IR 05000219/1997004

Insp Rept 50-219/97-04 on 970526-0706.Violations Noted. Major Areas Inspected:Aspects of Licensee Operations, Engineering,Maint & Plant Support

ML20196J712
Person / Time
Site:	Oyster Creek
Issue date:	07/29/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20196J695	List: IR 05000219/1997004 ML20196J688
References
50-219-97-04, 50-219-97-4, NUDOCS 9708050034
Download: ML20196J712 (51)

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

Docket No.: 50-219 License No.: DPR-16

Report No.: 97-04 l

Licensee: GPU Nuclear incorporated Facility: Oyster Creek Nuclear Generating Station l

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Location: 1 Upper Pond Road Parsippany, New Jersey 07054 ,

i Dates: May 26,1997 - July 6,1997 Inspectors: Joseph G. Schoppy, Senior Resident inspector Stephen M. Pindale, Resident inspector Todd H. Fish, Operations Engineer Joseph T. Furia, Senior Radiation Specialist Donald J. Florek, Senior Operations Engineer David M. Kern, Beaver Valley, Senior Resident Inspector Approved By: Peter W. Eselgroth, Chief Projects Branch No. 7

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9708050034 970729

PDR ADOCK 05000219

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l EXECUTIVE SUMMARY l

1 Oyster Creek Nuclear Generating Station Report No. 97-04 l This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a six-week period of inspectio I Plant Operations l l i e in general, operators demonstrated effective control of safety related system alignments, and maintained an awareness of equipment status. Operators did not '

maintain adequate configuration control in two minor instances. Although no safety l consequence resulted, attention to detail relative to configuration control was an l operator weakness. (01.1, O2.1)

e Operators and the fire brigade responded quickly and appropriately to a fire in the

"A" M-G battery charger. The licensee's longer term followup activities were continuing at the end of the inspection period and were properly focused on promptly restoring redundant charging sources to the 125 Vdc system. (01.2)

e The control room operators did not implement adequate self-checking techniques, j and supervisory oversight of control room activities was ineffective. As a result, a I

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licensed reactor operator unintentionally started the wrong emergency diesel generator. Another licensed operator mispositioned a control rod during routine surveillance testing by inadvertently moving the control rod one notch in the wrong direction (in vs. out). These errors indicate continued weakness in human l performance and warrants close management attention. (04.1, 04.2)

l e The Oyster Creek requalification exam for licensed operators, administered the week j of June 16,1997, provided an effective performance evaluation that appropriately I identified those operators that needed remediation. Operator performance was l generally good. However, some individuals failed th; written and walkthrough parts l of the exam, and NRC review determined that some of these individuals have had !

repetitive failures over a period of years. These recurrent requalification exam i failures appeared to indicate an ineffective long term remediation process and the l associated inability to maintain proficiency in some areas. The written exam did not

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meet all of the Oyster Creek expectations regarding week to week exam overlap, l which could potentially diminish the long term validity of the exam. Oyster Creek l staff ensured the medical fitness of and compliance with the medical requirements l for the operators. (05.1)  ;

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Maintenance

• The routine maintenance and surveillance activities observed by the inspectors were conducted safely and in accordance with station procedures. (M1.3)

• The non-outage corrective maintenance job order (CMJO) backlog trending matrix provided meaningful information for management to assess maintenance program performance. The non-outage CMJO backlog was reduced from 915 in October 1996 to 772 in May 1997. Improved work efficiencies due to better schedule adherence, trending analysis, and estabhshment of a fix-it-now team directly reduced the non-outage CMJO backlog. Backlog work was generally completed in a timely manner. The existing backlog did not adversely degrade risk significant system performance, and emergent corrective maintenance on these systems has been reduced. (M1.4)

Enaineerina

• The licensee provided substantial troubleshooting and evaluation efforts related to several momentary actuations from the main steam line low pressure switche Strong management oversight was also apparent. However, continued aggressive actions are necessary to identify the root cause(s) and corrective actions associated with the switch actuations due to the risk and consequences (main steam line isolation and scram) of coincident actuations of redundant sensing channels. (E1.1)

• The No.1 emergency diesel generator continued to display erratic loading during surveillance testing. Engineering evaluation and troubleshooting of the observed conditions identified several equipment problems. The causes for those problems and the licensee's effectiveness in identifyirg all relevant problems remains the subject of an existing open item. (E8.1)

Plant Suocort

• The licensee effectively implemented the radiation protection and security program (R1.1, S1.1)

• The radwaste and transportation program were effectively established. The licensee was able to successfully process plant liquids and solid waste material, package this and other radioactive materials, and successfully transport them off-site. One area of weakness was identified, however, in the implementation of plant procedures at the work site during the preparation of a radwaste shipping cask for transport. Had the inspector not identified a defect in the package preparation, the licensee would have been in violation of NRC regulations (upon shipment of the cask). Two additional procedural problems were also identified during the radwaste inspection, including an out-of-date procedure being maintained in the radwaste shipping office, and a procedural weakness which contributed to the contamination of the New Radwaste Building truck bay on June 4,1997. (R1.2)

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e The licensee's quality assurance program for radwaste and transportation, including audits and surveillances, was of generally high quality. Sufficient scope and technical depth was present to aid in the timely identification of issues and declining performance in these areas. A weakness in the quality verification (QV) process was identified as related to procedure usage by QV personnel. (R7.1)

• The licensee's immediate response to the July 1,1997, discovery that all 42  ;

emergency notification sirens had been inoperable due to a lightning strike (on June 23,1997) was appropriate. Their planned actions to prevent similar problems and '

to more promptly identify problems were adequate. However, the delay from June 23,1997, to July 1,1997, in identifying that all sirens had been inoperable was excessive and indicated an ineffective use of an existing self-test feature of the remotely located controlling computer. (P2.1)

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TABLE OF CONTENTS

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Paae N EX E C UTIV E S U M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

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T A B LE O F C O NT E NTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

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l. Operations (40500, 71707, 90712, 92901, 93702) ....................... 1

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01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

, 01.1 General Comments ................................. 1 01.2 Station Battery "A" Motor-Generator Set Charger Catastrophic Failu re a nd Fire . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 3

O2.1 Configuration Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . 4 04.1 Inadvertent Start of Wrong Emergency Diesel Generator (EDG)

i During Concurrent EDG Maintenance and Testing Activities .... 4 j

! 04.2 Mis-positioned Control Rod During Testing Due to Personnel Error............................................ 6 ;

05 Operator Training and Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 )

05.1 Licensed Operator Requalification Program Evaluation . . . . . . . . . 7

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08 Miscellaneous Operations issues ........................... 11

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M1 Conduct of Maintenance ....,............................ 12 i i M 1.1 Maintenance Activities . . . . . . . . . . . . . . . . , . . . . . . . . . . . . . 12 :

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M 1.2 Surveillance Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 l l M1.3 Maintenance and Surveillance Activities Conclusions ........ 13 l q

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M1.4 Non-Outage Corrective Maintenance Backlog Review . . . . . . . . 13  !

I M8 Miscellaneous Maintenance issues .......................... 15 Ill. Engineering (37551, 40500, 71707, 90712, 92903) . . . . . . . . . . . . . . . . . . . . . 16  ;

El Conduct of Engineering .................................. 16 i E1.1 Main Steam Line Pressure Switch Actuations During Power l Operations ...................................... 16 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 l IV. Plant Support (71707, 71750, 92904) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

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R1 Radiological Protection and Chemistry Controls ................. 19 R1.1 General Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 R1.2 Radwaste Processing Systems and Transportation of Radioactive Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

R8.1 Miscellaneous Radiological & Chemistry issues . . . . . . . . . . . . . 23

P2 Status of Emergency Preparedness Facilities, Equipment, and )

, Resources............................................ 24 l P2.1 Notification System inoperable Due to Equipment Damage During Electrical Storm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

, P In-Office Review of Licensee Procedure Changes . . . . . . . . . . . 25 j S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 25 S1.1 General Observations (71750) ........................ 25

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V. M a n a g em e nt M e etin g s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 PARTIAL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 INSPECTION PROCEDURES U SED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 ITEMS OPEN ), CLOSED, AND UPDATED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 EMERGENCY RESPONSE PROCCDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

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Report Details l

Summarv of Plant Status t The plant was operated at or near full power for the duration of this inspection period.

i 1. Operations (40500, 71707, 90712, 92901, 93702)

l 01 Conduct of Operations'

, O 1.1 General Comments l

The inspectors conducted frequent reviews of ongoing plant activities and operations using the guidance in NRC inspection procedure 71707. The inspectors observed piant activities and conducted routine plant tours to assess equipment l conditions, personnel safety hazards, procedural adherence and compliance with l regulatory requirement Control room activities were found to be well controlled and conducted in a professional manner with staffing levels above those required by Technical Specifications. The inspectors verified operator knowledge of ongoing plant activities, the reason for any lit annunciators, safety system alignment status, and existing fire watches. The inspectors also routinely performed independent l verification from the control room indications and in the plant that safety system alignment was appropriate for the plant's current operational mod .2 Station Batterv "A" Motor-Generator Set Charaer Failure and Fire i Insoection Scone (71707,93702,37551) I t  !

On June 27,1997, the motor-generator set (M-G) charger for the "A" station i battery failed while in service and resulted in a fire in the A/B battery rcor.). The inspector responded to the area, observed the fire brigade response and monitored the licensee's immediate response and evaluation activities. The inspector interviewed operations, maintenance and engineering personnel as related to recent operating history of both the "A" and "B" M-G chargers and the "A/B" static charger. The inspector also discussed with the licensee their proposed longer term actions to restore all system components to normal configuration.

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' Topical headings such as 01, M8, etc., are used in accordance with the NRC standardized

reactor inspection report outline. Individual reports are not expected to address all outline

topics.

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b. Observations and Findinas At 2:20 p.m., the control room operators received an alarm indicating that the "A" 125 Vdc M-G set charger tripped. An associated A/B battery room fire alarm also annunciated. The fire brigade was immediately dispatched. The fire brigade reported smoke in the room and that the Halon system had actuated. They further indicated that the fire was out by the time they arrived. The generator for the M-G charger had sustained significant damag i There is an M-G charger associated with each of the two ("A" and "B") batterie Both M-G chargers and both batteries are located in the same room. Only the "B" battery is classified as nuclear safety-related (NSR). A standby static charger, also located in that room, may be connected to either battery in the event of an M-G ,

charger failure. The other NSR battery, the "C" battery, is located in a different l building, with its own redundant static charger Prior to the fire, the "A" M-G charger was supplying the de load for the distribution l bus "A." The static charger was supplying the de load for distribution bus "B" because the "B" M-G charger was out of service due to a faulty rheostat. After the l fire and loss of the "A" M-G charger, the licensee had to consider several options to l restore a power supply to the associated "A" distribution bus. Although the "A" )

bus is not NSR and is not heavily loaded during normal power operations, some I important loads (e.g some control room annunciator panels) are supplied from that I bus, whose loss could impact plant operation l The licensee performed an engineering evaluation for the theostat from the "A" M-G charger (not NSR) and upgraded it's classification to NSR. It was installed on the

"B" M-G charger; and then, early on June 28,1997, the "B" M-G charger was placed in service for the "B" battery and the static charger was placed in service for the "A" batter On the day prior to the failure of the "A" M-G charger, maintenance personnel performed corrective maintenance (Job Order 515160) to instell new brushes on the generator. The licensee's initialinvestigation determined that the maintanance work did not cause the charger failure based upon the location of the damage (generator windings). However, a formal root cause analysis has not yet been initiated to positively determine the factors that contributed to the failure. The licensee plans to send the unit out for failure analysi By the end of the inspection, the licensee was considering several longer term options for restoring a normal "A" battery charger so that sufficient backup charging capability would be available in the event of arother failure. The options included replacing the failed M-G charger with a new M-G set or refurbishing the j existing unit. Another option included removing the failed M-G charger and installing a static charger in its place. These options would require significant time to complete (over a month). Therefore, for the interim, the licensee plans to process a temporary moditication to provide prompt backup charging capability to the "A" battery by installing a small charger and routing cable that could be

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connected to the "A" battery. This temporary modification would allow extended operation of the "A" battery in the event the "B" M-G charger fails, which would require transferring the static charger from the "A" to the "B" battery bu !

The inspector monitored the licensee's efforts, including those in response to the fire and the subsequent maintenance, operations, and engineering activities. The licensee's efforts were appropriate and demonstrated an acceptable safety perspectiv Conclusions The inspector concluded that the licensee respnded quickly and appropriately to a failure and fire at the "A" M-G bnuery charger. Their followup activities were  ;

continuing at the end of the inupection period and were properly focused on promptly restoring redunda.7t charging sources to the 125 Vdc syste !

02 Operational Status of Facilities and Equipment 0 Confiauration Control l l Insoect;on Scoce (71707) I

i The inspector routinely toured accessible plant areas to independently verify system lineups, equipment condition, and evaluate operator awareness of plant statu Observations and Findinas

Plant personnel maintained equipment in generally good condition. Operations I insured proper alignment of safety related components. In general, operations demonstrated effective control concerning equipment availability and operabilit In two minor instances, operators did not adequately maintain configuration contro ]

On June 30,1997, the inspector identified that operators inadvertently placed an information tag on valve V-9-7 (fire protection system post indicating valve) vice V- i 9-13 as intended. Operators originally hung the tags on May 22,1997, to inform  !

potential users that fire water flushing was in progress and shutting of the valve could render the fire suppression system inoperable. On June 30, operators verified that the fire water flush job order no longer required use of the information tags and removed all applicable tag On July 3,1997, the inspector observed that operators maintained valve V-44-230 (breathing air manifold isolation valve) danger tagged open since July 22,199 Operators originally tagged the valve open in accordance with station procedure 334.1. " Joy Air Compressor / Breathing Air System." Prior to securing the air

compressor, procedure 334.1 step 7.6.3 requires operators to remove all equipment

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control tags. Since July 1996, operators have started and stopped the joy air compressor numerous times, however, they maintained valve V-44-230 tagged open continuously. On July 3,1997, operators restored V-44-230 to its normal (closed) configuration in response to the inspector's question The inspector noted that these minor configuration control lapses resulted in no safety consequence. Guidance covered in procedure 334.1 is not a regulated activity and as such does not constitute a violation of technical specification 6. However, inspectors documented operator configuration control deficiencies in recent inspection reports (97-01,97-02) and remain concerned with operators'

inattention to detail in this are In addition, operators did not document the above configuration control deficiencies via their corrective action process (deviation report). Conclusions In general, operators demonstrated effective control of safety related system alignments, and maintained an awareness of equipment status. Operators did not maintain adequate configuration control in two minor instances. Although no safety consequence resulted, attention to detail relative to configuration control was an operator weaknes Operator Knowledge and Performance 04.1 Inadvertent Start of Wrona Emeraency Diesel Generator (EDG) Durina Concurrent l

EDG Maintenance and Testina Activities 1 Insoection Scoce (71707,61726. 62707) l On May 31,1997, a reactor operator inadvertently started the wrong emergency diesel generator (EDG) during post-maintenance testing activities. The inspector interviewed the reactor operator (RO) and senior reactor operator (SRO) involved with the control room activities. The inspector reviewed EDG response to the inadvertent start and subsequent shutdown, and reviewed the licensee's correctM actions following the error, Observations and Findinas During the operations shift, an RO was coordinating the test and troubleshooting activities associated with the EDG-1 from the control room. EDG-1 was inoperable at the time. The operator was using system procedure 341, "EDG Operation," and

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surveillance procedure 636.3.004, "EDG Load Test," to perform and monitor the l

EDG-1 activities. In addition, the RO was involved in processing system outage

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paperwork related to the EDG-1 ongoing maintenance.

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EDG-1 was started locally at 1:45 a.m. to setup a new governor. It was secured at 1:55 a.m. to add oil to the governor. EDG-1 was idle started at 2:30 a.m. to complete the governor setup and was taken offline at 3:10 a.m. As part of the normal adjustment evolution, EDG-1 was then automatically started at 3:28 a.m. for further monitoring of the new governor response. It was secured at 4:05 EDG-1 had been inoperable since May 29,1997 (12:00 p.m.). The associated technical specification (TS) allows one EDG to be inoperable for a period not to exceed seven days. In addition, TS 3.7 requires that the other EDG (EDG-2 in this case) shall be operated at least one hour every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> until repairs are complete EDG-2 was successfully tested as per this requirement (started at 4:50 a.m., and taken off-line at 6:01 a.m.) on May 30. EDG-2 was started at 4:20 a.m. on May 31 to meet the same requirement. The operators indicated to the inspector that EDG-2

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was operated for one hour, however, a log entry was not made to indicate the time l the EDG was taken off-line. EDG-2 testing was completed at about 5:30 a.m.

l Later in the shift, the same RO who had been testing both EDG-1 and EDG-2 for different purposes, intended to initiate a load test for EDG-1 following governor adjustment. However, he initiated a start to EDG-2 in error. The RO p! aced the control switch to stop and EDG-2 timed out to a stopped condition as per design.

l The licensee initiated several efforts in evaluating this event. The inspector l independently reviewed the circumstances leading up to the error. The inspector l found that there were several causes. The same RO was used to perfoim multiple but related tasks simultaneously. He was in the process of reviewing and closing-out the surveillance test paperwork for EDG-2 when he intended to start EDG-1. He

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was also involved in paperwork associated with system outage activities for EDG-1.

l The RO also failed to implement proper self-checking actions. Also, a separate control room RO, who was informally implementing a peer review of the activities, l left the control room to respond to a separate issue. Finally, the control room supervisor failed to ensure that the control room activities were consistent with operations management's expectations with respect to control of evolution i

The licensee also conducted a separate management review of this event to l understand the details leading to the error so that adequate corrective actions could ;

be identified. Several of the operators involved were temporarily removed from shift I licensed duties so that effective remediation could be accomplished.

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The control room operators failed to implement adequate self-checking techniques and supervisory oversight of control room activities was ineffective. As a result, a licensed reactor operator unintentionally started the wrong emergency diesel generator. This error indicates continued weakness in human performance and warrants close management attention.

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04.2 Mis-positioned Control Rod Durina Testina Due to Personnel Error Insoection Scope (71707,40500)

On June 22,1997, a licensed reactor operator (RO) inadvertently moved a control i rod in the wrong direction during surveillance testing. The inspector reviewed the I details surrounding the error, reviewed logs and procedures, and reviewed the licensee's self-assessment of the even Observations and Findinas l l

The control room operators were performing the weekly control rod drive (CRD)

exercise surveillance test via procedure 617.4.002, "CRD Exercise and Flow Test."

The licensee's reactivity management procedure, No.106.11, did not require either a pre-job brief by the senior reactor operator (SRO) or verbalizing (and acknowledgement) the intended actions by the RO for this particular test. However, due to recent performance problems, including those related to reactivity ,

management, operations management expected all shifts to implement these l requirements for this activity. Procedure 106.11 was being reviewed for revision to include these expectations. During the testing on June 22, the SRO did not l conduct a pre-brief to discuss management's expectations, and the operators did not verbalize their action During the test, control rod 38-23 was being exercised from its fully withdrawn position (48). The operator successfully moved the control rod from position 48 to position 46. However, when he attempted to return (withdraw) the control rod back to position 48, the operator inadvertently inserted the control rod one notch to position 44. Since the control rod was moved one notch beyond its intended position, operations supervision declared the control rod to be mis-positioned. Core engineering and the shift technical advisor were informed of the mispositioning, and the control rod was subsequently restored to position 4 In response to this event, the licensee conducted a detailed review, which was led by the group shift supervisor. The preliminary results indicated that the root cause for this event was a failure to properly self-check. Three control room operators (two ROs and one SRO) were removed from licensed duties and placed in an upgrade program to improve self-checking techniques and ensure awareness of relevant management expectation The inspector found the licensee's followup and response actions to be acceptabl The safety implications for this event were minimal, however, the continuing human performance problems that have been occurring during routine activities remain a concern, and was the subject of a management meeting with GPUN and the NRC on l

July 11,1997.

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7 Conclusions The licensee's review of this performance error was acceptable. The immediate corrective actions were appropriate to the circumstances, however, additional attention continues to be warranted to minimize these types of human performance error '

05 Operator Training and Qualification 05.1 Licensed Operator Reaualification Proaram Evaluation Insoection Scoce (71001) ,

I The inspectors reviewed the sample plan, written exam and operating exam given J during the on site inspection week of June 16,1997, and also reviewed written ;

exams administered in prior weeks. The inspectors compared the sample plan, written examination, job performance measures (JPM) and the simulator scenarios that were administered during the week of the inspection to the guidance contained in NUREG 1021, " Operator Licensing Examiner Standards," and the Oyster Creek procedure The inspector reviewed prior requalification exam results and assessed the effectiveness of the remediation program for those individuals who failed the ,

requalification exam. The inspector also interviewed operators and training staff to i assess the operator feedback process and responsivenet. of training to operator identified concern The irispector reviewed a sample of the licensed operators' medical records to determine whether the medical officer was complying with the requirement of performing biennial physicals and whether the operators were complying with special license conditions.

I Observations and Findinas Samole Plan l

The sample plan used by Oyster Creek to construct the biennial written exam provided the necessary guidance to ensure that subjects taught during the two year period were appropriately examined as defined in the Oyster Creek administrative l

procedures. However, the Oyster Creek administrative procedures did not consider

including in the examination important subjects not taught in the two year cycle as recommended in NUREG 1021, The training staff indicated that they would consider adding this feature in the future.

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! 8 Written i The written exam, especially the static portion, was a very good exam. The level of l

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difficulty of the questions was generally at the comprehension and analysis leve The inspector noted and discussed with the Oyster Creek training staff some improvements that could be made in question construction to improve the distractor's link to the stem of the question and to avoid double jeopardy question After comparing the June 16,1997, written exam to prior week exams, the inspector noted that the June 16,1997, written exam did not meet Oyster Creek expectations for exam overlap restrictions. Oyster Creek expected that 40% of the exam would be different from week to week. The RO and SRO examination only had 13-18% differences from the prior week exam. The overlap restriction exists to avoid exam compromise and retain exam validity. The inspector did not consider I that exam validity had been diminished for several reasons. The first was that Oyster Creek also used security agreements for the operators and the evaluators frequently cautioned the operators not to talk to other operators regarding the exam activities. This was observed by the inspector as well as identified during the operator interviews conducted. In addition, the performanc.s .n the written exam i for the week of June 16,1997 was significantly worse than p.br weeks. Three of

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the nine operators failed the exam and average grades (87.5 for SROs and 80 for ROs) were at least 5 points lower than the prior week exam. Performance on the new questions, not previously seen, was at the 95% success leve Oyster Creek reviewed their exam development process and determined that overlap problems would also occur in subsequent week exams. Oyster Creek determined that the Oyster Creek exam team had not identified sufficient questions to be used in the different versions of the exam developed according to the Oyster Creek guidelines. For the Oyster Creek process, a minimum of 104 unique questions were needed to be used whereas the SRO/RO exam only used 77/80 unique question Contributing to this was use of the same static simulator setup and question set for all exams, in addition, the Oyster Creek process did not use a checklist to verify that the each exam met the Oyster Creek procedural expectation To address the exams planned for subsequent weeks, Oyster Creek took actions to develop additional questions to be used in the exams and eiso develop a new static simulator setup and questions. For the exam week written, Oyster Creek determined that the exam results were valid, but were also planning to administer an additional comprehensive exam to this crew later in the year to confirm this determinatio Simulator l The scenario sets were well defined and were acceptable in scope for operator evaluation. Sufficient simulator scenarios were identified week to week to assure j exam integrity. The inspectors observed the simulator portion of the operating exams given to one operating crew. The crew (3 SROs and 6 ROs) was examined in two groups of 2 SROs,1 non-licensed STA (shift technical advisor), and 3 RO _______- ____________ _____

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Since the shift supervisor and STA were common to both groups, four different scenarios were given. A critique of the simulator exam was performed by managers from training and operations. Evaluations were performed for each individual and the crew. No failures were identified in the simulator exams during the time the inspectors observed performance. The Oyster Creek evaluations of the operators performance were effective and consistent with the inspector's evaluation Job Performance Measures (JPM)

All nine operators were administered the same five JPMs. The five JPMs concerned relevant operator task items. Four of the five JPMs were of the appropriate difficulty to test the competence of the operators. One JPM only required the operator to find a valve in the plant and close it. This JPM had little discriminatory value. Sufficient JPMs were identified week to week to assure exam integrit The Oyster Creek evaluators used proper techniques when administering the job performance measures (JPM). One operator failed the JPM portion of the exam while the inspectors were observing the examination process and two other operators failed one JPM but passed the JPM portion of the examinatio During the Wi;.-l administration of a JPM, which locally operated the emergency diesel me to , the operator performing the JPM opened the local procedure copy and nc N;sd that a JPM initiating cue sheet, similar to that passed out during the examinenou, was with the procedure and gave it to the evaluator. After the operator completed the JPM, which the operator performed unsuccessfully, the evaluator contacted training management. After training management intervention, Oyster Creek considered this to be a potential compromise of examination security and substituted another JPM, the single valve operation JPM described abov Oyster Creek subsequently administered the operator, and other operators not yet examined, the substituted JPM but still counted the JPM failure on the emergency diesel generator task. Upon investigation, the found cue sheet was determined to be an earlier revision of the JPM which may have been inadvertently left during the JPM validation process. The inspectors determined that the evaluators appropriately conducted JPMs. The specific evaluator and the training management involved with the potentially compromised JPM acted appropriately and conservatively to maintain the exam's integrit Review of Prior Exam Results and Remedial Proaram Effectiveness (IFl 50-219/97- 1

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The prior Oyster Creek requalification exam failures were as follows:

In 1995 three operator failed the written, two operators failed the JPMs and three operators failed the simulato I

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in 1996 a written exam was not given and no operators failed the JPM but five operators failed the simulato In 1997 through June 20,1997 with about half of the operators examined, four operators failed the written and three operators (one of which also failed the written) failed the JPM The requalification exam history for those six individuals who failed the 1997 indicated that two operators also failed in both 1995 and 1996, two operators also failed in 1995, one operator marginally passed prior requalification exams and was a multiple repeat f ailure in the requalification cycle weekly quizzes, and one operator was licenred in 1996 and this was his first requalification exa The six operators who failed the 1997 requalification examination have been removed from licensed duties. A remediation program had not been developed for these individuals as of June 20,1997. Based on discussions with the training staff, past remediation programs only addressed those weaknesses associated with the portion of the exam that was failed. Oyster Creek did not consider the other weaknesses for that individual identified during the requalification training cycl Oyster Creek also had not performed a root cause determination to determine why these individuals consistently failed their requalification exams. As a result, the inspector was concerned about the effectiveness of the requalification program's remediation aspects and its ability to maintain acceptable performance. The operator training supervisor agreed to further review and fully evaluate this concer An inspector follow up item will be opened to review the facility's evaluation of remediation program effectiveness for these individuals. (Inspector Follow-up Item 50-219/97-04-01)

The inspector further noted that two of the operators that failed in 1995,1996 and 1997 were staff licenses. A review of their training history indicated a large percentage of their training was performed as makeup training. The records indicated that they completed all of the required requalification program training but they did not complete a large percentage of their training within the scheduled requalification cycle and made special arrangements with training. This placed an additional burden of the training staff and may have contributed to the poor performance for these two individual Operator Fer"lback Operator feedback was effectively tracked and the operators were informed about the disposition of their comments. Through interviews, the inspectors determined that operators were generally satisfied with their training. However, the transition from a six to five shift rotation has resulted in approximately six iewer training days and occasional large gaps between training weeks. The operators interviewed were concerned about the decrease and gaps between training weeks combined with the increased level of difficulty of the exam. The Oyster Creek training staff was developing a new training schedule for the next requalification cycle to address the operators' concerns on the training schedule.

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f Some operators noted that Oyster Creek had not provided practice static exams or training using a static simulator setup during the requalification exam cycle. Thus, newly licensed operators were unneces9srily stressed by first experiencing a static written exam during the exam wee Medical Records The medical records for nine operators were reviewed, which indicated that the

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medical officer met the requirement of 10 CFR 55.21 to examine the operators l

every two years. The records also indicated that operators were complying with j speciallicense conditions. For example, one operator was precluded from standing solo watches due to an olfactory condition that limited his sense of smel Conclusions )

The Oyster Creek requalification exam for licensed operators was a very good exam with effective performance evaluation that appropriately identified those operators that need remediation. Operator performance was generally good. However, some individuals failed the written and walkthrough parts of the exam, and inspector review determined that some of these individuals have had repetitive failures over a

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period of years. These recurrent requalification exam failures appeared to indicate

! an ineffective long term remediation process and the associated inability to maintain proficiency in some areas. Training management agreed to fully evaluate this concern and address it, and an open item was established to assess the effectiveness in this area following the facility review.

The written exam administered the week of June 16,1997, did not meet all of the l Oyster Creek expectations regarding week to week exam overlap, and this could ( diminish the validity of the exam long term. Exam integrity was maintained during l l the requalification exam proces I

! i I Oyster Creek staff ensured the medical fitness of and compliance with the medical I i requirements for the operator ;

08 Miscellaneous Operations issues 0 Closed (IFl 50-219/96-03-04): This item related to the differences between the simulator and plant regarding reactor vesse;levelinstrumentation indicatio Following startup after refueling outaga 16R, Oyster Creek staff obtained actual plant response data for the specific levelinstrumentation and have modified the l

simulator SIMPROB file to agree with the plant. Operator interviews provided l additional information to indicate that the simulator and plant agree. This item is close ,

ll. Maintenance (61726,62707,90712. 92902)

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M1 Conduct of Maintenance

l M1.1 Maintenance Act;vities l Inspection Scoce (62707)

The inspectors observed selected maintenance activities on both safety-related and non-safety-related equipment to ascertain that the licensee conducted these j activities in accordance with approved procedures, Technical Specifications, and ;

appropriate industrial codes and standards. The inspectors observed all cr portions of the following job orders (JO):

• JO 515565 Install Emergency Service Water System i Vent Connectio I

• JO 516514 Emergency Diesel Generator-1 Speed Changer Module Replacement

• JO 516514 Emergency Diesel Generator-1 Governor Replacement.

l Observations and Findinas The inspectors concluded that the above activities had been approved for 1 l performance and were conducted in accordance with approved job orders and i

! applicable technical manuals and instructions. Personnel performing the activities l were knowledgeable of the activities being performed and were observing appropriate safety precautions and radiological practice M1.2 Surveillance Activities 1 Insoection Scope (61726)

The inspectors performed technical procedure reviews, witnessed in-progress surveillance testing, and reviewed completed surveillance packages. They verified that the surveillance tests were performed in accordance with Technical Specifications, approved procedures, and NRC regulations. The inspectors reviewed all or portions of the following surveillance tests:

• 617.4.002 " Control Rod Drive Exercise & Flow Test" l

• 636.4.003 " Diesel Generator Load Test"

• 609.4.001 " Isolation Condenser Valve Operability and in-Service Test"

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13 l Observations and Findinas A properly approved procedure was in use, approval was obtained and prerequisites were satisfied prior to beginning the test. Surveillance test instrumentation was l properly calibrated and used, radiological practices were adequate, technical

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specifications were satisfied, and personnel performing the tests were qualified and knowledgeable about the surveillance test procedur M1.3 Maintenance and Surveillance Activities Conclusions The maintenance and surveillance activities observed by the inspectors were conducted safely and in accordance with station procedure M1.4 Non-Outaae Corrective Maintenance Backloa Review Insoection Scoce (62707)

The inspector reviewed the non-outage corrective maintenance job order backlog to determine whether identified equipment discrepancies were being corrected in a ,

timely manner. Overall equipment / system availability was also reviewed to evaluate l whether identified equipment discrepancies were being corrected prior to !

degradation which could subsequently result in forced equipment / system outage The inspector reviewed job order backlog records, management trending documents, maintenance rule equipment performance trending documents, and the below listed procedures:

• 105, " Conduct of Maintenance", Rev. 37 e 2000-ADM-3022.01, "On-Line Maintenance Risk Management", Rev. 3 l e 2400-ADM-1220.08, " Job Order", Rev. 4 1 Observations and Findinas Backloa Trendina Maintenance management tracks non-outage corrective maintenance job order (CMJO) backlog in two separate components. Workable backlog is defined as CMJOs which are fully planned with parts verified available and assigned for wor Non-workable backlog is defined as identified equipment deficiencies which still need parts, planning, or procedures prior to releasing the CMJO to be worke Together, these two categories equal the total non-outage CMJO backlog. Based on external audits, non-outage CMJO backlog was redefined in October 1996 to include additional work categories which affect plant operation. Categories added included fire protection equipment, motor operated valve testing, plant modifications, and engineering support. The inspector determined that the revised backlog definition and trending matrix provided meaningful information for management's maintenance program assessment.

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The total non-outage CMJO backlog was 915 at the end of October 1996. This was reduced to 772 items (363 workable CMJOs and 409 non-workable [ planning)

CMJOs) at the end of May 1997. This backlog reduction was notable considering

! that several maintenance personnel were loaned to another utility for two months in l early 1997. Based on cunent resources, the existing workable CMJO backlog represents approximately 14 weeks of work in addition to the 409 unplanned CMJOs. Based on interviews and document reviews, the inspector determined that the licensee had more successfully focused resourcas to perform scheduled CMJOs

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with less resources diverted to emergent wor Three actions which strengthened schedule control were (1) only the Operations Shift Supervisor or operations management has authority to authorize work which has not been formally scheduled two weeks in advance, (2) causes for schedule deviations are identified and discussed in weekly management meetings for corrective action and are trended in quarterly reports, and (3) A fix-it-now maintenance team was established in May 1997. The two most recent Maintenance Schedule Adherence Quarterly Trend Reports indicated that schedule adherence has improved from 79% overall to 86% overall. The inspector determined that improved schedule adherence and related work efficiencies have directly reduced the non-outage CMJO backlo Backloa Content and Prioritization The inspector reviewed the non-outage CMJO backlog and determined tnd work was being completed in a timely manner. System engineers were heavily involved, and operations department concurrence received, in determining work priority and selecting job orders to be performed during planned system outage windows as described in station procedures. The inspector reviewed maintenance rule system performance data for all risk significant systems and concluded that the existing maintenance backlog was not adversely degrading system performance. While several systems remain in the (a)(1) category as per 10 CFR 50.65, the performance trends are generally positive and emergent corrective maintenance on risk significant systems has been reduced over the past 12 month c. Conclusions The inspector determined that non-outage CMJO backlog trending matrix provided meaningful information for maintenance program assessment. Total backlog was reduced from 915 in October 1996 to 772 in May 1997. Improved work efficiencies due to better schedule adherence, trending analysis, and establishment of a fix-it-now team directly reduced the non-outage CMJO backlog. Backlog work was generally completed in a timely manner. The existing backlog did not adversely degrade risk significant systems and emergent corrective maintenance on these

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Ill. Enaineerina (37551, 40500, 71707, 90712, 92903)

I E1 Conduct of Engineering E1.1 Main Steam Line Pressure Switch Actuations Durina Power Operations

! Inspection Scope (37551. 71707) l The inspector reviewed the licensea's actions in response to multiple momentary

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relay actuations associated with the main steam line isolation circuitry. The inspector reviewed control roorn computer alarm indications and local pressure switch configuration and status. In addition, the inspector interviewed engineering ;

personnel and reviewed associated engineering evaluations that were developed to

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troubleshoot and monitor the unexplained momentary relay actuation Observations and Findinas l Each of the two main steam lines has two low pressure switches (RE23A through

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D) that provide input to the main steamline isolation circuitry (one out of two twice logic) through relays 1K117 and 1K118 (for RE23A and RE23C) and relays 2K117 i and 2K118 (for RE23B and RE23D). In December 1996, all four pressure switcr.as were found to be below the technical specification required setpoints (See NFiO Inspection 50-219/96-12). The licensee attributed the drift of all four pressure switches to sensitivity to environmental conditions (humidity), which was based on industry experience and in-plant monitoring. Then, on March 28,1997, the licensee i replaced the pressure switches with new ones of a slightly different design. The

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micro-switches within the new pressure switches are hermetically sealed in order to prevent humidity-induced problems.

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Since March 1997, control room operators continued to observe momentary

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actuations of the main steam line isolation circuitry. They typically heard relay chatter in the control room panels and received an associated plant computer alarm display, which immediately cleared. The control room overhead annunciators have not usually actuated in conjunction with the relay chatter (due to the extremely

, short duration of the signal), however, some momentary alarms have occurred and

cleared without operator action. Engineering processed temporary modifications to install pressure transmitters upstream of the pressure swiches, pressure recorders, and diagnostic instrumentation across the pressure switch relay contacts.

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Engineering believed that there was some type of shock wave phenomenon occurring within the main steam line pressure sensing lines. They evaluated ambient temperature effects to determine if flashing was occurring within the sensing lines. Then they entered the condenser bay and installed insulation for the accessible portions of the sensing lines, however, significant results were not achieved. Further non-intrusive vibration testing and analysis confirmed the presence of process fluctuations in the sensing line _

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Engineering continued their troubleshooting activities through the end of the inspection period. Due to the potential risk with getting a momentary relay actuation (and corresponding steam line isolation signal) in the other RPS channel concurren; with a surveillance test that takes one pressure switch out of service for several minutes, management postponed performance of the surveillance test pending further system evaluation. The technical specification required due date for the surveillance tests is July 27,1997. The Operations Director stated that operators would perform a controlled shutdown of the unit rather than risk a reactor scram during a main steam isolation surveillance test, if the intermittent relay l actuations continued through July 24,199 '

l Conclusions Engineering provided substantial troubleshooting and evaluation efforts related to the main steam line pressure switches. Station management provided strong i oversight and a good safety focus. However, continued aggressive actions are l necessary to identify the root cause(s) and corrective actions associated with the '

spurious switch actuations due to the risk and consequences (main steam line ,

isolation and scram) of coincident actuations of redundant channel !

! l E8 Miscellaneous Engineering issues l l E8.1 (Ocen) Unresolved item 50-219/97-03-02): Emergency diesel generator (EDG) {

degraded performance identif;ed during surveillance testing. Part of this open item was related to identifying and correcting the cause(s) for lower than normal loading !

during surveillance testing. EDG-1 did not automatically reach its expected load of '

between 2700 and 2800 KW. In addition, during some of the tests, that load range !

L could not be reached even in manual load control (transfer mode). However, the minimum load required as per the procedure (2600 KW) and as pu design basis (2335 KW) was achieved during each tes l On May 29,1997, the licensee implemented a troubleshooting action plan to j identify the erratic loading problems. A recorder was used to monitor several electrical signals to observe the EDG response to load demand signals. The troubleshooting showed that the Auto Power Load Control (APTL), which controls I load while in peaking mode, could not increase load above 2600 KW. While i l changing the governor load limit knob as part of the action plan, the overspeed trip

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limit switch actuated, causing a trip of the EDG. The trip was due to setpoint drift of the electrical switch, which is bypassed in the emergency mode of EDG l operation, and it was subsequently adjusted. However, the EDG trip prevented the l personnel from completing the troubleshooting action plan at that time.

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The licensee concluded from their troubleshooting that the APTL apoeared to be functioning properly and that there was a problem within the governor. The licensee noted that the speed control dial on the existing governor was very loose, and they suspected that the dial clutch had allowed the mechanical speed setting to be reduced, resulting in the 2600 KW load limitation. The licensee installed a new i

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governor and it was setup with support from a vendor technician. After the final governor adjustments, the EDG was tested and it properly loaded to 2750 KW, where load was maintained during the one hour run. EDG-1 was declared operable on May 31,199 EDG-1 was successfully tested on June 9,1997, however, during the subsequent test on June 23,1997, the load again failed to maintain 2600 KW for one hou The operators promptly declared the EDG inoperable and entered the seven day (in any 30-day period) action requirement of technical specification (TS) 3.7. Since this same EDG was inoperable nearly two days on May 29-31 EDG, the licensee determined that the time remaining on the seven day time frame was five days and four hours. Engineering, maintenance and operations then initiated further troubleshooting activities. A consultant specializing in EDG engines was brought onsite to support inspection and repair activities. The licensee checked the fuel rack and governor for binding. Some binding was identified with the fuel rack position pointer and the governor actuator body. The pointer was moved to eliminate the binding. A subsequent EDG start, however, it again loaded to a lower than expected value.

. With EDG-1 operating, the licensee continued their troubleshooting activities. They found that the governor responded (voltage changes) to decreases to the APTL load j sharing lines. However, the governor did not respond to increases to the APTL load I sharing lines. These results indicated a problem within the 2301 A Load Sharing and Speed Control circuitry. Accordingly, the licensee replaced the 2301 A module, set i

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it up, and satisfactorily tested EDG-1. The EDG was declared operable on June 24, 1997. To confirm the effectiveness of the licensee's actions, they placed EDG-1 on an accelerated testing interval (daily, for three days). The results were acceptabl The licensee postulated several possible causes for the 2301 A module and governor problems. They plan to send both units to vendors for root cause analysi The inspector determined that the licensee's actions following the June 23 failure l

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were adequate. It was not clear, however, whether there was more than one problem that accounted for the erratic loading problems. The results of the root cause analyses are necessarv to determine the effectiveness of the licensee's troubleshootirg and corrective actions. The ability of the EDG to perform its required safety function during the period May 31 - June 23,1997, remains an unresolved item pending the results of the above root cause analyses and review of surveillance procedure-related issue E8.2 (Closed) Licensee Event Report 97-06: Reactor Shutdown Required by Control Rod 5% Scram Times Due to General Equipment Problem. This report documented performance problems with the scram solenoid pilot valves (SSPV) due to diaphragm material deficiencies. This problem has previously been identified as a generic industry issue. A special test program for a portion of the control rods identified the presence of this problem at Oyster Creek. This issue is discussed in detailin NRC Inspection report 50-219/97-03. The licensee's corrective actions were , acceptable. This LER is close .

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IV. Plant Support (71707,71750,92904)

l R1 Radiological Protection and Chemistry Controls l

R General Observations During entry to and exit from the radio!ogically controlled area (RCA), the inspectors verified that proper warning signs were posted, personnel entering were wearing i proper dosimetry, personnel and materials leaving were properly monitored for

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radioactive contamination, and monitoring instruments were functional and in l l calibration. During periodic plant tours, the inspectors verified that posted extended l Radiation Work Permits (RWPs) and survey status boards were current and l accurate. They observed activities in the RCA and verified that personnel were i complying with the requirements of applicable RWPs, and that workers were aware I of the radiological conditions in the are !

l R1.2 Radwaste Processina Systems and Transoortation of Radioactive Materials Inspection Scope (86750 and Tl 2515/133)

The inspector reviewed the liquid and solid radwaste processing system and the program for transporting radioactive materials. Additionally, the inspector reviewed the licensee's program as it relates to the implementation of the revisions to Title l 49, Code of Federal Regulations (49 CFR) for the transportation of radioactive i materials. The inspection was accomplished by a review of plant documents and '

procedures, interviews with personnel and walkdowns of the related system ;

I Observations and Findinas The inspector reviewed the licensee's Updated Final Safety Analysis Report (UFSAR) and procedures related to the radwaste and transportation program. In general, the UFSAR description of the liquid and solid radwaste systems (Chapters 11.2 and 11.4, respectively) were determined to accurately reflect current plant practices and equipment, with only minimal references to abandon in place equipment. The inspector discussed with licensee management the status of the two radwaste evaporators and their associated concentrates tanks, and was informed that the "A" evaporator was kept in a standby mode, while the "B" evaporator was abandoned in place. The need for the "A" evaporator was highlighted during this inspection when a seal leak in the service water system released salt water into the floor drain system. Its processing entailed the start-up of the "A" evaporator to process this liquid, rather than the sacrifice of resin beds, which would have resulted in a significant increase in radwaste generation.

I The inspector reviewed plant procedures related to the radwaste processing and radioactive material shipping program. Included in the procedures reviewed were three of the processing procedures which make up the Process Control Program

(PCP). These procedures, with one exception noted below, were determined to accurately reflect current plant practices and to allow for the proper operation of the

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l 19 solid radwaste processing systems. In one instance, the inspector determined that a procedural inadequacy contributed to a spill of radioactive liquid in the New Radwaste Building truck bay on June 4,1997. Specifically, paragraph 8.10.17 of procedure 352.0, utilized for the transfer and dewatering of spent resin failed to include a pre-operational pressure test of the dewatering hoses. The procedure i does require such a test of the transfer hoses from the spent resin tank. It was the dewatering line which leaked on June 4,1997 and led to the truck bay contamination. The licensee indicated that a change to this procedure would be forthcoming to address this procedural inadequacy. Additionally the inspector identified that the copy of procedure 351.31 maintained as a controlled copy by the radwaste shipping staff was out-of-date. Upon notification, the radwaste shipping

! staff obtained a current copy of this procedure and initiated an investigation as to why, when a new revision to this procedure was issued in May 1997, they did not receive a cop The inspector reviewed the shipping records for seven radioactive material and radwaste shipments made by the licensee in 1996 and 1997. Shipments reviewed ;

included waste for burial (spent resins and solidified filter sludge), dry active waste (DAW) for processing, radioactive material samples and contaminated laundry. All shipments reviewed were determined to be in compliance with Titles 10 and 49, Code of Federal Regulations. Also, on June 3,1997, the inspector observed the ,

loading of a spent resin liner into an NRC licensed shipping cask, and the l preparation of this material for shipment to the Barnwell Low-Level Radioactive Waste Disposal Facility. This was the first shipment of radioactive waste for burial made by the licensee since late 1996. In the interim, radwaste liners were being stored in the licensee's Low-Lc ret Radwaste Storage Facility (LLRWSF). During this activity, the inspector identified that the licensee failed to secure the cask's primary ,

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lid to the cask body in accordance with the Certificate of Compliance (Certificate No. 9249). Failure to utilize NRC licensed shipping casks in accordance with the Certificate of Compliance is a violation of 10 CFR 71.12. Since this discrepancy was identified prior to the shipment leaving the licensee's f acility, and since the licensee, upon notification by the inspector, took immediate actions to correct the deficiency, no violation is being issued. Of particular concern to the inspector, however, was the failure of licensee personnel to have at the work site copies of procedures for usage of this cask. In addition, a member of the licensee's Quality Verification organization was also present without a procedure or checklist, and also fmiled to identify this deficiency. This is a significant weakness in the licensee's t cogram, especially when consideration is given to the fact that this was the first shipment of waste material for burial in over seven mov.h The inspector also conducted inspections of various licensee processing facilities located in the New and Old Radwaste Buildings. Areas inspected were based on a review of health physics survey data provided to the inspector. Two areas in the New Radwaste Building were found to have resin beads on their floors. One area may be related to a spent resin tank pressurization event which had occurred in late May 1997. The source of the resin in the second area had not been determined as of the close of the specialist inspection. The inspector also did not enter the Fill Aisle in the New Radwaste Building, which in the past has been identified as a

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highly contaminated area, due to the presence of an 8 R/hr source (the ultrafiltration filter). The inspector did view the Fill Aisle through the use of four pre-installed video cameras, and informed the licensee that he would enter this area during a future inspection, when the high dose rate source had been remove In Old Radwaste, the inspector viewed a building where most of the equipment was abandoned in place, with the exception of the spent fuel pool filtration system, and two stillin-service pumps located in the large pump room. Conditions throughout this facility were poor, including large areas of high contamination and high dose rates. Since the two pumps in the large pump room are stillin service, maintenance

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activities and operations reviews of these pumps must be performed in a challenging radiological environment. While no unresolved safety questions were identified, the impact of work in this area on licensee goals for maintaining ]

occupational exposures as low as is reasonably achievable (ALARA) will be i reviewed during a future inspectio l i

The inspector reviewed the licensee's program for identifying hard to measure )

radionuclides to maintain compliance for waste classification as found in 10 CFR I 61.55. The licensee currently sends samples, including grab samples from a I recently installed sampler in the resin transfer system, for analysis on an annual I basis. Results are then reviewed by the radwaste shipping staff before being ]

incorporated into a computerized data base system for use, l l

Training for licensee staff involved in the preparation, packaging and transport of l

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radioactive materials in accordance with 49 CFR 172.700 is given on an annual basis by the radwaste shipping staff. The inspector reviewed the training materials, tests and training records associated with this program, and determined that the training met the requirements of the Department of Transportation. For personnel requiring training in accordance with NRC IE Bulletin 79-19, the licensee typically utilizes the services of a vendor. in 1996, vendor training was provided on-site to members of the radwaste shipping, radwaste operations, radiological engineering, training, Quality Verification and Quality Assurance staffs. The focus of this training was on the revised rules for transport of radioactive materials contained in 49 CF c. Conclusions The licensee has established generally effective processes and programs in the areas of radwaste processing and transportation of radioactive materials. One weakness was identified related to plant procedures, especially their utilization at the work site when preparing a package for transport. Additionally, a procedural weakness contributed to the contamination of a part of the licensee's facilit Records of shipments of radioactive materials were determined to be in compliance with all applicable regulations. The training of workers in transportation and radwaste was good.

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R7 Quality Assurance in RP&C Activities a. Insoection Scoce (86750)

The inspector reviewed audits and surveillances conducted by the licensee's and Nuclear Safety Assessment (NSA) and Quality Verification (QV) departments in the area of radwaste processing and transportation of radioactive materials.

l b. Observations and Findinas The inspector discussed the quality assurance program as it pertains to radwaste l processing and transportation of radioactive materials with quality assurance. This l discussion included a review of the licensee's most recent audit of the PCP and radwaste program conducted in 1996. The inspector noted the focus of the audit on in-plant performance, and that the scope of the audit was well beyond that required by plant technical specifications. In general, this report was determined to i be of sound technical basis, and of sufcient depth to identify both existing issues and declining trends in performance.

l The inspector also reviewed Quality Surveillance (OV) reports generated in late l 1996 and 1997. These reports were also generally well documented, although a

! noticeable difference in the scope and depth of these reviews between members of the O.V staff was evident. As noted in Section R1 above, the QV representative at the radwaste shipment on June 3,1997, was observed not to have a copy of the l plant procedures on hand, and failed to identify the error in attaching the primary

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cask lid. The inspector discussed this with the QV supervisor, who stated that this was an important issue that he was in the process of addressing. The inspector will review the adequacy of corrective actions during a future inspectio c. Conclusions The licensee's quality assurance program for radwaste and transportation, including l audits and surveillance was of generally high quality. Sufficient scope and technical depth was present to aid in the timely identification of issues and declining performance in these areas. However, a weakness in the QV process related to procedure usage was identified.

j R8.1 Miscellaneous Radioloaical & Chemistry issues l

l A discovery of a licensee operating their facility in a manner contrary to the l Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters ;

to the UFSAR description '

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the applicable portions of the UFSAR that related to the areas inspected. The inspector verified that the UFSAR wording was consistent with the observed plant

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P2 Status of Emergency Preparedness Facilities, Equipment, and Resources

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P2.1 Notification System inocerable Due to Eauioment Damaae Durina Electrical S arm Inspection Scooe (71750)

l On July 1,1997, the licensee identified that the prompt notificatire. system (sirc:.

system) was inoperable. The inspector interviewed emergencs/ preparedness personnel and reviewed the licensee's corrective actions in response to this event, including those to enhance prompt identification of a similar type failure in the l future.

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l Observations and Findinas 1 L

The computer associated with the siren is located at the Ocean County Sheriff's office. Upon the licensee's arrival to perform the bi-weekly signal test, they identified that the prompt notification system was inoperable. All 42 sirens were affected. The licensee reported this condition to the NRC as per the reporting requirements of 10 CFR 50.72.

i Based upon followup review, the licensee identified that the sirens had been inoperable since June 23,1997, when an electrical failure occurred apparently due to a lightning strike. The licensee replaced the failed components in the computer's master controller, and the system was returned to service. Within several hours of i the discovery,40 of the 42 sirens had been restored to an operable status. The two remaining inoperable sirens were restored to an operable status on the following da The master computer at the Sheriff's office performs an "autopoll" function whereby the system performs an electronic self-check every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The last autopoll was successfully performed and stored on June 2 In response to this event, the licensee was considering the addition of a backup computer that would indicate the identical display at the Oyster Creek station, redundant to the computer at the Sheriff's office. They also plan to conduct training of personnel at the Sheriff's office as related to diagnosing and reporting

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computer display anomalies in a more timely fashion.

I Conclusions j The inspector determined that the licensee's immediate response to the July 1, j 1997, discovery was appropriate. Their planned actions to prevent similar problems and to more promptly identify problems were adequate. However, the delay from June 23,1997, to July 1,1997, in identifying that all sirens were inoperable was excessive and indicated an ineffective use of an existing self-test feature of the remotely located compute l

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P3 Emergency Preparedness Procedures and Documentation l P In-Office Review of Licensee Procedure Chanoes An in-office review of revisions to the emergency plan and its implementing procedures submitted by the licensee was completed. A list of the specific revisions reviewed is identified below. Based on the licensee's determination that the changes do not decrease the overall effectiveness of the emergency plan, and that it continues to meet the standards of 10 CFR 50.47(b) and the requirements of

Appendix E to Part 50, NRC approval is not required for those change I

! Implementation of those changes will be subject to inspection in the future.

i S1 Conduct of Security and Safeguards Activities l

S1.1 General Observations (71750)

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During routine tours, access controls were verified in accordance with the Security

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Plan, security posts were properly manned, protected area gates were locked or l guarded, and isolation zones were free of obstructions. Vital area access points l were examined and verified that they were properly locked or guarded, and that l access control was in accordance with the Security Plan.

l l l V. Manaaement Meetinas l

X1 Exit Meeting Summary

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A verbal summary of preliminary findings was provided to the senior licensee management l on July 23,1997. During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspectors. No written inspection l material was provided to the licensee during the inspection. No proprietary information is included in this report.

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l 24 PARTIAL LIST OF PERSONS CONTACTED l

l Licensee (in alohabetical order)

l l G. Busch, Manager, Regulatory Aff airs l D. Croneberger, Director, Equipment Reliability l S. Levin, Director, Operations and Maintenance l K. Mulligan, Plant Operations Director l

J. Perry, Plant Maintenance Director l M. Roche, Director, Oyster Creek D. Slear, Director, Configuration Control l R. Tilton, Manager, Nuclear Safety Assessment NRC S. Pindale, Resident inspector J. Schoppy, Senior Resident inspector i

INSPECTION PROCEDURES USED i

Procedure N Title 40500 Effectiveness of Licensee Controls in identifying, Resolving, and Preventing Problems 37551 Onsite Er.gineering

61726 Surveillance Observation

62707 Maintenance Observation 71707 Plant Operations 71750 Plant Support 92700 Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities l 90712 Inoffice Review of Written Reports of Power Reactor Facilities

I 92901 Followup - Operations 92902 Followup - Maintenance i

l 92903 Followup - Engineering

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92904 Followup - Plant Support l 93702 Onsite Event Response

ITEMS OPENED, CLOSED, AND UPDATED

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ODened Number Tvoe Descriotion l

97-04-01 IFl Licensee to evaluate the operator training program's l remediation process effectiveness (05.1)

l 97-04-02 URI Degraded emergency diesel generator performance identified during surveillance testing. (E8.1)

Closed l Number Tvoe Descriotion 97-03-02 IFl Degraded emergency diesel generator performance identified during surveillance testing. (E8.1)

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! 96-03-04 IFl Differences between the simulator and plant regarding reactor vessel level instrumentation indications. (08.1)

97-06 LER Reactor Shutdown Required by Control Rod 5% Scram Times Due to Generic Equipment Problems. (E8.2)

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EMERGENCY RESPONSE PROCEDURES USED Document Document Title Revision (s)

EPIP-OC .01 Classification of Emergency Conditions 4 EPIP-OC .02 Direction of Emergency Response Emergency l Control Center (ECC) 18 EPIP-OC .03 Emergency Notification 18,19 EPIP-OC .06 Additional Assistance and Notification 17 EPIP-OC .10 Emergency Radiological Surveys Onsite 6 EPIP-OC .11 Emergency Radiological Surveys Offsite 8 EPIP-OC .12 Personnel Accountability 5

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EPIP-OC .13 Site Evacuation and Personnel Mustering

at Remote Assembly Area ;

EPlP-OC .25 Emergency Operations Facility (EOF) 16

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EPIP-OC .35 Radiological Controls Emergency Actions 10,11 EPIP-OC .40 Site Security Emergency Actions 5 EPIP-OC .41 Emergency Duty Roster Activation 4 l OEP-ACM-1319.01 Oyster Creek Emergency Preparedness Program 1,2 ,

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, OEP-ADM-1319.02 Emergency Response Facilities & Equipment l Maintenance 1 i OEP-ADM-1319.04 Prompt Notification System 1 EPIP-COM .45 Classified Emergency Termination / Recovery

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GPU Nuclear Inc. Management Meeting I

Oyster Creek Human Performance

July 11,1997  !

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AGENDA July 11,1997 Introduction Sander Levin t Director Ops and Maintenance

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Site Wide Initiatives Philip Scallon, J Manager, Safety Review

. Steps to Excellence

. Human Performance Work Group (IIPWG)

. Performance Enhancement Review Committee (PERC)

. Event Free Operations Program Operations Initiatives Kevin Mulligan Operations Director

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Maintenance Initiatives John Perry Plant Maintenance Director

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Conclusion Sander Levin .

Director Ops and Maintenance

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i SITE-WIDE i HUMAN PERFORMANCE IMPROVEMENT INITIATIVES

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1. Steps to Excellence Meetings

2. Human Performance Working Group 3. Pcrf'rmance Enhancement Review Committee 4. Event Free Operations Program

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STEPS TO EXCELLENCE MEETINGS

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e Conducted by the Site Director

. Participation by management, supervision and bargaining unit personnel j

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e Focus on human performance issues i

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t HUMAN PERFORMANCE WORKING GROUP i

e Comprised of senior station line management e Provides strategic planning function for monitoring and improving human performance e Meets at least once per quarter e Sponsors henchmarking efforts related to human performance improvement e Periodically reviews in-house operating experience

• Developed Event Free Operations program

• Reports findings and makes recommendations to Site Director

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PERFORMANCE ENHANCEMENT REVIEW COMMITTEE

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e Chaired by Site Director e Provides for senior station management review of significant human performance related events

- inciv&s participation by involved individuals and supervision e Focus on personal accountability for inappropriate behaviors e Management concurrence with event root cause and proposed corrective actions I

e Lessons learned are conveyed by HPES Eye Opener with site-wide distribution

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EVENT FREE OPERATION  !

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PLANT EVENT

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A CONSEQUENTIAL EVENT, CAUSED BY INADEQUATE IIUMAN PERFORMANCE, WIIICII RESULTS IN SIGNIFICANT ADVERSE IMPACT ON NUCLEAR OR PERSONNEL SAFETY, PLANT OPERATION, OR REGULATORY POSITIO I f

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PLANT EVENT i

CRITERIA

l Radiolonical/ Industrial Safety

- Lost Workday case

- Radiological event requiring NRC notification per 10CFR20

- Administrative' dose limits exceeded

- High Radiation Area violations

- Unmonitored release of radioactivity

- Multiple personnri contaminations from same event

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- Radioactive spiL resulting in significant spread of contamination

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Plant Operation /Eauioment Control / Maintenance /Engineerine

- Operation outside design basis

- Operation not allowed by Tech Specs

- Plant trip or significant transient j -Inadvertent criticality

- Fuel damage due to improper operation

- Unanticipated reactivity addition l - Mispositioned control rod l - Switching / Tagging error with significant potential for personnel injury or equipment damage

- Wrong train / wrong component operation, maintenance, or tagging error l - Significant equipment damage caused by mis-operation or maintenance

- Inadvertent safety system actuation

- Missed Tech Spec required surveillance

- Unplanned load reduction > 100 Mwe

- Significant deviation from administrative or procedural requirements l

R_ggplatory Consequence

- Cited NRC Notice of Violation Level III or higher

- NJPDES Violation

- INPO SOER, SEN or SER

- Cited OSHA Violation

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INITIAL GOAL

l AVERAGE > 40 DAYS BETWEEN EVENTS  !

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OYSTER CREEK PLANT OPERATIONS IIUMAN PERFORMANCE INITIATIVES l

CURRENT INITIATIVES

• Reinforced Management Expectations and Standards

Implemented Standard Industry Control Room Management Expectations and Standards I

• Enhanced Operator Training Programs i

e Provided Supervisory Skills Training

• Revised Switching and Tagging Process ,

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OYSTER CREEK PLANT OPERATIONS IIUhlAN PERFORNIANCE INITIATIVES FUTURE INITIATIVES

• Implement Event Free Operation Program

. Increase Personal Accountability

. Develop Department Specific Trend Reports

. Transfer Work Control Activities Outside Control Room

. Increase INPO Interaction and Involvement

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OYSTER CREEK PLANT MIAINTENANCE IIUNIAN PERFORMANCE INITIATIVES

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PREVIOUS INITIATIVES:

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. Identified Iluman Performance Deficiencies as an Issue

. Conducted " Stand Down Day (s)" to Focus on Iluman Performance Concepts and Programs

• Provided Training and Expectations Concerning Worker Self-Checking /I'eam-Checking  !

Concepts

"S T A R"

. Established Formal Event Categorization and Tracking Mechanisms Specific to Maintenance

. Pre-Job Preparation I

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OYSTER CREEK PLANT MAINTENANCE IIUMAN PERFORMANCE INITIATIVES CURRENT INITIATIVES .

t o Enhanced Analysis

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o Provided Resources Necessary to Determine Root Cause and Corrective Action through Interaction with Production Personnel o Summarize Monthly Maintenance Iluman Performance Related Deviation Reports and i

Assign as Required Reading to Craft PersonncI and Supervision i

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c Summarize Monthly Station Iluman Performance Related Deviation Reports for Supervision to Use in Conducting Pre-Job Briefings

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OYSTER CREEK PLANT MAINTENANCE IIUMAN PERFORMANCE INITIATIVES CURRENT INITIATIVES:

o Continued Visibility .

o Management / Craft Interface Meetings Conducted as Part of Training Cycle. Iluman Performance Trending and Performance is Standing Agenda Item o Iluman Performance Related Deviation Reports are Tracked and Trended as Rates

o Aggressive Goals IIave Been Established: i

> 1997 Goal of 1.17 Errors /10,000 Manhours Represents 25% Reduction from 1996 Experience

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OYSTER CREEK PLANT MIAINTENANCE HUhfAN PERFORhfANCE INITIATIVES CURRENT INITIATIVES:

o Applying the Data:

I o Supervision Coached on Pre-Job Briefings through "Alock" Briefing Exercises. Follow-up Done as Part of Performance Evaluation Process. Iluman Performance Included in Prc-Job Brief Checklis *

o Developed Special Training blodules Based on Trending Data i

o Work Controlling Documents (Job Orders) to Reference In-IIouse Operating Experience for Specific Components and Systems

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OYSTER CREEK PLANT MAINTENANCE IIUMAN PERFORMANCE INITIATIVES FUTURE INITIATIVES:

• Self-Assessment Addressing Effectiveress ofIluman Performance Programs in Pr sgress

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• Benchmarking ofIndustry Best Performing Plant Completed in July,1997. Data will be Incorporated into Self-Assessment Process ,

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. Orientation and Training Modules Stressing Iluman Performance Issues and Geared Toward i Temporary Outage Workforce Currently Being Developed i

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GPU NUCLEAR, IN OYSTER CREEK NUCLEAR GENERATING STATION ,

IIUMAN PERFORMANCE INITIATIVES i

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CONCLUSIONS:

• Previous Efforts llave Improved Performance, but Performance Isn't at an Acceptable Leve * Management Continues to Focus on IMPROVING PERFORMANCE e Performance Standards are Rising i

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