Text

Submittal of Changes to Palisades Nuclear Plant Technical Specifications Bases
	ML17312A000
Person / Time
Site:	Palisades
Issue date:	11/08/2017
From:	Hardy J; Entergy Nuclear Operations
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	PNP 2017-067
	Download: ML17312A000 (107)
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Enter[?Y.

PNP 2017-067 November 8, 2017 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Entergy Nuclear Operations, Inc.

Palisades Nuclear Plant 27780 Blue Star Memorial Highway Covert, MI 49043-9530 Tel 269 764 2000 Jeffery A. Hardy Regulatory Assurance Manager

SUBJECT:

Submittal of Changes to Palisades Nuclear Plant Technical Specifications Bases Palisades Nuclear Plant Docket 50-255 Renewed Facility Operating License No. DPR-20

REFERENCES:

1. Entergy Nuclear Operations Inc. letter, PNP 2016-021, "Submittal of Changes to Palisades Nuclear Plant Technical Specifications Bases," dated April 14, 2016 (ADAMS Accession No. ML16109A045)

Dear Sir or Madam:

In accordance with Palisades Nuclear Plant (PNP) Technical Specification Section 5.5.12, "Technical Specifications (TS) Bases Control Program," which requires that changes to the TS Bases, implemented without prior Nuclear Regulatory Commission (NRC) approval, be provided to the NRC on a frequency consistent with 10 CFR 50.71 (e), Entergy Nuclear Operations, Inc. hereby submits all PNP TS Bases changes since issuance of the previous TS Bases submittal, dated April 14, 2016 (Reference 1). provides a list of the affected sections and descriptions of the changes. provides page change instructions, and copies of the revised TS Bases Title Page, the List of Effective Pages, and the TS Bases sections identified in.

This letter identifies no new commitments and no revisions to existing commitments.

PNP 2017-067 Page 2 of 2 Sincerely, JAH/jse Attachments:

1.

List of Palisades Nuclear Plant Technical Specifications Bases Changes and Descriptions of Changes

2. Page Change Instructions and Revised Technical Specifications Bases cc:

Administrator, Region III, USNRC Project Manager, Palisades, USNRC Resident Inspector, Palisades, USNRC

Date July 26,2017 ATTACHMENT 1 LIST OF PALISADES NUCLEAR PLANT TECHNICAL SPECIFICATIONS BASES CHANGES AND DESCRIPTIONS OF CHANGES Affected Bases Change Description Sections B 3.0, Bases revised to reflect license B 3.4.10, B 3.4.14, amendment 262, dated May 30, 2017 B 3.5.2, B 3.6.3, (ADAMS Accession No.

B 3.6.6, B 3.7.1, and ML17082A465), which adopted B 3.7.5 Technical Specification Task Force (TSTF) traveler TSTF-545, "TS Inservice Testing Program Removal &

Clarify SR [Surveillance Requirement]

Usage Rule Application to Section 5.5 Testing."

The amendment deleted Technical Specification (TS) 5.5.7, "Inservice Testing Program" and added a new defined term, "INSERVICE TESTING PROGRAM," to the TSs. All existing references to the "Inservice Testing Program," in the TS Surveillance Requirements (SRs) were replaced with "INSERVICE TESTING PROGRAM" so that the SRs refer to the new definition in lieu of the deleted program.

The associated TS Bases were revised to reflect the TS changes.

1 of 2

August 8, 2017 Section B 3.8.3 This Bases section was revised to clarify operability requirements for the emergency diesel generator fuel oil transfer system, to relocate a paragraph concerning the presence of water within the fuel oil storage tank from the SR 3.8.3.6 Bases to the SR 3.8.3.5 Bases since TS SR 3.8.3.5 concerns fuel oil storage tank testing, to clarify the purpose of TS SR 3.8.3.6, and to correct an editorial error in the SR 3.8.3.6 Bases.

November 8,2017 Section B 3.3.5 The Bases references section was revised to include a calculation that determined the maximum acceptable total time delay for the second level under-voltage relay that will allow safety-related loads to perform their safety function during sustained under-voltage conditions for the safety related 2400V buses.

2 of 2

ATTACHMENT 2 PAGE CHANGE INSTRUCTIONS AND REVISED TECHNICAL SPECIFICATIONS BASES 100 Pages Follow

Technical Specifications Bases Page Change Instructions Revise the Palisades Nuclear Plant Technical Specifications Bases by removing the pages identified below and inserting the revised pages. Vertical lines in the margin indicate the area of change.

TECHNICAL SPECIFICATION BASES PAGES REMOVE INSERT Palisades Tech Spec Bases Palisades Tech Spec Bases List of Effective Pages, List of Effective Pages, Revised 04/14/2016 (3 pages)

Revised 11/08/2017 (3 pages)

Tech Spec Bases Title Page, Revised Tech Spec Bases Title Page, Revised 04/14/2016 (1 page) 11/08/2017 (1 page)

Pages B 3.0 B 3.0-21, Pages B 3.0 B 3.0-21, Revised Am 262 Revised 12/03/2014 (21 pages) 07/26/2017 (21 pages)

Pages B 3.3.5 B 3.3.5-6, Pages B 3.3.5 B 3.3.5-6, Revised 11/08/2012 (6 pages)

Revised 11/08/2017 (6 pages)

Pages B 3.4.10 B 3.4.10-4, Pages B 3.4.10 B 3.4.10-4, Revised Am 189 (4 pages)

Revised Am 262 07/26/2017 (4 pages)

Pages B 3.4.14 B 3.4.14-8, Pages B 3.4.14 B 3.4.14-8, Revised Am 189 Revised Am 262 08/09/2000 (8 pages) 07/26/2017 (8 pages)

Pages B 3.5.2 B 3.5.2-12, Pages B 3.5.2 B 3.5.2-12, Revised Am 262 Revised Am 228 (12 pages) 07/26/2017 (12 pages) 1 of 2

Pages B 3.6.3 B 3.6.3-12, Pages B 3.6.3 B 3.6.3-12, Revised Am 262 Revised 04/14/2011 (12 pages) 07/26/2017 (12 pages)

Pages B 3.6.6 B 3.6.6-13, Pages B 3.6.6 B 3.6.6-13, Revised Am 262 Revised 03/15/2012 (13 pages) 07/26/2017 (13 pages)

Pages B 3.7.1 B 3.7.1-4, Pages B 3.7.1 B 3.7.1-4, Revised Am 262 Revised 08/06/2004 (4 pages) 07/26/2017 (4 pages)

Pages B 3.7.5 B 3.7.5-9, Pages B 3.7.5 B 3.7.5-9, Revised 02/24/2005 (9 pages)

Revised Am 262 07/26/2017 (9 pages)

Pages 3.8.3 3.8.3-7 Pages 3.8.3 3.8.3-7 Revised 09/16/2011 (7 pages)

Revised 08/08/2017 (7 pages) 2 of 2

PALISADES TECHNICAL SPECIFICATIONS BASES LIST OF EFFECTIVE PAGES COVERSHEET Title Page Revised 11/08/2017 TABLE OF CONTENTS Pages i and ii Revised 02119/09 TECHNICAL SPECIFICATIONS BASES 8ases 2.0 Pages 82.1.1 82.1.1-4 Revised 04/14/11 Pages 82.1.2-1-82.1.2-4 226 - Revised 04/14/16 8ases 3.0 Pages 83.0 8 3.0-21 262 - Revised 07/26/17 8ases 3.1 Pages 83.1.1 83.1.1-5 226 - Revised 04/14/16 Pages 8 3.1.2 8 3.1.2-6 Revised 09/09/03 Pages 8 3.1.3 8 3.1.3-4 189 Pages 8 3.1.4 8 3.1.4-13 Revised 07/18/07 Pages 83.1.5-1-83.1.5-7 Revised 07/02/04 Pages 8 3: 1.6 8 3.1.6-9 Revised 07/30103 Pages 83.1.7-1-83.1.7-6 Revised 05/15/07 8ases 3.2 Pages 83.2.1-1-83.2.1-11 Revised 08/06/04 Pages 83.2.2 83.2.2-3 Revised 09/28/01 Pages 83.2.3 83.2.3-3 Revised 09/28/01 Pages 83.2.4 83.2.4-3 189 - Revised 08/09/00 8ases 3.3 Pages 8 3.3.1 8 3.3.1-35 226 - Revised 04/14/16 Pages 8 3.3.2 8 3.3.2-10 226 - Revised 04/14/16 Pages 8 3.3.3 8 3.3.3-24 Revised 03/20108 Pages 8 3.3.4 8 3.3.4-12 Revised 09/09/03 Pages 8 3.3.5 8 3.3.5-6 Revised 11/08/2017 Pages 8 3.3.6 8 3.3.6-6 226 - Revised 04/14/16 Pages 83.3.7 83.3.7-12 Revised 11/08/2012 Pages 8 3.3.8 8 3.3.8-6 Revised 02/24/05 Pages 83.3.9 8 3.3.9-5 189 - Revised 08/09/00 Pages 83.3.10 83.3.10-4 226 - Revised 04/14/16 8ases 3.4 Pages 8 3.4.1 8 3.4.1-4 Revised 08/24/04 Pages 8 3.4.2 8 3.4.2-2 189 Pages 83.4.3 83.4.3-7 Revised 02/17/12 Pages 8 3.4.4 8 3.4.4-4 Revised 09/21/06 Pages 8 3.4.5 8 3.4.5-5 Revised 09/21/06 Pages 83.4.6 83.4.6-6 Revised 07/31/07 Pages 83.4.7 83.4.7-7 Revised 07/31/07 Pages 83.4.8 83.4.8-5 Revised 07/31/07 Pages 8 3.4.9 8 3.4.9-6 256 - Revised 07/29/15 Pages 83.4.10 8 3.4.10-4 262 - Revised 07/26/17 Pages 83.4.11 8 3.4.11-7 Revised 02/24/05 1

Revised 11/08/2017

PALISADES TECHNICAL SPECIFICATIONS BASES 2

LIST OF EFFECTIVE PAGES 8ases 3.4 Pages 83.4.12-1-83.4.12-13 Revised 02/17/12 (Continues)

Pages 8 3.4.13 8 3.4.13-7 226 - Revised 04/14/16 Pages 83.4.14-1-83.4.14-8 262 - Revised 07/26/17 Pages 8 3.4.15 8 3.4.15-6 Revised 02/24/05 Pages 8 3.4.16 8 3.4.16-5 226 - Revised 04/14/16 Pages 83.4.17-1-83.4.17-7 226 - Revised 04/14/16 8ases 3.5 Pages 83.5.1 83.5.1-5 189 Page 83.5.1-6 191 Page 83.5.1-7 189 Page 83.5.1-8 191 ages 83.5.2 83.5.2-12 262 - Revised 07/26/17 Pages 83.5.3 83.5.3-4 Revised 07/22/02 Pages 83.5.4 83.5.4-7 227 Pages 8 3.5.5 8 3.5.5-5 227 8ases 3.6 Pages 83.6.1 83.6.1-4 Revised 03/15/12 Pages 83.6.2 83.6.2-8 Revised 03/15/12 Pages 8 3.6.3 8 3.6.3-12 262 - Revised 07/26/17 Pages 8 3.6.4 8 3.6.4-3 Revised 03/15/12 Pages 83.6.5 83.6.5-3 Revised 03/15/12 Pages 8 3.6.6 8 3.6.6-13 262 - Revised 07/26/17 8ases 3.7 Pages 8 3.7.1 8 3.7.1 -4 262 - Revised 07/26/17 Pages 83.7.2 83.7.2-6 226 - Revised 04/14/16 Pages 83.7.3 83.7.3-5 Revised 12/02/02 Pages 83.7.4 83.7.4-4 Revised 07/16/08 Pages 83.7.5 83.7.5-9 262 - Revised 07/26/17 Pages 83.7.6 83.7.6-4 Revised 04/14/11 Pages 83.7.7 83.7.7-9 Revised 06/07105 Pages 83.7.8 83.7.8-8 Revised 10/29/09 Pages 83.7.9 83.7.9-3 Revised 04/14/11 Pages 83.7.10 83.7.10-8 256 - Revised 07/29/15 Pages 83.7.11-1-83.7.11-5 256 - Revised 07/29/15 Pages 83.7.12 83.7.12-7 226 - Revised 04/14/16 Pages 83.7.13 8 3.7.13-3 226 - Revised 04/14/16 Pages 83.7.14 83.7.14-3 226 - Revised 04/14/16 Pages 83.7.15 83.7.15-2 236 Pages 83.7.16 83.7.16-5 250 - Revised 09/15/14 Pages 83.7.17 83.7.17-3 226 - Revised 04/14/16 Revised 11/08/2017

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 08/08/17 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 B 3.8.10-3 Revised 11/06/01 Bases 3.9 Pages B 3.9.1 B 3.9.1-4 189 - Revised 08/09/00 Pages B 3.9.2 B 3.9.2-3 189 - Revised 02/12/01 Page B 3.9.3 B 3.9.3-6 226 - Revised 04/14/16 Pages B 3.9.4 B 3.9.4-4 Revised 07/31/07 Pages B 3.9.5 B 3.9.5-4 Revised 07/31/07 Pages B 3.9.6 B 3.9.6-3 226 - Revised 04/14/16 Revised 11/08/2017

PALISADES PLANT FACILITY OPERATING LICENSE DPR-20 APPENDIX A TECHNICAL SPECIFICATIONS BASES Revised 11/08/201 7

LCO Applicability B3.0 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY BASES LCO LCO 3.0.1 LCO 3.0.2 LCO 3.0.1 through LCO 3.0.9 establish the general requirements applicable to all Specifications and apply at all times unless otherwise stated.

LCO 3.0.1 establishes the Applicability statement within each individual Specification as the requirement for when the LCO is required to be met (Le., when the plant is in the MODES or other specified conditions of the Applicability statement of each Specification).

LCO 3.0.2 establishes that upon discovery of a failure to meet an LCO, the associated ACTIONS shall be met. The Completion Time of each Required Action for an ACTIONS Condition is applicable from the point in time that an ACTIONS Condition is entered. The Required Actions establish those remedial measures that must be taken within specified Completion Times when the requirements of an LCO are not met. This Specification establishes that:

a.

Completion of the Required Actions within the specified Completion Times constitutes compliance with a Specification; and

b.

Completion of the Required Actions is not required when an LCO is met within the specified Completion Time, unless otherwise specified.

There are two basic types of Required Actions. The first type of Required Action specifies a time limit in which the LCO must be met. This time limit is the Completion Time to restore an inoperable system or component to OPERABLE status or to restore variables to within specified limits.

If this type of Required Action is not completed within the specified Completion Time, a shutdown may be required to place the plant in a MODE or condition in which the Specification is not applicable. (Whether stated as a Required Action or not, correction of the entered Condition is an action that may always be considered upon entering ACTIONS.)

Palisades Nuclear Plant B 3.0-1 Revised 07/26/2017

BASES LCO 3.0.2 (continued)

LCO Applicability B 3.0 The second type of Required Action specifies the remedial measures that permit continued operation of the plant that is not further restricted by the Completion Time. In this case, compliance with the Required Actions provides an acceptable level of safety for continued operation.

Completing the Required Actions is not required when an LCO is met or is no longer applicable, unless otherwise stated in the individual Specifications.

The nature of some Required Actions of some Conditions necessitates that, once the Condition is entered, the Required Actions must be completed even though the associated Conditions no longer exist. The individual LCO's ACTIONS specify the Required Actions where this is the case. An example of this is in LCO 3.4.3, "PCS Pressure and Temperature (PfT) Limits."

The Completion Times of the Required Actions are also applicable when a system or component is removed from service intentionally. The reasons for intentionally relying on the ACTIONS include, but are not limited to, performance of Surveillances, preventive maintenance, corrective maintenance, or investigation of operational problems.

Entering ACTIONS for these reasons must be done in a manner that does not compromise safety. Intentional entry into ACTIONS should not be made for operational convenience. Additionally, if intentional entry into ACTIONS would result in redundant equipment being inoperable, alternatives should be used instead. Doing so limits the time both subsystems/trains of a safety function are inoperable and limits the time conditions exist which may result in LCO 3.0.3 being entered. Individual Specifications may specify a time limit for performing an SR when equipment is removed from service or bypassed for testing. In this case, the Completion Times of the Required Actions are applicable when this time limit expires, if the equipment remains removed from service or bypassed.

When a change in MODE or other specified condition is required to comply with Required Actions, the plant may enter a MODE or other specified condition in which another Specification becomes applicable.

In this case, the Completion Times of the associated Required Actions would apply from the point in time that the new Specification becomes applicable and the ACTIONS Condition(s) are entered.

Palisades Nuclear Plant B 3.0-2 Revised 07/26/2017

BASES LCO 3.0.3 LCO Applicability B 3.0 LCO 3.0.3 establishes the actions that must be implemented when an LCO is not met and:

a.

An associated Required Action and Completion Time is not met and no other Condition applies; or

b.

The condition of the plant is not specifically addressed by the associated ACTIONS. This means that no combination of Conditions stated in the ACTIONS can be made that exactly corresponds to the actual condition of the plant. Sometimes, possible combinations of Conditions are such that entering LCO 3.0.3 is warranted; in such cases, the ACTIONS specifically state a Condition corresponding to such combinations and also that LCO 3.0.3 be entered immediately.

This Specification delineates the time limits for placing the plant in a safe MODE or other specified condition when operation cannot be maintained within the limits for safe operation as defined by the LCO and its ACTIONS. It is not intended to be used as an operational convenience that permits routine voluntary removal of redundant systems or components from service in lieu of other alternatives that would not result in redundant systems or components being inoperable.

Upon entering LCO 3.0.3, 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to prepare for an orderly shutdown before initiating a change in plant operation. This includes time to permit the operator to coordinate the reduction in electrical generation with the load dispatcher to ensure the stability and availability of the electrical grid. The time limits specified to reach lower MODES of operation permit the shutdown to proceed in a controlled and orderly manner that is well within the specified maximum cooldown rate and within the capabilities of the plant, assuming that only the minimum required equipment is OPERABLE. This reduces thermal stresses on components of the Primary Coolant System and the potential for a plant upset that could challenge safety systems under conditions to which this Specification applies. The use and interpretation of specified times to complete the actions of LCO 3.0.3 are consistent with the discussion of Section 1.3, Completion Times.

Palisades Nuclear Plant B 3.0-3 Revised 07/26/2017

BASES LCO 3.0.3 (continued)

LCO Applicability B3.0 A plant shutdown required in accordance with LCO 3.0.3 may be terminated and LCO 3.0.3 exited if any of the following occurs:

a.

The LCO is now met.

b.

A Condition exists for which the Required Actions have now been performed.

c.

ACTIONS exist that do not have expired Completion Times. These Completion Times are applicable from the point in time that the Condition is initially entered and not from the time LCO 3.0.3 is exited.

The time limits of Specification 3.0.3 allow 37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months for the plant to be in MODE 5 when a shutdown is required during MODE 1 operation. If the plant is in a lower MODE of operation when a shutdown is required, the time limit for reaching the next lower MODE applies. If a lower MODE is reached in less time than allowed, however, the total allowable time to reach MODE 5, or other applicable MODE, is not reduced. For example, if MODE 3 is reached in 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , then the time allowed for reaching MODE 4 is the next 29 hours3.356481e-4 days 0.00806 hours 4.794974e-5 weeks 1.10345e-5 months , because the total time for reaching MODE 4 is not reduced from the allowable limit of 31 hours3.587963e-4 days 0.00861 hours 5.125661e-5 weeks 1.17955e-5 months . Therefore, if remedial measures are completed that would permit a return to MODE 1, a penalty is not incurred by having to reach a lower MODE of operation in less than the total time allowed.

In MODES 1,2,3, and 4, LCO 3.0.3 provides actions for Conditions not covered in other Specifications. The requirements of LCO 3.0.3 do not apply in MODES 5 and 6 because the plant is already in the most restrictive Condition required by LCO 3.0.3.

The requirements of LCO 3.0.3 do not apply in other specified conditions of the Applicability (unless in MODE 1,2,3, or 4) because the ACTIONS of individual Specifications sufficiently define the remedial measures to be taken. Exceptions to LCO 3.0.3 are provided in instances where requiring a plant shutdown, in accordance with LCO 3.0.3, would not provide appropriate remedial measures for the associated condition of the plant.

An example of this is in LCO 3.7.14, "Spent Fuel Pool Water Level."

Palisades Nuclear Plant B 3.0-4 Revised 07/26/2017

BASES LCD 3.0.3 (continued)

LCD 3.0.4 LCD Applicability B 3.0 LCD 3.7.14 has an Applicability of "During movement of irradiated fuel assemblies in the spent fuel pooL" Therefore, this LCD can be applicable in any or all MODES. If the LCD and the Required Actions of LCD 3.7.14 are not met while in MODE 1, 2, or 3, there is no safety benefit to be gained by placing the plant in a shutdown condition. The Required Action of LCD 3.7.14 of "Suspend movement of irradiated fuel assemblies in spent fuel pool" is the appropriate Required Action to complete in lieu of the actions of LCD 3.0.3. These exceptions are addressed in the individual Specifications.

LCD 3.0.4 establishes limitations on changes in MODES or other specified conditions in the Applicability when an LCD is not met. It allows placing the plant in a MODE or other specified condition stated in that Applicability (e.g., the Applicability desired to be entered) when plant conditions are such that the requirements of the LCD would not be met, in accordance with LCD 3.0.4.a, LCO 3.0.4.b, or LCD 3.0.4.c.

LCD 3.0.4.a allows entry into a MODE or other specified condition in the Applicability with the LCD not met when the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time. Compliance with Required Actions that permit continued operation of the plant for an unlimited period of time in a MODE or other specified condition provides an acceptable level of safety for continued operation. This is without regard to the status of the plant before or after the MODE change.

Therefore, in such cases, entry into a MODE or other specified condition in the Applicability may be made in accordance with the provisions of the Required Actions.

LCD 3.0.4.b allows entry into a MODE or other specified condition in the Applicability with the LCD not met after performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, if appropriate.

The risk assessment may use quantitative, qualitative, or blended approaches, and the risk assessment will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR50.65(a)(4), which requires that risk impacts of maintenance activities to be assessed and managed. The risk assessment, for purposes of LCD 3.0.4.b, must take into account all inoperable Technical Specification equipment regardless of whether the equipment is included in the normal 1 0 CFR 50.65(a)(4) risk assessment scope.

Palisades Nuclear Plant B 3.0-5 Revised 07/26/2017

BASES LCO 3.0.4 (continued)

LCO Applicability B 3.0 The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants."

Regulatory Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." These documents address general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management actions, and example risk management actions. These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of backup success paths or compensatory measures), and determination that the proposed MODE change is acceptable. Consideration should also be given to the probability of completing restoration such that the requirements of the LCO would be met prior to the expiration of ACTIONS Completion Times that would require exiting the Applicability.

LCO 3.0.4.b may be used with single, or multiple systems and components unavailable. NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components.

The results of the risk assessment shall be considered in determining the acceptability of entering the MODE or other specified condition in the Applicability, and any corresponding risk management actions. The LCO 3.0.4.b risk assessments do not have to be documented.

The Technical Specifications allow continued operation with equipment unavailable in MODE 1 for the duration of the Completion Time. Since this is allowable, and since in general the risk impact in that particular MODE bounds the risk of transitioning into and through the applicable MODES or other specified conditions in the Applicability of the LCO, the use of the LCO 3.0.4.b allowance should be generally acceptable, as long as the risk is assessed and managed as stated above. However, there is a small subset of systems and components that have been determined to be more important to risk and use of the LCO 3.0.4.b allowance is prohibited. The LCOs governing these system and components contain Notes prohibiting the use of LCO 3.0.4.b by stating that LCO 3.0.4.b is not applicable.

Palisades Nuclear Plant B 3.0-6 Revised 07/26/2017

BASES LCO 3.0.4 (continued)

LCO Applicability B 3.0 LCO 3.0.4.c allows entry into a MODE or other specified condition in the Applicability with the LCO not met based on a Note in the Specification which states LCO 3.0.4.c is applicable. These specific allowances permit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not provide for continued operation for an unlimited period of time and a risk assessment has not been performed. This allowance may apply to all the ACTIONS or to a specific Required Action of a Specification. The risk assessments performed to justify the use of LCO 3.0.4.b usually only consider systems and components. For this reason, LCO 3.0.4.c is typically applied to Specifications which describe values and parameters (e.g., primary coolant system specific activity), and may be applied to other Specifications based on NRC plant-specific approval.

The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

The provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any plant shutdown. In this context, a plant shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, MODE 3 to MODE 4, and MODE 4 to MODE 5.

Upon entry into a MODE or other specified condition in the Applicability with the LCO not met, LCO 3.0.1 and 3.0.2 require entry into the applicable Conditions and Required Actions until the Condition is resolved, until the LCO is met, or until the plant is not within the Applicability of the Technical Specification.

Surveillances do not have to be performed on the associated inoperable equipment (or on variables outside the specified limits), as permitted by SR 3.0.1. Therefore, utilizing LCO 3.0.4 is not a violation of SR 3.0.1 or SR 3.0.4 for any Surveillances that have not been performed on inoperable equipment. However, SRs must be met to ensure OPERABILITY prior to declaring the associated equipment OPERABLE (or variable within limits) and restoring compliance with the affected LCO.

Palisades Nuclear Plant B 3.0-7 Revised 07/26/2017

BASES LCO 3.0.5 LCO 3.0.6 LCO Applicability B3.0 LCO 3.0.5 establishes the allowance for restoring equipment to service under administrative controls when it has been removed from service or declared inoperable to comply with ACTIONS. The sole purpose of this Specification is to provide an exception to LCO 3.0.2 (e.g., to not comply with the applicable Required Action(s)) to allow the performance of required testing to demonstrate:

a.

The OPERABILITY of the equipment being returned to service; or

b.

The OPERABILITY of other equipment.

The administrative controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the required testing to demonstrate OPERABILITY. This Specification does not provide time to perform any other preventive or corrective maintenance.

An example of demonstrating the OPERABILITY of the equipment being returned to service is reopening a containment isolation valve that has been closed to comply with Required Actions and must be reopened to perform the required testing.

An example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to prevent the trip function from occurring during the performance of required testing on another channel in the other trip system. A similar example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to permit the logic to function and indicate the appropriate response during the performance of required testing on another channel in the same trip system.

LCO 3.0.6 establishes an exception to LCO 3.0.2 for supported systems that have a support system LCO specified in the Technical Specifications (TS). This exception is provided because LCO 3.0.2 would require that the Conditions and Required Actions of the associated inoperable supported system LCO be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the plant is maintained in a safe condition are specified in the support system LCO's Required Actions. These Required Actions may include entering the supported system's Conditions and Required Actions or may specify other Required Actions.

Palisades Nuclear Plant B 3.0-8 Revised 07/26/2017

BASES LCO 3.0.6 (continued)

LCO Applicability B3.0 When a support system is inoperable and there is an LCO specified for it in the TS, the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' LCO's Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the plant is maintained in a safe condition in the support system's Required Actions.

However, there are instances where a support system's Required Action may either direct a supported system to be declared inoperable or direct entry into Conditions and Required Actions for the supported system.

This may occur immediately or after some specified delay to perform some other Required Action. Regardless of whether it is immediate or after some delay, when a support system's Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with LCO 3.0.2.

Specification 5.5.13, "Safety Functions Determination Program (SFDP),"

ensures loss of safety function is detected and appropriate actions are taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other limitations, remedial actions, or compensatory actions may be identified as a result of the support system inoperability and corresponding exception to entering supported system Conditions and Required Actions. The SFDP implements the requirements of LCO 3.0.6.

Cross train checks to identify a loss of safety function for those support systems that support multiple and redundant safety systems are required.

The cross train check verifies that the supported systems of the redundant OPERABLE support system are OPERABLE, thereby ensuring safety function is retained.

If this evaluation determines that a loss of safety function exists, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

Palisades Nuclear Plant B 3.0-9 Revised 07/26/2017

BASES LCO 3.0.7 LCO Applicability B 3.0 Special tests and operations are required at various times over the plant's life to demonstrate performance characteristics, to perform maintenance activities, and to perform special evaluations. Because TS normally preclude these tests and operations, Special Test Exceptions (STEs) allow specified requirements to be changed or suspended under controlled conditions. STEs are included in applicable sections of the Specifications. Unless otherwise specified, all other TS requirements remain unchanged and in effect as applicable. This will ensure that all appropriate requirements of the MODE or other specified condition not directly associated with or required to be changed or suspended to perform the special test or operation will remain in effect.

The Applicability of an STE LCO represents a condition not necessarily in compliance with the normal requirements of the TS. Compliance with STE LCO is optional.

A special test may be performed under either the provisions of the appropriate STE LCO or the other applicable TS requirements. If it is desired to perform the special test under the provisions of the STE LCO, the requirements of the STE LCO shall be followed. This includes the SRs specified in the STE LCO.

Some of the STE LCO require that one or more of the LCO for normal operation be met (i.e., meeting the STE LCO requires meeting the specified normal LCO). The Applicability, ACTIONS, and SRs of the specified normal LCO, however, are not required to be met in order to meet the STE LCO when it is in effect. This means that, upon failure to meet a specified normal LCO, the associated ACTIONS of the STE LCO apply, in lieu of the ACTIONS of the normal LCO. Exceptions to the above do exist. There are instances when the Applicability of the specified normal LCO must be met, where its ACTIONS must be taken, where certain of its Surveillances must be performed, or where all of these requirements must be met concurrently with the requirements of the STE LCO.

Unless the SRs of the specified normal LCO are suspended or changed by the special test, those SRs that are necessary to meet the specified normal LCO must be met prior to performing the special test. During the conduct of the special test, those Surveillances need not be performed unless specified by the ACTIONS or SRs of the STE LCO.

ACTIONS for STE LCO provide appropriate remedial measures upon failure to meet the STE LCO. Upon failure to meet these ACTIONS, suspend the performance of the special test and enter the ACTIONS for all LCOs that are then not met. Entry into LCO 3.0.3 may possibly be required, but this determination should not be made by considering only the failure to meet the ACTIONS of the STE LCO.

Palisades Nuclear Plant B3.0-10 Revised 07/26/2017

BASES LCO 3.0.8 LCO Applicability B 3.0 LCO 3.0.8 establishes conditions under which systems are considered to remain (continued) capable of performing their intended safety function when associated snubbers are not capable of providing their associated support function(s). This LCO states that the supported system is not considered to be inoperable solely due to one or more snubbers not capable of performing their associated support function(s). This is appropriate because a limited length of time is allowed for maintenance, testing, or repair of one or more snubbers not capable of performing their associated support function(s) and appropriate compensatory measures are specified in the snubber requirements, which are located outside of the Technical Specifications (TS). The snubber requirements do not meet the criteria in 10 CFR 50.36(c)(2)(ii), and, as such, are appropriate for administrative control.

If the allowed time expires and the snubber(s) are unable to perform their associated support function(s), the affected supported system's LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3.0.2.

Every time that the provisions of LCO 3.0.8 are applied it is required to confirm that at least one train (or subsystem) of systems supported by the inoperable snubbers would remain capable of performing their required safety or support functions for postulated design loads other than seismic loads. LCO 3.0.8 does not apply to non-seismic snubbers (Le., seismic vs non-seismic), implementation of this restriction, and the associated plant configuration shall be available on a recoverable basis for NRC staff inspection. SEP-SNB-PLP-001, "Snubber Examination and Testing Program," may be used as a reference for application of LCO 3.0.8 to site specific snubbers.

LCO 3.0.8.a applies when one or more snubbers are not capable of providing their associated support function(s) to a single train or subsystem of a multiple train or subsystem supported system or to a single train or subsystem supported system. LCO 3.0.8.a allows 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to restore the snubber(s) before declaring the supported system inoperable. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function and due to the availability of the redundant train of the supported system.

When applying LCO 3.0.8.a at least one AFW train (including a minimum set of supporting equipment required for its successful operation), or some alternative means of core cooling, not associated with the inoperable snubber(s), must be available. Implementation of this restriction and the associated plant configuration shall be available on a recoverable basis for NRC staff inspection.

LCO 3.0.8.b applies when one or more snubbers are not capable of providing their associated support function(s) to more than one train or subsystem of a multiple train or subsystem supported system. LCO 3.0.8.b allows 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to restore the snubber(s) before declaring the supported system inoperable. The 12 Palisades Nuclear Plant B3.0-11 Revised 07/26/2017

BASES LCO Applicability B 3.0 LCO 3.0.8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable based on the low probability of a seismic (continued) event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function.

LCO 3.0.9 When applying LCO 3.0.8.b at least one AFW train (including a minimum set of supporting equipment required for its successful operation) not associated with the inoperable snubber(s), or some alternative means of core cooling (e.g., F&B, fire water system or "aggressive secondary cooldown" using the steam generators) must be available. Implementation of this restriction and the associated plant configuration shall be available on a recoverable basis for NRC staff inspection.

LCO 3.0.8 requires that risk be assessed and managed. Industry and NRC guidance on the implementation of 10 CFR SO.6S(a)(4) (the Maintenance Rule) does not address seismic risk. However, use of LCO 3.0.8 should be considered with respect to other plant maintenance activities, and integrated into the existing Maintenance Rule process to the extent possible so that maintenance on any unaffected train or subsystem is properly controlled, and emergent issues are properly addressed. The risk assessment need not be quantified, but may be a qualitative awareness of the vulnerability of systems and components when one or more snubbers are not able to perform their associated support function.

LCO 3.0.9 establishes conditions under which systems described in the Technical Specifications are considered to remain OPERABLE when required barriers are not capable of providing their related support function(s).

Barriers are doors, walls, floor plugs, curbs, hatches, installed structures or components, or other devices, not explicitly described in Technical Specifications, that support the performance of the safety function of systems described in the Technical Specifications. This LCO states that the supported system is not considered to be inoperable solely due to required barriers not capable of performing their related support function(s) under the described conditions. LCO 3.0.9 allows 30 days before declaring the supported system(s) inoperable and the LCO(s) associated with the supported system(s) not met. A maximum time is placed on each use of this allowance to ensure that as required barriers are found or are otherwise made unavailable, they are restored.

However, the allowable duration may be less than the specified maximum time based on the risk assessment.

If the allowed time expires and the barriers are unable to perform their related support function(s), the supported system's LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3.0.2.

Palisades Nuclear Plant B3.0-12 Revised 07/26/2017

BASES LCO Applicability B3.0 LCO 3.0.9 This provision does not apply to barriers which support ventilation systems or to (continued) fire barriers. The Technical Specifications for ventilation systems provide specific Conditions for inoperable barriers. Fire barriers are addressed by other regulatory requirements and associated plant programs. This provision does not apply to barriers which are not required to support system OPERABILITY (see NRC Regulatory Issue Summary 2001-09, "Control of Hazard Barriers," dated April 2, 2001).

The provisions of LCO 3.0.9 are justified because of the low risk associated with required barriers not being capable of performing their related support function.

This provision is based on consideration of the following initiating event categories:

Loss of coolant accidents; High energy line breaks; Feedwater line breaks; Internal flooding; External flooding; Turbine missile ejection; and Tornado or high wind.

The risk impact of the barriers which cannot perform their related support function(s) must be addressed pursuant to the risk assessment and management provision of the Maintenance Rule, 10 CFR 50.65 (a)(4), and the associated implementation guidance, Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." Regulatory Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." This guidance provides for the consideration of dynamic plant configuration issues, emergent conditions, and other aspects pertinent to plant operation with the barriers unable to perform their related support function(s).

These considerations may result in risk management and other compensatory actions being required during the period that barriers are unable to perform their related support function(s).

LCO 3.0.9 may be applied to one or more trains or subsystems of a system supported by barriers that cannot provide their related support function(s),

provided that risk is assessed and managed (including consideration of the effects on Large Early Release and from external events). If applied concurrently to more than one train or subsystem of a multiple train or subsystem supported system, the barriers supporting each of these trains or subsystems must provide their related support function(s) for different categories of initiating events. For example, LCO 3.0.9 may be applied for up to 30 days for more than one train of a multiple train supported system if the affected barrier for one train protects against internal flooding and the affected barrier for the other train protects against tornado missiles. In this example, the affected barrier may be the same physical barrier but serve different protection functions for each train.

Palisades Nuclear Plant B 3.0-13 Revised 07/26/2017

BASES LCO Applicability B 3.0 LCO 3.0.9 If during the time that LCO 3.0.9 is being used, the required OPERABLE train or (continued) subsystem becomes inoperable, it must be restored to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Otherwise, the train(s) or subsystem(s) supported by barriers that cannot perform their related support function(s) must be declared inoperable and the associated LCOs declared not met. This 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period provides time to respond to emergent conditions that would otherwise likely lead to entry into LCO 3.0.3 and a rapid plant shutdown, which is not justified given the low probability of an initiating event which would require the barrier(s) not capable of performing their related support function(s). During this 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period, the plant risk associated with the existing conditions is assessed and managed in accordance with 10 CFR 50.65(a)(4).

Palisades Nuclear Plant B3.0-14 Revised 07/26/2017

SR Applicability B 3.0 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY BASES SRs SR 3.0.1 SR 3.0.1 through SR 3.0.4 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated. SR 3.0.2 and SR 3.0.3 apply in Chapter 5 only when invoked by a Chapter 5 specification.

SR 3.0.1 establishes the requirement that SRs must be met during the MODES or other specified conditions in the Applicability for which the requirements of the LCO apply, unless otherwise specified in the individual SRs. This Specification is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with SR 3.0.2, constitutes a failure to meet an LCO. Surveillances may be performed by means of any series of sequential, overlapping, or total steps provided the entire Surveillance is performed within the specified Frequency. Additionally, the definitions related to instrument testing (e.g., CHANNEL CALIBRATION) specify that these tests are performed by means of any series of sequential, overlapping, or total steps.

Systems and components are assumed to be OPERABLE when the associated SRs have been met. Nothing in this Specification, however, is to be construed as implying that systems or components are OPERABLE when:

a.

The systems or components are known to be inoperable, although still meeting the SRs; or

b.

The requirements of the Surveillance(s) are known to be not met between required Surveillance performances.

Surveillances do not have to be performed when the plant is in a MODE or other specified condition for which the requirements of the associated LCO are not applicable, unless otherwise specified. The SRs associated with a Special Test Exception (STE) are only applicable when the STE is used as an allowable exception to the requirements of a Specification.

Unplanned events may satisfy the requirements (including applicable acceptance criteria) for a given SR. In this case, the unplanned event may be credited as fulfilling the performance of the SA. This allowance includes those SRs whose performance is normally precluded in a given MODE or other specified condition.

Palisades Nuclear Plant B3.0-15 Amendment No. 262 Revised 07/26/2017

BASES SR 3.0.1 (continued)

SR 3.0.2 SR Applicability B3.0 Surveillances, including Surveillances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with SR 3.0.2, prior to returning equipment to OPERABLE status.

Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with SR 3.0.2. Post maintenance testing may not be possible in the current MODE or other specified conditions in the Applicability due to the necessary plant parameters not having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and the equipment is not otherwise believed to be incapable of performing its function. This will allow operation to proceed to a MODE or other specified condition where other necessary post maintenance tests can be completed.

An example of this process is:

a.

High Pressure Safety Injection (HPSI) maintenance during shutdown that requires system functional tests at a specified pressure. Provided other appropriate testing is satisfactorily completed, startup can proceed with HPSI considered OPERABLE.

This allows operation to reach the specified pressure to complete the necessary post maintenance testing.

SR 3.0.2 establishes the requirements for meeting the specified Frequency for Surveillances and any Required Action with a Completion Time that requires the periodic performance of the Required Action on a "once per... " interval.

SR 3.0.2 permits a 25% extension of the interval specified in the Frequency. This extension facilitates Surveillance scheduling and considers plant operating conditions that may not be suitable for conducting the Surveillance (e.g., transient conditions or other ongoing Surveillance or maintenance activities).

When a Section 5.5, "Programs and Manuals," specification states that the provisions of SR 3.0.2 are applicable, a 25% extension of the testing interval, whether stated in the specification or incorporated by reference, is permitted.

Palisades Nuclear Plant B 3.0-16 Amendment No. 262 Revised 07/26/2017

BASES SR 3.0.2 (continued)

SR Applicability B 3.0 The 2S% extension does not significantly degrade the reliability that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the SRs.

The exceptions to SR 3.0.2 are those Surveillances for which the 2S%

extension of the interval specified in the Frequency does not apply. These exceptions are stated in the individual Specifications. Examples of where SR 3.0.2 does not apply are the Containment Leak Rate Testing Program required by 10 CFR SO, Appendix J, and the American Society of Mechanical Engineers (ASME) Code inservice testing required by 10 CFR SO.SSa. These programs establish testing requirements and frequencies in accordance with the requirements of regulations. The TS cannot, in and of themselves, extend a test interval specified in the regulations directly or by reference.

As stated in SR 3.0.2, the 2S% extension allowed by SR 3.0.2 may be applied to Required Actions whose Completion Time is stated as "once per... " however, the 2S% 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 2S% extension applies to each performance of the Required Action after the initial performance. The initial performance of the Required Action, whether it is a particular Surveillance or some other remedial action, is considered a single action with a single Completion Time. One reason for not allowing the 2S% extension to this Completion Time is that such an action usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or accomplishes the function of the inoperable equipment in an alternative manner.

The provisions of SR 3.0.2 are not intended to be used repeatedly merely as an operational convenience to extend Surveillance intervals (other than those consistent with refueling intervals) or periodic Completion Time intervals beyond those specified.

Palisades Nuclear Plant B3.0-17 Amendment No. 262 Revised 07/26/2017

BASES SR 3.0.3 SR Applicability B3.0 SR 3.0.3 establishes the flexibility to defer declaring affected equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been completed within the specified Frequency. A delay period of up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or up to the limit of the specified Frequency, whichever is greater, applies from the pOint in time that it is discovered that the Surveillance has not been performed in accordance with SR 3.0.2, and not at the time that the specified Frequency was not met.

When a Section 5.5, "Programs and Manuals," specification states that the provisions of SR 3.0.3 are applicable, it permits the flexibility to defer declaring the testing requirement not met in accordance with SR 3.0.3 when the testing has not been completed within the testing interval (including the allowance of SR 3.0.2 if invoked by the Section 5.5 specification).

This delay period provides an adequate time to complete Surveillances that have been missed. This delay period permits the completion of a Surveillance before complying with Required Actions or other remedial measures that might preclude completion of the Surveillance.

The basis for this delay period includes consideration of plant conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements. When a Surveillance with a Frequency based not on time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering MODE 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, SR 3.0.3 allows for the full delay period of up to the specified Frequency to perform the Surveillance.

However, since there is not a time interval specified, the missed Surveillance should be performed at the first reasonable opportunity.

SR 3.0.3 provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.

Failure to comply with specified Frequencies for SRs is expected to be an infrequent occurrence. Use of the delay period established by SR 3.0.3 is a flexibility which is not intended to be used as an operational convenience to extend Surveillance intervals.

Palisades Nuclear Plant B 3.0-18 Amendment No. 262 Revised 07/26/2017

BASES SR 3.0.3 (continued)

SR Applicability B 3.0 While up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or the limit of the specified Frequency is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be performed at the first reasonable opportunity. The determination of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, availability of personnel, and the time required to perform the Surveillance. This risk impact should be managed through the program in place to implement 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensurate with the importance of the component. Missed Surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to determine the safest course of action. All missed Surveillances will be placed in the licensee's Corrective Action Program.

If a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable is considered outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon expiration of the delay period. If a Surveillance is failed within the delay period, then the equipment is inoperable, or the variable is outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon the failure of the Surveillance.

Completion of the Surveillance within the delay period allowed by this Specification, or within the Completion Time of the ACTIONS, restores compliance with SR 3.0.1.

Palisades Nuclear Plant B3.0-19 Revised 07/26/2017

BASES SR 3.0.4 SR Applicability B3.0 SR 3.0.4 establishes the requirement that all applicable SRs must be met before entry into a MODE or other specified Condition in the Applicability.

This Specification ensures that system and component OPERABILITY requirements and variable limits are met before entry into MODES or other specified conditions in the Applicability for which these systems and components ensure safe operation of the plant.

The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability. A provision is included to allow entry into a MODE or other specified condition in the Applicability when an LCO is not met due to Surveillance not being met in accordance with LCO 3.0.4.

However, in certain circumstances, failing to meet an SR will not result in SR 3.0.4 restricting a MODE change or other specified condition change. When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated SR(s) are not required to be performed, per SR 3.0.1, which states that surveillances do not have to be performed on inoperable equipment.

When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed.

Therefore, failing to perform the Surveillance(s) within the specified Frequency does not result in an SR 3.0.4 restriction to changing MODES or other specified conditions of the Applicability. However, since the LCO is not met in this instance, LCO 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specified condition changes.

SR 3.0.4 does not restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been performed within the specified Frequency, providing the requirement to declare the LCO not met has been delayed in accordance with SR 3.0.3.

The provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any plant shutdown. In this context, a plant shutdown is defined as a change in MODE or specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, MODE 3 to MODE 4, and MODE 4 to MODE 5.

Palisades Nuclear Plant B 3.0-20 Revised 07/26/2017

BASES SR 3.0.4 (Continued)

SR Applicability B 3.0 The precise requirements for performance of SRs are specified such that exceptions to SR 3.0.4 are not necessary. The specific time frames and conditions necessary for meeting the SRs are specified in the Frequency, in the Surveillance, or both. This allows performance of Surveillances when the prerequisite condition(s) specified in a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated LCO prior to the performance or completion of a Surveillance. A Surveillance that could not be performed until after entering the LCO's Applicability, would have its Frequency specified such that it is not "due" until the specific conditions needed are met.

Alternately, the Surveillance may be stated in the form of a Note as not required (to be met or performed) until a particular event, condition, or time has been reached. Further discussion of the specific formats of SRs' annotation is found in Section 1.4, Frequency.

Palisades Nuclear Plant B 3.0-21 Revised 07/26/2017

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 1 E loads during a Loss of Coolant Accident (LOCA) themselves are Class 1 E or are separated electrically from the Class 1 E portions.

Palisades Nuclear Plant B 3.3.5-1 Revised 11/08/2017

BASES BACKGROUND (continued)

Description DG - UV Start B 3.3.5 Each 2,400 V Bus (1 C and 1 D) 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 11/08/2017

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

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 11/08/2017

BASES LCO

( continued)

APPLICABILITY ACTIONS DG - UV Start B 3.3.5 This setpoint at the 2,400 V bus and reflected down to the 480 V buses 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.

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.

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 11/08/2017

BASES ACTIONS (continued)

SURVEILLANCE REQUIREMENTS DG - UV Start B 3.3.5 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.

SR 3.3.5.1 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 11/08/2017

BASES SURVEILLANCE REQUIREMENTS (continued)

REFERENCES SR 3.3.5.2 OG - UV Start B 3.3.5 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.

1.

10 CFR 50, Appendix A GOCs 17 and 21

2.

FSAR, Section 8.6

3.

Analysis EA-ELEC-VOLT-033

4.

Analysis EA-ELEC-VOL T-034

5.

Analysis EA-ELEC-EOSA-04

6.

FSAR, Chapter 14

7.

Analysis EA-ELEC-EOSA-03

8.

Analysis A-NL-92-111

9.

Analysis 0098-0189-CALC-001 Palisades Nuclear Plant B 3.3.5-6 Revised 11/08/2017

Pressurizer Safety Valves B 3.4.10 B 3.4 PRIMARY COOLANT SYSTEM (PCS)

B 3.4.10 Pressurizer Safety Valves BASES BACKGROUND The purpose of the three spring loaded pressurizer safety valves is to provide PCS overpressure protection. Operating in conjunction with the Reactor Protection System, three valves are used to ensure that the Safety Limit (SL) of 2750 psia is not exceeded for analyzed transients during operation in MODES 1 and 2 and portions of MODE 3. For the remainder of MODE 3, MODE 4, MODE 5, and MODE 6 with the reactor vessel head on, overpressure protection is provided by operating procedures and the LCO 3.4.12, "Low Temperature Overpressure Protection (L TOP) System."

The self actuated pressurizer safety valves are designed in accordance with the requirements set forth in the American Society of Mechanical Engineering (ASME), Boiler and Pressure Vessel Code,Section III (Ref. 1). The required lift settings are given in Table 3.4.10-1 in the accompanying technical specification. The safety valves discharge steam from the pressurizer to a quench tank located in the containment.

The discharge flow is indicated by an increase in temperature downstream of the safety valves, acoustic monitors, and by an increase in the quench tank temperature and level.

The lift settings listed in Table 3.4.10-1 correspond to ambient conditions of the valves at nominal operating temperature and pressure.

This requires either that the valves be set hot or that a correlation between hot and cold settings be established.

The pressurizer safety valves are part of the primary success path and mitigate the effects of postulated accidents. OPERABILITY of the safety valves ensures that the PCS pressure will be limited to 110% of design pressure. The consequences of exceeding the ASME pressure limit (Ref. 1) could include damage to PCS components, increased leakage, or a requirement to perform additional stress analyses prior to resumption of reactor operation.

Palisades Nuclear Plant B 3.4.10-1 Revised 07/26/2017

BASES APPLICABLE SAFETY ANALYSES LCO Pressurizer Safety Valves B 3.4.10 All accident analyses in the FSAR that require safety valve actuation assume operation of one or more pressurizer safety valves to limit increasing primary coolant pressure. The overpressure protection analysis assumes that the valves open at the high range of the lift setting including the allowable tolerance. The Loss of External Electrical Load incident and Loss of Normal Feedwater Flow incident are the two safety analyses events which rely on the pressurizer safety valves to mitigate an overpressurization of the PCS. The pressurizer safety valves must also accommodate pressurizer in surges that could occur from a Loss of Forced Primary Coolant Flow incident, and a Primary Pump Rotor Seizure incident. Single failure of a safety valve is neither assumed in the accident analysis nor required to be addressed by the ASME Code. Compliance with this specification is required to ensure that the accident analysis and design basis calculations remain valid.

The pressurizer safety valves satisfy Criterion 3 of 10 CFR 50.36(c)(2).

The three pressurizer safety valves are set to open near the PCS design pressure (2500 psia) and within the ASME specified tolerance to avoid exceeding the maximum PCS design pressure SL, to maintain accident analysis assumptions, and to comply with ASME Code requirements. The nominal lift settings values listed in Table 3.4.10-1, plus an allowable tolerance of +/- 3%, establish the acceptable "as-found" pressure band for determining valve OPERABILITY. Following valve testing, an as-left tolerance of +/- 1 % of the lift settings is imposed by SR 3.4.10.1 to account for setpoint drift during the surveillance interval.

The limit protected by this specification is the Primary Coolant Pressure Boundary (PCPB) SL of 110% of design pressure. The inoperability of any valve could result in exceeding the SL if a transient were to occur.

The consequences of exceeding the ASME pressure limit could include damage to one or more PCS components, increased leakage, or additional stress analysis being required prior to resumption of reactor operation.

Palisades Nuclear Plant B 3.4.10-2 Revised 07/26/2017

BASES APPLICABILITY ACTIONS Pressurizer Safety Valves B3.4.10 In MODES 1 and 2, and portions of MODE 3 above the L TOP temperature, OPERABILITY of three valves is required because the combined capacity is required to keep primary coolant pressure below 110% of its design value during certain accidents. Portions of MODE 3 are conservatively included, although the listed accidents may not require three safety valves for protection.

The LCO is not applicable in MODE 3 when any PCS cold leg temperatures are < 430°F and MODES 4 and 5 because L TOP protection is provided. Overpressure protection is not required in MODE 6 with the reactor vessel head removed.

With one pressurizer safety valve inoperable, restoration must take place within 15 minutes. The Completion Time of 15 minutes reflects the importance of maintaining the PCS overpressure protection system.

An inoperable safety valve coincident with an PCS overpressure event could challenge the integrity of the PCPB.

B.1 and B.2 If the Required Action cannot be met within the required Completion Time or if two or more pressurizer safety valves are inoperable, the plant must be brought to a MODE in which the requirement 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 at least one PCS cold leg temperature reduced to below 430°F within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowed is reasonable, based on operating experience, to reach MODE 3 from full power without challenging plant systems. Similarly, the 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed is reasonable, based on operating experience, to reduce any PCS cold leg temperature < 430°F without challenging plant systems.

Below 430°F, overpressure protection is provided by LTOP. The change from MODE 1, 2, or 3 to MODE 3 with any PCS cold leg temperature < 430°F reduces the PCS energy (core power and pressure), lowers the potential for large pressurizer insurges, and thereby removes the need for overpressure protection by three pressurizer safety valves.

Palisades Nuclear Plant B 3.4.10-3 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS REFERENCES SR 3.4.10.1 Pressurizer Safety Valves B3.4.10 SRs are specified in the INSERVICE TESTING PROGRAM.

Pressurizer safety valves are to be tested in accordance with the requirements of the ASME Code (Ref. 1), which provides the activities and the Frequency necessary to satisfy the SRs. No additional requirements are specified.

The pressurizer safety valve setpoint tolerance is +/- 3% for OPERABILITY; however, the valves are reset to within a tolerance of

+/- 1 % during the Surveillance to allow for drift.

1.

ASME Code for Operation and Maintenance of Nuclear Power Plants.

Palisades Nuclear Plant B 3.4.10-4 Amendment No. 262 Revised 07/26/2017

PCS PIV Leakage B3.4.14 B 3.4 PRIMARY COOLANT SYSTEM (PCS)

B 3.4.14 PCS Pressure Isolation Valve (PIV) Leakage BASES BACKGROUND The Reactor Safety Study (RSS), WASH-1400 (Ref. 1), identified a special class of Loss of Coolant Accidents (LOCAs) where the accident is initiated by the failure of check valves which separate the high pressure Primary Coolant System (PCS) from lower pressure systems connected to the PCS. This check valve failure could cause overpressurization and rupture of the lower pressure piping and result in a LOCA that bypasses containment. With the containment bypassed, the leakage would not be available for recirculation and when the Safety Injection Refueling Water Tank (SIRWT) emptied core cooling would be lost. This event has become known as "Event V."

When pressure isolation is provided by two in-series check valves and failure of one valve in the pair can go undetected for a substantial length of time, verification of valve integrity is required. Since these valves are important to safety, they should be tested periodically to ensure low probability of gross failure. Periodic examination of check valves must be undertaken to verify that each valve is seated properly and functioning as a pressure isolation device. The testing will reduce the overall risk of an inter-system LOCA. The testing may be accomplished by direct volumetric leakage measurement or by other equivalent means capable of demonstrating that leakage limits are not exceeded. The PCS PIV LCO allows PCS high pressure operation when leakage through these valves exists in amounts that do not compromise safety. The PIV leakage limit applies to each individual valve. Leakage through both PIVs in series in a line must be included as part of the identified LEAKAGE, governed by LCO 3.4.13, "PCS Operational LEAKAGE." This is true during operation only when the loss of PCS mass through two valves in series is determined by a water inventory balance (SR 3.4.13.1).

A known component of the identified LEAKAGE before operation begins is the least of the two individual leakage rates determined for leaking series PIVs during the required surveillance testing; leakage measured through one PIV in a line is not PCS operational LEAKAGE if the other is leaktight.

Palisades Nuclear Plant B 3.4.14-1 Revised 07/26/2017

BASES BACKGROUND (continued)

PCS PIV Leakage B 3.4.14 Although this specification provides a limit on allowable PIV leakage rate, its main purpose is to prevent overpressure failure of the low pressure portions of connecting systems. Therefore, this specification also addresses the potential for overpressurization of the low pressure piping in the Shutdown Cooling (SDC) system caused by the inadvertent opening of the SDC suction valves (MO-3015 and MO-3016) when the PCS pressure is above the design pressure of the SDC System. The leakage limit is an indication that the PIVs between the PCS and the connecting systems are degraded or degrading. PIV leakage or inadvertent valve positioning could lead to overpressure of the low pressure piping or components. Failure consequences could be a LOCA outside of containment, which is an unanalyzed condition that could degrade the ability for low pressure injection.

PIVs are provided to isolate the PCS from the following systems:

a.

Shutdown Cooling System; and

b.

Safety Injection System.

The PIVs which are required to be leak tested are listed in Table B 3.4.14-1.

Violation of this LCO could result in overpressurization of a low pressure system and the loss of the integrity of a fission product barrier.

APPLICABLE Reference 1 identified potential intersystem LOCAs as a significant SAFETY ANALYSES contributor to the risk of core melt. The dominant accident sequence in the intersystem LOCA category is the failure of low pressure piping outside of containment. The accident is the result of a postulated failure of the PIVs, which are part of the Primary Coolant Pressure Boundary (PCPB), and the subsequent pressurization of the lower pressure piping downstream of the PIVs from the PCS.

Overpressurization failure of the lower pressure piping would result in a LOCA outside containment and subsequent risk of core melt.

Reference 2 evaluated various PIV configurations, leakage testing of the valves, and operational changes to determine the effect on the probability of intersystem LOCAs. This study concluded that periodic leakage testing of the PIVs can substantially reduce the probability of an intersystem LOCA.

PCS PIV leakage satisfies Criterion 2 of 10 CFR 50.36(c)(2).

Palisades Nuclear Plant B 3.4.14-2 Revised 07/26/2017

BASES LCO APPLICABILITY PCS PIV Leakage B3.4.14 PCS PIV leakage is identified LEAKAGE into closed systems connected to the PCS. Isolation valve leakage is usually on the order of drops per minute. Leakage that increases significantly suggests that corrective action must be taken. The PIVs which are required to be leak tested are listed in Table 3.4.14-1.

The LCO PIV leakage limit is a maximum of 5 gpm. Reference 3 permits leakage testing at a lower pressure differential than that between maximum PCS pressure and the normal pressure of the connected system during PCS operation (the maximum pressure differential). The observed leakage rate must be corrected to the maximum pressure differential, assuming leakage is directly proportional to the square root of pressure differential.

The LCO also requires the SOC suction valve interlocks to be OPERABLE in order to prevent the inadvertent opening of the SOC suction valves when PCS pressure is above the 300 psig design pressure of the SOC suction piping. When PCS pressure is ~ 280 psia as sensed by the pressurizer narrow range pressure channels, an inhibit signal is placed on the control circuit for the SOC suction valves which prevents the valves from opening and thus avoiding a potential overpressurization event of the SOC piping. For the SOC suction valve interlocks to be OPERABLE, two channels of pressurizer narrow range pressure instruments must be capable of providing an open inhibit signal to their respective isolation valve.

In MODES 1, 2, 3, and 4, this LCO applies because the PIV leakage potential is greatest when the PCS is pressurized. In MODE 4, the requirements of this LCO are not required when in, or during the transition to or from, the SOC mode of operation since these evolutions are performed when PCS pressure is less than the limiting design pressure of the systems addressed by this specification.

In MODES 5 and 6, leakage limits are not provided because the lower primary coolant pressure results in a reduced potential for leakage and for a LOCA outside the containment.

Palisades Nuclear Plant B 3.4.14-3 Revised 07/26/2017

BASES ACTIONS PCS PIV Leakage B 3.4.14 The ACTIONS are modified by two Notes. Note 1 is added to provide clarification that each flow path allows separate entry into a Condition.

This is allowed based on the functional independence of the flow path.

Note 2 requires an evaluation of affected systems if a PIV is inoperable. The leakage may have affected system operability or isolation of a leaking flow path with an alternate valve may have degraded the ability of the interconnected system to perform its safety function.

A.1 and A.2 Required Action A.1 requires that isolation with one valve must be performed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months whenever one or more flow paths with leakage from one or more PIVs is not within limits. Four hours provides time to reduce leakage in excess of the allowable limit or to isolate the flow path if leakage cannot be reduced while restricting operation with leaking isolation valves. Required Action A.1 is modified by a Note stating that the valves used for isolation must meet the same leakage requirement as the PIVs and must be in the PCPB or the high pressure portion of the system.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time after exceeding the limit allows for the restoration of the leaking PIV to OPERABLE status. This time frame considers the time required to complete this action and the low probability of a second valve failing during this period.

B.1 and B.2 If leakage cannot be reduced or if the affected system can not be isolated within the specified 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 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 . This action reduces the leakage and also reduces the potential for a LOCA outside the containment. 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 3.4.14-4 Revised 07/26/2017

BASES ACTIONS (continued)

SURVEILLANCE REQUIREMENTS PCS PIV Leakage B 3.4.14 The inoperability of the SOC suction valve interlocks renders the SOC suction isolation valves incapable of preventing an inadvertent opening of the valves at PCS pressures in excess of the SOC systems design pressure. If the SOC suction valve interlocks are inoperable, operation may continue as long as the suction penetration is closed by at least one closed deactivated valve within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This action accomplishes the purpose of the interlock. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time provides time to accomplish the action and restricts operation with an inoperable interlock.

SR 3.4.14.1 Performance of leakage testing on each PCS PIV or isolation valve used to satisfy Required Action A.1 is required to verify that leakage is below the specified limit and to identify each leaking valve. The leakage limit of up to 5 gpm maximum applies to each valve. Leakage testing requires a stable pressure condition.

For the two PIVs in series, the leakage requirement applies to each valve individually and not to the combined leakage across both valves.

If the PIVs are not individually leakage tested, one valve may have failed completely and not be detected if the other valve in series meets the leakage requirement. In this situation, the protection provided by redundant valves would be lost.

Testing is to be performed every 9 months whenever the plant has been in MODE 5 for 7 days or more, but may be extended up to a maximum of 18 months, a typical refueling cycle, if the plant does not go into MODE 5 for at least 7 days. The 18 month Frequency is consistent with 10 CFR 50.55a(f), as contained in the INSERVICE TESTING PROGRAM, and is within the frequency allowed by the American Society of Mechanical Engineers (ASME) Code (Ref. 3), and is based on the need to perform the Surveillance under conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

The leakage limit is to be met at the PCS pressure associated with MODES 1 and 2. This permits leakage testing at high differential pressures with stable conditions not possible in the MODES with lower pressures.

Palisades Nuclear Plant B 3.4.14-5 Amendment No. 262 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS SR 3.4.14.1 (continued)

PCS PIV Leakage B 3.4.14 SR 3.4.14.1 is modified by three Notes. Note 1 states that the SR is only required to be performed in MODES 1 and 2. Entry into MODES 3 and 4 is allowed to establish the necessary differential pressure and stable conditions to allow performance of this surveillance.

Note 2 further restricts the PIV leakage rate acceptance criteria by limiting the reduction in margin between the measured leakage rate and the maximum permissible leakage rate by 50% or greater.

Reductions in margin by 50% or greater may be indicative of PIV degradation and warrant inspection or additional testing. Thus, leakage rates less than 5.0 gpm are considered acceptable if the latest measured rate has not exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximum permissible rate of 5.0 gpm by 50% or greater.

Note 3 limits the minimum test differential pressure to 150 psid during performance of PIV leakage testing.

SR 3.4.14.2 Verifying that the SOC suction valve interlocks are OPERABLE ensures that PCS pressure will not pressurize the SOC system beyond 125% of its design pressure of 300 psig. The interlock setpoint that prevents the valves from being opened is set so the actual PCS pressure must be < 280 psia to open the valves. This setpoint ensures the SOC design pressure will not be exceeded and the SOC relief valves will not lift. The narrow range pressure transmitters that provide the SOC suction valve interlocks are sensed from the pressurizer. Due to the elevation differences between these narrow range pressure transmitter calibration points and the SOC suction piping, the pressure in the SOC suction piping will be higher than the indicated pressurizer pressure. Due to this pressure difference, the SOC suction valve interlocks are conservatively set at or below 280 psia to ensure that the 300 psig (315 psia) design pressure of the suction piping is not exceeded. The 18 month Frequency is based on the need to perform these Surveillances under conditions that apply during a plant outage.

The 18 month Frequency is also acceptable based on consideration of the design reliability (and confirming operating experience) of the equipment.

Palisades Nuclear Plant B 3.4.14-6 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS (continued)

REFERENCES SR 3.4.14.3 PCS PIV Leakage B 3.4.14 This SR requires a verification that the four Low Pressure Safety Injection (LPSI) check valves (CK-31 03, CK-3118, CK-3133 and CK-3148) in the SOC flow path reclose after stopping SOC flow.

Performance of this SR is necessary to ensure the LPSI check valves are closed to prevent overpressurization of the LPSI subsystem from the High Pressure Safety Injection (HPSI) subsystem.

Overpressurization of the LPSI piping could occur if the LPSI check valves were not closed upon the receipt of a Safety Injection Signal and PCS pressure remained relatively high (e.g., during a small break LOCA). In this case, the higher pressure water from the discharge of the HPSI pumps could cause the lower pressure LPSI piping to exceed its design pressure. This event could result in a loss of emergency core cooling water outside containment which reduces the volume of water available for recirculation from the containment sump (Ref. 4).

SR 3.4.14.3 is required to be performed on a Frequency of "prior to entering MODE 2 whenever the LPSI check valves have been used for SOC." This ensures the LPSI check valves are closed whenever they have been opened for SOC operations prior to a reactor startup. The SR is modified by a Note which states that the surveillance is only required to be performed in MODES 1 and 2. Thus, entry into MODES 3 and 4 is allowed to establish the necessary differential pressure and to establish stable conditions to allow performance of this surveillance.

1.

WASH-1400 (NUREG-75/014), Appendix V, October 1975

2.

NUREG-0677, May 1980

3.

ASME Code for Operation and Maintenance of Nuclear Power Plants.

4.

Letter from Consumers Power Company to D.M. Crutchfield (NRC) Requesting a Change to the Palisades Plant Technical Specification, dated July 29, 1982 Palisades Nuclear Plant B 3.4.14-7 Amendment No. 262 Revised 07/26/2017

BASES System TABLE B 3.4.14-1 (page 1 of 1)

Required PCS Pressure Isolation Valves Valve No.

High Pressure Safety Injection Loop 1 A, Cold Leg Loop 1 B, Cold Leg Loop 2A, Cold Leg Loop 2B, Cold Leg Low Pressure Safety Injection Loop 1 A, Cold Leg Loop 1 B, Cold Leg Loop 2A, Cold Leg Loop 2B, Cold Leg Palisades Nuclear Plant B 3.4.14-8 CK-3101 CK - 3104 CK - 3116 CK - 3119 CK-3131 CK-3134 CK - 3146 CK - 3149 CK-3103 CK - 3118 CK-3133 CK - 3148 PCS PIV Leakage B3.4.14 Revised 07/26/2017

ECCS - Operating B 3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.2 ECCS - Operating BASES BACKGROUND The function of the ECCS is to provide core cooling and negative reactivity to ensure that the reactor core is protected after any of the following accidents:

a.

Loss of Coolant Accident (LOCA);

b.

Control Rod Ejection accident;

c.

Loss of secondary coolant accident, including a Main Steam Line Break (MSLB) or Loss of Normal Feedwater; and

d.

Steam Generator Tube Rupture (SGTR).

The addition of negative reactivity is d~signed primarily for the loss of secondary coolant accident where primary cooldown could add enough positive reactivity to achieve criticality and return to significant power.

There are two phases of ECCS operation: injection and recirculation.

In the injection phase, all injection is initially added to the Primary Coolant System (PCS) via the cold legs. After the Safety Injection Refueling Water Tank (SIRWT) has been depleted, the recirculation phase is entered as the ECCS suction is automatically transferred to the containment sump.

Two suitably redundant, 100% capacity trains are provided. Each train consists of a High Pressure Safety Injection (HPSI) and Low Pressure Safety Injection (LPSI) subsystem. In MODES 1 and 2, and in MODE 3 with PCS temperature ~ 325°F, both trains must be OPERABLE. This ensures that 100% of the core cooling requirements can be provided in the event of a single active failure.

Palisades Nuclear Plant B 3.5.2-1 Revised 07/26/2017

BASES BACKGROUND (continued)

ECCS - Operating B 3.5.2 Each train of a Safety Injection Signal (SIS) actuates LPSI flow by starting one LPSI pump and opening two LPSI loop injection valves.

Each train of an SIS actuates HPSI flow by starting one HPSI pump, opening the four associated HPSIIoop injection valves, and closing the pressure control valves associated with each Safety Injection Tank. In addition, each train of a SIS will provide a confirmatory open signal to the normally open Component Cooling Water valves which supply seal and bearing cooling to the LPSI, HPSI, and Containment Spray pumps.

The safety analyses assume that one only train of safety injection is available to mitigate an accident. While operating under the provisions of an ACTION, an additional single failure need not be assumed in assuring that a loss of function has not occurred. Therefore, the LPSI flow assumed in the safety analyses can be met if there is an OPERABLE LPSI flow path from the SIRWT to any two PCS loops.

The HPSI flow assumed in the safety analyses can be met if there is an OPERABLE HPSI flow path from the SIRWT to each cold leg. In each case, an OPERABLE flow path must include an OPERABLE pump and an OPERABLE injection valve.

A suction header supplies water from the SI RWT or the containment sump to the ECCS pumps. Separate piping supplies each train. The discharge headers from each HPSI pump divide into four supply lines after entering the containment, one feeding each PCS cold leg. The discharge headers from each LPSI pump combine to supply a common header which divides into four supply lines after entering containment, one feeding each PCS cold leg.

The hot-leg injection piping connects the HPSI Train 1 header and the HPSI Train 2 header to the PCS hot-leg. For long term core cooling after a large LOCA, Hot-leg injection is used to assure that for a large cold-leg PCS break, net core flushing flow can be maintained and excessive boric acid concentration in the core which could result in eventual precipitation and core flow blockage will be prevented. Within a few hours after a LOCA, if shutdown cooling is not in operation, the operator initiates simultaneous hot-leg and COld-leg injection. Hot-leg injection motor-operated valve throttle position and installed flow orifices cause HPSI flows to be split approximately equally between hot-and cold-leg injection paths.

Palisades Nuclear Plant B 3.5.2-2 Revised 07/26/2017

BASES BACKGROUND (continued)

ECCS - Operating B 3.5.2 Motor operated valves are set to maximize the LPSI flow to the PCS.

This flow balance directs sufficient flow to the core to meet the analysis assumptions following a LOCA in one of the PCS cold legs.

For LOCAs coincident with a loss of off-site power that are too small to initially depressurize the PCS below the shutoff head of the HPSI pumps, the core cooling function is provided by the Steam Generators (SGs) until the PCS pressure decreases below the HPSI pump shutoff head.

During low temperature conditions in the PCS, limitations are placed on the maximum number of HPSI pumps that may be OPERABLE. Refer to the Bases for LCO 3.4.12, "Low Temperature Overpressure Protection (L TOP) System," for the basis of these requirements.

During a large break LOCA, PCS pressure could decrease to

< 200 psia in < 20 seconds. The ECCS systems are actuated upon receipt of an SIS. If offsite power is available, the safeguard loads start immediately. If offsite power is not available, all loads will be shed at the time the diesel generators receive an automatic start signal. With load shedding completed, the diesel generator breakers will close automatically when generator voltage approaches a normal operating value. Closing of the breakers will reset the load shedding signals and start the sequencer. The sequencers will initiate operation of the engineered safeguard equipment required for the accident. The time delay associated with diesel starting, sequenced loading, and pump starting determines the time before pumped flow is available to the core following a LOCA.

The active ECCS components, along with the passive Safety Injection Tanks (SITs) and the Safety Injection Refueling Water Tank (SIRWT),

covered in LCO 3.5.1, "Safety Injection Tanks (SITs)," and LCO 3.5.4, "Safety Injection Refueling Water Tank (SIRWT)," provide the cooling water necessary to meet the Palisades Nuclear Plant design criteria (Ref. 1).

Palisades Nuclear Plant B 3.5.2-3 Revised 07/26/2017

BASES ECCS - Operating B 3.5.2 APPLICABLE The LCO helps to ensure that the following acceptance criteria, SAFETY ANALYSES established by 10 CFR 50.46 for ECCSs, will be met following a LOCA:

a.

Maximum fuel element cladding temperature is ::::; 2200°F;

b.

Maximum cladding oxidation is ::::; 0.17 times the total cladding thickness before oxidation;

c.

Maximum hydrogen generation from a zirconium water reaction is::::; 0.01 times the hypothetical amount generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react;

d.

Core is maintained in a coolable geometry; and

e.

Adequate long term core cooling capability is maintained.

The LCO also limits the potential for a post trip return to power following an MSLB event.

Both a HPSI and a LPSI subsystem are assumed to be OPERABLE in the large break LOCA analysis at full power (Ref. 2). This analysis establishes a minimum required runout flow for the HPSI and LPSI pumps, as well as the maximum required response time for their actuation. The HPSI pump is also credited in the small break LOCA analysis. This analysis establishes the flow and discharge head requirements at the design point for the HPSI pump. The SGTR and MSLB accident analyses also credit the HPSI pumps, but are not limiting in their design.

The large break LOCA event with a loss of offsite power and a single failure (disabling one ECCS train) establishes the OPERABILITY requirements for the ECCS. During the blowdown stage of a LOCA, the PCS depressurizes as primary coolant is ejected through the break into the containment. The nuclear reaction is terminated either by moderator voiding (during large breaks) or control rod insertion (during small breaks).

Following depressurization, emergency cooling water is injected into the cold legs, flows into the downcomer, fills the lower plenum, and refloods the core.

Palisades Nuclear Plant On smaller breaks, PCS pressure will stabilize at a value dependent upon break size, heat load, and injection flow. The smaller the break, the higher this equilibrium pressure. In all LOCA analyses, injection flow is not credited until PCS pressure drops below the shutoff head of the HPSI pumps.

B 3.5.2-4 Revised 07/26/2017

BASES APPLICABLE SAFETY ANALYSES (continued)

LCO ECCS - Operating B3.5.2 The LCO ensures that an ECCS train will deliver sufficient water to match decay heat boiloff rates soon enough to minimize core damage for a large LOCA. It also ensures that the HPSI pump will deliver sufficient water during a small break LOCA and provide sufficient boron to limit the return to power following an MSLB event. For smaller LOCAs, PCS inventory decreases until the PCS can be depressurized below the HPSI pumps' shutoff head. During this period of a small break LOCA, the SGs continue to serve as the heat sink providing core cooling.

ECCS - Operating satisfies Criterion 3 of 10 CFR 50.36(c)(2).

In MODES 1 and 2, and in MODE 3 with PCS temperature ~ 325°F, two independent (and redundant) ECCS trains are required to ensure that sufficient ECCS flow is available, assuming there is a single failure affecting either train. Additionally, individual components within the ECCS trains may be called upon to mitigate the consequences of other transients and accidents.

An ECCS train consists of an HPSI subsystem and a LPSI subsystem.

In addition, each train includes the piping, instruments, and controls to ensure the availability of an OPERABLE flow path capable of taking suction from the SIRWT on an SIS and automatically transferring suction to the containment sump upon a Recirculation Actuation Signal (RAS).

During an event requiring ECCS actuation, a flow path is provided to ensure an abundant supply of water from the SIRWT to the PCS, via the HPSI and LPSI pumps and their respective supply headers, to each of the four cold leg injection nozzles is available. During the recirculation phase, a flow path is provided from the containment sump to the PCS via the HPSI pumps. For worst case conditions, the containment building water level alone is not sufficient to assure adequate Net Positive Suction Head (NPSH) for the HPSI pumps.

Therefore, to obtain adequate NPSH, a portion of the Containment Spray (CS) pump discharge flow is diverted from downstream of the shutdown cooling heat exchangers to the suction of the HPSI pumps at recirculation during a large break LOCA. In this configuration, the CS pumps and shutdown cooling heat exchangers provide a support function for HPSI flow path OPERABILITY. The OPERABILITY requirements for the CS pumps and shutdown cooling heat exchangers are addressed in LCO 3.6.6, "Containment Cooling Systems." Support system OPERABILITY is addressed by LCO 3.0.6.

The flow path for each train must maintain its designed independence to ensure that no Single active failure can disable both ECCS trains.

Palisades Nuclear Plant B 3.5.2-5 Revised 07/26/2017

BASES APPLICABILITY ACTIONS ECCS - Operating B 3.5.2 In MODES 1 and 2, and in MODE 3 with PCS temperature ~ 325°F, the ECCS OPERABILITY requirements for the limiting Design Basis Accident (DBA) large break LOCA are based on full power operation.

Although reduced power would not require the same level of performance, the accident analysis does not provide for reduced cooling requirements in the lower MODES. The HPSI pump performance is based on the small break LOCA, which establishes the pump performance curve and has less dependence on power. The requirements of MODE 2 and MODE 3 with PCS temperature ~ 325°F, are bounded by the MODE 1 analysis.

The ECCS functional requirements of MODE 3, with PCS temperature

< 325°F, and MODE 4 are described in LCO 3.5.3, "ECCS - Shutdown."

In MODES 5 and 6, plant conditions are such that the probability of an event requiring ECCS injection is extremely low. Core cooling requirements in MODE 5 are addressed by LCO 3.4.7, "PCS Loops -

MODE 5, Loops Filled," and LCO 3.4.8, "PCS Loops - MODE 5, Loops Not Filled." MODE 6 core cooling requirements are addressed by LCO 3.9.4, "Shutdown Cooling (SOC) and Coolant Circulation - High Water Level," and LCO 3.9.5, "Shutdown Cooling (SOC) and Coolant Circulation - Low Water Level."

Condition A is applicable whenever one LPSI subsystem is inoperable.

With one LPSI subsystem inoperable, action must be taken to restore OPERABLE status within 7 days. In this condition, the remaining OPERABLE ECCS train is adequate to perform the heat removal function. However, the overall reliability is reduced because a single failure to the remaining LPSI subsystem could result in loss of ECCS function. The 7 day Completion Time is reasonable to perform corrective maintenance on the inoperable LPSI subsystem. While mechanical system LCOs typically provide a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time, this 7 day Completion Time is based on the findings of the deterministic and probabilistic analysis in Reference 5. Reference 5 concluded that extending the Completion Time to 7 days for an inoperable LPSI subsystem provides plant operational flexibility while simultaneously reducing overall plant risk. This is because the risks incurred by having the LPSI subsystem unavailable for a longer time at power will be substantially offset by the benefits associated with avoiding unnecessary plant transitions and by reducing risk during plant shutdown operations.

Palisades Nuclear Plant B 3.5.2-6 Revised 07/26/2017

BASES ACTIONS (continued)

ECCS - Operating B 3.5.2 Condition B is applicable whenever one or more ECCS trains is inoperable for reasons other than one inoperable LPSI subsystem.

Action B.1 requires restoration of both ECCS trains, (HPSI and LPSI) to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is based on an NRC study (Ref. 3), assuming that at least 100% of the required ECCS flow (that assumed in the safety analyses) is available.

If less than 100% of the required ECCS flow is available, Condition D 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 ECCS can provide one hundred percent of the required ECCS flow following the occurrence of any single active failure. Therefore, the ECCS 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.

C.1 and C.2 Condition C is applicable when the Required Actions of Condition A or B cannot be completed within the required Completion Time. Either Condition A or B is applicable whenever one or more ECCS trains is inoperable. Therefore, when Condition C is applicable, either Condition A or B is also applicable. Being in Conditions A or B, and Condition C concurrently maintains both Completion Time clocks for instances where equipment repair allows exit from Condition C while the plant is still within the applicable conditions of the LCO.

If the inoperable ECCS trains cannot be restored to OPERABLE status within the required Completion Times of Condition A and B, 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 PCS temperature reduce to < 325°F within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power in an orderly manner and without challenging plant systems.

Palisades Nuclear Plant B 3.5.2-7 Revised 07/26/2017

BASES ACTIONS (continued)

ECCS - Operating B 3.5.2 Condition 0 is applicable with one or more trains inoperable when there is less than 100% of the required ECCS flow available. Either Condition A or B is applicable whenever one or more ECCS trains is inoperable.

Therefore, when this Condition is applicable, either Condition A or B is also applicable. Being in Conditions A or B, and Condition 0 concurrently maintains both Completion Time clocks for instances where equipment repair allows exit from Condition 0 (and LCO 3.0.3) while the plant is still within the applicable conditions of the LCO.

One hundred percent of the required ECCS flow can be provided by one OPERABLE HPSI subsystem and one OPERABLE LPSI subsystem. The required LPSI flow (that assumed in the safety analyses) is available if there is an OPERABLE LPSI flow path from the SIRWT to any two PCS loops. Shutdown cooling flow control valve, CV-3006 must be full open. The required HPSI flow (that assumed in the safety analyses) is available if there is an OPERABLE HPSI flow path from the SIRWT to each PCS loop (having less than all four PCS loop flowpaths may be acceptable if verified against current safety analyses). A Containment Spray Pump and a sub-cooled suction valve must be available to support each OPERABLE HPSI pump. In each case, an OPERABLE flow path must include an OPERABLE pump and OPERABLE loop injection valves.

Reference 4 describes situations in which one component, such as the shutdown cooling flow control valve, CV-3006, can disable both ECCS trains. With one or more components inoperable, such that 100% of the required ECCS flow (that assumed in the safety analyses) is not available, the facility is in a condition outside the accident safety analyses.

With less than 100% of the req!Jired ECCS flow available, the plant is in a condition outside the assumptions of the safety analyses. Therefore, LCO 3.0.3 must be entered immediately.

Palisades Nuclear Plant B 3.5.2-8 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS SR 3.5.2.1 ECCS - Operating B 3.5.2 Verification of proper valve position ensures that the flow path from the ECCS pumps to the PCS is maintained. CV-3027 and CV-3056 are stop valves in the minimum recirculation flow path for the ECCS pumps.

If either of these valves were closed when the PCS pressure was above the shutoff head of the ECCS pumps, the pumps could be damaged by running with insufficient flow and thus render both ECCS trains inoperable.

Placing HS-3027A and HS-3027B for CV-3027, and HS-3056A and HS-3056B for CV-3056, in the open position ensures that the valves cannot be inadvertently misaligned or change position as the result of an active failure. These valves are of the type described in Reference 4, which can disable the function of both ECCS trains and invalidate the accident analysis. CV-3027 and CV-3056 are capable of being closed from the control room since the SIRWT must be isolated from the containment during the recirculation phase of a LOCA. A 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered reasonable in view of other administrative controls ensuring that a mispositioned valve is an unlikely possibility.

SR 3.5.2.2 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an actuation signal is allowed to be in a nonaccident position provided the valve automatically repositions within the proper stroke time. This Surveillance does not require any testing or valve manipulation. Rather, it involves verification that those valves capable of being mispositioned are in the correct position.

The 31 day Frequency is appropriate because the valves are operated under procedural control and an improper valve position would only affect a single train. This Frequency has been shown to be acceptable through operating experience.

Palisades Nuclear Plant B 3.5.2-9 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS (Continued)

SR 3.5.2.3 ECCS - Operating B3.5.2 SR 3.5.2.3 verifies CV-3006 is in the open position and that its air supply is isolated. CV-3006 is the shutdown cooling flow control valve located in the common LPSI flow path. The valve must be verified in the full open position to support the low pressure injection flow assumptions used in the accident analyses. The inadvertent misposition of this valve could result in a loss of low pressure injection flow and thus invalidate these flow assumptions. CV-3006 is designed to be held open by spring force and closed by air pressure. To ensure the valve cannot be inadvertently misaligned or change position as the result of a hot short in the control circuit, the air supply to CV-3006 is isolated. Isolation of the air supply to CV-3006 is acceptable since the valve does not require automatic repositioning during an accident.

The 31 day Frequency has been shown to be acceptable through operating practice and the unlikely occurrence of the air supply to CV-3006 being unisolated coincident with a inadvertent valve misalignment event or a hot short in the control circuit.

SR 3.5.2.4 Periodic surveillance testing of ECCS pumps to detect gross degradation caused by impeller damage or other hydraulic component problems is required by the ASME Code. This type of testing may be accomplished by measuring the pump developed head at only one point of the pump characteristic curve. This verifies both that the measured performance is within an acceptable tolerance of the original pump baseline performance and that the performance at the test flow is greater than or equal to the performance assumed in the plant safety analysis. SRs are specified in the INSERVICE TESTING PROGRAM of the ASME Code. The ASME Code provides the activities and Frequencies necessary to satisfy the requirements.

SR 3.5.2.5. SR 3.5.2.6. and SR 3.5.2.7 These SRs demonstrate that each automatic ECCS valve actuates to the required position on an actual or simulated actuation Signal, i.e., on an SIS or RAS, that each ECCS pump starts on receipt of an actual or simulated actuation Signal, i.e., on an SIS, and that the LPSI pumps stop on receipt of an actual or simulated actuation signal, i.e., on an RAS. 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 re-position CV-3001 and CV-3002 to a predetermined throttled position. RAS will close Palisades Nuclear Plant B 3.5.2-10 Amendment No. 262 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.5.2.5, SR 3.5.2.6, and SR 3.5.2.7 ECCS - Operating B 3.5.2 containment spray valve CV-3001, if containment sump valve CV-3030 does not open. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls.

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 unplanned transients if the Surveillances were performed with the reactor at power. The 18 month Frequency is also acceptable based on consideration of the design reliability of the equipment and operating experience. The actuation logic is tested as part of the Engineered Safety Feature (ESF) testing, and equipment performance is monitored as part of the INSERVICE TESTING PROGRAM.

SR 3.5.2.8 The HPSI Hot Leg Injection motor operated valves and the LPSIIoop injection valves have position switches which are set at other than the full open position. This surveillance verifies that these position switches are set properly.

The HPSI Hot leg injection valves are manually opened during the post-LOCA long term cooling phase to admit HPSI injection flow to the PCS hot leg. The open position limit switch on each HPSI hot leg isolation valves is set to establish a predetermined flow split between the HPSI injection entering the PCS hot leg and cold legs.

The LPSI loop injection MOVs open automatically on a SIS signal. The open position limit switch on each LPSI loop injection valve is set to establish the maximum possible flow through that valve. The design of these valves is such that excessive turbulence is developed in the valve body when the valve disk is at the full open position. Stopping the valve travel at slightly less than full open reduces the turbulence and results in increased flow. Verifying that the position stops are properly set ensures that a single low pressure safety injection subsystem is capable of delivering the flow rate required in the safety analysis.

The 18 month Frequency is based on the same factors as those stated above for SR 3.5.2.5, SR 3.5.2.6, and SR 3.5.2.7.

Palisades Nuclear Plant B 3.5.2-11 Amendment No. 262 Revised 07/26/2017

BASES REFERENCES SR 3.5.2.9 ECCS - Operating B3.5.2 Periodic inspection of the ECCS containment sump passive strainer assemblies ensures that the post-LOCA recirculation flowpath to the ECCS train containment sump suction inlets is unrestricted. Periodic inspection of the containment sump entrance pathways, which include containment sump passive strainer assemblies, containment sump downcomer debris screens, containment floor drain debris screens, containment sump vent debris screens, and reactor cavity corium plug bottom cup support assemblies, ensures that the containment sump stays in proper operating condition. The migration of LOCA-generated debris larger than the strainer perforation diameter through the two one-inch reactor cavity drain line corium plugs is not considered to be credible. The 18-month Frequency is based on the need to perform this Surveillance under outage conditions. This Frequency is sufficient to detect abnormal degradation and is confirmed by operating experience.

1.

FSAR, Section 5.1

2.

FSAR, Section 14.17

3.

NRC Memorandum to V. Stello, Jr., from R. L. Baer, "Recommended Interim Revisions to LCOs for ECCS Components," December 1,1975

4.

IE Information Notice No. 87-01, January 6, 1987

5.

CE-NPSD-994, "CEOG Joint Applications Report for Safety Injection Tank AOT/STI Extension," May 1995 Palisades Nuclear Plant B 3.5.2-12 Revised 07/26/2017

Containment Isolation Valves B 3.6.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.3 Containment Isolation Valves BASES BACKGROUND The containment isolation valves and devices form part of the containment pressure boundary and provide a means for isolating penetration flow paths. These isolation devices are either passive or active (automatic). Manual valves, de-activated automatic valves secured in their closed position (including check valves with flow through the valve secured) and blind flanges are considered passive devices. Check valves, or other automatic valves designed to close without operator action following an accident, are considered active devices. Two barriers in series are provided for each penetration so that no single credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds limits assumed in the safety analysis.

One of these barriers may be a closed system.

The Containment Isolation System is designed to provide isolation capability following a Design Basis Accident (DBA) for fluid lines that penetrate containment. Major nonessential lines (i.e., fluid systems that do not perform an immediate accident mitigation function) that penetrate containment, except for the main steam lines and instrument air line, are either automatically isolated following an accident or are normally maintained closed in MODES 1, 2, 3, and 4. Containment isolation occurs upon receipt of a Containment High Pressure (CHP) signal or a Containment High Radiation (CHR) signal. However, not all containment isolation valves are actuated by both signals. The signals close automatic containment isolation valves in fluid penetrations that are required to be isolated during accident conditions in order to minimize release of fission products from the Primary Coolant System (PCS) to the environment. Other penetrations that are required to be isolated during accident conditions are isolated by the use of valves or check valves in the closed position, or blind flanges. As a result, the containment isolation devices help ensure that the containment atmosphere will be isolated in the event of a release of fission products to the containment atmosphere from the PCS following a DBA.

Palisades Nuclear Plant B 3.6.3-1 Revised 07/26/2017

BASES BACKGROUND APPLICABLE SAFETY ANALYSES Containment Isolation Valves B 3.6.3 The plant safety analyses (Reference 5) assume containment isolation for the mitigation of a Loss of Coolant Accident (LOCA) and a control rod ejection accident. The Main Steam Line Break, Steam Generator Tube Rupture, and Control Rod Ejection accident analyses include scenarios in which the mass of steam from the Steam Generator is assumed to be released directly to the environment, and no credit is taken for containment isolation to mitigate the radiological consequences of those accidents. For other analyzed accidents, a release path via fluid lines connected directly to the secondary side of the steam generators would require a passive failure, and Palisades is not required to postulate passive failures of equipment performing safety functions in accident scenarios (Reference 6). Therefore, valves in fluid lines connected directly to the secondary side of the steam generators are not included in this Technical Specification.

The OPERABILITY requirements for containment isolation valves and devices help ensure that containment is isolated within the time limits assumed in the safety analyses. Therefore, the OPERABILITY requirements provide assurance that the containment leakage limits assumed in the accident analyses will not be exceeded in a DBA.

The 8 inch purge exhaust valves are designed for purging the containment atmosphere to the stack while introducing filtered makeup, through the 12 inch air room supply valves from the outside, when the plant is shut down during refueling operations and maintenance. The purge exhaust valves and air room supply valves are air operated isolation valves located outside the containment. These valves are operated manually from the control room. These valves will close automatically upon receipt of a CHP or CHR signal. The air operated valves fail closed upon a loss of air. These valves are not qualified for automatic closure from their open position under DBA conditions.

Therefore, these valves are locked closed in MODES 1, 2, 3, and 4 to ensure the containment boundary is maintained.

Open purge exhaust or air room supply valves, following an accident that releases contamination to the containment atmosphere, would cause a significant increase in the containment leakage rate.

The containment isolation valve LCO was derived from the assumptions related to minimizing the release of fission products from the primary coolant system to the environment, and establishing the containment boundary during major accidents. As part of the containment boundary, containment isolation valve (device) OPERABILITY supports leak tightness of the containment. Therefore, the safety analysis of any event requiring isolation of containment is applicable to this LCO.

Palisades Nuclear Plant B 3.6.3-2 Revised 07/26/2017

BASES Containment Isolation Valves B 3.6.3 APPLICABLE A Loss of Coolant Accident (LOCA) and a control rod ejection accident SAFETY ANALYSES are the two DBAs that require isolation of containment to minimize (continued) release of fission products to the environment (Ref. 5). In the analysis for each of these accidents, it is assumed that containment isolation devices that are required to be closed during accident conditions are either closed or function to close within the required isolation time following event initiation. This ensures that potential paths to the environment through containment isolation devices (including containment purge valves) are minimized. The safety analysis assumes that the purge exhaust and air room supply valves are closed at event initiation.

LCO The DBA analysis assumes that, within 25 seconds after receiving a CHP or CHR signal each automatic power operated valve is closed and containment leakage terminated except for the design leakage rate.

The single failure criterion required to be imposed in the conduct of plant safety analyses was considered in the design of the containment purge valves. Two valves in series on each line provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred. Both isolation valves on the 8 inch and 12 inch lines are pneumatically operated spring-closed valves.

The 8 inch purge exhaust and 12 inch air room supply valves may be unable to close in the environment following a LOCA. Therefore, each of the purge valves is required to remain locked closed during MODES 1, 2, 3, and 4. In this case, the single failure criterion remains applicable to the containment purge valves due to the potential for failure in the control circuit associated with each valve. Again, the purge system valve design precludes a single failure from compromising the containment boundary as long as the system is operated in accordance with the subject LCO.

The containment isolation valves satisfy Criterion 3 of 10 CFR 50.36(c)(2).

Containment isolation valves form a part of the containment boundary.

Compliance with this LCO will ensure a containment configuration that will limit leakage to those leakage rates assumed in the safety analyses.

Containment penetrations for fluid systems that perform an accident mitigation function are not required to be isolated.

Palisades Nuclear Plant B 3.6.3-3 Revised 07/26/2017

BASES LCO (continued)

Containment Isolation Valves B 3.6.3 Containment isolation valves (devices) consist of isolation valves (manual valves, check valves, air operated valves, and motor operated valves),

and blind flanges. There are two major categories of containment isolation devices that are used depending on the type of penetration and the function of the associated piping system:

a.

Active - automatic containment isolation devices that, following an accident, either receive a containment isolation signal to close, or close as a result of differential pressure;

b.

Passive - normally closed containment isolation devices that are maintained closed in MODES 1, 2, 3, and 4 since they do not receive a containment isolation signal to close and the penetration is not used for normal power operation.

The automatic power operated isolation valves are required to have isolation times within limits and to actuate upon receipt of a CHP or CHR signal as appropriate. Check valves are verified to be OPERABLE through the valve INSERVICE TESTING PROGRAM. The purge exhaust and air room supply valves must be locked closed.

The normally closed isolation devices are considered OPERABLE when manual valves are closed, automatic valves are de-activated and secured in their closed position, check valves are closed with flow secured through the pipe, or blind flanges are in place.

The devices covered by this LCO are listed in the FSAR (Ref. 2).

The purge exhaust and air room supply valves with resilient seals must meet the same leakage rate testing requirements as other Type C tested containment isolation valves addressed by LCO 3.6.1, "Containment."

This LCO provides assurance that the containment isolation devices will perform their designed safety functions to minimize the release of fission products from the primary coolant system to the environment and establish the containment boundary during accidents.

Palisades Nuclear Plant B 3.6.3-4 Amendment No. 262 Revised 07/26/2017

BASES APPLICABILITY ACTIONS Containment Isolation Valves B 3.6.3 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 isolation valves are not required to be OPERABLE in MODE 5. The requirements for containment isolation valves during MODE 6 are addressed in LCO 3.9.3, "Containment Penetrations."

The ACTIONS are modified by four notes. Note 1 allows isolated penetration flow paths, except for 8 inch exhaust and 12 inch air room supply purge valve penetration flow paths, to be unisolated intermittently under administrative controls. These administrative controls consist of stationing a dedicated operator at the device controls, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for containment isolation is indicated. Due to the fact that the 8 inch purge exhaust valves and the 12 inch air room supply valves may be unable to close in the environment following a LOCA and the fact that those penetrations exhaust directly from the containment atmosphere to the environment, these valves may not be opened under administrative controls.

Note 2 provides clarification that, for this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable containment isolation device. Complying with the Required Actions may allow for continued operation, and subsequent inoperable containment isolation devices are governed by subsequent Condition entry and application of associated Required Actions.

Note 3 ensures that appropriate remedial actions are taken, if necessary, if the affected systems are rendered inoperable by an inoperable containment isolation device.

Note 4 requires entry into the applicable Conditions and Required Actions of LCO 3.6.1 when leakage results in exceeding the overall containment leakage limit.

A.1 and A.2 Condition A has been modified by a Note indicating that this Condition is only applicable to those penetration flow paths with two containment isolation valves. For penetration flow paths with only one containment isolation valve and a closed system, Condition C provides appropriate actions.

Palisades Nuclear Plant B 3.6.3-5 Revised 07/26/2017

BASES ACTIONS A.1 and A.2 (continued)

Containment Isolation Valves B 3.6.3 In the event one containment isolation valve in one or more penetration flow paths is inoperable (except for purge exhaust or air room supply valves), the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation device that cannot be adversely affected by a single active failure. Isolation devices that meet this criterion are a closed and de-activated automatic containment isolation valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured. For penetrations isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available one to containment. Required Action A.1 must be completed within the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, considering the time required to isolate the penetration and the relative importance of supporting containment OPERABILITY during MODES 1, 2,3, and 4.

For affected penetration flow paths that cannot be restored to OPERABLE status within the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time and that have been isolated in accordance with Required Action A.1, the affected penetration flow paths must be verified to be isolated on a periodic basis. This is necessary to ensure that containment penetrations required to be isolated following an accident and no longer capable of being automatically isolated will be in the isolation position should an event occur. This Required Action does not require any testing or device manipulation.

Rather, it involves verification that those isolation devices outside containment and capable of being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside containment" is appropriate conSidering the fact that the devices are operated under administrative controls and the probability of their misalignment is low.

For the isolation devices inside containment, the time period specified as "prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the isolation devices and other administrative controls that will ensure that isolation device misalignment is an unlikely possibility.

Required Action A.2 is modified by a Note that applies to isolation devices located in high radiation areas and allows these devices to be verified 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 these devices, once they have been verified to be in the proper position, is small.

Palisades Nuclear Plant B 3.6.3-6 Revised 07/26/2017

BASES ACTIONS A.1 and A.2 (continued)

Containment Isolation Valves B 3.6.3 The Completion Time of once per 31 days for verifying each affected penetration flow path outside the containment is isolated is appropriate considering that the penetration can be isolated by the remaining isolable device. As stated in SR 3.02, 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...

tt basis. The 25% extension applies to each performance of the Required Action after the initial performance. Therefore, for devices outside the containment, while Required Action 3.6.3 A.2 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.

With two containment isolation valves in one or more penetration flow paths inoperable (except for purge exhaust valve or air room supply valve not locked closed), the affected penetration flow path must be isolated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The method of isolation must include the use of at least one isolation device that cannot be adversely affected by a single active failure. Isolation devices that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange.

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.

In the event the affected penetration is isolated in accordance with Required Action B.1, the affected penetration must be verified to be isolated on a periodic basis per Required Action A.2, which remains in effect. This periodic verification is necessary to assure leak tightness of containment and that penetrations requiring isolation following an accident are isolated.

The Completion Time of once per 31 days for verifying each affected penetration flow path is isolated is appropriate considering the fact that the devices are operated under administrative controls and the probability of their misalignment is low.

Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two containment isolation valves.

Condition A of this LCO addresses the condition of one containment isolation valve inoperable in this type of penetration flow path.

Palisades Nuclear Plant B 3.6.3-7 Revised 07/26/2017

BASES ACTIONS (continued)

C.1 and C.2 Containment Isolation Valves B 3.6.3 Condition C is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with only one containment isolation valve and a closed system. The closed system must meet the requirements of Reference 2. This Note is necessary since this Condition is written to specifically address those penetration flow paths in a closed system.

With one or more penetration flow paths with one containment isolation valve inoperable, the inoperable valve must be restored to OPERABLE status or the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation device that cannot be adversely affected by a single active failure. Isolation devices that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration. Required Action C.1 must be completed within the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time. The specified time period is reasonable, considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation barrier and the relative importance of supporting containment OPERABILITY during MODES 1, 2, 3, and 4. In the event the affected penetration is isolated in accordance with Required Action C.1, the affected penetration flow path must be verified to be isolated on a periodic basis. This is necessary to assure leak tightness of containment and that containment penetrations requiring isolation following an accident are isolated. This Required Action does not require any testing or device manipulation. Rather, it involves verification that those isolation devices outside containment and capable of being mispositioned are in the correct position.

The Completion Time of once per 31 days for verifying that each affected penetration flow path is isolated is appropriate considering the devices are operated under administrative controls and the probability of their misalignment is low. 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 on a "once per... " basis. The 25% extension applies to each performance of the Required Action after the initial performance.

Therefore, while Required Action 3.6.3 C.2 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 3.6.3-8 Revised 07/26/2017

BASES ACTIONS SURVEILLANCE REQUIREMENTS C.1 and C.2 (continued)

Containment Isolation Valves B 3.6.3 Required Action C.2 is modified by a Note that applies to isolation devices located in high radiation areas and allows these devices to be verified 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 these devices, once they have been verified to be in the proper position, is small.

The purge exhaust and air room supply isolation valves have not been qualified to close following a LOCA and are required to be locked closed.

If one or more of these valves is found not locked closed, the potential exists for the valves to be inadvertently opened. One hour is provided to lock closed the affected valves. The 1-hour Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining these valves closed.

E.1 and E.2 If the Required Actions and associated Completion Times are not met, 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.

SR 3.6.3.1 This SR ensures that the 8-inch purge exhaust and 12 inch air room supply valves are locked closed as required. If a valve is open, or closed but not locked, in violation of this SR, the valve is considered inoperable.

Valves may be locked closed electrically, mechanically, or by other physical means. These valves may be unable to close in the environment following a LOCA. Therefore, each of the valves is required to remain closed during MODES 1, 2, 3, and 4. The 31-day Frequency is consistent with other containment isolation valve requirements discussed in SR 3.6.3.2.

Palisades Nuclear Plant B 3.6.3-9 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.3.2 Containment Isolation Valves B 3.6.3 This SR requires verification that each manual containment isolation valve and blind flange located outside containment, and not locked, sealed, or otherwise secured in position, and required to be closed during accident conditions, is closed. The SR helps to ensure that post accident leakage of fission products outside the containment boundary is within design limits. This SR does not require any testing or device manipulation. Rather, it involves verification that those containment isolation devices outside containment and capable of being mispositioned are in the correct position. Since verification of device position for containment isolation devices outside containment is relatively easy, the 31-day Frequency is based on engineering judgment and was chosen to provide added assurance of the correct positions. Containment isolation valves that are open under administrative controls are not required to meet the SR during the time the valves are open. This SR does not apply to devices that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

The Note applies to valves and blind flanges located in high radiation areas and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, 3, and 4 for ALARA reasons. Therefore, the probability of misalignment of these containment isolation devices, once they have been verified to be in the proper position, is small.

SR 3.6.3.3 This SR requires verification that each containment isolation manual valve and blind flange located inside containment and not locked, sealed or otherwise secured in position, and required to be closed during accident conditions, is closed. The SR helps to ensure that post accident leakage of fission products outside the containment boundary is within deSign limits. For containment isolation devices inside containment, the Frequency of "prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days" is appropriate, since these containment isolation devices are operated under administrative controls and the probability of their misalignment is low. Containment isolation valves that are open under administrative controls are not required to meet the SR during the time that they are open. This SR does not apply to devices that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

Palisades Nuclear Plant B 3.6.3-10 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS SR 3.6.3.3 (continued)

Containment Isolation Valves B 3.6.3 The Note allows valves and blind flanges located in high radiation areas to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these containment isolation devices, once they have been verified to be in their proper position, is small.

SR 3.6.3.4 Verifying that the isolation time of each automatic power operated containment isolation valve is within limits is required to demonstrate OPERABILITY. The isolation time test ensures the valve will isolate in a time period less than or equal to that assumed in the safety analysis. The isolation time and Frequency of this SR are in accordance with the INSERVICE TESTING PROGRAM.

SR 3.6.3.5 For containment 8 inch purge exhaust and 12 inch air room supply valves with resilient seals, additional leakage rate testing beyond the test requirements of 10 CFR 50, Appendix J, Option B (Ref. 3), is required to ensure the valves are physically closed (SR 3.6.3.1 verifies the valves are locked closed). Operating experience has demonstrated that this type of seal has the potential to degrade in a shorter time period than do other seal types. Based on this observation and the importance of maintaining this penetration leak tight (due to the direct path between containment and the environment), a Frequency of 184 days was established as part of the NRC resolution of Generic Issue B-20, "Containment Leakage Due to Seal Deterioration" (Ref. 4) as specified in the Safety Evaluation for Amendment No. 90 to the Facility Operating License.

Palisades Nuclear Plant B 3.6.3-11 Amendment 262 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS (continued)

REFERENCES SR 3.6.3.6 Containment Isolation Valves B 3.6.3 Automatic containment isolation valves close on a containment isolation signal to minimize leakage of fission products from containment following a DBA. This SR ensures each automatic containment isolation valve will actuate to its isolation position on an actual or simulated actuation signal, i.e., CHP or CHR. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The 18 month Frequency was developed considering it is prudent that this SR be performed only during a plant outage, since isolation of penetrations would eliminate cooling water flow and disrupt normal operation of many critical components. Operating experience has shown that these components usually pass this SR when performed on the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

1.

FSAR, Section 5.8

2.

FSAR, Section 6.7.2 and Table 6-14

3.

10 CFR 50, Appendix J, Option B

4.

Generic Issue B-20

5.

FSAR, Chapter 14

6.

FSAR, Section 1.4.16 Palisades Nuclear Plant B 3.6.3-12 Revised 07/26/2017

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 07/26/2017

BASES BACKGROUND (continued)

Containment Cooling Systems B 3.6.6 If reliance is placed solely on 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. 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 SOC 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 07/26/2017

BASES BACKGROUND Containment Spray System (continued)

Containment Cooling Systems B 3.6.6 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, if the 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 07/26/2017

BASES BACKGROUND (continued)

Containment Air Cooler System Containment Cooling Systems B 3.6.6 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 07/26/2017

BASES Containment Cooling Systems B 3.6.6 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 07/26/2017

BASES APPLICABLE ANALYSES (continued)

Containment Cooling Systems B 3.6.6 The analysis and evaluation show that under the worst-case scenario, the highest peak containment pressure and the peak containment vapor 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 07/26/2017

BASES LCO APPLICABILITY Containment Cooling Systems B 3.6.6 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.

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 07/26/2017

BASES ACTIONS Containment Cooling Systems B 3.6.6 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 07/26/2017

BASES Containment Cooling Systems B 3.6.6 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 07/26/2017

BASES ACTIONS SURVEILLANCE REQUIREMENTS C.1 (continued)

Containment Cooling Systems B 3.6.6 If the Containment Spray side (tube side) of SOC 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 SOC 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-0911, 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.

SR 3.6.6.1 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 07/26/2017

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.6.3 Containment Cooling Systems B 3.6.6 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 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 Amendment No. 262 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.6.6 and SR 3.6.6.7 Containment Cooling Systems B 3.6.6 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 07/26/2017

BASES REFERENCES

1.

FSAR, Section 5.1

2.

FSAR, Section 14.18

3.

FSAR, Sections 6.2

4.

FSAR, Section 6.3 Containment Cooling Systems B 3.6.6

5.

ASME Code for Operation and Maintenance of Nuclear Power Plants.

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 Amendment No. 262 Revised 07/26/2017

MSSVs B 3.7.1 B 3.7 PLANT SYSTEMS B 3.7.1 Main Steam Safety Valves (MSSVs)

BASES BACKGROUND APPLICABLE SAFETY ANALYSES The primary purpose of the MSSVs is to provide overpressure protection for the secondary system. The MSSVs also provide protection against overpressurizing the Primary Coolant Pressure Boundary (PCPB) by providing a heat sink for the removal of energy from the Primary Coolant System (PCS) if the preferred heat sink, provided by the condenser and Circulating Water System, is not available.

Twelve MSSVs are located on each main steam header, outside containment, upstream of the main steam isolation valves, as described in the FSAR, Section 4.3.4 (Ref. 1). The MSSV rated capacity passes the full steam flow at RTP plus instrument error with twenty-three valves full open. This meets the requirements of the ASME Boiler and Pressure Vessel Code,Section III (Ref. 2). The MSSV design includes staggered lift settings, according to Table 3.7.1-1, in the accompanying LCO, so that only the number of valves needed will actuate. Staggered lift settings reduce the potential for valve chattering because of insufficient steam pressure to fully open all valves following a turbine reactor trip.

The design basis for the MSSVs comes from Reference 1 ; the purpose is to limit secondary system pressure to ~ 110% of design pressure when passing 100% of design steam flow. This design basis is sufficient to cope with any Anticipated Operational Occurrence (AOO) or accident considered in the Design Basis Accident (DBA) and transient analysis. (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.")

Palisades Nuclear Plant B 3.7.1-1 Revised 07/26/2017

BASES MSSVs B 3.7.1 APPLICABLE The events that challenge the MSSV relieving capacity, and thus PCS SAFETY ANALYSES pressure, are those characterized as decreased heat removal events, (continued) and are presented in the FSAR, Sections 14.12 and 14.13 (Refs. 3 and

4) respectfully. Of these, the full power loss of external load event is the most limiting. The event is initiated by either a loss of external electrical load or a turbine trip. No credit is taken for direct reactor trip on turbine trip, the turbine bypass valve, atmospheric dump valves, or pressurizer PORVs. The reduced heat transfer causes an increase in PCS temperature, and the resulting PCS fluid expansion causes an increase in pressure. The PCS pressure increases to ::; 2614.9 psia, this peak pressure is < 110% of the design pressure, or 2750 psia for the primary system, with the pressurizer safety valves providing relief capacity. The secondary system pressure increases to 1040.8 psia, this pressure is LCO APPLICABILITY

< 110% of the design pressure, or 1100 psia for the secondary system, with the MSSVs providing relief capability.

The MSSVs satisfy Criterion 3 of 10 CFR 50.36(c)(2).

This LCO requires twenty-three MSSVs to be OPERABLE in compliance with Reference 2. The OPERABILITY of the MSSVs is defined as the ability to open within the lift setting tolerances and to relieve steam generator overpressure. The OPERABILITY of the MSSVs is determined by periodic surveillance testing in accordance with the INSERVICE TESTING PROGRAM.

The lift settings, according to Table 3.7.1-1 in the accompanying LCO, correspond to ambient conditions of the valve at nominal operating temperature and pressure.

This LCO provides assurance that the MSSVs will perform their designed safety function to mitigate the consequences of accidents that could result in a challenge to the PCPB.

In MODES 1, 2, and 3 a minimum of twenty-three MSSVs are required to be OPERABLE, to provide overpressure protection required by both ASME Code and the accident analysis.

In MODES 4 and 5, there are no credible transients requiring the MSSVs.

The steam generators are not normally used for heat removal in MODES 5 and 6, and thus cannot be overpressurized; there is no requirement for the MSSVs to be OPERABLE in these MODES.

Palisades Nuclear Plant B 3.7.1-2 Amendment No. 262 Revised 07/26/2017

BASES ACTIONS SURVEILLANCE REQUIREMENTS MSSVs B 3.7.1 With one or more required MSSVs inoperable, the ability to limit system pressure during accident conditions will be degraded. The four hour Completion Time allows the operator a reasonable amount of time to make minor repairs or adjustments to restore the required number of inoperable MSSVs to OPERABLE status.

B.1 and B.2 If the required MSSVs cannot be restored to OPERABLE status in the associated Completion Time, the plant must be placed in a MODE in which the LCO does not apply. To achieve this status, the plant must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in 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.

SR 3.7.1.1 This SR verifies the OPERABILITY of the MSSVs by the verification of each MSSV lift setpoints in accordance with the INSERVICE TESTING PROGRAM. The safety and relief valve tests are performed in accordance with ASME Code (Ref. 5) and include the following for MSSVs:

a.

Visual examination;

b.

Seat tightness determination;

c.

Setpoint pressure determination (lift setting); and

d.

Compliance with owner's seat tightness criteria.

Palisades Nuclear Plant B 3.7.1-3 Amendment No. 262 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS REFERENCES SR 3.7.1.1 (continued)

MSSVs B3.7.1 The ANSI/ASME Standard requires that all valves be tested every 5 years, and a minimum of 20% of the valves tested every 24 months.

The ASME Code specifies the activities and frequencies necessary to satisfy the requirements.

Table 3.7.1-1 allows a +/- 3% setpoint tolerance for OPERABILITY; however, the valves are reset to +/- 1 % during the Surveillance to allow for drift.

The ambient temperature of the operating environment shall be simulated during the set-pressure test in accordance with Reference 5.

1.

FSAR, Section 4.3.4

2.

ASME, Boiler and Pressure Vessel Code,Section III, Article NC-7000, Class 2 Components

3.

FSAR, Section 14.12

4.

FSAR, Section 14.13

5.

ASME Code for Operation and Maintenance of Nuclear Power Plants.

Palisades Nuclear Plant B 3.7.1-4 Amendment No. 262 Revised 07/26/2017

AFW System B 3.7.5 B 3.7 PLANT SYSTEMS B 3.7.5 Auxiliary Feedwater (AFW) System BASES BACKGROUND The AFW System automatically supplies feedwater to the steam generators to remove decay heat from the Primary Coolant System upon the loss of normal feedwater supply. The AFW pumps take suction through a common suction line from the Condensate Storage Tank (CST)

(LCO 3.7.6, "Condensate Storage and Supply") and pump to the steam generator secondary side via two separate and independent flow paths to a common AFW supply header for each steam generator. The steam generators function as a heat sink for core decay heat. The heat load is dissipated by releasing steam to the atmosphere from the steam generators via the Main Steam Safety Valves (MSSVs) (LCO 3.7.1, "Main Steam Safety Valves (MSSVs)") or Atmospheric Dump Valves (ADVs)

(LCO 3.7.4, "Atmospheric Dump Valves (ADVs)"). If the main condenser is available, steam may be released via the turbine bypass valve.

The AFW System consists of two motor driven AFW pumps and one steam turbine driven pump configured into two trains. One train (AlB) consists of a motor driven pump (P-8A) and the turbine driven pump (P-8B) in parallel, the discharges join together to form a common discharge. The AlB train common discharge separates to form two flow paths, which feed each steam generator via each steam generator's AFW penetration. The second motor driven pump (P-8C) feeds both steam generators through separate flow paths via each steam generator AFW penetration and forms the other train (C). The two trains join together at each AFW penetration to form a common supply to the steam generators.

Each AFW pump is capable of providing 100% of the required capacity to the steam generators as assumed in the accident analysis. The pumps are equipped with independent recirculation lines to prevent pump operation against a closed system.

Each motor driven AFW pump is powered from an independent Class 1 E power supply, and feeds both steam generators.

Palisades Nuclear Plant B 3.7.5-1 Revised 07/26/2017

BASES BACKGROUND (continued)

AFW System B3.7.5 The steam turbine driven AFW pump receives steam from the steam generator E-50A main steam header upstream of the Main Steam Isolation Valve (MSIV). The steam supply valve receives an open signal from the Auxiliary Feedwater Actuation Signal (AFAS) instrumentation.

The turbine driven AFW pump feeds both steam generators through the same flow paths as motor driven AFW pump P-8A.

One pump at full flow is sufficient to remove decay heat and cool the plant to Shutdown Cooling (SOC) System entry conditions.

The AFW System supplies feedwater to the steam generators during normal plant startup, shutdown, and hot standby conditions.

The AFW System is designed to supply sufficient water to the steam generators to remove decay heat with steam generator pressure at the setpoint of the MSSVs, with exception of AFW pump P-8C. If AFW pump P-8C is used, operator action may be required to either trip the four Primary Coolant Pumps (PCPs), start an additional AFW pump, or reduce steam generator pressure. This will allow the required flowrates to the steam generators that are assumed in the safety analyses.

Subsequently, the AFW System supplies sufficient water to cool the plant to SOC entry conditions, and steam is released through the ADVs, or the turbine bypass valve if the condenser is available.

The AFW System actuates automatically on low steam generator level by an AFAS as described in LCO 3.3.3, "Engineered Safety Feature (ESF)

Instrumentation" and 3.3.4, "ESF Logic." The AFAS initiates signals for starting the AFW pumps and repositioning the valves to initiate AFW flow to the steam generators. The actual pump starts are on an "as required" basis. P-8A is started initially, if the pump fails to start, or if the required flow is not established in a specified period of time, P-8C is started. If P-8A and P-8C do not start, or if required flow is not established in a specified period of time, then P-8B is started.

The AFW System is discussed in the FSAR, Section 9.7 (Ref. 1).

Palisades Nuclear Plant B 3.7.5-2 Revised 07/26/2017

BASES AFW System B 3.7.5 APPLICABLE The AFW System mitigates the consequences of any event with a loss SAFETY ANALYSES of normal feedwater.

LCO The design basis of the AFW System is to supply water to the steam generator to remove decay heat and other residual heat, by delivering at least the minimum required flow rate to the steam generators at pressures corresponding to the lowest MSSV set pressure plus 3% with the exception of AFW pump P-8C. If AFW pump P-8C is used, operator action may be required to either trip the four PCPs, start an additional AFW pump or reduce steam generator pressure. This will allow the required flowrate to the steam generators that are assumed in the safety analyses.

The limiting Design Basis Accident for the AFW System is a loss of normal feedwater.

In addition, the minimum available AFW flow and system characteristics impact the analysis of a small break loss of coolant accident.

The AFW System design is such that it can perform its function following loss of normal feedwater combined with a loss of offsite power with one AFW pump injecting AFW to one steam generator.

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

This LCO requires that two AFW trains be OPERABLE to ensure that the AFW System will perform the design safety function to mitigate the consequences of accidents that could result in overpressurization of the primary coolant pressure boundary. Three independent AFW pumps, in two diverse trains, ensure availability of residual heat removal capability for all events accompanied by a loss of offsite power and a single failure.

This is accomplished by powering two pumps from independent emergency buses. The third AFW pump is powered by a diverse means, a steam driven turbine supplied with steam from a source not isolated by the closure of the MSIVs.

Palisades Nuclear Plant B 3.7.5-3 Revised 07/26/2017

BASES LCO (continued)

APPLICABILITY The AFW System is considered to be OPERABLE when the AFW System B 3.7.5 components and flow paths required to provide AFW flow to the steam generators are OPERABLE. This requires that the two motor driven AFW pumps be OPERABLE in two diverse paths, each supplying AFW to both steam generators. Prior to making the reactor critical during a plant startup, the turbine driven AFW pump shall be OPERABLE and capable of supplying AFW flow to both steam generators. When steam generator pressure is reduced, it is not required to have design inlet pressure available to the turbine driver in order to declare the turbine driven AFW pump OPERABLE.

As steam generator pressure drops, the required AFW pump discharge head decreases accordingly. The reduced steam generator pressure available at lower temperatures in MODE 3 does not inhibit the turbine driven AFW pump's ability to feed the steam generator (Ref. 3). The piping, valves, instrumentation, and controls in the required flow paths shall also be OPERABLE.

The LCO is modified by three Notes. Note one indicates that only one AFW train, which includes a motor driven pump, is required to be OPERABLE in MODE 4. This is because of reduced heat removal requirements, the short period of time in MODE 4 during which AFW is required, and the insufficient steam pressure available in MODE 4 to power the turbine driven AFW pump.

Note two states that the turbine driven AFW pump is only required to be made OPERABLE prior to making the reactor critical. It is required to be OPERABLE during subsequent MODE 1, 2, and 3 operation. This allowance is needed to provide sufficient steam pressure to perform turbine and pump testing. Note three indicates that any two AFW pumps may be placed in manual mode for the purpose of testing, for not more than 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . In this situation, the third AFW pump would still be available in the event of a plant transient. The two pumps that are in manual could be used at the discretion of the operator.

In MODES 1, 2, and 3, the AFW System is required to be OPERABLE and to function in the event that the main feedwater is lost. In addition, the AFW System is required to supply enough makeup water to replace steam generator secondary inventory, lost as the plant cools to MODE 4 conditions.

During heatup, the turbine driven AFW pump is only required to be made OPERABLE prior to making the reactor critical. It is required to be OPERABLE during subsequent MODE 1, 2, and 3 operation. This allowance is needed to provide sufficient steam pressure to perform turbine and pump testing.

Palisades Nuclear Plant B 3.7.5-4 Revised 07/26/2017

BASES APPLICABILITY (continued)

ACTIONS AFW System B 3.7.5 In MODE 4, the AFW System may be used for heat removal via the steam generator.

In MODES 5 and 6, the steam generators are not normally used for decay heat removal, and the AFW System is not required.

A Note prohibits the application of LCO 3.0.4.b to an inoperable AFW train. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an AFW train inoperable 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.

Condition A is applicable whenever one or more AFW trains is inoperable, in MODE 1, 2, or 3. 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 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is based on the assumption that at least 100% of the required AFW flow (that assumed in the safety analyses) is available to each steam generator. If the flow available to either steam generator is less than 100% of the required AFW flow, or if less than two AFW pumps are OPERABLE, Condition B must also be entered. In addition, if the combined flow available to both steam generators is less than 100% of the required AFW flow, Condition C must be entered as well.

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 AFW system can provide one hundred percent of the required AFW flow to each steam generator following the occurrence of any single active failure. Therefore, the AFW 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.

Palisades Nuclear Plant B 3.7.5-5 Revised 07/26/2017

BASES ACTIONS (continued)

B.1 and B.2 AFW System B 3.7.5 Condition B is applicable: 1) when the Required Actions of Condition A cannot be completed within the required Completion Time, 2) when the flow available to either steam generator is less than 100% of the required AFW flow, or 3) when less than two AFW pumps are OPERABLE.

Condition A is applicable whenever one or more trains is inoperable.

Therefore, when Condition B is applicable, Condition A is also applicable.

(If the combined flow available to both steam generators is less than 100% of the required AFW flow, 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.

Continued plant operation is not allowed if the available AFW flow to either steam generator is less than the required flow, because adequate AFW flow cannot be assured following a main steam line break affecting that steam generator (consider the case where the break occurs in the AFW piping). Therefore, if 1) the inoperable AFW trains cannot be restored to OPERABLE status within the required Completion Time of Condition A, or 2) the flow available to either steam generator is less than 100% of the required AFW flow, or 3) less than two AFW pumps are OPERABLE in MODES 1, 2, and 3, the plant must be placed in a MODE in which the LCO does not apply (except as noted in Condition C). To achieve this status, the plant must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in 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 3.7.5-6 Revised 07/26/2017

BASES ACTIONS (continued)

AFW System B 3.7.5 Condition C is applicable if the combined flow available to both steam generators is less than 100% of the required AFW flow; Condition A is applicable whenever one or more trains is inoperable; and Condition B is applicable when the flow available to either steam generator is less than 100% of the required AFW flow, or when less than two AFW pumps are OPERABLE. Therefore, when Condition C is applicable, Conditions A and B are also applicable. Being in Conditions A, B, and C concurrently maintains the Completion Time clocks for instances where equipment repair allows exit from Condition C while the plant is still within the applicable conditions of the LCO.

One hundred percent AFW flow (that assumed in the safety analyses) can be provided by anyone OPERABLE AFW pump and an OPERABLE flow path to each steam generator.

Required Action C.1 is modified by a Note indicating that all required MODE changes or power reductions are suspended until at least 100% of the required AFW flow is available. In this condition, there may be inadequate AFW flow available to remove decay heat and allow a stable plant shutdown.

With less than 100% of the required AFW flow available (ie. less than the AFW flow assumed in the safety analyses, while in MODES 1, 2, and 3, or less than the required AFW train OPERABLE while in MODE 4 with a steam generator relied upon for heat removal), the plant is in a seriously degraded Condition with no safety related means for conducting a cooldown, and only limited means for conducting a cooldown with nonsafety grade equipment. In such a condition, the plant should not be perturbed by any action, including a power change, that might result in a trip. The seriousness of this condition requires that action be started immediately to restore at least 100% of the required AFW flow available.

LCO 3.0.3 is not applicable, as it could force the plant into a less safe condition.

Palisades Nuclear Plant B 3.7.5-7 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS SR 3.7.5.1 AFW System B 3.7.5 Verifying the correct alignment for the required manual, power operated, and automatic valves in the AFW water and steam supply flow path provides assurance that the proper flow paths exist for AFW operation.

This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct position prior to locking, sealing, or securing. This SR also does not apply to valves that cannot be inadvertently misaligned, such as check valves. This Surveillance does not require any testing or valve manipulations; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position.

This test need not be performed for the steam driven AFW pump for MODE 4 operation.

The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

SR 3.7.5.2 Verifying that each required AFW pump's developed head at the flow test point is greater than or equal to the required developed head ensures that AFW pump performance has not degraded during the cycle. Flow and differential head are normal tests of pump performance required by the ASME Code (Ref. 2). This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance.

This SR is modified by a Note indicating that this SR for the turbine driven AFW pump does not have to be met in MODE 3 when steam pressure is below 800 psig. This is because there is insufficient steam pressure and pump discharge pressure to allow the turbine driven pump to reach the normal test conditions.

Performance of inservice testing as discussed in the ASME Code (Ref.

2), and the INSERVICE TESTING PROGRAM satisfies this requirement.

Palisades Nuclear Plant B 3.7.5-8 Amendment No. 262 Revised 07/26/2017

BASES SURVEILLANCE REQUIREMENTS (continued)

REFERENCES SR 3.7.5.3 AFW System B 3.7.5 This SR ensures that AFW can be delivered to the appropriate steam generator, in the event of any accident or transient that generates an AFAS, by demonstrating that each automatic valve in the flow path actuates to its correct position on an actual or simulated actuation signal.

Specific signals (e.g., AFAS) are tested under Section 3.3, "Instrumentation." This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The 18 month Frequency is acceptable, based on the design reliability and operating experience of the equipment.

This SR is modified by a Note which states the SR is only required to be met in MODES 1,2, and 3 when AFW is not in operation. With AFW in operation, the required trains are already aligned with the flow control valves in manual control.

SR 3.7.5.4 This SR ensures that the AFW pumps will start in the event of any accident or transient that generates an AFAS by demonstrating that each AFW pump starts automatically on an actual or simulated actuation signal. Specific signals (e.g., AFAS, handswitch) are tested under Section 3.3, "Instrumentation."

This test need not be performed for the steam driven AFW pump for MODE 4 operation.

The 18 month Frequency is acceptable, based on the design reliability and operating experience of the equipment.

This SR is modified by a Note. The Note states that the SR is only required to be met in MODES 1, 2, and 3. In MODE 4, the required pump is already operating and the autostart function is not required.

1.

FSAR, Section 9.7

2.

ASME Code for Operation and Maintenance of Nuclear Power Plants.

3.

Palisades Design Basis Document 1.03, Auxiliary Feedwater System, Section 3.4.1.

Palisades Nuclear Plant B 3.7.5-9 Amendment No. 262 Revised 07/26/2017

BASES Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 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-18B 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 08/08/2017

BASES Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 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.

APPLICABILITY 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.

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 08/08/2017

BASES ACTIONS Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 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.l 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 Fuel transfer pump P-18A can be controlled either manually or automatically via fuel oil day tank level controls. Fuel transfer pump P-18B can only be controlled manually. The P-18A fuel transfer system is OPERABLE if fuel oil can be transferred either automatically or manually by the P-18A fuel transfer pump.

If a fuel oil system is incapable of supplying fuel oil to a day tank or an engine mounted tank as required, then only the DG associated with that day tank or engine mounted tank is required to be declared inoperable if the fuel transfer system is not restored to OPERABLE status within its specified Completion Time.

Since DG 1-2 cannot power fuel transfer pump P-18B, without P-18A, DG 1-2 becomes dependent 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-18B, 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 Palisades Nuclear Plant B 3.8.3-3 Revised 08/08/2017

BASES ACTIONS C.1, 0.1, and E.1 (continued)

Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 be limited since an additional single active failure (P-18A) could disable the onsite power system. Because the loss of P-18B 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.

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.

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 08/08/2017

BASES SURVEILLANCE REQUIREMENTS SR 3.8.3.1 Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 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 08/08/2017

BASES SURVEILLANCE REQUIREMENTS SR 3.8.3.3 (continued)

Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 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 0975 (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 08/08/2017

BASES SURVEILLANCE REQUIREMENTS REFERENCES SR 3.8.3.5 (continued)

Diesel Fuel, Lube Oil, and Starting Air B 3.8.3 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.

SR 3.8.3.6 This SR demonstrates that the fuel transfer systems can, as applicable, automatically and manually transfer fuel from the Fuel Oil Storage Tank to each day tank, and automatically from each day tank to each engine mounted tank. Automatic or manual transfer of fuel oil is required to support continuous operation of standby power sources.

This SR provides assurance that the following portions of the fuel transfer system are OPERABLE:

a.

Fuel transfer pumps;

b.

Day and engine mounted tank filling solenoid valves;

c.

Day tank fill via automatic level controls or manual operation; and

d.

Engine mounted tank fill via 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.

1.

Regulatory Guide 1.137

2.

ANSI N195-1976

3.

ASTM Standards, 0975, 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 08/08/2017

PNP 2017-067, Submittal of Changes to Palisades Nuclear Plant Technical Specifications Bases

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