ML051650324

Technical Specification Bases Revisions, 30, 31, 32, and 33 Update

ML051650324
Person / Time
Site:	Palo Verde
Issue date:	06/02/2005
From:	Bauer S Arizona Public Service Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
102-05284-SAB/TNW/RKR
Download: ML051650324 (100)

Text

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Technical Specification 5.5.14 LAMS Palo Verde Nuclear Scott A. Bauer Department Leader, Tel. 623-393-5978 Fax 623-393-5442 Mail Station 7636 PO Box 52034 Generating Station Regulatory Affairs e-mail: sbauer~apsccom Phoenix. Arizona 85072-2034 102-05284-SAB/TNW/RKR June 2, 2005 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001

Subject:

Palo Verde Nuclear Generating Station (PVNGS)

Units 1, 2, and 3 Docket Nos. STN 50-528/5291530 Technical Specifications Bases Revisions 30, 31, 32, and 33 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 30, implemented on June 15, 2004, Revision 31, implemented August 25, 2004, Revision 32, implemented August 31, 2004, and Revision 33, implemented on September 9, 2004. The Revision 30 insertion instructions and replacement pages are provided in Enclosure 1. The Revision 31 insertion instructions and replacement pages are provided in Enclosure 2. The Revision 32 insertion instructions and replacement pages are provided in Enclosure 3. The Revision 33 insertion instructions and replacement pages are provided in Enclosure 4.

It should be noted that Revision 33 only corrects an editorial error on one of the Revision 32 pages.

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, CKS/TNW/RKR/ca Sfy ik(a'\

A member of the STARS (Strategic Teaming and Resource Sharing) Alliance Callaway

• Comanche Peak

• Diablo Canyon

• Palo Verde

• South Texas Project

• Wolf Creek 66

U. S. Nuclear Regulatort Cbmmission ATTN: Document Control Desk Technical Specifications Bases Revisions 30, 31, 32, and 33 Update Page 2

Enclosures:

1. PVNGS Technical Specification Bases Revision 30 Insertion Instructions and Replacement Pages

2. PVNGS Technical Specification Bases Revision 31 Insertion Instructions and Replacement Pages

3. PVNGS Technical Specification Bases Revision 32 Insertion Instructions and Replacement Pages

4. PVNGS Technical Specification Bases Revision 33 Insertion Instructions and Replacement Pages cc: B. S. Mallett NRC Region IV Regional Administrator M. B. Fields NRC NRR Project Manager G. G. Warnick NRC Senior Resident Inspector for PVNGS

ENCLOSURE I PVNGS Technical Specification Bases Revision 30 Insertion Instructions and Replacement Pages

PVNGS Technical Specifications Bases Revision 30 Insertion Instructions Remove Pacre: Insert New Pacre:

Cover page Cover page List of Effective Pages, List of Effective Pages, Pages 1/2 through Pages 1/2 through List of Effective Pages, List of Effective Pages, Page 7/8 Page 7/8 B 3.3.1-49/3.3.1-50 B 3.3.1-49/3.3.1-50 through through B 3.3.1-53/3.3.1-54 B 3.3.1-53/3.3.1-54 B 3.4.5-1/3.4.5-2 B 3.4.5-1/3.4.5-2 through through B 3.4.5-3/3.4.5-4 B 3.4.5-3/3.4.5-4 I

P VNGS Palo Verde Nuclear GeneratingStation Units 1, 2, and 3 Techncal Specification Bases Revision 30 June 15, 2004

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B 3.8.1-12 2 B 3.8.4-11 2 B 3.8.1-13 2 B 3.8.5-1 1 B 3.8.1-14 2 B 3.8.5-2 1 B 3.8.1-15 2 B 3.8.5-3 21 B 3.8.1-16 20 B 3.8.5-4 21 B 3.8.1-17 20 B 3.8.5-5 2 B 3.8.1-18 20 B 3.8.5-6 2 B 3.8.1-19 20 B 3.8.6-1 0 B 3.8.1-20 20 B 3.8.6-2 0 B 3.8.1-21 20 B 3.8.6-3 0 B 3.8.1-22 20 B 3.8.6-4 6 B 3.8.1-23 20 B 3.8.6-5 6 B 3.8.1-24 20 B 3.8.6-6 6 B 3.8.1-25 20 B 3.8.6-7 0 B 3.8.1-26 20 B 3.8.7-1 0 B 3.8.1-27 20 B 3.8.7-2 0 B 3.8.1-28 20 B 3.8.7-3 0 B 3.8.1-29 20 B 3.8.7-4 0 B 3.8.1-30 20 B 3.8.8-1 1 B 3.8.1-31 20 B 3.8.8-2 1 B 3.8.1-32 20 B 3.8.8-3 21 B 3.8.1-33 20 B 3.8.8-4 21 B 3.8.1-34 20 B 3.8.8-5 1 B 3.8.1-35 20 B 3.8.9-1 0 B 3.8.1-36 20 B 3.8.9-2 0 B 3.8.1-37 23 B 3.8.9-3 0 B 3.8.1-38 27 B 3.8.9-4 0 B 3.8.1-39 20 B 3.8.9-5 0 B 3.8.1-40 20 B 3.8.9-6 0 B 3.8.2-1 0 B 3.8.9-7 0 B 3.8.2-2 0 B 3.8.9-8 0 B 3.8.2-3 0 B 3.8.9-9 0 B 3.8.2-4 21 B 3.8.9-10 0 B 3.8.2-5 21 B 3.8.9-11 0 B 3.8.2-6 0 B 3.8.10-1 0 B 3.8.3-1 0 B 3.8.10-2 21 B 3.8.3-2 0 B 3.8.10-3 0 B 3.8.3-3 0 B 3.8.10-4 0 B 3.8.3-4 0 B 3.9.1-1 0 B 3.8.3-5 27 B 3.9.1-2 0 B 3.8.3-6 0 B 3.9.1-3 0 B 3.8.3-7 0 B 3.9.1-4 0 B 3.8.3-8 0 B 3.9.2-1 15 B 3.8.3-9 0 B 3.9.2-2 15 B 3.8.4-1 0 B 3.9.2-3 15 B 3.8.4-2 0 B 3.9.2-4 15 B 3.8.4-3 0 B 3.9.3-1 18 B 3.8.4-4 2 B 3.9.3-2 19 B 3.8.4-5 2 B 3.9.3-3 27 B 3.8.4-6 2 B 3.9.3-4 19 B 3.8.4-7 2 B 3.9.3-5 19 B 3.8.4-8 2 B.3.9.3-6 19 B 3.8.4-9 2 B 3.9.4-1 0 B 3.8.4-10 2 B 3.9.4-2 1 PALO VERDE UNITS 1, 2, AND 3 7 Revision 30 June 15, 2004

TECHNICAL SPECIFICATION BASES LIST OF EFFECTIVE PAGES Page Rev. Page Rev No. No. . I- No. No.

B 3.9.4-3 0 B 3.9.4-4 0 B 3.9.5-1 0 B 3.9.5-2 16 B 3.9.5-3 27 B 3.9.5-4 16 B.3.9.5-5 16 B 3.9.6-1 0 B 3.9.6-2 0 B 3.9.6-3 0 B 3.9.7-1 0 B 3.9.7-2 0 B 3.9.7-3 0 PALO VERDE UNITS 1, 2, AND 3 8 Revision 30 June 15, 2004

RPS Instrumentation - Operating B 3.3.1 BASES SURVEILLANCE SR 3.3.1.4 REQUIREMENTS A daily calibration (heat balance) is performed when THERMAL POWER is Ž 20%. The Linear Power Level signal and the CPC addressable constant multipliers are adjusted to make the CPC AT power and nuclear power calculations agree with the calorimetric calculation if the absolute difference is 2 2%

when THERMAL POWER is 2 80% RTP, and -0.5% to 10% when THERMAL POWER is between 20% and 80%. The value of 2% when THERMAL POWER is 2 80% RTP. and -0.5% to 10% when THERMAL POWER is between 20% and 80% is adequate because this value is assumed in the safety analysis. These checks (and, if necessary, the adjustment of the Linear Power Level signal and the CPC addressable constant coefficients) are adequate to ensure that the accuracy of these CPC calculations is maintained within the analyzed error margins. The power level must be > 20% RTP to obtain accurate data. At lower power levels, the accuracy of calorimetric data is questionable.

The tolerance between 20% and 80% RTP is +10% to reduce the number of adjustments required as the power level increases.

The -0.5% tolerance between 20% and 80% RTP is based on the reduced accuracy of the calorimetric data inputs at low power levels. Performing a calorimetric calibration with a -0.5%

tolerance at low power levels ensures the difference will remain within -2.0% when power is increased above 80% RTP.

If a calorimetric calculation is performed above 80% RTP, it will use accurate inputs to the calorimetric calculation available at higher power levels. When the power level is decreased below 80% RTP an additional performance of the SR to the -0.5% to 10% tolerance is not required if the SR has been performed above 80% RTP. During any power ascension from below 80% to above 80% RTP, the calibration requirements of ITS SR 3.3.1.4 must be met (except during PHYSICS TESTS, as allowed by the Note in SR 3.3.1.4). This is accomplished by performing SR 3.3.1.4 between 75% and 80% RTP during power ascension with an acceptance criteria of -0.5% to <2% to bound the requirements for both below and above 80% RTP.

The Frequency of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is based on plant operating experience and takes into account indications and alarms located in the control room to detect deviations in channel outputs. The Frequency is modified by a Note indicating this Surveillance need only be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reaching 20% RTP.

The 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reaching 20% RTP is required for plant stabilization, data taking, and flow veri ication. The secondary calorimetric is inaccurate at lower power levels.

(continued)

PALO VERDE UNITS 1.2.3 B 3.3.1-49 REVISION 30

RPS Instrumentation - Operating B 3.3.1 BASES SURVEILLANCE SR 3.3.1.4 (continued)

REQUIREMENTS A second Note in the SR indicates the SR may be suspended during PHYSICS TESTS. The conditional suspension of the daily calibrations under strict administrative control is necessary to allow special testing to occur.

SR 3.3.1.5 The RCS flow rate indicated by each CPC is verified to be less than or equal to the RCS total flow rate every 31 days.

The Note indicates the Surveillance is performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is Ž 70% RTP. This check (and. if necessary, the adjustment of the CPC addressable flow constant coefficients) ensures that the DNBR setpoint is conservatively adjusted with respect to actual flow indications as determined either using the reactor coolant pump differential pressure instrumentation and the ultrasonic flow meter adjusted pump curves or by a calorimetric calculation. Operating experience has shown the specified Frequency is adequate. as instrument drift is minimal and changes in actual flow rate are minimal over core life.

SR 3.3.1.6 The three vertically mounted excore nuclear instrumentation detectors in each channel are used to determine APD for use in the DNBR and LPD calculations. Because the detectors are mounted outside the reactor vessel, a portion of the signal from each detector is from core sections not adjacent to the detector. This is termed shape annealing and is compensated for after every refueling by performing SR 3.3.1.11. which adjusts the gains of the three detector amplifiers for shape annealing. SR 3.3.1.6 ensures that the preassigned gains are still proper. When power is < 15% the CPCs do not use the excore generated signals for axial flux shape information. The Note allowing 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reaching 15%

RTP is required for plant stabilization and testing. The 31 day Frequency is adequate because the demonstrated long term drift of the instrument channels is minimal.

SR 3.3.1.7 A CHANNEL FUNCTIONAL TEST on each channel is performed every 92 days to ensure the entire channel will perform its (continued)

PALO VERDE UNITS 1,2,3 B 3.3.1-50 REVISION 30

RPS Instrumentation - Operating B 3.3.1 BASES SURVEILLANCE SR 3.3.1.7 (continued)

REQUIREMENTS intended function when needed. The SR is modified by two Notes. Note 1 is a requirement to verify the correct CPC addressable constant values are installed in the CPCs when the CPC CHANNEL FUNCTIONAL TEST is performed. Note 2 allows the CHANNEL FUNCTIONAL TEST for the Logarithmic Power Level - High channels to be performed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after logarithmic power drops below 1E-4% NRTP.

The RPS CHANNEL FUNCTIONAL TEST consists of three overlapping tests as described in Reference 8. These tests verify that the RPS is capable of performing its intended function, from bistable input through the RTCBs. They include:

Bistable Tests A test signal is superimposed on the input in one channel at a time to verify that the bistable trips within the specified tolerance around the setpoint. This is done with the affected RPS channel trip channel bypassed. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint analysis.

The as found and as left values must also be recorded and reviewed for consistency with the assumptions of the interval between surveillance interval extension analysis.

The requirements for this review are outlined in Reference 9.

Matrix Logic Tests Matrix Logic tests are addressed in LCO 3.3.4. This test is performed one matrix at a time. It verifies that a coincidence in the two input channels for each Function removes power from the matrix relays. During testing.

power is applied to the matrix relay test coils and prevents the matrix relay contacts from assuming their de-energized state. This test will detect any short circuits around the bistable contacts in the coincidence logic, such as may be caused by faulty bistable relay or trip channel bypass contacts.

Trip Path Tests Trip path (Initiation Logic) tests are addressed in LCO 3.3.4. These tests are similar to the Matrix Logic (continued)

PALO VERDE UNITS 1.2.3 B 3.3.1-51 REVISION 30

RPS Instrumentation - Operating B 3.3.1 BASES SURVEILLANCE Trip Path Tests (continued)

REQUIREMENTS tests, except that test power is withheld from one matrix relay at a time, allowing the initiation circuit to de-energize, thereby opening the affected RTCB. The RTCB must then be closed prior to testing the other three initiation circuits, or a reactor trip may result.

The Frequency of 92 days is based on the reliability analysis presented in topical report CEN-327. "RPS/ESFAS Extended Test Interval Evaluation" (Ref. 9).

The CPC and CEAC channels and excore nuclear instrumentation channels are tested separately.

The excore channels use preassigned test signals to verify proper channel alignment. The excore logarithmic channel test signal is inserted into the preamplifier input, so as to test the first active element downstream of the detector.

The power range excore test signal is inserted at the drawer input, since there is no preamplifier.

The quarterly CPC CHANNEL FUNCTIONAL TEST is performed using software. This software includes preassigned addressable constant values that may differ from the current values.

Provisions are made to store the addressable constant values on a computer disk prior to testing and to reload them after testing. A Note is added to the Surveillance Requirements to verify that the CPC CHANNEL FUNCTIONAL TEST includes the correct values of addressable constants.

SR 3.3.1.8 A Note indicates that neutron detectors are excluded from CHANNEL CALIBRATION. A CHANNEL CALIBRATION of the power range neutron flux channels every 92 days ensures that the channels are reading accurately and within tolerance (Ref. 9). The Surveillance verifies that the channel responds to a measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drift between successive calibrations to ensure that the channel remains operational between successive tests.

CHANNEL CALIBRATIONS must be performed consistent with the plant specific setpoint analysis.

The as found and as left values must also be recorded and reviewed for consistency with the assumptions of the interval (continued)

PALO VERDE UNITS 1.2.3 B 3.3.1-52 REVISION 30

RPS Instrumentation - Operating B 3.3.1 BASES SURVEILLANCE SR 3.3.1.8 (continued)

REQUIREMENTS between surveillance interval extension analysis. The requirements for this review are outlined in Reference 9.

Operating experience has shown this Frequency to be satisfactory. The detectors are excluded from CHANNEL CALIBRATION because they are passive devices with minimal drift and because of the difficulty of simulating a meaningful signal. Slow changes in detector sensitivity are compensated for by performing the daily calorimetric calibration (SR 3.3.1.4) and the monthly linear subchannel gain check (SR 3.3.1.6). In addition. the associated control room indications are monitored by the operators.

SR 3.3.1.9 SR 3.3.1.9 is the performance of a CHANNEL CALIBRATION every 18 months.

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

The as found and as left values must also be recorded and reviewed for consistency with the assumptions of the surveillance interval extension analysis. The requirements for this review are outlined in Reference 9.

The Frequency is based upon the assumption of an 18 month calibration interval for the determination of the magnitude of equipment drift in the setpoint analysis as well as operating experience and consistency with the typical 18 month fuel cycle.

The Surveillance is modified by a Note to indicate that the neutron detectors are excluded from CHANNEL CALIBRATION because they are passive devices with minimal drift and because of the difficulty of simulating a meaningful signal. Slow changes in detector sensitivity are compensated for by performing the daily calorimetric calibration (SR 3.3.1.4) and the monthly linear subchannel gain check (SR 3.3.1.6).

(continued)

PALO VERDE UNITS 1.2.3 B 3.3.1-53 REVISION 30

RPS Instrumentation - Operating B 3.3.1 BASES SURVEILLANCE SR 3.3.1.10 REQUIREMENTS (continued) Every 18 months, a CHANNEL FUNCTIONAL TEST is performed on the CPCs. The CHANNEL FUNCTIONAL TEST shall include the injection of a signal as close to the sensors as practicable to verify OPERABILITY including alarm and trip Functions.

The basis for the 18 month Frequency is that the CPCs perform a continuous self monitoring function that eliminates the need for frequent CHANNEL FUNCTIONAL TESTS.

This CHANNEL FUNCTIONAL TEST essentially validates the self monitoring function and checks for a small set of failure modes that are undetectable by the self monitoring function. Operating experience has shown that undetected CPC or CEAC failures do not occur in any given 18 month interval.

SR 3.3.1.11 The three excore detectors used by each CPC channel for axial flux distribution information are far enough from the core to be exposed to flux from all heights in the core.

although it is desired that they only read their particular level. The CPCs adjust for this flux overlap by using the predetermined shape annealing matrix elements in the CPC software.

After refueling. it is necessary to re-establish or verify the shape annealing matrix elements for the excore detectors based on more accurate incore detector readings.

This is necessary because refueling could possibly produce a significant change in the shape annealing matrix coefficients.

Incore detectors are inaccurate at low power levels.

THERMAL POWER should be significant but < 70% to perform an accurate axial shape calculation used to derive the shape annealing matrix elements.

By restricting power to < 70% until shape annealing matrix elements are verified, excessive local power peaks within the fuel are avoided. Operating experience has shown this Frequency to be acceptable.

(continued)

PALO VERDE UNITS 1.2,3 B 3.3.1-54 REVISION 25

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 function 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 does not 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 Analyses have shown that the rod withdrawal event from SAFETY ANALYSES MODE 3 with one RCS loop in operation is bounded by the rod withdrawal initiated 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)

PALO VERDE UNITS 1.2,3 B 3.4.5-1 REVISION 0

RCS Loops - MODE 3 B 3.4.5 BASES LCO The purpose of this LCO isto require two RCS loops to be available 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 (225% wide range water level) of transferring heat from the reactor coolant at a controlled rate. Forced reactor coolant flow isthe required way to transport heat, 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 <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 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 any known or direct positive reactivity additions to the RCS due to dilution. Core outlet temperature is to be maintained at least 10'F below the saturation temperature so that no vapor bubble may form and possibly cause a natural circulation flow obstruction. The 10 degrees F isconsidered 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 iswith pressurizer pressure less than or equal to 350 psia, and inthat 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 inorder to use the provisions of the Note allowing the pumps to be de-energized.

InMODE 3 itissometimes 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 isadequate 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 inaccordance with the Steam Generator Tube (continued)

PALO VERDE UNITS 1.2,3 B 3.4.5-2 REVISION 30

RCS Loops - MODE 3 B 3.4.5 BASES LCO Surveillance Program. An RCP is OPERABLE if it is (continued) capable of being powered and is 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 3.4.4 "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 <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This time allowance is a justified period to be without the redundant.

nonoperating loop 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 <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, the unit must be placed in MODE 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. In MODE 4, the plant may be placed on the SDC System. The Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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 30

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 boron concentration 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> that the required number of RCS loops are in operation and circulating Reactor Coolant. Verification includes flow rate, temperature, or pump status monitoring, which help ensure that forced flow is providing heat removal. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> interval has been shown by operating practice to be sufficient to regularly assess degradation and verify operation within safety analyses assumptions. In addition.

control room indication and alarms will normally indicate loop status.

SR 3.4.5.2 This SR requires verification every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> that the secondary side water level in each SG is 2 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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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

ENCLOSURE 2 PVNGS Technical Specification Bases Revision 31 Insertion Instructions and Replacement Pages

PVNGS Technical Specifications Bases Revision 31 Insertion Instructions Remove Page: Insert New Page:

Cover page Cover page List of Effective Pages, List of Effective Pages, Pages 1/2 through Pages 1/2 through List of Effective Pages, List of Effective Pages, Page 7/8 Page 7/8 B 2.1.2-1/2.1.2-2 B 2.1.2-1/2.1.2-2 B 3.1.1-5/3.1.1-6 B 3.1.1-5/3.1.1-6 B 3.1.2-3/3.1.2-4 B 3.1.2-3/3.1.2-4 B 3.1.4-1/3.1.4-2 B 3.1.4-1/3.1.4-2 B 3.2.4-7/3.2.4-8 B 3.2.4-7/3.2.4-8 through through B 3.2.4-9/3.2.4-10 B 3.2.4-9/3.2.4-10 B 3.3.4-5/3.3.4-6 B 3.3.4-5/3.3.4-6 B 3.3.5-7/3.3.5-8 B 3.3.5-7/3.3.5-8 B 3.3.6-5/3.3.6-6 B 3.3.6-5/3.3.6-6 B 3.4.9-1/3.4.9-2 B 3.4.9-1/3.4.9-2 through through B 3.4.9-3/3.4.9-4 B 3.4.9-3/3.4.9-4 B 3.4.12-1/3.4.12-2 B 3.4.12-1/3.4.12-2 B 3.4.12-5/blank B 3.4.12-5/blank B 3.7.2-3/3.7.2-4 B 3.7.2-3/3.7.2-4 B 3.7.4-1/3.7.4-2 B 3.7.4-1/3.7.4-2 through through B 3.7.4-3/3.7.4-4 B 3.7.4-3/3.7.4-4 I

P VNGS Palo Verde Nuclear GeneratingStation Units 1, 2, and 3 Technical Specification Bases Revision 31 August 25, 2004

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B 2.1.1-1 0 B 3.1.4-5 0 B 2.1.1-2 0 B 3.1.5-1 0 B 2.1.1-3 21 B 3.1.5-2 28 B 2.1.1-4 21 B 3.1.5-3 28 B 2.1.1-5 23 B 3.1.5-4 28 B 2.1.2-1 0 B 3.1.5-5 28 B 2.1.2-2 31 B 3.1.5-6 28 B 2.1.2-3 0 B 3.1.5-7 1 B 2.1.2-4 23 B 3.1.5-8 28 B 2.1.2-5 0 B 3.1.5-9 28 B 3.0-1 0 B 3.1.5-10 28 B 3.0-2 0 B 3.1.5-11 28 B 3.0-3 0 B 3.1.6-1 0 B 3.0-4 0 B 3.1.6-2 0 B 3.0-5 0 B 3.1.6-3 0 B 3.0-6 1 B 3.1.6-4 0 B 3.0-7 0 B 3.1.7-1 0 B 3.0-8 0 B 3.1.7-2 0 B 3.0-9 0 B 3.1.7-3 28 B 3.0-10 14 B 3.1.7-4 0 B 3.0-11 14 B 3.1.7-5 25 B 3.0-12 14 B 3.1.7-6 0 B 3.0-13 0 B 3.1.7-7 0 B 3.0-14 0 B 3.1.7-8 0 B 3.0-15 0 B 3.1.7-9 0 B 3.0-16 17 B 3.1.8-1 28 B 3.0-17 17 B 3.1.8-2 28 B 3.0-18 17 B 3.1.8-3 28 B 3.0-19 17 B 3.1.8-4 28 B 3.1.1-1 28 B 3.1.8-5 28 B 3.1.1-2 0 B 3.1.9-1 0 B 3.1.1-3 28 B 3.1.9-2 0 B 3.1.1-4 12 B 3.1.9-3 0 B 3.1.1-5 27 B 3.1.9-4 0 B 3.1.1-6 31 B 3.1.9-5 28 B 3.1.2-1 28 B 3.1.9-6 1 B 3.1.2-2 0 B 3.1.10-1 0 B 3.1.2-3 31 B 3.1.10-2 28 B 3.1.2-4 28 B 3.1.10-3 0 B 3.1.2-5 0 B 3.1.10-4 0 B 3.1.2-6 0 B 3.1.10-5 0 B 3.1.2-7 12 B 3.1.10-6 0 B 3.1.2-8 0 B 3.1.11-1 0 B 3.1.2-9 0 B 3.1.11-2 28 B 3.1.3-1 0 B 3.1.11-3 0 B 3.1.3-2 0 B 3.1.11-4 28 B 3.1.3-3 0 B 3.1.11-5 0 B 3.1.3-4 0 B 3.2.1-1 28 B 3.1.3-5 0 B 3.2.1-2 10 B 3.1.3-6 0 B 3.2.1-3 28 B 3.1.4-1 0 B 3.2.1-4 0 B 3.1.4-2 31 B 3.2.1-5 0 B 3.1.4-3 0 B 3.2.1-6 0 B 3.1.4-4 0 B 3.2.1-7 0 PALO VERDE UNITS 1, 2, AND 3 1 Revision 31 August 25, 2004

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B 3.2.1-8 0 B 3.3.1-20 25 B 3.2.2-1 28 B 3.3.1-21 28 B 3.2.2-2 10 B 3.3.1-22 28 B 3.2.2-3 0 B 3.3.1-23 25 B 3.2.2-4 28 B 3.3.1-24 25 B 3.2.2-5 1 B 3.3.1-25 25 B 3.2.2-6 0 B 3.3.1-26 25 B 3.2.2-7 0 B 3.3.1-27 25 B 3.2.3-1 28 B 3.3.1-28 25 B 3.2.3-2 10 B 3.3.1-29 25 B 3.2.3-3 0 B 3.3.1-30 27 B 3.2.3-4 28 B 3.3.1-31 27 B 3.2.3-5 0 B 3.3.1-32 27 B 3.2.3-6 0 B 3.3.1-33 27 B 3.2.3-7 0 B 3.3.1-34 27 B 3.2.3-8 0 B 3.3.1-35 25 B 3.2.3-9 0 B 3.3.1-36 27 B 3.2.3-10 0 B 3.3.1-37 25 B 3.2.4-1 28 B 3.3.1-38 25 B 3.2.4-2 10 B 3.3.1-39 27 B 3.2.4-3 0 B 3.3.1-40 25 B 3.2.4-4 28 B 3.3.1-41 25 B 3.2.4-5 25 B 3.3.1-42 25 B 3.2.4-6 25 B 3.3.1-43 25 B 3.2.4-7 27 B.3.3.1-44 25 B 3.2.4-8 31 B.3.3.1-45 25 B 3.2.4-9 31 B.3.3.1-46 25 B.3.2.4-10 31 B.3.3.1-47 25 B 3.2.5-1 28 B.3.3.1-48 25 B 3.2.5-2 10 B.3.3.1-49 30 B 3.2.5-3 0 B.3.3.1-50 30 B 3.2.5-4 28 B.3.3.1-51 30 B 3.2.5-5 0 B.3.3.1-52 30 B 3.2.5-6 28 B.3.3.1-53 30 B 3.2.5-7 0 B.3.3.1-54 25 B 3.3.1-1 0 B.3.3.1-55 25 B 3.3.1-2 25 B.3.3.1-56 25 B 3.3.1-3 25 B.3.3.1-57 27 B 3.3.1-4 25 B 3.3.2-1 0 B 3.3.1-5 25 B 3.3.2-2 0 B 3.3.1-6 27 B 3.3.2-3 1 B 3.3.1-7 25 B 3.3.2-4 1 B 3.3.1-8 25 B 3.3.2-5 0 B 3.3.1-9 27 B 3.3.2-6 15 B 3.3.1-10 27 B 3.3.2-7 15 B 3.3.1-11 26 B 3.3.2-8 15 B 3.3.1-12 27 B 3.3.2-9 15 B 3.3.1-13 27 B 3.3.2-10 15 B 3.3.1-14 25 B 3.3.2-11 15 B 3.3.1-15 25 B 3.3.2-12 15 B 3.3.1-16 25 B 3.3.2-13 15 B 3.3.1-17 25 B 3.3.2-14 15 B 3.3.1-18 25 B 3.3.2-15 15 B 3.3.1-19 25 B 3.3.2-16 15 PALO VERDE UNITS 1, 2, AND 3 2 Revision 31 August 25, 2004

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B 3.3.2-17 15 B 3.3.5-18 0 B 3.3.3-1 25 B 3.3.5-19 0 B 3.3.3-2 27 B 3.3.5-20 1 B 3.3.3-3 25 B 3.3.5-21 0 B 3.3.3-4 25 B 3.3.5-22 0 B 3.3.3-5 25 B 3.3.5-23 0 B 3.3.3-6 25 B 3.3.5-24 0 B 3.3.3-7 27 B 3.3.5-25 0 B 3.3.3-8 27 B 3.3.5-26 0 B 3.3.3-9 27 B 3.3.5-27 10 B 3.3.3-10 25 B 3.3.5-28 10 B 3.3.3-11 25 B 3.3.5-29 10 B.3.3.3-12 25 B 3.3.6-1 0 B.3.3.3-13 25 B 3.3.6-2 0 B.3.3.3-14 25 B 3.3.6-3 0 B.3.3.3-15 27 B 3.3.6-4 0 B.3.3.3-16 25 B 3.3.6-5 31 B.3.3.3-17 25 B 3.3.6-6 0 B.3.3.3-18 25 B 3.3.6-7 27 B.3.3.3-19 27 B 3.3.6-8 27 B.3.3.3-20 27 B 3.3.6-9 0 B.3.3.3-21 27 B 3.3.6-10 0 B 3.3.4-1 0 B 3.3.6-11 0 B 3.3.4-2 0 B 3.3.6-12 0 B 3.3.4-3 0 B 3.3.6-13 0 B 3.3.4-4 0 B 3.3.6-14 0 B 3.3.4-5 0 B 3.3.6-15 0 B 3.3.4-6 31 B 3.3.6-16 0 B 3.3.4-7 0 B 3.3.6-17 27 B 3.3.4-8 0 B 3.3.6-18 0 B 3.3.4-9 0 B 3.3.6-19 0 B 3.3.4-10 0 B 3.3.6-20 0 B 3.3.4-11 0 B 3.3.6-21 1 B 3.3.4-12 0 B 3.3.6-22 1 B 3.3.4-13 0 B 3.3.7-1 2 B 3.3.4-14 0 B 3.3.7-2 2 B 3.3.4-15 0 B 3.3.7-3 0 B 3.3.5-1 0 B 3.3.7-4 0 B 3.3.5-2 0 B 3.3.7-5 0 B 3.3.5-3 0 B 3.3.7-6 0 B 3.3.5-4 0 B 3.3.7-7 0 B 3.3.5-5 0 B 3.3.7-8 0 B 3.3.5-6 0 B 3.3.7-9 2 B 3.3.5-7 0 B 3.3.8-1 0 B 3.3.5-8 31 B 3.3.8-2 0 B 3.3.5-9 0 B 3.3.8-3 0 B 3.3.5-10 0 B 3.3.8-4 0 B 3.3.5-11 0 B 3.3.8-5 0 B 3.3.5-12 1 B 3.3.8-6 1 B 3.3.5-13 0 B 3.3.8-7 0 B 3.3.5-14 0 B 3.3.8-8 0 B 3.3.5-15 0 B 3.3.9-1 0 B 3.3.5-16 0 B 3.3.9-2 2 B 3.3.5-17 0 B 3.3.9-3 21 PALO VERDE UNITS 1, 2, AND 3 3 Revision 31 August 25, 2004

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B 3.3.9-4 10 B 3.4.4-2 7 B 3.3.9-5 1 B 3.4.4-3 7 B 3.3.9-6 0 B 3.4.4-4 0 B 3.3.9-7 0 B 3.4.5-1 0 B 3.3.10-1 0 B 3.4.5-2 30 B 3.3.10-2 0 B 3.4.5-3 30 B 3.3.10-3 0 B 3.4.5-4 0 B 3.3.10-4 0 B 3.4.5-5 6 B 3.3.10-5 18 B 3.4.6-1 0 B 3.3.10-6 0 B 3.4.6-2 6 B 3.3.10-7 0 B 3.4.6-3 6 B 3.3.10-8 14 B 3.4.6-4 6 B 3.3.10-9 14 B 3.4.6-5 6 B 3.3.10-10 14 B 3.4.7-1 0 B 3.3.10-11 14 B 3.4.7-2 6 B 3.3.10-12 14 B 3.4.7-3 6 B 3.3.10-13 14 B 3.4.7-4 2 B 3.3.10-14 14 B 3.4.7-5 0 B 3.3.10-15 14 B 3.4.7-6 0 B 3.3.10-16 14 B 3.4.7-7 27 B 3.3.10-17 14 B 3.4.8-1 0 B 3.3.10-18 14 B 3.4.8-2 6 B 3.3.10-19 14 B 3.4.8-3 6 B 3.3.10-20 14 B 3.4.9-1 0 B 3.3.10-21 14 B 3.4.9-2 31 B 3.3.11-1 0 B 3.4.9-3 31 B 3.3.11-2 2 B 3.4.9-4 0 B 3.3.11-3 2 B 3.4.9-5 0 B 3.3.11-4 2 B 3.4.9-6 0 B 3.3.11-5 19 B 3.4.10-1 0 B 3.3.11-6 2 B 3.4.10-2 7 B 3.3.11-7 2 B 3.4.10-3 0 B 3.3.12-1 15 B 3.4.10-4 0 B 3.3.12-2 15 B 3.4.11-1 0 B 3.3.12-3 5 B 3.4.11-2 7 B 3.3.12-4 5 B 3.4.11-3 0 B 3.3.12-5 6 B 3.4.11-4 0 B 3.3.12-6 6 B 3.4.11-5 0 B 3.4.1-1 10 B 3.4.11-6 0 B 3.4.1-2 28 B 3.4.12-1 1 B 3.4.1-3 0 B 3.4.12-2 31 B 3.4.1-4 0 B 3.4.12-3 0 B 3.4.1-5 0 B 3.4.12-4 0 B 3.4.2-1 7 B 3.4.12-5 31 B 3.4.2-2 1 B 3.4.13-1 0 B 3.4.3-1 0 B 3.4.13-2 0 B 3.4.3-2 0 B 3.4.13-3 1 B 3.4.3-3 0 B 3.4.13-4 0 B 3.4.3-4 2 B 3.4.13-5 0 B 3.4.3-5 2 B 3.4.13-6 0 B 3.4.3-6 0 B 3.4.13-7 2 B 3.4.3-7 0 B 3.4.13-8 2 B 3.4.3-8 2 B 3.4.13-9 0 B 3.4.4-1 0 B 3.4.13-10 2 PALO VERDE UNITS 1, 2, AND 3 4 Revision 31 August 25, 2004

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B 3.4.14-1 0 B 3.5.3-9 0 B 3.4.14-2 23 B 3.5.3-10 2 B 3.4.14-3 23 B 3.5.4-1 15 B 3.4.14-4 7 B 3.5.4-2 0 B 3.4.14-5 2 B 3.5.4-3 0 B 3.4.14-6 2 B 3.5.5-1 0 B 3.4.14-7 2 B 3.5.5-2 7 B 3.4.15-1 0 B 3.5.5-3 4 B 3.4.15-2 0 B 3.5.5-4 4 B 3.4.15-3 0 B 3.5.5-5 0 B 3.4.15-4 0 B 3.5.5-6 0 B 3.4.15-5 0 B 3.5.5-7 0 B 3.4.15-6 0 B 3.5.6-1 0 B 3.4.15-7 0 B 3.5.6-2 1 B 3.4.16-1 2 B 3.5.6-3 0 B 3.4.16-2 10 B 3.5.6-4 24 B 3.4.16-3 0 B 3.5.6-5 27 B 3.4.16-4 0 B 3.6.1-1 0 B 3.4.16-5 0 B 3.6.1-2 25 B 3.4.16-6 0 B 3.6.1-3 0 B 3.4.17-1 0 B 3.6.1-4 29 B 3.4.17-2 27 B 3.6.1-5 29 B 3.4.17-3 0 B 3.6.2-1 0 B 3.4.17-4 0 B 3.6.2-2 25 B 3.4.17-5 0 B 3.6.2-3 0 B 3.4.17-6 0 B 3.6.2-4 0 B 3.5.1-1 0 B 3.6.2-5 0 B 3.5.1-2 0 B 3.6.2-6 0 B 3.5.1-3 7 B 3.6.2-7 0 B 3.5.1-4 0 B 3.6.2-8 0 B 3.5.1-5 0 B 3.6.3-1 27 B 3.5.1-6 0 B 3.6.3-2 27 B 3.5.1-7 1 B 3.6.3-3 27 B 3.5.1-8 1 B 3.6.3-4 27 B 3.5.1-9 0 B 3.6.3-5 27 B 3.5.1-10 1 B 3.6.3-6 27 B 3.5.2-1 0 B 3.6.3-7 27 B 3.5.2-2 0 B 3.6.3-8 27 B 3.5.2-3 0 B 3.6.3-9 27 B 3.5.2-4 0 B 3.6.3-10 27 B 3.5.2-5 0 B 3.6.3-11 27 B 3.5.2-6 0 B 3.6.3-12 27 B 3.5.2-7 1 B 3.6.3-13 27 B 3.5.2-8 22 B 3.6.3-14 27 B 3.5.2-9 1 B 3.6.3-15 27 B 3.5.2-10 1 B 3.6.3-16 27 B 3.5.3-1 0 B 3.6.3-17 27 B 3.5.3-2 0 B.3.6.3-18 27 B 3.5.3-3 0 B.3.6.3-19 27 B 3.5.3-4 0 B 3.6.4-1 25 B 3.5.3-5 0 B 3.6.4-2 1 B 3.5.3-6 2 B 3.6.4-3 1 B 3.5.3-7 2 B 3.6.5-1 0 B 3.5.3-8 1 B 3.6.5-2 1 PALO VERDE UNITS 1, 2, AND 3 5 Revision 31 August 25, 2004

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B 3.6.5-3 0 B 3.7.7-4 1 B 3.6.5-4 0 B 3.7.7-5 1 B 3.6.6-1 0 B 3.7.8-1 1 B 3.6.6-2 0 B 3.7.8-2 1 B 3.6.6-3 25 B 3.7.8-3 1 B 3.6.6-4 7 B 3.7.8-4 1 B 3.6.6-5 1 B 3.7.9-1 0 B 3.6.6-6 0 B 3.7.9-2 1 B 3.6.6-7 1 B 3.7.9-3 0 B 3.6.6-8 1 B 3.7.10-1 10 B 3.6.6-9 0 B 3.7.10-2 1 B 3.6.7-1 0 B 3.7.10-3 1 B 3.6.7-2 0 B 3.7.10-4 1 B 3.6.7-3 0 B 3.7.11-1 0 B 3.6.7-4 0 B 3.7.11-2 0 B 3.6.7-5 0 B 3.7.11-3 21 B 3.7.1-1 28 B 3.7.11-4 10 B 3.7.1-2 28 B 3.7.11-5 10 B 3.7.1-3 28 B 3.7.11-6 10 B 3.7.1-4 28 B 3.7.12-1 1 B 3.7.1-5 28 B 3.7.12-2 21 B 3.7.2-1 0 B 3.7.12-3 21 B 3.7.2-2 0 B 3.7.12-4 10 B 3.7.2-3 31 B 3.7.13-1 0 B 3.7.2-4 0 B 3.7.13-2 0 B 3.7.2-5 0 B 3.7.13-3 0 B 3.7.2-6 0 B 3.7.13-4 0 B 3.7.3-1 1 B 3.7.13-5 0 B 3.7.3-2 1 B 3.7.14-1 0 B 3.7.3-3 1 B 3.7.14-2 21 B 3.7.3-4 0 B 3.7.14-3 21 B 3.7.3-5 0 B 3.7.15-1 3 B 3.7.4-1 0 B 3.7.15-2 3 B 3.7.4-2 31 B 3.7.16-1 7 B 3.7.4-3 31 B 3.7.16-2 0 B 3.7.4-4 0 B 3.7.16-3 0 B 3.7.5-1 0 B 3.7.16-4 0 B 3.7.5-2 0 B 3.7.17-1 23 B 3.7.5-3 0 B 3.7.17-2 3 B 3.7.5-4 27 B 3.7.17-3 3 B 3.7.5-5 9 B 3.7.17-4 3 B 3.7.5-6 9 B 3.7.17-5 3 B 3.7.5-7 9 B 3.7.17-6 3 B 3.7.5-8 9 B 3.8.1-1 22 B 3.7.5-9 9 B 3.8.1-2 2 B 3.7.5-10 9 B 3.8.1-3 20 B.3.7.5-11 9 B 3.8.1-4 20 B 3.7.6-1 0 B 3.8.1-5 20 B 3.7.6-2 28 B 3.8.1-6 27 B 3.7.6-3 28 B 3.8.1-7 2 B 3.7.6-4 0 B 3.8.1-8 2 B 3.7.7-1 0 B 3.8.1-9 27 B 3.7.7-2 1 B 3.8.1-10 2 B 3.7.7-3 1 B 3.8.1-11 2 PALO VERDE UNITS 1, 2, AND 3 6 Revision 31 August 25, 2004

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B 3.8.1-12 2 B 3.8.4-11 2 B 3.8.1-13 2 B 3.8.5-1 1 B 3.8.1-14 2 B 3.8.5-2 1 B 3.8.1-15 2 B 3.8.5-3 21 B 3.8.1-16 20 B 3.8.5-4 21 B 3.8.1-17 20 B 3.8.5-5 2 B 3.8.1-18 20 B 3.8.5-6 2 B 3.8.1-19 20 B 3.8.6-1 0 B 3.8.1-20 20 B 3.8.6-2 0 B 3.8.1-21 20 B 3.8.6-3 0 B 3.8.1-22 20 B 3.8.6-4 6 B 3.8.1-23 20 B 3.8.6-5 6 B 3.8.1-24 20 B 3.8.6-6 6 B 3.8.1-25 20 B 3.8.6-7 0 B 3.8.1-26 20 B 3.8.7-1 0 B 3.8.1-27 20 B 3.8.7-2 0 B 3.8.1-28 20 B 3.8.7-3 0 B 3.8.1-29 20 B 3.8.7-4 0 B 3.8.1-30 20 B 3.8.8-1 1 B 3.8.1-31 20 B 3.8.8-2 1 B 3.8.1-32 20 B 3.8.8-3 21 B 3.8.1-33 20 B 3.8.8-4 21 B 3.8.1-34 20 B 3.8.8-5 1 B 3.8.1-35 20 B 3.8.9-1 0 B 3.8.1-36 20 B 3.8.9-2 0 B 3.8.1-37 23 B 3.8.9-3 0 B 3.8.1-38 27 B 3.8.9-4 0 B 3.8.1-39 20 B 3.8.9-5 0 B 3.8.1-40 20 B 3.8.9-6 0 B 3.8.2-1 0 B 3.8.9-7 0 B 3.8.2-2 0 B 3.8.9-8 0 B 3.8.2-3 0 B 3.8.9-9 0 B 3.8.2-4 21 B 3.8.9-10 0 B 3.8.2-5 21 B 3.8.9-11 0 B 3.8.2-6 0 B 3.8.10-1 0 B 3.8.3-1 0 B 3.8.10-2 21 B 3.8.3-2 0 B 3.8.10-3 0 B 3.8.3-3 0 B 3.8.10-4 0 B 3.8.3-4 0 B 3.9.1-1 0 B 3.8.3-5 27 B 3.9.1-2 0 B 3.8.3-6 0 B 3.9.1-3 0 B 3.8.3-7 0 B 3.9.1-4 0 B 3.8.3-8 0 B 3.9.2-1 15 B 3.8.3-9 0 B 3.9.2-2 15 B 3.8.4-1 0 B 3.9.2-3 15 B 3.8.4-2 0 B 3.9.2-4 15 B 3.8.4-3 0 B 3.9.3-1 18 B 3.8.4-4 2 B 3.9.3-2 19 B 3.8.4-5 2 B 3.9.3-3 27 B 3.8.4-6 2 B 3.9.3-4 19 B 3.8.4-7 2 B 3.9.3-5 19 B 3.8.4-8 2 B.3.9.3-6 19 B 3.8.4-9 2 B 3.9.4-1 0 B 3.8.4-10 2 B 3.9.4-2 1 PALO VERDE UNITS 1, 2, AND 3 7 Revision 31 August 25, 2004

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B 3.9.4-3 0 B 3.9.4-4 0 B 3.9.5-1 0 B 3.9.5-2 16 B 3.9.5-3 27 B 3.9.5-4 16 B.3.9.5-5 16 B 3.9.6-1 0 B 3.9.6-2 0 B 3.9.6-3 0 B 3.9.7-1 0 B 3.9.7-2 0 B 3.9.7-3 0 PALO VERDE UNITS 1, 2, AND 3 8 Revision 31 August 25, 2004

RCS Pressure SL B 2.1.2 B 2.0 SAFETY LIMITS (SLs)

B 2.1.2 Reactor Coolant System (RCS) Pressure SL BASES BACKGROUND The SL on RCS pressure protects the integrity of the RCS against overpressurization. In the event of fuel cladding failure, fission products are released into the reactor coolant. The RCS then serves as the primary barrier in preventing the release of fission products into the atmosphere. By establishing an upper limit on RCS pressure.

continued RCS integrity is ensured. According to 10 CFR 50, Appendix A. GDC 14, "Reactor Coolant Pressure Boundary." and GDC 15. "Reactor Coolant System Design" (Ref. 1). the Reactor Coolant Pressure Boundary (RCPB) design conditions are not to be exceeded during normal operation and Anticipated Operational Occurrences (AOOs). Also, according to GDC 28 (Ref. 1). "Reactivity Limits," reactivity accidents, including rod ejection, do not result in damage to the RCPB greater than limited local yielding.

The design pressure of the RCS is 2500 psia. During normal operation and AOOs, the RCS pressure is kept from exceeding the design pressure by more than 10%. in accordance with Section III of the ASME Code (Ref. 2). To ensure system integrity, all RCS components are hydrostatically tested at 125% of design pressure, according to the ASME Code requirements prior to initial operation, when there is no fuel in the core. Following inception of unit operation, RCS components shall be pressure tested, in accordance with the requirements of ASME Code,Section XI (Ref. 3).

Overpressurization of the RCS could result in a breach of the RCPB. If this occurs in conjunction with a fuel cladding failure, fission products could enter the containment atmosphere. raising concerns relative to limits on radioactive releases specified in 10 CFR 100. "Reactor Site Criteria" (Ref. 4).

APPLICABLE The RCS pressurizer safety valves, the Main Steam Safety SAFETY ANALYSES Valves (MSSVs). and the Reactor Pressure - High trip have settings established to ensure that the RCS pressure SL will not be exceeded.

(continued)

PALO VERDE UNITS 1.2.3 B 2.1.2-1 REVISION 0

RCS Pressure SL B 2.1.2 BASES APPLICABLE The RCS pressurizer safety valves are sized to prevent SAFETY ANALYSES system pressure from exceeding the design pressure by more (continued) than 10%. in accordance with Section III of the ASME Code for Nuclear Power Plant Components (Ref. 2). The transient that establishes the required relief capacity, and hence the valve size requirements and lift settings, is a complete loss of external load without a direct reactor trip. During the transient, no control actions are assumed except that the safety valves on the secondary plant are assumed to open when the steam pressure reaches the secondary plant safety valve settings.

I The Reactor Protective System (RPS) trip setpoints (LCO 3.3.1. "Reactor Protective System (RPS)

Instrumentation"), together with the settings of the MSSVs (LCO 3.7.1. "Main Steam Safety Valves (MSSVs)") and the pressurizer safety valves, provide pressure protection for normal operation and AOOs. In particular, the Pressurizer Pressure - High Trip setpoint is specifically set to provide protection against overpressurization (Ref. 5). Safety analyses for both the Pressure - High Trip and the RCS pressurizer safety valves are performed, using conservative assumptions relative to pressure control devices.

More specifically, no credit is taken for operation of the following:

a. Steam Bypass Control System;

b. Pressurizer Level Control System:

c. Pressurizer Pressure Control System; or

d. Main Feedwater System SAFETY LIMITS The maximum transient pressure allowable in the RCS under the ASME Code,Section III, is 110% of design pressure.

Therefore, the SL on maximum allowable RCS pressure is established at 2750 psia.

(continued)

PALO VERDE UNITS 1,2.3 B 2.1.2-2 REVISION 31

SDM - Reactor Trip Breakers Open B 3.1.1 BASES (continued)

ACTIONS A.1 (continued) possible, the boron concentration should be a highly concentrated solution. such as that normally found in the refueling water tank. The operator should borate with the best source available for the plant conditions.

In determining the boration flow rate, the time in core life must be considered. For instance, the most difficult time in core life to increase the RCS boron concentration is at the beginning of cycle. when boron concentration may approach or exceed 2000 ppm. Assuming that a value of 1%

Ak/k must be recovered and a boration flow rate of 26 gpm, it is possible to increase the boron concentration of the RCS by 100 ppm in less than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> with a 4000 ppm source.

If a boron worth of 10 pcm/ppm is assumed. this combination of parameters will increase the SDM by 1% Ak/k. These boration parameters of 26 gpm and 4000 ppm represent typical values and are provided for the purpose of offering a specific example.

SURVEILLANCE SR 3.1.1.1 REQUIREMENTS SDM is verified by performing a reactivity balance calculation, considering the listed reactivity effects:

a. RCS boron concentration:

b. CEA positions:

c. RCS average temperature;

d. Fuel burnup based on gross thermal energy generation;

e. Xenon concentration:

f. Samarium concentration: and

g. Isothermal temperature coefficient (ITC).

Using the ITC accounts for Doppler reactivity in this calculation because the reactor is subcritical. and the fuel temperature will be changing at the same rate as the RCS.

(continued)

PALO VERDE UNITS 1,2,3 B 3.1.1-5 REVISION 27

SDM - Reactor Trip Breakers Open B 3.1.1 BASES (continued)

SURVEILLANCE The Frequency of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is based on the generally slow REQUIREMENTS change in required boron concentration, and also allows (continued) sufficient time for the operator to collect the required data, which includes performing a boron concentration analysis, and complete the calculation. When taking credit for the Xenon concentration in the reactivity balance calculation, the frequency may have to be administratively controlled to ensure that SDM does not go below the limit due to Xenon decay.

REFERENCES 1. 10 CFR 50. Appendix A, GDC 26.

2. UFSAR. Section 15.1.

3. UFSAR, Section 15.4.

4. 10 CFR 100.

PALO VERDE UNITS 1.2.3 B 3.1.1-6 REVISION 31

SDM - Reactor Trip Breakers Closed B 3.1.2 BASES (continued)

APPLICABLE MSLB, a post trip return to power may occur: however, no SAFETY ANALYSES fuel damage occurs as a result of the post trip return to (continued) power, and THERMAL POWER does not violate the Safety Limit (SL) requirement of SL 2.1.1.

In addition to the limiting MSLB transient, the SDM requirement for MODES 3. 4. and 5 must also protect against:

a. Inadvertent boron dilution:

b. An uncontrolled CEA withdrawal from a subcritical condition:

c. Startup of an inactive reactor coolant pump (RCP): and

d. CEA ejection.

Each of these is discussed below.

In the inadvertent boron dilution analysis, the amount of reactivity by which the reactor is subcritical is determined by the reactivity difference between an initial subcritical boron concentration and the corresponding critical boron concentration. The initial subcritical boron concentration assumed in the analysis corresponds to the minimum SDM requirements. These two values (initial and critical boron concentrations), in conjunction with the configuration of the Reactor Coolant System (RCS) and the assumed dilution flow rate, directly affect the results of the analysis. For this reason the event is most limiting at the beginning of core life when critical boron concentrations are highest.

The withdrawal of CEAs from subcritical conditions adds reactivity to the reactor core, causing both the core power level and heat flux to increase with corresponding increases in reactor coolant temperatures and pressure. The withdrawal of CEAs also produces a time dependent redistribution of core power.

The uncontrolled CEA withdrawal transient is terminated by a high power level trip. Power level, RCS pressure, peak fuel centerline temperature, and the DNBR do not exceed allowable limits.

(continued)

PALO VERDE UNITS 1.2.3 B 3.1.2-3 REVISION 31

SDM - Reactor Trip Breakers Closed B 3.1.2 BASES (continued)

APPLICABLE The startup of an inactive RCP will not result in a SAFETY ANALYSES "cold water" criticality, even if the maximum difference in (continued) temperature exists between the SG and the core. Although this event was considered in establishing the requirements for SDM. it is not the limiting event with respect to the specification limits.

In the analysis of the CEA ejection event. SDM alone cannot prevent reactor criticality following a CEA ejection. At temperatures less than 500 F, the KN-I requirement ensures the reactor remains subcritical and, therefore. satisfies the radially averaged enthalpy acceptance criterion considering power redistribution effects. Above 500 F.

Doppler reactivity feedback is sufficient to preclude the need for a specific KN-i requirement.

The function of SHUTDOWN MARGIN is to ensure that the reactor remains subcritical following a design basis accident or anticipated operational occurrence. During operation in MODES 1 and 2, with keff greater than or equal to 1.0. the transient insertion limits of Specification 3.1.3.6 ensure that sufficient SHUTDOWN MARGIN is available.

SHUTDOWN MARGIN is the amount by which the core is subcritical, or would be subcritical immediately following a reactor trip, considering a single malfunction resulting in the highest worth CEA failing to insert. With any full strength CEAs not capable of being fully inserted, the withdrawn reactivity worth of the CEAs must be accounted for in the determination of SDM.

SHUTDOWN MARGIN requirements vary throughout the core life as a function of fuel depletion and reactor coolant system (RCS) cold leg temperature (TCOld). The most restrictive condition occurs at EOL. with TCold at no-load operating temperature, and is associated with a postulated steam line break accident and the resulting uncontrolled RCS cooldown.

In the analysis of this accident, the specified SHUTDOWN MARGIN is required to control the reactivity transient and ensure that the fuel performance and offsite dose criteria are satisfied.

(continued)

PALO VERDE UNITS 1.2.3 B 3.1.2-4 REVISION 28

MTC B 3.1.4 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.4 Moderator Temperature Coefficient (MTC)

BASES BACKGROUND According to GDC 11 (Ref. 1), the reactor core and its interaction with the Reactor Coolant System (RCS) must be designed for inherently stable power operation, even in the possible event of an accident. In particular, the net reactivity feedback in the system must compensate for any unintended reactivity increases.

The MTC relates a change in core reactivity to a change in reactor coolant temperature. A positive MTC means that reactivity increases with increasing moderator temperature:

conversely. a negative MTC means that reactivity decreases with increasing moderator temperature. The reactor is designed to operate with a negative MTC over the largest possible range of fuel cycle operation. Therefore, a coolant temperature increase will cause a reactivity decrease, so that the coolant temperature tends to return toward its initial value. Reactivity increases that cause a coolant temperature increase will thus be self limiting, and stable power operation will result. The same characteristic is true when the MTC is positive and coolant temperature decreases occur.

MTC values are predicted at selected burnups and temperatures during the safety evaluation analysis and are confirmed to be acceptable by measurements. Both initial and reload cores are designed so that the beginning of cycle (BOC) MTC is less positive than that allowed by the LCO.

The actual value of the MTC is dependent on core characteristics such as fuel loading and reactor coolant soluble boron concentration. The core design may require additional burnable absorbers, either fixed lumped poison rods or poisons distributed within selected fuel rods to yield an MTC at the BOC within the range analyzed in the plant accident analysis. The end of cycle (EOC) MTC is also imited by the requirements of the accident analysis. Fuel cycles that are designed to achieve high burnups or that have changes to other characteristics are evaluated to ensure that the MTC does not exceed the EOC limit.

(continued)

PALO VERDE UNITS 1,2.3 B 3.1.4-1 REVISION 0

MTC B 3.1.4 BASES (continued)

APPLICABLE The acceptance criteria for the specified MTC are:

SAFETY ANALYSES

a. The MTC values must remain within the bounds of those used in the accident analysis (Ref. 2): and

b. The MTC must be such that inherently stable power operations result during normal operation and during accidents, such as overheating and overcooling events.

Reference 2 contains analyses of accidents that result in both overheating and overcooling of the reactor core. MTC is one of the controlling parameters for core reactivity in these accidents. Both the most positive value and most negative value of the MTC are important to safety, and both values must be bounded. Values used in the analyses consider worst case conditions, such as very large soluble boron concentrations, to ensure the accident results are bounding.

Accidents that cause core overheating, either by decreased heat removal or increased power production, must be evaluated for results when the MTC is positive. Reactivity accidents that cause increased power production include the contro.l element assembly (CEA) withdrawal transient from either subcritical or full THERMAL POWER. The limiting overheating event relative to plant response is based on the Loss of Condenser Vacuum event (Ref. 3). The most limiting event with respect to a positive MTC is a CEA withdrawal accident from a subcritical or low (hot zero) power condition, also referred to as a startup accident (Ref. 4).

Accidents that cause core overcooling must be evaluated for results when the MTC is most negative. The event that produces the most rapid cooldown of the RCS, and is therefore the most limiting event with respect to the negative MTC, is a steam line break (SLB) event. Following the reactor trip for the postulated EOC SLB event, the large moderator temperature reduction combined with the large negative MTC may produce reactivity increases that are as much as the shutdown reactivity. When this occurs, a substantial fraction of core power is produced with all CEAs inserted, except the most reactive one, which is assumed withdrawn. Even if the reactivity increase produces slightly subcritical conditions, a large fraction of core power may be produced through the effects of subcritical neutron multiplication.

(continued)

PALO VERDE UNITS 1,2,3 B 3.1.4-2 REVISION 31

DNBR B 3.2.4 BASES . ., ..-7 LCO With the COLSS out of service, the limitation on DNBR as a (After CPC function of the ASI represents a conservative envelope of Upgrade) operating conditions consistent with the analysis (continued) assumptions that have been analytically demonstrated adequate to maintain an acceptable minimum DNBR for all AOOs. Operation of the core with a DNBR at or above this limit ensures that an acceptable minimum DNBR is maintained in the event of the most limiting AOO (i.e., loss of flow transient. CEA misoperation events, or asymmetric SG transient).

APPLICABILITY Power distribution is a concern any time the reactor is critical. The power distribution LCOs. however, are only applicable in MODE 1 above 20% RTP. The reasons these LCOs are not applicable below 20% RTP are:

a. The incore neutron detectors that provide input to the COLSS, which then calculates the operating limits, are inaccurate due to the poor signal to noise ratio that they experience at relatively low core power levels.

b. As a result of this inaccuracy. the CPCs assume a minimum core power of 20% RTP when generating the Local Power Density (LPD) and DNBR trip signals. When the core power is below this level, the core is operating well below the thermal limits and the resultant CPC calculated LPD and DNBR trips are highly conservative.

The upgraded CPC system consists of eight total CEACs instead of the two found in the CPC System prior to upgrade.

To facilitate the difference in the number of CEACs as well I as to support the enhanced features found in the upgraded CPC system, a second 3.2.4 Technical Specification has been developed. The determination on which Specification applies in based on whether or not the unit has received the upgraded CPCs. Each unit shall only use the Specification that reflects the status of their unit's CPC system (i.e..

before or after CPC upgrade). I (continued)

PALO VERDE UNITS 1,2,3 B 3.2.4-7 REVISION 27

DNBR B 3.2.4 BASES ACTIONS A.1 Operating at or above the minimum required value of the DNBR ensures that an acceptable minimum DNBR is maintained in the event of a postulated AOO. If the core power as calculated by the COLSS exceeds the core power limit calculated by the COLSS based on the DNBR. fuel design limits may not be maintained following an AOO and prompt action must be taken to restore the DNBR above its minimum Allowable Value. With the COLSS in service. 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is a reasonable time for the operator to initiate corrective actions to restore the DNBR above its specified limit, because of the low probability of a severe transient occurring in this relatively short time.

B.1. B.2.1. and B.2.2 If the COLSS is not available the OPERABLE DNBR channels are monitored to ensure that the DNBR is not exceeded.

Maintaining the DNBR within this specified range ensures that no postulated accident results in consequences more severe than those described in the UFSAR. Chapter 15. A 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Frequency is allowed to restore the DNBR limit to within the region of acceptable operation. This Frequency is reasonable because the COLSS allows the plant to operate with less DNBR margin (closer to the DNBR limit) than when monitoring with the CPCs.

When operating with the COLSS out of service and DNBR outside the region of acceptable operation. there is a possibility of a slow undetectable transient that degrades the DNBR slowly over the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> period and is then followed by an anticipated operational occurrence or an accident. To remedy this. the CPC calculated values of DNBR are monitored every 15 minutes when the COLSS is out of service and DNBR outside the region of acceptable operation. The 15 minute frequency is adequate to allow the operator to identify an adverse trend in conditions that could result in an approach to the DNBR limit. Also, a maximum allowable change in the CPC calculated DNBR ensures that further degradation requires the operators to take immediate action to restore DNBR to within limits or reduce reactor power to comply with the Technical Specifications (TS). With an adverse trend, 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is allowed for restoring DNBR to within limits if the COLSS is not restored to OPERABLE status. Implementation of this requirement ensures that reductions in core thermal margin are quickly detected and. if necessary, results in a (continued)

PALO VERDE UNITS 1.2.3 B 3.2.4-8 REVISION 31

DNBR B 3.2.4 BASES ACTIONS B.1. B.2. and B.2.2 (continued)

(continued) decrease in reactor power and subsequent compliance with the existing COLSS out of service TS limits. If DNBR cannot be monitored every 15 minutes. assume that there is an adverse trend.

With no adverse trend. 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is allowed for restoring the DNBR to within limits if the COLSS is not restored to OPERABLE status. This duration is reasonable because the Frequency of the CPC determination of DNBR has been increased, and, if operation is maintained steady. the likelihood of exceeding the DNBR limit during this period is not increased. The likelihood of induced reactor transients from an early power reduction is also decreased.

C.1 If the DNBR cannot be restored or determined within the allowed times of Conditions A and B. core power must be reduced. Reduction of core power to < 20% RTP ensures that the core is operating within its thermal limits and places the core in a conservative condition based on trip setpoints generated by the CPCs. which assume a minimum core power of 20% RTP.

The allowed Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience. to reach 20% RTP from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.4.1 REQUIREMENTS With the COLSS out of service. the operator must monitor the DNBR as indicated on all of the OPERABLE DNBR channels of the CPCs to verify that the DNBR is within the specified limits shown in the COLR. A 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Frequency is adequate to allow the operator to identify trends in conditions that would result in an approach to the DNBR limit.

(continued)

PALO VERDE UNITS 1.2.3 B 3.2.4-9 REVISION 31

DNBR B 3.2.4 BASES SURVEILLANCE SR 3.2.4.1 (continued)

REQUIREMENTS This SR is modified by a Note that states that the SR is only applicable when the COLSS is out of service.

Continuous monitoring of the DNBR is provided by the COLSS.

which calculates core power and core power operating limits based on the DNBR and continuously displays these limits to the operator. A COLSS margin alarm is annunciated in the event that the THERMAL POWER exceeds the core power operating limit based on the DNBR. This SR is also modified by a Note that states that the SR is not required to be performed until 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after MODE 1 with THERMAL POWER >

20% RTP. During plant startup (increase from 15-18% RTP),

the plant dynamics associated with the downcomer to economizer swapover may result in a temporary power increase above 20% RTP. The 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after reaching 20% RTP is required for plant stabilization.

SR 3.2.4.2 Verification that the COLSS margin alarm actuates at a power level equal to or less than the core power operating limit.

as calculated by the COLSS. based on the DNBR. ensures that the operator is alerted when operating conditions approach the DNBR operating limit. The 31 day Frequency for performance of this SR is consistent with the historical testing frequency of reactor protection and monitoring systems. The Surveillance Frequency for testing protection systems was extended to 92 days by CEN 327. Monitoring systems were not addressed in CEN 327: therefore. this Frequency remains at 31 days.

REFERENCES 1. UFSAR. Chapter 15.

2. UFSAR. Chapter 6.

3. CE-1 Correlation for DNBR.

4. 10 CFR 50, Appendix A, GDC 10.

5. 10 CFR 50.46.

6. Regulatory Guide 1.77, Rev. 0. May 1974.

7. 10 CFR 50, Appendix A. GDC 26.

PALO VERDE UNITS 1.2.3 B 3.2.4-10 REVISION 31

RPS Logic and Trip Initiation B 3.3.4 BASES BACKGROUND Reactor Trip Circuit Breakers (RTCBs) (continued)

Each RTCB is operated by either a Manual Trip push button, a Supplementary Protection System (SPS) Trip relay, or an RPS actuated Initiation relay. There are four Manual Trip push buttons, each of the pushbuttons operates one of the RTCBs.

Depressing either of the push buttons in both trip legs will result in a reactor trip.

When a Manual Trip is initiated using the control room push buttons, the RPS trip paths and Initiation relays are not utilized and the RTCB undervoltage and shunt trip attachments are actuated independent of the RPS.

Manual Trip circuitry includes the push button and interconnecting wiring to the RTCBs necessary to actuate both the undervoltage and shunt trip attachments, but excludes the Initiation relay contacts and their interconnecting wiring to the RTCBs, which are considered part of the Initiation Logic.

Functional testing of the entire RPS, from bistable input through the opening of the individual RTCBs, can be performed either at power or shutdown and is normally performed on a quarterly basis. UFSAR, Section 7.2 (Ref. 3). explains RPS testing in more detail.

APPLICABLE Reactor Protective System (RPS) Logic SAFETY ANALYSES The RPS Logic provides for automatic trip initiation to maintain the SLs during AOOs and assist the ESF systems in ensuring acceptable consequences during accidents. All transients and accidents that call for a reactor trip assume the RPS Logic is functioning as designed.

Reactor Trip Circuit Breakers (RTCBs)

All of the transient and accident analyses that call for a reactor trip assume that the RTCBs operate and interrupt power to the CEDMs.

(continued)

PALO VERDE UNITS 1.2.3 B 3.3.4-5 REVISION 0

RPS Logic and Trip Initiation B 3.3.4 BASES -S.

APPLICABLE Manual Trip SAFETY ANALYSES (continued) The Manual Trip is part of the RPS circuitry and can be used by the operator to perform a controlled reactor shutdown. It is also used by the operator to shut down the reactor whenever any parameter is rapidly trending toward its trip setpoint. A Manual Trip accomplishes the same results as any one of the automatic trip Functions.

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

LCO Reactor Protective System (RPS) Logic The LCO on the RPS Logic channels ensures that each of the following requirements are met:

A reactor trip will be initiated when necessary:

• The required protection system coincidence logic is maintained (minimum two-out-of-three, normal two-out-of-four): and

• Sufficient redundancy is maintained to permit a channel to be out of.service for testing or maintenance.

Failures of individual bistable relays and their contacts, are addressed in LCO 3.3.1. This Specification addresses failures of the Matrix Logic not addressed in the above.

such as the failure of matrix relay power supplies, or the failure of the trip channel bypass contact in the bypass condition.

A matrix logic is considered inoperable if a coincident trip in the same function in the two OPERABLE channels monitored by the Logic Matrix will not remove power from the coils of all four matrix relays. The OPERABILITY of the Matrix Logic is not affected by bypassed or inoperable measurement channels.

(continued)

PALO VERDE UNITS 1.2.3 B 3.3.4-6 REVISION 31

ESFAS Instrumentation B 3.3.5 BASES BACKGROUND ESFAS Logic (continued) of the Matrix Logic. Trip channel bypassing a bistable effectively shorts the bistable relay contacts in the three matrices associated with that channel.

Thus, the bistables will function normally, producing normal trip indication and annunciation, but ESFAS actuation will not occur since the bypassed channel is effectively removed from the coincidence logic. Trip channel bypassing can be simultaneously performed on any number of parameters in any number of channels, providing each parameter is bypassed in only one channel at a time. An interlock prevents simultaneous trip channel bypassing of the same parameter in more than one channel. Trip channel bypassing is normally employed during maintenance or testing.

In addition to the trip channel bypasses, there are also operating bypasses on select ESFAS actuation trips. These bypasses are enabled manually in all four channels when plant conditions do not warrant the specific trip protection. All operating bypasses are automatically removed when enabling bypass conditions are no longer satisfied. Operating bypasses normally are implemented in the bistable. so that normal trip indication is also disabled. The Pressurizer Pressure - Low input to the SIAS shares an operating bypass with the Pressurizer Pressure - Low reactor trip.

Manual ESFAS initiation capability is provided to permit the operator to manually actuate an ESF System when necessary.

Four handswitches (located in the control room) for each ESF Function are provided. and each handswitch actuates both trains. Each Manual Trip handswitch opens one trip path.

de-energizing one set of two initiation relays, one affecting each train of ESF. Initiation relay contacts are arranged in a selective two-out-of-four configuration in the Actuation Logic. Operating either handswitch in both trip legs will result in an ESFAS Actuation. This arrangement ensures that Manual actuation will not be prevented in the event of a single random failure. Each handswitch is designated a single channel in LCO 3.3.6.

(continued)

PALO VERDE UNITS 1.2.3 B 3.3.5-7 REVISION 0

ESFAS Instrumentation B 3.3.5 BASES APPLICABLE Each of the analyzed accidents can be detected by one or SAFETY ANALYSES more ESFAS Functions. One of the ESFAS Functions is the primary actuation signal for that accident.

An ESFAS Function may be the primary actuation signal for more than one type of accident. An ESFAS Function may also be the secondary, or backup, actuation signal for one or more other accidents.

ESFAS protective Functions are as follows:

1. Safety Injection Actuation Signal SIAS ensures acceptable consequences during large break loss of coolant accidents (LOCAs). small break LOCAs, control element assembly ejection accidents, steam generator tube ruptures, and main steam line breaks (MSLBs) inside containment. To provide the required protection, either a high containment pressure or a low pressurizer pressure signal will initiate SIAS. SIAS initiates the Emergency Core Cooling Systems (ECCS) and performs several other functions such as initiating control room filtration.

and starting the diesel generators.

2. Containment Spray Actuation Signal CSAS actuates containment spray. preventing containment overpressurization during large break LOCAs. small break LOCAs. and MSLBs or feedwater line breaks (FWLBs) inside containment. CSAS is initiated by high high containment pressure.

3. Containment Isolation Actuation Signal CIAS ensures acceptable mitigating actions during large and small break LOCAs, and MSLBs either inside or outside containment, and FWLBs inside containment.

CIAS is initiated by low pressurizer pressure or high containment pressure.

4. Main Steam Isolation Signal MSIS ensures acceptable consequences during an MSLB or FWLB (between the steam generator and the main feedwater check valve), either inside or outside containment. MSIS isolates both steam generators if either generator indicates a low pressure condition, a (continued)

PALO VERDE UNITS 1.2,3 B 3.3.5-8 REVISION 31

ESFAS Logic and Manual Trip B 3.3.6 BASES APPLICABLE Each of the analyzed accidents can be detected by one or SAFETY ANALYSES more ESFAS Functions. One of the ESFAS Functions is the primary actuation signal for that accident. An ESFAS Function may be the primary actuation signal for more than one type of accident. An ESFAS Function may also be a secondary, or backup, actuation signal for one or more other accidents.

ESFAS Functions are as follows:

1. Safety Injection Actuation Signal SIAS ensures acceptable consequences during large break loss of coolant accidents (LOCAs), small break LOCAs, control element assembly ejection accidents, steam generator tube ruptures, and main steam line breaks (MSLBs) inside containment. To provide the required protection, either a high containment pressure or a low pressurizer pressure signal will initiate SIAS. SIAS initiates the Emergency Core Cooling Systems (ECCS) and performs several other Functions.

such as initiating control room filtration and starting the diesel generators.

2. Containment Isolation Actuation Signal CIAS ensures acceptable mitigating actions during large and small break LOCAs and during MSLBs either inside or outside containment and feedwater line breaks (FWLBs) inside containment. CIAS is initiated by low pressurizer pressure or high containment pressure.

3. Recirculation Actuation Signal At the end of the injection phase of a LOCA. the Refueling Water Tank (RWT) will be nearly empty.

Continued cooling must be provided by the ECCS to remove decay heat. The source of water for the ECCS pumps is automatically switched to the containment recirculation sump. Switchover from RWT to containment sump must occur before the RWT empties to prevent damage to the ECCS pumps and a loss of core cooling capability. For similar reasons, switchover must not occur before there is sufficient water in the containment sump to support pump suction.

(continued)

PALO VERDE UNITS 1.2.3 B 3.3.6-5 REVISION 31

ESFAS Logic and Manual Trip B 3.3.6 BASES APPLICABLE 3. Recirculation Actuation Signal (continued)

SAFETY ANALYSES Furthermore, early switchover must not occur to ensure sufficient borated water is injected from the RWT to ensure the reactor remains shut down in the recirculation mode. An RWT Level - Low signal initiates the RAS.

4. Containment Spray Actuation Signal CSAS actuates containment spray. preventing containment overpressurization during large break LOCAs. small break LOCAs, and MSLBs or FWLBs inside containment. CSAS is initiated by high high containment pressure.

5. Main Steam Isolation Signal MSIS ensures acceptable consequences during an MSLB or FWLB (between the steam generator and the main feedwater check valve) either inside or outside containment. MSIS isolates both steam generators if either generator indicates a low pressure condition or a high level condition or if a high containment pressure condition exists. This prevents an excessive rate of heat extraction and subsequent cooldown of the RCS during these events.

6. 7. Auxiliary Feedwater Actuation Signal AFAS consists of two Steam Generator (SG) specific signals AFAS-1 and AFAS-2. AFAS-1 initiates auxiliary feed to SG #1. and AFAS-2 initiates auxiliary feed to SG #2.

AFAS maintains a steam generator heat sink during a steam generator tube rupture event and an MSLB or FWLB event either inside or outside containment.

Low steam generator water level initiates auxiliary feed to the affected steam generator, providing the generator is not identified (by the rupture detection circuitry) as faulted (an MSLB or FWLB).

(continued)

PALO VERDE UNITS 1,2.3 B 3.3.6-6 REVISION 0

Pressurizer B 3.4.9 B 3.4 REACTOR COOLANT SYSTEMS (RCS)

B.3.4.9 Pressurizer BASES BACKGROUND The pressurizer provides a point in the RCS where liquid and vapor are maintained in equilibrium under saturated conditions for pressure control purposes to prevent bulk boiling in the remainder of the RCS. Key functions include maintaining required primary system pressure during steady state operation and limiting the pressure changes caused by reactor coolant thermal expansion and contraction during normal load transients.

The pressure control components addressed by this LCO include the pressurizer water level, the required heaters and their backup heater controls, and emergency power supplies. Pressurizer safety valves and pressurizer vents are addressed by LCO 3.4.10 "Pressurizer Safety Valves-MODES 1.2. and 3," LCO 3.4.11 "Pressurizer Safety Valves-MODE 4,"

and LCO 3.4.12 "Pressurizer Vents", respectively.

The maximum steady state water level limit has been established to ensure that a liquid to vapor interface exists to permit RCS pressure control, using the sprays and heaters during normal operation and proper pressure response for anticipated design basis transients. The maximum and minimum steady state water level limit serves two purposes:

a. Pressure control during normal operation maintains subcooled reactor coolant inthe loops and thus inthe preferred state for heat transport: and

b. By restricting the level to a maximum, expected transient reactor coolant volume increases (pressurizer insurge) will not cause excessive level changes that could result indegraded ability for pressure control.

The maximum steady state water level limit permits pressure control equipment to function as designed. The limit greserves the steam space during normal operation, thus, both sprays and heaters can operate to maintain the design operating pressure. The level limit also prevents filling the pressurizer (water solid) for anticipated design basis transients, thus ensuring that pressure relief devices (continued)

PALO VERDE UNITS 1.2,3 B 3.4.9-1 REVISION 0

Pressurizer B 3.4.9 BASES BACKGROUND (pressurizer safety valves) can control pressure by (continued) steam relief rather than water relief. Ifthe level limits were exceeded prior to a transient that creates a large pressurizer insurge volume leading to water relief, the maximum RCS pressure might exceed the Safety Limit of 2750 psia.

The minimum steady state water level in the pressurizer assures pressurizer heaters, which are required to achieve and maintain pressure control, remain covered with water to prevent failure, which could occur if the heaters were energized uncovered.

The requirement to have two groups of pressurizer heaters ensures that RCS pressure can be maintained. The pressurizer heaters maintain RCS pressure to keep the reactor coolant subcooled. Inability to control RCS pressure during natural circulation flow could result in 0oss of single phase flow and decreased capability to remove core decay heat.

APPLICABLE In MODES 1. 2. and 3. the LCO requirement for a steam bubble SAFETY ANALYSES is reflected implicitly in the accident analyses. No safety analyses are performed in lower MODES. All analyses performed from a critical reactor condition assume the existence of a steam bubble and saturated conditions in the pressurizer. In making this assumption, the analyses neglect the small fraction of noncondensable gases normally present.

An implicit initial condition assumption of the Safety Analyses is that the RCS is operating at normal pressure.

The individual UFSAR Accident Analysis Sections must be reviewed to determine the assumed pressurizer heater operation during the transient. Steam generator tube rupture, for example, credits pressurizer class backup heaters to maintain adequate subcooling margin.

(continued)

PALO VERDE UNITS 1.2.3 B 3.4.9-2 REVISION 31

Pressurizer B 3.4.9 BASES APPLICABLE The Class lE pressurizer backup heaters are needed SAFETY ANALYSES to maintain subcooling in the long term during loss of (continued) offsite power. as indicated in NUREG-0737 (Ref. 1). The requirement for emergency power supplies is based on NUREG-0737 (Ref. 1). The intent is to keep the reactor coolant in a subcooled condition with natural circulation at hot, high pressure conditions for an undefined, but extended. time period after a loss of offsite power. While loss of offsite power is a coincident occurrence assumed in the accident analyses, maintaining hot, high pressure conditions over an extended time period is not evaluated in the accident analyses. The pressurizer satisfies Criterion 2 and Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requirement for the pressurizer to be OPERABLE with water level 2 27% indicated level (425 cubic feet) and < 56%

indicated level (948 cubic feet) ensures that a steam bubble exists. Limiting the maximum operating water level reserves the steam space for ressure control. The LCO has been established to minimize the consequences of potential overpressure transients. Requiring the-presence of a steam bubble is also consistent with analytical assumptions.

The LCO requires two groups of OPERABLE pressurizer heaters, each with a capacity t 125 kW and capable of being powered from an emergency power supply. The minimum heater capacity required is sufficient to maintain the RCS near normal operating pressure when accounting for heat losses through kjthe pressurizer insulation. By maintaining the pressure near the operating conditions, a wide subcooling margin to saturation can be obtained in the loops.

APPLICABILITY The need for pressure control is most pertinent when core heat can cause the greatest effect on RCS temperature resulting in the greatest effect on pressurizer level and RCS pressure control. Thus. Applicability has been designated for MODES 1 and 2. The Applicability is also provided for MODE 3. It is assumed pressurizer level is under steady state conditions. The purpose is to prevent solid water RCS operation during heatup and cooldown to avoid rapid pressure rises caused by normal operational (continued)

PALO VERDE UNITS 1.2.3 B 3.4.9-3 REVISION 31

Pressurizer B 3.4.9 BASES APPLICABILITY perturbation, such as reactor coolant pump startup. The (continued) LCO does not apply to MODE 5 (Loops Filled) because LCO 3.4.13. "Low Terperature Overpressure Protection (LTOP)

System," applies. The LCO does not apply to MODES 5 and 6 with partial loop operation. Also, a Note has been added to indicate the limit on pressurizer level may be exceeded during short term operational transients such as a THERMAL POWER ramp increase of > 5% RTP per minute or a THERMAL POWER step increase of > 10% RTP.

In MODES 1. 2, and 3. there is the need to maintain the availability of pressurizer heaters capable of being powered from an emergency power supply. In the event of a loss of offsite power, the initial conditions of these MODES gives the greatest demand for maintaining the RCS in a hot pressurized condition with loop subcooling for an extended period. For MODES 4. 5. or 6. it is not necessary to control pressure (by heaters) to ensure loop subcooling for heat transfer when the Shutdown Cooling System is in service and therefore the LCO is not applicable.

ACTIONS A.1 and A.2 With pressurizer water level not within the limit. action must be taken to restore the plant to operation within the bounds of the safety analyses. To achieve this status, the unit must be brought to MODE 3, with the reactor trip breakers open. within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to MODE 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

This takes the plant out of the applicable MODES and restores the plant to operation within the bounds of the safety analyses.

Six hours is reasonable, based on operating experience. to reach MODE 3 from full power in an orderly manner and without challenging plant systems. Further pressure and temperature reduction to MODE 4 brings the plant to a MODE where the LCO is not applicable. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time to reach the nonapplicable MODE is reasonable based on operating experience for that evolution.

(continued)

PALO VERDE UNITS 1.2.3 IB3.4.9-4 REVISION 0

Pressurizer Vents B 3.4.12 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.12 Pressurizer Vents BASES BACKGROUND The pressurizer vent is part of the reactor coolant gas vent system (RCGVS) as described in UFSAR 18.II.B.1 (Ref. 1). The pressurizer can be vented remotely from the control room through the following four paths (see UFSAR Figure 18.II.B-1):

1. From the pressurizer vent through SOV HV-103, then through SOV HV-105 to the reactor drain tank (RDT).

2. From the pressurizer vent through SOV HV-103, then through SOV HV-106 directly to the containment atmosphere.

3. From the pressurizer vent through SOVs HV-108 and HV-109, then through SOV HV-105 to the reactor drain tank (RDT). I

4. From the pressurizer vent through SOVs HV-108 and HV-109, then through SOV HV-106 directly to the containment atmosphere.

The RCGVS also includes the reactor head vent, which can be used along with the pressurizer vent to remotely vent gases that could inhibit natural circulation core cooling during post accident situations. However, this function does not meet the criteria of 10 CFR 50.36(c)(2)(ii) to require a Technical Specification LCO, and therefore the reactor head vent is not included in these Technical Specifications.

(continued)

PALO VERDE UNITS 1,2.3 B 3.4.12-1 REVISION 1

Pressurizer Vents B 3.4.12 BASES APPLICABLE The requirement for pressurizer path vent path to be SAFETY ANALYSES OPERABLE is based on the steam generator tube rupture (SGTR) with loss of offsite power (SGTRLOP) and SGTR with loss of offsite power and single failure (SGTRLOPSF) analysis. as described in UFSAR 15.6.3 (Ref. 4). It is assumed that the auxiliary pressurizer spray system (APSS) is not available for this event. Instead. RCS depressurization is performed by venting the RCS via a pressurizer vent path and throttling HPSI flow. The analysis assumes venting to the containment atmosphere via path 4 as described below.

The results of the CENTS based analysis for steam generator tube rupture with loss of offsite power and steam generator tube rupture and single failure, forwarded to the NRC in Reference 2 states that the auxiliary spray was assumed to be unavailable and use of pressurizer head vents was credited for de-pressurization. The staff has reviewed and accepted the results of the analysis. The staff's detailed evaluation has been reported in Amendment No. 149, which increases power to 3990 MWt for Unit 2 and incorporates replacement steam generator (Ref. 3).

The pressurizer vent paths satisfy Criterion 3 of 10 CFR 50.36 (c)(2)(ii).

LCO The LCO requires four pressurizer vent paths be OPERABLE.

The four vent paths are:

1. From the pressurizer vent through SOV HV-103, then through SOV HV-105 to the reactor drain tank (RDT).

2. From the pressurizer vent through SOV HV-103, then through SOV HV-106 directly to the containment atmosphere.

3. From the pressurizer vent through SOVs HV-108 and HV-109, then through SOV HV-105 to the reactor drain tank (RDT).

4. From the pressurizer vent through SOVs HV-108 and HV-109. then through SOV HV-106 directly to the containment atmosphere.

(continued)

PALO VERDE UNITS 1.2.3 B 3.4.12-2 REVISION 31

Pressurizer Vents B 3.4.12 BASES REFERENCES 1. UFSAR, Section 18.

2. "Palo Verde Nuclear Generating Station (PVNGS) Unit 2 Docket No. STN 50-529 Request for a License Amendment to Support Replacement of Steam Generators and Uprated Power Operations," Letter 102-046141-CDM/RAB. C, D.

Mauldin (APS) to the NRC, December 21, 2001.

3. "Palo Verde Nuclear Generating Station, Unit 2 (PVNGS-

2) - Issuance of Amendment on Replacement of Steam Generators and Uprated Power Operations (TAC NO.

MB3696", B.M. Pham (NRC) to G. R. Overbeck (APS).

September 29, 2003.

4. UFSAR, Section 15.

PALO VERDE UNITS 1,2,3 B 3.4.12-5 REVISION 31

This page intentionally left blank 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 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).

LCO This LCO requires that the MSIV 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. The MSIVs have redundant actuator trains. An MSIV is OPERABLE with one train of hydraulics unavailable to shut the valve. Only one OPERABLE MSIV is allowed to have an unavailable hydraulic train.

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 31

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 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 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 <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 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 <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time is consistent with that normally allowed for containment isolation valves that isolate a closed system penetrating 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 0

ADVs B 3.7.4 B 3.7 PLANT SYSTEMS B 3.7.4 Atmospheric Dump Valves (ADVs)

BASES BACKGROUND The ADVs provide a safety grade method for cooling the unit to Shutdown Cooling (SDC) System entry conditions, should the preferred heat sink via the Steam Bypass Control System to the condenser not be available, as discussed in the FSAR, Section 10.3 (Ref. 1). This is done in conjunction with the Auxiliary Feedwater System providing cooling water from the Condensate Storage Tank (CST). The ADVs may also be required to meet the design cooldown rate during a normal cooldown.

Four ADV lines are provided. Each ADV line consists of one ADV and an associated block valve. One ADV line per steam generator is required to meet the assumptions in the safety analyses. The ADV block valves are not required to be closed in the event of a stuck open ADV.

The ADVs are equipped with pneumatic controllers to permit control of the cooldown rate.

The ADVs are provided with a pressurized gas supply of bottled nitrogen that. on a loss of pressure in the normal instrument air supply, automatically supplies nitrogen to operate the ADVs. The nitrogen supply is sized to provide sufficient pressurized gas to operate the ADVs for the time required for RCS cooldown to the SDC System entry conditions.

A description of the ADVs is found in Reference 1. The ADVs require both DC sources and class AC instrument power to be considered OPERABLE. In addition. hand wheels are provided for local manual operation.

(continued)

PALO VERDE UNITS 1.2.3 B 3.7.4-1 REVISION 0

ADVs B 3.7.4 BASES APPLICABLE The design basis of the ADVs is established by the SAFETY ANALYSES capability to cool the unit to SDC System entry conditions.

A cooldown rate of 750 F per hour is obtainable by one or both steam generators. This design is adequate to cool the unit to SDC System entry conditions with only one ADV and one steam generator, utilizing the cooling water supply available in the CST.

In the accident analysis presented in the UFSAR, the ADVs are assumed to be used by the operator to cool down the unit to SDC System entry conditions for accidents accompanied by a loss of offsite power. Prior to the operator action, the Main Steam Safety Valves (MSSVs) are used to maintain steam generator pressure and temperature at the MSSV setpoint. This is typically 30 minutes following the initiation of an event.

(This is less for Steam Generator Tube Rupture (SGTR) events as detailed below). The limiting events are those that render one steam generator unavailable for RCS heat removal, with a coincident loss of offsite power: this results from a turbine trip. Typical initiating events falling into this category are a main steam line break upstream of the main steam isolation valves. and a feedwater line break. For the SGTR and SGTRLOP events. ADV's are assumed to be opened two minutes post trip to prevent cycling of Main Steam Safety Valves (MSSVs) and they remain open until the affected SG is isolated. From then on.

the ADVs on the unaffected SG is used till shutdown cooling entry conditions are reached.

The Steam Generator with a Loss of Offsite Power and a Single Failure (SGTRLOPSF) event. assumes an ADV on the affected SG sticks open 2 minutes post trip for the duration. The credited operator action of directing auxiliary feedwater to the affected SG keeps the tubes covered. Thus the majority of the heat removal during this event is conducted through the affected SG ADV.

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

LCO One ADV line is required to be OPERABLE on each steam generator to conduct a unit cooldown following an event in which one steam generator becomes unavailable. Failure to meet the LCO can result in the inability to cool the unit to SDC System entry conditions following an event in which the condenser is unavailable for use with the Steam Bypass Control System.

(continued)

PALO VERDE UNITS 1,2.3 B 3.7.4-2 REVISION 31

ADVs B 3.7.4 BASES .. I. .

LOC An ADV is considered OPERABLE when it is capable of (continued) providing a controlled relief of the main steam flow, and is capable of fully opening and closing on demand.

APPLICABILITY In MODES 1, 2. and 3. and in MODE 4. when steam generator is being relied upon for heat removal, the ADVs are required to be OPERABLE.

In MODES 5 and 6. an SGTR is not a credible event.

ACTIONS A.1 Required Action A.1 is modified by a Note indicating that LCO 3.0.4 does not apply.

With one required ADV line inoperable, action must be taken to restore the OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the availability of a nonsafety grade backup in the Steam Bypass Control System and MSSVs.

B.1 With two required ADV lines inoperable (one in each steam generator), action must be taken to restore one of the ADV lines to OPERABLE status. As the block valve can be closed to isolate an ADV, some repairs may be possible with the unit at power. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is reasonable to repair inoperable ADV lines, based on the availability of the Steam Bypass Control System and MSSVs, and the low probability of an event occurring during this period that requires the ADV lines.

(continued)

PALO VERDE UNITS 1,2.3 B 3.7.4-3 REVISION 31

ADVs B 3.7.4 BASES ACTIONS C.1 and C.2 If the ADV lines cannot be restored to OPERABLE status 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and in MODE 4. without reliance on the steam generator for heat removal, within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The allowed Completion Times are reasonable, based on operating experience. to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.4.1 REQUIREMENTS To perform a controlled cooldown of the RCS. the ADVs must be able to be opened and throttled through their full range.

This SR ensures the ADVs are tested through a full control cycle at least once per fuel cycle. Performance of inservice testing or use of an ADV during a unit cooldown may satisfy this requirement. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 10.3.

PALO VERDE UNITS 1.2.3 B 3.7.4-4 REVISION 0

ENCLOSURE 3 PVNGS Technical Specification Bases Revision 32 Insertion Instructions and Replacement Pages

PVNGS Technical Specifications Bases Revision 32 Insertion Instructions Remove Paae: Insert New Page:

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PAM Instrumentation B 3.3.10 BASES LCO (continued)

14. 15. 16. 17. Core Exit Temperature Core Exit Temperature is provided for verification and long term surveillance of core cooling.

An evaluation was made of the minimum number of valid core exit thermocouples necessary for inadequate core cooling detection. The evaluation determined the reduced complement of core exit thermocouples necessary to detect initial core recovery and trend the ensuing core heatup. The evaluations account for core nonuniformities including incore effects of the radial decay power distribution and excore effects of condensate runback in the hot legs and nonuniform inlet temperatures.

Based on these evaluations, adequate or inadequate core cooling detection is ensured with two valid core exit thermocouples per quadrant.

The design of the Incore Instrumentation System includes a Type K (chromel alumel) thermocouple within each of the 61 incore instrument detector assemblies.

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

The core exit thermocouples have a usable temperature range from 320F to 2300 0F. although accuracy is reduced at temperatures above 1800'F.

(continued)

PALO VERDE UNITS 1.2.3 B 3.3.10-13 REVISION 14

PAM Instrumentation B 3.3.10 BASES LCO 18. Steam Generator Pressure (continued)

Steam Generator pressure indication is provided for Steam Generator pressure verification. At PVNGS Steam Generator Pressure Instrumentation consists of:

SGA-PT-1013A SGB-PT-1013B SGC-PT-1013C SGD-PT-1013D SGA-PT-1023A SGB-PT-1023B SGC-PT-1023C SGD-PT-1023D

19. Reactor Coolant System-Subcooling Margin Monitoring The RCS Subcooling Margin Monitor is a portion of the Inadequate Core Cooling (ICC) Instrumentation required by Item II.F.2 in NUREG-0737, the post-TMI Action Plan. The ICC instrumentation enhances the ability of the Operator to anticipate the approach to. and recovery from. ICC. At PVNGS RCS subcooling Margin Monitoring Instrumentation consists of:

QSPDS A QSPDS B Each channel of QSPDS processing equipment will calculate the following saturation margin parameters:

a) RCS Saturation Margin - temperature margin based on the difference between saturation temperature and the maximum RTD temperature taken from the hot and cold legs. This algorithm uses the hottest RCS temperature (Thot or Tcold) and pressurizer pressure (PT-102) to complete the calculation.

b) CET Saturation Margin - temperature margin based on the difference between the saturation temperature and the representative core exit temperature calculated from the CET's. A representative CET value is first calculated (and displayed on the B02 trend recorder) for the input temperature. This is compared to pressurizer pressure (PT-102) to complete the saturation (continued)

PALO VERDE UNITS 1,2.3 B 3.3.10-14 REVISION 32

PAM Instrumentation B 3.3.10 BASES LCO 19. Reactor Coolant System-Subcooling Margin Monitoring (continued) margin calculation. Minimum requirements for CET operability must be met before the CET Saturation Monitor can be considered operable.

c) Upper Head Saturation Margin - temperature margin based on the difference between the saturation temperature and the unheated junction thermocouples (UHJTC) temperature. This algorithm uses the hottest of the three upper unheated thermocouples from RVLMS along with pressurizer pressure (PT-102) to complete the margin calculation.

One OPERABLE Subcooling Margin Monitor Channel consists of one RCS Saturation Margin indicator and one CET Saturation margin indicator. These indicators shall be from the same channel. Additionally, for any CET Saturation monitor indicator to be considered OPERABLE, the CET's for that channel must also be operable.

20. Reactor Coolant System Activity The RCS Activity provides an indication of fuel cladding failure. This indicates degradation of the first of three barriers to fission product release to the environment. The three barriers to fission product release are (1) fuel cladding. (2) primary coolant pressure boundary, and (3) containment. At PVNGS the RCS Activity Instrumentation consists of:

SQA-RU-150 SQB-RU-151 21, 22. HPSI System Flow HPSI System flow indication is provided for HPSI flow verification.

(continued)

PALO VERDE UNITS 1.2,3 B 3.3.10-15 REVISION 32

PAM Instrumentation B 3.3.10 BASES LCO 21. 22 HPSI System Flow (continued)

HPSI System flow is a Type A variable because the operator must manually balance the HPSI flow between the hot and cold legs when switching from cold leg injection to a combined cold/hot leg injection in support of LOCA Long Term Cooling to prevent boron precipitation in stagnate core areas. Monitoring of these instruments is not required for initial operation of HPSI flow. At PVNGS. HPSI System Cold Leg Flow indication consists of:

J-SIB-FT-0311 J-SIB-FT-0321 J-SIA-FT-0331 J-SIA-FT-0341 At PVNGS. HPSI System Hot Leg Flow indication consists of:

J-SIA-FT-0390 J-SIB-FT-0391 Two channels are required to be OPERABLE for all but one Function. Two OPERABLE channels ensure that no single failure within the PAM instrumentation or its auxiliary supporting features or power sources, concurrent with failures that are a condition of or result from a specific accident. prevents the operators from being presented the information necessary for them to determine the safety status of the plant and to bring the plant to and maintain it in a safe condition following that accident.

In Table 3.3.10-1 the exception to the two channel requirement is Containment Isolation Valve Position.

Two OPERABLE channels of core exit thermocouples are required for each channel in each quadrant to provide indication of radial distribution of the coolant temperature rise across representative regions of the core. Power distribution symmetry was considered in determining the specific number and locations provided for diagnosis of local core problems. Plant specific evaluations in response to Item II.F.2 of NUREG-0737 (Ref. 3) have determined that any two thermocouple pairings per quadrant.

satisfy these requirements. Two sets of two thermocouples in each quadrant ensure a single failure will not disable the ability to determine the radial temperature gradient.

(continued)

PALO VERDE UNITS 1.2.3 B 3.3.10-16 REVISION 32

PAM Instrumentation B 3.3.10 BASES LCO For loop and steam generator related variables, the required (continued) information is individual loop temperature and individual steam generator level. In these cases two channels are required to be OPERABLE for each loop of steam generator to redundantly provide the necessary information.

In the case of Containment Isolation Valve Position. the important information is the status of the containment penetrations. The LCO requires one position indicator for each active containment isolation valve. This is sufficient to redundantly verify the isolation status of each isolable penetration either via indicated status of the active valve and prior knowledge of the passive valve or via system boundary status. If a normally active containment isolation valve is known to be closed and deactivated, position indication is not needed to determine status. Therefore, the position indication for valves in this state is not required to be OPERABLE.

APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1, 2.

and 3. These variables are related to the diagnosis and preplanned actions required to mitigate DBAs. The applicable DBAs are assumed to occur in MODES 1. 2. and 3.

In MODES 4, 5. and 6. plant conditions are such that the likelihood of an event occurring that would require PAM instrumentation is low: therefore. PAM instrumentation is not required to be OPERABLE in these MODES.

ACTIONS Note 1 has been added in the ACTIONS to exclude the MODE change restriction of LCO 3.0.4. This exception allows entry into the applicable MODE while relying on the ACTIONS. even though the ACTIONS may eventually require plant shutdown. This exception is acceptable due to the passive function of the instruments, the operator's ability to monitor an accident using alternate instruments and methods. and the low probability of an event requiring these instruments.

Note 2 has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in Table 3.3.10-1. The Completion Time(s) of the inoperable channel(s) of a Function will be tracked separately for each Function starting from the time the Condition was entered for that Function.

(continued)

PALO VERDE UNITS 1,2.3 B 3.3.10-17 REVISION 32

PAM Instrumentation B 3.3.10 BASES ACTIONS A.1 (continued)

When one or more Functions have one required channel that is inoperable, the required inoperable channel must be restored to OPERABLE status within 30 days. The 30 day Completion Time isbased on operating experience and takes into account the remaining OPERABLE channel (or inthe case of a Function that has only one required channel, other non-Regulatory Guide 1.97 instrument channels to monitor the Function). the passive nature of the instrument (no critical automatic action isassumed to occur from these instruments). and the low probability of an event requiring PAM instrumentation during this interval.

B.1 This Required Action specifies initiation of actions in accordance with Specification 5.6.6. which requires a written report to be submitted to the Nuclear Regulatory Commission. This report discusses the results of the root cause evaluation of the inoperability and identifies proposed restorative Required Actions. This Required Action isappropriate inlieu of a shutdown requirement.

given the likelihood of plant conditions that would require information provided by this instrumentation. Also.

alternative Required Actions are identified before a loss of functional capability condition occurs.

C.1 When one or more Functions have two required channels inoperable (i.e.. two channels inoperable in the same Function), one channel inthe Function should be restored to OPERABLE status within 7 days. The Completion Time of 7 days is based on the relatively low probability of an event requiring PAM instrumentation operation and the availability of alternate means to obtain the required information. Continuous operation with two required channels inoperable in a Function is not acceptable because the alternate indications may not fully meet all performance qualification requirements applied to the PAM instrumentation.

(continued)

PALO VERDE UNITS 1.2.3 B 3.3.10-18 REVISION 32

PAM Instrumentation B 3.3.10 BASES ACTIONS C.1 (continued)

Therefore, requiring restoration of one inoperable channel of the Function limits the risk that the PAM Function will be in a degraded condition should an accident occur.

D.1 When two required hydrogen monitor channels are inoperable.

Required Action D.1 requires one channel to be restored to OPERABLE status. This Required Action restores the monitoring capability of the hydrogen monitor. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is based on the relatively low probability of an event requiring hydrogen monitoring and the availability of alternative means to obtain the required information. Continuous operation with two required channels inoperable is not acceptable because alternate indications are not available.

E.1 This Required Action directs entry into the appropriate Condition referenced in Table 3.3.10-1. The applicable Condition referenced in the Table is Function dependent.

Each time Required Action C.1 or D.1 is not met. and the associated Completion Time has expired, Condition E is entered for that channel and provides for transfer to the appropriate subsequent Condition.

F.1 and F.2 If the Required Action and associated Completion Time of Condition C are not met and Table 3.3.10-1 directs entry into Condition F. the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to MODE 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Times are reasonable, based on operating experience. to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

(continued)

PALO VERDE UNITS 1.2.3 B 3.3.10-19 REVISION 32

PAM Instrumentation B 3.3.10 BASES ACTIONS G.1 (continued)

Alternate means of monitoring Reactor Vessel Water Level.

RCS Activity, and Containment Area Radiation have been developed and tested. These alternate means may be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. If these alternate means are used, the Required Action is not to shut down the plant, but rather to follow the directions of Specification 5.6.6. The report provided to the NRC should discuss whether the alternate means are equivalent to the installed PAM channels. justify the areas in which they are not equivalent, and provide a schedule for restoring the normal PAM channels.

SURVEILLANCE A Note at the beginning of the SR table specifies that REQUIREMENTS the following SRs apply to each PAM instrumentation Function found in Table 3.3.10-1.

SR 3.3.10.1 Performance of the CHANNEL CHECK once every 31 days ensures that a gross failure of instrumentation has not occurred.

A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure: thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit. If the channels are within the criteria, it is an indication that the channels are OPERABLE.

(continued)

PALO VERDE UNITS 1,2,3 B 3.3.10-20 REVISION 32

PAM Instrumentation B 3.3.10 BASES SURVEILLANCE SR 3.3.10.1 (continued)

REQUIREMENTS If the channels are normally off scale during times when surveillance is required, the CHANNEL CHECK will only verify that they are off scale in the same direction.

Current loop channels are verified to be reading at the bottom of the range and not failed downscale.

The Frequency of 31 days is based upon plant operating experience with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval is a rare event.

The CHANNEL CHECK supplements less formal, but more frequent, checks of channel during normal operational use of the displays associated with this LCO's required channels.

A CHANNEL CALIBRATION is performed every 18 months or approximately every refueling. CHANNEL CALIBRATION is a complete check of the instrument channel including the sensor. The Surveillance verifies the channel responds to the measured parameter within the necessary range and accuracy. A Note excludes the neutron detectors from the CHANNEL CALIBRATION.

For the Containment Area Radiation instrumentation, a CHANNEL CALIBRATION as described in UFSAR Sections 18.II.F.1.3 and 11.5.2.1.6.2 will be performed.

The calibration of the Containment Isolation Valve (CIV) position indication channels will consist of verification that the position indication changes from not-closed to closed when the valve is actuated to its isolation position by SR 3.6.3.7. The position switch is the sensor for the CIV position indication channels.

The calibration of the containment hydrogen monitor will use sample gases containing a nominal one volume percent hydrogen, balance nitrogen, and four volume percent hydrogen, balance nitrogen.

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

PALO VERDE UNITS 1.2.3 B 3.3.10-21 REVISION 32

PAM Instrumentation B 3.3.10 BASES REFERENCES 1. UFSAR Section 1.8. Table 1.8-1.

2. Regulatory Guide 1.97. Revision 2.

3. NUREG-0737. Supplement 1.

PALO VERDE UNITS 1.2.3 B 3.3.10-22 REVISION 32

ENCLOSURE 4 PVNGS Technical Specification Bases Revision 33 Insertion instructions and Replacement Pages

PVNGS Technical Specifications Bases Revision 33 Insertion Instructions Remove Page: Insert New Pace:

Cover page Cover page List of Effective Pages, List of Effective Pages, Pages 1/2 through Pages 1/2 through List of Effective Pages, List of Effective Pages, Page 7/8 Page 7/8 B 3.3.10-21/3.3.10-22 B 3.3.10-21/3.3.10-22 I

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PAM Instrumentation B 3.3.10 BASES SURVEILLANCE SR 3.3.10.1 (continued)

REQUI REMENTS If the channels are normally off scale during times when surveillance is required, the CHANNEL CHECK will only verify that they are off scale in the same direction.

Current loop channels are verified to be reading at the bottom of the range and not failed downscale.

The Frequency of 31 days is based upon plant operating experience with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval is a rare event.

The CHANNEL CHECK supplements less formal, but more frequent. checks of channel during normal operational use of the displays associated with this LCO's required channels.

SR 3.3.10.2 A CHANNEL CALIBRATION is performed every 18 months or approximately every refueling. CHANNEL CALIBRATION is a complete check of the instrument channel including the sensor. The Surveillance verifies the channel responds to the measured parameter within the necessary range and accuracy. A Note excludes the neutron detectors from the CHANNEL CALIBRATION.

For the Containment Area Radiation instrumentation, a CHANNEL CALIBRATION as described in UFSAR Sections 18.II.F.1.3 and 11.5.2.1.6.2 will be performed.

The calibration of the Containment Isolation Valve (CIV) position indication channels will consist of verification that the position indication changes from not-closed to closed when the valve is actuated to its isolation position by SR 3.6.3.7. The position switch is the sensor for the CIV position indication channels.

The calibration of the containment hydrogen monitor will use sample gases containing a nominal one volume percent hydrogen, balance nitrogen, and four volume percent hydrogen, balance nitrogen.

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

PALO VERDE UNITS 1.2,3 B 3.3.10-21 REVISION 33

PAM Instrumentation B 3.3.10 BASES REFERENCES 1. UFSAR Section 1.8. Table 1.8-1.

2. Regulatory Guide 1.97. Revision 2.

3. NUREG-0737, Supplement 1.

PALO VERDE UNITS 1.2.3 B 3.3.10-22 REVISION 32