L-HU-06-023, Supplement to Application for Technical Specification Improvement Regarding Steam Generator Tube Integrity
| ML061380559 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 05/11/2006 |
| From: | Weinkam E Nuclear Management Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| L-HU-06-023 | |
| Download: ML061380559 (47) | |
Text
Committed to Nucle,erExceilence Nuclear Management Company, LLC L-HU-06-023 10 CFR 50.90 May 11,2006 U. S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001 Point Beach Nuclear Plant Units 1 and 2 Dockets 50-266 and 50-301 Renewed License Nos. DPR-24 and DPR-27 Supplement to Application For Technical Specification Improvement Reqardinq Steam Generator Tube lnteqrity Reference 1) License Amendment Request (LAR) titled, "Application For Technical Specification Improvement Regarding Steam Generator Tube Integrity",
dated February 16,2006 By letter dateld February 16,2006, Nuclear Management Company (NMC) submitted the referenceld LAR to adopt Technical Specification (TS) improvements regarding steam generator tube integrity provided in Technical Specification Task Force (TSTF)
Standard Technical Specification Change Traveler TSTF-449, "Steam Generator Tube Integrity", Revision 4. This letter supplements the referenced LAR to address April 27, 2006 telephone discussions with the Nuclear Regulatory Commission (NRC) Staff regarding Enclosures 4B and 5B which apply to the Point Beach Nuclear Plant, Units 1 and 2 (PBNP:). NMC is submitting this supplement in accordance with the provisions of 10 CFR 50.90.
NMC proposes in this supplement to revise PBNP TS 5.5.8 paragraph b.2 on pages 5.5-7 and 5.5-8 to include the clause, "total leakage rate for all SGs", which is consistent with the PBNP accident analyses and the guidance of TSTF-449. Enclosure 1, which includes the marked up changes to pages 5.5-7 and 5.5-8, replaces Enclosure 4B of the Reference LA,R in its entirety. Enclosure 2, which includes the revised changes to pages 5.5-7 and 5.5-8, replaces Enclosure 5B of the Reference LAR in its entirety.
The additional information provided in this supplement does not impact the conclusions of the Determination of No Significant Hazards Consideration and Environmental Assessment presented in the Reference February 16, 2006 submittal.
In accordance with 10 CFR 50.91, NMC is providing a copy of this letter and enclosures to the designated State Official.
700 First Street Hudson, Wisconsin 54016 Telephone: 715-377-3300
Document Cor~trolDesk Page 2 Summary of Commitments This letter contains no new commitments and no revisions to existing commitments.
I declare under penalty of perjury that the foregoing is true and correct.
Executed on
-E6ard J. k g dkam Director, Nuclear Licensing and Regulatory Services Nuclear Management Company, LLC Enclosures (2) cc: Administrator, Region Ill, USNRC Project: Manager, Point Beach Nuclear Plant, USNRC Senior Resident Inspector, Point Beach Nuclear Plant, USNRC State Official, Ms. Ave M. Bie - Public Service Commission of WI
ENCLOSURE I Proposed Technical Specification and Bases Pages (markup)
Point Beach Nuclear Plant Units 1 and 2 Technical Specification Pages Bases pages 32 pages follow
Definitions 1.1 1.1 Definitions The maximum allowable primary containment leakage rate, La, shall be 0.4% of primary containment air weight per day at the peak design containment pressure (P,).
LEAKAGE LEAKAGE shall be:
- a. Identified LEAKAGE
- 1. LEAKAGE, such as that from pump seals or valve packing (except reactor coolant pump (RCP) seal water injection or leakoff),
that is captured and conducted to collection systems or a sump or collecting tank;
- 2. LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or
- 3. Reactor Coolant System (RCS) LEAKAGE through a steam generator -to the Secondary System (~rimarvto secondary LEAKAGQ;
- b. Unidentified LEAKAGE All LEAKAGE (except RCP seal water injection or leakoff) that is not identified LEAKAGE;
- c. Pressure Boundarv LEAKAGE LEAKAGE (except grimarv to secondarv S-6 LEAKAGE) through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.
MASTER REL4Y TEST A MASTER RELAY TEST shall consist of energizing all master relays in the channel required for OPERABILITY and verifying the OPERABILITY of each required master relay. The MASTER RELAY TEST shall include a continuity check of each associated required slave relay.
The MASTER RELAY TEST may be performed by means of any series of sequential, overlapping, or total channel steps.
Point Beach 1.1-3 Unit 1 -Amendment No. 204-Unit 2 - Amendment No. 2-06
RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE L C 0 3.4.13 RCS operational LEAKAGE shall be limited to:
- a. No pressure boundary LEAKAGE;
- b. 1 gpm unidentified LEAKAGE;
- c. 10 gpm identified LEAKAGE;&
- d. U S343 gallons per day primary to secondary LEAKAGE through any one steam generator (SGl.
APPLICABILITY: MODES 1, 2, 3, and 4.
ACTIONS CONDITION REQUIRED ACTION COMPLETIONTIME A. RCS g p e m A. 1 Reduce LEAKAGE to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> LEAKAGE not within within limits.
limits for reasons other than pressure boundary LEAKAGE or primarv to secondarvXAKAGE.
B. Required Action and B. 1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A not AND met.
B.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> Pressure boundary LEAKAGE exists.
OR Primarv to secondary LEAKAGF not w ~ t h ~ n limlt.
Point Beach 3.4.13-1 Unit 1 - Amendment No. 204 Unit 2 - Amendment No. XJ.6
RCS Operational LEAKAGE 3.4.1 3 SURVEILLANCE REQUIREMENTS I
SURVEILLANCE FREQUENCY SR 3.4.13.1 ........................... NOTES.........................
L N o t required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation.
- 2. Not applicable to primarv to secondarv LEAKAGE.
Verify RCS Operational LFAKAGEeahge is 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> within limits by performance of RCS water inventory balance.
SR 3.4.13.2 ........................... NOTE---------------------------
Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of s t e d v state o p e r a t j o t a
V e r i f y y 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> primary t~ secondary LEAKAGE is < 150 aallons perday through any one.
Point Beach Unit 1 - Amendment No.
Unit 2 - Amendment No. 24X
SG Tube Integrity 3.4 REACTQR COOLANT SYSTEM (RCS) 3.4.17 Steam - Generator (SG) Tube Intearily
-L C- 0 3.4.17 - -. -... SG tube integritv shall be maintained.
AII SG tubes satisfvina the tube repair criteria shall be Q lugaed in accordance with the Steam Generator P r o a m APPLICABILITY:- MODES 1. 2. 3. and 4.
ACTIONS
................................................. NOTE--------------------------------------------------
S_eaamk.G~.n_diti.mentl?r is allowed for each SG tube, CONDITION REQUIRED ACTION 1 COMPLETION TIME A. One or more SG tubes A.l Verifv tube integrity of the 7 days satisf~ng&e.bhwdr a m t ubetslis cr~teriaand not p l u w maintained - until the next In accordance with the
- ~fbelinWa_aaSG Sae_2m=kn_eca_t~~ tub.e-in.specJ! on
-Program.
AND A.2 Plug the affected tubefs) in Prior to enterirg agordance with the Steam MODE 4 followina the G2L&G&.DBrn _n.exUefk-elingoutage or SG tube inspection B. Required Action and B.l Be in MODE 3.
-associated
- Completion TimeofCondition-Amt
.- -. -- BND SG tube intearitv not
-m-?- I ntained, -
I _ -
SURVEILLANCE REQUIREMENTS Point Beach -- 3.4.17-1 Unit 1 - Amendment No.
- .-- .- .. -...-- Unit 2 - Amendment Nol
SG Tube IntegCitS!
-- ------3.4.17 SURVEILLANCE 1 FREQUENCY SR 3.4.17.1 Verifv SG tube integrltv ~naccordance with the In accordance Steam Generator Program, with the Steam Generator Prosram SR 3.4.17.2 Verifv that each inspected SG tube that satisfies the Prior to enterinq i-e d in accordance with t h e MODE 4 following hmorproaram. iLscaJJhe inspection Point Beach 3.4.17-2 Unit 1 - Amendment No.
Unit--_AmendmentNo.
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) -Program A Steam Generator Proaram shall be established and implemented to ensure that SG tube integrity is maintained. In add~tjon.the Steam Generator Program shall include the followinq provcjions:
- a. Provis~onsfor condition monitorina assessments. Condition monitoring j f j with respect to the performance criteria for structural integrity and accident induced lskage, The "as found" c o n d h n refers to the condition of the SG i n a c t i o n 011tage;sdetermined from thanservice inspection results or by other means. prior to the oluggmg of tubes.
h d i ~ . n h m m l o ~ na
~ e a .c h s~u ~ ~~ ~ ~ r during which the SG tubes are ins~ectedor p l ~ ~ d J o c o n % 6 m t h athe t
- b. Perf~rmancecriteria for SG tube intearitv. SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, aa&dent inducedkak_age,and operati~n~a! LEAKAGE.
- 1. Structural intearitv performance criterion: All in-service steam generator tubes shall retain structuraI intearitv over the full ranae of normal operatina conditions (including startup, operation in the power mqe, hot standbv. and cool down and all anticipatedtransients included in the. .
desian specification) and design basis accidents. This W-
- A e s reta~nlnqa s a f f wt!xxifLm~slthmnormal stea~dystate full power operaton primary-to-secondary pressure M-erential and a safetv factor of 1.4 against burst applied to the design basis accident primary-to-secondary ..
pressure differentials.
@art from th.e above reqwements: add~tion ~71lo~d.mcolrd it iQns associated with ---the design basis accidents, or combinatiouf a a d e n t s in accordance wit' h th . I lsa be evaluated to determine if the associated loads contribute siqnificantlv to burst QrS-se I . In t he a s s e s s m m b f ~ ~
-those-ds
..- .- that do sianificantly affect burst c~r - c O J l --a .-D s ~ ~ ~
deterrnined and assess~incombinationwrththe l msure with a safety factor of 1.2 on the combined primary loads and 19 (onaxial secand&a&
- 2. Accident M u c e d Ieakaae ~erformancecriterion: The primarv to s e c o n d a n / a ~ e rate for any design basis accident. other than a SG tube ruWre. shall not exceed them^
rate assumed in the accident analysis in terms of t o t d h e a k a g e ~ i eQL f Point Beach 5.5-7 Unit 1 - Amendment No. 334 Unit 2 - Amendment No. 246
Programs and Manuals 5.5 5.5 Programs and Manuals all SGs and leakaae rate for an individual SG. I eakaqe is not t~
exceed 5QO gallons Der dav per SG.
- 3. The operational LEAKAGF performance criterion is specified in L C 0 3.4.13. "RCS Operational LEAKAGE2
- c. Provisions for SG tube repair criteria. Tubes found by inservice insnection 10 contain
- - flaws with a depth eauaI to or exceedina - 40% of the nominal tube wall thickness shall be pIuaaedL
- d. Provisions for SG tube inspections. Periodic SG tube i n s p ~ c t i o n s A & b e prformed. The number and portions of the tubes inspected and methods of inspection shall be performed with the obiective of detectinq flaws of any
&pe !e.a.. volumetr.~cflaws. axial and circumferential cracks) that mav be present dona the Ienah of the tube! from the tubeto-tubesheet weld at the lube inlet ts-- the t u b-to-tubesheet weld at the tube outlet, and that may satisfy
- the applicable tube repair criteria. Thctube-to-tubesheet weld is not part af the tube. in addition t~ meeting the reauire~nents~f d. 1: d 7, and below. the inspection scope. i ~ s ~ e c t i omethods n and inspection n ika&
s b a l l b P C I I S h a S m r e that $G tube i n t e g r- ~-
bmaintained
-- untilthcn&
SG-assessment
- of dearadation shall be werformedJo delermine the tvpe an&@un.offlaws to w h i c k t m b e s may be us-ce~tible and, based on thi~~ssessrnent: to determine which inspection methods n e ~ _ t n _ k ~ ~ I oavned d what I o c a.-~ n s .
I. Inspect 100°h of the tubes in each SG during the first refueling outage followina SG re~lacernent,
- 2. I Unit 1 (alloy 6
'. ' 0QT ed a
rt 100% of the O a r . 60 effextive full DQwer m o n t h Im . r !
hesin after the first inservice inspection of the SGs. In additim lr~soect50% of the tubes by tbe refuelina outaae nearest the midpoint of the -w erioci and the remaining 50% bv the refuelins L\~hiche g- . ins~ected A Ji.
- Unit 2 (allov 690 Thermally-Treated tubes): Inspect 100% of the tubes a t b r w -
effective full power months. The first sequential p e ~ b ~
considered to begin afi.e_r.thefirst inservice ins~ectionof the S a
-kin. inspect5~%ofth&~b~e~s_h.y_the&elina o u t a s nearest Point Beach 5.5-8 Unit 1 - Amendment No. 20%
Unit 2 - Amendment No.
Programs and Manuals 5.5 5.5 Programs and Manuals outwe-
- end-- of the period. No S G s b b - e r a t e for m a g than 72 effective full power months or three refueling outages f&!xcch_~~ie-i~ out being ins-&
-- 3. If crack indications are found in anv SG tube: t hen the next inspection for-
- each SG for the degradat~onmechanism that caused the c r z k indication s h d ~ ~ ~ 24L effective~ x ~ fulld power months or Q .
refuelina outaae (whichever is less). If definitive information. such as fro_m examination of a pulled tube. d iaanostic -- non-dzstructive testga or engineering evalu-ation indicates that a c r a c k - I indicationis-not
-ass.oc%&d
-. with a ~r~_~k&thentheindicationneednotbetreatedas.a
.crack
- e. Provisions for monitorina operational primary to secondary LEAKAGE.
Point Beach 5.5-9 Unit 1 - Amendment No. X M -
Unit 2 - Amendment No. 2%
Programs and Manuals 5.5 5.5 Programs and Manuals Point Beach 5.5-1 0 Unit 1 - Amendment No. 2Q4 Unit 2 - Amendment No. 2433
Programs and Manuals 5.5 5.5 Programs and Manuals Point Beach 5.5-1 1 Unit 1 - Amendment No. 281 Unit 2 - Amendment No. 2-06
Programs and Manuals 5.5 5.5 Programs and Manuals Point Beach 5.5-12 Unit 1 - Amendment No. ZW-Unit 2 - Amendment No. 206
Programs and Manuals 5.5 5.5 Programis and Manuals Point Beach 5.5-1 3 Unit 1 - Amendment No. 2Q Unit 2 - Amendment No. 246
7- ,
c a l m = r a1 m SlenUefl pUe s ~ e J 6 0 J d9 ' s S'E; slenuew pue S U J ~ J ~ O J ~
Reporting Requirements 5.6 5.6 Reportin~gRequirements 5.6.7 Tendon Surveillance Report (continued)
Nuclear Regulatory Commission pursuant to the requirements of 10 CFR 50.4 within thirty days of that determination. Other conditions that indicate possible effects on the integrity of two or more tendons shall be reportable in the same manner. Such reports shall include a description of the tendon condition, the condition of the concrete (especially at tendon anchorages), the inspection procedure and the corrective action taken.
5.6.8 Steam Generator Tube Inspection Report A~epoq shall be submittebithin 180 f - DE4 following corn~letionof an inspection performed in accordance with the Sgecification 5.5.8. $teaamGeneenerator fSG) Prograamrl?The_ceport shall
- indae:
a.--Thescone nf inspections performed on each S_G, examinabn techniques ut1k e d h 1 - ~ ~ d 2 3 ~ . ~
~~.;,,,._._=~.onCle_structive mechan-
- d. LocaJion: orientation (if linear). and measured sjzesdf available) of service
-e.-- -- -Num&~~oft~$_esgI~ge,&durin~einsp&n~~B~Aorhad&e degradation mechanism,
- f. Total number and ~ercentageof tubes pluaed to date
- g. The results of condition monitoring. including the results of tube pulls and in-siluiestina! and
-h. , --- T h e f k ~ pjuaaina percentage for all pluggi_ngjn-~sLh3G Point Beach 5.6-6 Unit 1 - Amendment No. 20-7 Unit 2 - Amendment No. 242
Reporting Requirements 5.6 5.6 Reporting Requirements Point Beach Unit 1 - Amendment No. 237 Unit 2 - Amendment No. 2-42
RCS Loops - MODES 1 and 2 B 3.4.4 BASES APPLICABLE the plant safety analyses are based on initial conditions at high core SAFETY ANALYSES power or zero power. The accident analyses that are most important to (continued) RCP operation are the two pump coastdown, single pump locked rotor, single pump (broken shaft or coastdown), and rod withdrawal events (Ref. 1).
Steady state DNB analysis has been performed for the two RCS loop operation. For two RCS loop operation, the steady state DNB analysis, which generates the pressure and temperature Safety Limit (SL) (i.e.,
the departure from nucleate boiling ratio (DNBR) limit) assumes a maximum power level of 120% RTP. This is the design overpower condition for two RCS loop operation. The value for the accident analysis setpoint of the nuclear overpower (high flux) trip is 118% and is based on an analysis assumption that bounds possible instrumentation errors. The DNBR limit defines a locus of pressure and temperature points that result in a minimum DNBR greater than or equal to the critical heat flux correlation limit.
The plant is designed to operate with all RCS loops in operation to maintain DNBR above the SL, during all normal operations and anticipated transients. By ensuring heat transfer in the nucleate boiling region, adequate heat transfer is provided between the fuel cladding and the reactor coolant.
RCS Loops- MODES 1 and 2 satisfL Criterion 2 of the NRC Policy Statement.
The purpose of this LC0 is to require an adequate forced flow rate for core heat removal. Flow is represented by the number of RCPs in operation for removal of heat by the SGs. To meet safety analysis acceptance criieria for DNB, two pumps are required at rated power.
In MODES 1 and 2, an OPERABLE RCS loop consists of an OPERABLE RCP in operation providing forced flow for heat transport and an OPERABLE S G S APPLICABILITY In MODES 1 and 2, the reactor is critical and thus has the potential to produce maximum THERMAL POWER. Thus, to ensure that the assumptions of the accident analyses remain valid, all RCS loops are required to be OPERABLE and in operation in these MODES to prevent DNB and core damage.
Point Beach B 3.4.4-2 Unit 1 -Amendment No. ZH Unit 2 -Amendment No.
RCS Loops - MODE 3 B 3.4.5 BASES LC0 (continued) b. Core outlet temperature is maintained at least i0°F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction; and
- c. The Rod Control System is not capable of rod withdrawal, to preclude the possibility of an inadvertent control rod withdrawal and associated power excursion.
An OPERABLE RCS loop consists of one OPERABLE RCP and one OPERABLE S G S
,- which has the minimum water level specified in SR 3.4.5.2. The OPERABLE RCP and SG must be in the same loop for the RCS loop to be considered OPERABLE. An RCP is OPERABLE if it is capable of being powered and is able to provide forced flow if required.
APPLICABILITY In MODE 3, this LC0 ensures forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing. One RCS loop provides sufficient circulation for these purposes. However, one additional RCS loop is required to be OPERABLE to ensure redundant capability for decay heat removal.
Operation in other MODES is covered by:
LC0 3.4.4, "RCS Loops - MODES 1 and 2";
LC0 3.4.6, "RCS Loops - MODE 4";
LC0 3.4.7, "RCS Loops - MODE 5, Loops Filled";
LC0 3.4.8, "RCS Loops - MODE 5, Loops Not Filled";
LC0 3.9.4, "Residual Heat Removal (RHR) and Coolant Circulation -
High Water Level" (MODE 6); and LC0 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation -
Low Water Level" (MODE 6).
ACTIONS If one required RCS loop is inoperable, redundancy for heat removal is lost. The Required Action is restoration of the required RCS loop to OPERABLE status within the Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This time allowance is a justified period to be without the redundant, nonoperating loop because a single loop in operation has a heat transfer capability greater than that needed to remove the decay heat produced in the reactor core and because of the low probability of a failure in the remaining loop occurring during this period.
Point Beach Unit 1 -Amendment No. %
Unit 2 -Amendment No. 2%
RCS Loops - MODE 4 B 3.4.6 BASES LC0 (continued) that are designed to validate various accident analyses values. An example of one of the tests is validation of the pump coastdown curve used as input to a number of accident analyses including a loss of flow accident. This test is generally performed during the initial startup testing program, and as such should only be performed once. If changes are made to the RCS that would cause a change to the flow characteristics of the RCS,the input values must be revalidated by conducting the test again. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> time period is adequate to perform the test, and operating experience has shown that boron stratification is not a problem during this short period with no forced flow.
Utilization of Note 1 is permitted provided the following conditions are met along with any other conditions imposed by initial startup test procedures:
- a. No operations are permitted that would dilute the RCS boron concentration, therefore maintaining the margin to criticality. Boron reduction is prohibited because a uniform concentration distribution throughout the RCS cannot be ensured when in natural circulation; and
- b. Core outlet temperature is maintained at least 10°F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.
Note 2 requires that the secondary side water temperature of each SG be I50°F above each of the RCS cold leg temperatures before the start of an RCP with any RCS cold leg temperature I the Low Temperature Overpressure Protection (LTOP) enabling temperature specified in the PTLR. This restraint is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.
SG secondary side water temperature can be approximated by using the SG metal temperature indicator.
An OPERABLE RCS loop comprises an OPERABLE RCP and an OPERABLE S G S
,- which has the minimum water level specified in SR 3.4.6.2. The OPERABLE RCP and SG must be in the same loop for the RCS loop to be considered OPERABLE.
Similarly for the RHR System, an OPERABLE RHR loop comprises an OPERABLE RHR pump capable of providing forced flow to an OPERABLE RHR heat exchanger. RCPs and RHR pumps are OPERABLE if they are capable of being powered and are able to provide forced flow if required.
Point Beach B 3.4.6-2 Unit 1 -Amendment No. ;281.
Unit 2 -Amendment No. XM3
RCS Loops - MODE 5, Loops Filled B 3.4.7 BASES LC0 (continued) Note 2 allows one RHR loop to be inoperable for a period of up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, provided that the other RHR loop is OPERABLE and in operation. This permits periodic surveillance tests to be performed on the inoperable loop during the only time when such testing is safe and possible.
Note 3 requires that the secondary side water temperature of each SG be I50°F above each of the RCS cold leg temperatures before the start of a reactor coolant pump (RCP) with an RCS cold leg temperature s Low Temperature Overpressure Protection (LTOP) arming temperature specified in the PTLR. This restriction is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.
Note 4 provides for an orderly transition from MODE 5 to MODE 4 during a planned heatup by permitting removal of RHR loops from operation when at least one RCS loop is in operation. This Note provides for the transition to MODE 4 where an RCS loop is permitted to be in operation and replaces the RCS circulation function provided by the RHR loops. Note 4 also allows both RHR loops to be removed from operation when at least one RCS loop is in operation to allow for the performance of leakage or flow testing, as required by Technical Specifications or by regulation. This allowance is necessary based on the design of the Point Beach RHR System configuration, which requires the system to be removed from service to perform the required PIV testing.
RHR pumps are OPERABLE if they are capable of being powered and are able to provide flow if required. An X W V S & S G can perform as a heat sink via natural circulation (Ref. 1) when it has an adequate water level and is O P E R A B L E P APPLICABILITY In MODE 5 with RCS loops filled, this LC0 requires forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing. One loop of RHR provides sufficient circulation for these purposes.
However, one additional RHR loop is required to be OPERABLE, or the secondary side water level of at least one SGs is required to be 2 30%
narrow range.
Point Beach B 3.4.7-3 Unit 1 -Amendment No. XI4 Unit 2 -Amendment No.
RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE Except for primary to secondary LEAKAGE, the safety analyses do not SAFETY ANALYSES address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for LOCA; 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 that primary to secondarv LFAKAGE from each steam aeneratw (SG)is 5OQ cuxhf increases to 500 gpd as a result of accident induced conditions. The L C 0 requirement to limit primary to secondary LEAKAGE thro-uah anv QneSG to less than or eaualo 150 gallons Der dav IS slgnificaMv less than the conditions assumed in the safety ana= l-Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a steam line break (SLB) accident. To a lesser extent, other accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid.
The FSAR (Ref. 2) analysis for SGTR assumes the contaminated secondary fluid is only briefly released via safety valves. The 500 gpd primary to secondary LEAKAGE Safetv analvsis assurn~tionis relatively inconsequential.
The SLB is more limiting for site radiation releases. The safety analysis for the SLB accident assumes 500 gpd primary to secondary LEAKAGE is through the affectedhew generator as an initial condition. The dose consequences resulting from the SLB accident are well within the limits defined in 10 CFR 100 or the staff approved licensing basis (i.e., a small fraction of these limits).
The RCS operational LEAKAGE satisfies Criterion 2 of the NRC Policy Statement.
RCS operational LEAKAGE shall be limited to:
- a. Pressure Boundarv 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 RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.
Point Beach B 3.4.13-2 Unit 1 -Amendment No. 281 Unit 2 - Amendment No. ZX
RCS Operational LEAKAGE B 3.4.13 BASES L C 0 (continued) b. Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment 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.
- c. ldentified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability of the RCS Makeup System. ldentified 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. Primarv to Secondarv LEAKAGE through Any One SG The limit of 150 aallons per dav per SG is based on the o~erational LEAKAGE performance criterion in NEI 97-06, Steam Genertpr Program Guidelines !
merational LEAKAGE performance criterion in NEI 97-06 states, "The RCS ~ p e osecondary
-- leakage through any
~
ane SG shall be Iirnited to 150 aallons per dav." _The l~rn~t IS based
~n operating exnerience with^^ tube deg'radat~onmechanisms that Gcult in tub.e~e~kage~h4op-er_aiana!~e-a-kage rat u d i t e c b a .
coaiunction with the imp1ement;ation of_theSteam Generatar Program is an effective measuref~minimizinahe - -
steam
-- tube r u ~ t u r e ~
APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.
In MODES 5 and 6, LEAKAGE limits are not required because the Point Beach B 3.4.13-3 Unit 1 -Amendment No. 3%
Unit 2 - Amendment No. 2%
RCS Operational LEAKAGE B 3.4.13 reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.
LC0 3.4.14, "RCS Pressure Isolation Valve (PIV) Leakage," measures leakage through each individual PIV and can impact this LCO. Of the two PlVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leak tight. If both valves leak and result in a loss of mass from the RCS, the loss must be included in the allowable identified LEAKAGE.
ACTIONS Unidentified LEAKAGE, =identified LEAKAGE-in excess of the L C 0 limits must be reduced to within limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCPB.
Point Beach B 3.4.13-4 Unit 1 -Amendment No. XM-Unit 2 -Amendment No. 333
RCS Operational LEAKAGE B 3.4.13 BASES ACTIONS (continued) B.1 and B.2 If any pressure boundary LEAKAGE exists, or primary to secondarv LEAKAGF is not within limit, or if unidentified QJ&A&W& identified LEAKAGE7 T a n n o t be reduced to within limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. The reactor must be brought to MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.
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.
In MODE 5, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.
SURVEILLANICE SR 3.4.13.1 REQUIREMENTS Verifying RCS LEAKAGE to be within the LC0 limits ensures the integrity of the RCPB is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.
Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.
The RCS water inventory balance must be met with the reactor at steady state operating conditions (i.e., stable temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows). The Surveillance is modified bv t w ~
Notes.Rwefm++N+wte 1 states- that this SR is not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishing steady state operation.
The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance provides sufficient time to collect and process all necessary data after stable plant conditions are established.
Point Beach B 3.4.73-5 Unit 1 -Amendment No. 204 Unit 2 -Amendment No. 2%
RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANICE Steady state operation is required to perform a proper inventory REQUIREMENTS balance since calculations during maneuvering are not useful. For RCS (continued) operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.
An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level.
It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. These leakage detection systems are specified in LC0 3.4.1 5, "RCS Leakage Detection Instrumentation."
Note 2 states that this SR is not appl i v LEAKAGE because LEAKAGE of 150 aallons per dav c a n n a measured accuratelv by an RCS water inventor~balance, The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.
This SR verifies that primary to secondary LEAKAGE is less or equal to 150 gallons per dav throuqh any one SG. Satisfyina the primam to secondary LEAKAGELmit ensures that the ~nerationalLEAKAGE gerfarmance criterion in the Steam Generator Program is met. If this S R m i met, c o m p l i a ~ ~with e LC0 3.4.17: "Steam-agerator Tube Integritv." shouldbe evaluated. The 150 gallons ser day limit is measured at room temperature . .
as described in Reference 4. The
~perationalLFAKAGF rate llmrt a ppI'ies to LEAKAGE through any one SG. If it isnot practical to assian the LEAKAGE to an individual SG. all the primary to seconday L E A ~ G ~ ~be. conservatively
- ~ ~ U I ~ assumed to be from one SG.
e da Note m.&&s
~ u r v e i I l a w e i ~ Q d j f i bv that the Surveillance is not required to be ~erformeduntil 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> after establishment of steady state operation. For RCS ~rimaryto seconcl;acy, LEAKAGE
--- .- -- determination,
- steady state is defined as stable RCS ressure. temnerature. owe r l v I D . ressazer and m a k e u ~ tank
-~s:~ovvn. 2d;CP seal inieect$n and return flows.
The Surveillance Frequency of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is a reasonable interval to trend ~rimarvto secondary LEAKAGE and recognizes t h e m a m
~f-eaakl~kage detectton in the prevention of acc'dents. The wrlrnary to Point Beach B 3.4.13-6 Unit 1 -Amendment No. 334 Unit 2 -Amendment No. 296
RCS Operational LEAKAGE B 3.4.13 monitors or radiochemical arab sarn~llnaIn accordance with the EPRl guidelines (Ref. 4).
REFERENCES 1. FSAR Section 1.3.3.
- 2. FSAR, Section 14.
- 3. NFI 97-06. "Steam Generator Program Guidelines."
- 4. EPRI, "Pressyrized Water Reactor P r i m a- r-v m d a r y Leak u~del~nes."
Point Beach Unit I-Amendment No. 2Q4 Unit 2 -Amendment No. 336
SG Tube integrity BASES BACKGROUND
- Steam aenerator (SG) tubes are small diameter. thin walled tubes that carrv primary coolant through the primary to secondarv heat exchanaers.
w r of importanl safetv functi~ns.Steam generator tubes are an integral wart of the reactor coolant pressure boundary
- . !RCPB)andd as such! are relied on lo maintain the primary t@s.is_olate-S he radoactive fission wroducts in the primary coolant from the secondary svstem. In g_d4!ddon.as part of the RCPB, the SGlubes are unique inthat thev act as theheat transfer surface between the grimaty and secondarv svstems ta r we h from . rim - - s m. S. ~ c i f i i n d r e s s e s only the RCPB integrity function of the SG. The SG he-at removal function is-addressed by L C 0 3.4.2!"RCS I oops - MODFS-1. and 2." LC0 3.4.5.
"RCS
- - l oop - -M 3.4. "RC s - MODE 4." and L C 0 3.4.7.
- --. . -.-- S a p SG tube integrity means that the tubes are capable of ~erforminatheir intended RCPB safetv function consistent with the licensing basis.
including applicable reaulato Steam
- aenerator tubina is subject. to a variety of dearadation mechanisms.~teamtubes ~r mav e x ~ e ~ i e n tube c e dearadation reLaled to corrosion - Dheno m s u D l t t l n a , i n m r atbx&and s t r - s ~ ~ r r i co rna c n 1 with other m- .-
induced whenomena such as denting and wear. These desradation mechanisms c a n m x i i r t u b e e g r i t y if thev are not manaqed effectiv*
- S'G perf~rmance The -- criteria are used to manaae SG tube degradation, Specification 5.5.8. "Steam Generator (SG) Program." requires that a program be-lished and im~lementedto ensure that SG . .
tube intearity 1s maintained. Pursuant to S~ecification5.5.8, tube integ I maintained when the SG performance criteria are met. T E a r e three SG r, rformance criteria; struwb-ral ink@ . acci ent induce I aka and.&erational LEAKAGE. The SG p e r f i k - h & k G E d in
&ecification 5.5.8. Meeting theSG . .
~erformance-~te~ia_12~~v~
ceas~nahk-a~~wrameofm*b~n~ng tube integrity at normalmd accidentconditions.
The processes used to meet the SG performance criteria are defined by the Steam Generator Proaram Guidelines (Ref. 1).
Point Beach B 3.4.17-1 Unit 1 - Amendment
-- No.
- -- Unit 2 -Amendment No,
SG Tube Integrity B 3.4.17 BASES APPLICABLE The steam generator tube rupture (SGTR) accident is the limitina des-lag SAFETY basis event for and avoidina an SGTR is the basis for this
~%!~.SES Specification. % HU,b,si~of a SGTR e z u m e s a bgundinq primary to secondary LEAKAGGE-mte eaual t o h e opecatiml LEAKAGE mte limits in L C 0 3.4.13. "RCS O~erationalLEAKAGE." ?[us .. -.
the l e a k a s r ~-_--t-- --e-~- a s _ s ~ d ~ w ~ -~ ~ ~ n d e - .. -. d-r ~ - ~ p l -t-
.- .. .. .. ~~si_n~srtuhe accidenl-analysis
- - for a SGTR assumes the contarnjnated secondary fluid
~.easedJgtheea~p-hereevi.aas.a_fety v a .
Theanalvsis for desian basis accidents and transients other than a SGTR
-a----s _su&theSGtubes-kin_kritv _(i.e,-wm assumed not to rupture.) In these analvses, the steam discharge to the atmosphere is based on primary to secondary LEAKAGE from each SG.
O ~ Q ~ ~ per ! Qdav ~ orS is a s w d to increase to 500 gallons per day as a result of accident induced conditions. For accidents that do not involve fuel d a w . the primarv coolant activity level of DOSE EQUVAL
- --- E--NT 1-13 1 is asswd_teheeewWeLI;03416. "RCS S~ecificActivity." limits. Fgr accidents that assume fueld-amage, the prBary coolant activity is a function of the amount ofactivitv .--- released f d h ~ d a m a g e fuel. d T h ~ ~ ~ e ~ . c ~ o n s e a ~ e n c xthessed_e& _veorltfs_are within thelimits of GDC 19 (Ref. 2}. lO~CF.R~IOO.~Ref..3~ or the NRC approved licen_sing basis (e.a.. a small fraction of these limits).
Steam generatortube
--- integritv satisfies Criterion 2 of 10 & C 5 0 . 3 6 ( c ~ ~
~ T h ~ L C C r e a u i r that e SGs t u k integrity be maintained. T h e L C O A .
re@res
- that all SG tubes that sasiytf-aed -- in accordance with the Steam Generator Program.
Ou-rina_anSl;ins~e.!dk&a.an~ i n . g ~ ~ ~ t e d ~ !s .the ~ Stt earn
' ~-f ~ e Generabr Proararn rewair c t i t m is removed from service m a . If z u b e was determined
- -- to satisfy-the
> .- reaair. .criteria
~.... but was not p l u m Lkeet~ybemautillhae
- - -- tube i n t e g a I n the context of this Specification: an SG tube is defined as the entire kng.t!uklhe tube: including the tube wall. between the tube-to-Uesk@
weld_a_tthe tube inlet and thetube-to-tubesheet weld at the tube o u M I&- tube-to-tubesheetweldisnotconskJ~ed
-- part of the tuhe, A SG tube has tube intearity when it satisfies the SG performance criteria.
The SG performance criteria are defined in Specification 5.5.8, "Steam Generator Program." and describe acce~tableSG tube pxformance, Point Beach B 3.4.17-2 Unit 1 -Amendment No.
Unit 2 -Amendment Ng
SG Tube Integrity B 3.4JT BASES LC0
- (continuled) The Steam Generator Program also provides the evaluation orocess for deherrnining conformance with the SG performance criteria. There are three SG performance criteria: structural intearitv,cc~denttnduced a
!c&kage: and operational LEAKAGE. Failure to meettany one of these criteria is c o n s i d e ~ dfailure to meet the LCO.
The structural integritv performancecriterion provides a margin of safety against tube burst or colla~seunder normal and accident conditions. and ensures
-- structural
.. inteuritv of the SG tubes under all antici~ated transients included in the design specjgc&ion. Tube burst is defined - asC corres~ondsto an unstable 0 0 increased in response to constant ~ressure)accompanied-by ductile
@lastlc) tearing of the tube material at the_en& of the dea -radat~on.
. ,, Tube collapse
-- isdklined as. "For the load displacement curve for a given structure, c~I@pse Qccurs at the t ~ of p the load versus displacement curve where - the
---slope of the curve becomes zero." The structural intearity performance criterion provides guidance on ass,essing lo;ild.%that have a significant effect on burst or collapse.- taht -1 as "An accident loadina condition o t h e r m differential pressure is consideredhcus-s
!gads in the assessment of the structural -
integrity performance criterion
! , x U ! d ~ m a lower structural limit or limiting b u r s t / c ~ l l a ~ condition se to be established." For tube integrity evaluat@ns: except for circumferential
. I ther mal loads are classified.~s..sec~d-ary d i ~ a d a t i o n axla lpilds. For circumfetytial dessdation. the classifica$on of axial thermal loads as s-primary or secondarv loads will be evaluated on a case-bv-case basis.
The division-between primary and secondarv classifications .-.
will be based on detailed analysis andlor testing Structural integritv requires that the primary membrane stress intensitv in a tube not exceed the yield strength for all ASMF Code. Section Ill,
_Sxa!.ke_L~vel
- A (ne_um_al o ~ ~ a t i conditions) ng andservice Level B l u ~ s 3 er abnormal -- conditions) transients included in the design specification, This includes safety fa-rs and applicable deslgn basis loads based on AS-~~II~RNB~. 41 and Draft R e a u l w Guide
-- 1.I 21 (Ref, 5)&
Ihe_aa&ent induced leakage performance crlterlon ensures that the p~lmar!, to secondary LEAKAGE caused b a destan bass accfdent, other than a SGTR.
-. ..... is within
-- the~ccident
- anahsis
awmptions. The accident analvsis assumes thatentntnduced leakage does not e~es:m gallons per day per $ . h I r i I n
&maw to s e c o n d a r v - @ d w -
- ~ -
Point Beach I3 3.4.17 Unit I-Amendment No..
Unit 2 - A m e n d m n l N a
SG Tube Integrity B 3.4.17 BASES LC0 (continued) primarv to secondarv LEAKAGF induced durina the accident. The operational LEAKAGE performance criterion ~rovidesan observable indication of SG tube conditions during plant oeeration. The limit on o~erationalLEAKAGEisontained in L C 0 3.4.1 3. "RCS Operational EAKAGE." and
- -- limits primary to secondarv LEAKAGE through anv one S G p - e a e r d a y . This limit is based on the assurn~tionthat a single crack leaking this amount would not propagate to a SGTR under th!,Z&t1essg n if i..!?nsof a LO g -
amount of LEAKAGE is due to more t b n one crack, the cracks are very small.
-- - andthe above assumption is c~nsewativ1e.
APPLICABILIl'Y Steam aenerator tube intearltv IS challenaed when the ~ressure differential across the tubes is large. Large differential pressures across SG tubes can onlv be exgerienced in MODF 1. 7 3: or 4.
- - condi -t io ns are f ar less challenaina in MODES 5 and 6 than durinq MODES 1: 2! 3.-and 4. In MODES 5 and 6. ~rirnaryto secondary differential pressure is low, r m- l t i n a ~nlower stresses a~ l . d & d !
p~tential for LEAKAGE.
ACTI0NS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube. This is acceptable because B e Reauired Actions provide a p e r o g r k t ~ c o ~ e n s a tactions ~ t y for each affected SG tube. Complyina with the Required Actions mav g ! l _ ~ a continued oweration. and subseauent affected SG tubes a ~ governed
- e by subsequent Condition -. entrv and a sglication of&sociated Required Actions.
A.l and A.2 Condition A a~wliesif it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube reoair criteria but were not plugged in accordance with the Steam Genergtor Proaram a?
required by SR 71.4.3 An evaluation of SG tube integritv of the affected tube(s1 must be ma r i rit is based
-on meeting the SG p e r f o r m a j m Generator Pragram. The SS repair criteria define limits on SG tube I -a--
- d. .
. aw growth between inspections while sti!!
e the SG performance--
p r o v l d l n ~ z s ~ r a n cthat criteria will continue to be mxt. In or rmine i h houfdhavebee_ n g s tube
- i,"g:",z% e v
-.- - a that the SG Berf~rmancecritqia will continue to be met until the next l t L C ~lin e IS ' ectionllhe tube integritv determination i ~ b M s t i m = i o n of the tube atthe time the sku-discxwered
-.- and the estimated growth of t h d e g r a d a u Point Beach B 3.4.17-4 Unit 1 -Amendment No, Ugt 2 -Amendment No.
SG Tube IntegriQ
- B3 . 4 x BASES ACTIONS (colntinued?prior to the next SG tube ins~ection.If it is determined that tube i n t e a is not beina maintained, Condition B aggIiesS A Comwletion Time of 7 davs is sufficient to complete the evaluation while minimizina the risk of alant operation with a SG tube that rnav not have lube integrity.
If the evaluation determines that the affected tube!s) have tube integrity.
Required Action A.2 allows plant operation to continue until the next refuelina outage or SG inswection provided the inspection interval
~ontinuesto he sup~ort r i n I sessment-thatreflects
-. -- the affected tubes. Howeve-Wmgged prior to zterina
- -- MODE 4 follnwina the next refuelingoutage or SG inspect=
This Corn~letionTime is acceptable since o p e r a m until the next inspection is su ~o r t e d ~ e o ~ s s e ~ s s m e n t .
-B.1 and 8.2 If the Required Actions and associated CornpleW Times of Cond~ t ~ A on are not met ar if SG tube intearitv is not beina rna~ntaned,the reactor must be brought to MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 5 within-36_hours, Theallowed Completion Times are reasonable, based on operating experience. to reach the desired plant conditions from full power concktis_n.sina~derly
- - mamer a ~ wrthout d challenaina plant s y s t e m SURVEILLANCE SR 3.4.17.1 REQUIREMEEJT~
During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06. Steam Generam Program Guidelines Ref. 1): and its referenced EPRl Guidelines, establish the content of the_Steam Generator Program. Use of theS_em Generator Program ensures that the inspection ~$_~oPo r priate and w i s t e n t with accepted industry practices, During SG imections a condition rnonitorina assessment of the SG tubes is performed. The condition monitoring assessment determines the 3s_foundv conditi~nof the SG tubes. The purposesf the c s n d i
_monitorinaasssrnent is to ensure that the SG ~erforrnancecriteria have been
- - met for the p~ -pre-viouso~eratingperiod.
Point Beach B 3.4.17-5 Unit 1 -Amendment No.
\ Jnit 3: - Amendment No.
SG Tube lnte~rity B 3.4.1 7 BASES SURVEILLANCE The Steam Generator P r o ~ r a mdetermines the scor>e of the inspection REQUIREMENTS and the methods used to determine whether the t u b e ~ m t a i flaws n (crantinued)- satisfving the tube reoair criteria. Inspection s c o w i e . ! which tubes or
- of tubina areas .. .. -.within the SG are to be inspected) is a function-and potential dearadation locations. The Steam Generator Program a h sgecifies the inspection methods to be used to find potential degradation, Inspection methods - - are a function of degradationrmorphology, non, destructive examination (NDE) technique capabilities, and inspection locations.
The Steam
-- Generator Program defines the Freauencv of SR 3.4.17.1.
The Freauencv is determined bv the o~eration aI assessment and other limits in the SG examination auidelines (Ref. 6). The Steam Generator Program uses information pn existing degradations and growth rates ta determine an inspection Frequency that provides reasonable assurance that the tubing will meet t h rformance criteria at the next scheduled inspection. - ~an= d t o . Snecification 5.5.8 contsins rescriptive.re~uirementsconcernina ins rvals to provtde
~. -d- d e d
-- _ a i u ~ s d ~ r m a n ~ w ~ M w m -
scheduled inspections. -.
During an SG inspection. anv inspected tube that satisfies thesteam
- n r a F a o r P -
The tube repair criteria delineated in Speclf~catton5.5.8 are intended to ensure that tubes acce~tedfor continued service satisfv theSG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addibn. the tube repair criteria, in conjunction with other elements of the Steam Generator Pr~ararn:
- -- ensure that the SG performance criteria will contvlue to be met until the next inspection of the subject tube(S). Reference 1 provides auidance for ~ e r f o ~ i operational na assessments_to verifv that the tube3 remaining
- - in service will continue to meet t he SG performance criteria_,
The Frequencv of prior to entering MODE 4 followina a SG inspection ensures that the Surveillance has been completed and all tubes meet~nq the repair criteria are plugged wrior to subjecting the SG t u b e s 3 significant
- primary tuec0ndat-y pressure d i f f e r e a Point Beach B 3.4.17-6 Unit 1 - A m e n d m e n t k Unit 2 -Amendment No
SG Tube Integrity B 3.4.17 BASES (continued)
REFERENCES 1. NEI 97-06. "Steam Generator Proaram Guidelines."
7 10 CFR 50 Appendix A?GDC lgL
- 3. 10 CFR 100.
-H g R e a u i a t o r v n"Basisearaded a Steam Generator Tube~,)I~August1976.
re W--
ta - Reactor Steam Generator Examination Guidelines."
Point
- B e a L B 3.4.17-7 Unit 1 -Amendment No, Unit 2 -Amendment No_
ENCLOSURE 2 Proposed Technical Specification Pages (revised)
Point Beach Nuclear Plant Units 1 and 2 Technical Specification Pages 11 pages follow
Definitions 1.1 1.1 Definitions The maximum allowable primary containment leakage rate, La,shall be 0.4% of primary containment air weight per day at the peak design containment pressure (P,).
LEAKAGE LEAKAGE shall be:
- a. Identified LEAKAGE
- 1. LEAKAGE, such as that from pump seals or valve packing (except reactor coolant pump (RCP) seal water injection or leakoff),
that is captured and conducted to collection systems or a sump or collecting tank;
- 2. LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or
- 3. Reactor Coolant System (RCS) LEAKAGE through a steam generator to the Secondary System (primary to secondary LEAKAGE);
- b. Unidentified LEAKAGE All LEAKAGE (except RCP seal water injection or leakoff) that is not identified LEAKAGE;
- c. Pressure Boundary LEAKAGE LEAKAGE (except primary to secondary LEAKAGE) through a nonisolable fault in an RCS I component body, pipe wall, or vessel wall.
MASTER REL4Y TEST A MASTER RELAY TEST shall consist of energizing all master relays in the channel required for OPERABILITY and verifying the OPERABILITY of each required master relay. The MASTER RELAY TEST shall include a continuity check of each associated required slave relay.
The MASTER RELAY TEST may be performed by means of any series of sequential, overlapping, or total channel steps.
Point Beach 1.1-3 Unit 1 - Amendment No.
Unit 2 - Amendment No.
RCS Operational LEAKAGE 3.4.1 3 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE L C 0 3.4.13 RCS operational LEAKAGE shall be limited to:
- a. No pressure boundary LEAKAGE;
- b. 1 gpm unidentified LEAKAGE;
- c. 10 gpm identified LEAKAGE; and
- d. 150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG).
APPLICABILIITY: MODES 1, 2, 3, and 4.
ACTIONS CONDITION REQUIRED ACTION COMPLETIONTIME A. RCS oplerational A. 1 Reduce LEAKAGE to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> LEAKAGE not within within limits.
limits for reasons other than pressure boundary LEAKAGE or primary to secondary LEAKAGE.
B. Required Action and B. 1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A not A N met.
B.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR Pressure boundary LEAKAGE exists.
OR Primary to secondary LEAKAGE not within limit.
Point Beach 3.4.1 3-1 Unit 1 - Amendment No.
Unit 2 - Amendment No.
RCS Operational LEAKAGE 3.4.13 SURVElLLAhlCE REQUIREMENTS SURVEILLANCE FREQUENCY S R 3.4.13.1 ---------------------------NOTES-------------------------
- 1. Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation.
- 2. Not applicable to primary to secondary LEAKAGE.
Verify RCS Operational LEAKAGE is within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> limits by performance of RCS water inventory balance.
SR3.4.13.2 ---........................ NOTE...........................
Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after establishment of steady state operation.
Verify primary to secondary LEAKAGE is 5 150 gallons per day through any one SG. 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Point Beach Unit 1 - Amendment No.
Unit 2 - Amendment No.
SG Tube lntegrity 3.4.17 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.17 Steam Generator (SG) Tube lntegrity L C 0 3.4.17 SG tube integrity shall be maintained.
&NJ All SG tubes satisfying the tube repair criteria shall be plugged in accordance with the Steam Generator Program.
APPLICABILITY: MODES 1, 2, 3, and 4.
ACTIONS
---I-------------------- NOTE-------------------------------------------
Separate Condition entry is allowed for each SG tube.
COhiDlTlON REQUIRED ACTION COMPLETION TIME A. One or more SG tubes A.l Verify tube integrity of the 7 days satisfying the tube repair affected tube(s) is criteria and not plugged maintained until the next in accordance with the refueling outage or SG Steam Generator tube inspection.
Program.
A.2 Plug the affected tube(s) in Prior to entering accordance with the Steam MODE 4 following the Generator Program. next refueling outage or SG tube inspection B. Required Action and B.l Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A not A m met.
B.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR SG tube integrity not maintained.
SURVEILLANCE REQUIREMENTS Point Beach 3.4.1 7-1 Unit 1 - Amendment No.
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SG Tube lntegrity 3.4.17 SURVEILLANCE FREQUENCY SR 3.4.17.1 Verify SG tube integrity in accordance with the In accordance Steam Generator Program. with the Steam Generator Program SR 3.4.17.2 Verify that each inspected SG tube that satisfies the Prior to entering tube repair criteria is plugged in accordance with the MODE 4 following Steam Generator Program. a SG tube inspection Point Beach Unit 1 - Amendment No.
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Programs and Manuals 5.5 5.5 Programs and Manuals Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following provisions:
- a. Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes.
Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.
- b. Performance criteria for SG tube integrity. SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.
Structural integrity performance criterion: All in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 against burst under normal steady state full power operation primary-to-secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary-to-secondary pressure differentials.
Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.
- 2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate Point Beach 5.5-7 Unit 1 - Amendment No.
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Programs and Manuals 5.5 5.5 Programs and Manuals Steam Generator (SG) Program (continued) for all SGs and leakage rate for an individual SG.
Leakage is not to exceed 500 gallons per day per SG.
- 3. The operational LEAKAGE performance criterion is specified in LC0 3.4.1 3, "RCS Operational LEAKAGE."
- c. Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.
- d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.
- 2. i. Unit 1 (alloy 600 Thermally Treated tubes): lnspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 48 effective full power months or two refueling outages (whichever is less) without being inspected.
ii. Unit 2 (alloy 690 Thermally Treated tubes): lnspect 100% of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 effective full power months. The first sequential period shall be Point Beach 5.5-8 Unit 1 - Amendment No.
Unit 2 - Amendment No.
Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) Proqram (continued) considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 72 effective full power months or three refueling outages (whichever is less) without being inspected.
- 3. If crack indications are found in any SG tube, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic nondestructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.
- e. Provisions for monitoring operational primary to secondary LEAKAGE.
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Programs and Manuals 5.5 5.5 Programs and Manuals This page retained for page numbering Point Beach Unit 1 - Amendment No.
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Programs and Manuals 5.5 5.5 Programs and Manuals This page retained for page numbering Point Beach 5.5-1 1 -
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Reporting Requirements 5.6 5.6 Reporting Requirements Tendon Surveillance R e ~ o r t (continued)
Nuclear Regulatory Commission pursuant to the requirements of 10 CFR 50.4 within thirty days of that determination. Other conditions that indicate possible effects on the integrity of two or more tendons shall be reportable in the same manner. Such reports shall include a description of the tendon condition, the condition of the concrete (especially at tendon anchorages), the inspection procedure and the corrective action taken.
5.6.8 Steam Generator Tube Inspection Report A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.8, Steam Generator (SG) Program. The report shall include:
- a. The scope of inspections performed on each SG,
- b. Active degradation mechanisms found,
- c. Nondestructive examination techniques utilized for each degradation mechanism,
- d. Location, orientation (if linear), and measured sizes (if available) of service induced indications,
- e. Number of tubes plugged during the inspection outage for each active degradation mechanism,
- f. Total number and percentage of tubes plugged to date,
- g. The results of condition monitoring, including the results of tube pulls and in-situ testing, and
- h. The effective plugging percentage for all plugging in each SG.
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