Text

Proposed Tech Specs Sections 3.3,3.5 & 3.6,converting to Its,Per NUREG-1432
	ML18066A591
Person / Time
Site:	Palisades
Issue date:	07/30/1999
From:	; CONSUMERS ENERGY CO. (FORMERLY CONSUMERS POWER CO.)
To:	;
Shared Package
ML18066A590	List: ML18066A588; ML18066A591;
References
	RTR-NUREG-1432 NUDOCS 9908050103
	Download: ML18066A591 (239)
	v • d • e

ENCLOSURE 1 CONSUMERS ENERGY COMPANY PALISADES PLANT DOCKET 50-255 CONVERSION TO IMPROVED TECHNICAL SPECIFICATIONS EDITORIAL CHANGES TO SURVEILLANCE REQUIREMENTS NOTES

9908050103 990730 PDR ADOCK 05000255 P PDR

DISCUSSION OF SURVEILLANCE REQUIREMENT NOTES The changes to the enclosed Surveillance Requirement Notes are provided to establish a consistent approach for avoiding SR 3.0.4 conflicts as recommended in paragraphs 4.1.?f and 4.1.?g of NUMARC 93-03, "Writer's Guide for the Restructured Technical Specification." These changes do not alter the intent of the Surveillance Requirement N'otes, but simply provide a consistent presentation in the use of the terms "only required" and "not required". As such, these change are strictly editorial in nature.

/

As stated in the writer's guide, the terms "only required" and "not required" are used to specify precise requirements for performance of a Surveillance. When a Surveillance is noted as "only required" or "not required" it must be accompanied by either "to be met" or "to be performed".

The use of "met" or "performed" convey specific meaning. A Surveillance is "met" only when the acceptance criteria is satisfied. "Performance" refers only to the requirement to specifically determine the ability to meet the acceptance criteria. Notes written to avoid potential SR 3.0.4 c.onflicts which contain a time requirement are more clearly stated as "not required". However, .

Notes written to avoid potential SR 3.0.4 conflicts which do not contain a time requirement are more clearly stated as "only required". The Surveillance Requirement Notes in the Palisade's ITS that are written to avoid potential SR3.0.4 conflicts have been revised to adopt this convention.

Lastly, two editorial changes were made for clarification and consistency. First, the Note in SR 3.4.1.3 was revised by adding the term "THERMAL POWER" to clarify that THERMAL POWER must be ;e: 90% RTP. Secondly, the initials "SR" in the Note for SR 3.8.1.3 was replaced by the full spelling of "Surveillance Requirement" to maintain consistency in Section 3.8. , , '* ,

Conforming changes, have been made to the Bases as appropriate.

(

\

)

LHR 3.2.1

ACTIONS B.

CONDITION lncore Alarm and Excore B.1 REQUIRED ACTION Reduce THERMAL COMPLETION TIME 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Monitoring Systems POWER to:;; 85% RTP.

inoperable for monitoring LHR. AND 8.2 Verify LHR is within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months limits using manual incore readings. AND Once per 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months thereafter C. Required Action and C.1 Reduce THERMAL 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion POWER to:;; 25% RTP.

Time not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.1.1 Verify LHR is within the limits specified in the 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months COLR.

Palisades Nuclear Plant 3.2.1-2 Amendment No.

LHR 3.2.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.1.2 Adjust incore alarm setpoints based on a Prior to operation measured power distribution. > 50% RTP after each fuel loading 31 EFPD thereafter

+o*b(~ ~(\*

SR 3.2.1.3 ---------- ~.:i:J---~-N()TE---------------------------

()nly requirecrwherfExcore Monitoring System is being used to monitor LHR.

Verify measured ASI has been within 0.05 of Prior to each initial target ASI for last 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . use of Excore Monitoring System to monitor LHR SR 3.2.1.4 Verify THERMAL P()WER is less than the APL. 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Palisades Nu.clear Plant 3.2.1-3 Amendment No.

LHR 3.2.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.2.1.5 Verify measured ASI is within 0.05 of target ASL 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months SR 3.2.1.6 Verify Tq ~ 0.03 . 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

Palisades Nuclear Plant 3.2.1-4 Amendment No.

PCS Pressure, Temperature, and Flow DNB Limits 3.4.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.1.1 Verify pressurizer pressure ~ 2010 psia and 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

s; 2100 psia.

SR 3.4.1.2 Verify PCS cold leg temperature 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

s; 542.99 + 0.0580(P-2060)+ 0.00001 (P-2060) 2 +

1.125(W-138) - 0.0205(W-138) 2

SR 3.4. 1.3 ------------------------------1\!()TE----------------------------

l\lot required to be performed until 31 EFPD after

~'~f\L Poiot~ i.:i ~ ~ 90% RTP.

~~ - ~------------~-----------------------------------------------------

Verify PCS total flow rate is ~ 352,000 gpm. 18 months After each plugging of 10 or more steam generator tubes Palisades l\luclear Plant 3.4.1-2 Amendment No.

PCS Loops - MODE 5, Loops Not Filled 3.4.8

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One SOC train inoperable. A.1 Initiate action to restore Immediately SOC train to OPERABLE status.

B. Two SOC trains B.1 Suspend all operations Immediately inoperable. involving reduction of PCS boron OR concentration.

SOC flow through the AND reactor core not within limits.

B.2 Initiate action to restore Immediately one SOC train to OPERABLE status and operation with SOC flow through the reactor core within limit.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.8.1 -------------------------------NOTE---------------------------

Only required to be ~~ed-when complying with LCO 3.4.8.a.

Verify one SOC train is in operation with 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

~ 2810 gpm flow through the reactor core.

Palisades Nuclear Plant 3.4.8-2 Amendment No.

PCS Loops - MODE 5, Loops Not Filled 3.4.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.8.2 -------------------------------NOTE---------------------------

Only required to be 13~ed when complying with LCO 3.4.8.b. ~

Verify one SOC train is in operation with 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

~ 650 gpm flow through the reactor core.

SR 3.4.8.3 -------------------------~------N()TE--------------------------

Only required to be ~ when complying with LCO 3.4.8.b. ~

V~rify two of three charging pumps are incapable 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of reducing the boron concentration in the PCS below the minimum value necessary to maintain the required SHUTDOWN MARGIN.

SR 3.4.8.4 Verify correct breaker alignment and indicated 7 days power available to the SOC pump that is not in operation .

Palisades Nuclear Plant 3.4.8-3 Amendment No.

Pressurizer 3.4.9

ACTIONS B.

CONDITION

< 375 kW pressurizer B.1 REQUIRED ACTION Restore required COMPLETION TIME 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months heater capacity available pressurizer heaters to from electrical bus 1D, or OPERABLE status.

electrical bus 1E, OR Required pressurizer heater capacity from electrical bus 1E not capable of being powered

from an emergency power supply.

C. Required Action and C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition B not AND met.

C.2 Be in MODE4. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.9.1 -----------------------~~ 1 0TE---------------------------

Not required to b~ until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after establishing a bubble in the pressurizer and the pressurizer water level has been lowered to within its normal operating band.

Verify pressurizer water level is < 62.8%. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.9.2 Verify the capacity of pressurizer heaters from 18 months electrical bus 1D, and electrical bus 1E is

~ 375 kW.

Palisades Nuclear Plant 3.4.9-2 Amendment No.

LTOP System 3.4.12

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.12.1 -------------------------------NOTE---------------------------

Only required to be p~d when complying with LCO 3.4.12.a. ~

Verify both HPSI pumps are incapable of injecting 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months into the PCS.

SR 3.4.12.2 Verify required PCS vent, capable of relieving :<: 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for 167 gpm at a PCS pressure of 315 psia, is open. unlocked open vent valve(s) 31 days for locked open vent valve(s)

SR 3.4.12.3- Verify PORV block valve is open for each required 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months PORV.

SR 3.4.12.4 -------------------------------NOTE---------------------------

Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after decreasing any PCS cold leg temperature to

< 430°F.

Perform CHANNEL FUNCTIONAL TEST on each 31 days required PORV, excluding actuation.

SR 3.4.12.5 Perform CHANNEL CALIBRATION on each 18 months required PORV actuation channel.

Palisades Nuclear Plant 3.4.12-3 Amendment No.

PCS PIV Leakage 3.4.14

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.14.1 -----~----------------N()TES--------------------------

1. -Net required to be performed in M()DES )f (D and~

2. Leakage rates ~ 5.0 gpm are unacceptable if the latest measured rate exceeded the rate determined by the previous test by an amount that reduces the margin between measured leakage rate and the maximum permissible leakage rate of 5.0 gpm by 50%

or greater.

3. Minimum test differential pressure shall not be less than 150 psid.

Verify leakage from each PCS PIV is equivalent to 18 months

~ 5 gpm at a PCS pressure of 2060 psia .

()nee prior to entering MODE 2 whenever the plant has been in M()DE 5 for 7 days or more, if leakage testing has not been performed in the previous 9 months SR 3.4.14.2 Verify each SOC suction valve interlock prevents its 18 months associated valve from being opened with a simulated or actual PCS pressure signal

~ 280 psia .

Palisades Nuclear Plant 3.4.14-3 Amendment No.

PCS PIV Leakage 3.4.14 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.14.3 ~----------------------N()TE-------------~----~--

.Nffi. required to be performed in M()OES $'and "4':

Verify each of the four Low Pressure Safety Prior to entering Injection (LPSI) check valves are closed. M()DE 2 after each use of the LPSI check valves for soc

Palisades Nuclear Plant 3.4.14-4 Amendment No.

AFW System 3.7.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.3 ----~~.!l!t..-~-~~-~~-i'J()~~~~~~~--~--~

1. -Net required to be met in MODES 2 or 3 when AFW ~peration.

z. -Net re~uira~ met iR-MODE 4 W'RSFI steaFA sei::ierator is relieG-Y.J'i}E>Fl..feP I ieat-1"emoval.

Verify each AFW automatic valve that is not 18 months locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

SR 3.7.5.4 l'C5i!il'l_~~~-~~i'J()l"E:~~

~quired to be met in MOD '.4wheAsteam geReFatoF is Felieel l:lJ30R foF "'1eat Feffievsl.

~--------------

Verify each required AFW pump starts automatically on an actual or simulated actuation signal.

18 months

Palisades Nuclear Plant 3.7.5-4 Amendment No.

CCW System 3.7.7

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.7.1 ------------------------------N()TE----------------------------

lsolation of CCW flow to individual components does not render the CCW System inoperable.

Verify each CCW manual, power operated, and 31 days automatic valve in the flow path servicing safety related equipment, .that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.7.2 Verify each CCW automatic valve in the flow path 18 months that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

SR 3.7.7.3 Verify each CCW pl.imp starts automatically on an 18 months actual or simulated actuation signal in the "with standby power available" mode .

Palisades Nuclear Plant 3.7.7-2 Amendment No.

sws 3.7.8 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.8.1 -----------------------------N()TE-----------------------------

lsolation of SWS flow to individual components does not render SWS inoperable.

Verify each SWS manual, power operated, and 31 days automatic valve in the flow path servicing safety related equipment, that is not locked, sealed, or otherwise secured in position, is in the correct position.

SR 3.7.8.2 Verify each SWS automatic valve in the flow path 18 months that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

SR 3.7.8.3 Verify each SWS pump starts automatically on an 18 months actual or simulated actuation signal in the "with standby power available" mode.

Palisades Nuclear Plant 3.7.8-2 Amendment No.

CRV Filtration 3.7.10

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.10.1 Operate each CRV Filtration train for ~ 10 31 days continuous hours with associated heater (VHX-26A or VHX-268) operating.

SR 3.7.10.2 Perform required CRV Filtration filter testing in In accordance with accordance with Ventilation Filter Testing the Ventilation Filter Program. Testing Program SR 3.7.10.3

°' ~* mo~~~!~-~~-~4, ~d)

____i:)'_______________________ l'J()l"i=--1---------------------------*-

+tot-required to be me~unng movement of irradiated fuel assemblies itl ~:-;~~,... ..... :- :'.:.. :.. ; ~*

~

--~-~**tei:i:-l.fi-~-t,... -Qf.,;~-~~~*-'l-c-~*-~*...~"';...~-e1-~~R=ie=SF::P:-....;;._I_ lon+o..1 I'\ mc.f'\

- - - -.1 *- -* I e

+

Verify each CRV Filtration train actuates on an 18 months

SR 3.7.10.4 actual or simulated actuation signal.

Verify one CRV Filtration train can maintain a positive pressure of ~ 0.125 inches water gauge, 18 months

relative to the adjacent area during the emergency mode of operation, at an emergency ventilation flow rate :of ~ 3040 cfm and ~ 3520 cfm.

Palisades l'Juclear Plant 3.7.10-3 Amendment No. 01/20/98

AC Sources - Operating 3.8.1

SURVEILLANCE REQUIREMENTS SR 3.8.1.3 SURVEILLANCE

N()TES---------------------------

FREQUENCY

1. Momentary transients outside the load range do not invalidate this test.

2. This Surveillance shall be conducted on only one DG at a time.

0 Surv\. 1lla.'f\c.~

3. Thisr'Sroshall be preceded by and immernately follow without shutdown a successful performance of SR 3.8.1.2.

Verify each DG is synchronized and loaded, and 31 days operates for ~ 60 minutes:

a. For ~ 15 minutes loaded to greater than or equal to peak accident load; and

b. For the remainder of the test at a load

~ 2300 kW and ~ 2500 kW.

SR 3.8.1.4 Verify each day tank contains~ 2500 gallons of 31 days fuel oil.

SR 3.8.1.5 Verify each DG rejects a load greater than or 18 months equal to its associated single largest post-accident load, and:

a. Following load rejection, the frequency is

~ 68 Hz;

b. Within 3 seconds following load rejection, the voltage is ~ 2280 V and ~ 2640 V; and

c. Within 3 seconds following load rejection, the frequency is~ 59.5 Hz and~ 61.5 Hz.

Palisades Nuclear Plant 3.8.1-5 Amendment No.

Containment Penetrations 3.9.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more containment A.1 Suspend CORE Immediately penetrations not in AL TERATIONS.

required status.

A.2 Suspend movement of Immediately irradiated fuel assemblies within containment.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.3.1 Verify each required containment penetration is in 7 days the required status.

SR 3.9.3.2 Verify each required automatic isolation valve 18 months closes on an actual or simulated Refueling Containment High Radiation signal.

Palisades Nuclear Plant 3.9.3-2 Amendment No.

LHR B 3.2.1 BASES ACTIONS B.1 and B.2 (continued)

With the lncore Alarm System inoperable for monitoring LHR and the Excore Monitoring System inoperable for monitoring LHR, THERMAL POWER must be reduced to ~ 85% RTP within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . Operation at

~ 85% RTP ensures that ample thermal margin is maintained. A 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is adequate to achieve the required plant condition without challenging plant systems. Additionally, with the lncore Alarm and Excore Monitoring Systems inoperable, LHR must be verified to be within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , and every 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months ,thereafter by manually collecting incore detector readings at the terminal blocks in the control room utilizing a suitable signal detector. The manual readings shall be taken on a minimum of 10 individual detectors per quadrant (to include a total of 160 detectors in a 10 hour1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months period). The time interval of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and the minimum of 10 detectors per quadrant are sufficient to maintain adequate surveillance of the power distribution to detect significant changes until the monitoring systems are returned to service .

If the Required Action and associated Completion Time are not met, THERMAL POWER must be reduced to~ 25% RTP. This reduced power level ensures that the core is operating within its thermal limits and places the core in a conservative condition. The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is reasonable, based on operating experience, to reach ~ 25% RPT from full power MODE 1 conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.2.1.1 REQUIREMENTS The lncore Alarm System provides continuous monitoring of LHR through the plant computer. The plant computer is used to generate alarm setpoints that are based on measured margin to allowed LHR.

As the incore detectors are read by the plant computer, they are continuously compared to the alarm setpoints. If the lncore Alarm System LHR monitoring function is inoperable, excore detectors or manual recordings of the incore detector readings may be used to monitor LHR. Periodically monitoring LHR ensures that the assumptions made in the Safety Analysis are maintained. This SR is modified by a Note that states that the SR is only~hen the lncore Alarm System is being used to monitor LHR. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is consistent with an SR which is to b performed each shift.

e. u 11(:.J +o be. h'l!..t Palisades Nuclear Plant B 3.2.1-7

LHR B 3.2.1

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.2.1.2 Continuous monitoring of the LHR is provided by the lncore Alarm System which provides adequate monitoring of the core power distribution and is capable of verifying that the LHR does not exceed its specified limits.

Performance of this SR verifies the lncore Alarm System can accurately monitor LHR by ensuring the alarm setpoints are based on a measured power distribution. Therefore, they are only applicable when the lncore Alarm System is being used to determine the LHR.

The alarm setpoints must be initially adjusted following each fuel loading prior to operation above 50% RTP, and periodically adjusted every 31 Effective Full Power Days (EFPD) thereafter. A 31 EFPD Frequency is consistent with the historical testing frequency of the reactor monitoring system. The SR is modified by a Note which c:;ah%.w~s~---~

the SR to be nly when the lncore Alarm System is being used to determine LHR

r-nc.+

SR 3.2.1.3 SR 3.2.1.3 requires, prior to initial use of the excore LHR monitoring function, verification that the absolute difference of the measured ASI and the target ASI has been ~ 0.05 for each OPERABLE channel for the last 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months using the previous 24 hourly recorded values.

Performance of this SR verifies that plant conditions are acceptable for the Excore Monitoring System to accurately monitor the LHR (Ref. 5).

The prior to initial use verification identifies that there have been no significant power distribution anomalies while using other monitoring methods, e.g., the incore detectors, which may affected the ability of the excore detectors to monitor LHR.

The SR is modified by a Note that states that the SR is only required to be met when the Excore. Monitoring System is being used to monitor LHR. Failure of this SR prevents the Excore Monitoring System from being consid~red OPERABLE for monitoring of LHR.

Palisades Nuclear Plant B 3.2.1-8

PCS Pressure, Temperature, and Flow DNB Limits B 3.4.1 BASES SURVEILLANCE SR 3.4.1.3{continued) *;~lr.i~,

REQUIREMENTS 0__f1__&mi:iL.~

The SR is modified by a Note(that-~~tes the SR is only required to be performed 31 EFPD afte~% RTP. The Note is necessary to allow measurement of the flow rate at normal operating conditions at power in MODE 1. The most common, and perhaps accurate, method used to perform the PCS total flow surveillance is by means of a primary to secondary heat balance (calorimetric) with the plant at or near full rated power. The most accurate results for such a test are obtained with the plant at or near full power when differential temperatures measured across the reactor are the greatest. Consequently, the test should not be performed until reaching near full power (i.e.,.=:: 90% RTP) conditions. Similarly, test accuracy is also influenced by plant stability.

In order for accurate results to be obtained, steady state plant conditions must exist to permit meaningful data to be gathered during the test. Typically, following an extended shutdown the secondary side of the plant will take up to several days to stabilize after power escalation. It is impracticable to perform a primary to secondary heat balance of the precision required for the PCS flow measurement until stabilization has been achieved. Furthermore, an integral part of the PCS flow heat balance involves the use of Ultrasonic Flow Measurement equipment for measuring steam generator feedwater flow. This equipment requires, stable plant operation at or near full power conditions before it can be used. As such, the Surveillance cannot be performed in MODE 2 or below, and will not yield accurate results if performed below 90% RTP.

REFERENCES 1. FSAR, Section 14.1 Palisades Nuclear Plant B 3.4.1-5

PCS Loops - MODE 5, Loops Not Filled B 3.4.8

BASES ACTIONS (contineud)

B.1 and B.2 If no SOC trains are OPERABLE or SOC flow through the reactor core is not within limits, except as provided in Note 1, all operations involving the reduction of PCS boron concentration must be suspended. Action to restore one SOC train to OPERABLE status and operation shall be initiated immediately and continue until one train is restored to operation and flow through the reactor core is restored to within limits. Boron dilution requires forced circulation for proper mixing and the margin to criticality must not be reduced in this type of operation. The immediate Completion Time reflects the importance of maintaining operation for decay heat removal.

SURVEILLANCE SR 3.4.8.1 and SR 3.4.8.2 REQUIREMENTS These SRs require verification every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months that one SOC train is in operation. Verification of the required flow rate ensures forced circulation is providing heat removal and mixing of the soluble boric acid. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency has been shown by operating practice to be sufficient to regularly assess SOC train status. In addition, control room indications and alarms will normall indica e train status.

SR 3.4.8.1 and SR 3.4.8.2 are eac per:fQr:r+HiRse ef the SR is only t:.:~: ~-t o 11eto bt ate to indicate tAEK-when complying with the applicable portion of the LCO. Therefore, it is only necessary to perform either SR 3.4.8.1, or SR 3.4.8.2 based on the method of compliance with the LCO.

Palisades Nuclear Plant B 3.4.8-4

PCS Loops - MODE 5, Loops Not Filled 8 3.4.8

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.4.8.3 This SR requires verification every* 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months that two of the three charging pumps are incapable of reducing the boron concentration in the PCS below the minimum value necessary to maintain the required SHUTDOWN MARGIN. Making the charging pumps incapable reducing the boron concentration in the PCS may be accomplished by electrically disabling the pump motors, blocking potential dilution sources to the pump suction, or by isolating the pumps discharge flow path to the PCS. Verification may include visual inspection of the pumps configuration (e.g., pump breaker position or valve alignment),

or the use of other administrative controls. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is based on engineering judgement considering operating practice, administrative control available, and the unlikeness of inadvertently aligning a charging pump for PCS injection during this period.

SR 3.4.8.3 is modified by a Note to indicate that 130FferFAaf'lee ef the SR is onl n&s&&&aF)' when complying with LCO 3.4.8.b .. When SOC flow through the reactor core is~ 2810 gpm, there is no restriction on charging pump operation.

SR 3.4.8.4 Verification that the required number of trains are OPERABLE ensures that redundant paths for heat removal are available and that additional trains can be placed in operation, if needed, to maintain decay heat removal and primary coolant circulation. Verification is performed by verifying proper breaker alignment and indicated power available to the required pump that is not in operation such that the SOC pump is capable of being started and providing forced PCS flow if needed.

Proper breaker alignment and power availability means the breaker for the required SOC pump is racked-in and electrical power is available to energize the SOC pump motor. The Frequency of 7 days is considered reasonable in view of other administrative controls available and has been shown to be acceptable by operating experience.

REFERENCES None Palisades Nuclear Plant B 3.4.8-5

Pressurizer B 3.4.9 BASES ACTIONS (continued)

If< 375 kW of pressurizer heater capacity is available from either electrical bus 1D or electrical bus 1E, or the pressurizer heaters from electrical bus 1E are not capable of being powered from an emergency power supply, restoration is required within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is reasonable considering that a demand caused by loss of offsite power would be unlikely in this period. Pressure control may be maintained during this time using the remaining available pressurizer heaters.

C.1 and C.2 If the required pressurizer heaters cannot be restored to an OPERABLE status within the allowed Completion Time of Required Action 8.1, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging safety systems. $imilarly, the Completion Time of 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months is reasonable, based on operating experience, to reach MODE 4 from full power in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.4.9.1 REQUIREMENTS This SR ensures that during steady state operation, pressurizer water level is mai.ntained below the nominal upper limit to provide a minimum space for a steam bubble. The Surveillance is performed by observing e

the indicated level. SR 3.4.9.1 is modified by a Note which states that verification of the pressurizer water level is not required to be pel'feP',.,eel until 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after a bubble has been established in the pressurizer and the pressurizer water level has been lowered to its normal operating band. The intent of this Note is to prevent an SR 3.0.4 conflict by delaying the performance of this SR until after the water level in the pressurizer is within its normal operating band following a plant heatup. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months interval has been shown by operating practice to be sufficient to regularly assess the level for any deviation and verify that operation is within safety analyses assumptions. Alarms are also available for early detection of abnormal level indications .

Palisades Nuclear Plant

B 3.4.9-5

LTOP System B 3.4.12

BASES ACTIONS (continued)

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

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

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

/n:~ _SR 3.4.12.1 is modified by a Note which only requires the SR to be

~perfermeEI when complying with LCO 3.4.12.a. When all PCS cold leg

. temperature are~ 300°F, a start of both HPSI pumps in conjunction with a charging/letdown imbalance will not cause the PCS pressure to exceed the 10 CFR 50 Appendix G limits. Thus, this SR is only required when any PCS cold leg temperature is reduced to less than 300°F.

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

Palisades Nuclear Plant B 3.4.12-10

PCS PIV Leakage B 3.4.14

BASES SURVEILLANCE REQUIREMENTS SR 3.4.14.1 (continued) f..D (?)

SR 3.4.14.1 is modified by three Notes.lNote 1ft"ates that the SR is required to be performed in MODES$ and k. Entry into MODES 3 .

and 4 is allowed to establish the necessary differential pressure and stable conditions to allow performance of this surveillance.

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

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

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

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

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

Palisades Nuclear Plant B 3.4.14-6

PCS PIV Leakage B 3.4.14

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.4.14.3 This SR requires a verification that the four Low Pressure Safety Injection (LPSI) check valves (CK-3103, CK-3118, CK-3133 and CK-3148) in the SOC flow path reclose after stopping SOC flow.

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

Overpressurization of the LPSI piping could occur if the LPSI check valves were not closed upon the receipt of a Safety Injection Signal and PCS pressure remained relatively high (e.g., during a small break LOCA). In this case, the higher pressure water from the discharge of the HPSI pumps could cause the lower pressure LPSI piping to exceed.

its design pressure. This event could result in a loss of emergency core cooling water outside containment which reduces the overall volume of water available for recirculation from the containment sump (Ref. 4).

SR 3.4.14.3 is required to be performed on a Frequency of "prior to entering MODE 2 whenever the LPSI check valves have been used for SOC." This ensures the LPSI check valves are closed whenever they have been opened for SOC operations prior to a reactor startup. l)e__

SR is modified by a Note which state~at t~ surveillance is~

required to be performed in MODES~nd~hus, entry into MODES 3 and 4 is allowed to establish the necessary differential pressure and to establish stable conditions to allow performance of this surveillance.

REFERENCES 1. WASH-1400 (NUREG-75/014), Appendix V, October 1975

2. NUREG-0677, May 1980

3. ASME, Boiler and Pressure Vessel Code,Section XI

4. Letter from Consumers Power Company to D.M. Crutchfield (NRC) Requesting a Change to the Palisades Plant Technical Specification, dated July 29, 1982 Palisades Nuclear Plant B 3.4.14-7

AFW System B 3.7.5 BASES SURVEILLANCE SR 3.7.5.2 REQUIREMENTS (continued) Verifying that each required AFW pump's developed head at the flow test point is greater than or equal to this required developed head ensures that AFW pump performance has not degraded during the cycle. Flow and differential head are normal tests of pump performance required by Section XI of the ASME Code (Ref. 2). This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance.

This test need not be performed for the steam driven AFW pump for MODE 3 or4.

Performance of inservice testing, discussed in the ASME Code,Section XI (Ref. 2), at 3 month intervals satisfies this. requirement.

SR 3.7.5.3 This SR ensures that AFW can be delivered to the appropriate steam generator, in the event of any accident or transient that generates an AFAS, by demonstrating that each automatic valve in the flow path actuates to its correct position on an actual or simulated actuation signal. Specific signals (e.g., AFAS) are tested under Section 3.3, "Instrumentation." This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The 18 month Frequency is acceptable, based on the design reliability and operating ex erience of the e~nt.

i4bh ont This SR is modified bf.t\*.'o Notes. Note states the SR is required rf1~

to be met in MODE9l2 and 3 when AFW is.J1n operation. Note 2 states *~

the SR is nGt req1:Jirsd te ee R=1et in MODE 4 wl=ief'I tl=ie ste81"1, ge11e1 ato1 s is relieel u13efl ier l=ieet re1¥1evl!I. In these MODES, the required AFW train(s) are already aligned..aA@f

with the flow control valves in manual control.

Palisades Nuclear Plant B 3.7.5-8

AFW System B 3.7.5

BASES SURVEILLANCE REQUIREMENTS (continued)

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

This test need not be performed for the steam driven AFW pump for MODE 3 or 4 operation.

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

This SR is modified by a Note. The Note states that the SR is~ rf3'!}J re uired to be met in MOD . In MODE 4, the required pump is already operating and the autostart function is not required.

REFERENCES 1. FSAR, Section 9.7

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

Palisades Nuclear Plant B 3.7.5-9

CCW System B 3.7.7 BASES SURVEILLANCE SR 3.7.7.1 (continued)

REQUIREMENTS This SR is modified by a Note indicating that the isolation of the CCW to components or systems may render those components inoperable but does not affect the OPERABILITY of the CCW System.

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

SR 3.7.7.2 This SR verifies proper automatic operation of the CCW valves on an actual or simulated actuation signal. Specific signals (e.g., safety injection, RAS) are tested under Section 3.3, "Instrumentation." This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative ~

controls. This SR is modified by a Note which states this SR is-Ftet- on IY re uired to be met in MOD ,f. The instrumentation providing the inpu signal is not required in MODE 4, therefore, to keep consistency with Section 3.3, "Instrumentation," the SR is not required to be met in this MODE. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

SR 3.7.7.3 This SR verifies proper automatic operation of the CCW pumps on an actual or simulated actuation signal in the "with standby power available" mode which tests the starting of the pumps by the SIS-X relays. The starting of the pumps by the sequencer is performed in Section 3.8 "Electrical Power Systems." This SR is modified by a Note which states this SR i Aet required to be met in MOD X The instrumenta ion prov1 mg e mpu s1gna 1s not required in MODE 4, therefore, to keep consistency with Section 3.3, "Instrumentation," the SR is not required to be met in this MODE. Operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

Palisades Nuclear Plant B 3.7.7-5

sws B 3.7..8

BASES SURVEILLANCE REQUIREMENTS SR 3.7.8.1 Verifying the correct alignment for manual, power operated, and automatic valves in the SWS flow path ensures that the proper flow paths exist for SWS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since they are verified to be in the correct position prior to locking, sealing, or securing. This SR also does not apply to valves that cannot be inadvertently misaligned, such as check valves. This Surveillance does not require any testing or valve manipulation; rather, it involves verification that those .valves capable of potentially being mispositioned are in the correct position. This SR is modified by a Note indicating that the isolation of SWS to components or systems may render those components inoperable but does not affect the OPERABILITY of the

.SWS.

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

SR 3.7.8.2 This SR verifies proper automatic operation of the SWS valves on an actual or simulated actuation signal. Specific signals (e.g., safety injection) are tested under Section 3.3, "Instrumentation." If the isolation valve for the noncritical service water header (CV-1359) or for containment air cooler VHX-4 (CV-0869) fail to close, then both trains of SWS are considered inoperable due to the diversion of cooling water flow. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under

/".....~istrative controls. This SR is modified by a Note which states this

~ ~iiot-re uired to be met in MOD K. The instrumentation providing

{ I 2. o. d! the input signal is not required in MO E 4, therefore, to keep 1

" consistency with Section 3.3, "Instrumentation," the SR is not required to be met in this MODE. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

Palisades Nuclear Plant B 3.7.8-4

sws B 3.7.8 BASES SURVEILLANCE SR 3.7.8.3 REQUIREMENTS (continued) The SR verifies proper automatic operation of the SWS pumps on an actual or simulated actuation signal in the "with standby power available" mode which tests the starting of the pumps by the SIS-X relays. The starting of the pumps by the sequencer is performed in Section 3.8, "Electrical Power Systems." This SR is modified by a Note w rc sta es 1s 1 ~ required to be met in MOD )(. The rns rumen a prov1 rng e rnpu s1gna 1s not required in MODE 4, therefore, to keep consistency with Section 3.3, "Instrumentation," the SR is not required to be met in this MODE. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

REFERENCES 1. FSAR, Section 9.1

2. FSAR, Section 6.1

Palisades Nuclear Plant B 3.7.8-5

sws B 3.7.8 BASES SURVEILLANCE SR 3.7.8.2 REQUIREMENTS (continued) This SR verifies proper automatic operation of the SWS valves on an actual or simulated actuation signal. Specific signals (e.g., safety

injection) are tested under Section 3.3, "Instrumentation." If the isolation valve for the noncritical service water header (CV-1359) or for containment air cooler VHX-4 (CV-0869) fail to close, then both trains of SWS are considered inoperable due to the diversion of cooling water flow. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. This SR is modified by a Note which states this SR is only required to be met in MODES 1, 2, and 3. The instrumentation providing the input signal is not required in MODE 4, therefore, to keep consistency with Section 3.3, "Instrumentation," the SR is not required to be met in this MODE. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

SR 3.7.8.3 The SR verifies proper automatic operation of the SWS pumps on an actual or simulated actuation signal in the "with standby power available" mode which tests the starting of the pumps by the SIS-X relays. The starting of the pumps by the sequencer is performed in Section 3.8, "Electr" al Power Systems." This SR is modified by a Note w this SR i :AOt required to be met in MO J:' The s instrumentation providing e mpu s1gna 1s no required in MODE 4, therefore, to keep consistency with Section 3.3, "Instrumentation," the SR is not required to be met in this MODE. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

REFERENCES 1. FSAR, Section 9.1

2. FSAR, Section 6.1 Palisades Nuclear Plant B 3.7.8-5

ENCLOSURE 2 CONSUMERS ENERGY COMPANY PALISADES PLANT DOCKET 50-255 CONVERSION TO IMPROVED TECHNICAL SPECIFICATIONS CHANGES TO ITS SECTION 3.3

ESF Instrumentation 3.3.3 3.3 INSTRUMENTATION 3.3.3 Engineered Safety Features (ESF) Instrumentation LCO 3.3.3 Four ESF bistables and associated instrument channels for each Function in Table 3.3.3-1 shall be OPERABLE.

APPLICABILITY: As specified in Table 3.3.3-1.

ACTIONS

NOTE-------------------------------------

Separate Condition entry is allowed for each.Function.

CONDITION REQUIRED ACTION COMPLETION TIME A. --------NOTE----------

Not applicable to RAS.

One or more Functions A. l Place affected 7 days with one ESF bistable or bistable in trip.

associated instrument channel inoperable.

B. ---------NOTE------~-- ------------NOTE-----------

Not applicable to RAS. LCO 3.0.4 is not

applicable.

One or more Functions B.1 Place one bistable 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months with two ESF bistables in trip.

or associated instrument channels inoperable. AND B.2 Restore one 7 days bistable and associated instrument channel to OPERABLE status .

Palisades Nuclear Plant 3.3.3-1 Amendment No. 06/25/99

ESF Logic and Manual Initiation 3.3.4 Table 3.3.4-1 {page 1 of 1)

Engineered Safety Features Actuation Logic and Manual Initiation APPLICABLE FUNCTION MODES

1. Safety Injection Signal (SIS)C*l 1,2,3

2. Steam Generator Low Pressure Signal (SGLP) CbJCcJ

3. Recirculation Actuation Signal (RAS) 1,2,3

4. Auxiliary Feedwater Actuation Signal 1,2,3 (AFAS)

5. Containment High Pressure Signal 1,2,3,4 .

(CHP)WCcJ

6. Containment High Radiation Signal (CHR)

(a) 1,2,3,4 SIS actuation by Pressurizer Low Pressure may be manually bypassed when pressurizer pressure is ~ 1700 psia. The bypass shall be automatically removed whenever pressurizer pressure is > 1700 psia.

(b) SGLP actuation may be manually bypassed when SG pressure is ~ 565 psia.

The bypass shall be automatically removed whenever steam generator pressure is

> 565 psia.

(c) Manual Initiation may be achieved by individual component controls.

(d) Not required to be OPERABLE when all Main Steam Isolation Valves (MSIVs) are closed and deactivated, and all Main Feedwater Regulating Valves (MFRVs) and MFRV bypass valves are either closed and deactivated, or isolated by closed manual valves.

(e) Manual Initiation channels not required .

Palisades Nuclear Plant 3.3.4-4 Amendment No. 06/25/99

PAM Instrumentation 3.3.7 SURVEILLANCE REQUIREMENTS

NOTE-------------------------------------

These SRs apply to each PAM instrumentation Function in Table 3.3.7-1.

SURVEILLANCE FREQUENCY SR 3.3.7.1 Perform CHANNEL CHECK for each required 31 days instrumentation channel that is normally energized.

SR 3.3.7.2 -------------------NOTE--------------------

Neutron detectors are excluded from the CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION. 18 months Palisades Nuclear Plant 3.3.7-3 Amendment No. 05/30/99

RPS Instrumentation B 3.3.1 BASES BACKGROUND Measurement Channels (continued)

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

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

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

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

The required RPS Trip Functions utilize the following input instrumentation:

Variable High Power Trip (VHPT)

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

Palisades Nuclear Plant B 3.3.1-3 05/30/99

RPS Instrumentation B 3.3.1 BASES BACKGROUND Measurement Channels (continued)

Loss of Load Trip The Loss of Load trip uses a single pressure switch, 63/AST-2, in the turbine auto stop oil circuit to sense a turbine trip for input to all four RPS auxiliary trip units. The Loss of Load Trip is actuated by turbine auxiliary relays 305L and 305R.

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

If a turbine trip is generated by loss of auto stop oil pressure, auto stop oil pressure switch 63/AST-2 will actuate relays 305L and 305R and generate a reactor trip. If a turbine trip is generated by an input to the solenoid trip valve, relays 305L and 305R, which are wired in parallel, will also be actuated and will generate a reactor trip .

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

Zero Power Mode Bypass Automatic Removal The Zero Power Bypass allows manually bypassing (i.e. disabling) four reactor trip functions, Low PCS Flow, Low SG A Pressure, Low SG B Pressure, and TM/LP (low PCS pressure), when reactor power (as indicated by the wide range nuclear instrument channels) is below 10-4%. This bypassing is necessary to allow RPS testing and control rod drive mechanism testing when the reactor is shutdown and plant conditions would cause a reactor trip to be present.

The Zero Power Mode Bypass removal interlock uses the wide range nuclear instruments (Nis) as measurement channels. There are only two wide range NI channels.

Separate bistables are provided to actuate the bypass removal for each RPS channel. Bi stables in the NI-1/3 channel provide the bypass removal function for RPS channels A and C; bistables in the NI-2/4 channel for RPS channels B and D.

Palisades Nuclear Plant B 3.3.1-6 05/30/99

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

The Allowable Values are specified for each safety related RPS trip Function which is credited in the safety analysis.

Nominal trip setpoints are specified in the plant procedures. The nominal setpoints are selected to ensure plant parameters do not exceed the Allowable Value if the instrument loop is performing as required. Operation with a trip setpoint less conservati.ve than the nominal trip

setpoint, but within its Allowable Value, is acceptable.

Each Allowable Value specified is more conservative than the analytical limit determined in the safety analysis in order to account for uncertainties appropriate to the trip Function. These uncertainties are addressed as described in plant documents. Neither Allowable Values nor setpoints are specified for the non-safety related RPS Trip Functions, since no safety analysis assumptions would be violated if they are not set at a particular value.

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

1. Variable High Power Trip {VHPT)

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

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

Palisades Nuclear Plant B 3.3.1-17 05/30/99

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

The VHPT is designed to limit maximum reactor power to its maximum design and to terminate power excursions initiating at lower powers without power reaching this full power limit. During plant startup, the VHPT trip setpoint is initially at its minimum value, ~ 30%.

Below 30% RTP, the VHPT setpoint is not required to "track" with Q Power, i.e., be adjusted to within 15% RTP. It remains fixed until manually reset, at which point it increases to ~ 15% above existing Q Power.

The maximum allowable setting of the VHPT is 106.5% RTP. Adding to this the possible variation in trip setpoint due to calibration and instrument error, the maximum actual steady state power at which a trip would be actuated is 115%, which is the value assumed in the safety analysis.

2. High Startup Rate Trip This LCO requires four channels of High Startup Rate Tr1~ Funct1on to be OPERABLE in MODES 1 and 2.'----'Flte 5

~!~ e ~~r:~~i~:::stb!~o:aia~:4~g~s;~~"w~~~R~~C ~6~ER is above 1JP8 RTP. If a Iii gh Startup Rate trip is bypassed wheH power is betweeH these limits, it must be coHsidered to be iHoperable.

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

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

The requirement for this trip Function is modified by a footnote, which allows The High Startup Rate trip to be byeassed when the wide range NI indicates below 10E-4ro or when THERMAL POWER is above 13% RTP. If a High Startup Rate trip is bypassed when power is between these limits, it must be considered to be inoperable.

Palisades Nuclear Plant B 3.3.1-18 05/30/99

~*------,

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

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

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

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

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

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

The 25.9% Allowable Value assures that there is an adequate water inventory in the steam generators when the reactor is critical and is based upon narrow range instrumentation. The 25.9% indicated level corresponds to the location of the feed ring.

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

The Allowable Value of 500 psia is sufficiently below the full load operating value for steam pressure so as not to interfere with normal plant operation, but still high enough to provide the required protection in the event of excessive steam demand. Since excessive steam demand causes the PCS to cool down, resulting in positive reactivity addition to the core, a reactor trip is required to offset that effect.

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

Palisades Nuclear Plant B 3.3.1-19 05/30/99

RPS Instrumentation B 3.3.1 BASES LCO 8. High Pressurizer Pressure Trip (continued)

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

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

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

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

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

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

10. Loss of Load Trip

-The LCO requires four Loss of Load Trip Function channels to be OPERABLE in MODE 1 with THERMAL POWER

~ 17% RTP.

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

Palisades Nuclear Plant B 3.3.1-20 05/30/99

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

Those RPS trip Functions which are assumed in the safety analyses (all except High Startup Rate and Loss of Load),

are required to be operable in MODES 1 and 2, and in MODES 3, 4, and 5 with more than one full-length control rod capable of being withdrawn and PCS boron concentration less than REFUELING BORON CONCENTRATION.

These trip Functions are not required while in MODES 3, 4, or 5, if PCS boron concentration is at REFUELING BORON CONCENTRATION, or when no more than one full-length control rod is capable of being withdrawn, because the RPS Function is al ready ful fi 11 ed. f REFUELING BORON CONCENTRATION provides sufficient negative reactivity to assure the reactor remains subcritical regardless of control rod position, and the safety analyses afld the SllUTDmdN MARGIN defiflitiofl both use the assumptiofl assume that the highest worth withdrawn full-length control rod will fail to insert on a tript. Therefore, under these conditions, ilfttl- the safety analyses assumptions afld SllUTDOWN MARGIN requiremeflts will be met without the RPS trip Function.

The High Startup Rate Trip Function is required to be OPERABLE in MODES 1 and 2, but may be bypassed when the associated wide range NI channel indicates below lE-4%

power, when poor counting statistics may lead to erroneous indication. It may also be bypassed whefl TllERMAL POWER is above 13l'~ RTP, where moderator temperature coeffi ci eflt afld fuel temperature coefficieflt make high rate of chaflge of power ufllikely. In MODES 3, 4, 5, and 6, the High Startup Rate trip is not required to be OPERABLE. Wide range channels.are required to be OPERABLE in MODES 3, 4, and 5, by LCO 3.3.9, "Neutron Flux Monitoring Channels," and in MODE 6, by LCO 3.9.2, "Nuclear Instrumentation."

The Loss of Load trip is required to be OPERABLE with THERMAL POWER at or above 17% RTP. Below 17% RTP, the ADVs are capable of relieving the pressure due to a Loss of Load event without cha 11 engi ng other overpressure. protection.

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

Palisades Nuclear Plant B 3.3.1-22 05/30/99

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

If one RPS bistable trip unit or associated instrument channel is inoperable, operation is allowed to continue.

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

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

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

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

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

Palisades Nuclear Plant B 3.3.1-24 05/30/99

RPS Instrumentation

BASES ACTIONS (continued)

C.1 B 3.3.1 Condition C applies to the failure of a single Loss of Load or associated instrument channel.

If one trip unit or associated instrument channel fails, it must be restored to OPERABLE status prior to THERMAL POWER

~ 17% RTP following a shutdown. If the plant is shutdown at the time the channel becomes inoperable, then the failed channel must be restored to OPERABLE status prior to THERMAL POWER~ 17% RTP. For this Completion Time, "following a shutdown" means this Required Action does not have to be completed until prior to THERMAL POWER ~ 17% RTP for the first time after the plant has been in MODE 3 following entry into the Condition. The Completion Time is based OR the fact that the safety analyses take RO credit for the fuRctioning of this trip assures that the plant will not be restarted with an inoperable Loss of Load trip channel.

D.1 and D.2 Condition D applies when one or more automatic ZPM Bypass removal channels are inoperable. If the ZPM Bypass removal channel cannot be restored to OPERABLE status, the affected ZPM Bypasses must be immediately removed, or the bypassed RPS trip Function channels must be immediately declared to*

be inoperable. Unless additional circuit failures exist, the ZPM Bypass may be removed by placing the associated "Zero Power Mode Bypass" key operated switch in the normal position.

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

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

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

Palisades Nuclear Plant B 3.3.1-25 05/30/99

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

The Required Actions are modified by a Note stating that LCO 3.0.4 is not applicable. The Note was added to allow the changing of MODES even though two channels are inoperable, with one channel tripped. MODE changes in this configuration are allowed because two trip channels for the affected function remain OPERABLE. A trip occurring in either or both of those channels would cause a reactor trip.

While it is cencepttlally pessible that, if the twe eperable chann~ls were these that de net have total channel separatien in their cable rotltings, a single failtlre cotlld disable both from trippiHg, iH reality, stlch failtlres are extremely tlnlikely. Most failtlres iwvolving a common cable fatllt wotlld catlse the affected channel (s) to fail in the de energized condition, thereby initiating a reacter trip not preveHtiHg one. In this configuration, the protection system is in a one-out-of-two logic, and the probability of a common cause failure affecting both of the OPERABLE channels during the 7 days permitted is remote.

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

Though not required, the other inoperable channel may be (trip channel) bypassed.

This Completion Time is sufficient to allow the operator to take all appropriate actions for the failed channels while ensuring that the risk involved in operating with the failed channels is acceptable. With one channel of protective instrumentation bypassed or inoperable in an unripped condition, the RPS is in a two-out-of-three logic for that function; but with another channel failed, the RPS may be operating in a two-out-of-two logic. This is outside the assumptions made in the analyses and should be corrected.

To correct the problem, one of the inoperable channels is placed in trip. This places the RPS in a one-out-of-two for that function logic. If any of the other unbypassed channels for that function receives a trip signal, the reactor will trip.

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

Palisades Nuclear Plant B 3.3.1-26 05/30/99

RPS Instrumentation

BASES ACTIONS G.1. G.2.1. and G.2.2 (continued)

B 3.3.1 The Completion Time is reasonable, based on operating experience, for placing the plant in MODE 3 from full power conditions in an orderly manner and without challenging plant systems. The Completion Time is also reasonable to ensure that no more than one full-length control rod is capable of being withdrawn or that the PCS boron concentration is at REFUELING BORON CONCENTRATION.

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

While Palisades is Ret cemmitted te perfermiRg all testiRg discussed iR ANSI/IEEE StaRdard 338 1977, CllANNEL CllECKS, CllANNEL FUNCTIONAL TESTS, AND CllANNEL CALIBRATIONS are perfermed iR accerdaRce with the guidaRce ef ANSI/IEEE StaRdard 338 1977, whl ch is eRdersed by Regul atery Gui de 1.118.

SR 3.3.1.1.

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

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

Palisades Nuclear Plant B 3.3.1-28 05/30/99

RPS Instrumentation

BASES SURVEILLANCE REQUIREMENTS SR 3.3.1.1 (continued)

B 3.3.1 The Containment High Pressure and Loss of Load channels are pressure switch actuated. As such, they have no associated control room indicator and do not require a CHANNEL CHECK.

The Frequency, about once every shift, is based on operating experience that demonstrates the rarity of channel failure.

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

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

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

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

Palisades Nuclear Plant B 3.3.1-29 05/30/99

RPS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.5 (continued)

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

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

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

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

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

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

A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and

non-Technical Specifications tests at least once per refueling interval with applicable extensions.

Palisades Nuclear Plant B 3.3.1-31 05/30/99

RPS Logic and Trip Initiation B 3.3.2 BASES LCO 3. Manual Trip (continued)

The LCO requires both Manual Trip channels to be OPERABLE in MODES 1 and 2, and in MODES 3, 4, and 5 when more than one full-length control rod is capable of being withdrawn and the PCS boron concentration is less than REFUELING BORON CONCENTRATION.

Two independent pushbuttons are provided. Each pushbutton is considered to be a channel. Depressing either pushbutton interrupts power to all four clutch power supplies, tripping the reactor.

. APPLICABILITY The RPS Matrix Logic, Trip Initiation Logic, and Manual Trip are required to be OPERABLE in MODES 1 and 2, and in MODES 3, 4, and 5 when more than one full-length control rod capable of being withdrawn and the PCS boron concentration is less than REFUELING BORON CONCENTRATION. This ensures the reactor can be tripped when necessary, but allows for maintenance and testing

when the reactor trip is not needed.

In MODES 3, 4, and 5 with no more than one full-length control rod capable of being withdrawn or the PCS boron concentration at REFUELING BORON CONCENTRATION, these Functions do not have to be OPERABLE. However, LCO 3.3.9, "Neutron Flux Monitoring Channels," does require neutron flux monitoring capability under these conditions.

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

Palisades Nuclear Plant B 3.3.2-6 06/25/99

RPS Logic and Trip Initiation B 3.3.2 BASES ACTIONS A.1 (continued)

Condition A applies if one Matrix Logic channel is inoperable i" aHy appli eabl e t10DE.

The channel must be restored to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . The Completion Time of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months provides the operator time to take appropriate actions and still ensures that any risk involved in operating with a failed channel is acceptable. Operating experience has demonstrated that the probability of a random failure of a second Matrix Logic channel is low during any given 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months interval. If the channel cannot be restored to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , Condition E. is entered.

Condition B applies if one Trip Initiation Logic channel is inoperable iH aHy applicable MODE. The Required Action require de-energizing the affected clutch power supplies. This removes the need for the affected channel by perfonning its associated safety function *. With the clutch power supplies associated with one initiation logic channel de-energized, the remaining two clutch power supplies prevent control rod clutches from de-energizing. The remaining clutch power supplies are in a one-out-of-two logic with respect to the remaining initiation logic channels in the clutch power supply path. This meets redundancy requirements, but testing on the OPERABLE channels cannot be perfonned without causing a reactor trip.

Required Action B.1 provides for de-energizing the affected clutch power supplies associated with the inoperable channel within a Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Palisades Nuclear Plant B 3.3.2-7 06/25/99

I I

RPS Logic and Trip Initiation

BASES ACTIONS B 3.3.2 (continued)

Condition c applies to the failure of one Manual Trip channel in any applicable MODE. With one manual reactor trip channel inoperable operation may continue until the reactor is shut down for other reasons. Repair during operation is not required because one OPERABLE channel is all that is required for safe operation. No safety analyses assume operation of the Manual trip.

The Manual Trip channels are not testable without actually causing a reactor trip, so even if the difficulty were corrected, the post maintenance testing necessary to declare the channel OPERABLE could not be completed during operation.

Because of this, the Required Action is to restore the inoperable channel to OPERABLE status prior to entering MODE 2 from MODE 3 during the next plant startup.

Condition D applies to the failure of both Trip Initiation Logic channels affecting the same trip leg. The affected control rod drive clutch power supplies must be de-energized immediately. With both channels inoperable, the RPS Function is Jost if the affected clutch power supplies are not de-energized. Therefore, immediate action is required to de-energize the affected clutch power supplies. The immediate Completion Time is appropriate since there could be a loss of safety function if the associated clutch power supplies are not de-energized. Entry inte LCD 3.0.3 is net an acceptable alternative in this cenditien.

E.1. E.2.1 and E.2.2 Condition E is entered if Required Actions associated with Condition A, B, C, or D are not met within the required Completion Time or if for one or more Functions more than one Manual Trip, Matrix Logic, or Trip Initiation Logic channel is inoperable for reasons other than Condition D.

In Condition E the reactor must be placed in a MODE in which the LCO does not apply. The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to be in MODE 3 is reasonable, based on operating experience, to reach the required MODE from full power conditions in an orderly manner.and without challenging plant systems *

Palisades Nuclear Plant 8 3.3.2-8 06/25/99

ESF Instrumentation B 3.3.3 BASES BACKGROUND Bistable Trip Units (continued)

There are four channels of bistables, designated A through D, for each ESF Function, one for each measurement channel.

Where bistable trip units are used, theyThe bistables for all required Functions, except CHP and RAS, receive an analog input from the measurement device, compare the analog input to trip setpoints, and provide contact output to the Actuation Logic.

CHP and RAS are actuated by pressure switches and level switches respectively.

There are feur channels ef bistables, designated A threugh D, fer each ESF Funetien, ene fer each measurement channel.

The Allowable Values are specified for each safety related ESF trip Function which is credited in the safety analysis.

Nominal trip setpoints are specified in the plant procedures.

The nominal setpoints are selected to ensure plant parameters do not exceed the Allowable Value if the instrument loop is performing as required. The methodology used to determine the nominal trip setpoints is also provided in plant documents.

Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. Each Allowable Value specified is more conse_rvative than the analytical limit determined in the safety analysis in order to account for uncertainties appropriate to the trip Function. These uncertainties are addressed as described in plant documents. A channel is inoperable if its actual setpoint is not within its Allowable Value.

Setpoints in accordance with the Allowable Value will ensure that Safety Limits of Chapter 2.0, "SAFETY LIMITS (Sls), 11 are not violated during Anticipated Operational Occurrences (AOOs) and that the consequences of Design Basis Accidents (DBAs) will be acceptable, providing the plant is operated from within the LCOs at the onset of the AOO or DBA and the equipment functions as designed.

ESF Instrument Channel Bypasses The only ESF instrument channels with built in bypass capability are the Low SG Level AFAS bistables. Those bypasses are effected by a key operated switch, similar to the RPS Trip Channel Bypasses. A bypassed Low SG Level channel AFAS bistable cannot perform its specified function and must be considered inoperable.

Palisades Nuclear Plant B 3.3.3-7 06/25/99

ESF Instrumentation B 3.3.3 BASES BACKGROUND ESF Instrument Channel Bvpasses (continued)

While there are no other built-in provisions for instrument channel bypasses in the ESF design (bypassing any other channel output requires opening a circuit link, lifting a lead, or using a jumper), this LCO includes requirements for OPERABILITY of the instrument channels and bistables which provide input to the Automatic Bypass Removal Logic channels required by LCO 3.3.4, "ESF Logic and Manual Initiation."

The Actuation Logic channels for Pressurizer Pressure and Steam Generator Low Pressure, however, have the ability to be manually bypassed when the associated pressure is below the range where automatic protection is required. These actuation logic channel bypasses may be manually initiated when three-out-of-four bypass permissive bistables indicate below their setpoint. When two-out-of-four of these bistables are above their bypass permissive setpoint, the actuation logic channel bypass is automatically removed. The bypass permissive bistables use the same four measurement channels as the blocked ESF function for their inputs.

APPLICABLE MaftyEach of the analyzed accidents can be detected by one or more SAFETY ANALYSES ESF Functions. One of the ESF Functions is the primary actuation signal for that accident. An ESF Function may be the primary actuation'signal for more than one type of accident.

An ESF Function may also be a secondary. or backup, actuation signal for one or more other accidents. Functions not specifically credited in the accident analysis, serve as backups and are part of the NRC approved licensing basis for the plant.

Palisades Nuclear Plant B 3.3.3-8 06/25/99

ESF Instrumentation

BASES B 3.3.3 APPLICABILITY All ESF Functions are required to be OPERABLE in MODES 1 21 1 and 3. In addition, Containment High Pressure and Containment High Radiation are required to be operable in MODE 4.

In MODES 1, 2, and 3 there is sufficient energy in the primary and secondary systems to warrant automatic ESF System responses to:

Close the main steam isolation valves to preclude a positive reactivity addition and containment overpressure;

Actuate AFW to preclude the loss of the steam generators as a heat sink (in the event the normal feedwater system is not ava1lable);

Actuate ESF systems to prevent or limit the release of fission product radioactivity to the environment by isolating containment and limiting the containment pressure from exceeding the containment design pressure during a design basis LOCA or MSLB; and Actuate ESF systems to ensure sufficient borated inventory to permit adequate core cooling and reactivity control during a design basis LOCA or MSLB accident.

The CHP and CHR Functions are required to be OPERABLE in MODE 4 to limit leakage of radioactive material from containment and limit operator exposure during and following a OBA.

The SGLP Function is not required to be OPERABLE in MODES 2 and 3, if all MSIVs are closed and deactivated and all MFRVs and MFRV bypass valves are either closed and deactivated or isolated by closed manual valves, since the SGLP Function is not required to perform any safety functions under these conditions.

In lower MODES, automatic actuation of ESF Functions is not required, because adequate time is available for plant operators to evaluate plant conditions and respond by manually operating the ESF components. if reqHired.

LCO 3.3.6 addresses automatic Refueling CHR isolation during CORE ALTERATIONS or during movement of irradiated fuel .

Palisades Nuclear Plant B 3.3.3-16 06/25/99

ESF Instrumentation B 3.3.3 BASES ACTIONS C.1 and C.2 (continued)

Condition C applies to one RAS SIRWT Low Level channel inoperable. The SIRWT low level circuitry is arranged in a "l-out-of-2 taken twice" logic rather than the more frequently used 2-out-of-4 logic. Therefore, Required Action C.1 differs from other ESF functions. With a bypassed SIRWT low level channel, an additional failure might disable automatic RAS, but would not initiate a premature RAS. With a tripped channel, an additional failure could cause a premature RAS, but would not disable the automatic RAS.

Since consi~erable time is available after initiation of SIS until RAS is reqHired aHd there is qHite a toleraHce OH the time wheH RAS must be initiated; and since a premature RAS could damage the ESF pumps, it is preferable to bypass an inoperable channel and risk loss of automatic RAS than to trip a channel and risk a premature RAS.

The Completion Time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months allowed is reasonable because the Required Action involves a circuit modification.

Required Action C.2 requires that the inoperable channel be restored to OPERABLE status within 7 days. The Completion Time is reasonable based upon operating experience, which has demonstrated that a random failure of a second channel occurring during the 7 day period is a low probability event.

D.1 and D.2 If the Required Actions and associated Completion Times of Condition A, B, or C are not met for Functions 1, 2, 3, 4, or 7, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

Palisades Nuclear Plant B 3.3.3-20 06/25/99

ESF Instrumentation

BASES B 3.3.3 ACTIONS E.1 and E.2 (continued)

If the Required Actions and associated Completion Times of Condition A, B, or C are not met for Functions 5 or 6, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE The SRs for any particular ESF Function are found in the REQUIREMENTS SRs column of Table 3.3.3-1 for that Function. Most functions are subject to CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, and CHANNEL CALIBRATION.

While Palisades is Hot committed te performiHg all testiHg disetJssed iH ANSI/IEEE StaHdard 338 1977, CllANNEL CllECKS, CllANNEL FUNCTIONAL TESTS, AND CllANNEL CALIBRATIONS are performed iH aeeordaHee with the gtJidaHee of ANSI/IEEE StaHdard 338 1977, whi eh is eHdorsed by RegtJl atory GtJi de 1.118.

SR 3.3.3.1 A CHANNEL CHECK is perfonned once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months on each ESF input channel which is provided with an indicator to provide a qualitative assurance that the channel is working properly and that its readings are within limits. A CHANNEL CHECK is not perfonned on the CHP and SIRWT Low Level channels because they have no associated control room indicator.

Perfonnance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is nonnally 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 instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to

operate properly between each CHANNEL CALIBRATION.

Palisades Nuclear Plant B 3.3.3-21 06/25/99

ESF Logic and Manual Initiation B 3.3.4 BASES BACKGROUND Manual Initiation (continued)

T~ere are HO siH~le maH~al eoHtrols ~rovided to aet~ate RAS RAS is actuated by manually actuating the circuit "Test" switch, however, RAS may also be manually initiated using individual component controls.

Manual actuation of AFW may be accomplished through pushbutton actuation o.f each AFAS channel or by use of individual pump and valve controls. Each automatic AFAS actuation channel starts the AFW pumps in their starting sequence (if P-8A fails to start, a P-8C start signal is generated, and if P-8C also fails to start, a P-8B start signal is generated) and opens the associated flow control valves.

APPLICABLE MaftyEach of the analyzed accidents can be detected by one or more SAFETY ANALYSES ESF Functions. One of the ESF Functions is the primary actuation signal for that accident. An ESF Function may be the primary actuation signal for more than one type of accident.

An ESF Function may also be a secondary, or backup, actuation signal for one or more other accidents. Functions such as Manual Initiation, not specifically credited in the accident analysis, serve as backups to Functions and are part of the NRC staff approved licensing basis for the plant.

The manual initiation is not required by the accident analysis.

The ESF logic must function in all situations where the ESF function is required (as discussed in the Bases for LCO 3.3.3).

Each ESF Function and its associated safety analyses are discussed in the Applicable Safety Analyses section of the Bases for LCO 3.3.3, ESF Instrumentation.

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

LCO The LCO requires that all components necessary to provide an ESF actuation be OPERABLE.

The Bases for the LCO on ESF automatic actuation Functions are addressed in LCO 3.3.3. Those associated with the Manual Initiation or Actuation Logic are addressed below.

ESF Logic and Manual Initiation Functions are required to be OPERABLE in MODES 1, 2, and 3, or in MODES 1, 2, 3, and 4, as appropriate, when the associated automatic initiation channels

addressed by LCO 3.3.3 are required.

Palisades Nuclear Plant B 3.3.4-4 06/25/99

ESF Logic and Manual Initiation B 3.3.4 BASES LCO 1. Safety Injection Signal (SIS)

(continued)

SIS is actuated by manual initiation, by a CHP signal, or by two-out-of-four Pressurizer Low Pressure channels decreasing below the setpoint. Each Manual Initiation channel consists of one pushbutton which directly starts the SIS actuation logic for the associated train. Each SIS logic train is also actuated by a contact pair on one of the CHP initiation relays for the associated CHP train.

a. Manual Initiation This LCO requires two channels of SIS Manual Initiation to be OPERABLE.

b. Actuation Logic This LCO requires two channels of SIS Actuation Logic to be OPERABLE. Failures in the actuation subsystems are addressed in this LCO.

c. CHP Logic Trains The CHP initiation relay (5P-x) input to the SIS logic is considered part of the SIS logic. Two channels, one per SIS train, must be OPERABLE.

d. Automatic Bypass Removal This LCO requires two channels of the automatic bypass removal logic for SIS Pressurizer Low Pressure to be OPERABLE ifi MODES 1, 2, afid 3. If an SIS automatic actuation channel is bypassed, other than as allowed by Table 3.3.4-1, the channel cannot perform its required safety function and must be considered to be inoperable.

As indicated by footnote (a), the Pressurizer Low Pressure logic train for each SIS train can be bypassed when three-out-of-four channels indicate below 1700 psia. This bypass prevents undesired actuation of SIS during a normal plant cooldown.

The bypass signal is automatically removed when two-out-of-four channels exceed the setpoint, in accordance with the philosophy of removing bypasses when .the enabling conditions are no longer satisfied.

Palisades Nuclear Plant 8 3.3.4-5 06/25/99

ESF Logic and Manual Initiation B 3.3.4 BASES LCO 1. Safety Injection Signal (SIS) (continued)

The bypass pennissive is set low enough so as not to be enabled during nonnal plant operation, but high enough to allow bypassing prior to reaching the trip setpoint.

2. Steam Generator Low Pressure Signal (SGLP)

a. Manual Initiation This LCO requires two channels of SGLP Manual Initiation to be OPERABLE. As indicated by footnote (c), thereThere is no manual control which actuates the SGLP logic circuits. The actuated components must be individually actuated using control room manual controls.

b. Actuation Logic This LCO requires two channels of SGLP Actuation Logic to be OPERABLE, one for each SG.

c. Automatic Bypass Removal This LCO requires two channels, one for each SG, of the SGLP automatic bypass removal logic to be OPERABLE in MODES 1, 2, anti 3. If an SIS automatic actuation channel is bypassed, other than as allowed by Table 3. 3". 4-1, the channel cannot perform its required safety function and must be considered to be inoperable.

As indicated by footnote (b), theffte SGLP from each SG may be bypassed when three-out-of-four channels indicate below 565 psia. This bypass prevents undesired actuation during a normal plant cooldown.

The bypass signal is automatically removed when two-out-of-four channels exceed the setpoint, in accordance with the philosophy of removing bypasses when the enabling conditions are no longer satisfied.

The bypass pennissive is set low enough so as not to be enabled during normal plant operation, but high enough to allo~ bypassing prior to reaching the trip setpoint.

Palisades Nuclear Plant B 3.3.4-6 06/25/99

ESF Logic and Manual Initiation B 3.3.4

BASES LCO (continued)

3. Recirculation Actuation Signal (RAS)

a. Manual Initiation This LCO requires two channels of RAS Manual Initiation to be OPERABLE. There is no manual control of which actuates the RAS logic circuits~

The actuated components must be individually actuated using manual controls.RAS is actuated by manually actuating the circuit "Test" switches.

b. Actuation Logic This LCO requires two channels of RAS Actuation Logic to be OPERABLE.

4. Auxiliary Feedwater Actuation Signal (AFAS)

a. Manual Initiation This LCO requires two channels of AFAS Manual Initiation to be OPERABLE. Each train of AFAS may be manually initiated with either of two sets of controls. Only one set of manual controls is required to be OPERABLE for each AFW train. One set of controls are the pushbuttons provided to actuate each train on the C-11 panel; the other set of controls are those manual controls provided on C-01 for each AFW pump and flow control valve.

b. Actuation Logic This LCQ requires two channels of AFAS Actuation Logic to be OPERABLE.

5. Containment High Pressure Signal (CHP)

a. Manual Initiation As indicated by footnote (c), this ffl-1 LCO requires the manual controls necessary to actuate those valves and components actuated by an automatic CHP to be OPERABLE.

b. Actuation Logic This LCO requires two channels of CHP Actuation Logic to be OPERABLE.

Palisades Nuclear Plant B 3.3.4-7 06/25/99

ESF Logic and Manual Initiation 8 3.3.4

BASES ACTIONS (continued) 8.1 and B.2 If two Manual. Initiation, Bypass Removal, or Actuation Logic channels are inoperable for Functions 1, 2, 3, or 4, or if the Required Action and associated Completion Time of Condition A cannot be met for Function 1, 2, 3, or 4, the reactor must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

C.1 and C.2 Condition C is entered when one.or more Functions have two Manual Initiation or Actuation Logic channels inoperable for Functions 5 or 6, ftftti or when the Required Action and associated Completion Time of Condition A are not met for Functions 5 or 6. If Required Action A.1 cannot be met within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.3.4.1 REQUIREMENTS A functional test of each SIS actuation channel must be performed each 92 days. This test is to be performed using the installed control room test .switches and test circuits for both "with standby power" and "without standby power". When testing the "with standby power" circuits, proper operation of the "SIS-X" relays must be verified; when testing the "without standby power" circuits, proper operation of the "OBA sequencer" and the associated logic circuit must be verified.

The test circuits are designed to block those SIS functions, such as injection of concentrated boric acid, which would interfere with plant operation.

The Frequency of 92 days is a feattlre ef the initial Palisades license based on plant operating experience.

Palisades Nuclear Plant B 3.3.4-10 06/25/99

ESF Logic and Manual Initiation B 3.3.4 BASES SURVEILLANCE SR 3.3.4.2 REQUIREMENTS (continued) A CHANNEL FUNCTIONAL TEST of each AFAS Actuation Logic Channel is perfonned every 92 days to ensure the channel will perfonn its intended function when needed. A successful test of the required contact(s) of a channel relay may be perfonned by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

Instrumentation channel tests are addressed in LCO 3.3.3.

SR 3.3.4.2 addresses Actuation Logic tests of the AFAS using the installed test circuits.

The Frequency of 92 days for SR 3.3.4.2 is in agreement with the conclusions of the reliability analysis presented in topical report CEN-327, "RPS/ESFAS Extended Test Interval Evaluation" (Ref. 2).

SR 3.3.4.3 A CHANNEL FUNCTIONAL TEST is perfonned on the manual ESF aetHatieninitiation channels, bypass remeval ehannels, and Actuation Logic channels, and bypass removal channels for eertainspecified ESF Functions, previding aetHatien ef the FHnetien. A successful test of the required contact(s) of a channel relay may be perfonned by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions.

This Stir¥ei 11 anee ¥erif1 es that the PtanHal Initi ati en FHneti ens are OPERABLE. This Surveillance afs-6 verifies that the enti rerequi red channels ef the Ptarrnal Aettiati en Legi e will perfonn +t-5-their intended functions when needed *

Palisades Nuclear Plant B 3.3.4-11 06/25/99

~-----

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

BASES BACKGROUND _The DGs provide a source of emergency power when offsite power is either unavailable or insufficiently stable to allow safe plant operation. Undervoltage protection will generate a UV Start in the event a Loss of Voltage or Degraded Voltage condition occurs. There are two UV Start Functions for each 2.4 kV vital bus.

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

1. Two levels of automatic undervoltage protection from loss or degradation of offsite power sources are provided.

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

Coincidence logic is provided to preclude spurious trips.

(

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

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

Palisades Nuclear Plant B 3.3.5-1 06/25/99

DG - UV Start B 3.3.5 BASES BACKGROUND Trip Setpoints (continued)

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

APPLICABLE The DG - UV Start is required for Engineered Safety Features SAFETY ANALYSES (ESF) systems to function in any accident with a loss of offsite power. Its design basis is that of the ESF Systems.

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

The required channels of UV Start, in conjunction with the ESF systems powered from the DGs, provide plant protection in the event of any of the analyzed accidents discussed in Reference 6, in which a loss of offsite power is assumed.

UV Start channels are required to meet the redundancy and testability requirements of GDC 21 in 10 CFR 50, Appendix A (Ref. 1).

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

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

The LCO fer the DG UV Start reqliires that three channels per

-bliS ef eaeh UV Start 1nstrlimentat1en Ftlnetion be OPERABLE when the assoeiated DG is reqliired te be OPERABLE. The UV Start Slipports safety systems assoei ated with ESF aettlatl on .

Palisades Nuclear Plant 8 3.3.5-3 06/25/99

DG - UV Start

BASES LCO B 3.3.5 The LCO for the DG - UV Start requires that three channels per bus of each UV Start instrumentation Function be OPERABLE when the associated DG is required to be OPERABLE. The UV Start supports safety systems associated with ESF actuation.

The Bases for the trip setpoints are as follows:

The voltage triR setpoint is set low enou9h such that spurious trips of the offsite source due to operat1on of the undervoltage relays are not expected for any combination of plant loads and normal grid voltages.

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

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

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

APPLICABILITY The DG - UV Start actuation Function is required to be OPERABLE whenever the11 associated DG is required to be OPERABLE per *

LCO 3.8.1, 11 AC Sources - Operating, 11 or LCO 3.8.2, 11 AC Sources

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

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

In the event a channel *s triR setpoint is found nonconservative with respect to the Specified SetpeiRtspecified setpoint, or the channel is found inoperable, then all affected Functions

provided by that channel must be declared inoperable and the LCO Condition entered. The required channels are specified on a per DG basis.-

Palisades Nuclear Plant B 3.3.5-4 06/25/99

Refueling CHR Instrumentation B 3.3.6 B 3.3 INSTRUMENTATION B 3.3.6 Refueling Containment High Radiation (CHR) Instrumentation BASES BACKGROUND This LCO addresses Refueling CHR actuation. When the Refueling CHR Monitors are enabled by their keylock switches, a CHR actuation may be automatically initiated by a signal from either of the Refueling CHR monitors or manually by actuation of either of the control room "CHR Manual Initiate" pushbuttons (pushing either Manual Initiate pushbutton will actuate both trains of CHR). A CHR signal initiates the following actions:

a. Control Room HVAC Emergency Mode;

b. Containment Isolation Valve Closure; and

c. Block automatic starting of Engineered Safeguards pump room sump pumps *

The Refueling CHR signal provides automatic containment isolation valve closure during refueling operations, using two radiation monitors located in the refueling area of the containment {elevation 649 ft). The monitors are part of the plant area monitoring system and employ one-out-of-two logic for isolation. During normal operation these monitors are disconnected from the CHR relays and will not initiate a CHR signal. A switch is provided to connect the Refueling CHR monitors into the CHR actuation circuit, so that CHR actuation can be initiated by these monitors during refueling ett+y.

Each monitor actuates one train of CHR logic when containment radiation exceeds the setpoint. Two separate enabling keylock switches, one per train, enable the Refueling CHR input to the CHR logic when switched to the "Refueling" Medeposition. Each Refueling CHR channel, associated keylock switch, and initiation circuit input to the CHR logic thus forms a one-out-of-one logic input to its associated CHR actuation logic train. The Refueling CHR isolation instrumentation is separate from the CHR instrumentation addressed in LCO 3.3.3, "ESF Instrumentation." However, the Refueling CHR Instrumentation does operate the same CHR actuation relays as the two-out-of-four CHR logic addressed in LCO 3.3.4. This*Lco is not included in LCOs 3.3.3 and 3.3.4 because of the differences in APPLICABILITY and the single channel nature of the Refueling CHR input. The Refueling CHR signal performs the automatic containment isolation valve closure Function during refueling operations required by LCO 3.9.3, "Containment Penetrations."

Palisades Nuclear Plant B 3.3.6-1 06/25/99

Refueling CHR Instrumentation B 3.3.6 BASES BACKGROUND The Refueling CHR Instrumentation provides protection from *

(continued) release of radioactive gases and particulates from the containment in the event a fuel assembly should be severely damaged during handling.

The Refueling CHR Instrumentation will detect any abnormal radiation levels in the containment refueling area and will initiate purge valve closure to limit the release of radioactivity to the environment. The containment purge supply and exhaust valves are closed on a CHR signal when a high radiation level in containment is detected.

The Refueling CHR Instrumentation includes two independent, redundant actuation subsystems, as described above.

Reference 1 describes the Refueling CHR circuitry.

Trip Setpoint No required setpoint is specified because these instruments are not assumed to function by any of the safety analyses.

Typically, the instruments are set at about 25 mR/hr above expected background for planned operations (including movement of the reactor vessel head or internals).

APPLICABLE The Refueling CHR Instrumentation isolates containment in the SAFETY ANALYSES event that area radiation exceeds an established level following a fuel handling accident. This ensures the

radioactive materials are not released directly to the environment and significantly reduces the offsite doses from those calculated by the safety analyses, which do not credit containment isolation (Ref. 2). Either way, i.e., with or without containment isolation, the offsite doses remain within the guidelines of 10 CFR 100.

The Refueling CHR Instrumentation is not required by the fuel handling accident analyses to maintain offsite doses within the guidelines of 10 CFR 100, but eperatiHg experieHee iHclieates tha-t containment isolation would provide a previcles significant reduction of the resulting offsite doses. Therefore, the Refueling CHR Instrumentation satisfies the requirements of Criterion 4 of 10 .CFR 50.36(c)(2) .

Palisades Nuclear Plant B 3.3.6-2 06/25/99

Refueling CHR Instrumentation

BASES LCO B 3.3.6 The LCO for the Refueling CHR Instrumentation requires that two channels of refueling CHR instrumentation and two channels of CHR manual initiation be OPERABLE, including the logic components necessary to initiate Refueling CHR Isolation. The CHR setpoint is chosen to be high enough to avoid inadvertent actuation in the event of normal background radiation fluctuations during fuel handling and movement of the reactor internals, but low enough to alarm and isolate the containment in the event of a Design Basis fuel handling accident.

APPLICABILITY In MODE 5 or 6, the Refueling CHR isolation of containment isolation valves is not normally required to be OPERABLE.

However, during CORE ALTERATIONS or during movement of irradiated fuel within containment, there is the possibility of a fuel handling accident requiring containment isolation on high radiation in containment. Accordingly, the Refueling CHR Instrumentation must be OPERABLE during CORE ALTERATIONS and when moving any irradiated fuel in containment.

In MODES 1, 2, 3 and 4, both the Containment High Pressure (CHP) and CHR signals provide containment isolation as discussed in the Bases for LCO 3.3.3 and LCO 3.3.4.

ACTIONS A.1. A.2.1. and A.2.2 Condition A applies to the failure of one Refueling CHR monitor channel, one CHR Manual Initiate channel, or one of each. The Required Action allows either initiation of a CHR signal by placing the inoperable channel in trip (which accomplishes the safety function of the inoperable channel), or suspension of CORE ALTERATIONS and movement of irradiated fuel assemblies within containment (which places the plant in a condition where the LCO does not apply). The Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is warranted acceptable because one additional channel of each Function remains operable during that* period and the probability of an additional failure occurring during this period is very small.

The suspension of CORE ALTERATIONS and fuel movement shall not preclude completion of movement of a component to a safe position.

Palisades Nuclear Plant B 3.3.6-3 06/25/99

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

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

The availability of PAM instrumentation is important so that responses to corrective actions can be observed and the need for, and magnitude of, further actions can be determined.

These essential The required instruments are identified in the FSAR Appendix 7C (Ref. 1) and ~ddress the recommendations of Regulatory Guide 1.97 (Ref. 2), as required by Supplement 1 to NUREG-0737, 11 TMI Action Items" (Ref. 3). * .

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

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

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

Provide information to the operators that will enable them to determine the potential for causing a gross breach of the barriers to radioactivity release; and

Provide information regarding the release of radioactive materials to allow for early indication of the need to initiate action necessary to protec*t the public and for an estimate of the magnitude of any impending threat.

Palisades Nuclear Plant B 3.3.7-1 06/25/99

PAM Instrumentation B 3.3.7

BASES BACKGROUND (continued)

These key variables are identified in Reference 1 by the plant specific Regulatory Guide 1.97 analyses (Ref. 1). This analysis identified the plant specific Type A and Category 1 variables and provided justification for deviating from the NRC proposed list of Category I variables.

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

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

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

Take the specified. preplanned. manually controlled actions. for which no automatic control is provided. that

are required for safety systems to accomplish their safety functions.

The PAM instrumentation also ensures OPERABILITY of Category I.

non-Type A variables. This ensures the control room operating staff can:

Detennine whether systems important to safety are perfonning their intended functions;

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

Detennine if a gross breach of a barrier has occurred; and

Initiate action necessary to protect the public as well as to obtain an estimate of the magnitude of any impending threat.

PAM instrtlmentatien that satisfies the eefinitien ef Type A in Regtllatery Gtliee 1.97 meets Criterien 3 ef 10 CFR S0.36(c)(2) .

Palisades Nuclear Plant B 3.3.7-2 06/25/99

PAM Instrumentation B 3.3.7

BASES APPLICABLE SAFETY ANALYSES (continued)

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

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

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

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

The exeeptiofl to the two ehaHHel requiremeflt is For Containment Isolation Valve Position. IH this ease indication, the important information is the status of the containment penetrations. The LCO requires one position ifldieator indication channel for each active containment isolation valve-:-

1isted in FSAR ARpendix 7C (Ref. 1). This is sufficieflt to reduHdafltl y verify the i sol ati Ofl status of each i sol able pefletratiofl either via ifldicated status of the active valve afld

~~!~:s~flo~~e~g~o~af~~ ~~:~!:ec:~!~ifl~~fl;iis:l!ii:fla~:~~:rls kfloWfl to be closed aHd deactivated, positiofl iHdicatiofl is Hot

~:;d;~ 1 :~sdi~e~~~esi:~~u~ 5 fl!~e~::~r;edt~: ~~sb~~~~st~~ieatiofl Listed below are discussions of the specified instrument Functions listed in.Table 3.3.7-1. Component identifiers of the sensors, indicators, power supplies, displays, and recorders in each instrument loop are found in Reference 1.

1, 2.

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

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

Palisades Nuclear Plant B 3.3.7-3 06/25/99

PAM Instrumentation

BASES LCO 11, 12.

B 3.3.7 Steam Generator Water Level (wide range) (continued)

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

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

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

CIV position is provided for verification of containment integrity. In the case of CIV position, the important information is the isolation status of the containment penetration. The LCO requires one channel of valve position indication in the control room to be OPERABLE for each active CI¥ in a centainment penetratien flew path CIV listed in FSAR Appendix 7C (Ref. 1). This is sttfficieRt te redttRdaRtly verify the iselatien stattts ef each iselable penetratieR via indicated stattts ef the active valve, as applicable, and prier knewledge ef passhe valve er system bettRdary stattts. This is sufficient to redundantly verify the isolation status of each associated penetration via indicated status of the CIVs, and by knowledge of a passive (check) valve or a closed system boundary.

If a penetration flow path is isolated, position indication for the CIV{s) in the associated penetration flow path is not needed to determine status. Therefore, as indicated in Note (a) the position indication for valves in an isolated penetration flow path is not required to be OPERABLE .

Palisades Nuclear Plant B 3.3.7-6 06/25/99

Alternate Shutdown System

B 3.3 INSTRUMENTATION B 3.3.8 Alternate Shutdown System B 3.3.8 BASES BACKGROUND The Alternate Shutdown System provides the control room operator with sufficient instrumentation and controls to maintain the plant in a safe shutdown condition from a location other than the control*room. This capability is necessary to protect against the possibility that the control room becomes inaccessible. A safe shutdown condition is defined as MODE 3.

With the p'l ant in MODE 3. the Auxiliary Feedwater (AFW) System and the steam generator safety valves or the steam generator atmospheric dump valves can be used to remove core decay heat and meet all safety requirements. The long term supply of water for the AFW System and the ability to borate the Primary Coolant System (PCS) from outside the control room allow extended operation in MODE 3.

lfl order to eflsHre Hse of SHfficieflt compofleflts of the AFW System afld SHfficiel'lt process il'lformatiofl to permit reactor MODE 3 col'ltrol il'I the evel'lt a fire damages eqHipmel'lt afld ci rcHi try of the mai fl feed*water system or the AFW System i fl the cofltrol room. cable spreadil'lg room, Eflgifleered SafegHards AHxiliary Paflel C 33 room, or the corridor betweefl Switchgear Room 1 C al'ld the chargil'lg pHmp rooms, The Auxiliary aHxiliary Hot Shutdown Col'ltrol Panels (C-150/C-150A) have beel'I provided itttd are located in the southwest electrical penetration room.

These panels are comprised of two enclosures, the main enclosure C-150 and an auxiliary enclosure C-150A. The description below combines these two enclosures into one entity "Panel C-150. 11 From this paHel, Panel C-150 provides control of the AFW flow control valves and col'ltrol of AFW turbine steam supply Valve a cal'I be eHabled. Indication of AFW flow, from the steam drivel'I AFW pHmp to both Steam Generators (SGs), water level of both

~. pressurizer pressure, and pressurizer level are eHabled by transfer provided. 11'1 additi Ol'I, primary cool al'lt pressHre (pressHrizer pressHre) is displayed by a primary seflsor dedicated to this HSe. Tral'ls fer of the above mel'lti 0F1ed systems is al'll'IHl'lciated il'I the col'ltrol room. See FSAR Section 7.4 (Ref. 1) for operation via Panel C-150.

The instrumentation and equipment controls that are required are listed in Table 3.3.8-1 .

Palisades Nuclear Plant B 3.3.8-1 06/25/99

Alternate Shutdown System B 3.3.8 BASES BACKGROUND Switches, which transfer control or instrument functions from (continued) the contra l room to the* auxi 1i ary s hutdowfl cofltrol paflel C-150 panel, alarm in the control room when the devices ifl the alterflate hot shutdowfl paflel are eftabledthe C-150 panel is selected.

APPLICABLE The Alternate Shutdown System is required to provide equipment SAFETY ANALYSES at appropriate locations outside the control room with a capability to maintain the plant in a safe condition in MODE 3.

The criteria governing the design and the specific system requirements of the Alternate Shutdown System are located in 10 CFR 50, Appendix A, GDC 19, and Appendix R (Ref. 2).

The Alternate Shutdown System has been identified as an important contributor to the reduction of plant risk to accidents and, therefore, satisfies the requirements of Criterion 4 of 10 CFR 50.36(c)(2) .

LCO The Alternate Shutdown System LCO provides the requirements for the OPERABILITY of one channel of the instrumentation and controls necessary to maintain the plant in MODE 3 from a location other than the control room. The instrumentation and controls required are listed in Table 3.3.8-1 in the accompanying LCO.

Equipment controls that are required by the alternative dedicated method of maintaining MODE 3 are as follows:

1. AFW flow control valves (CV-0727 and CV-0749); and

2. Turbine-driven AFW pump.

Instrumentation systems displayed on the Auxiliary Hot Shutdown Control Panel are:

1. Source range flux monitor;

2. AFW flow (HIC-0727 and HIC-0749C);

3. Pressurizer pressure;

4. Pressurizer level;

5. SG level and pressure; Palisades Nuclear Plant B 3.3.8-2 06/25/99

Alternate Shutdown System

BASES APPLICABILITY B 3.3.8 The Alternate Shutdown System LCO is applicable in MODES 1, 2, and 3. This is required so that the plant can be maintained in MODE 3 for an extended period of time from a location other than the control room.

This LCO is not applicable in MODE 4, 5, or 6. In these MODES, the plant is already subcritical and in the condition of reduced PCS energy. Under these conditions, considerable time is available to restore necessary instrument control Functions if control room instruments or control become unavailable.

ACTIONS A Note has been included that excludes the MODE change restrictions of LCO 3.0.4. This exception allows entry into an applicable MODE while relying on the ACTIONS, even though the ACTIONS may eventually require a plant shutdown. This is

-acceptable due to the low probability of an event requiring this system. The Alternate Shutdown System equipment can generally be repaired during operation without significant risk of spurious trip.

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 3.3.8-1. The Completion Time of the inoperable channel of a Function will be tracked separately for each Function, starting from the time the Condition was entered for that Function.

Condition A addresses the situation where the required channels of the Remote Shutdown System are inoperable. This includes any Function listed in Table 3.3.8-1 as well as the control and transfer switches.

Required Action A.1 is* to restore the channel to OPERABLE I_

status within 30 days. This allows time to complete repairs on the failed channel. The Completion Time is based on operating experience and the low probability of an event that would require evacuation of the control room.

Palisades Nuclear Plant B 3.3.8-4 06/25/99

Neutron Flux Monitoring Channels B 3.3.9

B 3.3 INSTRUMENTATION B 3.3.9 Neutron Flux Monitoring Channels BASES BACKGROUND The neutron flux monitoring channels consist of two combined source range/wide range channels, designated NI-1/3 and NI-2/4.

The wide range portions, (NI-3 and NI-4) provide neutron flux power indication from < lE-7% RTP to > 100% RTP. The source range portions, designated NI-1 and NI-2, provide source range indication over the range of 0.1 to 1E+5 cps.

This LCO addresses MODES 3, 4, and 5. In MODES 1 and 2, the neutron flux monitoring requirements are addressed by LCO 3.3.1, "Reactor Protective System (RPS) Instrumentation."

When the plant is shutdown; both neutron flux monitoring channels must be available to monitor neutron flux. If only one section of a neutron flux monitoring channel (source range or wide range) is functioning, the neutron fl~x monitoring channel may be considered OPERABLE if it is capable of detecting the existing reactor neutron flux. In this

application, the RPS channels need not be OPERABLE since the reactor trip Function is not required. By monitoring neutron flux pewer, loss of SOM caused by boron dilution can be detected as an increase in flux: Two channels must be OPERABLE to provide single failure protection and to facilitate detection of channel failure by providing CHANNEL CHECK capability.

APPLICABLE The wide raR~e neutron flux monitoring channels are necessary SAFETY ANALYSES to monitor core reactivity changes. They are the primary means for detecting, and triggering operator actions to respond to, reactivity transients initiated from conditions in which the RPS is not required to be OPERABLE. The neutron flux monitoring channel *s LCO requirements support compliance with 10 CFR 50, Appendix A, GDC 13 (Ref. 1). The FSAR, Chapters 7 and 14 (Refs. 2 and 3, respectively), describes the specific neutron flux monitoring channel feat~res that are critical to comply with the GDC.

The OPERABILITY of neutron flux monitoring channels is necessary to meet the assumptions of the safety analyses and provide for the detection of reduced SOM.

The neutron flux monitoring channels satisfy Criterion 4 of 10 CFR 50.36(c)(2).

Palisades Nuclear Plant B 3.3.9-1 06/25/99

Neutron Flux Monitoring Channels B 3.3.9

BASES LCO The LCO on the neutron flux monitoring channels ensures that adequate infonnation is available to verify core reactivity conditions while shut down. The safety function of these instruments is to detect changes in core reactivity such as might occur from an inadvertent boron dilution.

Two neutron flux monitoring channels are required to be OPERABLE. If only one section of a neutron flux monitoring channel (source range or wide range) is functioning, the neutron flux monitoring channel may be considered OPERABLE if it is capable of detecting the existing reactor neutron flux.

For example, with the source range count rate indicator functioning properly within its range, and in reasonable agreement with the other source range, a neutron flux monitor channel may be considered OPERABLE even though its wide range indicator is not functioning.

The source range nuclear instrumentation channels, NI-1 and NI-2, provide neutron flux coverage extending an additional one to two decades below the wide range channels for use during refueling, when neutron flux may be extremely low.

This LCO does not require OPERABILITY of the High Startup Rate Trip Function or the Zero Power Mode Bypass Removal Function.

Those functions are addressed in LCO 3.3.1, RPS Instrumentation.

APPLICABILITY In MODES 3; 4, and 5, neutron flux monitoring channels must be OPERABLE to monitor core power for reactivity changes.

In MODES 1 and 2, neutron flux monitoring channels are addressed as part of the RPS in LCO 3.3.1.

The requirements for source range neutron flux monitoring in MODE 6 are addressed in LCO 3.9.2, Nuclear Instrumentation.

11 11

Palisades Nuclear Plant B 3.3.9-2 06/25/99

3,3.4-t INSTRUMfNTATION SYSTEMS TESTS _r(3.~.4--0 Table~.

Instrumentation Surveillance Requirements for Engineered Safety Features CHANNEL CHANNEL FUNCTIONAL CHANNEL Functional Unit CHECK TEST CALIBRATION

[1 J 1. Safety Injection Signal {SIS)

,r&~1 ..J. ~.3]

a. Manual Initiation NA 18 months

b. SIS Lo 1cftire.s.sur..-3er pr.,trure. -Lo~ _.,f!(J.3..... a* NA n-Q; iat i on~Actuat{Qn, ana (a),~JZ.J. 3 .<f.l] NA ow p)'essure ltiock aUto re~et

~1\.),),ft3)

c. 18 months NA

d. Pre surizer Pressure 31 days r.

Inst ment Channels

[§] 2. Recirculation Actuation Signal {RAS) 3 ... 4.3]

a. Manual Initiation NA 18 months NA

b. RAS Logic NA 18 months NA

c. SIRWT Level Switches A 18 months months

[t.] 3. Auxiliary Feedwater Actuation Signal {AFAS)

~ie ~. :J. '"* 3 J

a. Manual Initiation NA 18 months NA

~~3.~.4-.~

b. AFAS Logic NA 92 days NA

c. "A" S!\;vel 1 31 days 18 months

d. 11 8 SG evel 11 urs 31 days 18 months

[.sit "3 .1.11.i] {a) .

[jll 1,J,,ll.l]

Amendment No. ~' 64, ~

4-77

ATTACHMENT 3

M.1 (continued)

DISCUSSION OF CHANGES SPECIFICATION 3.3.3, ESF INSTRUMENTATION CTS 3 .17. 2 is applicable when the plant is above 300 °F. CTS Required Actions 3.17.2.Sb requires the plant to be "in a condition where the affected equipment is not required within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months ." For CTS LCO 3.17.2, that would be below 300°F. ITS LCO 3.0.3 requires "the plant shall be placed in a MODE or other specified condition in which the LCO is not applicable." ITS LCO allows 31 hours3.587963e-4 days 0.00861 hours 5.125661e-5 weeks 1.17955e-5 months to be in MODE 4 (i.e., below 300°F). Again, since the required action is the same, and the completion time is shortened, this change is considered to be More Restrictive.

Therefore the replacement of CTS 3.17.2.5 wording "or if the number of operable channels is less than specified in the "Minimum Operable Channels" and reliance upon the requirements of ITS LCO 3~0.3 will result in a More Restrictive Change. This change is consistent with NUREG-1432.

M.2 Both CTS 3.17.2.5 and ITS 3.3.3 Condition D contain Required Actions to be taken when any Required Action is not completed and the associated completion time has expired. In CTS, these Required Actions are to place the reactor in HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and place the reactor in a condition where the affected equipment is not required, within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . In ITS LCO 3.3.3 these Required Actions are to be in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and to be in MODE 4 within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months (for functions which are addressed by CTS LCO 3.17.2).

The CTS "Operating Condition" definitions differ from the ITS "MODE" definitions of the same name.

CTS Required Actions 3.17.2.5a requires the plant to be in Hot Shutdown (i.e., subcritical) within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ; ITS Required Action 3.3.3 D.l requires the plant to be in MODE 3 (subcritical) within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . When starting from power operation, the entry conditions for CTS Hot Shutdown and ITS MODE 3 are essentially identical; when the plant is subcritical. Since the required action is the same, and the completion time is shortened, this change is considered to be More Restrictive.

CTS 3.17 .2 is applicable when the plant is above 300°F. CTS Required Actions 3.17.2.5b requires the plant to be placed "in a condition where the affected equipment is not required within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months ." For CTS LCO 3.17.2, that would be below 300°F. ITS Required Action 3.3.3 D.2 requires to be in MODE 4 (i.e., below 300°F) within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . Again, since the required action is the same, and the completion time is shortened, this change is considered to be More Restrictive.

Therefore the replacement of the CTS 3.17.2.5 requirements to be taken ~when any Required Action is not completed and the associated completion time has expired" by ITS Required Actions 3.3.3 D.l_and D.2 will result in a More Restrictive Change.

This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 4 of 8 06/25/99

ATTACHMENT 3

M.4 DISCUSSION OF CHANGES SPECIFICATION 3.3.3, ESF INSTRUMENTATION Both CTS 3.17.3.5 and ITS 3.3.3 Condition E contain Required Actions to be taken when any Required Action is not completed and the associated completion time has expired. In CTS, these Required Actions are to place the reactor in HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and place the reactor in a condition where the affected equipment is not required, within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . In ITS LCO 3.3.3 these Required Actions are to be in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and to be in MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (for functions which are addressed by CTS LCO 3.17.3).

The CTS "Operating Condition" definitions differ from the ITS "MODE" definitions of the same name.

CTS Required Actions 3.17.3.5a requires the plant to be in Hot Shutdown (i.e., subcritical) within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ; ITS Required Action 3.3.3 E.1 requires the plant to be in MODE 3 (subcritical) within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . When starting from power operation, the entry conditions for CTS Hot Shutdown and ITS MODE 3 are essentially identical; when the plant is subcritical. Since the required action is the same, and the completion time is shortened, this change is considered to be More Restrictive.

CTS 3 .17. 3 is applicable when the plant is above 210 °F. CTS Required Actions 3.17.3.5b requires the plant to be placed "in a condition where the affected equipment is not required within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months ." For CTS LCO 3.17.3, that would be below 210°F. ITS Required Action 3.3.3 E.2 requires to be in MODE 5 (i.e., below 200°F) within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . Again, since the required action is essentially the same, and the completion time is shortened, this change is considered to be More Restrictive.

Therefore the replacement of the CTS 3.17.3.5 requirements to be taken "when any Required Action is not completed and the associated completion time has expired" by ITS Required Actions 3.3.3 E.1 and E.2 will result in a More Restrictive Change.

This change is consistent with NUREG-1432.

M.5 The Allowable Value for the upper limit on CHP actuation has been reduced from 4.4 psig to 4.3 psig to assure that there is adequate margin for instrument tolerances.

During review of the allowed values for the Containment High Pressure (CHP)

Engineered Safety Feature (ESF) actuation setpoint for the Improved Technical Specification project, it was determined that the upper limit of 4.4 psig specified in current Technical Specification Table 3.16 Item 2 was not consistent with the assumptions of the FSAR Chapter 14.18 containment response analyses. The containment response analyses assume that the CHP ESF actuation occurs prior to containment pressure exceeding 4.3 psig, when allowance is made for the allowed "as found" calibration tolerances for the actual CHP ESF pressure switches. This change is more restrictive with respect t~ requiring a more rapid actuation following postulated LOCA or MSLB event. The 4.3 psig setting limit is that currently used by the plant, and is the setting required by the Operating Requirements Manual.

Palisades Nuclear Plant Page 6 of 8 06/25/99

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.3.4, ESF LOGIC AND MANUAL INITIATION A.5 CTS 3.17.3 requires the instrumentation channels to be OPERABLE except as allowed by the permissible operations bypasses. Reference to operational bypasses is revised such that they are specifically addressed in the ITS. In addition, the overall Applicability of this Specification is when the PCS is above COLD SHUTDOWN.

The Applicability of ITS 3. 3. 4 is "According to Table 3. 3 .4-1. " ITS Table 3. 3 .4-1 includes a MODES column where the Applicable conditions are included for each Function. The ITS Applicability associated with CTS Table 3.17.3 is MODES 1, 2, 3, and4.

The differences in the applicability between the CTS and ITS are negligible.

For the CTS COLD SHUTDOWN versus the ITS MODE 5, the temperature requirement is being less than 210°F versus being less than 200°F in the ITS.

This difference which is common between the CTS terms HOT SHUTDOWN and COLD SHUTDOWN and the corresponding ITS MODES 3 and 5 is the reactivity condition. The ITS MODE 3 and 5 are defined, as a reference point, by a reactivity condition of Keff < .99. However, in ITS Section 3 .1, the equivalent amount of SHUTDOWN MARGIN is required as that specified in the CTS definitions of HOT SHUTDOWN and COLD SHUTDOWN.

Therefore, the amount of SHUTDOWN MARGIN is considered to be same when the requirements of proposed ITS 3.1 are considered. These changes with respect to the Applicability are all considered to be administrative in that there is no significant impact to operation of the plant and they reflect the terminology and usage rules of NUREG-1432.

A.6 The requirements of CTS Tables 3.17.2 and 3.17.3 are revised to incorporate Footnote (c), which states that manual initiation may be achieved by individual component controls, and is applicable to Manual Initiation for Function 4.a (SGLP). This footnote is equivalent to the CTS entry requiring "1 set [of controls]/train, and is added to clarify that use of any individual component controls to actuate the SGLP Function is adequate. This change is considered to be administrative, in that it only provides clarification and does not alter any technical requirements.

A. 7 Not used .

Palisades Nuclear Plant Page 2 of 8 06/25/99

ATTACHMENT 3

M.2 DISCUSSION OF CHANGES SPECIFICATION 3.3.4, ESF LOGIC AND MANUAL INITIATION Both CTS 3.17.2.5 and ITS 3.3.4 Condition B contain Required Actions to be taken when any Required Action is not completed and the associated completion time has expired. In CTS, these Required Actions are to place the reactor in HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and place the reactor in a condition where the affected equipment is not required, within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . In ITS LCO 3.3.4 these Required Actions are to be in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and to be in MODE 4 within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months (for functions which are addressed by CTS LCO 3.17.2).

The CTS "Operating Condition" definitions differ from the ITS "MODE" definitions of the same name.

CTS Required.Actions 3.17.2.5a requires the plant to be in Hot Shutdown (i.e., subcritical) within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ; ITS Required Action 3.3.4 B.1 requires the plant to be in MODE 3 (subcritical) within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . When starting from power operation, the entry conditions for CTS Hot Shutdown and ITS MODE 3 are essentially identical;

when the plant is subcritical. Since the required action is the same, and the completion time is shortened, this change is considered to be More Restrictive.

CTS 3.17.2 is applicable when the plant is above 300°F. CTS Required Actions 3.17.2.5b requires the plant to be placed "in a condition where the affected equipment is not required within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months ." For CTS LCO 3.17.2, that would be below 300°F. ITS Required Action 3.3.4 B.2 requires to be in MODE 4 (i.e., below 300°F) within 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . Again, since the required action is the same, and the completion time is shortened, this change is considered to be More Restrictive.

Therefore the replacement of the CTS 3.17.2.5 requirements to be taken "when any Required Action is not completed and the associated completion time has expired" by ITS Required Actions 3.3.4 B. l and B.2 will result in a More Restrictive Change.

This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 4 of 8 06/25/99

ATTACHMENT 3

M.4 DISCUSSION OF CHANGES SPECIFICATION 3.3.4, ESF LOGIC AND MANUAL INITIATION Both CTS 3.17.3.5 and ITS 3.3.4 Condition C contain Required Actions to be taken when any Required Action is not completed and the associated completion time has expired. In CTS, these Required Actions are to place the reactor in HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and place the reactor in a condition where the affected equipment is not required, within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . In ITS LCO 3.3.4 these Required Actions are to be in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and to be in MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months (for functions which are addressed by CTS LCO 3.17.3).

The CTS "Operating Condition" definitions differ from the ITS "MODE" definitions of the same name.

CTS Required Actions 3.17.3.5a requires the plant to be in Hot Shutdown (i.e., subcritical) within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ; ITS Required Action 3.3.4 C. l requires the plant to be in MODE 3 (subcritical) within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . When starting from power operation, the entry conditions for CTS Hot Shutdown and ITS MODE 3 are essentially identical; when the plant is subcritical. Since the required action is the same, and the completion time is shortened, this change is considered to be More Restrictive.

CTS 3.17.3 is applicable when the plant is above 210°F. CTS Required Actions 3.17.3.5b requires the plant to be placed "in a condition where the affected equipment is not required within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months ." For CTS LCO 3 .17. 3, that would be below 210°F. ITS Required Action 3.3.4 C.2 requires to be in MODE 5 (i.e., below 200°F) within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . Again, since the required action is essentially the same, and the completion time is shortened, this change is considered to be More Restrictive.

Therefore the replacement of the CTS 3.17.3.5 requirements to be taken "when any Required Action is not completed and the associated completion time has expired" by ITS Required Actions 3.3.4 C.1 and C.2 will result in a More Restrictive Change.

This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 6 of 8 06/25/99

ATTACHMENT 3

ADMINISTRATIVE CHANGES (A)

A. l DISCUSSION OF CHANGES SPECIFICATION 3.3.8, ALTERNATE SHUTDOWN SYSTEM The proposed change will reformat, renumber, and reword the Current Technical Specifications (CTS), with no change of intent, to be consistent with NUREG-1432.

As a result, the Improved Technical Specifications (ITS) should be more easily readable and, therefore, understandable by plant operators, as well as other users.

During the Palisades Nuclear Plant ITS development, certain wording preferences or conventions were adopted which resulted in no technical changes to the CTS.

Additional information may also have been added to more fully describe each LCO and to be consistent with NUREG-1432. However, the additional information does not change the intent of the CTS. The reformatting, renumbering, and rewording process involves no technical changes to CTS.

A.2 CTS 3.17.5 is applicable when the PCS temperature is > 300°F. ITS 3.3.8 is applicable in MODES 1, 2, and 3. In accordance with ITS Table 1.1-1 average reactor coolant temperature must be > 300°F while in MOD:p8 1, 2, and 3. As such, this change is administrative. This change is consistent with NUREG-1432.

A.3 A Note was added to CTS 3.17.5 Actions which allows separate Condition entry for each function. The Note in ITS 3.3.8 provides explicit instructions for proper application of the Actions for Technical Specification compliance. In conjunction with the proposed Specification 1.3 - "Completion Times," this Note provides direction consistent with the intent of the existing Actions for the Alternate Shutdown System.

As such, this change is administrative. This change is consistent with NUREG-1432.

A.4 CTS Table 3.17.5 specifies the number of channels required to be Operable for Functions 19 and 20. ITS SR 3.3.8.2 requires verification that each Alternate Shutdown System control circuit and transfer switch is capable of performing its intended function every 18 months. In conjunction with the proposed Specification 1.1 definition of OPERABLE-OPERABILITY, ITS SR 3.3.8.2 provides direction consistent with the intent of the existing Specification for the Alternate Shutdown System. As such, this change is administrative. This change is consistent with NUREG-1432. .

Palisades Nuclear Plant Page 1of5 06/25/99

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.3.10, ESRV INSTRUMENTATION ADMINISTRATIVE CHANGES (A)

A. l A separate specification is proposed to maintain current licensing basis for the Engineered Safeguards (ES) Pump Room Radiation Monitors of CTS 3.16, 3.17, and 4.17. Proposed ITS 3.3.10, "Engineered Safeguards Room Ventilation (ESRV) Instrumentation," contains the Limiting Conditions for Operation, Applicability, Actions, and Surveillance Requirements to ensure an assumption of the radiological consequences analysis of the Loss of Coolant Accident (LOCA) is maintained. The analysis results are based on an assumption of automatic isolation of the ES pump rooms upon detection of high radiation levels following initiation of the recirculation phase of operation. All reformatting is in accordance with NUREG-1432. As a result, the Technical Specifications (TS) should be more readily readable, and therefore understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is made for consistency with similar Specifications within NUREG-1432. During Improved Technical Specification (ITS) development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or implied) to the TS. Additional information has also been added to more fully describe each subsection. This wording is consistent with NUREG-1432. Since the design is already approved by the NRC, adding more details does not result in a technical change. This is a change in format only with no associated changes in the requirements. Therefore, this change is administrative.

A.2 A Note was added to CTS 3.17.3.4 Actions which allows separate Condition entry for each channel. The Actions Note in ITS 3.3.10 provides explicit instructions for proper application of the Actions for Technical Specification compliance. In conjunction with the proposed Specification 1.3 - "Completion Times," this Note provides direction consistent with the intent of the existing Actions for the ESRV Instrumentation. As such, this change is administrative. This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 1of3 05/30/99

MORE RESTRICTIVE CHANGES (M)

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.3.10, ESRV INSTRUMENTATION M.l CTS 3.17.3.5 requires specific Actions when "any action required by CTS 3.17.3 is not met AND the associated completion time has expired." These Actions are to place the reactor in HOT SHUTDOWN within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , and in a condition where the affected equipment is not required within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . Based on the current Applicability of CTS 3.17.3, the condition where the affected equipment is not required is when the PCS is at or below COLD SHUTDOWN. In the ITS, the Required Action when the "Required Action and associated Completion Times are not met" is to enter ITS LCO 3.0.3, which requires that the plant be in MODE 3 in 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months and in MODE 5 in 37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months .

For the CTS COLD SHUTDOWN, the temperature requirement is less than 210°F, versus the ITS MODE 5 which has a temperature requirement of less than 200°F. The difference of 10 degrees is negligible and has no significant impact on operations. The other parameter which is common between the CTS HOT SHUTDOWN and COLD SHUTDOWN MODES and the corresponding ITS MODES 3, 4 and 5 is the reactivity condition. The ITS MODE 3, 4, and 5 are defined, as a reference point, by a reactivity condition of ~11 <0.99. However, in ITS Section 3.1, the equivalent amount of SHUTDOWN MARGIN is required as that specified in the CTS definitions of HOT SHUTDOWN and COLD SHUTDOWN. Therefore, the amount of SHUTDOWN MARGIN is considered to be same when the requirements of proposed ITS 3.1 are considered.

Since this change will require the plant to be in a lower MODE in a shorter time frame, this change is considered more restrictive. This change is appropriate because it continues to provide adequate time for an orderly plant shutdown without challenging plant systems.

This change imposes additional restrictions on plant operations and is consistent with the content of similar Specifications within NUREG-1432.

LESS RESTRICTIVE CHANGES - REMOVAL OF DETAILS TO LICENSEE CONTROLLED DOCUMENTS (LA)

LA.1 CTS Tables 3.17.3 and 4.17.3 contain detairs related to ESRV Instrumentation component identification. These details are not retained in the ITS and are relocated to the Bases.

These details are not necessary to ensure OPERABILITY of the ESRV Instrumentation ..

ITS 3.3.10 establishes the necessary requirements to ensure ESRV Instrumentation OPERABILITY, and therefore these details are not required to be in the Technical Specifications to provide adequate protection of the public health and safety. Any changes to these requirements in the Bases will require compliance with the Bases Change Control Program, as described in ITS Section 5.0. This change is a less restrictive movement of details change with no impact on safety. This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 2 of 3 05/30/99

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.3.10, ESRV INSTRUMENTATION LESS RESTRICTIVE CHANGES (L)

There were no "Less Restrictive" changes associated with this specification .

Palisades Nuclear Plant Page 3 of 3 05/30/99

RELOCATIONS (R)

ATTACHMENT 3 DISCUSSION OF CHANGES SECTION 3.3, INSTRUMENTATION R.1 CTS 3.8.ld requires radiation levels in the containment to be monitored continuously during refueling operations. CTS 3.8.2 provides the required actions to be taken when CTS 3.8.ld is not met. These requirements are being relocated to the Operational Requirements Manual (ORM). The radiation monitoring instrumentation is used to

monitor radiation levels throughout the plant. Some radiation monitoring instrumentation provide inputs to safety systems in order for these systems to mitigate Design Basis Accidents (DBAs). The radiation monitors in this section are not required to mitigate any DBAs, nor do they provide input into any system required to mitigate DBAs. These radiation monitors do not meet any criteria in 10 CPR 50.36(c)(2)(ii). Therefore, per 10 CPR 50.36(c)(2)(ii), this Specification can be relocated out of the Technical Specifications. Any changes to these requirements will require a 10 CPR 50.59 evaluation. This change is consistent with NUREG-1432.

R.2 CTS 3.17.6, Table 3.17.6, items 3, 4, 5, and 6, and associated Note(a), and CTS Table 4.17.6, items 3, 4, 5, and 6, contain operating requirements for instrumentation that monitors safety injection refueling water tank temperature (CTS 3.17.6.3), main feedwater flow (CTS 3.17.6.4), and temperature (CTS 3.17.6.5), and auxiliary feedwater flow (CTS 3 .17. 6. 6 and 3 .17. 6. 7). These requirements are being relocated to the Operational Requirements Manual (ORM). These instruments do not provide inputs to safety systems in order for these systems to mitigate Design Basis Accidents (DBAs).

They are not required to mitigate any DBAs, nor do they provide input into any system required to mitigate DBAs. These monitors do not provide a Type A or Category 1 post accident monitoring function; further, these monitors do not meet any criteria in 10 CPR 50.36(c)(2)(ii). Therefore, per 10 CPR 50.36(c)(2)(ii), these Specifications can be relocated out of the Technical Specifications. Any changes to these requirements will require a 10 CPR 50.59 evaluation. This change is consistent with NUREG-1432.

R.3 CTS 3.17.6, Table 3.17.6, items 8, 9, 10, and 11, and associated Note(a), and Table 4.17.6, items 8, 9, 10, 11, and associated Note(c), contain requirements for primary safety valve position indicator (CTS 3.17.6.8), PORV position indicators (CTS 3.17.6.9),

PORV block valve position indicator (CTS 3 .17. 6.10), and for the service water break detector (CTS 3.17.6.11). These requirements are proposed to be relocated to the Operational Requirements Manuhl (ORM). These instruments provide indications to the operator in the event of an abnormal condition associated with the specific monitored parameters. These instruments do not provide inputs to safety systems in order for these systems to mitigate Design Basis Accidents (DBAs). These instruments are not required to mitigate any DBAs, nor do they provide input into any system required to mitigate DBAs.

These instruments monitors do not meet any criteria in 10 CPR 50.36(c)(2)(ii). Therefore,

per 10 CPR 50.36(c)(2)(ii), these Specifications can be relocated out of the Technical Specifications. Any changes to these requirements will be made under the provisions of 10 CPR 50.59. This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 1of2 05/30/99

ATTACHMENT 3 DISCUSSION OF CHANGES SECTION 3.3, INSTRUMENTATION R.4 CTS Table 3.17.6, item 19, and associated Note(b), requires two fuel pool area radiation monitors to be operable at HOT STANDBY condition and above. CTS 3.17.6.19 requires the plant to stop moving fuel within the fuel pool area and to restore the monitor to OPERABLE status or provide equivalent monitoring capability within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . CTS Table 4.17.6, item 19, requires periodic surveillances on these monitors. These requirements are being relocated to the Operational Requirements Manual (ORM). These instruments do not provide inputs to safety systems in order for these systems to mitigate DBAs. The fuel pool area radiation monitors are not required to mitigate any DBAs, nor do they provide input into any system required to mitigate DBAs. These radiation monitors do not meet any criteria in 10 CPR 50.36(c)(2)(ii). Therefore, per 10 CPR 50.36(c)(2)(ii), this Specification can be relocated out of the Technical Specifications. Any changes to these requirements will require a 10 CPR 50.59 evaluation. This change is consistent with NUREG-1432.

R.5 CTS Table 3.17.6, item 12 (the Flux - AT alarm), the associated Action Statements (3.17.6.12.1and2), and Surveillance Requirements 4.17.6.12, have been relocated to the ORM. The Flux - AT alarm does not provide any inputs to safety systems or initiate any .

automatic actions. This alarm monitors the two input signals to the Variable High Power Trip auctioneer circuit and alarms if these signals differ by more than a pre-determined amount. The Flux - AT alarm do not meet any criteria in 10 CPR 50.36(c)(2)(ii).

Therefore, per 10 CPR 50.36(c)(2)(ii), this Specification can be relocated out of the Technical Specifications. Any changes to these requirements will require a 10 CPR 50.59 evaluation. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 2 of 2 05/30/99

ENCLOSURE 3 CONSUMERS ENERGY COMPANY PALISADES PLANT DOCKET 50-255 CONVERSION TO IMPROVED TECHNICAL SPECIFICATIONS CHANGES TO ITS SECTION 3.5

_I

ECCS-Shutdown 3.5.3

3.5 3.5.3 EMERGENCY CORE COOLING SYSTEMS (ECCS)

ECCS-Shutdown LCO 3.5.3 One~ jlressure /afety fl,jection cl!Ps1) train shall be OPERAS E.

fr_tJStRT } - )

MODE 3 with (D~lSfi~~'§ttreiflfn ~P'riz&Qf]f1tt,'(. '- .3~S 0 APPLICABILITY: f MODE 4.

IN1f1cdc. cu:.+10" to .

re.\tote one. L.Psl t.~1 l'\

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME L

A. Required >SI train A. l Resto e required SI 11 l)tur\

inoperable. trai to OPERABL sta us. 1mmc~1ci-k-.(1 B. Re ired Action and 8.1 a ociated Completi n me not met.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY o.,.to Sr"'~°"

n ,;,5.t, " &"5. *OPc.ra.+-11\~

SR 3.5.3.l The following SR~re applicabre: In accordance with applicable lli~t SRs SR 3.5.2.4 I*

CEOG STS 3.5-8 1 Rev 1, 04/07/95

ECCS-Shutdown B 3.5.3 BASES LCO (continued) a.-t ~cw+ ofk

~.J V.. MobG" ft.s -tt.o.ft.ni,.-\t>~ >- :3~ op APPLICABILITY In MODES I"' 2, and/ 3 with (Res pressure ~ I/Ou DSlal the OPERABILITY requirements for ECCS are covered by LCO 3.5.2.

(tl 1c.~ " !~ *5 In MODE 3 with <RcS/pres 110 o i and in MOOE 4, one OPERABLE ECCS train is acceptable without single failure consideration, based on the stable reactivity condition of the reactor and the limited core cooling requirements.

In HODES 5 and 6, unit conditions are such that the probability of an event requiring ECCS injection is extremely low. Core cooling requirements in MODE 5 are addressed by LCO 3.4.7, *Res Loops-MOOE 5, Loops Filled,*

and LCO 3.4.8, nRCS Loops-MODE 5, Loops Not Filled.,"

MODE 6 core cooling requirements are addressed by LCO 3.9.4, "Shutdown Cooling (SOC) and Coolant Circulation-High Water Level,* and LCO 3.9.5, "Shutdown Cooling (SOC) and Coolant Circulation-Low Water Level.*

,/r ACTIONS A.I *

- l With no QWSI i.."61;...

OPERABLE, the ~i~

-Pl.o.cif' re ared to respond to

oss of coolant acc;~ent.

!innbltQ~omP'!etion i ilRJ to restore at least one Jw SI train to Ac:kDn irust OPERABLE' status, ensures that prompt action is taken to (continued)

CEOG STS B 3. 5-21 Rev 1, 04/07 /95 l'ht tm trcd 1:rk c.o~ /t.t10ri 1ime. re ffeds

i +he: l~f'of't-a.nc.t. o.f: ma..1n+a.1n1n(j o."'

OP!K~ill LPs I tru..in Q." d

ECCS~Shutdown B 3.5.3 BASES ACTIONS A.I (continued) 10 When he Required Action can ot be completed within the req red Completion Time, controlled shutdown should b ini iated. Twenty-four ho rs is reasonable, based on op rating experience, to each MODE 5 in an orderly ma a without challenging lant systems.

SURVEILLANCE SR 3.5.3.1 REQUIREMENTS The applicable Surveillance descriptions from Bases 3.5.2 apply.

REFERENCES The applicable references from Bases 3.5.2 apply.

CEOG STS B 3.5-22 Rev 1, 04/07/95

Change ATTACHMENT 6 JUSTIFICATION FOR DEVIATIONS SPECIFICATION 3.5.3, ECCS - SHUTDOWN Discussion

9. The listing of applicable SRs contained in ISTS SR 3.5.3.1 has been modified to reflect the requirements of proposed ITS 3.5.3. Specifically, the following ISTS SRs were deleted:

ISTS SR 3. 5. 2 .1 - The intent of this SR is to preclude ECCS pump damage as a result of the ESP Pump Mini Flow valves being closed when PCS pressure is greater than the shut-off head of the ECCS pumps. This SR is not required in ITS 3. 5. 3 since PCS pressure will remain below the shut-off head of the HPSI pumps when PCS temperature is < 325°P.

ISTS SR 3.5.2.3 - This SR does not apply to this facility ..

ISTS SR 3.5.2.6 and ISTS SR 3.5.2.7 - These SRs test the automatic actuation of ECCS pumps and valves. Since ITS 3.5.3 does not rely on automatic actuation, these SRs are not applicable.

ISTS SR 3.5.2.9 - This SR addresses safety injection valves which have stops to properly position the valve. Since the flow rates associated with an ECCS train in MODE 3 with PCS temperature < 325 °P and in MODE 4 are less than the flow rates associated with an ECCS train in MODES 1and2 and MODE 3 with PCS temperature

> 325 °P, this SR is not applicable to the requirements of ITS 3. 5. 3.

10. The Actions for an inoperable ECCS train have been modified to reflect the Palisades design. That is, if the required LPSI train is inoperable, actions must be initiate immediately to restore one LPSI train to Operable status. The inability to maintain one LPSI train Operable would, in most cases, be caused by the concurrent inoperability of both LPSI pumps. Since the LPSI pumps also function as the Shutdown Cooling pumps, placing the plant in Mode 5 within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months may not be practicable due to the loss of forced PCS cooling. Therefore, the appropriate actions are to immediately initiate corrective measures and to continue these actions until one LPSI pump is restored to Operable status. The modified Required Actions for an inoperable LPSI train are consistent with the Required Actions for two inoperable SDC trains as presented in Specification 3.4.6, "PCS Loops - Mode 4."

Palisades Nuclear Plant Page 3 of 3 06/16/99

ENCLOSURE 4 CONSUMERS ENERGY COMPANY

. PALISADES PLANT DOCKET 50-255 CONVERSION TO IMPROVED TECHNICAL SPECIFICATIONS CHANGES TO ITS SECTION 3.6

DISCUSSION OF SECTION 3.6 CHANGES The following changes have been made to ITS Section 3.6; a) Several editorial changes have been made to ITS Section 3.6 in response to additional .

NRC comments from our July 1, 1999 meeting with the Staff. Each comment is discussed below and marked-up pages from our former submittal have been provided to show the corrections which we have made. (See marked-up pages listed after each comment, below) b) The Service Water flow rate required by SR 3.6.6.4 for the Containment Air Coolers has been revised to reflect recent changes to the safety analyses and system flow balancing. A conforming change has been made to the Bases. No equivalent to ITS SR 3.6.6.4 exists in CTS, so this change does not affect any of the supporting DOCs of JFDs. (See STS pages 3.6-23 and B 3.6-62, and ITS pages 3.6.6-2 and B 3.6.6-9) c) The Bases for SR 3.6.2.1 has been revised to include a clarification of the relationship between the ITS term "Containment Operability" and the Appendix J term "Containment Integrity". This clarification is necessary because 10 CFR 50, Appendix J Air Lock Testing requirements differ for periods when a plant's technical specifications require containment integrity and when they do not. The ITS do not utilize the term "Containment Integrity;" the term "containment operability is used in its place. (See STS page B 3.6-17, ITS page B 3.6.2-7, and LCO 3.6.2 JFD page 2 of 2)

Marked-up pages, showing the changes, are provided in this Enclosure; clean pages are provided in Enclosures 6 and 7.

The comments on our Section 3.6 RAI response were:

1) In the response to RAI 3.6.1-1, the marked-up of the DOC page showing deletion of 3.6.1 DOC A.5 was omitted.

A marked-up of page 2 of 6 of the 3.6.1 DOCs has been provided.

2) On STS Bases page B 3.6-1, all of the TSTF-52 changes were not incorporated and no JFD was provided.

A new JFD, 3.6.1 JFD-12 has been provided and noted in the STS marked-up. (See STS marked-up page B 3.6-1 and 3.6.1 JFD page 2 of 2)

3) On STS Bases page B 3.6-4, the sentence "Failure to meet ... to exceed limits." was deleted. This sentence should be retained, and modified to address the requirements of proposed SRs 3.6.1.1 and 3.6.1.3.

The Bases were revised as suggested. (See STS marked-up page B 3.6-4 and the associated insert page, and marked-up of ITS pages B 3.6.1-4 and B 3.6.1-5)

1

4) On STS Bases marked-up page B 3.6-4, delete the added text "following an outage that included Type A testing."

The offending text has been deleted. (See STS marked-up page B 3.6-4 and marked-up of ITS page B 3.6.1-4)

5) In the bases for SR 3.6.1.3, add a reference callout in the text and a listed reference for 10 CFR 50, Appendix J.

The Bases were revised as suggested. (See STS marked-up page B 3.6-4 insert, B 3.6-5, and marked-up ITS page B 3.6.1-5)

6) In the bases for SR 3.6.2.1, last line, utilize the TSTF-52 wording "combined Type B and C testing." Also add a reference callout in the text and a listed reference for 10 CFR 50, Appendix J.

The Bases were revised as suggested. (See STS marked-up pages B 3.6-17 & 18, and marked-up of ITS pages B 3.6.2-7, 8 & 9)

7) In the response to RAI 3.6.1-1, the marked-up of CTS page 4-21 (for LCO 3.6.2) did not show where DOC A.14 was used.

A revised marked-up of CTS page 4-21 (supporting LCO 3.6.2) has been provided.

8) In the bases for SR 3.6.3.5, expand the reference to 10 CFR 50, Appendix J to specifically address Option A The Bases were revised as suggested. (See STS marked-up pages B 3.6-31, and marked-up of ITS page B 3.6.3-12)

9) In the response to RAI 3.6.1-3, the marked-up of the DOC page showing deletion of 3.6.1 DOC A.4 was omitted.

A marked-up of page 2 of 6 of the 3.6.1 DOCs has been provided.

10) In the response to RAI 3.6.2-10, two DOCs were used to describe related parts of the same change. The discussions in 3.6.2 DOC A.9 should be moved to the discussions provided in DOC M.1.

The subject DOCs have been revised as suggested; DOC 3.6.2 A.9 has been deleted and DOC M.1 has been revised to also include the discussions formerly included in DOC A.9.

(See revised 3.6.2 DOC pages 3 of 1O and 5 of 10, and LCO 3.6.2 CTS marked-up page 4-20)

11) DOC A.1 O, for LCO 3.6.2, addresses the addition of a note which does not exist in CTS.

The discussions in DOC A.1 O seem to discuss the effect of the note on the ITS requirement, rather than the affect on the CTS requirement.

DOC A.1 O has been revised as suggested. (See revised 3.6.2 DOC page 4 of 10)

2

12) RAI responses 3.6.3-15, 16, & 17 contain a common typographical error in referring to deleted DOCs.

The subject RAI responses have been corrected. (See revised RAI response pages 16, 17, and 18)

13) DOC L.5 for LCO 3.6.3 needs to discuss the deletion of the "or in the frequency requirement of CTS 4.5.3b. '

DOC L.5 and the associated No Significant Hazards Consideration analyses have been revised as requested. (See 3.6.3 DOC page 10 of 11, and 3.6.3 NSHC page 7 of 10)

14) The bases for ITS LCO 3.6.3, Action C.1 and C.2 should be revised to use the STS wording in describing the note which modifies Action C.2.

The bases were revised as suggested. (See STS marked-up page B 3.6-26, and marked-up of ITS page B 3.6.3-8)

15) As discussed in RAI 3.6.3-24, an "L DOC" should be provided for the change from CTS 4.5.3c to ITS SR 3.6.3.4 which omits testing of "power operated" valves.

A new 3.6.3 "L DOC", L.7, and an associated No Significant Hazards Consideration analyses have been provided. (See revised RAI 3.6.3-24 response, 3.6.3 CTS marked-up page 4-21, DOC page 11 of 11, and NSHC page 1O of 10)

16) The bases for ITS LCO 3.6.3, Action C.1 and C.2 should be revised to use the STS wording, providing an appropriate reference which describes the requirements for the systems to which Condition C applies, as was done in TSTF-30, and to add the subject reference to the reference section.

The bases were revised and conforming changes made to JFD13. (See STS marked-up pages B 3.6-26 & 33, marked-up of ITS pages B 3.6.3-8 & 12, and 3.6.3 JFD page 4 of 5)

17) The bases for LCO 3.6.3 should be revised to retain (and revise appropriately) the text formerly deleted from paragraph 4 on STS page B 3.6-22.

The bases were revised as suggested. (See STS marked-up page B 3.6-22, and marked-up of ITS page B 3.6.3-4)

18) In ITS SR 3.6.2.1, in both Note 4 and the acceptance criteria, and in the associated bases, clarify that the "personnel air lock door testing" is between the seals testing.

The SR and bases were revised as suggested. (See STS marked-up page 3.6-6 insert, marked-up of ITS pages 3.6.2-5 & 6, and STS bases marked-up page B 3.6-17, and marked-up of ITS page B 3.6.2-7)

3

19) In the bases for LCO 3.6.5, add an explanation of how instrument uncertainties will be addressed.

The bases were revised as suggested. (See STS marked-up page B 3.6-42, and marked-up of ITS page B 3.6.5-3)

20) Revise the response to RAI 3.6.6-12 to clarify which valves are blocked closed when performing CTS SR 4.6.2a.

The response to RAI 3.6.6-12 has been revised as requested. (See revised page 49)

21) In addition to the corrections made in response to NRC reviewer comments, two additional editorial changes were found to be desirable, 1) the word "available" was added to the Condition description for LCO 3.6.6, Condition A (to more closely emulate STS Condition 3.5.2 A), and 2) LCO 3.6.6 DOC page 5 of 8 was revised to delete the unused DOC LA.3.

(See STS page 3.6.-21, ITS page 3.6.6-1, and LCO 3.6.6 DOC page 5 of 8)

4

REVISED RAI RESPONSE

CONVERSION TO IMPROVED TECHNICAL SPECIFICATIONS RESPONSE TO JANUARY 26, 1999 REQUEST FOR ADDITIONAL INFORMATION SECTION 3.6, CONTAINMENT NRC REQUEST:

3.6.3-15 DOC LA.3 CTS 4.2 Table 4.2.2 Item 13.a CTS 4.2 table 4.2.2 Item 13.a requires determining that the containment purge and ventilation isolation valves is closed by checking the valve position indicator in the control room. The "checking the valve position indicator in the control room" according to DOC LA.3 is being relocated to plant procedures. It is unclear from the discussion in DOC LA.3 if the procedure change control process is covered by 10 CFR 50.59 or some other non-regulatory control process. If the procedure change control process is not covered by 10 CFR 50.59 then the change is a Less Restrictive (L) change deletion of material rather than a Less Restrictive (LA) change. Less Restrictive (LA) changes are limited to those items which are relocated to licensee controlled documents covered by a 10 CFR 50.59 change control process.

Comment: Provide additional discussion and justification on the plant procedure change control process.

Consumers Energy Response:

A new DOC (DOC L.5) and NSHC (NSHC L.5) have been provided to justify the deletion of extraneous details contained in CTS 4.2. Table 4.2.2, Item 13a. DOC L.5 supersedes the justification previously provided in DOC LA.3. As such, DOC LA.3 has been deleted in its entirety.

Affected Submittal pages:

See RAI 3.6.3-14 .

16

CONVERSION TO IMPROVED TECHNICAL SPECIFICATIONS RESPONSE TO JANUARY 26, 1999 REQUEST FOR ADDITIONAL INFORMATION SECTION 3.6, CONTAINMENT NRC REQUEST:

3.6.3-16 DOC LA.4 CTS 4.2 Table 4.2.2 Item 13.b CTS 4.2 Table 4.2.2 Item 13.b requires performing a leak rate test of the containment purge and ventilation isolation valves by performing a leak rate test between the valves. The details of how to perform the test (between the valves) according to DOC LA.4 is being relocated to plant procedures. It is unclear from the discussion in DOC LA.4 if the procedure change control process is covered by 10 CFR 50.59 or some other non-regulatory control process. If the procedure change control process is not covered by 10 CFR 50.59 then the change is a Less Restrictive (L) change deletion of material rather than a Less Restrictive (LA) change. Less Restrictive (LA) changes are limited to those items which are relocated to licensee controlled documents covered by a 10 CFR 50.59 change control process.

Comment: Provide additional discussion and justification on the plant procedure change control process.

Consumers Energy Response:

A new DOC (DOC L.5) and NSHC (NSHC L.5) have been provided to justify the deletion of extraneous details contained in CTS 4.2. Table 4.2.2, Item 13b. DOC L.5 supersedes the justification previously provided in DOC LA.4. As such, DOC LA.4 has been deleted in its entirety.

Affected Submittal Pages:

See RAI 3.6.3-14 .

17

CONVERSION TO IMPROVED TECHNICAL SPECIFICATIONS RESPONSE TO JANUARY 26, 1999 REQUEST FOR ADDITIONAL INFORMATION SECTION 3.6, CONTAINMENT NRC REQUEST:

3.6.3-17 DOC LA.5 CTS 4.5.3.b CTS 4.5.3.b. requires that each CIV activates to ITS isolation position during COLD SHUTDOWN and at least once per refueling cycle. The "during COLD SHUTDOWN" according to DOC LA.5 is being relocated to plant procedures. It is unclear from the discussion in DOC LA.5 if the procedure change control process is covered by 10 CFR 50.59 or some other non-regulatory control process. If the procedure change control process is not covered by 10 CFR 50.59 then the change is a Less Restrictive (L) change deletion of material rather than a Less Restrictive (LA) change. Less Restrictive (LA) changes are limited to those items which are refloated to licensee controlled documents covered by a 10 CFR 50.59 change control process. See Comment Number 3.6.3-18.

Comment: Provide additional discussion and justification on the plant procedure change control process. See Comment Number 3.6.3-18.

Consumers Energ..v Response:

A new DOC (DOC L.5) and NSHC (NSHC L.5) have been provided to justify the deletion of extraneous details contained in CTS 4.5.3.b. DOC L.5 supersedes the justification previously provided in DOC LA.5. As such, DOC LA.5 has been deleted in its entirety.

Affected Submittal Pages:

See RAI 3.6.3-14 .

18

CONVERSION TO IMPROVED TECHNICAL SPECIFICATIONS RESPONSE TO JANUARY 26, 1999 REQUEST FOR ADDITIONAL INFORMATION SECTION 3.6, CONTAINMENT NRC REQUEST:

3.6.3-24 JFD 9 CTS 4.5.3.c STS SR 3.6.3.5 ITS SR 3.6.3.4 and Associated Bases ITS SR 3.6.3.4 and its associated Bases modifies STS SR 3.6.3.5 and its associated Bases in accordance with TSTF-46 which verifies the isolation time of each automatic power operated CIV. CTS 4.5.3.c verifies the isolation time of "each power operated or automatic" CIV. The CTS and ITS are not in agreement, in that the CTS requires all power operated valves to be tested which would include all non-automatic power operated valves and all automatic valves to be tested which would include check valves. The ITS does not include all these valves.

Comment: Revise the CTS markup and provide a discussion and justification for this Less Restrictive (L) change.

Consumers Energy Response:

CTS-4.5~:fo-~tates._ttiafi1the~-O--tion time Of each power operated or . utomati~ valv~ shall be verified in accordance with S ction XI of the ASME Boiler and Pres ure Vessel Code." Prior Amendment 184 to the Faci ty Operating License for the Palisad Plant, CTS 4.5.3c state "the isolation time of each ower operated or automatic valve s II be determined to be wi its limit as specified in Ta le 3.6.1 when tested in accordance ith Section XI of the ASM Boiler and Pressure Ves el Code." The isolation time limits s ecified in CTS Table 3.6.

applied only to "Auto Is lation Valves" as denoted in the "RE ARKS" column of Table .6.1.

I

\*1n the staffs Safety E aluation for Amendment 184, it was tated "the staff has revie ed the \

\licensee's proposed 'deletion of Table 3.6.1 and its assoc* ted TS changes and dete ined that\

\the changes are in ccordance with the guidance of GL 1-08. Deleting the list of ontainment \

fsolation valves d es not alter the existing TS require nt or the components the apply to. \

'f-ists of contain ent isolation valves are provided in t e Final Safety Analysis Re ort and in the :

'plant procedu s for performing penetration leak tes ng and isolation valve clos re time testing. \

The set of val es subject to the requirements of T 3. 6 and 4. 5 will not chang due to the \

I ff'roposed ch nge., The staff, therefore, find the p posed change acceptable Based on the contents of ormer CTS Table 3.6.1 and the inte of the change made in A endment 184, the \

fequireme ts of ITS SR 3.6.3.4 remain unchan d from CTS 4.5.3c. - - - - - - - _ _J

~ubmittal pages: A n~w----i:;;z*c.-n;;;z't) a.NJ I.JS ti<:.. ( µs H' L. :;)

rev~ bee n pfO<J;d"t,,J to -au s+t+y t/\~ oJ ~ h.. ho,...

-cf-the t(;r/)" II f1J4.y;,r Ofeto..1cd 1,.Q{~ t/ ~~~ ~

C.0 t.f. S'. 3 c.

25

CONVERSION TO IMPROVED TECHNICAL SPECIFICATIONS RESPONSE TO JANUARY 26, 1999 REQUEST FOR ADDITIONAL INFORMATION SECTION 3.6, CONTAINMENT NRC REQUEST:

3.6.6-12 DOC LA.2 CTS 4.6.2.a ITS SR 3.6.6.6 CTS 4.6.2.a specifies that for the Containment Spray System test "The test shall be performed with the isolation valves in the spray lines at the containment blocked closed." Insufficient information is provided to justify the relocation of this detail to plant procedures. CTS 4.6.2.a tests in part that the automatic containment spray valves actuate to their correct position on an actuation signal. The corresponding ITS SR is ITS SR 3.6.6.6. ITS SR 3.6.6.6 test all automatic valves except those locked, sealed or otherwise secured in the required position under Administrative control. Thus if the isolation valves at the containment are manual valves, then the relocation of the statement in CTS 4.6.2.a is acceptable. However, if the isolation valve is an automatic valve which actuates, then the statement cannot be relocated to procedures, but must be specified in the Bases. The ITS SR 3.6.6.6 exception for locked valves, which is not justified or indicated in the CTS markup, applies to those automatic valves that are normally locked in their correct position during operation and does not apply to valves that are locked for testing purposed.

Comment: Revise the CTS markup to correctly reflect ITS SR 3.6.6.6 and provide the appropriate discussion and justification for the changes associated with ITS SR 3.6.6.6 discussed above. In addition, if the locked closed isolation valves are automatic valves describe how these valves will be tested to verify that they will actuate to their correct position on an actuation.

Consumers Energy Response:

As described in the response to RAI Comment 3.6.6-11, DOC LA.2 has been deleted and a new DOC L.3 prepared to described the removal of this requirement to test the containment spray system "with the [header] isolation valves in the spray supply lines at the containment blocked closed." The valves used to accomplish this flow blockage are manual valves MV-3258 and MV-3259. There is one valve in each spray header just upstream of the automatic valves which open to actuate containment spray. This alignment does not support system OPERABILITY, it merely provides a cautionary allowance to prevent inadvertent spray actuation into the containment.

The containment spray valves (CV-3001 and CV-3002) are normally closed valves that automatically open if a containment high pressure signal is received. The valves are subject to the requirements of SR 3.6.6.6. The valves' automatic actuation is a required part of the overall system response to an accident. The spray valves CV-3001 and CV-3002, are not used to block spray flow to the containment during testing.

SR 3.6.6.6 and SR 3.6.6.7 together constitute testing that provides the same degree of testing as presented in CTS 4.6.2a. The CTS markup pages were modified as a result of the changes required to address RAI Comment 3.6.6-1 O,and -11 to reflect this correspondence. For additional information, see the responses to these comments.

Affected Submittal Pages:

No page changes.

49

REVISED SPECIFICATIONS

Containment Air Locks 3.6.2

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.2.1 -------------------NOTES-------------------

1. An inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.

2. Results shall be evaluated against acceptance criteria of SR 3.6.1.3 in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions.

3. A seal contact check shall be performed on the emergency escape air lock following each full pressure test. Emergency escape air lock door opening, solely for the purpose of ~

strongback removal and performance of the seal contact check, does not necessitate additional pressure testing *

4. Local leak rate tests, other than personnel air lock doo~~ shall be performed at ~ 55 psig--:-

Perform required air lock leakage rate -----NOTE------

testing in accordance with 10 CFR 50, SR 3.0.2 is not Appendix J, Option A, as modified by applicable approved exemptions.

The acceptance criteria for air lock In accordance testing are: with 10 CFR 50, Appendix J,

a. Overall air lock leakage rate is Option A, as

s; 1.0 La when tested at ~ Pa and modified by combined with all penetrations and approved valves subjected to Type B and C exemptions tests. However, during the first unit startup following testing performed in accordance with 10 CFR 50, Appendix J, Option A, as modified by approved exemptions, the leakage rate acceptance criteria is < 0.6 La when combined with all penetrations and valves subjected to Type B and C tests. (continued)

Palisades Nuclear Plant 3.6.2-5 Amendment No. 05/31/99

Containment Air Locks 3.6.2

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3. 6. 2. I (continued) f.:t.b,,,. ilt. Ooli-f.st_)J

b. For each personnel air lock door.fl leakage rate is ~ 0.023 La when tested at <!: 10.0 psig.

c. An acceptable emergency escape air lock door seal contact check consists of a verification of continuous contact between the seals and the sealing surfaces.

SR 3.6.2.2 Verify only one door in the air lock can be. 18 months opened at a time *

- Palisades Nuclear Plant 3.6.2-6 Amendment No. 05/31/99

~

C.TS L/. s. Zd I 6 SR 3. 6 .2 .1 1.

INSERT

NOTES-------------------

An inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.

~2. Results shall be evaluated against acceptance criteria of SR 3.6.1.3 in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions.

3. A seal contact check shall be performed on the emergency escape air lock following each full pressure test. Emergency escape air lock door opening, solely for the purpose of strongback removal and performance of the seal contact check, does not necessitate additional pressure testing.

4. Local leak rate tests, other than personnel air lock door~shall be pertormed at~ 55 ps1g.

Perform required air lock leakage rate testing in accordance -----NO~------

with 10 CFR SO, Appendix J, Option A, as modified by SR 3.0.2 is not applicable approved exemptions.

The acceptance criteria for air lock testing are: In accordance with 10 CFR 50, Appendix J,

a. Overall air lock leakage rate is s 1.0 L1 when tested Option A, as modified by at ~ P 1 !lnd combined with all penetrations and valves approved exemptions subjected to Type B and C tests. However, during the first unit startup following testing performed in accordance with 10 CFR 50, Appendix J, Option A, as modified by approved exemptions, the leakage rate acceptance criteria is < 0.6 L1 when combined with all penetrations and valves subjected to Type Band C tests.

L_ +

(_ ~~tc.r. +.-,.._ lltAI tc ~ )

b. For each persoiffiel air lock doo~ leakage rate is s 0.023 L1 when*tested at~ 10.0 psig.

c. An acceptable emergency escape air lock door seal contact check consists of a verification of continuous contact between the seals and the sealing surfaces .

3.6-6

Containment Cooling Systems 3.6.6

3.6 CONTAINMENT SYSTEMS 3.6.6 Containment Cooling Systems LCO 3.6.6 Two containment cooling trains shall be OPERABLE.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more A.1 Restore containment 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months containment cooling cooling train to trains inoperable. OPERABLE status. ~

Mill At least 100% of the cooling capability equivalent to a single OPERABLE containment cooling tra i n.r ava1lqblc, B. Required Action and B.l Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Ti me not met. Mm B.2 Be in MODE 4* 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months

Palisades Nuclear Plant 3.6.6-1 Amendment No. 05/31/99

Containment Cooling Systems 3.6.6

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.6.1 Verify each containment spray manual, power 31 days operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position.

SR 3.6.6.2 Operate each Containment Air Cooler Fan 31 days Unit for ~ 15 minutes.

SR 3.6.6.3 Verify the containment spray p1p1ng is full~ 31 days of water to the 735 ft elevation in the containment spray header *

SR 3.6.6.4 Verify total service water flow rate, when aligned for accident conditions, is L/8'00~3935.S- gpm to Containment Air Coolers VHX-1, VHX-2, and VHX-3.

18 months SR 3.6.6.5 Verify each containment spray pump*s In accordance developed head at the flow test point is with the greater than or equal to the required Inservice developed head. Testing* Program SR 3.6.6.6 Verify each automatic containment spray 18 months valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to its correct position on an actual or simulated actuation signal *

Palisades Nuclear Plant 3.6.6-2 Amendment No. 05/31/99

REVISED BASES

Containment B 3.6.1 BASES ACTIONS B.1 and B.2 (continued)

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

SURVEILLANCE SR 3. 6 .1.1 REQUIREMENTS Maintaining the containment.OPERABLE requires compliance with the visual examinations and Type A ieakage rate test requirements of the Containment Leak Rate Testing Program~-

_ _...,.As left leakage prior to the first startup after performing a required leakage test is required to be s 0.75 L4 for -

overa 11 Type A 1eakaget*fol lowing a11 012ta~e t~at ; nel wead Type A testiR9- At al other times between required leakage rate tests, the acceptance criteria is based on an overall rype A leakage limit of s 1.0 La. At s 1.0 La the offsite dose consequences are bounded by the assumptions of the safety analysis. SR Frequencies are as required by the Containment Leak Rate Testing Program. These periodic testing requirements verify that the containment leakage rate does not exceed the leakage rate assumed in the safety analysis.

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

f:alwrc. h med !l.\r i<<K Q.."~ C.0'f'lkuf\Mc."t 1uLe..+ "' VC.lvt.

kcQ.~~ Q,m*ts doe.s . * *

(lot 1X\.Gfldcii~ tht ~c e.~+M1 hJ..J of- the. o~l I -ry~ A ci t-k.r"' ~" o..ti()" .

Palisades Nuclear Plant B 3.6.1-4 05/31/99

Containment B 3.6.1 BASES SURVEILLANCE SR 3.6.1.3 . (~~.L(),

REQUIREMENTS (continued) Maintaining the containment OPERABL~Jrequires compliance with the Type B and C leakage ra~;~t requirements of 10 CFR 50, Appendix J, Option AK as modified by approved exemptions. Testing is performed at pressures ~ 55 psig.

j'AS left leakage prior to the first startup after performing a required 10 CFR 50, Appendix J, Option A, leakage test is required to be < 0.6 La for combined Type B and C leakage.

At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of s 1.0 La. Ats 1.0 La the offsite.dose consequences are bounded by the assumptions of the safety analysis. SR Frequencies are as required by Appendix J, Option A, as modified by approved exemptions. Thus, SR 3.0.2 (which allows Frequency extensions) does not apply.

These periodic testing requirements verify that the containment leakage rate does not exceed the leakage rate assumed in the safety analysis.

SR 3.6.1.3 is modified by a Note which states that local leak tests shall be performed at pressures ~ 55 psig. This value corresponds to the design pressure of the containment and bounds the maximum expected internal pressure resulting from an MSLB or design basis LOCA.

REFERENCES 1. FSAR, Chapter 14

2. FSAR, Section 14.18

3. FSAR, Section 5.8 l/. 10 cF~ so 1 Aerct¥J*t. J".

Palisades Nuclear Plant B 3.6.1-5 05/31/99

Containment Air Locks B 3.6.2

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

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

SURVEILLANCE SR 3.6.2.1 REQUIREMENTS Maintaining containment air locks PERABLE requires compliance with the leakage rat est requirements of 10 CFR 50, Ap endix J. Option A as modified by approved exem tions. his SR reflects the leakage- rate testing requirements with regard to air lock leakage (Type B leakage tests). The .acceptance criteria, were established during_

initial air lock and containment Operability testing.

Subsequent amendments to the Technical Specifications revised the acceptance criteria for overall Type B and C leakage limits and provided new acceptance criteria for the personnel air lock doors and the emergency air lock doors (Ref. 2). The periodic testing requirements verify that the air lock leakag*e does not exceed the allowed fraction of

~(\ +N:

{.)e.als 7e st) 1* the overall containment leaka e rate. eak rate tests, other an e personne air oc oo pressure~ 55 psig.

are performed at The Frequency.is equired by 10 CFR 50, Appendix J, Option A, as modified by approved exemptions. Thus, SR 3.0.2 (which allows Frequency extensions) does not apply.

Two exemptions to the requirements of 10 CFR 50, Appendix J have been granted for the containment air locks. The exemption granted by letter dated December 6, 1989 provides partial relief from the requirement of Paragraph III.D.2.(b)(ii) to leak test, at or above the cal~ulated design*basis accident peak containment pressure (Pa),

containment air locks which were opened during a period when containment integrity was not required. This exemption permits the substitution of a between-the-seal leak test at a reduced pressure, but not less than 10 psig, provided that no maintenance, modification, or other activity has been performed which could affect the sealing capability of the air locks.

Palisades Nuclear Plant B 3.6.2-7 05/31/99

Containment Air Locks B 3.6.2 BASES SURVEILLANCE SR 3.6.2.1 (continued)

REQUIREMENTS The exemption granted by letter dated September 30, 1997 applies only to the emergency escape air lock and provides partial relief from the requirement of Paragraph III.D.2.(b)(ii) and Paragraph III.D.2.(b)(iii). The requirement of Paragraph III.D.2.(b)(ii) is discussed above.

Paragraph III.0.2.(b)(iii) requires air locks opened during periods when containment integrity is required to undergo a full air lock pressure test within 3 days ~fter being opened. This exemption permits the performance of a door seal contact verification check in lieu of the final pressure test following the opening of the emergency escape air lock doors for post-test restoration or seal adjustment.

This exemption does not affect compliance with the requirement to perform a full pressure air lock test at 6 month intervals, or the requirement to perform a full pressure air lock test within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months o~ opening either air lock door during periods when containment integrity is required. *

The SR has been modified by four Notes. Note 1 states that an inoperable air lock door does not invalidate the previous*

successful performance of the overall air lock leakage test.*

This is considered reasonable since ~ither air lock door is capable of providing a fission product barrier in the event of a OBA. Note 2 has been added to this SR requiring the results to be evaluated against the acceptance criteria of SR 3.6.1.3. This ensures that air loc leakage is properly accounted for in determining the ove'411 ontainment leakage rate. Note 3 clarifies that itera ive p essure es ing o x

the emergency escape air lock is not required when the air lock doors are opened solely for the purpose of strongback removal and performance of the seal contact check. Note 4 ensures that air lock testing, other that door seal testing, is performed at a pressure ::!! 55 psig consistent with other Type B and C tests.

Palisades Nuclear Plant B 3.6.2-8 05/31/99

Containment Air Locks B 3.6.2

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.2.2 The air lock interlock is designed to prevent simultaneous opening of both doors in a singl.e air lock .. Since both the inner and outer doors of an air lock are designed to withstand the maximum expected post accident containment pressure, closure of either door will support containment OPERABILITY. Thus, the door interlock feature supports containment OPERABILITY while the air lock is being used for personnel transit into and out of containment. Periodic testing of this interlock demonstrates that the interlock will function as designed and that simultaneous opening of the inner and outer doors will not inadvertently occur. Due to the purely mechanical nature of this interlock, and given that the interlock mechanism is not normally challenged when the airlock is used for entry and exit {procedures require strict adherence to single door opening), this test is only required to be performed every 18 months. The 18 month frequency is based on the need to perform this Surveillance under the conditions that apply during plant outage, and the potential for loss of containment OPERABILITY *if the Surveillance were performed with the reactor at power.

The 18 month Frequency for the interlock is justified based on generic operating experience. The Frequency is based on engineering judgment and is considered adequate given that I

the interlock is not normally challenged during use of the airlock.

REFERENCES 1. FSAR, Chapter 14

2. FSAR, Section 5.8 3 10 C.FR. 50, Ar1cNl1'i T.

Palisades Nuclear Plant B 3.6.2-9 05/31/99

Containment Isolation Valves

-me. f.u~c. e.~~-t o."cl 0:lf' f'ot:N\ jjvpp1.y i..b.IVc:.S <.01# B 3.6.3 rtsi/1e.r.i' iltals rnvn+ Med +he. !Ja..NWI.. 2la.~~ fn-h BASES t</l+1'l re.~v1r~*~..,-ts O.Jl ot\\t.r '"i'jP(. C. 1-c.f.)tt_J LCO ~ntainment isola~ion valve ~~e r4l£s:~e) addressed by (continued) LCO 3.6.1, Containmen~s____ C te'!_i__.

11 This LCO provides assurance that the containment isolation valves and purge valves will perform their designed safety functions to minimize the loss of primary coolant inventory and establish the containment boundary during.accidents.

APPLICABILITY In MODES 1, 2, 3, and 4, a OBA could cause a release of radioactive material to containment. In MODES 5 and 6; the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES.

Therefore, the containment isolation valves are not required to be OPERABLE in MODE 5. The requirements for containment isolation valves during MODE 6 are addressed in LCO 3.9.3, "Containment Penetrations."

ACTIONS The ACTIONS are modified by four notes. Note one allows isolated penetration flow paths, except for 8 inch exhaust and 12 inch air room supply purge valve penetration flow paths, to be unisolated intermittently under administrative controls. These administrative controls consist of stationing a dedicated operator at the valve controls, who is in continuous conmunication with the control room. In this way, the penetration can be rapidly isolated when a need for containment isolation is indicated. Due to the fact that the 8 inch purge exhaust valves and the 12 inch air room supply valves may be unable to close in the environment following a LOCA and the fact that those

-Penetrations exhaust directly from the containment atmosphere to the environment, these valves may not be opened under administrative controls.

A second Note has been added to provide clarification that, for this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable containment isolation valve. Complying with the Required Actions may allow for continued operation, and subsequent inoperable containment isolation valves are governed by subsequent Condition entry and application of associated Required Actions *

Palisades Nuclear Plant B .;.6.3-4 05/31/99

Containment Isolation Valves B 3.6.3

_BA_S_E_S_______________________________________________________

ACTIONS C.1 and C.2 (continued)

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

i sol ation following an accident are isolated. The Completion Time of once per 31 days for verifying that each affected penetration flow path is isolated is appropriate considering the valves are operated under administrative controls and the probability of their misalignment is low.

Condition C is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with only one containment isolation valve and a closed This Note is necessary since this Condition is to specifically address those penetration flow paths in a closed system.

Required Action C.2 is modified by a Note that applies to valves and blind flanges located in high radiation areas and a11 ows these devices to be verified c1osed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to the~e areas is t*~icall~ restrict

Therefore, the probability ofCiD'.iiti ;t;Qitfr.9')these ev ces once they have been verified t°fe in the proper positio is small.

rn 15o.l1~nl'V'f.C\i ~ \P.hts

Palisades Nuclear Plant B 3.6.3-8 05/31/99

Containment Isolation Valves B 3.6.3 BASES SURVEILLANCE SR 3.6.3.5 REQUIREMENTS (continued) For containment 8 inch purge exhaust and 12 inch air room supply valves with resilient seals. additional leakage rate*

testing beyond the test requirements of 10 CFR 50, j OP+1F:ll A Appendix *"(Ref. 3). is required to ensure the valves are physically closed (SR 3.6.3.1 verifies the valves are locked closed). Operating experience has demonstrated that this type of seal has the potential to degrade in a shorter time period than do other seal types. Based on this observation and the importance of maintaining this penetration leak tight (due to the direct path between containment and the environment). a Frequency of 184 days was established as part of the NRC resolution of Generic Issue B-20, ~

"Containment Leakage Due to Seal Deterioration" (Ref. . as specified in the Safety* Evaluation for Amendment No. 9 to the Facility Operating License.

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

Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. FSAR, Section 5.8 t/ x. Generic Issue B-20 3'. 10 CFR 50, Append~x J I

I> . .

J..,

Palisades Nuclear Plant FSAi, ._.Sech.~ (g.[. 2._.,,

B 3.6.3-12 05/31/99

Containment Air Temperature B 3.6.5

BASES ACTIONS (continued)

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

SURVEILLANCE SR 3.6.5.l REQUIREMENTS Verifying that containment average air temperature is within the LCO limit ensures that containment operation remains

, within the limit assumed for the containment analyses. The I.ns+rti~A+ LJnct.rio..Att~& 140°F limit is the actual limit assumed for the accident a.re. °'"'°"'\'kd ~ '" -th )analyses and does not accou~t for. i nstru~ent inaccuracies-*.

DvrvQllQ.l'lc.~ f~IAI ~The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of th1 s SR 1s cons1 dered acceptable

based on the observed slow rates of temperature increase within containment as a result of environmental heat sources (due to the large volume of containment).

REFERENCES 1. FSAR, Section 5.8

2. FSAR. Section 14.18

3. FSAR, Table 14.18.2-3

Palisades Nuclear Plant B 3.6.5-3 05/31/99

Containment Cooling Systems B 3.6.6 BASES SURVEILLANCE SR 3.6.6.4 Verifying a total service water flow rate of ~ ~~~gpm REQUIREMENTS (continued) to CACs VHX-1, VHX-2, and VHX-3, when aligned for accident conditions, provides assurance the design flow rate assumed in the safety analyses will be achieved (Ref. 8). Also considered in selecting this Frequency were the known reliability of the cooling water system, the two train redundancy, and the low probability of a significant degradation of flow occurring between surveillances.

SR 3.6.6.5 Verifying that each containment spray pump's developed head at the flow test point is greater than or equal to the required developed head ensures that spray pump performance has not degraded during the cycle. Flow and differential pressure are normal tests of centrifugal pump performance required by Section XI of the ASME Code (Ref. 5) *

Since the containment spray pumps cannot be tested with flow through the spray headers, they are tested on recirculation flow. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this SR is in accordance with the Inservi ce Testing Progr,am.

SR 3.6.6.6 and SR 3.6.6.7 SR 3.6.6.6 verifies each automatic containment spray valve actuates to its correct position upon receipt of an actual or simulated actuation signal. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. SR 3.6.6.7 verifies each containment spray pump starts automatically on an actual or simulated actuation signal. The 18 month Frequency is based on the need to perform these Surveillances under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillances were performed with the reactor at power .

Palisades Nuclear Plant B 3.6.6-9 05/31/99

REVISED CTS MARKUPS AND DOCS

~ CONTAINMENT[@) .:5yS\~'MS (fi.2 Local Leaj/tletection Tests /(continued)) ~

b. Acceotance Criteria (1) The total leakage from all penetrations and isolation valves shall not exceed 0.60 L*.

(2) The leakage for a Personnel airlock door seal test shall not S'R3.~.2..I exceed 0. 023 L*.

', I

$(1...3~2./

(3) An ac~eptable Emergency Escape Airlock door seal contact check consists of a verification of conti~uous contact between the l'c. I sea~s and the sealing surfaces.

@ r-c:- /Correctiv~ctiOrl)

(1) at any im repairs shal N7 3 ' completed a conformance to the acceptance riterion of

' ~ 4.5.2.b(l) is not demonstrated within 48 h rs, the plant shall be aced in at least HOT SHUTDOWN thin the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months nd in COLD SHUTDOWN within the f. llowing 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .

~011'0 ~

C.:AIJD AA-A.I ,fl....2,f'..~

1 c.oND D

~ 0-te.\ ;--~ ~m b N~

Entry and exit is permissible through a "locked" air lock door to perform repairs on the affected air lock components.

f£ 4-20 CONTAINMENT TSCR CAaA~e 7, REV 2 Amendment No. ~. +74, -!++,

1-.iD~ l +o R.,...~,.. ~4-A > "*

5 A"'Ob

\ll~ 2 to i2.A ~r LJ)M A, > L,...

f\i/D ,....

l=\IJD~"R~A.~\-S,3' /@

~ P,:Pt:> rJ.,na"r to. "AA t;t- c.:,.,.,.l !3 > M. I

<. f'*.'PO Ac..17~ ~ 0k ':") + <2,,"' al i3 ") "'* 1

~, ~~D rJIJ7G' -z ~"'A ,r

c. A\)\) /\CiYDN c.. /' ~

4.5 CONTAINMENT TESTS 4.5.2 (continued)

@'.') Test Eregyencv (1) lnd1v1 al penetrations and conta1ti:m t isolation valves be l k rate tested at a frequency at least every <;ee 3.iD.I) ref eling, not exceeding a two-yea interval, except as s cified in a and b below:

See 3. I.>. 1)

I s R. 3.1,,.:z... I air lock penetration testshall be ~erformed~

s x-mon n erva s. ur1ng the*per1od be ween the six-mo th.tests when CONTAINMEN INTEGRITY is requ*red, a w:.µ... IOc.l=R Sb, APP 1 redu d pressure test for the oor seals or a fu air 0 PT A1 O..t1d o.. Ptr11*) loc penetration test shall performed within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months

<!"(. e,...,..p ~n~ af er either each air lock oor opening or th first of a

' ries of openings.

4.5.3

a. lves shall be demonstrated OPERABLE by p rformance of a cycling st and verification of isolation time fo auto isolation va es prior to declaring the valve to be OP BLE after maintenance repair, or replacement work is performed on the valve or its ass ciated actuator, control, or power circui .

b. Each is ation valve shall be demonstrated OPERABL by verifying that o each containment isolation right channel left channel test gnal, applicable isolation valves actuate o their required posi ion during COLD SHUTDOWN or at least once r refueling cycle.

See. 3.(..~

c. isolation time of each power operated or a tomatic valve shall verified in accordance with Section XI of he ASHE Boiler and ressure Vessel Code.

Prior to the reactor going critical after refueling outage, a visual check will be made to confirm that all "locked-closed" manual containment isolation valves are osed and locked (except for valves tha~ are open under administ~ tive control as permitted by LCO 3.6.1).

e. Each three months the isolation valv must be stroked to the position required to fulfill their s fety function unless it is established that such operation is ot practical during plant operation. The latter valves shal be full-stroked during each COLD SHUTDOWN.

m, H&, -t-74,

. [ .

_,. f e c .._. (. e +. ~ _., ~. *~ ?:,

4.5 4.5.2 {continued)

(l} Individual enetrations and containment iso tion valves shall )

be leak r e tested* at a f equency of at 1 st every SL~ 3.io.I refuelin, not exceeding two-year inter 1, except as s ecifi in (a} and (b elow:

(a} The containment equipment ~*ah and the fuel transfer --<._SI ee. s.l,,.

t e shall be tested at eac refueling outage or after I>

ach time used if that be sooner. ------***

(b} A full air 1 ck penetration test shall be performe at six-month i ervals. During the period between t e six-month ests when CONTAINMENT INTEGRITY is re uired, a I reduced p essure test for the door seals or a f 1 air lock pen ration test shall be performed withi 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months $e.e. 3.i.7..)

after e'ther each air lock door opening or t first of a series of openings.

/4.5.3 / Containment lsolatioij/Valves 1 The isolation valves shall be demonstrated OPERABLE by performance of a cycling test and verification of isolation time for auto I~\

isolation valves prior to declaring the valve to be OPERABLE after maintenance, repair, or replacement work is performed on the valve or its associated actuator, control, or power circuit.

0.-. C..C.+J OW'"

1 10 s;~. J~\-e.J s;

1\(Q)

~--....____.0 s~ 3. i...J.4 r---~::=================:=;:=:=;:===-__:_.\~

e ,,..:~j Mc:iDf '-\

,...,,....., MoCE 5 '.~

1'\.,,,t \"e..-ro.-""' e.J.

w;.fh:,_ -t\...Q. rre.J:o ...s

'\'l_ Jc.'\ .s ~

. 4-21

)

ADD {.~PTI ctJ .f.or L:ckl, ~ea Itel 1 oiW1~ S~\'J ~

Amendment No.

< or

'"' S<< 3.(o.3.e:,

C.i'h

/<iAI 30./-/

A.4.

ATTAC1'ENT 3 DISCUSSION OF CHA.t"'JGES SPECIFICATION 3.6.1, CONTAINMENT

{CTS 3.6. lc states "When positive re ctivity changes are made by boron dilution r jcoNTROL ROD motion (expect D r testing one CONTROL ROD at a time)." his

!statement is not required for MO ES 1, 2, 3 and 4, which is the Applicabilit for 3.6.1, since the Containment is equired to be OPERABLE which encompa es the requirements of "Containmen ntegrity." _For -MODE 5, proposed ITS L 3 .1.1 requires that adequate SHU OWN MARGIN be required and provides ctions to Immediately restore it if t requirement is not met. For MODE 6, pr osed ITS LCO 3. 9 .1 ensures ade ate SHUTDOWN MARGIN by specifying r quirements for boron concentration. I the specified boron concentration is not ma* tained, positive

reactivity additions st be suspended immediately and actions i

ated immediately to restore boron cone tration to within limits. Therefore, the pro sed ITS ensures adequate SHUTD WN MARGIN and the appropriate require nt for Containment OPERABILITY n all MODES. The CTS wording in 3.6.lc snot needed due to the redistribution requirements in the proposed ITS and ther ore this is considered to be an administr i e chan e. This chan e is consistent with UREG-143 A.5 TS 4.5.2d(l) specifie the test frequency for individual penettati ns and containment isolation valves. The allowing portion of 4.5.2d(l) " ... at a fre ency of at least every efueling, not exceeg/ng a two-year interval, except as specifie in (a) and (b) below:"

is replaced by "in ¥cordance with the Containment Leak Rat Testing Program."

The CTS 6.5.14, ¢ontainment Leak Rate Testing Program, tes "The Type Band Type C test~ po am shall meet the requirements of 10 CF 50, Appendix J, Option A, as modified by e exemption from certain requirements 10 CFR 50 Appendix J which was gr ted in an NRC letter to Consumers Pow company dated December 6, 1989." The Containment Leak Rate Tes Program will also be included in the prop9,ed ITS ..Therefore, by referencing the ontainment Leak Rate Testing Program ~ich will reference 10 CFR 50 Appendi J, there is no need to duplicate the testing r

uirements within specifications. This i considered to be an administrative change ince the requirements have not changed This change is consistent with u -1432 .

Palisades Nuclear Plant Page 2 of 6 01/20/98

A.7 SPECIFICATION 3.6.2, CONTAINMENT AIR LOCKS A TTACH:\IENT 3 DISCUSSION OF CHANGES CTS 4.5.2.c(3) and (4) state " ... the plant shall be placed in at least HOT SHUTDOWN within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLD SHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months ." In the proposed ITS, Condition D contains the same requirement when Required Actions and Associated Completion Ti.mes are not met except that the plant must be placed in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within a total of 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

With respect to temperature between the CTS and ITS, the proposed ITS MODE 3 is specified by being greater than 300°F while the CTS HOT SHUTDOWN is greater than 525°F. While the ITS covers a broader range, for a shutdown there is no effective difference for achieving either temperature in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months :;ince they are specified as "greater than." For the CTS COLD SHUTDOWN versus the ITS MODE 5, the temperature requirement is being less than 210°F versus being less than 200°F in the ITS. This difference of 10 degrees is negligible and has no significant impact on operations. The other parameter which is common between the CTS terms HOT SHUTDOWN and COLD SHUTDOWN and the corresponding !TS MODES 3 and 5 is the reactivity condition. The ITS MODE 3 and 5 are defined, as a reference point, by a reactivity condition of Keff < .99. However, in ITS Section 3 .1. the equivalent amount of SHUTDOWN MARGIN ls required as that specified in the CTS definitions of HOT SHUTDOWN and COLD SHUTDOWN. Therefore, the amount of SHUTDOWN MARGIN is considered to be same when the requirements of proposed ITS 3 .1 are considered. The time to reach the CTS COLD SHUTDOWN is specified as " ... within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months " while the ITS allows a total of 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months to reach MODES. Therefore, even if the plant is already in MODE 3 the full 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months are allowed. This change reflects the usage rules as specified in NUREG-1432. These changes are all considered to be administrative in that there is no significant impact to operation of the plant and they reflect the terminology and usage rules of NUREG-1432.

A.8 A.9 of ACTION B ..

the same air lock are ge to clarify the usage rules Palisades Nuclear Plant 05/31/99

C 11 L __.J. fJ.. _ ATTACHMENT 3

~e.(.. 1 ~~ la.6C. _ DISCUSSION OF CHANGES SPECIFICATION 3.6.2, CONTAINMENT AIR LOCKS A.10 The proposed ITS include o otes m SR 3. 6. 2. 1. The first Noce stat "An inoperable air lock door oes not invalidate the previous successful per nnance of the overall air lock leakag tests." This Note provides clarification on th usage rules of.

S for this panicular application because it is recognized that one c sed OPERABLE door will provide c ntainment integrity and should not invalidate e overall air lock leakage* test. T

is considered to be an administrative change clarify the application f the TS usa rules. This change is consistent with NURE 1432.

A.11 The proposed ITS includes Note 1 to the Required Actions for Condition A. The Note states "Required Actions A.I, A.2, and A.3 are not applicable if both doors in the same air lock are inoperable and Condition C is entered." This note is provided to clarify the usage rules in that if both air lock doors are inoperable and Condition C is entered, the Required Actions of Condition A are not entered but rather the Required Actions of Condition Care followed. This change is consistent with NUREG-1432.

A.12 The proposed ITS includes two Notes in SR 3.6.2.1. The second Note states "Results shall be evaluated against acceptance criteria of SR 3.6.1.3 in accordance with 10 CFR 50, Appendix I, as modified by approved exemptions." CTS 4.5.2c(2) starts

out by stating "If at any time it is determined that total containment leakage exceeds La .. **" This implies that the air lock leakage, as well as any other containment leakage, is always compared against the overall containment leakage requirements. Therefore, the addition of this note is an administrative change to provide a reminder to compare the test results against the overall containment leakage limit. This change is consistent with NUREG-1432.

A.13 Not used.

A.14 The Frequency of proposed ITS SR 3.6.2.1 is modified by a Note which states .that "SR 3 .0.2 is not applicable." The inclusion of this Note is for clarification purposes only and is considered Administrative in nature since the CTS does not contain an explicit exemption from the testing frequency of 10 CFR SO, Appendix J. Thus, both the CTS and ITS preclude frequency extensions for Type B and C leakage rate tests.

This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 4of10 05/31199

DOC 3.6.2, A.IO CTS 4.5.2d(l)(b) specifies the testing requirements for the air locks. Although not explicitly stated, failure of the reduced pressure test for an air lock door seal would not invalidate the previous performance of the full pressure test. This is because the air lock door seal test only verifies one door at a time and, unless specifically known otherwise, the remaining air lock door is considered Operable. Proposed ITS SR 3.6.2.1 includes two Notes. The first Note states "An inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage tests." This Note provides clarification on the usage rules of TS for this particular application because it is recognized that one closed OPERABLE door will provide containment integrity and should not invalidate the overall air lock leakage test. This is considered to be an administrative change since it does not alter the original intent of the CTS.

This change is consistent with NUREG-1432 .

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.6.2, CONTAINMENT AIR LOCKS A.15 CTS 3.6. la requires that Containment Integrity *be maintained "when the plant is above /

Cold Shutdown. In the ITS, this statement is equivalent to an Applicability of Modes /.

1, 2, 3, and 4 since the CTS definition of Cold Shutdown is essentially the same as the /

ITS definition of Mode 5. That is, each represents a plant condition at which the /.

average temperature of the primary coolant is below its boiling point at one standard /

atmosphere. From an analytical perspective, there is no significant difference between /

the CTS value of 210°F and the ITS value of 200°F for the upper temperature limit in /

Mode 5. Therefore, replacing the CTS phrase "when the plant is above Cold /

Shutdown" with an Applicability of "Mode l, 2, 3, and 4" is considered to be /

Administrative in nature. This change is consistent with NUREG-1432. /

MORE RESTRICTIVE CHANGES (M)

M.l In ITS 3.6.2, for a containment air lock to be considered Operable, the air lock (door) I interlock mechanism must be Operable. In the CTS, the containment air lock door~ I interlock mechanism is not required for containment air lock Operability. As such, I inclusion of the door interlock mechanism in the definition of an Operable containment I

air lock is considered to be an additional restriction on plant operations. The addition of this requirement is appropriate since the door interlock mechanism functions to

ensure that a gross breach of containment does not exist when the containment is required to be Operable by only allowing one air lock door to be opened at a time.

Inclusive with this change is a .new Condition (Condition B) which addresses the

_/

I I

inoperability of one or more interlock mechanism, and the corresponding Required /

Actions and Completion Times (B. l, 8.2, 8.3) which provide the appropriate I compensatory measures. The Required Actions are modified by three Notes. Note 1 I states that Required Actions 8.1, 8.2, and B.3 are not applicable if both doors in the I same air lock are inoperable and Condition C is entered, Note 2 allows containment I ingress and egress under the controls of a dedicated individual, and Note 3 allows lock

I closed air lock door in high radiation areas to be verified by administrative means. The I addition of Notes 2 and 3 are appropriate since they continue to ensure a leak tight I containment barrier is provided. Note 1 eliminates conflicts in the ITS usage rules.as I

.described iP DOC 4 si. Lastly, a new Surveillance Requirement (SR 3.6.2.2) has been I added to perform an interlock test every 18 months. That SR ensures the interlock, I feature will* functioned as designed. The addition of these More Restrictive changes are I consistent with NUREG-1432. I Sf\?.c.;~G!l.H:J, tl'lc. l"lotc. Clo.rt~ *fri~t~1JirtJ A~+t4M 6.1, "&. 2., Q,rd 5.~ a.r~ rio-f G-PPl~folc. 1-t btttf d6tl:S '" 1-ftc. ~~ ~,,. IAc.t are. l~o~roklc a."d ~wJ 1 +w1 C.. 1:S e:+t-r~&. !his '~ b~ ~-t. Re.~irccJ Ac+ions. o~ ~it1&n & Could fl6t bC me.t IJIM.. f.. -tha, I~ r'\o Cif~I~ door J" +he. a.~cc.~ a..;r ~c,K' o..nJ

~ridrhM C. frbU1dt.o -fhe a.wrofrP.i-1 (lmc4iaL a.c1-16"s ~r muLl-t(lii I")o~RJol'< ddO(!

ID f!tt. /ih.mt. Cl.if' JoU;.

Palisades Nuclear Plant Page 5of10 05/31/99

L.4 CTS 4.5.3d requires that prior to the reactor going critical after a refueling outage, a visual check will be made to confinn that all "locked-closed" manual containment isolation valves are closed and locked except for valves that are open under administrative controls. In the ITS, manual valve position verification is required by proposed SR 3.6.3.2 and SR 3.6.3.3. The requirements of SR 3.6.3.2 and SR 3.6.3.3 are less restrictive than the CTS since they only apply to valves that are "not locked, sealed, or otherwise secured in position." This proposed change is acceptable since these valves are verified closed when they are locked, sealed, or .otherwise secured in position. Administrative programs provide the appropriate controls to assure valves that are normally locked, sealed, or otherwise secured in position are in the correct position. This change is consistent with NUREG-1432 as modified by TSTF-45 Rev.I.

L.5 CTS 4.5.3a, CTS 4.5.3b, and CTS 4.2 Table 4.2.2, Items 13.a and 13.b contain details that are not necessary to describe, or are not pertinent to, any actual regulatory requirement. As such, these details are proposed for deletion. ..Specifically:

CTS 4.5.3a describes the testing necessary for CIVs prior to declaring the valves Operable after maintenance, repairs, or replacement work is performed on the valve or it$ associated actuator, control, or power circuit. Explicitly stating these tests as they relate to maintenance activities is unnecessary since the technical specifications stipulate the level of performance that must be met for an Operable CIV in the associated Surveillance Requirements.

CTS 4.5.3b states that each CIV shall be demonstrated Operable by verifying ... valves actuate to their required position*"during Cold Shutdown or at least once per refueling cycle". The phrase "during Cold Shutdown" is intended to describe the plant condition which best facilitates testing the applicable (automatic) CIVs. The phrase "at least once per refueling cycle" establishes the frequency for the test. Spec1 mg the plant condition at which CIV testing is performed (i.e., Cold Shutdown) is a detail which is not pertinent to the actual requirement for testing CIVs. The LCO Applicability for CIVs stipulates the plant conditions when CIVs are required to be Operable. Testing within the Applicability is governed by valve Operability, testing in plant conditions outside the Applicability has no impact on safety.

CTS 4.2 Table 4.2.2, Item 13a states the containment purge and ventilation isolation valves are determined closed "by checking the valve position indicator in the control room". The intent of verifying valve position is to ensure that the valve is in its correct position. Specifying that valve position be verified "by checking the valve position indicator in the control room" does not ~onstitute a requirement assumed iii the safety analyses. Rather, it simply provides a method for assuring the valve is in the correct position. Since the valves may be locked closed electrically, mechanically, or by other physical means, stipulating "by checking the valve position indicator in the control room" is an inappropriate detail not pertinent to the actual requirement.

(continued)

Palisades Nuclear Plant Page 10of11 05/31/99

ATTACHMENT 3

_ DISCUSSION OF CHANGES SPECIFICATION 3.6.3, CONTAINMENT ISOLATION VALVES L. 5 (continued)

CTS 4.2 Table 4.2.2, Item 13b states the containment purge and ventilation isolation.

valves are determined closed by performing a leak rate test "between the valves." .

Specifying that a leakage rate test be performed "between the valves" does not constitute a requirement assumed in the safety analyses. Rather, it simply provides a method for conducting the leakage rate test.

Since the above details are not necessary to describe, or are not pertinent to, any actual regulatory requirement, they can be deleted without an impact to public health and safety. These changes are consistent with NUREG-1432.

L.6 CTS 4.5.3b requires that each containment isolation valve be demonstrated Operable by verifying it actuates to its required position. In the ITS, an equivalent test is required by SR 3.6.3.6. However, ITS SR 3.6.3.6 does not require containment isolation valves under administrative controls that are locked. sealed, or otherwise secured in position to be tested. This is because these valves are already in the position necessary to -

perfonn the containment isolation function. Thus, there is no need to verify these valve can reposition on an actual or simulated actuation signal. The allowance not to test containment isolation valves that are locked, sealed, or otherwise secured in position is a relaxation from the requirements of the CTS. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 11of11 05/31/99

DOC 3 6 3, L.7 CTS 4.5.3c states "the isolation time of each power operated or automatic valve shall be verified in accordance with Section XI of the ASME Boiler and Pressure Vessel Code." ITS SR 3.6.3.4 requires a verification that "the isolation time of each automatic power operated containment isolation valve is within limits. A literal reading of CTS 4.5.3c would indicate that both power operated valves and automatic valve are required to be tested and that SR 3.6.3.4 would only require automatic valves to be tested. However, prior to Amendment 184 to the Facility Operating License for the Palisades Plant, CTS 4.5.3c stated "the isolation time of each power operated or automatic valve shall be determined to be within its limit as specified in Table 3.6.1 when tested in accordance with Section XI of the ASME Boiler and Pressure Vessel Code." The isolation time limits specified in CTS Table 3.6.1 applied only to "Auto Isolation Valves" as denoted in the "REMARKS" column of Table 3.6.1.

In the staffs Safety Evaluation for Amendment 184, it was stated "the staff has reviewed the licensee's proposed deletion of Table 3. 6.1 and its associated TS changes and determined that the changes are in accordance with the guidance ofGL 91-08. Deleting the list of containment isolation valves does not alter the existing TS requirement or the components they apply to. Lists of containment isolation valves are provided in the Final Safety Analysis Report and in the plant procedures for performing penetration leak testing and isolation valve closure time testing. The set of valves subject to the requirements of TS 3.6 and 4.5 will not change due to the proposed change. The staff, therefore, find the proposed change acceptable."

Based on the contents of former CTS Table 3.6.1 and the intent of the change made in Amendment 184, the requirements ofITS SR 3.6.3.4 remain unchanged from CTS 4.5.3c.

However, since the literal reading of CTS 4.5.3c implies a more restrictive set ofrequirements, deletion of non-automatic power operated valves (i.e., power operated CIVs that do not receive an automatic closure signal) has been charactered as a Less Restrictive Change. This change is consistent with NUREG-1432 .

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.6.6, CONTAINMENT COOLING SYSTE:\fS M.8 Not used.

M.9 Proposed SR 3.6.6.2 requires the containment cooler fans to be operated for

~ 15 minutes every 31 days. CTS 4.6.5.b only requires that each fan be exercised, with no minimum operating time. The addition of a required duration to this surveillance requirement is a more restrictive change, consistent with NUREG-1432.

LESS RESTRICTIVE CHANGES - REMOVAL OF DETAILS TO LICENSEE CONTROLLED DOCUMENTS (LA)

LA.1 In the CTS 3 .4. la and b, the major components (i.e., Containment Air Coolers and Containment Spray Pumps) of the containment cooling trains are listed with an associated diesel generator and required to be OPERABLE. In CTS 3.4. lc it also requires that "All heat exchangers, valves, piping, and interlocks associated with the above components and required to function during accident conditions are OPERABLE." In the proposed ITS the LCO will simply read: "Two containment cooling trains shall be OPERABLE." In the proposed ITS, the information regarding

what will comprise a train of containment cooling is not included in the TS LCO but will be addressed in the Bases. Changes to the Bases are made under licensee control in accordance with the Bases Change Control Program which is addressed in Chapter S of the ITS. This change is consistent with NUREG-1432.

LA.2 Not used.

LA.3 CTS 4.6.3a for Containment pray Pumps states in part that" Alternate manual le and the local breaker shall be practiced in the te program." CTS 4.6.3b s on to require that the pumps " ... operate for at ast fifteen minutes." The level o etail provided by these statements is more approp ate for plant test procedures. e overall requirement is that the pumps be teste to ensure their OPERAB . The requirement to alternate manual starting be een the le and the local breaker and to run the pump for a east not included in the proposed ITS and will be addr sed by plant test procedures. ges to plant test procedures are made in accord ce with the plant change con I process. These changes are consistent with N G-1432 .

05/31199 Palisades Nuclear Plant Page 5 of 8

REVISED NSHC

. ATT ACIThlENT ~

NO SIGNIFIC~'IT HAZARDS CONS ID ERATION SPECIFICATION 3.6.3, CONTAlmilENT ISOLATION VALVES LESS RESTRICTIVE CHANGE L.S (continued)

CTS 4.5.3b states that each CIV shall be demonstrated Operable by verifying ... valves actuate to their required position "during Cold Shutdown or at least once per refueling cycle". The phrase "during Cold Shutdown" is intended to describe the plant condition which best facilitates testing the applicable (automatic) CIVs. The phrase "at least once per refueling c cle" establishes the frequency for the test Specifying the plant condition at which CIV testing is performed (i.e., Cold Shutdown) is a detail which is not peninent to the actual requirement for testing CIVs. The LCO Applicability for CIVs stipulates the plant conditions when CIVs are required to be Operable .. Testing within the .Applicability is governed by valve Operability, testing in plant conditions outside the Applicability has no impact on safety.

CTS 4.2 Table 4.2.2, Item 13a states the containment purge and ventilation isolation valves are determined closed "by checking the valve position indicator in the control room". The intent of verifying valve position is to ensure that the valve is in its correct position. Specifying that valve position be verified "by checking the valve position indicator in the control room" does not constitute a requirement assumed in the safety analyses. Rather, it simply provides a -

method for assuring the valve is in the correct position. Since the valves may be locked closed electrically, mechanically , or by other physical means, stipulating* "by checking the valve position indicator in the control room" is an inappropriate detail not peninent to the actual requirement.

CTS 4.2 Table 4.2.2, Item 13b states the containment purge and ventilation isolation valves are determined closed by performing a leak.rate test "between the valves." Specifying that a leakage rate test be performed "between the valves" does not constitute a requirement assumed in the safety analyses. Rather, it simply provides a method for conducting the leakage rate test Since the above details are not necessary to describe, or are not pertinent to, any actual regulatory requirement, they can be deleted without an impact to public health and safety.

These changes are consistent with NUREG-1432.

lhe.. oc.c.urn.~c.-c.. o~ t'-. wo,.J or" / o O.I'\ e d 1+or1cJ ,_,.,.or a,nd hCLC bc.U\ OY'r\W\1-HL/ /'J lt\C.<. 1+ w~ n~t 1~tr.."deJ

+6 (>1'61Ji~). f'l 6r unl.J~ a.~, a..n Qi+<.rl'Q;+iVc. - eel\dltlct\

for ft.r~rtr-o."tt bl:lwu.n 11 C.oli Shu+d*wn" ()..nr:I 1*

n. ~t.Lt~ca c. ydt *:

Palisades Nuclear Plant Page 7of10 05/31/99

ATT ACIThlENT -'

NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.6.3, CONTAINMENT ISOLATION VALVES

3. *Doe8 this change involve a significant reduction in a margin of safety?

The margin of safety is a function of the overall containment leakage. The proposed*

change deletes the requirement to perform an actuation test of containment isolation valves that are locked, sealed, or otherwise secured in position. This change does not relax the requirement to maintain containment integrity, but recognizes that valves that are locked, sealed, or otherwise secured in position are already capable of performing their isolation function. As such, this change does not result in any activity that would result in an increase in the amount of radioactive material released to the environment.

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Palisades Nuclear Plant Page 10of10 05/31/99

NSHC for DOC 3 6.3, L.7 CTS 4.5.3c states "the isolation time of each power operated or automatic valve shall be verified in accordance with Section XI of the ASME Boiler and Pressure Vessel Code." ITS SR 3 .6.3 .4 requires a verification that "the isolation time of each automatic power operated containment isolation valve is within limits. A literal reading of CTS 4.5.3c would indicate that both power operated valves and automatic valve are required to be tested and that SR 3.6.3.4 would only require automatic valves to be tested. However, prior to Amendment 184 to the Facility Operating License for the Palisades Plant, CTS 4.5.3c stated "the isolation time of each power operated or automatic valve shall be determined to be within its limit as specified in Table 3.6.1 when tested in accordance with Section XI of the ASME Boiler and Pressure Vessel Code." The isolation time limits specified in CTS Table 3.6.1 applied only to "Auto Isolation Valves" as denoted in the "REMARKS" column of Table 3.6.1.

In the staffs Safety Evaluation for Amendment 184, it was stated "the staff has reviewed the licensee's proposed deletion of Table 3. 6.1 and its associated TS changes and determined that the changes are in accordance with the guidance of GL 91-08. Deleting the list of containment isolation valves does not alter the existing TS requirement or the components they apply to. Lists of containment isolation valves are provided in the Final Safety Analysis Report and in the plant

'procedures for performing penetration leak testing and isolation valve closure time testing. The set of valves subject to the requirements of TS 3.6 and 4.5 will not change due to the proposed change. The staff, therefore, find the proposed change acceptable."

Based on the contents of former CTS Table 3.6.1 and the intent of the change made in Amendment 184, the requirements ofITS SR 3.6.3.4 remain unchanged from CTS 4.5.3c.

However, since the literal reading of CTS 4.5.3c implies a more restrictive set ofrequirements, deletion of non-automatic power operated valves (i.e., power operated CIV s that do not receive an automatic closure signal) has been charactered as a Less Restrictive Change. This change is consistent with NUREG-1432.

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. Consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event. The proposed change deletes wording from the Technical Specifications that is not related to the actual requirement. The deletion of this information is not assumed to be an initiator of any analyzed event. Thus, the probability of an accident remains unchanged. The proposed changes do not reduce the functional requirement or alter the intent of any specification. As such, the consequences of an accident remains unchanged. Therefore, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the change create the possibility of a new or different kind of accident from

any accident previously evaluated?

The proposed change deletes information from the Technical Specifications that is not necessary to describe the actual requirement. The changes will not alter the plant configuration (no new or different type of equipment will be installed) or make changes in methods governing normal plant operation. The changes will not impose different requirements, and adequate control of activities will be maintained. The changes will not

alter assumptions made in the safety analysis and licensing basis. Therefore, the changes will not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

Margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. There are no design changes or equipment performance parameter changes associated with this change. No setpoints are affected, and no change is being proposed in the plant operational limits as a result of this change. The proposed changes delete information from the Technical Specifications that is not directly related to the actual requirement and does not alter the intent of the requirement. Therefore, the proposed changes do not involve a significant reduction in a margin of safety .

REVISED NUREG MARKUPS

3.6 CONTAINMENT SYSTEMS

3. s. 6ID rn~n=~~~~~~~~;;,.;:~~~~~~~~~;:::::.;-.1 c.i-s i.4.t LCO 3.6.6Q\ Two containmentlspr~ trains and/two containl]}entlcooling trains shall be OPE BLE. 1(0 APPLICABILITY: MODES 1, 2, ~ndt'3,[,/and 4f.I ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

(§v- .., "it ;I,,,

One containment~

(Cool;"~ .

A.l Restore containment C..'\"'~ 3. ~:z.

c.TS' l.'4.3 trai~inoperable. ~!train to 1--------------. OPERABLE status.

Af'JQ...

A+- \e.:.S'\- I 00 '?.., af:. ~ *

'-"'"l :~ ~ C.e.. ( "'.L: l: l-1

~i~:JJ<....t- ,-h:. c.. 'l': .... 'lle...

0\'1Z.4iJl.£ (.~ .....+..:""---"-t c.oJ:_,+... ~ ~

B. One containment 8.1 Resto containment cooling train cool* g train to inoperable. OPE BLE status.

4 days from discovery of

©

~

failure to meet the LCO

c. Two ontainment spray Restore one 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months tr ns inoperable. containment sp train to OPE status.

(continued)

CEOG STS 3.6-21 Rev 1, 04/07/95

~

Containment~ Cooling Systems j (Atmispheric)nd DualJJ-?)

3.6.6il-(li)

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3. 6. 63. l Verify each containment spray manual, power 31 days operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position.

.... *. -lv;-;-,

I

~.:r c.~

CTS !..\ l...SJ. SR 3.6.6f.2 Operate each containment eeeliA~ t11;n fan 31 days unit for ~ 15 minutes.

'<"il-.9."

. ---*--....._\

-.J\~,-~-:;_1*-.:,,. ...~-t'..'~;l'\1; C.:"n**f1":.(CI\~:\

l3Vdays/~ 'L-. 0 ~*\.sJ @

v~X-3 l@

31 days In accordance with the Inservice Testing Program SR 3.6 . * &* Verify each automatic containment spray '(1afmonths I Q:}

valve iR the flow path that is not locked, sealed, or otherwise secured in position, actuates to its correct position on an actual or simulated actuation signal.

(continued)

CEOG STS 3.6-23 Rev 1, 04/07/95

Canta i nment RAtmospher!cT~,@)

B 3. 6 .1 .

B 3.6' CONTAINMENT SYSTEMS B 3. 6 .1 Canta i nment I(AifuospherfcJ]

BASES I

a. 00:::::: ~ '

~ROUND The containment consists of tJ'e concrete lreietor bu}{d]Jlil / ~

l(g:B}, itf'stee~ ~1~r~ and the penetrations through this

~~T~vl structure. lht~c ure is designed to contain radioactive material that may be released from the reactor core following a Design Basis Accident (OBA). Additionally, this structure provides shielding from the fission products that may be present in the containment atmosphere following accident conditions.

The containment is a reinforced concrete structure with a rc:,__\_,,""',l "':-\.t... c~--'*--*"""-"~ cylindrical wall, a fllt foundati2n mat, and a s~allow dome l,1;'.2 f----..:...r~oo;.;f:-.:;*:1: !For cotfta i nmenY? with ungrputed tendons,,1 A.he cylinder \__0 T"r": \ol <+eel '!'e -.hre:..-"> wall is prestressed with a post tensioning system in the -~

Th_,_ ;,..,+,.r.,e-~ oN!ss,,.~ vertical and horizontal direction~@,t'he dome roof is /(0 1 prestressed utilizing a three way p'lfst tensioning system.

/.,,.~Js 0

"' \4 bd~ s\C\b The inside surface of the containment is lined with a carbon steel liner to ensure a high degree of ,leak tightness during a.~ .--.~:,-k.l ~ b 0 ~ ~ operating and accident conditions.

e.-...~,~ ,_~:I f~;' "'~- s+. .,,....._+....,.e. n The concrete* is requ l red for structural integrity of the I \.'::!)

c..."'~ H-*- -::h"4~ ,.,t: containment under OBA conditions. The steel liner and its

.- ~

~ ce:~~r(><{ c._a,..r*.r"'*

4 e penetrations es tab 1i sh the 1eakage limiting boundary of the containment. Maintaining the containment OPERABLE limits

,\,._\ the leakage of fission product radioactivity from the containment to the environment. SR 3.6.1.1 leaka e *rate req~1~emen s comp y w1 . , ppen ix mod1f1ed by approved exempt1ons. > opr.,~~ c to..- lire A +-:st,r

,,_.,,) 0

f. I , as *~

- ~A+;,, T-w i3+-Cl-c:~

I':;\

Ji;'i

~

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

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

I. capable of being closed by an OPERABLE automatic containment isolation system, or (continued)

B 3.6-1

~ 'Po. I: sc.c#H r-..) .... d~.,,, (t .. -+

""" C"'4.,,,"( ~n. ""'~ik o-+-

Containment J (Atmospheti cl h@J B 3.6. '

BASES ACTIONS B.l and B.2 (continued)

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

SURVEILLANCE SR 3.6.1.l REQUIREMENTS

+k (..o,..f-"-:- .....-e~f- Le ...\:.

1-~~~CI

~ ...h. Tesh'\ P.ro~,..,._

(ct)l'\iG.11'"""'+ l~falq,ttfl\J1--~

(.,.,,~tc..:~~e~~ L .....~

Re...t-e Tl!'di" p,..°j ..r...--.

SR 3.6.1.2 (continued)

CEOG STS B 3.6-4 Rev 1, 04/07/95

(_ It-..J SlRT

INSERT SR 3 6 1 3 Maintaining the containment OPERABLE requires compliance wit'- )he Type B and C leakage rate test requirements of 10 CPR 50, Appendix J, Option 1:J1~ modified by approved exemptions.1'Testing is performed at pressures ~ 55 psig. As left leakage prior Othe first startup affer performing a required 10 CPR 50, Appendix J, Option A, leakage test is required to be < 0.6 La for combined Type B and C leakage. At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of~ 1.0 La. At~ 1.0 La the offsite dose consequences are bounded by the assumptions of the safety analysis. SR Frequencies are as required by Appendix J, Option A, as modified by approved exemptions. Thus, SR 3.0.2 (which allows Frequency extensions) does not apply. These periodic testing requirements verify that the containment leakage rate does not exceed the leakage rate assumed in the safety analysis.

SR 3 .6.1.3 is modified by a Note which states that local leak tests shall be performed at pressures~ 55 psig. This value corresponds to the design pressure of the containment and bounds the maximum expected internal pressure resulting from an MSLB or design basis LOCA.

fo_d1.>f1.. ~ t"\'-t:\ Q..tr 1oc.t:. o,.,..d C.r"to..lf\Mt..... + l~C}{.c.+ttl\ ~lvt..

0

'._ ) e.a,.;('o.a~ ~\ rr.i45. d o's f'\tit. /n tJa. hci 0.+t f he a.. CC.~-t o..~ i IA'j o f th<- oulr-a.Ll 11Pt A /J._v_v x~ a'"

1 1 *

ae:1'c.rm,"a..+1ein.

B 3.6-4

Containment ~~o-~p_h_e_ti£[k~

B 3. 6 .1 -

BASES (continued)

REFERENCES I. [ 10/CFR 50, Aplendix J. -1 FS AR, C..ho.\ltu fLf k~

2. FSAR, Section f~ I (I)

3. FSAR, Section t~ / (I)

[4. Re~ulatory Gif'ide 1.35, /Revision [lJ. ~

Y- to C.Ef. so 1 As?e-rd"" .

~

CEOG STS B 3.6-5 Rev 1, 04/07/95

Containment Air Locks /<Atmoi{iheri c a/id Dua 1} 1-:q:

B 3 .6. 2 - ~-

BJ.SES ACTIONS C.l. C.2. and C.3 (continued)

Additionally, the affected air lock(s) must be restored to OPERABLE status within the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time. The specified time period is considered reasonable for restoring an inoperable air lock to OPERABLE status, assuming that at least one door is maintained closed in each affected air 1ock.

0.1 and 0.2 If the inoperable containment air lock cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to

@ at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to HOOE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SR 3.6.2.1 Maintaining containment air locks OPERABLE requires compliance with the leakage rate test requirements of

/of£oW AL 10 CFR SO, Ap~endix ~(Refj.(), as modified by approved

..__ _ _ _ _ _ _...;e;.,.;x~em,;;.;p;.;;t..._10;..;n,;.;;s~. ~This Slrreflects the leakage rate testing 1(0 requ1remen s with regard to air lock leakage (Type B leakage r Le&A.t<a.0t. rG\.-k tcis, e+ntr tests). The acceptance criteria were established during initial air lock and containment OPERABILITY testing. The

fh4.,.. p,l'Jct'\*ML Cl.lr 1~ periodic testing requirements verify that the air lock

~Q:ICS' b11.k'1'\ +nc .0(0.l.S leakage does not exceed the allowed fraction of the overall

+c st, O.t't N'W'w-J con a nmen e a e a . The Frequency is required by A~pendix ,l, as modified by approved exemptions. Thus, r>.4' i='CS~vrtS ? SSpr1' {,PP-+uau "A] SR 3.0.2 {which allows Frequency extensions) does not apply.

fO(lt

fr);lslRf7 f4 The SR has been modified by~ Notes. Note 1 states that an inoperable air lock door does not invalidate the previous successful performance of the overall air lock leakage test.

This is considered reasonable since either air lock door is capable of providing a fission product barrier in the event of a OBA. Note 2 has been added to this SR requiring the results to be evaluated against the acceptance criteria of (continued)

CEOG STS B 3.6-17 Rev 1, 04/07 /95 Sub~~uc.n_, a.~ncf d\CJ'\ts f6 inc. +c.c.!-*'ltC) I S~c.tc(A.t;~

(e.i/1 s(. cJ -fht ac.c e.ffa.nc.t. Cr1 +c.r I 0. f'or cl/ut'.I I 1y rt 5 I (_

A(A.C'\a.6' J1m1fs a,l'\aJ prwideJ for ft-it PuJonncL air- lot.< oloor.s arid VYIU'~.._11r-y a.1r loc.( deers (Re~. e. ').

f'i(.W a.ctcNo.ncc. c.r,Juio..

Containment Air Locks f (Atkospheri ti and Ducvi i}-~

8 3.6.2

r-r----k BASES SURVEILLANCE REQUIREMENTS SR 3.6.2.1 {continued) r-3 SR 3.6.l[J>:- This ensures that air lo~leakage is properly LINSl~T f uccounted for in determining the@lr containment leakage

/SrF 52.

I D

l\c.v' I rate., (ecmb/ncJi'YA:. &0..l'ldC)

SR 3.6.2.2

'B' REFERE~CES 2,. -(: 10 CFR 50, Appendix J.

& (Che-rhJ ©(Z) FSA~ t@"fyn) ~ I CD (0@ FSAR, Section sf~

I© e.v~r\ \ 6 ""o"'-f\-s. \'r.A.. l B ,..,...,. ....+h i:-~{~"~ ;r 'be..<eJ "'" ..J.M ~ h

~.e..r.\=..'""" -tt-.:, S.... , ... e:l\c.""u_ "-"':'Je.,.. 4-\...L c.a""J;~* .. .--.~ .+k...+ ""f1'11 d...,., .... '\ c. Fk~1 o~Te.."(fl- I "'"'~ ~ rc+e"'.h*e-!1_ _\:..,,. loss Os;: c.o~~.:..: .... ..... e--.+ Cl'GlZABI t...1T'I it~ S.._~_,..;\\d,,...o lo.le~ perf...,. ..... e.J w:..\1.-~ *. ,,..~M:io,. ~ f"'~r.

lhc. ti l'nbath Fn1V<.ntf ~r- ~ ll\ic,1)0(): 1~ ~Afititd ~ "' ~'"tr ic.

O~tinfJI .l:l'fe~IC(\Ce-CEOG STS B 3.6-18 Rev 1, 04/07/95

BASES (continued)

This LCO provides assurance that the containment isolation valves and purge valves will perform their designed safety ,C\

fu11ctions to minimize the loss of (fe:a(tor) coolant inventory hJ.J and establish the containment oundary during accidents.

APPLICABILITY In HODES l, 2, 3, and 4, a OBA could cause a release of.

radioactive material to containment. In MODES 5 and 6, the probability and consequences of these events ire reduced due to the pressure and temperature limitations of these MODES.

Therefore, the containment isolation valves are not required to be OPERABLE in MODE 5. The requirements for containment isolation valves during MODE 6 are addressed in LCO 3.9.3, "Containment Penetrations."

(continued)

CEOG STS B 3.6-22 Rev 1, 04/07/95

Contai iment Isolatio(1 Vabes (Atilj6spheri:;t' and Df'r.J1b)

B 3. .

BASES ACTIONS C.1 and C.2 (continued) path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the

~ affected penetration. Required Action C.l must be completed 72.. within the ::<<f:F-hour Completion Time. The specified time I \5 period is reasonable, considering the relative stability of 7S Tf

3o, f?t.vz the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of supporting containment OPERABILITY during MODES 1, 2, 3, and 4. In the event the affected penetration is isolated in accordance with Required Action C.1, the affected penetration flow path must be verified to be isolated on a periodic basis. This is necessary to assure leak tightness of containment and that containment penetrations requiring isolation following an accident are isolated. The Completion Time of once per 31 days for verifying that each affected penetration flow path is isolated is appropriate considering the valves are operated under administrative controls and the probability of their misalignment is low.

Condition C is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with only one containment isolation valve and a closed s stem. This Note is necessary since this Condition is wr1 en to specifically address those penetration flow paths in a closed system.

Required Action C.2 is modified by a Note that applies to valves and blind flanges located in high radiation areas and allows these devices to be verified closed by use of administrative means. Allowing verification by adminis~rative means is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment of these valves, once they have been verified to be in the proper position, is small.

J 11---~---~~-~--~~~~ ~~---~~~

12.:.l

[ With the condary containmen bypa~s leakage ra not within li it, the assumption of the safety anal sis are not (continued)

CEOG STS B 3.6-26 Rev 1, 04/07/95

Containment Isol-.tion Valves /(Atn\6'spheri(/and Dual)~

B 3 .6.3'

BASES SURVEILLANCE REQUIREMENTS SR 3.6.3.~continued} \(I:)

administrative means is considered acceptable, since access to these areas is typically restricted during MODES l, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these containment isolation valves, once they have been verified to be in their proper position, is small.

SR 3.6.3. I[)

Verifying that the isolation time of each ~w!ir operrted and~

automatic.,...containment isolation valve is within limits is IM) required to demonstrate OPERABILITY. The isolation time test ensures the valve will isolate in a time period less than or equal to that assumed in the safety analysis . .s{'The isolation time and Frequency of this SR are in accordance with the Inservice Testing Program pr §2 daNS\}V I~

a.s S Pec.1Y tn the SuJc.tt &IL.o.4-10fl .fOr A"""",.J mt.rr\ /Jo. 9 o i-o tht. fu&..i L+t o*~(.rc. ti*" 1'..ic.e.~-t-(cont i nu.ed}

CEOG STS B 3.6-31 Rev 1, 04/07/95

Containment Isolation Valves i(AtJri"ospheric/?nd Dual)~

B 3.6.3 BASES SURVEILLANCE REQUIREMENTS equal to the specif'ed leakage rate. This rovides assurance* that the assumptions in the saf y analysis are met. The leakag rate of each bypass le age path is assumed to be t maximum pathway leaka e {leakage through the worse of t e two isolation valves) unless the penetration i isolated by use of on closed and de-activate automatic valve, close manual valve, or blind flange. I this case, the leakage rate of the isolated bypass le age path is assumed t be the actual pathway f3J

~

leakage rough the isolation d ice. If both isolatio valves n the penetration are osed, the actual leaka.£fe rate

the lesser leakage r e of the two valves. ~is meth of quantifying maxim pathway leakage is on to be use for this SR (i.e., Ap ndix J maximum pathwaY. leakage li its are to be quantifi ~in accordance with A endix J).

u\e Frequency is requir by 10 CFR 50, Appendi J, as

~dified by approved e mptions (and therefore the Frequency extensions f SR 3.0.2 may not be plied), since the testing is an AP, endix J, Type C test. his SR simply imposes additional cceptance criteria.

(Bypass leakage *s considered part of L. (Reviewer's Note:

Unless specifi lly exempted].]

1 - - - - - - - - . . L . ._ _ _ _ _ _ _ ___!._ _ _ _ _ _ _ _ _ _ _ _

REFERENCES 1. FSAR, Section offf. l CJ l 2. / FSAR, se(Jion [ ] . I (j)

@ @. Generic Issue B-20.

/4. /Genericftssue B-i4./@

Q) ~ 10 CFR 50, Appendix J.

CEOG STS B 3.6-33 Rev 1, 04/07/95

Cont ai nr.i~nt Air Temperature [(Atii}6spher.i c ani Dual) ~*'§':

B 3.6.5 --

BASES (continued)

ACTIONS A.1 When containment average air temperature is not within the limit of the LCO, it must be restored to wjthin limit within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . This Required Action is necessary to return operation to within the bounds of the containment analysis.

The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is acceptable considering the sensitivity of the analysis to variations in this parameter and provides sufficient time to correct minor problems.

8.1 and 8.2 If the containment average air temperature cannot be restored to within its limit within the required Completion Time, the plant must be brought to a MODE in whi~h the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.5.1 REQUIREMENTS Verifying that containment average air temperature is within the LCO limit ensures that containment o eration remains w1th1n the limit assumed for the containment analyses. In ~

1\-..R.. \'100F' \;...,:~ i~ ~ order to determine the containment average air temperature, o:r:

o...c...t-"'-J... I: .....:~ ... s, ..... -~J. an arithmetic average is calculated using measurements taken at locations within the containment selected to provide a

.f-.:...- 4 c..ec.:Je~ o.,,-,.J.s~ representative sample of the overall containment atmosphere.

4...,) Joe.S I"\<>+ c.(CD~t The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of this SR is considered acceptable based on the observed slow rates of temperature increase

{-o .r i AS+ ,.r ....... ""' " .--..;- within containment as a result of environmental heat sources

,._ a.c.c. .... r £-C. \~~,* I~t (due to the lar e volume of containment . Furt ermore, e our r, quency 1s cons1 re a equa e 1n vi of other

()t(e~otlCS ~,~ 0.G~unTc.d indicati s available in t e control room, in uding alarms, ~

I I'\ i'hi. (.) tli"UIC.l b.I\ t;e to aler the operator to n abnormal contain nt temperature ~

fr~(a..re. condit"on.

(continued)

CEOG STS B 3.6-42 Rev 1, 04/07/95

(~

Containment ~--p-r/ij-,--,iln,......,~ Cool i11(. Systems /(Atlii6spheric ani"OU: ~---,0J B 3. 6. *j I:. ./

l BASES SURVEILLANCE SR 3.6.6j.l (continued)\ .r?)

REQUIREMENTS those valves outside containment and capable of potentially being mispositioned, are in the correct position.

SR 3.6.sj}.2 (1) 1 S:\fa:t'I ftl.:a.ted C. ,._1-,,_: __ .,~+ A-.',. c..Ju 0

1-/J\

z1J Operat1ng each111tontA10mentZcool1nglfrajn*fan unit for *

~ 15 minutes ensures that all trains are OPERABLE and that all associated controls are functioning properly. It also ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action. The 31 day Frequency was developed considering the known reliability of the fan units and controls, the two train redundancy available, and the low probability of a significant degradation of the containment cooling train occurring between surveillances.

F~At..- '(.J.le ~-(

I.I !z_)

~

SR 3.6.61Jfu-*

Veri fyin~ a~i ce water fl ow rate of v~~1. vr1-~-Z,o..-.J.v'1H.-n-?1c001 ingitl provides assurance the design f~~ rate assumed in the safety *analyses will be achieved (Ref~. Also

~ ~9~ to @ l fG',

(!;

considered in selectin this Frequency were the known reliability of the ~ter /Ystem, the ct'di?'tr redundancy, and th~ low probability of a significant degradation of flow occurring _between surveillances.

-, J> t.t.~ \)/l>-T\'-l.

the containment spray header is full of water to the -ii";;ua:;;1r:ft mln1mizes the time required to fill the header. This ensures that spray flow will be admitted to the containment atmosphere within the time frame assumed in the containment analysis. , The 31 day Frequency is based on the static nature of the fill header and the low probability of a significant degradation of the water level in the piping occurring between surveillances.

(tontinued)

CEOG STS B 3.6-62 Rev 1, Q4/07/95

REVISED JFDs

ATT ACIDIE~T 6 JUSTIFICATION FOR DEVIATIONS SPECIFICATION 3.6.1, CONT AL~IE:NT Change Djscussjon

8. The Palisades Nuclear Plant used Regulatory Guide l.3S as a reference for the Containment Structural Integrity Surveillance Program but does not fully commit to Regulatory Guide l.3S,. Therefore, this reference is not included in the proposed ITS.

9. Not used.

10. The Palisades Nuclear Plant is considered to be an" Atmospheric" containment. The heading titles referring to either "Atmospheric" or "Atmospheric and Dual" are deleted since they add no value to the usage of the plant specific Palisades Nuclear Plant Technical Specifications. In addition, the ponions of NUREG-1432 which are provided for "dual" containments are n.ot applicable to the Palisades Nuclear Plant.

11. A new SR (SR 3.6.1.3) has been added to address equipment and penetrations subject to Type Band C leakage rate t~sts in 4ccordance with 10 CFR SO, Appendix J, Option A. The creation of an additional SR is necessary since the Type A testing _*

specified in SR 3.6.1.1 is perfonned in accordance with 10 CFR SO, Appendix J, Option B. The requirement and Frequ.ency of ITS SR 3.6.1.3 is similar to ISTS SR 3.6.1.1 with the exception tb.at it l;;Ontains an explicit requirement to perform leak rate tests at ;i: SS psig consisteni with tire CTS. Conforming changes have been made to the Bases.

ISTS SR 3.6.1.1 was also modified by deleting the sentence which reads, "Failure to meet air lock and purge valve with resilient seal leakage limits .... does *not invalidate the acceptability of these overall leakage determination unless their contribution to the overall Type A, B, and C leakage causes that to exceed limits." The basis for this deletion is that the limit for air lock leakage is me same limit as the limit for combine

. Type B and C leakage and because there is no unique leakage limit specified for purge valves with resilient seals .

Palisades Nuclear Plant Page 2of2 05/31/99

ATT ACIDIE:\'T 6

Change Djscussjop JlJSTIFICATION FOR DEVIATIONS SPECIFICATION 3.6.2, CONTAINMENT AIR LOCKS

7. Not used.

8. The Palisades CTS does not contain a surveillance to test the interlock mechanism of the airlock. SR 3.6.2.2 is added in the proposed ITS. TSTF-17, Rev. 1, revises the Frequency of performing the surveillance from 184 days to 24 months to reflect that the surveillance is performed in the conditions that apply in a plant outage where the airlock is primarily used. For Palisades the Frequency is changed to 18 months to correspond with the current cycle lengths. The proposed changes to NUREG-1432 reflect the wording to perform the surveillance at the 18 month Frequency. This change is consistent with TSTF-17, Rev. 1.

9. The Palisades Nuclear Plant is considered to be an "Atmospheric" containment. The heading titles referring to either "Atmospheric" or "Atmospheric and Dual" are deleted since they add no value to the usage of the plant specific Palisades Nuclear Plant Technical Specifications. In addition, the portions of NUREG-1432 which are _

provided for "dual" containments are not applicable to the Palisades Nuclear Plant.

10 . The NUREG-1432 Bases for the Applicable Safety Analysis is modified to reflect the appropriate information for the Palisades Nuclear Plant. The air lock testing (Type B testing) is performed to 10 CFR 50 Appendix J Option A. The wording for the Option A Pa only refers to the peak pressure from a design basis accident. The Bases have been revised to include the maximum calculate peak pressures for both the LOCA and MSLB and to clarify that Type "B" testing is performed at containment pressure

~ 55 psig .

Palisades Nuclear Plant Page 2 of 2 05/31199

3.62JED11 The Bases discussion ofITS SR 3.6.2. l has been revised to state that "Containment Operability" is equivalent to "Containment Integrity". The purpose of this change is to eliminate the potential misinterpretation of air lock testing frequencies imposed by 10 CFR 5 0, Appendix J that are beyond those frequencies required in the technical specifications. Specifically, both the ISTS and ITS have replaced the term "Containment Integrity" with the term Containment Operability.

However, 10 CFR 50, Appendix J, paragraph III.D.2(b)(ii) continues to require that "air locks opened during periods when containment integrity is not required by the plant's technical specifications shall be tested at the end of such periods at not less the P /' Since the term "Containment Integrity" is no longer used in the technical specification, stating that "Containment Operability" is equivalent to "Containment Integrity" clarifies that air lock testing must be performed prior to entering Mode 4 from Mode 5 regardless if the test has been performed with its specified interval as allowed by SR 3.0.2 and SR 3.0.4 .

ATTACHMENT 4 NO SIGNIFICANT HAZARDS. CONSIDERATION CHAPTER 1.0, USE .AND APPLICATION ADMINISTRATIVE CHANGES (A)

The Palisades Nuclear Plant is converting to the Improved Technical Specifications (ITS) as outlined in NUREG-1432, "Standard Technical Specifications, Combustion Engineering Plants." Some of the proposed changes involve reformatting, renumbering, and rewording of Technical Specifications. These changes, since they do not involve technical changes to the Technical Specifications, are administrative.

This type of change is connected with the movement of requirements within the current requirements, or with the modification of wording which does not affect the technical content of the current Technical Specifications. These changes will also include nontechnical modifications of requirements to conform to the Writer's Guide or provide consistency with the Improved Standard Technical Specifications in NUREG-1432. Administrative changes are not intended to add, delete, or relocate any technical requirements of the current Technical Specifications. Any application of the information in Chapter 1. 0 which results in a significant "more restrictive" or "less restrictive" change will be discussed with its associated application.

In accordance with the criteria set forth in 10 CPR 50.92, Palisades Nuclear Plant staff has evaluated these proposed Technical Specification changes and determined they do not represent

a significant hazards consideration. The following is provided in support of this conclusion.

1. Does the change involve a significant increase in the probability or consequences of an accident previously evaluated?

The proposed changes involve reformatting, renumbering, and rewording of the existing Technical Specification. These modifications involve no technical changes to the existing Technical Specifications. The majority of changes were done in order to be consistent with NUREG-1432. During the development of NUREG-1432, certain wording preferences or English language conventions were adopted. The changes are administrative in nature and do not impact initiators of analyzed events. They also do not impact the assumed mitigation of accidents or transient events. Therefore, the changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

Palisades Nuclear Plant Page 1of5

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION CHAPTER 1.0, USE AND APPLICATION

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed changes involve reformatting, renumbering, and rewording of the existing Technical Specifications. The changes do not involve a physical alteration of the plant (no new or different type of equipment will be installed) or changes in methods governing normal plant operation. The changes will not impose any new or different requirements or eliminate any existing requirements. Therefore, the changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change .involve a significant reduction in margin of safety?

The proposed changes involve reformatting, renumbering, and rewording of the existing Technical Specifications. The changes are administrative in nature and will not involve any technical changes. The changes will not reduce a margin of safety because it has no impact on any safety analysis assumptions. Also, since these changes are administrative in nature, no question of safety is involved. Therefore, the changes do not involve a significant reduction in a margin of safety.

MORE RESTRICTIVE CHANGES (M)

There were no "More Restrictive" changes in Chapter 1.0.

LESS RESTRICTIVE CHANGES - REMOVAL OF DETAILS TO LICENSEE CONTROLLED DOCUMENTS (LA)

There were no "Removal of Details" changes made in Chapter 1.0.

Palisades Nuclear Plant Page 2 of5

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION CHAPTER 1.0, USE AND APPLICATION LESS RESTRICTIVE CHANGES (L)

L.1 CTS Section 10, "Definitions" contains defined terms that are not routinely used in the ITS, and details within defined terms that are not pertinent to the requirement in which .

they apply. Therefore, this information is proposed for deletion. Specifically:

"REACTOR CRITICAL" is defined as "The reactor is considered critical for purposes of administrative control when the neutron flux wide range channel instrumentation 4

indicates greater than 10 % of Rated Power." This definition is not included in the proposed ITS as it is a term which is not utilized throughout the proposed ITS. The administrative means to determine when the reactor is critical will be addressed by plant procedures.

The CTS definitions for "HOT STANDBY" and "POWER OPERATION" both contain the statement "and the neutron flux power range instrumentation indicates .... "

Details with respect to how reactor power is determined is more appropriate for plant procedures given the indications available at certain power levels and their associated accuracy. Therefore, this method of determining reactor power will not be included in the proposed ITS but, will be addressed in plant procedures.

SHUTDOWN BORON CONCENTRATION is defined as " ... a Primary Coolant System boron concentration sufficient to assure the reactor is subcritical by 2 % D.p with all Control Rods in the core and the highest worth Control Rod fully withdrawn."

Shutdown Boron Concentration is not a defined term in the proposed ITS since is not explicitly referred to throughout the proposed ITS. The Shutdown Margin requirements are specified in Section 3 .1, Reactivity Control, which define the amount of Shutdown Margin required. The boron concentration which would provide the required amount of Shutdown Margin will be specified in plant procedures.

Since the above terms and details are not necessary to describe, or are not pertinent to any regulatory requirement, they can be deleted without any impact to public health and safety. These changes are consistent with NUREG-1432 .

Palisades Nuclear Plant Page 3of5

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION CHAPTER 1.0, USE AND APPLICATION

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. Consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event.

The proposed change delete details from the Technical Specifications that are not necessary to describe, or are not pertinent to, any actual regulatory requirement. The deletion of details from the Technical Specifications is not assumed to be an initiator of any analyzed event. The proposed changes do not reduce the functional requirement or alter the intent of any specification. As such, the consequences of an accident remain unchanged. Therefore, the proposed change do not involve a significant increase in the probability or consequences Of an accident previously evaluated.

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change deletes detail from the Technical Specifications that are not necessary to describe, or are not pertinent to, any actual regulatory requirement. The changes will not alter the plant configuration (no new or different type of equipment will be installed) or make changes in methods governing normal plant operation. The change will not impose different requirements, and adequate control of activities will be maintained. The change will not alter assumptions made in the safety analysis and licensing basis. Therefore, the change will not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

Margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. There are no design changes or equipment performance .

parameter changes associated with this change. No setpoints are affected, and no change is being proposed in the plant operational limits as a result of this change. The proposed change deletes details from the Technical Specifications. Removal of these details is acceptable since this information is not directly pertinent to the actual requirement and does not alter the intent of the requirement. Since these details are not necessary to adequately describe the actual regulatory requirement, they can be moved to licensee controlled document without a significant impact on safety. Therefore, the proposed change do not involve a significant reduction in a margin of safety.

Palisades Nuclear Plant Page 4of5

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION CHAPTER 1.0, USE AND APPLICATION RELOCATED CHANGES (R)

There are no "Relocated" changes made in Chapter 1.0 .

Palisades Nuclear Plant Page 5of5

LESS RESTRICTIVE CHANGES (L)

NO SIGNIFICANT HAZARDS CONSIDERATION ATTACHMENT 4 SPECIFICATION 3.1.2, REACTIVITY BALANCE L.1 CTS 4.10 requires that if a difference between the observed and predicted steady-state concentrations reaches the equivalent of 1 % in reactivity, "the Atomic Energy Commission shall be notified within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and an evaluation as to the cause of the discrepancy shall be made and reported to the Atomic Energy Commission within 30 days. " In ITS 3 .1. 2, the requirement to notify the Atomic Energy Commission (Nuclear Regulatory Commission) within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and to submit a report in 30 day has been deleted since the appropriate Required Actions and associated Completion Times (See DOCs M.1 and M.2) for reactivity anomalies of 1 % have been incorporated into the technical specifications. Notification and reporting requirements will be made in accordance with 10 CPR 50.72 and 10 CPR 50.73, respectively. This change is consistent with NUREG-1432.

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. Consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful*

functioning of the equipment assumed to operate in response to the analyzed event.

The proposed change deletes specific notification requirements from the Technical Specifications. Deletion of notification requirements from the Technical Specifications is not assumed to be an initiator of any analyzed event since this information is not pertinent to the operation of the facility. The proposed changes do not reduce the functional requirement or alter the intent of any specification. As such, the consequences of an accident remain unchanged. Therefore, the proposed change do not involve a significant increase inthe probability or consequences of an accident previously evaluated .

Palisades Nuclear Plant Page 1of2

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.1.2, REACTIVITY BALANCE

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change deletes notification requirements from the Technical Specifications. The changes will not alter the plant configuration (no new or different type of equipment will be installed) or make changes in methods governing normal plant operation. The change will not impose different requirements, and adequate control of activities will be maintained. The change will not alter assumptions made in the safety analysis and licensing basis. Therefore, the change will not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

Margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. There are no design changes or equipment performance parameter changes associated with this change. No setpoints are affected, and no change is being proposed in the plant operational limits as a result of this change. The proposed change deletes notification requirements from the Technical Specifications.

Removal of this information is acceptable since reporting requirements mandated by 10 CFR 50.72 and 10 CFR 50.73 continue to provide the appropriate levels of notification commensurate with the importance of the plant condition. Therefore, the proposed change do not involve a significant reduction in a margin of safety .

Palisades Nuclear Plant Page 2of2

ATTAC1'ENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.1.5, SHUTDOWN AND PART - LENGTH ROD GROUP INSERTION LIMITS LESS RESTRICTIVE CHANGE (L)

L.1 CTS 3.10.6b states "The shutdown rods shall not be withdrawn until normal water

level is established in the pressurizer." This requirement was included in the CTS to assure criticality would not occur when the PCS was water solid. In the ITS, LCO 3.4.9, "Pressurizer" provides assurance the reactor will not be made critical when the PCS is water solid. Specifically, LCO 3.4.9 requires the pressurizer water level to be less than 62.8% prior to entering Mode 3. Specifying a maximum pressurizer water level preserves an implicit assumption in the safety analyses that a vapor-to-liquid interface exists in the pressurizer for proper PCS pressure response to anticipated design based transients initiate from a critical reactor. Although the ITS would allow shutdown rods to be withdrawn in Modes 4 and 5 without a bubble in the pressurizer, sufficient margin from a sustained critical condition is assured by maintaining ~ff

< 0.99 in these Modes. Therefore, the requirement of CTS 3.10.6b can be deleted without a significant impact of safety since LCO 3.4.9 ensures the reactor will not be.

made critical until a bubble is established in the pressurizer. This change is consistent with NUREG-1432.

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. The proposed change relaxes the prohibition on the withdrawal of shutdown rods in Modes 4 or 5 until a bubble.is established in the pressurizer. This change does not alter any accident precursors or initiators and thereby does not involve a significant increase in the probability of an accident previously evaluated.

The consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event, and the setpoints at which these actions are initiated. The proposed change does not alter the initial assumptions of any accident analysis, or alter the design assumptions of any system or component relied upon to function in the event of an accident. Therefore, this change does not involve a significant increase in the consequence of an accident previously evaluated .

Palisades Nuclear Plant Page 1of2

2.

SPECIFICATION 3.1.5, SHUTDOWN AND PART - LENGTH ROD GROUP ATTACI'ENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION INSERTION LIMITS Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change does not involve a physical alteration of the plant. No new equipment is being introduced, and no installed equipment is being operated in a new or different manner. The proposed change only relaxes the requirement to establish a bubble in the pressurizer prior to withdrawing the shutdown rods in Modes 4 and 5.

Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

The margin of safety is determined by the design and qualification of plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. The proposed change eliminates the requirement to establish a bubble in the pressurizer prior to withdrawing the shutdown rods in Modes 4 or 5. The purpose for establishing a bubble in the pressurizer is to accommodate anticipated pressure changes in the PCS in response to design basis transients initiate from a critical reactor. There are no analyzed events in Modes 4 or 5 involving an increase in PCS pressure as a result of shutdown rod movement. As such, it is not necessary to require a bubble in the pressurizer while moving the shutdown rods in these Modes. Therefore, relaxing the plant conditions in which the shutdown rods can be moved does not involve a significant reduction in a margin of safety.

Palisades Nuclear Plant Page 2of2

ATTACHMENT 4

LESS RESTRICTIVE CHANGE L.1 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.10, PRESSURIZER SAFETY VALVES In CTS 3 .1. 7 .1, the applicability is stated as "when the plant is operating above cold shutdown." The CTS defines cold shutdown, in part, as an average PCS temperature s: 210°P. In proposed ITS 3.4.9, the Applicability is stated as MODES 1 and 2, and MODE 3 with all PCS cold leg temperatures ~ 430°P. As such, the ITS does not require the pressurizer safety valves to be Operable when any PCS cold leg temperatures are below 430°P as required by the CTS. The function of the pressurizer safety valves is to keep PCS pressure below 1103 of its design value during certain accidents. When any PCS cold leg temperatures are

< 430°P, overpressure protection of the PCS is provided by the components required by proposed ITS 3.4.12, "Low Temperature Overpressure Protection." This is because the setpoints of the pressurizer safety valves are too high to ensure the integrity of the primary coolant pressure boundary is not compromised by limiting the maximum PCS pressure to within the pressure and temperature limits of 10 CPR 50, Appendix G during low temperature operations. The LTOP specification provides PCS overpressure protection by limiting the capability for mass input transients (e.g., limits the number of pumps capable of injecting into the PCS) and by having adequate pressure relieving capacity for heat input transients. Thus, the pressurizer safety valves are not required to provide overpressure protection of the PCS when any PCS cold leg temperatures are < 430°P .

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. The proposed change revises the plant condi~ions in which the pressurizer safety valves are required to be Operable. A change in the applicability of components required by the Technical Specifications is not assumed to be an initiator or precursor to any analyzed event. Therefore, the proposed change does not result in a significant increase in the probability of an accident previously evaluated.

The consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event, and the setpoints at which these actions are initiated. The proposed change does not alter the initial conditions for any analysis, or impact the availability or function of any plant equipment assumed to operate in response to an analyzed event. The function of the pressurizer safety valves is to provide overpressure protection for the PCS. When any PCS cold leg temperatures are < 430 °P, overpressure protection of the PCS is provided by the Low Temperature Overpressure Protection components and restrictions. Thus, the consequences of an accident previously evaluated remain unchanged. Therefore, the proposed change does not involve a significant increase in the consequences of an accident previously evaluated.

Palisades Nuclear Plant Page 1of7

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.10, PRESSURIZER SAFETY VALVES

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated? .

The proposed change does not involve a physical alteration of the plant. No new equipment is being introduced, and no installed equipment is being operated in a new or different manner. The proposed change only relaxes the plant conditions for which the pressurizer safety valves are required to be Operable to be consistent with the safety analysis. Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

The margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. The proposed change revises the plant conditions in which the pressurizer safety valves are required to be Operable such that the valves are no longer required when any PCS cold leg temperatures are < 430°F.

The proposed change does not affect any accident or transient analysis since the pressurizer safety valves are not credited in lower plant modes. This is because the setpoints of the pressurizer safety valves are to high to ensure the integrity of the primary coolant pressure boundary is not compromised by limiting the maximum pressure to within the pressure and temperature limits of 10 CFR 50, Appendix G during low temperature operations. Therefore, this change does not involve a significant reduction in a margin of safety.

LESS RESTRICTIVE CHANGE L.2 CTS 3 .1. 7 .1 action "b" requires that with one or more pressurizer safety valves inoperable, the reactor be placed in Cold Shutdown within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . In proposed ITS 3.4.10 Required Action B.2, if one pressurizer safety valve cannot be restored in 15 minutes, or two or more safety valves are inoperable, then the plant must be placed in MODE 3 with all PCS cold leg temperature < 430°F within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The requirements of the CTS are more restrictive than the ITS since the CTS requires the plant to be placed in Cold Shutdown and the ITS only requires the plant to be placed in MODE 3 with all PCS cold leg temperatures < 430°F. As discussed in DOC L.1, the Applicability for pressurizer safety valves has been revised to exclude those plant conditions when any PCS cold leg temperatures are < 430°F. As such, with one or more pressurizer safety valves inoperable it is only necessary to require the plant to be placed in a condition where the pressurizer safety valves are no longer required to perform the overpressure protection function for the PCS. This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 2of7

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.10, PRESSURIZER SAFETY VALVES

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. The proposed change revises the condition in which the plant is placed when any inoperable pressurizer safety valve cannot be restored to an Operable status in the required amount of time. The proposed change places the plant in a condition outside the Applicability for pressurizer safety valves. Placing the plant in a condition where inoperable components are no longer required by the Technical Specifications is not assumed to be an initiator or precursor to any analyzed event. Therefore, the proposed change does not result in a significant increase in the probability* of ail accident previously evaluated.

The consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event, and the setpoints at which these actions are initiated. The proposed change does not alter the initial conditions for any analysis, or impact the availability or function of any plant equipment assumed to operate in response to an analyzed event. The proposed change

places the plant in a condition where the pressurizer safety valves are no longer credited in the safety analysis whenever an inoperable pressurizer safety valve cannot be restored to an Operable status in the required amount of time. Therefore, the proposed change does not involve a significant increase in the consequences of an accident previously evaluated.

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?.

The proposed change does not involve a physical alteration of the plant. No new equipment is being introduced, and no installed equipment is being operated in a new or different manner. The proposed change only revises the plant conditions in which the plant is placed when any inoperable pressurizer safety valve cannot be restored to an Operable status in the required amount of time. Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated .

Palisades Nuclear Plant Page 3 of 7

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.10, PRESSURIZER SAFETY VALVES

3. Does this change involve a significant reduction in a margin of safety?

The margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. The proposed change only revises the plant conditions in which the plant is placed when any inoperable pressurizer safety valve cannot be restored to an Operable status in the required amount of time. The proposed change does not affect any accident or transient analysis since the plant is placed in a condition in which the pressurizer safety valves are no longer credited in the safety analysis. Therefore, this change does not involve a significant reduction in a margin of safety.

LESS RESTRICTIVE CHANGE L.3 CTS 4.2 Table 4.2.2 item 3 *requires a setpoint test of the pressurizer safety valves at a frequency of "one each refueling." The current fuel cycle at the Palisades plant is 18 months.

Thus, one pressurizer safety valve is tested approximately every 18 months. In proposed ITS 3.4.10, the surveillance frequency for testing the pressurizer safety valves is stated as "in accordance with the Inservice Testing Program." The Inservice Testing Program, as stipulated by the ASME Boiler and Pressure Vessel Code,Section XI and OM-1, require all valves of each type and manufacturer to be tested within each subsequent 5 year period with a minimum of 203 of the valves tested within any 24 months. For the pressurizer safety valves this means that at least one valve shall be tested each 24 months such that all three pressurizer safety valves will have been tested each subsequent 5 year period. The frequency for testing the pressurizer safety valves stipulated in the ITS is less restrictive than the frequency required by the CTS. The proposed frequency is considered acceptable since it is based on industry experience which has shown that this testing interval is sufficient to maintain the status of the pressurizer safety valves such that they are capable of performing their intended safety function and assure continued safe operation of the plant. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 4of7

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.10, PRESSURIZER SAFETY VALVES

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. The proposed change revises the surveillance frequency for verifying the setpoint of the pressurizer safety valves from "one each refueling" to "in accordance with the Inservice Testing Program." Relaxing the frequency in which pressurizer safety valve setpoints are confirmed does not have a detrimental impact on the integrity of any plant structure, system or component. This relaxation will not alter the operation of any plant equipment, or otherwise increase its failure probability. The probability that equipment failures resulting in an analyzed event will occur is unrelated to a component which initiates a protective action. As such, the probability of occurrence for a previously analyzed accident is not significantly increased.

The consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event. The proposed change does not alter the initial conditions assumed in the analysis, or affect the successful functioning of the equipment assumed to operate in response to the analyzed event.

The proposed change revises the frequency for verifying the setpoint of the pressurizer safety valves. The setpoint at which the pressurizer safety valves are assumed to function has remain unchanged. As such, this change does not affect the performance of any credited equipment assumed in the safety analysis. Therefore, the proposed change does not involve a significant increase in the consequence of an accident previously evaluated.

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change does not involve a physical alteration of the plant. No new equipment is being introduced, and no installed equipment is being operated in a new or different manner. There is no alteration to the parameters within which the plant is normally operated or in the setpoints which initiate protective or mitigative actions. No change is being proposed to the procedures governing normal plant operation or those procedures relied upon to mitigate a design basis event. Relaxing the frequency requirement to verify the pressurizer safety valve setpoints does not have a detrimental impact on the manner in which plant equipment operates or responds to an actuation signal. As such, no new failure modes are being introduced. Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated .

Palisades Nuclear Plant Page 5 of 7

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.10, PRESSURIZER SAFETY VALVES

3. Does this change involve a significant reduction in a margin of safety?

The margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. Relaxing the frequency at which the setpoints of the pressurizer safety valves are verified does not significantly impact these factors. There are no design changes or equipment performance parameter changes associated with this change. No setpoints are affected, and no change is being proposed in the plant operational limits as a result of this change. Therefore, this change does not involve a significant reduction in the margin *of safety.

LESS RESTRICTIVE CHANGE L.4 CTS 3.1.7.1Table3.1.7-1 contains footnote"*" which states "After testing or valve maintenance which could affect the setting, it shall be reset to within 1 % of the nominal setpoint prior to being returned to service." In the ITS, it is not necessary to include the phrase "or valve maintenance which could affect the setting" since this activity is covered by the definition of Operability. Anytime maintenance is performed on a component which is required to be Operable by the technical specifications (e.g., an instrument transmitter, or a motor operated valve), a determination of the impact on the components ability to perform its intended function must be made. If it is determined the affected component is no longer Operable, then the component must be declared inoperable and retested to ensure it will function as required. Since the requirement of Operability adequately addresses the return to service of a component following maintenance, it is no longer necessary to include the phrase "or valve maintenance which could affect the setting" in the ITS. As such, this phrase can be deleted from the CTS without altering the intent of the actual requirement. Deletion of these details is acceptable since they are not necessary to describe the actual regulatory requirement and will not result in a significant impact on safety. This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 6of7

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.10, PRESSURIZER SAFETY VALVES

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. Consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event.

The proposed change delete details from the Technical Specifications that are not

necessary to describe, or are not pertinent to, any actual regulatory requirement. The deletion of details from the Technical Specifications is not assumed to be an initiator of any analyzed event. The proposed changes do not reduce the. functional requirement or alter the intent of any specification. As such, the consequences of an accident remain unchanged. Therefore, the proposed change do not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change deletes detail from the Technical Specifications that are not necessary to describe, or are not pertinent to, any actual regulatory requirement. The changes will not alter the plant configuration (no new or different type of equipment will be installed) or make changes in methods governing normal plant operation. The change will not impose different requirements, and adequate control of activities will be maintained. The change will not alter assumptions made in the safety analysis and licensing basis. Therefore, the change will not create the possibility of a new or .

different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

Margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. There are no design changes or equipment performance parameter changes associated with this change. No setpoints are affected, and no change is being proposed in the plant operational limits as a result of this change. The proposed change deletes details from the Technical Specifications. Removal of these details is acceptable since this information is not directly pertinent to the actual requirement and does not alter the intent of the requirement. Since these details are not necessary to adequately describe the actual regulatory requirement, they can be moved to licensee controlled document without a significant impact on safety. Therefore, the proposed change do not involve a significant reduction in a margin of safety .

Palisades Nuclear Plant Page 7of7

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.14, PCS PIV LEAKAGE LESS RESTRICTIVE CHANGE L.1 CTS Table 3 .17. 6 item 17 requires two channels of SDC Suction Valve Interlocks to be Operable "above 200 psia PCS pressure." In proposed ITS 3 .4.14, the SDC suction valve interlocks are required to be Operable in MODES 1, 2, and 3, and in MODE 4, except during the SDC mode of operation, or transition to or from the SDC mode of operation. The requirements associated with the Applicability of ITS 3.4.14 represent a relaxation from the requirements of the CTS since the ITS will allow PCS pressure to be greater than 200 psia without requiring the SDC suction valve interlock function to be Operable. The function of the SDC suction valve interlock to prevent the inadvertent opening of the isolation valves which provide the interface between the high pressure piping in the PCS and the low pressure piping in the SDC system during periods when the PCS pressure is above the design pressure of the SDC system. The Applicability of ITS 3 .4.14 is appropriate since it continues to require the interlock function to be Operable whenever a potential for overpressurizing the SDC system suction piping from the PCS exists. This is ensured by requiring the interlock function to be Operable in all of MODE 4 unless the SDC system is in operation, or is being placed in, or removed from, operation. The lower temperature limit of MODE 4 is 201 °F. At this temperature, the corresponding PCS pressure is well below the 300 psig design pressure of the SDC system suction piping. Thus, ITS 3.4.14 requires the interlock function to be Operable well below the pressure in which it is required to perform its protective function. ITS 3 .4.14 does not require the interlock function to be Operable when the SDC system is in operation or is being placed in, or remove from, operation since these activities are procedurally controlled to occur only when the PCS pressure is within the design pressure of the SDC system piping.

Therefore, the proposed change is acceptable since it contains the appropriate requirements to ensure the integrity of the SDC system is not violated. This change is consistent with NUREG-1432.

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. The proposed change relaxes the plant condition in which the SDC suction valve interlock function is required to be Operable such that it is only required when a potential for overpressurization of the SDC system piping exists. As such, the probability of an accident involving an inter-system LOCA resulting from the failure of the SDC suction valve interlock function can not be increased since the interlock function is still required to be Operable at pressure equal to and greater than the design pressure of the SDC system piping. Therefore, the probability of occurrence for a previously analyzed accident is not significantly increased.

Palisades ,Nuclear Plant Page 1of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.14, PCS PIV LEAKAGE

1. (continued)

The consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event, and the setpoints at which these actions are initiated. The proposed change does not affect the initial conditions of any assumed analysis, or the availability and successful functioning of any equipment assumed to operate in response to analyzed events, or the setpoints at which any actions are initiated. Therefore, this change does not involve a significant increase in consequence of an accident previously evaluated

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change does not involve a physical alteration of the plant. No new equipment is being introduced, and no installed equipment is being operated in a new or .

different manner. There is no alteration to the parameters within which the plant is normally operated or in the setpoints which initiate protective or mitigative actions. No change is being proposed to the procedures governing normal plant operation or those

procedures relied upon to mitigate a design basis event. The proposed change relaxes the plant condition in which the SDC suction valve interlock function is required to be Operable. Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

The margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. The proposed change relaxes the plant condition in which the SDC suction valve interlock function is required to be Operable such that it is only required when a potential for overpressurization of the SDC system piping exists. The function of the SDC suction valve interlock is to prevent an inadvertent opening of the isolation valves which provide the interface between the high pressure piping in the PCS and the low pressure piping in the SDC system during periods when the PCS pressure is above the design pressure of the SDC system.

Eliminating the requirement to maintain the interlock Operable during periods when the PCS pressure is below the maximum design pressure of the SDC system does not result in a significant reduction in a margin of safety since an overpressurization event resulting from a failure of the interlock can not occur. Therefore, this change does not involve a significant reduction in the margin of safety.

Palisades Nuclear Plant Page 2of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.14, PCS PIV LEAKAGE LESS RESTRICTIVE CHANGE L.2 CTS 4.3i requires that whenever the integrity of a PIV can not be demonstrated and credit is being taken for compliance with specification 3.3.3b, "the integrity of the remaining check valve in each high pressure line having a leaking valve shall be determined and recorded daily and the position of the other closed valve located in that pressure line shall be recorded daily."

In proposed ITS 3.4.14, Required Action A.1 requires an inoperable PIV be isolated from the high pressure portion of the affected system by use of one closed manual, deactivated automatic, or check valve. In addition, each valve used for isolation must have been verified to meet the leakage requirements setforth in SR 3 .4 .14 .1. The ITS does not specify that the integrity of the remaining check valve be determined daily since this action represent a condition which is known to exist at the time of isolation, and which must continued to be met by the requirements of SR 3.0.1. Thus, the ITS simply removes an administrative function by eliminating the requirement to record the integrity of a check valve used to isolate an inoperable PIV on a daily basis. The requirement of CTS 4.3i which states "and the position of the other closed valve located in that pressure line shall be recorded daily" is no longer applicable as explained in DOC M.2 for this specification. This change is consistent with NUREG-1432.

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. The proposed change removes an administrative function by eliminating the requirement to record, on a daily basis, the integrity of a check valve used to isolate an inoperable PIV. The flow path which contains the inoperable PIV will continue to be isolated by an Operable valve which meets the specified leakage limits. Deletion of an administrative function is not assumed to be an initiator or precursor of any analyzed event. Therefore, the proposed change will not result in a significant increase in the probability or consequence of an accident previously evaluated .

Palisades Nuclear Plant Page 3of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.14, PCS PIV LEAKAGE

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change does not involve a physical alteration of the plant. No new equipment is being introduced, and no installed equipment is being operated in a new or different manner. There is no alteration to the parameters within which the plant is normally operated or in the setpoints which initiate protective or mitigative actions. No change is being proposed to the procedures governing normal plant operation or those procedures relied upon to mitigate a design basis event. The proposed change eliminates an administrative requirement to record the position of a valve used to isolated a PIV with excessive leakage. Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

The margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. The proposed change does not affect any .

accident or transient analysis. The change only removes an administrative function from the Technical Specifications by eliminating the requirement to record, on a daily basis, the integrity of a check valve used to isolate an inoperable PIV. The integrity of the valves used to pe!form the isolation function remain unaffected by this change.

Administrative processes used to controls plant equipment provide the necessary assurance that the inoperable valve remains isolated. A loss of integrity by the isolation valve will appear as increased PCS leakage which is detectable by plant operators. As such, removing this administrative function from the requirements of the technical specification will not have an impact on the margin of safety. Therefore, the proposed change does not involve a significant reduction in a margin if safety.

Palisades Nuclear Plant Page 4of10

- I I

ATTACH1\1ENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.14, PCS PIV LEAKAGE LESS RESTRICTIVE CHANGE L.3 CTS 3.3.3 and CTS 4.3h required periodic leakage testing of the specified PIVs every time the plant has been placed in the "Cold Shutdown Condition for more than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and such testing has not been accomplished within the previous 9 months." Proposed SR 3 .4 .14 .1 also -

requires leakage testing of specified PIVs but the Frequency is stated, in part, as "whenever the plant has been in MODE 5 for 7 days or more if leakage testing has not been performed in the previous 9 months." The amount of time the plant must be shutdown before PIV leakage testing is required by the ITS has been relaxed from the requirements of the CTS. The ITS allows the plant to be in MODE 5 for up to 7 days before testing is required. The CTS only allows the plant to be in Cold Shutdown Conditions for 3 days before testing is required. The extended period of MODE 5 operation allowed by the ITS does not significantly increase the probability of malfunction of the PIVs since the change in plant status over the four additional days of shutdown time does not change significantly. This change is consistent with NUREG-1432.

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

The proposed change relaxes the surveillance frequency for PIV leak testing. A less frequent performance of a Surveillance Requirement does not result in any hardware changes. The frequency of performance also does not significantly increase the probability of occurrence for initiation of any analyzed event since the function of the equipment, or limit for the parameter, does not change (and therefore any initiation scenarios are not changed) and the proposed frequency has been determined to be adequate to demonstrate reliable operation of the equipment or compliance with the parameter. Further, the frequency of performance of a surveillance does not significantly increase the consequences of an accident because a change in frequency does not change the assumed response of the equipment in performing its specified mitigation functions, or change the response of the core parameters to assumed scenarios, from that considered with the original frequency. Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change does not necessitate a physical alteration of the plant (no new or different type of equipment will be installed) or changes in parameters governing normal plant operation. The proposed change will still ensure compliance with the limiting condition for operation is maintained. Thus, this change does not create the

possibility of a new or different kind of accident from any accident previously evaluated.

Palisades Nuclear Plant Page 5of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.14, PCS PIV LEAKAGE

3. Does this change involve a significant reduction in a margin of safety?

The proposed change relaxes the surveillance frequency for PIV leak testing. Changes in the monitored parameter have been determined to be relatively slow during the proposed intervals, and the proposed frequency has been determined to be sufficient to identify significant impact on compliance with the assumed conditions of the safety analysis. In addition, other indications continue to be available to indicate potential noncompliance. Therefore, an extended surveillance interval does not involve a significant reduction in the margin of safety.

LESS RESTRICTIVE CHANGE L.4 CTS 3.3.3 and CTS 4.3h require all PIVs to be tested prior to returning to Power Operation after every time the plant has been placed in the Refueling Shutdown Condition, or the Cold Shutdown Condition for more than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (See Discussion of Change L.3 for this specification which justifies a change to 7 days). In proposed ITS 3.4.14, a similar testing requirement is associated with the Frequency of SR 3.4.14.1. However, SR 3.4.14.1 does not stipulate the plant condition of "Refueling Shutdown" since this plant condition does not exist in the ITS. Rather, proposed SR 3.4.14.1 contains a Frequency of"l8 months" (See Discussion of Change M.8).

The CTS defines "Refueling Shutdown" as a condition when the primary coolant is at Refueling Boron Concentration (i.e., at least 1720 ppm boron and the reactor subcritical by ~ 5% /::,. p with all control rods withdrawn) and Tave is less than 210°F. In the ITS, the Mode which closely .

matches the CTS plant condition of Refueling Shutdown is "MODE 6, Refueling." Presently, based on fuel design, an operating cycle for the Palisades plant is approximately 18 months. The CTS Frequency of "every time the plant has been placed in the Refueling Shutdown Condition" is essentially the same as the ITS Frequency of"18 months," However, deletion of the CTS Frequency has been characterized as less restrictive since a literal application of the CTS Frequency could result in additional and unnecessary performances of PIV testing. The proposed change eliminates the potential for unnecessary testing by deleting the conditional based surveillance frequency contained'in the CTS. This change is acceptable since PIV testing will continue to be performed consistent with 10CFR50.55a and within the frequency allowed by

. ASME Code Section XI. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 6of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.14, PCS PIV LEAKAGE

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. The proposed change eliminates an administrative requirement associated with the CTS to perform a surveillance on a conditional based frequency. This change does not alter any accident precursors or initiators and thereby does not involve a significant increase in the probability of an accident previously evaluated.

The consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event, and the setpoints at which these actions are initiated. The proposed change does not alter the initial assumptions of any accident analysis, or alter the design assumptions of any system or component relied upon to function in the event of an accident. Therefore, this change does not involve a significant increase in the consequence of an accident previously evaluated.

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change does not involve a physical alteration of the plant. No new equipment is being introduced, and no installed equipment is being operated in a new or different manner. The proposed change eliminates the requirement to perform a CTS surveillance after every time the plant has been placed in the Refueling Shutdown Condition. Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

The margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. The proposed change deletes the requirement to perform a leakage test on PIVs every time the plant is placed in the Refueling Shutdown Condition. Rather, testing is performed every 18 months. This change does not affect established safety limits, operating limits, or design assumptions.

No accident or transient analysis are affected by this change. The proposed change continues to ensure that the PIV s are tested at an adequate frequency to ensure they will function as required. Therefore, this change does not involve a significant reduction in a margin of safety .

Palisades Nuclear Plant Page 7of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.14, PCS PIV LEAKAGE LESS RESTRICTIVE CHANGE L.5 CTS 3.3.3 and CTS 4.3h require a test of the PIVs prior to returning the valves to service "after maintenance, repair or replacement." In the ITS, it is not necessary to stipulate testing requirements related to "maintenance, repair or replacement" since these activities are covered by the definition of Operability. Anytime maintenance, repair or replacement is performed on a component which is required to be Operable by the technical specifications (e.g., an instrument transmitter, or a valve), a determination of the impact on the component's ability to perform its intended function must be made. If it is determined the affected component is no longer Operable, then the component must be declared inoperable and then retested to ensure it will function as required. Since the requirement of Operability adequately addresses the return to service of a component following maintenance, it is no longer necessary to include the phrase "after maintenance, repair or replacement" in the ITS. As such, this phrase can be deleted from the CTS without altering the intent of the actual requirement. Deletion of these details is acceptable since they are not necessary to describe the actual regulatory requirement and will not result in a significant impact on safety. This change is consistent with NUREG-1432.

1. Does the change involve a significant increase in the probability or consequence of

an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. Consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event.

The proposed change delete details from the Technical Specifications that are not necessary to describe, or are not pertinent to, any actual regulatory requirement. The deletion of details from the Technical Specifications is not assumed to be an initiator of any analyzed event. The proposed changes do not reduce the functional requirement or alter the intent of any specification. As such, the consequences of an accident remain unchanged. Therefore, the proposed change do not involve a significant increase in the probability or consequences of an accident previously evaluated.

Palisades Nuclear Plant Page 8of10

ATTAC1'ENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.14, PCS PIV LEAKAGE

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change deletes detail from the Technical Specifications that are not necessary to describe, or are not pertinent to, any actual regulatory requirement. The changes will not alter the plant configuration (no new or different type of equipment will be installed) or make changes in methods governing normal plant operation. The change will not impose different requirements, and adequate control of activities will be maintained. The change will not alter assumptions made in the safety analysis and licensing basis. Therefore, the change will not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

Margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. There are no design changes or equipment performance parameter changes associated with this change. No setpoints are affected, and no change is being proposed in the plant operational limits as a result of this change. The proposed change deletes details from the Technical Specifications. Removal of these details is acceptable since this information is not directly pertinent to the actual requirement and does not alter the intent of the requirement. Since these details are not necessary to adequately describe the actual regulatory requirement, they can be moved to licensee controlled document without a significant impact on safety. Therefore, the proposed change do not involve a significant reduction in a margin of safety.

LESS RESTRICTIVE CHANGE L.6 The requirement to perform periodic leakage testing specified in CTS 4.3h is modified by footnote (a) which states that "to satisfy ALARA requirements, leakage may be measured indirectly (as from the performance of pressure indicators) if supported by computation showing that the method is capable of demonstrating valve compliance with the leakage criteria." Proposed ITS 3 .4 .14 does not contain this same statement since this iriformation only discusses an acceptable method of compliance with the LCO and is not necessary to describe the actual regulatory requirements. The allowance to indirectly measure leakage from a PIV using a pressure indicator does not alter the allowed leakage limit from a PIV but simply provides an alternate method for testing when personnel exposure to radiation is a consideration. Therefore, these details can be deleted from the CTS without a significant impact on safety. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 9of10

ATTAC1'ENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.4.14, PCS PIV LEAKAGE

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. Consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event.

The proposed change delete details from the Technical Specifications that are not necessary to describe, or are not pertinent to? any actual regulatory requirement. The deletion of details from the Technical Specifications is not assumed to be an initiator of any analyzed event. The proposed changes do not reduce the functional requirement or alter the intent of any specification. As such, the consequences of an accident remain unchanged. Therefore, the proposed change do not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the change create the possibility of a new Qr different kind of accident from any accident previously evaluated?

The proposed change deletes detail from the Technical Specifications that are not necessary to describe, or are not pertinent to, any actual regulatory requirement. The changes will not alter the plant configuration (no new or different type of equipment will be installed) or make changes in methods governing normal plant operation. The change will not impose different requirements, and adequate control of activities will be maintained. The change will not alter assumptions made in the safety analysis and licensing basis. Therefore, the change will not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

Margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. There are no design changes or equipment performance parameter changes associated with this change. No setpoints are affected, and no change is being proposed in the plant operational limits as a result of this change. The proposed change deletes details from the Technical Specifications. Removal of these details is acceptable since this information is not directly pertinent to the actual requirement and does not alter the intent of the requirement. Since these details are not necessary to adequately describe the actual regulatory requirement, they can be moved to licensee controlled document without a significant impact on safety. Therefore, the proposed change do not involve a significant reduction in a margin of safety .

Palisades Nuclear Plant Page 10of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM LESS RESTRICTIVE CHANGE L.1 CTS 3.5 does not provide an allowance to restore to OPERABLE status one steam supply to the steam driven AFW pump before declaring the pump inoperable. Proposed ITS 3.7.5

Required Action A.1 is less restrictive in that ITS allows 7 days for restoration prior to declaring the turbine driven pump inopera~le. The change to 7 days is reasonable in that the 7 day Completion Time is based on the redundant OPERABLE steam supply to the turbine driven pump, the availability of redundant OPERABLE motor driven pumps, and the low probability of an event requiring the inoperable steam supply to the turbine driven pump.

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems, or components. The proposed change allows time to restore one redundant steam supply to the steam driven AFW pump. This added allowance of time for restoration of the steam supply does not have a detrimental impact on the integrity of any plant structure, system, or component. This added allowance will not alter the operation of any plant equipment, or otherwise increase its failure probability. As such, the probability of occurrence for a previously analyzed accident is not significantly increased.

The consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to* operate in response to the analyzed event. The number of OPERABLE trains of AFW remains unchanged and continues to be periodically verified when an accident could occur. The change of allowing time for restoration of a redundant steam supply does not affect the assumptions of an analyzed event. This change does not affect the performance of any credited equipment since a redundant 100 % capability steam supply is available. As a result, no analysis assumptions are violated. Based on this evaluation, there is no significant increase in the consequences of a previously analyzed event .

Palisades Nuclear Plant Page 1of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM

2. Does the change create the possibility of a new or different ki.nd of accident from any accident previously evaluated?

The proposed change does not involve a physical alteration of the plant. No new equipment is being introduced, and no installed equipment is being operated in a new or different manner. There is no alteration to the parameters within which the plant is normally operated or in the set points which initiate protective or mitigative actions.

No change is being proposed to the procedures governing normal plant operation or those procedures relied upon to mitigate a design basis event. Allowing time to restore one steam supply to the steam driven AFW pump does not have a detrimental impact on the manner in which plant equipment operates or responds to an actuation signal. As such, no new failure modes are* being introduced. In addition, the change does not alter assumptions made in the safety analysis and licensing basis. Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

The margin of safety is established through equipment design, operating parameters, and the set points at which automatic actions are initiated. Allowing time for restoration of one redundant steam supply to the steam driven AFW pump does not significantly impact these factors. There are no design changes or equipment performance parameter changes associated with this change. Therefore, this change does not involve a significant reduction in the margin of safety.

LESS RESTRICTIVE CHANGE L.2 CTS 3.5.3 requires that if AFW does not satisfy the requirements of Specification 3.5.1 or the conditions of Specification 3.5.2 except as noted in Specification 3.5.4 the reactor must be placed in a COLD SHUTDOWN (ITS MODE 5) condition. With proposed ITS 3.7.5 Required Action C.2, the plant is placed in MODE 4, without reliance on a steam generator for heat removal. This change is less restrictive in the temperature of the primary would be 90°F higher. This change is reasonable in the AFW System is still required to be OPERABLE whenever the system is needed for accident mitigation by the safety analysis. The lowest MODE to which AFW is required by the safety analysis to be OPERABLE in proposed ITS is MODE 4. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 2of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems, or components. The proposed change allows a higher primary temperature where plant shutdown is stopped due to inoperability of AFW. This added allowance of temperature does not have a detrimental impact on the integrity of any plant structure, system, or component. This added allowance will not alter the operation of any plant equipment, or otherwise increase its failure probability. As such, the probability of occurrence for a previously analyzed accident is not significantly increased.

The consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event. The change still requires the plant to be placed in a condition where AFW is no longer required.

Although the primary system temperature may be 90°F higher, AFW is still not required at those temperatures so the consequences of a previously analyzed accident should remain unchanged. As a result, no analysis assumptions are violated. Based on this evaluation, there is no significant increase in the consequences of a previously

2.

analyzed event.

Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change does not involve a physical alteration of the plant. No new equipment is being introduced, and no installed equipment is being operated in a new or different manner. There is no alteration to the parameters within which the plant is normally operated or in the set points which initiate protective or mitigative actions.

No change is being proposed to the procedures governing normal plant operation or those procedures relied upon to mitigate a design basis event. Allowing primary temperature to be 90°F higher does not have a detrimental impact on the manner in which plant equipment operates or responds to an actuation signal. As such, no new failure modes are being introduced. In addition, the change does not alter assumptions made in the safety analysis and licensing basis. Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated .

Palisades Nuclear Plant Page 3of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM

3. Does this change involve a significant reduction in a margin of safety?

The margin of safety is established through equipment design, operating parameters, and the set points at which automatic actions are initiated. Allowing temperature to be .

90°F higher does not significantly impact these factors. There are no design changes or equipment performance parameter changes associated with this change. Therefore, this change does not involve a significant reduction in the margin of safety.

LESS RESTRICTIVE CHANGE L.3 CTS 4. 9a requires that the AFW pumps be started every 31 days. Proposed ITS SR 3. 7. 5. 2 requires the pumps to be tested in accordance with the Inservice Testing Program. This change is less restrictive in that each pump will be started once every 92 days vice every 31 days. This change combines the starting requirement and the code requirements (inservice tests). This change is reasonable in that this test confirms one point on the design curve and is indicative of pump performance as discussed in ASME Code,Section XI (see.DOC A.7). The starting requirement is reasonable due to the findings and recommendation as discussed in NUREG-1366, "Improvements to Technical Specifications Surveillance Requirements." This

change is consistent with NUREG-1432.

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems, or components. The proposed change allows a longer Frequency interval between performance of CTS 4.9.a.1 and 2, AFW pump starting surveillances. This added allowance of Frequency does not have a detrimental impact on the integrity of any plant structure, system, or component. Additionally, from the findings stated in NUREG-1366, "Improvements to Technical Specifications Surveillance Requirements,"

there has been an improvement in AFW pump availability when quarterly testing vice monthly testing has been performed. This added allowance will not alter the operation of any plant equipment, or otherwise increase its failure probability. As such, the probability of occurrence for a previously analyzed accident is not significantly increased .

Palisades Nuclear Plant Page 4of10

ATTACI'ENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM

1. (continued)

The consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event. The parameters by which OPERABILITY of the AFW pumps is determined remain unchanged. The number of OPERABLE trains of AFW remains unchanged and continues to be periodically verified when an accident could occur. The change of allowing a greater Frequency interval does not affect the assumptions of an analyzed event. This change does not have. a detrimental affect on the performance of any credited equipment since studies have shown that pump availability has increased since performing the surveillances at this Frequency. As a result, no analysis assumptions are violated.

Based on this evaluation, there is no significant increase in the consequences of a previously analyzed event.

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change does not involve a physical alteration of the plant. No new equipment is being introduced, and no installed equipment is being operated in a new or different manner. There is no alteration to the parameters within which the plant is normally operated or in the set points which initiate protective or mitigative actions.

No change is being proposed to the procedures governing normal plant operation or those procedures relied upon to mitigate a design basis event. Allowing a greater Frequency interval for the AFW pump surveillances does not have a detrimental impact on the manner in which plant equipment operates or responds to an actuation signal.

As such, no new failure modes are being introduced. In addition, the change does not alter assumptions made in the safety analysis and licensing basis. Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

The margin of safety is established through equipment design, operating parameters, and the set points at which automatic actions are initiated. Allowing a greater Frequency interval between performance of the AFW pump surveillances does not significantly impact these factors. There are no design changes or equipment performance parameter changes associated with this change. Therefore, this change does not involve a significant reduction in the margin of safety.

Palisades Nuclear Plant Page 5of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM LESS RESTRICTIVE L.4 CTS 3.5.2e allows one flow control valve in each train to be inoperable for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months if the corresponding redundant flow control valve in the other train is OPERABLE. This ensures that 1003 AFW flow to both steam generators are maintained. The proposed ITS modifies this requirement to allow one or more trains of auxiliary feedwater to be inoperable for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months as long as the other train is available and provides AFW to both steam generators. This change is less restrictive because it allows more than one flow control valves in one train to be inoperable for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , where as the CTS would require entry into LCO 3.0.3, even though there would be 1003 AFW flow to both steam generators available. Proposed ITS addresses this by the allowance of the two flow control valves in one train to be inoperable. These changes are acceptable since the proposed ITS still requires that the flow equivalent of one train of AFW to both steam generators be available and the time frame for the equipment to be inoperable is only 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . One train of AFW can supply 1003 of the AFW flow requirements to both steam generators for cooling during accident conditions.

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems, or components. The proposed change would allow two flow control valves in one train to be inoperable which, CTS does not currently allow. This inoperability is not assumed to be an initiator or precursor of any analyzed event. Allowing more than one flow control valves to be inoperable in one train does not have a detrimental impact on any plant structures, systems, or components since there is still a requirement to maintain 100 3 of the flow equivalent to a single AFW train available to both steam generators. The CTS allowance of one flow control valve in each train to be inoperable as long as the corresponding redundant flow control valve in the other train has the ability to supply AFW to the steam generator. This has basically the same affect, in both cases each steam generator still has 100 3 AFW flow capability. As such, the probability of a previously analyzed accident is not significantly increased.

The consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event and the set points at whiGh these actions are initiated. This change would allow two flow control valves in one train to be inoperable. However, each steam generator still has 100% AFW flow capability. No accidents are postulated in which only one train of AFW flowing to both steam generators would not be mitigated. As such, no analysis assumptions are violated. Therefore, there is no significant increase in the probability or consequences

of an accident previously evaluated.

Palisades Nuclear Plant Page 6of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change does not involve a physical alteration of the plant. No new equipment is being introduced, and no installed equipment is being operated in a new or different mam:ier. There is no significant alteration to the parameters within which the plant is normally operated and no alteration in the set points which initiate protective or mitigative actions. No significant change is being proposed to the procedures governing normal plant operation or those procedures relied upon to mitigate a design basis event. Allowing two flow control valves in one train to be inoperable does not have a detrimental impact on the manner in which plant equipment operates or responds to an actuation signal. As such, no new failure modes are being introduced. In addition, the change does not alter assumptions made in the* safety analysis and licensing basis. Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

The margin of safety is established through equipment design, operating parameters, and the set points at which automatic actions are initiated. Sufficient methods remain available to support mitigating an analyzed event. The proposed change that would allow two flow control valves in one train to be inoperable is not considered to be a significant reduction in the margin of safety for the following reason: each steam generator still has 100 3. AFW flow capability for a adequate heat sink for the Primary Coolant System. No set points are affected, and the small change in the plant operational limit as the result of this change has minimal effect. Therefore, this change does not involve a significant reduction in the margin of safety.

Palisades Nuclear Plant Page 7of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM LESS RESTRICTIVE CHANGE L.5 CTS 3.5.4 addresses the plant condition with all auxiliary feedwater pumps inoperable and requires that power be reduced "within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to the lowest stable power level consistent with reliable main feedwater system operation." Proposed Condition D of ITS 3.7.5 also addresses a loss of all auxiliary feedwater and is stated as "two AFW trains inoperable with both steam generators having less than 100% of the AFW flow equivalent to a single OPERABLE AFW train." The Required Actions for Condition D are modified by a Note which state that "LCO 3.0.3 and all other LCO Required Actions requiring MODE changes or power reduction are suspended until at least 100 % of the AFW flow equivalent to a single OPERABLE AFW train is available to at least one steam generator." The intent of the actions in the CTS and ITS are similar, that is, with a loss of all auxiliary feedwater capability the plant is in a seriously degraded condition and should not be perturbed by any action, including a power reduction. However, the CTS requires a power reduction to the lowest stable power level consistent with reliable main feedwater system operation within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Although the CTS does not identify a specific power level at which the main feedwater system is considered reliable, the requirement of the ITS is considered less restrictive since it does not require any reduction in power. This change is considered acceptable since the intent of both the ITS and CTS is to maintain the plant in a stable conditions while actions are taken to restore the auxiliary feedwater system to an OPERABLE status.

1. Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems, or components. The proposed change eliminates the requirement to reduce reactor power following a loss of all auxiliary feedwater capability in order to avoid an unnecessary perturbation of the plant. A reduction in reactor power is not assumed to be an initiator or precursor of any analyzed event. Thus, the probability of a previously analyzed accident is not significantly increased.

The consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event and the set points at which these actions are initiated. The proposed change does not alter the initial conditions assumed in the safety analyses or affect the availability of any equipment credited in the mitigation of any analyzed event. As such, the consequences of a previously evaluated accident have remain unchanged. Therefore, there is no significant increase in the consequences of an accident previously evaluated .

Palisades Nuclear Plant Page 8of10

ATTACHMENT 4 NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change does not involve a physical alteration of the plant. No new equipment is being introduced, and no installed equipment is being operated in a new or different manner. There is no significant alteration to the parameters within which the plant is normally operated and no alteration in the set points which initiate protective or mitigative actions. No significant change is being proposed to the procedures governing normal plant operation or those procedures relied upon to mitigate a design basis event. As such, no new failure modes are being introduced. Therefore, the change does not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

The margin of safety is established through equipment design, operating parameters, and the set points at which automatic actions are initiated. The proposed change has no affect on any accident or transient analyses. The proposed change eliminates the requirement to reduce reactor power following a loss of all auxiliary feedwater capability in order to avoid an unnecessary perturbation of the plant. The intent of this change is to avoid plant evolutions which may present a challenge to the main feedwater system during the period the auxiliary feedwater pumps are unavailable. By maintaining reactor power steady, there is an inherent increase in plant stability which lowers the likelihood that the auxiliary feedwater system will need to function. As such, this change does not involve a significant reduction in the margin of safety.

LESS RESTRICTIVE CHANGE L.6 CTS 4.9a. l and CTS 4.9a.2 require the starting of the AFW pumps from various plant locations in a three month period. The details of where to start the AFW pumps are not an assumption used in the safety analyses. The safety analyses only assumes the AFW pumps start on an actuation signal. Details for starting the AFW pump are more appropriately stated in plant procedures. As such, the starting locations for the AFW pumps can be deleted from the CTS without altering the intent of the actual requirement. Deletion of these details is acceptable since they are not necessary to describe the actual regulatory requirement and will not result in a significant impact on safety. This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 9of10

ATTACHMENT 4

1.

NO SIGNIFICANT HAZARDS CONSIDERATION SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM Does the change involve a significant increase in the probability or consequence of an accident previously evaluated?

Analyzed events are assumed to be initiated by the failure of plant structures, systems or components. Consequences of a previously analyzed event are dependent on the initial conditions assumed for the analysis, and the availability and successful functioning of the equipment assumed to operate in response to the analyzed event.

The proposed change delete details from the Technical Specifications that are not necessary to describe, or are not pertinent to, any actual regulatory requirement. The deletion of details from the Technical Specifications is not assumed to be an initiator of any analyzed event. The proposed changes do not reduce the functional requirement or alter the intent of any specification. As such, the consequences of an accident remain unchanged. Therefore, the proposed change do not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the change create the possibility of a new or different kind of accident from any accident previously evaluated?

The proposed change deletes detail from the Technical Specifications that are not necessary to describe, or are not pertinent to, any actual regulatory requirement. The changes will not alter the plant configuration (no new or different type of equipment will be installed) or make changes in methods governing normal plant operation. The change will not impose different requirements, and adequate control of activities will be maintained. The change will not alter assumptions made in the safety analysis and licensing basis. Therefore, the change will not create the possibility of a new or different kind of accident from any accident previously evaluated.

3. Does this change involve a significant reduction in a margin of safety?

Margin of safety is determined by the design and qualification of the plant equipment, the operation of the plant within analyzed limits, and the point at which protective or mitigative actions are initiated. There are no design changes or equipment performance parameter changes associated with this change. No setpoints are affected, and no change is being proposed in the plant operational limits as a result of this change. The proposed change deletes details from the Technical Specifications. Removal of these details is acceptable since this information is not directly pertinent to the actual requirement and does not alter the intent of the requirement. Since these details are not necessary to adequately describe the actual regulatory requirement, they can be moved to licensee controlled document without a significant impact on safety. Therefore, the proposed change do not involve a significant reduction in a margin of safety .

Palisades Nuclear Plant Page 10of10

ENCLOSURE 5 CONSUMERS ENERGY COMPANY PALISADES PLANT DOCKET 50-255 CONVERSION TO IMPROVED TECHNICAL SPECIFICATIONS CORRECTED PAGES FOR SUPPORTING DOCUMENTATION

ATT ACIDIE~T 6 JUSTIFICATION FOR DEVIATIONS SPECIFICATION 3.6.3,- CONTAINMENT ISOLATION VALVES Change Discussion

12. CTS 3.6.5 requires that the containment purge exhaust and air room supply isolation valves shall be locked closed whenever the plant is above COLD SHUTDOWN. This requirement is an implicit requirement in the proposed ITS 3.6.3 since it states "Each containment isolation valve shall be OPERABLE" and the proposed Bases state that the purge exhaust and air room supply valves must be locked closed. Therefore, an additional Action must also be provided in the proposed ITS if this requirement is not met. Proposed ITS Action D addresses the situation where "One purge exhaust or air room supply valve not locked closed" and requires that within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , the affected valve must be locked closed. This Action is added to the proposed ITS to reflect a plant specific change based on the Palisades Nuclear Plant CTS. Proposed Condition D replaced ISTS 3.6.3 Condition E since failure of the leakage rate test for the containment purge exhaust and air room supply valves indicates the affected valve may not be fully closed.

13. NUREG-1432 Condition Chas a "bracketed" 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months as a Completion Time for~*

inoperable containment isolation valve in a penetration flow path with only one containment isolation valve and a closed system. TSTF-30. Rev. 2, revises this 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . A Completion Time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is appropriate since it involves a closed system which minimizes the potential of a leakage pathway. Since the Palisades Nuclear Plant CTS did not provide an explicit Completion Time for this condition, the 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is included in the proposed ITS.

TSTF-30, Rev. 2, also included a change to the Bases for Required Action C. l and C.2 which stated: "The closed system must meet the requirements of Reference 3

("Reference 3" is SRP 6.2.4). Such a Bases statement is not nsistent with the current licensing basis and as not incorporated. SRP 6.2.4 does n provide "requirements,"

but rather provid review guidance for acceptability of th design for containment isolation capab

ty. The containment penetrations whic tilize closed systems have previously determined to be acceptable. The acce bility may have been based on compli with SRP 6.2.4 or may* have been just' ed on some other basis.

Whatever e basis, the.system design has been det

ed acceptable for use as a tmlIJitnt isolation* feature, and it is inappropri to now prevent such use unles it comp with SRP 6.2.4. Therefore, this chang is consistent with TSTF-30, R . 2, exc t where the generic change is inconsisten ith the current licensin basis.

For fa.hs~l -T)>e. tom~t re ~rtncA d<<.ume.~+ tS Fs f\-R Se.cfliin ro. l. ~. ,* _, _*

Palisades Nuclear Plant Page 4 of S 05/31/99

l .~<D DEFINITIONS (continued) I@

REFUELING BQRON CONCENTRATION REFUELING BORON CONCENTRATION shall bt a Pri111ry Coolant Syst111 boron concentration of at least 1720 PPll AHO sufficient to assure the reactor 1s subcritical by ~ 51 ~P with all CONTROL ROOS withdrawn.

@:S:~Qift .

Aool i cabil i tv p.,.:..,. -l-o

~ Obiective eir.+e,.: .:.."\ l'1 01> E \

cA~,,. -~k.

'?"°"" 1-e e"-a,J~ ... :J require e aluation of reactiv ty anomalies within the reactor. -T~l loe..!i"1 c.. \,""'"'"'P of loo EFf'O ~~+e,,- e.

~ \.,,c.J~... -~~:::::=:!~~........

s~ '3.\.'l.\ iJoh To eliminate possible e ors in the calculations of he initial reactivity of the core and the react v1ty depletion rate, the pr icted relation between fuel burnup and the b ron concentration, necessar to m1intain adequat1 control characteris cs, 111Ust be adjusted (no""a zed) to accurately reflect actual core condit ns. When rated power 1s rea ed initially, and with the control rod group in the desired positions, t e boron concentration is

measured and the predicted curve is adjusted o this point. As power operation proce ds, the measured boron cone tration is compared with the predicted cone ntration and the slop1 of t -curve relating burnup and reactivity 1 compared with that predicte

This process of normalizat on shall be co lated after about lei of th total core burnup. Thereaf r, actual bor conc1ntration can be comp ed with prediction and the r ctivity status of he cor1 can be continuousl evaluated. Any reactivity a maly greater an 11 would be unexpected, nd its occurrence would be t oroughly investi ated and evaluated. The me ods employed in calculating he reacti ity of the cor1 vs burnup d the reactivity worth of bo n vs burnup are. ven in the FSAR.

Th value of 11 is considered safe limit since a shutdown argin of at e rod in the fully withdrawn osition is al~ays (1) FSAR, Section 3.3.

I 4. lf (Deleted) I @ ~ @

I (Nett page As 4-62l,I

< AUD AC.\\ON B a.$' f.t'-C-S<l."'~~J ; ..... -r:TS.) @

4-46 Amendment No. 154.

January l, 1993

A.26 ATTAC1'ENT 3 DISCUSSION OF CHANGES CHAPTER 1.0, USE AND APPLICATION In the CTS, the definition for REFUELING SHUTDOWN includes the statement

" ... and Tave is less than 210°F." A temperature is not specified in the proposed ITS Definition of "MODE 6." A temperature is not specified in MODE 6 to remove confusion which could occur if the temperature rose above a value which would place the reactor in an undefined MODE. However, since the reactor vessel head closure studs are not detensioned until the unit is in MODE 5 (which has a specific limit on temperature of less than 200°F), there is no practical change in the requirements.

Therefore, this is considered an administrative change. This change is consistent with NUREG-1432.

TECHNICAL CHANGES - MORE RESTRICTIVE There were no "More Restrictive" changes made to Chapter 1.0.

TECHNICAL CHANGES - REMOVAL OF DETAILS There were no "Removal of Details" changes made to Chapter 1.0 .

Palisades Nuclear Plant Page 11of12

TECHNICAL CHANGES - LESS RESTRICTIVE ATTAC1'ENT 3 DISCUSSION OF CHANGES CHAPTER 1.0, USE AND APPLICATION L. l CTS Section 10, "Definitions" contains defined terms that are not routinely used in the ITS, and details within defined terms that are not pertinent to the requirement in which they apply. Therefore, this information is proposed for deletion. Specifically:

"REACTOR CRITICAL" is defined as "The reactor is considered critical for purposes of administrative control when the neutron flux wide range channel instrumentation indicates greater than 104 % of Rated Power." This definition is not included in the proposed ITS as it is a term which is not utilized throughout the proposed ITS. The administrative means to determine when the reactor is critical will be addressed by plant procedures.

The CTS definitions for "HOT STANDBY" and "POWER OPERATION" both contain the statement "and the neutron flux power range instrumentation indicates .... "

Details with respect to how reactor power is determined is more appropriate for plant procedures given the indications available at certain power levels and their associated accuracy. Therefore, this method of determining reactor power will not be included in the proposed ITS but, will be addressed in plant procedures.

SHUTDOWN BORON CONCENTRATION is defined as " ... a Primary Coolant System boron concentration sufficient to assure the reactor is subcritical by 2 % .ti.p with all Control Rods in the core and the highest worth Control Rod fully withdrawn."

Shutdown Boron Concentration is not a defined term in the proposed ITS since is not explicitly referred to throughout the proposed ITS. The Shutdown Margin I requirements are specified in Section 3 .1, Reactivity Control, which define the amount I of Shutdown: Margin required. The boron concentration which would provide the I required amount of Shutdown Margin will be specified in plant procedures. I I

Since the above terms and details are not necessary to describe, or are not pertinent to I any regulatory requirement, they can be deleted without any impact to public health and I safety. These changes are consistent with NUREG-1432. I RELOCATED There were no "Relocated" changes made to Chapter 1.0 .

Palisades Nuclear Plant Page 12of12

M.3 SPECIFICATION 3.1.2, REACTIVITY BALANCE ATTACHMENT 3 DISCUSSION OF CHANGES CTS 4.10 states in part " ... the boron concentration of the primary coolant shall be periodically compared with the predicted value," but does not specify what the frequency of the comparison is. In the proposed ITS, the frequency for SR 3.1.2.1 (verification that reactivity balance is within 1 % .t.p) is "Prior to entering MODE 1 after fuel loading AND 31 EPPD thereafter. " This frequency clarifies that the surveillance does not have to be performed prior to entry into MODE 1 in accordance with the provisions of SR 3.0.4. The 31 EPPD frequency is modified by a note which states "Only required after initial 60 EPPD." In addition, it clarifies that the 31 EPPD frequency is to be applied after the initial 60 EPPD since the predicted boron concentration may be* normalized to the actual concentration prior to 60 EPPD. These changes are considered to be more restrictive since the CTS does not define a frequency to perform the tests. These changes are consistent with NUREG-1432.

LESS RESTRICTIVE CHANGES - REMOVAL OF DETAILS TO LICENSEE CONTROLLED DOCUMENTS (LA)

There were no "Removal of .Details"( changes associated with this specification.

LESS RESTRICTIVE CHANGES (L)

L.1 CTS 4.10 requires that if a difference between the observed and predicted steady-state concentrations reaches the equivalent of 1 % in reactivity, "the Atomic Energy Commission shall be notified within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and an evaluation as to the cause of the discrepancy shall be made and reported to the Atomic Energy Commission within 30 days." In ITS 3.1.2, the requirement to notify the Atomic Energy Commission (Nuclear Regulatory Commission) within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and to submit a report in 30 day has been deleted since the appropriate Required Actions and associated Completion Times (See DOCs M. l and M.2) for reactivity anomolies of 1 % have been incorporated into the technical specifications. Notification and reporting requirements will be made in accordance with 10 CPR 50.72 and 10 CPR 50.73, respectively. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 3of3

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.1.5, SHUTDOWN AND PART-LENGTH ROD GROUP INSERTION LIMITS ADMINISTRATIVE CHANGES (A)

A.I All reformatting and renumbering are in accordance with NUREG-1432. As a result, the Technical Specifications (TS) should be more readily readable, and therefore understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is made consistent with NUREG-1432.

During Improved Technical Specification (ITS) development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or implied) to the TS. Additional information has also been added to more fully describe each subsection. This wording is consistent with NUREG-1432. Since the design is already approved by the NRC, adding more details does not result in a technical change.

A.2 The Bases of the current Technical Specifications for this section have been completely replaced by the revised Bases that reflect the format and applicable content consistent with NUREG-1432. The revised Bases are shown in the proposed Technical Specification Bases ..

A.3 CTS 3.10.3, Part-Length Control Rods, specifies that "The part-length control rods will be completely withdrawn from the core ... " In the proposed ITS, the part-length control rods are required to be z 128 inches as opposed to "completely withdrawn."

Requiring the part-length rods to be withdrawn z 128 inches has the same effect as completely withdrawn in that the rods are removed from the active region of the core.

This is consistent with NUREG-1432 in that the requirement for rods to be withdrawn is specified in terms of inches withdrawn. This is considered to be an administrative change.

A.4 CTS 3.10.3 specifies that the part-length controls will be completely withdrawn from the core "(except for the control rod exercises and physics test)." The exception for control rod exercises is addressed as part of the Applicability Note. The physics tests exceptions are no longer needed because the part-length rods are not required to be moved during PHYSICS TESTS. These changes are considered to be administrative changes since no requirements have changed. These changes maintain consistency with NUREG-1432.

Palisades Nuclear Plant Page 1of5

ATTAC1'ENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.1.5, SHUTDOWN AND PART-LENGTH ROD GROUP INSERTION LIMITS A.5 CTS Table 4.17.6 Item 2 requires that the Rod Position Indication have a CHANNEL CHECK performed every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . This requirement becomes SR 3.1.5.1 in the proposed ITS. Proposed SR 3.1.5.1 requires "Verify each shutdown and part length rod is withdrawn L 128 inches every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ." The surveillance in the proposed ITS functions to perform the same verifications as that intended in the CTS "CHANNEL CHECK" since the CTS definition of "CHANNEL CHECK" includes the statement "A CHANNEL CHECK shall include verification that the monitored parameter is within the lirriits imposed by the Technical Specifications." CTS 3 .10. 6 requires that the shutdown rods shall be withdrawn before any regulating rods are withdrawn.

CTS 3 .10.4b in part states that a part-length rod is considered inoperable if it is not fully withdrawn. CTS 3.10.3 requires that the part-length rods be completely withdrawn. Therefore, the proposed surveillance performs this by proposed ITS SR 3.1.5.1 ensuring that the shutdown and part-length rods are withdrawn L 128 inches. This is considered to be an administrative change since the requirements have not changed but have been reformatted in accordance with NUREG-1432.

A.6 CTS 3.10.6a states "All shutdown rods shall be withdrawn before any.regulating rods are withdrawn." In the proposed ITS, the phrase "above 5 inches" is added to clarify what is intended by "withdrawn." Allowing the regulating rods to be withdrawn up to 5 inches facilities normal operation of the control rod drive motors which are "bumped" to bring the rods off the bottom before they are withdrawn. This area of the core is very insignificant with respect to the integral worth of the rod. This also corresponds to the Shutdown Rod Insertion interlock which prevents the shutdown rods from being inserted once the regulating rods are withdrawn greater than 5 inches. This change is a clarification to define what "withdrawn" means with respect to the regulating rods .

Palisades Nuclear Plant Page 2 of 5

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.1.5, SHUTDOWN AND PART-LENGTH ROD GROUP INSERTION LIMITS A.7 CTS 3.10.6a states "All shutdown rods shall be withdrawn before any regulating rods are withdrawn." CTS 3.10.6c states "The shutdown rods shall not be inserted below their exercise limit until all regulating rods are inserted." The proposed ITS 3 .1.5 LCO states "All shutdown and part/length rod groups shall be withdrawn to

<'. 128 inches." The Applicability for LCO 3.1.5 is MODE 1, MODE 2 with any regulating rod withdrawn above 5 inches. The proposed ITS wording for the LCO and Applicability is equivalent to the CTS wording in 3.10.6b. In the ITS, the shutdown rods must be withdrawn :<'. 128 inches by the LCO before the regulating rods are withdrawn above 5 inches (see DOC A.6 for discussion on 5 inches criteria). In addition, the CTS 3 .10. 6c requirement that the shutdown rods cannot be inserted below their exercise limit is also maintained in the ITS. This is because the shutdown rods cannot be inserted, except for rod exercising allowed by Applicability note, until out of the MODE of Applicability which required the regulating rods to be ~ 5 inches withdrawn. Therefore, the CTS and the proposed ITS are equivalent.

A.8 CTS 3 .10. 7 includes an exception which allows a deviation from the requirement for shutdown rod limits during performance of CRDM exercises. The exception contains a qualifying statement which reads "if necessary to perform a test but only for the time necessary to perform the test. " The Applicability Note for proposed ITS 3 .1. 5 which also provides an exception from the requirement for shutdown rod limits during performance of CRDM exercise does not contain this same qualifier since these type details are governed by the usage rules for the ITS. Therefore, deletion of this information is considered administrative in nature. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 3 of 5

A.9 SPECIFICATION 3.1.5, SHUTDOWN AND PART-LENGTH ROD GROUP ATTACHMENT 3 DISCUSSION OF CHANGES INSERTION LIMITS CTS 3.10.3 and CTS 3.10.6 stipulate the requirement for rod position on an individual rod basis (i.e., all shutdown and part-length rod must be fully withdrawn). In addition,*

CTS 3.4.10.4a requires that a control rod must be aligned within 8 inches from the remainder of the bank. The CTS does not specify rod positions on a group basis, and does not contain actions when controls rods are misaligned from their groups by less than 8 inches. Proposed ITS 3.1.5 establishes insertion limits for the shutdown and part-length rod groups by requiring them to be withdrawn~ 128 inches. Required Action A.1 of ITS 3.1.5 requires that any shutdown or part-length rod group that is not within its group insertion limit be declared inoperable and the Conditions of ITS 3 .1.4 entered immediately. If the Required Action and associated Completion Time are not met, Required Action B.1 requires the plant to be in Mode 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . To ensure compliance with the requirements of LCO 3.1.5, for a control rod group to be considered above its insertion limit, all rods in that group must be above the insertion limit. The addition of ITS Required Actions A. l and B.1 is characterized as an administrative change since the action taken when a shutdown or part-length rod exceed its insertion limit is consistent with the CTS actions for an inoperable control rod.

MORE RESTRICTIVE CHANGES (M)

There were no "More Restrictive" changes associated with this specification.

LESS RESTRICTIVE CHANGES - REMOVAL OF DETAILS TO LICENSEE CONTROLLED DOCUMENTS (LA)

There were no "Removal of Details" changes associated with this specification .

Palisades Nuclear Plant Page 4 of 5

ATTAC1'ENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.1.5, SHUTDOWN AND PART-LENGTH ROD GROUP INSERTION LIMITS LESS RESTRICTIVE CHANGES (L)

L.1 CTS 3 .10. 6b states "The shutdown rods shall not be withdrawn until normal water level is established in the pressurizer." This requirement was included in the CTS to assure criticality would not occur when the PCS was water solid. In the ITS, LCO 3.4.9, "Pressurizer" provides assurance the reactor will not be made critical when the PCS is water solid. Specifically, LCO 3.4.9 requires the pressurizer water level to be less than 62.8% prior to entering Mode 3. Specifying a maximum pressurizer water level preserves an implicit assumption in the safety analyses that a vapor-to-liquid interface exists in the pressurizer for proper PCS pressure response to anticipated design based transients initiate from a critical reactor. Although the ITS would allow shutdown rods to be withdrawn in Modes 4 and 5 without a bubble in the pressurizer, sufficient margin from a sustained critical condition is assured by maintaining 1':ff

< 0. 99 in these Modes. Therefore, the requirement of CTS 3 .10. 6b can be deleted without a significant impact of safety since LCO 3.4.9 ensures the reactor will not be made critical until a bubble is established in the pressurizer. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 5 of 5

M .1 (continued)

ATTAC1'ENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.4.10, PRESSURIZER SAFETY VALVES The reduction in time the plant is allowed to operate with an inoperable pressurizer safety valve reflects the importance of maintaining PCS overpressure protection capability. Six hours to place the plant in MODE 3 is reasonable, based on operating experience, to reach this plant condition without challenging plant systems. This change is an additional restriction on plant operations and is consistent with NUREG-1432.

LESS RESTRICTIVE CHANGES-REMOVAL OF DETAILS TO LICENSEE CONTROLLED DOCUMENTS (LA)

There were no "Removal of Details" changes associated with this specification.

LESS RESTRICTIVE CHANGES (L)

L. l In CTS 3 .1. 7 .1, the applicability is stated as "when the plant is operating above cold shutdown." The CTS defines cold shutdown, in part, as an average PCS temperature

~ 210°F. In proposed ITS 3.4.9, the Applicability is stated as MODES 1 and 2, and MODE 3 with all PCS cold leg temperatures~ 430°F. As such, the ITS does not require the pressurizer safety valves to be Operable when any PCS cold leg temperatures are below 430°F as required by the CTS. The function of the pressurizer safety valves is to keep PCS pressure below 110% of its design value during certain accidents. When any PCS cold leg temperatures are < 430°F, overpressure protection of the PCS is provided by the components required by proposed ITS 3.4.12, "Low Temperature Overpressure Protection." This is because the setpoints of the pressurizer safety valves are too high to ensure the integrity of the primary coolant pressure boundary is not compromised by limiting the maximum PCS pressure to within the pressure and temperature limits of 10 CFR 50, Appendix G during low temperature operations. The LTOP specification provides PCS overpressure protection by limiting the capability for mass input transients (e.g., limits the number of pumps capable of injecting into the PCS) and by having adequate pressure relieving capacity for heat input transients. Thus, the pressurizer safety valves are not required to provide overpressure protection of the PCS when any PCS cold leg temperatures are < 430°F .

Palisades Nuclear Plant Page 2of4

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.4.10, PRESSURIZER SAFETY VALVES L. 2 CTS 3 .1. 7 .1 action "b" requires that with one or more pressurizer safety valves inoperable, the reactor be placed in Cold Shutdown within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . In proposed ITS 3 .4.10 Required Action B.2, if one pressurizer safety valve cannot be restored in 15 minutes, or two or more safety valves are inoperable, then the plant must be placed in MODE 3 with all PCS cold leg temperatures < 430°F within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The requirements of the CTS are more restrictive than the ITS since the CTS requires the plant to be placed in Cold Shutdown and the ITS only requires the plant to be placed in MODE 3 with all PCS cold leg temperatures < 430°F. As discussed in Discussion of Change L.1 above, the Applicability for pressurizer safety valves has. been revised to exclude those plant conditions when any PCS cold leg temperatures are s; 430°F. As such, with one or more pressurizer safety valves inoperable it is only necessary to require the plant to be placed in a condition where the pressurizer safety valves are no longer required to perform the overpressure protection function for the PCS. This change is consistent with NUREG-1432.

L.3 CTS 4.2 Table 4.2.2 item 3 requires a setpoint test of the pressurizer safety valves at a frequency of "one each refueling. " The current fuel cycle at the Palisades plant is 18 months. Thus, one pressurizer safety valve is tested approximately every 18 months. In proposed ITS 3.4.10, the surveillance frequency for testing the pressurizer safety valves is stated as "in accordance with the Inservice Testing Program." The Inservice Testing Program, as stipulated by the ASME Boiler and Pressure Vessel Code,Section XI and OM-1, require all valves of each type and manufacturer to be tested within each subsequent 5 year period with a minimum of 20 3 of the valves tested within any 24 months. For the pressurizer safety valves this means that at least one valve shall be tested each 24 months such that all three pressurizer safety valves will have been tested each subsequent 5 year period. The frequency for testing the pressurizer safety valves stipulated in the ITS is less restrictive than the frequency required by the CTS. The proposed frequency is considered acceptable since it is based on industry experience which has shown that this testing interval is sufficient to maintain the status of the pressurizer safety valves such that they are capable of performing their intended safety function and assure continued safe operation of the plant. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 3of4

L.4 ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.4.10, PRESSURIZER SAFETY VALVES CTS 3.1.7.1 Table 3.1.7-1 contains footnote"*" which states "After testing or valve maintenance which could affect the setting, it shall be reset to within 1 % of the nominal setpoint prior to being returned to service." In the ITS, it is not necessary to include the phrase "or valve maintenance which could affect the setting" since this activity is covered by the definition of Operability. Anytime maintenance is performed on a

component which is required to be Operable by the technical specifications (e.g., an instrument transmitter, or a motor operated valve), a determination of the impact on the components ability to perform its intended function must be made. If it is determined the affected component is no longer Operable, then the component must be declared inoperable and retested to ensure it will function as required. Since the requirement of Operability adequately addresses the return to service of a component following maintenance, it is no longer necessary to include the phrase "or valve maintenance which could affect the setting" in the ITS. As such, this phrase can be deleted from the CTS without altering the intent of the actual requirement. Deletion of these details is acceptable since they are not necessary to describe the actual regulatory requirement and will not result* in a significant impact on safety. This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 4of4

M.8 ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.4.14, PCS PIV LEAKAGE CTS 4.3h requires periodic leakage testing on each specified PIV after every time the plant has been placed in the Refueling Shutdown Condition, or the Cold Shutdown Condition for more than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months if such testing has not been accomplished within the previous 9 months. Proposed SR 3.4.14.1 specifies a similar Frequency but also requires testing to be performed every 18 months. The inclusion of this new Frequency imposes an additional restriction on plant operations since testing will be required every 18 months regardless if the plant is placed in Cold Shutdown. The proposed Frequency is acceptable since it establishes a testing period consistent with other ASME class 1 components. This change is consistent with NUREG-1432.

LESS RESTRICTIVE CHANGES -REMOVAL OF DETAILS TO LICENSEE CONTROLLED DOCUMENTS (LA)

LA.1 Not used.

LA.2 CTS Table 4.3.1 contains a listing of "Primary Coolant System Pressure Isolation Valves" which relate to the requirement for PIV leakage. In the ITS, this listing has been moved to the FSAR since it is not necessary to describe the actual regulatory requirement. As stated in Generic Letter 91-08, "Removal of Component Lists from Technical Specifications," "specifications may be stated in general terms that describe the types of components to which the requirements apply. This provides an acceptable alternative to identifying components by their plant identification number as they are currently listed in tables of TS components. The removal of components lists is acceptable because it does not alter existing TS requirements or those components to which they apply." As such, placing the PIVs listed in CTS Table 4.3.1 in the FSAR will not result in a significant impact on safety. Changes to the FSAR will be evaluated using the criteria established in 10 CFR 50.59. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 7of13

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.4.14, PCS PIV LEAKAGE LA.3 CTS Table 4.3.1 contains a listing of "Primary Coolant System Pressure Isolation Valves" which relate to the requirement for PIV leakage. The Maximum Allowable Leakage column in Table 4.3.1 is modified by five Notes. In the ITS, CTS Notes 1, 2, 4, and 5 have been moved to the Bases since they do not contain information pertinent to the performance of, or are necessary to establish compliance with the actual surveillance requirement. Notes 1, 2 and 4 simply state if the test results are acceptable or unacceptable based on the limits established the actual SR. Note 5 clarifies acceptable test methods based on Section XI of the ASME Boiler and Pressure Vessel Code. Related to Note 5, is Note (b) to CTS 4.3h which states that reduced pressure testing is acceptable. Since these details are not necessary to adequately describe actual regulatory requirements, they can be moved to a license controlled document without a significant impact on safety. Placing these details in the Bases provides adequate assurance that they will be maintained since the Bases are controlled by the Bases Control Program in proposed ITS Chapter 5.0.

LA.4 Not used.

LA.5 CTS Table 4.17 .6 item 17 requires a Channel Functional Test and a Channel Calibration of the SDC Suction Interlocks every 18 months. Proposed ITS 3 .4 .14 does not contain a similar requirement since the SDC Suction Interlock instruments do not initiate an automatic safety function. The function of the SDC Suction Interlock instruments is to monitor PCS pressure and to electrically prohibit the SDC suction valves from being remotely opened when PCS pressure is above the design pressure of the SDC system. The setpoint associated with these instruments has been selected to provide equipment protection and is not based on any accident or transient analysis events presented in FSAR Chapter 14. As such, there is no analytical value which can be compromised due to a failure to automatically initiate a protective function, or as a result of instrument drift. Therefore, the CTS requirement to perform a Channel Functional Test and a Channel Calibration of the SDC Suction Interlocks can be moved to a licensee controlled document without a significant impact on safety. Placing these requirements in the Operating Requirements Manual is acceptable since changes to the Operating Requirements Manual will be evaluated using the criteria established in 10 CFR 50.59. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 8of13

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.4.14, PCS PIV LEAKAGE LA.6 CTS 4.3j requires that the check valves in the LPSI system, which are used for shutdown cooling, be verified in the closed position following their use. CTS 4.3j also lists the check valves by their equipment identification number. These numbers are; CK-3103, CK-3118, CK-3133, and CK-3148. Proposed SR 3.4.14.3 also requires a verification that the four check valves in the LPSI system that have been used for operation of the shutdown cooling are verified closed but does not include the equipment identification number of the check valves. This is because this information is not necessary to adequately describe the actual regulatory requirement. As such, this information may be moved to an appropriate licensee controlled document without a significant impact of the health and safety of the public. Therefore, the equipment identification numbers of the four LPSI check contained in CTS 4.3j have been moved to the Bases. Placing these details in the Bases provides adequate assurance they will be maintained since the Bases are controlled by the Bases Control Program proposed in ITS Chapter 5.0. This change is consistent NUREG-1432.

LA.7 CTS 4.3g stipulates that a surveillance program to monitor radiation induced changes in the mechanical and impact properties of the reactor vessel materials shall be maintained as described in Section 4.5.3 of the FSAR. In the ITS, this requirement has been deleted since it is duplicative of existing requirements. 10 CPR 50.60 requires that licensees for all light water nuclear power reactors meet fracture toughness requirements and have a material surveillance program for the reactor coolant pressure boundary. These requirements are set forth in Appendices G and H to 10 CPR Part 50.

Since adequate regulatory requirements exist, CTS 4.3g can be deleted without any affects on public health and safety. This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 9of13

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.4.14, PCS PIV LEAKAGE LESS RESTRICTIVE CHANGES (L)

L.1 CTS Table 3.17.6 item 17 requires two channels of SDC Suction Valve Interlocks to be Operable "above 200 psia PCS pressure." In proposed ITS 3 .4.14, the SDC suction valve interlocks are required to be Operable in MODES 1, 2, and 3, and in MODE 4, except during the SDC mode of operation, or transition to or from the SDC mode of operation. The requirements associated with the Applicability of ITS 3 .4 .14 represent a relaxation from the requirements of the CTS since the ITS will allow PCS pressure to be greater than 200 psia without requiring the SDC suction valve interlock function to be Operable. The function of the SDC suction valve interlock to prevent the inadvertent opening of the isolation valves which provide the interface between the high pressure piping in the PCS and the low pressure piping in the SDC system during periods when the PCS pressure is above the design pressure of the SDC system. The Applicability of ITS 3 .4.14 is appropriate since it continues to require the interfock function to be Operable whenever a potential for overpressurizing the SDC system piping from the PCS exists. This is ensured by requiring the interlock function to be Operable in all of MODE 4 unless the SDC system is in operation, or is being placed in, or removed from, operation. The lower temperature limit of MODE 4 is 201°F.

At this temperature, the corresponding PCS pressure is well below the 300 psig design pressure of the SDC system suction piping. Thus, ITS 3 .4.14 requires the interlock function to be Operable well below the pressure in which it is required to perform its protective function. ITS 3.4.14 does notrequire the interlock function to be Operable when the SDC system is in operation or is being placed in, or remove from, operation since these activities are procedurally controlled to occur only when the PCS pressure is within the design pressure of the SDC system piping. Therefore, the proposed change is acceptable since it contains the appropriate requirements to ensure the integrity of the SDC system is not violated. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 10of13

L.2 ATTAC1'ENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.4.14, PCS PIV LEAKAGE CTS 4.3i requires that whenever the integrity of a PIV can not be demonstrated and credit is being taken for compliance with specification 3.3.3b, "the integrity of the remaining check valve in each high pressure line having a leaking valve shall be determined and recorded daily and the position of the other closed valve located in that pressure line shall be recorded daily." In proposed ITS 3.4.14, Required Action A.1 requires an inoperable PIV be isolated from the high pressure portion of the affected system by use of one closed manual, deactivated automatic, or check valve. In addition, each valve used for isolation must have been verified to meet the leakage requirements setforth in SR 3.4.14.1. The ITS does not specify that the integrity of the remaining check valve be determined daily since this action represent a condition which is known to exist at the time of isolation, and which must continued to be met by the requirements of SR 3.0.1. Thus, the ITS simply removes an administrative function by eliminating the requirement to record the integrity of a check valve used to isolate an inoperable PIV on a daily basis. The requirement of CTS 4.3i which states "and the position of the other closed valve located in that pressure line shall be recorded daily" is no longer applicable as explained in Discussion of Change M.2 for this specification.

This change is consistent with NUREG-1432.

L.3 CTS 3.3.3 and CTS 4.3h required perio~ic leakage testing of the specified PIVs every time the plant has been placed in the "Cold Shutdown Condition for more than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and such testing has not been accomplished within the previous 9 months." Proposed SR 3 .4 .14 .1 also requires leakage testing of specified PIVs but the Frequency is stated, in part, as "whenever the plant has been in MODE 5 for 7 days or more if leakage testing has not been performed in the previous 9 months. " The amount of time the plant must be shutdown before PIV leakage testing is required by the ITS has been relaxed from the requirements of the CTS. The ITS allows the plant to be in MODE 5 for up to 7 days before testing is required. The CTS only allows the plant to be in Cold Shutdown Conditions for 3 days before testing is required. The extended period of MODE 5 operation allowed by the ITS does not significantly increase the probability of a malfunction of the PIVs since the change in plant status over the four additional days of shutdown time does not change significantly. This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 11of13

ATTACHMENT 3

L.4 DISCUSSION OF CHANGES SPECIFICATION 3.4.14, PCS PIV LEAKAGE CTS 3.3.3 and CTS 4.3h require all PIVs to be tested prior to returning to Power Operation after every time the plant has been placed in the Refueling Shutdown Condition, or the Cold Shutdown Condition for more than 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (See Discussion of Change L. 3 for this specification which justifies a change to 7 days). In proposed ITS 3 .4.14, a sin:lilar testing requirement is associated with the Frequency of SR 3.4.14.1. However, SR 3.4.14.1 does not stipulate the plant condition of "Refueling Shutdown" since this plant condition does not exist in the ITS. Rather, proposed SR 3.4.14.1 contains a Frequency of "18 months" (See Discussion of Change M.8). The CTS defines "Refueling Shutdown" as a condition when the primary coolant is at Refueling Boron Concentration (i.e., at least 1720 ppm boron and the reactor subcritical by ~ 5 % ~ p with all control rods withdrawn) and Tave is less than 210°F. In the ITS, the Mode which closely matches the CTS plant condition of Refueling Shutdown is "MODE 6, Refueling." Presently, based on fuel design, an operating cycle for the Palisades plant is approximately 18 months. The CTS Frequency of "every time the plant has been placed in the Refueling Shutdown Condition" is essentially the same as the ITS Frequency of "18 months," However, deletion of the CTS Frequency has been characterized as less restrictive since literal application of the CTS Frequency could result in additional and unnecessary performances of PIV testing. The proposed change eliminates the potential for unnecessary testing by deleting the conditional based surveillance frequency contained in the CTS. This change is acceptable since PIV testing will continue to be performed consistent with 10CFR50.55a and within the frequency allowed by ASME Code Section XI. This change is consistent with NUREG-1432.

L.5 CTS 3.3.3 and CTS 4.3h require a test of the PIVs prior to returning the valves to service "after maintenance, repair or replacement.". In the ITS, it is not necessary to stipulate testing requirements related to "maintenance, repair or replacement" since these activities are covered by the definition of Operability. Anytime maintenance, repair or replacement is performed on a component which is required to be Operable by the technical specifications (e.g., an instrument transmitter, or a valve), a determination of the impact on the component's ability to perform its intended function must be made.

If it is determined the affected component is no longer Operable, then the component must be declared inoperable and then retested to ensure it will function as required.

Since the requirement of Operability adequately addresses the return to service of a component following maintenance, it is no longer necessary to include the phrase "after maintenance, repair or replacement" in the ITS. As such, this phrase can be deleted .

from the CTS without altering the intent of the actual requirement. Deletion of these details is acceptable since they are not necessary to describe the actual regulatory requirement and will not result in a significant impact on safety. This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 12of13

ATTAC1'ENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.4.14, PCS PIV LEAKAGE L.6 The requirement to perform periodic leakage testing specified in CTS 4.3h is modified by footnote (a) which states that "to satisfy ALARA requirements, leakage may be measured indirectly (as from the performance of pressure indicators) if supported by computation showing that the method is capable of demonstrating valve compliance with the leakage criteria." Proposed ITS 3 .4.14 does not contain this same statement since this information only discusses an acceptable method of compliance with the LCO and is not necessary to describe the actual regulatory requirements. The allowance to indirectly measure leakage from a PIV using a pressure indicator does not alter the allowed leakage limit from a PIV but simply provides an alternate method for testing when personnel exposure to radiation is a consideration. Therefore, these details can be deleted from the CTS without a significant impact on safety. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 13of13

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM ADMINISTRATIVE CHANGES (A)

A. l All reformatting and renumbering are in accordance with NUREG-1432. As a result, the Technical Specifications (TS) should be more readily readable, and therefore understandable by plant operators as well as other users. The reformatting, renumbering, and rewording process involves no technical changes to existing Technical Specifications.

Editorial rewording (either adding or deleting) is made consistent with NUREG-1432.

During Improved Technical Specification (ITS) development certain wording preferences or English language conventions were adopted which resulted in no technical changes (either actual or implied) to the TS. Additional information has also been added to more fully describe each subsection. This wording is consistent with NUREG-1432. Since the design is already approved by the NRC, adding more details does not result in a technical change.

A.2 The Bases of the current Technical Specifications for this section have been completely replaced by revised Bases that reflect the format and applicable content consistent with NUREG-1432. The revised Bases are shown in the proposed Technical Specification Bases.

A.3 CTS 3.5. lb informs the operator that the AFW instrumentation must meet the minimum operabilit)' requirements of Specification 3 .17. This statement is omitted in proposed ITS 3.7.5 because the ITS format does not usually provide similar "information" statements in the ITS. This change is considered administrative in the requirements are still in effect per proposed ITS 3.3. This change is consistent with NUREG-1432.

A.4 CTS 3.5.la states that the steam driven AFW pump will be OPERABLE prior to taking the reactor critical. Proposed ITS LCO 3.7.5 Note states the turbine driven AFW pump will be OPERABLE in MODES 1and2. This is considered to be an administrative change since the effect on operations is similar. This change is consistent with NUREG-1432.

A.5 CTS 3.5.3 requires that if the requirements of Specification 3.5.1 or the conditions of Specification 3.5.2, except as noted in Specification 3.5.4, are not met, the plant must be placed in HOT SHUTDOWN. In proposed ITS 3. 7. 5 Required Action C .1, the CTS term is replaced with MODE 3. This is considered to be an administrative change since the effect on operations is similar. This change is consistent with NUREG-1432 .

Palisades Nuclear Plant Page 1of6

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM A.6 A Note has been added to SR 3.7.5.3 which states "Not required to be met in MODES 2 or 3 when AFW is in operation." This Note is needed to prevent unnecessary entering of ACTIONS for LCO 3.7.5 during the startup or shutdown of the plant for not being able to meet the SR. Palisades uses the AFW system for steam generator level control during startup and shutdown in MODES 2, 3, and 4. During these operations the flow control valves used are in manual, and will not open automatically when an actuation signal is received, which would fail the SR. This change is administrative because CTS 4.9.b.l states "each valve to actuates to its correct position (or that the specified flow is established) upon receipt of a simulated auxiliary feedwater pump start signal." During startup or shutdown the valves are providing the proper flow for the existing plant condition. This Note is appropriate because the valves are needed to be throttled in these conditions to prevent overfilling of the steam generators due to low steam flow conditions, also the Note clarifies current licensing basis requirements.

A.7 This change adds the additional "inservice requirements" as described in ASME Code,Section XI to CTS 4.9.a. l and 2. This change is administrative in that these requirements are performed by current surveillances and also this change only combines the two requirements, Code and TS. This change is consistent with NUREG-1432.

A.8 CTS 3.5.4 provides corrective actions in the event all AFW pumps are inoperable. In this case, the capability to provide the required AFW flow to either steam generator has been lost. Proposed ITS 3.7.5 Condition D also provides corrective actions when the capability to provide the required AFW flow to either steam generator has been lost.

Condition D is stated as "two AFW trains inoperable with both steam generators having less than 100% of the AFW flow equivalent to a single Operable AFW train available in Mode 1, 2, or 3 or, (the) required AFW train inoperable in Mode 4. " Since the AFW system inoperabiliy addressed in ITS 3.7.5 Condition D (a loss of AFW function) is equivalent to the condition presented in CTS 3.5.4, this change has been characterized as administrative in nature .

Palisades Nuclear Plant Page 2 of 6

ATTAC1'ENT 3

A.9 DISCUSSION OF CHANGES SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM CTS 4.9.b.l and 2 specifies in part that for the Auxiliary Feedwater System valve and pump tests, operation of the system is initiated by a specific actuation signal from the normal actuation instrumentation. The proposed ITS SRs add the following phase "by an actual or simulated actuation signal." The allowance to use an actual or simulated actuation signal is based on the fact the channel being tested cannot differentiate between an actual or simulated signal and either initiation can demonstrate system OPERABILITY. The specific actuation signals (e.g., auxiliary feedwater pump start, auxiliary feed water actuation test) are tested under Section 3. 3, "Instrumentation."

Since the actuation signals are not required to be OPERABLE for LCOs 3.3.3, "Engineered Safety Features (ESP) Instrumentation," and 3. 3 .4, "Engineered Safety Features (ESP) Logic and Manual Initiation," in MODE 4. SRs 3.7.5.3 and 3.7.5.4 are modified by a Note which states the SRs are not required to be met in MODE 4 to keep consistency with the LCOs and current licensing basis. This is considered to be an administrative change since the system testing requirements have not changed. This change is consistent with NUREG-1432.

TECHNICAL CHANGES - MORE RESTRICTIVE (M)

M.1 CTS 3.5.1, 3.5.2, and 3.5.3 require AFW to be OPERABLE and provide associated action statements at a primary temperature of 300°F. Proposed ITS 3.7.5 Applicability is MODES 1, 2, 3, and MODE 4 when a steam generator is being relied upon for decay heat removal. MODE 4 temperature requirements are greater than 200°F and less than 300°F. This change is more restrictive in that if a steam generator is being used in MODE 4, then AFW will be required to be OPERABLE below 300°F which is not currently required. This change is consistent with NUREG-1432.

M.2 A Note has been added stating that "Only one AFW train, which includes a motor

driven pump, is required to be OPERABLE in MODE 4." CTS does not require any train to be OPERABLE in this condition (see DOC M. l). This change is more restrictive because of the additional requirement placed on the operation of the plant.

This change is consistent with NUREG-1432.

M.3 CTS 3.5.3 requires the plant to be placed in HOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and HOT SHUTDOWN within following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for a total of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to HOT SHUTDOWN.

Proposed ITS 3.7.5 Required Action C.l requires the plant to be placed in MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . MODE 3 is similar to HOT SHUTDOWN (see DOC A.5). This change is more restrictive in that the time allowed to place the plant in a similar condition is 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months shorter. The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions

in an orderly manner and withoui challenging plant systems. This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 3 of 6

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM M.4 CTS 3.5.2 Action completion times have been modified to reflect ISTS requirements for restoration of an inoperable AFW component/train, which imposes a maximum time limitation based on the time when "any required AFW component/train is inoperable."

Proposed ITS 3.7.5 Required Actions A.1 and B.1 include a requirement for restoration of all AFW component/train to operable status within 10 days of initial failure to meet the LCO requirement for AFW. These added Completion Times assure that alternating inoperabilities in AFW will not continue indefinitely without complete restoration to compliance with the LCO. The 10-day Completion Time is reasonable to assure timely restoration. This Completion Time is consistent with the NUREG-1432 philosophy of providing a maximum time consistent with the sum of a single steam driven AFW pump steam supply valve restoration time plus a AFW train restoration time.

LESS RESTRICTIVE CHANGES - REMOVAL OF DETAILS TO LICENSEE CONTROLLED DOCUMENTS (LA)

LA.1 CTS 3 .5. le and d contain details of the components associated with the AFW System which must be OPERABLE. Generally, the CTS lists applicable piping, valves, flow paths, and interlocks associated with these components which are required to function during accident conditions. In ITS, proposed LCO 3.7.5 requires that "Two AFW trains shall be OPERABLE." The details of what constitutes an OPERABLE AFW train are specified in the Bases. The Bases state the required components in each AFW train including piping, valves, instruments, and controls to ensure the availability of an OPERABLE flow path. As such, the AFW requirements in ITS are equivalent to the AFW requirements in the CTS without the added detail. Removing the details of the AFW from the CTS and placing them in the Bases of ITS is acceptable since these details are not pertinent to the actual requirements. Placing these details in the Bases provides adequate assurance that they will be maintained since the Bases are controlled by the Bases Control Program proposed in ITS Chapter 5.0. This change is consistent with NUREG-1432.

LA.2 Not used.

LESS RESTRICTIVE CHANGES (L)

L.1 CTS 3 .5 does not provide an allowance to restore to OPERABLE status one steam supply to the steam driven AFW pump before declaring the pump inoperable.

Proposed ITS 3.7.5 Required Action A.1 is less restrictive in that ITS allows 7 days for restoration prior to declaring the turbine driven pump inoperable. The change to 7 days is reasonable in that the 7 day Completion Time is based on the redundant OPERABLE steam supply to the turbine driven pump, the availability of redundant OPERABLE motor driven pumps, and the low probability of an event requiring the inoperable steam supply to the turbine driven pump.

Palisades Nuclear Plant Page 4of6

ATTAC1'ENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM L.2 CTS 3. 5. 3 requires that if AFW does not satisfy the requirements of Specification 3. 5 .1 or the conditions of Specification 3.5.2 except as noted in Specification 3.5.4 the reactor must be placed in a COLD SHUTDOWN (ITS MODE 5) condition. With proposed ITS 3.7.5 Required Action C.2, the plant is placed in MODE 4, without reliance on a steam generator for heat removal. This change is less restrictive in the temperature of the primary would be 90°F higher. This change is reasonable in the AFW System is still required to be OPERABLE whenever the system is needed for accident mitigation by the safety analysis. The lowest MODE to which AFW is required by the safety analysis to be OPERABLE in proposed ITS is MODE 4. This change is consistent with NUREG-1432.

L.3 CTS 4.9a requires that the AFW pumps be started every 31 days. Proposed ITS SR 3.7.5.2 requires the pumps to be tested in accordance with the Inservice Testing Program. This change is less restrictive in that each pump will be started once every 92 days vice every 31 days. This change combines the starting requirement and the code requirements (inservice tests). This change is reasonable in that this test confirms one point on the design curve and is indicative of pump perfonnance as discussed in ASME Code,Section XI (see DOC A.7). The starting requirement is reasonable due to the findings and recommendation as discussed in NUREG-1366, "Improvements to Technical Specifications Surveillance Requirements." This change is consistent with NUREG-1432.

L.4 CTS 3.5.2e allows one flow control valve in each train to be inoperable for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months if the corresponding redundant flow control valve in the other train is OPERABLE. This ensures that 100 3 AFW flow to both steam generators are maintained. The proposed ITS modifies this requirement to allow one or more trains of auxiliary feedwater to be inoperable for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months as long as the other train is available and provides AFW to both steam generators. This change is less restrictive because it allows more than one flow control valve in one train to be inoperable for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , where as the CTS would require entry into LCO 3.0.3, even though there would be 100% AFW flow to both steam generators available. Proposed ITS addresses this by the allowance of the two flow control valves in one train to be inoperable. These changes are acceptable since the proposed ITS still requires that the flow equivalent of one train of AFW to both steam generators be available and the time frame for the equipment to be inoperable is only 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . One train of AFW can supply 100% of the AFW flow requirements to both steam generators for cooling during accident conditions.

Palisades Nuclear Plant Page 5of6

ATTACHMENT 3 DISCUSSION OF CHANGES SPECIFICATION 3.7.5, AUXILIARY FEEDWATER (AFW) SYSTEM L.5 CTS 3.5.4 addresses the plant condition with all auxiliary feedwater pumps inoperable and requires that power be reduced "within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to the lowest stable power level consistent with reliable main feedwater system operation." Proposed Condition D of ITS 3.7.5 also addresses a loss of all auxiliary feedwater and is stated as "two AFW trains inoperable with both steam generators having less than 100 % of the AFW flow equivalent to a single OPERABLE AFW train." The Required Actions for Condition Dare modified by a Note which state that "LCO 3.0.3 and all other LCO Required Actions requiring MODE changes or power reduction are suspended until at least 100% of the AFW flow equivalent to a single OPERABLE AFW train is available to at least one steam generator." The intent of the actions in the CTS and ITS are similar, that is, with a loss of all auxiliary feedwater capability the plant is in a seriously degraded condition and should not be perturbed by any action, including a power reduction. However, the CTS requires a power reduction to the lowest stable power level consistent with reliable main feedwater system operation within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

Although the CTS does not identify a specific power level at which the main feedwater system is considered reliable, the requirement of the ITS is considered less restrictive since it does not require any reduction in power. This change is considered acceptable since the intent of both the ITS and CTS is to maintain the plant in a stable conditions while actions are taken to restore the auxiliary feedwater system to an OPERABLE status.

L.6 CTS 4.9a. l and CTS 4.9a.2 require the starting of the AFW pumps from various plant locations in a three month period. The details of where to start the AFW pumps are not an assumption used in the safety analyses. The safety analyses only assumes the AFW pumps start on an actuatfon signal. Details for starting the AFW pump are more appropriately stated in plant procedures. As such, the starting locations for the AFW pumps can be deleted from the CTS without altering the intent of the actual requirement. Deletion of these details is acceptable since they are not necessary to describe the actual regulatory requirement and will not result in a significant impact on safety. This change is consistent with NUREG-1432.

Palisades Nuclear Plant Page 6 of 6

~~~~~~~~~~~/@9 Sqe3.I>

~~:..r..;:..;;;...;..;.~..:;_;_~-=-~__..;.;;~=..:;-=-:....;;,.;;;:..:..:.;..:~.;.___.~~~-1

(§ A syste11, subsyste11, train, C0111Pon1nt, or device shall be OPERABLE, or have OPERABILITY, when 1t is capable of performing its specified functionsi and when all necessary attendant instru1111ntation, controls, electrica power, cooling or seal water_, lubrication,~ other auxiliary equif)llent that are.required for the syste11, subsyste*, train, component, or device to perfon1 its specified unctions are also c~ble of perfon11ng their related support fun ons. ~

So.~+,

eoWEB OPERATION The POWER OPERATION cond1t1on shall be when the reactor is c 1t1c l

.7 'l'I 1::-c.f'r

~

~~ ~e~T~B ~~~R~ower range instrumentation indlcatef g~ than

..0 L\J:V OUAQBANT eeWEB TILT

T14 * *-Ir\?)

QUADRANT POWER TILT shall be th~~:t;o of quadrant power minus/@

average quadrant power, to average qua r nt power.

~M;y .

BAL JiER lm-) ~ (j;..,r +,... ,;.~ ~ t-5)

@ltl !'@shall be a~ st}t'i}reactor core~f 2530 MW,. @

.._~-;!":- r1t.<>Q1~Y 1-3 Alllendment No. ~' G, i4, ~. ii, +l-i, -l-a4, ~. W, ~. 174 October 31, 1996 /

'P"f Jc..+ 0

ENCLOSURE 6 CONSUMERS ENERGY COMPANY PALISADES PLANT DOCKET 50-255 CONVERSION TO IMPROVED TECHNICAL SPECIFICATIONS SECTION 3.3, INSTRUMENTATION INSTRUMENT CHANNEL DRIFT MEASUREMENTS

INSTRUMENT CHANNEL DRIFT MEASUREMENTS 1--

As part of the implementation of Improved Technical Specifications (ITS), Palisades is seeking approval to extend the Functional Test interval for the Reactor Protection System (RPS) and Engineered Safety Feature Actuation System (ESFAS) channels from monthly to quarterly. The basis for this extension is provided in the approved NRC topical report CEN-327, "RPS/ESFAS Extended Test Interval Evaluation," as supplemented. This topical report was approved by NRC Safety Evaluation Report (SER) dated November 6, 1989. The SER approved extending the test interval with the following caveat:

The licensees must confirm that they have reviewed the instrument drift information for each instrument channel involved and have determined that drift occurring in that channel over the period of extended STI will not cause the setpoint value to exceed the allowable value as calculated for that channel by their setpoint methodology."

The purpose of this letter is to describe the method Palisades used to perform this review and to show that the drift will not cause the setpoint valve to exceed the allowable value based on an extended test interval.

Determination of setpoints for RPS/ES FAS at Palisades is based on the methodology provided in ISA Standard S67.04, "Setpoints for Nuclear Safety Related Instrumentation." Starting with the Allowable Value for a trip setting, as listed in the Technical Specifications, instrument loop components accuracy and drift values are statistically combined to establish a trip setpoint which is used to set the trip value in the channel bistables. These setpoints assure that if the channel components function within their accuracy and drift specifications, the channel will trip prior to exceeding the TS Allowable Value. Performance of functional tests and calibrations of I

the instrument loops provides continuing assurance that the instrument loop components operate within specifications during the appropriate interval. As some of the bistable components for the RPS and ESFAS differ in their operating principal, different methods of confirming that drift is acceptable are used for each of these systems. The sections below detail the method used to confirm that changing from monthly to quarterly functional testing will not J allow actual instrument channel drift to exceed the drift components specified in the setpoint ~

determination calculation.

.I Reactor Protection System ~

Figure 1 provides a simplified schematic of a typical RPS analog instrument loop. For the RPS, all the analog Bistable Trip Units (BTU) and the same and are interchangeable. These bistables are electronic comparators (operational amplifiers) which utilize a reference voltage as the trip setpoint. The process signal is developed across the loop resistor to provide 1-5 volt input to the bistable trip unit. If the input voltage exceeds the reference or trip setpoint in the appropriate direction the bistable changes state deenergizing the output relay. Drift of the setpoint of the BTU consists of two portions. One portion is the drift of the reference voltage used to establish the setpoint reference. The second portion of the drift is the change in the value of the process input required to trip the bistable for a given reference voltage. Each of these drift components is discussed below.

1

The reference voltage to the bistable trip unit is currently measured each month as part of our functional tests. If the reference voltage as-found is greater than +/-.0001V (+/-0.0025%) from the nominal value, the reference voltage is adjusted back to within this range. Typical drift data for the adjustments to the reference voltage of the 8 Steam Generator low level trip units (Table 1) shows that the maximum monthly drift of these units was +/-0.0014 volts (+/-0.035%). Linear extrapolation of this drift data to a 115 day test interval results in a total drift of +/-0.0054 volts

(+/-0.134%).

Vendor data for the RPS bistable specifies that the drift of the bistable is +/-0.003 volts

(+/-0.075%) per 30 days. Our setpoint methodology extrapolates this drift value to 0.006 volts (0.15%) for a 115 day test interval. As shown above, the maximum observed linearly extrapolated drift of the reference voltage was +/-0.0054 volts ( +/-0.134%) for a 115 day test frequency. This extrapolated drift is below the value assumed in our setpoint analysis, thus, extending the functional test interval from monthly to quarterly will not result in exceeding the drift value assumed for the reference voltage in our setpoint analysis.

To determine the process voltage at which the bistable trips, the process signal is increased or decreased to a value to trip the bistable. As part of this testing, the voltage at which the process trips the bistable is recorded. The methodology for this test uses a built-in test power supply to aid or buck the existing process signal. This method reflects Combustion Engineering's design philosophy that the process signal is never isolated from the RPS during testing. As a result of the methodology, process noise during measurement of the trip point voltage causes difficulty in obtaining an accurate measurement. Process noise is a real perturbation of the monitored signal resulting from turbulence of the parameter being monitored. Figure 2 shows the differences between two process signals, one relatively quiescent (Pressurizer Pressure), and one with significant process noise (Steam Generator Level). Both plots have a range of +/-10% of the monitored parameter. These plots show that the process noise associated with Steam Generator Level instrument loop is approximately 1% of the measurement range.

Figures 3 and 4 show data collected for the last two years for the process value which trips the RPS bistable. Figure 3, for the Steam Generator pressure .. shows data for channels which have very little process noise. As can be seen by observing the long term average of the this figure, there is relatively little drift associated with the value at which the process input trips the bistable. Figure 3 for the steam generator level channels shows the data obtained for a process signal containing significant process noise. Although the measured trip value fluctuates significantly, the average value for the period can be seen to be flat indicating little channel drift.

Due to the process noise associated with these channels, the drift from month to month cannot be directly obtained from this data.

2

During refueling outages, the entire instrument loop is calibrated using precision instrumentation. To perform this calibration, the transmitter is disconnected from the process and replaced with a precision pressure (differential pressure) source. Use of this precision source allows accurate determination of the loop voltage required to trip the bistable. Data collected during the past 4 refueling outage calibrations for the Steam Generator level channels is provided in Table 2. This data is collected after adjusting the reference to the precise setpoint voltage and thus changes in the setpoint between the 18 month nominal calibration intervals can be accurately determined. This data shows that there are only small changes in the bistable modules trip settings between refueling outages. All data was found to be within as-left tolerances and thus no adjustments were necessary as a result of these measurements. The maximum change between the calibration intervals was -0.013 volts (+/-0.325%).

The setpoint methodology for the RPS bistable trip units assigns a total device uncertainty to the RPS bistables of +/- 0.016 volts (+/-0.4%). This uncertainty is based on vendor accuracy and drift specifications for the bistable. The drift assumed in our methodology is based on a quarterly test frequency of 115 days (92 days + 25% ). As described above, the maximum observed change in the bistable trip point was 0.013 volts (+/-0.325%) between calibration intervals. As the 18 month data exceeds the proposed quarterly test frequency by a factor of 6, and as the observed data is within the specified uncertainties used in our setpoint calculation, increasing the test interval from monthly to quarterly will not result in exceeding the bistable uncertainty value assumed in the setpoint analysis.

Similar data for each of the Reactor Protection System instrument loops was reviewed with results similar to that shown for the steam generator level instrument loop. The data as discussed above shows that the RPS bistable trip units are very stable and that increasing the functional test interval for the Reactor Protection System from monthly to quarterly will not cause the setpoint value to exceed the allowable value as calculated by our setpoint methodology.

Engineered Safety Features Actuation System Figure 5 shows the monthly trip data taken for the low primary coolant system pressure channels which provide one of the engineered feature actuations. For these instrument loops, the bistable is an electro/mechanical device. The device consists of an LED and photosensitive driver. The position of a moving arm is changed based on the input signal. When the arm covers the LED, the photosensitive device turns off, changing the state of the output relays. As a result of this design, there is no reference voltage which can be measured and adjusted.

Thus, no adjustments are made to the bistable between calibration intervals. The current/voltage at which the bistable trips is, however, measured and recorded monthly .

3

Monthly trip voltage data is shown plotted on Figure 5. The data for this channel is taken in a similar manner to that described above for the RPS bistables. A test signal is inserted in parallel with the existing loop signal and the test signal is raised or lowered as appropriate to drive the bistable input toward the trip setting. This method results in the process noise riding on the signal resulting in some of the data scatter. Additional data scatter results from the repeatability (accounted for in the setpoint methodology) of the electro/mechanical bistable. Review of this data, however, shows that the setpoint remains well above the minimum acceptable value derived by our setpoint methodology and that there has been no obvious long term drift of these bistables over the last two and one-half years.

Additional data showing the low drift of these bistables is provided in Figure 6. This data shows the trip setpoint data taken during the last 3 calibration intervals. The data on the time line labeled (F) is the final data whereas the data labeled (A/F) is the as-found data. All data was found to be within as-left tolerances, however some adjustments were made to the instrument loop to locate the actual trip setpoint closer to the center of the acceptable range. From this data it can be seen that the as-found data taken was always within the allowable final tolerance.

Although this calibration data is for the combined drift of both the pressure transmitter and bistable, it shows that the combined drift of all loop components is low during the 18 month calibration interval.

Similar data for each of the Engineered Safety Feature Actuation System instrument loops was reviewed with results similar to that shown for the pressurizer pressure loop. The data as discussed above shows that the ESF bistable trip units are very stable and that increasing the functional test interval for the Engineered Safety Feature Systems from monthly to quarterly will not cause the setpoint value to exceed the allowable value as calculated by the our setpoint methodology .

4

Table 1

REACTOR PROTECTION SYSTEM MONTHLY FUNCTIONAL TEST MI-2 COMPARATOR VOLTAGE ADJUSTMENT DATA This data is obtained froin a monthly test where a built-in test power supply is connected to the process signal and it aids or bucks the process signal to drive it to the setpoint. This test records the voltage at the trip point. Additionally, the setpoint (reference) voltage of the Bistable Trip Unit (BTU) is measured and adjusted as necessary to meet Final tolerances. This setpoint voltage is used in the BTU to compare against the process signal to determine if the setpoint is exceeded.

MI-2 data from 4/97 to 3199 was reviewed. The following Table shows the date and magnitude of the comparator setpoint voltage adjustments made during this time period.

The Palisades RPS uses a 1 to 5 Vdc signal range. A 0.0001 Vdc adjustment corresponds to 0.0025% of scale change (0.0014 Vdc - 0.035%).

Equipment 2/98 7/98 9/98 10/98 LA-0751A AF 2.0764 F 2.0770

-0.0006 LA-0751B AF 2.0767 AF 2.0763. AF 2.0779 F 2.0771 F 2.0771 F 2.0770

-0.0004 -0.0008 0.0009 LA-0751C AF 2.0756 AF 2.0783 F 2.0770 F 2.0769

-0.0014 0.0014 LA-0751D AF 2.0775 AF 2.0766 F 2.Q17Q F 2.0770 0.0005 -0.0004 LA-0752A LA-0752B AF 2.0762 AF 2.0778 F 2.0770 F 2.0769

-0.0008 0.0009

LA-0752C LA-0752 AF 2.0757 F 2.0769

-0.0012 AF 2.0783 F 2.0770 0.0013

Table 2 REACTOR PROTECTION SYSTEM REFUELING OUTAGE DATA RI-4 This data is obtained from an end-to-end test where a pressure source is applied to the transmitter along with a calibrated pressure gauge, a multimeter is connected to the input on the Bistable Trip Unit (BTU), and the trip lights on the front of the BTU are visually monitored. Pressure is applied at the transmitter and when the trip lights illuminate, the As Found pressure and BTU input voltage are recorded.

For the Steam Generator #1 and #2, the desired BTU trip voltage is 2.077 Vdc.

The setpoint voltage data following is from historical REFOUT loop calibration procedures.

Equipment 5/98 11/96 6195 6/93 LA-0751A 2.080 2.070 2.067 2.080 LA-0751B 2.081 2.082 2.076 2.081 LA-0751C 2.079 2.078 2.073 2.067 LA-0751D 2.078 2.079 2.073 2.078 LA-0752A 2.079 2.079 2.075 2.080 LA*0752B 2.080 2.080 2.070 2.077 LA-0752C 2.077 2.075 2.070 2.078 LA-0752D 2.079 2.079 2.070 2.081

LOOP FIGUR~

POWER SUPPLY OTHER COMPONENTS

+ (-)

l TEST VOLTAGE r RLOAD T

l T

REFERENCE VOLTAGE .

..__~ + <->r----------4---~---_J SIMPLIFIED RPS TRIP CHANNEL TRANSMITTER TO PROCESS, OR CALIBRATION SOURCE

,., Y S .,- E

~

n A

.*: IV!

t: J .,

~. {J

1* Fl 1-Jh. D I N c 2110 . 00 7 5 . 00 2010 . 00

55. 00 09:08:54 09 : 14 : 53 09:20:53 PT0102A Pre s s u r i z er SI Ch a*n n e 1 P res s 2054.09 psia LT0751A Narr Rnge Lvl Stm Gen E-SOA 6 c]

6 ~'. v c-! r cent I l /\

. *:r.._,..i TREND .. F? MED I UM. F8 . S LO;\/ Fe : BAS°E * . F1j a* HOUR FS WI NDONS ,

- - FIGURE 3 - -

STM GEN #2 LOW PRESSURE I

2.76 --- - - -

2.74 0- ---0----~-----~-- 0---- 0 - -0 0 -0 -<) 0 <)- - 0 0 0 <) - 0 --- 0

PA-0752A Q) 2.72 -- ~ PA-07528 0>

-a1 i---u -9:.c-*

. ./

V 0 ~-~- ---1* ----lflb~

, - __::::~-" _,_,-1-~--- -* - --f- ----~-'o:- - ~- /-i*l~f-- t:- '*- - -_-"

Ill -- *----f~"'"-- .& PA-0752C

>a.

c

-~--. ----*- ---.---- -- - - ~-- 1 1 PA-07520 I- 2.7 o UPPER LIMIT

/\ LOWER LIMIT

/J-fr---6-----fs-- -A-----A- ----A---- A- ---6--- -A--- A--- A-------A- --A----!J- A- ---A -A- -- -A -A A 2.68 2.66 _L _ _ j _ __ J ______ L ___L_ _____ J ______ _J_ ____ L_ _____ !_ ____ J ____ J ____ J _______ J _____ j_ ___ L ___ J _______ l ______ L - _l .. I______ I APR'97 JUN'97 AUG'97 NOV'97 JAN'98 MAR'98 JUN'98 AUG'98 OCT'98 DEC'98 MAR'99 MAY'97 JUL'97 SEP'97 DEC'97 FEB'98 APR'98 JUL'98 SEP'98 NOV'98 FEB'99 i--- ------ PA-0752ASefPoi-rlf"AdJUsted-Oil-1'<)797~-*-f 1797, *a*na--5i~ia--:--PA-0752-s**setpOifif Adjusted- on **fo/97*,* 1f/91, *g/98, and fOi98

[PA-0752C Setpoint Adjusted on 4/97, 7/97, 10/97, 11/97, 5/98, 9/98, 10/98, 1/99, and 2/99: PA-07520 Setpoint Adjusted on 10/97, 11/97, 5/98, 9/98, an I_ - -- -------------------------------------------- ---------- - -- - ----------------- - - -- --- ---- -- - - --- ----- - - - ----------- ------- - -----

FIGURE 4 STM GEN #1 LOW LEVEL 2.12 0 0- -~---0----0---- -0-----0-. 0 . 0 -* 0 0 y 0 .0 0 - 0. 0 <> 0 <> 0 - 0 2.1

LA-0751A Q) 4? LA-07518 I O>

ro

+-'

.A LA-0751C I.

0 2.08

>Q. I I LA-07510 I I- o UPPER LIMIT

/\ LOWER LIMIT 2.06 f>r--6-----A---A--6--- --6 ----l's---6----6----6---6. -A-----A--6-----6.----6----6.-

6 - A A- -A- A !\ --/\..

2.04 __J__ .l_______ L __ _L ___ L ____l ____ L ___l ____l ______ L _____ J_ --- _! ________ L -- L ____J______ J ________ L _ .L. __ J _ . ___ l ____ L . .I I .. _ L APR'97 JUN'97 AUG'97 OCT'97 DEC'97 FEB'98 APR'98 JUN'98 AUG'98 OCT'98 DEC'98 FEB'99 MAY'97 JUL'97 SEP'97 NOV'97 JAN'98 MAR'98 MAY'98 JUL'98 SEP'98 NOV'98 JAN'99 MAR'99 l~~g;:~~-~:~~!~~f~:::~-~~-~~~-~:-;~~!:~~9~::n~:~~g~~ ~~~;~~~ri~-!~~~~!e1dJ~~~~~ J~ ~~~l~~~B~~~B~~~d~~~~-*

5 9 L

FIGURE 6 Rl-3 CALIBRATION DATA (PRESSURIZER LOW PRESSURE)

AS FOUND I FINAL 14.6

-+-PIA-0102Al:L I

- P I A-0102BLL I

---i&-PIA-0102CLL

-*-PIA-0102DLL 14.4

-.-upper Limit

_.__Lower Limit I

14.2 I-z w

a:

0 14

~

13.8 13.6 13.4 1--~~~~~---~~~~~~--~~~~~~-;.-~~~~~~t--~~~~~--.-~~~~~---4 6/21 /1993(F) 6/22/1995(A/F) 7/4/1995(F) 11/13/1996(A/F) 11/13/1996(F) r .l/1998(A/F) 5/6/1998(F)

DATE I

- _J

ML18066A591

Text

Navigation menu

Search