ML20211K805

Review of Motor-Operated Valve Performance

ML20211K805
Person / Time
Issue date:	12/31/1986
From:	Ellen Brown NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD)
To:
Shared Package
ML20211K781	List: ML20211K778 ML20211K805
References
TASK-AE, TASK-C603 AEOD-C603, TAC-R00141, TAC-R00142, TAC-R141, TAC-R142, NUDOCS 8612150167
Download: ML20211K805 (61)

Text

,. ()CIl CASE STUDY REPORT

• AE0D/C603 A REVIEW 0F MOTOR-0PERATED VALVE PERFORMANCE December 1986 l 1

Prepared by: Earl J. Brown l

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Office for Analysis and Evaluation of Operational Data U.S. Nuclear Regulatory Commission

• This report documents the results of a study completed by the Office for Analysis and Evaluation of Operational Data with regard to selected opet ating events. The findings, conclusions, and recommendations contained in this report are provided in support of other ongoing NRC activities and do not represent the position or requirements of the responsible program office or the Nuclear Regulatory Commission.

9612150167 961210 PDR ORG NEXD PDR

! l TABLE OF CONTENTS l -

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Page I E X E C UT I V E S L'MMA R Y , . . . . . . . . . . . . . . . . . . . . . . . . . 1

1.0 INTRODUCTION

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1.1 Purpose and Scope

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1.2 Background of Operating Experience and Previous Reviews . . 4 s >

{ 1.3 NRC Efforts in Response to AE00 Reports . . . . . . . . . . 8  !

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) 2.0 DISCUSSION AND EVALUATION ................... 10 i

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{ 2.1 Review of Previous AE0D Reports ............. 10 l 1

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2.2 Review of NRC Signature Tracing Test Program ....... 11 1

l 2.3 Review and Discussion of Databases ............ 20

! i j 2.4 Evaluation of NPRDS Event Data .............. 24 '

2.5 Evaluation of SCSS Event Da ta . . . . . . . . . . . . . . . 26 2.6 Signature Tracing Tests at Davis-Besse .......... 34

', 3.0 FINDINGS AND CONCLUSIONS . . . . . . . . . . . . . . . . . . . 37 i ,

j 3.1 Findings ......................... 37 l I  !

! 3.2 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . 39 <

4 i I 4.0 RECOMMENDATIONS ,....................... 41 i i 1

5.0 REFERENCES

. . . . . . . . . . . . . . . . . . . . . . . . . . . 43 l j APPENDIX A - Motor-Operated Valve Events From SCSS ......... 46

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LIST OF FIGURES -

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l Figure 2.2-1 Hypothetical Open-to-Close Valve Cycle as Indicated l by the TMD, the Switch-Position-Indicating Device, and j the Motor Current . . . . . . . . . . . . . . . . . . 13

! Figure 2.2-2 Hypothetical Close-to-Open Valve Cycle as Indicated l q by the TMD, the Switch-Position-Indicating Device, and the Motor Current . . . . . . . . . . . . . . . . . . 14 j Figure 2.5-1 Auxiliary Feedwater System ............. 30 i

l LIST OF TABLES Table 2.2-1 Interpretation of Valve Signatures in Figs. 2.2-1 and 2.2-2 . . . . . . . . . . . . . . . . . . . . . . 15

! Table 2.2-2 Summary of Abnormalities Detectable by M0 VATS Classified by Type ................. 18 i Table 2.3-1 LERs for Motor-Operated Valves During a 1981-1985(SCSS) .................. 21 4

Table 2.3-2 Reported LERs for Specific Systems ......... 23 i Table 2.3-3 NPRDS Reports for Valve Motor-Operator Events During 1978 through 1985 .............. 23

) Table 2.3-4 Distribution of NPRDS Reports for Specific ,

Systems ...................... 24 l

) Table 2.4-1 NPRDS Event Problem Category ............ 25 Table 2.5-1 Distribution of Events in Appendix A by Year .... 27 i Table 2.5-2 Distribution of Reported valve-Operated Events ... 27 I

Table 2.6-1 Preliminary Results from Signature Tracing Tests i of Safety-Related Potor-Operated Valves at ,

j Davis-Besse .................... 35  !

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! ,,o EXECUTIVE

SUMMARY

The purpose of this study is to provide an assessment of motor-operated valve assembly operating experience and to identify failure modes and overall valve operator performance. The study brings together and reviews previous NRC studies and documents (primarily AE00 reports and IE bulletins, circulars and information notices), reviews operating experience from 1981 to the present, and incorporates new data from an NRC valve testing program which utilized signature tracing techniques on valves in operating plants. This report also responds to action item 6(i) of the actions directed by the NRC Executive Director for Operations (EDO) to respond to the NRC staff investigation of the June 9, 1985 event at Davis-Besse (Refs. I and 2).

AE00 Report C203 (Ref 3), issued in May 1982, which addressed the valve operator-related events during 1978, 1979, and 1980, included several generic recommendations. The 1982 report identified several events involving defici-encies with settings of torque switches, limit switches and valve operator motor burnout. The major recommendations were: (1) improved methods and procedures for the setting of torque switches should be developed and evaluated relative to valve operability and functional qualification under accident conditions; (2) signature tracing techniques (such as measurement of electrical current and voltage applied to the motor) should be developed and used as part of the inservice test program with the objectives to serve as an indicator of changes in operability characteristics (e.g., aging, inadequate adjustment or maintenance) and a predictor of the remaining margin of failure; (3) the guidance to bypass thermal overload protective devices associated with motor-operated valves should be reassessed; and (4) follow-up action pertaining to IE Circular 77-01, " Malfunction of Limitorque Valve Operators" [ Note: these valves failed to open in a manner similar to the June 9,1985 event at Davis-Besse]shouldbeconductedbecauseeventssimilartotheconcernsidenti-fied continue to be reported, in addition, the issue of valve operator motor burnout was again reviewed in AE0D Report 5503 which was issued in September 1985. That investigation determined that motor burnout was still occurring; it appears to occur more frequently; and recommended expedited implementation of the plans to address motor burnout.

This current study represents an extension and update of the past reports.

Operating events from 1981 to the present that were retrievable from two broad databases were reviewed. The events reviewed included 565 LERs (1981 to the present) from the Sequence Coding and Search System (SCSS) and more than 600 events for 1984 and 1985 from the Nuclear Plant Reliability Data (NPRD) System.

l Review of these data indicates that recent motor-operated valve events involve failures that are similar to those observed in earlier studies and there is no apparent improvement in the rate of failure. Thus, the previous recommendations are still valid. Most of the valve inoperability was associated with items such as torque switch / limit switch settings, adjustments, or failures; motor burnout (over 200 events); improper sizing or use of thermal overload devices; premature degradation related to inadequate use of proteative devices; damage due to misuse (valve throttling, hammerin mechanical problems (loosened parts or improper assembly)g  ; or bypass of valve operate,r);

circuit around the torque switch not being installed or improperly set. In many events, however, the root causes of failure to operate were not specifically

determined and/or reported. Thus, the issue of valve performance and reliability is a complex subject that involves several technical disciplines.

In addition, the review of the data from 1981 to the present suggests two new areas for concern. The area of primary concern involves undetected valve failures. That is, a valve would be deemed operable based on a surveillance test, but actually would not operate during the next demand. An apparently successful surveillance test process can result in a situation in which there is component failure (e.g., motor burnout, operator parts failed, stem disc separation) or improper positioning of overload,torqueswitch,limitswitch)protectivedevices(e.g., thermal that are not detecte1 in the test.

.These failures, or improper positionings, can render the valve inoperable for the next demand and remain undetected because there are inadequate status indication features to alert plant operators about the true condition of the valves. The other new item is associated with reversing the direction of valve motion while it is already being operated, such as attempting to close a valve that was being opened. This process could exceed design requimagents with resultant valve failure, but the scope of this problem cannot be determined from the available data.

The most important conclusion from this study concerning valve assembly operability and performance / reliability is that current methods and procedures at many operating plants are not adequate to assure that motor-operated valve assemblies will operate when needed (e.g., under credible accident conditions).

The limited NRC test program utilizing signature tracing equipment demonstrated there were several safety-related valves in operating plants that exhibited deficiencies which could prohibit valve operation under accident conditions even though the valve had operated under test conditions. The most common deficiencies (see Table 2.2-2) involved incorrect adjustments that were undetected by existing plant procedures intended to assure operability, such as surveillance testing (plant technical specifications and ASME Code,Section XI inservice testing) or operator observations. Thus, assurance of valve operability appears to be strongly dependent upon diagnostic capability to correctly assess and evaluate valve assembly failures to operate so that root causes of failure, including erroneous switch setpoints, are correctly determined and proper changes are implemented.

In summary, operating experience from 1978 through mid-1985 illustrates that (1)valveassemblyfailuretooperatecontinuestobeasafetyconcernwith little improvement in performance / reliability; and (2) current programs and procedures can result in situations in which valves are inoperable when needed, as demonstrated by a recent NRC test program utilizing signature tracing techniques and the June 9, 1985 event at Davis-Besse and plant operators are not aware of this inoperability.

Therefore, AEOD believes that a concerted, high priority licensee ef fort is needed to develop and implement improved guidance, procedures, and/or equipment to address all aspects of safety-related motor-operated valve assembly oper-ability. Acceptable methods are needed to address the issues covered in recommendations 1 through 5 below. The overall goal is that these improved plant procedures and practices be routinely implemented in order to provide assurance of motor-operated valve assembly operability and reliability. If effective licensee action is not forthcoming after a reasonable period of time,

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) perhaps two years or so, regulatory action to address the following recommenda-

, tions should be implemented on an expedited basis. Recommendations are as i follows:

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(1) Effort to implement the recommendations presented in AE00 Case Study

! Report C203 (May, 1982) and AEOD Special Study Report 5503 (September, 1 1985) should be expeditiously implemented.

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l (2) Licensees should be required to establish procedures and diagnostic ,

j capability to determine root causes of failure to operate in order to  ;

j establish programs that will provide assurance of motor-operated valve i assembly performance and reliability under accident conditions.

j (3) Licensees should be required to develop a strong training program to i ensure that appropriate information and instructions are disseminated to operating and maintenance personnel. This effort should receive site i management support.  ;

i l (4) The scope of IE Bulletin 85-03 should be extended to cover all ,

! safety-related motor-operated valve assemblies required to be tested for l operational readiness in accordance with 10 CFR 50.55 a (g).

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1.1 Purpose and Scope

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The issues of valve assembly operability and performance / reliability have been

recognized safety concerns for some time. The primary operability concerns  ;

l relate to proper definition of accident conditions and resultant loads together [

j with adequate demonstration (e.g., functional qualification and surveillance

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testing) that a specific valve assembly can operate under design basis condi- l

' tions. Conversely, the issue of performance / reliability relates to whether the J valve assembly will operate when needed and involves evaluation of operating experience to assess implications about valve assembly performance under off-normal conditions. The term " valve assembly" represents a combination of a

! valve, a valve operator, and functional accessories necessary for valve

) assembly operation as a system. The motive power for the valve operator may be i electric, hydraulic, pneumatic, or mechanical. For this study, the drive source was electric and thus the term " motor-operator" is used. Also, the i operating experience databases have search capabilities dependent upon the I valve operator type which again introduces the terms motor-operator or electric

valve-operator.

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There have been several reviews of operating events associated with valve

~ assembly operability by both NRC and industry groups. Some reviews have

involved a single event while others have assessed several events to identify

, trends and pat; erns. The purpose of this study is to provide an overview of operating expsrience to identify failure modes and to assess valve assembly r performance. The study brings together and reviews previous studies (primarily AEGD reports), reviews operating experience from 1981 to the present, and incorporates new data from a limited test program using signature tracing techniques on valves in operating plants. The intent is to identify data sources, numbers of events, failure medes, and to provide an evaluation of the i operating experience relative to valve assembly performance. This report also

! provides a response to Action Item 6(1) assigned by the ED0 in response to the NRC staff investigation report of the June 9,1985 event at Davis-Besse j (Refs. I and 2),

i 1.2 Background of Operating Experience and previous Reviews i

l Motor-operated valves have been the subject of various studies and actions by r i NRC and the nuclear industry. The NRC actions have primarily been bulletins. l r

f circulars or information notices issued by the Office of Inspection and l Enforcement (IE) and various reports (case studies, special studies,  ;

l' engineering evaluations or technical review reports) issued by the Office for  !

r Analysis and Evaluation of Operational Data (AE00). The initial AE00 report, (Ref. 3), was issued in May 1982. That report provided a survey of .

l valve-operator related events occurring during 1978, 1979, and 1980 together  !

! with a general review of related reports by both NRC and industry groups. As a ,

j result, the report provides both a general review and an assessment of j potential generic valve operator safety issues through 1980. This current ,

study starts from the basic knowledge presented in AEOD/C203 including the  !

I generic recomendations; identifies and reviews subsequent reports, bulletins, i l and information notices; discusses searches of various plant operating event  !

databases from 1981 to the present; and provides an a;sessment of failure i

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o, l redes that affect valve assembly performance. The significant NRC documents associated with (MOVs) that were issued from 1981 to mid-1985 are included in References 4 through 30.

AE00/C203, which was issued in May 1982, provides a summary evaluation of valve motor-operator events through approximately 1980 and makes specific recommendations that would lead to appropriate definition and/or resolution of valve operability problems discernible from operating experience during 1978 through 1980. The investigation found that event causes could be grouped into j three major categories which are torque switch problems, limit switch problems, and motor burnout. The report concluded that these three categories l

represented most of the operational problems concerning performance / reliability or functional qualification. Similar issues were also addressed in IE documents IE IN 82-10 (Ref. 27) and IE Bulletin 81-02 and Supplement 1 (Ref.

29). The primary safety concerns noted in AE00/C203 related to effects of aging l on operability, margin for operability, and availability for operation when needed. Specific recommendations made in the 1982 AE0D study were as follows:

(1) "The existing recommendation to bypass thermal overload protective devices (seeRegulatoryGuide1.106(Reference 31)]associatedwithsafety-related valve motor operators should be reassessed" based on motor burnout events.

(2) " Improved methods and procedures for the setting of torque switches should be developed and evaluated relative to valve operability and functional qualification under accident conditions.... In addition, the initial torque switch settings, including those made during or immediately '

following valve assembly maintenance and subsequent adjustments, should be evaluated relative to operability." The primary concerns relate to whether

" operability under test conditions inplies a known margin exists such that the valve assembly will operate under accident conditions;" and "when l torque switch adjustment is necessary to permit operation under test l conditions, what accountability is there to ensure that margin is adecuate for safe operation under accident conditions."

l (3) " Signature tracing techniques (such as measurement of electrical current and voltage applied to the motor or measurement of the actual valve stem torque or thrust during valve operation) should be developed and tried on l selected valves as part of the periodic inservice testing program. The

! objectives of such methods should be to utilize them as an indicator of I changes in operability characteristics (aging, inadequate adjustment or maintenance, etc.) and a predictor of the remaining margin to failure."

(4) " Additional action pertaining to IE Circular 77-01, ' Malfunctions of Limitorque Valve Operators,' is needed because events similar to the concerns identified in the circular continue to be reported." (Note: The concern and events cited in IE Circular 77-01 involved failure of a valve assembly to open. The failure was similar to the June 9, 1985 event at Davis-Besse in which auxiliary feedwater isolation valves failed to reopen because the bypass around the torque switch was not set properly.)

AE0D/E305 (Ref. 4) was issued on April 13, 1983 and provides a review of eight events that occurred during 1981 and 1982. The report concludes that premature J

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degradation of MOV assemblies is occurring and that the degradation may not be apparent or detected either by or during required surveillance testing. Thus, an M0V may function under test conditions but have a level of degradation that could indicate imminent failure under accident conditions. The events involved I failute of the valves to shut which was attributed to a failed torque switch; l

burned out motors related to inadequate adjustment of a limit switch or torque switch; inadequate motor thermal overload protection; and vibration which loosened a limit switch. Similar issues were also addressed in IE IN 83-46 i

(Ref. 25) and IE IN 84-10 (Ref. 20). The AE00 report identified a need for l improved methods for obtaining appropriate limit switch / torque switch actuation setpoints and the use of signature tracing techniques to monitor and detect degradation.

AE00/E315 (Ref. 5) was issued on July 7,1983. The report provides an evalua-tion of an event that resulted in severe damage to a low pressure coolant injection (LPCI) system injection throttle valve and adjacent pipe supports at l

a BWR plant. The cause of damage was valve throttling outside the optimum range that resulted in severe vibration of the valve and piping system. In addition, approximately 4 months af ter the observed initial damage, l

unidentified effects of this vibration resulted in valve disc separation from l the stem. The valve had been throttled in an attempt to provide continuous l flow through residual heat reaoval (RHR) heat exchangers in the shutdown

! cooling mode and eliminate frequent cycling of inlet and outlet valves to the RHR heat exchangers. The report suggested dissemination of the information in i an IE information notice. Also, the report concluded it was appropriate for l NRR to review the RHR system operation for compatibility with valve assembly l design and qualification requirements as well as the adequacy of the RHR system flow control in the shutdown cooling trode. Similar issues were also addressed in IE IN 83-55 (Ref. 23) and IE IN 83-70 and Supplement 1 (Ref. 21).

l AE00/T410 (Ref. 6) was issued May 10, 1984 The report addressed an event in late March 1982 in which the high pressure coolant injection (HPCI) injection valve failed to fully open during a surveillance test required as part of the plant restart procedures after a refueling outage. The failure to fully open was attributed to omission of an electrical bypass circuit around the torque switch in the valve operator. Subsequent investi ten valves without the bypass circuit installedthis (gation identified represents nearlya 20%

totalofof the valves that were required to have the bypass circuit). In general, absence l

of the bypass circuit will not be detected by the surveillance test program in plant technical specifications or the inservice test program (ASME Code,Section XI). Depending upon operating conditions, the failure mode would ,

normally be failure of the valve to open because the torque switch tripped on  !

high load. The result is similar to the torque switch trip for the two auxiliary feedwater isolation valves that failed to reopen at Davis-Desse (either a low setting on the limit switch for the bypass circuit or omission of the bypass circuit will allow the torque switch to control maximum valve operatorload). IE Circular 81-13, which addressed similar events, was issued several months prior to the event reviewed in T410. Also, an LER for Arkansas Nuclear One Unit 2 involved bypass circuit omission on five valves. S affected by omission of the bypass circuit have been the HPCI system (ystems valves for coolant injection and steam supply to the pump turbine), reactor core isolation cooling (RCIC) system, core spray system, and RHR system (LPCI and

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oo centainment spray modes). Since licensees were not required to report action taken in response to the recommended action in IE Circular 81-13, there was no available data to determine whether the bypass circuits are in place at other plants.

l AE00/T420 (Ref. 7) was issued August 23, 1984. The report provides an evalua-l tion of an event in which an isolation valve in the RCIC system failed to open against reactor operating pressure even though it was designed to open with full differential pressure. The valve affected was an inboard isolation valve on the steam supply to the RCIC pump. After pressure equalization on both

! sides of the valve, the valve was opened. The report also concluded that valve

! failure to open against operating reactor pressure cast doubt on its ability to j close fully against high steam flow differential pressure conditions in a postulated RCIC steam line break outside containment. The study noted that surveillance testing of the valve would not detect such a potential inadequacy and recommended that these implications be considered further after the licensee completed a full examination of the valve assembly failure to operate.

AE0D/E501 (Ref. 8) was issued on January 17, 1985. The report discusses events involving MOV failures due to hammering. This observed mechanical damage was due to a phenomenon experienced by an MOV when it is subjected to repeated closing attempts after it has already reached the fully closed position.

Although only two specific events identified hammering, it was concluded that many MOVs have a typical control circuit that could permit repeated closing attenpts af ter the valve is closed. Herce, hammering could pose a potential generic problem. It was recommended that the report be used as the basis for issuing an information notice [IE IN 85-20 and Supplement I were issued (pef.16).].

AE0D/E502 (Ref. 9) was issued on January 25, 1985. The report provides an evaluation of the failure of an RHR system suppression pool cooling valve to operate by either the motor operator or manual handwheel. The failure to operate was due to a loosened setscrew in the anti-rotation device which

! allowed the anti-rotation device to shift position and caused the valve stem key to shear when the motor operator was started. It was determined that the mechanism could be generic because similar failures were identified on valves supplied by different manufacturers. The report suggested updating IE Information Notice 83-70 to cover valves supplied by those manufacturers not previouslyidentified(!EIN83-70SupplementIwasissued).

AE0D/E506 (Ref. 10) was issued May 20, 1985. The report provides an evaluation l of an event in which a valve stem failure occurred while attempting to manually '

i open the valve from a BWR suppression pool suction line to the loop B residual l heat removal system heat exchanger during a refueling outage. The valve stem material was type 410 stainless steel that had failed by intergranular stress corrosion cracking (!GSCC). The material hardness was higher than had been

! specified and was caused by improper heat treatment. Similar IGSCC valve stem failures were discovered at three other plants. The report suggested that IE issue an information notice and that NRP review the adequacy of ASME code requirements concerning assurance of proper hardness of martensitic stainless steel. Similar issues were also addressed in IE IN 85-59 (Ref.14) and IE IN 84-48 and Supplement 1 (Ref. 17).

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! AE00/E509 (Ref. 11) was issued July 25, 1985. The report provides an

( evaluation of an event involving depressurization of the reactor coolant system j while performing testing of the pressurizer power operated relief valve (PORV).

l The depressurization occurred when the PORV block valve was opened while the relief valve was failed open. The block valve motor operator could not close the valve against system differential pressure. The failure to close against system differential pressure appears to have been caused by an attempt to close the block valve (reverse direction) while it was still traveling in the open direction. The combined forces of momentum, friction and flow that resulted from reversal of valve operation caused torque switch actuation (trip) which stopped the valve in mid-position. The torque switch contacts later closed as load requirements dropped due to system pressure drop and the valve traveled to the closed position. The manufacturer of the motor operator indicated that reversal of direction has the potential to damage some valve operator components.

AE0D/S503 (Ref. 12) was issued in September 1985. The report evaluates recent valve operator motor burnout events. The investigation determined that motor burnout is still occurring and it appears to occur more frequently (180 events for the most recent 4 years compared to 19 events for the 3-year span 1978, 1979, and 1980). Motor burnout is a potentially significant concern because:  :

(1) MOVs are used extensively on safety systems, (2) the failure mechanism can l be common mode failure for a given plant, (3) failure can be undetected for ,

long periods of time, and (4) failure could prevent both motor driven and  ;

manual operation of the valve. The report concludes there is a need to address the lack of motor protection (which appears to result in burnout) and to l reassess Regulatory Guide 1.106 as recommended in AE00/C203. A similar issue was addressed in IE IN 84-13 (Ref. 19).

Additional valve issues not addressed by AE00 studies have been covered by IE l generic communication:, in two areas. One area involves installation or equip-l rrent assembly problems such as a shaft-to-actuator key falling out, loosening of a bearing locknut, incorrect installation of a pinion gear and worm gear

, segment, and use of incorrect material for a motor-to-shaft key. The documents involved are IE IN 85-67 (Ref.13), IE IN 85-22 (Ref.15), IE IN 84-36 including Supplement 1 (Ref.18), IE IN 83 02 (Ref. 26), and IE IN 81-08 (Ref.

28).

The other area involved discrepancies between the valve isolation signals

! listed in the technical specifications and the actual signils found for some l

Group 1 primary containment isolation valves. There was one information notice, IE IN 83-53 (Ref. 24), that discussed discrepancies in initiating ,

l signals for BWR Group 1 primary containment isolation valves.  :

Further,theNRCNuclearPlantAgingResearch(NPAR)Programincludedastudy of MOV assembly failures related to aging and service wear. That information appears in Reference 30 and was developed by ORNL under contract to NRC.

1.3 NRC Efforts in Response to AEOD_ Rep,o_rt_s, s

The AE00 reports reviewed in Section 1.2 contained both suggestions and recommendations. Those reports that were either an engineering evaluation or a

technical review usually received NRC action in the form of an IE information notice. The only AE0D reports that contained specific recommendations for NRC action were AE00/C203 (a case study), (Ref. 3), and AE00/S503 (a special study). The recommendations in S503 were a followup to previous issues raised in C203 relative to valve operator motor burnout. The NRR response to C203 was to incorporate the recommendations as part of the development plan for Generic Issue II.E.6.1, "In-Situ Testing of Valves," and to expand some existing research programs to accommodate a preliminary investigation of setting torque switches. Additionally, RES completed a valve test program using signature tracing equipment (Ref. 32). A brief discussion of the signature tracing program is included in Section 2.2 of this report. Also, Reference 33 indicates the NRR program for Generic issue II.E.6.1 was to have been awarded to a DOE contractor to commence work in November 1985. Subsequently, Reference 34 identified that a new task action plan will be prepared with program completion anticipated by the end of calendar year 1987. That program should address AE00 recommendations in reports C203 and $503.

5 2.0 DISCUSSION AND EVALUATION l

2.1 Review of Previous AE00 Reports The synopsis of AE0D reports presented in Section 1.2 represents the substantial aggregate of NRC efforts pertaining to assessment of MOV performance based on operating experience. Most of the events reviewed were

malfunctions identified during performance of a required component or system test to demonstrate operability. Hence, these test conditions could differ significantly from accident conditions when the valve assembly would be required to perform its safety function. There have been only a relatively few l events, such as with the auxiliary fecJwater isolation valves during the June 9, 1985 event at Davis-Besse, in which actual design basis conditions were present when the valves were required to operate. Even with this limitation, the operating experience can be used to demonstrate that some failure modes or mechanisms could adversely impact valve assembly operation under design basis conditions and to illustrate potential weaknesses concerning whether certain l settings are adequate to provide operation and/or protection.

The AE0D reports identified in References 3 through 12 provide much of the detailed analysis to substantiate the initial recommendations from C203 that are stated in Section 1.2 of this report. A description of some of the back-ground and findings are provided to aid in understanding the complexity of the various issues affecting valve assembly operability. The initial Case Study, C203, determined that approximately 25% of MOV events involved the torque switch as part of the corrective action to return the velve to operability (this included replacing the torque switch, cleaning associated contacts and/or adjusting the torque switch setpoint). In addition, limit switch adjustments were frequently mentioned. It was determined, however, that the torque switch was not a dominant cause of valve assembly inoperability.

Most events in which the valve assembly failed to operate occurred during a required test. Since tha torque switch has the inherent ability for adjustment, it became apparent that torque switch " corrective action," which usually involved increasing the setting, was responding to the symptoms of changes in operating characteristics rather than addressing root causes of valve assembly inoperability. In fact, it also was evident [See item (3), page 17 of Ref. 3.] that the plant operating staff's objective appeared to be to find .

corrective measures to return inoperable equipment to operational status rather than determine root causes of inoperability; i.e., a valve assembly failed to perform correctly during a required operability test and actions were performed r which resulted in the valve assembly passing the test. Hence, the immediate ,

problem was solved, but there was no basis for the new setting which, '

therefore, led to the AE0D recommendation for development of methods and procedures for setting torque switches.

It was also concluded in AE00/C203 that individual plants have only a very few valve operator events related to torque switches (only five plants had more  ;

than three events under reporting requirements at that time). Even though a broad view of several plants identified significant safety concerns about valve assembly inoperability, a specific plant site may have only a few events and may not be aware of either the significance of a given event or potential impending problems. This lack of information in combination with the difficulty l f

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in determining the root cause of inoperability appears to have resulted in the decision to merely make adjustments until the valve operates.

The failure mode associated with the torque switch is failure of the valve to either open or close because motor power was terminated by a torque switch trip. This is effectively a protective trip to prevent damage to the valve or operator internals due to overload conditions. Another type of failure mode identified in AE0D/C203 was motor burnout. This was determined to be related to bypassing of thermal overload devices which are used to protect the motor from excessive current.

Subsequent studies (Refs. 4 through 12) identified other failure modes as follows:

Premature degradation related to inadequate use of protective devices, Damage due to misuse such as throttling of a valve that could lead to excessive vibration and failure.

Failure to operate due to a bypass circuit around the torque switch not being installed,

• Failure to open against a differential pressure.

Hammering of the valve operator due to repeated actuation of the operator based on the control circuit design, Failure of a valve stem caused by intergranular stress corrosion cracking due to excessive material hardness as a result of improper heat treatment (although this was not a valve operator problem per se, valve operation based on valve operator indications and setpoints could appear to be acceptable even though the disc had not moved due to stem failure),

Component damage resulting from a loosened setscrew, and Continued motor burnout events with more than 200 events identified.

The failure modes identified have usually occurred under test conditions that usually are less severe than design basis conditions. However, the most difficult aspect of the failure modes mentioned is that they generally cannot be translated to a specific root cause. The failures have been related to several possible areas that include setting of limit switches and torque switches, inadequate use of protective devices, possible deficiencies in maintenance procedures or methods, incorrect assembly procedures, misuse of equipment, and unanticipated effect of a control circuit. These failures are indicative of a very complex interaction among the diverse features of valve assembly operation. The operating experience illustrates the importance of a thorough understanding of valve assembly operation including the control circuit and protective devices.

2.2 Review of NRC Signatur_o Tracing Test Program Past AE00 studies had recommended development and use of signature tracing techniques (Section 1.2 of this report). Reference 35 documents a request from I

I

the Office of Nuclear Reactor Regulation (NRR) to the Office of Nuclear Regulatory Research (RES) for funding to implement a limited test program utilizing newly developed equipment for signature trace testing of MOVs in cperating commercial nuclear plants. This proposed test program would also address aspects included in Generic Issue II.E.6.1. The objectives for the test program were:

(1) Learn what the signature tracing equipment can provide or determine about safety-related M0V readiness beyond that provided by the inservice testing in accordance with the ASME Code,Section XI.

(2) Identify and characterize the types of abnormalities found during the program utilizing the signature tracing equipment.

The test program utilized a commercially available test system. The testing involved 36 valves at four commercial nuclear plant sites and was conducted through Oak Ridge National Laboratory for RES as part of the Nuclear Plant Aging Research (NPAR) program. The complete report of all tests appears in Reference 32. The test system used is a portable signature analysis device developed for use in the field. The system obtains instantaneous readings of motor-operator characteristic parameters during a valve assembly cycle. These measured parameters are as follows:

Axial displacement of the worm to compress the operator spring pack [this displacement is proportional to the thrust delivered to the valve stem and uses a device called the " Thrust Measuring Device" (TMD)];

Time of actuation of torque and limit switches; and Motor current.

Schematic representations of hypothetical spring pack deflections, switch actuations, and motor currents for M0V open-to-close and close-to-open cycles are represented in Figures 2.2-1 and 2.2-2. Table 2.2-1 describes the significance of various points in Figures 2.2-1 and 2.2-2. This information is reproduced from Reference 32. The table and figures illustrate that valve opening and closing involves a complex sequence of switch actuations, load changes, and motor current changes. Variations or changes in any of these measured parameters may represent either improper settings, incorrect adjustments, or degradations that could adversely impact or prohibit valve assembly operation when needed. Some examples of these issues are discussed in the next several paragraphs to illustrate the complex interactions associated with assurance of valve assembly operability and to provide a basis for understanding and evaluating the operational data presented in later sections of this report.

The degradations, incorrect adjustments and other abnormalities identifiable by this test system were classified as two types: (1) degradation of valve parts which if allowed to progress (time dependent) could lead to MOV failure to operate, and (2) incorrect adjustments or other abnormalities that could either cause degradation of valve parts with ultimate MOV failure, or could directly cause MOV failure to operate under some anticipated operating conditions. A

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the switch-position-indicating device, and the motor current.

See Table 2.2-1 for explanation.

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the switch-position-indicating device, and the motor current.

See Table 2.2-1 for explanation.

1. Table 2.2-1 Interpretation of Valve Signatures in Figs. 2.2-1 and 2.2-2*

Thrust Signature

1. Spring-pack Relaxation The beginning worm position results from the stem thrust remaining from the previous valve operation. As soon as the motor starts, the spring pack relaxes and the worm returns to its zero deflection condition.

Because the spring pack is assisting the motor at this time, this period is short.

2. Zero Worm Deflection During this time interval, the spring pack is in its zero deflection position. The worm gear must make one-half a revolution before contacting the drive sleeve lugs. Meanwhile, the motor is accelerating to operating speed.

3. Hammerblow This thrust transient can occur when the valve stem starts moving, and also when the valve stem initiates movement of the obturator (in the case of some gate valves). Because the load on the stem may be much greater in the closed position, the thrusts at hammerblow are usually greater in the close-to-open cycle. In this example, the hammerblow is large enough to trip the torque switch momentarily. See No. 10.

4. Running Load This is the thrust required to overcome packing and gear friction. In this example, running load is greater than zero because spring-pack preload was less than running load. In many cases, the reverse is true and the TMD output does not reflect running load.

5. Valve Seating [open-to-close cycle only (Fig. 2.2-1)]

At this time in the open-to-close cycle, the valve obturator contacts the valve seat. Motion of the worm changes from all rotational to partly rotational and partly axial, resulting in the slowing down'of the stem as the spring pack is being compressed.

e Y

• Adapted from M0 VATS, Inc. , information brochure.

1. This Table was reproduced from Reference 32.

Table 2.2-1 (continued) i

6. Torque Switch Trip (TST)

The torque switch opens at its setpoint, shutting off power to the motor

[open-to-close cycle (Fig. 2.2-1].

7. Total Thrust The total thrust is the maximum thrust produced by the valve operator at a given setting of the torque switch. This may include inertia over-shoot of the thrust above the torque switch setpoint.

8. Available Thrust The available thrust is that portion of the total thrust useful for seating the valve. It consists of the difference between total thrust of No. 7 and running load of No. 4.

Switch Signatures The various switch positions as recorded by M0 VATS are represented by the width of the bar. In these examples, it is assumed the valve operation is stopped by the torque switch on closing (Fig. 2.2-1) and by the limit switch on opening (Fig. 2.2-2).

9. Both the bypass switch and the torque switch are closed. The bypass around the torque switch allows a momentary torque switch trip to accommodate the thrust from a hammerblow without tripping the motor.

10. The torque switch opens momentarily due to the hammerblow. The motor continues to run because the bypass (limit) switch is closed.

11. The bypass switch opens just after the hammerblow, while the torque switch remains closed. Any subsequent loads in excess of the torque switch setting will open the torque switch and shut down the motor.

12. The limit switch opens and shuts down the motor.

Motor Current Signature

13. The starting current, for an induction motor, is typically 6 times running current.

14. The hammerblow, if sufficiently large as it is in the close-to-open example, may cause a momentary but measurable current increase, as shown in Fig. 2.2-2.

1 l

list of six time dependent degradations and ten other abnormalities appears in Table 2.2-2. In addition, of these latter ten abnormalities, the six marked with an asterisk (*) can be considered as a type of abnormality that could cause valve failure to operate under certain operating conditions. For each abnormality the percentage of the 36 tested valves that exhibited that abnormality is also listed in Table 2.2-2.

The test results indicate that the three most common abnormalities (improperly set bypass switch, incorrect torque switch calibration, and unbalanced torque switch) involved incorrect adjustments of torque switches and limit switches (Table 2.2-2). The most frequently observed abnormality was an improperly set bypass limit switch which was found in 75% of the valves tested. (This was the same problem discovered with the auxiliary feedwater valves at Davis-Besse in Ref. 2. ) Each of these three commonly occurring abnormalities could result in valve failure to operate under certain conditions. It is significant to note that the six items marked with an asterisk (*) in Table 2.2-2, indicating a potential to cause valve failure to operate under certain conditions, were the most frequently occurring abnormalities discovered in the test program.

An explanation of the potential impact on valve operability for each of the 16 abnormalities listed in Table 2.2-2 is provided in Section 4 of Refer-ence 32. A brief discussion of the six abnormalities identified with an asterisk (*) in Table 2.2-2 will be provided below to enhance understanding of factars that can affect valve gerability. The intent is to understand the physical relationship between settings, surveillance or inservice testing, and potential effects when operating conditions (such as an accident) change. The six abnormalities are excessive packing tightness, excessive spring pack gap, loose stem nut locknut, unbalanced torque switch, incorrect torque switch calibration, and improperly set bypass limit switches.

Excessive packing tightness generally results in increased friction force losses in moving the valve stem in the packing. The normal torque switch setting should be selected to account for friction loads due to gearing, friction of the disc along guides, differential pressure loads, normal packing friction, and an operating margin load. However, if the packing deteriorates, the stem lubrication changes, or the packing is tightened to prevent steam or water leakage, the force required to overcome the friction can increase significantly above the normal load requirements. Since the torque switch settings are established to permit a maximum load application from the spring pack, any increased force necessary to overcome packing friction will result in a reduced thrust available for the valve to accomplish the intended function.

This could result in valve failure to close for isolation or open for injection due to a trip on maximum torque switch setting. Since open and close settings may differ significantly, the effect on valve operation could vary accordingly.

The normal preload on the spring pack is such that, when assembled in the motor operator, no gap should exist between the spring pack and the shoulder that holds it in place. If a spring pack gap exists, it permits rotation of the torque switch without a corresponding displacement of the spring pack so that the delivered thrust does not correspond with the setting on the torque switch.

The spring pack gap will cause the torque switch to trip at a delivered thrust that would be lower than anticipated with the torque switch setting based on no

1. Table 2.2-2. Sumary of Abnormalities Detectable by MOVATS Classified by Type Percent Percent Time Dependent with Incorrect Adjustments and with Degradations Abnormality Other Abnormalities Abnormality Bent stem 0 Excessive inertia 8 Gear wear 6 Inadequate stem lubrication 0 Motor pinion binding 0 Improper seating 0 Stem wear 8 Valve backseating 8 Grease haroening P

• Incorrect torque switch calibration 50 Motor degradation 3

• Unbalanced torque switch 33

• Excessive spring pack gap 17

• Excessive packing tightness 8

• Improperly set bypass switch 75

• Loose stem nut locknut 8

• Abnormalities which can cause valve failure under some anticipated operating conditions.

1. This Table was reproduced from reference 32.

gap. Thus, there is a possibility for valve assembly failure to close or open in situations where little margin exists between delivered thrust and thrust required for operation.

A loose stem-nut locknut would be reflected as a change (increase) in the time period between the initial hammerblow and when the disc unseats, which causes a second hammerblow, on a close-to-open cycle. This second hammerblow is not shown on Figure 2.2-2 because it is not needed to illustrate the concept of the signature tracing technique. However, this second hammerblow occurs because of the physical clearance or separation necessary in the disc and stem joint for reversing the direction of valve stem thrust. If the locknut becomes loose enough, the second hammerblow could be delayed so that the bypass switch may not provide protection against premature tripping of the torque switch. This could result in valve assembly inoperability when needed for performance of a safety function.

Torque switches can be installed in a manner such that ecual torque switch trip settings for close and open give actual thrust loads that are not equal and thus unbalanced. This abnormality can be detected by determining the actual amount of thrust which trips the torque switch in each direction by utilizing the stem thrust and control switch signatures. The practical effect of unbalance is that the actual thrust delivered is different from that

O anticipated from the setting on the torque switch. The actual thrust would be higher in one direction than the other for a given setting. For a low thrust value, the valve may fail to complete its stroke. A high thrust could lead to excessive closure loads, damage to various valve components, thermal overload actuation or motor damage, or possible failure to open after excessive closure thrust. The test program found approximately 33% of the valves had unbalanced torque switches.

Incorrect torque switch calibration can result in a valve stem thrust for a given setting that does not correspond to that given in the manufacturer's specifications. The abnormality can be determined by direct comparison of stem thrust by use of a load cell and torque switch setpoint. Incorrect torque switch calibration can lead to several types of problems because actual stem thrust load would be different than anticipated by the torque switch setting.

If the stem thrust was low, a valve may fail to isolate or complete its stroke.

In this situation, operation under surveillance test conditions may indicate acceptable performance, but high load conditions of an accident may result in inoperability due to incorrect torque switch calibration. An abnormally high stem thrust can lead to damage to the obturator or seat, mechanical degradation, actuation of thermal overload protective devices or motor burnout, or damage to other valve components with a potential for valve assembly failure to operate. The test program found approximately 50% of the valves tested had incorrect torque switch calibration.

The most prevalent abnormality detected during the test program was an improperly set limit switch to bypass the torque switch which was found in 75%

of the valves. During the normal close-to-open cycle for a valve, there is a hammerblow load that may be very high and thus could exceed the torque switch setting such that valve assembly operation would stop on a torque switch trip.

The mechanism to prevent such a trip is to install a limit switch to bypass around the torque switch protection (even though the torque switch could still actuate) so the bypass will still allcw operation of the valve operator motor.

If a bypass limit switch is set to terminate too early, the torque switch could deenergize the control circuit. A hammerblow or other unanticipated increased load, such as differential pressure over a portion of valve stem stroke that exceeded the torque switch setting, would cause a torque switch trip, and the valve assembly would cease operation. This was the cause of the failure of the auxiliary feedwater valves to reopen in the June 9,1985 event at Davis-Besse (Ref. 2).

The diagnostic information discussed in this section and Reference 32 clearly illustrates that the test system used can provide valuable information relative to valve assembly operational readiness that is well beyond that obtained from (ASME Code,Section XI) surveillance tests.

The test results from this limited NRC test program appear to be representative of observed data from several other plants. Information presented at the meeting of the ACRS Subcommittee on Reliability (Valves) on March 19, 1985 (Ref. 36) provided test data for a much larger number of valves. That data illustrated a broader distribution of deficiencies among the six abnormalities identified in the NRC test program. However, the expanded test data substantiate these six abnormalities as potential factors which adversely affect valve assembly performance and reliability.

2.3 Review and Discussion of Databases Since a primary purpose of this study was to provide an assessment of M0V failure modes on a generic basis, the general approach was to take a broad view to identify potential events. Section 1.2 of this report provides a perspective of past NRC studies. The conclusions and recommendations from previous NRC efforts have identified many areas that adversely impact valve assembly operability. The databases used to obtain M0V events for this current study were SCSS and NPRDS.

The SCSS database was initiated in 1981. The search of SCSS identified a total of 565 events involving electric motor operators from 1981 through mid-1985. A list of the number of events for each plant by year together with the totals for 1981 through 1985 is shown in Table 2.3-1. The information in Table 2.3-1 appears consistent with past reviews such as AE0D/C203 (Ref. 3) in that very few plants report five or more events in a given year. Also, the total number of events per year for 1981, 1982 and 1983 are relatively similar (160, 127, 200) followed by a significant drop in reported events (56 and 22) for 1984 and 1985. The drop in number of events is probably the result of new reporting requirements of the LER Rule that became effective on January 1,1984. More than 30 plants out of 83 reporting had no events reported for both 1984 and 1985.

There were 43 systems affected by the 565 LERs reported by the 83 plants. A list of the systems with more than ten reported events is shown in Table 2.3-2.

These 13 systems (including the category of unknown) account for over 500 of the 565 reported events. Hence, these 13 systems accounted for over 88% of the reported events while the remaining 30 systems account for less than 12% of the reported events.

A search of the NPRDS database for electric valve operator failures was conducted to determine the number of events reported during 1978 through 1985.

The number of events by year is shown in Table 2.3-3. The number of reported events from 1978 through 1982 was about 100 events per year. From 1981 through mid-1985 there were just over 1100 events reported (in contrast to 565 LER events). Furthermore, the data appears consistent with the new LER reporting requirements beginning on January 1, 1984, in that reports of electric valve operator failures increased significantly in 1984 to approximately four times the rate for 1978 through 1982.

The large number of NPRDS reports as well as limited utility participation in reporting to the NPRDS prior to 1984 raised several questions in attenoting to identify which plant systems were most affected. Since relatively bred utility participation only began after about January 1, 1984, and mord than 600 of the total reports were submitted during 1984 and the first 6 months of 1985, it was decided to limit this review to those r,eports submitted to NPRf15 during 1984 and 1985. This approach appears reasonatile based on the fact that the LER data system was the primary failure reporting databese prior to 1984 and AE0D closely monitored these LERs. Hence, the best available data appear to be covered by a review of all LERs from 1981 through 1985 and a review of NPRDS reports for 1984 and 1985. Hence, each NPRDS report for 1984 and 1985 was reviewed. The distribution of NPRDS events in terms of percentage of reports  ;

that involved specific systems appears in Table 2.3-4. -

Table 2.3-1 LERs for Electric Motor-0perated Valves During 1981 - 1985 (SCSS)

Count on LERs Submitted Facility Docket 1980 1981 1982 1983 1984 1985 Total Yankee Rowe 29 0 1 1 0 0 0 2 Big Rock Point 155 0 0 4 1 1 0 6 San Onofre 1 206 0 1 1 0 1 0 3 Connecticut Yankee 213 0 1 0 1 0 1 3 Oyster Creek 219 0 5 3 1 2 1 12 Nine Mile Point 1 220 0 2 0 0 0 0 2 Dresden 2 237 0 5 7 9 2 1 24 Ginna 244 0 0 0 1 2 0 3 Millstone 1 245 0 2 3 0 3 0 8 Indian Point 2 247 0 0 0 5 0 0 5 Dresden 3 249 0 2 0 4 1 1 8 Turkey Point 3 250 0 0 0 0 1 0 1 Turkey Point 4 251 0 0 2 3 2 0 7 Quad Cities 1 254 0 2 1 5 1 0 9 Palisades 255 0 1 0 0 1 0 2 Browns Ferry 1 259 0 0 1 0 1 1 3 Browns Ferry 2 260 0 2 0 1 0 0 3 Rcbinson 2 261 0 2 1 1 0 0 4 Monticello 263 0 3 4 1 0 0 8 Quad Cities 2 265 0 3 2 1 1 2 9 Point Beach 1 266 0 2 0 1 0 0 3 Oconee 1 269 0 1 1 1 0 0 3 Oconee 2 270 0 0 0 1 0 0 1 Vermont Yankee 271 0 3 4 4 0 0 11 Salem 1 272 0 1 0 0 1 0 2 Diablo Canyon 1 275 0 0 0 1 0 3 4 Peach Bottom 2 277 0 2 0 1 1 0 4 Peach Bottom 3 278 0 2 2 2 0 1 7 Surry 1 280 0 2 1 3 0 0 6 Surry 2 281 0 5 5 4 2 1 17 Prairie Island 1 282 ,.0 1 0 0 0 1 2 Oconee 3 287 13 1 0 2 0 0 3 Pilgrim 1 293 3 2 4 8 2 0 16 Zion 1 295 *) 0 2 2 0 1 5 Browns Ferry 3 296 0 7 0 2 2 1 12 Cooper 298 0 4 1 0 0 0 5 Crystal River? 3 302 0 6 3 5 0 0 14 Zion 2 304 0 1 1 3 0 0 5 Kewaunee 305 0 5 2 4 0 0 11

! Maine, Yankee 309 0 0 2 3 2 0 7 Salem;2 311 0 1 0 0 1 0 2 Rancho Seco 312 0 5 0 3 1 1 10 Arkansas Nuclear One 1 313 0 2 1 3 0 0 6

O O

Table 2.3-1 (continued)

Count on LERs Submitted Facility Docket 1980 1981 1982 1983 1984 1985 Total Cook 1 315 0 4 5 1 0 0 10 Cook 2 316 0 1 1 3 2 0 7 Calvert Cliffs 1 317 0 1 1 2 1 0 5 Calvert Cliffs 2 318 0 4 0 2 0 0 6 Three Mile Island 2 320 0 0 0 1 0 0 1 Hatch 1 321 0 1 4 7 0 0 12 Shoreham 322 0 0 0 0 0 1 1 Brunswick 2 324 0 9 1 4 2 1 17 Brunswick 1 325 0 2 3 4 0 0 9 Sequoyah 1 327 0 5 1 2 1 0 9 Sequoyah 2 328 0 2 0 1 1 0 4 Arnold 331 0 2 5 2 2 0 11 Fitzpatrick 333 0 4 2 3 3 0 12 ,

Beaver Valley 1 334 0 4 2 5 0 0 11 St. Lucie 1 335 0 1 3 0 0 0 4 Millstone 2 336 0 2 5 2 1 0 10 North Anna 1 338 0 2 1 .5 2 0 10

Ncrth Anna 2 339 0 2 3 5 1 0 11 Trojan 344 0 4 0 2 0 0 6 Davis-Besse 1 346 0 3 1 5 0 0 9 i

Farley 1 348 0 2 0 4 0 0 6 Limerick 1 352 0 0 0 0 0 2 2 San Onofre 2 361 0 0 5 4 1 0 10 San Onofre 3 362 0 0 0 7 0 0 7 Farley 2 364 0 0 1 2 0 0 3 Hatch 2 366 0 9 6 11 0 0 26 Arkansas Nuclear One 2 368 0 3 8 3 0 0 14 McGuire 1 369 0 8 1 2 1 0 12 McGuire 2 370 0 0 0 2 1 0 3 LaSalle 1 373 0 0 3 7 1 0 11 LaSalle 2 0 0 0 374 0 0 1 1 j Susquehanna 1 387 0 0 1 8 1 0 10 Susquehanna 2 388 0 0 0 0 1 0 1 St. Lucie 2 389 0 0 0 1 0 0 1 Summer 1 395 0 0 2 0 0 0 2 WPPSS 2 397 0 0 0 0 1 0 1 Lacrosse 409 0 0 1 0 0 0 1 Catawba 1 413 0 0 0 0 0 1 1 Grand Gulf 1 416 0 0 2 6 1 0 9 Wolf Creek 1 482 0 0 0 0 0 1 1 TOTALS 0 160 127 200 56 22 565

i Table 2.3-2 Reported LERs for Specific Systems System Number of LERs Percent of Total

1. Containment Isolation 153 27.1

2. Residual Heat Removal (BWR) 53 9.4

3. Essential Raw Cooling / Service Water 47 8.3

4. Auxiliary Feedwater (PWR) 44 7.8

5. Residual Heat Removal (PWR) 36 6.4

6. Containment Spray 29 5.1

7. High Pressure Coolant Injection (BWR) 28 5.0

8. Low Pressure Core Spray (BWR) 24 4.2

9. Reactor Core Isolation Cooling (BWR) 26 4.6

10. Chemical and Volume Control (PWR) 22 3.9

11. Pressurizer (PWR) 17 3.0

12. Condensate and Feedwater 13 2.3

13. Unknown 13 2.3 Table 2.3-3 NPRDS Reports for Electric Valve Operator Events During 1978 Through 1985 Year Number of Reported Events 1978 80 1979 77 - 256 1980 99 _

1981 105 1982 109 1983 246 1120 1984 439 1985 221 s i

l

s Table 2.3-4 Distribution of NPRDS Reports for Specific Systems System Percent of Total Reports

1. RHR/LPCI/ Decay Heat / Containment Spray 27.5

2. Essential Service Water / Nuclear Service Water 15.0

3. HPCI/HPSI 11.6

4. AFW/EFW 8.5

5. Main Steam 7.6

6. Primary System 6.9

7. RCIC 4.8

8. Containment Isolation 4.2

9. CVCS 3.4

10. Feedwater 3.1

11. Condensate 2.1

12. Low Pressure Core Spray 2.1

13. Component Cooling Water 1.9

14. Other 1.4 The most significant difference between the SCSS event data, Table 2.3-2, and the NPRDS event data, Table 2.3-4, appears with the events in the containment isolation system. From SCSS, 27.1% of the events were attributed to the containment isolation system while NPRDS identified only 4.2% of the events as involving this system. Further investigation revealed that the SCSS identifies 43 systems which interface with the containment system. That is, an event could involve a valve which served a dual function as part of a plant system such as RHR, HPCI, etc., as well as functioning in the containment isolation system. However, it appears that the NPRDS data would identify the plant system in which the valve served rather than the containment isolation function. Such a scenario appears plausible and, with this explanation, the event distribution by system from SCSS and NPRDS then are quite similar even though the events generally do not overlap.

Further comparison of SCSS and NPRDS event data for the systems affected (Tables 2.3-2 and 2.3-4) reveals information that was not recognized from previous studies. In both databases, events involving essential service water / nuclear service water rated second and third in terms of percentage of total reports. The data was not available in sufficient detail to determine whether the reported failures in these service water (SW) systems differed from those in the other systems.

2.4 Evaluation of NPRDS Event Data As indicated in the previous section, each 1984 and 1985 failure in the NPRDS database that involved electric motor operators was reviewed to identify the system involved. That review was extended to include an evaluation of the NPRDS fields: "cause of failure," " failure description," and " corrective action," in an attempt to assess and establish problem areas. The evaluation procedure involved the application of background knowledge and experience of

POV design, operation and failure modes to interpret narrative descriptions to identify major problem categories. Table 2.4.-1 identifies these categories together with the percentage of events in each category. The primary difficulty encountered during the review was that the narrative descriptions were often too brief and were frequently inadequate or inconsistent concerning how a valve failed and the stated failure cause. Further, in most instances, the narrative descriptions do not include additional discussion to provide information about operating conditions or circumstances of the failure to cperate which would suggest the root cause of inoperability.

The problem categories shown in Table 2.4-1 were generally provided as the cause of failure or the reason for inoperability of a valve assembly. Although the "cause of failure" cited certainly could prevent operability of a valve assembly, past experience and previous AE0D studies suggest that many of these categories actually represent symptoms rather than the underlying or " root" cause of valve assembly inoperability. For example, Category 1 identifies that an out of adjustment torque or limit switch was cited in 28.5 percent of the reports. This was previously identified by AE0D in Reference 3 (also discussed in Section 2.1) as a symptom of the problem rather than the cause.

That is, the plant staff utilized a torque switch or limit switch adjustment as the corrective measure to permit an inoperable valve assembly to pass a valve operability test. Further, categories 2 and 3, which represent 37.1 percent and 13.3 percent of the reports respectively, also appear to be symptoms rather than root causes. For example, many of the category 2 items (i.e.,

mechanical damage, lubrication, loose connections, cleaning contacts, broken bolts, and wear) appear to be related to something that was not done, not done Table 2.4-1 NPRDS Event Problem Category Problem Category (Cause of Failure) Percent of Total i

1. Torque / limit switch out of adjustment 28.5%

2. Mechanical damage, lubrication, loose 37.1%

connection, clean contracts, broken bolts, wear

3. Burnout /high current /TOL device not 13.3%

shut off or trip, motor failed or grounded

4. Torque / limit switch defective, 9.3%

replacement, preventive maintenance

5. Miscellaneous 9.0%

6. Breaker trip, fuse blow, coil bad 2.8%

l

• correctly, inadequate procedures, inadequate maintenance, or operational condition effects such as vibration or environment. Similarly, category 3 items, involving burnout, high current, thermal overload device not shutting off or tripping, and motor failed or grounded, appear indicative of component degradation or overload conditions that should have been investigated and resolved prior to the eventual motor failure. Thus, it appears that nearly 80 percent (categories 1, 2, and 3) of the NPRDS data may be indicative of symptoms rather than root causes of failure. The reported information, however, does not contain sufficient detail about the operating conditions to permit an indepth review or independent evaluation needed to determine the true' root cause of failure.

In summary, the number of reported events identified in Tables 2.3-1 and 2.3-3 indicate that NPRDS motor o failures reported in LERs (perated valve failure reports outnumber the MOVin the SCS 1984 and 1985. Since very few NPRDS reportable failures are contained in LERs for SCSS, by design, NPRDS currently represents the preponderance of individual component operating data for now and the foreseeable future. The data distribu-tion by the categories presented in Table 2.4-1 suggests that identification of potential safety issues pertaining to either individual events or detection of possible trends or patterns that warrant indepth evaluation may be a very difficult task because the available information does not adequately describe operating conditions which would be needed to evaluate the true root cause of j the reported failures.

2.5 Evaluation of SCSS Event Data i The SCSS database search identified 565 events. Each LER abstract was reviewed. Since AE0D had performed several evaluations of events in this time frame (Refs. 3 through 12) and has been monitoring these events, the review concentrated on icentification of: (1) events that were representative of failure modes simiiar to those identified previously; (2) events indicative of the complexity of identification of root cause of failure; or, (3) events that appear to represent new failure modes or different aspects not previously

! realized. Hence, the intent was to concentrate on later years (1984 and 1985)

!' as much as possible. Based on the three criteria described above, a total of 72 events were identified and are represented in Appendix A. Each event is presented by docket number, plant name, LER number, and a brief description of the event. The events in Appendix A involve 43 operating plants which imply a relatively broad spectrum of approximately 50% of the operating plants. The reports involve 43 events at 20 BWR plants and 29 events at 23 PWR plants.

The number of events by year used in Appendix A is given in Table 2.5-1. Also from the table, it is apparent that events which occurred during 1983, 1984, and 1985 are the most frequently cited in Appendix A. Although the total number of events (56 during 1984 and 22 during 1985) reported to SCSS has decreased drastically, the percentage of the total reported events considered significant increased to 43% in 1984 and 32% in 1985. However, without the experience and knowledge developed during past evaluations using a much larger

number of available events, it is doubtful whether such a small number of events would be sufficient to substantiate significance. In addition, Table 2.5.2 shows that the total number of valve reports to both SCSS and NPRDS has increased during 1983, 1984 and 1985 (the 1985 data represents approximately the first 6 months of the year) even though the reports to SCSS have decreased.

Table 2.5-1 Distribution of SCSS Events in Appendix A by Year Number of Events Number of Events in Appendix A Reported Year Number / Percent of Total Reported 1/1% 160 1981 7/6% 127 1982 200 1983 33/17%

24/43% 56 1984 1985 7/32% 22 (about 6 months) 565 Total 72/13%

Table 2.5-2 Distribution of Reported Valve-Operator Events Number of Reports Number of Reports Total in SCSS in NPRDS Year 105 265 1981 160 109 236 1982 127 246 446 1983 200 439 495 1984 56 22 221 243 (about six months) 1985 Previous NRC studies (Refs. 3 through 30) provide examples of several valve assembly failures to operate. These studies were identified in Section 1 and discussed in Sections 2.1 and 2.2 of this report. As discussed, the failure or damage mechanisms that have resulted in valve assembly failure to operate are as follows:

Torque switch / limit switch related settings, adjustment, failures, Motor burnout (more than 200 events identified),

• Thermal overload device use, sizing, and bypassing.

l l

A,

• Premature degradation related to inadequate use of protective devices,

• Damage due to misuse such as throttling of a valve which could lead to excessive vibration, Failure to operate due to a bypass circuit around the torque switch not being installed, Failure to open against differential pressure.

• Hammering of the valve operator due to repeated actuation of the operator based on the control circuit design, Failure of valve stem due to intergranular stress corrosion cracking (improper material heat treatment),

Component damage due to loosened setscrew.

The events listed in Appendix A generally provide examples of the failure modes identified above. A broad interpretation is that recent operating experience

~

illustrates that the same types of problems continue to occur. This result raises concerns relative to why corrective efforts do not appear to have been effective in solving, or at least in reducing the number of valve assembly failures to operate. A review of some of the events in Appendix A seems to point toward a situation involving very complex interactions of competing requirements that affect valve assembly operability.

Examples of torque switch / limit switch settings that led to valve assembly inoperability are given in Appendix A items 13, 18, 20, 23, 27, 38, 39, 40, 41, 51, 52, 57, 61, and 69. These events involved several different types of failures such as motor burnout, failure to lift off the seat, or thermal overload device trip; but all were associated with settings of torque switches and limit switches. Hence, determination of the root cause of inoperability can be a very difficult task. Similarly, items 22, 48, and 54 are examples of events in which extensive investigation was unsuccessful in assessing the root cause of failure. These types of events seem to suggest that the diagnostic capability of the signature tracing equipment discussed in Section 2.2 of this

• report would be a useful adjunct for failure analysis. Conversely, investigation procedures may alter or destroy the cause of increased loads that prevent operability so that the incentive to determine the root cause is diminished because the valve subsequently operated.

This search identified one event at Davis-Besse that appears to be a precursor to the June 9, 1985 event. During the June 1985 event, the isolation valves, AF-599 and AF-608, for the auxiliary feedwater system failed to reopen after being closed. Item 59 in Appendix A, which was reported in LER 346/84-003, describes an event that involved AFW isolation valve AF-599 on March 2, 1984.

The event description indicates the event included a Steam and Feedwater Rupture Control System (SFRCS) actuation on low steam generator pressure to close isolation valve AF-599 to steam generator #2. When an attempt was made to reopen isolation valve AF-599, the valve failed to open. The valve was opened manually, no mechanical problems were found, and the valve operatedThe properly. Failure to open was attributed to the torque switch setting.

original torque switch settings were 1.5 for both open and close. The

corrective action was to change the close setting to 1.0 and leave the open setting unchanged at 1.5. Although the previous close setting of 1.5 on the torque switch could have contributed to increased load requirements to open the valve during the March 1984 event, the June 9, 1985 event suggests that reset-ting the close torque switch did not address the root cause of valve failure to open. This was eventually discovered to be an incorrectly set torque bypass limit switch. Thus, this 1984 event at Davis-Besse provides further evidence of the importance of the task to identify and correct root causes of valve assembly inoperability.

There have been several other valve failures to operate in the auxiliary feedwater (AFW) system at Davis-Besse. A schematic of the AFW system is shown in Figure 2.5-1 (reproduced from Ref. 2). The normally open isolation valves, AF-608 and AF-599, were the valves that failed to reopen due to a high differential pressure after inadvertent closure in the June 9,1985 event.

Also, isolation valve AF-599 failed to reopen after an SFRCS actuation to close on a low steam generator pressure signal on March 2, 1984 (the precursor event discussed above) due to a high differential pressure. The other events have involved the normally closed injection valves (whose safety function is to open to provide water to the steam generators) and the steam supply valves to the turbine driven auxiliary feedwater pumps. The affected valves were injection valves (three of the four) AF-3870, AF-3872, AF-3869, and steam supply valve

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MS-106 which is not shown in Figure 2.5-1. These events were discussed in .

! Reference 3 (see items 2, 3, 4, and 6 on page 47). The eventual cause of inoperability during a component test for AF-3870 and AF-3872 was found to be a I high differential pressure across the valve which was the result of leaking

• downstream check valves. Also, part of the corrective action (see item 3, page 47 in Ref. 3) was to adjust the limit switch to set the bypass around the torque switch to prevent a trip of the torque switch when lifting the disc off the seat. These latter events were all part of the bases to support the AE00 recommendations in Reference 3 (1982) to develop proper procedures to set torque switches and to develop and implement signature tracing techniques to assess valve assembly readiness for operability.

The issue of determining whether proper setting of the limit switch to bypass the torque switch was the cause of inoperability has another aspect involving whether or not the bypass circuit was actually installed. This issue was discussed in Reference 6 in which 10 valves were found to have been in service for several years without the bypass circuit installed. Required testing had not identified this condition. One valve failed to operate during a required startup test and that event in conjunction with IE Circular 81-13 alerted the licensee to the nine other valves. In addition, items 66 and 67 in Appendix A identify a similar discovery of five valves at another plant. It appears that most of these valves had performed acceptably during surveillance tests until some adverse conditions developed. Even then, the root cause of the missing bypass circuit was not identified until after knowledge of the missing bypass circuits had been disseminated. These events further illustrate the operational aberrations that can complicate determination of the root cause of valve assembly failure to operate.

Evaluation of the event data in Appendix A also suggests a new or previously unrecognized aspect of valve assembly failure to operate. The issue of interest pertains to situations in which the valve motor operator would be

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SERVICE AF.3870 u

WATER l '

N = To oTSo si u AF l AF.360 3869 CST 9

AF i i FROM mm

"' 3871 DEAREATOR

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N = To oTSo n2 AF AF AF.388 599 3872 h #2 SERVICE WATER Figure 2.5-Ruxiliary Feedwater System *

• This is a schematic of the AFW System at Davis-Besse (reproduced from Ref. 2).

O incapable of operating during the next demand while the plant operating staff i was not aware of this inoperability status. The primary safety concerns involve: (1) the state of readiness of the valve for operability during the

next demand; (2) the possibility that inservice testing could leave the valve with an undetected failure following a test to demonstrate operability; and (3) the potential for inadequate or deficient procedures or equipment to detect either failed valves (or valve operators), or that the valve assembly together with the control circuit will not permit operation during the next demand.

? Some clear examples of these concerns are illustrated in items 24, 58, 63, j and 69 in Appendix A. Item 58 involved a trip and throttle valve that failed i

to operate on January 3, 1984 during a test, and rendered one train of the auxiliary feedwater system inoperable at Trojan. The motor thermal overload (TOL) devices were found tripped. Grease had apparently prevented the torque i switch from actuating to de-energize the motor when the valve was last closed on November 23, 1983. Since the motor continued to run, the TOL device tripped to protect the motor and rendered the valve inoperable. Thus, the valve was i

inoperable, without being detected, for approximately 40 days until discovered during the next surveillance test. The corrective action was to install a

- thermal overload alarm in the control room to indicate when the TOL trips.

j Item 63 involved a service cooling water return valve at Farley 2 that was i found closed and rendered diesel generator 2B inoperable. The valve in

i question had been closed to perform a timed stroke test. When the valve was to reopen following the timed closure, it appears that excessive current draw caused the power supply breaker to trip open. The valve was found closed 3ll 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> after it was thought to be open which represents an undetected failure. The operators were not aware that the valve was in the closed position because of a lack of independent main control room board position indication. In addition, a plant operator failed to perform a required local verification. Thus, human error, in conjunction with the lack of an alarm, resulted in a situation where the diesel generator was unavailable, a fact that was unknown to the plant operators.

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' Item 69 involves inoperability of an M0V that controls cooling water flow to the

! HPCI lube oil cooler and barometric condenser. The flow control valve would not open from the control room. Investigation revealed the motor was burned out. When the valve was last closed, it appears that the torque switch failed

! to open at the specified torque; therefore, the motor continued to run and burned out due to excessive torque with locked rotor current. The TOL bypass i circuit design was found to give in erroneous indication in the control room if l the MOV test / bypass switch was returned to the bypass position prior to r

actuation of the TOL devices because no alarm would occur (IE IN 84-13 was issued on this event). This test / bypass switch arrangement was an approach to comply with the guidance in Regulatory Guide 1.106 (Reference 31). However,  ;

the event indicates that implementation of the guidance could result in the

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j undesirable situation in which the valve was incapable of operating on the next i demand, and that fact could not be detected by plant operators. The proposed corrective action was to wait about 30 seconds after completing the test and then place the switch in the bypass position from the test position. ,

l Whether 30 seconds is sufficient time for a TOL device to respond (trip or  !

I alarm) to an overcurrent condition for the valve operator motor is questionable. Although the time required to receive a TOL trip was not i

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mentioned in most events, available data suggests a time delay on the order of minutes rather than seconds. In particular, item 24 in Appendix A identifies "about 10 minutes" before loss of power was indicated. Also, based on discussions with NRC staff at the site, it appears that for the event in item 69 (and also in IE IN 84-13), actual operator practice may involve extending the 30-second interval to about 2 minutes before placing the switch in the bypass position from the test position. This will provide improved detection capability in case an undesirable condftion develops. Furthermore,  !

the time needed for a TOL device to trip appears to be a very complex determination that could depend on several variables such as the TOL sizing -

criteria, motor capacity relative to normal operating levels, and the form of valve assembly degradation or failure (the failure mechanism may result in normal current rather than overload current).

Thus, these four events (24, 58, 63, and 69), clearly demonstrate an apparent deficiency or inability to detect the state of readiness of the valve assembly and control circuit for operability during the next demand. There also is evidence that the undetected failures occurred during the performance of a required surveillance test to demonstrate operability, and the valve was left in a condition in which it would not operate during the next demand. Examples

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of similar behavior are provided in items 5, 6, 13, 14, 15, 17, 20, 23, 24, 26, 30, 32, 33, 37, 40, 41, 49, 62, 68, and 72 in Appendix A.

The potential failure mechanism identified in Reference 11 that involved PORV g block valve failure with the valve in mid-position resulted from an overload trip caused by reversing the operating direction in mid-stroke. This appears to be a relatively recently identified failure mode. The reference also identified an earlier failure at another plant due to stroke reversal that resulted in motor burnup. However, the previous events identified motor burnout and mechanical damage that could occur because the valve operator

> component designs may not account for such demands. The primary concern is that this operating behavior appears to be very difficult to identify so that it could occur and plant operators may not be aware of such behavior. Also, j since this type of operational response depends upon the control circuitry, there is a potential for unanticipated damage to valve operators depending upon whether, or how, the reverse signal takes precedence over a previously applied signal for valve action. We have no available data to assess the potential

extent of this failure or damage mechanism.

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A recent event at Catawba (Ref. 37), which occurred after the time frame of the database searches for this study, provides additional insight about the relatively high rate of valve problems identified in service water systems that were mentioned in Section 2.3 (page 24). This event involved loss of both trains of the nuclear service water system (SW) for more than 40 minutes at a PWR plant due to a common mode failure mechanism. During inservice tests, which are conducted quarterly, the pump discharge isolation valve on each SW system train was reported as stopped in an intermediate position. The reported corrective action was to increase the torque switch setting to 2.75 from 1.5 for each valve because "the lower setting may not be sufficient to fully cycle the valves under all system alignments due to back pressure across the valves."

, Discussion: with plant staff about this event revealed that the actual position of the discharge valves was unknown and could have been between just off the seat to intermediate. Also, these valves have a bypass circuit around the

O torque switch for the open cycle. In addition, even th] ugh the Unit 1 SW discharge valve assemblies failed to open, SW flow to Unit 1 may have been provided by SW flow from Unit 2 SW pumps that were running and were shared with Unit 1 (at the time of the event, Unit 2 was not licensed but the SW pumps were running). Therefore, although not mentioned in the LER, these SW system valve assembly failures to open against differential pressure appear similar to the June 9, 1985 failures at Davis-Besse (Ref. 2). The Davis-Besse failures were caused by a combination of differential pressure and incorrect setting of the bypass limit switch around the torque switch. It should be noted that the nuclear service water valves which failed at Catawba are outside the scope of IE Bulletin 85-03: " Motor-0perated Valve Common Mode Failures During Plant Transients Due to Improper Switch Settings" (Ref. 38).

A significant safety concern pertaining to SW systems was addressed in IE Information Notice 86-11. " Inadequate Service Water Protection Against Core 4 Melt Frequency," (Ref. 39) that was issued on February 25, 1986. The information notice indicated that failure of all essential service water (ESW) may be an accident initiating event that could lead to core melt. The specific concern raised by the information notice involved insufficient redundancy in the ESW which could cause the component cooling water (CCW) system to heat up and trip the CCW pumps in 6 minutes. Without CCW, the reactor coolant pump seals may fail and cause a loss-of-coolant accident (LOCA). The ECCS pumps needed to mitigate the ensuing LOCA, might also fail without CCW. Therefore, the presence of a common mode failure mechanism for the ESW pump discharge valves would create a situation that is worse than iradequate redundancy.

Thus, it would appear that there is a sufficient basis to broaden the required operability demonstration to valve assemblies in additional systems, such as the ESW, that are not presently covered by the scope of IE Bulletin 85-03.

- As a followup to that Bulletin, a recent event illustrates the need for both licensee caution and thorough investigation before implementing the requirements in IE Bulletin 85-03 as well as the apparent inadequate scope of the Bulletin.

The event, which is discussed in IE Information Notice 86-29 (Ref. 40), involved modification of a limit switch setting to bypass the torque switch that led to a valve failure which contributed to an excessive cooldown rate at a PWR plant.

- The valve motor-operator torque switch bypass setpoint on the shutdown cooling system heat exchanger isolation valves had been adjusted (increased) to approxi-

! mately 16% of stroke travel because of concerns raised in IE Bulletin 85-03.

The motor-operators on these valves are protected from overload t'y torque switches. The bypass setting had been established so that increased torque required to initially open the valves against high differential pressure would not result in deenergizing the motor operator on a torque switch trip. However, due to the design of the valve assembly control circuitry, the torque switch bypass limit switch and the valve closed position indicating limit switch are on the same rotor. Therefore, changing the setting to extend the range (percent of stroke travel) of the torque switch bypass also affected the closed position indication in the control room. Therefore, when the indicating light implied the valve was closed, the valve was actually open about 16% of full stroke. Thus, plant operator action to stop the valve in accordance with the close light indication, when the valve was actually partially open, subse-quently led to excessive cooldown because the shutdown cooling system heat exchangers were not isolated. This event therefore demonstrates the importance of thoroughly understanding the motor operator design prior to implementing

modifications and points out the potentially inadequate scope of IE Bulletin 85-03. It also illustrates the limitations of the two-rotor limit switch assemblies.

Further evidence of the breadth of valve assembly inoperability among safety systens can be observed from Tables 2.3-2 (LERs for Specific Systems) and 2.3-4 (NPRDS Reports for Specific Systems). The intent is to compare the percentage of events involving systems explicitly covered by IE Bulletin 85-03 (high pressure coolant injection / core spray and emergency feedwater systems) and the percentage of events that involve other systems. The LER events for the IE Bulletin 85-03 systems (items 4, 7, 9 and 10 in Table 2.3-2) total only approximately 21 percent of all reports whereas other significant safety systems (RHR/LPCI/ Low Pressure Core Spray / Decay Heat / Containment Spray / Containment Isolation /Essert'al Service Water) total over 60 percent of all reports (items 1, 2, 3, 5, 6, and 8 in Table 2.3-2). In the NPRDS reports, approximately 25 percent of all reports involve systems covered by IE Bulletin 85-03 (items 3, 4, and 7 in Table 2.3-4) whereas other significant safety systems total approximately 49% of all reports (items 1, 2, 8 and 12 in Table 2.3-4). The combined data indicates that events with valve assembly inoperability involve systems covered by IE Bulletin 85-03 in just under 25 percent of the reports. Conversely, significant safety systems not covered by

! the Bulletin are involved in over 50 percent of the reports (about a 2 to 1 I ratio). Thus, the data appears to provide a strong basis for extending the scope of IE Bulletin 85-03 to cover these other significant safety systems.

1 2.6 Signature Tracing Tests at Davis-Besse As a result of the June 9,1985 event at Davis-Besse that involved multiple valve failures, the licensee decided to use signature tracing equipment to test more than 160 safety-related MOVs. Preliminary data from the signature tracing i tests was obtained from the licensee and is presented in Table 2.6-1. The table shows the type of degradation identified; the number of valves tested for that degradation; the number and percent of tested valves that had the degradation; and the percent of valves tested in other nuclear plants that exhibited this type of degradation. This latter percentage that is termed

" Industry Average" includes other nuclear plant valves tested with this type of signature tracing equipment and was obtained from a much larger sample than just the valves at Davis-Besse. Since not every valve was tested for each degradation, it is not possible to provide a specific number of valves involved in the " Industry Average." However, the suppliers of the signature tracing equipment, M0 VATS, Inc. indicated that depending upon the specific degradation, the number of valves tested was approximately 300 to 400 valves. Further, the tests involved valves at more than 27 nuclear plants. The data in the column under " Industry Average" was obtained from reference 41.

The three degradations in Table 2.6-1 with the greatest percentage of valves affected (marked with an asterisk, *) were also three of the top four degrada-tions identified in the NRC signature tracing tests (see Table 2.2-2 in Section 2.2). Each degradation was identified as an abnormality that can cause these safety-related valves to fail to operate under some credible anticipated operating conditions. Further, the incorrectly set close-to-open bypass limit switch and the unbalanced torque switch were the two most comon degradations identified in the " Industry Average" data. Thus, the available data suggests

. Table 2.6-1 Preliminary Results from Signature Tracing Tests of s Safety-Related Motor-0perated Valves at Davis-Besse Degradation No. of Valves No. of Dec radations Industry #

Tested Founc: /% Average, %

Close-to-open bypass 118 20/17% * (30)

Valve was advertently 118 5/4% (9) backseating Operator design 70 4/6% (13) thrust exceeded Torque switch 70 2/3% (27) setting excessive

- Torque switch 70 5/7% (17) j setting inadequate l Torque switch 38 26/68% * (80)

found unbalanced i

Spring pack gap 118 19/16% * (21)

High motor current 118 6/5% (6) 150% of rated I

High running load 70 6/8% (6) i

! Excessive inertia 118 4/3% (9)

Loose wormshaft locknut 118 1/1% (1)

Spring pack concern 118 2/2% (3)

Torque switch 118 8/7% (10) mechanical problem

. Operator gear wear 118 1/1% (7)

Seating concern 118 1/1% (3) i Unseating concern 118 1/1% (5)

Limit switch 118 1/1% (2) mechanical problem

1. This data was obtained from reference 41.

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4 these degradations are widespread and generic to the nuclear industry, although <

this is not generally recognized by iicensees nor identified by conventional j testing methods now in use.

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3.0 FINDINGS AND CONCLUSIONS The intent of this study was to provide a generic review of operating experience to address valve assembly performance and identify failure modes where possible. As discussed in previous sections of this report, the general approach used to accomplish the assigned task was to utilize past reports as a starting point; identify and review more recent operating events; and combine the past events, reports and recommendations with a review of the current operating events to provide a comprehensive assessment of valve assembly operability and performance. The AE00 findings pertaining to motor-operated valve assemblies are listed below.

3.1 Findings l (1) The recent M0V events involve failures that are similar to the failures addressed by past AE0D reports (case studies, special studies, engineering evaluations and technical reviews) and Office of Inspection and Enforcement documents (bulletins, circulars, and information notices).

Thus, inoperable valves continue to pose potential safety risks and the i.

recommendations in AE0D/C203 (Ref. 3) and AE00/S503 (Ref. 4) are still i valid. These reports were issued in May 1982 and August 1985,

! respectively.

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! (2) Not all licensee programs on operating experience assessment are I thoroughly assessing valve assembly malfunctions, determining the root cause of problems, and taking the necessary corrective actions on all applicable valve assemblies.

(3) Motor-operated valve assembly inoperability (failure or damage) has been manifested by the following:

Torque switch / limit switch related settings, adjustments, failures, f Motorburnout(over200 events).

Thermal overload device use, sizing, and bypassing.

Premature degradation related to inadequate use of protection devices.

Damage due to misuse such as throttling of a valve which could lead

. to excessive vibration (damage to the valve, valve operator, and piping support system).

Bypass circuit around the torque switch was not installed.

Failure to open against differential pressure.

Hammering of valve operator due to repeated actuation of the operator caused by the control circuit design.

• Valve stem failure due to intergranular stress corrosion cracking.

• Valve operator component damage due to loosened setscrews.

(4) Recent event data involving undetected valve assembly failures suggest a pattern that leads to a reduction in confidence level concerning the state of readiness for valve assembly operability during the next demand. This may manifest itself as actual component failure (motor burnout, operator parts failed, stem disc separation, etc.) or improper positioning of pro-tective devices (thermal overload, torque switch, limit switch, etc.)

such that the failure occurs during or soon after an apparently successful surveillance test to demonstrate valve performance. However, these failures, or improper positioning, that render the valve inoperable can remain undetected for extended time periods because of inadequate alarm or status indication features for the plant operators.

(5) There have been a few M0V failures related to reversing the direction of motion for an operating valve while in service. The events identified have involved manual actuation in which plant operators tried to close a valve while it was in the process of opening. The process of reversing direction of motion may involve a loading condition that was not consider-i ed in the design process; however, the type of control circuit can affect

'I whether such reversal can occur.

(6) There are several parameters or factors that can influence whether a valve

.n can operate or will perform when needed. This complex interaction involves: proper definition of applicable loads, setting of various switches, use of various protective devices, consideration of potential leaking between systems or other conditions that produce differential pressure, proper definition of friction loads, maintenance practices, control circuitry, and operator actions. Therefore, diagnosis to

' determine root causes of inoperability involves a thorough understanding of equipment operation, system load conditions, equipment and control circuit design, and diagnostic capability (knowledge and equipment). The I

event data indicate there are widespread inadequacies in diagnostic cap-abilities at operating plants and thus there is uncertainty concerning

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' the performance of safety-related, motor-operated valve assemblies under off-normal (i.e., accident) conditions.

' (7) The limited NRC test program, which used a commercially available signature tracing test system, demonstrated that: (1) this type of system could be useful for assessment and evaluation of valve inoperability; and (2) there were several safety-related valves in operating plants that exhibited deficiencies which could prohibit valve operation under accident conditions. These deficiencies were not detected by existing plant

, procedures tests or plant suchtechnicalas surveillance specificationstesting)(either or plant operatorASME, Section XI in observations.

In addition, preliminary data from valve tests at the Davis-Besse plant support this finding. The valve testing at Davis-Besse was conducted with the same type of signature tracing equipment used in the NRC test program, and the number of valves tested was about triple the number (in most <

l degradation categories) included in the NRC program.

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l (8) The operating data suppor ts the need for the requirements in the recently i issued IE Bulletin 85-03: " Motor-0perated Valve Common Mode Failures i During Plant Transients Due to Improper Switch Settings" (Ref. 38). l this study also illustrates that the However, the data reviewed deficiencies may take many formsduring(more than those addressed in the bulletin) and can affect safety-related valves in many systems [e.g.,

safety injection (intermediate pressure), low pressure core spray, LPCI mode of RHR, containment isolation, and service water] that are not specifically addressed by the bulletin.

(9) The information contained in NPRDS reports on M0V events is generally not descriptive enough to identify potential failure modes, safety issues, or possible damage or failure mode trends or patterns.

3.2 Conclusions The overriding conclusions from this study concerning valve assembly operability and performance / reliability are that the data demonstrates current methods and procedures at many plants are not adequate to assure that valves will operate when needed and that this issue of performance and reliability is a very complex subject which involves several technical disciplines. It is apparent that valve assembly operation during surveillance testing, under conditions which are less arduous than actual operating conditions, can and has provided a false sense of security about valve performance and reliability. Although there have been few examples of valve assembly failure to operate when needed, the June 9,1985 event at Davis-Besse in which auxiliary feedwater isolation valves failed to open illustrates the potential safety concerns. As discussed in Section 2.5, one of these valves failed to operate under actual demand conditions, when needed, in both 1984 and 1985. The first failure to operate was investigated, corrective action was implemented, and the valve was declared operable after a successful operability test under conditions that were less severe than actual demand conditions. Further, the test data presented in Tables 2.2-1 and 2.6-1, which was obtained with signature tracing equipment testing of valves in several nuclear plants, indicates a widespread or common I mode operability problem because a high percentage of the safety-related M0Vs exhibited abnormalities or degradations that could cause failure to operate i

under some anticipated conditions.

I Therefore, assurance of operabil.ity appears to be strongly dependent upon the diagnostic capability to assess and evaluate failures to operate so that root causes of failures are determined correctly. In this context, the data clearly

' demonstrates there is a need for the capability to determine the actual setpoints of switches because incorrect settings can render valves inoperable.

These steps in turn require a thorough understanding of equipment operation, system interaction loads, and procedures to set switches and protective devices. The entire process requires close cooperation among service technicians, equipment designers, plant systems and component engineers, plant operators, and plant management.

Thus, the evidence of widespread and diverse operability problems suggests the need for a concerted nuclear industry wide program to develop and implement improved guidance, procedures, and/or surveillance equipment to address all aspects of motor-operated valve assembly operability. The program should be a r

coordinated effort involving the equipment users (utilities) and product t

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Q designer or manufacturer (for both the valve operator and the valve body) and should draw upon individual expertise (specialists), NSSS vendor owners groups, other industry groups, and national standards groups as appropriate. The program result should be industry-wide implementation of acceptable and uniform methods for setting torque switches and limit switches, general and specific maintenance requirements, training and instruction requirements and procedures, inspection requirements, repair requirements, surveillance testing re-quirements, quality control, signature tracing requirements, and guidelines for root cause determination of inoperability. The improvement program should also encourage and/or require good communication among licensees to foster wide dissemination of specific valve problems which are identified, together with the root cause and corrective actions. The lessons learned from these plant-specific experiences should be fedback into the appropriate procedures or standards for use by all licensees. The overall goal for this industry wide program is to develop uniform guidance, procedures and/or equipment which licensee management would adopt with confidence, and which field personnel could implement consistently and effectively. The result of such a program would be that motor-operated valve assemblies would operate with the high degree of reliability needed to assure a high level of plant safety.

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4.0 RECOMMENDATIONS AE0D believes that a concerted, high priority licensee effort is needed to develop and implement improved guidance, procedures and/or equipment to address all aspects of safety-related motor operated valve assembly operability.

Acceptable methods are needed to address the issues covered in recommendations 1 through 5 (see below). The overall goal is that these improved plant specific procedures and practices be routinely implemented in order to provide assurance of valve assembly operability and reliability. It is envisioned that the development of improved methods will utilize individual expertise (specialists), licensee owners groups, industry groups, and national standards

. groups as appropriate.

If effective licensee action is not forthcoming after a reasonable period of time, perhaps two years or so, regulatory action to address the following recommendations should be implemented on an expedited basis.

(1) Effort to assess and implement the recommendations in AE0D Reports C203 (Ref. 3,1982) and S503 (Ref. 4,1985) should continue and be expedited.

This is currently scheduled for consideration as part of Generic Issue II.E.6.1. For completeness, a synopsis of those recommendations follows (items a, b, and c, were covered in AE0D/C203 and item d was covered in

• AE0D/S503):

(a) Improved methods and procedures for the setting of torque switches, including initial settings and setting adjustments made during or following maintenance or surveillance tests, should be developed and evaluated relative to valve operability and functional qualification i l under accident conditions. The primary concerns relate to whether 1 operability under test conditions implies existence of a known margin

such that the valve assembly will operate under accident conditions i and, when torque switch adjustment is necessary for operation under test conditions, what accountability is there to ensure adequate

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margin exists for operation under accident conditions.

(b) Signature tracing techniques (such as measurement of electrical current and voltage applied to the valve operator motor or measurement of the actual valve stem torque or thrust during valve

' operation) should be developed and tried on selected valves as part of the periodic inservice testing program. The objective of such methods should be to utilize them as an indicator of changes in 1

> operability characteristics (aging, inadequate adjustment or maintenance, etc.) and a predictor of when the remaining margin to failure is insufficient.

(c) Additional action pertaining to IE Circular 77-01, " Malfunctions of Limitorque Valve Operators" is needed because events similar to the i concerns identified in the circular continue to be reported. (Note:

The concern and events cited in IE Circular 77-01 involved valve assembly failure to open that was caused by an improperly set bypass around the torque switch which was similar to the auxiliary feedwater isolation valves that failed to reopen during the June 9, 1985 event atDavis-Besse.)

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D (d) Based on additional review and identification of more than 200 valve operator motor burnout events, we recommend expedited implementation of the NRR proposed plan to address motor burnout, including reassessment of Regulatory Guide 1.106.

(2) Licensees should be required to develop procedures and diagnostic capability to determine root causes of failure to operate in order to establish programs that will provide assurance of M0V assembly performance and reliability under accident conditions. The programs should include issues such as definition of system accident loads; determination of differential pressures; settings of various switches; use of protective devices and alarms; maintenance practices; surveillance test procedures; control circuitry; degradation mechanisms; a thorough understanding of equipment operation; and critical features and complex interactions that can result in valve assembly degradation or failure.

(3) Licensees should be required to develop a strong training program to ensure that appropriate information and instructions are disseminated to operating and maintenance personnel. Further, since assurance of valve assembly performance and reliability involves issues that require interdisciplinary efforts among service technicians, equipment designers,

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plant systems and component engineers, plant operators, and plant management; it is incumbent upon site management to support this effort.

The training program should include the issues covered by recommendation 3.

(4) Since valve assembly operability problems are diverse and involve many safety systems, the scope of IE Bulletin 85-03 should be expanded to cover all safety-related M0V assemblies required to be tested for operational readiness in accordance with 10 CFR 50.55 a (g). This will at least l address valve assemblies that were identified for inclusion in the

/' inservice test program.

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5.0 REFERENCES

4

. 1.s Memorandum from W. J. Dircks to H. R. Denton, et. al., " Staff Actions Resulting~from the Investigation of the June 9 Davis-Besse Event" (NUREG-1154), August 5,~ 1985.

.s .

2. 0.S. Nuclear Regulatory Commission, NUREG-1154,'" Loss of Main and Aux'iliary Feedwater Event at the Davis-Besse Plant on June 9,1985."

3. U.S. Nuclear Regulatory Commission, E. J. Brown and F. S. Ashe, " Survey of Valve Operator Related Events Occurring During 1978, 1979, and 1980,"

AE0D/C203, May 1982.

( 4. U.S. Nuclear Regulatory Commission, E. J. Brown and F. S. Ashe,

" Inoperable Motor Operated Valve Assemblies Due to Premature Degradation of Motors and/or Improper Limit Switch / Torque Switch Adjustment,"

AE0D/E305, April 13,1983.

5. ' U.S. Nuclear Regulatory Comission, E. J. Brown, " Misuse of Valve

,m Resulting in Vibration and Damage to the Valve Assembly and Pipe Supports," AE0D/E315, July 7, 1983.

+ -

6. U.S . Nuclear Regulatory Commission, E. J. Brown, " Injection Valve for the I, High Pressure Coolant Injection (HPCI) System Failure to Open During A Surveillance Test," AE0D/T410, May'10, 1984.

7. U.S. Nuclear Regulatory Commission, P. Lam, " Failure of an Isolation Valve of the Reactor Core Isolation Cooling System to Open Against Operating Reactor Pressure," AE0D/T420, August 23, 1984.

! 8. U.S. Nuclear Regulatory Commission, M. Chiramal, " Motor-Operated Valve i Failures-Due to Hammering Problem," AE0D/E501, January 17, 1985.

9. U.S. Nuclear Regulatory Comission, C. Hsu, " Failure of RHR Suppression Pool Cooling Valve to Operate," AE0D/E502, January 25, 1985.

10. U.S. Nuclear Regulatory Comission, C. Hsu, " Valve Stem Susceptibility to IGSCC Due to Improper Heat Treatment," AE0D/E506, May 2, 1985.

11. U.S. Nuclear Regulatory Commission, R. G. Freeman, " Salem Unit 2 Depressurization Event," AE0D/E509, July 25, 1985.

~

12. U.S. Nucleir Regulatory Commission, E. J. Brown, " Evaluation of Recent Valve Operator Motor Burnout Events," AE0D/S503, September 1985.

. 13. U.S. Nuclear Regulatory Commission, IE Information Notice 85-67,

" Valve-Shaft-to-Actuator Key May Fall Out of Place When Mounted Below

, . Horizontal Axis," August 8, 1985.

[ 14. U.S. Nuclear Regulatory Commission, IE Information Notice 85-59, " Valve Stem Corrosion Failures," July 17, 1985.

i

15. U.S. Nuclear Regulatory Commission, IE Information Notice 85-22, " Failure of Limitorque Motor-0perated Valves Resulting from Incorrect Installation of Pinion Gear," March 21, 1985.

16. U.S. Nuclear Regulatory Comission, IE Information Notice 85-20,

" Motor-0perated Valve Failures Due to Hamering Effect," March 12, 1985.

(Also, 85-20 Supplement I was issued on May 14,1985.)

17. U.S. Nuclear Regulatory Comission, IE Information Notice 84-48, " Failure of Rockwell International Globe Valves," June 18, 1984. (Also,84-48 Supplement I was issued November 16,1984.)

18. U.S. Nuclear Regulatory Commission, IE Information Notice 84-36, (Also,

" Loosening of Locking Nut on Limitorque Operator," Ma11, 1984.)y 1, 1984.

84-36 Supplement I was issued on September

19. U.S. Nuclear Regulatory Comission IE Information Notice 84-13

" Potential Deficiency in Motor-Operated Valve Control Circuits and Annunciation," February 28, 1984.

20. U.S. Nuclear Regulatory Commission, IE Information Notice 84-10,

" Motor-0perated Valve Torque Switches Set Below the Manufacturer's Recommended Value," February 21, 1984.

- 21. U.S. Nuclear Regulatory Commission, IE Information Notice 83-70,

" Vibration-Induced Valve Failures," October 25, 1983. (Also,83-70 Supplement I was issued March 4, 1985.)

22. U.S. Nuclear Regulatory Commission, IE Information Notice 83-65,

• " Surveillance of Flow in RTD Bypass Loops Used in Westinghouse Plants,"

October 7, 1983.

23. U.S. Nuclear Regulatory Commission, IE Information Notice 83-55,

" Misapplication of Valves by Throttling Beyond Design Range," August 22, 1983.

24. U.S. Nuclear Regulatory Commission, IE Information Notice 83-53, " Primary Containment Isolation Valve Discrepancies," August 11, 1983.

25. U.S. Nuclear Regulatory Commission, IE Information Notice 83-46, l " Common-Mode Valve Failures Degrade Surry's Recirculation Spray Subsystem," July 11, 1983.

26. U.S. Nuclear Regulatory Commission, IE Information Notice 83-02, "Limitorque H0BC, H1BC, H2BC, and H3BC Gearheads," January 28, 1983.

27. U.S. Nuclear Regulatory Commission, IE Information Notice 82-10,

" Follow-Up Symptomatic Repairs to Assure Resolution of the Problem,"

March 31, 1982.

28. U.S. Nuclear Regulatory Commission, IE Information Notice 81-08,

" Repetitive Failures of Limitorque Operators SMB-4 Motor-to-Shaft Key,"

March 20, 1981.

29. U.S. Nuclear Regulatory Commission, IE Bulletin 81-02, " Failure of Gate Type Valves to Close Against Differential Pressure," April 9, 1981.

(Also, 81-02 Supplement I was issued August 18,1981.)

30. NUREG/CR-4234, Volume 1, " Aging and Service Wear of Electric Motor-0perated Valves Used in Engineered Safety-Feature Systems of Nuclear Power Plants,"

June 1985, by ORNL.

31. U.S. Nuclear Regulatory Commission, Regulatory Guide 1.106, " Thermal Overload Protection for Electric Motors on Motor-0perated Valves,"

Revision 1, March 1977.

32. ORNL/NUREG/CR-4380, " Evaluation of the Motor-0perated Valve Analysis and Test System (M0 VATS) to Detect Degradation, Incorrect Adjustments, and Other Abnormalities in Motor-Operated Valves," January, 1986.

33. U.S. Nuclear Regulatory Commission, Memorandum from H. R. Denton to C. J.

- Heltemes, " Evaluation of Recent Valve Operator Motor Burnout Events,"

November 8, 1985.

34. U.S. Nuclear Regulatory Commission, Memorandum from H. R. Denton to C. J.

Heltemes, " Peer Review Comments on AE0D Preliminary Case Study - A Review of Motor-0perated Valve Performance," June 6, 1986.

35. U.S. Nuclear Regulatory Commission, Memorandum from H. R. Denton to R. B.

Minogue, "Use of Signature Tracing Techniques to Detect Degradation or Incorrect Adjustments of Safety Related Motor Operated Valves," May 14, 1984.

36. U.S. Nuclear Regulatory Commission, ACRS Subcommittee on Reliability

' Assurance (Valves), " Meeting Minutes of March 19, 1985."

37. LER 413/85-068-01, "Both Trains of Nuclear Service Water Inoperable Due to Low Torque Settings on Valves," Report dated January 2, 1986 for Catawba, Unit 1.

38. U.S. Nuclear Regulatory Commission, IE Bulletin No. 85-03: " Motor-

Operated Valve Common Mode Failures During Plant Transients Due to l

Improper Switch Settings," November 15, 1985.

i 39. U.S. Nuclear Regulatory commission, IE Information Notice 86-11,

" Inadequate Service Water Protection Against Core Melt Frequency."

, February 25, 1986.

40. U.S. Nuclear Regulatory Commission, IE Information Notice 86-29, " Effects of Changing Motor-0perator Switch Settings," April 25, 1986.

41. A. G. Charbonneau, " Signature Analysis Field Testing Results of Motor-0perated Valves," Proceedings - International Meeting, Nuclear Power Plant Maintenance held March 23-27, 1986 at Salt Lake City, Utah, Idaho Section of ANS, page 10-46.

s' APPENDIX A - MOTOR OPERATED VALVE EVENTS FROM SCSS Docket and LER Event Description Plant Number 84-013 While shutting the plant down for repairs, the MSIV failed to close on

1. 155 the manual close signal. The valve had stopped near the beginning of Big Rock Point the stroke on a torque switch trip. The torque switch had been set l below the manufacturer's recommended setting.

Main steam drain valves V-1-106, 107, and 110 failed to operate in the

2. 219 84-031 partially open position. Valves V-1-106 and 107 were closed by Oyster Creek placing a bypass around the control circuitry while V-1-110 was closed manually. Each valve stopped in the partially open position because of a torque switch trip.83-024 A review of historical data on torque switch setpoints revealed that

3. 219 the torque switches were set below the manufacturer's recommended Oyster Creek setpoint. IE Information Notice 84-10 was issued on this report.85-020 While performing HPCI steam line high flow isolation surveillance, the

4. 237 HPCI 2301-4 inboard isolation valve failed to close. Upon investi-Dresden 2 gation, dirty breaker auxiliary contacts were found.

The operator gear

5. 237 84-003 Core spray valve M0 2-1402-25A failed to operate.The cause of failure was hamme housing had failed.

Dresden 2 from repeated actuation signals to close the valve due to the control circuit, after the valve was already closed.83-083 Low pressure coolant injection valve 1501-3B tripped on thermal over-

6. 237 load. Underrated thermal overload devices were in use because a Dresden 2 recent installation of environmentally qualified motors had overlooked a change in thennal overload requirements.

Docket and LER Plant Number Event Description

7. 237 83-052 Shutdown cooling return valve M0 2-1001-5A failed to open. The motor Dresden 2 on valve M0 2-1001-5A was burned out due to water dripping from valve 2-1501-22A which had a packing leak.

8. 237 82-033 RWCU valve M0 2-1201-3 failed to close and was subsequently closed Dresden 2 manually. Cause appears to be a sticky limit switch contact that bypasses the torque switch in the close direction and a lack of lubrication on the valve stem.

9. 237 82-030 HPCI steam supply isolation valve 2301-4 failed to close. Caused Dresden 2 because motor shorted out due to a packing leak in which water entered the valve operator motor.

10. 237 83-024 Core spray test valve MO 1402-4A failed to open. After several Dresden 2 attempts, TOLs tripped. Motor was found burned out.

11. 244 84-005 RHR suction valve M0V-700 failed to open while attempting to go to Ginna shutdown on 5/14/84. Inspection subsequent to manual unseating revealed the packing gland flange had shifted to come in contact with the valve stem. Contact resulted in torque switch trip.

12. 244 84-002 RHR suction valve M0V-700 failed to open while going to cold shutdown Ginna on 3/3/84. Following manual unseating, the valve was stroked several times. The most probable cause was a dry stem or light torque switch setting.

13. 245 84-018 On 3/3/84, operation of outboard isolation condenser condensate return Millstone 1 valve, I-IC-3, became erratic. Subsequently, the motor overloaded and the circuit breaker began to smoke. Out-of-adjustment limit switch caused motor to run beyond the full closed position with extensive motor damage and valve failed in the full closed position.

14. 245 84-015 On 7/9/84, while restoring valve lineup after an Isolation Condenser Millstone 1 Functional and Calibration Test, the isolation condenser isolation valve, 1-IC-3, motor TOL and 125 volt dc ground alarms annunciated in I

i- ,

l Docket and LER Plant Number Event Description

' the control room. Out-of-adjustment limit switch caused motor to run after disc reached full closed position and motor was extensively damaged, and subsequently failed in full closed position.

15. 249 83-011 During LPCI system valve operability test, LPCI suction valve Dresden 3 M0 3-1501-5A failed to close on 3/14/83. Cause of failure to operate was mechanical overload which broke the operator housing. Cause of overload was not determined (see item 5 for Dresden 2 for a similar failure).

16. 250 84-035 Source of leakage to pressurizer relief tank was determined to be Turkey Point 3 block valve, M0V-3-535 that would not close upstream from PORV, PCV-3-456. The torque switch prevented complete closure. The breaker contacts that energize the valve operator were manually manipulated to .

drive the valve fully closed. The torque switch was replaced.

17. 254 84-014 During a refueling outage, it was determined that both LPCI injection Quad Cities 1 valves, 1-1001-29A and 1-1001-29B would not open. This was discovered in the process of starting the shutdown cooling mode of RHR. Residual heat removal was accomplished with the RWCU system and RHR system with valve 1-1001-298 25 percent open. Cause was hammering which resulted due to incorrect wiring diagram used to install the control circuit.

18. 254 83-038 The HPCI turbine steam supply valve, MO 1-2301-3, failed to open. The Quad Cities I limit switch contact which bypasses the torque switch opened prematurely.

19. 259 85-015 While attempting to throttle RHR loop II pump discharge valve, there Browns Ferry 1 was no indication of valve movement. The intermediate gear assembly spline teeth had sheared.

J

20. 259 84-012 Could not go to cold shutdown because RHR valve FCV 1-74-48 failed to Browns Ferry 1 open. The motor was found burned out. The close torque switch was set higher than recommended causing overtightening during closure.

s' 4 Docket and LER Plant Number Event Description

21. 265 84-014 HPCI isolation occurred while being run at low speed. When reset, Quad Cities 2 valve M0 2-2301-4 failed to open.

22. 265 83-011 While testing the RHR return to the suppression chamber valve, Quad Cities 2 M0 2-1001-36B, the circuit breaker overloads tripped repeatedly while attempting to open the valve. The valve was manually opened.

Attempts to correct the problem included replacing the circuit 1 breaker, disassembling the motor operator, replacing the entire circuit breaker, and decreasing the close torque switch setting (has operated successfully since decreasing the setting). Valve failed to operate eight times over a 4-week period.

23. 266 81-004 During IST, containment spray valve failed to open. Motor stopped on Point Beach TOL trip. The closing torque was excessive due to out-of-adjustment closing torque switch.

24, 271 82-014 Outboard RWCU system isolation valve, V12-18, would not open. The

Vermont Yankee TOL was found tripped. Valve was manually lifted off the seat. One-half hour later, the TOL was reset and the valve opened electrically.

About 10 minutes later, there was loss of indication on V12-18 and an 3

RWCU pump trip. The valve breaker was tripped and the motor had failed.

25. 271 82-013 Containment isolation valve CU-lb failed to seat satisfactorily.

i' Vermont Yankee Cause of failure was failure of the closing torque switch.

26. 272 84-021 Containment isolation valve received close signal, but would not Salem I reopen on operator demand (open light did not come on). The TOL device was jumpered in the control circuit which implied no TOL protection. The stem nut was not staked such that the valve never closed and motor kept running and burned out, i

! 27. 275 85-002 In an attempt to prevent a low-low SG level reactor trip, the operator Diablo Canyon 1 tripped the main turbine and reduced reactor power. During the event, the turbine driven AFW pump, AFW1-1, could not be started when inlet valve, FCV-95, did not open on manual demand. The limit switches were adjusted.

Docket and LER Event Description Plant Number

28. 277 85-001 While preparing for a diesel generator outage, "B" RHR injection Peach Bottom 2 valve, M-2-10-1548, failed to reopen after being closed. Simultaneous loss of valve position indication and overcurrent alarm. Valve stuck in closed position. TOL device melted due to stuck motor contactor in MCC which resulted in trip of motor circuit breaker. Cause was a warped bakelite coil and core housing which mechanically prevented the contactor from releasing.

29. 278 83-002 During leak rate testing, the HPCI isolation valve failed to fully Peach Bottom 3 close due to solidified grease in the valve operator gear train.

During back-up ECCS system testing, RCIC throttle valve motor T0Ls tripped. Orderly shutdown was initiated.

30. 282 85-010 During startup, the reactor tripped on low steam generator level.

Prairie Island During FW supply transfer from AFW to main FW, the FW pump was started and the discharge valve open signal was given. The not closed limit switch activated and dual position lights indicated the valve had begun to open, but in fact, the valve had tripped on high tcrque with the valve fully closed.84-018 On 12/20/34 LPCI injection valve, M0-1001-28A, would not close when

31. 293 securing shutdown cooling to perform a surveillance test. Cause was Pilgrim I determined to be worn teeth on the splined insert gear.

32. 293 84-020 On 12/12/84 when starting up after a refueling outage, containment Pilgrim I isolation was received due to a reactor high water level signal. High water level was caused by outboard LPCI injection valve (28A) which had not fully seated. The motor operator was repaired.

33. 293 82-042 During a surveillance timing test, HPCI torus suction valve, Pilgrim 1 M0-2301-35, did not operate. An open field winding was found on the operator motor. Due to its required service, the motor has no TOL or torque switch protection.

34. 295 85-004 While performing sump valve stroke tests, RHR suction valves, IM0V-SI8812 A & B, to the refueling water storage tank failed to i Zion 1 j

reopen after being closed. The valves reopened after several l

attempts. The root cause is unknown.

u*

• I Docket and LER Event Description Plant Number 85-003 During the HPCI surveillance test, it took 10 seconds longer than

35. 296 specified to reach rated flow conditions. The limit switch on the Browns Ferry 3 HPCI steam isolation valve was set to start the auxiliary oil pump when the valve reached the full open position rather than when the The valve started to open. The same problem was found on Unit 1.

RCIC system also failed when the RCIC turbine trip valve failed to reopen after a trip. Cause of failure was a worn brass worm gear.

36, 302 83-042 During surveillance testing on 9/27/83, the motor on steam supply valve, ASV-5, for EFW pump 2 burned up. The cause was initially Crystal River 3 reported as a faulty torque switch. A subsequent LER revision 1 identified the cause as a stuck contactor believed to be caused by a sticky substance such as cable pulling lubricant.83-009 During surveillance testing on 2/22/83, the emergency feedwater pump

37. 302 failed to start because the steam supply valve, ASV-5, failed to Crystal River 3 open. The cause was reported as motor burnout due to a failed torque switch. Discussions with the licensee revealed that subsequent investigations determined the TOL was sized for continuous duty which was a misapplication, the torque switch was set incorrectly, and the TOL is not alarmed on a trip (see LER 83-042 also).83-043 During quarterly testing, containment spray valve, 2 MOV-CS0004,

38. 304 failed to stroke. The torque switch tripped on a low setting due to Zion 2 the pump discharge pressure on the valve. The torque switch setting 2

was increased.83-015 After adjusting the packing on valve, MS-1008, on the main steam

39. 305 header to the turbine driven AFW pump, the valve cycled closed but Kewaunee failed to open until manually lifted off the seat. Failure to open was due to a faulty torque switch and the tripper cam being out of adjustment.

i 83-017 On May 9,.17, and 18, 1983, a cooling water outlet stop valve to the  !

40. 309 residual heat removal heat exchanger failed to open (normally closed)

Maine Yankee to allow primary component cooling flow. The valve was manually

s' Docket and LER Plant Number Event Description opened off the seat each time. The cause was a misadjusted torque switch. The close torque switch setting was found to be significantly

greater than the opening torque switch setting.

41. 309 83-016 The valve, SIA-M-54, failed to glose during routine monthly testing Maine Yankee (twice). The valve was manually operated and then cycled electrically several times. The opening limit switch was adjusted to prevent excessive tightening in the backseat position.

42. 311 84-018 During pressurizer overpressure protection system testing, reactor Salem 2 coolant system pressure rapidly decreased when block valve 2PR 6 was opening. The valve failed to reclose in required time. A broken wire was found and the close thrust was at minimum recommended value. It is suspected that the calculated required torque is not adequate when trying to reverse the valve direction in mid stroke.

43. 312 84-025 About 10 minutes after a reactor trip, the steam admission valve to Rancho Seco the auxiliary feedwater pump stopped in mid-position when attempting to secure the pump. The valve shaft was lubricated, stroked, and found acceptable.

44. 321 83-051 The core spray valve, E21-F015B, failed to close when returning the Hatch I loop to service. Investigation revealed the torque switch had failed.

45, 324 85-002 HPCI system was declared inoperable when the HPCI pump discharge Brunswick 2 valve, E41-F006, would not open. No cause was given.

46. 324 84-016 The RWCU system primary containment isolation valve 2-G31-F004, would Brunswick 2 not close and was manually closed. Later in the day, RWCU inboard isolation valve, 2-G31-F001, would not close. The problem with 2-G31-F004 was insufficient spring tension on the torque switch contacts which prevented the contacts from closing. The problem with

) 2-G31-F001 was attributed to a thin film buildup on the valve torque switch closing con. tacts.

s' ,

Docket and LER Plant Number Event Description

47. 324 83-063 While securing drywell/ suppression pool ventilation purging during Brunswick 2 startup, the 2-inch isolation valve, 2-CAC-V22, would not fully close. The motor operator was disassembled and inspected, but no problems were found which were associated with failure to close. New stem packing was installed.

48. 325 83-045 While performing reactor vessel loop calibration on 9/19/83, RCIC Brunswick 2 steam supply valve, E51-F007, would not completely open. While performing an RCIC instrumentation procedure on 9/24/83, valve E51-F007, would not reopen. The valve is inaccessible at power.

Subsequent investigation indicated the limitorque motor operator spring pack was loose and the retaining nut was installed upside down during initial construction.

49. 327 84-069 During performance of surveillance instruction SI-9, essential raw Sequoyah I cooling water valve, FCV-67-66, to diesel generator 2A-A was found in its normally closed position, but the thermal overload device was not reset. The valve would not have opened if required. The thermal overload had not been reset from a previous SI-251.2.51-251.2 was revised to check the thermal overloads before performance of the SI.

50. 328 83-115 Containment isolation valve, 2-FCV-70-143, failed to close in the Sequoyah 2 allowable time after being opened while performing maintenance instruction 11.2. A TOL heater had burned out. The valve was manually closed, the TOL replaced and valve tested and declared operable.

51. 331 84-025 During RCIC surveillance testing, the electrical supply breaker for Duane Arnold the steam supply valve was found to trip each time the valve was cycled closed. Investigation revealed the torque switch was out of adjustment.

52. 331 83-032 During required HPCI system inoperability testing, it was discovered Duane Arnold that RCIC outboard steam isolation valve M0-2401 would not fully close and a shutdown was initiated. The motor operator torque switch was tripping before the valve could fully close. After unsuccessful attempts to adjust the to,rque switch, it was replaced.

o 1

~

Docket and LER Number Event Description Plant 84-023 A reactor trip occurred due to reactor vessel low water level.

53. 333 Reactor level was restored with HPCI because the RCIC system failed to Fitzpatrick operate due to a shorted out motor on the steam supply valve.84-015 During normal surveillance testing, the HPCI torus suction valve, 23

54. 333 MOV-58, failed to open. Several subsequent attempts also resulted in Fitzpatrick failure to open. Further investigation failed to identify the cause for failure to fully open.

55. 333 83-060 A technical review of valve actuators indicated an incorrect motor Fitzpatrick operator was installed during maintenance on the RHR suppression pool outboard isolation valve, 10 MOV-39B. A design review indicated that design limits may be exceeded during one post-accident operating mode for RHR suppression pool cooling. However, assuming actual valve design information and calculated accident transient data, actuator sizing calculations confirm that valve 10 M0V-39B was capable of performing its intended design function with the incorrect operator installed between 1977 and Noven)ber 1983.83-011 While performing safeguards protection system train A testing, the

56. 334 motor thermal overload device for the containment sump to IA LHSI pump Beaver Valley 1 suction valve, MOV-SI-860A, was found tripped which disabled the valve. The valve was stroked after resetting the TOL device. No causewasdeterminedfor.theTOLactuation.84-010 Based on a concern raised at the Surry site, with torque switch

57. 338 settings and a request from the NRC resident inspector at North Anna, North Anna 1 an inspection of the torque "Mitch settings was conducted on five i

valves with three found to have incorrect settings. Further inspection of both units revealed half of the safety-related motor-operated valves had incorrect torque switch settings.

58. 344 83-022 On 1/3/84, the "A" train AFW pump failed to start due to an inoperable Trojan steam inlet trip and throttle valve. The motor TOLs were found tripped. Grease had apparently prevented the torque switch from actuating to de-energize the motor when the valve was last closed on 11/23/83. Since the motor was energized, the TOL tripped and rendered

e s

l' Docket and LER Number Event Description Plant the valve inoperable. Corrective action will be to install a thermal overload alarm in the control room to indicate when the TOL trips.84-003 On 3/2/84, #2 MSIV on steam generator 2 closed while at

59. 346 99 percent power. The reactor protection system actuated to trip the Davis-Besse 1 reactor on high flux. The Steam and Feedwater Rupture Control System (SFRCS) actuated on low steam pressure in SG #2 and isolated the steam and FW systems (including AFW valve AF599). The SFRCS was originally initiated manually on low SG level to isolate normal feedwater and align AFW to SG #2. When attempting to restore level in SG #2, AFW valve, AF599, failed to open. This was attributed to the torque switch setting. After it was opened manually, no mechanical problems were found and the valve operated properly.83-010 During AFW system function testing, isolation valve, MS106A, failed to

60. 346 close electrically. This was caused by a torque switch trip due to a Davis-Besse 1 dirty and improperly lubricated valve stem.

61. 348 83-063 During an inservice test, containment sump to containment spray pump suction valve, 1-CS-MOV-8826A, failed to open. Cause was Farley I out-of-adjustment limit switch.83-058 During valve testing, containment isolation valve, 3HV-0512, gave a

62. 362 dual indication with the valve found stuck in mid position. The San Onofre 3 breaker was found tripped, but investigation failed to identify the cause of the trip.83-068 Diesel generator 2B was declared inoperable when the B train service

63. 364 water return valve, Q2P16V536, was found closed. The cause was Farley 2 excessive current draw to the motor operator which resulted in the power supply breaker tripping open while the valve was being reopened following a timed stroke. The valve was discovered closed 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> after it was stroked. It was not apparent that the valve was in the closed position because of a lack of independent main control room board position indication and a plant operator failing to perform a required verification.

- o Docket and LER Plant Number Event Description

64. 366 83-124 During performance of an HPCI test, HPCI steam supply containment Hatch 2 isolation valve, 2E41-F003, failed to close. The cause was attributed to a torque switch trip before the valve closed. Investigation revealed the valve would operate properly several tines and then torque out during mid stroke. The torque setting was adjusted and stem lubricated.

65. 368 83-034 While in mode 1 at 90% full power, pressurizer spray valve, 2CV-4652, Arkansas Nuclear 2 failed to close completely. The valve was closed by bypassing the torque switch at the valve operator motor control center while stroking the valve closed from the control room. The torque switch setting was found to be incorrect.

66. 368 83-036 Rev. 1 Emergency feedwater (EFW) pump isolation valve, 2 CV-1026-2, failed to Arkansas Nuclear 2 close following surveillance testing. The valve failed to close due to changes in operating characteristics which were compensated for by valve stem lubrication and increasing the torque switch setting.

Subsequent investigation revealed that a bypass around the torque switch was not installed.

67. 368 82-038 Rev. I During low power physics testing of EFW control valve, ECV-1076-2, Arkansas Nuclear 2 it was found that a bypass circuit around the torque switch was not installed. This was discovered while investigating another valve (2CV-1026-2, LER 82-026 Rev. 1, item 66) that failed to close. Three additional valves were found to have the same wiring discrepancy.

68. 387 83-111 With the unit at 100% power, it was found that the cooling water Susquehanna 1 supply valve, HV-156 F059, to the HPCI lube oil cooler and barometric condenser would not cycle. The valve motor was burned out due to insulation breakdown.

69. 387 83-129 Motor-operated valve, HV-156 F059, would not operate frem the control Susquehanna 1 room. The torque switch failed to open at the specified torque. The motor continued to run and burned up on over torque with a locked

)

rotor. The TOL bypass circuit design was found to give an erroneous l indication in the control room in that if the M0V test / bypass switch l

.