Text

Insp Rept 50-285/97-09 on 970423-0610.Violations Noted But Not Cited & Being Considered for Escalated Enforcement Action.Major Areas Inspected:Operations,Maintenance, Engineering & Mgt Meeting
	ML20149D596
Person / Time
Site:	Fort Calhoun
Issue date:	06/17/1997
From:	; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:	;
Shared Package
ML20149D586	List: ML20149D582; ML20149D596;
References
	50-285-97-09, 50-285-97-9, FACA, NUDOCS 9707170189
	Download: ML20149D596 (20)
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ENCLOSURE

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket No.:

50-285

License No.:

DPR-40

Report No.:

50-285/97-09

Licensee:

Omaha Public Power District

Facility:

Fort Calhoun Station

Location:

Fort Calhoun Station FC-2-4 Adm.

P.O. Box 399, Hwy. 75 - North of Fort Calhoun

Fort Calhoun, Nebraska

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Dates:

April 23 through June 10,1997

Inspectors:

J. Shackelford, Senior Reactor Analyst

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C. Clark, Reactor Inspector, Maintenance Branch

P. Qualls, Reactor Inspector, Engineering Branch

W. Walker, Senior Resident inspector, Projects Branch B

Approved By:

Dwight D. Chamberlain, Deputy Director

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Division of Reactor Safety

Attachment:

Supplemental Information

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9707170189 970617

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ADOCK 05000295

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TABLE OF CONTENTS

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EX EC UTI VE S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii

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R e p o rt D e t a il s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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1. Operations

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Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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01.1 Main Steam Extraction Line Rupture Event

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Operator Knowledge and Performance

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04.1 Operator Performance and Procedural Issues . . . . . . . . . . . . . . .

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II . M a inte na n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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M2

Maintenance and Material Condition of Facilities and Equipment

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M2.1 Erosion / Corrosion Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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M7

Quality Assurance in Maintenance Activities . . . . . . . . . . . . . . . . . . .

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M7.1 Licensee Root Cause Investigation, Followup Activities and

Corrective Actions . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . .

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Ill. Engineering

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Plant Damage Assessment

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V. M a nagement M e eting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Public Meeting and Exit Meeting Summary . . . . . . . . . . . . . . . . . . . .

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ATTACHMENT: Supplemental Information

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EXECUTIVE SUMMARY

Fort Calhoun Station

NRC inspection Report 97-09

This team inspection investigated the causes, circumstances, and corrective actions

associated with the April 21,1997, extraction steam rupture at the Fort Calhoun Station.

The inspection team evaluated the operators' performance, procedural controls, plant and

equipment performance, maintenance, and engineering aspects of the event. The

inspection covered a 4-week period, with 2 of these weeks conducted onsite.

Onerations

The team identified a strength in the overall operator response to the event. The

licensed operators acted in a timely and decisive manner to trip the unit and to

isolate the steam rupture. The subsequent decisions to implement emergency

boration were conservative, and the plant was quickly stabilized.

The inspectors noted a weakness in use of fire protection procedures. The plant

operators displayed a lack of familiarity with the operating procedures used in

isolating selected portions of the fire protection system. This lack of familiarity

resulted in an unnecessary isolation of the entire fire protection system.

Maintenance

it was determined that the licensee had missed a potential opportunity to detect the

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degraded elbow by not considering the imp!! cations of an upstream pipe

replacement of a similar large radius elbow that had occurred in 1985 and had not

adequately considered industry operating experience in the selection process to

determine inspection locations to identify pipe wall thinning. Additionally, the

inspectors noted that the licensee's analytical model for predicting the relative wear

rate of components (CHECWORKS) had not accurately predicted the actual

observed wear rates associated with large radius elbows in the fourth stage

extraction steam system. These factors contributed significantly to the licensee's

failure to identify the wall thinning in the fourth stage extraction steam elbows.

Enaineerina

The inspectors determined that the overall plant and equipment response to the

event were normal and no anomalies were noted. All equipment functioned as

designed and no safety systems vvere actuated.

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Reoort Details

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Summarv of Plant Status

-The unit was manually tripped by the operators on April 21,1997, as a result of the

. extraction steam rupture event. The unit was placed in cold shutdown for repairs and was

subsequently returned to 100 percent power.

l. Ooerations

01

Conduct of Operations (93702)

01.1 Main Steam Extraction Line Ruoture Event

On April 21,1997, at approximately 8:20 p.m., the plant operators heard a loud

nome coming from the turbine building at the Fort Calhoun Station. The plant was

opereting at 100 percent power and no unusual operational activities were in

progress at that time. The plant operators opened the control room access to the

turbine building and noted steam emanating from the grating, which separates the

main turbine deck from the areas below. The plant operators determined that a

steam rupture was in progress and manually tripped the reactor. The reactor tnp

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resulted in a turbine trip.

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The following is the sequence of events for the main steam extraction line rupture

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that occurred on April 21,1997.

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The plant was operating at 100 percent power with norma!

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surveillance activities in progress.

2022

A loud noise was heard in the control room, presumably emanating

from the turbine building. The shift supervisor opened the control

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room door and observed a large amount of steam in the north end of

the turbine building. The shift supervisor returned to the control room

and ordered the reactor to be manually tripped.

2023

The reactor was manually tripped and Emergency Operating

Procedure-00, " Standard Post Trip Actions," was entered.

2024

Emergency boration was initiated as a precautionary measure. (The

operators determined that the potential existed for an uncontrolled

heat extraction.)

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A notification of unusua; event was declared based on the need for

increased plant awareness.

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Emergency Operating Procedure-00, " Standard Post Trip Actions,"

was completed. Emergency Operating Procedure-01, " Reactor Trip

Recovery," and Abnormal Operating Procedure-26, " Turbine

Malfunctions," were entered due to lowering vacuum on the

condenser and loss of the turning gear on the turbine. The plant

operators also entered Abnormal Operating Procedure-32, " Loss of

4160 volt or 480 volt Bus Power," due to the loss of Motor-Control

. Center 4C3 and the degradation of Motor-Control Center 4C5. Both

motor-control centers were in the direct path of the steam rupture.

2052

The plant emergency response organization was activated to assist in

assessing the damage from the steam leak and restoring power to the

secondary equipment.

2100

The turbine building fire protection system was isolated by placing

the diesel fire pump and the electric fire pump in pull to lock. This

was done to stop the spraying down of the turbine building by the

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fire sprinkler system that had actuated as a result of the event.

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Plant operators verified that the shutdown margin was adequate.

Emergency boration was secured.

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All continuous fire watches were established.

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The notification of unusual event was terminated and the emergency

response organization was secured. These decisions were based on

the determinations that plant conditions were stable and that the

damaged equipment had no adverse effect on maintaining a safe

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shutdown.

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The operators exited Emergency Operating Procedure-01, " Reactor

Trip Recovery" and entered Operating Procedure-3A, " Plant

Shutdown."

01.1.1 Plant Performance issues Associated with the Event

a.

Jmoection Scoce (93702)

The inspectors reviewed the plant and equipment response to the event. Both

primary and secondary side plant indications and responses were evaluated. The

performance and reliability of important equipment were assessed, as well as, the

potential for steam and moisture interaction with other plant equipment that was

not directly affected by the rupture.

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Observations and Findinas

The inspectors performed a review of the recorded critical plant data for primary

plant parameters associated with the event and no anomalies were noted, it was

also determined that no primary side alarms or abnormal indications were received

following the event. However, several alarms were received on extraction steam

pressure. It was determined that these alarms were to be expected based on the

location of the pipe rupture. No automatic safety-system actuations occurred

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during the event. However, portions of the fire protection system were actuated

throughout the turbine building due to the heat and temperature rise nssociated

with the steam rupture. The steam from the rupture caused seven wet pipe

sprinkler heads to actuate in the basement level of the turbine building.

These heads were in the immediate vicinity of the steam leek and were designed to

actuate at 160 degrees fahrenheit. The team noted that the steam in the vicinity of

these sprinkler heads exceeded the actuation temperature of the sprinkler heads.

The deluge system for the turbine tube oil reservoir also actuated at the time of

the event. This system contains 15 deluge nozzles that sprayed water in the area

of the reservoir and on the main tube oil pumps. The system was actuated by a

cate of temperature rise probe. (Tnis device will cause a deluge actuation if a

15 degrees fahrenheit per minute temperature increase occurs.) The team noted

that the rate of temperature increase in the area of the steam rupture probably

exceeded that required to actuate the detector. Due to the sprinkler and deluge

system actuations, fire water system pressure decreased and caused the fire

suppression water pumps to start automatically.

Following activation of the fire suppression system, intermittent electrical grounds

were received on Vital DC Bus 1 and 480V Bus 1B4C, both of which are safety

related. These grounds on the safety-related buses were determined to be most

likely due to grounds on the turbine building motor-control centers in the vicinity of

the pipe rupture. These motor-control centers are fed by the safety-related buses

and can be isolated by the tripping of the critical quality equipment feeder breakers

which isolate the nonsafety-related loads from their safety-related source. The

inspectors reviewed the material history of selected critical quality equipment

breakers on the 480V (184C-1) and vital de buses. This review indicated no

operational issues in the past 3 years.

However, the inspectors noted that problems with spurious tripping of safety-

related loads, as a result of grounds on nonsafety-related equipment, had occurred

both in the commercial nuclear industry, as well as, at Fort Calhoun Station.

License Event Report 50-285/95-007-01 documented the licensee's problems with

General Electric RMS-9 trip units. The licensee indicated that 13 RMS-9 trip units

had been replaced on safety-related breakers as of August 22,1996. The basis for

the repir. cement of these particular RMS-9 trip units was the possibility of a

commoa mode failure as the result of receiving multiple grounds resulting from a

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design basis accident. However, during the inspection, the inspectors noted that an

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additional 44 RMS-9 trip units existed on safety-related loads and load centers

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which had not been previously replaced. The licensee's rationale for not replacing

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these breakers was that sufficient redundancy ceuld be demonstrated during design

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basis scenario's with the worst-case postulated RMS-9 trip unit failures. However,

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'it was determined that the licensee's approach may not have been conservative in

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all cases.' In particular,.during some maintenance configurations, the SI-2C high

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pressure safety injection pump may have been susceptible to postulated RMS-9 trip

unit failures during certain design basis scenarios. The licensee is in the process of

reanalyzing the basis for RMS-9 trip unit. replacements and currently plans to

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replace all of the RMS-9 trip units, which carry safety-related loads. In addition the

. licensee is reviewing all plant loads associated with RMS-9 trip units and is

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. developing criteria for replacing some of the nonsafety-related units. This item will

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remain open pending further review regarding the licensee's criteria for not

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r'eplacing some safety-related RMS-9 trip units in the original modification (50-

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285/9709-01).

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. The inspectors evaluated the potential for steam to intrude from the turbine building

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into the auxiliary building. In particular, the inspection focused on the 125 volt de

battery rooms, the electrical switchgear rooms, and the cable spreading rooms.

The inspectors noted that the only method of communication between the turbine

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building and these areas was via four fire doors and a damper over the cable

spreading room door. No fire alarms were received from any of these areas of the

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auxiliary building and inspection of these areas did not indicate any moisture

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intrusion. (It is expected that steam intrusion would have resulted in fire alarms in

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these areas because they are equipped with ionization detectors.) Also, a review of

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the ventilation systems was conducted and discussions were held with the

' ventilation system engineer concerning the potential for steam intrusion from the

turbine building'into the safety-related areas of the auxiliary building. It was

determined that separate ventilation systems exist for the safety-related areas and

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that no potential existed for steam intrusion via the ventilation systems.

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Conclusions

The team concluded that the plant and equipment response were normal. All plant

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systems operated as designed and no equipment failures or abnormal indications

were noted. - Further, the inspectors concluded there was no steam intrusion from

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the turbine building into the safety-related electrical switchgear rooms. However,

the rupture resulted in significant, challenge to the plant operators and led to a

reduction in the station fire protection capabilities.

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- Operator Knowledge and Performance -

04.1 - Operator Performance and Procedural Issues

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Inspection Scone

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The team reviewed the operators' response and procedural issues associated with

the event. Interviews were conducted with plant operators, and control room log

reviews were performed. An overall evaluation of operator performance and

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procedural adequacy was performed with respect to the specific operator actions

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associated with the event.

b.

Observations and Findinas

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.The inspectors noted that the' operator's actions to respond to the event w'ere

timely, decisive, and conservative. The operators acted quickly by tripping the'

reactor within 19 seconds of the initiation of the event. Additionally, the team

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determined that the operators took conservative measures by initiating emergency

boration to ensure that an adequate shutdown margin was maintained in

consideration of the potential for an uncontrolled heat extraction during the event.

It was determined that the correct emergency operating and abnormal operating

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procedures were' implemented during the event. The inspectors responded to the

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site in the early recovery stages of the event and noted that the control room was

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orderly and that good command and control were demonstrated by the licensed

senior operator and the shift supervisor.

However, the inspectors did note a _ weakness during the response to the event

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with the operators' knowledge of fire protection procedures. Operating

Instruction OI-FP-1, " Fire Protection System Water System," Revision 25, contains

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detailed steps on the isoletion of the fire protection system. Specifically,

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this procedure contained details on isolating fire protection water to the turbine

building basement, the turbine lube oil deluge and the turbine building mezzanine

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sprinkler systems. During the event the operators attempted to isolate the fire

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' protection system using only the piping and instrument drawings and without

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referring to the proper procedure. The inspectors conducted selected interviews

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with auxiliary operat_ ors, who were attempting to isolate the fire protection

system the night of the event, and each individual interviewed indicated that

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Operating instruction Ol-FP-1 should have been used. This would have made

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isolation of the fire protection system more timely and would not have resulted

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in an isolation of the entire turbina building fire protection capability. The

operators attempted to isolate the fire protection system for approximately

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40 minutes before a decision was made by the shift supervisor to secure the fire

pumps. This terminated the spraying down of equipment in the turbine building and

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rendered the fire protection system inoperable without operator action to restart the

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fire pumps. The operators placed the fire protection system pumps in pull to lock in

accordance with Standing Order S0-G-103, " Fire Protection Operability Criteria and

Surveillance Requirements," Revision 5. The NRC is reviewing the adequacy of this

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procedure and the results of this review will be dispositioned in NRC Inspection

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- Report 50-285/97-06. The inspectors determined that the lack of familiarity with

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the fire protection procedures resulted in an unnecessary reduction in station fire

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. protection capabilities.

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During the followup to the event, the licensee identified the failure to

establish a continuous fire watch in the required time after securing the fire

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pumps. -This was documented in Condition Report 199700499, which indicated

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that the sprinkler system for the diesel rooms was out-of-service for approximately

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . Standing Order SO-G-103, " Fire Protection Operability Criteria and

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Surveillance Requirements." Revision 5, Attachment 3, Step 2, requires that a

continuous fire watch be established within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months if the sprinkler system is -

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inoperable. Failing to establish a continuous fire watch within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is a

violation of Technical Specification 5.8.1. The licensee conducted training and .

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issued an operations memorandum to address this deficiency. Additionally,

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refresher training on the usage of plant fire protection procedures was scheduled

for the licensee's requalification program. This nonrepetitive licensee-identified and

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corrected v!olation, is being treated as a noncited violation consistent with Section

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V11.B1 of the NRC Enforcement Policy (50-285/9709-02).

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Conclusions

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.The team concluded that licensed operator actions were accomplished in an

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expeditious manner. The operators' decisions were both rational and conservative.

'An overall strength was noted in the area of licensed operator response. A

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weakness was noted in the area of the use of the procedures to manually isolate

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selected fire protection headers.

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11 Maintenance

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Maintenance and Material Condition of Facilities and Equipment

M2.1 Erosion / Corrosion issues

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Inspection Scope (49001, 62706)

The team reviewed those aspects of the licensee's maintenance rule and

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erosion / corrosion control programs as they pertained to the circumstances

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surrounding the April 21,1997, pipe rupture event.

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Observations and Findinas

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The licensee determined,' and _the team agreed, that the failure of the piping in

. the fourth stage extraction steam system was most likely due to flow. accelerated

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corrosion. The design conditions of the fourth stage extraction system were

300 psig/425*F and the system was composed of primarily 12-inch diameter piping

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fabricated from A-1068 carbon steel with a nominal wall thickness of .375 inches.

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The;" fishmouth" break, which occurred, was approximately 4 feet long by 1 foot

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wide,'and it was postulated that an approximately 2-4 inch wide by 4 foot long

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_ section of pipe was below minimum wall thickness before the rupture. _ The failure

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-location occurred on'what is known as a "large radius elbow." The as-found '

readings on the failed pipe revealed a minimum wall thickness of the rupture seam

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.of .054 inches, whereas the minimum allowable pipe thickness was .126 inches.

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The failure location was modeled in the licensee's erosion / corrosion program (i.e.,

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Location S-25) but the actual wall thickness had never been measured by

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nondestructive examination techniques. The licensee had relied on a predictive

methodology (CHECWORKS) to monitor the condition of the large radius elbows in

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the extraction steam system. The CHECWORKS methodology had predicted a

lower wear rate on the large radius elbows relative to other potential wear locations

within the fourth stage extraction steam system.

The team determined that a prior opportunity to detect and prevent the failure had

existed. It was discovered that Field Change 85-94 had been implemented in 1985

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to replace the piping immediately upstream of the failure location. This modification

included the replacement of the next upstream large radius elbow due to excessive

wear caused by erosion / corrosion. The licensee indicated that the first elbow in the

system (a short radius elbow) had developed a pinhole leak due to flow accelerated

corrosion. During replacement of the short radius elbow, it was discovered that the

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next downstream elbow (a large radius elbow located immediately upstream of the

site of the April 21,1997, pipe rupture) was also significantly degraded due to

erosion / corrosion and required replacement. The licensee could not produce

documentation to indicate that any inspections were conducted at that time on

Location S-25, (the failure location), or any other large radius elbows in the

extraction steam system. Thus, the team determined that this information would

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have'been sufficient to indicate that high wear rates were occurring in the large

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radius elbows despite the predictions made by the analytical methodology.

Additionally, the team determined that the licensee had not adequately incorporated

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industry operating experience into the erosion / corrosion program. Various NRC

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information notices and industry notifications were available. They provided

Insights into significant operating failures in extraction steam and other similar

systems. Additionally, several other sources of industry information, which

contained an extensive amount of information related to similar problems in the

extraction steam systems at other plants, were available to the licensee. These

sources of industry information had not been adequately factored into to the

licensee's erosion / corrosion program with respect to choosing suitable piping

inspection locations.

As a result of the rupture, the licensee inspected all other large radius elbows at the

facility, which had not been previously inspected. It was determined that the

furthest downstream large Radius Elbow S-32 in the fourth stage extraction piping

was also significantly below minimum wall thickness and had to be replaced. (The

minimum wall reading was .044 inches.) Inspection Location S-27, another large

radius elbow in the fourth stage extraction piping, was also found to have exhibited

excessive wear, although this particular elbow had not exceeded the minimum

allowable thickness. (This location exhibited a minimum wall reading of .155

inches and was replaced by the licensee.) .The large radius elbow at Location S-27

was in the licensee's analytical model for the erosion / corrosion program and had

never been inspected due to the lower relative wear rate predictions for large radius

elbows which were supplied by the model. The licensee also inspected the large

radius elbows in the second stage extraction steam system and these elbows were

found to have acceptable wall thickness readings.

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The licensee's staff acknowledged the deficiencies associated with incorporating

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plant and industry operating experience into the erosion / corrosion program. In

response to this issue, the licensee implemented a panel of industry experts from

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other utilities and industry groups whose charter was to review the Fort Calhoun

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Station erosion / corrosion program with respect to the incorporation of industry

insights. The erosion / corrosion program susceptibility evaluation was upgraded to

conform to industry standards. The entire steam seal system, steam generator

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blowdown suction / discharge of the blowdown transfer pumps, condensate

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' recirculation and steam traps and drains were added to the program.' Additionally,

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.this review group identified a number of additional inspection locations which were

not being actively inspected in the licensee's program. The licensee conducted

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ultrasonic testing inspections of these locations and determined that several other

locations in a different plant system had degraded to the point whereby the walls

had exceeded minimum. wall thickness standards. It was found that three separate

parallel lines in the heater drains system (Location D-95) had very localized areas,

which were below the minimum allowable well thickness and required replacement

(i.e., the minimum readings were .08 inches). Additionally, the licensee identified

that Location S-54 in the sixth stage extraction steamline exhibited unacceptable

. wall thickness reading and required replacement. This particiutar piece of piping

was known as a " pup" piece and was located immediately downstream of piping

that had been replaced in 1985 with an alloy of chromium-molybdenum material.

This location had a minimum wall thickness reading of .107 inches. h summary,

the net result of these programmatic reviews of the licensee's erosion / corrosion

program was the identification of five additional pipe locations (not including the

rupture location) whose wall thicknesses had degraded below the minimum

allowable.

The fourth and sixth stage extraction steam system and the heater drains

system had been included within the scope of the licensee's program to implement

10 CFR 50.65, " Requirements for Monitoring the Effectiveness of Maintenance at

Nuclear Power Plants." These systems were included as subsystems of the main

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feedwater system and had been classified as being of low risk significance and

were being monitored under Section (a)(2) of the Rule. The system performance

criteria had been identified at the plant level and required that no forced shutdowns,

power reductions, or trips be caused by maintenance preventable functional failures

of the system. The licensee's program plan for. implementation of the Maintenance

Rule (Section 4, paragraph 3) specified that the plant operating experience review

. program would provide the responsible organizations the industry operating

experience necessary for incorporating the required information into the

maintenance rule program. Additionally, paragraph 4 of the program plan specified

that the special services engineering department would maintain specialized

programs to respond to component-specific concerns. The erosion / corrosion

program was considered to be one such specialized program under the umbrella of

maintenance rule implementation. Finally, the Maintenance Rule implementing

Instruction MRil-2, Section 5.3.4, " Condition Monitoring," stated that no specific

condition monitoring was required by the Fort Calhoun Station Maintenance Rule

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Project. The Fort Calhoun Station Maintenance Rule Project made maximum use of

existing programs, such as erosion / corrosion control, to provide the necessary

condition monitoring functions as required by the rule.

The Maintenance Rule,10 CFR 50.65(a)(1), requires, in part, that each holder of an

operating license shall monitor the performance of structures, systems, or

components against licensee established goals, in a manner sufficient to provide

reasonable assurance that such structures, systems, and components are capable

of fulfilling their intended functions. Such goals shall be established commensurate

with safety and, where practical, take into account industry-wide operating

experience.10 CFR 50.65(a)(2) states, in part, that monitoring as specified in

paragraph (a)(1) is not required where it has been demonstrated that the

performance or condition of a structure, system, or component is being effectively

controlled through the performance of appropriate preventive maintenance such

that the structure, system, or component remains capable of performing its

intended function.

The inspectors determined that the licensee had not established appropriate goals

for those components in the fourth and sixth stage extraction steam system, and

the heater drains system whose pipe walls had degraded to the extent that

minimum wall thickness criterion had been exceeded. Additionally, it was

determined that the licensee had not adequately incorporated industry-wide

operating experience in the establishment of goals and performance monitoring

activities, as required by the maintenance rule. As a result, a pipe rupture occurred

on April 21,1997, due to inadequate monitoring of the condition of the fourth

stage extraction steam system. This pipe rupture resulted in a significant plant

transient and personnel hazard. The pipe rupture required the plant operators to trip

the unit and enter the emergency operating procedures in order to stabilize the

plant. Additionally, damage occurred to certain balance-of-plant equipment, and a

significant asbestos hazard was created due to damaged piping insulation in the

vicinity of the rupture. The event also actuated portions of the fire protection

system, which had to be disabled, thus, decreasing the station's fire protection

capabilities. This is considered to be an apparent violation of 10 CFR 50.65 (50-

285/9709-03).

In addition to the apparent violation described above, the inspectors noted the

following deficiencies associated with the predictions generated by the

CHECWORKS analytical model:

Large radius elbows were monitored on the basis of predictive wear analysis

only. There had been no erosior>l corrosion examinations performed of large

radius elbows.

Engineering judgement was not adequately incorporated into the sample of

components selected for erosion / corrosion examination (i.e., only those

components with the highest predicted wear were inspected).

i

9

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_ _ _ _ _ . _ _ _ .

__

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

t

.

[

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1

,

!

'

The erosion / corrosion engineer had not routinely evaluated the accuracy of

the analytical results. Therefore, the relatively poor predictive capability of

i

.

the program with respect to this comparison of predicted wear to measured

2

[

. wear was not detected for the fourth stage extraction steam system at Fort

.:

Calhoun Station.

'

1

>

!-

Actual component' measured wall thickness inspection data from the 1995

i

and.1996 erosion / corrosion examinations had not been incorporated into the -

j

analytical model.

,

1

i

.

Minor modeling input errors related to incorrect component geometry codes

l

'were identified by the team. The modeling input errors appeared to be the

_

'

result of incorrect component identification on as-built drawings used to

,

generate input data. A similar deficiency of this type had been identified by

r

the NRC in a routine erosion / corrosion inspection conducted in 1994.

Only one train of multiple train systems had been modeled in the analysis.

j

,

l'

Of particular significance was the fact that the CHECWORKS predictions for the

fourth stage extraction steam system were not consistent with the actual observed

wear rates as measured b' the licensee following the event. in particular, those

y

.

inspection locations whose relative wear rates were predicted to be the highest for.

- this specific application (i.e., short radius elbows and tees) did not exhibit

.significant actual measured wear. Conversely, the larger radius elbows (which had

. been predicted to exhibit a lower relative wear rate) were wearing at rates higher

than predicted for this specific application.

As of'the end date of the inspection, the licensee had not determined the specific

reasons for the discrepancies between the predictions and the actual observed wear

rates for those compunents in the. fourth stage extraction steam system. However,

i

the licensee did identify several other issues associated with the implementation of

.

the CHECWORKS methodology during a self-assessment associated with the

'

steamline rupture event. These self-assessment findings are discussed in Section

M7.1 of this report. As a result of these discrepancies, the licensee issued an

industry notification, which reported the details of the issues associated with

respect to the analytical n.athodology and its impact on this event,

c.

. Conclusions

The team concluded that significant weaknesses existed in the licensee's

erosion / corrosion program. Specifically, the team concluded that the licensee had

. not adequately incorporated industry experience into the program, particularly in the

area of the selection of inspection site locations. Additionally, the licensee had not

properly incorporated prior plant operating inexperience into the program for the

!

selection of inspection site locations. Finally, it was determined that the licensee's

analytical model for predicting wear rates on the affected system components had

not accurately predicted the actual wear rates and that an over-reliance existed

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with respect to the model's predictions for the extraction steam system. The result

of these deficiencies led to significant degradation (i.e., exceeded minimum wall

thickness requirements) in six separate piping locations in three separate plant

systems. One of these areas of degradation resulted in a catastrophic failure of the

piping, which caused an unnecessary plant transient and significant personnel

hazard and contributed to a reduction in the station's fire protection capabilities.

However, at the exit meeting on June 10,1997, the licensee indicated that several

,

i

of these locations which were found to be below minimum wall thickness were not

significant failures. The licensee stated that the piping replacements associated

<

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with these l'ocations were implemented at > precautionary measure.

f

M7

Quality Assurance in Maintenance Activities

M7.1 Licensee Root Cause Investiaation, Followuo Activities and Corrective Actions

a.

Insoection Scope (93702)

The team reviewed the licensee's self-assessment efforts, root-cause analysis, and

corrective actions associated with the steam rupture event.

b.

Qbservations and Findinas

i

The licensee performed a formal root-cause analy. sis of the extraction steam line

rupture event. The analysis was performed in two phases: Phase 1 was a

j

preliminary root-cause analysis to identify apparent causes and to identify the root

cause of the reason for not detecting the imminent failure of the piping. Phase 2 of

i

the root-cause analysis would provide a final root cause, which would include a

'

failure analysis (including a metallurgical examination) of the failed piping conducted

j

by two separate and independent laboratories.

'

The Phase 1 root-cause analysis results determined that the piping failure was most

likely the result of flow-accelerated corrosion, which had occurred over a relatively

I

long period of time. The licensee determined, and the team agreed, that the

degradation in the piping could have been detected well before the event. It was

1

determined that an over-reliance was placed on one predictive factor, the

relationship between elbow radius and predicted wear rate, in determining the

specific locations for ultrasonic testing inspection site locations. Additionally, it

was determined that there had been insufficient consideration of both industry and

plant-specific operating experience in the selection of inspection site locations. The

licensee also determined that the erosion / corrosion program lacked a detailed

methodology to choose ultrasonic testing inspection locations and that inadequate

management oversight existed with respect to the implementation of the program.

The licensee chartered a formal self-assessment team to review the

erosion / corrosion program at the facility. The team was composed of plant

personnel and management, as well as, industry representatives from other utilities,

Electric Power Research Institute, and contract engineering firms. The self-

11

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assessment team conducted a broad-based review of the erosion / corrosion program

'

and identified various program weaknesses and some strengths. The self-

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assessment findings were formulated into issues which were to be addressed in

~

three phases: (1) prior to plant startup, (2) pric,r to start-up from the 1998 outage,

and (3) those which were considered to be long-term corrective actions,

i

The most significant findings of the self-assessment effort identified specific factors

which contributed to the failure to identify the eroded piping in the extraction steam

system. In particular, the opportunity to identify excessive wear was missed due to

failure to inspect the S-25 elbow during replacement of the next upstream large

radius elbow in 1985. Additionally, the licensee's team noted that the plant had-

1

consistently missed the opportunity to identify high wear systems by not '

. adequately incorporating industry operating experience into the erosion / corrosion

'

program. The over-reliance on the predictive results of the'CHECWORKS

methodology (which had not accurately predicted the failure) was also a significant -

contributing factor.

,

Additional findings of the licensee's team included observations of various program

weaknesses in the erosion / corrosion program. The licensee's team noted the

following weaknesses in the program:

!

,

.

The licensee had not aggressively pursued the change out of carbon-steel

- with more resistant material.

l

The erosion / corrosion program did not provide a thorough description of

susceptibility criteria or documentation of system susceptibility

determinations.

No detailed procedures existed for how inspection locations should be

,

selected.

j

The measured wear process, which was used, was not consistent with

f

industry standards. The licensee had not been conducting point-to-point

'

comparisons of all the ultrasonic test readings associated with a given

component / location to determine the maximum wear rates. The licensee

had been using the data from the ten lowest thickness locations to

determine the wear rates.

A considerable amount of susceptible piping that was suitable for modeling

!

was not included in the analytical models.

l

c

(

No documentation existed that indicated that the analytical models were

'l

kept current.

'

The analytical models had not been verified.

~

'The erosion / corrosion program had not been maintained current with

industry standards.

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12

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._.___________._m.__.

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

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Some data packages could not be located for several inspection point

p

locations from the 1996 outage.

E

As a result of the root-cause analysis and self-assessment team efforts, the

licensee identified specific actions to be accomplished prior to restarting the unit.

i

The following activities were completed prior to the plant's restart on May 12,

.

1997:

'

e

'

I

.

Reviews were conducted for all systems within the scope of the erosion /

corrosion control program. The remaining large radius elbows, which had

l

been predicted to exhibit lower relative wear rates, were inspected. Two

.

'

additional elbows in the fourth stage extraction steam piping were replaced

due to excessive wear.

i

.

All pipes dominstream of previously replaced piping or components were

evaluated as to whether or not previous inspections had been conducted.

One location was found to have not been previously inspected. An

inspection was conducted on this location and it was found to have an -

'

.

acceptable wall thickness.

1

The erosion / corrosion program susceptibility evaluation was upgraded to

,

conform to industry standards. The entire steam seal system, steam

!-

generator blowdown suction / discharge of the blowdown transfer pumps,

i

condensate recirculation and steam traps and drains were added to the

!

program. Several additional required inspections were identified during this

j

review and all of the additional inspection locations were found to exhibit '

'

- acceptable wall thicknesses.

!

1

1-

A reinforcing pad was installed on Component S-56 (a branch location on

,

.the sixth stage extraction steam line feeding the low pressure heaters).

<

l-

All 1996 outage inspection packages, which had not been independently

4

reviewed, were reviewed and found to be acceptable.

'

' All missing 1996 outage inspection packages were located. It was

i

- *

determined that three of the missing packages had not undergone any

reviews to determine whether the readings for the affected components

4

were below minimum allowable wall thickness. Additionally, several of the

,

missing packages had not undergone the required independent review. All of

the'affected packages were reviewed, and all wall thickness readings were

'l

,

determined to be acceptable.

J

4

' Thirty components .which showed significant wear or whose. wear rate

,

'

could potentially lead to exceeding minimum' wall thickness, were

reevaluated using an industry standard analysis methodology. One of these

components required re-inspaction and the subsequent readings were found

,

to be acceptable,

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- A review of industry operating experience was conducted. This review

resulted in the addition of severalinspection locations. Subsequent

inspections of these additionallocations resulted in the replacement of three

parallel pipes in the heater drain system.

Additionally, the licensee identified the following short-term corrective actions to be

completed prior to the restart from the next refueling outage:

(

Upgrade the erosion / corrosion c'ontrol procedures to include more specific

g'uidance on choosing inspection locations.

Upgrade the measured wear determination process and the sample

expansion process to conform to industry standards.

Revise the erosion / corrosion control program to include a document that

controls the identification of system susceptibility criteria.

Incorporate past outage data into the current CHECWORKS model and

perform a verification of the^model. Additionally, formal controls will be

established to ensure thet model changes are properly documented.

Finally, the licensee identified a long-term corrective action related to the need for a

followup assessment of the erosion / corrosion program. The followup assessment

was intended to be verification that the interim improvements in the program were

providing satisfactory results.

c.

Conclusions

The team concluded that the licensee's self assessment and preliminary

determination of apparent causes were adequate. The root cause associated with

the failure to identify the degraded elbow appeared reasonable. The inspectors

determined tlM the corrective actions completed prior to restart and the proposed

short- and Ic'. , Lttm cosctive actions were acceptable. However, the team

determined that additional actions to properly evaluate the predictive validity of the

model would be necessary in order to maintain an awareness of the model's ability

to reliably predict wear rates. _The final determination regarding the Phase 11

root-cause analysis and the effectiveness of the short- and long-term actions will be

reviewed in future inspections and are characterized as an NRC inspection followup

item (50-285/9709-04). Additionally, further review of the licensee's overall

program for incorporating industry-wide operating experience into applicable plant

programs is planned and was characterized as an NRC inspection followup item

(50-285/9709-05).

14

2

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Ill.Enaineerina

E8

Plant Damage Assessment

a.

insoection Scoce (93702)

l

The team conducted an assessment of the damaged areas of the turbine building.

Additionally, the team reviewed the licensee's plan and scope of activities for

conducting a plant damage assessment and the associated recovery activities.

b.

Observations and Findinas

The licensee's damage assessment team developed criteria in determining the area

to be inspected for damage due to the rupture. The area defined for extensive

assessment included the area of obvious physical damage, as well as, an area

defined by a qualitative assessment of the thermal-hydraulic conditions associated

with the rupture. The licensee defined the " break-affected" zone as that area

extending outward from the break location in a roughly cone-shaped configuration

that terminated at the turbine building wall. This assumption was based on visual

examinations of the steam impingement effects, as well as, assumptions regarding

the temperature and pressure of the steam and the duration of the event.

The scope of the damage assessment included a disposition of every plant system

i

and whether or not the system could have been affected by the rupture. For those

systems that had the potential for damage, damage assessment teams were formed

and walkdowns were conducted. The results of the walkdowns were collated in

" damage assessment reports," which were submitted to the overall damage

assessment effort leaders for tracking purposes. The damage assessment teams,

which were formed, consisted primarily of the cognizant system, design, and

maintenance engineers, as well as, selected craft personnel. The following

paragraphs provide a summary of the significant findings associated with the

damage assessment effort.

The component in the " break-affected" zone with the most extensive damage was

the Motor-Control Center 4C5. The inspectors observed that the motor-control

center was approximately 8 inches out-of-plumb from the top to bottom. The back

panels were bent open and deformed by the effects of steam impingement.

Motor-Control Center 4C3, which was immediately adjacent to 4C5 did not display

any structural damage. However, this particular motor-control center lost power

during the event. (The motor-control center was subsequently re-energized during

the recovery efforts.) There were two other motor-control centers in this area

which did not suffer any obvious physical damage, but had been significantly

" sprayed" with asbestos insulation that had been displaced during the event. The

licensee consulted with the vendor of the motor-control centers and conducted the

necessary repairs to the damaged equipment. A small portion of the bus insulation

in the vertical section of the motor-control center was repaired and extensive clean

l

up was required to remove all of the powdered pipe insulation. The breaker for the

'

turbine seal oil pump required replacement due to physical damage.

l

15

.

Several cable trays were also located in the " break-affected" zone. The cable

trays directly in the stearn impingement zone were twisted and the unistrut cable

tray support was significantly damaged. Several cable tray dividers and covers

were displaced. The licensee performed a 100 percent visualinspection of all

36 instrumentation and control cables which were associated with the turbine

control valves and stop valves. In addition, tests were performed prior to the

unit's restart to ensure that the valves retained their ability to perform their

design function. Additionally, visualinspections were conducted on all 480 volt ac

power cables. The licensee implemented a sampling methodology to determine the

electrical condition of the remaining cables in the affected cable trays.

Approximately 33 percent of the remaining cables were meggared with the primary

focus being that of the pump and fan motor loads. There were 56 cables in this

area, and no problems were identified. The licensee indicated that while these

j

cables were not safety related, they had been purche'ed to identical specifications

i

as that of other safety-related cables in the plant.

The licensee stated that all of the electricaljunction boxes in the " break-affected"

i

zone had been inspected for signs of moisture. A total of six junction boxes were

identified to have exhibited signs of moisture intrusion. (Five of these junction

boxes were in the " break-affected" zone.) The one affected junction box, which

was not in the damaged area, was immediately outside the control room. The

licensee postulated that this particular junction box had most likely been sprayed

down during the asbestos clean up of the turbine building. In addition, junction

)

boxes were spot checked throughout other areas of the turbine building (outside of

the break-affected zone) to ensure that moisture from the steam had not impacted

other areas. No additional electricaljunction boxes were identified as having been

impacted by moisture intrusion.

'

Pipe supports and equipment supports in the general area of the pipe rupture were

inspected and three supports were noted to have been damaged. All three of the

affected supports were on the fourth stage extraction steam line near the site of

the pipe ru.pture. All of the damaged supports were either repaired or replaced.

Additionally, it was noted that some damage had occurred to the turbine ,stop and

control valves. Specifically the drain lines for Stop Valve 1 and 2 were bent. Stop

Valves 1 and 2 and Control Valves 1 and 3 were in the direct path of the steam

impingement. These drain lines were heated and straightened, no replacement was

necessary. The solenoid valves and linear variable differential transformers were

inspected on these valves and no obvious damage was noted. However, these

components were replaced as a precautionary measure. Also, the servo valves on

'

Control Valves 1 and 3 were replaced and the limit switches on Stop Valves 1

and 2 were cleaned and inspected. The inspectors noted that the turbine stop

valve limit switches supply a turbine trip signal to the reactor protection system.

16

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c.

Conclusions

l

The team determined that the scope of the licensee's damage assessment was

!

reasonable and adequate. The observed damage was of a localized nature in the

immediate vicinity of the pipe rupture. No safety-related equipment or equipment

required for safe shutdown was damaged. The licensee indicated that future

additional followup inspections of certain important electrical components would be

conducted periodically following startup to ensure that corrosion due to potentially

undetected moisture would not affect the reliable operation of those components.

V. Manaaement Meetinas

X1

Public Meeting and Exit Meeting Summary

.

The licensee and NRC conducted a public meeting at the site on May 2,1997, to

j

discuss the licensee's root-cause analysis, damage assessment, self assessment,

and corrective action efforts. The team presented the inspection results to

members of licensee management at the conclusion of the inspection on June 10,

1997. _The licensee acknowledged the findings which were presented. The

Inspectors asked the licensee whether any of the materials examined during the

inspection should be considered proprietary. The licensee indicated that the details

associated with the CHECWORKS predictive methodology should be considered

proprietary. None of these details are contained in this report.

.

l

17

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.

ATTACHMENT

SUPPLEMENTAL INFORMATION

PARTIAL LIST OF PERSONS CONTACTED

Licensee

R. Andrews, Manager-Nuclear Assessments

C. Br.unnert, Manager Ouality Assurance

J. Chase, Plant Manager

M.. Core, Manager System Engineering

S. Gambhir, Manager-Engineering and Operations Support

J. Gasper, Manager-Nuclear Projects

W. Gates, Vice-President of Nuclear Operations

B. Lisowyj, Station Engineering

E. Matzke, Station Licensing

R. Phelps, Manager-Station Engineering

R. Short, Manager-Operations

H. Sufick, Manager-Security

J. Tills, Manager-Nuclear Licensing

NRC

E. Merschoff, Regional Administrator

A. Howell, Director, Division of Reactor Safety

K. Brockman, Deputy Director, Division of Reactor Projects

D. Chamberlain, Deputy Director, Division of Reactor Safety

D. Graves, Project Engineer, Projects Branch B

R. Wharton, Project Manager, Office of Nuclear Reactor Regulation

INSPECTION PROCEDURES USED

49001

Inspection of Erosion / Corrosion Monitoring Programs

62706

Maintenance Rule

93702

Prompt Onsite Response to Events at Operating Power Reactors

ITEMS OPENED AND CLOSED

.

Opened

50-285/9709-01

IFl

Replacement of RMS-9 trip units (Section 01.1.1)

'

50-285/9709-02

NCV

Establishing required fire watches (Section 04.1)

1

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....

_-.---.

....

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f

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-2-

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<

50-285/9709-03

APV

Failure to monitor the condition of plant piping systems and

l'

incorporate industry-wide operating experience in

accordance with 10 CFR 50.65 (Section M2.1)

50 285/9709-04

IFl

Adequacy of short- and long-term corrective actions

'

associated with the erosion / corrosion control program

(Section M7.1)

50-285/9709-05

IFl

Incorporation of industry-wide operating experience into

plant programs (Section M7.1)

Closed

50-285/9709-02

NCV

Establishing required fire watches (Section 04.1)

LIST OF DOCUMENTS REVIEWED

Procedures

Revision

Title

NOD-QP-21

6

" Operating Experience Review Program"

PED-gel-56

5

" Configuration Change Closeout"

l

QCP-200

11

" Certification Requirements For Quality Control Inspectors"

. OCP-331

6

" Ultrasonic Thickness Measurement for Erosion / Corrosion"

OCP-332

8

" Gridding Procedure for Erosion / Corrosion"

. SO-G-21

62

" Modification Control"

SS-PM-MX-0800

0

" Ultrasonic inspection of Station Pipe"

Modification Reauests

Title

FC-85-94

" Extraction Steam Elbows"

,

FC-80-102

"6th Stage Extraction Erosion"

2

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ML20149D596

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