Text

Insp Repts 50-334/97-07 & 50-412/97-07 on 970831-1004. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support
	ML20198S649
Person / Time
Site:	Beaver Valley
Issue date:	11/07/1997
From:	; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:	;
Shared Package
ML20198S624	List: IR 05000334/1997007; ML20198S617; ML20198S635;
References
	50-334-97-07, 50-334-97-7, 50-412-97-07, 50-412-97-7, NUDOCS 9711140081
	Download: ML20198S649 (47)
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U. S. NUCLEAR REGULATORY COMMISSION REGION 1 License No DPR 66, NPF 73 Report No /97-07, 50-412/97-07 Docket No , 50-412 Licensee: Duquesne Light Company (DLC)

Post Office Box 4 Shippingport, PA 15077 Facility: Beaver Valley Power Station, Units 1 and 2 Inspection Period: August 31,1997 through October 4,1997 Inspectors: D. Kern, Senior Resident inspector F. Lyon, Resident inspector G. Dentel, Resident inspector S. Pindale, Resident inspector, Oyster Creek D. Brinkman, Senior Project Manager, NRR J. Nick, Project Engineer, DRP P. Kaufman, Emergency Response Coordinator, ORA Approved by: P. Eselgroth, Chief Projects Branch 7 9711140001 971107 PDR 0 ADOCK 05000334 PDR

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EXECUTIVE SUMMARY Beaver Valley Power Station, Units 1 & 2 NRC inspection Report 50-334/97-07 & 50 412/97-07 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support. The report covers a 5-week period of resident inspection; in addition, it includes the results of an announced Corrective Action Program inspection performed by regions' inspector Operations

The "1R12 Pre-Outage Safety Review" conducted by ISEG, Unit 1 Operations, and Outage Management Department was thorough and provided reasonable recommendations for enhancing safety posture. (Section 01.2)

The flush of the "A" boron recovery degassifier subsystem was effective in reducing radiation levels. The proper method to perform the flush was not tully understood by work planning management, operations department, and system engineering personnel. Concerns raised by operators and the inspectors were eventually addressed by the use of a temporary operating procedure for the flus (Section 01.3)

On October 2, a failed comparator circuit card caused a Unit 2 pressurizer power operated relief valve to open, inducing a plant pressure transient. Operators promptly assessed plant conditions and took action to limit the plant transien Technicians and operators closely coordinated troubleshooting and repair activitie Causal assessment was technically sound and repairs were promptly complete (Section 01.4)

Inspectors identified some programmatic weaknesses in the implementation of the Retired Equipment Program. Some equipment was red tagged as " retired in place" without recognizing that it was required for use in emergency operating procedures and abnormal operating procedures. This was an unresolved item pending completion of NRC review. (Section O3.1)

Maintenance

Maintenance and engineering personnel effectively coordinated their efforts to successfully replace the Unit 2 "C" high head safety injection pump rotos assembl (Section E2.2)

Ennineerina

The licensee was slow to initiate a formal operability determination for a degraded condition in the Unit 2 digital rod position indication (DRPI) system. However, the inspectors determined that the licensee verified that the TS for DRPI were met during this period. (Section E1.1)

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Executive Summary

Engineers properly evaluated an industry concern regarding meisture intrusion into inadequate Core Cooling Monitor (ICCM) thermocouples. The evaluation was thorough and closely integrated industry and vendor information. The infermation was clearly presented to the Nucleer 5afety Review Board which supported a timely management decision regarding proposed maintenance. The decision to continue operating with the ICCM system in its current analyzed condition was appropriat (Section E2.1)

On August 28,1997, the licensee experienced gas binding of the Unit 2 "C" high head safety injection (HHSI) pump due to inadequate venting of the chargi % line Failure to take effective corrective action to preclude repetition of gas binding events between 1993 and 1997 is an apparent violation. Two weeks after the gas binding event, the pump failed to meet TS differential pressure performance requirements and was subsequently replaced. The repeated gas binding events were the most likely cause for the pump's degraded performance. (Section E2.2)

o Licensee management's initiative to perform an in-depth team analysis of the HHSl events was good, overall. The team focused primarily on replacing the failed pump, but was only minimally effective in reviewing the majority of the issues related to causal analysis and long term corrective actions. Adequacy of the surveillance test procedure for determining functionality of the high head safety injection pumps is an unresolved item. Interim corrective actions were adequate to detect an increase in void size and growth; but, the actions were not effectively coordinated with operations. (Section E2.2)

The engineering evaluation for an unexpected start of emergency diesel generator (EDG) 1-2 during a f ast bus transfer test was reasonable based on the existing plant configuration, bus loading, and EDG undervoltage setpoints. There were no adverse safety consequences to the inadvertent EDG start, but it presented an unnecessary challenge to the EDG, Considering the long history of inadvertent Unit 1 EDG starts under certain plant conditions, the licensee has been slow to resolve the issu (Section E2.3)

The licensee f ailed to properly evaluate and approve several revisions to the station's heavy load lift program between 1983 and 1990. The Operatic,n Safety Committee review process was inconsistent and controls to retain safety evaluations for changes to approved lift paths as described in the Updated Final Safety Analysis Report were inadequate. Licensee evaluation of this issue was comprehensive and corrective actions were well focused. (Section E8.1)

Plant Suncort

Emergency Preparedness drills provided satisfactory training for the emergency response organization. Thero was a good focus on orienting new staff to their i duties and responsibilities and developing a smooth information flow path within the emergency response organization, and familiarizing staff with the communications m

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Executive Summary and assessment equipment in the emergency response facilities. The post drill f acility and controller critiques were generally thorough and there was good participation from allievels of the staff. Strengths were identified for reinforcement and weaknesses were no'ed for further evaluation and improvement. (Section P1.1)

Safety Assessment and Quality Verification e Quality Services Unit (OSU) Operations Program audit and surveillance activities were generally effective in eva'uating operations performance, identifying weaknesses, and follow-up corrective action verifications. Some exceptions were noted in that several negative NRC findings were not similarly identified through OSU activities. OSU management initiated appropriate action to ensure these findings are addressed through future surveillance and audit activities. Operations management's use of OSU for independent assessments of suspected problem areas was a strength. (Section 07.1)

e Knowledge and use (initiation) of the Condition Report (CR) system was mixe There were ir$ stances where CRs were warranted but were not initiated or were delayed, indicating that the licensee was not making full use of the CR system. CR evaluations, root cause determinations, and corrective actions were good overal Two CRs were not fully evaluated in a timely fashion, and the licensee subsequently initiated additional actions to achieve resolution. Monthly CR trending information receives attention from senior station management. (Section 07.2)

e Overall Quality Services Unit (OSU) involvement in oversight activities was good, and audits were of high quality. OSU's use of outside people (e.g. other utilities) to gain further industry perspective during the performance of audits was considered a strength. Notwithstanding, failuro to obtain NRC approval prior to shifting Procurement OC responsibilities from the QSU to the Procurement Department was a reduction in quality assurance program commitments and was a Violatio (Section 07.2)

e Self assessments were generally of good quality and were self-critical. However, the self assessment process demonstrated a weakness in that several station departments were not meeting management's expectations for adhering to established self assessment schedules. Evaluations of industry operating experience information were thorough and technically accurate. The Nuclear Safety Review Board demonstrated a strong questioning attitude. The Offsite Review Committee also functioned well. (Section 07.2)

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TABLE OF CONTENTS PAGE N EX EC UT IV E SU M M ARY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . il T ABLE O F CO NT E NTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v 1. Operations .................................................... 1 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 01.1 General Comments (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

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01.2 Unit 1 Pre Outage Safety Review (71707) . . . . . . . . . . . . . . . . . 1 01.3 Temporary Procedure Used for Flush of Degassification System . . 2 01.4 Spurious Unit 2 Pressurizer Power Operated Relief Valve Opening......................................... 3 03 Operations Procedures and Documentation ..................... 4

03.1 Retired Equipment Program ........................... 4 07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 07.1 Audits and Surveillances of Operations Department Activities . . . 6 07.2 Effectiveness of Licensee Controls in identifying, Resolving, and Preventing Problems ............................. 7 08 Miscellaneous Operations issues (90712,92700,92901) . . . . . . . . . . 16 08.1 (Closed) Licensee Event Report (LER) 50-334/97-024 . . . . . . . . 16 08.2 (Closed) LER 50 334/97-025 ......................... 16 08.3 (Closed) LER 50 3 34/9 7 016 01 . . . . . . . . . . . . . . . . . . . . . . . 16 08.4 (Closed) LER 50 3 3 4 /9 7 00 5-0 2 . . . . . . . . . . . . . . . . . . . . . . . 17 II . M aint e n a nc e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 M1 Conduct of Maintenance ................................. 17 M 1.1 Routine Maintenance Observations (62707) . . . . . . . . . . . . . . . 17 M1.2 Routine Surveillance Observations (61726) ............... 17 M2 Maintenance and Material Crndition of Facilities and E<1uipment ..... 18 M2.1 Installation of Transmitters . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 111. En g i n e e r i n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19 El Conduct of Engineering .................................. 19 E1.1 Digital Rod Position Indication, Basis for Continued Operability (37551) ................................. ...... 19 E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 20 E2.1 Potential incore Thermocouple Defect . . . . . . . . . . . . . . . . . . . 20 E2.2 Charging Pump Gas Binding . . . . . . . . . . . . . . . . . . . . . . . . . . 21 E2.3 Unexpected Diesel Start During Bus Transfer Test .......... 26 E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 E (Closed) Unresolved item 50-334 & 412/96-09-03 . . . . . . . . . . 27 I V . Pl a n t S u p p o r t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 P1 Conduct of EP Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29 P E P D rill s . . . . . . . . . . . . . . . . . . . . ................... 29 P8 Miscellaneous EP Issues (92904) ........................... 32 v

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s Table of Contents P (Closed) Unresolved item 50-334 and 412/96-05-03 ........ 32 P8.2 (Closed) Inspectic,n Follow-up item (IFI) 50-334 and 412/94-8104.......................................... 33 P8.3 (Closedi IFl 50 334 and 412/96-01-01 .................. 33 P8.4 (Closed) IFl 60-334 and 412/96-0102 .................. 34 L1 Review of FS AR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 V. M a n ag e m e nt M e et ing s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 X1 Exit M e e ting Summ a ry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35 PARTI AL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 IN SPECTIO N PROCFD'.?flES U SED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37 ITEMS OPENED, CLOSED AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38 LI ST O F A C R O N Y M S U S E D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

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. Reoort Details Swntuarv of Plant Status Unit 1 began this inspection period at 100% power. On September 27, operators began a power reduction to enter the 12th refueling outage (1R12). Following ma:n steam safety valve testing at 50% power, the unit was shutdown on September 28 and entered Mode 5 (cold shutdown). On October 4, the reactor vessel head was detensioned and Unit 1 entered Mode 6 (refueling).

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Unit 2 operated this inspection period at 100% power, l. Ooerationg 01 Conduct of Operations 01.1 General Comments (717071'

Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety-conscious; specific events and noteworthy observations are detailed m the sections belo .2 Mnit 1 Pre-Outano Safety Review (717011 Inspectors reviewed the "1R12 Pre-Outage Safety Review" (letter NDISEG:1130, dated September 2,1997) conducted by the Independent Safety Evaluation Group (ISEC., Unit 1 Operations, and Outage Management Department. The pre-outage saft y review was conducted in accordance with Nuclear Power Division AdnJnistrative Procedure (NPDAP) 8.26, Rev 4, " Shutdown Safety / Outage Management."

The safety review addressed the outage schedule and its effect on the key safety functions of decay heat removal, RCS inventory control, power availability, reactivity control, and containment control. Emphasis was placed on maximizing the operability and defense-in-depth of key safety components and systems, and recommendations were provided to enhance safety posture. In addition, " time to RCS boiling" and " time to core uncovery" were reviewed based on anticipated plant conditions throughout the outage. The parameters will be used to monitor station posture for the decay heat removal key shutdown safety function. The minimum

" time to RCS boiling" was expected to be 21 minutes during isolation of the RCS loops on September 29. The evolution was scheduled to be controlled under NPDAP 8.23, " Infrequently Performed Tests and Evolutions." Other high risk activities were also reviewed. No mid-loop or reduced inventory activities were planned with fuelin the reactor vesse ' Topical headings such a 01, M8, etc., are used in accordance with the NRC standardized reactor inspection report outline. Individual reports are not expected to address all outline topic .____ _ _______

. _ _ _ s The licensee concluded that their approach was consistent with NUMARC 91-06,

" Guidelines for iridustry Actions to Assess Shutdown Management," and that there was adequate defense in-depth for key shutdown safety functions for the 1R12 outage, inspectors assessed that the review was thorough and provided reasonable recommendations for enhancing safety postur .3 Temoorarv Procedure Used for Flush of Deaassifigign System Inspection Scope (71707)

The inspectors examined the method of flushing the "A" boron recovery degassifier subsystem. Before the flush, the inspectors performed walkdowns of the areas and questioned the system engineer, operators, and operations management. The inspectors also reviewed the following procedures:

1/2 OM-48.2.B, "Use, Approval and Distribution of Temporary Operating Procedures (TOP)", Rev. 9 2 TOP-97-08, " Flush of "A" Boron Recovery Degassifier Subsystem," Rev. 0 . Observations and_Eindinas On August 21, health phycies technicians observed increased radiation levels in the boron recovery degassifier system. Proper radiological controls were implemented upon discovery. The system engineer's initial evaluation determined that the increased radiation levels were observed after a routine refill of the mixed demineralizer resin bed. The root cause evaluation for the increased radiation levels was still underway at the end of the inspection period. The issue was documented in condition report (CR) 97145 The "A" boron recovery degassifier subsystem had been scheduled for corrective maintenance previous to the increased radiation levels. To reduce radiation levels, the system engineer developed a series of steps to perform numerous valve manipulations and attach temporary hoses in order to perform a flush of the degassifier steam heater, degassifier and spray nozzles, and the degassifier recirculation pump discharge piping and restricting orifice. After discussions with operations management and work planning, the work was to be conducted under an operational clearance and a maintenance work request (MWR). Some reactor operators and senior reactor operators raised concerns about the use of a MWR for this type of operation. The inspectors also questioned the controls associated with the MWR. Several new precautions or compensatory measures were added or considered to address operator and inspector concerns: 1) a complete walkdown/ verification of valve position for the degassifier syster,1; 2) tagging each valve to be manipulated to assure control; and,3) properly tagging the hoses with jumper tags. Operating Manual Chapter 48 specifies that, "... temporary procedures should be issued to provide guidance in unusual situations ... and to ensure orderly and uniform operations for short periods when the plant, a system, or a component of a system is performing in a manner not covered by existing

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detailed procedures." The MWR as written was providing guidance for an unusual situation for a short time period that was not covered by existing procedures. After further discussion with the inspectors regarding control of the flush activity, operations management decided that a temporary operating procedure rather than an MWR was warrante The inspectors observed that the onsite safety committee (OSC) performed a thorough rev:ew of the TOP. Of particular note, the OSC questioned the effects on operating systems, such as the primary grade water system and liquid waste line The flush was successfully completed on September 12 with a substantial drop la radiation levels, Conclusion The flush of the "A" boron recovery degassifier subsystem was effective in reducing radiation levels. The proper method to perform the flush was not fully understood by work management, operations department, and system engineering personnel. The concerns raised by the inspectors were eventually addressed by use of a temporary operating procedure for the flus .4 Sourious Unit 2 Pressurizer Power Operated Relief Valve Ooenina Inspection Scoce (71707)

On October 2,1997, a pressurizer power operated relief valve (PORV) opened unexpectedly. The inspectors reviewed the event including operator response, causal assessment, and repair to evaluate licensee response to this event. This review was performed on-site through interviews and reviews of station document Observations and Findinas At 7:20 p.m., one of three Unit 2 pressurizer PORVs (2RCS PCV455C) opened for no apparent reason. Pressurizer (PZR) pressure had been in the normal program band (approximately 2235 psig) with no indication of approaching the PORV lift setpoint of 2335 psig. The reactor cperator immediately checked RCS pressure indications, expected alarm annunciators, and PZR spray control indications and determined that an overpressure condition did not exist. The operator then placed the 2RCS-PCV455C control switch in the "close" position which resulted in valve closure. The valve reached full closure 7 seconds after it began openin Pressurizer pressure dropped to 2180 psig during the transient. Operators energized additional PZR heaters to restore pressure above 2220 psig as required by TS. The inspectors determined that operators properly assessed plant conditions and took prompt action to limit the plant transient and challenge to reactor safet Maintenance technicians reviewed station drawings, identified potential causes for the valve opening and briefed the Nuclear Shift Supervisor (NSS). Initial investigation actions to measure test voltages and verify relay position were well defined and clearly discussed with the NSS. Based on the data obtained,

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Instrumentation and Control technicians developed a work plan to evaluate a suspect f ailed comparator card and replace it,if necessary. The work plan was performed, the comparator card replaced, and the 2RCS PCV455C returned to service early on October 3. The inspectors reviewed control station drawings with technicians and system engineers and determined that identification and '

replacement of the failed comparator card were technically sound. Full review of plant response to the transient, assessment of the comparator card failure mechanism, and related plant design questions were in progress under CR 971708 at the close of the inspection period, Conclusions On October 2, a failed comparator circuit card ccused a Unit 2 PZR PORV to open inducing a plant pressure transient. Operators properly assessed plant conditions and took prompt action to limit the plant transient and challenge to reactor safot .

Technicians and operators closely communicated and coordinated troubleshooting and repair activities. Causal assesstr.ent was technically sound and repairs were promptly complete Operations Procedures and Documentation 03.1 Retired Eauinment Proaram Lnicection Scone (71707)

Inspectors reviewed the Retired Equipment Program following the licensee discovery that some equipment was tagged as " retired in placo" that was required for use in an emergency operating procedure (EOP). Qhservations and Findinas As part of the licensee's corrective actions for configuration control problems in the February March 1997 timeframe, operators reviewed and tagged out components that were no longer in use or had been abandoned-in-place. Subsequently, Nuclear Power Division Administrative Procedure (NPDAP) 8.33, " Retired Equipment Program," Rev.0, was implemented on August 15 without phasing in the components that operators had already tagged out of servic White conducting EOP training, the licensee identified that the containment iodine f ans were red-tagged as " retired in place," but the f ans are reouired in EOP FR Z.3,

" Response to High Containment Radiation Level," Rev. 2, and abnormal operating procedure (AOP) 1.49.1, " Irradiated Fuel Damage," Rav. 3. The issue was documented on CR 971644. Following questions by inspectors, the licensee also identified through an extent-of-condition review that steam generator blowdown tank 1FW TK-1 was red tagged out as " retired in place," though it was required in EOP ES-3.2, *Fost-SGTR Cooldown Using Blowdown," Rev. _ _ _

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Operators had originally selected equipment to tag as " retired in place" based on their experience, judgement, and historical knowledge of its frequency of use. For example, equipment that had not been used in several cycles was a good candidate for evaluatica as retired in place. Operators tagged out over 50 systems and components that were judged to be no longer in use. There was no formal review or checklist to follow. The tagouts were intended to be an interim measure for configuration control purposes until the formal " retired equipment program" was implemented. However, after implementation of NPDAP 8.33, there was no follow-up to enter the equipment already tagged as " retired in place" into the formal, approved progra System and Performance Engineering Department (SPED) engineers also maintained a list of systems and components that were potential candidates for retirement; however, they had not yet been entered into the NPDAP 8.33 program, inspectors noted that the containment loc.ine fans were on the SPED candidate list with a recommendation that they not be retired. The steam generator blowdown tank was also on the SPED list, but no recommendation regarding retirement had been mad The D4ector, System Engineering, stated that implementation of the NPDAP 8.33 program had been delayed while training system engineers on the new program, but that he expected all evaluations to be complete by December 15. At the end of the oeriod, no equipment had been retired in accordance with NPDAP 8.3 As immediate corrective action, the containment iodine fans and 1FW TK 1 were untagged and returned to service. The licensee compared the operations tagouts and SPED list to ensure that all of the tagged components were included in the SPED list. Potential candidato components for retirement were assigned to responsible system engineers to begin the NPDAP 8.33 evaluation proces Impectors asseued that the initial review done by operators was weak because it failed to consider the potential impact on procedures of removing the equipment from service. in addition, NPDAP 8.33 was implemented without a transition from the interim tagouts to the new program requirements, inspectors considered these to be programmatic weaknesse c. Conclusions Some equipment was red-tagged as " retired in place" without recognizing that it was required for use in EOPs and AOPs. This was an unresolved item pending completion of NRC review (URI 50-334 and 412/97-07 01).

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07 Guality Assurance in Operations

07.1 Audits and Surveillances of Qoerations Deoartment Activities Inspection Scone (71707)

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TS require audits of plant operations to be performed under the cognizance of the i Off site Review Committee. The inspectors reviewed a selection of Operations ~ :

Program surveillances and audits performed by the Quality Services Unit (OSU) to determine whether the scope was appropriate and whether meaningful findings were identified, Observations and Findinas The inspectors reviewed 85 OSU surveillances covering the period January 1995 {

through August 1997 as well as the 1996 and 1997 annual Operations Program l audits. QSU personnel observed a wide variety of operations activities with

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emphasis pieced upon planned plant transients such as unit shutdown, reactor '

vessel draindown, and unit startup. Operator performance was generally evaluated

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as good. Weaknesses were occasionally observed in areas such as poor communications among the control room staff, failure to log TS limiting conditions r of operation, control room access control, administrative overburden for Senior Reactor Operators, poor control of reactivity additions, configuration control . -

deficiencies, and a building backlog of operations procedure change requests. An isolated instance of poor command and control of Ucensed activities during a Unit 1 shutdown in August 1996 was identified, highlighted to senior management, and appropriate corrective actions implemente Weaknesses noted were clearly documented on appropriate corrective action forms such as quality assurance deficiency reports (prior to January 1,1997) and !

condition reports (beginning January 1,1997). Noteworthy strengths toward the end of the period reviewed included improvements in operator communications and ,

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repeatbacks, control room access control, configuration management, and implementing UFSAR reviews as part of the operations department procedure revision process. The inspectors determined that the QSU findings were typically consistent with NRC findings. Corrective actions to address identified weaknesses were well focused and follow up surveillance and audit activities were performe i The inspectors noted that some types of performance deficiencies noted in 1997 NRC inspection reports were not specifically identified or addressed in the QSU audits and surveillances, although NRC findings are publicly available to the QSU for their use. Examples included operator failure to recognize applicable TS limiting conditions of operation, poor logkeeping and review practices, poor control of troubleshooting activities, and outdated operating documents such as standing

. operating orders and Sasis for continued operation. The inspectors questioned why ,

these deficiencies had not been identified during OSU activities. The QSU Operations Supervisor informed the inspectors that a wide variety of sources including NRC inspection reports and various industry reports and assessments are

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reviewed and used to formulate OSU assessment and audit plans. The OSU Opere' ions Supervisor produced records indicating that these above four areas had bec. monitored, on a limited basis in the past. Af ter discussing these observations with the inspectors, he determined that the existing surveillance and audit plans would be revised to include additional emphasis in the four areas listed above. In addition, OSU management plans to enhance department performance by adding another operations experienced person to the QSU operations staff in early 199 Conclusions The inspectors conc luded that OSU Operations Program audit and surveillance activities were generally effective m evaluating operations performance, identHying weaknesses, and follow up corrective action verifications. Some exceptions were noted in thsi toveral areas of negative NRC findings were not similarly identified through OSU activities. QSU management initiated appropriate action to ensure i thesa artes are add;essed through future surveillance and audit activitie '

Operatiors mensgement's use of OSU for independent assessments of suspected prottem areas was a s'rengt .2 Effectiveness of Mc9nsoo Controls in Identifyina Resolvina, and Preventina Problems Insnection Scone (4050'M On September 15 19,1997 four inspectors conducted a performance-based and programmatiu evaluation to determine the effectiveness of licensee controls in identifying, resolvbg, and preventing issues that degrade the quality of plant .

operations or shfety. These controls include: safety review committees, root cause analysis programs, corrective action programs, self-assessment programs, and other processes that provide for the incorporation of operating experience feedback. The inspection was performed using the guidance of Inspection Procedure 40500,

" Effectiveness of Licensee Controls in identifying and Resolving Problems." The inspectors conducted plant tours, interviewed personnel and reviewed documentation to complete this inspection, Qbiprvations and Findirag Problem identification The process used at Beaver Valley Power Station for the identification and resolution of problems is the Condition Report (CR) system. The licensee implemented the CR system on January 1,1997, after a quality assurance sucit concluded the prior corrective action program was ineffective. The Condition Report Program Administrator (CRPA), who has a staff of technical reviewers and administrative sunport personnel, reports to the Director of Licersin _ _ __ ._ __ _ ___ _ __ .

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Nuclear Power Division Manual (NPDAP) 5.2, " Initiation of Condition Reports,"

Rev. 6, provides instructions for the preparation of CRs. NPDAP 5.6, " Processing of Condition Reports, Rev. O, provides instructions for the processing of CR Except for CRs initiated by Quality Services Unit (OSU) personnel, the CRPA is responsible for 1) establishing the category and due date of CRs,2) identifying assigned organizations for investigation of CRs,3) reviewing CR documentation for adequacy, completeness, and identification of any cverdue actions and 4)

subsequent coordination and final closure of CRs. For CRs initiated by the OSU, OSU personnel are responsible for the above action The inspectors found that knowledge and use (initiation) of the CR system by station workers was generally good, but wes varied. Supervisors generated substantially more CRs than craft personnel. The licensee's July 1997 CR Monthly Report indicated that 57.5% of the 1997 (1332 to date) CRs were generated by Individuals / Groups, a non supervisory designation. However, a separate recent review by the operations department identified conflicting results. Their review showed that only 37 of the last 1000 CRs (3.7%) were generated by bargaining unit personnel. The discrepancy largely related to the Individuals / Groups category being a broad category that includes bargaining personnel in addition to other non-supervisory personnel, such as the engineering departments. The licensee acknowledged the limitation within the Individuals / Groups category definitio The inspectors interviewed several operators and reviewed several completed CRs, and confirmed that few bargaining personnel initiate CRs. Sorne of the reactor operators stated that they have not initiated any CRs and they don't plan to. They indicated that they inform their supervisor of the need to generate a CR. This was consistent with normal CR processing practices at the plant. However, inspectors identified an example where information was not effectively communicated, resulting in delayed CR initiation. Specifically, on September 17, operations purged the wrong chemical and volume control system domineralizer for several days. The error was logged by a reactor operator, who informed one of the Operations Technical Assistants of the need to initiate a CR. However, when questioned by the inspectors on Saptember 18, the licensee said that operations and chemistry were evaluating what to do next to address the problem. After additional discussion with the inspectors, the licensee decided a CR was appropriate, and submitted one. As the Operations Technical Assistant was not initially familiar with the event details, he may not have recognized the need to initiate the CR without additional involvement by the inspector Maintenance exhibited similar performance relative to CR identification. Most of the earlier CRs were initiated by supervisors, although in many instances, at the prompting of craf t personnel. Licensee management acknowledged the need to further encourage CR idantification at the bargaining unit level of the organization, and has initiated recent efforts to improve performance in this regard. The more recent trend of maintenance CRs clearly indicates that the problem identification process has been disseminated to the bargaining unit level personnel in that the bargaining unit personnel have generated 43 CRs since July 1997. This improvement in the identification of plant and hardware deficiencies at the

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bargaining unit level can be attributed to 1) a recent revision to the !icensee's Maintenance Standard, which was revised to reflect management's expe:tations relative to problem identification by workers, and 2) severa! CR training sessions provided to the bargaining unit personnel in June 199 The inspectors identified some items during this inspection that the licensee did not initially submit as CRs. There were identified from reviews of operator logs, morning meeting discussions, and during a plant tour. For example,

The reactor coolant pump sealleakoff system filters were replaced with rnw ones in July 1997 (for " finer" filtration) that require frequent replacemen During a morning meeting, the licensee identified that the warehouse inventory was low for the new filter type. Apparently, it was low because the " Stock Level Evaluation," which prescribes the timing and quantity for new orders, was not chaaged after the marked usage rate changed. The licensee did not consider submitting a CR to identify the potential process deficiency until the inspectors questioned them (CR subsequently submitted).

Operators purged the wrong demineralizer on September 17,1997 (Chemical and Volume Contro!! Boron Pacovery System). As discussed above, the licensee subsequently submitted a C * Fire pump FP P 1 automatically started after connecting a hose to a hydrant, due to a leaking nozzle (September 11,1997, log review). The hydrant was subsequently isolated. No CR was initiate * The inspectors identified during a tout that the position indication lights for several of the post accident sample systern valves, located on a panel in the auxiliary building, were apparently burnt out. There were no deficiency tags, and the number of the valves that were affected (at least four) were indicative that the problem had existed for some extended time perio Training on the CR process was varied among the station departmants. All of the System Performance Engineering Department engineers rece;ved training, while about 75% of Nuclear Engineering Department engineers received training. Since prnviding CR training to maintenance craf t personnel in June 1997, bargaining unit workers have submitted more CRs, particularly mechanical maintenance worker Some operators indicated a lack of detailed knowledge regarding CR system, particularly related to examples of issues or events that should be captured as a C In summary, knowledge and use (initiation) of the CR system by station workers was generally good, but was varied. The inspectors' identification of items for which CRs appeared warranted but were not initiated indicates that the licensee was not making full use of the CR system. The licensee acknowledged this concern, and was evaluating further actions to improve program implementatio CRs were largely submitted by supervisors when compared to bargaining unit personnel. Recent management efforts have resulted in bargaining unit oersonnel identifying and documenting more CR _ _ _ _ -.

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Root Cause Analysis, Problem Evaluation and Corrective Action The inspectors selected several CRs to determine whether the licensee properly evaluated the issue or event, including the associated root cause analysis and corrective actions. The inspectois selected operations, maintenance and engineering CR Overall, root cause determinations were good. The level of root cause evaluation was ccmmensurate with the significance of the individual CRs. Several of the CRs had an associated Extent of Condition (EOC) evaluation, which determined whether the CR documented a repetitive event, whether there were past occurrences in the industry, or whether there were generic implications of the event. The inspectors found that the quality of the EOC evaluations was acceptable, although the EOC ovaluations performed at the beginning of the CR program implementation (January 1997) were of lesser quality and detail. The CR administrator informed the inspectors that part of his responsibility was to provide coaching to individuals when processing the early CRs to communicate management's expectatior.s for completing EOC evaluation The inspectors concluded by reviewing several CRs (open and closed) that the licensee was appropriately evaluating CRs. However, two examples were identified where the licensee's evaluation and corrective actions were not thorough and timely. CR 970128, which was initiated on January 18,1997, was related to several cold weather preparation problems. The CR administration technical reviewer felt that the associated evaluation needed improvement, but his concems have not been satisfectorily addressed by the individual assigned to respond to the CR. When the inspectors reviewed the CR, it was still open and not resolved. The inspectors stressed the importance of reviewing this CR pdpl to experiencing cold weather to prevent recurrence. The licensee acknowledged this concern, and stated the CR response would be formally rejected, requiring a revised respons The second CR, No. 970055, was initiated on January 3,1997, and identified that operation of the 2RCP-H2C pressurizer heater group (Unit 2) is not consistent with the UFSAR description. Specifically, a proportional heater bank, designed to cycle on and off automatically in response to pressure changes, has been operated in a continuously energized condition since initial plant operation. The associated event assessment, dated February 18.1997, concluded thc' the described condition was not a deficiency because the UFSAR excerpt provided an overview of the " design capability" of the system rather than the allowed operation modes. However, the CR administrator questioned that determination and placed the CR in a " hold" status. When questioned by the inspectors, the CR administrator recognized the untimely resolution of the issue and formally rejected the CR response, and the issue was forwarded to the UFSAR review group for a formal determination. The licensee acknowledged these two issues and implemented prompt and appropriate actions after they were identified by the inspectors. These two examples appeared isolated as compared to the relatively large sample size reviewed by the inspector Nonetheless, the inspectors stressed the importance of timely and thorough review and disposition of CR response . _ _ . _ _ _ _ _ _ _ - __-__

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The inspectors found that corrective actions were typically implemented in a timely f ashion and were technically appropriate. Recently, the licensee determined that corrective actions they committed to implement in Licensee Event Reports did not always match the corresponding CR corrective actions. As a result of this discrepancy between corrective actions, the licensee appropriately initiated CR 971565 to resolve the proble The number of overdue SPED (system engineering) items (evaluations of CRs and corrective action implementation) was increasing over time. This appeured to be related to the fact that a majority of CRs required some level of engineering review for a thorough evaluation. Licensee mana0ement acknowledged and previously recognized this trend and has initiated efforts to review the nature, appropriateness, and priority of the SPED backlog items. Site managernent plans to implement changes to efficiently manage the SPED backlog, as appropriate. The inspectors noted that the overdue items were generally classified as a lower safety priority and did not present an immediate safety concer The inspectors reviewed several of the CR monthly reports, published by Nuclear Licensine. The reports are issued to senior station management and provide extensive data, graphs, and tronds. Senior management reviews the data and issues action items to management level personnel to address developing trends. -

For example, the August CR monthly report identified the development of a negative trend related to preventive maintenance in that 25 CRs were generated related to -

preventive maintenance in that 25 CRs were generated related to preventive maintenance. A response, due October 31,1997, was issued to the SPED manager to conduct an evaluation of this trend. The CR database, as consolidated in the monthly report, indicated that an average of 185 CRs have been generated per month since January 1997. The current number of open CRs is approximately 1100, with the majority of them assigned to the engineering departments. As stated above, the licensee is evaluating the engineering backlog. The data contained in the reports receives appropriate attention by senior station management, in summary, the inspectors found that CR evaluations, root cause determinations, and corrective actions were good overall. The Extent of Condition reviews, conducted at the beginning of the CR program, exhibited weakness, but increased emphasis and training by the CR administration resulted in higher quality review Two CRs were not fully evaluated in a timely fashion, and the licensee subsequently initiated additional actions to achieve resolution. Monthly CR trending information receives attention from senior station managemen Employee Concern Program The licensee implemented a formal employee concern resolution program in 199 As of the period of this inspection, the program had handled 34 concerns. The inspectors reviewed the general content of various program concerns with the program coordinator. Most of the concerns had been resolved, but four remained open. The program was being properly implemented and employee concerns were I

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tracked app.*opriately. Confidentiality was maintained very well, and the program coord:nator contacted employees for a final close-out to verify that the concern had been resolved. One specific area had a relatively large number of concerns. The ins 9ectors discussed this large number with the licensee's management to ensure that they were aware of this. The licensee's management representative stated that they were aware of this trend and had taken some actions to determine the potential significanc The inspectors noted that potentially safety significant items were not entered in a 10CFR50 Appendix B corrective action system, such as the CR system. As a result, trending analysis, investigation of repeat problems, or generic problem reviews were not performed. The licensee had similarly identified this question at the some time it was identified by the inspectors. The licensee had committed to review the program procedures ano determine whether future technical issues could be separated from the employee concerns and entered into the CR system without losing the confidentiality of the concern resolution program. The licensee also stated they would review the existing concerns for any appropriate safety signii; cant issues that could be entered into the CR system. The inspectors determined that this action was appropriat Industry Operating Experience Review Program The licensee's Safety and Licensing gruup is responsible for maintaining control of the Industry Operating Experience Review Program (IOER) at the station. AllIOER information, which includes industry, INPO, and NRC items (excluding NRC bulletins snd generic letters), is received by the Safety & Licensing group. Since the beginning of 1997, allindustry operating relatcd experience information is entered and tracked m the licensee's Commitment Action Tracking System (CATS) data base. Currently, there are 199 items entered into CATS dealing with industry operating experience. The information is initiaily screened by the Safety &

Licensing group to determitie if the items or issues are applicable to the station, if it's determined that a more technical review is necessary, the information is forwarded to the appropriate department for their assessment and dispositio Open items, as a result of this process, are tracked to closur The inspectors re7imed evaluations for INPO SER 197, "Nonconserve ive Operation During Isolation of a Reactor Recirculation Pump," Westinghouse -

Nuclear Safetv Advisory Letter NSAL 97-01, " Pressure and Delta Transmitter Drift,"

and NRC Information Notice 88 23, " Potentia' Gas Binding of High Pressure Safety injection Pumps." A recent Unit 2 gas bindir8g event (see Section E1.2) has caused the licensee to reevaluate NRC Inforr.1ation Notico 80 23. The inspectors determined that the licensee is cun9ntly conducting tiiorough and technical accure.te evaluations of industry operating experience information. The informbtion is being properly assessed, dispositioned, and any resulting corrective actions are being appropriately entered and tracked by the Safety & Licensing Department via CAT __ _ _ _ _

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Quality Assurance During this inspection, the inspectors reviewed the following OSU audits: BV C 97- ,

06, " ORC Fire Protection Audit," BV C 9716, " Oversight Groups Audit," and BV C-97-19."199/ Quality Control Program Audit." QSU personnel initiated 11 CRs during the course of audit BV-C 97 06, six CRs during the course of audit BV C 97-16, and 14 CRs during the course of audit BV-C 97-19. In addition to the six CRs initiated during audit BV C 9716 (conducted January 31,1997, through February 21,1997), OSU personnel identified three additional concerns for which CRs were not initiated during the course of the audit. The audit report states that these three concerns were brought to the attention of the then Manager, Nuclear Safety Department (NSD). Timely and appropriate correctivo actions were subsequently take During a review of the above noted OSU audita and during interviews with OSU 4 auditors, the inspectors determined that DLC OSU auditors were frequently accompanied by representatives from other licensees, and that DLC OSU auditors likewise frequently participated in audits at other licensee's facilities. The ,

inspectors concluded this to be a good initiative, in 1994, the licensee changed the facility organization and moved the Quality Control (OC) receipt inspectors from OSU to the Procurement Department. The QC receipt inspectors are responsible for performirig inspections on newly received, safety-related components to ensure that the components meet specifications as per the procurement documents. The QC inspectors were assigned to the Director -

of Warehouse Operations, who in turn, reported to the Manager of Procuremen This change had the potential to reduce the authority and organizational freedom of the QC inspectors from the line organization and therefore, could make them more susceptible to the pressures of cost and schedules (ref.10 CFR 50, Appendix B.I).

In April 1995, the new Manager of Procurement reorganized the department and -

had the QC inspectors report directly to him. This later change allowod for more organizational freedom and authority, but the QC function still reported to procurement management. At the time of the inspection, the QC receipt inspection section was still part of the Procurement Departmen This organizational change to the cuality assuranco (QA) program was not identified oy the hcensee as a reduction in commitment in the QA program descriptio Licensee representatives stated that they did not believe that the change made to the UFSAR was a change to the QA program since it was not stated in Chapter 17 (Quality Assurance Program Description - Operations) of the UFSAR. The actual change was made in Chapter 13 (Conduct of Operations) of the UFSAR. Therefore, the licensee did not report the change to the NRC. However, the inspectors found that the change to Chapter 13 of the UFSAR had the potential to adversely affected

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the organizational relationship of the QA organization. Pursuant to i 50.54(a)(3),

the Duquesne Light Company was required to inform the NRC of this reduction in commitments in its OA program description and should have sought approval prior

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to its implementation. As such, the licensee's actions in this area constitute a violation to 10 CFR 60.54(a). (VIO 50 334/97 07 02)

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in summary, the inspectors concluded that OSU personnel were generally appropriately identifying problems or conditions that affect plant safety or are adverse to quality. Overall QSU involvement in oversight activities was good. QA audits were of high quality. QSU's use of outside people (e.g. other utilities) to gain further industry perspective during the performance of audits was considered a strength.

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Safety Committees Nuclear Safety Review Board The inspectors attended a portion of Nuclear Safety Review Board (NSRB) meeting No. 97 60 on September 16,1997. A draft of Licensee Event Report 1 97 027,

" Missed Surveiliance of the Refueling Water Storage Tank Boron Conccntration,"

was discussed during the meeting. The NSRB members demonstrated a strong ,

questioning attitude during the discussion of this egenda item tnd asked several probing questions regarding weaknesses in tha surveillance program for sampling the refueling water storage tank boron concentration. These qucstions and the .

ensuing discussions led to a determination that the Chemi',try Department only logs the start time for taking a sample as satisfying a technical specification (TS)

surveillance and not the actual satisfactory comr'etion of the analysis that actually demonstrates compliance with the TS surveillance requirements, in response to this determination of weaknesses in the surveillance programs, the licensee initiated CR 971601 on September 17,199 Offsite Review Committeo Although the Offsite Review C >mmittee (ORC) did not conduct a meeting during this inspection, the inspectors interviewed the ORC Coordinator and reviewed the ORC meeting minutes for its August 6,1997, meeting (ORC 288). From this interview and review of the meeting minutes, the inspector determined that the ORC and its subcommittees are performing comprehensive and thorough reviews with an appropriate emphasis on safet CR 970423 was initiated by OSU personnel during performance of audit BV-C-97-16 because two non DLC members of the ORC had not participated in at least two audits during 1996 as had been directed by the Senior Vice President and Chief Nuclear Officer. During this inspection, the inspectors confirmed that all non-DLC members of the ORC had either participated in two audits or were scheduled to participate in at least two audits during 1997. Participation of non-DLC ORC members in audits is tracked in the ORC meeting minutes, in summary, the NSRB is functioning in an excellent manner, demonstrating a strong questioning attitude. The licensee's initiation of CR 971601 demonstratod an appropriate response to a concern (weaknesses in the TS surseillance programs)

identified during the course of an NRSB meeting. The ORC is also functioning well and its non-DLC members are participating in at least two audits per calendar yea _ _ _ . . _ _ . _ _ , _

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Self Assessments NPDAP 8.29, " Conduct of Self Assessments," Rev. 3, provides guidance for conducting self-assessments in all Nuclear Power Division departments at BVP During this inspection, the inspectors reviewed the most recently completed self-assessments for the Operations, Maintenance, and Engineering Department Section IV.F. of NPDAP 8.29, provides that the OSU shall determine whether the self-assessment process is being effectively implemented. On January 8,1997, OSU issued the 1996 Self-Assessment Plan Year End Status Report, which provided the status of the self assessments scheduled for 1996. This report showed that of the 66 self assessments that had been scheduled for 1996,48 had been completed, seven had been rescheduled, four had been deleted, two were in progress, and the status of five was unknown. For 1997, OSU has developed a 1997 Self Assessment Schedule that is intended to show all 1997 self- ,

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assessments. Actual dates are to be entered when a self assessment has been issued. The inspectors reviswed this schedule dated September 17,1997,and determined that five self assessments scheduled for the second calendar quarter of 1997 were not complete The inspectors found that the self assessments cond ut.'ed by the operations department were generally self-critical and probing. The inspectors reviewed several operations self assessments, including startup and shutdown activities, a control room deficiency program review, a maintenance work request post r maintenance test (PMT) review, and a component mispositioninu review. Some of l the more notable findings included 1) the control room deficiency program review found that the program was not meeting site goals related to identifying and fixing control room deficiencies, and 2) there war. insufficient staff at the work control center and PMTs were sometimes untimely. In response to the findings, the inspectora found that the licensee had either implemented or planned to implement appropriate Torrective actions for resolution.

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The inspectors concluded that the maintenance department was not meeting l

management's expectations or adhering to the established self-assessment schedule. The maintenance department delayed two self-assessments, work control and schedule, that were scheduled to be completed by the end of September 1997. The above two self assessments were postponed pending receipt of a prior third party evaluation report. The inspectors reviewed the completed -

maintenance self assessments in the following areas, which were found to be of acceptable quality: Maintenance Program Unit Human Factors; Foreign Material Exclusion Program; and, Plant Instrument Calibration Program.

l SPED was not meeting the commitment to OSU for the number of self-assessments.

i Licensee management stated that this was a deliberate decision to defer some self-l assessments due ?o manpower constraints and ether priorities. TM inspector l reviewed some of the completed SPED self assessments and concluded that they l were very detailed and identified some areas for improvemen . -

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In summary, the completed self assessments that were reviewed by the inspectors were generally st ' critical and probing. However, deficiencies in the self-

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assessment process were noted in that the licensee's internal commitments to perform scheduled self assessments were not met. Several station departments were not meeting management's expectations in adhering to established self-assessment schedules. Two maintenance self assessments (work control and ,

schedule) that were to be completed by September 1997 were postponed. SPED also was not meeting schedule commitments - a conscious decision was made by management to defer self assessments due tn manpower restraint Conclusions Overall, the licensee effectively identifies, evaluates and corrects proble~a, primarily througn their pioblem identification corrective action program. Other nechanisms likewise exist to identify problems, such as self assessments, emplo) .se concerns ('

program and audits. Some examples were identified for which the licensee has not exercised the CR process, indicating that the CR system needs continued management attention to make full and effective use of the proces Miscellaneous Operations issues (90712,92700,92901)

08.1 (Closed) Licensee Event Reoort (LER) 50-334/97 014: Failure of Refueling Water Storage Tank Level Transmitter Leads to Entry into Technical Specification 3. The event was documented in NRC Inspection Report 50-334 and 412/97-06, Section 01.3. No new issues were revealed by the LE .2 (Closed) LER 50-334/97 025: Ground in Feedwater Flow Controller Results in High Steam Generator Level and Subsequent Turbine Trip / Reactor Tri The event was documented in NRC Inspection Report 50-334 and 412/97-06, Section 01.2. The extent of condition review determined that the same type of controller (Model 124 Westinghouse /Hagen flow and pressure controller) was used in many non safety related applications in other systems on U it 1. This controller type was not used on Unit 2. The Event Response Team evaluation concluded that the ground was due to an isolated maiufacturing defect unique to the particular controller that failed on Unit 1. Inspectors reviewed the licensee's 10 CFR 21 reportability determination (letter ND3MPM:1101 dated September 12,1997) and agreed with the conclusion that 10 CFR 21 reporting requirements did not apply to the controller, since it was non safety related and was not a basic componen Licensee corrective actions were complete .3 (Closedn LER 50-334/97-016-01: Unit 1 Shutdown Required by T.S. 3.0.3 Due to Inoperable Steam Generator Low-Low Level Reactor Protection System Tri The event was documented in NRC Inspection Report 50-334 and 412/97-05. No new issues were revealed by the LER revision. The dates for completion of future corrective actions were revise _ _ _ __ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ - .

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08.4 (Cloced) LER 50-334/97-005-02: Inadvertent Operation of 345 KV Bus Backup l Timer Relay Results in Dual Unit Reactor Trip l The event was documented in NRC Inspection Report 50 334 and 412/97-02. No j new issues were revealed by the LER revision. The dates for completion of future corrective actions were revise ;

. 11. Maintenance

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M1 - Conduct of Maintenance M1 1 Routine Maintenance *)bservations (62707)

The inspectors observed the following maintenance activit i !

MWR 058298 Support Main Steam Safety Valve Testing

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The activity observed and reviewed was performed safely and in accordance with proper procedures. Inspectors noted that an rmpropriate level of supervisory attention was given to the wor '

t M1.2 Routine Surveillance Observations (61726)

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The inspectors observed selected surveillance tests. Operationel surveillance tests

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(OSTs), and Beaver Valley Tests (BVTs) reviewed and observed by the inspectors are listed below, i

10ST 2 " Turbine Driven Auxiliary Feedwater Pump Test," Rev. 9

1/20ST-48.12 " Area inspection for Uncontrolled Operator Aids," Re * 10ST-3 "Offsite to Onsite Power Distribution," Rev. 4

1/20ST+44A.15 " Chlorine Actuation by Unit 1 SSPS of Control Room isolation /CREuAPS Systems," Rev. 7

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10ST-30.12A " Train A Reactor Plant River Water System Full Flow Test,"

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IBVT1.2 "Trevitest Method for Main Steam Safety Valve Setpoint Test," Rev 5 l' * 1 BVT1.1 "Si Accumulator Discharge Check Valves Full Stroke Test,"

Re * 10ST-11,4A " Accumulator Check Valve Test (1SI-51, 52, 53)," Rev. 5

10ST 11.4B ' " Accumulator Check Valve Test [1SI-48,49, SOL" Rev. 3

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The surveillance testing was performed safely and in accordance with proper procedures. Additional observations regarding surveillanca testing are discussed in the following sections. The inspectors noted that an appropriate level of supervisory attention was given tu the testing, depending on its r ansitivit The acceptance criteria was met for the 1/20ST-44A.15, despite the challenge to operators due to leaking valve 1VS 10 (header discharge isolation for air tanks 1VS-TK 6E and 7E). Operators were required to use compensatory actions to perform the test by shutting the air tank isolation valves. The compensatory actions were identified on a caution tag on the valve. This was an identified condition that was documented on Work Request 88590, dated August 16,1997. Inspectors identified the condition as an " operator work-around." The ANSS agreed and took appropriate action to identify and tract this item accordingl M2 Maintenance and Material Condition of Facilitle. and Equipment M2.1 Installation of Transmitters Insoection Scope (929_QL The inspectors perforrned walkdownr of safety related systems and noted that shipping caps remained on pressure transmitters. The inspectors questioned the maintenance engineers, system engineers, and instrumentation and control (l&C)

technicians on the plastic shipping caps installed in the spare conduit port of Rosemount Transmitters, Observations and Findinas During systems walkdowns, the inspectors noted that plastic foreign material exclusion (FME) shipping caps were installed in the spare conduit ports on some component cooling water, auxiliary feedwater, recirculation spray, and quench spray transmitters. System engineers and l&C technicians subsequently performed comprehensive walkdowns of Unit 1 and Unit 2 identifying additional examples of plastic shipping caps installed in the transmitter The transmitters, found with the plastic shipping caps, were not required to have an environmentally qualified seal based on their 10 CFR 50.49 equipment qualification categorization and/or because the equipment was located in a mild environment as documented in the environmental equipment qualification report. The vendor manual for the subject transmitter model, Rosemount 1151 AP/GP, directs that conduit connections on the transmitter housing should be sealed or plugged to avoid moisture intrusion. For harsh environments, the conduit connection must be closed with a threaded metal plug. The inspectors observed that the maintenance l procedure for installation of environmentally qualified Category I transmitter included l steps to install the metal plug. The inspectors did not identify any environmentally l qualified Category I transmitter installed without the metal plug.

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The licensee determined that based on vendor documents, industry information, and their evaluation, they will replace the plastic shipping caps with stainless steel plugs. The inspectors verified that the maintenance work request to install stainless stent plurs was writte Conclusion The inspectors identified that plc tic shipping caps were installed in pressure transmitters in safety system. The ship 6 aps installed in the spare condu t ports

of various transmitters did not affect insw.nent operability or cualification. The inspectors observed that replacing the shipping caps with stainless stee! plugs was in line with the vendor manual and good operational practice. The licensee's corrective actions were comprehensive Ill. Enaineerina E1 Conduct of Engineering

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E1.1 Digital Rod Position Indication. Basis for Continued Oaerability (37551)

l On July 24, rsstem engineers identified from their rod drop testing data that the

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Unit 2 digital rod position indication system (DRPI) Channels F 6 and F-8 "A" data and "B" data cables were reversed. TS 3.1.3.2 requires that DRPI be capable of determining the contrci rod positions within +/- 12 steps. Engineering established l during DRPI full accuracy mode (Data "A" and Data "B" both being read), the indicated rod positions would be accurate within +/- 12 steps. This determination was not formally documented in their basis for continued operability (BCO) process.

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Due to another DRPIissue, the system was subsequently placed in half accuracy l mode of operation. Interim measures to take readings in full accuracy every four hours were established. A formal BCO was written afMr NRC inspectors questioned the operability determination methods. The BCO was completed approximately two months af ter the initial event. The licensee haa explored variou* other options (such as a tempor,ry mwification) prior to committing to having a BCO for this degraded condition. Overall, the inspectors assessed that the licensee was slow in performing their formal operability determination. However, the inspectors determined that the licensee verified that the TS for DRPI were met during this perio .__

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E2 Engineering Support of Facilities and Equipment

. E Potential incore Thermocounle Defect

Inspection Scone (37551,92903)

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The industry identified a safety concern regarding potent 9 tip-weld in-leakage on

Inadequate Core Cooling Monitor (ICCM) thermocouples. > ne entrapped moisture .

could subsequently heat up and cause the thermocouple to burst and become (

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inoperable f""owing a design basis loss of coolant accident. The inspectors interviewed personnel and reviewed technical documents to evaluate licensee resolution of this issu Observations and Findinas ( The vendor issued Nuclear Safety Advisory Letter (NSAL)95-006, "incore Thermocouple Moisture intrusion," which informed the industry of this potential problem. An elect cal d resistance measurement test was recommended to

. determine whether moisture had intruded, thereby making the thermocouple -

susceptible to the postulated f ailure. The original test criteria specified acceptance criteria of .;>_1 million ohms resistance measured using 100 volts. Based on data j taken at two other facilities, Beaver Valley engineers questioned the validity of the J test rnethod and analysis. Engineers believed that properly functioning thermucouples which did not have moisture intrusion may also fail the acceptance criteria for this test Following consultation with various industry sources the licensee proposed an -

alternate set of test criteria. The vendor confirmed that this alternate criteria should provide valid :ewits. A separate, mdependent vendor was hired to perform the testing at Unc 1 The licensee had procured 20 replacement thermocouples and observed thermocouple replacement at another site to prepare for thermocouple

9 acements 1 if the test data indicated this was necessar Engirw,c wiiked closely with the vendor in test preparation and performance to ensure H d iity. The core had 51 installed ICCM thermocouples, seven of which we;a out of service for other .*efects. Three thermocouples failed the 6 resistance check and four others indicated other abnormalities requiring further

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evaluation. Thirty-seven ICCM thermocouples passed all test criteria. TS require-

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four ICCM thermocouples per quadrant (or 16 total) to be operable. Engineers determined that three ur more thermocouples per power train were available in each quadrant. This provided a substantial margin, beyond the TS required number of ICCM thernocouples. Based on this information station management decided that the ICCk system was not adversely degraded and did not require thermocouple replacemen _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ - _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _

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The inspectors attended the Nt. War Safety Review Board (NSRB) presentation for this issue and observed that engin.ers presented the information clearly and concisely. This was a noted improvement over v> oral other NSRB presentations during the past three months during which p%4 ente:3 were not fully prepared and were unable to make recommendations to m r agen ent. Based on the material presented, management decided to indefiniteg pos' sone anv ICCM thermoccuple replacements. The inspectors determined that this decision was appropriate based on the inherent risk based on industry experience associated with theneiocouple replacement and the existing availability of unaf fected ICCM thermocouple Conclusions The inspectors determined that engineers properly evaluated an industry concern regarding moisture intrusicn into ICCM thermocouples. The evaluation was thorough and closely integrated industry and vendor information. The information was clearly presented to NSRB which supported a timely management decision regarding proposed maintenance. The decision to continue operating with the ICCM system in its current analyzed condition was appropriat E2.4 Charaina Pumo Gas Bindina Insoection Scoce (37551. 92703)

The inspectors reviewed the events surrounding the August 28,1997, gas binding of the Unit 2 "C" charging /high head safety injection pump (2CHS-P21C) and the subsequent fai;ure of the pump to rneet Technical Specifications (TS) requirement The inspectors examined historical performance data, vendor information, and NRC Information Notico 88-23 and associated supplements. The inspectors also interviewed system engineers, design engineers, and operators. Finally, the inspectors reviewed the effectiveness of the team assigned to perform a complete review of the event Observations and Findinas Gas Bindina Event On August 28,1997, the reactor operator started 2CHS-P21C, then stopped the pump 20 seconds later af ter the pump showed indication that it was gas boun Prior to the start of 2CHS P21C, operators vented the pump in two venting periods, one lasting 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and the other lasting 74 minutes. Normal venting periods are less than 10 minutes. Based on the abnormal amount of gas vented, the pump was started to verify operability and subsequently was gas bound due to inadequate venting of the charging lines. The licensee determined that this August 28,1997, i

gas binding event was a likely contributor to the degraded pump performance

observed on September 12. The inspectors determined that the opportunity to

! prevent damage to the pump and gain valuable data on gas voiding in the charging l lines was missed following the August 1997 event (if used before starting the

pump, ultrasonic testing could have detected the amount of gas voiding in the l lines).

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On Sep* ember 9, operators observed pressurizer level dropping (the pressurizer low level alarm failed to alarm). This was attributed to the charging flow control valve (2CHS-FCV122) not fully opening. 2CHS-P21C pump performance was verified to be satisfactory with 160 gpm flow rate a 2472 psid pump differential pressur This point was above the minimum operatmg point (MOP) for the pump. An instrumentation and controls technician investigated the pressurizer low level alarm and charging flow control valve problems. On September 11, RCS letdown isolated due to insufficient self checking by the instrumentation and controls technician and poor human factors in the procedure for pressurizer low level alarm restoratio Oprators took appropriate action and restored letdow On S(ptember 12, after completing repair work on 2CHS-FCV122, the valve was returntd to service and normal letdown restored. Pressurizer level began dropping again. Operators obtained operating parameters for the running charging pump, 2CHS P21C, and noted that the pump's differential pressure was only 2341 psi The TS limit is 2437 psid. Operators responded to the decreasing pressurizer level by closing a normally > pen RCS letdown orifice valve which stabilized level. 2CHS-P21C was declared inuperable and removed from service. The rotating assembly

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and ca',ing of charging pump 2CHS-P21C were replaced and the pump was ..

declared operable on October Multi-Discioline Team Formed in response to the events on August 28 and September 12, the licensee formed a

multi-discipline team to review the events leading to the f ailure of 2CHS-P21C to

! meet its TS requirements. The team's objectives were to review and analyze the l following: 1) gas venting process and site historical documents; 2) TS

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requirements and bases; 3) charging pump performance history and current -

condition; 4) timeline of events and operating conditions of the charging pumps; and

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5) maintenance / planning for the replacement of the "C" charging pump, i

l The inspectors assessed that management's initiative to perform an in-depth team l evaluation of the events on August 28 and September 12 was good. System ( engineering management noted that the team did not achieve its objectives in numerous instances and plans to issue a condition report to address the remaining l issues. The inspectors also noted that ;everal areas were not completely reviewed.

t Some of the areas included: 1) whether 2CHS-FCV-122 had an actual problem on September 9 or did 2CHS-P21C degradation cause the pressurizer level drop; 2)

review of control room data from the September 12 pressurizer level decrease; 3)

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interim actions until permanent resolution is achieved; and 4) adequacy of surveillance testing, j The inspectors observed good performance overall by the team in supporting the replacement of 2CHS-P21C. The team coordinated procurement, maintenance, and engineering tasks related to the replacement in a timely and safe manner. The team also completed an evaluation on the extent of condition for the remaining five l charging pumps for Unit 1 and Unit 2. The team reviewed the hours in service, starts in 1997, vibration data, hydraulic performance data, and abnormal events.

l The inspi ctors questioned the reliability of Unit 1 CH-P-1 A based on the number of

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hours in service (55484 hours), a previous gas binding event in 1996, and higher vibration reading than the other pumps. System engineers noted that the number hours in service was relatively high; however, engineers identified that the vendor had not placed a specific service life for the pump. In addition, the vendor recommends thorough performance monitoring of the pumps and in particular vibrations to determine pump degradation, rather than pump disassembly and inspection. The vibrations observed on CH-P-1 A, although higher than the other pumps, did not reach the ASME threshold for increased monitoring and the vibration levels observed had remained relatively constan Beaver Vallev History and Related Vendor Information In March 1988, Beaver Valley experienced gas binding of the Unit 2 High Head Safety injection (Charging) Pump (2CHS-P21 A). NRC Information Notice 88-23,

" Potential for Gas Binding of High-Pressure Safety injection Pumps During a Loss-of-Coolant Accident," highlighted ths industry issue. Engineering performed model testing and UT examination of piping to determine gas growth rates. Several solutions were analyzed and a manual venting path was established for both unit The venting times were established based on UT measures of gas accumulation and an estimated maximum acceptable void size (based on prior history). Continuous -

venting was reviewed, but not implemented.

! In June 1993, the licensee experie f.ed gas binding of 2CHS-P21C. The excessive

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gas accumulation was attributed to inadequate manual venting of the charging line For Unit 2, the charging lines are vented to the volume control tank (VCT).

l Engineers observed that there is minimal pressure difference between the vent path

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and the VCT, which results in insufficient driving head to effectively remove gas from the system. Therefore, the venting process relies on t1e buoyancy of the hydrogen gas to bubble out of the lines, in the licensee's engineering evaluation,-

the decision to implement the manual venting rather than continuous venting was

"an interim change resulting from implementation problems and refueling outage time constraints. The manual vent design provides only a limited solution to the i void elimination." The corrective actions stated in response to this evelt were to l install thc. design for continuous ventin Following the September 12,1997, event, the inspectors noted that the corrective action proposed in 1993 had not been implemented. The licensee could not determine why this corrective action was not completed, yet this item was closed out in their tracking system. In November 1996, tne licensee experienced gas -

binding again of 2CHS-P21C. The root cause was again attributed to inadequate venting of the charging lines. The corrective action was to modify the vent path to

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improve the manual venting of the system. This corrective action was scheduled

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for completion by January 15,1998. No interim actions were taker co prevent recurrence of gas binding, in August 1997, the licensee experiencea gas binding of t

2CHS-P21C due to inadequate venting of the charging lines. In September, this l

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pump failed to meet the TS criteria, was declared inoperable, and was replace The licensee determined that the August 28,1997, gas binding event was a likely contributor to the degraded pump performance observed on September 12. The licensee plans to conduct a detailed failure analysis of the failed "C" charging pum During each event discussed above, operators quickly intervened and stopped 2CHS-P21C after observing low pump amperage. Based on vendor information and the NRC Information Notices, significant voiding in high head safety injection lines can cause gas binding of the pump and significantly contribute to damage of the pump. Beaver Valley experienced degraded conditions for 2CHS-P21C during thre instances from 1993 to 1997. Failure to implement appropriate corrective actions to prevent recurrenca of these significant conditions adverse to quality is an apparent violation of 10 CFR 50, Appenoix "B," Criterion XVI (eel 50-412/97-07-O't). ;

Corrective Actions (Interim and Lono-Term)

The team developed interim actions to prevent recurrence of the gas binding event on August 28,1997. After the event, quality services engineers periodically performed ultrasonic testing (UT) of the Unit 2 idle charging pumps' lines to detect void size and growth. The system engineers used this data to validate previous void growth assumptions and to ensure gas voids do not accumulate sufficiently to cause gas binding of the pump. Previous Unit 2 void growth assumptions were l conservative compared to existing growth rates. Unit 1 UT inspections were not

conducted until the end of September. The inspectors noted that validation of void growth rates for Unit 1 and Unit 2 were not conducted since the original testing in 1988. For Unit 1, only 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months of data from 1988 were used to determine the r void growth rates and subsequent venting frequencies.

l The inspectors assessed that verification of the original growth rates after the August 28,1997 event was prudent; however, the licensee failed to perform this assessment since 1988. On October 7, quality services detected a one inch l

horizontal gas accumulation along the six inch suction line piping of a Unit 1 l charging pump. The senior reactor operator declared the pump inoperable, based on his understanding that any voiding may cause gas binding of the pump. Based on discussions with engineering, engineers could not give a definite answer on operability, and an engineering memorandum was generated. The inspectors assessed that the operator made the correct decision based on the available information. Failure to provide acceptance criteria for operability determination when the periodic UT examination for gas voiding was first recommended, was a weakness on the part of engineerin Shortly after the August 28,1997, event, engineers identified an error in 20M-7.4.A " Placing a Charging /HHSI Pump in Standby or in Service," Rev. 5. The venting frequenc;es assumed that when the "A" pump (2CHS-P21 A) was the spare or third pump, the recirculation valve (2CHG-MOV275A) was closed. Otherwise, the actual veid growth rate would become greater than the assumed values. The procedure only contained a note that informed operators that they may close the l valve to reduce gas accumulation. On October 4, quality services engineers

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significant voiding of the spare "A" high head safety injection piping. This gas accumulation was due to the recirculation valve having been placed in the open position. The inspectors assessed that the safety consequence was minimal because the pump is vented prior to operation of the pump; however, the licensee corrective actions, after identification of the September 12,1997, problem, were slow to prevent the voidin Long term corrective actions were still being eva!aated at the close of the inspection period. Based on interviews, the corrective actions planned after the November 1996 event to irrprove manual venting of gas will not be completed by January 15, 199 The inspectors assessed that the interim corrective actions were adequate to detect void size and growth; however, implementation of the actions were a weaknes The implementation of long-term corrective action continues to be slow. The original discovery of the problem dates back to 198 Surveillance

- The inspectors reviewed the surveillance procedures to verify that they ensure .

functionality of the high head safety injection pumps. The inspectors identified several possible discrepancies in the surveillance procedure. The procedure allows flow to be adjusted from approximately 200 gpm to as low as 60 gpm to meet TS required differential pressure. Surveillance test acceptance criteria are not adjusted to address the actual pump flow established for the test. Engineers identified that the minimum operating points curve is the design basis requirements for pump operability. This curve is not contained in tha surveillance procedure and does not address pump performance characteristics below 130 gpm. The relationship between TS, the surveillance, the minimum operating points curve, and ASME requirements was not clearly designated. The issue, of the surveillance verifying operability of the pump is unresolved pending NRC reviev. of past surveillance test data and the ongoing engineering evaluation (URI 50-334 and 412/97-07-04). Conclusion The gas binding of the Unit 2 "C" high head safety injectic,n pump on August 28 was due to inadequate venting of the charging lines. Gas binding had previously occurred in 1993 and 1996. Failure to preclude repetition of this event is an apparent violation. On September 12, the pump f ailed to meet TS differentia; pressure performance requirements and was subsequently replace Licensee management's initiative to perform an in-deptn team analysis of the events on August 28 and September 12 was good, overall. Overall, the inspectors concluded that the team satisfactorily evaluated the event; however, the inspectors and system engineering mtnagement noted that several areas designated to be reviewed were not completed or were only minimalb reviewed. The review of the surveillance to l

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determine functionality of the high head safety injection pumps was not completed and is an unresolved item interim corrective actions were adequate to detect an increase in void size and growth; but, the actions were not effectively coordinated with operation E2.3 Unexoected Diesel Start Durina Bus Transfer Test Insoection Scoce (71707,92903)

Inspectors reviewed the unexpected start of emergency diesel generator (EDG) 1-2 during the performance of 10ST-36.5, " Emergency Switchgear Operation Test (Transfer from Unit to System Station Transformer)," Rev. 2, on September 2 The licensee reported the event to the NRC in accordance with 10 CFR 50.72 as an inadvertent engineered safety features actuatio Observations and Findinas Surveillance test 10ST-36.5 is performed on a refueling outage interval to verify the operability of the two physically independent circuits between the offsite power transmission network and the onsite class 1E electrical distribution system. The test starts with power supplied by unit station service transformers (USST) 1C and 1D and ends with power being supplied by system station service transformers (SSST) 1 A and 1 The hot bus transfers of normal 4kV buses 1 A,18,1D, and 1C were performed within the acceptance criteria of the 'est, but EDG 12 started during the transfer of bus 1D. The EDG did not load onto the bus since bus voltage did not go low enough to cause the bus to shed and the EDG to load. Procedure step 25 required the operator to, " Verify that the No. 2 Diesel Generator did not start." The event was documented on CR 97166 System engineers reviewed the event. An EDG had never started during performance of the OST before, but engineers found that the bus loading and plant configuration were different than in past performances. The major difference was that the main feed pump powered from the 1D side was secured. As a result, the bus voltage drop was faster than in the past and the EDG start setpoint was reached. Engineers compared the voltage and current curves from previous OST performances to support the conclusion that the electrical system response and the EDG start were reasonable given the existing plant configuration and EDG undervoltage setpoints inspectors reviewed the engineering evaluation and agreed that it was reasonabl The inadvertent starting of Unit 1 EDGs has been documented for reactor trips in the past (for example, NRC Inspection Reports 50-334 and 412/96-05,97-02, and 97-06). Typically, EDG 1-1 has been noted to start during the 4kV bus transfer to offsite power following a reactor trip and during the start of reactor coolant pump 1 A. The inspectors noted that EDG 1-2 also has a history of starting during bus transfers. The problem does not apply to Unit 2 because the undervoltage setpoints

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of the EDGs are different. Engineering has evaluated the Unit 1 EDG undervoltage setpoints (TER 10943) and the licensee intends to submit a TS change request (1 A-243) by the end of this year to change the setpoints as a permanent solution to the inadvertent EDG starts. While there have been no direct, adverse safety consequences to the inadvertent EDG starts, inspectors consider that the condition presents an unnecessary challenge to the EDGs. The licensec has been aware of the condition since at least the construction of Unit 2 and has been slow to resolve i Conclusiong _

The licensee engineering evaluation concluded that the inadvertent start of EDG 1-2 was reasonable based on the existing plant configuration, bus loading, and EDG undervoltage setpoints. inspectors assessed that the evaluation was thoroug There were no adverse safety consequences to the inadvertent EDG start. Despite the long history of inadvertent EDG starting, the licensee has been slow to resolve i E8 Miscellaneous Engineering issues E (Closed) Unresolved item 50-334 & 412/96 09-03: Heavy Load Lift Program, 1 Failure to Update FSAR and indeterminate 50.59 evaluation Insoection Scone (92903)

This item addressed heavy load lift program discrepancies between lif t paths identified in the Unit 2 UFSAR and those shown in station procedure MPUAM 4.10,

" Handling of NUREG 0614 - Heavy Loads", Rev.1. In November 1996, the licensee identified a discrepancy concerning approved lift paths within the intake structure. The inspectors subsequently noted additional discrepancies and questioned the extent of condition, including whether the heavy load lift paths in the licensee procedure nad been properly evaluated and whether unevaluated paths had been used. The i;.spectors interviewed personnel, reviewed station drawings, and corrective actions to determine extent of condition and evaluate licensee problem resolutio Observations and Findinas The licensee initially wrote Problem Report 2-96-796 to review the extent of condition and identified three heavy load lift paths that were not supported by approved 10 CF3 50.59 safety evaluations. The inspectors reviewed these findings and questioned whether the full extent of condition had been identified. After further discussions with the inspectors, licensing engineers perforrned a much more indepth extent of condition review. This review identified several additional load path discrepancies and wrote CR 970614 to resolve the .

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Licensing engineers and maintenance personnel performed a detailed issue review, including a formal root cause analysis. The heavy load lift path history file was purged when this program was reassigned between engineers several years ag Safety evaluations for changes to the approved lift paths wer. most likely kept in this file up to that point. However, engineers could not find current documented evidence of the safety evaluations for several of the changes. The changes in question were performed during the timeframe June 1983 through April 199 Changes made since April 1990 were properly supported by approved safety evaluation documents. in addition to missing safety evaluations, the licensee also identified numerous UFSAR changes which had not been submitted, and numerous MPUAM 4.10 procedure revisions which were needed. Causes for the deficiencies included:

(1) Inadequate control of safety evaluation originals due to the lack of a procedurally specified document retention pat (2) Failure to document the Operations Safety Committee (OSC) meeting number on the safety evaluation original to indicate OSC approva (3) Making heavy load lift path changes based on previous safety evaluations without properly analyzing if the previous safety evaluation enveloped th proposed change to the safe load pat (4) Insufficient self checking that changes incorporated into MPUAM 4.10 drawings matched changes on drawings submitted to the OSC with safety evaluation Refueling engineers confirmed that seven of the heavy load lift paths in question had been used. The licensee determined that use of these seven paths did not constitute an unanalyzed condition that significantly compromised plant safety, immediate corrective actions were taken to danger tag associated lifting cranes to ensure heavy load lif t paths were not used unless safety evaluations existed to demonstrate they were properly avaluated and approved. Safety evaluations were subsequently performed which supported the Unit 1 lifting paths which were in question. Procedures were updated and danger tags cleared for those paths prior to the current Unit 1 refueling outage. Safety evaluations for Unit 2 paths are in progress and scheduled for completion by December 31,1997. The licensee concluded that use of the seven heavy load lift paths in question was not a reportable event. The inspectors concluded that the reportability assessment was correct and that immediate corrective actions were adequat The inspectors noted that CR 970614 identified twelve instances in which the safety evaluations were not availabla to support changes made to the load paths contained in MPUAM 4.10. In addition several Unit 2 UFSAR drawings had not been updated as required when the station revised the heavy load lift paths. Based on document review and interviews with numerous individums, the inspectors determined that it was hignty likely that 50.59 safety evaluations were performed for the majority of the load path changes, but the approved 50.59 documents were not retained, it is also highly probable that 50.59 safety evaluations were not

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performed or did not fully support several of the load path changes. The inspectors deterrnined that OSC review of heavy load lift path revisions had been inconsistent, approved revised load path drawings were not implemented as approved, and the safety evaluation retention process was inadequate. Recent inspections indicate that safety evaluation retention has improve Major revisions were made to MPUAM 4.10 (currently Rev. 4) and NPDAP 8.18,

"10 CFR 50.59 Evaluations" (currently Rev. 4) to address the causal factors listed above. The inspectors determined that the procedure revisions were comprehensive and well written to preclude recurrenc CFR 50.59 requires that safety evaluations be performed to determine whether changes to the f acility as described in the safety analysis report (UFSAR) create an unreviewed safety question. The safety evaluations must be retained until termination of the license.10 CFR 50.71(e) requires that the FSAR be updated periodically to reflect changes to the facility. Failure to perform and retain safety evaluations for changes to the heavy load lift paths as described above, and failure to update the UFSAR were violations. This licensee identified and corrected violation is being treated as a Non Cited Violation, consistent with Section Vll. of the NRC Enforcement Policy (NCV 50-412/97-07-05), Conclusions The inspectors concluded that the licensee failed to properly evaluate and approve several revisions to the station's heavy load lift program between 1983 and 199 The OSC review process was inconsistent and controls to retain safety evaluations for changes to approved lift paths as described in the UFSAR were inadequate. The licensee evaluation of this issue was comprehensive and corrective actions were

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well focuse IV Plant Support P1 Conduct of EP Activities P EP Drills Inspection Scoce (7175J)J Inspectors observed poruons of the emergency preparedness drills conducted by DLC on September 9 and 16. Observations included the controller pre-drill briefings and post-drill f acility and controller critiques, as well as drill activities in the control room, radiological operations center (ROC), operations support center (OSC),

technical support center (TSC), emergency operations facility (EOF), joint public information center (JPIC), and within the plan _

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b. Qhtgrvations and Findinas The drills were conducted as off year training for two of the three licensee emergency response organization (ERO) teams. The third ERO team had conducted a drill earlier this yea . The scenario involved a Unit 2 main turbine accident with multiple personnel injuries followed by a steam generator tube rupture with a stuck-open atmospheric steam dump valve. Inspectors observed the activation and augmentation of the ERO, activation of emergency response facilities, and actions of other emergency response personnel. The drill was conducted to provide hands-on training in a controlled situation rather than as a graded test. As a result, some lessons learned from the September 9 drill were immediately incorporated into the September 16 drill. The following strengths were noted:

The Nuclear Shift Supervisor (NSS) correctly classified the esent in accordance with the emergency action lavels during the drill. The NSS maintained a calm, steady working environment in the exarcise control room and emphasized clear event classificatio Emergency responso facilities were quickly staffed and activate Task priorities were clearly established and communicated in the TSC. Periodic announcements were made by the Emergency Director to keep the TSC staff up to-date on plant status and priorities. The Emergency Director interacted well with the activity coordinator Turnover between the NSS and the Emergency Director was clea The OSC coordinator clearly communicated task priorities and provided concise, informative job briefings to work crews prior to dispatching them into the fiel The radiation technician performed a good dose survey along the entire travel path and work area for an OSC field team. The radiation technician briefed workers on survey results promptl Protective action decision making was correct for the drill scenari Post-drill facility and controller critiques were unbiased, with candid discussions of strengths, weaknesses, and potential improvement JPIC staff demonstrated a good understanding of their job positions and roles, and a good rumor ccntrol process. Press briefings were goo The following observations indicate areas where improvement may be necessary:

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Inspectors observed that notifications to state and local officials were not accomplished within 15 minutes of the declaration of an ALERT condition during either drill. Notifications took from 18 to 20 minutes. Problems with meeting the 15 minute criteria were also noted during notifications for UNUSUAL EVENT and SITE AREA EMERGENC Inspectors noted that an operator went directly to the main steam valve room and isolated the stuck open atmospheric steam dump without first contacting ROC personnel to verify radiological conditions. The event posed an elevated dose rate in this area, but the operator was unaware of the dose rat The radiation technician accompanying a maintenance team into the field did not have proper monitoring equipment to verify contamination levels until prompted by the inspectors. Contamination swipe survey techniques were susceptible to cross contamination and overestimating contamination levels, which could result in unnecessarily delaying OSC response teams in the fiel The inspectors noted that the three discrepancies listed above were not identified by the licensee at their initial drill critique. The inspectors then discussed these .-

issues with drill cor. trollers to ensure they were identified for resolutio Realism and interaction between the control room and other ERO facilities was limited due to use of an NSS office as a control room and assigning controllers to-act as both controller and control room player. The office was crowded with drill players / controllers, observers, and on-duty shift personnel. The drill was not designed to exercise a control room operating crew; the Director-EP Planning stated that operating crew training in emergency procedures was accomplished in the simulator, inspectors noted, however, that the benefits of integrated training of the operating crew with the rest of the ERO were los The OSC activation checklist does not define minimum staffing requirements to support activation. This could result in providing TSC with a false indication of readiness and capability if staffing from appropriate maintenance disciplines is not presen The turnover between the Emergency Director and Emergency Recovery Manager was interrupted by public affairs staff to get two news releases approve Problems were nohd with communications equipment in many locations, particularly during the September 9 drill. Some headsets and phone lines did not work properly. The site page anncuncements were not heard in the TSC and EOF for much of the drill. Some communications from the sito to the JPIC were slow or incorrect. Communications were improved for the September 16 dril Site procedures were unclear regarding handling fatalities and ascociated responsibilities for notification t

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Dnll weaknesses for timely initial notifications and for response to injured personnel /f atalities were dNumented on Condition Reports 971737 and 971736, respectivel !nspectors also reviewed the EP Department "1997 EPP Mini-Drill Critique Report,"

letter NPD3DEP:2284, aated October 9,1997. The licensee satisfied all drill objectives except, " demonstrate the ability to perform timely and accurate emergency classification notifications (from the Control Room) to appropriate State and County agencies per EPP/IP 1.1." The report provided a good summary of exercise strengths, weaknesses, and recommendation Conclusions inspectors assessed that the EP drills provided satisfactory training for the emergency response organization. There was a good focus on orienting new staff to their duties and responsibilities and developing a smooth information flow path 3 within the ERO, and familiarizing staff with the communications and assessment equipment in the emergency response facilities. The post-drill facility and controller critiques were thorough and there was good participation from alllevels of the staf Strengths were identified for reinforcement and weaknesses were noted for further evaluation and improvemen P8 Miscellaneous EP issues (92904)

P (Closed) Unresolved item 50 334 and 412/96-05-03: Implementation of media training was inconsistent with the EP Pla EP Plan Section 8.1.2.f, Rev.7, stated that, " Major news organizations...will be invited annually to attend or receive training." In practice, the licensee mailed information packets to local news mrAia offices annually and conducted biennial training in local media offices instead of inviting media representatives to the site as stated in the EP Plan. The licensee committed to correcting the discrepancy and to completing a comprehensive review of the EP Plan to identify any other inconsistencie The licensee review identified four additional discrepancies in the EP Plan, inspectors reviewed the additional discrepancies (licensee EP Tracking List items 96-72,73,74, and 75) and assessed that they were minor in natur The media training inconsistency and the four additional discrepancies were corrected by Revision 8 to the EP Plan, dated September 20,1996, as documented on EP Section letter NPD3DEP:2099. The EP Plan was changed to state that,

" Major news organizations...will be provided information annually." In addition, the licensee EP Section provided training as requested by local news agencie Inspectors reviewed the EP Han change and discussed current practices with EP management end assessed that the licensee was in compliance with the EP Pla . - . . _ - . ._ .- . - - ..

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10 CFR 50, Appendix E, Section F.1, requires that, "...a radiological orientation training program shall be made available to... local news media persons." Failure to comply with the EP Plan as stated prior to Revision 8 constitutes a violation of minor significance and is being treated as a Non-Cited Violation consistent with Section IV of the NRC Enforcement Policy (NCV 50 334 and 412/97-07 06).

P8.2 - (Closed) Insoection Follow uo item flFl) 50-334 and 412/94-81-04: Weak process for ERO staffing and weak surveillance test for ERO call-ou The item was previously discussed in NRC Inspection Report 50-334 and 412/96-05, Section P8.2, and was open pending review of licensee procedure changes to provide an accountability mechanism to ensure that inanagement expectations regarding the responsibilities of beeper holders were me !nspectors reviewed Administrative Procedure EP-5, "1/20ST-57.1, Review and Trending," Rev. 5, dated March 27,1997, which described the accountability mechanism for beeper holders. Briefly stated, all beeper holder responses to the

6tiodic emergency beeper notification system surveillance test were tracke Individuals who failed to respond to a test were required to provide an explanation for their non-response. Personnel who provided unsatisfactory responses were trended over the next three tests. Continued failure to respond resulted in a graduated escalation of review from the Supervisor, Onsite EP, to the Division Vice President, inspectors discussed the procedure with EP management and reviewed the current response trends. Inspectors assessed that the accountability l mechanism was satisfactory to ensure that management expectations were met.

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The IFl is close P8.3 (Closed) IFI 50 334 and 412/96-01-01: Control Room staffing during emergency-event During the graded, biennial EP exercise conducted on February 27,1996, inspectors believed that control room exercise participants were overburdened during the fire brigade response, which involved two of the four licensed control room operator Shift staffing should always be at a sufficient level to accomplish necessary

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functions during an emergency even Operations management reviewed the issue and concurred. Special Operating Order l 1/2-96 04 was issued on July 31,1996, requiring that, "During an event requiring l fire brigade response, the control room licer' sod staff (NSS, ANSS. RO, PO) at the

affected unit will remain in the control room. The position of brigade chief will be filled by the unaffected unit's ANSS (Assistant Nuclear Shift Supervisor)..."

Operators from the affected unit were assigned as assistant chief and brigade captain. The ANSS logs were subsequently changed to ref'ect the new Emergency Squad organization and unit affiliation of the members. The change in fire emergency expected response was provided to a!! operations personnel in an operations department memo dated August 6,1996. Inspectors reviewed the changes to the fire brigade and assessed that the licensee adequately addressed the concern of depleting the control room staff during a fire response. The IFl is closed.

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P8.4 (Closed) IFl 50-334 and 412/96-01-07,: Technical assessment of accident conditions by TSC staf During the graded, biennial EP exercise conducted on February 27,1996, inspectors noted the inability of the TSC staff to prioritize and resolve technical issues in a timely manner. In particular, the engineering staff lacked a clear understanding of the reactor vessellevelindication system (RVLIS).

Inspectors discussed the issue with EP staff and reviewed the following documentation:

(1) RVLIS Review Lesson Plan LP-EP-RVLIS2, dated March 24,1997, (2) RVLIS Study Guide, explaining the operation cf RVLIS and its use in the emergency operating procedures (EOPs), dated June 14,1996,and subsequent study guide follow ups, (3) EM 111845, correlating RVLIS full range indication to vessel height, (4) EP RVLIS Training Lesson Plan LP-EP-RVLIS1, dated March 21,1997, to provide EP core damage assessment training to engineering coordinators, nuclear / thermal engineers, and mechanical engineers, (5) EP letter NPD3DEP:2073, dated August 9,1996, to information Services Section to correct misidentified RVLIS computer points in the Plant Monitoring System, and (6) applicable EOP and operating manual changes to incorporate the RVLIS informatio Inspectors also observed TSC engineering staff assessment of core inventory using the revised RVLIS guidance during the EP drills conducted on September 9 and 16, 1997. No difficulties were noted. In addition, inspectors observed good prioritization and resolution of technical issues by the TSC during the drills. Overall TSC activities, maintenance activities, and enginee<ing activities were clearly prioritized and tracked on status boards. Engineering staff were sensitive to monitoring core status as well as providing support for emergent equipment issue This IFl is close L1 Review of FSAR Commitments A recent discovery of a licensee operating their f acility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that compared plant prectices, procedures and/or parameters to the UFSAR descriptio While performing the inspections discussed in this report, the inspectors reviewed the applicable parts of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameters, with the exceptions discussed in Section E I l

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! V. Manaaemp.pt Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to niembers of licensee management at the conclusion of the inspection on October 14,1997. The licenses acknowledged the findings presente '

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The inspectors asked the licensee whether any materials exarnined during the inspection should be considtsred proprietary. No proprietary information was identified.

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PARTIAL LIST OF PERSONS CONTACTED P1C R. LeGrand, Vice President, Nuclear Operations / Plant Manager S. Jain, Vice President, Nuclear Services K. Ostrowski, Manager. Quality Servicea Unit B. Tuite, General Manager, Nuclear Operations R. Hansen, General Manager, Maintenance Programs Unit R. Vento. Manager, Health Physics D. Orndorf, Manager, Chemistry J. Macdonald, Manager, System & Performance Engineering K. Beatty, Generai !,ianager, Nuclear Support Unit J. Arias, Dir*Mor, Safety & Licensing W. Kline, Manager, Nuclear Engineering Department R. Brosi, Manager, Management Services O. Arredondo, Manager, Nuclear Procuremen?

URG D. Kern, SRI G. Dentel, RI F. Lyon, RI M. Hart, NRC Intern

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I INSPECTION PROCEDURES USED I

IP 37551: Onsite Engineering IP 40500: Effectiveness of Licensee Controls in identifying, Resolving, and Preventing Problems IP 61726: Surveillance Observation IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support IP 90712: In Office Revie u of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92700: Onsite Review of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901: Follow-up - Operations IP 92902: Follow-up - Engineering IP 92903: Follo'n-up - Msintenance IP 92904: Follow-up - Plant Support t

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ITEMS OPENED, CLOSED AND DISCUSSED

999D94 50-334&412/97-07 01 URI Retired Equipment Program (Section O3.1)

50 334/97-07-02 VIO 10 CFR 50.54(a)(3) Failure to Obtain NRC Approval Prior to Reduction in OA Program Commitments-Procurement QC Function (Section 07.2)

50-412/97-07-03 eel 10 CFR 50 Appandix B Critorion XVI Correction Actions

- Failure to Prevent Recurrence of Gas Binding of tbs High Head Safety injection Pumps (Section E2.2)

50-334&412/97-07-04 URI Adequacy of the High Head Safety injection Surveillance Test to Ensure Operability (Section E2.2)

Qoened/ Closed 50-412/97-07-05 NCV Failure to Perform and Retain 10 CFR 50.59 Safety Evaluations for Heavy load Lift Program Revisions (Section E8,1)

50 334&412/97-07-06 NCV Implementation of Media Training inconsisten+ With the EP Plan (Section P8.1)

Closed 50-334&412/96 09-03 URI Heavy Load Lift Program, Failure to Update FSAR and Indeterminate 50.59 Evaluations (Section E8.1)

50-334/97-024 LER Failure of Refueling Water Storage Tank Level Transmitter Leads to Entry into TS 3.0.3 (Section 08.1)

50-334/97-025 LER Ground in Feedwater Flow Controller Results in High Steam Generator Level and Subsequent Turbine Trip / Reactor Trip (Section 08.2)

50 334/97-016 01 LFR Unit 1 Shutdown Required by TS 3.0.3 Due to Inoperable Steam Generator Low-Low Level Reactor Protection System Trip (Section 08.3)

50-334/97-005-02 LhR Inadvertent Operation of 345 KV Bus Backup Timer Relay Results in Dual Unit Reactor Trips (Section 08.4)

50-334&412/96-05-03 URI implementation of Media Training Inconsistent With the EP Pla- lo8.1)

50 334&412/94-81-04 IFl Weak Process for ERO Staffing and Weak Surveillanco Test for ERO Call-Out (Section P8.2)

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50-334&412/96-01-01 IFl Control Room Staffing During Emergency Events (Section P8.3)

50-334&412/96-01-02 IFl Technical Assessment of Act,ident Conditions by TSC Staff (Section P8.4)

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flST OF ACRONYL OSED ANSS Assistant Nuclear Shift Supervisor AOP Abnormal Operating Procedure BCO Basis for Continued Operation BVPS Beaver Valley Power Station CATS Commitment Action Tracking System CR Condition Report CP.PA Condition Report Program Administr ator DLC Duquesne Light Company DRP Digital Rod Position DRPl Digital Rod Positica Indication EDG Emergency Diesel Generator EOC Extent of Condition EOF Emergency Operations Facility EOP Emergency Operating Procedure ERO Emergency Response Organization FME Tore'gn i.*Nerial Exclusion gpm Gallons Per Minute l&C instrumentation & Control ICCM Inadequate Core Cooling Monitor IFl Inspection Follow-up Item IOER fndustry Operating Experience Review IR12 Unit 112th Ret eling Outage ISEG Independent Safety Evaluation JPIC J9 int Public Information Center MOP Mini,num Operating Point MPUAM Maintenance Program Unit Administration Manual MSP Maintenance Surveillance Procedure MWR Maintenance Work Request NCV Nancited Violation NPDAP Nuclear Power Division Administrative Procedure NSAL Nuclear Safety Advisory Le:ter NSU Nuclear Shift Department NSRb Nuclear Safety Review board NSS Nuclear Shift Supervisor OSC Operations Safety Committee ORC Offsite Review Committee OSC Onsite Safety Committee OSC Operations Suppurt Center OST Operational Surveillance Test PMP Preventive Maintenance Procedure PMP Post Maintenance Testing PO Plant Operator PZR Pressurizer QA Quality Assurance QC Ouality Control OSU Quality Service Unit l

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41 R Reactor Operator ROC Radiological Operations Center RVLIS Reactor Vessel Level Indication System SPED System Performance Engineering Department SSST System Station Service Transformer TOP- Temporary Operating Procedure TS - Technical Specification TSC Technical Support Center UFSAR Updated Final Safety Analysis Report

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URI Unresolved item USST Unit Station Service Transformer UT Ultrasonic Test VCT Volume Control Tank PORV Pressurizer Power Operated Relieve Valve

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v t e Inspection Report - Beaver Valley - 1997007
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \|
1997 Quarterly Integrated 1Q (0) 2Q (0) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle 7(0) 9(0) 10(0) 11(0) Security Operator Exams Emergency Planning Other

IR 05000334/1997007

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