ML20204J399

Insp Repts 50-324/86-16 & 50-325/86-15 on 860601-30. Violations Noted:Failure to Take Adequate Corrective Action on Jumper Control & Failure to Declare Support Inoperable When Required

ML20204J399
Person / Time
Site:	Brunswick
Issue date:	07/14/1986
From:	Fredrickson P, Fredrickson R, Garner L, Mellen L, Ruland W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20204J372	List: ML20204J367 ML20204J382 ML20204J399
References
50-324-86-16, 50-325-86-15, NUDOCS 8608110078
Download: ML20204J399 (9)

See also: IR 05000324/1986016

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p Krio UNITED STATES -

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101 MARIETTA STREET,N.W. *

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Report Nos. 50-325/86-15 and 50-324/86-16. *

Licensee: Carolina Power and Light Company t,

P. O. Box 1551 t

Raleigh, NC 27602

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Docket Nos.: 50-325 and 50-324 License Nos.:'DPR-71 and DPR-62

Facility Name: Brunswick 1 and 2

Inspection Conducted: June 1-30, 1986

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Inspectors: h b 7 //9!N

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M S. Mellen i Date Signed

Approved by:

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E. Fredrickson, Section Chief

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Date Signed

YDE \.Dvision of Reactor Projects

SUMMARY

Scope: This routine safety inspection involved the areas of followup on

unresolved item, maintenance observation, surveillance observation, operational

safety verification, and onsite followup of events.

Results: Two violations - failure to take adequate corrective action concerning

jumper control; failure to follow procedures by not declaring a support

inoperable when required.

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REPORT DETAILS

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1. Persons Contacted - Licensee Employees

P. Howe, Vice President - Brunswick Nuclear Project

C. Dietz, General Manager - Brunswick Nuclear Project

T. Wyllie, Manager - Engineering and Construction

E. Bishop, Manager - Operations

L. Jeres, Director - Quality Assurance / Quality Control (QA/QC)

R. Helme, Director - Onsite Nuclear Safety - BSEP

J. Chase, Assistant tc General Manager

J. O'Sullivan, Manager - Maintenance

G. Cheatham, Manager - Environmental & Radiation Control

K. Enzor, Director - Regulatory Compliance

B. Hinkley, Manager - Technical Support

R. Groover, Manager - Project Construction

A. Hegler, Superintendent - Operations

W. Hogle, Engineering Supervisor

W. Tucker, Engineering Supervisor

B. Wilson, Engineering Supervisor

R. Creech, I&C/ Electrical Maintenance Supervisor (Unit 2)

R. Warden, I&C/ Electrical fiaintenance Supervisor (Unit 1)

W. Dorman, Supervisor - Quality Assurance (QA)

W. Hatcher, Supervisor - Security

R. Poulk, Senior NRC Regulatory Specialist

W. Murray, Senior Engineer - Nuclear Licensing Unit

Other licensee employees contacted included construction craftsmen,

engineers, technicians, operators, office personnel, and security force

members.

2. Exit Interview (30703)

The inspection scope and findings were summarized on July 3, 1986, with the

general manager. The licensee acknowledged the findings without exception.

The licensee did not identify as proprietary any of the materials provided

to or reviewed by the inspectors during the inspection.

3. Followup on Previous Enforcement Matters (92702)

Not inspected.

4. Followup on Unresolved Item (92701)

(Closed) Discrepancies Found After In-service Inspection (ISI)

(324/86-15-02). This item identified two conditions on safety-related

supports which required further review. As described in the subject report,

fixed hanger 2E11-21FH62 located on the Low Pressure Coolant Injection

(LPCI) pathway was missing a nut. The licensee has acknowledged that the

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missing support item could impair proper functioning of the support. With

the nut missing, there was no means to prevent the stud which attaches the

hanger to the pipe clamp from coming out and rendering the hanger

inoperable. The unit was in cold shutdown at the time the inspector

observed the missing item. Procedure PT-91.0.37, Residual Heat Removal

(Ell), Class 2, Loop B, VT-3/VT-4 Examination of Component Supports, step

II.B.2, requires a support to be declared inoperable if there is a missing

support item that could impair proper functioning of the support. The

safety-related support was not declared inoperable. This failure to follow

procedure PT-91.0.37 is a violation of Technical Specification 6.8.1.c,

which requires procedures to be implemented for surveillance of

safety-related equipment. This is a violation (324/86-16-01).

The second item involved anchor bolts associated with the base plate on the

High Pressure Coolant Injection (HPCI) snubber support 2E41-61SS99. One

bolt was found to be located such, that an unfilled hole partially

overlapped with the one the bolt was in. The licensee verified the torque

on the remaining three bolts and verified that the support was adequate to

perform its function. However, because it did not conform to the present

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installation specification No. 248-107, Installation of Seismic Pipe

Supports and Miscellaneous Structural Steel, the licensee removed the base

plate and re-oriented it such that all four anchor bolts would meet current

criteria. The work plans or other installation documentation which

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installed the original support are not available. I.E. Bulletin 79-02 and

79-14 inspection records note no deficiencies with the support. The

licensee could not provide any documentation showing that the support has

been modified. The inspector has concluded that this was probably an

original installation problem because that type of anchor was used only

during construction. Subsequent modifications have used a different anchor.

The inspector also observed that the In-Service Inspection (ISI) performed

on this support during the present refueling outage also failed to identify

, the condition. PT-91.0.24, High Pressure Coolant Injection (E41), Class 2,

VT-3/4 Examination of Component Supports, requires a support to be declared

inoperable if there are cracks in the concrete greater than 1/16 inch in

width, which emanate from the anchor bolt hole. However, the licensee's

employee responsible for the ISI program indicated that an unfilled drilled

hole is not a crack and thus not reportable under the ASME Section XI ISI

program. No violation is being issued because the support was found

operable based on the licensee's calculations. The inspectors discussed

with management the inappropriateness of such a narrow interpretation of the

regulations.

The inspector accompanied two structural engineers when they took

measurements on the anchor bolt holes. One engineer stood on a 3 Kip

hydraulic snubber to examine the anchor bolt holes. The inspector reported

the unsound practice to licensee management.

One violation and no deviations were identified.

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5. Maintenance Observation (62703)

The inspectors observed maintenance activities and reviewed records to

verify that work was conducted in accordance with approved procedures,

Technical Specifications, and applicable industry codes and standards. The

inspectors also verified that: redundant components were operable;

administrative controls were followed; tagouts were adequate; personnel werel

qualified; correct replacement parts were used; radiological controls were

proper; fire protection was adequate; quality control hold points were

adequate and observed; adequate post-maintenance testing was performed; and

independent verification requirements were implemented. The inspectors

independently verified that selected equipment was properly returned to

service.

Outstanding work requests were reviewed to ensure that the licensee gave

priority to safety-related maintenance.

The inspectors observed / reviewed portions of the following maintenance

activities:

MI-10-3G Traversing In-Core Probe Calibration System.

WR&A 85-ABFBI TIP Calibration System.

No violations or deviations were identified.

6. HPCI Overspeed Trip Unit Inoperability (62703)

On June 27, 1986, the licensee found the Unit 1 High Pressure Coolant

Injection (HPCI) system mechanical overspeed trip unit inoperable. The

licensee had performed an inspection of the trip unit as a result of GE

Rapid Information Communication Services Information Letter (RICSIL) No. 004

to detect swelling of the tappet assembly. The licensee had found on

June 13, 1986, that the bottom of the tappet was gouged. They contacted the

turbine vendor (Terry). Based on the gouge in the tappet, the vendor

recommended an inspection of the governor weight assembly mounted on the

turbine shaft. The licensee found that the upper adjusting screw and spring

were no longer in place. These parts were found in the lower casing. The

turbine and shaft were not damaged. A similar inspection on the Unit 2

turbine found the mechanical overspeed device intact. The licensee repaired

the Unit 1 overspeed device with new parts. The licensee believes that the

event was caused by failure of a set screw to retain the assembly. The set

screw location made it difficult to tighten. The mecnanical overspeed trip

had been modified on Unit 1 during the 1985 refueling outage and in 1984 on

Unit 2 in response to GE Service Information Letter No. 392.

No violations or deviations were identified.

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7. Surveillance Observation (61726)

The inspectors observed surveillance testing required by Technical

Specifications. Through observation and record review, the inspectors

verified that: tests conformed to Technical Specification requirements;

administrative controls were followed; personnel were qualified;

instrumentation was calibrated; and data was accurate and complete. The

inspectors independently verified selected test results and proper return to

service of equipment.

The ir.spectors witnessed / reviewed portions of the following test activities:

PT-15.8 Post Accident Sampling System Valve Operability Test.

PT-25.2P Triaxial Time-History Accelerographs Channel Check.

PT-34.33.2.1 Fire Detection Instrumentation Operability Test,

Administration Building, Switch Yard Relay House.

IMST-HPCI13M HPCI Steam Leak Detection Channel Functional Test.

1MST-HPCI15M HPCI Steam Leak Detection Channel Functional Test.

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IMST-HPCI24R HPCI Steam Leak Detection Channel Calibration.

1MST-RCIC13M RCIC Steam Leak Detection Channel Functional Test.

1MST-RPS27R RPS Scram Discharge Volume High Water Level Channel

Functional Test and Channel Calibration.

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No violations or deviations were identified.

8. Operational Safety Verification (71707) (71710)

The inspectors verified conformance with regulatory requirements by direct

observations of activities, facility tours, discussions with personnel,

reviewing of records and independent verification of safety system status.

The inspectors verified that control room manning requirements of 10 CFR

50.54 and the technical specifications were met. Control room, shift

supervisor, clearance and jumper / bypass logs were reviewed to obtain

information concerning operating trends and out of service safety systems to

ensure that there were no conflicts with Technical Specifications Limiting

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Conditions for Operations. Direct observations were conducted of control

room panels, instrumentation and recorder traces important to safety to

verify operability and that parameters were within Technical Specification

limits. The inspectors observed shift turnovers to verify that continuity

of system status was maintained. The inspectors verified the status of

selected control room annunciators. Results of the jumper log review are

contained in paragraph 9.

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Operability of the Unit 1 Residual Heat Removal System Loop B and the Unit 2

Core Spray Loop A trains was verified by insuring that: each accessible

valve in the flow path was in its correct position; each power supply and

breaker, including control room fuses, were aligned for components that must

activate upon initiation signal; removal of power from those ESF

motor-operated valves, so identified by Technical Specifications, was

completed; there was no leakage of major components; there was proper

lubrication and cooling water available; and a condition did not exist which

might ~ prevent fulfillment of the system's functional requirements.

Instrumentation essential to systein actuation or performance was verified

operable by observing on-scale indication and proper instrument valve

lineup, if accessible. One item involving improper locking of valves is

discussed in paragraph 10.

The inspectors verified that the licensee's health physics

policies / procedures were followed. This included a review of area surveys,

radiation work permits, posting, and instrument calibration.

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The inspectors verified that: the security organization was properly manned ,

and security personnel were capable of performing their assigned functions;

persons and packages were checked prior to entry into the protected area

(PA); vehicles were properly authorized, searched and escorted within the

PA; persons within the PA displayed photo identification badges; personnel

in vital areas were authorized; effective compensatory measures were

employed when required; and security's response to alarms was adequate.

The inspectors also observed plant housekeeping controls, verified position

of certain containment isolation valves, and verified the operability of

onsite and offsite emergency power sources.

During routine tours of the facility, the following items were observed and

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called to the Licensee's attention:

On June 29, 1986, the inspector determined that the 18 conventional service

water pump motor upper bearing oil cooler discharge line was abnormally warm

as compared to the others in service. The licensee determined that there

was little or no flow through the cooler and secured the pump. The cyclone

separator which supplies water to the cooler was found to be blocked. The

pluggage was most likely oyster shells. Auxiliary operators are now

checking operation of the separators on their normal rounds.

Removal of the pump from service, left four pumps in service. Technical

Specifications were met in that only three pumps are required for

operability.

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In addition, the inspector observed that 2A nuclear service water pump

appeared to show excessive vibration. The licensee took measurements and

determined that the vibration had approximately quadrupled since the last

reading. Data is taken monthly. Disassembly revealed that the bearings

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were severely worn. The licensee attributed the condition to normal end of

life. This left four pumps in service on Unit 2.

During the month, the inspector observed a condition in which equipment

which was free to move was left in the vicinity of safety-related equipment.

A battery discharge tester approximately 3'x3'x6' and weighing several

hundred pounds was left within 3 feet of the 2A battery, the 250 volt

emergency Division I D.C. supply. The tester is on rollers and was

unsecured. The licensee chained the tester to the wall. A recommendation

to provide a seismically designed restraining device for the tester was

discussed in a memorandum from R. E. Helme, Director of Onsite Nuclear

Safety (ONS), to J. L. Harness, Manager Plant Operations, dated April 26,

1983. The item is still open. Additional inspection is necessary to

determine what actions were taken in response to the ONS concern. This

subject will be addressed in next month's resident inspector report.

No violations or deviations were identified.

9. Jumper and Wire Removal (71710)

A review of the electric jumper log was conducted June 9,1986. Jumper

No. 2 was missing from the storage cabinet but was not signed out. This

condition had previously been identified by Quality Assurance and a

Non-Conformance Report (NCR) No. S-86-028 had been issued on May 29, 1986.

Notations in the log indicated that jumpers Nos. 27, 28, 29, 32, 33, 46, 76

and 79 had been missing prior to September, 1984. A log entry dated

April 4, 1986, listed jumpers Nos. 201, 293, 330 and 345 as missing.

With the assistance of a licensed operator, the inspector performed a field

verification of jumpers installed in the Unit 2 control room back panels.

The inspector located in panel P604, jumpers 33 and 46, which were listed as

missing prior to September, 1984. These were tagged as having been

installed on May 3,1983, per plant modification 77-032. Subsequent review

by the licensee revealed that these were in a non safety-related

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application.

The inspector discussed the above items with the muager of operations. At

that time, in response to the NCR, the licensee was in the process of

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searching for jumper No. 2. The search was expanded to locate and record

installed jumpers and wire lifts in safety-related applications. The search

included pa,els in the control room, Unit I and 2 reactor buildings and the

diesel generator building. The search resulted in locating four additional

jumpers and more than 50 wire lifts which were not documented properly.

None of the jumpers found were determined to be in safety-related

applications. The jumpers not located have been presumed to have been

destroyed or installed in some non-safety-related application. The wire

lift data is still being reviewed. To date, all the wire lifts researched

appear to have been authorized per a plant modification, a maintenance work

request or an engineering work request. Results of the search are

documented in the response to the NCR.

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As noted in the NCR, failure to control jumper No. 2 is a failure to follow

procedure AI-59, Jumper, Wire Removal and Designated Jumper Administrative

Instruction. This is a violation of Technical Specification 6.3.1.a, which

requires procedures listed in Appendix A to Regulatory Guide 1.33, November,

1972, be implemented. The eight above-mentioned jumpers listed as missing

prior to September, 1984 (the time of discovery), also involved failure to

follow AI-59.

10 CFR 2, Appendix C, Section V.A., says a Notice of Violation will not

generally be issued if the violation was identified by the licensee and that

it was not a violation that could reasonably be expected to have been

prevented by the licensee's corrective action for a previous violation. The

corrective action for the September,1984 events should have prevented the

violation discovered in May, 1986. Thus a Notice of Violation is being

issued. Normally, the violation would be concerning failure to follow

procedures; however, in this case because the licensee has made two attempts

at corrective action within two years concerning controlling jumpers and

maintaining proper records in this area and yet continues to have difficulty

as exerplified by jumper No. 2, a Notice of Violation will be issued for

failurc to take adequate corrective action. The first corrective action was

taken in September, 1984. This, including moving the jumper cabinet to the

Shift Operator Supervisor's (SOS) office and assigning the responsibility

for maintaining the jumpers to the shift support staff in the SOS's office.

The second corrective action occurred approximately a year later in response

to an internal operations audit. On September 3, 1985, an audit reported

that jumpers Nos. 92,109,118, 214 and 215, were each assigned twice and

that duplicate jumper logs existed. Again, the licensee re-assigned the

responsibility for maintaining the jumper program and provided training in

the area.

10 CFR 50, Appendix B, Criterion XVI, Corrective Action, requires conditions

adverse to quality be promptly identified and corrected. Furthermore, it

states that, "In case of significant conditions adverse to quality, the

measures shall assure that the cause of the condition is determined and

corrective action taken to preclude repetition." The inability to determine

if a jumper is installed in a safety-related application, installed in a

non-safety-related application or destroyed is a significant condition

adverse to quality.

The failure of the above-mentioned measures to preclude the violation

associated with jumper No. 2 is a violation of 10 CFR 50, Appendix B,

Criterion XVI (325/86-15-01 and 324/86-16-02).

One violation and no deviations were identified.

10. Locked Valves (71707)

On June 13, 1986, during walkdown of the Unit 1 Residual Heat Removal (RHR)

Loop B, the inspector found the E11-F018D Valve not locked. This is the

manual isolation of the minimum flow line for the D RHR pump. The valve was

open as required. Operating proceiure OP-17, Residual Heat Removal System

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Operating Procedure, valve lineup checklist page 118 of revision 8 dated

May 5,1986, requires the valve to be locked open. The checklist completed

September, 1985, prior to unit startup from refueling, shows on page 128 of

revision 6 of OP-17, that the valve was locked open and had been

independently verified as such. The time at which the valve was unlocked is

not known. Technical Specification surveillance requirement 4.5.3.2.a.2,

requires each valve in , the flow path that is not locked, sealed, or

otherwise secured in position be verified once every 31 days to be in its

correct position. PT-08.1.3, LPCI/RHR System Component Test, which

implements the surveillance, assumes that E11-F0180 is locked and thus does

not include it in the 31 day verification. Hence, failure to maintain the

valve as locked, can result in the surveillance not being performed

correctly. The licensee has determined that the minimum flow line must be

operable for the RHR pump to be operable. A Surveillance Field Report (SFR)

No.86-016 issued June 9, 1986, was amended by Quality Assurance (QA) to

incorporate this unsecured valve. Cause and corrective action will be

tracked under the SFR.

No violations or deviations were identified.

11. Followup on Events at Operating Reactors (93702)

On June 18,1936, at 8:11 a.m. , Unit 2 reactor scrammed from 55% power due

to low water level . All engineered safety features functioned as designed.

No automatic or manual initiation of emergency core cooling systems were

required. Reactor pressure and water level were controlled using the steam

dumps and condensate /feedwater systems. The unit was placed in cold

shutdown for a scheduled six day outage to recouple a control rod and

balance air flows inside the drywell.

The trip was caused by partial diversion of feedwater while attempting to

place the second feedpump in service. The discharge check valve of B

feedpump was stuck open. When the B discharge valve was opened, flow from

the A pump flowed through the B discharge valve and recirculation valve back

to the condenser. The partial loss of feedwater caused the low level scram.

Disassembly of the check valve revealed the set screw which holds the hinge

pin in place was not longer sufficiently engaged to prevent the hinge pin

from working out. The hinge pin had slipped out of position thereby

allowing the disc to cock to one side and not seat properly. The inspector

has no further questions concerning this event. The unit was restarted on

June 27, 1986.

The inspector witnessed portions of the reactor startup. The inspector

verified that: the control rod withdrawal sequence was approved; the

startup was conducted using approved procedures and that activities were

conducted in accordance with approved procedures.

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In addition, the inspector reviewed the control board for abnormalities.

All abnormalities were clearly marked on the board with corrective actions

the operator should take in the event the tagged out or malfunctioning

equipment was needed.

No violations or deviations were identified.

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