ML20141A344

Responds to 850723 Request for Guidance Re Requirements for Inservice Testing of Relief Valves Used for Overpressure Protection of safety-related Sys.Engineering Issues Branch Review Indicates Testing of Subj Valves Unnecessary

ML20141A344
Person / Time
Site:	Turkey Point
Issue date:	03/31/1986
From:	Novak T Office of Nuclear Reactor Regulation
To:	Gibson A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
References
NUDOCS 8604040445
Download: ML20141A344 (4)

Text

March 31, 1986 g(y-d69 DISTRIRUTION Centreb.Eiler NRC PDR MEMORANDUM FOR: Albert F. Gibson, Director PAD #2 Rdg Local PDR Division of Reactor Safety Gray File T. Novak Region II L. Rubenstein D. Miller FROM: Thomas M. Novak, Acting Director D. Mcdonald Division of PWR Licensing-A

SUBJECT:

TIA 85-51 REQUIREMENTS FOR INSERVICE TESTING 0F RELIEF VALVES Your memorandum dated July 23, 1985, requested guidance relating to the requirements for inservice testing (IST) of relief valves used for over-pressure protection of various safety-related systems. You specifically requested assistance regarding the testing requirements of ECCS accumulator tank relief valves at Turkey Point, Units 3 and 4, and guidance regarding testir.g requirements for relief valves in general.

Your request was reviewed oy the Engineering Issues Branch (EIB) and the details of the review are enclosed. EIB has concluded that the testing of the ECCS accumulator tank relief valves at Turkey Point, Units 3 and 4, is not required. However, as stated in the enclosure, there are cases where this interpretation cannot be made. The Code has recently been revised to clarify the IST requirements for relief valves and will resolve any concerns as licensee's update to the newer Code requirements.

The enclosed review by EIB is being provided to all the Regions due to the generic nature of the guidance provided in relation to the IST requirements for relief valves used for overpressure protection of various safety-related systems.

I trust you find the enclosed guidance responsive to your request and resolves your specific concerns relating to the testing requirements of the ECCS accum-ulator tank relief valves at the Turkey Point Plant. If we can be of further assistance, please do not hesitate to contact us.

Thomas M. Novak, Acting Director Division of PWR Licensing-A

Enclosure:

As stated cc: See next page f

/

• See previous concurrence

• LA: PAD #2 *PM: PAD #2 *D: PAD #2 . -A D. Miller D. Mcdonald;bg L. Rubenstein . vak 3/ /86 3/ /86 3/ /86 86 8604040445 860331 fDR ADOCM 05000250 PDR

MEMORANDUM FOR: Albert F. Gibson, Director Division of Reactor Safety Region II FROM: Thomas M. Novak, Acting Director Division of PWR Licensing-A

SUBJECT:

TIA 85-51 REQUIREMENTS FOR INSERVICE TESTIN OF RELIEF VALVES Your memorandum dated July 23, 1985, requested guidance elating to the requirements for inservice testing (IST) of relief val es used for over-pressure protection of various safety-related systems You specifically reauested assistance regarding the testing requireme ts of ECCS accumulator tank relief valves at Turkey Point, Units 3 and 4, nd guidance regarding testing requirements for relief valves in general.

Your request was reviewed by the Engineering Iss es Branch (EIB) and the details of the review are enclosed. EIB has co cluded that the testing of the ECCS accumulator tank relief valves at Tur ey Point, Units 3 and 4, is not required. This determination is based on he current wording of the inservice testing Code, ASME Section XI. Ho ver, as stated in the enclosure, there are cases where this interpretation c not be made. The Code has recently been revised to clarify the IS requirements for relief valves and will resolve any concerns as licensee' update to the newer Code require-ments.

The enclosed review by EIB is being prov ded to all the Regions due to the generic nature of the guidance provided in relation to the IST requirements for relief valves used for overpressure protection of various safety-related systems.

I trust you find the enclosed guidan _ responsive to your request and resolves your specific concerns relating to t e testing requirements of the ECCS accum-ulator tank relief valves at the Tu key Point Plant. If we can be of further assistance, please do not hesitate o contact us.

Thomas M. Novak, Acting Director Division of' PWR Licensing-A

Enclosure:

As stated cc: See next page L

D.

'k hller M: PAD #2

. Mcdonald;b .

2 AD:PWR-A enstein T. Novak 3/ 86 /g5/86 -

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V. Stello J. Heltemes .

J. Partlow J. Taylor .

E. Jordan

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E. Rossi R. Baer B. Grimes W. Russell T. Speis R. Bernero G. Lainas D. Crutchfield D. Eisenhut i J. Miller G. Holahan j S. Varga E. Butcher B. Sheron J

] T. Murley J. Keppler R. Martin J. Martin i

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ENCLOSURE ENGINEERING ISSUES BRANCH EVALUATION OF REGION II CONCERNS 1 l

INSERVICE TESTING REQUIREMENTS FOR PELIEF VALVES ,

As requested in memorandum dated July 23, 1985, the Engineering Issues Branch (EIB) has reviewed the Region II questions regarding the requirements for inservice testing of relief valves used for overpressure protection of various safety-related systems. In Reference 1, Region II specifically requested assistance regardina testing recuirements of ECCS accumulator tank relief  !

valves at Turkey Point 3 and 4. Region II also requested guidance regarding  !

testing requirements for relief valves in general.

EIB has concluded that the confusion about whether to test various ASME Class 1, 2, and 3 relief valves is due to the specific wording of past editions of the inservice testing code, ASME Section XI. These editions, which are currently being implemented for plant inservice testing, specify that those valves to be included for inservice testing be " Class 1, 2, and 3 . . . which are required to perform a specific function in shutting down a reactor . . .

or in mitigating the consequences of an accident." Because of this wording, most licensees do not include the majority of overpressure protection valves in their inservice testing programs. The licensee for Turkey Point is an example of this, as stated in the Region II memorandum where a determination has been made that the function of the accumulator relief valves is not required for safety in the context of the referenced Code wording.

However, there are some systems wher this interpretation clearly cannot be made, i.e., where the failure of a ' tlief valve will disable the function of a safety system. A recent AE0D report (E. Brown to K. Seyfrit dated November 25,1985) described an event where low setpoints on relief valves jeopardized or severely impaired capabilities of the Standby Liquid Control System on a Boiling Water Reactor. A copy of the AEOD report is attached.

Fortunately, the Code has recently been revised to clarify this area. The Winter 1985 Addenda to the 1983 Section XI Code specifically requires in-

• service testing of all Class 1, 2, and 3 overpressure protection devices.

Therefore, in the future, as licensees update to this newer Code requirement at the beginnina of their next 10 year inspection interval, as defined in 10 CFR 50.55a(g), all of the Code Class 1, 2, and 3 relief valves will have to be included in the inservice testing program and inservice tes*:ed.

Principal Contributors:

G. Hammer F. Cherny j

Attachment:

As stated l I

ATTACHMENT DISTRIBUTION:

POR ROAB SF ROAB CF EBrown C / MChiramal KSeyfrit TIppolito

- CHeltemes, Jr.

August 13, 1985 SRubin AEOD FCherny,.iCF JPage, NRR MEMORANDUM FOR: Karl V. Seyfrit, Chief Reactor Operations Analysis Branch AE0D/T507 Office for Analysis and Evaluation of Operational Data THRU: Matthew Chiramal, Chief Engineering Section Reactor Operations Analysis Branch Office for Analysis and Evaluation of Operational Data ,

FROM: Earl J. Brown Engineering Section Reactor Operations Analysis Branch Office for Analysis and Evaluation of Operational Data

SUBJECT:

STANDBY LIQUID CONTROL SYSTEM PRESSURE RELIEF VALVES LIFT AT A PRESSURE LOWER THAN REACTOR COOLANT PRESSURE The enclosed report is forward for your information and further consideration.

This event at Hatch 2 in which the relief valves lifted at 600 and 700 psig rather than the specified range of 1350 psig 25 psig appears to be an isolated case resulting from degraded valves. A review of operational data of relief valves in the standby liquid control system did not identify similar events. It does not appear that additional NRC effort is needed.

/4 Earl J. Brown Engineering Section Reactor Operations Analysis Branch Office for Analysis and Evaluation of Operational Data E 6. . gL &q R0}B:AEOD SC:ROAB:A(OD BC:RDAB:AE00 KVSeyfrit DD:AE00 TIppol o EBrown:as MChiramal Y./

8/ 7 /85 8/(l/85 8/f/85 8/j p 5 zy f07/70 M 2 -  !

AE0D TECHNICAL REVIEW REPORT

• UNIT: E. I. Hatch, Unit 2 TR. REPORT NO.: AE0D/T DOCKET N0.: 50-366 DATE:

LICENSEE: Georgia Power Company EVALUATOR / CONTACT: Earl J. Brown NSSS/AE: General Electric /Bechtel ,

SUBJECT:

STANDBY LIQUID CONTROL SYSTEM PRESSURE RELIEF VALVES LIFT AT A PRESSURE LOWER THAN REACTOR COOLANT PRESSURE EVENT DATE: May 5, 1984 (LER 366/84-005)

SUMMARY

Both loops of the standby liquid control system would have been unable to inject sodium pentaborate because, during a test, relief valves lifted at 600 and 700 psig rather than the set point range of 1350 psig 25 psig.

A review of available data suggests that these events were isolated cases and were the result of degraded valves rather than an indication of a' generic problem. No additional AE0D effort seems necessary at this time.

DISCUSSION It was discovered during bench tests that pressure relief valves in the standby liquid control (SLC) system at Edwin I. Hatch, Unit 2 lifted at a pressure lower than the set pressure of 1350 psig 25 psig. The event occurred on May 5, 1984 and is described in LER 366/84-005. The test pro-cedure is performed at six month intervals. The "A" loop relief valve, 2C41-F029A, lifted at 600 psig and the "B" loop relief valve, 2C41-F0298, lifted at 700 psig. Since this lift pressure was several hundred psig below the set pressure, it represents a situation quite different from normal set point drift.

A review of the P&ID drawing indicates that lifting of either of these relief valves would result in recirculation of the pump discharge flow back to the intake side of the SLC pump. Hence, in the event of an injection signal, the as found condition of the relief valves indicates that the sodium pentaborate*

solution would just recirculate through the SLC pump rather than be injected into the reactor vessel when the reactor pressure is greater than 700 psig.

Investigation by the licensee revealed the stem on relief valve 2C41-F029A was broken at the cotter pin hole which permitted the valve spring to decompress and lose tension. Relief valve 2C41-F029B was found to have excessive wear on the valve stem and the valve stem guide.

• This document supports ongoing AEOD and NRC activities and does not represent the position or requirements of the responsible NRC program office.

DUJ"1I W_Q 1 A j&f

' The immediate corrective action by the licensee was to replacr. the damaged relief valves, Lonergan Model LCT-20, with a different model, LCT-30, supplied .

by the same manufacturer. Since this mode of failure has potential generic  !

implications which resulted in complete inability to inject sodium'pentaborate when needed, a search of the Sequence Coding Search System (SCSS) data base was conducted to review for similar events.

The data base search of SCSS was conducted for relief valves in standby liquid control systems and all events in standby liquid control systems. There were 43 events involving the SLC system, but only 11 events involved a relief valve in the SLC system. Table 1 is a list of the 11 events with LER number, plant name, event date, and event description with the cause of failure if it was stated in the LER. It is evident from the 11 events that low relief valve lif t pressures of 600 and 700 psig only occurred for two valves at Hatch Unit 2 and one at Pilgrim. The valves at Hatch 2 were physically damaged with a broken However, one event at stem or one valve and excessive wear on the other valve.

Pilgrim (item 3) identifies a low lift pressure at approximately 600 psig but the cause could not be determined. Subsequent testing of the valve at Pilgrim resulted in valve lift within set point specifications. Although the very low lift pressure of 600 psig was similar at Hatch and Pilgrim, the valves were supplied by different manufacturers. The valves at Hatch were manufactured by Lonergan and that at Pilgrim was manufactured by Crosby.

The valves identified for all events in Table I were manufactured by either Crosby or Lonergan. The valves at Pilgrim and Vermont Yankee are Crosby .

valves and those at Hatch and Brunswick are Lonergan valves. Hence, only four plants have reported problems with relief valves lifting outside of specifica-tion requirements. Furthermore, at least two sites have identified that relief valve lift problems appear related to the test procedure.. Discussions with licensee staff at Brunswick (items 7, 8, and 9) revealed that the test procedure was the primary cause of r'elief valve lifting outside of specifica-tion limits. The reduced time interval between tests was apparently not effective (18 months to 6 months) in reducing improper lift pressure. However, the test procedure was changed from using the SLC pump pressure and audio recognition of valve lift to bench testing with water and a portable positive.

displacement pump. Since that procedure was implemented, there have been no further reports involving SLC relief valves.

A search of NPRDS was conducted in an attempt to further assess potential l generic implications. There were no additional BWR plants identified in that search that use the Model LCT-20 relief valves. However, the search did i iddntify use of the same model valve at a few PWR plants in the service water system, component cooling water system, feedwater system, and auxiliary feed-water system. However, no unusual events were identified.

1 FINDINGS AND CONCLUSIONS A review of the available operating data appears to suggest that the two relief valves lifting at 600 to 700 psig at Hatch 2 were isolated events.

Furthermore, those valves were degraded in a manner that has not been reported by other licensees. It also appears that certain test methods used (like at Brunswick) to establish the pressure at which these valves lift may be the primary cause of reported lift pressures outside the acceptable set pressure range.

Based on available information, it is concluded that these events do not represent a generic issue for BWR plants relative to inability to inject sodium pentaborate into the reactor vessel when needed. There does not appear to be a need for additional NRC action at this time.

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• TABLE 1 RELIEF VALVE EVENTS IN STAND 8Y LIQUID CONTROL SYSTEM Event LER Number / Plant Date Event Description

1. 271/81-031 11-9-81 Relief Yalve SR-39-B was found Vermont Yankee to have set point of 1540 psig.

Set point range was 1400-1490 psig. Suspected cause of drift was crystallization of sodium pentaborate.

2. 271/84-013 7-21-84 Relief valves SR-11-38 A&B were Vermont Yankee found to have a set point below the required range. Most probable cause of low setpoint was the testing technique.-

3. 293/85-001 1-1-85 SLC system was inoperable due to Pilgrim 1 debris in SLC system storage . tank and test tank. The "A" relief valve lifted at about 600 psig vs.a set point of 1450 psig. The "B" relief valve, which lifted below setpoint but within range,

was found with pieces of rubber gloves between the blowdown adjus-ting orifice and plunger. Cause of "A" lif ting low is- unknown. It lifted at the required setpoint on subsequent bench tests.

4 321/81-006 1-19-81 SLC loop "A" relief valve, IC41-Hatch 1 F029A, lifted at 1200 psig vs. a

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setpoint of 1325 75 psig. Cause was attributed to setpoint drift.

5. 321/81-020 3-18-81 SLC loop "B" relief valve.

Hatch 1 1C41-F0298, lifted at 1180 psig vs a setpoint of 1325 75 psig.

Cause was attributed to setpoint drift.

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l TABLE 1 (Continued)

6. 321/83-102 10-11-83 SLC relief valve IC41-029A would Hatch 1 not lift in the range 1325 75 psig. Valve was disassembled, .

and cleaned and bench tested successfully.

7. 324/82-041 3-14-82 SLC relief valve 2-C41 029A Brunswick 2 lifted at 1465 psig vs retpoint of 1400 50 psig. Further evalua-tion is planned. Test frequency was changed to 6 month intervals from 18 month intervals.

. 8. 325/80-057 7-3-80 SLC relief valve 1-C41-F0298 did Brunswick 1 not lift in the setpoint range of 1400 50 psig. Cause was attributed to setpoint drift.

Test interval increased to every 6 months.

9. 325/83-019 4-25-83 Both units had SLC relief valves

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Brunswick I outside the setpoint range of 1400 50 psig. Unit I relief valves 1-C41-F029A and F029B lifted

at 1321 psig and 1529 psig respec-tively. Unit 2 relief valves 2-C41-F029A and F029B lifted at 1403 psig (acceptable) and 1323 psig respectively. Cause appears to have been the test method which

' utilized SLC discharge pressure and an audible report of valve opening. .

! 10. 366/81-014 3-18-81 SLC relief valve failed to lift Hatch 2 at 1400 psig vs. set pressure of 1350 50 psig. Cause was set-point drift.

11. 366/84-005 5-25-84 SLC relief valves in loops "A" Hatch 2 and "B" (2C41-F029A and 2C41-F029B) lifted at 600 psig and 700 psig respectively. Would have been unable to inject sodium pentaborate into reactor vessel.

Cause was damaged and worn valve components.

.