Text

Proposed Tech Specs 3.4.12 Re RCS Operational Leakage,Ts 5.6 Re Procedures,Programs & Manuals & TS 5.7 Re Reporting Requirements
	ML20137G829
Person / Time
Site:	Crystal River
Issue date:	03/27/1997
From:	; FLORIDA POWER CORP.
To:	;
Shared Package
ML20137G818	List: 3F0397-16, Application for Amend to License DPR-72 Re Once Through SG Tube Surveillance Program; ML20137G829;
References
	NUDOCS 9704010536
	Download: ML20137G829 (26)
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l Crystal River Unit 3 Technical Specification Change Request Notice 211 3

Changes marked in Strikeout and Shadow Fonts l

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9704010536 970327 PDR ADOCK 05000302 P PDR

l RCS Operational LEAKAGE I 3.4.12 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.12 RCS Operational LEAKAGE LC0 3.4.12 RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE; j

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE; and i 1

d. 150 gpd of primary-to-secondary LEAKAGE :

through any one steam generator (OTSG). !

Two OTSGs shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS ,

CONDITION REQUIRED ACTION COMPLETION TIME !

A. RCS LEAKAGE not within A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months limits for reasons within limits.

other than pressure boundary LEAKAGE.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND QR B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Pressure boundary LEAKAGE exists.

Crystal River Unit 3 3.4-22 Amendment No.

W1id Until Refuel !! Only

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RCS Operational LEAKAGE B 3.4.12 BASES-I APPLICABLE The FSAR (Ref. 3)-analysis for sfisisiTiehEFi'tEEf66EWiiifdF4 SAFETY ANALYSES (SGTR) assumes the contaminated"seEondiFF f161d'ii^on17 -

(continued) briefly released via safety valves and the majority is steamed to the condenser. The 1 gpm primary to secondary LEAKAGE is relatively inconsequential in terms of offsite dose.

The FSAR steam line break (SLB) analysis (Ref. 4) is more limiting for site radiation releases. The safety analysis for the SLB accident assumes 1 gpm primary to secondary LEAKAGE in one generator as an initial condition. The dose consequences resulting from the SLB accident meet the acceptance criteria defined in 10 CFR 100.

RCS operational LEAKAGE satisfies Criterion 2 of the NRC -

Policy Statement.

LCO RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being i indicative of material deterioration. LEAKAGE of this I type is unacceptable as the leak itself could cause further deterioration,;resulting in higher LEAKAGE.

Violation of this LCO could result in continued degradationoftheFeictoEso~ol'Ahtij(fskiUFi%dhditj~

(RCPB). LEAKAGE past" kii1Tiha'^ phi sti~'is"not~^^

pressure boundary LEAKAGE.

b. Unidentified LEAKAGE !

One gallon per minute (gpm) of unidentified LEAKAGE is !

allowed as a reasonable minimum detectable amount that ;

the containment atmosphere and sump level monitoring equipment can detect within a reasonable time period.

Violation of this LC0 could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

(continued)

Crystal River Unit 3' B 3.4-54 Amendment No.

4 RCS Operational LEAKAGE B 3.4.12 BASES

c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with the detection of unidentified LEAKAGE and is well within the capability of the RCS makeup system. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE).

Violation of this LC0 could result in continued degradation of a component or system.

d. Primary to Secondary LEAKAGE throuah All Steam Generators (OTSGs)

This leakage limit complement; the :t;tistical analysi performed ;; the b;;is for the disposition strategy for first span intergranular Attack (ICA) cddy current indication . The statistical analy;i demonstr;tc; lev probability of LEAKACE frcm first span ICA indication; during the Operating cycle. This reduced LEAKACE limit is intended to provide additional ;;;urance that if primary to seccadary LEAKACE : cre to cc+ue, it . ill be detected, and the plant shutdevin in ; timcly ~ manner. Thiill.EAKAGE?litiiff i si;e s tabl i s hsd iteleh s u re? th a ti tubisHn i t i al lyll e a ki ng~

during i normali ope rati onido? noti contri b~utel exces si vely toctotal: leakage during postulited4 accident ^ ~

^

conditions M The 150;gpd?limittis!:Ancon' servi {ille*'l'ijnff which ! i sl consi stent 1wi ths the : operation;a141.eakage;11mi t specified in:NRC: Generic; Letter;95-05;foriplants .

implementingEAlternate Repair 1 Criteria 3 JCR;3)has .

el ect ed ;to ivol un t arily Ladop tit hi si con s e rvativ e (l imi t to(ensure:plantVshutdownjinTaltimelylmannerrin.. . .. .

re sponsel to ' detecti on.' of ? pri mary: t o f s'ec'ondary-l LEAKAG E J Primary tb~ secondary LEAKAGE'~must' be inclu'ded in the~ ~

total allowable limit for identified LEAKAGE.

Two OTSGs are also required to be OPERABLE. This requirement is met by satisfying the augmented inservice inspection requirements of the Steam Generator Tube Surveillance Program (Specification 5.6.2.10).

(continued)

Crystal River Unit 3 B 3.4-55 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals- (continued) 5.6.2.10 OTSG Tube Surveillance Program (continued) in the specific area of an OTSG are inspected with the '

inspection result classification and the corresponding action required as specified in Table 5.6.2-3. No credit will be taken for these tubes in meeting minimum sample size requirements. Degraded or defective tubes l found in these areas will not be considered in determining the inspection results category as long as the mode of degradation is unique to that area and not random in nature.

-sZ f:..InieWiielfsbssWi tW5i tMiksGIGA MndildiWondidit6s f MB10TSGSidentifisdnintthe10TSG^ l I n se rsi c'e d n s pecti on) Survsil l ance ? Procedu re Mmu st?be inspectedIwi_thibobbin7and!MotorizsdlRotatingiPancake_

C oi 1X(MRPC )feddyicuprsntXtechn i que sj fromit hell owe rstu6s., !

'sheetisecondaryi.faceito f the;bottomiofithelfirstitube^ l s upportf pl ~ateldu ri hgi esch ti n se rv i ce nn s pecti on%fs theiB i OTSG hj Noj c red i t si;s y tbf.b_e {tikeniforithi s].i nspestibnfi n~

meet i ng :.mi n imumJs ampl e ::. s i zej requ i rements1::; fore thegandom ,

inspection? iDefectiveltubesifodnd(duringl:this l inspectionfaFeitolbeipluggedjoMslsevedb.]DsgridifbE_ '

defective;t bes:: found;during(thist::inspectionvare :notyto belcon s i de red l i ni dete rmini ng B the.bi n specti 6nt res ul t s category L forzthelrandom 6 inspection p unlessiths"~"

degradat i on Mech an i sm i iden t i fi edi.i~ "s "Falmechani sni?bnisE i thanjpit g ikef1 gay '"~ ~ ^ ^ ~~ ~ ~

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(continued)

Crystal River Unit 3 5.0 14 Amendment No.

l Wlid Until Refucl 11 Only l

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c Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals (continued) 5.6.2.10 OTSG Tube Surveillance Program (continued) :

The results of each bobbin coil sample inspection shall be classified into one of the following three categories:

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NOTE--------------------------~------ ,

In all inspections, previously degraded tubes whose degradation -

has not been spanned by a sleeve must exhibit significant incre;;c (

in the :pplicable imperfection size acastrencnt (1 0.3V bcbbin

coil ::plitude. increase for first :::n ICA indic;tica: cr >10% '

further ::11 p nctratica for all ct;cr imperfections) (>10%) '

furtheFVWallip_enst_f.i.._tl.~6ns to be included in the below percentage g.g - ~

l Cateaory Inspection Results C-1 Less than 5% of the total tubes ,

inspected are degraded tubes and none.of the inspected tubes are i defective. i C-2 One or.more tubes, but not more than 1% of the total tubes inspected are defective, or between 5% and 10% of i the total tubes inspected are ,

degraded tubes.

r C-3 .More than 10% of the total tubes i inspected are degraded tubes or more than 1% of the inspected tubes are defective.

(continued)

Crystal River Unit 3 5.0-14A Amendment No.

. . _ _ _ _ --. . - - - ~ ~ .- _ . - ._ m Procedures, Programs and Manuals 5.6 1

5.6 Procedures, Programs and Manuals ;

1 5.6.2.10 OTSG Tube Surveillance Program (continued) i 1

4. Acceptance criteria:

a. Vocabulary as used. in this Specification: ,

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1. Tubing or Tube means that portion of the tube or sleeve !

which forms the primary system to secondary system i pressure boundary. i

2. Imperfection means an exception to the dimensions, finish or contour of a tube from that required by fabrication drawings or specifications. Any indicatica l belcw :11 degraded tube criteria :pccified in item t imperfection:. EddiWuffant 1 belcw :[:" be cca idered ::testihg ihdinatfo6Mbe16(20%i6f2thifn6 :

th_ickneshti fjdet'setable8msyj bs3onsidefedjjss imperfections) ;

3. Degradation means a service-induced cracking, wastage, wear, or general corrosion occurring on either inside or outside of a tube. i i

4. Degraded Tube means a tube containing : fir:t :p n ICA ,

indicatica with bcbbin coil : plitude 10.55" cr 1 !

0.13 inche: 2xial extent er 10.3 circumferential i cxtent er imperfections 120% of the nominal wall thickness caused by degradation except where all such degradation has been spanned by the installation of a ;

sleeve. '

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5. % Degradation means the' percentage of the tube wall i thickness affected or removed by degradation. '

6. Defect means an imperfection of such severity that it !

exceeds the plugging / sleeving limit except where the ,

imperfection has been spanned by the installation of a sleeve. A tube containing a defect in its pressure i boundary is defective. Any tube which does not permit ;

the passage of the eddy-current inspection probe shall !

be deemed a defective tube. y

7. Fir:t :p;n Inter grariular Attack (ICA) indication: me n

Scbbin coil indicatica located between the 1^wer ti,

_ . ^_;h^^t,;^ ^r6ra'

___ 4___; u.. unnr f;;^ ._t.,.-

rad t'^ ,fir,;t .._ . .tu'_^ _ _ . ,_;;pp^rt,_

____u_ m yiu6w vvis a imwu vy eini v vv rau w w w w i umw w a iw inv i yr av i vyy ch r:cteristic cf ICA. Pit #11ks?IntergrahulaEAttick (IGA)71ndicAti6n?.means"albobbinicolhiindicatiof confirmedLbiTMotorized Rotatin'1Pincike'Coih g (MRPC)'?6F "

otheriqual i fi ed !i nspecti on 3 thchni quesi t'6i havba Volumet,ricHpitE11ke morph 61ogyfcharactefHtjsi6fMIGAt l

i (continued) l Crystal River Unic 3 5.0-16 u,,42 Amendment No.

n_,m n_. o n _ c, . . _ ,

vus su vie w i e ow uwe is 44 vusy

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Procedures, Programs and Manuals 5.6 ,

5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG Tube Surveillance Program (continued)

8. Plugging / Sleeving Limit means the extent of degradation beyond which the tube shall be restored to serviceability by the installation of ,

a sleeve or removed from service because it may j become unserviceable prior to the next inspection i and is equal to 40% of the nominal tube or sleeve wall thickness. No more than five thousand sleeves may be installed .in each OTSG.

9. Unserviceable describes the condition of a tube if it leaks or contains a defect large enough to j affect its structural integrity in the event of an Operating Basis Earthquake, a loss-of-coolant accident, or a main steam line or feedwater line break, as specified in 5.6.2.10.3.c, above.

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10. Tube Inspection means an inspection of the entire l 0TSG tube as far as possible.

b. The OTSG shall be determined OPERABLE after completing the corresponding actions (plug or sleeve all tubes exceeding the plugging / sleeving limit and all tubes i containing through-wall cracks) required by Table I 5.6.2-2 (and Table 5.6.2-3 if the provisions of l Specification 5.6.2.10.2.d are utilized). Defective !

tubes may be repaired in accordance with the B&W process (or method) equivalent to the method described ,

in report BAW-2120P.

5.6.2.11 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit steam generator tube degradation and low pressure turbine disc stress corrosion cracking. The program shall include:

a. Identification of a sampling schedule for the critical variables and control points for these variables;

b. Identification of the procedures used to measure the values of the critical variables; 5.6.2.11 Secondary Water Chemistry Program (continued) l (continued) <

Crystal River Unit 3 5.0-17 Amendment No.

Wlid til Refuel 11 Cr.ly

Procedures, Programs and Manuals 5.6 I

5.6 Procedures, Programs and Manuals

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c. Identification of process sampling points, which shall ,

include monitoring the discharge of the condensate pumps for !

evidence of condenser in leakage; i l

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d. Procedures for the recording and management of data, ;

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, e. Procedures defining corrective actions for all off control !

point chemistry conditions; and )

f. A procedure identifying the authority responsible for the )

interpretation of the data and the sequence and timing of -

administrative events, which is required to initiate l corrective action. i j 5.6.2.12 Ventilation Filter Testing Program (VFTP) j A program shall be established to implement the following required j

, testing of the Control Room Emergency Ventilation System (CREVS) ;

'; per the requirements specified in Regulatory Guide 1.52, Revision 2, 1978, and in accordance with ASME N510-1975_ and ASME N509-1976.

l a. Demonstrate for each train of the CREVS that an inplace test 1

of the-high efficiency particulate air (HEPA) filters shows a penetration and system bypass < 0.05% when tested in i accordance with Regulatory Guide 1.52, Revision 2,1978, and l 4

in accordance with ASME N510-1975 at a flowrate of 43,500 )

cfm i 10%.

b. Demonstrate for each train of the CREVS that an inplace test ,

of the charcoal adsorber shows a penetration and system l bypass < 0.05% when tested in accordance with Regulatory I

Guide 1.52, Revision 2, and ASME N510-1989 at the system

. flowrate of 43,500 cfm i 10%.

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c. Demonstrate for each train of the CREVS that a laboratory test of a sample of the charcoal adsorber, when obtained as l' described in Regulatory Guide 1.52, Revision 2, 1978, shows the methyl iodide penetration less than 1% when tested in accordance with Table 2 of Regulatory Guide 1.52, Revision 2 i and ASME N509-1976 at a temperature of 80*C and 70% relative

humidity.

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5.6.2.12 VFTP (continued)

, (continued) 2 Crystal River Unit 3 5.0-18 Amendment No.

Slid Until Rc'=1 11 Only 4

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,_ Reporting Requirements 5.7 5.7 Reporting Requirements 5.7.2 Special Reports (continued)

The following Special Reports shall be submitted:

a. When a Special Report is required by Condition B or F of LC0 3.3.17 " Post Accident Monitoring (PAM)

Instrumentation," a report shall be submitted within the 1

following 14 days. The report shall outline the preplanned ,

alternate method of monitoring, the cause of the '

' inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status. ,

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b. Any abnormal degradation of the containment structure ;

detected during the tests required by the Containment Tendon i Surveillance Program shall be reported to the NRC within

30 days. The report shall include a. description of the tendon condition, the condition of the concrete (especially 4

3 at tendon anchorages), the inspection procedures, the

tolerances on cracking, and the corrective action taken.

c. Following each inservice inspection of steam generator

, (OTSG) tubes, Tthe NRC ch:11 be nctified of the fcl10 wing -

i prior te ascen:ica inte MODE 4: thsThumbeE6fftsbiE510ggsd -

ahdisl eeVedHn ie scif[0TSG ?sh a113 beWepo rted itol the !NRC y Wi thi li gggyy .,

1. Number of tubc: plugged and :lceved

2. Crack like indication; in the first span l'

3. An :::cs:=cnt of the growth in the first span indications, ;nd

4. Rc ult: cf in situ prc :ure testing, if perfrcr cd.

l The complete results of the OTSG tube inservice inspection shall be submitted to the NRC within 12 months following the completion of the inspection. The report shall include:

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1. Number and extent of tubes inspected, 4

2. Location and percent of wall-thickness __ penetration for each indication of an imperfection, isd j

3. Lccation, bcbbin coil ap litude, and axial and circumferential extent (if determined) for c;ch first p:n ICA indication, and, 4- Identification of tubes plugged and tubes sleeved. l (continued)

Crystal River Unit 3 5.0-29 Amendment No.

hlid Until Refuel 11 Only

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Crystal River Unit 3 i Technical Specification Change Request Notice 211

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RCS Operational LEAKAGE 3.4.12 l

3.4 REACTOR COOLANT SYSTEM (RCS) l 1

3.4.12 RCS Operational LEAKAGE l l

i LC0 3.4.12 RCS operational LEAKAGE shtll be limited to: '

a. No pressure boundary LEAKAGE;

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE; and

d. 150 gpd of primary-to-secondary LEAKAGE l through any one steam generator (OTSG). l Two OTSGs shall be OPERABLE. l APPLICABILITY: MODES 1, 2, 3, and 4.

i ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RCS LEAKAGE not within A.1 Reduce LEAKAGE to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months limits for reasons within limits.

Other than pressure boundary LEAKAGE.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time not met. AND QB B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months Pressure boundary I LEAKAGE exists.

i Crystal River Unit 3 3.4-22 Amendment No. ,

RCS Operational LEAKAGE B 3.4.12 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.12 RCS Operational LEAKAGE BASES BACKGROUND Ouring the life of the plant, the joint and valve interfaces I contained in the RCS can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration. The purpose of the RCS Operational LEAKAGE LCO is to lir. . system operation in the presence of LEAKAGE from these sources to amounts that do )

not compromise safety. This LC0 specifies the types and '

amounts of LEAKAGE.

10 CFR 50, Appendix A, GDC 30 (Ref. 1), requires means for detecting and, to the extent practical, identifying the source of reactor coolant LEAKAGE. Regulatory Guide 1.45 (Ref. 2) describes acceptable methods for selecting leakage detection systems. OPERABILITY of the leakage detection systems is addressed in LC0 3.4.14, "RCS Leakage Detection Instrumentation."

The safety significance of RCS LEAKAGE varies widely depending on its source, rate, and duration. Therefore, detecting, monitoring, and quantifying reactor coolant LEAKAGE is critical, Qu'.ckly separating the identified LEAKAGE from the unidentified LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur.

A limited amount of leakage inside containment is expected from auxiliary systems that cannot be net 100% leaktight.

Leakage fro.n these systems should be detected, located, and .

isolated from the containment atmosphere, if possible, to not interfere with RCS leakaga detection.

APPLICABLE Except for pri'rary to secondary LEAKAGE, the safety analyses SAFETY ANALYSES do not address nperational LEAKAGE. However, other operational LEAkAV is related to the safety analyses for a LOCA in that the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmosphere assumes 1 gpm primary to secondary LEAKAGE as the initial condition.

(continued)

Crystal River Unit 3 B 3.4-53 Amendment No.

RCS Operational LEAKAGE B 3.4.12 ,

BASES APPLICABLE The FSAR (Ref. 3) analysis for steam generator tube rupture l SAFETY ANALYSES (SGTR) assumes the contaminated secondary fluid is only (continued) briefly released via safety valves and the majority is steamed to the condenser. The 1 gpm primary to secondary LEAKAGE is relatively inconsequential in terms of offsite dose.

The FSAR steam line break (SLB) analysis (Ref. 4) is more limiting for site radiation releases. The safety analysis for the SLB accident assumes 1 gpm primary to secondary LEAKAGE in one generator as an initial condition. The dose consequences resulting from the SLB accident meet the acceptance criteria defined in 10 CFR 100.

RCS operational LEAKAGE satisfies Criterion 2 of the NRC Policy Statement.

LC0 RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE.

Violation of this LC0 could result in continued degradation of the reactor coolant pressure boundary l (RCPB). LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

b. Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is .

allowed as a reasonable minimum detectable amount that l the containment atmosphere and sump level monitoring -

equipment can detect within a reasonable time period.

Violation of this LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

I (continued)

Crystal River Unit 3 B 3.4-54 Amendment No.

RCS Operational LEAKAGE B 3.4.12 ;

BASES

c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with the detection of unidentified LEAKAGE and is well within the capability of the RCS makeup system. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary '

LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff-(a normal function not considered LEAKAGE).

Violation of this LC0 could result in continued degradation of a component or system.

d. Primary to Secondary LEAKAGE throuah All Steam Generators (OTSGs)

This LEAKAGE limit is established to ensure that tubes initially leaking during normal operation do not I contribute excessively to total leakage during postulated accident conditions. The 150 gpd limit is l a conservative limit which is consistent with the -

operational leakage limit specified in NRC Generic !

Letter 95-05 for plants implementing Alternate Repair Criteria. CR-3 has elected to voluntarily adopt this conservative limit to ensure plant shutdown in a timely manner in response to detection of primary to i secondary LEAKAGE. Primary to secondary LEAKAGE must be included in the total allowable limit for identified LEAKAGE.

Two OTSGs are also required to be OPERABLE. This requirement is met by satisfying the augmented inservice inspection requirements of the Steam Generator Tube Surveillance Program (Specification 5.6.2.10).

l (continued)

Crystal River Unit 3 8 3.4-55 Amendment No.

RCS Operational LEAKACE B 3.4.12 BASES APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE or an event that challenges OTSG tube integrity is greatest since the RCS is pressurized. In MODES 5 and 6, LEAKAGE limits and 0TSG OPERABILITY are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE or failure.

LC0 3.4.13, "RCS Pressure Isolation Valve (PIV) Leakage,"

measures leakage through each individual PIV and can impact this LCO. Of the two PIVs in series in each line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leaktight. If both valves leak and result in a loss of mass from the RCS, the loss must be included in the determination of allowable identified LEAKAGE.

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Crystal River Unit 3 8 3.4-55A Amendment No.

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RCS Operational LEAKAGE B 3.4.12 BASES THIS PAGE INTENTIONALLY LEFT BLANK i

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Crystal River Unit 3 B 3.4-55B Amendment No.

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RCS Operational LEAKAGE l B 3.4.12 BASES ACTIONS aml If unidentified LEAKAGE, identified LEAKAGE, or primary to secondary LEAKAGE are in excess of the LCO limits, the LEAKAGE must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCP8.

D.1 and B.2 If any pressure boundary LEAKAGE exists or if unidentified, identified, or primary to secondary LEAKAGE cannot be ,

reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be placed in a lower pressure condition to reduce the severity of the LEAKAGE and its potential consequences. The reactor 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 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This action reduces the LEAKAGE and also reduces the stresses that tend to degrade the pressure boundary.

The Completion Times allowed are reasonable, based on operating experience, to reach the required conditions from full power conditions in an orderly manner and without challenging plant systems. In MODE 5, the pressure stresses acting on the RCPB are much lower and further deterioration is much less likely.

i SURVEILLANCE SR 3.4.12.1 REQUIREMENTS Verifying RCS LEAKAGE within the LCO limits ensures that the integrity of the RCPB is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection.

Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance. Primary to secondary LEAKAGE is also measured by performance of an RCS water inventory balance in conjunction with effluent monitoring within the secondary steam and condensate systems.

(continued)

Crystal River Unit 3 B 3.4-56 Amendment No.

RCS Operational LEAKAGE B 3.4.12 '

BASES SURVEILLANCE SR 3.4.12.1 (continued)

REQUIREMENTS The RCS water inventory balance must be performed with the reactor at steady state operating conditions and near operating temperature and pressure. The test must be performed prior to entry into MODE 2 if it has not been performed within the past 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This surveillance is not required to be performed for entry into MODE 4 or MODE 3 or for non-steady state conditions in MODE 3, but must be performed in MODE 3 if 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation are achieved. If the test is not performed prior to all other requirements for entry into MODE 2 being satisfied, entry into MODE 2 must be delayed until steady state operation is established and the requirements of SR 3.0.4 are satisfied.

Steady state operation is required to perform a meaningful ,

water inventory balance; calculations during maneuvering are :

not useful. For RCS operational LEAKAGE determination by

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

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

4 SR 3.4.12.2 This SR provides the means necessary to determine OTSG OPERABILITY in an operational MODE. The requirement to

, demonstrate OTSG tube integrity in accordance with the Steam Generator Tube Surveillance Program emphasizes the importance of OTSG tube integrity, even though this Surveillance cannot be performed at normal operating

, conditions.

i REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.

2. Regulatory Guide 1.45, May 1973.

3. FSAR, Section 14.2.2.2.

4. FSAR, Section 14.2.2.1.

Crystal River Unit 3 B 3.4-57 Amendment No.

Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals (continued) t 5.6.2.10 Steam Generator (OTSG) Tube Surveillance Program i

Each 0TSG shall be demonstrated OPERABLE by performance of the i following augmented inservice inspection program. i

1. Each OTSG shall be determined OPERABLE during shutdown by ;

selecting and inspecting at least the minimum number of !

OTSGs specified in Table 5.6.2-1.

2. The OTSG tube minimum sample size, inspection result ;

classification, and the corresponding action required shall 1 be as specified in Table 5.6.2-2. The inservice inspection '

of OTSG tubes shall be performed at the frequencies specified in Specification 5.6.2.10.3 and the inspected tubes shall be verified acceptable per the acceptance i criteria of Specification 5.6.2.10.4. The tubes selected for each inservice inspection shall include at least 3% of the total number of tubes in all OTSGs. The tubes selected for these inspections shall be selected on a random basis except:

a. Where experience in similar plants with similar water chemistry indicates critical areas to be inspected, .

then at least 50% of the tubes inspected shall be from j these critical areas.

b. The first inservice inspection (subsequent to the preservice inspection) of each 0TSG shall include:

1. All nonplugged tubes that previously had detectable wall penetrations (>20%), and j

2. Tubes in those areas where experience has indicated potential problems.

c. The second and third inservice inspections may be less than a full tube inspection by concentrating (selecting )

at least 50% of the tubes to be inspected) the inspection on those areas of the tube sheet array and j on those portions of the tubes where tubes with ;

imperfections were previously found. I

d. Tubes in specific limited areas which are distinguished by unique operating conditions or physical construction may be excluded from random samples if all such tubes (continued)

Crystal River Unit 3 5.0-13 Amendment No.

s Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG Tube Surveillance Program (continued) in the specific area of an OTSG are inspected with the inspection result classification and the corresponding action required as specified in Table 5.6.2-3. No credit will be taken for these tubes in meeting minimum sample size requirements. Degraded or defective tubes found in these areas will not be considered in determining the inspection results category as long as the mode of degradation is unique to that area and not random in nature.

e. Inservice tubes with pit-like IGA indications in the first span of the B OTSG, identified in the OTSG Inservice Inspection Surveillance Procedure, must be inspected with bobbin and Motorized Rotating Pancake Coil (MRPC) eddy current techniques from the lower tube sheet secondary face to the bottom of the first tube support plate during each inservice inspection of the B OTSG. No credit is to be taken for this inspection in meeting minimum sample size requirements for the random inspection. Defective tubes found during this inspection are to be plugged or sleeved. Degraded or defective tubes found during this inspection are not to be considered in determining the inspection results category for the random inspection, unless the degradation mechanism identified is a mechanism other than pit-like IGA.

(continued)

Crystal River Unit 3 5.0-14 Amendment No.

]" Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals i

1 5.6.2.10 OTSG Tube Surveillance Program .(continued)

The results of each bobbin coil sample inspection shall be classified into one of the following three categories: -

1 ------------------------------NOTE-------------------------------- !

, In all inspections, previously degraded tubes whose degradation !

has not been spanned by a sleeve must exhibit significant (>10%) !

further wall. penetrations to be included in the below percentage

, calculations.

Cateaory Insoection Results C-1 Less than 5% of the total tubes r inspected are degraded tubes and ;

none of the inspected tubes are a

defective.

C-2 One or more tubes, but not more than

, 1% of the total tubes inspected are defective, or between 5% and 10% of the total tubes inspected are !

degraded tubes. l C-3 More than 10% of the total tubes inspected are degraded tubes or more than 1% of the inspected tubes are defective.

l i

l (continued)

Crystal River Unit 3 5.0-14A Amendment No.

f'8 Procedures, Programs and Manuals -

e 5.6 s

5.6 Procedures, Programs and' Manuals L . .

5.6.2.10; OTSG Tube Surveillance Program (continued)

{ ,

3'

3. The above-required inservice inspectim of OTSG tubes shall i be performed at the following frequenc s: i

a. Inservice inspections shall be perf armed at intervals of not less than 12 nor more than 24 calendar months J after the previous inspection. If two consecutive inspections following service under all volatile

, treatment (AVT) conditions, not including the !

preservice inspection, result in all inspection results :

falling into the C-l' category, or if two consecutive !

inspections demonstrate that previously observed '

degradation has not continued and no additional degradation has occurred, the inspection interval may l be extended to a maximum of once per 40 months. 1 I

b. If the inservice inspection of an OTSG, conducted in accordance with Table 5.6.2-2 or Table 5.6.2-3 requires a third sample inspection whose results fall in ,

i Category C-3, the inspection frequency shall be reduced ,

. to at least once per 20 months. The reduction in !

l inspection frequency shall apply until a subsequent ,

j inspection demonstrates that a third sample inspection

.' is not required. .

, c. Additional unscheduled inservice inspections shall be performed on each OTSG in accordance with the first sample inspection specified in Table 5.6.2-2 or Table 5.6.2-3 during the shutdown subsequent to any of the following conditions:

1. Primary-to-secondary tube leaks (not including leaks originating from tube-to-tube sheet welds) in excess of the limits of Specification 3.4.12,

2. A seismic occurrence greater than the Operating !

Basis Earthquake, 1

3. A loss-of-coolant accident requiring actuation of_ !

the engineered safeguards, or

4. A main steam line or feedwater line break.

(continued)

. Crystal River Unit 3 5.0-15 Amendment No.

, I

. l Procedures, Programs and Manuals i 5.6 i 1

5.6 Procedures, irograms and Manuals l

l 5.6.2.10 OTSG Tube Surveillance Program (continued) l

4. Acceptance criteria:

a. Vocabulary as used in this Specification:

1. Tubing or Tube means that portion of the tube or sleeve which forms the primary system to secondary system pressure boundary.

2. Imperfection means an exception to the dimensions, l finish or contour of a tube from that required by fabrication drawings or specifications. Eddy-current testing indications below 20% of the ;

nominal tube wall thickness, if detectable, may be ;

considered as imperfections. l

3. Degradation means a service-induced cracking, i wastage, wear, or general corrosion occurring on '

either inside or outside of a tube.

4. Degraded Tube means a tube containing imperfections 120% of the nominal wall thickness caused by degradation except where all such degradation has been spanned by the installation of a sleeve.

5. % Degradation means the percentage of the tube wall thickness affected or removed by degradation.

6. Defect means an imperfection of such severity that it exceeds the plugging / sleeving limit except where the imperfection has been spanned by the installation of a sleeve. A tube containing a defect in its pressure boundary is defective. Any tube which does not permit the passage of the eddy-current inspection probe shall be deemed a l defective tube.

7. Pit-like Intergranular Attack (IGA) indication means a bobbin coil indication confirmed by Motorized Rotating Pancake Coil (MRPC) or other qualified inspection techniques to have a l volumetric, pit-like morphology characteristic of l IGA.

l (continued)

Crystal River Unit 3 5.0-16 Amendment No.

_ _ _ _ _ _ _ _ _ _ . _ _ _ . . _ _ . . . - . _ _ ._ m .

' i Procedures, Programs and Manuals 5.6 5.6 Procedures, Programs and Manuals 5.6.2.10 OTSG Tube Surveillance Program (continued)

8. Plugging / Sleeving Limit means the extent of degradation beyond which the tube shall be restored to serviceability by the installation of a sleeve or removed from service because it may become unserviceable prior to the next inspection !

and is equal to 40% of the nominal tube or sleeve 1 wall thickness. No more than five thousand i sleeves may be installed in each OTSG. l

9. Unserviceable describes the condition of a tube if it leaks or contains a defect large enough to affect its structural integrity in the event of an Operating Basis Earthquake, a loss-of-coolant accident, or a main steam line or feedwater line break, as specified in 5.6.2.10.3.c, above.

10. Tube Inspection means an inspection of the entire OTSG tube as far as possible.

b. The OTSG shall be determined OPERABLE after completing the corresponding actions (plug or sleeve all tubes i exceeding the plugging / sleeving limit and all tubes !

containing through-wall cracks) required by Table 5.6.2-2 (and Table 5.6.2-3 if the provisions of Specification 5.6.2.10.2.d are utilized). Defective tubes may be repaired in accordance with the B&W process (or method) equivalent to the mthod described ,

in report BAW-2120P. 1 I

5.6.2.11 Secondary Water Chemistry Program

This program provides controls for monitoring secondary water chemistry to inhibit steam generator tube degradation and low pressure turbine disc stress corrosion cracking. The program shall include

a. Identification of a sampling schedule for the critical variables and control points for these variables;

b. Identification of the procedures used to measure the values '

of the critical variables; i

i (continued)

Crystal River Unit 3 5.0-17 Amendment No.

I

Reporting Requirements i 5.7 i

5.7 Reporting Requirements 5.7.2 Special Reports (continued) 4' The following Special Reports shall be submitted

a. When a Special Report is required by Condition B or F of LC0 3.3.17, " Post Accident Monitoring (PAM)

Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the .

inoperability, and the plans and schedule for restoring the J instrumentation channels of the Function'to OPERABLE status.

i

b. Any abnormal degradation of the containment structure !

detected during the tests required by the Containment Tendon l Surveillance Program shall be reported to the NRC within ;

30 days. The report shall include a description of the '

tendon condition, the condition of the concrete (especially at tendon anchorages), the inspection procedures, the tolerances on cracking, and the corrective action taken.

c. Following each inservice inspection of steam generator (OTSG) tubes, the number of tubes plugged and sleeved in each OTSG shall be reported to the NRC within 15 days. ;

The complete results of the OTSG tube inservice inspection shall be submitted to the NRC within 12 months following the completion of the inspection. The report shall include:

1. Number and extent of tubes inspected,

2. Location and percent of wall-thickness penetration for i each indication of an imperfection, and

3. Identification of tubes plugged and tubes sleeved.

Results of OTSG tube inspections that fall into Category C-3 t shall be reported to the NRC prior to resumption of plant operation. This report shall provide a description of investigations conducted to determine cause of the tube ,

degradation and corrective measures taken to prevent i recurrence.

(continued) j Crystal River Unit 3 5.0-29 Amendment No.

l

ML20137G829

Text

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