ML20141E945

Integrated Insp Repts 50-334/97-04 & 50-412/97-04 on 970427-0607.Violations Noted.Major Areas Inspected:Licensee Operations,Engineering,Maint & Plant Support

ML20141E945
Person / Time
Site:	Beaver Valley
Issue date:	04/27/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20141E937	List: ML20141E932 ML20141E939 ML20141E945
References
50-334-97-04, 50-334-97-4, 50-412-97-04, 50-412-97-4, NUDOCS 9707010235
Download: ML20141E945 (37)

See also: IR 05000334/1997004

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U. S. NUCLEAR REGULATORY COMMISSION

REGION I

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License Nos. DPR-66, NPF-73 I

Report Nos. 50-334/97-04, 50-412/97-04

Docket Nos. 50-334, 50-412

Licensee: Duquesne Light Company (DLC)

Post Office Box 4

Shippingport, PA 15077

Facility: Beaver Valley Power Station, Units 1 and 2

Inspection Period: April 27,1997 through June 7,1997

Inspectors: D. Kern, Senior Resident inspector

F. Lyon, Resident inspector

G. Dentel, Resident inspector

J. Furia, Senior Radiation Specialist

G. Smith, Senior Physical Security inspector

E. King, Physical Security inspector

Approved by: P. Eselgroth, Chief

Reactor Projects Branch 7

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9707010235 970623

PDR ADOCK 05000334

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EXECUTIVE SUMMARY.

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Beaver Valley Power Station, Units 1 & 2

NRC Inspection Report 50-334/97-04 & 50-412/97-04

This integrated inspection included aspects of licensee operations, engineering,

maintenance, and plant support. The report covers a 6-week period of resident inspection.

In addition, it includes the results of announced inspections by regional inspectors in the

radioactive waste and transportation program, and in the physical security area.

Ooerations

e Operators maintained positive control of core reactivity during a May.15,1997

inoperable analog control rod position indication event. However, several

longstanding operator performance weaknesses were evident. (e.g., Operator use of

-technical specifications (TS) and clear operating crew communication of TS

applicability, shift turnover review, and logkeeping). (Section 01.2)

e Operations management did not effectively ensure Special Operating Orders (S00)

and Standing Night Orders (SNO) content was maintained current. Extraneous and

outdated information was maintained active in SOO/SNO documents.

(Section 03.1)

e Recent failures by operations personnel to identify conditions adverse to quality in a

timely manner, including an inoperable service water pump, two trains of

supplemental leak collection'and release system out of service at once, and

improper shift operating log turnover reviews were a violation. (Gc: tion 01.3)

Maintenance

e Performance weaknesses were noted as operations and maintenance personnel

failed to effectively minimize safety related equipment out of service time during l

planned maintenance activities. The primary cause was that work activities were J

not properly staffed and managed through shift turnovers. Equipment out of service

' time did not exceed TS or maintenance rule criteria. Several positive actions were  ;

being developed to improve on-line safety related maintenance coordination, but I

were not in place for assessment during this inspection period. (Section M1.3)

e. In April 1997, the maintenance work request (MWR) process and Fix-It-Now (FIN)

maintenance program were effectively revised to streamline work processes and

help reduce the non-outage corrective MWR backlog. Overall, the two procedure

revisions clarified responsibilities, established better criteria for initiating ~and -

categorizing work requests, and strengthened the MWR review process through the

Work Control Screening Committee. Oversight of FIN team maintenance activities

was appropriate. The revised processes expedited work completion and directly led

to reducing the non-outage corrective maintenance backlog (1356 MWRs using

previous definition, 996 MWRs using the new definition which excludes support

work activities, design changes, inspections, blanket work activities, and preventive ,

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maintenance). (Section M1.4)

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(EXECUTIVE SUMMARY CONTINUED)

$ e Operations, electricians, and system engineers effectively evaluated and corrected a

low emergency battery cell voltage, in time to avoid a forced plant shutdown.

System engineering developed effective contingency actions and properly evaluated

the operability determination. The inspectors noted that surveillance procedures

incorporated all TS and Institute of Electrical and Electronic Engineers, Inc.  ;

[ requirements. (Section M2.1)

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e While reviewing an unresolved item the inspectors determined that Unit 1 chemical

i injection lines did not have redundant heat trace as described in the UFSAR for vital  !

< lines that are subject to freezing. The inspectors concluded that overall safety

consequences were minimal. (Section M8.1) )

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Enaineerina l

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l e The inspectors reviewed selected technical evaluation reports (TERs) for a five year

} period following each unit startup. The documented bases for the 10 CFR 50.59

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. screenings and related safety evaluations which supported the TERs were adequate.  !

When safety e. valuations were not performed, the 10 CFR 50.59 applicability  !

j screening justifications were well supported. On March 7,1997, station l

' management established more stringent controls, limiting the use of TERs for plant j

l modifications. (Section E3.1)

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j e Annual 10 CFR 50.59 reports from 1990 to 1996 were comprehensive.

j (Section E3.2)

! . Plant Sucoort

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e The licensee maintained an effective security program. Management support was

evident by the procurement and replacement of two package search units and the

development and installation of tactical response delay barriers and defensive

j fighting positions. Management controls for identifying, resolving, and preventing

i programmatic problems were effective, protected area detection equipment was

j consistent with the NRC-approved physical security plan (the Plan), audits were

j thorough and in-depth, and security equipment testing was being performed as

required in the Plan. Maintenance of equipment was being performed in a timely

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manner as evidenced by minimal compensatory posting associated with security

, equipment repairs. (Section S2, S7)

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Section 3.2.1.5 of the Plan, titled " Search and Admittance Control Hardware," was

l reviewed. Licensee provisions for land vehicle control measures satisfy regulatory

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requirements and licensee commitments. The inspectors determined that search

and admittance control hardware was tested and maintained as required in the Plan

and applicable procedures. (Section S8)

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e The radioactive waste and transportation program was evaluated during this

i inspection period, including implementation of the revised transportation re<3ulations

j found in Title 49, Code of Federal Regulations. While the program was generally

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(EXECUTIVE SUMMARY CONTINUED)

effective, severalinstances of procedural weaknesses and outdated process and

system descriptions were identified. (Section R1)

Safety Assessment and Quality Verification

e Quality assurance audits of engineering activities to implement plant changes were

indepth. Audit findings identified several instances where 10 CFR 50.59 was not

properly or completely implemented. The licensee's corrective action program

demonstrated that audits of engineering have continued to provide sufficient

coverage to uncover and correct engineering deficiencies in this area.

(Section E7.1)

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TABLE OF CONTENTS

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l' EX EC UTIVE S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i

F l. Operations .................................................... 1 i

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

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

01.2 Inoperable Unit 1 Analog Control Rod Position Indication (ARPI) . 1

01.3 Operator Recognition of Conditions Adverse' to Quality . . . . . . . . 4 l

j O2 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 5

O2.1 Engineered Safety Feature System Walkdowns (71707) . . . . . . . 5

j 03 Operations Procedures and Documentation ..................... 6

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03.1 Special Operating Orders and Standing Night Orders . . . . . . . . . . 6

1 08 Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

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08.1 (Closed) LER 5 0-412 /9 600 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

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j 11. M a i n t e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

i M1 Conduct of Maintenance .................................. 8

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M 1.1 Routine Maintenance Observations (62707) . . . . . . . . . . . . . . . . 8

M1.2 Routine Surveillance Observations (61726) ................ 8

i M1.3 On-Line Maintenance Activities . . . . . . . . . . . . . . . . . . . . . . . . . 9

i M1.4 Revised Maintenance Work Request (MWR) Process and

Expanded Fix-It-Now (FIN) Maintenance Program . . . . . . . . . . . 11

j M2 Maintenance and Material Condition of Facilities and Equipment ..... 13

M2.1 Inoperable Unit 2 Station Battery 2-1 ................... 13

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M8 Miscellaneous Maintenance issues .......................... 14

? M8.1 (Closed) Unresolved item 50-334/96010-03 .............. 14

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e lil . Enginee ri ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

E3 Engineering Procedures and Documentation . . . . . . . . . . . . . . . . . . . . 15

} E3.1 Safety Evaluations for Technical Evaluation Reports . . . . . . . . . 15 1

E3.2 Annual 10 CFR 50.59 Reports ........................ 17 -!

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E7 Quality Assurance in Engineering Activities . . . . . . . . . . . . . . . . . . . . 18 ,

j E7.1 Quality Assurance (QA) Audits of Engineering Activities . . . . . . 18

l E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . 19

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E8.1 (Closed) Unresolved item 50-412/96010-05 .............. 19

I V . Pl a n t S u p p o rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20 l

R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 20

R5 Staff Training and Qualification in RP&C . . . . . . . . . . . . . . . . . . . . . . 22

R7 Quality Assurance in Radiological Protection and Chemistry Activities . 22

L1 Review of Updated Final Safety Analysis Report (UFSAR) Commitments .... 23

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S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 23

S2 Status of Security Facilities and Equipment .................... 24

S 2.1 Protected Area Detection Aids ........................ 24

S2.2 Testing, Maintenance and Compensatory Measures . . . . . . . . . 25

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S6- Security Organization and Administration . . . . . . . . . . . . . . . . . . . . . . 25

S7 Quality Assurance in Security and Safeguards Activities . . . . . . . . . . . 26

S7.1 Effectiveness of Management Controls . . . . . -. . . . . . . . . . . . . 26

S7.2 Audits

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S8 Miscellaneous Security and Safeguards issues . . . . . . . . . . . . . . . . . . 27

S8.1 Vehicle Barrier System (VBS) ......................... 27

S8.2 Vehicle Barrier System (VBS) ......................... 28

S8.3 Bomb Blast Analysis ............................... 28

S8.4 Procedural Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

V. M a n a g e m e n t M ee ting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

X1 Exit Meeting Sum m a ry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

ATTACHMENT .................................................. 30

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Report Details

Summarv of Plant Status

Unit 1 began this inspection period at full power. On May 15,1997, operators entered

Technical Specification (TS) 3.0.3 after two control rod Analog Rod Position Indications

(ARPI) indicated greater than 12 steps apart from the group demand counters. The control

rods were returned to within 12 steps before a unit shutdown was commenced (Section

01.2). The unit remained at full power for the remainder of the period.

Unit 2 operated at full power throughout the period.

l. Operations

01 Conduct of Operations

01.1 General Comments (71707)'

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Using inspection Procedure 71707, the inspectors conducted frequent reviews of

ongoing plant operations. In general, the conduct of operations was professional

and safety-conscious; specific events and noteworthy observations are detailed in

the sections below.

01.2 Inonerable Unit 1 Analoa Control Rod Position Indication (ARPI)

a. Inspection Scoce (71707. 92901. 93702)

The inspectors were informed that Unit 1 ARPI had performed unreliably during a

reactor core flux mapping evolution, which may have resulted in operators taking

the actions required by Technical Specification (TS) 3.0.3. The inspectors

interviewed personnel, reviewed operator logs, and other records to determine what

had transpired and evaluate operators' response to the event.

b. Observations and Findinas

Event

On May 15,1997, Unit 1 operators moved control rods as part of a planned core

flux mapping evolution. At 12:05 pm, with control rods stationary, operators noted

that the ARPl on two rods within the same bank had drifted and now indicated > 12

steps from the group demand position. Control rod H2 indicated 227 steps, control

rod P8 indicated 219 steps, and the group step counter was at 206 steps.

Operators immediately initiated abnormal operating procedure (AOP) 1.1.7, " Rod

Position Indication Malfunction", Rev. 4. Primary voltage readings (H2 = 228 steps,

P8 = 228 steps) taken at 12:08 pm confirmed that both control rod position

indications were >12 steps from the group (206 steps).

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

standardized reactor inspection report outline. Individual reports are not expected to

address all outline topics.

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The Nuclear Shift Supervisor (NSS) directed reactor engineers to perform incore flux i

mapping as specified in AOP 1.1.7 to verify control rod position. At 1:30 pm the l

P8 ARPI drifted down to within 12 steps of the group step counter. At about the j

same time the NSS determined that , based on flux map results, the control rods  !

were correctly aligned with the group and the observed discrepancies indicated

ARPl problems. At about 1:30 pm the NSS contacted operations management to

discuss the ARPI problems. At 2:20 pm operators began withdrawing control rods

to their . normal full out (227 steps) position. At 2:35 pm all ARPI indications agreed

within 12 steps of the full out position and operators exited AOP 1.1.7. At 3:00

pm the operations staff contacted incensing personnel to discuss the event and the i

TS limiting conditions for operation (LCOs) which may have been applicable,

inspector Follow-up

Later on May 15, licensing personnel informed the inspectors of the Unit 1 ARPl

problems. Based on the initial discussion, inspectors questioned whether control

room operators had recognized which TS LCOs were applicable during the event

and whether they had taken proper actions. At 5:00 pm (2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after shift

turnover) the inspectors went to the control room, printed the shift operating logs,

discussed current status with the new shift, and briefly discussed the event with

the off-going nuclear shift supervisor (NSS). The inspectors noted that no TS LCO

entries or exits for the observed control rod position discrepancies were identified in ;

the operator logs or shift turnover checklists.

The inspectors also questioned whether the H2 ARPI was operable. The assistant

NSS stated the H2 ARPI was operable since based on observed performance, H2

ARPI agreed closely with the group step counter near the current (full out) position.

Early on May 16, the NSS informed the inspectors that he had updated the control

room logs to reflect the TS LCOs that had been in effect during the ARPI event.

The inspectors reviewed the updated computer generated shift operating logs and

observed that all entries were inserted at their time of occurrence with no indication

of these being late entries. It was apparent that control room logs could be altered

after the shift had relieved without any indication of late entries or that changes had

been made.

On May 16, the inspectors informed the station manager and the operations

manager that this event called into question (1) whether licensed operators

recognized TS/ license LCO entry requirements in a timely manner and (2) the

quality / reliability of logkeeping practices to maintain the station operations legal

record. In addition, the inspectors questioned the basis for considering the H-2

ARPI operable. The H2 ARPI had not indicated within 12 steps of the group step

counter until the operators began rod withdrawal to restore the control rod group to

the full out position. The licensee reevaluated ARPl operability and declared the H2

ARPIinoperable at 10:25 am on May 16,1997.

During subsequent interviews the off-going NSS informed the inspectors that he

knew which TS LCOs had been in effect during his shift but had not made

corresponding log entries. The NSS believed the one entry regarding initiating AOP

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i 1.1.7 was sufficient for log entry in lieu of logging the numerous TS LCO entries

and exits since this AOP was specifically written to respond to ARPI malfunctions.

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Insoector Observations / Concerns

Operators maintained positive control and propedy assessed several diverse

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indications of core reactivity during this event. Based on interviews and review of

control room logs, the inspectors identified the following conditions adverse to the

quality of communications relative to plant TS LCO status:

a. Control room staff (two SROs, two ROs, one STA) teamwork was weak in

that TS were not effectively referenced in parallel with AOP implementation.

When TS were referenced (about 1/2 hour into the event), the NSS identified

applicable TS LCOs, but did not clearly communicate his determinations to

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the operating crew,

b. The control room staff failed to log applicable TS LCO entries or exits as )

{ required by procedure 1/2-OM-48.5.A prior to shift turnover (including two

j simultaneous 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> plant shutdown TS LCO action statements, TS 3.0.3

and TS 3.1.3.1.b).

c. The offgoing NSS/ANSS signed off their watch (performed turnover) without

properly certifying the accuracy of operations log entries made during their

shift as required by procedures 1/2-OM-48.1.C,1/2-OM-48.5.A, and 1-OM-

54.1. A.

d. The oncoming control room shift did not question the incomplete logs prior

to assuming the shift, although they had been briefed on ARPI discrepancies

experienced during the previous shift,

e. The computer generated shift operating logs were edited / altered at a later

date/ time with no visible indication that a change was made. Approximately

3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after shift turnover, the off-shift NSS updated the official control

room logs to include TS LCO entries & exits from the event. These entries

were not identified as late entries. Entries made were stillinsufficient to

identify which specific TS LCO action statements were applicable.

f. l.ogkeeping procedures and practices were poor and didn't describe how late

r.ntries were to be made to computerized logs.

g. Based on interviews, the logkeeping, TS usage, and shift turnover

weaknesses discussed above were longstanding / widespread practices.

Licensee Assessment / Corrective Actions l

On May 21, the inspectors informed the station manager that initiallicensee review l

of the ARPI event appeared slow and lacked depth. Two condition reports were

written to evaluate (1) the cause for the difference between ARPI and the group

step counter position and (2) the inspector observation that the computer  !

logkeeping system permitted the shift operating log to be revised after the shift logs

had been closed out. However, six days after the event, licensee evaluations did

not appear to specifically address operators' use of TS and operating crew

communication of TS LCO applicability, shift turnover review, and apparent

longstanding log keeping performance weaknesses. The station manager stated he

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t- agreed that logkeeping procedures were poor and that he would ensure the issues

-were reviewed in detail.

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The licensee's event review was performed in several separate portions, both inside

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and outside of the station's condition report system. Preliminary findings were

consistent with those identified by the inspectors. The H2 ARPl was declared i

inoperable on May 16,1997 and associated TS required actions were performed. A

basis for continued operation was performed to evaluate continued operation with a

degraded Unit 1 ARPl system. Additional interim corrective actions included

discontinuing use of computer logs, several logkeeping procedures were revised, a

station manager directive concerning operability dterminations, TS usage, and I

management notifications was issued, and corresponding training was held with all  !

operating crews. The event was still under licensee review at the close of the  !

inspection period.

c. Conclusions ,

The inspectors determined that severallongstanding operator performance

weaknesses were evident during operator response to the May 15,1997,

! inoperable ARPI event (e.g. Operator use of TS and clear operating crew

communication of TS LCO applicability, shift turnover review, and logkeeping).

Failure to properly perform operator logkeeping and shift turnover reviews as

, required by procedures 1-OM-54.1.A,1/2-OM-48.1.C, and 1/2-OM-48.5.A is

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further discussed in Section 01.3.

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1- - 01.3 Ooerator Recoanition of Conditions Adverse to Quality

f a. Inspection Scope (71707. 92901)

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!. The inspectors reviewed several examples of operator performance which indicated

! a potential insensitivity to recognizing equipment or plant condition.

i b. Observations and Findinos

j On May 15,1997, operators moved control rods as part of a planned core flux

mapping evolution as described in Section 01.2. Although operators immediately

, initiated the procedure for abnormal control rod position, they did not evaluate TS in

a timely manner and effectively communicate applicable TS LCOs among the

i operating crew. The NSS and ANSS turned over the watch to the next shift

j' without properly certifying operating log accuracy as required by BVPS procedures

i 1/2-OM-48.1.C, " Conduct of Operations, Organizational and Responsibilities of the

Operations Group", Rev 1,' 1/2-48.5.A, " Conduct of Operations, Logs and Reports",

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Rev.10, and 1-OM-54.1.A, " Station Logs", Rev O. In addition, operators didn't

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adequately question H2 ARPI operability at shift turnover. The basis for considering

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H2 A9P1 operable was weak. As a result they didn't declare the H2 ARPI

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inoperable and implement applicable TS LCO action requirements until the next day

(May 16,1997) following additional inspector questioning and engineering review.

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On March 23,1997, operators made the train "A" emergency diesel generator l

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(EDG) 2-1) inoperable during bar-over of the EDG in preparation for monthly )

surveillance run~. During the same time period, the supplemental leak collection and i

release system (SLCRS) train "B" was also inoperable due to exhaust fan and vortex  !

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damper repairs. The nuclear shift supervisor was unaware that during the 17 I

minutes when the EDG was unavailable, an LCO (TS 3.0.5) was inadvertently

j entered since the "A" SLCRS train did not have an operable emergency power l

supply. The on-coming nuclear shift supervisor correctly identified the condition

and EDG testing was postponed. This was licensee identified after the fact, but not  :

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recognized at time of occurrence by the on-shift control room crew (two SROs, two

ROs, one STA).

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! Seal water _ supply valve 2SWS-SOV-130A had failed to open during a surveillance

test on March 8,1997. Operations personnel did not adequately track the status of

planned corrective maintenance. As a result, on March 13,1997, operations

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supervisors failed to recognize the service water system was inoperable for about

, 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> until questioned by NRC inspectors. #

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

assure that conditions adverse to quality, such as failures, malfunctions,

deficiencies, deviations, defective material and equipment, and nonconformances

are promptly identified and corrected. The identification of the significant condition

adverse to quality, the cause of the condition, and the corrective action taken shall

be documented and reported to appropriate leveis of management. The above listed

failures to promptly identify conditions that were adverse to quality represent a

violation of 10 CFR 50, Appendix B, Criterion XVI (VIO 50-334(412)/97004-01)

c. Conclusions

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Recent failures by operations personnel to identify conditions adverse to quality in a

timely manner, including an inoperable service water pump, two trains of '

supplemental leak collection and release system out of service at once, and

incomplete shift operating logs were a violation.

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02 Operational Status of Facilities and Equipment  !

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O2.1 Enaineered Safetv Feature System Walkdowns (71707)

The inspectors walked down accessible portions of selected systeme to assess

equipment operability, material condition, and housekeeping. Minor discrepancies

were brought to DLC staff's attention and corrected. No substantive concerns were

identified. The following systems were walked down: ,

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• Unit 1 River Water System

• Unit 2 Primary Component Cooling Water System

• Unit 2 Auxiliary Feedwater System

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} 03 Operations Procedures and Documentation

03.1 Soecial Operatina Orders and Standina Niaht Orders

a. Insoection Scone (71707) 1

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,' The inspectors reviewed the Unit 2 Special Operating Orders (SOOs) and Standing

: Night Orders (SNOs) for current applicability, timeliness in incorporation into existing

, procedures, and the periodic review process. The following procedures were

j reviewed during the inspection.

q; * 1/20ST-48.17 " Standing Night Orders Foriodic Review," Rev. O

* 1/20ST-48.18 "Special Operating Orders Periodic Review," Rev. O

j * 1/20M-48.1.D " Operations Shift Rules of Practice," Rev. 25

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i b. Observations and Findinas

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The SOO purpose per OM Chapter 48.1.D is "to cover specific administrative or off-

j normal plant situations of a short term nature or to convey information or general '

directions to Operations shift personnel." The General Manager Nuclear Operations 1

! (GMNO) or designee is rosponsible for generation and periodic review of the SOOs. 1

The inspectors noted that guidance for SNO content and use did not exist. The '

Technical Assistant to the General Manager Nuclear Operations (TAGMNO) stated

the purpose of SNOs is to convey information to Operations shift personnel that is

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requirements. Per procedures 1/20ST-48.17 and 1/20ST-48.18, the SNOs and

i SOOs are reviewed every six months to determine if they should remain, be

! incorporated in the operating manual, or cancelled. If it should be incorporated, a =

! target (or completion) due date is assigned and a request to cancel the SOO or SNO

j when completed is generated.

)- The inspectors reviewed the nine open SOOs and the 14 open SNOs for Unit 2.

i The inspectors noted that most of the SOOs/SNOs were issued before 1995. 1

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Several open SOOs/SNOs contained data that was out of date (e.g., maximum  !

torque values for Unit 2 MOV packing gland adjustments). Other open SOOs/SNOs

l were already incorporated into procedures, and the items were not cancelled at that

4 time. The periodic reviews did not identify the cut-of-date SOOs/SNOs. Some

SOOs/SNOs identified to be incorporeted did not have target due dates but were

identified as items to be completed as schedule permits. The inspectors observed

that there was no predetermined tracking mechanism to determine if the procedure

change has been made (item incorporated) or if the target due date has been met.

l -In addition, the procedure change requests were not linked to the SOOs or the

l SNOs Therefore, tracking of the progress or completion of the procedure change

i was difficult. The inspectors did r:ot identify any instance where operators used

i outdated information contained in the SOOs/SNOs.

!  !

The inspectors presented their findings to operations management. The TAGMNO I

j stated that operations would perform a review of all outstanding SOOs and SNOs.

j After their review,21 of 28 SNOs and 6 of 16 SOOs (Unit 1 and Unit 2) were

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cancelled. Six of the remaining 7 SNOs and 8 of the rema;ning 10 SOOs have now  !

been scheduled for incorporation into station procedures and cancellation by August

1997. The GMNO stated that it v v. their intention to reduce the number of SNOs

and SOOs to zero, in addition, revisions were initiated to the periodic review ,

! procedures (1/2OST-48.17 and 1/20ST-48.18) to include additional measures to

'

ensure timely review and closure of SOOs/SNOs. The changes' established a clear

. link between the corrective document and the open SOOs/SNOs and active tracking

, of the target due date. The inspectors determined that the licensee corrective

i actions were comprehensive. '

!

i

American National Standard N18.7-1976/ANS 3.2 provides guidelines for operating

c,rders and for special orders. The guidelines state that " provisions should be made

for periodic review, updating and cancellation of.special orders." The NRC endorsed <

this ANSI standard in Regulatory Guide 1.33, Rev. 2. DLC committed to Regulatory

Guide 1.33, Rev. 2 through UFSAR 1.8 and TS 6.8.1.a. Contrary to the above, the

procedures used for periodic review (1/20ST-48.17 and 1/20ST-48.18) were not ,

effectively implemented and followed in that out of date information was not -!

identified and corrected or eliminated, and target due dates were not assigned to '

SOOs and SNOs identified to be incorporated in procedures. The inspectors did not

= identify any adverse safety consequence as a result of this violation. This failure

constitutes a violation of minor sigrificance and is being treated as a Non-cited

Violation (NCV 334(412)/97004 02), consistent with Section IV of the NRC

tinforcement Policy.

c. Conclusions

Operations management did not effectively ensure SOO/SNO content was

maintained current. Extraneous and outdated information was maintained active in

SOO/SNO documents. No adverse safety consequence was identified as a result of

the failure to properly implement administrative controls for review o' the SOO

and SNO.

08 Miscellaneous Operations issues (71707, 92700)

08.1 (Closed) LER 50-412/96002: Condition Prohibited by Technical Specifications -

Containment Penetration not Isolated within the Time Limit.

On February 20,1996, with Beaver Valley Unit 2 at fuil power, the rr.ain steart'.

radiation monitors discharge isolation valve failed to stroke prop'.triy during a .

surveillance test. The valve was a containment isoleNr. valve and therefore was -

required to be isolated within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. A Nuclear Safety Department notice v,ritten

in 1994 identified the valve as a containment isolation vr4lve requiring compliance

with TS 3.6.3.1. However, the valve had not been addad to the containment

isolation valve list prior to the February 20,1996 event. 'The containment

penetration was isolated per TS 3.6.3.1,15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> and 36 minutes after failure of

the valve.

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y T7ee licensee determined the root causes of this event were a breakdown in the

"

administrative controls governing document updates during initial plant construction

in 1985 and inadequate follow-up of actions documented in the Nuclear Safety

Department Notice. The inspectors determined that the causal analysis lacked

4

depth in that the licensee failed to determine why there was inadequate follow-up

actions to the Nuclear Safety Department Notice and why the notice was not

effectively communicated to operational crews. However, the corrective actions

addressed the programmatic problems and extensive changes have been made to

the corrective action program, the corrective action tracking system, and the

Nuclear Safety Department. Corrective actions included: 1) addition of the valve to

.

the containment isolation valve table; 2) enhancement of the process for tracking

action items; 3) review of all existing Nuclear Safety Department Notices; and 4)

enhancements to the condition remart prenram. Failure to isolate the Unit 2 main

steam radiation monitor discharge line wLnin the time specified by TS 3.6.3.1 is a

violation. This licensee identified and corrected TS violation is being treated as a

Non-Citeo Violation, consistent with Section Vil of the NRC Enforcement Policy

(NCV 50-412/97094-03),

11. Maintenance

M1 Conduct of Maintenance

M 1.1 Routine M_ajntenance Observations (62707)

The inspectors observed all or portions of maintenance activities on important

systems and components listed below.

• MWR 061867 Support inspection / Cleaning in "C" Intake Bay

• MWR 063667 Corrective Maintenance on 480 V MCC-1-ES, Supply to

MOV-RS-156A

The activities observed and reviewed were performed safely and in accordance with

proper procedures, inspectors noted that an appropriate level of supervisory

attention was given to the work depending on its priority and difficulty.

M1.2 Routine Surveillance Observations (61726)

The inspectors observed all or portions of operational surveillance tests (OSTs)

listed below.

• 10ST-?OA " Reactor Plant River Water System Valve Test for A tieader,"

Rev.9

• 10ST-30.2 " Reactor Plant River Water Pump 1 A Test," Rev.10

• 20ST-24.4 " Steam Turbine Driven Auxiliary Feed Pump [2FWE*P22]

Test," Rev. 27

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l * 20ST-30.6. " Service Water Pump [2SWS*P21C) Test," Rev.10

l The surveillance testing was performed safely and in accordance with proper

l procedures. Additional observations regarding surveillance testing are discussed in

j the following sections. The inspectors noted that an appropriate level of

supervisory attention was given to the testing, depending on its sensitivity.

M1.3 On-Line Maintenance Activities

I

a. Insoection Scope (62707)

The inspectors reviewed several on-line safety related maintenance activities

involving technical specification (TS) limiting conditions of operation (LCO) to

evaluate whether the equipment out of service time was effectively. managed,

b. Observations and Findinas

i

!

On May 6,1997, while verifying component configurations in the control room the '

- inspectors observed that two TS LCOs were in effect due to planned maintenance.

The inspectors reviewed the maintenance work request (MWR) packages and

associated equipment clearances and discussed the work with the control room i

staff. The unit 1 steam driven auxiliary feedwater pump was out of service for an

environmental qualification inspection on the recirculation flow valve (SOV-FW-102) .,

.using MWR 059942. The unit 2 normal seal water supply to two service water

system (SWS) pumps was isolated to inspect and repair 2SWS-SOV-130B using

MWRs 061786 & 061790. Each work activity was time critical as it invoked a 72

hour plant shutdown LCO. NPDAP 7.12, "Non-Outage Scheduling, Planning, and

Risk Assessment", Rev. 3 indicates that work activities with .172 hour0.00199 days <br />0.0478 hours <br />2.843915e-4 weeks <br />6.5446e-5 months <br /> LCO

statements should be worked continuously. Planners had estimated that the 2SWS-

SOV-130B repair would require two days which clearly indicated the importance of

this work.

The inspectors noted about three hours of dead time on each of the two work

activities which resulted from inefficient coordination. Maintenance personnel did

not begin work on SOV-FW-102 until 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after operations had posted the

clearance. Mechanics did not begin work on 2SWS-SOV-130B until 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after

instrumentation and control technicians completed their work activity on the valve.

Failure by operations and maintenance personnel to properly coordinate work

activities through shift turnover periods were the key contributors to the delays.

Specifically, mechanical maintenance and Instrumentation & Control personnel were

not properly staffed to support timely turnover of work activities. Operations

personnel and maintenance personnel did not effectively coordinate resources to

post equipment clearances and promptly begin work.

Each work activity was completed within the TS permitted LCO time interval and

maintenance rule performance criteria was not exceeded. The inspectors observed

excehnt coo'dination between mechanics and quality control personnel during

reinstal ation of 2SWS-SOV-1308. However, the inspectors expressed concern that

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ineffective scheduling and coordination within the maintenance department and

between operations and maintenance personnel had unnecessarily prolonged safety

related equipment out of service time. This was a performance weakness within

the operations and maintenance departments.

The inspectors discussed the above observations with the Operations and

Maintenance Department managers. Bcth managers agreed that delays as 1

discussed above were unacceptable and that several actions were being developed

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to' improve work coordination. Near term plans include establishment of the l

maintenance work control center and the operations work processing center (each >

staffed one shift per day with a senior reactor operator), new positions for a

maintenance coordinator within each of the maintenance disciplines, a restructured

planning and scheduling organization with additional staff, a clear indicator on

maintenance work documents to highlight whether each discrete maintenance

activity is a maintenance rule or LCO item, small group training seminars at the craft

level to discuss coordination of critical maintenance work, and consideration of 1

revised maintenance staffing hours. The Maintenance Department has scheduled a  ;

self assessment of the work management process (scheduling and planning) for j

June 1997. The inspectors noted that these actions have excellent potential, but

are not yet fully developed or implemented.

The Maintenance manager. informed the inspectors that as an interim measure,

additional coordination between the Maintenance manager and the Operations i

manager would take place to clearly address coordination of LCO maintenance-

activities. During backshift hours the on-shift maintenance supervisor has been

tasked to coordinate closeiy with the operations shift supervisor to ensure timely

handoffs for LCO maintenance and return to service testing. The inspectors closely

observed two additional LCO maintenance activities the following week and noted

that both jobs were effectively coordinated,

c. Conclusions

Performance weaknesses were noted as operations and maintenance personnel

failed to effectively minimize safety related equipment out of service time during

two planned maintenance activities. The primary cause was that work activities-

were not properly staffed and managed through shift turnovers. Equipment out of )

service time did not exceed TS or maintenance rule criteria. Several positive actions l

were being developed to improve LCO maintenance coordination, but were not in  !

place for assessment during th!s inspection period. ,

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, M1.4 Revised Maintenance Work Reauest (MWR) Process and Exoanded Fix-It-Now (FIN)

Maintenance Prooram

u. Insoection Scope (62707)

.The non-outage corrective MWR backlog ramained steady (about 1500 MWRs), but

above station goals for several months despite use of overtime and contractor

personnel to help reduce the backlog. Maintenance management recently (April

1997) revised the MWR process and FIN maintenance program to streamline work

processes and help reduce the backlog. The inspectors reviewed the recent process

revision: to determine whether they were being safely implemented and evaluate  ;

their effect on MWR backlog.

b. Observations and Findinas

Station management determined that the MWR process was administratively

cumbersome and was often misused to perform work which could be performed  :

using simpler processes. Examples included housekeeping requests, and minor

maintenance activities, and recurring preventive maintenance tasks. MWRs could

be initiated by any station emp!oyee via a variety of methods and without an easy

method to track them into the planning and scheduling process. NPDAP 7.5,

" Maintenance Work Request", Rev. 8, and NPUAM 4.11, Fix-It-Now Maintenance

Program", Rev. 2, were revised to more properly categorize work and reduce-

administrative burden.

The inspectors reviewed the revised procedures with maintenance personnel and

observed the following,

e The housekeeping hotline was established to support minor housekeeping

requests such as replacing light bulbs.

e Management has directed that procedures be written and scheduled for

recurring preventive maintenance tasks.

e All Work Requeste must be submitted via work request tag (WRT). WRTs

pertaining to equipment deficiencies are delivered to the nuclear shift

supervisor (NSS) for operability, reportability, and priority assignment.

Support MWRs are delivered to the maintenance planning manager.

e A daily Work Control Screening Committee was established to review all

work request tags to verify proper work priority, plant mode, TS concerns,

scheduling, and work type (e.g. MWR or FIN work order). The committee is

multi-disciplined to provide a broad knowledge base.

o Planners are responsible to identify and document post maintenance test

(PMT) criteria in the MWR. The NSS then reviews / concurs and directs the

PMT to be performed. Previously the NSS had to identify all PMT criteria.

e An SRO was assigned as FIN team leader to provide close oversight to the

recently expanded FIN team (approximately 20 people).

o One SRO each was assigned to the maintenance work control center and to

the new operations work processing center.

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The inspectors met with the newly assigned FIN team leader and discussed FIN

team activities and the revised procedure. The FIN team leader screens all FIN team  ;

work activities after they are assigned by the Work Control Screening Committee '

and demonstrated a strong working knowledge of the FIN maintenance procedure.

The inspectors noted several items in the new FIN procedure which were not clearly

described. Examples included, the definition of " operations acceptance of a post I

s maintenance test", " FIN maintenance", and " job validation walkdowns." The FIN

team leader indicated these items would be included when the procedure is next

revised to capture other improvements noted by the FIN team leader during the first

two weeks of using the new procedure. Based on these discussions, the inspectors

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concluded that oversight of FIN team activities was appropriate. The work load

completed by the FIN team increased from about 50 tasks per week in March to

about 100 tasks per week beginning in May 1997. FIN team work backlog was

about 6-8 weeks. This increased productivity reflected increased FIN team staffing

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and the revised FIN maintenance procedure.

I Overall, the two procedure revisions clarified responsibilities, established better  !

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criteria for initiating MWRs, and strengthened the MWR review process through the

Work Control Screening Committee. The inspectors attended several daily

screening committee meetings and observed that the WRTs reviewed were properly

screened. Items segregated as FIN work orders were properly evaluated. The

inspectors noted that the screening committee composition wasn't defined in

procedures and questioned how committee membership and experience would be

maintained. The Director of Work Management informed the inspectors that

committee mernbership would be clarified in an upcoming procedure revision.

The revised MWR and FIN processes expedited work completion and directly led to l

reducing the non-outage corrective maintenance backlog to 1356 at the end of May

1997. At the end of the report period the inspectors noted that the licensee

recently redefined the term "non-outage corrective MWR backlog" to exclude

certain work categories which were previously included (e.g support work activities,

design changes, inspections, blanket work activities, and preventive maintenance).

2

Under the new definition the non-outage corrective maintenance backlog was 996

MWRs at the end of May 1997.

'

c. . onclusions

in April 1997, the MWR process and FIN maintenance program were effectively

revised to streamline work processes and help reduce the non-outage corrective

'

MWR backlog. Overall, the two procedure revisions claritied responsibilities,

established better criteria for initiating MWRs, and strengthened the MWR review

process through the Work Control Screening Committee. Oversight of FIN Team

maintenance activities was appropriate. Maintenance activities were properly

categorized as either housekeeping requests, FIN work orders, procedural preventive

maintenance, or MWRs. The revised processes expedited work completion and

directly led to reducing the non-outage corrective maintenance backlog (1356

MWRs using previous definition, 996 MWRs using the new definition).

12

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M2 Maintenance and Material Cmdition of Facilities and Equipment

M 2.1 Inocerable Unit 2 Station Batterv 211.

a. Insoection Scope (71707,62707. 37551)

A Unit 2 Station Battery Cell was found below Technical Specification (TS) limits

during quarterly testing. The inspectors reviewed the initial operation and

engineering response and TS requirements. The inspectors evaluated the applicable

NRC regulatory guide, IEEE standards, and pertinent UFSAR sections. The following

procedures were reviewed during the inspection:

• 2MSP-39.01-E " Battery No. 2-1 Test and Inspection," Rev. 3

• 20ST-39.1 A " Weekly Station Battery Check, [ BAT *2-1]," Rev. 5

• 2BVT-01.39.06 " Station Battery [ BAT *2-1] Performance Discharge Test," l

Rev.1

• 2BVT-01.39.01 " Station Battery [ BAT *2-1] Service Test," Rev.1

l

b. Observations and Findinas  !

On May 17 at 2:20 pm, electrical maintenance technicians notified the control room

that battery cell 14 in the 2-1 station battery had a voltage of 2.061 V. The TS

allowable value is greater than 2.07 V. TS 3.8.2.3 requires the inoperable battery l

bank restored to operable status within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> or be in hot standby within the next l

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Operators effectively communicated with system engineers and

electricians to resolve the low battery cell voltage. The electricians, with operator l

assistance, placed the station battery on equalizing charge. The battery reached the

required TS voltage (as determined while on float) and was declared operable at

5:07 p.m. Operators had prepared the necessary procedures and surveillance

procedures to shutdown, but shutdown was not initiated. The station battery was

placed on a 100 hour0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> equalizing charge to bring the low battery cell voltage up to

the limits listed in the TSs (greater than 2.07 V within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and greater than l

2.13 V witidn 7 days). The battery cell maintained a voltage above the TS limits

after the equalizing charge.

System engineers followed the issue and developed possible contingency actions if

the battery cell voltage dropped after the equalizing charge. The system engineers

visually inspected the battery to determine if any internal problems could be

identified. The engineers did not find any abnormal corrosion, sediment, electrolyte

appearance or plate distortions. The inspectors noted that a specific root cause

was not identified, but system engineers effectively used past data, vendor

assistance, and current trends for their operability determination. The probable

cause was battery cell aging effects (e.g. sediment accumulation) which are

inherent to the battery cell operation. The engineers concluded that there was not a

large f ault in the battery cell as evidenced by the recovery of the battery cell voltage

with the equalizing charge. The current data and vendor recommendations

supported the operability determination. The licensee has revised their procedures

to increase the monitoring of battery cells with lower voltages through improved

pilot cell selection during surveillancr testing.

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The inspectors reviewed TS surveillance requirements, UFSAR descriptions, NRC 1

Regulatory Guide 1.129 " Maintenance, Testing and Replacement of Large Lead

Storage Batteries for Nuclear Power Plants," Rev.1 (licensee committed to the

Regulatory Guide in Unit UFSAR 1.8), and IEEE Std 450-1975, "lEEE Recommended

Practice for Maintenance, Testing and Replacement of Large Lead Storage Batteries

for Generating Stations and Substations" (licensee commitment to the IEEE Std. per

the Regulatory Guide). The inspectors concluded the surveillance recommendations

and requirements were incorporated in station procedures,

i

c. Conclusions

Operations, electricians, and system engineers effectively evaluated and corrected a

{

low emergency battery cell voltage in time to avoid a forced plant shutdown.

System engineering developed effective contingency actions and properly evaluated l

the operability determination. The inspector noted that surveillance procedures l

incorporated all TS and IEEE requirements.

M8 Miscellaneous Maintenance issues (92903) i

M8.1 (Closed) Unresolved item 50-334/96010-03: Potential Unit 1 RWST Heat Trace

Design Discrepancies.

During the winter months, Unit 1 and Unit 2 experienced cold weather related l

problems with RWST lines. The details are documented in inspection Report 50-

334(412)/96010. The unresolved item concerned Unit 1 heat trace requirements j

specified in the UFSAR. The UFSAR for Unit 1 requires all vital lines that are j

subject to freezing be heat traced by two circuits. System and licensing engineers  !

defined vital lines as " system flow path for which flow is included in the accident

analysis as mitigating the consequences of postulated accidents. In other words, {

such lines are ' vital' in attaining and maintaining the plant in a safe shutdown  !

condition during postulated accident conditions." The definition was an

interpretation of a number of references.  !

l

The inspectors found that of the two RWST lines in question, the RWST make-up l

'

line would not be considered a vital line, and therefore would not be subject to the

redundant heat trace requirement. The chemical injection line would be considered

a vital line. The sodium hydroxide liquid contained in the chemical injection line is

not subject to freezing above minus 15 F (IEEE Std 622-1979). The system

engineer concluded that the chemical injection line was not subject to freezing. ,

After further questioning by thre inspectors, the system engineer provided a basis for I

a minimum temperature using weather data for the local area. The weather data

provided information on median annual minimum extremes (for the Pittsburgh

area,-1 F). The inspectors reviewed Unit 1 UFSAR Table 2.2-2, which shows a

minimum temperature of -20 F for the Pittsburgh area. Therefore, the inspectors l

concluded that the chemical injection line was subject to freezing. This vital line ]

does not have redundant heat trace and therefore is a de facto change from the

UFSAR.

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The inspectors evaluated the safety consequences of the failure to evaluate this

change from the UFSAR. The inspectors noted several mitigating factors. The low

i freezing temperature of the fluid (-15 F) reduces the susceptibility of the chemical

. injection line to freezing. The medium annual minimum extreme temperature is -

1 F. The chemical injection line has a single heat trace on the line to prevent

freezing. Low temperature and heat trace alarms provide advance notice to alert

operators to respond to prevent freezing of the line. Industry standards for heat

trace (IEEE Std 622-1979) states "that redundancy is not normally applied on freeze ,

protection systems, but may be applied if conditions warrant." The inspectors

concluded that overall safety consequence was low. However, the licensee's

failure to perform a 10 CFR 50.59 safety evaluation when changes were made to

i the facility as stated in the UFSAR was a violation. The inspectors concluded that

'

the heat trace discrepancy would most likely have been identified by the licensee's

ongoing 100% UFSAR verification initiative. Therefore, consistent with Section

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Vll.B.3 of the NRC Enforcement Policy, this issue is not subject to enforcement

action,

.

j

J

l j'! Enaineerina

E3 Engineering Procedures and Documentation j

E3.1 Safetv Evaluations for Technical Evaluation Reoorts

i

a. Insoection Scope (37551)

i The inspectors reviewed several Technical Evaluation Reports (TERs) written in the

years shortly following the initial startup of Beaver Valley Units 1 and 2 to evaluate

the effectiveness and completeness of their associated screening for 10 CFR 50.59

applicability and any required safety evaluations.

1 b. Observations and Findinas

,

l The licensee normally utilized the Design Change Package (DCP) process to

accomplish modifications and changes to the Unit 1 and 2 plants. The TER process

, was normally used for performing technical evaluations, calculations, equipment

'

classification changes, material equivalency evaluations, etc. However, the licensee

also used the TER process when a minor change was needed that required a

l reduced engineering effort to assure the appropriate design controls were

maintained. The licensee Ica had nuclear engineering administrative procedures in

place that require safety reviews for TERs, when appropriate. However, recent

j concerns regarding the use of TERs to accomplish physical plant changes have

prompted the licensee to review the controls over their use. Following an

engineering management evaluation, the licensee determined on March 7,1997 that

l all plant changes must use the formal Design Change Package (DCP) process unless

! sufficient justification exists for use of a TER.

1

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The inspectors reviewed 11 selected TERs completed during the initial years after

each unit commenced operation to evaluate the safety screening and safety

evaluations required under 10 CFR 50.59 for plant chenges, tests, and experiments.

Unit 1

TER-017: Governor Valve GV-1 Limit Switch Modification (12/16/83)

TER-038: Reactor Coolant Pump No. 2 Seal Modification (8/22/84)

TER-135: MOV-CH-289 Operator Replacement (5/11/88)

TER-421: Procedure for Flux Thimble Tube Repositioning (8/2/88)

TER-558: Revision of Flow Diagram 5700-RM-16A for QA Downgrade

(12/19/88)

Unit 2,

TER-296: Containment Instrument Air Motor-Operated Valves 2iAC"MOV

130/133/134 (1/29/89)

TER-423: Personnel Air Lock O-Rings Material Changes (9/12/88)

TER-664: Verification of Calculation for VitalInstrument Bus #1 Voltage Output

Setpoint Change (4/26/89)

TER-818: Replacement of Woodward Governor on 2FWE-T22 With a Stock

Woodward Governor (2/4/89)

TER-832: Material Change Evaluation for Containment isolation Relief Valve

2SSR-RV122 (2/23/89)

Units 1 and 2 Common

TER-798: Evaluation of Material Change for Pacific Valve Disc Assembly

(2/14/89)

Full scale safety evaluations were written for TER-017 and -421. These SEs

sufficiently addressed the impact on plant safety and concluded that no unreviewed

safety question existed from the changes. The SEs appropriately concluded that the

changes did not represent a reduction in the margin of safety as defined in the

Updated Final Safety Analysis Report (UFSAR) and that no change to the UFSAR

was necessary.

Safety evaluation screenings were completed for TER-038 and -558, which i

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determined that no change to the UFSAR was necessary. The screenings

documented sufficient technical bases for concluding that an unreviewed safety

question would not result from the changes.

TER-038, -135, -296, -428, -798, -818, and -832, represented a component, ,

material, or spare parts equivalency change where no SE or change to the UFSAR  !

was necessary. A sufficient technical basis was documented to support the

conclusion that no functional changes, equipment qualification, or unreviewed

safety questions were involved. Adequate technical justification was also

documented in design review checklists for the equivalency evaluations in these

TERs in support of not performing a 10 CFR 50.59 screening. Some inconsistencies

16

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! lwere noted in these TERs, e.g., an Engineering Memorandum was used to approve

, a material evaluation or spare parts change without formally completing all required

TER forms; however, these inconsistencies did not affect the need for or lack of a

j safety evaluation screening.

TER-664 represented an engineering calculation to verify the results of a vendor

'

calculation for a setpoint change. No 10 CFR 50.59 screening and no change to

3 the UFSAR was necessary since the licensee's calculation confirmed the vendor's

l calculation and the setpoint remained within the original band defined by the

, UFSAR.

The inspectors noted that independent engineering reviews were documented for all

i

of the TERs listed above. The appropriate safety classification of plant equipment

was also indicated in all cases. Thorough material evaluations or design

verifications were accomplished, as appropriate,

c. Conclusions .;

The inspectors concluded 'that the documented bases provided for the 10 CFR

50.59 screenings'and safety evaluations were adequate in all cases. For the TERs

that were screened for 50.59 applicability, justifications were well supported for not

performing an SE, and that no unreviewed safety question existed. No increase in

the probability or consequence of malfunction of equipment required to prevent or

mitigate the consequences of any analyzed accident, and no reduction in the margin

of safety as defined in the basis for any technical specification requirement existed.

E3.2 Annual 10 CFR 50.59 Reports

a. Insoection Scoce (37551)

The inspectors reviewed the annual 10 CFR 50.59 raports submitted by the licensee

to the NRC from 1985 through 1996.

1

b. Observations and Findinas

1

During the years of 1985 to 1996, the licensee submitted twelve annual 10 CFR

50.59 reports to the NRC containing brief descriptions of tests, changes, and

experiments, and the supporting safety evaluations for Unit 1. Nine similar reports

were submitted for Unit 2 during the years of 1988 to 1996.

The inspectors compared the contents of the annual letters to a list of several

hundred DCPs performed by the licensee after both units were initially licensed to

operate. Based on the comparison, the inspectors noted that the annual reports

from 1985 to 1990 did not contain all SEs performed for plant modifications and

other tests or experiments performed during these years. Approximately 130 DCPs

identified on the list were not included in any of the annual NRC reports for both

units. The inspectors selected 15 DCPs for Unit 1,19 for Unit 2, and two dual unit

DCPs that appeared to warrant a full SE from their descriptions and apparent

significance, and requested that the licensee confirm that the SEs were written.

I

17

_ . - , _ - _ _ . _ _ _ . _ _ . . . _ - _ . _ . _ _ _ _ . . _ _._... .. _ _.. _..___ _ _

[

.

.

.

J The Director of Engineering Assurance indicated that the SEs for all 36 DCPs (and

others from the 130 total) were in fact written, and were currently maintained in

!

controlled engineering files. The inspectors independently reviewed the 36 selected ,

5 DCPs and determined that 15 of the changes met criteria to be included in the

anr.ual 10 CFR 50.59 report to the NRC. All 15 were properly reported to the NRC.

j The remaining 21 DCPs were not changes to the facility, tests, or experiments as

j described in the safety analysis report. The inspectors noted that the 10 CFR

j 50.59 annual reports for plant changes, tests, and experiments were much more

comprehensive after 1990. This reflected improved controls to ensure changes

were consistently. forwarded to licensing engineers for reportability screening.

c. Conclusions

i The inspectors concluded that the annual 10 CFR 50.59 reports from 1990 to 1996

- were comprehensive and included the appropriate safety evaluations written to

] support tests, experiments, and plant changes at both Units 1 and 2.

[ -!

_

E7 Quality Assurance in Engineering Activities

E7.1 Quality Assurance (QA) Audits of Enaineerina Activities I

l a .- Insoection Scooe (37551)

l The inspectors reviewed recent QA audits of engineering activities to determine if1

the licensee has identified instances where DCPs, TERs, or other plant changes,

j tests, and experiments have not received a proper safety evaluation in accordance

with 10 CFR 50.59.

4

b. Observations and Findinas

i

d

The licensee's Quality Assurance (OA.\ organization performs formal program audits

'

of nuclear engineering and maintenance activities on an annual basis. Each audit

- included a review of engineering design changes, plant modifications, technical and l

!' safety evaluations, and was also intended to assure that the appropriate engineering

l reviews are completed for maintenance activities,

j

.

The inspectors discussed the engineering audit process with QA management and

! reviewed a comprehensive listing of approximately 1300 QA audit observations and

findings in engineering from 1986 through 1994. The listing identified several

l findings associated with deficient plant modifications and 10 CFR 50.59 safety

evaluations. The following findings and observations contained notable concerns,

i as follows:

I Audit No. Findina/ Observation

!

$ BV-C-87-38 e A temporary modification was performed without

'

, supporting documentation.

BV-1 -87-38 e SE not documented for a DCP

.

18

.

i

.

BV-C-88-24 * SEs not present in three DCPs.

• Design change accomplished by a maintenance activity

without an SE.

BV-C-88-46 * No documented SE found for two DCPs.

BV-2-89-02 * Incomplete SE.

BV-C-90-38 * Relay operating time increased without an SE being

written.

BV-C-91 -04 * An SE did not consider seismic Category 11 over I

criteria, and did not consider potential effects on control

room habitability.

• An SE did not provide an adequate basis for a new

pressure rating, did not identify a safety-related i

function, and misapplied the single failure criterion.

• An SE contained an incorrect statement and required

clarification.

BV-C-93-07 * An SE was not changed to reflect the revised scope of

a modification, and authorization for work was provided I

prior to completion of a SE. l

l

The inspectors also reviewed the follow-up actions taken by the site line i

organizations responsible for the resolution and disposition of these findings. The I

documentation was complete, and the identified corrective actions were later l

evaluated by the QA organization for effectiveness. All corrective actions were

closed out upon satisfactory evaluation by the QA organization.

c. Conclusion

The inspectors concluded that the identified deficiencies in audit reports reflected

indepth QA audits and evaluations, that effectively uncovered instances where 10

CFR 50.59 was not properly or completely implemented. The licensee's corrective

actions program demonstrated that audits of engineering have continued to provide

sufficient coverage to uncover and correct engineering deficiencies in this area.

E8 Miscellaneous Engineering issues (929 33)

E8.1 (Closed) Unresolved item 50-412/96010-05: EDG 2-1 Operability with 2EGS-19 l

Closed '

On January 28,1997, operators found that the emergency diesel generator (EDG)

2-1 governor cooling water outlet valve (2EGS-19) was 95% shut instead of its

normal full open position. The initial operability determination had inadequate

technical basis to support the conclusion. This item remained open pending

licensee performance and inspectors review of a revised engineering evaluation to

support an operability determination.

19

}

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,

!. ,

.

Operators performed an EDG test run on February 26,1997 to gather additional

j performance data to support engineering analysis of EDG operability. The

} inspectors observed the test and discussed performance characteristics with

licensee and vendor personnel. .The vendor and licensee engineers performed

l independent heat transfer model calculations using the test data. They each

I conciuded that the EDG governor oil temperature and viscosity would remain within

acceptable limits for continued EDG operation with 2EGS-19 shut.

!

l The inspectors reviewed the operability evaluation and supporting calculations

l provided independently by the vendor and by station engineers. The inspectors

i noted that both calculations had assumed EDG room temperatures well below the

j design limit of 122 degrees F. Engineers demonstrated that the effect of the

elevated room temperature would be minor and not change their conclusion. The

i- inspectors independently calculated the affect and determined that the EDG

j. governor oil would have remained within prescribed limits with 2EGS-19 shut and

the EDG room at the design temperature limit of 122 degrees F. The heat transfer

[ models, supporting calculations, and the operability determination were technically

! sound and correctly concluded that the EDG remained operable.

4

IV. Plant Suonort

R1 Radiological Protection and Chemistry (RP&C) Controls

a. Insoection Scooe (71750. 86750 & Tl 2515/133)

The inspectors reviewed the liquid and solid radwaste processing system and the'

program for transporting radioactive materials. Additionally, the inspectors

reviewed the licensee's program as it relates to the implementation of the revisions

to Title 49, Code of Federal Regulations (49 CFR) for the transportation of

radioactive materials. The inspection was accomplished by a review of plant

documen's and procedures, interviews with personnel and walkdowns of the related

systems.

b. Observations and Findinas

The inspectors reviewed the licensee's documentation and description of the liquid

and solid radwaste processing systems, contained in the UFSAR and Process

Control Program (PCP) for each unit. Chapter 11 of each unit's UFSAR contains the

system descriptions for liquid and solid radioactive waste processing. In the case of

both units, the original (as built) systems were described, which included the use of

evaporacors to process floor and equipment drain liquids, and cement solidification

systems for ensuring solid waste form compliance. No waste evaporators or

cement solidification systems have been used at Unit 1 since 1988. At Unit 2,

neither the waste evaporator nor the Stock cement system have ever been used.

Notwithstanding, the solid waste processing description is also contained in Chapter

18 of each unit's Operations Manual, which also forms the bases for each unit's

Process Control Program (PCP). As discussed in Section R8 below, the licensee

previously committed to the NRC to provide a revision of the UFSAR for each unit,

and willinclude revisions to the liquid and solid radwaste processing systems to

20

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.

'

reflect current plant operations. At the exit meeting on May 16,1997, the licensee

also indicated that a similar review of the PCP for each unit would be conducted,

and revisions, as appropriate, would be made. (IFl 50-334(412)/97004-04)

The inspectors also reviewed the licensee's procedures used in the radwaste and

transportation program, with particular emphasis on procedures related to the

implementation of the transportation regulations contained in 49 CFR. Table R1 i

contains a listing of the procedures reviewed. The inspectors noted that in several

instances, the licensee's procedures contained only minimalinformation. Based on i

discussions with licensee personnel and direct observations made by the inspectors,  !

it appeared that the licensee was very dependent on the personal knowledge of key

individuals for implementing the transportation program. Program support, as l

provided by procedures, was weak. For example, while procedure RP 3.23,

Revision 1, contains detailed information on how to perform a hand calculation for

)

I

ensuring materials to be transported meet the activity criteria for shipment as low

specific activity (LSA) or st mntaminated object (SCO), no guidance on what l

! constitutes LSA material or an J is provided. Additionally, no procedural J

guidance or justification is provit d for the selection of packaging for radioactive '

material. Although the inspectors did not identify any errors in the packaging and

transport of radioactive materials from the licensee's facility, the lack of detailed

procedural support in this area is a weakness.

,

]

Since the mid-1980's the licensee has done an excellent job in the development and

tracking of scaling factors for difficult to measure radionuclides. Detailed analysis

and trending data for radionuclides found in the licensee's waste streams were

readily retrievable and clearly demonstrated the licensee's detailed knowledge in this

area. Since the licensee has experienced few failed fuel pins, the waste streams for

both units have remained fairly constant over the past several years for both units.

,

The inspectors reviewed seven radioactive material shipment records, two from

1996 and five from 1997. These shipment records included materials being sent

for burial as radwasts, materials for radwaste processing and/or decontamination,

laundry and chemical samples. The shipments reviewed were well documented,

and contained allinformation necessary to properly classify the shipments for  ;

transportation and disposal (as applicable).

The inspectors toured the liquid and solid radwaste processing areas at both units

with members of the radwaste operations staff. All areas inspected at both units

were found to be appropriately posted for radiological control, and to be generally

well maintained and free of unnecessary debris. No leaking of materials from tanks

and vessels was observed. In Unit 1, the waste evaporator system, which was

utilized until 1988 was determined to be oppropriately decontaminated to minimize

exposures to plant personnel. Solidificat;on and waste evaporator systems at Unit 2

were never utilized, and thus radiologica' controls were unnecessary.

21

,

. . _ - -- .. - - - -. - - . . . _ - -

.

. .

c. Conclusions

The licensee has established a generally effective program for the processing and

transportation of radioactive materials, with the exception of procedural weaknesses

and out-of-date system descriptions. All shipments of radioactive materials

'

reviewed were determined to be in full compliance with Titles 10 and 49 CFR.

Weaknesses were identified in the documentation of plant processes found in the

UFSAR and PCP at both units.

4 R5 Staff Training and Qualification in RP&C

a. Insoection Scoce (86750 & Tl 2515/133)

'

The inspectors reviewed the licensee's training program for all staff members

i'

involved in the transportation of radioactive material (in accordance with 49 CFR

172.700) and radinaste shipments for disposal (in accedance with NRC IE

Bulletin 79-19).

-

b. Observations and Findinas

-The inspectors reviewed the licensee's training programs for plant personnel

involved in the transportation of radioactive materials and radioactive wastes.

Training was given on a biennial basis, and included members of the operations and

health physics staffs, and the QA organization. Training was also given to the lead

training instructor through the use of vendor supplied courses. In 1996, in

3 preparation for the implementation of the revisions to 49 CFR, the licensee brought

in a contractor and used this training to meet its biennial training commitment.

c. Conclusions

The licensee has established a successful training program for staff members

involved in the transportation and disposal of radioactive materials.

R7 Quality Assurance in Radiological Protection and Chemistry Activities

a. Inspection Scoce (86750)

The inspectors reviewed audits and surveillance conducted by the licensee's Quality

Assurance Department in the area of radwaste processing and transportation of

radioactive materials,

b. Observations and Findinas

The inspectors discussed the quality assurance program as it pertains to radwaste

processing and transportation of radioactive materials with the lead Quality

Assurance (QA) auditor for this area. This discussion included a review of the

licensee's current on-going QA audit of the radwaste program, and surveillances

conducted by QA during 1996 and 1997. The inspectors noted the focus of both

the audit and surveillance on in-plant performance, including the use of a contractor

22

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.

.

specialist for the on-going radwaste audit, and the numerous surveillances in

radwaste/ transportation that were conducted. In general, these reports were

determined to be of sound technical basis, and of sufficient depth to identify both

existing issues and declining trends in performance. The QA auditor also discussed

with the NRC inspectors the similarity of findings regarding deficiencies in the PCP

and UFSAR related to outdated system and process descriptions,

c. Conclusion.g

The licensee's QA program for radwaste and transportation, including audits and

surveillance is of generally high quality. Sufficient scope and technical depth is

present to aid in the timely identification of issues and declining performance in

these areas.

L1 Review of Updated Final Safety Analysis Report (UFSAR) Commitments

A recent discovery of a licensee operating their facility in a manner contrary to the

Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a i

special focused review that compared plant practices, procedures and/or parameters

to the UFSAR description.

- While performing the inspections discussed in this report, the~ inspectors reviewed

the applicable portions of the UFSAR that related to the areas inspected. Unit 1

UFSAR heat trace discrepancies are discussed in Section M8.1 of this report. Tne

inspectors identified that the system and proc 3ss descriptions for the liquid and

solid radweste processing at both units, contained in Chapter 11-of each unit's

UFSAR was significantly out-of-date and did not accurately reflect current plant

operations. The licensee is currently committed to completing a UFSAR verification

project by December 21,1998 (Duquesne Light Company letter to the NRC, dated

December 26,1996). Corrections to these sections will be included in this

submission.

The UFSAR does not specifically includ3 security program requirements; therefore,

.

the inspectors compared licensee activities to the NRC-approved physical security

plan, which is the applicable document. While performing the security inspection,

the inspectors reviewed Section 3.2.1.5 of the Plan, Revision 32 dated

February 7,1997, titled, " Search and Admittance Control Hardware." The

inspectors determined, by observing access control equipment testing, discussions

with security supervision and reviews of applicable procedures and records, that

search and admittance control hardware was tested and maintained as required in

the Plan and applicable procedures.

S1 Conduct of Security and Safeguards Activities

a. Inspection Scope (81700)

Determine whether the security program, as implemented, met the licensee's

commitments in the NRC-approved security plan (the Plan) and NRC regulatory

requirements. The security program was inspected during the period of

I 23

.

- - e- , -r .r- --- , a r -- ~rv-g y

. - . -. . - -. - - - .. - - . -- .- .

.

.

May 12-16,1997. Areas inspected included: management support and audits;

effectiveness of management controls; protected area detection equipment; testing,

maintenance and compensatory measures; and the vehicle barrier system.

b. Observations and Findinas

Management support was evident by the procurement and replacement of two x-ray

package search units, the development and installation of tactical response delay

barriers and defensive fighting positions, and the Manager of Security's position in

the organizational structure and reporting chain permits management's awareness

of issues and concerns. Management controls for identifying, resolving, and

preventing programmatic problems were effective, protected area detection aids

were installed and maintaineti as required by the NRC-approved physical security

plan (the Plan), and audits were thorough and in-depth. Security equipment testing

was being performed as required in the Plan and maintenance of security equirment

was being performed in a timely manner as evidenced by minimal compennmy

posting associated with security equipment repairs.

Based on inspectors' observations and discussions with plant engineering and

security management, the inspectors determined that the licensee's provisions for

-land vehicle control measures satisfy regulatory requirements and licensee ,

commitments. As an enhancement to the inspection, the UFSAR initiative,

Section 3.2.1.5 of the Plan, titled " Search and Admittance Control Hardware," was

reviewed. The inspectors determined, by observing access control equipment

testing, discussions with security supervision and reviews of applicable procedures

and records, that search and admittance control hardware is being tested and

maintained as required in the Plan and applicable procedures.  !

c. Conclusions

The inspectors determined that the licensee was conducting its security and

safeguards activities in a manner that protected public health and safety and that

the program, as implemented, met the licensee's commitments and NRC

requirements.

S2 Status of Security Facilities and Equipment

l

S2.1 Protected Area Detection Aids

a. Inspection Scooe (81700)

Conduct a physical inspection of the PA intrusion detection systems (IDSs) to verify

that the systems were functional, effective, and met licensee commitments.

)

l

b. Observations. Findinas and Conclusion '

On May 14,1997, the inspectors conducted a walkdown of the protected area

perimeter and determined, by observations, and by reviewing applicable testing and

24

L l

1

.

,

maintenance records that they were functional and effective, and were installed and

maintained as described in the Plan.

S2.2 Testino Maintenance and Compensatorv Measures

a .- Insoection Scope (81700)

Determine whether programs are implemented that will ensure the reliability of

security related equipment, including proper installation, testing and maintenance to i

replace defective or marginally effective equipment. Additionally, determine that I

when security related equipment fails, the compensatory measures put in place are l

comparable to the effectiveness of the security system that existed prior to the i

failure, l

b. Observations and Findinos

The inspectors reviewed testing and maintenance records for security-related

equipment and found that documentation was on file to demonstrate that the

licensee was testing and maintaining systems and equipment as committed to in the

Plan. A priority status was being assigned to each work request and repairs were

normally being completed within the same day a work request necessitating

compensatory measures was generated. The inspectors also noted that the

working relationship between security, maintenance and the instrumentation and

control (l&C) departments was excellent as evidenced by the noticeable decline in

open work requests related to security equipment during the review of maintenance j

records. Specifically, in November 1995, the inspectors noted a total of 76 open

.

)

work requests, in May 1996,40 open work requests were noted, and as of this i

inspection 18 open work requests were noted, none which required compensatory

measures,

i

'

c. Conclusions

Documentation on file confirmed that security equipment was being tested and

maintained as required. Repair work was timely and the use of compensatory i

measures was found to be appropriate and minimal.

S6 Security Organization and Administration

a. Insoection Scoce (81700)

Conduct a review of the level of management support for the licensee's physical

security program.

b. Observations and Findinas

The inspectors reviewed various 5 '

,n,  ; since the last

program inspection, which was col, , iese enhancements

included the procurement and replac6i ackage search units to

enhance access control of packages into i.. '

't ..a area and the development

25

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,

!

!

.

and installation of tactical response delay barriers and defensive fight:ng positions in

preparation for the March 1 - April 3,1997, OSRE. The inspectors reviewed the

, Security Manager's position in the organizational structure and reporting chain. The i

Manager of Security reports to the General Manager Nuclear Support, who reports I

directly to the Vice President Nuclear Services. Additionally, the inspectors noted

! that the access authorization program, being safeguards related, report directly to

the Manager of Security.

J

c. Conclusions

Management support for the physical security program was determined to be

effective. No problems with the organizational structure that would be detrimental

j. to the effective implementation of the security and safeguards programs were

noted. 1

S7 Quality Assurance in Security and Safeguards Activities )

S7.1 Effectiveness of Maneaement Controls

l a. Insoection Scoce (81700)

Determine if the licensee has controls for identifying, resolving and preventing

programmatic problems,

b. Observations and Findinos

The inspectors reviewed the licensee controls for identifying, resolving, and

preventing security program problems. These controls included the implementation

of a departmental self-assessment program, which includes the performance of

observation tours by security supervision and the performance of the NRC-required

annual quality assurance (QA) audits. The licensee also utilizes industry data, such

as violations of regulatory requirements identified by the NRC at other facilities, as

criteria for self-assessment. The inspectors reviewed documentation applicable to

the performance of the self-assessment program and noted that five self-

assessment and 25 observation tours were conducted in 1996 and as of this

inspection, one self-assessment and five observation tours were performed during

1997. The inspectors determined, based on a review of the safeguards event logs,

self-assessments and observation tours, that personal performance errors were

minimal.

c. Conclusions

The inspectors concluded that controls were effectively implemented to prevent and

resolve potential weaknesses.

26

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.

l

5 l

. .

l S7.2 Audits

F

a. insoection Scope (81700)

L

' i

~ Review the licensee's QA report'of the NRC-required security program audit to

<-

determine if the licensee's commitments as contained in the Plan were being

satisfied.

b. Observations and Findinas

I

,

The inspectors reviewed the 1997 QA audit of the security program, conducted

'

January 29 - March 18,1997, (Audit No. BV-C-97-03) and the 1996 QA audit of

the fitness for-duty (FFD) program, conducted May 13 - August 26,1996. The

, audits were found to have been conducted in accordance with the Plan and FFD

.

rule. To enhance the effectiveness of the' audits, the security audit team included I

l one independent security specialist and the FFD audit team included two technical

specialists.  !

,  !

'

The security audit report identified five condition reports (CRs) and seven

recommendations. Two CRs were written against the maintenance department, ~one

} . CR was written against Nuclear Documentation and Records, and two CRs were i

written against security. The security CRs involved Plan revisions and procedural

reviews not being performed in e timely manner. The FFD audit identified one CR

and one recommendation. The FFD CR involved the dissemination of continual

j behavioral observation training information during supervisor and escort FFD - i

j training. The CRs were not indicative of programmatic weaknesses but would

i enhance program effectiveness. The audit results had been disseminated to the

J- appropriate lovels of management. The inspectors determined, based on

g discussions with security management and FFD supervision and a review of the

responses to the CRs, that the corrective actions were effective. 1

c. Conclusions  !

The inspectors' review concluded that the audits were comprehensive in scope and

depth, that the findings were appropriately distributed and addressed and that the

3

audit program was being properly administered.

S8 Miscellaneous Security and Safeguards issues (81700, Tl 2515/132)

S8.1 Vehicle Barrier System (VBS)

l

General i

On August 1,1994, the Commission amended 10 CFR Part 73, " Physical Protection

, of Plants and Materials," to modify the design basis threat for radiological sabotage

to include the use of a land vehicle by adversaries for transporting personnel and

their hand-carried equipment to the proximity of vital areas and to include the use of

I a land vehicle bomb. The amendments require reactor licensees to install vehicle

control measures, including vehicle barrier systems (VBSs),' to protect against the

i

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\

J

l

I

malevolent use of a land vehicle. Regulatory Guide 5.68 and NUREG/CR-6190 were

issued in August 1994 to provide guidance acceptable to the NRC by which the t

licensees could meet the requirements of the amended regulations, j

A March 29,1996, letter from the licensee to the NRC forwarded Revision 29 to its

physical security plan that detailed the actions implemented to meet the  !

requirements of 10 CFR 73.55 (c)(7) and the design goals of the " Design Basis Land

Vehicle" and " Design Basis Land Vehicle Bomb." A NRC September 26,1996, ,

letter advised the licensee that the changes submitted had been reviewed and were I

determined to be consistent with the provisions of 10 CFR 50.54(p) and were

acceptable for inclusion in the NRC-approved security plan. {

-This inspection, conducted in accordance with NRC Inspection Manual Temporary

Instruction 2515/132, " Malevolent Use of Vehicles at Nuclear Power Plants," dated

January 18,1996, assessed the implementation of the licensec's vehicle control

measures, including vehicle barrier systems, to determine if they were

commensurate with regulatory requirements and the licensee's physical security

plan.

S8.2 Vehicle Barrier System (VBS)

{

a. Insoection Scone

l

1

The inspectors reviewed documentation that described the VBS and physically

inspected the as-built VBS to verify it was consistent with the licensee's summary

description submitted to the NRC and was in accordance with the provisions of

NUREG/CR-6190.

'

b. Observations and Findinas i

The inspectors' walkdown of the VBS and review of the VBS summary description i

disclosed that the as-built VBS was consistent with the summary description and

met or exceeded tha specifications in NUREG/CR-6190. )

l

c. Conclusion '

The inspectors determined that there were no discrepancies in the as-built VBS or

the VBS summary description.

S8.3 Bomb Blast Analysis

l

a. Insoection Scope

The inspectors reviewed the licensee's documentation of the bomb blast analysis l

and verified actual standoff distances provided by the as built VBS. l

l

t

28 I

!

i

_ _ _ . , _ _ _ _ . _ _ _ _ _ _

..

.

4- b. Obsetvations and Findinas

] The inspectors' review of the licensee's documentation of the bomb blast analysis

determined that it was consistent with the summary description submitted to the

NRC. The inspectors also verified that the actual standoff distances provided by

their as-built VBS were consistent with the minimum standoff distances calculated

using NUREG/CR-6190. The standoff distances were verified by review of scaled

drawings and actual field measurements,

c. Conclusion

No discrepancies were noted in the documentation of bomb blast analysis or actual i

standoff distances provided by the as-built VBS.

S8.4 Procedural Controls ,

a. Inspection Scope  !

~

The inspectors reviewed applicable procedures to ensure that they had been revised

to include the VBS.

b. Observations and Findinas

The inspectors reviewed the licensee's procedures for VBS access control

measures, surveillance and compensatory measures. The procedures contained

.

effective controls to provide passage through the VBS, provide adequate

surveillance and inspection of the VBS, and provide adequate compensation for any

degradation of the VBS.

c. Conclusions

The inspectors' review of the procedures applicable to the VBS disclosed no

discrepancies.

V. Manaaement Meetinas

X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee manage rent on  ;

May 16 and June 19,1997. The licensee acknowledged the findings presented.

The inspectors asked the licensee whether any materials examined during the inspection

should be considered proprietary. No proprietary information was identified.

!

29

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i

,

l

.

ATTACHMENT

PARTIAL LIST OF PERSONS CONTACTED

D_LC

R. LeGrand, Vice President, Nuclear Operations / Plant Manager

S. Jain, Vice President, Nuclear Services

B. Tuite, General Manager, Nuclear Operations  !

C. Hawley, General Manager, Maintenance Programs Unit

K. Beatty, General Manager, Nuclear Support Unit

J. Arias, Director, Safety & Licensing

K. Ostrowski, Manager, Quality Services

R. Vento, Manager, Health Physics

D. Orndorf, Manager, Chemistry

'M. Johnston, Manager of Security

R. Hart, Supervisor, Regulatory Compliance {

D. Kline, Director Nuclear Security Operations

N. DiPietro, Supervisor Security Services

J. Belfiore, Senior Quality Assurance Specialist

D. Price, Senior Engineer

C. Custer, Acting Manager, System and Performance Engineering

M. Perger, Director, Quality Services Unit

R. Hart, Senior Licensing Supervisor, Compliance

A. Mizia, Supervisor, Quality Services Unit

T. Porter, Supervisor, Quality Services Unit

NILG

D. Kern, SRI

G. Dentel, RI

F. Lyon, RI

J. Furia, RP Specialist

G. Smith, Security Specialist

E. King, Security Specialist

INSPECTION PROCEDURES USED

i

IP 37551: Onsite Engineering

i

IP 61726: Surveillance Observation

IP 62707: Maintenance Observation

IP 71707: Plant Operations

IP 71750: Plant Support

IP 81700: Physical Security Program for Power Reactors

IP 86750: Sold Radioactive Waste Management and Transportation of Radioactive l

Waste ,

IP 92901: Follow-up - Operations ,

IP 92903: Follow-up - Engineering

IP 92904: Follow-up - Plant Support I

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. IP 92700: Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor

Facilities

IP 93702: Event Response

Tl 2515/132: Malevolent Use of Vehicles at Nuclear Power Plants

Ti 2515/133: Implementation of Revised 49 CFR Parts 100-179 and 10 CFR Part 71

ITEMS OPENED, CLOSED AND DISCUSSED

Open

50-334/97004-01 VIO Operations personnel failures to identify conditions

adverse to quality (Section 01.3)

50-334(412)/97004-04 IFl PCP Program Update (Section R1)

Closed

50-334(412)/97004-02 NCV Failure to Follow ANS Guidelines for Operating Orders

and Special Orders (Section 03.1)

50-412/97004-03 NCV Condition Prohibited by TS - Containment Penetration  ;

Not isolated Within Time Limit (Section 08.1)

50-412/96002 LER Condition Prohibited by TS - Containment Penetration

not Isolated within Time Limit (Section 08.1)

50-334/96010-03 URI Potential Unit 1 RWST Heat Trace Design Discrepancies

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(Section M2.1)

50-412/96010-05 URI EDG 2-1 Operability with 2EGS-19 Closed (Section

E8.1)

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NRC Tl 2515/132 TI . Malevolent Use of Vehicles at Nuclear Power Plants

1 (Sections S8.1-S8.5)

J NRC Tl 2515/133 Tl Implementation of Revised 49 CFR Parts 100-179 and

10 CFR Part 71 (Section R1)

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LIST OF ACRONYMS USED

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AOP Abnormal Operating Procedure

ARPI Analog Rod Position Indicator

BVPS Beaver Valley Power Station

CAS Central Alarm System

CCTV Closed Circuit Television

CFR Code of Federal Regulations

CR Condition Report

DCP Design Change Package

DLC Duquesne Light Company

FFD Fitness-for-Duty

FIN Fix it Now

GMNO General Manager Nuclear Operations

l&C Instrumentation and Control

IDS Intrusion Detector System

IEEE Institute of Electrical and Electronics Engineers

IFl Inspection Follow-up ltem

LCO Limiting Condition for Operations

LSA Low Specific Activity

MWR Maintenance Work Request

NCV Non-Cited Violation

NSS Nuclear Shift Supervisor

OST Operational Surveillance Test

PA Protected Area

PCP Process Control Program l

PDR Public Document Room

PMP Post Maintenance Testing l

QA Quality Assurance  !

RO Reactor Operator I

RP&C Radiological Protection and Chemistry l

SAS Secondary Alarm System

SFM Security Force Members

SNO Standing Night Order

SOO Special Operating Orders

SRO Senior Reactor Operator

SS Shift Supervisor

STA Shift Technical Assistance

SWS Service Water System

T&Q Training and Qualification i

TAGMNO Technical Assistant to the General Manager Nuclear Operations I

TER Technical Evaluation Report

the Plan NRC-Approved Physical Security Plan

TS Technical Specification 4

UFSAR Updated Final Safety Analysis Report

VBS Vehicle Barrier System

VIO Violation

WRT Work Request Tag 2 ,

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