ML20076B508
| ML20076B508 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 08/12/1983 |
| From: | Howe P CAROLINA POWER & LIGHT CO. |
| To: | Harold Denton Office of Nuclear Reactor Regulation |
| References | |
| LAP-83-371, NUDOCS 8308190385 | |
| Download: ML20076B508 (18) | |
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e SERIAL: LAP-83-371 Carolina Power & Light Company AUG 121983 Mr. Harold R. Denton, Director Of fice of Nuclear Reactor Regulation United States Nuclear Regulatory Commission Washington, DC 20555 BRUNSWICK STEAM ELECTRIC PLANT, UNIT NOS.1 AND 2 DOCKET NOS. 50-325 AND 50-324 LICENSE NOS. DPR.71 AND DPR-62 STAFF MEETING ON BWR PIPE CRACKS
Dear Mr. Denton:
On behalf of Carolina Power & Light Company (CP&L), I would like to express our appreciation for the opportunity to present our case on the BWR pipe crack issue to members of your staff at a meeting on August 8,1983.
' Copies of the slides presented at that meeting are attached for your information, as well as the requested data on the water chemistry history and leak detection instrumentation sensitivity for Brunswick Units 1 and 2.
Supplementary information is also provided in regard to operator training, testing to be conducted during unscheduled shutdowns, and corrective action to be taken if IGSCC indications are detected. Additionally, committments are provided which limits the inoperability of the sump flow integrator to no more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> as well as provided for daily monitoring of the leakage calculations by the on site nuclear review group.
We wish to reiterate that based on all inspections made to date on the Brunswick units, the relative age of the plants, and industry experience and research on the generation and growth of intergranular stress corrosion cracks, it is CP&L's position that acceleration of the inspections now 7scheduled for November 1983 is not justified. Whereas the recent EPRI test results do point out the need for continued training of Ur inspectors in crack depth sizing techniques, CP&L has not based any of its actions to date on the ability to -determine crack depth. Indeed, as previously presented to your staff, CP&L has and will continue to maintain a very conservative approach to detection and repair of these cracks.
- NNQ MQ-Carolina Power & Light Company recognizes the need for continued
'go detection, repair, and ultimate-elimination of these cracks from BWR piping.
.mn Carolina Power & Light Company also recognizes the necessity for sound O
.n management practices and proper planning of plant activities. We will
,g continue to review the present outage schedule in an effort to find
,oo alternative means of schedule acceleration; however, it' remains our position N
that the disruption of outage preparation, direct and indirect cost increases e
to our_ customers, and potential increases in man-rem exposure that would
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result f rom an ordered,. arbitrary change in the planned schedule at this late mea date are not justified.
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~ 411 Fayetteville Street
- P.f O. Box 1551
- Raleigh, N. C,27602 L
Mr. H. R. Denton Carolina Power & Light Company welcomes any suggestions your staff might offer on this issue and trusts that a mutually acceptable solution can be f ound.
Please do not hesitate to contact our staff should you have any questions.
Yours very truly, P. W. Howe Vice President Brunswick Nuclear Project JSD/af (7640JSD)
Attachment cc:
Mr. D. O. Myers (NRO-BSEP)
Mr. J. P. O'Reilly (NRC-RII)
Mr. S. D. MacKay (NRC)
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Attachment I to LAP-83-371 4
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Inspections Prior to the Scheduled Outane i
e CP&L commits to following action plan to perform inspections of large diameter recirculation pipe welds during unscheduled outages on Brunswick Unit No. 2.
Should an unscheduled outage occur, the duration will be estimated based on the cause of the shutdown; if this duration is ten days or longer, the following recirculation welds will be ultrasonic inspected:
Weld No.
SRI Carbon Content Susceptibility Rank 2-B32-28-A-3 1.46 0.059 1
2-B32-28-A-14 1.51 0.059 1
2-B32-28-A-15 1.42 0.059 1
If the initial outage duration is estimated to be 1ess than ten days, but is subsequently extended, the inspections will be performed if at any time the estimated remaining duration is ten days or longer.
Spool replacement or overlay repairs will be performed on joints that are found to contain:
1.
Unresolved circumferential indications with a length such that for a through-wall crack of that length, the combination of P,and Pb f r the crack cross section exceeds 1.5 Sm, or J
2.
Through-wall cracks.
Axial cracks are not a safety concern regardless of depth because the section properties of the pipe are not affected. The criteria for circumferential cracks ensures that structural margin is maintained based on conservative assumptions regarding crack depth.
If any of the joints inspected requires repair by the criteria stated above, an additional three large diameter (_ 12") weld joints will be inspected.
If any joints in the second group require repair, an additional three joints will be inspected.
The inspection personnel will be qualified to the requirements of IEB 83-02 as amended by the letter of July 21, 1983.
The inspection described in this plan will be performed only if qualified personnel with sufficient allowable radiation exposure are available from LMT or Southwest Research Institute.
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r Leak Detection Sensitivity and Operability The Primary Containment Sump Flow Integrating System measures the unidentified leakage to within 0.5 cpm for an eight-hour period. The current operability requirement is that any one leak detection system may be inoperable for up to 31 days. The three systems are:
the Sump Flow Integrating System, the Primary Containment Atmosphere Particulate Radioactivity Monitoring System, and the Primary Containment Gaseous Radioactivity Monitoring System.
We will institute an administrative limit of three days for the Sump Flow Integrating System to be inoperable, after which the unit will be placed in at least hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This limit will apply only to Unit No, 2 until the inspections required by IEB 83-02 are complete.
As stated in previous submittals, we have already established a limit on the increase in unidentified leakage in the drywell of 0 gpm for a 24-hour period.
The On-Site Nuclear Safety group will review the Unit No. 2 drywell leakage data on a daily basis until the inspections required by IEB 83-02 are complete.
Water Chemistry History The total hours that the water chemistry exceeded technical specification limits since 1978 are tabulated below for each unit.
Total Hours Above Technical Specification Chemistry Limits Year Unit No. 1 Unit No. 2 1976 35.7 1977 68.3 28.7 1978 309 251 1979 124 242 1980 183 183 1981 14.5 241 1982 35.0 59.0 1983 13.1 2.0 Operator Training A discussion of IGSCC causes and effects, and a review of small break and large break IDCA emergency instructions have been included in the weekly shift briefings of Operations personnel excluding Fire Protection and Radwaste personnel. These briefings will also include appropriate current developments in this area.
Attachnent 2 to LAP-83-371
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i OUTLINE I.
CONCLUSIONS
,1 II.
INSPECTION RESULTS 4
III. BASES FOR CONCLUSIONS j
IV.
IMPACT V.
AVAILABILITY OF INSPECTION PERSONNEL i
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CONCLUSIONS o
Unit No. 2 inspections performed in February 1983,-
demonstrated low probability of IGSCC cracking o
Unit No. 1 inspection results support same conclusion o
Design features support lower susceptibility to IGSCC o
Sizing accuracy has no impact on BSEP o
Conclusions are based on detection, not sizing Three repairs made on Unit No. I conservatively o
overlayed o
Augmented leak detection surveillances implemented i
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Continued operation of Unit No. 2 until November does not constitute a safety concern l
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SUMMARY
OF UNIT NO. 2 INSPECTIONS Inspection done February 7 and 8, 1983, prior to issuance of IEB 83-02; however, methods conform to Bulletin requirements.
Level III inspector qualified at Battelle.
o LMT used to perform UT inspections o
1.5 MHz dual element transducer master / slave system o
Eight 12" Jet pump inlet pipe to safe-end welds o
Highest carbon content and stress rule indices of system o
No indications o
Four 4" Bypass line welds o
Small diameter; therefore, highly susceptible o
No indications o
Leak test was performed to verify integrity of 12" lines (40 welds) o Used LP developer to enhance technique o
Recire pump run to pressurize piping
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SUMMARY
OF UNIT NO. 1 INSPECTIONS o
Inspection personnel complied with IEB 82-03 o
SWRI performed inspections, 1.5 MHz single-element transducer o
Twenty 12" jet pump inlet pipe welds o
Two axial through-wall cracks found o
Ten welds in piping 20" diameter or larger o
Sample included both end caps and all bimetallic welds (3) o Two small axial indications 5% and 11%
of wall thickness found on one 28" weld o
Sized using crack tip diffgaction technique o
Two Sweep-o-;r' to header welds adjacent to end caps t'
o Four 4" bypass line welds o
No indications l
o No circumferential indications i
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LIST OF WELDS INSPECTED ON BRUNSWICK UNIT 2 IN FEBRUARY 1983 WELD NO.
DESCRIPTION SRI ji 2-B32-12"-A-4 PIPE TO SAFE END 1.27 0.075 2-B32-12"-B-4 PIPE TO SAFE END 1.36 0.075 2-B32-12"-C-4 PIPE TO SAFE END 1.60 0.075 2-B32-12"-E-4 PIPE TO SAFE END 1.58 0.075 2-B32-12"-F-4 PIPE TO SAFE END 1.46 0.075 2-B32-12"-G-4 PIPE TO SAFE END 1.42 0.075 2-B32-12"-H-4 PIPE TO SAFE END 1.53 0.075 2-B32-12"-K-4 PIPE TO' SAFE END 1.25 0.075 2-B32-4"-A-1 DISCHARGE VALVE BYPASS 1.22 0.071 2-B32-4"-A-10 DISCHARGE VALVE BYPASS 1.19 0.071 2-B32-4"-B-1 DISCHARGE VALVE BYPASS 1.22 0.071 2-B32-4"-B-10 DISCHARGE VALVE BYPASS 1.20 0.071 l
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BASES FOR CONCLUSIONS I.
EVALUATION OF UNIT NO. 2 RESULTS o
Personnel qualified at Battelle.
o Welds inspected have high stress rule indices and carbon content, including highest in system.
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Twelve welds UT inspected and 40 welds 1
inspected with augmented visual technique represent significant sample size. No indications found.
o The four 4-inch and eight 12-inch welds i
UT inspected are likely to experience cracking and leakage earlier than the larger piping.
o Larger piping not inspected has larger margin of safety than smaller piping due to thicker wall.
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o Critical crack length is significantly longer for large pipes compared to crack length for leak detection.
t BASZS FOR CONCLUSIONS (Cont'd)
II.
EVALUATION OF UNIT NO. 1 RESULTS o
Personnel qualified at Battelle.
o Welds inspected have high stress rule indices and carbon content, including highest in system.
o 36 welds UT inspected represent significant sample size. No circumferential cracks found.
Three welds with axial indications. Only one large weld found with two shallow axial indications.
o Sample included 3 bimetallic welds. No indications found in bimetallic welds.
o Unit Nos. I and 2 designs are the same and installed by the same contractor and procedures.
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BASES FOR' CONCLUSIONS (Cont'd)
III. DESIGN FEATURES REDUCE SUSCEPTIBILITY TO CRACKING o
One short (2'1") connecting spool is SS o
Three bimetallic welds o
All 3 bimetallic welds inspected on Unit No. 1 - no indications o
End caps have lower stress than other l
designs o
Deep-dish design o
No history of pipe vibration on recire pipe or RHR f
o No indications found on Unit No. 1 sweep-o-let welds l
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BASES FOR CONCLUSIONS (Cont'd)
IV.
SIZING ERRORS DO NOT IMPACT BSEP o
Conclusion that low probability of IGSCC cracking exists is based on lack of detection of cracking.
o UT personnel were qualified at Battelle on crack detection I
Weld overlays were conservatively designed o
o Two through-wall axial leaks in 12" pipe have full thickness overlays.
28" weld sized by LMT using crack tip o
diffraction.
Indications estimated to be 5% and 11% deep and axial. The as-built minimum overlay thickness of 0.47" is adequate for a through-wall axial crack in the 28" pipe.
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BASES FOR CONCLUSION (Cont'd)
V.
AUGMENTED LEAK DETECTION SURVEILLANCES IMPILENTED o
Increase in unidentified leakage limited to 2 gpm per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> o
Drywell sumps are monitored every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> o
Drywell atmospheric radiation monitor channel surveillance every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> vs. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
In case of inoperability of monitor, grab samples are taken every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> vs. every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
VI.
LEAK-BEFORE-BREAK IS STILL VALID Stable cracks will result in easily measur-o able leakage rates inside the containment long before factors of safety decrease to uncomfortable levels.
Ample time is provided to assure safe plant shutdown.
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IMPACT o
IMPACT ASSESSMENT BASED ON MINIMUM SCOPE AND NO REPAIRS o
30 DAYS FROM AUGUST 15 o
$200,000 DIRECT COSTS MINIMUM o
70 MAN-REM MINIMUM o
$2.3 MILLION FIPLACEMENT POWER MINIMUM o
REDUCE RESERVES FROM 2072 MW to 1282 MW o
SEVERE DISRUPTION OF OUTAGE PREPARATION o
60 DAYS FROM AUGUST 15 j
o BEGIN MAJOR OUTAGE EARLY--17-DAY EXTENSION f
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$3.4 MILLION REPLACEMENT POWER o
REDUCE RESERVES FROM 2312 MW TO 1522 MW o
DISRUPTION OF OUTAGE DUE TO PREMATURE START 1
o 90 DAYS FROM AUGUSi 15 i
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$160,000 DIRECT COSTS o
55 MAN-REM o
NO INDIRECT COSTS o
FEWER PERSONNEL NEEDED l
AVAILABILITY OF INSPECTION PERSONNEL o
Few available qualified at EPRI, as per latest requirement o
Inspectors who could qualify have limited available exposure--4 Rem Corporate limit o
Training inexperienced personnel is time-consuming, limited capacity o
Extreme difficulty in obtaining trained personnel in 30 days.
Inspection personnel available to support November outage date.
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