ML20137T514

Insp Rept 50-458/97-06 on 970202-0315.Violations Noted. Major Areas Inspected:Operations,Maintenance,Engineering, Plant Support & Plant Status

ML20137T514
Person / Time
Site:	River Bend
Issue date:	04/11/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20137T485	List: ML20137T480 ML20137T492 ML20137T514
References
50-458-97-06, 50-458-97-6, NUDOCS 9704160111
Download: ML20137T514 (21)

See also: IR 05000458/1997006

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ENCLOSURE 2

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U.S. NUCLEAR REGULATORY COMMISSION I

REGION IV

Docket No.: 50-458

License No.. NPF-47

Report No.. 50-458/97-06

Licensee: Entergy Operations, Inc.

Facility: River Bend Station

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Location: 5485 U.S. Highway 61 l

St. Francisville, Louisiana 70775

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Dates: February 2 through March 15,1997

Inspectors: W. F. Smith, Senior Resident inspector

D. L. Proulx, Resident inspector

Approved By: P. H. Harrell, Chief, Project Branch D

Division of Reactor Projects

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Attachment: Supplemental Information l

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9704160111 970411

PDR ADOCK 05000458

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EXECUTIVE SUMMARY

River Bend Station

NRC Inspection Report 50-458/97-06

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This inspection included aspects of licensee operations, maintenance, engineering, and

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

Operations

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• In general, the performance of plant operators was professional and reflected a i

focus on safety, with the exception that entry into the at-the-controls area was not I

always properly controlled and the at-the-controls operator spent approximately l

20 minutes filling out nonwork-related paperwork (Section 01.1).

• A nuclear equipment operator (NEO) exhibited good practices and a questioning

attitude during rounds. However, the operator round sheets did not require periodic

checks of standby liquid control (SLC) pump parameters or a tour of the traversing

incore probe (TIP) system area (Section 01.2).

• The licensee appropriately trained the operators and staged materials for the

effective implementation of an emergency operating procedure (EOP)

(Section O2.1).

• A violation was identified for failure to develop administrative procedures with

apecific controls for reviewing and approving overtime for staff that performed

safety-related work. Severalindividuals exceeded the Technical Specification (TS) i

overtime limitations without proper administrative approvals (Gection 06.1). l

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• In general, the Nuclear Review Board (NRB) effectively reviewed plant issues and

recommended corrective actions, with notable exceptions. The excessive backlog

of Facility Review Committee (FRC) minutes impeded the NRB's ability to perform l

timely and effective oversight of FRC activities. Quality Assurance (QA)

surveillance resources were not allocated among the functional areas commensurate l

with performance (Section 07.1). I

Maintenance

• Mechanics performed good troubleshooting and correction of the Control Building

Chiller C low refr.'gerant temperature trip. The trip was caused by an isolated case

of poor workmenship related to a previous improper assembly of the economizer

valve float arm. A noncited violation (NCV) was identified for failure to properly

implement the applicable work instructions during the previous assembly

(Section M1.1).

• The Division il emergency diesel generator (EDG) maintenance outage was generally

well planned and performed. The electricians used a test configuration not

described in the maintenance action item (MAI) and wera unaware of whether or

not they complied with the procedure until reviewing wiring drawings later

(Section M1.2).

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• Personnel performed surveillance testing well. Self-checking was evident

(Section M1.3). i

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= The engineer performing the logic system functional test review exhibited excellent

attention to detailin identifying that the loss of power contact for the Division !! l

EDG rear air starting system was not properly tested. An NCV was identified for ,

failure to comply with TS Surveillance Requirement (SR) 3.0.2. The licensee's initial l

review of the past operability of Division 11 EDG was weak in that the review did not

discover a past outage of the forward air starting system (Section M1.4).

Enaineerina

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Reactor engineers demonstrated poor performance by calculating an incorrect full

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power exposure at which to change the operating limit minimum critical power ratio i

(OLMCPR). Consequently, a nonconservative limit was being monitored by the

reactor operators for 6 days; however, no thermallimits were exceeded

(Section E2.1). l

• The failure to maintain clear procedural guidance for the implementation of a

performance-based local leak rate test (LLRT) program resulted in missed

surveillance testing of some valves and unnecessary testing of other valves which

required taking safety-related systems out of service during plant operation at

power. A violation of TS 5.4.1.a was identified for failure to maintain the proper

guidance (Section E3.1).

Plant Sucoort

• Housekeeping in the plant continued to be excellent (Section 01.1).

• A violation for failure to post a radiation area was identified. On two occasions, the

radiation area posting at the entrance to the alternate decay heat removal (ADHR)

system room was modified without radiation protection (RP) technician approval.

Radiological postings were inappropriately relocated on two previous <.secasions,

which indicated that increased personnel sensitivity to radiologic.c! postings was

required (Section R1.1).

• Security boundaries were maintained properly and entry screening processes were

performed properly. The inspectors noted during night tours that the protected area

was properly illuminated (Section S1.1).

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Report Deta;ls

Summarv of Plant Status

The plant operated at essentially 100 percent power for the duration of this inspection

period.

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1. Operations

01 Conduct of Operations

01.1 General Comments (71707)

The inspectors conducted frequent reviews of ongoing plant operations including

control room observations, attendance at plan-of-the-day meetings, and plant tours.

, in general, the performance of plant operators was professional and reflected a

focus on safety, with minor exceptions. During a sustained control room

observation on February 11,1937, the inspectors noted that entrances into the

control room at-the-controls area were not controlled in accordance with licensee

policies. Several personnel entered the at-the-controls area without permission or a

stated operations purpose. In addition, the inspectors noted that the at-the-controls

operator spent approximately 20 minutes filling out nonwork-related paperwork.

The inspectors discussed these observations with the Operations Manager, who

stated that these observations did not reflect written management policies for

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control room conduct and operations personnel would be briefed on proper control

room conduct.

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Decisions made in support of maintenance were usually conservative based on the

inspectors' reviews of TS limiting conditions for operation entered and exited.

During plant tours, the inspectors found that housekeeping continued to be

excellent. Any minor discrepancies identified by the inepectors were promptly

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01.2 NEO Tours

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a. Inspection Scoce (71707)

On February 15,1997, during a backshift tour, the inspector accompanied the

reactor building NEO during the conduct of operator rounds. The operator rounds

included tours of the standby cooling tower, auxiliary building, fuel building, primary

containment, and several tunnels.

b Observations and Findinas

The inspector noted that the NEO demonstrated good self-checking techniques and

a questioning attitude during the tour. The NEO checked severalitems that were

important to safety but not specifically required to be signed off during the operator

rounds. The NEO identified two plant equipment deficiencies and wrote MAls for

the items. However, the inspectors identified two apparent weaknesses with the

operator round signoff sheets.

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The inspectors noted that the operator rounds procedure required the NEOs to

check lubricating oil level in several safety-related pumps and f ans, including the

emergency core cooling system and the standby service water pumps. However,

the operator round sheets only required a general inspection of SLC system area for

housekeeping purposes. Further, the round sheets did not specifically require the

NEOs to check the lubricating oil level of the SLC pumps or other appropriate pump

checks. During this inspection period, an MAI was issued for gasket replacement

on the Division 11 SLO pump because of a lubricating oil leak and a crack was

discovereo on the pump casing, which demonstrated a need to examine the SLC

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system during operator rounds.

The inspectors also noted that the operator round sheets required periodic entry

j (approximately every 2 weeks) into most of the high radiation and locked high

' radiation areas. In addition, the operator round sheets required a visual inspection

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of the suppression pool at the 95-foot elevation of containment. However, the

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round sheets required no entries into the area where the TIP system was located.

This area was identified as a high radiation area and was also located at the 95 foot

elevation of containment. The inspectors noted that, eckhout periodic tours of the

TIP system area, items could be in the suppression pc6 Lelow the TIP system area

and items could be left near the TIP system for a signWiuant period of time without

notice. The licensee performed maintenance in the TIP system area during this

inspection period, which required a number of items to be brought into the TIP

system area. The inspectors discussed improving the operator rounds weaknesses

with the Operations Manager, who stated that Operations would evaluate

improvements to the operator round sheets.

c. Conclusions

The NEO accompanied by the inspectors exhibited good operator practices and a

questioning attitude during reactor building operator rounds. The inspectors noted

areas for improvement with the operator round sheets in that the procedure did not '

require periodic checks of the SLC pumps or a tour of the TIP system area.

02 Operational Status of Facilities and Equipment

O2.1 Walkdown of EOP Suonortina Enclosures

On February 2% 1997, the inspectors evaluated licensee implementation of an EOP

supporting enclosure was contained within Pr2,ceire EOP 5, " Emergency Operating

Procedures-Enclosures," Revision 9. The inspectors walked down Enclosure 4,

which addressed defeating the isolation of the reactor water cleanup . system on low

reactor pressure vessel level and upon initiation of SLC. The inspectors verified that

all keys and tools were staged and that on-shift licensed operators wr e sufficiently

f amiliar with the actions stated in these enclosures. The inspectors t eluded that

the licensee adequately trained the operators and staged materials for effective

implementation of Enclosure 4 of Procedure EOP 5.

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06 Operations Organization and Administration ,

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06.1 Plant Staff Overtime Review

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a. Inspection Scoce (71707)

The inspectors reviewed tha overtime records of Operations, Radiation Protection,

and Plant Engineering personnel for January and February 1997 to ensure that the

licensee met the requirements of TS 5.2.2.e. In addition, the inspectors reviewed

proceoures to ensure that the TS was properly implemented.

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The requirements for controlling on-shift operator overtime were contained in

Procedure ADM-0022, " Conduct of Operations," Revision 19. This procedure

required formal documentation of the reasons for exceeding the TS overtime limits

in the control room operator log. The inspectors reviewed operator time sheets and

noted no instances of operating shift personnel exceeding the overtime 1

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requirements. However, the inspectors noted that everal individuals routinely

worked 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a 7-day period with the plant cytru sting. This heavy work

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schedule did not meet the intent of TS 5.2.2.e, which states that the operating shift

1 complement shall be met without routine heavy use of overtime. The inspectors l

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also noted that several support staff personnel exceeded 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48-hour

period and 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in a 24-hour period. The licensee stated that because these

personnel were reviewing condition reports (CR), writing procedures, and I

performing other support functions, the support personnel were not considered

subject to the TS restrictions on working hours.

The inspectors reviewed the overtime controls for Radiation Protection personnel.

The inspectors noted that Procedure RBNP-024, " Radiation Protection Plan,"

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Revision 7, implemanted the requirements of TS 5.2.2.e. However,

Procedure RBNP-024 merely repeated the words of TS 5.2.2.e, which states that

deviations from the TS overtime guidelines shall be authorized by the Plant Manager

4 or his designee in accordance with approved procedures. Procedure RBNP-024 did

not identify the procedure to be used. The inspectors identified five instances of

pesonnel exceeding 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in a 48-hour period. The Radiation Control

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Superintendent stated that the extra hours worked (up to 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />) were shift

turnover activities. The inspector noted that the extra hours were spent in radiation

protection shop meetings and training, which the licensee considered to be part of

shift turnover.

The inspectors reviewed the overtime of system engineers for January and

February 1997 and noted 14 instances where the TS limits were exceeded. For

exaniple, one individual worked 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> in a 24-hour period. The Manager, Plant

Engineering stated that none of these system engineers had performed

safety-related work, although records indicated that these individuals spent

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significant amounts of time in the plant during their work periods. No procedure

was in place to control overtime of system engineers, as required by the TS.

The inspectors reviewed Procedure ADM-0023, " Conduct of Maintenance,"

Revision 138, to ascertain how the Maintenance Department implemented

TS 5.2.2.e. Section 8.1.5 of Procedure ADM-0023 stated that overtime shall be

controlled per Section 5 of the TS. No further direction was given for how overtime

for maintenance personnel was to be controlled administratively.

The inspectors requested that the licensee provide objective evidence that the Plant

Manager or his designee performed monthly reviews of overtime assigned as

required by TS 5.2.2.e. The licensee did not have objective evidence that these

reviews were performed. However, the licensee stated that when supervisors

reviewed their employees' time sheets, they ensured that excessive hours were not

worked. The inspectors performed a review of CRs dating back 3 years and noted

that no CRs were written concerning excessive overtime during this period of time.

In addition, the last CR written for personnel exceeding overtime controls was

written in 1994 by QA personnel, which appeared to indicate the quality of these

reviews was questionable.

TS 5.2.2.e states, in part, that procedures shall be developed to limit the working

hours of staff who perform safety-related functions, in addition, TS 5.2.2.e

. requires specific controls for the Plant Manager or his designee to document

exceeding the overtime limits and perform monthly reviews of overtime usage. The

procedures did not clearly delineate how each of these functions was to be

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performed for all of the personnel performing safety-related functions and what

specific controls were in place. In addition, the procedures did not define what

constituted safetyw lated work or shift turnover. The failure to maintain specific

administrative procedures that delineated specific controls for reviewing and

approving overtime for personnel who perform safety-related functions is a violation

of TS 5.2.2.e (50-458/9706-01).

c. Conclusions

A violation was identified for failure to develop administrative procedures with

specific controls for reviewing and approving personnel overtime. The licensee's

process for controlling overtime was weak in that the process was fragmented and

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was without clear definitions, lines of responsibility, and administrative processes.

Several individuals exceeded the TS overtime limitations without proper

administrative approvals.

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07 Quality Assurance in Operations

07.1 Nuclear Review Board

j a. inspection Scoce (71707)

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l The inspectors attended thc NRB meeting held on February 21,1997, and reviewed

the subcommittee reports and various presentations.

b. Observations and Findinas

The NRB meeting consisted of presentations on several safety and plant

performance issues, which was followed by formal discussion of these issues by

the members. The inspectors noted that, in general, the NRB membership asked

probing questions and recommended appropriate corrective actions.

The subcommittee for the FRC identified that the FRC minutes had not been issued

in a timely manner. There was a backlog of approximately 25 sets of minutes with

some being about 1 year late. The inspectors noted that untimely issuance of FRC

minutes impacted the NRB's ability to perform its oversight function because the

NRB bases much of its review of FRC effectiveness on FRC minutes. The licensee

initiated a CR to enter this item into the corrective action program. Although the

untimely issuance of the FRC minutes was indicative of poor performance, the FRC

charter did not have timeliness goals and no violation of NRC requirements

occurred.

The inspectors also observed the presentation of the NRB subcommittee that

provided oversight of the QA organization. The subcommittee concluded that QA

was effective without an apparent definition of what constituted QA effectiveness

(e.g., was QA reactive or were outside organizations identifying major issues that

QA had audited). The NRB recognized that QA required improvement but did not

emphasize some performance issues. For example, during the past quarter, QA

performed 17 surveillances of Maintenance, 5 of Engineering, and 3 of Operations.

The inspectors noted that these three functional areas have performed at the same -

level, as identified in the recent Systematic Assessment of Licensee Performance

report, so QA allocation of resources for surveillances did not appear to be

performance based. The NRB was not aware of the basis for the number of

surveillances performed in each area, in addition, one NRB member noted that a

number of QA reports were written and reviewed by the sarre person, but no action

was taken by the NRB to review whether or not this was considered a good

practice. The inspectors also noted that none of the subcommittees contained ,

outside members, which could have added to the quality of the subcommittee i

reviews.

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The inspectors discussed these observations with the Director, Nuclear Safety (the

NRB chairman) who agreed with the comments. The licensee initiated actions to

improve the effectiveness of the NRB.

c. Conclusions

The NRB was generally effective in reviewing plant issues and recommending

appropriate corrective actions. The excessive backlog of FRC minutes impeded the

NRB's ability to perform timely and effective oversight of FRC activities. QA

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surveillance resources were not allocated among the functional areas commensurate

with performance.

08 Miscellaneous Operations issues (92901)

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08.1 (Closed) Inspection Followun item (IFI) 50-458/95026-01: Review of methods used

1 by the licensee to manage overall plant risk associated with on-line maintenance.

The inspectors reviewed " River Bend Station On-Lins Maintenance Guidelines,"

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Revision 0, which was prepared by the on-line maintenance natural work team. The

document provided guidelines for integrating quantitative and qualitative risk

insights into the on-line maintenance process. The guidelines described the on-line

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maintenance process, which included the role of the various disciplines involved and

use of the equipment out of service (EOOS) computer.

The inspectors attended a 2-week look-ahead meeting on February 26,1997. This

meeting was attended by planners from the various Maintenance, Operations, and

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Radiation Protection disciplines, the work week manager for the week being

planned, the outage management senior planner who operated the EOOS computer,

the work control supervisor, and others. The attendees discussed the proposed

work, testing, and operations on the plant planned for the week of March 9. There

was a good exchange of information and the inspectors noted that the EOOS

planner was knowledgeable of the nature of the activities and their impact on the

plant. This individual was also a licensed reactor operator in the past.

On February 27, the inspectors observed the outage management senior planner

apply the EOOS program to the information gained in the February 26 meeting

above. The planne demonstrated proficiency in applying the program and produced

a report that identified the plant safety index for each day and night during the

planned week of March 9. The plant safety index was a simplified graded

representation of core damage frequency. The values for the week of March 9

were Green (nonrisk significant) even though there suas a Division 11 EDG outage

planned. This was expected, however, because the planners staggered the

equipment outages to minimize diverse system outages and the 12-week revolving

schedule restricted the week of March 9 to Division ll only, which eliminated the

potential for a loss of safety fonction.

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The inspectors interviewed the operating personnel on day shift on February 27 and 1

found that the shift technical advisor and the work control supervisor had a working 1

j knowledge of the EOOS computer monitor. They were cognizant of the need to l

. utilize the EOOS program when emergent work or testing appeared or the schedule j

i shifts to the extent that safety-significant equipment could be placed out of service.

This was acceptable.

11. Maintenance

M1 Conduct of Maintenance

M1.1 Troubleshootina of Control Buildina Chiller C

a. Insoection Scope (62707)

The inspectors observed portions of troubleshooting activities associated with tiie

low refrigerant temperature trip of safety-related Control Building Chiller C. The

work was accomplished in accordance with MAI 310606.

b. Observations and Findinas

On February 19,1997, Control BuilJing Chiller C tripped off because of low

refrigerant temperature. This chiller provided air conditioning to the control building,

including the main control room. Chiller D started automatically and assumed the

load, as designed.

The operators declared the chiller inoperable and since there was another operable l

100 percent capacity chiller in Division I, TS limiting conditions for operation were j

met. CR 97-0227 was initiated to enter the prob lem into the corrective action

program. Chiller C was overhauled in the fall of 1996, including the chemical j

cleaning of the chiller heat exchangers. Subsequent to the cleaning, there were

problems experienced after the startup of the chiller with refrigerant strainers

becoming clogged. This was resolved by repeated running of the chiller and

cleaning of the strainers and filters. This appeared to have been successful until the

February 19 trip of the chiller. The licensee suspected that the strainer and filter

were clogged again, so the MAI instructed the mechanics 'io open and inspect the

strainer in the economizer and tho filters in the filter / dehydrator.

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The inspectors reviewed the MAIinstructions and found them to be well written

and concise. The inspectors observed the mechanics as they opened both ends of

the economizer to inspect for clogged strainers or foreign materiai. The work was

performed well and in accordance with the mal instructions. The mechanics were

trained and experienced in working with the chillers.

When mechanics removed the head from the high side of the economizer, the float

valve float was lying in the bottom, disconnected from the valve operating shaft.

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The system engineer explained that failure of the float valve to operate properly 1

caused the chiller to trip on low refrigerant temperature because there was

insufficient refrigerant returning to the evaporator. The system engineer l

documented this problem in CR 97-0227. The inspectors noted that the fastener

compressing the clamp on the end of the float arm was not tight enough to

compress the lock washer and secure the arm to the valve shaft; therefore, the float  !

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worked itself off the valve shaft. Because there was a key on the valve shaft, the l

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float valve probably functioned properly until it fell off the valve shaft. l

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System Engineering management evaluated the loose fastener issue and determined j

that this was an isolated workmanship problem not affecting the other three  !

safety related chillers because they had not been dismantled recently for major

cleaning as was Chiller C. The issue of human performance was referred to the '

In-House Events Analysis group for root cause and corrective action determination

in accordance with the corrective action program.

The inspectors questioned maintenance management as to the cause of the i

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improper assembly of the float arm. The inspectors reviewed the documentation of  !

the previous installation of the economizer float arm, which occurred on 1

October 13,1996 (MAI 307327). The inspectors found that the instructions were

adequate to properly install the float arm and apparently were not followed. The )

Mechanical Maintenance Superintendent stated that the instructions were adequate  !

and the mechanics failed to self-check or peer check the installation. This was

exacerbated by the limited accessibility of the fastener for tightening in accordance i

with MAI 307327.

Corrective actions taken or planned by the licensee included checking the

economizer low side float arm (it was properly installed), ensuring the high side float

arm was properly reassembled by checking for tightness on the valve shaft,

changing the mal instructions to specifically check the float arm for proper

assembly during future work on all the safety-related chillers, and reinforcing

self-checking and peer checking while reviewing this incident with mechanical

maintenance personnel.

Failu e to comply with the written instructions in MAI 307327 for installation of the

Chiller C economizer float arm is a violation of TS 5.4.1.a. However, this

self-identified and licensee-corrected violation is being treated as an NCV consistent

with Section Vll.B.1 of the NRC Enforcement Policy. Specifically, the violation was

self-identified and documented by the licensee, was not willful, actions taken as a

result of a previous violation should not have corrected this problem, and

appropriate corrective actions were completed by the licensee (50-458/9706-02).

c. Conclusions

Mechanics demonstrated good performance as they perfrmed troubleshooting and

correction of the Control Building Chiller C low refrigerant temperature trip. The trip

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resulted from improper assembly of the chiller economizer valve float arm. An NCV

i was identified for failure to properly implement the applicable work instructions

during the previous assembly.

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l M1.2 Dsion 11 EDG Outaae

a. Inmeetion Scoce (62707)

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The inspectors witnessed the following MAls on March 12,1997, during the  :

Division II EDG maintenance outage. )

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' MAI P593078 Calibrate Temperature Switch 1EGS-TS2B l

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MAI P593131 Calibrate Temperature Switch 1EGS-TS9?R

MAI P591340 Preventive maintenance on Breaker 1ENSSWGR-BKR-ACB27

(Division II EDG 4160 Volt Supply Breaker) j

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i b. Observations and Findinas

The inspectors noted that the Division 11 maintenance outage was well planned with

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the Division ll EDG unavailability time minimized. MAls P593078 and P593131 -

were performed well ent' in accordance with procedures.

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During performance of MAI P591340, the electricians timed the breaker opening

and closing using a test cabinet. Step 9.9.1 required the electricians to connect

, the breaker test cabinet leads to Terminals 6,7, and 9 of the secondary ,

disconnects. The breaker primary disconnects were required to be connected to the i

timer and the timer connected again using the secondary disconr'ects. The

electricians connected the leads from the timer to test ja':ks on the face of the plant

breaker test cabinet,

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The inspectors questioned the electricians on this practice because the timer test  ;

leads were not connected directly to Terminals 6,7, and 9. The electricians replied

that the MAI was written for performance of the preventive maintenance in the

shop, rather than using the breaker test cabinet installed in the field. The

electricians further stated that the configuration used was functionally equivalent to I

the setup described in the MAI and they intended to perform the work, then revise

the MAI to fit the methodology used. The electricians did not know if the test

setup that they used actually connected through Terminals 6,7, and 9 of the

breaker. The technicians completed the task and the breaker was retested

satisfactorily.

Following completion of the task, the electricians researched the acceptability of the

test setup using wiring drawings. The electricians found that they had actually

used Contacts 6,7, and 9; therefore, the electricians complied with the procedure.

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The inspectors reviewed the drawings and concurred with the electricians'

conclusion.

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The inspector discussed these observations with electrical maintenance supervision.

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The inspectors noted that although a violation did not occur, the electricians  !

. appeared to proceed in the face of uncertainty and had the MAI been worded l

} slightly differently, the electricians would not have been in compliance with the '

MAI. The Electrical Maintenance Supervisor agreed with the inspectors comments j

and discussed them with the electricians. '

c. Conclusions

The Division ll EDG maintenance outage was well planned with the Division 11 EDG

unavailability time minimized. The MAls for the Division ll EDG were generally

performed well.

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M1.3 Surveillance Observations 4

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a. Inspection Scooe (61726) l

The inspectors observed all or portions of the following surveillance tests during this

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STP-309-0202 Division 11 EDG operability testing on February 11,1997.

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PEP-0083 Signature testing of Motor Operated Valve 1E51-MOVF059,

tank bypass to the condensate storage tank, a

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postmaintenance test, on February 19.

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STP-051-4522 Emergency core cooling system and reactor core isolation

, cooling response to reactor vessel low water level channel

functional test, on February 24.

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l b. Observations and Findinas

The inspectors found that the surveillance tests listed above were conducted

properly such that meaningful results were obtained. Self-checking and peer

checking wea evident when it was appropriate to do so. During independent

verification, the verifiers demonstrated a conscious effort to maintain independence

from the performers. TS limiting conditions for operation were entered, when

required. Measuring end test equipment was verified to have been in calibration.

The inspectors reviewed the completed test documentation and noted that it was

legible and all acceptance criteria were met.

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c. C_,

o nclusions l

All surveillance tests observed in this section of the report were performed properly l

and in accordance with the applicable procedures. Self checking was evident as the

test performers manipulated valves and switches. l

M 1.4 Missed EDG Surveillance i

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a. Inspection Scope (61726) j

The inspectors evaluated the response to CR 97-01J4, which identified that the

loss of power function to the Division il EDG had not been adequately surveillance

tested.

b. Observations and Findinas

On February 13,1997, during a logic system functional test review, the licensee

identified that they had not been adequately testing the starting circuitry for the

Division ll EDG, The licensee found that individual contacts actuated each of the air

banks for the air starting system. The forward air starting system contact was

adequately tested during refueling outage (RFO) 6, but the contact for the rear air I

starting system had not been verified as operable. Therefore, the licensee noted

that TS 3.3.8.1 (EDG instrumentation) requirements may not have been met.

The licensee wrote an operability evaluation, which stated that the EDG was

operable because either the forward or rear air starting system was adequate to

meet the system design basis, and as long as the forward air starting system was

operable, the Division ll EDG was operable. The inspector reviewed the licensee's

operability assessment and identified no concerns.

However, the inspector asked the licensee if the forward air system had been

removed from service such that the licensee was depending on the rear air starting

system (which was not adequately surveillance tested) for operability of the Division

11 EDG. The system engineer stated that, since RFO 6, the forward air starting

system for the Division 11 EDG had not been removed from service. The inspector

independently reviewed the tracking limiting conditions for operation since RFO 6

and identified that the forward air starting system was declared inoperable from

February S-19,1997. In addition, the inspector identified three 2-week periods in

the previoun operating cycle where the forward air starting system was inoperable.

These time periods in which the forward air starting system was inoperable

exceeded the 72-hour limiting condition for operation for the Division 11 EDG. In

addition, the licensee changed operational modes from Mode 4 (Cold Shutdown), to

Mode 2 (Startup) on February 14 with the forward air inoperable.

Therefore, the failure to test the loss-of-power contact for the rear air starting ,

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system of the Division 11 EDG during the time periods when the forward air starting

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system was inoperable constituted a missed surveillance. The licensee revised tne

test procedure to ensure that all of the loss of power functions were properly

tested. Because this test was intrusive while operating at power, the licensee

chose not to perform the test until the next outage or if forward air became

inoperable again. Although the licensee had not performed the surveillance test, the

licensee believed, based on past EDG reliability and engineering judgment, that the

surveillance of the rear air starting circuitry would probably pass; therefore, the

Division 11 EDG was capable of meeting its intended safety function even during

times that forward air was inoperable.

The failure to perform the required surveillance of the loss-of-power contact for the

rear air starting system of the Division 11 EDG was a violation of TS SR 3.0.2. This

licensee-identified and corrected violation is being treated as an NCV consistent

with Section Vll.B.1 of the NRC Enforcement Policy. Specifically, the violation was

identified by the licensee, was not willful, actions taken as a result of a previous

violation should not have corrected this problem, and appropriate corrective actions

were completed by the licensee (50-458/9706-03).

c. Conclusions l

The engineer performing the logic system functional test review exhibited excellent

attention to detail in identifying that the loss of power contact for the Division il l

EDG rear air starting system was not properly tested. An NCV was identUied for )

failure to comply with TS SR 3.0.2. The licensee's initial review of the Division 11  ;

EDG past operability was weak in that the review did not discover a past outage of  !

the forward air starting system.

Ill. Enaineerina

E2 Engineering Support of Facilities and Equipment

E2.1 Inaoorooriate Acolication of Core Ooeratina Limits Reoort  ;

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a. Insoection Scoce (37551)

The inspectors reviewed the actions in response to CR 97-0256, where the reactor

engineers identified an error in applying required changes in the OLMCPR at the

correct time within the current fuel cycle, as required for GE-11 fuel.

b. Observations and Findinas

On February 25,1997, while monitoring and reviewing the approach of the reactor

full power exposure at which the OLMCPR for the newer GE-11 fuelin the reactor

must be changed from 1.28 to 1.32, the reactor engineers realized that the date

should have been February 19. Consequently, from February 19-25, the reactor

operators had been monitoring a maximum fraction limiting critical power ratio

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(MFLCPR) that was nonconservative and could have allowed the OLMCPR limit to

be exceeded.

The reactor engineers immediately implemented an administrative limit of 0.969 for

MFLCPR. The limit was normally 1.0. This compensated for an OLMCPR limit of

1.32 until the correct limit was programmed into the 3D Monicore computer

i monitor. The program was subsequently adjusted on February 26 and the

monitored parameters were restored to those normally observed by the reactor

operators.

, The core operating limits were not exceeded during the above 6-day period. The

reactor engineers reviewed the historic core performance edits and found that the

highest MFLCPR was 0.911, which translated to 0.9395 with an OLMCPR of 1.32.

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The licensee stated that the cause of the above problem was human arror. The

supplemental reload licensing report from General Electric indicated ;.: dicted

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end-of-cycle full pnwer exposure of 11,850 megawatt days per short ton of fue:.

The report indicated that the OLMCPR should be changed from 1.28 to 1.32 when

the exposure reached end-of-cycle, minus 3350 megawatt days per short ton.

Subsequent to startup from RFO 6, the startup and operations report stated that the

predicted eno-of-cycle full power exposure would be 12,626.2. The reactor

engineer subtracted 3350 from 12,626.2 instead of 11,850, in error, and tracked

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core exposure to the longer exposure time.

To prevent a recurrence, the licensee was considering requesting software for the

i 3D Monicore System to automatically shift the OLMCPR limit at the appropriate time

during the fuel cycle. The appropriate actions were taken to reduce personnel

, errors.

The inspectors concluded that there was no violation of regulatory requirements;

] however, this was poor human performance. The safety significance was mitigated

by the fact that the reactor was being operated with sufficient margin from thermal

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limits such that minor errors, as discussed above, did not result in exceeding the

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c. Conclusions

The reactor engineers demonstrated poor performance by calculating the incorrect

full power exposure at which to change the OLMCPR for GE-11 fuelin the reactor in

accordance with the license. Consequently, a nonconservative limit was being

monitored by the reactor operator for 6 days. No licensed thermallimits were

exceeded because the reactor was being operated with sufficient margin below the

limits.

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E2.2 Review of Facihtv Conformance to Updated Final Safety Analysis Report

Descriptions

Discovery of a licensee operating a facility in a manner contrary to the Updated

Final Safety Analysis Report highlighted the need for a special focused review that

compares plant practices, procedures, and/or parameters to the Updated Final

Safety Analysis Report. While performing the inspections dic,assed in this report,

the inspectors reviewed the applicable portions of the Updated Final Safety Analysis

Report that related to the areas inspected. The inspectors verified that the Updated

Final Safety Analysis Report wording was consistent with the observed plant

practices, procedures, and/or parameters. No inconsistencies were noted.

.E3 Engineering Procedures and Documentation

E3.1 Deficiencies in Determinina Extended LLRT Intervals

a. Insoection Scope (37551)

The inspectors reviewed the response to CR 97-0127, which identified four

safety-related valves that were inappropriately selected for an extended LLRT

interval of 5 years, and therefore were not tested within the 2-year interval required

by the LLRT program,

b. Observations and Findinas

On February 4,1997, while reviewing LLRT intervals in preparation for testing to be

performed during the upcoming refueling outage in September 1997 (RFO 7), Plant

Engineering determined that four safety-related valves were not tested during the

previous refueiing outage in January 1996 (RFO 6). The valves were not tested

because they were selected for a 5-year LLRT interval pursuant to the

performance-based LLRT program, which implemented Option B of 10 CFR Part 50,

Appendix J.

The four containment isolation valves in question were: (1) E12-MOVF027B, Low

Pressure Coolant Injection B to the reactor, (2) E12-MOVF0378, Low Pressure

Coolant injection B to the reactor, (3) E51-MOVF068, reactor core isolation cooling

turbine exhaust to the suppression pool, and (4) SWP-MOV503B, standby service

water return from Containment Unit Cooler B.

The operators entered TS SR 3.0.3, which allowed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the licensee to

accomplish the LLRT for the valves before declaring the effected systems inoperable

because of the missed surveillance. The LLRT was completed satisfactorily for each

of the four valves by February 7. It was r.ecessary to declare the effected systems

inoperable in order to support testing and the operators entered the appropriate

TS limiting conditions for operation.

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The licensee explained that the personnel in charge of the LLRT program prior to l

RFO 6 did not document why they selected the four valves for the extended

interval. The licensee stated they assumed the decision was based on the criteria

stated in Procedure ADM-0050, " Primary Containment Leakage Rate Testing,"

Revision 4. Procedure ADM-0050 implemented a performance-based LLRT program

pursuant to 10 CFR Part 50, Appendix J, Option B. According to

Procedure ADM-0050, in order to select a given valve for extended LLRT interval,

among other criteria, the two previous consecutive LLRT as-found results must not

have' exceeded the administrative limits. The four valves had satisf actory results in

RFO 4; however, the RFO 5 results were as-left after maintenance was performed

on the actuators.

On February 4,1997, Plant Engineering determined that the criteria had not been

met, and therefore, an LLRT should have been performed on the four valves during

RFO 6. While this was considered to be a missed surveillance, the licensee stated

that this was probably a conservative decision, because the nature of the

maintenance done during RFO 5 probably had no significant effect on the leak

tightness of the valves. The inspectors reviewed the documentation of the

maintenance performed on the four valves and found that the actuators were

removed from the valves, dismantled in the shop, cleaned and lubricated, and in

two cases, the torque switches were balanced. This was clearly more work than

Procedure ADM-0050 allowed in order to accept an as-left LLRT for an as-found

value.

On February 13, the licensee informed the inspectors that they had looked more

thoroughly into the LLRT history of the valves and found in each case that an

acceptable as-found LLRT was completed during RFO 3 and no maintenance was

done at that time. Furthermore, the licensee demonstrated to the inspectors'

satisfaction that the actuator maintenance performed during RFO 5 would not have

had any significant impact on valve leakage and thus would not have masked a

problem if it had occurred with valve seat tightness. Therefore, it was not

necessary to perform the LLRTs on the four valves on February 4 as described

above. The inspectors questioned why this did not come to light during the Plant

Engineering review ano the reply was that the RFO 3 data was not on the matrix

they were using.

The inspectors expressed concern that the licensee appeared to have been

unsuccessful in implementing and prescribing a program that effectively reflected

the test interval guidance provided by NUREG-1493, " Performance-Based ,

Containment Leak-Test Program," September 1995, and the " Nuclear Energy I

Institute industry Guideline for implementing Performance-Based Option of

10 CFR Part 50, Appendix J," July 26,1995. It was evident that the licensee had

several opportunities to correct the problem. For example, in January 1996, a

programmatic review identified 18 valves that may not have met the criteria for

extended intervals (CR 96-0319). The CR was closed in March 1996. In

July 1996, during a Quality Assurance review, another valve was identified as

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having been placed on extended interval inappropriately (CR 96-1327). No other

similar examples were identified during that review. The CR was closed in

August 1996.

In September 1996, a reevaluation of CR 96-0319 identified two valves that should

have been tested during RFO 6 (CR 96-0319A). An NCV was identified on this

issue in NRC Inspection Report 50-458/96-14, Section M1.3. Also in

September 1996, the inspectors identified that Procedure ADM-0050 permitted a

25 percent extension on LLRT test intervals, when TS 5.5.13 does not allow it.

Although there were no examples found where the extension was inappropriately

used, as of February 1997, the procedure error had not been corrected

(CR 96-1564). During this inspection period, because of ambiguities in the

performance-based LLRT program, safety-related systems were taken out of service

unnecessarily during power operation to accomplish testing that was not needed.

The licensee explained that in January 1996, because of the complexity and

newness of the performance-based LLRT program at River Bend, experienced and

knowledgeable people were brought in from another plant and established the first

program for Entergy Operations, Inc., to make sure that proper decisions were made -

for testing during RFO 6. Again in February 1997, industry experts were brought in

to review the program in preparation for testing during the upcoming RFO 7.

Although these were proactive initiatives to ensure proper implementation of their

new performance-based LLRT program, the inspectors considered the program

should have been corrected early in 1996.

Corrective actions initiated during this inspection period included clarifying the

requirements associated with the performance-based LLRT program by revising

Procedure ADM-0050 and providing the appropriate training for personnel

responsible for implementation of the program. The licensee also indicated that

Engineering would be documenting the basis of each component placed on

extended test intarval. On February 13,1997, the General Manager, Plant

Operations directed the establishment of a review team whose charter would be to

step back and review the overall surveillance program and recent initiatives to

determine if an adjustment was warranted, based on the above CRs.

Because the licensee identified and was in the process of correcting nearly all of the

above problems associated with the LLRT program, the inspectors considered

exercising enforcement discretion. However, Section Vll.B.1.(b) of the NRC's

Enforcement Policy, NUREG-1600 could not be satisfied, in that this was a violation

that could reasonably have been expected to have been prevented by the corrective

actions for previuus licansee findings. Failure to establish and maintain adequate

procedures to implement a satisfactory performance-based LLRT program pursuant

to 10 CFR Part 50, Appendix J, is a violation of TS 5.4.1.a (50-458/9706-04).

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c. Conclusions

. The failure to establish clear procedural guidance for the implementation of a

performance-based LLRT program pursuant to 10 CFR Part 50, Appendix J,

Option B, resulted in missed td.ing of valves and unnecessary testing of other

valves that required taking safety-related systems out of service during plant '

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operation at power. A violation of TS 5.4.1.a was identified.

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IV. Plant Support

R1 Radiological Protection and Chemistry Controls

R1.1 Insoection Scone (71750)

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a. Throughout this inspection period, the inspectors observed performance in

radiological protection. The inspectors observed a sample of radiation, high

, radiation, and locked high radiation areas to verify that these areas were properly

posted and controlled.

b. Observations and Findinas

On February 20,1997, the inspectors noted that Door TUO70-001 was propped

open to support the ADHR modification. The personnel involved properly obtained

permission from the control room to prop this door open and an hourly fire watch

patrol was assigned. However, the sign posted to inform personnel that this area

was a radiation area was hung on this door. Therefore, when door TUO70-001 was

propped open, the radiation area sign was obscured from view such that not all

personnal entering the area would not be aware that they were entering a radiation J

area. 1

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The inspectors informed RP that the entrance to the ADHR room was not

adequately posted. An RP technician relocated the radiation area sign from the door

to a stanchion placed at the doorway. The licensee initiated CR 97-0257 to enter

this item into the corrective action program.

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On February 24, an RP technician reinspected the radiological postings near the

ADHR room. The RP technician noted that the stanchion with the radiation area

sign that was previously located in the doorway cf the ADHR room had been moved

to a corner of the room. RP personnel reposted the area by hanging the radiation

area sign on a rope across the doorway. This additional unauthorized movement of

the radiation area sign was added to CR 97-0257.

10 CFR 20.1902(a) requires each radiation area to be conspicuously posted with

signs stating " CAUTION, RADIATION AREA." Because the radiation area sign et

the entrance to the ADHR room was obscured from view, this radiation area was

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not conspicuously posted as required. The failure to conspicuously post a radiation

area is a violation of 10 CFR 20.1902(a) (50-458/9706-05).

The inspectors noted that this violation was mitigated because no unauthorized

personnel entered the radiation area without proper dosimetry. However, the

inspectors noted that River Bend general employee training information directed

radiation workers to obey all radiological postings and stated that any unauthorized

removal or movement of radiological postings will not be tolerated. The above

violation indicated that personnel involved with the ADHR modification were not

adequately implementing their training on basic radiological work practices. In

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addition, NRC Inspection Report 50-458/96-06 discussed two previous instances in

which radiological postings were inappropriately relocated, which indicated that

improvement in ensuring radiological postings were intact was required.

, c. Conclusions

A violation was identified for failure to conspicuously post a radiation area. On two

occasions the radiation area posting at the entrance to the ADHR room was

modified without RP approval, which indicated that personnel were not sufficiently

sensitive to following basic radiation prctection practices. No unauthorized entries

or unmonitored dose resulted from these posting deficiencies.

S1 Conduct of Security and Safeguard Activities

S 1.1 General Comments (71750)

Throughout this inspection period, the inspectors observed security and safeguards

practices. Security boundaries were maintained properly and entry screening

processes were performed properly at the primary access point. The inspectors

noted during night tours that the protected area was properly illuminated.

V. Manaaement Meetinas

X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management at the

conclusion of the inspection on March 24,1997. 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.

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ATTACHMENT

SUPPLEMENTAL INFORMATION

PARTIAL LIST OF PERSONS CONTACTED

Licensee

J. P. Dimmette, General Manager, Plant Operations

' M. A. Dietrich, Director, Quality Programs

D. T. Dormady, Manager, System Engineering

J. R. Douet, Manager, Maintenance

J. Holmes, Superintendent, Chemistry

H. B. Hutchens, Superintendent, Plant Security

D. N. Lorfing, Supervisor, Licensing

C. R. Maxson, Senior Lead Licensing Engineer i ,

J. R. McGaha, Vice President-Operations

W. P. O'Malley, Manager, Operations

W. H. Odell, Superintendent, Radiation Control

D. L. Pace, Director, Engineering

INSPECTION PROCEDURES USED

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IP 37551 Onsite Engineering

IP 61726 Surveillance Observations .

IP 62707 Maintenance Observation j

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lP 71707 Plant Operations

IP 71750 Plant Support Activities

IP 92901 Followup - Operations

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ITEMS OPENED AND CLOSED l

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Opened I

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50-458/9706-01 VIO Failure to establish procedure to control overtime l

(Section 06.1)

50-458/9706-04 VIO Failure to adequately maintain LLRT program

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(Section E3.1) )

! 50-458/9706-05 VIO Failure to conspicuously post radiation area ,

(Section R1.1) l

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Closed

50-458/95026-01 IFl Review of plant risk assessment for on-line maintenance l

(Section 08.1) l

Opened and Closed

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50-458/9706-02 NCV Failure to implement MAI on control building emergency

chiller (Section M1.1)

50-458/9706-03 NCV Missed surveillance on EDG air start circuitry

(Section M1.4)

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LIST OF ACRONYMS USEO

ADHR Alternate Decay Heat Removal

CR Condition Report

EDG Emergency Diesel Generator

EOOS Equipment Out of Service

EOP Emergency Operating Procedure

FRC Facility Review Committee

IFl Inspection Followup item

LLRT Local Leak Rate Testing

MAI Maintenance Action item

MFLCPR Maximum Fraction Limiting Critical Power Ratio

NCV Noncited Violation

NEO Nuclear Equipment Operator

NRB Nuclear Review Board

OLMCPR Operating Limit Min; mum Critical Power Ratio

PDR Public Document Room

QA Quality Assurance

RFO Refueling Outage

RP Radiation Protection

SLC Standby Liquid Control

SR Surveillance Requirement

TIP Traversing incore Probe

TS Technical Specification