Engineering Directors also report to the Vice President of Engineering.
Refer to section 2.3.3 for the responsibilities and authorities of the Station Engineering Directors.
Matrixed to the Engineering organization is corporate support for information technology that includes the acquisition and enhancement of computer
: hardware, communication and software
: systems, established to support the operational requirements of the nuclear The Information Technology Manager administers the digital technology software quality assurance program and ensures that cyber security and the stability of the computer based local area network, the distributed
: network, plant process systems, and related digital equipment is properly maintained.
Revision 85 ORGANIZATION CHAPTER 1 Page 5of15 3. The Executive Director Corporate Operations advises Company management regarding the overall performance and reliability of plant operations and makes recommendations for performance improvement as appropriate.
Reporting to the Executive Director Corporate Operations are the performance improvement, fire protection, maintenance
: services, and outage services organizations.
The Performance Improvement Director reports to the Executive Director Corporate Operations and is responsible for providing the leadership team with a comprehensive picture of station performance.
The performance improvement organization provides direction and control of the station's learning
: programs, including the corrective action program, the operating experience
: program, the self-assessment and benchmarking
: programs, and human performance tools usage. Reporting to the Performance Improvement Director are corporate functional area managers and learning program managers that have been established to provide functional area governance and oversight and to monitor station performance and drive improvement in key functional areas, such as operations, maintenance, chemistry,
: radwaste, work management, and plant outages.
The Fire Protection Manager reports to the Executive Director Corporate Operations and is responsible for providing fire protection and control services to the nuclear stations.
The Fire Protection organization maintains the fire protection
: program, including operation, maintenance and testing of the fire protection systems and equipment, and overseeing processes such as transient combustible controls and confined space activities.
The Maintenance Services Manager reports to the Executive Director Corporate Operations and is responsible for providing the nuclear stations with comprehensive support to make repairs and to assist in post maintenance tests at the nuclear units as scheduled.
The Maintenance Services organization provides supplemental maintenance technicians to support scheduled work; provides control and calibration of measuring and test equipment used in safety-related work activities; and performs calibration of station radiation protection devices.
This department also provides facilities maintenance support; resources for protecting the environment from day-to-day plant operations; and is responsible for maintaining the site's meteorological tower and equipment.
The Outage Services Manager reports to the Executive Director Corporate Operations and is responsible for coordinating refueling outage support and overseeing the in-service testing and inspection Revision 85 ORGANIZATION CHAPTER 1 Page 6of15 program.
The Outage Services organization provides support to the stations during outages in the areas of reactor services, turbine services, and inspection
: services, including non-destructive examination and quality verification independent inspections.
This department also oversees and is responsible for the independent spent fuel storage installation and dry cask storage related activities associated with spent fuel handling,
: loading, and cask processing.
: 4. The Regulatory Operations Director provides direction and control of regulatory functions that support the stations, including licensing, environmental, nuclear security, and emergency preparedness activities required for safe operation of the nuclear units. This position is responsible for developing policies and standardized processes for maintaining the station's licensing basis, and for the preparation of correspondence and required submittals to the NRC and other federal, state, and local regulatory agencies.
Reporting to this position are managers for licensing, regulatory compliance, environmental
: affairs, security, and emergency preparedness.
The Regulatory Operations organization maintains:
-The plant operating licenses and final safety analysis
: reports,
-The biological and environmental programs for the site, -The nuclear security
: program, including site access controls for badging, background investigations, and fitness for duty, as well as testing and maintenance of security
: systems, and -The emergency preparedness
: program, including maintenance of the emergency organization staffing and training, as well as maintaining the emergency response facilities.
: 5. The Nuclear Training Director provides direction and control of the training functions that support the stations, including accredited
: training, management and supervisory
: training, initial and continuing
: training, and specialty training.
This position is responsible for developing policies and standardized processes for implementing and maintaining a knowledgeable and proficient station work force. Reporting to this position is a technical training
: manager, and station training managers for operations and maintenance.
The training program established ensures that those personnel performing activities affecting quality are able to achieve and maintain suitable proficiency in their work discipline.
The training also includes the administrative controls and OAP requirements that will enable workers to understand arid fulfill policies and procedurally driven job expectations.
Revision 85 ORGANIZATION CHAPTER 1 Page 7of15 6. The NOS Director provides direction and control of functions that audit and assess the safe operation of the nuciear stations, the quality of work performed by support personnel, compliance with the QAP, nuclear safety requirements, company policies, regulatory commitments, governmental regulations, and vendor quality program oversight.
This position has been delegated the authority and has the independence to interpret quality requirements, identify quality problems and trends, and provide recommendations or solutions to quality problems.
Functional responsibilities include:
-Establishing quality assurance practices and policies Ensuring effective implementation of the independent safety review function
-Maintaining independent audit and assessment activities
-Initiating stop work, ordering unit shutdown, or requesting any other actions deemed necessary to avoid unsafe plant conditions or a significant violation of the QAP -Overseeing implementation of the three-tiered approach to accomplish the oversight of nuclear safety -Maintaining a trained and qualified staff of personnel within the NOS organization and ensuring orientation of all Company personnel to the QAP is performed as part of general employee training
-Ensuring the planning, scheduling, and performance of audits and assessments are conducted within the Company as defined in the QAP and NOS procedures
-Overseeing the initiation,
: trending, and recommendation of solutions for deficiencies identified by the NOS organization
-Controlling the maintenance and content of the QAP and the program for employee concerns
-Overseeing the nuclear station NOS activities, including day and emergent plant performance issues -Coordinating assessments/observations of selected operation, maintenance,
: testing, engineering, and contractor activities
-Periodically apprising the President and CNO and the Nuclear Safety Review Board of the status of quality assurance functions at Company nuclear facilities, and immediately notifying them of significant issues affecting quality -Settling disputes between NOS and other organizations
-Serving as the certifying authority for Lead Auditor and Independent Inspector candidates
-Verifying satisfactory implementation of solutions for significant conditions adverse to quality -Overseeing implementation of the independent inspection program Revision 85 ORGANIZATION CHAPTER 1 described in Chapter 10, including use of independent inspection hold points to verify conformance to applicable codes and standards
-Verifying compliance to the QAP by ensuring associated quality activities are conducted thru rigorous procedure use and adherence Company policies and organizational structure assure that this management position has sufficient organizational freedom and independence to carry out its responsibilities.
This management position assures that an appropriate QAP is established, maintained, and effectively executed throughout the nuclear organization.
Reporting to this position is an audit manager, a QA programs
: manager, an employee concerns program manager, and station assessment personnel.
Certain quality activities governed by this QAP reside and are managed by PSEG organizations outside of the NOS Department.
In order to ensure the associated quality functions, i.e., the Laboratory and Testing Services Quality Assurance
: Manager, the Procurement Design Engineering
: Manager, the Warehouse Receipt Inspector Supervisor, and the Non-Destructive Examination (NDE) Independent Inspection Superintendent, can perform their quality functions with sufficient independence from cost and schedule when opposed to safety considerations, a matrixed relationship (i.e., a dotted line reporting relationship) has been established from these individuals to the NOS Director.
This arrangement bestows the NOS Director with the authority to intervene in an inappropriate decision being made by a member of line management when a quality issue has been factually identified by any of these four entities.
: 7. Of the management positions matrixed to the P&CNO: Page 8of15 -The Business Support Director ensures integrated support to senior management and the nuclear stations for associated business and financial This organization is responsible for business planning and financial process improvement, business operations records management, and financial actions associated with nuclear unit decommissioning reporting and trust fund activities.
-The Nuclear Procurement Director ensures that the quality requirements of this QAP are met in the area of procurement and warehousing.
This includes establishing priorities and providing operational control of the purchase of non-fuel goods and services required for nuclear operations.
This organization is responsible for the procurement of safety-related materials and services, material receipt inspection, inventory
: control, and parts storage and warehousing.
-The Human Resources, Legal, and Communications management personnel facilitate support as needed by the P&CNO. Revision 85 ORGANIZATION CHAPTER 1 2.3 Station Organization The Station Vice President (SVP) is the senior manager directly responsible for the activities involving the safe, efficient and reliable operation and maintenance of the Company's nuclear units. These activities include plant operation, maintenance, work management, outage management, engineering
: sJpport, training, chemistry, radiation protection, liaison activities with regulatory and other agencies, and general administration and process control.
This individual is responsible for station compliance with its NRC operating
: license, associated governmental regulations, and ASME code requirements.
In support of the SVP, day-to-day direction and management oversight of activities associated with effective nuclear station operational performance is provided.
The following functions have station management who report directly to the SVP: -Overall plant operations
-Organizational effectiveness The following functions have management that is matrixed to the SVP: -Plant Engineering
-Business Operations
-Human Resources 2.3.1 The management position for overall plant operations, i.e., the Plant Manager, assures the safe, reliable, and efficient operation of the plant within the constraints of the plant's operating
: license, administrative
: controls, and QAP. This includes ensuring the prompt reporting of unusual plant events, the thorough evaluation of plant safety-related activities a11d issues, implementation of effective corrective
: actions, and ensuring that necessary support and resources are available.
Functional.
areas of responsibility in.elude:
: 1. An on-site multi-disciplined review committee responsible for review of activities that affect nuclear safety, reports to, and advises the management position responsible for plant operation on matters related to nuclear safety. The committee shall review safety-related changes to Technical Specifications and License Amendments prior to implementation; root cause evaluations; and corrective actions for significant conditions adverse to quality.
The committee shall also ensure that plant activities are conducted safely and that changes do not require NRC review and approval prior to implementation.
, Page 9 of 15. Revision 85 ORGANIZATION CHAPTER 1 The committee functions in accordance with written instructions which delineate committee composition, responsibility, authority, member qualifications, meeting frequency, subjects to be reviewed, reporting requirements, and administrative controls under which the group operates.
The committee chair shall have the authority to obtain assistance from outside consultants or organizations if sufficient expertise is not available from within the Company to enable it to perform its review responsibilities.
* In performing its independent review responsibilities, the on-site review committee shall keep safety considerations paramount when opposed to cost or schedule considerations.
Also, should a voting member have direct responsibility for prior preparation or technical review of an item being presented to the committee, or where similar conflicts may be likely, that member shall be replaced (if necessary to fulfill the quornm) by another voting member not having such potential conflict.
This committee is referred to as the Plant Operations Review Committee.
: 2. Management positions responsible for chemistry, environmental, operations, maintenance, on-line work management, radiation protection, and outage management report directly to the position responsible for overall plant operations thereby providing control over those activities necessary for safe operation and maintenance of the plants. The management position responsible for operations oversees the plant operations personnel and crews that control the nuclear units on a day-to-day basis. This individual ensures that the nuclear units are operated within the constraints of the plant's operating license.
On each crew, the reactor operators have the authority and responsibility for shutting the reactor down whenever it is determined to be appropriate from a nuclear safety standpoint or when an automatic shutdown should have occurred but did not. . The management position responsible for operations has the responsibility to determine the circumstances, analyze the cause, and determine that operations can proceed safely before the reactor is returned to power after a trip or an unscheduled or unexplained power reduction.
2.3.2 The management positio.n for organizational effectiveness is responsible for overseeing station performance assessments and trending, recommending, and initiating
*solutions for identified gaps in performance.
This individual ensures the station takes steps as needed to resolve identified performance gaps through effective implementation of the station's learning programs.
Page 1 O of 15 Revision 85 ORGANIZATION CHAPTER 1 2.3.3 Reporting to the management position for organizational effectiveness is a staff of performance improvement and learning program specialists that facilitate implementation of the following programs:
corrective action . self-assessment benchmarking operating experience The management position for plant engineering reports to the Vice President of Engineering, but has direct interface with the SVP. This individual has the responsibility and authority for day-to-day engineering support activities, develops and maintains engineering
: programs, policies, procedures, and provides engineering services in accordance with the QAP. A staff of supervisory, technical, and administrative personnel supports plant operations and maintenance activities.
The station's management position for engineering reports directly to the Vice President of Engineering in order to promulgate independence from the cost and scheduling pressures associated with plant operations to allow the engineering staff to remain focused on their nuclear safety-related tasks. Functional areas of responsibility include:
design engineering engineering administration modifications and their implementation plant configuration control system engineering system testing technical support 2.3.4 Management positions for business operations and human resources are matrixed to the SVP to assist in controlling the financial, administrative, and personnel (staffing) activities associated with running the station.
* Page 11 of 15 Revision 85 ORGANIZATION CHAPTER 1 2.4 2.5 Page 12of15 Oversight of Nuclear Safety In association with -the NUREG-0737 Independent Safety Engineering Group (ISEG) requirements, the Company uses a three-tiered approach to accomplish the oversight of safety which comprises: -A collection of program elements for implementing and/or reviewing areas of quality of plant operations and nuclear safety. These elements include system performance monitoring, review of operating experience information, operability evaluations, and reviews of changes to technical specifications and final safety analysis reports that affect design bases. Specific guidance is contained in applicable procedures and programs.
-An NOS staff that assesses and audits aspects of Company activities within the scope of the OATR relating to safety. This provides for an overview of activities affecting or potentially affecting safety. -An on-site review committee that reports to and advises the Plant Manager on all matters related to nuclear safety associated with plant operations; and an off-site review committee that reports to and advises the P&COO of the results of oversight of plant operation relative to nuclear safety. The off-site committee also notifies the P&CNO of any nuclear safety-related issues that may effect operation of the nuclear units. Responsibility Each holder of a position as identified in this Chapter, has the responsibility for the scope and effective implementation of the OAP in
* their functional area and may delegate all or part of the activities of planning, establishing, and implementing the OAP to other qualified individuals, but retains the responsibility for the program's effectiveness.
The head of each department/functional area performing quality activities is responsible for: -Administering those activities within their organization which are required by this QAP; -Establishing and maintaining clear definitions for the duties and responsibilities of personnel within their organization who perform quality activities;
-Planning, selecting, and training personnel to meet the requirements of this QAP; and -Performing and coordinating the quality activities within their department and ensuring appropriate interface occurs with the NOS department.
Revision 85 ORGANIZATION CHAPTER 1 2.6 The Company is responsible for ensuring that the applicable portion(s) of the QATR is properly documented,
: approved, and implemented before an activity within the scope of the QAP is undertaken by the Company or by others. Personnel performing independent audit, assessment, and inspection I
* functions for the Company have the responsibility, authority, organizational
: freedom, and sufficient independence from cost and schedule when opposed to safety considerations to: -Assure that further processing,
: delivery, installation,
.or use is controlled until proper disposition of a nonconformance, deficiency, or unsatisfactory condition has occurred.
-Identify quality problems.
-Initiate, recommend, or provide solutions to quality problems through designated channels.
-Initiate stop work or request other actions deemed necessary to avoid unsafe plant conditions or a significant violation of the QAP. -Verify implementation of solutions for significant conditions adverse to quality.
-Escalate unresolved quality problems to the level of management necessary to effect resolution.
The Company may delegate certain phases of the work to company labo.r and contracted
: services, which act as the Company's agents in assigned areas. They shall work to a Company accepted quality program (or in accordance with the Company's program) under overall site direction, and document their organization and any delegated responsibilities necessary to establish,
: execute, and verify their quality program.
The Company may also assign the authority for certification and stamping in accordance with the ASME Code. Delegation of commercial grade services shall be controlled through procurement documents and purchasing requirements.
Authority When the-Company delegates responsibility for planning, establishing, or implementing any part of the overall QAP, sufficient authority to accomplish the assigned responsibilities is delegated.
Regardless of delegation, the Company retains responsibility.
ORGANIZATION CHAPTER 1 Page 13of15 Revision 85 2.7 Page 14of15 New Nuclear Development The Company has obtained an Early Site Permit (ESP) from the Nuclear Regulatory Commission for the potential development of a new nuclear facility at the Salem and Hope Creek Generating Station site. The responsibility for this project is the Site Regulatory Compliance Director.
As part of the application, a separate QAP was established to govern the implementation of the quality criteria necessary to satisfy the 1 OCFR52 Subpart A requirements associated with the ESP. This quality program was written to support the ESP Safety Analysis Report and is contained in a stand-alone Quality Assurance Program Document.
On a limited basis with respect to the ESP project, administrative controls and processes of this QAP (associated with the operating units) will be used in certain areas, such as audits, vendor surveillances, and procurement.
Revision 85 I I ORGANIZATION CHAPTER 1 Simplified Organizational Relationship Chart Figure 1-1 Chairman
& Chief Executive Officer (CEO) Public Service Enterprise Group (PSEG) President
& Chief Operating Officer (P&COO) PSEG Power LLC I Nuclear Safety I /l Review Board (NSRB) , , , , , , , , I , , , , , President President
& Chief Nuclear , President PSEG Fossil LLC Officer (CNO) PSEG ER& T LLC PSEG Nuclear LLC ,' /------,
I I Business Support Engineering
-,..-Information I Corporate Human Resources Vice President Technology Directors*
Procurement Legal I Communications Station Director Nuclear Oversight II Fuels rH Projects I Vice Presidents
------... _ I (NOS) ------, --Outage Services Engnr'g , , I --, I 1--NDE Superintendent Services
, , I , I I I QV & NDE Inspectors
, , I QA Programs
-4 Employee Concerns I I , I I Manager Program Manager I I Station I I Plant I I Engineering Managers I Directors I I Lab & Testing Services I I QA Manager I I I I r--Equipment Repair I I I CMS QC Inspector I I I I I I Station Assessment NOS Audit I Plant Operations Team Lead Manager I Other I Station Review Committees I I I Procurement Design Directors (PORC) ---Engineering Manager I Team Lead Internal Auditors I Warehouse/Inventory Assessors and Vendor Auditors Receipt Inspectors Legend: Responsibility
------------
Matrixed Responsibility
* For Corporate Operations, Regulatory Operations, and Nuclear Training.
------------------
Explicit Communication Page 15of15 Revision 85 QUALITY ASSURANCE PROGRAM CHAPTER2
: 1. 2. 2.1 Page 1of4 SCOPE The purpose of this chapter is to define how the Company's QAP applies to those activities such as training, design, procurement, fabrication, installation, modification, maintenance, repair, refueling, operation, inspection, and tests related to structures,
: systems, and components.
The QAP also applies to certain non-safety related structures,
: systems, components and activities to a degree consistent with their importance to safety. Policies, directives, procedures, guidelines,
: manuals, or instructions shall be reviewed,
: approved, distributed, and revised in accordance with administrative
*procedures.
REQUIREMENTS General The QAP comprises all those planned and systematic actions necessary to provide adequate confidence that structures,
: systems, and components will perform satisfactorily in service.
Quality assurance includes quality verification, which comprises the examination of those physical characteristics of material, structure, component, or system, which provide a means to control the quality of the material, structure, component, or system to predetermined
* requirements.
All persons and organizations involved in activities in support of the nuclear sites and governed by this program are responsible for implementing the requirements of this manual. The QAP is based upon 1 OCFR50, Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants."
The requirements of 1 OCFR50.54, "Conditions of Licenses,"
1 OCFR50.55a, "Codes and Standards,"
1 OCFR50.59, "Changes, Tests, and Experiments,"
1 OCFR50 Appendix A, "General Design Criteria for Nuclear Power Plants,';
1 OCFR50 Appendix R, "Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979," are included in the basis for the QAP. The requirements of 10CFR21, "Reporting of Defects and compliance,"
: 10CFR71, Subpart H, "Packaging and Transportation of Radioactive Material
-Quality Assurance,"
and 1 OCFR72, Subpart G, "Licensing Requirements for the Independent Storage of Spent Nuclear Fuel, High-Level Radioactive Waste, and Reactor-Related Greater Than Class C Waste -Quality Assurance" are also included.
The Company is committed to carrying out the provisions of various NRG regulatory guides and industry standards, which further define QAP requirements (see attached Appendix C). Revision 85 QUALITY ASSURANCE PROGRAM CHAPTER2 2.2 2.3 2.4 Page 2 of 4 Nuclear safety-related activities, including activities affecting the fire protection of safety-related areas, are to be accomplished under suitably controlled conditions; taking into consideration the need for procedures, special controls, cleanliness, special processes, test equipment, tools, and personnel qualifications and skills necessary to achieve the required quality.
The verification of quality occurs by inspection,
: testing, examination, and operational monitoring of SSC performance, as well as implementation of formal assessment, audit, and independent review activities.
Supplier's Quality Assurance Program The Company's procurement documents require that each vendor, supplier, or contractor maintain a quality assurance program that satisfies 10 CFR 50 Appendix B and the applicable portions of: -ASME NQA-1 or the ANSI N45.2 series of standards for previously accepted non-ASME QAPs -ANSI N18.7 standards
.:... ASME Section Ill, Appendix XXll for suppliers of ASME code design services Planning Planning establishes the systematic, sequential progression of actions to meet the defined requirements.
The Company documents these plans in appropriate communications, approvals, instructions, and procedures.
Activities described in the QAP are planned, as appropriate for the situation,*
so they are accomplished under controlled conditions which include appropriate equipment, qualified personnel, suitable environment, and use of appropriate procedures.
Program Description The Company's total program for providing administrative controls and qu*ality assurance is incorporated in many diverse documents.*
The Company's nuclear document hierarchy describes the implementation of the QAP. Approved implementing procedures and instructions are written to the extent necessary to implement the quality requirements of 10 CFR 50 Appendix B. Line, staff, administrative, and quality
* oversight organizations issue and control these implementing procedures.
All activities affecting quality are described in sufficient detail to assure quality.
Revision 85 QUALITY ASSURANCE PROGRAM CHAPTER2 2.5 Page 3 of 4 Indoctrination
& Training Formal indoctrination and training programs for personnel performing or verifying activities within the scope of this OAP are established and maintained.
These programs shall meet or exceed the requirements in applicable federal regulations as well as appropriate industry standards, including ANSI/ANS 3.1-1981 Section 5, and the accreditation standards set by the National Nuclear Accrediting Board. A training organizational element is established and staffed with qualified instructors and is responsible for planning, scheduling, developing and providing training to Company personnel.
The indoctrination and training programs are established by on-site and by off-site organizational units responsible for the performance or verification of activities within the scope of the OAP. Indoctrination,
: training, and qualification programs are established such that: -Certificate of qualification clearly delineates the specific functions personnel are qualified to perform and the criteria used to qualify personnel in each function.
-Formal training and qualification programs documentation includes the objective, content of the program, attendees, and date of attendance.
-Personnel responsible for performing quality-affected activities are instructed as to the purpose, scope, and implementation of the quality-related
: manuals, instructions, and procedures.
-Personnel verifying activities affecting quality are trained and qualified in the principles, techniques, and requirements of the activity being performed.
-Proficiency of personnel performing and verifying activities affecting quality is maintained by re-training, re-examining, re-qualifying, and/or re-certifying as determined by management or program commitment.
-Proficiency tests are given to those personnel performing and verifying activities affecting
: quality,
'and the acceptance criteria are developed to determine if individuals are properly trained and qualified.
In addition to knowledge and demonstrated abilities, personnel performing or verifying activities associated with this QAP must also be evaluated for trustworthiness and the physical capabilities that are
* required to successfully perform their assigned tasks. This includes such things as visual acuity, hand dexterity, and their ability to manage fatigue and remain fit to perform their assigned work.
Revision 85 QUALITY ASSURANCE PROGRAM CHAPTER2 2.6 2.7 Page 4 of 4 Program Review The effectiveness of the OAP and its implementation is periodically reviewed by various organizations at various levels using various tools, such as focused area self-assessments, development and trending of key performance indicators, causal analysis
: reports, and industry peer review visits. The results of these reviews are documented in reports to senior management for evaluation and corrective action is initiated as required.
The effectiveness of the QAP is also evaluated and
* reported by NOS through this organization's on-going monitoring, assessment, and inspection functions.
Otner organizational elements provide additional information/
evaluations as requested.
Quality Assurance Manual This QATR is a Quality Assurance Manual (QAM) that contains the Company's OAP for its operating units. The QAM is made available to NRC, Company personnel, the Authorized Nuclear Inspector (ANI), and other regulatory authorities.
The Company submits revisions to the QAP document (as a topical report) to the NRC for acceptance in accordance with 10 CFR 50.54, Conditions of Licenses, Section (a). The Company developed and maintained a separate Quality Assurance Program Document (QAPD) for the ESP project activities described in section 2.6 of Chapter 1. The QAPD implements quality assurance measures equivalent in substance to the measures described in 10 CFR 50 Appendix B applicable to the project.
Because the ESP is for new generation nuclear designs, the QAPD is based on different codes and standards than is committed to in the QATR. For this reason, the two OAP documents are maintained and implemented separately in every respect; meaning that the OAP for the ESP project will be strictly based on the content of the QAPD, while the QAP for the operating nuclear units will be strictly based on the content of the QATR. Where resources of the operating nuclear units are needed to support the ESP, procedures will be prepared and utilized to govern the utilization of these resources in a manner that meets the requirements of both QAPs. With the issuance of the permit from the NRC, the ESP project activities have teased and the QAPD has been placed in a dormant condition under the control of the Director Regulatory Affairs. These controls will remain in effect until such time as the Company deems it appropriate to modify its stance on new nuclear facilities and actions are taken to re-activate the QAPD to align with the needs of the business.
Revision 85 DESIGN CONTROL CHAPTER3 1 2 2.1 2.2 Page 1 of 7 SCOPE The purpose of this chapter is to establish the requirements and control measures for assuring design bases and regulatory requirements are correctly translated into design documents.
The scope of design control covers all phases of engineering design, including:
identification of design inputs (criteria and bases); identification and control of design interfaces; production of design documents, calculations and analyses; procurement related engineering and design verification.
REQUIREMENTS General The Company has overall responsibility for design and. design control activities including, preparing, reviewing, approving, and verifying design documents related to the plant's structures,
: systems, and components within the scope of the QAP. Additionally, the Company is responsible for reactor core design analysis, core design specifications and design reviews, for nuclear fuel and in-core components.
Qualified personnel perform detailed design activities or review and control design work involving electrical, mechanical, structural, and instrumentation and control designs.
Design activities are conducted to written procedures that include consideration of quality standards, quality assurance requirements, suitability of material parts,
* equipment, and processes, control of design interfaces, analytical or testing requirements, design basis, and configuration management.
Design Input The Company has the responsibility to properly translate applicable safety analysis
: reports, regulatory requirements, ASME Code requirements, and design bases into specifications,
: drawings, procedures and instructions.
The Company is responsible for electrical, mechanical, structural, instrumentation and control, nuclear engineering activities involved in nuclear station modifications, and also maintains a configuration management program.
Revision 85 DESIGN CONTROL CHAPTER3 2.3 Page 2 of 7 Design inputs, such as design bases, performance requirements, regulatory requirements, codes, and standards shall be identified and documented.
Their selection shall be reviewed and approved by the responsible design organization.
The design input shall be specified and approved in a timely manner and be to the level of detail necessary to provide a consistent basis for making design decisions, accomplishing design verification, and evaluating design changes.
Changes from approved design inputs, including the reason for the changes shall be identified,
: approved, documented, and controlled.
Design Process The Company is responsible for design changes, performs detailed design activities, and issues design documents in accordance with approved procedures.
The responsible design organization shall prescribe and document design activities in a timely manner and to the level of detail necessary to permit verification that the design meets requirements.
Included in this scope of activities are considerations for field design engineering, fire hazards, human factors,
: physics, seismic, stress, compatibility of materials, application of special process, associated computer programs;
: thermal, hydraulic, ALARA and radiation
: factors, the safety analysis accident scenarios, and accessibility for in-service inspection, maintenance and repairs, and quality standards.
Design documents shall be adequate to support facility design, construction, and operation.
Selection of the appropriate quality standards shall be documented, reviewed and approved.
Reasons for changes from specified quality standards, shall be identified, documented, approved and controlled.
Design methods, materials, parts, equipment, and processes that are essential to the function of the structure, system, or component shall be selected and reviewed for suitability of application.
Applicable industry experience,*
as set forth in reports or other documentation, shall be made available to cognizant design personnel.
Revision 85 DESIGN CONTROL CHAPTER3 2.4 2.5 Page 3 of 7 The final design output documents and approved changes thereto shall be relatable to the design input by documentation in sufficient detail to permit design verification.
The final design shall identify assemblies and/or components that are part of the item being designed.
If materials, parts, equipment, or processes are different from the published supplier information, these differences shall be documented.
Commercially standard (catalog items) materials, parts, or equipment, which have been previously approved for different applications, are reviewed for suitability in the design process.
Design Analyses Design analyses shall be performed in a planned, controlled, and documented manner. Design analysis documents shall be legible and suitable for reproduction, filing, and retrieval.
They shall be sufficiently detailed as to purpose, method, assumptions, design input, references, and units such that a person technically qualified in the subject can review, understand the analysis, and verify the adequacy of the results without recourse to the originator.
Calculations shall be identified for retrievability by subject including structure, system, component, originator,
: reviewer, and date or by other unique identifiers.
Computer programs shall be controlled to assure that changes are documented and approved.
Verification shall be required for changes to previously verified computer programs including evaluation of the effects of these changes as specified below. Computer programs may be utilized for design analysis without individual verification of the program for each application provided:
-The computer program has been verified to show that it produces correct solutions for the encoded mathematical model within defined limits for each parameter employed.
-The encoded mathematical model has been shown to produce a valid solution to the physical problem associated with the particular application.
Design Verification Design control measures shall be applied to verify the adequacy of design, such as by one or more of the following:
-Performance of design reviews.
-Performance of qualification tests. -Use of alternate calculations.
Revision 85 DESIGN CONTROL CHAPTER3 2.5.1 Page 4 of 7 The results of design verification shall be documented including the identification of the verifier.
Design verification shall be performed by competent individual(s) other than those who performed the original design; but may be from the same organization.
This verification may be performed by the originator's supervisor, provided the supervisor did not specify a singular design approach, rule out certain design considerations, did not establish the design inputs used in the design, or the supervisor is the only individual in the organization competent to perform the verification. Cursory supervisory reviews do not satisfy the intent of design verification.
Verification shall be performed in a timely manner. Design verification, for the stage of design activity accomplished, shall be performed prior to release for procurement, manufacture, construction, or release to another organization for use in other design activities provided sufficient data exists. Any unverified portion of the design shall be identified and controlled.
In all cases the design verification shall be completed prior to relying upon the component, system, structure, or computer program to perform its function.
Extent of Design Verification The extent of the design verification required is a function of the importance to safety, the complexity of the design, the degree of standardization, the state of the art, and the similarity with previously proven designs.
Where the design has been subjected to a verification
: process, the process need not be duplicated for identical designs.
For each application the applicability of standardized or previously proven designs for design inputs shall be verified.
Known problems affecting the standard or previously proven designs and their effects on other features shall be considered.
The original design and associated verification shall be adequately documented and referenced in subsequent applications.
Design verification shall be required for changes to previously verified designs.
This includes evaluation of the effects of those changes on the overall design and on any affected design analyses.
Revision 85 DESIGN CONTROL CHAPTER3 2.5.2 2.6 Page 5 of 7 Design Reviews Verification consists of a check of design adequacy by such methods as design reviews, use of alternate calculations or methods, or performance of verification or qualification testing.
The method, or combination of methods, used to verify a design will be selected on a case-by-case basis Acceptable verification methods include one or more of the following items: -Alternate calculations using alternate methods that verify the correctness of original calculations or analyses.
-Critical design reviews providing assurance that the final design is correct and satisfactory.
-Where design adequacy is to be verified by qualification tests, the tests are identified.
Change Control Changes to final designs, field changes, modifications to operating facilities, and nonconforming items dispositioned use-as-is or repair shall be justified and subject to design control measures commensurate with those applied to the original design. These measures shall include assurance that the design analyses for the structure, system, or components are still valid. A 1 OCFR50.59/72.48 review is performed for changes to the facility.
Changes shall be approved by the same affected groups or organizations, which reviewed and approved the original design documents.
In the case where the original organization is no longer responsible for design approval, then a new responsible design organization shall be designated.
The designated organization shall have demonstrated competence in the specific design area of interest and have an adequate understanding of the requirements and intent of the original design. Revision 85 DESIGN CONTROL CHAPTER3 2.7 2.8 2.9 Page 6 of 7 When a design change is approved, other than by revision to the affected design documents, measures shall be established to incorporate, where appropriate the change into these documents.
Plant personnel will be made aware of design changes/modifications, which may affect the performance of their duties. Where a significant design change is necessary because of an incorrect design, the design process and verification procedure shall be reviewed and modified as necessary.
Design Errors The Company detects deficiencies or errors in design or in the design quality assurance program by: -Actual failure during operation.
-Assessments.
-Design verification measures.
-Other means. -Personnel using the design documents.
-Tests conducted.
Interface Control Design interfaces shall be identified and controlled.
The Company shall coordinate design efforts among the participating organizations.
Interface controls shall include the assignment of responsibility and the establishment of procedures among participating design organizations.
Controls shall° be for the review, approval,
: release, distribution and revision of documents involving design interfaces.
Design information transmitted across interfaces shall be documented and controlled.
Vendor Design Control The Company reviews and accepts the specifications and drawings for electrical, mechanical, instrumentation, nuclear and structural
: material, equipment, and erection work, prepared by the Architect Engineer and NSSS Supplier.
The purpose of these reviews is to verify inclusion of inspection, testing and acceptance criteria.
The Architect Engineer's evaluation of fabricator and erector's detailed
: designs, drawings, and work instructions are reviewed for reasonableness and completeness.
Audits are conducted by the company for design review systems of architect engineers, nuclear fuel, and NSSS suppliers.
Revision 85 DESIGN CONTROL CHAPTER3 2.10 2.11 Page 7 of 7 The Company assures that: -Architect engineers and NSSS suppliers maintain procedures to assure that their. personnel certifying ASME Section Ill design activities are qualified Registered Professional Engineers in accordance with ASME Section Ill, Appendix XX.Ill. -Personnel certifying ASME Section Ill design activities are qualified Registered Professional Engineers in accordance with ASME Section Ill, Appendix XX.Ill. The Company provides qualified personnel to review and approve the resolution of non-conformances relating to electrical, mechanical, instrumentation and structural portions of the plant and to evaluate discrepant modification test results for operating plants. Modifications The Company performs modifications that may affect the function of safety-related structures,
: systems, or components in a manner to assure quality at least equivalent to that specified in original design bases and requirements, materials specifications, and inspection requirements.
Documentation and Records The Company notifies jurisdictional authorities of the location of ASME Code related permanent records.
Design documentation and records, which provide evidence that the design and design verification process were performed in accordance with the requirements of this chapter, shall be stored and maintained.
Documentation of design analyses shall include the following:
-List of any computer calculation and the bases for its use. -List of assumptions and indication of those that must be verified as the design proceeds.
-List of design inputs and their sources.
-Results of literature searches or other applicable background data. -Review and approval.
-Statement of the objective of the analyses.
Revision 85 PROCUREMENT DOCUMENT CONTROL CHAPTER4 1 2 2.1 2.2 2.2.1 2.2.2 Page 1of4 SCOPE* This Chapter identifies the requirements for preparation, review, approval,
: release, and retention of procurement documents.
REQUIREMENTS General The Company establishes measures for the preparation, review, and approval of procurement documents for those items and activities within the scope of the QATR. Procurement documents at all tiers include or reference the appropriate regulatory, technical, and quality requirements necessary to assure adequate quality.
These requirements include reference to 10CFR21 when applicable.
Content of Procurement DocumentS Procurement documents at all tiers include the following items as deemed necessary by the Company.
Scope of Work Procurement documents describe the scope of the items or services to be furnished by a supplier.
For those items that are important to plant safety, applicable requirements should be specified in the procurement document.
Technical Requirements The Company establishes measures in controlled procedures to; specify technical requirements by reference to the appropriate specific
: drawings, specifications, codes, standards, regulations, procedures, or instructions, including revisions thereto that describe the items or services to be furnished.
* The procurement documents identify test, inspection and acceptance requirements as appropriate.
These documents identify as appropriate special instructions and requirements for such activities as design, material and component identification, fabrication, special process controls,
: cleaning, erecting, packaging,
: handling, shipping, and extended storage.
Revision 85 PROCUREMENT DOCUMENT CONTROL CHAPTER4 2.2.3 2.2.4 2.2.5 Page 2 of 4 Quality Assurance Program Requirements Measures are established, in controlled procedures, to ensure the appropriate technical and quality requirements are established, by qualified personnel, for the material, equipment, and services purchased from vendors, suppliers, or contractors.
* Any changes to these requirements require prior approval by the Company.
Each vendor, supplier, or contractor has an acceptable quality assurance
: program, which is consistent with applicable regulatory requirements for the item or service.
The Nuclear Oversight Vendor Audit Group (NOVA) maintains a controlled list of evaluated suppliers that are audited on a triennial basis. The evaluated list of such vendors, suppliers, and contractors is described in controlling procedures for the appropriate safety classification except for procurement from other licensees that has a NRC approved quality program.
Procurement documents require the vendors to incorporate quality assurance program requirements in sub-tier procurement documents and allow right of access to the vendors, sub.,.tier
: vendors, and contractors facilities and records for inspection or audit by the Company or designated representative.
Commercial Grade Items (items not originally designed or manufactured as a basic component) shall be subject to a Commercial Grade process before such items are approved for related applications within the Company's nuclear units. The process is consistent with the guidance contained in Generic Letter 89-02 and 10 CFR 21 for the supply of basic components.
Non-conformances The Company procurement documents specify the requirements for reporting and approving the disposition of supplier non-conformances.
"Use-as-is" or "Repair''
requires approval of the supplier disposition by the appropriate Company representative.
Documentation Requirements The procurement documents shall identify, at all tiers, the documentation required to be submitted for information, review, and approval including the time requirements for submittal.
The Company procurement documents require the supplier to maintain specific quality assurance documents including retention times and disposition requirements.
Revision 85 PROCUREMENT DOCUMENT CONTROL CHAPTER4 Page 3 of 4 When purchasing commercial grade calibration or testing services from a laboratory holding accreditation by an accrediting body recognized by the International Laboratory Accreditation Cooperation (ILAC) Mutual Recognition Arrangement (MRA), commercial grade surveys need not be performed provided each of the following conditions are met: 1. A documented review of the supplier's accreditation is performed and includes a verification of the following:
: a. The calibration or test laboratory holds accreditation by an accrediting body recognized by the ILAC MRA. The accreditation encompasses ISO/IEC-17025:2005, "General Requirements for the Competence of Testing and Calibration Laboratories."
: b. For procurement of calibration
: services, the published scope of accreditation for the calibration laboratory covers the needed measurement parameters, ranges, and uncertainties.
: c. For procurement of testing services, the published scope of accreditation for the test laboratory covers the needed testing services including test methodology and tolerances/uncertainty.
: 2. The purchase documents require that: a. The service must be provided in accordance with their accredited ISO/IEC-17025:2005 program and scope of accreditation.
: b. As-found calibration data must be reported in the certificate of calibration when calibrated items are found to be tolerance.
(for calibration services only) c. The equipment/standards used to perform the calibration must be identified in the certificate of calibration.
(for calibration services only) d. The Company must be notified of any condition that adversely impacts the laboratory's ability to maintain the scope of
* accreditation.
: e. Additional technical and quality requirements, as necessary, based upon a review of the procured scope of services, which may include, but are not necessarily limited to, tolerances, accuracies, and industry standards.
: 3. It is validated, at receipt inspection, that the laboratory's documentation certifies that: a. The contracted calibration or test service has been performed in accordance with their ISO/IEC-17025:2005
: program, and has been performed within their scope of accreditation, and b. The purchase order's requirements are met. Revision 85 PROCUREMENT DOCUMENT CONTROL CHAPTER4 2.2.6 2.3 2.4 Page 4 of 4 Spare and Replacement Parts The procurement documents require the identification of appropriate spare and replacement parts or assemblies and the appropriate delineation of the technical and quality assurance related data required for ordering these parts or assemblies.
These spare parts and replacement items are at least equivalent to the original design requirements.or those specified by a properly reviewed and approved revision.
Procurement Document Review Measures are established in controlled procedures to ensure the appropriate technical and quality requirements are established for the material,*-equipment, and services purchased from vendors, suppliers, or contractors to release for bid and contract award. These documented
: reviews, including changes to the specification or purchase order, ensure the technical and quality requirements are correctly stated, inspectable, and controllable and have adequate acceptance and rejection criteria and are prepared,
: reviewed, and approved in accordance with QAP requirements.
Review of the exceptions or changes requested by the supplier are reviewed to ensure they do not change or impact the technical or quality requirements and are incorporated in to the procurement documents, prior to the supplier proceeding, using the same review and approval process as appropriate except for commercial terms and editorial changes.
Personnel who have access to pertinent information and who have an adequate understanding of the requirements and intent of the procurement documents shall perform reviews required by this chapter.
Procurement Records.
Records as required by the procurement documents or the QATR are retained in the Company's department files, vendor files, or both locations.
Revision 85 INSTRUCTIONS, PROCEDURES AND DRAWINGS CHAPTERS 1 2 2.1 Page 1of4 SCOPE Activities governed by the Company's OAP shall be performed as directed by documented instructions, procedures, and drawings appropriate for the activity.
The requirements for the use of these procedures shall also be prescribed in writing.
These instructions, procedures, and drawings shall include responsibilities and acceptance criteria as applicable or appropriate for the activity.
Those participating in any activity shall be aware of and use the proper and current revision of instructions, procedures,
: drawings, and engineering requirements for performing the activity.
Procedures may include reference to vendor equipment
: manuals, design drawings and specifications, prerequisites, special precautions, and the delineation of work to be performed.
Equipment Manuals and manufacturers instructions shall be readily available for use. REQUIREMENTS General Operation, maintenance, or modification of equipment shall be preplanned and performed in accordance with written procedures that are appropriate to the circumstances and that conform to applicable codes, standards, specifications, and criteria.
Documents identify and specify the content of records to be generated in conducting the activity.
The establishment and execution of quality procedures shall occur based on industry standards accepted by the Company.
Procedures shall be used by station staff, as well as those under their direction, and adhered to during all safety-related activities, including operating, maintenance, modifications, in-service inspection, refueling, and stores functions.
Temporary procedures may be issued to provide guidance in unusual situations that are not within the scope of the normal procedures.
Temporary procedures shall be subject to review and approval, and shall include designation of the time period during which they may be used. In the event of an emergency not covered by an approved procedure, authorized personnel shall provide appropriate direction to minimize personnel injury and damage to the facility and to protect the health and safety of plant personnel and the general public. Revision 85 INSTRUCTIONS, PROCEDURES AND DRAWINGS CHAPTERS 2.2 2.3 2.3.1 Page 2 of 4 Preparation and Review Procedures shall be prepared,
: reviewed, approved, and used as prescribed in writing, and shall contain step by step instructions in the degree of detail necessary for qualified individuals to perform the required function or task. Where appropriate, these procedures will include checklists containing the necessary attributes to be observed or measured.
These documents shall include or reference appropriate quantitative or qualitative acceptance criteria for determining that prescribed activities have been satisfactorily accomplished.
The procedures will be independently reviewed and evaluated by other involved company organizations with interface responsibilities and the comments forwarded to the issuing department.
Procedures and Programs Review and approval of site procedures are performed in accordance with technical specification requirements as delineated in the Technical Review or Station Qualified Review (SQR) programs.
Technical Review and Control 1. Procedures required by a station's Technical Specifications and other procedures which affect nuclear safety, as determined by the manager responsible for station operation, and changes thereto, other'than editorial or typographical
: changes, shall be reviewed as follows prior to implementation, except as noted in item 5 (below).
-Each procedure or procedure change shall be independently reviewed by. a qualified individual knowledgeable in the area affected other than the individual who prepared the procedure or procedure change. This review shall include a determination of
* whether or not additional cross-disciplinary reviews are necessary.
If deemed necessary, the reviews shall be performed by the qualified review personnel of the appropriate discipline(s).
-Proposed change to the approved fire protection program will include a review to determine if the change will have an adverse effect on the ability to achieve and maintain safe shutdown, including whether NRG review and approval is required prior to the implementation of the change. Revision 85 INSTRUCTIONS, PROCEDURES AND DRAWINGS CHAPTERS Page 3 of 4 -Review of procedures or proposed changes to those procedures that describe the means for controlling or operating structures,
: systems, and/or components as described in the UFSAR, will include a review to determine if NRC review and approval is necessary prior to the implementation of the procedure activity.
This review is based on the review of a written 10 CFR 50.59n2.48 review and evaluation prepared by qualified individual(s),
or documentation that a 10 CFR 50.59n2.48 evaluation is not required.
-The on-site review committee shall review and recommend approval of items requiring NRC review and approval prior to station approval for implementation.
NRC approval shall also be obtained prior to station approval for implementation.
-Department head approval authority shall be as specified in station procedures.
-Written records of reviews performed in accordance with this specification shall be prepared and maintained.
-Editorial and typographical changes shall be made in accordance with station procedures.
: 2. Technical reviewers shall advise their supervisors and/or the on-site review committee on all matters related to nuclear safety that are identified during reviews; The reviewer shall be other than the originator.
The reviewer shall determine if additional disciplinary reviews are required to ensure all applicable technical disciplines are included.
This review shall ensure technical
: accuracy, compliance with regulatory requirements, and shall verify the originator's determination of whether items reviewed constitutes a change to the Technical Specifications, Operating
: License, or if NRC review and approval is required prior to implementation.
-Corporate procedures used to support the stations an.d that serve to govern activities important to safety shall undergo a technical review prior to initial issuance and following subsequent substantive revisions.
Revision 85 INSTRUCTIONS, PROCEDURES AND DRAWINGS CHAPTER 5 Page 4 of 4 3. Technical reviewers shall be qualified to perform technical reviews based on the individual's
: training, experience, and knowledge level. Technical reviewers, assigned the responsibility for reviewing 1 OCFR50.59/72.48 reviews and evaluations, shall receive training in this process.
Technical reviewers shall be qualified to perform this function and meet or exceed the education and experience requirements of ANSI 3.1-1981.
Personnel shall have expertise in one or more of the following disciplines as appropriate, for the subject or subjects being reviewed:
-Chemistry.
-Instrumentation and controls.
-Mechanical and electrical systems.
-Nuclear power plant technology.
-Radiological controls.
-Reactor engineering.
-Reactor operations.
: 4. Technical reviews shall be documented and records maintained.
: 5. Temporary Changes Temporary changes to procedures required by 2.3.1.1 (above) may be made provided:
-The intent of the original procedure is not altered.
-The change is approved by two members of the plant management staff knowledgeable in the areas affected by the procedures; at least one of whom holds a Senior Reactor Operator's License on the unit affected.
-The change is documented,
: reviewed, and approved in accordance with 2.3.1 (above) within 14 days of implementation.
Revision 85 DOCUMENT CONTROL CHAPTERS 1 2 2.1 Page 1of3 SCOPE Measures shall be established to control and coordinate the Classification, review, approval,
: issuance, revision, and change of documents that prescribe methods or provide the technical and/or quality requirements for activities and items within the scope of this program.
These measures shall ensure that such documents are reviewed for adequacy, approved for release and use, and distributed to the location where the activity is performed.
REQUIREMENTS General.
The Company document control process ensures that procedures are reviewed and approved before initial use. The Company has in place programmatic
: controls, which ensure that procedures are technically and administratively correct before use. These programmatic controls ensure that procedures are reviewed and revised as needed, when pertinent source material is changed, when the plant design is changed, or when deficiencies are identified and corrected.
Provisions shall be established to ensure that infrequently used procedures are reviewed prior to use, unless they have been reviewed within the previous two years. Due to their importance to safety, biennial reviews of abnormal procedures (such as emergency operating procedures) shall be part of the required review process.
Periodic biennial review requirements are satisfied by implementation of several processes and programs.
These processes and programs provide the programmatic controls that ensure the required reviews are accomplished and include the following:
-Commitment Management and Tracking Process -Integrated Reporting/Corrective Action Program -Operational Experience Feedback Program -Plant Modification Program Procedure Feedback/Revision Process -Technical Specification and Updated Final Safety Analysis Report Revision Programs
-Vendor Information Program Revision 85 DOCUMENT CONTROL CHAPTERS 2.2 2.3 Page 2 of 3 Reviews The company has also established provisions to ensure that the following reviews are conducted:
-Inspection, identification of inspection personnel, and documentation of inspection results.
-Maintenance, modification, and inspection procedures are reviewed by qualified personnel; knowledgeable in quality assurance
* disciplines.
-Necessary inspection requirements,
: methods, and acceptance criteria have been identified.
Controlled Documents Written document control procedures shall be established to provide for the control of approved documents.
Documents that are controlled
: include, but are not limited to, the following items: -As-built drawings.
-Calibration procedures.
-Computer codes and software.
-Corrective action reports.
-Design specifications.
-Emergency operating procedures.
-Engineering calculations.
-lnspe.ction and test reports.
-Nonconformance reports.
-NOS procedures.
-Operating procedures.
-Purchase orders and related documents.
-Safety analysis reports.
-Supplier audif and surveillance procedures.
-Technical specifications (station and Independent Spent Fuel Storage Installation)
-Temporary and emergency procedure changes. -T apical reports.
-Work instructions and procedures.
Revision 85 DOCUMENT CONTROL CHAPTERS 2.4 2.5 Page 3 of 3 Control Measures The Company document control process includes the following document control measures:
-Coordinating and controlling interface documents.
-Distributing documents approved for issuance in accordance with updated and current distribution lists. -Establishing document control procedures to assure that proper documents are accessible and are being used. -Establishing lists of documents controlled by organizations involved with activities affecting quality.
-Establishing procedural requirements for the protection of safeguards information
-Identifying and assuring that proper documents are used in performing activities affecting quality.
-Identifying qualified individuals or organizations responsible for preparing, reviewing, approving and issuing documents, including revisions.
-Recalling or identifying obsolete documents.
Document Changes The Company document control process ensures changes to documents are reviewed and approved by the same organizations that performed the original review and approval, unless delegated to another responsible organization.
The reviewing organization has access to pertinent background data or information upon which to base their approval.
To avoid a possible
.omission of a required review, the Company document control process includes provisions to control minor changes.
Revision 85 CONTROL OF PURCHASED
: MATERIAL, EQUIPMENT AND SERVICES CHAPTER 7 1 2 2.1 2.1.1 2.1.2 Page 1 of 10 SCOPE The Company establishes measures to assure the quality of purchased
: material, equipment and services conform to procurement document requirements for items contained within the QATR. REQUIREMENTS Supplier Selection General The Company establishes measures to assure that purchased
: material, equipment, and services conform to the procurement documents for safety related and ASME code specifications as appropriate.
This assurance is accomplished by controlling both the selection of procurement sources and acceptance of the product at the source and/or upon receipt at the appropriate location.
The Company procedures, which address the procurement process and receipt and storage of material and equipment, clearly define the responsibilities and interfaces between the line requisitioning organization, engineering, supply and quality assurance.
Methods The Company establishes measures for evaluation and selection of procurement sources.
For safety-related items, the measures must be completed prior to the award of the* contract.
These measures include one or more of the following:
-Evaluation of the supplier's history of providing an identical or similar product that performs satisfactorily in actual use. -Supplier's current quality records supported by documented qualitative and quantitative information that can be objectively evaluated.
-Supplier's technical and quality capability of meeting the applicable quality requirements of 1 OCFR50 Appendix B as determined by a direct evaluation of its facilities and personnel and the
* implementation of its quality assurance program.
Revision 85 CONTROL OF PURCHASED
: MATERIAL, EQUIPMENT AND SERVICES CHAPTER 7 2.2 2.3 2.3.1 Page 2of10 -Review and evaluation of audits, surveys, and inspections conducted by other utilities, or American Society of Mechanical Engineers (ASME). -If there is insufficient evidence of a QAP, the initial evaluation is of the existence of a QAP addressing the scope of the services to be provided.
The initial audit is performed after the supplier has completed sufficient work to demonstrate that its organization is implementing a QAP. The Company documents and files the results of these measures and maintains a list of approved suppliers that have been evaluated to determine their ability to provide acceptable products and/or services.
Suppliers of non-safety-related products and/or services do not need to meet these measures,
: however, if being used for an augmented quality (refer to Appendix A) application, a procurement plan will*be used to specify and control source quality.
Bid Evaluations The Company reviews and evaluates bids and awards contracts using written procedures and documents the results.
The Company designates individuals or organizations to review bids to assure that they conform to the procurement document requirements and the supplier has the appropriate technical
: ability, Quality Program, production capability, personnel, and acceptable past performance to supply the product or service.
The Company obtains commitments to resolve unacceptable quality conditions identified as part of the bid evaluation before award of the contract and ensure exceptions and alternatives do not impact the technical or quality requirements.
Supplier In-Process Control General The Company establishes measures to interface with and to verify supplier performance.
These measures include the following items: -Establishing an understanding between the Company and the supplier of the provisions and specifications contained in the procurement documents.
-Establishing a method of document information exchange between the Company and the supplier.
Revision 85 CONTROL OF PURCHASED
: MATERIAL, EQUIPMENT AND SERVICES CHAPTER 7 2.3.2 2.3.3 Page 3of10 -Establishing the extent of source surveillance and inspection activities.
-Identifying and processing necessary change information.
-Requiring the supplier to identify planning techniques, tests, inspections, and processes to be used in fulfilling procurement document requirements.
-Reviewing supplier documents that are generated or processed during activities fulfilling procurement requirements.
In-Process Control and Verification Planning The Company and the supplier establish as appropriate, notification points including hold and witness points, and incorporate into the appropriate documents based upon the complexity and scope of the item or service.
When required by the procurement document or specification, surveillances and evaluations at the supplier's facility are conducted to verify continued compliance with the quality assurance requirements of the procurement documents.
Qualified individuals or its agents accomplish source inspections at the . supplier's facility to verify that the procurement item or service is being supplied in accordance with the requirements of the procurement documents.
Such inspections, examinations or tests are accomplished in accordance with written procedures, plans, and/or checklists containing or referencing appropriate acceptance criteria.
Upon acceptance by source verification, the Company furnishes documented evidence of acceptance to the receiving destination of the item, to the purchaser, and to the supplier.
Programmatic Verification The Company or its agents verify the effectiveness of the supplier's quality program by survey, audit or surveillance.
Verification is performed at intervals consistent with the importance to safety, complexity and quality of the product or services furnished.
Activities are witnessed or observed and the results documented when source verification is performed.
Revision 85 CONTROL OF PURCHASED
: MATERIAL, EQUIPMENT AND SERVICES CHAPTER 7 2.3.4 2.3.5 2.4 2.4.1 Page 4of10 The Company conducts audits per the requirements established in Chapter 18 or reviews audits performed by other license holders as defined in procedures.
The results of these audits are used to support the maintenance of the list of evaluated suppliers.
Verification activities are conducted as early as practicable so that subsequent activities do not prevent disclosure of deficiencies.
The Company's verification activities do not relieve the supplier of its responsibility for quality verification.
Supplier and Verification of Supplier Performance Records The Company establishes methods to control, handle and approve supplier documents.
Suppliers submit their documents per procurement requirements.
Acceptance criteria are used for the acquisition, processing, and record evaluation of technical inspection and test data. The Comp,any records activities to verify supplier conformance with the requirements of procurement documents.
Source surveillances, procurement plans, inspections, audits, surveys, receiving inspections, non-conformance dispositions, waivers and corrective actions concerning supplier activities are documented.
This documentation is used to determine the supplier's quality assurance program effectiveness.
Control of Procurement Changes The Company documents changes to procurement documents involving technical or quality assurance matters.
These changes are subjected to the same review and approval process as the original procurement document except for commercial terms and conditions and editorial changes.
Acceptance of Purchased Items and Services General Upon receipt the applicable materials, parts, and components are controlled.
Qualified inspection personnel are responsible for inspecting, releasing, and maintaining the inspection status of purchased material and equipment.
After receipt inspection, the purchased material is placed in a controlled storage area or issued for installation or further work. ' Revision 85 CONTROL OF PURCHASED
: MATERIAL, EQUIPMENT AND SERVICES CHAPTER 7 2.4.2 2.4.3 Page 5of10 Acceptance by Receiving Inspection The Company uses approved procedures to accept purchased items and services.
Acceptance of an item or service from a supplier includes certificate of conformance, source verification, receiving inspection or post installation testing at the plant location or a combination thereof.
Items are inspected during receipt using approved procedures and checklists.
The Company does receiving inspections using procedures and inspection instructions to verify conformance to the specified requirements, using objective evidence to check such features as: complete documentation and visual inspection of: proper configuration; identification; dimensional, physical and other characteristics; freedom from shipping damage; and cleanliness.
Items, which cannot meet the purchase order requirements, will be segregated and controlled as defined in the applicable procedures.
The Company coordinates the review of supplier documentation with the receiving inspection when procurement documents require such documentation to be furnished prior to the receiving inspection.
Source verification and audit activities are factored into the receipt inspection activities as appropriate.
Acceptance by Source Verification The Company considers acceptance by source verification when the item or service is: ..... Complex in design, manufacture, and test; or -Difficult to verify quality characteristics after delivery; or -Vital to plant safety. Source verification shall be implemented in accordance with plans to perform inspections, examinations, or tests at pre-determined points. Upon acceptance by source verification, the Company furnishes documented evidence of acceptance to the receiving destination of the item, to the purchaser, and to the supplier.
Revision 85 CONTROL OF PURCHASED
: MATERIAL, EQUIPMENT AND SERVICES CHAPTER 7 2.4.4 2.4.5 Page 6of10 Acceptance by Certificate of Conformance The supplier's certificate of conformance attests the product or service provided is in accordance with the procurement documents is reviewed during source and/or receipt inspections to verify compliance.
This document provides the purchase order number; codes, standards or other specifications required to be met in the purchase order. Requirements which cannot be met must be included with an explanation why and a means to resolve the non-conformances.
A person who is responsible for quality assurance function attests to this certificate The validity of a supplier's certificate of conformance is ascertained through any of the following methods:
-An independent inspection agency -Quality assurance audits or surveillances at intervals commensurate with the suppliers past performance.
-Receipt inspections.
-Source inspection.
-Surveillance.
-Testing of hardware.
Inspection and test activities verify that the hardware performs in accordance with applicable technical requirements and serve to demonstrate that the *hardware meets the requirements stated in a certificate of conformance.
The results of the source and/or receipt inspections, the acceptability of supplier furnished documentation, and the resulting determination of conformance or nonconformance is documented.
Acceptance by Post Installation Testing When post-installation testing is used, the Company and the supplier mutually establish post-installation test requirements and acceptance documentation.
Acceptance by this method is satisfactory when performed following the accomplishment of at least one preceding method and when: -It is difficult to verify the quality characteristics of the item without it being installed and in use; or Revision 85 CONTROL OF PURCHASED
: MATERIAL, EQUIPMENT AND SERVICES CHAPTER 7 2.4.6 2.4.7 Page 7of10 -The item requires an integrated system checkout or test with other items to verify its quality or -The item cannot prove its ability to perform its intended function except when in use. Acceptance of Services Only In cases involving procurement of services only, the Company accepts the service by any of the following methods:
-Technical verification of data produced.
-Surveillance, audit, survey, or assessment of the activity.
-Review of objective evidence for conformance to the procurement document requirements such as certifications, stress reports, etc. In lieu of the above the Company performs a receiving inspection for items arriving back onsite that were sent offsite for repair, testing, or rework. Commercial Grade Items Where the safety related design utilizes commercial grade items, the following requirements are a permissible alternative for acceptance, to other requirements of this Chapter:
: 1. An approved design document identifies the commercial grade item. (An alternate commercial grade item may be applied, provided the cognizant design organization provided verification that the alternate commercial grade item will perform the intended function and will meet design requirements applicable to both the *replaced item and its application.)
: 2. The Company performs source evaluation and selection, where determined necessary, based on complexity and importance to safety. -Commercial grade dedication plans for use in safety-related applications state responsibility for 1 OCFR21 requirements.
-The Company identifies commercial grade items in the purchase order by the supplier's published product description.
Revision 85 CONTROL OF PURCHASED
: MATERIAL, EQUIPMENT AND SERVICES CHAPTER 7 2.4.8 Page 8of10 3. One or a combination of the following methods shall be utilized to provide reasonable assurance that the item meets the acceptance criteria for the characteristics identified to be verified for acceptance:
-Acceptable supplier/item performance records.
-Commercial grade survey of the supplier.
-Source verification.
-Special test(s) or inspection(s) or both. 4. After receipt of a commercial grade item, the Company determines the following:
-Damage was not sustained during shipment.
Documentation, as applicable to the item, was received and is acceptable.
Inspection and/or testing are accomplished, as required by the purchaser, to assure conformance with the manufacturer's published requirements.
The item received was the item ordered.
Acceptance of Calibration Services For suppliers of commercial grade calibration services with accreditation by a nationally recognized accrediting body, a documented review of the supplier's accreditation by the*purchaser may be used in lieu of inspections or tests following delivery or process surveillances during performance of this service.
The review shall include, at a minimum, all of the following:
.1. The accreditation is to ANSl/ISO/IEC 17025. 2. The calibration laboratory holds a domestic accreditation by one of the following accrediting bodies, which are recognized by the International Laboratory Accreditation Cooperation (ILAC) Mutual Recognition Arrangement (MRA): -The National Voluntary Laboratory Accreditation Program (NVLAP),
administered by NIST -The American Association for Laboratory Accreditation (A2LA) -ACLASS Accreditation Services (ACLASS)
-International Accreditation Services (IAS) -Laboratory Accreditation Bureau (L-A-B)
* 3. The published scope of accreditation for the calibration laboratory covers the needed measurement parameters, ranges, and uncertainties.
Revision 85 CONTROL OF PURCHASED
: MATERIAL, EQUIPMENT AND SERVICES CHAPTER 7 2.5 2.6 Page 9of10 4. The purchase documents impose additional technical and administrative requirements, as necessary, to satisfy the company QAP and technical requirements.
The technical requirements include the following items included in the calibration/certificate report: -As-found data. -As-left data. -Identification of the laboratory equipment and standards used. 5. The purchase documents require reporting as-found calibration data when calibrated items are found out-of-tolerance.
Presence of Documentary Evidence Documented evidence that material or equipment conforms to procurement requirements is present at the site before use or installation.
This documentary evidence is.traceable to the item and shall be retained at the nuclear power plant site* and shall be sufficient to identify the specific requirements such as codes, standards, or specifications met by the purchased material and equipment.
Nonconforming material may be issued for use or installation using a conditional release method provided authorization and technical justification for the conditional release is obtained and becomes part of the material's documentary evidence.
Spare or Replacement Items Procedures control the procurement, storage and issuance of materials and components including spare and replacement parts. Procurement documents for these items identify the appropriate technical and quality related requirements.
The Company purchases spare parts and replacement items, equipment and components to at least the original design. requirements or those specified by a properly reviewed and approved revision.
Where the QA requirements of the original item cannot be determined, qualified individuals conduct an engineering evaluation to establish appropriate requirements and controls.
This evaluation insures that interfaces, interchangeability, safety, fit and function are not adversely affected or are contrary to applicable regulatory or ASME Code requirements.
The evaluators document their results.
Revision 85 CONTROL OF PURCHASED
: MATERIAL, EQUIPMENT AND SERVICES CHAPTER 7 2.6.1 2.6.2 Page 10of10 Where the Company procured the original item with no specifically identified quality assurance program requirements, or from an Original Equipment Manufacturer/Supplier (OEM/OES) who no longer is on a list of evaluated suppliers identical (like-for-like) items may be similarly procured from the OEM/OES through the use of procurement plans . . In such cases, the Company conducts a joint technical engineering and quality assurance documented evaluation to established requirements and controls to assure at least equivalent product performance.
The evaluation shall assure that interfaces, interchangeability, safety, fit and function are not adversely affected or are not contrary to applicable regulatory or ASME Code requirements.
Procurement from Other Utilities Purchases of safety related items can be made from other utilities who have had an NRC approved QA Program in effect at the time of their procurement and receipt and such utility has maintained a quality system program for storage,
: handling, and maintenance with documented traceability to the manufacturer of the items. Certificates-of-Conformance to the above requirements and associated required documentation are provided.
Maintenance or Modification The Company performs maintenance or modifications that may affect the function of safety related structures,
: systems, or components in a manner to assure quality at least equivalent to that specified in original design bases and requirements, materials specifications, and inspection requirements.
Revision 85 IDENTIFICATION AND CONTROL OF MATERIALS, PARTS AND COMPONENTS CHAPTERS 1 2 2.1 2.2 Page 1 of 2 SCOPE Controls are established to assure that only correct and accepted items are.used or installed.
Identification shall be maintained on the items or in documents traceable to the items, or in a manner, which assures that identification is established and maintained.
REQUIREMENTS General The Company establishes measures for the identification and control of materials, parts and components, including partially fabricated assemblies, and assures that only correct and accepted items are used or installed.
Identification is maintained on the items or in documents traceable to the items. Physical identification shall be used to the maximum extent possible.
Provisions are in place to maintain
: markings, which could be damaged during shipping or handling or deterioration due to environmental exposure.
Provisions are also established to control nonconforming items and maintain parts, material, and equipment in storage traceable to quality assurance documents.
Nonconforming material issued for use or installation on a conditional release basis is controlled in a manner that ensures appropriate follow-up is performed.
Traceability Items within the scope of the OAP shall be identified, so that they can be traced to the appropriate documentation, which provides objective evidence that the technical and quality requirements are met. Responsible organizations document and maintain identification and traceability of items from initial receipt, throughout fabrication, installation, and use of the items such as: subassemblies, components, equipment
: numbers, part numbers, serial number, heat treatment number, batch or lot numbers.
When installed material or equipment is removed for maintenance, repair, or modification, control measures are implemented to ensure proper identification and traceability is maintained.
Before use or installation of an item, the installer verifies that identification has been maintained.
Revision 85 IDENTIFICATION AND CONTROL OF MATERIALS, PARTS AND COMPONENTS CHAPTERS 2.3 2.4 2.5 2.6 2.7 Page 2 of 2 Identification Methods Identification is on the item where practicable.
Identification is clear, unambiguous and indelible.
Identification does not affect the fit, function,
: quality, and service life of the item. If the item cannot be practicably marked, the Company uses records traceable to the item for identification.
If physical identification is either impractical or insufficient for proper control, the Company controls an item by physical separation, procedural control or other appropriate means. Transfer of Markings Prior to cutting or dividing
: material, each new piece shall be marked with the same traceability markings of the original piece to ensure that the traceability of the material is maintained.
These markings shall not be obliterated or hidden by surface treatment or coatings unless other means of identification are substituted.
The Company independently verifies proper identification of each piece. Limited Life Items The Company identifies and controls items having limited life to preclude use of items whose shelf life or operating life has expired.
Stored Items The Company uses procedures to assure proper control of identification for items in storage.
Software Items To the extent appropriate, the Company establishes controls to permit authorized and prevent unauthorized access to computer software.
Revision 85 CONTROL OF SPECIAL PROCESSES CHAPTERS*
1 2 2.1 2.2 Page 1of3 SCOPE Processes affecting quality of items or services shall be controlled.
Special processes that control or verify quality shall be performed by qualified personnel using qualified procedures in accordance with specified requirements, and are properly documented and evaluated.
These requirements are defined in codes, standards, specifications, or special instructions.
The quality of such processes is assured through reliance on operator skill and in-process control.
Examples of special processes
: include, but are not limited to welding, heat-treating, chemical
: cleaning, and non-destructive examination (NDE). REQUIREMENTS General The Company organization directing work during repair, replacement, modification, or in-service inspection (ISi) activities is responsible for controlling special processes.
Special process controls are assured through independent assessment and inspection activities.
Process Control Instructions, procedures,
: drawings, checklists, or other appropriate means control processes.
Process controls specify the prerequisite steps, processing
: details, conditions to be maintained during the process, equipment requirements, inspection and test requirements, acceptance
: criteria, and record requirements.
Controlling includes:
-Maintenance and retention of records.
-Personnel qualification.
-Procedure development and qualification.
-Procedure implementation.
-Qualification of equipment.
Revision 85 CONTROL OF SPECIAL PROCESSES CHAPTERS 2.3 Page 2 of 3 Special Processes Measures shall be established and documented to assure that special processes are accomplished under controlled conditions in accordance with applicable codes, standards, applications
: criteria, regulatory requirements and commitments, and other special requirements including the use of qualified personnel and procedures.
Special processes are controlled by: instructions, procedures,
: drawings, checklists, travelers, or other appropriate means. Special process controls specify the preparatory steps, processing
: details, conditions to be maintained during the process, equipment requirements, inspection and test requirements, acceptance
: criteria, and record requirements.
Special process procedures are written and qualified in accordance with applicable requirements.
Special process procedures are reviewed and approved as follows:
-Coating and ASME Code concrete placement procedures are reviewed and approved by the appropriate Company organizations.
-Company, contractor and sub-contractor heat-treating,
: welding, brazing, and other non-NDE procedures are reviewed and approved by Engineering.
-Company NOE procedures are reviewed and approved by the appropriate Company Level Ill. -Contractor, subcontractor, Section Ill, XI, and other ISi-reiated NOE procedures are reviewed and approved by the Company NOE Level Ill. * -The responsible Company engineering organization reviews contractor and subcontractor special process procedures
.. When permitted by applicable requirements, the Company may direct contractors or subcontractors to use Company special process procedures.
The Company assures that qualification of Company, contractor and subcontractor ASME Code NOE procedures, is verified by an Authorized Inspection Agency (AIA). When there is a specific reason to question whether special process procedure requirements are being met, the Company or the AIA may require re-evaluation of the procedure before work may proceed.
For special processes not covered by the existing codes or standards, or when the quality requirements of an item exceed the requirements of established codes or standards, the necessary qualifications of personnel, procedures and equipment shall be defined in the procedure.
Revision 85 CONTROL OF SPECIAL PROCESSES CHAPTER9 2.4 2.5 Page 3 of 3 Personnel Qualification
: Company, contractor, and subcontractor personnel performing special processes are trained, tested, qualified, or certified in accordance with a procedure that meets applicable requirements.
When permitted by applicable requirements, the Company may qualify and control contractor and subcontractor personnel.
The Company assures that qualification of Company, contractor, and subcontractor ASME Code NDE personnel is verified by the AIA. When there is a specific reason to question the ability of an individual performing special processes, the Company, or the AIA may require re-evaluation before that individual will be permitted to resume work. Individuals failing any retest will be removed from applicable operations pending re-qualification.
The appropriate NDE Level Ill is responsible for personnel and procedure development and qualification to ASME Code requirements for nondestructive examination.
This position holder is qualified and certified in accordance with ASNT SNT-TC-1A I ASNT CP-189 and may designate qualified deputies for certification of personnel and procedures, and final Company authority of the interpretation of any NDE indication that has been recorded by a Level II Examiner or by a NDE contractor's Level Ill examiner.
Training and certification of personnel associated with nondestructive examination are carried out in accordance with the requirements of ASME NQA-1 and ASME Section XI. A Level Ill certified person administers all ASME Code examination activities.
Special Process Records Special process records provide evidence that special processes were performed in accordance with approved procedures by qualified personnel.
These records are retained by; the Company, the contractor, or subcontractor, as required by procurement documents.
Records are maintained for currently qualified personnel, processes, and equipment for each special process.
Revision 85 INSPECTION CHAPTER 10 1 SCOPE 2 2.1 2.2 Page 1of4 The Company plans and executes an inspection program to verify that activities affecting the quality of safety-related structures,
: systems, and components conform to documented requirements.
For modification and non-routine maintenance activities, inspections are conducted in a manner similar (i.e., frequency, type and personnel performing such inspections) to those associated with construction phase activities.
The independent inspections described in this Chapter are not intended to dilute or replace the clear responsibility of the first line supervisors for the quality of work performed under their supervision or personnel performing the activity.
REQUIREMENTS General The Company establishes controls for coordination and execution of inspection plans. Company quality verification organizations or other qualified organizations are responsible for implementation of established inspection plans. If an inspection plan includes inspections by personnel other than those in a quality verification organization,.the inspection requirements, personnel qualification
: criteria, and inspector independence will be accepted by the responsible quality organization prior to implementation.
Inspection Plans The Company prepares documented inspection plans. These inspection plans are applied when the activity is started.
The inspection plans may be separate documents or an integral part of approved instructions, procedures or drawings.
Related codes, standards, specifications and design documents are used to develop the inspection plans. Procedures used for documenting inspection plans are selectively
: reviewed, as appropriate by quality verification personnel, to assure that necessary verification points and inspection criteria are included.
The plans identify:
-Acceptance criteria.
-Activities to be inspected.
-Inspection characteristics.
Inspection techniques/equipment (including accuracy requirements).
Revision 85 INSPECTION 2.3 2.4 Page 2of4 CHAPTER 10 -Provisions for inspection and test status. -Provisions for the recording of inspection results.
-Qualification requirements.
-Responsible organizations.
Inspection Personnel and Qualification A qualification program is established and documented to conform to applicable codes, standards, or licensing requirements.
Qualifications and certifications are kept current.
Qualified personnel perform inspections.
Inspectors with valid certifications perform inspections for acceptance.
Inspectors are independent of those who perform or directly supervise the activity being inspected.
Ori-the-Job training inspections shall be performed under the direct supervision of qualified personnel.
Second line supervisory personnel may conduct inspection of operating activities or other qualified personnel not assigned first line supervisory responsibility for the conduct of the work. Operating activities are defined as work functions associated with normal operations of the plant, routine maintenance, and certain technical services routinely assigned to the onsite operating organization.
Supervisor hold points may be procedurally established to inspect the quality of certain stages of work; however, these hold points shall not be used in the place of required independent inspection hold points performed by qualified inspection personnel.
Inspection Process Inspections are performed using approved instructions, procedures, process sheets, travelers, or checklists and applicable drawings.
-Inspections are performed for each work or operating activity where necessary to verify quality.
Where inspection sampling is used to verify the acceptability of a group of items, the sampling procedure shall be based on recognized standard practices.
-Process mon.itoring may be used when inspection of processed material or products is impossible or impractical.
When necessary, to ensure quality throughout the duration of the process, both inspection and process monitoring will be systematically used to verify conformance to requirements.
Revision 85 INSPECTION 2.5 Page 3 of 4 CHAPTER 10 -When required independent inspections must be performed before work can continue, hold points are established in appropriate documents.
Consent to waive independent inspection hold points is recorded prior to continuation of work. These waivers must have appropriate justification documented and be approved by a designated management representative.
When inspection is desired, but not mandatory before work can continue, witness points are established.
Completion of hold and witness points is documented.
-When acceptance criteria are not met, corrected areas are inspected.
Such inspections are documented in the Corrective Action Program as well as the associated work package.
-Changes to, or rework of, an item after inspection requires inspection of the affected areas. -A final evaluation is performed.
Inspection results are reviewed to confirm that required inspections and quality records have been completed, identified non-conformances have been resolved and the item conforms to specified requirements.
Engineering, Maintenance, Operations or Quality Verification approves final acceptance of the item. -Inspection records are of sufficient detail to confirm completion and, as a minimum, identify:
-Authorized individual approving results.
-Date of inspection.
-Inspector/Data recorder.
-Item inspected.
-M&TE used. -Reference to action taken in connection with identified non-conformances.
-Results or acceptability.
-Type of observation.
-When the inspection activity is performed using a separate procedure, the procedure and its revision are recorded.
In-Service Inspections A program for the required ISl/IST inspection of completed
: systems, structures and components shall be planned and executed by or for the organization responsible for the operation of the plant to assure that plant components perform satisfactorily under all operating conditions.
Revision 85 INSPECTION 2.6 Page 4of4 CHAPTER10 Inspection methods shall be established and executed to applicable codes, standards and regulations, including baseline examinations and subsequent periodic examinations, which continue through the life of the plant in accordance with applicable technical
$pecifications.
Independent Verification Qualified personnel using approved procedures conduct independent verifications.
Characteristics to be verified and methods to be employed shall be specified.
Verification results and unacceptable conditions identified shall be documented.
Persons other than those who performed or directly supervised the work being verified shall perform verifications.
Personnel must have qualifications of greater than or equal to the activity being verified.
Revision 85 TEST CONTROL CHAPTER 11 1 2 2.1 2.1.1 2.1.2 Page 1 of 6 SCOPE A documented test program shall be established in accordance with applicable technical specifications, license conditions, and design documents to assure that all testing required demonstrating that the structures,
: systems, or components within the scope of this QAP will perform satisfactorily in service.
REQUIREMENTS General Testing Program The Company establishes and controls a test program to assure that design and performance criteria have been satisfied and assures that testing does not adversely affect the safe operation of the plant. The test program includes, as appropriate, procedures to ensure those structures,
: systems, subsystems, and components will perform in service.
Appropriately trained and qualified personnel conduct testing.
The extent of testing shall be based on the complexity of the modification, replacement, or repair. The test program covers all required tests including:
-Demonstration of satisfactory performance following plant maintenance and modifications or procedural changes.
-Operational tests. -Production tests. -Prototype qualification tests. -Tests during design. -Tests during fabrication.
-Tests required by plant maintenance or modifications.
Test Procedures The program uses written test procedures, which include the requirements and acceptance limits from applicable design documents.
The Company reviews and approves test procedures and changes to test procedures, including changes that alter test sequence, in a similar manner to the original.
Revision 85 TEST CONTROL CHAPTER 11 Page 2 of 6 The organization responsible for the design of the item to be tested establishes the test requirements and acceptance criteria.
Test requirements and acceptance criteria are based upon specified requirements contained in applicable design or other pertinent documents.
Test requirements include specific characteristics to be tested. The Company specifies specific test methods when they must be employed, uses written procedures or checklists, and documents the status of equipment both before and after testing.
The Company may use appropriate sections of related documents, such as ASTM methods, supplier
: manuals, equipment maintenance instructions, or approved drawings or travelers with acceptance criteria in lieu of specially prepared written test procedures.
Such documents must include adequate instructions to assure the required quality of work. Test and inspection procedures contain: -A description of objectives.
-Acceptance criteria or limits contained in applicable design or other source documents, such as vendor's literature, engineering drawings or plant specifications that will be used to evaluate results.
-Any special equipment or calibrations required to conduct the test or inspection.
-Instructions or checklists used to verify or document that affected plant systems are arranged in their correct lineup and for restoring the system to the condition consistent with the normal operating status. -Limiting conditions.
-Prerequisites for, or checks to be made prior to performing the tests or inspections including any special conditions to be used to simulate normal or abnormal operating conditions.
-Data documentation is in compliance with test procedures.
-Equipment to be tested is properly released for testing.
-Inspections and tests are done under suitable environmental conditions.
-Proper calibrated inspection and test instruments are used. -Retention control of test data documentation is adequate.
-Responsibilities.
-Test or inspection requirements contained in applicable design documents.
Revision 85 TEST CONTROL CHAPTER 11 Page 3of6 Where tests and inspections are to be witnessed, the procedure identifies hold points or witness points in the testing sequence to permit witnessing.
The procedure requires appropriate approval for the test to continue beyond the designated hold point. 1. Prerequisites Prerequisites include the following, as applicable:
-Appropriate test equipment.
-Calibrated instrumentation in accordance with Chapter 12, Control of Measuring and Test Equipment.
-Condition of test equipment and the item to be tested. -Provisions for data acquisition.
-Suitable environmental conditions.
-Trained personnel.
Procedures ensure that prerequisite steps for equipment testing have been or will be performed.
Such steps include:
-*completion of necessary construction maintenance and modification activities.
-Formal release for testing.
-Measures to preserve equipment status. -Prior testing.
-Safety precautions.
A detailed prescribed physical inspection of equipment components and facilities is performed to ensure readiness for operation.
Typical inspection items include:
-Calibration of instruments.
-Cleanliness.
-Luprication.
-Presence of safety devices.
-Setting of limit switches.
: 2. Schedule Schedules are provided to assure that all necessary tests are performed and properly evaluated on a timely basis. Testing is scheduled so that the safety of the plant is never dependent on the performance of an untested system. Revision 85 TEST CONTROL CHAPTER 11 2.2 Page 4 of 6 3. Test Results and Records Appropriate Company personnel evaluate test results to assure conformance with design and performance requirements.
Inspection and test results are documented in a test report or data sheet. Each report identifies the following:
-Acceptability of the test. -Actions taken to correct the deviations noted. Any deviation of test results from acceptance criteria (nonconformance).
-As-found condition.
As-left condition.
Completion date and other significant dates and times. -Data sheets completed during the tests. Documents that provide acceptance criteria.
-Identification of the conditions encountered which were not anticipated.
-Identity of inspector or tester. -Item to which it applies.
-Location where testing was performed or where test samples were taken. -Measuring and test equipment used. Person evaluating test results.
-Procedures or instructions followed in performing the task. -Test procedures.
-Test results.
Instrumentation and Control The Company tests instrumentation and control channels to assure that they are properly calibrated
.. In addition, specific tests are performed at critical levels such as "set points" in a manner simulating the approach toward the set point. These calibrations are made with the devices in their normal positions if the calibration is dependent upon location or attitude.
Testing determines that a proper response is obtained over the operating range of the device. It gives particular attention to verifying independence and dependence, as appropriate, of the elements of the systems.
Calibration documentation includes indicating the date and identity of the person that performed the calibration.
Revision 85 TEST CONTROL CHAPTER 11 2.3 2.4 Page 5of6 The Company prepares and documents installation, inspection and test procedures and work instructions for instrumentation and electrical equipment.
These documents are kept current and revised as necessary to assure that installation, inspections and tests are performed in accordance with latest information.
They include as appropriate:
-Approvals.
-Data report forms. -Frequency of inspection or test. -Identification of test equipment and date for required re-calibration where required for interpretation of test results.
-Inspection and test acceptance limits. -Inspection and test equipment required.
-Inspection and test objectives.
-Installation specifications.
-Precautions to avoid component or system damage during testing or inspection.
-Prerequisites.
-Sequence of tests (if applicable).
-
actions to be performed.
Electrical Tests Electrical tests include as appropriate:
-Continuity tests, short circuit tests, polarity and rotational tests. -Control system tests including indicating meters, recorders, transducers, targets and lamps, annunicators and alarms, controls and interlocks.
-Insulation resistance measurements as specified.
-Over potential (HIPOT) tests as specified.
Over potential tests conform to the applicable codes and standards.
The manufacturer's recommendations are considered.
-Voltage breakdown tests on liquid insulation.
Mechanical Tests The Company performs mechanical tests to ascertain that electric and/or instrumentation components or systems can withstand system pressure ratings.
As a minimum, the* Company applies such tests to pressure sensing and transmitting devices operating in steam, hydraulic, and vacuum systems and their hydraulic or pneumatic interconnecting piping or tubing and associated instruments.
Revision 85 TEST CONTROL CHAPTER 11 2.5 2.6 2.7 2.8 Page 6of6 Pressurized equipment that is part of electrical apparatus such as heat exchangers, circulating
: systems, actuating
: systems, and electric and instrumentation containment penetrations are likewise tested if site assembled or fabricated.
Tests are conducted after the assembly is complete even though the components may have been tested previously.
These tests are performed in accordance with the applicable codes and standards.
Physical and Chemical Tests Physical and chemical tests, in accordance with the applicable codes, include, as appropriate:
-Chemical analysis of fluids for oxygen or moisture content and purity. -Radiation sensitivity testing to confirm that radiation sensor and controlling devices is properly functioning.
Surveillance Tests . The Company's test program covers surveillance testing during the operational phase to provide assurances that failures or substandard performance do not remain undetected and that the required reliability of safety related systems is maintained.
Maintenance or Major Procedure Change The Company performs tests following plant modification or significant changes in operating procedures to confirm that the modification or changes produce expected results.
These tests also demonstrate that the change does not produce an unsafe operating condition.
Software Tests The Company ensures computer programs for safety-related applications are appropriately tested. Software applications are tested in a manner to ensure that the new functionality is operating properly and can be introduced to the production environment with minimal disruption.
When appropriate, periodic in-use manual or automatic self-check routines are prescribed and performed for those applications where computer failures or drift can affect required performance.
Revision 85 CONTROL OF MEASURING AND TEST EQUIPMENT CHAPTER 12 1 2 2.1 2.2 Page 1of3 SCOPE Measures and responsibilities are established to assure tools, gauges, instruments, and other Measuring and Testing Equipment (M&TE) used in activities affecting quality are properly controlled, calibrated, and adjusted at specified periods to maintain accuracy within specified limits. Measures shall also be established for the control of permanently installed instrument and control devices.
REQUIREMENTS General The Company is responsible for the governance of M& TE. This includes the establishment of calibration practices, intervals, accuracy requirements, certification/de-certification, and equivalency decisions, as well as the resolution of technical issues regarding M&TE calibration.
The engineering organizations are responsible for decisions regarding the acceptability of changes to M&TE specifications where accuracies are less conservative tha,n those currently established.
The engineering organization performs M&TE equivalency calculations for these items to assure associated specifications are consistent with plant design, test procedures, and accuracy requirements (excluded are analytical chemistry and radiochemistry instruments).
The stations are responsible for the control and maintenance of calibrated M& TE for the station.
The stations are also responsible for the control of station analytical chemistry instrumentation, radiochemistry instrumentation, and standard solutions.
Control A control program specifies how M&TE are stored, handled, and used. As a minimum the following items are addressed:
-Administrative controls (including equipment marking and traceability to calibration records).
-Certification requirements.
-Calibration interval and method. -Damaged or suspect M& TE. -Environmental restrictions.
Revision 85 CONTROL OF MEASURING AND TEST EQUIPMENT CHAPTER 12 2.3 2.4 2.5 2.6 Page 2 of 3 -Items not requiring certification.
-M&TE selection.
-Out of tolerance resolution.
-Personnel qualifications.
-Repairs and maintenance.
-Status and usage history.
Labeling Equipment shall be suitably marked to indicate calibration status. Where neither labeling nor coding is practical, procedures shall provide for monitoring of records to ensure control.
Accuracy Calibration of M& TE should be against reference standards that have an accuracy of at least four times the required accuracy of M&TE. Calibration of reference standards will be against hierarchical standards more accurate than the reference standards calibrated.
When this is not possible, standards must have an accuracy that assures the M&TE is within the required tolerance, and that the basis for acceptance is documented and authorized by responsible management.
Traceability and Interval M& TE is calibrated against and traceable to certified standards having valid relationships to nationally recognized standards.
Where national standards do not exist, provisions are established to document the basis for calibration.
Calibration intervals are established for all M&TE and the Company program specifies how this interval is established.
Certified M& TE Certified M&TE is required where measureme'nts with specific accuracy/tolerance requirements are delineated:
-Calibration of other M& TE. -Environmental monitoring.
-Safety-related and applicable ASME applications.
-Technical Specification related applications (including balance of plant systems).
-Verification of design parameters.
Revision 85 CONTROL OF MEASURING AND TEST EQUIPMENT CHAPTER 12 2.7 2.8 2.9 2.10 Page 3 of 3 Certified M&TE is not required when measurements do not require specific accuracy or when commercial devices (such as rulers, tape measures, levels) provide adequate accuracy.
Calibration is not required for electronic stopwatches.
Corrective Actions When M& TE is found to be out-of-tolerance, an evaluation is made of its previous uses to determine corrective action. Suspect equipment is identified and segregated to prevent inadvertent use. Devices that are consistently found out of calibration are repaired or replaced.
Vendor Control Vendors supplying calibration services are on the Company's approved suppliers list. When the Company uses a vendor to calibrate M&TE, the procurement documents shall impose a requirement for the accredited laboratory to provide as-found calibration data when any item being calibrated is found to be out-of-tolerance.
Corrective actions are then taken by the Company based on this information.
Commercial Devices Control measures are not required for rulers, tape measures, levels, and other such commercial
: devices, if such equipment provides adequate accuracy.
Calibration Records M&TE calibration records contain, as a minimum:
-As found/as left condition.
-Calibration data. -Calibration procedure used. Calibration results.
-Equipment location.
-Established accuracy.
-Individual performing calibration.
-Last calibration date. -Next calibration date. -Out of tolerance notification.
Repairs (if any). -Serial number. -Standards used. Revision 85 
: HANDLING, STORAGE AND SHIPPING CHAPTER13 1 2 2.1 2.2 Page 1of2 SCOPE The Company establishes measures to control and specify special protective conditions in accordance with an item's design and procurement requirements, as necessary, to prevent damage or deterioration of materials, components, and systems during handling, packaging, preservation,
: storage, and shipping.
REQUIREMENTS General The Company uses written procedures or instructions for cleaning, packaging,
: shipping, storage, preservation, and to specify detailed requirements for access to storage areas, housekeeping, and removal of items from storage.
Procedures include provisions for inspection, examination, testing and documentation.
These procedures specify special protective conditions necessary to prevent damage, deterioration or loss before and after receipt of materials, equipment, special nuclear material, and radioactive wastes. Procurement documents or the vendor's quality program specifies the establishment of controls, to assure through the use of shipping procedures to provide protection during loading and transit and inspections that items are delivered in acceptable condition.
Special Equipment and Environments Wheri required, the Company:
-Provides special equipment and special protective environments.
-Specifies special *equipment (such as containers, shock absorbers and accelerometers).
-Specifies special protective environments (such as inert gas atmosphere, specific moisture content levels and temperature levels).
-Verifies the maintenance of special equipment and special protective environments.
Revision 85 
: HANDLING, STORAGE AND SHIPPING CHAPTER 13 2.3 2.4 2.5 2.6 Page 2 of 2 Classification of Items Levels and methods of storage are classified to minimize the possibility of damage, deterioration, or contamination of items. This is based on the important physical characteristics and the importance to safety and reliability of the item. This classification considers the manufacturer's requirements.
The Company packages, ships, receives, stores, and handles items according to established manufacturers requirements or the Company's' prescribed level. When a package or assembly contains items of different levels, the Company classifies it to the highest level designated for any of the items contained.
Special Handling Tools and Equipment The Company inspects and tests special handling tools and equipment using procedures at specified time intervals to verify adequate maintenance.
The Company provides special handling procedures and instructions for items that are susceptible to handling damage. These procedures delineate acceptable techniques, necessary qualifications and precautions for maintenance and use. Operators of special handling and lifting equipment have experience or are trained in their usage.
* Marking and Labeling The Company establishes instructions for marking and labeling to identify,
: maintain, and preserve an item, including indication of the presence of special environments or the need for special controls.
Consumable materials such as chemicals,
: reagents, and lubricants maintained in storerooms and warehouses are controlled procedurally by an inventory control system, which includes provisions for identifying storage requirements and shelf lives by commodity, when applicable.
Disposal of commodities whose shelf life has expired is addressed and controlled by procedures.
Storage Periodic monitoring is performed to assure that storage areas are being maintained in accordance with applicable requirements.
Access to storage areas shall be controlled and limited.
Cleanliness and good housekeeping practices shall be enforced at all times in the storage areas. Fire protection measures commensurate with the type of storage area shall be provided and maintained.
Revision 85 INSPECTION, TEST AND OPERATING STATUS CHAPTER 14 1 2 2.1 Page 1of4 SCOPE Measures shall be established and documented to identify inspection, test, and operating status of structures,
: systems, and components in the scope of this OAP. Such measures shall provide means for assuring that required inspections and tests are performed and that the acceptability of items with regard to inspections and tests performed is known throughout procurement, installation, and operation in order to preclude inadvertent bypassing or altering the sequence of such inspections and tests. REQUIREMENTS General The Company uses markings, tags, stamps, routing cards, labels, forms, inspection
: records, or other means to identify the operating status of plant equipment.
This identification helps avoid inadvertent bypassing of the inspections and tests required prior to its use. In cases where documentary evidence is not available to confirm that an item has passed required inspections and tests, that item shall be considered nonconforming.
An operability determination for the nonconforming item with timeliness commensurate with the potential safety significance of the issue is performed.
The operability determination is focused on whether the non-conforming item is capable of performing or supporting its specified functions of prevention or mitigation as described in the current licensing basis and will result in the determination of continued plant operation.
If operability is assured based on this prompt determination, plant operation can continue while an appropriate corrective action program is implemented to restore qualification of the non-conforming item. Control procedures describe the use of such tags, stamps, routing cards, labels, forms, inspection
: records, and other methods.
The authority for application and removal of tags, markings, labels and stamps is specified.
: Tagging, labeling, color-coding, physical separation, or using an inventory system identifies acceptable or unacceptable items for installation.
The Company:
-Clearly identifies and documents all temporary connections, such as jumpers and bypass lines, and temporary set points of control equipment to allow restoration before placing the item in service.
Revision
.85 INSPECTION, TEST AND OPERATING STATUS CHAPTER 14 2.1.1 2.2 2.2.1 Page 2 of 4 -Conditionally releases items for installation pending subsequent correction of any non-conformances.
-Controls the use of nonconforming items pending an evaluation and approved disposition by authorized personnel.
-Indicates the date an item was placed in the acceptable or unacceptable installation status. -Maintains
: records, marks equipment to indicate calibration status, and identifies test equipment found out of calibration.
Procedures The Company uses procedures for control of equipment to maintain personnel and reactor safety and to avoid unauthorized operation of equipment.
These procedures require control measures such as locking or tagging to secure and identify equipment in a controlled status. The procedures require independent verifications, where appropriate, to ensure that necessary
: measures, such as equipment
: tagging, have been done correctly.
Operating Status Release for Maintenance Operating personnel, including a senior reactor operator, as applicable, may grant permission to release plant systems or equipment for maintenance or surveillance testing.
Prior to granting permission, such operating personnel:
Determine how long it may be out of service.
-Determine what functional testing or redundant systems are required prior to and during the out-of-service period. -Verify that the equipment or system can be released.
The Company documents such permission.
The Company uses independent verification to the extent necessary to ensure that the proper system was removed from service.
The Company considers the degraded protection available when one subsystem of a redundant safety system has been removed for maintenance or surveillance testing.
Revision 85 INSPECTION, TEST AND OPERATING STATUS CHAPTER14 2.2.2 2.2.3 Page 3 of 4 Preparation for Work After permission has been granted to take the equipment out of service, measures provide for protection of equipment and workers.
The Company clearly identifies the status of equipment and systems at any location where the equipment can be operated.
The Company enforces strict control measures for such equipment.
The operating staff can easily identify equipment, which is in other than normal conditions.
* In addition to the requirements of the technical specifications, conditions to be considered in preparing equipment for maintenance or surveillance testing include, for example:
-Electrical hazards.
-Entry into closed vessels.
-Establishment of a path for decay heat removal.
-Handling hazardous materials.
-Hazardous atmospheres and ALARA considerations.
-Method of emergency core cooling.
-Shutdown margin. -Temperature and pressure of the system. -Valves between work and hazardous materials.
-Venting,
: draining, and flushing.
When entering a closed system, the Company prevents the entry of extraneous material and removes foreign material before re-closing the system. Appropriate personnel inform control room supervision of changes in equipment status, including temporary modifications, and the effects of such changes.
Temporary Modifications The Company controls temporary modifications, such as temporary bypass lines, electrical
: jumpers, lifted electrical leads, and temporary trip point settings with approved procedures.
These procedures include requirements for the period of time when the temporary modification is in effect. They also include a requirement for: -An independent or concurrent verification by a second person of the prop*er installation or removal of the temporary modification, or -A functional test which conclusively proves the proper installation or removal of the temporary modification.
Revision 85 INSPECTION, TEST AND OPERATING STATUS CHAPTER 14 2.2.4 2.2.5 Page 4 of 4 The Company maintains a log or other documented evidence for the current status of such temporary modifications.
The Company reviews temporary modifications periodically to assess their continued need and propriety.
Inspections and Tests The status of inspection and test activities shall be identified either on the components or in documents traceable to the components where it . is necessary to assure that required inspections and post maintenance tests have been satisfactorily performed to assure that equipment which has not passed the required inspections and tests is not inadvertently installed, used, or operated.
Return to Service When equipment is ready to be returned to service, operating personnel place the equipment in operation and verify and document its functional acceptability.
The Company assures return to normal conditions using approved procedures, including:
-Assuring that all alarms, which are indicative of inoperative status, are cleared.
-Removal of electrical jumpers.
-Removal of signals used during testing.
-Returning valves, breakers, or switches to proper start-up Of operating positions.
A second qualified person verifies proper alignment of equipment unless: -All equipment, valves and switches involved in the activity can be proven to be in their correct alignment by functional testing without adversely affecting the safety of the plant, or -Such verification would result in significant radiation exposure.
The person who performs verifications (independent or concurrent) is qualified to perform such tasks. When placed into* service, equipment receives additional surveillance during the run-in period. The on-duty supervisor responsible for the unit formally accepts equipment, which is returned to service.
Revision 85 NONCONFORMING MATERIALS, PARTS OR COMPONENTS CHAPTER 15 1 2 2.1 2.1.1 Page 1of4 SCOPE Controls shall provide for identification, evaluation, segregation when practical, disposition of nonconforming items, and for notification to affected organizations.
Items that do not conform to specified requirements shall be controlled to prevent inadvertent installation or use. REQUIREMENTS General Nonconforming items are processed in accordance with the corrective action program and/or documented procedures.
The Company uses written procedures to identify and control items, services or activities that do not conform to requirements.
These procedures address the: -Disposition
'of nonconforming items. -Documentation of identified nonconformances.
-Identification of nonconforming items. -Notification of affected organizations.
-Operability determination of the SSC with the identified nonconforming condition
-Segregation of nonconforming items. Implementation of these procedures prevents the inadvertent use, operation, or unauthorized installation of nonconforming items. Supplier Nonconforming Items The Company and its suppliers establish and document measures for the identification, control and disposition of items and services that do not meet procurement document requirements.
These measures provide for: -A review of nonconforming items. -Company disposition of supplier recommendations.
-Maintenance of records for supplier nonconformances.
-Supplier notification to the Company of a nonconformance.
These notifications include a supplier recommended disposition (e.g. as-is" or "repair")
and technical justification.
The supplier submits nonconformances to the Company for approval if:
* The item does not conform to the original procurement requirement even though the item can be restored to a condition such that the capability of the item to function is unimpaired, or Revision 85 NONCONFORMING MATERIALS, PARTS OR COMPONENTS CHAPTER15 2.2 2.3 2.4 2.4.1 2.4.2 Page 2 of 4
* The supplier cannot correct the nonconformance by continuation of the original manufacturing process or by rework, or
* The supplier has violated a requirement in supplier documents, which have been approved by the Company, or
* The supplier has violated a technical or material requirement.
-Verification of disposition for nonconformances.
Identification The Company identifies nonconforming items by marking,
: tagging, or other methods, which do not adversely affect the end use of the item. The identification is legible and easily recognizable.
Segregation When practical, the Company segregates nonconforming items by placing them in a clearly identified and designated hold area until properly dispositioned.
When segregation is impractical or impossible due to physical conditions such as size, weight or access limitations, other precautions are employed to preclude inadvertent use of a nonconforming item. Disposition Control Nonconforming characteristics shall be reviewed and recommended dispositions of nonconforming items shall be proposed and approved in accordance with documented procedures.
Further processing,
: delivery, installation, or use of a nonconforming item shall be controlled pending an evaluation, and an approved disposition by authorized personnel.
Evaluation The Company has responsibility for resolution of nonconformances in accordance with written procedures.
Where ASME Code requirements are involved, the Authorized Inspection Agency reviews and accepts or rejects the disposition and justification.
Engineering provides technical justification and independent review of nonconformances dispositioned as repair or use-as-is.
Revision 85 NONCONFORMING MATERIALS, PARTS OR COMPONENTS CHAPTER 15 2.4.3 2.4.4 Page 3of4 For items under a contractor's direct control, the Company may delegate to the contractor the authority to perform a technical evaluation of nonconformances, if the contractor has an acceptable procedure for handling nonconforming items. Where the Company delegates such authority, the contractor is responsible for establishing that: -All actions fall within the requirements set by the Company.
-An accepted nonconformance meets the design intent. -ASME Code items meet the requirements of the ASME Code. -Personnel performing the evaluation meet the requirements of section 2.4.3 below. When a technical evaluation has not been delegated to a supplier, the Company makes a technical evaluation of all pertinent data relating to the nonconformity, including the cause, where known, and the corrective action either taken or planned to prevent recurrence per the corrective action program.
The Company retains the responsibility for the satisfactory resolution of supplier nonconformances.
Personnel Personnel having expertise in the pertinent discipline determine whether a nonconforming item may be accepted "as-is,"
may be repaired to an acceptable condition, or must be rejected.
These personnel have adequate competence and knowledge necessary to make this evaluation and have access to pertinent background information.
Documentation
. The Company identifies nonconforming items and documents their disposition (e.g., use-as-is, reject, repair, or rework).
Each disposition is technically justified and traceable to each item. Appropriate documentation is retained.
Nonconformances to design requirements that are dispositioned as "use-as-is" or "repair" are subject to design control measures commensurate with those applied to the original design. The Company technically justifies dispositions designated "use-as-is" and "repair" to. assure that the final condition of any nonconforming item meets applicable code requirements and will not adversely affect the safety, operability, or maintainability of the item, or of the component or system in which it is installed.
The "as-built"
: records, if such records are required, reflect the accepted deviation.
Revision 85 NONCONFORMING MATERIALS, PARTS OR COMPONENTS CHAPTER 15 2.4.5 Page 4 of 4 If the noncoriformance can be corrected after installation, the item may be released for installation on a conditional release basis. The Company documents the authority and technical justification for the conditional release of the item and makes it part of the documentation.
: Repaired, Reworked, or Scrapped Items The Company re-examines repaired or reworked items using procedures and the original acceptance criteria unless the nonconforming item's disposition has established alternate acceptance criteria.
Items that have been corrected are re-inspected or re-tested as required by the approved disposition.
The area of inspection may be confined to the area of the nonconformance.
When it has been determined that the corrected item is satisfactory, the status of the item is changed to "acceptable" and an appropriate entry is made in the documentation after acceptance is determined.
The Company scraps, discards or transfers to training usage a nonconforming item that cannot be corrected or accepted "as-is."
Nonconforming items that are being used for training must be controlled (e.g., administratively controlled, permanently identified, marked, or Material ID Tag or Q level indicators obliterated, etc.) to prevent inadvertent or inappropriate use of the item. Revision 85 CORRECTIVE ACTION CHAPTER16 1 2 2.1 2.2 Page 1of4 SCOPE This Chapter describes the Company program to identify and correct conditions adverse to quality.
. REQUIREMENTS General The Company implements a Corrective Action Program to promptly identify and correct items or occurrences that are adverse to quality or might adversely affect the safe operation of a nuclear generating station.
These items or occurrences are screened for reportability, operability, Part 21, and industry operating experience.
The Company makes a thorough investigation of occurrences and identifies corrective action to prevent recurrence of an event, as appropriate.
Events may include reactor trips, failed equipment, personnel errors, and procedural infractions.
Measures are taken to assure that the cause of any significant condition adverse to quality is determined and to implement corrective action to prevent recurrence.
Conditions Adverse to Quality Measures are established to assure that conditions adverse to quality are identified, classified as to significance, evaluated to determine cause and corrective
: actions, reviewed to determine the existence of trends, and effectively corrected.
Examples of conditions adverse to quality are provided in procedures.
Examples include failures, malfunctions, adverse trends, deficiencies (including programmatic),
deviations, defective
: material, design errors, equipment, and nonconformance to specified requirements.
An independent review body reviews violations, deviations and reportable events that require a report to the NRG in accordance with regulatory requirements and company procedures.
This includes the review of results of any investigations made and the recommendations resulting from such investigations.
These include items such as: -Events, as defined in applicable site technical specifications.
-Significant operating abnormalities or deviations from normal ot expected performance of plant safety-related structures,
: systems, or components.
-Violations of applicable codes, regulations, orders, technical specifications, license requirements or internal procedures or instructions having safety significance.
Revision 85 CORRECTIVE ACTION CHAPTER 16 2.2.1 Page 2 of 4 Significant Conditions Adverse to Quality In cases of significant conditions adverse to quality the root cause of the condition is determined and documented, resolution determined and documented, and corrective action taken and documented to preclude recurrence.
The impact of such conditions on completed and related items and activities is evaluated.
Follow-up reviews are then performed to verify that the corrective actions taken were effective.
: 1. Procurement The Company uses procedures that include methods for the identification of conditions adverse to quality and for timely corrective action. The Company requires individual vendors and their contractors to include corrective action measures in their quality assurance programs.
In cases of significant conditions adverse to quality that arise during the procurement
: process, the Company uses procedures to describe the method used to: -Identify and document deviations and non-conformances.
-Review and evaluate the conditions to determine the cause, extent and measures needed to correct and prevent recurrence.
* -Report the conditions and corrective action to the appropriate levels of management.
-Implement and maintain required corrective action. 2. Plant Hardware Malfunctions The causes of malfunctions are determinec;I, evaluated, and recorded, as appropriate.
Experience with the malfunctioning equipment and similar components are reviewed and evaluated to determine if a replacement component of the same type can be expected fo perform the function reliably.
If evidence indicates that common components in safety-related systems have performed unsatisfactorily, corrective measures are planned prior to replacement or repair of all such components.
Appropriate procedures are revised in a timely manner to prevent recurrence of equipment malfunction or abnormal operation.
: 3. Incorrect Design When a significant design change *is necessary because of an incorrect design, the Company reviews and modifies the design process and verification procedures, as appropriate.
In cases of significant or recurring deficiencies (or errors),
the Company follows written procedures to correct the deficiency (or error), determine the cause and make changes in the design process and the QAP to prevent similar types of deficiencies (or errors) from recurring.
Revision 85 CORRECTIVE ACTION CHAPTER16 2.3 2.4 Page 3of4 Verification and Follow-up The Company screens identified issues to verify suitable categorization and moves those that are not found to be conditions adverse to quality out of the corrective action program.
Resources are then applied to resolve issues based on significance.
The Company verifies completion of corrective actions for maintenance, repair, refueling, operation activities, completion of corrective action taken for assessment deficiencies (including programmatic),
and performs assessments of site corrective action. The Company tracks and verifies completion of corrective action taken for independent audit and assessment findings and approves the completion of corrective actions.
Trending and audit/assessment results are evaluated to assure that corrective measures are implemented effectively and that actions to prevent recurrence are effective as appropriate.
The Company also requires contractors and vendors to follow-up on corrective action commitments within their quality programs.
The Company regularly and analyzes records to: -Assure that the causes of a nonconformance and the corrective action have been clearly described.
-Assure-that authorized Company personnel have evaluated the overall effect resulting from the use of nonconforming items. -Determine whether corrective measures will preclude recurrence.
Evaluation and Qualification Personnel performing the evaluation function are responsible for considering the cause and the feasibility of corrective action to assure that the necessary quality of an item is not deteriorated.
Where it is determined that the cause cannot be corrected immediately, the due date of corrective action will be determined during the review and ev1aluation.
Evaluation may indicate the need for investigations to assure that corrective measures are considered complete and may also indicate that the nature of the deficient condition is minor and does not require corrective action. Qualified personnel are responsible for determining the* root cause(s) of an event and developing recommendations to preclude recurrence.
These personnel report the results of their determination to appropriate station personnel and Company management.
Revision 85 CORRECTIVE ACTION CHAPTER 16 2.5 Page 4 of 4 Documentation and Reporting The Company documents the identification of significant conditions adverse to quality, the cause of the condition, the corrective action taken, and reports these items to the appropriate levels of management and an on-site review committee.
Independent reviews of the corrective actions for significant conditions adverse to quality are performed by the on-site review committee and the Nuclear Oversight organization.
If the identified issue is not an indication of a significant failure in any portion of the OAP, the Company does not require reporting to management.
Reports are made immediately if prompt corrective action is required.
Formal reports are filed with the appropriate regulatory agency, when required.
Reports of investigations include a detailed description of the occurrence, the findings of the investigation, and the recommended corrective measures.
The Company notifies the rest of the nuclear industry of significant events with generic implications and its circumstances to help preclude a similar event occurring at another plant. The Company keeps records to identify incidents (e.g., major damage, personal injury, or major schedule delays),
nonconforming items, unfavorable conditions, programmatic deficiencies identified in audit and assessment
: reports, significant equipment
: failures, and malfunctions that occur during station operation.
The Company tracks the completion of corrective actions for conditions adverse to quality and maintains records of their resolution.
Parts or all of this system may be electronically monitored and electronic records may be used as the sole record of such a system. Revision 85 QUALITY ASSURANCE RECORDS CHAPTER17 1 2 2.1 2.2 Page 1of3 SCOPE The Company establishes and implements a program, which defines requirements and responsibilities for identification, generation, collection, compilation,
: storage, maintenance, retention, and retrieval of records necessary to provide evidence of quality in design, fabrication, installation, inspection,
: testing, and operating activities.
REQUIREMENTS Program The records program provides for: -Administration.
-Receipt and transmittal.
-Retention and disposition.
-Safekeeping and classification.
-Storage and preservation (includes temporary and permanent records)
Administration Authority and responsibility for record control activities are delineated in procedures.
Records are administered through a system, which includes an index of record type, retention period, and storage location.
Distribution of records shall be controlled in accordance with written procedures.
Measures are established for replacement, restoration, or substitution of lost or damaged records.
Records are legible,
: accurate, complete, identifiable, and retrievable.
Records are considered valid and complete when dated and stamped, initialed, signed, or otherwise authenticated.
Corrections, revisions, or supplements to completed records are reviewed and approved by an authorized individual in the originating organization.
Such changes are dated and stamped, initialed, signed, or otherwise authenticated including the use of electronic approval and authorization.
Revision 85 QUALITY ASSURANCE RECORDS CHAPTER 17 2.3 2.4 Page 2 of 3 Records may be stored in electronic media provided that the process for managing and storing data is documented in procedures that comply with applicable regulations.
Media used for the retention of records include (but are not limited to): microform, compact recordable (CD-R), and magnetic media including videotape, computer tape, optical disks, and hard disk storage.
Electronic records retention must be an integral component of a corporate records management
: program, approved by the management position responsible for Company records.
The format used must be capable of producing
: legible, accurate, and complete documents during the required retention period. Electronic approval and authorization procedures are established to assure that only those persons authorized grant the required approvals.
Receipt and Transmittal A system for receipt control of records is established.
Receipt control is required for records transferred between Company locations, vendors and the Company, and from Company department files to final storage locations.
Systems are established to transfer records between Company locations and between vendors and the Company.
Records transferred from Company department files to a final storage location are also under such systems.
The system of receipt control of records for permanent or temporary storage includes inventory of transmitted
: records, receipt acknowledgment, and control of records *during receipt.
Storage and Preservation Record storage facilities are established and maintained in a manner that minimizes the risk of damage or destruction.
Interim storage provisions shall be established to properly maintain and protect records until they are permanently transferred to record storage facilities for retention.
Records may be kept by suppliers and maintained on an available basis for a specified period of time. Star.age and Preservation systems provide for: -Assignment of responsibilities.
-Attachment in binders,
: folders, or envelopes for storage in steel file cabinets or on shelving in containers.
-Control and accountability of records removed.
Revision 85 QUALITY ASSURANCE RECORDS CHAPTER 17 2.4.1 2.5 2.6 2.7 Page 3of3 -Damage from natural disasters such as winds, floods, and fires. -Following manufacturer recommendations for special recording media. -Protection from environmental conditions such as high and low temperatures and humidity.
-Protection from infestation of insects, mold, or rodents etc. -Special processed records such as radiographs, photographs, negatives, microfilm, and magnetic media to prevent damage from excessive light, stacking, electromagnetic fields, temperature and* humidity.
Temporary Storage Measures are established for temporary storage of records When required by an organization's procedures for activities such as for processing, review, or use. These measures require that these records are stored in a 1-hour fire rated container and that a maximum allowable storage time limit is specified.
Safekeeping and Classification Measures are established to prevent access to records by unauthorized personnel.
These measures guard against theft and vandalism.
Records are classified and retained in accordance with applicable regulations.
Retention and Disposition Record retention periods are established to meet regulatory, UFSAR, and License requirements.
The most stringent retention period is implemented when multiple requirements exist. Plant Operating Records Required plant operating records are grouped into two retention periods; 5-year and lifetime.
These type of records are those that are specified by applicable regulations, standards, codes, and licensing basis documents.
Methods of control, identification, permanent
: storage, and retrieval of these records are specified in administrative procedures.
Revision 85 AUDITS/ASSESSMENTS CHAPTER 18 1 2 2.1 2.1.1 Page 1of6 SCOPE A documented, comprehensive system consisting of regulatory audits and performance assessments of the Conipany and its vendors are conducted to verify OAP compliance,
: adequacy, and effectiveness.
Audits and assessments are conducted in accordance with written procedures or checklists.
Audits are performed to the requirements of ASME NQA-1 to evaluate the audited organization and to assure completion of required corrective
: actions, commitments or improvements, and determine effectiveness in meeting program objectives.
REQUIREMENTS Audits and Assessments
-General Scheduling The internal audit program is conducted on a performance driven frequency that is commensurate with the condition of the area being audited.
Internal audits are usually conducted over a 24-month time period, however, frequencies can vary by regulation and when there are indications that negative performance is occurring in an area to be audited.
Regulatory variances are identified in the Appendix B "Audit Frequency" portion of this document.
Thus, the audit frequencies utilized are determined based on regulatory considerations, the risk and consequences of the area being assessed, and the observed performance of the area. Except for the Security and Emergency Preparedness Audits (items I., and m., of Appendix B), audits may be extended beyond their original scheduled due date based on the following criteria:
: 1. A maximum extension not to exceed 25 percent of the audit interval is allowed (unless a specific regulation prohibits it). For example, audits on a 24-month frequency should not exceed a maximum time between audits of 30-months; audits on an annual (12-month) frequency should not extend beyond 15-months.
: 2. When an audit interval extension greater than one month is used, the next audit for that particular area is scheduled from the original anniversary month rather than from the month the extended audit was performed.
: Likewise, if an audit is performed earlier than scheduled, this early completion date becomes the new start date for the 12 or 24 month audit interval.
Item 1 (above) applies to supplier audits and evaluations as well, except that a total combined interval for any three consecutive inspection or audit intervals should not exceed 3.25 times the specified interval.
Revision 85 AUDITS/ASSESSMENTS CHAPTER 18 2.1.2 2.1.3 Page 2of6 For scheduling purposes and with appropriate adjustments for approved extensions, audits shall be tracked on a calendar month basis such that an audit must start no later than the end of the same calendar month the audit was last started.
An audit is considered to have been started when the first day of auditing field time begins. Planned assessments of station activities supplement the scheduled audits and are conducted to monitor overall station performance.
Scheduling of internal assessment activities is flexible since assessments are primarily on-going to monitor day-to-day evolutions or to review emergent events or conditions (e.g., reactor transients, significant quality program failures, etc.). The management position responsible for NOS, or designated staff member(s),
approves the conduct of these activities.
Audit and assessment schedules are reviewed semi-annually and revised accordingly to assure that coverage is appropriately maintained.
Preparation*
A documented plan or an agenda identifies an audit or assessment scope, requirements, audit or assessment personnel, activities to be evaluated, organizations to be notified, applicable documents, and schedule.
An approved checklist or procedure for each scheduled audit or assessment identifies the quality and technical elements of the area or items to be evaluated.
Audit plans, agendas, checklists, and procedures as applicable are prepared in advance under the direction of a certified Lead Auditor (LA). Independent assessments will be led by individuals who meet the requirements of ANSl/ANS-3.1-1981 paragraph 4.4.5. Personnel Experienced and qualified personnel perform assessments and audits and are familiar with written procedures, standards, and processes applicable to the area being evaluated.
and audit personnel shall have sufficient authority and organizational freedom to make the assessment and audit process meaningful and effective and shall not have direct responsibilities in the areas to be assessed or audited.
They shall have access to the plant records necessary to fulfill their function.
The LA shall organize and direct audits and ensure the teams collectively have the required experience or training for the activities to be evaluated.
Assessment Team Leads will organize and facilitate internal station evaluations and assessments.
Technical Specialists Revision 85 AUDITS/ASSESSMENTS CHAPTER 18 2.1 .. 4 Page 3of6 shall supplement the teams when required to provide additional experience and competence.
Audit and assessment personnel (including members of the off-site review committee) shall have sufficient authority and organizational freedom to implement their assigned responsibilities, including immediate unfettered access to obtain records, meet with personnel, and travel to jobsite locations as needed to gather objective evidence regarding the performance of important to safety activities.
This access must be accomplished,
: however, in compliance with applicable access control measures for security, radiological protection, and personal safety. Performance
-Performance assessments and audits are conducted to assess specific activities, processes, and records on the basis of their impact and importance relative to safety, reliability, and functionality with respect to risks and consequences.
Assessments are flexible and can be focused on areas most in need of improvement.
Audits are structured to verify compliance with the quality assurance program conditions necessary to meet regulatory requirements.
Planned audits include independent review of the effectiveness of programs, processes, and those administrative controls necessary to ensure nuclear, radiological, and environmental safety and security is being maintained.
Planned assessments include license required independent reviews of plant specific activities, as well as more comprehensive evaluations of station performance to identify gaps in meeting industry standards.
One of the assessments shall be an annual review of the content and implementation of the security program required to meet the requirements of 10 CFR 37, Physical Protection of Category 1 and Category 2 Quantities of Radioactive Material.
Audits are initiated early to assure effective quality assurance during design, procurement, manufacturing, construction, installation, inspection,
: testing, and operations.
Additional unscheduled audits and assessments may also be performed at various stages of activities, based on the nature _and safety significance of the work being done, to verify continued adherence to and effectiveness of the quality systems.
Objective shall be examined to the extent necessary to determine that a quality program is being effectively implemented.
Any deficiencies identified during internal audits and assessments shall be captured in the Company's corrective action program.
Revision 85 AUDITS/ASSESSMENTS CHAPTER18 Page 4of6 The Company establishes programs for reviews and assessments to:
* Verify that activities covered by this QATR are performed in conformance with the requirements established,
* Review significant proposed plant changes or tests,
* Verify that reportabre events are promptly investigated and corrected, and
* Detect trends which may not be apparent to the day-to-day observer.
These programs are, themselves, reviewed for effectiveness as part of the overall assessment process as described herein. The Company uses self-assessment (performed by or for the group responsible for the activity being assessed) and independent assessment (such as that performed
.bY the Nuclear Oversight organization) to monitor overall performance, identify anomalous
. performance and precursors of potential
: problems, and verify satisfactory resolution of problems.
Persons responsible for carrying out these assessments are cognizant of day-to-day activities such that they can act in a management advisory function with respect to the scope of the assessment.
Both self-assessments and independent assessments are accomplished using instructions or procedures that provide detail commensurate with the assessed activity's complexity and importance to safety. The Company's nuclear stations maintain an on-site review committee (referred to as the Plant Operations Review Committee or PORC) to review overall plant performance, and advise site management on matters related to nuclear safety. This committee functions in accordance with the standards specified in C. The Company periodically performs independent reviews of matters involving the safe operation of its nuclear power plants, with *a minimum of one such review being conducted for each generating station each year. The review addresses matters that plant and corporate management determine warrant special attention, such as plant programs, performance trends, employee
: concerns, or other matters related to safe plant operations.
The review is performed by a team consisting of personnel with experience and competence in the activities being reviewed, but independent (from cost and schedule considerations) from the organizations responsible for those activities.
The review is supplemented by outside consultants or organizations as necessary to ensure the team has the requisite expertise and competence.
The team's results are documented and reported to
* responsible management.
Revision 85 AUDITS/ASSESSMENTS CHAPTER 18 2.1.5 Page 5of6 Reporting and Follow-up An audit report includes the description of the audit scope, identification of the team and personnel contacted during audit activities, a summary of results (including a statement on effectiveness of the OAP elements),
and a description of each finding.
The LA shall sign the audit report for which he or she is responsible.
Formal assessment reports are written in an understandable format identifying sources for the conclusions drawn, including the personnel interviewed and the documentary material reviewed.
The recommendations and proposed actions as well as the content of the final report is approved by NOS supervision responsible for the team. Audit and assessment results are promptly distributed to the management position responsible for NOS and to the appropriate managerial level of the organization having responsibility for the area or activity audited/assessed.
Findings or deficiencies requiring prompt corrective action are reported immediately to the management of the assessed organization.
: Findings, deficiencies, performance gaps, and recommendations of each audit and assessment shall be reported to appropriate site management and the management position responsible for NOS. All findings of noncompliance with NRC requirements,.
and any significant nuclear safety or quality issues requiring escalated action, will be directed through the management position responsible for NOS to the P&CNO in accordance with procedural Responsible management shall take the necessary actions to correct findings identified in the assessment/audit.
They will identify the corrective action to be taken, actions that will prevent recurrence, and a schedule for implementing these actions.
Responses to audit and assessment findings are revfewed for adequacy.
Follow-up verification of the completion of scheduled corrective action commitments are performed by NOS to assure findings or adverse conditions are corrected in accordance with procedural requirements.
Follow-up action of previous deficient areas or adverse conditions (including re-audit) is taken to verify that corrective action has been completed, is effective, implementation continues, and is properly documented, when indicated.
Revision 85 AUDITS/ASSESSMENTS CHAPTER18 2.1.6 2.2 2.3 Page 6 of 6 Records Audit and assessment results are documented and reports are generated and retained.
Associated documentation is on file at the appropriate location.
Personnel qualification records for assessment and audit team members are established, maintained, and reviewed.
Vendor Audits Audits or surveys of vendors and their sub-tier suppliers are performed to a pre-established schedule.
Audits are performed on a triennial basis. Documented supplier performance monitoring is performed in accordance with approved procedures as an acceptable alternate to the performance of the annual evaluation of suppliers.
The management position responsible for the audit program (or designee),
shall review and approve the audit I survey schedule and checklists, and sign reports.
Schedules are reviewed semi-annually and revised accordingly to assure that suppliers are assessed,
: audited, or surveyed as required.
Audit program requirements are imposed on suppliers by appropriate contract or procurement documents.
The Company's active participation in nuclear industry audits provides an alternative means to fulfilling its responsibility for examining supplier activities.
With regard to fitness for duty services that are provided by off-site contractors as well as for Health and Human Services certified laboratories, they are audited on a nominal 12 month frequency.
Independent Management Assessment A periodic audit (not to exceed 24 months) of the status and adequacy of the QAP is performed by independent organization to assure that the Company's quality assurance management and nuclear oversight process is being accomplished in a manner that meets 10 CFR 50 Appendix B and other applicable requirements.
The management position responsible for NOS submits the results of this assessment to the P&CNO. Revision 85 AUGMENTED QUALITY APPENDIX A 1 2 2.1 Page 1of6 SCOPE It is the Company's policy to assure a high degree of availability and reliability for its nuclear plants while ensuring the health and safety of the public and its workers.
Therefore, the QAP is applied in a graded manner to certain areas and activities that are not clearly defined as safety related.
The Company calls this application Augmented Quality.
Augmented Quality includes systems and components that are subject to the requirements of ASME Code Sections:
I "Power Boilers,"
IV "Hot Water Heaters,"
and VIII "Non-fired Pressure Vessels."
This appendix applies to all sites unless otherwise noted below or in other appendices included in the QAP. REQUIREMENTS The Company applies the following augmented quality requirements to certain systems, structures, components (SSC), and activities that are not safety related to a degree consistent with their importance to safety. Unless otherwise noted: -Deficiencies are addressed in accordance with the corrective action program.
-Program records of audits and reviews are maintained as required.
-Routine audits are performed of the program's content and implementation.
Augmented quality applicability extends to non-safety-related items or services for which the Company has made regulatory or design basis commitments requiring QAP involvement.
These include but are not limited to fire protection and event mitigation equipment, accident monitoring instrumentation, certain components that contain significant amounts of radioactivity (e.g., greater than 10 CFR 50.67 limits),
to items that maintain structural integrity to preclude inadvertent damage to safety-related equipment, to important-to-safety SSCs such as the Dry Cask Storage Systems and the Independent Spent Fuel Storage Installation, and to certain services such as Security background checks. Augmented quality may also be used for plant availability reasons where special controls are required to be implemented to assure reliability.
Health Physics and ALARA (As Low As Reasonably Achievable)
The Company develops, documents, and implements a radiation protection program sufficient to ensure compliance with the provisions of 10 CFR 20. The Company uses, to the extent practical, procedures Revision 85 AUGMENTED QUALITY APPENDIX A 2.2 2.3 Page 2of6 and engineering controls based on sound radiation protection principles to achieve occupational doses and doses to the public that are as low as reasonably achievable.
Controls for radioactive waste management systems include those augmented quality measures that provide for the reasonable assurance needed to protect both the health and safety of the public and that of plant operating personnel.
Transport of Radioactive Waste When the Company contracts with vendors to transport radioactive waste in NRG approved shipping
: packages, it meets the requirements of 10 CFR 71, Subpart H. The Company assures that this service is procured from an organization with a QAP and if applicable, includes a NRG licensed transport system. Loading, surveying,
: closure, placarding, and inspections are conducted in accordance with written procedures and instructions.
Transport casks and trailers are inspected before release in accordance with Department of Transportation (DOT) 49 CFR requirements.
Shipping manifests, including final radiation
: surveys, are completed and retained.
Radioactive waste shipments not meeting the requirements for NRG approved packaging, shall meet the requirements of DOT 49 CFR. Fire Protection 10 CFR 50 Appendix A, General Design Criteria (GDC) 3 requires that the Company's nuclear facilities have an established fire protection program that provides fire protection features such that the adverse effect of fires on structures, systems and components important to safety is minimized.
The QAP established for these fire protection SSCs ensures that design, procurement, instruction, procedures,
: drawings, inspection, installation,
: testing, maintenance, operations, nonconforming Items, corrective action, records, audits and administrative controls meet the applicable Quality Assurance guidelines as described in the applicable edition of Branch Technical Position (BTP) 9.5-1 for each company site. Engineering determines what fire protection SSCs protect structures,
: systems, and components important to safety. Engineering also establishes the requirements for the design, procurement, fabrication, installation and/or modification of these fire protection SSCs. Routine testing of fire protection systems assures reliability.
All other fire protection equipment and supplies will be of commercial
: quality, in accordance with National Fire Protection Association (NFPA) guidelines.
Revision 85 AUGMENTED QUALITY APPENDIX A 2.4 2.5 2.6 2.6.1 2.7 Page 3 of 6 Repairs and Alterations The (equirements of ASME Code Sections II, V, and IX shall be imposed as applicable for the repair or alteration of job specific work scope. Repairs and alterations performed under the R Certificate Of Authorization shall meet the requirements of the New Jersey Administrative Code 12:90 and the National Board Inspection Code NB-23 except where appropriately noted in Company written procedures and instructions.
Station Blackout Company generating stations rely on non-safety related equipment to achieve the redundancy required by 10 CFR 50.63. Quality Assurance requirements are implemented in accordance with Regulatory Guide 1.155, Station*
: Blackout, Appendix "A" and "B." Replacement and consumable parts and supplies are classified "non-safety related" in accordance with original specifications and are procured as commercial items with provisions to ensure design-related guidelines used in complying with 10 CFR 50.63 are included.
Routine testing of Station Blackout (SBO} SSCs assures the necessary redundancy is maintained.
SBO SSC reliability is monitored in accordance with the Station's Maintenance Rule program.
Dry Cask Storage System Hope Creek Generating Station (HCGS} and Salem Generating Station (SGS} HCGS and SGS QAP requirements are performed in accordance with the applicable 10 CFR 72.212 report, which invokes the NRG approved 10 CFR 50 Appendix B quality assurance program as described in this QATR. The Independent Spent Fuel Storage Installation (ISFSI) SSCs that are deemed important-to-safety are categorized as A and B components in accordance with NUREG/CR-6407.
Category C ISFSI components are treated with augmented quality tenets. Quality assurance records are also maintained for the ISFSI by the Company and the certificate holder per 10 CFR 72.17 4 until the ISFSI license or Certificate of Compliance (CoC) is terminated.
Emergency Planning Requirements with respect to equipment and records for Emergency Preparedness are described in an Emergency Plan that meets the requirements of 10 CFR 50.47. Augmented quality consideration should be given to those systems and equipment used for assessing and monitoring the consequences of a radiological emergency, including equipment important to emergency response as identified per Revision 85 AUGMENTED QUALITY APPENDIX A 2.8 2.9 2.10 Page 4of6 INPO 10-007, such as event classification instrumentation.
Security Requirements with respect to equipment and records for Security are controlled for each station by an NRC approved Station Security Plan that is prepared and implemented in accordance with the requirements contained in 10 CFR 73.55. Augmented quality requirements should be applied to items and services associated with Security Background Checks, Fitness-For-Duty
: Testing, and Cyber Security Critical Digital Assets. Support Services When the Company procures support services from suppliers, it is in accordance with.written procedures and instructions.
Although it is not necessary that these suppliers have a QAP approved by the Company, i.e., need not be on the approved suppliers list, they must provide a QAP that has the appropriate controls to address the regulatory aspects of the product or service they are supplying.
For support services associated with radiological monitoring
*in the environment, suppliers should provide a copy of their QAP that includes the necessary program elements of Revision 1 or 2 of Regulatory Guide 4.15, and should routinely provide data summaries sufficiently detailed to permit evaluation of their program for services in areas such as: -Meteorology
-Offsite Dose Calculation
-Radiological Environmental Monitoring Structures and Components Subject to an Aging Management Program for License Renewal For the period of extended operations associated with station license renewal:
: 1. The Company implements the requirements of QATR Chapters 1 through 18 for safety-related structures and components subject to an aging management program.
: 2. The Company implements the administrative
: controls, corrective
. actions, and confirmation processes described in QATR Chapters 6, Document
: Control, and 16, Corrective Action, for related structures and components that are subject to an aging management program.
Revision 85 AUGMENTED QUALITY APPENDIX A 2.11 2.11.1 2.11.2 Page 5of6 Fukushima Dai-ichi Event Based Quality Requirements Regarding reliable Spent Fuel Pool instrumentation at both Salem and Hope Creek Generating Stations per NRC Order EA-12-051.
: 1. The Company maintains reliable indication of the water level in associated spent fuel storage pools at each of its nuclear facilities.
: 2. Components that make up the instrumentation will be assigned augmented quality constraints as appropriate.
The requirements for the design, procurement, fabrication, installation and/or modification of these level instruments will be established.
Routine testing of the Spent Fuel Pool instrumentation systems will assure reliability.
: 3. The extent to which augmented quality is applied should assure primary and backup Spent Fuel Pool instrument channel reliability will exist for extended periods of time at temperature,
: humidity, and radiation levels consistent with pool water at saturation conditions.
Regarding reliable Hardened Containment Venting System (HCVS) at the Hope Creek Generating Station per NRC Order EA-13-109.
: 1. The Company design for HCVS components including instrumentation should, as minimum, meet the quality design requirements of the plant, ensuring HCVS functionality.
-The HCVS up to and including the second isolation valve is designed to the same quality requirements of the connected system up to the first isolation valve. -HCVS elements that are not covered by 5.3.1.1 should be reliable and rugged to ensure HCVS functionality following a seismic event. -Additionally, HCVS non-safety equipment installed to meet the requirements of Order EA-13-109 must be implemented so that they do not degrade the existing safety-related systems.
Revision 85 AUGMENTED QUALITY APPENDIX A Page 6 of 6 2. Severe Accident Water Addition (SAWA) components including instrumentation should, as minimum, meet the quality design requirements of the plant, ensuring HCVS functionality.
-The connection point is designed to the same quality requirements of the connected system up to the first isolation valve. -The SAWA piping system beyond the first isolation valve should meet the quality requirements of Order EA-13-109.
-Portable equipment supporting both a FLEX function and a SAWA function should meet the limiting quality requirements of Order EA-12-049 and EA-13-109.
-Portable equipment supporting a SAWA function only should meet the quality requirements of Order EA-13-109.
-Additionally, SAWA non-safety, permanently installed equipment and piping systems must be installed to meet the requirements of Order EA-13-109 and mus.t be installed so that they do not degrade any existing safety-related systems.
: 3. Design quality requirements and supporting analysis documentation should be auditable, and controlled in accordance with the Company's records management and document control system. 4. HCVS equipment should be initially tested or have other reasonable means used to verify that its performance conforms to the design and operational requirements.
-Validation of source manufacturer quality is not required.
-The HCVS maintenance program should ensure that the HCVS equipment reliability is being achieved in a manner similar to that.required for FLEX equipment.
Standard industry templates (e.g., EPRI) and associated bases may be developed to define specific maintenance and testing.
Revision 85 AUDIT FREQUENCY APPENDIX B Internal audits shall be conducted on a performance driven frequency, not to exceed 24 months or at the frequencies indicated below, in accordance with Chapter 18 of this QAP. Audits shall include the following safety-related areas as applicable:
AUDIT FREQUENCY
: a. The conformance of unit operation to provisions contained within the technical specifications and applicable license conditions.
24 Months b. The adherence to procedures,
: training, and qualification of the station staff. 24 Months -c. The results of actions taken to correct deficiencies occurring in facility equipment, structures,
: systems, components, or method of 24 Months operation that affect nuclear safety (Corrective Action Program).
: d. The performance of activities required by the Quality Assurance Program to meet the criteria of Appendix B of 1 OCFR50, including:
-Operations
* -Nuclear Fuels -Chemistry 24 Months -Engineering
-Procurement
-Maintenance
-QA Functions (Evaluated by NIEP audit.)
* Includes on-site review committee activities.
: e. The fire protection programmatic controls including the 24 Months implementing procedures
{by qualified NOS personnel).
: f. The fire protection equipment and program implementation, including verification of compliance with the administrative controls and implementation of QA criteria as they apply to fire protection 24 Months features and safe shut-down capability.
An independent fire protection specialist meeting Society of Fire Protection Engineer member grade (or equivalent) qualifications shall serve on the audit team. g. The Radiological Environmental Monitoring Program (REMP) and its 24 Months results.
Page 1 of 3 Revision 85 AUDIT FREQUENCY APPENDIXB
: h. The Offsite Dose Calculation Manual (ODCM) and implementing 24 Months procedures.
: i. The Process Control Program (PCP) and implementing procedures 24 Months for the solidification of radioactive wastes. j. The performance of activities required by the Company QAP for 24 Months effluent and non-radiological environmental monitoring.
: k. Randomly selected procedures**
to ensure that the programmatic control processes used to assure that procedures are technically and administratively correct prior to use are resulting in timely and accurate procedure revisions.
24 Months **Includes a representative sample of "routine" plant procedures (as defined in section 13.5 of the Salem and Hope Creek UFSARs) that are used more frequently than every two years. I. The Security Plan and implementing procedures (1 OCFR73.55(m) and 10CFR50.54(p)(3)).
(Audit frequency can be extended to 24 months if an independent assessment finds that there has been no 12 Months change to personnel, procedures, equipment, or facilities that potentially could have adversely affected this program in the first 12 months of the 24 month period.)
: m. The Emergency Plan and implementing procedures (1 OCFR50.54(t)).
(Audit frequency can be extended to 24 months if an independent assessment finds that there has been no change to personnel, 12 Months procedures, equipment, or facilities that potentially could have adversely affected this program in the first 12 months of the 24 month period.)
: n. Independent review/assessment activities.
(This audit can be 24 Months performed by, and when it is scoped into, the NIEP audit.) 0. The conformance of Independent Spent Fuel Storage Installation operation to provisions contained within the technical specifications and applicable license conditions and results of actions taken to 24 Months correct deficiencies occurring in facility equipment, structures,
: systems, components, or methods of operation affecting nuclear safety. (Reference NUREG/CR-6407 and 1 OCFR72, Subpart G.) Page 2 of 3 Revision 85 AUDIT FREQUENCY APPENDIXB
: p. Access Authorization (AA) Program (1 OCFR73.56(n)).
An 24 Months independent individual who is knowledgeable of and practiced with meeting the performance objectives and requirements of the access authorization program or the program elements being audited shall serve on the audit te.am. (If the AA program is not under the direct daily supervision or observation of Company personnel, it must be audited on a nominal 12 month frequency.)
: q. Personnel Access Data System (PADS) (10CFR73.56(n)).
(If the 24 Months PADS program is not under the direct daily supervision or observation of Company personnel, it must be audited on a nominal 12 month frequency.)
: r. Station Black Out (Regulatory Guide 1.155, Appendix A). 24 Months s. Radiation protection activities as defined in 1 OCFR20. 24 Months t. Fitness For Duty (FFD) Program (1 OCFR26.41
). (The appropriate frequency, scope, and depth of additional auditing within the 24 24 Months month period should, if required, be based on the frequency, nature, and severity of discovered
: problems, testing errors, personnel or procedural
: changes, and previous audit findings.)
: u. Cyber Security Program (1 OCFR73.54(g)).
(Audit frequency can be set at 24 months as long as an audit can and will be initiated within 12 months following a change to personnel, procedures, equipment, 24 Months or facilities that potentially could have adversely affected this program in the first 12 months of the 24 month period.)
: v. Nuclear Repair Program (1 OCFR50.55a).
(Audit frequency based on 12 Months requirements from the National Board Guide for "R" and "NR" Certificates of Authorization in conjunction with the National Board Inspection Code (NBIC), Part 3, Repairs and Alterations
{NBIC NB-23} requirements.)
Page 3 of 3 Revision 85 CODES, STANDARDS AND GUIDES APPENDIXC 1 SCOPE 1.1 Page 1 of 10 The QAP takes into account the need for special controls, processes, test equipment, tools, and skills necessary to attain the required quality and the need for the verification of quality by inspection and test. The codes and standards listed below represent a listing of quality assurance codes and standards used to define the quality assurance program.
Codes and Standards A general listing of quality assurance related codes and standards, such as: ASME B&PV, ANSI, AWS, and IEEE used throughout the Company at each nuclear station can be found in the applicable station-specific Updated Final Safety Analysis Report (UFSAR).
The UFSAR should be referenced to identify station-specific commitments with respect to these codes and standards.
This QAP complies with the quality requirements of the following codes and standards unless otherwise noted in sub-section 1.3: -ANSl/ANS-3.1-1981, "Selection, Qualification and Training of Personnel for Nuclear Power Plants."
-ANSI N18.7-1976/ANS-3.2, "Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants."
(Refer to Sub-sections 1.3.1, item 5., and 1.3.2, item 3., of this Appendix for notes on use.) -ANSl/ASME NQA-1-1994, "Quality Assurance Requirements for Nuclear Facility Applications."
* Part I, "Basic Requirements and Supplementary Requirements for Nuclear Facilities"
* Part II, "Quality Assurance Requirements For Nuclear Facility Applications",
and * . Part III, "Nonmandatory Appendices,"
limited to Appendix 2A-1, "Nonmandatory Guidance on the Qualifications of Inspection and Test Personnel,"
Appendix 2A-3, "Nonmandatory Guidance on the Education and Experience of Lead Auditors,"
Appendix 17A-1, "Nonmandatory Guidance on Quality Assurance Records,"
and Appendix 18A-1, "Nonmandatory Guidance on Audits."
The Company complies with this nonmandatory guidance as long as it does not conflict with federal regulations or other required industry standards/guidance.
Exception:
The qualification of Non-Destructive Examination (NOE} personnel can be in accordance with ANSl/ASNT CP-189 rather than through *SNT-TC-1A as specified in NQA-1-1994 Supplement 2S-2. Revision 85 CODES, STANDARDS AND GUIDES APPENDIXC 1.2 Regulatory Guides The applicable station-specific UFSAR should be referenced to identify station-specific commitments with respect to the Regulatory Guides listed in this section.
The OAP also complies with the regulatory positions of the following Regulatory Guides and additional programmatic quality requirements unless otherwise noted in sub-section 1.3: -1.8, "Personnel Qualification and Training"
-1.26, "Quality Group Classification and Standards for Nuclear Power Plants" -1.29, "Seismic Design Classification"
-1.31, "Control of Ferrite Content in Stainless Steel Weld Material"
-1.33, "Quality Assurance Program Requirements"
-1.52, "Design,
: Testing, and Maintenance Criteria for Atmosphere Cleanup System Air Filtration and Absorption Units of Light Water Cooled Nuclear Power Plants" * -1.54, "Quality Assurance Requirements for Protective Coatings Applied to Water Cooled Nuclear Power Plants" -1.68, "Pre-Operational and Initial Start-Up Test Programs for Water Cooled Reactors"
-1.137, "Fuel Oil Systems for Standby Diesel Generators" 1.142, "Safety Related Concrete Structures for Nuclear Power Plants" -1.143, "Design Guidance for Radioactive Waste Management SSCs Installed in Light Water-Cooled Nuclear Power Plants" -1.155, "Station Blackout"'
1.3 Station-Specific Clarifications and Exceptions In each of the standards that the Company complies with, other documents (e.g., other standards, codes, regulations, tables, or appendices) are referenced or described.
These other documents may contain useful quality assurance
: guidance, however, if they are not explicitly committed to by the Company, they are not considered QAP "requirements".
Also, these other documents may not be the current guidance being employed by the Company and therefore should not be employed.
For example, the Company has determined to comply with ANSI N18.7-1976/ANS 3.2, however, this standard references other standards such as ANSI N45.2.11 in section 5.2.7.2 for design modifications, which is not the current guidance committed to by the Company.
In this case, NQA-1-1994 should be substituted for ANSI N45.2.11.
Page 2 of 10 Revision 85 CODES, STANDARDS AND GUIDES APPENDIXC 1.3.1 Page 3of10 Hope Creek Generating Station (HCGS) 1. UFSAR 1.8.1.8, Conformance to Regulatory Guide 1.8, Revision 2, April 1987: "Qualification and Training of Personnel for Nuclear Power Plants."
HCGS complies with Regulatory Guide 1.8, except as noted below. a. The management position responsible for operations shall either hold a Senior Reactor Operator License (SRO) or have held an SRO license for a similar unit (BWR) or have been certified at an appropriate simulator for equipment senior operator knowledge.
: b. Licensed operator qualifications and training shall be in accordance with 1 OCFR55. c. The management position responsible for radiation protection shall meet or exceed the qualifications of Regulatory Guide 1.8, September 1975. d . .The management positions at the corporate and site level responsible for Nuclear Oversight and the management positions responsible for engineering that report to a management position responsible for engineering and technical
: support, which corresponds to the Engineer in Charge, must meet or exceed the qualifications of ANSI/ANS 3.1-1981.
: e. Members of the off-site review committee shall meet or exceed the qualifications described in Section 4. 7 of ANSI/ANS 3.1-1981. Exceptions to this requirement may be granted to a maximum of two members of the committee provided these members meet the following alternative qualifications:
: i. Has a minimum of twenty years nuclear related experience, ii. Shall hold or have held a senior reactor operator license or certification, and iii. Shall have served as a minimum in a nuclear vice-pre$ident or equivalent position.
The PSEG Chief Nuclear Officer or a Chief Operating Officer shall approve via written documentation any members accepted to the committee using the alternative qualification method. 2. UFSAR 1.8.1.26, Conformance to Regulatory Guide 1.26, Revision 3, February 1976: "Quality Group Classifications and Standards for Water, Steam, and Radioactive Waste Containing Components of Nuclear Power Plants."
HCGS complies with Regulatory Guide 1.26, with the clarifications outlined below. Revision 85 CODES, STANDARDS AND GUIDES APPENDIXC Page 4of10 a. The Company does recognize the need for the assurance of the specified operation of certain non-safety-related structures, systems and components, such as fire protection
: systems, radioactive waste treatment, handling and storage systems, and Seismic Category II/I items. Such assurance is documented through the specification of limited quality assurance programs (described in Table 3.2-1, footnotes 22, 50 and 52). In addition, items designated "R" in Table 3.2-1 will be included in the QA program during operations to the extent required by Regulatory Guide 1.143. b. The exception to Position C.2.b is that since the reactor recirculation pumps do not perform any safety function arid since failure of the reactor coolant pumps due to seal or cooling water failure does not have serious safety implications, the control rod drive (CRD) seal purge supply and Reactor Auxiliaries Cooling System (RAGS) cooling water to the seal coolers are quality group D. c. Additionally, Position C.2.b of Regulatory Guide 1.26 requires that cooling water systems important to the safety function of the standby diesel generators be Quality Group C. HCGS's diesel generator cooling water systems are classified as Quality Group C except for the engine mounted piping systems (such as the lube oil headers, water headers, cylinder heads, etc). The engine mounted piping systems are part of the diesel engine and its auxiliary support systems, which, as stated in Section B of the Regulatory Guide, are not covered by this guide. These systems are manufactured to the manufacturer's proprietary design requirements, which do not necessarily meet the requirements of ASME Section Ill or ANSI B.31. However, the components used are pressure tested and the manufacturing processes are monitored as a part of the . suppliers approved QA program, which addresses the 18 criteria contained within 10 CFR 50, Appendix B. Additional quality assurance requirements invoked include:
-Periodic documented sub supplier audits (including plant visits),
-Review and approval of sub supplier QA programs and manuals,
-Test and inspection audits, -Calibration of test gauges before and after use, and -Control of calibration records and acceptance devices.
: d. With the imposition of the above design, manufacturing, and testing controls, the on-skid and off-skid piping and components have been made to be equivalent to Quality Group C. This meets the requirements in Section B of the guide to design, Revision 85 CODES, STANDARDS AND GUIDES APPENDIXC Page 5of10 fabricate, erect and test the diesel engine and its auxiliary support systems to quality standards commensurate with the safety function to be performed.
: e. NUREG-0737, Item ll.k.3.25 extends the requirements of Position C.2.b by requiring demonstration that the consequences stemming from a loss of cooling water to the reactor recirculation pump seal coolers is acceptable following a loss of power for at least 2 hours. NED0-24951 (Reference 5.4-4) confirms that the HCGS design meets the requirements of NUREG-0737, Item ll.k.3.25.
: 3. UFSAR 1.8.1.29, Conformance to Regulatory Guide 1.29, Revision 3, September 1978: "Seismic Design Classification."
HCGS complies with Regulatory Guide 1.29, subject to the exceptions and clarifications listed in the HCGS UFSAR. 4. UFSAR 1.8.1.31, "Conformance to Regulatory Guide 1.31, Revision 3, April 1978: Control Ferrite Content Stainless Steel Weld Metal." Although Revision 3 of Regulatory Guide 1.31 is not applicable to HCGS, per its implementation
: section, HCGS complies with it, subject to exceptions and clarifications listed in the HCGS UFSAR. 5. UFSAR 1.8.1.33, Conformance to Regulatory Guide 1.33, Revision 2, February 1978: "Quality Assurance Program Requirements
* (Operation)."
NQA-1-1994 contains quality assurance requirements similar to those in the ANSI N45.2 series. The administrative control elements from ANSI N18.7 are included in this QATR. a. Regulatory Position C.1, the Company uses Appendix "A" of RG 1.33 as guidance in establishing the types of procedures required for plant operation and support.
: b. Regulatory Position C.2 is no longer considered valid, as the referenced standards and guidance have now been incorporated into ASME NQA-1-1994, or are specifically addressed in this QATR. c. Regulatory Position C.3 applies since the company uses independent review. However, the ANSI N18.7-1976/ANS-3.2 subjects for independent review; including the paragraph 4.3.4 independent review items, such as Technical Specification
: changes, license amendments, and Emergency Plan changes; the paragraph 4.5 independent review of audit reports; and the paragraph 5.2.11 independent review of SCAQs, shall be performed by the on-site review committee.
Review of these subjects by the off-site review committee is not required.
Additionally, the ANSI N18.7-1976/ANS-3.2 paragraph 4.3.2 guidance on independent review committee composition, Revision 85 CODES, STANDARDS AND GUIDES APPENDIX C Page 6of10 meeting frequency, quorum, and records are not required to be met. This criteria will be procedurally established by the Company as needed to support management expectations and quality requirements.
: d. In lieu of compliance with Regulatory Position C.4, the Company establishes audit topics and frequencies as described in Appendix "B" of this QATR. e. In lieu of compliance with Regulatory Position C.5, the Company has established appropriate equivalent requirements within this QATR. f. Regarding section 5.1 of ANSI N18.7-1976, the text "a summary document shall be compiled by each owner organization to identify the sources, to index such source documents to the requirements of this Standard and to provide a consolidated base for description of the program",
is being interpreted by the Company as an electronic
: database, i.e., the Document Control and Records Management System (DCRMS),
that contains all the source documents required to implement the QAP and enables electronic sorts and text searches that serves to provide the consolidated base for description of the program.
: g. Regarding section 5.2.15 of ANSI N18.7-1976, third paragraph, the text "unusual incident" is interpreted to mean "reportable incident."
: 6. UFSAR 1.8.1.52, Conformance to Regulatory Guide 1.52, Revision 2*, March 1978: "Design,
: Testing, and Maintenance Criteria for Accident Engineered-Safety-Feature Atmosphere Cleanup System Air Filtration and Adsorption Units of Light Water Cooled Nuclear Power Plants."
HCGS complies with Regulatory Guide 1.52, subject to exceptions and clarifications listed in the HCGS UFSAR. 7. UFSAR 1.8.1.137, Conformance to Regulatory Guide 1.137, Revision 1, October 1979: "Fuel-Oil Systems for Standby Diesel Generators."
Although Regulatory Guide 1.137 is not applicable to HCGS, per its implementation
: section, HCGS complies with it, subject to exception of regulatory position C.1, which endorses ANSI N195-1976 Section 8.2.d and as modified by Technical Specification Amendment Nos. 74 and 100. Refer to the HCGS UFSAR. 8. UFSAR 1.8.1.142, Conformance to Regulatory Guide 1.142, Revision 1, October 1981: "Safety-Related Concrete Structures for Nuclear Power Plants (Other than Reactor Vessels and Containments)."
Regulatory Guide 1.142 is not applicable to HCGS per its implementation section.
SRP Section 3.8.4, Acceptance Criteria 11.2, requires that Seismic Category I structures be designed in accordance with ACI 349-1976 as augmented by Regulatory Guide 1.142. HCGS Seismic Category I structures are designed based on ACI 318-1971.
Revision 85 CODES, STANDARDS AND GUIDES APPENDIXC Page 7of10 a. A review of the design of the HCGS Seismic Category I structures indicates that there is no impact due to differences in the structural acceptance criteria between ACI 318-71 and ACI 349-76 as augmented by Regulatory Guide 1.142. See Design Criteria Comparison Table 1.8-4. b. The load combinations used are in conformance with the following SRP sections except that the 0.9 load factor on dead load as required by ACI 349-76 was not used: Structures SRP Section Primary Containment Internal 3.8.3.11.3.b Concrete Structures Other Seismic Category 3.8.4.11.3.b Concrete Structures
: c. Based on parametric
: analyses, an adequate design margin exists to compensate for the effects of the reduced dead load factor. 9. UFSAR 1.8.1.143, Conformance to Regulatory Guide 1.143, Revision 1, October 1979: "Design Guidance for Radioactive Waste Management
: Systems, Structures, and Components Installed in Light Water Cooled Nuclear Power Plants."
Although Regulatory Guide 1.143 is not applicable to HCGS, per its implementation
: section, HCGS complies with it, subject to exceptions and clarifications listed in the HCGS UFSAR. 10. UFSAR 1.8.1.120, "Conformance to Regulatory Guide 1.120, Revision 1, November 1977: Fire Protection Guidelines for Nuclear Power Plants."
HCGS complies with Regulatory Guide (RG) 1.120 with the exceptions discussed in the HCGS UFSAR. Since most of the guidelines in Regulatory Guide 1.120 have been incorporated in BTP CMEB 9.5.1, Revision 2, dated July 1981, the exceptions are only for those items that are not found in, BTP CMEB 9.5.1, Revision
: 2. See Section 9.5.1 for an evaluation of SRP 9.5.1 and additional exceptions.
Also, see Appendix 9A for an evaluation of the HCGS design against the requirements of 1 OCFR50, Appendix R. 11. Applicable Section XI ASME Code Years and Addenda for the Hope Creek In Service Testing (IST) and In Service Inspection (ISi) Programs:
: a. IST: OM Code -2001 with 2003 OMb Addenda b. ISi: 2001 Edition with 2003 Addenda Revision 85 CODES, STANDARDS AND GUIDES APPENDIXC 1.3.2 Page 8of10 Salem Generating Station (SGS) 1. Regulatory Guide 1.8, "Qualification and Training of Personnel for Nuclear Power Plants,"
Revision 2, April 1987. Salem complies with the Regulatory Guide 1.8, except as noted below. a. The management position responsible for operations shall either hold an SRO license or have held an SRO license for a similar unit (PWR) or have been certified at an appropriate simulator for equipment senior operator knowledge.
: b. Licensed operator qualifications and training shall be in accordance with 1 OCFR55. c. The management position responsible for radiation protection shall meet or exceed the qualifications of Regulatory Guide 1.8, September 1975*. Note: Section 6.3.1 of the Salem Technical Specifications (TS} indicates that the facility staff shall meet or exceed the minimum qualifications of ANSI N18.1-1971.
Actual staff qualifications,
: however, is governed by the Salem UFSAR and QATR to ANSI 3.1-1981.
Because ANSI 3.1-1981 has more stringent and exacting standards than . ANSI N18.1-1971, the Salem TS requirements are satisfied.
: d. The management positions at the corporate and site level responsible for Nuclear Oversight and the Management positions responsible for engineering that report to a management position responsible for engineering and technical
: support, which corresponds to the Engineer in Charge, must meet or exceed the qualifications of ANSI/ANS 3.1-1981.
: e. Members of the off-site review committee shall meet or exceed the qualifications described in Section 4.7 of ANSI/ANS 3.1-1981. Exceptions to this requirement may be granted to a maximum of two members of the committee provided these members meet the following qualifications:
: i. Has a minimum of twenty years nuclear related experience, ii. Shall hold or have held a senior reactor operator license or certification, and iii. Shall have served as a minimum in a nuclear vice-president or equivalent position.
The PSEG Chief Nuclear Officer or a Chief Operating Officer shall approve via written documentation any members accepted to the committee using the alternative qualification method. Revision 85 CODES, STANDARDS AND GUIDES APPENDIXC Page 9of10 2. Regulatory,Guide 1.31, "Control Of Ferrite Content In Stainless Steel Weld Metal." Salem complies with Regulatory Guide 1.31 subject to the clarification and exceptions listed in the SGS UFSAR. 3. Regulatory Guide 1.33, "Quality Assurance Program Requirements (Operation)."
NQA-1-1994 contains quality assurance requirements similar to those in the ANSI N45.2 series. The administrative control elements from ANSI N18.7 are included in this QATR. a. Regulatory Position C.1, the Company uses Appendix "A" of RG 1.33 as guidance in establishing the types of procedures required for plant operation and support.
: b. Regulatory Position C.2 is no longer considered valid, as the referenced standards and guidance have now been incorporated into ASME NQA-1-1994, or are specifically addressed in this QATR. c. Regulatory Position C.3 applies since the company uses independent review. However, the ANSI N18.7-1976/ANS-3.2 subjects for independent review; including the paragraph 4.3.4 independent review items, such as Technical Specification
: changes, license amendments, and Emergency Plan changes; the paragraph 4.5 independent review of audit reports; and the paragraph 5.2.11 independent review of SCAQs, shall be performed by the on-site review committee.
Review of these subjects by the off-site review committee is not required.
Additionally, the A_NSI N18.7-1976/ANS-3.2 paragraph 4.3.2 guidance on independent review committee composition, meeting frequency, quorum, and records are not required to be met. This criteria will be established by the Company as needed to support management expectations and quality requirements.
: d. In lieu of compliance with Regulatory Position C.4, the Company establishes audit topics and frequencies as described in Appendix "B" of this QATR.
* e. In lieu of compliance with Regulatory Position C.5, the Company has established appropriate equivalent requirements within this QATR. f. Regarding section 5.1 of ANSI N18.7-1976, the text "a summary document shall be compiled by each owner organization to identify the sources, to index such source documents to the requirements of this Standard and to provide a consolidated base for description of the program",
is being interpreted by the Company as an electronic
: database, i.e., the Document Control and Records Management System (DCRMS),
that contains all the source documents required to implement the QAP and enables electronic sorts and text searches that serves to provide the consolidated base for description of the program.
Revision 85 CODES, STANDARDS AND GUIDES APPENDIXC
: g. Regarding section 5.2.15 of ANSI N18.7-1976, third paragraph, the text "unusual incident" is interpreted to mean "reportable incident."
: 4. Regulatory Guide 1.52, "Design, Testing And Maintenance Criteria For Atmosphere Cleanup System Air Filtration And Absorption Units Of Light-Water-Cooled Nuclear Power Plants, " The Salem Station atmosphere cleanup systems, which fall within the scope of the Regulatory Guide, are as follows:
Primary Systems:
: 1. Containment Fan Cooler Units . Secondary Systems:
: 1. Control Room Emergency Filtration Unit 2. Auxiliary Building Exhaust Units
* 3. Fuel Handling Building Exhaust Units All of these systems conform to the intent of the regulatory guide in many respects.
The areas where the systems are at variance with the intent of the regulatory positions are stated in the SGS UFSAR. 5. Regulatory Guide 1.137, "Fuel Oil Systems for Standby Diesel Generators,"
October 1979. Diesel fuel oil sampling is subject to verification during routine monitoring and audits of the fuel oil program and procedures conducted by NOS personnel and to exceptions and clarifications listed in the SGS UFSAR. 6. Regulatory Guide 1.143, "Design Guidance For Radioactive Waste Management
: Systems, Structures, And Components Installed In Light -Water -Cooled Nuclear Power Plants."
Accordance with guidance provided in this Regulatory Guide, the Contaminated Floor and Equipment Drain Systems and small portions of the Liquid Waste Disposal System that are designated with Piping Schedule 53D (Piping Specification SPS53) have been reclassified to be Non-Nuclear (Quality Group D). The Salem Station design meets the intent of the Regulatory Guide. Augmented quality assurance requirements have been imposed to ensure that the quality level recommended in the Regulatory Guide is maintained.
: 7. Branch Technical Position APCSB 9.5-1, Appendix A, "Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1, 1976." The QA Program is applied to the Fire Protection Program to an extent consistent with the requirements of Section C of Appendix A to Branch Technical Position APCSB 9.5-1. 8. Applicable Section XI ASME Code Years and Addenda for the Salem In Service Testing (IST) and In Service Inspection (ISi) Programs:
: a. IST: OM Code -2001 with 2003 OMb Addenda b. ISi: 2004 Edition (Salem Unit 1 and Unit 2) c. Containment ISi: 2004 Edition (Both Unit 1 & Unit 2) Page 10 of 10 Revision 85 DEFINITIONS APPENDIX D 1 SCOPE 2 2.1 2.2 2.3 2.4 2.5 2.6 Page 1 of 20 This Appendix consists of definitions for words or phrases found in the QAP and provide a common basis for understanding those words or* phrases that may have a different meaning when used elsewhere.
All words and phrases are subject to review and revision, as circumstances require.
GLOSSARY OF TERMS Approval Approval as used herein means by signature or initialing and date by an authorized individual.
ASME Boiler and Pressure Vessel Code, Sections I, IV, VIII, & XI Refers to ASME Section I -Power Boilers, Section IV -Heating Boilers, Section VIII -Pressure
: Vessels, and Section XI -Rules for In-Service Inspection of Nuclear Power Plant Components.
ASME Boiler and Pressure Vessel Code, Section Ill, Division 1 and Division 2 for Concrete Containment Refers to ASME Section Ill, Division 1 and Division 2 for Concrete Containment; ASME Section Ill; ASME Code; ASME; or Code. Audit A planned and documented activity performed to determine by investigation, examination, or evaluation of objective evidence the adequacy of and compliance with established procedures, instructions,
: drawings, and other applicable documents, and the effectiveness of implementation.
An audit should not be confused with surveillance or inspection activities performed for the sole purpose of process control or product acceptance.
Audit Team Leader An individual who meets the certification requirements of Lead Auditor per NQA-1 (or equivalent),
and thus is qualified to plan, perform and direct an audit, report findings, and evaluate corrective actions.
An Audit Team Leader (ATL) is appointed to lead all audit activities.
Auditor An individual qualified and authorized to perform any portion of an audit through the examination of quality assurance practices and verification of whether requirements are being met, including Audit Team Leaders, technical specialists, and others such as training and management representatives who have no direct responsibility for the area they are to audit. Revision 85 DEFINITIONS APPENDIX D 2.7 Augmented Quality 2.8 2.9 2.10 2.11 2.12 2.13 Page 2 of 20 Quality considerations given to non-safety related items or services for which the station has made a regulatory or design basis commitment, or for plant availability
: reasons, special controls are required to be implemented to assure reliability.
Authorized Inspector An Authorized Inspector (Al) as used herein is meant to mean Authorized Nuclear Inspector (ANI). An ANI is an employee of an Authorized Inspection Agency (AIA) who has qualifications for and has been properly accredited for Division 1 or Division
: 2. Authorized Nuclear In-service Inspector An Authorized Nuclear In-service Inspector (ANll) is an employee of an AIA who has qualifications for and has been properly accredited for ASME Section XI. Balance of Plant Generating station items and equipment not designed, furnished or installed as a part of the Nuclear Steam Supply, System. Balance of Plant items include safety-related and ASME Code items, such as the containment as well as non safety-related and non-ASME Code items. Basic Component "Basic component",
when applied to nuclear power reactors means a plant structure, system, component or part thereof necessary to assure (1) the integrity of the reactor coolant pressure
: boundary, (2) the capability to shut down the reactor and maintain it in a safe shutdown condition, or (3) the capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to those referred to in 10CFR50.67.
Bid Package The total of drawings, specifications, codes, standards, quality and other requirements that describes the task on which a prospective contractor/supplier will bid. Calibration A method of assuring accuracy of gauges and instruments used for measuring and testing by comparing with recognized standards.
Revision 85 DEFINITIONS APPENDIX D 2.14 Certificate of Compliance/Conformance (CoC) 2.15 2.16 2.17 2.18 2.19 2.20 2.21 Page 3of20 A document signed or otherwise authenticated by an authorized individual certifying the degree to which items or services meet specified requirements, such as those in purchasing requisitions.
Certified Personnel Personnel who have passed a formal training program and a formal proficiency test for special processes such as welding, plating and nondestructive testing.
Certified Standards Standards
*of measurement whose accuracy can be traced to standards at the National Institute of Standards and Technology or established standards.
Certified Material Test Report A document attesting that material is in accordance with specified requirements including the actual results of all required chemical
: analyses, tests and examinations.
Change Order A formal award to a vendor or contractor covering revision(s) to the original Purchase Order or Change Order, involving but not limited to quantity, technical requirements, quality assurance requirements or scope of work. Characteristic Any property or attribute of an item, process or service that is distinct, describable and measurable, as conforming or nonconforming to specified quality requirements.
Quality characteristics are generally identified in specifications and drawings, which describe the item, process or service.
Code A recognized standard for using or processing materials, or for the skill involved in use or processing.
See ASME Boiler and Pressure Vessel Code, Section Ill or Section XI, whichever is applicable.
Cognizant Engineer The engineer assigned a specific task or area of responsibility in the design or testing of a component or system. Revision 85 DEFINITIONS APPENDIX D 2.22 Commercial Dedication 2.23 2.24 2.25 2.26 2.27 Page 4 of 20 CommerCial grade items that are intended for safety-related end use (performing a basic component function per 10CFR21) are required to be dedicated.
C_ommercial grade dedication is a process that identifies the item's critical characteristics that must be verified to provide reasonable assurance the item will perform its intended safety function.
* Commercial Grade Item An item that was not subject to design or specification requirements unique to nuclear facilities, and can be used in applications other than nuclear facilities, and was ordered from the manufacturer/supplier on the basis of specifications set forth in the manufacturer's published product description (for example, a catalog).
Component ASME Code items such as vessels, concrete containments, piping systems, pumps, valves, core support structures and storage tanks which will be combined with other components to form an assembly or installation of a nuclear power plant. Component Identification Number An identification number assigned (where appropriate) to an item for use throughout its lifetime.
Condition Adverse to Quality An all-inclusive term used in reference to any of the following;
: failures, malfunctions, deficiencies, defective items, and non-conformances.
Construction Activities at the building site necessary to erect, inspect and accept a power generating station and its associated installation.
It can also mean the performance of major rework or modification activities during the Operations Phase such as steam generator replacement, reactor vessel head replacement, or replacement of a safety-related analog control system with a digital system. This definition applies unless otherwise indicated:
Construction (ASME Section Ill Div.1) comprises all activities relating to materials, design fabrication, examination,
: testing, inspection and certification required in the manufacture and installation of items. Construction (ASME Section Ill Div. 2) includes all those operations required to build the component and its parts in accordance with the Design Drawings and Construction Specification, which have been prepared by the Designer (AE). Revision 85 DEFINITIONS APPENDIX D 2.28 Contract (including purchase order) 2.29 2.30 2.31 2.32 2.33 2.34 2.35 Page 5 of 20 A binding agreement between two or more persons or companies.
Contractor Any organization under contract for furnishing items or services.
It includes the terms vendor, supplier, subcontractor, fabricator and tier levels of these where appropriate.
A "Code" contractor is a contractor holding a valid ASME Section Ill Certificate of Authorization.
Corrective Action Measures taken to rectify conditions adverse to quality, and, where necessary, to preclude repetition.
Critical Characteristics Those important design, material, and performance characteristics of a commercial grade item that, once verified, will provide reasonable assurance that the item will perform its intended safety function.
Dedication An acceptance process undertaken to provide reasonable assurance that a Commercial Grade Item used as a basic component will perform its intended safety function and, in this respect, is deemed equivalent to an item designed and manufactured under a 10 CFR 50 Appendix B Quality Assurance Program.
Department When a responsibility is given to a department in this Manual it is meant that the department head has the responsibility.
Design Change Any change in design that may affect functional requirements, operating conditions, safety-,
regulatory-,
reliability-,
and ASME related requirements, performance objectives, plant reliability or design life and would require that affected documentation be changed.
Design Controls Methods for assuring that basic design requirements are formalized and translated into design documents with proper review to assure the scheduled release of a valid design. Revision 85 DEFINITIONS APPENDIX D 2.36 Design Criteria 2.37 2.38 2.39 2.40 2.41 2.42 Page 6 of 20 Statements of the form, function and interface requirements within well defined limitations.
Design Requirements Documents that set the functional requirements, operating conditions, safety requirements, performance objectives, design margins and design life. Included are any special requirements for size, weight, ruggedness, materials, fabrications or constructions,
: testing, maintenance, operating environments, safety margins and derating factors.
Design Review An analysis of design with respect to technical
: adequacy, interface
: control, inspectability, maintainability and conformance to applicable codes, standards, regulations and design criteria.
Design Specification A document that sets the functional requirements; design requirements; environmental conditions, including radiation; ASME Code classification; definition of the boundaries; and material requirements.
Sufficient detail shall be contained within the document to provide a complete basis for design.
* For Section Ill ASME Code, Division I: A document prepared by the owner or owner's designee, which provides a complete basis for construction in accordance with the ASME Code, Section Ill. Destructive Test A test to determine the properties of a material or the behavior of an item, which results in the destruction of the sample or item. Deviation A nonconformance.
Departure of a characteristic from specified requirements.
Documentation Any written or pictorial information describing,
: defining, specifying, reporting or certifying activities, requirements, procedures or results.
Revision 85 DEFINITIONS APPENDIX D 2.43 Dry Cask Storage System 2.44 2.45 2.46 2.47 2.48 2.49 Page 7 of 20 A physical system, either a cask or canister in its shielding
: overpack, which holds the spent fuel from a nuclear reactor and is considered a component of the ISFSI. The system is licensed by the NRC and is operated and maintained in accordance with the NRC issued Certificate of Conformance and approved Final Safety Analysis Report (FSAR). Examination Specific actions by qualified personnel using qualified procedures to verify that items and fabrication processes are in conformance with specified requirements.
This term, when used in conjunction with qualification of personnel to perform quality-related activities shall mean a written examination.
Fabricator An organization involved in the manufacture of equipment.
For ASME Section Ill Division 2, the fabricator is an NPT Certificate Holder. Final Safety Analysis Report (FSAR) A finalization of the preliminary safety analysis report prepared for the Nuclear Regulatory Commission prior to issuance of an operating license.
Flow Chart A representation of the sequence of activities such as procurement, fabrication, processing,
: assembly, inspection and test, or the sequence of individual operations within one or more of those functions.
Hold Point A designated stopping place during or following a specific activity at which inspection or examination is required (usually to verify an important quality function such as foreign material exclusion) before further work can be performed.
Hold points can be performed by either job supervisors or independent inspectors as identified in associated procedures or work instructions
.. Inspection Hold Point (IHP) These are similar in nature to a hold point. IHPs should be performed by individuals who have remained independent of the activity being inspected.
Typically independent quality verification inspectors perform IHPs as prescribed in associated procedures or work instructions.
Revision 85 DEFINITIONS APPENDIX D 2.50 Important To Safety 2.51 2.52 2.53 2.54 Page 8of20 An activity important to safety is that which is: -Quality related, or is -A function involving administrative
: controls, such as policies, procedures, and organizational structure, established to assure nuclear safety, or is -Necessary to establish a work environment that provides the ability for personnel to complete safety-related tasks in a planned and systematic
: fashion, such as training, housekeeping, radwaste
: shipping, maintaining measuring and test equipment, etc. Equipment important to safety is that which is: -Safety-related, or is Non-safety-related, but whose failure could prevent satisfactory accomplishment of the safety functions specified for safety-related components, or is Used for post-accident monitoring of key variables and systems, or is Used for radwaste shipping or spent fuel storage.
Incident Occurrence of major damage, serious personal injury or significant schedule delay. Independent Review Review completed by personnel not having direct responsibility for the work functions under review regardless of whether they operate as a part of an organizational unit or as individual staff members.
Independent Safety Review An independent review performed with a deliberately critical examination of processes, events, or documents from the standpoint of nuclear safety. Independent Spent Fuel Storage Installation A facility designed and constructed for the interim storage of spent nuclear fuel and other radioactive materials associated with spent fuel (1 OCFR72.3).
Independent Spent Fuel Storage Installation (ISFSI) refers to the facility authorized for storage of spent fuel under 1 OCFR72 and includes the storage pad, the storage containers, and any support facilities.
: However, if the ISFSI is located on a reactor site it does not include any structures, facilities, or services that are part of the 1 OCFR50 license, unless they are identified as being shared jointly.
An ISFSI may contain several different Dry Cask Storage System designs.
Revision 85 DEFINITIONS APPENDIX D 2.55 In-Service Inspection 2.56 2.57 2.58 2.59 2.60 Page 9of20 A mandatory program of examinations,
: testing, inspections and control of repairs and replacements to ensure adequate safety in maintaining the nuclear power plant and to return the plant to service in a safe and expeditious manner. Inspection A phase of quality verification that, by means of examination, observation or measurement, determines the conformance of materials,
: supplies, components, parts, appurtenances,
: systems, processes or structures to predetermined quality requirements.
Interface When two or more organizations have responsibilities for accomplishing an activity, the functional relationship that one organization has to the others in completing the activity is called "interface" relation.
One example of.interface is when on organization must perform a step, which is a prerequisite to another organization accomplishing its function.
Interface can also mean that several organizations accomplishing similar activities are under the coordination control of one organization.
Interface control Consideration that components and structures are geometrically and functionally compatible and those materials are compatible with both process and environment.
Item Any level of unit assembly, including structure, system, subsystem, subassembly, component, part or material.
When ASME Code items are referenced, this means products constructed under a certificate of authorization and material.
Jurisdictional Boundaries The physical limits of an ASME Code item, which are identified to determine the applicability of ASME Code rules for that item. Revision 85 DEFINITIONS APPENDIX D 2.61 Lifetime Record 2.62 2.63 2.64 Page 10of20 A record that meets one or more of the following criteria:
-Those that would be of significant value in demonstrating capability for safe operation;
-Those that would be of significant value in maintaining, reworking, repairing, replacing, or modifying an item; -Those that would be of significant value in understanding the cause of an accident or malfunction of an item; -Those that provide required baseline data for in-service inspections.
Line Department An organization connotation for a group of individuals who perform a "line function",
meaning one that directly advances an organization in its core work.
For nuclear generation, this always includes groups like Operations, Maintenance,.
and Chemistry.
A "staff function" assists the overall organization with specialized advisory and support functions.
For example, Human Resources,
: Finance, and Licensing are generally considered to be staff functions. -A First Line Supervisor correlates to the management position that is directly in charge of the work force within a line department. -A Second Line Super.visor correlates to the management position that is responsible to oversee the performance of a First Line Supervisor within the line department.
Maintenance/Modification Work Package The complete set of documentation that enables the station to fabricate,
: examine, test and install ASME and safety related items. The work package consists of the work request, provisions for station traveler, document checklist and maintenance/modification procedures and supporting information such as, but not limited to, approved
: drawings, design specifications, and special process procedures.
Material A substance or combination of substances forming components, parts, pieces,.
and equipment.
(Intended to include such things as machinery,
: castings, liquids, formed steel shapes, aggregates, and cement.)
When ASME Code material is referenced, this refers to metallic materials manufactured to a SA, SB, or SFA Specification or any other material specification permitted by Section Ill of the ASME Code. For Division 2, this refers to metallic as well as to nonmetallic materials, conforming to the specifications permitted in Section Ill of the ASME Code. Revision 85 DEFINITIONS APPENDIX D 2.65 Material Supplier 2.66 2.67 2.68 An organization which supplies material produced and certified by Material Manufacturers, but does not perform any operations that affect the material except when agreed upon by the Certificate Holder who uses the material in ASME Code construction or when so authorized by a Quality System Certificate (Materials).
The Material Supplier may perform and certify the results of tests, examinations,
: repairs, or treatments required by the material specification that were not performed by the Material Manufacturer.
Measuring and Test Equipment (M& TE) Equipment used to quantitatively generate or measure physical or electrical parameters with a known degree of accuracy for the purpose of calibration, inspection, test, or repair of plant mechanical, electrical, or instrument control equipment.
Modification A change.to an item made necessary by, or resulting in, a change in design requirements.
A planned change in plant design or operation and accomplished in accordance with the requirements and limitation of applicable codes, standards, specifications, licenses and predetermined safety restrictions.
National Standards Standards maintained at or issued by the National Institute of Standards and Technology (NIST) or other designated institutions, and the values for natural physical constants and conversion factors recommended by NIST. 2.69 NOE Administrator Chief Level Ill (NOE) for the Company.
2.70 Non-compliance A failure to comply with a regulatory requirement.
Page 11 of 20 Revision 85 DEFINITIONS APPENDIX D 2.71 Nonconformance 2.72 2.73 2.74 2.75 Page 12of20 A nonconformance is a deficiency in characteristic, documentation, or procedure that renders the quality of a structure, system, or component (SSC) or activity unacceptable or indeterminate.
Some examples of nonconforming conditions include the following:
* As-built equipment, or as-modified equipment, does not meet UFSAR descriptions or design bases.
* Deviation from prescribed processing, inspection, or test procedures.
* Physical defects.
* Requirements cannot be substantiated with proper documentation.
* Test failures.
* There is failure to conform*
to one or more applicable codes or standards specified in the UFSAR or procurement documents.
Non-permanent Record A record that is required to show evidence that an activity was performed in accordance with the applicable requirements, but does not meet the criteria for a lifetime record. NQA-1-1994 (ANSl/ASME NQA-1-1994)
Quality Assurance Program Requirements for Nuclear Facilities.
For ASME Section Ill activities, NQA-1 is as modified by the ASME Code. Nuclear Safety Assurance that the health and safety of individuals,
: society, and the environment are protected against radioactivity originating from the nuclear fuel or special nuclear material.
Nuclear Steam Supply System (NSSS} That portion of the nuclear generating plant that provides steam from nuclear heat. It includes the reactor, its control systems, main coolant and steam generation
: systems, fuel handling equipment, emergency core cooling system and other safeguards, associated electrical equipment, instrumentation, spent fuel handling and radioactive waste disposal system. Revision 85 DEFINITIONS APPENDIX D 2. 76 Objective Evidence 2.77 2.78 2.79 2.80 Page 13of20 Any documented statement of fact, other information or record, either quantitative or qualitative, pertaining to the quality of an item or activity, based on direct observations, measurements or. tests that can be verified.
Off-site Review Off-site review is the review and investigative function required by plant technical specifications and/or safety analysis reports.
Off-site review requirements are satisfied by an off-site review committee.
On-site Review On-site review is the review and investigative function required by plant technical specifications and/or safety analysis reports.
On-site review requirements are satisfied by a technical review program and/or by an on-site review committee, Which may be named differently at each operating plant. Operable/Operability A system, subsystem, train, component or device shall be operable or have operability when it is capable of performing its specified function(s) and when all necessary attendant instrumentation,
: controls, electrical power, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component or device to perform its function(s) are also capable of performing their related support function(s).
NOTE: Licensed operators determine safe operation of the plant. Operational Tests Tests that are performed during the operations of the plant to verify continued satisfactory performance of safety-related structures, systems and components.
Revision 85 DEFINITIONS
, APPENDIX D 2.81 Personnel Access Data System (PADS) 2.82 2.83 2.84 2.85 2.86 Page 14of20 A computerized and restricted access data system used by the domestic commercial nuclear power industry to share information to process the applications of workers for unescorted access to nuclear power plants. This system is intended to meet regulatory requirements mandating that certain information be available to any power reactor licensee by retaining certain access information in a central computer database.
Permanently Installed Instrument and Control Devices The installed plant equipment ineluding computer points used in determining acceptance criteria of Technical Specification surveillances.
Preliminary Safety Analysis Report (PSAR) The initial detailed safety evaluation prepared for the U.S. Nuclear Regulatory Commission prior to issuance of the site construction permit. The PSAR delineates design, normal and emergency operation, potential accidents and predicted consequences of such accidents and the means proposed to prevent such accidents and/or reduce their consequences to acceptable levels. Pre-Operational Testing Preliminary testing prior to fuel loading and plant operation to assure that construction and installation are complete and to verify design and system functions.
Procedure A controlled document that specifies or describes how an activity is to be performed.
It may include methods to be employed, equipment or materials to be used, accept/reject criteria and sequence of operations.
Proprietary Designs Designs engineered, produced and sold by manufacturers in accordance with their criteria and warranty.
Revision 85 DEFINITIONS APPENDIX D 2.87 Purchase Requisition 2.88 2.89 2.90 2.91 2.92 2.93 Page 15 of 20 The basic document describing a material, component or service that is converted into a purchase order for procurements.
Quality Assurance All those planned and systematic actions necessary to.provide adequate confidence that an item or a facility will perform satisfactorily in service.
For the ASME Code, Quality Assurance comprises all those planned and systematic actions necessary to provide adequate confidence that all items designed and constructed are in accordance with the applicable ASME Code. Quality Assurance Program (QAP) The Quality Assurance Program is the method for complying with the provisions of 1 OCFR50 Appendix B for nuclear power plant systems, structures, and components that prevent or mitigate the consequences of postulated accidents that could cause undue risk to the health and safety of the public. The Quality Assurance Program is defined in the Quality Assurance Topical Report and implementing procedures.
Quality Assurance Topical Report (QATR) A NRC approved regulatory document that describes quality assurance program elements for the operational phase of nuclear power plants. This term is synonymous with Quality Assurance Program Description (QAPD), Operation Quality Assurance Program (OQAP), and Quality Assurance Manual (QAM). Quality Control See Quality Verification.
Quality-Related Activities which influence quality of safety-related items or work related to those systems, structures and components as identified in the station UFSAR, Section 3.2, including
: training, designing, purchasing, fabricating,
: handling, shipping,
: storing, cleaning, preserving,
: erecting, installing, inspecting,
: testing, operating, maintaining, repairing, refueling, or modifying.
Quality Verification Those quality assurance examinations and actions that provide a means to control and measure the characteristics of an item, process or facility to determine or establish conformance to acceptance standards and specified requirements.
Revision 85 DEFINITIONS APPENDIX D 2.94 Receipt Inspection 2.95 2.96 2.97 2.98 2.99 Page 16of20 An inspection which verifies that items are in satisfactory condition, that they match the purchase order requirements and that required documentation accurately reflects the item(s) received.
Visual and physical inspection will be performed as necessary to determine the acceptability of the item(s).
Record A completed document that:
* Furnishes evidence of the quality of items or activities.
* Furnishes evidence of compliance with regulations or requirements.
* Is required by Technical Specifications.
Included are such related documents as drawings, specifications, procurement documents, procedures, operating logs, and reportable occurrences.
Such documents may be originals or reproduced copies. Registered Professional Engineer (RPE) A person competent in the applicable field of design and qualified in accordance with the requirements of ASME Section Ill, Appendix XXlll. Repair The process of restoring a nonconforming characteristic to a condition such that the capability of an item to function reliably and safely is unimpaired, even though that item still may not conform to the original requirements.
For ASME Section Ill items, repair is the process of physically restoring a nonconformance to a condition such that an item complies with ASME Code requirements.
Request For Bid Invitation made to suppliers or contractors to bid on a specific task for materials, goods and services.
Request For Purchase A generating station's document originated by foremen, supervisors or department heads that designates the required items and services and delineates the design specifications, applicable codes and standards, as well as, any special requirements.
This document is the basis of initiating a Purchase Requisition.
Revision 85 DEFINITIONS APPENDIX D 2.100 Rework 2.101 2.102 2.103 2.104 2.105 Page 17of20 The process by which a nonconforming item is made to conform to a prior specified requirement by completion, re-machining, and assembling using previously approved procedural requirements.
(For ASME Section Ill, rework is same as repair.)
Safety-Related Structures,
: systems, components (SSC's),
procedures and controls that are relied upon to remain functional during and following design basis events to ensure the integrity of the reactor coolant pressure boundary; the capability to shut down the reactor and maintain it in a safe shutdown condition; or the capability to prevent or mitigate the consequences of accidents that could result in potential offsite exposures to members of the public. Seismic Classification Plant structures, systems and components important to safety which are designed to withstand the effects of a safe shutdown earthquake and remain functional if they are necessary to assure: The integrity of the reactor coolant pressure
: boundary, or The capability to shutdown the reactor and maintain it in a safe condition, or The capability to prevent or mitigate the consequences of accidents, which could result in potential offsite exposures comparable to the guideline exposures of 10CFR100.
Significant Condition Adverse to Quality (SCAQ) A significant condition adverse to quality is one which, if uncorrected, could have a serious effect on safety or operability.
Source Inspection Inspection carried out at a vendor's plant prior to shipment of purchased items. Special Process A process, the results of which are highly dependent on the control of the process or skill of the operator, or both, and in which the specified quality cannot be readily determined by inspection or test of the product.
* Revision 85 DEFINITIONS APPENDIX D 2.106 Specification 2.107 2.108 A concise set of requirements to be satisfied by a product, material or process.
The set of requirements may, also, indicate the procedure by which one may determine if the given requirements are satisfied.
Stand-alone Document Is where information is assembled that is capable of fully describing an activity/issue/topic independent of other documentation.
Supporting facts should be included or their location clearly referenced.
Authentication of the document by affixing a seal, signature, initial or other acceptable method of proof of its validity, is required for it to be a completed quality record. Start-Up Tests Tests that are performed after initial fuel loading and proceed through several power level plateaus to 100% power. 2.109 Stock Material 2.110 2.111 Material which is or may be used for conversion to an ASME SA, SB, or SFA Specification or allowable ASTM Specification.
As used in this Program, Stock Material is that material that has not been produced in accordance with an NCA 3800 QA Program.
Stop Work Collective term used to describe the following three levels of stopping work activities:
*
* A hold imposed by a Department Head on a department or general work activity.
* A Stop Work Action initiated by NOS management.
* The stopping of a single or specific work activity by NOS personnel.
Surveillance The act of monitoring or observing to verify whether an item or activity conforms to specified requirements.
Such as an examination of supplier's manufacturing, inspection and test operations and of records of work in progress.
This activity is documented.
2.112 Survey Page 18of20 A documented evaluation of an organization's ability to perform activities as verified by a determination of the adequacy of the organization's quality program and by a review of the implementation Revision 85 of that program at the location of work. DEFINITIONS APPENDIX D 2.113 Technical Review (non-conforming item) 2.114 2.115 2.116 2.117 2.118 2.119 Page 19of20 A determination as to whether a nonconforming item will be accepted "as-is",
: reworked, repaired to acceptable condition or rejected.
Technical Specification The design and performance criteria and operating limits and principles of an operating license to be observed during initial fuel loading, critical
: testing, start-up, power operations, refueling and maintenance operations.
Test Determination of the physical and functional properties of an item by subjecting the item to a set of physical,
: chemical, environmental or operating conditions.
Test Plan An outline, narrative description or flow diagram indicating the tests to be performed, the methods to be used and the points in the process where they are to be executed.
It may be in the form of a test procedure.
Traceability The ability to trace the history, application, or location of an item or like items or activities by means of recorded identification.
UFSAR Abbreviation for the Updated Final Safety Analysis Report, which is the document submitted by the Company to the Nuclear Regulatory Commission in accordance with 1OCFR50.71.
Use-As-ls A disposition which may be imposed for a nonconformance when it can be established that the discrepancy will result in no adverse conditions to safety and that the item under consideration will continue to meet all engineering functional requirements including performance, maintainability, fit and safety. Revision 85 DEFINITIONS APPENDIX D 2.120 Variation 2.121 2.122 2.123 Page 20of20 A nonconformance.
Departure of a characteristic from specified requirements.
Verification The act of reviewing, inspecting,
: testing, checking,
: auditing, or otherwise determining and documenting whether items, processes,
: services, or documents
.conform to specified requirements.
Two commonly used types of verification are described as follows:
Concurrent Verification is also known as "apart-in-action" because the verification is being done concurrently as the action is implemented.
Concurrent Verification is accomplished when two individuals verify the actions concurrently and apart from each other as they perform the task. Concurrent verification should be used for any action that if performed incorrectly, could result in an immediate threat to personnel safety, nuclear safety, reliable plant operation, or for an activity that can't be verified after it's completed.
Independent Verification is also known as "apart-in;..time" because the verification occurs at some time after the action has been performed.
An independent verification is performed at a later time by a* second qualified individual who is not part of the initial job performance checking the actions previously performed by others. Independent verification may be used in cases were actions if done incorrectly, could significantly affect nuclear and personnel safety, regulatory or . other issues important to safe and reliable plant operations, but would not result in immediate consequences.
Witness Points In a sequential operation, a notification to the Company, or its authorized agent, that a phase of work is about to be reached, so that it may be witnessed at a specific time, or in process, to verify acceptable performance of the phase. Witness points may be established in the traveler, procedure or in the course of monitoring the work activity.
Work Instructions Actions to be completed by personnel while they are performing specific tasks in areas such as material controls and identification and fabrication, installation, or maintenance of equipment.
Revision 85 SUPPLEMENT AL APPLICATIONS (STATION SPECIFIC)
APPENDIXE 1 2 2.1 2.1.1 Page 1 of 4 SCOPE 1 OCFR50 Appendix B requires a quality assurance program be established in writing and executed for activities affecting the related function of designated structures, systems and components to an extent consistent with their importance to safety. REQUIREMENTS Hope Creek Generating Station (HCGS) Items cm the HCGS Q-List, and the DCSS / ISFSI Category A, B, and C SSCs, are subject to the applicable controls of this QAP. HCGS Q-List a. Activities and Services:
: 1. Safety-related activities delineated in Regulatory Guide 1.33, Appendix A (see Regulatory Guide for further breakdown of activities).
Procedures that govern important to safety activities have a "Q" suffix added to the end of the procedure number and/or have a "Q" quality code in the document control and records management system. Procedures associated with 2.1.3 and 2.1.4 activities should use an "F" or "R" quality code respectively.
: 2. Other safety-related activities, such as design control, procurement, and audits, which satisfy the requirements of the operational QAP as described in this manual. 3. Modifications to Site Grading.
: b. Structures,
: Systems, and Components:
: 1. Seismic Category I and other struCtures,
: systems, and components as indicated to have QA requirements in Table 3.2-1 of the HCGS UFSAR. 2. Seismic II/I designation (meaning those portions of SSCs whose continued function is not required but whose failure could reduce the functioning of any Seismic Category I plant feature to an unacceptable safety level) is incorporated on the following design document types: Drawings Area drawings
-
unit masonry*
details Control room-ceiling layouts Floor plans Heating & ventilation duct layout Miscellaneous steel drawings Piping and Instrumentation Diagrams (P&ID's)
System isometrics Revision 85 SUPPLEMENTAL APPLICATIONS (STATION SPECIFIC)
APPENDIXE 2.1.2 2.1.3 Page 2 of 4 Indices -Equipment index -Pipe line index Specifications Acoustical unit ceilings
-Insulation for reactor pressure vessel (RPV) and drywell piping equipment The Seismic II/I identification on drawings and indices is provided in the detail of the document, as necessary, to define "Q" items/boundaries.
A "Q" suffix is added to the drawing number of those drawings that identify application of the Seismic II/I QA program.
The Seismic II/I identification on specifications consists of adding a "Q" suffix to the specification number. Seismic II/I structures,
: systems, and components are further delineated in UFSAR Table 3.2-1. "F" -Designated Systems a. An "F" designation is incorporated on the following design document types: .1. Drawings
-P&ID's for the Fire Protection System (FPS) -Concrete unitmasonry details -Door hardware schedules
-Fire wall location drawings
-FPS isometrics
-FPS safety-related area drawings
-Lighting and telephone plans -Lighting notes, symbols, and details -Penetration seal details -Structural steel fireproofing drawings
: 2. Indices -Equipment index Instrument index -Pipe line index Valve index b. FPS-QA identification system incorporation on drawings and indices is provided in the detail of the document, as necessary, to define "F" items/boundaries.
An "F" suffix is added to the drawing number of those drawings that identify application of the FPS-QA program.
Specifications are as follows:
-Carbon dioxide systems -Deluge water spray and sprinkler system Revision 85 SUPPLEMENTAL APPLICATIONS (STATION SPECIFIC)
APPENDIX E 2.1.4 2.1.5 Page 3of4 -Fire and smoke.detection system -Fireproofing of structural steel -Horizontal fire pumps -Hose racks for wet standpipe system -Installation of carbon dioxide system -Portable extinguishers
: c. FPS-QA identification system incorporation onto specifications consists of adding an "F" suffix to the specification number. d. Fire Protection
: Systems, including emergency lighting and communications, are further delineated in UFSAR Table 3.2-1. "R" -Designated Systems a. The letter "R" shall be used to identify items of the Radioactive Waste Management System which protect the health and safety of the public, and plant operating personnel from uncontrolled discharge of solid, liquid, or gaseous radioactive waste to the environment.
: b. The radwaste management systems classified as quality group R shall be designated by the use of R-flags on piping and instrumentation diagrams.
Quality group R standards shall be those provided in Regulafory Guide 1.143. Radwaste Management Systems are further deline.ated in UFSAR Table 3.2-1. Quality Classifications for SSCs of the Independent Spent Fuel Storage Installation
: a. The following documents list the "important to safety" (i.e., Quality Category A, B or C) and "not important to safety" quality classifications of the Dry Cask Storage System (DCSS) and Independent Spent fuel Storage Installation (ISFSI) structures,
: systems, and components (SSCs). 1. DCSS Final Safety Analysis Report (Certificate Holder's):
-Table 2.2.6 of HI-STORM 100 FSAR (Docket 72-0048)
-Table 8.1.6 of HI-STORM 100 FSAR (Docket 72-0048)
: 2. PSEG Nuclear, Independent Spent Fuel Storage Installation 10 CFR 72.212 Evaluation Report Revision 85 SUPPLEMENTAL APPLICATIONS (STATION SPECIFIC)
APPENDIX E 2.2 2.2.1 2.2.2 Page 4 of 4 Salem Generating Station (SGS) Items on the SGS 0-List, and the DCSS / ISFSI Category A, B, and C SSCs, are subject to the applicable controls of this QAP. SGS Q-List a. The listing below identifies those activities and services to which the OAP applies during operations:
: 1. Safety-related activities delineated in Regulatory Guide 1.33, Appendix A (see Regulatory Guide for further breakdown of activities).
Procedures that govern important to safety activities have a "O" suffix added to the end of the procedure number and/or have a "O" quality code in the document control and records management system. 2. Modifications to the shoreline dike identified in Section 3.4 of the SGS UFSAR. 3. Other safety-related activities, such as design control, procurement, and audits, which satisfy the requirements of the operational OAP as described in this manual. b. Structures,
: Systems, and Components
: 1. Items and systems contained in commitment letters to the NRC are administered through station procedures and tracked using an electronic database.
: 2. The Class I structures,
: systems, and components identified in Section 3.2 of the SGS UFSAR. 3. The OAP controls apply to the Class II structures,
: systems, and components identified in Section 3.2.1 of the SGS UFSAR as described in engineering design bases documents and associated procedures.
Quality Classifications for SSCs of the Independent Spent Fuel Storage Installation
: a. The following documents list the "important to safety" (i.e., Quality Category A, B or C) and "not important to safety" quality classifications of the Dry Cask Storage System (DCSS) and Independent Spent Fuel Storage Installation (ISFSI) structures,
: systems, and components (SSCs). 1. DCSS Final Safety Analysis Report (Certificate Holder's):
-Table 2.2.6 of HI-STORM 100 FSAR (Docket 72-0048)
-Table 8.1.6 of HI-STORM 100 FSAR (Docket 72-0048)
: 2. PSEG Nuclear, Independent Spent Fuel Storage Installation 10 CFR 72.212 Evaluation Report Revision 85 LR-N 17-0034 Enclosure 3 PSEG Nuclear, LLC Salem Nuclear Generating Station Unit 1 & Unit 2 Technical Specification Bases As of January 30, 2017 2.1 SAFETY LIMITS 2.1.l REACTOR CORE The restrictions of this safety limit prevent overheating of the fuel and possible cladding perforation which would result in the release of fission products to the reactor coolant.
Overheating of the fuel cladding is prevented by restricting fuel operation to within the nucleate boiling regime where the heat transfer coefficient is large and the cladding surface temperature is slightly above the coolant saturation temperature.
Operation above the upper boundary of the nucleate boiling regime could result in excessive cladding temperatures because of the onset of departure from nucleate boiling (DNB) and the resultant sharp reduction in heat transfer coefficient.
DNB is not a directly measurable parameter during operation and therefore THERMAL POWER and Reactor Coolant Temperature and Pressure have been related to DNB through correlations which have been I developed to predict the DNB flux and the location of DNB for axially uniform and non-uniform heat flux distributions.
The local DNB heat flux ratio, DNBR, defined as the ratio of the heat flux that would cause DNB at a particular core location to the local heat flux, is indicative of the margin to ONB. The DNB design basis is as follows:
uncertainties in the WRB-1 and WRB-2 correlations,*
plant operating parameters, nuclear and thermal parameters, fuel fabrication parameters, and computer codes are considered statistically such that there is at least a 95 percent probability with 95 percent confidence level that DNBR will not occur on the most limiting fuel rod during Condition I or II events. This establishes a design DNBR value which must be met in plant safety analyses using values of input parameters without uncertainties.
The curves of Figure 2.1-1 shows the loci of points of THERMAL eoWER, I Reactor Coolant System pressure and average temperature for which the minimum DNBR is no less than the design DNBR value, or the average enthalpy at the vessel exit is equal to the enthalpy of saturated liquid. SALEM -UNIT 1 B 2-1 Amendment No. 201 SAFETY LIMITS BASES The curves are based on an enthalpy hot channel factor, F11T"6Hr and a I reference cosine with a peak of 1.55 for axial power shape. An allowance is included for an increase in at reduced power based on the expression:
where: F11TP6H is the limit at RATED THERMAL FOWER (RTP) specified in the Core Operating Limits Report (COLR). FFaH is the Power Factor Multiplier for s.pecified in the COLR, and P is THERMAL POWER RATED THERMAL POWER These limiting heat flux conditions are higher than those calculated for the range of all control rod positions from rods FULLY WITHDRAWN to the I maximum allowable control rod insertion assuming the axial imbalance is within the limits of the fi(AI) function of the Overtemperature trip. When the axial power imbalance is not within the tolerance, the axial power imbalance effect on the Overtemperature AT trips will reduce the setpoints to provide protection with core safety limits. 2.1.2 REACTOR COOLANT SYSTEM PRESSURE The restriction of this Safety Limit protects the integrity of the Reactor Coolant System from overpressurization and thereby prevents the release of radionuclides contained in the reactor coolant from reaching the containment atmosphere.
The reactor pressure vessel and pressurizer are designed to Section III of the ASME Code for Nuclear Power Plant which permits a maximum transient pressure of 110% (2735 psiq) of desiqn pressure.
The Reactor Coolant System pipinq and fittings are designed to ANSI B 31.1 1955 Edition while the valves are designed to ANSI B 16.5, MSS-SP-66-1964, or .ASME Section III-1968, which permit maximum transient pressures of up to 120% (2985 psiq) of component design pressure.
The Safety Limit of 2735 psig is therefore consistent with the design criteria and associated code requirements.
The entire Reactor Coolant System is hydrotested at 3107 psig, 125% of design to del'l\Onstrate integrity prior to initial operation.
Salem -Unit l B 2-2 Amendment No. 201 2.: LIMITING SAFETY SYSTEM SETTINGS 2.2.l REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS The Trip Setpoints are the nominal values at which the bistables are set. Any bistable is considered to be properly adjusted when the "as-left."
value i.s within the band for CHANNEL CALIBRATION accuracy (i.e., +/-rack calibration+
comparator setting accuracy).
The Trip Setpoints used in the bistables are based on the analytical limits stated in the UFSAR. The selection of these Trip Setpoints is such that adequate protection is provided when all sensor and processing time delays are taken into account.
To allow for calibration tolerances, instrumentation uncertainties, instrument drift, and severe environment errors for those Reactor Protection system (RPS) channels that must function in harsh environments as defined by 10 CFR 50.49, the Trip Setpoints and Allowable Values specified in the Technical Specification Limiting Conditions for Operation (LCO's) are conservatively adjusted with respect to the analytical limits. The methodology used to calculate the Trip Setpoints is consistent with Instrument Society of America standard ISA-567.04-1982, which is endorsed via NRC Regulatory Guide 1.105, Rev. 2. The actual nominal Trip Setpoint entered into the bistable is more conservative than that specified by the Allowable Value to account for changes in random measurement errors detectable by a CHANNEL FUNCTIONAL TEST. one example of such a change in measurement error is drift during the surveillance interval.
If the measured setpoint does not exceed the Allowable Value, the bistable is considered OPERABLE.
Setpoints in accordance with the Allowable Value ensure that the safety analyses which demonstrate that safety limits are not violated remain valid (provided the unit is operated within the LCO's at the onset of any design basis event and the equipment functions as designed)
. The Trip Setpoints and Allowable Values listed in the LCO's incorporate all of the known uncertainties applicable for each channel.
The magnitudes of these uncertainties are factored into the determination of each Trip Setpoint.
All field sensors and signal processing equipment for these channels are assumed to operate within the allowances of these uncert'ainty magnitudes.
Manual Reactor Trip The Manual Reactor Trip is a redundant channel to the automatic protective instrumentation channels and provides manual reactor trip capability.
Power Range. Neutron Flux The Power Range, Neutron Flux channel high setpoint provides reactor core protection against reactivity excursions which are too rapid to be protected by temperature and pressure protective circuitry.
The low set point provides redundant protection in the power range for a power excursion beginning from low power. The trip associated with the low setpoint may be manually bypassed when P-10 is active (two of the four power range channels indicate a power level of above approximately 9 percent of RATED THERMAL POWER) and is SALEM -UNIT l B 2-3 Amendment No. 159 LIMITING SAFETY SYSTEM SETTINGS BASES automatically reinstated when P-10 becomes inactive (three of the four channels indicate a power level below approximately 9 percent of RATED THERMAL POWER) . Power Range, Neutron Flux, High Rate The Power Range Positive Rate trip provides protection against rapid flux increases which are characteristic of rod ejection events from any power level.
this trip complements the Power Range Neutron Flux High and Low trips to ensure that the criteria are met for rod ejection from partial power. Intermediate and Source Range, Nuclear Flux The Intermediate and Source Range, Nuclear Flux trips provide reactor core protection during reactor startup.
These trips provide redundant protection to the low setpoint trip of the Power Range, Neutron Flux channels.
The Source Range Channels will initiate a reactor trip at about 10+5 counts per second unless manually blocked when P-6 becomes active. The Intermediate Range Channels will initiate a reactor trip.at a current level proportional to approximately 25 percent of RATED THERMAL POWER unless manually blocked when P-10 becomes active. No credit was taken for operation of the trips associated with either the Intermediate or Source Range Channels in the accident analyses;
: however, their functional capability at the .specified trip settings is required by this specification to enhance the overall reliability of the Reactor Protection System. Overternperature
/!,. T The Overtemperature
/!,. T trip provides core protection to prevent DNB for all combinations of pressure, power, coolant temperature, and axial power distribution, provided that the transient is slow with respect to piping transit delays from the core to the temperature detectors (about 4 seconds),
and pressure is within the range between the High and Low Pressure reactor trips. This setpoint includes corrections for changes in density and heat capacity of water with temperature and dynamic compensation for piping delays from the core to the loop temperature detectors.
With normal axial power distribution, this reactor trip limit is always below the core safety limit as shown in Figure If axial peaks are greater than design, as indicated by the difference between top and bottom power range nuclear detectors, the reactor trip is automatically reduced according to the notations in Table 2.2-1. SALEM -UNIT 1 B 2-4 Amendment No. 278 (PSEG Issued)
LIMITING SAFETY SYSTEM SETTINGS Operation with a reactor coolant loop out of service below the 4 loop P-8 set point does not require reactor protection system set point modification because the P-a set point and associated.trip will prevent DNB during 3 loop operation exclusive of the overtemperature
!T set point. Three loop operation above the 4 loop P-8 set point has not been evaluated and is not permitted.
Overpower
!T The Overpower
!T reactor trip provides assurance of fuel integrity, e.g., no melting, under all possible overpower conditions, limits the required range for overtemperature
!T protection, and provides a backup to the High Neutron Flux trip. The setpoint includes corrections for changes in density and heat capacity
*of water with temperature, and dynamic compensation for piping delays from the core to the loop temperature detectors.
No credit was taken for operation of this trip in the accident analyses;
: however, its functional capability at the specified trip setting is required by this specification to enhance the overall reliability of the Reactor Protection System. Pressurizer The Pressuxizer High and Low Pressure trips are provided to limit the pressure range in which reactor operation is permitted.
The High Pressure trip is backed up by the pressurizer code safety valves for RCS overpressure protection, and is therefore set lower than the set pressure for these valves (2485 psig). The Low Pressure trip provides protection by tripping the reactor in the event of a loss of reactor coolant pressure.
Pressurizer Water Level The Pressurizer High Water Level trip ensures protection against Reactor Coolant system overpressurization by limiting the water level to a volume sufficient to retain a steam bubble and prevent water relief SALEM -UNIT l B 2-5 Amendment No. 201 I LIMITING SAFETY SYSTEM SETTINGS through the pressurizer safety valves. No credit was taken for operation of this trip in the accident analyses;
: however, its functional capability at .the specified trip setting is required by this specification to enhance the overall reliability of the Reactor Protection System. Loss of Flow The Loss of Flow trips provide core protection to prevent DNB in the event of a loss of one or more reactor coolant pumps. Above ll percent of RATED THERMAL POWER, an automatic reactor trip will occur if the flow in any two loops drop below 90t of nominal full loop flow. Above 36t (P-8) of RATED THERMAL POWER, automatic reactor trip *will occur if the flow in any single loop drops below 90t of nominal full loop flow. This latter trip will.prevent the minimum value of the DNBR from going below the design DNBR value during normal operational transients.
Steam Generator Water Level The Steam Generator Water Level Low-Low trip provides core protection by preventing operation with the steam generator water level below the minimum volume required for adequate heat removal capacity, The specified setpoint provides allowance that there will be sufficient water inventory in the steam generators at the time of trip to allow for starting delays of the auxiliary feedwater system. SALEM -UNIT 1 B 2*6 Amendment No. 201 LIMITING SAF!TY SYSTEM SETTINGS Undervoltage and Underfreguency
-Reactor coolant Pump Susses The Undervoltage and Underfrequency Reactor Coolant Pump bus trips provide reactor core protection against DNB as a result of loss of voltaqe or underfrequency to mere than one reactor coolant pump. The specified set points assure a reactor trip signal is generated before the low flow trip set point is reached.
Time delays are incorporated in the underfrequency and undervoltage trips to prevent spurious reactor trips from momentary electrical power transients.
For undervoltage, the delay is set so that the time required for a signal to reach the reactor trip breakers following the simultaneous trip of two or more reactor coolant pump bus circuit breakers shall not *exceed 0.9 seconds.
For underfrequency, the delay is set so that the time required for a signal to reach the reactor trip breakers after the underfrequency trip setpoint is reached shall not exceed 0.3 seconds.
Turbine Trip A Turbine Trip causes a direct reactor trip when operating above P-9. Each of the turbine trips provide turbine protection and reduce the severity of the ensuing transient.
No credit was taken in the accident analyses for operation of these trips. Their functional capability at the specified trip settings is required to enhance the overall reliability of the Reactor Protection System. a Z-'7 I* cdlrr nt Ho. 113 I LIMITING SAFETY SYSTEM SETTINGS BASES Safety Injection Input from ESF If a reactor trip has not already been generated by the reactor protective f nstn.unentat1on, the ESF automatic actuation logic channels wtll fn1tf ate a reactor trip upon any sfgnal which 1n1tiates a safety injection, This trip is provided to protect the core in the event of a LOCA. The ESF instrumentation channels whfch fnitf ate a safety injection signal are shown fn Table 3.3-3. Reactor Coolant Pump Breaker Position Trf e The reactor Coolant Pump Breaker Position Trip 1s an anticipatory tr1p which provides reactor core protection against De resulting from the opening of two or more pump breakers above P-7. This trip fs blocked below P-7. The open/close position trf p assures a reactor trfp signal is generated before the low flow trtp set point is reached.
No credit was taken fn the accident analyses for operation of thf s trtp. The functional capability at the open/close position settings ts required to enhance the overall relf ab111ty of the Reactor Protectfon System. SALEM -UNIT 1 B 2-8 Amendment No. 87 *s--.-
.. *. r 3/4.0
,BASES specification J.O.l through 3.0.4 establish the general requirements I applicable to Limitin9 Conditions for Operation.
These requirements are based I on the requirements for Limitin9 conditions for Operation stated in the Code I of Federal Re9ulations, 10 CFR 50.36(C)(2):
I I "Limiting conditions for operation are the lowest functional capability I or performance levels *of equipment.
required for safe operation of* the j facility.
When a limiting condition for operation of a nuclear reactor is not f met, the licensee shall shut down the reactor or follow any remedial action I permitted by tha technical specification until the condition can be met." I I Specification 3.0.1 establishes the Applicability statement within each I individual specification as the requirement for when (i.e., in which I OPERATIONAL MODES or other 1pecified conditions) conformance to the Limiting I Conditions for Operation is required for safe operation of the facility.
The I ACTION requirements establish those remedial measures that must be taken I
* within specified time limits when the requirements of A Limiting Condition for I Operation are not met. I I There are two basic types of ACTION requirements.
Th**first specifies the I remedial measures that permit continued operation of the facility which is not I further restricted by the time limits of the ACTION requirement*.
In this I case, conformance to the ACTION requirement*
provide*
an acceptable level of I safety for unlimited continued operation as long as the AC'l'ION requirements I continue to be met. The second type of ACTION requirement specifies a time I limit in which conformance to the conditiona of the Limiting Condition for I Operation must be met. Thia time limit is the allowable outage time to I restore an inoperablo sy1tem or component to OPERABLE statu* or for restorinq I parameters within specified limits. If these action* are not completed within I
* the allowable outage time limits, a shutdown i* required to place the facility I in a MOCE or condition in which the specification no lon9er applies.
It is \ not intended that th* ahutdcwn ACTION requirements be used as an I convenianca which permit* (routine) voluntary removal of a ay1tem(*)
or I component(s) from service in lieu of other alternatives that would not result I in redundant systems or components being inoperable.
,,-... j* I The specified time limit* of the ACTION requirements are applicable from the I point in time it ia identified that a Limiting Condition for Operation is not j met. Th* time limits of the ACTION requirement*
are also applicable when a I system er component is removed from service for surveillance testing or I inveati9ation ct operational problems.
Individual specifications may include \ a specified time limit for the completion of.a Surveillance Requirement when I equipment is removed from service.
In this case, the allowable outage time I limits of the ACTION rec;Uirements are applicable when thi1 limit expires if I the surveillance hat not bean completed.
When &*shutdown i* required to I comply with ACTION requirements, the plant may have entered a MODE in which a I new specification become* applicable.
In this case, the limit* of the I ACTION requirement*
would apply from th* point in time that the new I apeeification become* applicable if the requirement*
of the Limiting condition I for Operation are not met. I SALEM -UNI'l' 1 B 3/4 0-l Amendment No. 131 APPtICAB!¥ITY BASES Specification 3.0.2 establishes that noncompliance with a specification exist. when the requirements of the Limiting Condition for Operation are not met and the associated ACTION requirements have not been implemented within the specified time interval.
The purpose cf this specification is to clarify that . ( l) implementation of the ACTION requirements within the specified time interval constitutes compliance with a specification and (2) completion of the remedial measures of the ACTION requirements is not required when compliance with a Limiting condition of operation is restored within the time interval specified in the associated ACTION requirements.
... Specification 3.0.3 establishes the shutdown ACTION requirements that must be implemented when a Limiting condition for Operation is not met and the condition ia not specifically by the associated ACTION requirements.
The purpose of this specification is 'to delineate the time ?imita for placing the unit in a safe shutdown MODE when plant operation cannot be maintained within th* limits for safe operation defined by the r..imitinc; Condition11 for operation and its ACTION requirements.
It i* not intended to be uaad aa an operational convenience which permits (routine) voluntary removal of redundant syatem11 or components from service in lieu of other alternative*
that would not result in redundant systems or component*
being inoperable.
one hour is allowed to prepare for an orderly shutdown bef or* initiating a change in plant operation.
Thi* time permits the operator to coordinate the reduction in .electrical generation with the load dispatcher to en1ure the atability and availability of the electrical grid. The time limit*
ied to reach lower MODES of operation permit the shutdown to proceed in a controlled and orderly manner that is well within the specified maximum cooldown rata and within the cooldown capabilitie1 of the facility assuming only the minimum required equipment is OPERABLE.
This reduces thermal stresses on components of the primary coolant system and the potential for a plant up1et that could challenge safety systems under c*onditions for which this apecif
. applies.
If remedial mea1ure1 permitting limited continued operation of th* facility under the provi1iona cf tha ACTION requirements are completed, th* shutdown may be teJ:minated.
Th* time limit* of the ACTION requirementi are applicable from the point in time there was a failure to meet a Limiting condition fer Operation.
Therefore, the shutdown may be terminated if.the ACTION requirement*
have.been met or the time limit* of the ACTION requirements have not expired, thu1 providing an allowance for the completion of the required action1.
The time limits of specification 3.0.3 allow 37 hour* for the plant to be in the COLD SHUTDOWN MODE when a shutdown is required during the POWER MODE of operation.
If the plant is in a lower MODE of operation when a shutdown is required, the time limit for reaching the next lower KODE*of operation applies.
: However, if a lower MODE of operation 1* reached in laa11 time than allowed, the total allowable time to reach CO:C.D. SHUTDOWN, applicable MODE, i11 not reduced.
For example, if HOT STAtmBY i* reached in 2 houri, the time allowed to reach HO'l' SHUTDOWN is the next 1:1 hour* becau** of the total time to reach HOT SHUTDOWN is not reduced*
from the*allowable limit of 13 hours. Therefore, if remedial measures are completed that would permit SALEK -UNI'l' l B 0-2 Amendment No. 131 , .. I I I I I I I I I I I I I I I I I I I I I I I t \
.I I I I I I I I I I I I I I I I I I I I I I ,. 
: APPLICABILITY BASES return to POWER operation, a penalty is not incurred by having to reach a lower MODE of operation in less than the total time allowed.
The same principle applies with regard to the allowable outage time limits of the ACTION requirements, if compliance with the ACTION requirements for one specification in entry into a MODE or condition of operation for another specification in which the requirements of the Limiting Condition for Operation are not met. If the new specification becomes applicable in less time than specified, the difference may be added to the allowable outage time limits of the second specification.
: However, the allowable outage time limits of ACTION requirements for a higher MODE of operation may not be used to extend the allowable outage time that is applicable when a Limiting Condition for Operation is not met in a lower MODE of operation.
The shutdown of Specification 3.0.3 do not apply in MODES 5 and 6, because the-ACTION requirements of individual specifications define the remedial measures to be taken. Specification 3.0.4 establishes limitations on changes in MODES or other specified conditions in the Applicability when an LCD is not met. It allows placing the unit in a MODE or other specified condition stated in that Applicability (e.g., the Applicability desired to be entered) when unit conditions are such that the requirements of the LCO would not be met, in accordance with LCO 3.0.4.a, LCO 3.0.4.b, or LCD 3.0.4.c.
LCO 3.0.4.a allows entry into a MODE or other specified condition in the Applicability with the LCO not met when the associated ACTIONS to be entered perm:i-t continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time. Compliance with Required Actions that permit continued operation of the unit for an unlimited period of time in a MODE or other specified condition provides an acceptable level of safety for continued operation.
This is without regard to the status of the unit before or after the MODE change. Therefore, in such cases, entry into a MODE or other specified condition in the Applicability may be made in accordance with the provisions of the Required Actions.
LCO 3.0.4.b allows entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management
: actions, if appropriate.
The risk assessment may use quantitative, qualitative, or blended approaches, and the risk assessment will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR 50.65(a)
(4), which requires that risk impacts of activities to be assessed and managed.
The risk assessment, for the purposes of LCO 3.0.4.b, must take into account all inoperable Technical Specification equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)
(4) risk assessment scope. The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants."
Regulatory Guide 1.182 endorses the guidance in Section.
11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."
These documents general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management
: actions, and example risk management actions.
These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management SALEM -UNIT 1 B 3/4 0-3 Amendment No. 276 APPLICABILITY BASES personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of backup success paths or compensatory measures),
and determination that the proposed MODE change is acceptable.
Consideration should also be given to the probability of completing restoration such that the requirements of the LCO would be met prior to the expiration of ACTIONS Completion Times that would require exiting the Applicability.
LCO 3.0.4.b may be used with single, or multiple systems and components unavailable.
NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components.
The results of the risk assessment shall be considered in dete.rmining the acceptability of entering the MODE or other specified condition in the Applicability, and any corresponding risk management actions.
The LCO 3.0.4.b risk assessments do not have to be documented.
The Technical Specifications allow continued operation with equipment unavailable in MODE 1 for the duration of the Completion Time. Since this is allowable, and since in general the risk impact in that particular MODE bounds the risk of transitioning into and through the applicable MODES or other specified conditions in the Applicability of the LCO, the use of the LCO 3.0.4.b allowance should be generally acceptable, as long as the risk is assessed and managed as stated above. However, there is a small subset of systems and components that have been determined to be more important to risk and use of the LCO 3.0.4.b allowance is prohibited.
The LCOs governing these system and components contain Notes prohibiting the use of LCO 3.0.4.b by stating LCO 3.0.4.b is not applicable.
LCO 3.0.4.c allows entry into a MODE or other specified condition in the Applicability with the LCO not met based on an ACTION in the Specification which states LCO 3,0.4.c is applicable.
These specific allowances permit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not provide for continued operation for an unlimited period of time and a risk assessment has not been performed.
This allowance may apply to all the ACTIONS or to a specific Required Action of a Specification.
The risk assessments performed to justify the use of LCO 3.0.4.b usually only consider systems and components.
For this reason, LCO 3.0.4.c is typically applied to Specifications that describe values and parameters (e.g., Containment Air Temperature, Containment
: Pressure, Moderator Temperature Coefficient),
and may be applied to other Specifications based on NRC plant-specific approval.
* The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.
The provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS.
In addition, the provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown.
In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 31 MODE 3 to MODE 4, and MODE 4 to MODE 5. Upon entry into a MODE or other specified condition in the Applicability with the LCO not met, LCO 3.0.l and LCO 3.0.2 require entry into the applicable Conditions and SALEM -UNIT 1 B 3/4 0-3a Amendment No.276 API?LICABILITY BASES Required Actions until the Condition is resolved, until the LCO is met, or until the unit is not within the Applicability of the Technical Specification.
Surveillances do not have to be performed on. the associated inoperable equipment (or on variables outside the specified limits),
as permitted by SR 4.0.1. Therefore, utilizing LCO 3.0.4 is not a violation of SR 4.0.1 or SR 4.0.4 for any Surveillances that have not been performed on inoperable equipment.
: However, SRs must be met to ensure OPERABILITY prior to declaring the associated equipment OPERABLE (or variable within limits} and restoring compliance with the affected LCO. SALEM -UNIT 1 B 3/4 0-3b Amendment No.276 APPLICABILITY BASES Specification 3.0.5 DELETED SALEM -UNIT 1 B 3/4 0-4 Amendment No. 253 
) APPLICABILITY BASES Specification 3.0.6 establishes the allowance for restoring equipment to service under administrative controls when it has been removed from service or declared inoperable to comply with ACTIONS.
The sole purpose of this Specification is to provide an exception to LCO 3.0.2 "(e.g., to not comply with the applicable Required Action(s))
to allow the performance of testing required to restore and demonstrate:
: a. The OPERABILITY of equipment being returned to service; or b. The OPERABILITY of other equipment.
The administrative controls ensure the. time the equipment is returned to service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the testing required to restore and demonstrate the operability of the equipment.
This Specification does not provide time to perform any other preventive or corrective maintenance.
An example of demonstrating the OPERABILITY of the equipment being returned to service is reopening a containment isolation valve that has been closed to comply with Required Actions and must be reopened to perform the testing required to restore and demonstrate OPERABILITY.
An example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to prevent the trip function from occurring during the performance of testing required to restore OPERABILITY of another channel in the other trip system. A similar example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to permit the logic to function and indicate the appropriate response during the performance of testing required to restore and demonstrate the OPERABILITY of another channel in the same trip system. SALEM -UNIT l B 3/4 0-4a Amendment No. 253 APl?LICABILITY BASES Specifications 4.0.l through 4.0.5 establish the general requirements applicable to Surveillance Requirements.
These requirements are based on the Surveillance Requiremenus stated in the Code of Federal Regulations, 10 CFR 50.36(c)
(3): "Surveillance requirements are requirements relating to test, calibration, or inspection to ensure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions of operation will be met." Specification 4.0.l establishes the requirement that Surveillance Requirements must be met during the OPERATIONAL MODES or other specified conditions in the Applicability for which the requirements of the Limiting Conditions for Operation apply, unless otherwise specified in an individual Surveillance Requirement.
This specification is to ensure that surveillances are performed to verify the OPERABILITY of systems and components and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with Specification 4.0.2, constitutes a failure to meet an LCO. Systems and components are assumed to be OPERABLE when the associated Surveillance Requirements have been met. Nothing in this Specification,
: however, is to be construed as implying that systems or components are OPERABLE when either: a. The systems or components are known to be inoperable, although still meeting the Surveillance Requirements, or b. The requirements of the Surveillance(s) are known to be not met between required Surveillance performances.
Surveillances do not have to be performed when the facility is in an OPERATIONAL MODE or other specified condition for which the requirements of the associated Limiting Condition for Operation do not apply, unless otherwise specified.
The Surveillance Requirements associated with a Special Test Exception are only applicable when the Special Test Exception is used as an allowable exception to the requirements of a specification.
Unplanned events may satisfy the requirements (including applicable acceptance criteria) for a given Surveillance.
In this case, the unplanned event may be credited as fulfiiling the performance of the Surveillance Requirement.
This allowance includes those Surveillances whose performance is normally precluded in a given OPERATIONAL MODE or other specified condition.
Surveillances, including Surveillances invoked by ACTIONS, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with Specification 4.0.2 prior to returning
*equipment-to OPERABLE status. Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE.
This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with Specification 4.0.2. Post maintenance testing may not be possible in the current OPERATIONAL MODE or other specified conditions in the Applicability due to the necessary unit parameters not having been established.
In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and SALEM -UNIT 1 B 3/4 0-5 Amendment No. 256 APPLICABILITY BASES the equipment is not otherwise believed to be incapable of performing its function.
This will allow operation to proceed to an OPERATIONAL MODE or other specified condition where other necessary post maintenance tests can be completed.
Some examples of this process are: a. Auxiliary Feedwater (AFW) pump turbine maintenance during refueling that requires testing at steam pressures
> 680 psig. However, if other appropriate testing is satisfactorily completed, the AFW system can be considered OPERABLE.
This allows startup and other necessary testing to proceed until the plant reaches the steam pressure required to perform the testing.
: b. High Pressure Safety Injection (HPI) maintenance during shutdown that requires system func.tional tests at a specified pressure.
Provided other appropriate testing is satisfactorily completed, startup can proceed with HPI considered OPERABLE.
This allows operation to reach the specified pressure to complete the necessary post maintenance testing.
Specification 4.0.2 establishes the limit for which the specified time interval for surveillance Requirements may be extended.
It permits an allowable extension of the normal surveillance interval to facilitate surveillance scheduling and consideration of plant operating conditions that be suitable for conducting the surveillance; e.g., transient
:.ans or other ongoing surveillance or maintenance activities.
It also* es flexibility to accoilimodate the length of fuel cycle for .dillances that are performed at each refueling outage and are specified
.vith an 18 month surveillance interval.
It is not intended*
that this provision be used repeatedly as a convenience to extend surveillance intervals beyond that specified for surveillances that are not.performed during refueling outages.
The limitation of Specification 4.0.2 is based on engineering judgment and the recognition that the most probable result of any particular surveillance being performed is the verification of conformance with the Surveillance Requirements.
This provision is sufficient to ensure that the reliability ensured through surveillance activities is not significantly degraded beyond that obtained from the specified surveillance
: interval, Specification 4.0.3 establishes flexibility to defer declaring affected equipment inoperable, or an affected variable outside the specified limits, when a Surveillance has not been completed within the specified frequency.
A delay period of up to 24 hours or up to the limit of the specified frequency, whichever is greater, applies from the point in time that it is discovered that the Surveillance has not been in accordance with TS 3.0.2, and not at the time that the specified frequency was not met. This delay period provides adequate time to complete Surveillances that have been missed. This delay period permits.the completion.of a Surveillance before complying with Required Actions or other remedial measures that might preclude completion of the Surveillance.
The basis for this delay period includes consideration of unit conditions, adequate
: planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any
.. particular surveillance being performed is the verification of conformance with the requirements.
SALEM -UNIT 1 B 3/4 0-6 Amendrnen t No. 256 APPLICABILITY BASES When a surveillance with a Frequency based not on time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering MODE 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed wheri specified, SR 4. 0. 3 allows for the full delay period of up to the specified Frequency to perform the Surveillance.
: However, since there is not a time interval specified, the missed Surveillance should be performed at the first reasonable oppo*rtunity.
SR 4,0.3 provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.
Failure to comply with specified frequencies for Surveillances is expected to be an infrequent occurrence, Use of the delay period established by SR 4.0.3 is a flexibility which is not intended to be used as an operational convenience to extend Surveillance intervals.
While up to 24 hours or the limit of the specified Frequency is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be.performed at the first reasonable opportunity.
The determination of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the Surveillance as as any plant configuration changes required or shutting the plant down to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions,
: planning, availability of personnel, and the time required to perform the Surveillance.
This risk impact should be managed through the program in place to implement 10 CFR50.65(a)
(4) and its int>lementation
: guidance, NRC Regulatory Guide 1.182, 'Assessing and Managing Risk Before Maintenance Activities a.t Nuclear Power Plants.'
This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk action thresholds, and risk management action up to and including plant shutdown.
The missed Surveillance Qe treated as an emergent condition as discussed in the Regulatory Guide. The-risk may use quantitative, qualitative, or blended methods.
The degree of depth and rigor of the evaluation should be commensurate with the importance of the component, Missed Surveillances for important components should be analyzed quantitatively.
If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to determine the safest course of action. All missed Surveillances will he placed in the licensee1s Corrective Action Program.
If a Surveillance is not completed**within.
the allowed delay period, then .. :the .... equipment is considered inoperable, or the variable is considered outside the specified limits, and the Completion Times of the, Required Actions for the applicable LCO begin inunediately upon expiration of the delay period. If a Surveillance is failed within the delay period, then the equipment is inoperable, or the variable is outside the specified limits, and the Completions Times of the Required Actions for the applicable LCO begins immediately upon the failure of the Surveillance.
Completion of the Surveillance within the delay period allowed by this Specification, or within the Completion Time of the Actions, restores compliance with SR 4.0.1, SALEM -UNIT 1 B 3/4 0-7 .Amendment No. 256 APPLICABILITY BASES Specification 4,0.4 establishes the requirement that all applicable SRs must be met before entry into a MODE or other specified condition in the Applicability.
This Specification ensures that system and component OPERABILITY requirements and variable limits are met before entry into MODES or other specified conditions in the Applicability for which these systems and components ensure safe operation of the unit. THe provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to oeERABLE status before entering an associated MODE or other specified condition in the Applicability.
A provision is included to allow entry into a MODE or other specified condition in the Applicability when an LCO is not met due to Surveillance not being met in accordance with LCO 3.0.4. However, in two circumstances, failing to meet an SR not result in SR 4.0.4 restricting a MODE change or other specified condition change: (1) When a system, subsystem,
: division, component, device or variable is inoperable or outside its specified limits, the associated SR(s) are not required to be performed, per SR 4.0.1,* which states that surveillances do not have to be perfo:r:med on inoperable equipment.
When equipment is inoperable, SR 4.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed.
Therefore, failing:
to perform the Surveillance(s) within the specified Frequency does not result in an SR 4.0.4 restriction to changing MODES or other specified conditions of the Applicability.
: However, since the LCO is not met in this instance, LCO 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specified condition changes.
(2) SR 4,0.4 does not restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been performed within the specified Frequency, provided the requirement to declare the LCO not met has been delayed in accordance with SR 4.0.3. The provisions of SR 4.0.4 shall not prevent entry into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS.
In addition, the provisions of SR 4.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown.
In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, MODE 3 to MODE 4, and MODE 4 to MODE 5. The precise requirements for performance of SRs are specified such that exceptions to SR 4.0.4 are not necessary.
The specific time frames and conditions necessary for meeting the SRs are specified in the Frequency, in the Surveillance, or both. This allows performance of Surveillances when the prerequisite condition(s) specified in a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated LCO prior to the performance or completion of a Surveillance.
A Surveillance that could not be performed until after entering the LCO's Applicability would have its Frequency specified such that it is not "due" until the speeific conditions needed are met. Alternately, the Surveillance may be stated' in the foJ:In of a Note, as not required (to be met or performed) until a particular event, condition, or time has been reached.
Further discussion of the specific formats of SRs' annotation is found in Section 1.4, Frequency.
SALEM -UNIT 1 B 3/4 0-8 Amendment No.276 APPLICABILITY BASES 4.0.5 Deleted SALEM -UNIT 1 Specification deleted per Amendment 297 B 3/4 0-9 Amendment No.297 (PSEG Issued) 
*--3/4.l REACTIVITY CONTROL SYSTEMS BASES 3/4.1.l BORATION CONTROL 3/4.1.l.l and 3/4.l.l.2 SHUTDOWN MA&GIN A sufficient SHUTDOWN MARGIN ensures that ll the reactor can be made subcritical from all operating conditions,
: 2) the reactivity transients
.associated with postulated accident conditions are controllable within acceptable limits, and 3) the reactor will be maintained sufficiently subcritical to preclude inadvertent criticality in the shutdown condition.
SHUTDOWN MARGIN requirements vary throughout core life as a function of fuel depletion, RCS boron concentration, and RCS Ta*s* The most restrictive condition occurs at EOL, with Tavs at no load operating temperature, and is associated with a postulated steam line break accident and resulting uncontrolled RCS cooldown.
In the analysis of this accident, a minimum SHUTDOWN MARGIN of l.3t Ak/k is initially required to control the reactivity transient.
Accordingly, the SHUTDOWN MARGIN requirement is based upon this limiting condition and is consistent with FSAR safety analysis assumptions.
With Tava s 200°F, the reactivity transients resulting from a postulated steam line break cooldown are minimal and a l\ Ak/k shutdown margin provides adequate protection.
3/4.1.1.4 MODERATOR.
IEMPERA.TQRE COEFFICIENT
!MTCl The limitations on MTC are provided to ensure that the value of this coefficient remains within the limiting condition assumed in the accident and transient analyses.
SALEM -UNIT l B 3/4 l-1 Amendment No. 201 .....
3/4.l REbCTIVITY CONTROL SYSTEMS BASES 3/4.l.l.4 MODERATOR TEHPERAJ'URE COEFFICIENT (MTCl (Continued)
The MTC values of this specification are applicable to a specific set of plant conditions; accordingly, verification of MTC values at conditions other than those explicitly stated will require extrapolation to those conditions in order to permit an accurate comparison.
The negative MTC value equivalent to the most positive moderator density coefficient (MDC), was obtained by incrementally correcting the MDC used in the FSAR analysis to nominal operating conditions.
These corrections involved:
(l) a conversion of the MDC used in the FSAR analysis to its equivalent MTC, based on the rate of change of moderator density with temperature at RATED THERMAL POWER conditions, and (2) subtracting from this value the largest differences in MTC observed between EOL, all rods withdrawn, RATED THERMAL POWER conditions, and those most adverse conditions of moderator temperature and pressure, rod insertion, axial power skewing, and xenon concentration that can occur in normal operation and lead to a significantly more negative EOL MTC at RATED THERMAL i'OWER. These corrections transformed the MDC used in the FSAR analysis into the limiting End of cycle Life (EOLl MTC value. The 300 ppm surveillance limit MTC value represents a conservative value at a core condition of 300 ppm equilibrium boron concentration that is obtained by correcting the limiting EOL MTC for burnup and boron concentration.
The surveillance requirements for measurement of the MTC at the beginning and near the end of the fuel cycle are adequate to confirm that the MTC remains with its limits since this coefficient changes slowly due principally to the reduction in RCS boron concentration associated with fuel burnup. 3/4.l.l.5 MINIMUM TE!1PER,ATQRS FOR CRITIChLIIX This specification ensures that the reactor will not be made critical with the Reactor Coolant System average temperature less than 541°F. This limitation is required to ensure l) the moderator temperature coefficient is within its analyzed temperature range, 2) the protective instrumentation is within its normal operating range, 3) the P-12 interlock is above its allowable
: eetpoint,
: 4) the pressurizer is capable of being in an OPERABLE status with a steam bubble, and 5) the reactor pressure vessel is above its minimum RTNDT temperature.
SALEM -UNIT l B 3/4 1-2 Amendment No.201 *-** \ --* 
( ( REACTIVITY CONTROL SYSTEMS BASES 3/4.1.2 BORATION SYSTEMS The boron injection system ensures that negative reactivity control.is available during each mode of facility operation.
The components required to perform this function include:
: 1) borated water sources,
: 2) charging pumps, 3) separate flow paths*, 4) boric acid transfer pumps, and 5) offsite power or an emergency supply from OPERABLE diesel generators.
With the RCS average temperature 350°F, a minimum of two boron injection flow paths are required to ensure single functional capability in the event an assumed failure renders one of the flow paths inoperable.
The boration capability of either flow path is sufficient to provide a SHUTDOWN MARGIN from expected operating conditions of 1. 3.% delta k/k after xenon decay and cooldown to 200°F. The maximum expected boration capability (minimum boration volume) requirement is established to conservatively bound expected operating conditions throughout core operating life. The analysis assumes that the most reactive control rod is not inserted into the core. The maximum expected boration capability requirement occurs at EOL from full power equilibrium xenon conditions and requires borated water from a boric acid tank in accordance with TS Figure 3.1-2, and additional makeup from either: (1) the second boric acid and/or batching, or (2) a maximum of 41,800 gallons of 2,300 ppm borated water from the refueling water storage tank. With the refueling water storage tank as the only borated water source, a maximum of 73, 800 gallons of 2,300 ppm borated water is required.
: However,
.. to be consistent with the ECCS requirements, the RWST is required to have a minimum contained volume of 364,500 gallons during operations in MODES 1, 2, 3 and 4. The boric acid tanks, pumps, valves, and piping contain a boric acid solution concentration of between 3.75% and 4.0% by weight. To ensure that the boric acid remains in solution,"
the tank fluid temperature and the process pipe wall temperatures are monitored to ensure a temperature of 63°F, -*-*-**--*-*--**--or
**ari"Cive
-is *m.a1.ntained*;*-*
Tne* tan1Cfluia**
aha-pipe-*
wall temperatures are monitored in the main control room. A 5°F margin is provided to ensure the boron will not precipitate out. Should ambient temperature decrease below 63°F, the.boric acid tank heaters, in conjunction with boric acid pump recirculation, are capable of maintaining the boric acid in the tank and in the pump at or above 63°F. A small amount of boric acid in the flow path between the boric acid recirculation line and the suction line to the charging pump will precipitate out,-but it will not cause flow blockage even with temperatures below 50°F. With the RCS temperature below 350°F, one injection system is acceptable without single failure consideration on the basis of the stable reactivity condition of the reactor and the additional restrictions prohibiting CORE ALTERATIONS and positive reactivity change in the event the single injection system becomes inoperable.
SALEM -UNIT 1 B 3/4 1-3 TSBC SCN 05-042 REACTIVITY CONTROL SYSTEMS BASES The boron capability required below 200 °P in sufficient to provide a SHUTDOWN MARGIN of 1% delta k/k after xenon decay and cooldown from 200 °P to 140 °F. This condition requires either 2,600 gallons of 6,560 ppm borated water from the boric acid storage tanks or 7,100 gallons of 2,300 ppm borated water from the refueling water storage tank. The 37,000 gallons limit in the refueling water storage tank for Modes 5 and 6 is based upon 21,210 gallons that is undetectable due to lower tap location, 8,550 gallons for instrument error, 7,100 gallons required for shutdown margin, and an additional 140 gallons due to rounding up. The limits on contained water volume and boron concentration of the RWST also ensure a pH value of between 7.0 and 10.0 for the solution recirculated within containment after a LOCA. This pH band minimizes the evolution of iodine and minimizes the effect of chloride and caustic stress corrosion on mechanical systems and components.
The contained water volume limits include allowance for water not available because of discharge line location and other physical characteristics.
The OPERABILITY of one boron injection system during REFUELING ensures that this system is available for reactivity control while in MODE 6. 3/4.1.3 MOVABLE CONTROL ASSEMBLIES The specifications of this section ensure that (1) acceptable power distribution limits are maintained, (2) the minimum SHUTDOWN MARGIN is maintained, and (3) limit the potential effects of rod mis-alignment on associated accident analyses.
OPERABILITY of the control rod position indicators is required to determine control rod positions and thereby ensure compliance with the control rod alignment and insertion limits. OPERABLE condition for the analog rod position indicators is defined as being capable of indicating rod position to within the allowed rod misalignment relative to the bank demand position for a range of positions.
For the Shutdown Banks and Control Bank A this range is defined as the group demand counter indicated position between O.and 30 steps withdrawn inclusive, and between 200 and 230 steps withdrawn inclusive.
This permits the operator to verify that the control rods in these banks are either fully withdrawn or fully inserted, the normal operating modes for these banks. Knowledge of these banks' positions in these ranges satisfies all accident analysis assumptions concerning their position.
The range for Control Bank B is defined as the group demand counter indicated position between 0 and 30 steps withdrawn inclusive, and between 160 and 230 *steps withdrawn inclusive.
For Control Banks C and D the range is defined as the group demand counter indicated position between o and 230 steps, withdrawn.
Comparison of the group demand counters to the bank insertion limits with
* verification of rod position with the analog rod position indicators (after thermal soak after rod motion) is sufficient verification that the control rods are above the insertion limits. The full out position will be specified in the reload analysis for the cycle. This position will be within the band established by FULLY WITHDRAWN and will be administratively controlled.
This band is allowable to minimize RCCA wear, consistent with Information Notice 87-19 andRCCA examinations that were conducted during Salem Unit 1 Fall outage 2005 (1R17) by the Salem RCCA vendor AREVA NP. (Refer to LAR S09-01) SALEM -UNIT l B 3/4 l-4 Amendment No. 292 (PSEG Issued)
REACTIVITY CONTROL SYSTEMS BASES The ACTION statements which permit limited variation from the basic requirements are accompanied by additional restrictions which ensure that the original criteria are met. Mis-alignment of a rod requires measurement of peaking factors or a restriction in THERMAL POWER; either of these restrictions provide assurance of fuel rod integrity during continued operation.
The reactivity worth of a mis-aligned rod is limited for the remainder of the fuel cycle to prevent exceeding the assumption used in the accident analysis.
The maximum rod drop time restriction is consistent with the assumed rod drop time used in the accident analyses.
Measurement with Tavg >541°F and with all reactor coolant pumps operating ensures that the measured drop times will be representative of insertion times experienced during a reactor trip at operating conditions.
Control rod positions and OPERABILITY of the rod position indicators are required to be verified in accordance with the Surveillance Frequency Control Program with more frequent verifications required if an automatic monitoring channel is inoperable.
The Surveillance Frequency is based on operating experience,
*equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
The terms "Shutdown Rod Position Indicator",
"Analog Rod Position Indicator",
"Control Rod Position Indicator",
and Rod Position Indicator" are all used in this bases section or in the Technical Specifications, and all refer to indication driven by the output of the Analog Rod Position Indication (ARPI) system. One method for determining rod position are the indicators on the coritrol console.
An alternate method of determining rod position is the plant computer.
Either the control console indicator or plant computer is sufficient to comply with this specification.
The plant computer receives the same input from ARPI as the control console indicators and provides resolution equivalent to or better than the control console indicators.
The plant computer also provides a digital readout of rod position which eliminates interpolation and parallax errors inherent to analog scales. Rod demand position is indicated on the control console and the plant computer.
The rod demand position is a digital signal, namely a pulse, and is generated each time the Rod Control System demands a rod position step change, one pulse for each rod step. The pulses are "counted" and displayed by the control console group demand step counters.
There are two group step counters for each bank of rods with exception of shutdown banks C and D. The plant computer also "counts" and displays the demand pulses. Only the group 1 demand position of each rod bank is displayed on the* plant computer as only the group 1 pulses are routed to the plant computer.
The group 1 demand position on the plant computer is, by default, called "Cont Bank A Steps" or "SID Bank A Steps" etc. with no reference to group 1 or group 2. As the plant computer receives the same demand pulses from the Rod Control System as the control console group demand step counters and provides equivalent resolution, the plant computer "bank step" display provides an alternate method of determining group 1 rod demand position.
Either the control console group 1 demand step counter or the plant computer "bank step" display is sufficient to comply with this specification for group 1 rod demand position.
Only the control console group 2 demand counter can be used to comply with the specification for group 2 rod demand. SALEM -UNIT 1 B 3/4 1-5 Amendment No. 299 (PSEG Issued) 3/4.2 POWER DISTRIBUTION LIMITS BASES The specifications of this section provide assurance of fuel integrity during Condition I {Normal Operation) and II (Incidents of Moderate Frequency)
J events by: (a) m7eting thde D{Nl3 desi91'.1 criterion during normal operation and in . short term transients, an b) limiting the fission gas release, fuel pellet temperature and cladding mechanical properties to within assumed design criteria.
In addition, limiting the peak linear power density during Condition I events provides assurance that the initial conditions assumed for the LOCA analyses are met and the ECCS acceptance criteria limit of 2200°F is not exceeded.
The definitions of hot channel factors as used in these specifications are as follows:
FQ(Z) Heat Flux Hot Channel Factor, is defined as the maximum local heat flux on the surface of a fuel rod at core elevation Z divided by the average fuel rod heat flux, allowing for manufacturing tolerances on fuel pellets and rods. FNAH Nuclear Enthalpy Rise Hot Channel Factor, is defined as the ratio of the integral of linear power along the rod with the highest integrated power to the average rod power.
Radial Peaking Factor is defined as the ratio of peak power density to ave.rage power density in the horizontal plane at core elevation
: z. 3/4.2.l AXIAL FLUX DIFFERENCE (AfD) The limits on AXIAL FLUX DIFFERENCE assure that the FQ(Z) upper bound envelope of the FQ limit specified in the core Operating Limits Report (COLR) times the normalized axial peaking factor is not exceeded during either normal operation or in the event of xenon redistribution following power changes.
Target fiux difference determined at equilibrium xenon conditions.
The full length rods may be positioned within the core in accordance with their respective insertion limits and should be inserted near their normal position for steady state operation at high power levels. The value of the target flux difference obtained under these conditions divided by the fraction of RATED THERMAL POWER is the target flux difference at RATED THERMAL POWER for the associated core burnup conditions.
Target flux differences for other THERMAL POWER levels are obtained by multiplying the RATED THERMAL POWER value *by the appropriate fractional THERMAL POWER level. The periodic updating of the target flux difference value is *necessary to reflect core burnup considerations.
SALEM -UNIT 1 B 3/4 2-l Amendment No. 201 POWER DISTRIBUTION LIMITS BASES Although it is intended that the plant will be operated with the AXIAL FLUX DIFFERENCE within the target band in the COLR per Specification 3.2.1 about the target flux difference, during rapid plant THERMAL POWER reductions, control rod motion will cause the AFD to deviate outside of the target band at reduced THERMAL POWER levels. This deviation will not affect the xenon redistribution sufficiently to change the envelope of peaking factors which may be reached on a subsequent return to RATED THERMAL POWER (with the AFD within the target band) provided the time duration of the deviation is limited.
Accordingly, a 1 hour penalty deviation limit cumulative during the previous 24 hours is provided for operation outside of the target band but within the limits specified in the COLR while at THERMAL POWER levels between 50% and 90% of RATED THERMAL POWER. For THERMAL POWER levels between 15% and 50% of rated THERMAL POWER, deviations of the AFD outside of the target band are less significant.
The penalty of 2 hours actual time reflects this reduced significance.
Provisions for monitoring the AFD are derived from the plant nuclear instrumentation system through the AFD Monitor Alarm. A control room recorder continuously displays the auctioneered high flux difference and the target band limits as a function of power level. An alarm is received any time the auctioneered high flux difference exceeds the target band limits. Time outside the target band is graphically presented on the strip chart. Measurement of the target flux the power distribution when the core preferably at high power levels with measurement provides the equilibrium the target value can be determined.
with core burnup. difference is accomplished by measuring is at equilibrium xenon conditions, the control banks nearly withdrawn.
This xenon axial power distribution from which The target flux difference varies slowly Alternatively, linear interpolation between the most recent measurement of the target flux differences and a predicted end of cycle value provides a reasonable update because the AFD changes due to burnup tend toward 0% AFD. When the predicted end of cycle AFD from the cycle nuclear design is different from 0%, it (the prediction) may be a better value for the interpolation.
Figure B 3/4 2-1 shows a typical monthly target band. SALEM -UNIT 1 B 3/4 2-2 Amendment No. 307 (PSEG Issued)
* Percent of Rated Thermal Power 90,.. 80% 70% 60% 50% 40% 30% 20% 0 -20" INFORMATION ONLY* <}--Target Flux Dif ' I r -10% 0 10% 20"* INDICATED AXIAL F1.UX DIFFERENCE f erence Flgure I 314 2-1 TYPICAL INDICATED AXIAL FLUX DIFFERENCE VERSUS THE"MAL POWER Refer to COLR Figure 2 !or Actual Limits SALEM -UNIT l Amendment No. 201 
 
LIMITS BASES 3/4.2.2 and 3/4.2.3 HEAT FLUX AND NUCLEAR ENTHALPY HOT CHANNEL ANO RACIAL Fi d PEAKING FACTORS -Fo(Zl, F DH iln FJCY(Z) The limits on heat flux and nucl*ar *nthalpy hot chann*l factors ensure that ll the design limits on peax local power density and minimW'l'I CNBR are not exceeded and 2> in the event of a LOCA the peak fuel clad temperature will not exceed the 2200&deg;F ECCS acceptance criteria limit. Each of these hot channel factors are measurable but will normally only be determined psriodically a6 specified in Specifications 4.2.2 and 4.2.3. This poriodic surveillance is suffici*nt to insure that the hot channel factor limits are maintained provided:
: a. Control rod in a single move together with no individual rod insertion differing from the group dvrnand position by than the allowed rod mislagnment.
: b. Control rod groups are sequenced with overlapping groups as in Spvcific*tion 3.1.J.S.
: c. The control rod insertion limits of Specifications J.1.3.4 and J.l.J.5 are maintained.
: d. axial power distribution, expracsad in terms of AXIAL FLUX CIFF.EJ\ENC:E.
is maintunQd with1n the limits. The relaxation in as a function of THERMAL POWER allows changes in the radial power shape for all permissible rod ineertion limits. FNDM will be within i:s limits provided conditions a thru d above, are maintained.
When an FQ m*asurement is tak*n, both experimental error and :nanufacturing tol*ranca JflU9t be allowed for 5\ ie the appropriate for A full core map taken with th* incore detector flux mapping system and 3' ic the appropriace allowance
!or manufacturing tolerance. measurements obt*1ned using the Power Distribution SyGtem (PDMS), th* appropriate measurement uncertainty is determined using the 111C1asurement uncertainty methodology contained in WC:AP 12472-P-A.
The c;yele and plant uncertainty calculation information n**ded to support th* POMS calculat1on is conta1ned in the COLR. The PDHS will auto1N1tically calculate and apply the correct meaaurement uncerta1nty.
and apply a-3\ allowance for m.nufacturing tolerance.
When r"ow is measured.
exp*rimental error must be allowed fer and is obtained from the COLR when using the POMS or the incore det*ction system. The specified limit !or ,.,DH also contains an H allowance for uncertainties wh1ch mean that normal operation will result in &#xa3;FRTP:1H
/l. OS where FltTPDH is the limit of RATED THERMAL POWER (:RTP) specified in the CORE OPERATING LIMITS R!PORT ICOLRJ. The 8% allowanCQ is based on the following considerations:
SALEM -UNIT l B 3/4 Z-4 IU'nendinent No. 231 POWER DISTRIBUTION LIMITS BASES a. abnormal perturbations in the radial power shape, such as from rod misalignment, effect F"t.H more directly F0, b. although rod movement has a direct influence upon limiting F0 to within its limit, such control is not *readily available to limit E"'t.Hr and c. errors in prediction for control power shape detected during startup physics tests can be compensated for in F0 by restricting axial flux distributions.
This compensation for E"'t.H is less readily available.
The appropriate measurement uncertainty for obtained using PDMS is determined using the measurement uncertainty methodology contained in WCAP 12472-P-A.
The cycle and plant specific uncertainty information needed to support the PDMS calculation is contained in the COLR. The PDMS will automatically calculate and apply the correct measurement uncertainty to the measured F"t.H. The radial peaking factor Fxy(z) is measured periodically to provide assurance that the hot channel factor, F0(z), remains within its limit. The Fxy limit for Rated Thermal Power ( FRTPxy),
as provided in the COLR per specification 6.9.1.9, was determined from expected power control maneuvers over the full range of burnup conditions in the core. The core plane regions applicable to an Fxy evaluation exclude the following, measured in percent of core height (from the bottom of the fuel): a. Lower core region, from 0% to 8% inclusive,
: b. Upper core region, from 92% to 100% inclusive,
: c. Grid plane regions at +/- 2%, inclusive, and d. Core plane regions within+/- 2% of core height (+/-2.88 inches) about the bank demand position of the bank "D" control rods. 3/4.2.4 QUADRANT POWER TILT RATIO The quadrant power tilt ratio limit assures that the radial power distribution satisfies the design values used in the power capability analysis.
Radial power distribution measurements are made during startup testing and periodically during power operation.
The limit of 1.02 at which corrective action is required provides DNB and linear heat generation rate protection with x-y plane power tilts. A limiting tilt of 1.025 can be tolerated before the margin for uncertainty in F0 is depleted.
The limit of 1.02 was selected to provide an allowance for the uncertainty associated with the indicated power tilt. The two hour time allowance for operation with a tilt condition greater than 1.02 but less than 1.09 is provided to allow identification and correction of a dropped or misaligned rod. In the event such action does not correct the tilt, the margin for uncertainty on F0 is reinstated by reducing the power by 3 percent from RATED THERMAL POWER for each percent of tilt in excess of 1.0. SALEM -UNIT 1 B 3/4 2-5 TSBC S2015-072 POWER DISTRIBUTION LIMITS BASES 3/4.2.5 DNB PARAMETERS The limits on the DNB related parameters assure that each of the parameters are maintained within the normal steady state envelope of operation assumed in the transient and accident analyses.
The limits are consistent with the initial FSAR assumptions and have been analytically demonstrated adequate to maintain a minimum DNBR of the design DNBR value throughout each analyzed transient.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
SALEM -UNIT 1 B 3/4 2-6 Amendment No. 299 (PSEG Issued) 3/4.3 INSTRUMENTATION BASES 3/4.3.1 and 3/4.3.2 PROTECTIVE AND ENGINEERED SAFETY FEATURES (ESF) INSTRUMENTATION The OPERABILITY of the protective and ESF instrumentation systems and interlocks ensure that 1) the associated ESF action and/or reactor trip will be initiated when the parameter monitored by each channel or combination thereof exceeds its setpoint,
: 2) the specified coincidence logic and sufficient redundancy is maintained to permit a channel to be out of service for testing or maintenance consistent with maintaining an appropriate level of reliability of the Reactor Protection and Engineered Safety Features instrumentation and, 3) sufficient system functional capability is available from diverse parameters.
The OPERABILITY of these systems is required to provide the overall reliability, redundance and diversity assumed available in the facility design for the protection and mitigation of accident and transient conditions.
The integrated operation of each of these systems is consistent with the assumptions used in the accident analyses.
The Trip Setpoints are the nominal values at which the bistables are set. Any bistable is considered to be properly adjusted when the "as-left" value is within the band for CHANNEL CALIBRATION accuracy (i.e., +/-rack calibration+
comparator setting accuracy)
. The Trip Setpoints used in the bistables are based on the analytical limits stated in the UFSAR. The selection of these Trip Setpoints is such that adequate protection is provided when all sensor and processing time delays are taken into account.
To allow for calibration tolerances, instrumentation uncertainties, instrument drift, and severe environment errors for those Reactor Protection System (RPS) channels that must function in harsh environments as defined by 10 CFR 50.49, the Trip Setpoints and Allowable Values specified in the Technical Specification Limiting Conditions for Operation (LCO's) are conservatively adjusted with respect to the analytical limits. The methodology used to calculate the Trip Setpoints is consistent with Instrument Society of America standard ISA-S67.04-1982, which is endorsed via NRC Regulatory Guide 1.105, Rev. 2. The actual nominal Trip Setpoint entered into the bistable is more conservative than that specified by the Allowable Value to account for changes in random measurement errors detectable by a CHANNEL FUNCTIONAL TEST. One example of such a change in measurement error is drift during the surveillance interval.
If the measured setpoint does not exceed the Allowable Value, the bistable is considered OPERABLE.
Setpoints in accordance with the Allowable Value ensure that the safety analyses which demonstrate that safety limits are not violated remain valid (provided the unit is operated within the LCO's at the onset of any design basis event and the equipment functions as designed)
. The Trip Setpoints and Allowable Values listed in the LCO's incorporate all of the known uncertainties applicable for each channel.
The magnitudes of these uncertainties are factored into the determination of each Trip Setpoint.
All field sensors and signal processing equipment for these channels are assumed to operate within the allowances of these *uncertainty magnitudes.
The surveillance requirements specified for these systems ensure that the overall system functional capability is maintained comparable to the original design standards.
The periodic surveillance tests are sufficient to demonstrate this capability.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Specified surveillance and maintenance outage times have been determined in accordance with WCAP-10271, "Evaluation of Surveillance Frequencies and Out of Service Times for the Reactor Protection SALEM -UNIT 1 B 3/4 3-1 Amendment No. 299 (PSEG Issued)
BASES Instrumentation System,"
and Supplements to that report. Out of service times were determined based on maintaining an appropriate level of reliability of the Reactor PrQtection System and Engineered Safety Features instrumentation.
The verification of response time provides assurance that the reactor trip and the engineered safety features actuation associated with each channel is completed within the time limit assumed in the safety analysis.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Response Time acceptance criteria have been relocated to UFSAR Sections 7.2 and 7.3 tables. No credit is taken in the analysis for those channels with response times indicated as not applicable (i.e., N.A.). The FSAR tables 7.3-8 Note 8 response times for feedwater isolation are based on WCAP-16503, "Salem Unit 1 and Unit 2 Containment Response to LOCA and MSLB for Containment Fan Cooler Unit (CFCU) Margin Recovery Project,"
Revision 3, (LCR S06-10).
SGFP trip and FIV closure are credited in the containment analyses for LOCA and MSLB in case an FRV fails open. Response time may be verified by actual response time tests in any series of sequential, overlapping or total channel measurements, or by the summation of allocated sensor response times with actual response time tests on the remainder of the channel.
Allocations for sensor response times may be obtained from: (1) historical records based on acceptable response time tests (hydraulic, noise, or power interrupt tests), (2) inplace, onsite, or offsite (e.g. vendor) test measurements, or (3) utilizing vendor engineering specifications.
WCAP-13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" provides the basis and methodology for using allocated sensor response times in the overall verification of the channel response time for specific sensors identified in the WCAP. Response time verification for other sensor types, and other components that do not have plant-specific NRC approval to use alternate means of verification, must be demonstrated by test. The allocation for sensor response times must be verified prior to placing the component in operational service and re-verified following maintenance that may adversely affect response time. In general, electrical repair work does not impact response time provided the parts used for repair are of the same type and value. One example where response time could be affected is replacing the sensing assembly of a transmitter.
Channel testing in a bypassed condition shall be performed without lifting leads or jumpering bistables.
The CHANNEL CALIBRATION surveillance for the Power Range Neutron Flux Function instrumentation is modified by Note 17. Note 17 states that in MODES 1 and 2 the SSPS input relays are excluded from this Surveillance when the installed bypass test capability is used to perform this surveillance.
When the installed bypass test capability is used, the channel is tested in bypass versus tripped condition.
To preclude placing the channel in a tripped condition, the SSPS input relays are excluded from this surveillance.
The exclusion of the SSPS input relays from this test is intended to reduce the potential for an inadvertent reactor trip during surveillance testing.
Therefore, the exclusion of the SSPS input relays from the surveillance is only applicable in MODES 1 and 2. The SSPS input relays must be included in the CHANNEL CALIBRATION surveillance at least once every 18 months. SALEM -UNIT 1 B 3/4 3-la Amendment No. 312 (PSEG Issued)
BASES The CHANNEL FUNCTIONAL TEST surveillances for the Power Range Neutron Flux and Power Range Neutron Flux High Positive Rate Function Instrumentation are modified by Note 18. Note 18 states that the SSPS input relays are excluded from this surveillance when the installed bypass test capability is used to perform this surveillance.
When the installed bypass test capability is used, the channel is tested in a bypassed versus tripped condition.
To preclude placing the channel in a tripped condition, the SSPS input relays are excluded from this surveillance.
The exclusion of the SSPS input relays from this test is intended to reduce the potential for an inadvertent reactor trip during surveillance testing.'
The SSPS input relays must be included in the CHANNEL CALIBRATION surveillance at least once every 18 months. 3/4.3.3 MONITORING INSTRUMENTATION 3/4.3.3.1 RADIATION MONITORING INSTRUMENTATION The OPERABILITY of the radiation monitoring channels ensures that 1) the radiation levels are continually measured in the areas served by the individual channels and 2) the alarm or automatic action is initiated when the radiation level trip setpoint is exceeded.
In the postulated Fuel Handling
: Accident, the revised dose calculations, performed using 10 CFR 50.67 and Regulatory Guide 1.183, Alternative Source Term, do not take credit for automatic containment purge isolation thus allowing for continuous monitoring of containment activity until containment closure is achieved.
If required, containment purge isolation can be initiated manually from the control room. SALEM -UNIT 1 B 3/4 3-lb Amendment No. 312 (PSEG Issued)
BASES 3/4.3.3.1 RADIATION MONITORING INSTRUMENTATION (Continued)
CROSS REFERENCE
-TABLE 3.3-6 T/S Table Instrument Description Acceptable RMS Item No. Channels la Fuel Storage Area lRS or 1R9 lb DELETED 2ala Containment Gaseous Activity Purge & 1Rl2A or 1R41A, Pressure/Vacuum Relief Isolation and D<11 <21 2alb Containment Gaseous Activity RCS Leakage 1Rl2A Detection 2a2a (NOT USED) 2a2b Containment Air Particulate Activity RCS lRllA Leakage Detection 2bl Noble Gas Effluent Medium Range Auxiliary 1R41B & D (1) (3) (5) Building Exhaust System (Plant Vent) 2b2 Noble Gas Effluent High Range Auxiliary 1R41C & D (1) (4) (5) Building Exhaust System (Plant Vent) 2b3 Noble Gas Effluent Condenser Exhaust System 1Rl5 3a Unit 1 Control Room Intake Channel 1 (to Unit lRlB-1 1 Monitor)
Unit 1 Control Room Intake Channel 2 (to Unit 2RlB-2 2 Monitor)
Unit 2 Control Room Intake Channel 1 (to Unit 2R1B-l 2 Monitor)
Unit 2 Control Room Intake Channel 2 (to Unit lRlB-2 1 Monitor)
Immediate action(s),
in accordance with the LCO Action Statements, means that the required action should be pursued without delay and in a controlled manner. (1) The channels listed are required to be operable to meet a single operable channel for the Technical Specification's "Minimum Channels Operable" requirement.
(2) The setpoint applies to 1R41D. The measurement range applies to 1R41A and B which display in uCi/cc using the appropriate channel conversion factor from cpm to uCi/cc. SALEM -UNIT 1 B 3/4 3-2 Amendment No. 299 (PSEG issued)
INSTRUMENTATION BASES (3) 1R41D is the setpoint channel; 1R41B is the measurement channel.
(4) 1R41D is the setpoint channel; 1R41C is the measurement channel.
(5) The release rate channel 1R41D setpoint value of 2E4 uCi/sec is within the bounds of the concentration setpoint values listed in Table 3.3-6 for normal and accident plant vent flow rates. 3/4.3.3.2 THIS SECTION DELETED 3/4.3.3.3 THIS SECTION DELETED 3/4.3.3.4 THIS SECTION DELETED SALEM -UNIT 1 B 3/4 3-2a TSBC S2013-057 BASES 3/4.3.3.5 REMOTE SHUTDOWN INSTRUMENTATION The OPERABILITY of the remote shutdown instrumentation ensures that sufficient capability is available to permit shutdown and maintenance of HOT STANDBY of the facility from locations outside of the control room. This capability is required in the event control room habitability is lost and is consistent with General Design Criteria 19 of 10 CFR 50. 3/4.3.3.6 THIS SECTION DELETED 3/4.3.3.7 ACCIDENT MONITORING INSTRUMENTATION The OPERABILITY of the accident monitoring instrumentation ensures that sufficient information is available on selected plant parameters to monitor and assess these variables following an accident.
This capability is consistent with the Recommendations of Regulatory Guide 1.97, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident,"
December 1975. 3/4.3.3.8 RADIOACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION The purpose of tank level indicating devices is to assure the detection and control of leaks that if not controlled could potentially result in the transport of radioactive materials to UNRESTRICTED AREAS. 3/4.3.3.9 THIS SECTION DELETED 3/4.3.3.10 THIS SECTION DELETED 3/4.3.3.11 THIS SECTION DELETED 3/4.3.3.12 THIS SECTION DELETED 3/4.3.3.13 THIS SECTION DELETED SALEM -UNIT 1 B 3/4 3-3 Amendment No. 282 (PSEG Issued)
THIS PAGE LEFT INTENTIONALLY BLANK SALEM -UNIT 1 B 3/4 3-3a Amendment No. 282 INSTRUMENTATION BASES 3/4.3.3.14 POWER DISTRIBUTION MONFTORING SYSTEM (PDMS) The Power Distribution Monitoring System (PDMS) provides core monitoring of the limiting parameters.
The PDMS continuous core power distribution measurement methodology begins with the periodic generation of a highly accurate 3-D nodal simulation of the current reactor power distribution.
The simulated reactor power distribution is then continuously adjusted by nodal and thermocouple calibration factors derived from an incore power distribution measurement obtained using the incore movable detectors to produce a highly accurate power distribution measurement.
The nodal calibration factors are updated in accordance with the Surveillance Frequency Control Program.
Between calibrations, the fidelity of the measured power distribution is maintained via adjustment to the calibrated power distribution provided by continuously input plant and core condition information.
The plant and core condition data utilized by the PDMS is cross checked using redundant information to provide a robust basis for continued operation.
The loop inlet temperature is generated by averaging the respective temperatures from each of the loops, excluding any bad data. The core exit thermocouples provide many readings across the core and by the nature of their usage with the PDMS, smoothing of the measured data and elimination of bad data is performed with the Surface Spline fit. PDMS uses the NIS Power Range excore detectors to provide information on the axial power distribution.
Hence, the PDMS averages the data from the four Power Range excore detectors and eliminates any bad excore detector data. The bases for the operability requirements of the PDMS of the accuracy and reliability of the core parameters by the PDMS core power distribution monitor function.
under four categories:
is to provide assurance measured and calculated These requirements fall 1. Assure an adequate number of operable critical sensors.
: 2. Assure sufficiently accurate calibration of these sensors.
: 3. Assure an adequate calibration database regarding the number of data sets. 4. Assure the overall accuracy of the calibration.
The minimum number of required plant and core condition inputs include the following:
: 1. Control Bank,Positions.
: 2. At least 50% of the cold leg temperatures.
: 3. At least 75% of the signals from the power range excore detector channels (comprised of top and bottom detector section)
. 4. Reactor Power Level. 5. A minimum number and distribution of operable core exit thermocouples.
: 6. A minimum number and distribution of measured fuel assembly power distribution information obtained using the incore movable detectors is incorporated in the nodal model calibration information.
The sensor calibration of Items 1, 2, 3, and 4 above are covered under other specifications.
Calibration of the core exit thermocouples is accomplished in two parts. The first being a sensor specific correction to K-type thermocouple temperature indications based on data from a cross calibration of the thermocouple temperature indications to the average RCS temperature measured via the RTDs under isothermal RCS conditions.
The second part of the thermocouple calibration is the generation of thermocouple flow mixing SALEM -UNIT 1 B 3/4 3-4 Amendment No. 299 (PSEG Issued)
INSTRUMENTATION BASES factors that cause the radial power distribution measured via the thermocouples to agree with the radial power distribution from a full core flux map measured using the incore movable detectors.
This calibration is updated in accordance with the Surveillance Frequency Control Program.
The operability requirements previously contained in Specification 3.3.3.2 have been moved to UFSAR Section 7.7.2.8 as part of Amendment 282. 3/4.3.4 DELETED SALEM -UNIT 1 B 3/4 3-5 Amendment No. 299 (PSEG Issued) 3/4.4 REACTOR COOLANT SYSTEM BASES 3/4.4.1 REACTOR COOLANT-LOOPS ANO COOLANT CIRCULATION The plant is designed to operate with all reactor coolant loop* in operation, and meet th* ONB criterion durinq all no:mal operation*
and anticipated tra.nsient.s.
In MoOES 1 and 2 with lass than all coolant loops in operation, this specification requires
.. that the plant be in at least HOT STANDBY within 1 hour. In MOOE 3, a aingl* reactor coolant loop provides a\lfficient heat removal for removing decay heat; but, aingl* failur* considerations r*quire all loops be in operation whenever the rod control system i* energized and at least one loop be in O:p9ration when th* rod control system ia deen*rgized.
In MODE 4, a single reactor coolant loop or :RHR loop provides sufficient heat removal for ramoving decay heat; but, aingle failure considerations require that at least 2 loops be OPERABLE.
'l'hus, if the reactor coolant loops are not OPERABLE, this specification requires that two RHR loops be OPERABLE.
In MODE 5, single failure consideration*
require that two RHR loops bft OPERABLE.
For support systems:
Service Water (SW) and Component Cooling (CC), component redundancy is necessary to ensur* no single active component failure will cause tha loss of Decay Heat One piping path of SW and CC is adequate when it supports both :RHR loops. 'l'he support systems needed before entering into the desired configuration (e.g., one service water loop out for maintenance in Modes 5 and 6) are controlled by procedures, and include the following:
* A requirement that two RHR, two CC and two SW pumps, powered from two different vital buses be kept operable
* A listing of the activa (air/motor operated) valves in the affected flow path to pa locked open or disabled Note that four filled r*actor coolant loops, with at l***t two steam generators with at laaat their secondary aide water l*val greater than or equal to 5% (narrow ranqe), may be substituted for one residual heat removal loop. This ensures that a single failure does not cause a loss of decay heat removal.
The operation of one Reactor Coolant Pump or one RHR Pump provide*
adequate flow to ensure mixing, prevent stratification and produce gradual reactivity changes during Boron concentration reductions in the Reactor' Coolant System. 'l'h* r*activity change rate asaociatad with Boron concentration r*ductions will, therefore, be within the capability of operator recognition and control.
The restriction*
on starting a Reactor Coolant Pump below P-7 with one or more RCS cold legs less than or *qual to 312 vF are provided to pravent RCS pressure transients, caused by energy additions from the secondary which could exceed the limits of Appendix G to lOCFR Part SO. The RCS will be protected against overpressure transients and will not exceed th* limits of Append.ix G by either (1) restricting the water volume in the pressurizer (thereby providing a volume into which the primary coolant can expand, or (2) by restricting the starting of Reactor Coolant Pumps to those times when secondary water temperature in each steam generator is less than SO &deg;F above each of the RCS cold leg temperatur*s.
SALEM -UNIT 1 B 3/4 4-1 Amendment No 21 4 REACTOR COOLANT SYSTEM BASES 3/4.4.2 SAFETY VALVES The pressurizer code safety valves operate to prevent the RCS from being pressurized above its Safety Limit of 2735 psig. Each safety valve is designed to relieve 420,000 pounds per hour of saturated steam at the valve setpoint.
The relief capacity of a single safety valve is adequate to relieve any overpressure condition which could occur during shutdown.
In the event that no safety valves are OPERABLE, an operating RHR loop, connected to the RCS, provides overpressure relief capability and will prevent RCS overpressurization.
In addition, the Overpressure Protection System provides a diverse means of protection against RCS overpressurization at low temperature.
While in Mode 5 the safety valve requirement may be met by establishing a vent path of equivalent relieving capacity when no code safety valves are OPERABLE.
During operation, all pressurizer code safety valves must be OPERABLE to prevent the RCS from being pressurized above its safety limit of 2735 psig. The combined relief capacity of all of these valves is greater than the maximum surge rate resulting from a complete loss of load assuming no reactor trip until the first Reactor Protective System trip setpoint is reached (i.e., no credit is taken for a direct reactor trip on the loss of load)&deg; and also assuming no operation of the power operated relief valves or steam dump valves. Demonstration of the safety valves lift settings will occur only during shutdown and will be performed in accordance with the provisions of Section XI of the ASME Boiler and Pressure Code. Surveillance testing allows a +/- 3% lift setpoint tolerance.
: However, to allow for drift during subsequent operation, the valves must be reset to within +/- 1% of the lift setpoint following testing.
3/4.4.3 RELIEF VALVES The OPERABILITY of the PORVs and block valves is determined on the basis of their being capable of performing the following functions:
A. Manual control of PORVs to control reactor coolant system pressure.
This is a function that is used for the steam generator tube rupture accident and for plant shutdown.
B. Automatic control of PORVs to control reactor coolant system pressure.
This is a function that reduces challenges to the code safety valves for overpressurization events, including an inadvertent actuation of the Safety Injection System. C. Maintaining the integrity of the reactor coolant pressure boundary.
This is a function that is related to controlling identified leakage and the ability to detect unidentified reactor coolant pressure boundary leakage.
SALEM -UNIT 1 B 3/4 4-la Amendment No.244 REACTOR COOLANT SYSTEM BASES ***-************** 3 / 4
* 4 .* 3 .RELIEF VALVES (continued)
D. Manual; control of the block valve to: (1) unblock an* isolated PORV to allow. i . .t be .. used. f<?r ma!1ual and* automatic*
cont:rol;;.of
*Reacto*r Coolant*
System pressure (Items A & B),
(2) a: PORV.
seat leakage (Item C). E. Manual control of a block valve to isolate a stuc;:k-open*
PORV . SALEM -UNIT 1 B 3/ 4 4.-lb .Amendment No. 194 REACTOR COOLANT SYSTEM BASES 3/4.4.4 PRESSURIZER The limit on the maximum water volume in the pressurizer assures that the parameter is maintained within the normal steady-state envelope of operation assumed in the SAR. The limit is consistent with the initial SAR assumptions.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
The maximum water volume also ensures that a steam bubble is formed and thus the RCS is not a hydraulically solid system. The requirement that a minimum number of pressurizer heaters be OPERABLE assures that the plant will be able to establish natural circulation.
3/4.4.5 STEAM GENERATOR (SG} TUBE INTEGRITY The LCO requires that SG tube integrity be maintained.
The LCO also requires that all SG tubes that satisfy the plugging criteria be plugged in accordance with the Steam Generator Program.
During an SG inspection, any inspected tube that satisfies the Steam Generator Program plugging criteria is removed from service by plugging.
If a tube was determined to satisfy the plugging criteria but was not plugged, the tube may still have tube integrity.
In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. Tubes with service-induced flaws located greater than 15.21 inches below the top of the tubesheet do not require plugging.
Tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 15.21 inches below the top of the tubesheet shall be plugged upon detection.
The tube-to-tubesheet weld is not considered part of the tube. A SG tube has tube integrity when it satisfies the SG performance criteria.
The SG performance criteria are defined in Specification 6.8.4.i, "Steam Generator (SG} Program,"
and describe acceptable SG tube performance.
The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.
There are three SG performance criteria:
structural integrity, accident induced leakage, and operational leakage.
Failure to meet any one of these criteria is considered failure to meet the LCO. The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification.
Tube burst is defined as, "The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure}
accompanied by ductile (plastic}
tearing of the tube material at the ends of the degradation."
Tube collapse is defined as, "For the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero." The structural integrity performance criterion provides guidance on assessing loads that significantly affect burst or collapse.
In that context, the term "significant" is defined as, "An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established."
SALEM -UNIT 1 B 3/4 4-2 Amendment No. 309 (PSEG Issued}
BASES 3/4.4.5 STEAM GENERATOR (SG) TUBE INTEGRITY (Continued)
The determination of whether thermal loads are primary or secondary loads is based on the ASME definition in which secondary loads are self-limiting and will not cause failure under single load application.
For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis. The division between primary and secondary classifications will be based on detailed analysis and/or testing.
Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code, Section III, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification.
This includes safety factors and applicable design basis loads based on ASME Code, Section III, Subsection NB and draft Reg. Guide 1.121. The accident induced leakage performance criterion ensures that the to-secondary leakage caused by a design basis accident, other than a steam generator tube rupture (SGTR), is within the accident analysis assumptions.
The accident analysis assumes that accident induced leakage does not exceed 1 gpm per SG. The accident induced leakage rate includes any primary-to-secondary leakage existing prior to the accident in addition to primary-to-secondary leakage induced during the accident.
The operational leakage performance criterion provides an observable indication of SG tube conditions during plant operation.
The limit on operational leakage is contained in LCO 3.4.6.2, "Operational Leakage,"
and limits secondary leakage through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of leakage is due to more than one crack, the cracks are very small, and the above assumption is conservative.
The ACTION requirements are modified by a Note clarifying that the Actions may be entered independently for each SG tube. This is acceptable because the ACTION requirements provide appropriate compensatory actions for each affected SG tube. Complying with the ACTION requirements may allow for continued operation, and subsequent affected SG tubes are governed by subsequent ACTION requirements.
If it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube plugging criteria but were not plugged inaccordance with the Steam Generator
.Program, an evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program.
The SG plugging criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection.
The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next SG tube inspection.
An action time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SALEM -UNIT 1 B 3/4 4-3 Amendment No. 309 (PSEG Issued)
REACTOR COOLANT SYSTEM BASES 3/4.4.5 STEAM GENERATOR (SG) TUBE INTEGRITY (Continued)
SG tube that may not have tube integrity.
If the evaluation determines that the affected tube(s) have tube integrity, plant operation is allowed to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes. However, the affected tube(s) must be plugged prior to entering HOT SHUTDOWN following the next refueling outage or SG inspection.
This action time is acceptable since operation until the next inspection is supported by the operational assessment.
If SG tube integrity is not being maintained or the ACTION requirements are not met, the reactor must be brought to HOT STANDBY within 6 hours and COLD SHUTDOWN within 36 hours. The action times are reasonable based on operating experience, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.
During shutdown periods the SGs are inspected as required by surveillance requirements and the Steam Generator Program.
NEI 97-06, "Stearn Generator Program Guidelines,"
and its referenced EPRI Guidelines, establish the content of the Stearn Generator Program.
Use of the Stearn Generator Program ensures that the inspection is appropria.te and consistent with accepted industry practices.
During SG inspections a condition monitoring assessment of the SG tubes is performed.
The condition monitoring assessment determines the "as found" condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period. The Stearn Generator Program deterrni.nes the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube plugging criteria.
Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations.
The Stearn Generator Program also specifies the inspection methods to be used to find existing and potential degradation.
Inspection methods are a function of degradation morphology, nondestructive examination (NDE) technique capabilities and inspection locations.
The Frequency is determined by the operational assessment and other limits in the SG examination guidelines.
The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection.
In addition, Specification 6.8.4.i contains prescriptive requirements concerning inspection intervals to provide added.assurance that the SG performance criteria will be met between scheduled inspections.
If crack indications are found in any SG tube, the maximum inspection interval for all affected and potentially affected SGs is restricted by Specification 6.8.4.i until subsequent inspections support extending the inspection interval.
During an SG inspection, any inspected tube that satisfies the Stearn Generator Program plugging criteria is removed from service by plugging.
The tube plugging criteria delineated in Specification 6.8.4.i are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in size measurement and future growth. In addition, the tube plugging
: criteria, in conjunction with other elements of the Stearn Generator
: Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s).
NEI 97-06 provides guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.
The Frequency of prior to entering HOT SHUTDOWN following a SG inspection SALEM -UNIT 1 B 3/4 4-4 Amendment 309 (PSEG Issued)
REACTOR COOLANT SYSTEM BASES 3/4.4.5 STEAM GENERATOR (SG) TUBE INTEGRITY (Continued) ensures that the Surveillance has been completed and all tubes meeting the plugging criteria are plugged prior to subjecting the SG tubes to significant primary-to-secondary pressure differential.
3/4.4.6 REACTOR COOLANT SYSTEM LEAKAGE 3/4.4.6.1 LEAKAGE DETECTION SYSTEMS The RCS leakage detection systems required by this specification are provided to monitor and detect leakage from the Reactor Coolant Pressure Boundary.
These detection systems are consistent with the recommendations of Regulatory Guide 1.45, "Reactor Coolant Pressure Boundary Leakage Detection Systems",
May 1973. 3/4.4.6.2 OPERATIONAL LEAKAGE Industry experience has shown that while a limited amount of leakage is expected from the RCS, the unidentified portion of this leakage can be reduced to a threshold value of less than 1 GPM. This threshold value is sufficiently low to ensure early detection of additional leakage.
The 10 GPM IDENTIFIED LEAKAGE limitation provides allowance for a limited amount of leakage from known sources whose presence will not interfere with the detection of UNIDENTIFIED LEAKAGE by the leakage detection systems.
PRESSURE BOUNDARY LEAKAGE of any magnitude is unacceptable since it may be indicative of an impending gross failure of the pressure boundary.
Therefore, the presence of any PRESSURE BOUNDARY LEAKAGE requires the unit to be promptly placed in COLD SHUTDOWN.
Primary-to-Secondary Leakage Through Any One SG The primary-to-secondary leakage rate limit applies to leakage through any one Steam Generator.
The limit of 150 gallons per day per steam generator is based on the operational leakage performance criterion in NEI 97-06, Steam Generator Program Guidelines.
The Steam Generator Program operational leakage performance criterion in NEI 97-06 states, "The RCS operational primary-to-secondary leakage through any one SG shall be limited.to 150 gallons per day." The limit is based on operating experience with steam generator tube degradation mechanisms that result in tube leakage.
The operational leakage rate criterion in conjunction with the implementation of the Steam Generator program is an effective measure for minimizing the frequency of steam generator tube ruptures.
Actions Unidentified leakage or identified leakage in excess of the LCO limits must be reduced to within limits within 4 hours. This action time allows time to verify leakage rates and either identify unidentified leakage or reduce leakage to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the reactor coolant pressure boundary (RCPB). If any pressure boundary leakage exists, or primary-to-secondary leakage is not within limit, or if unidentified or identified leakage cannot be reduced to within limits within 4 hours, the reactor must be brought to lower pressure conditions to reduce the severity of the leakage and SALEM -UNIT 1 B 3/4 4-4a Amendment No. 309 (PSEG Issued)
REACTOR COOLANT SYSTEM BASES 3/4.4.6.2 OPERATIONAL LEAKAGE (Continued) its potential consequences.
It should be noted that leakage past seals and gaskets is not pressure boundary leakage.
The reactor must be brought to HOT STANDBY within 6 hours and COLD SHUTDOWN within 36 hours. This action reduces the leakage and also reduces the factors that tend to degrade the pressure boundary.
The action times reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
In COLD SHUTDOWN, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely. Surveillances Verifying RCS leakage to be within the LCO limits ensures the integrity of the Reactor Coolant Pressure Boundary is maintained.
Pressure boundary leakage would.at first appear as unidentified leakage and can only be positively identified by inspection.
It should be noted that leakage past seals and gaskets is not pressure boundary leakage.
Unidentified leakage and identified leakage are determined by performance of an RCS water inventory balance.
The RCS water inventory must be met with the reactor at steady state conditions.
The surveillance is modified by a Note that the surveillance is not required to be performed until 12 hours after establishing steady state operation.
The 12 hour allowance provides sufficient time to collect and process all necessary data after stable plant conditions are established.
Steady state operation is required to perform a proper inventory balance since calculations during maneuvering are not useful. For RCS operational leakage determination by water inventory
: balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and Reactor Coolant Pump seal injection and return flows. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Mode ascension to MODE 1-3 is acceptable without a current RCS Inventory
: Balance, provided the asterisked note of "Not required to be completed until 12 hours after establishment of steady state operations",
is complied with. Satisfying the primary-to-secondary leakage limit ensures that the operational leakage performance criterion in the Steam Generator Program is met. If SR 4.4.6.2.c is not met, compliance with LCO 3.4.5, Generator Tube Integrity,"
should be evaluated.
The 150 gallons per day limit is measured at room temperature (in accordance with EPRI PWR Primary-to-Secondary Leak Guidelines).
If it is not practical to assign the leakage to an individual steam generator, all the primary-to-secondary leakage should be conservatively assumed to be from one Steam Generator.
The Surveillance is modified by a Note which states that the surveillance is not required to be performed until 12 hours after establishment of steady state operation.
For RCS secondary leakage determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and Reactor Coolant Pump seal injection and return flows. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
The primary-to-secondary leakage is determined using continuous process radiation monitors or radiochemical grab sampling (in accordance with EPRI PWR Primary-*to-Secondary Leak Guidelines)
. 3/4.4.7 THIS SECTION DELETED SALEM -UNIT 1 B 3/4 4-4b Amendment No. 299 (PSEG Issued)
REACTOR COOLANT SYSTEM BASES 3/4.4.B SPECIFIC ACTIVITY The limitations on the specific activity of the primary coolant ensure that the resulting 2 hour doses at the site boundary will not exceed an appropriately small fraction of Part 100 limits following a steam generator tube rupture accident in conjunction with an assumed steady state secondary steam generator leakage rate of 1.0 GPM. The values for the limits on specific activity represent interim limits based upon a parametric evaluation by the NRC of typical site locations.
These values are conservative in that specific site parameters of the Salem site, such as site boundary location and meteorological conditions, were not considered in this evaluation.
The NRC is finalizing site specific criteria which will be used as the basis for the reevaluation of the specific activity limits of this site. This reevaluation may result in higher limits. Reducing Tavg to <500&deg;F prevents the release of activity should a steam generator tube rupture occur since the saturation pressure of the primary coolant is below the lift pressure of the atmospheric steam relief valves. The surveillance requirements provide adequate assurance that excessive specific activity levels in the primary coolant will be detected in sufficient time* to take corrective action. Information obtained on iodine spiking will be used to assess the parameters associated with spiking phenomena.
A reduction in frequency of isotopic analyses following power changes may be permissible if justified by the data LCO 3.0.4,c is applicable.
This allowance permits entry into the applicable MODE ( S) while relying on the ACTIONS, SALEM -UNIT 1 B 3/4 4-5 Amendment No.276 REACTOR COOLANT SYSTEM BASES 3/4.4.9 PRESSURE/TEMPERATURE LIMITS The temperature and pressure changes during heatup and cooldown are limited to be consistent with the requirements given in the ASME Boiler and Pressure Vessel Code, Section XI, Appendix G. 1} The reactor coolant temperature and pressure and system heatup and cooldown rate (with the exception of the pressurizer}
shall be limited in accordance with Figures 3.4-2 and 3.4-3 for the service period specified thereon.
a) Allowable combinations of pressure and temperature for specific temperature change rates are below and to the right of the limit lines shown. Limit lines for cooldown rates between those presented may be obtained by interpolation.
bl. Figures 3.4-2 and 3.4-3 define limits to assure prevention of nondoctile failure only. For normal operation, other inherent plant characteristics, e.g., pump heat addition and pressurizer heater capacity, may limit the heatup and cooldown rates that can be achieved over certain pressure-temperature ranges. 2) These limit lines shall be calculated periodically using methods provided below. 3) The secondary side of the steam generator must not be pressurized above 200 psig if the temperature of the steam generator is below 70&deg;F. 4) The pressurizer heatup and cooldown rates shall not exceed 100&deg;F/hr and 200&deg;F/hr, respectively.
The spray shall not be used if the temperature difference between the pressurizer and the spray fluid is greater than 320&deg;F. 5) System preservice hydrotests and in-service leak and hydrotests shall be performed at pressures in accordance with the requirements of ASME Boiler and Pressure Vessel Code, Section XI. The fracture toughness properties of the ferritic materials in the reactor vessel are determined in accordance with the NRC Standard Review Plan, ASTM El85-82, and in accordance with additional reactor vessel requirements.
These properties are then evaluated in accordance with Appendix G of the 1996 Summer Addenda to Section XI of the ASME Boiler and Pressure Vessel Code and the calculation methods described in WCAP-14040-NP-A, Rev. 2, "Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves",
January 1996, and ASME Boiler and Pressure Vessel Code Case N-640, "Alternative Reference Fracture Toughness for Development of P-T Limit Curves for Section XI, Division l", approved March 1999. Heatup and cooldown limit curves are calculated using the most limiting value of the nil-ductility reference temperature, RTNor* at the end of 32 effective full power years of service life. The 32 EFPY service life period is chosen such that the limiting RTNor at the 1/4T location in the core region is greater than the of the limiting unirradiated material.
The selection of such a --limiting assures that all components in the Reactor Coolant System will be operated conservatively in accordance with applicable Code requirements.
SALEM -UNIT 1 B 3/4 4-6 Amendment No. 243 I REACTOR COOLANT SYSTEM BASES The reactor vessel materials have been tested to determine their initial RTNM'; the results of these tests are shown in Table B 3/4.4-1.
Reactor operation and resultant fast neutron (E greater than 1 MeV) irradiation can cause an increase in the RTHDT. An adjusted reference temperature, (ART), based upon the fluence and the copper and nickel content of the material in question, can be predicted.
The ART is based upon the largest value of RTMDT computed by the methodology*
presented in Regulatory Guide 1.99, Revision
: 2. The ART for each material is given by the following expression:
ART = Initial RTllt11'
+ MlTNDT + Margin Initial RTNM' is the reference temperature for the unirradiated material.
is the mean value of the adjustment in reference temperature caused by the irradiation and is calculated as follows:
.1RTllDT a Chemistry Factor x Fluence Factor The Chemistry Factor, CF(F), is a function of copper and nickel content.
It is given in Table BJ/4.4-2 for welds and in Table B3/4.4-3 for base metal (plates and forgings).
Linear interpolation is permitted.
The predicted neutron fluence as a function of Effective Full Power Years . {EFPY) has been calculated and is shown in Figure B3/4.4-l.
The fluence factor can be calculated by using Figure B3/4.4-2.
Also, the neutron fluence at any depth in the vessel wall is determined as follows:
f * (f surface) x (e-0*2'x) where "f surface" is from Figure B3/4.4-l, and X (in inches) is the depth into the vessel wall.
the "Margin" is the quantity in &deg;F that is to be added to obtain conservative, upper-bound values of adjusted reference temperature for the calculations required by Appendix G to 10 CFR Part 50. * * [27 Margin = 2Vu1 Tu .6 If a measured value of initial RTNDT for the material in question is used, aI may be taken as zero. If generic value.of initial RTllD'l'is used, a1, should be obtained from the same set of data. The standard deviations, for MlTNllT, aA, are 28&deg;F for welds and 17&deg;F for base metal, except that need not exceed o.so*times the mean value of surface.
The heatup and cooldown limit curves of Figures 3.4-2 and 3.4-3 include predicted adjustments for this shift in RTNM' at the end of 32 EFPY. SALEM -UNIT 1 B 3/4 4-7 Amendment No. 243 I REACTOR COOLANT SYSTEM BASES Values of ARTimr determined in this manner may be used until the results from the material surveillance
: program, evaluated according to ASTM ElBS, are available.
Capsules will be removed in accordance with the requirements of ASTM El.85-82 and 10 CFR Part SO, Appendix H. The heatup and cooldown curves must be recalculated when the ARTllD'r determined from the surveillance capsule exceeds the calculated L\RTllD'r for the equivalent capsule radiation exposure.
Allowable pressure-temperature relationships for various heatup and'cooldown rates are calculated using methods derived from Appendix G in Section XI of the ASME Boiler and Pressure Vessel Code as required by Appendix G to l.O CFR Part so and these methods are discussed in detail in WCAP-14040-NP-A, Rev. 2, ''Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit curves",
January 1996, and ASME Boiler and Pressure Vessel Code Case N-640,
* Alternative Reference Fracture Toughness for Development Of P-T Limit curves for Section XI, Division 1w I approved March 1999. The general method for calculating heatup and cooldown limit curves is based upon the principles of the linear elastic fracture mechanics (LEFM) technology.
In the calculation procedures a semi-elliptical surface defect with a depth. of one-quarter of the wall thickness, T, and a length of 3/2T is assumed to exist at the inside of the vessel wall as well as at the outside of* the vessel wall. The dimensions of this postulated crack, referred to in Appendix G of ASME Section XI as the reference flaw, amply exceed the current capabilities of inservice inspection techniques.
Therefore, the reactor operation limit curves developed for this reference crack are conservative and provide sufficient safety margins for protection against nonductile failure.
To assure that the radiation embrittlement effects are accounted for.in the calculation of the limit curves, the most limiting value of the nil-ductility reference temperature, RTii!7r, is used and this includes the radiation induced shift, 6.RTNllT corresponding to the end of the period for which heatup and cooldown curves are generated.
The ASME approach for calculating the allowable limit curves for various heatup and cooldown rates specifies that the total stress intensity factor, K1, for the combined thermal and pressure stresses at any time during heatup or cooldown.
cannot be greater than the reference stress intensity factor, K1c, for the metal temperature at that time. K1c is obtained from the reference fracture toughness curve, defined in ASME Code Case N-640. The K1c curve is given by the equation:
K1c
* 33.2 + 20.734 exp [0.02(T-RT1117r)]
(l)
* where K1c is the reference stress intensity factor as a function of the metal temperature T and the metal nil-ductility reference temperature RT1117r.
Thus, the _governing eq&#xb5;at;:ion for Cl!Ullysis defined in Appendix G of the ASME Code as follows:
(2) SALEM -UNIT 1 B 3/4 4-8 Amendment No. 243 ---
REACTOR COOLANT SYSTEM BASES where K1" is the stress intensity factor caused by membrane (pressure) stress. K1T is the stress intensity factor caused by the thermal gradients.
K1e is.provided by the code as a function of temperature relative to the RTimr of the material.
c 2.0 for level A and B service limits, and C = 1.5 for inservice hydrostatic and leak test operations.
At any time during the heatup or cooldown transient, K1e is determined by the metal temperature at the tip of the postulated flaw, the appropriate value for RTNDT, and the reference fracture toughness
*curve. The thermal stresses resulting from temperature gradients through the vessel wall are calculated and then the corresponding (thermal) stress intensity
: factors, K1T, for the reference flaw are computed.
From Equation (2) the pressure stress intensity factors are obtained and from these the allowable pressures are calculated.
COOLDOWN For the calculation of the allowable pressure versus coolant temperature during cooldown, the Code reference flaw is assumed to exist at the inside of the vessel wall. During cooldown, the controlling location of the flaw is always at the inside of the wall because the thermal gradients produce tensile stresses at the inside, which increase with increasing cooldown rates. Allowable pressure-temperature relations are generated for both steady-state and finite cooldown rate situations.
From these relations composite limit curves are constructed for each cooldown rate of interest.
The use of the composite curve in the cooldown analysis is necessary because control of the cooldown procedure is based on measurement of reactor coolant temperature, whereas the limiting pressure is actually dependent on the material temperature at the tip of the assumed flaw. During cooldown, the l/4T vessel location is at a higher temperature than the fluid adjacent to the vessel ID. This condition, of course *. is not true for the steady-sta_te situation.
It follows that at any given reactor coolant temperature, the developed during cooldown results in a higher value of K1e at the l/4T location for finite cooldown rates than for steady-state operation.
Furthermore, if conditions exist such that the increase in Klc exceeds KlT* the calculated allowable pressure during cooldown will be greater than the state value. The above procedures are needed because there is no direct control on temperature at the l/4T location, therefore, allowable pressures may unknowingly be violated if the rate of cooling is decreased at various intervals along a cooldown ramp. The use of the composite curve eliminates this problem and assures conservative operation of the system for the entire cooldown period. SALEM -UNIT l B 3/4 4-.9 Amendment No. 243 l REACTOR COOLANT SYSTEM BASES HEATUP Three separate calculations are required to determine the limit curves for finite heatup rates. As is done in the cooldown allowable temperature relationships are developed for steady-state conditions as well as finite heatup rate conditions assuming the presence of a l/4T defect at the inside of the vessel wall. The thermal gradients during heatup produce compressive stress at the inside of the wall that alleviate the tensile stresses produced by internal pressure.
The metal temperature at the crack tip lags the coolant temperature therefore, the K1c for the l/4T crack during I heatup is lower than the K1cfor the l/4T crack during steady-state conditions at the same coolant temperature.
During heatup, especially at the end of the transient, conditions may.exist such that the effects of compressive thermal stresses and different K1cS for steady-state and finite heatup rates do not I offset each other and the pressure-temperature curve based on steady-state conditions no longer represents a
bound of all similar curves for finite heatup rates when the l/4T flaw is considered.
Therefore, both cases have to be analyzed in order to assure that at any coolant temperature the lower value of the allowable pressure calculated for steady-state and finite heatup rates is obtained.
The second portion of the heatup analysis concerns the calculation of pressure-temperature limitations for the case in which a l/4T deep outside surface flaw is assumed.
Unlike the situation at the vessel inside surface, the thermal gradients established at the outside surface during heatup produce stresses which are tensile in nature and thus tend to reinforce any pressure stresses present.
These thermal stresses, of course, are dependent on poth the rate of heatup and the time (or coolant temperature) along the heatup ramp. Furthermore, since the thermal stresses, at the outside are tensile and increase with increasing heatup rate, a lower bound curve cannot be defined.
Rather, each heatup rate of interest must be analyzed on an individual basis. Following the generation of pressure-temperature curves for both the state and finite heatup rate situations, the final limit curves are produced as follows.
A composite curve is constructed based on a point-by-point
.
* comparison of the steady-state and finite heatup rate data. 'At any given temperature, the allowable pressure is taken to be the lesser of the three values* taken from the curves under consideration.
The use of the composite curve is necessary to set conservative heatup
* limitations because it is possible for conditions to exist such that over the course of the heatup ramp the controlling condition switches from the inside to the outside and the pressure limit must at all times be based on analysis of the most critical criterion.
SALEM -UNIT l B 3/4 4-10 Amendment No. 243 ---
REACTOR COOLANT SYSTEM BASES Finally, the new 10CFR50 rule which addresses the metal temperature of the closure head flange is considered.
This 10CFR50 rule states that the metal temperature of the closure flange regions must exceed the material RTNoT by at least 120&deg;F for normal operation when the pressure exceeds 20 percent of the preservice hydrostatic test pressure (621 psig for Salem). Table B3/4 4-1 indicates that the limiting RTwoT of 28&deg;F occurs in the closure head flange of Salem 1, and the minimum allowable of.this region is 14B&deg;F at pressures greater than 621 psig, These limits do not affect Figures 3.4-2 and 3.4-3. Although the pressurizer operates in temperature ranges above those for which there is reason for concern of non-ductile
: failure, operating limits are provided to assure compatibility of operation with the fatigue analysis performed in accordance with the ASME Code requirements.
The OPERABILITY of two POPS or an RCS vent opening of greater than 3.14 square inches ensures that the RCS will be protected from pressure transients which could exceed the limits of Appendix G to 10 CFR Part 50 when one or more of the RCS cold legs are less .than or equal to 312&deg;F. Either POPS has adequate relieving capability to protect the RCS from overpressurization when the transient is limited to either (1) the start of an idle RCP with the secondary water temperature of the steam generator less than or equal to 50&deg;F above the RCS cold leg temperatures, or (2) the start of an intermediate head safety injection pump and its injection into a water solid RCS, or the start of a high head safety injection pump in conjunction with a running positive displacement pump and its injection into a water solid RCS. The minimum electrical power sources required to assure POPS operability (based on POPS meeting the single failure criteria) consist of a normal (via offsite power) and an emergency (via batteries) power source for each train of POPS. Emergency diesel generators are not required for POPS to meet single failure . criteria and therefore are not required for POPS OPERABILITY.
LCO 3.0.4.b is not applicable to an inoperable LTOP system when entering MODE 4. There is an increased risk associated with entering MODE 4 from MODE 5 with an inoperable LTOP system. The provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
SALEM -UNIT 1 B 3/4 4-11 Amendment No.276 TABLE B 3/4.4-1 SALEH UNIT 1 REACTOR VESSEL TOUGHNESS DATA Plate No. or Weld Hateridl Cu T Component No. Type (%) Ni('iJ ("F) Cl Hd Dome 82407-1 A5338, Cl.l 0.20 0.50 -30 Cl Hd Seqment 82406-1 A5338. Cl.l 0.13 0.52 -20 Cl Hd Seqment 82406-2 A533B, Cl.l 0.16 0.50 -30 Cl Hd Seqment 82406-3 A533B, Cl.1 o, 10 0.53 -50 Cl Hd Flanqe 82811 A508 Cl.2 -0.12 28* Vessel Flanqe 82410 A508, Cl.2 -0.61 60* Inlet Nozzle 82408-1 A508, Cl.2 -0.68 50* Inlet Nozzle 82408-2 A508. Cl. 2 -0.71 46* Inlet Nozzle 82408-3 A508. Cl.2 -0.66 41* Inlet Nozzle 82408-4 A508. Cl.2 -0.65 9* Outlet Nozzle B2409-l A508. Cl.2 -0.69 60* Outlet Nozzle 82409-2 A508. Cl.2 -0.69 60* Outlet Nozzle B2409-3 A508, Cl.2 -0. 74 60* Outlet Nozzle B2409-4 A508 Cl.2 -0.74 60* Uooer Shell B2401-l A533B Cl.l 0.22 0.48 -30 Uooer Shell B2401-2 A5338, Cl.l 0.19 o. 48 0 Uooer Shell B2401-3 A533B.* Cl.l 0.24 0.51 -10 Inter Shell B2402-l A533B. Cl.1 0.24 0.53 -30 Inter Shell 82402-2 A533B. Cl. l 0.24 0.53 -30 Inter Shell 82402-3 A5338, Cl. l 0.22 0.51 -40 Lower Shell 82403-1 A5338, Cl.1 0.19 0.48 -40 Lower Shell B2403-2 A533B, Cl.1 0.19 0.49 -70 Lower Shell B2403-3 A533B Cl.l 0.19 0.48 -40 Bot Hd Seament B2404-l A533B. Cl.l 0.10 0.52 10 Bot Hd Se,,,.,..nt B2404-2 A533B Cl. l 0.11 0.53 -so Bot Hd Seament 82404-3 A533B. Cl.l 0.12 0.52 10 Bot Hd Dome 82405-1 A533B. Cl.l 0.15 0.50 -20 Circum Weld Bet 8-042 -0.22 1.02 -Nozzle Shell ' Int. Shell Circum Weld 9-042 -0.22 0.73 -Bet. Int. and Lower Shell Int. Shell 2-042 -0.18 1.04 -Vertical Weld tA.B.Cl Lower Shell 3-042 -0.19 1.04 -Vertical Weld (A,8,C] * *** Estimated per NRC Standard Review Plan Section 5.3.2 . Estimated per Pressurized Thermal Shock Rule, 10 CFR 50.61 50 ft lb 35-Mil Temp ("Fl 99* 89* 95* 66* 22* o* 43* 26* 31* '11* 95* 95* 10* 13* 87* 80* 114* 105 55 57 70 86 90 48* 60* 47* 57* ----SALEH -UNIT l B 3/4 4-12 RT (&deg;F) 39 29 25 6 28 60 50 46 47 9 60 60 60 60 27 20 34 45 3 4 18 6 10 0 10* 56*** -56*** -56*** -56*** Average Upper Shelf Enerav Nox-mal to Principal Working Principal Working Direction (ft-lb) Direction (ft-lb) 71. 5* 110 97* 125 19* 122 86* 132 129* 199 94* 145 94* 144 102* 157 105* 161 108.5* 167 48* 75 51* 78 79* 121 82* 126 74* 114 79* 122 62* 96 91 97 98 112 104 127 93 143 83 128 85 131 78* 120 86* 132 82* 126 69* 106 --112 -96.2 -112 -I Amendlllent No. 243 TABLE B 3/4.4.2 IACl'OI N llLDS, *r ' Copper, Wt.-1 ....L LE U2 l:J2 0 IO IO IO to IO IO to 0.01 . to ., ., IO IO to IO o.m 21 II 'Z1 'Z1 2'7 21 2'7 0.03 22 31 41 41 41 41 41 0.04 14 4S " " " " " CLOS II 41 ., II .. .. .. o.oe
* II 17 It n ..12 n 0.07 32 55 II II N u u o.oe M II IO 108 lQI 1QI IQI 0.09 40 11 "' 115 122 122 122 0.10 " II t7 122 133 131 131 0.11 49 .. 101 130 144 141 141 0.12 12 72 103 135 113 111 111 0.13 II 11 IOI 111 112 112 171 0.14 11 71 lOI 142 111 112 111 0.15 H 14 112 141 171 191 200 0.1& 10 u 115 141 171 199 211 0.17 '15 92 111 151 lN 207 221 0.11 '11 95 122 154 117 214 230 0.10 13 100 121 157 191 220 231 0.20 u ICM 129 190 IN 223 245 0.21 t2 IOI 133 lM 197 229 252 0.22 11 112 13'1 187 -232 257 0.23 101 117 140 lH 203 231 213 0.24 105 121 144 173 :aoe 230 281 0.25 110 121 141 179 309 143 2'72 o.2e 113 130 111 llO 212 NI 218 0.2'7 111 13' 111 114 211 241 2IO 0.21 122 131 110 11'1 211 251 2M 0.29 121 1'2 lM 1111 222 IN 217 o.ao 131 141 117 1N 225 217 2QO 0.31 131 111 1'12 111 *321 2IO 293 0.32 HO 111 171 a 231 213 2H 0.33 1'* 110 llO a 234 HS 290 0.3-& 141 lM 114 209 231 2151 302 0.36 153 lU 117 212 241 212 305 *0.31 151 172 111 . 218 245 275 308 0.37 112 117 IH 220 241 271 311 0.31 111 112 223 250 281 314 0.31 111 111 203 227 IN us 317 0.40 175 119 to'7 231 217 211 320 SALEM UNIT 1 11 3/1. !.*13 Amendment No. 108 TABLE B 3/4.4-3 mDaSTIY flc:rol POI IAll Ml!AL, *r o..,,a.,
Jt:I -2.. U2 UR 1..E 0 IO IO IO IO IO IO IO 0.01 IO IO IO IO IO IO to O.OI IO IO IO to IO IO to 0.03 ao to to IO to IO to O.Of 22 28 21 28
* 28 28 o.*
* 11 11 31 11 11 11 o.oe 21 rt S'I ST 11 *n n 0.07 31 '3 " " " " " o.oe u " 11 11 11 11 11 0.09 17 63 II II II II II 0.10 41 II ag 85 .., .., f7 0.11 41 82 T2 74 .,, .,, rt 0.12 49 17 79 13 .. .. .. 0'.13 13 71 u 11 II * " O.H 17 75 11 100 106 IOI IOI 0.11 11 IO " 110 111 117 UT 0.11 es " 106 111 123 121 0.17 ff .. 110 12'7 132 136 13& 0.11 73 12 us 134 141 144 1'6 0.19 11 97 . llO 142 1IO lU 15" I 0.20 102 121 149 159 1M 116 0.21
* 107 121 165 111 112 174 0.22 tl 112 13" 111 171 111 114 0.23
* 117 131 187 114 110 IN 0.3-6 100 121 143 172 191 Ht 304 0.21 104 128 1'8 1'11 199 IOI 21.& 0.28 108 130 111 llO aD6 218 221 0.2'7 114 134 155 114 211 221 230 0.11 111 131 110 111 211 m In 0.21 U4 lG 1M 111 221 241 241 0.30 129 141 117 lN 221 141 117 0.11 114 111 172 111 -Ill -0 . .12 139 111 171 -tsl -2'7-6 o.* 1'6 110 110 IOI
* IN tn O.M HI lM 114 -m .. 290 0.11 113 161 11'7 212 241 2'72 .. o.ae 111 173 111 211 141 271 -0.31 112 1'1'7 lN no 241 271 -0.31 lM 112 IOO m 2IO 211 313 0.39 171 111 -227 2N -311 0.60 175 lit 207 231 U7 -no SALEM UNIT 1 B 3/4 4*14 Amendment No. 108 1.0E+20 1.0E+19 -N E 0 -c: -CD 0 c Q) v ::I u: c: 0 ...... I ...... ::> Q) z 1.0E+18 / I I I 1.0E+17 0 5 Figure B 3/4.4-1 SALEM -UNIT 1 1--""" i.--_!---"" .JI" -/" Fluence at Vessel Inner Radius 45&deg; Azimuth 10 15 20 25 30 Service Life (Effective Full Power Years) Fast neutron f luence (E>lMeV) as a function of full power service life (EFPY) 35 B 3/4 4-15 Amendment No. 243
* en > t"' t>:I ::i: c 2l H t-:J ..... b:l w ........ I I-' O' &sect;' Cl) ::s 0.. 3 Cl) *::s c-i" 2 0 . 1* ( J 0 j Cl .: 0 t> * .... I ...._., n/CJA1II>1 Mevt ( Fluence factor for use in the expression for.ll.RTNDT FIGURE 8 3/4 4-2 ..
REACTOR COOLANT SYSTEM BASES 3/4.4.10 DELETED 3/4.4.11 THIS SECTION INTENTIONALLY BLANK 3/4.4.12 REACTOR VESSEL HEAD VENTS Reactor Coolant System vents are provided to exhaust noncondensible gases and/or steam from the Reactor Coolant System that could inhibit natural circulation core cooling.
The OPERABILITY of a reactor vessel head vent path ensures the capability exists to perform this function.
The valve redundancy of the Reactor Coolant System vent paths serves to minimize the probability of inadvertent or irreversible actuation while ensuring that a single failure in a vent valve power supply or control system does not prevent isolation of the vent path. The function, capabilities, and testing requirements of the Reactor Coolant System Vent Systems are consistent with the requirements of Item II.Bl of NUREG-0737, "Clarification of TMI Action Plan Requirements,"
November 1980. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Correction lettr dated February 15, 1990, to Amendment 108 dated January 29, 1990. SALEM UNIT 1 B 3/4 4-17 Amendment No. 299 (PSEG Issued) 3/4,5 EMERGENCY CORE COOLING SYSTEMS BASES 3/4.5.1 ACCUMULATORS The OPERABILITY of e.ach RCS accumulator ensures that a sufficient volume of borated water will be immediately forced into the reactor core through each of the cold legs in the event the RCS pressure falls below the pressure of the accumulators.
This initial surge of water into the core provides the initial cooling mechanism during large RCS pipe ruptures.
The limits on accumulator volume, boron concentration and pressure ensure that the assumptions used for accumulator injection in the safety analysis are met. The accumulator power operated isolation valves are considered to be "operating bypasses" in the context 0&#xa3; IEEE Std. 279-1971, which requires that bypasses of a protective function be removed automatically whenever permissive conditions are not met. In addition, as these accumulator isolation valves fail to meet single failure criteria, removal of power to the valves is required.
The limits for operation with an accumulator inoperable for any reason except an isolation valve closed minimizes the time. exposure of the plant to a LOCA event occurring concurrent with fai'lure of an additional accumulator which may result in unacceptable peak cladding temperatures.
If a closed isolation valve cannot be immediately opened, the full capability of one accumulator is not available and prompt action is required to place the reactor in a mode where this capability
.is not required.
3/4.5.2 and 3/4.5.3 ECCS SUBSYSTEMS The OPERABILITY of two independent ECCS subsystems ensures that sufficient emergency core cooling capability will be available in the event of a LOCA assuming the loss of one subsystem
*through any single failure consideration
.. Either subsystem operating in conjunction with the accumulators
*is capable of supplying sufficient core cooling to limit the peak cladding
*temperatures*
within acceptable limits for all postulated break sizes ranging from the double ended break of the largest RCS cold leg pipe downward.
In addition, each ECCS subsystem provides long term core cooling capability in the recirculation mode during the accident recovery period. The limitation for a maximum of one safety injection pump or centrifugal charging pump to be OPERABLE and the Surveillance Requirement to verify all safety injection pumps except the allowed OPERABLE pump to be inoperable below 312&deg;F provides assurance that a mass addition pressure transient can be relieved by the operation of a single POPs relief valve. When running a safety injection pump with the RCS temperature less than 312 &deg;F with the potential for injecting into the RCS and creating a mass addition pressure transient, two independent means of preventing reactor coolant system injection will be utilized.
The two independent means can be satisfied by any one of the following methods.:
{1} A manual isolation valve locked in the closed position; or (2) Two manual isolation valves closed; or _ (3) One motor operated valve closed and its breaker de-energized and control circuit fuses removed; or (4) One air operated valve closed and its air supply maintained in such a manner as to ensure that the valve will remain closed. SALEM -UNIT 1 B 3/4 5-1 . TSBC SCN 06-030 EMERGENCY CORE COOLING SYSTEMS BASES ECCS SUBSYSTEMS (Continued)
With the RCS temperatu.re below 350&deg;F, one OPERABLE ECCS subsystem is acceptable without single failure consideration on the basis of the stable reactivity condition of the reactor and the limited core cooling The surveillance requirements, which are provided to ensure the OPERABILITY of each component, ensure that, at a minimum, the-assumptions used in the safety analysis are met and that subsystem OPERABILITY is maintained.
The safety analyses make assumptions with respect to: 1) both the maximum and minimum total system resistance, and 2) both the maximum and minimum branch injection line resistance..
These resistances, in conjunction with the ranges of potential pump performance, are used to calculate the maximum and minimum ECCS flow assumed in the safety analyses.
The maximum and minimum flow surveillance requirements in conjunction with the maximum and minimum pump performance curves ensures that the assumptions of total system resistance and the distribution of that system resistance among the various paths are met. The maximum total pump flow surveillance requirements ensure the pump runout limits* of 560 gpm for the centrifugal charging pumps and 675 gpm for the safety injection pumps are not exceeded.
The surveillance requirement for the maximum difference between the maximum and minimum individual injection line flows ensure.that the minimum individual injection line resistance assumed for the spilling line following a LOCA is met. LCO 3.0.4.b*is not applicable to an inoperable ECCS high head subsystem when entering MODE 4. There is an increased risk associated with entering MODE 4 from MODE 5 with an inoperable ECCS high head subsystem.
The provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and _components, should not be applied in this circumstance.
SALEM -UNIT l B 3/4 5-la Amendment No.276 EMERGENCY CORE COOL:ING SYSTEMS BASES ECCS SUBSYSTEMS (Continued)
. ....__,.,.
W;i.th the RCS temperature below 3SO&deg;F, one OPERABLE ECCS subsystem is acceptable without s;i.ngle failure consideration on the basis of the stable reactivity condition of the reactor and the limited core cooling requirements.
'l'he surveillance requirements, which are provided to ensure the OPERAB:IL:Ifi of each component, ensure that, at a minimum, the assumptions used in the safety analysis are met and that subsystem OPERABILITY is maintained.
'l'he safety analyses make assumptions with respect to: 1) both the :maximum and minimum total system resistance, and 2) both the maximum and minimum branch injection line resistance.
'l'hese resistances, in conjunction with the ranges of potential pump perfo:rmance, are used to calculate the maximum and minimum ECCS flow assumed in the safety analyses.
The maximum and minimum flow surveillance requirements in conjunction with the maximum and minimum pump performance curves ensures that the assumptions of total system resistance and the distribution of that system resistance among the various paths are met. The maximum total pump flow surveillance requirements ensure the pump runout limits of 560 gpm for the centrifugal charging pumps and 675 gpm for the safety injection pumps are not exceeded.
Due to the effect of pump suction boost alignment, the runout limits for the surveillance criteria are S 554 gpm for C/SI pumps, S 664 gpm for SI pumps in cold leg alignment, and S 654 gpm for SI pUI!ps in hot leg alignment.
'l'he surveillance requirement for the maximum difference between the maximum and minimum individual injection line flows ensure that the minimum individual injection line resistance assumed for the spilling line following a LOCA is met. 3/4.5.4 SEAL INJECTION FLOW The Reactor Coolant Pump (RCP) seal injection flow restriction limits the amount of ECCS flow that would be diverted from the injection path following an ECCS actuation.
This limit is based on safety analysis assumptions, since RCP seal injection flow is not isolated during Safety Injection (SI). The LCO is not strictly a flow limit, but rather a flow limit based on a flow line resistance.
Line pressure and flow must be known to establish the proper line resistance.
Flow line resistance is determined by assuming that the RCS pressure is at normal operating
: pressure, and that the centrifugal charging pump discharge pressure is greater than or equal to 2430 psig. Charging pump header pressure is used instead of RCS pressure, since it is more representative of flow diversion during an accident.
The additional LCO modifier, charging flow control valve full open, is required since the val.ve is designed to fail open. With the LCO specified discharge pressure and control valve position, a flow l;mit is.established.
This flow limit is used in the accident analysis.
A provision has been added to exempt surveillance requirement 4.0.4 for entry into MODE 3, since the surveillance cannot be performed in a lower mode. The exemption is permitted for up to 4 hours after the RCS pressure has stal;>ilized within +/- 20 psig of operating pressure.
The RCS pressure SALEM -ONIT 1 B 3/4 5-2 Amendment No Nl/!J, 208 EMERGENCY CORE COOLING SYSTEMS BASES requirement produces the conditions necessary to correctly set the manual throttle valves. The exemption is limited to 4 hours to ensure timely surveillance completion once the necessary conditions are established.
3/4.5.S REFUELING WATER STORAGE TANK The OPERABILITY of the RWST as part of the ECCS ensures that a sufficient supply of borated water is available for injection by the ECCS in the event of a LOCA. The limits on RWST minimum volume and boron concentration ensure that: (1) sufficient water is available within contaiIU11ent to permit recirculation cooling flow to the core, (2) the reactor will remain subcritical in the cold condition following a small LOCA assuming complete mixing of the RWST, RCS, and ECCS water volumes with all control rods inserted except the most reactive control assembly (ARI-1),
and (3) the reactor remain subcritical in the cold condition following a large break LOCA (break flow area > 3.0 sq. ft.) assuming complete mixing of the RWST, RCS, and ECCS water and other sources of water that may eventually reside in the sump following a LOCA with all control rods assumed to be out (ARO). The limits on contained water volume and boron concentration also ensure a pH value of between 7.0 and 10.0 for the solution recirculated within containment after a LOCA. This pH band minimizes the evolution of iodine and minimizes the effect of chloride and caustic stress corrosion on mechanical systems and components.
The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other physical characteristics.
SA,LEM -UNIT 1 B 3/4 5-3 April 29, 1998 *-
3/4.6 CONTAINMENT BASES 3/ 4*. 6. 1 PRIMARY CONTAINMENT 3/4 6.1.1 CONTAINMENT INTEGRITY Primary CONTAINMENT INTEGRITY ensures that the release of radioactive
:naterials from the containment atmosphere will be restricted to those leakage paths and associated leak rates assumed in the accident analyses.
This restriction, in conjunction with the leakage rate limitation, will limit the site boundary radiation doses to within the limits of 10 CFR 100 during accident conditions.
The purpose of this surveillance requirement (4.6.1.la) is not to perform any testing or valve manipulations, but to verify that containment isolation valves capable of being mispositioned are in their proper safety position (closed).
Physical verification (hands on verification) that these penetrations (containment isolation valves) are in the proper position is performed prior to entering Mode 4 from Mode 5 and documented in the appropriate valve line-up.
Allowing the use of administrative means to verify compliance with the surveillance requirement for these.valves is accepiable based on the limited access to these areas in Modes 1, 2, 3, and 4 for ALARA reasons.
Therefore, the probability of misalignment of these containment isolation valves, once they have been verified in the proper position, is small. The service water accumulator vessel and discharge valves function to maintain water filled, subcooled fluid conditions in the containment fan coil unit (CFCU) cooling loops during accident conditions.
The service water accumulator vessel and discharge valves were installed to address the Generic Letter 96-06 issues of column separation waterhammer and two phase flow during an accident involving a loss of offsite power. The operability of each service water accumulator vessel and discharge valve is required to ensure the integrity of containment penetrations associated*
with the containment
*fan coil units during accident conditions.
If a service water accumulator vessel does not meet the vessel surveillance requirements, or if the discharge valve response time does not meet design acceptance criteria when tested in accordance with procedures, the containment integrity requirements of the CFCU cooling loops exclusively supplied by the inoperable accumulator vessel or discharge valve are .not met. Limiting Condition*
for Operation 3.-6.1.1 is applicable, and the cooling loops, for the two CFCU's exclusively supplied by the inoperable accumulator are to be removed from service and isolated to maintain containment integrity.
3/4 6.1.2 CONTAINMENT LEAKAGE The limitations on containment leakage rates ensure that the total containment leakage volume will not exceed the value assumed in the accident analyses at the peak accident pressure Pa. As an added conservatism, the measured overall integrated leakage rate (Type A test) is further limited to less than or equal to 0.75 La or less than or equal to 0.75 Lt, as applicable, during performance of the periodic test to account for possible degradation of the containment leakage barriers between leakage tests. *
* The surveillance testing for measuring leakage rates are consistent with the Containment Leakage Rate Testing Program.
3/4.6.1.3 CONTAINMENT AIR LOCKS Containment air locks form part of the containment pressure boundary and provide a means for personnel access during all MODES of operation.
Each air lock is nominally a right circular
: cylinder, 10 feet in diameter, with a door at each end. Tl)e doors are interlocked during normal operation to prevent simultaneous opening.
SALEM .:... UNIT 1 B 3/4 6-1 Amendment No.227 , 
-------------------------------------------------
--3/4.6 CONTAINMENT
..........
--..... .:::-
:...* . .:::-BASES During periods when containment is no:. required to be OPERABLE, door mechanism may be disabled, allowing both doors of an air lock to remain open =or extended periods when freauent containment entry is necessary.
Each air lock door nas been designed tested io cert!fy its ability to withstand a excess o= the maximum expected pressure
=allowing a !)esi;p Basis A*ccidem:
(JB.<i_)
in con:.ainr:ier,:..
As such, closure of a single door suppc!'.'ts com:ainment OPER.Z:\.BILIT-!.
Each of the doc.rs contains double gasketed seals and local leakage rate testing capability to ensure pressure integrity.
To effect a leak tight seal, the a!r lock design uses seated doors (i.e., an increase in containment inte!'.'nal pressure results in increased sealing force on each door}. Each personnel air lock is provided with limit switches on both doors that provide control room indication of door position.
Additionally, control room indication is provided to alert the operator whenever an air lock door interlock mechanism is defeated.
The containment air locks forin part of the containment pressure boundary.
As such, air lock integrity and leak tightness is essential for maintaining the containment leakage rate within limit in the event of a DBA. Not mainta.ining a; ... lock integrity or leak tightness may result in a leakage rate in excess of assumed in the unit $afety analysis.
The DBAs that result in a release of radioactive material within containment are loss of coolant accident and a rod ejection accident.
In the analysis of each of these accidents, it is assumed that containment is OPERABLE such that release of fission products to the environment is controlled by the rate of containment leakage.
The containment was designed an allowable leakage rate of 0.1% of containment air weight per day. This leakage rate is defined in lOCFR.50, Appendix J as La=
of containment air per day, allowable containment leakage rate the calculated peak containment pressure Pa= 47.0 psig following a DBA. The allowable leakage rate forms the basis for the acceptance criteria imposed on the surveillance requirements associated with the air locks. *Each containment air lock forms part of the containment pressure boundary.
As part of containment, the air lock safety function is related to control.of the containment leakage rate resulting from a OBA. Thus, each air lock's structural integrity and leak tightness are essential to the successful mitigation of such an event. Each air lock is required to be OPERABLE.
For the air lock to be considered
: OPERABLE,
*the air lock interlock mechanism must be OPERABLE, the air lock must be in compliance with the Type B air lock leakage test, and both air lock doors must be OPERABLE.
The interlock allows only one air lock door.of an air lock to be opened at one time. This pr9vision ensures that a gross breach of containment does not exist when containment is required to be OPERABLE.
Closure of a.single door in each air lock is sufficient to provide a leak tight barrier following postulated events. Nevertheless, both doors are kept closed when the air lock is not being used for normal entry into and exit from containment.
* In MODES 1, 2, 3, and 4, a DBA could cause a release.of radioactive material to containment
.. In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the containment air locks are not required in MODE 5 to prevent leakage of radioactive material from containment.
The requirements for the containment air locks during MODE 6 are addressed in LCO 3.9.4, "Containment Building Penetrations".
The ACTIONS are modified by five notes. Note (1) allows entry and exit to perform repairs on the affected air lock component.
If the outer door is inoperable, then it may be easily accessed for most repairs.
It is preferred that the air lock be accessed from inside primary containment by entering through the other OPERABLE air lock. SALEM -UNIT 1 B 3/4 6-la Amendment No.227 3/4.6 CONTAINMENT SYSTEMS BASES However, if this is not practicable, or if repairs on either door must be performed from the barrel side of the door then it is permissible to enter the air lock through the OPERABLE door, which means there is a short time during which the containment boundary is not intact (during access through the OPERABLE door) . The ability to open the OPERABLE door, even if it means the containment boundary is temporarily not intact, is acceptable due to the low probability of an event that could pressurize the containment during the short time in which the OPERABLE door is expected to be open. After each entry and exit, the OPERABLE door must be irmnediately closed. If ALARA conditions permit, entry and exit should be via an OPERABLE air lock. Note (2) adds clarification that separate condition entry is allowed for each air lock. This is acceptable, since the required ACTIONS provide appropriate compensatory measures for each inoperable air lock. Complying with the Required Actions may allow for continued operation.
A subsequent inoperable air lock is governed by condition entry for that air lock. Notes (3) and (4) ensure that only the required ACTIONS and associated completion times of condition
: c. are required if both doors in the same air lock are inoperable.
With both doors in the same air lock inoperable, an OPERABLE door is not available to be closed. Required ACTIONS c.l and c.2 are the appropriate remedial actions.
The exception of these Notes does not affect tracking the completion time from the initial entry into condition a., only the requirement to comply with the required ACTIONS.
In the event the air lock leakage results in exceeding the overall containment leakage rate, Note (5) directs entry into the applicable Conditions and required ACTIONS of LCO 3.6.1, "Primary Containment."
With one air lock door in one or more containment air locks inoperable, the OPERABLE door. must be verified closed (ACTION a.l) in each affected containment air lock. This ensures that a leak tight containment barrier is maintained by the use of an OPERABLE air lock door. This ACTION must be completed within 1 hour. The specified time period is consistent with the ACTIONS of LCO 3.6.1.1 that requires that containment be restored to OPERABLE status within 1 hour. OPERABILITY of the air lock interlock is not required to support the OPERABILITY of an air lock door. In addition, the affected air lock penetration must be isolated by locking closed the OPERABLE air lock door within the 24 hour completion time (ACTION a.2). The 24 hour completion time is reasonable for locking the OPERABLE air lock door, considering the OPERABLE door of the affected air lock is being maintained closed. Required ACTION a.3 verifies that an air lock with an inoperable door has been isolated by the use of a locked and closed OPERABLE air lock door. This ensures that an acceptable containment leakage boundary is maintained.
The completion time of once per 31 days is based on engineering judgement and is considered adequate in view of the low likelihood of a locked door being mispositioned and other administrative controls.
ACTION a.3 allows the use of the air lock for entry and exit for 7 days under administrative controls if both air locks have an inoperable door. This 7-day restriction begins when the second air lock is discovered to be inoperable.
Containment entry may be required on a periodic basis to perform Technical Specification Surveillances and required
: ACTIONS, as well as other activities on equipment inside containment that are required by Technical Specifications or activities on equipment that support Technical Specification required equipment.
This Note is not intended to preclude performing other activities (i.e., Technical Specification required activities) if the containment is entered, using the inoperable air lock, to perform an allowed entry listed above. This allowance is acceptable due to the low probability of an event that could pressurize the containment during the short time that the OPERABLE door is expected to be open. SALEM -UNIT 1 B 3/4 6-lb Amendment No. 227 3/4.6 CONTAINMENT BAS'ES Because of ALARA considerations, ACTION a.3 also allows air lock doors located in high radiation areas to be verified locked closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted.
Therefore, the probability of misalignment of the door, once it has been verified to be in the proper position, is small. With an air lock *interlock mechanism inoperable in one or more air locks, the required ACTIONS and associated completion times are consistent with those specified in*Condition
: a. In addition, ACTION b.3 allows entry into and exit from containment under the control of a dedicated individual stationed at the air lock to ensure that only one door is opened at a time (i.e., the individual performs the function of the interlock).
In addition, ACTION b.3 allows air lock doors located*
in high radiation areas to be verified locked closed by use of administrative means. ACTION c.l requires that with one or more air locks inoperable for reasons other than those described in condition
: a. b., action must be initiated immediately to evaluate previous combined leakage rates using current air lock test results.
An evaluation is acceptable, since it is overly conservative to immediately declare the containment inoperable if both doors in an air lock have failed a seal test or if the overall air lock leakage is not within limits. In many instances (e.g., only one seal per door* has failed),
containment remains OPERABLE, yet only 1 hour (per LCO 3.6.1.1) would be provided to restore the air lock door to OPERABLE status prior to requiring plant shutdown.
In addition, even with both doors failing the seal test, the overall containment leakage rate can still be within limits. Required ACTION c.2 requires that one door in the affected containment air lock must be verified to be closed within the 1 hour completion time. This specified time period is consistent with the ACTIONS of LCO 3.6.1.1, which requires that containment be restored to OPERABLE status within 1 hour. Additionally, the affected air lock(s) must be restored to OPERABLE status within the 24 hour completion time. This completion time begins at the time that the air lock is discovered to be inoperable.
The specified time period is considered reasonable for restoring an inoperable air lock to OPERABLE status, assuming that at least one door is maintained closed in each affected air lock. If the inoperable containment air lock cannot be restored to OPERABLE status within the required completion time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least Hot Standby within 6 hours and to Cold Shutdown within the following 30 hours. The allowed completion times are reasonable based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
Maintaining containment airlocks OPERABLE requires compliance with the leakage rate test requirements of 10CFR50, Appendix J, as modified by approved exemptions.
This Surveillance Requirement reflects the leakage rate testing requirements with regard to air lock leakage (Type B leakage tests). The acceptance criteria were established during initial air lock and containment OPERABILITY testing.
The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall containment
*leakage rate. The frequency is required by Appendix J, as modified by approved exemptions.
Thus, the provision of Specification 4.0.2 (which frequency extensions) does not apply. SALEM -UNIT 1 B 3/4 6-lc Amendment No. 215 3/4.6 CONTAINMENT SYSTEMS BASES The air lock interlock is designed to prevent simultaneous opening of both doors in a single air lock. Since both the inner and outer doors of an air lock are designed to withstand the maximum expected post accident containment
: pressure, closure of either door will support containment OPERABILITY.
Thus, the door interlock feature supports containment OPERABILITY while the air lock is being used for personnel transit in and out of the containment.
Periodic testing of this interlock demonstrates that the interlock will function as designed and that simultaneous opening of the inner and outer doors will not inadvertently occur. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
SALEM -UNIT 1 B 3/4 6-ld Amendment No. 299 (PSEG Issued)
CONTAINMENT SYSTEMS BASES 3/4.6.1.4 INTERNAL PRESSURE The limitations on containment internal pressure ensure that: 1) the containment structure is prevented from exceeding its design negative pressure differential with respect to the outside atmosphere of 3,5 psig and 2) the containment peak pressure does not exceed the design pressure of 47 psig during the limiting pipe break conditions.
The pipe breaks considered are LOCA and steam line breaks. The limit of 0.3 psig for initial positive containment pressure is consistent with the accident analyses initial conditions.
The maximum peak pressure expected to be obtained from a LOCA or steam line break event is s; 47 psig. 3/4.6.1.5 AIR TEMPERATURE The limitations on containment average air temperature ensure that the overall containment average air temperature does not exceed the initial temperature condition assumed in the accident analysis for a LOCA or steam line .break. In order to determine the containment average air temperature, an . average is calculated using measurements taken at locations within containment selected to provide a representative sample of the overall containment atmosphere.
. CONTAINMENT STRUCTURAL INTEGRITY This limitation ensures that the structural integrity of the containment will be maintained comparable to the original design standards for the life of the facility.
Structural integrity is required to that the containment will *withstand the design pressure.
The visual inspections of the concrete and liner and the Type A leakage test both in accordance with the Containment Leakage Rate Testing Program are sufficient to demonstrate this capability.
(Note that the elements of 3/4.6.1.7.were RELOCATED to 3/4 6.3 by LCR S06-06) SALEM -UNIT 1 B3/4 6-2 Amendment No.277 (PSEG Issued)
CONTAINMENT SYSTEMS BASES 3/4.6.2 .DEPRESSURIZATION AND COOLING SYSTEMS *3/4.6.2.l CONTAINMENT SPRAY SYSTEM The OPERABILITY of the containment spray system, when operated in conjunction with the Containment Cooling System, ensures that containment depressurization and cooling capability will be available in the event of a LOCA. The pressure reduction and resultant lower containment leakage rate are consistent with the assumptions used in the accident analyses.
Normal plant operation and maintenance practices are not expected to trigger surveillan*ce requirement
: 4. 6. 2 .1. d. Only an unanticipated circumstance would initiate this surveillance, such as spray actuation, a major configuration change, or a loss of foreign material control when working within the affected boundary of the system. If an activity occurred that presents the potential of creating nozzle blockage, an evaluation would be performed
.by the engineering organization to determine if the amount cf nozzle b:lockage would impact the required*
design capabilities of the containment spray system. If the evaluation determines that the containment spray system would continue to perform its design basis function, then performance of the air or smoke flow test would not be required.
I"f the evaluation cannot determine the impact to the containment spray system, then the air or smoke flow test would be performed to determine if any nozzle blockage has occurred.
3/4.6.2.2 SPRAY ADDITIVE SYSTEM The OPERABILITY of the spray additive system ensures that sufficient NaOH is added to the containment spray in the event of a LOCA. The limits on NaOH minimum volume and concentration, ensure that l} the iodine removal efficiency of the spray water is maintained because of the increase
;n pH value, and 2) corrosion effects on components within containment are* minimized.
The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other physical characteristics.
These assumptions are consistent with the iodine removal efficiency assumed in the accident analyses.
3/4.6.2.3 CONTAINMENT COOLING SYSTEM The OPERABILITY of the containment cooling system ensures that adequate heat removal capacity is available when operated.in conjunction with the containment spray systems during post:-LOCA conditions.
The surveillance requirements for the service water accumulator vessels ensure each tank contains sufficient water and nitrogen to maintain water filled, subcooled fluid conditions.
in three containment fan coil unit (CFCU) cooling loops in response to a loss of offsite power, without injecting nitrogen covergas into the containment fan coil unit loops assuming the most limiting single failure.
* The surveillance requirement for the discharge valve response time test ensures that on a loss of offsite power, each discharge valve actuates to the open position in accordance with the design to allow sufficient tank discharge into CFCU piping to maintain wate*r filled, subcooled fluid cond.itions in three CFCU cooling loops, assuming the most limiting single failure.
SALEM -UNIT 1 B 3/4 6-3 Amendment No. 287 (PSEG Issued)
CONTAINMENT SYSTEMS BASES The surveillance requirements for the CFCUs ensure sufficient SWS flow through each operating cooler to provide the minimum containment cooling as assumed by the containment response analysis for a design-basis LOCA or MSLB event. The surveillance flow rate is selected to ensure adequate heat removal (with no phase flow) . The specified surveillance flow rate represents the total flow from both the CFCU coils and the CFCU motor-cooler.
3/4.6.3 CONTAINMENT ISOLATION VALVES The OPERABILITY of the 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.
Containment isolation within the time limits specified ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a LOCA. The opening of locked or sealed closed containment isolation valves (penetration flow paths) on an intermittent basis under administrative control includes the following considerations:
(1) stationing a dedicated individual, who is in constant communication with the control room, at the valve controls, (2) instructing this individual to close these valves in an accident situation, and (3) assuring that environmental conditions will not preclude access to close the valves and that this action will prevent the release of radioactivity outside the containment.
The main steam isolation valves (MSIVs) fulfill their containment isolation function as remote-manual containment isolation valves. The automatic closure of the MSIVs is not required for containment isolation due to having a closed system inside containment.
The remote-manual containment isolation function of the MSIVs can be accomplished through either the use of the hydraulic operator or when the MSIV has been tested in accordance with surveillance requirement 4.7.1.5 the steam assist function can be credited.
Surveillance Requirement (SR) 4.6.3.1.3 only applies to the MS7 (Main Steam Drain) valves and the MS18 (Main Steam Bypass) valves. The MS167 (Main Steam Isolation) valves are tested for main steam isolation purposes by SR 4.7.1.5.
For containment isolation
: purposes, the MS167s are tested as remote/manual valves pursuant to Specification 4.0.5. The containment purge supply and exhaust isolation valves are required to be closed during plant operation since these valves have not been demonstrated capable of closing during a LOCA. Maintaining these valves (or equivalent isolation device) closed during plant operations ensures that excessive quantities of radioactive materials will not be released via the containment Purge system. A containment purge valve is not a required containment isolation valve *when its flow path is isolated with a blind flange tested in accordance with SR 4.6.1.2.b.
The inboard valve of both the containment purge supply and exhaust penetrations has been replaced with a testable, double a-ring blind flange. The blind flange serves as the containment boundary and performs the containment integrity function in Modes 1,2,3,and
: 4. The outboard valve of both the containment purge supply and exhaust penetrations performs no containment integrity function in MODES 1-4; these valves operate during shutdown for normal system purging and containment closure when the blind flanges are removed.
SALEM -UNIT 1 B 3/4 6-4 Amendment No. 287 (PSEG Issued)
CONTAINMENT SYSTEMS BASES SALEM -UNIT 1 This page left intentionally blank B 3/4 6-5 Amendment No.52008-084 (PSEG Issued) 3/4.7 PLANT SYSTEMS BASES 3/4.7.1 TURBINE CYCLE 3/4.7.1.1 SAFETY VALVES The OPERABILITY of the main steam line code safety valves ensures that the secondary system pressure will be limited to within 110% of its design pressure of 1085 psig during the most severe anticipated system operational transient.
The MSSVs also provide protection against of the Reactor Coolant Pressure Boundary by providing a heat sink for the removal of energy from the Reactor Coolant System if the pref erred heat sink is not available.
The maximum relieving capacity is associated with a turbine trip from 100% RATED THERMAL POWER coincident with an assumed loss of condenser heat sink (i.e., no steam bypass to the condenser).
The specified valve lift settings and relieving capacities are in accordance with the requirements of Section III of the ASME Boiler and Pressure Code, 1971 Edition.
The total relieving capacity for all valves on all of the steam lines is 16.66 x 106 lbs/hr which is 110.3 percent of the maximum calculated steam flow of 15.10 x 106 lbs/hr at 100% RATED THERMAL POWER. A minimum of 2 OPERABLE safety valves per OPERABLE steam generator ensures that sufficient relieving capacity is available for the allowable THERMAL POWER restriction in Table 3.7-2. STARTUP and/or POWER OPERATION is allowable with one or two inoperable safety valves within the limitations of the ACTION requirements on the basis of the reduction in secondary steam flow associated with the required reduction of RATED THERMAL POWER. The acceptable power level (in percent RATED THERMAL POWER) for operation with inoperable safety valves was determined by performing explicit transient analysis.
The events that challenge the relief capacity of the safety valves are those resulting in decreased heat removal capability.
In this category of events, a loss of external electrical load and/or turbine trip is the limiting anticipated operational occurrence.
A series of cases was analyzed for this transient covering up to two inoperable safety valves on each steam generator.
The results of these cases were used to determine a maximum thermal power level from which the event could be initiated without exceeding the primary and secondary side design pressure limits. Thus, the maximum allowed power level as a function of the number of inoperable MSSVs on any steam generator is presented in Table 3.7-1. Note that the power level values presented on this table are the direct inputs into the transient analysis cases and do not include any allowance for calorimetric error. Actual power level reductions must include calorimetric uncertainty and other allowances for operating margin as deemed necessary.
Specific accident analyses for RCCA Bank Withdrawal at Power scenarios demonstrate that adequate safety valve relief capacity exist with up to two inoperable safety relief valves on each steam generator.
These cases demonstrate that the reactor trip on OTDT along with the relief from the available main steam safety valves is sufficient to.meet secondary side pressurization limits. SALEM -UNIT 1 B 3/4 7-1 Amendment No. 244 PLANT SYSTEMS BASES For three inoperable main steam safety valves in one or more steam generators, thermal reactor power must be reduced in conjunction with a reduction in the Power Range Neutron Flux High trip setpoint to prevent overpressurization of the main steam system. The transient analysis assumes that the MSSVs will start to open at the lift setpoint with 3% allowance for setpoint tolerance.
In addition, the analysis accounts for accumulation by including a 5 psi ramp for the valve to reach its fully open position.
Inoperable MSSVs are assumed to be those with the lowest lift setting.
Surveillance testing as covered in Table 4.7-1 allows a +/- 3% lift setpoint tolerance.
: However, to allow for drift during subsequent operation, the valves must be reset to within +/- 1% of the lift setpoint following testing.
3/4.7.1.2 AUXILIARY FEEDWATER SYSTEM The OPERABILITY of the auxiliary f eedwater system ensures that the Reactor Coolant System can be cooled down to less than 350&deg;F from normal operating conditions-in the event of a total loss of off-site power. Verifying that each Auxiliary Feedwater (AFW} pump's developed head at the flow test point is greater than or equal to the required minimum developed head ensures that the AFW pump performance has not degraded during the cycle, and that the assumptions made in the accident analysis remain valid. Flow and differential head are normal tests of centrifugal pump performance required by Section XI of the ASME Code. Because it is undesirable to introduce cold AFW into the steam generators while operating, the test is performed on recirculation flow. This test confirms one point on the pump design curve (head vs flow curve}, and is indicative of pump performance.
Inservice testing confirms pump operability, trends performance and detects incipient failures by indication of pump performance.
The flow path to each steam generator is ensured by maintaining all manual maintenance valves locked open. A spool piece consisting of a length of pipe may be used as an equivalent to a locked open manual valve. The manual valves in the flow path are: lAFl, 11AF3, 12AF3, 13AF3, llAFlO, 12AF10, 13AF10, 14AF10, 11AF20, 12AF20, 13AF20, 14AF20, 11AF22, 12AF22, 13AF22, 14AF22, 11AF86, 12AF86, 13AF86, and 14AF86. LCO 3.0.4.b is not applicable to an inoperable AFW train. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an AFW train inoperable.
The provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
3/4.7.1.3 AUXILIARY FEED STORAGE TANK The OPERABILITY of the auxiliary feed storage tank with the minimum water volume ensures that sufficient water is available to maintain the RCS at HOT STANDBY conditions for 8 hours with steam discharge to -the atmosphere concurrent with total loss of off-site power. The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other physical characteristics.
SALEM -UNIT 1 B 3/4 7-2 Amendment No.276 PLANT SYSTEMS BASES 3/4.7.1.4 ACTIVITY The limitations on secondary system specific activity ensure that the resultant off-site radiation dose will be limited to a small fraction of 10 CFR Part 100 limits in the event of a steam line rupture.
This dose also includes the effects of a coincident 1.0 GPM primary to secondary tube leak in the steam generator of the affected steam line. These values are consistent with the assumptions used in the accident analyses.
3/4.7.1.5 MAIN STEAM LINE ISOLATION VALVES The OPERABILITY of the main steam line isolation valves ensures that no more than one steam generator will blowdown in the event of a steam line rupture.
This restriction is required to 1) minimize the positive reactivity effects of the Reactor Coolant System cooldown associated with the blowdown, and 2) limit the pressure rise within containment in the event the steam line rupture occurs within containment.
The OPERABILITY of the main steam isolation valves within the closure times of the surveillance requirements are consistent with the assumptions used in the accident analyses.
If the closure time of the main steam isolation valve (MSIV) during technical specification surveillance testing (performed at a Stearn Generator pressure between 800 psig and 1015 psig) is 5.0 seconds or less and the engineered safety feature response time (including valve closure time) for the steam line isolation (MSI) signal (Table 3.3-5) is 5.5 seconds or less, then assurance is provided that MSI occurs within 12 seconds under accident conditions, where Steam Generator pressure may be lower. This method of testing assures that for main steam line ruptures that are initiated from Modes 1-3 conditions that generate a MSI signal via automatic or manual initiation and have adequate steam line pressure to close, the main steam lines isolate within the time required by the accident analysis.
Fast closure of the MSIVs is assured at a minimum steam pressure of 170 psia. However, the MSIV will still close via the steam assist function between 118 -170 psia with slightly greater closure times. For main steam line ruptures that receive an automatic or manual signal for MSI and do not have adequate steam pressure to close the MSIVs (less than 118 psia), the event does not require MSIV closure to provide protection to satisfy design basis requirements (e.g., minimum DNBR remains above the minimum DNBR limit value and peak containment pressure remains below 47 psig). Testing for SR 4.7.1.5 is performed prior to opening the MSIVs for power operation.
During testing, only one valve is opened at a time, with the other three valves remaining closed in the safe position, ensuring isolation capability is maintained.
In the event of a steam line rupture, a postulated failure of the tested valve in the open position would result in the blowdown of a single steam generator since the remaining three MSIVs are closed. Failure of a single MSIV to close is consistent with the accident analysis assumptions for a major secondary system pipe rupture (UFSAR Section 15.4.2).
SALEM -UNIT 1 B 3/4 7-3 Revised by letter dated 6-19-2003 PLANT SYSTEMS BASES 3/4.7.2 STEAM GENERATOR PRESSURE/TEMPERATURE LIMITATION The limitation on steam generator pressure and temperature ensures that the pressure induced stresses in the steam generators do not exceed the maximum allowable fracture toughness stress limits. The limitations of 70?F and 200 psig are based on average steam generator impact values taken at lO?F and are sufficient to prevent brittle fracture.
3/4.7.3 COMPONENT COOLING WATER SYSTEM The OPERABILITY of the component cooling water system ensures that sufficient cooling capacity is available for continued operation of related equipment during normal and accident conditions.
The component cooling water system (CCW) consists of two safeguards mechanical trains supplied by three pumps powered from separate vital buses. This complement of equipment assures adequate redundancy in the event of a single active component failure during the injection phase. Operability of the CCW system exists when both mechanical trains and all three CCW pumps are operable.
3/4.7.4 SERVICE WATER SYSTEM The OPERABILITY of the service water system ensures that sufficient cooling capacity is available for continued operation of safety related equipment during normal and accident conditions.
The redundant cooling capacity of this system, assuming a single failure, is consistent with the assumptions used in the accident conditions within acceptable limits. SALEM -UNIT 1 B 3/4 7-4 March 7, 1997 3/4.7 PLANT SYSTEMS BASES 3/4.7.5 FLOOD PROTECTION The limitation on flood protection ensures that facility protective actions will be taken *and operation will be terminated in the event of flood conditions.
The limit of elevation 10.5' Mean Sea Level is based on the elevation above which facility flood control measures are required to provide protection to safety related equipment.
3/4.7.6 CONTROL ROOM EMERGENCY AIR CONDITIONING SYSTEM BACKGROUND:
The control room emergency air conditioning system (CREACS) provides a protected environment from which occupants can control the unit following an uncontrolled release of radioactivity, hazardous chemicals, or smoke. The OPERABILITY of the CREACS ensures that 1) the ambient air temperature does not exceed the allowable temperature for continuous duty rating for the equipment and instrumentation cooled by this system and 2) the control room will remain habitable for operations personnel during and following all credible accident conditions.
The CREACS consists of two independent, redundant trains, one from each unit that re-circulate and filter the air in the Control Room Envelope (CRE) and a CRE boundary that limits the inleakage of unfiltered air. Each CREACS train consists of a prefilter, a high efficiency particulate air (HEPA) filter, an activated charcoal adsorber section for removal of gaseous activity (principally iodines),
and fans. Ductwork, valves or dampers, doors, barriers, and instrumentation also form part of the system. The CREACS is a shared system between Unit 1 and 2 supplying a common CRE. During emergency operation following receipt of a Safety Injection or High Radiation actuation signal, for areas inside the CRE, one 100% capacity fan in each Unit's CREACS will operate in a pressurization mode with a constant amount of outside air supplied for continued CRE pressurization.
One fan from each train will automatically start upon receipt of an initiation signal, with one fan in each train in standby.
A failure of one fan will result in the standby fan automatically starting.
Each CREACS.train has two 100% capacity fans, such that any one of the four fans is sized to provide the required flow for CRE pressurization within the common CRE during an emergency.
A failure of one CREACS filtration train requires manual actions to properly reposition dampers in support of single filtration train operation.
To minimize control room radiological doses, the CREACS outside air is supplied from the non-accident unit's emergency air intake through the connected supply duct (as determined by which unit received an accident signal).
Outside air is mixed with recirculated air, passed through each CREACS filter bank (pre-filter, HEPA filter, and charcoal adsorber) and cooling coil, and distributed to the common CRE. The CREACS is designed to maintain a habitable environment in the CRE for 30 days of continuous occupancy after a Design Basis Accident (OBA) without exceeding 5 Rem total effective dose equivalent (TEDE). SALEM -UNIT 1 B 3/4 7-5 Amendment No. 286 (PSEG Issued) 3/4.7 PLANT SYSTEMS BASES The CREACS is an emergency system, parts of which may also operate during normal unit operations in the standby mode of operation.
Upon receipt of the actuating signal(s),
normal air supply to the CRE is isolated, and the stream of ventilation air is recirculated through the system filter trains. The prefilters remove any large particles in the air to prevent excessive loading of the HEPA filters and charcoal adsorbers.
Pressurization of the CRE minimizes infiltration of unfiltered air through the CRE boundary from all the surrounding areas adjacent to the CRE boundary.
CREACS will be manually initiated in the recirculation mode only in the event of a fire outside the CRE, a toxic chemical
: release, or testing.
The CRE is the area within the confines of the CRE boundary that contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions.
This area encompasses the control room and other non-critical areas to which frequent personnel access or continuous occupancy is not necessary in the event of an accident.
The CRE is protected during normal operation, natural events, and accident conditions.
The CRE boundary is the combination of walls, floor, roof, ducting, doors, penetrations and equipment that physically form the CRE. The OPERABILITY of the CRE boundary must be maintained to ensure that the inleakage of unfiltered air into the CRE will not exceed the inleakage assumed in the licensing basis analysis of design basis accident (OBA) consequences to CRE occupants.
The CRE and its boundary are defined in the Control Room Envelope Habitability Program.
APPLICABLE SAFETY ANALYSES The CREACS components are arranged in redundant, safety related ventilation trains. The location of components and ducting within the CRE ensures an adequate supply of filtered air to all areas requiring access. The CREACS provides airborne radiological protection for the CRE occupants, as demonstrated by the CRE occupant dose analyses for the most limiting design basis accident, fission product release presented in the UFSAR, Chapter 15. The CREACS provides protection from smoke and hazardous chemicals to the CRE occupants.
The analysis of hazardous chemical releases demonstrates that the toxicity limits are not exceeded in the CRE following a hazardous chemical
: release, as described in UFSAR, Section 6.4. The evaluation of a smoke challenge demonstrates that it will not result in the inability of the CRE occupants to control the reactor either from the control room or from the remote shutdown panels, as described in UFSAR, Section 9.5. SALEM -UNIT 1 B 3/4 7-5a TSBC S2011-238 3/4.7 PLANT SYSTEMS BASES LCO Two independent and redundant CREACS trains are required to be OPERABLE to ensure that at least one is available if a single active failure disables the other train. Total system failure, such as from a loss of all ventilation trains or from an inoperable CRE boundary could result in exceeding a dose of 5 rem TEDE to the CRE occupants in the event of a large release.
In order for the CREACS trains to be considered
: OPERABLE, the CRE boundary must be maintained such that the CRE occupant dose from a large radioactive release does not exceed the calculated dose in the licensing basis consequence analyses for DBAs, and that CRE occupants are protected from hazardous chemicals and smoke. The LCO is modified by a Note allowing the CRE boundary to be opened intermittently under administrative controls.
This Note only applies to openings in the CRE boundary that can be rapidly restored to the design condition, such as doors, hatches, floor plugs, and access panels. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings, these controls are proceduralized and consist of stationing a dedicated individual at the opening who is in continuous communication with the operators in the CRE. This individual will have a method to rapidly close the opening and to restore the CRE boundary to a condition equivalent to the design condition, when a need for CRE isolation is indicated.
A significant contributor to this system's OPERABILITY are the dampers, which are required to actuate to their correct positions.
The following dampers are associated with the respective LCO*: a.l Fan outlet dampers:
1(2)CAA15 and 1(2)CAA16 These dampers ensure that the flow path for CREACS is operable and are required to open upon CREACS initiation.
The associated fan outlet damper will open on fan operation.
a.4 Return air isolation damper: 1(2)CAA17 When aligned for single train operation, the associated air return isolation damper will be administratively controlled in the open position.
: b. Other dampers required for automatic operation in the pressurization or recirculation modes: Control Area Air Conditioning System (CAACS) outside air intake isolation dampers:
1(2)CAA40, 1(2)CAA41, 1(2)CAA43 and 1(2)CAA45 The normally open outside air intake dampers 1(2)CAA40 and inlet plenum isolation dampers 1(2)CAA43 will be closed under emergency conditions.
The normally closed outside air intake dampers 1(2)CAA41 and inlet plenum isolation dampers 1(2)CAA45 are normally closed and remain closed under emergency conditions.
* Operability of the CREACS requires that each of the Unit 2 dampers are also operable SALEM -UNIT 1 B 3/4 7-5b Amendment No. 286 (PSEG Issued) 3/4.7 PLANT SYSTEMS BASES Control Area Air Conditioning System (CAACS} exhaust isolation dampers:
1(2}CAA18 and 1(2}CAA19.
These dampers are normally closed and are required to remain closed to prevent inleakage from the outside environment in the event of a toxic release.
Control Room Emergency Air Conditioning System (CREACS}
air intake dampers: 1(2}CAA48, 1(2}CAA49, 1(2}CAA50 and 1(2}CAA51 CREACS outside air intake dampers are maintained closed during normal and recirculation operation and are opened automatically upon initiation of CREACS pressurization.
The control logic will automatically open the CREACS air intake dampers farthest from the radiation source based upon which Unit's Solid State Protection System (SSPS} or Radiation Monitoring System (RMS} signal is received.
CAACS and CREACS interface isolation dampers:
1(2}CAA14 and 1(2}CAA20 These two dampers are normally open and do not have associated redundant dampers.
These dampers serve a boundary function by isolating the CREACS from the CAACS during emergency operation of the CREACS. Note: Dampers 1(2}CAA5, CAACS recirculation damper will receive an accident alignment signal to ensure proper accident configuration of CAACS. This damper, however, is not required for the OPERABILITY of CREACS as defined in the LCO. APPLICABILITY In all MODES and during movement of irradiated fuel assemblies, the CREACS must be OPERABLE to ensure that the CRE will remain habitable during and following a OBA. During movement of irradiated fuel assemblies, the CREACS must be OPERABLE to cope with the release from a fuel handling
: accident, involving handling irradiated fuel. SALEM -UNIT 1 B 3/4 7-5c Amendment No. 286 (PSEG Issued}
3/4.7 PLANT SYSTEMS BASES ACTIONS When one CREACS train is inoperable, for reasons other than an inoperable CRE boundary, action must be taken to align CREACS for single filtration train operation within 4 hours, and restore the inoperable filtration train to OPERABLE status within 30 days. Single filtration train alignment is only permitted if the Unit with the operable CREACS train is also in Chilled Water LCO 3.7.10.a configuration.
Single filtration train alignment is not permitted if in the LCO 3.7.10.c configuration.
This ensures required cooling coil heat removal capacity is available.
In this Condition, the remaining OPERABLE CREACS train is adequate to perform the CRE occupant protection function.
With CREACS aligned for single filtration train operation and with one of the two remaining fans or associated outlet damper inoperable, restore the inoperable fan or damper to OPERABLE status within 72 hours. However, the overall reliability is reduced because a failure in the OPERABLE CREACS train could result in loss of CREACS function.
The 72 hours completion time is based on the low probability of a OBA occurring during this time period, and ability of the remaining train components to provide the required capability.
If the unfiltered inleakage of potentially contaminated air past the CRE boundary and into the CRE can result in CRE occupant radiological dose greater than the calculated dose of the licensing basis analyses of DBA consequences (allowed to be up to 5 rem TEDE), or inadequate protection of CRE occupants from hazardous chemicals or smoke, the CRE boundary is inoperable.
Actions must be taken to restore an OPERABLE CRE boundary within 90 days. During the period that the CRE boundary is considered inoperable, action must be* initiated to implement mitigating actions to lessen the effect on CRE occupants from the potential hazards of a radiological or chemical event or a challenge from smoke. Actions must be taken within 24 hours to verify that in the event of a DBA, the mitigating actions will ensure that CRE occupant radiological exposures will not exceed the caiculated dose of the licensing basis analyses of OBA consequences, and that CRE occupants are protected from hazardous chemicals and smoke. These mitigating actions (i.e., actions that are taken to offset the consequences of the inoperable CRE boundary) should be preplanned for implementation upon entry into the condition, regardless of whether entry is intentional or unintentional.
The 24-hour completion time is reasonable based on the low probability of a DBA occurring during this time period, and the use of mitigating actions.
The 90 day completion time is reasonable based on the determination that the mitigating actions will ensure protection of CRE occupants within analyzed limits while limiting the probability that CRE occupants will have to implement protective measures that may adversely affect their ability to control the reactor and maintain it in a safe shutdown condition in the event of a DBA. In addition, the 90 day completion time is a reasonable time to diagnose, plan and possibly repair, and test most problems with the CRE boundary.
In MODE 1, 2, 3, or 4, if the inoperable CREACS train or the CRE boundary cannot be restored to OPERABLE status within the required completion time, the unit must be placed in a MODE that minimizes accident risk. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours, and in MODE 5 within the following 30 hours. The allowed completion times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
SALEM -UNIT 1 B 3/4 7-5d Amendment No. 316 (PSEG Issued) 3/4.7 PLANT SYSTEMS BASES In MODE 5 or 6, or during movement of irradiated fuel assemblies, if the inoperable CREACS train cannot be restored to OPERABLE status, align CREACS for single filtration train operation within 4 hours, or suspend movement of irradiated fuel assemblies.
With CREACS aligned for single filtration train operation with one of the two remaining fans or associated outlet damper inoperable, restore the fan or damper to OPERABLE status within 72 hours. The 72 hours completion time is based on the ability of the remaining train components to provide the required capability.
In MODE 5 or 6, or during the movement of irradiated fuel assemblies, with two CREACS trains inoperable or with one or more CREACS trains inoperable due to an inoperable CRE boundary, action must be taken immediately to suspend activities that could result in a release of radioactivity that might require isolation of the CRE. This places the unit in a condition that minimizes the accident risk. This does not preclude the movement of fuel to a safe position.
Immediate action(s),
in accordance with the LCO Action Statements, means that the required action should be pursued without delay and in a controlled manner. SURVEILLANCE REQUIREMENTS Standby systems should be checked periodically to ensure that they function properly.
TS Surveillance Requirement verifies that each fan is capable of operating for at least 15 minutes by initiating flow through the HEPA filter and charcoal adsorbers train(s) to ensure that the system is available in a standby mode. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Filter testing verifies that the required CREACS testing is performed in accordance with the surveillance requirements.
The surveillance requirements include testing the performance of the HEPA filter, charcoal adsorber efficiency, minimum flow rate, and the physical properties of the activated charcoal.
Specific test Frequencies and additional information are discussed in detail in the surveillance requirements.
Filter testing will be in accordance with the applicable sections of ANSI N510 (1975) with the exception that laboratory testing of activated carbon will be in accordance with ASTM D3803 (1989). The acceptance criteria for the laboratory testing of the carbon adsorber is determined by applying a minimum safety factor of 2 to the charcoal adsorber removal efficiency credited in the design.basis dose analysis as specified in Generic Letter 99-02. Actuation testing verifies that each CREACS train starts and operates on an actual or simulated actuation signal. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
SALEM -UNIT 1 B 3/4 7-5e Amendment No. 299 (PSEG Issued) 3/4.7 PLANT SYSTEMS BASES The control room envelope is considered intact and able to support operation of the CREACS when the emergency air conditioning system is capable of maintaining positive pressure with the control room boundary door(s) closed. Unfiltered air inleakage testing verifies the OPERABILITY of the CRE boundary by testing for unfiltered air inleakage past the CRE boundary and into the CRE. The details of the testing are specified in the Control Room Envelope Habitability Program.
Each CAACS normal air intake ductwork has two radiation detector channels.
The two detector channels from Unit 1 and Unit 2 CAACS air intake provide input to common radiation monitor processors.
Each radiation monitor processor (one for lRlB-1/lRlB-2 and one for 2RlB-1/2RlB-2) provides a signal to initiate CREACS in the pressurization mode should high radiation be detected.
A minimum of one out of two detectors in either intake will initiate the pressurization mode. With two detector channels inoperable on a Unit, operation may continue as long as CREACS is placed in-service in the pressurization or recirculation mode. Pressurization mode will be initiated after 7 days with one inoperable detector.
Radiological releases during a fuel handling accident while operating in the recirctilation mode could result in unacceptable radiation levels in the CRE since the automatic initiation capability has been defeated for high radiation due to isolation of the detectors.
Therefore, movement of irradiated fuel assemblies or Core Alterations at either Unit will not be permitted when in the recirculation mode. The CRE is considered habitable when the radiological dose to CRE occupants calculated in the licensing basis analyses of OBA consequences is no more than 5 rem TEOE and the CRE occupants are protected from hazardous chemicals and smoke. The testing verifies that the unfiltered air inleakage into the CRE is no greater than the flow rate assumed in the licensing basis analyses of OBA consequences.
When unfiltered air inleakage is greater than the assumed flow rate, CRE boundary is inoperable.
Required action allows time to restore the CRE boundary to OPERABLE status provided mitigating actions can ensure that the CRE remains within the licensing basis habitability limits for the occupants following an accident.
Compensatory measures are discussed in Regulatory Guide 1.196, Section C.2.7.3, which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F. These compensatory measures may also be used as required mitigating actions.
Options for restoring the CRE boundary to OPERABLE status include changing the licensing basis OBA consequence
: analysis, repairing the CRE boundary, or a combination of these actions.
Depending upon the nature of the problem and the corrective action, a full scope inleakage test may not be necessary to establish that the CRE boundary has been restored to OPERABLE status. SALEM -UNIT 1 B 3/4 7-Sf Amendment No. 286 (PSEG Issued)
PLANT SYSTEMS BASES =============================================================================
3/4.7.7 AUXILIARY BUILDING EXHAUST AIR FILTRATION SYSTEM The Auxiliary Building Ventilation System (ABVS) consists of two major subsystems.
They are designed to control Auxiliary Building temperature during normal and emergency modes of operation, and to maintain slightly negative pressure in the building to prevent unmonitored leakage out of the building and, to contain Auxiliary Building airborne contamination (by maintaining slightly negative pressure) during Loss of Coolant Accidents (LOCA) . The two subsystems are: 1. A once through filtration exhaust system, designed to contain particulate and gaseous contamination and prevent it from being released from the building in accordance with 10CFR20, and 2. A once through air supply system, designed to deliver outside air into the building to maintain building temperatures within acceptable limits. For the purposes of satisfying the Technical Specification LCO, one supply fan must be administratively removed from service such that the fan will not auto-start on an actuation signal; however, the supply fan must be OPERABLE with the exception of this administrative control.
These systems operate during normal and emergency plant modes. Additionally, the system provides a flow path for containment purge supply and exhaust during Modes 5 and 6. Either the Containment Purge system or the Auxiliary Building Ventilation System with suction from the containment atmosphere, with associated radiation monitoring will be available whenever movement of irradiated fuel is in progress in the containment building and the equipment hatch is open. If for any reason, this ventilation requirement can not be met, movement of fuel assemblies within the containment building shall be discontinued until the flow path(s) can be reestablished or close the equipment hatch and personnel airlocks.
Appropriate filtration surveillances are contained in the UFSAR Section 9.4.2.4, Test and Inspections.
Auxiliary Building exhaust air filtration system functionality is not required to meet LCO 3.7.7.1.
The ventilation exhaust consists of three 50% capacity fans that are powered from vital buses. The fans are designed for continuous operation, to control the Auxiliary Building pressure at -0.10" Water Gauge with respect to atmosphere.
The ventilation supply consists of two 100% capacity fans that are powered from vital buses, and distribute outdoor air to the general areas and corridors of the building through associated ductwork.
SALEM -UNIT 1 B 3/4 7-5g TSBC SCN 06-015 PLANT SYSTEMS BASES ======================================================================
AUXILIARY BUILDING VENTILATION ALIGNMENT MATRIX NORMAL VENTILATION (Normal plant operations)*
Any two of the three exhaust fans and either of the two supply fans.
* The normal alignment is two exhaust fans and one supply fan. During cooler seasons, and with the absence of the system heating coils, it may be required to limit the amount of colder outside air entering the building.
In this case, it is acceptable to secure both supply fans from operation and reduce the number of operating exhaust fans to one. There is sufficient capacity with the single exhaust fan to maintain the negative pressure within the auxiliary building boundary.
EMERGENCY VENTILATION (Emergency plant operations)
At least two of the three exhaust fans and either one of the two supply fans. Note: During a Safety Injection (SI) all three exhaust fans and one of the supply fans will start. This is acceptable and will maintain the boundary pressure while supplying the required cooling to the building.
Should access/egress become difficult with the three exhaust fans running, one of the exhaust fans should be secured.
OPERABILITY of the Auxiliary Building Ventilation.
System ensures that air, which may contain radioactive materials leaked from ECCS equipment following a LOCA, is monitored prior to release from the plant via the plant vent. Operation of this system and the resultant effect on offsite and control room dose.calculations was assumed in the accident analyses.
ABVS is discussed in Updated Final Safety Analysis Report (UFSAR) Section 9.4.2. 3/4.7.8 SEALED SOURCE CONTAMINATION The limitations on removable contamination for sources requiring leak testing, including alpha emitters, is based on 10 CFR 70.39(c) limits for plutonium.
This limitation will ensure that leakage from byproduct, source, and special nuclear material sources will not exceed allowable intake values. SALEM -UNIT 1 B 3/4 7-5h Amendment 271 PLANT SYSTEMS BASES 3/4.7.9 SNUBBERS All snubbers are required OPERABLE to ensure that the structural integrity of the reactor coolant system and all other safety related systems is maintained during and following a seismic or other event initiating dynamic loads. Snubbers excluded from the program are those installed on nonsafety related systems and then only if their failure or failure of the system on which they were installed, would have. no adverse effect on any safety related system. The program for examination, testing and service life monitoring for snubbers is required to be performed in accordance with ASME BPV Code, Section XI or the OM Code and the applicable addenda as required by 10 CFR 50.55a(g) or 10 CFR 50.55a(b)(3)(v),
except where the NRC has granted specific written relief, pursuant to 10 CFR 50.55a(g)(6)(i),
or authorized alternatives pursuant to 1 O CFR 50.55a(a)(3).
SALEM -UNIT 1 B 3/4 7-6 Amendment No. 301 (PSEG Issued)
PLANT SYSTEMS BASES SALEM -UNIT 1 THIS PAGE INTENTIONALLY BLANK (Material Deleted}
B 3/4 7-7 Amendment No. 301 (PSEG Issued}
PLANT SYSTEMS BASES 3/4.7.10 CHILLED WATER SYSTEM -AUXILIARY BUILDING SUBSYSTEM The OPERABILITY of the chilled water system ensures that the chilled water system will continue to provide the required normal and accident heat removal capability for the control room area, relay rooms, equipment rooms, and other safety related areas. Verification of the actuation of each automatic valve on a Safeguards Initiation signal includes actuation following receipt of a Safety Injection signal. The Auxiliary Building Chilled Water (AB CH) systems can be operated in three possible LCO configurations:
: 1. Three Chillers Required (LCO 3.7.10.a)
: 2. Two Chillers Required (LCO 3.7.10.b)
: 3. Units Cross-Tied (LCO 3.7.10.c)
Three Chillers Required Configuration:
Removal of non-essential heat loads from the chilled water system in the event one chiller is inoperable ensures the remaining heat loads are within the heat removal capacity of the two operable chillers.
Removal of non-essential heat loads from the chilled water system in the event two chillers are inoperable and aligning the CREACs to the maintenance mode ensures the remaining heat loads are within the heat removal capacity of the operable chiller.
During chiller testing, operator actions can take the place of automatic actions.
During Modes 5 and 6 and during movement of irradiated fuel assemblies, chilled water components do not have to be considered inoperable solely on the basis that the backup emergency power source, diesel generator, is inoperable.
This is consistent with Technical Specification 3.8.1.2 which only requires two operable diesel generators.
Two Chillers Required Configuration:
In Two Chiller configuration the analyses demonstrate the system will continue to provide required cooling capability to the control room and safety related areas during normal operation and in the event of an accident in conjunction with a single failure.
The analyses for Two Chiller configuration were performed with both trains of Control Room Emergency Air Conditioning (CREACS) operable and one chiller operating in each unit. This configuration accounts for one of the two required chillers in a unit being out of service and an accident and single failure (loss of chiller) in the opposite unit. The restrictions for entering Two Chiller configuration ensure that the heat loads are within the heat removal capacity of the remaining operable chiller.
The heat removal capacity of the chiller is based on the service water and outside air temperatures present during the period of November 1st through April 30th. Removal of the Emergency Control Air Compressor (ECAC) from the CH system ensures that the heat load is within the capacity of the remaining chiller.
SALEM -UNIT 1 B 3/4 7-8 Amendment No. 316 (PSEG Issued)
PLANT SYSTEMS BASES If one unit is in the Two-Chiller configuration (LCO 3.7.10.b) and the other unit is in the Three Chiller configuration (LCO 3.7.10.a),
CREACS single filtration train alignment is allowed with the unit that is in Three Chiller configuration supplying the CREACS train. Additionally, nonessential heat loads must be isolated from the chilled water system on BOTH Units. Alignment of the single CREACS train to the unit in the Two-Chiller configuration is not permitted.
When entering LCO 3.7.10.b, the third chiller must have CH flow isolated to prevent recirculation of cooling water flow through the non-operating chiller.
When restoring from LCO 3.7.10.b for transitioning to the Three Chiller configuration, the third chiller may be un-isolated under administrative controls.
The administrative controls will require that an operator be dedicated during restoration activities to re-isolate the chiller, if necessary, in the event an accident occurs during the restoration activities.
The loss of the 2 required chillers requires the unit that has the lost the chillers to commence a controlled shutdown (or suspend CORE ALTERATIONS and movement of irradiated fuel assemblies if in MODES 5 or 6 or during the movement of irradiated fuel) and transition the CREACS to single filtration operation with the opposite unit supplying the CREACS train unless both units transition to the Cross-Tied configuration.
In the event that the Cross-tied configuration cannot be implemented or the transition to CREACS single filtration train alignment cannot be implemented, both units will commence a controlled shutdown (or suspend CORE ALTERATIONS and movement of irradiated fuel assemblies if in MODES 5 or 6 or during the movement of irradiated fuel) . Required operating conditions will be verified every 24-hours (SR 4.7.10.d) when in the Two-Chiller configuration.
Cross-Tied Configuration:
In Cross-tie configuration the analyses demonstrate the system will continue to provide required cooling capability to the control room and safety related areas during normal operation and in the event of an accident in either unit. The supporting calculations were performed assuming that one of the required chillers is unavailable due to either a single failure or being out of service (two chillers remaining).
The analyses for Cross-Tied configuration determined that both train of CREACS must be operable.
With only a single train of CREACS operable, the remaining CREACS cooling coil cannot maintain the control room envelope temperatures within acceptable limits. Therefore, entry into CH Cross-Tied configuration is only allowed when both trains of CREACS are operable.
A note is added to TS 3.7.6 Action a to alert operators that CREACS single filtration operation is not permitted if the units are in the CH Cross-tied configuration.
The restrictions for entering the Cross-Tied configuration ensure that the heat loads are within the heat removal capacity of the remaining two operable chillers.
The heat removal capacity of the chillers is based on the service water and outside air temperatures present during the SALEM -UNIT 1 B 3/4 7-Sa Amendment No. 316 (PSEG Issued)
PLANT SYSTEMS BASES period of November 1st through April 30th. Removal of both units' ECACs and both units' non-essential heat loads from the CH system ensures that the heat load is within the capacity of the remaining chillers.
When restoring from LCO 3.7.10.c, the cross-tie valve can be closed under administrative controls.
The administrative controls will require that an operator be dedicated during restoration activities to re-open the cross-tie valve, if necessary, in the event an accident occurs during the restoration activities.
If two Chillers become inoperable in Cross-Tie configuration then both units must commence a controlled shutdown (or suspend CORE ALTERATIONS and movement of irradiated fuel assemblies if in MODES 5 or 6 or during the movement of irradiated fuel) . Required operating conditions will be verified every 24-hours (SR 4.7.10.e) when in the Cross-Tied configuration.
SALEM -UNIT 1 B 3/4 7-Sb Amendment No. 316 (PSEG Issued)
PLANT SYSTEMS BASES 3/4.7.11 FUEL STORAGE POOL BORON CONCENTRATION In the Maximum Density Rack (MDR) design, the spent fuel storage pool is divided into two separate and distinct regions.
Region 1, with 300 storage positions, is designed to accommodate new fuel with a maximum enrichment of 4.25 wt% U-235. Unirradiated and irradiated fuel with initial enrichments up to 5.0 wt% U-235 can also be stored in Region 1 with some restrictions.
These restrictions are stated in TS 3/4.7.12.
Region 2, with 1332 storage positions, is designed to accommodate unirradiated and irradiated fuel with stricter controls as compared to Region 1. These controls are also stated in TS 3/4.7.12.
The water in the spent fuel storage pool normally contains soluble boron, which results in large subcriticality margins under actual operating conditions.
: However, the NRC guidelines, based upon the accident condition in which all soluble poison is assumed to have been lost, specify that the limiting ketf of 0.95 be evaluated in the absence of soluble boron. Hence, the design of both regions is based on the use of unborated water, which maintains each region in a subcritical condition during normal operation with the regions fully loaded. The double contingency principle discussed in ANSI N-16.1-1975 and the USNRC letter of April 14, 1978, to all Power Reactor Licensees
-OT Position for Review and Acceptance of Spent Fuel Storage and Handling Applications (Accession
# 7910310568) allows credit for soluble boron under other abnormal or accident conditions, consistent with postulated accident scenarios.
For example, the most severe accident scenario is associated with the abnormal location of a fresh fuel assembly of 5.0 wt% enrichment which could, in the absence of soluble poison, result in exceeding the design reactivity limitation (ketf of 0.95). This could occur if a fresh fuel assembly of 5.0 wt% enrichment were to be inadvertently loaded into a Region 1 or Region 2 storage cell otherwise filled to capacity.
To mitigate these postulated criticality related accidents, boron is dissolved in the pool water. Calculations for the worst case configuration confirmed that 800 ppm soluble boron (includes an appropriate allowance for boron concentration measurement uncertainty) is adequate to compensate for a mis-located fuel assembly.
Subcriticality of the MDR with no movement of assemblies is achieved without credit for soluble boron and by controlling the location of each assembly in accordance with TS 3/4.7.12.
Prior to movement of an assembly, it is necessary to verify the fuel storage pool boron concentration is within limit in accordance with TS 3/4.7.11.
Most postulated abnormal conditions or accidents in the spent fuel pool do not result in an increase in the reactivity of either MDR region. For example, an event that results in an increase in spent fuel pool temperature or a decrease in water density will not result in a reactivity increase.
An event that results in the spent fuel pool cooling down below normal conditions does not impact the criticality analysis since the analysis assumes a water temperature of 4&deg;C. This assures that the reactivity will always be lower over the expected range of water temperatures.
SALEM -UNIT 1 B 3/4 7-9 Amendment No.262 PLANT SYSTEMS BASES 3/4.7.11 FUEL STORAGE POOL BORON CONCENTRATION (continued)
: However, accidents can be postulated that could increase the reactivity.
This increase in reactivity is unacceptable with unborated water in the storage pool. Thus, for these accident occurrences, the presence of soluble boron in the storage pool prevents criticality exceeding limits in both regions.
The postulated accidents are basically of three types. The first type of postulated accident is an abnormal location of a fuel assembly, the second type of postulated accident is associated with lateral rack movement, and the third type of postulated accident is a dropped fuel assembly on the top of the rack. The dropped fuel assembly and the lateral rack movement have been previously shown to have negligible reactivity effects (<0.0001 Ok). The misplacement of a fuel assembly could result in Keff exceeding the 0.95 limit. However, the negative reactivity effect of a minimum soluble boron concentration of 600 ppm compensates for the increased reactivity caused by any of the postulated accident scenarios.
The accident analyses are summarized in the FSAR Section 9.1.2. The determination of 600 ppm has included the necessary tolerances and uncertainties associated with fuel storage rack criticality analyses.
To ensure that soluble boron concentration measurement uncertainty is appropriately considered, additional margin is incorporated into the limiting condition for operation.
As such, increasing the minimum required boron concentration in the fuel storage pool to 800 ppm conservatively covers the expected range of boron reactivity worth along with allowances associated with boron measurements.
The concentration of dissolved boron in the fuel storage pool satisfies Criterion 2 of 10 CFR 50.36{c)
(2) (ii). The fuel storage pool boron concentration is required to be greater than or equal to 800 ppm. The specified concentration of dissolved boron in the fuel storage pool preserves the assumptions used in the analyses of the potential critical.
accident scenarios.
This concentration of dissolved boron is the minimum required concentration for fuel assembly storage and movement within the fuel storage pool. This LCO applies whenever fuel assemblies are stored in the spent fuel storage pool, until a complete spent fuel storage pool verification has been performed following the iast movement of fuel assemblies in the spent fuel storage pool. This LCO does not apply following the verification, since the verification would confirm that there are no misloaded fuel assemblies.
With no further fuel assembly movements in progress, there is no potential for a misloaded fuel assembly or a dropped fuel assembly.
Salem -Unit 1 B 3/4 7-10 Amendment No.262 PLANT SYSTEMS BASES 3/4.7.11 FUEL STORAGE POOL BORON CONCENTRATION (continued)
The Required Actions are modified indicating that LCO 3.0.3 does not apply. Storage of fuel assemblies and the boron concentration in the spent fuel storage pool are independent of reactor operation.
Therefore TS 3/4 3.7.11 and TS 3/4 3.7.12 include the exception to LCO 3.0.3 to preclude an inappropriate reactor shutdown.
When the concentration of boron in the fuel storage pool is less than required, inunediate action must be taken to preclude the occurrence of an accident or to mitigate the consequences of an accident in progress.
This is most efficiently achieved by inunediately suspending the movement of fuel assemblies.
The concentration of boron is restored simultaneously with suspending movement of fuel assemblies.
Alternatively, beginning a verification of the fuel storage pool fuel locations, to ensure proper locations of the fuel, can be performed.
: However, prior to resuming movement of fuel assemblies, the concentration of boron must be restored.
This does not preclude movement of a fuel assembly to a safe position.
If the LCO is not met while moving fuel assemblies in the spent fuel pool while in MODE 5 or 6, LCO 3.0.3 would not be applicable.
If moving fuel assemblies in spent fuel pool while in MODE 1, 2, 3, or 4, the fuel movement is independent of reactor operation.
Therefore, inability to suspend movement of fuel assemblies is not sufficient reason to require a reactor shutdown.
This SR verifies that the concentration of boron in the fuel storage pool is within the required limit. As long as this SR is met, the analyzed accidents are fully addressed.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Salem -Unit 1 B 3/4 7-11 Amendment No. 299 (PSEG Issued)
PLANT SYSTEMS BASES 3/4.7.12 FUEL ASSEMBLY STORAGE IN THE SPENT FUEL POOL In the Maximum Density Rack (MOR) design, the spent fuel storage pool is divided into two separate and distinct regions.
Region 1, with 300 storage positions, is designed to accommodate new fuel with a maximum enrichment of 4.25 wt% U-235. Unirradiated and irradiated fuel with initial enrichments up to 5.0 wt% U-235 can also be stored in Region 1 with some restrictions.
These restrictions are stated in TS 3/4.7.12.
Region 2, with 1332 storage positions, is designed to accommodate unirradiated and irradiated fuel with stricter controls as compared to Region 1. These controls are also stated in TS 3/4.7.12.
The water in the spent fuel storage pool normally contains soluble boron, which results in large subcriticality margins under actual operating conditions.
: However, the NRC guidelines, based upon the accident condition in which all soluble poison is assumed to have been lost, specify that the limiting keff of 0.95 be evaluated in the absence of soluble boron. Hence, the design of both regions is based on the use of unborated water, which maintains each region in a subcritical condition during normal operation with the regions fully loaded. The double contingency principle discussed in ANSI N-16.1-1975 and the USNRC letter of April 14, 1978, to all Power Reactor Licensees
-OT Position for Review and Acceptance of Spent Fuel Storage and Handling Applications (Accession
# 7910310568) allows credit for soluble boron under other abnormal or accident conditions, since only a single accident need be considered at one time. For example, the most severe accident scenario is associated with the abnormal location of a fresh fuel assembly of 5.0 wt% enrichment which could, in the absence of soluble poison, result in exceeding the design reactivity limitation (keff of 0.95). This could occur if a fresh fuel assembly of 5.0 wt% enrichment were to be "inadvertently loaded into a Region 1 or Region 2 storage cell otherwise filled to capacity, for any of the configurations.
To mitigate these postulated criticality related accidents, boron is dissolved in the pool water. Calculations for the worst case configuration confirmed that 800 ppm .soluble boron (includes an appropriate allowance for boron concentration measurement uncertainty)is adequate to compensate for a mis-located fuel assembly.
Safe operation of the MOR with no movement of assemblies may therefore be achieved by controlling the location of each assembly in accordance with TS 3/4.7.12.
Prior to movement of an assembly into a fuel assembly storage location in Region 1 or Region 2, it is necessary to perform SR 4.7.11 and either SR 4.7.12.1 or SR 4.7.12.2.
In summary, before moving an assembly into the storage racks it is necessary to:
* validate that its final location meets the criticality
* and since there is a potential to misload the assembly, we need to ensure
* that the Fuel Storage Pool boron concentration is greater than the minimum
* required to preclude exceeding criticality limits prior to moving. The configuration of fuel assemblies in the fuel storage pool satisfies Criterion 2 of 10 CFR 50. 36 (c) (2) (ii). Salem -Unit 1 B 3/4 7-12 Amendment No.262 PLANT SYSTEMS BASES 3/4.7.12 FUEL ASSEMBLY STORAGE IN THE SPENT FUEL POOL (CONTINUED)
The restrictions on the placement of fuel assemblies within the spent fuel pool in accordance with TS 3/4.7.12, in the accompanying LCO, ensures the kerr of the spent fuel storage pool will always remain < 0.95, assuming the pool to be flooded with unborated water. This LCO applies whenever any fuel assembly is stored in Region 1 or Region 2 of the fuel storage pool. The Required Actions are modified indicating that LCO 3.0.3 does not apply. Storage of fuel assemblies and the boron concentration in the spent fuel storage pool are independent of reactor operation.
Therefore TS 3/4.3.7.11 and TS 3/4.3.7.12 include the exception to LCO 3.0.3 to preclude an inappropriate reactor shutdown.
When the configuration of fuel assemblies stored in Region 1 or Region 2 of the spent fuel storage pool is not in accordance with TS 3/4.7.12, the immediate action is to initiate action to make the necessary fuel assembly movement(s) to bring the configuration into compliance with TS 3/4.7.12.
If unable to move fuel assemblies while in MODE 5 or 6,.LCO 3.0.3 would not be applicable.
If unable to move fuel assemblies while in MODE 1, 2, 3, or 4, the action is independent of reactor operation.
Therefore, inability to move fuel assemblies is not sufficient reason to require a reactor shutdown.
The SR verifies by administrative means that the initial enrichment and burnup of the fuel assembly is in accordance with TS 3/4.7.12 in the accompanying LCO. Salem -Unit 1 B 3/4 7-13 Amendment No. 276 3/4.8 ELECTRICAL POWER SYSTEMS BASES 3/4.8.1 and 3/4.8,2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS The OPERABILITY of the A.C. and D.C power sources and associated distribution s.ystems during operation ensures that sufficient power wiJ.l be available to supply the safety related equipment required for 1) the safe shutdown of the facility, and 2) the mitigation and control of* accident conditions within the facility.
The minimum specified independent and redundant A.C. and D.C. power sources and distribution systems satisfy the requirements of General Design Criterion 17 of Appendix "A" to 10 CFR Part 50. The ACTION requirements specified for the levels of degradation of the power sources provide restriction upon continued facility operation commensurate with the level of degradation.
The OPERABILITY of the power sources are consistent with the initial condition assumptions of the accident analyses and are based upon maintaining at least two independent sets of onsite A.C. and D.c. power sources and associated distribution systems OPERABLE during accident conditions coincident with an assumed loss of offsite power and single failure of one onsite A.C. source. When ? system or component is determined to be inoperable solely because its emergency power source is inoperable, or solely because its normal power source is inoperable, it may still be considered
: OPERABLE, provided the appropriate Actions of 3.8.l.1.a.2, b.2 or d.2 are satisfied.
Action 3,8.1.1.a.2, which only applies if the train cannot be powered from an offsite source, is intended to provide assurance that an event coincident with a single failure of the associated DG will not result in a complete loss of safety.function of critical redundant required systems.
Failure of a single circuit will generally not, by itself, cause any equipment to lose normal AC power. Action 3,8.1.1.b.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems.
Action 3.8.1.1.d.2, which applies when two offsite circuits are inoperable, is intended to provide assurance that an event with a coincident single failure will not result in a complete loss of redundant required
.. safety functions.
These systems are powered from the inde'pendent AC electrical power train. However, redundant required systems or components credited by this specification are not necessarily powered from AC electrical sources.
For example, the single train turbine-driven auxiliary feedwater pump is redundant to the two motor-driven pumps. Redundant required system or component failures consist of inoperable equipment associated with a train, redundant to the train that has an inoperable DG or power. LCO 3.0.4.b is not applicable to an inoperable DG. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG. The provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in* this circumstance, SALEM -UNIT 1 B 3/4 B-1 Amendment No.276 3/4.B ELECTRICAL POWER SYSTEMS BASES (Continued}
==========================================================-====================
The completion time for these actions is intended to allow the operator time to evaluate and repair any discovered inoperabilities, This completion time also allows for an exception to the normal "time zero" for beginning the allowed outage time clock, starting only on discovery that both: a. One train has no offsite power supplying its .loads, one DG is inoperable or two required offsite circuits are inoperable; b. A required system or component on the other train is inoperable.
SALEM -UNIT 1 B 3/4 8-la Amendment No.276 3/4.8 ELECTRICAL POWER SYSTEMS BASES (Continued)
If at any time during these conditions a redundant required system or component subsequently bec9mes inoperable, this completion time begins to be tracked.
Discovering no offsite power to one train of the onsite Class lE Electrical Power Distribution System, or one required DG inoperable, coiricident with one or more inoperable required support or supported systems or components that are associated with the qther train that has power, results in starting the completion times for the Action. The specified time is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.
The remaining OPERABLE AC supplies (one offsite circuit and three DGs for Condition (a), two offsite c1rcuits and two DGs for Condition (b), or three DGs for Condition are adequate to supply electrical power to the onsite Class lE Distribution System. Thus, on a component basis, single failure protection for the required system or component's function may have been lost; however, function has not been lost. The completion time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required system or component.
Additionally, the completion time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period. The completion time for Condition d (loss of both offsite circuits) is reduced to 12 hours from that allowed for one train without offsite.
power (Action 3.8.l.1.a.2).
The rationale is that Regulatory Guide 1.93 allows a* completion time of 24 hours for two required offsite circuits inoperable, based upon.the assumption that two complete safety trains are OPERABLE.
When a concurrent requndant required system or component failure exists, this assumption is not the case, and a shorter completion time of 12 hours is appropriate.
The OPERABILITY of the minimum A.C. and D.C, power sources and associated distribution systems during shutdown and refueling ensures that 1) the facility can be maintained in the shutdown or refueling condition for extended time periods and 2) sufficient instrumentation and control capability is available for monitoring and maintaining the unit status. The Applicability of specifications 3.8.2.2, 3.8.2.4, and 3.8.2.6 includes the movement of irradiated fuel assemblies.
This will insure adequate electrical power is for proper operation of the fuel handling building ventilation system during movement of irradiated fuel in the spent fuel pool. An.offsite circuit would be.considered inoperable if it were not available to one required train.
two trains are required by LCOs 3.8.2.2 and 3.B.2.4, the one train with offsite power available may be capable of supporting sufficient required features to allow continuation of CORE ALTERATIONS and irradiated fuel movement.
By the allowance of the option to declare required features inoperable, with no offsite power available, appropriate restrictions will be implemented in accordance with the affected required features LCO's actions.
With the offsite circuit or diesel generator not available to all required trains, the option exists to declare all required features inoperable.
Since this option may involve undesired administrative
: efforts, the allowance for sufficiently conservative actions is made. With both required diesel *generators inoperable, the minimum required diversity of AC power sources is SALEM -UNIT 1 B 3/4 8-2 Amendment No. 264 (.
3/4.8 ELECTRICAL POWER SYSTEMS BASES (Continued)
=============================================================================
not available.
Therefore, it is required to suspend CORE ALTERATIONS, movement of irradiated fuel assemblies, and operations involving positive reactivity additions that could result in loss of required shutdown margin or boron concentration.
Suspending positive reactivity additions that could result in failure to meet the minimum shutdown margin or boron concentration limit is required to assure continued safe operation, The Surveillance Requirements for demonstrating the OPERABILITY of the diesel generators are based upon the recommendations of Regulatory Guide 1.9, "Selection of Diesel Generator Set Capacity for Standby Power Supplies,"
March 10, 1971, and Regulatory Guide 1.108, "Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants,"
Revision 1, August 1977. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Regulatory Guide 1.108 criteria for determining and reporting valid tests and failures, and accelerated diesel generator
: testing, have been superseded by implementation of the Maintenance Rule for the diesel generators per 10CFR50.65.
In addition to the Surveillance Requirements of 4.8.1.1.2, diesel preventative maintenance is performed in accordance with procedures based on manufacturer's recommendations with consideration given to operating experience.
The minimum voltage and frequency stated in the Surveillance Requirements (SR) are those necessary to ensure the Emergency Diesel Generator (EDG) can accept Design Basis Accident (DBA) loading while maintaining acceptable voltage and frequency levels. Stable operation at the nominal voltage and frequency values is also essential in establishing EDG OPERATILITY, but a time constraint is not imposed.
The lack of a time constraint is based on the fact that a typical EDG will experience a period of voltage and frequency oscillations prior to reaching steady state operation if these oscillations are not dampened out by load application.
In lieu of a time constraint in the SR, controls will be provided to monitor and trend the actual time to reach stable operation within the band as a means of ensuring there is no voltage regulator or governor degradation that could cause an EOG to become inoperable.
"Standby condition" for the purpose of defining the condition of the engine i:mmediately prior to starting for surveillance requirements requires that the lube oil temperature be between 100 &deg;F and 170 &deg;F. The minimum lube oil temperature for an OPERABLE diesel is 100 &deg;F. The thirteen second time requirement for the Emergency Diesel Generator to reach rated voltage and frequency was originally based on a Westinghouse assumption of fifteen seconds that included the delay time between the occurrence of the incident and the application of electrical power to the first sequenced safeguards pump (BURL-3011, dated November 13, 1974) and included an instrument response time of two seconds (BURL-1531, dated July 27, 1970). The times specified in UFSAR Section 15.4 bound the thirteen seconds specified in the TS. The narrower band for frequency specified for testing performed in steady state isochronous operation will ensure the EDG will not be run in an
* overloaded condition (steady state) during accident conditions.
Steady state is assumed to be achieved after one minute of operation in the isochronous mode with all required loads sequenced on the bus. The narrower band for steady state voltage is specified for operation when SALEM -UNIT 1 B 3/4 8-3 Amendment No.299 (PSEG Issued) 3/4.8 ELECTRICAL POWER SYSTEMS BASES (Continued) the EOG is not synchronized to the grid to ensure the voltage regulator will protect driven equipment from over-voltages during accident conditions.
Procedural controls will ensure that equipment voltages are maintained within acceptable limits during testing when paralleled to the grid. The wider band for frequency is appropriate for testing done with the governor in the droop mode. Likewise the wider band for voltage is appropriate when paralleled to the grid. All voltages and frequencies specified in SR 4.8.1.1.2 are representative of the analytical values and do not account for postulated instrument inaccuracy.
Instrument inaccuracies for EOG voltage and frequency are administratively 9ontrolled.
Preventive maintenance includes those activities (including pro-test inspections, measurements, adjustments and preparations) performed to maintain an otherwise OPERABLE EOG in an OPERABLE status. Corrective maintenance includes those activities required to. correct a condition that would cause the EOG to be inoperable.
Surveillance requirement 4.8.1.2 is modified by a Note. The reason for the Note is to preclude requiring the OPERABLE OG(s) from being paralleled with the offsite power network or otherwise rendered inoperable during performance of the surveillance requirement, and to preclude de-energizing a required ESF bus or disconnecting a required offsite circuit during performance of surveillance requirements.
With limited AC sources available, a single event could compromise both the required circuit and the OG. It is the intent that these surveillance requirements must still be capable of being met, but actual performance is not required during periods when the DG and offsite circuit are required to be OPERABLE.
During Startup, prior to entering Mode 4, the surveillance requirements are required to be completed if the surveillance frequency has been exceeded or will be exceeded prior to the next scheduled shutdown.
3/4.8.3 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES Containment electrical penetrations and penetration conductors are protected by either deenergizing circuits not required during reactor operation or by demonstrating the OPERABILITY of primary and backup overcurrent protection circuit breakers during periodic surveillance.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Each manufacturer's molded case circuit breakers and lower voltage circuit breakers are grouped into representative samples which are then tested on a rotating basis to ensure that all breakers are tested. If a wide variety exists within any manufacturer's brand of molded case or lower voltage circuit breakers, it is necessary to further divide that manufacturer's breakers into groups and treat each group as a separate type of breaker for surveillance purposes.
Containment penetration conductor overcurrent protective device information is provided in the UFSAR. SALEM -UNIT 1 B 3/4 8-4 Amendment No.299 (PSEG Issued) 3/4.9 REFUEL&deg;ING OPERATIONS BASES 3/4.9.l BORON CONCENT8ATIOli The limit on the boron concentration of the Reactor Coolant System (RCS), the refueling cavity, the fuel storage pool and the refueling canal during refueling ensures that the reactor remains subcritical during Mode 6. Refueling boron concentration is the soluble boron concentration in the coolant in each of these volumes having direct access to the reactor core during The soluble boron concentration offsets the core reactivity and is*measured by chemical of a representative sample of the coolant in eacn of the volumes.
The refueling boron concentration limit is specified in the Core Operating Limits Report (COLR). Plant procedures ensure the specified boron concentration in order to maintain an overall core reactiv!&deg;ty o.f Keff $ o. 95 during fuel handling, with control rods and fuel assemblies assumed to be in the most adverse configuration (least negative reactivity) allowed by plant procedures.
General Design Criterion 26 of lOCFR 50, Appendix A rec;tUires that two independent reactivity control systems of different design principles be provided.
One of these systems must be capable of holding the reactor core subcritical under cold conditions.
The Chemical and Volume Control System (CVCS) is the system capable of maintaining the reactor subcritical in cold conditions by maintaining the boron concentration.
The reactor is brought to shutdown conditions be'fore beginning operations to open the reactor vessel for refueling.
After the*RCS is cooled and *depressurized and the vessel head is unbolted, the head is* slowly removed to form the refueling cavity. The refueling canal and the refueling cavity are then flooded with borated water from the refueling water storage tank through the open reactor vessel by gravity feeding or by the use of the Residual Heat Removal (RHR) System pumps. The fuel storage pool is also adjusted to the refueling boron concentration specified in the COLR. 'l'he action of the RHR System in the RCS and the natural circulation due to thermal driving heads in the reactor vessel and refueling cavity mix the added concentrated boric acid with the water in the refueling canal. The RHR System is in operation during refueling (see 'TS 3/4.9.8, "Residual Heat Removal (RHR) and Coolant Circulation
-: All Water levels, " and "Low Water Level") to provide forced circulation in the RCS and assist in maintaining the boron concentrations in the the refueling canal, and the refueling cavity above the COLR limit. SALEM -UNIT l B 3/4 9-1 Amendment No. 262 3/4.9 REFUELING OPERATIONS BASES During refueling operations, the reactivity condition of the core is consistent with the initial conditions assumed for the boron dilution accident in the accident analysis and is conservati.ve for MODE 6. The boron concentration limit specified in the*coLR is based on the core at the beginning of each fuel cycle (the end of refueling) and includes an uncertainty allowance.
The required boron concentration and the plant refueling procedures that verify the correct fuel-.loading plan {including full core mapping) ensure that the Keff of the core will remain during the refueling operation.
Hence, at least a 5%
margin of safety is established during refueling.
During refueling, the water volume in the spent fuel pool, the transfer canal, the refueling canal, the refueling cavity, and the reactor vessel form a single mass. As a result the soluble boron concentration is relatively the same in each of these volumes.
The RCS boron concentration satisfies Criterion 2 10CFR50.36(c)
(2) (ii). The .LCO requires that a minimum boron concentration be maintained in the RCS, the refueling canal, the fuel storage pool and the refueling cavity while in MODE 6. The boron concentration limit specified in the COLR ensures that a core Keff S 0.95 is maintained fuel handling operations.
Violation of the LCO could lead to an inadvertent criticality during MODE 6. This LCO is applicable in MODE 6 to ensure that the fuel in the reactor vessel will remain subcritical.
The required boron concentration ensures a Keff S 0.95. A note to this LCO modifies the Applicability.
The note states that the limits on boron concentration are only applicable to the refueYing canal, the fuel storage pool and the refueling cavity when those volumes are connected to the Reactor Coolant System. When the refueling canal, the fuel storage pool and the refueling cavity are isolated from the RCS, no potential path for boron dilution exists. Above.MODE 6, LCOs 3.1.1.1 and 3.1.1.2 ensure that an adequate amount of negative reactivity is available to shut down the reactor and maintain it subcritical.
Continuation of CORE ALTERATIONS or positive reactivity additions (including actions to reduce boron concentration) is contingent upon maintaining the unit in compliance with the LCO. If the boron concentration of any coolant volume in the RCS, the refueling canal, the fuel storage pool or the refueling cavity is less than its limit, all operations involving CORE ALTERATIONS or positive reactivity additions must be suspended irmnediately.
Suspension of CORE ALTERATIONS and positive reactivity additions shall not preclude moving a component to a safe position.
Operations that individually add limited positive reactivity (e.g. temperature fluctuations from inventory addition or temperature control fluctuations),
but when coinbined with all other operations affecting core reactivity (e.g., intentional boration) result in overall net negative reactivity
: addition, are not precluded by this action. SALEM -UNIT 1 B 3/4 9-la Amendment No. 262 3/4.9 REFUELING OPERATIONS BASES =============================================================================
In addition to immediately s&#xb5;spending CORE ALTERATIONS and positive reactivity additions, boration to restore the concentration must be initiated immediately.
In determining the required combination of boration flow rate and concentration, no unique Design Basis Event must be satisfied.
The only requirement is to restore the boron concentration to its required value as soon as possible.
In order to raise the boron concentration as soon as possible, the operator should begin boration with the best source available for unit conditions.
Once actions have been initiated, they must be continued until the boron concentration is restored.
The restoration time depends on the amount of boron that must be injected to reach the required concentration.
The Surveillance Requirement (SR) ensures that the coolant boron concentration in the RCS, and connected portions of the refueling canal, the fuel storage pool and the refueling cavity, is within the COLR limits. The boron concentration of the coolant in each required volume is determined periodically by chemical analysis.
Prior to reconnecting portions of the refueling canal, the fuel storage pool or the refueling cavity to the RCS, this SR must be met per SR 4.0.4. If any dilution activity has occurred while the cavity or canal was disconnected from the RCS, this SR ensures the correct boron concentration prior to communication with the RCS. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
3/4.9.2.1 UNBORATED WATER SOURCE ISOLATION VALVES During MODE 6 operations, all isolation valves for the reactor makeup water sources containing unborated water that are connected to the Reactor Coolant System (RCS) must be closed to prevent unplanned boron dilution of the reactor coolant.
The isolation valves must be secured in the closed position.
Securing the required valves in the closed position during refueling operations ensu.res that the valves cannot be inadvertently opened, and prevents the flow of unborated water to the filled portion of the RCS. This action precludes the possibility of an inadvertent boron dilution event occurring during MODE 6 refueling operations.
By isolating unborated water sources, a safety analysis for an uncontrolled boron dilution event in accordance with the Standard Review Plan (NUREG-0800, Section 15.4.6) is not required for MODE 6. If any required valve is found not secured in the closed position, there is a potential of having a diluted boron concentration in the RCS. Immediately suspend CORE ALTERATIONS, and initiate actions to secure the valve in the closed position.
Surveillance Requirement 4.9.1 must be performed to demonstrate that required boron concentration exists. The 4 hour completion time is sufficient to obtain and analyze a reactor coolant sample for boron concentration.
Surveillance Requirement 4.9.2.1 demonstrates through a system walkdown that the required valves are closed. The surveillance frequency is controlled under the Surveillance Frequency Control Program.
3/4.9.2.2 INSTRUMENTATION The source range neutron flux monitors are used during refueling operations to determine the core reactivity condition.
Two OPERABLE source range neutron flux monitors are required to alert the operator to unexpected changes in core reactivity, such as a boron dilution event. This ensures that redundant monitoring capability is available to detect changes in core reactivity.
Based on isolating all boron dilution*paths per LCO 3.9.2.1, only the source range neutron flux monitor visual indication in the control room is required for OPERABILITY.
SALEM -UNIT 1 B 3/4 9-1b Amendment No. 311 (PSEG Issued) 3/4.9 REFUELING OPERATIONS BASES =============================================================================
Any combination of NIS source range neutron flux monitors and/or Gamma-Metrics post-accident neutron flux monitors may be used to satisfy the LCO. Two of the four total source range neutron flux monitors are required to be OPERABLE.
With only one required source range neutron flux monitor OPERABLE, redundancy has been lost. Suspending positive reactivity additions that could result in failure to meet the minimum boron concentration limit is required to assure continued safe operation.
With no required source range neutron flux monitor OPERABLE, action to restore a monitor to OPERABLE status shall be initiated immediately.
With no source range neutron flux monitor OPERABLE, there is no direct means of detecting changes in core reactivity.
However, since positive reactivity additions are not to be made, the core reactivity condition is stabilized until the source range neutron flux monitors are OPERABLE.
This stabilized condition is confirmed by performing Surveillance Requirement 4.9.1 to ensure that the required boron concentration exists and adequate-shutdown margin is maintained.
3/4.9.3 DECAY TIME The minimum requirement for reactor subcriticality prior to movement of irradiated fuel assemblies in the reactor pressure vessel ensures that sufficient time has elapsed to allow the radioactive decay of the short lived fission products.
The 80-hour decay time (LAR S08-01) is consistent with the assumptions used in the fuel handling accident analyses and the resulting dose calculations using the Alternative Source Term described in Reg. Guide 1.183. The minimum requirement for reactor subcriticality also ensures that the decay time is consistent with that assumed in the Spent Fuel Pool cooling analysis.
The calendar based restrictions are established for the actual movement of irradiated fuel; i.e., movement cannot commence in the October 15th through May 151h window unless at least 80 hours has elapsed since subcriticality was achieved.
The 80 hour clock can start prior to October 15 but must end in the October 15th -May 15th window for the 80 hour criteria to be applicable.
Similarly, fuel movement between May 16th and October 14th commence*unless at least 168 hours has elapsed since subcriticality was achieved.
Delaware River water average temperature between October 15th and May 15th is determined from historical data taken over 30 years. The use of 30 years of data to select maximum temperature is consistent with Reg. Guide 1.27, "Ultimate Heat Sink for Nuclear Power Plants". A core offload has the potential to occur during both applicability time frames. In order not to exceed the analyzed Spent Fuel Pool cooling capability to maintain the water temperature below 180&deg;F, two decay time limits are provided.
In addition, PSEG has developed and implemented a Spent Fuel Pool Integrated Decay Heat Management Program as part of the Salem Outage Risk Assessment.
This program requires a pre-outage assessment of the Spent Fuel Pool heat loads and heatup rates to assure available Spent Fuel Pool cooling capability prior to offloading fuel. SALEM -UNIT 1 B 3/4 9-1c Amendment No. 311 (PSEG Issued) 3/4.9 REFUELING OPERATIONS BASES =============================================================================
3/4.9.4 CONTAINMENT BUILDING PENETRATIONS During movement of irradiated fuel assemblies within containment the requirements for containment building penetration closure capability and OPERABILITY ensure that a release of fission product radioactivity within containment will not exceed the guidelines and dose calculations described in Reg. Guide 1.183, Alternative Radiological Source Term for Evaluating Design Basis Accidents at Nuclear Power Reactors.
In MODE 6, the potential for containment pressurization as a result of an accident is not likely. Therefore, the requirements to isolate the containment from the outside atmosphere can be less stringent.
The LCO requirements during movement of irradiated fuel assemblies within containment are referred to as "containment closure" rather than containment OPERABILITY.
For the containment to be OPERABLE, CONTAINMENT INTEGRITY must be maintained.
Containment closure means that all potential containment atmosphere release paths are closed or capable of being closed. Closure restrictions include the administrative controls to allow the opening of both airlock doors and the equipment hatch during fuel movement provided that: 1) the equipment inside door or an equivalent closure device installed is capable of being closed with four bolts within 1 hour by a designated personnel;
: 2) the airlock door is capable of being closed within 1 hour by a designated personnel,
: 3) either the Containment Purge System or the Auxiliary Building Ventilation System taking suction from the containment atmosphere are operating and 4) the plant is in Mode 6 with at least 23 feet of water above the reactor pressure vessel flange. Administrative requirements are established for the responsibilities and appropriate actions of the designated personnel in the event of a Fuel Handling Accident inside containment.
These requirements include the responsibility to be able to communicate with the control room, to ensure that the equipment hatch is capable of being closed, and to close the equipment hatch and personnel airlocks within 1 hour in the event of a fuel handling accident inside containment.
These administrative controls ensure . containment.closure will be established in accordance with and not to exceed the dose calculations performed using guidelines of Regulatory Guide 1.183. SALEM -UNIT 1 B 3/4 9-1d Amendment No. 311 (PSEG Issued) 3/4.9 REFUELING OPERATIONS BASES . ====================================================================F===
The containment serves to limit the fission product radioactivity that may be released from the. reactor core following an accident, such that offslte radiation exposures are maintained well within the requirements of 1OCFR100 and Reg. Gulde 1.183, Alternative Source Term, as appllcable.
Addltlonally, the containment provides radiation shielding from the fission products that may be ln the containment atmosphere following accident conditions.
The Containment Equipment Hatch, which ls part of the containment pressure
: boundary, provides a means for .moving large -equipment and components Into or out of containment.
During movelT)ent of Irradiated fliel assemblies within containment, the Containment Equipment Ha:tch inside door .can be operi provided that: 1) It Is capable of: being closed with four bolts within 1
* hour by designated*
personnel,
: 2) either the Containment Purge System or the Auxiliary Bulldlng Ventilation System taking suction from the containment atmosphere are operating and 3) The plant Is In Mode 6 with at least 23 feet of water above th1;1 reactor pressure vessel flange. Good engineering practice dictates that the bolts required by the LOO are approximately
_eciually spaced. An equivalent closure device may be Installed a!i an alternative to Installing the Containment Equipment Hatch Inside door with a minimum of four bolts. Such a closure device may provide penetrations for temporacy to support main,tenance ins.ide.
containment a1 closure Is required; and niay *tie Installed ln place of the Containment Equipment Hatch inside door or outside door. Penetrations incorporated Into the design of an equivalent closure device wlll be. considered a part of the boundary and such wlll be subject *to the requirements of Technical
*specification 3/4.9.4.
Any equlvalent closure device used to satisfy the requirements of Technical Specification 3/4.9.4.a will be designed, fabricated, Installed, tested, and utlllzed In accordance with established p*rocedures to ensure that the design requirements for the mitigation of a fuel. handling accident during refueling operations are met. In case that this equivalent closure device Is Installed In lieu of the hatch Inside* door, the same restrictions and administrative controls apply to ensure closure wlll take place within 1 hour following a FHA Inside containment.
The containment air locks, which are also part of the containment pressure
: boundary, provide a means for personnel access during operation In MODES 1, 2, 3, and 4 as specified In LOO 3.6.1.3, "Containment Air Locks". Each alr lock has a. door at both ends. The doors are normally interlocked to prevent
* simultaneous opening when containment OPERABIL11'Y Is required.
During periods of unit shutdown, when containment closure Is not required and frequent containment entry Is .necessary, the air lock Interlock mechanism may be disabled.
This allows both doors of an airlock to remain open for extended periods.
* During movement of Irradiated fuel assemblies within containment, containment closure may be *required; therefore, the door interlock mechanism may remain disabled,
*and both doors of each containment airlock may be open If: 1) At least one door of each airlock Is capable of being closed within 1 hour by a dedicated Individual,
: 2) either the Containment Purge System or the Auxiliary Building Ventilation System taking suction from the containment atmosphere are operating and 3) the plant is In Mode 6 with at least 23 feet of water above the reactor pressure vessel flange. In the postulated Fuel Handling
: Accident, the revised dose calculations, performed using 1 O CFR 50.67 and Regulatory Gulde 1.183, Alternative Source Term, do not take credit for automatic containment purge Isolation thus allowing for continuous monitoring of containment activity until containment closure Is achieved.
If required, containment purge.Isolation can be initiated from the control room. The other containment penetrations that provide direct access from containment atmosphere to outside atmosphere must be Isolated on at least one side. Isolation may be achieved by an OPERABLE automatic Isolation valve, or by a manual Isolation valve, blind flange, or equivalent.
Equivalent isolation methods may include the use of a material that can provide a temporary atmospherlo
: pressure, ventilation barrier.
Any method used to satisfy the requirements of Technical Specification 3/4.9.4.c.1 wlll be designed, fabricated, Installed, tested, and utilized In accordance with establlshed procedures to ensure that the design requirements for the mitigation of a fuel handling accident during refueling operations are met. *
* SALEM *UNIT 1* B 3/4 9*2 Amendment No. 263 3/4.9 REFUELING OPERATIONS BASES ===============================================================================
The surveillance requirement 4.9.4.2 demonstrates that the necessary
: hardware, tools, and equipment are available to close the equipment hatch. The surveillance is performed prior to movement of irradiated fuel assemblies within the containment.
This surveillance is only required to be met when the equipment hatch is to be open during fuel movement.
3/4.9.5 COMMUNICATIONS Deleted.
3/4.9.6 MANIPULATOR CRANE Deleted.
3/4.9.7 CRANE TRAVEL -SPENT FUEL STORAGE BUILDING Deleted.
3/4.9.8 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION The requirements that at least one residual heat removal loop be in operation ensures that (1) sufficient cooling capacity Is available to remove decay heat and maintain the water in the reactor pressure vessel below 140&deg;F as required during the REFUELING MODE, and* (2) sufficient coolant circulation is maintained through the reactor core to minimize the effects of a boron dilution Incident and prevent boron stratification.
A minimum flow rate of 1000 gpm Is required.
Additional flow limitations are specified In plant procedures, with the design basis documented in the Salem UFSAR. These flow limitations address the concerns related to vortexing and air entrapment in the Residual Heat Removal system, and provide operational
*flexibility by adjusting the flow limitations based on time after shutdown.
The requirement to have two RHR loops OPERABLE when there is less than 23 feet of water above the reactor vessel flange ensures that a single failure of the operating RHR loop will not result in a complete loss of residual heat removal capability.
SALEM -UNIT 1 B 3/4 9-3 Amendment No. 293 (PSEG Issued)
REFUELING OPERATIONS BASES
. . For support systems:
Service Water (SW) and Component
.Cooling (CC), component redundancy Is necessary to ensure no single active component failure will cause the loss of Decay Heat Removal.
One piping path of SW and CC ts adequate when It supports both RHA loops. The support systems needed before entering Into the desired configuration (e.g., one service water loop out for maintenance In Modes 5*and 6) are controlled by procedures, and Include the tollowlng:
* A requirement
*that the two RHR, two CC and two SW pumps, powered from two different vital
.
* A fisting of the active *(air/motor oper.ated) valves In the .affected flow path to be locked open or disabled.
Note that four filled reactor coolant loops, with at least two steam generators with at least their secondary side water level greatel' than or equal to 5&deg;/o (narrow range), may be substituted tor one residual heat removal loop. This ensures that a single does not cause a loss of decay heat removal.
With the reactor vessel head removed and 23 feet of water above the reactor pressure*vessel flange, a
* large' heat s1nk
* 1s avallable for cci're cooling.
Thus,* 1n the event 'of. a f allure* of the operating*
"RH R loop;: . * . adequate time Is provided to Initiate emergency procedures to cool the core. 3/4.9.9 .(NOT USED) 3/4.9.10 and 3/419/11 WATER LEVEL* REACTOR VESSEL AND STORAGE POOL The restrictions on minimum water level ensure that sufficient water depth Is available to remove 99% of the assumed 10&deg;io Iodine gap actMty. released from *the rupture of an Irradiated fuel assembly.
The mlnlmurn water depth ts consistent with the assumptions of the accident
.. 3/4.9.12 FUEL HANDLING AREA VENTILATlqN SYSTEM The operablllty of the F.uel Handling Area Ventilation System during movement of Irradiated fuel ensures that a release of fission product radioaotivl:tY wlthli:i the Fuel Handling Building will not exceed the guidelines and dose calculations described l.n Reg. Gulde 1.183, Alternative Radlological Source Term tor Evaluating Design Basis Accidents at Nuclear Power Reactors.
SALEM
* UNIT 1 8 3/4 9.4 Amendment No. 263 3/4.10 SPECIAL TEST EXCEPTIONS BASES 3/4.10.1 SHUTDOWN MARGIN This special test exception provides that a minimum amount of control rod worth is immediately available for reactivity control when tests are performed for control rod worth measurement.
This special test exception is required ta permit the periodic verification of the actua1 versus predicted core reactivity condition occurring as a result of fuel burnup or fuel cycling operations.
3/4.10.2 GROUP HEIGHT, INSERTION, AND POWER DISTRIBUTION LIMITS This special test exception permits individual control rods to be positioned outside of their normal group heights and insertion limits during the performance of such PHYSICS TESTS as those required to l} measure control rod worth and 2) determine the reactor stability index and damping factor under xenon .oscillation conditions.
3/4.10.3 PHYSICS TESTS This special test exception permits PHYSICS TESTS to be performed at less than or equal to 5% of RATED THERMAL POWER and is required to verify the fundamentai nuclear characteristics of the reactor core and related instrumentation.
3/4.10.4 NO FLOW TESTS This special test exception permits reactor criticality under no flow conditions and is required to perform cer.tain startup and PHYSICS TESTS while at low THERMAL POWER levels. SALEM -UNIT l B 3/4 10-1 3/4.ll RADIOACTIVE EFFLUENTS BASES 3/4.ll.l LIQUID EFFLUENTS 3/4.ll.l.l Deleted 3/4.ll.l.2 Deleted*
SALEM UNIT l B 3/4 11*1 Amendment RADIOACTIVE EFFLUENTS BASES 3/4.11.l.3 Deleted 3/4.ll.l.4 LIQUID HOLDUP TANKS The in this specification include all those outdoor tanks. that are not surrounded by liners, dikes, or walls capable of holding *the tank contents and.that do not have tank overfl9ws and surrounding area drains connected to the liquid radwaste treatment system. SALEM -UNIT l :B 3/4 11-2 Amendment No. 234 RADIOACTIVE EFFLUENTS BASES .Restricting the quantity of radioactive material contained in the specified provides assurance that in the event of an uz;controlled release of the tanks* contents, the resulting concentrations would be-less than the limits of 10 CFR. Part 20, Appendix B, Table II, Column 2, at the nearest potabl'e water supply and the surface water supply in an UNRESTRICTED AREA. 3/4.ll.2 GASEOUS EFFLUENTS 3/4.11.2.1 Deleted SALEM -UNIT 1 .Amendment No.234 RADIOACTIVE EFFLUENTS BASES 3/4.ll.2.2 Deleted 3/4.ll.2.3 Deleted SALEM
* UNIT l .... I. B 3/4 11**4 Amendment No. 234 RADIOACTIVE EFFLUENTS BASES 3/4.il.2.4 Deleted SALEM -UNIT l B 3/4 ll-5 Amendment No. 234 RADIOACTIVE EFFLUENTS BASES 3/4,ll.2.5 EXPLOSIVE GAS MIXTURE This specification is provided to ensure that the concentration of potentially explosive gas mixtures contained in the waste gas holdup system is maintained below the flammability limits of hydrogen and oxygen.
the concgntration:of oxygen below the specified values provides assurance that the reieases of radioactive materials will be controlled in conformance the requirements of General.
Design Criterion 60 of Appendix A to lO CFR Part 50. This specification is not applicable to portions of the Waste Gas system Removed from service for provided that the portions removed for maintenance are isolated from sources of hydrogen and purged of hydrogen to less than 4% by volume. 3/4.ll.3 Deleted SALEM -UNIT l B 3/4 ll-6 Amendment No. 261 RADIOACTIVE EFFLUENTS
* BASES 3/4.11.4 Deleted SALEM UNIT 1 Amendment No. 234 RADIOACTIVE EFFLUENTS BASES 3/4.l.2 Deleted SALEM -UNJ:T 1 B 3/4 12-1 Amendment No. 234 This Page Intentionally Blank SALEM -UNIT l B 3/4 l.2-2 Amendment No. 234 
. l SAFE TY LIMITS
:REACTOR The restrictiona of thi.a aaj;ety 1imit prevent ovarhaatinq of the f'uel and cladding perforation which would result in th* release of fission products to the r*actor coolant:.
overheating of th* fuel cladding
.is p.:'8Veetad by restricting fuel operation to within th* nucleat.
boiling regilae where the heat tn.nsfer coe&#xa3;ficitmt ia l.a:ga and the cladding au:fact1 temperature i* *l.ight.ly above th* cool.ant
*aturation temperature.
Operation abov. th* upper bounda%y of th* nucl*ate boiling raqima coul.d .result in excessive cladding becaua* of th* on.s*t of departure from nucleate boil.ing (DNB) and th* resultant aharp ractuction
:in heat transfer
* coefficient.
DNB is not a directly measurable paramate:
during operation and therefore ni!::RM1'L POWER and bactor Cool.ant Tamperature and Pressure have bean related to DNB through correlations which have been developed to predict the orm fl.we and the location of t>NB for axially unifor:mand ncn-unifo:r."m heat fl.ux distributions.
The local DNB heat nwc ratio, ONBR, decided as the ratio of the heat fl.we that would cause DNB at a particul.a.r core location to the local heat flux, is indicative of the margin to ONB. Tile ONB design basis is as fol.lows:
uncertai.nt.i.es
.in the WRB-1 and WU-2 c:)rrelations,*
plant operating parameters, nuclear and th*.:mal parameters, fuel fabrication parameters, and computer codes a.re considered statistica.lly such t.'1at there is at 1eaat a, 95 percent probability vith 95 percent confidence
*iaval that DNER will. not occur en the most lilaiting fuel .rod during Condition I and II events. This establishes a dasign DNBR value which aust be 111.ot in plant safety anal.yses using values of input Pa.rameters without uncertainties.
The curves of Figure 2.1-1 *hova the loci of pointa of '!HE:RMAL
-i'OW!:R,
-I R.aactor Coolant System pressu.r*
and-average fe.r which the minim.um D::mR is no less than th* design DNBR value, o.r the avarage ianthalpy at tha viassel exit is equal to the enthalpy of saturated.
liqW.d. The curves are based on an enthalpy hot channel facto:, J"CTAB and a reference cosine with a peak of 1.55 for axial pove.r shape . .An allovanca i.s ir1cluded.
for an increase in !9'411 at reduced power based on th* exprea:icn:
[l.O + PF611 (1.0 -P)] Where: ip the.J.imit at RATED POWER in th* Cc.re Operating Lim.its Report (COLR). PF.u is the Factor Mul.tiplie.r Ff.All cm.a, -and P is THERMAL POWER RATED 1'HE:RMAL POWZll These 1.illliting heat flux conditions a.re higher than those cal.culated for the range of control red positions from FOLLY WJ:THORAWN to the maximum allowable control rod insertion assuming th* axial. powar .i.%ibalance is wi.thi.n the limits of the f1 (delta I) funcd.on of the ove.rtamperature tri.p. When the axial power SA::.EM -UNIT 2 B 2-1 .Amendment No. 197 
*. SAFETY LIMITS BASES imbalance is not within the tolerance, the axial power imbalance affect on the Overtemperature delta T trips will reduce the setpoints to provide protection consistent with core safety limits. 2. 1.2 REACTOR COOLANT SYSTEM PRESSURE The restriction of this*Safety Limit protects th1 integrity of the.Reactor Coolant System from overpressurization and thereby prevents the release of radionuclides contained in the reactor coolant from reaching the containment atmosph*rL The reactor p1"8ssure vessel and pressurizer are designed to Section III of the ASME Codi for Nuclear PO'Mer Plant which permits a maximum transient pressure of 110: (2735 psig) af design pressure.
The Reactor COolant System piping and fittings are designed to AHSI B 31.1 1955 Edition whil1 the valves are designed to ANSI B 16.S, MSS-SP-66-1964, or ASME Section III-1968, which permit maximum transient pressures of up to l20S (2985 psig) of component design pressure.
The Safety Limit of 2735 psig is therefore consistent with th1 design criteria and associated code requirements.
The entire Reactor Coolant System f s hydrotested at* 3107 psfg, l2SS of design pressure, to demonstrate 1ntegrfty prior to fnit1al operation.
SAUM* -UNIT 2 B 2*Z 2.2 LIMITING SAFETY SYSTEM SETTINGS 2.2.1 REACTQR TRIP SYSTEM INSTRUMENTATION SET?OINTS The Trip Setpoints are the nominal values at which the bistables are set. Any bistable is considered to be properly adjusted when the "as-left" value is within the band for CHANNEL CALIBRATION accuracy (i.e., +/- rack calibration+
comparator setting accuracy)
. The Trip Setpoints used in the are based on the analytical limits stated in the UFSAR. The selection of these Trip Setpoints is such that adequate protection is provided when all sensor and processing time delays are taken into account.
To allow for calibration tolerances, instrumentation uncertainties, instrument drift, and severe environment errors for those Reactor Protection System (RPS) channels that must function in harsh environments as defined by 10 CFR 50.49, the Trip Setpoints and Allowable Values specified in the Technical Specification Limiting Conditions for Operation (LCO's) are conservatively adjusted with respect to the analytical limits. The methodology used to calculate the Setpoints is consistent with Instrument society of America standard ISA-$67.04-1982, which is endorsed via NRC Regulatory Guide 1.105, Rev. 2. The actual nominal Trip Setpoint entered into the bistable is more conservative than that specified by the Allowable Value to account for changes in random measurement errors detectable by a CHANNEL FUNCTIONAL TEST. One example of such a change in measurement error is drift during the surveillance interval.
If the measured setpoint does not exceed the-Allowable Value, the bistable is considered OPERABLE.
Setpoints in accordance with the Allowable Value ensure that the safety analyses which demonstrate that safety limits are not violated remain valid (provided the unit is within the LCO' s at onset of any design basis event and the equipment functions as designed).
The Trip Setpoints and Allowable Values listed in the LCO's incorporate all of the known uncertainties applicable for each channel.
The magnitudes of these uncertainties are factored into the determination of each Trip Setpoint.
All field sensors and signal processing equipment for these channels are assumed to operate within the allowances of these uncertainty magnitudes.
Manual Reactor Trip The Manual Reactor Trip is a redundant channel to the automatic protective instrumentation channels and provides manual reactor trip capability.
Power Range, Neutron Flux The Power Neutron Flux channel high setpoint provides reactor core protection against reactivity excursions which are too rapid to be protected by temperature and pressure protective circuitry.
The low set point provides redundant protection in the power range for a power excursion beginning from low power. The trip associated with the low setpoint may be manually bypassed when P-10 is active (two of the four power range channels indicate a power level of above approximately 9 percent of RATED THERMAL POWER) and is auto-SALEM -UNIT 2 B 2-3 Amendment
!".J. 140 I LIMITING SAFETY SYSTEM SETTINGS BASES matically reinstated when P-10 becomes inactive (three of the four channels indicate a power level below approximately 9 percent of RATED THERMAL POWER) . Power Range, Neutron Flux, High Rate The Power Range Positive Rate trip provides protection against rapid flux increases which are characteristic of rod ejection events from any power level. Specifically, this trip complements the Power Range Neutron Flux High and Low trips to ensure that the criteria are met for rod ejection from partial power. Intermediate and Source Range, Nuclear Flux The Intermediate and Source Range, Nuclear Flux trips provide reactor core protection during reactor startup.
These trips provide redundant protection to the low setpoint trip of the Power Range, Neutron Flux channels.
The Source Range Channels will initiate a reactor trip at about 10+5 counts per second unless manually blocked when P-6 becomes active. The Intermediate Range Channels will initiate a reactor trip at a current level proportional to approximately 25 percent of RATED THERMAL POWER unless manually blocked when P-10 becomes active. No credit was taken for operation of the trips associated with either the Intermediate or Source Range Channels in the* accident analyses;
: however, their functional capability at the specified trip settings is required by this specification to enhance the overall reliability of the Reactor Protection System. Overtemperature T The Overtemperature T trip provides core protection to prevent DNB for all combinations of pressure, power, coolant temperature, and axial power distribution, provided that the transient is slow with respect to piping transit delays from the core to the temperature detectors (about 4 seconds),
and pressure is within the range between the High and Low Pressure reactor trips. This setpoint includes corrections for changes in density and heat capacity of water with temperature and dynamic compensation for piping delays from the core to the loop temperature detectors.
With normal axial power distribution, this reactor trip limit is always below the core safety limit as shown in Figure 2.1-1. If axial peaks are greater than design, as indicated by the difference between top and bottom power range nuclear detectors, the reactor trip is automatically reduced according to the notations in Table 2.2-1. SALEM -UNIT 2 B 2-4 Amendment No. 261 (PSEG Issued)
LIMITING SAFETY SYSTEM SETTINGS BASES Operation with a reactor coolant loop out of service below the 4 loop P-8 setpoint does not require reactor protection system setpoint modification because the P-8 setpoint and associated trip will prevent DNB during 3 loop operation exclusive of the Overtemperature delta T setpoint.
Three loop operation above the 4 loop P-8 has not been evaluated and is not permitted.
Overpower Delta T The Overpower delta T reactor trip provides assurance of fuel integrity, e.g., no melting, under all possible overpower conditions, limits the required range for Overtemperature delta T protection, and provides a backup to the High Neutron Flux trip. The setpoint includes corrections for changes in density and heat capacity of water with temperature, and dynamic compensation for piping delays from the core to the loop temperature detectors.
As a result of the new AREVA steam generators, credit is taken for the operation of this trip in the accident analyses for the protection of the reactor core following a main steam line break. Pressurizer Pressure The Pressurizer High and Low Pressure trips are provided to limit' the pressure range in which reactor operation is permitted.
The High Pressure trip is backed up by the pressurizer code safety valves for RCS overpressure protection, and is therefore set lower than the set pressure for these valves (2485 psig) .. The Low Pressure trip provides protection by tripping the reactor in the event of a loss of reactor coolant pressure.
Pressurizer Water Level The Pressurizer High Water Level trip ensures protection against Reactor Coolant System overpressurization by limiting the water level to a volume sufficient to retain a steam bubble and prevent water relief through the pressurizer safety valves. No credit was taken for operation of this trip in the accident analyses;
: however, its functional capability at the specified trip setting is required by this specification
*to enhance the overall reliability of the Reactor Protection System. SALEM -UNIT 2 B 2-5 Amendment No. 52010-119 (PSEG Issued) 
----* ----L::MI'l'ING SAFETY SYSTEM SETTINGS
=============-===============sn=========================================-=-=-======
Lc.i** of Flow Th* Loaa of' Flow t:i.pa core protection to prevent DNB .i.ll the 11V1mt of a 1oaa of one er moJ:e z:eactor coolant pumps. AJ:)ova 11 pe:cent of' RADn THZR!Q.L POWER, an autcaatic reactor trip 1ti.ll occur if' th* now in any two 1oop* drop below 90t o:f nal f'ul.1 l.oop fl.ow. Abov9 36' (P-8) of' RAftn POWER, autoaatic
:.actor Uip will cc=: if' th* f'low in any aingle loop drops tieiow 90-t o:f tJOJllin&l f'ul.l 1oop Thi* latter trip will prevent th* minilllum value of the ONBR f'rom going below the d**i;n IlNBR value dw:i?lg normal. operatioD&l.
transicita.
StQam (!enerator Water Leva1 1'he Steam. Generator Water Level I.ow-Low trip provides core protection by p:rftvenUnq operation with the steam generator water level. below the m.im-WD vo:.uma :required for adequate beat removal capacity.
The specified aetpoint p:rovides allowance that the::e will be sufficient water inventory in the atea: gene:rators at the ti.me of trip to allow for starting of the auxi..liary fectdwatar system. SAIJ:M -
2 B 2-6 Alllendmen t No
* 1 9 7 LIMITING SAFETY SYSTEM SETTINGS BASES and Underfreguency
-Reactor Coolant Pump Busses The Undervoltage and Underfrequency Reactor Coolant Puni> bus trips provide reactor core protection against IH5 as a result of loss of voltage or
* underfrequency to more than one reactor coolant pump. The specified set points assure a reactor trip signal is generated before the 1C7ff flow trip set point is reached.
Time delays are incorporated in the underfrequency and undervoltage trips to prevent spurious reactor trips from momentary electrical pcwer transients.
For undervoltage, the delay fs set so that the time required for a signal to reach the reactor trip breakers following the sinultaneous trip of two or more reactor coolant puq> bus circuit breakers shall not exceed 0.9 seconds.
For underfrequency, the delay is set so that the time required for a signal to reach the reactor trip breakers after the underfrequenc:y trip set point is reached shall not exceed 0.3 seconds.
Turbine Trip A Turbine Trip causes a direct reactor trip when operating above P-9. Each of the turbine trips provide turbine protection and reduce the severity of the ensuing transient.
No credit was taken in the accident analyses for operation of these trips. Their functional capabflfty at the specified trfp settings is required to enhance the overall reliability of the Reactor Protection System. Safety Injection Input from ESF If a reactor trf p has not already been generated by the reactor protective instrumentation, the ESF automatic actuation logic channels will initiate a reactor trip upon any signal which initiates a safety injection.
This trip is provided to protect the core in the event of a LDCA. The ESF instrumentation channels which initiate a safety injection signal are shown f n Table 3.3-3. Reactor Coolant Pump Breaker Position Trip The Reactor Coolant Pump Breaker Pos1tfon Trip 1s an anticipatory trip which provides reactor core protection against resulting from the opening of two or more pump breakers above P-7. This trip 1s blocked below P-7. The open/close position trip assures a reactor trip signal fs before the low flow trip set point is reached.
No credit was taken in the accident analyses for operation of this trip *. The functional capability at the open/close position settings 1s required to enhance the overall reliab111ty of the Reactor Protection system. SALEM -UNIT 2 B 2-7 Amendment No
* 60 3/4,0 APPL!CABitITY
,BASES Specifie1,!on J.O.l through 3.0.4 establish the qeneral requirements I applicable to-Limitinq conditions for These requirements are based I on the requirements for Limiting conditions for Operation etated in the Code. I of Federal Regulations, 10 CFR S0.36(c)(2):
I I ''Limiting conditions for operation are the lowest functional capability I or performance level* of equipment required for safe operation of the I facility.
When a limitinq condition for operation of a nuclear reactor is not I met, the licensee ehall shut down the reactor or follow any remedial action I permitted by the technical specification until the condition can be met." 1 I specification 3.0.1 establishes the Applicability statement within each I individual
&pacification a* the requirement for when (i.e., in which I MODES or other specified conditions) conformance to the Limiting I conditions for Operation i* required for aafe operation of the facility.
The I ACTION requirement*
establish those remedial measure*
that mu1t b* taken I within specified time limits when the requirements of a Limiting condition for I Operation are not met. I I There are two ba*ic type* of ACTION requirement*.
The firet specifiea the I remedial mea*ur**
that permit operation of th* facility which .11 not I rHtr_ict*d by th* time limit* cf th* ACTION requirement*.
In thi* I case, conformance to the ACTION requirement*
provide*
an acceptable level of I safety for unlimited continued operation a* long a1.th* ACTION r*quiremanta I continue to be met. The second type of ACTION requirement 1pecifia*
a time I limit in which conformance to the condition*
of th* Limiting Condition for \ Operation must be met. Thi* time limit i* the allowable outage time to I restore an inoperable
*y*t*m or component to OPERABLE 1tatu* or for re1toring I parameters within 1pecified limits. If these action* are not completed within I the allowable outage time limit&, a shutdown i* required to place the facility I in a MODE or condition in which the *pacification no longer applie*.
It ie I not intended that th* shutdown ACTION requirements b* uaed a1 an operational
\ convenience which permits (routine) voluntary removal of a sy*tem(a) or I component(*)
from service in lieu of other alternativ**
that would not ra*ult I in redundant
*y*t*m* or component*
being inoperable.
I I The specified time limit* of th* ACTION r*quirement*
are applicable from the l point in time it ii identified that a Limiting Condition for Operation i* not l met. The time Limit* of the ACTION requirement*
are al*o applicable when a I syatem or i* r*movad from 1ervice for *urveillance teeting or l inve1ti9a\ion of operational problems.
Individual ep*citication1 may include l a specified tim* limit for th* completion of a surveillance R*quir*m*nt wh*n I equipment i* rlimov*d from service.
In thi* case, the allowabl*
outage time l limit* of the ACTION requirement*
ar* applicable when thi* limit *xpir** if I the*eurveillanc*
ha* not been completed.
When a 1hutdown ii r*quir*d to I comply with ACiION requirements, the plant may have entered a MODE in which a I new *pecification become* applicable.
In thi*.ca1e, th* time limit* of the I ACTION requirement*
would apply from the point in time that th* new I specification become* applicable if th* requirement*
of the Limiting condition I for operation are not met. I SALEM -UNIT 2 B 3/4 0-l Amendment No. 110 APfL!CABI(.ITY
,BASES 3.0.2 establishe*
that noncompliance with a specification exiata when th* requirements of the Limiting condition for Operation are. not met and the associated ACTION requirements have not been implemented within the specified time interval.
The purpose of this specification ie to clarify that implementation of the ACTION requirements within the eper.ified time interval constitutes compliance with a specification and (2) completion of the remedial measures of the ACTION requirement*
is not required when compliance with a Limiting condition of Operation ie reatored within the time interval specified in the associated requirement*.
I I I I I I I I I I Specification 3.0.3 establishes the shutdown ACTION requirements that must be I implem*nted when a Limiting Condition for Op*ration i* not met and the I condition i* not *pecifically addre*aed by the ***ociated ACTION requirements, I The purpose of this specification ie to delineate the time limit.a for placing I the unit in a safe shutdown MODE when plant operation cannot be maintained I within the limits for safe operation defined by th* Limiting condition*
for I Operation and its ACTION requirements.
* It h not intended to be uaed a* an 1 oper4tional convenience which permit* (routin*)
voluntary removal of redundant I syatem* or component*
from service in lieu of oth*r alternativ**
that would I not re*ult in redundant ayatema or component*
inop*rable.
On* hour i* I allowed to prepar' for an orderly before initiating a chan9e in plant I operation
*. Thi* time permit* the operator to coordinate the r*duction in I electrical generation with the load diapatch*r to *naure the *tability and . . '* availability of th* electrical grid. Th* tim* limit* 1pecifi*d
.to reach lowt.. MODES of operation permit the shu1;down to proceed in a controlled and orderly*---*
1 manner that ia well within the apecifiad maximum cocldown rate and within the I cooldown capabilitie1 of th* facility a*1wning only th* minimum required I equipment 11 OPERABLE.
Thi* reduce* thermal *tr***a*
on component*
of the . I primary coolant system and the potential for a plant upset t*hat could I challenge aafetl' 1y1tem1 under conditicna for which this epecif icat.ion I applie1.
I If remedial m*a1ure1 permitting limited continued operation of th* facility under the proviaiona of the ACTION requirem*nt*
are ccmpl*ted, th* shutdown may be terminated.
The time limit* cf the ACTION requirement*
are applicable from th* point in time th*.r* waa a failure to meet a Limit.in9 condition for Operation.
Therefore, th* ahutdown may b* te&'Dlinated if th* ACTION requirement*
have been met or the tim* limit* of the ACTION requirement*
have not *xpi.Eed, thu* prcvidinq an allowance for th* completion of th* required action*.
Th* time limit* of Specification 3.0.3 allow 37 hour* for th* plant to be in the COLD SHUTDOWN MODE when a shutdown i* .r*quir*d during th* POWER MODE Cf ope.ration.
If th* plant i* in a lower MODE of ope.ration wh*n a 1hutdown i* required, the time limit for reaching the next lower MODI of ope.ration appli***
Howev*r, if a lower MODE of operation i* reached in le** tirn* than allow*d, th* total allowable tim* to reach COLD SHUTDOWN, or oth*r applicable MODI, i1 not reduced.
For example, if HOT STANDBY i* reached in 2 hours, th* time allowed to reach HOT SHUTDOWN i* the next 11 hour* becau** of th* total time to reach HOT SHUTDOWN i* not reduced from th* allowabl*
limit of 13 hour*. Therefore, if remedial measures are completed that would permit a SALIM -UNIT 2 B 3/4 0-2 Am*ndm*nt No.110 I I I I I I I I I l I I I I I I I \
APPLICABILITY BASES to POWER* operation, a penalty is not incurred by having to reach a lower MODE of operation in less than the total time allowed.
The same applies with regard to the allowable outage time limits of the ACTION requirements, if compliance with the ACTION requirements for one specification results in entry into a MODE or condition of operation for another specification in which the requirements of the Limiting Condition for Operation are not met, If the rtew* ape.citicat'.ion b.ecomes applicable in less time than specified, the difference may be to:the allowable outage time limits of the second specification.
: However, the allowable outage time limits of ACTION requirements for a higher MODE of operation may not be used to extend the allowable outage time that is applicable when a Limiting Condition for Operation is not met in a lower MODE of operation.
The shutdown requirements of Specification 3.0.3 do not apply in MODES 5 and 6, because the ACTION requirements of individual specifications define the remedial to be: taken. Spei::if.ication
*3. O. 4 establishes limitations on changes in MODES or other specified conditions in the Applicability when an LCO is not met. It allows placing the unit in a.MODE or other specified condition stated in that Applicability (e.g., the Applicability desired to be entered) when unit conditions are such that the requirements o:f the LCO would not be met, in accordance with LCD 3. 0. 4. a, LCO or LCO 3.0.4.c.
LCO 3.0.4.a allows entry into a MODE or other specified condition in the with the LCO not met when the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time. Compliance with Required Actions that permit continued operation of the unit for. an unlimited period of time in a MODE or other specified condition.provides an acceptable level of safety for continued operation.
This is without regard to the status.of the unit before or after the MODE change. Therefore, in such cases,* entry into a MODE or other specified condition in the Applicability may be made in: accordance with the provisions of the Required Actions.
LCO 3.o*.4,b allows entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability pf entering the MODE or other specified condition in the Applicability, and establishm.ent of risk management
: actions, if appropriate, The: risk assessment may use quantitative, qualitative, or blended approaches, and the risk .asse*ssmen.t will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR 50.65(a)
(4), which requires that risk impacts of maihtenan*ce activities*
to be assessed and managed.
The risk assessment, for the purposes of LCO 3.0.4.b, mu$t take into account all inoperable Technical Specification equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a*)(4) risk as.sessment scope. The risk assessments will be conducted using the proc.edures and guidance endorsed by Regulatory Guide 1.162, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants."
Regulatory Guide 1.182 endorses
.the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."
These documents address general guidance for conduct of the risk assessment, quantitative and. qualitative guidelines for establishing risk management
: actions, and example risk management actions.
These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management SALEM -UNIT 2 B 3/4 0-3 Amendment No. 256 AJ?PLJ;CABILITY BASES personnel, actions to reduce the duration of the condition, actions to nu..ninuze the magnitude of risk increases.(establishment of backup success paths or compensatory measures),
and determination that the proposed MODE change is acceptable.
Consideration should also be given to the probability of completing rest.oration such that.the requirements of the LCO would be met prior to the expiration of ACTIONS Comple.tion Times that would require exiting the Applicability.
LCO 3.**o.4.b may:be used with single, or multiple systems and components unavailable.
NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components.
The results of the risk shall be considered in determining the of entering the MODE or other specified condition in the Applicability, and any corresponding risk management actions.
The LCO 3.0.4.b risk assessments do not have to be documented.
The Technical Specifications allow continued operation with equipment unavailable in MODE* 1 for the duration of the Completion Time. Since this is allowable, and since in general the *risk impact in that particular MODE bounds the risk of transitioning into and through the applicable MODES or other specified conditions in the Applicability of the LCO, the use of the LCO 3.0.4.b allowance should be generally acceptable, as long as the risk is assessed and managed as stated above. However, a
subset of systems and components that have been determined to be more important risk and of the LCO 3.0.4.b allowance is prohibited, The LCOs governing these* system and components contain Notes prohibiting the use* of LCO 3. 0 *. 4 .b by stating that LCO 3. 0. 4 .b is not applicable.
allows entry into* a MODE or other specified condition in the Appli9ability with the LCO not met based on an ACTION in the Specification which states LCO 3.0."4.c is applicable.
These specific allowances permit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not,provide for continued operation for an unlimited period of time and a risk assessment has not been performed.
This allowance may apply to all the ACTIONS or to a specific Required Action of a Specification.
The risk assessments performed to justify the use of LCO 3.0.4,b usually only consider systems and components.
For this reason, LCO 3.0.4.c is typically applied to Specifications that describe values and*pararneters*(e.g.,
Containment Air Temperature, Containment
: Pressure, Moderator Temperature Coefficient),
and may be applied to other Specifications based on NRC plartt-specific:approval.
The provisions.of this Specification should not be interpreted as endorsing the failure to exe+cise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability,
* The provisions' of LCO* 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS.
In addition, the provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown.
In this .context, a unit shutd9wn is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE,2 to MODE 3, MODE 3 to MODE 4, and MODE 4 to MODE 5, . ; Upon entry into a MODE or other specified condition in the Applicability with the LCD not met, LCO 3*. 0 .1 and LCO 3. 0. 2 require entry into the applicable Conditions and SALEM -UNIT Z B 3/4 0-3a Amendment No. 258 APPLICABILITY BASES Required Actions until.the Condition is resolved, until the LCO is met, or until the unit 'is not within the Applicability of the Technical Specification.
Surveillances do not have to be performed on the associated inoperable equipment (or on variables outside the specified limits),
as permitted by SR 4.0.1. Therefore, utL).izing LCO 3.0.4 is not a violation of SR 4.0.1 or SR 4.0.4 for any Surveillances that :have not been performed:on inoperable equipment.
: However, SRs must be met to ensure prior tp declaring the associated equipment OPERABLE (or variable within limits).
a*nd restoring compliance with the affected LCO. SALEM -UNIT B 3/4 0-3b Amendment No. 258 **
APPLICABILITY BASES Specification 3.0.5 DELETED SALEM -UNIT 2 B 3/4 0-4 Amendment No. 234 
! I* APPLICABILITY BASES Specification
: 3. 0. 6 establishes the allowance for restoring equipment t*o service under administrative controls when it has been removed from service or declared inoperable to comply with ACTIONS.
The sole purpose of this Specification is to provide an exception to LCO 3.0.2 (e.g., to not comply with the applicable Required Action(s))
to allow the performance of testing required to restore and demonstrate:
: a. The OPERABILITY of the equipment being.returned to service; or b. The OPERABILITY of other equipment.
The administrative controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the testing required to restore and demonstrate the operability of the equipment.
This Specification does not provide time to perform any other preventive or corrective maintenance.
An example of demonstrating the OPERABILITY of the equipment being returned to service is reopening a containment isolation valve that has been closed to comply with Required Actions and must be reopened to perform the testing required to restore and demonstrate OPERABILITY.
An example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to prevent the trip function from occurring during the performance of testing required to restore OPERABILITY of another channel in the other trip system. A similar example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to permit the logic to function and indicate the appropriate response during the performance of testing required to restore and demonstrate the OPERABILITY of another channel in the same trip system .. SALEM -UNIT 2 B 3/4 0-4a Amendment No. 234 APPLICABILITY BASES Specifications 4.0.1 through 4.0.S establish-the general requirements applicable to Surveillartce Requirements.
These requirements are based on the surveillance Requirements stated in the Code of Federal Regulations, 10 CFR 50.36(c)
(3): nsurveillance requirements are requirements relating to test, calibration, or inspection to ensure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions of operation will be met." seecification 4.0.l establishes the requirement that Surveillance Requirements must be met during the OPERATIONAL MODES or other specified conditions in the Applicability for which the requirements of the Limiting Conditions for Operation apply, unless otherwise specified in an individual Surveillance Requirement.
This specification is to ensure that surveillances are performed to verify the OPERABILITY of systems and components and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with Specification 4.0.2, constitutes a failure to meet an LCO. Systems and components are assumed to be OPERABLE when the associated surveillance Requirements have been met. Nothing in this Specification,
: however, is to be construed as implying that systems or components are OPERABLE when either: a. The systems or components are known to be inoperable, although still meeting the Surveillance Requirements, or b. The requirements of the Surveillance(s) are known to be not met between required Surveillance performances.
surveillances do not have to be performed when the facility is in an OPERATIONAL MODE or other specified condition for which the requirements of the associated Limiting Condition for Operation do not apply, unless otherwise specified.
The surveillance Requirements associated with a Special Test Exception are only applicable when the Special Test Exception is used as an allowable exception to the requirements of a specification.
Unplanned events may satisfy the requirements (including applicable acceptance criteria) for a given surveillance.
In this case, the unplanned event may be credited as fulfilling the performance of the Surveillance Requirement.
This allowance includes those Surveillances whose performance is normally precluded in a given OPERATIONAL MODE or other specified condition.
surveillances, including Surveillances invoked by ACTIONS, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. surveillances have to be met and performed in accordance with Specification 4.0.2 prior to returning equipment to OPERABLE status. Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE.
This includes ensuring applicable surveillances are not failed and their most recent performance is in accordance with Specification 4.0.2. Post maintenance testing may not be possible in the current OPERATIONAL MODE or other specified conditions in the Applicability due to the necessary unit parameters not having been established.
In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and SALEM -UNIT 2 B 3/4 0-5 Amendment No. 237 APPLICABILITY BASES the equipment is not otherwise believed to be incapable of performing its function.
This will allow operation to proceed to an OPERATIONAL.MODE or* other specified condition where other necessary post maintenance tests can be: completed.
Some examples of this process are: a. Auxiliary Feedwater (AFW) pump turbine maintenance during refueling that requires testing at steam pressures
> 680 psig. However, if other appropriate testing is satisfactorily completed, the AFW system can be considered OPERABLE.
This allows startup and other necessary testing to proceed until the plant reaches the steam pressure required to perform the testing.
: b. High Pressure Safety Injection (HPI) maintenance during shutdown that requires system functional tests at a specified pressure.
Provided other appropriate testing is satisfactorily completed, startup can* proceed with HPI considered OPERABLE.
This allows operation to reach* the specified pressure to complete the necessary post maintenance testing.
Specification 4.0.2 establishes limit for which the specified time interval for surveillance Requirements may be extended.
It permits an allowable extension of the normal surveillance interval to facilitate surveillance scheduling and consideration of plant operating conditions that may not be suitable for conducting the surveillance; e.g., transient conditions or other ongoing surveillance or maintenance activities.
It also provides flexibility to accommodate the length of a fuel 'cycle for surveillances that are performed at each refueling outage and are specified with an 18 month surveillance interval.
It is not intended that this provision be used repeatedly as a convenience to extend surveillance intervals beyond that specified for surveillances that are not performed during refueling outages.
The limitation of Specification 4.0.2 is based on engineering judgment and the recognition that the most probable result of any particular surveillance being performed is the verification of conformance with the Surveillance Requirements.
This provision is sufficient to ensure that the reliability ensured through surveillance activities is not significantly degraded beyond that obtained from the specified surveillance interval.
Specification 4.0.3 establishes the flexibility to defer declaring affected equipment inoperable, or an affected variable outside the specified limits, when a Surveillance has not been completed within the specified frequency.
A delay period of up to 24 hours or up to the limit of the specified frequency, whichever is greater, applies from the point in time that it is discovered that the surveillance has not been performed in accordance with TS 3.0.2, and not at the time that the specified frequency was not met. This delay period provides adequate time to complete Surveillances that have been missed. This delay period permits the completion of a surveillance before complying with Required Actions or other remedial measures that might. preclude completion of the Surveillance.
The basis for this delay period includes consideration of unit conditions, adequate
: planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular surveillance being performed is* the verification of conformance with the requirements.
SALEM -UNIT 2 B 3/4 0-6 Amendment No. 237 APPLICABILITY BASES When a Surveillance with a Frequency based not on time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering MODE.l after each fuel loading, or in accordance with io*cFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, SR 4.0.3 allows for the full delay period of up to the specified Frequency to perform the Surveillance.
: However, since there is not a time interval specified, the .missed Surveillance should be performed at the first reasonable opportunity.
SR 4.0.3 provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.
Failure to comply with specified frequencies for Surveillances is expected to be an infrequent occurrence.
Use of the delay period established by SR 4.0.3 is a flexibility Which is not intended to be used as an operational convenience to extend Surveillance intervals.
While up to 24 hours or the limit of the specified Frequency is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be performed at the first reasonable opportunity.
The determination of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions,
: planning, availability of personnel, and the time required to perform the Surveillance.
This risk impact should be managed through the program in place to implement 10 CFR50.65(a)
(4) and its implementation
: guidance, NRC Regulatory Guide 1.182, 'Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants.'
This Regulatory Guide addresses consideration of ternporarY and aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown.
The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods.
The degree of depth and rigor of the evaluation should be commensurate with the importance of the component.
Missed surveillances for important components should be analyzed quantitatively.
If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to determine the safest course of action. All missed Surveillances will be placed in the licensee's Corrective Action Program.
If a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable, or the variable is considered outside the specified limits, and the Completion Times of the Required Actions for the applicable LCO begin immediately upon expiration of the delay period. If a Surveillance is failed within the delay period, then the equipment is inoperable, or the variable is outside the specified limits, and the Completions Times of the Required Actions for the applicable LCO begins immediately upon the failure of the Surveillance.
completion of the Surveillance within the delay period allowed by this Specification, or within the Completion Time of the Actions, restores compliance with SR 4.0.1. SALEM -UNIT 2 B 3/4 0-7 Amendment No . 237 
:APPLICABILITY 13ASES Specification 4.0.4 establishes the requirement that all applicable SRs must be met before entry into a MODE or other specified condition in the .Applicability,
.This Specification ensures that system and component OPERABILITY requirements
:and variable limits are met before entry into MODES or other specified
:conditions
:in the Applicability for which these systems and components ensure of* the unit. The provisions of this Specification should not -be interpreted as endorsing the failure to exercise the good practice of systems or components to OPERABLE status before entering an associatect;MODE or other specified condition in the Applicability.
A provisiorJ.
is included to allow entry into a MODE or other specified
.condition in the Applicability when an LCO is not met due to Surveillance not being met in accordance with LCO 3.0.4. *However, two certain circumstances, failing to meet an SR will not result in SR 4.0.4 restricting a MODE change or other specified condition change: (1) When a system, subsystem,
: division, component, device or variable is or outside its specified limits, the associated SR{s) are not required to performed, per SR 4.0.1, which states that surveillances do. not have to be performed on inoperable equipment.
When equipment is inoperable,*_sR.4.0.4 does not apply to the associated SR(s) since the requirement for the SR{s) to be perfonned is removed.
Therefore, fai*ling to perform the surveillance (s) within the specified Frequency does:not result in an SR 4.0.4 restriction to changing MODES or other conditions of the Applicability.
: However, since the* LCO is not met in this instance, LCO 3.0.4 will govern any restrictions that may (or apply to MODE or other specified condition changes.
(2) SR 4.0.4 does not *restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been within the specified-Frequency, provided the requirement to declare the LCO not *met been delayed in accordance with SR 4.0.3 * . The provisions of SR shall not prevent entry into MODES or other *specified conditions in the Applicability that are required to comply with :ACTIONS.
In addition, the provisions of SR 4.0.4 shall not prevent changes in .MODES or conditions in the Applicability that result from any unit shutdown.
In this context, a unit shutdown is defined as a change in MODE o*r other specified condition in the Applicability associated with .transitioning from MODE l to MODE 2, MODE 2 to MODE 3, MODE 3 to MODE 4, and .MODE 4 to MODE 5. * . . The precise for performance of SRs are specified such that *exceptions*to SR 4.0.4.are not necessary.
The specific time frames. and qonditions;necessary for meeting the SRs are specified in the Frequency, in *the""Surveil-lance,.
or both. This allows performance of Surveillances when the *prerequisite*condition(s) specified in a Surveillance procedure require entry into the MODE or* other specified.condition in the Applicability of the associated:LCO prior to the performance or completion of a Surveillance.
A Surveillan6e that could be performed until after entering the LCO's *.Applicability would have its Frequency specified such that it is not "due" the conditions needed are met. Alternately, the Surveillance
_may be stated in the form of a Note, as not required (to be met or performed) until a event, condition, or time has been reached.
Further discussion.of the specific formats of SRs' annotation is found in Section 1.4, Frequency.
; SALEM -UNIT 2 B 3/4 0-8 Amendment No. 258 
'-...---._.-----3/4.1 CONTROL SXSTJ!MS BASES 3/4.1.1 BQBATlQH CONTRO# 3/4.1.1.1 apd 3/4.1.1.2 SHT11'pO!D!
KNUjp! A auff'icie=t SHU1'WWN IQRGlH ea.urea that 1) 1:he :.actor m be 1l&da *===itical
&#xa3;.rca all cpe:ati:g ccmdi.Uona, r.act:l.vity uanaienu
-.aociat.d with poatulatecl acc::idea.t c:ocdi.tiona ue con=oll@l*
ritl1:1zi li.aita, azid 3) the *ill aaint&ined auffic:iezitiy
*=critical b> pr*c:luda c::it.icalit:y the cond:i.t:ion
* . .
* SKO"rDOWN MN\CIN n:y t:hroughout core aa a of fuel depletion, RCS baron concent:aticn, and RCS 1' * .,.. ':he moat r*at:ict.i,,.
cond.ition occur* at SOI., wich 1'.,. at no load oparating temperatuze, and .i* &Hociated with a pcatul.at.cl
*team li.J)e break accidut Md :eaulting uncont:olled RCS cool.down.
h an&lya.ia of Chis accident, a a1ciam. sfft.r.mowN tWtQtN 1
* 3t >>./k :18 ini tJ.ally required to control the r ..
ty I
* t:ansient.
Acco::d:i.ngly, the SHtJTl:>OWN w.aQl:N requir .. m1t ia upon th.ia l.ilU.ting condition and i* conaiatent with FSAR a&fety anall"*i*
***'Wllpt.iona.
With 1' * ..., l*** thazi or equal to 2oo*F, the ructivity t:anaiants reau.lting troc a _postulated ateua line break cool.down ar* 211.ini.m&l.
and a l.t ahutdown margin adequate protect.ion.
314 . 1 . l . 3 MOCEAA'?OR TEMP!RAMJi COJFFI!dUNT CM'l'Cl 'l'he limi.taticns on M!'C ue provided to enau:e that the value of t:hia coeffici*nt ru.ains within th* li&iting condition ass'Wlled
.in the accident and transient analy****
SALEM -'DNI'? 2 B 3/4 1*1 Aaendm.en t Ho. 19 7 3/4.l JU:>.;'l'IYITY CONTROL SYS'r&#xa3;MS BASIS 3 / 4 . l .1. 3 MOOEIQ'?OR
'?'EMPERATtJY COEFFICJEN'f
<M'l'Cjl
<Continu14>
Th* M'1'C valuH of thia are applicaJ:)l*
to a mpeci.fic aet of' plant condition.;
accordingly, ve:ification of lee: valu** at concli.tiona othu thm1 tho** explicitly atated will reqW.J:e axtZaPolation to thoae conditions ill order to an accurate c:oapa.:i.aon.
* I * * * * * * . . 'l'h* .Jat JMgatift M'1'C value equivalent to the aoat poaitiv.
aode:ator dansi ty (MDC) , wu by inc:*entally co::ecting the MDC ua-1 in !'SM analyaia to 11M1inal cpe:ati.ng c:onditiona.
Th*** co::act.iou
:i.nvolvecl:
(1) a conve::dcm of the MDC uaed in th* l'SAR &D.&lyai*
to i.b eqW.valent M'l'C, baaed on the rate of of aoderator density with at: RA'l'EJ:>
1'HEmfAI.
llOWZJl ccndition9, and (2) aubt.:acting
.froa thi* value th*
diffe:encea in lft'C observed between KOL, all rod.a vithd:awn, M'l'ED POWER condition.,
mid tho** aoat adve:ae condition.a of &Qda:ator temperat:u::*
and p:**sur*,
rod insution, axial power ak*vinq, and xenon concentration that: can occw:' in noraal operation and l.ad to a aii;nificantly
=ore negati.ve EOI. M'l'C at RA1'ED 1'HZRMAL POWER. 'l'h*** correctio=a tranatomed the HDC.valu*
used :i.n th* !'SAR analysis into the l.:1.aiti.ng End ot Cycle I.if* (!:OI.) MTC value. 'l'h* 300 ppa surveillance lUtit M'l'C: value rep::eaents a conservative value at a core condition of 300 ppm ec;W.lib::iwt boron concent:ati.on
'that is obtained by cor.:ectinc;
'the li.m.it.i.nq EOI. M'l'C :for bumup and born conceit.ration.
Th* surveillance reqW.re:menta f'o:: aeaai:.:aaez:at of the MTC at 'th* beginning and near 'th* end of' the cycl.* a::* adequate to. cont'i.::m that 'the ruiains with ita li.mits al.nee t:hi.a coef'f'i.cient changes slowly due p:iDcipally to the reductioz:a
:i.n RCS "ron concent::at.i.on associated with 1uel bw:zwp. 3 / 4 .1 . 1 . 4 MINIHgM TEMPERATQRZ
.lQB c:RI'l'ICALI'l'I This specification ensures that the reactor will not be made c::itical wi'th the Reactor Coolant System average tempe:atu::*
leaa than 5.U.*F. ni.ia limitation i* :equi:ed to enaure 1) th* aode:at:o:
temperature coefticient ia within its analyzed temperature zange, 2) the protective i.nat:uaentation i* within its no%:&l operating range, 3) th* P-12 i.nte::lock ia abov. it.a allowable setpoi.nt:,
,, the pnaaurizaz i* capable of bei.ng i.n an OPERABLE status vith a *t*U and 5) th* reactor.
pressuze vessel ia above its m;JU.mWll JU'MD!
SAUM -WIT 2 B 3/4 1-2 A:lendaent No.197 
( ( ****----*------
---------
REACTIVITY CONTROL SYSTEMS BASES 3/4 .1.2 BORATION SYSTEMS The boron injection system ensures that negative reactivity control is available during each mode of facility operation.
The components required to perform this function include:
: 1) borated water sources,
: 2) charging pumps, 3) separate flow paths, 4) boric acid transfer pumps, and 5) offsite power or an emergency power supply from OPERABLE diesel generators.
With the RCS average temperature 350&deg;F, a minimum of two boron injection flow paths are required to ensure single functional capability in the event an assumed failure renders one of the flow paths inoperable.
The boration capability of either flow path is sufficient to provide a SHUTDOWN MARGIN from expected conditions of 1.3% delta k/k after xenon decay and cooldown to 200&deg;F. The maximum expected boration capability (minimum boration volume) requirement is established to conservatively bound expected operating conditions throughout core operating life. The analysis assumes that the most reactive control rod is not inserted into the core. The maximum expected boration capability requirement occurs at EOL from full power equilibrium xenon conditions and requires borated water from a boric acid tank in accordance with TS Figure 3.1-2, and additional makeup from either: (1) the second boric acid tank and/or batching, or (2) a maximum of 41,800 gallons of 2,300 ppm borated water from the refueling water storage tank. With the refueling water storage tank as the only borated water source, a maximum of 73,800 gallons of 2,300 ppm borated water is required.
: However, to be consistent with the ECCS requirements, the RWST is required to have a minimum contained volume of 350,000 gallons during operations in MODES 1, 2, 3 and 4. The. boric acid tanks, pumps, valves, and piping contain a boric acid solution concentration of between 3.75% and 4% by weight. To ensure that the boric acid remains in solution, the tank fluid temperature and the process pipe wall temperatures are monitored to ensure a temperature of 63&deg;F, or above is maintained.
The tank fluid and pipe wall temperatures are monitored in the main control room. A 5&deg;F margin is provided to ensure the boron will not precipitate out. Should ambient temperature decrease below 63&deg;F, the boric acid tank heaters, in conjunction with boric acid pump recirculation, are capable of maintaining the boric acid in the tank and in the pump at or about 63&deg;F. A small amount of boric acid in the flowpath between the boric acid recirculation line and the suction line to the *::harging pump will precipitate out, but it will not cause flow blockage even with temperatures below 50&deg;F. With the RCS temperature below 350&deg;F, one injection system is acceptable without single failure consideration on the basis of the stable reactivity condition of the reactor and the additional restrictions prohibiting CORE OPERATIONS and positive reactivity change in the event the single injection system becomes inoperable.
SALEM -UNIT 2 B 3/4 1-3 TSBC SCN 05-042 --,-------------------------------------********
REACTIVITY CONTROL SYSTEMS BASES The boron capability required below 200 &deg;F is sufficient to provide a SHUTDOWN MARGIN of 1% delta k/k after xenon decay and cooldown from 200 &deg;F to 140 &deg;F. This condition requires either 2,600 gallons of 6,560 ppm borated water from the boric acid storage tanks or 7,100 gallons of 2,300 ppm borated water from the refueling water storage tank. The 37,000 gallons limit in the refueling water storage tank for Modes 5 and 6 is based upon 21,210 gallons that is undetectable due to lower tap location, 8,550 gallons for instrument error, 7,100 gallons required for shutdown margin, and an additional 140 gallons due to rounding up. The limits on contained water volume and boron concentration of the RWST also ensure a pH value of between 7.0 and 10.0 for the solution recirculated within containment after a LOCA. This pH band minimizes the evolution of iodine and minimizes the effect of chloride and caustic stress corrosion on mechanical systems and components.
The contained water volume limits include allowance for water not available because of discharge line location and other physical characteristics.
The OPERABILITY of one boron injection system during REFUELING ensures that this system is available for reactivity control while in MODE 6. 3/4.1.3 MOVABLE CONTROL ASSEMBLIES The specifications of this section ensure that (1) acceptable power distribution limits are maintained, (2) the minimum SHUTDOWN MARGIN is maintained, and (3) limit the potential effects of rod mis-alignment on associated accident analyses.
OPERABILITY of the control rod position indicators is required to determine control rod positions and thereby ensure compliance with the control rod alignment and insertion limits. OPERABLE condition for the analog rod position indicators is defined as being capable of indicating rod position to within the allowed rod misalignment relative to the bank demand position for a range of positions.
For the Shutdown Banks and Control Bank A this range is defined as the group demand counter indicated position between 0 and 30 steps withdrawn inclusive, and between 200 and 230 steps withdrawn inclusive.
This permits the operator to verify that the control rods in these banks are either fully withdrawn or fully inserted, the normal operating modes for these banks. Knowledge of these banks' positions in these ranges satisfies all accident analysis assumptions concerning their position.
The range for Control Bank B is defined as the group demand counter indicated position between 0 and 30 steps withdrawn inclusive, and between 160 and 230 steps withdrawn inclusive.
For Control Banks C and D the range is defined as the group demand counter indicated position between 0 and 230 steps withdrawn.
Comparison of the group demand counters to the bank insertion limits with verification of rod position with the analog rod position indicators (after thermal soak after rod motion) is sufficient verification that the control rods are above the insertion limits. The full out position will be specified in the reload analysis for the cycle. This position will be within the band established by FULLY WITHDRAWN and will be administratively controlled.
This band is allowable to minimize RCCA wear, consistent with Information Notice 87-19 and RCCA examinations that were conducted during Salem Unit 2 Spring outage 2008 (2Rl6) by the Salem RCCA vendor AREVA NP (Refer to LAR S09-01).
SALEM -UNIT 2 B 3/4 1-4 Amendment No. 276 (PSEG Issued)
REACTIVITY CONTROL SYSTEMS BASES The ACTION statements which permit limited variation from the basic requirements are accompanied by additional restrictions which ensure that the original criteria are met. alignment of a rod requires measurement of peaking factors or a restriction in THERMAL POWER; either of these restrictions assurance of fuel rod integrity during continued operation.
The reactivity worth of a mis-aligned rod is limited for the remainder of the fuel cycle to prevent exceeding the assumption used in the accident analysis.
* The maximum rod drop time restriction is consistent with the assumed rod drop time used in the accident analyses.
Measurement with T avg >541&deg;F and with all reactor coolant pumps operating ensures that the measured drop times will be representative of insertion times experienced during a reactor trip at operating conditions.
Control rod positions and OPERABILITY of the rod position indicators are required to be verified in accordance with the Surveillance Frequency Control Program with more frequent verifications required if an automatic monitoring channel is inoperable.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
The terms "Shutdown Rod Position Indicator,"
"Analog Rod Position Indicator,"
"Control Rod Position Indicator,"
and "Rod Position Indicator" are all used in this bases section or in Technical Specifications, and all refer to indication driven by the output of the Analog Rod Position Indication (ARPI) system. One method for determining rod position are the indicators on the control console.
An alternate method of determining rod position is the plant computer.
Either the control console indicator or plant computer is sufficient to comply with this specification.
The plant computer receives the same input from ARPI as the control console indicators and provides resolution equivalent to or better than the control console indicators.
The plant computer also provides a digital readout 'of rod position which eliminates interpolation and parallax errors inherent to analog scales. Rod demand position is indicated on the control console and the plant computer.
The rod demand position is a digital signal, namely a pulse, and is generated each time the Rod Control System demands a rod position step change, one pulse for each rod step. The pulses are "counted" and displayed by the control console group demand step counters.
There are two group demand step counters for each bank of rods with exception of shutdown banks C and D. The plant computer also "counts" and displays the demand pulses. Only the group 1 demand position of each rod bank is displayed on the plant computer as only the group 1 pulses are routed to the plant computer.
The group 1 demand position on the plant computer is, by default, called "Cont Bank A Steps" or "SID Bank A Steps" etc. with no reference to group 1 or group 2. As the plant computer receives the same demand pulses from the Rod Control System as the control console group demand step counters and provides equivalent resolution, the plant computer "bank step" display provides an alternate method of determining group 1 rod demand position.
Either the control console group 1 demand step counter or the plant computer "bank step" display is sufficient to comply with this specification for group 1 rod demand position.
Only the control console group 2 demand counter can be used to comply with the specification for group 2 rod demand. SALEM -UNIT 2 B 3/4 1-5 Amendment No. 282 (PSEG Issued) 3/4 .2 LIMITS BASES 1'ba apec:::lf'ications of' th:i.a section provide assurance cf' f'aal.
during Cond.iticn r CNomal Operation) and II (Inc::ic:lents of' Med.rate
!'reqt.iency) evaiits by: Ca) :m .. t.i.D!l th* DNB J)ed,gn CriC.:ia du:ing no:mal operation aJ1d .in t.e:ia t:anai.enb, and (b) th* f'i.aaion c;aa rel ... *, f'uel pell.et temp.::*tw:*
mid cladding
**ch&nic:&l.
properti**
to within aHuaed ded;n c::i teria. l.n addition, l..i&iting the peak powe:: denai t;y during Condition I event.a provide*
.. aurance.
that the col:l&.tiou
***'IZldd for the ux:A anal.ya**
u* aet and the ZCCS acceptazice c::iteri.a J..iait of'
:I.a iiot u:ceected.
1'h*
of' hot chamlel :tacto::a aa used .in th*** apeci!'ication.
are as followa:
FQ (Z) Heat Flwc Hot Channel Factor, i*
** th* local heat f'lwc on th*
of a f'uel. :od at core *l.vation Z diVided try the average fuel rod heat :flux, allowing f'or tolerances on fuel pellets and rods. ?'41 Nuclea: Enthalpy Ria* Hot Channel Factor, .:i.a aa the c:if the i.nteqral of linear powu along th9 red with the highest integrated pcwer to the ave.rage rod power. F rt (Z) bdial Peaking Factor is de:!inec:l u the ratio of' power denai ty to avtU"ag*
power derulity in th* horizontal.
plane at co:* el.evat.ion
: z. 3/4. 2. l AXD.L FI.OX t>IFFEUNO:
(.M'D) Th* l..iaib on n.m OI!'TI:UNCl-&s*u::*
that th* F0(Z) upper bound envel.ope the Fg liait specified i.n the CCU OPERATDiG LIMITS REPORT (COLR) times the a.xi.al
!!actor ia not du.r:ing either nol:lllal.
operat:i.on or.in th* event cf xenon r9diat.n.buticn f'ollovin9 pow*: c:h&ng***
Ta:get f'lux c:lil!ference i* dat.::s.ined at equil.il:>ri:wa xanon c:onditiou with the part length control rod.a wi t:hd:&WZ) l!ro11 th* core. Th* fu11 le.ngth may J:>e positioned Within the cc:* u ac:co:dance with their ::eapect:i.ve itl.aution luuts &lld ahou1d be nea: their nonaal poaition l!or *taady atate operation at hi.gh pow.: l!1'V9l*.
'?h* value of the target l!lwc c:l.if.farance obta:i.ned uzider th*** condition*
by t:h* f'raction cf Mn:D i* th* t&:g*t nwc dif'l!*rence at '1'HZJQQL POWJ:lt l!or th* ***oci.ated burnup C:ondition*.
f'lwc d:i.l!f'erencea
.for ether POMZ3' l.vel* a:* t.a.:inlld by su1 t.ipl.ying the RA.DD JIOWZ1t th9 -.pp:oprl.at9 f'ractional. POWER level. 1'h* period.ic:
updating of the target :!lu.x difference val.ue i* n*c*s*&J:Y t.o ref'lect core burnup SJ\UM -'ONI'l' 2 B 3/4 2-1 Amendment No. 197 POWER DISTRIBUTION LIMITS BASES Although it is intended that the plant will be operated with the AXIAL FLUX DIFFERENCE within the target band in the COLR per Specification 3.2.1 about the target flux difference, during rapid plant THERMAL POWER reductions, control rod motion will cause the AFD to deviate outside of the target band at reduced THERMAL POWER levels. This deviation will not affect the xenon redistribution sufficiently to change the envelope of peaking factors which may be reached on a subsequent return to RATED THERMAL POWER (with the AFD within the target band) provided the time duration of the deviation is limited.
Accordingly, a 1 hour penalty deviation limit cumulative during the previous 24 hours is provided for operation outside of the target band but within the limits specified in the COLR while at THERMAL POWER levels between 50% and 90% of RATED THERMAL POWER. For THERMAL POWER levels between 15% and 50% of rated THERMAL POWER, deviations of the AFD outside of the target band are less significant.
The penalty of 2 hours actual time reflects this reduced significance.
Provisions for monitoring the AFD are derived from the plant nuclear instrumentation system through the AFD Monitor Alarm. A control room recorder continuously displays the auctioneered high flux difference and the target band limits as a function of power level. An alarm is received any time the auctioneered high flux difference exceeds the target band limits. Time outside the
* target band is graphically presented on the strip chart. Measurement of the target flux difference is accomplished by measuring the power distribution when the core is at equilibrium xenon conditions, preferably at high power levels with the control banks nearly withdrawn.
This measurement provides the equilibrium xenon axial power distribution from which the target value can be determined.
The target flux difference varies slowly with core burnup. Alternatively, linear interpolation between the most recent measurement of the target flux differences and a predicted end of cycle value provides a reasonable update because the AFD changes due to burnup tend toward 0% AFD. When the predicted end of cycle AFD from the cycle nuclear design is different from 0%, it (the prediction) may be a better value for the interpolation.
Figure B 3/4 2-1 shows a typical monthly target band. SALEM -UNIT 2 B 3/4 2-2 Amendment No. 289 (PSEG Issued)
* Percent of Rated Thermal 100" 0 -20" IN!'01CMA'1'ION ONL'!* <1-Ilrftf 'lu* Dlll'9mMll9
*--0 INDICATED AXIAL "LUX DIFFERENCE P'lfUN a M 2-t TY'ICAL tNDICATID AXIAL ,WX D9'1"1RENCI va11aua THIRMAL POWllll SALIM -t7NI1' 2
* 3/' 2-3 Aaendaent Ho. 197 POWER DISTR:SUTION LIMITS and 314.2.3 HEAT FLUX AND NUCLEAR ENTHALPY HOT CHANNEL AND RACIAL PEAKING FACTORS -Fg(Z) AND &i The limit* on heat flux and nuclear enthalpy hot channel factors and RCS flow rate ensure that l) the design limit& on peak local power density and minimum DNBR are not exc**d*d ond Zl in the event o: a LOCA the peak fuel clad temperature will not exceed the 2200cF ECCS acceptance criteria limit. E&ch of these hot chann*l factors are measural)le but will normally only oe determined periodically as specifi*d in Specifications 4.2.2 and 4.2.3. This periodic surveillance is sufficient to insure thAt th* limits are provided:
: a. Control rod in a sin9le group mcve together with no individua.l rod insertion di!fering from the group demand position by more than the allowed rod misalignment.
: b. Control rod groups are s*quence4 with overlapping groups as aeseribad in Specification 3.l.3.5.
: c. The control rod insertion limits of Specifications J.l.3.4 and 3.l.J.S are maintained.
: d. The axial power distribution.
wxpreseed in terms of AXIAL FLUX DIFFERENCE, is maintained within the limits. The relaxation in r'AH as a tunction ot THERMAL POW!R allows changes in the radial power shape for all permis1ible rod insertion limits. will b* maintained within its limits provided conditions a through d above, are maintained.
When an Fg measurement is taken.
experimEltal error and manufacturing tolerance must be allowed for. Five percent is the appropriate allowance for a full core map taken with the ineor* detector flux mapping system and 3' is the appr0priate allowance
!er manutacturin; tolerance.
For m*asur*ments obt*ined ueing th* Power Distribution Monitoring Syatem (PDMS), the appropriate m*asurement uncertainty is determined using the measurem*nt uncertainty methodology contained in WCAP 12472-P-A.
The cycle and plant uncertainty calculation information needed to support the POMS calculation is eontained in the COLR. The PDMS will automatically calculate and apply the corr*ct measurement unce:tainty, and apply a 3\ allowance for manufacturing tolerance.
When FNoH is measured, experimental error must be allowed for and i! obtained from the COLR when using tha POMS or the incoro detection ayatem. The specified limit for p)'oH also contains an St Gllowance uncertaintie=
wh.*ch mean that norm*l operation will result i.n rH6H S FllPToM/l.08.
Where FRPT6H is the limit at RATED THERMAL POWER IRTPl spocified in the CORE OPEl\ATING LIMITS REPORT (COLR). The 8' allowance is baaed on the following considerations:
SALEM -UNIT 2 B 3/4 2-4 Amendmane No. 218 -*
POWER DISTRIBUTION LIMITS BASES 3/4.2.2 and 3/4.2.3 HEAT FLUX AND NUCLEAR ENTHALPY HOT CHANNEL AND RADIAL PEAKING FACTORS -Fa(Z) AND FfH (Continued)
: a. abnormal perturbations in the radial power shape, such as from rod misalignment, effect FfH directly than Fa. b. although rod movement has a direct influence upon limiting Fa to within its limit, such control is not readily available to limit FfH, and c. errors in prediction for control power shape detected during startup physics test can be compensated for in Fa by restricting axial flux distributions.
This compensation for FfH is less rapidly available.
The appropriate measurement uncertainty for FN t.H obtained using PDMS is using the measurement uncertainty methodology contained in WCAP 12472-P-A.
The cycle and plant specific uncertainty information needed to support the PDMS calculation is contained in the COLR. The PDMS will automatically calculate and apply the correct measurement uncertainty to the measured FN t.H* The radial peaking factor Fxy(Z) is measured periodically to provide assurance that the hot channel factor Fa(Z), remains within its limit. The Fxy limit for RA TED THERMAL POWER FRTP xy , as provided in COLR per specification 6.9.1.9, was determined from expected power control maneuvers over the full range of burnup conditions in the core. The core plane regions applicable to an Fxy evaluation exclude the following, measured in percent of core height (from the bottom of the fuel): a. Lower core region, from 0% to 8% inclusive,
: b. Upper core region, from 92% to 100% inclusive,
: c. Grid plane regions at+/- 2%, inclusive, and d. Core plane regions within+/- 2% of core height(+/-
2.88 inches) about the bank demand position of the bank "D" control rods. 3/4.2.4 QUADRANT POWER TILT RA TIO The quadrant power tilt ratio limit assures that the radial power distribution satisfies the design values used in the power capability analysis.
Radial power distribution measurements are made during startup testing and periodically during power operation.
SALEM -UNIT 2 B 3/4 2-5 TSBC 82015-072 POWER DISTRIBUTION LIMITS BASES The limit of 1.02 at Which corrective action is required provides DNB and linear heat generation rate protection with x-y plane power tilts. A limiting tilt of 1.025 can be tolerated before the margin for uncertainty in Fa is depleted.
The limit of 1.02 was selected to provide an allowance for the uncertainty associated with the indicated power tilt. The 2 hour time allowance for operation with a tilt condition greater than 1.02 but less than 1.09 is provided to allow identification and correctiOn of a dropped or misaligned rod. In the event such action does not correct the tilt, th!3 niargin for uncertainty on Fa is reinstated by reducing the power by 3% from RATED THERMAL POWER for each percent of tilt in excess of 1.0. 3/4.2.5 DNB PARAMETERS The limits on the DNB related parameters assure that each of the parameters are maintained with the normal steady state envelope of operation assumed in the transient and accident analyses.
The limits are consistent with the initial FSAR assumptions and have been analytically demonstrated adequate to maintain a minimum DNBR of the design DNBR value throughout each analyzed transient.
The Surveillance Frequency is based on operating experience, equipment reliability, and
* plant risk and is controlled under the Surveillance Frequency Control Program.
SALEM -UNIT 2 B 3/4 2-6 Amendment No. 282 (PSEG Issued) 3/4.3 INSTRUMENTATION BASES 3/4.3.1and3/4.3.2 PROTECTIVE AND ENGINEERED SAFETY FEATURES (ESF) INSTRUMENTATION The OPERABILITY of the protective and ESF instrumentation systems and interlocks ensure that 1) the associated ESF action and/or reactor trip will be initiated when the parameter monitored by each channel or combination thereof exceeds its setpoint,
: 2) the specified coincidence logic and sufficient redundancy is maintained to permit a channel to be out of service for testing or maintenance consistent with maintaining an appropriate level of reliability of the Reactor Protection and Engineered Safety Features instrumentation and, 3) sufficient system functional capability is available from diverse parameters.
The OPERABILITY of these systems is required to provide the overall reliability, redundance and diversity assumed available in the facility design for the protection and mitigation of accident and transient conditions.
The integrated operation of each of these systems is consistent with the assumptions used in the accident analyses. The Trip Setpoints are the nominal values at which the bistables are set. Any bistable is considered to be properly adjusted when the "as-left" value is within the band for CHANNEL CALIBRATION accuracy (i.e.,+/- rack calibration+
comparator setting accuracy). The Trip Setpoints used in the bistables are based on the analytical limits stated in the UFSAR. The selection of these Trip Setpoints is such that adequate protection is provided when all sensor and processing time delays are taken into account.
To allow for calibration tolerances, instrumentation uncertainties, instrument drift, and severe environment errors for those Reactor Protection System (RPS) channels that must function in harsh environments as defined by 10 CFR 50.49, the Trip Setpoints and Allowable Values specified in the Technical Specification Limiting Conditions for Operation (LCO's) are conservatively adjusted with respect to the analytical limits. The methodology used to calculate the Trip Setpoints is consistent with Instrument Society of America standard ISA-S67.04-1982, which is endorsed via NRC Regulatory Guide 1.105, Rev. 2. The actual nominal Trip Setpoint entered into the bistable is more conservative than that specified by the Allowable Value to account for changes in random measurement errors detectable by a CHANNEL FUNCTIONAL TEST. One example of such a change in measurement error is drift during the surveillance interval.
If the measured setpoint does not exceed the Allowable Value, the bistable is considered OPERABLE.
Setpoints in accordance with the Allowable Value ensure that the safety analyses which demonstrate that safety limits are not violated remain valid (provided the unit is operated within the LCO's at the onset of any design basis event and the equipment functions as designed).
The Trip Setpoints and Allowable Values listed in the LCO's incorporate all of the known uncertainties applicable for each channel.
The magnitudes of these uncertainties are factored into the determination of each Trip Setpoint.
All field sensors and signal processing equipment for these channels are assumed to operate within the allowances of these uncertainty magnitudes.
The surveillance requirements specified for these systems ensure that the overall system functional capability is maintained comparable to the original design standards.
The periodic surveillance tests are sufficient to demonstrate this capability.
The Surveillance Frequency is SALEM -UNIT 2 B 3/4 3-1 Amendment No. 282 (PSEG Issued)
INSTRUMENTATION BASES based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Specified surveillance and maintenance outage times have been determined in accordance with WCAP-10271, "Evaluation of Surveillance Frequencies and Out of Service Times for the Reactor Protection Instrumentation System,"
and Supplements to that report. Out of !:!ervice times were determined based on maintaining an appropriate level of reliability of the Reactor Protection System and Engineered Safety Features instrumentation.
The verification of response time provides assurance that the reactor trip and the engineered safety features actuation associated with each channel is completed within the time limit assumed in the safety analysis.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Response time acceptance criteria have been relocated to UFSAR Section 7.2 tables and 7.3 tables. No credit is taken in the analysis for those channels with response times indicated as not applicable (i.e., N.A.). The Note 8 response times for feedwater isolation are based on WCAP-16503, "Salem Unit 1 and Unit 2 Containment Response to LOCA and MSLB for Containment Fan Cooler Unit (CFCU) Margin Recovery Project,"
Revision 3, (LCR S06-10).
SGFP trip and FIV closure are credited in the containment analyses for LOCA and MSLB in case an FRV fails open. Response time may be verified by actual response time tests in any series of *sequential, overlapping or total channel measurements, or by the summation of allocated sensor response times with actual response time tests on the remainder of the channel.
Allocations for sensor response times may be obtained from: (1) historical records based on acceptable response time tests (hydraulic, noise, or power interrupt tests), (2) inplace, onsite, or offsite (e.g. vendor) test measurements, or (3) utilizing vendor engineering specifications.
WCAP-13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" provides the basis and methodology for using allocated sensor response times in the overall verification of the channel response time for specific sensors identified in the WCAP. Response time verification for other sensor types, and other components that do not have plant-specific NRC approval to use alternate means of verification, must be demonstrated by test. The allocation for sensor response times must be verified prior to placing the component in *operational service and re-verified following maintenance that may adversely affect response time. In general, electrical repair work does not impact response time provided the parts used for repair are of the same type and value. One example where response time could be affected is replacing the sensing assembly of a transmitter.
Channel testing in a bypassed condition shall be performed without lifting leads or jumpering bistables.
* The CHANNEL CALIBRATION surveillance for the Power Range Neutron Flux Function instrumentation is modified by Note 17. Note 17 states that in MODES 1 and 2 the SSPS input relays are excluded from this surveillance when the installed bypass test capability is used to perform this surveillance.
When the installed bypass test capability is used, the channel is tested in bypass versus tripped condition.
To preclude placing the channel in a tripped condition, the SSPS input relays are excluded from this surveillance.
The exclusion of the SSPS input relays from this test is intended to reduce the potential for an inadvertent reactor trip SALEM -UNIT 2 B 3/4 3-1a Amendment No. 293 (PSEG Issued)
INSTRUMENTATION BASES during surveillance testing.
Therefore, the exclusion of the SSPS input relays from the surveillance is only applicable in MODES 1 and 2. The SSPS input relays must be included in the CHANNEL CALIBRATION surveillance at least once every 18 months. The CHANNEL FUNCTIONAL TEST surveillances for the Power Range Neutron Flux and Power Range Neutron Flux High Positive Rate Functio*n Instrumentation are modified by Note 18. Note 18 states that the SSPS input relays are excluded from this surveillance when the installed bypass test capability is used to perform this surveillance.
When the installed bypass test capability is used, the channel is tested in a bypassed versus tripped condition.
To preclude placing the channel in a tripped condition, the SSPS input relays are excluded from this surveillance.
The exclusion of the SSPS input relays from this test is intended to reduce the potential for an inadvertent reactor trip during surveillance testing.
The SSPS input relays must be included in the CHANNEL CALIBRATION surveillance at least once every 18 months. 3/4.3.3 MONITORING INSTRUMENTATION 3/4.3.3.1 RADIATION MONITORING INSTRUMENTATION The OPERABILITY of the radiation monitoring channels ensures that 1) the radiation levels are continually measured in the areas served by the individual channels and 2) the alarm or automatic action is initiated when the radiation level trip setpoint is exceeded.
SALEM -UNIT 2 B 3/4 3-1b Amendment No. 293 (PSEG Issued)
INSTRUMENTATION BASES 3/4.3.3.1 RADIATION MONITORING INSTRUMENTATION (Continued)
In the postulated Fuel Handling
: Accident, the revised dose calculations, performed using 10 CFR 50.67 and Regulatory Guide 1.183, Alternative Source Term, do not take credit for automatic containment pl.Jrge isolation thus allowing for continuous monitoring of co.ntainment activity until containment closure is achieved.
If required, containment purge isolation can be initiated manually from the control room. CROSS REFERENCE
-TABLE 3.3-6 T/S Table Instrument Description Acceptable RMS Item No. Channels 1a 1b 2a1a 2a1b 2a2a 2a2b 2b1 2b3 3a Fuel StoraQe Area 2R5 or 2R9 DELETED Containment Gaseous Activity Purge & PressureNacuum 2R12A or 2R41A, Relief Isolation B and D<1> <2> Containment Gaseous Activity RCS Leakaoe Detection 2R12A (NOT USED) Containment Air Particulate Activity RCS Leakage 2R11A Detection Noble Gas Effluent Medium Range Auxiliary Building 2R41 B & Dl1Jl3Jl5J Exhaust System (Plant Vent) Noble Gas Effluent High Range Auxiliary Building 2R41 C & Dl1Jl4Jl5J Exhaust System (Plant Vent) Noble Gas Effluent Condenser Exhaust System 2R15 Unit 2 Control Room Intake Channel 1 (to Unit 2 Monitor) 2R1B-1 Unit 2 Control Room Intake Channel 2 (to Unit 1 Monitor) 1R1B-2 Unit 1 Control Room Intake Channel 1 (to Unit 1 Monitor) 1R1B-1 Unit 1 Control Room Intake Channel 2 (to Unit 2 Monitor) 2R1B-2 (1) The channels listed are required to be operable to meet a single operable channel for the Technical Specification's "Minimum Channels Operable" requirement.
(2) For Modes 1, 2, 3, 4 & 5, the setpoint applies to 2R41 D per Specification 3.3.3.9.
The measurement range applies to 2R41A and B which display in &#xb5;Ci/cc using the appropriate channel conversion factor from cpm to &#xb5;Ci/cc. (3) 2R41D is the setpoint channel; 2R41B is the measurement channel.
(4) 2R41 D is the setpoint channel; 2R41 C is the measurement channel (5) The release rate channel 2R41 D setpoint value of 2E4 uCi/sec is within the bounds of the concentration setpoint values listed in Table 3.3-6 for normal and accident plant vent flow rates. SALEM UNIT2 8 3/4 3-2 TSBC S2013-057 INSTRUMENTATION BASES Immediate action(s),
in accordance with the LCO Action Statements, means that the required action should be pursued without delay and in a controlled manner. 3/4.3.3.2 THIS SECTION DELETED 3/4.3.3.3 THIS SECTION DELETED 3/4.3.3.4 THIS SECTION DELETED 3/4.3.3.5 REMOTE SHUTDOWN INSTRUMENTATION The OPERABILITY of the remote shutdown instrumentation ensures that sufficient capability is available to permit shutdown and maintenance of HOT STANDBY of the facility from locations outside of the control room. This capability is required in the event control room habitability is lost and is consistent with General Design Criterion 19 of 10 CFR 50. 3/4.3.3.6 THIS SECTION DELETED 3/4.3.3.7 ACCIDENT MONITORING INSTRUMENTATION The OPERABILITY of the accident monitoring instrumentation ensures that sufficient information is available on selected plant parameters to monitor and assess these variables following an accident.
This capability is consistent with the Recommendations of Regulatory Guide 1.97, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident,"
December 1975 and NUREG-0578,"TMl-2 Lessons Learned Task Force Status Report and Short-Term Recommendations."
SALEM -UNIT 2 B 3/4 3-3 Amendment No. 265 (PSEG Issued).
INSTRUMENTATION BASES 3/4.3.3.8 RADIOACTIVE LIQUID EFFLUENT MONITORING INSTRUMENTATION The purpose of tank level indicating devices is to assure the detection and contr9I of leaks that if not controlled could potentially result in the transport of radioactive materials to UNRESTRICTED AREAS. 3/4.3.3.9 THIS SECTION DELETED 3/4.3.3.10 THIS SECTION DELETED 3/4.3.3.11 THIS SECTION DELETED 3/4.3.3.12 THIS SECTION DELETED 3/4.3.3.13 THIS SECTION DELETED SALEM -UNIT 2 B 3/4 3-3a Amendment No. 265 (PSEG Issued)
INSTRUMENTATION BASES 3/4.3.4 Deleted 3/4.3.3.14 POWER DISTRIBUTION MONFTORING SYSTEM CPDMSl The Power Distribution Monitoring System (PDMS) provides core monitoring of the limiting parameters.
The PDMS continuous core power distribution measurement methodology begins with the periodic generation of a highly accurate 3-D nodal simulation of the current reactor power distribution.
The simulated reactor power distribution is then continuously adjusted by nodal and thermocouple calibration factors derived from an incore power distribution measurement obtained using the incore movable detectors to produce a highly accurate power distribution measurement.
The nodal calibration factors are updated in accordance with the Surveillance Frequency Control Program.
Between calibrations, the fidelity of the measured power distribution is maintained via adjustment to the calibrated power distribution provided by continuously input plant and core condition information.
The plant and core condition data utilized by the PDMS is cross checked using redundant information to provide a robust basis for continued operation.
The loop inlet temperature is generated by averaging the respective temperatures from each of the loops, excluding any bad data. The core exit thermocouples provide many readings across the core and by the nature of their usage with the PDMS, smoothing of the measured data and elimination of bad data is performed with the Surface Spline fit. PDMS uses the NIS Power Range excore detectors to provide information on the axial power distribution.
Hence, the PDMS averages the data from the four Power Range excore detectors and eliminates any bad excore detector data. SALEM -UNIT 2 B 3/4 3-4 Amendment No. 282 (PSEG Issued)
INSTRUMENTATION.
BASES The bases for the operability requirements of the PDMS is to provide assurance of the accuracy and reliability of the core parameters measured and calculated by the PDMS core power distribution monitor function.
These requirements fall under four categories:
: 1. Assure an adequate number of operable critical sensors.
: 2. Assure sufficiently accurate calibration of these sensors.
: 3. Assure an adequate calibration database regarding the number of data sets. 4. Assure the overall accuracy of the calibration.
The minimum number of required plant and core condition inputs include the following:*
: 1. Control Bank Positions.
: 2. At least 50% of the cold leg temperatures.
: 3. At least 75% of the signals from the power range excore detector channels (comprised of top and bottom detector section).
: 4. Reactor Power Level. 5.
* A minimum number and distribution of operable core exit thermocouples.
: 6. A minimum number and distribution of measured fuel assembly power distribution information obtained using the incore movable detectors is incorporated in the nodal model calibration information.
The sensor calibration of Items 1, 2, 3, and 4 above are covered under other specifications.
Calibration of the core exit thermocouples is accomplished in two parts. The first being a sensor specific correction to K-type thermocouple temperature indications based on data from a cross calibration of the thermocouple temperature indications to the average RCS temperature measured via the RTDs under isothermal RCS conditions.
The second part of the thermocouple calibration is the generation of thermocouple flow mixing factors that cause the radial power distribution measured via the thermocouples to agree with the radial power distribution from a full core flux map measured using the incore movable detectors.
This calibration is updated in accordance with the Surveillance Frequency Control Program.
The operability requirements previously contained in Specification 3.3.3.2 have been moved to UFSAR Section 7.7.2.8 as part of Amendment 265. SALEM -UNIT 2 8 3/4 3c.5 Amendment No. 282 (PSEG Issued) l/f .4 Wc:"l'OR cooI.AJrr IISTll BAHS ******************************************************************************
311 ''. 1 JtQCtl01l eoo?..MT t;()OPS MP Coot.ANT
'IJl.gn.AUOH The pla:t ia designed to operate with all reactor coolant loop* in operation, meet th* de*isi= criteria duri:; all normal operation*
and anticipated tran.ienta.
Zn HOD*s 1 mid 2 with l*** tA&z:i. all coolant loop* in operation, thia *p*cification requir**
that th* pl&Dt be in at lea*t BOT STANDBY within l hc1U'. In HOD* 3, a *in;l* reactor coola:t loop provide*
aufficient h*at r-=cval for removing decay heat1 ailigle failu:-e requir* all loop* b* in operation whenever th* rod control ay*tem i* energized and at l*aat one -loop be in operation whe: th* rod control ayatmza i* d*an*rgiz*d.
In XODZ 4, a *ingl* reactor coolant loop or RJal loop provide*
*uffici*nt removal fer removing decay heat1 but, *in;l* failure con*iderationa require that at l***t 4 loop* be OPKR.ABLZ.
Thu*, if the reactor coolant loops are not OPBRAJU..S, thi* specification require*
that two RKR loop* be OPZJU.BLE.
In HODZ 5, *ingle failur* conaiderationa r*quir* that two JUDl loop* be Ol'IRllL.J:.
Por aupport ayateJIUI:
Service Water (Slfl and Ccmpon*nt Cooling (CC), component redWld&.1:1cy ia neceaaary to enaura no aingle active component failure will cau** th* lo** of Decay Beat Removal.
o=e piping path of SW and CC i* adequate when it aupporta both RKR loop*. The *uppcrt *Y*tama n**d*d before enuring into th* de*ired configuration (e.g., one aervic* water loop out for m.ainten&nc*
in Mod** 5 and 6) are ccntroll*d by procedure*,
and include the following:
* A requirement that twc RD, two CC: and two SW pu=pa, powered from two ctifferant vital bu*** b* kept opera.bl*
* A liating of th* active Cair/JDOtor operated) valv** in th* affacted flow path to ba locked open or dia&bled Note that tour tilled reactor coolant loopa,-with at l***t two *team generator*
with at l***t their aide water level greater than or equal to 5\ (narrow r&.1:1g*),
may b*
for o:* re1idual beat removal loop. Thi* enaur** that a ain;l* failure do** net cau** a lo** cf decay h*at r-=oval.
The operation of on* aeactor Coolant Pump or en* REJl Pump prcvid**
adequate flow to enaur* prev.nt atratification
&lld produce gradual raactivity cbL1:1g...---duri.cg
:ao:ron concentration reduction.
in th* **actor CoolLllt Sy*tm:a.
Tb* reactiTity ch&ni* rat* a**ociated With BcrOll concentration reductioaa will, therefore, be within th* capability cf operator recognition
&%Id control.
The r**triction*
en *t&rti:g a aaactor Coolant Pump below P-7 with one or more acii cold l*i* l*** th.an or equal to are pr'O'Yid*d to prevent RCS pr***ure tran1ient*,
cau**d by energy addition*
-from th* eecocdary system, which could exceed th* 11.s.it*
of Appendix G to lOC71t Part 50. Th* RCS will be protected again*t overpr***ur*
tra.naienta Lnd will net e.xce*d th* limit* of Appendix Q by either (1) r**tricting th* wat*r volume in th* pr***uriz*r (thereby providing
* velum* into which th* pri.Jzi,ary coolant can exp&nd, or (2l by re1trictin; th* at&rting of Raaetor Ceola.at J>\.m:lp*
to tho** time* when *ecocdary Water te.mperature iJ:I each Steam generator ia le88 th&n 5o*p above each of th* RCS cold leg tuip*ratuz***
Sllb -'CN'XT 2
* l/4 1-1 Amendment No. 197 REACTOR COOLANT SYSTEM BASES 3/4.4.2 and 3/4.4.3 SAFETY VALVES The pressurizer code safety valves operate to prevent the RCS from being pressurized above its Safety Limit of 2735 psig. Each safety valve is designed to relieve 420,000 pounds per hour of saturated steam at the valve setpoint.
The relief capacity of a single safety valve is adequate to relieve any overpressure condition which could occur during shutdown.
In the event that no safety valves are OPERABLE, an operating RHR loop, connected to the RCS, provides overpressure relief capability and will prevent RCS overpressurization.
In addition, the Overpressure Protection System provides a diverse means of protection against RCS overpressurization at low temperature.
While in Mode 5 the safety valve requirement may be met by establishing a vent path of equivalent relieving capacity when no code safety valves are OPERABLE.
During operation, all pressurizer code safety valves must be OPERABLE to prevent the RCS from being pressurized above its safety limit of 2735 psig. The combined relief capacity of all of these valves is greater than the maximum surge rate resulting from a complete loss of load assuming no reactor trip until the first Reactor Protective System trip setpoint is reached (i.e., no credit is taken for a direct reactor trip on the loss of load) and also assuming no operation of the power operated relief valves or steam dump valves. Demonstration of the safety valves lift settings will occur only during shutdown and will be performed in accordance with the provisions of Section XI of the ASME Boiler and Pressure Code.
* Surveillance testing allows a +/- 3% lift setpoint tolerance.
: However, to allow for drift during subsequent operation, the valves must be reset to within +/- 1 % of the lift setpoint following testing.
3/4.4.4 PRESSURIZER The limit on the maximum water volume in the pressurizer assures that the parameter is maintained within the normal steady-state envelope of operation assumed in the SAR. The limit is consistent with the initial SAR assumptions.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the
* Surveillance Frequency Control Program.
The maximum water volume also ensures that a steam bubble is formed and thus the RCS i.s not a hydraulically solid system. The requirement that a minimum number of pressurizer heaters be OPERABLE enhances the capability of the plant to control RCS pressure and establish natural circulation.
3/4.4.5 RELIEF VALVES The OPERABILITY of the PORVs and block valves is determined on the basis of their being capable of performing the following functions:
A. Manual control of PORVs to control reactor coolant system pressure.
This is a function that is used for the steam generator tube rupture accident and for plant shutdown.
SALEM -UNIT 2 B 3/4 4-2 Amendment No. 282 (PSEG Issued)
REACTOR COOLANT SYSTEM BASES 3/4.4.5 RELIEF VALVES (continued)
B. Automatic control of PORVs to control reactor coolant system pressure.
This is a function that reduces challenges to the code safety valves for overpressurization events, including an inadvertent actuation of the Safety Injection System. C. Maintaining the integrity of the reactor coolant pressure boundary.
This is a function that is related to controlling identified leakage and ensuring the ability to detect unidentified reactor coolant pressure boundary leakage.
D. Manual control of the block valve to : (1) unblock an isolated PORV to allow it to be used for manual and automatic control of Reactor Coolant System pressure (Items A & B), and (2) isolate a PORV with excessive seat leakage (Item C). E. Manual control of a block valve to isolate a stuck-open PORV. 3/4.4.6 STEAM GENERA TOR CSG) TUBE INTEGRITY The LCO requires that SG tube integrity be maintained.
The LCO also requires that all SG tubes that satisfy the plugging criteria be plugged in accordance with the Steam Generator Program.
* During an SG inspection, any inspected tube that satisfies the Steam Generator Program plugging criteria is removed from service by plugging.
If a tube was determined to satisfy the plugging criteria but was not plugged, the tube may still have tube integrity.
In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall, between the tube-to-tubesheet weld at the tube inlet and the tubesheet weld at the tube outlet The tube-to-tubesheet weld is not considered part of the tube. A SG tube has tube integrity when it satisfies the SG performance criteria.
The SG performance criteria are defined in Specification 6.8.4.i, "Steam Generator (SG) Program,"
and describe acceptable SG tube performance.
The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.
There are three SG performance criteria:
structural integrity, accident induced leakage, and operational leakage.
Failure to meet any one of these criteria is considered failure to meet the LCO. SALEM -UNIT 2 B 3/4 4-3 Amendment No. 291 (PSEG Issued)
REACTOR COOLANT SYSTEM BASES The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification.
Tube burst is defined as, "The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic) tearing of the tube material at the ends of the degradation."
Tube collapse is defined as, "For the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero." The structural integrity performance criterion provides guidance on assessing loads that significantly affect burst or collapse.
In that context, the term "significant" is defined as, "An accident loading condition other than differential pressure is considered significant when the addition of loads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established."
For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis. The division between primary and secondary classifications will be based on detailed analysis and/or testing.
Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code, Section III, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification.
This includes safety factors and applicable design basis loads based on ASME Code, Section III, Subsection NB and draft Reg. Guide 1.121. The accident induced leakage performance criterion ensures that the secondary leakage caused by a design basis accident, other than a steam generator tube rupture (SGTR), is within the accident analysis assumptions.
The accident analysis assumes that accident induced leakage does not exceed 1 gpm per SG. The accident induced leakage rate includes any primary-to-secondary leakage existing prior to the accident in addition to primary-to-secondary leakage induced during the accident.
The operational leakage performance criterion provides an observable indication of SG tube conditions during plant operation.
The limit on operational leakage is contained in LCO 3.4.7.2, "Operational Leakage,"
and limits primary-to-secondary leakage through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of leakage is due to more than one crack, the cracks are very small, and the above assumption is conservative.
The ACTION requirements are modified by a Note clarifying that the Actions may be entered independently for each SG tube. This is acceptable because the Action requirements provide appropriate compensatory actions for each affected SG tube. Complying with the Action requirements may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Action requirements.
SALEM -UNIT 2 B 3/4 4-3a Amendment No. 262 (PSEG Issued)
REACTOR COOLANT SYSTEM BASES If it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube plugging criteria but were not plugged in accordance with the Steam Generator
: Program, an evaluation of SG tube integrity of the affected tube(s) must be made. Steam. generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program.
The SG plugging criteria define limits on SG tube that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next refueling outage or SG tube inspection.
The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the
* estimated growth of the degradation prior to the next SG tube inspection.
An action time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.
If the evaluation determines that the affected tube(s) have tube integrity, plant operation is allowed to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes. However, the affected tube(s) must be plugged prior to entering HOT SHUTDOWN following the next refueling outage or SG inspection.
This allowed outage time is acceptable since operation until the next inspection is supported by the operational assessment.
If SG tube integrity is not being maintained or the Action requirements are not met, the reactor must be brought to HOT STANDBY within 6 hours and COLD SHUTDOWN within 36 hours. The action times are reasonable based on operating experience, to reach the desired plant conditions from full power conditions in an orderly manner and without challenging plant systems.
During shutdown periods the SGs are inspected as required by surveillance requirements and the Steam Generator Program.
NEI 97-06, "Steam Generator Program Guidelines,"
and its referenced EPRI Guidelines, establish the content of the Steam Generator Program.
Use of the Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.
During SG inspections a condition monitoring assessment of the SG tubes is performed.
The condition monitoring assessment determines the "as found" condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period. The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube plugging criteria.
Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations.
The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.
Inspection methods are a function of degradation morphology, nondestructive examination (NOE) technique capabilities and inspection locations.
The Frequency is determined by the operational assessment and other limits in the SG examination guidelines.
SALEM -UNIT 2 B 3/4 4-3b Amendment No. 291 (PSEG Issued)
REACTOR COOLANT SYSTEM BASES The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection.
In addition, Specification 6.8.4.i contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.
If crack indications are found in any SG tube, the maximum inspection interval for all affected and potentially affected SGs is restricted by Specification 6.8.4.i until subsequent inspections support extending the inspection interval.
During an SG inspection, any inspected tube that satisfies the Steam Generator Program plugging criteria is removed from service by plugging.
The tube plugging criteria delineated in Specification 6.8.4.i are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in size measurement and future growth. In addition, the tube plugging
: criteria, in conjunction with other elements of the Steam Generator
: Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s).
NEI 97-06 provides guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.
The Frequency of prior to entering HOT SHUTDOWN following a SG inspection ensures that the Surveillance has been completed and all tubes meeting the plugging I criteria are plugged prior to subjecting the SG tubes to significant primary-to-secondary
* pressure differential.
SALEM -UNIT 2 B 3/4 4-3c Amendment No. 291 (PSEG Issued)
REACTOR COOLANT SYSTEM BASES 3/4.4.7 REACTOR COOLANT SYSTEM LEAKAGE 3/4.4.7.1 LEAKAGE DETECTION SYSTEMS The RCS leakage detection systems required by this specification are provided to monitor and detect leakage from the Reactor Coolant Pressure Boundary.
These detection systems are consistent with the reconunendations of Regulatory Guide 1.45, "Reactor Coolant Pressure Boundary Leakage Detection Systems,"
May 1973. 3/4.4.7.2 OPERATIONAL LEAKAGE Industry experience has shown that while a limited amount of leakage is expected from the RCS, the unidentified portion of this leakage can be reduced to a threshold value of less than 1 GPM. This threshold value is sufficiently low to ensure early detection of additional leakage.
The 10 GPM IDENTIFIED LEAKAGE limitation provides allowance for a limited amount of leakage from known sources whose presence will not interfere with the detection of UNIDENTIFIED LEAKAGE by the leakage detection systems.
The surveillance requirements for RCS Pressure Isolation Valves provide added assurance of valve integrity thereby reducing the probability of gross valve failure and consequent intersystem LOCA. Leakage from the RCS Pressure Isolation Valves is IDENTIFIED LEAKAGE and will be considered as a portion of the allowed limit. PRESSURE BOUNDARY LEAKAGE of any magnitude is unacceptable since it may be indicative of an impending gross failure of the pressure boundary.
Therefore, the presence of any PRESSURE BOUNDARY LEAKAGE requires the unit to be promptly placed in COLD SHUTDOWN.
Primary to Secondary Leakage Through Any One SG The primary-to-secondary leakage rate limit applies to leakage through any one Steam Generator.
The limit of 150 gallons per day per steam generator is based on the operational leakage performance criterion in NEI 97-06, Steam Generator Program Guidelines.
The Steam Generator Program operational leakage performance criterion in NEI 97-06 states, RCS operational primary-to-secondary leakage through any one SG shall be limited to 150 gallons per day." The limit is based on operating experience with steam generator tube degradation mechanisms that result in tube leakage.
The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.
The dosage contribution from the tube leakage will be within 10 CFR 50.67 limits in the event of either a steam generator tube rupture or steam line break. The analyses are based on the total primary to secondary leakage from all SGs of 1 gallon per minute as a result of accident induced conditions.
SALEM -UNIT 2 B 3/4 4-4 Amendment No. 262 (PSEG Issued)
REACTOR COOLANT SYSTEM BASES 3/4.4.7.2 OPERATIONAL LEAKAGE (Continued)
Actions Unidentified leakage or identified leakage in excess of the LCO limits must be reduced to within limits within 4 hours. This action time allows time to verify leakage rates and either identify unidentified leakage or reduce leakage to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the reactor coolant pressure boundary (RCPB). If any pressure boundary leakage *exists, or primary-to-secondary leakage is not within limit, or if unidentified or identified leakage cannot be reduced to within limits within 4 hours, the reactor must be brought to lower pressure conditions to reduce the severity of the leakage and its potential consequences.
It should be noted that leakage past seals and gaskets is not pressure boundary leakage.
The reactor must be brought to HOT STANDBY within 6 hours and COLD SHUTDOWN within 36 hours. This action reduces the leakage and also reduces the factors that tend to degrade the pressure boundary.
The action times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
In COLD SHUTDOWN, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely. Surveillances Verifying RCS leakage to be within the LCO limits ensures the integrity of the Reactor Coolant Pressure Boundary is maintained.
Pressure boundary leakage would at first appear as unidentified leakage and can only be positively identified by inspection.
It should be noted that leakage past seals and gaskets is not pressure boundary leakage.
Unidentified leakage and identified leakage are determined by performance of an RCS water inventory balance.
The RCS water inventory must be met with the reactor at steady state operating conditions.
The surveillance is modified by a Note that the surveillance is not required to be performed until 12 hours after establishing steady state operation:
The 12 hour allowance provides sufficient time to collect and process all necessary data after stable plant conditions are established.
Steady state operation is required to perform a proper inventory balance since calculations during maneuvering are not useful. For RCS operational leakage determination by water inventory
: balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and Reactor Coolant Pump seal injection and return flows. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency C,antrol Program.
Satisfying the primary-to-secondary leakage limit ensures that the operational leakage performance criterion in the Steam Generator Program is met. If SR 4.4. 7 .2.1.c is not met, compliance with LCO 3.4.6, "Steam Generator Tube Integrity,"
should be evaluated.
The 150 gallons per day limit is measured at room temperature (in accordance with EPRI PWR to-Secondary Leak Guidelines).
If it is not practical to assign the leakage to an individual steam generator, all the primary-to-secondary leakage should be conservatively assumed to be from one Steam Generator.
The Surveillance is modified by a Note that states that the surveillance is not required to be performed until 12 hours after establishment of steady state operation.
For RCS primary-to-secondary leakage determination, steady SALEM-UNIT 2 B 3/4 4-4a Amendment No. 282 (PSEG Issued)
REACTOR COOLANT SYSTEM BASES 3/4.4.7.2 OPERATIONAL LEAKAGE (Continued) state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and Reactor Coolant Pump seal injection and return flows. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
The secondary leakage is determined using continuous process radiation monitors or radiochemical grab sampling (in accordance with EPRI PWR Primary-to-Secondary Leak Guidelines).
3/4.4.8 THIS SECTION DELETED SALEM -UNIT 2 B 3/4 4-5 Amendment No. 282 (PSEG Issued) 
 
COOLANT SYSTEM BASES 3/4.4.9 ACTIVITY The. limitations on the specific activity of the primary coolant ensure that the resulting 2 hqur doses at* the si.te boundary will not exceed an appropriately small fraction of Part 100 limits following a steam generator tube rupture accident in conj&#xb5;nction an assumed steady state primary-to-secondary steam generator leakage rate;of 1.0 GPM. values for the limits on specific activity represent interim limits based upon a parametric evaluation by the NRC of typical site locations.
These values are conservative in that spe.cific site parameters of the Salem site, such as site boundary location and meteorological conditions, were not considered in this evaluation.
The NRC is finalizing site specific criteria which will be used as the basis for.the reevaluation of the specific activity limits of this site. This reevaluation may result in higher limits. Reducing T avg : to less than 500&deg;F prevents the release of activity should a steam generator tube*rupture occur since the saturation pressure of the primary coolant is the lift pressure of the atmospheric steam relief valves. The surveillance requirements provide adequate assurance that excessive specific activity levels in the primary coolant will be detected in sufficient time to take corrective action. Info.llllation obtained on iodine spiking will.be used to assess the parameters associated with spiking phenomena.
A reduction in frequency of isotopic analyses following power changes may be permissible if justified by the data obtained.
LCO 3.0.4,.c is applicable.
This al.1,owance permits entry into the applicable MODE(S) while relying .on the ACTIONS.
SALEM -UNIT 2 B 3/4 4-6 Amendment No, 258 REACTOR COOLANT SYSTEM BASES 3/4.4.10 PRESSURE/TEMPERATURE LIMITS The temperature and pressure changes during heatup and cooldown are limited to be consistent with the requirements given in the ASME Boiler and Pressure Vessel Code, Section XI, Appendix G. 1) The reactor coolant temperature and pressure and system heatup and cooldown rate (with the exception of the pressurizer) shall be limited in accordance with Figures 3.4-2 and 3.4-3 for the service period specified thereon.
a) Allowable combinations of pressure and temperature for specific temperature change rates are below and to the right of the limit lines shown. Limit lines for cooldown rates between those presented may be obtained by interpolation.
b) Figures and 3.4-3 define limits to assure prevention of nonductile failure only. For normal operation, other inherent plant characteristics, e.g., pump heat addition and pressurizer heater capacity, may limit the heatup and cooldown rates that can be achieved over certain pressure-temperature ranges. 2) These limit lines shall be calculated periodically using methods provided below. 3) The secondary side of the steam generator must not be pressurized above 200 psig if the temperature of the steam generator is below 70&deg;F. 4) The pressurizer heatup and cooldown rates shall not exceed 100&deg;F/hr and 200&deg;F/hr, respectively.
The spray shall not be used if the temperature difference between the pressurizer and the spray fluid is greater than 320&deg;F. 5) System preservice hydrotests and in-service leak and hydrotests shall be performed at pressures in accordance with the requirements of ASME Boiler and Pressure Vessel Code, Section XI. The fracture toughness properties of the ferritic materials in the reactor vessel are determined in accordance with the NRC Standard Review Plan, ASTM El85-82, and in accordance with additional reactor vessel requirements.
These properties are then evaluated in accordance with Appendix G of *the 1996 Summer Addenda to Section XI of the ASME Boiler and Pressure Vessel Code and the calculation methods described in WCAP-14040-NP-A, Rev. 2, "Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves",
January 1996, and ASME Boiler and Pressure Vessel Code Case N-640, "Alternative Reference Fracture Toughness.
for Development of P-T Limit Curves for Section XI, Division l", approved March 1999. Heatup and cooldown limit curves are calculated using the most limiting value of the nil-ductility reference temperature, RTNDT, at the end of 32 effective full power years of service life. The 32 EFPY service life period is chosen such that the limiting RTNOT at the 1/4T location in the core region is greater than the RTNDT of the limiting unirradiated material.
The selection of such a limiting RTNDT assures that all components in the Reactor Coolant System will be operated conservatively in accordance with applicable Code requirements.
SALEM -UNIT 2 B 3/4 4-7 Amendment No. 224 I REACTOR COOLANT SYSTEM BASES The reactor vessel materials have been tested to determine their initial RTNoti the results of these tests are shown in Table B 3/4.4-1.
Reactor operation and resultant fast neutron (E greater than 1 MEV) irradiation can cause an increase in the RTNDT* An adjusted reference temperature, (ART), based upon the fluence and the copper and nickel content of the material in question, can be predicted.
The ART is based upon the largest value of RTNM" computed by the methodology presented in Regulatory Guide 1.99, Revision
: 2. The ART for each material is given by the following expression:
ART = Initial RTNDT + .l\RTNDT
+ Margin Initial RTNDT is the reference temperature for the unirradiated material.
6RTNDT is the mean value of the adjustment in reference temperature caused by the irradiation and is calculated as follows:
6RTNDT = Chemistry Factor x Fluence Factor The Chemistry Factor, er (F), is a function of copper and nickel content.
It is given in Table 83/4.4-2 for welds and in Table 83/4.4-3 for base metal (plates and forgings).
Linear interpolation is permitted.
The predicted neutron fluence as a function of Effective Full Power Years (EFPY) has been calculated and is shown in Figure The fluence factor can be calculated by using Figure 83/4.4-2.
Also, the neutron fluence at any depth in the vessel wall is determined as follows:
-0.24X f (f surface) x (e ) where "f surface" is. from Figure 83/4.4-1, and X (in inches) is the depth into the vessel wall. Finally, the "Margin" is the quantity in &deg;F that is to be added to obtain conservative, upper-bound values of adjusted reference temperature for the calculations required by Appendix G to 10 CFR 50. Margin =
+ u A 2 If a measured value of initial RTNDT for the material in is used, a1 may be taken as zero. If generic value of initial RTNDT is used, o1 should be obtained from the same set of data. The standard deviations, for a4, are 28&deg;F for welds and 17&deg;F for base metal, except that 04 need not exceed 0. 50. times the mean value of 6RTNDT surface.
The heatup and cooldown limit curves of Figures 3.4-2 and 3.4-3 include predicted adjustments for this shift in RTNDT at the end of 32 EFPY. SALEM -UNIT 2 B 3/4 4-8 Amendment No. 224 I _,,,,, I REACTOR COOLANT SYSTEM BASES Values of &RTNDT determined in this manner may be used until the results from the material surveillance
: program, evaluated according to ASTM El85, are available.
Capsules will be removed in accordance with the requirements of ASTM El85-82 and 10 CFR Part 50, Appendix H. The heatup and cooldown curves must be recalculated when the &RTNDT determined from the surveillance capsule exceeds the calculated
&RTNor for the equivalent capsule radiation exposure.
Allowable pressure-temperature relationships for various heatup and cooldown rates are calculated using methods derived from Appendix G in Section XI of the ASME Boiler and Pressure Vessel Code as required by Appendix G to 10 CFR Part 50 and these methods are discussed in detail in WCAP-14040-NP-A, Rev. 2, "Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves",
January 1996, and ASME Boiler and Pressure Vessel Code Case N-640, "Al.ternative Reference Fracture Toughness for Development of P-T Limit Curves for Section XI, Division l", approved March 1999. The general method for calculating heatup and cooldown limit curves is based upon the principles o.f the linear elastic fracture mechanics (LEFM) technology.
In the calculation procedures a semi-elliptical surface defect with a depth of one-quarter of the wall thickness, T, and a length of 3/2T is assumed to exist at the inside of the vessel wall as well as at the outside of the vessel wall. The dimensions of this postulated crack, referred to in Appendix G of ASME Section XI as the reference flaw, amply exceed the current capabilities of inservice inspection techniques.
Therefore, the reactor operation limit curves developed for this reference crack are conservative and provide sufficient safety margins for protection against nonductile failure.
To assure that the radiation ernbrittlement effects are accounted for in the calculation of the limit curves, the most limiting value of the nil-ductility reference temperature, RTNDT, is used and this includes the radiation induced shift, corresponding to the end of the period for which heatup and cooldown curves are generated.
The ASME approach for calculating the allowable limit curves for various heatup and cooldown rates specifies that the total stress intensity factor, K1, for the combined thermal and pressure stresses at any time during heatup or cooldown cannot be greater than the reference stress intensity factor, Kier for the metal temperature at that time. Kie is obtained from the reference fracture toughness curve, defined in ASME Code Case N-640. The K1ecurve is given by the equation:
Kie= 33.2.+ 20.734 exp [0.02(T-RTNDT)]
(1) where Kie is the reference stress intensity factor as a function of the metal temperature T and the metal nil-ductility reference temperature RTNDT* Thus, the governing equation for the heatup-cooldown analysis is defined in Appendix G of the ASME Code as follows:
(2) SALEM -UNIT 2 8 3/4 4-9 Amendment No. 224 REACTOR COOLANT SYSTEM BASES where K1K is the stress intensity factor caused by membrane (pressure) stress. K1t is the stress intensity factor caused by the thermal gradients.
K1c is provided by the code as a function of temperature relative to the I RTND'l' of the material.
C = 2.0 for level A and B service limits, and C = 1.5 for inservice hydrostatic and leak test operations.
At any time during the heatup or cooldown transient, K1c is* determined by the I metal temperature at the tip of the postulated flaw, the appropriate value for RTNoT1 and the reference fracture toughness curve. The thermal stresses resulting from temperature gradients.through the vessel wall are calculated and then the corresponding (thermal) stress intensity
: factors, K11, for the reference flaw are computed.
From Equation (2) the pressure stress intensity factors are obtained and from these the allowable pressures are calculated.
COOLDOWN For the calculation of the allowable pressure versus coolant temperature during cooldown, the Code reference flaw is assumed to exist at the inside of the vessel wall. During cooldown, the controlling location of the flaw is always at the inside of the wall because the thermal gradients produce tensile stresses at the inside, which increase with increasing cooldown rates. Allowable pressure-temperature relations are generated for both steady-state and finite cooldown rate situations.
From these relations composite limit curves are constructed for each cooldown rate of interest.
The use of the composite curve in the cooldown analysis is necessary because.
control of the cooldown procedure is based on measurement of reactor coolant temperature, whereas the limiting pressure is actually dependent on the material temperature at the tip of the assumed flaw. During cooldown, the l/4T vessel location is at a higher temperature than the fluid adjacent to the vessel ID. This condition, of course, is not true for the steady-state situation.
It follows that at any given reactor coolant temperature, the &T developed during cooldown results in a higher value of Kic at the 1/4T
* I location for finite cooldown rates than for steady-state operation.
Furthermore, if conditions exist such that the increase in K1c exceeds K1T, I the calculated allowable pressure during cooldown will be greater than the steady-state value. The above procedures are needed because there is no direct control on temp.erature at the l/4T location, therefore, allowable pressures may unknowingly be violated if the rate of cooling is decreased at various intervals along a cooldown ramp.
The use of the composite curve eliminates this problem and assures conservative operation of the system for the entire cooldown period. SALEM -UNIT 2 B 3/4 4-10 Amendment No. 224 -
REACTOR COOLANT SYSTEM BASES HEATUP Three separate calculations are required to determine the limit curves for finite heatup rates. As is done in the cooldown
: analysis, allowable pressure-temperature relationships are developed for steady-state conditions as well as finite. heatup rate conditions assuming the presence of a l/4T defect at the inside of the vessel wall. The thermal gradients during heatup produce compressive stress at the inside of the wall that alleviate the tensile stresses produced by internal pressure.
The metal temperature at the crack tip lags the coolant temperature.
Therefore, the Kxc for the l/4T crack during heatup is lower than the Kxc for the l/4T crack during steady-state conditions at the same coolant temperature.
During heatup, especially at the end of the transient, conditions may exist such that the effects of compressive thermal stresses and different K1cs for steady-state and finite heatup rates do not each other and the pressure-temperature curve based on steady-state conditions no longer represents a lower bound of all similar curves for finite heatup rates when the l/4T flaw is considered, Therefore, both cases have to be analyzed in order to assure that at any coolant temperature the lower value of the allowable pressure calculated for steady-state and finite heatup rates is obtained.
The second portion of the heatup analysis concerns the calculation of pressure-temperature limitations for the case in which a l/4T deep outside surface flaw is assumed.
Unlike the situation at the vessel inside surface, the thermal gradients established at the outside surface during heatup produce stresses which are tensile in nature and thus tend to reinforce any pressure stresses present.
These thermal stresses, of course, are dependent on both the rate of heatup and the time (or coolant temperature) along the heatup ramp. Furthermore, since the thermal stresses, at the outside are tensile and increase with increasing heatup rate, a lower bound curve cannot be defined.
Rather, each heatup rate of interest must be analyzed on an individual basis. :allowing the generation of pressure-temperature curves for both the steady-state and finite heatup rate situations, the final limit curves are produced as follows.
A composite curve' is constructed based on a point-by-point comparison of the steady-state and finite heatup rate data. At any given temperature, the allowable pressure is taken to be the lesser of the three values taken from the curves under consideration.
The use of the composite curve is necessary to set conservative heatup limitations because it is possible for conditions to exist such that over the course of the heatup ramp the controlling condition switches from the inside to the outside and the pressure limit must at all times be based on analysis of the most critical criterion.
SALEM -UNIT 2 B 3/4 4-11 Amendment No. 224 REACTOR COOLANT!SYSTEM BASES Finally, the new 10CFR50 rule which addresses the metal temperature of the closure head regions is considered.
This 10CFR50 rule states that. the metal temperature of the closure flange regions must exceed the material RTNDT by .at *least 120&deg;F for normal operation when the pressure exceeds 20 percent of the preservice hydrostatic test pressure (621 psig for Salem), Table indicates that the limiting RTNoT of 2B&deg;F occurs in the closure head flange of Salem-Unit 2, and the minimum allowable temperature of this region is 148&deg;F at greater than 621 psig. These limits do not affect Figures 3.4-2 and 3.4-3. Although the pressurizer operates in temperature ranges above those for which there is reason* for concern of non-ductile
: failure, operating limits are to assure compatibility of operation with the fatigue analysis perfo.i:med in accordance.
with the ASME Code requirements.
The '.OPERABILITY of two POPSs or an RCS vent opening of greater than 3.14 sguare inches ensures that the RCS will be protected from pressure transients which could exqeed the limits* of Appendix G to 10 CFR Part 50 when one or more of the RCS cold iegs are less than or equal to 312&deg;F. Either POPS has adequate relieving capability to protect the RCS from overpressurization when the *transient is limited to either (1) the start of an idle RCP with the secondary water temperature of the steam generator less than or equal to 50&deg;F above the RCS cold leg temperatures, or (2) the start of an Intermediate Head Safety Injection pump and its injection into a water solid RCS, or the start of a High Head Injection pump. in conjunction with a running Positive Displacement pump and its injection into a water solid RCS. The minimum electrical power sources required to as*sure POPS* operability (based on POPS meeting the single failure criteria) consist of a. n&#xa2;rmal (via offsite power) and an emergency (via batteries) power source for each train.of POE'S. Emergency diesel generators are not required for POPS to
:single failure criteria and therefore are not required for POPS OPERABILITY.
LCO 3.0.4.b is: not applicable to an inoperable LTOP system when entering MODE 4. There is an increased risk associated with entering MODE 4 from MODE 5 with an LTOP system. The provisions of LCO 3.0.4.b, which allow entry into a MODE or other specitied condition in the Applicability with the LCO not met after performance of' a risk assessment addressing inoperable systems and components, should not_ be applied, in this circumstance.
SALEM -UNIT 2 B 3/4 4-12 Amendment No. 256 TABLE;. 1/4.4-1 SALEM UNIT 2 REACTt ESSEL TOUGHNESS DATA Component Plate No. Material Cu (\) Ni T or Weld Type (\) (oF) NO. Closure Hd Dome 84708 A533BCL1 0.11 0.10 -40 Closure Hd Peel 85007-3 A533BCL1 0.12 o.57 -20 Closure Hd Peel 84707-1 A533BCL1 0.10 0.55 0 Closure Hd Peel 84707-3 A53JBCL1 0.13 o.63 0 Closure Hd Flng 84702-1 A508CL2 -o.68 28* Vessel Flange 85001 ASOSCL2 -0.10 12* Inlet Nozzle 84703-1 A508CL2 -0.69 60* Inlet Nozzle 84703-2 A508CL2 -o.69 60* Inlet Nozzle 84703-3 AS08CL2 -o.68 60* Inlet Nozzle 84703-4 A508CL2 -0.81 60* outlet Nozzle 84704-1 A508CL2 -o.84 60* Outlet Nozzle 84704-2 A508CL2 -0.11 60* Outlet Nozzle 84704-3 A508CL2 -o.69 28* Outlet Nozzle 84704-4 AS08CL2 -0.71 60* Upper Shell 84711-1 AS33BCL1 0.11 0.55 O* Upper Shell 84711-2 A5338CL1 0 .14 o.56 -10 Upper Shell 84711-3 A533BCL1 0.12 o.sa -10 Inter, Shell 84712-1 A5338CL1 0.13 o.56 0 Inter. Shell 84712-2 A5338CL1 0.12 0:62 -20 Inter. Shell 84712-3 AS338CL1 0.11 0.57 -so Lower Shell 84713-1 A533BCL1 0.12 0.60 -10 Lower Shell 84713-2 A5338CL1 0.12 o.57 -20 Lower Shell 84713-3 A5338CL1 0.12 0.58 -10 Bottom Hd Peel 84709-1 AS33BCL1 0.12 0.60 -30 Bottom Hd Peel 84709-2 A533BCL1 0.12 o.se -20 Bottom Hd Peel 84709-3 A5338CL1 0.11 o.56 -20 Bottom Head 84710 A5338CL1 0.12 0.60 -30 Circum. Weld Bet 8-442 -0.28 o.74 -Nozzle Shell & Int. Shell \ Circum. Weld Bet .9-442 -0.197 0.060 -Int. Shell & Lower Shell Int. Shell 2-442 -0.219 o.735 -Vertical Weld [A,8,C] Lower Shell 3-442 -0.213 o.867 -Vertical Weld [A,B, Cl Estimated per NRC Standard Review Plan Section 5.8.2, 100% Shear not reached 50 ft-lb 35 -Mil Temp (oF) 4S* 15* 51* 66* 39* 4* 62* 25* 32* 40* 8* 20* 8* 40* 50* 60* 88* <60 72 70 68 68 70 54* 42* 71* 60* ----* ** *** Estimate per Pressurized Thermal Shock Rule, 10 CFR 50.61 SALEM -UNIT 2 B 3/4 4-13 RT (oF) -15* -20* O* 6* 28* 12* 60* 60* 60* 60* 60* 60* 28* 60* o* o* *28* 0 12 10 8 8 10 -6* -18* 11* O* -56*** -56*** -56*** -56*** Average Upper Shell Energy Normal to Principal Principal Working Working Direction Direction (ft-lb) (ft-lb) 82.5 127 97* 149 84* 129 84* 129.5 104* 160 107* 164 >72* >111** >61* >.94** >71* >109** 80* 123.5 82* 126 75* 116 82* 126 77* 119 . 87* 134 .79* 122 69* 107 106 138 97 127 .s 107 116 I 98 127 103 135.5 121 135.S 90* 139 I 89* 137.5 .93* 143 77* 118 --99.7 -96.2 -114 -Amendment No. 224 
. . . TAJILE a J/4.4.2 mlllISTIT N m.J>a1 *r ea,,.r, -'-
LEU!i !tel 0 to to to ., IO to to 0.01 . IO to to ., IO to to O.OI 21 It 21 17 17 -rt 21 o.os 12
* 41 41 41 41 41 O.CM ,. a " 14 14 " " O.Cll * " " II II *
* O.OI
* u n a a .a a 0.01 n II II 16 .. II .. O.OI 31 II IO IOI lOI lOI IOI o.oe 40 11 N 111 122 122 m 0.10 .. .. " 122 133 131 ISi o.u 41 II 101 130 1'4 HI 1'1 0.12 12 n lOI 111 IU 181 111 o.1s .. " lot lJI Ill 111 lft O.H 11 " lOI IG 111 112 1* 0.11 .. ... 112 148 111 111 -0.11 70
* 111 141 171 l" 211 0.17 11 12 111 111 IN 221 0.11. Tt ti 122 154 117 214 230 0.19 u 100 121 157 111 2IO' 231 O.IO .. 1CN 129 110 UM m 245 0.21 H . IOI 133 IM 11'1 221 212 0.22 11 112 UT 111 -m 211 o.n 101 UT 140 lit 231 0.24 IOI 121 "' 113 2)t 239 -0.25 110 121 HI 111 -243 272 o.:ae 111 uo 111 llO 212 "' 271 0.21 UI lJi& 111 114 211 ,.. .0 0.21 122 ISi 110 111 211 211 ... 0.21 121 142 IN 111 m IN 211 O.JO lJl HI 117 IN 221 217 290 0.11 !JI. 111 172 ltl ** -213 o.n uo 111 171 IOI 2'1 113 291 0.33 1'4 110 llO -De .. 2ff 0.34 141 IN IN 309 m 289 302 0.31 113 1U 111 212 241 272 305 O.JI 111 171 111 219 241 2'71 30I 0.37 1U 177 1te. 230 Ml 211 SU 0.31 lH 112 -m SIO 211 31' 0.39 171 111 -227 ... 211 S17 0.40 171 1n -231 21'1 .. SALIM !Jll IT Z B J/4 4-14. Amendment No. 86 
' . TABLE B 314.4-3 caamr 1.craa raa .... ll'l!AL,
*r W\-1 dck&"ft-1
_!!.. U2 LE L!!2 L.12 0 ID ID ID ID 10 ID JO 0.01 ID ID ID ID ID ID ID ID ID ID 10 ID ID :ao o.m ID 30 ID 10 ID 10 ID 0.04 22
* 21 * *
* 21 O.GI
* 11 11 31 31 31 31 o.oe 21 37 37 31 31 *Sf rt 0.01 31 '3 " "' "' " " O.OI u .. 11 51 11 11 11 0.09 J7 13 II II II II II 0.10 *1 II II II 11 11 11 0.11 12 72 14 77 n .,., 0.12 C9 17 19 13 .. ..
* 0.13 13 71 II 11 .. .. H 0.1' 17 11 11 100 lOI 108 108 . 0.15 11 IO " 110 115 117 117 0.11 u " 104 111 123 121 12! 0.17 H .. 110 127 132 135 13& 0.11 73 12 111 13' 141 14' 14' 0.19 71 t7 130 H2 150 15' 164 0.20 102 HI 158 184 lU 0.21 N 107 121 111 117 172 17* 0.22 91 112 13' 111 171 111 114 0.23 91 117 131 U7 114 190 1M 0.24 100 121 1'3 172 ' 1111 199 304 0.21 104 121 1'8 171 1n
* 214 0.28 lOSI 130 111 llO a 211 zu 0.27 11' 13' 151 114 211 m 230 0.21 111 131 110 11'7 211 333 231 0.21 U4 143 16' 191 221 241 3" ().JO 121 141 117 194 221 249 267 0.31 13' 111 112 lit 221 216 2" o.u Ut 111 171 -231 2IO 27* o.u 14' lto 1IO '&deg;' 2'4 184 212 O.J.4 141 16' 114 '&deg;' 238 2'I 2SIO O.JI 153 111 117 212 241 272 2N 0.38 15& 173 111 211 Ml 276 303 0.31 112 177 JN D> Ml 271 JOI 0.31 lM 112 300 m 2IO 211 313 o.n 111 111 :m 227 2N -317 0.40 175 1n '111 231 217 -no S.U.ZM t7NIT Z B 3/4 4-15 Amendment No. 86 1.0E+20 This Curve Represents the Fluence at the Inner Radlus of the limiting Longitudinal Weld Seam Located the 30&deg; .Azmuth 1.0E+19 N' --E .---Q) /..-0 c: Cl) /' u:: c: /' g ::> ID z I Ftuence at Vessel Inner Radius I 30&deg;Azimuth 1.0E+18 I I I I 1.0E+17 0 5 10 15 20 25 30 35 Service Life (Effective Full Power Years) Figure B 3/4.4-1 Fast neutron fluence (E > 1 MeV) as a function of full power service life (EFPY) SALEM -UNIT 2 B 3/4 4-16 Amendment No. 224 -
rn !i! c z H '""' 1\.1 l.d w --.... i' I ._. " l:> 3 ro ::I Cl. 3 ro ::I .-+ 2 0 (0 O"I 2. J a .. a a ii i ... J .........
.,_ ... >tlleVI Pl uence Pact or for uae in the expression for 4 RTNDT FIGURE 8 3/4.4-1 REACTOR COOLANT SYSTEM BASES 3/4.4.11 DELETED 3/4.4.12 REACTOR VESSEL HEAD VENTS Reactor Coolant System vents are provided to exhaust noncondensible gases and/or steam from the Reactor Coolant System that could inhibit natural circulation core cooling.
The OPERABILITY of a reactor vessel head vent path ensures the capability exists to perform this function.
The valve redundancy of the Reactor Coolant System vent paths serves to minimize the probability of inadvertent or irreversible actuation while ensuring that a single failure vent in a valve power supply or control system does not prevent isolation of the vent path. The function, capabilities, and testing requirements of the Reactor Coolant System Vent Systems are consistent with the requirements of Item 11.B.1 of NUREG.:0737, "Clarification of TMI Action Plant Requirements,"
November 1980. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
SALEM -UNIT 2 B 3/4 4-18 Amendment No.282 (PSEG Issued) 3/4.5 EMERGENCY CORE COOLING SYSTEMS BASES 3/4.5.1 ACCUMULATORS The OPERABILITY of each RCS accumulator ensures that a sufficient volume of borated water will be immediately forced into the reactor core through each of the cold legs in the event the RCS pressure falls below the pressure of the accumulators.
This initial surge of water into the core provides the initial cooling mechanism during large RCS pipe ruptures.
The limits on accumulator volume, boron concentration and pressure ensure that the assumptions used for accumulator injection in* the safety analysis are met. The accumulator power operated isolation valves are considered to be "operating bypasses" in the context of IEEE Std 279-1971, which requires that bypasses of a protective function be removed automatically whenever permissive conditions are not met. In addition, as these accumulator isolation valves fail to meet single failure criteria, removal of power to the valves is required.
The limits for operation with an .accumulator inoperable for any reason except an isolation valve closed minimizes the time exposure of the plant to a LoCA event occurring concurrent with failure of an additional accumulator which may result in unacceptable peak cladding temperatures.
If a closed isolation valve cannot be immediately opened, the full capability of one accumulator is not available and prompt action is required to place the reactor in a mode wpere this capability is not required.
3/4.5.2 and 3/4.5.3 ECCS SUBSYSTEMS The OPERABILITY of two independent ECCS subsystems ensures that sufficient emergency core cooling capability will be available in the event of a LOCA assuming the loss of one subsystem through any single failure Either subsystem operating in conjunction with the accumulators is capable of supplying sufficient core cooling to limit the peak cladding temperatures within acceptable limits for all postulated break sizes ranging from the double ended break of the largest RCS cold leg pipe downward.
In addition, each ECCS subsystem provides long term core cooling capability in the recirculation mode during the accident recovery period. SALEM -UNIT 2 B 3/4 5-1 EMERGENCY CORE COOLING SYSTEMS .ECCS SUBSYSTEMS (Continued)
With the RCS temperature below 350&deg;F, one OPERABLE ECCS subsystem is ac.ceptable without single failure consideration on the basis of the stable re.activity condition of the reactor and the limited core cooling requirements.
The lirtdtation for a *maximum of one safety injection pump or one centrifugal.charging pump to be OPERABLE and the Surveillance requirement to verify a+l safety injection pumps except the allowed OPERABLE safety injection pUmp to be inoperable below 312&deg;F provides assurance that a mass addition pressure transient can be relieved by the operation of a single POPS relief'valve.
When r1.mning a safety injection pump with the RCS temperature less than 312 &deg;F:with tbe potential for injecting into the RCS and creating a mass addition pressure transient, two independent means of preventing reactor coolant system injection will be utilized, The two independent means can .be satisfied by any of the following methods:
"(1) A manual isolation*
valve locked in the closed position; or .(2) Two man1.1al isolation valves closed; or *(3) One motor operated valve closed and its breaker de-energized and control circuit fuses remove.cl; or (4) One air' operated valve closed and air supply maintained in such a manner as t.o ensure that the valve will remain closed. The surveillance r.equirements, which are provided to ensure the OPERABILITY of each component, ensure that, at a minimum, the assumptions used in the safety are met and that subsystem OPERABILITY is maintained.
The safety analyses make the assumptions with respect to: 1) both the maximum and minimum total system resistance, and 2) both the maximum and minimum branch injection line resistance.
These resistances, in conjunction with *the ranges of potential pump performance, are used to calculate
-t;he rnaxlmum and mi.nirnum ECCS flow assumed in the safety analyses.
The maximum and minimum flow surveillance requirements in conjunction with the mqximum and minimum pump performance curves ensures that the _assumptions of total system resistance and the distribution of that system resistance:among the various paths are met. The maximum total pump flow surveillance requirements ensure the pump runout limits of 560 gpm for the centrifugal charging pumps and 675 gpm for the safety'injection pumps are not exceeded.
Due to the effect of pump _s&#xb5;ction boost alignment, the runout limits for the surveillance criteria gpm for C/SI s 664 gpm for SI pumps in cold leg alignment and 654 *gpm for SI.pumps in hot leg alignment.
The surveillance requirement for the maximum difference between the _maximum and minimum individual injection line flows ensure that the minimum i*ndivi.dual:
injection line resistance assumed for the spilling line *following a LOCA is met. LCO 3.0.4.b is not applicable to an inoperable ECCS high head when entering MODE 4. There is an increased risk associated with entering MODE 4 from MODE 5 with an inoperable ECCS high head subsystem.
The provisions of LCO 3.0.4.b, which allow entry into a MODE or other .specified conditfon in the Applicability with the LCO not met after -performance of a risk assessment addressing inoperable systems and components; should not be applied in this circumstance.
SALEM -UNIT 2 B 3/4 5-2 Amendment No. 256 
. . EMERGENCY CORE:coOLING SYSTEMS BASES" .
SEAL iNJECTION FLOW The Reactor Coolant Pump (RCP) seal injection flow restriction limits the amount of ECCS flow that would*be
.diverted from the injection path following an ECCS actuation.
This limit: is based on safety analysis assumptions, since RCP seal inji:iction flow :is not isolated durillg Safety Injection (SI). The LCO is not strictly a flow limit, but rather a flow limit based on a flow line Line pressure and flow must be known to establish the proper line resistance.
Fl;ow line .resistance is determined by assuming that the RCS pressure is at nonnal operating
: pressure, and that the centrifugal charging pump discharge pressure is greater than or equal to 2430 psig. Charging pump header pressure is used instead of .RCS pre.ss&#xb5;re,*
since it is more representative of flow diversion during an accident.
* The additional LCO modifier, charging flow control valve full open,* is required since the valve is designed to fail open. With the LCO specified discharge and control valve position, a flow limit is established.
This flow limit is tj.sed in the accident ana.lysis.
A provision has been added to exempt surveillance requirement
: 4. 0 ,*4 for entry into MODE 3, since the surveillance cannot. be performed in a lower mode. The is permitted for up to 4 hours after the RCS pressure has stabilized within +/- 20 psig of operating pressure.
The RCS pressure requirement produces the conditions to correctly set the manual throttle valves. The exemption is lirnit:ed.
to 4 hQurs to ensure timely surveillance completion once the necessary condi.tions are established;
*.
REFUELING WATER STORAGE TANK The OPERABILITY of the RWST as a part of the ECCS ensures that a sufficient supply*of borated water is available for injection by the ECCS in the event of a LOGA.-* .The limits on RWST minimum volume and boron concentrations ensure "that: (1) water is available within containment to permit recirculation cooling flow to the core, (2) the will remain subcritical in the cold condition following a small LOCA complete mixing of the RWST, RCS, and ECCS water volumes with all*contrcil rods inserted except the most reactive control assembly (ARI-1),
and (3) the* reactor :will* remain subcritical in the cold condition following a large break LOCA,(break area*> 3.0 sq. ft.) assuming complete mixing of the RWST, RCS, and ECCS *water and.other sources *Of water that may eventually reside in the sump
: a.
with alql control rods assumed to be out (ARO). The limits on contained water volume and boron concentration also ensure a pH value of between 7.0 and.
for the solution recirculated within containment after a LOCA. This pH band minimizes the of* iodine and minimizes the effect of chloride and caus.tic stress *corrosipn on mechanical systems and components.
The contained water volume limit includes an*allowance for water not usable because of tank discharge line location or.other physical characteristics.
SALEM -UNIT 2 B 3/4 5-3 Amendment No.258 3/4.6 CONTAINMENT SYSTEMS BASES 3/4.6.1 PRIMARY CONTAINMENT 3/ 4 6 .1. 1 CONTAINMENT I.NTE,GRITY Primary CONTAINMENT INTEGRITY ensures that the release of radioactive materials from the containment atmosphere will be restricted to those leakage paths and associated leak rates assumed in the accident analyses.
This restriction, in conjunction with the leakage rate limitation, will limit the site boundary radiation doses to within the limits of 10 crR 100 during accident conditions.
The purpose of this surveillance requirement (4.6.1.la) is not to perform any testing or valve manipulations, but to verify that containment isolation valves capable of being mispositioned are in their proper safety position (closed).
Physical verification (hands on verification) that these penetrations (containment isolation valves) are in the proper position is performed prior to entering Mode 4 from Mode 5 and documented in the appropriate valve line-up.
Allowing the use of administrative means to verify compliance with the surveillance requirement for these valves is acceptable based on the limited access to these areas in Modes 1, 2, 3, and 4 for ALARA reasons.
Therefore, the probability of misalignment of these containment isolation valves, once they have been verified in the proper position, is small. The service water accumulator vessel and discharge valves functi*on to maintain water filled, subcooled fluid conditions in the containment fan coil unit (CFCU) cooling loops during accident conditions.
The service water accumulator vessel and discharg.e valves were installed to address the Generic Letter 96-06 issues of column separation waterhammer and two phase flow during an accident involving a loss of offsite power. The operability of each service water accumulator vessel and discharge valve is required to ensure the integrity of containment penetrations associated with the containment fan coil units during accident conditions.
If a service water accumulator vessel does not meet the vessel surveillance requirements, or if the discharge valve response time does not meet design acceptance criteria when tested in accordance with procedures, the containment integrity requirements of the CFCU cooling loops exclusively supplied by the inoperable accumulator vessel or discharge valve are not met. Limiting Condition for Operation 3.6.1.1 is applicable, and the cooling loops for the two CFCU's exclusively supplied by the inoperable accumulator are to be removed from service and isolated to maintain containment integrity
.. 3/4 6.1.2 CONTAINMENT LEAKAGE The limitations on containment leakage rates ensure that the total containment leakage volume will not exceed the value assumed in the accident analyses at the peak accident pressure Pa. As an added conservatism, the measured overall integrated leakage rate (Type, A test) is further limited to less than or equal to 0.75 La or less than or equal to 0.75 Lt, as applicable, during performance of the periodic test to account for possible degradation of the containment leakage barriers between leakage tests. The surveillance testing for measuring leakage rates are consistent with the Containment Leakage Rate Testing Program.
3/4.6.1.3 CONTAINMENT AIR LOCKS Containment air locks form part of the containment pressure boundary and provide a means for personnel access during all MODES of operation.
Each air lock is nominally a right circular
: cylinder, 10 feet in . diameter, with a door at each end. The doors are interlocked during normal operation to prevent simultaneous opening.
SALEM -UNIT 2 8 3/4 6-1 Amendment No.208, 3/4.6 CONTAINMENT SYSTEMS BASES During periods when containment is not required to be OPERABLE, the door interlock mechanism may be disabled, allowing both doors of an air lock to remain open for extended periods when frequent containment entry is necessary.
Each air lock door has been designed and tested to certify its ability to withstand a pressure in excess of the maximum expected pressure following a Design Basis Accident (OBA) in containment
*. As such, closure of a single door supports containment OPERABILITY.
Each of the doors contains double gasketed seals and local leakage rate testing capability to ensure pressure integrity.
To effect a leak tight seal, the air lock design uses pressure*seated doors (i.e., an increase in containment internal pressure results in increased sealing force on each door). Each personnel air lock is provided
.with limit switches on both* doors that provide control room indication of door position.
Additionally, control room indication is provided to alert the operator whenever an air lock door interlock mechanism is defeated.
The containment air locks form part of the containment pressure boundary.
As such, air lock integrity and tightness is essential for maintaining the containment leakage rate within limit in the event of a DBA. Not maintaining air lock integrity or leak tightness may result in a leakage rate in excess of that assumed in the unit safety analysis.
The DBAs that result in a release of radioactive material within containment are a loss of coolant accident and a rod ejection accident.
In the analysis of each of these accidents, it is assumed that containment is OPERABLE such that of fission products to the environment is controlled by. the rate of containment leakage.
The containment was designed with an allowable leakage rate of 0.1% of containment air weight per day. This leakage rate is defined in 10Cl1'R50, Appendix J as La = 0.1% of containment air weight per day, the maximum allowable containment leakage rate at the calculated peak containment internal pressure Pa= 47.0 psig following a DBA. The allowable leakage rate forms the basis for the acceptance criteria imposed on the surveillance requirements associated with the air locks. Each containment air lock forms part of the containment pressure boundary.
As part of containment, the air lock safety function is related to control of the containment leakage**rate resulting from a DBA. Thus, each air lock's structural integrity and leak tightness are essential to the successful mitigation of such an event.
* Each air lock is required to be OPERABLE.
For the air lock to be considered
: OeERABLE, the air lock interlock mechanism must be OPERABLE, the air lock must be in compliance with the Type B air lock leakage test, and both air lock doors must be OPERABLE.
The interlock allows only one air lock door of an air lock to be opened at one time. This provision ensures that a gross breach of containment does not exist when containment is required to be OPERABLE.
Closure of a single door in each air lock is sufficient to provide a leak tight barrier following postulated events. Nevertheless, both doors are kept closed when the air lock is not being used for normal entry into and exit from containment.
In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment.
In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the containment air locks are not required in MODE 5 to prevent leakage of radioactive material from containment.
The requirements for the containment air locks during MODE 6 are addressed in LCO 3.9.4, "Containment Building Penetrations"
. SALEM -UNIT 2 B 3/4 6-la Amendment No.209 3/4.6 CONTAINMENT SYSTEMS BASES The ACTIONS are modified by five notes. Note (1) allows entry and .. exit to perform repairs on the.affected air lock compoQent.
If the outer door is inoperable, then it may be easily accessed for. moat repairs.
It is preferred that the air lock be accessed from inside primary containment by entering through the other OPERABLE air lock. However, if this is not practicable, or if repairs on either door must be performed from the barrel side of the door then it is permissible to enter the air lock through the OPERABLE door, which means there is a short time during which the containment boundary is not intact (during access through the OPERABLE door). The ability to open the OPERABLE door, even if it means the containment boundary is temporarily not intact, is acceptable due to the low probability of an event that could pressurize the containment during the short time in which the OPERABLE door isexpected to be open. After each entry and exit, the OPERABLE door must be immediately closed. If ALARA conditions permit, entry and exit should be via an OPERABLE air lock. Note (2) adds clarification that separate condition entry is allowed for each air lock. This is acceptable, since the required ACTIONS provide appropriate compensatory measures for each inoperable air lock. Complying with the Required Actions may allow for continued operation.
A subsequent inoperable air lock is governed by condition entry for that air lock. Notes (3) and (4) ensure that only the required ACTIONS and associated completion times of condition
: c. are required if both doors in the same air lock are inoperable.
With both doors in the same air lock inoperable, an OPERABLE door is not available to be closed. Required ACTIONS c.l and c.2 are the appropriate remedial actions.
The exception of these Notes does not affect tracking the completion time from the initial entry into condition a., only the requirement to comply with the required ACTIONS.
In the event the air lock leakage results in exceeding the overall containment leakage rate, Note (5) directs entry into the applicable Conditions and required ACTIONS of LCO 3.6.1, "Primary Containment".
*with one.air lock door in one or more containment air locks inoperable, the OPERABLE door must be verified closed {ACTION a.l) in each affected containment air lock. This ensures that a leak tight containment barrier is maintained by the use of an OPERABLE air lock door. This ACTION must be completed within l hour. The specified time period is consistent with the ACTIONS of LCO 3.6.1.1 that requires that containment be restored to OPERABLE status within 1 hour. OPERABILITY of the air lock interlock is not required to support the OPERABILITY of an air lock door. In addition, the affected air lock penetration must be isolated by locking closed the OPERABLE air lock door within the 24 hour completion time (ACTION a.2). The 24 hour completion time is reasonable for locking the OPERABLE air lock door, considering the OPERABLE door of the affected air lock is being maintained closed. Required ACTION a.3 verifies that an air lock with an inoperable door has been isolated by the use of a locked and closed OPERABLE air lock door. This ensures that an acceptable containment leakage boundary is maintained.
The completion time of once per 31 days is based on engineering judgement and is considered adequate in view of the low likelihood of a locked door being mispositioned and other administrative controls.
ACTION a.3 allows the use of the air lock for entry and exit for 7 days under administrative controls if both air locks have an inoperable door. This 7-day restriction begins when the second air lock is discovered to be l. inoperable.
SALEM -UNIT 2 B 3/4 6-lb Amendment No.208 3/4.6 CONTAINMENT SYSTEMS BASES Containment entry may be required on a periodic basis to perform Technical Specification Surveillances and required
: ACTIONS, as well as other activities on equipment inside containment that are required by Technical Specifications or activities on equipment that support Technical Specification required equipment.
This Note is not intended to preclude performing other activities (i.e., non-Technical Specification required activities) if the containment is entered, using the inoperable air lock, to perform an allowed entry listed above. This allowance is acceptable due t9 the low probability of an event that could pressurize the containment during the short time that the OPERABLE door is expected to be open. Because of ALARA considerations, ACTION a.3 also allows air lock doors located in high radiation areas to be verified locked closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since acqess to these areas is typically restricted.
Therefore, the probability of misalignment of the door, once it has been verified to be in the proper position, is small. With an air lock interlock mechanism inoperable in one or more air locks, the required ACTIONS and associated completion times are consistent with those specified in Condition
: a. In addition, ACTION b.3 allows entry into and exit from containment under the control of a dedicated individual stationed at the air lock to ensure that only one door is opened at a time (i.e., the individual performs the function of the interlock).
In addition, ACTION b.3 allows air lock doors located in high radiation areas to be verified locked closed by use of administrative means. ACTION c.l requires that with one or more air locks inoperable for reasons other than those described in condition
: a. orb., action must be initiated immediately to evaluate previous combined leakage rates using current air lock test results.
An evaluation is acceptable, since it is-overly conservative to immediately declare the containment inoperable if both doors in an air lock have failed a seal test or if the overall air lock leakage is not within limits. In many instances (e.g., only one seal per door has failed),
containment remains OPERABLE, yet only 1 hour (per LCO 3.6.1.1) would be provided to restore the air lock door to OPERABLE status prior to requiring plant shutdown.
In addition, even with both doors failing the seal test, the overall containment leakage rate can still be within limits. Required ACTION c.2 requires that one door in the affected containment air lock must be verified to be closed within the 1 hour completion time. This specified time period is consistent with the ACTIONS of LCO 3.6.1.1, which requires that containment be restored to OPERABLE status within 1 hour. Additionally, the affected air lock(s) must be restored to OPERABLE status within the 24 hour completion time. This completion time begins at the time that the air lock is discovered to be inoperable.
The specified time period is considered reasonable for restoring an inoperable air lock to OPERABLE status, assuming that at least one door is maintained closed in each affected air lock. If the inoperable containment air lock cannot be restored to OPERABLE status within the required completion time, the plant must be brought to a MODE in which the LCO does not apply. .To achieve this status, the plant must be brought to at least Hot Standby within 6 hours and to Cold Shutdown within the following 30 hours. The allowed completion times are reasonable based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SALEM -UNIT 2 B 3/4 6-lc Amendment No. 208 CONTAINMENT SYSTEMS BASES Maintaining containment airlocks OPERABLE requires compliance with the leakage rate test requirements of 1 OCFR50, Appendix J, as modified by approved exemptions.
This Surveillance Requirement reflects the leakage rate testing requirements with regard to air lock leakage (Type B leakage tests). The acceptance criteria were established during initial air lock and containment OPERABILITY testing.
The periodic testing requirements verify that the air lock leakage.does not exceed the allowed fraction of the overall containment leakage rate. The frequency is required by Appendix J, as modified by approved exemptions.
Thus, the provision of Specification 4.0.2 (which allows frequency extensions) does not apply. The air lock interlock is designed to prevent simultaneous opening of both doors in a single a_ir lock. Since both the inner and outer doors of an air lock are designed to withstand the maximum expected post accident containment
: pressure, closure of either door will support containment OPERABILITY.
Thus, the door interlock feature supports containment OPERABILITY while the air lock is being used for personnel transit in and out of the containment.
Periodic testing of this interlock demonstrates that the interlock will function as designed and that simultaneous opening of the inner and outer doors will not inadvertently occur. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
SALEM -UNIT 2 B 3/4 6-1d Amendment No. 282 (PSEG Issued) 
 
SYSTEMS BASES 3/4.6.1.4 INTERNAL PRESSURE The limitations on containment internal pressure ensure that: 1) the containme&#xb5;t structure is prevented from exceeding its design negative pressure differential with respect to the outside atmosphere of 3.5 psig, and 2) the containment peak pressure does not exceed the design pressure of 47 psig during the limiting pipe break conditions.
The pipe breaks considered are LOCA and steam line breaks. The limit of 0.3 psig for initial positive containment pressure is consistent with the accident analyses initial conditions.
The maximum peak pressure expected to be obtained from a LOCA or steam line break event is 47 psig. 3/4.6.1.5 AIR TEMPERATURE The limitations on containment average air temperature ensure that the overall containment average air temperature does not exceed the initial temperature condition assumed in the accident analysis for a LOCA or steam line break. In order to determine the containment average air temperature, an average is calculated using measurements taken at locations within containment selected to provide a representative sample of the overall containment atmosphere, 3/4,6.1.6 CONTAINMENT STRUCTURAL INTEGRITY This limitation ensures that the structural integrity of the containment will be maintained comparable to the original design standards for the life of the facility.
Structural integrity is required to ensure that the containment will withstand the design pressure.
The visual inspections of the concrete and liner and the Type A leakage test, both in accordance with the Containment Leakage Rate Testing Program, are sufficient to demonstrate this capability.
:(Note that the elements of 3/4*.6.1.7 were RELOCATED to 3/4 6.3 by LCR 506-06) SALEM -UNIT 2 B 3/4 6-2 Amendment No.260 (PSEG Issued)
CONTAINMENT SYSTEMS BASES 3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS 3/4.6.2.1 CONTAINMENT SPRAY SYSTEM The OPERABILITY of the containment spray system, when operated in conjunction with the Containment Cooling System, ensures that containment depressurization and cooling capability will be available in the event of a LQCA. The pressure reduction and resultant lower containment leakage rate are consistent with the assumptions used in the accident analyses.
The containment spray system also provides a mechanism for removing iodine from the containment atmosphere and therefore the time requirements for restoring an inoperable spray system to OPERABLE status have been maintained consistent with that assigned other inoperable ESF equipment.
Normal plant operation and maintenance practices are not expected to trigger surveillance requirement 4.6.2.1.d.
Only*an unanticipated
.circumstance would initiate this surveiiiance, such as inadvertent spray actuation, a major configuration change, or a loss of foreign material control when working within the affected boundary of the system. If an activity occurred that presents the potential of creating nozzle blockage, an evaluation would be performed by the engineering organization to determine if the amount of nozzle blockage would impact the required design capabilities of the containment spray system. If the evaluation determines that the containment spray system would continue to perform its design basis function, then performance of the air or smoke flow test would not be required.
If the evaluation cannot conclusively determine the impact to the containment spray system, then the air or smoke flow test would be performed to determine if any nozzle blockage has occurred. 3 / 4. 6
* 2 *. 2 SPRAY ADDITIVE SYSTEM The OPERABILITY of the spray additive system ensures that sufficient NaOH is added to the containment spray in the event of a LOCA. The limits on NaOH volume and concentration, ensure that 1) the iodine removal efficiency of the spray water is maintained because of the increase in pH value, and 2) corrosion effects on components within containment are minimized.
The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other physical characteristics.
These assumptions are consistent with the iodine removal efficiency assumed in the accident analyses.
3/4.6.2.3 CONTAINMENT COOLING SYSTEM The OPERABILITY of the containment cooling system ensures that adequate heat removal capacity is available when operated in conjunction with the containment spray systems during conditions.
The surveillance requirements for the service water accumulator vessels ensure each tank contains sufficient water and nitrogen to maintain water filled, subcooled fluid conditions in three containment fan coil unit (CFCU) cooling loops in.response to a loss of offsite power, without injeqting nitrogen covergas into the containment fan coil unit loops assuming the most limiting single failure.
The surveillance requirement for the discharge valve response time test ensures that on a loss of offsite power, each discharge valve actuates to the open position in accordance with the design to allow sufficient tank discharge into CFCU piping to maintain water filled, subcooled fluid conditions in three CFCU cooling loops, assuming the most limiting single failure.
SALEM -UNIT 2 B 3/4 6-3 Amendment No. 270 (PSEG Issued)
CONTAINMENT SYSTEMS BASES The surveillance requirements for the CFCUs ensure sufficient SWS flow through each operating cooler to provide the minimum containment cooling as assumed by the containment response analysis for a design-basis LOCA or MSLB event. The surveillance flow rate is selected to ensure adequate heat removal (with no phase flow) . The specified surveillance flow rate represents the total flow from both the CFCU coils and the CFCU motor-cooler 3/4.6.3 CONTAINMENT VALVES The OPERABILITY of the 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.
Containment isolation within the time limits specified ensures that the release of radioactive*material to the environment will be consistent with the assumptions used in the analyses for a LOCA. The opening of locked or sealed closed containment isolation valves (penetration flow paths) on an intermittent basis under administrative control includes the following considerations:
(1) stationing a dedicated individual, who is in constant communication with the control room, at the valve controls, (2) instructing this individual to close these valves in an accident situation, and (3) assuring that the environmental conditions will not preclude access to close the valves and that this action will prevent the release of :radioactivity outside the containment.
* The main steam isolation valves {MSIVs) fulfill their containment isolation function as containment isolation valves. The automatic closure of the MSIVs is not required far containment isolation due to having a closed system inside containment.
The remote-manual containment isolation function of the MSIVs can be accomplished through either the use of the hydraulic operator or when the MSIV has been. tested in accordanc_e with surveillance requirement
: 4. 7 .1. 5 the steam assist closure function can be credited.
Surveillance Requirement (SR) 4.6.3.3 only applies to the MS7 {Main Steam Drain) valves and the MS18 (Main Steam Bypass) valves. The MS167 (Main Steam Isolation) valves are tested for main steam isolation purposes by SR 4.7.1.5.
For containment isolation
: purposes, the MS167s are tested as remote/manual valves pursuant to Specification 4.0.5. 3 / 4 . 6 . 4 COMBUSTIBLE GAS CONTROL The OPERABILITY of the equipment and systems required for the detection and control of hydrogen gas ensures that this equipment will be available to maintain the hydrogen concentration within containment below its flammable limit during past-LOCA conditions.
Either recombiner unit is capable of controlling the expected hydrogen generation associated with l) zirconium-water reactions,
: 2) radiolytic decomposition of water, and 3) corrosion of metals within containment.
These hydrogen control systems are consistent with the recommendations of Regulatory Guide 1.7, "Control of Combustible Gas Concentrations in Containment Following a LOCA,11 March 1971. SALEM -UNIT 2 B 3/4 6-4 Amendment No. 270 (PSEG Issued)
CONTAINMENT SYSTEMS BASES containment purge supply and exhaust penetrations performs no containment integrity function in MODES 1-4; these valves operate during shutdown for normal system purging and containment closure when the blind flanges are removed.
SALEM -UNIT 2 B 3/4 6-5 Amendment No. S200B-OB4 (PSEG Issued) 3/4. 7 PLANT SYSTEMS BASES 3/4.7.1 TURBINE CYCLE 3/4. 7 .1.1 SAFETY VALVES The OPERABILITY of the main steam line code safety valves ensures that the secondary system pressure will be limited to within 110% of its design pressure of 1 085 psig during the most severe anticipated system operational transient.
The MSSVs also provide protection against overpressurization of the Reactor Coolant Pressure Boundary by providing a heat sink for the removal of energy from the Reactor Coolant System if the preferred heat sink is not available.
The maximum relieving capacity is associated with a turbine trip from 100% RATED THERMAL POWER coincident with an assumed loss of condenser heat sink (i.e., no steam bypass to the condenser).
The specified valve lift settings and relieving capacities are in accordance with the requirements of Section 111 of the ASME Boiler and Pressure Code, 1971 Edition.
The total relieving capacity for all valves on all of the steam lines is 16.66 x 106 lbs/hr which is approximately 110% of the maximum calculated steam flow of 15.12 x 106 lbs/hr at 100% RATED THERMAL POWER. A minimum of 2 OPERABLE safety valves per OPERABLE steam generator ensures that sufficient relieving capacity is available for the allowable THERMAL POWER restriction in Table 3.7-1. STARTUP and/or POWER OPERATION is allowable with inoperable safety valves within the limitations of the ACTION requirements on the basis of the reduction in secondary steam flow associated with the required reduction of RATED THERMAL POWER. The acceptable power level (in percent RATED THERMAL POWER) for operation with inoperable safety valves was determined by performing explicit transient analysis.
The events that challenge the relief capacity of the safety valves are those resulting in decreased heat removal capability.
In this category of events, a loss of external electrical load and/or turbine trip is the limiting anticipated operational occurrence.
A series of cases was analyzed for this transient covering up to two inoperable safety valves on each steam generator.
The results of these cases were used to determine a maximum thermal power level from which the event could be initiated without exceeding the primary and secondary side design pressure limits. Thus, the maximum allowed power level as a function of the number of inoperable MSSVs on any steam generator is presented in Table 3.7-1. Note that the power level values presented on this table are the direct inputs into the transient analysis cases and do not include any allowance for calorimetric error. Actual power level reductions must include calorimetric uncertainty and other allowances for operating margin as deemed necessary.
Specific accident analyses for RCCA Bank Withdrawal at Power scenarios demonstrate that adequate safety valve relief capacity exist with up to two inoperable safety relief valves on each steam generator.
These cases demonstrate that the reactor trip on OTDT along with the relief from the available main steam safety valves is sufficient to meet secondary side pressurization limits. SALEM -UNIT 2 B 3/4 7-1 Amendment No. 259 (PSEG Issued}
PLANT SYSTEMS BASES For three inoperable main steam safety valves in one or more steam generators, thermal reactor power must be reduced in conjunction with a reduction in the Power Range Neutron Flux High trip setpoint to prevent overpressurization of the main steam system. The t.ransient analysis assumes that the MSSVs will start to open at the lift setpoint with 3% allowance for setpoint tolerance.
In addition, the analysis accounts for accumulation by including a 5 psi ramp for the valve to reach its fully open position.
Inoperable MSSVs are assumed to be those with the lowest lift setting.
Surveillance testing as covered in Table 3.7-4
* allows a +/- 3% lift setpoint tolerance.
: However, to allow for drift during subsequent operation, the valves must be reset to within+/- 1 % of the lift setpoint following testing.
3/4.7.1.2 AUXILIARY FEEDWATER SYSTEM The OPERABILITY of the auxiliary feedwater system ensures that the Reactor Coolant System can be cooled down to less than 350&deg;F from normal operating conditions in the event of a total loss of offsite power. Verifying that each Auxiliary Feedwater (AFW) pump's developed head at the flow test point is greater than or equal to the required minimum developed head ensures that the AFW pump performance has not degraded during the cycle, and that the assumption made in the accident
* analysis remain valid. Flow and differential head are normal tests of centrifugal pump performance required by Section XI of the ASME Code. Because it is undesirable to introduce
. cold AFW into the steam generators while operating, the test is performed on recirculation flow. This test confirms one point on the pump design curve {head vs flow curve), and is indicative of pump performance.
lnservice testing confirms pump operability, trends performance and detects incipient failures by indication of pump performance.
The flow path to each steam generator is ensured by maintaining all manual maintenance valves locked open. A spool piece consisting.
of a length of pipe may be used as an equivalent to a locked open manual valve. The manual valves in the flow path are: 2AF1, 21AF3,22AF3,23AF3,21AF10,22AF10,23AF10,24AF10,21AF20,22AF20,23AF20, 24AF20, 21AF22, 22AF22, 23AF22, 24AF22, 21AF86, 22AF86, 23AF86, and 24AF86. LCO 3.0.4.b is not applicable to an inoperable AFW train. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an AFW train inoperable.
The provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
3/4.7.1.3 AUXILIARY FEED STORAGE TANK The OPERABILITY of the auxiliary feed storage tank with the minimum water volume ensures that sufficient water is. available to maintain the RCS at HOT STANDBY conditions for 8 hours with steam discharge to the atmosphere concurrent with total loss of offsite power. The contained water volume limit includes an allowance for water not usable because of tank discharge line location or other physical characteristics.
SALEM -UNIT 2 B 3/4 7-2 Amendment No. 258 PLANT SYSTEMS BASES 314. 7 .1.4 ACTIVITY The limitations on secondary system specific activity ensure that the resultant offsite radiation dose will be limited to a small fraction of 10 CFR Part 100 limits in the event of a steam line rupture.
This dose also includes the effects of a coincident 1.0 GPM primary to secondary tube leak in the steam generator of the affected steam line. These values are consistent with the assumptions used in the accident analyses.
* 3/4.7.1.5 MAIN STEAM LINE ISOLATION VALVES The OPERABILITY of the main steam line isolation valves ensures that no more than one steam generator will blowdown in the event of a steam line rupture.
This restriction is required to 1) minimize the positive reactivity effects of the Reactor Coolant System cooldown associated with the blowdown, and 2) limit the pressure rise within containment in the event the main steam line rupture occurs within containment.
The OPERABILITY of the main steam isolation valves within the closure times of the surveillance requirements are consistent with the assumptions used in the accident analyses.
If the closure time of the main steam isolation valve (MSIV) during technical specification surveillance testing (performed at a Steam Generator pressure between 800 psig and 1015 psig) is 5.0 seconds or less and the engineered safety feature response time {including valve closure time) for the steam line isolation
{MSI) signal {Table 3.3-5) is 5.5 seconds or less, then assurance is provided that MSI occurs within 12 seconds under accident conditions, where Steam Generator pressure may be lower. This method of testing assures that for main steam line ruptures that are initiated from Modes 1.-3 conditions that generate a MSI signal via automatic or manual initiation and have adequate steam line pressure to close, the main steam lines isolate within the time required by the accident analysis.
Fast closure of the MS IVs is assured at a minimum steam pressure of 170 psia. However, the MSIV will still close via the steam assist function between 118 -170 psia with slightly greater closure times. For main steam line ruptures that receive an automatic or manual signal for MSI and do not have adequate steam pressure to close the MSIVs {less than 118 psia), the event does not require MSIV closure to provide protection to satisfy design basis requirements
{e.g., minimum DNBR remains above the minimum DNBR limit value and peak containment*pressure remains below 47 psig). Testing for SR 4.7.1.5 is performed prior to opening the MSIVs for power operation.
During testing, only one valve is opened at a time, with the other three valves remaining closed in the safe position, ensuring isolation capability is maintained.
In the event of a steam line rupture, a postulated failure of the tested valve in the open position would result in the blowdown of a single steam generator since the remaining three MSIVs are closed. Failure of a single MSIV to close is consistent with the accident analysis assumptions for a major secondary system pipe rupture {UFSAR Section 15.4.2).
SALEM -UNIT 2 B 3/4 7-3 Revised by letter dated 6-19-2003 PLANT SYSTEMS BASES 3/4.7.2 STEAM GENERATOR PRESSURE/TEMPERATURE LIMITATION The limitation on steam generator pressure and temperature ensures that the pressure induced stresses in the steam generators do not exceed the maximum allowable fracture toughness stress limits. The limitations of 70&deg;F and 200. psig are based on average steam generator impact values taken at 10&deg;F and are sufficient to prevent brittle fracture.
3/4.7.3 COMPONENT COOLING WATER SYSTEM The OPERABILITY of the component cooling water system ensures sufficient cooling capacity is available for continued operation of safety-related equipment during normal and accident conditions.
The component cooling water system (CCW) consists of two safeguards mechanical trains supplied by three pumps powered from separate vital buses. This complement of equipment assures adequate redundancy in the event of a single active component failure during the injection phase. Operability of the CCW system exists when both mechanical trains and all three CCW pumps are pperable.
3/4.7.4 SERVICE WATER SYSTEM The OPERABILITY of the service water system ensures that sufficient cooling capacity is available for continued operation of safety-related equipment during normal and accident conditions.
The redundant cooling capacity of this system, assuming a single failure, is consistent with the assumptions used in the accident conditions within limits. SALEM -UNIT 2 B 3/4 7-4 March 7, 1997 PLANT SYSTEMS BASES 3/4.7.5 FLOOD PROTECTION The limitation on flood protection ensures that facility protective actions will be taken and operation will be terminated in the event of flood conditions.
The limit of elevation 10.5' Mean Sea Level is based on the elevation abov.e which facility flood control measures are required to provide protection to safety-related equipment.
3/4.7.6 CONTROL ROOM EMERGENCY AIR CONDITIONING SYSTEM BACKGROUND:
The control room emergency air conditioning system (CREACS) provides a protected environment from which occupants can control the unit following an uncontrolled release of radioactivity, hazardous chemicals, or smoke.
* The OPERABILITY of the CREACS ensures that 1) the ambient air temperature does not exceed the allowable temperature for continuous duty rating for the equipment and instrumentation cooled by this system and 2) the control room will remain habitable for operations personnel during and following all credible accident conditions.
The CREACS consists of two independent, redundant trains, one from each unit that circulate and filter the air in the Control Room Envelope (CRE) and a CRE boundary that limits inleakage of unfiltered air. Each CREACS train consists of a prefilter, a high efficiency
'particulate air (HEPA) filter, an activated charcoal adsorber section for removal of gaseous activity (principally iodines),
and fans. Ductwork, valves or dampers, doors, barriers, and instrumentation also form part of the system. The CREACS is a shared system between Unit 1 and 2 supplying a common CRE. During emergency operation following receipt of a Safety Injection or High Radiation actuation signal, for areas inside the CRE, one 100% capacity fan in each Unit's CREACS will operate in a pressurization mode with a constant amount of outside air supplied for continued CRE pressurization.
One fan from each train will automatically start upon receipt of an initiation signal, with one fan in each train in standby.
A failure of one fan will result in the standby fan automatically starting.
Each CREACS train has two 100% capacity fans, such that any one of the four fans is sized to provide the required flow for CRE pressurization within the common CRE during an emergency.
A failure of one CREACS filtration train requires manual actions to properly reposition dampers in support of single filtration train operation.
To minimize control room radiological doses, the CREACS outside air is supplied from the non-accident unit's emergency air intake through the cross-connected supply duct (as determined by which unit received an accident signal).
Outside air is mixed with recirculated air, passed through each CREACS filter bank (pre-filter, HEPA filter, and charcoal adsorber) and cooling coil, and distributed to the common CRE. The CREACS is designed to maintain a habitable environment in the CRE for 30 days of continuous occupancy after a Design Basis Accident (DBA) without exceeding 5 Rem total effective dose equivalent (TEDE). SALEM -UNIT 2 B 3/4 7-5 Amendment No. 269 (PSEG Issued)
PLANT SYSTEMS BASES The CREACS is an emergency system, parts of which may also operate during normal unit operations in the standby mode of operation.
Upon receipt of the actuating signal(s),
normal air supply to the CRE is isolated, and the stream of ventilation air is recirculated through the system filter trains. The prefilters remove any large particles in the air to prevent excessive loading of the HEPA filters and charcoal adsorbers.
Pressurization of the CRE minimizes infiltration of unfiltered air through the CRE boundary from all the surrounding areas adjacent to the CRE boundary.
CREACS will be manually initiated in the recirculation mode only in the event of a fire outside the CRE, a toxic chemical
: release, or testing.
The CRE is the area within the confines of the CRE boundary that contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions.
This area encompasses the control room and other non-critical areas to which frequent personnel access or continuous occupancy is not necessary in the event of an accident.
The CRE is protected during normal operation, natural events, and accident conditions.
The CRE boundary is the combination of walls, floor, roof, ducting, doors, penetrations and equipment that physically form the CRE. The OPERABILITY of the CRE boundary must be maintained to ensure that the inleakage of unfiltered air into-the CRE will not exceed the inleakage assumed in the licensing basis analysis of design basis accident (OBA) consequences to CRE occupants.
The CRE and its boundary are defined in the Control Room Envelope Habitability Program.
APPLICABLE SAFETY ANALYSES The CREACS components are arranged in redundant, safety related ventilation trains. The location of components and ducting within the CRE ensures an adequate supply of filtered air to all areas requiring access. The CREACS provides airborne radiological protection for the* CRE occupants, as demonstrated by the CRE occupant dose analyses for the most limiting design basis accident, fission product release presented in the UFSAR, Chapter 15. The CREACS provides protection from smoke and hazardous chemicals to the CRE occupants.
The analysis of hazardous chemical releases demonstrates that the toxicity limits are not exceeded in the CRE following a hazardous chemical
: release, as described in UFSAR, Section 6.4. The evaluation of a smoke challenge demonstrates that it will not result in the inability of the CRE occupants to control the reactor either from the control room or from the remote shutdown panels, as described in UFSAR, Section 9.5. SALEM -UNIT 2 B 3/4 7-5a TSBC 82011-238 PLANT SYSTEMS BASES LCO Two independent and redundant CREACS trains are required to be OPERABLE to ensure that at least one is available if a single active failure disables the other train. Total system failure, such as from a loss of all ventilation trains or from an inoperable CRE boundary could result in exceeding a dose of 5 rem TEDE to the CRE occupants in the event of a large radioactive release.
In order for the CREACS trains to be considered
: OPERABLE, the CRE boundary must be maintained such that the CRE occupant dose from a large radioactive release does not exceed the calculated dose in the licensing basis consequence analyses for DBAs, and that occupants are protected from hazardous chemicals and smoke. The LCO is modified by a Note allowing the CRE boundary to be opened intermittently under administrative controls.
This Note only applies to openings in the CRE boundary that can be rapidly restored to the design condition, such as doors, hatches, floor plugs, and access panels. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings, these controls are proceduralized and consist of stationing a dedicated individual at the opening who is in continuous communication with the operators in the CRE. This individual will have a method to rapidly close the opening and to restore the CRE boundary to a condition equivalent to the design condition, when a need for CRE isolation is indicated.
A significant contributor to this system's OPERABILITY are the dampers, which are required to actuate to their correct positions.
The following dampers are associated with the respective LCO*: a.1 Fan outlet dampers:
1(2)CAA15 and 1(2)CAA16 These dampers ensure that the flow path for CREACS is operable and are required to open upon CREACS initiation.
The associated fan outlet damper will open on fan operation.
a.4 Return air isolation damper: 1(2)CAA17 When aligned for single train operation, the associated air return isolation damper will be administratively controlled in the open position.
: b. Other dampers required for automatic operation in the pressurization or recirculation modes: Control Area Air Conditioning System (CAACS) outside air intake isolation dampers:
1 (2)CAA40, 1 (2)CAA41, 1 (2)CAA43 and 1 (2)CAA45 The normally open outside air intake dampers 1 (2)CAA40 and inlet plenum isolation dampers 1 (2)CAA43 will be closed under emergency conditions.
The normally closed outside air intake dampers 1 (2)CAA41 and inlet plenum isolation dampers 1 (2)CAA45 are normally closed and remain closed under emergency conditions.
* Operability of the CREACS requires that each of the Unit 1 dampers are also operable SALEM -UNIT 2 B 3/4 7-5b Amendment No. 269 (PSEG Issued)
PLANT SYSTEMS BASES Control Area Air Conditioning System (CAACS) exhaust isolation dampers:
1(2)CAA18 and 1(2)CAA19.
These dampers are normally closed and are required to remain .closed to prevent inleakage from the outside environment in the event of a toxic release.
Control Room Emergency Air Conditioning System (CREACS) air intake dampers:
1(2)CAA48, 1(2)CAA49, 1(2)CAA50 and 1(2)CAA51 CREACS outside air intake dampers are maintained closed during normal and recirculation operation and are opened automatically upon initiation of CREACS pressurization.
The control logic will automatically open the CREACS air intake dampers farthest from the radiation source based upon which Unit's Solid State Protection System (SSPS) or Radiation Monitoring System (RMS) signal is received.
CAACS and CREACS interface isolation dampers:
1(2)CAA14 and 1 (2)CAA20 These two dampers are normally open and do not have associated redundant dampers.
These dampers serve a boundary function by isolating th.e CREACS from the CAACS during emergency operation of the CREACS.
* Note: Dampers 1 (2)CAA5, CAACS recirculation damper will receive an accident alignment signal to ensure proper accident configuration of CAACS. This damper, however, is not required for the OPERABILITY of CREACS as defined in the LCO. APPLICABILITY In all MODES and during movement of irradiated fuel assemblies, the CREACS must be OPERABLE to ensure that the CRE will remain habitable during and following a OBA. During movement of irradiated fuel assemblies, the CREACS must be OPERABLE to cope with the release from a fuel handling
: accident, involving handling irradiated fuel. SALEM -UNIT 2 B 3/4 7-Sc Amendment No. 269 (PSEG Issued)
PLANT SYSTEMS BASES ACTIONS When one CREACS train is inoperable, for reasons other than an inoperable CRE boundary, action must be taken to align CREACS for single filtration train operation within 4 hours, and restore the inoperable filtration train to OPERABLE status within 30 days. Single filtration train alignment is only permitted if the Unit with the operable CREACS train is also in Chilled Water LCO 3.7.10.a*configuration
.. Single filtration train alignment is not permitted if in the LCO 3.7.10.c configuration.
This ensures required cooling coil heat removal capacity is available.
In this Condition, the remaining OPERABLE CREACS train is adequate to perform the CRE occupant protection function.
With CREACS aligned for single filtration train operation and with one of the two remaining fans or associated outlet damper inoperable, restore the inoperable fan or damper to OPERABLE status within 72 hours. However, the overall reliability is reduced because a failure in the OPERABLE CREACS train could result in loss of CREACS function.
The 72 hours completion time is based on the low probability of a OBA occurring during this time period, and ability of the remaining train components to provide the required capability.
If the unfiltered inleakage of potentially contaminated air past the CRE boundary and into the CRE can result in CRE occupant radiological dose greater than the calculated dose of the licensing basis analyses of OBA consequences (allowed to be up to 5 remTEDE),
or inadequate protection of CRE occupants from hazardous chemicals or smoke, the CRE boundary is inoperable.
Actions must be taken to restore an OPERABLE CRE boundary within 90 days. During the period that the CRE boundary is considered inoperable, action must be initiated to implement mitigating actions to lessen the effect on CRE occupants from the potential hazards of a radiological or chemical event or a challenge from smoke. Actions must be taken within 24 hours to verify that in the event of a OBA, the mitigating actions will ensure that CRE occupant radiological exposures will not exceed the calculated dose of the licensing basis analyses of OBA consequences, and that CRE occupants are protected from hazardous chemicals and smoke. These mitigating_
actions (i.e., actions that are taken to offset the consequences of the inoperable CRE boundary) should be preplanned for implementation upon entry into the condition, regardless of whether entry is intentional or unintentional.
The 24-hour completion time is reasonable based on the low probability of a OBA occurring during this time period, and the use of mitigating actions.
The 90 day completion time is reasonable based on the determination that the mitigating actions will ensure protection of CRE occupants within analyzed limits while limiting the probability that CRE occupants will have to implement protective measures that may adversely affect their ability to control the reactor and maintain it in a safe shutdown condition in the event of a OBA. In addition, the 90 day completion time is a reasonable time to diagnose, plan and possibly repair, and test most problems with the CRE boundary.
In MODE 1, 2, 3, or 4, if the inoperable CREACS train or the CRE boundary cannot be restored to OPERABLE status within the required completion time, the unit must be placed in a MODE that minimizes accident risk. Jo achieve this status, the unit must be placed in at least MODE 3 within 6 hours, and in MObE 5 within the following 30 The allowed completion times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
SALEM -UNIT 2 B 3/4 7-5d Amendment No. 297 (PSEG Issued)
PLANT SYSTEMS BASES In MODE 5 or 6, or during movement of irradiated fuel assemblies, if the inoperable CREACS train cannot be restored to OPERABLE status, align CREACS for single filtration train operation within 4 hours, or suspend movement of irradiated fuel assemblies.
With CREACS aligned for single filtration train operation with one of the two remaining fans or associated outlet damper inoperable, restore the fan or damper to OPERABLE status within 72 hours. The 72 hours completion time is based on the ability of the remaining train components to provide the required capability.
* In MODE 5 or 6, or during the movement of irradiated fuel assemblies, with two CREACS trains _inoperable or with one or more CREACS trains inoperable due to an inoperable CRE boundary, action must be taken immediately to-suspend activities that could result in a release of radioactivity that might require isolation of the CRE. This places the unit in a condition that minimizes the accident risk. This does not preclude the movement of fuel to a safe position.
Immediate action(s),
in accordance with the LCO Action Statements, means that the required action should be pursued without delay and in a controlled manner. SURVEILLANCE REQUIREMENTS Standby systems should be checked periodically to ensure that they function properly.
TS Surveillance Requirement verifies that each fan is capable of operating for at least 15 minutes by initiating flow through the HEPA filter and charcoal adsorbers train(s) to ensure that the system is available in a standby mode. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Filter testing verifies that the required CREACS testing is performed in accordance with the surveillance requirements.
The surveillance requirements include testing the performance of the HEPA filter, charcoal adsorber efficiency, minimum flow rate, and the physical properties of the activated charcoal.
Specific test Frequencies and additional information are discussed in detail in the surveillance requirements.
Filter testing will be in accordance with the applicable sections of ANSI N510 (1975) with the exception that laboratory testing of activated carbon will be in accordance with ASTM D3803 (1989). The acceptance criteria for the laboratory testing of the carbon adsorber is determined by applying a minimum safety factor of 2 to the charcoal adsorber removal efficiency credited in the design basis dose analysis as specified in Generic Letter 99-02. Actuation testing verifies that each CREACS train starts and operates on an actual or simulated actuation signal. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the S1..1rveillance Frequency Control Program.
SALEM -UNIT 2 B 3/4 7-5e Amendment No. 282 (PSEG Issued)
PLANT SYSTEMS BASES The control room envelope is considered intact and able to support operation of the CREACS when the emergency air conditioning system is capable of maintaining positive pressure with the control room boundary door(s) closed. Unfiltered air inleakage testing verifies the OPERABILITY of the CRE boundary by testing for unfiltered air inleakage past the CRE boundary and into the CRE. The details of the testing are specified in the Control Room Envelope Habitability Program.
Each CAACS normal air intake ductwork has two radiation detector channels.
The two detector channels from Unit 1 and Unit 2 CAACS air intake provide input to common radiation monitor processors.
Each radiation monitor processor (one for 1 R1 B-1/1 R1 B-2 and one for 2R1B-1/2R1B-2) provides a signal to initiate CREACS in the pressurization mode should high radiation be detected.
A minimum of one out of two detectors in either intake will initiate the pressurization mode. With two oetector channels inoperable on a Unit, operation may continue as long as CREACS is placed in-service in the pressurization or recirculation mode. Pressurization mode will be initiated after 7 days with one inoperable detector.
Radiological releases during a fuel handling accident while operating in the recirculation mode could result in unacceptable radiation levels in the CRE since the automatic initiation capability has been defeated for high radiation due to isolation of the detectors.
Therefore, movement of irradiated fuel assemblies or Core Alterations at either Unit will not be permitted when in the recirculation mode. The CRE is considered habitable when the radiological dose to CRE occupants calculated in the licensing basis analyses of OBA consequences is no more than 5 rem TEDE and the CRE occupants are protected from hazardous chemicals and smoke. The testing verifies that the unfiltered air inleakage into the CRE is no greater than the flow rate assumed in the licensing basis analyses of OBA consequences.
When unfiltered air inleakage is greater than the assumed flow rate, CRE boundary is inoperable.
Required action allows time to restore the CRE boundary to OPERABLE status provided mitigating actions can ensure that the CRE remains within the licensing basis habitability limits for the occupants following an accident.
Compensatory measures are discussed in Regulatory Guide 1.196, Section C.2. 7 .3, which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F. These compensatory measures may also be used as required mitigating actions.
Options for restoring the CRE boundary to OPERABLE status include changing the licensing basis OBA consequence
: analysis, repairing the CRE boundary, or a combination of these actions.
Depending upon the nature of the problem and the corrective action, a full scope inleakage test may not be necessary to estc;iblish that the CRE boundary has been restored to OPERABLE status. SALEM -UNIT 2 B 3/4 7-5f Amendment No. 269 (PSEG Issued)
PLANT SYSTEMS BASES 3/4.7.7 AUXILIARY BUILDING EXHAUST AIR FILTRATION SYSTEM The Auxiliary Building Ventilation System (ABVS) consists of two major subsystems.
They are designed to control Auxiliary Building temperature during normal and emergency modes of operation, and to contain Auxiliary Building airborne contamination (by maintaining slightly negative pressure) during Loss of Coolant Accidents (LOCA); The two subsystems are: 1. A once through filtration exhaust system, designed to contain particulate and gaseous contamination and prevent it from being released from the building in accordance with 1 OCFR20, and 2. A once through air supply system, designed to deliver outside air into the building to maintain building temperatures within acceptable limits. For the purposes of satisfying the Technical Specification LCO, one supply fan must be administratively removed from service such that the fan will not auto-start on an actuation signal; however, the supply fan must be OPERABLE with the exception of this administrative control.
These systems operate during normal and emergency plant modes. Additionally, the system provides a flow path for containment purge supply and exhaust 'during Modes 5 and 6. Either the Containment Purge system or the Auxiliary Building Ventilation System with suction from the containment atmosphere, with associated radiation monitoring will be available whenever movement of irradiated fuel is in progress in the containment building and the equipment hatch is open. If for any reason, this ventilation requirement can not be met, movement of fuel assemblies within the containment building shal! be discontinued until the flow path(s) can be reestablished or close the equipment hatch and personnel airlocks.
Appropriate filtration surveillances are contained in the Updated Final Safety Analysis Report (UFSAR) Section 9.4.2.4, Test and Inspections.
Auxiliary Building exhaust air filtration system functionality is not required to meet LCO 3.7.7. The ventilation exhaust consists of three 50% capacity fans that are powered from vital buses. The fans are designed for continuous operation, to control the Auxiliary Building pressure at -0.1 O" Water Gauge with respect to atmosphere.
* The ventilation supply consists of two 100% capacity fans that are powered from vital buses, and distribute outdoor air to the general areas and corridors of the building through associated ductwork.
SALEM -UNIT 2 B 3/4 7-5g TSBC SCN 06-015 PLANT SYSTEMS BASES 314.7.7 AUXILIARY BUILDING EXHAUST AIR FILTRATION SYSTEM (cont'd)
AUXILIARY BUILDING VENTILATION ALIGNMENT MATRIX NORMAL VENTILATION (Normal plant operations)*
Any two of the three exhaust fans and either of the two supply fans:
* The normal alignment is two exhaust fans and one supply fan. During cooler seasons, and with the absence of the system heating coils, it may be required to limit the amount of colder outside air entering the building.
In this case, it is acceptable to secure both supply fans from operation and reduce the number of operating exhaust fans to one. There is sufficient capacity with the single exhaust fan to maintain the negative pressure within the auxiliary building boundary.
EMERGENCY VENTILATION (Emergency plant operation)
At least two of the three exhaust fans and either one of the two supply fans. Note: During a Safety Injection (SI) all three exhaust fans and one of the supply fans will start. This is acceptable and will maintain the boundary pressure while supplying the required cooling to the building.
Should access/egress become difficult with the three exhaust fans running, one of the exhaust fans should be secured.
OPERABILITY of the Auxiliary Building Ventilation System ensures that air, which may contain radioactive materials leaked from ECCS equipment following a LOCA, is monitored prior to release from the plant via the plant vent. Operation of this system and the resultant effect on offsite and control room dose calculations was assumed in the accident analyses.
ABVS is discussed in UFSAR Section 9.4.2. SALEM -UNIT 2 B 3/4 7-Sh Amendment No. 252 PLANT SYSTEMS BASES 3/4.7.8 SEALED SOURCE CONTAMINATION The limitations on removable contamination for sources requiring leak testing, including alpha emitters, is based on 10 CFR 70.39(c) limits for plutonium.
This limitation will ensure that leakage from byproduct, source, and special nuclear material sources will not exceed allowable intake values. Sealed sources are classified into three groups according to their use, with surveillance requirements commensurate with the probability of damage to a source in that group. Those sources which are frequently handled are required to be tested more often than those which are not. Sealed sources which are continuously enclosed within a shielded mechanism (i.e., sealed sources within radiation monitoring or boron measuring devices) are considered to be stored and need not be tested unless they are removed from the shielded mechanism.
SALEM -UNIT 2 B 3/4 7-5i Amendment No.209 PLANT SYSTEMS BASES 3/4.7.9 SNUBBERS All snubbers are required OPERABLE to ensure that the structural integrity of the reactor coolant system and all other safety related systems is maintained during and following a seismic or other event initiating dynamic loads. Snubbers excluded from the program are those installed on nonsafety related systems and then only if their failure or failure of the system on which they were installed, would have no adverse effect on any safety-related system. The program for examination, testing and service life monitoring for snubbers is required to be performed in accordance with ASME BPV Code, Section XI or the OM Code and the applicable addenda as required by 10 CFR 50.55a(g) or 10 CFR 50.55a(b)(3)(v),
except where the NRC has granted specific written relief, pursuant to 10 CFR 50.55a(g)(6)(i},
or authorized alternatives pursuant to 10 CFR 50.55a(a)(3).
* SALEM -UNIT 2 B 3/4 7-6 Amendment No. 284 (PSEG Issued) 3/4.7 PLANT SYSTEMS BASES SALEM -UNIT 2 THIS PAGE INTENTIONALLY BLANK (Material Deleted)
B 3/4 7-7 Amendment No. 284 (PSEG Issued)
PLANT SYSTEMS BASES 3/4.7.10 CHILLED WATER SYSTEM -AUXILIARY BUILDING SUBSYSTEM The OPERABILITY of the chilled water system ensures that the chilled water system will continue to provide the required normal and accident heat removal capability for the control room area, relay rooms, equipment rooms, and other safety related areas. Verification of the actuation of each automatic valve on a Safeguards Initiation signal includes actuation following receipt of a Safety Injection signal. The Auxiliary Building Chilled Water (AB CH) systems can be operated in three possible LGO configurations:
: 1. Three Chillers Required (LCO 3.7.10.a)
: 2. Two Chillers Required (LCO 3.7.10.b)
: 3. Units Cross-Tied (LCO 3. 7.1 O.c) Three Chillers Required Configuration:
Removal of non-essential heat loads from the chilled water system in the event one chiller is inoperable ensures the remaining heat loads are within the heat removal capacity of the two operable chillers.
Removal of non-essential heat loads from the chilled water system in the event two chillers are inoperable and aligning the CREACs to the maintenance mode ensures the remaining heat loads are within the heat removal capacity of the operable chiller.
During chiller testing, operator actions can take the place of automatic actions During Modes 5 and 6 and during movement of irradiated fuel assemblies, chilled water components do not have to be considered inoperable solely on the basis that the backup emergency power source, diesel generatc:ir, is inoperable.
This is consistent with Technical Specification 3.8.1.2 which only requires two operable diesel generators.
Two Chillers Required Configuration:
In Two Chiller configuration the analyses demonstrate the system will continue to provide required cooling capability to the control room and safety related areas during normal operation and in the event of an accident in conjunction with a single failure.
The analyses for Two Chiller configuration were performed with both trains of Control Room Emergency Air Conditioning (CREACS) operable and one chiller operating in each unit. This configuration accounts for one of the two required chillers in a unit being out of service and an accident and single failure (loss of chiller) in the opposite unit. The restrictions for entering Two Chiller configuration ensure that the heat loads are within the heat removal capacity of the remaining operable chiller.
The heat removal capacity of the chiller is based on the service water and outside air temperatures present during the period of November 1st through April 30th. Removal of the Emergency Control Air Compressor (ECAC) from the CH system ensures that the heat load is within the capacity of the remaining chiller.
SALEM -UNIT 2 B 3/4 7-8 Amendment No. 297 (PSEG Issued)
PLANT SYSTEMS BASES If one unit is in the Two-Chiller configuration (LCO 3.7.10.b) and the other unit is in the Three Chiller configuration (LC6 3. 7 .1 O.a), CREA CS single filtration train alignment is allowed with the unit that is in Three Chiller configuration supplying the CREACS train. Additionally, nonessential heat loads must be isolated from the chilled water system on BOTH Units. Alignment of the single CREACS train to the unit in the Two-Chiller configuration is not permitted.
When entering LCO 3.7.10.b, the third chiller must have CH flow isolated to prevent recirculation of cooling water flow through the non-operating chiller.
When restoring from LCO 3. 7 .10.b for transitioning to the Three Chiller configuration, the third chiller may be un-isolated under administrative controls.
The administrative controls will require that an operator be dedicated during restoration activities to re-isolate the chiller, if necessary, in the event an accident occurs during the restoration activities.
The loss of the 2 required chillers requires the unit that has the lost the chillers to commence a controlled shutdown (or suspend CORE ALTERATIONS and movement of irradiated fuel assemblies if in MODES 5 or 6 or during the movement of irradiated fuel) and transition the CREACS to single filtration operation with the opposite unit supplying the CREACS train unless both units transition to the Cross-Tied configuration.
In the event that the Cross-tied configuration cannot be implemented or the transition to CREACS single filtration train alignment cannot be implemented, both units will commence a controlled shutdown (or suspend CORE ALTERATIONS and movement of irradiated fuel assemblies if in MODES 5 or 6 or during the movement of irradiated fuel). Required operating conditions will be verified every 24-hours (SR4.7.10.d) when in the Chiller configuration.
Cross-Tied Configuration:
In Cross-tie configuration the analyses demonstrate the system will continue to provide required cooling capability to the control room and safety related areas during normal operation and in the event of an accident in either unit. The supporting calculations were performed assuming that one of the required chillers is unavailable due to either a single failure or being out of service (two chillers remaining).
The analyses for Cross-Tied configuration determined that'both train of CREACS must be operable.
With only a single train of CREACS operable,
'the remaining CREACS cooling coil cannot maintain the control room envelope temperatures within acceptable limits. Therefore, entry into CH Cross-Tied configuration is only allowed when both trains of CREACS are operable.
A note is added to TS 3.7.6 Action a to alert operators that CREACS single filtration operation is not permitted if the units are in the CH Cross-tied configuration.
The restrictions for entering the Cross-Tied configuration ensure that the heat loads are within the heat removal capacity of the remaining two operable chillers.
The heat removal capacity of the chillers is based on the service water and outside air temperatures present during the SALEM -UNIT 2 B 3/4 7-8a
* Amendment No. 297 (PSEG Issued)
PLANT SYSTEMS BASES period of November 1st through April 30th. Removal of both units' ECACs and both units' essential heat loads from the CH system ensures that the heat load is within the capacity of the remaining chillers.
When restoring from LCO 3. 7 .1 O.c, the cross-tie valve can be closed under administrative controls.
The administrative controls will require that an operator be dedicated during restoration activities to re-open the cross-tie valve, if necessary, in the event an accident occurs during the restoration activities.
If two Chillers become inoperable in Cross-Tie configuration then both units must commence a controlled shutdown (or suspend CORE ALTERATIONS and movement of irradiated fuel assemblies if in MODES 5 or 6 or during the movement of irradiated fuel). Required operating conditions will be verified every 24-hours (SR 4.7.10.e) when in the Tied configuration.
SALEM -UNIT 2 B 3/4 7-8b Amendment No. 297 (PSEG Issued)
PLANT SYSTEMS BASES 3/4.7.11 FUEL STORAGE POOL BORON CONCENTRATION In the Maximum Density Rack (MDR) design, the spent fuel storage pool is divided into two separate and distinct regions.
Region 1, with 300 storage positions, is designed to accommodate new fuel with a maximum enrichment of 4.25 wt% U-235. Unirradiated and irradiated fuel with initial enrichments up to 5.0 wt% U-235 can also be stored in Region 1 with some restrictions.
These restrictions are stated in TS 3/4. 7 .12. Region 2, with 1332 storage positions, is designed to accommodate unirradiated and irradiated fuel with stricter controls as compared to Region 1. These controls are also stated in TS 3/4. 7 .12. The water in the spent fuel storage pool normally contains soluble boron, which results in large subcriticality margins under actual operating conditions.
: However, the NRG guidelines, based upon the accident condition in which all soluble poison is assumed to have been lost, specify that the limiting kett of 0.95 be evaluated in the absence of soluble boron. Hence, the design of both regions is based on the use of unborated water, which maintains each region in a subcritical condition during normal operation with the regions fully loaded. The double contingency principle discussed in ANSI N-16.1-1975 and the USNRC letter of April 14, 1978, to all Power Reactor Licensees
-OT Position for Review and Acceptance of Spent Fuel Storage and Handling Applications (Accession#
7910310568) allows credit for soluble boron under other abnormal or accident conditions, consistent with postulated accident scenarios.
For example, the most severe accident scenario is associated with the abnormal location of a fresh fuel assembly of 5.0 wt% enrichment which could, in the absence of soluble poison, result in exceeding the design reactivity limitation (kett of 0.95). This could occur if a fresh fuel assembly of 5.0 wt% enrichment were to be inadvertently loaded into a Region 1 or Region 2 storage cell otherwise filled to capacity.
To mitigate these postulated criticality related accidents, boron is dissolved in the pool water. Calculations for the worst case configuration confirmed that 800 ppm soluble boron (includes an appropriate allowance for boron concentration measurement uncertainty)is adequate to compensate for a mis-located fuel assembly.
Subcriticality of the MDR with no movement of assemblies is achieved without credit for soluble boron and by controlling the location of each assembly in accordance with TS 3/4. 7 .12. Prior to movement of an assembly, it is necessary to verify the fuel storage pool boron concentration is within limit in accordance with TS 3/4. 7 .11. Most postulated abnormal conditions or accidents in the spent fuel pool do not result in an increase in the reactivity of either MDR region. For example, an event that results in an increase in spent fuel pool temperature or a decrease in water density will not result in a reactivity increase.
An event that results in the spent fuel pool cooling down below normal conditions does not impact the criticality analysis since the analysis assumes a water temperature of 4&deg;C. This assures that the reactivity will always be lower over the expected range of water temperatures.
SALEM -UNIT 2 B 3/4 7-9 Amendment No.244 PLANT SYSTEMS BASES 3/4.7.11 FUEL STORAGE POOL BORON CONCENTRATION (continued)
: However, accidents can be postulated that could increase the reactivity.
This increase in reactivity is unacceptable with unborated water in the storage pool. Thus, for these accident occurrences, the presence of soluble boron in the storage pool prevents criticality excef3ding limits in both regions.
The postulated accidents are basically of three types. The first type of postulated accident is an abnormal location of a fuel assembly, the second type of postulated accident is associated with lateral rack movement, and the third type of postulated accident is a dropped fuel assembly on the top of the rack. The dropped fuel assembly and the lateral rack movement have been previously shown to have negligible reactivity effects (<0.0001 ok). The misplacement of a fuel assembly could result in Keff exceeding the 0.95 limit. However, the negative reactivity effect of a minimum soluble boron concentration of 600 ppm compensates for the increased reactivity caused by any of the postulated accident scenarios.
The accident analyses are summarized in the FSAR Section 9.1.2. The determination of 600 ppm has included the necessary tolerances and uncertainties associated with fuel storage rack criticality analyses.
To ensure that soluble boron concentration measurement uncertainty is appropriately considered, additional margin is incorporated into the limiting condition for operation.
As such, increasing the minimum required boron concentration in the fuel storage pool to 800 ppm conservatively covers the expected range of boron reactivity worth along with allowances associated with boron measurements.
The concentration of dissolved boron in the fuel storage pool satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
The fuel storage pool boron concentration is required to be greaterthan or equal to 800 ppm. The specified concentration of dissolved boron in the fuel storage pool preserves the assumptions used in the analyses of the potential critical accident scenarios.
This concentration of dissolved boron is the minimum required concentration for fuel assembly storage and movement within the fuel storage pool. This LCO applies whenever fuel assemblies are stored in the spent fuel storage pool, until a complete spent fuel storage pool verification has been performed following the last movement of fuel assemblies in the spent fuel storage pool. This LCO does not apply following the verification, since the verification would confirm that there are no misloaded fuel assemblies.
With no further fuel assembly movements in progress, there is no potential for a misloaded fuel assembly or a dropped fuel assembly.
SALEM -UNIT 2 B 3/4 7-10 Amendment No. 244 PLANT SYSTEMS BASES 3/4.7.11 FUEL STORAGE POOL BORON CONCENTRATION (continued)
The Required Actions are modified indicating that LCO 3.0.3 does not apply. Storage of fuel assemblies and the boron concentration in the spent fuel storage pool are independent of reactor operation.
Therefore TS 3/4 3. 7 .11 and TS3/ 4 3. 7 .12 include the exception to LCO 3.0.3 to preclude an inappropriate reactor shutdown.
When the concentration of boron in the fuel storage pool is less than required, immediate action must be taken to preclude the occurrence of an accident or to mitigate the consequences of an accident in progress.
This is most efficiently achieved by immediately suspending the movement of fuel assemblies.
The concentration of boron is restored simultaneously with suspending movement of fuel assemblies.
Alternatively, beginning a verification of the fuel storage pool fuel locations, to ensure proper locations of the fuel, can be performed.
: However, prior to resuming movement of fuel assemblies, the concentration of boron must be restored.
This does not preclude movement of a fuel assembly to a safe position.
If the LCO is not met while moving fuel assemblies in the spent fuel pool while in MODE 5 or 6, LCO 3.0.3 would not be applicable.
If moving fuel assemblies in the spent fuel pool while in MODE 1, 2, 3, or 4, the fuel movement is independent of reactor operation.
Therefore, inability to suspend movement of fuel assemblies is not sufficient reason to require a reactor shutdown.
This SR verifies that the concentration of boron in the fuel storage pool is within the required limit. As long as this SR is met, the analyzed accidents are fully addressed.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
SALEM -UNIT 2 B 3/4 7-11 Amendment No. 282 (PSEG Issued)
PLANT SYSTEMS BASES 3/4.7.12 FUEL ASSEMBLY STORAGE IN THE SPENT FUEL POOL In the Maximum Density Rack (MOR) design, the spent fuel storage pool is divided into two separate and distinct regions.
Region 1, with 300 storage positions, is designed to accommodate new fuel with a maximum enrichment of 4.25 wt% U-235. Unirradiated and irradiated fuel with initial up to 5.0 wt% U-235 can also be stored in Region 1 with some restrictions.
These restrictions are stated in TS 3/4. 7 .12. Region 2, with 1332 storage positions, is designed to accommodate unirradiated and irradiated fuel with stricter controls as compared to Region 1. These controls are also stated in TS 3/4. 7 .12. The water in the spent fuel storage pool normally contains soluble boron, which results in large subcriticality margins under actual operating conditions.
: However, the NRC guidelines; based upon the accident condition in which all soluble poison is assumed to have been lost, specify that the limiting kett of 0.95 be evaluated in the absence of soluble boron. Hence, the design of both regions is based on the use of unborated water, which maintains each region in a subcritical condition during normal operation with the regions fully loaded. The double contingency principle discussed in ANSI N-16.1-1975 and the USNRC letter of April 14, 1978, to all Power Reactor Licensees
-OT Position for Review and Acceptance of Spent Fuel Storage and Handling Applications (Accession
# 7910310568) allows credit for soluble boron under other abnormal or accident conditions, since only a single accident need be considered at one time. For example, the most severe accident scenario is associated with the abnormal location of a fresh fuel assembly of 5.0 wt% enrichment which could, in the absence of soluble poison, result in exceeding the design reactivity limitation (kett of 0.95). This could occur if a fresh fuel assembly of 5.0 wt% enrichment were to be inadvertently loaded into a Region 1 or Region 2 storage cell otherwise filled to capacity, for any of the configurations. To mitigate these postulated criticality related accidents, boron is dissolved in the pool water. Calculations for the worst case configuration confirmed that 800 ppm soluble boron (includes an appropriate allowance for boron concentration measurement uncertainty) is adequate to compensate for a mis-located fuel assembly.
Safe operation of the MDR with no movement of assemblies may therefore be achieved by controlling the location of each assembly in accordance with TS 3/4. 7 .12. Prior to movement of an assembly into a fuel assembly storage location in Region 1 or Region 2, it is necessary to perform SR 4.7.11 and either SR 4.7.12.1 or SR 4.7.12.2.
In summary, before moving an assembly into the storage racks it is necessary to:
* validate that its final location meets the criticality requirements;
* and since there is a potential to misload the assembly, we need to ensure that the Fuel Storage Pool boron concentration is greater than the minimum required to preclude exceeding criticality limits prior to moving. The configuration of fuel assemblies in the fuel storage pool satisfies Criterion 2 of 10 CFR 50.36(c}(2)(ii).
SALEM -UNIT 2 B 3/4 7-12 Amendment No.244 PLANT SYSTEMS BASES 3/4.7.12 FUEL ASSEMBLY STORAGE IN THE SPENT FUEL POOL (CONTINUED)
The restrictions on the placement of fuel assemblies within the spent fuel pool in accordance with TS 3/4. 7 .12, in the accompanying LCO, ensures the keff of the spent fuel storage pool will always remain < 0.95, assuming the pool to be flooded with unborated water. This LCO applies whenever any fuel assembly is stored in Region 1 or Region 2 of the fuel storage pool. The Required Actions are modified indicating that LC03.0.3 does not apply. Storage of fuel assemblies and the boron concentration in the spent fuel storage pool are independent of reactor operation.
Therefore TS 3/4.3. 7 .11 and TS 3/4.3. 7 .12 include the exception to LCO 3.0.3 to preclude an inappropriate reactor shutdown.
When the configuration of fuel assemblies stored in Region 1 or Region 2 of the spent fuel storage pool is not in accordance with TS 3/4. 7 .12, the immediate action is to initiate action to make the necessary fuel assembly movement(s) to bring the configuration into compliance with TS 3/4.7.12.
If unable.to move fuel assemblies while in MODE 5 or 6, LCO 3.0.3 would not be applicable.
If unable to move fuel assemblies while in MODE 1, 2, 3, or 4, the action is independent of reactor operation.
* Therefore, inability to move fuel assemblies is not sufficient reason to require a reactor shutdown.
The SR verifies by administrative means that the initial enrichment and burnup of the fuel assembly is in accordance with TS 3/4.7,12 in the accompanying LCO. SALEM -UNIT 2 B 3/4 7-13 Amendment No.258 3/4. 8 ELECTRICAL POWER SYSTEMS BASES 3/4.8.l and.3/4.8.2 A.C .. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS The OPERABILITY of the A.C. and D.C power sources and associated distribution*systems during operation ensures that sufficient power will be available to supply the.safety related equipment required for 1) the safe shutdown
*of: the facility, and*2) the.mitigation and control of accident conditions within the facility.
The minimum specified independent and .redundant and D.C, power sources and distribution systems satisfy the of General Desi.gn Criterion 17 of Appendix "A" to 10 CFR Part 50. The.ACTION requirements specified for the levels of degradation.of the power s*ources provide restriction upon continued facility operation commensurate with the level of.degradation.
The OPERABILITY of the power sources are: consistent with the initial condition assumptions of the accident analyses and are based upon maintaining at least two independent sets of onsite A.c.: and D.C. power sources and associated distribution systems OPERABLE during accident conditions coincident with an assumed loss of offsite p9wer and single failure of one onsite A.C. source. When a system or component is determined to be inoperable solely because its *emergen'cy power source is inoperable, or solely because its normal power source is inoperable, it may still be considered
: OPERABLE, provided the appropriate; Actions of 3.8.1.1.a.2, b.2 or d.2 are satisfied.
* Action 3.8.1.1.a.2, which only applies if the train cannot be powered from an .offsite source, is intended to provide assurance that an event coincident with a single failure of the associated DG*will not result in a *complete
],.o'ss of sa.fety function of critical redundant required systems . . Failure of *a single offsite circuit will generally not, by itself, cause any equipment to lose normal AC power. Action 3.8*.1.1.b.2 is intended to provide .assurance a loss of offSite power, during the period that a DG is inoperable,'
does not result in a complete loss of safety function of critical systems.
Action 3.8.1.1.d.2, which applies when two offsite circuits are inoperable,'.
is intended to provide assurance that an event with a coincident
.single failure will *not result in a complete loss* of redundant required safety functions.
These.* systems are powered from the independent AC electrical power train *. However, redundant required systems or components credited by this specification are nqt necessarily powered from AC electrical sources.
For example, the single train turb.ine-driven auxiliary feedwater pump is redundant
*:to the two :motor-driven pumps. Redundant required system or component failures consist*
of:inoper<,\ble equipment associated with a train, redundant to the that.has an inoperable DG or offsite power. LCO 3.0.4.b, is not applicable to an inoperable DG. There is an increased risk .associated:with entering a MODE or other specified condition in the Applicability with an inoperable DG. The provisions of LCO 3.0.4.b, which allow* entry into a MODE or other *specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
SALEM -UNIT 2 B 3/4 8-1 Amendment No. 258 APPLICAB;I:LI'.TY
.BASES The* completion time for these actions is intended to allow the operator
:time to evaluate and repair any discovered inoperabilities.
This completion time also allows for an exception to the normal "time zero" for beginning the
* _ailowed outage time clock, starting only on discovery that both: a. One train has no* offsite power supplying its loads, one DG is inoperable or two required offsite circuits are inoperable; and b. A=required system or component on the other train is inoperable.
If at any time during these conditions a redundant required system or *component subsequently becomes inoperable, this completion time begins to be *tracked.
Discovering no offsite power to one train of the onsite Class lE Electrical
.Power Distribution System, or one required DG inoperable, coincident
;with one or more inoperable required support or supported systems
* SALEM -UNIT 2 B 3/4 8-la Amendment No. 258 
' ' I ,. 1' '3/4. 8 ELECTRICAL POWER SYSTEMS .BASES (Continued) or components that are associated with the other train that has power, results starting the completion times for the Action. The specified time is acceptable:because.it minimizes risk while allowing time for restoration
.before subjecting the unit to transients associated with shutdown.
The remaining OPERABLE AC supplies (one offsite circuit and three DGs for Condition (a), two offsite circuits and two DGs for Condition (b), or three DGs for Condition (d)) are adequate to supply electrical power to the onsite *class lE* D;tstribution System. Thus, on a component basis, single failure protection*for the required system or component's function may have beep lost; however, function has not been lost. The completion time takes into account the component OPERABILITY of the redundant counterpart to the inoperable*
requtred or component.
the completion time takes into account capacity and capability of the remaining AC sources, a reasonable time for -repairs, and the low probability of a DBA occurring during this The completion time for Condition d (loss of both offsite circuits) is reduced to 12 hours from that allowed for one train without offsite power (Action 3.8.1.1.a.2),
The rationale is that Regulatory Guide 1.93 allows a completi'on
*time oi: 24 hours for two required offsite circuits inoperable, based upon the assumption that two complete safety trains are OPERABLE.
When a _concurrent:
redundant required system or component failure exists, this assumption.is not the case, and a shorter completion time of 12 hours is : appropriate.
The OPERAB!LITY of the.minimum specified A.C. and D.C. power sources and systems during shutdown and refueling ensures 'that .'l) the facility cal'). be maintained in the shutdown or refueling condition for extended time periods and 2) sufficient instrumentation and control capability i's for .monitoring and maintaining the unit status. The_Applicability of specifications 3.8.2.2, 3.8.2.4, and 3.8.2.6 includes the movement of fuel assemblies.
This will insure adequate electrical power is available for proper operation*
of the fuel handling building
._ventilation system during movement of irradiated fuel in the spent fuel pool. An offsite*circuit would be considered inoperable if it were not available to one* required train, Although two .trains are required by LCOs 3.8.2.2 and 3.8.2.4, the one train with offsite power available may be capable of supporting sufficient required features to allow continuation of CORE *.ALTERATIONS and irradiated fuel movement.
By the allowance of the option to declare required features inoperable, with no offsite power available,
_appropriate restrictions will be implemented in accordance with the affected required features LCO's actions.
With the offsite circuit or diesel generator not available to all required t.rains, option exists to declare all required features inoperable.
Since *this option may involve undesired administrative
: efforts, the allowance for .sufficiently conservative actions is made. With both required diesel .generators.inoperable,.the minimum required diversity of AC power sources is not Therefore, it is required to suspend CORE ALTERATIONS,
*movement of irr.adiated fuel assemblies, and operations involving positive reactivity.additions that could result in loss of required shutdown margin or ,boron concentration.
Suspending positive reactivity additions that could result in failure to meet the minimum shutdown margin or boron concentration l*imit is required to assure continued safe operation.
*SALEM -UNIT 2 B 3/4 8-2 Amendment No.246 3/4.8 ELECTRICAL POWER SYSTEMS BASES <Continued)
The Surveillance Requirements for demonstrating the .OPERABILITY of the diesel generators are based upon the recommendations of Regulatory Guide 1.9, "Selection of Diesel Generator Set Capacity for Standby Power Supplies,"
March 10, 1971, and Regulatory Guide 1.108, "Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants,"
Revision 1, August 1977. -The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
Regulatory Guide 1.108 criteria for determining and reporting valid tests and failures, and accelerated diesel generator
: testing, have been superseded by implementation of the Maintenance Rule for the diesel generators per 1 OCFR50.65.
In addition to the Surveillance Requirements of 4.8.1.1.2, diesel preventative maintenance is performed in accordance with procedures based on manufacturer's recommendations with consideration given to operating experience.
The minimum voltage and frequency stated in the Surveillance Requirements (SR) are those necessary to ensure the Emergency Diesel Generator (EOG) can accept Design Basis Accident (OBA) loading while maintaining acceptable voltage and frequency levels. Stable operation at the nominal voltage and frequency values is also essential in establishing EOG OPERATILITY, but a time constraint is not imposed.
The lack of a time constraint is based on the fact that a typical EOG will experience a period of voltage and frequency oscillations prior to reaching steady state operation if these oscillations are not dampened out by load application.
In lieu of a time constraint in the SR, controls will be provided to monitor and trend the actual time to reach stable operation within the band as a means of ensuring there is no voltage regulator or governor degradation that could cause an EOG to become inoperable.
"Standby condition" for the purpose of defining the condition of the engine immediately prior to starting for surveillance requirements requires that the lube oil temperature be between 100 &deg;F and 170 &deg;F. The minimum lube oil temperature for an OPERABLE diesel is 100 &deg;F. The thirteen second time requirement for the Emergency Diesel Generator to reach rated voltage and frequency was originally based on a Westinghouse assumption of fifteen seconds that included the delay time between the occurrence of the incident and the application of electrical power to the first sequenced safeguards pump (BURL-3011, dated November 13, 1974) and included an instrument response time of two seconds (BURL-1531, dated July 27, 1970). The times specified in UFSAR Section 15.4 bound the thirteen seconds specified in the TS. The narrower band for frequency specified for testing performed in steady state isochronous operation will ensure the EOG will not be run in an overloaded condition (steady state) during accident conditions.
Steady state is assumed to be achieved after one minute of operation in the isochronous mode with all required loads sequenced on the bus. The narrower band for steady state voltage is specified for operation when the EOG is not synchronized to the grid to ensure the voltage regulator will protect driven equipment from voltages during accident conditions.
Procedural controls will ensure that equipment voltages are maintained within acceptable limits during testing when paralleled to the grid. The wider band for frequency is appropriate for testing done with the governor in the droop mode. Likewise the wider band for voltage is appropriate when paralleled to the grid. SALEM -UNIT 2 B 3/4 8-3 Amendment No.282 (PSEG Issued) 3/4.8 ELECTRICAL POWER SYSTEMS BASES (Continued)
All voltages and frequencies specified in SR 4.8.1 :1.2 are representative of the analytical values and do not account for postulated instrument inaccuracy.
Instrument inaccuracies for EOG voltage and frequency are administratively controlled.
Preventive maintenance includes those activities (including pro-test inspections, measurements, adjustments and preparations) performed to maintain an otherwise OPERABLE EOG in an OPERABLE status. Corrective maintenance includes those activities required to correct a condition that would cause the EOG to be inoperable.
Surveillance requirement 4.8.1.2 is modified by a Note. The reason for the Note is to preclude requiring the OPERABLE OG(s) from being paralleled with the offsite power network or otherwise rendered inoperable during performance of the surveillance requirement, and to preclude de-energizing a required ESF bus or disconnecting a required offsite circuit during performance of surveillance requirements.
With limited AC sources available, a single event could compromise both the required circuit and the DG. It is the intent that these surveillance requirements must still be capable of being met, but actual performance is not required during periods when the DG and offsite circuit are required to be OPERABLE.
During Startup, prior to entering Mode 4, the surveillance requirements are required to be completed if the surveillance frequency has been exceeded or will be exceeded prior to the next scheduled shutdown.
3/4.8.3 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES Containment electrical penetrations and penetration conductors are protected by either deenergizing circuits not required during reactor operation or by demonstrating the OPERABILITY of primary and backup overcurrent protection circuit breakers during periodic surveillance.
The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program..
Each manufacturer's molded case circuit breakers and lower voltage circuit breakers are grouped into representative samples which are then tested on a rotating basis to ensure that all breakers are tested. If a wide variety exists within any manufacturer's brand of molded case or lower voltage circuit breakers, it is necessary to further divide.that manufacturer's breakers into groups and treat each group as a separate type of breaker for surveillance purposes.
Containment penetration conductor overcurrent protective device information is provided in the UFSAR. SALEM -UNIT 2 B 3/4 8-4 Amendment No. 282 (PSEG Issued) 3/4.9 REFUELING OPERATIONS BASES 3/4.9.1 BORON CONCENTRATION The limit on the boron concentration of the Reactor .Coolant System (RCS), the refueling cavity, the fuel storage pool and the refueling canal during refueling ensures that the reactor remains subcritical during Mode 6. Refueling boron concentration is the soluble boron concentration in the coolant in each of these volumes having direct access to the reactor core during refueling.
The soluble boron concentration offsets the core reactivity and is measured by chemical analysis of a representative sample of the coolant in each of the volumes.
The refueling boron concentration limit is specified in the Core Operating Limits Report (COLR)
* Plant procedures ensure the specified boron concentration in order to maintain
.an overall core reactivity of Keff 0.95 during fuel handling, with control rods and fuel assemblies assumed to be in the most adverse.configuration (least negative reactivity) allowed by plant procedures.
General Design Criterion 26 of 10CFR SO, Appendix A requires that two independent reactivity control systems of different design principles be provided.
One of these systems must be capable of holding the reactor core subcritical under cold conditions.
The Chemical and Volume Control System (CVCS) is the system capable of maintaining the reactor subcritical in cold conditions by maintaining the boron concentration.
The reactor is brought to shutdown conditions before beginning operations to open the reactor vessel for refueling.
After the RCS is cooled and depressurized and the vessel head is unbolted, the head is slowly removed to form the refueling cavity. The refueling canal and the refueling cavity are, then flooded with borated water from the refueling water storage tank through the open reactor vessel by gravity feeding or by the use of the Residual Heat Removal (RHR) System pumps. The fuel storage pool is also adjusted to the refueling boron concentration specified in the COLR. The pumping action of the RHR System in the RCS and the circulation due to thermal driving heads in the reactor vessel and refueling cavity mix the added concentrated boric acid with the water in the refueling canal. The RHR System is in operation during refueling (see TS 3/4.9.B, "Residual Heat Removal (RHR) and coolant Circulation
-All Water levels, " and "Low Water Level") to provide forced circulation in the RCS and assist in maintaining the boron concentrations in the RCS, the refueling canal, and the refueling cavity above the COLR limit. SALEM -UNIT 2 B 3/4 9-1 Amendment No. zq.lj.
3/4.9 REFUELING OPERATIONS BASES During refueling operations, the reactivity condition of the core is consistent with the initial conditions assumed for the boron dilution accident in the accident analysis and is conservative for MOPE 6. The boron concentration limit specified in the COLR is based on the core reactivity at the beginning of each fuel cycle (the end of refueling) and includes an uncertainty allowance.
The boron concentration and *the plant refueling procedures that verify the correct fuel-loading plan (including full core mapping}
ensure that the Keff of the core will remain S 0.95 during the refueling operation.
Hence, at least a 5% Ak/k margin of safety is established during refueling.
During refueling, the water volume in the spent fuel pool, the transfer canal, the refueling canal, the cavity, and the reactor vessel form a single As a result the soluble boron concentration is relatively the same in each of these volumes.
The RCS boron concentration satisfies Criterion 2 10CFRS0.36(c)
(2) (ii). The LCO requires that a minimum boron concentration be maintained in the RCS, the refueling canal, the fuel storage pool and the refueling cavity while in MODE 6. The boron concentration limit specified in the COLR ensures that a core Keff $ 0.95 is maintained during fuel handling operations.
Violation of the LCO could lead to an inadvertent criticality during MODE 6. This LCO is applicable in MODE 6 to ensure that the fuel in the reactor vessel will remain subcritical.
The required boron concentration ensures a Keff $
A note to this LCO modifies the Applicability.
The note states that the limits on boron concentration are only applicable to the refueling canal, the fuel storage pool and the refueling cavity-when those volumes are connected to the Reactor Coolant System. When the refueling canal, the fuel storage pool and the refueling cavity are isolated from the RCS, no potential path for boron dilution exists. Above MODE 6, LCOs 3.1.1.1 and 3.1.1.2 ensure that an adequate amount of negative reactivity is available to shut down the reactor and maintain it subcritical.
Continuation of CORE ALTERATIONS or positive reactivity additions (including actions to reduce boron concentration) is contingent upon maintaining the unit in compliance with the LCO. If the boron concentration of any coolant volume in the RCS, the refueling canal, the fuel storage pool or the refueling cavity is less than its limit, all operations involving CORE ALTERATIONS or positive reactivity additions must be suspended immediately.
suspension of CORE.
* ALTERATIONS and positive reactivity additions shall not preclude moving a component to a safe position.
that individually add limited positive reactivity (e.g. temperature fluctuations from inventory addition or temperature control fluctuations),
but when combined with all other operations affecting core reactivity (e.g., intentional boration) result in overall net negative reactivity
: addition, are riot precluded by this action. SALEM -UNIT 2 B 3/4 9-la Amendment No. 244 3/4.9 REFUELING OPERATIONS BASES In addition to immediately suspending CORE ALTERATIONS and positive reactivity additions, boration to restore the concentration must be initiated immediately.
In determining the required combination of boration flow rate and concentration, no unique Design Basis Event must be satisfied.
The only requirement is to restore the boron concentration to its required value as soon as possible.
In order to raise the boron concentration as soon as possible, the operator should begin boration with the best source available for unit conditions.
Once actions have been initiated, they must be continued until the boron concentration is restored.
The restoration time depends on the amount of boron that must be injected to reach the required concentration.
The Surveillance Requirement (SR) ensures that the coolant boron concentration in the RCS, and connected portions of the refueling canal, the fuel storage pool and the refueling cavity, is within the COLR limits. The boron concentration of the coolant in each required volume is determined periodically by chemical analysis.
Prior to reconnecting portions of the refueling canal, the fuel storage pool or the refueling cavity to the RCS, this SR must be met per SR 4.0.4. If any dilution activity has occurred while the cavity or canal was disconnected from the RCS, this SR ensures the correct boron concentration prior to communication with the RCS. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
3/4.9.2.1 UNBORATED WATER SOURCE ISOLATION VALVES During MODE 6 operations, all isolation valves for the reactor makeup water sources containing unborated water that are connected to the Reactor Coolant System (RCS) must be closed to prevent unplanned boron dilution of the reactor coolant.
The isolation valves must be secured in the closed position.
Securing the required valves in the closed position during refueling operations ensures that the valves cannot be inadvertently opened, and prevents the flow of unborated water to the filled portion of the RCS. This action precludes the possibility of an inadvertent boron dilution event occurring during MODE 6 refueling operations.
By isolating unborated water sources, a safety analysis for an uncontrolled boron dilution event in accordance with the Standard Review Plan (NUREG-0800, Section 15.4.6) is not required for MODE 6. If any required valve is found not secured in the closed position, there is a potential of having a diluted boron concentration in the RCS. Immediately suspend CORE ALTERATIONS, and initiate actions to secure the valve in the closed position.
Surveillance Requirement 4.9.1 must be performed to demonstrate that the required boron concentration exists. The 4 hour completion time is sufficient to obtain and analyze a reactor coolant sample for boron concentration.
Surveillance Requirement 4.9.2.1 demonstrates through a system walkdown that the required valves are closed. The surveillance frequency is controlled under the Surveillance Frequency Control Program.
3/4.9.2.2 INSTRUMENTATION The source range neutron flux monitors are used during refueling operations to determine the core reactivity condition.
Two OPERABLE source range neutron flux monitors are required to SALEM -UNIT 2 B3/49-1b Amendment No. 292 (PSEG Issued) 3/4.9 REFUELING OPERATIONS BASES alert the operator to unexpected changes in core reactivity, such as a boron dilution event. This ensures that redundant monitoring capability is available to detect changes in core reactivity.
Based on isolating all boron dilution paths per LCO 3.9.2.1, only the source range neutron flux monitor visual indication in the control room is required for OPERABILITY.
Any combination of NIS source range neutron flux monitors and/or Gamma-Metrics accident neutron flux monitors may be used to satisfy the LCO. Two of the four total source range neutron flux monitors are required to be OPERABLE.
With only one required source range neutron flux monitor OPERABLE, redundancy has been lost. Suspending positive reactivity additions that could result in failure to meet the minimum boron concentration limit is required to assure continued safe operation.
With no required source range neutron flux monitor OPERABLE, action to restore a monitor to OPERABLE status shall be initiated immediately.
With no source range neutron flux monitor OPERABLE, there is no direct means of detecting changes in core reactivity.
However,,since positive reactivity additions are not to be made, the core reactivity condition is stabilized until the source range neutron flux monitors are OPERABLE.
This stabilized condition is confirmed by performing Surveillance Requirement 4.9.1 to ensure that the required boron concentration exists and adequate shutdown margin is maintained.
3/4.9.3 DECAY TIME The minimum requirement for reactor subcriticality prior to movement of irradiated fuel assemblies in the reactor pressure vessel ensures that sufficient time has elapsed to allow the radioactive decay of tl)e short lived fission products.
The 80-hour decay time (LAR S08-01) is consistent with the assumptions used in the fuel handling accident analyses and the resulting dose calculations using the Alternative Source Term described in Reg. Guide 1.183. The minimum requirement for reactor subcriticality also ensures that the decay time is consistent with that assumed in the Spent Fuel Pool cooling analysis.
The calendar based restrictions are established for the actual movement of irradiated fuel; i.e., movement cannot commence in the October 15th through May 15th window unless at least 80 hours has elapsed since subcriticality was achieved.
The 80 hour clock can start prior to October 15 but must end in the October 15th -May 15th window for the 80 hour criteria to be applicable.
Similarly, fuel movement between May 15th and October 14th cannot commence unless at least 168 hours has elapsed sir:ice subcriticality was achieved.
Delaware River water average temperature between October 151h and May 15th is determined from historical data taken over 30 years. The use of 30 years of data to select maximum temperature is consistent with Reg. Guide 1.27, "Ultimate Heat Sink for Nuclear Power Plants".
A core offload has the potential to occur during both applicability time frames. In order not to exceed the analyzed Spent Fuel Pool cooling capability to maintain the water temperature below 180&deg;F, two decay time limits are provided.
In addition, PSEG has developed and implemented a Spent Fuel Pool Integrated Decay Heat Management Program as part of the Salem Outage Risk Assessment.
This program requires a pre-outage assessment of the $pent Fuel Pool heat loads and heat-up rates to assure available Spent Fuel Pool cooling capability prior to offloading fuel. SALEM -UNIT 2 B 3/4 9-1c Amendment No. 292 (PSEG Issued) 3/4.9 REFUELING OPERATIONS BASES 3/4.9.4 CONTAINMENT BUILDING PENETRATIONS During movement of irradiated fuel assemblies within containment the requirements for containment building penetration closure capability and OPERABILITY ensure that a release of fission product radioactivity within containment will not exceed the guidelines and dose calculations described in Reg Guide 1.183, Alternative Radiological Source Term for Evaluating Design Basis Accidents at Nuclear Power Plants. In MODE 6, the potential for containment pressurization as a result of an accident is not likely. Therefore, the requirements to isolate the containment from the outside atmosphere can be less stringent.
The LCO requirements during movement of irradiated fuel assemblies within containment are referred to as "containment closure" rather than containment OPERABILITY.
For the containment to be OPERABLE, CONTAINMENT INTEGRITY must be maintained.
Containment closure means that all potential release paths are closed or capable of being closed. Closure restrictions include the administrative controls to allow the opening of both airlock doors and the equipment hatch during fuel movement provided that: 1} the equipment inside door or an equivalent closure device installed is capable of being closed with four bolts within 1 hour by a designated personnel;
: 2) the airlock doors are capable of being closed within 1 hour by designated personnel,
: 3) either the Containment Purge System or the Auxiliary Building Ventilation System taking suction from the containment atmosphere are operating and 4} the plant is in Mode 6 with at least 23 feet *of water above the reactor pressure vessel flange. Administrative requirements are established for the responsibilities and appropriate actions of the designated personnel in the event of a Fuel Handling Accident inside containment.
These requirements include the responsibility to be able to communicate with the control room, to ensure that the equipment hatch is capable of being closed, and to close the equipment hatch and personnel airlocks within 1 hour in the event of a fuel handling accident inside containment.
These administrative controls ensure containment closure will be established in accordance with and not to exceed the dose calculations performed using guidelines of Regulatory Guide 1.183. SALEM -UNIT 2 B 3/4 9-1d Amendment No. 292 (PSEG Issued}
REFUELING OPERATIONS BASES The containment serves to limit the fission product radioactivity that. may be released from* the reactor core following an accident, such that offsite radiation*.
exposures are maintained well within the requirements of 10CFR100 and Reg Guide .1.183, Alternative Source Term, as applicable.
Additionally, the containment provides radiation shielding from the fission products that may be present in the containment atmosphere following accident conditions.
The Containment Equipment Hatch, which ls part of the containment pressure
: boundary, provides a means for moving large equipment and components Into or out of containment.
During movement of irradiated fuel assemblies wfthln containment can be open provided that: 1) It ls capable of being .closed with four bolts within 1 hour by personnel, 2)" either the Containment Purge System or the Auxlllary Bullding Ventilation System taking suction from the containment atmosphere are operating and 3) the plant is In Mode 6 with at least 23 feet of water above the reactor pressure vessel* flange. Good engineering practice dictates that the bolts required by the LCO are approximately squatly spaced. *An equivalent closure device may be installed as an alternatlve to lnstalling the Containment Equipment
.Hatch Inside door with a minimum of four bolts. . Such a closure device may provide penetrations for temporary services used to support maintenance act,vlties Inside containment at times when containment plosure and may -be .installed
*in .place of the Containment.
Equipment
'Hatch*inslde door or outside door. Penetrations Incorporated
.Into the design of an equivalent closure device will be considered a part of the containment.
boundary and as such wlll be subject to the requirements of Technical Specification 3/4.9.4.
Any equivalent closure device used to satisfy the requirements of Technical SpecHlcatlon 3/4.9.4.a will be designed, fabricated, Installed, tested, and utilized In with established procedures fo ensure that the design requlrem!:lnts for the mitigation of a .fuel handling accident during refueling operations are met. In case that this equivalent closure device Is Installed In lieu of the equipment hatch insh;le door, the same restrictions and administrative controls apply to ensure closure will take place within 1 hour following a Fuel Handling Accident Inside containment.
The containment air locks, which are also part* of containment pressure
: boundary, provide a means for personnel access during operation In MODES 1, 2; 3, 4 as specified in LCO 3.6.1.3,.
"Containment Air Locks". Each air lock *has a door at both ends. The doors are normally Interlocked to prevent slmultan.eous opening when containment OPERABILITY Is required
.. During periods of unit shutdown, when . containment closure Is .not required and containment E!ntry is necessary, the air look Interlock mechanism may be disabled.
This allows both doors of an airlock to remain open for extended periods.
During movement
.of lrr&diated fuel assemblies within comalnment, containment closure may be required; therefore; the door. interlock mechanism may remain disabled, and
* both doors of each containment airlock may be open If: 1) At least one door of each ls capable of being closed within 1 hour by dedicated personnel,)
: 2) either the Containment Purge $ystem or the Auxiliary Building Ventilation System taking suction from the containment atmosphere are operating and 3) The plant Is In Mode 6 with at least 23 feet of water above the reactor pressure vessel flange. . . In the postulated FHA, the revised dose calculations performed using RG 1.183 criteria, do not assume automatlc containment purge Isolation thus .allowing for contlnous monitoring of containment acltivity until the release pathways are Isolated.
. If required, manual Isolation of containment purge can be Initiated from the control room.
* The other containment penetrations that provide direct from containment atmosphere to outside atmosphere must be Isolated.
on at least one side. Isolation may be achieved by an OPERABLE automatic Isolation-valve, or by a manual Isolation valve, blind flange, or equivalent:
*Equivalent Isolation
*methods may Include the use of a material that can provide a temporary atmospheric
: pressure, ventilation barrier.
Any equivalent method used to satisfy.the requirements of Technical Specification
,S/4.9.4.c.1 will be designed, fabricated, Installed, tested, and utilized
. In accordance with procedures to ensure that the design requirements for the mitigation of a fuel handling accident during refueling operations are met.-SALEM -UNIT 2 B 3/4 9-2 Amendment No. 245 REFUELING OPERATIONS BASES ==============================================================================
The surveillance requirement 4.9.4.2 demonstrates that the necessary
: hardware, tools, and equipment are available to close the equipment hatch. The surveillance is performed once per refueling prior to the start of movement of irradiated fuel assemblies within the containment.
This surveillance Is only required to be met when the equipment hatch is open. 3/4.9.5 COMMUNICATIONS Deleted.
3/4.9.6 MANIPULATOR CRANE Deleted.
3/4.9.7 CRANE TRAVEL -SPENT FUEL STORAGE BUILDING Deleted.
3/4.9.8 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION The requirements that at least one residual heat removal loop be in operation ensures that (1) sufficient cooling capacity is available to remove decay heat and maintain the water In the reactor pressure vessel below 140&deg;F as required during the REFUELING MODE, and (2) sufficient coolant circulation is maintained through the reactor core to minimize the effects of a boron dilution incident and prevent boron stratification.
A minimum flow rate of 1000 gpm is required.
Additional flow limitations are specified in plant procedures, with the design basis documented in the Salem UFSAR. These flow limitations address the concerns related to vortexing and air entrapment in the Residual Heat Removal system, and provide operational flexibility by adjusting the flow limitations based on time after shutdown.
The requirement to have two RHR loops OPERABLE when there Is less than 23 feet of water above the reactor vessel flange ensures that a single failure of the operating RHR loop will not result in a complete loss of residual heat removal capability.
For support systems:
Service Water (SW) and Component Cooling (CC), component redundancy is necessary to ensure no single active component failure will cause the loss of Decay Heat Removal.
One piping path of SW and CC is adeq1,.1ate when it supports both RHR loops. The support systems needed before entering into the desired configuration (e.g., one service water loop out for maintenance in Modes 5 and 6) are controlled by procedures, and include the following: -A requirement that the two RHR, two CC and two SW pumps, powered from two different vital buses be kept operable -A listing of the active (air/motor operated) valves in the affected flow path to be locked open or disable.
SALEM -UN IT 2 B 3/4 9-3 Amendment No. 277 (PSEG Issued)
REFUELING OPERATIONS BASES . Note that four filled reactor coolant loops, with at least two steam generators with at least their secondary side water level greater than or equal to 5% (narrow range),.
may be substituted for one residual heat removal loop. This.ensures that single fallure do.es not cause a loss of decay heat removal.
With the reactor vessel head removed and 23 feet of water above the reactor pressure vessel flange, a large heat sink is available for core cooling.
Thus,* In the event of a fall&#xb5;re of the operating AHR loop, adequate time is provided to Initiate emergency procedures to cool the care.
* 3/4.9,9 (Not Used)
* 3/4.9.10 and 3/4/9/11 WATER LEVEL-REACTOR VESSEL AND STORAGE POOL The restrictions on minimum water level ensure that sufficient water depth Is available to remove 99% of the assumed 10% iodine* gap activity*
released from the rupture of an Irradiated fuel assembly.
The minimum water depth*ls consistent with the assumptions of the accident analysis.
3/4.9.12 FUEL.HANDLING AREAVENTILATION SYSTEM *
* I , * * *
* t The operablllty of the Fuel Handling Area Ventllatlon System during movement of Irradiated fuel ensures that a .release of fission product radioactivity within the Fuel Handling Bulldlng will not exceed the guidelines and dose calculations described In-Reg. Gulde 1.183, Alternative Radiological Source Term for Evaluating Design Basis Accidents at Nuclear Power Reactors.
SALEM -UNIT 2 B 3/4 9-4 Amendment No. 245 3/4.10 SPECIAL TEST EXCEPTIONS BASES 3/4.10.1 SHTJTI>OWN MARGIN This special test.exception provides that a amount of control rod worth is immediately available for reactivity control when tests are performed for control rod worth measurement.
This special test exception is required to permit the periodic verification of the actual versus predicted core reactivity condition occurring as a result of fuel burnup or fuel cycling operations.
3/4.10.2 GROOP HEIGHT, INSERTION, AHD POWER DISTRIBUTION LIMITS This special test exception permits individual control rods to be positioned outside of their normal heights and insertion limits during the performance of such PHYSICS TESTS as those required to 1) measure control rod worth, and 2) determine
*the reactor stability index and damping &#xa3;.actor under xenon oscillation conditions.
3/4.10.3 PHYSICS TESTS 'l'his special test exception permit* PHYSICS TESTS to be performed at less than or equal to 5\ of RATBD TBBRMAL POWER with the Reactor Coolant Systelll.
Tavg slightly lower than normally allowed so that the fundamental nuclear characteristics of the reactor core and related instrumentation can be verified.
In order for various characteristics to be accurately
: measured, it is, at times, necessary to operate outside the normal restrictions of these Technical Specifications.
For inatance, to measure the moderator temperature coefficient at BOL, it is necessary to position the various I control rods at heights which may not be allowed by Specification 3.1.3.5 which may, in turn, cause the RCS Tavg to fall slightly below the minimum temperature of Specification 3.1.1.4.
3/4.10.4 NO FLOW TBSTS This special test exception pe:mita reactor criticality under no flow conditions and is required to perform certain startup and PHYSICS TESTS while at low THERMAL POWER levels. SALEM -UNIT 2 B 3/4 10-1 Amendment No. 206 3/4.ll RADIOACTIVE EFFLUENTS BASES* 3/4.11.l LIQUID EFFLUENTS 3/4.11.1.1 Deleted 3/4.11.1.2 Deleted SALEM -UNIT 2 B 3/4 11-1 Amendment No. 215 RADIOACTIVE EFFLUENTS BASES 3/4.11.l.3 Deleted 3/4.11.l.4 LIQUID HOLDOP TANKS The tanks listed in this specification include all those outdoor tanlcs that are not by liners, or walls .capable of holding.the contents and do not have t;mk overflows and surrounding area drains connected to the liquid radwaste system. SALEM -UNIT 2 B 3/4. ll-2 Amendment No. 215 RADIOACTIVE EFFLUENTS BASES Restricting the _quantity of radioacti.ve material contained
'in the specified tanks provides assurance that. in the event of an uncontrolled release of the tanks' contents, the,resulting concentrations would be less than the limits of 10 CFR Part 20, J\.ppendix B,* Table-II, Column 2, at the nearest potable water supply and the *nearest surface water supply in an UNRESTRICTED AREA * . 3/4.ll.2 GASEOUS EFFLUENTS 3/4.11.2.l Deleted SALEM a. UNIT 2 s 3./4 11-3 . *. JUnendment No. 215 RADIOACTIVE EFFLUENTS BASES . 3/4.11.2.2*
?eleted 3/4.11.2.3 Deleted SALEM -UNIT 2
* B 3/4. 11-4 Amendment No. 215*
RADIOACTIVE EFFLUENTS BASES 3/4.11.2.4 Deleted*
SALEM -UNIT 2 B 3/4 11-5 Amendment No. 215 RADIOACTIVE EFFLUENTS BASES. 3/4.ll.2.5 EXPLOSIVE GAS MIXTURE This specification is provided to ensure that the concentration of potentially explosive gas mixtures contained in the waste gas holdup system is maintained below the flammability limits of hydrogen and oxygen. Maintaining the concentration of oxygen below the specified values provides assurance'that the releases of radioactive materials will be controlled in conformance with the requirements of General Design Criterion 60 of Appendix A to lb CFR Part 50. This specification is not applicable to portions of the Waste System Removed from service for maintenance, provided that the portions removed for maintenance are isolated from sources of hydrogen and purged of hydrogen to less than 4% by.;volume.
3/4.11.3 Deleted SALEM -UNIT 2 B 3/4 ll-6 Amendment No, 243 RADIOACTIVE EFFLUENTS SAS ES 3/4.ll.4 Deleted SAI.EM -ONIT 2 *j. B 3/4 11*7 Amendment No. 215 RADIOACTIVE EFFLUENTS BASES 3/4.12 Deleted SALEM -UNIT 2 B 3/4 12-l Amendment No. 215 
-This Page Intentionally Blank .._;....*
SALEM -UNIT 2 B 3/4 12-2 Amendment No. 215.}}

Revision as of 01:12, 8 July 2018

Redirect to:

Retrieved from "https://kanterella.com/w/index.php?title=ML17046A229&oldid=838455"