ML18152B788
| ML18152B788 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 04/28/1998 |
| From: | NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML18152B787 | List: |
| References | |
| NUDOCS 9805040088 | |
| Download: ML18152B788 (6) | |
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0 UNITED STATES
(
NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION REQUEST FOR RELIEF FROM ASME CODE REQUIREMENTS -
DEFERRAL OF REPAIR TO RESIDUAL HEAT REMOVAL SYSTEM PIPING VIRGINIA ELECTRIC AND POWER COMPANY SURRY POWER STATION, UNIT.1... -
DOCKET NO. 50-280
1.0 INTRODUCTION
10 CFR 50.55a(g) requires nuclear power facility piping and components to meet the applicable
- requirenients of Section XI of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (the Code).Section XI of the Code specifies Code-acceptable repair methods for flaws that exceed Code acceptable limits in piping that is in-service. A Code repair is required to_ restore the structural integrity of flawed Code piping, independent of the operational mode of the plant when the flaw is detected. Those repairs not in compliance with Section XI of the Code are non-Code repairs. However, the implementation of required Code repairs to ASME Code Class 1, 2,* or 3 systems is often impractical for nuclear licensees since the repairs normally require an insolation of the system requiring the repair, often requiring a shutdown of the nu~lear power plant.
Technical Specification (TS) 4.0.5 says, in part, that inservice inspection of ASME Code Class 1, 2, and 3 components shall be performed in accordance with Section XI of the ASME Code and applicable addenda as required by 10 CFR 50.55a. This regulation further states that specific written relief from Code requirements may be granted by the Commission pursuant to 10 CFR 50.55a(g)(6)(i).
Alternatives to Code requirements may be used by nuclear power plant licensees when authorized by the Commission if the proposed alternatives to the requirements are such that "they are shown to provide an acceptable level of quality and safety in lieu of the Code requirements [10 CFR 50.55a(a)(3)(i)], or if compliance with the Code requirements would result in hardship or unusual difficulty without a compensating increase in the level of quality and safety [10 CFR 50.55a(a)(3)(ii)].
A licensee may also submit requests for relief from certain Code requirements when a licensee has dstermined that conformance with certain Code requirements is impractical for its facility
[10 CFR 50.55a(g)(5)(iii)l Pursuant to 10 CFR 50.55a(g)(6)(i), the Commi.ssion may grant such relief and may impose such alternative requirements as it determines is authorized by law and will not endanger life or property or the common defense and security and is otherwise in the 9805040088 980428 PDR ADOCK 05000280 p
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2 public interest giving due consideration to the burden upon the licensee that could result if the requirement were imposed on the facility.
2.0 BACKGROUND
By letters dated March 23 and 27, 1998, Virginia Electric and Power Company (VEPCO or the licensee) requested relief from the provisions of the ASME Code in order to defer repair of a pin-hole leak.in a residual heat removal (RHR) system pipe. The request for relief was due to the need to continue operation of the system as part of an ongoing unit outage wherein the unit was being brought to cold shutdown.. After achieving cold shutdown and performing other
- unrelated maintenance outage activities;* the licensee would proceed with the-Code repair to -
the affected pipe spool in the RHR system. The anticipated delay in performing the Code repair (between the time of discovery of the leak and the repair) would be approximately 6 days.
In support of the request for deferral, the licensee presentE:ld technical analyses showing that although the leaking pipe spool was degraded, it still maintained adequate structural margins against all design loads; there was no significant loss of flow, flooding, or spraying on other equipment, no observable flaw growth, and that a prompt repair would impose undue and
- .undesirable hardships upon the licensee. Additionally, the licensee proposed additional measures supporting the technical analyses: periodic visual examination of the leak location once per day prior to the repair to monitor for any changes in leakage that would require immediate action and performance of a failure analysis of the RHR pipe leak to confirm the nature of the flaw.
3.0 EVALUATION 3.1 Impracticality of Repairs On March 22, 1998, the licensee detected evidence of minor leakage in Class 2 piping that is part of the RHR system at Surry Power Station, Unit 1. The licensee identified the leak at a location downstream of the RHR heat exchangers discharge and bypass piping in the common return header that feeds both Loops B and C of the Reactor Coolant System (RCS) cold legs.
The leakage was identified when collected boric acid was observed at the location identified above. Boric acid accumulation was estimated as 8 inches long, 1 inch wide by 1/4 inch thick.
No boric acid accumulation was found on the floor. The boric acid was removed to identify the leakage source. A rounded indication measuring 1/32 of an inch in diameter was found
. approximately 1/8 of an inch upstream ofthe toe of weld 2-02. Seepage, which quickly solidified, was identified at the location approximately 20 seconds after cleaning.
Although the RHR piping is capable of performing its intended function, the piping does not meet the ASME Code acceptance criteria due to the through-wall leak. Specifically, the degraded condition of the piping did not comply with Section XI, 1989 Edition, IWA-5250, Corrective Measures, and IWC-3600, Analytical Evaluation of Flaws, as applied to through-wall leakage in the piping pressure boundary. The ASME Section XI Code in IWA-5250 and JWC-3600 requires the repair or replacement of through-wall leakage found during operation. As such, VEPCO declared ttie RHR piping inoperable pending repair or replacement although the
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3 system was left in service. Technical Specification (TS) 3.1.A.1.d requires that two cooling loops be available for decay heat removal. This TS condition is met by having the RCS loops available (cooling through the steam generators).
To effect a repair of th_e RHR piping, it is necessary to isolate and drain the RHR system which would require using the RCS loop cooling method. However, remaining in cold shutdown with RHR isolated and drained creates a hardship. With the plant in cold shutdown, in conjunction with the need to isolate and drain the RHR system for repairs, the only available method for maintaining the plant at less 'than 200 degrees would be to use the currently operable/operating RCS loops. This method is not preferred for cooling the RCS at less than 200 degrees.
Specifically, the RCS cooling method requires the RCS to remain at approximately 300 psig.
This method utilizes a reactor coolant pump (RCP) pumping the reactor coolant through the steam generator primary _side and feeding/steaming on the secondary side. Therefore, the_
temperature at which the primary side can be maintained is dependent on steam generator
- pressure (due to the delta T across the steam generator and the relationship between Tsat and Psat). The specific hardships to this approa_ch are that: 1) the RCS would have to remain
- pres~urized prev~nting the other necessary outage maintenance, and 2) the only way to use this method and keep temperatures less than 200 degrees F would require having the steam generators steaming to a vacuum*.
The source of the vacuum would have to be the main condenser. The secondary systems/components that would be necessary to implement this approach are non-safety-related with their power sources coming from non-emergency buses. As a result, this approach relies on a backup method of cooling the reactor that is not normally used. Additionally, the
- operations staff had no formal training on using this method of plant cooling, nor are procedures currently available for providing the required guidance. In order to ensure positive control of the operational change, procedures would have to be developed and training would have to be conducted prior to implementing the repair.
Based upon the preceding licensee operations analysis, the staff finds the option of repairing the flaw in the current operating condition (i.e:, relying on heat removal from the steam generators at below 200 degrees) is undesirable. Additionally, the staff finds that defueling is not a practical approach for repairs due to the significant and unplanned impacts it would cause to the presently planned maintenance outage scope.
3.2 Flaw Sizing andRoot Cause Evaluation Surry Unit 1 was ramping down to cold shutdov.rn to effect repairs on unrelated equipment when the licensee identified a through-wall leak on piping approximately 1/8 of an inch upstream of the toe of weld 2-02 on line 12'!-RH-19-602. The* piping.is fabricated from 12-inch NPS schedule 40S welded type 304 austenitic stainless steel. VEPCO performed a visual examination of the piping. The licensee reported a rounded indication measuring 1/32 of an inch in diameter and located a*pproximately 1/8 of an inch upstream of the toe of weld 2-02.
The licensee performed an ultrasonic test (UT) of the affected area that included the weld and approximately 4 inches of base metal covering the circumference of the pipe. The exam
4 consisted of 45 and 60-degree shear wave scans in three directions (clockwise, counterclockwise and perpendicular to the weld). The UT was performed using equipment, methods, and personnel qualified under the intergranular stress-corrosion cracking (IGSCC) performance demonstration initiative. A zero degree scan was also performed on the area.
The UT did not identify any reflectors typical of intergranular stress corrosion cracking, transgranular cracking or subsurface cavities. The licensee did confirm nominal wall thickness with the UT.
The licensee stated that although the cause of the through-wall leak was not known at that time, they believed it was an isolated incident based on previous satisfactory inservice inspections,.
pressure testing, and visual exams conducted during system walkdowns. Since the root cause was unknown, the licensee committed, by letter dated March 27, 1998, to perform a metallurgical examination of the flaw for root cause determination. The results of this examination are expected to be completed within 3 weeks from the date of flaw sample
- removal, which was anticipated to occur on March 29, 1998. The results of this evaluation will be reported,* by letter, to the NRC staff for information only.
3.3 Structural Evaluation Three different analyses were performed to establish structural integrity:
- 1)
Area reinforcement analysis to establish that no ductile tearing of the line will occur when a postulated hole type of flaw is subjected to applicable design pressure.
. 2)
A limit load analysis to establish that no ductile rupture will occur when the line with a postulated crack-like flaw is subjected to dead weight, thermal expansion, and design basis earthquake (DBE) loading in addition to design pressure, and
- 3)
A fracture mechanics analysis to establish that no brittle fracture will occur when the line with a postulated crack-like flaw is subjected to dead weight, thermal expansion, and DBE loading in addition to design pressure.
The analyses results showed that adequate structural margins exist for continued operation of the affected pipe. However, some calculational discrepancies between the licensee's approach arid the staff-accepted methods were noted in two of the methods. These differences resulted in the margins against failure being less conservative than the licensee had concluded, but still acceptable overall. The staff's evaluation follows.
3.3.1 Limit Load Analysis To eliminate the ductile rupture as a possible failure mechanism, the licensee performed a limit load analysis on the flawed piping. For the crack geometry, the licensee assumed a through-wall crack length of 0.34 inch, 1 O times the length of the flaw indication. For the loading, the
- licensee considered the combined.pipe loading from pressure, dead weight, the maximum thermal, and the DBE. For the material properties,*the licensee used the ultimate strength and yield strength for A312-TP304 stainless steel material at the design temperature of 400 degrees Fahrenheit. A standard limit load analysis was executed by the licensee to give a safety factor
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of 17.3. The safety factor is defined by the licensee as the ratio of the rupture moment to the applied moment.
The staff agrees with the crack geometry, loading, and material properties used by the licensee.
However, afteran examination of the calculation details, the staff determined that the safety factor defined _by the licensee is not consistent with the definition in Appendix C, "Evaluation of Flaws in Austenitic Piping," of Section XI of the ASME Code. According to Appendix C, the safety factor should be defined as the ratio of the sum of the rupture bending stress and the axiai stress from the limit load analysis to the sum of the applied bending stress and the axial stress. Using this definition and the appropriate values in the submittal, the staff arrived at a safety factor of 6.35, a number much lower than the licensee's safety factor of 17.3.
- Further,
- due to the proximity of the flaw to the weld, the flaw should be considered as being located in the heat-affected zone. Hence, a Z-factor may apply. The staff conservatively used the Z-fa_ctor formula for the submerged arc welding weld, and derived a Z-factor of 1.56 for this case. Considering this, the staff revised the safety factor from 6.35 to 4.07. Since this value is still greater than the safety factor of 2. 77 for normal operating and 1.39 for emergency and faulted conditions specified in Appendix C of the ASME Code, the staff accepts the licensee's conclusion that a ductile rupture will not occur at the leak location.
3.3.2 Fracture Mechanics Evaluation To eliminate the brittle fracture as a possible failure mechanism, the licensee performed a linear elastic fracture mechanics (LEFM) analysis on the flawed piping. The same crack geometry and loading used in the limit load analysis were employed in the LEFM evaluation. An
- exception was that the residual stresses of 20.8 ksi was also included in the applied stress intensity factor (applied K) calculation. As to the fracture toughness (K,c), the licensee adopted the value of 135 ksi(in)~ in accordance with the guidance from Generic Letter (GL) 90-05. The licensee calculated the applied Ks due to bending moment (K18), pressure (K1p), axial tension (K1T), and residual stress (K1R) separately. The resultant applied K is the sum of the individual applied K with a load safety factor of 1.4 applied to the first three applied Ks. The ratio of the resultant applied K to K1c, is reported to be 0.175.
The LEFM type of analysis is specified in GL 90-05 for performing temporary non-Code repair of.ASME Code Class 1, 2, and 3 piping, including austenitic piping. The LEFM type of analysis for preventing brittle fracture has not been specified in the ASME Code for austenitic piping.
Consequently, the staff used the ASME acceptance criteria based on applied stress intensity factor for ferritic piping to conduct the evaluation, i.e., a safety factor (or margin) of 3.16 for normal conditions and 1..41 for emergency and faulted conditions. The staff agrees with the crack geometry, loading, and fracture toughness used by the licensee. The licensee did not report the sources for the equations used for its applied K calculations. To verify the results, the staff used the equations from NUREG/CR-4572 to calculate K18, Km and K1R, and the equation from Tada's handbook, "The Stress Analysis of Cracks Handbook," to calculate K1p.
The discrepancy between the staff's applied K value and the licensee's applied K value for each type of loading is within 1 %. Hence, the methodology fo, the applied K calculation is acceptable. The licensee's load safety factor of 1.4 is ih accordance with GL 90-05 and can be considered as a source of additional conservatism since the ASME approach for flaw evaluation (LEFM) does not require a load safety factor. Using the appropriate values in the submittal, the
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staff calculated.the safety factor fo be 5.7 (1/0.175), exceeding the ASME criteria. Hence, the staff accepts the licensee's conclusion that a brittle fracture is not likely to occur at the leak location.
3.3.3 Area Reinforcement Analysis The licensee performed an analysis to determine the largest postulated hole that the RHR line
. can sustain without ductile tearing when the pipe is subjected to design pressure at the location of the flaw. The licensee referenced the area reinforcement rules in ANSI 831.1.0-1967 for the calculation of allowable hole-size. The ANSI 831.1.0-area reinforcement rules provide design
.. criteria branch. for connections -to. assure-that the piJ;)e
- has suffici_ent strength in -the area-of the -
branch opening to compensate for the weakening effect of the opening in the pipe wall. The
. licensee determined that the ANSI 831.1.0 reinforcement rules could be met for a.34 inch
' diameter hole in the pipe. The estimated flaw size was determined to be approximately 1/32 inch in diameter. The staff considers the licensee's use of the ANSI 831.1.0 area reinforcement rules an adequate method to assess the potential for ductile failure due to internal pressure at the location of the fli;iw. The staff also believes there should be a margin of safety between the measured flaw size and the hole size determined from the area reinforcement rules to account for uncertainty in the measured flaw size and shape. On the basis of the licensee's evaluation described above, the staff considers that adequate margin exists between the calculated flaw size based on area reinfoicement rules and the flaw size measured in the pipe.
4.0 CONCLUSION
Based upon the above discussed structural analyses and operational considerations for alternative cooling methods, the staff finds, under the provisions of 10 CFR 50.55a(a)(3)(ii), that an immediate Code repair of the RHR pipe would pose an undue hardship upon the licensee without a consequent increase in safety or reliability. Thus, the staff finds the proposed deferral of the Code repair to be acceptable.
Principal Contributors: G. Hornseth, S. Coffin, S. Sheng, and J. Fair Date: April 28, 1998
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