ML20140D272

Integrated Insp Rept 50-302/97-05 on 970330-0503.Violations Noted.Major Areas Inspected:Operations,Engineering,Maint, Plant Support & Review of restart-related Open Items

ML20140D272
Person / Time
Site:	Crystal River
Issue date:	06/02/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20140D240	List: ML20140D236 ML20140D268 ML20140D272
References
50-302-97-05, 50-302-97-5, NUDOCS 9706100315
Download: ML20140D272 (40)

See also: IR 05000302/1997005

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U.S. NUCLEAR REGULATORY COMMISSION

REGION II

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Docket No: 50-302

License No: DPR-72

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Report No: 50-302/97-05

Licensee: Florida Power Corporation

Facility: Crystal River 3 Nuclear Station

Location: 15760 West Pcwer Line Street

Crystal River. FL 34428-6708

Dates: March 30 through May 3. 1997

Inspectors: S. Cahill. Senior Resident Inspector i

T. Cooper. Resident Inspector

S. Sanchez. Resident Inspector ,

P. Fillion. Reactor Inspector, paragraphs E8.7

L. Mellen. Project Engineer, paragraphs E8.2. E8.3

R. Schin. Reactor Inspector, paragraphs E8.1. E8.2

M. Thomas. Reactor Inspector, paragraphs E8.4 - E8.9

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Approved by: K. Landis, Chief. Projects Branch 3 ,

Division of Reactor Projects  ;

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EXECUTIVE SUMMARY

Crystal River 3 Nuclear Station

NRC Inspection Report 50-302/97-05 ,

This integrated inspection included aspects of licensee operations. l

engineering, maintenance, plant support. and review of restart-related open

items. The report covers a 5-week period of resident inspection, in addition,

it includes the results of announced inspections by three reactor inspectors

and one project engineer from Region II.

Doerations

A violation (VIO 50-302/97-05-01) with four examples was identified for

failure to follow clearance tagging procedural recuirements. Numerous

problems have occurred over a several month perioc which indicate that the

implementation of licensee clearance tagging process was significantly

deficient. A comprehensive corrective action plan was not developed for

several months and was still awaiting the final root causes determination.

The ongoing problems indicate a need for a comarehensive and significant

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change. The inspectors concluded these and otler examples indicated that the

licensee's overall process for configuration and status control of plant

equipment remained deficient (Section 01.2).

Equipment labelling was determined to be a weakness due to the significant

potential for tagging or manipulation of the wrong component and the use of

indelible markers for plant equipment labelling which could potentially bypass

labelling controls and verifications (Section 02.2).

Several examples of poor questioning attitudes were observed causing the

inspectors to conclude that Operations ownership'and cognizance of plant

spaces, equipment, and 3rocesses was poor. Due to the numerous examples. the

inspectors considered t1is a weakness in Operations (Section 04.1).

Licensee self-assessment activities continue to be effective. Deficiencies

were identified with commitment tracking, which are being addressed. The

licensee's Licensing organization was undergoing several personnel changes

intended to result in improved Licensing performance (Section 07.1).

Problems continue to be observed with the corrective action program but a

pending revision to the program procedure addresses the majority of the

problems. Timeliness of root cause and corrective action development for

significant problems remains a challenge. Numerous investigation deficiencies

, were observed in an event followup that indicated a need for a logical and

l rigorous event review process for immediate investigotions of problems

(Sections 01.2 and 07.2).

Maintenance

The inspectors concluded that all observed maintenance and surveillance

activities were performed in accordance with procedures and desired results

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were obtained (Section M1.1).

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Enaineerina

The inspectors concluded that online maintenance and surveillance of active

components that were relied upon by both trains of high pressure injection and i

emergency feedwater were adequately controlled, with one exception. The

Technical Specifications did not address the cross-train dependency of the A

emergency die el generator on the B train turbine-driven emergency feedwater I

pump. EFP-2. However, the licensee was attively addressing this issue by i

drafting a. Technical Specification amendment request and had included it on j

their restart list. Also, the licensee had addressed past maintenance l

problems with EFP-2 (Section E8.1).

The inspectors concluded that there were nonconservative errors in the

licensee's calculations for control complex habitability envelope leakage and  ;

Jost-accident operator dose. The inspectors also concluded that the licensee  !

lad failed to implement procedures for operators to address the potential I

failure of control complex habitability envelope isolation dampers susceptible

to single failure, as committed to in response to NUREG 0737. Item III.D.3.4.

These issues are added to Unresolved Item (URI 50-302/95-02-02). Control

Complex Habitability Envelope Leakage, and remain open pending further

licensee and NRC review (Section E8.2).

An Unresolved Item (URI 50-302/97-05-02) was identified regardirg the question

of whether the 50.59 safety evaluation for the Improved Technical ,

Specification basis change should have addressed the remote operation of the I

atmospheric dump valves described in the licensee's shutdown from outside the

control room procedure (Section E8.6).

The proposed corrective actions for precursor card 97-2360 were weak in that

the corrective actions did not adequately address the' apparent cause

identified for the precursor card (Section E8.6).  ;

A Violation (VIO 50-302/97-05-03) was identified for certain annunciator

response procedures that contained incorrect information (Section E8.7).

An Unresolved Item (URI 50-302/97-05-04) was identified for weaknesses in the

licensee's commitment tracking process (Section E8.9).

Plant Suocort

An inspector review of a licensee Health Physics self-assessment on corrective !

action plans identified some documentation deficiencies, but no deficiencies

were found with the licensee's assessment. findings and response plan. No l

l other problems were noted in the areas of radiological controls or chemistry i

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The results of an off-hours emergency staffing drill were reviewed and a

quarterly drill was observed that indicated emergency 3reparedness activities

were performed well and only minor deficiencies were o] served (Section Pl.1). '

. A loss of power to central alarm station equipment was investigated and

revealed a security staff lack of familiarity with the operation and function

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of some installed equipment. Security management did not a)propriately

prioritize the issue and obtain adequate resolution from otler departments, so

final resolution of the problem is still pending (Section S2.1).

A problem with the security computer operating system run-time expiration that

had the potential to disable the security system was appropriately addressed

by the licensee (Section S2.2).

The inspectors assessed the licensee's performance concerning the five areas

of continuing NRC concern in the following paragraphs: the assessment is

limited to the specific restart-related issue addressed in the respective

paragraph.

NRC AREA 0F CONCERN ASSESSMENT PARAGRAPH

04.1 07.1 07.2 E8.1 E8.4 E8.6 E8.7

Management Oversight I G A G A I

Engireering Effectiveness G G I

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Knowledge of Design Basis G G A

Compliance With Regulations A A A G I

Operator Performance I I A A

5 - Superior G = Good A = Adequate / Acceptable I = Inadequate

Blank = Not Evaluated / Insufficient Information

04.1: Operator Performance Observations and Safety Culture Examples I

07.1: Licensee Self-Assessment Activities

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07.2: Corrective Action Program

l E8.1: URl 50-302/97-01-06: HPI System Design Licensing Basis, and TS Concerns

E8.4: IFI 50-302/95-15-03: Design Requirements for Reactor Coolant Pump Cooler

Failure  ;

E8.6: Problem Identification

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l E8.7: IFI 50-302/96-201-16: Coordination of Second Level Undervoltage Relay I

, (SLUR) Setting VS Inverter Operation. (Identified as IFI 50-302/96-201- j

l 06 in NRC Report 96-201)

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Report Details

Summary of Plant Status

The unit remained in Mode 5 with a bubble in the aressurizer throughout the

inspection period, continuing in the outage that Jegan on September 2. 1996.

Work on several major physical modifications commenced this re) ort period.

These included Emergency Feedwater (EFW) cavitating venturis, EFW motor-

operated cross-tie Valve EFV-12, and overpressurization chambers for

containment penetration isolations to address concerns in NRC Generic Letter 96-06. Assurance of Equipment Operability and Containment Integrity During

Design Basis Accident Conditions.

L. Operations

01 Conduct of Operations

01.1 General Comments (71707)

Using Inspection Procedure 71707 the ins)ectors conducted routine

reviews of ongoing plant operations whic1 included shift turnovers,

response to problems, review of logs observation of non-licensed

o)erator rounds, and verification of clearance tagging orders. Notable l

oaservations are discussed in the following paragraphs.

Several attention to detail and personnel errors plus a poor process for

clearance tagging discussed in Section 01.2 resulted in the

identification of several examples of a violation of requirements for

following the equipment clearance tagging procedure. The inspectors ,

observed several examples of )oor questioning attitudes by operators es '

discussed in Section 04.1. T1ese observations caused the inspectors to

conclude that Operations ownership and cognizance of plant spaces,

equipment. and processes was poor. Due to the numerous examples, the

inspectors considered this a weakness in Operations. The inspector also

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observed several deficiencies in plant labelling, some of which

l contributed to problems discussed in Sections 01.2 and 04.1. Other

problems were noted with the absence or unavailability of certain flow

diagrams or electrical schematics. The inspectors were concerned with

this because it impaired the abilities of operators to perform their

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jobs. The inspectors also considered this a weakness due to the

l significant potential for incorrect component manipulation or tagging.

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l 01.2 Clearance Taaaina Problems

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a. Insoection Scone (71707)

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The inspector reviewed the licensee's response to four examples of

clearance tagging problems. The licensee has had an ongoing effort to

correct deficiencies in their clearance tagging system in response to

problems and a violation documented in Ins)ection Report 50-302/97-01.

Although significant management attention las been focused on the

process, problems continue to occur.

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The inspector observed that the Operations department had initiated +

attempts to aggregate these individual problems into a single

.com)rehensive plan which would also encompass equipment status control 1

pro]lems noted in Inspection Reports 50-302/97-01 and 97-02. The

licensee formally documented and ap3 roved this corrective action plan on

April 25. The-inspector reviewed t;e final written version and found it l

comprehensive but still not a direct result of a root cause evaluation. t

A common root cause evaluation was still pending at the end of the  !

report period for the multitude of tagging and equipment status l

problems. The licensee did intend to revise their plan based on the i

results of the finalized root cause analysis. The inspector considered ,

these following tagging problems as further deficiencies in the  ;

, licensee's overall process for configuration and status control of plant  ;

l ecuipment which the licensee has not yet fully corrected. The inspector  ;

icentified these problems as several examples of a violation of licensee  !

orocedural requirements, VIO 50-302/97-05-01, Failure to Follow  !

Equipment Tagging Control Procedural Requirements. Specific examples ,

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On March 27 operators discovered two red tags on the breaker cubicles

for the A and B makeup pumps (MUP) that were part of electronic i

clearance order (ECO) 96-012-98. This EC0 had been authorized for  !

removal on January 17 and both tags were signed and independently  ;

verified as removed on the same date. Other tags were hanging on the

breaker for operational concerns so the breakers were in the correct

position for plant conditions. The licensee implemented an immediate i

investigation and documented the problem on precursor card (PC) 97-2238 i

l to implement corrective action The licensee did not identify any other

clearance tags that were missing or could have been inadvertently pulled I

so they removed the EC0 96-012-98 tags. The inspector noted that the  !

clearance certification of all-active clearances performed.every 30 days  ;

did not identify this discrepancy. The certification is done on a

staggeredbasisthroughoutthe30 days,andonlyactiveclearancesare -

verified. Hence the presence'of inactive tags would not be questioned

, by an individual' verifying other tags on the breakers. The inspector

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also noted that the specified location of the suspect tags was on the

4160 volt breaker cubicle for the MVP, and the position was racked out i'

on the floor.' The inspector noted that the licensee's 3ractice was to

normally locate this type of tag on a chain across the areaker cubicle

j itself to prevent reinsertion of the racked out breaker. However, this ,

i practice was not documented in any licensee procedural guidance which  !

i may have contributed to this problem. The licensee has observed other i

! 3roblems with the location of these type of tags in that tags could be  ;

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lung on the racked out breaker, the door of the cubicle, or an installed  ;

, internal grounding breaker. The failure to remove the correct tags l

3roperly was identified as the first example of VIO 50-302/97-05-01, i

Failure to Follow Equipment Tagging Control Procedural Requirements.

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On Aprii 3. ECO 97-03-189 authorized fuel handling crane (FHCR) 7 to be l

tagged for preventive maintenance. The tag to be hung on the local i

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disconnect switch labelled "FHCR-7 MAIN DISC" was incorrectly hung on a

adjacent disconnect switch, six feet away for the spent fuel pool gate

hoist labelled "SFHT - 3 TON YALE MONORAIL HOIST." The latter

disconnect was labelled with small. handwritten letters applied with a

indelible marker pen while the FHCR-7 disconnect was labelled with ,

l clearly visible, adhesive black letters on a white background that were

approximately two inches tall. The adhesive labels were routinely used

by the licensee for plant labelling. The licensee found the aroblem on

April 4 when pulling the tags after the ECO was released to ]e changed

to another ECO. Actual work had not been authorized or commenced on the

incorrect ECO. The involved individuals were removed from clearance

duties, and a short term investigation was initiated by the licensee.

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The hanging of the tags on the incorrect breaker was identified as the

second example of VIO 50-302/97-05-01. Failure to Follow Equipment

Tagging Control Procedural Requirements.

On April 21 a maintenance foreman was walking down his clearance when he

noted the red tag hung on Valve SWV-60, the SW cooling water inlet to

control complex compressor 18, was actually labelled "CHV-60." The tag

had been hung by an Operations individual, verified by a second

individual, and then verified again by a licensed Senior Reactor

Operator. The last additional check was required as an interim

corrective action in response to the aforementioned problems. None of

these three individuals noted the tag discrepancy. Operations

a)propriately performed an investigation that verified the tag was on

t1e correct valve and removed the involved individuals from further

clearance activities. This effort revealed that the Chief Nuclear

0)erator (CNO), who had written the clearance tagging order, was also

tie individual who second checked the tag hanging. This impaired his

ability to be an independent verifier and contributed to his failure to

notice the discrepancy. The hanging of the incorrectly labelled tag on

SWV-60 and failure to be corrected by three individuals was identified

as the third example of VIO 50-302/97-05-01. Failure to Follow Equipment

Tagging Control Procedural Requirements.

On April 12. a Shift Supervisor on Duty (SSOD) was walking down ECO 97-

03-164 on the main turbine turning gear to verify release positions for

the ecui) ment. He observed a red tag hanging on the air supply line

statec tlat the position of the air line was disconnected but the line

was actually connected. The licensee initiated an immediate

investigation which identified a disagreement between the operations and

the contract maintenance personriel regarding the position of the air

line after tagging and prior to the maintenance. The operators who hung

the tags stated the air line was disconnected by them per the tagging

order while the maintenance crew stated they found the line tagged but

connected prior to starting their maintenance. The investigation

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culminated in Operations and Maintenance supervisors and managers

assembling the involved individuals in a single room on April 13 to

resolve the discrepancies. The ins)ector witnessed this meeting and

noted the following problems with tie investigation:

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. Adequate written, inde)endent personnel statements had not been

obtained from all of t1e involved individuals - several had been

obtained over the phone after the individuals had left the site

following night shift and were no longer fit for duty:

. The operations supervisor leading the meeting tainted the validity

of the information to be obtained by assuming and stating that the

involved individuals had observed conditions and taken actions

that were still in question:

. The licensee supervisors did not have any investigation plan or

use any root cause method prior to convening the meeting. The

supervisors had not yet initiated a PC corrective action document,

and trained investigator assistance was not requested.

Consequently, the meeting was disorganized and consisted of a

series of random, repetitive, and disjointed questions:

. The meeting lasted one hour and much specific information was

presented but was not retained because the licensee did not

transcribe any notes of the meeting. This omission hampered the

ensuing investigation as was obvious by the supervisors'

difficulty reconstructing the details of what was said after the

meeting:

. Although the associated individuals actions spanned several days,

no attem)t was made to develop a time line for the sequence of

events w1ich would have assisted the investigators in resolving

smaller discrepancies between the individuals' accounts of the

problem:

. The licensee focused on resolving the disagreement between the two

groups and initially did not pursue the other problems that were

revealed in the meeting:

. The managers performing the investigation eliminated the

involvement of any third party mani)ulation of the air line that

would account for the disagreement )ased on their perceptions and

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not any specific evidence.

The inspector determined from the investigation meeting that the

maihtenance personnel stated they found the air line connected with a

tag on the turning gear. They moved the tag down the air line because

they were to remove the turning gear and did not want to remove the tag

with it. They assumed they were authorized to implement the tagged

position of disconnected. Therefore, they disconnected the air line and

l removed the turning gear. Consecuently, when the same crew reinstalled

the turning gear they reconnectec the air line with the red tag still on

the air line which is how the SSOD found it on April 12. The

maintenance crew claimed they had questioned the tag but had not

discussed it with supervision in maintenance or operations. They

rationalized their actions taken on a red tagged component by stating

that they had never observed operations personnel break air lines in the

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past and that it was normally a maintenance activity. The first '

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o)erator who implemented the tagging clearance order stated he vented

t1e line by closing an upstream air supply valve. V-5, and venting the

l .line between a closed solenoid valve and the turning gear by removing i

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connecting ca)s at the turning gear. Air pressure was still present

upstream of t1e solenoid valve and the solenoid was not included on the

ECO. The operator later recognized the line was to be disconnected per

the clearance and replaced the caps but did not tighten them. The caps

l would appear to be properly installed from a visual' inspection. The

operators also later added Valve V-5 to the clearance as a more

effective isolation.after walking down the lines. The operators claimed

that an adequate print of the involved air lines on the main turbine-

platform was not available so the availability of V-5 was ' unknown, and.

it was not included on the original' clearance. The inspector noted the  !

following problems with the action of the involved individuals, some of  !

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which were also noted by licensee management.

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. The maintenance crew exhibited an extreme lack of questioning

attitude and adequate supervisory notification when the problem

was initially recognized.

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, tagged position of a red tagged component and move a red tag is an

l extremely significant breakdown of the principles of the clearance

tagging system. The adequacy of the licensee's clearance

training, expectations for contractors, and supervisory oversight

l of contractors appeared questionable.

l . The maintenance crew's attempt to justify their. actions

considering that operators did not normally break air lines was

inappropriate and irrelevant. This was not initially recognized

and corrected by. maintenance management

. The lack of adequate flow prints or schematics impairs Operations

ability to author safe and effective tagging orders.

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. The operator who removed the air line vent caps and did not fully

reinstall them did not have any direction or procedural guidance

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the caps would be reinstalled so equipment configuration control

was lost.

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downstream of an untagged solenoid valve without recuiring closing

V-5 and venting the line, as the operator actually cid, had the

potential to result in breaking the connection on a live line if

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the solenoid valve leaked by or been actuated.

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of the red tag, and the inadequacy of the original clearance as the

fourth and most significant example of VIO 50-302/97-05-01. Failure to

Follow Equipment Tagging Control Procedural Requirements. l

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The inspector verified the licensee had taken several promp~t. interim

corrective actions for each of the four problems. Ori April 4 Short Term

Instruction (STI)97-010 was issued to restrict the hanging of all  ;

clearances. Exceptions if any could be authorized by the SSOD and would '

l require observance by a senior reactor operator (SRO) while being hung.  ;

On Aprii 14 the Director Nuclear Plan Operations (DNPO) directed that  !

the SRO reviews continue as well as a similar review and verification by ,

maintenance supervision prior to performing work. This was implemented i

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by STI 97-012. The licensee also verified all existing clearances for l

adequacy. A site-wide configuration management standdown was held on

April 21. The ins)ector reviewed the presentations for the standdown i

and found them to ae detailed discussions of the events that had l

occurred and the significance of proper configuration control. The l

inspector noted that other events not discussed in the examples above j

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were included in the briefings including two events where valves would i

not stroke because operators did not recognize air or electrical power  !

to these valves was not properly restorm' following tagging cr was still l

tagged. On April 24 the licensee initit .ec an Operations Study Book l

entry to reiterate specific requirements fo, implementing the Sto).  !

Think. Act. Review (STAR) concept when r, m 9q clearance tags. T1e l

entry stressed that discrepancies must be 1. mediately brought to

l supervision's attentiontand resolved before 3roceeding. The licensee

also initiated several efforts to maximize t,e time supervisors were in

the plant monitoring clearance activities to ensure expectations were

met and reinforced. j

Although the licensee's root cause analysis was still not finalized at

the close of this Inspection Report period, their 3reliminary assessment

l indicated problems in their tagging process descri)ed by CP-115. an

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unacceptable level of personnel errors, inadequate inde)endent

l verifications. and inadequate supervisory presence in t1e field.

Earlier problems with the control of clearance tagging resulted in a <

complete revision of CP-115 which the licensee expected to commence

training on and implement in the latter part of May. The-licensee also

reviewed the corrective action system database to ensure all

configuration control deficiencies were captured in the scope of their

investigation. The licensee was incorporating these corrective actions

into the revision of CP-115.

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c. Conclusions

The inspector concluded that the licensee clearance tagging process was

l significantly deficient as indicated by numerous problems which occurred

L over a several month period. Although the licensee has responded to the i

I details of each problem with corrective actions a comprehensive l

corrective action plan was not developed for several months and is still i

awaiting the final root causes determination. Implementation of this i

plan is still ongoing. Consequently, problems have continued to occur. '

The ongoing problems indicate a need for a comprehensive and significant

change. The inspector concluded these and other examples indicate that

the licensee's overall process for configuration and status control of

plant equipment was deficient.

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02 Operational Status of Facilities and Equipment

02.1 Decay Heat System Walkdown (71707)

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The inspectors performed a review of the A train of the decay heat (DH)

removal system. The inspectors reviewed the design basis documentation,

the Final Safety Analysis Report (FSAR), and the Technical

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Specifications for the system prior to performing a detailed system ,

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walkdown. The system lineup procedure. OP-404. Decay Heat Removal

System, was reviewed and comaared to the flow diagram for the system.

At the time of the review. t1e B train of DH was in service for shutdown

cooling and the A train was idle. During the walkdown, no discrepancies

were noted.

02.2 Eauioment labellina

a. Insoection Scooe (71707. 92901. 92902) 2

The inspectors assessed the adequacy of equipment labelling for

accuracy, visibility, and clarity (unambiguous). I

b. Observations and Findinas

The inspector observed several examples of inadequate and poor labelling

of )lant equipment, some of which contributed to previously described

]ro)1 ems. Examples included unlabelled recorders WD-101 on the

Radioactive Waste panel that indicated system flow and radiation monitor

countrate. Neither of the two pens on both of the recorders was

labelled and the inputs to each color pen were opposite from one i

recorder to the other. The Auxiliary Building operators questioned by 1

the inspector indicated they knew which input went to each pen from l

experience.

Another example involved three electrical control panels in the Fire

Pump Building which were label;ed Pump 3A. 3B, and 3C respectively for

the three main Fire Service Fumps (FSP) in the building. However the

i licensee's unique identification numbers for these pumps were FSP-2A,

l FSP-1. and FSP 2B respectively. Tags on the pumps and licensee prints

use these latter numbers. The former numbers were used by the

licensee's architect during construction. On May 1 the inspector

observed Clearance 97-04-192 hanging on the cabinet for pump 3B. Red

Tag R-005 was originally written to Josition the FSP-1 local disconnect i

switch on the FSP-1 local control ca)inet to be OPEN. However, the tag

had been revised by a handwritten change to read the " knife switch" on  !

the FSP-1 local control cabinet to be OFF. An engraved licensee label

on the suspect switch read " KNIFE SWITCH" but did not contain any unique

, identification numbers. Vendor supplied metal tags on the cabinet

labelled the switch as " Isolating Switch" with positions of ON and 0FF.

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As mentioned above, there was not any indication that the panel was

associated with FSP-1 because the label for the cabinet read " Pump 3B."

Another knife switch on the cabinet with a vendor supplied tag was  !

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l labelled " manual control" which c.reated further potential confusion as

to the correct placement of Tag 4-005. Tag R-004 on the same clearance

was required to position Breaker #-1 in local distribution Janel ACDP-7

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to OPEN. However, the inspector observed that the tagged areaker had no

markers of any sort. It could be surmised that it was correctly

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Breaker #1 because it was the top breaker in the left of two columns

with the breaker to the right being number two and the breaker below

being number three. This lack of any positive indication as to the

correct breaker was not questioned by the operators hanging the tag.

The inspector was unable to verify positively that either of these the

tags were on the correct panels or components by using the installed

labels and questioned how the operators hanging the tags could sign for

verification in the absence of this information.

Other problems noted by the inspector include widespread use of pencil

and indelible marker writing to label plant equipment and provide

l operational guidance. Switches for the reactor coolant pump lube oil

collection system pump control panel in the Intermediate Building that

were labelled with a arrow and a mark indicating the direction to

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manipulate them for drain flow were one example. The same panel also

had a pressure transmitter with a local gage reading in percent but no

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indication as to what parameter the gage was indicating. In another,

! the inspector observed expected filter differential pressure (DP)

l readings above a DP gage that were followed in ap)arently the same

I handwriting by a note indicating the filter was clanged in 1982.

l The inspector also noted from followup on other events that plant

clearance tags generated by the licensee's EC0 system normally do not

match the labels on plant equipment. especially with electrical

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equipment. Valves normally were tagged with a three letter and two

l number designator which matched the ECO but descriptive labels were not

l included on most mechanical equipment and those that were tagged usually  ;

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did not match the clearance tags closely. The operators indicated that  ;

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this had not been a problem and there was no ongoing attempt to fix the  ;

discrepancies in the ECO database as they were encountered. j

As discussed in the fourth example of Section 02.1. the inspector was i

l concerned about the unavailability of system schematics that hampered

! operator's ability to author effective clearances. A plant operator

identified a similar concern with the unavailability of electrical load

lists or drawings for a non-safety related electrical panel documented

on PC 97-2957.

c. Conclusions

,

The inspector concluded the licensee's ecuipment labelling and lack of

,

certain equipment. prints was a weakness cue to the significant potential

for tagging or manipulation of the wrong component. The inspector also

concluded the use of indelible markers for plant equipment labelling

could potentially bypass labelling controls and verifications and was

unacceptable. The lack of any effort to address the problem was

indicative of poor management attention in the past. However, new

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licensee management has addressed the specific deficiencies discussed

above and has committed to a significant upgrade'and reconciliation of j

l the plant labelling.

t .

04 Operator Knowledge and Performance

i

04.1 00erator Performance Observations and Safety Culture Examoles l

<

, a. Insoection Scooe (71707) i

l ,

!

L .The inspectors reviewed Operations performance that was indicative of

l the operators' questioning attitudes and safety culture. Licensee

management has focused on improving performance in these areas.

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b. Observations and Findinas

i

The. inspectors' observed numerous examples. most of which were negative, J

that were indicative of licensee performance in this area.

l

l . On April 6. an operator performing a purge on a control complex l

chiller was distracted and left the purge unit running for 14-  ;

hours versus the procedure requirement of between 30 and 45 j

minutes:

'

<

e Several operators were unfamiliar with the results of a building

spray pump (BSP) surveillance performed with an altered impeller. i

One shift supervisor was unconcerned with the results because it  :

didn't ha) pen on his shift while a board o)erator was unaware that I

the pump lad even been run the day before )ecause he was on a

-

several day break in the shift work schedule. This- significant

evolution was documented in the operator logs that this individual i

was required to review when returning from any time off: I

l * The reassembly of the BSP following the impeller replacement had ,

to be repeated because of a crimped gasket. Neither maintenance  :

nor operations personnel initiated a corrective action document i

until questioned by the Engineering Director several days later: j

i

e A sealed spent fuel pool cooling throttle valve was repositioned -l

and resealed withcot any procedural guidance: J

e Shift operations supervision did not develop a plan for local and

periodic decay heat pump bearing temperature monitoring with the l

computer link that monitored and alarmed these parameters out of i

, service.- The problem was not logged by either the SS0D or Shift i

Manger (SM) and informal direction to the operators was to monitor

it more frequently which was widely interpreted by different

j

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. operators: ,

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' . .A problem with the fuel handling crane overhead rail related to a

-

dead spot that would disable the crane if it stopped in that spot

, was not adequately addressed. There was no plan developed for

I

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.

10

restoring the Spent Fuel Cooling Pump (SFD) missile covers if the

crane became stuck. A suggestion was made in the SSOD log to

avoid stopping in the dead spot, but this was not implemented by

any procedure, tag, or formal directive. Only the findings of an

investigation into the cause of the crane sticking were logged by

the SS00, not the original problem:

. Plant housekeeping was observed to be poor by the inspectors.

Equipment, furniture and tool boxes were found adrift in various

locations of the Auxiliary and Intermediate Buildings with no

indication as to their purpose. Ladders were missing or not

stowed properly after work and securing of equipment for seismic

concerns was very inconsistent. Local operating procedure binders

were empty in the fire pump buildings. These discrepancies were

not questioned by non-licensed building operators on their rounds:

. On April 1, an inspector noted an SS00 log entry on the Emergency

Feedwater Valve (EFV)-36 piping replacement. After the clearance

was implemented the line continued to drain. As a result, the

clearance boundary was expanded to provide an additional valve to ,

isolate the system. The inspector observed that a PC or work '

request (WR) had not been written to identify and correct the  ;

leaking emergency feedwater system valves. '

. On April 9 an inspector noted an SSOD log entry described a

clearance for fire service Valve 77 that also had to be expanded

to get a better isolation to support the scheduled work. The

inspector again observed that neither a PC or a WR had been

generated to repair the identified leaking valves.

. The licensee's response to develop a contingency plan and obtain a

Plant Review Committee review of it for a large algae bloom along

the coast that shut down cooling units of fossil power plants was

good. A single point of contact was established to ensure their

preparedness if the bloom migrated.

c. Conclusions

The inspector concluded these examples indicated the ownership of plant

spaces and equipment by Operations personnel was poor and was indicative

of poor attention to procedure adherence. These events also

demonstrated a lack of sensitivity and questioning attitude on the part

of the involved personnel. The inspectors considered this a weakness.

The inspector assessed the licensee's performance, with respect to this

restart-related issue, in the five NRC continuing areas of concern:

l

• Management Oversight - Inadequate

. Engineering Effectiveness - N/A

• Knowledge of the Design Basis - N/A

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. Compliance with Regulations - Adecuate  !

e Operator Performance - Inacequate  :

06- Operations Organization and Administration ,

p  : 06.1;Several organizational changes were announced on April 3,1997, that i

L will occur over the next'several months. i

! *' Bruce Hickle will become the Restart Director'and will continue >

'

l. reporting to the Vice President. Nuclear Production. He will be

l responsible for all aspects of the activities leading to restart.

He will also be responsible.for the development of the Startup and

'

Power Ascension Program and the Long Term Improvement Plan

,

e Charles'(Chip) Pardee will become the Director. Nuclear Plant 1

!

Operations. t

. .

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• Bob Grazio will be joining Florida Power. Corporation (FPC) as the

Director of Regulatory Affairs. He will be responsible for all ,

' licensing and regulatory interface. This position replaces the  ;

current position of Director. Nuclear Operations Site Support.

' '

. Mark Marano will join FPC as the Director.-Site Services which ,

will include responsibility for Information Technology. Document i

Control. Contract Services. Financial Planning. Long Range i

L

'

Business. Planning and other corporate interface areas. Bill

Conklin will continue in his present position as Director, Nuclear

l

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Operations Materials and Controls.

1

07 Quality Assurance in Operations  !

'

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07.1. Licensee Self-Assessment Activities  !

J

a. Insoection Scooe (71707. 90712. 40500) ,

I

=The. inspectors reviewed various licensee self-assessment activities and

corrective action process which included:

e routine reviews of Nuclear Quality Assessments (NOA) activities

and findings:

e observation of the NOA monthly audit _97-04 exit interview:

• reviews of precursor cards entered in to the corrective action

system

e observation of management Corrective Action. Review Board (CARB)

meetings:

1

l  :. observations of the licensee's Restart Panel meetings: and

l * observations of the licensee *s Plant Review Committee meetings.

!

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12  ;

i b. Observations and Findinas  !

N0A inspections continue to be responsive and have identified some l

,- worthwhile findings.' One report was noted by the inspector to be l

[ especially thorough. A review of the licensee's new 10 CFR 50.59 safety '

l ' evaluation process that was implemented on March 31, 1997, was done by ,

an outside contract specialist. The inspector.noted that the individual  !

,

performed a good. thorough audit of-the process and identified several

L deficiencies, none of which constituted a significant problem.

!

.The inspector observed that the licensee's tracking of commitment via

l- their " NOTES" system was poor. -Numerous gaps in the data existed, 1

L particularly for 1995 when data was not routinely entered in the system. i

The_ inspector noted the format was not conducive to managing and

! tracking items and concluded it contributed to licensee problems

l ensuring commitments were met. Similar problems were observed by the  ;

licensee's Quality Assurance group in their 97-02 audit which prompted

- licensee management to direct s comprehensive correspondence review to-

L ensure all commitments were appropriately ca]tured. Further details of

'

.this problem are discussed in Section E8.9 w11ch resulted in the

'

identification of an. Unresolved Item.

The Plant' Review Committee (PRC) was functioning well and was an )

effective reactor safety oversight group. Presentations were consistent  ;

due to format changes and the inspector observed that 10 CFR 50.59  ;

I safety evaluations received-an large amount of scrutiny. A clear chain

l of custody process continues to function well. Revision 40 to'-

Administrative Instruction 300, . Plant Review Committee Charter, was

l issued March 27, 1997. .The inspector reviewed the new procedure and

i found only one notable problem in that a commitment to develo) a method

to document the basis and contingencies for-PRC decisions to )e routed

to the operations shift supervision was not fully implemented. The

commitment arose out of a problem documented in NRC Inspection Report

.50-302/97-01. The licensee is reassessing their method of implementing

the desired result. Previous concerns with screening of items to ensi1re - i

l

they were considered for PRC review when required have not been fully i

! resolved by the licensee. However, the inspector was satisfied with the '

j

L current process and did not note any items that bypassed a required PRC

L review. )

i

The inspector reviewed the licensee's " Licensing and Regulatory  ;

,

Performance Self-Assessment - Benchmarking Trip" report that documented  ;

L a visit to two other plants to improve the licensee's licensing '

performance Numerous potential improvements were identified, but no

action plan had been developed to implement the changes. - The ins)ector  :

verified the licensee had plans to implement the recommendations )ut  :

L numerous recent personnel changes had caused them to be delayed.

i The inspector reviewed the licensee's " Health Physics Self-Assessment - 4

i Corrective Action Plans. (CRSA 97-01/HP 97-1)" completed on February 28,

.

~1997. The goal of the assessment was to verify corrective action plans '

.

!' for radiological safety issues were developed, implemented, and

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13 '

effective. The inspector noted that the scope and goal of the audit was

thoroughly. documented and justified, but the findings and justifications

for the conclusions were not thoroughly dispositioned. The inspector

verified the basis for some of the conclusions and did not . identify any.

further deficiencies and concluded the deficiency was limited to  !

documentation. The inspector identified one other deficiency in that

the licensee often assumed corrective actions were effective based on

the absence of any further events. The inspector considered the use of ,

other measures of effectiveness necessary to ensure the cause of.the  !

problem was corrected. Again, the licensee had done some of this, but

( 1t wasn't thoroughly documented. The inspector verified each of the i

L self-assessment findings was being appropriately addressed and tracked ,

l for closure by HP management and was also entered as a PC in the

L licensee's corrective action system. Although, this last paragraph

referred to activities which would normally.be characterized under the

Plant Sapport area, it has been located so as to combine self assessment  ;

'

observations.

i

c. Conclusions

The inspector concluded the licensee self-assessment activities were ]

effective. The inspector also concluded the licensee's Licensing 1

l

'

organization was in flux but the changes should result in improved l

Licensing performance, j

l

'

j. The inspector assessed the licensee's performance, with respect to this  !

j restart-related issue, in.the five NRC continuing areas of concern:

l

. Management Oversight - Good

. Engineering Effectiveness - N/A l

. Knowledge of the Design Basis - N/A 1

Compliance with Regulations - Adequate

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. Operator Performance - N/A

07.2 Corrective Action Proaram (40500)

The ins)ector observed that although the corrective action program still I

has pro)lems, 3ending issuance of Revision 57 to Procedure CP-111,

Waussing of 3recursor Cards for Corrective Action Program which will

cor;ect a majority of the noted deficiencies. Implementation of tne new  !

l.

'

revision is planned by the licensee for late May, 1997. The inspectors j

continue to observe examples where the licensee does not use PCs to i

track and implement corrective actions although the group that was the  !

u primary problem, Operations, has improved. Timeliness of significant '

'

'

problems being processed by the system was poor. Two NRC issues that

L were cited violations identified in December 1996 and January 1997 were

not-reviewed by the CARB until A)ril 11, 1997. The licensee had already

, responded to the violations whic1 raises questions on the adeouacy of

their~ response. Licensee management was appropriately addressing these  :

'

,

problems.  :

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!: As seen in the numerous investigation deficiencies discussed in the i

fourth example of VIO 50-302/97-05-01 in Section 01.2 concerning >

investigation of MT turning gear tagging problem, a rigorous and logical ,

i process is needed'for immediate investigations of problems. Notable

l deficiencies such as the lack of a plan, discussions being directed by a

!

'

team leader, 'no notes taken, incomplete personnel statements, unclear

delineation of responsibilities, uncertain scope of information required '

to be assembled, and the lack of a timeframe for report development made

the need obvious. The licensee has areviously recognized this need and

was working on developing guidance w1ich will replace the licensee's

existing guidance in Operations Instruction (01) 12, Investigation of  :

Abnormal Events. Revision 1. The licensee's effort will culminate in an '

event review team procedure with basic guidance for gathering

information immediately' following an event.

The' inspector assessed the licensee's performance, with respect to this

restart-related issue, in the five NRC continuing areas of concern:

,

.- Management Oversight - Adequate

. Engineering Effectiveness - N/A i

e Knowledge of the Design Basis - N/A  !

. Compl %1 ce with Regulations - Adecuate '

. Operator Performance - Inacequate i

II. Maintenance

L M1 Conduct of Maintenance

M1.1 General Comments

a. Insoection Scooe (62707. 61726)

Using Inspection Procedures 62707 and 61726. the inspectors observed all

or portions of the following WRs and surveillance procedures (SP) and

reviewed associated documentation. The following activities were

included:

,

. WR NU 0340401 Prefabricate piping and piping supports for the

installation of the emergency feedwater

cavitating venturies

. WR NU 0339887 Modify the emergency feedwater recirculation-

Jiping and supports per Modification Approval

Record (MAR) 96-10-02-01 for the installation of

the cavitating venturies

. WR NU 0340741 Install equipment, piping, and pipe supports per

MAR 96-10-02-01

L

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.~ WR NU 0339304 Fabricate and install new conduit supports for

MAR 96-10-02-01

a - - _ . _-

_ __ . .

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. WR NU 0339324 Replace EFV-12 with Atwood-Morrill parallel disc

gate valve per MAR 96-10-10-03

• SP-301 Shutdown Daily Surveillance Log, Revision 99

b. Observations and Findinas

The inspectors observed the activities identified above and concluded

that the work being performed was in accordance with the ap3 roved work

instructions.. All work observed was performed with the worc packages

present and in active use. Pre-job )lanning was thorough and in

sufficient detail to prepare the tec1nicians for the assigned tasks.

Technicians were experienced and knowledgeable of their assigned tasks.

The inspectors frequently observed supervisors and system engineers

monitoring job progress, and quality control personnel were present

whenever required by procedure.

The inspectors reviewed the implementation of tagging order 97-04-026,

which isolated the emergency feedwater system for the installation of

the cavitating venturies on EFP-2. A walkdown was performed which

verified that each component was in the position specified on the

tagging order and properly tagged.

c. Conclusions

The inspectors concluded that Maintenance activities were performed in

accordance with procedures and desired results were obtained.

III. Enaineerina

El Conduct of Engineering

i El.1 Enaineerina Work Hours

a. Insoection Scoce (37550. 37551)

The inspectors reviewed the hours of work for the plant engineering i

personnel during the present outage. i

,

b. Observations and Findinas

On February 4, 1997, an anonymous PC was written documenting a concern

that engineering, planning and first line supervision were being ,

l required to work extensive uncompensated overtime, which was causing a l

major breakdown in employee morale.  !

l

The inspector reviewed the licensee's resolution to the PC and performed i

follow-up of the concerns. The licensee acknowledged that the I

engineering staff was being required to work uncompensated overtime but i

did not characterize the amount of time as excessive. On February 20. l

1997, the licensee management agreed to pay eXemat employees an extended l

shift differential for certain circumstances. Tlese included: the time 1

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worked must-be preapproved and prescheduled, the shortest period an

employee will be placed on extended shift differential will be one pay

period, and the extended shift differential will ecual 40% of the

l employee's normal pay for the period. The extendec shift differential

was not for occasional emergent work. The licensee considered that the

employee's salary was established with the potential to cover the

occasional emergent work.

.

The inspectors reviewed the engineering time records for the duration of

! the present outage. Until the extended shift di.fferential was

l implemented, the engineering staff did not maintain official records of -

l the actual hours worked by the staff. .The inspector discussed the hours  :

being worked with the department manager. From October 1996 through ,

'

March 1997, the design engineers have been on 50 hour5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br /> weekly schedules.

i Between March 1997 and April 1997, the design engineers have been on 60

l. hour weekly schedules. The manager is planning to ) lace the design .  ;

!- engineering staff on alternating 50 and 60 hour6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> weedy schedules. These

schedules were approved by the department manager.

l

^

l The system-engineering staff are not required to keep total hours worked

l . on their time records, but are encouraged to do so by the department

l- manager. The inspector observed that it is very common for the system

engineers to record the actual hours worked in the comment section of

'the time sheets. The manager of the system engineers informed the

i inspectors that the schedule was not fixed, but that the goal was to

! limit system engineers to no more than two concurrent 60 hour6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> weeks,  !

l followed by a return to a normal schedule. The manager estimated that -l

-since the implementation of the extended shift differential, that

.approximately sixty percent of the system engineers were approved at any-

one time. The inspector reviewed the individual time sheets for the

department. No cases where personnel had worked more than 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> in a

one week period were identified.

AI-100, Facility Administrative Policies, requires that any personnel

,

engaged in safety-related activities not work more than 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> in a

f seven day )eriod without a))roval from certain managers, such as the

! Assistant )NPO, Assistant HP0 Maintenance, Manager of Operations,

Manager of Chemistry and Radiation Protection, or Nuclear Shift Manager

<

(NSM). For work in excess of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a seven day period, only the

DNPO, or in his absence the.NSM, may approve the overtime. The

licensee's policy is to consider. engineering activities as safety-

related. l

c. Conclusions

~

No readily retrievable objective evidence exists that shows any

- violation of overtime restrictions, as outlined in Generic Letter (GL)

i 82-02, Nuclear Power Plant Staff Working Hours. or mirrored in licensee

[ Procedure AI-100. Periods of extended overtime have been acknowledged

'

by licensee management, but these periods were below the amounts

controlled by either the NRC or the licensee. The licensee has

demonstrated an effort to. minimize the overtime worked by exempt

!

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)

personnel, but the licensee concluded that the plant shutdown due to l

engineering and management deficiercies has necessitated overtime to  !

complete the plant recovery in a timely fashion.

E8 Miscellaneous Engineering Issues l

1

E8.1 (Closed) URI 50-302/97-01-06: HPI System Desian. Licensino Basis. and TS

Concerns

a. Insoection Scooe (92903) I

During this inspection, the inspectors followed u) on the third (of

three) examples of this unresolved item (URI). T1e first two examples ,

of this URI were addressed in Inspection Report (IR) 50-302/97-06. The j

third example of this URI involved a concern with maintenance and  !

surveillance testing of active components that were relied upon by both i

trains, and Technical Specifications (TS) compliance during the i

maintenance and surveillance testing. The components that were relied

upon by both trains included High Pressure Injection (HPI) injection i

Valves MUV-23 MUV-24, MUV-25. and MUV-26: the normal makeup valve. MUV-  !

27: the Reactor Coolant Pump (RCP). seal injection valve, MUV-18: the

normal letdown valve, MUV-49: the HPI pump discharge crosstie valves,

i MUV-3 and MUV-9: and the turbine-driven emergency feedwater pump. EFP-2.  ;

The inspector had considered that further review was needed to determine l

when these components were out of service for maintenance or l

,

surveillance testing with the )lant in Mode 4 or above during the last i

l three years, and in each case low TS compliance was effected.  ;

b. Observations and Findinas

The inspectors further reviewed the TS and noted that TS 3.5.2 required l

that two Emergency Cure Cooling System (ECCS) trains shall be operable

in Modes 1, 2 and 3. However. TS Bases 3.5.2, ECCS-Operating, addressed

the fact that the HPI system downstream of the HPI pumps was not ,

l separable into two distinct trains. It states that when components '

become inoperable, an assessment of the HPI system to perform its safety

function must be performed. If the system can continue to perform its

safety function, without assuming a single active failure, then the 72

hour loss of redundancy ACTION is appropriate. If the inoperability

, renders the system, as is, incapable of performing its safety function,

l without postulating a single active failure, then the plant is in a  !

l- condition outside the safety analysis and must enter into Limiting ,

Condition for Operation (LCO) 3.0.3 immediately. The inspectors l

l assessed that each one of the subject components could be inoperable. I

and with nc other components inoperable at the same time, the system  ;

could meet the stated criteria for use of the 72-hour ACTION statement. j

. The inspectors noted that TS 3.7.5 required that two EFW trains be

operable in Modes 1. 2 and 3: TS 3.8.1 required that two Emergency

Diesel Generators (EDGs) be operable in Modes 1, 2, 3 and 4. However,

neither these TS nor their bases address the cross-train dependency of

the A EDG on the B train turbine-driven emergency feedwater pump. The

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inspectors verified that the licensee )lanned to submit to the NRC a

recuest for a TS revision to address t1is cross-train dependency. In

adcition, the licensee had the issue identified on their restart list

(items R-2 and D-29-B), and already had a draft of the TS revision.

The inspectors reviewed selected records of maintenance and surveillance

testing performed on these components during the previous two years

while the plant was operating. The inspectors found that in each case

when one of the com)onents had been placed out of service for

maintenance while t1e plant was operating the appropriate TS LCO ACTION

statement was entered and logged in the Shift Supervisor's log. Also,

other equipment was not inappropriately logged out of service at the

same time. The inspectors noted that most of these components were

rarely taken out of service for maintenance while the plant was

operating, with one exception. EFP-2 had been out of service for online

maintenance on several occasions, for repeated packing leakage and oil

quality problems. On further review of the EFP-2 maintenance problems,

the inspectors found that the licensee had addressed the packing leakage

problem by installing a different ty)e of packing. The different

packing had resolved the packing leacage poblem and also apparently

resolved the oil quality problem (the last three cuarterly oil samples

from EFP-2 had tested good). The engineers statec that past Jacking

leakage had apparently caused moisture to get into the oil, w1ich in

turn had caused high acidity in the oil,

c. Conclusions

The inspectors concluded that online maintenance and surveillance of

active components that were relied upon by both trains was adequately

controlled, with the exception of the TS not addressing the cross-train

dependency of the A EDG on the B train EFP-2. However, the licensee was

actively addressing this issue by drafting a TS amendment request, and

had included it on their restart list. Also, the licensee had addressed

past maintenance problems with EFP-2. URI 50-302/97-01-06 is closed.

The inspectors assessed the licensee's performance, with respect to this

issue, in the five areas of continuing NRC concern:

. Management Oversight - Good

. Engineering Effectiveness - Good

. Knowledge of the Design Basis - Good

. Compliance with Regulations - Good

. Operator Performance - N/A

E8.2 L0oen) URI 50-302/95-02-02. Control Comolex Habitability Envelooe

(CCHE) Leakaae

a. Insoection Scooe (92903.1

During this inspection, the inspectors followed up on three areas of

this URI listed below that needed further NRC review.

!

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.

.

i

19

. Design calculations for CCHE leakage through dampers, doors and

penetrations; including assumed differential pressures across

ventilation dampers.

,

• Procedures for emergency repairs to dampers susceptible to single

failure (as committed to by the licensee in response to NUREG

0737. Item III.D.3.4.).

• Design calculations for operator dose and how they account for at

least two hours of time to repair dampers susceptible to single

failure (per NUREG Item III.D.3.4).

b. Observations and Findinas

1) The inspectors had previously noted that design calculations for

CCHE leakage included differential pressures across Dampers D-1

and D-2 that did not appear to be correct. The licensee's

calculated pressure on the inside of CCHE isolation Damper D-1 was

minus 1.0 inches of water gauge (w.g.) and the calculated pressure

on the inside of CCHE isolation Damper D-2 was plus 0.67 inches

w.g. However, with the control room emergency ventilation system

(CREVS) in emergency recirculation. Dampers D-1 and 0-2 were

separated by only a few feet of ventilation ducting and fully open

Damper D-3. Using vendor damper information. the inspectors

calculated that the pressure dro) across fully o)en Damper D-3

(and the difference in pressure aetween D-1 and 3-2) would be ,

about 0.1 inches w.g. Therefore, the inspectors concluded that  !

the licensee's calculated pressures of minus 1.0 and plus 0.67

inches w.g. (a difference in pressure between D-1 and D-2 of 1.67

inches w.g.) were apparently not correct. The inspectors noted

that changes in these calculated pressures would affect the

calculated post-accident operator dose.

During this inspection the inspectors reviewed the calculations

of the differential pressures across (and leakage through) Dampers

D-1 and D-2. These included a calculation. Control Complex l

Habitability Analysis (Heating Ventilation and Air Conditioning <

(HVAC) Damper Leakage), dated February 20. 1986; and Calculation

M-91-0007. Air Handling Calculations, dated April 21, 1992. The

inspectors found the following.

. The 0.67 inches w.g. pressure inside D-2 was calculated by

adding line pressure drops from just upstream of fan AHF-19

(and even further upstream of D-2) to the High Efficiency

Particulate Air (HEPA) filters (downstream of D-1 and even

further downstream of D-2). This pressure calculation did

not start at any point with near zero pressure (i.e. inside

the control room) did not end at Damper D-2, and also did i

not include the pressure added by Fan D-19. In short, the  !

!

inspectors found that the method used to calculate the

pressure on the inside of D-2 did not appear to be valid.

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

-

. .

i

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20

t

,

. .The minus 1.0 inches w.g. pressure inside D-1 was calculated l

l by adding line pressure drops from D-1 to the control room  :

'

L and subtracting the pressure added by Fan AHF-18 to arrive

at a value.of minus 0.11 inches w.g., then rounding this-  !

value to minus 1.0 inches w.g. However, it did not include j

a plate (with holes in it) installed in the CREVS a few ~

years ago by the air conditioning cooling coils downstream  ;

of AHF-18 to keep moisture. carryover out of the control room

ceiling. The system engineer stated that the installation  ;

of this plate dropped ventilation flows by about 10%. The  ;

! inspectors assessed that inclusion of this plate in.the .!

l calculation would likely change the calculated pressure  ;

l inside D-1 to a positive value.

r .

'

. The calculation rounded the minus 0.11 inches w.g.

calculated )ressure inside D-1 to minus 1.0 inches w.g. '

pressure (tle calculation stated this was for conservatism).  :

and the minus 1.0 inches d/p resulted in a calculated

inleakage through Damper D-1 of 191 cubic feet per minute

, (cfm). This inleakage would'go through the charcoal filters

l

and thus was counted as filtered leakage (the filter's remove ';

almost all of the radioactive Iodine from the air). The

-

l calculation counted the balance of the 355.cfm of inleakage

i as unfiltered leakage (355 CFM equals .06 of the CCHE volume

l Jer hour, assumed by the licensee so that the CCHE would not l

l 1 ave to be pressure tested as allowed by the NRC Standard 3

l Review Plan). The inspectors noted that use of an .

artificially high number for filtered leakage was not

conservative but was actually nonconservative, in that it >

reduced the allowance for unfiltered leakage and thus i

reduced the calculated operator dose. The inspectors

estimated that correctly calculated or measured pressures j

would reveal a positive pressure inside both D-2 and D-1. -

resulting in net additive outleakages through both dam)ers.  !

no filtered leakage, all of the 355 CFM of assumed leacage i

,

'

being unfiltered, and higher calculated post-accident ]

operator dose. The inspectors noted that a positive  ;

pressure inside 0-1 and D-2 could also cause the total- ,

calculated CCHE leakage to exceed 355 CFM which could l

l further increase calculated post-accident operator dose. 1

Additionally, the inspectors noted that the licensee's

!= calculated post-accident operator dose (29.49 REM to the l

thyroid) was very near the regulatory limit of 30 REM to the i

. thyroid,- so that any increase could exceed the regulatory

'

l

l limit. t

In response to the inspectors' concerns with calculated values for I

damper leakage, the licensee initiated PC No. 97-2026.

,

]

i 2) The inspectors asked to see licensee procedures for emergency

repairs to dampers susceptible to single failure (as committed to

l. by the licensee in response to NUREG 0737. Item III.D.3.4.), such

=. a. . .- - - --

__ _ . _ _ . _ . _ . _ . . _ _ _ - _ . _ _ _ . _ _ ._.

• '

I l

,

I

l  !

( 21 i

!

as Dampers D-2, D-99 D-12. and D-3. The system engineer and  ?

operations personnel stated that there were no such procedures.  !

-In response to this inspector concern, the licensee' initiated a

PC.

r

-3) The inspectors reviewed the design calculation for operator dose,

Calculation I-86-0003, Off Site Doses and Maximum Allowable

l

-!

Infiltration; Rev. 8. dated April 19, 1996. The inspectors noted  !

L

the below about this calculation: i

,  ;

L e It concluded that the limiting 30-day post-accident dose to i

control room o)erators is thyroid dose from Iodine, which is  ;

calculated to ]e 29.49 REM and is very close the regulatory i

limit of 30 REM. This calculation assumes that a CREVS i

emergency recirculation fan is started by operators within  !

10 minutes.

l

l

e It did not account for time to repair dampers susceptible to

single failure. but instead assumed that CCHE isolation-

l

,

l- dampers close immediately (in less than one minute). The  :

allowance of at least two hours to repair dampers

-

!

'

susceptible to single failure is discussed in the NRC .

Standard Review Plan, which is referenced by NUREG 0737, d

Item III.D.3.4. In correspondence with the NRC in.1987 1'

E through 1989 regarding Item III.D.3.4, the licensee did not

commit to comply with the Standard Review Plan but did

commit to have procedures for operators to address the

potential failure of dampers that are susceptible to single

failure.

. It concluded, in pages inserted by Rev. 8 in 1996, that if

operators do not start an emergency recirculation fan until

30 minutes after event initiation, then the calculated 30-

day post-accident operator dose will be either 22.65 REM,

22.696 REM or 14.147 REM based on the use of different

assumptions. The assumptions used in these calculations,

-

for dose from reactor building (RB) leakage and ECCS

leakage, were different than the assumptions ~ used in the

previous calculation of 29.49 REM discussed in a) above.

The purpose statement'in front of the calculation stated

that International Commission on Radiation Protection (ICRP)

30 dose conversion factors were used in lieu of ICRP 2  :

factors, but no basis was given for the use~of different  !

assumptions. The inspectors noted that, due to EDG loading

concerns, operators had been instructed in 1996 to delay I

starting an emergency recirculation fan until 30 minutes

l after event initiation. The. inspectors noted that just

delaying the start of the emergency recirculation fan would .

'

actually increase the operator dose from 29.49 REM, not

decrease it.

,

._ -- _ _. . , , -

._

..

22

l

l * It nonconservatively assumed CCHE isolation dampers close in

, 11.5 seconds. This was less than the 30 seconds assumed in

i

Calculation I-92-011 and also less than the 40 seconds from

l actual testing.

. It nonconservatively assumed a CREVS air flow of more than

that measured in recent surveillance testing. The FD-302-

753 series drawings also showed a higher air flow.

• It nonconservatively did not appear to take into account

pressure drop changes from the particulate matter that would

accumulate in the charcoal filters during an event, charcoal

filter iodine removal efficiency degradation due to moisture

content, or operation of the charcoal filters near the upper

end of their allowable pressure drop.

. It included a potentially nonconservative assumption that

10% of the control room volume was filled with interior

walls. The inspectors noted that less assumed control room

volume results in less assumed inleakage and a lower

calculated operatcr dose.

. It included a potentially nonconservative assumption that

between 8 to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after an event, the offsite

respiration rate drops by 50% then raises back to the

initial respiration rate. There was no stated basis for

this assumption. The inspectors noted that a lower assumed

respiration rate results in a lower calculated dose.

• It inconsistently assumed that filtered leakage was 191 CFM

(on sheet 39) and also assumed that filtered leakage was 70

CFM (on sheet 23) and that in each case the balance of the

assumed total 355 CFM of leakage was unfiltered. The i

Control Complex Habitability Analysis (HVAC Damper Leakage)

calculation, discussed above. calculated the value of

filtered leakage to be 191 CFM. Also, Calculation I-92-0011

assumed that filtered leakage was 70 CFM.

c. Conclusions

The inspectors concluded that there were nonconservative errors in the

licensee's calculations for CCHE leakage and post-accident operator  ;

dose. The inspectors also concluded that the licensee had failed to

implement procedures for operators to address the potential failure of

CCHE isolation dampers susceptible to single failure, as committed to in

response to NUREG 0737, Item III.D.3.4. These issues are added to URI l

,

50-302/95-02-02 and remain o)en pending: 1) further licensee l

'

calculation or testing of CCiE leakage. licensee assessment of the  !

resulting impact on current and past operability of the CREVS. and NRC l

review of that information; and 2) further licensee and NRC review of '

l the licensing basis for CCHE isolation dampers susceptible to single i

failure. URI 50-302/95 02-02 also remains open pending further NRC

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

l

l

23

review of the effects of a breach in the CCHE on CREVS operability, the

need for a change in the TS and TS bases to address the effects of a i

breach in the CCHE on CREVS operability, and the need for a CREVS TS

l surveillance for CCHE integrity.

l

l Since further licensee and NRC review of these issues is needed, the

!

inspectors did not at this time assess the licensee's performance with t

respect to these issues. -

'

E8.3 (Closed) LER 50-302/95-013-01. Desian Deficiency May Cause Makeuo Tank '

Vortexina Resultina in Failure to Meet Apoendix R Reauirements

a. Insoection Scoce (92700) t

This inspection effort focused on the corrective actions specified in

LER 50-302/95-013-01.

'b. Observations and Findinas )

i

On July 7,1995. FPC notified the NRC that Crystal River Unit 3 (CR3)

had operated outside its licensing (design) basis for 10 CFR 50 Appendix

R. in that two 10 CFR 50 Appendix R fire scenarios were identified which

~would provide operators less than eight hours to isolate the makeup tank

(Event Number 29036). On February 27, 1996 FPC issued Revision 1 to LER

95-013. Revision 1 supplied supplemental information associated with

the information presented on July 7, 1995.

In addition to the actions reviewed in IR 50-302/96-06. the ins)ector

reviewed the licensee's completed closeout package and all of t1e

licensee actions taken subsequent to IR 50-302/96-06. This included a

review of all information included in the closecut package and all

referenced documentation.

l

c. Conclusions

l

The inspector confirmed that all of the substantial issues were

addressed.in IR 50-302/96-06. The ins)ector confirmed that the

supplemental information submitted in Revision 1 was also addressed in

IR 50-302/96-06. The inspector also concluded that the closecut package

was complete and the actions taken were appropriate.  !

E8.4 (Closed) IFI 50-302/95-15-03. Desian Reauirements for Reactor Coolant

Pumo Cooler Failure j

a. Insoection Scoce (92903) l

This issue involved a concern regarding the potential failures of the ,

RCP thermal barrier heat exchanger piping as it relates to the

j

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24

licensing basis and design basis of CR3. The inspector followed up on

licensee and NRC actions to resolve this issue.

I b. Observations and Findinas

The NRC Region II submitted Task Interface Agreement (TIA)-95-014 to the

NRC Office of Nuclear. Reactor Regulation (NRR) requesting NRR to review

the CR3 design basis relating-to the potential failures of the RCP

tLrrmal barrier heat exchanger piping and its associated nuclear

,

ser / ices closed cycle cooling =(NSCCC) system. NRR res)onded to the TIA

f' and concluded that the. potential failures of the RCP tiermal barrier

heat exchanger piping were not within the original design for CR3. In a

letter, dated August 27 1996, NRR requested information from the

licensee. Potential Overpressurization of the NSCCC System Piping -

Request for Additional Information (TAC No. M93604). The licensee

, responded to this request for additional information (RAI) in letters

L dated October 8. 1996, and February 28, 1997. NRR is currently

,

reviewing the licensee's responses to the RAI. Therefore, this

! Inspector Followup Item (IFI) will be closed and the NRR review of the

licensee's response will be tracked under TAC No. M93604.

c. Conclusions

, NRC concluded that the potential failures of the RCP thermal barrier

l heat exchanger piping were not within the original design for CR3. NRC

'

is currently reviewing the licensee's response to the RAI. This item is

closed and further NRR review will be tracked under TAC No. M93604.

The inspector assessed the licensee's performance, with respect to this

,

issue, in the five areas of continuing NRC concern:

l

l e Management Oversight - N/A

l . Engineering Effectiveness - Good

. -Knowledge of the Design Basis - Good

L e Compliance with Regulations - N/A

l . Operator Performance - N/A

E8.5 (Closed) LER 50-302/96-002. Personnel Errors by Enaineerina Result in

Ooeration Outside Desian Basis Due to Inadeouate Safety /Non-Safet.y

l

Circuit Isolation

a. ~Insoection Scooe (40500. 92903)

The inspector reviewed the subject LER in conjunction with VIO

50-302/95-21-03, which involved improper' isolation of Class IE from Non

Class IE electrical circuitry for the reactor building purge valves and

, mini-purge valves. This LER will be closed and the remaining corrective

[ actions will be followed up in conjunction with VIO 50-302/95-21-03.

!

,

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25

E8.6 Problem Identification

a. Insoection Scooe (40500)  :

!

l~ The inspector followed up on some NRC questions and licensee PCs related j

to Appendix R issues on the licensee's restart list. j

b. Observations and Findinas

l

The inspector reviewed licensee documentation, selected PCs. and the  !

g related licensee responses to address the issues identified. .;

,

i. . The inspector reviewed PC 97-1522, which identified a concern  ;

where high temperatures in the intermediate building during a loss  :

of offsite power (LOOP) prohibited unprotected access to the.  :

, atmospheric dump valves (ADVs). This raised a question as to what '

l

'

impact this would have on manual operation.of the ADVs and the  !

ability-to achieve cold shutdown in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> during an Appendix R.  !

fire event. ' The licensee determined that this condition was i

reportable under 10 CFR 50.72. The NRC.will review this concern

_

further during followup of the licensee's planned LER (not yet i

!

issued as of. this inspection date).  !

-. The inspector reviewed PC 97-2360' which identified a concern

,

!

where remote control of the ADVs may not be available for long

term cooling as described in Abnormal Procedure AP-990. Shutdown

From Outside Control Room. The procedure directed operators to

use instrument air or align the ADV backup nitrogen supply to

allow remote control of the ADVs from the remote shutdown Janel-

during an Appendix R fire event. The PC identified that t,e l

apparent cause of failing to recognize the limitations of the ADV 4

backup nitrogen supply was a lack of understanding of the Appendix

R requirements associated with control room evacuation. During

review of the corrective actions for this PC, the inspector noted

that the proposed corrective actions'were weak in that they did

not adequately address the apparent cause that was identified for

the PC.

. The inspector reviewed a change made to Section B3.7.4 of the

Improved Technical Specifications (ITS) Bases, which involved the

ADVs and the associated backup nitrogen supply for the valves, i

This change included the associated 10 CFR 50.59 safety

L evaluation. Durina review of the change Jackage., the inspector

'

noted that the ITS Bases indicated that tie ADV backup nitrogen

l ' supply was installed and sized to provide sufficient pressurized

'

gas to operate the ADVs for four hours, which was the time

L required to cope with a station blackout (SBO) event. The

inspector noted that use of the ADV backup nitrogen supply for  !

operation of the ADVs from the remote shutdown panel during an- I

i A)pendix R fire event was described in licensee Abnormal Procedure

. A)-990, Shutdown From Outside Control Room. The abnormal .

[ procedure does 'not discuss manual operation of the ADVs. I

l

'  :

_ _ __. __ . . - _

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

. .  !

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26

,

_ The inspector questioned the adequacy of 50.59 performed for this [

ITS Basis change in that the 50.59 does not address AP-990, which >

takes credit for using the ADV backup nitrogen supply to operate -

the ADVs from the remote shutdown panel. The ins)ector discussed )

the 50.59 with licensee personnel who indicated tlat the 50.59 was  !

considered to be adequate because use of the ADV backup nitrogen  !

supply for remote operation of the ADVs during an Appendix R fire  :!

event was not taken credit for in the Appendix R licensing basis '

and design-basis. The Appendix R licensing and design bases only J

took credit for manual operation of the ADVs during an . Appendix R  ;

fire event. The inspector differed with the licensee's position -

on this 50.59. The inspector informed the licensee that this 1'

question of whether the 50.59 should have addressed the use of the

ADVs in AP-990 will be reviewed further during subsequent.NRC j

inspections. This issue will be tracked as URI 50-302/97-05-02. >

50.59 Safety Evaluation does not Address Operation of the. l

Atmospheric Dump Valves from the Remote Shutdown Panel During an )

Appendix R Fire Event. j

i

c. Conclusions '

)

The inspector concluded that the proposed corrective actions for PC l

97-2360 were weak.in that they did not adequately address the apparent i

cause that was identified for the PC. The inspector j

adequacy of 50.59 performed for the ITS Basis change in thatquestioned

the 50.59 the i

did not address AP-990, which took credit for using the ADV backup 1

nitrogen supply to operate the ADVs from the remote shutdown panel.

'

This cuestion of whether the 50.59 should have. addressed the use of the

ADVs cescribed in AP-990 will be tracked as an unresolved item.

The inspector assessed the licensee's performance, with respect to this-

issue, in the five areas of continuing NRC concern:

. Management Oversight - Adequate

• Engineering Effectiveness - N/A

.- Knowledge of the Design Basis - Adequate

e Compliance with Regulations - N/A

e Operator Performance - Adequate

E8.7- (Closed) IFI 50-302/96-201-16. Coordination of Second Level Undervoltaae

Relav (SLUR) Settino VS Inverter Ooeration. [ Identified as IFI 96-201-

06 in NRC Insoection Reoort 96-2011.

! a. Insoection Scooe (92903) J

. I

This IFI involved a concern with regard to the vital inverters when the  !

" battery supplying _ load" alarm annunciated on several occasions when i

L chiller CHHE-1A was started.

i

!

'

1

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27

b. Observations and Findinas

With regard to the vital inverters, the " battery supplying load" alarm

went to the alarm condition on several occasions concomitant with

starting 193 kW chiller CHHE-1A. The purpose of this alarm was to warn

o)erators that the source of power for the inverters had switched from

t1e normal 480 Volts Alternating Current (VAC) source to the backup 125

Volts Direct Current (VDC) source. The inspectors were concerned that

these events represented a problem with overall system voltage or the

SLUR set point.

1

The following facts were determined during this inspection. Channels A i

and C inverters were replaced during the spring 1996 outage due to aging

concerns with the original inverters under MARS 93-05-07-03 and 04. The i

original inverters had an alarm driven by a contact making ammeter,

which gave indication that the DC system was supplying power to the -

inverter. Due to the way that the specification for the new A and C  !

inverters was written, the manufacturer supplied a " battery supplying l

load" alarm driven by a voltage relay sensing voltage at the DC input I

and set at 127 VDC. After installation, the circuit was revised to  !

sense voltage at a point between the AC source rectifier and the DC

auctioneering diodes and set at 135 VDC. j

The various related voltages were:

Normal voltage at output of AC source rectifier - 139 VDC

1

.

!

. Voltage alarm set point - 135 VDC (97 percent of normal source)

. Charger float voltage - 130 VDC (93.5 percent of normal source).

It was estimated by the ins)ector that starting a 193 kW chiller, which

was fed from the same bus tlat feeds the inverter, would cause bus l

voltage to dro) below 97 percent of normal. Power conditioning

equipment in t1e inverter upstream of the voltage relay were a

transformer and silicon controlled rectifiers (SCRs). Review of the

information in the instruction manual led to the conclusion that this

equipment was not designed to completely filter out motor starting

voltage dip transients. Therefore, given the arrangement of the voltage

relay, normal expected transients, such as motor starting and system

disturbances, would be expected to operate the relay. The voltage relay

would go to alarm state only momentarily. then return to normal

condition. Confirmation of inverter rectifier circuit operation in

response to motor start trarsients was restart item D-47. The licensee

planned to confirm operation by consulting with the manufacturer and

,

performing on-site tests.

l The inverters for channels B and D were in the on-site warehouse. and

i they had been modified by the manufacturer to use current sensing for

i the "DC supplying load" alarm. This modification would eliminate the

alarm upon motor starting. Installation of inverters B and D was

restart item M-7. Engineers stated that modification of the "DC

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

t 1

• -

[ )

.

28 l

1

sup)1ying load" alaim on inverters A and C would be made under a MAR  !

paccage by on-site personnel. However, this work was not a restart item

and could be rescheduled for refuel 11 outage. j

Given the fact that the inverter load can transfer between the normal AC

l

'

source and the backup DC source. depending on the relative voltage I

- levels', the inspector reviewed battery and emergency generator loading i

vis-a-vis the inverter loads. By review of Battery and Charger Sizing  !

Calculation. E-90-0099, Rev 2, the inspector confirmed that the ,

inverters were carried as a load for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> in the Loss of Coolant. 1'

Accident (LOCA)/ LOOP scenario and four hours in the Blackout scenario.

Also. by' review of drawings, the inspector confirmed that there was an l

85-second delay on retransfer to AC after a LOOP to ride out emergency i

diesel generator sequencing time.  !

,

The inspector reviewed the pages in Annunciator Response Procedure AR-  ;

701, SSF P Annunciator Response, that applied to the annunciator point l

" inverter trouble.' There was a se '

inverters. Each ' inverter trouble"parate point for each

point comprised four or of fivethe problem

four

i

t.

+

. conditions. The :coblem condition generating the annunciator could be  !

l determined from-tie sequence of events recorder. The inspector noted i

l that the procedure sheets for inverters A and C were revised to  !

incorporate information changed by MARS 93-05-07-03 and 04. The i

inspector noted that ir, formation in the " indicated condition" block of  :

the alarm' response procedure was not correct or not consistent with j

cther documents for three of the event points. t

l

[ The indicated condition for-event point 0164 was given in terms of l

'

current rather than voltage. As previously discussed, the MAR revised

this event point from current sensing to voltage sensing. The set point

for event point 0169 was given as 168 A, but the MAR functional test .

package indicated that the relay was set at 200 A. The set point for  !

event point 0189 was given as 114 V, but the MAR functional test package  !

indicated that the_ relay was set at 111.5 V. The inspector then i

determined that the MAR package indirectly specified the set points  ;

associated with the inverters by stating that the set _ points for the new i

inverters would remain the same as for the original int rters. This was  :

a valid statement except for event point 0169 which was changed from 1

current sensing to voltage sensing. Apparently, the set point l'

L infortnation in the alarm response procedure for event )oints 0169 and

L 0189 was incorrect before the MAR was implemented in t1e spring of 1996.  !

Operations personnel who revised the alarm response procedure to '

l

incorporate the MAR changes did not attempt to change any set point

information, because the MAR stated that the set points were not.

changing.

The fact that " indicated condition" block for a number of annunciator  !

L response procedure pages for safety-related equipment were incorrect i

constitutes a violation of the Technical Specification 5.6.1.1. which  ;

requires by reference to Regulatory Guide 1.33, Quality Assurance

'

!

Program Requirements, that each safety-related annunciator have its own .

4

written procedure, which would normally contain the meaning of the  ;

i

l

l

r. - - . - - _ _ .

~

,

_ - _ _ -__ _ _ _ _ _ _ _ - _____ __

. .

29

annunciator among other information. The violation was identified as

Violation 97-05-03. Incorrect Information in Annunciator Response

Procedure for Inverters.

Additional documents reviewed included the FSAR, the Design Basis

Document. IEEE Std 308 June 1969, Purchase Specification MS-211 for the

new inverters and Precursor Cards 96-3744, 96-3528, 96-2853, 97-0333.

Also, the four inverters VBIT-1A 1B 1C and 10 were examined in a

walkdown inspection.

c. Conclusions

The overall conclusion with regard to inspection of the subject issue I

was that the observed inverter related alarms, simultaneous with  !

starting of certain motors did not represent any problem with system  !

voltage or the SLUR set point which was the concern stated in the IFI. l

Therefore. IFI 50-302/96-201-16 is closed. As a result of reviewing

this issue, the NRC identified that certain annunciator response I

procedures contained incorrect information, and a violation was issued

for this problem. This )roblem was caused by deficiencies in the

modification process. T1ere had been differences of opinion within the

licensee's organization about the significance of the momentary inverter l

trouble alarm occurring in conjunction with starting large motors. l

Design Engineering thought that the alarm could indicate the inverter I

was not performing as designed. System Engineering thought the inverter

was working as designed. While this issue did not represent an

immediate operability concern, it was an issue requiring resolution. In

the inspector's judgement, resolution of this issue was delayed

indicating that engineering performance was less than effective.

With regard to IFI 96-201-16. the inspector assessed the licensee's

aerformance, for the time period of June 1996 to present, in the five

1RC continuing areas of concern as follows: l

. Management Oversight - Inadequate

. Engineering Effectiveness - Inadequate

. Knowledge of the Design Basis - N/A

. Compliance with Regulations - Inadequate

. Operator Performance - Adequate

E8.8 (Closed) LER 50-302/95-025-01. Personnel Errors by Architect Enaineer

Result in Ooeration Outside Desian Basis Due to Inadeouate Safety /Non-

. Safety Circuit Isolation

a. Inspection Scoce (40500. 92903)

The inspector reviewed the subject LER in conjunction with VIO 50-

302/95-21-03, which involved improper isolation of Class IE from Non

Class IE electrical circuitry for the reactor building purge valves.

This LER will be closed and the corrective actions for this LER will be

followed up in conjunction with VIO 50-302/95-21-03.

t

i

. .

30

E8.9 (Ocen) VIO 50-302/95-21-03. Failure to Isolate the Class IE from the Non

Class IE Electrical Circuitry for the Reactor Buildina Purae and Mini-

Purae Valves

a. Insoection Scooe (40500. 92903)

This violation involved failure of the licensee to isolate properly

Class IE from Non Class IE electrical circuitry for the reactor building

purge and mini-purge valves. The inspector followed up on the

licensee's corrective actions for this violation in conjunction with

LERs 50-302/95-025-01 and 50-302/96-002.

b. 0bservations and Findinas

The inspector reviewed the corrective actions specified in LERs 50-

302/95-025-01, and 50-302/96-002 and the licensee's response to VIO 50-

302/95-21-03 that was issued for this concern. The corrective actions

were reviewed for compliance with the FSAR. TS, and applicable licensee

procedures. The inspector noted that some of the corrective actions

specified in the responses had been completed. Other corrective actions

involved implementation of modifications to address the issue. Some of

the modifications had been implemented. During review of the corrective

actions, the inspector noted that the licensee had completed the

evaluation of alternatives to the non-isolated design of the control

circuits for reactor building Purge Valves AHV-1A and AHV-1D. This

evaluation (conclusions documented in licensee interoffice

correspondence (IOC) N0E96-0201, dated December 12. 1996) determined

that the resolution for isolation discrepancies of Purge Valves AHV-1A

and AHV-]D would also Nguire a design modification which could involve

pullino new cables and upgrading or installing new equipment.

Durint further review, the inspector noted that one of the problem

reporcs initiated for this issue (PR 95-0223) indicated that the

completion date for the evaluation had been extended from December 20,

1996, to May 31. 1998. The inspector discussed this PR with licensee

Jersonnel who indicated that the evaluation had been completed in

Jecember 1996 as discussed in IOC N0E96-0201, and the May 31. 1998 date

was the scheduled date for implementation of the modification. The

inspector noted that this item had recently been evaluated by the

licensee and included on the restart list for im)lementation of the

modification prior to restart from the current slutdown. Licensee

personnel further indicated that although the evaluation was completed

in December 1996. they did not supplement LER 50-302/95-025-01 or VIO

50-302/95-21-03 by December 20, 1996, as was stated by the licensee in

earlier responses to these items (su)plement 01 to the LER dated

December 22, 1995, and response to t7e VIO dated March 25, 1996). The

licensee initiated n eursor card PC 97-2413 to address the failure to

supplement the LER and VIO by December 20, 1996. The inspector

considered the l u nsee's handling of the supplements to the LER and VIO

to be a weakness in cne licensee's commitment tracking process. The

inspector informed the licensee that this new issue will be identified

and tracked as URI 50-302/97 05-04. LER and Violation not Supplemented

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

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by Date Stated by Licerisee. This item is unresolved pending further NRC  !

review of the licensee's corrective actions to address this new issue. ,

LER 50-302/95-025-01 will be closed and VIO 50-302/95-21-03 remains open l

1 to follow licensee corrective actions to address the original issue i

!- involving the improper isolation of Class IE from Non Class IE i

'

J electrical circuitry for the reactor building purge valves. l

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c. Conclusions -

.

e

The inspector concluded that the licensee had completed some of the j

, specified corrective actions to address this item, including the

evaluation of alternatives to the non-isolated design of the control  ;

l

circuits for reactor building Purge Valves AHV-1A and AHV-1D. However. l

the. licensee did not supplement LER 50-302/95-025-01 or VIO 50-302/95- j

21-03 by December 20, 1996, as was stated in the previous responses to i

the LER and VIO. The licensee's handling of these LER and VIO -

supplements demonstrated a weakness in the licensee's commitment

tracking process which was identified as an unresolved item.

The inspector assessed the licensee's performance, with respect to this

issue, in the five areas of continuing NRC concern:

. Management Oversight - Adequate

• - Engineering Effectiveness - Adequate 1

-* Knowledge of the Design Basis'- N/A

e Compliance with Regulations - Adequate

e Operator. Performance - N/A

IVm Plant Sucoort ,

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R1- Radiological Protection and Chemistry (RP&C) Controls

R1.1 General Comments (71750) j

i

The inspectors conducted routine tours of the licensee's radiologically

controlled areas (RCA) and verified radiological controls such as

control of locked areas, surveys and postings, and access controls.

Daily shutdown chemistry results were reviewed during normal work days.

No )roblems were noted in these areas. Radiation areas were clearly

marced and controlled.

The inspectors observed that daily priority is placed on tracking of

radiological exposure against outage goals. The licensee has been

. refining their goals and predictions and results were significantly 1

improved. The inspectors also noted that Health Physics management 4

responded strongly and a)propriately to an incident where food wrappers l

were found in the RCA. ianagement expectations and intolerance for

,

future' incidents were clearly communicated. ,

The inspector reviewed the licensee's "HP Self-Assessment - Corrective

l- Action Plans (CRSA 97-01/HP 97-1)" completed on February 28, 1997, which l

is discussed further in Section 07.1. Although the inspectors

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32

identified some documentation deficiencies, no deficiencies were found

with the licensee's assessment. findings and response plan. The

inspectors did not identify any deficiencies in the areas of  ;

,

radiological controls or chemistry.

P1 Conduct of EP Activities

Pl.1 Emeraency Preoaredness Drill

a. Insoection Scone (71750)

The inspectors reviewed the results of an off-hours staffing drill

conducted on April 24. observed a quarterly drill conducted on May 1.

and discussed pending changes with licensee Emergency Preparedness j

personnel,

b. Observations and Findinas

The licensee performed the unannounced, off-hours staffing drill of the

Technical Support Center (TSC) and Emergency Offsite Facility (EOF) at

7:33 p.m. on April 24. The licensee required individuals to respond to

the site to assess the time needed to activate the facilities with an

adequate staff against the 60 minute requirement. The TSC and EOF were

operational yithin 49 and 37 minutes, respectively. The inspector l

!

reviewed the results. confirmed the response was satisfactory, and )

concluded it was a valid and proactive test of the ability to respond to

an actual event.

The licensee has also revised their normal event drill schedule to

increase the frequency of drills to quarterly and include a full TSC

activation which will include use of the control room simulator. The

l inspectors observed the first of these drills on May 1 at both the

simulator and the TSC. The inspectors noted that the overall drill went

well, efficient manning and use of the TSC was demonstrated good

command and control and formal three-way communication between operators

was evident at the simulator, and a self-critical post-drill critique

was done immediately following the drill. The ability of the operating

,

crew in the simulator to establish an accurate steam generator tube leak

'

rate for the scenario using only plant parameters was considered a

example of good o)erator performance. The inspectors did note two

l deficiencies at tle TSC. Two phone lines shared by the TSC with other

organizations did not function during the drill because the other

i

organizations had relocated the phone lines and the loss of the TSC

l phone line was not recognized. The licensee was correcting the problem.

l The other deficiency was the lack of a plant status board in the TSC to

!

indicate basic plant parameters. The inspectors noted that several TSC

staff members had to ask the Emergency Director basic plant status

questions such as the condition of reactor coolant system (RCS) letdown

and the time since subtriticality of the core was obtained. These

parameters would be readily apparent if a status board was used. The

licensee was considering adding a status board along with many other

ponding TSC equipment and layout changes.

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c. Conclusion

The inspectors concluded emergency preparedness activities were

performed well. Only minor deficiencf " were observed.

S2 Status of Security Facilities and Equipment

S2.1 Loss of Power to Central Alarm Station Eauioment

a. Insnection Scone (71750)

The inspectors reviewed the following procedures:

• SS-201. Revision 29. Security Force Personnel General Orders.

Duties, and Responsibilities

. SS-300. Revision 24. Security Equipment Testing. Calibration.

Inspection, and Maintenance

The inspectors also reviewed the security logs and Security Information

Reports related to the event (s). Several security officers,

supervisors managers, and electrical maintenance and engineering

personnel were interviewed to aid in understanding the sequence of

events and the setup of equipment.

l b. Observations and Findinas

At approximately 14:48 on April 17 power was unexpectedly lost to the

central alarm station (CAS) workstations and an intelligent multiplexer

(IMUX-2) due to some troubleshooting being performed on vital bus

transformer VBTR-4C. An uninterru)tible power supply (UPS) is utilized

in the system to assist in a smoot1 transfer of power from one source to

another (i .e. , inverter to transformer, or inverter to inverter). The

UPS is not an alternate source of )ower for the CAS workstation. The

loss of power occurred when the 5BR breaker on VBTR-4C was closed and

the UPS sensed a loss of voltage while the transfer switch " lined-up"

the voltages from the transformer and inverter before completing the i

switch. This "line-up" takes only a fraction of a second but did not '

occur fast enough to 3revent the loss of the CAS workstation & IMUX.

Also at this Joint, tie UPS transferred to its backup supply (i.e.

batteries) tius repowering the CAS workstations and IMUX-2. However,

it was unbeknownst to anyone that the UPS continued to run on its l

battery supply.

.

l At approximately 18:03 on A]ril 17. power was again lost to the CAS

l workstations and IMUX-2. T11s time there was not any maintenance

! activity ongoing that could have contributed to the power loss. Upon

investigation by electrical maintenance personnel (19:11) it was

discovered that the UPS had powered itself down after running out the i

batteries. After the first power loss. the UPS had failed to auto 1

transfer to its normal ]ower, thereby running on batteries for about

three hours. When the JPS was reset, power was immediately restored to

the CAS workstations and IMUX-2.

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At approximately 22:10 on April 17. power was lost to the CAS

workstations & IMUX-2 for a third time. Again, there was.not any

maintenance activity ongoing that could have contributed to the power

loss. The UPS was reset by security personnel and power was restored.

It was not clear what occurred to cause the UPS to trip a third time.

Security declared a " security alert" during the first and second power

losses. This required the establishment of extra roving and posting of

officers within a prescribed time period. During the third power loss,

since security had already gone through two other power losses, they

knew what to do (reset UPS), therefore no security alert was declared.

Security wrote PC 97-2708 to docament the first power lost. This PC was

assigned a " grade of C" which means an apparent cause evaluation is

necessary. The apparent cause evaluation is due after the end of this

inspection period. Security had not requested any other assistance from i

engineering until questioned by the inspector.

c. Conclusions i

Engineering continues to evaluate the purpose of the UPS in the system  ;

and will determine whether it needs to be replaced or removed. The

ins)ectors will further review the issues and events surrounding this

pro)lem to determine if appropriate corrective actions are taken to

prevent recurrence. The inspectors concluded the loss of power to the

equipment revealed a security staff lack of familiarity with the

operation and function of their installed equipment. Security ,

management also did not appropriately prioritize the issue and obtain

adequate timely resolution from other departments, so final resolution

of the problem is still pending.

..

S2.2 Security Comouter Ooeratina System Run-Time Exoiration (71750)

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On April 25. Security was notified by the Information Technology group, who l

received the information from a manufacturer (Digital Equipment Corporation). i

warning that the VAX security computer operating system was designed and

installed with a run-time library that only allows a four digit entry (i.e..

9999 days). Since the system was installed in 1970, the 9999 days are running

out (May 19, 1997, was the run-out date) and the potential exists for the <

system to shutdown when this time expires. Security wrote Precursor Card 97-

2035 to document the problem.

)

,

The vendor. Sysica, will supply a " patch" to prevent an interruption in the

I run-time library logic. The " patch" will be installed and tested on a j

i different computer before installation on the security com) uter. DEC has  ;

t

notified other VAX users of this problem and the licensee las contacted three i

other utilities which have similar systems (BG&E. Duane Arnold. & Pilgrim).  !

-

The licensing department has determined that the problem is not reportable

under 10 CFR Part 50.9(b) or 10 CFR Part 21. The reason for not reporting

this information is that security is not encompassed by Part 21 requirements

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and the manufacturer was the one to identify the problem. The inspectors  :

l reviewed 10:CFR Part 21 and agree that the issue is not. reportable.  !

.I

l L. Manaoement Meetinas -

X1 Exit Meeting Summary

l

!. The inspection scope and findings.were summarized on April 4. April 18,

A3ril 25 and May 5,1997. Proprietary information is not contained in i

L t11s report. Dissenting comments were not received from the licensee.  :

PARTIAL LIST OF PERSONS CONTACTED

,

,

Lic_ensees

]

.

' R. Anderson. Senior Vice President, Nuclear Operations l

J.-Baumstark, Director. Quality Programs j

-J. Campbell, Assistant Plant Director, Maintenance and Radiation Protection '

J. Cowan, Vice President, Nuclear Production

R. Davis,. Assistant Plant Director, Operations and Chemistry- i

B. Gutherman. Manager. Nuclear Licensing i

G. Halnon, Assistant Plant Director. Nuclear Safety  ;

B. Hickle Director, Nuclear Plant Operations )

J. Holden. Director, Nuclear Engineering and Projects  !

D. Kunsemiller, Director Nuclear Operations Site Support

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S. Elde NRC Contractor, Region II (March 31 through April 4,1997) .

!

P. Fillion, Reactor Inspector, Region II (March 31- through April 4,1997).  !

K. Landis,' Branch Chief. Region II-(April 10 through 11. 1997) i

L. Mellen Project Engineer, Region II (April 14 through 18, 1997) {

W. Rogers. Senior Reactor Analyst, Region II (March 31 through April 4.1997) i

R. Schin, Reactor Inspector, Region II (Aaril 14 through 18, 1997) -'

M. Thomas. . Reactor Inspector, Region II (iarch 31 through April 4.1997. April

21 through 25. 1997) ]

S. Wong, NRC Contractor, Region II (March 31 through April 4,1997)

!

INSPECTION PROCEDURES USED l

1

IP 37750 Engineering

IP 37551: Onsite Engineering '

IP 40500: Effectiveness of Licensee Controls in Identifying, Resolvirg and

Preventing Problems

IP 61726: Surveillance Observations

IP 62707: Conduct of Maintenance

IP 71707: Plant Operations-

IP 71750: Plant Support Activities

IP 90712: In Office Review of Written Reports

! IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power

!

Reactor Facilities <

l IP 92901: Followup - Operations i

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IP 92902: Followup - Maintenance

IP 92903: Followup - Engineering

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

lypg Item Number Status Descriotion and Reference

VIO 50-302/97-05-01 Open Failure to Follow Equipment Tagging

Control Procedural Requirements.

(paragraph 01.2)

URI 50-302/97-05-02 Open 50.59 Safety Evaluation does not .

Address Operation of the Atmospheric

Dump Valves from the Remote Shutdown

Panel During an A)pendix R Fire

Event. (paragrap1 E8.6)

VIO 50-302/97-05-03 Open Incorrect Information in Annunciator

Response Procedure for Inverters. i

(paragraph E8.7) '

URI 50-302/97-05-04 Open L S and Violation not Supplemented

by Date Stated in Licensee  ;

Responses. (paragraph E8.9) l

Closed

ly.gg Item Number Status Descriotion and Reference

URI 50-302/97-01-06 Closed HPI System Design. Licensing Basis,

and TS Concerns. (paragraph E8.1)

LER 50-302/95-013-01 Closed Design Deficiency May Cause Makeup

Tank Vortexing Resulting in Failure

to Meet A)pendix R Requirements.

(paragrapa E8.3)

l

IFI 50-302/95-15-03 Closed Design Requirements for Reactor

Coolant Pump Motor Cooler Failure.

(paragraph E8.4)

LER 50-302/96-002-00 Closed Personnel Errors by Engineering

Result in Operation Outside Design

Basis Due to Inadequate Safety /Non-

Safety Circuit Isolation.

(paragraph E8.5)

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IFI 50-302/96-201-16 Closed Coordination of Second Level I

'

Undervoltage Relay (SLUR) Setting VS

Inverter Operation. (paragraph

E8.7)  ;

LER 50-302/95-025-01 Closed Personnel Errors by Architect

Engineer Result in Operation Outside .

Design Basis Due to Inadequate  !

Safety /Non-Safety Circuit Isolation.  !

(paragraph E8.8) -

'

Discussed

IY2e Item Number Status Descriotion and Reference

URI 50-302/95-02-02 Open Control Complex Habitability

Envelope Leakage. (paragraph E8.2)

VIO 50-302/95-21-03 Open Failure to Isolate the Class IE from  ;

the Non Class IE Electrical '

Circuitry for the Reactor Building

Purge and Mini-Purge Valves. .;

(paragraphs E8.5. E8.9)

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.

LIST OF ACRONYMS USED

'

ADV - Atmospheric Dump Valve

AI - Administrative Instruction

ANSS - Auxiliary Nuclear Shift Supervisor

AP - Abnormal Procedures

BSP - Building Spray Pump

CARB - Corrective Action Review Board

CAS - Central Alarm Station

CCHE - Control Complex Habitability Envelope

CFM - Cubic Feet per Minute

CFR - Code of Federal Regulations '

CN0 - Chief Nuclear Operator

CP - Compliance Procedure

CREVS - Control Room Emergency Ventilation System

CR3 - Crystal River Unit 3

DH - Decay Heat

DHP - Decay Heat Pump

DHV - Decay Heat Valve

DNPO - Director, Nuclear Plant Operations '

DP - Differential Pressure

ECCS - Emergency Core Cooling System

l ECO - Electronic Clearance Order

EDG - Emergency Diesel Generator

EFIC - Emergency Feedwater Initiation and Control

EFP - Emergency Feedwater Pump

l EFV - Emergency Feedwater Valve -

EFW - Emergency Feedwater

EOF - Emergency Offsite Facility

FLUR - First Level Undervoltage Relays

FPC - Florida Power Corporation

FSAR - Final Safety Analysis Report

FSP - Fire Service Pump

GL - Generic Letter

HEPA - High Efficiency Particulate Air

HPI - High Pressure Injection

HVAC - Heating Ventilation and Air Condition

ICRP - International Commission on Radiation Protection

IEEE - Institute of Electrical and Electronics Engineers

IFI - Inspection Followup Item

l IOC - Interoffice Correspondence

! IR - Inspection Repor:

11 5 - Improved Technical Specifications

Kw - Kilowatts

LCO - Limiting Condition for Operation

LER - Licensee Event Report

LOCA - Loss of Coolant Accident

LOOP - Loss of Offsite Power

LPI - Low Pressure Injection

MAR - Modification Approval Record

MUP - Make-up Pump

i MUV - Make-up Valve

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NCV - Non-cited Violation l

NOTES - Nuclear Operations Tracking and Expediting System I

NOV - Notice of Violation ,

NOA - Nuclear Quality Assessments

NRC - Nuclear Regulatory Commission

l NRR - Office of Nuclear Reactor Regulation

i NSCCC - Nuclear Services Closed Cycle Cooling System

NSM - Nuclear Shift Manager

NSS - Nuclear Shift Supervisor

01 - Operating Instruction

PC - Precursor Card

PM - Preventive Maintenance

!

PR - Problem Report

PRC - Plant Review Committee

l RAI - Request for Additional Information

RB - Reactor Building .

l RCA - Radiologically Controlled Area -

RCP - Reactor Coolant Pump

RCS - Reactor Coolant System

RP&C - Radiological Protection and Chemistry

l SB0 - Station Blackout

i SCR - Silicon Controlled Rectifier  ;

SFP - Spent Fuel Coolant Pump i

'

SLUR - Second Level Undervoltage Relays

l SM - Shift Manager  :

- Surveillance Procedure

'

SP

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SR - Surveillance Requirement

SR0 - Senior' Reactor Operator

SS0D - Shift Supervisor on Duty

STD - Standard

STI - Short Term Instruction

TC - Temporary Change

, TDBD - Topical Design Basis Document

l TIA - Task Interface Agreement

TS - Technical Specification

TSC - Technical Su) port Center

i UPS - Uninterrupti)le Power Supply

URI - Unresolved Item

VAC - Volts Alternating Current

VDC - Volts Direct Current

VIO - Violation

W.G. - Water Gauge

WI - Work Instructions

WR - Work Request

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