ML19360A087

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Submittal of Revision 31 to Updated Final Safety Analysis Report and Technical Specification Bases Changes & Quality Assurance Topical Report, NO-AA-10, Rev. 88
ML19360A087
Person / Time
Site: Salem, Hope Creek  PSEG icon.png
Issue date: 12/05/2019
From: Duke P
Public Service Enterprise Group
To:
Document Control Desk, Office of Nuclear Reactor Regulation
Shared Package
ML19360A097 List:
References
LR-N19-0102
Download: ML19360A087 (128)
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Text

Security Related Information -Withhold Under 10 CFR 2.390 LR-N 19-0102 December 05, 2019 PSEG Nuclear LLC P.O. Box 236, Hancocks Bridge, NJ 08038-0236 United States Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001 Salem Generating Station - Unit 1 and Unit 2 0PSEG

TS 6.17.d (Unit 1)

TS 6.16.d (Unit 2)

NEI 99-04 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 Final Safety Analysis Report, Revision 31, Salem Units 1 & 2 Technical Specification Bases changes, 10 CFR 54.37(b) review results for Salem Units 1 & 2, 2018 Summary of Revised Regulatory Commitments for Salem and PSEG Nuclear LLC Quality Assurance Topical Report, NO-AA-10, Revision a*a PSEG Nuclear LLC (PSEG) hereby submits:

Revision No. 88 to the PSEG Nuclear LLC Quality Assurance Topical Report (QATR), NO-AA-10, which documents a change to the Salem/Hope Creek CD Enclosure 1, CD-1, contains Security Related Information - Withhold Under 10 CFR 2.390. When separated from CD-1, this document is decontrolled.

At53

  • a(}of 11?0 7

/J/c_/

DEC O 5 2019 Page 2 LR-N19-0102 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)

NEI 99-04 (SHC) Quality Assurance Program (QAP) in accordance with the requirements of 10 CFR 50.54(a)(3) and 10 CFR 71.106(b)

Complete updated copies of the Salem Unit 1 and Unit 2 Technical Specification Bases, which include changes through December 05, 2019, 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 A summary of regulatory commitments that were changed and not reported by other means during the time period between January 1, 2018 and November 25, 2019.

Revision No. 31 to the Salem UFSAR is being submitted in its entirety electronically via CD-ROM and contains identified text, table and figure changes required to reflect the plant configuration as of June 1'8, 2019, 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. The previous revision to the Salem UFSAR was issued on May 11, 2018.

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 31 of the UFSAR for security-related information (SRI). Consequently, Revision 31 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 10 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 information that is SRI and designates it as "Security-

. Related Information - Withheld Under 10 CFR 2.390." The version on CD-2 is suitable for public disclosure.

In accordance with the Nuclear Energy Institute (NEI) process for managing Nuclear Regulatory Commission (NRC) commitments and associated NRC notifications, PSEG performed a review of regulatory commitments to determine if there were any Salem changed/closed commitments that were not reported by other means during

DEC O 5 20l9 Page 3 LR-N 19-0102 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)

NEI 99-04 the time interval from January 1, 2018 through November 25, 2019. The review concluded that there were no changed or closed commitments during that time period.

PSEG has developed Revision 88 of 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-N 18-0053 dated May 11, 2018.

The changes to the QATR are being made in accordance with the requirements of 10 CFR 50.54(a)(3) and 10 CFR 71.106(b). The changes involved no reduction in commitments and therefore did not require prior NRC approval. 10 CFR 50.54(a)(3) requires that changes that do not reduce the commitments be submitted in accordance with 10 CFR 50.71 (e). Revision 88 is the current version of the QATR that is in use at PSEG, and became effective on June 28, 2019.

A summary of the changes made to the QATR in Revision 88 is provided in of this letter. Enclosure 2 of this letter provides a copy of Revision 88 of the QATR for information purposes. contains complete updated copies of the Salem Unit 1 and Unit 2 Technical Specification Bases with changes through December 05, 2019.

An evaluation was completed to determine whether any newly-identified SSCs existed in support of submitting Salem UFSAR Revision 31. 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 10 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 Revision 31, 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.

DEC O 5 2019 Page4 LR-N19-0102 10 CFR 50.71 (e) 10 CFR 50.54(a)(3) 10 CFR 54.37(b) 10CFR71.106 TS 6.17.d (Unit 1)

TS 6.16.d (Unit 2)

NEI 99-04 If you have any questions or require additional information, please do not hesitate to contact Mr. Lee Marabella, at_(856) 339-1208.

Sincerely, QJ_ l[l.. 2 D Paul Duke

- v--\\

Manager, Licensing PSEG Nuclear, LLC Attachments:

1. Summary Report of UFSAR Changes i/

CD

Enclosures:

1. CD-1, Salem UFSAR Rev. 31 (Withhold from public disclosure)./
2. CD-2, Salem UFSAR Rev. 31 (Redacted version suitable for public disclosure) /

Other

Enclosures:

1. Quality Assurance Topical Report, NO-AA-10, Revision 88 Summary of Changes../
2. Quality Assurance Topical Report, NO-AA-10, Revision 88,,,,-
3. Salem Nuclear Generating Station Unit 1 & Unit 2 Technical Specification Bases as of December 05, 2019

DEC O

TS 6.16.d (Unit 2)

NEI 99-04 CC (Cover letter, Other Enclosures 1, 2 and Attachment 1 only)

Administrator - Region I - USNRC Licensing Project Manager - Salem and Hope Creek - USNRC USN RC 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 (Cov~r letter, Other Enclosures 1 and 2 only)

USNRC Senior Resident Inspector - Hope Creek

{Cover letter only)

Site Compliance Commitment Coordinator Corporate Commitment Coordinator

O~t O 5 2011 Page 5 *

. LR-N19.:.0102

10 CFR 54.37(b) 10 CFR71.106

. TS 6.17.d (Unit.1)

TS 6.16.d (Unif2)

NEI 99-04

  • CC * (Cover letteri Other Enclosures 1 i 2 *and Attachment 1 only)

Administrator. - Region I - USN RC Licensing Project Manager - Salem and Hope Creek - USNRC USN RC 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 *

(Cov~r letter, Other Enclosures 1 an*d 2 only)

USN RC Seni_or Resident Inspector - Hope Creek *

(Cover letter only)

Site Compliance Commitment Coordinator Corporate COmmitment Coordinator

LR-N 1 9-01 02 Summary Report of UFSAR Changes

LR-N19-0102 S~mmary Report of Changes Page 1 of 4 Salem UFSAR Revision 31 CN#

SECT AFFECTED PAGES, TABLES DESCRIPTION BASIS

& FIGURES SCN 17-013 9.2 9.2-9 Changes to the description of how the Change reviewed and approved by Service Water flow to the CCHX is Design E~gineering. A 1 OCFR50.59 controlled.

screening !and evaluation is included in the SCN 117-013 package.

SCN 18-002 11.4,7.5 11.4-20, T11.4-3 sh2, T11.4-4 Changes made to reflect removal of Design Change package 80120796 I

sh2, T7.5-4 sh2 Radiation Monitors 1 R47 and 2R47 from instituted.: Associated 50.59 *Screening the electrical penetration area in the included ira SCN 18-002 package.

Auxiliary Building.

SCN 18-006 7.2, 7.7, 7.2-27, -28, -30, T7.2-2 sh3,

. Changes made to reflect the disabling of Design Change package 80122162

15TOC, 7.7-1, -2, -3, -5, F7.7-1, 15-xiv, automatic rod withdrawal for rod control.

instituted. I Associated 50.59 Screening is 15.2 15.2-16, -49, F15.2-11 sh 1 &2 included in the SCN 18-006 package.

SCN 18-007 9.4 9.4-1b Change reflects installation of non-safety Design C~ange package 80114076 (Unit related demineralizer skid and safety

2) instituted. Associated* 50.59 Screening related piping from #22 chilled water pump is included in the SCN 18-007 package.

discharge to the expansion tank.

SCN 18-008 4 TOG, 4.1, 4-iv, T4.1-2 sh1, 4.3-55 thru Change reflects the addition of a discussion Change reviewed and approved by 4.3, 15 4.3-63, 15-ii, 15.1-24, -25, -26, of Doppler models, PARAGON and_

Nuclear Fuels. A 1 OCFR50.59 screening TOG, 15.1, T15.1-2 sh 3 & 4, 15.3-15, -21 NEXUS. It also added new section in and evaluation is included in the SCN 18-15.3 Chapter 4.3 for pin power reconstruction and it adds a new section in Chapter 15 for 008 pack~ge.

PARAGON and NEXUS.

SCN 18-010 3.6 3.6-55 Change reflects a correction to page Change reviewed and approved by Salem missed by previously implemented SCN 15-Plant Engineering. A Fire Protection 016 and 18-003 for changing the CO2 Change Regulatory Review evaluation is system from automatic to manual in the included in the SCN 18-010 package.

diesel generator area.

LR-N19-0102 CN#

SCN 18-011 SCN 18-012 SCN 18-013 SCN 18-015 SCN 18-016 SCN 18-017 SECT 3.6 15.2 4.2 5.2 15.4 6.2, 7 TOG, 7.7, 9.4, 10.2, 11.3 AFFECTED PAGES, TABLES

. & FIGURES 3.6-50 15.2-57, -62 4.2-13 5.2-69, -70 F15.4-48, -49 6.2-79, -80, 7-vii, 7.7-12, -13, -

21a, T7.7-3 sh1, T7.7-4 sh1, T7.7-5 sh1, T7.7-6 sh1, 9.4-15,

-15a, -15b, 10.2-6a, -6b, -7, -8, 11.3-12, -13 Summary Report of Changes Salem UFSAR Revision 31 DESCRIPTION Changes reflect revision to the description of how a Moderate En~rgy Line Break postulated to occur in the Component Cooling Heat Exchanger rooms can affect the component cooling water pump motors.

Change reflects a deletion of references voided in DCP 80118856 but not removed from the UFSAR by SCN 16-017 for DCP 80118856. Added correct reference to UFSAR for PORV analysis.

Change reflects a fuel design change.

Reconstitutable Top Nozzle is replaced by Westinghouse Integral Nozzle design for RFA-2 fuel.

Change reflects a revision of the description of how intersystem leakage would be detected for the Safety Injection System.

Change reflects the Salem 2 Cycle 24 Core Reload Design.

Change reflects the relocation of requirements previously placed in the UFSAR to the TRM for various equipment.

Page 2 of 4 BASIS Change reviewed and approved by Design Engineering. A 10CFR50.59 screening ls included in the SCN 18-011 package.,

Change reviewed and approved by Design Engineering. A 1 OCFR50.59 screening ;is included in the SCN 18-012 package. :

Design C~ange package 80120891 instituted. : A 50.59 screening is included in the SC~ 18-013 package.

Change reviewed and approved by Plant Engineeril)g. A 50.59 Screening is included in SCN 18-015 package.

Design C~ange package 80120308 instituted. : Associated 50.59 Screening included irj} SCN 18-016 package.

Change r~viewed and approved by*

Design E~gineering, Plant Engineering and Radiation Protection. A 50.59 Screening is included in SCN 18-017 package.:

LR-N19-0102 CN#

SCN 18-018 SECT 10.2 SCN 18-019 5.5 SCN 18-021 15.4 SCN 19-003 Appendix 3A SCN 19-006 9.1 SCN 19-008,

13 TOC, 13.1

. AFFECTED PAGES, TABLES

& FIGURES 10.2-6b, -7 5.5-7 15.4-35 3A-12, -14, -16 T9.1-4 Sheet 2 13-i, -ii, -iii, 13.1-1 thru -12, T13.1-1 sh1, F13.1-1, -2, -3, 4

Summary Report of Changes Salem UFSAR Revision 31 DESCRIPTION Change reflects an alternative to specific actions for the Turbine Overspeed Protection System provided the plant is not in an unanalyzed condition. The actions were relocated from Unit 1 and 2 Technical Specifications by amendments 224 and 205.

Change reflects the replacement of the RCP Seal No. 1 with Sigma Seal. Seal replacement is being performed over multiple outages.

The change revises the description of single-failure considerations within the analyses to eliminate reader confusion.

Change reflects a revision to the requirement of Ferrite content in austenetic weld filler materials and the adoption of Reg Guide 1.31 Revision 4.

Changes reflect a correction to containment bulding equipment hatch weight Change reflects removal of information concerning organization structure and reporting relationships. This information is duplicated in the QATR or is considered excessive detail that is not important to provide an understanding of the plant's design and operation.

Page 3 of 4 BASIS Change re:viewed and approved by Plant Engineering. A 50.59 Screening is included in SCN 18-018 package.

Design Change package 80122692 instituted. A 50.59 screening is included in the SCN 18-019 package.

Change reviewed and approved by Nuclear F~els and Reactor Engineering.

A 50.59 Screening is included in the SCN 18-021 papkage.

Change r~viewed and approved by Design En:gineering. Associated 50.59 Screeningi included in SCN 19-003 package..

Change reviewed and approved by Reactor Engineering. A 50.59 Screening is includetj in the SCN 19-006 package.

Change reviewed and approved by Human Resources and Nuclear Oversight.: A regulatory review form for a non-regul~tory change is included in the SCN 19-0p8 package.

LR-N19-0102 CN#

SECT SCN 19-009 9.2 SCN 19-011 9.1 SCN 19-012 9.1 SCN 19-013 Appendix B AFFECTED PAGES, TABLES

& FIGURES 9.2-8 T9.1-4sheet6 T9.1-4 sheets 4 & 5 B-32 Summary Report of Changes.

Salem UFSAR Revision 31 DESCRIPTION Change reflects a correction to clarify the SWIS sump pump capacity description.

Change reflects a revision to the Service Water Pump weight.

Change reflects an update to the Heavy Load Weight and Maximum Safe Lift Height for Recipricating Charging pump coupling and crane capacity.

Change reflects an update of the acceptance criteria for pH values for the SFP teltale and seismic gap.

Page 4 of 4 BASIS Change re,viewed and approved by Plant Engineeri~g. A 50.59 Screening is included iri the SCN 19-009 package.

Design Change package 80122526 instituted. ;Associated 50.59 Screening included in the SCN 19-011 packa~e.

Change r~viewed and approved by Reactor Epgineering. A 50.59 Screening is included in the SCN 19-012 package.

Change r~viewed and approved by Programs !Engineering. A 50.59 Screening! is included in the SCN 19-013 package..

For the worst case scenario, six sprinkler heads are assumed to supply approximately 393 gpm to suppress the fire.

Flow restrictors (orifices) were added to the two drains in the room to prevent drain flow from exceeding the sump tank overflow line capacity, thus precluding flooding of other rooms on the 64 ft elevation due to backflow through the interconnected floor drains.

Area 3 - Electrical Penetration Area - Elevation 78 Feet This area contains only the fire protection preaction sprinkler piping which is similar to that installed in the 64 ft switchgear room that replaced the CO2 fire suppression system.

In a fire, the pressurized air that is in the line between the deluge supply valve and the closed sprinkler heads is released by the melting of a fusible link that opens the deluge valve when other electric alarm signals have been received.

When the deluge valve opens the dry preaction sprinkler piping is charged with water.

The backpressure provided by the 20 psig air that is maintained in the dry preaction system piping helps prevent the occurrence of water hammer in the preaction system when the deluge valve opens.

CJnder the assumed worst case conditions, the preaction system can supply approximately 382 gpm flowing to six sprinkler heads to suppress a fire.

Because the existing 4-inch drain in the room is capped due to HELB considerations, a new 4-inch drain was added that empties to the RHR valve room on the 55 ft elevation.

Check valves in the drain lines prevent backflow interaction with the two new drains added to 84 ft switchgear room that also empty to the RHR valve room.

The drainage from the 84 ft switchgear room and the 78 ft elevation electrical penetration room combine and empty into the RHR valve room and from there drain to one RRR pump room on the 45 ft elevation.

Areas 4*, 5, and 6 -

Rod Control Reactor Trip Breakers and Miscellaneous 460 V Vital Electrical Gear - Elevation 84 Feet Curbing at access points into these~~reas has been provided to prevent flooding from adj a cent areas.

The 4 60 V switchgear room on the 84 ft elevation also replaced the CO2 fire suppression system with an automatically initiated, interlocked, preaction sprinkler system that was designed and installed per the requirements in NFPA 13 (2002 Edition).

The preaction sprinkler system in the 460 V switchgear room operated the same as those in the 4160 V Switchgear Room and in the Electrical Penetration Room.

3.6-49 SGS-CJFSAR Revision 25 October 26, 2010

The* fire protection pip.ing *within the 4 60 V switchgear room meets Seismic Category I requirements.

The fire protection ' tie-ins to the 6-inch fire protection header and isolation valves located outside the room in.the hallway on the 84 ft elevation meet Seismic II/I requirements.

There.are *two.existing 4-inch floor drains in the hallway that drain to the waste holdup tanks on the 64 -ft elevation.

Two new 4-inch drains were added to remove water.from the switchgear room should the *sprinkler system discharge in the event of a fire.

Assuming the worst-case scenario, six sprinkler heads in a tight area grouping would discharge 379 gpm in the event of a fire in the room.

The drain lines, which are open-ended and equipped with check valves to prevent backup, empty to the RHR valve room on the 55 ft elevation.

From there, the water drains via an existing floor drain to a RHR pump room sump pit on the 45 ft elevation.

With flooding of one RHR pump room that could potentially incapacitate one RHR pump, the other RHR pump located in the adjacent, separate, non-flooded RHR pump room would be available.

No other design basis accidents are postulated to occur coincidental with a fire.

However, switchgear room fires may result in the loss of both onsite and offsite power to the vital buses, which could result in a total loss of the RHR system, making it temporarily unavailable for providing decay heat removal.

Safe shutdown for Salem is defined as hot standby.

Existing procedures identify repairs to, the components that are required for establishing one RHR loop as necessary for achieving cold safe shutdown.

In addition, Appendix R provides for remote cabling of ei the_r RHR pump in the event of a fire.

However, the maximum flood level in the RHR pt;JJ.[lp.:*,:r:oom:: 30 minutes after actuation of one of the preaction sprinkler systems added to the switchgear rooms and the-el*ectrical penetration room is calculated to be less than 13 inches, which is well below the elevation of an RHR pump.

Area 7 - Safety Injection Pump Room - Elevation 84 Feet

  • This area contains MEL piping.. Floor drainage capacity however is adequate to prevent flooding* of the comp._artment.

Water spray

  • from service water or demineralized water piping could affect safety injection. pump *motors, The safety injection pump motors have been protected from overhead spray by means of a protective shroud.

Area 8 -

Component Cooling Heating Exchanger Rooms -Elevation 84 Feet This area contains service water and fire protection MEL piping.

Floor drainage capacity in the area is adequate to prevent flooding.

Water spray from service water pipe cracks could affect 22 or 23 component cooling pump motors and associated controls, dependent on the crack location.

3.6-50 SGs.:...oFSAR Revision 31 December 5, 2019

In the unlikely, event that one of the larger.tanks without a dike or berm were to drain its contents, most likely due to operator error, the resulting flood would spread out over an extensive floor area in the Auxiliary Building which would limit the flood height and preclude damaging safe shutdown equipment.

The waste holdup, waste* monitor-holdup,. and *evaporator bottoms storage tanks are diked to contain the volumes within the tank area*.

The monitor tanks are not diked, but the failure of any of these tanks would not' cause flooding serious enough to prevent Cla$s I

( seismic).. safety-related equipment from operating satisfactorily.

Aside from floor drainage systems, stairwells, and floor openings would prevent water from rising to levels that could be termed critical; A similar investigation showed that equipment arrangement and floor drainage systems design are adequate to. pr~vent flooding

  • in the. event of a non-.Class I (seismic) pipe rupture serious enough to prevent safeguards systems from operating satisfactorily.

Fire Protection pipe systems have been demonstrated.to*be adequately supported to withstand seismic events without structural pipe*failure.

Nitrogen.and hydrogen storage cylinders are located in the Auxiliary Building.

Ruptures will* not. jeopardize the requ;Lred operation of a Class I (seismic)

system, since the tanks, located at Elevation 122 feet *in corridors. to the north and south of the drumming and baling area, are isolated from Class* I (seismic) equipment by virtue of their location, as well as by concrete walls.

Supplementing the Public Service Electric & Gas 1972 ' (response to Mr. R.

C.

De Young's letter (PSE&G) letter of November 2, of September 2 6, 197 2),

the failure of carbon dioxide fire protection *equipment will.not affect operation of safeguards systems.

  • Manual systems are provided in the diesel-generator areas.

Manual carbon dioxide fire protection equipment *. is provided in the control and relay room areas.

SGS-UFSAR 3.6-55 Revision 31 December 5, 2019.

3. _6, 5.14 Electrical Cable Environmental Qualifica.tion All electrical cable types which are used *tor *safety-related equipment in areas subject to *adverse environmental conditions from pipe ruptures.have been qualified for continued operation "in these environments.

Qualification tests consisted of ~xposure of the cable samples to thermal aging (e.g. 250°F for 7 days) radiation exposure (e.g. 100 x 10 6 R equivalent air dose with a Co 60 source), and* cyclic steam and.chemical spray (e.g. 340°F, 105 psig steam, Boric Acid and Sodium Hydroxide, cycled for 14 days).*

Testing after exposure showed no significant detrimental change in insulation resistance, insulation dielectric. breakdown capability1 or cable strength

  • and ductility parameters.

3.6.6 References for Section 3.6

1.
Letter, A.

Giambusso (AEC) to F.

w.
Schneider (PSE&G),

dated December 18, 1972, with attachment "General Information Required for Consideration of the Effects of a

Piping System Break Outside Containment," Letter, D. B,;,Vassall.o (AEC) to F. W. Schneider (PSE&G),

dated January 31, 1973, with attachment "Errata Sheet for 'General Information Required for Consideratior1 of the Effects of a Piping System Break Outside Containment.'"

2.
3.
4.
5.
6.
7.
Griffith, A.

A,,

"The Phenomena of Rupture and Flow Solids,*;,

Philosophic Transact.ions a_~ th_e Royal Society of London, Vol. 221, pp.

. 163:...198, 1920.

Letter, R. C. De Young (AEC) to F. W. Schneider (PSE&G), dated May 21, 1973.

Branch Technical Position.. MEB 3-1, "Postulated Rupture Locations in Fluid System Piping Inside and Outside Containment," attached to SRP Section 31 6.2, Rev._ 2, June 1987.

Branch Technical Position SPLE 3-1, "Protection Against Postulated Piping Failures in Fluid Systems Outside Containment," attached to SRP Section 3.6.1, Rev. 2, October 1990.

Letter from Mr. James C. Stone, NRC, to Mr. Steven E. Miltenberger, PSE&G, dated May 25, 1994, "Leak-Before-Break Evaluation of Primary Loop Piping, Salem Nuclear Generating Station, Units 1 and 2".

EPRI TR-1006937 "Extension of the EPRI Risk Informed ISI Methodology to Break Exclusion Region Programs," April 4, 2002.

3.6-56 SGS-UFSAR Revision 25 October 26, 2010

which were prior to the inc:eption of the NRC' s quality group classification system.

The-Regulatory Guide was not issued until March 1972, at which time construction was well underway.

The codes and standards which were used are presented in the appropriate sections of the FSAR.

Regulatory Guide 1.27 -ULTIMATE HEAT SINK (Revision 2)

The Salem Station design generally conforms with the intent of the Regulatory Gui:de ( FSAR Section 9.. 2).

Regulatory Guide 1. 28 :-

QUALITY ASSURANCE PROGRAM REQUIREMENTS (DESIGN AND CONSTRUCTION)

Salem Generating Station is committed to the requirements of NQA:_1-1994 for Quality Assurance Program requirements.

Regulatory Guide 1.29 -.SEISMIC DESIGN CLASSIFICATION, 8/73 The* Salem Station design conforms to the intent of

  • the Regulatory Guide.

Previously, the only area of non-conformance with the Regulatory Guide was in the classification of the Spent Fuel Pool Cooling (SFPC)

System. SFPC piping and pipe supports are analyzed as seismic class I.

SFPC components have been seismically evaluated under SQUG GIP methodology..

The basis for this classification is provided in Section 9.1.

Regulatory Guide 1.30 -

QUALITY ASSURANCE REQUIREMENTS FOR THE INSTALLATION, INSPECTION, AND TESTING INSTRUMENTATION AND ELECTRIC EQUIPMENT, 8/72 (endorses N45.2.4)

The Salem Station design conforms with the intent of the Regulatory* Guide.

3A-ll SGS-UFSAR Revision 23 October 17,.2007

Regulatory Guide 1.31 -

CONTROL OF FERRITE CONTENT IN.STAINLESS STEEL WELD METAL.PRIOR TO-REVISION 4 The Regulatory Guide states that-weld deposits should_contain;between 5-and 12 to 15 percent delta ferrite.

I:t.is not practical-to.. specify." abs_olute minimum'-'_

or even maximum delta ferrite 1~ ts as a basis for acceptance or.: rej ectiqn: of_

otherwise acceptable austenitic stainless steel welds.

Westinghouse places control on the actual wire analysis for inert gas welding.

processes and on the final weld deposit for the fluxing weld process.

In the case of the bare wire, when used with inert gas processes, although the wire may contain 5 percE!_nt ferrite, only about 1 or 2 percent ferrite will be developed in the resultant weld deposits.

This is not the case in fluxing processes such as when using coated arc electrodes o_r submerged arc, since the flux is enriched with additional ferrite fo~ers resulting in_ higher ferrite contents in the resultant weld deposits. Similarly, the amount of ferrite that may exist in any given weld will vary. across the width of the weld deposit depending upon the base materials being joined.

For example, when fully austenitic wrought product is welded, the interface regions will be practically zero percent ferrite because of the resultant base metal dilution, but it will progressively increase toward the weld centerline.

Conversely, when a two-phase (austenitic +

ferrite) cast product which norrn;;;_lly **'*contains over 15 percent ferrite is welded, the interface region will be high in delta ferrite content depending upon the amount* of delta ferrite available and diluted from the casting base material.

The ferrite distribution in a

  • weld *will also vary depending upon the weld position. -

0That is: in areas of the downhand and horizontal position, weld deposit ferrite wili be the :highest; :whereas,* in the verticai and overhead position~ weld deposit 3A-12 SGS-UFSAR Revision 31 December 5, 2019

ferrite will be.the lowest ~in a

gi"izen weld because of different welder manipulations necessary.to over.come eff1:=cts: of gravi_ty.

In addition, types-310 and 330 weld materials a:re always fully austenitic, yet sound welds are being made every day with these alloys using fine tuned welding procedures.

Also, welds are being made wi thotit the u~fe of filler metal, such as electron beam welds and autogeneous gas shie'lded tungsten arc welds.

Furthe*rmore, the limits* as set are arbitrary' because various methods used to measure the percentage of delta lerrite yield widely differing results.

The Welding Research Council has recognized this situation and have an organized approach which may result in an acceptable solution.

The basis for classifying the low, medium, and high enetgy input ranges is nqt given in the Regulatory Guide.

Using the* Westinghouse conservative welding procedure parameters, the following energy inputs are being 'applied to produce high quality welds*.

They are:

1.

SMAW 15.4 to 95 kJ/in. using 1/16 to 3/16 dia electrodes

2.

GTAW 2.16 to 32.5 kJ/i~. using.03 to 1/8 dia wires

3.

GMAW 46 to 55 kJ/in. using.03 to 1/16 dia wires

4.

SAW 74 to 79 kJ/in. using.09 to 1/8 dia wires Westinghouse has a large amount of evidence showing that the above energy input raI).ges produce fissure-free weldments in both ~hop a;nd onsite w~lding._

Westinghouse doe;,s not require. in-proces.s delta.. ferrite determination.

Whe.n tl)e welding material is tested (in accordance with t1:.~, r.equirements of.. _

ASME Section III, NB2430, and includes delta ferrite determinations),

sound welds displaying more than one 3A-13 SGS-UFSAR Revision 6 February 15, 1987

percent average delta ferrite content by any agreed method. of.determination will be considered unquestionable.

All other,sound w.elds which ~isplay less than 1 percent average delta ferrite will be considered acceptable provided there is no evidence of malpractice or deviation from procedure parameters.

If evidence of. the latter prevails~... sampling will be required to determine the acceptability of the welds.

The sample size shall be 10 percent of the welds in the system or component.

If any of th.ese weld samples are defective, that is, fail to pass bend tests as described by ASME,Section IX, all remaining welds shall be sampled and all defective welds shall be removed and replaced.

Field welding of the nuclear steam supply system and other nuclear class components is performed using Public Service Electric and Gas (PSE&G) welding procedures.

In some areas of austenitic stainless steel welding, these procedures call for use of the 16-8-2 electrode.

This particular electrode composition _was developed to provide fissure-free welds in au'steni tic systems withou_t reliance on ferrite content, which is generally limited to 3 percent, and frequently the amount is less than 1 percent.

Therefore, ferrite control and determination, which comprise the bulk of the Regulatory Guide, are not considered applicable to the 16-8-2 welding electrode.

The 16-8-2 welding electrode was initially developed for service temperatures where delta ferrite exhibits a tendency to transform into the sigma phase, and ernbrittling condition in austenitic stainless steel.

Service temperatures at the Salem Station are too low to support a need for this '.type of protection, but PSE&G' s long :Service* history 0Wi th this welding composition ( since 1955) in steam.. piping systems. has provided a level of confidence and. expertise which overrides the consideration* of alternate materials.

Service -a:nd inspection records show that numerous welds* have' been performed *satisfactorily in high pressure steam service temperatures up to 1100°F for operating times exceeding 150,000 h~urs.in the PSE&G generating sy~t~:ms.

Regulatory Guide 1.31 -

CONTROL OF FERRITE CONTENT IN STAINLESS STEEL WELD METAL REVISION 4, OCTOBER 2013 Salem Generating Station adheres to Revision 4 of Regulatory Guide 1.31.

Per this revision of the regulatory guide, ferrite content in the weld metal as depicted by a ferrite number (FN) of weld metal used for welds in austenitic stainless steel core support structures, reactor internals, and class 1, 2 and 3 components should be between 5 and 20.

The lower limit provides sufficient ferrite to avoid microfissuring in welds, whereas the upper limit provides a ferrite content adequate to offset dilution and reduce thermal aging effects..

3A-14.

SGS-UFSAR Revision 3],.

December 5, 2019

PSE&G welding* and inspection practices comply with the,intent of the Regulatory Guide and Appendices A and B to:10CFR50 in the following manner:

1.
  • strict control is maintained over electrode chemistry and Identification for procedure qualification, welder qualification, and production welding.

This is accomplished through purchase specifications, certified mill test

reports, segregation of untested lots from approved lots, locked storage of welding supplies on site, recorded allocation of electrodes to welders, and maintenance of lot identity from site receiving to completed weld joint.
2.

The weld procedure qualification demonstrates the capabiiity of

3.
4.

producing welds free from unacceptable fissuring.

This includes visual examination of procedure qualification bend bars and macrotech specimens with the unaided eye and under 10 power magnification.

Welder performance qualification bend bars, when made, are examined in the same manner to verify that the welder's technique maintains freedom from unacceptable fissures.

Welds. for nuclear clas.s systems are subjected _to a liquid penetrant a.nd radiographic examination. where required. Heavy wall wel:is, such as in the reactor coolant piping, are subj ect~d to in~prqces s__

examinations by a liquid penetrant and radiography at one or more intermediate stages in the. welding out of the groove.

5.

Ferrite content for each lo_t of austenitic stainless steel electrode is qualified by magnegage measurements of a test weld pad.

For nucle.ar plant welds, ferrite 3A-i5 SGS-UFSAR Revision 6 *'

February 15, 1987

I outside the range of 5FN to 20FN for E-308, E-309, and E-316 is considered rejectable.

6.

Production welding par_a:rµeters. are monitored on a spot-che_ck basis by the field welding supervision-and the Field Q1.1ality Control*Grou..p.

Regulatory Guide 1. 32 -

USE OF IEEE STANDARD 308-1971, "CRITERIA FOR CLASS lE.

ELECTRIC SYSTEMS FOR 'NUCLEAR POWER "GENERATING STATIONS" The Salem Station design satisfies the requirements of IEEE Standard 308-1971, with the exception that Class 1 diesel fuel oil.storage capacity provides less than seven days of diesel operation under worst case loading.

See Section

9. 5. 4 for a description of how long term Emergency Diesel _generator fuel oil storage requirements are met.

Regulatory Guide. 1.33 -

QUALITY ASSURANCE PROGRAM REQUIREMENTS (OPERATION),

2/78 (endorses NlS,7-1976/ANS 3.2),,

The Salem Generating Station is committed* to the

  • requirements of NQA-,-1-,-.1994.

See the Quality Assurance Topical Report, Appendix C, Section 1. 3. 2. 3 for further discussion.

Regulatory Guide 1.34 -

CONTROL OF *ELECTROSLAG WELD PROPERTIES Electroslag welding of Nuclear Classes 1 and 2 components is confined to the area of reactor _coolant piping elbows.

These are made from cast clamshells of ASTM A.351 Gr. CF-SM joined together*' <m longi t:udina~ seams by the electroslag process.

Welding of these components was procedure control moni tared by Westinghouse.

p~rJormed under specified. weld

, PSE&G also e~tablished that the shop produc*tion welds were :in conformance.to the procedure* qualificati-.on.

3A-16 SGS-UFSAR.-

Revision 31..

December 5~ 2019

section 4.3.* 2.2.3 4.3.2~2.4 4.3.2.2.5 4.3.2.2 *. 6 4.3.2.2.7.

4.3.2.2.B 4,3.2,2.9 4.3.2.3 4.. 3.2. 3.1 4.3.2.3.2 4.3.2.3.3 4.3.2.3.4 4.3.2.3.5 4.3.2.4 4.3.2.4.1 4.3.2.4.. 2 4.3.2.4.3 4.3.2,4.4 4.3.2.4.5 4.3.2.4.6 4.3.2.4.7 4.3.2,4.B 4.3.2.4.9 4.3.2,5 4.3.2.S.1 4.3.i.5.2

  • 4.3,2,5.3 4,3,2.5.4 4.3.2.s.s SGS"".'UFSAR TABLE OF CONTENTS (Cont}

Assembly Powe*r Distribution

. Axial* Power Distribution*

Deleted

. Limiting_ Power Distributiori_

  • E~erilnental Verificaj:icn of Power Distribution Analysis Testing.

Monitoring Instrumentation Reactivity Coefficients ruel Temperature (Doppler) Coefficient

  • *Modera-tor Coefficients Power Coefficient comparison of Calculated and Experimental Reactivity Coefficients Reactivity Coefficients Used in Transient
  • Analysis control Requirements
  • Doppler varis.J:,le Average Moderator Temperature Redistribution void content Rod Insertion Allowance eurnup Xenon and Samarium Po~soning pH Effects Experimental Confirmation control chemical Poison Roa Cluster Control Assemblies Burnable Absorbers peak Xenon Startup

,*.}

Load Follow Control and Xenon*Control 4-lii 4.3-17

4. 3-17 4.3-18 4.3-20 4.3-26 4,3-29 4.3-29 4.3-30 4, 3-30*

4.3-31 4.3-34 4.3-34 4,3-35 4,3-35 4.3-36 4.3-36

  • 4.3-37 4.3-37 4.3-37 4.3-38 4.3-38 4.3-38 4.3-39
4. 3..:.39 4.3-39
4, 3-40 4,3*41 4.3-41 4,3-42 Rev is ion l ;* *..

October 16, 1998

Section 4.3.2.5.6 4.3.2.6 4.3.2.7 4.3.2.8 4.3.2.8.1 4.3.2.8.2 4.3.2.8.3 4.3.2.8.4 4.3.2.8.5 4.3.2.8.6 4.3.2.9 4.3.3 4.3.3.1 4.3.3.2 4.3.3.3 4.3.3.4 4.3.4 4.4 4.4.1 4.4.1.1 4.4.1.2 4.4.1.3 4.4.1.4 4.4.1.5 4.4.2 4.4.2.1 4.4.2.2 4.4.2.2.1 SGS-UFSAR TABLE OF CONTENTS (Cont)

Title Burnup Control Rod Patterns and Reactivity Worth Criticality of Fuel Assemblies Stability Introduction Stability Index Prediction of the Core Stability Stability Measurements Comparison of Calculations with Meas_uremen ts Stability Control and Protection Vessel Irradiation Analytical Methods Fuel Temperature (Doppler) Calculations Macroscopic Group Constants Spatial Few-Group Diffusion Calculations Pin Power Re9onstruction References for Section 4.3 THERMAL AND HYDRAULIC DESIGN Design Bases*

Departure Fr:om Nucleate Boiling Design Basi_s Fuel Temperature Design Basis Core Flow Design Basis Hydrodynamic Stability Design Bases Other Considerations Description Summary Comparison FU:el Cladding Temperatures (Including Densification)

Uranium Dioxide Thermal Conductivity 4-iv 4.3-42 4.3-42 4.3-45 4.3-46 4.3-46 4.)-4 6 4.3-47 4.3-48 4.3-50 4.3-51 4.3-52 4.3-53 4.3-54 4.3-55 4.3-58 4.-3-60 4.3-60 4,4-1 4.4-1 4.-4-2 4.4-2a 4.4-3 4.4-4 4.4-4 4.4-5 4.4-5 4.4-7 4.4-9 Revision 31 December 5, 2019

TABLE 4.1-2 ANALYTIC TECHNIQUES IN CORE DESIGN Analysis Mechanical Design of Core Internals Loads, Deflections, and Stress Analysis Fuel Rod Design Fuel Performance Characteristics (temperature, internal pressure, clad stress, etc.)

Nuclear Design _

1) Cross Sections and Group ;

Constants

2) X-Y and X-Y-Z Power*

Distributions, Fuel Depletion, Critical Boron ~oncentrations, x-y and X-Y-Z Xenon Distributions, Reactivity Coefficients

3) Axial Power Distributions Control Rod Worths, and Axial Xenon Distribution SGS-UFSAR Technique Static and Dynamic Modeling Semi-empirical thermal model of fuel rod with consideration of fuel density changes, heat transfer,_ fission gas release, etc.

Micr6scopic data Macroscopic constants for homoganized cor~

regions Group constants for control rods with self-shielding 2-Group Diffusion Theory_

1-D, 2-Group Diffusion Theory 1 of 2 Computer Code Section Referenced Blowdown code, FORCE, Finite element structural analysis code, and others Westinghouse fuel rod design model Modified ENDF/B library LEOPARD/CINDER type or PHOENIX-P

  • HAMMER-AIM or PHOENIX-P PARAGON or NEXUS TURTLE (2-D) or ANC(2-D or 3-D)

PANDA or APOLLO 4.2.1.3.1 4.3.3.1

4. 4. 2. 2 4.'4.3.4.2 4.3.3.2 4.3.3.2 4.3.3.2 4:3.3.2
4. 3. 3. 3
4. 3. 3. 3 Revision 31 December 5, 2019

hole in the nozzle plate to facilitate attachment and nozzle plate thickness is reduced to provide additional rod growth.

Additional details of this design feature, evaluation of the reconstitutable top nozzle are given Reference 15.

removal, and; 2) the axial space for fuel the design bases and in Section 2. 3. 2 in The square adapter plate is provided with round and obround penetrations to permit the flow of coolant upward through the top nozzle.

Other round holes are provided to accept sleeves which are welded to the adapter plate and mechanically attached to the thimble tubes.

The ligaments in the plate cover the tops of the fuel rods and prevent their upward ejection from the fuel assembly.

The enclosure is a sheet metal shroud which sets the distance between the adapter plate and the top plate.

The top plate has a large square hole in the center to permit access for the control rods and the control rod spiders.

Holddown springs are mounted on the top plate and are fastened in place by screws and clamps located at two diagonally opposite corners.

The clamps are attached to the nozzle by a specific arrangement of tack welds or tack weld ( s) in combination with a stainless steel. clamp screw, depending on the manufacturing process in place at the time a given fuel region was built.

The spring screws apply a load directly to the base of the hold-down springs.

The clamps do not have any bearing surfaces that load the spring to the nozzle, but primarily provide a stationary location for attachment of lock wires that prevent rotation of the spring screws.

On the other two corners, integral pads are positioned which contain alignment holes for locating the upper end of the fuel assembly.

Salem Units 1 and 2 later implemented the Westinghouse Integral Nozzle (WIN) design in RFA-2 fuel assemblies.

The WIN design, while similar to the RTN, incorporates design and manufacturing improvements to eliminate the Inconel 718 spring screw for attachment of the holddown springs.

In the WIN nozzle, the springs are assembled into the nozzle pad and pinned in place.

The WIN design provides a wedged rather than a clamped (bolted) joint to transfer the fuel assembly holddown forces into the top nozzle structure.

A replacement reconstitutable top nozzle (RRTN) design may be used in a reload cycle to replace the original reconstitutable top nozzle (RTN) or the WIN on I an irradiated fuel assembly. The mechanical features of the RRTN are the same as those for the RTN (see Figure 4.2-2) or the WIN with some minor dimensional differences in the top nozzle adapter plate thimble hole to facilitate attachment to an irradiated fuel assembly. The RRTN design contains hold-down springs and screws made of Inconel 718, whereas, other components are made of Type 304 stainless steel.

Guide and Instrument Thimbles The guide thimbles are structural members which also provide channels for the neutron absorber rods, burnable poison rods, or neutron source assemblies. Each one is fabricated from Zircaloy-4 or ZIRLOTM tubing having two different diameters.

The larger diameter at the top provides a relatively large annular area to permit rapid insertion of the control rods during a reactor trip as well as to accommodate the flow of coolant during normal operation.

Four holes are provided on the thimble tube above the dashpot to reduce the rod drop time.

The lower portion of the guide thimbles has a reduced diameter to produce a dashpot action near the end of the control rod travel during normal operation and to accommodate the outflow of water from the dashpot during a reactor trip.

The dashpot is closed at the bottom by means of an end plug which is provided with a small flow port to avoid fluid stagnation in the dashpot volume during normal operation.

The top end of the guide thimble is fastened to a tubular insert by three expansion swages.

The insert engages into the top nozzle and is secured into position by the lock tube.

The lower end of the guide thimble is fitted with an end plug which is then fastened into the bottom nozzle by a locked screw.

4.2-13 SGS-UFSAR Revision 31 December 5, 2019

Fuel rod support grids are fastened to the guide*. thimble assemblies to create an integrated structure.-

Since welding of the Inconel grid.,and Zircaloy thimble is not possible; *the fastening technique depicted on Figures 4. 2-5 and 4.2-9 is used for all but the top and bottom grids in a fuel assembly.

An expanding tool is inserted into-the inner diameter of the Zircaloy or Zirlo TM thimble tube to the elevation of the zircaloy sleeves that have been welded to the Zircaloy middle grid assemblies.

The four-lobed tool forces the thimble and sleeve outward to a

predetermined

diameter, components.

thus joining the two The top grid-to-thimble attachment for the Vantage SH, Vantage+, and RFA design is shown on Figure 4. 2-7..

The Zircaloy or ZIRLo' thimbles are fastened to the top nozzle inserts by expanding the members as shown on Figure 4. 2-7.

The inserts then engage the top nozzle and are secured into position by the insertion of lock tubes.

The bottom grid assembly i*s joined to the fuel assembly as showri on Figure 4. 2-

11.

The stainless ste~l insert* is spot welded to the bottom grid *and later captured between the guide thimble end plug and the bottom nozzle by means of a stainless steel thimble screw.

The described methods. of gri~_ f~st~ning. are standard and have been used successfully since the introduction of Zircaloy guide thimbles in 1969.

The

  • central instrumentation thimble of each* fuel assembly is constrained by seating in counterbores in each nozzle.

'This tube is a constant diameter and

_guides the incore neutron detectors.

  • This thimble is expanded at the top_ and mid grids in _the same manner as. the J;)revi_ously _discussed expansion of the guide

.thimbles to the grids.

4.2-13a SGS-UFSAR Revision 18 April 26, 2000

The effective pellet temperature for pellet dimensional change is that value which produces the same outer;-pellet radius in a virgin pellet as that obtained from the temperature model.

The effective clad temperature for dimensional change is its average value.

The temperature calculational model has been validated by plant Doppler defect data as shown in Table 4.3-6 and Doppler coefficient data as shown on Figure 4. 3-32.

Stability index measurements also provide a sensitive measure of the Doppler coefficierit near full pciwer (see Section 4.3.2.8).

It can be seen that Doppler defect data is typically within 0.2 percent ~p of prediction.

ALPHA/PHOENIX/ANC has two Doppler models -

a Doppler power model and a Doppler temperature model. The default Doppler model in APA is the temperature model and is based on a fit of fast absorption cross sections against the fuel temperature at 0, 1,

and 2. times the reference power.

In NEXUS/ANC9, the effects of fuel temperature are captured on all the cross sections directly, as it is one of the fundamental parameters used to fit cross sections.

4.3.3.2 Macroscopic Group Constants There are lattice codes which have been.used for the generation of mac,roscopic group constants needed in the spa_tial, few-group diffusion codes. One is a version of the LEOPARD and CINDER codes, which has historically been the source of the macroscopic group constants.

The others are PHOENIX-P.

  • and PARAGON, which are used in present reload designs (Reference 30 and 38).

The NEXUS methodology (Reference 39) is a reparameterization of the PARAGON nuclear data output.*

The NEXUS methodology provide*s* *a*'. linkage* between PARAGON.and ANC, establishing a new code system, while.still using PARAGON.

Macroscopic few-group constants and. analogous microscopic cross sections (needed.for feedback and microscopic depletion calculations) were previously generated for fuel cells by a version of the LEOPARD (Reference 15) and CINDER

.. (Reference 16) codes, which are linked internally and provide burnup dependent cross sections.

Normally a simplifi~d approximation of the main fuel chains is used;

however, where needed, a

complete solution for all the significa.nt isotopes in the fuel chains from Th-232 to Cm-244 is available (Reference 20).

Fast and thermal cross section library tapes contqin microscopic cross sections taken for the most part from the ENDF/B (Reference 21) library, with a few exceptions where other data provide better agreement with critical experiments, isotopic measurements, and plant critical boron values.

The effect on the unit fuel cell of non-lattice components in the fuel assembly is obtained by supplying an appropriate volume fraction of these materials in an extra region which is homogenized with the unit cell in the fast (MUFTI and thermal (SOFOCATE) flux calculations.

In the thermal calculation, the fuel rod, clad, and moderator are homogenized by energy-dependent disadvantage factors derived from an analytical fit to integral transport theory results.

4.3-55 SGS-UFSAR Revision 31 December 5, 2019

Group constants for discrete..

  • burnable absorber*

c!:'!lls, guide

thimbles, ipst;rument thimbles, and interass.embly gaps are g~nerated in a manner analogous to the* fuel cell calculation.
  • Reflect.or* group,constants are taken from infinite medium LEOPARD calculations.

Baffle-group. constants are calculated from an average of core and radial. reflector... microscopic group constants for stainless steel.

Group constants for control rods are calculated in a linked version of the HAMMER (Reference 22) and AIM (Reference 23) codes to provide.an improved treatment of self shielding in the broad resonance structure of these isotopes at epi thermal energies than is available in LEOPARD.

The Doppler broadened cross sections of _the control rod materials are repres-ented as smooth cross sections in the 54-group LEOPARD fast group structure an~ in 30 thermal groups.

The four-group constants in the rod cell and appropriate extra region are generated in the coupled space-energy transport HAMMER calculation.

A corresponding AIM calculation of the homogenized rod cell with extra region is used to adjust the absorption cross sections of the rod cell to match the reaction rates in HAMMER.

  • These transport-equivalent group constants are reduced to two-group constants* for use in space-dependent diffusion calculations.

In discrete X-Y calculations only one mesh interval per cell is used, and the rod group constants*are further adjusted' for use in this standard mesh by reaction rate matching the slandard mesh unit assembly to a fine-mesh unit assembly calculation....

Validation of the cross section method is based on analysis of critical experiments as shown in Table 4. 3-7, isotopic data as. shown in.. Table. 4. 3-8, plant critical boron (CB) -. values -at- *HZP, BOL, as shown in Table. 4. 3-:9 and at

.HFP. as a fun~tfon of b~rnup ~:s shown on Figure~ 4. 3-33. through 4. 3-35. ** Control rod worth measurements are shown in Table 4.3-10.

Confirmatory critical experiments on discrete burnable absorbers are* described in Reference 24.

PHOENIX-P has.. been approved by the *usNRc<a*s a lattice code for the generation of macroscopic and microscopic* few group -cross sections for PWR analysis (Reference 30).

. PHOENix...,p. is. a. two-dimensional, _multigroup, tran*sport'-based lattice code capable* of providing all nece*ssary data for PWR analysis.

  • Since it is a dimensiona-1 lattice code, PHOENIX.,-P does not rely on predetermined spatial/spectral.interaction assumptions for the heterogeneous fµel lattice. and can provide a

more accurate mul tigroup flux sol:uti'on than versions of LEOPARD/CINDER.

The solution. fo~ the detailed spatial £lux into two major,.~teps.in. PHOENIX-P (Reference 4.3-56 SGS-UFSAR and energy

30).

distribution is. divided Revision 31 December 5, 2019

First,. a two-dimensiona-1 fine* energy group nodal solution is obtained; coupling individual subcell regions (pellet, clad, and moderator) as well.as surrounding pins, using *a method based on. Car*lvik' s collision probability approach and heterogeneous response fluxes which preserve the heterogeneity of the* pin cells and their surroundings.

  • The nodal solution provides an accurate and detailed local flux distribution, which is then used to homogenize th*e pin cells spatially to fewer groups.
Then, a

standard* S4 discrete ordinates calculation solves for the angular distribution, based on the group-collapsed and homogenized cross-sections from the. first step.

These S4 fluxes normalize the detailed. spatial and energy nodal

fluxes, which are then used to compute reaction
rates, power distributions and to deplete the fuel and burnable absorbers.

A standard Bl calculation evaluates the fundamental mode critical spectrum, providing an improved fast diffusion coefficient for the core spatial codes.

PHOENIX-P employs a multiple energy group library consisting of 42 or more energy groups derived mainly from. ENDF /B files. This library was designed to capture the integral properties of the multigroup data properly during group.,

collapse and to model important resonance parameters properly.

It contains all neutronics data necessary for modeling fuel, fission products, cladding and structural materials,

coolant, and control and burnable.* absorber materi.als present in the PWRs.

Group constants for burnable. absorber cells, control rod cells, guide thimbles and instrumentation thimbles, or other, non-fuel cells, can be. obtained directly from PHOENIX-P without any adjusqnents. such. as those requir_ed in the ce.;1.1 or ID lattice codes.

PARAGON is. a two-dimensional multi-group neutron (and gamma) transport code..

It is an improvement over the Westinghouse licensed code PHOENIX-P.(Reference 30). The main difference between PARAGON (Reference 38) and PHOENIX-Presides in the flux solution calculation. PHOENIX-P u~es,a nodal* qell. s.olution coupled to an S4 transport solution as de.scribed in* Reference 38. PARAGON uses the CollisionProbabi],ity theory within the interface current method to solve :the inte*gral transport equation. Throughout the whole calculation, PARAGON uses the exact heterogeneous geometry of the assembly and *the same.energy groups as in the cross-section library to compute the* multi-group fluxes for each micro'-

tegion-location of the assembly.

In order to generate the multi-group data that will be used by a core simulator* code PARAGON goes through four steps 'of *calculations*:* res*onanc*e self-shielding, flux solution, homogeniza.'ti~n a:nci 'burnup calculation; PARAGON can provide nuclear

data, both cross sections and pin power information, to a core simulator code such as ANC.

4.3-57 SGS-UFSAR Revision 31 December 5, 2019

I The NEXUS methodology (Reference 39) is.a repa:rameterization-of the PARAGON nuclear data output (cross sections) and a.. new,:-econstruction approach.with the ANC core simulator code to simplify the use.of this code system for design use.

The NEXUS -methodology provides a linkage between PARAGON and -ANC,. establishing a new code system, while still using PARAGON.

The* NEXUS approa~h i$* to *account for the spectral changes by.parameterizing the cross section output of.PARAGON, such that the cycle specific boron letdown curves do not need to be proyided in the analysis.

The parameterization adequately accounts for the relevant neutronic effects of_ temperature feedback, fuel depletion, burnable poisons, boron concentrations, and fission products.

The NEXUS methodology (Reference 39) approach uses a calculational matrix of lattice code calculations performed with PARAGON. to fa.rm a set of data in order to parameterize the cross sections according to a spectra], index

( s.r), the moderator temperature (Tm), and the fuel temperature (Tf). These parameters, in conjunction with nuclide tracking during irradiation, allow for feedback-free cross

sections, and correction functions to be-generated.

The lattice calculations are performed using. a base-line reference depletion case with several branches to account for the.effects of different local conditions, thus providing a data set.that covers_ a wide range of potential local conditions ranging from those typical of a cold shutdown reactor condition to full power conditions. The SI is based on the ratio _ of the epi thermal to thermal ne.utron flux and is a measure of the local neutron spectrum. The Tm and Tf dependences account for changes in moderation and resonance absorption respectively. These parameters are used to develop a series of correction factors,* to account for

  • these physical effects using a

-- multi variable least-squares technique.

The correction factors 'are dependent on the differences between the nodal values

  • _for these_ parameters and the values used in the reference lattice depletion calculations. The effects of xenon, actinides, othefr fission products, and burnable absorbers are directly accounted for_ *by first tracking the number density of each isotope dir~ctly, thereby accounting for explicitly for fuel

. depletion. The macroscopic cross sections _themselves are recons_tructed baseci on

'these number densities and the, microscopic cross section f_or each particular isotope given the nodal conditi*ons.: The microscopic cross.sections in these

-cases are adjusted* by correction -functions based on local nodal parameters.

. 4. 3. 3. 3 Spatial Fei/-Group Diffusion Calculations Histo:i;ically, spatial few-group diffusion calculations consisted primarily of_

. two-:-group X-Y calculations using an.updated version of the-TURTLE code arid two-gr;up axial calcul*a~tion~ using an updated version of the PANDA code.

Discrete X-Y calculations.( l mesh per cell) were carried out t'o determine critical boron concentrations and power distributions in the X-Y-plane.

4.3-58 SGS-UFSAR Revision 31 December 5, 2019

An axial average in the X-Y* plane was. obtained by synthesis. from unrodded and rodded-planes*.

Axial. effects*:iin unrodded depletion calculations were accounted for by the axial buckling;* which varies with burnup and is determined by radial depletion* calculations which are matched: in reactivity to the analogous R-*z depletion calculation.

The moderator coefficient is evaluated by varying.the inlet* temperature in the same X-Y calculations.-used for power distribution and rea8tivity predictions.

Validation of the reactivity calculations is associated with the validation of the group constants themselves, as discussed in Section 4.3.3.2.

Validation of the Doppler calculations is associated with the fuel temperature validation discussed iri Section 4. 3. 3; 1.

Validation of the moderator coefficient calculations is obtained by comparison with plant measuremen_ts at hot zero power conditions as shown in Table 4.3-11.

Axial calculations are* used to determine differential control rod war.th curves

(.reactivity versus rod insertion) and axial power shapes during steady state and transient *xenon-conditions (flyspeck curve)..,

Group constants ar.e obtained from the three-dimensional.* nodal model by flux-volume weighting on an axial.:.

slice-wise basis.

Radial bucklings are-determined by varying parameters in the*

buckling model while forcing the one-dimensional model to reproduce the. axial characteristics (axial offset, mid-plane power) of the three-dimensional model.

Recent few-group spatial calculations have input PHOENIX-P or PARAGON supplied two-group*: cross-sections *to the Advanced. Nodal Code (ANC).

ANC is a two-group, two or.* three-dimensional* nodal codE:_

c_apable of.. determining typical nuclear design analyses, such as-critical boron c.oncentrations, average_ assembly an.ct pin powers, contr.ol. _rod worths, reactivity coefficients, a~sembly and pi_n, burnups and axial power distributions.

Through the use of advanced nodal':

techniques, ANC. is able to produce solutions similar to the fine mesh, finite difference diffusion theory codes such as TURTLE/TORTISE:

ANC has* been benchmarked agai~st TORTISE (an improved version of TURTLE) for normal and off-normal conditions, such* as **ejected rod, stuck rod and* dropped rod, (Reference 31); The qualification' of the PHOENIX'--P/ANC methodology against measured data is given in Reference 30.. The qualification : of the PARAGON/ANC

  • methodology against measured,.data.-is giv\\=n in Reference. 38.

The qualification_ of the NEXUS/ANC methodology against measured data is given in Reference 39.

  • The qualification of new pin power recovery methodqlogy can be found in Reference
40.

Validation of the spatial codes for calcula_.ting power distributions involves the use of in-core an:ct ex-core detectors 'and. the BEACON core *monitoring system (PDMS) and *is discussed in Section* 4.3.2*.2*.7. Note that BEACON (Refe*rence 37) was affirmed for continued use with the USNRC approved Westinghouse design model methodologies PHOENIX-P/ANC, PARAGON/ANc; and NEXUS/ANC.

4.3-59 SGS-UFSAR Revision 31 December 51. *201~

I 4.3,3,4* Pin Power Reconstruction The conventional methodology implemented in ANC calculates the homogeneous pin power distribution and applies the group-wise pin power form factors (these were referred to as wpin factors")

to obtain the final pin power.

The conventional methodology has shown historically that it can predict the pin power with high accuracy for traditional PWR cores, which are operated without significant insertion of control rod banks. With the introduction of new PWR core designs control rods may be* inserted into the core during operation, which may significantly. change the heterogeneity of the fuel assemblies. Since the conventional methodology used in ANC does not include the control rod history effect on the pin factors, the pin power distribution is not as accurate when control rods are inserted for significant periods of time during operation.

This is particularly true_ for high-worth control rods. Moreo_ver, because the control rod insertion and withdrawal strategy is not pre-determined, conventional pin power methodology has difficulty in capturing the heterogeneitx change and the accumulated history impact on the pin power distribution. This limitation is overcome by the new methodology (Reference 4 0), _ which directly follows the_ history of each individual fuel rod in ANC and computes the fuel rod macroscopic cross-sections based on the fuel rod history and the local spectrum. Therefore, the new methodology enables ANC to calculate

. the effect of control rod insertion during operation on pin power distribution while maintaining the same accuracy as the conventional method for a

traditional core.

Based on comparison with measured data it is estimated that the accuracy of current analytical methods is:

+/- 0.2 percent ~p for Doppler defect

-5

+/- 2 x 10

/°F for moderator coefficient

+/- 50 ppm for critical boron concentration with depletion

+/- 3 percent for power distributions

.. +/- 0.2 percent ~p for rod bank worth

+/- 4 pcm/step -for differential rod worth

+/- 0.5 pcm/ppm for boron worth

.+/- 0.1 percent ~p for moderator defect 4.3.4 References for Section 4.3

2.

Langford, F. L. and Nath, R. J., Jr., "Evaluation of Nuclear Hot Channel Factor Uncertainties," WCAP-7308-L, April 1969 (Westinghouse Proprietary) and WCAP-7810 (Non-Proprietary), December 1971.

4.3-60 SGS-UFSAR Revision 31 December 5, 2019

3.

McFarlane, A. F., "Core Power Capability in Westinghouse PWRs," WCAP-7267-L, October 1969 (Proprietary) and WCAP-7809 (Non-Proprietary),

December 1971.

4.

Hellman, J. M.

(Ed.), "Fuel Densification Experimental Results and Model for Reactor Application,"

WCAP-8218-P-A (Proprietary) and WCAP-8219-A (Non-Proprietary), March 1975.

5.
Moore, J. S.,

"Power Distribution Control of Westinghouse Pressurized Water Reactors," WCAP-7208, September 1968 (Proprietary) and WCAP-7811 (Non-Proprietary), December 1971.

6.

McFarlane, A.

F.,

"Power Peaking Factors," WCAP-7912-P-A, (Proprietary) and WCAP-7912~A, (Non-Proprietary), January 1975.

7.

Altomare, S. and Barry, R. F., "The TURTLE 24.0 Diffusion Depletion Code,"

WCAP-7213-P-A (Proprietary) and WCAP-7758 (Non~Proprietary),

February 1975.

8.

Cermak, J. o*., et al, "Pressurized Water Reactor pH -

Reactivity Effect,"..

Final Report, WCAP-3696-8 (EURAEC-2074), October,1968.

9.
_Outzs, J. E., "Plant Startup Test Report, H.

B. Robinson Unit No. 2,"

WCAP-7844, January 1972.

10. _Poncel, C. G. and Christie, A. M., "Xenon-Induced Spatial Instabilities in Large PWRs," WCAP-3680-20 (EURAEC-1974), March 1968.
11.

Skogen, F. B. and McFarlane, A. F., "Cont:i:-ol Procedures for Xenon-Induced X-Y Instabilities in Large PWRs," WCA;F-36_89-21, (EURAEC-2111),

February 1969.

12.

Skogen, F. B. and McFarlane, A. F., *"Xenon-Induced Spacial -Instabilities in Three-Dimensions," WCAP-3680~22 (EURAEC-2116)~ September 1969.

13.

Lee, J. C., et al, "Axial Xenon Transient. *Tests at the Rochester Gas and Electric Reactor," WCAP-7964, June 1971. -

14.

Altomare, S. and Minton, G., "The PANDA Code,-" WCAP-7048-P-A (Propri*etary) and WCAP-7757-A (Non-Proprietary), February 1975.

'4.3-61 SGS-UFSAR Revision 31 December 5, 2019

15.

Barry, R. F., "LEOPARD -

A Spectrum. Depende_nt Non-Spatial Depletion Code for the IBM-7094," WCAP-3269-26, September 1963.

16.

Engl~nd, T.

R.,

"CINDER A One-Point Depletion and Fission Product Program," WAPD-TM-334,. August -1962.

17.

Kubit, C. J., "Safety Related Research and Development for Westinghouse Pressurized Water Reactors, Program Summaries, Spring-Fall 1973," WCAP-8204, October 1973.

18.

Poncelot, C.

  • G.,

"LASER -

A Depletion Program for Lattice Calculations Based on MUFT and THEMOS," WCAP-6073, April 1966.

19.
Olhoeft, J.

E.,

"The Doppler Effect for

a. Non-Uniform Temperature Distribution in Reactor Fuel Elements," Final Report, WCAP-2048, July 1962.
20.
Nodvik, R.

J.,

et al, "Supplementary Report on Evaluation of Mass Spectrometric and Radiochemical. Ana~ysis of Yankee Core I Spent Fuel, Including Isotopes of Elements Thor.ium Through Curium," WCAP-6086, August 1969.

21.

Drake, M. K. (Ed.), "Data Fo=iats. and Procedure f.or the ENDF Neutron Cross Section Library," 8NL-50274, ENDF-102, Vol. 1, 1970.

22.
    • Suich,. J.. E.. and Honeck, H. C., "The HAMMER System, Heteroge.neous Ar)alysis by Multigroup Methods of Exponentials and Reactors," DP-1064, January

-1967.

23.

Flatt, H.

P.

and Baller, D. C.,

"AIM-5, A Multigroup, One Dimensional Diffusion Equ,ation Code," NAA-SR-4 694, March. 1960.

24.

Barry, R. *F., "Nuclear Design of Westinghouse Pressurized Water Reactors with Burnable Poison. Rods," WCAP-7806,. December 1971.

25.

Strawbridge, L. E. and Barry, R. F., "Criticality Calculations for Unifo=i Water-Moc:ierated Lattices," Nuclear Science andEngineering 23, 58, 1965.

26.

Nodvik, R. J., "Saxton Core II Fuel Perfo=iance Evaluation," WCAP-3385-56,

. Part.IJ, -"Evaluation qf Mass Spectrometri.c and ;Radiochemical Materials

~alyses of Irradiated __ Saxton Plutonium F~s'!.l," July 1970.

4.3-62 SGS-UFSAR Revision 31 December 5, 2019

27.

Leamer, *R. D., *et al, "PU02-'U02 Fueled Critical Experiments," WCAP-3726-1, July 1967.

28.

Davidson~ S.

29.

Henderson, W. B., "Results of the Control Rod Worth Program," WCAP-9217, October 1977. *

30.

Nguyen, T. Q. et al., "Qualification of the PHOENIX-P/ANC Nuclear Design System for PressurizedWater Reactor Cores," WCAP-11596-P-A, June 1988.

31.

Liu, Y. S., et al., "ANC:

A Westinghouse Advanced Nodal Computer Code,"

WCAP-10966-A, September 1986.

32.

Iorii, J. A.

and Petrarca, D. J., "Westinghouse Wet Annular Burnable Absorber Evaluatipn Report", WCAP-10021-P-A, Revision 1, October 1983

33.

Bradfute, J. L., et al, "Cri ticaii ty Analysis of the Salem *uni ts* 1 and 2 Fresh Fuel racks", NFU...:.VTDWW-94-083-00, January 1994

34.

C.L. Beard and T. Morita, "BEACON Core Monitoring and Operations Support System", WCAP-12472-P-A, August, 1994_-

3 5.

T. R. Wa they, "Conditional Extension of the Rod Misalignment Technical Specifica'tion for Salem Units 1 and 2," WCAP 14962/14963, August* 1997.

36.

T.

Morita and W.

H.

Slagle, "BEACON Core Monitoring and Operations Support System (WCAP-12472-P-A)," Addendum 1-A, January 2000.
37.

W. A. Boyd, "BEACON*Core Monitoring and Operation Support System,-' (WCAP-12472-P-A)," Addendum 4, September 2012.

38.

W.

H.

Slagle, "Qualification of* the Two-Dimens*ional Transport* Code Paragon (WCAP-16045-P-A)," Revision 0, August 2004.
39.

W.

H.

Slagle, "Qualification bf the *NEXUS Nuclear Data *Methodology (WCAP-16045-P-A)," Addendum 1-A Revision 0, August 2007.

40. * - Zhang B.,

et al,. "Qualificat.ton of the *New

'Pin Power Recovery Methodology (WCAP-10965-P~A), Addendum 2-A* Revision- 0, September***°2010.

4.3-63 SGS-UFSAR Revision 31 December 5, 2019

i I_

A preliminary estimate of the leakage can be obtained from the rate of condensate flow increase during the transient; a better estimate can be made from the steady state condensate flow at equilibrium conditions. The device alarms on a O. 06 gpm condensate flow rate, which indicates that a 1 gpm or larger leak has been developing for about 5 minutes.

The system can be checked during reactor shutdown.

5.2.7.1.5 Intersystem Leakage Detection The following provisions are available for the detection of intersystem leakage from the RCS:

1.

Radiation monitors are provided for the Steam Generator Blowdown System, each Main Steam Line and condenser air removal effluent line which alert the operator to reactor coolant leakage into the Main Steam and Feedwater Systems from steam generator tube leaks.

2.

Radiation monitors are provided for the Component Cooling System to detect reactor coolant leakage into the system from the Residual Heat Removal System.

detection.

Surge tank level is also an indicator for leakage

3.

The accumulators are isolated from the RCS by two check valves. They are also provided with a remote manual valve.

Leakage would be detected by level and pressure changes in the accumulators.

4.

The high-head SIS line is isolated from the RCS by two check valves and normally closed remote manual valves.

Leakage from the RCS, that would pass the normally closed SJ12/SJ13 gate valves, would be detected by pressure changes in the line.

5.2-69 SGS-UFSAR Revision 31 December 5, 2019

5.

The Residual Heat Removal System. and* the Intermediate Head SIS are isolated from the RCS by two check *valves and normally clos.ed remote manual valves.

Leakage would cause operation of, the relief valves which discharge to the containment sump.

RCS leakage can also be detected :by level changes in the volume control tank, as well as by RCS water inventory balances,* which are performed.periodically.

The indications identified above are provided, with appropriate alarms, in the control room.

5.2.7.2 Indication in Control Room Positive indications in the control room of leakage of coolant from the RCS to the lower containment compartmen,t are provided by equipment which permits continuous *monitoring of the lower containment compartment air activity and humidity, and condensate run-off from the fan coolers. '.['his equipment provides indication of normal background which is indicative of a basic level of leakage

(

from primary systems and components. Any increase in the observed parameters are an indication of change within the lower containment.compartment, and the equipment provided is capable of moni taring this change.

The basic design criterion is the detection of.deviations from normal containment environmental conditions including air particulate activity, radiogas activity, humidity,

.condensate, and in addition, in *the case of gross leakage, the J,iquid inventoEy in the process systems and containment.sump.

5. 2. 8 Inservice Inspection Program:

Pre service and inservice inspection for Class 1, 2, and. 3 components are in accordance with the rules of 10CFR50.55(a),

Paragraph (g) to the extent practical.

Relief. from the* applic_able A,SME Section XI. inspection requirements have been transmitted to t;he* NRC through the Inservh:e Inspection Program Long Term Plans and Testing Pro~~ams.

5.2-70 SGS-UFSAR Revision 31 December _5, 2019

There are no other credible. *s*ources of shaft seizure other than impeller rubs.

Sudden seizure of the*pump bearing is precluded by graphite in the bearing. Any seizure* in the.seals results*' in. a. shearing of the anti-rotation pin (or pins for the RCPs which have installed the upgrade No. 1 RCP SIGMA Seal) in the seal ring.

The motor has adequate power to continue pump operation even after the above occurrences.

Protective relays are provided to trip the supply breaker on an overcurrent condition during. startup and.normal operation. Indication of pump malfunction is provided by the following alarms:

bearing water high temperature, excessive Number 1 seal leakoff, and excessive pump vibration.

If a pump malfunction is indicated, the affected pump is taken out of service for investigation.

5.5.1.~.6 Critical Speed The RCP shaft is designed so that its operating speed is below its first critical speed.

This shaft design, even

  • under the most severe postulated transient, gives low values of actual stress.

5.5.1.3.7 Missile Generation Precautionary me*asures taken to preclude missile formation from RCP components a*ssure that the pumps will not produce missiles under any anticipated.accident

  • conditions.

Each component of the pump is analyzed for missile* generation. Any fragments of the motor rotor would be contained by*the heavy stator.* The same conclusion applies to the pump impeller, because the small fragments that might be ejected would be contained by the heavy casing.

5.5.1.3.8 Pump Cavitation The minimum NPSH required by the RCP at best estimate flow is approximately 170 feet (approximately 85 *psi).

In order -for the* coritrolled---leakage, seal. to operate correctly, it is necessary to require a

  • minimum differential* pressure of approximately 200 psi across the Number 1 seal.

This corresponds to a primary loop pressure at which the minimum NPSH requirement is exceeded and no limitation on pump operation occurs from this source.

5.5.1.3.9 Pump Overspeed Considerations For turbine trips actuated by either the Reactor Trip System or the *Turbine Protection System, the generator breaker disconnects the generator permitting the RCPs to remain connected to the external network for 30 seconds to prevent any pump overspeed condition; 5.5-7 SGS-UFSAR Revision 31 December 5, 2019

An electrical fault requiring immediate trip of;, "the generator. (with resulting turbine trip). could result in* an over speed. c:;ondi tion. Howev_er, the... Turbine Control System and the turbine inte:;rcept valves limit the ove_rspeed.. to less than 120 percent.

As addi tion?.J.

  • packup, the. Turbine Protecti_9n System has a mechanical overspeed protection trip, usually set at about 110 percent of turbine speed.
  • In.c.ase a* generator. trip deenergizes the pump buses, the RCP motors are transferred to off$ite power ~ithin six to ten cycles.

5.5.1.3.10 Anti-Reverse Rotation Device Each of the RCPs is provided with an anti-reverse ro~ation device in the motor.

This anti-reverse mechanism consists of pawls mounted on the outside diameter of the flywheel, a serrated ratchet plate mounted on. the motor frame, a.spring return for the ratchet.plate, and two shock.absorbers.

After the motor has slowed and come to a stop, the dropped pawls engage the ratchet plate and, as the motor tends to rotate in the opposite direction, the ratchet plate also rotates until i_t. is stopped by the shock absorbers.

The rotor. remains in this position until the motor is energiz,ed _again.

When.. the

-.motor is started, the ratchet plate.is returned to its original position by the spring return.

As the motor begins to rotate, the pawls drag over the ratchet plate. When the motor reaches sufficient speed, the pawls are bounced into an elevated position and are held in that position by friction resulting from centrifugal forces acting upon the pawls.

Considerable plant experience with the anti-reverse rotation device has shown high reliability of operation.

5.5.1.3.11 Shaft Seal Leakage During normal operation, leakage along the RCP shaft is controlled by three shaft seals arranged in series.

Charging flow is directed to each RCP via a seal water injection filter.

It enters the pump and is directed to a point between the pump shaft bearing and the pump seals.

The flow splits and a portion flows down the shaft through and around the lower radial bearing, down past the thermal *barrier heat exchanger and into the RCS; the remainder flows up the pump shaft annulus and provides a back pressure on the Number 1 seal and a controlled flow through the seal.

Above the seal, most of the flow leaves the pump via the Number 1 seal leak-off line.

Minor flow passes through the Number 2 seal and its leak-off line, and through the Number 3 seal and its leak-off line.

5.5-8 SGS-UFSAR Revision 30 May 11, 2018

Hydrogen* concentration *is measured -by a hydrogen partial pressure sensor in conjuncti*on w.ith a total :*pressure sensor.

The partial pressure sensor is galvanic in* nature, consisting of a platinum black electrode and a platinum oxide counter electrode within a polysulfone housing; The range of measurement is O to 10 volume percent with an accuracy of 2 percent of full scale. *

  • Output is displayed in one Control Room.

Alarms are provided for high hydrogen concentration, power failure, system error, and calibration mode.

Power is supplied from vital sources.

In addition* to the Hydrogen Monitoring System,

  • hydrogen* concentration may be determined by taking a grab sample using the containment air particulate detector (APO) skid.

In amendments 281 and 264 to Salem Units 1

and 2 Operating Licenses,.. a.

commitment was made* to maintain the capability for* the hydrogen monJ..toring'.

system for diagnosing

  • beyond design basi*s accidents.

The functionality requirements of the containment hydrogen analyzers are ** contained in the Salem Technical Requirements Manual.

6.2-79 SGS-UFSAR Revision 31 December 5, 2019

6.2.6 References for Section 6.2

1.

Field, C. V., "Fan Cooler Motor*Qnit.Test,",WCAP-7829, April 1972.

2.

Styrikovich, M. A. et al., "Attornnoyl Energiya," Volume 17, No. 1, pp. 45-49, (Translation in UDE -

621..039.562.5), July 1964.

-3.

Parsley, Jr.., L. F., "Design Considerations of Reactor Containment Spray Systems - Part VI." ORNL-TM-2412. Part 6, 1969.

4.

Parsley, Jr., L. F., "Design Considerations of Reactor Containment Spray Systems - Part VII." ORNL-TM-2412, Part 7, 1970.

5.

Eggleton, A. E. J., "A Theoretical Examination of Iodine-Water Partition

  • Coeff:ici.ent," AERE (R).- 4887, 1967.

6.2-80 SGS-UFSAR Revision 31 December 5,* 2019

Table 7.3-8 7.3-9 7.5-1 7.5-2 7.5-3 7.5-4 7.5-5 7.7-1 7.7-2 T.'/-3 7.7-4 7.7-5 7.7-6 7.10-1 7.10-2 7.10-3 SGS-UFSAR LIST OF TABLES (Cont)

Title Salem Unit 1 -

Engineered Safety Features Response Times Salem Unit 2 -

Engineered Safety Features Response Times Main Control Room Indicators and/or Recorders Available to the Operator Main Control Room Indicators and/or Recorders Available to the Operator to Monitor Significant Plant Parameters During Normal Operation Index Type "A" Variables Summary of Instrumentation Compliance with Regulatory Guide 1.97 Justification for Nonconformance to Regulatory Guide 1.97 Rod Stops Overhead Annunciator-Groupings-Deleted*

Deleted Deleted

  • Figure 7.2-1 7.2-2 7.2-3 7.2-4 7.2-5 7.2-6 7.2-7 7.3-1 7.3-2 7.3-3 7,3 7. 6-1

. 7. 7-1*

7.7-2 7.7-3 7.7-4 SGS-UFSAR LIST OF FIGURES Title Illustration of Overpower and Overtemperature ~T Setpoints vs Tavg)

Deleted:

Refer to Plant Drawing 221051 (M

Setpoint Reduction Function for Overpower and Overtemperature

~T Trips Pressurizer Pressure Control and Protection System Pressurizer Level Control and Protection_System Pressurizer Sealed Reference Leg Level System Steam Generator Level Control and Protection System Containment Pressure Instrumentation Typical MOV 230 V Power Lockout Typical MOV Control Power Lockout without Interposing Rela?

Typical MOV ___ Control Power Lockout with. Interposing Relay Ac9umulator Discharge Valves - Status Mo_nitoring Block-Diagram of Reactor Control System Control Bank Rod Insertion Monitor Rod Deviation Comparator In-Core Instrumentation Details 7-viii Revision 27 November 25, 2013

For the postulated abnormal conditions, the exact c.ornbination of conditions (reactor coolant pressure, temperature and core power, instrumentation inaccuracies, etc.)

will not cause a DNBR to go below 1.30 before a reactor trip.

The simultaneous loss of power to all of the reactor coolant pumps is the accident condition most likely to approach a DNBR of 1.30 for the calculated worst fuel rod.

In any event, the DNBR is near 1.30 for only a few seconds.

The AT trip functions are based on the differences between measured hot leg and cold leg temperatures.

These differences are proportional to core power.

The AT trip functions are provided with a nuclear differential flux feedback* to reflect a measure of axial power distribution.

adverse axial distribution which could lead conditions.

This will assist in preventing an to exceeding the allowable core In the event of a difference between the upper and lower ion chamber signals that exceeds the desired range, automatic feedback signals are provided to reduce the overpower-overtemperature trip setpoints, which in turn block rod withdrawal and reduce the load to maintain appropriate operating margins.

7.2.3.2 Specific Control and Protection Interactions Nuclear Flux Four power-range nuclear flux channels* are provided for overpower protection.

Isolated outputs from all four channels are auctioneered for automatic rod control.

If any channel fai'ls in such a way as to produce a low output, that channel is incapable of proper overpower protection.

Two-out-of-four overpower trip logic will I ensure an overpower trip if* needed even with an independent failure in another channel.

7.2-27 SGS-UFSAR Revision 31 December 5, 2019

I In addition, the Control System wiYl respond only to rapid change*s in indicated nuclear flux; slow

  • changes or drifts are
  • compenEi"ated by th'e t:eni.perature control signals.

Coolant Temperature One hot-leg and one cold-leg temperature reading is provided t,rom each co_olant loop to use for protection.

Narrow-range thermowell resistance temperature detectors (RTDs) are provided for each coolant loop.* In the hot legs, sampling scoops are used because the flow is stratified; that is, the fluid temperature is not uniform over a cross section of the hot leg.

One dual-element RTD is mounted in each of the three sampling scoops associated with. each* ho.t leg.

The scoops *extend into the flpw stream at locations 120 degrees. apart in the cross-sectional plane. Each scoop.,has five orifices which sample the hot-leg flow along the lead;Lng edge of the scoop...

Outlet ports are provided in the scoops_ to direct.. the sampled fluid past the sensing element of the RTDs.

One of each RTD's dual elements is used for protection, while the other is an installed spare.

Three p*rotection readings from each hot leg are averaged to provide a hot-leg reading for that loop.

One dual-element RTD is mounted in a thermowell associated with each cold leg. No flow sampling is needed because coolant flow is well mixed by the reactor coolant pumps.

As is the case with the hot leg, one element is used while the other is an installed spare.

Certain control signals are derived from individual protective channels through isolation amplifiers.

The isolation amplifiers are classified as part of the protective system.

signals.

The reactor control system uses the highest of four isolated Tavg The RTDs are a fast-response design which conforms to applicable IEEE standards and 10CFR50.49 requirements.

SGS-UFSAR 7.2-28 Revision 31 December 5, 2019

The main requirement f~:r reactor :Protection is that the temperature dif~eren~_e between the hot leg. and cold ~eg varias. linearly with power.

All AT setpoints are in terms of the full power t..T; thus, absolute AT measurements are not required.

power will be verified during startup tests.

Linearity of t..T with Reactor* protection logic using re.actor coolant** loop temperatures is 2/4, with one channel per reactor coolant loop.

This complies with all appli:cable IEEE Standard 279-1971 criteria.

Since

  • reactor control* is based on the highest average temperature from the four loops, the control rods are always moved based upon the most pessimistic temperature measurement with respect to margins to DNB.

A spurious low average te!D.l?erature measurement from any loop temperature control. channel will _*cause no control action.

A 7.2-29 SGS-UFSAR Revision 11 July 22, 1991

. \\

11,*

spurious high average temperature measurement will cause direction).

rod insertion 0

(safe Channel deviation signals in the Control *.System will give an alarm if any temperature channel deviates significantly from the auctioneered

{highest).

Automatic rod withdrawal blocks will also occur if any one of four nuclear channels indicates an overpower condition, or if any two of four temp.erature* channels indicate an overtemperature or overpower condition.

Although automatic rod withdrawal is disabled, the automatic rod withdrawal blocks remain.

Two-out-of-four (2/4) trip logic is used to ensure that an overtemperature or overpower ~T. trip will occur if needed, even with an independent failure in another channel. Finally,

  • as shown in Section 15.1, the combination *of trips on nuclear overpower and high pressurizer pressure also serves to limit an excursion for any rate of reactivity insertion.

7.2-30 SGS-UFSAR Revision 31 December 5, 2019

Designation C-1 C-2 C-3 C-4 C-5 C-6 C-7 TABLE 7.2-2 (Cont)

Derivation 1/2 Neutron flux (intermediate

  • range) above setpoint 1/4 Neutron flux (power range) above setpoint 2/4 Over-temperature ~T above setpoint 2/4 Overpower ~T above setpoint 1/1 Turbine steamline inlet pressure below setpoint 1/2 Turbine steamline inlet pressure below setpoint 1/1 Time derivative (absolute value) of turbine steamline inlet pressure (decrease only) above setpoint Function Blocks automatic and manual control rod withdrawal*

Blocks automatic and manual control rod withdrawal*

Blocks automatic and manual control rod withdrawal*

Actuates turbine runback via load reference Blocks automatic and manual control rod withdrawal*

Starts turbine runback via load reference Blocks automatic control rod withdrawal*

Blocks turbine runback via load limit Makes steam dump valves available for either tripping or modulation

  • Automatic rod withdrawal is disabled 3 of 4 SGS-UFSAR Revision 31 December 5, 2019

Variable Ref. No.

17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 SGS-UFSAR TABLE 7.5-4 (Cont)

Variable Description Containment Hydrogen Concentration -

Analyzers Containment Effluent Radioactivity Noble Gases from Identified Release Points - Monitors Deleted RHR System Flow - Transmitters RHR Heat Exchanger Outlet Temperature -

Thermocouples Accumulator Tank Level and Pressure -

- Transmitters

- Transmitter Range Accumulator Isolation Valve Position Boric Acid Charging Flow -

Transmitters Flow in HPI System - Transmitters Flow in LPI System - Transmitters Refueling Water Storage Tank Level and Low Level Alarm - Transmitters

- Transmitter Range Reactor Coolant Pump Status Primary System Safety Relief Valve Positions (including PORV and code valves) or Flow through or Pressure in Relief Valve Lines Pressurizer Level - Transmitters

- Transmitter Range Pressurizer Heater Status (Current) - Heaters 2 of 5 Compliance Level 3a 3b 3a 4b 1

Unit 1-3a Unit 2-1 3a 3a Unit l-3a Unit 2-1 Unit 1-4c Unit 2-1 1

1 Unit 1-3a Unit 2-1 Unit 1-4c Unit 2-1 2

Revision 31 December 5, 2019

7.7 CONTROL SYSTEMS NOT REQUIRED FOR SAFETY The Nuclear Steam System's controls for the Salem Generating Station and the D.

C. Cook Plant are functionally the same.

7.7.1 Design Basis 7.7.1.1 Reactor Control System The Reactor Control System is designed to reduce nuclear plant transients for the design load perturbations, so that reactor trips will not occur for these load changes.

Overall, reactivity control is achieved by the combination of chemical shim and Rod Cluster Control Assemblies (RCCA).

Long-term regulation of core reactivity is accomplished by adjusting the concentration of boric acid in the reactor coolant.

Short-term reactivity control for power changes is accomplished by moving RCCAs.

The function of the Reactor Control System is to provide automatic insertion*

of the RCCAs during power operation of the reactor.

The system uses input signals including neutron flux, coolant temperature, and turbine load.

The Chemical and Volume Control System (CVCS) (Section 9) supplements the Reactor Control System by the addition and removal of varying amounts of boric acid solution.

There is no provision for a direct continuous visual display of primary coolant boron concentration.

When the reactor is critical, the best indication of reactivity status in the core is the position of the control group in relation to power and average coolant temperature.

There is a direct relationship between control rod position and power, and it is this relationship which establishes the lower insertion limit calculated by the rod insertion limit monitor.

There are two alarm setpoints to alert

  • Automatic Rod Withdrawal is disabled 7.7-1 SGS-UFSAR Revision 31 December 5, 2019

the operator to take corrective action in the event a, control group-approaches or reaches its lower limit.

Any unexpected change in the position of the control group under automatic control, or a change in coolant temperature under manual control provides a direct and immediate indication. of a change ;Ln the reactivity _status. of the reactor.

In addition, periodic samples are taken for determination of the coolant boron concentration.

The. variation in concentration during core life provides a further check on the:reactivity status of the reactor. including core depletion.

The Reactor. Control System is designed to enable the reactor to follow load changes automatically when the output is above approximately 15 percent of nominal, power.

Control rod positioning -may be. performed automatically when plant output is above this value, and manually at any time.

Automatic Rod Withdrawal is disabled.

Automatic control rod positioning is limited to rod insertion.

The operator is able to select any single bank of rods for manual operation. This is accomplished with a multiposition switch so that he may not select more than one bank.

He may also select automatic or manual reactor control,. in which case the control banks can be moved on~y in their normal sequence with some overlap as one bank reaches its ~ull withdrawal position and the next bank begins to withdraw.

The system enables the nucl.ear unit to accept a step load increase of 10 percent and a ramp increase of,5 percent per minute within the load. range of 15 percent to.100 percent without reactor trip subject to possible xenon limitations.

Similar step and ramp load reductions are. possibl-e within U1e range of. 100 percent. to 15. percent of nominal power.

The Steam Dump System permits the plant to accept an additional 4 0-percent. load reduction without reactor or turbine trip.

7.7-2 SGS-UFSAR Revision 31 December 5, 2019

The Reactor Control System is,' Capable of restoring-coolant.average temperature to within the programmed temperature

deadband, following a

scheduled or unexpected change in load.

Automatic Rod Withdrawal is disabled.

Only automatic rod insertion is available to restore coolant average temperature.

The pressurizer water level is programmed to be a function of the auctioneered coolant average temperature.

This is to minimize the requirements on the eves and Waste Disposal System (WDS) resulting from coolant density changes during loading and unloading from full power to zero power.

Following a reactor and turbine trip, sensible heat stored in the reactor coolant is removed without actuating the steam generator safety*valves by means of controlled steam dump to the condenser and by injection of auxiliary feedwater into-the steam generators. -Reactor Coolant System (RCS) temperature is reduced to the no load condition.

This no-load coolant temperature is maintained by steam dump to the condensers which removes residual heat.

7.7.1.2 Operating Control Stations The Salem Generating Stations have a common Control Room* with separate control stations for each* unit; as shown* on Plant Drawing 204803.

The* Control-Rooms are located in the - Auxiliary Building, The information presented in this section pertains to both Control Rooms; although only one is described.-

Each unit is equipped with separate Control 'Stations which contain those cpntrols and instrumentation necessary for operation of that unit under* -norina,l and' abnormal conditions.

The Control Room is c::onti:huously occupied by the.

operating personnel under all operating conditions.

  • Equipment in this* area had_

been designed to minimize the possibility of* a** condition which could *lead to inaccessibility or evacuation.

Control Room shielding and ventilation are designed such that the occupants of the room shall not receive doses in excess of 5 rem

7. 7-3 SGS-UFSAR Revision 31 December 5, 2019

to the whol~ body, or,its equivalent to any part.;of the bQdy, daring the course of a_. ~ose-of-COolant Accident (L~).

T~ia includes doses, received during ingress and egress.

The control Room Air Ccndi:ticning System i.s de11cribad in section 9.

The CCJntrol ROcm is designed to ba* continuously *occupied by qua1.ified operati?lg personnel under all operating and Design Baals Accident (DBA) conditions. Beth Control

  • Rooms share
  • a. number of
  • separate Communication Systenls.
  • One system consists of direct dialing telephones. Another.independent Communication System is a. party.' line and voice paging system, wbich.. prov icles the primary means.of **,

CC1111111Unication between plan,t operations personnel throughout th** atation.

Battery-operated portable two-way transceivers are provided for special purpoaas.

There is a separate system interconnecting the Containment Building, control Rocm

  • and. refueling area.

These systems are llinergized from inverter powered buaaa.

The capability to bring the reactor to a hot shutdown condition is provided at locations outside tbe Control '.Room. The majority of equipnent for this c:ond.1.tion is located in the auxiliary feedwa.ter pump area.

7.7.2 System Design Two independent Control Systems of different_principlea pro~ide redundancy,of reactivity control.

One of the two Reactivity Control system~ 8Jliploys RCCAa to regulate the-posit1.0'1-of the neutron absorbers within the reactor core.

The other Reactivity Control systelll employs the.eves to. regulate the concentration

~..

{

of. bcric acid, solution neutron at)sorber in the RCS.

These sylll!tema are daecribed in _sect~ons -~ and. 9,.respectively.

The Reactor Control System is designed to provide *stable. system control over the full range of automa.tic operation throughout core life without requiring operator adjustment cf setpoints other-than :tiei~l calibration. *.

7.7-4 Revision 6 February 15, 1987

A simplified block diagram of the Reactor Control System is shown on

'Figure 7. 7-1.

The Reactor C6nt:tol System controls. the reactor coolant. average temperature by regulation of control rod bank position.

The system is capable of restoring reactor coolant average temperature to the programmed value following a

change in load.

The programmed coolant average temperature increas.~s linearly from zero pow.er,to the full power condition.

. The Reactor

<::;antral System will also initially compens.ate. for reactivity changes caused by fuel depletion and/or*

xenon transients.

Long-term compensation.for these two effects is periodically made by adjustment of the boron concentration* to return the control rod bank to its normal operating range.

The reactor coolant loop average temperature*s are determined from hot leg and cold leg. measurements in each reactor coolant loop.

The error between the programmed average temperature and the highest of the measured average temperatures from each of the reactor coolant loops constitutes the primary control signal as shown on Figure 7.7-1.

An additional control input signal is derived from the reactor power vs.

turbine load mismatch signal.

This additional control input signal improves system performance by enhancing response and reducing trahsients peaks.

From these input signals, the rod.

direction command signals are derived.

  • The *rod speed command signal. varies over the
  • corresponding range of 3. 7 5
  • to 4 5 inches
  • per miriute depending on* the magnitude and the rate of* ch_;,nge - of the input -- signals.

The rod direction command signal is determined by' the -"pds'itive or negative value of the temperature difference signal.

The rod speed* and rod direction command* si.gnais are fed to the Rod Control System.

7.7.2.1 Rod Cluster Control Assembly Arrangements There are 53 RCCAs divided into four shutdown banks of 24 RCCAs and four control banks of 29 RCCAs.

The control banks are the only rods that can be manipulated under automatic control.

Automatic Rod Withdrawal is disabled.

Only Automatic Rod Insertion is available.

groups to obtain smaller incremental 7.7-5 SGS-UFSAR The control rods are divided into Revision 31 December 5,-- 2019

reac:ti vi ty changes per step.. All RCCAs in a group.; are electrically.parall!=led to move simultaneously.

There is individual position i~dication for each RCCA.

7.7.2.2 Rod Control For a compTete description of rod *control and position indication systems, *see I.

References 1, 2 and 3.

7.7.2.2.1 Control Bank Rod Insertion Monitor The purpose of the control bank rod insertion monitor is to give warning.to the operator of a decrease in shutdown margin.

Since the amount of shutdown reactivity required for the design shutdown margin following a reactor trip increases with increasing power, the. allowable* rod insertion limits must be decreased with increasing power.

One parameter which is proportional to power is used an input to the insertion monitor.

This is the AT between the hot leg and the cold leg, which is a direct function of reactor power.

The rod insertion monitor uses this parameter for each control rod bank as follows:

ZLL = A(.1T) auct where:

z..

  • *LL (aT) auct A, C SGS-UFSAR
  • '* ":. ~- ;,. *... *.

,.,.. l *~ ***

. rn~xirnum. permissible insertion limit for affected control bank' highest ~T for all 'four loops constants chosen t~ maintain ZLL~ actual limit;.based_on physics calculations 7.7-6 Revision 18 April 26, 2000

i.

I Thi~ circuit pre~ents a:large increase*in reactor coolant temperature following a *1~r~e,. sudden ~o~d*tj~cr~ase.

The error signal is a difference between the

'leaq/lag. COI'flpensate*.auq_tioner!:!d-:Tavg*_ *and* the reference Tavg and is based -on t_ur~ine steamline* inlet pressure.

i The jT

  • signal is -thl;l same as that used in the RCS. The lead/lag compensation
-~vg for.!the. T..

-signal i*s. t*o compensate for lags* in. the plant thermal response and avg..

_in valve positioning_; *.. F~llow_ing a sudden load decrease, T

f is immediately re J

decreased and T tends to incre<;1se, thus generating an immedia'te demand a_vg slg~al for *steam *dump.

Since *q.onj:.rol rods are available in this *situation, ste~m dump* terrnin,;1tes ~s. the :error comes within the maneuvering capability of the,c;ontrol' rods.*.

The., stee.m dump flow reduces proportionaily. as the control rods act to reduce the 'average coolarit t'emperature. * 'The artificial.load is therefore removed as the ; coolant average temperature is restored to its PFogrammed equilibri~m

i.

. I' value.

The ;_purpose. of* the. Ste*am Dump System i.s to reduce RCS transients following a subs.tantial turbine load redqct~on. J:?y bypassing main steam directly to the con~en~er, thereby maintaining an artificial load on the steam generators, The Cont'rol Rod System can*then :i:educe the.reactor temperature to a new equilibrium va:1qe. witho.ut c'ausing oyertemp~rature arid/or overpressure conditions.

I The ! dump val*ves are modulated *by the. *react"or : coolant average temperatur;e sigri.al.

The. req~ired number of steam dump va],ves. c::an be tripped quickly to

. stroke. full open 'or' modulate,*. de_pendi_ng upon the magnitude of the temperature error signal resulting*'from loss of load.

E'ollio:wing a react,or*. and turbine trip,.decay heat and sensible heat stored in the i reactor coolant are.removed without actuating the steam generator safety i

val~es. by 11\\eans of controlled steain *dump to 7.7-11' SG_S-.Ui;:'SAR Revision 21 December 6, 2004

  • .1

the condenser and by injection of feedwater to the steam generators.

Following a turbine trip, as monitored by the turbine trip signal, the load rejection steam dump controller is defeated and the turbine trip steam dump controller becomes active.

Since control rods are not available in this situation, the demand signal is the error signal between the lead/lag When the error compensated auctioneered T and the no load reference T avg avg signal exceeds a predetermined setpoint, the dump valves are tripped open in a prescribed sequence.

As the error signal reduces in magnitude indicating that the RCS T is being reduced toward the reference no load value, the dump avg valves are modulated by the plant trip controller to regulate the rate of removal of decay heat and thus gradually establish the equilibrium hot shutdown condition.

The error signal determines whether a group of valves is to be tripped open or modulated open. - In either case, they are modulated when the error is below the trip-open setpoints.

7.7.2.8 In-core Instrumentation The in-core instrumentation is designed to yield information on the neutron flux distribution and fuel assembly outlet temperatures at selected core locations.

Using the information thus obtained, it is possible to confirm the reactor core design parameters.

The functionality requirements for_the in-core instrumentation are contained in the Salem Technical Requirements Manual.

7.7-12 SGS-UFSAR Revision 31

-December 5, 2019

7.7.2.9 Operating Control Stations The Control Room provides the necessary controls and indication to start, operate and shut down the unit with sufficient redundant information displays and alarm indications to ensure safe and reliable operation under all normal and abnormal conditions.

The most important unit controls are located on the control console, which is of freestanding, horseshoe shaped design, constructed of steel.

The front horizontal portion contains the most frequently used operating controls while the rear vertical portion contains less frequently used controls and indicators.

7.7-13 SGS-UFSAR Revision 31 December 5, 2019

Controls and indicators are functionally grouped* on a

system basis to facilitate safe, reliable operation of the unit during tran.sients as well as normal 6peration. Those systems requiring mor~ frequent operator attention are located in the central area, while iess frequently used controls are located on either side.

Most of the console instruments consist of plug-in; back-lighted pushbutton stations and vertical scale indicators.

Operator action consists of a momentary push of a bot ton.

The lights in the buttons are used for status, information and alarm indication.

. Alarms are provided in the Control Room to.alert the operator. of abnormal plant conditions.

The alarm displays are* located either on a console pushbutton control station, where corrective action would be taken, o:r: on the overhead annunciator.

An alarm signal causes a back-lighted pushbutton to flash and the console audible alarm to sound until acknowledged by the operator.

Upon clearing of an alarm condition, the console audible ringback is sounded.

Other alarms are displayed on an annunciator panel located overhead above the console. This panel consists of* illuminated. windows and. separate audible alarm and ringback tones.

Two first-out annunciator panels.indicate, by means of red and white lights, the first r-eactor or turbine trip to occur.

A comprehensive status panel, employing the same type of illuminated windows as the corisole, indicates the condition of trip channels and alarms.

By means of a "mimic bus" arrangement, the interaction of trip conditions and permissives can be quickly

analyzed, Diesel generator automatic load sequencing, critical valve status
  • and other important information are also clearly_ displayed, A computer is employed to assist the:operator and to monitor the unit, Selected parameter trends can be recorded while alarm conditions are indicated to the
operator, The computer output c_opsists. of a vtdeo. display mounted on the

. console,*. logging. printer mounted

  • on Control room. panels located convenient to the plant operators.

The video display and printers are independent device~..

Vertical *panels form the walls. of* the Control Room* and contain - controls for

systems, which require onl/.. bc_ciasional.. operator attention as well as miscellaneous recorders and indicators.

Reliability and ease of service has been designed into the Control Room.

The

~aj.?ri"i:"y of the console instruments are plug~in module~.

_::in the unlikely. case tha_t_ a pushbutton station or indica:tor on. _the console malfunctions, it_ can be readily removed and replaced from the front of the console.

No. ac~e.ss to the inside of the console is needed, Re-lamping can also be quickly accomplished from the front of the pushbutton.

7.7-14 SGS-UFSAR Revision 23 October 17, 2007

7.7.2.11 Residual Heat*R;;:,moval Performance Monitoring System The residual heat removal.. pe,rforrnance mopitoring warning of loss of decay h.eat removal capabilities.

system provides an The system includes:

early

1.

Two independent narrow range continuous Reactor Coolant System level indications and wide range RCS level indication whenever the RCS is in a reduced inventory (mode 5 or *6);

The *narrow level range. monitored is from Elevation 97' to Elevation 91.1'.

The wide range level is monitored. from elevation 97 feet to 109. 5 feet.

The wide range midloop level is used while reactor vessel level is above the narrow range midloop level indication.

2.

.other monitoring capability:

a.

RHR pump discharge flow

b.

RHR pump discharge pressure

c.

RHR.pump suction pressure

d.

RHR pump motor current The system is shown on the RCS and RHR system drawings (Plant Drawings 205301 and 205332).

The system is designed to accurately.monitor water level while the R.[IR system is operating with the RCS dra*ined to. the mid level of the RPV. nozzles.

This level allows draining of the steam generators but establishes a very narrow operating level over which the RHR pumps will have adequate N.PSH.

The Reactor Vessel Level.Indicating System (Plant Drawing 205332) provides.a wide *range level indication but is not accurate enough for the purposes described. *in NRC Generic Letter 88-17.

The testing design criteria are the same as used

  • for instruments that *c;);re connected to full reactor temperature and pressure.

The channel design and physical location of. the transmi tt.ers prevent any physical damage from a

refueling seal failure even though the system is not specifically designed to function while flooded or over this range.

The low side of the level transmitter is connected to the pre*ssurizer and can be manually aligned** to measure the static water level *,in the vessel with or without pressure in the vessel.

The.. system is* not. required for s_afe. sr1ut,:down, and

shutdown, therefore, it is not safety related.

is used, only durinsr cold Ho11ever, it.is designed, installed, and maintained as if it were safety related.

7.7.2.12 Seismic Monitoring Instrumentation The operability:.of the seismic monitoring instrumentation ensures that sufficient capability is available 'to prompt,iy dete'rmine the magnitude. ~{,,~

. seismic event and evaluate the response. of those features. impor't.ii.:n:'t 'to' safJ1\\i.

This capabi*litr 7.7-21 SGS-UFSAR Revfsion 27 November 25, 2013

is required to permit comparison of the ~easured response to that used in the design basis for the facility.

The functionality requirements for the seismic moni taring instrumentation are contained in the Salem Technical Requirements Manual.

7.7.2.13 Meteorological Monitoring Instrumentation The meteorological instrumentation ensures that sufficient meteorological data is available for estimating potential radiation doses to the public as a result of routine or accidental release of radioactive materials to the atmosphere.

This capability is required to evaluate the* need for initiating protective measures to protect the heal th and safety of the public.

The functionality requirements of the meteorological monitoring instrumentation are contained in the Salem Technical Requirements Manual.

7.7.3 System Design Evaluation 7.7.3.1 Unit Stability The Rod Control System is designed to limit the amplitude and the frequency of continuous oscillation of coolant average temperature about the Control System setpoint within acceptable values.

Continuous oscillation can be induced by the introduction of a feedback control loop with an effective loop gain which is either too large or too small with respect to the process transient response, i.e., instability induced by the control system itself.

Because stability is more difficult to maintain at low power under automatic control, no provision is made to provide automatic control below 15 percent of full power.

The Control System is designed to operate as a stable system over the full range of automatic control throughout core life.

7.7.3.2 Step Load Changes Without Stearn Dump A typical power control requirement is to restore equilibrium conditions, without a trip, following a plus or minus 10 percent step change in load demand, over the 15 to 100 percent power range for automatic control..

The design must necessarily be based on conservative conditions and a greater transient capability is expected for actual operating conditions.

A load demand greater than full power is prohibited by the turbine control load limit devices.

7.7-2la SGS-UFSAR Revision 31 December 5, 2019

SGS-UFSAR TABLE 7. 7..:.3 This Table has been deleted 1 of 1 Revision 31 December 5, 2019

SGS-UFSAR TABLE 7.7-4 This Table has been deleted 1 of 1 Revision 31 December 5, 2019

SGS-UFSAR TABLE 7.7-5 This Table has been deleted 1 of 1 Revision 31 December 5, 2019

SGS-UFSAR TABLE 7.7-6 This Table has been deleted 1 of 1 Revision 31 December 5, 2019

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PSEG Nuclear LLC SALEM NUCLEAR GENERATING STATION BLOCK DIAGRAM OF REACTOR CONTROL SYSTEM I

I I

I U~dated FSAR Figure 7.7-1 R V 31 DECEMBER 05 2019

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ © 2013 PSEG Nuclear LLC.

Al I R!.9b_ts ReserveJ

Description Polar Crane Jib Mobile Cherry Pickers (2)

Demineralizer &

Ion Exchanger Service Monorail SGS-UFSAR OVERHEAD HANDLING SYSTEMS Rated Capacity (ton) 12.5 15 6

Location (ft)

Containment Building Elevation 130 Containment Building Elevation 130 Containment Building Elevation 130 Containment Building Elevation 130 Containment Building Elevation 130 Auxiliary Building Elevation 122 TABLE 9.1-4 (Cont)

Description RCP Motor Access Plugs RCP Motor RCP Motor Flywheel Equipment Hatch Stud Rack with 9 RPV Head Studs Lead Filled Plugs Concrete Floor Plugs 2 of 6 Weight (lb) 30,000 77,000 14,250 23,300 7,000 10,000 5,000 HEAVY LOAD Drop Height (ft) 60 60 60 N/A N/A Safety Related Equipment/

Components Involved in Dropped Lift 22 above El. 102' eve system control cables 1~ above El. 122' running in Trays 1A418, 1A420,2A418, 2A420, Drawing 205841.

2 Revision 31 December 5, 2019

OVERHEAD HANDLING SYSTEMS Rated Description Auxiliary Feedwater Pumps Monorails Charging Pump Monorails Capacity (ton) 1.65, 2.45 Component 1.6 Cooling Pump Monorails Safety Injection 1.3 Pump Monorails SGS-UFSAR Location (ft)

Auxiliary Building Elevation 84 Auxiliary Building Elevation 84 Auxiliary Building Elevation 84 Auxiliary Building Elevation 84 TABLE 9.1-4 (Cont)

Description Hittman Casks Lid Portable Demin Motor Driven Pump Turbine Driven Pump Weight (lb) 9,500 9,000 4,400 3,300 Upper Centr. Charging 4,900 Pump Casing Recip. Charging Pump Motor Recip. Charging Pump Coupling Component Cooling Pump Motor Safety Injection Pump Motor 4 of 6 1,500 6,000 2,650 2,450 HEAVY LOAD Drop Height (ft) 2~ Area A 14 Area B 3

3 3 1/2 3 1/2 5

8 4

Safety Related Equipment/

Components Involved in Dropped Lift Redundant air supply

  • Associated eve piping and waste decon. tanks on the elevation below.

There may be occasion to lift over operable component cooling pump in the case of pumps 12 & 13.

Waste holdup tanks, monitor tanks, vital

. cable trays, and service water piping on elevation below.

Safety injection pump.& piping.

Revision 31 December 5, 2019

OVERHEAD HANDLING SYSTEMS Rated Description Containment Spray Pump Monorails Monorail Serving Elevation 55' and Elevation 45' Temporary Crane Mobile Crane Cask Handling Overhead Crane Service Water Strainers Monorails Mobile Crane Crawler Crane Capacity (ton) 2.15 2.15 18 30 115 Main 10 Aux 5

160 275 Location (ft)

Auxiliary Building Elevation 84 Auxiliary Elevation 55 Roof Auxiliary Building el. 140' Fuel Handling Building Elevation 130 Service Water Intake Structure above Service Water Strainer El. 90' Service Water Intake Structure El. 112' TABLE 9.1-4 (Cont)

HEAVY LOAD Description Containment Spray Pump Motor Residual Heat Building Motor Access Plug Misc.

Spent Fuel Cask w/Spent Fuel Bottom Block Service Water Strainer Service Water Concrete Cover Plugs (hatch MKPC-1 and MKPC-2)

Weight (lb) 4,000 3,950 Removal Pump 12,400 200,000 4,200 7,000 12,000 &

13,500 Drop Height (ft) 3 1/4 2 1/2 above el.

55' 1 above El. 55' 12 1

Area A Safety Related Equipment/

Components Involved in Dropped Lift Associated containment spray piping.

Chemical Volume Control (CVC) System and service water piping and vital cable trays on the elevation below.

Residual heat removal pump and piping.

Safety related equipment on the floors below.

See Notes 1 & 2 Spent fuel in racks Transfer Pool liner Service water piping and header.

Intake bays pump suctions on elevation below.

Service Water intake structure Service Water piping and header

& intake bay pump suctions on the elevation below see Note 4.

Note 1:

Because the crane is single failure proof as per ASME NOG-1-2004, a load drop is not credible.

Note 2:

The cask handling overhead crane can be load tested for a lower capacity and used to lift lower loads.

Note 3:

Deleted.

Original crane is 18 ton Grove crane. *

    • Tadano crane SGS-UFSAR 5 of 6 Revision 31 December 5, 2019

Description Crawler Crane Note 4:

SGS-UFSAR OVERHEAD HANDLING SYSTEMS R.;ited Capacity (ton)

Location (ft)

TABLE 9.1-4 (Cont)

Description Service Water Pump Service Water Pump Motor Weight (lb) 12,800 13,200 275 Service Water Traveling Screens 17,325 Intake Structure El. 112 & 122 Fish Gate 3,000 HEAVY LOAD Drop Height (ft) 12 12 Area A&B 2 Area C Safety Related Equipment/

Components Involved in Dropped Lift Service Water intake structure -

service water piping and header

& intake bay pump sections on the elevation below, see Note 4.

For Area locations see VTD 315130 Sheet 2 "Nine-Month Response for Control of Heavy Loads for Salem Nuclear Station Units 1

& 2" figure B-10, A20 and A21.

6 of 6 Revision 31 December 5, 2019 I

The hypochlori te system piping inside the service water intake structure is designed for Class II (seismic) conditions, but the pipe supports are designed to Class I (seismic) criteria.

The separated redundant service water lines between the service water pumps and the Unit 1 component cooling heat exchangers are not located in open trenches as such, but rather are constructed of reinforced concrete pipe completely buried in the ground.

Thus, in effect, they are located in "sepc:rate trenches."

The principal supply line piping runs are separated by about 13 feet.

This separation, in conjunction with the depth at which they have been

buried, makes these lines essentially invulnerable to damage from a single postulated event.

The above discussion also applies to the service water piping to the Unit 2 component cooling heat exchangers except for one section of piping running a-long the west side of the Auxiliary Building.

Though not buried, this piping is located within a 4 foot-6 inch thick reinforced concrete pipe tunnel.

The redundant supply lines within the tunnel are separated by a 3-foot thick reinforced concrete wall, again precluding coincident failure due to a single event.

Status is displayed and control of each service water pump is available on the main control panel so that an operator can determine if an abnormal number of pumps is operating.

In addition, indication of the 14 and 24 pump in "TEST" is displayed on the auxiliary annunciator during performance of surveillance testing. Status and control of all SWS isolation valves and motor-operated header block and tie valves is also available to the operator in the Control Room.

The motor-operated valve operators (with the exception of the Turbine Area isolation valves) complete their closing or opening cycle in 1 minute while the containment isolation valves can close in 10 seconds.

The Turbine Area isolation motor operated valves have a more rapid operating time of a maximum of 37 seconds.

The rupture of a large pipe or other event causing a high system flow demand will be indicated to the operator by decreasing pump header pressure shown on the main control panel.

Low pump header pressure will be alarmed to the main control room.

If pump discharge header pressure continues to*fall, and outside power is available, a backup service water pump will start automatically.

9.2-7 SGS-UFSAR Revision 18 April 26, 2000

Each SWIS pump compartment contains a sump whose nominal capacity is 49 cu. Ft.

(366 gal.), and each has a sump pump capable of removing over 250 gpm.

In the event that a pipe rupture occurs in a watertight pump compartment in the service water intake structure, which is beyond the capacity of the sump pump, high sump level for the affected compartment will be alarmed to the Control Room.

The Control Room operator can remotely close the tie valves and header block valves at the intake structure to isolate the affected compartment and remotely start the remaining pumps in the other pump compartment to permit an orderly plant shutdown.

In the event that a main yard supply header is ruptured, the affected header can be isolated by the Control Room operator who can also open the tie valves at the Auxiliary Building.

Rupture of a header pipe for Unit 2 in the pipe tunnel can also be detected by high level to the Control Room alarm from the sumps containing a 100 gpm pump.

The Control Room operator can determine the affected header by remotely closing the intake tie valves and observing which pump header is affected by low-low pressure.

Once the rupture yard header is isolated, the intake tie valves can be opened and all service water pumps made available.

Service water piping in the Auxiliary Building is, for the most part, accessible during operation for inspection by the operators.

Generic Letter (GL) 96-06 was iss~edby the NRC to notify utilities of ~afety

_,signi_f_icant issues that. could affect containment integrity and equipment operability_during accident conditions.

The SW system is designed to withstand the effects of events described in GL 96-06.

These GL concerns of thermally induced overpressure,. the development of** tw*o-phase flow regions, and column separation or voiding leading to the possibility of waterharnmer events are addressed by system modifications.

A pressurized *tank* in each of the two service water headers is installed to serve the con.tainment fan cooler unit (CFCU) loops.. The supply lines between the* tanks ana the: SW headers have fast opening* valves. to allow flow in the event of a LOOP (Loss Of Off-si*te Power)

  • or LOOP/LOCA.

The tanks have a volume of 15,000 gallons each a:nd* are* pressurized with nitrogen, and dj,scharge into the SW system upon a: los.s of.. off-site power.

The vessels are* sized to conti3.in sufficient water inventory to keep the SW piping full for all postulated operating and single failure conditions.

A separate building houses the storage tanks, piping and the storage tank instrumentation and controls.

9.2-8 SGS-UFSAR Revision 31 December 5, 2019

In the event that radiation is detected at one of the service water outlets from the containment, the condition is* alarmed in the Control Room.

The final decision to isolate the coils is based on plant conditions, analyses, and indications.

The service water flow* throu*gh the containment fan cooler uni ts is indicated on the control console.

A temperature detector monitors the fan cooler outlet temperature, which is indicated on the control console; high water temperature could be an indication of inadequate flow.

The service water flow through each Component Cooling Heat Exchanger is normally controlled by means of a cascade contr9l system which simultaneously throttles both the inlet and. outlet control valves with a common control air signal.

The valves are throttled to maintain component cooling water outlet temperature as t~e primary parameter, and flow will be limited to a nominal operating value of 10, 000 GPM as the secondary parameter.

  • The Service* Water flo_w can be controlled manually in order to establish the desired Compon*ent Cooling outlet temperature.

The indicati_ng valve control system is m~unted on an instrument panel which is located in the Auxiliary Building in the vicinity of the heat. exchanger. In addition, a flow transmitter alarn1s a service *water high flow condition on the overhead annunciator in the Controi Room.

In certain post-accident alignme.nts,. available system pressure will be limited such.that the Component Cooling Heat _Exchanger original design flow of 10,000 gpm may not be attainable for both heat exchangers.

As noted in Table 9.2~1, the currently evaluated design (minimum required) flow has been defined to. be 8,000 gpm with 90° F.water.

The capability of meeting or exceeding this:flow, where required, is demonstrated in detailed system*calculations.

9.2-9 SGS-UFSAR Revision 31 December 5, 2019

Material inspection, fabrication, and quality control conform to ANSI B31. 7.

  • Where not possible to comply with ANSI B31.7, the* requirements of ASME III-1971, which incorporated ANSI B31. 7*, * *were adhered to.

In addition, the weld inspection* criteria of later Editions and. Addenda* of ASME III, as approved by the NRC, can be specified.

Radiographs of Nuclear Class 3 cement-lined pipe were difficult to interpret.

The 1970 addenda to B31. 7 allowed* 100-percent magnetic particle inspection in-lieu of random radiography.

This provision was also incorporated into Section III, 1971 Edition.

The SWS contains Nuclear Class 3 cement-liried pipe for

  • I which this alternate inspection method was utilized.

In addition, the weld

. ~::p:::~o:a:r::e:;:c::ie~~ter Editions and Addenda of ASME III, as approved by I

I For the original cement lined piping the use of a later code was restricted to*

inspection and did not involve any requirements from Section III such as material, stress calculations,* etc., that would modify our original design.

Consequently, other requirements from a later code would not be applicable.

There.fore it is believed that the integrity of field

  • welds has not been compromised and that we have complied with our conunitment to-use ANSI B31. 7 whenever possible.
  • In addition, the weld inspection criteria of later Editions and Addenda of ASME II I, as approved by the NRC, can be. spE;ci f ied.

As part of a reliability improvem~nt program, replac.ement of portions of the system piping was initiated in 1988 for both Onit 1

and Unit

2.

The replacement material selected after an extensive qualification program is a 6%

molybdenum Austenitic Stainless Steel, which is furnished to the material requirements of the ASME code S,ection III, Division 1.

However, fabrication, inspection and insfallation of this piping m9-terial i.s in accordance with ANSI 831.7 *antj ther13for_e __ compliance with the conunitment to utilize ANSI B31.7.

wherever possible has again been maintained.

In addition, the weld inspection criteria of later Editions and Adden!'.ia of ASME III, as approved by the NRC, can..

be specified.

In. order to provide enhanced r:1ccuracy. and repeatability for. periodic ASME Section* XI performance testing, a full flow Service Water* Pump surveillance test line was.added to the Service W'ater Intake 9.2-9a SGS-UFSAR Revision 18 April 26, 2000

e

Both units CREACS operates simultaneously in pressurized mode during a

radiological design bases. a9cident and in. full. recirculation mode during a toxic gas, ha_zardous. chemical release; or ;imoke generated inside the control room area.

Provisions in the design provide for a single CREACS train to be operated and provide *long term occupancy : in.the CRE during a radiological condition.

The CAACS and CREACS cooling coils are supplied with chilled water from the Chilled Water System located in. each uni,t' s. mechanical equipment area located at elevation 100 foot of the Auxiliary Building.

Each unit's Chilled Water System consists of three 50% capacity package ~hiller units, two 100% capacity recirculating -.pumps, condensers cooled by the.. service water system (SWS), and interconnecting refrigeration, service water and chilled water piping.

The Chilled Water System has a

side stream demineralizer to maintain water chemistry and a recirculation line from the chilled water pump (1CHE6, 2CHE7) to. the chilled water expansion tank (lCHEl, 2CHE8) drain line. to prevent stagnant water conditions in the. tank.

The demineralizer and recirculation line are added. as a part of the plant life extension commitments.

The Chilled Water System has ample capacity to cool the areas serviced by CAACS and CREACS.

during normal and emergency operating conditions.

.During single CREAC~ train operation,. the

  • associated cooling coil is provided with sufficient chilled..

water with. two chillers _in service to maintain. temperatures inside.the CRE below 85°F at outside summer. design conditions, except for the Data Logging

Rooms, which are maintained below 90°F.

The air conditioning equipment is designed to Class I (seismic) criteria*and cari be*eriergized from the standby ac power supply*.

Depending oh outside climatic: conditions, one or two CAACS fans per unit are*

normally in operation, the third* serving as *standby.

The CREACS is i*sol'ated and in standby during normal operation. *

  • The CAACS normally operates with a fixed amount of outside air to maintain a siight positive pressure in* the CRE.

The controi area ventilation system has* four *mod*es of' operation.

follows:

They are* as Normal (Mode 1)

This is *the operating mode* for CAACS. *during normai p'lant operations.* in* this mode, a. mixture:: of outside air and r.ecirc.ulated air is* supplied to. the* control room areas (relay room, equipment

room, and the CRE) to maintain design temperature conditions within limits.

Typically,_ one or two, supply fans are*

operating with the third acting as a backup.

The outside makeup (CAA40

& 43 open) and recirculated air is mixed and filtered through roughing filters, cooled (or heated), and supplied to the control room areas.

The CRE and control room areas (relay and control equipment rooms) are maintained at a positive pressure.

The CREACS is isolated and in standby.

9.4-lb SGS-UFSAR Revision 31 December 5, 2019

fire Inside control Area (Mode 2)

rn the event of a fire or_111110ke gen-.rated i,n the control r~, each unita.CAACS is. mAl'.lually initiated by the op:trators f.or.,on~ through, 1001 outside air operation. or purge. In this mode, a.11_ of the n,ormal intake (CAA40, 41_, 4_3 __ & 45) and ~ha~at d*rs (CAA1~ & 19). open _and return damper (CAAS) closed tc* allow 100, outside air to be pumped through the control room areaa and expeiled to the outside, thereby making the control rccm habitable.*

A ~imum of two ~CS supply fans can be operating in this mode.

Roughing filters are used for filtering the outside air.

The CREACS is isolated and in standby.

fire outside eont;21 Area fMgde 3)

In the event of airborne toxic gas,,,bazargous chemical. relell9el!I, or IIJIIQke £~

outside the.control rOQD, provisions are made for 1001 recirculated air~ :rn this mode, all of the normal intakes (CAA40, 41, 43 & 4~), emergency intakes (CAA4S, 49,.50 & 51) and axhauat:.

(CJUUB

19).. dampera are ~loaad isolating ~

ventilation systems from the outside environment..

The Unit 1 and 2_ CAACS are is~lated from the am (by closure of CAA14 and CAA20 dampers> and operates in the

£u11 recir~lAtion supplying cool air *to the relay and equipnent* rooma,*while both unit' a CREACS operate to recirculate air to the cm:. A maximum of two CAACS supply *fans,_ and _one CBEACS supply fan_ per unit.can be operating in 1;hi~ mode

  • Chillad_water control valva CB74 open and CH16S ia parmanentiy open to supply chilled water to the CAACS and c.REACS coils, respectively. Recirculated air to the control room envelope paaliaa tbrougti a cooling. coif and high ef:ficienq particulate air (HEPA) and charcoal filter banks.

'l'hia mode is manually initiated. by the operators frcm both control rooms.

Accident Pressurized -. Two Filtration Train Alignment {Mode 4) *.

A mode. of. opera:tion has been proyid~d in_ the event of airbo~e radioactivity au,id long term, occupancy of the. control...room.. In _this mQd,e, all.of the normal i_nt:.ake

~'

(CAA40, 41, 43 & 45), exhaust (CAAlB & 19), and CRB boundary (CAAl.4 and c,lA20) dampers are cloaed isolating both units CAACS from the cuteide environment and the ~-. Chilled water control valve CH16,8 is perman~ntly opan.

Trua CAACS operates in Koda 3 with CH74 _valve open;.1'n emergeintj: i.ntalce ;trom ~ne"unit w~ll open and. the oppoaite will remain closed baaed on which unit initiated the accident 8ignal. Both CREACS filtration trains will start with one fan operating in each unit.

If one of the fans fails to start, the standby fan wiil automatically start.

9.4-2 SGS-UFSAR Revision 16 January 31, 1998

~-*

Auxiliary Building and the containment.

This reduces the potential hazard of irradiated particles being transported throughout -.the.. building and reduc~s-1:he loading on the exhaust filters.

The HEPA type exhaust filters, in turn, continuously minim:iz~

the.. *release of particulate radioactivity to. the envir~~~nt wh*ile the st~ndby. charcoal fii ter is. available to adsorb gaseous contamination*.

The *d~sign * ~"apabiiity' of '*a thr~~-part high level

  • filtd:tfon tra.in 8nsU'res that a11 8Xhaustect emissions.,

4

,f~om the Auxiliary Building and the*

. containment are within the requirements of 10CFR20.

Availability of the Auxiliary Bu~lding supply and.exhaust yenb,lation equi.pment is ensured by connection to the standby ac power supply.

The room coolers located near vital pumping equipment are single capacity units.

The total capacity of the room cooler(s); in a given area,.. in conjunction with the exhaust air flow rate, is designed to limit the area temperature to the design values even if all pumping equipment in the area is operated continiJ.ously.

In the event that the Safety Injection Pump*Room cooler fails** concur~ent with operation of both. SI pumps, temperature in the SI Pump*

Room may exceed 120°F. _Equipment in this area wil~ operate at temper,a~~res to 146°F.

,Similarly, in the event that the 12 (22) Component Cooling Water.(CCW)

Room Cooler fails concurrent with operation of*. both CCW pumps in the* room, terrip'eratures in the 12 (22) CCW Heat Exchanger and :Pump R*oom may exceed 120°F:

Equipment in this.. area will operp.te at 1:emperatures to. 132°F.

. ~ '*.,.....

9.4.2.4 Test and Inspections All components of* the. Auxiliary. Building Ve:qtilq.tiqr:i_ SyC?tem are... 9ubj ected *to. a test and inspection program.

This program is similar to that described for the Containment Ventilation: System (Section 9."4'. 4 )'~ '*e:Xce*pt the resistance -to* LOCA pre~sure. :a:nd temperature trahsien:ts is not': applicable to the Auxiliary Bi:iilding

,*~ '

equipment.

The A~xiliary Building exhaust ai; iiltr'ati~n :system :testing is' ~ontained, i~

the Salem Technical. Requirements ~-'.iarrual. * *

  • 9.4-15 SGS-UFSAR Revision 31 December 5, 2019

9.4.3 Fuel Handling Area ventilation

9. 4 *. 3.1 Design Bases The Ventilation System is designed to exhau_st the spent fuel pool area at 60 air changes an hour within a 10..:foot height above the pool *cturing design conditions for spent fuel storage.

Out of

  • a system operating capacity of 20 1 000 cfm, 15,000 cfm is exhausted from the spent fuel pool area (10,000 of which is extracted right at the pool surface) and the remaining 5,000 cfm of system capacity ventilates other parts of the building, Because of the potential for radioactive releases from the spent fuel, defective fuel cladding or a fuel handling mishap, the building is maintained at a slight negative pressure to assure tnleakage -of air rather than outleakage.

The total capacity of the Ventilation System, along with the area space heaters, is designed to maintain the building between 60°F and 105°F, The space heaters are not safety-related, do not receive Class lE power, and would not be available during a loss of offsite power.

-An eva,:J.uation of the Fuel Handling Building has justified a minimum temperature of 40°F.

Although there is no dire~t control of the humidity in the building and there can be instances of 100-percent relative humidity around the spent fuel pool when the outdoor air is damp, the relative humidity under design conditions is expected to be less than 70 percent.

The exhaust filter units, fans and controls are designed to Class I (seismic) criteria.

The discharge ductwork from the fuel handling area to the plant vent is also designed to Class I (seismic) criteria, The supply air equipment is served by the Normal AC J?ower System* only, whereas the exhaust air equipment can be energized from the Standby AC !?ower System in the event of a loss of offsite power,* The seismic design and analysis methodologies used to qualify all ductwork and the contained equipment are described in Section 3,8.4.4.1.

9. 4-16 SGS-tJFSAR Revision 20 May 6, 2003

10.2.2.5 Instrumentation Instrumentation is provided to continuously monitor and/or alarm such turbine generator parameters as the following:

1.
  • Generator load
2.

Shaft vibration a~ bearings

3.

Shaft eccentricity

4.

Shell expansion

5.

Differential expansion between turbine* shell and rotor

6.

Turbine speed

7.

Turbine casing temperatures

8.

Bearing temperatures

9.

Hydrogen gas and stator cooling water temperatures

10.

Generator frequency

11.

Exhaust hood te~perature

12.

Condenser vacuum

13.

Stator winding temperatures

14.

Hydrogen pressure and purity

15.

Bearing lube oil and hydraulic oil pressure 10.2.2;6 TURBINE OVERSPEED PROTECTION The information in this section was relocated to the. Salem Technical Requirements Manual.

10. 2-6a SGS-UFSAR

-~,._ : ';:_

Revision 31 December 5, 2019

This* page left intentionally.blank 10.2-6b SGS-UFSAR Revision 31 December 5',* 2019.

SGS-UFSAR This page left intentionally blank 10.2-7 Revision 31 December 5, 2019

10.2.3 Turbine Missiles The subject. of turbine missile charact.. eristics,. probability of occurrence and protection of. essential safety_ equipment is covered in Sect.ion.3. 5.

Section 3.5 also deals with characteristics of the turbine discs, b_lades, and rotors as they relate to the subject of turbine missile formation.

10.2.4 Evaluation Automatic control actions, alarms and trips are initiated by deviations of system variables from preset values.

In every instance automatic control functions are programmed such that appropriate corrective action is taken to protect the RCS as well as the Steam and Power Conversion Systems.

10.2.5 Turbine Generator Test and Inspection 10.2.5.1 Turbine Generator Monitoring Each turbine generator is equipped with supervisory instrumentation that monitor such variabies

  • as pressure, temperatures, flows*;

speed,

  • vibration, eccentricity, rotor position, casing. differential and rotating differential expansion.

In the event that abnormal re:~dings are being. received, investigations will be made to ascertain the cause of the abnormal readings and, if necessary, the unit will be shut down.

Investigations made may consist of nondestructive tests, such as visual, magnetic particle, liquid penetrant, ultrasonic and radiographic, where deemed possible.

Periodic inspections will be made as recommended by the turbine generator manufacturer.

10.2-8 SGS-UFSAR Revision 31 December 5, 2019

Design flow rate, scfm 30 Design delivery pressure, psig 100 Gas Analyzer Redundant gas analyzers, one in each Salem Unit aI}d both cross-connected, are provided in accordance with the recommendations of NUREG-0472 to automatically monitor the concentration~ of oxygen and hydrogen in the system~ in order to indicate when the accumulation of these gases approaches an explosive mixture.

  • Upon indication by' alarm -that the oxygen level is approaching a hazardous level, provisions must be made to either isolate the component or purge with nitrogen to the GWS. The gas analyzer has suitable connections for sampling

. when necessary from the.. following components:

Waste gas to plant vent Reactor coolant drain tank Spent resin storage tank Gas decay tanks (2 points) eves holdup tanks Boric acid evaporator and gas stripper Volume control tank Pressure relief tank

. Gas decay: tat1k. samples are analyzed continJo_usly to ensure that the _ ~~ygen concentration remains less.. than. or. ~quai° t~ 2 percent.

Separate feed ;lines with calibration gases are provided for analyz_er calibration purposes.

The

  • 11.3-11 SGS-UFSAR Revision 20 May 6, 2003 I
  • '"\\'

I

high-span calibration gas is nominally 4% oxygen, and low-span calibration gas is nominally 1% oxygen.

The balance of the calibration mixtures consists of nitrogen, except for small amounts of hydrogen (between 1% and 2.5%).

The gas mixture allows calibration of the analyzer to the profile expected in the sample stream at alarm conditions.

Design data for the analyzers are as follows:

Oxygen Hydrogen Recorder printout (chart)

By partial pressure measurement 0-5% o2 Range By partial pressure measurement 0-25% H2 Range Waste Gas Decay Tank: every 3 minutes Sequential sampling (cover gas): each point All. major equipment in the Gaseous Radwaste Disposal System is located outside of the Reactor Containment Building in the Auxiliary Building, Elevation 64 feet and 122 feet.

11. 3-12 SGS-,UFSAR..

Revision 31 December 5, 2019

Piping Gas piping is mainly carbon steel with stainless steel piping in some sections installed as part of modifications.

Piping connections are welded except where flanged connections are necessary to facilitate equipment maintenance.

Valves exposed to gases are either carbon steel or stainless steel.

Isolation valves are provided to isolate each piece of equipment for maintenance, to direct the flow of waste through the system, and to isolate storage tanks for radioactive decay.

Relief valves are provided for tanks containing radioactive wastes if the tanks might be over-pressurized by improper operation or component malfunction.

Codes and Standards Additional information is presented in Table 11'.2-3 for system piping, valves and compressors.

11.3.4 Operating Procedures The gaseous wastes processed by this system consist primarily of hydrogen stripped from reactor coolant during boron recycle and degassing operations and nitrogen from the various tank cover gases and from the degassing operation.

These gases are discharged to the vent header which feeds the suction of the waste gas compressors.

One of the two waste gas compressors will be operating with the other compressor being on standby.

pressure of 0.5 to 4.0 psig.

The operating compressor maintains a vent header If the vent header pressure rises to standby compressor automatically energizes.

The compressors can be pump gas to the waste decay tanks; 2) transfer gas between tanks; gas directly to the eves holdup tanks.

11. 3-13 4 psig, the used to: 1) and 3) pump SGS-UFSAR Revision 31*

December 5,-* 2019

I To pump gas to the gas. decay tanks, -the operator selects two tanks at

  • the auxiliary control panel No. 104: one to receive gas, and one for standby. When the tank in,..service is pressurized to 92 psig, flow is automatically switched to the standby tank and an alarm alerts the operator to select a new standby tank. The decay tank being filled is sampled automatically by the.gas analyzer and an alarm will alert the operator to a high oxygen content.

The tank must then be isolated and the operator is required to direct *flow to the standby tank and select a new standby tank.

As the liquid in the eves holdup tanks is processed by the boric acid evaporator, gas must be provided as cover gas to replace the processed liquid.

The cover gas may be provided from any of. the gas decay tanks or from the nitrogen supply.

The gas decay tank supplying the returning cover gas is selected manually at the auxiliary control panel No.

104 by opening the appropriate valve iri the return line header.

To maximize total residence time for gas decay in the system, the last tank filled should be the first tank returned as cover gas, A backup supply of gas to the holdup tanks is provided from the bulk nitrogen header for makeup when return flow is not available from the decay tanlcs.

Before a gas decay tank is discharged to the plant vent for release to atmosphere, a sample must be taken to 'determine activity concentration of the gas and total activity inventory in the tank.

Total tank activity inventory is determined from the

  • activity concentration and pressure 'in the tank.

To release the gas, the appropriate local manual stop valve is opened to the plant vent and the gas.discharge modulating valve is opened at the auxiliary control panel.

If the Plant Vent Radiation Monitor detects high activity during release, the modulating valve automatically trips closed. To reopen the valve, the switch must first be reset by returning it to the closed position. The valve can then be repositioned.

The equipment which connects with the vent header system is limited in number.

Under normal operating conditions no air is perrnitt.ed to enter the vent header.

During maintenance operations air could enter the boric acid* evaporator vent condenser or the waste evaporator vent condenser.

During maintenance operations on either of these pieces of equipment, the valve on the equipment discharge line to the vent header is closed.

When maintenance operations are completed, and prior to opening the valves, the equipment is filled with nitrogen to purge the air.

During discharge, the nitrogen purge is continued.

No fluids can get into the vent header.

11. 3-14 SGS-UFSAR Revision 23 October 17, 2007

Control Room Area.**(channel 2:...RlA~

  • 1~RlA) - This channel continuously monitors the Control." Room* *area.

This area monitor does not have its own integral flashing beacon* and horn. since it is located in the Control Room and an alarmed condition*is indicated by the annunciator and audible alarm (Unit 2 is provided with LED alarm indication and an adjustable volume horn).

This is* a non-safety-related unit with a vital power supply.

2.

Containment Area (Low Range) (l-R2, 2-R2)

3.

Radiochemistry Laboratory (R3)

4.

Charging Pump Room (l-R4, 2c-R4)

5.

Fuel Handling Building (Channels* 1-R5 and 2-R5) - These channels continuously monitor the fuel storage areas.

A high: radiation alarm from -either unit wil~ initiate charco~l filtration of the Fuel Handling Building atmosphere.

The Fuel Handling Accident in the.fuel Handling Building was analyzed without credit for filtration by the Fuel Handling Building Ventilation System.

For Unit 2 the high radiation-alarm will automatically start the exhaust fans..

In addition to the integral.alarm.horn and flashing bea.con, these units actuate. an eme_rgency evacuatio_n -horn in. the. buildi_ng and radiation alert lights.outside of the bui_l~ing.

Each unit is on a _ separate vital power supply.

6.

. Sampling Room (R6A).

7.

. In-core Seal Table (l-R7, _ 2-R7)

8.

Fuel Storage Area (l-R9, 2-R9) - These channels continuously monitor the fuel storage areas.

.A high radiation alarm from eitl;ler.unit will SGS-UFSAR automatically start the. exhaust. fans (Unit 2.only) and initiate charcoal 11.4-19 Revision 22 May 5, 2006

filtration of the Fuel Handling Building atmosphere.

The Fuel Handling Accident in the Fuel Handling* Building was analyzed without credit for charcoal filtration by the Fuel Handling Building Ventilation System.

In addition to the integral alarm horn and flashing beacon, these units actuate an emergency evacuation horn in the building and radiation alert lights outside of the building.

Each unit is on a separate vital power supply.

9.

Containment Personnel and Equipment Hatches (1-RlOA, Band 2-RlOA, B)

10. Counting Room (R20B)
11. Containment Area (High Range)

(1-R44 A and B and 2-R44 A and B) -These channels continuously monitor the containment area and are provided with a special ion chamber detector for extended range capability in a post-accident environment.

power supply.

This is a safety-related unit with a vital

12. Public Service Control Point (R23)
13. Fuel Handling and Cask Handling Cranes (l-R32 A and B, 2-R32 A and B) -

These channels are not connected to the central Radiation Monitoring System and are not provided with integral horns and flashing beacons. A flashing beacon and al.arm bell on the cranes are initiated.

14. Mechanical Penetration Area (1-R34 and 2-R34)
15. Condensate Filter Area (1-R40 and 2-R40)
16.

(Deleted)

17.

(Deleted)

11. 4-20 SGS-UFSAR Revision 31 December 5, 2019

Channel No.

R23 l-R32A (2) l-:-R34 l-R44A l-R44B NOTES:

Channel Description Monitoring Room Fuel Handling Crane Monitor Mechanical Penetration Area Containment (High Range)

Containment (High Range)

Type of Detector GM Tube GM Tube GM Tube (1)

Also performs a safety function TABLE 11. 4-3 (Cont.)

Range Control Function/Interlocks 10-1 -10 4 mR/hr 10-1 -10 4 mR/hr 10-1 -10 4 mR/hr

. 10° -

107 R/hr lOO -

107 R/hr (2)

Local monitor only.

Not indicated, r~corded, or alarmed in the control.room.

2 of 2 Revision 31 December 5, 2019

Channel Channel No.

Description 2-R34 2-R44A 2-R44B NOTES:

Mechanical Penetration Area Containment (High Range)

Containment (High Range)

TABLE 11.4-4 (Cont.)

Type of Detector GM Tube Ion Chamber Ion Chamber 10-1 -10 6 mR/hr 10° -10 7 R/hr 10° -10 7 R/hr Also performs a safety function.

Control Functions/Interlocks (1)

(2)

Local only -

Not connected to RMS monitor in the Control Equipment Room.

2 of 2 SGS-UFSAR Revision 31 December 5, 2019

Section 13.1 13.1.1 13.1.1.1 13.1.1. 2 13.1.1.3 i3.1.1. 4 13.1.1.4.1 SECTION 13 CONDUCT OF OPERATION TABLE OF CONTENTS Title ORGANIZATION STRUCTURE Deleted Deleted Deleted Deleted Deleted Deleted 13.1.1.4.1.1 Deleted 13.1.1.4.1.2

13. 1.1. 4. 1. 3 13.1.1. 4.1. 4 13.1.1. 4. 2 13.1.1.4.3 13.1.1.4.4 13.1.2 13.1. 3 13.1.4 13.1. 5
13. 1. 6 13.1.7
13. 1. 8
13. 1. 9 13.1.10 13.1.11 13.2 13.3 13.4 13.5 13.5.1 13.5.2 13.5.3 13.5.4 13.6 13.7 SGS-UFSAR Deleted Deleted Deleted Deleted Deleted Radiation Protection Deleted Deleted Deleted Deleted Deleted Deleted Deleted Deleted Deleted Deleted TRAINING EMERGENCY PLANNING REVIEW AND AUDIT PLANT PROCEDURES Administrative Procedures Operating and Maintenance Procedures Additional Operating and Maintenance Procedures Technical Requirements Manual PLANT RECORDS SECURITY 13-i 13.1-1 13.1-1 13.1-1 13.1-1 13.1-1
  • 13.1-1 13.1-2 13.1-1 13.1-1 13.1-1 13.1-1 13.1-1 13.1-2 13.1-2 13.1-2 13.1-2 13.1-2 13.1-2 13.1-2 13.1-2 13.1-2 13.1-2 13.1-2 13.1-2 13.2-1 13.3-1 13.4-1 13.5-1 13.5-2
13. 5-3 13.5-4
13. 5-7 13.6-1 13.7-1 Revision 31 December 5, 2019

TABLE OF CONTENTS (Cont)

LIST OF TABLES Table Title 13.1-1 Deleted 13.5-1 Administrative Procedure Topics 13.5-2 Abnormal Operating Procedures 13-ii SGS-UFSAR Revision 31 December 5, 2019

Figure 13.1-1 13.1-2 13.1-3 13.1-4 SGS-UFSAR Title Deleted Deleted Deleted Deleted TABLE OF CONTENTS (Cont)

LIST OF FIGURES 13-iii Revision 31 December 5, 2019

SECTION 13 CONDUCT OF OPERATIONS 13.1 ORGANIZATION STRUCTURE The original content of this chapter has been modified as allowed by Regulatory Guide 1.181 in conjunction with NEI 98-03, Guidelines for Updating Final Safety Analysis Reports (see UFSAR Appendix 3A).

On August 21, 2000, the operating licenses for the Salem Units 1 & 2, and for the Hope Creek station were transferred from Public Service Electric & Gas (PSE&G) to PSEG Nuclear LLC.

PSEG Nuclear LLC, a limited liability company, is a

subsidiary of Public Service Enterprise Group (PSEG),

an investor-owned company headquartered in the State of New Jersey.

PSEG Nuclear LLC is dedicated to the safe, reliable and efficient operation of the nuclear units and assumes full responsibility for meeting all license obligations.

The PSE&G corporate organization and its functions and responsibilities are described in Chapter 2 of the Quality Assurance Topical Report NO-AA-10, as revised.

For the Hope Creek project, Bechtel Power Corporation and Bechtel Construction, Inc. designed and constructed the plant.

General Electric Company designed, supplied and provided engineering support for the Nuclear Steam Supply System (NSSS) for the Hope Creek project.

For the Salem projects, PSE&G and Westinghouse Electric Corporation jointly participated in the design and construction of each unit.

PSE&G provided an experienced and trained staff to support preoperational testing, core load and power ascension testing programs of the nuclear units.

The PSEG 1')'uclear LLC organizational structure and reporting relationships are described in the Quality Assurance Topical Report NO-AA-10.

Roles and responsibilities are described in administrative procedures.

13.1.1 13.1.1.1 13.1.1. 2 Deleted Deleted Deleted 13.1.1.3 Deleted 13.1.1.4 Deleted 13.1.1.4.1 Deleted 13.1.1.4.1.l Deleted 13~1.l.4.l.2 Deleted 13.1.1.4.1.3 Deleted 13.1.1.4.1.4

  • Deleted 13.1.1.4.2 Deleted SGS-UFSAR 13.1-1 Revision 31 December 5, 2019

13.1.1.4.3 Deleted 13.1.1.4.4 Radiation Protection The Radiation Protection Program and organization are described in Section 12.3.

13.1. 2 Deleted 13.1. 3 Deleted 13.1.4 Deleted 13.1. 5 Deleted 13.1. 6 Deleted 13.1. 7 Deleted 13.1.8 Deleted 13.1.9 Deleted 13.. 1.10 Deleted 13.1.11 Deleted SGS-UFSAR 13,1-2 Revision 31 December 5, *2019

SGS-UFSAR Table 13.1-1 This Table Has Been Deleted See HR-AA-104 1 of 1 Revision 31 December 5, 2019

This Figure Has Been Deleted PSEG NUCLEAR L.L.C.

SALEM GENERATING STAT JON RELATIONSHIP WITH PUBLIC SERVICE ENTERPRJSE GROUP SALEM UFSAR-REV 31 December 5, 2019 SHEET 1 OF 1 F13.1-1

This Figure Has Been Deleted PSEG NUCLEAR L.L.C.

SALEM GENERATING STATION NUCLEAR ORGANIZATION SALEM UFSAR - REV 31 December 5, 2019 SHEET 1 OF 1 F13.1-2

This Figure Has Been Deleted PSEG NUCLEAR L.L.C.

SALEM GENERATING STATION SITE OPERATIONS ORGANIZATION SALEM UFSAR - REV 31 SHEET 1 OF 1 December 5, 2019

  • F13.1-3

This Figure Has Been Deleted PSEG NUCLEAR L.L.C.

SALEM GENERATING STATION STATION OPERATIONS DEPARTMENT SALEM UFSAR - REV 31 SHEET 1 OF 1 December 5, 2019 F13.1-4

Section 15.l

15. 1. 1 15.1.2 15.1.2.1 15.1.2.2 15.1. 2. 3 15.1. 3
15. L 4 15.1. 5 15.1. 6
15. l. 7 15.1.7.1 15.1.7.2 15.1.8 15.1.8.1 15.1.8.2 15.1.8.3 15.1.8.4 SECTION 15 ACCIDENT ANALYSIS TABLE OF CONTENTS Title CONDITION I -

NORMAL OPERATION AND OPERATIONAL TRANSIENTS Optimization of Control Systems Initial Power Conditions Assumed in Accident Analyses Power Rating Initial Conditions Power Distribution Trip eoints and Time Delays to Trip Assumed in Accident Analyses Instrumentation Drift and Calorimetric Errors - Power Range Neu~ron Flux Rod Cluster Control Assembly Insertion Characteristics Reactivity Coefficients Fission Product Inventories Activities in the Core Activities in the Fuel Pellet Cladding Gap Residual Decay Heat (ANS-1979)

Fission Product Decay Decay of U-238 Capture Products Residual Fissions Distribution of Decay Heat Following Loss-of-Coolant Accident 15.1. 9

,., ___ Computer Codes Utilized l:5.1. '!3. 1 FACTRAN 15-i SGS-UFSAR r

15.1-1 15.1-3 15.1-4 15.1-4 15.1-5 15.1-6 15.1-7 15.1-a*

15.1-9 15.1-10 15.1-12 15.1-12 15.1-12 15.1-14 15.1-15 15.1-15 15.1-16 15.1-17 15.1-17 15.1-18 Revision 18 April 26, 2000 I

I

Section 15.1. 9. 2 15.1. 9. 3 15.1. 9. 4 15.1.9.5 15.1.9.6 15.1. 9. 7 15.1.9.8 15.1.10 15.2 15.2.1 15.2.1.1 15.2.1.2

15. 2.1. 3
15. 2.1. 4 15.2.2 15.2.2.1 15.2.2.2 15.2.2.3 15.2.2.4 15.2.3 15.2.3.1 15.2.3.2 15.2.3.3 15.2.3.4 15.2.4 SGS-UFSAR TABLE OF CONTENTS (Cont)

Title LOFTRAN PHOENIX-P ANC TWINKLE THINC PARAGON NEXUS References for Section 15.1 CONDITION II -

FAULTS OF MODERATE FREQUENCY Uncontrolled Rod Cluster Control Assembly Bank Withdrawal from a Subcritical Condition Identification of Causes and Accident Description Method of Analysis Results Conclusions Uncontrolled Rod Cluster Control Assembly Bank Withdrawal at Power Identification of Causes and Accident Description Method of Analysis Results Conclusions Rod Cluster Control Assembly Misalignment Identification of Causes and Accident Description Method of Analysis Results Conclusions Uncontrolled Boron Dilution 15-ii 15.1-21 15.1-21 15.1-22 15.1-22 15.1-24 15.1-24 15.1-24 15.1-24 15.2-1 15.2-2 15.2-2 15.2-5 15.2-7 15.2-7 15.2-8 15.2-8 15.2-10 15.2-11 15.2-12 15.2-13 15.2-13 15.2-15 15.2-15 15.2-17 15.2-18 Revision 31 Decembers, 2019

SGS-UFSAR,.

THIS PAGE INTENTIONALLY BLANK 15-xiiib Revision 7 July 22, 1987

Figure 15.2-5 15.2-6 15.2-7 15.2-8 15.2-9 15.2-10

15. 2-11 15.2-12 15.2-13 15.2-14 15.2-15 15.2-16 15.2-17 15.2-18 15.2-19 SGS-UFSAR LIST OF FIGURES (Cont)

Title Transient Response for Uncontrolled Rod Withdrawal from Full Power Terminated by High Neutron Flux Trip (75 PCM/SEC)-

Transient Response for Uncontrolled Rod Withdrawal from Full Power Terminated by Overtemperature AT Trip (3 PCM/SEC)

Transient Response for Uncontrolled Rod Withdrawal from Full Power Terminated by Overtemperature AT Trip (3 PCM/SEC)

Effect of Reactivity Insertion Rate on Minimum ONER for a Rod Withdrawal Accident from 100 Percent Power Effect of Reactivity Insertion Rate on Minimum ONER for a Rod Withdrawal Accident from 60 Percent Power Effect of Reactivity Insertion Rate on Minimum ONER for a Rod Withdrawal Accident from 10 Percent Power DELETED DELETED All Loops Operating, Two Loops Coasting Down All Loops Operating, Two Loops Coasting Down All Loop Operating, Two Loops Coasting Down DELETED DELETED DELETED DELETED 15-xiv Revision 31 December 5, 2019

The TWINKLE code is used to predict the kinetic behavior of a reactor for transients which cause a major perturbation in the spatial neutron flux distribution.

TWINKLE is further described in Reference 18.

15.1-23 SGS-UFSAR Revision 11 July 22, 1991

15.1.9.6 THINC The THINC code is described in Section 4.4.3.1.

15.1.9.7 PARAGON PARAGON is a two-dimensional, multi-group transport theory computer code.

The nuclear cross-section library used by PARAGON contains cross-section data based on a 70 energy group structure derived from ENDF/B-VI files. PARAGON performs a 2D 70 group flux calculation which couples the individual subcell regions (pellet, cladding, and moderator) as well as surrounding rods via a collision probability technique and interface current method.

PARAGON is capable of modeling all cell types needed for PWR core design application.

PARAGON is further described in Reference 23.

15. 1. 9. 8 NEXUS The NEXUS methodology is a reparameterization of the PARAGON nuclear data output and a new reconstruction approach within the ANC core simulator code to simplify the use of this code system for design use.

The NEXUS methodlogy provides a linkage between PARAGON and ANC, establishing a new code system, while still using PARAGON.

NEXUS is further described in Reference 24.

15.1.10 References for Section 15.1

1.

Supplemental information on fuel design transmitted from R. Salvatori, Westinghouse NES, to D. Knuth, AEC, as attachments to letters NS-SL-518 (12/22/72),

NS-SL-521 (1/4/73),

NS-SL-524 (1/4/73) and" NS-SL-543 (1/12/73),

(Westinghouse NES Proprietary); and supplemental information on fuel design transmitted from R. Salvatori, Westinghouse NES, to D.

Knuth, AEC, as attachments to letters NS-SL-527 (1/2/73) and NS-SL-544

.(1/12/73).

2'.-

Regulatciry Guide 1.183, "Alternative Radiological Source Terms fcir Evaluating Design Basis Accidents at Nuclear Power Reactors", July 2000.

15.1-24 SGS-UFSAR Revision 31 December 5, 2019

3.

DELETED

4.

DELETED

5.

DELETED

6.

DELETED-

7.

Shure, K.,

"Fission Product Decay Energy in Bettis Technical Review,"

WAPD-BT-24, p. 1-17, December 1961.

8.

Shure, K. and Dudziak, D. J., "Calculating Energy Released by Fission Products," Trans. Am.-Nucl. Soc. 4 (1) 30 (1961).

9.

U.K.A.E.A. Decay Heat Standard.

10.

Stehn, J. R. and Clancy, E. F., "Fission-Product Radioactivity and Heat Generation" in "Proceedings of the Second United Nations International Conference on the Peaceful Uses of Atomic Energy," Volume 13, pp. 49-54,-

United Nations, Geneva, 1958.

  • 11.

Obenshain, F.

E.

and Foderaro, A.

H.,

"Energy from Fission Product Decay," WAPD-P-652, 1955.

12.

Hargrove, H. G., "FACTRAN, a Fortran IV Code for Thermal Transients in a uo2 Fuel Rod," WCAP-7908, December 1989.

13.

DELETED

14.

DELETED

15.

Burnett, T. W. T., et al, - "LOFTRAN Code Description," WCAP-7907, April 1974.

-16.

Nguyen, T. Q., et al, *"Qµalificat:\\.on of the PHOENIX-P/ANC Nuclear_ Design System for Pressurized Water Reactor Cores", WCAP-11596, June 1988,.

17.

Liu, Y.. - S., et -al,_ "ANC: A.Westinghouse Advanced "Nodal Compute_r Code",

WCAP-10965, September 1986.

18.
Risher, D.

H., Jr. and Barry, R.

F.,

"TWINKLE A Multi-Dimensional Neutron Kinetics Computer Code," WCAP-7979, November 1972.

15.1-25 SGS-UFSAR Revision 31 December 5, 2019

19.

Deleted

20.

Deleted

21.

Liden, E. A.,

PSE&G to Varga, S. A.,

USNRC, "Supplemental Information Request for Amendment, Salem Generating Station Unit Nos. 1 and 2, Docket Nos. 50-272 and 50-311," February,25, 1985.
22.

Letter from T. R. Croasdaile (Westinghouse) to J. T. Boettger (PSE&G),

Subject:

Safety Analysis for PSE&G Proposed Doppler Curve ( Proprietary Document), June 28, 1984; 84PS*-G-058, NFUI 84-366.

23.

W.

H.

Slagle, "Qualification of the Two-Dimensional Transport Code Paragon (WCAP-16045-P-A)," Revision O, August 2004.
24.

W.

H.

Slagle, "Qualification of the NEXUS Nuclear Data _ Methodology (WCAP-16045-P-A)," Addendum 1-A Revision O, August 2007.

15.1-26 SGS-UFSAR Revision 31 December 5, 2019

Faults CONDITION Ill Loss of Reactor Coolant from Small Ruptured Pipes or from Cracks in Large Pipe which Actuate Emergency Core Cooling Inadvertent Loading of a Fuel Assembly into an Improper Position Complete Loss of Forced Reactor Coolant Flow Waste Gas Decay Tank Rupture Single RCC Assembly Withdrawal at Full Power CONDITION IV Major rupture of pipes containing reactor coolant up to and including double-ended rupture of the largest pipe in the Reactor Coolant System (Loss of Coolant Accident)

SGS-UFSAR TABLE 15.1-2 (Cont)

Reactivity Coefficients Assumed Moderator Moderator Computer Temperature(1)

Density(1)

Codes Utilized (Ak/°F)

(Ak/gm/cc)

NOTRUMP, SBLOCTA PHOENIX-P, PARAGON, NEXUS,ANC NA LOFTRAN 0

THING, FACTRAN NA NA ANG, THING NA PHOENIX-P, PARAGON or NEXUS SATAN Function of BASH Moderator coco Density (See LOCBART Section 15.4.1) 3 of 4 Initial NSSS

. Thermal Power Output Assumed Doppler(2)

(MWt)

NA Upper NA NA Function of Fuel Temp.

(See Section 15.4.1)

Revision 31 December 5, 2019 3479 3216-3563 (4) 3431 3577 3423 3579

TABLE 15.1-2 (Cont)

Initial Reactivity Coefficients NSSS Assumed Thermal Power Moderator Moderator Output Computer Temperature(1)

Density(1)

Assumed Faults Codes Utilized

/~k/"F)

/~k/qm/cc)

Doppler(2)

/MWt)

CONDITION IV (cont)

Major Secondary System Pipe LOFTRAN, THINC Function of Fig. 15.4-49 0

Rupture, up to and Including Moderator (Subcritical)

Double-Ended Rupture (Rupture Density (See of a Steam Pipe)

Section 15.2.13)

(Fig. 15.4-50 Unit 1)

(Fig. 15.4-48 Unit 2)

Steam Generator Tube Rupture NA NA NA NA 3577 Single Reactor Coolant Pump LOFTRAN 0

Upper 3431 Locked Rotor and Reactor THING, FACTRAN Coolant Pump Shaft Break Fuel Handling Accident NA NA NA 3600 Rupture of a Control Rod TWINKLE, FACTRAN -0 pcm/°F SOL Consistent 0 and 3479 (7)

Mechanism Housing (RCCA PHOENIX-P,

-26 pcm/°F EOL with lower Ejection)

PARAGON or limit shown NEXUS on Fig 15.1-5 NOTES:

(1)

Only one is used in an analysis, i.e., either moderator temperature or moderator density coefficient.

(2)

Reference Figure 15.1-5 for Doppler power coefficients.

. See UFSAR Section 4.5 for the applicable station reload analysis.

(3)

Cases are considered at 3 different initial power levels - 100%, 60%, and 10%.

(4)

Core power is assumed in the analysis.

(5)

Analysis is performed at 102% of an NSSS power of 3423 MWt which is equivalent to 100.6% of 3471 MWt.

(6)

No pump heat is assumed in the analysis.

(7)

Analysis is performed at 102% of a core power of 3411 MWt which is equivalent to 100.6% of 3459 MWt.

4 of4 SGS-UFSAR Revision 31 December 5, 2019

15.2.3.2 Analysis of Effects and Consequences 15.2.3.2.1 Method of Analysis A.

One or More Dropped RCCAs from the Same Group The LOFTRAN computer code (Reference

4) calculates the transient system response for the evaluation of the dropped RCCA event.

The code simulates the neutron kinetics,

RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, steam generator, and steam generator safety valves.

The code computes pertinent plant variables including temperatures, pressures, and power level.

Transient reactor coolant system state points (temperature, pressure, and power) are calculated by LOFTRAN.

Nuclear

  • models are used to obtain a

hot channel factor consistent with the primary system conditions and reactor power.

By incorporating the primary conditions from the transient analysis and the hot channel factor from the nuclear analysis, the DNB design basis is shown to be met using the THINC code.

The transient response analysis, nuclear peaking factor analysis, and performance of the DNB design basis confirmation are performed in accordance with the methodology described in Reference 15.

Note that the analysis does not take credit for the power-range negative flux rate reactor trip.

B.

Dropped RCCA Bank A dropped RCCA bank results in a symmetric power change in the core.

As discussed in Reference 15, assumptions made in the dropped RCCA(s) analysis provide a bounding analysis for the dropped RCCA bank.

C.

Statically Misaligned RCCA SGS-UFSAR Steady-state power distributions are analyzed using appropriate nuclear physics computer codes.

The peaking factors are then used as input to the THINC code to calculate the DNBR.

The analysis examines the following cases:

1.
2.
3.

With the reactor initially at full power, the worst rod withdrawn with bank D inserted at the insertion limit, With the reactor initially at full power, the worst rod dropped with bank D inserted at the insertion limit, and With the reactor initially at dropped with all other rods out.

15.2-15 full power, the worst rod Revision 18 April 26, 2000 is is is I

The analysis assumes this incident to occur at beginning of life since this results in the least-negative value of the moderator temperature

  • coefficient.

This assumpti_on maximizes.the. power. rise and minimizes the tendency of the most:--negative moderator temperature coefficient. to flatten the power distribution.

An analysis was performed to confirm that BOL_bounds EOL conditions.

15.2.3.2.2 Results A.

One or More Dropped RCCAs

  • Single or multiple dropped RCCAs within the same group result in a negative reactivity inse*rtion.

The core is not adversely affected during this *period since power is decreasing rapidly.

Either

  • reactivity feedback or control bank withdrawal will reestablish power.

The plant will establish a new equilibrium condition following a dropped rod event in manual rod control.

Without control system interaction, a new equilibrium is achieved at a reduced power le_vel and reduced primary temperature.

Following plant stabilization, the operator may manually retrieve the RCCA(s) by following approved operating procedures.

B.

Dropped RCCA Bank

-A_ dr_opped RCCA bank results in a negative reactivity. insertion greater than 500 pcm.

The core is not adversely affected during the insertion period since power is decreasing rapidly.

The transient will proceed as described in Part A.

However, the return to power __ will be less due to the greater worth of the entire bank.

The power transient for a dropped RCCA bank is symmetric, Following plant stabilization, normal procedures are followed.

15.2-16 SGs.:..uFSAR Revision 31 December 5, 2019

15.2.11.4 Conclusions It has been demonstrated that for an excessive load increase the minimum DNBR during the transient will not be *below the limit value.

15.2.12 Accidental Depressurization of The Reactor Coolant System 15.2.12.1 Identification of Causes and Accident Description The most severe core conditions resulting from an accidental depressurization of the RCS are associated with an inadvertent opening of a pressurizer safety valve.

The event results in a rapidly decreasing.RCS pressure.

The effect of the pressure decrease is a decrease in the neutron flux via the moderator density feedback.

The pressurizer level increases initially due to expansion caused by depressurization and then decreases following reactor trip.

The reactor will be tripped by the following RPS signals:

1.

Pressurizer low pressure

2.

Overtemperature AT 15.2.12.2 Method of Analysis The accidental depiessurization transient is' analyzed by employing -the detailed digital computer code LOFTRAN.

  • The *code simulates the neutron kinetics,. RCS, pressurizer, pressurizer relief. ahd 'safety *valves, pres'surizer* spray, steam generator, and steam 15.2-49 SGS-UFSAR Revision 31 December 5,. 201.~.

I

generator safety valves.

The code computes pertin,ent., plant variables includi_ng

.-~

temperatures, pressures, and power level.

In calculating the PNBR, the following conservative assumptions are made:

1.

The accident is analyzed using 'the Revised Thermal Design Procedure.

  • Initial core power, reactor coolant average temperature, and RCS pressure are assumed to be at their nominal values consistent with steady-state full-power operation.

Uncertainties in initial conditions are included in the DNBR limit described in Reference 21.

2.

A zero moderator coefficient of reactivity conservative for BOL

-operation

  • in* order to provide a

conservatively low amount of negative reactivity feedback due to changes in moderator temperature..

The spatial effect of void due to local or subcooled boiling is not considered in the analysis with respect to reactivity feedback or core power shape.

3.

A high (absolute value) Doppler coefficient of reactivity such that the resultant amount of positive feedback is conservatively high in order to retard any power decrease due to moderator _reactivity feedback.

It should also be noted that in the analysis pow~r peakj,.ng factors are kept constant at the design. values while.,. in fact, the.core feedback effects would result in. considerable flattening of the power. distribution.

This would significantly increase the calculated D1'j)3R;. however, no credit is taken for this effect.

15.2.12.3 Results I

  • Figure 15, 2-38 il-:Lustrates. the.nuclear power transient following the accident.

I Reactor trip. on overtemperature L\\.T occurs as* shown dn Figure 15. 2-38. The pressure decay transient following the accident is given on Figure 15. 2-38.

The resulting DNBR never goes below the limit value as shown on Figure 15.2-39.

15.2-50 SGS-UFSAR Revision 18 April 26, 2000

  • -;: \\;

The Spurious Operation of the SIS at Power is analyzed using the LOFTRAN

[4]

code.

LOFTRAN simulates the neutron kinetics, RCS, pressurizer, pressurizer relief and safety valves, pressurizer spray, feedwater system, steam generator, steam generator safety valves, and the effects of the SI system.

The code computes pertinent ~lant variables, including_temperatures, pressures and power level.

The following basic assumptions were used to define and evaluate this event:

a.

Initial reactor power is at its maximum value (+0.6%).

Uncertainties are

b.

c.*

d.

0 deducted from* the initial RCS temperature

  • and pressure (-5 F and -50 psi).

Assuming lower values of initial T and pressure tends to reduce avg the time predicted to fill the pressurizer.

The SI signal ca*uses the reactor to trip.

Core* residual decay heat generation is based upon long term operation at the initial power level.

Two centri'fugal charging pumps* and one positive displacement pump are in operation, with

  • the miniflow valves open.

begins imme.diately.

Full charging SI flow The pressurizer sprays and heaters operate at their maximum capacity.

  • The pressurizer sprays* limit the RCS pressure, - permitting a higher SI delivery rate, which fills' the* pressurizer sooner.

The.heaters add energy to pressuri.zed fi.uid*,

  • causin'g it to *expand,' and thus fill. the

'pressurize.t:" at an i~creased rate.

e.

Either the pressurizer PORV block valves are open, or they are opened by the operators before the pressurizer safety valves open.

-f.

One of the pressurizer *PORVs* opens.,.' and.relieves. water.

.. downstream piping are qualified for :this. ~afe1;:y_-related application* [17.J.

I 15.2-57 SGS-UFSAR

'>J r"\\

Revision 31 December 5, 2019

  • t's.*l. *..;;,,<f,'*-"*'.'**,'.: ? '*

I I

I 15.2.14.3 Results Fuel Cladding Integrity (evaluation)

If the SI signal does* *not trip

  • the reactor and. turbine, then nuclear power would decrease as borated water is added to the core.

Since steam flow would be maintained,. the mismatch between nuclear power. and load would cause T avg pressurizer pressure, and pressurizer water volume to decrease until the low pressurizer pressure reactor trip setpoint is reached.

The DNB ratio would increase, due mainly to the decrease in power and T

, and always remain above avg its safety limit value.

Therefore, this event would not pose a challenge to fuel clad integrity.

Pressure Limits and Escalation into a More Serious Event (accident analysis)

An analysis was performed using the LOFTRAN code.

The resulting transient response plots are depicted in Figures 15.2-44 and 15.2-45.

Nuclear

power, T

pressurizer pressure, avg' and pressurizer water volume

decrease, and steam pressure increases, as the result of the reactor and turbine trips demanded by the spurious SI signal.

Pressurizer pressure and pressurizer water volume begin to increase as water is added to the RCS by the SIS and the pressurizer sprays and heaters operate.

Pressurizer pressure stabilizes as the pressurizer spraying limits the pressurizer pressure to within about 4 0 psi above its initial value.

The action of the pressurizer sprays, in limiting the pressure, allows more SI water to be added to the reactor coolant system, which surges into the pressurizer.

It is assumed that the operators open the PORV block valves, if they are closed, before the pressurizer safety valves open.

After the pressurizer becomes water-solid, the pressure rapidly increases to the PORV opening setpoint (conservatively assumed to be only 100 psi above the initial pressure, or 2300 psia).

Only one of the two PORVs is assumed to open and relieve water.

15.2-58 SGS-UFSAR Revision 18 April 26, 2000

15.2.16 References For Section 15.2

1.

Gangloff, W. C., "An Evaluation of Anticipated Operational Transients in Westinghouse Pressurized Water Reactors," WCAP-7*486,. May 1971.

2.
Risher, D.

H:

Jr. and Barry, R.

F.,

"TWINKLE -

A Multi-dimensional Neutron Kinetics Computer Code,"

WCAP-7979-P-A,

January, 1975 (Proprietary) and WCAP-8028-A, January, 1975 (Non-Proprietar~),
3.

Hunin, C.

"FACTRAN, A Fortran Code for Thermal Transients in uo2 Fuel Rod," WCAP-7908, June 1972.

4.
5.

Burnett, T. W. T. et al., "LOFTF,AN Code Description," WCAP-7907-P-A (Non-proprietary), April 1984.

Altomare, S.

R.

and Barry, F_.,

"The TURTLE

24. 0 Diffusion Depletion Code," WCAP-7758, September 1971.
6.

Deleted.

7.

Geets,. J, M.,

"MARl~EL -

A *Digit.al Computer Code for Transient Analysis of a Multiloop PWR System," WCAP-7909, June 1972.

8.

Ma:p.gan,

~-

A.,

"Overpressure Pr;tectlon for Westinghouse Pressurized Water Reactors,". WCAP-7769, October 1971.

15.2-61 SGS-UFSAR Revision 24 May 11, 2009

9.

DELETED

10.

Westinghouse Letter, NS-TMA-2162, Anderson to Schwencer, November 15, 1979.

11.

Westinghouse Letter, NS-TMA-2167, Anderson to Schwencer, November 28, 1979.

12.

Westinghouse Letter, NS-EPR-2545, Rahe to Berlinger, January 20, 1982.

13.

DELETED

14.

CT-27336, Siemens Technical Report, "Missile Probability Analysis PSEG Nuclear LLC Salem Unit 1", Revision 1, dated November 5, 2003.

15.

Hassler, R. L., Lancaster, D. B., Monger, F. A., Ray, S., "Methodology for the Analysis of the *Dropped Rod Event," WCAP-11394-P-A, January 1990.

16.
Wathey, T.R.,

"Conditional Extension of Rod Misalignment Technical Specification for Salem Unit 1 and 2," WCAP-14962-P, August, 1997.

17.*

Engineering Calculation No. S-C-RC-MDC-2366, "PORV Accumulator Capacity Evaluation," (March 27, 2017).

18.

DELETED

19.

DELETED

20.

DELETED

21.

Friedland, A. J., and Ray, S., "Revised Thermal Design Procedure", WCAP-11397-P-A, April 1989.

22.

Stewart, J. A., "Salem Unit 1 and 2 Feedwater Malfunction Analysis," CN-TA-15-10, VTD 902896, Sheet 037.

15.2-62 Revision 31*

December 5, 2019

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I 1 l _________________________________________ ~I PSEG Nuclear LLC SALEM NUCLEAR GENERATING STATION

.. *~.......

TRANSIENT RESPONSE TO DROPPED ROD CLUSTER CONTROL ASSEMBLY Utdated FSAR R V 31 DECEMBER 05 2019 Figure 15.2.11 SHEET 1 I

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© 2013 PSEG Nuclear LLC.

Al I Rights Reserved. I

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In the unlikely event of multiple failures which result in continuous withdrawal of a single RCCA, it is not possible, in all cases, to provide assurance of automatic reactor trip such that core safety limits are not violated.

Withdrawal of a single RCCA results in both positive reactivity insertion tending to increase core power, and an increase in local power density in the core area "covered" by the RCCA.

15.3.5.2 Method of Analysis Power distributions within the core are calculated by the ANC Code (Reference

10) based on macroscopic cross sections generated by the PHOENIX-P Code (Reference 9), PARAGON Code (Reference 17) 1 or NEXUS code (Reference 18).

The I

peaking factors are then used by THINC to calculate the minimum DNBR for the event.

The case of the worst rod withdrawn, from Bank D inserted at the insertion limit, with the reactor initially at full power, was analyzed.

This incident is assumed to occur at beginning of life, since this results in the minimum value of the moderator density coefficient.

This maximizes the power rise and minimizes the tendency of increased moderator temperature to flatten the power distribution.

15.3.5.3 Results Two cases have been considered as follows:

1.

If the reactor is in the manual control mode, continuous withdrawal of a single RCCA results in both an increase in core power and coolant temperature, and an increase in the local hot channel factor in the area of the failed RCCA.

In terms of the overall system response, this case is similar to those presented in Section 15.2.2; however, the increased local power peaking in the area of the withdrawn RCCA results in lower minimum DNBRs than for the withdrawn bank cases.

Depending on 15.3-15 SGS-UFSAR Revision 31 December 5, 2019

initial bank insertion and location of the withdrawn RCCA, automatic reactor trip may not occur sufficiently fa_st to prevent the minimum core ONER from falling below the limit value.

Evalu~tion of this case at the power and coolant conditions at which the overtemperature ~T trip would be expected to trip the plant shows. that an upper limit for the number of rods with a DNBR less than the limit value is 5 percent.

2.

If the reactor is in autornati~ control mode, withdrawal of a single RCCA will result in the immobility of other RCCAs in the controlling bank.

The transient will then proceed in the same manner as Case 1 described above.

For such cases as above, a trip will ultimately ensue, although not sufficiently fast in all cases to prevent a minimum DNBR in the core of less than the limit value.

15.3.5.4 Conclusions For the case of one RCCA fully withdrawn with the reactor in the automatic or manual control mode, and initially operating at full power with Bank D at the insertion limit, an upper bound of the number of fuel rods experien~ing DNBR <

the limit value is 5 percent of the total fuel rods in the core.

For both cases discussed, the indicators and alarms mentioned would function to alert the operator to the malfunction before DNB could occur.

For Case 2 discussed above, the insertion limit alarms (both low and low-low alarms) would also*serve in this regard.

15.3.6 Accidental Release of Waste Gases 15.3.6.1 Situations Considered Gaseous activity which could be released in the unlikely event of a tank rupture will result in an offsite whole body and inhalation dose well below I

10CFRS0.67 limits.

The main sources of gaseous 15.3-16 SGS-UFSAR Revision 25 October 26, 2010

I

11.

Bordelon, F. M.,

"Calculation of Flow Coastdown After toss of Reactor Coolant Pump (PHOENIX Code)," WCAP-7973, September 1972.

12.

Burnett, T. W. T. et al, "LOFTRAN Code Description," WCAP-7907, April 1974.

13.

Hargrove, H.G., "FACTRAN, A FORTRAN-IV Code for Thermal Transients in uo2 Fuel Rods," v>iCAP-7908,.December 1989.

14.

(This text was deleted)

15.

Thompson, C. M., et al.,

"Addendum to the Westinghouse Small Break ECCS Evaluation Model Using the NOTRUMP Code and Safety Injection in the Broken Loop and COSI Condensation Model," WCAP-10054-P-A, Addendum 2, Revision 1 (Proprietary) and WCAP-10081-NP, Revision 1 (Non-Proprietary),

July 1997.

16.

WCAP-16676-NP, R.D.

Ankney and J.L. Grover, "Analysis Update for the Inadvertent Loading Event," March 2009.

17.

W.. H.

Slagle, "Qualification of the Two-Dimensional Transport Code

'Paragon (WCAP-16045-P--:A),"-Revision 0, August 2004.

18.

W.

H.

Slagle, "Qualification of the NEXUS Nuclear.Data.Methodology (WCAP-16054-P-A)," Addendum 1-A Revision O, August 2007.

15.3-21 SGS-UFSAR Revision 31 December 5, 2019

larger than the reactivity calculated for all cases.

These results verified conservatism; i.e., underprediction of negative reactivity feedback from power generation.

3.

Minimum SIS capability for the injection of borated flow into the RCS is assumed in the analysis.

Due to single failure considerations, injection flow is assumed to be delivered by only a single charging pump.

[Note that this assumption is taken conservatively and is beyond normal single-failure criteria.

It is made in addition to the minimum SIS (minimum safeguards) assumption, despite the calculated RCS pressure shown in Figure 15.4-51A which is below the shutoff head of the IHSI pump after about 20 seconds, the failure of the Feedwater Regulating Valve of the faulted Steam Generator, and the Regulatory Guide 1.183 RO requirement to assume that a control rod is stuck at its fully withdrawn position.]

The modeling of the SIS in LOFTRAN is described in Reference 27.

SGS-UFSAR A conservatively bounding total time delay is modeled in the analysis to account for the delay between the time that the ESF actuation setpoint is reached and the time that SIS flow is capable of being pumped from the RWST into the RCS cold leg header.

The total time delay assumed in the analysis is 22 seconds.

This 22 second assumption was selected to conservatively bound the sum of the following time delay components:

a.

Instrumentation, logic and signal transport time delay associated with generation and transport of the SI signal, and

b.

The following actions which occur in parallel:

1.

SIS suction valve alignment (opening of RWST valves followed by closure of VCT valves), and

2.

High Head SI/Charging Pump starting and attaining full speed.

15.4-35 Revision 31 December 5, 201,9

In addition, the analysis cons~~:;~ti,~~ly assumes that the SIS i'ines between the RWST and the RCS initially contain unborated water. After the appropriate total time delay described above, the analysis takes into account the purging of this unborated water prior to crediting the injection of borated flow from the RWST into the RCS.

4.

Two cases are considered.

Both model a complete severance of the main steam line at the outlet of the steam generator with the plant initially at no load conditions.

One case models full RCS flow and the other case models loss of RCS flow due to loss of offsite power early in the transient.

Note that a loss of offsite power at anytime during the transient,results in a loss of forced RCS cooling and subsequently a less severe reactivity transient.* As such, the case without offsi te power available is not discussed further in this section.

5.

Power peaking factors corresponding to one stuck RCCA and non-uniform core inlet coolant temperatures are determined at end of core life.

The coldest core inlet temperatures are assumed to occur in the sector with the stuck rod.

The power peaking factors account for the effect of.the local void in the region of the stuck control assembly during the return to power phase following the steam line break.

This

void, in conjunction with the large negative moderator coefficient, partially offsets the effect of the stuck assembly. The pow?r peaking factors depend upon the core power, temperature, pressure, and flow, and, thus, are different for each case studied.

SGS-UFSAR 15.4-36

  • Revision 2 4 May 11, 2009

Salem Unit 2 Multiplication Factor I

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200 250 300 350 400 450 500 Core Average Temperature f'F)

.----------------------------~

Revision 31 DECEMBER 05,2019 Salem Nuclear Generating Station' PSEG Nuclear, LLC VARIATION OF K-eff WITH MODERATOR SALEM NUCLEAR GENERATING STATION TEMPERATURE - UNIT 2 Updated FSAR Figure 15.4-48

© 2000 PSEG Nuclear, LLC, Al I Rights Reserved.

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Revision 31 DECEMBER 05,2019 Salem Nuclear Gen*erating. Station PSEG Nuclear, LLC VARIATION OF REACTIVITY WITH POWER AT CONST ANT SALEM NUCLEAR GENERATING STATION CORE AVERAGE TEMPERATURE Updated FSAR Figure 15.4-49

© 2000 PSEG Nuclear, LLC. Al I Rights Reserved,

7. Add an Examination Checklist for masonry wall inspection requirements.
8. Parameters monitored for wooden components will be enhanced to include:

Change in Material Properties, Loss of Material due to Insect Damage and Moisture Damage.

9.. Specify an inspection frequency of not greater than 5 years for structures including submerged portions of the service water intake structure.

10. Require individuals responsible for inspections and assessments for structures to have a B.S. Engineering degree and/or Professional Engineer

.license, and a minimum of four years experience working on building structures.

11. Perform periodic sampling, testing, and* analysis of ground water chemistry for pH, chlorides, and sulfates on a frequency of 5 years. Groundwater samples in the areas adjacent to Unit 1 containment struct~re and Unit 1 auxiliary building will also be tested for boron concentration.
12. Require supplemental inspections of the affected in scope structures within 30 days following extreme environmental or natural phenomena (large
  • floods, significant earthquakes, hurricanes, and tornadoes)..
13. Perform a chemical analysis of ground or surface water in-leakage when there is significant in-leakage or there is reason to believe that the in-leakage may be damaging concrete elements or reinforcing steel.
14. Implementing procedures will be enhanced to include additional acceptance criteria details specified in ACI 349.3R-96.
15. When the reactor cavity is flooded up, Salem will periodically monitor the telltales associated with the reactor cavity and refueling canal for leakage..

If telltale leakage is observ'3d, then the pH of the leakage will be measured to ensure that concrete reinforcement steel is not experiencing a corrosive environment. In addition, Salem will periodically inspect the leak chase system associated with the reactor cavity and refueling canal to ensure the telltales are free of significant blockage. Salem will also inspect concrete surfaces for degradation where leakage has been observed, in accordance with this Program.

These enhancements will be implemented prior to entering the period of extended operation.

The following table is provided to tabulate the acceptance* criteria from the

. Structures Monitoring Program Enhancement 5 c. associated with testing the water drained from the Salem Unit 1 SFP telltales and seismic gap drain.

. 8-31 SGS-UFSAR Revision 26 May 21, 2012

Acceptance Criteria-Salem Unit 1 SFP Telltales and Seismic Gap Drain Acceptance Criteria Chemical Frequency for Analysis SFP Telltales Seismic Gap Drain monitoriQfl 0,NestWall).

(East Wall) pH

> 6.0 and

> 6.5 Samples taken

< 9.0 and< 10.0 monthly Chloride

~ 500 ppm

~ 500 ppm Samples taken every 5* months Sulfate

~ 1,500 ppm

~ 1,500 ppm Samples taken every 6 months Boron For Information For Information Only Samples taken Only monthly Iron For Information For Information Only.

Samples taken every Only 6 months Chemistry results that do not me~t one of the criteria will be entered into the corrective action program for an investigation and evaluation.

A.2.1.34 RG 1.127, Inspection of Water-Control Structures Associated With Nuclear Power Plants The RG 1.127, Inspection of Water-Control Structures Associated With Nuclear Power Plants is implemented through the Structures Monitoring Program._ The RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants program is an existing program that will be enhanced to require inspection of water control structures and components that are in scope for license renewal. These structures include the Service Water Intake structure and Shoreline Protection and Dike structures (including outer walls of the Circulating Water Intake Structure); rhe RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants aging management program addresses age-related deterioration, degradation due to extreme environmental conditions, and the effects of natural phenomena that may affect the safety function of the water control structures. The program manages loss of material, cracking, and change in material properties for concrete components, loss of material and loss of preload for steel and metal components, loss of material and change in material properties for wooden components, hardening and loss of strength for elastomers, and loss of material and loss of form for earthen water control structures. Elements of the program are designed to.

detect degradations and take corrective actions to prevent a loss of an intended function.

The RG 1.127, Inspection of Water-Control Structures Associated With Nuclear Power Plants Program Will be enhanced to include:

8-32 SGS-UFSAR Revision 31 December 5, 2019

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