Text

Technical Specifications Bases Revisions 38, 39, and 40 Update
	ML063480336
Person / Time
Site:	Palo Verde
Issue date:	12/05/2006
From:	Bauer S; Arizona Public Service Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	102-05605-SAB/TNW/RKR
	Download: ML063480336 (87)
	v • d • e

Technical Specification 5.5.14 L A M

A subsidiary of Pinnacle West Capital Corporation Scott A. Bauer Department Leader, Regulatory Affairs Tel. 623-393-5978 Mail Station 7636 Palo Verde Nuclear Fax 623-393-5442 PO Box 52034 Generating Station e-mail: sbauer@apsc.com Phoenix, Arizona 85072-2034 102-05605-SAB/TNW/RKR December 05, 2006 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001

Dear Sirs:

Subject:

Palo Verde Nuclear Generating Station (PVNGS)

Units 1, 2 and 3 Docket Nos. STN 50-528/529/530 Technical Specifications Bases Revisions 38, 39, and 40 Update Pursuant to PVNGS Technical Specification (TS) 5.5.14, "Technical Specifications Bases Control Program," Arizona Public Service Company (APS) is submitting changes to the TS Bases incorporated into Revision 38, implemented on September 20, 2006, Revision 39, implemented November 20, 2006, and Revision 40, implemented on November 20, 2006. The Revision 38 insertion instructions and replacement pages are provided in Enclosure 1. The Revision 39 insertion instructions and replacement pages are provided in Enclosure 2. The Revision 40 insertion instructions and replacement pages are provided in Enclosure 3.

No commitments are being made to the NRC by this letter. Should you have any questions, please contact Thomas N. Weber at (623) 393-5764.

Sincerely, SAB/TNW/RKR/gt A member of the STARS (Strategic Teaming and Resource Sharing) Alliance

-At Callaway 0 Comanche Peak 0 Diablo Canyon 0 Palo Verde 0 South Texas Project

Wolf Creek

U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Technical Specifications Bases Revisions 38, 39, and 40 Update Page 2

Enclosures:

1. PVNGS Technical Specification Bases Revision 38 Insertion Instructions and Replacement Pages

2. PVNGS Technical Specification Bases Revision 39 Insertion Instructions and Replacement Pages

3. PVNGS Technical Specification Bases Revision 40 Insertion Instructions and Replacement Pages cc:

B. S. Mallett M. B. Fields G. G. Warnick NRC Region IV Regional Administrator NRC NRR Project Manager NRC Senior Resident Inspector for PVNGS

ENCLOSURE 1 PVNGS Technical Specification Bases Revision 38 Insertion Instructions and Replacement Pages

PVNGS Technical Specifications Bases Revision 38 Insertion Instructions Remove Page:

Cover page List of Effective Pages, Pages 1/2 through List of Effective Pages, Page 7/8 B 3.3.1-45/3.3.1-46 B 3.3.2-9/3.3.2-10 B 3.3.5-23/3.3.5-24 B 3.4.4-1/3.4.4-2 B 3.4.5-1/3.4.5-2 B 3.4.5-3/3.4.5-4 B 3.4.6-3/3.4.6-4 B 3.4.7-3/3.4.7-4 B 3.4.14-3/3.4.14-4 through B 3.4.14-7/Blank Insert New Page:

Cover page List of Effective Pages, Pages 1/2 through List of Effective Pages, Page 7/8 B 3.3.1-45/3.3.1-46 B 3.3.2-9/3.3.2-10 B 3.3.5-23/3.3.5-24 B 3.4.4-1/3.4.4-2 B 3.4.5-1/3.4.5-2 B 3.4.5-3/3.4.5-4 B 3.4.6-3/3.4.6-4 B 3.4.7-3/3.4.7-4 B 3.4.14-3/3.4.14-4 through B 3.4.14-7/3.4.14-8 B 3.4.18-1/3.4.18-2 through B 3.4.18-7/3.4.18-8 B 3.6.4-1/3.6.4-2 B 3.6.6-3/3.6.6-4 B 3.8.3-3/3.8.3-4 B

B B

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Revision 38 September 20, 2006

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Revision 38 September 20, 2006

_,RPS..Instrumentation -

Operating B 3.3. 1 BASES ACTIONS (continued)

With a channel process measurement circuit that affects multiple functional units inoperable or in test, bypass or trip all associated functional units as listed below:

Process Measurement Circuit Functional Unit (Bypassed or Tripped)

1.

Linear Power (Subchannel or Linear)

2.

Pressurizer Pressure-High (Narrow Range)

3.

Steam Generator Pressure-Low Variable Overpower (RPS)

Local Power Density-High (RPS)

DNBR-Low (RPS)

Pressurizer Pressure-High (RPS)

Local Power Density-High (RPS)

DNBR-Low (RPS)

Steam Steam Steam Steam Steam Steam Generator Generator Generator Generator Generator Generator Pressure-Low

1 Level-Low

2 Level-Low (RPS)

(ESF)

4.

Steam Generator (Wide Range)

Level-Low Level-Low (RPS)

1 Level-Low (ESF)

2 Level-Low (ESF)

5.

Core Protection Calculator Local Power Density-High (RPS)

DNBR-Low (RPS)

A.1 and A.2 Condition A applies to the failure of a single trip channel or associated instrument channel inoperable in any RPS automatic trip Function.

RPS coincidence logic is two-out-of-four.

If one RPS channel is inoperable, startup or power operation is allowed to continue, providing the inoperable channel is placed in bypass or trip in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (Required Action A.).

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months allotted to bypass or trip the channel is sufficient to allow the operator to take all appropriate actions for the failed channel and still ensures that the risk involved in operating with the failed channel is acceptable.

The failed channel must be restored to OPERABLE status prior to entering MODE 2 following the next MODE 5 entry.

With a channel in bypass, the coincidence logic is now in a two-out-of-three configuration.

(continued)

PALO VERDE UNITS 1,2,3 B 3.3.1-45 REVISION 38

,RPS Instrumentation - Operating B 3.3.1 BASES ACTIONS A.1 and A.2 (continued)

The Completion'Time ofprior to entering MODE 2 following the next MODE 5,entry.is based on adequate channel to channel independence, which allows a two-out-of-three channel operation since no singlefailure will cause or

'Prevent a reactor trip.

The intent of this requirement is that should a failure occur that cannot be repaired during power operation, then continued operation is allowed without requiring a plant shutdown.

However, the failure needs to be repaired during the next MODE'5 outage:

Allowing the unit to exit MODE 5 is acceptable, as the appropriate retest may not be possible until normal operating pressures and temperatures are achieved.

If the failure occurs while in MODE 5, then the problem needs to be resolved during that shutdown, and OPERABILITY restored prior to the *subsequent MODE 2 entry.

B.1 Condition B applies to, the failure of two channels in any RPS automatic trip Function.

The Required Action is modified by a Note stating that

'CO 3.0.4 is not applicable.

The Note'was added to allow the changing of MODES, eventhough two'channels are 1inoperable, with one channel'bypassed and one tripped.

In this configurati'on, the protection.system is in a one-out-of-two lbgic, which is adequate to ensure that no random failure will prevent protection system operation.

Required Action B.,1 provides for placing one inoperable channel'in bypass, and the other channel in trip within the Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

This Completion Time is sufficient to allow the operator to take all appropriate actions for the failed channels while ens~uring the risk involved in operating with the failed channels is acceptable.

With one channel of protective instrumentation bypassed, the RPS is in a two-out-of-three logic; but with another channel failed, the RPS may be operating in a two-out-of-two logic.

This is outside the assumptions made in the analyses and should be corrected.

To correct the problem, the second channel is placed in trip.

(continued)

PALO VERDE UNITS 1.2,3 B 3.3.1-46 REVISION 38

,.RPS Instrumentation -

Shutdown B 3.3.2 BASES APPLICABILITY (continued)

The Steam Generator #1 Pressure-Low, and the Steam Generator #2 Pressure-Low trips; RPS.Logic, RTCBs, and Manual Trip are required in MODE 3 with the RTCBs closed, to provide protection for large MSLB events in MODE 3. The Steam Generator Pressure-Low trip in this lower MODE is addressed in this LCO.

The RPS Logic in MODES 1,2,3,4, and.5 is addressed in LCO 3.3.4, Reactor Protection System (RPS)

Logic and Trip Initiation.

The applicability for the Logarithmic Power Level-High function is modified by a Note that allows the trip to be bypassed when logarithmic power is > 1E-4% NRTP, and the bypass is automatically removed when logarithmic power is 1E-4% NRTP.

ACTIONS The most common causes of channel inoperability are outright failure or drift of the bistable or process module sufficient to exceed the tolerance allowed by the plant specific setpoint analysis.

Typically, the drift is found to be small and results in a. delay of actuation rather than a total loss of function.

This determination-is generally made during the performance of.a CHANNEL FUNCTIONAL TEST when the process instrument is set up for adjustment to bring it to within specification.

If the trip setpoint is'less conservative than'the Allowable Value stated in~the LCO, the channel is declared inoperable immediately, and the appropriate Condition(s) must be entered immediately.

In the event a channel's trip setpoint'is found nonconservative with. respect to the Allowable Value, or the excore logarithmic power.channel or RPS bistable trip unit is found inoperable, then ll affected Functions provided by that channel must be declared inoperable and the unit must enter the'Condition for, the particular protection Function affected.

(continued)

PALO VERDE UNITS 1,2,3 B 3.3.2-9 REVISION 35

I

,I RPS Instrumentation -

Shutdown B 3.3.2 BASES ACTIONS With a channel process measurement circuit that affects (continued) multiple functional units inoperable or in test, bypass or trip all associated functional units as listed below:

PROCESS MEASUREMENT CIRCUIT FUNCTIONAL UNIT (Bypassed or Tripped)

Steam Generator Pressure-Low Steam Generator Pressure - Low (RPS)

Steam Generator #1 Level - Low (ESF)

Steam Generator #2 Level - Low (ESF)

When the number of inoperable channels in a trip Function exceeds that specified in any related Condition associated with the same trip Function, then the plant is outside the safety analysis.

Therefore, LCO 3.0:3. is immediately

,entered, if applicable in the current MODE of operation.

A.L, and A.2-Condition A applies.to the failure of a single trip channel or associated instrument..channel inoperable in any RPS function.

The RPS coincidence logic is two-out-of-four.

If one channel is inoperable, operation in MODES 3, 4, and 5 is allowed to continue, providing the inoperable-channel is placed in bypass or trip in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months (Required Action A.).

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months allotted to bypass or trip the channel is sufficient to allow the operator to take all appropriate actions for the failed channel while ensuring that the risk involved in operating with the failed channel is acceptable.

The.failed channel must be restored to.OPERABLE status prior to entering MODE.2 following the next MODE 5 entry.

With a channel bypassed, the coincidence logic is now in a two-out-of-threeconfiguration.

The Completion Time is based on adequate channel to channel independence, which allows a two-out-of-three channel operation since.no single failure will cause or prevent a reactor trip.

The intent of this requirement is that should a failure occur that cannot be repaired during power operation, then continued operation is allowed without requiring a plant shutdown.

However, the failure needs to be repaired during the next MODE 5 outage.

Allowing the unit to exit MODE 5 is acceptable, as the appropriate retest may not be possible until normal operating pressures and temperatures are achieved.

If the failure occurs while in MODE 5, then the problem needs to be resolved during that shutdown, and OPERABILITY restored prior to the subsequent MODE 2 entry.

(continued)

PALO VERDE UNITS 1,2,3 B 3.3.2-10 REVISION 38

ESFAS Instrumentation B 3.3.5 BASES ACTIONS..

A.1 and A.2

(.continued)

The, Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months allotted to restore, bypass, or trip the channel is sufficient to allow the operator to take all appropriate actions for, the failed channel and still ensures-that the risk involved in operating with the failed.channel is acceptable.

The failed channel must be restored to OPERABLE status prior to entering MODE 2 following the next MODE 5 entry.

With a channel bypa.ssed, the. coincidence logic is now in a two-out-of-three,configuration.

The Completion Time of prior to entering'iMODE 2 following the next MODE 5 entry is based on adequate.'channel to channel independence, which allows a two-out-of-three channel operation, since no single failure will cause or prevent an ESF actuation.

The i.nteht of this requi.rement is that should a failure occur that cannot be repaired during power operation, then continued operation is allowed without requiring a plant shutdown.

However, the failure needs to be repaired during the next MODE 5 outage.

Allowing the unit to exit MODE 5 is acceptable, as the appropriate retest may not be possible until normal operating pressures and temperatures are achieved.

If the failure occurs while in MODE 5, then the problem-needs to.be resolved during that shutdown, and OPERABILITY restored prior to~the.subsequent MODE 2 entry.

B.1 The 'Required Action is modified by'a Note stating that LCO 3.0.4 is not"*applicable.*

The'Note was added to allow the changing of MODES'even though two channels are inoperable, with'one channel bypassed and one tripped.

In this configuration,the protection system is in a one-out-of-two logic,'which is adequate to ensure that no random'failure will prevent protection system operation.

Condition B applies to the failure of two channels of one or more input parameters in the following ESFAS automatic trip Functions:

1.

Safety Injection Actuation Signal Containment Pressure - High Pressurizer Pressure - Low

2.

Containment Spray Actuation Signal Containment Pressure - High High (continued)

PALO VERDE UNITS 1,2,3 B 3.3.5-23 REVISION 38

ESFAS Instrumentation B335 BASES ACTIONS B.1 (continued)

3.

Containment Isolation Actuation Signal Containment Pressure - High Pressurizer Pressure - Low

4.

Main Steam Isolation Signal Steam Generator #1 Pressure -'Low Steam Generator #2 Pressure'.- Low' Steam Generator #1 Level-High Steam Generator #2 Level-High..

Containment Pressure-High

5.

Recircul~ation Actuation Signal Refueling Water Storage Tank'Level -

Low

6.

Auxiliary Feedwater Actuation Signal SG #1 (AFAS-1)

Steam Generator #1 Level -

Low SG Pressure Difference (SG #2 > SG #1) - High

7.

Auxiliary. Feedwater Actuation Signal SG #2 (AFAS-2)

Steam Generator. #2 Level '.Low SG Pressure Difference (SG #1 > SG #2) - High With two'inoperable channels, power operation may continue, provided one inoperable channelis placed in bypass and the other channel is placed in trip withi,n 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

With one channel of protective inýtrumentatibh bypassed, the ESFAS Function is in two-out-of-three. logic in the bypassed input parameter, but with another.,ch~annel.failed, the ESFAS may be operating with a two-out-ofLtwologic,.This is outside the

,.assumptions made in the analyses and should be corrected.

To correct the problem, the second channel is placed in

trip, This places the ESFAS Function in a one-out-of-two logic.

If any of 'the other OPERABLE channels receives a trip signal, ESFAS actuation-will'occur.

One of the two inoperable channels will need to be restored to OPERABLE status prior to the next required CHANNEL FUNCTIONAL TEST because channel surveillance testing on an OPERABLE channel requires that the OPERABLE channel be placed in bypass.

However, it is not possible to bypass more than one ESFAS channel, and placing a second channel in trip will result in an.ESFAS actuation.

Therefore, if one ESFAS channel is-in trip and a second channel is in bypass, a third inoperable channel would place the unit in LCO 3.0.3.

(continued)

PALO VERDE UNITS 1,2,3B B 3.3.5-24 REVISION 38

RCS Loops -

MODES 1 and 2 B 3.4.4 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.4 RCS Loops -

MODES 1 and 2 BASES BACKGROUND The primary function of the RCS is removal of the heat generated in thefuel due to the fission process and transfer of this heat, via the steam generators (SGs),

to the secondary plant.

The seconda'ry functions of the RCS include:

a.

Moderating the neutron energy level to the thermal state,..to increase the probability of fission;

b.

Improving the neutron economy by acting as a

" reflector;

c.

Carrying the-soluble neutron poison, boric acid;

d.

Providing a second barrier against fission product release to the environment: and e.,

Removing the heat generated in the fuel due to fission product decay following a unit shutdown.

The RCS configuration for heat transport uses two RCS loops.

',Each RCS loop'contains a SG and two Reactor Coolant Pumps (RCPs),.

An'RCP is located in each ofthe two SG cold legs.

The pump flow rate has been sized to.provide core heat removal with appropriate margin to Departure from Nucleate Boiling (DNB) during power operation and for anticipated transients originating from power operation.

This Specification requires two RCS loops with both RCPs in operation.in each loop'.-.The intent of the Specification is to require core heat removal with forced flow during power operation.

Specifying two RCS loops provides the minimum necessary paths (two SGs) for heat removal.

APPLICABLE Safety analyses contain various assumptions for the Design SAFETY ANALYSES Bases Accident (DBA) initial conditions including RCS

'pressure, RCS temperature, reactor power level, core parameters,, and safety system setpoints.

The important (continued)

PALO VERDE UNITS 1,2,3 B 3.4.4-1 REVISION 0

RCS Loops -

MODES 1 and 2 B 3.4.4 BASES APPLICABLE aspect for this LCO is the reactor coolant forced flow rate, SAFETY ANALYSES which is represented by the number of RCS loops in service.

(continued)

The reactor coolant pumps.provide sufficient. forced circulation flow through the reactor coolant system to assure adequate heat removal from the reactor core during power operation.

The plant is designed to operate with both reactor coolant loops and associated reactor coolant pumps in operation, and maintain a departure from nucleate boiling ratio,(DNBR), above the DNBR. Safety Limit during all normal operations and anticipated transients.

The safety analyses that are ofmost importance to RCP operation are the total loss of reactor coolant flow, single-pump locked rotor, single pump (broken shaft or. coastdown),.and rod withdrawal events (Ref. 1).

RCS Loops -

MODES 1 and 2 satisfy Criterja 2 and 3 of 10 CFR 50.36 (C)(2)(i.i).

LCO The purpose of this LCO is.to require.adequate forced flow for core heat removal.

Flow is.represented by having both RCS loops with both RCPs in each loop._in operation for removal of heat by the two SGs.

To meet safety analysis acceptance criteria for DNB, four pumps are required at-rated power.

Each OPERABLE loop consists of two RCPs providing forced flow forheat transport to an SG that'is OPERABLE.

SG, and hence RCS loop, OPERABILITY:with regard to SG water level is ensured by the Reactor Protection System (RPS) in MODES 1 and 2.

(continued)

PALO VERDE UNITS 1,2,3 B 3.4.4-2 REVISION 38

RCS Loops -

MODE 3 B 3.4.5 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.5 RCS Loops -

MODE 3 BASES BACKGROUND The primary functiton of the reactor coolant in MODE 3 is removal of decay heat'and transfer of this heat, via the Steam Generators (SGs),

to the secondary plant fluid.

The secondary function of the reactor coolant is to act as a carrier for soluble neutron poison, boric acid.

In MODE 3, Reactor Coolant Pumps (RCPs) are used to provide forced :circulation heat removal'during heatup and cooldown.

The MODE 3 decay heat removal requirements are low enough that a single RCS loop with one RCP is sufficient to remove core decay heat.

However, two RCS loops are required to be OPERABLE to provide redundant paths for decay heat removal.

Only one RCP needs to be OPERABLE to declare the associated RCS loop OPERABLE.

Reactor coolant natural circulation is not normally used but is sufficient for core cooling.

However, natural circulation doesnot provide turbulent flow conditions.

Therefore,-boron reduction in natural circulation is prohibited because mixing to obtain a homogeneous concentration in all,.portions of the:RCS cannot be ensured.

APPLICABLE SAFETY ANALYSES

,Analyses have shown that the rod withdrawal event from MODE 3 withon&RCS loop in operation is bounded by the rod withdrawal initi.ated,from MODE 2.

Failure to provide heat removal may result in challenges to a fission product barrier. The-RCS loops are part of the primary success path that functions or actuates to prevent or mitigate a Design Basis Accident or transient that either assumes the failure of, or presents a challenge to, the integrity of a fission product barrier.

RCS Loops -

MODE 3 satisfy Criterion 3 of 10 CFR 50.36 (c)(2)(ii).

(continued)

REVISION 0 PALO VERDE UNITS 1,2,3 B 3.4.5-1

RCS Loops -

MODE 3 B 3.4.5 BASES LCO

.,The purpose of this LCO. is to require two RCS loops to be avai.lable for-heat removal, thus providing redundancy.

The LCO requires the two loops to be OPERABLE with the intent of requiring-both SGs to be.capable (Ž 25% wide rangewater level) of transferring heat from the reactor coolant at a controlled rate.

Forced reactor coolant flow is the required way to transportheat, although.natural circulation flow provides adequate removal..

A minimum of one running RCP meets the LCO requirement for one loop in operation.

The Note permits a limited period of operation without RCPs.

All RCPs may be de-energized for

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period.

This means that natural circulation, has been established.

When in natural circulation, a reduction in boron concentration is prohibited because an, even concentration distribution throughout the RCS cannot'be ensured.

The intent is to stop anyknownor direct positive reactivity additions to the RCS due. to dilution.

Core outlet temperature is to be maintlained at least 100F below the saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction, The 10 degrees F is considered the.actual value of the necessary difference between RCS core outlet temperature and the saturation temperature associated with RCS pressure to be maintained during the time the pumps would be de-energized.

The instrument error associated with determining this difference is 27*degrees F. (The only restriction for

-instrumentation use is with pressuri~zer pressure less than or equal to 350 psia, and in that situation the narrow range pressurizer pressure instrumentation must be used.)

Therefore, the indicated value-of the difference between RCS core outlet temperature and the saturation temperature associated with RCS pressure must be greater than or equal to 37 degrees F in order to use the provisions of the Note allowing the pumps to be de-energized.

In MODE 3 it is sometimes necessary to stop all RCPs (e.g.,

to perform surveillance or startup testing, or to avoid operation below the RCP minimum net positive suction head limit).

The time period is acceptable because natural circulation is adequate for heat removal, or the reactor coolant temperature can be maintained subcooled and boron stratification affecting reactivity control is not expected.

An OPERABLE RCS loop (loop 1 or loop 2) consists of at least one associated OPERABLE RCP and an associated SG that is OPERABLE.

(continued)

PALO VERDE UNITS 1,2,3 B 3.4.5-2 REVISION 38

RCS Loops -

MODE 3 B 3.4.5 BASES LCO An RCP is-OPERABLE, if it.

is capable-of being powered and is

(continued) able to provide forced flow.if required.

APPLICABILITY In MODE 3, the heat load is lower than at power: therefore,

one RCS loop in operation is adequate for transport and heat removal.

A second RCS loop is required to be OPERABLE but not -in operation for redundant heat removal capability.

Operation in other MODES is covered by:

LCO 31..4.4 "RCS Loops-MODES 1 and 2..-

LCO-3.4.6, "RCS Loops -

MODE 4";

LCO 3.. 4:7, "RCS Loops -

MODE 5, Loops Filled" LCO 3.4.8% "RCS Loops -

MODE 5, Loops Not Filled";

LCO 3.9.4, "Shutdown. Cooling.(SDC) and Coolant

Circulation - High Water Level" (MODE 6): and LCO 3.9.5,. "Shutdown Cooling (SDC). and Coolant Circulation -- Low Water, Level" (MODE 6).

ACTIONS A 1 If;one required RCS loop.is inoperable, redundancy for forced flow heat removal is lost.

The-Required Action is restoration of the required RCS loop. to OPERABLE status within a Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

This time allowance is,a justified period to be without the redundant, nonoperating l.oop because a single loop in operation has a heat transfer capability greater than that needed to remove the decay heat produced in the reactor core.

B.1 If restoration is not possible within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , the unit must be placed in MODE 4, within.12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

In MODE 4, the plant may be placed on the SDC System.

The Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is compatible with required operation to achieve cooldown and depressurization from the existing plant conditions in an orderly manner and without challenging plant systems.

(continued)

PALO VERDE UNITS 1,2,3 B 3.4.5-3 REVISION 38

RCS Loops -

MODE 3 B 3.4.5 BASES ACTIONS C.1 and C.2 (continued)

If no RCS loop is OPERABLE or in operation, all operations involving a reduction of RCS boropnconcentration must be immediately suspended.

This is necessary because boron dilution requires forced circulation~for proper homogenization.

Action to restore one RCS. loop to OPERABLE

-status and operation shall.be initiated immediately and continued until one RCS loop is restored to OPERABLE status and operation.

The immediate, Completion Times reflect the importance of maintaining operation for decay heat removal.

SURVEILLANCE SR 3.4.5.1 REQUIREMENTS This SR requires verification every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months that the required number of RCS loops are in operation and circulating Reactor Coolant.

'Verification includes flow rate, temperature, or pump s*tatus monitoring, which help ensure that forced flowis.providing heat removal.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months interval has-been shown by'operating practice to be sufficient to regularly assess degradation and verify operation within safety analyses a'ssumptions.

In addition, control room indication and alarms will normally indicate loop status.

SR 3.4.5.2 This.SR 'requi res vern i cati on,every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months that the secondary side water level in-each SG is Ž 25% wide range.

An adequate SG water level is required in order to :have a heat sink for removal Of the core decay heat from the reactor coolant.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months interval has been shown by operating practice to be sufficient to regularly assess degradation and verify operation within the safety analyses assumptions.

(continued)

PALO VERDE UNITS 1,2,3 B 3.4.5-4 REVISION 0

RCS Loops -

MODE 4 B 3.4.6 BASES LCO Note 2 requires, that before an RCP may be-started with any (continued)

RCS cold leg temperature

214°F during cooldown, or

291°F during heatup, that secondary side Water temperature (saturation temperature corresponding to SG pressure) in each.SG is <,1000.F above each of the RCS cold leg temperatures.

The numerical values for RCS cold leg temperature at which this Note is applicable do not account for all instrument uncertainty.

Use of an indicated value of'217°F or below during cooldown and 2941F or below during heatup ensures that the actual limits will not be exceeded.-

These values, which include appropriate instrument

.,uncertai'nty, are establisshed within the applicable plant procedures.

Satisfying the above condition will preclude a large pressure surge i.n the RCS when the RCP is started.

Note 3,,restricts RCP operation to no more than 2 RCPs with RC.S cold leg temperature : 200'F, and no more than 3 RCPs

wi.th.RCS cold leg temperature >200 0 F.but ! 500 0 F.

Satisfying. these conditions will maintain the analysis assumptions of the flow induced pressure correction factors

,due to RCP operation (Ref. 1)

An OPERABLE RCS loop consists of at least one OPERABLE RCP and an SG that is OPERABLE and has the minimum water level specified in SR 3.4.6.2.

Similarly, for the SDC System, an OPERABLE SDC train is composed of anOPERABLE SDC pump (CS or LPSI) capable of providing flow to the SDC heat exchanger for heat removal.

RCPs and SDC-pumps are OPERABLE if they are capable of being powered and areable to prov~ide, flow. if required.

APPLICABILITY In MODE 4, this LCO applies because it is possible core decay heat and to provide proper boron mixing-either the RCS loops and SGs or the SDC System.

to remove with Operation in other MODES is covered by:

LCO 3.4.4 "RCS Loops-MODES 1 and 2";

LCO 3.4.5, "RCS Loops -

MODE 3";

(continued)

PALO VERDE UNITS 1,2,3 B 3.4.6-3 REVISION 38

RCS Loops -

MODE 4 B 3.4.6 BASES APPLICABILITY LCO 3.4.7, 'RCS. Loops.- MODE 5, Loops Filled.

(continued)

LCO 3.4.8'"RCS Loops -

MODE 5, Loops. Not Filled";

LCO 3.9.4, "Shutdown Cooling (SDC) and Coolant Circulation - High Water Level" (MODE 6): and LCO 3.9.5, "Shutdown Cooling (SDC) and Coolant Circulation-Low Water Level" (MODE 6).

ACTIONS A.1 If only one required RCS loop is OPERABLE and in operation, redundancy for heat removal is lost.

Action must be initiated immediately to restore a'second loop to OPERABLE status.

The immediate Completion Time reflects the importance of maintaining the availabil-ity, of two paths for decay heat removal.

B.1 If only one required SDC train 'is OPERABLE and in operation, redundancy for heat removal is lost.

The plant must be placed in MODE 5 within the next 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .,

Placing the plant in MODE 5 is a conservative action with regard to_

decay heat removal.

With only one SDC-train OPERABLE, redundancy for decay heat removal is lost and, in the event

of a loss of the remaining SDC train,.it would be safer to initiate that loss from MODE 5 (* 210°F) rather than MODE 4 (210°F to 350 0F).

The Completion lime of.24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable, based onoperating experience' to reach MODE 5 from MODE 4, with only one.SDC train operating, in an orderly manner-and without challenging plant systems.

C.1 and C.2, If no RCS loops or SDC trains are OPERABLE, or in operation, all operations involving reduction of RCS boron concentration must be suspended and action to restore one RCS loop or SDC train to OPERABLE status and operation must be initiated.

Boron dilution requires forced circulation for proper mixing, and the-margin to criticality must not be reduced in this type of operation.

The immediate Completion Times reflect the importance of decay heat removal.

The action to restore must continue until one loop or train is restored to operation.

(continued)

PALO VERDE UNITS 1,2,3 B 3,4.6-4 REVISION 6

I*

I.RCS Loops -

MODE 5, Loops Filled B 3.4.7 BASES LCO in order to use the provisions of the Note allowing the (continued) pumps to be de-energized.

In this MODE,. the SG(s) can be usedas the-backup for SDC heat'removal.

To ensure their

,availability, the RCS loop flow path is to be maintained with.subcooled liquid.

In MODE 5ý, it is sometimes necessary to stop all RCP or SDC forced circulation.

This is permitted to change operation from one SDC train to the other, perform surveillance or startup testing, perform the transition to and from the SDC, or to avoid operation below the RCP minimum net positive suction head limit.

The time period is acceptable because natural circulation is acceptable for decay heat removal the reactor coolant :temperature can be maintained subcooled, and boron, stratification affecting reactivity control is not expected.

Note 2 allows one SDC train to be inoperable for a period of up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months provided.that the other SDC train is OPERABLE and in operation.

This permits periodic surveillance tests to be performed on the inoperable train during the only time when such testing is safe and possible.

Note 3 requires that before an RCP may be started with any

.RCS co,ld leg. temperature.* 214°F during a cooldown, or 291°F during'a heatup, the secondary side water temperature (saturation temperature corresponding to SG pressure) in each SG must be < 100°F above each of the RCS cold leg temperatures.

The.numerical values for RCS cold leg.,temperature at which this Note is applicable do not account for all-inistrument uncertainty.'

Use of an indicated value of 217°F or'below during cooldown and 294°F or below during heatup ensures that the actual l.imits will not be exceeded.

These values, which include appropriate instrument uncertainty, are established within the applicable plant procedures.

Satisfying the above condition will preclude a low temperature overpressure event due to a thermal transient when the RCP is started.

Note 4 restricts RCP operation to no more than 2 RCPs with RCS-cold leg temperature 5 200'F, and no more than 3 RCPs with RCS cold leg temperature > 200 0F but

5000 F.

Satisfying these conditions will maintain the analysis assumptions of the flow induced pressure correction factors due to RCP operation (Ref. 3).

(continued)

PALO VERDE UNITS 1,2,3 B 3.4.7-3 REVISION 6

RCS Loops -

MODE 5, Loops Filled B 3.4.7 BASES LCO Note. 5 provides for an orderly transition from MODE 5 to (continued)

MODE"4 during a planned heatup-by permitting removal of SDC trains from operation when at least'one RCP is in.

operation.

This Note provides for the transition to MODE 4'where an RCP is permitted to be in operation and replaces the RCS circulation function provided by the SDC1 trains.

An OPERABLE SDC train is composed, of an OPERABLE SDC pump (CS or LPSI) capable of providing flow to the SDC heat exchanger for heat removal.

SDC pumps are OPERABLE. if-they.are.-capable of being powered and are able to provide flow (current Section XI), if required.

A SG can perform as a heat sink when it is OPERABLE and has the minimum water level specified in SR 3.4.7.2.

I The RCS loops may not be considered filled until two conditions needed for operation of the steam generators are met.

First, the RCS'must be intact: This means that all

.removable'portions of the primary "pressure boundary (e.g.,

manways, safety valves) are securely fastened.

Nozzle dams are removed.

All manual drain and vent valves are closed, and any open system penetrations (e.g., letdown, reactor head vents) are capable of remote closure from the control room.

An intact-primary allows the system to be pressurized as needed to achieve the subcooling margin necessary to establish natural circulation cooling.

When the RCS is not intact, as described, 'a loss'of SDC flow results in blowdown 6f,"coolant through boundary openings that also could prevent adequate natural circulation between the core and steam generators.

Secondly, the concentration of dissolved or otherwise entrained gases in the coolant must be limited or other controls established so that gases coming out of solution in the SG U-tubes will not adversely affect natural circulation.

With these-conditions.met, the SGs are a functional method of RCS heat removal upon loss of the operating SDC train.

The ability to feed and steam SGs at all times is riot required when RCS temperature is less than 210°F because significant loss of SG inventory through boiling will not occur during time anticipated to take corrective action.

The required SG level provides sufficient time toeither restore the SDC train or implement a method for feeding and steaming the SGs (using non-class components if necessary).

(continued)

PALO VERDE UNITS 1,2,3 B. 3.4. 7-4 REVISION 38

RCS Operational LEAKAGE B 3.4.14 BASES APPLICABLE on operating experience as an indicatioh of one or more SAFETY ANALYSES propagating tube leak mechanisms.

This leakage rate limit (continued) provides additional assurance against tube rupture at normal and faulted conditions and provides additional assurance that cracks will not propagate to burst prior to detection by leakage monitoring methods and commencement of plant shutdown.

RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36 (C)(2)(ii).

LCO RCS bperational,LEAKAGE'shall be limited to:

a.

Pressure Boundary LEAKAGE No, pressure boundary LEAKAGE is allowed, being indicative of material deterioration.

LEAKAGE of this type is unacceptable as the leak itself could cause further., deterioration, resulting in higher LEAKAGE.

'Violation'of thisLCO could result in continued degradation of the RCPB.

LEAKAGE past seals and gaskets is.not pressure boundary LEAKAGE.

b..

Unidentified LEAKAGE.

One gallor-per minute (gpm of Unidentified LEAKAGE is all6wed as a reasonable minimum detectable amount that the con tainment.air, monitoring and containment sump level monitoring equipment can detect within a

reasonabl, etime period.

Violation of this LCO could result in cohtinued degradation of the RCPB, if the LEAKAGE i s,frobmthe.,.pressure' boundary.

c.

Ident*ified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because,LEAKAGE, is from known sources that do not interfere with~detecti:on of unidentified LEAKAGE and is well within the capability of the RCS makeup system.

Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled Reactor Coolant Pump (RCP) seal leakoff (a normal function not considered LEAKAGE).

Violation of this LCO could result in continued degradation of a component or system.

(continued)

PALO VERDE UNITS 1,2,3 B 3.4. 14-3 REVISION 34

I...

RCS Operational LEAKAGE B 3.4.14 BASES LCO (continued)

LCO 3.4.15, "RCS Pressure Isolation Valve (PIV)

Leakage," measures leakage through each individual PIV and can impact this LCO.

Of the two PIVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leaktight.

If both valves leak and result in a loss of mass from the RCS, the loss must be included in the allowable identified'LEAKAGE.

d.

Primary to Secondary LEAKAGE through Any One SG The limit of 150 gallons per day-per SG is based on the operational LEAKAGE performance criterion in NEI 97-06, Steam Generator Program'Guidelines (Ref. 7).

The Steam 'Generator Program bpe'rational LEAKAGE performance criterion in NEI 97-06 states, "The RCS operational primary to secondary Teakage through any one SG shall be limited to 150 gallons per day."

The limit is based 'on'.operating experience with SG tube degradation mechanisms,thIat result'in tube leakage.

The operational leakage ratecriterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube'*ruptures.

APPLICABILITY In MODES 1, 2, 3, and 4, the'potenti'al for RCPB LEAKAGE is greatest when the RCS is-pressurized.:

In MODES 5 and 6, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.

(conti nued)

PALO VERDE UNITS 1,2,3 B 3.4.14-4 REVISION 38

RCS Operational LEAKAGE B 3.4.14 BASES ACTIONS A.1 Unidentified LEAKAGE or identified LEAKAGE in excess of the LCO limits must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

,This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to

.within limits before the reactor must be shut down.

This action is necessary to prevent further deterioration of the RCPB.

B.1 and B.2 If'any *iressure'boundary LEAKAGE, exists, or primary to

,secondary LEAKAGE is not within limits, or if unidentified

o..identified LEAKAGE cannot be reduced to within limits

.withi-n 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ' the reactor must.be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences.

The reactor 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 .

Thi.s-action'redoces the LEAKAGE and also reduces the factors that tend-fo.degrade the pressure boundary.

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

In MODE 5, the pressure stresses acting,.on the RCPB are much lower, and further, deterioration is much less likely.

(continued)

PALO VERDE UNITS 1,2,3 B 3.4.14-5 REVISION 38

RCS Operational LEAKAGE B 3.4.14 BASES SURVEILLANCE SR 3.4.14.1 REQUIREMENTS Verifying RCS LEAKAGE to be-within the LCO limits ensures the integrity of:the RCPB is maintained.,Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection.

Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.

The RCS water inventory balance must be performed with the reactor at steady state operating conditions (stable pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and;RCP seal injection and return flows).

This surveillance is modified by two notes.

Note 1 states that this SR is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishing steady state operation.

This means that once steady state operating conditions are established, 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is allowed for completing the Surveillance.

When required by.the Frequency, and after steady state operating conditions are established, the surveillance must be completed prior to the end of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation.

If steady state operating conditionshave not been established for 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , this surveillance is not required until Steady state operation is established for 12.hours.

This SR is not required to be

..completed prior to changing MODES if-steady state operation has not been established 'f6r 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides sufficieht time tQ collect and process all necessary data after stable plantconditions are established.

Further-discussion of SR note format is found in Section 1.4, Frequency.

Note 1 allows for SR 3.4.14.1 nonperformance due to planned or unplanned transients.

This Note is not intended to allow transients solely for the purpose of avoiding SR 3.4.14.1 performance.

Steady state operation.is required to perform a proper water inventory balance since calculations during maneuvering are not useful.

For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

(continued)

PALO VERDE UNITS 1,2,3 B 3.4.14-6 REVISION 38

RCS Operational LEAKAGE B 3.4.14 BASES SURVEILLANCE SR 3.4.14.1 (continued)

REQUIREMENTS An early warningof pressure boundary LEAKAGE or unidentified LEAKAGE is provided by-the automatic systems that monitor the containment atmosphere radioactivity and the containment sump' level.

These. leakage detection systems

_.;are specified in LCO 3.4.16, "RCS Leakage Detection Instrumentation.

Note 2 states that this SR is not applicable to primary to secondary LEAKAGE because LEAKAGE of 150 gallons per day cannot be measured accurately by an RCS water inventory bal.ahce-.,

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage

",detection. in the prevention of accidents; SR 3.4.14.2 This SR verifies that p rimary to secondary LEAKAGE is less than or equal to '150'gallon's per day through any one SG.

Satisfying the primary to secondary LEAKAGE limit ensures

.that the operational LEAKAGE~performahce criterion in the Steam Generator Program is met.

If this SR is not met, compliance with..LCO 3.4.18,."Steam Generator Tube Integrity;". should be evaluated.

The 150 gallons per day limit, is measuredat room temperature as'described in Reference 8.

'The operational LEAKAGE rate limit applies to LEAKAGE through any one SG.

If it is not practical to assign the LEAKAGE to'an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG..'

i..The*'Surveillance is modified by a Note which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 'after establishment of.steady state operation.

This means that once steady state' operating conditions are established., 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is allowed for completing the Surveillance.

When.required by the'Frequency, and after steady state operating conditions are established, the surveillance must be completed prior to the end of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation.

If steady state operating conditions have not been established for 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , this surveillance is not required until steady state operation is established for 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

This SR is not required to be completed prior to changing MODES if steady state operation (continued)

PALO VERDE UNITS 1,2,3 B 3.4. 14-7 REVISION 38

RCS Operational LEAKAGE B 3.4.14 BASES SURVEILLANCE SR 3.4.14.2 (continued)

REQUIREMENTS has not been established for 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides sufficient time to collect and-process all necessary data after stable plant conditions are established.

Furth'er discussion of SR note".format is found in Section 1.4, Frequency.

The Note allows for SR 3.4.14.2 nonperformance due to planned or unplanned transients:

This Noteis not intended to allow transients solely for.the purposeof avoiding SR 3.4.14.2 performance.

For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and'RCP seal injection and return flows.

The Surveillance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . is a reasonable interval to trend primary to seconda~ryLEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

The-primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical!*grab sampling in accordance with the EPRI guidelines (Ref. 8).

REFERENCES 1

10 CFR 50, Appendix A, GDC 30.

2..

Regulatory Guide 1.45, May 1973.

3.

UFSAR, Section.15.6.-

4.

UFSAR, Section 6.4.

5.

10 CFR Part 100.

6.

10 CFR 50, Appendix A, GDC19.

7.

NEI 97-06, "Steam Generator Program Guidelines."

8.

EPRI, "Pressurized Water Reactor. Primary-to-Secondary Leak Guidelines."

PALO VERDE UNITS 1,2,3 B 3.4. 14-8 REVISION 38

SG Tube Integrity B 3.4.18 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.18 Steam Generator *(SG) Tu66In'tegrity BASES BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers.

The SG tubes have a number of important safety functions.

SG tubes are.an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintai.n the primary system's pressure and inventory.

The SG tubes isolate the radioactive fission products in.the primary coolant from the secondary system.

In addition, 'as part of-the RCPB,-the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system.

This Specification addresses only the RCPB integrity function of the SG.

The SG heat.removal function is addressed by LCO 3.4.4, "RCS Loops$

MODES 1 and 2," LWO 3.4.5, "RCS Loops

- MODE 3,"

.LCO 3.4.6, "RCS Loops,-

MODE 4," and LCO 3.4.7, "RCS Loops -

MODE 5, Loops Filled."

SG tube integrity means,'that the tubes are capable of performing their intended RCPB safety function consistent with the licensing basis, including applicable regulatory requirements.

SG tubing.is subject to a variety of degradation mechanisms.

SG tubes may experiencetobe degradation-related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking-, along with other mechanically induced phenomena such as denting and wear.

These degradation mechanisms can impair tube integrity if they are not managed effectively.

The SG performance criteria are used to manage SG tube degradation.

Specification 5.5.9, "Steam Generator (SG)

Program," requires that a program be established and implemented to ensure that SG tube integrity, is maintained.

Pursuant to Specification 5.5.9, tube integrity is maintained when the SG performance criteria are met.

There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE.

TheSG performance criteria are described in Specification 5.5.9.

Meeting the SG performance criteria provides, reasonable assurance of maintaining tube integrity at normal and accident conditions.

The processes used to meet the SG performance criteria are defined by the Steam Generator Program Guidelines (Ref. 1).

(continued)

REVISION 38 PALO VERDE UNITS 1,2,3 B 3.4.18-1

SG Tube Integrity B 3.4.18 BASES APPLICABLE SAFETY ANALYSES The steam generator tube *rupture (SGTR) accident is the limiting design basis event for SG tubes and avoiding an SGTR is the basis for this Specification.

The analysis of a

.SGTR.event assumes a bounding primary to secondary LEAKAGE rate equal to one gallon per-minute (1440 gallons per day) in the unaffected SG plus-,the leakage rate associated with a double-ended.rupture of.a single tube.

The accident analysis for a SGTR assumes the contaminated secondary, fluid is only briefly released to the atmosphere via safety valves and the majority is discharged to the main condenser.

The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their.structural integrity (i.e., they are assumed not to rupture).

In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE of 0.5 gallon per.minute (gpm) from each SG or 1 gpm from both SGs., or is assumedto increase to those levels as a resultof accident induced conditions.

For accidents that do not involve fuel damage:, the primary coolant activity level is assumed to-be equal to the LCO 3.4.17.,

"RCS Specific Activity,"

limits.

For accidents that assume,-fuel, damage,,the primary coolant activity is a function of the amount of activity released from the damaged fuel.

The dose consequences of these events are within.the limits of GDC.19 (Ref. 2),

10. CFR 100 (Ref. 3) or the NRC approved l.icensing.basis (e.g..,

a-small fraction of these limits).

Steam generator, tube integrity satisfies Criterilon 2 of 10 CFR 50.36(c)(2)(ii).,

LCO The LCO requires that SG-tube integrity be maintained.

The LCO also requires that all *SG.tubes that satisfy the repair criteria be 'plugged in accordance with the Steam Generator Program.

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging.

If a tube was determined to satisfy the repair criteria but was not plugged, the tube may still have tube integrity.

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube wall between the tube-to-tubesheet weld at the tube inlet and the (continued)

PALO VERDE UNITS 1,2,3 B 3.4.18-2 REVISION 38

.SG Tube Integrity B 3.4.18 BASES LCO tube-to-tubesheet weld at the tube outlet., The tube-to-(continued) tubesheet~weld is not considered part of the tube.

An SG tube has tube integrity when it satisfies the SG performance criteria..

The SG performance criteria are

,.defined inSpecificati~on.5.5.9, "Steam Generator Program,"

and describe acceptable SG tube performance.

The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.

Thereare three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE.

.Failure"'tO meet any one-of these criteria is considered

'failure to meet the LCO.

Th# structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the'iSG tubesunder all anticipated transients included in the design"specification.:

Tube burst is defined as, "The gross

.structuralVfailure of thetube wall.

The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in reSponse to constant pressure) accompanied by ductile (plastic) tearing of thetube material at the ends of the degradation."

Tube collapse is defined as, "For the load displacement curve for a given structure,'collapse occurs at the top of *the load versus displacement curve where the slope of the curve becomes zero."

The structur.al integrity performance criterion provides guidance on assessing loads that have a significant effect on burst or collapse.

In that context; the-term."significantly" is defined as "An accident loading condition other, than differential:pressure is considered significant When the addition of such loads in the assessment of the structural integrity perfor'mance criterion could cause a lower structural limit or limiting burst/collapse condition to be established."

For tube integrity evaluations, except for circumferential degradation, axial thermal loads are (continued)

PALO VERDE UNITS 1,2,3 B 3.4.18-3 REVISION 38

SG Tube Integrity B 3.4.18 BASES LCO classified as secondary loads.

For circumferential (continued) degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-caselbasis.

The division between primary and secondary classifications will be based on detailed analysis and/or testing.

Strudtural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code,Section III, Service Level A (normal operating conditions) and Service Leve]lB (upset or abnormal conditions) transients included in the design specification.

This includes safety factors and applitable design basis loads based on ASME Code, Section-IIIJ, Subsection NB (Ref. 4) and Draft Regulatory Guide'1.12,1 (Ref.5).

The accident induced leakage performancecriterion ensures that the primary to secondary LEAKAGE. caused by a design basis accident, other, than'a SGTR,.is within the accident analysis assumptions.. The.accident'analysis assumes that accident induced ieakageldoes not exceed 0.5 gpm from each SG orl.gpm total from both SGs.

The accident induced leakage rate includes ary primarytot secondary LEAKAGE existing prior to the accident in additibn to primary to secondary LEAKAGE induced'during th6 accident.

The operational. LEAKAGE performance criterion provides an obse'ývable indication of: SG tube conditions during plant operation.

The limi.t on operational LEAKAGE is contained in LCO 3.4.14,, "RCS Operational LEAKAGE_". and limits primary to secondary LEAKAGE through, any One. SG to 150 gallons per day.

This limit is based 'on. the assumption that, a single crack leaking this amount would not propagate to. a SGTR under the stress conditions of a LOCA or main steam line break.

If this amount of LEAKAGE is.

due to more than one crack, the cracks are very small, and the above assumption is conservative.

APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large.

Large differential pressures across SG tubes can only be experienced.in MODE 1, 2, 3,.or.4.

(continued)

PALO VERDE UNITS 1,2,3 B 3.4.18-4 REVISION 38

SG Tube Integrity B 3.4.18 BASES APPLICABILITY RCS conditions are'far less challenging in.MODES 5 and 6 (continued);.

than during MODES 1, 2, 3, and 4.- In MODES 5 and 6, primary

'to secondary differential pressure is low, resulting in lower.

stresses and reduced potential for LEAKAGE.

ACTIONS The ACTIONS are. modified by. aNote clarifying that the Conditions may be entered independently for each SG tube.

Thisis acceptable because theRequired Actions provide appropriatecompensatory actions for each.affected SG tube.

Complying;with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.

A..

and A.2 Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were'not plugged in accordance with the SteamGenerator Program as required'by SR 3.4.18.2.

An evaluation ofSG tube integrity of the affected tube(s) must be made.... Steam generator tdbe integri.ty. is based on meeting the SG'performance criteria described inthe Steam Generator Program.

The SGrepair criteria define limits on SG tube degradation that allow for.flaw growth between inspections while still prov.idingassurance that theSG performance criteria will continue'to be met.

In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance'Cri'teri-a will continue to be met until the next refueling outage 6r SG tube inspection.

The tube integrity determination is based.on the estimated condition of the tube at the time.the situation is discovered and the estimated growth of.the degradation-prior to the next SG tube inspection.

If it is determ'ined thattube integrity is not being maintained, Condition B applies.

A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with

-a SG tube that may not have tube integrity.

If the evaluation determines that the affected tube(s) have tube integrity, RequiredAction A.2 allows plant operation to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected (continued)

PALO VERDE UNITS 1,2,3 B 3.4.18-5 REVISION 38

SG Tube Integrity B 3.4.18 BASES ACTIONS A.1 and A.2 (continued) tube(s)., However, th& affected tube(s) must be plugged prior, to entering MODE 4 following the next refueling outage or SG inspection.

This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.

B.1 and B.2 If the Required Actions *and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and 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 aesi'red plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE "SR 3.4.18.1 REQUIREMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program..

NEI 97-06, Steam Generator Program Guidelines (Ref; 1), and its referenced EPRI Guidelines, estabiishWthe content of the Steam Generator Program.

Use of the.Steam Generator Program ensures that the inspection is appropriate and consistent with accepted industry practices.

During SG inspections a condi-tion monitoring assessment of the SG tubes is performed, The condition monitoring assessment determines the "as found" condition of the SG tubes.

The purpose of the condition monitoring assessment is toensure that the SG performance criteria have been met for the previous operating period The Steam Generator Program determi-nes the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria.

Inspection'scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations.

The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.

Inspection methods are a (continued)

PALO VERDE UNITS 1,2,3 B 3.4.18-6 REVISION 38

SG Tube Integrity B 3.4.18 BASES SURVEILLANCE SR 3.4.18.1 (continued)`

REQUIREMENTS function of degradation morphology: non-destructive e~xamination (NDE) technique capabilities,, and inspection

-locations.

The Steam Generator Program defines the Frequency of SR 3.4.18.1.

The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 6).

The Steam Generator Program uses information on existing degradations and growth rates to determine an inspectioh Frequency~that. provides reasonable assurance that the.tubing will meet the SG performance criteria at the next scheduled inspection.

In addition, Specification 5.5.9 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 3.4.18.2 During an SG inspection,.any-inspected tube-that satisf-ies the Steam Generator Program repair criteria is removed from service by plugging.

The tube repair criteria delineated in Specification 5.5.9 are intended to ensure that the tubes accepted for.continued service satisfy the SG performance criteria with allowance for error in theflaw size measurement and for.future flaw,growth.

In addition, the tube repair criteria, in conjunction.with other elements of the,.Steam Generator Program, ensure that the SG performance criteria wil.l continue to be met until the next inspection of the subject tube(s).

Reference 1 provides guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria..

The Frequency of prior to'entering MODE 4 following a SG inspection ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged prior to subjecting the SG.tubes to significant primary to secondary pressure differential.

(continued)

PALO VERDE UNITS 1,2,3 B 3.4.18-7 REVISION 38

SG Tube Integrity B 3.4.18 BASES REFERENCES

1.

NEI 97-06, "Steam Generator Program Guidelines,"

2.

10 CFR 50 Appendix A, GDC 19.

3.

10 CFR 100.

4.

ASME Boiler and Pressure Vessel Code,i Section III, Subsection-NB..

5.

Draft Regulatory Guide 1.121, "Basis for Plugging Degraded Steam Generator.Tubes," August 1976.

6.

EPRI, "Pressurized Water Examination 'Guidelines."

Reactor Steam Generator PALO VERDE UNITS 1,2,3 B 3.4.18-8 REVISION 38

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

These limits also prevent the containment pressure from exceeding the containment-design negative pressure differential with respect to the outside atmosphere in the event of inadvertent actuation of the Containment Spray System.

Containment pressure is.a process variable that is monitored and controlled.

The containment pressure limits are derived from the input conditions used in the containment functional analyses and the containment structure external pressure analysis.

Should operation occur outside these limits coincident with a Design Basis Accident (DBA),

post accident containment pressures could exceed calculated values.

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

The limiting DBAs considered for determining the maximum containment internal pressure (Pa) are the LOCA and MSLB.

A double ended discharge line break LOCA with maximum ECCS results in the highest calculated internal containment pressure of 52.0 psig for units operating at 3876 MWt RTP, and 58.0 psig for unit operating at 3990 MWt RTP, which is below the internal design pressure of 60 psig.

The postulated DBAs are analyzed assuming degraded containment Engineered Safety Feature (ESF)

Systems (i.e., assuming the loss of one ESF bus, which is the worst case single active failure, resulting in one train of the Containment Spray System being rendered inoperable).

It is this maximum containment pressure that is used to ensure that the licensing basis dose limitations are met.

The initial pressure condition used in the containment analysis bounds the containment pressure allowed during normal operation.

The LCO limit of 2.5 psig ensures that, in the event of an accident, the maximum peak containment internal pressure, 52.0 psig for units operating at 3876 MWt RTP, and 58.0 psig for unit operating at 3990 MWt RTP, and the maximum accident design pressure for containment, 60 psig, are not exceeded.

(continued)

PALO VERDE UNITS 1,2,3 B 3.6.4-1 REVISION 35

Containment Pressure B 3.6.4 BASES APPLICABLE SAFETY ANALYSES (continued)

The containment was also'designed for anexcess external pressure of 4.0 psig to withstand the resultant pressure drop from an accidental actuation of the Containment Spray System..

The maximum external pressure loading that would occur as a result of this transient is when the minimum internal pressure of -3.5 psig is reached.

This is based on an.initial.containment pressure of -1.0 psig (The lower technical specification limit plus instrument uncertainty) and the calculated pressuredrop of 2.5 psi.

The upper LCO limit of 2.5 psig does not compensate for any instrument inaccuracies.

Use of an indicated limit of 1.8 psig ensures that the actual limit of 2.5 psig will not be exceeded.,

The lower LCO limit of -0.3 psig h as. beei derived,to account for instrument inaccuracies.

The indicated limit of

-0.3 psig ensures that the actual l~imitOf -1.0 psig will not be exceeded.(Ref. 3)

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

LCO Maintaining containment pressure less than or equal to the.

LCO. upper pressure limit ensures that, in the event of a DBA', the resultant peak containment accident pressure will remain below the containment design pressure.

Maintaining containment pressure greater than or equal to the LCO lower pressure limit ensures that the containment will not exceed the design negative pressure differential following the inadvertent actuation of the Containment Spray System.

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment.

Since maintaining containment pressure within limits is essential to ensure initial conditions assumed in the accident analysis are maintained, the LCO is applicable in MODES 1, 2, 3, and 4.

In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES.

Therefore, maintaining containment pressure within the limits of the LCO is not required in MODE 5 or 6.

(continued)

PALO VERDE UNITS 1,2,3 B 3.6.4-2 REVISION 38

Containment Spray System B 3.6.6 BASES BACKGROUND.

The Cohtainment Spray System accelerates the air mixing (continued)`

process between the upper domie space of the containment atmosphere during LOCA operations..

It-also prevents any hot spot'air pockets during the containment cooling mode and avoids any hydrogen concentration in pocket areas.

APPLICABLE SAFETY ANALYSES The Containment Spray System limits the temperature and pressure that could be experienced following a DBA.

The Containment Spray System is required to~be capable of

reducing containment pressure to 1/2 the'peak pressure within'24'hours following a DBA... The limiting DBAs considered relative to containment temperature and pressure are the Loss Of Coolant Accident (LOCA) and the Main Steam Line Break (MSLB).

The DBA LOCA and MSLB are analyzed using computer codes designed'to predict the resultant containment pressure and temperature transients'."

No DBAs are assumed to occur simultaneously or consecutively.

The postulated DBAs are analyzed with regard to containment ESF systems, assumi.ng the'loss of one ESF bus,' which is the worst case single active failure, resulting in one train of the Containment Spray System being rendered inoperable.

The analysis and evaluation show that under the worst case scenario, the highest peak containment pressure is 52.0 psig for units operating at 3876 MWt RTP,,and. 58.0 psig for unit operating 't'3990 MWt RTP (experienced during a LOCA).

The analysis'shows, thatthe peak containment vapor temperature is405.650 F'(experienced during a MSLB):- Both results are within the design.

(See the Bases for Specifications 3.6.4, "Containment Pressure," and 3.6.5, "Containment Air T~mperature,"`for a detailed discussion.)

The analyses and evaluations assume a power level of 102% RTP, one

-containment -spray train operating, and initial (pre-accident) conditions of 120'F and 16.7 psia (LOCA) and 13.22 psia (MSLB).

The analyses also assume a response time delayed initiation in orderto'provide a conservative calculation of'peak containment pressure and temperature

.responses.

The effect of an inadvertent containment spray actuation has been.analyzed and is discussed in the Bases for

.Specification'3.6.4.

(continued)

PALO VERDE UNITS 1,2,3 B 3.6.6-3 REVISION 38

Containment Spray System B 3.6.6 BASES APPLICABLE SAFETY ANALYSES (continued)

The modeled Containment Spray System. actuation. from the containment analysi,s is-based upon a response time, associated with exceeding the containment High-High pressure setpoint to achieve full flow-through.the containment spray nozzles.

The Containment Spray System total response time includes diesel generator startup..(for loss of offsite, power), block, loading of equipment, containment spray pump startup,,and spray line filling (Ref. 2).

The Containment Spray System mixes the containment atmosphere to provide a uniform hydrogen concentration.

Hydrogen may accumulate in containment following a LOCA as a result of:.

a.

A metal. steam reaction between the zirconium fuel rod cladding and the reactor coolant;

b.

Radiolytic decomposition of water in the Reactor Coolant.System (RCS) and the containment sump;

c.

Hydrogen i'n the RCS at the time of the LOCA (i.e.,

hydrogen dissolved in the reactor coolant and hydrogen gas in the pressurizer vapor space): or

d.

Corrosion of metals exposed to Containment Spray System. and Emergency.Core Cooling.Systems solution.

'To. evaluate containment function of calculated.

Reference 8 calculated.

the potential for hydrogen accumulation in following a LOCA, the hydrogen generation as a time following the initiation of the accident is

,Conservative assumptions recommended by are used to maximize the amount of hydrogen The Containment Spray System. satisfies Criterion 3 of 10 CFR 50.36 (c)(2)(ii).

LCO During a DBA, one containment spray train is required to maintain the containment peak pressure and temperature below the design limits (Ref. 5), to remove iodine from the containment atmosphere to maintain concentrations below those assumed in the safety analysis, and provide hydrogen mixing.

To ensure that these requirements are met, two containment spray trains must.be OPERABLE.

Each spray train must be capable of taking suction from the RWT on a (continued.)

PALO VERDE UNITS 1,2,3 B 3.6.6-4 REVISION 7

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES APPLICABILITY1'

,air are-required'to be within limits when the associated DG (continued')

is required to be OPERABLE.'

ACTIONS

'..The ACTIONS Table is modified by, a Note indicating that separate Condition entry. is allowed for each DG.

This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable DG subsystem. Complying with the Required Actions for one inoperable DG subsystem may allow for continued operation, and subsequent inoperable DG subsystem are governed by separate Condition entry and application* of associated Required Actions.

A.1 In this Condition',(i..e.,, < 80% indicated fuel level), the 7 day fuel oil supply (70,700 gallon of fuel) for a DG is not available. ::However, the Condition is restricted to fuel.

oil level reductions.that:maintain at least a 6 day supply (61,410 gallons of-,fuel.).

These circumstances may be caused by events such as full load operation required after an inadvertent start while at minimum required level; or feed and,.bleed. operations, which may be necessitated by increasing particulate levels or any number of other oil quality degradations.. This restriction allows sufficient time for obtaining the requisite replacement volume and performing the 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 level prior to declaring the DG inoperable,.

This period is acceptable based on the remaining capacity (>_ 6 days or

> 71%-indicated~fuel level), the.:fact that procedures will be initiated to obtain replenishment, and the low probability of an event during this brief period.

B.1 With lube oil inventory < 2.5 inches visible in the sightglass, sufficient. lubricating oil-to support 7 days of

'continuous DG operation at full load conditions may not be available.

However,. the Condition is restricted to lube oil volume reductions that maintain at least a 6 day supply.

(continued)

PALO VERDE UNITS 1,2,3 B 3.8.3-3 REVISION 38

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES ACTIONS B.1 (continued)

This restriction allows sufficient time to obtain the requisite replacement volume.

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 volume prior to declaring the DG inoperable.

This period is acceptable based on the remaining capacity ( > 6 days), the low rate of usage, the fact that procedures will be initiated to obtain replenishment, and the low probability of an event during this brief period.

The normal level of lube oil is maintained at mid-scale visible on the sightglass which ensures sufficient lube oil to support at least 13.5 days of engine operation during periods when the DG is supplying maximum post-LOCA load demand as discussed in the. FSAR (Ref. 1).

This is based on a conservative lube~oil consumption rate of 1.5 gallons per hour and 486 gallons of available lube oil between the top of the lube oil suction pipe in the engine crankcase (minimum available level) and the mid-scale position on the sightglass.

252 gallons qr 7 days of available lube oil is actually indicated at 1 inch visible in the sightglass.

With- Ž 2.5 inches visi'ble in:the sightglass, a conservative supply of lube oil is ensured foF 7 da~s of full load operation.

C.1 This Condition is'entered as a result of a failure to meet the acceptance criterion of SR 3.8.3.3.

Normally, trending of particulate levels allows sufficient time to correct high particulate levels prior to reaching the limit of acceptability.

Poor sample procedures (bottom sampling),

contaminated sampling equipment, and errors in laboratory analysis can produce failures that do not follow a trend.

Since the presence of particulates does not mean failure of the fuel oil to burn properly in the diesel engine, and particulate concentration is unlikely to change significantly between Surveillance Frequency intervals, and proper engine performance has been recently demonstrated (within 31 days), it is prudent to allow a brief period prior to declaring the associated DG inoperable.

The 7 day Completion time allows for further evaluation, resampling, and re-analysis of the DG fuel oil.

(continued)

PALO VERDE UNITS 1,2,3 B 3.8.3-4 REVISION 0

ENCLOSURE 2 PVNGS Technical Specification Bases Revision 39 Insertion Instructions and I Replacement Pages

PVNGS Technical Specifications Bases Manual Revision 39 Replacement Pages and Insertion Instructions The following LDCR is part of this change:

LDCR 06-B022 Instructions Remove Paqe:.

Cover Page List of Effective Pages, Pages 1, through 8 B 3.7.2-3 & 4

.Insert New Pa-qe:

Cover Page List of Effective Pages, Pages 1 through 8 B 3.7.2-3 & 4

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B.MSIVs B 3.7.2 BASES APPLICABLE main steam header downstream of the closed MSIVs in SAFETY ANALYSES the intact loops.

(continued)

b.

A break outside of containment and upstream from the MSIVs.

This scenario is not a containment pressurization concern.

The uncontrolled blowdown of more than one steam generator must be prevented to limit the potential for uncontrolled RCS cooldown and positive reactivity addition.

Closure of the MSIVs isolates the break, and limits the blowdown to a single steam generator.

c.

A break downstream of the MSIVs.

'This type of break" will be isolated by the closure of the MSIVs.

Events such as increased steam flow through the turbine or the steam bypass valves will also, terminate on closure of the MSIVs.

d.

A steam generator tube rupture.

For this scenario, closure of the MSIVs isolates the' affected steam generator from the intact steam generator.

In addition to minimizing radiological releases, this enables the operator to maintain the pressure of the steam generator with the ruptured tube high enough to allow flow isolation while remaining below the MSSV setpoints, a necessary step toward isolating theflow through the rupture.

e.

The MSIVs are also utilized during other events such, as a feedwater line break.

These events are less limiting so far as MSIV OPERABILITY is concerned.

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

LCO This LCO requires that the MSIV and its associated actuator trains in each of the four steam lines be OPERABLE.

The MSIVs are considered OPERABLE when the isolation times are within limits, and they close on an isolation actuation signal.

This LCO provides assurance that the MSIVs will perform their design safety function to mitigate the consequences of accidents that could result in offsite exposures comparable to the 10 CFR 100 (Ref. 4) limits.

(continued)

PALO VERDE UNITS 1,2,3 B 3.7.2-3 REVISION 39

MSIVs B 3.7.2 BASES (continued)

APPLICABILITY The MSIVs must be OPERABLE in MODE 1 and in MODES 2, 3 and 4 except when all MSIVs are closed and deactivated when there is significant mass and energy in the RCS and steam generators.

When the MSIVs are closed, they are already performing their safety function.

In MODES 5 and 6, the steam generators do not contain much energy because their temperature is below the boiling point of water: therefore, the MSIVs are not required for isolation of potential high energy secondary system pipe breaks in these MODES.

ACTIONS A.1 and A.2 With one MSIV. inoperabl.e in MODE 1, time is allowed to restore the component to OPERABLE status.

Some repairs can be made to the MSIV with the unit hot.

The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, considering the probability of an accident occurring during the time period that would require closure of the.MSIVs.

The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion-Ti.me ist consistent with that normally allowed for containment isolation valves that isolate a closed system penetrat-i:ng containment.

These valves differ from other containment isolation valves in that the closed system provides an additional means for containment isolation.

(continued)

PALO VERDE UNITS 1,2.3 B 3.7.2-4 REVISION 37

ENCLOSURE 3 PVNGS Technical Specification Bases Revision 40 Insertion Instructions and Replacement Pages

PVNGS Technical Specifications Bases Revision 40 Insertion Instructions Remove Pace:

Cover page List of Effective Pages, Pages 1/2 through List of Effective Pages, Page 7/8 B 3.4.18-1/3.4.18-2 B 3.7.2-1/3.7.2-2 through B 3.7.2-5/3.7.2-6 B 3.7.5-3/3.7.5-4 Insert New Page:

Cover page List of Effective Pages, Pages 1/2 through List of Effective Pages, Page 7/8 B 3.4.18-1/3.4.18-2 B 3.7.2-1/3.7.2-2 through B 3.7.2-9/3.7.2-Blank B 3.7.5-3/3.7.5-4 I

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SG Tube Integrity B 3.4.18 B 3.4 REACTOR COOLANT SYSTEM...(RCS)

B 3.4.18 Steam Generator (SG).Thbe..I1nt6grity BASES BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers.

The SG tubes have a number of important safety functions.

SG tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory.

The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system.

In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system.

This Specification addresses only the RCPB integrity function of the SG.

The SG heat removal function is addressed by LCO 3.4.4, "RCS Loops.-

MODES 1 and 2," LCO 3.4.5, 'RCS Loops - MODE 3,"

LCO 3.4.6, "RCS Loops -

MODE 4," and LCO 3.4.7, "RCS Loops MODE 5, Loops Filled."

SG tube integrity means that the tubes are capable of performing their intended RCPB safety function consistent with'the licensing basis, including applicable regulatory requirements.

SG tubing is subject to a variety of degradation mechanisms.

SG tubes may experience tube degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and wear.

These degradation mechanisms can impair tube integrity if they are not managed effectively.

The SG performance criteria are used to manage SG tube degradation.

Specification 5.5.9, "Steam Generator (SG)

Program," requires that a program be established and implemented to ensure that SG tube integrity is maintained.

Pursuant to Specification 5.5.9, tube integrity is maintained when the SG performance criteria are met.

There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE.

The SG performance criteria are described in Specification 5.5.9.

Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

The processes used to meet the SG performance criteria are defined by the Steam Generator Program Guidelines (Ref. 1).

(continued)

REVISION 38 PALO VERDE UNITS 1,2,3 B 3.4.18-1

SG Tube Integrity B 3.4.18 BASES APPLICABLE The steam generator tube rupture (SGTR) accident is the SAFETY limiting design basis event for SG tubes and avoiding an ANALYSES SGTR is the basis for this Specification.

The analysis of a SGTR event, assumes a.bounding primary to secondary.LEAKAGE rate equal to one gallon per minute (1440 gallons per day) in the unaffected. SG plus the leakage rate associated with a double-ended rupture of a.single tube.

The SGTR accident analysis is described in.UFSAR Sectjon 15.6.3.

The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain.their structural integrity (i.e.,,they are assumed not to rupture).

In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE of,0.5 gallon per minute (gpm) from each SG or 1, gpm from both SGs,' or ijs assumed to-ih'rease to those levels as a result of accident induced conditions...

For accidents that do.not involve fuel damage, the primary cool'ant activity level is assumed to beequal to the LCO'3.4.17, "'RCS'Specific Activity,"

limits.

For accidents that assume fuel damage, the primary coolant activity is a function'of-the amount of activity released

.from the damaged fuel.

The dose consequences of these events are within the limits of GDC 19 (Ref. 2)_10 CFR 100 (Ref. 3) or the NRC approved-licensing,basis (e:.g.,

a small fraction of these limits):.

Steam generator tube integrity satisfies'Criterion 2 of 10 CFR 50.36() (2)(ii)

LCO The LCO requires that SG tube integrity be maintained.

The LCO also requires that all SG tubes that satisfy the repair criteria be plugged in accordance withthe;Steam Generator Program.

During an SG inspection, any;inspected tube that satisfies the Steam Generator Program repair criteria-is removed from service by plugging..

If a tube was determined to satisfy the repair criteria but was not plugged, the tube may still have tube integrity.

In the context of this Specification, a SG. tube is defined as the entire length of the tube, including the tube wall between the tube-to-tubesheet weld at the tube inlet and the (continued)

PALO VERDE UNITS 1,2,3 B 3.4.18-2 REVISION 40

MSIVs B 3.7.2 B 3.7 PLANT SYSTEMS B 3.7.2 Main: Steam Isolation Valves (MSIVs)

BASES BACKGROUND The MSIVs isolate steam flow from the secondary side of the

steam generators following a High Energy Line Break (HELB).

MSIV closure terminates flow from the unaffected (intact) steam generator.

One MSIV i.s located in each main steam line outside, but close to: cbntainment.

The MSIVs.are downstream from the Main Steam Safety Valves (MSSVs),

atmospheric dump valves,

,,and'auxiliary feedwater pump turbine steam supplies to pre'vent their being isolated from the steam generators by MSIV closure.

Closing the MSIVs isolates each steam generator from the other, and isolates the turbine, Steam By~pass Control.. System, and other auxiliary steam supplies from the. steam generators.

SThe MSIV is a,28-inch.gate valvewith redundant hydraulic actuator trains., The actuation system is composed of redundant trains'A bnd'B."'The instrumentation and controls of the train A valve actuator trains are physically and electrically separate and independent of the instrumentation and control-of the:-train B valve actuator trains.

Either actuator train can independently perform the safety function to fast-close the MSIV on demand.

Each actuator train consists of ahydraulic accumulator controlled by solenoid valves on the associated MSIV.

The MSIVs close on a main steam isolation signal generated by either low steam generator pressure, high steam generator level or high:containmentpressure.

The MSIVs fail closed on loss of control or actuation power.

The MSIS also actuates the Main Feedwater Isolation Valves (MFIVs) to close.

The MSIVs may also be actuated manually.

A description of the MSIVs is found in the FSAR, Section 10.3 (Ref. 1).

(continued)

PALO VERDE UNITS 1,2,3 B 3.7.2-1 REVISION 40

MSIVs B 3.7.2 BASES APPLICABLE The design basis of the'MSIVs is established by the SAFETY ANALYSES containment analysis for the large steam line break (SLB) inside containment, as discussed~in the CESSAR, Section 6.2 (Ref. 2).

It is also influenced by the accident analysis of the SLB events presented in the UFSAR, Section 15.1.5 (Ref.;3).,The design precludes the blowdown of more than one steam generator., assuming a single active component failure (e.g., the failure, of one MSIV to close on demand).

The limiting case for the containment analysis is the hot zero power SLB inside containment, with a loss of offsite power following turbine trip,,andfailure of the MSIV on the affected steam line to close.

At zero power, the steam generator inventory and temperature are at their maximum, maximizing the analyzed mass and energy release to the containment.

Due to reverse flow, failure of the MSIV to close contributes to, the total release of-the additional mass and energy in the steam headers, which are downstream of the, other MSIVs.

With.the most reactive control element assembly assumed stuck in the fully.withdrawn position, there *is an. increased possibility that the core will become critical and return to poweri The-core is ultimately shut I

down by the borated water:injection delivered by the Emergency Core.Cooling, System.. Other failures considered are the failure of an MFIV to close, and failure of an emergency diesel generator to start.

The. accident analysis compares several different SLB events against different acceptance criteria.

The large SLB outside containment upstream of the MSIV is limiting for offsite dose, although a break in this short section of main steam header has a very low probability., The large SLB inside containment at hotzero power is the limiting case for a post tripreturn toipower.

The analysis includes scenarios with offsite power available and with a loss of offsite power following turbine trip.

With of~fsite poweravailable,.the reactor coolant pumps continue to circulatecoolant through the steam generators, maximizing the Reactor Coolant System (RCS) cooldown.

With a loss of offsite power, the response of mitigating systems, such as the High Pressure Safety Injection (HPSI) pumps, is delayed.

Significant single failures considered include:

failure of a MSIV to close, failure of an emergency diesel generator, and failure of a HPSI pump.

(continued)

PALO VERDE UNITS 1,2,3 B 3.7.2-2 REVISION 40

MSIVs B 3.7.2 BASES APPLICABLE SAFETY ANALYSES..

(continued)

.The MSIVs serve-only a safety function and remain open

during power; operation; These valves operate under the following situations:

a.

An HELB inside containment:

In order to maximize the mass and energy release into the containment, the analysis :assumes that the MSIV in the affected steam line remains open.

For this accident scenario, steam is discharged into containment from both steam generators, until closure of the MSIVs in the intact steam generator occurs.

After,MSIV closure, steam is discharged into containment only from the affected steam generator, and from the residual steam in the

.main steam header downstream of the closed MSIVs in the intact loops.'I, b%. A break outside of containment and upstream from the MSIVs.

This scenario *is not a containment pressurization concern.

The uncontrolled blowdown of more~than.one steam generator.must be prevented to

-limit 'the potential for uncontrolled RCS cooldown and positive reactivity addition.

Closure of the MSIVs isola'tes, the break,.and limits the blowdown to a single steam generator.

c.

A break downstream of the MSIVs.

This type of break will be isolated by the closure of the MSIVs.

Events such *as increased steam flow through the turbine or the steam bypass valves will also terminate on closure of the MSI.Vs.

d.-

A s~team generator tube rupture.

For this scenario, closure of the MSIVs isolates the affected steam generator from' the intact steam generator.

In addition to' minimizing radiological releases, this enables the operator.to maintain the pressure of the steam generator with the ruptured tube high enough to allow flow isolation while remaining below the MSSV setpoints, a necessary step toward isolating the flow through the rupture.

e The MSIVs are also utilized during other events such as.a feedwater line break.

These events are less limiting so far as MSIV OPERABILITY is concerned.

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

(continued)

REVISION 40 PALO VERDE UNITS 1,2,3 B 3.7.2-3

MSIVs B 3.7.2 BASES (continued)

LCO This LCO requires that the MSIV and its associated actuator trains in each of the four steam lines be OPERABLE.

The MSIVs are considered OPERABLE when the isolation times are within limits, and.they close on.an isolation actuation signal.

'An MSIV actuator train is-considered OPERABLE when it is capable of fast-closing the associated MSIV on demand and within the required isolation time.

This includes having adequate accumulator pressure to support fast-closure of the MSIV within the required isolation time and adequate air pressure availableto fast close the.MSIV.

This LCO provides assurance-that the MSIVs will perform their design safety function to mitigate the consequences of accidents that could result in offsiteexposures comparable to the 10 CFR 100 (Ref. 4) limits.

APPLICABILITY The MSIVs must be OPERABLE in MODEl and in MODES,2, 3 and 4 except when all MSIVs are closed.and deactivated when there is significant mass and energy i~n the, RCS and steam generators.

When. the.MSIVs are closed,-they are already performing their safety function.

The MSIV actuator trainsmust be OPERABLE in MODES 1, 2, 3 and 4. to support operation-of the. MSIV.-

In MODES 5 and 6, the steam generators do not contain much energy because their temperature is below the boiling point of water; therefore, the MSIVs are not required for isolation of potential high energy secondary system pipe breaks in these MODES.

ACTIONS The LCO specifies OPERABILITY. requirements for the MSIVs as well as for their associated actuator trains.

The Conditions and Required Actions for TS 3.7.2 separately address inoperability of the MSIV actuator trains and inoperability of the MSIVs themselves.,

(continued)

PALO VERDE UNITS 1,2,3 B 3.7.2-4 REVISION 40

,A¸, :.,..*,.., ;*'.*.,','....

MSIVs B 3.7.2 BASES (continued)

ACTIONS

'.A.1 (continued)

With one MSIV with a, single actuator train inoperable

.(i.e., one Train A or one.Train B), action must be taken to restore the inoperable actuator train to OPERABLE status within 7 days.

The 7-day Completion Time is reasonable in light of the redundant actuator-train design such that with one actuator train, inoperable, the affected MSIV is still capable of closing~on demand via theremaining OPERABLE actuator train.

The 7-day Completion-Time takes into account the redundant.OPERABLE.actuator train to the MSIV, reasonable time for repairs, and the low probability of an event occurring that requires the inoperable actuator train

..to -the 'affected MSIV.

Y... B:., 1.,

With two MSIVs each with a single actuator train inoperable such that the inoperable actuator trains are not in the same train (i.e6, one Train A andone Train B), action must be taken'to restore one of the inoperable actuator.trains to.OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

With two actuator trains:inoperable on twoMSIVs, there is an increased

.likel.ihood that an additional failure (such as the failure of an actuation-logic train) could cause~one MSIV to fail to close.

The 72-hour Completion Time is reasonable since the.,Vredundant'actuator train design ensures that with only one actuator train on-each of,two affected MSIVs inoperable, each MSIV is still capable of closing on demand.

C.1 With two MSIVs each witha single actuator train inoperable and the inoperable actuator trains are both in the same train (i.e:, both Train A, or both Train B),

action must be taken to restore one of the inoperable actuator trains to OPERABLE status'within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

The 48-hour Completion

Time provides a reasonable amount of time for restoring at least one actuator train since the redundant actuator train design, for each MSIV ensures that a single inoperable actuator train cannot prevent the affected MSIV(s) from closing on demand.

With two actuator trains inoperable in the same separation group, an additional failure (such as the failure of an actuation logic train in the other separation group) could cause both affected MSIVs to fail (continued)

PALO VERDE UNITS 1,2,3 B 3.7.2-5 REVISION 40

MSIVs B 3.7.2 BASES (continued)

ACTIONS C.1 (continued)

(continued) to close on demand.

The 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Completion Time takes into the redundant OPERABLE actuator trains to the affected MSIVs and the low probability of an event occurring that requires the inoperable actuator trains to the affected MSIVs.

D.1

.With two actuator trai.ns for one MSIV inoperable, Required Action D.1:provides assurance that the appropriate Action is entered for one MSIV inoperable.ý Eailure of both actuator trains for a single MSIV results in the inability to fast close theaffected MSIV on demand.

E.1 With three or more MSIV actuator trains inoperable or when Required Action A.1, B.1, or Cl. cannot be completed within

.the required Completion Time;, the affected MSIVs may be incapable of closing, on demand and must be immediately declared inoperable.

Having three'actuator trains inoperable could involve two inoperableactuator trains on one MSIV and one inoperable actuatortrain on another MSIV, or an inoperable actuator train on each of three MSIVs, for which the inoperable actuator trains could all be in the same separation group or be staggered among the two separation groups.

Depending on which of these conditions or combinations is in effect, the condition or combination could mean that all ofthe affected MSIVsremain capable of closing on demand (due to the redundant actuator, train design), or that at least one MSIV is inoperable, or that with an additional single failure up to three MSIVs could be incapable of closing on demand.

Therefore, in some cases, immediately declaring the affected MSIVs inoperable is conservative (when some or all of the affected MSIVs may still be capable of closing on demand even with a single additional failure), while in other cases it is appropriate (when at least one of the MSIVs would be inoperable, or up to three could be rendered inoperable, by an additional single failure).

Required Action E.1 is conservatively based on the worst-case condition and therefore'requires immediately declaring all the affected MSIVs inoperable.

Declaring two (continued)

PALO VERDE UNITS 1,2,3 B 3.7.2-6 REVISION 40

MSIVs B 3.7.2 BASES (continued)

ACTIONS E.1 (continued)

(continued) or more MSIVs inoperable while-in MODE 1 requires entry into LCO3.0.3.

F.1 With one MSIV inoperable in MODE 1, time is allowed to restore the component to OPERABLE status.

Some repairs can be made to the MSIV with the unit hot.

The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, considering the probability of an accident occurring during.the time period that would require closure of the MSIVs..

Condition F is entered when one MSIV is inoperable in MODE 1, including when both actuator trains for one MSIV are operable.

When only one actuator train is inoperable on one MSIV, Condition A applies.

The,4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time, is consistent with that normally allowed for containment isolationvalves that isolate a closed systempenetrating containment.

These valves differ from other containment isolation valves in that the closed systemprovidesan additional means for containment

.isolation.*

.G. 1 If the MSIV cannot be restored to,OPERABLE within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the unit must be placed in a MODE in-which the LCO does not apply.

To achieve this status; the unitmust be placed in MODE 2 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and Condition H would be entered.

The Completion Time is reasonable, based on operating experience,.,to reach MODE 2,.and close the MSIVs in an orderly manner and.without challenging unit systems.

H.

and H.2 Condition H is modified by a Note indicating that separate Condition entry is allowed for each MSIV.

Since the MSIVs are required to be OPERABLE in MODES 2 and 3, the inoperable MSIVs may either be restored to OPERABLE status or closed.

When closed, the MSIVs are already in the position required by the assumptions in the safety analysis.

(continued)

PALO VERDE UNITS 1,2,3 B 3.7.2-7 REVISION 40

MSIVs B 3.7.2 BASES (continued)

ACTIONS H.1 and H.2 (continued)

(continued)

The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time-is consis.tent with tbat allowed in Condition F.

Inoperable MSIVs that cannot be restoredto OPERABLE status within the specified:Completion Time, but are closed, must be verified on a periodic basis to be closed.

This is necessary to ensure that theassumptions in the safety analysis remain valid.

The 7 day Completion Time is reasonable, based on engineering judgment, MSIV status indications available in the control room, and other administrative controls, to ensure these Valves are in the closed position.

1.1 and 1.2 If the MSIVs cannot-be restored to OPERABLE status, or closed, within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply.

To achieve this status, the unit 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 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 reqUiredunit conditions--

from MODE 2 conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.2.1 REQUIREMENTS This SR verifies that the closure time of each MSIV is

4.6 seconds with each actuator train on an actual or simulated actuation signal.

The MSIV closure time is assumed in the accident and containment analyses.

This SR is normally performed upon returning the unit to operation following a refueling outage.

The MSIVs should not be full stroke tested at power.

The Frequency for this SR is in accordance with the Inservice Testing Program.

This Frequency demonstrates the valve closure time at least once per refueling cycle.

(continued)

PALO VERDE UNITS 1,2,3 B 3.7.2-8 REVISION 40

MSIVs B 3.7.2 BASES (continued)

SURVEILLANCE REQUIREMENTS (continued)

SR 3.7.2.1 (continued)

This test is conducted in MODE 3, with the unit at operating temperature and pressure, as discussed in the Reference 5 exercising requirements.

This SR is modified by a Note that allows.entry into and operation in MODE 3 prior to performing the SR.

This allows.a delay of testing until MODE 3, *in order to'establish conditions consistent with those under which the acceptance criterion was

'generated.

REFERENCES

1.

UFSAR, Section 10.3.

2.

CESSAR, Section 6.2.

3.

UFSAR, Section 15.1.5.

4.-. I0 CFR 100.11.

5.

ASME, Boiler and Pressure Vessel Code,Section XI, Inservice Inspection, Article IWV-3400.

PALO VERDE UNITS 1,2,3 B 3.7.2-9 REVISION 40

This page intentionally blank

AFW System B 3.7.5 BASES APPLICABLE SAFETY ANALYSES (continued)

The design basis of the essential AFW trains 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 1270 psia at the entrance to the steam generators.

The limiting Design Basis Accidents (DBAs) and transients for the AFW System are as follows:

a.

Feedwater Line Break (FWLB);

and

b.

Main Steam Line Break (MSLB).

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

The AFW System design is such that it can perform its function following an FWLB between the MFW isolation valve and containment, combined with a loss of offsite power following turbine trip, and a single active failure of the steam turbine driven AFW pump.

In such a case, the AFAS logic might not detect the affected steam generator if the backflow check valve to the affected'MFW header worked properly.

The non-essential motor driven AFW pump, if started manually, would deliver to the broken down comer header at the pump runout flow until the problem was detected, and flow was terminated by the operator.

Sufficient flow would be delivered to the intact steam generator by the essential motor driven AFW pump.

The AFW System satisfies Criterion 3 of 10 CFR 50.36 (c)(2)(ii(n (continued)

PALO VERDE UNITS 1,2,3 B 3.7.5-3 REVISION 40

AFW System B 3.7.5 BASES LCO This LCO requires that three 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 reactor coolant pressure boundary.

Two essential and one non-essential 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 the essential motor driven AFW pump from an emergency bus.

The non-essential motor driven AFW pump can be manually loaded on its emergency bus.

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.

The AFW System is considered to be OPERABLE when the 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 capable of supplying AFW to either steam generator.

The turbine driven AFW pump shall be OPERABLE with redundant steam supplies from each of the two main steam lines upstream of the MSIVs and capable of supplying AFW flow to either of the two steam generators.

The piping, valves, instrumentation, and controls in the required flow paths shall also be OPERABLE.

Although the operability of the non-essential motor driven AFW pump is important from a risk perspective, this pump is not credited in the PVNGS Accident Analyses.

The LCO is modified by a Note indicating 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 supply available in MODE 4 to power the turbine driven AFW pump.

(continued)

PALO VERDE UNITS 1,2,3 B 3.7.5-4 REVISION 27

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