ML20151Z323

Insp Repts 50-334/98-04 & 50-412/98-04 on 980628-0815. Violation Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20151Z323
Person / Time
Site:	Beaver Valley
Issue date:	09/15/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20151Z313	List: ML20151Z310 ML20151Z318 ML20151Z323
References
50-334-98-04, 50-334-98-4, 50-412-98-04, 50-412-98-4, NUDOCS 9809210284
Download: ML20151Z323 (58)

See also: IR 05000334/1998004

Text

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U. S. NUCLEAR REGULATORY COMMISSION

REGION 1

License Nos. DPR-66, NPF-73

Report Nos. 50-334/98-04,50-412/98-04

Docket Nos. 50-334,50-412

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Licensee: Duquesne Light Company (DLC) i

Post Office Box 4

Shippingport, PA 15077

Facility: Beaver Valley Power Station, Units 1 and 2 i

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Insperin Period: June 28,1998, through August 15,1998

Inspectors: D. Kern, Senior Resident inspector

G. Dentel, Resident inspector

G. Wertz, Resident inspector  !

E. King, Emergency Preparedness / Safeguards Specialist

J. Furia, Senior Radiation Specialist

J. Laughlin, Resident inspector

D. Brinkman, Senior Project Manager, NRR

J. Brand, Resident inspector

K. Kolaczyk, Mechanical Engineering Specialist  ;

J. Trapp, Senior Risk Analyst  ;

M. Ferdas, Reactor Engineer -

S. Hansell, Resident inspector

Approved by: P. Eselgroth, Chief i

Reactor Projects Branch 7

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ADOCK 05000334

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EXECUTIVE SUMMARY

Beaver Valley Power Station, Units 1 & 2

NRC Inspection Report 50-334/98-04& 50-412/98-04

- This integrated inspection included aspects of licensee operations, engineering,

i maintenance, and plant support. The report covers a 7-week period of resident inspection.

In addition, it includes the results of announced inspections by regional security and

radiological protection specialist inspectors.

Ooerations

• Command and c,ontrol prior to and during the August 11, Unit 1 reactor startup

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were good. The prestartup containment walkdown as well as the preevolution

l briefing for startup were comprehensive. Maintenance personnel responded

promptly and effectively coordinated with operations personnel to resolve concerns

regarding instrument indications. (Section 01.2)

L * On August 11, Unit 1 tripped from 24% reactor power due to a steam generator

(SG) level transient experienced while transferring feedwater flow control from the

bypass feedwater regulating valve (FRV) to the main FRV. Prior to the trip, I

operators did not fully discuss and recognize the effects of placing a failed steam

flow instrument in trip, which enabled the reactor to trip at a higher SG water level.

Operators responded properly to the reactor trip. (Section 01.3)

o -* The post trip critique and event response team report identified several important "

causes and corrective actions for the trip. The inspectors identified several

information gathering / assessment deficiencies, including the lack of recommended

actions to improve steam generator level control during subsequent feedwater

regulating valve transfer evolutions. Plant management took appropriate actions to

address these concerns prior to authorizing plant restart. Operating crew seminars,

conducted prior to unit restart, effectively focussed on crew awareness and

communications. (Secticn 01.4)

• The licensee developed and implemented a Unit 1 Restart Action Plan (RAP) to

provide assurance that known conditions adverse to quality were corrected and that l

personnel, processes, and equipment were ready for unit restart. Corrective actions )

to address weaknesses in Technical Specification compliance were comprehensive.  !

The RAP and its implementation were appropriate to address the root causes for the )

extended forced unit outage. (Section 07.1)

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Maintenance

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• A design change to modify the Unit 1480 Volt emergency bus under voltage relay

scheme was implemented correctly. The maintenance personnel performing the

work were knowledgeable and appropriately briefed. Missing motor control center

panel fasteners were identified by the maintenance crew and properly dispositioned

by the site staff. The infrequently performed test or evolution briefing was

professional, notwithstanding two minor deficiencies. (Section M1.1)

• Human performance errors continued to impact plant operations. Maintenance

personnel failed to adhere to procedures for configuration control and work control

when attempting to resolve excessive packing leakage on the Unit 1 turbine driven

auxiliary feedwater pump. These actions delayed pump restoration by twenty-two

hours. (Section M1.2)

• The current Fix-it-Now (FIN) team current work scope and volume was relatively  ;

low. FIN team maintenance work performance was methodical and good self l

checking and radiological control practices were noted. (Section M1.3)

o Maintenance on safety related check valves to correct a motion binding issue was

properly performed and supervised. (Section M1.4)

Enaineerina

• The licensee identified binding issues associated with thirty Unit 2 check valves.

Causal analysis for this issue during the last refueling outage was incomplete, which

contributed to several additional failures occurring during this outage. Although the

va!ves affected multiple safety systems, the safety significance was low due to

redundant, diverse isolation valves for each of the check valves affected. Licensee

investigation, root cause analysis, quality controls, and corrective action during this

period were comprehensive. (Section E1.1)

• System and Performance Engineering Department personnel developed a systematic

and comprehensive process to evaluate system status and readiness. System

engineers were knowledgeable and consistent in their implementation of the

required system health reviews, providing appropriate recommendations to station

management regarding readiness for Unit 1 restart. Insights gained during the

system health reviews were shared with appropriate departments for

implementation. (Section E2.1)

• In response to an NRC violation, the licensee performed an extent of condition

review which identified numerous design issues for which the TSs were non-

conservative. Appropriate corrective actions including interim administrative

controls, development of TS amendment requests, and process revisions to ensure

the facility is operated within its design basis were established. Interdepartmental

coordination and the quality of engineering work to resolve the issues were

excellent. The safety significance of the design issues was low and the licensee

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- correctly determined that Unit 1 could restart prior receiving TS amendment

approval from the NRC for the subject issues. (Section E8.1)

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i Plant Suonort

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• ' . The program for the control of contaminated materials and equipment was effective.  !

The licensee appropriately identified and maintained records of spills and other j

occurrences as required under 10 CFR 50.75(g)(1). (Section R1) i

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• - The program for identifying and tracking hot spots, and shielding to reduce j

occupational exposures was effectively implemented. The Unit 1 refueling outage  ;

in 1997 (1R12) was completed with the lowest total dose in unit history. (Section l

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• . Records of occupational exposures were appropriately maintained in accordance

with.10 CFR 20. (Section R1)

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• The annual radworker training program, using a mock-up facility, was effective.  !

(Section R5) I

' * - . Security and safeguards activities were conducted in a manner that protected public ,

health and safety in the areas of access authorization, alarm stations, i

communications, and protected area access control of personnel and packages.  ;

(Section S1)

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• - Security facilities and equipment in the areas of protected area assessment aids,

protected area detection aids, personnel search equipment, and illumination and

- surveillance hardware were well maintained and reliable. (Section S2)

-* Security force members adequately demonstrated that they had the requisite

l~ knowledge necessary to effectively implement the duties and responsibilities

associated with their position. Security force personnel were trained in accordance

! with the requiremer of.the Training and Qualificaitons Plan and training

i documentation was y iperly maintained and accurate. (Sectfons S4 and S5)

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• Management support was adequate to ensure effective implementation of the

security program, and was evidenced by adequate staffing' levels and the allocations

of resources to support programmatic needs. (Section S0)

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• Audits of the security program were comprehensive in scope and depth, audit  ;

y findings were reported to the appropriate level of management, and the program j

h was properly administered. In addition, a review of the documentation applicable to  ;

the self-assessment program indicated that the program was effectively I

implemented to identify and resolve potential weaknesses. (Section S7) l

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TABLE OF CONTENTS

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EX EC UTIVE S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii

TA B LE O F CO NT ENT S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . v

1. Operations .................................................... 1

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

01.1 General Comments (71707) ........................... 1

01.2 Unit 1 Reactor Startup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

01.3 U nit 1 R e a ctor Trip . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

01.4 Unit 1 Reactor Trip Evaluation and Restart ................. 4

07 Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6

07.1 Assessment of Unit 1 Restart Action Plan implementation . . . . . . 6

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

08.1 Inspector Review of Independent Plant Assessment (71707) ... 11

11. M a i nt e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

M1.1 Modification to Unit 1480 Volt Emergency Bus Under Voltage Relay

Scheme ........................................ 11

M1.2 Improper Response to Unit 1 Excessive Turbine Driven Auxiliary J

Feedwater (AFW) Pump Packing Leakage . . . . . . . . . . . . . . . . . 12

M1.3 : Beave Valley Fix-It-Now (FIN) Maintenance Process . . . . . . . . . 14

M1.4 Check Valve Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

111. E n g i n e e ri n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

E1.1 Check Valve Binding ............................... 15

E2 Engineering Support of Facilities and Equipment ................. 18

E2.1 Unit 1 System Health Reviews for Restart ................ 18

E8 Misce!!aneous Engineering Issues ........................... 19

E8.1 (Closed) eel 50-334(412)/98-03-05 . . . . . . . . . . . . . . . . . . . . . 19

E8.2 (Closed) LER 5 0-412/9 7-01 1 . . . . . . . . . . . . . . . . . . . . . . . . . . 22

I V . Pl a nt S u p po rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 22

R5 Staf f Training and Qualification in RP&C . . . . . . . . . . . . . . . . . . . . . . . 24

S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 25

S2 Status of Security Facilities and Equiprnent . . . . . . . . . . . . . . . . . . . . . 26

S3 Security and Safeguards Procedures and Documentation . . . . . . . . . . . 27

S4 Security and Safeguards Staff Knowledge and Performance . . . . . . . . . 28

S5 Security and Safeguards Staff Training and Qualiiication . . . . . . . . . . . 28

S6. Security Organization and Administration . . . . . . . . . . . . . . . . . . . . . . 29

S7 Quality Assurance in Security and Safeguards Activities ........... 29

V. M a n a g e m e nt M e e ting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

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X1 Exit Meeting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

l X2 Management Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

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l PARTIAL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

l INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 3 3

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! ITEMS OPENED, CLOSED AND DISCUSSED . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . 34

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LIST O F ACRONYM S U SED . . . . . . . . . . . . . . . . . . . . . . ' . . . . . . . . . . . . . . . . . . . 35

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L Report Details

Summarv of Plant Status ,

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l Unit 1 began the inspection penod in cold shutdown (Mode 5). The plant entered hot

shutdown (Mode 4) on August 6 and synchronized to the grid on August 11. This

completed a 192 day forced outage during which numerous technical specification (TS)

surveillance testing and design issues were corrected. The plant experienced a reactor trip

on August 11 at 3:12 p.m. due to "A" Steam Generator (SG) low water level coincident

with steam flow and feedflow mismatch while attempting to place the main feedwater

regulating valves (FRVs)in service. Unit 1 restarted and synchronized to the grid on

August 15.

Unit 2 remained in Mode 5 throughout this inspection period in order to correct

longstanding design discrepancies and to resolve various TS limiting condition of operation

(LCO) and surveillance testing issues. Major work involved a detailed review of the current

licensing basis to validate TS and surveillance requirements compliance, steam generator

tube inspections, and repairs to various check valves. (Section E1.1)

1. Operations I

01 Conduct of Operations

01.1 General Comments (71707)  !

The inspectors conducted reviews of ongoing plant operations. In general, the

conduct of operations was professional and safety-conscious. Specific events and

noteworthy observations are detailed in the sections below, in particular, the

inspectors noticed good plant and system knowledge by the Nuclear Operators (NO)

while performing their plant rounds and prompt resolution of NRC identified

deficiencies.

01.2 Unit 1 Reactor Startuo

a. inspection Scope (71707)

On August 11,1998, the inspectors observed Unit 1 reactor startup activities from

the main control room. The review included the completion of the startup

requirements contained in operation procedure 10M-50.4.D(ISS3)," Reactor Startup

from Mode 3 to Mode 2," Rev. 31, achievement of reactor criticality, and unit

synchronization to the grid,

b. Observations and Findinos

! The operations crew was professional and very knowledgeable of plant equipment

status. Station personnel conducted a thorough equipment walkdown inside

containment after pressurizing the reactor coolant system. Minor discrepancies

were identified and properly corrected. The Nuclear Shift Supervisor (NSS)

performed a detailed briefing prior to the mode change and the start of control rod

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withdrawal to criticality. The briefing included a review of all applicable

precautions, limitations, and a clear standard for reactivity management. The

reactor engineer provided a good overview of the estimated critical position for the

reactor startup.

The NSS and assistant NSS demonstrated noteworthy command and control

throughout the reactor startup. The startup requirements were completed after

thorough evaluation and the evolution was conducted at a controlled pace. Crew

communications and the use of proper repeat backs were evident for the entire

startup. Senior plant management provided proper oversight for the back shift

evolution. An additional reactor operator and senior reactor operator were assigned

to control room duties to assist the normal crew. Control room distractions were

minimized with the exception of a nuisance alarm related to a reactor coolant pump

temperature recorder. The reactor achieved criticality at 7:15 a.m.

Control room operators carefully observed feedwater flow and steam flow

indications during power ascension from 5% to 15% reactor power. Several

channels of this instrumentation were slow to indicate flow at this low power level.

While this is not uncommon at low power levels, operators requested

instrumentation and control technicians to investigate the indications to confirm

whether they were providing appropriate signals. Technicians confirmed that "A"

SG steam flow channel IV instrument (F-MS-475) had failed downscale due to a

failed signalisolator. Operators properly declared the irestrument inoperable and

entered the TS 3.3.1.1 Limiting Condition of Operation (LCO) which permits

continued power operation provided that the instrument is fixed or its protection

signal bistable is placed in the trip position within the following six hours.

The main turbine was synchronized to the grid at 1:13 p.m. The inspectors noted

excellent communications among the operating crew. The shift technical advisor

demonstrated close teamwork with the reactor operator as he alerted the crew to

the initiation of a minor reactor coolant system (RCS) pressure transient as turbine

load was increased.

c. Conclusions

Command and control prior to and during the August 11, Unit 1 reactor startup

were notable. The prestartup containment walkdown as well as the preevolution

briefing for startup were comprehensive. Maintenance personnel responded

promptly and effectively coordinated with operations personnel to resolve concerns

regarding instrument indications.

01.3 Unit 1 Reactor Trio

a. Insoection Scoce (71707)

On August 11, approximately two hours after being placed on-line, the Unit 1

reactor tripped. The inspectors responded to the control roorn, interviewed

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personnel, reviewed station records, and observed licensee activities to assess the

cause of the trip and operator response to the trip.

b. Obsecrations and Findinas

Steam flow instrument F-MS-475 failed at 12:40 p.m. (see Section 0.1.2), with the

reactor at 15% power and the main turbine off-line. This instrument provides a

signal to one of two channels of the steam flow /feedwater flow mismatch

coincident with low SG level reactor trip protection logic. This trip function is

designed as a preemptive protection action and is not credited in the station

accident analysis. While technicians prepared a correct lve maintenance work

package the NSS directed that the main turbine be placed on-line and reactor power

was stabilized at 24%.

Technicians informed the NSS that instrument repairs would not be complete prior

to expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> TS 3.3.1.1 LCO action time. The NSS directed

technicians to place the instrument bistable in trip. Immediately prior to placing the

bistable in trip, the "A" SG level was stable at 44%, with level being controlled by

the bypass feedwater regulating valve (FRV). The next planned activity was to

transfer feedwater flow control from the bypass FRV to the main FRV. This transfer  !

typically results in some amount of SG level fluctuation as control is shifted to the '

main FRV. The NSS had previously informed the inspectors that F-MS-475 would

be placed in trip later within the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> LCO period, when the plant was stable. The

inspectors questioned the NSS regarding whether placing the instrument bistable in

trip now, prior to transferring feedwater control to the main FRVs, was prudent. ,

The NSS stated that he believed this action was appropriate since it places the j

instrument in a safe condition (protective signal active) and the repairs would not be

complete within the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> LCO period. At 2:40 p.m., technicians piaced the F-MS- )

475 bistable in trip which inserted one of the two trip signals necessary for the

reactor trip function to actuate. The remaining signal necessary for a reactor trip

was a low "A" SG level signal at 25% narrow range level. Without this bistable in

trip, the reactor would not receive a trip signal based on SG level, until reaching the

low-low SG level trip setpoint of 15%. Based on subsequent interviews, the

inspectors determined that operators were aware of the 25% level trip setpoint.

Shortly after placing F-MS-475 in trip, operators transferred "A" SG level control

from the bypass FRV to the main FRV. "A" SG levellowered as the main FRV was

slower to ope 7 than operators had anticipated. Operators had not been pre-briefed

that the gain adjust for the "A" main FRV had been adjusted to slow valve response

following the last reactor startup in January 1998. Operators were unable to

restore SG level prior to receiving a reactor trip at 3:12 p.m. Operators properly

responded to the reactor trip and the subsequent RCS cooldown. Prompt operator

actions included manualisolation of the main steam isolation valves, isolation of the

RCS letdown system, and manual alignment of the charging pump suction to the

refueling water storage tank. Operators properly reported the automatic reactor trip

as required by 10 CFR 50.72.

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c. Conclusions

y . .On. August 11, Unit 1 tripped from 24% reactor power due to a steam generator

l' (SG) level transient experienced while transferring feedwater flow control from the

bypass feedwater regulating valve (FRV) to the main FRV. Prior to the trip,

operators did not fully discuss and recognize the affects of placing a failed steam

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flow instrument in trip, which enabled the reactor to trip at a higher SG water level.

' Operators responded properly to th i reactor trip.

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01.4 Unit 1 ' Reactor Trio Evaluation and Restart

a. Inspection Scope (71707. 92901)

The inspectors' attended the post trip critique and reviewed the event response team

(ERT) report to evaluate licensee assessment of the trip and actions taken to

preclude recurrence,

b. Observations and Findinos

. The acting General Manager of Nuclear Operations (GMNO) conducted a post trip.

critique, one hour after the trip.'The inspectors noted that written statements were

obtained and personnel freely responded to questions. However, the inspectors

also observed deficiencies during the critique. Some questions (e.g., regarding main

FRV control signals and valve position) were asked and responded to in a general

nature rather than detailed specifics, in some cases the responses were provided -

by personnel who were not present in the control room, based on what they

expected to occur rather than what was witnessed. Additionally, several

departments who would typically be represented at a post trip critique, were not

notified of the meeting. The inspectors noted that while not required, use of the

newly established critique process described in NPDAP 5.10, " Conduct of Critiques

and Multi-Discipline Analysis Team investigations," Rev.- O, would have provided the

. structure to preclude these deficiencies. The inspectors discussed these

observations with the acting GMNO and the plant manager. The plant manager had

similar observations and assigned actions to reevaluate the post trip review process.

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An ERT was established to investigate the trip and provide associated i

recommendations to plant management prior to unit restart. The inspectors

observed the ERT report presentation to the Nuclear Safety Review Board (NSRB). i

The report provided a detailed review of equipment response and causal factors.  !

The primary cause of the trip was determined to be cognitive error by the shift

crew, failure to fully recognize and respond to the tripping of the steam

. flow /feedwater flow mismatch bistables enabling a reactor trip to occur at a higher

SG level. Specifically, the operating crew did not stop and verbalize the fact that ,

they would now have a much smaller margin between operating SG level and the l

protective trip prior to transferring FRV control. Appropriate recommendations were  !

L ' made to address this root cause. Senior plant management conducted additional l

l operating crew seminars, pnor to each shift, to emphasize crew awareness and

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communications. The inspectors noted that the selection of visual aids and scenario

examples was outstanding.

The NSRB endorsed the ERT findings and recommended additionallong term actions

to evaluate the FRV control design to determine whether improvements could be

made which would limit the magnitude of SG level transients. While these

recommendations were appropriate, the inspectors observed that no action had

been completed or assigned which would directly improve the operator's ability to

minimize the SG level transient associated with transferring from the bypass FRV to

the main FRV on the subsequent reactor startup. The NSRB accepted the condition

that SG level may change 10-20% during this evolution. The inspectors questioned

this performance and asked whether the NSRB had taken sufficient action to

preclude a repeat of the reactor trip. The burden on operations personnel, created

by the SG level transient while transferring FRV control, had not been addressed.

The NSRB chairman responded to the inspectors' comments by directing the acting

GMNO to evaluate options to improve SG level control during the FRV transfer

evolution prior to reactor restart.

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Operations, engineering, maintenance, and training personnel worked closely

together and revised the procedure for transferring FRV control. This new method

was presented to the NSRB in a subsequent meeting along with the identification of

an additional steam flow transmitter that had failed during the trip. The steam flow

transmitter failure had been overlooked by the ERT, but was subsequently identified  !

by system engineers and corrected prior to reactor startup. Operators were properly )

trained on the revised FRV transfer procedure. Operators noted much improved SG l

level control during the next FRV transfer on August 16. The transient was

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approximately 5-8% level deviation in place of the 20% deviation experienced on  !

August 11. The plant manager met with the inspectors to discuss several potential

areas of improvement identified by the plant manager during August 10-16.

c. Conclusions

The post trip critique and event response team report identified several important

causes and corrective actions for the trip. Yet the inspectors identified several

information gathering / assessment deficiencies, including the lack of recommended

actions to improve steam generator level control during subsequent feedwater

regulating valve (FRV) transfer evolutions. Plant management took appropriate l

actions to address these concerns prior to authorizing plant restart. Operating crew

seminars, conducted prior to unit restart, effectively focussed on crew awareness

and communications.

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07 Quality Assurance in Operations

07.1 Assessment of Unit 1 Restart Action Plan implementation

a. insoection Scope (71707. 37551)

The 'icensee developed and implemented a Unit 1 Restart Action Plan (RAP) to

pr; lo assurance that known conditions adverse to quality were corrected and that

personnel, processes, and equipment were ready for unit restart. The RAP

contained 65 individual action items, each of which was identified for completion

prior to one or more restart milestones (e.g., reactor coolant system pressurization,

Mode 4, Mode 2, and 30% reactor power). The action items were subdivided into

tiie areas of process and program enhancements (P), culture enhancements (C), self

assessments (S), plant material condition (M), and management oversight (O). The

NRC formed a Beaver Valley Oversight Panel (BVOP) to provide inspection oversight l

regarding licensee readiness for unit restart. The inspectors reviewed the RAP,  !

observed licensee actions, interviewed personnel, and reported to the BVOP l

providing assessment of licensee readiness to restart Unit 1.

b. Observations and Findinas

Based on licensee performance during the past year, the BVOP identified five root j

causes associated with problems leading to the extended dual unit shutdown.  ;

- - Deficiencies in site-wide knowledge of TS and Licensing Basis.

- Weaknesses in day-to-day operational activities as a result of poor

communication, control room awareness, and work management

breakdowns. Recognition and resolution of degraded conditions was

inconsistent.

- Poor previous corrective action (prior to January 1997) and operating

experience programs. Many current problems were previously identified, but

not corrected.

- Failure to plan and work activities (maintenance in particular) according to

schedule.

- Low overall performance standards in the past and acceptance of problems.

Based on reviewing the RAP and attending daily restart assessment panel meetings

during which licensee management discussed the status of RAP action items, the

inspectors determined that the RAP and its implementation were appropriate to

address the root causes listed above. The inspectors independently evaluated

licensee implementation, validation, and oversight for the various RAP action items.

Inspector assessment of several RAP action items associated with maintenance or

training are being documented in NRC Inspection Report Nos. 50-334(412)/98-301.

Additional selected inspectors observations are listed below.

RAP Action items S-3. 0-5: TS Compliance

The inspectors reviewed the licensee's root cause analysis and corrective actions

for the programmatic weakness concerning TS compliance. The root cause analysis

was thorough and determined that weaknesses existed in personnel knowledge of

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7

TS, as well as management expectations regarding TS compliance. The inspectors

determined that the scope and implementation of the RAP, combined with station-

wide TS compliance training appropriately addressed the TS compliance issue prior

to Mode 4. Additionally, the Independent Safety Evaluation Group was assigned

the future task of performing an effectiveness review to determine if corrective

actions ht v 5een effective in eliminating TS compliance problems.

RAP Action items P-1. P-2. P-4: Procedures

The inspectors reviewed the licensee's process for ensuring that all necessary

procedure revisions were completed prior to Mode 4. These plans were

appropriately supervised and executed. The inspectors verified that the revisions

were completed by reviewing a representative sample of revised procedures.

Additionally, the inspectors verified that the procedure review and approval process

was revised to ensure that all future procedure revisions were in compliance with

TS. This revision required additional reviews, including a 10 CFR 50.59 applicability i

review for all procedure revisions. The inspectors concluded that these changes

were appropriate to ensure that safety related procedures received the proper level

of review.

RAP Action items S-8. M-3: Condition Reports. Problem Reports, Desian Chanaes

The inspectors reviewed DLC's process for reviewing condition reports, problem

reports, design change packages and corrective actions prior to ascension to Mode

4, and interviewed associated managers to determine the extent and adequacy of

the process. The inspectors con::luded that DLC's efforts were methodical,

thorough, and received the appropriate level of management attention.

RAP Action item M-10: Open Enaineerina Memorandum (EM) Backloa

The inspectors reviewed the actions that were performed to determine if any open

ems constituted a TS operability challenge. The inspectors reviewed the open EM's

list, reviewed a sample of safety related systerns' ems, interviewed three system

engineers and reviewed the documentation prepared for this issue. The inspectors

noted that system engineers had included a review of open ems on their system

health reviews, and that adequate focus was given to the potential aggregate

effects of the issues on their assigned systems. The inspectors concluded the

actions, reviews, and documentation were adequate.

RAP Action item P-17: System Recovery to Ensure Adeauste Fillina & Ventina Of

Systems

The inspectors reviewed the actions performed to ensure adequate filling and

venting of systems prior to returning to service. This action was assigned to

prevent water hammer or gas binding events, such as those previously identified on

the quench spray, high head safety injection, and low head safety injection

systems. The inspectors interviewed the responsible program manager, and

reviewed applicable documentation including training requirements. The inspectors

noted that adequate measures were in place to ensure that draining requirements

were identified in the work package, and that an Operations Department Stai.Jard

had been developed to require filling of drained systems as part of the system

clearance restoration process. Additionally, the licensee has implemented a

.

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8

I

comprehensive void monitoring process, which included procedures and periodic

ultrasonic testing (UT) for void monitoring and prevention. The inspectors

determined that these actions were appropriate to resolve the concern for presence

of gas in safety related systems.

RAP Action item P-26: Troubleshootina Process.

The inspectors reviewed the actions to ensure that troubleshooting activities were

appropriately recognized, prioritized, and tracked to a timely closure. The licensee

developed a new procedure to provide administrative instructions for tracking the

removal of equipment from service and the return equipment to service following

testing or repairs. The procedure revision also included provisions to identify

affected departments and responsible individuals. Additionally, the procedure

established requirements for data collection for root cause analysis, and provided

guidance for definitions of risk levels involved with troubleshooting and established

management approval requirements based on risk. Administrative actions were in

place to ensure that the Equipment Out-Of-Service Form was attached to any

maintenance work requests (MWR) generated for troubleshooting activities, and to

ensure that the MWR remained the controlling document. The inspectors observed

portions of two troubleshooting activities during Unit 1 power ascension. Both

activities were properly controlled. The inspectors concluded that the licenseo

implemented adequate actions to enhance the overall effectiveness of the

troubleshooting process.

RAP Action item P-5: Timeliness of Operability Determinations

On several occasions during the past year, operations department personnel failed

to evaluate degraded conditions in a timely manner. To ensure operability

assessments were timely and conservative, BVPS recently developed Appendix E,

" Operable / Operability Determination of Systems, Structures and Components

(SSC)s," to operation's procedure 1/20M-48.1.1" Technical Specification

Compliance." The new appendix contained guidance that reflected current industry

practice regarding how the operability of equipment was determined and assessed.

For example,1/2OM-481.1 indicated the timeliness of operability determinations

should be commensurate with safety significance. To assess safety significance,

the originator of the operability assessment was instructed to use the allowed

outage times contained in TS. Additionally, consistent with industry practice,

1/2OM-48.1.lindicated equipment operability was dependent on the availability of

support systems.

Training on the new appendix was accomplished by providing a " Required Reading"

package to operation's personnel. BVPS reinforced the training by providing

classroom instruction, and a written test administered during the licensed operator

requalification training program. At the close of the inspection report period, all

licensed operators and licensed operator candidates had completed the required

training. The inspectors determined that Appendix E of 1/20M-48.1.1 provided

adequate guidance to assess the operability of equipment. The training provided to

operators on the new appendix was thorough. Quality Services Unit personnel

identified deficiencies in operations personnel awareness of the new process

. - . . .- - .

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9

following training and appropriately raised this issue to station management for

action.

RAP Action items P-24, P-25: Enaineerina Review and Analysis of Technical

Specification Related items

Between 1994 and 1998 the licensee failed to implement appropriate administrative

controls or requested license amendments for several design issues as discussed in

Section E8.1. Most of these issues were originally processed using technical

evaluation reports (TERs) or ems. As corrective action, the licensee revised NEAP

2.13, " Technical Evaluation Reports," Rev. 5, and NPDAP 2.4, " Engineering

Memoranda," Rev. 7, to ensure that questions or issues associated with compliance

to TS were appropriately recognized, prioritized, and tracked. The revisions

emphasized the need for the preparers of ems and TERs to complete timely reviews I

of issues, which could affect the plant design basis or TS. Further, these changes I

reinforced the need for the preparers of ems and TERs to consider how the analysis

conclusion could affect the plant design basis.

For example, NPDAP 2.4 required the preparers of TERs, to assign a priority code of

one, the highest priority, for evaluations which were needed to determine if the

plant met TS or Updated Final Safety Analysis Report (UFSAR) requirements.

Similarly, procedure NEAP 2.13 indicated, when ems were prepared, evaluators

should consult the TS and UFSAR and determine if the plant design basis needs to

be changed by preparing a safety evaluation.

Based on interviews and reviewing the recent procedure revisions, the inspectors I

determined that NPDAP 2.4 and NEAP 2.13 provided sufficient instruction for  ;

engineers to ensure TS and UFSAR related issues are recognized and adequately I

resolved during the preparation of ems and TERs.

RAP Action item M-8: Temporary Modification Review

The inspectors conducted a review of temporary modifications (TMs) to determine if

TMs individually or collectively represented a challenge to safe operation of Unit 1

or could violate plant TS As on July 28,1998, there were seven TMs installed on J

Unit 1. None of the TMs compensated for the loss of risk significant equipment or

violated plant TS. The inspectors determined that the number and content of the

TMs was reasonable.

RAP Action item P-12. Manaaement Response Team

The inspectors reviewed the charter and implementation of the management

response team (MRT). The MRT charter was completed and contained sufficient

details to properly implement the team. The inspectors questioned whether training

was provided for each MRT member as stated in the restart action plan description.

The plant manager stated the training for MRT members and nuclear shift

supervisors would occur after completion of the item but prior to Mode 4 entry.

The training was conducted and the MRT properly established prior to Mode 4

entry.

. _ . . _ _ _ _ _ _ _ .. _ _ _ _ _ _ __ ._ . _ _ . . _ _

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10

M-5. M-6. Review of Operator Workarounds and Control Room Deficiencies

The inspectors reviewed the Unit 1 operator workarounds and control room

deficiencies to independently assess the impact on the operators. The inspectors

determined that the operator workarounds and control room deficiencies did not

adversely affect operation of the facility. However, the inspectors identified several

additional control room deficiencies that were not currently being tracked. The end

result is these items did not receive the higher priority that control room deficiencies

normally receive. The licensee assigned the fix-it-now manager as the owner of the

control room deficiency list to address the inspectors' concerns. Senior

Management conducted similar control room inspections and identified deficiencies

not tracked on the control room deficiency list. At the close of the report perbd,

the control room deficiency list had been properly updated with work priorities

assigned for each item.

!

RAP Action item B-8: Cumulative Unit 1 Basis for Continued Operation (BCO)

Review

Thirteen BCOs were written prior to restart to assess degraded or non-conforming i

Unit 1 conditions. The inspectors reviewed each BCO and attended the NSRB l

meeting at which the cumulative affect of the BCOs was discussed. The inspe.: tors 1

determined that the rationale for each BCO was technically sound with appropriate

compensatory measures implemented when necessary. The established time limit

for each BCO to be in effect was appropriately developed based on risk insights. ,

Reactor operation with the 13 BCOs in effect did not pora a challenge to reactor i

safety.

i

RAP Action items O-3. O-4: Onsite Safety Committee (OSC) and NSRB Oversicht

The Unit 1 restart manager prepared a restart readiness report listing the status of

each action item and presented the report to the OSC and NSRB prior to Mode 4.

The inspectors observed OSC and NSRB oversight activities, including action

validations and reviews of the report. The inspectors determined that the OSC and

NSRB members demonstrated a questioning perspective throughout their oversight

activities. Following resolution of their questions, both the OSC and NSRB

recommended to the plant manager that the unit was ready for Mode 4 and

subsequent recommendations for power ascension.

c. Conclusions

The licensee developed and implemented a Unit 1 Restart Action Plari (RAP) to

provide assurance that known conditions adverse to quality were corrected and that

personnel, processes, and equipment were ready for unit restart. Corrective actions

to address weaknesses in Technical Specification (TS) compliance were

comprehensive. The RAP and its implementation were appropriate to address the

root causes for the extended forced unit outage.

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08 Miscellaneous Operations issues

08.1 Insoector Review of Indeoendent Plant Assessment (71707)  !

The Industry of Nuclear Power Operations (INPO) performed an independent plant

assessment in August 1997. The INPO assessment findings were documented in

an interim report in October 1997, and a final report issued in May 1998. The

inspectors reviewed the interim report upon issuance, and reviewed the final report  ;

during this report period. The inspectors determined that the INPO plant I

assessment findings were consistent with the performance assessments contained I

in the NRC inspection reports for 1997. No additional NRC regional follow-up j

inspection is planned. l

11. Maintenance

M1 Conduct of Maintenance i

M 1.1 Modification to Unit 1480 Volt Emeraency Bus Under Voltaae Relav Scheme.

a. Insocction Scooe (62707)

The inspectors observed partial performance of design change package (DCP) 2336,

" Unit 1480 Volt Emergency bus Under Voltage Relay Scheme." The inspectors

also observed the infrequently performed tests and evolutions (IPTE) briefing in

accordance with (iaw) site procedure NPDAP 8.23, " Infrequency Performed Tests or

Evolutions," Rev. 3.

b. Observations and Findinas

The IPTE briefing was professional and thorough with the exception that lessons

learned from industry operating experience were omitted. The inspectors

questioned the responsible test manager (RTM) about the omission. The RTM

indicated that he did not have sufficient tirne to obtain any lessons learned

information for the briefing. The IPTE briefing was performed in the control room

just prior to the normal shift briefing. This disrupted the normal shift briefing which

occurred later and with limited shift participation as the crew members with

assignments frorn the IPTE briefing had left to perform their tasks. Both of these

minor issues have been communicated to Operations management.

The temporary operating procedure (TOP); 1 TOP-98-05, was written for installation

of the new relays. The inspectors determined the TOP was complete and accurate

for the work activity being performed. The installation and testing of the new relays

was performed iaw DCP 2336. The DCP involved replacing the 480 volt

undervoltage (UV) relays and relocating the relay's sensing location from the ground

detection potential transformers (pts) to the load pts. The DCP also modified the

wiring of the switch gear to include a " pallet" switch to defeat the UV application of

I the relay when the bus supply breaker is open or racket out. The relay crew spent

the previous week familiarizing themselves with the DCP and were knowledgeable

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12

of the work being performed. The inspectors observed selected portions of the

relay installation and testing and determined the work was properly performed law

the approved DCP. Lifted leads were properly identified,-the work area was clean

and uncluttered, and mobile work carts were properly secured.

The lead technician, in removing a cabi..et panel for access, identified that it was  ;

missing all of its fasteners. He promptly notified his supervisor who initiated a

condition report and MWR to replace the missing fasteners. Other motor control

center panels in both safety divisions were checked and a few missing fasteners ,

were identified and replaced. l

c. Conclusions

A design change to modify the Unit 1480 Volt emergency bus under voltage relay

scheme was implemented correctly. The maintenance personnel performing the

work were knowledgeable and appropriately briefed. Missing motor control center

panel fasteners were identified by the maintenance crew and properly dispositioned

by the site staff. The infrequently performed test or evolution briefing was i

professional, notwithstanding two minor deficiencies. l

!

M1.2 Imorocer Resoonse to Unit 1 Excessive Turbine Driven Auxiliarv Feedwater (AFW)

Pumo Packina Leakaae

a. Insoection Scope (61726)

The inspectors observed the partial performance of 1-OST 24.9, " Turbine Driven

AFW Pump (1-FW-P-2) Operability Test," Rev.19. including observation of the

outboard pump packing leak and corrective measures implemented.

- b. Observations and Findinas

On August 8, the inspectors observed, during the performance of 1-OST 24.9, a

packing leak on the turbine driven AFW pump consisting of both water and steam

vapor. The pump was in service and performance engineers were obtaining

temperature readings from both the inboard and outboard shaft area. The  ;

performance engineers requested maintenance personal to assist in assessment of

the leak. The maintenance supervisor who arrived to support the leak assessment

immediately commenced to open the packing stuffing box supply valve. This is

contrary to the requirements of station procedures 1/20M-48.3.D," Equipment

Administrative Control," Rev.18, which states that permanently installed valves

and equipment will only be operated by personnel of the BVPS Operating Group,

and Maintenance Programs Unit Administrative Manual (MPUAM) Section 4.2,

" Work Order Control," Rev. 7, which states that plant equipment shall not be

manipulated unless procedurally enntrolled by an approved work procedure, a

clearance or a caution tag.

The nuclear operator (NO) supporting the test in the field did not attempt to stop the

maintenance supervisor from manipulating the valve or subsequently adjusting the

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13

packing gland nuts. During the performance run, no operations supervision

observed the leak for assessment purposes. The inspectors determined that

inadequate command and control of this evolution contributed to the maintenance

supervisor's actions.

After three adjustments to the packing supply valve failed to make any improvement

in the leak and steam plum, the maintenance supervisor obtained a pipe wrench that

was lying on the floor and applied torque to the packing gland nuts. This action

was contrary to the requirements of MPUAM Section 4.2, which states that "all

Maintenance related activities to be performed (including troubleshooting) SHALL be

clearly defined by a work order control document..." No change in steam vapor

leakage rate resulted from this action and the pump was subsequently shut down

and later repacked.

The inspectors discussed the two apparent inappropriate actions with the

maintenance supervisor immediately after the event. The supervisor explained that

he took the immediate actions that he did because of his concern for the health of

the pump shaft. The inspectors noted that performance engineers had been

monitoring temperature readings on the pump and were satisfied that the packing

seat-shaft was not overheating. However, the maintenance supervisor didn't

property resolve his concern with the NO or the performance engineers prior to his

actions. These actions by the maintenance supervisor, represented a continuance

of human performance errors as documented in NRC Integrated Inspection Report

Nos. 50-334(412)/98-03.

The inspectors determined that a maintenance supervisor failed to adhere to site

procedures while investigating excessive turbine driven AFW pump packing leakage.

These actions delayed restoration of the safety related pump by twenty-two hours.

The licensee was slow to enter this event in their corrective action program as it

took three days for a condition report to be written. Failure to properly implement

1/20M-48.3.D and MPUAM Section 4.2 violated T.S. 6.8.1.a , which requires that,

" written procedures shall be established, implemented and maintained covering...

the applicable procedures recommended in Appendix "A" of Regulatory Guide 1.33,

Rev. 2, February 1978." (VIO 50-334/98-04-01)

Other portions of the test included observations by the inspectors of the reactor

operator (RO) initiating the surveillance. The operator was knowledgeable of the

test and when he became aware that he could not concurrently start the test and

time a relay needed for the procedure, he appropriately requested a second operator

to provide assistance.

c. Conclusions

, Human performance errors continued to impact plant operations. Maintenance

l personnel failed to adhere to procedures for configuration control and work control

when attempting to resolve excessive packing leakage on the Unit 1 turbine driven

auxiliary feedwater pump. These actions delayed pump restoration by twenty-two

j hours.

__ ... _ _ _. . - - . . ., - - . = - - - .

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14

M1.3 Beaver Vallev Fix-It-Now (FIN) Maintenance Process

a. Insoection Scooe (62707)

The FIN team maintenance process was established to enable workers to complete

minor maintenance items more quickly with less administrative controls than are in

place for larger maintenance items. The licensee has recently proposed revisions to

the FIN process to permit the FIN team to perform additional emergent work items

and thereby reduce the adverse impact that emergent work has on scheduled

maintenance activities. The inspectors reviewed various documents, conducted

interviews, and observed FIN team maintenance activities to assess FIN team

effectiveness.

b. Observations and Findinas

The FIN team maintenance process, procedure guidance, daily meetings and plant

work activities were reviewed by the inspectors. The FIN process written procedure

guidance was referenced in the Maintenance Programs Unit Administrative Manual,

section 4.11, "Fix-It-Now Maintenance Program," Rev 4. The procedure contained

a basic description of the FIN process and contained clear examples of the work

activities that were allowed and not allowed to be performed by the FIN team. The

FIN program implementation was relatively new at Beaver Valley and additional

program enhancements were planned at the time of the report period end date. The

proposed changes were intended to improve the FIN team effectiveness and time

efficiencies.

A daily 9:30 a.m. meeting was held in the FIN work area to review the prior day's

work request tags. The review evaluated each equipment deficiency for the proper

work priority and applicability for FIN work. The FIN team selected work tasks that

were a priority 3 or lower work request, minor maintenance items, jobs with a

duration of 2-3 hours, and short term TS LCO work. Currently the FIN teams do not

work on safety related, EQ, or Appendix "R" work request items.

The inspectors observed FIN team mechanical maintenance personnel during the

performance of four maintenance work request (MWR) job tasks. The jobs were

pre-planned and signed on by the work control senior reactor operator. Radiological

control personnel reviewed the MWRs and coordinated the assistance from a

radiological controls plant technician. The mechanics assembled all of the

equipment and materials to perform the job. The work included the cleaning and

inspection of boric acid leaks on four primary plant motor operated valves. The

mechanics work performance was methodical and good self checking and

radiological control practices were noted. l

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c. Conclusions

The Fix-it-Now (FIN) team current work scope and volume was relatively low. FIN

team maintenance work performance was methodical and good self checking and

radiological control practices were noted.

M1.4 Check Valve Maintenance

a. Insoection Scope (62707. 37551)

In response to weighted arm check valve issues at Unit 2 (see Section E1.1), the

inspectors observed disassembly of 2 SIS *42, examined various disassembled check

valve components and interviewed mechanical maintenance technicians and vendor

representatives.

I

b. Observations and Findinas '

The maintenance was conducted in accordance to maintenance work instructions.

Maintenance workers were generally knowledgeable on the work requirements and

the check valves design. Radiological controls were followed by the maintenance

crews. Radiological controls personnel provided good support. Problems in the

field were properly handled with good supervisor and vendor support.  !

c. Conclusions

Maintenance on safety related check valves to correct a motion binding issue was  ;

properly performed and supervised.

Ill. Enoineerina

E1 Conduct of Engineering

i

E1.1 Check Valve Bindina

a. Inspection Scoce (71707. 37551. 92902. 92700)

The inspectors reviewed licensee's actions in response to binding of various

containment isolation check valves. The inspectors reviewed surveillance tests,

examined check valve components after disassembly, and interviewed system

engineers, mechanical maintenance technicians, and vendor representatives. The  ;

following procedures were reviewed:  !

• 1/2 CMP-75-ATWOOD CHECK-1M, " Repair of Atwood & Morrill Bolted

Bonnet Backweighted Check Valves," Rev. 3

• 2BVT 1.47.11, " Safety injectior, and Charging System Containment

Penetration Valve Integrity Test," Rev. 4

• 2BVT 1.47.5, " Type C Leak Test," Rev. 4

.

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16

• 2BVT 1.47.3, " Containment Isolation Check Valves Test," Rev. 2

• 20ST 11.16, " Leakage Testing RCS Pressure isolation Valves," Rev.10

b. Observations and Findinas

On April 1,1998,2OSS*3 was found to be binding through its entire stroke and

would remain open when released from any open position. The licensee identified

that increased breakaway torques were experienced for several other check valves.

2 SIS *42 had failed its torque test earlier in 1998 and was disassemb!cd and

overhauled. During testing 2 SIS *46 failed to open with 350 ft-lbs, and corrosion

residue was found in this valve. Additional valves also required higher than normal

torque values to stroke the valves. Separately, a system engineer identified three

valves (2 SIS *84,2 SIS *94,2 SIS *95)that had stuck in the open position after the

high head full flow test. The combination of these events resulted in extensive

review of the susceptibility of weighted arm check valves to binding and the

possibility of a common mode failure mechanism.

The licensee identified that the primary contributor to the binding was that the shaft

and o-ring bushings experienced excessive corrosion in a borated water

environment. The licensee attributed this failure mode to improper material

selection for the bushing material. Additional problems identified included: 1)

alignment and clearance problems,2) non-ideal shaft material selection; 3) o-ring

seat design inadequacies; 4) improper disk stop design; 5) degraded o-rings; and 6)

improper angle to vertical of the weighted arm (when the valve is full open). The

evaluation of degraded o-rings and the angle for the weighted arm was ongoing at

the close of the inspection period.

In response to the above issue, the licensee planned to inspect, modify, and test all

thirty-three weighted arm check valves of this design. The list of valves consisted

of Unit 2 high head safety injection, safety injection, recirculation spray, quench

spray, fire protection valves and Unit 1 fire protection valves. Twenty-two of the

Unit 2 valves are containment isolation valves and required operable per TS 3.6.3.1.

The modifications included replacement of the shaft and o-ring bushings with a

materialless susceptible to corrosion in a boric acid environment. Additional

changes included shaft materialimprovements, o-ring seat design changes, weld

buildups on the disk stops, and alignment and clearance changes. The licensee also '

plans to evaluate the preventive maintenance tasks for the check valves. The

inspectors noted that the root cause analysis was not completed at the end of the  ;

inspection period, but the licensee analysis to date was generally thorough and

corrective actions were extensive. Additional problems encountered during the

inspection and repair of the check valves were appropriately addressed. Quality

Services Unit (OSU) personnel provided timely assistance by identifying quality

deficiencies at the vendor's facilities. The inspectors observed selected

maintenance activities (see Section M1.1).

System engineers reviewed past performance and identified that the binding issue

existed since 1992 and possibly earlier. Initial corrective actions were to replace j

'

and lubricate the check valve bushing o-rings on an increased frequency. In 1995

l

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17

and 1996, the licensee identified that five check valves failed to close under the

weight of its own weight arm (2OSS*3,2OSS*4,2 SIS *42,2 SIS *47, and

2CHS*472). In response to these issues, the licensee identified possible causes as

o-ring bushing corrosion deposits and incorrect shaft clearances. Corrective action.s

identified included replacement of the o-ring bushings with new materials. The

corrective actions to address the root cause identified in 1996 were not planned

and scheduled until after the additional failures occurred in 1998.

Upon reviewing the previous material history, the inspectors determined that

previous licensee causal analysis and corrective actions were incomplete. Valve

opening breakaway torque on several valves, including 2 SIS *46 and 2 SIS *47 was

not sufficiently evaluated to identify an increasing trend and support development of

focused corrective actions prior to their failure during the current outage.

10 CFR 50, Appendix B, Criterion XVI, requires that measures shall be taken to

promptly identify and correct conditions adverse to quality. The failures identified in

1996 were not fully evaluated and associated corrective actions were not

implemented in a timely manner. The incomplete corrective actions contributed to

multiple valve failures in 1998, and represented a violation of 10 CFR 50, Appendix

B, Criterion XVI. During the current outage, the licensee identified the valve

f ailures, identified additional causal factors, and initiated extensive corrective

actions. The inspectors determined that the safety significance was low due to

redundant, diverse isolation valves for each of the check valves affected. This non-

repetitive, licensee-identified, and corrected violation is being treated as a Non-Cited

Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV

50-334(412)/98-04-02).

The inspectors reviewed the licensee event report (LER) for the common mode

failure of containment isolation check valves. The licensee described the issue, root

causes, and corrective action. The inspectors observed minor discrepancies

including additional failures and causal factors that were not described in the LER.

The issues were brought to the licensee attention and appropriate action taken. The

LERs (98-22-00 and 98-22-01) are closed.

c. Conclusions

The licensee identified binding issues associated with thirty Unit 2 check valves.

Causal analysis for this issue during the last refueling outage was incomplete, which

contributed to several additional failures occurring during this outage. Although the

valves affected multiple safety systems, the safety significance was low due to

redundant, diverse isolation valves for each of the check valves affected. Licensee

investigation, root cause analysis, quality controls, and corrective action during this

period were comprehensive.

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18

E2 Engineering Support of Facilities and Equipment

E2.1 Unit 1 System Health Reviews for Restart

a. Insoection Scope (37551. 71707)

The inspectors independently reviewed applicable documentation, held individual

interviews with three system engineers, and their managers, and verified completion

of activities on a sample basis to determine whether the licensee had properly

evaluated system readiness for unit restart.

b. Observations and Findinas

The inspectors determined that System and Performance Engineering Department

(SPED) personnel developed a systematic and comprehensive process to evaluate

system status and readiness. The inspectors verified that safety related systems

were included in the evaluation. SPED management participated in individual

system health review meetings with the system engineers The reviews were based

upon system walkdowns combined with aggregate assessment of all activities

which could potentially affect system performance. These activities included

operational concerns and workarounds, maintenance work requests, open

engineering memorandums, temporary modifications, open design change requests,

condition reports, equipment out of service logs, deficiency tags, and caution tags.

The three system engineers interviewed were knowledgeable on their specified

systems and were consistent in their implementation of the required system health

reviews.

Adequate documentation and record keeping of system health reviews were also

observed. Operations department personnel performed an independent system

health assessment which was a beneficial complement to the reviews performed by

SPED personnel. The inspectors observed that the results of the system health

reviews were clearly presented to the NSRB. During this inspection the inspectors

questioned the current methodology used by instrumentation and control

technicians to calibrate the lead / lag or rate lag circuits of the reactor protection

system channels. The licensee discussed the issue knowledgeably and initiated EM

116752 to further evaluate this issue.

c. Conclusions

System and Performance Engineering Department (SPED) personnel developed a

systematic and comprehensive process to evaluate system status and readiness.

System engineers were knowledgeable and consistent in their implementation of the

required system health reviews, providing appropriate recommendations to station

management regarding readiness for Unit 1 restart. Insights gained during the

system health reviews were properly shared with appropriate departments for

implementation.

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19

E8 Miscellaneous Engineering issues (90712,92700)

E8.1 (Closed) eel 50-334(412)/98-03-05: Failure to implement Adequate Administrative

Controls and Submit TS Amendment Requests for Conditions Outside of Station

Accident Analysis

a. Inspection Scope (37550,37551)

In response to NRC Violation 50-334(412)/98-01-03the licensee conducted a

detailed extent of condition review and identified 14 additional issues for which the

current technical specifications (TS) were non-conservative with respect to the

station (s) design basis. The largest issue involved reactor protection system (RPS)

and engineered safety feature (ESF) allowable actuation values. The licensee l

evaluated each issue, made operability determinations, applied associated l

compensatory measures, and began preparation of TS amendment requests where j

they determined one was needed. The inspectors independently reviewed station {

records, interviewed personnel, and evaluated system operability to determine that  ;

safety significance of the issues.

b. Observations and Findinas

lhe inspectors reviewed each of the 14 issues in detail, including assessment of

associated licensee operability evaluations, position papers, and basis for continued

operation (BCO) documents. In each case, using NRC Generic Letter 91-18,

information to Licensees Regarding NRC inspection Manual Section on Resolution

of Degraded and Nonconforming Conditions", Rev.1, the licensee determined that

no TS amendment was needed prior to unit restart. A selected group of the issues

is discussed below:

RPS/ESF TS Setooints end Allowable Values

in 1994, the licensee conducted a technical review of the RPS and ESF actuation

system instrumentation trip setpoints. This initiative was conducted to ensure that

plant specific documentation was correctly reflected in the design analysis, address

several generic industry issues, reflect protective equipment replacements, and

include vendor specification changes. The results of this review identified that

some TS trip setpoints and allowable values were not conservative. The inspectors

confirmed that in 1994, the licensee revised the calibration surveillance procedures

to reflect the new trip setpoints. However, in approximately 20 instances

(documented in NRC IR Nos. 50-334(412)/98-03),where the original trip setpoints

were acceptable and only the allowable values required revision, the new allowable

values were not properly incorporated into the surveillance procedures. The failure

to incorporate the allowable values in the surveillance procedures was caused by a

combination of weak administrative controls and poor verification by engineering

personnel and procedure writers to ensure that the procedures were appropriately

revised.

,

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20

Failure to revise the surveillance procedures affected the licensee's ability to

determine if the as-found setpoints had changed to an extent where the channel

was inoperable and potentially reportable to the NRC. However, since the setpoints

in the surveillance procedures were appropriately revised in 1994, the as-left trip

setpoints were not affected. Therefore, the safety significance for the failure to

appropriately include the new allowable values into the test procedures was low, in

addition, the licensee reviewed the as found surveillance test results dating back to

1994 to determine whether the failure to revise the allowable valves had resulted in

inappropriate operability determinations. This review determined that the affected

instrumentation was never inappropriately declared operable. Therefore, there was

no adverse safety consequence as a result of the failure to update the allowable i

values in the surveillance procedures. The inspectors independently reviewed I

maintenance history records and concluded that the failure to implement the correct I

allowable values did not result in a reportable event.

Upon identification, the surveillance test procedures were revised to reflect the

appropriate allowable values. The inspectors verified that the procedures were j

appropriately revised. The licensee implemented several additional corrective '

actions including the development of TS amendment requests, BCOs (until a TS

amendment is approved), implementation of plant design changes where needed,

and improving administrative procedures to prevent recurrence. The inspectors

determined that the Unit 1 BCO for the RPS/ESF issue was technically sound. The

Unit 2 BCO remained under development at the close of the inspection period.

Dynamic Time Constants for RPS Setooints

The licensee identified an issue regarding the use of dynamic time constants in Over

Pressure delta Temperature, Over Temperature delta Temperature, and Low

Pressurizer Pressure RPS trip functions. TS state that the time constant used will ,

equal an exact time in seconds (e.g. T1 = 30). The installed plant equipment is not  !

capable of meeting an exact equality value. As manufactured, the equipment has f

an inherent accuracy band (e.g. T1 =30 +/- 10%). UFSAR Accident analysis used  ;

the exact T1 value without allowing margin for the + /- accuracy band.

I

Beaver Valley engineers, with assistance from the Nuclear Steam System Supplier

recently performed new calculations which demonstrated that the plant can operate

with the +/-10% time constant band and remain within UFSAR analysis. The l

licensee generated a position paper which demonstrated that this issue was not a

safety issue. The inspectors reviewed the position paper and agreed that the issue

does not pose an adverce safety concern. But the TS still specified an exact time  !

constant value, in lieu of a tolerance range, which the plant does not meet.

Following NSRB review of the approved position paper, the licensee planned to

await the improved Standard TS project to revise the TS. The inspectors informed

the licensee that this corrective action would be untimely. In response, the licensee

revised their schedule to submit a TS amendment request in the next two to three

months to correct this problem. At the close of this report period the proposed TS  ;

amendment request had been presented to the OSC and was being properly tracked l

for accountability.

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BVPS-1 EDG Freauency Tolerance Discrepancy

CR 980569 noted that TS 4.8.1.1.2.a.5 was non-conservative in that this TS

required the output frequency of the EDGs to be within 2% of 60 hertz, while

design analysis 8700-DMC-3072 assumes a frequency range of only 1% based

on high head safety injection (HHSI) pump operation during safety injection. The

speed of HHSI equipment (pumps and motor operated valves) is affected by the

EDG generator frequency during an accident. CR 980569 noted that exceeding the

1 % frequency specified could result in a run-out condition of the HHSl pumps. CR

980569 also noted that although the analysis stated that this 1 % frequency

would be administratively controlled by the OSTs, the applicable OSTs did not

provide sufficient administrative controls. Therefore, DLC created an administrative

insert for the TSs which specified the 1 % frequency limit and initiated j

appropriate revisions to 10ST-36.3 and 10ST-36.4, respectively. The inspectors

reviewed the proposed changes to these OSTs and concluded that these

administrative controls were adequate for plant restart prior to receiving a TS

amendment.

1

In each case, the licensee identified the discrepancy and initiated appropriate I

corrective actions. During this inspection period, additional non-coriservative TS for

which the licensee had either failed to implement appropriate administrative controls

or failed to submit a TS amendment included:

• Inoperable Main Steam Safety Valves

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• BVPS-1 Emergency Diesel Generator (EDG) Largest Single Load Rejection

Test

• BVPS-1 Control Room Emergency Ventilation

• Refueling Water Storage Tank Level

• EDG Fuel Oil Storage Tank Level

As discussed above and in NRC IR 50-334(412)/98-03,ections to resolve technical

design issues as described in this section, from approximately 1994 to 1998, were

inadequate in that station design was not properly maintained, conditions adverse to

quality were not fully corrected in a timely manner, and TS were not properly

maintained. These were violations of 10 CFR 50, Appendix B, Criterion lli " Design

Control" and Criterion XVI " Corrective Actions," and 10 CFR 50.36(b). The

inspectors determined that, in response to NRC Violation 50-334(412)/98-01-03,

the licensee performed an appropriate extent of condition review, identified

pertinent design issues, performed technically sound operability assessments and

BCOs, and put appropriate administrative controls in place for Unit 1. Appropriate

actions were initiated using the licensee condition report system for Unit 2. The

root causes for the violations listed in this section are similar to the causes for the

original violation. The collective safety significance of the additional design issues

was low, and based on material history reviews, there was no adverse safety

consequence. This non-repetitive, licensee-identified, and corrected violation is

being treated as a Non-Cited Violation, consistent with Section Vil.B.1 of the NRC

l Enforcement Policy. (NCV 50-334(412)/98-04-03).

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c. Conclusions

in response to an NRC violation, the licensee performed an extent of condition

review which identified numerous design issues for which the TSs were non-

conservative. Appropriate corrective actions including interim administrative l

controls, development of TS amendment requests, and process revisions to ensure l

the facility is operated within its design basis were established. Interdepartmental l

coordination and the quality of engineering work to resolve the issues were

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excellent. The safety significance of the design issues was low and the licensee  !

correctly determined that Unit 1 could restart prior receiving TS amendment

approval from the NRC for the subject issues.

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E8.2 (Closed) LER 50-412/97-011: Inadequate Electrical isolation in Secondary Process

Rack Circuitry Due to Design Error.

The inspectors conducted an in-office review of the LER. The issue was

documented in NRC Inspection Report 50-334(412)/98-80and resulted in an NCV.

The LER properly described the event. The root cause evaluation and corrective

actions were comprehensive. No new issues were identified in the LER.

IV. Plant Support

R1 Radiological Protection and Chemistry (RP&C) Controls

a. Insoection Scope (83726)

The inspectors reviewed the programs for: (1) control of radioactive materials; (2)

maintaining occupational exposures as low as is reasonably achievable (ALARA);

and, (3) personnel radiation exposure records.

Areas reviewed under control of radioactive materialincluded transport of

potentially contaminated tools and equipment within the radiologically controlled

area (RCA), examination and free release of tools and equipment from the RCA, and

documentation of spills or other unusual occurrences involving the spread of

contamination in and around the facility, in accordance with 10 CFR 50.75(g)(1).

This review was conducted by examination of records, interviews with plant

personnel, and direct field observations.

Areas reviewed under ALARA included preparations for steam generator inspections

at Unit 2, installation and tracking of shielding packages in the RCA, and tracking of

hot spots. This review was conducted by examination of records and interviews

with plant personnel.

Areas reviewed under personnel dosimetry records included maintenance of NRC

required record forms, annual and special whole body count records and termination

records. This review was accomplished by examining a random sampling of

records, including records for current and former radiation workers, both licensee

employees and contractors.

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l b. Observations and Findinas  !

Control of Radioactive Material

The program for control of radioactive material, especially potentially contaminated

l materials, was conducted in accordance with licensee procedures (HP Manual,

Chapter 1, Part lil, " Contamination Control", Rev. 2; RP 3.4, " Handling Radioactive

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Material," Rev. 5; and RP 3.5, " Removing Material From an RCA," Rev. 0). The

two RP procedures were undergoing significant revision at the time of this

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inspection, with Health Physics Manual Change Notices (HPMCN) issued for each.

These changes were made to clarify that numericallimits listed in these procedures

for the free release of materials from the RCA were minimum detection limits and

not release limits. I

Equipment stored in support of radiological work, especially for refueling outages,

were placed at the Shippingpert Atomic Power Statioa (SAPS) warehouse. This I

material is generally contaminated, with limitations for storage based on direct

radiation levels on packages and on the aggregate radiation level seen at the

warehouse fence line. The licensee does not have a hot side tool storage facility.

Consequently, during outages, large numbers of hand tools are required to be

surveyed out of the RCA on a daily basis. The licensee is currently considering the

establishment of a contaminated tool facility inside of the RCA to reduce the

potential for inadvertent release of contaminated tools from the RCA.

A " Green h Clean" program has been established to provide for the disposition of

non-radioacdve materials which are brought into the RCA. A number of containers

and postings are located throughout the RCA to support this program. Bags of

material from these receptacles are surveyed prior to removal from the RCA, then

transported to a vendor for sorting, item recovery and disposal. The licensee does

not directly release this material to the local landfill.

Records of spills and other occurrences made in accordance with 10 CFR l

50.75(g)(1) were maintained by the licensing department, based on information l

provided by health physics. At the time of this inspection, extensive records of two l

areas outs;de the RCA where contamination has occurred have been maintained.

These areas (near the Unit 1 river water pipe and by LW-TK-7A/78) were identified

in 1994 and 1996 respectively. The records include documentation on the cause of

the contamination, remediation efforts undertaken, and residual contamination

remaining. Additionally, six other spills which occurred and/or were identified

during the 1970's and 1980's have also been documented. These records are not

as extensive, although post-remediation records do identify the level of residual

contamination. ,

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Maintainina Occuoational Exoosures ALARA

The program for maintaining occupational exposures ALARA includes processes and

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procedures to track hot spots within the facility and to provide shielding as a means

of reducing area ambient radiation dose rates. Hot spots, when identified, are

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documented and evaluated by the health physics staff and records of periodic

surveillances are maintained and trended. Health physics is also responsible for

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identifying hot spots to be reduced in scope through engineering controls or

shielding. Shielding packages are prepared by health physics based on total job

work scope dose savings projections, and are placed in accordance with

specifications provided on a case-by-case basis by plant engineering.

Radiation exposure goals established for 1997 included an outage exposure goal of

201 person-rem for the Unit 1 rJueling outage (1R12). Total exposure for the

outage was 223.9 person-rem, which included significant expansion of the outage

scope and length. Although the exposure total exceeded the established goal, it

does represent the lowest refueling outage exposure total ever at Unit 1. Exposure

estimates for 1998 were based on a full operating year at Unit 1 and a month-long

refueling outage at Unit 2, r:either of which have occurred. The licensee is planning

to conduct steam generator inspections during August-September 1998, and has

written radiation work permits and ALARA reviews to support this effort.

Dosimetrv Records

The licensee maintained records of personnel exposures in accordance with 10 CFR

20.2106. A review of a random sampling of these records demonstrated that

appropriate records were being properly maintained. Records of external exposures,

potential internal uptakes, annual whole bcdy counts and other pertinent exposure

data were maintained by the dosimetry section of health physics. Termination

reports for workers no longer employed at Beaver Valley were available for review.

Instances where workers had terminated without having an exit whole body count

were documented, together with records demonstrating the attempts to contact

these workers.

c. Conclusions

..

The program for the control of contaminated materials and equipment was effective.

The licensee appropriately identified and maintained records of spills and other

occurrences as required under 10 CFR 50.75(g)(1).

, The program for identifying and tracking hot spots, and shielding to reduce

l occupational exposures was effectively implemented. The Unit 1 refueling outage

in 1997 (1 R12) was completed with the lowest total dose in unit history.

Records of occupational exposures were appropriately maintained in accordance

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with 10 CFR 20.

R5 Staff Training and Qualification in RP&C

I a. Inspection Scone (83726)

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The inspectors reviewed the program for training radiation workers, including the

control of potentially contaminated materials. This inspection was accomplished by

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reviewing training records including lesson plans and handouts, and by attending

portions of the general employee training (GET) program, specifically the dress-

out/ mock-up facility training.

b. Observations and Findinos

All employees having access to the RCA are required, on an annual basis, to attend

GET and radworker training. As part of this three-day training program, workers

must successfully complete a mock-up training exercise in a simulated RCA.

Workers are graded on their ability to detect problems, respond to audible and visual

alarms, and to be able to safely enter, work, and then exit a posted contaminated

area,

c. Conclusions l

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The annual radworker training program, using a mock-up facility, was effective.

S1 Conduct of Security and Safeguards Activities

a. Insoection Scope (81700)

The inspectors determined whether the conduct of security and safeguards

activities met the licensee's commitments in the NRC-approved physical security

plan (the Plan) and NRC regulatory requirements. The security program was 1

inspected during the period of July 6-9,1998. Areas inspected included: access  !

authorization program; alarm stations; communications; and protected area (PA)

access control of personnel and packages.

b. Observations and Findinos l

Access Authorization Prooram. The inspectors reviewed implementation of the

access authorization (AA) program to verify implementation was in accordance with

applicable regulatory requirements and the Plan commitments. The review included

an evaluation of the effectiveness of the AA procedures, as implemented, and an

examination of AA records for 17 individuals. Records reviewed included both

persons who had been granted and had been denied access. The AA program, as

implemented, provided assurance that persons granted unescorted access did not

constitute an unreasonable risk to the health and safety of the public. Additionally,

the inspectors verified, by reviewing access denial records and applicable

procedures, that appropriate actions were taken when individuals were denied i

access or had their access terminated. Those actions included the availability of a {

formalized process that allowed the individuals the right to appeal the licensee's  !

decision.

Alarm Stations. The inspectors observed operations of the Central Alarm Station

(CAS) and the Secondary Alarm Station (SAS) and verified that the alarm stations

! were equipped with appropriate alarms, and surveillance and communications

capabilities. Interviews with the alarm station operators found them knowledge:, ole

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of their duties and responsibilities. The inspectors also verified, through i

observations and interviews, that the alarm stations were continuously manned,

independent and diverse so that no single act could remove the plants capability for

detecting a threat and calling for assistance, and the alarm stations did not contain

any operational activities that could interfere with the execution of the detection,

assessment and response functions. l

Communications. The inspectors verified, by document reviews and discussions

with alarm station operators, that the alarm stations were capable of maintaining

continuous intercommunications, communications with each security force member

(SFM) on duty, and were exercising communication methods with the local law

enforcement agencies as committed to in the Plan. I

Protected Area (PA) Access Control of Personnel and Hand-Carried Packaaes. On

July 7- 8,1998, the inspectors observed personnel and package search activities at

the personnel access portals. The inspectors determined, by observations, that

positive controls were in place to ensure only authorized individuals were granted

access to the PA and that all personnel and hand carried items entering the PA were

properly searched.

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c. Conclusions

Security and safeguards activities were conducted in a manner that protected public

health and safety in the areas of access authorization, alarm stations,

communications, and protected area access entrol of personnel and packages.

This portion of the program, as implemented, mat the licensee's commitments and

NRC requirements.

S2 Status of Security Facilities and Equipment

a. Insoection Scone (81700)

Areas inspected were PA assessment aids, PA detection aids, and personnel search

equipment,

b. Observations and Findinas

PA Assessment Aids. On July 7,1998, the inspectors evaluated the effectiveness

of the assessment aids, by observing on closed circuit television, a SFM conducting

a walkdown of the PA. The assessment aids, in general, had good picture quality

and good zone overlap. However, as noted in the previous inspection conducted in

January 1998, due to long fields of view and walling effect in several zones, the

alarm station operator's ability to properly assess the cause of an alarm would be

l limited if it were not for the use of the video capture system as an enhancement to

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the assessment program. The inspectors were informed, by security management,

that an assessment aid upgrade is being developed which will address the

assessment aid concerns. Additionally, to ensure the Plan commitments are

satisfied, the licensee has procedures in place requiring the implementation of

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compensatory measures in the event the alarm station operator is unable to properly

assess the cause of an alarm.

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Personnel and Packane Search Eauipment. On July 8,1998, the inspectors I

observed both the routine use and the daily performance testing of personnel and I

package search equipment. The inspectors determined, by observations and

procedural reviews, that the search equipment performs in accordance with licensee

procedures and the Plan commitments.

EA Detection Aids. On July 7,1998, the inspectors observed a SFM conducting

performance testing of the perimeter intrusion detection system (PIDS). The testing

consisted of 26 intrusion attempts in 25 zones, that resulted in the SFM being

detected in each intrusion attempt. The inspectors determined that the equipment

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was functional and effective and met the requirements of the Plan. '

illumination and Surveillance Hardware. While performing the inspection discussed

in this report, Section 3.1.3 of the Plan, titled "lliumination and Surveillance  ;

Hardware," was reviewed. The inspectors determined, by conducting a lighting  !

survey accompanied by a security supervisor with a calibrated light meter, that the

security lighting program clearly exceeds the minimallighting requirements as

specified in the Plan,

c. Conclusions

Security facilities and equipment in the areas of protected area assessment aids,

protected area detection aids, personnel search equipment, and illumination and

surveillance hardware were well maintained and reliable.

S3 Security and Safeguards Procedures and Documentation

a. inspection Scoce (81700)

Areas inspected were implementing procedures and security event logs.

b. Observations and Findir1gs

Security Proaram Procedve_s. The inspectors verified that the procedures were

consistent with the Plan commitments, and were properly implemented. The

verification was accomplished by reviewing selected implementing procedures

associated with PA access control of personnel and packages, testing and

maintenance of personnel search equipment, and performance testing of PA

detection aids.

Security Event Loas. The inspectors reviewed the Security Event Log for the

previous six months. Based on this review, and discussion with security

management,it was determined that the licensee appropriately analyzed, tracked,

resolved and documented safeguards events that the licensee determined did not

require a report to the NRC within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Additionally, the inspectors noted, during

( the review of the safeguards event logs, that since the last core inspection

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conducted in January 1998, there was a reduction in log entries associated with

personnel errors,

c. Conclusions

Security and safeguards procedures and documentation were properly implemented.

Event Logs were properly maintained and effectively used to analyze, track, and

resolve safeguards events.

S4 Security and Safeguards Staff Knowledge and Performance

a. Inspection Scope (81700)

The area inspected was security staff requisite knowledge,

b. Observations and Findinas

Security Force Reauisite Knowledae. The inspectors observed a nurnber of SFM's

in the performance of their routine duties. These observations included alarm

station operations, personnel and package searches, and performance testing of the

intrusion detection system. Additionally, the inspectors interviewed SFMs and,

based on the responses to the inspectors, determined that the SFMs were

knowledgeable of their responsibilities and duties, and could effectively carry out

their assignments. I

c. Conclus!qns

The SFMs adequately demonstrated that they had the requisite knowledge

necessary to effectively implement the duties and responsibliities associated with

their position.

S5 Security and Safeguards Staff Training and Qualification l

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a. Insoection Scope (81700)

Areas inspected were security training and qualifications and training records.

b. Observations and Findinas

Security Trainina and Qualifications (T&Q). On July 9,1998, the inspectors

randomly selected and reviewed T&Q records of 10 SFMs. Requalification records

were inspected for armed, unarmed, and supervisory personnel. The results of the

review indicated that the security force was being trained in accordance with the

approved T&Q plan. Additionally, on July 8,1998, the inspectors observed initial

qualification classroom training which addressed proper handcuffing techniques.

The instructor was very knowledgeable of the course material, presented it in an

effective manner, and safety was always stressed.

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Trainina Records.' The inspectors were able to verify, by reviewing training records, i

that the records were properly maintained, accurate and reflected the current

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qualifications of the SFMs.

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c. Conclusions

Security force personnel were trained in accordance with the requirements of the

Training and Qualifications Plan. Training documentation was properly maintained

and accurate. i

S8' Security Organization and Administration

a. Insoection Scope (81700)

Areas inspected were management support, effectiveness, and staffing levels. j

b. Observations and Findinas

. Manaaement Suonort. The inspectors reviewed various program enhancements

made since the last program inspection, which was conducted in January 1998.

These enhancements included the allocation of resources for bench marking

initiatives, the allocation of resources for the remodeling of the CAS, and the

assessment aid upgrade that is presently in the developmental phase.

,

Manaaement Effectiveness. The inspectors reviewed the management i

organizational structure and reporting chain and noted that the Manager of

Security's position in the organizational structure provides a means for making '

senior management aware of programmatic needs. Senior management's positive .

initiatives to address programmatic concerns is evident by the programmatic l

improvements as noted in this report.

Staffina Levels. The inspectors verified that the total number of trained SFMs

immediately available on shift met the requirements specified in the Plan. ,

c. Concluttiong

Management Lupport was adequate to ensure effective implementation of the

security program, and was evidenced by adequate staffing levels and the allocations

of resources to support programmatic needs.

S7 Quality Assurance in Security and Safeguards Activities

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a. Insoection Scone (81700)

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ll Areas' inspected were audits, problem analyses, corrective actions and effectiveness

of management controls.

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b. Observations and Findinas

A_udits. The inspectors reviewed the 1998 quality assurance (QA) audit of the AA

program, (Audit No. BV-C-98-06) and the 1998 QA audit of the security program,

(Audit No. BV-C-98-01). Both audits were conducted February 3 - March 12,

1998, and were found to have been conducted in accordance with the Plan and AA

rule. To enhance the effectiveness of the audits, both audit teams included an

independent technical specialist.

The AA audit report identified no condition reports (CR) and six recommendations.

The security audit identified five CRs and ten recommendations. Two security CRs

were associated with administrative issues and three CRs were associated with

maintenance of security equipment. The inspectors determined that the findings

were not indicative of programmatic weaknesses, and the findings would enhance

program effectiveness. Discussions with security management and AA staff  :

revealed that the responses to the findings were completed, and the corrective

actions were effective.

Problem Analyses. The inspectors reviewed data derived from the security

department's self-assessment program. Potential weaknesses were properly

identified, tracked, and trended.

Corrective Actions. The inspectors reviewed corrective actions implemented by the

licensee in response to the QA audits and self-assessment program. The corrective

actions were effective, as demonstrated by a reduction in personnel performance

issues and loggable safeguards events.

l Effectiveness of Manaaement Controls. The inspectors observed that the licensee

I

had programs in place for identifying, analyzing, and resolving problems. They

included the performance of annual QA audits, a departmental self-assessment

program, and the use of industry data such as violations of regulatory requirements

identified by the NRC at other facilities, as a criterion for self-assessment.

c. Conclusions

Audits of the security program were comprehensive in scope and depth, audit

findings were reported to the appropriate level of management, and the program

j was properly administered. in addition, a review of the documentation applicable to

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the self-assessment program indicated that the program was effectively

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implemented to identify and resolve potential weaknesses.

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V. Manaaement Meetinag

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X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management after

the conclusion of the inspection, on August 26,1998. The licensee acknowledged the l

findings presented. l

The inspectors asked the licensee whether any materials examined during the inspection

should be considered proprietary. No proprietary information was identified.

X2 Management Meeting Summary  ;

.On July 16,1998, an onsite management meeting was conducted between Duquesne

Light Company and members of the NRC Beaver Valley Oversight Panel (BVOP, chaired by ,

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R. V. Crienjak, Deputy Director of Reactor Projects, NRC Reg!on 1. The meeting was

conducted to review the current status of Beaver Valley Unit 1 readiness for restart. A

copy of the slides presented at this meeting are attached as enclosure (3).

- On August 4,1998, a Unit 1 Plant Status call was conducted between Mr. J. Cross and

members of the DLC staff and the NRC BVOP. The licensee discussed the status of

completing their Unit 1 Restart Action Plan, management oversight activities, and pending

licensing action.

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PARTIAL LIST OF PERSONS CONTACTED

.

D.kG

R. Brandt, Vice President, Nuclear Operations

S. Jain, Senior Vice President, Nuclear Services

M. Pergar, Acting Manager, Quality Services Unit

B. Tuite, General Manager, Nuclear Operations

R. Hansen, General Manager, Maintenance Programs Unit

R. Vento, Manager, Health Physics

D. Orndorf, Manager, Chemistry

F. Curi, Manecer, Nuclear Construction

J. Matsko, Manager, Outage Management Department

T. Lutkehaus, Manager, Maintenance Planning & Administration

T. Cosgrove, Coordinator, Onsite Safety Committee

J. Macdonald, Manager, System & Performance Engineering

K. Beatty, General Manager, Nuclear Support Unit

S. Hobbs, Acting Director, Safety & Licensing

W. Kline, Manager, Nuclear Engineering Department

R. Brosi, Manager, Management Services

- O. Arredondo, Manager, Nuclear Procurement

N. Mulig, Technical Assistant, Vice-President

D. Huff, General Manager - Nuclear Support Unit

M. Johnston, Manager of Security

D. Kline, Director Nuclear Security Operations

N. DiPietro, Supervisor Security Services

R. Dibler, Coordinator, Security Procedures and Training

B. Sepelak, Senior Licensing Engineer

D. Miller, Supervisor NED

. J. Belfiore, Quality Assurance Auditor

A. Castagnacci, Senior Health Physics Specialist - Radwaste/ Transportation

E. Cohen, Director, Radiological Operations, Unit 2

D. Girdwood, Director, Radiological Operations, Unit 1

C. Haney, Training Supervisor

R. Hart, Licensing

R. Pucci, Health Physics Specialist - ALARA

J. Saunders, Health Physics Supervisor

D. Weitz, Senior Health Physics Specialist - ALARA

MBC

D. Kern, SRI

, G. Wertz, Rl

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.. - ._ . .. .- - -. . . _.

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I 33

L

INSPECTION PROCEDURES USED

IP 37551: Onsite Engineering

IP 61726: Surveillance Observations

IP 62707: Maintenance Observations

IP 71707: Plant Operations

IP 71750: Plant Support Activities l

lP 81700: Physical Security Program for Power Reactors l

lP 83726: Control of Radioactive Materials and Contamination, Surveys, and Monitoring l

lP 90712: In-Office Review of Written Reports of Nonroutine Events at Power Reactor i

Facilities l

lP 92700: - Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor

Facilities

IP 92901: Follow-up Operations

IP 92902: Follow-up Maintenance i

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34

'

ITEMS OPENED, CLOSED AND DISCUSSED

Opened

50-334/98-04-01 VIO Inadequate Unit 1 Turbine Driven Auxiliary Feedwater '

Pump Maintenance (Section M1.2)

Ooened and Closed

,

50-334(412)98-04-02 NCV incomplete Cccrective Actions for Safety Related Check

Valve Binding issues (Section E1.1) ,

50-334(412)98-04-03 NCV Failure to Maintain Design Control and inadequate ,

Corrective Actions (Section E8.1)

Clpsed

50-412/97-11 LER Inadequate Electrical isolation in Secondary Process

Rack Circuitry Due to Design Error (Section E8.2)

50-334/98 22 LER Common Mode Failure of Containment Isolation Check

Valves (Section E1.1)

50-334/98-22-01 LER Common Mode Failure of Containment isolation Check

Valves (Section E1.1)

50-334(412)/98-03-05 eel Failure to implement Adequate Administrative Controls

and Submit TS Amendment Requests for Conditions

Outside of Station Accident Analysis (Section E8,1)  :

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35 'i

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. LIST OF. ACRONYMS USED ;

iAA' Access Authorization-  !

AFW-- Auxiliary Feedwater i

ALARA As Low as'is Reasonably Achievable

ANSS Assistant Nuclear Shift Supervisor. i

BCO~ Basis for Continued Operation . 'l

BVOP - Beaver Valley Oversight Panel '

.BVPS-' Beaver Valley Power Station )

CAS- Central Alarm System

CFR Code of Federal Regulations

-l

CR' Condition Report

DCP.. . Design Change Package

DLC; Duquesne Light Company

DRO Director of Radiological Operations

EDG Emergency Diesel Generator

=EM Engineering Memorandum

ERT. ' Event Response Team

.ESF Engineered Safety Feature

.FFD Fitness-for-Duty

FIN Fix-It-Now

FRV. Feedwater Regulating Valve

GET. General Employee Training

GMNO General Manager Nuclear Operations

' HHSI . High Head Safety injection

HPMCN Health Physics Manual Change Notice

~

IPTE Infrequently Performed Tests and Evolutions

'

law . In Accordance With

,LCO' Limiting Condition of Operation

LER Licensee Event Report

MPUAM ' Maintenance Program Unit Administration Manual

L: MRT Management Review Team -

'MSSV. Main Steam Safety Valve

MWR ' Maintenance Work Request i

NEAP Nuclear Engineering Administrative Procedure i

NO- Nuclear Operator '  !

'NPDAP Nuclear Power Division Administrative Procedure I

NRC Nuclear Regulatory Commission ]

Nuclear Safety Advisory Letter

'

NSAL

NSRB Nuclear Safety Review Board

NSS. Nuclear Shift Supervisor

NUREG - NRC Technical Report Designation

r

OM Operating Manual

'OSC: :Onsite Safety Committee

OST, Operational Surveillance Test

RO Reactor Operator

PA Protected Area

PDR. Public Document Room

,

.

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36

PDR Public Document Room

PIDS Perimeter intrusion Detection System

PT Potential Transformer l

QA~ Quality Assurance  !

QSU Quality Services Unit I

RAP Restart Action Plan

RCA' Radiologically Controlled Area

RCS Reactor Coolant System

RP&C Radiological Protection and Chemistry j

RPS- Reactor Protection System 1

RO Reactor Operator

RTS Responsible Test Manager

SAPS _ Shippingport Atomic Power Station

SAS Secondary Alarm System

SFM. Security Force Member

SG Steam Generator

)

1

SPED System and Performance Engineering Department

l

SSC - System Structures and Components- '

T&Q Training and Qualification

TER Technical Evaluation Report ,

the Plan NRC-approved physical security plan j

' TM Temporary Modification

>

TOP Temporary Operating Procedure

TS Technical Specification

UFSAR Updated Final Safety Analysis Report

UT Ultrasonic Testing

'UV Undervoltage i

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Management Meeting

l

Nuclear Regulatory Commission

&

Duquesne Light Company

July 16,1998

Beaver Valley Site

V

Duquesne Light Participants

+ J. E. Cross President Generation Group

+ S. C. Jain Sr. Vice President, Nuclear Services l

+ R. D. Brandt Vice President, Nuclear Operations

+ R. L, LeGrand Vice President, Operations Support

+ W. R. Kline Manager, Nuclear Engineering

+ K. L. Ostrowski Unit 1 Restart Manager

+ B. T. Tuite General Manager Nuclear Operations

,

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Agenda

.

+ Opening Remarks (JEC)

+ Plant Status (RDB)

+ Restart Strategy (SCJ)

+ AdministrativeIssues(WRK)

+ ProcessIssues(RLL)

+ Hardware Issues (KLO)

+ Restart Action Plan (KLO)

+ Operations Staffing (BTT)

.

+ Closing Remarks(JEC)

3

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Plant Status

!

R. D. Brandt

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Plant Status

+ Plant Condition

1

+ Critical Path Activities .

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+ Technical Specification Training

+ Human Performance

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Restart Strategy l

S. C. Jain

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Restart Strategy ,

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+ Administratiye Issues l

+ Process Issues i

+ Hardware Issues

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Administrative Issues I

Multi-Discipline Analysis Team

(MDAT)

W. R. Kline

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MDAT

+ Goals

+ Discovery Process

+ Issues

+ Root Cause

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+ Conclusions

'

+ Prior to Startup

+ Post-Startup

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MDAT Goals

i

+ Process Control

l + Change Control

+ Extent of Condition

+ Determine Root Cause

l

+ Establish Startup Requirements

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3

. - . . - . -- . . . _.

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.

,

.

MDAT Discovery Process  !

+ Team Representation

+ Document / Process Investigation

+ Issue Identification

'

+ Restart Protocol

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MDAT Issues

+ Setpoint/ Allowable Value Changes

I

+ Processes

+ Mindset

12

6

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MDAT Root Cause

i

+ Feedback Inconsistencies j

+ Administrative Controls

+ Procedure vs. Licensing Changes l

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MDAT Conclusion

+ Equipment Operable  :

+ Process Deficiencies

+ FeedbackInconsistencies

+ Licensing Changes vs. Procedure

+ Interim Measures Appropriate

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MDAT Activities Prior to Startup

+ Complete BCO's

+ Revise Processes

+ ProvideTraining

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Post-Startup Activities

+ Submit LAR's

+ Post-MDAT Activities  !

- Improved Technical Specifications

- Best Estimate LOCA Reanalysis

.

16

8

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Process Issues

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R. L. LeGrand

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Approach

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+ Process

+ Causal Factors

+ Pre-Startup Actions

+ Post-Startup Actions

+ Summary

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18

9

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Approach

+ Condition Reports

.

- Change Process

'

- NPDAP / Section Procedures

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Causal Factors I

+ Management Oversight

l

+ Feedback Mechanism

+ Mindset

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10

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Pre-Startup Actions  ;

i

+ Change Process  :

- Flow Charted .

t

- Revised Change Process Procedures

- Trained Personnel

- Executive and NSRB Review

- Independent Review

+ NPDAP's  !

- Compared and Revised as Necessary

- Implementing Procedures

- Feedback Mechanism

n i

Post-Startup Actions ,

+ DEMMAND

+ Remaining Processes

+ Self-Assessment - 6 Months Effectiveness

Review

n

!!

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Summary

.

+ Management Oversight .

+ Feedback Mechanism ,

+ Mindset Change

t

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4

Hardware Issues

K. L. Ostrowski

24

12

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Hardware Issues l

i

+ Items Completed

- CREBAPS

- PORV's

+ Ongoing Items

- Check Valves

- Undervoltage Relays  ;

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25

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Restart Action Plan

K. L. Ostrowski

.

26

13

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_ . . . . . _ __ _ .- __

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BEAVER VALLEY RESTART PROCESS

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Oversight

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. Restart Milestones

+ RCS Pressurization (complete)

+ Mode 4

+ Mode 2

+ 30% Power

i

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28

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6

.

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1

Operations Staffing

B. T. Tuite

-

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Operations Staffing 4

+ SeniorReactorOperators

- 12 in 1997

- 7 in 1998

+ Active RO and AO Training Program

+ Active Pipeline

+ Good Performance

- 100% Examination Pass Rate

- Best Scores in Region 1

30

15

p, .

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Operations SRO Staffing

i

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40 /

35  !

30

25 _

20 -

l  ; - -

;  ;

Jan- Jan- Mar. Apr- Jul- Dec- Apr- Jun- Aug

96 97 97 97 97 97 98 98 58

(est)

• Star,ng increase'of 75% in 1997- 1998 period.

31

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