Text

Insp Repts 50-413/90-10 & 50-414/90-10 on 900322-26.No Violations Noted.Major Areas Inspected:Insp Charter Developed on 900321 & Available to Team
	ML20034B019
Person / Time
Site:	Catawba
Issue date:	04/13/1990
From:	Russell Gibbs; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML20034B016	List: ML20034B015; ML20034B019;
References
	50-413-90-10, 50-414-90-10, NUDOCS 9004250221
	Download: ML20034B019 (22)
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NUCLEAR RE ULATORY COMMISSION

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101 MARIETTA STREET.N.W.

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ATLANT A, GEORGI A 30323

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U. S. NUCLEAR ~ REGULATORY COMMISSION-

REGION II.

SPECIAL INSPECTION TEAM

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. Report Nos.:

50-413/90-10 and 50-414/90-10'

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Licensee:

Duke Power Company

422 South Church Street

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Charlotte, NC 28242

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~ Docket Nos. :

50-413 and 50-414

License-Nos.:

NPF-35 and NPF-52

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Facility Name

Catawba l'and 2

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Inspection Conducted: March 22 - 26, 1990.

. Team ' Leader: ' :htm $ll4)

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.Ri Gibbs, Reactor Engineer

Dhte Signed

Team Members:

B.-Orders, Senior Resident, RII

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M.. Lesser, Resident Inspector, RII

C. Rapp, Reactor Engineer, RII

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Approved by:

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P. J. Kellogg', Section Chi [ef

Date Signed

Operational Programs Section

Operations Branch

Division of Reactor Safety

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TABLE OFfCONTENTS-

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INTRODUCTION - FORMATION AND INITIATION 0F THE INSPECTION _ TEAM.-

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!A.

Background ..

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Formation of the inspection' team

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Inspection team charter.

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._ Persons contacted are3-listed'in Appendix C

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Abbreviations and' acronyms are listed-in Appendix 0L

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SUMMARY OF THE MARCH 20,;1990 EVENT-

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' DETAILED SEQUENCE.OF EVENTS--

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IV. . DUKE- POWER COMPANY INITIAL RESPONSE 'f0 THE EVENT -

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Shift. Staffing

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Operators response to the event-

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EVALUATION OF DESIGN ASPECTS' CONTRIBUTING TO THE EVENT

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ENGINEERING EVALUATION OF THE EVENT

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Determination- of Reactor Coolant System (RCS)(NC)-'and Residual:.. Heat

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Removal (RHR) (ND) System pressures ~-

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. Calibration check .of RHR (ND)Jdischarge: pressure to the_ all points-

computer

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C.

EngineeH ng Evaluation of overpressurized components;

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D.

RHR (ND) high discharge' pressure annunciator'

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Scheduling Mechanisms-

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- Power Operated Relief Valve (PORV) Surveillances

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- Modification of RHR (ND) suction valve logic

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.VII.

EVENT REPORTABILITY

VIII.

ROOT CAUSE DETERMINATION-

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EXIT INTERVIEW

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. APPENDIX A: DETAILED SEQUENCE OF EVENTS

. APPENDIX B: PRESSURE CURVE

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APPENDIX C: PERSONS CONTACTED

APPENDIX D:-ACRONYMS AND ABBREVIATIONS

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REPORT DETAILS

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'I. ' INTRODUCTION - FORMATION AND INITIATION 0F THE INSFECTION TEAM -

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Background

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Catawba Unit 1 is a-Westinghouse-design four loop pressurized water

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reactor.

TheLUnit is - located :sixL miles nortSwest lof Rock Hill,

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South . Carolina in' Yo'rk : County. 'Initia~1 'criticalityt was . achieved on'

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- January 7,1985, and commercial . operation- began June 29,l1985.1

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On March 20s 1990, at'approximatelyL11:30 p.m.,~the-licensee reported

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a Unit l' Catawba Nuclear Station ' overpressure - event. :to L the NRC.

During-the morning of March 21, 1990,- several discussions concerning

the event were held- between the Resident and Regional staff. <Thesei

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discussions were concluded.during the afternoon of March 21, 1990,nby

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a conference call including the licensee, Nuclear' Reactor Regulation,

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(NRR), Office of Analysis and= Evaluation of 0perational' Data.(AEOD),-

the Catawba resident inspector and ' other membersg ofs.the- NRC. Region

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Il staff.

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Formation of_ the inspection team

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During the morning of Marche 21',- -- 199 0, _ the Regional- Administrator,

af ter. briefings by the Resident -and' Regional staff and consultation

with senior NRC. management, directed the dispatch of a speciall

inspection team to the Catawba site. The team traveled during .the

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afternoon and evening of March 21, 1990,'and: began the-review of the=

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event early on the morning of March 22', 1990.

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Special Inspection Team Charter

The inspection charter was developed on - March - 21, 1990, .and was

available to the team when they arrived on sighti on March 22, 1990.

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The charter specified that the following-tasks be' accomplished:

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1.

Develop and validate a detailed sequence of events associated

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with the. overpressurization of the Residual Heat _ Removal

System.

Identify any human factor / procedural deficiencies

related to the event.

2.

Evaluate operations -involvement in system lineup prior to

commencing fill and vent of -the Reactor Coolant System.

3.

Validate the licensee's analysis of pressures and temperatures

that the RCS (NC) and- RHR- (ND) systems experienced during this

transient.

4.

Evaluate the possible design aspects which could have contributed

to this event.

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Evaluate reportability of the' event.

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Prepare; a special inspection report documenting, the results of

the above activities by April- 13, 1990.

D.

Persons contacted are listed in ~ Appendix C.

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-Abbreviatiens and Acronyms used ini this._ report. are : listedb n.

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appendix D.

II. - SUMMARY OF THE MARCH 20, 1990 EVENT

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On March 19,. 1990,-' the - licensee; commenced filling'. of' the RCS -'(NC)

following a refueling outage. By'7:08 a.m. on March 20, 1990,- theLfollowing

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plant conditions-exist:

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PORVs are:open-

Reactor Head vents are closed

Train "A" of RHR (ND) is in service-

RCS . (NC) system and the Pressurizer are filled and' .not yet

completely Vented

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One charging pump is running

Letdown to the RHR (ND) system is established-

At 7:08 a.m. the final _ steps to bring;up-RCS (NC) pressure are taken,-which

include closing - the PORVs .and__ selecting of the : Low Temperature Over-

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Pressure Protection Mode (LTOP.) for the PORVs. At 7:24 a.m. charging-flow-

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1s established at 100 gpm and letdown flow is at 50 gpm.to raise pressure

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in the RCS (NC).

At this time the operators are monitoring; plant'

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pressure by two wide range RCS (NC) gauges and'a. low: range RCS-(NC) gauge.

The operators are unaware, at this time, that the root . valves to- the'

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transmitters, which provide pressure signals to these.. gauges, are -

isolated. RCS (NC) pressure begins to increase withoute any indication on

these pressure gauges.

Pressure continues to rise jnd peaks:at 455 psig

between 9:36 a.m. and 9:42 a.m.

Also, RHR-(ND)' discharge , pressure peaks at-

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625 psig and RHR (ND) suction pressure reaches RCS (NC) . pressure, which

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causes the

"B" Train RHR (ND) suction relief valve to relieve to the

Pressure Relief Tank (PRT).

At 9:45 a.m. the -. operators ' notice that .PRT

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level is increasing rapidly,. which is abnormal.

They reduce ' charging .

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flow to 95 gpm, notify supervision and begin to look for the source of the

PRT level increase. Thinking 'that the source; of the PRT levellincrease

is from a leaking PORV, the operators isolate each of the PORVs one at. a

time to determine which one is leaking.

This action- does not result in

isolating the leakege to the PRT.

Between 9:51 a.m.

and 9:57 a.m. - the

operators notice that pressure-in the

"A" train RHR (ND) dischargeLis 375

psig and realize, based on experience, that RCS (NC) pressure'is about

175 psig. An cperator in containment is ordered- to investigate the RHR

(ND) suction relief valves. At 9:57 a.m. letdown flow- is increased from

60 gpm to 120 gpm in order to lower pressurizer level to an on scale

reading and to facilitate opening of the FORVs. At 10:08 a.m. the operator

in containment reports that the "B" train RHR (ND) relief valve is passing

flow and control room operators isolate "B" train RHR (ND) by closing the

suction valve.

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Licensee investigation determines the cause of the problem to be'that the

root valves to the pressure transmitters, which provide pressure signals

to the control room gauges and LTOP, are isolated. .The-licensee enters

the eight hour Limiting Condition for 0peration (LCO) .for inoperable PORVs

per Technical Specification (TS) 3.4'.9.3 at 10:30 a.m.

At Approximately .

11:15 a.m. the "B" RHR (ND) suction valve is. realigned opened to the _RCS

(NC) and reseating of the RHR (ND) suction relief valve. is' verified.

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At 1:45 p.m. the PORVs are opened ventingL the RCS (NC). At approximately

2:20 p.m. the pressure instruments are unisolated and the PORVs are 6clared

operable. The licensee ' notified the NRC of the event at approximately

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11:30 p.m. that day.

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III. DETAILEO SEQUENCE OF EVENTS

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The sequence of . events was developed from 'di scussions . with - licensee-

personnel, review of the plant all . points data computer' and review of

operating logs and procedures.

The detailed sequence of events is provided

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in Appendix A.

IV. DUKE POWER COMPANY INITIAL RESPONSE TO'THE EVENT

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A.

Shift Staffing

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Each unit has one SR0 licensed operator, a Unit Supervisor (US) and

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two R0 licensed operators, Cor, trol Room Operators (CRO).

The US is

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responsible for coordinating unit operation with other plant

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organizations.

During this event, the US was outside . the control

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room assisting with Retctor Protection System (RPS) Motor-Generator

(MG) maintenance. The US is not required by Technical Specifications

for shift manning. The two CR0s were' responsible-for conducting the

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evolution and assisting with any testing at.tivities.

A senior SRO,

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Shif t Supervisor (SS), and a Control Room SR0 (CRSRO), are over both

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units. The CRSR0 assists the SS with administrative duties such as

maintaining the Technical Specification Action item Log (TSAIL).

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The CRSR0 inust be in the control room and is responsible for command

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and control.

B.

Evaluation of Operator Response to the Event

Af ter the Pressurizer had been filled and the PORVs closed, the

operators aligned RHR (ND) and CVCS (NV) to pressurize the RCS (NC)

system.

Based on previous experience, the operators assumed this

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pressurization would take four to five hours. The previous shift had

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vented the upper head for about three hours.

This is greater than the

one hour vent done on previous refueling outages.

The additional

venting was a result of a procedure interpretation.

The procedure

states to vent the upper head until a solid stream of water is

observed in the sightglass.

The previous shift interpreted this to

mean no air bubbles and continued venting until no air was detected.

This venting was discussed during shift turnover, but the operators

did not consider this to affect the time required for the

pressurization.

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The operators dependance on past experience and fai_ lure to consider

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this additional- venting resulted in a f ailure to' recognize ~ that the

. pressurization of the RCS (NC) would take a much shorter' time than

previously experienced.

Several other activities were in progress during this evolution; RPS

response time- testing, Main Feedwater (CF) pump 1A turbine overspeed

testing, calibration of the RCS '(NC) _ pump seal dp; transmitters, and-

valve stroke time testing of the Chemical and Volume Control (CVCS)-

(NV) system Eletdown Isolation valves.

The- operators were also

monitoring Pressurizer Relief Tank (PRT) level because the previo~ s

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shift had experienced several _ Reactor Coolant Drain Tank- (RCDT)-

(NCDT) pump trips while. reducing PRT level.

These activities diverted-

the operators attention from the pressurization. The operators were

too -involved with other -activities. to pr'operly monitor RCS (NC)

system pressure during the RCS (NV) fill, vent- and pressurization

evolution. ' This is an area of weakness and is identified as IFI

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50-413/90-10-01.

At about 9:45 a.m. , the operators observed a rapid increase in PRT

level.

The operators took several -actions to identify the source of

the problem, and, once the overpressure condition was identified, to

reduce system pressure:

First, the. operators ' assumed it was' a

problem with the~ PRT. level reduction and verified system alignment.

When it was determined system alignment was correct, the _ operators

individually closed the PORV block valves to determine if a PORV was

leaking.

When PRT level continued to ' increase, _ the_ block _ valves

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were reopened.

The Reactor Water Makeup-(RMW) pump was stopped to

check if leaking containment isolation valves were the cause, but

PRT level continued to' increase.

A - system engineer suggested a

leaking RHR '(ND) suction relief valve could be the cause of the PRT

level increase.

Two Auxiliary Operators inside containment were-

directed to check the RHR (ND) suction relief valves .for- flow and

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reported flow from the train "B" RHR (ND) suction ~ relief valve.

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Because the RHR (ND) pump. produces 200 psid and train "A" RHR (ND)-

pump discharge pressure indicated 375 psig, RCS (NC) system pressure

was initially thought to be 175 psig.

Since the RHR (ND) suction

relief valves have a cold set pressure -of 465 psig, the operators

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assumed the train

"B" RHR (ND) suction relief was -leaking.

In

accordance with AP-19, Loss of Residual Heat Removal System '- Case

II, the suction isolation valves were closed to stop the loss of RCS

(NC) inventory.

The operators also reduced charging flow and

increased letdown to reduce RCS (NC) system pressure. An analysis of

train "A" RHR (ND) discharge pressure computer data indicated RCS

(NC) pressure could have reached 450 psig. All of the operators

actions during the initial few minutes of the event were reasonable

for the given conditions and were conducted in a timely fashion.

At this time, the operators also realized the Low Range RCS (NC)

pressure instrument should be on-scale.

The operators consulted

Instrumentation and Electronics (IAE) about the operability of _the

Low Range and Wide Range RCS (NC) pressure instrumentation and were

informed they had been isolated for maintenance.

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Because the Wide Range RCS (NC) pressure signal is used to actuate

the LTOP PORVs, the - operators declared the PORVs inoperable. :To

comply with Technical Specification 3.4.9.3 action statement,- ther

operators _ drained the Pressurizer to 97 percent and opened the PORVs.

During operator interviews, the operators stated the Wide-Range RCS

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(NC) pressure-instruments normally indicate a static head: pressure of-

about-30 psig when performing the fill and vent evolution. The Wide

Range RCS (NC) pressure instruments indicated about. 3 psig : during

this event.

The operators attributed this differencer to_ instrument -

accuracy and did not question the= operability of the-Wide Range' RCS

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(NC) pressure instruments.

During the pressurization, the operators actions were controlled by

the mindset this evolution would require four to five hours, and-the.

exclusive monitoring of Wide Range RCS (NC) system pressure. Other

indications were available to the operators including CVCS (NV)'.

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Letdown pressure and flow, and train

"A" RHR -(ND) discharge pressure,

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Neither of these instruments were monitored until af ter the RHR -(ND){

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suction relief valve lif ted. Computer trend data showed. substantial

increases in these parameters prior . to the relief )if ting.

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operators failed to monitor RCS (NC) system pressure with diverse

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instrumentation and focused attention- se',;iy on Wide Range' RCS (NC)

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pressure.

The draining of the Pressurizer as a part of recovery was compounded

by malfunctioning of .the RCS (NC) pump seal flow controller.

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controller would not automatically maintain proper seal flow.

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seal flow to maintain proper seal injection.

This ~ hindered ' the

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operators ability to quickly reduce pressurizer level and open the

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PORVs.

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The operators may have more quickly recognized the pressure increase

had RCS (NC) pump seal dp and train "B" RHR (ND) discharge pressure;

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instrumentation been available.

The train "B" RHR (ND) pump discharge

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pressure meter had been isolated for maintenance and was not available.

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The RCS (NC) pump seal dp would have indicated an increased' dp

between charging pressure and RCS (NC) system pressure. _ Train

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RHR (ND) discharge pressure would have indicated-the suction relief

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was not failed but had opened due to actual high RCS (NC) pressure.

Additionally, the train "A" High Discharge Pressure alarm did not

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actuate which would have provided another indication of RCS (NC)

pressure increase (see paragraph VI.D for additional discussion. of

this item).

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V.

EVALUATION OF DESIGN ASPECTS CONTRIBUTING TO THE EVENT

The inspection team did not identify any design deficiencies which

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contributed to the event.

However, several design deficiencies were

identified in recovery from the event.

These issues are discussed in

paragraph VI.G of this report.

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VI. ENGINEERING EVALVATION OF THE EVENT

A.

Determination of Reactor Coolant System and Residual Heat Removal

System pressures

The licensee used the all points data computer to investigate the

transient and determine the pressures, which were ~placed on the RC

(NC) and RHR (ND)' systems. The pressure analysis was derived by two

separate sets of - calculations and, therefore, provided redundant -

confirmation of _the - actual pressures experienced by the systems.

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The methods used were- ban.d on RHR (ND) discharge pressure computer

data, and PRT level increase computer data:

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RHR (ND) discharge pressure: - The first approach used- the computer

data which originated from the."A". train RHR (ND) discharge pressure

transmitter.

The signal from this transmitter provides pressure inputs

to the computer, the control room "A" train RHR (ND) discharge

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pressure gauge, and the high RHR (ND) discharge pressure annunciator

in the control room. The signal to the computer is read out and

recorded at five minute intervals. By calling up this data'after-the.

event the licensee was able to obtain a plot of RHR'(ND) pressure at

five minute intervals during the event (See Appendix- B). - Analysis

of this plot lead to the conclusion that the maximum pressure-during

the event occurred between 9:36 a.m., and 9:42 a'.m.

Review of the

curve, determined that the maximum pressure during the event could

have been greater than the pressure at- 9:36 a.m. -or 9:42 a.m. -(the

slope of the curve on the left hand side of the 9:36 a.m. data' point

is increasing, while the slope of the curve on the right of the-

9:42 a.m. data point is decreasing).

Licensee personnel, therefore,

utilized a french curve to extend these two curves .until they

intersected above either of the pressures, at a time of approximately-

9:38 a.m.

This approach is both reasonable and conservative.

This-

conclusion is based on the unlikely occurrence 'of' a severe pressure

spike during such a short time frame, and the fact that pressure

between the two points is higher than any of the pressures on either

side of the points or the points. themselves.

Reading from the

graph, then, lead to the conclusion that the maximum RHR (ND)

discharge -pressure during the event, based solely on computer data,

was 690 psig.

The 690 psig value was then . adjusted for the

calibration error in the computer input signal (see calibration

discussion in paragraph VI.B below) to reach the conclusion that the

maximum RHR (ND) discharge pressure had reached 625 psig.

The

licensee then calculated the RHR (ND) purrp differential' pressure (dp)

as 170 psig using the pump head curve at a flow rate of 3100 gpm (the

flow during the event). Subtracting the dp from the maximum adjusted

pressure resulted in a maximum RCS (NC) and RHR (ND) suction pressure

of 455 psig (625-170=455).

PRT level increase:

The second method of determining the system

pressures involved using the data obtained from the computer

concerning the PRT level increase during the event.

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The . computer data on level increase, knowledge of PRTssize, and PRT

pump down rate were used to calculate the flow rate into the PRT from

the RHR (ND) relief valve. This calculation resulted'in a flow rate

through the relief valve of 152.5 gpm. The technical data on the

-relief valve includes a maximum flow through the rehef valve (full

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open) of 900 gpm.at a pressure to fully'open of 495 psig. This data

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coupled with a flow of 152.5 gpm and use of linear interpolation

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results in' a RCS' (NC) and_ RHR (ND) suction pressure of 457.6' psig.

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(450+152.5/900x45=457.6).

This value ' compares to the; 455 psig

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redundant method-of pressure-determination.

A review of TS 3.4.9.1 by the . inspection team, with RCS (NC)-

pressure. and temperature at 455 psig and- 114 degrees f ahrenheit, .

respectively,- determined that the plant was well within -the

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pressure / temperature limits required by this'TS.

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B.

Calibration check of RHR (ND) discharge pressure- to th'e = all points

computer

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On the evening of the event and during the early morning hours of

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the next day the _ licensee performed a calibration' check _ of the "A"

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train RHR (ND) pressure transmitter and the circuitry to the control

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room gauges, high pressure annunciator, and the computer = input. This

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check determined that all equipment was functioning properly with

the exception of the signal to the computer.

The- data obtained

during the check of the-computer was as follows:

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Desired

As found

Allowable range

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psig

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(input)

(computer

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reading)

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-7.0 to 7.0

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175

197.0

168 to 182

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350

394.1

343 to 357

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525

590.8

518 to 532

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700

693 to 707

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- Computer readout off scale high.

Review of this data lead to the conclusion that the computer read

out higher pressures during the transient than had actually been

experienced. Also, the calibration check had verified the accuracy

of the other components in the circuitry, and the transmitter

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itself, and therefore, the problem was in the interface between the

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pressure signal and the computer itself.

Review of the above data

shows, that at the value of 525 psig desired, the computer read

65 psig higher than actual pressure (590.8-525=65).

Therefore, the

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licensee subtracted 65 psig from the 690 psig, determined in the RHR

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(ND) discharge pressure calculation above, to conclude that RHR (ND)

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maximum discharge pressure during the event was 625 psig.

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It should be noted that the 65 psig is . a conservative. estimate.

This is due to the fact that the differences between the " desired

readings" and the "as Found" readings are increasing -in a _ linear

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fashion, and in the pressure ~ range of_the transient (approx 625 psig)

the difference between actual system pressure and the computer read

out would be even. higher than 65 psig.

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C.

Engineering Evaluation of overpresturized components

Based' on a maximum _ RHR (ND) discharge pressure during the event of

625 psig,. the licensee concluded that the discharge. piping and

components had been pressurized above the system design pressure of

600 psig.

As

a. result,.an engineering analysis of all pipe,

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fittings, valves, instrumentation - and mechanical components was

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performed to very operability.

The inspection team reviewed. the

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overall analysis and a sample of the specific affected components to

determine the extent of the analysis. The analysis was thorough and

technically valid. Pipe, fittings, valves, and mechanical components

were reviewed against hydrostatic test pressures . placed on the'

equipment during the construction phase, and in all cases hydrostatic

pressures exceeded 625 psig.

Instrumentation was reviewed ~ against

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the safe working pressures specified by the applicable vendors. The

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inspection team and the licensee concluded that no. components were

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damaged during the event.

The licensee does, however, plan.to do

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calibration checks of instrumentation to verify their accuracy prior -

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to taking the unit critical.

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RHR (ND) high discharge ' pressure annunciator

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During the investigation it was noted that one piece of data did not

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correlate with' the transient scenario outlined above.

If'the

"A"

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train RHR (ND) discharge pressure reached 625 psig, the RHR (ND)

high pressure annunciator (set to alarm at 579 psig) should _ have

alarmed during the event. Review of the alarms in the computer data

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base during the event, and discussions with the on shift operatorr

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concluded that this alarm did not sound during the event.

The set

point of the alarm was verified correct during the calibration check

of equipment on the night of the event (see paragraph V.b above).

This

irregularity could not be explained by the licensee prior to the

I

inspection exit.

Investigation of_ this . issue by the licensee is

continuing. This issue will be the subject of a future inspection at

!

Catawba and is identified as Unresolved Item 50-413/90-10-02.

3

E.

Scheduling Mechanisms

i

The licensee had experienced leaks at the compression fittings of

high pressure instrument tubing penetrating containment and initiated

modifications to replace all compression fittings with socket weld

_

'

joints. Work Request 1493 MES was written for the instrument tubing

associated with Reactor Coolant Loop three Hot Leg Wide Range

Pressure (1NCPT5140) and Reactor Coolant Loop three Hot Leg Low Range

i

Pressure (INCPT5142).

i

A

. _ .

.

..

.

-

.

-. '

.

'

9-

Work Request 5941 IAE was written.fo'r tubing associated with-Reactor

Coolant Loop.two Hot Leg Wide. Range Pressure (INCPT5120).

The. licensee's overall

program for tracking,

scheduling and

maintaining work activities during refueling outages _is described in

Integrated Scheduling Procedure 3.3, Unit Mode Change Requirements,

and includes the.use of three computer programs; Nuclear Maintenance

Data Base (NMDB), Tech Spec - Action' Item: Log (TSAIL) and Project /2.

'

NMDB is 'used to provide a historical record of. completed work

requests > and can be . accessed to obtain the status of outstanding

"

work requests. TSAIL is' used primarily by Operation's .to track- TS

equipment that i s ' i noperable , hcwever TSAIL is not, used to track

.

work activities associated with equipment-during outages. Operations

'

relies on input from Integrated Scheduling (IS)- to perform this

-

function.

Project /2 is used by IS during refueling outages to

schedule windows for the large volume of work activities. A window

is established when .IS forwards an Operations Outage Information

Request Sheet-to Operations to determine plant conditions necessary

1.

to- begin work and . plant conditions / mode changes prior to which the

l

activity must be completed. Once this determination is made, the work

j

is entered into Project /2 as an " activity".

In. this case the

activities to modify the instrument tubing were ertered into Project /2

with requirements to be completed prior to' setting the reactor vessel

}

~

head, replacement of a pressurizer code: safety (vent path) and prior

,

to RCS (NC) System fill and vent.

Any support work for the activity involving other groups is performed-

l

under a supplemental work request.

Examples might include interference

l

removal or disconnecting' motor leads.

In this case root valve

j

isolation and restoration was to be performed by IAE under supplemental

l

work requests 1491 MES-1 and 5491 IAE-2. Supporting or supplemental

work requests are listed in Project /2 as " notes" under the main

i

activity and are not spec'ifically scheduled as " activities".

On February 7,1990, the instruments' root valves were isolated. On

!

February 21, the socket welding work was completed and this inform--

!

ation forwarded to IS. IS updated Project /2 to show the welding as

4

complete. The program logic is such-that any " notes" associated with

3

an " activity" are not specifically scheduled and therefore the notes

i

are also removed from Project /2 when the main activity is completed.

!

In this case the work requests associated with restoring the root'

)

valves were removed from Project /2.

Herein lies' one programmatic

j

weakness with the scheduling and tracking program.

Since supplemental

work requests are not scheduled by Project /2 another mechanism is

necessary to determine when the supplemental work request is to be

completed.

l

The licensee's program, as outlined in IS Procedure 3.3 requires

i

that during the outage, searches are performed in NMDB for

l

outstanding work requests for determination of when the item is to

4

be completed.

,

!

)

l

.

l

]

_

.L

.-

,

'

- 10 '-

Lists are compiled and forwarded to responsible groups to make the.

-

determination, however~ this requirement ' only applies. to work needed

-

to be complete prior to entering modes 4, 3, 2, and!1.

.

"

There ire no programmatic. requirements for:IS to_ identify outstanding;

work requirements to be completed prior to modes 6, 5 or for plant,~

- 1

condition changes within. modes 6 and 5.

Nevertheless, IS members have historically performed informal searches-

through NMDB and compiled lists of work requests needed for ' selected

~

plant condition changes ~ such as mid-loop operations or refueling

activities. NMDB and Project /2 however-have never been set'up.to be

able to sort outstanding work requests based on all' plant . condition

changes.

Therefore there is no mechanism currently available .for-

the licensee to easily track all items which must be completed prior

_"

to changing a plant condition within mode 5 and 6.

In this case- the isolation 1 and restoration work requests were

identified by searches through NMDB and ine.orrectly determined -as -

required by mode

4.

This was done in spite of direction' from

-

Operations that the system was needed- prior to setting the reactor -

head.

The reason for this can be summarized by the following

,

weaknesses with the licensee's programs.

Supplemental work requests are not scheduled by IS on Project /2

--

during outages.

Supplemental work requests are scheduled by _ searching and

--

sorting NMDB for outstanding work requests and identifying

whether they must be completed prior to mode 4, 3, 2, or 1.

~

There exists no mechanism to ensure outstanding work requests

are completed prior to plant condition changes or mode 5 and 6

changes other than informal searches conducted for certain

,

condition changes ( i.e, mid-loop operations).

--

Management controls failed to place adequate emphasis on

activities needed for safe operation in modes 5 and

6.

Personnel performing searches did not. have adequate guidance

and tools available to ensure work items were completed prior

to plant condition changes.

The need for this was recognized

by those personnel which accounts for the informal -searches

done for certain plant condition changes.

r

10 CFR 50 Appendix B Criterion XIV requires that measures

b+

established for indicating the operating status of safety-related

equipment.

In that the licensee's outage scheduling program is the

primary method of maintaining the operating status of plant equipment

during refueling outages and since the program failed to identify

outstanding work on the PORV's ( LTOP),

resulting in their

inoperability and f ailure to operate during the pressure transient

event of March 20, this is identified as an apparent violation.

L

.

C

.

1

'

11

F.

PORV Surveillances

TS 4.4.9.3.1 requires that an Analog Channel Operational- Test (ACOT)

be performed on the PORV's to demonstrate operability of the LTOP

feature of providing an overpressure lif t setting of- less than or

equal to 450 psig.

The surveillance is required within ' 31 days

prior to entering a condition in which the PORV's are required to be

,

operable and at least once per 31 days thereaf ter..-

Prior-to this

event the RCS (NC) System was vented' through open PORV's which were'

not ' required - to be operable until they were closed at 7.:08 a.m. on -

March 20,.1990,

i

The inspection team requested to see the results of the surveillances

done within the last 31 days.

The licenseef determined that the-

surveillances had not been' performed.

The inspectors determined that- the

failure Lto perform the

surveillances did not contribute to the event.

The ACOT verifies

operability of the channel by disconnecting the output f rom the

transmitter and applying

test

signals

into

the. instrument

electronics and verifying response.

Therefore the closed root

valves for the pressure transmitters would not have~ been detected

had the surveillance been properly performed.-

The failure to conduct the tests nevertheless exposed weaknesses in

the licensee's program for scheduling surveillances required for

certain plant conditions.

The surveillanceL scheduling program is

independent of the outage scheduling program. _This particular

surveillance is scheduled on a 31 day periodicity by a - computer

program.

Each period a' Standing Work Request (SWR) is issued by the

Maintenance Planning Department to the responsible group, _ IAE, who

then performs the test.

During refueling outages the tests are not

-

required by Technical Specifications, however,. Planning continues to,

issue the SWR, and IAE merely documents it as not required and forwards

the information back to Planning for entry into.NMDB.

In this case the SWR's were issued for each channel on various dates

in early March.

IAE engineers recognized the necessity to perform

the ACOT's for PORV operability prior to setting the reactor head.

IAE Technicians attempted the surveillances, however discovered the

reactor protection cabinets to 'be de-energized for unrelated work

and therefore could not perf orm them. IAE failed to follow-up and

conduct the surveillances when the cabinets were later powered up.

The root cause appeares to be an inadequate program to assure that

necessary survillances to support plant condition changes within a

mode are performed. The licensee has an adequate program to preform

surveillance prior to plant mode changes.

This is indicative of a

programmatic weakness and is identified as an apparent violation in

that the licensee failed to perform the required surveillances.

r

-

,

'

.

.;

_,

'

12

2

k

G.

Modification of RHR (ND) suction valve logic

When the aforementioned pressure transient:was recognized and it was-

realized that 1ND38B, the relief valve for the "B"1 train of the ~RHR

(ND) system was relieving to the PRT, operators closed valve'IND36B,

isolating the pump suction : from the C hot leg. When the-operators

attempted to re-open;1ND36B, it would not respond.

In the subsequent

investigation it was determined that the. electrical logic associated

with the valve's interlock had been modified during the refueling

outage in Juu a manner.as to prevent valve IND36B from being opened -

when power '1s removed..from valve - 1FW55B.

Valve 1FW55B is- the ND

suction. valve from the refueling water storage tank. ' Although this

modification changed the function of valve IND368,_ the Nuclear 15tation

j

Modification (NSM) process did .not adequately identify this fact to

o

the operations staff who is responsible for making required procedure

changes and performing the necessary training to facilitate operation

of the modified equipment.

To the contrary, the 50.59 evaluation

performed for the modification and presented to operations .in the

modification package stated that the valves would operate-identically

to the way they had previously, that all indications and interlocks

associated with valve operation, positions etc., would not be affected

by the changes and that no new failure modes.would be created ' as a

result of this modification.

This turned out not to be the case as

explained below.

The modification which altered the aforementioned interlock was

identified as CN-10942, and was implemented as a result . f findings

o

in IEB 85-03 "MOV Con: mon Mode Failures ~ During Plant Transients Due

,

to Improper Switch Settings",

Selected valve operators in a number of _ systems were modified to

resolve concerns for tnese valves - not attaining their desi red -

positions due to insufficient torque switch settings relative to the

resistance through the stroke travel.

'

The subject valve operators have " limit switch" actuated " torque.

bypass switch" contacts.

When the limit setting is reached,- the

.'

torque switch will trip the motor when high torque is1 measured

signifying valve abnormality.

Prior to the modification the valves

-

engaged the torque switch at a small value of open stroke position

(5 percent). This somet,.imes caused the Sotor to trip when the valve

was not fully unseated. To assure that these valves open fully, the

" torque bypass switch" was set to defeat the torque switch for an

opening stroke travel of 50 percent.

In general, these modifications were perforned by moving the torque

bypass leads for the motor-open (M/0) leg of the subject valves'

operators to a spare limit switch which was adjusted to 50 percent

travel.

However, on certain valves, including 1FW55B, the RHR (ND)

suction isolation valve for the "B" RHR (ND) pump from the refueling

water storage tank, a relay had to be added to extend contact

availability and thu.s facilitate the modification.

.

v

.

'

13

~

In this specific case, prior to the modification, the interlock

prevented opening IND36B if IFW55B _ was open.

Prior to the

modification, the interlock was provided from a set of contacts on' a.

position switch roto'r on valve 1FW558- and was independent of IFW55B

-

having electrical power available. -As a result of the modification,

the contacts, which now provide the interlock, function when the

j

aforementioned relay - energizes.

.This cccurs when IFW55B closes.

Resultantly, the modification makes the interlock' dependent not only

7

-on the position of 1FW55B but also on the relay having power

available. Tersely restated,. if 1FW55B has power removed, IND36B can

-

not be opened electrically, regardless of the position of IFW55B.

'

On the day of the event, the operators responded to the inability to

open IND36B by dispatching an operator to manually open the valve

which is located inside containment.

A number of concerns were -identified in the NRC's review of this

'

modification.

First, the.50.59 evaluation which was performed for the

modification was inadequate in that it provided inaccurate, 'and

misleading information to the operations staff personnel who are

required to review modification packages- to determine the' effect on

plant operating procedures.

They were misled into believing the

modification did not affect the function of the electrical interlock.

"

In fact, as discussed earlier, quite the contrary was stated in the

engineering analysis which supported 'and was attached to .the modifi-

cation package.

The modification summary (scope document) stated that

a relay had been added however it was not recognized by operations

that its power dependance would affect the interlock.

The licensee implemented station modification CN-10942 which

modified the interlock circuity between valves IND36B and 1FW55B

without prior Commission approval even though the modification

increased the probability of malfunction of the -affected ' valves by

making the position dependent ~ interlock also dependent on having -

electrical power available to valve 1FW55B.

This in effect

increased the probability of a malfunction by adding: an. additional

failure mode, loss of power of 1FW558.

This additional failure mode evidenced itself on March 20,1990,

while operators were attempting to recover from an RCS (NC)/RHR (ND)

pressure transient when valve IND36B could not be re-opened due to

valve 1FW55B not having power available.

These deficiencies are identified as apparent violations of NRC

requirements.

VII. EVENT REPORTABILITY

The team concluded that the March 20, 1990, event was a reportable event

under the requirements of 10 CFR 50.72. This conclusion is based on the

following:

~

.

r, :

,

w

.

e

10 CFR 50.72, subparagraph (b).(2).(iii).(D)

r' equi res that the-

'

licensee notify the NRC, as soon as practical, and in all cases

'

within four hours of the occurrence of any event or condition that.

alone.could have prevented the fulf111 ment of the_ safety function of-

structures or systems that are needed to' mitigate the consequences

1

of an accident.

The licensee failed to make a report within four hours following.the-

3

event that occurred on March 20, 1990. Note: The licensee did make

a courtesy. report approximately 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> after the event at

11:30 p.m.~on the day of the event.

The event involved the isolation;of the pressure transmitters that

provide safety _ signals to the~ Low Temperature Over Pressure

Protection System (LTOP). LTOP provides these signals to the Power

Operated Relief Valves and the RHR (ND) suction valves to control

the position of the valves during a low temperature overpressure-

transient.

The isolation of these signals prevented. the PORVs from performing

their intended safety function (opening, to prevent overpressure)

during the event, and would have prevented the 1 RHR- (ND) suction-

,

isolation valves from performing their intended safety function.

(closing on overpressure) had the pressure :in the RCS;(NC) reached

their set' point.

This deficiency is identified as an apparent violation of NRC

requirements.

VIII. ROOT CAUSE DETERMINATION

The root cause of the March 20, 1990, event was lack of management control

of the outage maintenance / modification process which resulted in

inadequate plant operating status.

IX. EXIT INTERVIEW

'

The preliminary findings of this special inspection were discussed on

March 24, 1990, with those persons indicated in Appendix C.

No dissenting

comments were received.

.

4

>

.

,.

-a-

_.-

,

^

APPENDIX A

L

February 7, 1990:

-Instrument root valves . for RCS (NC) Wide Range Pressure Instruments

INCP5120 and 1NCP5140 and RCS (NC) Low Range Pressure Instrument 1NCP5142

'

,

'

are isolated per Work Request 1493 MES-1 and 5491 1AE-1 for modification

work

February 21, 1990:

Modifications to replace compression fittings with, socket weld joints on

pressure instrument tubing completed

March 7, 1990:

1:22 p.m.

. Reactor vessel head set; _RCS (NC) vent path via steam

generator manway

i

March 12, 1990:

12:07 p.m.

Reactor Vessel head tensioned; Unit' entered' Mode 5

o

March 19, 1990:

'

On March 19, 1990, Unit I was in Mode 5 in a drained down condition. The

three PORV's and reactor head vents were open.

Train "A" RHR -(ND) pump was

operating removing decay heat and Train "B" RHR (ND) pump was in standby.

Both trains' loop suction isolation- valves were open with power removed.

At 1:00 p.m. fill and venting operations commenced using OP/1/A/6150/01,

1:00 p.m.

Commence fill of RCS (NC) system; RCS (NC) vent path via

open PORV's

3:00 p.m.

Centrifugal Charging Pump "1B" started to establish seal

injection and filling of RCS (NC) system

10:00 p.m.

Cold leg injection lines filled

March 20, 1990:

2:04 a.m.

Cold leg injection lines and cold legs vented

4:01 a.m.

Pressurizer level at 22 percent

4:19 a.m.

Reactor Vessel Head Vents are closed

5:01 a.m.

RHr (ND) Letdown established

5:05 a.m.

Pressurizer Level at 75 percent

i

5:30 a.m.

Power applied to RHR (ND) loop isolation valves in

preparation for pressurizing RCS (NC) system

,

-

-=

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. Appendix 1A

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-

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.

.7:08 a.m.

Pressurizer .is full and' PORV's~ areLclose'd 'by . procedure

- 7.09 a'.m.

Low. Temperature .0ver Pressure Protection. Mode for.'PORV's?

!

is selected-

17:24 a.m~.

Operators; establish charging flowiatt100'gpmiandlmaintaini

50 psig backpressure on ..RHR. (ND)fletdown; 'toi; commence

pressurizing . RCS - (_NC) systemo tol .100 psig fori venting -

operations

.

..

3

Operators periodically monitor: low 1 range RCS (NC). system

pressure and; wide _ range pressure instruments. Gages read.

i

0: psig sand _ computer pointLindicates 53 psign forinext -few -

hours-

a

.

e

Reactor coolant. system : starts .to pressurize with' no.

corresponding indicat, ion on RCS (NC)npressure instruments

<

,

9:38 a.m.

(

)

.RHR ND ;and RCS (NC) pressure peaks andtRHR (ND) suction.~

.

relief opens

'

4

-

- -

^!

9:45 a.m.

Operators observe PRT level increasing;! Recognizing _

i

something. is abnormal, they Ereduce . charging _.to 95 gpm and:

1

noti fy . supervi sion.

The RHR (ND)' pump "1A" High Dischargei

Pressure annunciator at 579 psig does ; not 'alarmT and'

-

operators are unaware of the ' abnormally 1high?RHRl(ND) Jand:

.

RCS (NC) system pressure

a

9:51 a.m.

Operators suspect that a PORV is -leaking toLthe: PRT and

!

'

isolate one at time =in order. to . identify which e one.

t

PORV's determined not to :be ~the: source of input to PRT'

i

,

Operators observe I RHR (ND) pump "1A"T Discharge; Pressure

-indicating 375 psig and recognize that the pressure.is-too high

z

for the expected plant conditions. Using:thumbrules.of:RHR:

(ND) pump differential pressure = 200 psid, operators' estimate

!

RCS (NC) system is pressurized to.175 psig with no corresponding

indicction on the RCS (NC) pressure instruments. Operators

suspect RHR (ND) suction relief valve is leaking to. PRT' and

,

order personnel in containment'to investigate

,

9:57 a.m.

Operators decide to lower pressurizer level to obtain a'

reading on scale in order to vent the system; Letdown flow

increased from 60 gpm to 120 gpm.

Charging flow gradually

reduced

10:08 a.m.

Personnel in containment identify RHR-(ND) suction relief-

1ND-38 is passing flow. Control Room operators isolate "B"

'

train RHR (ND) by shutting ND36, _ND37

RCS (NC) System pressure is reduced

s

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10:30~a.m,t

. Operators obtain-informationi.thatHthe pressuretinstrUmentf

. were? isolated and declare.thelPORV'syinoperable..

-- A

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11: 12Ja.m;

OperatorsLattemptitof restore;.'!B(train; RHR'-(ND) however;arei

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.'B trai_n L RHR '(ND)f reitored;tofoperable ? status .

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,

.

. . . .

v

..

1:454p.m.

PORV!s' opened,and.RCS (NC);systemiislvented-~

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2:20,p.m.

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PPENDIX B

PRESSURE CURVE

i

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CNS ORC DATR FOR UNIT 1 FOR R1484

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ND PMP R DISCHARGE PRESS

'

800 .SIG

.

P

4

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760 l--

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Agguppurru.k pr.a-

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TIME CHOURS) FROM START OF-MAR 20

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'

.

APPENDIX CL

.

PERSONS CONTACTED

-Name

Title - Work Group

R. Abernathy.

Unit I Outage Manager, Integrated Scheduling

P. Barrett

. Design Engineer, Design Engineering

W. Beaver

Performance Manager,-Technica1' Services

M. Buckner

I&E Technician, Maintenance Department

A. Bhatnagar

Test Engineer, Technical Services

R. Casler

Operations Superintendent, Operations Dept.

-T. Crawford

Integrated Scheduling ~ Superintendent, Integrated

' Scheduling

E. Fritz'

Design Engineer, Design Engineering-

B. Hal1 man

Performance Engineer, Technical: Services

T. Harrall

Design Engineer, Design Engineering-

J. Forbes

Technical Services Superintendent, Technical' Services

R. Glover

.Compilance Manager,' Technical;$ervices

V. King

Compliance ~ Technician, Technical Services

S. Lefier

Design Engineer, Design Engineering

W. McCollum

Maintenance Superintendent, Maintenance =

T. Owen

Station Manager, Catawba Nuclear Station

S. Putnam

I&E Technician, Maintenance Department

D. Tower

Unit I Operating Engineer, Operations Department-

NRC Personnel

R. Gibbs

Reactor Engineer, Region II

B. Orders

Senior Resident, Region II

M. Lesser

Resident Inspector, Region'II

C. Rapp

Reactor Engineer, Region II

Attended Exit Meeting

,

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APPENDIX 0

ACRONYMS AND ABBREVIATIONS

'ACOT

Analog Channel Operational Test

AEOD

Office For Analysis And Evaluation Of Operational Data

CF

Feedwater

CFR

Code of Federal Regulations-

CR0

Control Room Operator

CRSRO

Control Room Senior. Reactor Operator

CVCS (NV)

' Chemical Volume and Control System

dp

'

Differential Pressure

DPC

Duke Power Company

gpm

Gallons Per_ Minute

IAE

Instrumentation-And Electronics

IEB

Inspection And Enforcement Bulletin

IFI

Inspector. Follow-up Item

IS

Integrated Schedule:

LC0

Limiting Condition For 0peration.

LTOP

Low Temperature'Over Pressure Protection

MES

Mechanical Equipment Section

MOV

Motor Operated Valve

NCDT

Reactor Coolant Drain Tank

NMDB

Nuclear Maintenance Data Base

NRC

Nuclear Regulatory Commission

NRR

Nuclear Reactor Regulation

NSM

Nuclear Station Modification

PORV

Power Operated Relief. Valve

PRT

Pressure Relief Tank

psid

Pounds Per Square Inch Differential

psig

Pounds Per Square Inch Gage

RC (NC)

Reactor Coolant

RCDT

Reactor Coolant Drain Tank

'RCS (NCS)

Reactor Coolant System

RHR (ND)-

Residual Heat Removal

RMW

Reactor Makeup Water

R0

Reactor Operator

RPS

Reactor Protection System

SRO

Senior Reactor Operator

SS

Shift Supervisor

SWR

Standing Work Request

TS

Technical Specifications

TSAIL

Technical Specification Action Item List

.

ML20034B019

Text

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