Text

Report to NRC of Changes to Technical Specifications Bases
	ML12318A055
Person / Time
Site:	Palisades
Issue date:	11/09/2012
From:	Gustafson O; Entergy Nuclear Operations
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	PNP 2012-097
	Download: ML12318A055 (151)
	v • d • e

Entergy Nuclear Operations, Inc.

Palisades Nuclear Plant En bnfff-ql JL_.JILL.'1 27780 Blue Star Memorial Highway Covert, MI 49043 Tel 269-764-2000 Otto W Gustafson Licensing Manager PNP 2012-097 November 9, 2012 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

SUBJECT:

Report to NRC of Changes to Technical Specifications Bases Palisades Nuclear Plant Docket 50-255 License No. DPR-20

Dear Sir or Madam:

This report is submitted in accordance with Palisades Technical Specification 5.5.12.d, which requires that changes to the Technical Specifications Bases, implemented without prior Nuclear Regulatory Commission (NRC) approval, be provided to the NRC on a frequency consistent with 10 CFR 50.71(e). Attachment 1 provides a listing of all bases changes since issuance of the previous report, dated April 25, 2011, and identifies the affected sections and describes the nature of the changes. Attachment 2 provides page change instructions, a copy of the current Technical Specifications Bases List of Effective Pages, and the revised Technical Specifications Bases sections and table listed in Attachment 1.

Summary of Commitments This letter identifies no new commitments and no revisions to existing commitments.

Sincerely, owg/rbh Attachments: 1. List of Technical Specifications Bases Changes

2. Revised Technical Specifications Bases cc: Administrator, Region III, USNRC Project Manager, Palisades, USNRC Resident Inspector, Palisades, USNRC

-Acoo(

ATTACHMENT 1 LIST OF TECHNICAL SPECIFICATIONS BASES CHANGES Date Affected Bases Change Description Technical Specification Revised revision date 11/08/2012 Bases (TSB)

Title Page Palisades TSB Revised to incorporate changes noted below List of Effective Pages Editorial change to clarify the TSB for required 08/30/2011 Section B 3.3.1 operability for high start-up rate trip and loss of load trip.

This change was to remove the acronym "CPCo" from the references for engineering analyses, and "CPCo" should no longer be 11/08/2012 Section B 3.3.5 included within these references. This acronym refers to the Consumers Power Company, which is the former owner and operator of Palisades, and is obsolete.

This change to delete a note that was missed when license amendment number 219 was 11/08/2012 Section B 3.3.7 adopted. The reason for the original change was to align the basis with mode restraints being adopted in accordance with Standard Technical Specifications (TSTF-359, Rev 9).

This change implements license amendment number 245, which added three TS figures for 02/17/2012 Section B 3.4.3 pressure temperature limits and low temperature overpressure curves out to 42.1 effective full power years.

This change implements license amendment number 245, which added three TS figures for 02/17/2012 Section B 3.4.12 pressure temperature limits and low temperature overpressure curves out to 42.1 effective full power years.

This change implements license amendment number 244, which included a revision of the 03/15/2012 Section B 3.6.1 calculated peak containment pressure and refers to this calculated value along with the supporting analyses.

This change implements license amendment number 244, which included a revision of the 03/15/2012 Section B 3.6.2 calculated peak containment pressure and refers to this calculated value along with the supporting analyses.

Page 1 of 2

ATTACHMENT 1 LIST OF TECHNICAL SPECIFICATIONS BASES CHANGES Date Affected Bases Change Description This change implements license amendment number 244, which included a revision of the 03/15/2012 Section B 3.6.4 calculated peak containment pressure and refers to this calculated value along with the supporting analyses.

This change implements license amendment number 244, which included a revision of the 03/15/2012 Section B 3.6.5 calculated peak containment pressure and refers to this calculated value along with the supporting analyses.

This change implements license amendment number 244, which included a revision of the 03/15/2012 Section B 3.6.6 calculated peak containment pressure and refers to this calculated value along with the supporting analyses.

This change implements license amendment number 246. Further, the change included the Region 1 spent fuel pool criticality analysis that was reanalyzed to take into account zero 11/08/2012 Section B 3.7.16 carborundum, a conservative swelling model of the panels that encapsulate the carborundum. Additionally, the SFP water outside of the fuel assembly envelope was assumed to be a void. Credit is taken for soluble boron, depleted fuel, and for burnup.

This TSB was changed to adopt license amendment number 242, which relocated the stored diesel fuel oil and lube oil numerical volume requirements from TS to TSB.

11/08/2012 Section B 3.8.1 Another change was made to modify a sentence to correct class 1E components i.e.,

off-site power is not 1E. The final change was to clarify which modes Station Power Transformer 1-2 will not be used to power 2400 V safety related buses.

This TSB was changed to adopt license amendment number 242 and engineering 09/16/2011 Section B 3.8.3 change EC 12118, which estimates greater fuel oil consumption for the diesel generators at full power.

ATTACHMENT 2 REVISED TECHNICAL SPECIFICATIONS BASES Page Change Instructions Title Page List of Effective Pages Technical Specification Bases Section B 3.3.1 Section B 3.3.5 Section B 3.3.7 Section B 3.4.3 Section B 3.4.12 Section B 3.6.1 Section B 3.6.2 Section B 3.6.4 Section B 3.6.5 Section B 3.6.6 Section B 3.7.16 Section B 3.8.1 Section B 3.8.3 147 Pages Follow

Technical Specifications Bases Page Change Instructions Revise your copy of the Palisades Technical Specifications Bases by removing the pages identified below and inserting the revised pages. Vertical lines in the right-hand margin indicate the area of change.

REMOVE INSERT Technical Specification Bases Technical Specification Bases Title Page, Revised 03/15/2012 (1 page) Title Page, Revised 11/08/2012 (1 page)

Palisades Tech Spec Bases Palisades Tech Spec Bases List of Effective Pages List of Effective Pages Revised 03/15/2012 (2 pages) Revised 11/08/2012 (3 pages)

B 3.3.1-1 through B 3.3.1-35 B 3.3.1-1 through B 3.3.1-35 Revised 04/14/11 (35 pages) Revised 08/30/2'0011 (35 pages)

B 3.3.5-1 through B 3.3.5-6 B 3.3.5-1 through B 3.3.5-6 Revised 04/14/2011 (6 pages) Revised 11/08/2012 (6 pages)

B 3.3.7-1 through B 3.3.7-12 B 3.3.7-1 through B 3.3.7-12 Revised 04/19/2005 (12 pages) Revised 11/08/2012 (12 pages)

B 3.4.3-1 through B 3.4.3-7 B 3.4.3-1 through B 3.4.3-9 Revised 01/27/2005 (7 pages) Revised 02/17/2012 (9 Pages)

B 3.4.12-1 through B 3.4.12-13 B 3.4.12-1 through B 3.4.12-13 Revised 04/14/11 (13 Pages) Revised 02/17/12 (13 Pages)

B 3.6.1-1 through B 3.6.1-4 B 3.6.1-1 through B 3.6.1-4 Revised 12/10/2002 (4 Pages) Revised 03/15/2012 (4 Pages)

B 3.6.2-1 through B 3.6.2-8 B 3.6.2-1 through B 3.6.2-8 Revised 08/12/2003 (8 Pages) Revised 03/15/2012 (8 Pages)

B 3.6.4-1 through B 3.6.4-3 B 3.6.4-1 through B 3.6.4-3 Revised 04/27/2001 (3 Pages) Revised 03/15/2012 (3 Pages)

B 3.6.5-1 through B 3.6.5-3 B 3.6.5-1 through B 3.6.5-3 Revised 09/09/2003 (3 Pages) Revised 03/15/2012 (3 Pages)

B 3.6.6-1 through B 3.6.6-13 B 3.6.6-1 through B 3.6.6-13 Amendment 227 (13 Pages) Revised 03/15/2012 (13 Pages)

B 3.7.16-1 through B 3.7.16-5 B 3.7.16-1 through B 3.7.16-4 Amendment 246, Revised 11/08/2012 Amendment 246 (4 pages) (5 pages)

B 3.8.1-1 through B 3.8.1-24 B 3.8.1-1 through B 3.8.1-24 Revised 01/11/2012 (24 pages) Revised 11/08/2012 (24 pages)

B 3.8.3-1 through B 3.8.3-7 B 3.8.3-1 through B 3.8.3-7 Revised 09/16/2011 (7 Pages) Revised 09/16/2011 (7 Pages)

PALISADES PLANT FACILITY OPERATING LICENSE DPR-20 APPENDIX A TECHNICAL SPECIFICATIONS BASES Revised 11/08/2012

PALISADES TECHNICAL SPECIFICATIONS BASES 1 LIST OF EFFECTIVE PAGES COVERSHEET Title Page Revised 11/08/12 TABLE OF CONTENTS Pages i and ii Revised 02/19/09 TECHNICAL SPECIFICATIONS BASES Pages B 2.1.1-1 -B 2.1.1-4 Revised 04/14/11 Bases 2.0 Pages B 2.1.2 B 2.1.2-4 189 Bases 3.0 Pages B 3.0 B 3.0-16 Revised 02/24/05 Bases 3.1 Pages B 3.1.1-1 - B 3.1.1-5 189 Pages B 3.1.2-1 - B 3.1.2-6 Revised 09/09/03 Pages B 3.1.3-1 - B 3.1.3-4 189 Pages B 3.1.4-1 - B 3.1.4-13 Revised 07/18/07 Pages B 3.1.5-1 - B 3.1.5-7 Revised 07/02/04 Pages B 3.1.6-1 - B 3.1.6-9 Revised 07/30/03 Pages B 3.1.7-1 - B 3.1.7-6 Revised 05/15/07 Bases 3.2 Pages B 3.2.1-1 - B 3.2.1-11 Revised 08/06/04 Pages B 3.2.2-1 - B 3.2.2-3 Revised 09/28/01 Pages B 3.2.3-1 - B 3.2.3-3 Revised 09/28/01 Pages B 3.2.4-1 - B 3.2.4-3 189 - Revised 08/09/00 Bases 3.3 Pages B 3.3.1 B 3.3.1-35 Revised 08/30/2011 Pages B 3.3.2 B 3.3.2-10 189- Revised 02/12/01 Pages B 3.3.3 B 3.3.3-24 Revised 03/20/08 Pages B 3.3.4 B 3.3.4-12 Revised 09/09/03 Pages B 3.3.5 B 3.3.5-6 Revised 11/08/2012 Pages B 3.3.6 B 3.3.6-6 189 - Revised 02/12/01 Pages B 3.3.7 B 3.3.7-12 Revised 11/08/2012 Pages B 3.3.8 B 3.3.8-6 Revised 02/24/05 Pages B 3.3.9 B 3.3.9-5 189 - Revised 08/09/00 Pages B 3.3.10-1 - B 3.3.10-4 189 Bases 3.4 Pages B 3.4.1 B 3.4.1-4 Revised 08/24/04 Pages B 3.4.2 B 3.4.2-2 189 Pages B 3.4.3 B 3.4.3-7 Revised 02/17/12 Pages B 3.4.4 B 3.4.4-4 Revised 09/21/06 Pages B 3.4.5 B 3.4.5-5 Revised 09/21/06 Pages B 3.4.6 B 3.4.6-6 Revised 07/31/07 Pages B 3.4.7 B 3.4.7-7 Revised 07/31/07 Pages B 3.4.8 B 3.4.8-5 Revised 07/31/07 Pages B 3.4.9 B 3.4.9-6 189 Pages B 3.4.10-1 - B 3.4.10-4 189 Pages B 3.4.11-1 - B 3.4.11-7 Revised 02/24/05 Revised 11/08/2012

PALISADES TECHNICAL SPECIFICATIONS BASES 2 LIST OF EFFECTIVE PAGES Bases 3.4 Pages B 3.4.12-1 -B 3.4.12-13 Revised 02/17/12 (Continues) Pages B 3.4.13-1 -B 3.4.13-7 Revised 03/20/08 Pages B 3.4.14-1 -B 3.4.14-8 189 - Revised 08/09/00 Pages B 3.4.15-1 -B 3.4.15-6 Revised 02/24/05 Pages B 3.4.16-1 -B 3.4.16-5 Revised 02/24/05 Pages B 3.4.17-1 -B 3.4.17-7 223 Bases 3.5 Pages B 3.5.1-1 - B 3.5.1-5 189 Page B 3.5.1-6 191 Page B 3.5.1-7 189 Page B 3.5.1-8 191 Pages B 3.5.2-1 - B 3.5.2-12 228 Pages B 3.5.3-1 - B 3.5.3-4 Revised 07/22/02 Pages B 3.5.4-1 - B 3.5.4-7 227 Pages B 3.5.5-1 - B 3.5.5-5 227 Bases 3.6 Pages B 3.6.1 B 3.6.1-4 Revised 03/15/12 Pages B 3.6.2 B 3.6.2-8 Revised 03/15/12 Pages B 3.6.3 B 3.6.3-12 Revised 04/14/11 Pages B 3.6.4 B 3.6.4-3 Revised 03/15/12 Pages B 3.6.5 B 3.6.5-3 Revised 03/15/12 Pages B 3.6.6 B 3.6.6-13 Revised 03/15/12 Bases 3.7 Pages B 3.7.1-1 - B 3.7.1-4 Revised 08/06/04 Pages B 3.7.2-1 - B 3.7.2-6 Revised 12/02/02 Pages B 3.7.3-1 - B 3.7.3-5 Revised 12/02/02 Pages B 3.7.4-1 - B 3.7.4-4 Revised 07/16/08 Pages B 3.7.5-1 - B 3.7.5-9 Revised 02/24/05 Pages B 3.7.6-1 - B 3.7.6-4 Revised 04/14/11 Pages B 3.7.7-1 - B 3.7.7-9 Revised 06/07/05 Pages B 3.7.8-1 - B 3.7.8-8 Revised 10/29/09 Pages B 3.7.9-1 - B 3.7.9-3 Revised 04/14/11 Pages B 3.7.10-1 - B 3.7.10-8 230 Pages B 3.7.11-1 - B 3.7.11-5 189 Pages B 3.7.12-1 - B 3.7.12-7 Revised 07/16/03 Pages B 3.7.13-1 - B 3.7.13-3 189 - Revised 08/09/00 Pages B 3.7.14-1 - B 3.7.14-3 Revised 09/09/03 Pages B 3.7.15-1 - B 3.7.15-2 236 Pages B 3.7.16-1 - B 3.7.16-5 246 - Revised 11/08/12 Pages B 3.7.17-1 - B 3.7:17-3 Revised 04/14/11 Revised 11/08/2012

PALISADES TECHNICAL SPECIFICATIONS BASES 3 LIST OF EFFECTIVE PAGES Bases 3.8 Pages B 3.8.1 B 3.8.1-24 Revised 11/08/12 Pages B 3.8.2 B 3.8.2-4 Revised 11/06/01 Pages B 3.8.3 B 3.8.3-7 Revised 09/16/11 Pages B 3.8.4 B 3.8.4-9 Revised 07/13/06 Pages B 3.8.5 B 3.8.5-3 Revised 11/06/01 Pages B 3.8.6 B 3.8.6-6 189 - Revised 08/09/00 Pages B 3.8.7 B 3.8.7-3 189 Pages B 3.8.8 B 3.8.8-3 Revised 11/06/01 Pages B 3.8.9 B 3.8.9-7 Revised 11/06/01 Pages B 3.8.10-1 - B 3.8.10-3 Revised 11/06/01 Bases 3.9 Pages B 3.9.1-1 - B 3.9.1-4 189 - Revised 08/09/00 Pages B 3.9.2-1 - B 3.9.2-3 189 - Revised 02/12/01 Pages B 3.9.3-1 - B 3.9.3-6 189 - Revised 08/09/00 Pages B 3.9.4-1 - B 3.9.4-4 Revised 07/31/07 Pages B 3.9.5-1 - B 3.9.5-4 Revised 07/31/07 Pages B 3.9.6-1 - B 3.9.6-3 189 - Revised 02/27/01 Revised 11/08/2012

RPS Instrumentation B 3.3.1 B 3.3 INSTRUMENTATION B 3.3.1 Reactor Protective System (RPS) Instrumentation BASES BACKGROUND The RPS initiates a reactor trip to protect against violating the acceptable fuel design limits and breaching the reactor coolant pressure boundary during Anticipated Operational Occurrences (AOOs). (As defined in 10 CFR 50, Appendix A, "Anticipated operational occurrences mean those conditions of normal operation which are expected to occur one or more times during the life of the nuclear power unit and include but are not limited to loss of power to all recirculation pumps, tripping of the turbine generator set, isolation of the main condenser, and loss of all offsite power.") By tripping the reactor, the RPS also assists the Engineered Safety Features (ESF) systems in mitigating accidents.

The protection and monitoring systems have been designed to ensure safe operation of the reactor. This is achieved by specifying Limiting Safety System Settings (LSSS) in terms of parameters directly monitored by the RPS, as well as LCOs on other reactor system parameters and equipment performance.

The LSSS, defined in this Specification as the Allowable Values, in conjunction with the LCOs, establish the threshold for protective system action to prevent exceeding acceptable limits during Design Basis Accidents (DBAs).

During AOOs, which are those events expected to occur one or more times during the plant life, the acceptable limits are:

" The Departure from Nucleate Boiling Ratio (DNBR) shall be maintained above the Safety Limit (SL) value to prevent departure from nucleate boiling;

Fuel centerline melting shall not occur; and

" The Primary Coolant System (PCS) pressure SL of 2750 psia shall not be exceeded.

Maintaining the parameters within the above values ensures that the offsite dose will be within the 10 CFR 50 (Ref. 1) and 10 CFR 100 (Ref. 2) criteria during AOOs.

Palisades Nuclear Plant B 3.3.1 -1 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES BACKGROUND Accidents are events that are analyzed even though they are not (continued) expected to occur during the plant life. The acceptable limit during accidents is that the offsite dose shall be maintained within an acceptable fraction of 10 CFR 100 (Ref. 2) limits. Different accident categories allow a different fraction of these limits based on probability of occurrence. Meeting the acceptable dose limit for an accident category is considered having acceptable! consequences for that event.

The RPS is segmented into four interconnected modules. These modules are:

" Measurement channels;

" RPS trip units;

Matrix Logic; and

Trip Initiation Logic.

This LCO addresses measurement channels and RPS trip units. It also addresses the automatic bypass removal feature for those trips with Zero Power Mode bypasses. The RPS Logic and Trip Initiation Logic are addressed in LCO 3.3.2, "Reactor Protective System (RPS) Logic and Trip Initiation." The role of the measurement channels, RPS trip units, and RPS Bypasses is discussed below.

Measurement Channels Measurement channels, consisting of pressure switches, field transmitters, or process sensors and associated instrumentation, provide a measurable electronic signal based upon the physical characteristics of the parameter being measured.

With the exception of High Startup Rate, which employs two instrument channels, and Loss of Load, which employs a single pressure sensor, four identical measurement channels with electrical and physical separation are provided for each parameter used in the direct generation of trip signals. These are designated channels A through D.

Some measurement channels provide input to more than one RPS trip unit within the same RPS channel. In addition, some measurement channels may also be used as inputs to Engineered Safety Features (ESF) bistables, and most provide indication in the control room.

Palisades Nuclear Plant B 3.3.1-2 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES BACKGROUND Measurement Channels (continued)

(continued)

In the case of High Startup Rate and Loss of Load, where fewer than four sensor channels are employed, the reactor trips provided are not relied upon by the plant safety analyses. The sensor channels do however, provide trip input signals to all four RPS channels.

When a channel monitoring a parameter exceeds a predetermined setpoint, indicating an abnormal condition, the bistable monitoring the parameter in that channel will trip. Tripping two or more channels of bistable trip units monitoring the same parameter de-energizes Matrix Logic, (addressed by LCO 3.3.2) which in turn de-energizes the Trip Initiation Logic. This causes all four DC clutch power supplies to de-energize, interrupting power to the control rod drive mechanism clutches, allowing the full length control rods to insert into the core.

For those trips relied upon in the safety analyses, three of the four measurement and trip unit channels can meet the redundancy and testability of GDC 21 in 10 CFR 50, Appendix A (Ref. 1). This LCO requires, however, that four channels be OPERABLE. The fourth channel provides additional flexibility by allowing one channel to be removed from service (trip channel bypassed) for maintenance or testing while still maintaining a minimum two-out-of-three logic.

I Since no single failure will prevent a protective system actuation, this arrangement meets the requirements of IEEE Standard 279-1971 (Ref. 3).

Most of the RPS trips are generated by comparing a single measurement to a fixed bistable setpoint. Two trip Functions, Variable High Power Trip and Thermal Margin Low Pressure Trip, make use of more than one measurement to provide a trip.

The required RPS Trip Functions utilize the following input instrumentation:

Variable Higqh Power Trip (VHPT)

The VHPT uses Q Power as its input. Q Power is the higher of NI power from the power range NI drawer and primary calorimetric power (AT power) based on PCS hot leg and cold leg temperatures. The measurement channels associated with the VHPT are the power range excore channels, and the PCS hot and cold leg temperature channels.

Palisades Nuclear Plant B 3.3.1-3 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES BACKGROUND Measurement Channels (continued)

" Variable Hicqh Power Trip (VHPT) (continued)

The Thermal Margin Monitors provide the complex signal processing necessary to calculate the TM/LP trip setpoint, VHPT trip setpoint and trip comparison, and Q Power calculation. On power decreases the VHPT setpoint tracks power levels downward so that it is always within a fixed increment above current power, subject to a minimum value.

On power increases, the trip setpoint remains fixed unless manually reset, at which point it increases to the new setpoint, a fixed increment above Q Power at the time of reset, subject to a maximum value. Thus, during power escalation, the trip setpoint must be repeatedly reset to avoid a reactor trip.

Higqh Startup Rate Trip The High Startup Rate trip uses the wide range Nuclear Instruments (NIs) to provide an input signal. There are only two wide range NI channels. The wide range channel signal processing electronics are physically mounted in RPS cabinet channels C (N1-1/3) and D (NI-2/4). Separate bistable trip units mounted within the N1-1/3 wide range channel drawer supply High Startup Rate trip signals to RPS channels A and C. Separate bistable trip units mounted within the NI-2/4 wide range channel drawer provide High Startup Rate trip signals to RPS channels B and D.

Low Primary Coolant Flow Trip The Low Primary Coolant Flow Trip utilizes 16 flow measurement channels which monitor the differential pressure across the primary side of the steam generators. Each RPS channel, A, B, C, and D, receives a signal which is the sum of four differential pressure signals. This totalized signal is compared with a setpoint in the RPS Low Flow bistable trip unit for that RPS channel.

Palisades Nuclear Plant B 3.3.1-4 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES BACKGROUND Measurement Channels (continued)

(continued)

Low Steam Generator Level Trips There are two separate Low Steam Generator Level trips, one for each steam generator. Each Low Steam Generator Level trip monitors four level measurement channels for the associated steam generator, one for each RPS channel.

" Low Steam Generator Pressure Trips There are also two separate Low Steam Generator Pressure trips, one for each steam generator. Each Low Steam Generator Pressure trip monitors four pressure measurement channels for the associated steam generator, one for each RPS channel.

High Pressurizer Pressure Trip The High Pressurizer Pressure Trip monitors four pressurizer pressure channels, one for each RPS channel.

Thermal Margin Low Pressure (TM/LP) Trip The TM/LP Trip utilizes bistable trip units. Each of these bistable trip units receives a calculated trip setpoint from the Thermal Margin Monitor (TMM) and compares it to the measured pressurizer pressure signal. The TM/LP setpoint is based on Q power (the higher of NI power from the power range NI drawer, or AT power, based on PCS hot leg and cold leg temperatures) pressurizer pressure, PCS cold leg temperature, and Axial Shape Index. The TMM provide the complex signal processing necessary to calculate the TM/LP trip setpoint, TM/LP trip comparison signal, and Q Power.

Palisades Nuclear Plant B 3.3.1-5 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES BACKGROUND Measurement Channels (continued)

(continued)

" Loss of Load Trip The Loss of Load Trip is initiated by two-out-of-three logic from pressure switches in the turbine auto stop oil circuit that sense a turbine trip for input to all four RPS auxiliary trip units. The Loss of Load Trip is actuated by turbine auxiliary relays 305L and 305R.

Relay 305L provides input to RPS channels A and C; 305R to channels B and D. Relays 305L and 305R are energized on a turbine trip. Their inputs are the same as the inputs to the turbine solenoid trip valve, 20ET.

If a turbine trip is generated by loss of auto stop oil pressure, the auto stop oil pressure switches, by two-out-of-three logic, will actuate relays 305L and 305R and generate a reactor trip. If a turbine trip is generated by an input to the solenoid trip valve, relays 305L and 305R, which are wired in parallel, will also be actuated and will generate a reactor trip.

" Containment High Pressure Trip The Containment High Pressure Trip is actuated by four pressure switches, one for each RPS channel.

Zero Power Mode Bypass Automatic Removal The Zero Power Bypass allows manually bypassing (i.e., disabling) four reactor trip functions, Low PCS Flow, Low SG A Pressure, Low SG B Pressure, and TM/LP (low PCS pressure),

when reactor power (as indicated by the wide range nuclear instrument channels) is below 10-4%. This bypassing is necessary to allow RPS testing and control rod drive mechanism testing when the reactor is shutdown and plant conditions would cause a reactor trip to be present.

The Zero Power Mode Bypass removal interlock uses the wide range nuclear instruments (NIs) as measurement channels.

There are only two wide range NI channels. Separate bistables are provided to actuate the bypass removal for each RPS channel. Bistables in the NI-1/3 channel provide the bypass removal function for RPS channels A and C; bistables in the NI-2/4 channel for RPS channels B and D.

Palisades Nuclear Plant B 3.3.1-6 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES BACKGROUND Several measurement instrument channels provide more than one (continued) required function. Those sensors shared for RPS and ESF functions are identified in Table B 3.3.1-1. That table provides a listing of those shared channels and the Specifications which they affect.

RPS Trip Units Two types of RPS trip units are used in the RPS cabinets; bistable trip units and auxiliary trip units:

A bistable trip unit receives a measured process signal from its instrument channel and compares it to a setpoint; the trip unit actuates three relays, with contacts in the Matrix Logic channels, when the measured signal is less conservative than the setpoint.

They also provide local trip indication and remote annunciation.

An auxiliary trip unit receives a digital input (contacts open or closed); the trip unit actuates three relays, with contacts in the Matrix Logic channels, when the digital input is received. They also provide local trip indication and remote annunciation.

Each RPS channel has four auxiliary trip units and seven bistable trip units.

The contacts from these trip unit relays are arranged into six coincidence matrices, comprising the Matrix Logic. If bistable trip units monitoring the same parameter in at least two channels trip, the Matrix Logic will generate a reactor trip (two-out-of-four logic).

Four of the RPS measurement channels provide contact outputs to the RPS, so the comparison of an analog input to a trip setpoint is not necessary. In these cases, the bistable trip unit is replaced with an auxiliary trip unit. The auxiliary trip units provide contact multiplication so the single input contact opening can provide multiple contact outputs to the coincidence logic as well as trip indication and annunciation.

Palisades Nuclear Plant B 3.3.1-7 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES BACKGROUND RPS Trip Units (continued)

(continued)

Trips employing auxiliary trip units include the VHPT, which receives contact inputs from the Thermal Margin Monitors; the High Startup Rate trip which employs contact inputs from bistables mounted in the two wide range drawers; the Loss of Load Trip which receives contact inputs from one of two auxiliary relays which are operated by two-out-of-three logic switches sensing turbine auto stop oil pressure; and the Containment High Pressure (CHP) trip, which employs containment pressure switch contacts.

There are four RPS trip units, designated as channels A through D, each channel having eleven trip units, one for each RPS Function. Trip unit output relays de-energize when a trip occurs.

All RPS Trip Functions, with the exception of the Loss of Load and CHP trips, generate a pretrip alarm as the trip setpoint is approached.

The Allowable Values are specified for each safety related RPS trip Function which is credited in the safety analysis. Nominal trip setpoints are specified in the plant procedures. The nominal setpoints are selected to ensure plant parameters do not exceed the Allowable Value ifthe instrument loop is performing as required. The methodology used to determine the nominal trip setpoints is also provided in plant documents. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. Each Allowable Value specified is more conservative than the analytical limit determined in the safety analysis in order to account for uncertainties appropriate to the trip Function. These uncertainties are addressed as described in plant documents. A channel is inoperable if its actual setpoint is not within its Allowable Value.

Setpoints in accordance with the Allowable Value will ensure that SLs of Chapter 2.0 are not violated during AOOs and the consequences of DBAs will be acceptable, providing the plant is operated from within the LCOs at the onset of the AOO or DBA and the equipment functions as designed.

Note that in the accompanying LCO 3.3.1, the Allowable Values of Table 3.3.1-1 are the LSSS.

Palisades Nuclear Plant B 3.3.1-8 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES BACKGROUND Reactor Protective System Bypasses (continued)

Three different types of trip bypass are utilized in the RPS, Operating Bypass, Zero Power Mode Bypass, and Trip Channel Bypass. The Operating Bypass or Zero Power Mode Bypass prevent the actuation of a trip unit or auxiliary trip unit; the Trip Channel Bypass prevents the trip unit output from affecting the Logic Matrix. A channel which is bypassed, other than as allowed by the Table 3.3.1-1 footnotes, cannot perform its specified safety function and must be considered to be inoperable.

Operating Bypasses The Operating Bypasses are initiated and removed automatically during startup and shutdown as power level changes. An Operating Bypass prevents the associated RPS auxiliary trip unit from receiving a trip signal from the associated measurement channel. With the bypass in place, neither the pre-trip alarm nor the trip will actuate ifthe measured parameter exceeds the set point. An annunciator is provided for each Operating Bypass. The RPS trips with Operating Bypasses are:

a. High Startup Rate Trip bypass. The High Startup Rate trip is automatically bypassed when the associated wide range channel indicates below 1E-4% RTP, and when the associated power range excore channel indicates above 13% RTP. These bypasses are automatically removed between 1 E-4% RTP and 13% RTP.

b. Loss of Load bypass. The Loss of Load trip is automatically bypassed when the associated power range excore channel indicates below 17% RTP. The bypass is automatically removed when the channel indicates above the set point. The same power range excore channel bistable is used to bypass the High Startup Rate trip and the Loss of Load trip for that RPS channel.

Palisades Nuclear Plant B 3.3.1-9 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES BACKGROUND Operating Bypasses (continued)

(continued)

Each wide range channel contains two bistables set at 1 E-4% RTP, one bistable unit for each associated RPS channel. Each of the two wide range channels affect the Operating Bypasses for two RPS channels; wide range channel N1-1/3 for RPS channels A and C, wide range channel NI-2/4 for RPS channels B and D. Each of the four power range excore channel affects the Operating Bypasses for the associated RPS channel. The power range excore channel bistables associated with the Operating Bypasses are set at a nominal 15%, and are required to actuate between 13% RTP and 17% RTP.

Zero Power Mode (ZPM) Bypass The ZPM Bypass is used when the plant is shut down and it is desired to raise the control rods for control rod drop testing with PCS flow, pressure or temperature too low for the RPS trips to be reset. ZPM bypasses may be manually initiated and removed when wide range power is below 1E-4% RTP, and are automatically removed if the associated wide range NI indicated power exceeds 1 E-4% RTP. A ZPM bypass prevents the RPS trip unit from actuating ifthe measured parameter exceeds the set point. Operation of the pretrip alarm is unaffected by the zero power mode bypass. An annunciator indicates the presence of any ZPM bypass. The RPS trips with ZPM bypasses are:

a. Low Primary Coolant System Flow.

b. Low Steam Generator Pressure.

c. Thermal Margin/Low Pressure.

The wide range NI channels provide contact closure permissive signals when indicated power is below 1E-4% RTP. The ZPM bypasses may then be manually initiated or removed by actuation of key-lock switches.

One key-lock switch located on each RPS cabinet controls the ZPM Bypass for the associated RPS trip channels. The bypass is automatically removed ifthe associated wide range NI indicated power exceeds 1 E-4% RTP. The same wide range NI channel bistables that provide the ZPM Bypass permissive and removal signals also provide the high startup rate trip Operating Bypass actuation and removal.

Palisades Nuclear Plant B 3.3.1-10 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES BACKGROUND Trip Channel Bypass (continued)

A Trip Channel Bypass is used when it is desired to physically remove an individual trip unit from the system, or when calibration or servicing of a trip channel could cause an inadvertent trip. A trip Channel Bypass may be manually initiated or removed at any time by actuation of a key-lock switch. A Trip Channel Bypass prevents the trip unit output from affecting the RPS logic matrix. A light above the bypass switch indicates that the trip channel has been bypassed. Each RPS trip unit has an associated trip channel bypass:

The key-lock trip channel bypass switch is located above each trip unit.

The key cannot be removed when in the bypass position. Only one key for each trip parameter is provided, therefore the operator can bypass only one channel of a given parameter at a time. During the bypass condition, system logic changes from two-out-of-four to two-out-of-three channels required for trip.

APPLICABLE Each of the analyzed accidents and transients can be detected by one SAFETY ANALYSES or more RPS Functions. The accident analysis contained in Reference 4 takes credit for most RPS trip Functions. The High Startup Rate and Loss of Load Functions, which are not specifically credited in the accident analysis, are part of the NRC approved licensing basis for the plant, and are required to be operable in accordance with their respective LCO. The High Startup Rate and Loss of Load trips are purely equipment protective, and their use minimizes the potential for equipment damage.

The specific safety analyses applicable to each protective Function are identified below.

1. Variable High Power Trip (VHPT)

The VHPT provides reactor core protection against positive reactivity excursions.

The safety analysis assumes that this trip is OPERABLE to terminate excessive positive reactivity insertions during power operation and while shut down.

Palisades Nuclear Plant B 3.3.1 -11 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES APPLICABLE 2. High Startup Rate Trip SAFETY ANALYSIS (continued) There are no safety analyses which take credit for functioning of the High Startup Rate Trip. The High Startup Rate trip is used to trip the reactor when excore wide range power indicates an excessive rate of change. The High Startup Rate trip minimizes transients for events such as a continuous control rod withdrawal or a boron dilution event from low power levels. The trip may be operationally bypassed when THERMAL POWER is

< 1E-4% RTP, when poor counting statistics may lead to erroneous indication. It may also be operationally bypassed at

> 13% RTP, where moderator temperature coefficient and fuel temperature coefficient make high rate of change of power unlikely.

There are only two wide range drawers, with each supplying contact input to auxiliary trip units in two RPS channels.

3. Low Primary Coolant System Flow Trip The Low PCS Flow trip provides DNB protection during events which suddenly reduce the PCS flow rate during power operation, such as loss of power to, or seizure of, a primary coolant pump.

Flow in each of the four PCS loops is determined from pressure drop from inlet to outlet of the SGs. The total PCS flow is determined, for the RPS flow channels, by summing the loop pressure drops across the SGs and correlating this pressure sum with the sum of SG differential pressures which exist at 100% flow (four pump operation at full power Tve). Full PCS flow is that flow which exists at RTP, at full power Tave, with four pumps operating.

4, 5. Low Steam Generator Level Trip The Low Steam Generator Level trips are provided to trip the reactor in the event of excessive steam demand (to prevent overcooling the PCS) and loss of feedwater events (to prevent overpressurization of the PCS).

The Allowable Value assures that there will be sufficient water inventory in the SG at the time of trip to allow a safe and orderly plant shutdown and to prevent SG dryout assuming minimum AFW capacity.

Palisades Nuclear Plant B 3.3.1-12 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES APPLICABLE 4, 5. Low Steam Generator Level Trip (continued)

SAFETY ANALYSIS (continued) Each SG level is sensed by measuring the differential pressure in the upper portion of the downcomer annulus in the SG. These trips share four level sensing channels on each SG with the AFW actuation signal.

6, 7. Low Steam Generator Pressure Trip The Low Steam Generator Pressure trip provides protection against an excessive rate of heat extraction from the steam generators, which would result in a rapid uncontrolled cooldown of the PCS. This trip provides a mitigation function in the event of an MSLB.

The Low SG Pressure channels are shared with the Low SG Pressure signals which isolate the steam and feedwater lines.

8. High Pressurizer Pressure Trip The High Pressurizer Pressure trip, in conjunction with pressurizer safety valves and Main Steam Safety Valves (MSSVs), provides protection against overpressure conditions in the PCS when at operating temperature. The safety analyses assume the High Pressurizer Pressure trip is OPERA13LE during accidents and transients which suddenly reduce PCS cooling (e.g., Loss of Load, Main Steam Isolation Valve (MSIV) closure, etc.) or which suddenly increase reactor power (e.g., rod ejection accident).

The High Pressurizer Pressure trip shares four safety grade instrument channels with the TM/LP trip, Anticipated Transient Without Scram (ATWS) and PORV circuits, and the Pressurizer Low Pressure Safety Injection Signal.

Palisades Nuclear Plant B 3.3.1-13 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES APPLICABLE 9. Thermal Margin/Low Pressure (TM/LP) Trip SAFETY ANALYSIS (continued) The TM/LP trip is provided to prevent reactor operation when the DNBR is insufficient. The TM/LP trip protects against slow reactivity or temperature increases, and against pressure decreases.

The trip is initiated whenever the PCS pressure signal drops below a minimum value (Pmin) or a computed value (Pvar) as described below, whichever is higher.

The TM/LP trip uses Q Power, ASI, pressurizer pressure, and cold leg temperature (Tc) as inputs.

Q Power is the higher of core THERMAL POWER (AT Power) or nuclear power. The AT power uses hot leg and cold leg RTDs as inputs. Nuclear power uses the power range excore channels as inputs. Both the AT and excore power signals have provisions for calibration by calorimetric calculations.

The ASI is calculated from the upper and lower power range excore detector signals, as explained in Section 1.1, "Definitions."

The signal is corrected for the difference between the flux at the core periphery and the flux at the detectors.

The Tc value is the higher of the two cold leg signals.

The Low Pressurizer Pressure trip limit (Pvar)iS calculated using the equations given in Table 3.3.1-2.

The calculated limit (Pwar) is then compared to a fixed Low Pressurizer Pressure trip limit (Pmin). The auctioneered highest of these signals becomes the trip limit (Ptrip). Ptrip is compared to the measured PCS pressure and a trip signal is generated when the measured pressure for that channel is less than or equal to Ptrip.

A pre-trip alarm is also generated when P is less than or equal to the pre-trip setting, Ptrip + AP.

The TM/LP trip setpoint is a complex function of these inputs and represents a minimum acceptable PCS pressure for the existing temperature and power conditions. It is compared to actual PCS pressure in the TM/LP trip unit.

Palisades Nuclear Plant B 3.3.1-14 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES APPLICABLE 10. Loss of Load Trip SAFETY ANALYSIS (continued) There are no safety analyses which take credit for functioning of the Loss of Load Trip.

The Loss of Load trip is provided to prevent lifting the pressurizer and main steam safety valves in the event of a turbine generator trip while at power. The trip is equipment protective. The safety analyses do not assume that this trip functions during any accident or transient. The Loss of Load trip uses two-out-of-three logic from pressure switches in the turbine auto stop oil circuit to sense a turbine trip for input to all four RPS auxiliary trip units.

11. Containment High Pressure Trip The Containment High Pressure trip provides a reactor trip in the event of a Loss of Coolant Accident (LOCA) or Main Steam Line Break (MSLB). The Containment High Pressure trip shares sensors with the Containment High Pressure sensing logic for Safety Injection, Containment Isolation, and Containment Spray.

Each of these sensors has a single bellows which actuates two microswitches. One microswitch on each of four sensors provides an input to the RPS.

12. Zero Power Mode Bypass Removal The only RPS bypass considered in the safety analyses is the Zero Power Mode (ZPM) Bypass. The ZPM Bypass is used when the plant is shut down and it is desired to raise the control rods for control rod drop testing with PCS flow or temperature too low for the RPS Low PCS Flow, Low SG Pressure, or Thermal Margin/Low Pressure trips to be reset. ZPM bypasses are automatically removed if the wide range NI indicated power exceeds 1E-4% RTP.

Palisades Nuclear Plant B 3.3.1-15 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES APPLICABLE 12. Zero Power Mode Bypass Removal (continued)

SAFETY ANALYSIS (continued) The safety analyses take credit for automatic removal of the ZPM Bypass if reactor criticality due to a Continuous Control Rod Bank Withdrawal should occur with the affected trips bypassed and PCS flow, pressure, or temperature below the values at which the RPS could be reset. The ZPM Bypass would effectively be removed when the first wide range NI channel indication reached 1E-4% RTP. With the ZPM Bypass for two RPS channels removed, the RPS would trip on one of the un-bypassed trips.

This would prevent the reactor reaching an excessive power level.

If a reactor criticality due to a Continuous Control Rod Bank Withdrawal should occur when PCS flow, steam generator pressure, and PCS pressure (TM/LP) were above their trip setpoints, a trip would terminate the event when power increased to the minimum setting (nominally 30%) of the Variable High Power Trip. In this case, the monitored parameters are at or near their normal operational values, and a trip initiated at 30% RTP provides adequate protection.

The RPS design also includes automatic removal of the Operating Bypasses for the High Startup Rate and Loss of Load trips. The safety analyses do not assume functioning of either these trips or the automatic removal of their bypasses.

The RPS instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2).

LCO The LCO requires all instrumentation performing an RPS Function to be OPERABLE. Failure of the trip unit (including its output relays), any required portion of the associated instrument channel, or both, renders the affected channel(s) inoperable and reduces the reliability of the affected Functions. Failure of an automatic ZPM bypass removal channel may also impact the associated instrument channel(s) and reduce the reliability of the affected Functions.

Palisades Nuclear Plant B 3.3.1-16 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES LCO Actions allow Trip Channel Bypass of individual channels, but the (continued) bypassed channel must be considered to be inoperable. The bypass key used to bypass a single channel cannot be simultaneously used to bypass that same parameter in other channels. This interlock prevents operation with more than one channel of the same Function trip channel bypassed. The plant is normally restricted to 7 days in a trip channel bypass, or otherwise inoperable condition before either restoring the Function to four channel operation (two-out-of-four logic) or placing the channel in trip (one-out-of-three logic).

The Allowable Values are specified for each safety related RPS trip Function which is credited in the safety analysis. Nominal trip setpoints are specified in the plant procedures. The nominal setpoints are selected to ensure plant parameters do not exceed the Allowable Value if the instrument loop is performing as required. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. Each Allowable Value specified is more conservative than the analytical limit determined in the safety analysis in order to account for uncertainties appropriate to the trip Function.

These uncertainties are addressed as described in plant document,.

Neither Allowable Values nor setpoints are specified for the non-safety related RPS Trip Functions, since no safety analysis assumptions would be violated if they are not set at a particular value.

The following Bases for each trip Function identify the above RPS trip Function criteria items that are applicable to establish the trip Function OPERABILITY.

1. Variable High Power Trip (VHPT)

This LCO requires all four channels of the VHPT Function to be OPERABLE.

The Allowable Value is high enough to provide an operating envelope that prevents unnecessary VHPT trips during normal plant operations. The Allowable Value is low enough for the system to function adequately during reactivity addition events.

Palisades Nuclear Plant B 3.3.1-17 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES LCO 1. Variable High Power Trip (VHPT) (continued)

(continued)

The VHPT is designed to limit maximum reactor power to its maximum design and to terminate power excursions initiating at lower powers without power reaching this full power limit. During plant startup, the VHPT trip setpoint is initially at its minimum value, < 30%. Below 30% RTP, the VHPT setpoint is not required to "track" with Q Power, i.e., be adjusted to within 15% RTP. It remains fixed until manually reset, at which point it increases to

< 15% above existing Q Power.

The maximum allowable setting of the VHPT is 109.4% RTP.

Adding to this the possible variation in trip setpoint due to calibration and instrument error, the maximum actual steady state power at which a trip would be actuated is 113.4%, which is the value assumed in the safety analysis.

2. High Startup Rate Trip This LCO requires four channels of High Startup Rate Trip Function to be OPERABLE in MODES 1 and 2.

The High Startup Rate trip serves as a backup to the administratively enforced startup rate limit. The Function is not credited in the accident analyses; therefore, no Allowable Value for the trip or operating bypass Functions is derived from analytical limits and none is specified.

The High Startup Rate Trip is required to be OPERABLE, in accordance with the LCO, even though the Trip Function is not credited in the accident analysis.

The four channels of the High Startup Rate trip are derived from two wide range NI signal processing drawers. Thus, a failure in one wide range channel could render two RPS channels inoperable. It is acceptable to continue operation in this condition because the High Startup Rate trip is not credited in any safety analyses.

The requirement for this trip Function is modified by a footnote, which allows the High Startup Rate trip to be bypassed when the wide range NI indicates below 1OE-4% or when THERMAL POWER is above 13% RTP. If a High Startup Rate trip is bypassed when power is between these limits, it must be considered to be inoperable.

Palisades Nuclear Plant B 3.3.1-18 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES LCO 3. Low Primary Coolant System Flow Trip (continued)

This LCO requires four channels of Low PCS Flow Trip Function to be OPERABLE.

This trip is set high enough to maintain fuel integrity during a loss of flow condition. The setting is low enough to allow for normal operating fluctuations from offsite power.

The Low PCS Flow trip setpoint of 95% of full PCS flow insures that the reactor cannot operate when the flow rate is less than 93% of the nominal value considering instrument errors. Full PCS flow is that flow which exists at RTP, at full power Tave, with four pumps operating.

The requirement for this trip Function is modified by a footnote, which allows use of the ZPM bypass when wide range power is below 1 E-4% RTP. That bypass is automatically removed when the associated wide range channel indicates 1 E-4% RTP. If a trip channel is bypassed when power is above 1E-4% RTP, it must be considered to be inoperable.

4, 5. Low Steam Generator Level Trip This LCO requires four channels of Low Steam Generator Level Trip Function per steam generator to be OPERABLE.

The 25.9% Allowable Value assures that there is an adequate water inventory in the steam generators when the reactor is critical and is based upon narrow range instrumentation. The 25.9%

indicated level corresponds to the location of the feed ring.

6, 7. Low Steam Generator Pressure Trip This LCO requires four channels of Low Steam Generator Pressure Trip Function per steam generator to be OPERABLE.

The Allowable Value of 500 psia is sufficiently below the full load operating value for steam pressure so as not to interfere with normal plant operation, but still high enough to provide the required protection in the event of excessive steam demand.

Since excessive steam demand causes the PCS to cool down, resulting in positive reactivity addition to the core, a reactor trip is required to offset that effect.

Palisades Nuclear Plant B 3.3.1-19 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES LCO (continued) 8. High Pressurizer Pressure Trip This LCO requires four channels of High Pressurizer Pressure Trip Function to be OPERABLE.

The Allowable Value is set high enough to allow for pressure increases in the PCS during normal operation (i.e., plant transients) not indicative of an abnormal condition. The setting is below the lift setpoint of the pressurizer safety valves and low enough to initiate a reactor trip when an abnormal condition is indicated.

9. Thermal Margin/Low Pressure (TM/IP) Trip This LCO requires four channels of TM/LP Trip Function to be OPERABLE.

The TM/LP trip setpoints are derived from the core thermal limits through application of appropriate allowances for measurement uncertainties and processing errors. The allowances specifically account for instrument drift in both power and inlet temperatures, calorimetric power measurement, inlet temperature measurement, and primary system pressure measurement.

Other uncertainties including allowances for assembly power tilt, fuel pellet manufacturing tolerances, core flow measurement uncertainty and core bypass flow, inlet temperature measurement time delays, and ASI measurement, are included in the development of the TM/LP trip setpoint used in the accident analysis.

The requirement for this trip Function is modified by a footnote, which allows use of the ZPM bypass when wide range power is below 1E-4% RTP. That bypass is automatically removed when the associated wide range channel indicates 1 E-4% RTP. If a trip channel is bypassed when power is above 1E-4% RTP, it must be considered to be inoperable.

Palisades Nuclear Plant B 3.3.1-20 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES LCO 10. Loss of Load Trip (continued)

The LCO requires four Loss of Load Trip Function channels to be OPERABLE in MODE 1 with THERMAL POWER > 17% RTP.

The Loss of Load trip may be bypassed or be inoperable with THERMAL POWER < 17% RTP, since it is no longer needed to prevent lifting of the pressurizer safety valves or steam generator safety valves in the event of a Loss of Load. Loss of Load Trip unit must be considered inoperable if it is bypassed when THERMAL POWER is above 17% RTP.

This LCO requires four RPS Loss of Load auxiliary trip units, relays 305L and 305R, and pressure switches 63/AST-1, 63/AST-2, and 63/AST-3 to be OPERABLE. With those components OPERABLE, a turbine trip will generate a reactor trip.

The LCO does not require the various turbine trips, themselves, to be OPERABLE.

The Nuclear Steam Supply System and Steam Dump System are capable of accommodating the Loss of Load without requiring the use of the above equipment.

The Loss of Load Trip Function is not credited in the accident analysis; therefore, an Allowable Value for the trip cannot be derived from analytical limits, and is not specified.

The Loss of Load Trip is required to be OPERABLE, in accordance with the LCO, even though the Trip Function is not credited in the accident analysis.

11. Containment High Pressure Trip This LCO requires four channels of Containment High Pressure Trip Function to be OPERABLE.

The Allowable Value is high enough to allow for small pressure increases in containment expected during normal operation (i.e., plant heatup) that are not indicative of an abnormal condition.

The setting is low enough to initiate a reactor trip to prevent containment pressure from exceeding design pressure following a DBA and ensures the reactor is shutdown before initiation of safety injection and containment spray.

Palisades Nuclear Plant B 3.3.1-21 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES LCO (continued) 12. ZPM Bypass The LCO requires that four channels of automatic Zero Power Mode (ZPM) Bypass removal instrumentation be OPERABLE.

Each channel of automatic ZPM Bypass removal includes a shared wide range NI channel, an actuating bistable in the wide range drawer, and a relay in the associated RPS cabinet. Wide Range NI channel 1/3 is shared between ZPM Bypass removal channels A and C; Wide Range NI channel 2/4, between ZPM Bypass removal channels B and D. An operable bypass removal channel must be capable of automatically removing the capability to bypass the affected RPS trip channels with the ZPM Bypass key switch at the proper setpoint.

APPLICABILITY This LCO requires all safety related trip functions to be OPERABLE in accordance with Table 3.3.1-1.

Those RPS trip Functions which are assumed in the safety analyses (all except High Startup Rate and Loss of Load), are required to be operable in MODES 1 and 2, and in MODES 3, 4, and 5 with more than one full-length control rod capable of being withdrawn and PCS boron concentration less than REFUELING BORON CONCENTRATION.

These trip Functions are not required while in MODES 3, 4, or 5, if PCS boron concentration is at REFUELING BORON CONCENTRATION, or when no more than one full-length control rod is capable of being withdrawn, because the RPS Function is already fulfilled. REFUELING BORON CONCENTRATION provides sufficient negative reactivity to assure the reactor remains subcritical regardless of control rod position, and the safety analyses assume that the highest worth withdrawn full-length control rod will fail to insert on a trip. Therefore, under these conditions, the safety analyses assumptions will be met without the RPS trip Function. j The High Startup Rate Trip Function is required to be OPERABLE in MODES 1 and 2, but may be bypassed when the associated wide range NI channel indicates below 1E-4% power, when poor counting statistics may lead to erroneous indication. In MODES 3, 4, 5, and 6, the High Startup Rate trip is not required to be OPERABLE. Wide range channels are required to be OPERABLE in MODES 3, 4, and 5, by LCO 3.3.9, "Neutron Flux Monitoring Channels," and in MODE 6, by LCO 3.9.2, "Nuclear Instrumentation."

Palisades Nuclear Plant B 3.3.1-22 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES APPLICABILITY (continued) The High Startup Rate Trip Function is required to be OPERABLE in MODES 1 and 2, but may be bypassed when the associated wide range NI channel indicates below 1E-4% power, when poor counting statistics may lead to erroneous indication. In MODES 3, 4, 5, and 6, the High Startup Rate trip is not required to be OPERABLE. Wide range channels are required to be OPERABLE in MODES 3, 4, and 5, by LCO 3.3.9, "Neutron Flux Monitoring Channels," and in MODE 6, by LCO 3.9.2, "Nuclear Instrumentation."

The Loss of Load trip is required to be OPERABLE with THERMAL POWER at or above 17% RTP. Below 17% RTP, the ADVs are capable of relieving the pressure due to a Loss of Load event without challenging other overpressure protection.

The trips are designed to take the reactor subcritical, maintaining the SLs during AOOs and assisting the ESF in providing acceptable consequences during accidents.

ACTIONS The most common causes of channel inoperability are outright failure of loop components or drift of those loop components which is sufficient to exceed the tolerance provided in the plant setpoint analysis. Loop component failures are typically identified by the actuation of alarms due to the channel failing to the "safe" condition, during CHANNEL CHECKS (when the instrument is compared to the redundant channels), or during the CHANNEL FUNCTIONAL TEST (when an automatic component might not respond properly). Typically, the drift of the loop components is found to be small and results in a delay of actuation rather than a total loss of function. Excessive loop component drift would, most likely, be identified during a CHANNEL CHECK (when the instrument is compared to the redundant channels) or during a CHANNEL CALIBRATION (when instrument loop components are checked against reference standards).

In the event a channel's trip setpoint is found nonconservative with respect to the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or RPS bistable trip unit is found inoperable, all affected Functions provided by that channel must be declared inoperable, and the plant must enter the Condition for the particular protection Functions affected.

Palisades Nuclear Plant B 3.3.1-23 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES ACTIONS (continued) When the number of inoperable channels in a trip Function exceeds that specified in any related Condition associated with the same trip Function, then the plant is outside the safety analysis. Therefore, LCO 3.0.3 is immediately entered if applicable in the current MODE of operation.

A Note has been added to the ACTIONS to clarify the application of the Completion Time rules. The Conditions of this Specification may be entered independently for each Function. The Completion Times of each inoperable Function will be tracked separately for each Function, starting from the time the Condition was entered.

A.1 Condition A applies to the failure of a single channel in any required RPS Function, except High Startup Rate, Loss of Load, or ZPM Bypass Removal. (Condition A is modified by a Note stating that this Condition does not apply to the High Startup Rate, Loss of Load, or ZPM Bypass Removal Functions. The failure of one channel of those Functions is addressed by Conditions B, C, or D.)

If one RPS bistable trip unit or associated instrument channel is inoperable, operation is allowed to continue. Since the trip unit and associated instrument channel combine to perform the trip function, this Condition is also appropriate ifboth the trip unit and the associated instrument channel are inoperable. Though not required, the inoperable channel may be bypassed. The provision of four trip channels allows one channel to be bypassed (removed from service) during operations, placing the RPS in two-out-of-three coincidence logic. The failed channel must be restored to OPERABLE status or placed in trip within 7 days.

Required Action A.1 places the Function in a one-out-of-three configuration. In this configuration, common cause failure of dependent channels cannot prevent trip.

The Completion Time of 7 days is based on operating experience, which has demonstrated that a random failure of a second channel occurring during the 7 day period is a low probability event.

Palisades Nuclear Plant B 3.3.1-24 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES ACTIONS A.1 (continued)

(continued)

The Completion Time of 7 days is based on operating experience, which has demonstrated that a random failure of a second channel occurring during the 7 day period is a low probability event.

B.1 Condition B applies to the failure of a single High Startup Rate trip unit or associated instrument channel.

If one trip unit or associated instrument channel fails, it must be restored to OPERABLE status prior to entering MODE 2 from MODE 3. A shutdown provides the appropriate opportunity to repair the trip function and conduct the necessary testing. The Completion Time is based on the fact that the safety analyses take no credit for the functioning of this trip.

C.1 Condition C applies to the failure of a single Loss of Load or associated instrument channel.

If one trip unit or associated instrument channel fails, it must be restored to OPERABLE status prior to THERMAL POWER > 17% RTP following a shutdown. If the plant is shutdown at the time the channel becomes inoperable, then the failed channel must be restored to OPERABLE status prior to THERMAL POWER > 17% RTP. For this Completion Time, "following a shutdown" means this Required Action does not have to be completed until prior to THERMAL POWER >_17% RTP for the first time after the plant has been in MODE 3 following entry into the Condition. The Completion Time trip assures that the plant will not be restarted with an inoperable Loss of Load trip channel.

Palisades Nuclear Plant B 3.3.1-25 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES ACTIONS D.1 and D.2 (continued)

Condition D applies when one or more automatic ZPM Bypass removal channels are inoperable. If the ZPM Bypass removal channel cannot be restored to OPERABLE status, the affected ZPM Bypasses must be immediately removed, or the bypassed RPS trip Function channels must be immediately declared to be inoperable. Unless additional circuit failures exist, the ZPM Bypass may be removed by placing the associated "Zero Power Mode Bypass" key operated switch in the normal position.

A trip channel which is actually bypassed, other than as allowed by the Table 3.3.1-1 footnotes, cannot perform its specified safety function and must immediately be declared to be inoperable.

E.1 and E.2 Condition E applies to the failure of two channels in any RPS Function, except ZPM Bypass Removal Function. (The failure of ZPM Bypass Removal Functions is addressed by Condition D.).

Condition E is modified by a Note stating that this Condition does not apply to the ZPM Bypass Removal Function.

Required Action E.1 provides for placing one inoperable channel in trip within the Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . Though not required, the other inoperable channel may be (trip channel) bypassed.

Palisades Nuclear Plant B 3.3.1-26 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES ACTIONS E.1 and E.2 (continued)

(continued)

This Completion Time is sufficient to allow the operator to take all appropriate actions for the failed channels while ensuring that the risk involved in operating with the failed channels is acceptable. With one channel of protective instrumentation bypassed or inoperable in an untripped condition, the RPS is in a two-out-of-three logic for that function; but with another channel failed, the RPS may be operating in a two-out-of-two logic. This is outside the assumptions made in the analyses and should be corrected. To correct the problem, one of the inoperable channels is placed in trip. This places the RPS in a one-out-of-two for that function logic. If any of the other unbypassed channels for that function receives a trip signal, the reactor will trip.

Action E.2 is modified by a Note stating that this Action does not apply to (is not required for) the High Startup Rate and Loss of Load Functions.

One channel is required to be restored to OPERABLE status within 7 days for reasons similar to those stated under Condition A. After one channel is restored to OPERABLE status, the provisions of Condition A still apply to the remaining inoperable channel. Therefore, the channel that is still inoperable after completion of Required Action E.2 must be placed in trip if more than 7 days have elapsed since the initial channel failure.

F.1 The power range excore channels are used to generate the internal ASI signal used as an input to the TM/LP trip. They also provide input to the Thermal Margin Monitors for determination of the Q Power input for the TM/LP trip and the VHPT. If two power range excore channels cannot be restored to OPERABLE status, power is restricted or reduced during subsequent operations because of increased uncertainty associated with inoperable power range excore channels which provide input to those trips.

The Completion Time of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months is adequate to reduce power in an orderly manner without challenging plant systems.

Palisades Nuclear Plant B 3.3.1-27 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES ACTIONS G.1, G.2.1, and G.2.2 (continued)

Condition G is entered when the Required Action and associated Completion Time of Condition A, B, C, D, E, or F are not met, or if the control room ambient air temperature exceeds 90 0 F.

If the control room ambient air temperature exceeds 90 0 F, all Thermal Margin Monitor channels are rendered inoperable because their operating temperature limit is exceeded. In this condition, or if the Required Actions and associated Completion Times are not met, the reactor must be placed in a condition in which the LCO does not apply.

To accomplish this, the plant must be placed in MODE 3, with no more than one full-length control rod capable of being withdrawn or with the PCS boron concentration at REFUELING BORON CONCENTRATION in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

The Completion Time is reasonable, based on operating experience, for placing the plant in MODE 3 from full power conditions in an orderly manner and without challenging plant systems. The Completion Time is also reasonable to ensure that no more than one full-length control rod is capable of being withdrawn or that the PCS boron concentration is at REFUELING BORON CONCENTRATION.

SURVEILLANCE The SRs for any particular RPS Function are found in the SR column of REQUIREMENTS Table 3.3.1-1 for that Function. Most Functions are subject to CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, and CHANNEL CALIBRATION.

SR 3.3.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. Under most conditions, a CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying that the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Palisades Nuclear Plant B 3.3.1-28 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.1 (continued)

REQUIREMENTS (continued) Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication

.and readability. If a channel is outside the criteria, it may be an indication that the transmitter orthe signal processing equipment has drifted outside its limits.

The Containment High Pressure and Loss of Load channels are pressure switch actuated. As such, they have no associated control room indicator and do not require a CHANNEL CHECK.

The Frequency, about once every shift, is based on operating experience that demonstrates the rarity of channel failure. Since the probability of two random failures in redundant channels in any 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months period is extremely low, the CHANNEL CHECK minimizes the chance of loss of protective function due to failure of redundant channels. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel OPERABILITY during normal operational use of the displays associated with the LCO required channels.

SR 3.3.1.2 This SR verifies that the control room ambient air temperature is within the environmental qualification temperature limits for the most restrictive RPS components, which are the Thermal Margin Monitors. These monitors provide input to both the VHPT Function and the TM/LP Trip Function. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is reasonable based on engineering judgment and plant operating experience.

SR 3.3.1.3 A daily calibration (heat balance) is performed when THERMAL POWER is > 15%. The daily calibration consists of adjusting the "nuclear power calibrate" potentiometers to agree with the calorimetric calculation ifthe absolute difference is > 1.5%. Nuclear power is adjusted via a potentiometer, or THERMAL POWER is adjusted via a Thermal Margin Monitor bias number, as necessary, in accordance with the daily calibration (heat balance) procedure. Performance of the daily calibration ensures that the two inputs to the Q power measurement are indicating accurately with respect to the much more accurate secondary calorimetric calculation.

Palisades Nuclear Plant B 3.3.1-29 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.3 (continued)

REQUIREMENTS (continued) The Frequency of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is based on plant operating experience and takes into account indications and alarms located in the control room to detect deviations in channel outputs.

The Frequency is modified by a Note indicating this Surveillance must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is > 15% RTP.

The secondary calorimetric is inaccurate at lower power levels. The 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allows time requirements for plant stabilization, data taking, and instrument calibration.

SR 3.3.1.4 It is necessary to calibrate the power range excore channel upper and lower subchannel amplifiers such that the measured ASI reflects the true core power distribution as determined by the incore detectors. ASI is utilized as an input to the TM/LP trip function where it is used to ensure that the measured axial power profiles are bounded by the axial power profiles used in the development of the Tiniet limitation of LCO 3.4.1. An adjustment of the excore channel is necessary only if reactor power is greater than 25% RTP and individual excore channel ASI differs from AXIAL OFFSET, as measured by the incores, outside the bounds of the following table:

Allowed Group 4 Group 4 Reactor Rods > 128" withdrawn Rods <128" withdrawn Power

< 100% -0.020 < (AO-ASI) < 0.020 -0.040 5 (AO-ASI) 5 0.040

< 95 -0.033 < (AO-ASI) < 0.020 -0.053 < (AO-ASI) 5 0.040

< 90 -0.046 < (AO-ASI) < 0.020 -0.066 5 (AO-ASI) 5 0.040

< 85 -0.060 < (AO-ASI) < 0.020 -0.080 < (AO-ASI) < 0.040

< 80 -0.120 < (AO-ASI) < 0.080 -0.140 5 (AO-ASI) 5 0.100

< 75 -0.120 < (AO-ASI) < 0.080 -0.140 5 (AO-ASI) 5 0.100

< 70 -0.120 5 (AO-ASI) < 0.080 -0.140 5 (AO-ASI) < 0.100

< 65 -0.120 < (AO-ASI) < 0.080 -0.140 < (AO-ASI) < 0.100

< 60 -0.160 < (AO-ASI) < 0.120 -0.180 < (AO-ASI) < 0.140

< 55 -0.160 5 (AO-ASI) < 0.120 -0.180 5 (AO-ASI)

0.140

< 50 -0.160 5 (AO-ASI) 5 0.120 -0.180 5 (AO-ASI) < 0.140

< 45 -0.160 5 (AO-ASI) 5 0.120 -0.180 -<(AO-ASI) < 0.140

< 40 -0.160 5 (AO-ASI) 5 0.120 -0.180 < (AO-ASI) < 0.140

< 35 -0.160 < (AO-ASI) < 0.120 -0.180 < (AO-ASI) 5 0.140

< 30 -0.160 5 (AO-ASI) 5 0.120 -0.180 5 (AO-ASI) 5 0.140

< 25 Below 25% RTP any AO/ASI difference is acceptable Table values determined with a conservative Pvar gamma constant of -9505.

Palisades Nuclear Plant B 3.3.1-30 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.4 (continued)

REQUIREMENTS (continued) Below 25% RTP any difference between ASI and AXIAL OFFSET is acceptable. A Note indicates the Surveillance is not required to have been performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is >Ž25% RTP.

Uncertainties in the excore and incore measurement process make it impractical to calibrate when THERMAL POWER is < 25% RTP. The 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allows time for plant stabilization, data taking, and instrument calibration.

The 31 day Frequency is adequate, based on operating experience of the excore linear amplifiers and the slow burnup of the detectors. The excore readings are a strong function of the power produced in the peripheral fuel bundles and do not represent an integrated reading across the core. Slow changes in neutron flux during the fuel cycle can also be detected at this Frequency.

SR 3.3.1.5 A CHANNEL FUNCTIONAL TEST is performed on each RPS instrument channel, except Loss of Load and High Startup Rate, every 92 days to ensure the entire channel will perform its intended function when needed. For the TM/LP Function, the constants associated with the Thermal Margin Monitors must be verified to be within tolerances.

A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

Any setpoint adjustment must be consistent with the assumptions of the current setpoint analysis.

The Frequency of 92 days is based on the. reliability analysis presented in topical report CEN-327, "RPS/ESFAS Extended Test Interval Evaluation" (Ref. 5).

Palisades Nuclear Plant B 3.3.1-31 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.6 REQUIREMENTS (continued) A calibration check of the power range excore channels using the internal test circuitry is required every 92 days. This SR uses an internally generated test signal to check that the 0% and 50% levels read within limits for both the upper and lower detector, both on the analog meter and on the TMM screen. This check verifies that neither the zero point nor the amplifier gain adjustment have undergone excessive drift since the previous complete CHANNEL CALIBRATION.

The Frequency of 92 days is acceptable, based on plant operating experience, and takes into account indications and alarms available to the operator in the control room.

SR 3.3.1.7 A CHANNEL FUNCTIONAL TEST on the Loss of Load and High Startup Rate channels is performed prior to a reactor startup to ensure the entire channel will perform its intended function.

A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

The High Startup Rate trip is actuated by either of the Wide Range Nuclear Instrument Startup Rate channels. N1-1/3 sends a trip signal to RPS channels A and C; NI-2/4 to channels B and D. Since each High Startup Rate channel would cause a trip on two RPS channels, the High Startup Rate trip is not tested when the reactor is critical.

The four Loss of Load Trip channels are all actuated by a single pressure switch monitoring turbine auto stop oil pressure which is not tested when the reactor is critical. Operating experience has shown that these components usually pass the Surveillance when performed at a Frequency of once per 7 days prior to each reactor startup.

Palisades Nuclear Plant B 3.3.1-32 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.8 REQUIREMENTS (continued) SR 3.3.1.8 is the performance of a CHANNEL CALIBRATION every 18 months.

CHANNEL CALIBRATION is a complete check of the instrument channel including the sensor (except neutron detectors). The Surveillance verifies that the channel responds to a measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drift between successive calibrations to ensure that the channel remains operational between successive tests. CHANNEL CALIBRATIONS must be consistent with the setpoint analysis.

The bistable setpoints must be found to trip within the Allowable Values specified in the LCO and left set consistent with the assumptions of the setpoint analysis. The Variable High Power Trip setpoint shall be verified to reset properly at several indicated power levels during (simulated) power increases and power decreases.

The as-found and as-left values must also be recorded and reviewed for consistency with the assumptions of the setpoint analysis.

As part of the CHANNEL CALIBRATION of the wide range Nuclear Instrumentation, automatic removal of the ZPM Bypass for the Low PCS Flow, TM/LP must be verified to assure that these trips are available when required.

The Frequency is based upon the assumption of an 18 month calibration interval for the determination of the magnitude of equipment drift.

This SR is modified by a Note which states that it is not necessary to calibrate neutron detectors because they are passive devices with minimal drift and because of the difficulty of simulating a meaningful signal. Slow changes in power range excore neutron detector sensitivity are compensated for by performing the daily calorimetric calibration (SR 3.3.1.3) and the monthly calibration using the incore detectors (SR 3.3.1.4). Sudden changes in detector performance would be noted during the required CHANNEL CHECKS (SR 3.3.1.1).

Palisades Nuclear Plant B 3.3.1-33 Revised 08/30/2011

RPS Instrumentation B 3.3.1 BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 21

2. 10 CFR 100

3. IEEE Standard 279-1971, April 5, 1972

4. FSAR, Chapter 14

5. CEN-327, June 2, 1986, including Supplement 1, March 3, 1989 Palisades Nuclear Plant B 3.3.1-34 Revised 08/30/2011

RPS Instrumentation B 3.3.1 Table B 3.3.1-1 (page 1 of 1)

Instruments Affecting Multiple Specifications Required Instrument Channels Affected Specifications Nuclear Instrumentation Source Range NI-1/3, Count Rate Indication @ C-150 Panel 3.3.8 (#1)

Source Range NI-1/3 &2/4, Count Rate Signal 3.3.9 & 3.9.2 Wide Range N1-1/3 & 2/4, Flux Level 10-' Bypass 3.3.1 (#3, 6, 7, 9, & 12)

Wide Range NI-1/3 & 2/4, Startup Rate 3.3.1 (#2)

Wide Range NI-1/3 & 2/4, Flux Level Indication @EC-06 Panel for 3.3.7 3.3.7 (#3) & 3.3.9 Power Range NI-5, 6, 7, & 8, Tq 3.2.1 & 3.2.3 Power Range NI-5, 6, 7, & 8, Q Power 3.3.1 (#1 & 9)

Power Range NI-5, 6, 7, & 8, ASI 3.3.1 (#9) & 3.2.1 & 3.2.4 Power Range NI-5, 6, 7, & 8, Loss of Load/High Startup Rate Bypass 3.3.1 (#2 & 10)

PCS T-Cold Instruments TT-0112CA, Temperature Signal (SPI AT Power for PDIL Alarm Circuit) 3.1.6 TT-0112CA & 0122CA, Temperature Signal (C-150) 3.3.8 (#6 & 7)

TT-0122CB, Temperature Signal (PIP AT Power for PDIL Alarm Circuit) 3.1.6 TT-0112CA & 0122CB, Temperature Signal (LTOP) 3.4.12.b. 1 TT-0112CC &0122CD (PTR-0112 & 0122) Temperature Indication 3.3.7 (#2)

TT-01 12 & 0122 CC & CD, Temperature Signal (SMM) 3.3.7 (#5)

TT-0112 & 0122 CA, CB, CC, & CD, Temperature Signal (Q Power & TMM) 3.3.1 (#1 & 9) & 3.4.1.b PCS T-Hot Instruments TT-0112HA, Temperature Signal (SPI AT Power for PDIL Alarm Circuit) 3.1.6 TT-0112HA & 0122HA, Temperature Signal (C-150) 3.3.8 (#4 & 5)

TT-0122HB, Temperature Signal (PIP AT Power for PDIL Alarm Circuit) 3.1.6 TT-0112 & 0122 HC & HD, Temperature Signal (SMM) 3.3.7 (#5)

TT-0112HC & 0122HD (PTR-0112 & 0122) Temperature Indication 3.3.7 (#1)

TT-01 12 & 0122 HA, HB, HC, & HD, Temperature Signal (Q Power & TMM) 3.3.1 (#1 & 9)

Thermal Margin Monitors PY-0102A, B, C, &D 3.3.1 (#1 & 9)

Pressurizer Pressure Instruments PT-0102A, B, C, & D, Pressure Signal (RPS & SIS) 3.3.1 (#8 & 9) &

3.3.3 (#1.a & 7a)

PT-0104A & B, Pressure Signal (LTOP & SDC Interlock) 3.4.12.b.1 & 3.4.14 PT-0105A & B, Pressure Signal (WR Indication & LTOP) 3.3.7 (#5) & 3.4.12.b.1 P1-0110, Pressure Indication @ C-150 Panel 3.3.8 (#2)

SG Level Instruments LT-0751 &0752 A, B, C, & D, Level Signal (RPS &AFAS) 3.3.1 (#4 & 5) &

3.3.3 (#4.a & 4.b)

LI-0757 &0758 A & B, Wide Range Level Indication 3.3.7 (#11 & 12)

LI-0757C & 0758C, Wide Range Level Indication @ C-150 Panel 3.3.8 (#10 & 11)

SG Pressure Instruments PT-0751 & 0752 A, B, C, & D, Pressure Signal (RPS & SG Isolation) 3.3.1 (#6 & 7) &

3.3.3 (#2a, 2b, 7b, 7c)

PT-0751A and PT-0752A Pressure Signal (C-150/150A) 3.3.8 (#8 & 9)

PIC-0751 & 0752 C & D, Pressure Indication 3.3.7 (#13 & 14)

PI-0751E &0752E, Pressure Indication @ C-150 Panel 3.3.8 (#8 & 9)

Containment Pressure Instruments PS-1801, 1802, 1803, & 1804, Switch Output (RPS) 3.3.1 (#11)

PS-1801, 1802A, 1803, & 1804A, Switch Output (ESF) 3.3.3 (#5.a)

PS-i 801A, 1802, 1803A, & 1804, Switch Output (ESF) 3.3.3 (#5.b)

Note: The information provided in this table is intended for use as an aid to distinguish those instrument channels which provide more than one required function and to describe which specifications they affect. The information in this table should not be taken as inclusive for all instruments nor affected specifications.

Palisades Nuclear Plant B 3.3.1-35 Revised 08/30/2011

DG - UV Start B 3.3.5 B 3.3 INSTRUMENTATION B 3.3.5 Diesel Generator (DG) - Undervoltage Start (UV Start)

BASES BACKGROUND The DGs provide a source of emergency power when offsite power is either unavailable or insufficiently stable to allow safe plant operation.

Undervoltage protection will generate a UV Start in the event a Loss of Voltage or Degraded Voltage condition occurs. There are two UV Start Functions for each 2.4 kV vital bus.

Undervoltage protection and load shedding features for safety-related buses at the 2,400 V and lower voltage levels are designed in accordance with 10 CFR 50, Appendix A, General Design Criterion 17 (Ref. 1) and the following features:

1. Two levels of automatic undervoltage protection from loss or degradation of offsite power sources are provided. The first level (loss of voltage) provides normal loss of voltage protection. The second level of protection (degraded voltage) has voltage and time delay set points selected for automatic trip of the offsite sources to protect safety-related equipment from sustained degraded voltage conditions at all bus voltage levels.

Coincidence logic is provided to preclude spurious trips.

2. The undervoltage protection system automatically prevents load shedding of the safety-related buses when the emergency generators are supplying power to the safeguards loads.

3. Control circuits for shedding of Class 1 E and non-Class 1E loads during a Loss of Coolant Accident (LOCA) themselves are Class 1E or are separated electrically from the Class 1E portions.

Palisades Nuclear Plant B 3.3.5-1 Revised 11/08/2012

DG - UV Start B 3.3.5 BASES BACKGROUND Description (continued)

Each 2,400 V Bus (1C and 1D) is equipped with two levels of undervoltage protection relays (Ref. 2). The first level (Loss of Voltage Function) relays 127-1 and 127-2 are set at approximately 77% of rated voltage with an inverse time relay. One of these relays measures voltage on each of the three phases. They protect against sudden loss of voltage as sensed on the corresponding bus using a three-out-of-three coincidence logic. The actuation of the associated auxiliary relays will trip the associated bus incoming circuit breakers, start its associated DG, initiate bus load shedding, and activate annunciators in the control room. The DG circuit breaker is closed automatically upon establishment of satisfactory voltage and frequency by the use of associated voltage sensing relay 127D-1 or 127D-2.

The second level of undervoltage protection (Degraded Voltage Function) relays 127-7 and 127-8 are set at approximately 93% of rated voltage, with one relay monitoring each of the three phases. These relays protect against sustained degraded voltage conditions on the corresponding bus using a three-out-of-three coincidence logic. These relays have a built-in 0.65 second time delay, after which the associated DG receives a start signal and annunciators in the control room are actuated. If a bus undervoltage exists after an additional six seconds, the associated bus incoming circuit breakers will be tripped and a bus load shed will be initiated.

Trip Setpoints The trip setpoints are based on the analytical limits presented in References 3 and 4, and justified in Reference 5. The selection of these trip setpoints is such that adequate protection is provided when all sensor and processing time delays are taken into account. To allow for calibration tolerances, instrumentation uncertainties, and instrument drift, setpoints specified in SR 3.3.5.2 are conservatively adjusted with respect to the analytical limits. A detailed analysis of the degraded voltage protection is provided in References 3 and 4.

The specified setpoints will ensure that the consequences of accidents will be acceptable, providing the plant is operated from within the LCOs at the onset of the accident and the equipment functions as designed.

Palisades Nuclear Plant B 3.3.5-2 Revised 11/08/2012

DG - UV Start B 3.3.5 BASES APPLICABLE The DG - UV Start is required for Engineered Safety Features (ESF)

SAFETY ANALYSES systems to function in any accident with a loss of offsite power. Its design basis is that of the ESF Systems.

Accident analyses credit the loading of the DG based on a loss of offsite power during a LOCA. The diesel loading has been included in the delay time associated with each safety system component requiring DG supplied power following a loss of offsite power. This delay time includes contributions from the DG start, DG loading, and Safety Injection System component actuation.

The required channels of UV Start, in conjunction with the ESF systems powered from the DGs, provide plant protection in the event of any of the analyzed accidents discussed in Reference 6, in which a loss of offsite power is assumed. UV Start channels are required to meet the redundancy and testability requirements of GDC 21 in 10 CFR 50, Appendix A (Ref. 1).

The delay times assumed in the safety analysis for the ESF equipment include the 10 second DG start delay and the appropriate sequencing delay, if applicable. The response times for ESFAS actuated equipment include the appropriate DG loading and sequencing delay.

The DG - UV Start channels satisfy Criterion 3 of 10 CFR 50.36(c)(2).

LCO The LCO for the DG - UV Start requires that three channels per bus of each UV Start instrumentation Function be OPERABLE when the associated DG is required to be OPERABLE. The UV Start supports safety systems associated with ESF actuation.

The Bases for the trip setpoints are as follows:

The voltage trip setpoint is set low enough such that spurious trips of the offsite source. due to operation of the undervoltage relays are not expected for any combination of plant loads and normal grid voltages.

Palisades Nuclear Plant B 3.3.5-3 Revised 11/08/2012

DG - UV Start B 3.3.5 BASES LCO This setpoint at the 2,400 V bus and reflected down to the 480 V buses (continued) has been verified through an analysis to be greater than the minimum allowable motor voltage (90% of nominal voltage). Motors are the most limiting equipment in the system. MCC contactor pickup and drop-out voltage is also adequate at the setpoint values. The analysis ensures that the distribution system is capable of starting and operating all safety-related equipment within the equipment voltage rating at the allowed source voltages. The power distribution system model used in the analysis has been verified by actual testing (Refs. 5 and 7).

The time delays involved will not cause any thermal damage as the setpoints are within voltage ranges for sustained operation. They are long enough to preclude trip of the offsite source caused by the starting of large motors and yet do not exceed the time limits of ESF actuation assumed in FSAR Chapter 14 (Ref. 6) and validated by Reference 8.

Calibration of the undervoltage relays verify that the time delay is sufficient to avoid spurious trips.

APPLICABILITY The DG - UV Start actuation Function is required to be OPERABLE whenever the associated DG is required to be OPERABLE per LCO 3.8.1, "AC Sources - Operating," or LCO 3.8.2, "AC -Sources -

Shutdown," so that it can perform its function on a loss of power or degraded power to the vital bus.

ACTIONS A DG - UV Start channel is inoperable when it does not satisfy the OPERABILITY criteria for the channel's Function.

In the event a channel's trip setpoint is found nonconservative with respect to the specified setpoint, or the channel is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition entered. The required channels are specified on a per DG basis.

Palisades Nuclear Plant B 3.3.5-4 Revised 11/08/2012

DG - UV Start B 3.3.5 BASES ACTIONS A.1 (continued)

Condition A applies if one or more of the three phase UV sensors or relay logic is inoperable for one or more Functions (Degraded Voltage or Loss of Voltage) per DG bus.

The affected DG must be declared inoperable and the appropriate Condition(s) entered. Because of the three-out-of-three logic in both the Loss of Voltage and Degraded Voltage Functions, the appropriate means of addressing channel failure is declaring the DG inoperable, and effecting repair in a manner consistent with other DG failures.

Required Action A.1 ensures that Required Actions for the affected DG inoperabilities are initiated. Depending upon plant MODE, the actions specified in LCO 3.8.1 or LCO 3.8.2, as applicable, are required immediately.

SURVEILLANCE SR 3.3.5.1 REQUIREMENTS A CHANNEL FUNCTIONAL TEST is performed on each UV Start logic channel every 18 months to ensure that the logic channel will perform its intended function when needed. The Undervoltage sensing relays are tested by SR 3.3.5.2. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

The Frequency of 18 months is based on the plant conditions necessary to perform the test.

Palisades Nuclear Plant B 3.3.5-5 Revised 11/08/2012

DG - UV Start B 3.3.5 BASES SURVEILLANCE SR 3.3.5.2 REQUIREMENTS (continued) A CHANNEL CALIBRATION performed each 18 months verifies the accuracy of each component within the instrument channel. This includes calibration of the undervoltage relays and demonstrates that the equipment falls within the specified operating characteristics defined by the manufacturer.

The Surveillance verifies that the channel responds to a measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drift between successive calibrations to ensure that the channel remains operational between successive tests. CHANNEL CALIBRATIONS must be performed consistent with the setpoint analysis.

The Frequency of 18 months is a typical refueling cycle. Operating experience has shown this Frequency is acceptable.

REFERENCES 1. 10 CFR 50, Appendix A GDCs 17 and 21

2. FSAR, Section 8.6

3. Analysis EA-ELEC-VOLT-033

4. Analysis EA-ELEC-VOLT-034

5. Analysis EA-ELEC-EDSA-04

6. FSAR, Chapter 14

7. Analysis EA-ELEC-EDSA-03

8. Analysis A-NL-92-1 11 Palisades Nuclear Plant B 3.3.5-6 Revised 11/08/2012

PAM Instrumentation B 3.3.7 B 3.3 INSTRUMENTATION B 3.3.7 Post Accident Monitoring (PAM) Instrumentation BASES BACKGROUND The primary purpose of the Post Accident Monitoring (PAM) instrumentation is to display plant variables that provide information required by the control room operators during accident situations. This information provides the necessary support for the operator to take the manual actions, for which no automatic control is provided, that are required for safety systems to accomplish their safety Functions for Design Basis Events.

The OPERABILITY of the PAM instrumentation ensures that there is sufficient information available on selected plant parameters to monitor and assess plant status and behavior following an accident.

The availability of PAM instrumentation is important so that responses to corrective actions can be observed and the need for, and magnitude of, further actions can be determined. The required instruments are identified in FSAR Appendix 7C (Ref. 1) and address the recommendations of Regulatory Guide 1.97 (Ref. 2), as required by Supplement 1 to NUREG-0737, "TMI Action Items" (Ref. 3).

Type A variables are included in this LCO because they provide the primary information required to permit the control room operator to take specific manually controlled actions, for which no automatic control is provided, that are required for safety systems to accomplish their safety functions for Design Basis Accidents (DBAs).

Category I variables are the key variables deemed risk significant because they are needed to:

Determine whether other systems important to safety are performing their intended functions; Provide information to the operators that will enable them to determine the potential for causing a gross breach of the barriers to radioactivity release; and Provide information regarding the release of radioactive materials to allow for early indication of the need to initiate action necessary to protect the public and for an estimate of the magnitude of any impending threat.

Palisades Nuclear Plant B 3.3.7-1 Revised 11/08/2012

PAM Instrumentation B 3.3.7 BASES BACKGROUND These key variables are identified in the plant specific Regulatory (continued) Guide 1.97 analyses (Ref. 1). This analysis identified the plant specific Type A and Category 1 variables and provided justification for deviating from the NRC proposed list of Category I variables.

The specific instrument Functions listed in Table 3.3.7-1 are discussed in the LCO Bases.

APPLICABLE The PAM instrumentation ensures the OPERABILITY of Regulatory SAFETY ANALYSES Guide 1.97 Type A variables, so that the control room operating staff can:

Perform the diagnosis specified in the emergency operating procedures. These variables are restricted to preplanned actions for the primary success path of DBAs; and

" Take the specified, preplanned, manually controlled actions, for which no automatic control is provided, that are required for safety systems to accomplish their safety functions.

The PAM instrumentation also ensures OPERABILITY of Category I, non-Type A variables. This ensures the control room operating staff can:

Determine whether systems important to safety are performing their intended functions;

Determine the potential for causing a gross breach of the barriers to radioactivity release;

Determine if a gross breach of a barrier has occurred; and Initiate action necessary to protect the public as well as to obtain an estimate of the magnitude of any impending threat.

Category I, non-Type A PAM instruments are retained in the Specification because they are intended to assist operators in minimizing the consequences of accidents. Therefore, these Category I variables are important in reducing public risk.

PAM instrumentation that satisfies the definition of Type A in Regulatory Guide 1.97 meets Criterion 3 of 10 CFR 50.36(c)(2).

Palisades Nuclear Plant B 3.3.7-2 Revised 11/08/2012

PAM Instrumentation B 3.3.7 BASES LCO LCO 3.3.7 requires at least two OPERABLE channels for all Functions except Containment Isolation Valve Position Indication. This is to ensure no single failure prevents the operators from being presented with the information necessary to determine the status of the plant and to bring the plant to, and maintain it in, a safe condition following that accident.

Furthermore, provision of at least two channels allows a CHANNEL CHECK during the post accident phase to confirm the validity of displayed information.

For Containment Isolation Valve Position indication, the important information is the status of the containment penetrations. The LCO requires one position indication channel for each containment isolation valve listed in FSAR Appendix 7C (Ref. 1).

Listed below are discussions of the specified instrument Functions listed in Table 3.3.7-1. Component identifiers of the sensors, indicators, power supplies, displays, and recorders in each instrument loop are found in Reference 1.

1,2. Primary Coolant System (PCS) Hot and Cold Leg Temperature (wide range)

PCS wide range Hot and Cold Leg Temperatures are Type B, Category 1 variables provided for verification of core cooling and long term surveillance.

Reactor outlet temperature inputs to the PAM are provided by two wide range resistance elements and associated transmitters (one in each loop). The channels provide indication over a range of 50'F to 700'F.

3. Wide Ranae Neutron Flux Wide Range Neutron Flux indication is a Type B, Category 1 variable, and is provided to verify reactor shutdown.

4. Containment Floor Water Level (wide ranqe)

Wide range Containment Floor Water Level is a Type B, Category 1 variable, and is provided for verification and long-term surveillance of PCS integrity.

Palisades Nuclear Plant B 3.3.7-3 Revised 11/08/2012

PAM Instrumentation B 3.3.7 BASES LCO 5. Subcooled Margin Monitor (continued)

The Subcooled Margin Monitor (SMM) is a Type A, Category 1 variable used to identify conditions, which require tripping of the primary coolant pumps and throttling of safety injection flows. Each SMM channel uses a number of PCS pressure and temperature inputs to determine the degree of PCS subcooling or superheat.

6. Pressurizer Level (Wide Range)

Pressurizer Level is a Type A, Category 1 variable, and is used to determine whether to terminate Safety Injection (SI), if still in progress, or to reinitiate SI if it has been stopped. Knowledge of pressurizer water level is also used to verify the plant conditions necessary to establish natural circulation in the PCS and to verify that the plant is maintained in a safe shutdown condition.

7. (Deleted)

8. Condensate Storage Tank (CST) Level CST Level is a Type D, Category 1 variable, and is provided to ensure water supply for AFW. The CST provides the safety grade water supply for the AFW System. Inventory is monitored by a 0 to 100% level indication. CST Level is displayed on a control room indicator. In addition, a control room annunciator alarms on low level.

The CST is the initial source of water for the AFW System. However, as the CST is depleted, manual operator action is necessary to replenish the CST.

Palisades Nuclear Plant B 3.3.7-4 Revised 11/08/2012

PAM Instrumentation B 3.3.7 BASES LCO 9. Primary Coolant System Pressure (wide ranqe)

(continued)

PCS wide range pressure is a Type A, Category 1 variable provided for verification of core cooling and PCS integrity long-term surveillance.

Wide range PCS loop pressure is measured by pressure transmitters with a span of 0 psia to 3000 psig. Redundant monitoring capability is provided by two channels of instrumentation. Control room indications are provided on C12 and C02.

10. Containment Pressure (wide ranqge)

Wide range Containment Pressure is a Type C, Category 1 variable, and is provided for verification of PCS and containment OPERABILITY.

It is also an input to decisions for initiating containment spray.

11, 12. Steam Generator Water Level (wide range)

Wide range Steam Generator Water Level is a Type A, Category 1 variable, and is provided to monitor operation of decay heat removal via the steam generators. The steam generator level instrumentation covers a span extending from the tube sheet to the steam separators, with an indicated range of -140% to +150%. Redundant monitoring capability is provided by two channels of instrumentation for each SG.

Operator action for maintenance of heat removal is based on the control room indication of Steam Generator Water Level. The indication is used during a SG tube rupture to determine which SG has the ruptured tube. It is also used to determine when to initiate once through cooling on low water level.

13,14. SG Pressure Steam Generator Pressure is a Type A, Category 1 variable used in accident identification, including Loss of Coolant, and Steam Line Break. Redundant monitoring capability is provided by two channels of instrumentation for each SG.

Palisades Nuclear Plant B 3.3.7-5 Revised 11/08/2012

PAM Instrumentation B 3.3.7 BASES LCO 15. Containment Isolation Valve Position (continued)

Containment Isolation Valve (CIV) Position is a Type B, Category 1 variable, and is provided for verification of containment OPERABILITY.

CIV position is provided for verification of containment integrity. In the case of CIV position, the important information is the isolation status of the containment penetration. The LCO requires one channel of valve position indication in the control room to be OPERABLE for each CIV listed in FSAR Appendix 7C (Ref. 1). This is sufficient to redundantly verify the isolation status of each associated penetration via indicated status of the CIVs, and by knowledge of a passive (check) valve or a closed system boundary.

If a penetration flow path is isolated, position indication for the CIV(s) in the associated penetration flow path is not needed to determine status.

Therefore, as indicated in Note (a) the position indication for valves in an isolated penetration flow path is not required to be OPERABLE.

16, 17, 18, 19. Core Exit Temperature Core Exit Temperature is a Type C, Category 1 variable, and is provided for verification and long term surveillance of core cooling.

Each Required Core Exit Thermocouple (CET) channel consists of a single environmentally qualified thermocouple.

The design of the Incore Instrumentation System includes a Type K (chromel alumel) thermocouple within each of the incore instrument detector assemblies.

The junction of each thermocouple is located above the core exit, inside the incore detector assembly guide tube, that supports and shields the incore instrument detector assembly string from flow forces in the outlet plenum region. These core exit thermocouples monitor the temperature of the reactor coolant as it exits the fuel assemblies.

The core exit thermocouples have a usable temperature range from 32 0 F to 2300 0 F, although accuracy is reduced at temperatures above 1800 0 F.

Palisades Nuclear Plant B 3.3.7-6 Revised 11/08/2012

PAM Instrumentation B 3.3.7 BASES LCO 20. Reactor Vessel Water Level (continued)

Reactor Vessel Water Level is monitored by the Reactor Vessel Level Monitoring System (RVLMS) and is a Type B, Category 1 variable provided for verification and long-term surveillance of core cooling.

The RVLMS provides a direct measurement of the collapsed liquid level above the fuel alignment plate. The collapsed level represents the amount of liquid mass that is in the reactor vessel above the core.

Measurement of the collapsed water level is selected because it is a direct indication of the water inventory. The collapsed level is obtained over the same temperature and pressure range as the saturation measurements, thereby encompassing all operating and accident conditions where it must function. Also, it functions during the recovery interval. Therefore, it is designed to survive the high steam temperature that may occur during the preceding core recovery interval.

The level range extends from the top of the vessel down to the top of the fuel alignment plate. A total of eight Heated Junction Thermocouple (HJTC) pairs are employed in each of the two RVLMS channels. Each pair consists of a heated junction TC and an unheated junction TC. The differential temperature at each HJTC pair provides discrete indication of uncovery at the HJTC pair location. This indication is displayed using LEDs in the control room. This provides the operator with adequate indication to track the progression of the accident and to detect the consequences of its mitigating actions or the functionality of automatic equipment.

A RVLMS channel consists of eight sensors in a probe. A channel is OPERABLE if four or more sensors, two or more of the upper four and two or more of the lower four, are OPERABLE.

21. Containment Area Radiation (high range)

High range Containment Area Radiation is a Type E, Category 1 variable, and is provided to monitor for the potential of significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans.

Palisades Nuclear Plant B 3.3.7-7 Revised 11/08/2012

PAM Instrumentation B 3.3.7 BASES APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1, 2, and 3.

These variables are related to the diagnosis and preplanned actions required to mitigate DBAs. The applicable DBAs are assumed to occur in MODES 1, 2, and 3. In MODES 4, 5, and 6, plant conditions are such that the likelihood of an event occurring that would require PAM instrumentation is low; therefore, PAM instrumentation is not required to be OPERABLE in these MODES.

ACTIONS A note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in Table 3.3.7-1. The Completion Time(s) of the inoperable channel(s) of a Function will be tracked separately for each Function, starting from the time the Condition was entered for that Function.

A.1 When one or more Functions have one required channel that is inoperable, the required inoperable channel must be restored to OPERABLE status within 30 days. The 30-day Completion Time is based on operating experience and takes into account the remaining OPERABLE channel, the passive nature of the instrument (no critical automatic action is assumed to occur from these instruments), and the low probability of an event requiring PAM instrumentation during this interval.

ACTIONS B._1 (continued)

This Required Action specifies initiation of actions in accordance with Specification 5.6.6, which requires a written report to be submitted to the Nuclear Regulatory Commission. This, report discusses the results of the root cause evaluation of the inoperability and identifies proposed restorative Required Actions. This Required Action is appropriate in lieu of a shutdown requirement, given the likelihood of plant conditions that would require information provided by this instrumentation. Also, alternative Required Actions are identified before a loss of functional capability condition occurs.

C.1 When one or more Functions have two required channels inoperable (i.e., two channels inoperable in the same Function), one channel in the Function should be restored to OPERABLE status within 7 days. The Completion Time of 7 days is based on the relatively low probability of an event requiring PAM instrumentation operation and the availability of Palisades Nuclear Plant B 3.3.7-8 Revised 11/08/2012

PAM Instrumentation B 3.3.7 BASES alternate means to obtain the required information. Continuous operation with two required channels inoperable in a Function is not acceptable because the alternate indications may not fully meet all performance qualification requirements applied to the PAM instrumentation. Therefore, requiring restoration of one inoperable channel of the Function limits the risk that the PAM Function will be in a degraded condition should an accident occur.

D.1 Condition D is currently not used.

Palisades Nuclear Plant B 3.3.7-9 Revised 11/08/2012

PAM Instrumentation B 3.3.7 BASES ACTIONS E.1 (continued)

This Required Action directs entry into the appropriate Condition referenced in Table 3.3.7-1. The applicable Condition referenced in the Table is Function dependent. Each time Required Action C.1 is not met, and the associated Completion Time has expired, Condition E is entered for that channel and provides for transfer to the appropriate subsequent Condition.

F.1 and F.2 If the Required Action and associated Completion Time of Condition C is not met, and Table 3.3.7-1 directs entry into Condition F, the plant must be brought to a MODE in which the requirements of this LCO do not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

G.1 Alternate means of monitoring Reactor Vessel Water Level and Containment Area Radiation have been developed and tested. These alternate means may be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. If these alternate means are used, the Required Action is not to shut down the plant, but rather to follow the directions of Specification 5.6.6.

The report provided to the NRC should discuss the alternate means used, describe the degree to which the alternate means are equivalent to the installed PAM channels, justify the areas in which they are not equivalent, and provide a schedule for restoring the normal PAM channels.

Palisades Nuclear Plant B 3.3.7-10 Revised 11/08/2012

PAM Instrumentation B 3.3.7 BASES SURVEILLANCE A Note at the beginning of the Surveillance Requirements specifies that REQUIREMENTS the following SRs apply to each PAM instrumentation Function in Table 3.3.7-1.

SR 3.3.7.1 Performance of the CHANNEL CHECK once every 31 days ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verify the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit. If the channels are within the criteria, it is an indication that the channels are OPERABLE. If the channels are normally off scale during times when surveillance is required, the CHANNEL CHECK will only verify that they are off scale in the same direction. Off scale low current loop channels are verified to be reading at the bottom of the range and not failed downscale.

As indicated in the SR, a CHANNEL CHECK is only required for those channels which are normally energized.

The Frequency of 31 days is based upon plant operating experience with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31-day interval is a rare event. The CHANNEL CHECK supplements less formal, but more frequent, checks of channel during normal operational use of the displays associated with this LCO's required channels.

Revised 11/08/2012 B 3.3.7-11 Nuclear Plant Palisades Nuclear Palisades Plant B 3.3.7-11 Revised 11/08/2012

PAM Instrumentation B 3.3.7 BASES SURVEILLANCE SR 3.3.7.2 REQUIREMENTS (continued) A CHANNEL CALIBRATION is performed every 18 months or approximately every refueling. CHANNEL CALIBRATION is typically a complete check of the instrument channel including the sensor.

Therefore, this SR is modified by a Note, which states that it is not necessary to calibrate neutron detectors because of the difficulty of simulating a meaningful signal. Wide range and source range nuclear instrument channels are not calibrated to indicate the actual power level or the flux in the detector location. The circuitry is adjusted so that wide range and source range readings may be used to determine the approximate reactor flux level for comparative purposes. The Surveillance verifies the channel responds to the measured parameter within the necessary range and accuracy.

For the core exit thermocouples, a CHANNEL CALIBRATION is performed by substituting a known voltage for the thermocouple.

The Frequency is based upon operating experience and consistency with the typical industry refueling cycle and is justified by an 18 month calibration interval for the determination of the magnitude of equipment drift.

REFERENCES 1. FSAR, Appendix 7C, "Regulatory Guide 1.97 Instrumentation"

2. Regulatory Guide 1.97

3. NUREG-0737, Supplement 1 Palisades Nuclear Plant B 3.3.7-12 Revised 11/08/2012

PCS P/T Limits B 3.4.3 B 3.4 PRIMARY COOLANT SYSTEM (PCS)

B 3.4.3 PCS Pressure and Temperature (P/T) Limits BASES BACKGROUND All components of the PCS are designed to withstand effects of cyclic loads due to system pressure and temperature changes. These loads are introduced by startup (heatup) and shutdown (cooldown) operations, power transients, and reactor trips. This LCO limits the pressure and temperature changes during PCS heatup and cooldown, within the design assumptions and the stress limits for cyclic operation.

Figures 3.4.3-1 and 3.4.3-2 contain P/T limit curves for heatup, cooldown, and Inservice Leak and Hydrostatic (ISLH) testing, and data for the maximum rate of change of primary coolant temperature.

Each P/T limit curve defines an acceptable region for normal operation.

The P/T limit curves include an allowance to account for the fact that pressure is measured in the pressurizer rather than at the vessel beltline and to account for primary coolant pump discharge pressure. The use of the curves provides operational limits during heatup or cooldown maneuvering, when pressure and temperature indications are monitored and compared to the applicable curve to determine that operation is within the allowable region.

The LCO establishes operating limits that provide a margin to brittle failure of the reactor vessel and piping of the Primary Coolant Pressure Boundary (PCPB). The vessel is the component most subject to brittle failure, and the LCO limits apply to the vessel.

10 CFR 50, Appendix G (Ref. 2), requires the establishment of P/T limits for material fracture toughness requirements of the PCPB materials.

Reference 2 requires an adequate margin to brittle failure during normal operation, anticipated operational occurrences, and system hydrostatic tests.

The neutron embrittlement effect on the material toughness is reflected by increasing the nil ductility reference temperature (RTNDT) as neutron fluence increases.

The actual shift in the RTNDT of the vessel material will be established periodically by removing and evaluating the irradiated reactor vessel material specimens, in accordance with ASTM E 185 (Ref. 4) and Appendix H of 10 CFR 50 (Ref. 5). The operating P/T limit curves will be adjusted, as necessary, based on the evaluation findings and the requirements of 10 CFR 50, Appendix G (Ref. 2).

Palisades Nuclear Plant B 3.4.3-1 Revised 02/17/2012

PCS P/T Limits B 3.4.3 BASES BACKGROUND A discussion of the methodology for the development of the P/T limit (continued) curves is provided in Reference 1 and Reference 7. The P/T limit curves were originally developed to be valid up to an accumulated reactor vessel wall fluence at the limiting circumferential weld of 2.192 x 1019 n/cm 2 (E

>1.0 MeV). It was subsequently determined that this fluence would be reached prior to the operating license expiration date. In order to continue to use the existing P/T limit curves, an evaluation (Ref. 8) using more recently approved NRC methods was performed to demonstrate that the P/T limit curves are valid through the operating license expiration date, equivalent to 42.1 Effective Full Power Years (EFPY). This evaluation was performed using the adjusted RTNDT (ART) corresponding to the limiting beltline region material of the reactor vessel. The ART is defined as the sum of the initial reference temperature (RTNDT) of the material, the mean value for the adjustment in RTNDT caused by neutron irradiation, and a margin term to account for uncertainties in RTNDT, percent nickel, percent copper, neutron fluence and calculational procedures (Ref. 9).

The specific input parameters below were used to validate that the existing P/T limit curves are conservative through an applicability period of 42.1 EFPY. The input parameters are for the limiting reactor vessel material, which are the intermediate and lower shell axial welds 2-112 and 3-112.

2

1. A peak reactor vessel wall surface fluence of 2.161 x 1019 n/cm (E > 1.0 MeV)

2. ART values, at 1/4T = 252.7°F, and at 3/4T = 185.8°F

3. Initial RTNDT = -56 *F

4. Margin term = 65.5 'F The P/T limit curves are composite curves established by superimposing limits derived from stress analyses of those portions of the reactor vessel and head that are the most restrictive. At any specific pressure, temperature, and temperature rate of change, one location within the reactor vessel will dictate the most restrictive limit. Across the span of the P/T limit curves, different locations are more restrictive, and, thus, the curves are composites of the most restrictive regions.

Palisades Nuclear Plant B 3.4.3-2 Revised 02/17/2012

PCS PIT Limits B 3.4.3 BASES BACKGROUND The heatup curve represents a different set of restrictions than the (continued) cooldown curve because the directions of the thermal gradients through the vessel wall are reversed. The thermal gradient reversal may alter the location of the tensile stress between the outer and inner walls.

The minimum temperature at which the reactor can be made critical, as required by Reference 2, shall be at least 40°F above the heatup curve or the cooldown curve and not less than the minimum permissible temperature for the ISLH testing. However, the criticality limit is not operationally limiting; a more restrictive limit exists in LCO 3.4.2, "PCS Minimum Temperature for Criticality," and LCO 3.1.7, "Special Test Exceptions (STE)."

The consequence of violating the LCO limits is that the PCS has been operated under conditions that can result in brittle failure of the PCPB, possibly leading to a nonisolable leak or loss of coolant accident. In the event these limits are exceeded, an evaluation must be performed to determine the effect on the structural integrity of the PCPB components.

The ASME Code,Section XI, Appendix E (Ref. 6), provides a recommended methodology for evaluating an operating event that causes an excursion outside the limits.

APPLICABLE The P/T limits are not derived from Design Basis Accident (DBA)

SAFETY ANALYSES Analyses. They are prescribed during normal operation to avoid encountering pressure, temperature, and temperature rate of change conditions that might cause undetected flaws to propagate and cause nonductile failure of the PCPB, an unanalyzed condition. Reference 1 establishes the methodology for determining the P/T limits. Since the P/T limits are not derived from any DBA, there are no acceptance limits related to the P/T limits. Rather, the P/T limits are acceptance limits themselves since they preclude operation in an unanalyzed condition.

The PCS P/T limits satisfy Criterion 2 of 10 CFR 50.36(c)(2).

Palisades Nuclear Plant B 3.4.3-3 Revised 02/17/2012

PCS P/T Limits B 3.4.3 BASES LCO The two elements of this LCO are:

a. The limit curves for heatup, cooldown, and ISLH testing; and

b. Limits on the rate of change of temperature.

The LCO limits apply to all components of the PCS, except the pressurizer.

These limits define allowable operating regions and permit a large number of operating cycles while providing a wide margin to nonductile failure.

The limits for the rate of change of temperature control the thermal gradient through the vessel wall and are used as inputs for calculating the heatup, cooldown, and ISLH testing P/T limit curves. Additional cooldown rate restrictions were put in place due to the reactor vessel head nozzle repairs per Reference 7. Thus, the LCO for the rate of change of temperature restricts stresses caused by thermal gradients and also ensures the validity of the P/T limit curves.

Violating the LCO limits places the reactor vessel outside of the bounds of the stress analyses and can increase stresses in other PCPB components. The consequences depend on several factors, as follows:

a. The severity of the departure from the allowable operating P/T regime or the severity of the rate of change of temperature;

b. The length of time the limits were violated (longer violations allow the temperature gradient in the thick vessel walls to become more pronounced); and

c. The existences, sizes, and orientations of flaws in the vessel material.

APPLICABILITY The PCS P/T limits Specification provides a definition of acceptable operation for prevention of nonductile failure in accordance with 10 CFR 50, Appendix G (Ref. 2) and due to the reactor vessel nozzle repairs (Ref. 7). Although the P/T limits were developed to provide guidance for operation during heatup or cooldown (MODES 3, 4, and 5) or ISLH testing, their Applicability is at all times in keeping with the concern for nonductile failure. The additional cooldown rate restrictions for the reactor vessel nozzle repairs only apply when the reactor vessel head is on the reactor vessel. The limits do not apply to the pressurizer.

Palisades Nuclear Plant B 3.4.3-4 Revised 02/17/2012

PCS P/T Limits B 3.4.3 BASES APPLICABILITY During MODES 1 and 2, other Technical Specifications provide limits (continued) for operation that can be more restrictive than or can supplement these P/T limits. LCO 3.4.1, "PCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits"; LCO 3.4.2, "PCS Minimum Temperature for Criticality"; and Safety Limit 2.1, "Safety Limits," also provide operational restrictions for pressure and temperature and maximum pressure. Furthermore, MODES 1 and 2 are above the temperature range of concern for nonductile failure, and stress analyses have been performed for normal maneuvering profiles, such as power ascension or descent.

The actions of this LCO consider the premise that a violation of the limits occurred during normal plant maneuvering. Severe violations caused by abnormal transients, at times accompanied by equipment failures, may also require additional actions from emergency operating procedures.

ACTIONS A.1 and A.2 Operation outside the P/T limits must be corrected so that the PCPB is returned to a condition that has been verified by stress analyses.

The 30 minute Completion Time reflects the urgency of restoring the parameters to within the analyzed range. Most violations will not be severe, and the activity can be accomplished in this time in a controlled manner.

Besides restoring operation to within limits, an evaluation is required to determine if PCS operation can continue. The evaluation must verify the PCPB integrity remains acceptable and must be completed before continuing operation. Several methods may, be used, including comparison with pre-analyzed transients in the stress analyses, new analyses, or inspection of the components.

ASME Code,Section XI, Appendix E (Ref. 6), may be used to support the evaluation. However, its use is restricted to evaluation of the vessel beltline.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable to accomplish the evaluation.

The evaluation for a mild violation is possible within this time, but more severe violations may require special, event specific stress analyses or inspections. A favorable evaluation must be! completed before continuing to operate.

Palisades Nuclear Plant B 3.4.3-5 Revised 02/17/2012

PCS P/T Limits B 3.4.3 BASES ACTIONS A.1 and A.2 (continued)

Condition A is modified by a Note requiring Required Action A.2 to be completed whenever the Condition is entered. The Note emphasizes the need to perform the evaluation of the effects of the excursion outside the allowable limits. Restoration alone per Required Action A.1 is insufficient because higher than analyzed stresses may have occurred and may have affected the PCPB integrity.

B.1 and B.2 If a Required Action and associated Completion Time of Condition A are not met, the plant must be placed in a lower MODE because:

a. The PCS remained in an unacceptable P/T region for an extended period of increased stress; or

b. A sufficiently severe event caused entry into an unacceptable region.

Either possibility indicates a need for more careful examination of the event, best accomplished with the PCS at reduced pressure and temperature. With reduced pressure and temperature conditions, the possibility of propagation of undetected flaws is generally decreased.

Pressure and temperature are reduced by placing the plant in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in MODE 5 with PCS pressure < 270 psia within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

The Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Palisades Nuclear Plant B 3.4.3-6 Revised 02/17/2012

PCS P/T Limits B 3.4.3 BASES ACTIONS C.1 and C.2 (continued)

The actions of this LCO, anytime other than in MODE 1, 2, 3, or 4, consider the premise that a violation of the limits occurred during normal plant maneuvering. Severe violations caused by abnormal transients, at times accompanied by equipment failures, may also require additional actions from emergency operating procedures. Operation outside the P/T limits must be corrected so that the PCPB is returned to a condition that has been verified by stress analyses.

The Completion Time of "immediately" reflects the urgency of restoring the parameters to within the analyzed range. Most violations will not be severe, and the activity can be accomplished in a short period of time in a controlled manner.

Besides restoring operation to within limits, an evaluation is required to determine if PCS operation can continue. The evaluation must verify that the PCPB integrity remains acceptable and must be completed before continuing operation. Several methods may be used, including comparison with pre-analyzed transients in the stress analyses, new analyses, or inspection of the components.

ASME Code,Section XI, Appendix E (Ref. 6), may be used to support the evaluation. However, its use is restricted to evaluation of the vessel beltline.

The Completion Time of prior to entering MODE 4 forces the evaluation prior to entering a MODE where temperature and pressure can be significantly increased. The evaluation for a mild violation is possible within several days, but more severe violations may require special, event specific stress analyses or inspections.

Condition C is modified by a Note requiring Required Action C.2 to be completed whenever the Condition is entered. The Note emphasizes the need to perform the evaluation of the effects of the excursion outside the allowable limits. Restoration alone per Required Action C.1 is insufficient because higher than analyzed stresses may, have occurred and may have affected the PCPB integrity.

Palisades Nuclear Plant B 3.4.3-7 Revised 02/17/2012

PCS P/T Limits B 3.4.3 BASES SURVEILLANCE SR 3.4.3.1 REQUIREMENTS Verification that operation is within the limits of Figure 3.4.3-1 and Figure 3.4.3-2 is required every 30 minutes when PCS pressure and temperature conditions are undergoing planned changes. This Frequency is considered reasonable in view of the control room indication available to monitor PCS status. Also, since temperature rate of change limits are specified in hourly increments, 30 minutes permits assessment and correction for minor deviations within a reasonable time. Calculation of the average hourly cooldown rate must consider changes in reactor vessel inlet temperature caused by initiating shutdown cooling, by starting primary coolant pumps with a temperature difference between the steam generator and PCS, or by stopping primary coolant pumps with shutdown cooling in service. The additional restrictions in Figure 3.4.3-2, required for the reactor vessel head nozzle repairs, use the average core exit temperature to provide the best indication available of the temperature of the head inside material temperature. This indication may be either the average of the core exit thermocouples or the vessel outlet temperature.

Surveillance for heatup and cooldown operations may be discontinued when the definition given in the relevant plant procedure for ending the activity is satisfied.

This SR is modified by a Note that requires this SR be performed only during PCS heatup and cooldown operations. No SR is given for criticality operations because LCO 3.4.2 contains a more restrictive requirement.

Palisades Nuclear Plant B 3.4.3-8 Revised 02/17/2012

PCS P/T Limits B 3.4.3 BASES REFERENCES 1. Safety Evaluation for Palisades Nuclear Plant License Amendment No. 245, dated January 19, 2012

2. 10 CFR 50, Appendix G

3. Deleted

4. ASTM E 185-82, July 1982

5. 10 CFR 50, Appendix H

6. ASME, Boiler and Pressure Vessel Code,Section XI, Appendix E

7. Safety Evaluation for Palisades Nuclear Plant License Amendment No. 218, dated November 8, 2004

8. Engineering Analysis EA-EC27959-01, "Palisades Pressure-Temperature Limit Curves and Upper-Shelf Energy Evaluation,"

February 2012

9. Regulatory Guide 1.99, Revision 2, May 1988 Palisades Nuclear Plant B 3.4.3-9 Revised 02/17/2012

LTOP System B 3.4.12 B 3.4 PRIMARY COOLANT SYSTEM (PCS)

B 3.4.12 Low Temperature Overpressure Protection (LTOP) System BASES BACKGROUND The LTOP System controls PCS pressure at low temperatures so the integrity of the Primary Coolant Pressure Boundary (PCPB) is not compromised by violating the Pressure and Temperature (P/T) limits of 10 CFR 50, Appendix G (Ref. 1). The reactor vessel is the limiting PCPB component requiring such protection. LCO 3.4.3, "PCS Pressure and Temperature (P/T) Limits," provides the allowable combinations for operational pressure and temperature during cooldown, shutdown, and heatup to keep from violating the Reference 1 requirements during the LTOP MODES.

The toughness of the reactor vessel material decreases at low temperatures. As the vessel neutron exposure accumulates, the material toughness decreases and becomes less resistant to pressure stress at low temperatures (Ref. 2). PCS pressure, therefore, is maintained low at low temperatures and is increased only as temperature is increased.

The potential for vessel overpressurization is most acute when the PCS is water solid, which occurs only while shutdown. Under that condition, a pressure fluctuation can occur more quickly than an operator can react to relieve the condition. Exceeding the PCS P/T limits by a significant amount could cause brittle fracture of the reactor vessel. LCO 3.4.3 requires administrative control of PCS pressure and temperature during heatup and cooldown to prevent exceeding the P/T limits.

This LCO provides PCS overpressure protection by limiting coolant injection capability and requiring adequate pressure relief capacity.

Limiting coolant injection capability requires all High Pressure Safety Injection (HPSI) pumps be incapable of injection into the PCS when any PCS cold leg temperature is < 300 0 F. The pressure relief capacity requires either two OPERABLE redundant Power Operated Relief Valves (PORVs) or the PCS depressurized and a PCS vent of sufficient size.

One PORV or the PCS vent is the overpressure protection device that acts to terminate an increasing pressure event.

Revised 02/17/2012 Plant Nuclear Plant Palisades Nuclear B 3.4.12-1 B 3.4.12-1 Revised 02/17/2012

LTOP System B 3.4.12 BASES BACKGROUND With limited coolant injection capability, the ability to provide core (continued) coolant addition is restricted. The LCO does not require the chemical and volume control system to be deactivated or the Safety Injection Signals (SIS) blocked. Due to the lower pressures in the LTOP MODES and the expected core decay heat levels, the chemical and volume control system can provide adequate flow via the makeup control valve. If conditions require the use of an HPSI pump for makeup in the event of loss of inventory, then a pump can be made available through manual actions.

The LTOP System for pressure relief consists of two PORVs with temperature dependent lift settings or a PCS vent of sufficient size.

Two PORVs are required for redundancy. One PORV has adequate relieving capability to prevent overpressurization for the allowed coolant injection capability.

PORV Requirements As designed for the LTOP System, an "open" signal is generated for each PORV if the PCS pressure approaches a limit determined by the LTOP actuation logic. The actuation logic monitors PCS pressure and cold leg temperature to determine when the LTOP overpressure setting is approached. If the indicated pressure meets or exceeds the calculated value, a PORV is opened.

The LCO presents the PORV setpoints for LTOP by specifying Figure 3.4.12-1, "LTOP Setpoint Limit." Having the setpoints of both valves within the limits of the LCO ensures the P/T limits will not be exceeded in any analyzed event.

When a PORV is opened in an increasing pressure transient, the release of coolant causes the pressure increase to slow and reverse. As the PORV releases coolant, the system pressure decreases until a reset pressure is reached and the valve closed. The pressure continues to decrease below the reset pressure as the valve closes.

Palisades Nuclear Plant B 3.4.12-2 Revised 02/17/2012

LTOP System B 3.4.12 BASES BACKGROUND PCS Vent Requirements (continued)

Once the PCS is depressurized, a vent exposed to the containment atmosphere will maintain the PCS at containment ambient pressure in an PCS overpressure transient if the relieving requirements of the transient do not exceed the capabilities of the vent. Thus, the vent path must be capable of relieving the flow resulting from the limiting LTOP mass injection or heatup transient and maintaining pressure below the P/T limits. The required vent capacity may be provided by one or more vent paths.

Reference 3 has determined that any vent path capable of relieving 167 gpm at a PCS pressure of 315 psia is acceptable. The 167 gpm flow rate is based on an assumed charging imbalance due to interruption of letdown flow with three charging pumps operating, a 40'F per hour PCS heatup rate, a 60°F per hour pressurizer heatup rate, and an initially depressurized and vented PCS. Neither HPSI pump nor Primary Coolant Pump (PCP) starts need to be assumed with the PCS initially depressurized, because LCO 3.4.12 requires both HPSI pumps to be incapable of injection into the PCS and LCO 3.4.7, "PCS Loops-MODE 5, Loops Filled," places restrictions on starting a PCP.

The pressure relieving ability of a vent path depends not only upon the area of the vent opening, but also upon the configuration of the piping connecting the vent opening to the PCS. A long, or restrictive piping connection may prevent a larger vent opening from providing adequate flow, while a smaller opening immediately adjacent to the PCS could be adequate. The areas of multiple vent paths cannot simply be added to determine the necessary vent area.

The following vent path examples are acceptable:

1. Removal of a steam generator primary manway;

2. Removal of the pressurizer manway;

3. Removal of a PORV or pressurizer safety valve;

4. Both PORVs and associated block valves open; and

5. Opening of both PCS vent valves MV-PC514 and MV-PC515.

Plant B 3.4.12-3 Revised 02/17/2012 Palisades Nuclear Palisades Nuclear Plant B 3.4.12-3 Revised 02/17/2012

LTOP System B 3.4.12 BASES BACKGROUND Reference 4 determined that venting the PCS through MV-PC514 and (continued) MV-PC515 provided adequate flow area. The other listed examples provide greater flow areas with less piping restriction and are therefore acceptable. Other vent paths shown to provide adequate capacity could also be used. The vent path(s) must be above the level of reactor coolant, to prevent draining the PCS.

One open PORV provides sufficient flow area to prevent excessive PCS pressure. However, if the PORVs are elected as the vent path, both valves must be used to meet the single failure criterion, since the PORVs are held open against spring pressure by energizing the operating solenoid.

When the shutdown cooling system is in service with MO-3015 and MO-3016 open, additional overpressure protection is provided by the relief valves on the shutdown cooling system. References 5 and 6 show that this relief capacity will prevent the PCS pressure from exceeding its pressure limits during any of the above mentioned events.

APPLICABLE Safety analyses (Ref. 7) demonstrate that the reactor vessel is Safety Analyses adequately protected against exceeding the Reference 1 PIT limits during shutdown. In MODES 1 and 2, and in MODE 3 with all PCS cold leg temperature at or exceeding 430 0 F, the pressurizer safety valves prevent PCS pressure from exceeding the Reference 1 limits. Below 430'F, overpressure prevention falls to the OPERABLE PORVs or to a depressurized PCS and a sufficiently sized PCS vent. Each of these means has a limited overpressure relief capability.

The actual temperature at which the pressure in the P/T limit curve falls below the pressurizer safety valve setpoint increases as the reactor vessel material toughness decreases due to neutron embrittlement. Each time the P/T limit curves are revised, the LTOP System should be re-evaluated to ensure its functional requirements can still be satisfied using the PORV method or the depressurized and vented PCS condition.

Reference 3 contains the acceptance limits that satisfy the LTOP requirements. When originally generated, the validity period for the LTOP Setpoint Limit curve in Figure 3.4.12-1, which is based on the Reference 3 analysis, ended prior to the operating license expiration date. A subsequent analysis was performed (Ref. 9) which demonstrated that the current LTOP Setpoint Limit curve is valid through the operating license expiration date, equivalent to 42.1 effective full power years of operation.

Any change to the PCS must be evaluated against these analyses to determine the impact of the change on the LTOP acceptance limits.

Palisades Nuclear Plant B 3.4.12-4 Revised 02/17/2012

LTOP System B 3.4.12 BASES APPLICABLE Transients that are capable of overpressurizing the PCS are Safety Analyses categorized as either mass injection or heatup transients (continued)

Mass Iniection Type Transients

a. Inadvertent safety injection; or

b. Charging/letdown flow mismatch.

Heatup Tvoe Transients

a. Inadvertent actuation of pressurizer heaters;

b. Loss of Shutdown Cooling (SDC); or

c. PCP startup with temperature asymmetry within the PCS or between the PCS and steam generators.

Rendering both HPSI pumps incapable of injection is required during the LTOP MODES to ensure that mass injection transients beyond the capability of the LTOP overpressure protection system, do not occur. The Reference 3 analyses demonstrate that either one PORV or the PCS vent can maintain PCS pressure below limits when three charging pump are actuated. Thus, the LCO prohibits the operation of both HPSI pumps and does not place any restrictions on charging pump operation.

Fracture mechanics analyses were used to establish the applicable temperature range for the LTOP LCO as below 4301F. At and above this temperature, the pressurizer safety valves provide the reactor vessel pressure protection. The pressure-temperature limit curves and LTOP curve are based on reactor vessel material properties which change over time due to radiation embrittlement. These curves are valid for the period of time corresponding to the reactor vessel material condition which was assumed when the curves were generated. At the time the curves were developed, they were based on being valid up to a neutron irradiation accumulation equal to 2.192 x 1019 n (neutrons)/cm 2 (Ref. 3). The vessel materials in the current curve analysis (Ref. 9) were assumed to have a neutron irradiation accumulation equal to 42.1 effective full power years of operation. The current analysis determined an LTOP enable temperature that is bounded by the LTOP LCO.

Palisades Nuclear Plant B 3.4.12-5 Revised 02/17/2012

LTOP System B 3.4.12 BASES APPLICABLE PORV Performance Safety Analyses (continued) The fracture mechanics analyses show that the vessel is protected when the PORVs are set to open at or below the setpoint curve specified in Figure 3.4.12-1 of the accompanying LCO. The setpoint is derived by modeling the performance of the LTOP System, assuming the limiting allowed LTOP transient. The valve qualification process considered pressure overshoot and undershoot beyond the PORV opening and closing setpoints, resulting from signal processing and valve stroke times.

The PORV setpoints at or below the derived limit ensure the Reference 1 limits will be met.

The PORV setpoints will be re-evaluated for compliance when the P/T limits are revised. The P/T limits are periodically modified as the reactor vessel materialtoughness decreases due to embrittlement caused by neutron irradiation. Revised P/T limits are determined using neutron fluence projections and the results of examinations of the reactor vessel material irradiation surveillance specimens. The Bases for LCO 3.4.3 discuss these examinations.

The PORVs are considered active components. Thus, the failure of one PORV represents the worst case, single active failure.

PCS Vent Performance With the PCS depressurized, analyses show the required vent size is capable of mitigating the limiting allowed LTOP overpressure transient. In that event, this size vent maintains PCS pressure less than the maximum PCS pressure on the P/T limit curve.

The PCS vent is passive and is not subject to active failure.

LTOP System satisfies Criterion 2 of 10 CFR 50.36(c)(2).

Palisades Nuclear Plant B 3.4.12-6 Revised 02/17/2012

LTOP System B 3.4.12 BASES LCO This LCO is required to ensure that the LTOP System is OPERABLE.

The LTOP System is OPERABLE when both HPSI pumps are incapable of injecting into the PCS and pressure relief capabilities are OPERABLE.

Violation of this LCO could lead to the loss of low temperature overpressure mitigation and violation of the Reference 1 limits as a result of an operational transient.

To limit the coolant injection capability, LCO 3.4.12.a requires both HPSI pumps be incapable of injecting into the PCS. LCO 3.4.12.a is modified by two Notes. Note 1 only requires both HPSI pumps to be incapable of injecting into the PCS when any PCS cold leg temperature is < 300'F.

When all PCS cold leg temperatures are __300°F, a start of both HPSI pumps in conjunction with a charging/letdown imbalance will not cause the PCS pressure to exceed the 10 CFR 50 Appendix G limits. Thus, a restriction on HPSI pump operation when all PCS cold leg temperatures are > 300OF is not required. Note 2 is provided to assure that this LCO does not cause hesitation in the use of a HPSI pump for PCS makeup if it is needed due to a loss of shutdown cooling or a loss of PCS inventory.

The elements of the LCO that provide overpressure mitigation through pressure relief are:

a. Two OPERABLE PORVs; or

b. The PCS depressurized and vented.

A PORV is OPERABLE for LTOP when its block valve is open, its lift setpoint is set consistent with Figure 3.4.12-1 in the accompanying LCO and testing has proven its ability to open at that setpoint, and motive power is available to the valve and its control circuit.

A PCS vent is OPERABLE when open with an area capable of relieving

? 167 gpm at a PCS pressure of 315 psia.

Each of these methods of overpressure prevention is capable of mitigating the limiting LTOP transient.

Palisades Nuclear Plant B 3.4.12-7 Revised 02/17/2012

LTOP System B 3.4.12 BASES APPLICABILITY This LCO is applicable in MODE 3 when the temperature of any PCS cold leg is < 4300 F, in MODES 4 and 5, and in MODE 6 when the reactor vessel head is on. The pressurizer safety valves provide overpressure protection that meets the Reference 1 P/T limits at and above 430'F.

When the reactor vessel head is off, overpressurization cannot occur.

LCO 3.4.3 provides the operational P/T limits for all MODES.

LCO 3.4.10, "Pressurizer Safety Valves," requires the OPERABILITY of the pressurizer safety valves that provide overpressure protection during MODES 1 and 2, and MODE 3 with all PCS cold leg temperatures

> 430 0 F.

Low temperature overpressure prevention is most critical during shutdown when the PCS is water solid, and a mass addition or a heatup transient can cause a very rapid increase in PCS pressure with little or no time available for operator action to mitigate the event.

ACTIONS A Note prohibits the application of LCO 3.0.4.b to inoperable PORVs used for LTOP. There is an increased risk associated with entering MODE 4 from MODE 5 with PORVs used for LTOP inoperable and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

A. 1 With one or two HPSI pumps capable of injecting into the PCS, overpressurization is possible.

The immediate Completion Time to initiate actions to restore restricted coolant injection capability to the PCS reflects the importance of maintaining overpressure protection of the PCS.

Palisades Nuclear Plant B 3.4.12-8 Revised 02/17/2012

LTOP System B 3.4.12 BASES ACTIONS B.1 (continued)

With one required PORV inoperable and pressurizer water level < 57%,

the required PORV must be restored to OPERABLE status within a Completion Time of 7 days. Two valves are required to meet the LCO requirement and to provide low temperature overpressure mitigation while withstanding a single failure of an active component.

The Completion Time is based on only one PORV being required to mitigate an overpressure transient, the likelihood of an active failure of the remaining valve path during this time period being very low, and that a steam bubble exists in the pressurizer. Since the pressure response to a transient is greater if the pressurizer steam space is small or if the PCS is solid, the Completion Time for restoration of a PORV flow path to service is shorter. The maximum pressurizer level at which credit can be taken for having a bubble (57%, which provides about 700 cubic feet of steam space) is based on judgment rather than by analysis. This level provides the same steam volume to dampen pressure transients as would be available at full power. This steam volume provides time for operator action (if the PORVs failed to operate) in the interval between an inadvertent SIS and PCS pressure reaching the 10 CFR 50, Appendix G pressure limit. The time available for action would depend upon the existing pressure and temperature when the inadvertent SIS occurred.

C.1 The consequences of operational events that will overpressurize the PCS are more severe at lower temperature (Ref. 8). With the pressurizer water level > 57%, less steam volume is available to dampen pressure increases resulting from an inadvertent mass injection or heatup transients. Thus, with one required PORV inoperable and the pressurizer water level > 57%, the Completion Time to restore the required PORV to OPERABLE status is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time to restore the required PORV to OPERABLE status when the pressurizer water level is > 57%, which usually occurs in MODE 5 or in MODE 6 when the vessel head is on, is a reasonable amount of time to investigate and repair PORV failures without a lengthy period with only one PORV OPERABLE to protect against overpressure events.

Palisades Nuclear Plant B 3.4.12-9 Revised 02/17/2012

LTOP System B 3.4.12 BASES ACTIONS D.1 (continued)

If two required PORVs are inoperable, or if the Required Actions and the associated Completion Times are not met, or ifthe LTOP System is inoperable for any reason other than Condition A, B, or C, the PCS must be depressurized and a vent established within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The vent must be sized to provide a relieving capability of :> 167 gpm at a pressure of 315 psia which ensures the flow capacity is greater than that required for the worst case mass injection transient reasonable during the applicable MODES. This action protects the PCPB from a low temperature overpressure event and a possible brittle failure of the reactor vessel.

The Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to depressurize and vent the PCS is based on the time required to place the plant in this condition and the relatively low probability of an overpressure event during this time period due to operator attention and administrative requirements.

SURVEILLANCE SR 3.4.12.1 REQUIREMENTS To minimize the potential for a low temperature overpressure event by limiting the mass injection capability, both HPSI pumps are verified to be incapable of injecting into the PCS. The HPSI pumps are rendered incapable of injecting into the PCS by means that assure that a single event cannot cause overpressurization of the PCS due to operation of the pump. Typical methods for accomplishing this are by pulling the HPSI pump breaker control power fuses, racking out the HPSI pump motor circuit breaker, or closing the manual discharge valve.

SR 3.4.12.1 is modified by a Note which only requires the SR to be met when complying with LCO 3.4.12.a. When all PCS cold leg temperature are _>300 0 F, a start of both HPSI pumps in conjunction with a charging/letdown imbalance will not cause the PCS pressure to exceed the 10 CFR 50 Appendix G limits. Thus, this SR is only required when any PCS cold leg temperature is reduced to less than 300 0 F.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months interval considers operating practice to regularly assess potential degradation and to verify operation within the safety analysis.

Palisades Nuclear Plant B 3.4.12-10 Revised 02/17/2012

LTOP System B 3.4.12 BASES SURVEILLANCE SR 3.4.12.2 REQUIREMENTS (continued) SR 3.4.12.2 requires a verification that the required PCS vent, capable of relieving __167 gpm at a PCS pressure of 315 psia, is OPERABLE by verifying its open condition either:

a. Once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for a valve that is not locked open; or

b. Once every 31 days for a valve that is locked open.

The passive vent arrangement must only be open to be OPERABLE.

This Surveillance need only be performed if vent valves are being used to satisfy the requirements of this LCO. This Surveillance does not need to be performed for vent paths relying on the removal of a steam generator primary manway cover, pressurizer manway cover, safety valve or PORV since their position is adequately addressed using administrative controls and the inadvertent reinstallation of these components is unlikely. The Frequencies consider operating experience with mispositioning of unlocked and locked vent valves, respectively.

SR 3.4.12.3 The PORV block valve must be verified open every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to provide the flow path for each required PORV to perform its function when actuated. The valve can be remotely verified open in the main control room.

The block valve is a remotely controlled, motor operated valve. The power to the valve motor operator is not required to be removed, and the manual actuator is not required locked in the inactive position. Thus, the block valve can be closed in the event the PORV develops excessive leakage or does not close (sticks open) after relieving an overpressure event.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency considers operating experience with accidental movement of valves having remote control and position indication capabilities available where easily monitored. These considerations include the administrative controls over main control room access and equipment control.

Palisades Nuclear Plant B 3.4.12-11 Revised 02/17/2012

LTOP System B 3.4.12 BASES SURVEILLANCE SR 3.4.12.4 REQUIREMENTS (continued) Performance of a CHANNEL FUNCTIONAL. TEST is required every 31 days. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay This is acceptable because all of the Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. PORV actuation could depressurize the PCS and is not required. The 31 day Frequency considers experience with equipment reliability.

A Note has been added indicating this SR is required to be performed 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after decreasing any PCS cold leg temperature to < 430'F. This Note allows a discrete period of time to perform the required test without delaying entry into the MODE of Applicability for LTOP. This option may be exercised in cases where an unplanned shutdown below 430'F is necessary as a result of a Required Action specifying a plant shutdown, or other plant evolutions requiring an expedited cooldown of the plant.

The test must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering the LTOP MODES.

SR 3.4.12.5 Performance of a CHANNEL CALIBRATION on each required PORV actuation channel is required every 18 months to adjust the entire channel so that it responds and the valve opens within the required LTOP range and with accuracy to known input.

The 18 month Frequency considers operating experience with equipment reliability and is consistent with the typical refueling outage schedule.

Palisades Nuclear Plant B 3.4.12-12 Revised 02/17/2012

LTOP System B 3.4.12 BASES REFERENCES 1. 10 CFR 50, Appendix G

2. Generic Letter 88-11

3. CPC Engineering Analysis, EA-A-PAL-92-095-01

4. CPC Engineering Analysis, EA-TCD-90-01

5. CPC Engineering Analysis, EA-E-PAL-89-040-1

6. CPC Corrective Action Document, A-PAL-91-011

7. FSAR, Section 7.4

8. Generic Letter 90-06

9. Engineering Analysis EA-EC27959-01, "Palisades Pressure-Temperature Limit Curves and Upper-Shelf Energy Evaluation,"

February 2012 Palisades Nuclear Plant B 3.4.12-13 Revised 02/17/2012

Containment B 3.6.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.1 Containment BASES BACKGROUND The containment consists of a concrete structure lined with steel plate, and the penetrations through this structure. The structure is designed to contain fission products that may be released from the reactor core following a design basis Loss of Coolant Accident (LOCA). Additionally, this structure provides shielding from the fission products that may be present in the containment atmosphere following accident conditions.

The containment is a reinforced concrete structure with a cylindrical wall, a flat foundation mat, and a shallow dome roof. The foundation slab is reinforced with conventional mild-steel reinforcing. The internal pressure loads on the base slab are resisted by both the external soil pressure and the strength of the reinforced concrete slab. The cylinder wall is prestressed with a post tensioning system in the vertical and horizontal directions. The dome roof is prestressed utilizing a three-way post tensioning system. The inside surface of the containment is lined with a carbon steel liner to ensure a high degree of leak tightness during operating and accident conditions.

The concrete structure is required for structural integrity of the containment under Design Basis Accident (DBA) conditions. The steel liner and its penetrations establish the leakage limiting boundary of the containment. Maintaining the containment OPERABLE limits the leakage of fission product radioactivity from the containment to the environment. SR 3.6.1.1 leakage rate requirements comply with 10 CFR 50, Appendix J, Option B (Ref. 4) as modified by approved exemptions.

The isolation devices for containment penetrations are a part of the containment leak tight boundary. To maintain this leak tight boundary:

a. All penetrations required to be closed during accident conditions are either:

1. capable of being closed by an OPERABLE automatic containment isolation system, or

2. closed by manual valves, blind flanges, or de-activated automatic valves secured in their closed positions, except as provided in LCO 3.6.3, "Containment Isolation Valves";

Palisades Nuclear Plant B3.6.1 -1 Revised 3/15/2012

Containment B 3.6.1 BASES BACKGROUND b. Each air lock is OPERABLE, except as provided in LCO 3.6.2, (continued) "Containment Air Locks";

c. The equipment hatch is properly closed and sealed.

APPLICABLE The safety design basis for the containment is that the containment SAFETY ANALYSES must withstand the pressures and temperatures of the limiting DBA without exceeding the design leakage rate.

A Loss of Coolant Accident (LOCA) and a control rod ejection accident are the two DBAs that are analyzed for release of fission products within containment (Ref. 1). In the analysis of each of these accidents, it is assumed that containment is OPERABLE such that release of fission products to the environment is controlled by the rate of containment leakage. The containment was designed with an allowable leakage rate of 0.10% of containment air weight per day at a design pressure of 55 psig and a design temperature of 283oF (Ref. 3).

Satisfactory leakage rate test results are a requirement for the establishment of containment OPERABILITY.

The containment satisfies Criterion 3 of 10 CFR 50.36(c)(2).

LCO Containment OPERABILITY is maintained by limiting leakage to

< 1.0 La, except prior to the first startup after performing a required Containment Leak Rate Testing Program leakage test. At this time, the applicable leakage limits must be met.

Technical Specification ADMIN 5.5.14 defines La as the maximum allowable leakage rate at pressure Pa. The Pa value of 54.2 psig represents the analytical value for a large break LOCA found in Reference 1.

Compliance with this LCO will ensure a containment configuration, including the equipment hatch, that is structurally sound and that will limit leakage to those leakage rates assumed in the safety analysis.

Palisades Nuclear Plant B3.6.1-2 Revised 3/15/2012

Containment B 3.6.1 BASES LCO Individual leakage rates that may be specified for the containment air (continued) lock (LCO 3.6.2) and purge valves which have resilient seals (LCO 3.6.3) are not specifically part of the acceptance criteria of 10 CFR 50, Appendix J. Therefore, leakage rates exceeding these individual limits only result in the containment being inoperable when the leakage results in exceeding the overall acceptance criteria of 1.0 La.

APPLICABILITY In MODES 1,2, 3, and 4, a DBA could cause a release of fission products into containment. In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, containment is not required to be OPERABLE in MODE 5 to prevent leakage of fission products from containment. The requirements for containment during MODE 6 are addressed in LCO 3.9.3, "Containment Penetrations."'

ACTIONS A.1 In the event containment is inoperable, containment must be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining containment OPERABILITY during MODES 1, 2, 3, and 4. This time period also ensures that the probability of an accident (requiring containment OPERABILITY) occurring, during periods when containment is inoperable, is minimal.

B.1 and B.2 If containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Palisades Nuclear Plant B3.6.1-3 Revised 3/15/2012

Containment B 3.6.1 BASES SURVEILLANCE SR 3.6.1.1 REQUIREMENTS Maintaining the containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Containment Leak Rate Testing Program. Failure to meet individual air lock and containment isolation valve "local leak rate" leakage limits does not invalidate the acceptability of the overall leakage determination unless their contribution to overall Type A, B, or C leakage causes that leakage to exceed limits. As left leakage prior to the first startup after performing a required Containment Leak Rate Testing Program leakage test is required to be < 0.6 La for combined B and C leakage, and

< 0.75 La for overall Type A leakage. At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of _ 1.0 La. At < 1.0 La the offsite dose consequences are bounded by the assumptions of the safety analysis.

SR Frequencies are as required by the Containment Leak Rate Testing Program. These periodic testing requirements verify that the containment leakage rate does not exceed the leakage rate assumed in the safety analysis.

SR 3.6.1.2 This SR ensures that the structural integrity of the containment will be maintained in accordance with the provisions of the Containment Structural Integrity Surveillance Program.

REFERENCES 1. FSAR, Chapter 14

2. FSAR, Section 14.18

3. FSAR, Section 5.8

4. 10 CFR 50, Appendix J, Option B Palisades Nuclear Plant B 3.6.1-4 Revised 03/15/2012

Containment Air Locks B 3.6.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.2 Containment Air Locks BASES BACKGROUND Containment air locks form part of the containment pressure boundary and provide a means for personnel access during all MODES of operation.

Two air locks provide access into the containment. Each air lock is nominally a right circular cylinder, with a door at each end. The personnel air lock doors are 3 foot, 6 inches by 6 foot, 8 inches. The emergency escape air lock doors are 30 inches in diameter. The doors are interlocked to prevent simultaneous opening. During periods when containment is not required to be OPERABLE, the door interlock mechanism may be disabled, allowing both doors of an air lock to remain open for extended periods when frequent containment entry is necessary.

Each air lock door has been designed and tested to certify its ability to withstand a pressure in excess of the maximum expected pressure following a Design Basis Accident (DBA) in containment. As such, closure of a single door supports containment OPERABILITY. Each of the doors contains double gasketed seals and local testing capability to ensure pressure integrity. To effect a leak tight seal, the air lock design uses pressure seated doors (i.e., an increase in containment internal pressure results in increased sealing force on each door).

Air lock integrity and leak tightness are essential for maintaining the containment leakage rate within limit in the event of a DBA. Not maintaining air lock integrity or leak tightness may result in a leakage rate in excess of that assumed in the plant safety analysis.

Palisades Nuclear Plant B 3.6.2-1 Revised 03/15/2012

Containment Air Locks B 3.6.2 BASES APPLICABLE A Loss of Coolant Accident (LOCA) and a control rod ejection accident SAFETY ANALYSES are the two DBAs that are analyzed for release of fission products within containment (Ref. 1). In the analysis of each of these accidents, it is assumed that containment is OPERABLE such that release of fission products to the environment is controlled by the rate of containment leakage. The containment was designed with an allowable leakage rate of 0.10% of containment air weight per day at a design pressure of 55 psig and a design temperature of 283°F (Ref. 2). This allowable leakage rate forms the basis for the acceptance criteria imposed on the SRs associated with the air lock.

The containment air locks satisfy Criterion 3 of 10 CFR 50.36(c)(2).

LCO Each containment air lock forms part of the containment pressure boundary. As part of the containment pressure boundary, the air lock safety function is related to limiting the containment leakage rate to

< 1.0 La. Thus, each air lock's structural integrity and leak tightness are essential to the successful mitigation of such an event.

Technical Specification ADMIN 5.5.14 defines La as the maximum allowable leakage rate at pressure Pa. The Pa value of 54.2 psig represents the analytical value for a large break LOCA found in Reference 1.

Each air lock is required to be OPERABLE. For the air lock to be considered OPERABLE, the air lock interlock mechanism must be OPERABLE, the air lock must be in compliance with the Type B air lock leakage test, and both air lock doors must be OPERABLE. The interlock allows only one air lock door of an air lock to be opened at one time. This provision ensures that a gross breach of containment does not exist when containment is required to be OPERABLE. Closure of a single OPERABLE door in each air lock is sufficient to provide a leak tight barrier following postulated events. Nevertheless, both doors are kept closed when the air lock is not being used for normal entry into or exit from containment. Air lock test connection isolation valves are considered to be part of the associated air lock outer door.

Palisades Nuclear Plant B 3.6.2-2 Revised 03/15/2012

Containment Air Locks B 3.6.2 BASES APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of fission products to containment. In MODES 5 and.6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the containment air locks are not required in MODE 5 to prevent leakage of fission products from containment. The requirements for the containment air locks during MODE 6 are addressed in LCO 3.9.3, "Containment Penetrations."

ACTIONS The ACTIONS are modified by three notes. The first note allows entry and exit to perform repairs on the affected air lock component. If the outer door is inoperable, then it may be easily accessed for most repairs.

It is preferred that the air lock be accessed from inside containment by entering through the other OPERABLE air lock. However, if this is not practicable, or if repairs on either door must be performed from the barrel side of the door then it is permissible to enter the air lock through the OPERABLE door, even if this door has been locked to comply with ACTIONS. This means there is a short time during which the containment boundary is not intact (during access through the OPERABLE door). The ability to open the OPERABLE door, even if it means the containment boundary is temporarily not intact, is acceptable because of the low probability of an event that could pressurize the containment during the short time in which the OPERABLE door is expected to be open. After each entry and exit, the OPERABLE door must be immediately closed. If ALARA conditions permit, entry and exit should be via an OPERABLE air lock.

A second Note has been added to provide clarification that, for this LCO, separate Condition entry is allowed for each air lock. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable air lock. Complying with the Required Actions may allow for continued operation, and a subsequent inoperable air lock is governed by subsequent Condition entry and application of associated Required Actions. A third Note has been included that requires entry into the applicable Conditions and Required Actions of LCO 3.6.1, "Containment," when leakage results in exceeding the overall containment leakage limit.

Revised 03/15/2012 B 3.6.2-3 Palisades Nuclear Plant Palisades Nuclear Plant B 3.6.2-3 Revised 03/15/2012

Containment Air Locks B 3.6.2 BASES ACTIONS A.1, A.2. and A.3 (continued)

With one air lock door inoperable in one or more containment air locks, the OPERABLE door must be verified closed (Required Action A.1) in each affected containment air lock. This ensures that a leak tight containment barrier is maintained by the use of an OPERABLE air lock door. This action must be completed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . This specified time period is consistent with the ACTIONS of LCO 3.6.1, which requires containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

In addition, the affected air lock penetration must be isolated by locking closed an OPERABLE air lock door within the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is considered reasonable for locking the OPERABLE air lock door, considering the OPERABLE door of the affected air lock is being maintained closed.

Required Action A.3 verifies that an air lock with an inoperable door has been isolated by the use of a locked and closed OPERABLE air lock door. This ensures that an acceptable containment leakage barrier is maintained. Required Action A.3 is modified by a Note that applies to air lock doors located in high radiation areas and allows these doors to be verified locked closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of the door, once it has been verified to be in the proper position, is small.

The Completion Time of once per 31 days is based on engineering judgment and is considered adequate in view of the low likelihood of a locked door being mispositioned and other administrative controls. As stated in SR 3.0.2, the 25% extension allowed by SR 3.0.2 may be applied to Required Actions whose Completion Time is stated as "once per..." however, the 25% extension does not apply to the initial performance of a Required Action with a periodic Completion Time that requires performance on a "once per.. ." basis. The 25% extension applies to each performance of the Required Action after the initial performance. Therefore, while Required Action 3.6.2 A.3 must be initially performed within 31 days without any SR 3.0.2 extension, subsequent performances may utilize the 25% SR 3.0.2 extension.

Palisades Nuclear Plant B 3.6.2-4 Revised 03/15/2012

Containment Air Locks B 3.6.2 BASES ACTIONS A.1, A.2, and A.3 (continued)

The Required Actions have been modified by two Notes. Note 1 ensures that only the Required Actions and associated Completion Times of Condition C are required if both doors in the same air lock are inoperable.

With both doors in the same air lock inoperable, an OPERABLE door is not available to be closed. Required Actions C.1 and C.2 are the appropriate remedial actions. The exception provided by Note 1 does not affect tracking the Completion Time from the initial entry into Condition A; only the requirement to comply with the Required Actions.

Note 2 allows use of the air lock for entry and exit for 7 days under administrative controls if both air locks have an inoperable door. This 7 day restriction begins when the second air lock is discovered inoperable. Containment entry may be required to perform Technical Specifications (TS) Surveillances and Required Actions, as well as other activities on equipment inside containment that are required by TS or activities on equipment that support TS-required equipment. This Note is not intended to preclude performing other activities (i.e., non-TS-required activities) if the containment was entered, using the inoperable air lock, to perform an allowed activity listed above. This allowance is acceptable due to the low probability of an event that could pressurize the containment during the short time that the OPERABLE door is expected to be open.

B.1, B.2, and B.3 With an air lock interlock mechanism inoperable in one or more air locks, the Required Actions and associated Completion Times are consistent with those specified in Condition A.

The Required Actions have been modified by two Notes. Note 1 ensures that only the Required Actions and associated Completion Times of Condition C are required if both doors in the same air lock are inoperable.

With both doors in the same air lock inoperable, an OPERABLE door is not available to be closed. Required Actions C.1 and C.2 are the appropriate remedial actions. Note 2 allows entry into and exit from containment under the control of a dedicated individual stationed at the air lock to ensure that only one door is opened at a time (i.e., the individual performs the function of the interlock).

Palisades Nuclear Plant B 3.6.2-5 Revised 03/15/2012

Containment Air Locks B 3.6.2 BASES ACTIONS B.1, B.2, and B.3 (continued)

Required Action B.3 is modified by a Note that applies to air lock doors located in high radiation areas and allows these doors to be verified locked closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of the door, once it has been verified to be in the proper position, is small.

C.1, C.2, and C.3 With one or more air locks inoperable for reasons other than those described in Condition A or B, Required Action C.1 requires action to be initiated immediately to evaluate previous combined leakage rates using current air lock test results. If the overall containment leakage rate exceeds the limits of LCO 3.6.1, the conditions of that LCO must be entered in accordance with Actions Note 3. An evaluation is acceptable since it is overly conservative to immediately declare the containment inoperable if both doors in an air lock have failed a seal test or if the overall air lock leakage is not within limits. In many instances (e.g., only one seal per door has failed), containment remains OPERABLE, yet only 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (per LCO 3.6.1) would be provided to restore the air lock door to OPERABLE status prior to requiring a plant shutdown. In addition, even with both doors failing the seal test, the overall containment leakage rate can still be within limits.

Required Action C.2 requires that one door in the affected containment air lock must be verified to be closed. This action must be completed within the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time. This specified time period is consistent with the ACTIONS of LCO 3.6.1, which requires that containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Additionally, the affected air lock(s) must be restored to OPERABLE status within the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time. The specified time period is considered reasonable for restoring an inoperable air lock to OPERABLE status, assuming that at least one door is maintained closed in each affected air lock.

Palisades Nuclear Plant B 3.6.2-6 Revised 03/15/2012

Containment Air Locks B 3.6.2 BASES ACTIONS D.1 and D.2 (continued)

If the inoperable containment air lock cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.2.1 REQUIREMENTS Maintaining containment air locks OPERABLE requires compliance with the leakage rate test requirements of the Containment Leak Rate Testing Program.

This SR reflects the leakage rate testing requirements with regard to air lock leakage (Type B leakage tests). The acceptance criteria, were established during initial air lock and containment Operability testing.

Subsequent amendments to the Technical Specifications revised the acceptance criteria for overall Type B and C leakage limits and provided new acceptance criteria for the personnel air lock doors and the emergency air lock doors (Ref. 2). The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall containment leakage rate. The Frequency is required by the Containment Leak Rate Testing Program.

The SR has been modified by two Notes. Note 1 states that an inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test. This is considered reasonable since either air lock door is capable of providing a fission product barrier in the event of a DBA. Note 2 has been added to this SR requiring the results to be evaluated against the acceptance criteria of SR 3.6.1.1. This ensures that air lock leakage is properly accounted for in determining the combined Type B and C containment leakage rate.

Palisades Nuclear Plant B 3.6.2-7 Revised 03/15/2012

Containment Air Locks B 3.6.2 BASES SURVEILLANCE SR 3.6.2.2 REQUIREMENTS (continued) The air lock interlock is designed to prevent simultaneous opening of both doors in a single air lock. Since both the inner and outer doors of an air lock are designed to withstand the maximum expected post accident containment pressure, closure of either door will support containment OPERABILITY. Thus, the door interlock feature supports containment OPERABILITY while the air lock is being used for personnel transit into and out of containment. Periodic testing of this interlock demonstrates that the interlock will function as designed and that simultaneous opening of the inner and outer doors will not inadvertently occur. Due to the purely mechanical nature of this interlock, and given that the interlock mechanism is not normally challenged when the airlock is used for entry and exit (procedures require strict adherence to single door opening), this test is only required to be performed every 24 months.

The 24 month Frequency for the interlock is justified based on generic operating experience. The Frequency is based on engineering judgment and is considered adequate given that the interlock is not normally challenged during use of the airlock.

REFERENCES 1. FSAR, Chapter 14

2. FSAR, Section 5.8

3. 10 CFR 50, Appendix J, Option B Palisades Nuclear Plant B 3.6.2-8 Revised 03/15/2012

Containment Pressure B 3.6.4 B 3.6 CONTAINMENT SYSTEMS B 3.6.4 Containment Pressure BASES BACKGROUND The containment pressure is limited during normal operation to preserve the initial conditions assumed in the accident analyses for a Loss of Coolant Accident (LOCA) or Main Steam Line Break (MSLB).

Containment pressure is a process variable that is monitored and controlled. The containment pressure limits are derived from the input conditions used in the containment functional analyses. Should operation occur outside these limits coincident with a Design Basis Accident (DBA),

post accident containment pressures could exceed calculated values.

APPLICABLE Containment internal pressure is an initial condition used in the DBA SAFETY ANALYSES analyses to establish the maximum peak containment internal pressure.

The limiting DBAs considered for determining the maximum containment internal pressure are the LOCA and MSLB. A large break LOCA results in the highest calculated internal containment pressure of 54.2 psig, which is below the internal design pressure of 55 psig. The postulated DBAs are analyzed assuming degraded containment Engineered Safety Feature (ESF) systems (i.e., assuming the limiting single active failure).

See the Bases for 3.6.1, "Containment," for a discussion on containment pressures resulting from a LOCA.

The initial pressure condition used in the containment analysis was 15.7 psia (1.0 psig) in MODES 1 and 2 and 16.2 psia (1.5 psig in MODES 3 and 4). The LCO limits of 1.0 psig in MODES 1 and 2, and 1.5 psig in MODES 3 and 4 ensures that, in the event of an accident, the maximum accident design pressure for containment, 55 psig, is not exceeded.

A higher containment pressure limit is allowed in MODES 3 and 4 where the reactor is not critical and the resulting heat addition to containment in a DBA is lower.

Palisades Nuclear Plant B 3.6.4-1 Revised 03/15/2012

Containment Pressure B 3.6.4 BASES APPLICABLE The external design pressure of the containment shell is 3 psig. This SAFETY ANALYSES value is approximately 0.5 psig greater than the maximum external (continued) pressure that could be developed if the containment were sealed during a period of low barometric pressure and high temperature and, subsequently, the containment atmosphere were cooled with a concurrent major rise in barometric pressure. Vacuum breakers are, therefore, not provided and no minimum containment pressure specification is required.

Containment pressure satisfies Criterion 2 of 10 CFR 50.36(c)(2).

LCO Maintaining containment pressure less than or equal to the LCO upper pressure limit ensures that, in the event of a DBA, the resultant peak containment accident pressure will remain below the containment design pressure. Two limits for containment pressure are provided to reflect the analyses which allow for a higher containment pressure when the reactor is not critical due to less heat input to containment in the event of a DBA.

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment. Since maintaining containment pressure within limits is essential to ensure initial conditions assumed in the accident analysis are maintained, the LCO is applicable in MODES 1, 2, 3, and 4.

In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining containment pressure within the limits of the LCO is not required in MODE 5 or 6.

ACTIONS A.1 When containment pressure is not within the limits of the LCO, containment pressure must be restored to within these limits within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The Required Action is necessary to return operation to within the bounds of the containment analysis. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is consistent with the ACTIONS of LCO 3.6.1, "Containment," which requires that containment be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Palisades Nuclear Plant B 3.6.4-2 Revised 03/15/2012

Containment Pressure B 3.6.4 BASES ACTIONS B.1 and B.2 (continued)

If containment pressure cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.4.1 REQUIREMENTS Verifying that containment pressure is within limits ensures that operation remains within the limits assumed in the accident analyses. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency of this SR was developed after taking into consideration operating experience related to trending of containment pressure variations during the applicable MODES. Furthermore, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal containment pressure condition. The limit of 1.0 psig for MODES 1 and 2, 1.5 psig for MODES 3 and 4 are the actual limits used in the accident analysis and do not account for instrument inaccuracies.

REFERENCES 1. FSAR, Section 14.18 Palisades Nuclear Plant B 3.6.4-3 Revised 03/15/2012

Containment Air Temperature B 3.6.5 B 3.6 CONTAINMENT SYSTEMS B 3.6.5 Containment Air Temperature BASES BACKGROUND The containment structure serves to contain radioactive material that may be released from the reactor core following a Design Basis Accident (DBA). The containment average air temperature is limited during normal operation to preserve the initial conditions assumed in the accident analyses for a Loss of Coolant Accident (LOCA) or Main Steam Line Break (MSLB).

Containment air temperature is a process variable that is monitored and controlled. The containment average air temperature limit is derived from the input conditions used in the containment accident analyses. This LCO ensures that initial conditions assumed in the analysis of containment response to a DBA are not violated during plant operations.

The total amount of energy to be removed from containment by the Containment Spray and Cooling systems during post accident conditions is dependent on the energy released to the containment due to the event, as well as the initial containment temperature and pressure. The higher the initial temperature, the more energy that must be removed, resulting in a higher peak containment pressure and temperature. Exceeding containment design pressure may result in leakage greater than that assumed in the accident analysis (Ref. 1). Operation with containment average air temperature in excess of the LCO limit may result in an initial condition higher than that assumed in the accident analysis.

APPLICABLE Containment average air temperature is an initial condition used in the SAFETY ANALYSES DBA analyses that establishes the containment environmental qualification operating envelope for both pressure and temperature. The limit for containment average air temperature ensures that operation is maintained within the assumptions used in the DBA analysis for containment. The accident analyses and evaluations considered both LOCAs and MSLBs for determining the maximum peak containment pressures and temperatures. The LOCA event is bounding with respect to peak containment pressure, and the MSLB event is bounding with respect to peak containment temperature. This is due to the differences in the magnitude and timing of the mass and energy release rates between the two events. The LOCA peak pressure occurs prior to any containment heat removal components being placed in service. The MSLB peak temperature occurs after heat removal equipment has been in operation.

The initial pre-accident temperature inside containment was assumed to be 145°F to provide analysis margin from the Technical Specification limit of 140OF (Ref. 2).

Palisades Nuclear Plant B 3.6.5-1 Revised 03/15/2012

Containment Air Temperature B 3.6.5 BASES APPLICABLE Containment average air temperature satisfies Criterion 2 of ANALYSES SAFETY 10 CFR 50.36(c)(2).

(continued)

LCO During a DBA, with an initial containment average air temperature less than or equal to the LCO temperature limit, the resultant peak accident pressure is maintained below the containment design pressure. As a result, the ability of containment to perform its function is ensured.

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment. In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining containment average air temperature within the limit is not required in MODE 5 or 6.

ACTIONS A.1 When containment average air temperature is not within the limit of the LCO, it must be restored to within limit within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . This Required Action is necessary to return operation to within the bounds of the containment analysis. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is acceptable considering the sensitivity of the analysis to variations in this parameter and provides sufficient time to correct minor problems.

Palisades Nuclear Plant B 3.6.5-2 Revised 03/15/2012

Containment Air Temperature B 3.6.5 BASES ACTIONS B.1 and B.2 (continued)

If the containment average air temperature cannot be restored to within its limit within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.5.1 REQUIREMENTS Verifying that containment average air temperature is within the LCO limit ensures that containment operation remains within the limit assumed for the containment analyses. The 145°F limit is the actual limit assumed for the accident analyses and does not account for instrument inaccuracies.

Instrument uncertainties are accounted for in the surveillance procedure.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of this SR is considered acceptable based on the observed slow rates of temperature increase within containment as a result of environmental heat sources (due to the large volume of containment).

REFERENCES 1. FSAR, Section 5.8

2. FSAR, Section 14.18 Palisades Nuclear Plant B 3.6.5-3 Revised 03/15/2012

Containment Cooling Systems B 3.6.6 B 3.6 CONTAINMENT SYSTEMS B 3.6.6 Containment Cooling Systems BASES BACKGROUND The Containment Spray and Containment Air Cooler systems provide containment atmosphere cooling to limit post accident pressure and temperature in containment to less than the design values. Reduction of containment pressure reduces the release of fission product radioactivity from containment to the environment, in the event of a Main Steam Line Break (MSLB) or a large break Loss of Coolant Accident (LOCA). The Containment Spray and Containment Air Cooler systems are designed to the requirements of the Palisades Nuclear Plant design criteria (Ref. 1).

The Containment Air Cooler System and Containment Spray System are Engineered Safety Feature (ESF) systems. They are designed to ensure that the heat removal capability required during the post accident period can be attained. The systems are arranged with two spray pumps powered from one diesel generator, and with one spray pump and three air cooler fans powered from the other diesel generator. The Containment Spray System was originally designed to be redundant to the Containment Air Coolers (CACs) and fans. These systems were originally designed such that either two containment spray pumps or three CACs could limit containment pressure to less than design. However, the current safety analyses take credit for one containment spray pump when evaluating cases with three CACs, and no air cooler fans in cases with two spray pumps and both Main Steam Isolation Valve (MSIV) bypass valves closed. If an MSIV bypass valve is open, 2 service water pumps and 2 CACs are also required to be OPERABLE in addition to the 2 spray pumps for containment heat removal.

To address this dependency between the Containment Spray System and the Containment Air Cooler System the title of this Specification is "Containment Cooling Systems," and includes both systems. The LCO is written in terms of trains of containment cooling. One train of containment cooling is associated with Diesel Generator 1-1 and includes Containment Spray Pumps P-54B and P-54C, Containment Spray Valve CV-3001 and the associated spray header. The other train of containment cooling is associated with Diesel Generator 1-2 and includes Containment Spray Pump P-54A, Containment Spray Valve CV-.3002 and the associated spray header, and CACs VHX-1, VHX-2, and VHX-3 and their associated safety related fans, V-1A, V-2A, and V-3A.

Palisades Nuclear Plant B 3.6.6-1 Revised 03/15/2012

Containment Cooling Systems B 3.6.6 BASES BACKGROUND If reliance is placed solely on one spray pump and three CACs, at least (continued) two service water pumps must be OPERABLE to provide the necessary service water flow to assure OPERABILITY of the CACs. Additional details of the required equipment and its operation is discussed with the containment cooling system with which it is associated.

Containment Spray System The Containment Spray System consists of three half-capacity (50%)

motor driven pumps, two shutdown cooling heat exchangers, two spray headers, two full sets of full capacity (100%) nozzles, valves, and piping, two full capacity (100%) pump suction lines from the Safety Injection and Refueling Water Tank (SIRWT) and the containment sump with the associated piping, valves, power sources, instruments, and controls. The heat exchangers are shared with the Shutdown Cooling System. SIRWT supplies borated water to the containment spray during the injection phase of operation. In the recirculation mode of operation, containment spray pump suction is transferred from the SIRWT to the containment sump.

Normally, both Shutdown Cooling Heat Exchangers must be available to provide cooling of the containment spray flow in the event of a Loss of Coolant Accident. If the Containment Spray side (tube side) of one SDC Heat Exchanger is out of service, 100% of the required post accident cooling capability can be provided, if other equipment outages are limited (refer to Bases for Required Action C.1).

The Containment Spray System provides a spray of cold borated water into the upper regions of containment to reduce the containment pressure and temperature during a MSLB or large break LOCA event. In addition, the Containment Spray System in conjunction with the use of sodium Tetraborate (LCO 3.5.5, "Containment Sump Buffering Agent and Weight Requirements,") serve to remove iodine which may be released following an accident. The SIRWT solution temperature is an important factor in determining the heat removal capability of the Containment Spray System during the injection phase.

Palisades Nuclear Plant B 3.6.6-2 Revised 03/15/2012

Containment Cooling Systems B 3.6.6 BASES BACKGROUND Containment Spray System (continued)

In the recirculation mode of operation, heat is removed from the containment sump water by the shutdown cooling heat exchangers.

The Containment Spray System is actuated either automatically by a Containment High Pressure (CHP) signal or manually. An automatic actuation opens the containment spray header isolation valves, starts the three containment spray pumps, and begins the injection phase.

Individual component controls may be used to manually initiate Containment Spray. The injection phase continues until an SIRWT Level Low signal is received. The Low Level signal for the SIRWT generates a Recirculation Actuation Signal (RAS) that aligns valves from the containment spray pump suction to the containment sump. RAS re-positions CV-3001 and CV-3002 to a predetermined throttled position to ensure adequate containment spray pump NPSH. RAS opens the HPSI subcooling valve CV-3071, if the associated HPSI pump is operating.

After the containment sump valve CV-3030 opens from RAS, HPSI subcooling valve CV-3070 will open, if the associated HPSI pump is operating. RAS will close containment spray valve CV-3001, if containment sump valve CV-3030 does not open. The Containment Spray System in recirculation mode maintains an equilibrium temperature between the containment atmosphere and the recirculated sump water.

Operation of the Containment Spray System in the recirculation mode is controlled by the operator in accordance with the emergency operating procedures.

The containment spray pumps also provide a required support function for the High Pressure Safety Injection pumps as described in the Bases for specification 3.5.2. The High Pressure Safety Injection pumps alone may not have adequate NPSH after a postulated accident and the realignment of their suctions from the SIRWT to the containment sump.

Flow is automatically provided from the discharge of the containment spray pumps to the suction of the High Pressure Safety Injection (HPSI) pumps after the change to recirculation mode has occurred, ifthe HPSI pump is operating. The additional suction pressure ensures that adequate NPSH is available for the High Pressure Safety Injection pumps.

Palisades Nuclear Plant B 3.6.6-3 Revised 03/15/2012

Containment Cooling Systems B 3.6.6 BASES BACKGROUND Containment Air Cooler System (continued)

The Containment Air Cooler System includes four air handling and cooling units, referred to as the Containment Air Coolers (CACs), which are located entirely within the containment building. Three of the CACs (VHX-1, VHX-2, and VHX-3) are safety related coolers and are cooled by the critical service water. The fourth CAC (VHX-4) is not taken credit for in maintaining containment temperature within limit (the service water inlet valve for VHX-4 is closed by an SIS signal to conserve service water flow), but is used during normal operation along with the three CACs to maintain containment temperature below the design limits.

The DG which powers the fans associated with VHX-1, VHX-2, and VHX-3 (V-1A, V-2A and V-3A) also powers two service water pumps.

This is necessary because if reliance is placed solely on the train with one spray pump and three CACs, at least two service water pumps must be OPERABLE to provide the necessary service water flow to assure OPERABILITY of the CACs.

Each CAC has two vaneaxial fans with direct connected motors which draw air through the cooling coils. Both of these fans are normally in operation, but only one fan and motor for each CAC is rated for post accident conditions. The post accident rated "safety related" fan units, V-1A, V-2A, and V-3A, serve to provide forced flow for the associated cooler. A single operating safety related spray header will provide enough air flow to assure that there is adequate mixing of unsprayed containment areas to assure the assumed iodine removal by the containment spray. In post accident operation following a SIS, all four Containment air coolers are designed to change automatically to the emergency mode.

The CACs are automatically changed to the emergency mode by a Safety Injection Signal (SIS). This signal will trip the normal rated fan motor in each unit, open the high-capacity service water discharge valve from VHX-1, VHX-2, and VHX-3, and close the high-capacity service water supply valve to VHX-4. The test to verify the service water valves actuate to their correct position upon receipt of an SIS signal is included in the surveillance test performed as part of Specification 3.7.8, "Service Water System." The safety related fans and the V-4A non-safety related fan are normally in operation and only receive an actuation signal through the DBA sequencers following an SIS in conjunction with a loss of offsite power. This actuation is tested by the surveillance which verifies the energizing of loads from the DBA sequencers in Specification 3.8.1, "AC Sources-Operating."

Palisades Nuclear Plant B 3.6.6-4 Revised 03/15/2012

Containment Cooling Systems B 3.6.6 BASES APPLICABLE The Containment Spray System and Containment Air Cooler SAFETY ANALYSES System limit the temperature and pressure that could be experienced following either a Loss of Coolant Accident (LOCA) or a Main Steam Line Break (MSLB). The large break LOCA and MSLB are analyzed using computer codes designed to predict the resultant containment pressure and temperature transients.

The Containment Cooling Systems have been analyzed for three accident cases (Ref. 2). All accidents analyses account for the most limiting single active failure.

1. A Large Break LOCA concurrent with a loss of offsite power,

2. An MSLB occurring at various power levels with both MSIV bypass valves closed with offsite power available, and

3. An MSLB occurring at 0% RTP with both MSIV bypass valves open, both with and without offsite power available.

The postulated large break LOCA is analyzed, in regard to containment ESF systems, assuming the loss of offsite power and the loss of one ESF bus, which is the worst case single active failure, resulting in one train of Containment Cooling being rendered inoperable (Ref. 6).

The postulated MSLB is analyzed, in regard to containment ESF systems, assuming the worst case single active failure.

The MSLB event is analyzed at various power levels with both MSIV bypass valves closed, and at 0% RTP (MODE 2) with both MSIV bypass valves open. Having any MSIV bypass valve open allows additional blowdown from the intact steam generator. These cases consider single active failure scenarios both with and without offsite power available.

With offsite power available, the analysis evaluates failure of various relays responsible for starting containment heat removal components on receipt of SIS or CHP signals. On loss of offsite power, the analysis evaluates failure of an emergency diesel generator resulting in one train of containment cooling being rendered inoperable. Generally, cases with offsite power available are bounding as the primary coolant pumps remain in service resulting in forced convection through the steam generators increasing the blowdown energy.

Palisades Nuclear Plant B 3.6.6-5 Revised 03/15/2012

Containment Cooling Systems B 3.6.6 BASES APPLICABLE The analysis and evaluation show that under the worst-case scenario, the ANALYSES highest peak containment pressure and the peak containment vapor (continued) temperature are within the design basis. (See the Bases for Specifications 3.6.4, "Containment Pressure," and 3.6.5, "Containment Air Temperature," for a detailed discussion.) The analyses and evaluations considered a range of power levels and equipment configurations as described in Reference 2. The peak containment pressure case is the large break LOCA with initial (pre-accident) conditions of 145°F and 15.7 psia. The peak temperature case is the 0% power MSLB with initial (pre-accident) conditions of 145°F and 16.2 psia. The analyses also assume a response time delayed initiation in order to provide conservative peak calculated containment pressure and temperature responses.

The external design pressure of the containment shell is 3 psig. This value is approximately 0.5 psig greater than the maximum external pressure that could be developed if the containment were sealed during a period of low barometric pressure and high temperature and, subsequently, the containment atmosphere was cooled with a concurrent major rise in barometric pressure.

The modeled Containment Cooling System actuation from the containment analysis is based on a response time associated with exceeding the Containment High Pressure setpoint to achieve full flow through the CACs and containment spray nozzles. The spray lines within containment are maintained filled to the 735 ft elevation to provide for rapid spray initiation. The Containment Cooling System total response time of < 60 seconds includes diesel generator startup (for loss of offsite power), loading of equipment, CAC and containment spray pump startup, and spray line filling.

The performance of the Containment Spray System for post accident conditions is given in Reference 3. The performance of the Containment Air Coolers is given in Reference 4.

The Containment Spray System and the Containment Cooling System satisfy Criterion 3 of 10 CFR 50.36(c)(2).

Palisades Nuclear Plant B 3.6.6-6 Revised 03/15/2012

Containment Cooling Systems B 3.6.6 BASES LCO During an MSLB or large break LOCA event, a minimum of one containment cooling train is required to maintain the containment peak pressure and temperature below the design limits (Ref. 2). One train of containment cooling is associated with Diesel Generator 1-1 and includes Containment Spray Pumps P-54B and P-54C, Containment Spray Valve CV-3001 and the associated spray header. This train must be supplemented with 2 service water pumps and 2 containment air coolers if an MSIV bypass valve is open. The other train of containment cooling is associated with Diesel Generator 1-2 and includes Containment Spray LCO Pump P-54A, Containment Spray Valve CV-3002 and the associated spray header, and CACs VHX-1, VHX-2, and VHX-3 and their associated safety related fans, V-1A, V-2A, and V-3A. To ensure that these requirements are met, two trains of containment cooling must be OPERABLE. Therefore, in the event of an accident, the minimum requirements are met, assuming the worst-case single active failure occurs.

The Containment Spray System portion of the containment cooling trains includes three spray pumps, two spray headers, nozzles, valves, piping, instruments, and controls to ensure an OPERABLE flow path capable of taking suction from the SIRWT upon an ESF actuation signal and automatically transferring suction to the containment sump.

The Containment Air Cooler System portion of the containment cooling train which must be OPERABLE includes the three safety related air coolers which each consist of four cooling coil banks, the safety related fan which must be in operation to be OPERABLE, gravity-operated fan discharge dampers, instruments, and controls to ensure an OPERABLE flow path.

CAC fans V-1A, V-2A, and V-3A, must be in operation to be considered OPERABLE. These fans only receive a start signal from the DBA sequencer; they are assumed to be in operation, and are not started by either a CHP or an SIS signal.

APPLICABILITY In MODES 1, 2, and 3, a large break LOCA event could cause a release of radioactive material to containment and an increase in containment pressure and temperature requiring the operation of the containment spray trains and containment cooling trains.

In MODES 4, 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Thus, the Containment Spray and Containment Cooling systems are not required to be OPERABLE in MODES 4, 5 and 6.

Palisades Nuclear Plant B 3.6.6-7 Revised 03/15/2012

Containment Cooling Systems B 3.6.6 BASES ACTIONS A.1 Condition A is applicable whenever one or more containment cooling trains is inoperable. Action A.1 requires restoration of both trains to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The 72-hour Completion Time for Condition A is based on the assumption that at least 100% of the required post accident containment cooling capability (that assumed in the safety analyses) is available. If less than 100% of the required post containment accident cooling is available, Condition C must also be entered.

Mechanical system LCOs typically provide a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time under conditions when a required system can perform its required safety function, but may not be able to do so assuming an additional failure.

When operating in accordance with the Required Actions of an LCO Condition, it is not necessary to be able to cope with an additional single failure.

The Containment Cooling systems can provide one hundred percent of the required post accident cooling capability following the occurrence of any single active failure. Therefore, the containment cooling function can be met during conditions when those components which could be deactivated by a single active failure are known to be inoperable. Under that condition, however, the ability to provide the function after the occurrence of an additional failure cannot be guaranteed. Therefore, continued operation with one or more trains inoperable is allowed only for a limited time.

B.1 and B.2 Condition B is applicable when the Required Actions of Condition A cannot be completed within the required Completion Time. Condition A is applicable whenever one or more trains is inoperable. Therefore, when Condition B is applicable, Condition A is also applicable. (If less than 100% of the post accident containment cooling capability is available, Condition C must be entered as well.) Being in Conditions A and B concurrently maintains both Completion Time clocks for instances where equipment repair allows exit from Condition B while the plant is still within the applicable conditions of the LCO.

If the inoperable containment cooling trains cannot be restored to OPERABLE status within the required Completion Time of Condition A, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Palisades Nuclear Plant B 3.6.6-8 Revised 03/15/2012

Containment Cooling Systems B 3.6.6 BASES ACTIONS C.1 (continued)

Condition C is applicable with one or more trains inoperable when there is less than 100% of the required post accident containment cooling capability available. Condition A is applicable whenever one or more trains is inoperable. Therefore, when this Condition is applicable, Condition A is also applicable. Being in Conditions A and C concurrently maintains both Completion Time clocks for instances where equipment repair restores 100% of the required post accident containment cooling capability while the LCO is still applicable, allowing exit from Condition C (and LCO 3.0.3).

Several specific cases have been analyzed in the safety analysis to provide operating flexibility for equipment outages and testing. These analyses show that action A.1 can be entered under certain circumstances, because 100% of the post accident cooling capability is maintained. These specific cases are discussed below.

One hundred percent of the required post accident cooling capability can be provided with both MSIV bypass valves closed if either;

1. Two containment spray pumps, and two spray headers are OPERABLE, or

2. One containment spray pump, two spray headers, and three safety related CACs, are OPERABLE (at least two service water pumps must be OPERABLE if CACs are to be relied upon).

One hundred percent of the required post accident cooling capability can be provided for operation with a MSIV bypass valve open or closed if either;

1. Two containment spray pumps, two spray headers, and two safety related CACs, are OPERABLE (at least two service water pumps must be OPERABLE if CACs are to be relied upon), or

2. One containment spray pump, one spray header, and three safety related CACs are OPERABLE (at least three service water pumps must be OPERABLE to provide the necessary service water flow to assure OPERABILITY of the CACs).

The components described in items 1 and 2 directly above, are necessary to mitigate a MSLB where offsite power is available and primary coolant pumps continue to operate. Therefore, components from both trains of containment heat removal are required.

Palisades Nuclear Plant B 3.6.6-9 Revised 03/15/2012

Containment Cooling Systems B 3.6.6 BASES ACTIONS C.1 (continued)

If the Containment Spray side (tube side) of SDC Heat Exchanger E-60B is out of service, 100% of the required post accident cooling capability can be provided, if other equipment outages are limited. One hundred percent of the post accident cooling can be provided with the Containment Spray side of SDC Heat Exchanger E-60B out of service if the following equipment is OPERABLE: three safety related Containment Air Coolers, two Containment Spray Pumps, two spray headers, CCW pumps P-52A and P-52B, two SWS pumps, and both CCW Heat Exchangers, and if

1. One CCW Containment Isolation Valve, CV-0910, CV-091 1, or CV-0940, is OPERABLE, and

2. Two CCW isolation valves for the non-safety related loads outside the containment, CV-0944A and CV-0944 (or CV-0977B), are OPERABLE.

With less than 100% of the required post accident containment cooling capability available, the plant is in a condition outside the assumptions of the safety analyses. Therefore, LCO 3.0.3 must be entered immediately.

SURVEILLANCE SR 3.6.6.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves, excluding check valves, in the Containment Spray System provides assurance that the proper flow path exists for Containment Spray System operation. This SR also does not apply to valves that are locked, sealed, or otherwise secured in position since these were verified to be in the correct positions prior to being secured.

This SR also does not apply to valves that cannot be inadvertently misaligned, such as check valves. This SR does not require any testing or valve manipulation. Rather, it involves verification that those valves outside containment and capable of potentially being mispositioned, are in the correct position.

SR 3.6.6.2 Operating each safety related Containment Air Cooler fan unit for

_>15 minutes ensures that all trains are OPERABLE and are functioning properly. The 31-day Frequency was developed considering the known reliability of the fan units, the two train redundancy available, and the low probability of a significant degradation of the containment cooling train occurring between surveillances.

Palisades Nuclear Plant B 3.6.6-10 Revised 03115/2012

Containment Cooling Systems B 3.6.6 BASES SURVEILLANCE SR 3.6.6.3 REQUIREMENTS (continued) Verifying the containment spray header is full of water to the 735 ft elevation minimizes the time required to fill the header. This ensures that spray flow will be admitted to the containment atmosphere within the time frame assumed in the containment analysis. The 31-day Frequency is based on the static nature of the fill header and the low probability of a significant degradation of the water level in the piping occurring between surveillances.

SR 3.6.6.4 Verifying a total service water flow rate of __4800 gpm to CACs VHX-1, VHX-2, and VHX-3, when aligned for accident conditions, provides assurance the design flow rate assumed in the safety analyses will be achieved (Ref. 8). Also considered in selecting this Frequency were the known reliability of the cooling water system, the two train redundancy, and the low probability of a significant degradation of flow occurring between surveillances.

SR 3.6.6.5 Verifying that each containment spray pump's developed head at the flow test point is greater than or equal to the required developed head ensures that spray pump performance has not degraded during the cycle. Flow and differential pressure are normal tests of centrifugal pump performance required by Section XI of the ASME Code (Ref. 5).

Since the containment spray pumps cannot be tested with flow through the spray headers, they are tested on recirculation flow. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this SR is in accordance with the Inservice Testing Program.

Palisades Nuclear Plant B 3.6.6-11 Revised 03/15/2012

Containment Cooling Systems B 3.6.6 BASES SURVEILLANCE SR 3.6.6.6 and SR 3.6.6.7 REQUIREMENTS (continued) SR 3.6.6.6 verifies each automatic containment spray valve actuates to its correct position upon receipt of an actual or simulated actuation signal.

This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls.

SR 3.6.6.7 verifies each containment spray pump starts automatically on an actual or simulated actuation signal. The 18-month Frequency is based on the need to perform these Surveillances under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillances were performed with the reactor at power.

Operating experience has shown that these components usually pass the Surveillances when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

Where the surveillance of containment sump isolation valves is also required by SR 3.5.2.5, a single surveillance may be used to satisfy both requirements.

SR 3.6.6.8 This SR verifies each safety related containment cooling fan actuates upon receipt of an actual or simulated actuation signal. The 18-month Frequency is based on engineering judgement and has been shown to be acceptable through operating experience. See SR 3.6.6.6 and SR 3.6.6.7, above, for further discussion of the basis for the 18 month Frequency.

SR 3.6.6.9 With the containment spray inlet valves closed and the spray header drained of any solution, an inspection of spray nozzles, or a test that blows low-pressure air or smoke through test connections can be completed. Performance of this SR demonstrates that each spray nozzle is unobstructed and provides assurance that spray coverage of the containment during an accident is not degraded. Verification following maintenance which could result in nozzle blockage is appropriate because this is the only activity that could lead to nozzle blockage.

Palisades Nuclear Plant B 3.6.6-12 Revised 03/15/2012

Containment Cooling Systems B 3.6.6 BASES REFERENCES 1. FSAR, Section 5.1

2. FSAR, Section 14.18

3. FSAR, Sections 6.2

4. FSAR, Section 6.3

5. ASME, Boiler and Pressure Vessel Code, Section Xl

6. FSAR, Table 14.18.1-3

7. FSAR, Table 14.18.2-1

8. FSAR, Table 9-1

9. EA-GOTHIC-04-09 Rev. 3, Containment Response to a MSLB Using GOTHIC 7.2a, October 2010.

10. EA-GOTHIC-04-08, Rev. 3, Containment Response to a LOCA Using GOTHIC 7.2a, October 2010.

Palisades Nuclear Plant B 3.6.6-13 Revised 03/15/2012

Spent Fuel Pool Storage B 3.7.16 B 3.7 PLANT SYSTEMS B 3.7.16 Spent Fuel Pool Storage BASES BACKGROUND The fuel storage facility is designed to store either new (nonirradiated) nuclear fuel assemblies, or used (irradiated) fuel assemblies in a vertical configuration underwater. The storage pool is sized to store 892 fuel assemblies, which includes storage for failed fuel canisters.

The fuel storage racks are grouped into two regions, Region I and Region II per Figure B 3.7.16-1. The racks are designed as a Seismic Category I structure able to withstand seismic events. Region I contains racks in the spent fuel pool having a 10.25 inch center-to-center spacing and a single rack in the north tilt pit having an 11.25 inch by 10.69 inch center-to-center spacing. Region II contains racks in both the spent fuel pool and the north tilt pit having a 9.17 inch center-to-center spacing. Region I has restrictive loading patterns to address degradation of neutron absorbing material in the Region I racks. The loading patterns accommodate face-adjacent fuel assemblies with consideration of burnup credit in subregion 1B, 1C, 1 D, and 1 E. Region I also has provisions for storing non-fissile bearing components. Because of the smaller spacing and an analyzed poison concentration of zero (Boraflex), Region II also has limitations for fuel storage. Further information on limitations can be found in Section 4.0, "Design Features." These limitations (e.g., enrichment, burnup, loading patterns) are sufficient to maintain a keff of _<0.95 when flooded with borated water and keff < 1.0 when flooded with unborated water.

APPLICABLE The fuel storage facility was originally designed for noncriticality by use SAFETY ANALYSES of adequate spacing, and "flux trap" construction, whereby the fuel assemblies are inserted into neutron absorbing stainless steel cans.

The current criticality calculations also take credit for soluble boron to prevent criticality.

The spent fuel pool storage meets the requirements specified in "Guidance on the Regulatory Requirements for Criticality Analysis of Fuel Storage at Light-Water Reactor Power Plants", Laurence I. Kopp, U.S. Nuclear Regulatory Commission, Office of Nuclear Reactor Regulation, Reactor Systems Branch, February 1998. This document established the requirements for use of soluble boron to maintain keff *0.95.

The spent fuel pool storage satisfies Criterion 2 of 10 CFR 50.36(c)(2).

Palisades Nuclear Plant B 3.7.16-1 Amendment No. 489, 207, 2-96, 246 Revised 11/08/2012

Spent Fuel Pool Storage B 3.7.16 BASES LCO The restrictions for Region I in Specification 4.3.1.1 on fuel assembly maximum nominal planar average U-235 enrichment and minimum burnup along with their storage pool loading patterns plus the restrictions on the placement of non-fissile bearing components, ensure that the keff of the spent fuel pool will always remain _<0.95, assuming the pool to be flooded with water borated to 850 ppm. Non-fissile bearing components shall be stored in accordance with Specification 4.3.1.1 m. Specification 4.3.1.1 refers to Tables 3.7.16-2 through 3.7.16-5 in the accompanying LCO.

The restrictions for Region II in Table 3.7.16-1, in the accompanying LCO, on fuel assembly decay time, maximum nominal planar average U-235 enrichment and minimum burnup combinations, ensure that the keff of the spent fuel pool will always remain _< 0.95, assuming the pool to be flooded with water borated to 850 ppm. The restrictions are consistent with the criticality safety analyses performed for the spent fuel pool according to Table 3.7.16-1, in the accompanying LCO. Fuel assemblies not meeting the criteria of Table 3.7.16-1 shall be stored in accordance with Specification 4.3.1.1.

Specification 4.3.1.1, 4.3.1.2, and 4.3.1.3 describe U-235 enrichment restrictions for fuel assemblies stored based on maximum nominal planar average U-235 enrichment. The term "nominal" describes the design enrichment specified for an assembly. The criticality calculations that support the storage requirements include a manufacturer's fuel enrichment tolerance of +/-0.05 weight percent U-235. Specifications 4.3.1.1, 4.3.1.2, or 4.3.1.3 do not include the manufacturer's fuel enrichment tolerance.

The term "maximum" refers to an assembly's limiting nominal planar average U-235 enrichment. Palisades' fuel assembly design may have several distinct axial planar regions, and each region may have a different nominal planar average U-235 enrichment. Additionally, fuel assembly enrichments may vary from pin to pin within a given axial planar region. The criticality analysis conservatively assumes each pin is loaded with the nominal enrichment for that planar region. The highest nominal planar average enrichment of the distinct axial planar regions is considered to be the maximum nominal planar average enrichment for that assembly. This value is used to verify that storage requirements have been met. The manufacturer's fuel enrichment tolerance of +/-0.05 weight percent is excluded from this value.

Sub-Regions 1A, 1B, & 1C, in Region 1 of the main fuel pool can be distributed in any manner providing that any 2-by-2 grouping of cells Palisades Nuclear Plant B 3.7.16-2 Amendment No. 489, 207, 236, 246 Revised 11/08/2012

Spent Fuel Pool Storage B 3.7.16 BASES and the assemblies in them meet the requirements of 4.3.1.lf, 4.3.1.lg, or 4.3.1.1h for the number of cells occupied. For example, for a 4-by-4 group of cells, all of the following 2-by-2 configurations must be examined against the above requirements:

The concept in the example above shall be expanded for the entire Region I of the main fuel pool.

Similarly, Sub-Regions 1D & 1E, in Region 1 of the north tilt pit can be distributed in any manner providing that any 2-by-2 grouping of cells and the assemblies in them meet the requirements of 4.3.1.lj or 4.3.1.1 k for the number of cells occupied.

APPLICABILITY This LCO applies whenever any fuel assembly or non-fissile bearing component is stored in the spent fuel pool or the north tilt pit.

ACTIONS The ACTIONS are modified by a Note indicating that LCO 3.0.3 does not apply.

If moving irradiated fuel assemblies while in MODE 5 or 6, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, 3, or 4, the fuel movement is independent of reactor operation. Therefore, in either case, inability to move fuel assemblies is not sufficient reason to require a reactor shutdown.

When the configuration of fuel assemblies or non-fissile bearing Palisades Nuclear Plant B 3.7.16-3 Amendment No. 4-89, 2-0-7, 2-W, 246 Revised 11/08/2012

Spent Fuel Pool Storage B 3.7.16 BASES components stored in the spent fuel pool is not in accordance with the storage requirements, immediate action must be taken to make the necessary movement(s) to bring the configuration into compliance with the requirements.

SURVEILLANCE SR 3.7.16.1 REQUIREMENTS This SR verifies by administrative means that the combination of fuel assembly maximum nominal planar average enrichment and proposed fuel assembly placement is in accordance with Specification 4.3.1.1 prior to placing the assembly in a storage location. This SR also verifies by administrative means that non-fissile bearing component storage will be in accordance with Specification 4.3.1.lm prior to placing the component in a Region I storage location.

This SR also verifies by administrative means that the combination of maximum nominal planar average U-235 enrichment, burnup and decay time of the fuel assembly is in accordance with Table 3.7.16-1, 3.7.16-2, 3.7.16-3, 3.7.16-4 or 3.7.16-5, as appropriate, in the accompanying LCO prior to placing the fuel assembly in a storage location.

REFERENCES None Palisades Nuclear Plant B 3.7.16-4 Amendment No. 489, 2--7, 236, 246 Revised 11/08/2012

Spent Fuel Pool Storage B 3.7.16 BASES N _ ý 176.00" Ref.

MAIN POOL Region I of the main pool is comprised of Sub-Regions 1A, 1B, and 1C. Region I of the north tilt pit is comprised of Sub-Regions 1D and 1E.

These Sub-Regions are defined in Specification 4.3.1.1 and are not related to the rack.

Figure B 3.7.16-1 (page 1 of 1)

Spent Fuel Pool Arrangement Palisades Nuclear Plant B 3.7.16-5 Amendment No. 41-9, 2-W, 2a6, 246 Revised 11/08/2012

AC Sources - Operating B 3.8.1 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources - Operating BASES BACKGROUND Sources of AC power to the plant Class 1E Electrical Power Distribution System include the offsite power sources, and the Class 1E onsite standby power sources, Diesel Generators 1-1 and 1-2 (DGs). As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.

The AC power system at Palisades consists of a 345 kV switchyard, three circuits connecting the plant with off-site power (station power, startup, and safeguards transformers), the on-site distribution system, and two DGs. The on-site distribution system is divided into safety related (Class 1 E) and non-safety related portions.

The switchyard interconnects six transmission lines from the off-site transmission system, the output line from the Covert Generating Station, and the output line from the Palisades main generator. These lines are connected in a "breaker and a half scheme between the Front (F) and Rear (R) buses such that any single off-site line may supply the Palisades station loads when the plant is shutdown.

Two circuits supplying Palisades 2400 V buses from off-site are fed directly from a switchyard bus through the startup and safeguards transformers. They are available both during operation and during shutdown. The third circuit supplies the plant loads by "back feeding" through the main generator output circuit and station power transformers after the generator has been disconnected by a motor operated disconnect.

The station power transformers are connected into the main generator output circuit. Station power transformers 1-1 and 1-2 connect to the generator 22 kV output bus. Station power transformer 1-3 connects to the generator output line on the high voltage side of the main transformer. Station power transformers 1-1 and 1-3 supply non-safety related 4160 V loads during plant power operation and during backfeeding operations. Station power transformer 1-2 can supply both safety related and non-safety related 2400 V loads during backfeeding operation.

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AC Sources - Operating B 3.8.1 BASES BACKGROUND The three startup transformers are connected to a common 345 kV (continued) overhead line from the switchyard R bus. Startup transformers 1-1 and 1-3 supply 4160 V non-safety related station loads; Startup Transformer 1-2 can supply both safety related and non-safety related 2400 V loads.

The startup transformers are available during operation and shutdown.

Safeguards Transformer 1-1 is connected to the switchyard F bus. It feeds station 2400 V loads through an underground line. It is available to supply these loads during operation and shutdown.

The onsite distribution system consists of seven main distribution buses (4160 V buses 1A, 1B, 1F, and 1G, and 2,400 V buses 1C, 1D, and 1E) and supported lower voltage buses, Motor Control Centers (MCCs), and lighting panels. The 4160 V buses and 2400 V bus 1E are not safety related. Buses 1C and 1D and their supported buses and MCCs form two independent, redundant, safety related distribution trains. Each distribution train supplies one train of engineered safety features equipment.

In the event of a generator trip, all loads supplied by the station power transformers are automatically transferred to the startup transformers.

Loads supplied by the safeguards transformer are unaffected by a plant trip. If power is lost to the safeguards transformer, the 2400 V loads will automatically transfer to startup transformer 1-2. If the startup transformers are not energized when these transfers occur, their output breakers will be blocked from closing and the 2400 V safety related buses will be energized by the DGs.

The two DGs each supply one 2400 V bus. They provide backup power in the event of loss of off-site power, or loss of power to the associated 2400 V bus. The continuous rating of the DGs is 2500 kW, with 110 percent overload permissible for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . The required fuel in the Fuel Oil Storage Tank and DG Day Tank will supply one DG for a minimum period of 7 days assuming accident loading conditions.

If either 2400 V bus, 1C or 1 D, experiences a sustained undervoltage, the associated DG is started, the affected bus is separated from its offsite power sources, major loads are stripped from that bus and its supported buses, the DGs are connected to the bus, and ECCS or shutdown loads are started by an automatic load sequencer.

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AC Sources - Operating B 3.8.1 BASES BACKGROUND The DGs share a common fuel oil storage and transfer system. A (continued) single buried Fuel Oil Storage Tank is used, along with an individual day tank for each DG, to maintain the required fuel oil inventory. Two fuel transfer pumps are provided. The fuel transfer pumps are necessary for long-term operation of the DGs. Testing and analysis have shown that each DG consumes about 200 gallons of fuel oil per hour at 2750 kW and about 180 gallons of fuel oil per hour at 2500 kW. Each day tank is required to contain at least 2500 gallons and contains sufficient fuel for about 13.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months of full load operation (Ref. 8). Beyond that time, a fuel transfer pump is required for continued DG operation.

Either fuel transfer pump is capable of supplying either DG. However, each fuel transfer pump is not capable, with normally available switching, of being powered from either DG. DG 1-1 can power either fuel transfer pump, but DG 1-2 can only power P-18A. The fuel oil pumps share a common fuel oil storage tank, and common piping.

Fuel transfer pump P-18A is powered from MCC-8, which is normally connected to Bus 1D (DG 1-2) through Station Power Transformer 12 and Load Center 12. In an emergency, P-1 8A can be powered from Bus 1 C (DG 1-1) by cross-connecting Load Centers 11 and 12.

Fuel transfer pump P-18B is powered from MCC-1, which is normally connected to Bus 1C (DG 1-1) through Station Power Transformer 19 and Load Center 19. P-18B cannot be powered, using installed equipment, from Bus 1D (DG 1-2).

APPLICABLE The safety analyses do not explicitly address AC electrical power. They SAFETY ANALYSES do, however, assume that the Engineered Safety Features (ESF) are available. The OPERABILITY of the ESF functions is supported by the AC Power Sources.

The design requirements are for each assumed safety function to be available under the following conditions:

a. The occurrence of an accident or transient,

b. The resultant consequential failures,

c. A worst-case single active failure,

d. Loss of all offsite or all onsite AC power, and

e. The most reactive control rod fails to insert.

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AC Sources - Operating B 3.8.1 BASES APPLICABLE One proposed mechanism for the loss of off-site power is a perturbation SAFETY ANALYSES of the transmission grid because of the loss of the plant's generating (continued) capacity. A loss of off-site power as a result of a generator trip can only occur during MODE 1 with the generator connected to the grid.

However, it is also assumed in analysis for some events in MODE 2, such as a control rod ejection. No specific mechanism for initiating a loss of off-site power when the plant is not on the line is discussed in the FSAR.

In most cases, it is conservative to assume that off-site power is lost concurrent with the accident and that the single failure is that of a DG.

That would leave only one train of safeguards equipment to cope with the accident, the other being disabled by the loss of AC power. Those analyses which assume that a loss of off-site power and failure of a single DG accompany the accident assume 11 seconds from the loss of power until the bus is re-energized. This time includes time for all portions of the circuitry necessary for detecting the undervoltage (relays and auxiliary relays) and starting the DG. Included in the 11 seconds, the analyses also assume 10 seconds for the DG to start and connect to the bus, and additional time for the sequencer to start each safeguards load.

The same assumptions are not conservative for all accident analyses.

When analyzing the effects of a steam or feed line break, the loss of the condensate and feedwater pumps would reduce the steam generator inventory, so a loss of off-site power is not assumed.

In MODE 5 and MODE 6, loss of off-site power can be considered as an initiating event for a loss of shutdown cooling event.

The AC sources satisfy Criterion 3 of 10 CFR 50.36(c)(2).

LCO Two qualified circuits between the offsite transmission network and the onsite Class 1 E Electrical Power Distribution System and an independent DG for each safeguards train ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence or a postulated DBA.

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AC Sources - Operating B 3.8.1 BASES LCO General Design Criterion 17 (Ref. 1) requires, in part, that: "Electric (continued) power from the transmission network to the'onsite electric distribution system shall be supplied by two physically independent circuits (not necessarily on separate rights of way) designed and located so as to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions."

The qualified offsite circuits available are Safeguards Transformer 1-1 and Startup Transformer 1-2. Station Power Transformer 1-2 is not qualified as a required source for LCO 3.8.1 since it is not independent of the other two offsite circuits. Station Power Transformer 1-2 will not be used in normal operations to power the 2400 V safety related buses in Modes 1-4.

Each offsite circuit must be capable of maintaining acceptable frequency and voltage, and accepting required loads during an accident, while supplying the 2400 V safety related buses.

Following a loss of offsite power, each DG must be capable of starting and connecting to its respective 2400 V bus. This will be accomplished within 10 seconds after receipt of a DG start signal. Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and continue to operate until offsite power can be restored to the 2400 V safety related buses.

Proper sequencing of loads and tripping of nonessential loads are required functions for DG OPERABILITY.

APPLICABILITY The AC sources are required to be OPERABLE above MODE 5 to ensure that redundant sources of off-site and on-site AC power are available to support engineered safeguards equipment in the event of an accident or transient. The AC sources also support the equipment necessary for power operation, plant heatups and cooldowns, and shutdown operation.

The AC source requirements for MODES 5 and 6, and during movement of irradiated fuel assemblies are addressed in LCO 3.8.2, "AC Sources - Shutdown."

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AC Sources - Operating B 3.8.1 BASES ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable DG.

There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

A.1 To ensure a highly reliable power source remains with the one offsite circuit inoperable, it is necessary to verify the OPERABILITY of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in failure to meet this Required Action. However, if a second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition C, for two offsite circuits inoperable, is entered.

As stated in SR 3.0.2, the 25% extension allowed by SR 3.0.2 may be applied to Required Actions whose Completion Time is stated as "once per.. ."however, the 25% extension does not apply to the initial performance of a Required Action with a periodic Completion Time that requires performance on a "once per.. ." basis. The 25% extension applies to each performance of the Required Action after the initial performance. Therefore, while Required Action 3.8.1 A.1 must be initially performed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months without any SR 3.0.2 extension, subsequent performances at the "Once per 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months " interval may utilize the 25% SR 3.0.2 extension.

A.2 According to the recommendations of Regulatory Guide (RG) 1.93 (Ref. 2), operation may continue in Condition A for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the plant safety systems. In this Condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1E Distribution System.

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AC Sources - Operating B 3.8.1 BASES ACTIONS A.2 (continued)

The 72-hour Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period. The second Completion Time for Required Action A.2 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single continuous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable, and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 7 days. This could lead to a total of 10 days, since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 7 days (for a total of 17 days) allowed prior to complete restoration of the LCO. The 10-day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 10 day Completion Time means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

The Completion Time allows for an exception to the normal "time zero" for beginning the Completion Time "clock." This will result in establishing the "time zero" at the time that the LCO was initially not met, instead of at the time Condition A was entered.

B.1 To ensure a highly reliable power source remains with an inoperable DG, it is necessary to verify the availability of the offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions and Required Actions must then be entered.

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AC Sources - Operating B 3.8.1 BASES ACTIONS B.2 (continued)

In accordance with LCO 3.0.6, the requirement to declare required features inoperable carries with it the requirement to take those actions required by the LCO for that required equipment.

Required Action B.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed with redundant safety related trains. Redundant required feature failures consist of inoperable features within a train redundant to the train that has an inoperable DG. If the train that has an inoperable DG contains multiple features redundant to the inoperable feature in the other train, all those multiple features must be declared inoperable. For example, if DG 1-1 and Containment Spray Pump P-54A are inoperable concurrently, Containment Spray Pumps P-54B and P-54C must both be declared inoperable. In this example, if off-site power were lost, neither P-54B nor P-54C would be available.

The Completion Time for Required Action B.2 is intended to allow the operator time to evaluate and repair any discovered inoperabilities.

This Completion Time also allows for an exception to the normal "time zero" for beginning the Completion Time "clock." In this Required Action, the Completion Time only begins on discovery that both:

a. An inoperable DG exists; and

b. A required feature on the other train is inoperable.

If at any time during the existence of this Condition (one DG inoperable) a redundant required feature subsequently becomes inoperable, this Completion Time begins to be tracked.

Discovering one required DG inoperable coincident with one or more inoperable required supporting or supported features, or both, that are associated with the OPERABLE DG, results in starting the Completion Time for Required Action B.2. Four hours from the discovery of these events existing concurrently, is acceptable because it minimizes risk while allowing time for restoration before subjecting the plant to transients associated with shutdown.

In this Condition, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost.

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AC Sources - Operating B 3.8.1 BASES ACTIONS B.2 (continued)

The 4-hour Completion Time takes into account the OPERABILITY of the redundant counterpart to the inoperable required feature.

Additionally, the 4-hour Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

B.3.1 and B.3.2 Required Action B.3 provides an allowance to avoid unnecessary testing of the OPERABLE DG. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.2 (test starting of the OPERABLE DG) does not have to be performed. If the cause of inoperability exists on other rGs, the other DGs would be declared inoperable upon discovery and Condition E of LCO 3.8.1 would be entered. Once the failure is repaired, the common cause failure no longer exists and Required Action B.3.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed to not exist on the remaining DG, performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of that DG.

In the event the inoperable DG is restored to OPERABLE status prior to completing Required Action B.3.1 or B.3.2 the corrective action system would normally continue to evaluate the common cause possibility.

This continued evaluation, however, is no longer under the 24-hour constraint imposed while in Condition B. According to Generic Letter 84-15 (Ref. 3), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable to confirm that the OPERABLE DG is not affected by the same problem as the inoperable DG.

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AC Sources - Operating B 3.8.1 BASES ACTIONS B.4 (continued)

In Condition B, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System for a limited period. The 7-day Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

The second Completion Time for Required Action B.4 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently returned OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This could lead to a total of 10 days, since initial failure to meet the LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (for a total of 13 days) allowed prior to complete restoration of the LCO. The 10-day Completion Time provides a limit on time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 7 day and 10 day Completion Time means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

As in Required Action B.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed time "clock." This will result in establishing the "time zero" at the time that the LCO was initially not met, instead of at the time Condition B was entered.

Palisades Nuclear Plant B 3.8.1 -10 Revised 11/08/2012

AC Sources - Operating B 3.8.1 BASES ACTIONS C.1 (continued)

In accordance with LCO 3.0.6 the requirement to declare required features inoperable carries with it the requirement to take those actions required by the LCO for that required equipment.

Required Action C.1, which applies when two required offsite circuits are inoperable, is intended to provide assurance that an event with a coincident single failure will not result in a complete loss of redundant required safety functions. The Completion Time for this failure of redundant required features is reduced to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The rationale for the reduction to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is that RG 1.93 (Ref. 2) recommends a Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for two required offsite circuits inoperable, based upon the assumption that two complete safety trains are OPERABLE. When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is appropriate. These features are powered from redundant AC safety trains.

The Completion Time for Required Action C.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities.

This Completion Time also allows for an exception to the normal "time zero" for beginning the Completion Time "clock." In this Required Action, the Completion Time only begins on discovery that both:

a. All required offsite circuits are inoperable; and

b. A required feature is inoperable.

If at any time during the existence of Condition C (two offsite circuits inoperable), a required feature becomes inoperable, this Completion Time begins to be tracked.

Palisades Nuclear Plant B 3.8.1-11 Revised 11/08/2012

AC Sources - Operating B 3.8.1 BASES ACTIONS C.2 (continued)

According to the recommendations of RG 1.93 (Ref. 2), operation may continue in Condition C for a period that should not exceed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

This level of degradation means that the offsite electrical power system does not have the capability to accomplish a safe shutdown and to mitigate the effects of an accident; however, the onsite AC sources have not been degraded. This level of degradation generally corresponds to a total loss of the immediately accessible offsite power sources.

With both of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the plant in a safe shutdown condition in the event of a DBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst-case single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time provides a period of time to effect restoration of one of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria.

If two offsite sources are restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , unrestricted operation may continue. If only one offsite source is restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , power operation continues in accordance with Condition A.

D.1 and D.2 Pursuant to LCO 3.0.6, the Distribution System ACTIONS would not be entered even if all AC sources to it were inoperable resulting in de-energization. Therefore, the Required Actions of Condition D are modified by a Note to indicate that when Condition D is entered with no AC source to any train, the Conditions and Required Actions for LCO 3.8.9, "Distribution Systems - Operating," must be immediately entered. This allows Condition D to provide the requirements for the loss of one offsite circuit and one DG without regard to whether a train is de-energized. LCO 3.8.9 provides the appropriate restrictions for a de-energized train.

In Condition D, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. The 12-hour Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

According to the recommendations of RG 1.93 (Ref. 2), operation may continue in Condition D for a period that should not exceed 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

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AC Sources - Operating B 3.8.1 BASES ACTIONS E.1 (continued)

With both DGs inoperable, there are no remaining standby AC sources.

Thus, with an assumed loss of offsite electrical power, no AC source would be available to power the minimum required ESF functions.

Since the offsite electrical power system is the only source of AC power for this level of degradation, the risk associated with continued operation for a short time could be less than that associated with an immediate controlled shutdown (the immediate shutdown could cause grid instability, which could result in a total loss of AC power). Since an inadvertent generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.

According to the recommendations of RG 1.93 (Ref. 2), with both DGs inoperable, operation may continue for a period that should not exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

F.1 and F.2 If the inoperable AC power sources cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to an operating condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

G.1 Condition G corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown.

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AC Sources - Operating B 3.8.1 BASES SURVEILLANCE The AC sources are designed to permit inspection and testing of all REQUIREMENTS important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, Appendix A, GDC 18 (Ref. 4).

Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulated accident conditions).

The SRs for demonstrating the OPERABILITY of the DGs are in accordance with the recommendations of RG 1.9 (Ref. 5) and RG 1.137 (Ref. 6).

Where the SRs discussed herein specify voltage and frequency tolerances for the DGs operated in the "Unit" mode, the following is applicable. The minimum steady state output voltage of 2280 V is 95%

of the nominal 2400 V generator rating. This value is above the setting of the primary undervoltage relays (127-1 and 127-2) and above the minimum analyzed acceptable bus voltage. It also allows for voltage drops to motors and other equipment down through the 120 V level.

The specified maximum steady state output voltage of 2520 V is 105%

of the nominal generator rating of 2400 V. It is below the maximum voltage rating of the safeguards motors, 2530 V. -The specified minimum and maximum frequencies of the DG are 59.5 Hz and 61.2 Hz, respectively. The minimum value assures that ESF pumps provide sufficient flow to meet the accident analyses. The maximum value is equal to 102% of the 60 Hz nominal frequency and is derived from the recommendations given in RG 1.9 (Ref. 5).

Higher maximum tolerances are specified for final steady state voltage and frequency following a loss of load test, because that test must be performed with the DG controls in the "Parallel" mode. Since "Parallel" mode operation introduces both voltage and speed droop, the DG final conditions will not return to the nominal "Unit" mode settings.

SR 3.8.1.1 This SR assures that the required offsite circuits are OPERABLE. Each offsite circuit must be energized from associated switchyard bus through its disconnect switch to be OPERABLE.

Since each required offsite circuit transformer has only one possible source of power, the associated switchyard bus, and since loss of voltage to either the switchyard bus or the transformer is alarmed in the control room, correct alignment and voltage may be verified by the absence of these alarms.

Palisades Nuclear Plant B 3.8.1-14 Revised 11/08/2012

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.1 (continued)

REQUIREMENTS The 7 day Frequency is adequate because disconnect switch positions cannot change without operator action and because their status is displayed in the control room.

SR 3.8.1.2 This SR helps to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and to maintain the plant in a safe shutdown condition.

The monthly test starting of the DG provides assurance that the DG would start and be ready for loading in the time period assumed in the safety analyses. The monthly test, however does not, and is not intended to, test all portions of the circuitry necessary for automatic starting and loading. The operation of the bus undervoltage relays and their auxiliary relays which initiate DG starting, the control relay, which initiates DG breaker closure, and the DG breaker closure itself are not verified by this test. Verification of automatic operation of these components requires de-energizing the associated 2400 V bus and cannot be done during plant operation. For this test, the 10-second timing is started when the DG receives a start signal, and ends when the DG voltage sensing relays actuate. For the purposes of SR 3.8.1.2, the DGs are manually started from standby conditions. Standby conditions for a DG mean the diesel engine is not running, its coolant and oil temperatures are being maintained consistent with manufacturer recommendations, and > 20 minutes have elapsed since the last DG air roll.

Three relays sense the terminal voltage on each DG. These relays, in conjunction with a load shedding relay actuated by bus undervoltage, initiate automatic closing of the DG breaker. During monthly testing, the actuation of the three voltage sensing relays is used as the timing point to determine when the DG is ready for loading.

The 31-day Frequency for performance of SR 3.8.1.2 agrees with the original licensing basis for the Palisades plant.

Plant B 3.8.1-15 Revised 11/08/2012 Palisades Nuclear Palisades Nuclear Plant B 3.8.1-15 Revised 11/08/2012

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.3 REQUIREMENTS (continued) This Surveillance verifies that the DGs are capable of synchronizing with the offsite electrical system and accepting loads greater than or equal to the equivalent of the maximum expected accident loads for at least 15 minutes. A minimum total run time of 60 minutes is required to stabilize engine temperatures.

During the period when the DG is paralleled to the grid, it must be considered inoperable. This is because there are no provisions to automatically shift the DG controls from parallel mode to unit mode.

Additionally, when paralleled, there are certain conditions where the protection schemes may not prevent DG overloading and subsequent breaker trip and lockout.

The 31-day Frequency for this Surveillance is consistent with the original Palisades licensing basis.

The SR is modified by three Notes. Note 1 states that momentary transients outside the required band do not invalidate this test. This is to assure that a minor change in grid conditions and the resultant change in DG load, or a similar event, does not result in a surveillance being unnecessarily repeated. Note 2 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations. Note 3 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.

SR 3.8.1.4 This SR provides verification that the level of fuel oil in the day tank is at or above the level at which fuel oil is automatically added. The specified level is adequate for a minimum of 13.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months of DG operation at full load.

The 31-day Frequency is adequate to assure that a sufficient supply of fuel oil is available, since low-level alarms are provided and plant operators would be aware of any uses of the DG during this period.

Palisades Nuclear Plant B 3.8.1-16 Revised 11/08/2012

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.5 REQUIREMENTS (continued) Each DG is provided with an engine overspeed trip to prevent damage to the engine. The loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. This Surveillance may be accomplished with the DG in the "Parallel" mode.

An acceptable method is to parallel the DG with the grid and load the DG to a load equal to or greater than its single largest post-accident load. The DG breaker is tripped while its voltage and frequency (or speed) are being recorded. The time, voltage, and frequency tolerances specified in this SR are derived from the recommendations of RG 1.9, Revision 3 (Ref. 5).

RG 1.9 (Ref. 5) recommends that the increase in diesel speed during the transient does not exceed 75% of the difference between synchronous speed and the overspeed trip setpoint, or 15% above synchronous speed, whichever is lower. The Palisades DGs have a synchronous speed of 900 rpm and an overspeed trip setting range of 1060 to 1105 rpm. Therefore, the maximum acceptable transient frequency for this SR is 68 Hz.

The minimum steady state voltage is specified to provide adequate margin for the switchgear and for both the 2400 and 480 V safeguards motors; the maximum steady state voltage is 2400 +10% V as recommended by RG 1.9 (Ref. 5).

The minimum acceptable frequency is specified to assure that the safeguards pumps powered from the DG would supply adequate flow to meet the safety analyses. The maximum acceptable steady state frequency is slightly higher than the +2% (61.2 Hz) recommended by RG 1.9 (Ref. 5) because the test must be performed with the DG controls in the Parallel mode. The increased frequency allowance of 0.3 Hz is based on the expected speed differential associated with performance of the test while in the "Parallel" mode.

The 18-month surveillance Frequency is consistent with the recommendation of RG 1.9 (Ref. 5).

Revised 11/08/2012 Palisades Nuclear Plant Palisades Nuclear Plant B 3.8.1-17 B 3.8.1-17 Revised 11/08/2012

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.6 REQUIREMENTS (continued) This Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits. The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine and generator load response under a complete loss of load.

These acceptance criteria provide DG damage protection. The 4000 V limitation is based on generator rating of 2400/4160V and the ratings of those components (connecting cables and switchgear) that would experience the voltage transient. While the DG is not expected to experience this transient during an event and continue to be available, this response ensures that the DG is not degraded for future application, including re-connection to the bus if the trip initiator can be corrected or isolated.

In order to ensure that the DG is tested under load conditions that are as close to design basis conditions as possible, yet still provide adequate testing margin between the specified power factor limit and the DG design power factor limit of 0.8, testing must be performed using a power factor < 0.9. This is consistent with RG 1.9 (Ref. 5).

The 18-month Frequency is consistent with the recommendation of RG 1.9 (Ref. 5) and is intended to be consistent with expected fuel cycle lengths.

SR 3.8.1.7 As recommended by RG 1.9 (Ref. 5) this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source. This test verifies all actions encountered from the loss of offsite power, including shedding of the nonessential loads and re-energizing of the emergency buses and respective loads from the DG.

The requirement to energize permanently connected loads is met when the DG breaker closes, energizing its associated 2400 V bus.

Permanently connected loads are those that are not disconnected from the bus by load shedding relays. They are energized when the DG breaker closes. It is not necessary to monitor each permanently connected load.

Revised 11/08/2012 Palisades Nuclear Palisades Plant Nuclear Plant B 3.8.1-18 B 3.8.1-18 Revised 11/08/2012

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.7 (continued)

REQUIREM ENTS The DG auto-start and breaker closure time of 10 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. For this test, the 10-second timing is started when the DG receives a start signal, and ends when the DG breaker closes.

The safety analyses assume 11 seconds from the loss of power until the bus is re-energized.

The requirement to verify that auto-connected shutdown loads are energized refers to those loads that are actuated by the Normal Shutdown Sequencer. Each load should be started to assure that the DG is capable of accelerating these loads at the intervals programmed for the Normal Shutdown Sequence. The sequenced pumps may be operating on recirculation flow.

The requirements to maintain steady state voltage and frequency apply to the "steady state" period after all sequenced loads have been started. This period need only be long enough to achieve and measure steady voltage and frequency.

The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved. The requirement to supply permanently connected loads for > 5 minutes, refers to the duration of the DG connection to the associated safeguards bus. It is not intended to require that sequenced loads be operated throughout the 5-minute period. It is not necessary to monitor each permanently connected load.

The requirement to verify the connection and supply of permanently and automatically connected loads is intended to demonstrate the DG loading logic. This testing may be accomplished in any series of sequential, overlapping, or total steps so that the required connection and loading sequence is verified.

The Frequency of 18 months is consistent with the recommendations of RG 1.9 (Ref. 5).

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

B 3.8.1-19 Revised 11/08/2012 Nuclear Plant Palisades Nuclear Plant B 3.8.1-19 Revised 11/08/2012

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.8 REQUIREMENTS (continued) RG 1.9 (Ref. 5) recommends demonstration once per 18 months that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , > 120 minutes of which is at a load above its analyzed peak accident loading and the remainder of the time at a load equivalent to the continuous duty rating of the DG. SR 3.8.1.8 only requires > 100 minutes at a load above the DG analyzed peak accident loading. The 100 minutes required by the SR satisfies the intent of the recommendations of the RG, but allows some tolerance between the time requirement and the DG rating. Without this tolerance, the load would have to be reduced at precisely 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months to satisfy the SR without exceeding the manufacturer's rating of the DG.

The DG starts for this Surveillance can be performed either from standby or hot conditions.

In order to ensure that the DG is tested under load conditions that are as close to design conditions as possible, yet still provide adequate testing margin between the specified power factor limit and the DG design power factor limit of 0.8, testing must be performed using a power factor of < 0.9. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

In addition, a Note to the SR states that momentary transients outside the required band do not invalidate this test. This is to assure that a minor change in grid conditions and the resultant change in DG load, or a similar event, does not result in a surveillance being unnecessarily repeated.

During the period when the DG is paralleled to the grid, it must be considered inoperable. This is because there are no provisions to automatically shift the DG controls from parallel mode to unit mode.

Additionally, when paralleled, there are certain conditions where the protection schemes may not prevent DG overloading and subsequent breaker trip and lockout.

The 18-month Frequency is consistent with the recommendations of RG 1.9 (Ref. 5).

Revised 11/08/2012 Palisades Nuclear Palisades Plant Nuclear Plant B 3.8.1-20 B 3.8.1-20 Revised 11/08/2012

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.9 REQUIREMENTS (continued) As recommended by RG 1.9 (Ref. 5), this Surveillance ensures that the manual synchronization and load transfer from the DG to the offsite source can be made and that the DG can be returned to ready to load status when offsite power is restored. The test is performed while the DG is supplying its associated 2400 V bus, but not necessarily carrying the sequenced accident loads. The DG is considered to be in ready to load status when the DG is at rated speed and voltage, the output breaker is open, the automatic load sequencer is reset, and the DG controls are returned to "Unit."

During the period when the DG is paralleled to the grid, it must be considered inoperable. This is because there are no provisions to automatically shift the DG controls from parallel mode to unit mode.

Additionally, when paralleled, there are certain conditions where the protection schemes may not prevent DG overloading and subsequent breaker trip and lockout.

The Frequency of 18 months is consistent with the recommendations of RG 1.9 (Ref. 5).

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

Revised 11/08/2012 Palisades Nuclear Plant Palisades Nuclear Plant B 3.8.1-21 B 3.8.1-21 Revised 11/08/2012

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.10 REQUIREMENTS (continued) If power is lost to bus 1C or 1D, loads are sequentially connected to the bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs by concurrent motor starting currents. The 0.3-second load sequence time tolerance ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load and ensures that safety analysis assumptions regarding ESF equipment time delays are met. Logic Drawing E-1 7 Sheet 4 (Ref. 7) provides a summary of the automatic loading of safety related buses.

The Frequency of 18 months is consistent with the recommendations of RG 1.9 (Ref. 5), takes into consideration plant conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.11 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, PCS, and containment design limits are not exceeded.

The requirement to energize permanently connected loads is met when the DG breaker closes, energizing its associated 2400 V bus.

Permanently connected loads are those that are not disconnected from the bus by load shedding relays. They are energized when the DG breaker closes. It is not necessary to monitor each permanently connected load. The DG auto-start and breaker closure time of 10 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. For this test, the 10-second timing is started when the DG receives a start signal, and ends when the DG breaker closes. The safety analyses assume 11 seconds from the loss of power until the bus is re-energized.

Revised 11/08/2012 Palisades Nuclear Palisades Plant Nuclear Plant B 3.8.1-22 B 3.8.1-22 Revised 11/08/2012

AC Sources - Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.11 (continued)

REQUIREMENTS In addition, a Note to the SR states that momentary transients outside the required band do not invalidate this test. This is to assure that a minor change in grid conditions and the resultant change in DG load, or a similar event, does not result in a surveillance being unnecessarily repeated.

The requirement to verify that auto-connected shutdown loads are energized refers to those loads that are actuated by the DBA Sequencer. Each load should be started to assure that the DG is capable of accelerating these loads at the intervals programmed for the DBA Sequence. Since the containment spray pumps do not actuate on SIS generated by Pressure Low Pressure, the test should be performed such that spray pump starting by the sequencer is also verified along with the other SIS loads. The sequenced pumps may be operating on recirculation flow or in other testing modes. The requirements to maintain steady state voltage and frequency apply to the "steady state" period after all sequenced loads have been started. This period need only be long enough to achieve and measure steady voltage and frequency.

The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved. The requirement to supply permanently connected loads for _>5 minutes, refers to the duration of the DG connection to the associated 2400 V bus. It is not intended to require that sequenced loads be operated throughout the 5-minute period. It is not necessary to monitor each permanently connected load.

The Frequency of 18 months takes into consideration plant conditions required to perform the Surveillance and is intended to be consistent with an expected fuel cycle length of 18 months.

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

Revised 11/08/2012 Palisades Nuclear Plant Palisades Nuclear Plant B 3.8.1-23 B 3.8.1-23 Revised 11/08/2012

AC Sources - Operating B 3.8.1 BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 17

2. Regulatory Guide 1.93, December 1974

3. Generic Letter 84-15, July 2, 1984

4. 10 CFR 50, Appendix A, GDC 18

5. Regulatory Guide 1.9, Rev. 3, July 1993

6. Regulatory Guide 1.137, Rev. 1, October 1979

7. Palisades Logic Drawing E-17, Sheet 4

8. Engineering Change 12118 Revised 11/08/2012 Palisades Nuclear Plant Nuclear Plant B 3.8.1-24 B 3.8.1-24 Revised 11/08/2012

Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 BASES 3.8 ELECTRICAL POWER SYSTEMS B 3.8.3 Diesel Fuel, Lube Oil, and Starting Air BASES BACKGROUND The Diesel Generators (DGs) are provided with a storage subsystem having a required fuel oil inventory sufficient to operate one diesel for a period of 7 days, while the DG is supplying maximum post-accident loads. The fuel oil storage subsystem is comprised of the Fuel Oil Storage Tank and a fuel oil day tank. This onsite fuel oil capacity is sufficient to operate the DG for longer than the time to replenish the onsite supply from offsite sources.

Fuel oil is transferred from the Fuel Oil Storage Tank to either day tank by either of two Fuel Transfer Systems. The fuel oil transfer system which includes fuel transfer pump P-18A can be powered by offsite power, or by either DG. However, the fuel oil transfer system which includes fuel transfer pump P-1 8B can only be powered by offsite power, or by DG 1-1.

For proper operation of the standby DGs, it is necessary to ensure the proper quality of the fuel oil. Regulatory Guide (RG) 1.137 (Ref. 1) addresses the recommended fuel oil practices as supplemented by ANSI N195-1976 (Ref. 2).

The DG lubrication system is designed to provide sufficient lubrication to permit proper operation of its associated DG under all loading conditions. The system is required to circulate the lube oil to the diesel engine working surfaces and to remove excess heat generated by friction during operation. The onsite storage is sufficient to ensure 7 days of continuous operation. This supply is sufficient supply to allow the operator to replenish lube oil from offsite sources. Implicit in this LCO is the requirement to assure, though not necessarily by testing, the capability to transfer the lube oil from its storage location to the DG oil sump, while the DG is running.

Each DG is provided with an associated starting air subsystem to assure independent start capability. The starting air system is required to have a minimum capacity with margin for a DG start attempt without recharging the air start receivers.

Palisades Nuclear Plant B 3.8.3-1 Revised 09/16/2011

Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 BASES APPLICABLE A description of the Safety Analyses applicable in MODES 1, 2, 3, and SAFETY ANALYSES 4 is provided in the Bases for LCO 3.8.1, "AC Sources - Operating";

during MODES 5 and 6, in the Bases for LCO 3.8.2, "AC Sources -

Shutdown." Since diesel fuel, lube oil, and starting air subsystems support the operation of the standby AC power sources, they satisfy Criterion 3 of 10 CFR 50.36(c)(2).

LCO Stored diesel fuel oil is required to have sufficient supply for 7 days of full accident load operation. It is also required to meet specific standards for quality. Additionally, the ability to transfer fuel oil from the storage tank to each day tank is required from each of the two transfer pumps.

Additionally, sufficient lube oil supply must be available to ensure the capability to operate at full accident load for 7 days. This requirement is in addition to the lube oil contained in the engine sump.

The starting air subsystem must provide, without the aid of the refill compressor, sufficient air start capacity, including margin, to assure start capability for its associated DG.

These requirements, in conjunction with an ability to obtain replacement supplies within 7 days, support the availability of the DGs. DG day tank fuel requirements are addressed in LCOs 3.8.1 and 3.8.2.

APPLICABILITY DG OPERABILITY is required by LCOs 3.8.1 and 3.8.2 to ensure the availability of the required AC power to shut down the reactor and maintain it in a safe shutdown condition following a loss of off-site power. Since diesel fuel, lube oil, and starting air support LCOs 3.8.1 and 3.8.2, stored diesel fuel oil, lube oil, and starting air are required to be within limits, and the fuel transfer system is required to be OPERABLE, when either DG is required to be OPERABLE.

Palisades Nuclear Plant B 3.8.3-2 Revised 09/16/2011

Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 BASES ACTIONS A..1 In this Condition, the available DG fuel oil supply is less than the required 7 day supply, but enough for at least 6 days. The fuel oil inventory equivalent to a 6 day supply is 28,592 gallons (Ref. 5). This inventory is conservatively based on an uprated 2600 kW DG capacity.

This condition allows sufficient time to obtain additional fuel and to perform the sampling and analyses required prior to addition of fuel oil to the tank. A period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is considered sufficient to complete restoration of the required inventory prior to declaring the DGs inoperable.

B.1 In this Condition, the available DG lube oil supply in storage is less than the required 7 day supply, but enough for at least 6 days. The lube oil inventory equivalent to a 6 day supply is 268 gallons (Ref. 5). This inventory is conservatively based on an uprated 2600 kW DG capacity.

This condition allows sufficient time to obtain additional lube oil. A period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is considered sufficient to complete restoration of the required inventory prior to declaring the DGs inoperable.

C.1, D.1, and E.1 Since DG 1-2 cannot power fuel transfer pump P-1 8B, without P-1 8A, DG 1-2 becomes dependant on offsite power or DG 1-1 for its fuel supply (beyond the approximately 13.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months it will operate on the day tank), and does not meet the requirement for independence. Since the condition is not as severe as the DG itself being inoperable, 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is allowed to restore the fuel transfer system to operable status prior to declaring the DG inoperable.

Without P-1 8B, either DG can still provide power to the remaining fuel transfer system. Therefore, neither DG is directly affected. Continued operation with a single remaining fuel transfer system, however, must be limited since an additional single active failure (P-1 8A) could disable the onsite power system. Because the loss of P-1 8B is less severe than the loss of one DG, a 7 day Completion Time is allowed.

If both fuel transfer systems are inoperable, the onsite AC sources are limited to about 13.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months duration. Since this condition is not as severe as both DGs being inoperable, 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months is allowed to restore one fuel transfer pump to OPERABLE status.

Palisades Nuclear Plant B 3.8.3-3 Revised 09/16/2011

Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 BASES ACTIONS F.1 (continued)

With the stored fuel oil properties, other than viscosity, and water and sediment, defined in the Fuel Oil Testing Program not within the required limits, but acceptable for short term DG operation, a period of 30 days is allowed for restoring the stored fuel oil properties. The most likely cause of stored fuel oil becoming out of limits is the addition of new fuel oil with properties that do not meet all of the limits. This 30 day period provides sufficient time to determine if new fuel oil, when mixed with stored fuel oil, will produce an acceptable mixture, or if other methods to restore the stored fuel oil properties are required. This restoration may involve feed and bleed procedures, filtering, or combinations of these procedures. Even if a DG start and load was required during this time interval and the fuel oil properties were outside limits, there is a high likelihood that the DG would still be capable of performing its intended function.

G.1 With a Required Action and associated Completion Time not met, or with diesel fuel oil, lube oil, or starting air subsystem not within limits for reasons other than addressed by Conditions A, B, or F, the associated DG may be incapable of performing its intended function and must be immediately declared inoperable.

In the event that diesel fuel oil with viscosity, or water and sediment is out of limits, this would be unacceptable for even short term DG operation. Viscosity is important primarily because of its effect on the handling of the fuel by the pump and injector system; water and sediment provides an indication of fuel contamination. When the fuel oil stored in the Fuel Oil Storage Tank is determined to be out of viscosity, or water and sediment limits, the DGs must be declared inoperable, immediately.

Palisades Nuclear Plant B 3.8.3-4 Revised 09/16/2011

Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.1 REQUIREMENTS This SR provides verification that there is an adequate inventory of fuel oil in the storage subsystem to support either DG's operation for 7 days at full post-accident load. The fuel oil inventory equivalent to a 7 day supply is 33,054 gallons (Ref. 5) when calculated in accordance with References 1 and 2. This inventory is conservatively based on an uprated 2600 kW DG capacity. The required fuel storage volume is determined using the most limiting energy content of the stored fuel.

Using the known correlation of diesel fuel oil absolute specific gravity or API gravity to energy content, the required diesel generator output, and the corresponding fuel consumption rate, the onsite fuel storage volume required for 7 days of operation can be determined. SR 3.8.3.3 requires new fuel to be tested to verify that the absolute specific gravity or API gravity is not less than the value assumed in the diesel fuel oil consumption calculations. The 7 day period is sufficient time to place the plant in a safe shutdown condition and to bring in replenishment fuel from an offsite location.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is specified to ensure that a sufficient supply of fuel oil is available, since the Fuel Oil Storage Tank is the fuel oil supply for the diesel fire pumps, heating and evaporator boilers, in addition to the DGs.

SR 3.8.3.2 This Surveillance ensures that sufficient stored lube oil inventory is available to support at least 7 days of full accident load operation for one DG. The lube oil inventory equivalent to a 7 day supply is 313 gallons and is based on an estimated consumption of 1.0% of fuel oil consumption (Ref. 5). This inventory is also conservatively based on an uprated 2600 kW DG capacity.

A 31 day Frequency is adequate to ensure that a sufficient lube oil supply is onsite, since DG starts and run times are closely monitored by the plant staff.

SR 3.8.3.3 The tests listed below are a means of determining whether new fuel oil and stored fuel oil are of the appropriate grade and have not been contaminated with substances that would have an immediate, detrimental impact on diesel engine combustion.

Testing for viscosity, specific gravity, and water and sediment is completed for fuel oil delivered to the plant prior to its being added to the Fuel Oil Storage Tank. Fuel oil which fails the test, but has not been Palisades Nuclear Plant B 3.8.3-5 Revised 09/16/2011

Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.3 (continued)

REQUIREMENTS added to the Fuel Oil Storage Tank does not imply failure of this SR and requires no specific action. If results from these tests are within acceptable limits, the fuel oil may be added to the storage tank without concern for contaminating the entire volume of fuel oil in the storage tank.

Fuel oil is tested for other of the parameters specified in ASTM D975 (Ref. 3) in accordance with the Fuel Oil Testing Program required by Specification 5.5.11. Fuel oil determined to have one or more measured parameters, other than viscosity or water and sediment, outside acceptable limits will be evaluated for its effect on DG operation.

Fuel oil which is determined to be acceptable for short term DG operation, but outside limits will be restored to within limits in accordance with LCO 3.8.3 Condition F.

SR 3.8.3.4 This Surveillance ensures that, without the aid of the refill compressor, sufficient air start capacity for each DG is available. The pressure specified in this SR is intended to reflect the acceptable margin from which successful starts can be accomplished.

The 31 day Frequency takes into account the capacity, capability, redundancy, and diversity of the AC sources and other indications available in the control room, including alarms, to alert the operator to below normal air start pressure.

SR 3.8.3.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the Fuel Oil Storage Tank once every 92 days eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it reduces the potential for water entrainment in the fuel oil during DG operation.

Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and from breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies and acceptance criteria are established in the Fuel Oil Testing Program based, in part, on those recommended by RG 1.137 (Ref. 1). This SR is for preventative maintenance.

Palisades Nuclear Plant B 3.8.3-6 Revised 09/16/2011

Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE SR 3.8.3.6 REQUIREMENTS (continued) The presence of water does not necessarily represent failure of this SR provided the accumulated water is removed in accordance with the requirements of the Fuel Oil Testing Program.

This SR demonstrates that each fuel transfer pump and the fuel transfer system controls operate and control transfer of fuel from the Fuel Oil Storage Tank to each day tank and engine mounted tank. This is required to support continuous operation of standby power sources.

This SR provides assurance that the following portions of the fuel transfer system is OPERABLE:

a. Fuel Transfer Pumps;

b. Day and engine mounted tank filling solenoid valves; and

c. Day and engine mounted tank automatic level controls.

The 92 day Frequency corresponds to the! testing requirements for pumps in the ASME Code,Section XI (Ref. 4). Additional assurance of fuel transfer system OPERABILITY is provided during the monthly starting and loading tests for each DG when the fuel oil system will function to maintain level in the day and engine mounted tanks.

REFERENCES 1. Regulatory Guide 1.137

2. ANSI N195-1976

3. ASTM Standards, D975, Table 1

4. ASME, Boiler and Pressure Vessel Code,Section XI

5. Engineering Analysis EA-EC6432-01 Palisades Nuclear Plant B 3.8.3-7 Revised 09/16/2011 I

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