ML20245B595

Responds to NRC Re Violations Noted in Insp Rept 50-325/88-45.Corrective Actions:Mods Completed Which Provide Accurate Indication on RTGB & Local Control Panel for Inlet & Outlet Valves.Fee for Civil Penalties Encl

ML20245B595
Person / Time
Site:	Brunswick
Issue date:	04/17/1989
From:	Watson R CAROLINA POWER & LIGHT CO.
To:	NRC OFFICE OF ENFORCEMENT (OE)
References
EA-88-316, NLS-89-081, NLS-89-81, NUDOCS 8904260167
Download: ML20245B595 (9)

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.i p ,. Carolina Power & Light Company .

( ' P. O. Box 1551 e Raleigh, N. c. 27002

. SERIAL: .NLS-89-081 f' j APR L71989 l r .i n

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Nucteer Generation i

Director, Office of Enforcement

'U..S. Nuclear Regula'ory Commission Washington, DC 20555 BRUNSWICK STEAM ELECTRIC PLANT, UNIT NO. 1 DOCKET NO. 50-325/ LICENSE NO. DPR-71 1

REPLY T0- A NOTICE OF VIOLATION (EA 88-316)

Gentlemen:

On March 16, 1989, the Nuclear Regulatory Commission issued a Notice of Violation (NOV) and Proposed Imposition of Civi1 Penalty (EA 88-316) for two

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events that resulted in :the loss of secondary containment integrity during the

. period of December. 11-14, 1988 at the Brunswick Steam Electric Plant-Unit No. 1. Carolina Power & Light Company (CP&L) hereby responds to the NOV.

Attachment 1 to this letter is CP&L's " Reply to the Notice of Violation" (10CFR2.201).

As noted in Attachment 1, CP&L acknowledges that both proposed violations

-constituted violations of regulatory requirements. Carolina Power & Light Company reaffirms its belief that these violations are rooted principally in design control problems. Enclosed is a check payable to the Treasurer of the United States in the amount of One Hundred Fifty Thousand Dollars ($150,000).

If'you have any questions, please contact me at (919) 546-4176 or Mr. Pedro Salas at (919) 546-4015.

Yours very truly, hh WW R. A. Watson RAW /PS/crs (272CRS)

Enclosures cc: .Mr. S. D. Ebneter Mr. E. G. Tourigny Mr. W. H. Ruland NRC Document Control Desk R. A. Watson, having been first' duly sworn, did depose and say that the information contained herein is true and correct to the best of his information knowledge and belief; and the sources of his information af,%,,,,

officers, Company.

~ employees, contt actors, and agents of Carolina Power & Li$t"g (; g,,# *t us,I S COhRY  %

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1 so UNITED STATES OF AMERICA NUCLEAR REGULATORY COMMISSION OFFICE OF ENFORCEMENT in the Matter of: ) Docket No. 50-325

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Carolina Power & Light Company ) Enforcement Action 88-316 1 (Brunswick Steam Electric Plant )

Unit No. 1) ) ,

RESPONSE OF CAROLINA POWER & LIGHT COMPANY TO THE NOTICE OF VIOLATION AND PROPOSED IMPOSITION OF CIVIL PENALTY t DATED MARCH 16, 1989 ,

1 Transmittal Letter Attachment 1 - 2.201 Reply I

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3 ATTACHMENT 1 Carolina Power & Light Company Brunswick Steam Electric Plant Reply to Notice of Violation Enforcement Action 88-316 Inspection Report Number 50-325/88-45 I. INTRODUCTION In accordance with 10CFR2.201 of the Commission's Rules ac;d Practice ar !

Procedure, as described in the NRC Staff's March 16, 1989 letter transmitting the subject Notice of Violation, Carolina Power & Light Compcny (CP&L) hereby replies to the cited Notice of Violation and Proposed Imposition of Civil Penalty ("NOV").

II. REPLY TO INDIVIDUAL ALLEGED VIOLATIONS In the NOV, the NRC Staff identified two alleged Severity Level III violations, denominated as A and B. In this response, for each alleged violation, CP&L 4111 (1) admit the allegations, (2) provide the reason for the violation, (3) identify the corrective steps taken and the results achieved, and (4) state further actions to be taken and the date when full compliance will be achieved.

A. Alleged Violation Relating to the Operability of the Standby Gas Treatment System (A)

1. The NOV states:

Technical Specification 3.6.6.1 requires that two independent standby gas treatment trains be operable when irradiated fuel is handled in the secondary containment.

Contrary to the above, both trains of the standby gas treatment system were inoperable while ' adiated fuel was handled in the secondary containmet- ' rom December 11-14, 1988. Both standby gas eatment inlet isolation dampers, 1C-BFV-RB and 1G-BFV-RB, were shut, isolating both trains.

This is a Severity Level III violation (Supplement I).

(Civil Penalty - $100,000)

(272CRS)

2. CP&L's Response to A

a. Admission of Violation: CP&L admits that from December 11-14, 1988, both trains of the standby gas treatment (SBGT) system were inoperable while irradiated fuel was handled in the secondary containment. Both SBGT inlet isolation dampers, 1C-BFV-RB and 1G-BFV-RB, were only open approximately 5%, therefore effectively isolating both trains. CP&L admits that this constitutes a violation of Technical Specification 3 6.6.1.

b. Reason for the Violation: As noted in the enforcement conference and Licensee Event Report 1-88-032, the investigation into the event identified several causal factors leading up to this loss of secondary containment. These included: design deficiencies with the VC"e position indication; inadequate procedural guidance on system restora.'ra 'ollowing testing; inadequate communications between members of the Operations staff when restoring the system to its standby lineup; and inadequate attention to detail while making plant tours (failure to identify the valves being out of position by motor control center (MCC) valve indication).

On December 5,1988, a clearance was issued to allow perfor aance of Periodic Test (PT)-15.1 3, Standby Gas Treatment System Helium Leak Detection Test, on the suction piping of the SBGT system. This test requires that the inlet valves to the SBGT trains be shut with the outlet valves open. This evolution must be performed manually as the centrol switch which operates these valves operates both the inlet and outlet valves together. On December 11, 1988, the test was completed, and the clearance was removed.

While removing the clearance on the inlet valves, the Auxiliary Cperators (A0s) manually operated the inlet volves off the closed seat (the valves had been manually torqued shut). The valves were not manually restored to the full open position because the A0s thought that the Control Operator (CO) would fully open the valves with the Control switch. There were no communications between the A0s and the CO on the positioning of the inlet valves. Later, the A0s verified the restored lineup in accordance with PT-15.1.3, by using the indications provided on the Reactor-Turbine Generator Board (RTGB). As they had manually opened the inlet valves greater than the closed position limit switch (approximately 5% open), the single indication on the RTGB which reflects the position on the inlet and outlet valve for each train showed open.

A review of the design logic of the inlet and outlet valve position indication determined that the indication position on the RTGB or at the local control panel may not reflect the actual position of these valves. If one of the two valves has its open limit switch actuated and the other valve is open beyond the closed limit switch, the indication provided is "0 PEN." The same is true for valves in the closed position, in that if one valve has actuated its closed limit switch and the other valve is closed below its open limit switch, the indication is " CLOSED." If one valve had actuated its open limit switch and the other valve had actuated its closed limit switch, there would be no indication on the RTGB. Likewise, if both valves were positioned between the open and closed limit switches, dual indication would be provided on the PTGB.

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, As noted, the indication on the RTGB and the local control patiel

, indicated that both valves were open. There are two additional locations where valve position can be verified: locally at the valves, and' locally on the MCC for each valve. The location of these valves makes it improper to expect that the incorrect position of the inlet valves be icentified by local observation; however, the indicating lights located on the MCCs should have been identified by the operations or plant staff during normal plant tours.

With the valve positioned between the open and the closed limit switches, the valve pcsition indication on the valve breaker compartment for each valve indicated both open and closed (dual indication). This was identified by the Resident Inspector as noted.

In 1984, it was identified that the valve automatic opening logic was different between Unit 1 and Unit 2. On Unit 2, the inlet valves receive an automatic open signal on a SBGT system initiation whereas this logic is not part of the Unit 1 design. There is no requirement for the automatic opening signal; it was just a feature which was incorporated in the Unit 2 design. At that time, the logic for Unit 1 was reviewed to determine if a design change was desired to make the Unit 1 valves automatically open. It was decided to leave the logic as is, as the inlet and outlet valves were design'ed to be closed only for maintenance activities. Training was provided to the Operations staff concerning this design difference, however, this design difference did not have a direct effect on this event. A review of the valve restoration section of PT-15.1 3 determined that a caution was not provided which identified that the position of the inlet and outlet valves could not be verified by RTGB indication. This caution had been added to the SBGT Operation Procedure (0P) after the indicating logic design problem was identified in 1984. Had this caution been included in the PT or had the PT referenced the OP for valve restoration, the valve restoration process would have identified the out of position inlet valves. Further procedural reviews indicated that the fuel sipping procedure did not require verification of SBGT standby line up prior to fuel movement. i Modifications have been completed on both units which correct the RTGB indications. As a result of these modifications, procedural changes to PT-15.1 3 are rot considered necessary.

c. Corrective Steps Taken and Results Achieved: Plant modifications have been completed which provide an accurate indication on the RTGB and the local control panel for the inlet and outlet valves. That modification provides for an open (red) indication when both valves are open, a closed (green) indication when both valves are closed, and no indication when either valve is in the intermediate position.

To assist Operations and plant personnel in identifying potential problem of this nature, SBGT breaker compartments as well as other selected site load breakers have been labeled to reflect the normal expected position of that component. With these labels, it is easier to identify a component being out of its expected position at the MCC. >

The Plant General Manager conducted a briefing for each of the Operations shifts concerning these two violations in December 1988. Each briefing lasted l 30 to 45 minutes and typically included the Shift Operating Supervisor, the l

( Shift Foremen, the Senior 7ontrol Operators, and Control Operators, the

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Aux,iliary Operators, and other shift support personnel. The briefing included

^ : discussions on: (1) a review of this event; (2) that plant performance is directly dependent on plant personnel performance; (3) the need to take the time to do the job right; (4) plant professionalism and self discipline to high personal standards; (5) the need to always question indications / activities in the field which do not appear correct, and (6) properly communicating and operating by "doing what you say--saying what you do." In addition, a training session was provided during the first quarter of real time training on the proper methods of communicating. This briefing also discussed proper methodology of conducting plant tours.

A review of the RTGB for other indications which may not be reflective of the actual condition / position was performed by Operations personnel.

Correction of those indications has been assigned to the engineering section. Until those. corrections are completed, a periodic independent local verification has been established to assure positive control is maintained by the Operations staff.

The Training Unit has included this event in its lesson plan for Secondary Containment.

d. Corrective Actions Which Will Be Taken and Date When Full Compliance Will Be Achieved: The Technical Suppo'rt Unit is reviewing the list of indications on the RTGB, developed by Operations, which may not be reflective of actual cendition/ position. The schedule for corrective actions will be completed by June 1, 1989. In addition, the fuel sipping procedure will be revised to require verification of SBGT operation prior to the next use of that procedure. This is expected to be the Unit 2 refueling outage scheduled for September 9, 1989 B. Alleged Violation Relating to Secondary Containment Isolation Dampers (B)

1. The NOV states:

Technical Specification 3.6.5.2 requires that the secondary containment isolation dampers 1A-BFIV-RB, 1B-BFIV-RB, 10-BFIV-RB, and 1D-BFIV-RB be operable when irradiated fuel is being handled in the secondary containment.

Contrary to the above, the secondary containment isolation dampers were open with air isolated from their actuators, rendering the dampers inoperable while fuel was being handled in the secondary containment from December 11-14, 1988.

This is a Severity Level III violation (Supplement 1).

(Civil Penalty - $50,000)

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(272CRS)

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2. CP&L's Response to B

a. Admission of Violation: CP&L admits that from December 11-14, 1988, the secondary containment isolation dampers 1A-BFIV-RB, 1B-BFIV-RB,1C-BFIV-RB, and 1D-BFIV-RB were open with air isolated from their actuators, rendering the dampers inoperable. CP&L admits that this constitutes a violation of Technical Specification 3 6.5.2.

b. Reason for the Violation: The root cause of this event was several design deficiencies with the secondary containment dampers. A contributing cause was an operator error by a Senior Control Operator (SCO) in the initiation of a System clearance on one division of instrument air.

As noted in the Enforcement Conference and Licensee Event Report 1-88-034, the investigation into this event determined that the secondary containment dampers were not designed in accordance with the requirement of the plant Safety Analysis Report (SAR). The SAR dictates that safety systems be designed and divided such that a single active failure cannot render inoperable the safety function of that system. Included within a single active failure is an operator error.

The secondary containment damper system is comprised of two inlet dampers in series and two exhaust dampers in series. These dampers use instrument air to operate (isoitte) and have accumulators installed to insure a supply of air is available to isolate and maintain the dampers closed should the air system be lost. The investigation determined that all four of the dampers (Division I and II) were supplied by the Division I instrument air system, and that the accumulators would leak down to a level where sufficient operating pressure was not available if the instrument air system were isolated. This design allowed a single active failure, operator error, to defeat the safety function of the secondary containment damper system.

The original design of the dampers did not allow for the loss of air for an extended period of time. The damper actuators can be purchased with a handwheel or a spring return (failed closed) mechanism. Because the original specifications requested manual operation, a return spring was not provided.

The system could have been provided with a positive closure system that would have caused the air operator to close the valves on low instrument air pressure; however, because of the existence of redundant air compressors, large receiver tanks and the existr.nce of a connection from the containment atmospheric dilution (CAD) nitrogen storage vessel for long-term supply, the original system design did not address the loss of instrument air as a credible event. Plant modifications and evaluations performed in the 1981-1983 time frame both removed the CAD nitrogen supply and downgraded the air system from non-interruptible instrument air to interruptible instrument air. The evaluatio: which downgraded the air system incorrectly identified the dampers as " fail-aare" (close components).

The personnel error involved a Senior Control Operator reviewing a clearance on the Division I instrument air header to allow modifications on that system. This review was quit e complicated and took several hours to complete. While reviewing the plant drawings for this clearance, he failed to recognize that air to the secondary containment dampers would be isolated. It should be noted that even if he had recognized the dampers as a load, he l

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1 thought that they would still have isolated if required (single active failure proof). Had he recognized them as a load, he would have taken the proper i

action as required by the Technical Specifications prior to removing them from l

service.

Additional design reviews determined that should the dampers close on an actuation signal and the instrument air system were lost, there would be no way of assuring that the dampers remained closed, as air pressure both closes the valve and keeps it seated. This review determined that on a loss of air, the dampers c>uld relax on the closed seat, thereby potentially loosing secondary containment integrity,

c. Corrective Steps Taken and Results Achieved: A Standing Instruction was initiated that requires that the secondary containment dampers be manually closed on a loss of instrument air. When the vulves are manually closed, the manual closing mechanism assures that the valve remains seated independent of the instrument air system. In addition, a caution tag was hung on those Unit 2 instrument air valves which, if shut, could cause a loss of i the air supply to the damper without an alarm. This has been done to ensure control of these valves until the air system is modified during the next refueling outage.

In the event of a loss-of-coolant accident (LOCA) with a loss of off-site power, a temporary diesel powered air compressor has been established to allow operations personnel the ability to reestablish instrument air within two hours, which is prior to the accumulators on the dampers bleeding down to an inoperable level. This time requirement was determined for both Unit 1 and Unit 2 by system leak testing.

.The design for the Unit 1 dampers was modified during the recent refueling / maintenance outage to restore the dampers to operable status. The modification separates the instrument air to the dampers into divisions to prevent a single active failure and provides a latching mechanism to ensure that the dampers remain seated.

Administrative Instruction (AI)-58, Equipment Clearance Procedure, has been revised to require that clearance reviews of this type receive a second assessment by a licensed individual. In addition, two task forces have been established in an effort to resolve clearance problems. One task force is made up of Operations personnel and is to report to the Manager-Operations.

The other task force is to report to the Plant General Manager and is comprised of unit managers or supervisors from Operations, Maintenance, Technical Support, and Outage Management. This activity was also identified in response to a violation identified in NRC Inspection Report 89-02.

Activities being conducted in accordance with Generic Letter 88-14 identified this design problem in parallel with this event. In accordance with that generic letter, other safety-related air-operated actuators have been or are being tested and field verified to ensure that they fulfill their intended safety functions.

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As previously noted, the Plant General Manager conducted a briefing for each of the Operations shifts concerning these two violations in December 1988. Each briefing lasted 30 to 45 minutes and typically included the Shift Operating Supervisor, the Shift Foremen, the Senior Control Operators, the Control Operators, the Auxiliary Operators, and other shift support personnel. The briefing included discussions on: (1) a review of this event; (2) that plant performance is directly dependent on its personnel performance; (3) the need to take the time to do the job right; (4) plant professionalism and self discipline to high personal standards; and (5) the need to always question indications / activities in the field that do not appear correct.

The Training Unit has included this event in the lesson plan for Secondary Containment.

d. Corrective Steps Which Will Be Taken and Date When Full Compliance Will Be Achieved: Modifications to the Unit 2 secondary containment dampers will be completed during the upcoming refueling /

maintenance outage, scheduled to begin in September 1989. The results of the two clearance task forces will be completed by May 31, 1989 These results will also provide a schedule for completing any required actions. A supplemental response will be provided by June 30, 1989 providing the results of the task forces and a schedule for implementation.

As noted in our response to EA 88-149, the Systems Engineering program is currently being implemented. In response to both of these violations, the system engineer was immediately notified of the initial problem and was instrumental in the event assessment and subsequent corrective actions. A final implementation schedule will be provided by April 28, 1989, as committed in that response.

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