ML18087A531
| ML18087A531 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 10/07/1982 |
| From: | Public Service Enterprise Group |
| To: | |
| Shared Package | |
| ML18087A530 | List: |
| References | |
| NUDOCS 8210270142 | |
| Download: ML18087A531 (8) | |
Text
Attachment 1 Description of Change Section 3/4.7.9, Paragraph 4.7.9a is to be revised as follows:
SURVEILLANCE REQUIREMENTS 4.7.9 Each snubber shall be demonstrated OPERABLE by performance following augmented inservice inspection program and the requirements of Specification 4.0.5.
- a.
Visual Inspection The first inservice visual inspection of snubbers shall be performed after four months but within 10 months of INITIAL CRITICALITY and J
shall include all snubbers listed in Tables 3.7-4a and 3.7-4b.
If no snubbers are found inoperable, the second inservice visual inspection shall be performed during the first refueling outage.
If one or more snubbers in the same Table are found inoperable during the first inservice visual inspection, the second inservice visual inspection shall be performed in accordance with the following schedule:
No. Inoperable Snubbers in a Table per Inspection Period 1
2 3, 4 5' 6' 7 8 or more Subsequent Inspection Period for each Table*tl 12 months + 25%
6 months + 25%
124* days +-25%
62 days + 25%
31 days + 25%
Similarly, inspections subsequent to the second inservice.visual inspection shall be performed during each refueling ou~age unless snubbers are found to be inoperable in which case the above schedule would apply.
Within each Table, the snubbers may be categorized into two groups:
Those accessible and those inaccessibe during reactor operation.
Each group within a Table may be inspected independently in accordance with the above schedule *
- The inspection interval shall not be lengthened more than one step at a time.
t!The provisions of Specification 4.0.2 are not applicable.
8210270142 821007 PDR ADOCK 05000272 P
PDR l
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- 1. /
Reason for Change Amendment 5 to the Salem Unit 2 Technical Specifications changed the first inservice visual inspection for hydraulic snubbers from four-to-six months after initial criticality to four-to-ten months after Power Operations.
When the amendment was issued on 2/11/82, no provision was made to account for the fact that the first inservice visual inspection had already been performed, and compliance with that particular requirement of paragraph 4.7.9a would be impossible.
Furthermore, the schedule for subsequent inspections described in paragraph 4.7.9a originate from the first inspection, not from a fixed date such as initial criticality, power operation or commercial operation so that th_e validity of the first inspection must be clearly established.
Also, paragraph 4.7.9a is unclear as to whether the schedule described applies to periods subsequent to the first inservice inspection or to the second inservice inspection or if the second inspection must be performed 12 months +/- 25% from the date of the first inspection even if 0 snubbers are found to be inoperable.
Discussions with the NRC have established the following points:
- 1.
The intent of the paragraph 4.7.9a, e.g. early inservice inspection to detect "infant mortality" common to hydraulic snubbers, was met with the first inspection 4 months after initial criticality.
- 2.
The intent of paragraph 4.7.9a is to require a second inspection 12 months +/- 25% after the first even if.O snubbers are found inoperable but that shutdown of the plant just to perform the inspection is not justified, particulary if no snubbers are found inoperable by the previous inspection.
- 3.
- Subsequent inspections, including the second inservice inspection, may be done at the earliest available plant shutdown of sufficient duration or during each refueling outage, whichever comes first, if no inoperable snubbers are found in the preceding inspection.
l.
- Safety Evaluation Industry wide operating experience has been that the major dsitribution of failures among dynamic restraints, particularly hydraulic snubbers, has been within the first few months of operation at full operating temperature.
This service condition is achieved independent of the level of power operation as long as the plant is at normal-0perating temperatures.
Visual examination of the Salem Unit 2 hydraulic snubbers after approximately four months at full operating temperature similarly revealed no evidence of failure or abnormal conditions.
The probability of a failure occurring in a snubber demonstrated to have good operating characteristics in the first months of operation is very low.
It is concluded, based on the considerations discussed above, that because the amendment does not involve a significant increase in the probability or consequences of accidents previously considered and does not involve a signi-ficant decrease in a safety margin, this amendment does not. involve a signifi-cant hazards consideration.
PROPOSED LICENSE CHANGE SALEM UNIT NO. 2 DOCKET NO. 50-311 DESCRIPTION OF CHANGE (Ref. LCR 82-20)
Delete License Condition C-15.b Inspection Ports which reads "PSE&G shall install inspection ports in the steam generators".
REASON FOR CHANGE Upper inspection ports are a minimal value on a generic basis such that a backfit requirement, independent of a plant specific problem, which has not occurred at Salem Unit 1 or 2, is not technically justified, nor cost effective.
SAFETY EVALUATION The NRC requirment f o-r installation of_ inspection ports to examine Row 1 tubes on the steam generators (SQ's) of No. 2 Unit Salem Nuclear Generating Station at the first refueling outage was committed to by PSE&G for an operating license.
Subsequent investigations and service experience indicate that the benefit derived from external inspection of the Row 1 tubes at the "U-Bend" is questionable.
We believe that delaying the installation of inspection ports until the second refueling outage will not compromise safety and/or reliability~
Leaks have occurred in Row 1 "U-Bend" tubes in nin~ units.
Three were apex leaks and six were tangent point leaks.
The apex leaks were associat_ed with stresses caused by severe denting at tube support plates or tubes manufactured by the Mannesman process.
Apex leaks were large (up*to 150 gpm).
Tangeat leaks start very low (approximately.007 gpm) and have increased slowly to a maximum of approximately.7 gpm.
Denting has not contributed significantly to "U-Bend" leakage (with one exception -
Surry No. 2, which was an apex leak).
Tangent point leaks in Westinghouse Series 51 steam generators have been confirmed in three domestic plants (six of ten SG's) of the 14 plants in commercial operation with 45 SG's.
These leaks have been confined to Series 51 SG's generators manufac~
tured around the 1972 period.
Tube leakage and eddy current indications are confined to Row 1 tubes manufactured by Westinghouse.
Leaks have been relatively.small, and orderly shutdowns have occurred in each case.
Cracks appear to be short and tight with a low length/depth aspect ratio.
Samples removed from leaking tubes indicate that cracking progre*sses from the tube I.D. to O.D. and occurs at the tangent point opposite the smooth bend transition.
SAFETY EVALUATION -
Continued Eddy current indications have confirmed tangent point conditions on the intrados and extrados portions of bends which have been associated with cracking found to date.
Improved eddy.current probes and I.D. inspection techniques have been established to provide reasonable pre-leak information for both the intrados and extrados portions of the "U-Bend".
External surface inspec-tions would be limited to the intrados bend area and the top of the top support plate.
Support place conditions do not contribute to the cracking of non-dented tubes.
Leaks have appeared initially in plant operations at approximately 400 full effective full power days ( EFPD)
- The tubes used at Salem Nos. 1 and 2 Units steam generators were manufactured prior to 1972 and service time of No. 1 Unit has exceeded 900 EFPD without any indication of leakage.
Feedwater contamination control for both units has been rigorously applied, and the rate of denting observed in No. 1 Unit du~ing the first refueling outage has been reduced to a ne~ligible amount.
No. 2 Unit has had the benefits of rigorous contamination control since start-up.
Therefore, the value of visual inspection of the top support plate is reduced.
Service experience, analysis of defective material removed from service, and improved inspection techniques support our position of not needing inspection ports *at the Row 1 "U-Bend" area at this time.
Based on the consideration discussed above, it is concluded that this amendment would not introduce an unreviewed safety question.
e-PROPOSED LICENSE CHANGE SALEM UNIT N0.2 DOCKET NO.
50~ 311 DESCRIPTION OF CHANGE (Ref: LCR 82-21)
Delay Technical Specification Requirement 4.6.3.b (Pressure Drop Test) due on October 16, 1982 until the design change to relocate the test connections to a safely accessable area is completed during the first Unit 2 refueling outage.
REASON FOR CHANGE Conducting this test under present conditions is a safety hazard to test personnel and plant operation.
In order to perform this test during operation a containment entry is required.
The test connections are located near the ceiling on elevation 100' and are accessable only :by climb.ing and walking on safety related cable trays.
SAFETY EVALUATION The leak rate through 2VC5&6 was last measured on February 19, 1981 and a Pressure Drop Test was conducted on June 24, 1982, showing no increase in leak_ rate* over a 16 month period.
Based on the above information, it is concluded that this ammendment would not involve a signif ic~nt increase in the probability or consequences of any accident reviewed in the Safety A.Palysis Report nor in the possibility of an accident or ma~function of safety important equipment of a different type than previously evaluated and does not involve a significant decrease in safety margin as defined in the Technical Specifications 'Bases.
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PROPOSED LICENSE CHANGE SALEM UNIT NO. 1 DOCKET NO. 50-272 DESCRIPTION OF CHANGE (Ref: LCR 82-22)
A one time deferral of Technical Specifications 4.3.1.1, REACTOR TRIP !NSTRUMENTATION, monthly surveillance requirement of Table 4.3-1 for Pressurizer Water Level-High, is required for a period of eight days for Channel I and for a period of two days for Pressurizer Water Level-High, Channel III.
This will allow power operation to continue until the Unit No. 1 Refueling Outage scheduled for 10/16/82.
REASON FOR CHANGE On 9/27/82, Pressurizer Water Level Channel III was determined to be INOPERABLE due to an apparent-detector cali~ration drift.
ACTION #7 of Table 3.3-1 was placed in effect, which allows continued POWER OPERATION until the next CHANNEL FUNCTIONAL TEST which is due (with a 25% extension) on 10/14/82.
On 10/8/82, Pressurizer Water Level channel I CHANNEL FUNCTIONAL TEST is due.
This test can not be accomplished with Channel III in Action #7 without tripping the unit.
Repair of Channel III can be accomplished; but, there is concern that upon returning the ~hannel to service a reactor trip may occur due to an interraction-with Channel I pressurizer water level channel similar to that experienced on 8/27/82'. The cause for the 8/27/82 trip will be thoroughly investigated during the upcoming Unit No. 1 Refueling outage.
SAFETY EVALUATION The 31 day surveillance CHANNEL FUNCTIONAL TEST is designed to verify that the instruments important to safety operate cor-rectly within their prescribed accuracy requirements.
The REASON FOR CHANGE section above lists the reason why this surveillance interval should be extended.
Review of the Pressurizer High Level Trip channel results in the following conclusions:
(1)
This channel is not a primary trip but rather a secondary trip channel providing a backup to the High Pressurizer Pressure Trip channel.
The-High Pressurizer Pressure Trip channel is fully opera-tional and will continue to meet.its Technical Specifications surveillance requirements.
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SAFETY EVALUATION -
Continued (2)
The remaining operable pressurizer level channels (Channels I and II) are redundant and are compared to each other (channel check) at least once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> so that any significant calibration deficiency would be identified.
(3)
Review of Channels I and II CHANNEL FUNCTION TEST historical data shows that these channels have remained within Technical Specification requirements since the last unit refueling outage.
Based on the considerations discussed above, and the fact that the 8-day (Channel I) and 2-day (Channel II) deferral times requested constitute only an approximate 21% and 5% increase, respectively, in the allowable surveillance interval, it is concluded that this amendment does not involve a significant increase in the probability or consequences of any accident reviewed in the Safety Analysis Report nor in the possibility of an accident or malfunction of safety important equipment of a different type than previously ev~luated and does not involve a significant decrease in safety margin. as defined in the Technical Specifications Bases.