IR 05000219/1987027

Insp Rept 50-219/87-27 on 870821-10004.No Violations Noted. Major Areas Inspected:Plant Operations,Physical Security,Ler & Drywell Shell Thinning Concern Reviews & Maint.Problem Re CRD Mechanism Accumulator Pressures Identified

ML20149D623
Person / Time
Site:	Oyster Creek
Issue date:	01/05/1988
From:	Cowgill C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20149D622	List: IR 05000219/1987027 ML20149D617
References
50-219-87-27, IEB-79-02, IEB-79-14, IEB-79-2, IEB-80-25, IEIN-86-036, IEIN-86-36, NUDOCS 8801130059
Download: ML20149D623 (18)

Text

_. - _ _ _

,. ..

.

U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Report N /87-27 Docket N License N DRP-16 Priority --

Category C Licensee: GpU Nuclear Corporation 1 Upper Pond Road Parsippany, NJ 0705 Facility Name: Oyster Creek Nuclear Generating Station Inspection At: Forked River, New Jersey Inspection Conducted: August 21 - October 4, 1987 Participating Inspectors: W. H. Bateman W. H. Baunack R. A. Mc Brearty J. F. Wechselberger Approved by: 6d h MIDate C. J. C wgil G ief, Reactor Projects Section 1A I_nspection Summary:

Areas Inspected: Routine inspections were conducted by the resident and two region based inspectors (205 hours0.00237 days <br />0.0569 hours <br />3.38955e-4 weeks <br />7.80025e-5 months <br />) of activities in progress including plant operations, radiation control, physical security, surveillance, and maintenanc The inspec-tors also followed up new drywell shell thinning concerns, reviewed Licensee Event Reports and periodic and special reports, and periodically toured the control room and other portioris of the power plant. During this report period, a violation of a Technical Specification Safety Limit occurre Inspection activity associated with the Safety Limit violation is documented in NRC Inspection Report 50-219/87-2 Results: No violations were identified. A problem was identified concerning con-trol rod drive mechanism accumulator pressures. The sixth unplanned maintenance outage since plant restart in December 1986 commenced during this report perio On September 16, 1987 the unplanned outage was changed in classification to a mid-cycle maintenance outage based on a projected delay in plant restart because of events surrounding the Safety Limit violation.

l h$k f00b Q

_ _ _ _ _ - _ _

,

..

.

DETAILS l

1 1. Review of Key Operational Events l During this report period, the following key operational events occurred and were followed up by the inspectors:

--

A leak from a main flash tank manway cover started and efforts were made to repair it on lin These efforts involved reducing plant power and tightening the manway cover seal. The efforts were unsuccessful and the leak continued to grow worse. In parallel with this leak, the drywell unidentified leakrate was increasing, the rate of increase of the tores water level was increasing, and the identified leakrate was higher than normal, thus, confirming suspicions of a leak past the bonnet-to-body pressure seal of Feedwater isolation valve V-2-35. A decision was made to shutdown the plant and perform required maintenance. The plant was shutdown on September 9, 198 Two days after the shutdown, on September 11, 1987, the licensee violated Technical Specification Safety Limit 2.1.E while attempting to recover

, from a leak in a closed cooling water system. Details of this event are described in NRC Inspection Report 50-219/87-2 Problems that were thought to be corrected reappeared. These included loss of open valve position indication on mainsteam isolation valve NS-03A, poor performance of a feedwater pump motor bearing oil slinger, a leak from a threaded drain connection in a feedwater pump housing, fail-ure of an intermediate range detector and other intermediate range in-strumentation problems, poor trunnien room fan performance, periodic re-ceipt of half scram signcis, and poor performance of the offgas sample pump. The failure of maintensnce and engineering support groups to effectively identify and correct the root causes of these problems con-tinues to make operating the plant more difficul . Status Report on Drywell_Shell Thinning i In late November 1986, the licensee notified the NRC of a condition involving corrosion of the outer surface of the drywell shell. The licensee detected thinning of the outside surface of the drywell shell where it is cushioned by a layer of sand. This is the subject of Generic Letter 87-05 dated March 12, 1987.

l A sampling plan to determine the extent of the thinning was developed by the licensee including ultrasonic (UT) thickness measurements of the drywell s. hel The licensee has committed to continue the UT shell thickness test programs at future outages of opportunity including forced outages otherwise requiring drywell entry during the next cycl _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _

_--

,..

, ..

.

. 3 Specification 15-328227-004 entitled "Functional Requirements for Drywell Containment Vessel Thickness Examination" established the minimum requirements-for ultrasonic testing of the Oyster Creek drywell containment vessel for wal thickness measurements. The document specifies the type of equipment to be used and the elevations at which the drywell shell is to be prepared. The examination is to be performed on accessible portions of a 1" wide band ex-tending 360*.around the shel On September 26, 1987 UT measurements were made along the accessible portions of a 1" wide, 360 band at the 50'2" elevation of the drywell shell. The nominal plate thickness at that elevation is 0.770", the design minimum thickness based on specified material properties is 0.725", and the-licensee has calculated the minimum allowable thickness, based on certified material properties, to be 0.671". The licensee's data reveal numerous readings which are less than the nominal plate thickness, and in a few scattered instances l -are less than the design minimum thickness. The area displaying the lowest readings'was found to be almost directly above the bay 11 area which, in 1986, displayed the second most severe thinning where the shell is cushioned by the i sand layer. The NRC has requested that the licensee consider additional in-

'

spection at the 50'2" elevation to further characterize the extent of the wall

thinning. The area above the most severe thinning at the sand layer, bay 19, was not examined because of obstructions which precluded access to the 1" wide band. The licensee plans to perform additional measurements at the 82' ele-vation of the drywell shel This area will continue to be reviewed in further inspection . Onsite Review of Licensei Event Reports (LERs)

The following LERs were reviewed to determine if reporting requirements were met, the report was adequate in assessing the event, the cause appeared accur-ate, corrective actions appeared appropriate, generic applicability was con-sidered, the licensee review and evaluation were complete and accurate, and the LER form was properly complete (Closed) 84-04: Violation of Secondary Containment Integrity During refueling a contractor employee found both doors of a reactor building airlock open at the same time. This constituted a violation of secondary containmen The airlock doors were immediately shut to restore secondary containment, The inspector verified that the requirements associated with the air locks i and the correct operation of the doors has been included in the Oyster Creek l General Employee Training. Also, Work Request 20946 replaced a warning sign i which was missing above one interlock override switc l

_ ._

_

.. ..

(Closed) 84-05: Isolation Condenser Piping Leak Near Weld Joint During hydro testing of the isolation condensers, a leak was noted on the "A" condenser condensate pipin GPUN performed Safety Evaluation SE-323357.002, and submitted Technical Analysis Report 580 to the NRC relative to this matter. Additional testing was performed and nepoirs were made. The NRC issued a Safety Evaluation, dated September 20, 1984 concerning the acceptability of the isolation con-denser pipin (Closed) 84-08: Degradation of Neutron Monitoring Instrument Dry Tubes This report describes the identification by the licensee of cracks found in the neutron monitoring instrument dry tubes.

i

'

Ouring Inspection 86-12, the licensee's actions to replace all twelve instru-ment dry tubes was reviewed. However, the LER remained open pending the licensee's submittal of a supplemental report. This supplemental report was submitted on October 15, 1986. The inspector verified that a licensing action item has been written to assure the dry tubes are inspected on a refueling outage basis as recommended by General Electric.

,

(Closed) 84-26: Emergency Service Water Pressure Less than Containment

'

Spray Pressure Oue to Change in System Operation and Decreased Emergency Service Water System Performance This report describes a condition which has existed for sometime. A review of this LER was conducted during Inspection 86-12. At that time the licensee indicated the system would be returned to its original design prior to startup from the llR refueling outage and that a supplemental report would be issue A supplemental report was submitted on May 27, 198 This report indicated that the necessary corrective action had been taken during 11R to restore the system to operate as intended. The inspector verified that action has been taken to add steps to surveillance procedure 607.4.003, Containment Spray and Emergency Service Water Pump Inservice Test, to monitor the required delta pressure during routine surveillance testin (Closed) 85 22: Reactor Scram Due to Main Generator Trip

! During power operation (at 77%), a phase differential current transformer, part of the main generator protection system, faile This failure initiated a generator trip, turbine trip, and reactor scra Shortly after the scram was reset, a main steam isolation valve closure and scram occurred. The second scram occurred as a result of an operator inadvertently ranging the Intermediate Range Monitors (IRMs) past range nine to pick up the range ten contact The IRMs in range ten, with less than 850 psig reactor pressure, resulted in the main steam isolation valve closure and associated scra . .. -

. 5 This LER had been reviewed during Inspection 86-24. At that time, the LER remained open pending completion of a range switch modification to prevent inadvertent actuation of the IRM range ten contacts. The inspector verified that a modification has been made to the IRM range switch. This modification mechanically makes it more difficult to rotate the switch from range nine to range ten and in that way is intended to make the operators aware of their approaching range 10. On January 6, 1987, this modification was ineffective in preventing another inadvertent range ten actuatio At the time of the event, the NRC inspectors interviewed several control room operators to determine the effectit ness of the newly installed mechanical device designed to prevent inadvertent switch upranging. The consensus opinion was the device was not effectiv This information was discussed with the licensee. The matter is the subject of previously unresolved items (219/86-02-02 and 219/86-02-03).

4. In-Office Review of Licensee Event Reports (LERs)

The LERs in this section were reviewed to determine if reporting requirements were met, the report was adequate in assessing the event, the cause appeared accurate, corrective actions appeared appropriate, and generic applicability was considered. The following LERs meet these criteri (Closed) 85-06: Reactor Scram Due to Low Water Level With the reactor subcritical and at approximately 400 MWT, power was being decreased to facilitate a primary containment entry when an automatic scram occurred due to a reactor low water level condition. The low level condition resulted from a rapid power decrease which initiated a reactor level transient from which operators were not able to recover. In response to the scram, all control rods inserted, all plant systems responded as expected and control room operators brought the plant to a shutdown condition. Procedures have been changed, and operators have been provided additional training in reactor level contro (Closed) 85-09: 480 Volt Unit Substation Overload As a result of an electrical load study performed, it was determined that 480 volt unit substation 1A2 or 1B2 may be overloaded during a loss of coolant accident with offsite power available and concurrent loss of one unit sub-statio The cause of this deficiency has been determined to be a design problem, and the fact that the impact of plant modifications on bus loading was not evaluated for this particular set of conditions. Corrective action consisted of the addition of fans to the transformers for the unit substations which has increased their capacity by 15% and brought the anticipated worst case loading within the rating of all the unit substation component _ _______ _

. . ..

e

(Closed)_85-24: Reactor Trip Due to High Neutron Flux A reactor trip from full power occurred due to a high neutron flux conditio The high neutron flux condition was the result of a void collapse in the core region. This void collapse resulted from a 12 psi reactor pressure increase which was caused by the failure of the electric pressure regulator. The electric pressure regulator failed due to a loose wire connection. The cause of the loose connection was determined to be the failure of technicians to install a flat washer at the connection. The connection was properly made up and other connections were checked. Plant response following the trip was as expected with the exception of reactor water level control. As a result of this and other reactor level control problems following reactor trip an action item was initiated to provide operators with specific guidance fo feedwater control following trip (Closed)_84-28; Failure of B & E Electromatic Relief Valve to Open This report describes the failure of two electromatic relief valves to operate during surveillance testing following a refueling outag The corrective action taken to prevent recurrence (seal welding retainer) is identical to t that taken at another facilit No other similar problems have been experi-I enced with the valves and the valves have successfully passed a subsequent surveillance performed after the last refueling outag (Closed) 86-01: Reactor Low Level Sensors Found Out of Specification l

l This report Jescribes the identification of three of four reactor low level sensors being found out of specification during monthly surveillance as well I as other subsequent problems associated with these instruments. As a resalt l of these problems all reactor water level switches were replaced with analog instruments. Routine inspections have verified the satisfactory operation of these new instruments.

I (Closed) 86-02: Inoperable Containment Spray Snubber Caused by Personnel Error l

l This report identifies an occurrence where a safety related hydraulic snubber l was mistakenly made inoperable. The error resulted from the shift supervisor

! misunderstanding a short form. He understood from the short form that the I work was intended to repair an inoperable snubber instead of replacing a com-l ponent on an operable snubber. The snubber was inoperable for approximately I ten minutes. To prevent a similar event, a copy of the LER was made required reading for all shif t supervisors and maintenance planning personne _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ .

. -.

v .. ..

.

.(Closed)86-03: Three of Eight Isolation Condenser Pipe Break Sensors Out of Specification During routine surveillance testing three of eight pipe break sensors for the steam and condensate lines of both isolation condensers were found to have setpoints slightly out of specification. All three sensors were satisfactor-ily readjusted to trip within the desired setpoint limits and returned to servic { Closed) 86-05: Core Spray and Diesel Generator Initiation Caused by Procedural Deficiency An inadvertent Core Spray System and Emergency Diesel Generator automatic initiation occurred during a surveillance test due to valving one low level sensor into service after being connected to a test gauge and the line not filled with water. This caused a pressure drop in a common sensing line shared by reactor low low level sensors. The pressure drop initiated the event. Corrective action consisted of making a procedure change and Mahni-cian training on the proper technique for filling instrument lines before valving instruments into servic (Closed)_86-07: Reactor Shutdown Due to Reactor Lew Water Level Switch Repeatability Problems A plant shutdown was conducted due to repeatability / drift problems with reac-tor low water level scram switches. The low water level scram switches were replaced with a different model switc (Closed) 86-08: Local Leak Rate Test Results Local leak rate testing identified twenty-one containment isolation valves having leak rates in excess of the acceptance criteria specified in Technical Specifications. All valves were either replaced or repaire Subsequent local leak rate testing verified that all of the containment isolation valves had acceptable leakage rates. Local leak rate testing is reviewed as part of the routine inspection progra (Closed) 86-11: Secondary Containment Isolation and Initiation of Star.dby Gas Treatment System The cause of the secondary containment isolation and initiation of the standby gas treatment system was a spurious power supply spike which tripped the reactor building vent radiation monitor The faulty power supply was re-place Subsequent trouble shooting identified several failed capacitors.

L

.. ..

.

(Closed)86-12: Containment Isolation and Standby Gas Initiation Caused by Electrical Storm A primary containment isolatf or., secondary containment isolation, and standby gas treatment system initiation occurred when lightning struck a electrical distribution line which caused a transient on a line supplying plant load The event caused an automatic bus transfer of power supplies to a vital bu The automatic bus transfer is a break before make design and its transfer time is not sufficiently fast to prevent protective relays from deenergizin Corrective action consisted of restoring electrical configuration to norma A long term solution is under revie (Closed) 86-13: Secondary Containment Isolation and Initiation of Standby Gas Treatment System A secondary containment isolation and standby gas treatment system initiation occurred as a result of an area radiation monitor power supply failure. The power supply failure resulted from a broken wire. The failed power supply was replaced with a spare uni (Closed) 86-14: Jontainment Spray System Seismic Concerns Stress analysis of the Containment Spray (CS) system piping and pipe supports performed as part of the reanalysis program for IE Bulletins 79-02 and 79-14 revealed deficiencies in four CS system pipi.1g supports. This condition existed since original plant construction. The four supports were upgraded during the 11R outag [C_lo_ sed)86-16: Fuel Clad _ Failures Due to Pellet / Clad Interactions During fuel sipping operation it was discovered that 47 fuel bundles had cladding failures. The cladding failures appear to be the result of pellet /

clad interaction which resulted from the Power Shape Monitoring System (PSMS)

inadequately monitoring preconditioning interim operating management recom-mendations and improper operating guidance. Corrective action consisted of revising the PSMS program and operating procedures. Cycle 10 fuel failure follow-up was documented in Inspection Report 86-3 (Closed) 86-17: Containment Isolations and Standby Gas Initiations Caused by__ Storms This event is identical as that described in LER 86-12. A follow-up report will be submitted when the action taken to prevent recurrence has be evaluate (Closed) 86-18: Secondary Containment Leak Rate Secondary containment leak rate test failed to meet acceptance criteria be-cause a temporary cap on the service water overboard line had f allen of The cap was replaced and a subsequent successful leak rate test performe __

- - _ - - _

-

..

'

.

.

(Closed) 86-19: Standby Gas Initiation Caused by Personnel Error The Standby Gas Treatment System (SGTS) initiated when one end of an elec-trical jumper inside a control room panel fell off and caused a short to grotnd. ,The short blew two fuses in the reactor. protection system. initiating the event. The immediate corrective action-was to replace the blown fuses, remove the jumper, and secure the SGTS. Long term corrective action will be-to review and revise jumper contro .{ Closed)86-27: Standby Gas Treatment System Initiation Caused by Personnel-Error A secondary containment isolation and Standby Gas Treatment System (SGTS)

initiation occurred when an area radiation monitor power supply was inad-vertently grounded during a surveillance. The ground was caused by an I & C-technicians test probe. A second SGTS initiation occurred as a result of an incomplete repair of a spare power supply from a previous failure. Corrective action consisted of technician training, procedure changes and an evaluation to made test contacts more accessibl '

'(Closed) 86-28: Personnel Error Defeats an Automatic Initiation Function of Standby Gas Treatment System Ouring the installation of a modification it was noted that'all reactor low-low water level initiatica signals to the standby gas treatment system had been jumpered out. The review of this event is documented in Inspection Re-

.

port 50-219/86-38.

l (Closed) 86-29: Potential Inoperability of Core Spray / Emergency Service Water Pumps Due to Inadequate Design and Procedure Reviews l During emergency service water (ESW) pump thermal over current relay testing it was determined its long term current setpoint was incorrec Testing

'

showed the relay may actuate within the operating current band. This condi-tion, for the ESW pump, resulted from increasing system flow requirements without considering the tolerance of the thermal relay. A similar condition was noted for the core spray pumps, which could exceed their relay setpoints if operated in run-out mode. The core spray pump problem resulted from original design. Corrective action consisted of reviewing other systems.

l No other systems were affected. Also, the setpoints for the thermal relays of the ESW and core spray pumps were raised.

l (Closed) 86-30: Isolation Condenser "A" Isolation on Spurious High Flow Signal The "A" isolation condenser condensate return line differential pressure flow sensor sensed a differential pressure above the isolation actuation setpoint, t

The High differential pressure condition was caused by a leak in a newly in-stalled flow sensor snubber. The root cause of this event was a procedural

.. ..

.. ..

.

!

I l

deficiency in that a post-snubber replacement leak test was not specified in a procedure. Corrective action consisted of repairing the leak and reviewing other procedures for similar problem < .(Closed) 86-32: Reactor Trip on High Neutron Flux Caused by Cold Feedwater Addition Oue to Operator Error A reactor trip occurred due to a high neutron flux condition caused by cold feedwater addition to the reactor vessel. The cold feedwater addition re-sulted from the improper manipulation of the feedwater regulating valve local controller and the operator not remaining cognizant of the feedwater regulat-ing valve positio Corrective action consisted of reviewing the event with each oncoming shift and providing additional event related training in the operator training progra Also, new feedwater regulating valve controllers that will not cause lockup on loss of signal have been ordere (Closed) 86-33: Standby Gas Treatment Initiation Caused by Ground on Arm

_

Ribbon Cable Due to Personnel Error A reactor building ventilation and standby gas treatment system initiation occurred when an area radiation monitor trip unit was inadvertently grounded during maintenance. An instrument technician caused the ground by pinching a ribbon cable when inserting one of the monitor trip units. Corrective ac-tion consisted of replacing the pinched cable, instructing maintenance per-sonnel, and checking the integrity of the other ribbon cable . Review of NRC Bulletins Bu_lletin 80-25, Operating Problems with Target Rock Safety Relief Valves at BWRs NUREG/CR-3794 proposed certain follow up in order to closecut Bulletin 80-2 The follow-up requested was verification that Bulletin Action Item 2 has been incorporated in facility procedures.

l The inspector verified that facility Procedure 602.4.003, Electromatic Relief Valve Operability Test, contained the requirement that if a safety relief valve fails to function as designed, excepting for pressure setpoint require-mentr, and the cause of the malfunction is not clearly determined, understood ( or corrected the valve shall be removed from service, disassembled, inspected

'

and adjusted, and tested in accordance with the valve aperability test pro-cedur The licensee's initial response to this Bulletin did not include the above informatien because, as noted in licensee files, the licensee was advised by the NRC that the Bulletin only applied to plants with target rock safety-relief valve This Bulletin remains close _ _ _ . . _ _ - _ _ _

&

-

.

.

6. Observation of Physical Security During daily tours, the inspectors verified access controls were in accordance with the Security Plan, security posts were properly manned, protected area gates were locked or guarded, and isolation zones were free of obstruction The inspectors examined vital area access points to verify that they were properly locked or guarded and that access control was in accordance with the Security Pla No unacceptable conditions were identifie . Plant Operation Review 7.1 Periodic toers of the control room were conducted by the inspectors during which time the following documents were reviewed:

--

Control Room and Group Shift Supervisor's Logs;

--

Technical Specification Log;

--

Control Room and Shift SJpervisor's Iurnover Check Lists;

--

Reactor Building and Turbine Building Tour Sheets;

--

Equipment Control Logs;

--

Standing Orders; and,

--

Operational Memos and Directive .2 Periodic tours of the facility were conducted by the inspectors to make an assessment of the equipment conditions, safety, and adherence to operating procedures and regulatory requirements. The following areas were among those inspected:

--

Turbine Building

--

Vital Switchgear Rooms

--

Cable Spreading Room

--

Diesel Generator Building

--

Reactor Building The following additional items were observed or verified: Fire Protection:

--

Randomly selected fire extinguishers were accessible and inspected on schedul __ _ _ _ _ _ _ _

.

_

..

-

.,

a

,

--

Fire doors were unobstructed and in their proper positio Ignition sources and combustible materials were controlled in ac-cordance with the licensee's approved procedure Appropriate fire watches or fire patrols were stationed when equip-ment was out of servic . Equipment Control:

I

--

Jumper and equipment mark-ups did not conflict with Technical 1 Spec'fication requirement !

l

'

--

Conditions requiring the use of jumpers received prompt licensee attentio Administrative controls for the use of jumpers and equipment mark-ups were properly implemente yttal Instrumentation: >

.

--

Selected instruments appeared functional and demonstrated parameters t;ithin Technical Specification Limiting Conditions for Operation, Housekeeping:

--

Plant housekeeping and cleanliness were in accordance with approved licensee program No unacceptable conditions were identifie . Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee pursuant to Technical Specification requirements were examined by the inspectors. This review included the following considerations: the report includes the infor-mation required to be reported to the NRC; planned corrective actions are adequate for resolution of identified problems; and the reported information is vali The following reports were reviewed:

--

Special Report 87-04, dated 7/29/87, described how the Fire Suppression Water System became inoperable as a result of system leakage which re-

quired running both fire pumps to maintain system pressure. Fire watches I were posted as required by Technical Specification. Subsequent investi-gation into the cause of the leakage determined that a valve body had cracked due to excessive stresses induced as a result of a recent modi-

. _ _ _

.. ..

.

, 13 fication to add piping to the syste The valve was repaired. The lic-ensee evaluated the problem and corrected it by implementing a modifica-tion to the valve flange boltin Special Report 87-05, dated 7/31/87, described a deficiency identified in the north wall of the Cable Spread room where a portion of a back wall had been removed to eliminate a cable try support interference. A fire watch was posted to meet Technical Specification requirements until re-pairs can be made during a future outag . Radiation Protection During entry to and exit from the RCA, the inspectors verified that proper warning signs were posted, personnel entering were wearing proper dosimetry, personnel and materials leaving were properly monitored for radioactive con-tamination, and monitoring instruments were functional and in calibratio Posted extended Radiation Work Permits (RWPs) and survey status boards were reviewed to verify that they were current and accurate. The inspector ob-served activities in the RCA to verify that personnel complied with the re-quirements of applicable RWPs and that workers were aware of the radiological conditions in the are On September 9, 1987 the licensee notified the resident inspectors that, dur-ing routine periodic inspections of full-face negative pressure respirators, a Scott particulate air filter was found with a hole drilled into the side of the cannister upstream of the filter element. The respirator and filters were located in a locked cabinet near the monitoring and change facilit The defective filter was found on 8/28/87. A prior routine licensee inspec-tion on 8/14/87 did not identify the hole in the cartridg The cartridge in question was placed into the cabinet on 8/17/87 and had been routinely DOP tested and found satisfactory after release from stores and prior to placement in the cabinet. Inspections of all other Scott filters both in the field and in stores were immediately performed and no other defective units were iden-tifie A protection factor for the affected cannister was determined to be about 2 These types of filters are not used in an iodine atmosphere and, based on atmospheres in which the defective filter could have been used, would not have resulted in any excessive internal uptake. The defective filter had not been used. The part number for the Scott filter cartridge is 604100-50. The size of the hole was about 1/8" diameter and appeared to have been drilled into the cannister after the time it left stores and was DOP tested. The licen-see's investigation did not identify who had drilled the hole in the cannister or why the hole may have been drille Based on thorough and prompt investi-gations after identification of the problem and the results that indicated no other cannisters had been tampered with, the inspectors concluded there were no additional concerns the licensee needed to address. This conclusion

- _ _ _ - _ _ .

.

._ .. ..

. .

.

.

l was also based on the facts that routine inspections are performed and, in l

fact, identified the problem and the remaining protection factor of 20 (the normal protection factor is 50) and the controlled use of the filter l

The inspectors has no further questions regarding this area, l 10. Outage Activities The sixth unplanned outage commenced when the plant was shutdown on September The principle cause of the shutdown was an increased unidentified drywell leak rate. An inspection of the drywell indicated the source of the uniden-tified leakage to be a bonnet pressure seal leak on feedwater isolation valve V-2-35. Plans were underway at the end of this report period to repair the valve by either using additional sealant or freeze sealing the feedwater line and disassembling and repairing the valv During the early part of the unplanned outage, a Technical Specification Safety Limit was violate Because of the projected time delay in restarting the plant as a result of this event, the licensee, on September 16, decided to declare the outage a mid-cycle maintenance outage. This marked the com-mencement of a multitude of maintenance activities, PMs, and routine Tech Spec required surveillances including snubber inspections, local leak rate testing of containment isolation valves, and the integrated leak rate test of containmen These and other activities including repairs to the reactor building roof, installation of new high density fuel racks, redesign of elec-tromatic relief valve acoustic monitor splices, and replacement of certain electrical components associated with the recirculation pump motor generator sets were underway at the end of this report perio The inspectors reviewed various aspects of these work activitie No unacceptable conditions were identified.

l 1 HCU 22-11 On August 31, 87 during a tour of the reactor building, the inspector noted that HCU 22-11 accumulator pressure was indicating zero pressure. The in-i spector informed an equipment operator and asked if he could pressurize the accumulator. The equipment operator made several attempts, but each time the pressure decayed off at a noticeable rate on the local pressure gauge. It appeared that a packing leak existed on V-111, the accumulator charging valv This was discussed with licensee management, who was aware of the V-111 pack-ing leak on HCU 22-11 and had been conducting additional charging of the ac-cumulator to maintain the required gas pressure for several days. As a result of the inspectors observation, the licensee upgraded a routine work order to immediate maintenance to replace the packing on V-111, which was accomplished in a short time frame. The Oyster Creek Technical Specifications do not specifically address accumulator gas pressure as a condition of operability for control rods nor do they specify a time period in which to take action to address control rod problems before the particular rod should be declared inoperable. The licensee should consider control rod operability requirements

____- _- _ _ _ _ _ _ _ .

.

..

.

.

based on accumulator gas pressure and a reasonable time period to effect re-pairs before a CR0 should be declared inoperable. Presently, this is not clear in Technical Specifications nor do any operating procedures specify any requirements. In addition, the licensee did not perform an evaluation to assess the significance of the operability of this particular CR0 accumulator to remain pressurize The inspector has expressed concern in this area and the NRC has requested licensee respons . Liquid Poiso M ystem Metal Particles On September 22, 1987 the licensee informed the inspector that fine metal particles had been found in the liquid poison test tank. The licensee cleaned the test tank, obtained samples of the metal particles for later analysis, and proceeded with a troubleshooting program to determine the source of the particles and the amount of any pump degradation. The licensee flushed the demineralized water lines into the test tank eliminating that as a possible source of the metal particles and then recirculated each liquid poisor pump on the test tank to remove any particles in the pump and associated pipin Some fine metal particles were removed from each liquid poison pump and piping by recirculating each pump on the test tank. Next, a system surveillance test to evaluate pump performance was conducted showing that no pump degradation had occurred. The inspector met with the licensee to discuss test results and plans to ensure system degradation had not occurre The licensee determined that the particles most likely resulted from a modi-fication to the system to install a flow indicating device which required adding a penetration to the test tank. This modification apparently was only partially completed in 1980 with valve V-19-48 added in 1983 to complete the modification as presently configured. The licensee completely flushed the system upstream of the squib valves until all of the fine metal particles were removed. In addition, the licensee contracted the pump vendor to witness an i inspection of the pump internals to further verify that no pump damage had ,

occurred. The licensee found some scratches on the pump plungers and elected to rebuild both pumps with new plungers. The material report indicated that the metal particles were 316 stainless steel which was not used in the manu-

,

facture of the pump internals.

,

The inspector expressed concern that metal particles may have deposited in the injection lines downstream of the squib valve The licensee stated that the particle size was insignificant and would not cause any damage if these particles were flushed into the reactor vessel and connecting systems. To support this, the licensee referred to a lost part analysis report performed by General Electric that supported the licensee's contention. The inspector questioned, in consideration of a local leak rate test (LLRT) planned for the liquid poison system check valve and a surveillance requiring the firing of !

the squib valves, if the LLRT could be performed prior to the squib valve firin The performance of the LLRT essentially performs a flushing of a ;

'

majority of the liquid poison injection line and firing the squib prior to i

_

.

.. **

. . . >

!

. 16 performing the LLRT would have the effect of flushing the injection line into I the reactor vessel. Performing the LLRT first would allow an assessment of i the amount of particle deposition in the injection lin ~

The licensee choose ,

, to perform the squib firing prior to conducting tne LLR1 to facilitate other  !

plant evaluations in order to support plant restar Subsequently and prior to performing these, the licensee elected to enter the 11M outage. After this decision, the licensee performed the LLRT followed by the squib firing sur- E veillance. It was reported that little particle deposition was evident as could be determined from the performance of the LLRT on the injection line '

check valve. The inspector discussed his concern of prioritizing important work based on plant restart considerations with the licensee. Licensee man-  ;

agement indicated that, based upon an evaluation of the particle size, either  ;

method was acceptable and,.as a result of having more time, choose to pursue *

the most conservative approach.

.

1 Isolation Condenser Baseline  !

In a November 25, 1986 letter GPUN committed to establish a baseline uniden- t tified leak rate value in order to evaluate a postulated high energy line  !

l break (HELB) within the isolation condenser penetrations. If the unidentified  !

leakage increased greater than 2 gpm above the baseline, the licensee is to l

,

confirm using diagnostic techniques that the source of the increased leakage is not from the isolation condenser penetration. A NRR letter dated December '

.

24, 1986 confirmed this commitment and the licensee's intent to modify the penetrations in the cycle 12R outage in order to support the cycle 11R restart.

1 During this report period, the unidentified leakage approached the baseline plus 2 gpm limit established by the licensee. Based on an inspection of the i i solation condenser in a previous shutdown and a subsequent startup, the lic- l ensee elected to recalculate the baseline leakage rate in the beginning of September 1987. The previous baseline was established over a 25 day period i'

from March 16, 1987 to April 9, 1987 after the unidentified leak rates had

'

stabilized and the plant was operating at 100% power. For the second base'ine i the licensee determined that stable operating conditions and leak rates were [

achieved during the period of August 22-31, 1987. The inspector reviewed the +

( licensee isolation condenser leak detection program and the data for estab- +

11shing the new baseline unidentified leak rate. The inspector expressed a i concern that leak rate data was not as stable as compared to the original leak  !

data which was used to support the first baseline and that an evaluation of  ;

'

the isolation condenser temperatures as delineated in the leak detection pro- t gram would indicate that the increase in unidentified leak rate was not as j

. a result of any isolation condenser penetration weld itakage. The licensee .

acknowledged the inspectors concern and performed the evaluation of the isolation condenser temperatures. They determined that the increase in un-identified leakage was from another source, most likely the leaking V-2-35 feedwater maintenance isolation valve. The inspector conducted an independent j review of the isolation condenser temperatures and came to the same conclusio !

Subsequently, the plant shutdown for secondary maintenance item !

!

The inspector had r.o further questions regarding this matter, t

.

.

---.,, . -

--.,-,w,--,-.---,.,,-- y, , ---,-,,.y _ v -,,,7-, .-.-.-y_. ,-._.y_ . _ . . , - - _ ,,,-y ,,

,. .

.

. 17 14. CR0 10-07 High Differential Drive Pressure On July 5,1987 the licensee experienced difficulty notching in Rod 10-07 with less than 390 psid differential drive pressure. The inspector discussed with the licensee who elected to declare the rod inoperable in accordance with station procedure 617.4.002, CRD Exercise and Flow Test /IST Cooling Water, which requires control rod drives (CRO) to move with less than 390 psi The procedure states that if this criteria cannot be met, to declare the rod in-operable and follow the requirements of Technical Specification 3.2.B.4 and Procedure 104, Control of Non-Conformances and Corrective Actio Technical Specification 3.2.B.4 requires a CRD to be declared inoperable if the rod cannot be moved with control rod drive pressure. This is interpreted as drive pressure in its normal range. The licensee's procedural limit of 390 psid differential drive pressure is within the Technical Specification requirements, although it is a surveillance procedure criteria that, as indicated above, should be met. The inspector reviewed previous station procedure 617.4.002 surveillances to determine any other potential CR0 problems. The review in-dicated the following:

DATE CRD NUMBER DIFFERENTIAL _ PRESSURE (PSIDJ 3/29/87 10-07 380 (Insert)

5/24/87 10-07 360 6/7/87 10-07 350 (Insert)

42-39 350 (Insert)

46-27 380 (Insert)

6/14/87 10-07 390 (Insert and Withdrawal)

10-31 350 (Insert)

46-27 390 (Insert)

6/21/87 10-07 390 (Insert and Withdrawal)

6/28/87 10-07 440 (Insert and Withdrawal)

14-07 380 (Insert)

340 (Withdrawal)

7/5/87 10-07 390(Insert) ,

For the surveillances indicated above which required equal to or greater than 390 psid to move the rod, the licensee annotated the surveillance procedure with the statement that technical specification criteria was met even though the surveillance criteria was not satisfie This review indicates the licensee is not strictly adhering to procedural re-quire ents. Additionally, the inspector noted that the licensee had not evaluated tha condition, rather had noted that the limits of the Technical Specifications had not been exceeded. The inspector expressed concern that potentially degraded conditions nad not been considere _ _ _ _ _ _ .

e .

.

. 18 l

l In response to this concern the licensee has changed the surveillance proce-

'

dure to require the involvement of plant engineering for problem resolution when the drive differential pressure criteria cannot be met. This should avoid future problems. Additionally, during troubleshooting, the licensee l adjusted the 120 (withdrawal speed control needle valve) and 123 (insert speed 1 control needle valve) valves on the 10-07 hydraulic control unit to correct

'

the short withdraw times and long insert times respectivel In addition, the 120 valve was replace Friction testing was conducted and determined that no excessive friction existed. Post maintenance testing determ;ned the rod stroke to be satisfactory with normal CRD pressur The inspector had no further questions regarding this matte . Exit Interview  ;

A summary of the results of the inspection activities performed during this report period were made at meetings with senior licensee management at the end of the inspectio The licensee stated that, of the subjects discussed at the exit intervies, no proprietary information was included.

I

%

. . . . . . . . . . . . . . . . .

-

. . . _ _ . _ .