IR 05000293/1986007

Insp Rept 50-293/86-07 on 860309-0428.No Violation Noted. Major Areas Inspected:Accessible Parts of Plant Structures, & Physical Security.Concerns Re Inadequate Log Keeping Noted

ML20206H742
Person / Time
Site:	Pilgrim
Issue date:	06/13/1986
From:	Strosnider J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20206H728	List: IR 05000293/1986007 ML20206H724
References
50-293-86-07, 50-293-86-7, GL-84-11, NUDOCS 8606260281
Download: ML20206H742 (34)

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i U. S. NUCLEAR REGULATORY COMMISSION REGION I ,

Docket / Report No. 50-293/86-07 License: DPR-35 i Licensee: Boston Edison Company j 800 Boylston Street j Boston, Massachusetts 02199 Facility: Pilgrim Nuclear Power Station

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Location: Plymouth, Massachusetts

! Dates: March 9, 1986 - April 28, 1986

1 Inspectors: M. McBride, Senior Resident Inspector H. Eichenholz, SRI, Yankee cBr art , Reactor Engineer Approved by: e dods 8 l ck R. Strosnider, Chief, Projects Section 18 Date i Summary: March 9, 1986 - April 28, 1986 -

Inspection Report 50-293/86-07 i Areas Inspected: Routine resident inspection was conducted of the control

room, accessible parts of plant structures, plant operations, radiation protec-

! tion, physical security, plant operation records, plant events, maintenance, j surveillance, reactor vessel instrument line repair, and reports to the NRC.

Results: No violations were identified. However, concerns about inadequate log keeping (section 3), resolution of operating concerns that have health physics implications (section 4.e), safety evaluation philosophy (section 4.e), inadequate Operations Review Committee (ORC) review of debris in a main j steam line isolation valve (section 4.f), lack of proper package searches at l an entrance to a plant vital area (section 5), and inadequate health physics

! corrective action (section 6) were identified. The licensee's actions during

! an outage to repair a leaking reactor vessel instrument line were considered j well organized and thorough.

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TABLE OF CONTENTS Page Summary of Facility Activities ... .... .............. 3 Licensee Action on Previous Inspection Findings ... ... 3 Routine Periodic Inspections . . ............ .... .... 4 Daily Inspection . ... ...................... 4 Systems Al i gnment In specti on . . . . . . . . . . . . . . . . . . . . 6 Biweekly Inspections ... ... . . ................. 6 Plant Maintenance . ............ ....... .... .. 6 Surveillance Testing ... ............. .. ........ 8 Review of Plant Events ........ ..... ................ 9 Plant Shutdown Because of Leaking Head Spray

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Line .. . .. ... ........ ... ............. ... 9 Reactor Shutdown Due to a Leaking Reactor Vessel Instrument Line ... .. .. .... .. ..... .... 10 Spurious Half Scrams Caused by Spiking Neutron Monitor .......... . ...... .... .. ............. 11 Group One Primary Containment Isolation While the

R e a c to r wa s S h u td own . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

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' Seat Failure in an RHR Torus Cooling Block Valve, MO-1001-36A .. ............. .................... 12

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' Plant Shutdown due to a Turbine Hydraulic System Leak and Subsequent Scram . . . . . . . . . . . . . . . . . 14 Reactor Shutdown due to RHR Injection Valve Leakage and Subsequent Scram ..................... 15 Damage to Secondary Containment Penetration Seals ........... ...... ...................... 16 Failed Diesel Generator Lockout Relay ............ 16 Broken Cap Screws on MO-1400-4A Motor Operator ... 16 Observations of Physical Security . . . . . . . . . . . . . . . . . . . . . 16 Radiation Protection and Chemistry ................... 17 Review of LER's ........ . ............................ 18 1 Reactor Vessel Instrument Line Repair ................. 19 i Organization and Administration ...................... 28 :

10. Management Meetings ...... . ........ ................. 29 i

, Attachments

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j DETAILS

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Summary of Facility Activities l Four unplanned reactor shutdowns occurred during the inspection period due i to

(1) piping damage to the head spray portion of the residual heat i removal (RHR) system; (2) a leaking reactor vessel instrument line; (3) a leak in the control oil system for the main turbine; and (4) leaking RHR j injection valves which caused the RHR system to be periodically pres-1 surized. The reactor scrammed during the latter two shutdowns after the l main steam line isolation valves (MSIV's) unexpectedly closed. An NRC Augmented Inspection Team was onsite between April 12 and 25, 1986 to

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review the causes of the unexpected MSIV isolations, the inability to open j the outboard MSIV's following the scrams, and the recurring RHR pressuriza-tion events (NRC Inspection Report 50-293/86-17). Corrective actions for these problems had not been completed at the end of the inspection period

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and will be reviewed during a future inspection. The plant was in cold shutdown at the end of the inspection perio ,

2. Licensee Action on Previous Inspection Findings I

(Closed) Follow Item (82-29-01): Review Licensee's Report on the-

! October 28, 1982 Trip of the "A" Recirculation Pump. Based upon the ini-i tial inspector review on this event, two items required additional revie They involved 1) conditions leading to the development of a ground on the

! "B" 125 VDC Station Battery and 2) maintenance troubleshooting activities and problems encountered.

! The first item was reviewed in Inspection Report 50-293/82-30. This report r documented that the ground was caused by moisture accumulation inside the

motor operator of the High Pressure Coolant Injection System's steam supply

valve (MOV 2301-3), and discussed corrective action taken by the licensee i

to preclude recurrence of the problem. The inspector reviewed the current j revision to procedure 3.M.3-8, Inspection / Trouble Shooting-Electrical

< Circuits, and had no further questions. This revision requires that

! ara;ysis and documentation be provided for the potential effects of

} trouble shooting techniques and also requires thoroughly discussing with the Watch Engineer the approach selected in performing an investigation of

! malfunctioning circuits.

I The inspector had no further questions on this ite .,

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(Closed) Unresolved Item (83-10-01) Review licensee's Operability Deter-mination of the Reactor Core Isolation Cooling System Due to an Offset on ,

the Indicator of the Flow / Indicator Controller. This item reflects a con-

! dition that leaves a residual flow indicationgof approximately 50-60 GPM i

following the performance of the reactor core isolation cooling pump oper-l ability test. This condition was observed to recur intermittently during .

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the special inspection conducted on February 18, 1986 to March 7, 1986, as documented in Inspection Report No. 50-293/86-06. As a result of NRC

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observances and inspection followup, the licensee was requested to inves-tigate the cause and take corrective actions by June 1,1986. This item I

will be followed under an open item generated during the 86-06 inspection, i.e., 86-06-06.

i l (0 pen) Violation (85-03-05): Failure to test scram trip logic and alarms i as required by Technical Specifict tion Table 4.1.1. During the reactor

} startup on April 1,1986, the inspector verified that the functional test -

) for the average power range monitors (APRM) was performed within four hours after entering the run mode. This was within the licensee's guidelines i and meets the technical specification requirement that the test be performed

"as soon as practicable" after returning to the run mode. This item will remain open, pending review of the corrective actions for additional items in the violatio . Routine Periodic Inspections '

l Daily Inspection

During routine facility tours, the following were checked: manning, access control, adherence to procedures and limiting conditions for operations (LC0's), instrumentation and recorder traces, control room annunciators, safety equipment operability, control room logs -

l and other licensee documentation.

! The following observations were made during these daily inspections:

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During the inspection period it was noted that entry into Techni-

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cal Specification action statements, such as Fire Protection /

feature inoperabilities resulting from maintenance or modifica-i tion activities, and important operational related events were

[ not being recorded in the control room log maintained by the

Nuclear Operating Supervisor (N05). Examples of events not i

recorded in the log were 1) a half actuation of the Reactor

{ Protection System due to the spurious response of the "G" Inter-i mediate Range Monitoring Channel on April 6,1986,2) the loss of a freeze seal installed on the reactor vessel instrumentation piping associated with nozzle N16A on March 28, 1986, 3) the i "A" Containment Cooling Subsystem being declared inoperable on

• 7 April 2, 1986, due to excessive leakage past the seat of valve MO 1001-36A, and 4) the initial high system pressure alarms for

the residual heat removal system on April 10, 1986.

1 It was further noted that there was no information within the station procedures that would provide the appropriate adminis-trative guidance on plant log maintenance. The inspector dis-

cussed his observations and concerns at a meeting with the Chief l Operatin'g Engineer (COE) on April 10, 1986. The COE acknowledged i

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ance for operations personnel on log entry practices and mainten-ance of logs would be added to a station procedure in a timely

, manner. At the exit meeting, the licensee agreed to require

< that RHR high pressure alarms be logged in the future. Subse-quently, the licensee indicated that procedural guidance for log keeping would be prepared within 60 days following the inspection.

t I The inspector indicated that the licensee's log maintenance practices would be reviewed during routine inspections of the l facility, and determined that the licensee understood the issue

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and would provide timely corrective measures.

j The inspector had no further questions on this matte !

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During a tour of the upper switchgear room on April 2,1986, the j inspector observed an unattended stepladder adjacent to the diesel

generator output breaker compartment on the safety related 4.16KV l A5 Bus. The ladder was used by contractor personnel who were .

installing conduit per MR 85-46-44. The observed condition was brought to the attention of the duty Watch Engineer (W.E.) by the inspector so as to effect timely corrective actions. This

item reflects a lack of proper field supervision of contractor

personne The inspector was informed by the W.E. that the ,

cognizant plant personnel would be contacted and he would register the appropriate concerns. The inspector had no further

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comments on this item.

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The inspector discussed control room staffing requirements when

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the reactor mode switch was in startup and shutdown positions i with the licensee during the inspection period. The inspector observed that the licensee did not maintain a licensed operator at the main control panels when the reactor was shutdown, but

{ relied on the control room supervisor to observe the. reactor i controls. The acceptability of this practice depends on 1) the

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adequacy of turnover to the supervisor when the operator leaves

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the panels; 2) the position of the supervisor in the control

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room; and 3) maintaining the reactor mode switch in the shutdown or refueling position .

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The inspector noted no instances of violation of NRC staffing i

requirements, but did notice that control room personnel were '

i not fully aware of the requirements. At the exit meeting, the '

potential for a control room staffing problem was discusse The inspector also noted that the licensee's administrative l procedures need to be reviewed to ensure that_any requirements j for control room staffing which exceed minimum NRC requirements ,

are suitably followe The inspector had no further questions  !

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6 Systems Alionment Inspection

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Proper operating configurations were verified for selected piping system trains. Major motor operated and manual valve positions for safety equipment were verified during routine checks of the control

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room. Valve power supply, breaker alignment, and safety equipment controller set points were also checke No items for further inspection were identified and no unacceptable conditions note c. Biweekly Inspections During plant tours, the inspector observed shift turnovers and checked:

plant conditions, valve positioning and locking (where required),

instrumentation lineup, radiological controls, security, safety, and general adherence to regulatory requirements. Plant housekeeping and cleanliness were evaluate Plant Maintenance s

The inspector observed and reviewed maintenance and problem investi-gation activities to verify compliance with regulations, administra-tive and maintenance procedures, codes and standards, proper QA/QC involvement, safety tag use, equipment alignment, jumper use, per-sonnel qualifications, radiological controls for worker protections, fire protection, retest requirements, and reportability per Technical Specification A list of reviewed items is included in Attachment 2 to this repor The inspector had the following ooservations:

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MR 86-208 was issued to control the removal and reinstallation

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of the air operator on Valve A0-220-44. It was necessary for I

the licensee to perform this activity to facilitate access for repair of the leaking weld in instrument piping associated with Nozzle N16A. Following the reassembly, the licensee performed post maintenance operability testing (i.e., time testing) per procedure 8.7.4.3 Test Isolation Valves Except MSIVs which was completed on March 31, 198 .

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The inspector determined that no local leakage testing was performed on the valve however, since the body to bonnet tack weld was not broken and no work was performed that would have the potential for changing the seating characteristics of the valve, this was considered to be acceptable. Valve removal and installation was controlled by Procedure 3.M.4-10. The inspector noted that the licensee also completed work on MR 86-202, which called for repacking the valve. The timing of the valve was per-

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formed subsequent to the valve's repacking. No unacceptable con-ditions were noted by the inspector during the review of these item On February 4, 1986, the licensee issued MR 86-6-18 to repair a pinhole leak at the body to bonnet flange of the Start-Up Regulator Valve FCV-643. The work was implemented on March 28, 1986 and consisted of replacing the valve stem, stem packing, bonnet gasket, repairing the seating surface and replacing the poppet. The extensive nature of the work was in response to a recent plant startup that identified the Start-Up Regulator as leaking excessively past it's seat, and necessitated the increased work scope of the M According to a licensee representative, the excessive leakage resulted from not hi.ving a lock nut between the valve stem and operator coupling that allowed the valve disc to rotate and lodge in the coupling. Once this occurred, full valve closure could not be achieved. The inspector noted that the plant opera-tors were appropriately concerned about the recent plant startup problems encountered with feedwater control, and acknowledged that timely licensee corrective actions were implemented on this valve during the plant outage to repair the N16A nozzle instru-

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ment line lea No deficiencies were identified during the inspectors review of this ite As a result of repair work in the Drywell for the leaking instrumentation line associated with Nozzle N16A, the licensee initiated testing activity on 480VAC Breakers B1815A&B located on MCC 818 on March 21, 1986. Breaker B1815A failed its instan-taneous overcurrent trip test specified in procedure 3.M.3- The two breakers are the power supplies for welding circuits, one inside and one outside the Drywell. Maintenance Requests 83-46-385 and -386, for the "A" and "B" breakers, respectively, were both issued on August 4, 1983 for breaker calibration and overhaul. However, that work had not been completed as of March

, 21, 1986. The testing was being performed at this time to en-sure proper operation of the breaker's protective features, which reflected licensee concerns developed as a result of the loss of MCC 820 on February 11, 1986 due to the inoperability of a welding circuit supply breake _ _ - _ _ . _ _ _ _ _

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The licensee issued Failure and Malfunction Report 86-065.for this event, which documented that it was neither a Technical Specification issue nor was it reportable. Although the licensee has demonstrated his concern for operability of electrical pro-tective features, the failure to perform the preventative main-tenance in a timely manner is an ongoing concern that the NRC has with the licensee, Furthermore, this event supports the con-cern that the NRC currently has regarding the lack of an adequate preventive maintenance program for 480 VAC molded case circuit breakers. The NRC concerns and requested licensee corrective action is documented in Inspection Report 50-293/86-0 The inspector verified that proper licensee corrective actions were implemented for Breaker B1815A and had no further questions on this specific ite e. Surveillance Testing The inspector observed parts of tests to access performance in accordance with approved procedures and LC0's, test results (if completed), removal and restoration of equipment, and deficiency review and resolutio A list of reviewed items is included in Attachment 2 to this repor The inspector had the following observations:

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On March 31, 1986 and April 1, 1986 the inspector reviewed licensee activities associated with the implementation of Temporary Procedure No. TP86-40 Rev. 1 IGSCC Visual Examina-tio The licensee had been performing the visual examina-tion requirements of Generic Letter (GL) 84-11 by utilizing this procedure during each plant outage in which the con-

. tainment is de-inerted. On November 25, 1985, in a letter to NRC:NRR, the licensee requested relief from the frequency requirement for performing the visual examinatio ;

In lieu of the original requirement, the licensee proposed that a visual examination for leakage of the reactor coolant

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l piping be performed during each plant outage in which the

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containment is de-inerted, unless such an inspection has been performed during the previous 92 days. This request for relief from the visual examination guidance in GL 84-11 was granted by the NRC:NRR on February 12, 1986. Revision I to TP 85-40 incorporates the granted relief. Based upon a review of licensee records, the inspector determined that the inspection was last performed on January 6, 1986, and per the current guidance did not have to be performe l

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However, a licensee representative indicated that although there was 8 days left before they would have been required to do the inspection, assuming the plant were still shut-down, it was a more conservative approach to perform the inspection. The licensee, in determining to perform this inspection at this time, exhibited a conservative approach to this issue from a safety standpoin One item of concern noted by the inspector involved an apparent lack of coordination between the Operations Department and the visual examination personnel. All inspections were performed at a reactor pressure of 600

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psig; however, the examination personnel believed that by the time they completed the inspection, the reactor would have been at approximately 900 psig. They were not aware that the plant operators had decided to hold reactor pressure to 600 psig. The licensee determined that although the inspection was performed at a lower pressure than rou-tinely used, the results were not invalid. Additionally, when applying the ALARA concept, they could not justify a re-entry into the Drywell. The inspector verified that there was no licensee procedural guidance or written commitment, or NRC guidance on what main coolant system pressure to maintain during the visual examinatio No violations were identified as a result of reviewing this

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surveillance activity.

4. Review of Plant Events Plant Shutdown Because of Leaking Head Spray Line On March 7,1986 at approximately 3:00 p.m., a plant operator dis-covered water on the floor of the torus room. Subsequent investiga-

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tion revealed that the water was coming from a leaking pipe elbow in a four-inch head spray lin The head spray line comes off the "A" loop low pressure coolant injection (LPCI) line. A reactor shutdown was initiated at 4:40 p.m. on March 7 and the unit was subsequently placed in cold shutdow The licensee walked down accessible sections of the head' spray line and found evidence of water hammer damage, including:

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Three straightened pipe elbows,

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Four displaced pipe supports,

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Two bottomed out pipe support spring cans, and

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A flattened section of pipe at a wall penetratio Tne head spray feature is part of the RHR system. It was used to cool tne upper reactor vessel internals during routine shutdowns. It has not been used during the current operating cycle due to concerns about induced thermal stresses in the internals. The licensee believes that air may have been introduced into the upper portions of the head spray line from system leakage and inadequate venting. As corrective action, the head spray line was cut and capped at the connection to the RHR system (Plant Design Change 86-20). The damaged section of piping was removed. The adequacy of venting practices in the RHR i system will be reviewed during followup to NRC inspection 50-293/86-1 ! An additional concern about RHR venting is discussed in section 4.e

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, An LER was issued on April 7,1986 that discussed this event (LER l 86-005). The draft of this LER stated that the LPCI system was not

! inoperable because the leak rate out of the damaged head spray pipe

{ was low. The inspector expressed concern that the LPCI system may l have been affected by the generally degraded state of the head spray piping. The statement was removed from the LER. Instead, the LER stated that an engineering evaluation of the effect of the degraded piping on LPCI and containment spray operability would be conducted j and the LER updated. The inspector had no further question l b. Reactor Shutdown Due to a Leaking Reactor Vessel Instrument Line On March 15, 1986 at 8:20 a.m., a reactor shutdown was initiated after unidentified leakage increased 1.3 gpm during the previous i four hours. Increasing leakage was also indicated by an alarming i

drywell airborne radioactivity monitor. A leak was subsequently

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found at a fillet weld in a two-inch to one-inch reducing fitting in a reactor vessel instrument line. The weld was located within two feet of the reactor vessel and could not be isolated from the vessel .

The reactor was subsequently placed in cold shutdown on March 15,

, 198 The leak rate continued at about 0.25 gpm after the reactor

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had been depressurized, i

The instrument penetration was located seventy inches above the top of active fue The reactor water level instruments that used the tap were not affected by the leak. The instrument line repair is discussed further in section eight of this report. The repair was completed and the reactor restartei on March 31, 1986,

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4 J Spurious Half Scrams Caused by Spiking Neutron Monitor

On March 20 and April 6,1986, spurious half scram signals were generated by a signal spike on intermediate range monitor "G". The reactor was in cold shutdown during both incidents. The inspector discussed the problem with the licensee's maintenance staff and i reviewed maintenance documentatio The licensee attributed the f first incident to electrical circuit noise caused by grindin During a subsequent reactor shutdown on April 4, IRM and coincident average power range monitor (APRM) readings were recorded using

surveillance procedure 8.M.1-2. The "G" IRM was found to be more sensitive than the other IRM's, although the "G" monitor was still I

within the no adjust limit of the procedur Following the second half scram on April 6, the sensitivity of the "G" IRM was reduced using the calibration data collected on April 4. No additional spurious half scrams from IRM spiking occurred during the inspection perio The inspector reviewed the maintenance and surveillance documentatio No inadequacies were identified, d. Group One Primary Containment 1 solation While the Reactor was Shutdown On March 22,1986 at 5:39 p.m., a spurious Group One primary contain-ment isolation occurred which closed the main steam line isolation valves (MSIV) and the inboard main steam line drain valve. The reactor was in cold shutdown at the time of the inciden The process computer did not properly indicate the MSIV closur An LER was issued (86-007) which described the incident. No root

, cause for the isolation was identified and an update LER is planned.

i An engineering request was submitted to change the relay contact position for the computer input signal from primary containment

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isolations. This change should minimize the chance of an isolation

, occurring without computer logging.

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Additional spurious MSIV closures occurred subsequently on April 4

and 12, 1986. An NRC Augmented Inspection Team (AIT) reviewed all

three isolations during inspection 50-293/86-17. Although the I spurious isolations had operational impact, the incidents did not I indicate any breakdown in the primary containment safety functio Additional followup on this issue will be conducted under the AIT report open items, i

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12 Seat Failure in an RHR Torus Cooling Block Valve, MO-1001-36A On April 2,1986 at approximately 9:00 a.m. the plant operators were preparing to operate the "A" RHR System in the Torus Cooling Mode of RHR to transfer water from the suppression pool to radwaste. When the upstream RHR block valve (MO 1001-34A) was opened, the keep fill low pressure annunciator was received in the control room. The Control Room Operator attributed the alarm to either his actions or excessive leakage past the seat of the inboard suppression pool cooling block valve (1001-36A).

Plant operators transferred 7500 gallons of torus water to radwaste

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and then checked to determine whether the excessive leakage condition still existed. It was thought that the water transfer could dislodge

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any foreign material under the seat of the MO 1001-34 A valve if this was the cause of the condition. Following additional operator assess-ment, MR 86-244 was issued to initiate corrective actions on the 1001-36' A valv Initial efforts by maintenance personnel consisted of increasing the setting on the valve's torque switch to maximum. The inspector observed the maintenance activity at the motor control center in the reactor building and determined that the activities were being conducted in j accordance with approved station procedures and there was proper

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regard for preventing excessive current conditions on the valve's motor. Subsequently the licensee concluoed that the valve was travel-

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ing to the full close position and the problem was not related to the

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proper functioning of the motor operator. At 1:50 p.m. the plant

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operators declared the "A" Containment Cooling System inoperable and

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initiated alternative surveillance testing per. procedure 8.5.3.7 and technical specification requirement Following a review of station procedure 2.2.86, Residual Heat Removal '

(RHR), the inspector noted that there are no instructions to provide high point venting of tne RHR System either proceeding or following 7 the completion of transferring of suppression pool water, to radwast Immediate inspector concerns involved the potential for water hammer that might occur from an RHR pump startup if the excessive leakage past the seat of the valve MO 1001-36A prevented the keep fill system from maintaining the "A" RHR subsystem piping full. The inspector questioned the duty Nuclear Watch Engineer (NWE) and determined that the concern was already recognized. An operator was dispatched to the reactor building to vent the high point of the system in question

, but, was waiting for the issuance of an RWP to control the opening of a process syste <

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i j The NWE expressed concern that waiting for an RWP represented an unnecessary hinderance to operators in performing their duties in a

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timely manner, and appeared to be resigned to the fact that this kind of condition, although undesirable from a plant safety perspec-tive, would not be resolved. The inspector was concerned that the licensee had not approached this issue with proper regard for the

! need to perform timely actions utilizing workable methods that address radiological protection control This issue was discussed with the Chief Operating Engineer on April' 11, 1986, who was requested to 1)

review the circumstances of this condition, 2) develop, in cooperation with the Radiological Section Manager, a workable mechanism for venting of process systems that is responsive to both timely operational con-cerns and plant / personal radiological protection, and 3) encourage the plant operators to bring these kinds of concerns to his attention for necessary resolutio The COE indicated that he understood and agreed in principal with the concerns involved in the issue and would

provide timely resolutio The plant operator's response to the off normal keep fill low pressure annunciator, and identification of appropriate concerns relating to the possibility of water hammer, reflects a conscientious attitude l and concern for plant safet Subsequently, the Itcensee determined that the seat ring had failed in i the 1001-36A valve due to a valve manufacturing proble The 36A valve is a 12-inch globe valve installed during original plant con-structio The seat ring was apparently welded into the valve in a manner that induced stress in the ring weld, causing it to subsequently fail. The licensee discussed the failure with the valve manufacturer, Anchor Valve Co., and concluded that the failure was due to an isolated welding problem.

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A safety evaluation was prepared that indicates that the seat failure in the 36A valve did not degrade any safety function (safety evaluation 1946). The inspector expressed concern about the engineering philosophy in the evaluation at the exit meetin Specifically, the evaluation I indicated that even though a damaged 36A valve introduces a possible ]

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^ loss of low pressure coolant injection (LPCI) function by single failure l of another (34A) valve; a worse single failure already exists in the LPCI system (failure of an injection valve). Therefore, the evaluation concluded that no degradation of safety function is generated by the

36A valve problem. The inspector noted that this type of engineering l reasoning could be used to strip out redundancy from the LPCI syste Since the safety evaluation was not used to justify continued plant operation with a damaged 36A valve, the inspector had no further questions about the evaluatio l l

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Valve body erosion was detected in the 36A valve. The smallest measured wall thickness was 0.725 inch. The valve manufacturer indicated that this wall thickness was acceptable and that minimum wall thickness was 0.56 inc At the exit meeting, the licensee stated that the corresponding valve

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in the "B" loop of the RHR system, 1001-36B, would be disassembled and inspected during the next refueling outage. The acceptability of the licensee's evaluation is unresolved, pending the completion of that inspection (86-07-01). The new seating material in the repaired 36A valve is not equivalent to the original material and will require replacement during the next refueling outage. The inspector had no further questions.

f. Plant Shutdown Due to a Turbine Hydraulic System Leak and Subsequent Scram On April 4.1986 at 1:00 p.m., a controlled reactor shutdown was initiated c ae to the detection of a small oil leak in the turbine hydraulic control system. During the shutdown, at 8:15 p.m. on April 4, a spurious group-one primary containment isolation occurred which caused a reactor scram from low powe The outboard main steam isolation valves would not open for over an hour after the

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isolation was reset.

I The licensee evaluation indicated that the isolation was caused by a low steam line pressure whil'e in the run mode isolation trip. However,

! the reactor mode switch had been transferred to the startup mode prior

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to the incident. The licensee concluded that the mode switch had not l been fully transferred, causing the isolation during the reactor cool-dow The control room staff were trained on the preferred method of operating the mode switch prior to starting the reactor on April 10, 198 I The failure of the outboard MSIV's to open af ter the scram was '

attributed to a local air leak in the "A" outboard MSIV air operator coupled with a drop in instrument air pressure at the MSIV's caused by repeated attempts to open the valves. During a subsequent inspec-tion of the "A" outboard MSIV air opeator, pieces of paper and plastic

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sheeting were found inside the operator's four way valve. The paper

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was folded, suggesting that it was placed in the operator rather than blown in from the air line. Paper pulp was later found throughout the operator, including in the main operator cylinder. A second MSIV ,

was disassembled and inspecte No additional paper was foun I i

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The inspector attended an Operations Review Committee (ORC) meeting on April 8, 1986 where the post trip review for the April 4 scram was reviewed. The mode switch problem and the MSIV air leak were discussed in detail. The ORC discussion focused on the April 4 isolation; concluding that since the MSIV's closed during that

, isolation, the paper found in the "A" MSIV could not have interfered

with the MSIV safety functio The licensee indicated that the "A"

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outboard MSIV operator had last been disassembled during the 1984 i refueling outage. Although some of the MSIV operators had been inspected (for unrelated problems) since then, three MSIV's had not been examined since the outag The ORC concluded that the sampling l inspection of the MSIV's was adequate and that the plant could restar The inspector expressed concern that a breakdown in housekeeping

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control occurred during MSIV reassembly during the 1984 outage. This breakdown could have affected any of the MSIV's. The inspector questioned whether the MSIV closure time had been affected and also questioned whether the paper and plastic could become more significant depending on their location in the operator. The inspector discussed the concerns with the Plant Manager. The licensee delayed startup to inspect the MSIV operators that had not been previously inspecte No further paper was foun At the exit meeting, the inspector indicated that the ORC review of

, the paper incident had not been thorough. The licensee indicated that the MSIV work controls during the 1984 outage were being reviewed. The inspector had no further questions at this tim i

g. Reactor Shutdown due to RHR Injection Valve Leakage and Subsequent

Scram On April 10, 1986, a reactor shutdown was initiated after RHR injection valve leakage caused high pressure (400 psig) alarms for the RHR system to annunciate in the control room. During the shutdown, a spurious primary containment isolation occurred and the reactor scrammed. The

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isolation sequence was similar to the April 4, 1986 isolatio The

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reactor was placed in cold shutdow Subsequently, a Confirmatory Action Letter (CAL) was issued regarding

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the April 4 and April 12 isolations and the RHR injection valve leakag These problems were eyamined further by an NRC Augmented Inspection Team (report 50-293/86-17). The reactor was not restarted prior to

] the end of the inspection period.

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16 Damage to Secondary Containment Penetration Seals On April 18, 1986, several defects were noted in rubber boots that seal secondary containment penetrations for the feedwater lines in the steam tunnel. The licensee declared the penetrations inoperable and notified the NRC via the ENS telephone line. The licensee review of this problem had not been completed by the end of the inspectio The acceptability of licensee corrective actions will be reviewed prior to plant startu This item is unresolved (86-07-02). Failed Diesel Generator Lockout Relay On April 26,1986 at 1:58 p.m., a General Electric 12CFD differential relay for the feeder breaker (152-509) from the "A" diesel generator to safety bus A5 failed, burning up a lockout trip coi The licensee promptly extinguished a small fire, racked down the feeder breaker, and declared the "A" diesel generator inoperable. The plant was in cold shutdown at the time of the incident. The licensee had not formulated corrective actions by the end of the inspection perio The licensee's corrective actions for the relay failure will be reviewed prior to plant startup (86-07-03). Broken Cap Screws on MO-1400-4A Motor Operator On April 26, 1936, an operator noticed that two of four cap screws holding the motor operator on the MO-1400-4A valve had broken. The cap screw heads were found hanging by lock wires during a routine check of the motor operator. The cap screws have repeatedly loosened on this motor operator and are the subject of two 1983 LER's (83-010 and 83-035) and an open NRC tracking item (85-06-03). The cap screws were lock-wired in place after they were found 1sose in 198 At the end of the inspection, the licensee had not completed an engineering evaluation of this problem and formulated corrective action. The acceptability of the licensee's corrective action will be reviewed prior to plant startup (86-07-04).

5. Observations of_ Physical Security Checks were made to determine whether security conditions met regulatory requirements, the physical security plan, and approved procedures. Those checks included security staffing, protected and vital area barriers, personnel identification, access control, badging, and compensatory measures when require .

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The inspector noted the following:

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The inspector reviewed the licensee's vital area access controls during major maintenance while the plant was in cold shutdown on March 22, 1986. As a result of this review, the inspector identified concerns involving 1) the type of security personnel being assigned, 2) the nature and extent of training provided for their assigned duties, and 3) an apparent failure to provide searches of all packages entering the vital area to ensure only authorized material are permitte As a result of inspector observations and concerns, cognizant licensee >ersonnel were informed, and corrections actions taken to provide the proper searches of packages prior to entry into the vital are The relevant details of the inspector's observatio.is were provided to the NRC: Region I security specialist, who will review these items in a future security inspection (86-07-05).

6. Radiation Protection and Chemistry Radiological controls were observed on a routine basis during the reporting perio Standard industry radiological work practices, conformance to radiological control procedures and 10 CFR Part 20 requirements were ob-served. Independent strveys of radiological boundaries and random surveys of nonradiological poir.ts throughout the facility were taken by the inspec-to The following problem was note During tours of the reactor building on April 15 and April 30, 1986, the inspector noted I&C personnel inside the reactor vessel instru-ment cages on the 51-foot level using poor contamination control In both cases, the workers had taken handsets from the plant page system in non-contaminated areas, stretched the page phone cords across contaminated area boundaries, and used the page handsets inside the instrument cages (posted contaminated areas, slip ons and gloves required for entry). In both cases, the technicians were observed kneeling on the potentially contaminated floor in the cages on pieces of protective clothing. However, the kneeling pads were too sma11 and the workers' pantlegs were touching the floo In the second instance, the workers had on cotton glove liners instead of the required rubber gloves. Licensee health physics management had mentioned that cotton gloves were not adequate contamination pro-tection during a meeting with other station management earlier that week. The managers were told that the use of cotton gloves was un-acceptable and that station workers should be reminde .

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The inspector notified health physics technicians of the first incident. There were not aware of the practice of taking page handsets out of clean areas and into the instrument cage The page handsets were subsequently checked and were not contaminate The inspector also discussed the first incident with licensee managers in the Radiation Protection Group. On April 17, 1986, the licensee's radiation protection management in the presence of NRC regional management stated that corrective actions would be taken

, and that the I&C group would be contacted. However, no corrective

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actions were taken until af ter the inspector identified the second incident, two weeks late A Radiological Occurrence Report (ROR)

was not initiated until after the second inciden The I&C manage-ment stated that they had not been made aware of the problem. The licensee subsequently instructed I&C personnel on contaminated area practices and posted the entrances to the instrument cages to require a higher level of health physics authorization (i.e., required radia-tion work permits to enter).

! At the exit meeting, the inspector noted that the safety significance I

of the incidents was low. However, the lack of timely corrective action and the failure of radiation workers to follow good contamina-tion area control practices was of concer The radiation protection practices at the station will be routinely reviewed during future NRC inspection . Review of LER's LER's submitted to NRC:RI were reviewed to verify that the details were clearly reported, including accuracy of the description of cause and adequacy of corrective actio The inspector determines whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup. The following LER's were reviewed.

1 LER N Event Date Report Date Subject

86-002-00 1/16/86 2/18/86 Reactor Scram due to Pressure Switch

, Sensitivity 66-003-00 2/11/86 3/13/86 480V Safety Bus Inadver-tently De-energized During Maintenance 86-004-00 2/20/86 3/24/86 SLCS Declared Inoperable when Squib Valves not Tested Insitu

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LER N Event Date Report Date Subject 86-005-00 3/7/86 4/7/86 Head Spray Piping Leak in Torus Room 86-006-00 3/16/86 4/15/86 Weld Leak on Reactor Water Level Instrument Line 86-007-00 3/22/86 4/22/86 Main Steam Line Isolation While Reactor Shutdown 86-003-00 4/4/86 5/5/86 Reactor Scram and MSIV Reset Problems The events described in LER's 86-02 and 03 were reviewed during inspection

$6-0 The events in LER 86-03 were also reviewed during inspection 86-0 The events in LER 86-04 were reviewed during inspection 86-06. The events in LER's 86-05 through 07 were reviewed during this inspection. Inadequa-cies in the draft of LER 86-05 are discussed in section 4 of this repor No additional deficiencies in the LER's were identifie . Reactor Vessel Instrument Line Repair Overview of Event and Outage Tasks  !

As a result of increasing drywell floor leakage of 1.2 GPM from 4:00 a.m. to 8:00 a.m. on March 15, 1986, and an alarm condition on a drywell airborne radioactivity monitor at 7:40 a.m. , the plant operators initiated a controlled plant shutdown at 8:20 a.m. Although Daily Log Test No. 28A of procedure 2.1.15 (incorporates Generic Letter 84-11 requirements) specifies a plant shutdown should be initiated for inspection and corrective action if the increase in the rate of unidentified leakage is in excess of 2 GPM within a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or less period, the plant operators displayed a proper questioning attitude and conservative judgement in taking the plant shutdown action. By approxirately 4:00 a.m., the plant was in cold shutdown, and the licensee determined that the leakage was attributable to a cracked fillet weld in a two-inch-to one-inch reducing coupling on the instru-ment line piping associated with the N16A nozzle coming off of the reactorpressurevessel.Thisinstrumentpenetra4tonislocaced approximately 70 inches above the top of the acti7e fuel. F&MR 86-055 was issued to document the findings and the NRC was notified of the plant shutdow _ . - - _ - . _

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Subsequently, the licensee assigned overall repair responsibilities to the Director of Outage Management and the Outage Management Group (OMG). As part of the piping repair efforts the licensee developed a repair plan and implemented repair activities. Significant involvement of the General Electric Company (G.E.) and in-house engineering re-sources were utilized by the licensee in developing and implementing repair activities. During this period, problems were encountered and nonconforming conditions were discovered. The resident inspector closely followed the outage activities and problem resolutions which spanned the period of March 16, 1986 through April 1, 1986. An NRC:

Region I Specialist Inspector was sent to the site to review the licensee's repair activity. The results of the NRC review are contained belo (1) Cause of the Instrument Line Leak The cause of the failed weld has not been conclusively determined by the licensee's Nuclear Engineering Department (NED) but, it is believed to be due to a slight defect at the root of the original fillet weld between the 2" pipe and socket welded coup-ling. There's also a possibility that a high mechanical loading resulted from one of the pipe supports which was found bound up, and restricted pipe movement in a direction that was intended to have free movement. The defect combined with high loading may have caused the weld to fai The licensee's engineering staff utilized their " Root Cause and Corrective Measures Analysis" worksheet as a structured process to arrive at the potential root cause(s) of the problem. The inspector noted that various potential / root causes were listed and properly dispositioned. IGSCC was ruled out as a root cause. Additionally, a more detailed evaluation of the failed connection will be performed when the repaired section of pipe is removed during the next refueling outag (2) Bound Lateral Support and Missing Guide on Nozzle N16A Instrument Piping On March 16, 1986 during a walkdown of the as-built configura-tion of the N16A Biological Shield Blockout, it was discovered by a Site Engineering Organi:ation (SEO) representative during the walkdown that the first pipe guide off the nozzle was miss-ing and the first pipe guide off the' equalizing column was bound u The licensee issued F&MR 86-056 to document the finding The licensee believes that the bound pipe in the lateral support prevented vertical movement during vessel heatup, and induced a bending moment on the socket weld reducer couplin __ , . - -- - _ . . _ _ .-. - - - . . . _ . . .- .

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f Licensee corrective actions involved design and materials pro- :

i curement actions by the Nuclear Engineering Department, and implementation of the repair / replacement efforts by the Construc-

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tion Management Group (CMG) as cor. trolled by MRs 86-50-8 and -13 i issued on March 21, 1986. The licensee discussed the root cause j for the as-found conditions in the LER developed for the instru-j ment line leakage event (LER 86-06).

{ (3) Nozzle N16B Biological Shield Blockout-Missing Retaining Steel i

i As a result of an SEO walkdown on March 24, 1986 to verify

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installation of blocks and retaining steel at the Biological

Shield Blockout A-88, it was discovered that two steel beams i that secure existing blocks in place in the lower section were 3 missing. The licensee documented the finding on F&MR No. 86-07 The inspector noted that the NED was utilized to evaluate and disposition the as-found condition.

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The licensee reinstalled the two missing beams and shims in j accordance with the instructions contained on MR 86-56-40, as a performed by it's maintenance contractor-Bechtel.

j (4) N16A Nozzle Installed Backwards-During Reactor Vessel Fabrication l

) During the preparations for the repair an "as-built" configuration review was conducted on the N16A penetration. On October 23, j 1986, it was discovered that Inconel and 304 stainless steel materials on the instrument lines from the nozzle were reversed j during the original vessel fabricatio The licensee documented

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this finding in F&MR No. S6-068 and the NRC was notified on the

, finding via the ENS telephone line.

l The licensee investigated nozzles of similar designs (N168,

N15A, N158, and N14) and found, using radiography, chemical

! etching, delta ferrite measurements and chemical analysis of J

metal scraping that the N16A nozzle was the only instance of

r material reversal. The above work activities were conducted in accordance with approved station procedures and MRs86-211,

)86-213, 86-50-5, 86-50-6, 86-50-7, 86-50-10, 86-50-11, 86-50-12

and 86-50-1 l

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I l The licensee contacted the vessel fabricator, Combustion Engi- I i neering Corp., to appraise them of the N16A nozzle discrepancy, i so that, their Nuclear Engineering Department can review the-i problem for 10 CFR 21 implications.

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As a result of radiographic examinations of the exposed bimetallic weld (Inconel to stainless steel using a stainless steel to stainless steel welding procedure) and General Electric Co. 's investigation of the structural, metallurgical and environmental effects of the incorrect installation, the licensee has determined that the as-found nozzle condition does not constitute an unsafe condition. The licensee's analysis is documented in Safety Eval-uation No. 1942 issued on March 27, 198 During the next refueling outage the bimetallic weld will be cut out upstream of the inconnel nozzle and a shop fabricated bimetallic spool piece replacing both the weld in question and the failed socket weld will be installe (5) Identification of Ductwork Deficiencies During a walkdown in the drywell to review blockout removal requirements at nozzle N16A on March 16, 1986, a CMG represent-ative observed that the 24" diameter ventilation duct was un-connected and misaligned at the 74' elevation. The licensee's findings resulted in issuance of F&MR No. 86-05 The ductwork was subsequently removed to gain access to the l' N16A Biological Shield Blockout per MR 86-20-7. Furthermore, as i documented in a memorandum from the cognizant NED representative to CMG on March 21, 1986, a comparison of the as-built conditions to the Bechtel Specification No. 6498-M-64 determined that dis-i crepancies existed in Ducts 205B & D. The licensee implemented corrective action to restore the ductwork to the as-built condi-tions. Additionally, damage to a portion of the ductwork at a bend was identified. The licensee developed Temporary Modifica-tion (TM) No. 86-12 to repair the damage duct. Part of the repair utilized a wide band of duct-tape over the repair strips to seal the ventilated air within the duc Although this repair appeared to be structurally adequate to the inspector, there was no discussion or treatment in the TM, or it's associated safety evaluation, No. 86-14, of the potential for the duct-tape plugging an ECCS pump suction path in the Toru The inspector raised the concern with the Technical Chief '

Engineer, who acknowledged the inspectors concerns and revised the TM and SE to deal with the issue. The licensee added restraining features over the duct-tape to preclude loose parts concerns. The licensee was responsive to NRC concerns and initiatives on this matter. The TM was completed on March 31, 1986 and was controlled by MR 86-235.

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i (6) Replacement of Missing Mirror Insulation at Nozzle N16B

On March 21, 1986 the licensee issued MR 86-50-7, in part, to i

remove vessel insulation on nozzle N16B to facilitate QC inspec-l

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tion and testing (due to inverted nozzle concern) and provide subsequent replacement to the as found condition. Mirror insula-

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tion panels were removed around the nozzle and verified by Bechtel QC. When reinstallation of the panels occurred at a later date,

) the Bechtel QC inspector noted that a third panel (18" x 28")

! was missin The panel had fallen between the annular space of

the vessel and the bioshield to a lower elevation. Since the insulation could not be restored to the as-found condition with j the missing panel, Bechtel Nonconformance Report No. 633 was issued on March 27, 1986. The licensee developed SE No. 1943, which documented that the approximately 40 pound insulation i i section fell 20 feet and impacted reactor vessel inlet nozzle '

i N2 The structural evaluation noted that the nozzle N2B had

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not been degraded as a result of the impact. Leaving the dis-i lodged section in place and providing a piece of replacement

insulation was determined by the licensee's NED to be an accept-1 able disposition to the issu i

, (7) Restoration of Piping Insulation on Nozzles i

During the performance of the repair activities for nozzle N16A instrument piping, visual inspection of installed insJlation on

piping associated with nozzles N15A&B, and N16A&B, indicated j that insulation was not in accordance with the applicable i

drawings. The licensee's inspection personnel issued NCR 86-15 l to describe the nonconformance and document the disposition.

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' The disposition required the insulation on the subject piping to be restored. MR 86-50-17 was issued to control the main-

tenance activity. The licensee used 2" thick Nukon spiral wra SE No. 1638, dated March 31, 1984, describes the use of the Nukon material, that it is in conformance with R.G.1.36, and

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its use will no*. result in loose parts concerns associated with j clogging ECCS pump strainers in the Torus.

b. Onsite Review Committee (ORC) Involvement

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t i Almost from the onset of the event, the ORC was involved in the

, event followup and repair activities. The ORC maintained an active

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role in reviewing the subsequent plant activities and providing an

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oversight role to address nuclear safety issues. Where appropriate, the ORC directed that surveillance activities be held in abeyance to j maintain equipment availability to provide vessel makeup capability.

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A major reflection of the positive involvement, from a safety per-

spective, that the ORC provided during the outage are the requirements

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contained in Temporary Procedure (TP) No. 86-40, Controls for Repair "

i Work to Reactor Vessel Penetration N16A. Among these requirements were the establishment of a plant operator to monitor reactor water f level during repair activity, maintain secondary containment integrity, l establish controls that would minimize efforts to establish primary

! containment integrity, maintain all low pressure ECCS operable, j establish dedicated communications between the drywell work locations j to outside the drywell and to the control room, and specify various j contingency actions.

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l Whether the ORC was reviewing procedures, TMs, SEs, or proposed j equipment configurations developed to support the repair activity, J the committee reviews were timely, thorough and technically sound.

Additionally, the ORC ensured that proper support staff (e.g.,

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engineering and contractor personnel) were involved as part of committee deliberation l Procedural Controls l To supoort their repair activities, the licensee developed and

implemented procedures to specify administrative, operational, and engineering controls, provide for the sequencing of the repair

, evolutions, and provide the detail procedural instructions to ensure i the work is conducted properly and safely. Licensee personnel developed supporting SEs to provide the documentation that no unreviewed safety issues existed as a result of procedure implementation. An extensive r array of procedures were developed for the repair effort, and are listed in Attachment 3 to this repor ,

) No inadequacies in the area of procedural controls were identifie i

! Outage Management and Engineering Involvement l

l The performance of the OMG demonstrated that planning and control of j the outage activities was a continuing licensee strength. A high level of attention was directed at ensuring the continued involvement of

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the site operating managers and groups in the deliberations, planning, and implementation of the outage activities. The twice per day t

management planning sessions, which included the offsite engineering groups, were effective. OMG representatives were continuously avail-able and involved throughout the outag [ The NED provided a high level of support and was judged by the

inspector to be a strong engineering resource. In addition to the availability onsite of a designated NED Assistant Deputy Manager, on

, call engineering personnel were provided on a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> basis. NED

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personnel assigned specific responsibilities in the repair efforts were observed to be routinely involved at the site to support planning and implementation evolutions. Engineering efforts were tracked for status and completion, and demonstrated responsiveness to the site activities and identification of problems and nonconforming condition A post outage review by all licensee groups involved in the outage was conducted to identify lessons learned and areas were performance could be improve e. Control of Contractors Overall control of contractors reflected a coordinated effort by the OMG. As part of determining the sequential order of repair evolutions, the licensee established a repair organization chart, which listed all contractor groups and their relationship to the designated licen-see group controlling their action The chart was contained in pro-cedure TP 86-48, Sequence of Work For Repair of Vessel Penetration N16 Based upon ORC review and concern, all damage control responsibilities, in case of a complete parting of the cracked weld during the course of the repair, was designated to be the responsibility of licensee personnel. The NED demonstrated effectivene.ss in coordinating and controlling the contractor groups assigned to their areas of respon-sibilit The use of mockups by the contractor personnel resulted in minimizing exposures, and helped to ensure that the repairs would proceed as planned. One evolution, which involved the reassembly of a Biological Shield Blockout resulted in unnecessary exposure to mair.tenance contractor personnel due to required rework. Although contractor QC involvement was specified and used, the licensee's maintenance contractor failed to perform adequately. Licensee concern was evident and corrective measures taken as a result by the Director of Outage Managemen Work instructions were developed and utilized by the contractor groups in performing their activities. These instructions were reviewed by the inspector, with no deficiencies identified. Adequate field super-vision of contractors was evident throughout the repair proces f. Repair Program (1) Pipe Repair The licensee has planned the sequence of the repair activities, and approved procedures were in place which controlled the various phases of the temporary repair. These include procedures for nondestructive examination (NDE), installation and removal of

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, freeze seals, installation and use of welding and cutting equip-ment, precautions to be observed during the repair, actions and

{ equipment required to mitigate the consequences in the_ event of j the complete parting of the cracked weld during the course of j

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the repair, and hydrostatic testing of the completed repair.

The original construction was done to the requirements of USAS

B31.1 augmented by ASME Section III, 1968 Edition. The repair is intended to meet the requirements of ASME Section XI,1980

Edition including Winter 1980 Addenda. The repair, which was in i progress during the course of this inspection, was planned to

! be made by welding a 316L stainless steel sleeve over the j defective portion of the piping.

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The inspector reviewed procedures which are listed in the t Attachment 3 to this report, welder and welding procedure j qualification records, special process control sheets, travelers associated with the repair, and safety evaluations prepared by

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j the licensee regarding the pipe repai ;

. Observations via closed circuit television were made of a portion i

of the overlay welding which was controlled from a remote station j outside of the drywell. Additionally the inspector reviewed NDE j data, discussed the repair with cognizant General Electric 1 Company (G.E.) personnel and reviewed.the G.E. letter dated

{ 3/21/86 which approved the use of 0-ring seals for the repai The letter confirmed that the 0-ring material was approved by

) G.E. for use in the BWR operational environmen , The inspector found that the repair activities were controlled

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by approved licensee procedures, emergency personnel and equipment

were available at the required locations, and the activities 4 were well planned and coordinated by the licensee. The coordina-tion between the licensee's repair organization (i.e., OMG and i

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NED) and General Electric's onsite/offsite repair support groups

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was well planned and resulted in excellent interactions between the groups in developing / implementing repair techniques.

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(2) ALARA Planning & Tracking

As part of the outage work scope, the licensee implemented an i ALARA Tracking Program. On a rautine basis, the licensee posted

) and distributed the estimated vs. actual ALARA performance for outage related work. When exposure estimates were judged too i high, the licensee's ALARA staff would revise the estimates

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downward. Throughout the outage the inspector noted a concerted effort to track and minimize unnecessary exposure. Following j the completion of the outage, the licensee planned on issuing a

summary report on their ALARA experience for this outag *

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(3) Loss of the Freeze Plug During the pipe restoration portion of the repair on March 28, 1986, the upstream freeze seal failed at 6:00 At the time of this incident, the piping system was assembled, however all

the welds were not rooted in. A. full freeze was not performed because of concern that the frost line of the freeze seal could migrate to the weld area. Approximately 15 minutes prior to the loss of the seal, a nitrogen Dewar supplying liquid nitrogen to the seal was changed out. Initial response by contractor personnel resulted in attempting to tape the unwelded sockets to control leakage. The contractors performing the welding and freeze seal left the drywell. The control room was informed of the occurrence by an OMG representative. Freeze seal contractor personnel returned to the drywell and reestablished the seal at 7

05 Subsequently, the socket tack welds were ground out and the line removed and drained for rewelding. The total leakage due to the loss of the freeze seal was estimated at about 20 gallons of reactor wate One welder was slightly contaminated but, was readily decontaminated by showerin Due to the apparent influences of maintaining a minimum preheat temperature of 50 degrees Fahrenheit as required by Welding Procedure TP 86-43, the freeze seal was not maintained as cold as possibl Following the direction of the licensee, the integrity of the freeze seal was to take priority. Welders were able to maintain preheat conditions for the weld while the freeze seal was established at the full freeze conditions. The I

licensee informed the inspector that this experience will be factored into their procedures wh'en freeze sealing techniques i are utilized in the futur The inspector had no further questions on this item at this tim g. QA and QC Involvement

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j Licensee involvement of QA and QC Organizations were evident during

the inspector's review of the repair program, including in contractor support organizations. Because both G.E. and Bechtel QA Programs are approved by the licensee, appropriate delegation of QA responsibil-

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_ities had been specified.

J Nonconformances issued by both G.E. and Bechtel, including their i recommended dispositions and/or corrective actions received the review of'the'NED responsible engineer and Nuclear Engineering Manager as part of the nonconformance disposition review-proces ?

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As part of the G.E. Travelers, the inspector noted that hold / check points were designated for G.E. QC personnel and licensee cognizant personnel. At various times during the repair activities, licensee QC oersonnel performed surveillance inspections of contractor and licensee work activities. The inspector reviewed the written inspec-tion reports generated by the QC personnel to document their surveil-lance inspections. The inspector noted that as a result of QC Inspec-tion Report IRS 86-36 issued in March 20, 1986, Deficiency Report 1518 was issued by the QA Manager to document contractor performance of inspection work on nozzle N16A without an approved MR. Recommended

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corrective action was stipulated, with OMG, NED, and site maintenance groups involved in the response to the identified deficienc The licensee's corrective action was effective in prec.luding recurrence of the deficienc No inadequacies were identified by the inspector in this are . Organization and Administration In a March 14, 1986 memorandum the Nuclear Operations Manager (NOM)

designated the Management Services Section Head (MSSH) to be acting NOM for the period of March 15-22, 1986. The responsibility to act as the Emergency Director was assigned to the Technical Section Manager (TSM)

during this period. On March 17, 1986, the inspector reviewed the qualifications of the MSSH to determine if the requirements of Technical Specification (TS) 6.3, Facility Staff Qualifications, were being met.

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TS 6.3 requires that plant personnel are selected in accordance with ANSI N18.1-1971, Selection and Training of Personnel for Nuclear Power Plant According to the ANSI Standard, the plant manager (the equivalent position of the NOM) shall have acquired the experience and training normally re-l quired for examination by the NRC for a Senior Reactor Operator's (SRO)

license, whether or not the examination is take The inspector determined that the MSSH had never obtained SRO license and it had not been cer-tified that he would have received a license if he were to take the appli-cable NRC examination The inspector met with licensee representatives, including the Vice President-Nuclear, to discuss this issue and inspector concerns. Subse-quently, a memorandum was issued by the Vice President-Nuclear on March 18, 1986 that designated the TSM, who holds a current SRO license and had the experience and education stipulated in ANSI 18.1-1971, as the acting t NO The inspector had no further questions on this ite ,

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10. Management Meetings At periodic intervals during the course of the inspection period, meetings were held with senior facility management to discuss the inspection scope and preliminary findings of the resident inspector. No written material was given to the licensee that was not previously available to the publi .

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Attachment 1 to Inspection Report 50-293/86-07 Persons Contacted L. Oxsen, Vice President, Nuclear Operations C. Mathis, Nuclear Operations Manager (Senior Licensee Manager Present at Exit Meeting)

A. Pederson, Nuclear Operations Manager P. Mastrangelo, Chief Operating Engineer D. Swanson, Nuclear Engineering Department Manager K. Roberts, Director Outage Management N. Brosee, Maintenance Section Head T. Sowdon, Radiological Section Head J. Seery, Technical Section Head E. Ziemianski, Management Services Section Head S. Wollman, On-Site Safety and Performance Group Leader B. Eldridge, Acting Chief Radiological Engineer R. Sherry, Chief Maintenance Engineer D. Mills, Construction Management Group Leader J. McEachern, Resource Protection and Control Group Leader E. Graham, Compliance and Administrative Group Leader l

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4 i Attachment 2 To Inspection Report 50-293/86-07

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, Portions of the following surveillance tests were reviewed:

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IGSCC Visuci Examination, Temporary Procedure No. TP 85-40 conducted j on April 1, 198 . Portions of the following maintenance and modification activities were reviewed:

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MR 86-202, Repack A0 220-44 due to leakage

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MR 86-244, MO 1001-36A valve leaks through j --

MR 86-159, Repair to the HPCI steam line trap l

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MR 86-216, Trip to IRM "G" caused half scram l --

MR 83-46-385, Breaker 1815A Calibration and Overhaul

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MR 83-46-386, Breaker 1815B Calibration and Overhaul

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MR 86-208, Remove Valve Operator on A0 220-44 to allow access to i leaking pipe wald

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MR 86-207, Remove and Replace Ductwork and Blockout N16A (steel &

j blocks) as required for support of repairs to reactor water level

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MR 86-211 Perform etching on 2 inch N16A nozzle to identify weld i locations

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MR 86-213 N16B nozzle blockout removal to facilitate NDT I

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MR 86-235 Install Temporary Modification (TM) 86-12 i

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MR 86-50-40 Biological Shield A-8B missing steel beams

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MR 86-50-5 N15A Nozzle preparation for QC inspection and testing

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MR 86-50-6 N15B Nozzle preparation for inspection and testing

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MR 86-50-7 N16B Nozzle QC inspection and testing t

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MR 86-50-8 Reactor Support on N16A

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MR 86-50-9 Repair leak in reactor water piping on N16A Nozzle I

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MR 86-50-10 N15A Nozzle QC inspection and testing i i

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Attachment 2 2

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MR 86-50-11 N15B Nozzle QC inspection and testing

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MR 86-50-12 N16B Nozzle QC inspection and testing

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MR 86-50-13 Replace missing guide support on piping of N16A Nozzle

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MR 86-50-17 Restore insulation on nozzles

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MR 86-50-18 Perform and etching on N14 nozzle

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TM 86-10 Repair Crack in 2 inch reducer socket weld (non pressurized service)

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TM 86-11 Repair Crack in 2 inch reducer socket weld (pressurized service)

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TM 86-12 Modification of Drywell ducting J

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Attachment 3 The following procedures were reviewed by the inspector as part of the licensee's repair efforts for the cracked weld on Nozzle N16A instrument piping:

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TP 86-26, Rev. O, Radiographic Examination of Welds. General Requirements

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TP 86-29, Rev. O, Ferrite Measurement Procedure

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TP 86-30, Rev. O, Etching Procedure

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TP 86-31, Rev. O, Determination of Ferrite Content Using a 1.053 Meter

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TP 86-34, Rev. O, Freeze Plugs in 2" NPS and Smaller Stainless Piping

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TP 86-35, Rev. O, Arc Strike Removal

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TP 86-36, Rev. O, Materials and Processes

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TP 86-37, Rev. O, Tool and Equipment Control

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TP 86-38, Rev. O, Visual Examination

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TP 8G-39, Rev. O, Liquid Penetrant Examination

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TP 86-40, Rev. 1, Controls For Repair Work to Reactor Vessel Penetration N16A

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TP 86-41, Rev. O, Weld Procedure 8.8.20

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TP 86-42, Rev. O, Weld Procedure 8.8.21

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TP 86-43, Rev. O, Weld Procedure 8.8.14

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TP 86-44, Rev. O, Weld Procedure 8.8.15

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TP 86-45, Rev. O, Weld Procedure 8.8.19

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TP 86-48, Rev. O, Sequence of Work For Repair of Vessel Penetration N-16-A

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TP 86-53, Rev. O, Peening Repair Procedure

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TP 86-51, Rev. O, Special Hydrostatic Test for Replacement Sleeve to Nozzle N16A of Reactor Vessel

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Attachment 3 2

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TP 86-50, Rev. O, Furmanite Seal to Support Repair of N16A Nozzle

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TP 86-54, Rev. O, UT Examination of Pipe and Tube

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Procedure No. 2.1.8 3, Visual Examination For Leakage During System Pressure Testing

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