ML20080G313

Draft Review of Operating Experience for South Texas 1 & 2, 1991-1992.Related Info Encl

ML20080G313
Person / Time
Site:	South Texas
Issue date:	03/31/1993
From:	OAK RIDGE NATIONAL LABORATORY
To:	NRC OFFICE FOR ANALYSIS & EVALUATION OF OPERATIONAL DATA (AEOD)
Shared Package
ML20079R170	List: ML20080G308 ML20080G313 ML20080G556
References
CON-FIN-A-9135, FOIA-94-162 ORNL-NOAC-276, ORNL-NOAC-276-DRFT, NUDOCS 9502070163
Download: ML20080G313 (50)

Text

DRAFT ORhl/NOAC-276 REVIEW OF THE OPERATING EXPERIENCE FOR SOUTH TEXAS 1 AND 2 FROM JANUARY 1991 - DECEMBER 1992 Engineering Technology Division Nuclear Operations Analysis Center March 1993 Prepared for the NUCLEAR REGULATORY COMMISSION OFFICE FOR ANALYSIS AND EVALUATION OF OPERATIONAL DATA under Interagency Agreement DOE 1886-8913-5A NRC FIN No. A9135 Prepared by the OAK RIDGE NATIONAL LABORATORY Oak Ridge, Tennessee 37831 operated by MARTIN MARIETTA ENERGY SYSTEMS, INC.

for the U.S. DEPARTMENT OF ENERGY 9502070163 940602 PDR FOIA LAWRENC94-162 PDR

t DRAFT i

l Table of Contents i

i List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................. ............. ii I

1.0 INTRODUCTION

. . . . . . . . . . . . . . . . . ......... ... ............................. 1 l

2.0 ANALYSIS OF LERS AS A FUNCTION OF REPORTABILITY CODES . . . . . . . . . . . . . . . . . . 3 2.1 10 CFR 50.73(a)(2)(iv) ESF Actuations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 2.1.1 South Texas 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 2.1.2 South Texas 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............... 3 2.2 10 CFR 50.73(a)(2)(i) Unanalyzed Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 3.0 ANALYSIS OF PERSONNEL ERRORS . . . . . . . . . . . . . . . . . . . . . . . . ................... 8 3.1 Intrinsie Human Errors . . . . . . . ...... ................................. 8 3.2 Task Description inadequacy . . . . . . . . . . . . . ...................... ....... 8 4.0 ANALYSIS OF COMPONENT FAILURES ... ... .... ...... .......... . . . . . . 13 4.1 AC Circuit Breakers . . 4

.......................................13 l 4.2 Toxie Gas Primary Elements . . . . . . . . . . . . . . . . . . . . . . . . ..................13 4.3  !

Cables and Wires . ..... .... ........................... . . . . . . . . . . 13 '

4.4 Isolation Valves . . ............ ........... ........................13 4.5 Fasteners . . . . . . .................... ............................. 13 5.0 ANALYSIS OF SYSTEM AND TRAIN OCCURRENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 5.1 Residual Heat Removal System ......................................15 5.2 Primary Coolant System . .. ... . ... .... ......................... 15 5.3 Auxiliary Feedwater System .........................................15 5.4 Chilled Water System . ... ..........................................15 APPENDIX A: LISTING OF ABSTRACTS FOR SOUTH TEXAS 1 AND 2 LERS . . . . . . . . . . . . . A-1 l

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DRAFT List of Tables Table 1.1 New 3. and 4. loop Westinghouse Plant Peer Group . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 Table 2.1 Comparison of Reportability Codes at South Texas 1 and 2 and Other Peer Group >

Plants........................................................... 4 Table 2.2 Number of LERs Reporting ESF Actuations at South Texas 1 and 2 and Other Peer G rou p Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ...... 5 Table 23 Number of LERs reporting RPS Actuations While Critical at South Texas 1 and 2 and Other Peer Group Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Table 3.1 Personnel Actidry Versus Cause For Personnel Errors at South Texas 1. . . . . . . . . . . . 9 Table 3.2 Personnel Activity Versus Cause For Personnel Errors at Other Peer Group Plants (average number of errors per plant) . .................... .............. 10 l

l Table 33 Personnel Activity Versus Cause for Personnel Errors at South Texas 2. . . . . ...... 11 Table 4.1 Dominant Component Failures at South Texas 1 and 2 and Other Peer Group i Plants . . . . . . . . . . . . . .... .. ............ ......................... 14 l

Table 5.1 Summary of Train Failures et South Texas 1 and 2 and Other Peer Group Plants . . . . 16 l Table 5.2 Summary of System Occurrences at South Texas 1 and 2 and Other Peer Group Plants . . . . . . . . . . . .................. ........... ................. 16 Table A.1 Listing of LERs in Analyzed Categories . ... ..... ........... . . . . . . . . . . . A-2 Table A.2 Table A.2 Abstracts of LERs Reported at South Texas 1 and 2 . . ..............A-4 ii l

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DRAFT

1.0 INTRODUCTION

The Nuclear Operations Analysis Center (NOAC) was requested by NRC's Office for Analysis and evaluation of Operational Data (AEOD) to review the operating experience from January 1991 through December 1992 ,

for the South Texas 1 and 2 plants. This review will assist NRC staff in preparmg for a Diagnostic Team 'l evaluation of the South Texas 1 and 2 plants.

As compared to other operating experience reviews conducted by NOAC, this review focused on selected areas and will not provide overall fmdags regarding plant operations. Any fmdags or observations are relevant only to the specific area analyzed.

Tables 1.1 through 5.2 in the report reflect the same information normally compiled for a comprehensive review of operating experience. Based on a review of this data, the following areas were chosen for further analys l

e Licensee Event Reports (LERs) involving reportabilitycriterion 50.73(a)(2)(iv) i

- ESF actuations (Table 2.1) '

e LERs involving reportability criterion 50.73(a)(2)(ii) - Unanalyzed conditions (Table 2.1) i e

Personnel errors involving intrinsic human error associated with operations [

activities (Tables 3.1 through 33) .

Personnel errors involving task description inadeqwnaes associated with testing / calibration and operations activities (Tables 3.1 through 33) l e

Component failures involving AC circuit breakers, toxic gas primary elements, cables and wires, isolation valves, and fasteners (Table 4.1)

Train and system occurrences involving the residual heat removal, primary coolant, auxahary feedwater, and chilled water systems (Tables 5.1,5.2).

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The operating performance of South Texas 1 and 2 is compared to other plants similar in design. Table 1.1

' describes all of the plants in the peer group of new 3- and 4-loop Westinghouse reactors. All peer group data i presented excludes the contribution of South Texas 1 and 2 to the peer group averages. ,

The data in the tables was derived from LER information contained in the Sequence Codmg and Search Sy' ,

(SCSS). He indscated number of personnel errors, component failures, system occurrences, etc., presented in the tables refleas actual numbers of errors or failures as enmded in SCSS, not a count of LERs involvmg thosi failures. Note that a single LER may involve multiple errors or failures, resulting in more errors and failures  !

than LERs.

Appendix A lists the abstracts of events for South Texas 1 and 2 which were included in this review. nree LERs which occurred in 1992 were not yet available in the SCSS database (498/92-021,499/92-009,499/92!

LER 498/92-021 describes a technical specification violation caused by a failure to properly perform response time testing of the main steam isolation bypass valves. LER 499/92-009 describes a missed surveillance caused {

by a faulty modem from a toxic gas monitor. LER 499/92-010 describes a reactor trip caused by failure of a  !

driver card in the control system for a feedwater control valve.  !

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DRAFT i Table 1.1 New 3- and 4-Loop Westinghouse Plant Peer Group i

Plant Name Docket Initial Criticahty Commercial Electrical !

Operation Rating -  !

Beaver Valley 2 412 8/4/87 11/17/87 833 Braufwood 1 456 5/29/87 7/29/88 1120 Braxiwood 2 457 3/8/88 10/17/88 1120 Byron 1 454 2/2/85 9/16/85 1120 Byron 2 455 1/9/87 8/21/87 1120 Callaway 1 483 10/2/84 12/19/84 1171 Catawba 1 413 1/7/85 6/29/85 1145 Catawba 2 414 5/8/86 8/19/86 1145 Comanche Peak 1 445 4/3/90 8/13/90 1150 Diablo Canyon 1 275 4/29/84 5/7/85 1086 Diablo Canyon 2 32.1 8/19/85 3/13/86 1119 Harris 1 400 1/3/87 5/2/87 900 McGuire 1 369 8/8/81 12/1/81 1180 McGuire 2 370 5/8/83 3/1/84 1180 Millstone Point 3 423 1/23/86 4/23/86 1154 Seabrook 1 443 6/13/89 8/19/90 1200 Sequoyah1 327 7/5/80 7/1/81 1148 Sequoyah 2 328 11/5/81 6/1/82 1148 South Texas 1 498 3/8/88 8/25/88 1250 South Texas 2 499 3/12/89 6/19/89- '1250<

Summer 1 395 10/22/82 1/1/84 900 Vogtle 1 424 3/9/87 6/1/87 1101  !

Vogtle 2 425 3/28/89 5/20/89 1101 Wolf Creek 1 482 5/22/85 9/3/85 1170 l

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DRAFT 2.0 ANALYSIS OF LERS AS A FUNCTION OF REPORTABILITY CODES ,

Table 2.1 compares the percentage of LERs in various reportability categories for events occurrmg at South Texas 1 and 2 to the peer group percentages. This table indicates that both South Texas 1 and 2 reported a higher percentage of events resulting in ESF actuations than the peer group. South Texas 2 also reported a higher percentage of LERs classified as unanalyzed conditions than the peer group. Events at both South Texas 1 and 2 in all other categories were at or below peer group percentages. The following sections provide detailed analyses of events which: (1) resuhed S ESF actuations, or (2) were classified as unanalyzed condidons.

2.1 10 CFR 50.73(a)(2)(lv) ESF Actuations As shown in Tab!c 2.2, South 'l:xas 1 and 2 ranked fourth and second in the peer group, respecuvely, in the i number of event that resulted in ESF actuations. During the review period, South Texas 1 reported 22 events, and South Texas 2 reported 15 events. Included in the ESF actuations are events that resulted in RPS actuations.

Table 2.3 compares the number of events that resulted in RPS actuations while the reactor was critical for each plant in the peer group. South Texas 2 ranked second in the peer group with 7 RPS actuations, and South Texas 1 was average with 4 RPS actuations.

i 2.1.1 South Texas 1. Three of the four RPS actuations at South Texas 1 involved personnel errors (498/91-021,91022,92-003). These include operations, maintenance and administrative errors. Personnel errors are further described in Section 3. The fourth RPS actuation (498/91012) involved random failure of a timer relay.

Three events involved spurious high readings on a toxic gas analyzer for the control room (498/91-003,91010,91-017). Two events (498/92-001,91-008) involved spurious actuation of the containment ventilation isolation system. One event (498/91-015) involved failure in a sequencer test circuit, which resuhed in an inadvertent start of an annliary feedwater pump. One event involved breaker phase-to-ground flashover caused by a failure of a snap ring which held the connecting pin in place (498/91-007). The remaining 11 events (498/91-002,91-004,91-008, 91-013,92-005, 92-007,92-009, 92-010,92-014, 92-015,92-016) involved personnel errors, including operations, maintenance and administrative errors. These errors are further described in Section 3.

2.1.2 South Texas 2. Three of the seven RPS actuadons at South Texas 2 involved personnel errors (499/001,91-007,91-010). These included operations, maintenance and administrative errors, which are further described in lecdon 3. Two RPS actuations were caused by a difference in saturation rates of the current transformer associated with relay 87-1/G1 (499/91-003,91-004). One event (499/92-001) was associated with a failed diode, which resulted in dropping a control rod into the reactor core. One event (499/92-003) involved the loss of all three turbine-driven steam generator feedwater pumps due to rain leakage into the electrobydraulic control cabinet that housed the controls for the three pumps.

%ree of the ESF actuations involved spurious high readings of the toxic gas monitor for the control room (492/91-005,91-006, 92-008). Two events involved spurious actuation of the containment ventilation isolation j

system (499/91008,92-005). One event (499/91-009) invohed failure in a sequencer test circuit, which resulted j in an inadvertent start of an auxiliary feedwater pump. This event was similar to 498/91-015. One event l

(499/92-006) involved the failure of both power supplies for the digital rod posidon indication panel. One event (499/92-007) involved inadequate training to prevent " burping" of solenoid operated valves. '

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DRAFT Table 2.1 Comparison of Reportability Codes at South Texas 1 and 2 and Other Peer Group Plants Reportability Category Percentage of all Percentage of Percentage of Peer Groups South Texas 1 South Texas 2 LERs LERs LERs 10 CFR 50.73(a)(2)(iv) ESF Actuations 35 50 83 10 CFR 50.73(a)(2)(i) Shutdowns or Technical 51 39 6 Specification Violations Other: Voluntary report, special report, Part 8 9 -

21 report, etc.

10 CFR 50.73(a)(2)(v) Event that could have 8 7 -

prevented fulfillment of a safety function 10 CFR 50.73(a)(2)(vii) Sinaje failure criteria 7 5 --

10 CFR 50.73(a)(2)(ii) Unanalyzed condition 7 5 11 ,

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DRAFT ,

Table 2.2 Number of I.ERs Reporting ESF Actuations at South Texas 1 and 2 and Other Peer Group Plants Plant Docket Number of LERs Reporting ESF Actuations Comanche 1 445 24 South Texas 2 499 22 Vogtle 2 425 16 South Texas 1 498 15 Diablo Canyon 1 275 13 McGuire 2 370 12 Vogtle 1 424 12 Seabrook 1 443 12 Millstone 3 423 10 Catawba 2 414 9 Braidwood 1 456 9 Beaver Valley 2 412 9 Shearon Harris 1 400 9 Braidwood 2 457 8 Catawba 1 413 8 Callaway 1 483 8 Sequoyah 2 328 8 Wolf Creek 1 482 8 McGuire 1 369 7 Sequoyah 1 327 7 Byron 2 455 6 Summer 1 395 5 Diablo Canyon 2 323 4 -

Byron 1 454 3 5

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DRAFT '

Table 23 Number of LERs reporting RPS Actuations While Critical at South Texas 1 and 2 and Other Peer Group Plants Plant Docket Number of LERs Reporting RPS Actuations While Critical Comanche 1 445 10 South Texas 2 499 7' McGuire 2 370 7 Seabrook 1 443 7 Diablo Canyon 1 275 6 Braidwood 2 457 6 Vogtle 2 425 5 South Texas 1 498 '4 McGuire 1 369 4 -

Catawba 1 413 4 Millstone 3 423 4 Callaway 1 483 4

Shearon Harris 1 400 4 Sequoyah 2 328 i 4

Sequoyah 1 327 3  !

Catawba 2 414 2 i

Byron 2 455 2 Wolf Creek 1 482 2 Summer 1 395 2 Braidwood 1 456 1 Byron 1 454 1 Vogtle 1 424 i

1 Beaver Valley 2 412 1 ,

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. . -. . . . -. . _ . . - = -. ..

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DRAFT 2.2 10 CFR 50.73(a)(2)(1) Unamelyzed Conditions  !

South

• Texas 1 and 2 cach had 2 events classified as unanalyzed conditions. The events at South Texas l included unproper design of the pressurizer safety relief valves (498/91-024) and the power operated relief valve on the ,

cold overpressure minierian system (498/92-019). These events were discovered through NRC informauon  !

nodecs and through industry notifications. A justification for continued operation was issued in each case, l The events at South Texas 2 ir:luded a failure to properly update the technical sg+--E-='- for an l

overtemperature deka temperature trip setpoint (499/92-002) and identification of a need to revise technical  !

specification 3.63 to help prevent unnecessary shutdowns due to loss of containment isolation valves (499/092-  !

004). >

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DRAFT 3.0 ANALYSIS OF PERSONNEL ERRORS Summaries of personnel errors reported at South Texas 1 and 2 are presented in Tables 3.1 and 3.2, respec A summary of average personnel errors for the peer group is presented in Table 3.3 for comparison. The tables indicate that South Texas I has a much higher number of personnel errors reported than the peer group during the review period. Intrinsic human errors and task description inadequacies were particularly numerou at South Texas 1. South Texas 2 reported a lower number of personnel errors than the peer group average!

every category.

3.1 Intrinsie Husman Errors '

Eleven events at South Texas l involved intrinsic human errors involving administrative activities. Of th were directly related to task description inadequacies, and are AM-d in Section 3.2. One event not related to task description inadequacies involved misunderstanding of the requirements of the containment integr ,

technical specification, resulting in a violation (498/92-002). The other two events involved late reportin '

technical specification violations due to inadequate understanding of the reporting requirements (498/91-010 009).

Five events involved intrinsic human errors involving operations activities. Two of these events involved p!

communication:

one during performance of the ESF power availability surveillance (493/91-006), and the other during addition of corrosion inhibitor, which resulted in failure to reopen the makeup water valve to the component cooling water surge tank (498/92-016).

The other three events involved inattention to detail, including:

delay in noticing improper sequencing of loads following startup of a diesel generator (498/91-008) e failure to notice improper positioning of the auxiliary feedwater flow control valves (498/92-006) failure to properly follow procedures, resulting in actuation of a component cooling water pump (498/92-015).

3.2 Task Description Inadequacy Twelve events at South Texas l involved testing / calibration procedural deficiencies (four events had ina which applied to both South Texas 1 and 2, which resulted in a total of 16 deficiencies counted in the These procedural inadequacies included the following:

three events associated with curveillance procedures developed by someone unfamiliar with the systems (498/92-004,92-013,92-017). Procedural reviews were not adequate to detect these procedural errors a

lack of controls to ensure that the fuel handling building truck door remains closed during refueling (498/91-005)

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DRAFT Table 3.1 Personnel Activity Versus Cause For Personnel Errors at South Texas 1 Personnel Intrinsic Task Unknown Inadequate Proper Total Activity Human Description Cause - Man - Human Error Inadequacy Machine Action l

Interface Maintenance 4 7 1 0 0 12 Testing / 6 16 0 0 0 22 Calibration i

Design 4 0 0 0 0 4 Administrative 11 2 0 0 0 13 Operations 6 6 0 0 2 14 Installation 0 0 0 0 0 0 l 4

Fabncatson 4 0 0 0 0 4 Radiation 0 0 0 0 0 0 -

Protection Construction 0 0 0 0 0 0 Unknown 0 0 0 0 0 0 Total 35 31 0 1 2 69 h 1

0 9

-. ~ . - . . - -. -- _- - . . . _ _ _ _ _ - _ - - _ _ _ _ _ _ _ _ _ _ _

L DRAFT Table 3.2 Personnel Activity Versus Cause For Personnel Errors at Other Peer Group Plants (average number of errors per plant)

Personnel Intrinsic Task Unknown Inadequate Proper Total:

Actmty Human Description Cause Man Machine Human Error inadequacy Interface Action ' ,

Maintenance 4 3 0 0 0 '

7 Testing / 4 9 0 0 .0 13 Cahbration Design 4 0 0 0 0 4 Administrative 5 1 0 0 0 6 r Operations 3 3 0 0 0 6 Installation 0 0 0 0 0 0 Fabncation 1 0 0 0 0 1 Radiation 0 0 0 0 0 0 Protection '

Construction 0 0 0 0 0 0 Unknown 0 0 0 0 0 0 Total 21 16 0 0 0 37 10 1

DRAFT Table 3.3 Personnel Activity Versus Cause for Personnel Errors at South Texas 2 Personnel Intrinsie Task Unknown .

Inadequate Proper Total :

Actinty Human Descripdon Cause Man- Human -

Error Inadequacy Machine Acdon Intedace.

Maintenance 2 1 0 1 0 4 Testing / 0 0 1 0 0 1 Calibradon Design 0 0 0 0 0 0 Administradve 4 0 0 0 0 4 Operations 3 1 0 0 2 6 Installation 0 0 0 0 0 0 Fabricadon 0 0 0 0 0 0 Radiation 0 0 0 i

0 0 0 Protection l Construction 0 0 0 0 0 0 Unknown 0 0 1 0 0 1 Total 9 3 1 1 2 16 1

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DRAFT

• lack of controls to ensure surveillance testing is performed, when not completed within one shift (498/91-016) e post maintenance test procedure inadequate to identify operability of the rod position deviation monitor (498/91020) e insufficient emphasis on the risk associated with performance of a calibration of the reactor coolant flow transmitter (498/92-003) e lack of guidance for performing a surveillance test of a component cooling water pump (498/92-005) e lack of distinction between steps which verify equipment startup and steps which require an attempted startup (498/92-009) lack of complete procedures for changing component cooling water pump configurations (498/92-010) e improper sequence of steps in the containment ventilation isolation actuation and response time test (498/92-014) poor administrative review of the power operated relief valve setpoint curves for the cold overpressure mitigation system (498/92-019).

Six events involved operational procedure inadequacies. These events included:

lack of controls to ensure that the fuel handling building truck door remains closed during refueling (498/91-005) e using the wrong procedure during the performance of the ESF power availability surveillance (498/91-006) e lack of proper procedures following a partial loss of offsite power (498/91-008) lack of controls to ensure proper positioning of the auxiliary feedwater flow control valves (498/92-006) e poorly written procedures requiring extra operator attention (498/92-015) lack of procedural step to verify valve position during injection of conosion inhibitor to the component cooling water surge tank (498/92-016) 12

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DRAFT 4.0 ANALYSIS OF COMPONENT FAILURES Single failures of components are not generally required to te reported in LERs. However, component failures are frequently initiators of reportable events. Dese failura can be analyzed to determine trends, however this analysis should not be confused with a comprehensive component failure analysis.

Table 4.1 presents the dominant component failures at South Texas 1 and 2 and compares these to peer group averages. Failures are defined as actual or potential undesired equipment performance which would result in a repair action. A repair action would include replacmg a power supply, rebuilding a pump, or repacking a valve.

Resetting switches or manipulating valves do not constitute repair actions.

4.1 AC Circuit Breakers South Texas 1 reported four occurrences involving AC wuit breakers, as compared to none for South Texas 2 and an average of one for the peer group. These occurrences were reported in two LERs. One event (498/91-008) involved improper lubricatic.: of a load center feeder breaker. Not only was the breaker not greased as needed, but an improper grease was used. The other event (498/91-007) involved the failure of a snap ring which resulted in a phase-to-ground flashover.

i 4.2 Toxic Gas Primary Elements South Texas 2 reported three occurrences involving toxic gas primary elements, as compared to none at South Texas 1 and an average less than one for the peer group. These occurrences include two spunous actuation i signals due to a failed circuit board (499/91-006) and one spurious signal due to a failed infrared source (499/92 !

008).

1 4.3 Cabiss and Wires South Texas 1 reported three occurrences involving cables and wires, as compared to none at South Texas 2 and an average of one for the peer group. Two occurrences involved cracked insulation on the leads to all of the  ;

residual heat removal motors (498/91-023). These cracks did not result in a failure of the motors. T  ;

occurrence involved a random failure of a connection to a radiation monitor, which resuhed in a spunous actuation of the containment ventilation isolation system at South Texas 1 (498/92-008).  !

4.4 Iseintion Valves  !

South Texas 2 reported three occurrences involving isolation valves, as compared to none at South Texas 1 and an average of one for the peer group. One occurrence involved a leaking pressurizer spray valve which was blocked in during a pressure transient, thus contributing to the opening of the pressurizer relief valves (499/91-  ;

007). He other occurrences involved the failure of both containment isolation valves for penetration M-86. The '

cause of the failures was not identified in the 1.ER.

4J Fasteness i

South Texas 1 reported two occurrences involving fasteners, and South Texas 2 reported three occurrences, as compared to an average of one for the peer group. One occurrence involved loose screws on a fuse block (499/91-001). Two occurrences involved disengaged linkage arms on spray valves in the safety injection system (499/914)10). Both occurrences at South Texas 1 involved a failed snap ring on a breaker, which resulted m a breaker phase-to-ground Dashover (498/91-007). 1

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DRAFT Table 4.1 Dominant Component Failures at South Texas 1 and 2 and Other Peer Group Plants Component Peer Group South Texas South Texas 2 Plants (avg) 1 AC Circuit Breaker 1 4 9 Toxic Gas Primary Element 0 0 3 Cable / Wire 1 3 0 Isolation Valve 1 0 3 Fastener 1 2 3 14

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DRAFT 5.0 ANALYSIS OF SYSTEM AND TRAIN OCCURRENCES i Table 5.1 summarizes the dominant train failures at South Texas 1 and 2 during the review period, and compares these to the peer group averages. Table 5.2 summarizes the dominant system occurrences and compares South Texas 1 and 2 to the peer group averages. These failures and occurrences are defined as undesired performance, ahrments, or configurations of syste ns, not just catastrophic failures or instances of systems not performing l when called upon.

1 5.1 Residual Heat Removal System

)

1 For South Texas 1, a total of five residual heat removal train failures, and 16 system occurrences, were counted I in the SCSS database. Whde these figures are much higher than peer group averages, note that these l i

occurrences were reported in three events (still a higher figure than the peer group average). Two events were

' caused by tripping electrical breakers during refueling outages (498/91-0(77,91-006). One event involved the discovery of cracking of the motor lead insulation on all residual heat removal pumps (498/91-023). The cracks did not lead to a loss of the pumps.

5.2 Primary Coolant System j

1 For South Texas 1, a total of four train failures were reported in three separate LERs. Two of the events  !

involved intrmsic human error which resulted in reactor trips. One event (498/91-022) involved an operator l failing to properly perform a functional test of the solid state protection system logic train, the other event l

(498/91-021) involved an electrician misapplying multimeter test leads resulting in actuation of a lockout relay l and loss of power. The third event involving train failure resulted from review of NRC information notice 89-90, i

which indicated that the pressurizer safety relief valves were improperly designed (498/92-024). '

5.3 Auxillan Feedwater Sptem South Texas 1 reported one auxiliary feedwater train failure, and South Texas 2 reported two, as compared to 'I a peer group average of two failures. These events include mispositioning the four aimhary feedwater flow control valves at South Texas 1 (498/92 006), and failure to perform a required pressure test before placing a steam supply line to a turbine-driven pump in senice at South Texas 2 (499/91-002). Neither event resulted in  ;

a loss of aunhary feedwater.

5.4 Chilled Water fystem South Texas I reported a technical specification violation when one chiller was declared inoperable due to a low i oil level indication while another chiller was also inoperable. This event lasted for less than 10 minutes (498/92  !

001). Note that investigation of this event revealed that other occurrences similar to this event were not properly l identified as violations.

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DRAFT Table 5.1 Summary of Train Failures at South Texas 1 and 2 and Other Peer Group Plants System Average number of Number of Train Number of Train--

Train Failures at Peer Failures at South Failures at South Group Plants Texas 1 Texas 2 Residual Heat Removal 1 5 0 Primary Coolant 1 4 2 Auxahary Feedwater 2 1 2 Chilled Water I 0 1 1 l

t Table 5.2 Summary of System Occurrences at South Texas 1 and 2 and Other Peer Group Plants i

l System Average Number of Number of system Number of system  !

system failures at Peer failures at South failures at South Group Plants Texas 1 Texas 2.

Residual Heat Removal 3 16 0 Nonnuclear 10 14 11 Instrumentation Containment Isolation 6 4 14 High Voltage AC 3 13 4 Reactor Protection 3 12 2 low Voltage AC 4 11 4 Component Cooling 2 11 2 W ater 16

DRAFT APPENDIX A: LISTING OF ABSTRACTS FOR SOUTH TEXAS 1 AND 2 LERS l

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1 DRAFT i

L Table A.1 Listing of LERs in Analyzed Categories

]

Leas for South Teams 1 ESF Actuations 1 498/91 001 2 498/91 002 3 498/91 004 4 498/91 007 I 5 498/91 003 6 498/91 008 7 498/91 010 8 498/91 012  !

9 498/91 013 10 498/91 015 11 498/91 017 12 498/91 022 '

13 498/91 021 14 498/92 003 15 498/92 005 16 498/92-007 l 17 498/92 008 18 498/92 009 19 498/92-010 20 498/92 014  ;

21 498/92-015 22 498/92 016 j i

LERs for South Temos 2 ESF Actuations '

1 499/91 001 2 499/91 003 3 499/91 004 4 499/91 005 5 499/91 006 6 499/91 007 7 499/91 008 8 499/91 009 9 499/91 010 10 499/92-001 11 499/92 003 12 499/92-005  !

13 499/92 006 14 499/92 007 15 499/92-008 Leas for South Temes 1 RPS Actuations 1

1 498/91 012 2 498/91 022 3 498/91-021 4 498/92 003 l

LERs for South Temas 2 RPS Actuations 1 499/91 001 2 499/91 003 3 499/91 004 4 499/91 007 j 5 499/91 010 6 499/92-001 7 499/92 003 i i

Leks for South Teams 1 Intrinsic Administrative Errors )

l 1 498/91 002 2 498/91 006 3 698/91 010 4 498/91-013 5 498/91 020 6 498/92 002 7 498/92-004 8 498/92-009 9 498/92 013 10 498/92-017 11 498/92 019 LERs for South Temos 1 Intrinsic operations Errors 1 498/91 006 2 498/91 008 3 498/92 006 4 498/92 015 i 5 498/92 016 LERs for South Teams 1 Testin9/ Calibration Task Description inademancies 1 498/91 005 2 498/91 016 3 498/91 020 4 498/92 003 i 5 498/92-004 6 498/92-005 7 498/92 009 8 498/92 010 9 498/92 013 10 498/92 014 11 498/92-017 12 498/92-019 LERs for South Temes 1 Operations Task Description inadequecies j

1 498/91 005 2 498/91 006 3 498/91 006 4 498/92-006 5 498/92 015 6 498/92 016 LERs For South Temas 1 Component Faltures i i

AC tircuit Breakers 1 498/91 007 2 498/91 008 Cable / wire 1 498/91-023 2 498/92 006 Festener 1 498/91 007 LERs for South Teams 2 Component Failures tonic Cas Prisinry Etamont 1 499/91 006 2 499/92 008 Isolation valve A-2

l DRAFT 1 499/91 007 2 499/92 004 Fentr!er 1 499/91 001 2 499/91 010 I LERs for South Texas 1 Train Failures Reeldust Heat Removat 1 498/91 007 2 498/91 008 3 498/91 023 Prfmary coolant 1 498/91 021 2 498/91-022 3 498/91 024 i i

Aunillary F*ter 1 498/92-006 Chitled Water  !

1 498/92 001 Leas for South Temos 2 Train Failures Primary Coolant I

1 499/91 001 Austif ary Feter 1 499/91 002 i h

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r DRAFT Table A.2 Abstracts of Leas Reported at South Texas 1 and 2 FORN 1 LER SCSS DATA 02-ee .a... ... u ;m.m.u . . . . = u u..m = = = = u.e.23-93 m.

DOCKET YEAR LER NLastEL REVISION DCS NLMSER NSIC EVENT CATE 499 1991 001 0 9102110269 221012 01/09/91 *

. m u ... u; m m m m . m m m . m . m ... m m . m ASSTRACT POWER LEVEL - 1001. ON JANUART 9,1991 UNIT 2 WAS IN MODE 1 AT 1001 POWR. AT 2207 NOURS, FEEDWATER ISOLATION '

VALVE (FWIV) 2C CLOSED DURING THE INVESTIGATION FLOW NITROGEN AND LOW NYDRAULIC PRESSURE ALARMS FOR FWlV 2C.

THE RESULTANT LOSS OF FEEDWATER FLOW CAUSED A DECREASE lu STEAM GENERATOR (SG) LEVEL Am THE REACT 0E WAS MANUALLY TRIPPED. THE CAUSE OF THE MANUAL REACTOR TRIP WAS A FAILED- CLOSED FEEDWATER ISOLATION VALVE. THE FEEDWATER ISOLATION VALVE CLOSED WNEN AN OPERATOR INCORRECTLY REM 0WED A POWER SUPPLY FUSE TO THE TRIP SOLEN 0lD. l THE FUSE WAS REM 0WED WNEW TRYING TO DETERMINE THE SOURCE OF POWER LOSS 70 THE FWlV NYDRAULIC SKID. TNIS WAS l CAUSED BY f ALLURE TO COORDINATE OPERATIONAL PROBLEM INViSTIGATION Am THE USE OF INFORMATION WITNOUT PROVIDING NECESSARY VERIFICATION; ANNUNCIATOR RESPONSF PROCEDURES DID NOT PROVIDE DIRECTION PERTAINING TO A LOSS OF POWER; Am LACK OF FORMAL TRAINING ON THE INVESTIGATION OF POWER SUPPLIES. CORRECTIVE ACTIONS INCLtR)Es TRAINING OF  !

LICENSED AND NON-LICENSED OPERATOR $; REVISION OF ANNUNCIATOR RESPONSE PROCEDLatES; AS WELL AS OTHER RECLARENCE MEASURES.

FORM 2 LER SCSS DATA 02 23 93 *

. ...mm. ..m..m...m. .m.. m. . .m..m.. . .

DOCKET YEAR LER NLMBER REVISION DCS NUMSER NSic EVENT DATE ios 1991 001 22 m . m m u u _. u u m e.. m 0 ... m . 6031291022... mmm.01/22/91 .1075...

.m.

AssTRACT POWER LEVEL - 000E. ON JANUARY 22,1991, UNIT 1 WAS IN ITS THIRD REFUELING OUTAGE WITH No FUEL IN THE REACTOR VESSEL. AT 1520 NOURS, A CONTAINMENT VENTILATION ISOLATION ACTUATION JCCURRED. OPERATION 3 PERSONNEL VERIFIED THAT ALL EQUIPMENT ACTUATED As DEllGNED. THE RADIATION MONITORING SYSTEM DID NOT I WICATE ANY NIGN RADIATION CONDITIONS. RADIATION LEVELS IN THE REACTOR CONTAINMENT BUILDING WERE DETERMINED TO SE NORMAL PRIOR TO AND FOLLOWING THE ACTUATION. THE CONTAINMENT VEWTILATION ISOLATION ACTUATION APPEARS TO BE THE RESULT OF A SPURittas ACTUATION OF THE RADIAfl0N MONITORING SYSTEM. NOWEVER, THE CAUSE OF THE SPURIOUS SIGNAL FROM THE RADIATION MONITORING SYSTEM COULD NOT SE DETERMINED.

FORM 3 LER SCSS DATA 02 23-93 mm . m . m . m ..... m m ...... m ..... . m .

DOCKET YEAR LER NLRetER REVISION DCS NUMBER NSIC EVENT DATE 498 1991 00 1 911125017 223568

...m= u u u . . . u .2m ... m .. m m m m 3m . m m m . 01/26/91 .e.. m i

ABSTRACT POWER LEVEL 0001. ON JANUARY 26, 1991, UNIT 1 WAS IN ITS THIRD REFUELING OUTAGE WITH NO FUEL IN THE REACTOR VESSEL Am THE REACTOR COOLANT SYSTEM VENTED TO ATMOSPNERE. AT 0850 Mouts, DURING THE FIRST PERFORMANCE OF A PREVENTIVE MAINTENANCE (PM) WORK ACTIVITY, AN AUTOMATIC ACTUATION OF tw2 SAFETY INJECTION (SI) SYSTEM nrrmasp IN ONE OF THREE TRAINS (TRAIN C) AS A RESULT OF LESS THAN ADEGUATE PM WORK INSTRUCTIONS. ALL ASSOCIATED ENGlWEERED SAFETT FEATURES (ESF) EQUIPMENT OPERATED AS EMPECTED. THE CAUSE OF THE LESS TNAN ADEmeATE WORK INSTRUCTIONS WAS PERSONNEL ERROR IN THAT TWO SUPERVISORS FAILED TO REQUIRE FURTMER REVIEW OF WORK INSTRUCTIONS WHICH THEY BELIEVED MAD POTENTIAL FOR CAUSING AN UNPLANNED ESF ACTUATION. CORRECTIVE ACTIONS IMCLet INACTIVATING THE SUBJECT PM AND THE ASSOCIATED PMS FOR THE OTNER ACTUATION TRAINS IN BOTH UNITS. THESE PMS WILL DE CORRECTED PRIOR TO FUTURE USE. FURTHER CORRECTIVE ACTIONS WERE TAKEN TO !$5UE A TRAINING BULLETIN TO APPROPRIATE OPERATIONS Am MAINTENANCE SUPERVISORS DESCRIBING THE EVENT, Am TO COUNSEL THE TWO SUPERVISORS ON THE NECESSITY OF PERFORMING THOROUGH REVIEWS OF PROCEDURES AND WORK INSTRUCTIONS THAT HAVE THE POTENTIAL TO CAUSE UNPLANNED ESF ACTUATIONS.

A-4

l DRAFT FORM 4 LER SCSS DATA 02 23 93 e m e m eee m e m eeeeeeeeeeeee m e m eee m eeeeeeee m oseeeee m ee.

DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE i 499 1991 002 0 9103120274 221189 01/31/91 eeeeen = = . . = = --_ = = m eeeee m eeeeee = ... = = = = = = ee A88 TRACT POWER LEVEL 1001. ON JANUARY 31, 1991, UNIT 2 WAS IN MODE 1 AT 1001 POWER. DURING A REVIEW OF A COMPLETED WORK PACKAGE FOR WELD REPAIRS ON THE TURSINE DRIV"N AUXILIARY FEEDWATER (AFW) PLDIP 24 STEi;t SUPPLY LINE, IT WAS DISCOVERED THAT THE ASME SECTION M1 PRESSURE TEST REQUIRED BY TECMICAL SPECIFICATION 4.0.5 NAD NOT BEEN PERF0FAED PRIOR TO RETURNING THE SYSTEM TO SERVICE. THIS RESULTED IN THE AFW PLDIP 24 Bl.ING ADMINISTRATIVELY ,

IMOPCRABLE FROM DECEISER 5, 1990 TO FEBRUARY 3,1991. THE CAUSES OF TNis EVENT ARJ LESS THAN ADEGUATE s PRGEDURAL CONTROLS WNICN ALLOWED THE PLAMER 10 DEFER CoprLETION OF THE PRESSURE TEST DRTA $NEET, LESS THAN l4EeuATE REVIEW 0F THE REVISED WORK PACKAGE BY THE COGNIZANT SYSTEM ENGINEER Am LESS THAN ApteuATE REVIEW 0F THE POST MAINTENANCE TEST REGUIREMENTS PRIOR TO RETURN TO SERVICE. CORRECTIVE ACTIONS INCLlaE SUCCESSFUL PERFORMANCE OF THE CCDE PRESSURE TEST, REV1$10N OF APPROPRIATE PROCEDURES AND TRA!NING OF APPROPRIATE MAINTENANCE PLANNERS AND SYSTEM ENGINEERS.

t FORM 5 LER SCSS DATA 02 23-93 eeeeeeme = = . . . = . = = = eemeeeeeemmmeeeemmeemmee e

?

DOCKET YEAR LER NLSIBER REVISION DCS NUMBER NSIC EVENT DATE 498 1991 004 0 9103260059 221277 02/15/91 e e m oo m =.__. = e m een m ee m eee m eee m e m ee m eee n m e A85 TRACT POWER LEVEL 000E. ON FEstunRY 15,1991, UNIT 1 WAS IN ITS THIRD REFUELING OUTAGE WITH NO FUEL IN THE REACTOR VESSEL . AT 0259 HOURS, A PARTIAL LOSS OF OFFSITE POWER OCCURRED DURING MAINTENANCE OF AN OVERCURRENT PROTECTION RELAY. THE SUPPLY 3REAKER TO 13.8 KV STAND 8Y BUS 1H TRIPPED WHICH SUPPLIES POWER TO THE 4.16 KV ENGINEERI3 SAFETY FEATURES (ESF) SUS E1C. STAND 8Y DIESEL GENERATOR 813 LOADED AS REQUIRED, RESTORING POWER TO TRAIN C.

THE CAUSE OF THIS EVENT WAS DETERMINED TO BE LACK OF ATTENTION TO WORK PERFORMANCE METHODS. AN ELECTRICIAN INADVERTENTLY TOUCNED THE TRIP CONTACT ON THE PROTECTIVE RELAY IN THE PROCESS OF INSERTING THE CONTACT PL CORRECTIVE ACTIONS INCLLDE TRAINING OF MAINTENANCE PERSONNEL, REVISION OF APPROPRIATE GE RELAY CALIBRATION PROCEDURES AW ADDITION OF A TRAINING 0 EJECTIVE ON THE PROPER METHOD FOR INSTALLING RELAY CONTACT PLUGS.  !

FORM 6 LER SCSS DATA 02 23-93 mmeeee= . . . = = = = =meeeemeeemoseeememeeemeeme DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 498 1991 005 0 9103270165 221278 02/18/91 meemeee= = = . . = = meemeeemmeeeememeseeemmemeo ASSTRACT POER LEVEL

• 0001. ON FEBRUARY 18,1991, UNIT 1 WAS IN MODE 6, AT 1334 HOURS. THE FUEL HAWLING BUILDING (FHS)

TRUCK 00GR WAS OPENED WHILE OPERATIONS PERSONNEL WERE INVOLVED IN FUEL HANDLING AS PART OF THE CORE RELOAD.

APPROKIMATELY 1340 NOURS, AN OPERATOR ON THE FHS FUEL SRIDGE NOTED THAT THE DOOR WAS OPENED AND SECURED ALL FUEL MOWEMENT. THE DOORS WERE CLOSED AT 1359 HOURS. THE FHS EMMAUST AIR SYSTEM WAS REWERED INOPERABLE WNEN THE FMS TRUCK DOORS WERE OPENED. FUEL MOWEMENT WAS SUSPENDED IpeqEDIATELY UPON DISCOVERY AS REQUIRED BY TECMICAL SPECIFICATION 3.9.12 UNTIL THE FNB VENTILAfl0N SYSTEM WAS RESTORED TO AN OPERABLE CONDIT!DN. THE CAUSE OF TNlt EVENT WAS INCOMPLETE ADMINISTRATIVE CONTROLS ON THE FHS TRUCK DOOR. THERE WERE NO CONTROLS IN PLACE TO EN THE APPROPRIATE TECMICAL SPECIFICATION REQUIREMENTS FOR THE FHS EMMAUST AIR SYSTEM WERE FOLLOWD. CORRECT ACTIONS INCLLBE PLACE 9ENT OF ADDITIONAL LOCKS ON THE FHS TRUCK 000RS, ISSUANCE OF A BULLETIN /MIGHT ORDERS TO SECURITY Am HEALTH PNYSICS PERSONNEL TO ENSURE THAT IN ADDITION TO SECURITY AND NEALTN PHYSICS THAT OPERATI PERSONNEL ARE ALSO PRESENT AT THE DOOR PRIOR To OPENING, ISSUANCE OF A MEMORANDLas TO LICENSED OPERATORS DittVSSING THIS INCIDENT, AN EVALUATION TO DETERMINE THE EFFECT OF THE FNB DOORS ON THE OPERASILITY OF THE FNS EXNAUST AIR SYSTEM, AND ESTA8LISNMENT OF APPROPRIATE ADMINISTRAT!YE CONTROLS.

l l

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A-5 j i

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DRAFT  !

FORM 7 LER SCSS DATA 02-23-93

. m n . _ _ _ _ _ _ u _ _ . _ n u m.. mm.m ..mmm. m DOCKET YEAR LER NL8WER REv!SION DCS IRAISER NSIC EVENT DATE 498 1991 006 0 910 2 0

.:.== .. _ _ a u. ....=.= a.3280307m m m .21315o. m..*. m m .2./.22/91 A88 TRACT POWER LEVEL 000E. ON FEBRUARY 24, 1991, UNIT 1 WAS IN MODE 6 IN ITS THIRD REFUELING OUTAGE. AT 0603 HOURS DURlWG PERFORMANCE OF A SURVEILLANCE TEST, IT WAS DISCOVERED THAT THE CLASS 1E 120 VOLT D!$TRIBUTION PANEL DP002 WAS ENERGI2ED FROM ITS ALTERNATE POWER SUPPLY IN VIOLATION OF TECHNICAL SPECIFICATION 3.8.3.2. IIgEDI ATE i l

ACTIONS WERE TAKEN TO RESTORE THE DISTRIBUTION PANEL TO ITS PROPER ALIGNIIfNT. THE CAUSES OF THIS EVENT WERE FAILURE TO COORDINATE THE TRANSFER OF POWER TO THE DISTRIOUTION PANEL DUE TO INADEGUATE VERSAL CCpetallCATIONS AND FAILURE TO MOMITOR THE ASSOCIATED ALARMS WNICN ANNUNCIATE IN THE CONTROL R0(31 DURING AN UNDERVOLTAGE COWITION. CORRECTIVE ACTIONS INCLtDE TRAINING OF LICENSED AND WON-LICENSED OPERATORS, AND AN EVALUATION OF THE PLANT'S rtsetERING SCNEME FOR ELECTRICAL PANELS, FORM 6 LER SCSS 02 23 93 t

.= _u . = = u u..- .__ : m . m . DATA mm .m me.mm.m DOCKET YEAR LER NisetER REVISION DCS NLeeBER NSIC EVENT OtTE 498 1991 007 1 9110180008 223158 03

. .n __ -___ a m m . m m .. . m m m .. m ... /09/91 . ..

A88 TRACT POWER LEVEL 0001. ON MARCH 9, 1991, UNIT 1 WAS IN COLD SHUTDOWN DURING A REFUELING OUTAGE, AND UNIT 2 WAS OPERATING AT 100 PERCENT POWER. WHILE RETURNING A TRANSMISSION LINE TO SERVICE, A SWITCHYARD BREAKER EXPERIENCED >

A PHASE TO GROUND FLASNOVER CMSED BY A DISLODGED CONNECTING PIN IN THE INTERRUPTER LINEAGE MECHANISM. THE SNAP RING WNICM HOLDS THE CONNECTING PIN IN PLACE HAD FALLEN 007. THE BREAKER FAULT CAUSED PROTECTION CIRCUITRY TO CLEAR THE SOUTH BUS AND OFFSITE POWER WAS LOST TO SEVERAL ENGINEERED SAFETY FEATURES (ESF) BUSES. ONE UNIT 1 '.

STANDSY DIESEL GENERATOR ($800) AND TWO UNIT 2 $3DGS STARTED AND CARRIED THEIR LOADS. ALTHOUGN THE IIgEDIATE CAU5E OF THIS EVENT IS THE DISLG)GED CONNECTING PIN, THE CAUSE FOR THE SNAP RING FALLING OUT OF PLACE IS NOT KN0 bat. AS A RESULT OF THis EVENT, THE BREAKER HAS SEEN REPAIRED AND A MODIFIED PIN DESIGN NAS SEEN INSTALLED IN ALL BREAKERS OF THE SAME MODEL AS THE BREAKER WHICH HAD A FAULT.

FORM 9 LER SCSS DATA 02 23 9

..m.= = = . . : .m.mmmme..m..m. m..e mme.3 DOCKET YEAR LER IRAISER REVISION DCS NUMBER N$tc EVENT DATE 498 1991 003 0 9102250306 221511 01/27/91

. ..mm m.m ..m.m.m mm.m.. .mmmm ASSTRACT POWER LEVEL 0001. ON JANUARY 27,1991, UNIT 1 WAS IN ITS THIRD REFUELING OUTAGE WITH NO FUEL IN THE REACTOR VESSEL. AT 0335 HOURS A RADI ATION MONITOR FOR THE CONTROL ROOM ENVELOPE WENT INTO HlGH ALARM AND ACTUATED THE CONTROL RCDN VENTILATION SYSTEM TO THE REC!RCULATION WITH FILTERED MAKEUP MODE. THE ALARM CLEARED AFTER APPROKIMATELY TWO MINUTES. SAMPLES OF THE CONTROL ROOM ATMOSPHERE DID NOT IDENTIFY ANY ACTIVITY. THE REDUNDANT MONITOR REMAINED IN THE NORMAL RANGE THROUGNOUT THl3 PERIOD. MAINTENANCE WAS PERFORMED ON THE ACTUATED IIONITOR AND THE MONITOR WAS SUCCESSFULLY CALIBRATED. THE CAUSE OF THIS EVENT IS UNKNOWN.

FORM 10 LER SCSS DATA 02 23 93 a...................................................................

DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 498 1991 008 1 91t0240262 223253 03/1

.m.= : n n u - - n. ... m. ..m.. ....m...mmm.5 /91.

ABSTRACT POWER LEVEL - 000%. ON MARCH 15,1991, UNIT 1 WAS IN MODE 5 DUE TO A REFUELING OUTAGE. THE UNIT EXPERIENCED A PARTIAL LOSS OF OFFSITE POWER (LOOP) TO TRAIN A AT 1313 HOURS DUE TO ACTUATION OF THE UNIT AUXILIARY TRANSFORMER PILOT WIRE RELAY WHICH OPENED A SWITCHYARD BREAKER. DURING RECOVERY FROM THE FIRST LOOP, A LOOP OCGNtRED ON TRAIN B 0F UNIT 1 AT 1328 HOURS WHEN A 13.8 KV STANDBY BUS FEEDER BREAKER WAS OPENED BY A CONTROL ROOM OPERATOR.

BOTH LOOP EVENTS WERE DUE TO INADEGUATE PROCEDURES. THE SutJECT PROCEDURES NAVE BEEN REVISED APPROPRI ATELY. IN ADDITION, A LOAD CENTER FEEDER BREAKER FAILED TO CLOSE DUE TO INADEGUATE LUBRICATION. WORK REQUESTS HAVE BEEN ISSUED TO ADDRESS PROPER LUBRICATION.

A-6 i

DRMT FORM 11 LER SCSS DATA 02-23-93 ou . = .. _ _e m m m m e m m eeeeeeee m m eeeeeeeeeeeeeee o DOCKET YEAR LER NLsmER REVISION DCS NUMBER NSIC EVENT DATE 498 1991 009 1 9108050280 222690 03 eeeeeeeee m m m ee m ee m eeeee m eee m m eeeeee = =.= = ee/11/91 ee m ABSTRACT POWER LEVEL 000%. ON MARCN 10, 1991, A CRACKED FUEL INJECTOR N0ZZLE T!P FROM LOT 150010 WAS 70uMD IN ST*eBY DIESEL GENERATOR (SDG) 12. ON MARCN 13, 1991, A CRACKED N0ZILE TIP FROM LOT 150006 WAS FOUND IN SDG 13. HOUSTON LIGHTING & FDWER (HL&P) CONDUCTED EDDY CURRENT EXAMINATION GF 151 INJECTOR N0ZZLE TIPS FROM THESE AS WELL AS SPARES, Am IDENTIFIED SEVERAL ADDITIONAL CRACKED N0ZZLE T!PS FROM LOT 150006. COOPER-BESSEIER (THE '

SDG SUPPLIER) NOTIFIED THE NRC PURSUANT TO 10CFR21 AW NL&P FILED LER 91009 REY. O ACCDRDINGLY. ADD INVESTIGATIONS RESULTED IN THE CONCLUSIONS THAT INADEQUATE LIGAMENT TNICKNESS Am EXCESSIVE NITR THE PROBABLE CAUSES OF THE F AILURES. ML&P ALSO REMOVED LOT 150009 FRGE SERVICE WHICH SN0 BED CR LABORATORY EXAMINATION, AW , AS A CONSERVATIVE MEASURE, ALL LOTS OF THE 1500XX SERIES MANUFACTURED BY ALLIED SIGNAL WERE ALSO REMOVED. A REVIEW OF CURRENT MANUFACTURING METHODS SN0hED THA$ IMPROVEMENTS N DIMENSIONAL CONTROL. THE INFORMATION DEVELOPED NAS BEEN SHARED WITH COOPER BESSEMER AND MPR ASS MANAGER OF THE COOPER BESSEMER OWNER'S GROUP). ADDITIONAL RECURRENCE CONTROLS HAVE BEEN ADDED AT INCLLR)ING EXAMINATION FOR DEPIN OF NITRIDING.

FORM 12 LER SCSS DATA 02 ee m m n en___u u m e m m eeee m ee.. m m m e eeee m ee m e.93 e DOCKET YEAR LER WUMBER REVISION DCS WUMBER NSIC EVENT DATE 498 1991 010 1 9111250183 223569 04 eemeeee= = _ . = _ememememeemmemeemeeeeeeeeeeem/04/91 see ABSTRACT POWER LEVEL - 013%. ON APRIL 4,1991, UNIT 1 WAS IN MODE 1 AT 13 PERCENT POWER. AT 0843 HOURS, THE MAIN CONTROL ROOM RECE!VED A T0XIC GAS HIGH CONCENTRATION ALARM. THE CONTROL ROOM VENTILATION SYSTEM WAS M THE RECIRCULATION MODE AS A CONSERVATIVE RESPONSE. NO T0XIC GAS WAS DETERMINED TO BE PRESEN INVEST!GAfl0N. THE ALARM OCCURRED AS A RESULT OF A FAILURE IN THE EMERGENCY RESPONF FACILITIES DA

• AND DISPLAY SYSTEM COMPUTER. THE CAUSE OF THE ALARM WAS A FAILED FIBER OPTM & TTA ACQUISITION CO SUBSYSTEM PRINTED CIRCUIT BOARD. THE FAILED PRINTED CIRCUIT BOARD NAS BEEN RMg.n AS A RESULT OF THE EVENT.

r FORM 13 LER SCSS DATA 02 23 93 eeeeeee m u ......= ..e m m m m m m m eee m ee m eee m ee m ee D0CKET YEAR LER NUMBER REYlSION DCS WUMBER NSIC EVENT DATE 499 1991 003 0 9104220136 221975 03 eee-seen . . . _ _ _ _ u n - _ . _ es memeemm.memeeeeeeeee/,14/91 em ABSTRACT POWER LEVEL - 1005. ON MARCH 14,1991, UNIT 2 WAS OPERATING AT 100% WHILE UNIT 1 WAS IN MODE 5. AT 1810 HOURS, UNIT 1 CONTROL ROOM PERSONNEL CLOSED THE SWITCNYARD BREAKER TO ENERGIZE THE UNIT 1 MAIN AW A TRANSFORMERS.

14EEDIATELY FOLLOWING THIS BREAKER CLOSURE, THE UNIT 2 3 PHASE GENERATOR ISOPNASE BUS DIFFERENTIAL RELAY ACTUATED. THIS CAUSED THE GENERATOR LOCKOUT RELAT TO ACTUATE WHICH RESUL TRIP AND REACTOR TRIP. DURING THE RECOVERY PROCESS THE MAIN STEAM ISOLATION VALVES (MSIV) WERE GENERATOR (SG) MSIV WAS SUBSEQUENTLY REOPENED WHILE A SG LEVEL WAS NEAR THE LOW LOW SETPolNT A AUKILIARY FEEDWATER ACTUAfl0N. THE PROTECTIVE RELAY ACTUATION WAS CAUSED BY DIFFERENCES IN THE S OF THE TWO CURRENT TRANSFORMERS THAT SUPPLY THE DIFFERENTIAL RELAY. THE AFW ACTUATIDW WAS CA PROCEDURES THAT FAILED TO PROVIDE GUIDANCE REGARDING MINIMLat SG LEVELS DURING MSIV MANIPUL CORRECTIVE ACTIONS RELATIVE TO THE CURRENT TRANSFORMERS WILL BE REPORTED IN LER 91004, WHICH DESCRIBES A

$1MILAR SUBSEQUENT REACTOR TRIP EVENT. PROCEDURES WILL BE REVISED AND THIS EVENT WILL BE INCLISED IN REQUALIFICATION TRAINING TO MIKIMIZE THE POTENTIAL FOR UNNECESSARY AFW ACTUATIONS.

A-7

I DRAFT FORM 14 LER SCS$ DATA 02 23 93

.m. w..m.m.m.m..m w mm..mmmm... m...

DOCKET YEAR LER NWSER REVISION DCS NUMBER kSIC EVENT DATE 499 1991 004 0 91050 03/30/91

. n -.__ = n a m m .. m . . 60214 221976 m m . m .... m m . m .

ABSTRACT POWER LEVEL 1001. ON MARCH 30,1991, UNIT 2 WAS OPERATING AT 1001 WHILE UNIT 1 WAS IN MODE 3. UNIT 1 CONTROL ROOM PERSONNEL CLOSED THE SWITCMYARD BREAKER TO ENERGIZE THE UNIT 1 MAIN AND AUMILIARY TRANSFORMERS.

IMMEDIATELY FOLLOWING THIS BREAKER CLOSURE, THE UNIT 2 R PNASE GENERATOR ISOPNASE BUS DIFFERENTIAL RELAY ACTUATED. THIS CAUSED THE GENERATOR LOCKOUT RELAY TO ACTUATE WNBCN RESULTED IN A TURBINE TRIP AND REACTOR THE PROTECTIVE RELAY ACTUATION WAS CAUSED BY DIFFERENCES IN THE SATURATION RATES OF THE TWO CURRENT TRANS THAT SUPPLY THE DIFFERENTI AL RELAY . AN EVALUATION 15 UNDERWAY TO ESTABLISM THE FEASIBILITY OF NARDWARE CN!

TO ADDRESS THIS PROBLEM. AS AN INTERIM MEASURE, A TEMPORARY MODIFICATION NAS BEEN INSTALLED THAT REMOVES THE PROTECTIVE FUNCTION FROM THE AFFECTED DIFFERENTI AL RELAY. REDUNDANT PROTECTION IS PROVIDED BY OTNER PRO RELAYS.

FORM 15 LER SCSS DATA 02 23 93 m .m i

. .m.m.m..m....m.m...m.....m....mu DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 49 1991 011 0 9105140266 222021 04

... 8... m ......m...m...m.mm..m m... ..m./.08/91 w

ASSTRACT POWER LEVEL - 0775. ON 4/8/91, UNIT 1 WAS IN MODE 1 AT 771 POWER. AT 2205 HOURS, AN OPERASILITY TEST WAS PERFORMED ON THE TRAIN D FEEDWATER ISOLATION VALyf (FWlV). THE VALVE STROKED AS REQUIREDT HWEVER, ONE OF THE TWO REDUNDANT SOLENOID VALVES WHICH ACTUATES THE FEEDWATER VALVE FAILED. SINCE THE CONDITIONS OF TECN S 3.7.1.7 FOR sux)ES 1 AND 2 COULD WOT BE MET, A PLANT SMUTDOWN WAS INITI ATED AND A NOTIFICATION OF mmM EVEG (NOUE) WAS DECLARED. THE NRC WAS NOTIFIED AT 0023 HOURS ON 4/9/91. THE FWlv WAS SECURED AND TAGGED AT 0650 HOURS AND UNIT 1 WAS BRWGMT TO MODE 3 AT 0803 HOUR $. THE CAUSE OF THIS EVENT WAS FAILURE OF ONE OF TWO REDUNDANT FWiv SOLENOID VALVES TO OPERATE DUE TO NYDRAULIC FLUID POLYMERIZATION. CORRECTIVE ACTIONS INCL ,

ELIMINAflWG THE MAJOR SURCE OF MOISTURE ENTRY INTO THE NYDRAULIC SYSTEM, FLUSN!NG THE HYDRAb.!C SYSTEM AND -

REPLACING THE NYDRAULIC FLUID, REVISION OF PREVENTIVE MAINTENANCE ACTIVITIES AND PLANT MODIFICATIONS TO ADD CLEAN-UP SKIDS AND RELOCATE THE SOLEN 0!D VALVES.

FORM 16 02-

.m.....mm mm.o.LER SCS.$ DATA. m . m . m .. m m mm.m .. m m e.23-93 DOCKET YEAR LER NWBER REVISION DCS NUMBER WSIC EVENT DATE 496 1991 012 1 9111070005 223301 04

......w m .. m .. m .. m m . m m .....w ... m ./12/91 ...

AS$ TRACT POWER LEVEL

• 040%. ON 4/12/91, AT 0418. THE UNIT 1 REACTOR TRIPPED FROM 40% POWER. A TURBINE TUIP, FEEDWATER ISOLATION AND AUMILIARY FEEDWATER ACTUATION OCCURRED AS A RESULT OF THE REACTOR TRIP. SYSTEp3 OPERATED AS DESIGNED IN RESPONSE TO THE REACTOR TRIP. IT WAS DETERMINED THAT RCD DRIVE MOTOR GENERATOR LRDMG TRIPPED DUE TC A TRANSIENT INDUCED BY RDMG #12 WHICH WAS FOUND RUNNING WITH ITS MOTOR AND GENERATO CLOSED WITN WO QUTPUT VOLTAGE TO THE REACTOR TRIP SWITCNGEAR. IT !$ BELIEVED THAT INTERMITTENT PICK UP A DROP-0UT OF THE 2R RELAY, WHICH ACTUATES CONTACTS TO SUPPLY POWER TO THE RDMG SET #12's GENERATOR VOLTAGE REGULATOR, CAUSED INSTABILITY IN THE VOLTAGE REGULATOR OPERATION. THE 2R RELAY MALFUNCTION WAS DLE TO A DEFECTIVE OUTPUT SWITCH. THE INSTABILITY OF THE YOLTAGE REGULAfl0N RESULTED IN TRANSIENTS THAT CAUSE CURRENT TO THE RDMG SET #11 AND A SUBSEQUENT TRIP OF THE GENERATOR OUTPUT BREAKER. IT IS ALSO BELIEVED 2R RELAY CONTACTS SUPPLYING POWER TO THE VOLTAGE REGULATOR EVENTUALLY REMAINED OPEN LONG EN3 OF THE GENERATOR FIELD IN THE RDMG SET #12. A LDSS OF THE GENERATOR FIELD RESULTS IN 2ERO CUTPUT VOLTAGE FR THE GENERATOR. THE LOSS OF SOTH OF THE POWER SOURCES TO THE REACTOR TRIP SWITCMGEAR RESULTED IN THE 2R RELAY'S TIMER AND CONTROL RELAY WERE REPLACED AND A PROCEDURAL CHANGE HAS BEEN MADE TO ENNAN OF MALFUNCTION.

l 1

l l

A-8 j l

l

I' DRAFT l

FORM 17 LER SCSS DATA 0 2 23 93

. .= = = = - . = = = = : = _ . = m..m. m .e .w.  !

DOCKET YEAR LER MLMBER REVIslCal DCS NLarMR NSic EVENT DATE 498 1991 013 0 910513J376 04/1

. . = .

= = = = = = ........ 222015..= = = =.2/.91..

I ABSTRACT I POWER LEVEL 0001. ON APRIL 12,1991, UNIT 1 WAS IN MODE 3 AT NORMAL OPERATING PRESSURE AND TEMPERATURE. AT 1321 HOURS, OURING TRmJBLESN00 TING OF AN ENGINEERED SAFETY FEATURE (ESF) SEQUENCER AUTCMATIC TESTING FAILURE, A MCSE !!! (SAFETY INJECTION COINCIDENT WITH LOSS OF OFFSITE POWR) SEQUENCER ACTUATION WAS INITIATED INl B. THE ACTUAfl0N RESULTED FROM LESS THAN ADEeuATE TROUBLESN00 TING INSTRUCTIONS. PLANT EQUIPMENT OPEi DESIGNED AND TNERE WERE NO $1GNIFICANT TRANSIENTS AS A RESULT OF THE ESF SEQUENCER ACTUATION. TROUB '

PROGRAM PROCEDURES WILL SE REVISED AS A CORRECTIVE ACTION.

F 18 LER SCSS DATA 02 23-93

.ORM m = = .... = = = = _ = . . = = = = = = . . = = =

1 DOCKET YEAR LER IRMBER REVISION DCS NUMBER NEIC EVENT DATE 499 1991 005 1 9111180286 223454 04 weem .= = = = = en. m.m..... m..m....n./11/91 mn ABSTRACT POWR LEVEL 1001. ON APRIL 11,1991, UNIT 2 WAS IN MODE 1 AT 100 PERCENT POWER. AT 1130, AN AUTCmATIC ENGINEERED SAFETY FEATURES (ESF) ACTUATION OF CRE HVAC TRAINS B AND C TO EMERGENCY MODE OCCURRED. C ENVELOPE (CRE) HVAC TRAIN A HAD BEEN MANUALLT ACTUATED TO THE EMERGENCY MODE IN SUPPORT OF A SUR PROCEDURE. NO INDICATION OF A HIGH RADIATION OR SAFETY INJECTION $1GNAL WAS FOUND. THEkE HAS SEEN N ESTABLISHED FOR TNIS ACTUATION.

FORM 19 LER 02 23 93

. . = = = = = = = = = .SCSS DATA

..m...m.m.m. .. m..m DOCKET YEAR LER MLMBER REVisl0N DCS NUMBER NSIC EVENT DATE 49 014 e8 1991 m m : = = = = = e.e 2 92012 m m m 2D010.. m m m 223809 04/

ee. m .20/91....

ASSTRACT POWER LEVEL 1001. ON APRIL 20,1991, UNIT 1 WAS IN MODE 1 AT 1001 POWER. AT 0406 HOURS, WHILE CONDUCTING A CONTAINMENT SUPPLEMENTAL PURGE TO LOWER THE CONTAINMENT PRESSURE IN RESPONSE TO A CONTAINMENT HIG ALARM, CONTAINMENT EXTENDED RANGE PRESSURE CHANNEL 9759 WAS FOUND TO READ 5 PSIG WHILE CHANNEL 9760 READ 0 PSIC.

CHANNEL 9759 WAS DECLARED IMOPERASLE AT 0407 HOURS. REVIEW OF HISTORICAL COMPUTER RECORDS INDICATEC CNANNEL HAD BEEN IN0PERASLE IN EXCESS OF THE SEVEN DAY ALLOWED OUTAGE TIME. AFTER INITIAL RECALIBRATION, SUBSEQUENT CHANNEL CHECK SURVEILLANCE REVEALED AN ADDITIONAL ERRATIC OUTPUT $1GNAL SY THE TRANSMIT i TRANSMITTER CONTROL CARD WAS REPLACED AND THE TRANSMITTER WAS CALIBRATED. CHANNEL CHECKS WRE PERF FOR ONE MONTN TO CONFIRM THE CHANNEL WAS REPAIRED. ALTHOUGH NO GENERIC FAILURF MECHANISM MAS SEEN ESTA8LISHED,  !

THE FAILURE RATES ARE CONSISTENT WITH INDUSTRY EXPERIENCE. THESE TRANSMITTERS ARE BElkG MONITOREDi FACILITY TREADING PROGRAM. i l

FORM 20 LER SCS$ DATA 02 23-93 emm. = _ _ _ = = = = _ = = m.m.m.mm.m.nm.. ......

DOCKET YEAR LER NLMBER REVISION DCS NLmtER N11C EVENT DATE 498 1991

.m.. m.5 G1 0 9105300179 222 04/2

... m . m . m ...149n. m m .2./.91 . .

ABSTRACT POWER LEVEL 1001. ON APRIL 22, 1991. UNIT 1 WAS IN MODE 1 OPERATING AT 1001 POWER. AT 0200, DURING PERFORMANCE OF A TRAIN "C" ENGINEERED SAFETY FEATURE SEQUENCER SURVEILLANCE TEST, THE TRAIN "C" AUNILIARY FEEDWATER ( AFW) PLMP INADVERTENTLY STARTED. THE PUMP WAS SEQJRED AT 0208. THE CAUSE OF THIS EVEN OF A LIGHT ENITTING DIODE (LED) IN THE SEQUENCER TEST CIRCulTRY. THE LED HAS BEEN REPLACED. AN EVALUATI DETERMINED THAT A SIMILAR FAILURE OF AN LED IN THE SEQUENCER ACTUATION CIRCUITRY, RATHER THAN THE TEST CIRCUITRY, WOULD PREVENT ACTUAil0N OF THE ASSOCIATED ESF COMPONENT. THE FUNCTIONALITY OF THE SEQUENCER IS TESTED QUARTERLY. IN ADDITION, IF SUCN A FAILURE OCQJRRED, AN ALARM WOULD INDICATE THE AFFECTED COMPONENT MAD FAILED TO START AND OPERATOR ACTION COULD BE TAKEN TO START THE COMPONENT. THEREFORE, SINCE THERE HAS SEEN ONLY ONE SUCM FAILURE AT STP, WO ADDITIONAL CORRECTIVE ACTION IS PLANNED.

i A-9 l

DRAFT FORM 21 LER SCSS DATA

.m=u-. 02 23 9

._ a a umeme .mmmm..m.mm m.3 DOCKET YEAR LER NLMBER REVill0N DCS NLMBER NSIC EVENT DATE 498 1991 016 0 22219 05

.. m .  :-________u. .mmm 9106180160m.m.m.m m m2./.13/91w.

t ASSTRACT POWER LEVEL 1001. ON MAY 13,1991, AT APPROKIMATELY 2230 HOURS, UNIT 1 WAS IN M(BE 1 AT 100 PERCENT POWR.

If WAS DISCDVERED THAT THE TECHNICAL SPECIFICATION 3/4.7.1.4 REQUIREMENTS FOR DETERMINING OF THE SECONDARY COOLANT SYSTEM NAD NOT BEEN PERFORMED WITHIN THE REQUIRED SURVEILLAN VIOLATION OF TECHNICAL SPECIFICATION 3/4.7.1.4 AND IS REPORTABLE PUREUANT TO 10CFR50.73(A)(2)(I STEAM GENERATOR BLOWolas RADIATION MONITOR DATA WAS CHECKED, AND IT WAS VERIFIED THAT SECOWARY ACTIVITY MAD NOT EXCEEDED NORMAL VALUES OR THE TECHNICAL SPEC!FICATION LIMlf DURING TNis PERIOD. THE CAUSE O FAILURE TO ENSUNE TESTING WAS PERFORMED BEFORE EXCEEDING THE SURVEILLANCE INTERVAL.

CORRECTIVE ACTIONS INCumED ISSUANCE OF SPECIAL ORDERS, AND CMANGING PROCEDURE AND LABORATORY SCNEDULES 70 IMPROVE VIS!BILITY AND INCREAS AWARENESS OF SURVEILLANCE TIMES.

FORM 22 LER SCSS DATA 02-e m m .. ... m .... m . m m e.. m . m m .23-93 ..

DOCKET YEAR LER NlmRER REVISION DCS NLMRER NSIC EVENT DATE 499 1991 006 0 9106180374 222 05/16/91

.em.mm mm.m.....m.mumesmmm.193 m ..... m . m .

AR$ TRACT I POWR LEVEL 1001. ON MAY 16,1991 UNIT 2 WAS IN MODE 1 AT 100 PERCENT POWER. AT 0558 NOURS, THE CONTROL ROOM VENTILATION SYSTEM ACTUATED TO THE RECIRCULATION MODE AS A RESULT OF A SPURIOUS TRIP FROM '

THE SPURIOUS ACTUATION SIGNAL SELF RESET AT 0559 NOURS. ALSO AT 0042 hours4.861111e-4 days <br />0.0117 hours <br />6.944444e-5 weeks <br />1.5981e-5 months <br /> ON MAY 21, 1991 ANOTHER SIMILAR ACTUATION OCCURRED FROM THE SAME ANALYZER AS THE FIRST EVENT. THE EXACT CAUSE OF BOTN EVEi DETERMINED SUT MAS BEEN ATTRIBUTED TO POOR ELECTRICAL CONNECTION ON ONE OR MORE PLUG IN IN THE ANALYZER. CORRECTIVE ACTIONS INCLLCE TROUBLESN00 TING OF THE FAILED ANALYZER, FURTMER DESIGN IMPROVEIENTS TO MINIMIZE FALSE ACTUATION SIGNALS, AND DEVELOPMENT OF PREVENTIVE MAINTENANCE TASKS TO PERIODICALLY RESEAT INTEGRATED CIRCUlf CHIPS IN THE T0XIC GAS A*ALYZERS.

{

i FORM 23 LER SCSS DATA 02 23 93 l j

DOCKET YEAR LER NLMBER REVISION DCS NUNSER NS!C EVENT DATE 499 1991 007 1 9202030253 223871 05

..w .. m ... m . .. m m ....... m m m . m ../22/91 .m.

ASSTRACT POWER LEVEL - 1001. ON 5/22/91, UNIT 2 WAS IN MODE 1 AT 1001 POWER. AT APPROKIMATELY 2220 HRS, WHILE WAITING IN THE AREA 0F THE MAIN GENERATOR BREAKER TO UNLOCK A LOCAL CA81 NET FOR AN ELECYR"AL MAINTENANCE INDIVIDU A NON-LICENSED OPERATOR INADVERTENTLY ACTUATED THE LOCAL GENERATOR BREAKER EMERGE.wT TRIP PUSN LOSS M SECOISART LOAD CAUSED AN AUTCMATIC OVER TEMPERATURE DELTA TEMPERATURE (OTST) REACTOR SPRAT WAS UNASLE To REDUCE THE PRESSURE BEFORE THE PRESSURIZER PORVS OPENED AT APPROKIMAT GENERATOR 2C POER-OPERATED RELIEF VALVE (PORV) FAILED TO OPEN EVEN THOUGH THE PRESSURE EX SETPo!NT. THE NON LICENSED OPERATOR RESPONSIBLE FOR THE TNIP WAS COUNSELLED WITH REGARDS t ATTENTION TO PERFORMANCE OF OPERATIONS ACTIVITIES. THE STEAM GENERATOR 2C PORY NAS SEEN REP DESIGNS HAVE BEER REVIEWED TO IDENTIFY CHANGES THAT CAN PREVENT $1MILAR INADVERTENT ACTUAfl0NS.

24 LER SCSS DATA 02 23-

. FORM ee..e= a u..u .ee m m m m e..e... m m e. m e. m m m e m .93 .

DOCKET YEAR LER WLmsER REVISION DCS NLMBER NSic EVENT DATE A99 1991 008 0 9107020306 22239 05

.mm m .m. ..m.. m.mm3m m .../.25./91 A38 TRACT POWER LEVEL - 0001. ON MAY 25,1991. UNIT 2 WAS IN MODE 3 AT 2235 PSIG AND 567 DEGREES. AT 0107 A CONTAINMENT j VENilLATION ISOLATION (CVI) ACTUATION OCCURRED. ON MAY 26, UNIT 2 WAS IN M(BE 1 AT 751 POWER WHEN AT 0558 A i

SECOND CVI ACTUATION OCCURRED. TR(1JBLESN00 TING FOLLOWING THE ACTUATIONS INDICATED THAT A FAULT ASSOCIATED WITN ONE OF THE TWO PURGE EXHAUST RADIATION MONITORS (RT 8012) CAUSED THE TWO SPURIO j THE FAULTY MOCOLE HAS BEEN REPLACED. AN ANALYSIS IS BElWG FERFORMED TO DETERMINE THE FAILURE M(DE. -

1 A-10 I l

i l

I

DRAFT FORM 25 LER SCSS DATA 02-23-93 e- . =. = a u aeeee= = . . . a eeemoweemee.= . . . . -- eee DOCKET YEAR LER NWBER REVISION DCS NWDER NSic EVENT DATE 496 1991 017 0 9107020304 222516 05/26/91 e = = . = = - . = = . _ . . memeemmmmeeee = = . . = = u = = m ABSTRACT l

POWER LEVEL 1001. ON MAY 26,1991, UNIT 1 WAS IN MODE 1 AT 100 PERCENT POWER. AT 1534 HOURS, THE CONTROL ROOM

{

VENTILAfl0N SYSTEM ACTUATED TO THE RECIRCULATION MW)E AS A RESULT OF A SPURIOUS TRIP FROM A TONIC GAS ANALTZER. j THE EXACT CAUSE OF THE EVENT COULD NOT BE DETERMINED BUT HAS BEEN ATTRIBUTED TO POOR ELECTRICAL CONNECTION ON ONE OR MORE PLUG IN INTEGRATED CIRCUIT CHIPS IN THE ANALYZER. CORRECTIVE ACTIONS INCLLR>E TROLSLESN00 TING OF THE FAILED ANALYZER, FURTHER DES!GN IMPROVEMENTS To MINIMIZE FALSE ACTUATION SIGNALS, Am DEVELOPMENT OF PREVENTIVE MAINTENANCE TASKS 70 PERI (IllCALLT RESEAT INTEGRATED CIRCUIT CHIPS IN THE TOKIC GAS ANALY2ERS.

FORM 26 LER SCS$ DATA 02 23-93 eeeeeee=. = .: = = _ _a u.= = =......= = ..= = = = = = e DOCKET YEAR LER IPJMBER REVISION DCS NWSER NSIC EVENT DATE 496 1991 018 0 9100050243 222691 07/02/91 emee= = . . . . a u = eseeemeemeee semmemmememeeeee.

A85 TRACT POWER LEVEL 1001. ON JULY 2,1991, UNITS 1 AND 2 WERE IN MODE 1 AT 100 PERCENT POWER. AT ABOUT 1300 HOURS, AN ENGINEER REALIZED THAT THE ALARM ASSOCIATED WITH THE CONDENSER AIR REMOVAL SYSTEM (CARS) WIDE RANGE NOBLE CAS ACTIVITY MONITOR WAS NOT FUNCTIONING. AS A RESULT THE CARS NOBLE GAS MONITOR WAS DECLARED INOPERABLE. IT WAS DETERMINED THAT THIS CONDITION MAS EXISTED SINCE THE STARTUP OF EACM UNIT. THE CAUSE OF THE EVENT HAS BEEN ATTRIBUTED To MISUNDERSTANDING OF THE INTERNAL FUNCT!ONS OF THE MONITOR WHEN PROCESS FLOW !$ BELOW DESIGN l VALUES. CORRECT!vE ACTIONS INCLtR)E CHANGING AND REVIEWING THE DATABASE CONFIGURATIONS OF THE GAS ACTIVITY l MONITORS, AND VERIFILATION OF THE PROCESS FLOW SUBSTITUTE VALUE FUNCTION.

)

I FORM 27 LER SCSS DATA i 02 23-93 eeeeem*= = =. _.aeee memeeemosomememesmome,eem 1 DOCKET YEAR LER NWSER REVISION DCS NWSER NSIC EVENT DATE 499 1991 009 0 9108290165 222831 07/07/91 1 eee m e = = . a a = e m m ee m ee m m e m es m m m m eeeeese AtlTRACT POWER LEVEL - 100K. ON JULY 7,1991, UNIT 2 WAS IN MODE 1 AT 1001 POWER. DURING PERFORMANCE OF AN A TRAIN

)

ENGINEERED SAFETY FEATURE (ESF) SEQUENCER SURVEILLANCE TEST THE A TRAIN AUXILIARY FEEDWATER (AFW) PWP .

thADVERTENTLY STARTED. THE TEST WAS SECURED AT 0220 HOURS. THE CAUSE OF THE EVENT APPEARS TO BE A FAILED OPEN  !

LIGHT EMITTING DIG)E (LED) IN THE CIRCUIT ASSOCIATED WITH THE BLOCKING RELAY FOR THE AFW PUMP. THIS CONCLUSION IS BASED ON INDICAfl0NS NOTED DURING ESF SEQUENCER TROUBLESHOOTING. THE CIRCUIT BOARD ASSOCIATED WITH THE AFW PWP BLOCKING RELATS AND THE SLOCKING RELAY CIRCUITS WERE TESTED SAflSFACTORILY. AN ENGINEERING REVIEW WILL BE CONDUCTED TO DETERMINE IF A GENERIC PROBLEM MAY EXIST WITH THE LEDS USED IN SEQUENCER CIRCUITS. j FORM 28 LER SCSS DATA 02 23 93 I sees m = = = = ..a m eeeeee m m e eeee m m ee m e m m ee m m e DOCKET YEAR LER NWBER REVISION DCS NUMBER NSIC EVENT DATE t 498 1991 019 0 9110110115 223107 09/05/91 e = = . a u...- .. ... u m es m eee m e m e m o m m ee m eeeee m m ASSTRACT i

POWER LEVEL 100E. ON SEPTEMBER 5,1991, UNIT 1 WAS IN MODE 1 AT 1001 POWER. AT 1806 HOURS, THE CONTROL ROOM RECEIVED A REACTOR COOLANT DRAIN TANK (RCDT) LEVEL HI HI/LO Lo ALARM. AT 1838 HOURS, REACTOR COOLANT SYSTEM (RCS) LEAKAGE WAG DETERMINED TO BE APPROKIMATELY 15 GALLONS PER MINUTE (GPM), WHICN IS GREATER THAN THE TECHNICAL SPECIFICATION 3.4.6.2 LIMITS. AT A RESULT, THE PLANT DECLARED AN UNUSUAL EVENT. AT 1954 HOURS, PLANT PERSONNEL ENTERED THE REACTOR CONTAINMENT BUILDING (RCB) TO INVESTIGATE. SY !$0LATING NORMAL LETDOWN WITH EXCESS LETDOWN IN SERVICE AND 00$ERv!NG THE LEAK RATE DECREASE, THE LEAKAGE WAS IDENTIFIED TO BE IN THE RCS LETDOW VALVE A1CVLCV0465. THIS EVENT RESULTED FRCM DAMAGED VALVE PACKING. THE VALVE WAS INSPECTED AND NO EVIDENCE WAS FOUND TO INDICATE A CAUSE FOR THE PACKING F AILURE. THE VALVE WAS REPACKED AND RETURNE'D TO AN OPERABLE STATUS.

FURTHER CORRECTIVE ACTION WILL INVOLVE DISASSEMBLING THE VALVE DURING THE WEKY REFUELING OUTAGE FOR UNIT 1 TO ATTEMPT TO LOCATE AND REPAIR THE CAUSE FOR PACKING FAILURES.

A-11 1

- .- ~ . - .- - = .

DRAFT FORM 29 LER SCSS DATA 02 23-93 e m eeeeu. -_ = : = = _ _ . meseemeenm = = = = u : _ _ . a =

DOCKET YEAR LER NUMBER REVIt!0N DCS NUMBER NSIC EVENT DATE 498 1991 020 0 9110250041 223254 e==:-_ _: = =_e=

09/14/91

.= u m e m u . : _ ..

ABSTRACT POWER LEVEL - 1001. ON 9/14/91, AT 1439, UNIT 1 WAS IN MODE 1 AT 1005 POWER WEN THE RQD POSITION DEVIATION MONITOR WAS INCORRECTLY DECLARED OPERABLE BT THE SHIFT SUPERVISOR. THE ERROR WAS DISCOVERED CW 9/15 WNEN THE "Re DEVIATION" ANNUNCIATOR WAS RECEIVED DURING THE TIE THE MONITOR WAS INCORR i OPERABLE, TWO INCREASED FREQUENCY SURVEILLANCES WERE MISSED, RESULTING IN A TECN SPEC V10LAfl0N. THE CAUSEI THE EVENT WAS THAT ERRORS WERE MADE BY THREE $NIFT SUPERVISORS IN IMPLEENTINGREtilREENTS THE PenNhm  !

REGARDING TNE OPERABILITY TRACK!NG LOG SYSTEM. ALSO, THE SN!FT SUPERVISOR WND INCORRECTLY DECLARED TME MONIT OPERABLE DID WOT CONSULT ALL REFERENCES PRIOR TO MAKING AN QPERASILITY DETERMINATION. A INADEGUATE IDENTIFICAfl0N OF THE EFFECT OF THE TEMPORARY MCBIFICATION PACKAGE WNICN 001 IMOPERABILITY. A BRIEFING WILL BE GIVEN TO THE LICENSED GPERATORS STRESSING THE IMPORT TRACKING LOG SYSTEM AS DESCRIBED IN THE CONFIGURATION memWT PROCEDLSE. ALSD, A MEND NAS BEEN SENT TO ALL SENIOR REACTOR OPERATORS STRESSING THE NEED TO EMMAUST ALL AVAILABLE REFERENCES Pal 0 DETERMINATIONS.

THE TEWORARY MtBIFICAfl0N REQUEST FORM MAS BEEN REVISED TO PROWIDE A CLEARER OPE DETERMINATION REMINDER.

l FORM 30 LER SCSS DATA l

m m .e m ee m m m = = = =e m ee m m e. m ee.. m 02 e 23-93 eee. )

DOCKET YEAR LER NtalBER REVISION DCS NUMBER NSIC EVENT DATE 498 1991 022 0 9111190 2 10 i

eee.eee. = _ _ __. = x .e.e m m e.. m . m .266 m ee.23453e.en m em ees /.14/91 i ABSTRACT POER LEVEL - 1001. ON OCTOBER 14, 1991, AT 2304 HOURS, UNIT 1 WAS IN MODE 1 AT 100 POER. SOLID STATE PROTECTION SYSTEM (SSPS) LOGIC TRAIN R FUNCTIONAL TEST WAS IN PROGRESS WHEN THE LICENS THE SURVEILLANCE MISUNDERST0tB THE INTENT OF A NOTE IN THE PROCEDURE AND FAILED TO BLOCK BEFORE PROCEEDING TO THE WEXT STEP. THE aMEMORIES" TEST SWITCN WAS PLACED IN POSITION 16 ,

R TRIP SIGNAL WAS GENERATED. TRAIN R TRIP SIGNAL GENERATED A " TURBINE TRIP UPON REACTOR T NOT BEEN BLOCKED AND THE " MEMORIES" TEST SWITCM ALSO MALFUNCTIONED, WNICH IF IT MAD FUNCTIONED PROPERLY SuttfL i

NAVE ALSO SLOCKED THE TRIP SIGNAL. SUBSEQUENTLY, THE MAIN TURBINE TRIPPED AND, ColNCIDENT WITN A " REACTOR POER ABOVE 50" SIGNAL, A VALID TRAINS REACTOR TRIP SIGNAL WAS GENERATED TRIPPlWG THE REACTOR. THE CAUSE OF fuit EVElst i WAS PERSONNEL ERROR BY THE LICENSED OPERATOR WND EXERCISED POOR JL2GEMENT WNILE PERFORMING THE TESTI CONTRIBUTlWG FACTORS WERE A LESS THAN IDEAL PROCEDURE AND THE MALFUNCTION OF THE " MEMOi CORRECTIVE ACTIONS INCLLSE SITE-WIDE TRAINING SES$!ONS FOR APPROPRI ATE PLANT PERSONNEL ST  ;

0F SELF VERIFICATION DURING WORK PERFORMANCE, COUNSELING OF THE LICENSED OPERATOR INVOLVED IN THE EVE' REVISION TURBlWE. OF ALL SP SERIES SURVEILLANCES PERFORMED AT POWER THAT HAVE THE POTENTIAL TO TR FORM 31 L

.eeeee: = = _._ = ueeemn.ER SCSS 02 23-93 em ee mDAT m mAm se. m eee m m eeee m DOCKET YEAR LER NLsIBER REYlSION DCS NUMBER NSIC EVENT DATE 498 1991 024 0 9111270005 223450 10 e=_ a = u = ___ = _ u m m m e m e.e m .. m . n eee m eeeeeeee es.e m/31/91  !

ABSTRACT POWER LEVEL 100E. DURING A REVIEW OF NRC INFORMAfl0N NOTICE 89 90 SUPPLEMENT 1, DATED SEPTEMBER 5, 1991 AND WCAP-12910, WITH UNIT 1 IN MODE 1 AT 100 PERCENT POWER AND UNIT 2 IN A MODE 6 REFUELING OUTAGE, IT WAS DISCOVERED TNAT THE UFSAR CNAPTER 15 SAFETY ANALYSIS DID NOT CONSIDER THE TIME REQUIRED TO P FOR THE PRESSURIZER SAFETY RELIEF VALVES (SRVS). IpetEDIATE ACTIONS TAKEN TO INVESTIGATE THE PROBLEM CONFIRE D THAT THE CAttilLATED PEAK RCS PRESSURE FOR THE LOCKED ROTOR EVENT WITH THE PRESSURIZER SRV LO WEILD EXCEED THE NRC SAFETY LIMIT OF 110% DESIGN PRESSURE. ON OCTOBER 30, 1991, A STATION PROBLEM REPORT WAS ISSUED IDENTIFYING THE DEFICIENCY lu THE SAFETY ANALYSIS ON NOWEMBER 5, 1991, A JUSTIFICATION FOR CONTINUED OPERAfl0W (JCO) WAS ISSUED. THE JC0 CONCLUDED THAT THE CONDITION DOES NOT RESULT IN EITNER STPEGS 2 BEING IN AN UNSAFE CONDITION. THE CAUSE OF THE EVENT WAS THAT THE NSSS VENDOR DID NOT CON '

ASSOCIATED WITH PURGING THE PRESSURIZER SRV LOOP SEALS IN THE SAFETY ANALYS!$. SINCE THE JC' IDENTIFIED THAT No UNSAFE CONDITION EXISTS, NO IMMEDIATE CORRECTIVE ACTIONS ARE PLANNED. AFTER THE NRC APPROWAL

• OF WCAP 12910 AND WESTINGNOUSE OWNERS GROUP (WOG) kESOLUTION OF THIS ISSUE, ADDITIONAL ACTIONS WILL BE DEVELOPED L AS NECESSARY.

l

}

A-12  !

. - . . _ _ . -- . ~_

DRAFT FORM 32 LER

. .: =:__ 02-23 9

_ u u n _SCSS DATAu. m =.. .__ .__ .___ -__ .3 DOCKET TEAR LER NUMER REVISION DCS NL810ER NSICEVENT DATd 496 1991 021 0 9111

.::.. ....: . _...= m m 250263 223570 10/10/91

.===_..___==u A88 TRACT POWER LEVEL - 1001. 0W OCToeER 10,1991, AT 2056, UNIT 1 WAS IN MODE 1 AT 1001 POWER WNEN POWER FROM THE 1J BUS WAS LOST. DURING THE PERFearr 0F WORK ACTIVITIES, A MAINTENANCE ELECTRICIAN MISAPPLIED IRJLT 2A WNICN ACTUATED THE 86N LOCKl11T RELAT CAUSI POER ON 1J SUS, REACTOR COOLANT PLAIP (RCP) 10 TRIPPED AND CAUSED A REACTOR TRIP DUE TO LO BUS WAS RE ENERLIZED AT 2059 FROM THE UNIT AUKILIARY TRANSFORMER WITH N OF THIS EVENT WAS PER90NNEL ERROR. THE MAINTENANCE ELECTRICIAN'S ATTEN ,

ELEMENTARY DRAWING READING Am TAGJBLESNOOTlWG TECINeleutS lERE LESS T NELD FOR APPROPRIATE PLANT PERSONNEL STRESSING THE APPLICATION OF SELF .

A TESTING DRAWINGS TO AIDPROGRAM WILL BE IWLEIENTED IN Pggymers OF MAINTENANCE ACTIVITIES. TO ENSURE THAT APPLICABLE PERSON FORM 33 LER SCSS DATA

.:. . u = 02 23 9

..e. m e m .. m .. m m m e.3 DOCKET TEAR LER NtstBER REVISION DCS NLSIBER WSIC EVENT DATE 496 1991 023 0 91 22

. m . m m 10/20

. . m . . m .11270022.... . 3571. . m m ./91 A85 TRACT POWER LEVEL - 0001. ON OCTOBER 20,1991 UNIT 1 WAS IN MODE 4 AND UNIT 2 WAS IN NO-MG)E DURING A SCHEDULED REFUELING OUTAGE, WNEW THE DETERMINATION WAS MADE THAT CRACKS FOUND ON THE REllDual H "T" LEADS EPOKY INTERFACE WERE REPORTABLE. ON OCTOBER 11, 1991, WHILE PERFORMING WORK ON ,

LEADS FOR THE MOTOR WERE DISCOVERED TO BE DAMAGED. EXAMINATION OF TH 1 TRAIN A AND TRAIN C, REVEALED SIMILAR MOTOR LEAD INSULATION CRACKING ON ALL OF THESE R' CAUSE OF THIS CRACKING IS THAT DIFFERENCES IN THE FLEXISILITY OF THE MOT AND INSULAil0N U$ LNG RATCNEN SLEEVES, CONCENTRATED THE BENDING STRESS IN THE CABLE IN THE EPORY CAUSING THE CRACKING. THE UNIT 1 RNR PUMP MOTOR "T" LEAD INSULATION CRACKS NAVE BE 2 RNR MOTOR RECURRENCE "T" LEADS WILL BE REPAIRED DURING THE CURRENT REFUELING QU OF THE CRACK!NG.

i FORM LER

. m m 34m m m m S.CS.S DATA. m . m ... m ... 2m23..93 0 DOCKET 49 TEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 1991 010 1 92093 0

.9= = =. ____... _ = . m . m m .. m .00002=.12..m .... ...=..../24/91 ABSTRACT  !

POdER LEVEL 0161. On DecesRier '1 24,1991, at 1644 hours0.019 days <br />0.457 hours <br />0.00272 weeks <br />6.25542e-4 months <br />, Unit 2 was operating at 30% Rated Thernet Power (RTP) when Injection pressuriser (SI) ectuation sprey valve on low PCV 655C pressure at 1648f ailed hoursopen.

from 161 ThisRTP.

ultimately caused an automatic reactor trip and Safet secured to terminate the transient. All avellebte safety equipment Three Reactor Coolant Puisis (RCPs) were performed as designed and no actunt injection to the reactor occurred. The cause was disenoegement of the feocaseck are Linkope to the volve stem 1

i connecting plate on the pressuriger sprey valve controtter. Locking nuts were added to the sprey velve feestasck are linkage comecting screws. Corrective actions included improving maintenance work instructions, conducting plant management reviews with personnet to discuss the event, and providing training on lessons learned from the event. LER92227001.U2 i

l i

A 13 t

i

DRAFT FORM 35 LER SCSS DATA 0

. x . . . . _ = = . = - . . . u u me .e m. .. . . = = u .=e..e.

2- 23 93 DOCKET YEAR LER NLSIDER REVISION DCS NisqBER WSIC EVENT DATE 49 e8= = = . .. u u a _ = _ = _ = = . = = = . m m u_ = = . = 10/18/91 1992 002 0 9202250231 224104

=

ABSTRACT POWER LEVEL ,

0001. ON JANUARY 24,1992, UNIT 1 WAS IN MODE 1 AT 1001 WNCN IT WAS DISCOVERED THAT CONTAllBENT l

INTEGRITY REQUIRE 8ENTS WERE VIOLATED BEGINNING ON OCTOBER 18, 1991, AND LASTING APPRON!MATELY 47 NOURS. REPA WERE 4, MADE TO A LEAKING NANDNOLE COVER ON THE SECONDARY $1DE OF STEAM GENERA 13R 1C, WNILE THE UNIT WAS IN IN IN VIOLATION OF THE CONTAINMENT INTEGRIT Y TECHNICAL SPECIFICATION. THIS EVENT WAS CAUSED MISINTERPRETATION OF THE REQUIREMENTS OF THE CONTAINMENT INTEGRITY TECHNICAL SPECIFICA!

INCLLDE DISSENINAfl0N OF INFORMATION REGARDING THIS EVENT TO PLANT MANAGEIENT AND APPROPRIATE OPERATIO I LICENSING, AND SCNEDULING PERSONNEL. THIS EVENT WILL ALSO BE REVIEWED WITN APPROPRIATE PLANT PERSONNEL DURI <

LICENSED OPERATOR RfeuALIFICAfl0N TRAINING AS THROUGN A MANAGEMENT Am TECANICAL STAFFl ADDIT!0NALLY, MAINTENANCE WILL ADO GUIDANCE TO APPROPRIATE PROCEDURES, THAT CtWTAINNENT INTEGRITY 18 REGUIRE  ;

IN MtBES 1 THROUGN 4 AND THAT OPENING SECONDARY STEAN GENERATOR COWERS BREACNES CONTAINMI FORM 36 LER SCSS DATA

.. . m m= n u . ...m. . mm. ...02 23..93 DOCKET YEAR LER NL8IBER REVISION DCS NtsqBER WSIC EVENT DATE 499 1992 001 0 9202250110 22410 01/22/92

. m m . m m m . . m . . .. m .. m m .5... m ABSTRACT POWER LEVEL - 100E. ON JANUARY 22,1992, UNIT 2 WAS IN MODE 1 AT 1001 POWER. AT 0909 NOURS, UNIT 2 EXPERIENCED A REACTOR TRIP DUE TO POWER RANGE HIGH NEUTRON FLUX NEGATIVE RATE. THE PLANT WAS BROUG IN MODE 3 WITH NO UNEXPECTED POST TRIP TRANSIENTS. THE CAUSE OF THE POWER RANGE HIGN N TRIP WAS DROPPING OF CONTROL ROD H 6 INTO THE REACTOR CORE. THE C03 TROL ROD DROPPED W ITS ASSOCIATED STATIONARY GRIPPER C0!L'S POWER CILCUIT FAILED OPEN, RESULTING IN AN INTERRUPTION OF QJRRENT TO THE STATIONARY GRIPPER Coll. THE CAUSE OF THE DIODE FAILURE REMAINS UNKNOWN. THE FAULTY DIODE WAS REP ALONG WITH ALL DTNER BLOCKING DitBES SHARING THE FAULTY DICDE'S MANUFACTURER'S DATE CCDE FAULTY DICDE AND THE OTHER SELECTED DIODES TO AN INDEPEWENT LABORATORY FOR ANALYSIS NL8 RESULTS OF THE ANALYSIS AND INITIATE FURTHER CORRECTIVE ACTIONS AS NEEDED. ADDITIONALLY HL&P, IN COOPERATION WITN WESTINGNOUSE, WILL PERFORM TESTING TO DETERMINE IF THE BLOCKING DIODES CAN BE ELIMINATED FROM TNE PRESENT R(B* CONTROL SYSTEM DESIGN.

F 37 02 23-9 3

.OR81= = ..... _ = = _ =. .L.ER S. CSS DATA.m..mm.m..~ . m.m l

DOCKET YEAR LER NLSIBER REVISION DCS NUMBER NSIC EVENT DATE 499 1992 002 0 9202250104 2 01/22/92 i

.. ~ ~ ~ m . .. ~ ~ .. 24106 . m . m . m ...

i ABSTRACT POWER LEVEL 100E. ON JANUARY 22,1992, IT WAS DETERMINED THAT STP UNIT 2 NAD BEEN OPERATED IN A CONFIEJRATION WHICH RESULTED IN AN OVER TEMPERATURE DELTA TEMPERATURE (OTDT) TRIP SETPo!NT WHICH WAS TO THE UFSAR SAFETY ANALYSIS. FOR A PERIOD OF APPROKIMATELY ONE MONTH BEGINNING ON SEPTEMBER 19, 1990, UNIT WAS OPERATED WITN A FAILED THOT RESISTANCE TEMPERATURE DETECTOR (RTD) WNICH WAS BYPASSED A REFUELING OUTAGE. ALTHOUGN WITHIN THE LIMITS OF THE TECHNICAL $PECIFICATIONS, OPERATION LlITH THE FAILED RfD ColNCIDENT WITH THE NONCONSERVATIVE OTDT SETPOINT, WHICH $NOULD NAVE INCORPORATED VERITRAK TRANSMITTER UNCERTAINTIES, REPRESENTED A REPORTABLE CONDITION PURSUANT TO 10CFR50.73 FOR OPERATION IN AN UNAssALY2ED Coelfl0N. THE CAUSE OF THIS EVENT WAS PERSONIIEL ERROR THROUGN A LACK OF ATTENTION TO DETAIL IN TH RESOLUTION OF NSSS VENDOR RECCDOIEIIDAfl0NS. ADMINISTRATIVE COMPENSATORY ACTIONS ALLOW STP CONTINUE NORMAL OPERAfical WITHIN THE PRESENTLY DEFINED SAFETY LIMITS UNTIL THE PLANT SAFETY AN Am ANY NECESSARY TECHNICAL SPECIFICAfl0N CHANGES ARE APPROVED.

i A 14

--- - . _ - . . - _- ~_- - . _

DRAFT FORM 38 LER SCSS DATA eeee: = _ _ _ __2.._. 02 23-93

= _____= : m e m eee_ _. ____u_u=___a DOCKET YEAR LER NLSIDER REVISION DCS NL81BER NSIC EVENT DATE e:

499 1992 003 0 9203310183 224301 02/24/92

---_ .:_ ___ _ .:. _ ::_:::_2.:: _ ___:: _ .:_:__::: _______:::

ABSTRACT POW R LEVEL - 1001. ON FEBRuART 24, 1992 AT 1515 NOURS, UNIT 2 WAS IN MtBE 1 AT 10R POWR. FEEDWATER FLOW OSCILLATIONS WRE OBSERVED ON THE STEAM DRIVEN (SGFPT) 823. AT 1703 NOURS, THE LINEAR VARIABLE DIFFERENTIAL TRANSFORIER FOR THE NIGN PRES,!

VALVE FOR SGFPT 822 FAILED LOW AND THE TURBINE SUBSEQUENTLY TRIPPED ON OVERSPEED. AT 1810 IIOUR i OBSERVED 10 hAVE DECREASING SPEED. THE SGFPT #21 WAS PLACED IN MmA.L AND GI SPEED CCalTIIRED TO DECREASE. SLSBEGINNTLY, MANUAL TLasINE LQAD REDUCTION BEGAN Am CONTROL RSS AUTOMATIC. AT 1811 NOURS, THE REACTOR WAS MNuaLLY TRIPPED WITN STEAM GENECATOR WATER LEVELS AT 47 (

8 RAIIGE) AG DECREASIIIG. THE CAUBE OF TNis EVENT WAS RAIN WATER LEAKilIG TIIRIRIB GENERATER BulLDilIG (105) ROOF AW INTO THE ELECTRONYDRAULIC CONTROL (ElIC) CABilIET, WHICH IS THE CtBl FOR ALL THREE SGFP'S, THE EN ELECTRONIC CONTROL STSTEM WAS DRIED CUT Am SGFPT #21 A2 #22 CtBIT l

RECALIBRATED. BELZONA FLEXIBLE MEMBRANE WAS APPLIED TO THE LEAKING EXPANS MtBIFICATICIls WILL BE IMPLEMENTED TO SEAL THE TGB RODFS OF BOTN UNITS.

1

]

FORM 39 LER SCS eeeeeee= _:... .. __ = = = = $ DATA = =;ee m a .= =

02 23-93

__a ===eeeeeeee DOCKET YEAR LER NUW ER REVISION DCS NUMBER NSIC EVENT DATE 4"5 1992 001  !

eeu = = u_ ______=;eeeee.e 0m eeee.03060094 92 224399 01/30/92 i eeeee m m eeeeee m eeeeeeeeee ABSTRACT POWR LEVEL - 1001. ON JANUARY 22, 1992, UNIT 1 WAS IN MODE 1 AT 100 PERCENT POWER. ESSENTIAL CHILLER 11C W INOPERABLE FOR MAINTENANCE. DUE TO AN OBSERVED LOW O!L LEVEL ON ESSENTIAL CN!LLER 118, OPERATIONS D '

CNILLER OPERABLE. THis CONSTITUTED TWO TRAlWS OF ESSENTIAL CHILLERS BEING CPERA TECHNICAL SPECIFICATION 3.0.3. THE PERIOD OF TIME DURIIIG WHICH TWO TRAINS OF ESS WAS LESS ESSENTIAL TNAll CHILLER ONE HOUR.

OPERABILITY, WILL BEAPPLICABLE REVISED. OPERATING AND MAINTENANCE PROCEDURES ADDR 6 L

i FORM 40 LER SCSS DATA o u =_ = : : ________ = == x = = ee m ee m m e m e m eee -=02-23-93 . . . = .

DOCKET YEAR LER IILAISER REVISIGIf DCS IRDIBER NSic EVENT DATE 49B 1992 003 0 9204210378 224501 I

e = =_ = u = m : =_ : = _ +

ee m o m m m eeeeeee= =:03/14/92 a =.m AB6 TRACT  !

i POWER LEVEL - 1001. 018 MARCH 14 1992. UNIT 1 WAS IN MODE 1 AT 1001 POWR. A REACTOR TRl APPRONIMATELY 1108 NOURS FROM A MOMENTARY FALSE REACTOR COOLANT LOW FLOW TRIP -

TECHNICIAIIS CALIBRATING THE REACTOR COOLANT FLOW TRANSMITTER REVERSED THE PROC i TRANSMITTER CAUSING A MOMENTARY LOW (BELOW SETPCINT) DIFFERENTIAL PRESSURE TO B!

FLOW TRANSIITTERS. TN!S EVENT COMPLETED THE LOGIC IN THE SOLID STATE PROTECT!0lf SYS i CAUSE OF TNil EVENT WAS FAILURE TO FOLLOW PROCEDURES WHICH RESULTED FROM INSUFF' EMPNASIS ON TNE RISK ASSOCIATED WITH THE TASK, AW A LIMITED SENSE OF RESPOIISIBILITT BY THE TECHNICIANS 10 i

ENSURE PROPER TASK COIN >LETION. THE ACTIONS BEING TAKEN TO CORRECT TN!S EVENT A '

BE PRESENT TO ENSURE EMPNAS13 IS PLACED 011 COMPLETING THE ACTIVITY CORRECTLY WIIEN I OCCURI CLEAR DIRECTION FOR USE AND PNTSICAL PRESENCE OF PROCEDURES NAS BEEN PROVIDED TO MAINTE AW A IIEMORAWLSI FR0pl MANAGEMENT WAS ISSUED EMPNASIZING THE SELF CNECKING PRINCIPLE.

i A-15 i

DRAFT FORM 41 LER SCSS DATA 02-

. m.. m. m. .n..m .. .m .m.mn 23m-93 DOCKET TEAR LER NUMBER REVISIDW DCS NUMBER NSIC EVENT DATE 499 1992 00 1 9 0

. . m m .5.. . .... m .. m .209150399.. .. m m .. 05/08 . ... m ../92 ABSTRACT POWER LEVEL - 1001. On May 8,1992, Unit 2 was in Mode 1 at 1001 power. At approximately 1324 hours0.0153 days <br />0.368 hours <br />0.00219 weeks <br />5.03782e-4 months <br /> a Containment Ventitation Isolation (CVI) actuation occurred. Operations personnet verified that all ogsipment actuated as designed. The radiation munitoring system did not indicate any high radiation conditions. The Contalrument Ventitation isolation actuation appears to be the result of an omsipment failure in a radiation monitorine RM 23A moeste. Tro@teshooting of the suspect RM 23A modJte and maintenance history evetustions have been perf onned. LER92233001.U2 FOR 42

.M.m e L.ER SCSS DATA... m m. m .. .x n u02n;e23 93 DOCKET TEAR LER NLateER R[ VISION DCS NLastER NSIC EVENT DATE 499 1992 004 0 9206020382 224995 04 m e .. m . m . m ... m m . m .. m m . m .. m . m /28/92 ......

ABSTRACT POWER LEVEL - 100%. ON APRIL 28,1992, AT 1730 HOURS, UNIT 2 WAS IN MODE 1 AT 1001 POWER WHEN AM snamial EVENT WAS DECLARED. UNIT 2 CastENCED THE PLANT SHUTDOWN DUE TO AN ENTRT INTO TECHNICAL SPECIFICAfl0N (TS) 3.0 THE ENTRY INTO TS 3.0.3 WAS REQUIRED WHEN THE ACTION STATEMENT OF TS 3.6.3 COULD NOT BETHE MET.

ACTION STATEMENT REQUIRES THAT AT LEAST ONE ISCLATION VALVE BE OPERA 8LE IN EACH AFFECTED PENETRATION THAT IN TH1$ CASE, BOTH CONTAINMENT !$0LAT10W VALVES (58 FV 4187 AND SS FV 4187A) FOR PENETRATION M 86 WERE DECLARED IMOPERASLE AFTER ATTEMPTS WERE MADE TO CLOSE EACH VALVE WITHOUT SUCCESS. THE CAUSE OF THE VALVE FAIL NOT BEEN DETERMINED. THE CORRECTIVE ACTIONS TO PREVENT RECURRENCE ARE BEING EVALUATED. A TS CHANG EVALUATED TO ALLOW CREDIT FOR THE STEAM CENERATOR TUBES, TURESHEET AND SHELL AS AN ISOLATION BARRIER.

FORM 43 02 23-93 emm ;nu ;u_ .m.LER

w. SCSSm.. DATA m.......mmem. m DOCKET TEAR LER NLastER REVISION DCS NUNSER NSic EVENT DATE 499 1992 006 0 9206240312 0 m*.mn. ..... .m. ... .m.. 225109...w w . 5/22/92 m.

A88 TRACT POWER LEVEL 1001. ON MAT 22,1992, UNIT 2 WAS IN MODE 1 AT 100%, WHEN THE CDePONENT COOLING WATER (CCW) CUTLLT VALVE FROM RES!!LAL HEAT REMOVAL HEAT EXCHANGER 2C OPENED FOR WO APPARENT REASON. AS A RESULT, CCW HEADER PRESSURE DECREASED AND CCW PUMP 2A AUTOMATICALLT STARTED DUE TO THE TRANSIENT. THE CAUSE OF THIS EVENT KNOWN AT THIS TIME. PLANT OPERATORS PERFORMED A VISUAL INSPECTION OF THE VALVE AND STROKED THE VALVE WITH NO ADVERSE FINDINGS. ADDITIONALLT, THE OPERATORS SAflSFACTORILT TESTED THE FUNCTION OF THE SLAVE RELATS AND THE VALVE RESPONSE. THE MOST LIKELT CAUSE OF THis EVENT IS A LOSS OF POWER TO THE SOLAN0!D VALVE $1NCE NO LEAKS WERE DETECTED AND THE VALVE STROKED SATISTACTORILT. ADDITIONAL TROUBLESHOOT!kG WOULD NOT RESULT IN A CON CAUSE OF THE EVENT, THEREFORE, NO ADDITIONAL CORRECTIVE ACTIONS ARE NECESSART.

A-16

- _- . . -= - ~ . -- _.

DRAFT FORM 44 LER SCSS DATA 0 ou._.- . . : = see= = = _ . : = = u _ a eseessu u u - _ _ = 2=23= =93=

DOCKET YEAR LER NLmeER REVISION DCS NUMBER NSIC EVENT DATE 496 1992 006 0 9206290075 0 05/19/92 ou . . .. .___ __u==_==_ _ _.a eu .-_: =. .. eee ASSTRACT POWR LEVEL 1001. ON MAY 19,1992, UNITS 1 Am 2 WERE IN MODE 1 AND AT 1005 POWER. A SYSTEM ENGINEER PERFORMING A BIENNIAL REVIEW OF A SURVE!LLANCE TEST PROCEDURE USED TO TEST THE MANUAL REACTOR TRIP FUNCTION, IDENTIFIED THAT THE TEST DID NOT ADEGUATELY TEST ALL CONTACTS ASSOCIATED WITN THE MASSWITCNES USE A MANUAL REACTOR TRIP VIA THE SMUNT TRIP DEVICE. THE LACK OF TNis TESTING REWERED SOTN CHANNELS OF REACTOR TRIP FUNCTION IMOPERASLE. TECNNICAL SPECIFICATION 3.0.3 WAS ENTERED Am AN UNuguAL EVENT WAS DECLARED.

THE UNUguAL EVENT WAS TERMINATED FOLLOWING VERSAL AUTNORIZATION FRtBI THE NRC THROUGN A TEWORARY WAIVER OF C35*LIANCE. THE CAUSE OF THE EVENT WAS UNFAMILIARITY OF THE INDIVIDUAL RESPONSISLE FOR DEVELOPING ,

PROCEDURE WITN THE REACTOR TRIP FEATURE. A CONTRIBUTING CAUSE WAS INADEGUATE REVIEW OF THE PROCEi VARIOUS REVIEW CYCLES. CORRECTIVE ACTIONS INCLts)Es DEVELOPING A TEWORARY PROCEDLSE TO TEST THE M TRIP VIA THE $NUNT TRIP DEVICE, REVISING THE PERMANENT PROCEDURE TO ADDRESS THE WECESSART TESTING, AS REVIEWING SURVEILLANCE PROCEDURES TO ENSURE THAT THEY MEET TECHNICAL SPECIFICATION REGUIREMNTS.

9 FORM 45 LER SCSS DATA eeeeee. . _ u:::: = u: _ . _ _ .emmeeeee= = = = =me= =02-23 ...== 93 DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 496 1992 005 0 9207150030 0 06 e u. _ = = __ = = = = = = u = _ u .... m es u u . a eeeeeeeeee/06/92 eeee.

A85 TRACT POWER LEVEL - 1001. On Jme 8,1992 Unit 1 was in Mode 1 at 1001 power, when an inadvertent start of a cogenent Cooling Water (CCW) pulp occurred. This event occurred when the discharge heeder pressure went below the setpoint for starting the staney PLap. The discharge header pressure decreased because of a high flow condition when one of two rmning pumps was manustty shut dom during performance of a surveillance test. The flow condition wee caused by inadvertently tesving a large velve open. The cause of this event was that inadequate proceerst guidance was available for performance of the test line@. The possibility of this type of actuation was not recognized and was not incorporated in procochares. corrective actions include performing I en evoluotion to determine which plant procachares need to be reviewed for insuffletent prococharat steps to operate plant egulpment, revising the appropriate procedures to incorporate appropriate guidance for proper system configurations and to swport the conduct of testing, and developing a clear plant directive, for Operetiens pereennet, emphoeiaing thet safety equipuent mentpu(atiens sust be governed by written gutdance and that procockarel changes must be isplemented before work proceeds when written guidance is tecking.

LER92183001.U1 FORM 46 LER SCSS DATA 02 23 93 e= u.....u u u . .: : _u u uee m eeeeeeeeeeeeeeeeeeeeeeeeeeeee DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 496 1992 006 0 9207270063 0 03 eeeeeeeeee u u n a umeeeemseemeeeee eeeeemeeemeeeme/18/92 see.

ASSTRACT POWER LEVEL 0331. On March 18, 1992, with Unit 1 in made 1 at 335 power, the Shif t Seervisor discovered that att four Auxiliary Feechneter (AFW) flow control vetves were in the closed position following a reactor trip on March 14, 1992, contrary to the normal position as specified per procochares. The correct position for the AFW flow control vetves is specified as open in plant procockares and plant drawings. The cause of this event was less than adecmante procochares. A contributing cause woe inattention to detait by the operating crews in not detecting the etspositioned vetves for four days. Corrective actions included immediately opening the AFW float control velves, revising the Reactor Trip Response procochare to recgaire opening the AFW controt velves of ter securing the AFW p6aps, and revising the Plant Starte to 1001 procockare so that verification of AFW system alignment for automatic operation prior to Mode 1 is not a conditional step. Additionetty, this event will be added to the Licensed Operator Requalification Training. In addition, the Independent Safety Engineering Group (ISEC) will perform an in-depth review of causal f actors for volve misoositioning. Additional corrective actions will be developed based on the results of ISEG's review. LER92195001.01 A-17

1 I

. 1 I

l DRAFT I FORIt 47 i LER 02 23-93

..u n___________ a__ m m .S. CSS  : n DATA n a n.u _ _ _ _ _ _ n u um DOCKET YEAR LER IMIBER REVISION DCS IMIBER WSIC EVENT DATE 498 1992 007 0 920 0 07/10/92

. = = = = _ __ =:-____ = m . m . m .8240342 . .. m .eem= _ . = = = =

ASSTRACT POWER LEVEL 0951. On July 10, 1992, et approximately 0917 hours0.0106 days <br />0.255 hours <br />0.00152 weeks <br />3.489185e-4 months <br /> Unit 1 was in leode 1 et 95 percent power.

An toiptennes Engineered Safety Features (ESF) ectuation occurred during the performance of the Spent Fuel Pool Enheust Monitor surveittence test. Instrueentation and Control (!&C) Technicians were performing the survoittence test es required by Technicet Specificatione. An erroneous value wee entered into the RN 23A module.

With the erroneous vetus being present een the conversion f actor was otheemently entered, the RM 23A inesodf ately processed the data and prometurely actuated the Fuel handling Building isolation equipment. The cause of the event is attributed to tack of attention to deteit and not using effective self-verification l methods.

Corrective actione included resterting the survoittance test without further incident, and providing the technician involved with a written reminder tender the STPEGS Constructive Discipline Program. NLap wilt steo perform en evolustion to determine which procedares need to be revised to ensure a chant verification is performed for those actions where incorrect data entry errors could cause ESF actuations. LER92203001.01 FORet 48 LER SCSS DATA 0

. .n - _ _ _ n _ _ _ _ n u..m mm .mmw...... m.2 .23-93 DOCKET YEAR LER NUEEBER REVISION DCS apIBER NSIC EVENT DATE 498 1992 008 0 9209 0 07/

.n u n____n. __u . .. m m m .020007mm m...mm.31/92 .

ASSTRACT POWER LEVEL 1005. On July 31,1992, Unit 1 was in Mode 1 et 1005 power. At 1048 hours0.0121 days <br />0.291 hours <br />0.00173 weeks <br />3.98764e-4 months <br />, a Containment Ventitetton Isolation (CVI) actuotion occurred. Control Room persorviel verified that ett egipment actuster' as designed. The Containment Vent Isolation radiation monitors did not indicate any high radiation conditions.

The moet tikely causa of this event is a momentary variance in current to the remote control unit (Ree I3A) eseociated with radiation monitor (RI 80133) for the containment Purge system sufficient to cause en actuation.

Troietoshooting of both radiation monitors for the Containment Purge System witi be rerfonned. Additionally, hot comoctione identified in the Unit 1 RM 23 module cabinets will be repelred. LER92231002.U1 FORft 49 LER SCSS DATA

.::::::::___ ::-__ :::::::: .___::_:::__::::.:_ _.__::___ :_02___ 23::::

93 DOCKET YEAR LER IUEBER REVISION DCS NUNDER NS!C EVENT DATE 498 1992 009 0

. m.x ___u n; u. .... m .0904019492. m . . m ... 0. m ..

08./01/92 A88 TRACT POWER LEVEL 1001. On August 1, 1992, Unit 1 was in Mode 1 et 1001 power. Testing of the Solid State Protection System ($$PS) ectuation train "C" slave relays wee in progress. At approximately 2049 hours0.0237 days <br />0.569 hours <br />0.00339 weeks <br />7.796445e-4 months <br />, the operator performing the Auxillery Feedwater (AFW) portion of the test misread a procedure step which directed him to verify that the #13 AFW pump did not start following a relay actuation. Rather then verify the plap did '

not start. the operator turned the controt switch on in en etteopt to verify that the pump would not start.

The #13 AFW pump storted and discharged into "C" Stoes Geerstor. The operator wickly restited the error and stopped the p6mp. The cause of this event wee inattention to detalt, in that the operator misreed the test procockare. Corrective actions include revising the $sPS Actuation Train Steve Relay Test procedarse to provide more distinction between steps which verify owipment startte and steps which rs:putre en etteopted coepenent startup and including this event into the Licensed Operator Rowellfication training. Additionetty, other survelliance procedures were identified to ensure that equipment actuotione are clearly defined and a plan of action was developed to ersence these procedures. LER92231001.ut t

A-18 i

l' l l l

l

[

l l DRAFT l

FORM 50 LER SCSS DATA 02-23 93

\ e_ 22.____

DOCKET TEAR LER IK8EBER REVISION DCS NtastER NSIC EVENT DATE 496 1992 010 0 9209110174 0 Oft /08/92 e m u.. _ ..

_____=u___=_=u. ______.::=___u ABSTRACT I POWER LEVEL - 100E. On August 8, 1992, Unit 1 wee in Mode 1 et 1005 power. Operators began a surveillance to verify acceptable Component Cooling Water (CCW) flow to the Reactor Contairusent Fan Cooters (RCFCs). While establishing flow via the running "g" Train CCW pump to the RCFC the stenstsy train "A" CCW pump started skaa to a sensed low pressure on the miscellaneous staply header. The "A" train CCW ptaus started and operated property and was shut dansi when it was verified not to be rewired. The cause of this event was lack of adequate procockaren guidance, corrective actions include revising the surveillance proceskare to rewire the operator to place the other ptags selector switches in of f during the surveillance and revising the system operating j procedure to include guidance for changing puso configurations. LER92239001.U1 i

FORM 51 LER SCSS DATA e::::.:== ___

__ ::. ___._ :. ___ _::: -_==::::::_ __02-23-93 i

DOCKET YEAR LER NUMBER REVISION DC. NUMSER NSIC EVENT DATE 496 1992 011 0 9209300276 m ee= u u ..___u_ : a u m m eeeee m e m = = u u.0m 08 eeee/24/92 m eo ABSTRACT POWER LEVEL 0931. On Aust.at 24,1992, Units 1 and 2 were in Mode 1, with Unit 1 at 931 power and coasting down, and unit 2 at 1001 power. The Survettlance Review Task Force identified that the perfonosnce of the Reactor Coolant Ptsup (RCP) Undervoltage (UV) and underfrequency (UF) Trip Actuating Device Operability Test (TADOT) survelttance procockares did not verify the bistable status monitoring (BSM) lights operability. The l i

cause of thIs event is due to the writers and outhorities who approve Fle!d Changes (FCs) not identifying the '

need to verify the SSM Lights, which were required to be tested per the Technical Specifications. This was chas to inedsequate Leiderstanding of the definition of TADOT by the individuals involved. This event occurred as a result of FCs in the Spring of 1990. The FCs (etso a contributing factor) ellowed the removat of verification of a portion of the RCP UV and UF circuitry and the BSM tights from the test precockare. This allowed the survoittence test to be ineouplete and attowed entry into Mode 1, following the outage, with only a partistly proven channen. Corrective actions includes verification of operability of SSM Lights in both tstits, revision of BSM acceptance criteria of the surveittance precockare, performance of RCP TA00TS that are schecksted sharing outages white the plant is in Mode 5 and prior to Mode 1, e cteer definition of TAD 07 will be focustly l

documented and presented to appropriate personnet for training, and revision of the procockare to timit the use '

l of FCs for changing acceptance criterie. LER9226100..U1 FORM 52 l LER SCSS DATA 02 23-93 '

BEAR R NWiBik 'Rivisio DCSNNIBER NSic iVkNTbATE 496 1992 012 0 9210090281 0 09 l m o m ee = _ : = m m ee m esee m eseeeeeeeeeeeeeeeee m em m/03/92 AOSTRACT j PohER LEVEL - 0068 4 September 3,1992, Unit 1 was in Mode 1 et 861 power (cometdown). Operations personnet and the system

..neer noted on unusuet condition on the Olgitet Rod Position I idication (DRPI) penet.

conditions detenorated to where it was impossible to determine control rod positions. At 1049 hours0.0121 days <br />0.291 hours <br />0.00173 weeks <br />3.991445e-4 months <br />, both channets of DRPI were doctored inoperable and en entry into Technical Specification 3.0.3 was made. At 1149 i

j heure, en unuouel Event was declared due to being in a condition where a shutdown was rewired by the Technicet Specifications.

Accordingly, et 1352 hours0.0156 days <br />0.376 hours <br />0.00224 weeks <br />5.14436e-4 months <br />, with DRPI still inoperable, a shutdown of the unit was consoonced.

At 1415 hours0.0164 days <br />0.393 hours <br />0.00234 weeks <br />5.384075e-4 months <br />, I&C Techniciens coupleted the replacement of one of the redtsident power stapties and DRPI indication wee recovered. The power rocksction wee inusediately terminated and foitowing an essessment DRPI was doctored operable et 1426 hours0.0165 days <br />0.396 hours <br />0.00236 weeks <br />5.42593e-4 months <br />.

The cause of this event was the failure of one of the DRPI control moshale power stapties coupled with an apparent unknown f atture of the rechandant power supply. Corrective actions include replacing one of the two power stapties and returning DRPI to an operable status, replacing the remaining f atted power supply during the secoming unit 1 outage, and developing testing for both teitts for the DRPI systen that will include en assessment of the control system power stanties. The test will be implemented during the next Unit 2 refueling outege. LER92266001.U1 A-19

l l

DRAFT l FORM 53 LER $ CSS DATA

. = = =.... n m e.. m m m .= = = = =02... 23 93 1 l

DOCKET YEAR LER NLAISER REVISION DCS NUMBER N$1C EVENT DATE 499 1992 007 9

_=;e= =_. . = 212210226m m =_.= ua m 09 /.12./92 0

1

. =.. . . . ..

ASETRACT l

POWER LEVEL 100K. On Septemmer 12 1992, Unit 2 was in Mode 1 et 1001 power. Operators were perfoming tNorterly Main Steam system vetve operability testing of the solenoid operated containment isolation velve.

An operator was dispatched to the Isolation Velve C2icle (IVC) building to open the Main Steam taistream menuel drain isolation volve. At 0535 hours0.00619 days <br />0.149 hours <br />8.845899e-4 weeks <br />2.035675e-4 months <br />, approximately one minute af ter the volve was manuelty opened, the above seat drain line valve on the Main Steam line "D" (MS7903A) indicated open in the Control Room. Ne intentionel action was taken to open MtT903A. The cause of the menpocted opening of the isolation valve is aburping", en edesirable, but avoidebte chorectoristic of piloted 50Vs. The slow closure of MS7903A foitowing the " burping" transion* was apparently due to a position indication malfection caused or inf tuenced by talespot teagueretures internet to the SOV. Corrective actions include providing training to appropriate plant departmante describing 4 the burping chorectoristics of piloted SOVs including suggested operationet means for avoiding the problem.

Additionetty, l a review of other sys t.as contelning piloted Sove will be perfonood to determine the ,

susceptibility of " burping." system surveittence procedures will be revised as necessary. LER92336001.U2 i FORN 54 LE 0 m . . m .. R SCSS DATA. ..... .... m . 2-23.93

. )

DOCKET YEAR LER NUMBER REVISION DCS NUMBER NSIC EVENT DATE 499 1992 00ls 0 9210200003 0 09

. . .=. _ .- = ;.. m . m m m e.. m m m ./.15/92 A8sTRACT 1 POWER LEVEL 1001. On Septoneer 15, 1992, Unit 2 was in Mode 1 at 1001 power. At 0834 hours0.00965 days <br />0.232 hours <br />0.00138 weeks <br />3.17337e-4 months <br /> a concret room toxic gas non ESF eterm was received. Control room personnel were in the procese of verifying the votidity of the stars when the control roas envelope heating ventitetton and Air conditioning system actuated to the recirculation mode on a high toxic gas E5F octuation signet. The re&ndent anstyrer did not actuate. Testing of the anstyrer indicated the cause to be a foited infrared source. The enetyrer has been repaired and returned to service. The existing toxic gas anstyrers are to be repieced with state of the art models. These changes will be made during the current outage for Unit 1 and chring the next scheduled refueling outage for Unit 2.

LER92273001.U2 i

FORn 55 L 0 em . = = = = . . ...ER SCSS DAT Am m m m m u m 2 mm. 23-93 DOCKET YEAR LER MlaIBER REY!$ ION DCS NUMBER W5IC EVENT DATE 49

.6 ..m 1992 s

01 0 9210210031 m 3 m . m . m . m m . m . m .0 . 09/1

. m 5./92 A85 TRACT POWER LEVEL 100E. On Septester 15,1992, Units 1 and 2 were in Mode 1, with unit 1 et 79% power and consting down, and Unit 2 at 1001 power. The Surveittence Review Task Force identified that the portion of the Containment Spray (N13) channels between the process instrumentation and the Engineered safety Feature (EEF) actuation and Logic instrumentation wee not being tested. At 0855 hours0.0099 days <br />0.238 hours <br />0.00141 weeks <br />3.253275e-4 months <br />, both Units entered Technicet specification 3.0.3, however relief ettowed by Technicet specification 4.0.3 was used to delay entry into the 3.0.3 oction statements for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to complete the required testing. The required testing was satisf acterity completed at 1611 hours0.0186 days <br />0.448 hours <br />0.00266 weeks <br />6.129855e-4 months <br /> and at 1335 hours0.0155 days <br />0.371 hours <br />0.00221 weeks <br />5.079675e-4 months <br />, for unit 1 and unit 2 respectively, and Technicet specification 3.0.3 wee emited. The cause of this event wee that the indivichet(s) developing the surveillance test precedures did not recognire the significance of the test circuit used to verify continuity of Conteirusent Spray (N!*3) circuitry. Corrective actions included verifying the continuity of the Containment $ prey (HI 3) circuitry and revising the procedures governing Contatrument Pressure Analog Channet Operational Test, to verify contiruity of the Contetruosnt sprey (HI 3) circuits. LER92283001.U1 A-20 i

.. ~ . . -

DRAFT F(RN $6 LER SCSS DATA

. :::_ __ 02-23-93 22._:2 _ ___: .__ __...__.::_ ::::__ _____::_

DOCKET YEAR LER IUISER REV!510N DCS NL8EBER N51C EVENT DATE 498 1992 014 9211030004

.: = : n . - _ _ _ u = =m e 0u u.___u =._=.u_u 0u;= = 09/2_.8./92 e ABSTRACT POE R LEVEL - 000E. On Septentier 28, 1992, Unit I was in mode 6 during a refueling outage. The Containment Ventilation Isolation (CVI) Actuation and Response Time Test was in progress. The procochare used verifies the response time for equipment remaired to actuate on a CVI signet by simulating a high radiation signet to radiation monitors RT 8012 and RT 8013. At 1623 hours0.0188 days <br />0.451 hours <br />0.00268 weeks <br />6.175515e-4 months <br />, white testing RT-8012, RT 8012 went into eterm and actuated the CV1. This occurred one step earlier than intended in the sequence of the procedure. The cause of this event was attributed to a teos than ademaste proceskare. The CVI actuation was caused by a high radiation siyst due to en artificially low high alarm setpoint established charing test conditions. The value used was too low for existing radiological conditions. Corrective actions include: 1) revising the Unit 1 surveillance proceskare to change the saattiplication factor used when calculating the new setpoint for the response time test to increase the test value of the high stare setpoint and 2) performing an evetustion to determine if the methodology can be laproved to reenace the potential for future actuations. LER92293001.U1 FORM 57 LER SCS9 DATA e=__.___.=___= ...u_=u..m. 02-23-93 m m. mmm mm DOCKET YEAR LER NUMBER REVISION DCS NL818ER NSIC EVENT DATE 498 1992 015 0 9 0 10/03 i

eu _ u u __u n u n u n u m ... m .211120152. m m u u n u n..u /92 ABSTRACT POWER LEVEL 0001. On October 3, 1992, at 0433 hours0.00501 days <br />0.12 hours <br />7.159392e-4 weeks <br />1.647565e-4 months <br />, Unit 1 was in Mode 6 white in a refueling outage. The C train (1C) Component Cooling Water (CCW) ptap received an automatic actuation from the miscellaneous header low pressure signet. Prior to the start. the operators had fitted and vented the Engineered Safety Features (ESF) heeeer operable status. of the is CCW train per the component Cooling Water system proceskare in order to restore it to an The miscettaneous header was isolated from the B train pump by closed autcastic volves and the IB play was not yet rwriing.

in the proceskare was to manuelty start the IB pimp.The static fiti and vent was completed satisfactority and a s When the 18 ptsp was started, the 1C plap started on low header pressure.

The cause of this event was attributed to inattention to operating conditions emecerbetad by proceskarat conditions which reestred extra attention by the operator. Corrective actions include revising the affected proceskare to make the mode selector switch setting mandatory, reviewing and revising additional precockares to incorporate the mandatory mode selector switch setting, co6siseling the involved Operatione l i

personnet, and incorporating this event into Licensed operator Requalification Training. LER92297001.U1 FORM 58 LER SCSS DATA

.uuuau ____ u u _ u u __ m m 02 23 93 m m .. m m m m ..

DOCKET YEAR LER IMIBER REVISION DCS NL818ER NSIC EVENT DATE 498 1992 016 0 921110012 0 mn_ _________num. m..m .m.1. m m .u_ 10/04/92 ABSTRACT POWR LEVEL 000E. On October 4,1992, Unit 1 was in Mode 6 during a refueling outage. The Domineralized Water nokste valve to the Component Cooling Water (CCW) surge tank had been isolated the previous day, in properation for en addition of corrosion irhibitor. At approximately 0318 hours0.00368 days <br />0.0883 hours <br />5.257936e-4 weeks <br />1.20999e-4 months <br />, Unit 1 emperienced an uretervied Engineered Safety Features (ESF) actuation due to en automatic p6mp start of CCW components caused by a low level in the CCW surge tart. The appropriate off noriset procedare was inplemented and level in the surge tank wee restored without further incident. Att ESF equipment operated as designed. This event was the result of a failure to reopen the CCW surge tank makeup valve foitowing a chemical addition. The immediate cause of this event is less than ademaste casameiications. An additional cause was the lack of a procetharat step to verify valve position.

This event will be included in requalification training for Licensed and non Licensed operators, chemical operators and chemistry techniciano. The procockare associated with this surveitlance witL be revised to include a requirement for verification when manipulating safety related yetves. Additionally, a review witL be performed of procockares that contains Operations and Chemistry interie es to ensure adocasete independent verification is specified for those systems that regsire verification of valve positioning. LER92297002.U1 l

l A-21 i

-_____A

l DRAFT FORM 59 LER SCSS DATA 02 23 93 eeee u x _ u u u .-_ _ = u ._: = = = _ . u u = en eee __ u u _ u om DOCKET YEAR LER NimgER REVISION DCS NLmcER NSIC EVENT DATE 496 1992 017 0 9212160045 0 11/11/92 e::_::__ __ __. _____:::__ ::__ :_ _:____:eee:__. __ __:_ ..:::

A88 TRACT POWER LEVEL 0001. On Noveeer 1,1992, et 1506 hours0.0174 days <br />0.418 hours <br />0.00249 weeks <br />5.73033e-4 months <br />, Unit 1 wee defueled sharing a refueling outage eruf unit 2 was in Mode 1 et 1001 power. The Survettlance Review Task Force identified that the Foeesoter Isolation Actuation and Response Time Testing procedures did not settsfy the requirements for the time reepense testing i between Safety injection and Feedwater Isolation because they did not test through the sieve relays. It mass later discovered that a simiter condition existed between NI*Hi Steen Generator Level and Feeduster Laeletion circuitry.

Unit 2 entered Technical Specification 3.0.3, however relief allowed by Technical Specification 4.0.3 was used to deley entry into the 3.0.3 oction statements for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to complete the regaired testing.

Unit 1 did not enter any Technical Specification action statemente since none were applicable et that time.

The regsf red testing wee completed for unit 2 on November 12,1992 et 0706 hours0.00817 days <br />0.196 hours <br />0.00117 weeks <br />2.68633e-4 months <br /> and for Unit 1 on Decamer 5, 1992 et 2030 hours0.0235 days <br />0.564 hours <br />0.00336 weeks <br />7.72415e-4 months <br />. The cause of this event was that the individuals involved in developing the original surveillance test precedures did not odegantely incorporate the regairements to perform the response time testing. Corrective action included performing the regaired response time testing using the slave releys one revising the Feechneter Isolation Actuation and Response Time Testing Procockares to occurately test through the steve releys. LER92335001.u1 FORM 60 LER SCSS DATA 02-23 93 e eem a . . . . . . . . . . u .emmeeeemeeeememeemee u . . u u :eeeeee DOCKET YEAR LER NLBIgER REVISION DCS NtalgER NSic EVENT DATE 496 1992 019 0 9301050273 0 tu02/92 e===.. .. .. __. u .ee m m e m e m eeee m ee m eeeeeeeeeeeeee m APSTRACT POWER LEVEL - 0001. On December 2,1992, Unit 1 was in Mode 5 during a refueling outage and unit 2 wee in Mode 1 at 1005 power. At 1500 hrs, white reviewing a nuclear eetwork item regarding a calculation error effecting the Power Operated Relief Velve (PORV) setpoint curves for the Cold Overpressure Mitigetton System (CtBIB), it wee determined that the same condition existed at South Temas Project. The snelysis perfonned by Westinghouse for the CINIS setpoint nestected the pressure loss of the reactor coolant flow through the reactor core. This resulted in a higher pressure et the reactor core mic5 Lane elevation then the pressure et the sensing point in the RCS hot Leg. Because of the error, CCBIS has been technically inoperable since the startup of each tmit.

Corrective actions for this event include issuing a Justification for Contirued Operation (JCO), resetting the high PORV CCBIs setpoint curves to meet the JC0 Limit and requesting Westinghouse to revise the CCBIS Safety Anotysis as wenn es providing a root cause enelysis on this event to determine the generic implication and corrective actions. LER92356001.u1 FORM 61 LER SCSS DATA emm 02-23-93

_ u u . = _ u u - _ = = = = = _ =:ee..........e m ee m m ee DOCKET TEAR LER NL81gER REVIS!001 DCS NUMgER NSIC EVENT DATE 496 1992 018 0 9212290250 0 10 eeo u = __ ___. u u u u ee = = u ._ u eee m eseeee m eeeeeee mm o m/21/92 ASSTRACT POWER LEVEL - 000E. On October 21, 2, Unit 1 was defueled charing a refueling outage. Af ter being reset et the third refueling outage for unit 1 (1RE03), to the specified value of 2445 psig +/- 1.01, the setpoints for the j 1

Unit 1 Pressuriser Safety Velves were found to be 4.71 below to 3.51 above the reasired setpoint charing the fourth refueling outage (1RE04). This is e deviation from the e/- 1.01 Technicet Specification regairement.

The Unit 1 Pressurizer safety Velves (PSV-3450, 3451 & 3452) had been sent to Wie Laboratories for setpoint verification testing. Pressuriter Safety valve setpoint drif t is en inchastry wide problem which as been known for some time. The Westinghouse Owners Group (WOG) has addressed this generic problem and WCAP-12910, which makes specific recteenendatione relative to PSV setpoint verification testing, has been issued. Corrective actions include pursuing of forts to modify the test prococture to test the Pressurf ter safety Velve lif t setpoint on saturated steen es recommended by WCAP 12910 which is pending NRC corcurrence. LER92346001.01 A-22

4 i

DRAFT FORM 62 LER SCs3 DATA 02 23-93 DOCKET YEAR LER lO SER REVISION DCS NLMBER liSIC EVENT DATE

.. 498

. 1992-020 0 9301130191 0 12/08/92 AS$ TRACT POWER LEVEL. - 0001. On December 9,1992, Unit I was in Mode 3 at 0% power. While operators were perfraing control boord walkdowns, it was discovered that the Toxic Gas Monitor ME 9326 channel was not in the tripped condition es ressired by Technicet Specif f cetion 3.3.3.7. Additionetiy on Deconeer 12, 1992 the monttor was once again fotsid not to be in the rowired tripped condition. Toxic Gas Monitor ME 9326 had been declared inoperable since November 23, 1992, chas to a noisy power supply and the chamel was tripped as reeJf red by Technical Specifications on Novemeer 28, 1992. The cause of this event was less than adeeJate design of the toxic gas monitors. There is no means to positively place the monitor in trip. A switch to ensure positive control of the trip function on the toxic gas monitors will be instatted. LER93006001.U1 A-23

. U" hY &c e.

4 _ h > . ,,

, - . . . l *,' i

.... .e. t. .

DIAGNOSTIC EVALUATION TEAM MEETING .- , , ..,_ c g w ,

/

Wednesday, March 10, 1993 -

t 'c. ./ ~/= e.s. '

MNBB, Room 6507 1 1:00 p.m. '..troduction B. Hehl/S. Rubin e Team Organization, Areas of Evaluation, Schedule e Mission of the Diagnostic Evaluation (DE)

Program

. DE Process and Methodology e South Texas Project - Areas of Special Interest 1:30 p.m. - Conduct of the Diagnostic Evaluation R. Lloyd/H. Bailey e DE Team Licensee / Counterpart Meetings e DE Observation Forms e Formal Management Interviews  ;

e Team Leader and Member Roles and Interfaces e Onsite Interim Exit Meeting .

. Team Member and Contractor Professic.salism 2:00 p.m. - Break '

2:20 p.m. - Conduct of the Diagnostic Evaluation (Continued) t e Plant Description and System S. Pu11ani Selected for Verticle Slice 2:50 p.m. - Evaluation Plans and Report R. Lloyd/H. Bailey

. Functional Area Evaluation Plan 1 Preparation e DET Report Format and Schedule 3:20 p.m. - Bagman Trip Debriefing H. Bailey /M. Smith e Documents on Hand e Document Libraries e Document Control Process e Information Binders 3:40 p.m. - Functional Area Team Breakout Meetings

. Functional Area Evaluation Plan Review /

Assignments e Performance / Background Material Review 5:00 p.m. - Adjourn s

y .

J-r i

DIAGNOSTI EVALUATION TEAM MEETING  ;

Wednesday, March 10, 1993 MNBB, Room 6507 1:30 p.m. . Conduct of the Diagnostic Evaluation - Lloyd/ Bailey /Pullani DET Characteristics - Henry.

o During the conduct of the DEie Jiscussed earlier) the DET:

Identifies (or confirms) and documents both strengths and weaknesses in safety performance. i For weaknesses, the team evaluates and documents the adequacy of associated corrective actions. ,

Identifies the root causes of weaknesses, including any weaknesses in corrective actions.

o I want to stress again that the evaluation is performance based and can I include any safety related, important to safety and/or BOP equipment. Do not evaluate a performance issue in terms of known or potential i violations of regulations. If you do, you will be likely miss the big picture on performance issues; issues that clearly impact performance, but are not normally cited as violations.

o With regard to programmatic issues; do not pursue an issue unless you suspect it to be a root cause of a performance weakness. . The STP is believed to have excellent programs on paper.

Data Collection - Henry o One important feature of a DE is the large amount of document review completed before the team goes onsite. This review allows you to rapidly come up to speed on the issues after you reach the site and contribute fully to the DET.

o Weaknesses in performance are not hard ta find. The licensee has many of them documented in miscellaneous deficiency tracking systems such as station problem reports (SPRs), service requests (SRs), and QA Audits, surveillances and assessment reports. We have stacks of these documents in our DET library, o Despite all these documented performance problems, in many cases the licensee doesn't know: 1) the full extent of the problem, 2) how to temporarily fix the problem with the available resources, and 3) what the root causes are (that would identify a permanent fix). So these s deficiency tracking system documents I have mentioned are a good place to get started before we get to the site.

i ) [{}

1 l

o Documents that are relevant to your functional area should be read while the DET is still in Bethesda. Michelle will discuss our DET library later.

o I have beaten-on document reviews pretty good, but the other methods of ,

data collection are also a little different for a DE. We do a large number of interviews. To really understand how an organization functions-(or fails to function), interviews are essential. To understand in the shortest time what the problems are, interviews are invaluable. You will find that the workers know what the problems are if you will just ask them and it can save you from drilling a lot of dry i holes. And some of them have been just hoping that you would ask them. i Other people on the DET will need to know what you find out in- 1 interviews, so we ask you to document the interviews. Enough for r.ow on 1 interviews. Ron will be talking more on this later.

o The last data source I will mention is observations. We do observations as the opportunity arises, but don't count on the opportunity arising as much as you may be accustomed for activities such as maintenance, testing and plant evolutions. DETs have a high profile onsite and for whatever reason, we haven't been able to observe a lot of maintenance, for example. We also believe what you d2 observe may be skewed quite a bit from the normal routine. We believe that if the document reviews mentioned earlier show, for example, that there have been repeat failures of a major piece of equipment, then the DET's time onsite might better be spent understanding why the repeat failures occurred than on witnessing another corrective maintenance on this equipment that might cover 3-4 days and would most likely be done strictly by the book while the DET observes (due to high DET profile and lack of time for maintenance to " lapse back" into their normal habits). Of course, the j ideal situation is for the DET to do both activities. l Team Leader and Member Roles and Interfaces: Henry o The team leaders will schedule and assign members work onsite.

o Team members should not represent an issue as a finding to the licensee until it has been discussed with the team leader and he has agreed.

Interviews: Ron o Two types - structured and unstructured.

Interview Preparation and Conduct:

1. Determine what it is you need to know, and who you should talk to gain the information before you schedule an interview.

2. Clearly write down your interview questions in a logical order.

This will help you to control the interview, and at least appear coherent in front of the licensee. To open the interview, allow a

l .

I few minutes to introduce yourself and to explain what the interview is.about. For structured interviews, prepare 10 to 15 questions that you would like answered. Generally, "open" type questions are preferred. Ask your questions and let the '

interviewee talk. Be professional, do not use " leading" or

" loaded" questions, and don't make any snide remarks. Each time you finish an interview, the licensee will get together and talk about what kinds of questions were asked and the individual's -

responses. Mix things up.

3. For a structured interview, plan on spending at least one hour and not more than two hours to complete your interview.

4. Provide for at least a 1/2 hour block of time following your interview to expand on the notes that you took on questions asked.

Interview Closing:

1. Recap areas covered by the interview with the interviewee.

1

2. Ask the interviewee if he/she has any additional questions to ask.

3. Recap what the interviewee owes you in terms of documents requested, unanswered questions, etc. If a document is requested,

. fill out a document request form so it can be properly requested and tracked by Michelle.

Interview Documentation:

1. Immediately following your interview, go over your interview notes to fill in additional detail whi.e your memory is still fresh. If you can type, use the word processor to save you valuable time.

2. Transfer interview notes to a DEO form on a disk. Underline what you feel is important information, including strengths or weaknesses.

o Structured interviews should always be summarized and documented in a Diagnostic Evaluation Observation (DEO) format. Each functional area (FA) team (except M&O) should try to conduct 3-4 structured interviews each day. The M&O team will conduct many more.

o Inform Michelle of interviews that you plan to do. The schedule of first week's interviews should be set prior to arrival onsite. Look at the organization chart to pick your interviewees.

o Each functional area (FA) team should start with the department /section I head, both as a matter of courtesy and also to understand the big picture on how the organization is supposed to be operating, and where the interfaces are with other departments. Some senior managers are eager to indicate where they think the problems are and their plan for correction. They will also indicate what they believe are organizational strengths.

i o Early on, the interviews should shift more to a " bottom up" approach, i.e. nonsupervisory personnel, foremen,1st line supervisors, etc.  ;

DE Observation Forms (DEOs): Ron i

o Used to record both the results of interviews and functional area team findings. You will receive a copy of a file with blank DEO forms.

o DEOs include statement of the issue, substantiating information, an assessment of the root cause for findings, and licensee actions being taken to address your concern.

i o The potentially significant portions of all interviews are recorded on DEOs as soon as practicable after the interview. '

o In addition to interviews, those findings expected to be discussed in j the DET report are included on DEOs.

o DEOs are predecisional information. Neither DEOs or any other written idraft1 information is to be oiven to licensee. ,

i o Give a copy of your DE0 file (disk) to Michelle every couple of days, so she can print and merge the files as necessary. This way, all DEOs can '

be read by the entire DET.

l i

Functional Area Team Meetings With Licensee Counterparts: Henry o Team leaders meet daily preferably just before DET meeting.

o Purpose - to keep licensee appraised of findings of fact, clear up any mistakes in the facts, coordinate future activities.

o Make your licensee counterparts aware of all your DEOs as they are written. This will allow the licensee the opportunity to understand the ,

concern and rebut each DEO. ,

o Have a mini closeout meeting with your counterpart no later than the 9th i of April and the 30th of April. Go through each DEO and come to an understanding of the validity of the concern. >

l Note: Scheduling interviews and requesting documents should be coordinated r through Michelle to avoid duplication and schedular conflicts.

DET Meetings: Henry o All team members are expected to attend the daily DET meetings. The  !

team leaders will be the spokepersons at the meetings unless either a

, member's team leader or the DET manager asks a member to address an issue.

o Items discussed at these DET meetings should be limited to those of l

general interest and should not include of detailed expose or your team's itinerary for the riay.

Onsite Interim Exit Meeting: Henry o DET Leader will present team observations for each functional area except M10 on April 30. Your specific functional area observations will be turned in to the DET Leader by noon on April 29.

l Team Member and Contractor Professionalism: Henry / Bill o No prospecting for future business with the licensee o No exchanging of business cards trith the licensee

, o No fraternizing with the licensee I

I o No shop talk in resturants and bars that can be heard by anyone outside i the DET o Any questions, discuss them with your team leader 2:00 p.m. - Break - All 2:20 p.m.- Plant Description and System Selection S. Pullani 2:50 p.m. - Functional Area Evaluation Plan Preparation: Ron o Each functional area team leader (with support from their team members) is responsible for producing an evaluation plan to be reviewed by the ,

DET Leader during the second meeting March 24-25. I o Keep the evaluation plan concise, not exceeding 4-6 pages single spaced.

o Allow for contingencies in your plan. Don't continue to beat a dead i' horse just because you have an assignment to look at a particular area.

If you find a dry hole, move on to sramething that would be productive.

3 The format for your evaluatica plans should mimic the report format (see I

the FitzPatrick DET report). Assign responsibility for each section of your plan. This process will save time during the report writing phase.

of the DET.

Report Format and Schedule: Ron o Report format and level of detail should resemble the FitzPatrick .J

. . __ _= -. . - _ . -

1 i

report. The first s 'tence in each paragraph /section should be written ;

in conclusion form. e remainder of the paragraph /section should  :

provide the details t :noport the conclusion made.

j o Use the King's english :n past tense.

o Initial draft of DET report due May 12. i o

Your report section should be 99% complete by the week of May 24, since this is the week of the formal licensee exit. Each team will be i required to produce final findings and conclusion slides to be used at the exit.  !

o final report due to the EDO by June 11.

3:20 p.m. - Bagman Trip Debriefing Prescott/ Smith i

i f

l I

4 l

DIAGNOSTIC EVALUATION TEAM MEETING .

Thursday, March 11, 1993 MNBB, Room 6507 8:00 a.m. - Introduction E. Jordan /B. Hehl 8:30 a.m. - Region IV Briefing l e Director Reactor Projects B. Beach e Deputy Director Reactor Safety A. Howell e Senior Resident Inspector J. Tapia 10:00 a.m. - Break 10:20 a.m. - NRR Briefirg

. South Texas Project Manager G. Dick '

. LPEB Performance Evaluation P. Ray 11:10 a.m. - AE0D Performance Indicators D. Hickman e Plant PIs ,

e Maintenance PIs 11:30 a.m. - DET Administrative Requirements M. Smith

. Travel Arrangement

. Rental Cars t e Lodging Accommodations i e Site Access Training .

. Working Hours / Timekeeping  !

1 12:00 p.m. - Lunch 1:00 p.m. - Breakout Meetings

. Team Manager / Team Leader Interface Meetings  !

. Team Member Performance / Background Material Review 3:00 p.m. - STP Badging Activities A. Woods l 5:00 p.m. - Adjourn Friday, March 12, 1993 MNBB, Room 6507 8:00 a.m. - 2:00 p.m. Continue Team Breakout Meetings O.

e Functional Area Evaluation Plan Review /

Assignments Performance / Background Material Review j ///)

.