IR 05000335/1996004

Partially Withheld Draft Ltr Forwarding Draft Insp Repts 50-335/96-04 & 50-389/96-04 on 960218-0330 & Draft Notice of Violation

ML20140A461
Person / Time
Site:	Saint Lucie
Issue date:	05/23/1997
From:	Landis K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20140A447	List: IR 05000335/1996004 ML20140A443
References
FOIA-96-485 50-335-96-04, 50-335-96-4, 50-389-96-04, 50-389-96-4, NUDOCS 9706040211
Download: ML20140A461 (76)

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! PREDECISIONAL

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DRAFT INFORMATION NOT FOR DISTRIBtTIION l

l Florida Power & Light Company l ATTN: T. F. Plunkett President - Nuclear Division -

P. O. Box 14000 l Juno Beach, Florida 33408-0420 SUBJECT: NRC INTEGRATED INSPECTION REPORT NOS. 50-335/96-04 AND 50-389/96-04 ,

l AND NOTICE OF VIOLATION

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! Gentlemen:

This refers to the inspection conducted on February 18 through March 30. 1996,  :

at the St. Lucie facilit The purpose of the inspection was to determine l whether activities authorized by the license were conducted safely and in l l accordance with NRC recuirements. At the conclusion of the inspection, the I

findings were discussec with those members of your staff identified in the

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enclosed repor ;

t Areas examined during the inspection are identified in the report. Within these areas, the inspection consisted of selective examinations of procedures and representative records, interviews with personnel, and observation of activities in progress.

Based on the results of this inspection, the NRC has determined that violations of NRC requirements occurred. The violations are cited in the enclosed Notice

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of Violation (Notice) and the circumstances surrounding them are described in l detail in the subject inspection report. The violations are of concern because they indicate that personnel performance with respect to procedure compliance and I usage and attention to detail persist even after corrective actions had been l completed for previous, similar, violations. Particularly illustrative of this

! point is a violation for failures associated ,with the Unit 1 containment particulate / iodine / gaseous radiation monitor. The event displayed particularly poor performance on the part of several individuals and includecl aspects of i failing to access and follow a procedure, compounded by failing to capitalize on

! multi)le opportunities to identify the inoperable component through logtaking.

l Logta ting weaknesses were furt'aer compounded by the fact that non-licensed operators taking the logs were electronically prompted that a key parameter

associated with the component's operability was unacceptably low. The failure l to pursue this condition, over six logtaking opportunities, would tend to I indicate that a lack of a questioning attitude extends to multiple personne It is also noted that a failure to employ an approved procedure lead to a condition ,of Emergency Diesel Generator inoperability (the subject of another violation in the enclosed report). ,

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9706040211 970523 PDR FOIA BINDER 96-405 PDR C:W'51\00QgGT\lR-96-04\SL9604. MAR

infammlienth Wf rectMSWes 6mmd8 1997 in accordance with)e Freedom of InformM Act, exemptions & 7C-E0lk 76 M S /

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PREDECISIONAL DRAFT INFORMATION NOT FOR DISTRIBUTION

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As documented in the report, we have performed an initial review of the Licensee Event Report you submitted for the subject event. While we found your immediate corrective actions appropriate, we question the scope of the actions delineated in your transmittal. Consequently, in your response to the enclosed Notice,

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please describe what actions you will take to instill, in non-licensed operators, an understanding of the vital role they play in the early detection of off-normal conditions during logtaking and log review. Additionally, please describe your basis for believing that other cases of inoperability in components have not been overlooked through similar errors and any actions you have taken (or plan to take) to identify those components which may be rendered inoperable in a similar manner (by non Operations personnel performing routine evolutions for which the control room may not have cognizance). We would be very interested in how your Plan to Improve Operational Performance initiative is (or will be) addressing the problems leading to this violation. Please be prepared to discuss this issue at the next FPL/NRC management meetin You are required to respond to this letter and should follow the instructions specified in the enclosed Notice when preparing your response. In your response, you should document the specific actions taken and any additional actions you plan to prevent recurrence. Your response may reference or include previous docketed correspondence if the correspondence adequately addresses the required response. After reviewing your response to this Notice, including your proposed corrective actions and the results of future inspections, the NRC will determine whether further NRC enforcement action is necessary to ensure compliance with NRC regulatory requirement In accordance with 10 CFR 2.790 of the NRC's " Rules of Practice " a copy of this letter, its enclosures, and your response will be piaced in the NRC Public Document Room (PDR). To the extent possible, your response should not include :

any personal privacy, proprietary or safeguards information so that it can be placed in the PDR without reductio The responses directed by this letter and the enclosed Notice are not subject to the cle'arance orocedures of the Office of. Management and Budget as i equired by 1 the Paperwork Reduction Act of 1980, Pub. L. No.'96-51 j Should you have any questions concerning this letter, please contact u

Sincerely, l

l Kerry D. Landis, Chief l Reactor Projects Branch 3 ,

Division of Reactor Projects

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Docket Nos'. 50-335, 50-389 License 4Nos. DPR-67, NPF-16 l

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PREDECISIONAL ;

DRAFT INFORMATION~ NOT FOR DISTRIBUTION i

Enclosures:

Notice of Violation

Inspection Report

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REGION II==

l Docket Nos: 50-335, 50-389 ,

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License Nos: DPR-67, NPF-16  !

Report No: 50-335/96-04, 50-389/96-04 I

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Licensee: Florida Power & Light Co.

Facility: St. Lucie Nuclear Plant Units 1 & 2

!~ Location: 9250 West Flagler Street

Miami, FL 33102

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! Dates: February 18 - March 30, 1996  !

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Inspectors: M. Miller, Senior Resident Inspector 4 S. Sandin, Resident Inspector i M. Thomas, Reactor Inspector, paragraph M1.2

F. Wright, Reactor Inspector, t )aragraphs R1, R3, R5, R6, R7, and R8 j 1. Chou, Reactor Inspector,

, paragraphs 1.2.1 tt) rough 1.2.4 l E. Lea, Project Engineer, j paragraphs 04.2, 04.4, M8.2, M8.3, and M8.4

J. Coley, Reactor Inspector, paragraphs M1.2.5 through 1.2.10 and M Moorman, License Examiner, paragraphs 04.3 and Approved by: K. Landis, Chief Projects Branch 3 i Division of Reactor Projects c

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DRAFT INFORMATION' NOT FOR DISTRIBUTION EXECUTIVE SUMMARY St. Lucie Nuclear Plant. Units 1 & 2 NRC Inspection Report 50-335/96-04, 50-389/96-04 This integrated inspection included aspects of licensee operation >. maintenance, and plant support. The report covers a 6-week period of resident inspection; in addition, it includes input from regional inspectors in the areas of Maintenance and Plant Suppor Doerations e Operators performed well during a Unit 1 dropped CEA event on February 2 Response to the transient, declaration of an Unusual Event, and a manual reactor trip (inserted when feedwater anomalies were identified) were all timely and appropriat e The return to power of Unit 1 was complicated by an attempt to synchronize to the grid with the main generator disconnects ope A procedural weakness was the root caus e Walkdowns of both units' Containment Spray systems resulted in the identi fication of a number of procedural, drawing and hardware deficiencie e Control room observations resulted in the identification of:

e a failure to employ a procedure for boric acid addition (an additional example of a previous violation - VIO 96-03-01)

e failures to make required log entries for reactivity manipulations and a main generator hydrogen addition (VIO 96-04-02)

e A containment gaseous / particulate / iodine monitor was rendered inoperable due to a failure to follow procedures, c9mbined with a lack of proper follow through on the part of non-licensed operators taking logs (VIO 96-04-01).

e An Emergency Diesel Generator was rendered inoperable due to a failure to follow procedures while placing the fuel oil tank on recirculation (VIO 96-04-03).

e The requalification program is supporting management expectations for operations and covering timely and important topic Maintenanch a

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e The procedures used for testing and maintenance on a number of observed I maintenance activities were adequate to provide the details for the craft

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to perform maintenance. inspection, and calibration. The crafts were knowledgeable and skillful in doing work. The inspectors were satisfied with the work performed. However..one weakness was observed for a crew l not signing and dating the work copy of the Work Order in the field prior ,

to physically starting wor '

l e A review of maintenance rocedure revision control indicated that th )

licensee's program contai ed vulnerabilities which could result in the  !

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wrong revision to a given procedure being used in the fiel The licensee's corrective actions were satisfactor e There were weaknesses noted in the licensee's maintenance program relative to the SBCS valves and MFR e Reviews of historical data for CEA maintenance revealed that post- l modification testing acceptance criteria for Unit 1 CEA power cables were not applied to post-modification test data (VIO 96-04-04).

e Closeout of an Unresolved Item concerning poor HP work practices exhibited by maintenance personnel resulted in a non-cited violation for failure to adhere to Radiation Work Permit requirements (NCV 96-04-05)

Enaineerina e The engineering disposition for a deficiency identifwi in Unit 1 Boroflex panel length was reviewed and found to be satisfactor Plant Sucoort e Based on interviews with licensee staff, record reviews, and observations made during tours of licensee facilities: the inspector found the RP program to be adequately managed .and internal and externa exposure control programs were effectively implemented with all radiation exposures within 10 CFR Part 20 limits. One non-cited violation was identified concerning failure to follow procedures for the control of contaminated tools utilized in the licensee s radiological control area (NCV 96-04-06).

e The permanent modifications for cooling Unit 2 Containment Building in 1995 was 'a positive step in increasing worker efficiency and reducing collective outage dose and number of personnel contamination events. The modification demonstrated managements comitment to worker safety. RP and ALAR e Unp15nned maintenance activities and rework significantly increased outage work in 1995 and was the primary reason the licensee exceeded it's 1995 4 I- C:\W1\D00MNn!R 96-04\SL9604. MAR Report printed 10:56 am. Tuesday. January 14. 1997 10 f

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annual collective dose goal of 2.83 person-rem by approximately 129 person-

rem. This was bas 1cally a maintenance and operations problem adversely

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irr?wHgg the statjon ALARA program. ,

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PREDECISIONAL DRAFT INFORMATION - NOT FOR DISTRIBUTION Report Details Summary of Plant Status

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Unit 1 ,

. 1 Unit 1 operated at full power from the beginning of the inspection period until l

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February 22, when a manual trip was initiated during a unit shutdown. The shutdown was the result of a dropped and unrecoverable CE The unit achieved criticality on February 24 and returned to full power operations on February 2 On March 26. the unit was downpowered for waterbox cleaning. The unit returned j to full power on March 29 and remained at full power through the end of the l inspection perio l

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Unit 2 Unit 2 operated at essentially full power throughout the inspection perio l I. Ooerations 01 Conduct of Operations (71707, 61726, 93702)

01.1 General Comments

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Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of opera-tions was professional and safety-conscious; specific events and notewor-thy observations are detailed in the sections belo .2 Unit 1 TS reauired shutdown / trio On February 22, at 8:55 a.m. . Unit 1 began FLCEA testing per OP 1-011005 " Control Element Assembly Periodic Exercise." This test is performed at least once every 92 days in modes 1.or 2 as required by TS 4.1.3.1.2 to verify o)erability of each full-length CEA' not fully inserted. Per the test metlodology, each full-length CEA is inserted at least 7.5 inche All CEAs in Groups 1, 2 and 3 were successfully exercised. At 10:03 when operators were preparing to exercise CEA #57 (the last CEA in Group 4), CEA #20 (Group 2) dropped. Power initially fell to 93 percen Operators responded promptly by matching turbine load per 0NOP 1-011003 "CEA Off-Normal Operation and Realignment." Efforts to recover CEA #20 were unsuccessful and, consequently, a Unit 1 shutdown per TS 3.0.3 and NOUE occurre The inspector was present in the control room and observed the decision-making process leading to a unit shutdown. Initially. Unit 1 entered TS 3;1.3.1 action statement e. which stated "With one full length CEA C:\bPSl\DOCtKNT\lR-% 04\SL%04MR Report printed 10[56 am Tuesday, January 14,1997 12

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l misaligned from any other CEA in its group by 15 or more inches, operation

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in Modes 1 and 2 may continue providri that the misaligned CEA is )

positioned within 7.5 inches of other CEAs in its group within the time

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constraints shown in Figure 3.1-la." Figure 3.1-la allowed 60 minutes to

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restore CEA group alignmen l At 10:30 a.m., when it became clear that CEA #20 was not recoverable, action statement f. was entered. Action statement f stated:

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"With one full length CEA misaligned from any other CEA in its group

by 15 or more inches beyond the time constraints shown in Figure 3.1-la, reduce power to less than or equal to 70 percent of rated thermal power prior to completing action f.1 or Restore the CEA to operable status within the specified alignment requirements, or  ;

I Declare the CEA inoperable and satisfy the shutdown margin l requirements of Specification 3.1.1.1. After declaring the )

CEA inoperable, operation in Modes 1 and 2 may continue l pursuant to the requirements of Specification 3.1. provided:

a) Within one hour the remainder of the CEAs in the group with the inoperable CEA shall be aligned to within inches of the inoperable CEA while maintaining the l allowable CEA sequence and insertion limits shown on ,

Figure 3.1-2: t' ne thermal power level shall be :

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restricted to Specification 3.1.3.6 during subsequent operation perio b) The shutdown margin requirement of Specification 3.1. is determined at least once per 12 hourc." l The shutdown margin calculation was pdrformed using OP 1-011005 I

" Surveillance Requirements for Shutdown Margin. Modes 1 and 2 (Critical)." ;

There was a discussion between operations and reactor engineering on ,

whether the more restrictive PDIL of Unit l's Plant Physics Curve C.5 as referenced for an immovable CEA were applicabl If so, this would require reducing power to less than approximately 34 percent within 1 l hour. It was concluded that imovable referred to a withdrawn stuck CEA and was not applicable in this case. However. TC #1-96-33 was issued to document this clarificatio ,;

At 12:00 p.m.. Unit 1 entered TS 3.0.3 since CEA #20 could not be real'igned within the one hour allowed for continued operation. At 12:05 f p4m., the NPS dec16ced an NOUE based on Increased Awareness due to a p

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PREDECISIONAL DRAFT INFORMATION' NOT FOR DISTRIBUTION Shutdown required by Technical Specifications for which the required shutdown is not reached within the action limits. Since TS 3.1.3.1 had no

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explicit requirement or allowed time associated with a single inoperable CEA not aligned within 7.5 inches of the other CEAs in the group, the

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licensee's encry into TS 3.0.3 was appropriate. However, the basis for l

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the declaration of an NOUE was incorrect. TS 3.0.3 stated JWhen a LCO is not met, except as provided in the associated action requirements, within l one hour action shall be initiated to place the unit in a mode in which l the specification does not apply by placing it, as applicable in at least .

hot standby within the next six hours." An NOUE would have been required '

if the unit was not in hot standby within seven hours. The inspector reviewed EPIP 3100022E. " Classification of Emergencies " and concluded that the NOUE was voluntary based on criteria 6.A. for Unusual Even " Emergency Coordinator's Judgement that plant conditions exist which warranted increased awareness on the part of the operating staff and/or local authorities."

During the shutdcwn at approximately 30 percent power with only the "1B" MFW pump in service, operators observed fluctuations in SGWLs. An attempt to take manual control of the "1A" MFRV and prevent overfeeding the SG was unsuccessful. The NPS directed operators to manually trip the unit at ,

approximately 26 percent powe Various equiament problems were l encountered following the trip and during restart w1ich are discussed in  !

paragraphs M2.1 of this repor l At 1:30 p.m., the NOUE was exited with Unit 1 stable in hot standby (mode l 3),

The inspector observed the operators respond to the dropped CEA #20 and '

i implement the Emergency Plan. Operator response was consicered excellen All required actions were promptly executed with a minimum of direction provided by supervisio The inspectors' reviewed the post. trip package which was, with the exceptions noted in paragraph M1.2, considered acceptabl On February 23 at 9:00 a.m. Unit 1 commenced a startu During withdrawal of Shutdown Bank "A" for an operability check, CEA #47 dro) ped from 12 inches to the bottom. At 11:55 a.m. the remaining Shutdown' 3ank

"A" CEAs were driven to the bottom and the startup terminate A containment entry was made for I&C troubleshooting of CEA #47 proble y

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See paragraph M1.2 of this report for a discussion of CEA troubleshooting

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issue Unit 1 completed a second startup and was returned to service on February 24. 'See paragraph 01.3 of this report t i

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. 01.3 Unit 1 Switchyard Electrical Misalianment-R:I 96-A-0039

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On February 24. at 2:15 a.m. . Unit 1 commenced a second startup with entry into Mode 1 on February 25 at 12:33 a.m. After ' closing the Main l Generator Output Breaker during synchronization with the Grid operators received annunciator C-29. " GENERATOR MOTORING," and noted that the

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i synchroscope continued to rotate. The Main Generator Output Breaker was 1 opened to prevent a backup lockcut and Generator trip. The licensee i

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determined that both Unit 1 Generator Disconnects, 8G27 and 8G29, were ,

open (the Main Generator disconnects are opened aer procedure if the unit i is off-line more than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> by either OP 1-0030125. " Turbine Shutdown - ,

Full Load to Zero Load." step 8.29 or, in this case,1-E0P-02, " Reactor l Trip Recovery," step 20). TC 1-96-036 to OP 1-0030124 " Turbine Startup Zero to Full Load." was issued to restore the switchyard lineup following which, the Main Generator was successfully synchronized to the Gri I The inspector had several concerns regarding the switchyard misalignment:

e No STAR or IHE was generated documenting that an inadequate l procedure was identified during use which resulted in an anticipatory alarm that a generator backup lockout would occur. An Operations Department Problem Report (Data Sheet 7) was complete however AP No. 0010120 Rev 79. " Conduct of Operations" step states that " Problem reports should be utilized to supplement other reporting and corrective processes; i.e.. LER. IHE."

e Completed OP 1-0030124 did not document any repeated steps following the initial failure to synchronize to the grid as reported in the RCO log entry of 3:55 e OP 1-0030124 was revised in October 1995 adding a .N_QTF,before step 8.1 which stated "Jf startup of the turbine is a result of a turbine trip OR Turbine shutdown and the cause has been corrected. Then the subsequent restart can be commenced with Section 8.3." This revision failed to provide a separate verification that the Unit 1 Generator Disconnects. 8G27 and 8G29, were CLOSED as was accomplished in step 8.1.4 if steps 8.1 and 8.2 were not performe e TC 1-96-036 added the above verification as step 8.3.1. resequencing ,

all other steps in section 8.3. Since the completed OP 1-0030124 did not document any repeated steps, the inspector concluded that this step was performed out-of-sequenc ,.

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' wit 1 no signatures. This precludes an independent verification that [4 C:\leSl\DgNT\lR-96-04M9604.MR Report printed 10:56 am. Tuesday January 14. 1997 15 f

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PREDECISIONAL DRAFT INFORMATION - NOT FOR DISTRIBUTION l a particular step was or was not performe l

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The liccnsee initiated a Data Sheet 7 (Operations Departnnt Problem l Report) to document this event. Unit 1 completed the power ascension without further inciden Operational Status of Facilities and Equipment (71707) l 02.1 Enaineered Safety Feature System Walkdowns The inspectors used Inspection Procedure 71707 to walk down accessible portions of the following ESF systems: During the week of March 4, the inspector performed a walkdown of the Unit 1 Containment Spray System. This consisted of a review of the following procedures and engineering drawings and verification of current system alignment including:

e OP 1-0420020 Rev 31. " Containment Spray - Initial Valve Alignment" l e ONOP 1-0030131. Rev 62, " Plant Annunciator Summary" e Applicable Engineering Drawings The following discrepancies were noted: l (1) OP 1-0420020. Rev 31. " Containment Spray - Initial Valve Alignment" e V07230 was listed as Locked Closed, however, no lock was l installe e V07163 and vd7191 positions were given as Closed although they were Administratively Controlled as Locked Closed per AP 1-0010123 gnd did have locks installe e Precaution 4.1 stated that "Certain valves in this system are aligned for shutdown cooling and must not be repositioned without considering the impact upon shutdown cooling. These valves will be designated."

The following valves were not designated as shown in OP 1-0010123 (sheets 43, 46, and 52):

e V07161 (sh. 43). V07164 (sh. 46) and MV-07-3 MV-07-3B (sh. 52) were designated " Locked Closed

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when Shutdown Cooling in service."

"f 4 e V07130 was Locked Closed during cooldown and (

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should have been annotated by Note 2, "These

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cooldown."

e MV-07-1A and MV-07-1B were annotated with Note however, they were not repositioned Locked Closed per OP 1-0030127 (Cooldown) and OP 1-0030121 (Heatup - sh. 14.

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15) only ensured that these valves were Open or Locked-Ope e V07160 had no valve tag or other identifier.

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e V07224 and V07225 descriptions were not consistent with i

AP 1-001012 d e SE-07-1A. SE-07-2A. SE-07-1B SE-07-2B descriptions were i not consistent with RTGB-106 tag identification, l (2) ONOP 1-0030131. Rev 62. " Plant Annunciator Summary" e Annunciator R-2 CAUSTIC TANK PRESS HIGH

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Setpoint 7 psig was incorrec PIS-07-7 was set at 8 l psig increasing (TEDB).

j e Annunciator R-12 CAUSTIC TANK LEVEL LOW / LOW-LOW

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l Setpoint in TEDB was given as 65" decreasing and 3" decreasing. Gallonage was from strapping table which was not referenced. The Sensing Element LIS-07-7D only -  !

closed one of four NaOH admission valves. The other  !

three closed on a Caustic Tank Level Low-Low setpoint of l 3" decreasing from LIS-07-7A. LIS-07-7B and LIS-07-7 e Annunciator R-21 CONTMT SPRAY HEADER A PRESS LOW

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Sensing element was identified as PT-07-3A. rather than PIS-07-3A appearing on CWD 362 e Annunciator R-22 CONTMT SPRAY HEADER B PRESS LOW Sensing element was identified as PT-07-3B rather than PIS-07-3B appearing on CWD 362

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e Annunciator R-31 CONTMT SPRAY FCV-07-1A FAIL TO OPEN

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DRAFT INFORMATION'- NOT FOR DISTRIBUTION j on CWD 28 CWD showed alarm after 15 second l

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e Annunciator R-32 CONTMT SPRAY FCV-07-1B FAIL TO OPEN Setpoint of 10 seconds after OPEN signal was not shown on CWD 28 CWD showed alarm after 15 second (3) Engineering Drawing e 8770-G-08 "Flos Diagram Containment Spray and Refueling Water Systems." Rev 31 l LT 07-7A is shown isolated by V07237 and V07244. Field verification found junction box with cable to LT labelled as LT 07-7 LT 07-7C is shown isolated by V072387 and V07243. Field verification found junction box with cable to LT l labelled as LT 07-7 i V07223. V07230 and V07233 were not shown as Locked Close V07152 IB SDC HX Outlet vent was installed at the bottom of the pipe, thus appearing unable to vent the piae. In contrast. V071/.81A SDC HX Outlet vent was installed on the top of the pip !

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(4) OP 1-0010123. Rev 100. " Administrative Control of Valve l Locks and Switches" l

e V07223. V07230 and V07233 were Locked Closed in OP 1-0420020. however, none were Administratively Controlled l per AP 1-001012 ,

o V07145. V07130. V07255. V07257 (sh. 72), and V0727 V07272 (sh. 74) were not designated " Valves Locked Closed if Shutdown Cooling in service or less than 1750 psia RCS Pressure" as was done for Unit j e MV-07-3A and MV-07-3B (sh. 43, 46 and 52) appeared in Appendix "F." TC# 2-95-683 transferred the functionally '

equivalent valves MV-07-3 and MV-07-4 from Appendix "F" to Appendix "L." MV-07-3A and MV-07-3B were also

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repositioned by OP 1-0030127 (Cooldown). This was identified as an inconsistency between Unit [i t *

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PREDECISIONAL e DRAFT INFORMATION NOT FOR DISTRI8UTION During the week of March 11. the inspector performed a walkdown of the Unit 2 Containment Spray System. This consisted of a review of l

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of current system alignment including:

.e OP 2-0420020. Rev 1 " Containment Spray initial V61ve Alignment" i e ONOP 2-0030131. Rev 50, " Plant Annunciator Summary"

e Applicable Engineering Drawings

. The following discrepancies were noted

(1) OP 2-0420020. Rev 1 " Containment Spray Initial '!alve

Alignment" )

e V07106, V07390 through V07393. V07191 and V07163  ;

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positions were given as Closed although they were i Administratively Controlled as Locked Closed per AP 2-s 0010123.

i e MV-07-3 and MV-07-4 positions were given as 0)en

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although they were Administratively Controlled as Locced

Open by keyswitch at RTGB-206 per AP 2-001012 i

e V29429 and V29430 (Nitrogen Supply) were not included in

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initial lineup as was done for Unit e V3868 2A SDC HX Outlet Vent was omitted from lineu l

e Valves whose positions would be verified by control room i indication. e.g. SE-07 3 SE-07-35. riv-0/-1A. MV-07-1 MV-07-3. MV-07-4. etc. , were r.ot identified as was done  :

for Unit 1.

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e Precaution 4.1 stated that "Certain valves in this i system are aligned for shutdown cooling and must not be repositioned without considering the impact upon

, shutdom coolin These valves will be designated."

The following valves were not designated as shown in OP i 2-0010123 (sheets 51, 54, 84 and 85):

' e V07162 (sh. 51) and V07165- (sh. 54) were designated " Locked Closed when Shutdown Cooling in service." j

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e V07145. V07130 (sh.85), and SH07248, SH0725 SH07253 (sh.84) were designated " Valves Locked C:\WP51\ DOC p T.IR 96-04\SL9604. MAR Report printed 10:56 an. Tuesday. January 14. 1997 19 e

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DRAFT INFORMATION - NOT FOR DISTRIBUTION Closed if Shutdown Cooling in service or _less than 1750_ psia RCS Pressure."

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(2) ON0P 2-0030131. Rev 50. " Plant Annunciator-Summary" e Annunciator S-10 HYDRAZINE TK LEVEL LO -

Setpoint of 35.5 inches was incorrec PCM 109-294 issued 9/16/94 changed setpoint to 36.7 inche TEDB has no reference to this setpoin e Annur.ciator S-20 HYDRAZINE TK LEVEL LO-LO Auto Action that Hydrazine pumps 2A/2B stop was unrelated to Sensing Element LIS-07-9. Sensing Elements LS-07-10A and LS-07-10B stopped Hydrazine Pumps 2A and 28 and closed SE-07-3A and 3B at the same setpoint as LIS-07- (3) Engineering Drawing e 2998-G-08 " Flow Diagram Containment Spray and Refueling Water Systems." Rev 23. Sh 1 V07101 (86) and V07106 (04) were shown as Closed instead of Locked Close V07334 (F5) and V07335 (G5) were shown as Open instead of Locked Ope " LOW LEVEL STOPS PUMP & CLOSES VALVE" (F1 and F3) was incorrec The note should have read " LOW-LOW LEVEL STOPS PUMP & CLOSES VALVE."

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e 2998-G-08 " Flow Diagram Containment Spray and Refueling Water Systems". Rev 23. Sh 2 V07390 through V07393. V07191 and V07163 (C2-3. D2-3) ,

were shown as Closed instead of Locked Close l (4) OP 2-0010123. Rev 69. " Administrative Control of Valves. Locks '

and Switches" e S6.1 incorrectly references St. Lucie Unit 1 UFSA '

e :l TC# 2-95-683 transferred valves MV-07-3 and MV-07-4 from

Appendix "F" to Appendix "L" and stated the reason for j

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' DRAFT INFORMATION' NOT FOR DISTRIBUTION the change, in part, as "MV-07-3&4 are to be closed until mode 3/1750' psia." however, the change failed to

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annotate the position with "#", " Valves Locked Closed if Shutdown Cooling in service or less than 1750 psia RCS Pressure" as annears on sh. 8 .

e Note "#," " Valves Locked Closed if Shutdown Cooling in service" on sh. 85 was not complete. It should have included "or less than 1750 psia RCS Pressure" - see OP 2-0030127 (Cooldown).

e TC# 2-95-688. Section G. " Authorization Date" left i blan . The licensee documented the inspectors findings on STAR 951515 and PMAI-96-03-402 and 403 Equipment operability, material condition, and housekeeping were-accept- i able in all case Several minor discrepancies were brought to the .l licensee's attention and were corrected. The inspectors identified two areas of concern as a result of these walkdowns: On Unit 1, the licensee's failure to identify 'and correct during previous system alignments the misidentification of LT 07-7A and'LT l 07-7C as noted in paragraph 02.1.a(3) abov On Unit 2, the licensee's failure in implementing PCM 109-294

' Attachment 1 (TEDB) and the Other Affected Documents " Plant to identify any affected procedure which may require revision due to  !

this modification, including the annunciator procedures" as noted in paragraph 02.1.b(2) abov .; .

02.2 Eauioment Clearances The inspectors independently verified the following equipment clearances for correctness: on Feed Reg. Backup Air - This clearance consisted of four tags isolating the Backup Air supplies to FCV-9011. FCV-9021, 1A MSIV Accumulator and the IB MSIV Accumulator, which were no longer in use. All tags were in place and the valves were in the correct position During verification, the inspector identified two discrepancies to the ANPS and the Work Control Center:

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, (1) Two of the tags were weathered and needed to be replace '

-(2) Twenty Administratively Controlled valves, i.e. all of the

' "1A" and "1B" MSIV valves listed in Appendix N of AP 1-0010123

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DR/FT INFORMATION'- NOT FOR DISTRIBUTIGi Rev 100. " Administrative Control of Valves. Locks and Switches." had locks installed, however, none have position

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placards attached as recuired by AP 0010143 Rev 1 " Labeling / Tagging of Plant Equipment." step 8.1.11. Similar valves on Unit 2 were removed as Administrative Controlled valves by TC #2-95-688 issued December 29, 1995 and did not have locking devices installe on replacement of HVA-3B - This clearance consisted of two tags isolating the electrical supply to the HVA-3B. Both tags were in place and the breakers in the correct positio on MV-09-14 Cross-Tie between AFW Pump "1B" discharge to SG "1A" - This clearance consisted of one tag isolating the electrical suppl The tag was in place and the breaker in the correct positio on Condensate Pump "2B" - This clearance consisted of two tags; one aligning the power supply to the "2C" Condensate Pump and the other isolating the suction side of the pump. Both tags were in place and the transfer switch and the suction valve in the correct positicn on the New Fuel Storage Area Crane - This clearance consisted of one tag isolating the electrical suppl The tag was in place and the breaker ir, the correct positio The inspectors noted that Operations appears to be improving in the area of attention to detail in clearance preparatio Operations Procedures and Documentation (61726)

03.1 OP 3200051. Rev 16. "At Power Determination of Moderator Temperature Coefficient and Power Coefficient" . ,

This procedure provided the method for determining MTC at power and was performed per TS 4.1.1.4.2.c which required verification that MTC was within TS 3.1.1.4 limits "At any THERMAL POWER within 7 EFPD after reaching a RATED THERMAL POWER equilibrium boron concentration of 300 ppm."

On March 4. Unit 1 commenced the MTC tes During insertion of CEA #1 from 105 inches to 104 inches to maintain delta T p,,ower at 100 percen CEA #1 droppe Operators entered ON0P 1-0110030. CEA Off-Normal." and took the required actions to reestablish CEA alignment. The MTC test was exited and a STAR written to investigate and correct the cause of the dropped CEA. Vendor representatives were called onsite to evaluate the C:\@51\D0gNT\1R-96-04\5L%04. MAR Report printed 10:56 am. Tuesday, January 14, 1997 22 f

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' DRAFT INFORMATION - NOT FOR DISTRIBlITION previous visicorder readings taken on CEA #1 following replacement of the timer card on March 2 (NPWO 63/5079).

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After a discussion with Operations, I&C (in conjunction with an independent vendor review) concluded, after performing a system evaluation and procedural review that the CEA #1 drop may have 'been a result of

" operator technique " i.e. allowing the Rod Control System to stop inward CEA motion before depressing the CEA Motion Inhibit (CMI) bypass to resume inward motion and releasing the CMI bypass switch prematurely after stopping CEA inward motio TC #0-96-031 to the MTC procedure provided clear instructions to operators on use of the CMI bypass pushbutton momentary switch to preclude dropping a CE On March 6. the inspectors attended a management review meeting where a plan of action was adopted prior to recommencing the MTC test on March It was decided at this meeting that CEA #1 would be declared INOPERABLE during connection and removal of test equipment. This decision was based on a voluntary entry into TS 3.1.3.1 for planned maintenance should the CEA dro On March 7. the inspector attended the pretest brief held in the Unit 1 control room. The brief was thorough and included the management decision to declare CEA #1 INOPERABLE during installation and removal of test equipment.

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The inspector remained in the control room during performance of the test and made the following observations:

o CEA #1 was declared INOPERABLE during installation and removal of test equipment with no Equipment Out-0f-Service Log entry mad CEA #1 was paralleled to CEA #68 during installation and removal of l test equipmen This ensured that loosening terminal block connections could not inadvertently cause CEA #1 to drop. However, any attempt to move a paralleled CEA would result in a drop since a paralleled CEA receives power to the Upper Gripper coil only. Thus, operators logged CEA #1 INOPERABLE and entered TS 3.1.3.1.c which stated:

"With one full length CEA ino addressed by Action a above,but perable withindue to causes its above other than specified alignment requirements and either fully withdrawn or within the long term steady state insertion limits if in CEA group 7 operation in MODES 1 and 2 may continue."

l i TS 3.1.3.1.a described " inoperable CEAs" as those CEAs being

' imovable as a result of excessive friction or mechanical a

C:\W51\DOCQENT\lR 96-04\SL%04. MAR Report printed 10.56 am. Tuesday. January 14,1997 23 t c i

l l PREDECISIONAL DRAFT INFORMATION NOT FOR DISTRIBUTION interference or known to be untrippable. Thus. CEA #1 was not ino)erable per TS. as it both satisfied alignment criteria and was

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meclanically free to perform it safety functio Following a discussion with the ANPS. the inspector concluded that

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the failure to complete an Equipment Out-Of-Service Ltg entry was a I

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cognitive error attributable to several factors:

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e The decision to declare CEA #1 INOPERABLE and enter TS 3.1.3.1.c for installation and removal of test equipment was

! briefed as part of the test evolution and entirely voluntar e TS 3.1.3.1.c had no action times ascociated with an LC I For the above reasons, the inspector concluded that operators viewed this as being crotrolled within the context of an infrequently performed test ar evolution and forgot the administrative requirement for entry in the Out-Of-Service Lo Although the requirement to complete an Equipment Out-0f-Service Log entry was not met, the inspector attributed the cause to simple cognitive

error with no safety significance. The inspector's evaluation of

! safety significance is based on:

l e RCO log entries documenting installation and removal of test equipment for CEA #1 which clearly identified when the CEA was l considered inoperabl e CEA #1 remained capable of performing its safety function at all time e Independent verification of I&C jumper suspec I&C installed a jumper per step 8.5.1 of the test procedure in order to clear CWP and allow CEA. withdr.awal to avoid a tri The inspector observed both the installation and somewhat informal independent verificatio The technician who performed the independent verification pointed out the location where the jumper was to be installed before installation and remained at the instrument cabinet during installatio The Maintenance Manager, who was in the control room at the time, questioned the adequacy of the independent verification and had an I&C Supervisor reverify the jumpe The jumper was reverified to be properly installe The inspector found the Maintenance Manager was proactive in recognizing this potential error.

l l e ' Verification step in test procedure signed in erro C;\WP51\DOCWKWT\1R-% 04\SL9604. MAR Report printed 10:56 am. Tuesday January 14, 1997 M

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Step 8.4 verified that RCS boron concentration was stable based on  :

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two consecutive samples ~ taken .at 15 minute intervals with a

.. difference between the RCS and )ressurizer of less than or equal to 25 ppm The Test Specialist hac verified this step as complete with three samples recorded at 30 minute interval The inspector <

brought this to the attention of the NPS to erfsure that an additional two samples would be taken per the 15 minute criteria.

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The inspector questioned the Test Specialist the following day regarding this matter. The Test Specialist stated that it was his intention .to request additional RCS samples as required and acknowledged that he had signed this step in error. The inspector  :

re%wed several completed MTC procedures including the aborted one  !

performed on March 4, and concluded that the Test Specialist was  ;

aware of the 15 minute interval requirement, j In general, the inspector concluded that this infrequent test was ,

performed satisfactorily. However, it should be pointed out that neither '

the Test Specialist or Management Designee assigned to provide Management Oversight identified the above three discrepancie The inspector e reviewed the completed MTC test procedure and found no discrepancies.

L 04 Operator Knowledge and Performance (71707, 71715)

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! 04.1 Failure to Follow Conduct of Ooerations Procedure IR 95-03. which addressed an overdilution event on Unit 1. noted that

operators had not employed the appropriate procedure in performing the

! subject dilutio The ins,pectors noted that AP 0010120. " Conduct of l

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Operations," Appendix M. Procedural Compliance and Implementation."

stated that procedures would be implemented and complied with by operators and described tasks considered to be " skill of the trade," which did not require a procedure in-hand during performance of the specified

activities. The inspectors noted that boror) concentration control was not

! one of the evolutions considered to be " skill of the trade." The failure l

of the operator performing the dilution at the time to employ OP 1-

0250020, Boron Concentration Control - Normal Operation." was cited as a i

violation of AP 0010120.

l On February 22. while touring the Unit 2 control room, the inspector

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observed operators adding boric acid to the VCT for temperature contro ;

! At the completion of the evolution, the inspector noted that the operators p had not employed a procedure for the evolution. The inspector questioned the ANPS overseeing the activity as to the need to employ the procedur A review of AP 0010120 indicated that boron concentration control was  ;

still not considered " skill of the trade."  ;

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' DRAFT INFORMATION NOT FOR DISTRIBUTION l The licensee investigated the issue and reported that the subject ( procedure had been out and available previously in the shift. The

! licensee determined that the procedure had been put away sometime during 1 l the shift in ) reparation for tours by NRC senior managers, who were onsite i for the pub'ic SALP meeting conducted on that dat The inspector concluded that the failure of the operators to employ OP 2-0250020. " Boron Concentration Control - Normal Operation," constituted a violation of AP j 0010120. " Conduct of Operations.' However, as the licensee had not had an l l opportunity to describe and execute their corrective action to the violation described in IR 96-03, the incident is cited as an additional l example of EEI 335,389/96-03-01 " Operators Failed to Follow Procedures i for Boron Dilution, Watch Turnover, Procedure Adherence, and Event i Reporting." l 04.2 Unit 1 Containment FIG Rendered 005 Due to Personnel Error Following the Unit 1 trip of February 22, a number of containment entries l were made to troubleshoot CEA In preparation for one such entry, an HP l technician was dispatched to obtain a grab sample of the containment atmosphere on February 22 at 1:55 p.m. The methodology for obtaining the l l

sample involved attaching a removable air sampling device to quick l disconnect fittings which placed the device in a parallel path to the air i

flow moving through the PIG unit. A valve (procedurally designated as l valve 3) located between the quick connects was then to be throttled closed to force the air flow through the sample device at a predetermined i rate. A sample was then to be taken for a minimum of 30 minute ., at which

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time the throttle valve was to be returned to its open poution and the sample device was to be isolated at the quick disconnect: nd removed from

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the unit.

l When the HP technician performed the sample, he failed to return the throttle valve to its open position. The result was that flow through the PIG was reduced to approximately 15 percent of the intended value, l rendering the PIG inoperable. The licensee's investigation et the event I revealed that the HP technician failed to employ HPP-22. Rev 2 " Air Sampling." Step 7.5.1.R required that, upon completion of the sampling valve 3 be returned to the full open position. In fact, the subject ste i was )roceeded by a caution statement stating that valve 3 must be returne

! to t1e full open position. The failure of the HP technician to employ the governing procecure for obtaining air samples is one exam e of a violation (VIO 335/96-04-01 " Failures to Follow Procedures Le to Unit l 1 Containment PIG Inoperability").

The PIG remained in its inoperable state until February 24, when a

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chem,istry technician performing an unrelated task noted the indicated flow

! through the PIG at a value much lower than normal (a fraction of one scf vice 2.5 to 3.5 scfm required by procedure), which resulted in the C:\WP51\D0QgKT\lR % 04\SL%04.Mt Rep:t printed 10:56 am. Tuesday. January 14, 1997 26 e

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identification of the PIG's ino erability and its return to servic During that time, SNP0s recorded the lower-than-normal flow values during l 1couang rounds once per shif O hand-held computers) to take logs, perators employed parameterdata loggers (small

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! and when a given was sensed

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to be out-of-specification by the computer, the operator was prompted to

! enter the data again to verify that the out-of-specificatton value was, indeed, the intended value. In the case of PIG air flow, SNP0s logged the

[ data twice each round without pursuing the cause for the low reading.

l AP 0010120. Rev 79, " Conduct of Operations. Appendix F. " Log Keeping."

stated, in part. " Log readings shall be compared to previous readings to '

! detect abnormal trends or conditions and verified to L'e within the minimum i and maximum values for that parameter. All log redings outside the

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min / max values shall be circled with reasons stated for abnormal readings..." The failure of SNP0s to identify the low flow condition of '

the Unit I containment PIG and to provide reasons for the observed i aerformance is an example of a violation (VIO 96-04-01, " Failures to rollow Procedures Lead to Unit 1 Containment PIG Inoperability").

Additionally, the direction that out-of-specification values should be

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" circled" indicated that the procedure was not current, as the direction was a clear reference to paper logs (the predecessor of the data loggers).

which had not been employed for some time by SNP0s.

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On February 24, the unit was taken critical, resulting in a change from

Mode 3 to Mode TS 3.0.4 stated that " Entry into an OPERATIONAL MODE or other specified applicability condition shall not be made when the l conditions of the Limiting Condition for Operation are not met..." Unit

, 1 entered Mode 2 on 5:13 a.m. on February 24 with the containment PIG l inoperable. TS 3.4.6.1 requires the PIG to be operable in mode 2. As a result of the violations detailed above, the licensee transitioned from l Mode 3 to Mode 2 in contradiction of TS 3. The insSectors concluded that a number of barriers to failure were breachec in this event. The specific actions relating to those barriers included:

e An HP technician performed an activity without availing himself of the a]propriate procedure e The H) technician failed to properly reposition a valve e SNP0s failed, on multiple opportunities, to determine the cause for out-of-specification log readings l

e SR0s reviewing log data did not identify the out-of-specification J

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values L e The Conduct of Operations )rocedure aapendix which discussed log l , taking was out-of-date, wit 1 no curren; methodology describing how l to identify out-of-specification values in the new, "paperless " '

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logtaking environment.

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e A low flow alarm setpoint for the PIG appeared to be set i nonconservatively, as it was based on a no-flow, rather than low !

_ flow, conditiori (see discussion of LER-specified correcuve actions I below) l The inspector reviewed the licensee's discussion of the event in LER 335 96-003-00. " Containment Particulate and Gaseous Monitor Out of Service i Resulting in a Condition Prohibited by Technical Specifications Due to Personnel Error." In the LER, the licensee described corrective actions l which included: I e Disciplining the HP technician involved in the even e Enhancement of both units' logs to include a written explanation for out-of-specification reading ,

e Incorporating sign-offs in HP procedures for actions involving the l manipulation of plant equipmen e Reviewing the event with HP personnel emphasizing procedural complianc The inspector reviewed Rev 3 to HPP-22. and noted that the new revision included requirements that the control room be notified at the beginning i and end of containment sampling (new requirements) and that independent verifications be made of valve positions following sampling. Similar changes were made to the procedure for Unit 2 samplin The inspector discussed the event with the Operations Su)ervisor and asked whether, in the past, the PIGS were declared inoperaale when sampling occurred and was informed that they had not, but that they would in the future. The inspector concluded that the licensee's corrective actions for the short term appeared adequate; however, the licensee may not have adequately bounded the issue in the LER's treatment. Specifically, the LER did not discuss what other pieces of equipment were o)erated by personnel other than operations which may be susceptible ;o similar errors, nor did the licensee discuss what . actions. if any were taken to ensure that SNP0s understand the importance of questionino out-of-specification data. The inspector will follow these issues ir cIosing the subject LE In sumary, the inspector found that the undetected inoperability of the subject component was the result of not employing a procedure while performing a grab sample. The condition was extended in time due to inadequate logtaking on the part of non-licensed operators and inadequate review of the logs taken. As a result of these failures, a violation of TS occurred when a reactor startup was performed with the component 00 Additional weaknesses included a logging procedure which was not up-to-l date, and an historical failure on the part of Operations to declare the c6ntainment PIG 00S when grab sampling was taking place.

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04.3 Control Room Observation

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The inspector observed control room operations in both units at various times during the inspection period of March 25-29, 1996. Observation of l steady state plant operations and shift turnover were conducted to determine if tae operators were operating the plant in accordance with plant procedures and guidelines. The inspector compared observed operator performance to the requirements and guidelines for operator performance in AP 0010120. Rev 80. " Conduct of Operations." This procedure covered topics such as procedure compliance and implementation, communication l

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crew relief / shift turnover and log keeping among others. To fulfill one l of the corrective actions to the recent overdilution event (see IR 96-03). l Operations Management reinforced through operating crew briefings their l expectations in " Conduct of Operations." Particular emphasis was placed !

on notification of Operations Management, log keeping, focus on reactivity i thanges, and the short term turnover process. In a letter to the NRC dated March 6.1996, the licensee stated that the above stated corrective action was complet Operator conduct in the control room was generally business-like and professional. The inspector observed no unauthorized reading material in l the control room and noted that the majority of conversations between oper6 tors concerned plant operatio Plant policy concerning communications between operators was stated in AP -0010120. Anpendix " Communications," and provided guidelines for face-to-face comn' .nications, i The appendix stated that face-to-face communications should include l repeat-backs with confirmation (three-way communications). Face-to-face l l

communication between the operators was rarely conducted in accordance with this guidance. The inspector observed one conversation during which a repeat-back was used, and this was not followed by a confirmation.

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The RCO maintained a chronological log to document events and operator actions of importance. The requirements for maintaining the chronological log were stated in AP 0010120. Appendix F, ", Log Keeping." Among the items that were required to be entered in the RC0 chronological log were reactivity manipulations and abnormal conditions related to turbine-generator auxiliary systems. The inspector observed the Unit 1 RC0 l perform two RCS dilutions of 300 gallons each on March 27. 1996. A review

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of the RC0 logs the next day indicated that not only were the two observed reactivity manipulations not entered into the RCO chronological log as required, but t1ere were no log entries for dilutions. The initial log entry made when assuming the shift included the statement " Board RCO .;

diluting periodically to maintain RCS temperature." Discussions with the

ANPS indicated that he thought this general log entry was adequate to i comply with log keeping requirements. However, the shift before and the 7'

l shift after logged two and seven dilutions, respectively in addition to

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._ The shift turnover meeting between the off-going day shift and the on-coming peak shift on March 27 included information that the Unit 1 main i generator hydrogen cooling system pressure needed to be increased due to loss from a slow leak. When the ANPS was asked whether this should be conducted using the Normal Operating procedure or the Off-Normal Operating l Procedure, the ANPS expressed no preference for either and told the SNP0  ;

to choose one. The inspector determined the next day from the SNPO logs that the Unit 1 main generator hydrogen pressure was increased at approximately 6:30 p.m. The SNP0 logs did not say which procedure was used, however, discussions with the operators indicated that the ONOP for !

loss of main generator hydrogen was typically used since it did not require an extensive valve line-up and could be conducted in a minimal I amount of time. The next day, the inspector reviewed the peak shift RCO i logs and determined that the Unit 1 main generator hydrogen pressure )

increase was not entered into the RC0 chronological log as required. The l failure to enter the above three events into the RCO Chronological as  !

required is identified as a violation (V10 50-335/96-04-02, " Failure To Make Required Log Entries").

At the exit interview, the plant manager and operations manager stated that it was not their expectation that the operators log every reactivity l manipulation when frequent manipulations were required to balance a i transient. They stated that since the initial shift log entry had  !

included the statement " Board RCO diluting periodically to maintain RCS temperature," there was no need to log each individual dilutio Based on the above. the inspector concluded that implementation of AP 0010120. " Conduct of Operations " was spotty and that plant management and operations would benefit from a more rigorous implementation of the procedur .4 Inocerable EDG Due to Ooerator Error ,

On January 5, in IHE Number 96-02, the licensee identified an event in which improper valve line up for recirculating the 1A DFOST occurred. An improper valve line-up occurred following a request made by chemistry to operations to place the 1A DFOST on recirculation for sampling. The subject valve lineup resulted in the inadvertent inoperability of the ED Based on the review of the event there were procedure violations comitted by operations, comunication problems and training deficiencie Details of the events are as follow The Unit 1 RC0 was contacted at 1:30,a.m. by chemistry to place the 1A DFDST on recirculation. The Unit i 1 SNP0 was contacted and askea to com)1ete the task. There were no i

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iridications that the RCO directed the ShP0 to perform the task according i

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gumance). The SNP0 performed the function by closing the discharge of the DF0 transfer pump (creating a flow path back to the DFOST via the pump's minimum flow line), as opposed to establishing the procedure-based

! lineup through DFOST cross-connect and truck fill aiping (wtrich would have allowed the DF0 transfer pump to replenish the LA EDG day tank, should such replenishment be necessary, thus ensuring EDG operability). The failure of the SNPO to establish the appropriate valve lineup for the DFOST recirculation is one example of a violation (VIO 50-335/96-04-0 " Failure to Follow Procedures While Placing EDG Fuel Oil Tank on Recirculation").

At 2:45 rimary chemistry contacted the control room to determine the status of ;he 1A DFOS The RCO contacted the SNPO concerning the completion of the task. The SNPO reported that the task had been completed since 2:00 a.m. There was no indication that the SNP0 reported back to the control room that the task had been completed. Step 5.A.9 of Appendix A in Conduct Of Operations stated that the SNPO "Shall report promptly to the control room any equipment or valve manipulations so that the RCO will be aware of the current Plant Status." The failure of the SNPO to advise the control room of the completion of the assigned task is one example of a violation (VIO 96-04-03. " Failure to Follow Procedures While Placing EDG Fuel Oil Tank on Recirculation").

Licensed operators are typically trained to give instruction as to what l procedure and section of the procedure should be completed in order to

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perform a task or evolution. In some instances the control room operator ;

will give specific instruction on what must be done to complete a tas Following conversations with the licensee, the inspector confirmed that operators are trained to provide direction in the manner described abov A review of documentation associated with the event and interview with licensee personnel indicated that the SNPQ was not aware of procedural steps for placing the DFOST on recirculation. The fact that the SNPO was not aware of the procedural steps is an indication of training inadequacy or weaknesses. Also there is no indication that the SNPO was instructed by the licensed operator to perform the evolution per the applicable procedure until the licensed operator realized that the system was improperly aligne Following conversations with training personnel the inspector confirmed that during operator licensing training, operators would give the procedure number and steps to be completed in order to perform the task. The procedure number and steps would be given to the individual performing the task. It was also confirmed that the individual comp]eting the task nuld report back to the control room once the assigned task was completed. This is as example of both the licensed operator and the non-licensed operator not performing as traine '

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05 Operator Training and Qualification (71715, 92901)

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05.1 Licensed Ooerator Reaualification Program The~ inspector observed portions of licensed operator requalification training that were conducted during the inspection period. -This included l

simulator training directed by the training department and a classroom session led by the shifts * Nuclear Plant Supervisor, the senior person on the shift.

l The simulator session provided training and practice for the crew on a rapid plant downpower maneuver necessitated by jellyfish intrusion into the circulating water system. The downpower was followed by a loss of l power to an electrical bus that caused loss of running circulating water pumps and presented conditions that eventually caused a reactor trip. The instructor emphasized conduct of operations issues to the crew and their importance to safe plant operation. He also provided a good synopsis of l management expectations for professional conduct in the control room and i of the need to improve from the level that~ currently exists. This meant

! that the requalification simulator training would, for future sessions, require the operators to )ractice and strictly adhere to the conduct of operations guidelines anc requirements. Previous training had mostly

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focussed on the technical aspect of plant operations with little or no l

emphasis on conduct of operation Log keeping was emphasized to the cre However, the training department was unable to provide the l

operators with a laptop computer on which to keep logs the way they are kept in the plant. ? roper communication techniques were emphasized by the

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instructor. However, during the scenario, these techniques were rarely l used. . During the downpower practice. -the operators allowed some plant parameters to get outside of their normal operating limit The instructor highlighted this to the operatou and explained how their focus was on just completing the downpower and not accomplishing the downpower within the operating limits of the plant. Portions of the scenario were

. video taped to allow the operators the , opportunity to self-critique l themselve The inspector attended a classroom session that covered the " Conduct of Operations" procedure. The session was led by the shifts' NPS. He covered the new changes to the procedure and answered questions from the

o>erators as necessary. Log keeping was covered during the session and tie NPS specifically addressed the requirement to log reactivity manipulation Tha session was scheduled for two hours. The NPSs*

lecture took apprcximately one hour and the remaining hour was allotted for self-study.

l The ' inspector reviewed the licensee's schedule for the previous and upcoming 24 month requalification periods. The current two year period is

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1994. As of this review, the current 24 month period was scheduled to end i

_ approximately 26 months after the official end of the previous 24 month ;

perio While the total amount of time of the current and previous I requalification periods combined does not exceed 24 months. the amount of time from the end of the previous cycle to the end of'thecurrent cycle would exceed by two months that allowed by the regulations. This has i occurred because the current requalification period has been modified to l contain six cycles of training, instead of five cycles as were contained in the previous period. The licensee interpreted the regulation to allow all training to be conducted within a two year period that they could define. In defining their periods, they counted the two years from the beginning of the calendar year and not from the end of the previous cycl The licensee is making arrangements to change their schedule to comply with the regulation while considering whether or not to seek an exemption from the regulatio !

Within this area. no violations or deviations were identifie *

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05.2 Followuo On Previously Identified Insoection Ite_m_s 05. NRC Inspection Report 50-335.389/94-19 identified that the 11'censee j could, ay procedure, maintain an SRO licensed operator up to date in I requalification training by requiring that operator to pass the required annual operating test at the R0 level. This allowed some efficiency in the requalification training program since SR0 licensed operators whose facility assigned position requires only an R0 license could be examined in less time. The program required an l SR0 affected by this policy to receive special training and examination as an SR0 prior to assuming a position that required and SRO license. This was identified as URI 50-335.389/94-19-0 Since this inspection, the licensee has removed this from the governing procedure. Administrative, Procedure 0005720. Licensed Operator Requalification Program. Rev 36. Currently, all licensed operators are required to be examined at the level of their NRC ,

license. Since there were no significant examples of operators not

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receiving the 3 roper examination and since the licensee has taken corrective act1on, this item is close . NRC Inspection Report 50-335.389/94-19 identified that AP 000572 " Licensed Operator Requalification Program." allowed the Operations Supervisor to maintain an active license by virtue of filling the osition. In accordance with 10 CFR 55.53(e). maintaining an active

, icense recuires that an operator be " actively performing the I functions of an operator or senior operator." Since the Operations

' Supervisor had not filled a position that required a license, this r

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DRAFT INFORMATION - NOT FOR DISTRIBUTION was identified as inspector followup item 50-335.389/94-19-03. The licensee has changed the governing procedure to address this

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inadequacy. The corrective action for this item is adequate ~ and this item is close .

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- 05. NRC Examination Report 50-335/94-300 identified that thi$t- Lucie '

emergency operating procedures did not adequately provide guidance to the operators to ensure that a reactor coolant pump was trip)ed

~w hen reactor coolant system temperature-dropped below 50W. An RCP is tripped in this condition to prevent core uplift. Th^ * were changed to address this concern however the change did not provide the guidance necessary to ensure consistent implementation of the requirement. The training department initiated a corrective action. .

number PM 96-03-312. to. address this problem. The St. Lucie E0Ps will undergo another revision which is scheduled to be completed by July 1996. This item will remain open until the E0Ps have been revise Hiscellaneous Operations Issues 0 (Closed) VIO 50-335/95-15-03. " Failure to Follow Procedure and Document Abnormal Valve Position in the Valve Switch Deviation Loa" g . . .

The gp.ector reviewed the licensee's activities relating to the subject

. %i6Tatlon','which complicated a loss of RCS inventory event on August 10, 199 The issue involved a series of floor drain valves (HCV 25-1/7F - ~

which had been left in the closed position following difftulties encountered while testing them prior to the arrival of Hurrisone Eri Operators had failed to log the fact that the valves were left shut in the Valve Switch Deviation log. When a relief valve lifted while placing Unit 1 on shutdown cooling coolant collected in.the Unit 1 pipe tunnel and was not removed via the floor drains due to the closed valve The inspector reviewed work order packages which documented maintenance activities on the subject valves f6r the subject perio NPW0s 61/5778 and 61/5785 documented work which had been performed on valve HCV 25- which had failed to operate properly during stroke testing & Work was wrforn)ed on September 8 through 10. 199 Work performed Mder these

,iPW0s included verifying proper valve / actuator alignment, remgl of the actulit9r and bonnet, and repacking the valv . . . .

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NPW0,61/5721 documented work performed' o'riLHCV 25-1. removin t hervalve':s-- '-

actuator and bonnet to. inspect for blockage. This work occurred on Stptember 1 through 5,1995, and included the removal of approximately L{ 2

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pounds of debris from the valve's inlet and outle ,

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All NPWO packages appeared appropriately documented and included completed

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procedures for the activities performed. All NPW0s included-QI 11sPR/PSLc l 2 retest forms which required satisfactory stroke tests as post-In all cases, the forms were annotatedii

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maintenance test that stroke time testing was not required..as.the, valves Totmj werd,"p4tidicate n .the.., . ,

licensee's IST program. The inspector verified that 'the ~ valves we're"not- ~.

' included in the licensee's ASME Section XI IST program. All ,4 tests were j performed satisfactoril The inspector reviewed the balance of the licensee's corrective actions

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for this event, which included briefing operations personnel on the goal l of error-free operation, increased log reviews, and the adoption of a l verbatim compliance policy with respect to procedures. While subsequent i NRC inspections indicated that personnel errors involving logkeeping and I procedural com)liance continue to present a significant challenge to the licensee, the inspector concluded that the licensee's proposed corrective actions were appropriate to the subject violation and that they were executed per the commitments specified in the response to the NOV. This violation is closed, ,

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M1 Conduct of Haintenance (62703)

I i M1.1 General Comments The inspectors observed maintenance activities on systems and components to determine if the activities were conducted in accordance with

! regulatory requirements, approved procedures, and appropriate industrial codes and standards. The inspectors also reviewed the selected procedures and verified that corrective maintenance activities for safety-related systems and components were being conducted in a manner which resulted in reliable safe operation of the plant and plant equipment. In order to ensure that the maintenance was performed effectively, the inspectors verified the following specific elements: dpplicable tools were properly calibrated, correct parts and tools were used, supervision was adequate, and approved procedures / instructions were use M1.2 Field Observations j M1. Unit 1 Emergency Diesel Generator 1A Test and Surveillance P;1or to diesel generator test and surveillance, the inspectors o) served that a diesel generator engineer and a technician walked i down the radiators to check erosion / corrosion problems. Several

' photos were taken for evidence to show the management about severe -

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l 4 problems on the radiators. Per the engineer, these radiators were I

j installed just about three years ago and has corrosion problems due . 1

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to the salty environmen The licensee already plans to replace

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them during the coming outage. The photos would be used to confirm

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the severe condition and speed the process, e

! There were two diesel engines connecting to a , common diesel

! generator in the middle to produce electricity. This type of diesel i arrangement is called tandem. One engine contains 12 cylinders and l the other contains 16 cylinders.

l The procedure used for test and surveillance was Operating Procedure i 1-2200050A, Rev 24. "1A Emergency Diesel Generator Periodic Test and General Operation Instructions." The inspectors observed activities related to the testing such as checking diesel mounted fuel tank level, diesel oil storage tank level, the operability of 1A fuel oil transfer pump, blowing down all four air receivers, engine and governor. oil levels, engine running at 900 RPM, 4200 volts, 3400 KW of power, local alarms and annunciators in the control room, engine I oil temperature and pressure, the full speed of 900 RPM at least one hour, etc. The inspectors noticed a small amount of oil leak around several cylinder covers. The engineer stated that the small amount l of oil leak was norma !

The inspectors considered that the diesel generator engineer and ;

testing operator were knowledgeable and skillful in handling the a test and performing the maintenance. The diesel started as expected I and ran smoothly in a good conditio !

M1. Unit 2 Waste Gas Compres'sor Maintenance The inspectors observed head inspection and asscmbly on Unit 2 Waste Gas Compressor, The seal was leaking and was replace The

)rocedure used was 2-MMP-06.01, Rev 1. " Waste Gas Disassembly, Repair, and Reassembly." The compressor and parts were inspected for damage, cuts, nicks, scra'tches ' degradation, cracks, etc. No defects were found. The parts were cleaned using Isopropyl Alcoho All 0-rings were replaced with new 0-rings and the sizes of new 0-rings matched the sizes of the old 0-ring The head assembly included the installation of the support head, lower head, three layers of diaphragms, the cap screws to secure the diaphragms with the torque to six in.-lbs, the u)per head. 0-rings attached to all heads, and the head assembly bolts with torque to 300 ft.-lbs. The inspectors especially observed the craftsmen torque the head assembly bolts to 300 ft.-lbs in a torcue sequence

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marked on top of the upper head because the right >olt torque -

, sequence would distribute the torque pressure and prevent damage to the bolts and head The inspectors ilso verified the torque C:\W51\D0dHT\lR-%-04\$L9604.N4R Report printed 10:56 am. Tuesday, January 14.1997 37 i

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PREDECISIONAL DRAFT INFORMATION - NOT FOR DISTRIBUTION l wrenches to be within the calibration date M1. Unit 2 CTCS Recirculating Pump 281 Mechanical Seal Replacement l

The Condenser Tube Cleaning Systems are new syst, ems and were installed a couple of months ago to circulate and clean intake cooling water through the condenser tubes. The recirculating pum)s have leaked 'since the installation. The inspectors observed t1e replacement of the Chesterton 442 Mechanical Seal. The old seal was inspected by the licensee's engineer for damage, wear, degradatio etc. No damage was found. However, the seal was found to have wear i slightly due to the grit. There was no procedure for this task.

The craftsmen followed the instructions attached to the kit for the removal and installation of the seal During the review of the copy of the Work Order in the field, the inspectors found that the craftsmen did not sign and date on page 2 of the Work Order, which requires the craftsmen to verify that they were working on the correct unit and components prior to physically starting work. The inspectors questioned the craftsmen as to why they did not sign and date on the page 2 of the Work Order as required. They realied that the master copy (or control copy) of the Work Order was arought to the field, signed, and returned to the office prior to physically starting work. The copy of the Work Order in the field was not required to be signed since the master copy was already signe Later, the supervisor said that the craftsmen went to the field for the clearance and came back to the office to sign the master copy which meant that they verified the correct unit and components prior to physically starting work. The inspectors questioned what the effective time spans for the clearance document were. The supervisor said "as long as you want."

The aroblem is that the craftsmen may not go back the field immeciately to physically star.t work due to other problems. It may be delayed a couple of days or months due to the change of the procedure, condition, environment, or emergency. Therefore, signing in the master copy after the clearance check could not verify that the act was prior to physically starting work. The copy in the field was still required to be signed and dated prior to physically starting work. The management agreed to reinforce the requirement to sign the work copy in the field. The inspectors considered this problem as a weaknes '

M1. Torque Wrench Calibration

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The inspectors observed the torque wrench calibration practice in 4 order to see if they complied with the arocedur The procedure '

used was General Maintenance Procedure M-0004, Rev 18. " Calibration C : \W51\DOCikNT\ lR-96-04\$L%04.mR Report printed 10:56 am. Tuesday. January 14. 1997 38 i

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torque wrench tester was Model TBT-600. Prior to the torque wrench calibration, the tester itself was required to be calibrated using ,

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The inspectors witnessed the retest of several torque wrsnches which indicated all of them to be within the acceptable range of + or - 4 percent of torque values. Each torque wrench was checked at 20 i percent. 40 percent. 60 percent. 80 percent, and 100 percent of its  !

capacity. The torque wrench operator tested wrenches and compared  :

the test values against the tables in the attachments to the procedur The tables lists the acce) table ranges for each torque values. The inspectors randomly selected several tor  !

the tables, checked the figures of the range values,que and foundvalues them from )

to be acceptabl ;

M1. Replacement of V23113 Replacement of Valve No. V23113 on Unit 2 was observed. This is. the  !

4 inch isolation valve for the Steam Generator Closed Blowdown to 1 the Heat Exchanger 2A-1 Inlet. Work was conducted in accordance  ;

with Master Work Order Task No. 95-028027-1 The inspector l observed welding pre)arations and fitu In addition, the l inspectors verified tlat work was performed in accordance with written instructions, proper revisions of procedures were used, welder certification, welding procedure parameters and weld filler material controls and certifications were satisfactor '

M1. Welding Supporting Control Room Air Conditioner Replacement Welding activities for ACC-3B were observed. This is the Unit 1 air cooled condensing unit for the control room ventilation syste Work was conducted in accordance with Work Order Task No. 96-0065401. Welder certification, welding procedure parameters, and weld filler material controls and certifications were verified satisfactor M1. Observation of Liquid Penetrant Testing Liquid )enetrant examination activities were observed for a new pipe /va've assembly on the Unit 2 Steam Generator Closed Blowdown system. Work was conducted in accordance with Work Order Task N and Traveler Nos.96-373. 4. 5. and 6. Examination of welds No. 2001, 2002, 2003 and 2004 for valves No. V23139 and V23140 ,

were observed. The inspector verified that the examinations were

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t conducted in accordance with ap 3 Technique sheet 9.5, Rev. proved Welding procedure filler materials,N welderPT-1. Metho C:\ w Sl\ b MT\lR-96-04\SL9604. MAR Report printed 10:56 am. Tuesday, January 14. 1997 39 f

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certification and welding procedure parameters were also verified.

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M1. Charging Pump Packing Replacement j

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Portions of maintenance activities involving the replacement of ~ 1 i packing for Unit 2 Charging Pump No. PP2B were observed.' This work s was performed in accordance with Master Work Order Task No.

, 96006925-01 and General Maintenance Procedure No. 2-M-0041. Revision

29. The inspectors verified that work was conducted in accordance with the approved procedure, craftsmen were knowledgeable of the

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work process, and the proper revision of.the work procedure had been )

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verifie i M1.' V23139B Corrective Maintenance l Corrective maintenance for Unit 2 Steam Generator Closed Blowdown  !

system Valve No. V23139B was observed. This is a 3/4 inch root

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valve for the 2B1 heat exchanger which had develo)ed a steam leak in

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the valve's bonnet to body connection. Master kork Order Task No.

i 96003894-01 and General Maintenance Procedure No. M-0043 was used to performed this maintenance activit However, corrective

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maintenance was ineffective due to valve's state of deterioration, i A determination was subsequently made to replace the valve.

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j M1.2.10 Waterbox Maintenance i

Portions of the tube cleaning activities in the 1A2 Inlet Waterbox- '

i on the Unit 1 Condenser (1A) was observed. T'ais work was conducted in accordance with Master Work Order Task No. 9600612101.

i M1.2 Reactive insoection to follow uo on licensee actions to address eauioment

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Droblems identified durina Unit 1 shutdown / trio on February 22.192fL i

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i M1. Rod Control System Problems

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(a) CEA #20 dropped rod I&C performed troubleshooting on CEA #20 per PWO 63/4997. The inspector reviewed the work package and interviewed the I&C System Supervisor present at the time to determine bow the licensee approached rod control troubleshooting overall, and specifically, how this failure was diagnosed and correcte Tech Manual 8770-6947. Section 6.2. " EVALUATION OF IMPROPER  ;

CEDM OPERATION," stated that "the first step in locating the

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malfunction is to obtain a Visicorder trace of the coil 1 currents." Included in this section were lists of common j l

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indications of malfunctions and their causes. The I&C System

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Supervisor, prior to obtaining a Visicorder current trac verified that the power transformer was operating properly and checked the 3-phase input to the power switch. At this )oin he found that the 15 amp "A" and "B" phase' fuses.were ) low The blown fuses were replaced and the leads fr6m the Load Transfer power switch substituted for the Upper Gripper power switc The circuit was reenergized causing the surge suppressor resistor and diode to fai A subsequent evaluation determined that the "A" phase Upper Gripper power switch SCR had failed in the short, current conducting mod After reviewing the work package, the inspector questioned the I&C System Supervisor as to whether there was a troubleshooting procedure available and/or if he had referred to the Tech manual which specifically identified for #17

Observed Condition " Dropped CEA" under Cause. " Failed SCR circuit (s) in the upper gripper power switch." The I&C System Supervisor stated that rod control troubleshooting is performed by obtaining a Visicorder trace and evaluating circuit response based on expert knowledge of the system to identify faults. In this particular instance, the Tech manual was not reviewed prior to troubleshooting and there is no I&C troubleshooting procedure for the rod control syste (b) CEA #47 dropped rod during ' Unit 1 restart I&C performed troubleshooting on CEA #47 )er PWO 63/501 Resistance checks determined a 31K Ohm reating on the Upper

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A containment entry and check of the Gripper power cable collto/ CEA wiring #47 found the quick disconnect adapter was a) proximately eight turns loose. The I&C System Supervisor clecked the remaining 6.0 adapt,ers and found about five more approximately 1/16 turn loose. A second resistance reading measured approximately 8.9 Ohms . which was within specifications. The inspector noted that the PWO package did not fully document the as-found condition of the adapter M1. Steam Bypass Control System (SBCS) Valve Problems (a) PCV-8801 Erratic Operation The SBCS is used at low power. Normally. PCV-8801, which is rated for five percent steam flow, modulated to control t

secondary pressure and temperature. The other SBCS valves

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22. the SBCS was being used to dump steam to the condense The control room operators noted that SBCS valve PCV-8801 was not modulating properly. The valve controller was placed in manual by operators. The modulation problem was investigated by I&C personnel who backed out the adjusting screw on the booster relay for the valve until the booster was no longer involved in operation of the valve. The booster relay was adjusted under WO 9600241 This corrected the erratic operation. The valve controller was returned to automatic operation and no other problems were experience The inspectors reviewed WO 96002418 and noted that the W0 also verified that the booster relay adjusting screw was backed all the way out on PCV-8802. PCV-8803, and PCV-880 The inspectors reviewed the two previous post trip packages for Unit 1, including the operator logs for the shutdowns and restarts and found no indication of previous erratic SBCS valve operatio (b) PCV-8802 Failure PCV-2802 failed to stroke during testing following the reactor trip. This test was performed to verify operation after the l instritment air systeal was checked during followu) to the i probhms identified (discussed below) for 3CV-880 Troubleshooting revealed that the seal around the manual enerator stem and the diaphragm cover was leaking by so that ,

tfiere was not enough air pressure on the diaphragm to stroke l the valve. The seal was replaced by I&C personnel and the l valve stroked satisfactoril I The inspectors examined, the failed seal, reviewed the work  !

order package and concluded that this failure was unique and unrelated to the problems identified for PCV-8801 and PCV-8804. The inspectors questioned whether this valve would have actuated if called upo (c) PCV-8804 Output Pressure Signal While checking the other Unit 1 SBCS valves for problems similar to that found for PCV-8801, I&C personnel found that PCV-8804 had a closed input air signal to the positioner but indicated a pressure increase on the output air signal line to the valve actuator. I&C personnel removed the positioner to

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connection after removing the positione This substance was also found to a much lesser degree in l valves PCV-8802, PCV-8803, and PCV-880 PCV-8801 had not yet been examine Finding the black powdery substance caused the licensee to perform a check of the instrument air syste e An attempt to calibrate the positioner on the bench was unsuccessful due to excessive wear on an internal spool valve. The wear appeared to be from normal in service usage. The positioner was disassembled and the licensee found the black powdery substance and a ferrous and '

rubber-like material inside the positioner. However, laboratory analysis was not possible due to the small l quantity (less than 1 gram) of the substance that was available. The licensee indicated during discussions that they believed the source of the rubber-like '

material and the black powdery substance was the actuator diaphrag This was based on a microscopic comparison of a sample of the diaphragm with the substance collected from the positione e The licensee concluded that these conditions would not cause a failure and believed that PCV-8804 would have opened upon demand. This was later confirmed when a similar output demand condition (discussed below) was found on a Unit 2 SBCS valv The inspectors examined the material collected from the Unit 1 SBCS valves, reviewed the chemistry reports for the monthly routine sampling performed on the IA system, reviewed several annual particulate repo.rts and concluded that the IA system was not the source of the b1'ack powdery substance or the ferrous and rubber-like materia The inspectors questioned the licensee as to whether the Unit 2 SBCS valves had been examined for conditions similar to those found in PCV-8804. The licensee indicated that the Unit 2 valves had not been examined because they believed that, since all the SBCS actuators and positioners had been replaced (under PCM 047-295, Steam Bypass Control System Actuator Modification) during the Unit 2 refueling outage in the fall

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of 1995, there was no need to perform this examinatio . The inspectors reviewed the PCM package, completed work .

implementing documents, performed field inspections, and C:\#51\ DOC 5fMNR-%-04\SL9604 Mt Report printed 10:56 am. Tuesday. January 14. 1997 43

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SBCS valves had been reali.ced. During the field varificatio '

the inspectors observec that the Unit 2 PCV-8803 output demand signal read 85 psig, which was similar to Unit 1 PCV-8804 l

conditio .

The licensee initiated STAR 960359 to evaluate the condition '

for Unit 2 valve PCV-8803. The evaluation concluded that a build up of positioner output pressure while the valve was in  ;

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standby had no effect on valve operation. The licensee verified this conclusion by isolating PCV-8803 and capturing as-found positioner settings and valve movement, inspecting the internal positioner filters for debris. and performing a calibration check on the positioner. PCV-8803 was stroked on February 28. All pressures and strokes were normal and no movement of the valve was produced. The filters internal to l the positioner were inspected and found to be clean. The i licensee concluded that the cause of the positive output  !

l pressure from the positioner while the valve was in standby i

was an indication of leakage of the spool valve inside the l

positioner. Spool valve leakage could be caused by failure of l the spool valve to seat or miscalibration of the spool valve

! signal. Spool miscalibration may be caused by calibration

! drift or a very small original setting discrepanc The i licensee indicated that a review of the vendor recommended <

steam bypass valve actuator and positioner PM guidance was in I progress for. both units and the results of the review would be documented in In-House Event Report No. 96-02 l The inspectors concluded that the licensee's investigation into the SBCS valve problems lacked thoroughness in that the

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extent of condition did not include examining the Unit 2 SBCS valves for similar conditions. Also, not all of the vendor PM guidance for the positioner * was incorporated into the licensee's PM program for the SBCS valves, and these PMs had i not been performe i (d) SBCS Flow Capability l

l- During further review of.the SBCS valves, the inspectors noted

! that the licensee had initiated STAR 960348 for Unit 1 and l STAR 951419 for Unit These STARS were written to identify that the modifications to the SBCS valves may not allow the

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steam bypass flow capacity for the SBCS that was specified in i;

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the UFSA The STARS indicated that the modifications j 4 'resulted in a reduction of the SBCS's ability to accommodate a load rejection from up to 45 percent of full steam flow as

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specified in the UFSAR to up to 39 percent of full steam flow, as indicated in licensee calculation PSL-2FSM-95-01 Revisions 0 and 1. The licensee concluded that no potential

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4 o)erability concern existed in any mode of plant operation.

T1is conclusion was based on the SBCS not being required for plant safety (UFSAR Section 7.7) and there was no credit taken ,

f in any Chapter 15 Accident Analyses for the steam dump and

. bypass syste The steam dump and bypass valves were class 1fied as non-seismic and non nuclear safety related. The UFSAR stated that if the bypass valves failed to open on

command, the atmospheric dump valves provided a means for

, controlled cooldown of the RCS and the main steam safety

, valves provided the safety related over pressure protection for the steam generator The inspectors reviewed UFSAR Sections 7.7.10.4.4.15; STARS 960348 and 951419; and calculation PSL-2FSM-95-015. Rev 0 and Rev 1: and concluded that the licensee's operability evaluations were satisfactory and adequate technical justification was provide M1. Main Feedwater Regulating Valve (MFRV) Failure (a) FCV-9011, which is the 1A MFRV failed to properly respond and control S/G water level during shutdown. This resulted in the licensee having to trip the reactor from approximately 26 percent power. FCV-9011 operated erratically due to a leaking air line between the lockup regulator and the actuator upper air chamber. The air leak was discovered to be a failure of the IA copper tubing at the swaged fittin The failure occurred within the ferrule which created the swaged join The failure caused excessive air leakage from the actuator which resulted in unstable control of the valve and an increase in the 1A S/G water lbvel. The inspectors reviewed the licensee's actions to resolve the failure of FCV-9011 and noted that the licensee's investigation lacked thoroughness in the following areas:

e The post trip position of this valve was not verified in that the licensee did not determine if the valve had locked up (fail-as-is) as designed on a loss of IA. or if the valve had closed as designed on a turbine tri e The laboratory report did not discuss the condition of

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the non-failed joints, nor was the laboratory made aware s

that additional mechanical stress had been applied to j the failed air line prior to analysi C:\br51\D0bMT\IR-96-04\SL9604. MAR Report printed 10:56 an. Tuesday. January 14. 1997 45

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PREDECISIONAL DRAFT INFORMATION NOT FOR DISTRIBUTION e The cause for the MFRV air supply regulator responding slowly during PMT after the IA line tubing replacement was not identified. The air regulator was replaced and

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the valve operated properly. The licensee concluded ;

that the sluggish response of the air regulator was not a contributing factor to FCV-9011 unstable respons (b) Backup IA Supply Removed From Service During further review of the MFRV problem, the inspectors noted that the backup IA supply to the 1A MFRV had been  :

removed from service. Discussions with licensee personnel

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revealed that the backup IA supply had been removed from service for several years. However. Annunciator E-41 "FW REG VLV BACK-UP AIR SUPPLY PRESS LOW," alarm and Off-Normal Procedure ONOP 1-0030131 had not been revised to reflect the current configuration of the syste The inspectors questioned licensee personnel as to whether the backup air supply had been removed from service under the licensee's equipment abandonment proces Licensee personnel indicated that the backup IA supply had not been formally abandoned, but a PCM was being prepared to address abandonment of the ,

equipment. The inspectors noted that a clearance to isolate i the MFRVs from the backup IA supply was not issued until February 2 The inspectors concluded that the system configuration did not contribute to the MFRV failur However, not revising the annunciator or the ONOP were considered to be a weaknes (c) MFRV Air Supply Regulator Failure During stroking of the 1A MFRV following IA line replacement, the "FW REG VLV SUPPLY' AIR PRESS LOW" alarm was received in the control roo The licensee replaced the degraded air regulator and successfully stroked the valve with no IA alarms. The inspectors examined the replacement regulator in the field and noted that the regulator setting was approximately 100 psi The inspectors questioned this setting since the manufacturer's label on the regulator established the service range as35-100 psi During their follow up to this question, the licensee discovered inconsistencies in the documents specifying the pressure at the regulator. The licensee changed the pressure setting at

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the regulator and indicated that the varnous documents were i-O 4 being reviewed to correct the inconsistencie C:\WP51\D05HT\lR %-04\SL%04.9%R Report printed 10.56 am. Tuesday, January 14. 1997 4b

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M3.1 Review of LLRT Records .

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Q_ I The inspector reviewed maintenance records relating to the LLRT of the Unit 2 Equipment Hatch following the most recent refueling outage to ensure that records were appropriately documented and stored.4 subject  !

test was conducted in accordance with OP 2-1300051. Rev 13. "+eeskleak Rate Test." Data Sheet 3. " Seals." The inspector found the data sheet archived and retrievable in the vault, with results for the test in question of 260 SCCM at,42 psig following closure of the e'quipment hatc The inspector noted that no acceptance criteria for seal leakage was identified on the data sheets in question. This was discussed with the cognizant test engineer, who stated that the data obtained was combined with other LLRT data and compared to a total leakage acceptance criteri The inspector reviewed the entire archived package for the performance of the test in question and could not identify where any sumation of LLRT data had occurred. The cognizant engineer was also unable to identify l where the combined LLRT leakage data was archived. As a result, a new

- ;-;. . . . leakage summary was prepared (using the data which had been archived).

reviewed and submitted for archiva When totaled, all containment leakage summaries were well within acceptable limit ~ M3.'2 _ Maintenance Procedures -.

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During the work activities described in paragraph M3.1, above. the i

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inspectors noted that the craftsmen would go verify that the procedure they were using was the appro,priate revision in accordance with the requirements of paragraph 4.5 in Procedure No. QI 6-PR/PSL-1 (Document Control). One occasion when the inspectors accompanied the craftsmen to aerform this verification the craftsmen found that revision 14 of Procedure No. M-0043 which the planner had furnished in the maintenance package was not the current revision when compared with the maintenance control copy in the North Service Buildin Further review by the inspectors also revealed that the procedures index was not being updated when.new procedure revisions were received as the cover sheet the index stated: The inspectors also questioned whether the contr edures =_

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were available to backshifts since the doors of the room h'a locks on them- _

Trie inspectors discussed the issue with appropriate management personnel ,

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! regarding the above procedure control concerns. The discussion revealed that docement control only considered the procedure index correct on the date indicated on the index cover sheet. In accordance with procedure

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this is -a dated once every three months when control copies of the l procedures are audited against an up to date index. The. inspector was t

also informed that the craft know to verify their procedures against the 1 control copies of the documents verses the index. since'the index is a l memorandum and by procedure does not supersede the requirements of a control documen Based on observations of craftsmen audited this inspection, procedures in the maintenance package are verified against the control copy -of the procedur In addition, the craftsmen audited

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followed the document control  !

the procedure ~ in each cas procedure The apparent and used discrepancy of thethe correct revisioi issuing the incorrect revision of General Maintenance Procedure M-0043 No, plann)

resulted because the planner had entries to made in the procedure and on the date he made these entries he had verified revision as the correct I revision on that date. This, therefore, was not a discrepancy but one of the reasons the craftsmen are required to verify the procedure before us As a result of above findings and questions raised by the inspector, two 1 STAR Action Reports were written (Nos. 960456 & 7) to evaluated the effectiveness of document control. Management's attention focused on corrective actions in response to these reports and during the week the inspector was on site (March 25-29) the following corrective measures were establishe e All maintenance groups now will use only one new centralized library l in the North Service Buildin This library has an attendant manning it and updating centrol procedures 10 Hrs. a day. The room j where the library is located has also had the locks removed from the I doors in order that no backshift personnel are excluded from using  !

the facilit j e The document index cover sheef has b#en revised to insure that this uncontrolled document is not used for procedur.e status except on the date indicated on the cover sheet e When planners now verify procedure revisions during the planning stage they will double stamp the procedure and only sign one verification blocks. This will require the user to also verify the procedur e An up-to-date procedure index will be established on all on-line -

computers by approximately August 199 When this enhancement is

' fully implemented the index will supersede all documents for

. establishing procedure status. All plant personnel will have access

'to the index at that time.

C:\W51\DOCbi\!R-% 04\SL%04.MR Report printed 10:56 am. Tuesday. January 14. 1997 40 f

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- PREDECISIONAL DRAFT INFORMATION - NOT FOR DISTRIBlfTION The inspectors considered the ste)s taken or in the process of being taken

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by the licensee to be substantia' improvements in document control. All actions observed during the above corrective maintenance were.also found to be satisfactor _ MS Mainte#ance Staff Training and Qualification -

y M5.1 Maintenance Deoartment Reoraanization

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The licensee recently implemented a major reorganization in its maintenance organizatio Major aspects of the action initolved breaking the organization down ihto functional areas and the creation of rotating shift supervisors who rotate through shifts with the NPSs and who are ,

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tasked with coordinating the overall maintenance efforts for their shift The stated )urpose of the reorganization was to provide better support to Operations )y providing single points of contact and accountability and to provide the segregation of responsibilities necessary to free field Jersonnel from administrative duties to allow focus on the plan Reporting to the Maintenance Manager under the new organization are:

e 5 Rotating Shift Supervisors e A Valve and Welding Supervisor e A Rotating Equipment Supervisor e A Stationary Equipment Supervisor e A Unit 1 Electrical Supervisor e A Unit 2 Electrical Supervisor -

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e A Maintenance Budget Superviso'r e An Instrumentation and Control Supervisor e A Project and Maintenance Support Supervisor e A Maintenance Programs Supervisor .

The inspector performed a random sampling of maintenance supervisor qualifications for the positions listed above and for su)ervisory personnel reporting to those above.*TS 6.3.1 (both units) statec that the unit staff shall meet or exceed the minimum qualifications of ANSI /ANS . The ANSI /ANS standard required that su the standard) possess a High School Diploma equivalent or~and pervisors that they (asdefined have at least 4 years of experience in the discipline they supervise. QI 1-PR7PSt.-1, " Site Organization," required that records be kededicating =_

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that these qualifications were met. The inspector reviewed thelicensee's records for 10 randomly selected supervisors and found that the records ~

were complete, included a verification that the ANSI /ANS requirements were .

mdt, and included records of-past experience and of all-completed FPL i

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training. No deficiencies were identifie Quality Assurance in Maintenance Activities

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M7 M7.1 Unit 1 CEDM coil resistance readinas -

Following maintenance on CEA #47, the inspector reviewed Tech Manual 8770-6947 guidance for CEDM periodic maintenance and, more specifically, the coil resistance parameters. Tech manual sections 6.1.2.1 and 6.1. recommended:

e Each refueling. "The upper gripper coil resistance shoulci be measured and recorded. Deviations of greater than .5 ohms should be investigated" and, o Periodic maintenance. " Check the resistance of each coil and its resistance to ground every third year. The resistance of the coil

should be within 10 percent of the initial resistance per Table and the resistance to ground at 500V should be a minimum of 10,

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ohms."

The licensee calculated the mean and standard deviation for each of the coils and identified all coils that fall outside +/- 2 X S.D. Insulation resistance for all five coils and the cable is measured at one time and must be > 1 megohm @ 500V which is ' consistent with the Tech Manual specificatio The inspector reviewed PWO 63/8002 which measured CEDM coil stack resistances prior to the last Unit 1 outage in 1994. Seven coils were identified as outside of 2 X S.D., four of which were annotated as System 80 coil The inspector reviewed the attached raw data tables and identified four additional coil resistance readings outside of 2 X The inspector also reviewed PCM 13'3-191 dompleted May 199 This PCM upgraded the CEDM power cables and installed the ciuick disconnect adapters. These adapters were installed hand tight with the caveat "Do not use excessive force or any hand tools." PWO 63/0046 which supi 'ted this modification provided 013-PR/PSL-1 Rev 29. " Acceptance Criteila".

item #11 Attachment 4 "PCM Testing Document." This was "The resistance readings for the CEDM lift coil, load transfer coil, pulldown coil, lower gripper and upper gripper coil are within the range of Figure 20 of Re .

Han. 3.2 +/- 1 ohm." In the " Detailed Procedure", item #12:

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. At the Coil Power Progransning Cabinets, measure and record all five i coil resistances for shutdown and regulating CEDMs. (12.1) ,

C:\WP51\D05(NT\lR-96-04\SL%D4 MAR Report printed 10:56 am. Tuesday January 14. 1997 50 i

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DRAFT INFORMATION - NOT FOR DISTRIBUTION l e attachment 012FYP8002. FRG approved #93-132

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I 1) At CPP Cabinets measure and record UG coil resistance for each startup and regulating CEDM. Ensure one lead of field cable )

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is iifted prior to measuring and is relanded prior to continuing to next. Use a meter with resistance resolution of 0.01 ohm ) Record CEDM temperature if possible, using temperature prob ) Calculate the mean and standard deviation for resistance and identify all CEDM coils that fall outside the mean plus or minus 2 X standard deviatio . ;

e item 1 Calculate the mean and standard deviation for resistance and identify all CEDM coils that fall outside the mean +/- 12 * standard deviation).

The inspector noted that item 12.3 had two calculated means and standard deviations: Lift coil mean 3.514. standard deviation 0.120 (handwritten)

and (Unidentified) Mean 7.501. standard deviation 0.22 The inspector calculated the mean and standard deviation for each of the stack coils consistent with the methodology used in PWO 63/8002:

COIL MEAN ' X LIFT 3.52 0.12 0.23 UPPER GRIPPER 7.46 0.27 0.55 LOWER GRIPPER 7.49 0.28 0.57 PULLDOWN 7.53 0.15 0.29 LOAD TRANSFER 7.53 0.18 0.36 The inspector identified 13 CEDMs whose coil resistance readings were outside the allowable range of the calculated means +/- 2 X S.D:

[.gjl Allowable Rance Outside

,e Lift 3.29 - 3.75 #2 <

1. 17 ,

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e Upper Gripper 6.91 - 8.01 #43 C:\WP51\D05EKi\lR96-04\SL9604MR Report printed 10:56 am. Tuesday. January 14. 1997 51 i

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1. 52 e Lower Gripper 6 92 - 8.06 #43 #52 e Pulldown 7.24 - 7.82 #24 .#48 e Load Transfer 7.17 - 7.89 #9 #22 #28 #49 R.?

Using the values calculated in the PWO 63/0046 and assuming that the unidentified mean and standard deviation applies to all but the Lift coils:

Coil Allowable Ranae Outside e Lift 3.27 - 3.75 #2 #17 All Others 7.04 - 7.96 e Upper Gripper #43 #49 #52 o Lower Gripper #43 #52 e Pulldown #24 e Load Transfer #9 #28 #49 This method should have identified t'he abole 11 CEDMs resistance readings as outside the acceptance criteri Using the " Acceptance Criteria" item 11 and assuming a CEDM temperature of 80* F, the allowable ranges including lead resistance, are:

.( 211 Allowable Ranae Outside e Lift 2.34 - 4.34 None

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o Upper Gripper 5.98 - 7.98 #49 (UG & LT) ,

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Lower Gripper #24 (PD)

4 Pulldown #9 (LT)

Load Transfer }

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Item 13 " Test Documentation" contains the statement by the Journeyman that

"All values are acceptable." PWO 63/0046 under Task Description step 3 is a signed verification stating " Verify the resistance readings are within the acceptance criteria of the 013-PR/PSL-1." The inspector concluded that the acceptance criteria provided in this PCM was confusing and not entirely me I&C issued a STAR to Engineering in October 1995 requesting acceptance criteria for coil resistances. Engineering is working with vendor and has made a commitment to close this STAR 30 days prior to the scheduled Unit 1 refueling outag The safety significance of this finding with res)ect to coil condition was minimal in that the ven'Jor Who has reviewed coi~ resistance data (Unit 2)

has not provided the hcensee any limiting values and the Tech Manual may have been misapplied with respect to appropriate acceptance criteria for this PCM. However, the inspector was concerned about the apparent failure to apply and recognize that the acceptance criteria was not me This failure to assure that test results had been satisfied, as identified above, is identified as a violation (VIO 335/96-04-04 " Failure to Adequately Evaluate Unit 1 CEDM Coil Resistance Test Results").

M7.2 FRG review of Unit 1 CEA #1 On March 7 the inspector attended the FRG meeting which reviewed PWO 63/5102. This PWO contained a detailed procedure for installation and removal of test equipment in troubleshooting CEA #1 prior to performing MTC testing (see paragraph 03a of this report).

As part of the FRG review process, the originator of the PWO verbally described what this PWO would accomplish and responded to questions by FRG member At the completion of the review process the FRG secretary

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prepared the minutes for signof The inspector received a copy of the PWO for review and noted the requirement under the completed Technical Review signoff that " Vendor tech manuals, drawings, documents /NPWO instructions used as procedures must be reviewed and approved by the FRG orior to use " Steps 3 and 12 of the PWO referred to performing steps in Tech Manual 8770-694 AP 0010432, Rev 88, " Nuclear Plant Work Orders," instruction 8.4.3. states, in part, "In the case where a controlled vendor technical manual is to be used to provide step-by-step instructior.s. the s)ecific sections (e.g'., paragraphs and steps) shall be invoked in the wort descri) tion or i

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! the technical manual or portions thereof attached to the bPWO, as necessary." This requirement is part of the " level of usage" philosophy C:\WP51\D0Q NT\lR 5 04\SL9604. MAR Report printed 10.56 am. Tuesday. January 14. 1997 53 f

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l ado)ted in September 1995 thus eliminating FRG review of complete vendor '

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tec1nical manual After the inspector questioned whether this requirement had been satisfied, a co)y of the referenced tech manual steps was attached to this NPWO prior to JRG approva .

The inspector concluded that FRG had addressed the relevant safety issues i l adequately but had not reviewed the NPWO in sufficient detail to identify l l the above deficienc M8 Miscellaneous Maintenance Issues (62703, 92904. 92902, 92700) l M (Closed) Unresolved Item 335/96-01-01 URI 96-01-01 documented a condition identified by the NRC on February 15,

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in which workers in a posted contaminated area were observed not adhering to the applicable RWP requirements for anti-contamination clothin Observed conditions included an unbuttoned lab coat, wearing cloth gloves only (no rubber gloves), and failing to wear glove The inspector reviewed the issue with the licensee and determined the following:

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e An RWP (96-119) was properly prepared for the work in question e Radiological requirements for the job in question were appropriately established and met the minOnum requirements for a contaminated area s)ecified in HP-50, " Protective Clothing Requirements" e T1e area in question was not contaminated at the time the condition was observed The licensee initiated a Radiological Deficiency Report to document the issue and determined, through interviews that the observed conditions resulted from workers forgetting requirements in the course of attempting to correct a deficiency which had placed the unit in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TS A This appeared to be complicated by the fhct that the workers reported knowing that the area was radiologically clean, based upon previous surveys, which contributed to a causal attitude toward the requirements of the RW The licensee's corrective actions included stopping the work and counseling those involved, management reiteration of ex]ectations for w under RWPs and a revision to ADM-08.02, " Conduct of Faintenance," wh, added a verification that RWP requirements were met prior to beginnin3 wor The ' inspector concluded that the observed conditions constituted a l l

violation of the licensee's procedures, which required adherence to RWP !

! requirements. However, the licensee's corrective actions were adequate l

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and the event was of minimal safety significance. The inspector concluded

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th '". ding constitutes a violation of minor significance and is being treated as a NCV, consistent with Section IV of the NRC Enforcement Policy (NCV-96-04-05, " Improper Health Physics Practices").  ;

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M8.2 (Closed) LER 335/94-010. " Inadvertent B Train Enaineered Safeauards

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Features Actuation Sianal (ESFAS) due to a deficient Instrument and Control Test Procedure."

The inspector reviewed the subject LER and the corrective actions specified in the LER. The inspector verified that the corrective actions identified in the LER were completed, and that procedures were revised to ;

include the corrective actions when applicable. The inspector concluded that the corrective actions were satisfactor Based on the implementation of the corrective actions, the LER is close i

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M8.3 (Closed) LER 335/94-009-1. " Inadvertent Safety Iniection Actuation

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Sianal/ Containment Isolation Sianal Due To Failed Pressure Transmitters." ;

The ins)ector reviewed the corrective actions associated with the LER and found t1em to be acceptable. Documentation reviewed indicated that I & C

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personnel completed the replacement of five transmitters as specified in the corrective actions and plans are in place to replace other transmitters in the futur Based on the implementation of the corrections action specified, the LER is close M8.4 (Closed) LER 335/94-008-0. " Inadvertent Containment Isolation Sianal (CIS)

Caused By Failure Of The B Instrument Invertor Concurrent With Channel D CIS in Triooed Condition."

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The inspector reviewed those procedures identified in the corrective I actions, and verified that specified changes had been incorporated into the procedure. Based on the completion of t,he specified correction action the LER is close M8.5 (Ocen) LER 335/96-001-00. " Control Room Emeraency Ventilation System Inocerable Due to Imorocer System Confiauration."

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On February 19 at approximately 2:25 a.m., the STA observed an apparent negative pressure when entering the Unit 1 control roo In the subsequent investigation it was discovered that due to maintenance activities in the Electrical Equipment Room, two ventilation boundaries were breached, i.e. inlet plenum access hatch opened on February 19, at approximately 2:20 a.m., for periodic maintenance on HVS-5B fan and the access hatch removed on HVA-3C with the inlet damper in the open position ,

as replaced on February 18, at approximately 12:30 This >

inadvertently established a ventilation flow path with intake supply air C:\WP51\DOCbi\lR-96-04\SL9604. MAR Report printed 10:56 am. Tuesday, January 14. 1997 55

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correctite actions were taken to close the access doors for.hoth HVA-3C and HVS-5A and HVS-58. This restored the control room HVAC to.its design basis for accident conditions capability as of 2:37 ~

. The liteiisee 3erformed an Engineering Assessment which is doemented in LER 335/96-00:.-00 and concluded that this configuration placed the Unit 1

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control room outside of its design basi An immediate 1-hour notification (outside of design basis - event 129994) was made,m-February ~

19, pursuant to 10 CFR 50.7 _ , . .

The inspector reviewed the ' licensee's LER, RC0 logs, clearance log Equipment Out-0f-Service logs and concluded that the licensee's immediate corrective actions were timely and that the Engineering Assessment adequately evaluated the safety implications of this configuration. Unit 1 was placed in TS 3.0.3 at 2:20 a.m., however, the immediate corrective actions were completed within the one hour allowed. The inspector was unable to close this LER in that not all of the corrective actions have been implemente III. Enaineerina E2 Engineering Support of Facilities and Equipment (37551)

E2.1 Unit 1 Soent Fuel Pool Boroflex Nonconformance During blackness testing on the Unit 1 spent fuel pool conducted Mar"ch 14 I through 17, 1995, the licensee found one portion of one boroflex panel missing. Boroflex panels were added to the fuel pool in 1988 to allow the use of high density fuel racks. The panels absorb neutrons, creating storage cells which are, essentially, isolated from a neutronics

)erspective. PertheUnit1UFSAR,9.1.2.1,thecellsacttoensurethat c,r, will remain less than .95 for a series of postulated conditions, to include the loss of all soluble boron in the pool. Soluble boron levels in the pool are to be maintained at~a minimum of 1720 ppm per TS 5. The missing section of boroflex existed at the top 15 inches of the panel

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.. separating cell.s. AH17 and AG17. At the time of the discovery, the Reactor Engineering Supervisor discussed the issue with the inspector and stated that-cQrrective actions were being considered. STAR 950548 wiut prepared _-

to document the conditio In the interim, the affectedTEls were remoyed from consideration for storage of fue .-

Safety Evaluation JPN-PSL-SEFJ-95-023. Rev 3. " Revised Safety Evaluation for Missing Partial Boroflex Panel in PSL SFP Storage Cell 17AH." The ~

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inspector reviewed the package, which documented the licensee's root cause effort, corrective actions and 50.59 evaluatio The licensee could not i establish a root cause for the subject condition except to conclude that

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it was a manufacturing defect. The conclusion that the condition was a manufacturing defect. vice degradation or shrinkage (as has been seen in the material in the past) was based on an abrupt, rather than ragged .

profile observed in the bbckness test data. The inspector reviewed the l test results in a test report prepared by the blackness testing vendor l (HOLTECH International). The subject deficiency was highlighted, as were  !

less significant instances of gaps in other panels The licensee's evaluation then determined that the missing boroflex was an isolated occurrence based upon the following: l e The subject deficiency was the only such deficiency identified in the 154 Janels for which blackness tests at St. Lucie have been performe e The vendor which manufactured the boraflex panels (Joseph Oat Corp.)

had an approved Appendix B OA/0C program and the program was augmented by a resident FPL OC inspector during manufacturing. The program required a verification of proper sizing of each boraflex 3anel by both the mechanic performing the work and a OC inspecto e PL performed audits of vendor records after the discovery of the condition, and found adequate supporting information to conclude i that inspections were performed as require I e The deficiency was the only one of its type reported by industry in j more than 2500 panels for which EPRI reported test result ,

including over 1700 manufactured by the subject vendo )

Additionally, the subject panel was the only one to exhibit the l deficiency of three panels of the same lot number in the St. Lucie !

Unit I fuel poo l

The licensee's evaluation also considered the fuel storage history of the  ;

subject cells and determined that 'two sp'ent fuel assemblies had been  ;

stored adjacent to one another, separated by the . subject panel, for a l

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period of ap3roximately three and one half months. The assemblies were verified to lave the required burnup for storage in those locations and included essentially natural uranium axial blankets of 6 and 9 inch lengths which reduced the reactivity in the area of the missing borafle The inspector reviewed the applicable sections of the FSAR and found that the licensee had correctly characterized the issue with respect to the history of the affected cells. Additionally, the inspector found that the licensee's corrective action (placing the cells off-limits to fuel storage .

in the future) was sufficient to ensure safety in the futur The i inspector reviewed AP 1-0010250. Rev 4. " Guidelines for the Use of the 4 o

Unit 1 High Density Spent Fuel Racks." Preoperational Test procedure

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" Spent Fuel Map," and verified that the appropriate changes had been made

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to prohibit storage in the affected cell The inspector found that the licensee had been less .than thorough in evaluating the potential scenarios which might have occu~rred with the condition unknown to the licensee. In particular, the UFSAR, section 9.1.2.3.1.3 stated that the inadvertent placement of a fresh fuel assembly in the region of the pool affected by the deficiency had the potential to exceed the limiting reactivity should there be a concurrent loss of soluble boron and that, in such a case, the presence of 500 ppm boron would ensure that the infinite multiplication factor would not exceed the design basis reactivity for that region of the pool. The licensee's evaluation did not address whether a misplaced fresh fuel assembly, in the absence of soluble boron, would have exceeded design basis limit Similarly, the licensee's evaluation did not consider what the worst case scenario would be, should a similar defect exist in another area of the

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pool; instead choosing to describe the subject defect as isolated and non-recurrin The inspector attended a FRG meeting on March 12, which discussed the subject issue. The inspector verified that a cuorum was present. The FRG chairman acted properly to keep the focus of tie discussion on safety and the entire FRG directed pertinent questions toward the presenter. Of particular interest to the inspector, the FRG questioned how the SE could attempt to credit the vendor's OA program as insurance against other failed panels when such an obvious deficiency escaped the 100%

verification 3rocess. The preparer could not answer how the deficiency passed throug1 the process, but stated that the extensive program which was in pldce, complimented by an FPL employee on-site at the vendor location assuring implementation of the program, combined with the lack of other deficient panel data provided the necessary assurance that the problem was not generi .

In conclusion, the inspector found the licensee's evaluation of the subject condition to be satisfactory and the 50.59 evaluation to be appropriately supported. The inspector found the FRG review process aggressive in its review of the issue and appropriately focused on safet IV Plant Supoort (83750)

R1 Radiological Protection and Chemistry (RP&C) Controls (83750)

R1.1 External and Internal Exoosure Controls

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This program area was reviewed to evaluate the adequacy of licensee RP c6ntrols for internal and external radiation hazards and to verify C:\bP51\DOCtKNT\lR 96 04\SL%04. MAR Report printed 10:56 am. Tuesday Januory 14. 1997 58

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. individual radiation doses did not exceed the dose limits described in i '

Si. W t C. of 10 CFR Part 2 ;

Selected elements of the licensee's personnel exposure control program were reviewe Based on direct observation. review of records and

. . discussions with licensee personnel the inspectors noted the following

i e Reviewed RWP's provided adequate RP instructions'and controls:

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o Personnel monitoring equipment was utilized appropriately:

e Locked high radiation areas were properly posted and secured; and e Process and engineering controls to limit exposures to airborne radioactivity were considered and utilized when possibl l The licensee reported the following maximum doses (Rems) for individuals a in calendar year 1995 and 1996 to date:

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l Year TEDE Skin Extremity Lens-Eye 1995 2.263 2.452 2.452 2.263 1996 0.254 0.258 0.258 0.254 Part 20 Limits: ,

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5.000 50.000 50.000 15.000 Adm. Limits:

Site 2.500 25.000 25.000 7.500 Total 4.500 45.000 45.000 13.500 1996 data through February 26.149 In 1995, the highest individual CDE dose assigned was 287 mrem and the highest CEDE dose assigned was 33 mrem. No individual internal exposures had been identified at the time of the inspection for 1996. All external and internal exposures were well within the regulatory limit The licensee has applied for NVLAP certification of its electronic dosimeter progra The licensee has completed performance testing in categories II, IV, and VI b. and passed in categories IV and VI.b. The ,

licensee did not plan to re-test in category II, an accident category i

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since the licensee did not plan to use the electronic dosimeters as the pfimary dosimeter for emergency respons The licensee had already received its on site review and expected certification of the electronic C:\W51\00$ENT\1R-96-04\SL9604. MAR-Report printed 10:56 am. Tuesday January 14, 1997 59 f

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dosimetry program in 1996. The licensee has been conducting parallel .

testing' of TLDs and electronic dosimeters for approximatel.v two years, j

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The licensee expects to keep the TLD as the dose of record, at,this tim J The licensee planned to. continue using TLDs for special monitoring -

conditioos such as high beta dose component fields or neutron fields. The on-going ' work in obtaining accreditation of the FPL electronimimetry l program was identified as a good example of the health physics ~ program  ;

technical capabilitie , l Through review of licensee procedures and resorted dose info 3Ia.t.10r#..the inspector concluded the licensee was im)lemen;ing adequate RP contro's and i monitoring individual occupational rad' ation exposures in accordance with the requirements and that all individual doses reported were within l 10 CFR Part 20 limits. ,

i No violations or deviations were identifie R3 RP&C Procedures and Documentation (83750)

R3.1 Control of Radioactive Materials and Contamination. Surveys and Monitorina This 6fdA'las"r'e'viswed to evaluate the licensee's control of radioactive  :

l and contaminated materia l

- - - St. Lucie TS 6.8.1 required written procedures be established, implemented and maintained covering the activities recommended in Appendix .A of_ _ _

- RG 1.33 Rev 2 dated February 1978. RG 1.33, Appendix A, 1978, required written procedures for contamination contro The inspector reviewed the licensee's procedures for the control of tools within the licensee's RCA. St Lucie.HPP- 41 Rev 1. " Movement of Material and Equipment," dated September 29, 1994, described the licensee's procedures for positive control of materials and ecuipment located in and leaving the RCA. Section 7.5 of HPP-41 addressec the use of tools and equ pment in the RCA. Step 7.5.2., stated " Paint contaminated tools and equ pment designated for use in the RCA with purple paint." Step 7. sta ed, in part "Unless otherwise authorized, use only those tools that meet the following criteria for fixed and removable radioactivity:

- I}e, ta-Gamma < 10 mrem /hr Fixed and 4 -

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< 1,000 dpm/100 cm Removable."

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Daring a tour of the licensee's RCA the inspector noticed maintenance workers working on some equipment in the Hot Tool Roo The inspecter ..

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returning tools to the storage cabinet The worker returning tools '

reported the tools had not been use The inspector noted the Hot Tool Room was a self-serve facility and that there appeared to be little control of materials or tools entering or leaving the room. Many workers left the tool room without the tools they had been looking for and the inspector noted some of the tool bins were empt The inspector made independent radiation and contamination surveys of the items stored there. During the survey the inspector found numerous tools that were not painted with purple paint and 2 tools exceeding the contamination levels for such tool One tool having approximately 14 mrem /hr beta gamma exceed the fixed beta gamma contamination limit of 10 mrem /hr and another set of jacking bolts having contamination levels of

approximately 1.500 dpm/100 cm exceeded the removable contamination limit of 1.000 dpm/100 cm. The inspector identified the tools to a health

physics technician and they were promptly removed from the Hot Tool Room for decontamination. The inspector stated that failure to paint tools utilized in the RCA with purple paint and failure to control tools having radiation levels in excess of licensee procedure limits appeared to be violations of licensee procedure requirements. The inspector reported the finding constitutes a violation of minor significance and is being treated as a NCV. consistent with Section IV of the NRC Enforcement Polic NCV 50-335.389/96-04-06: Violation of TS 6.8.1 requirements for failure to follow contamination control procedures for the control and use of contaminated tools in the RC In order to provide better control of these tools, licensee representatives reported that there vould be a worker assigned to the Hot Tool Room for half a day on day shifts and,the tool room would be locked at all other times.

l The inspector also requested and observed surveys of selected tools in the licensee's Clean Tool Room. No contaminated tools were found during those l

surveys.

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The inspecMr toured the yard and individual buildings in the RCA and noted th6t there appeared to be more contaminated material stored within the RCA than the inspector had observec at the site on previous RP l inspection The inspector determined that some of the additional l

material was material that had not been de. contaminated following the 1995 l outage The problems with the Hot Tool Room and the amount of 3

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contaminated material accumulating around the site appeared to be the i related to the significant cuts in the nmbers of utility workers on site C:\W51\00C3ENT\lR E04\SL%04.7%R Report printed 10:56 am. Tuesday. January 14. 1997 b1 l

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during and following the most recent outages. The inspector reported to l licensee management that continued attention was needed to reduce the amount of radioactive material and contaminated material the licensee had

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stored in yard and warehouse Licensee representatives reported temporary personnel would be hired during the next few months to reduce the backlog of contaminated materia Housekeeping in the Auxiliary Buildings was generally goo However process areas such as the decontamination facility and equipment storage areas such as the one near the Unit 1 personnel -access hatch were cluttered and untidy. No uncontrolled containers of radioactive n.aterial

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or contamination were identifie At the time of the inspection the licensee reported there were only 250 ft'

of contaminated area in the licensee's decontamination plan, which included 106.063 ft2 The plan excluded the Containment Buildings and2 certain process areas such as the decontamination facility. The 250 ft was the lowest level obtained by the licensee in recent year The inspector reviewed documentation of selected PCEs and annual PCE trends. The inspector noted that the licensee had approximately 83 PCEs in 1995 which exceed the goal of 50 PCEs. The number of outage days in l 1995, approximately 170, was the primary reason the licensee had exceeded this goal. The licensee actually had fewer PCEs in 1995 than in 199 The licensee had 95 PCEs in 1994 ' lith ap'3roximately 104 outage days. The licensee documented PCEs at a thresho d of 100 cpm above background, measured with a thin window GM detector. The inspector noted the licensee

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surveyed the walkways in the Auxiliary Buildings daily with large swipes

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which helped in reducing the number of PCE occurring in clean areas. No concerns with PCEs were identified during the inspection.

4 The inspector observed several empty drums in the RCA and inquired about the licensee's procedures for releas.ing empty drums having onc? contained hazardous material or used oi The inspector learned that drums

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containing a hazardous material and radioactive contamination were not

released and were stored within the RCA. Fifty-five gallon drums of hazardous material free of radioactive contamination and exiting the RCA were stored on a special pad on the secondary side of the facility. Used

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oil leaving the RCA which could have been exposed to radioactive contamination was sampled and analyzed for uncontrolled releas The inspector determined that used oil from the site was collected in a holding tank for offsite processing. The inspector also learned that the licensee had processors for separat'ing water from oil which were located on the secondary side of the facility in the Turbine Buildings. The separated oil from an oil and water mixture was transferred to the oil i-holding tank and the separated W was released to the yard drainage C:\WP51\ d NT\lR 96 04\$L9604.m R Report printed 10:56 am. Tuesday January 14,1997 62

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system which emptied into evaporation / percolation ponds located within the

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protacted are The inspector noted that the east pond was posted with signs displaying a radiation symbol and the words: " Restricted Area .Keepout" and j

" Radioactive Materials Area." The inspector determined that the east pond i had received some contaminated water from a spill in 1977. The inspector learned that in 1992 the licensee had sampled and evaluated the soil from the pond berm and botto At that time, detectable radioactive contamination was observed at various depths of 1-6 feet with the activity decreasing with depth. The most significant level of contamination detected was in the first three feet of sediment below the pond with radioactive concentrations of 1.5E-6 micro-Ci/g of Cs-137 and 2.4 E-6 micro-C1/g of Co-60. Licensee representatives reported that the water was 4 curredy free of measurable contamination. The inspector observed

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several species of fowl utilizing the pond during the inspectio No concerns with the removal of drums from the primary to secondary side of the facility were identifie One NCV and no deviations were identified.

R5 Staff Training and Qualification in RP&C (83750)

R5.1 Trainino This area was reviewed to verify that site health physics technicians were receiving continuing training.

Through interviews with licensee personnel, review of licensee training documents and training records the inspector determined that the licensee was providing continuing training for health physics technicians. The licensee provided approximately 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> of continuing training for health physics technicians in 1995 and expected to provide approximately that amount in 1996. However, the licensee had not developed a schedule for proposed training. The inspector noted the 1995 training provided was appropriate for continuing health physics technician trainin The inspector determined the technicians generally found the quality of the training good and useful for their responsibilitie No violations or deviations were identifie R6 RP&C Organization and Administration (83750)

R6.1 Occuoation Radiation Exoosure Control Proaram Chanaes Changes in the RP program, since the last inspection, were reviewed to assess their impact on the effective implementation of the RP progra C:\WP51\D0dGT\lR-504\SL9604. MAR Report printed 10.56 am. Tuesday. January 14. 1997 63 e

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equipment, programs, and procedure The previous RP insnection was ;

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conducted during the period of May 30.through June 2.1995. With the

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exception of organizational changes described below the licensee had not made any significant changes in the RP progra .

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! The site health physics department lost several positions in down-sizing activities in February 1996. The number of site senior health physics

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technicians was reduced from 32 to 30 and 2 health physics supervisor positions were also eliminated. The most significant change in numbers of  ;

l staff reductions was the decline in decontamination workers from 22 to 1 l

i The responsibilities held by the Special Project Material Condition Supervisor and Instrumentation Supervisor were temporarily transferred to '

- the ALARA Supervisor and the Radioactive Waste Supervisor respectivel The inspectordid not identify any concerns with the licensee's changes in

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. organization structure or in the qualifications of personnel receiving new program responsibilities. While the loss of the two su)ervisors reduced

. collective staff expertise it did not appear that t1e changes would adversely affect the licensed. programs for control of radiation

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exposures and radioactive mater 1' s.

l No concerns were identified with the reductions in the number of health j 2hysics technicians. The decontaminatio1 workers reductions did appear to lave a negative impact ' on the quantity of contaminated material the

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licensee had stored around the facility (Paragraph R3.1). However, no

violations of regulatory requirements concerning the control of radioactive material were identified during the inspectio '

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The organization chain of command structure from the site Health Physics i

Supervisor to the Operations Manager to the Plant General Manager had not  ;

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change However, recert changes in personnel were made for the

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Operations Manager and the Plant Ger.1eral Manager positions.

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4 There were also decreases in the number of vendor personnel supporting

. site health physics activities in 1995. The number of senior health '

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physics technicians decreased from 69 in 1994 to 51 in 1995. Other

decreases from 1994 levels to those in 1995 included: junior health

physics technicians from 41 to 18: dosimetry technicians from 16 to 13:

and decontamination personnel from 53 to 44. Additional decreases in the e

numbers of vendor su) port personnel during outages were not expected in

1996. However, the '1censee planned to bring in the personnel as needed j and did not plan to use the personnel throughout the entire outage.

j No violations or deviations were identifie ,

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Audits of RP activities were reviewed to determine the adequacy of the licensee's identification and corrective action programs for deficiencies or weaknesses related to the control of radiation or radicar,tive materia The inspector reviewed the licensee's 1995 and 1996 audits of RP program activities. Reviews of RP activities during this period were limited to several performance monitoring activities which the licensee referred to as PHONS. -Five PHONS were conducted in the RP area in 1995 and two were on-going during the inspection for 1996. The inspector also reviewed the checklist and auditor notes for each of the 1995 PHONS. One finding requiring corrective actions was identified in the five PHONS and the inspector verified it's corrective actions were proceedin The inspector determined that the licensee was reviewing the RP program and tracking audit findings for cr;rrectio No concerns with the licensee's audit program, findings or corrective actions were identifie No violations or deviations were identifie R8 Miscellaneous RP&C Issues (83750)

R8.1 Maintainina Occooational Exoosures ALARA This program area was reviewed to determine the status and effectiveness of ALARA program initiatives in reducing collective dose for the sit Areas reviewed included site annual and outage goals and objectives, and the collective dose result A summary of recent collective dose and goals for the site is shown belo Collective Personnel Excosures'(Person-Rem) _

Annual Dose Outage Dose Actual Goal Title Actual Goal Days 1993 460 477 U2-SNO 71 -

U1-RF0 387 444 61 U1-SN0 55 -

1994 505 600 U2-RF0 168 187 71

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The 1996 dose information was measured with electronic dosimeters and was i current through February 2 The 1996 U1-RF0 outage goals had not been issue Unplanned outages, maintenance activities and re-work were the primary reasons the licensee exceeded the 1995 annual collective dose goal of 283 person-rem by approximately 129 person-re This was basically a maintenance and operations problem which significantly and adversely impacted the station ALARA program. The duration of the U2 RF0 was expected to be 53 days and actually lasted approximately 83 days due to expanded work scope and rework. The licensee also had an extended outage on U1 of approximately 80 days. Even with the increased work load, the 1995 annual collective dose was the lowest since 1992 when the licensee had 245 person-rem.

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The site collective dose goal for 1996 had just been approved by plant management. The ALARA staff had identified four possible site collective dose goals for management consideratio The goals considered such factors as industry averages and historical performance. Upper management selected the most challenging one at 356 person-re The licensee had just started a new'ALARA Man-Rem Budget program similar to one utilized at Turkey Point. At the time of the inspection the plan had just been approved and little use of the system had been made. The plan assigned a dose budget for each department and the departments were required to complete assigned responsibilities without exceeding their allotted dose budget. An element of the plan permitted departments to borrow dose from one another as neede The licensee expects the implementation of the process to result in increased involvement of the St. Lucie staff in dose reduction solution The licensee completed a permanent modification on U2 Containment Building in 1995 which 3rovided air conditioning to the building during outage '

The licensee p' anned to make the same modification on U1 during the 1996 RF0 scheduled for Spring 199 The licensee had found that air C:\WPSl\DOCNT\lR %-04\SL9604. MAR Report printed 10:56 as. Tuesday, January 14. 1997 bb d

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conditioning modification was an example of licensee management's support for personnel safety. RP and ALARA program ~

The inspector also learned the licensee had started preliminary preparations for a U1 SG replacement project scheduled for January in 199 Based on direct observation, discussion and review nf records the inspector concluded the licensee was utilizing ALARA techniques and making progress in reducing collective doses for the staff. However, the recent failure to meet 1995 annual collective dose goal indicated additional attention to reduce collective doses during outages was neede No violations or deviations were identifie P4 Staff Knowledge and Performance in EP (71750)

On January 22, at approximately 7:45 p.m., Unit 2 began a downpower from )

100 percent to 90 percent in preparation for turbine valve testin During the downpower. I&C was changing a FC (Field Contact) - 250 power l supply for annunciator housing #1. in the annunciator logic cabinet. At j

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a] proximately 8:20 p.m. , annunciator panels H (Reactor Coolant System), J (leactor Coolant Pumps) K (CEAs). L (Reactor Protection System), M (CVCS)

and N (Waste Management) on RTGB 203, 204 and 205 went into alarm and ,

remained locked in. The licensee entered ONOP 2-0030137, " Partial or ;

Complete loss of Annunciators," and stabilized power at approximately 97 l percen At approximately 8:35 p.m. , I&C identified and replaced the redundant FC- l

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250 power supply fuse in the annunciator logic housing #1 which had blow The locked in annunciator alarms cleared dnd at approximately 8:40 appeared to be operating properly. The ONOP was then exite The inspector reviewed IHE #96-009, the work package generated, and the EPIP 3100022E. " Classification of Emergencies."

The inspector reviewed the PWO work package with the I&C Supervisor. The Journeyman observed an electrical arc between the electrical lead and the terminal where the lead was being relanded prior to the blown fuse indication for the redundant power suppl The I&C Manager said this should not have occurre The inspector also reviewed the Enaineerina Justification for PCM 045-293M which was approved November 23. 1993 and subsequently implemented. This C:\WP51\D05HT\1R 96-04\SL%04. MAR Report printed 10:56 an. Tuesday January 14. 1997 b7

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PCM provided an individual field contact )ower supply for each of the four annunciator logic housings which woulc result in a partial loss of j

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approximately 25 percent of the annunciators rather than complete luss due

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to a single power supply failure. This MEP was classified as Non-Safety l Relate .

EPIP Event / Class 8.B. " Loss of Alarms / Communication / Monitoring" provides the following criteria for an Unusual Event: ,

! Sicnificant loss of effluent monitorina caoability. communications.

! inc ication and alarm oanels. etc. which imoairs ability to oerform accident or emeraencv_ assessmen ,

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~ Unplanned loss of most or all Safety System annunciators for greater  :

than 15 minutes." i If the initiating condition is met for entry into the EAL and even though the condition has cleared, the NPS is required to make an emergency ,

declaration per EPIP ste)s 4.3 and 8.2. In this particular instance, although the RTGB 203. 20L and 205 annunciators were lost for greater than '

l 15 minutes, the NPS concluded that redundant alarms on RTGB 206. ERDAD RPS. ESFAS. LPH and the PACB were adequate so as not to impair accident or emergency assessmen In IHE 96-009. under paragraph VIII. Reportability Evaluation:

"It was determined that most safety system annunciators remained operable during this anomaly so no emergency classification needed to be made."

"For the majority of annunciators affected, redundant alarms on RTGB 206. ERDADS. RPS. ESFAS. LPM'and the PACB were available to alert J

operators to abnormal conditions."

The inspector recognized that a reportability determination involved applying engineering judgmen However, entry into an EAL requires identification and evaluation of which safety system annunciators remained operabl In this regard, the inspector requested that the licensee identify all safety system annunciators and for those annunciators that i were lost, i.e. windows H. J. K. L. M and N. the redundant alarms which l are referred to above. In a suasequent discussion with lead STA the licensee position was that any single failure of an annunciator power  ;

supply would not constitute an entry condition for an emergency classificatio i l

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nonconservative in other cases, particularly RTGB 20 ; V. Manaaement Meetinas and Other Areas .

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X1 Review of UFSAR. Commitments A recent discovery of a licensee o)erating their facility in a manner cnntrary to the UFSAR description lighlighted the need for additional verification that licensees were complying with the UFSAR commitment i

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During an approximate two month time period all reactor inspections will provide additional attention to UFSAR commitments and their incorporation into plant practices, procedures, and/or parameter While performing the inspections which are discussed in this report the i inspectors reviewed the applicable portions of the UFSAR that related to 4

, the areas inspected. The inspectors verified that the UFSAR wording was

. consistent with the observed plant practices, procedures, and parameters.

Minor deficiencies were noted with respect to the Containment Spray System

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walkdowns performed during this period. They were as follows:

e V07223 was to be locked closed per UFSAR paragraph 6.2. The

valve was found to be administratively controlled as locked closed '

per the appropriate administrative procedure, however, the procedure

- was not annotated to refer to the UFSAR commitment, as is normally

. done per the licensee's program e UFSAR Table 6.2-22 shows Unit 1 NaOH concentration as 30-32 w/o. TS 3.6.2.2.a specified 28.5-30.5 w/ e Unit 2 UFSAR Table 7.3-4 lists the EDGs as being started on a CSA This feature was removed via PCM during the most. recent Unit 2 outag ,

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These issues were forwarded to the licensee for. resolutio X2 Exit Meeting Summary A pre-exit meeting was held with the licensee on February 29, 1996, to discuss the results of inspections relating to the February 22 trip of Unit 1 and associated' maintenance issue Dissenting comments were not received from the license The inspection scope and findings for the occupational radiation exposure inspection were summarized in a pre-exit meeting with the licensee held on h March 1. 1996. Upper plant management, e.g.. Plant General Manager. Site I Vice President. Operations Manager, did not attend the exit meeting. The i

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inspector asked that the inspection findings and the inspector's comments

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be conveyed to upper plant management. The inspector described the areas i

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inspected and discussed in detail the inspection results. 'The inspector )

reported to licensee management that continued attention was needed to l

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reduce the amount of radioactive material and contaminated material the  !

licensee had stored in yard and warehouses. Dissenting comments were not i received from the licensee. Proprietary information is not contained in

- this report, i A pre-exit meeting was held with the licensee on March 8.1996 to discuss t a visiting inspectors observations of maintenance activities. Dissenting ,

l- comments were not received from the license l

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A pre-exit interview was held with the licensee on March 28, 1996 to discuss observations of control room activities. Dissenting comments from j

the licensee's management are described in paragraph 04.3, above.

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A pre-exit meeting was held with the licensee on March 29, 1996, to )

discuss aspects of maintenance observations made during the preceding  !

. week. Dissenting comments were not received from the license )

The scope and results of this integrated inspection report were discussed I with the licensee in an exit meeting conducted on April 3, 199 Dissenting comments were not receive X3 Pre Decisional Enforcement Conference Summary A Pre-Decisional Enforcement Conference was held with the licensee on March 8.1996, at NRC Region II to discuss potential enforcement resulting from IR 50-335.389/96-03, which discussed an overdilution event which  !

occurred on Unit !

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Licensee

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Bladow. W., Site Quality Manager .

. Bohlke. W., Site Vice President  !

! Buchanan H., Health Physics Supervisor  !

L Burton. C. Site Services Manager l

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Dawson.' R., Business Manager l

Denver, D., Site Fngineering Manager  !

, Fincher. P., Training Manager  !

, Frechette, R., Chemistry Supervisor

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Fulford, P., Daerations Support and Testing Supervisor

• Heffelfinger. (., Protection Services Supervisor Holt, J., Information Services Supervisor

Kreinberg. T., Nuclear Material Management Superintendent

. Marchese, J., Maintenance Manager Olson, R. Instrument and Control Maintenance Supervisor-

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0'Farrell. C., Reactor Engineering Supervisor i i

Pell. C.. Outage Manager

Wood. C.. System and Component Engineering Manager

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- Sager. D. Vice President. Nuclear Assurance

! Scarola, J., St. Lucie Plant General Manager

Weinkam, E., Licensing Manager

West. J., Operations Manager

Marple, C.. Operations Supervisor l White, W., Security Supervisor

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Other licensee employees contacted included office, operations, engineering,

-maintenance, chemistry / radiation, and corporate personnel.

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. PREDECISIONAL DRAFT INFORMATION NOT FOR DISTRIBUTION INSPECTION PROCEDURES USED

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IP 37551: Onsite Engineering I IP 40500: Effectiveness of Licensee Controls in Identifying. Resolving, and

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Preventing Problems .

IP 61726: Surveillance Observations <

IP 62703: Maintenance Observations I

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IP 71707: Plant Operations IP 71715: Sustained Control Room and Plant Observation IP 71750: Plant Support Activities '

IP 83750: Occupational Exposure IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92902: Followup - Maintenance IP 92903: Followup - Engineering IP 92904: Followup - Plant Support l IP 93702: Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED. CLOSED, AND DISCUSSED Ooened

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50-335/96-04-01 VIO " Failures to Follow Procedures Lead to Unit 1 Containment PIG Inoperability" 50-335/96-04-02 VIO " Failure to Make Required Log Entries" 50-335/96-04-03 VIO " Failure to Follow Procedures While Placing EDG Fuel Oil Tank on Recirculation"

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50-335/96-04-04 VIO " Failure to Adequately Evaluate Unit 1 CEDM Coil Resistance Test Results"

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Closed 50-335/95-015-03 VIO " Failure to Follow Procedures and Document Abnormal Valve Position"

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50-335/96-01-01 URI " Improper Health Physics Practices"

50-335/96-04-05 NCV " Improper Health Physics Practices" 50-335/94-010-00 LER " Inadvertent B Train Engineered Safeguards Features Actuation Signal (ESFAS) due to a Deficient Instrument and Control Test Procedure" 50-335/94-009-01 LER "LER 335/94-009-1. Inadvertent Safety Injection Actuation Signal / Containment Isolation Signal Due To Failed Pressure Transmitters" 50-335/94-008-00 LER " Inadvertent Containment Isolation Signal (CIS)

Caused By Failure Of The B Instrument Invertor

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Concurrent With Channel D CIS in Tripped 4 Condition" 50-335.389/96-04-06 NCV " Failure to follow contamination control i

C:\W51\DO@kNT\IR 96-04\SL%04. MAR Report printed 10:56 am. Tuesday, January 14. 1997 72

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3rocedures for tools utilized in the licensee's RCA"

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335/96-001-00 LER " Control Room Emergency Ventilation System Inoperable Due to Improper System Configuration"

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C : \W"i1\DDRifi\ !R-%-04\SL9604.MmA Report printed 10:56 an. Tuesday, January 14,1997 73 'i i

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DRAFT INFORMATION NOT FOR DISTRIBUTION

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LIST OF ACRONYMS USED

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ADM Administrative Procedure AE00 Analysis and Evaluation of 0)erational Data. Office for (NRC) '

ALARA As Low as Reasonably Achievaale (radiation exposure)

i- ANPS Assistant Nuclear Plant Supervisor .

ANS American Nuclear Society l ANSI American National Standards Institute

. ADV Air Operated Valve l

AP Administrative Procedure '

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ASME Code American Society of Mechanical Engineers Boiler and Pressure Vessel Code j ATTN Attention

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B0P Balance of Plant

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cc Cubic Centimeter CDE Committed Dose Equivalent i CEA Control Element Assembly d

CEDE Committed Effective Dose Equivalent i

! CEDM Control Element Drive Mechanism  !

I CFR Code of Federal Regulations  :

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Ci Curies l

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1 CIS Containment Isolation System

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cm Centimeter

CMI CEA Motion Inhibit

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c >m Counts Per Minute  !

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C )P Coil Power Programming

! CTCS Condenser Tube Cleaning System CVCS Chemical & Volume Control System ,

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CWD Control Wiring Diagram l CWP CEA Withdrawal Prohibit DF0 Diesel Fuel Oil

DFOST Deisel Fuel Oil Storage Tank *

d)m Disintegration Per Minute '

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D)R . Demonstration Power Reactor (A type of operating license) '

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EAL Emergency Action Level EDG Emergency Diesel Generator

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EEI Escalated Enforcement Item Effective Full Power Days I

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EFPD

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E0P Emergency Operating Procedure EP Engineering Package EPIP Emergency Plan Implementing Procedure l

ERDADS Emergency Response Data Acquisition Display System

, ESF Engineered Safety Feature

! ESFAS

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Engineered Safety Feature Actuation System  ;.

F Fahrenheit j

i FC Field Contact

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, PREDECISIONAL DRAFT INFORMATION - NOT FOR DISTRIBUTION FCV Flow Control Valve FLCEA Full Length Control Element Assembly

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FPL ine Florida Power & Light Company FR Federal Regulation FRG Facility Review Group .

GM Geiger-Muller-HCV Hydraulic Control Valve .

HP Health Physics HPP Health Physics Procedure HVAC Heating Ventilation and Air Conditioning HVS Heating and Ventilating Supply (fan, system. etc.)

HX Heat Exchanger I&C Instrumentation and Control IA Instrument Air IHE In-House-Event Report IP Inspection Procedure IR [NRC] Inspection Report ISOL Isolated IST Inservice Testing (program)

LCO TS Limiting Condition for Operation I LER Licensee Event Report LIS Level Indicating Switch LLRT Local Leak Rate Test LPM Loose Parts Monitor LS Level Switch LT Level Transmitter  !

MEP Minor Engineering Package MFRV Main Feedwater Regulating Valves MFW Main Feed Water MMP Mechanical Maintenance Procedure MOV Motor Operated Valve mrem millirem MSIV Main Steam Isolation Valve  ;

MTC Moderator Temperature Coefficient l MV . Motorized Valve Na0H Sodium Hydroxide

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NCV NonCited Violation (of NRC requirements) )

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NOUE Notice of Unusual Event NOV Notice of Violation NPF Nuclear Production Facility (a type of operating license)

NPS Nuclear Plant Supervisor NPWO Nuclear Plant Work Order NRC Nuclear Regulatory Commission NVLAP

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National Voluntary Laboratory Accreditation Program ,

ohm . Unit of Electrical Resistance  !

OHM Occupational Health Management I

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. PREDECISIONAL DRAFT INFORMATION NOT FOR DISTRIBUTION ONOP .0ff Normal Operating Procedure 00S Out Of Service l

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0P Operating Procedure PACB Plant Auxiliary Control Board PCE Personnel Contamination Event .

PCM Plant Change / Modification i PCV Pressure Control Valve  !

Power Dependent Insertion Limits I PDIL PDR NRC Public Document Room PIG Particulate-Iodine-Noble Gas Monitor PIS Pressure Indicator / Switch PM Preventive Maintenance PHON Performance Monitoring PMT Post Maintenance Test ppm Part(s) per Million psia Pounds per square inch (absolute)

]sig Pounds per square inch (gage) i

)SL Plant St. Lucie i PWO Plant Work Order l QI Quality Instruction RAB Reactor Auxiliary Building RCA Radiation Control Area RC0 Reactor Control Operator RCP Reactor Coolant Pump RCS Reactor Coolant System i Rev Revision RF0 Refueling Outage R [NRC] Regulatory Guide RII Region II - Atlanta, Georgia (NRC)

.R0 Reactor [ licensed] Operator RP Radiation Protection RPS Reactor Protection System RTGB Reactor Turbine Generator Board *

RWP Radiation Work Permit SALP Systematic Assessment of Licensee Performance ', '

SBCS Steam Bypass Control System SCCM Standard Cubic Centimeters per Minute

.SCE Systems and Com)onent Engineering ,

SCFM Standard Cubic Foot / Feet Per Minute  !

SCR Silicon Controlled Rectifier I Standard Deviation l SDC Shut Down Cooling l SE Safety Evaluation

SG Steam Generator SGWL

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Steam Generator Water Level SN0 .

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