ML20140G893

Insp Rept 50-155/97-04 on 970313-0429.Violations Noted. Major Areas Inspected:Operations,Maint & Engineering

ML20140G893
Person / Time
Site:	Big Rock Point File:Consumers Energy icon.png
Issue date:	06/10/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20140G871	List: ML20140G866 ML20140G885 ML20140G893
References
50-155-97-04, 50-155-97-4, NUDOCS 9706170127
Download: ML20140G893 (20)

See also: IR 05000155/1997004

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U.S. NUCLEAR REGULATORY COMMISSION ,

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REGION ll!  !

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Docket No: 50-155 ,

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License No: DPR-06

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Report No: 50-155/97004(DRP)

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l Licensee: Consumers Energy j

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Facility: Big Rock Point Nuclear Power Plant

Location: 10269 U.S. 31 North

Charlevoix, MI 49720

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Dates: March 13 - April 29,1997

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inspectors: R. J. Leemon, Senior Resident Inspector

1. N. Jackiw, Project Engineer

H. A. Walker, Reactor Inspector i

Approved by: Bruce L. Burgess, Chief i

Reactor Projects Branch 6

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9706170127 970610

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EXECUTIVE SUMMARY

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Big Rock Nuclear Power Plant

NRC Inspection Report 50-155/97004

l This routine inspection covered aspects of licensee operations, engineering, maintenance,

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and plant support.

,Qoerations

• The inspectors concluded that the activities associated with reactor plant startups

and shutdowns were appropriately conducted. No violations of NRC requirements

were identified. (Section 01.2)

• The inspectors identified that, in reviewing the work package, work control center

(WCC) personnel did not determine that tagging was required to test the amplidyne

controller. which resulted in the 138 KV line tone relay being damaged. On another

occasion, after WCC personnel had tagging removed from main steam isolation

j valve (MSIV) MO-7050 following stroke testing by operations personnel, WCC

personnel did not ensure that MO-7050 was re-tagged prior to maintenance

workers meggering the valve. (Section 01.3)

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• Operations department personnel correctly performed the hydrostatic testing of the

containment portion of the post incident system. (Section 01.4)

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Maintenance  !

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• Maintenance and surveillance activities were appropriately performed and

accurately documented. (Section M1.1) -

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l * The inspectors concluded that an electrician did not acquire the required. tagging

and clearance to test a coilin the amplidyne controller. This resulted in varistors on

the 138 KV line tone control panellocated in the control room to fail. This was a i

violation of Technical Specifications. (Section M1.2) l

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l * The inspectors concluded that maintenance personnel violated procedure l

requirements when meggering the MSIV-7050 motor without personnel protective

tagging and with the DC feeder breaker closed. (Section M1.3)

• To prevent further steam cutting darnage to backup core spray valves MO-7071

and VPI-303 and the increase in unidentified primary system leakage, the licensee

shut the plant down and refurbished the valves. (Section M1.4)

• The licensee unknowin0l y operated the station with protective devices for direct

current breakers 72-11 and 72-12 different than the original plant design. (Section

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• Indications were identified on diesel fire pump (DFP) relief valve RV-5062 springs;

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however, the DFP relief valve had been operable. The licensee verified that there

were no indications on a new spring and the spring was installed in the diesel fire

pump relief valve. (Section M1.6)

• The licensee promptly shut the plant down upon discovery of malfunctioning of the

No. 2 recirculation pump inner seal. Maintenance activities observed by the

inspectors related to the job were appropriately performed. (Section M1.7) '

Enoineerino

• The system modification design package to upgrade the portion of the fire

l protection / post incident system inside containment to a design pressure of 200 psig

l appeared to be good. The installation of 200 psig relief valves inside containment  :

was made to prevent the actuation of these relief valves during fire pump testing l

and reduce the leakage problem through these valves.

The 1955 ASME Boiler and Pressure Vessel Code, which applies to Big Rock Point,

allows the design pressure to be exceeded, by a limited amount, for short periods

of time. The external portions of this system appeared to meet this criteria.

(Section E1.1)

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l * The inspectors found that the licensee's corrective actions for previous condition

j reports relating to clearance and tagging orders were ineffective. (Section E1,.2)

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Reoort Details

Summarv of Plant Status

On March 2,1997, the reactor was shutdown and the plant was taken to cold shutdown

to repair backup core spray valves MO-7071 and VPI-303, which were experiencing a

small amount of steam leaking through them. Following repairs to the valves, the plant

remained in cold shutdown while performing an analysis to re-rate the containment portion

of the post incident system from 150 psig to 200 psig. Upgrade work on the post incident

system was completed, and on April 20,1997, at 6:50 a.m., the reactor was taken

critical. At 12:30 p.m., with reactor pressure at 580 psig, the recirculation pump's seal

flows were being adjusted when the operator determined that the inner seal on the No. 2

recirculation pump (RCP) was not functioning properly. At 1:47 p.m., the reactor was

shutdown by a manual scram from 1 per cent power to repair the RCP seal. On April 27,

1997, at 3:45 p.m., the reactor was again taken critical, and on April 28,1997, at 5:25

a.m., the main generator breaker failed to close. At 10:59 a.m. the turbine was stopped,

and at 5:14 p.m. the reactor was shut down. The licensee was repairing the failed main

generator breaker at the end of the inspection period.

1. Operatioris

01 Conduct of Operations

01.1 General Comments (71707)

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Using inspection Procedure 71707, the inspectors conducted frequent reviews of

ongoing plant operations. Specific events and findings are detailed in the sections

below.

01.2 Ooservations of Plant Startuos and Shutdowns

a. Insoection Scooe

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The inspectors attended infrequently performed test and evolution briefings (IPTE) ,

conducted by the outage manager and reactivity management briefings conducted I

by the shift supervisor (SS). The inspectors observed the licensee's startup and

shutdown activities.

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l b. Observations and Findinas i

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The inspectors observed reactor shutdowns and startups between March 2,1997, l

and April 28,1997 and the associated IPTE briefing. During these IPTE briefings,

the inspectors observed management stressing safety as the number one priority

and reminding the crew of their responsibility if an unsafe condition was identified.

The reactor engineer appropriately discussed what the expected critical rod notch

and startup step would be, and the reactivity value of the rod notches near the

critical position. The inspectors observed that during reactor startup, procedures

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were in-hand and being followed, two operators properly verified the control rod to

be moved and used repeat back communications, SSs provided good command and

control, and three way communications existed among all members of the operating l

crew. An extra operator, with no other duties, was assigned to continuously I

monitor the reactor control panels. I

c. Conclusions

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The inspector.s concluded that the activities associated with reactor plant startups l

and shutdowns were appropriately conducted. No violations of NRC requirements

were identified.

01.3 Taaaina Reauirements For Testina Eauioment Not identified by Work Control Center

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a. Insoection Scooe l

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The inspectors reviewed the work control center's (WCC) involvement related to

testing the amplidyne controller and meggering a main steam line isolation valve

(MStV) without the required tagging. The inspectors held discussions with the

WCC personnel and reviewed condition reports (CR), work orders (WO), and

tagging orders: l

• CR C-BRP-97-164: 125 VDC ground resulted in smoke in the )

control room

• CR C-BRP-97-165: Inadequate tagging for breaker functional test

• WO SPS-12611404: Functional inspection of circuit breaker 052-

2A24 and inspect and test / operate associated  !

contactor for amplidyne motor generator test l

• CR C-BRP-97-18: Auxiliary shutdown 125 VOC system ground

resulting from meggering MO-7050 1

• WO NSS-12710295: Assist with TR-390 (leak testing MSIV) with 1

installation and removal of test fixture

• Tagging Order Tagging MO-7050 (MSIV) WO 1270295

977-50133:

b. Observations and Findinas

WCC personnel consisting of a licensed reactor operator and a licensed senior

reactor operator reviewed WO SPS-12611404 for testing the 138 KV line

amplidyne breaker and controller. The inspector noted that the work planner did

not specify that tagging was required on the WO. Breakers were generally removed

from the motor control center and tested at a test stand, in some cases, the

controllers were part of the breaker and tagging would not be required. WCC

l personnel appeared to have the mind set that tagging was not required for testing

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breakers and controllers, and thus concluded that the WO was marked correctly.

The amplidyne controller for circuit breaker 052-2A24 was located external to the

breaker and had a separate 125 VDC breaker. The breaker configuration was

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indicated on a drawing attached to the WO. Following leak testing of MSIV MO-

7050, WCC personnel requested that maintenance workers clest the tagging on

i valve MO-7050 in order that operations personnel could strok's test the valve.

After stroke testing the valve, WCC personnel had scheduled meggering of MO-

7050 as part of post maintenance testing. WCC personnel failed to ensure that the

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breaker for MO-7050 was re-tagged prior to the maintenance workers meggering 7

the valve.

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l c. Conclusion

The inspectors identified that, in reviewing the work package, WCC personnel did

not determine that tagging was required to test the amplidyne controller, which

resulted in the 138 KV line tone relay being damaged. After WCC personnel had

removed the tags from MSIV MO-7050 following stroke testing by operations

personnel, WCC personnel did not ensure that MO-7050 was re-tagged prior to

maintenance wo kers meggering the valve (Reference Section M1.3).  !

01.4 Hvdrostatic Testina of Containment Portion of Post Incident System f

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a. Insoection Scooe

The inspectors monitored the hydrostatic testing of the containment portion of the

[ post incident system in preparation for re-rating the piping to 200 psig. The

inspectors attended pre-job briefings, reviewed procedure TV-40H-A, " Hydrostatic

Test of Post incident System in Containment," and observed hydrostatic testing of ,

the system. 1

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b. Observations and Findinos ,

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On April 15,1997, during a first attempt to test the containment portion of the  !

post incident system to 300-350 psig, boundary valves VFP-30 and VFP-29,  ;

between the fire and core spray systems, leaked back into the screen house portion 1

of the system. During the test when containment test pressure reached

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approximately 200 psig, the screen house portion of the system increased to 150

psig. The test was terminated, and the licensee redesigned the test and made

procedure changes to run the diesel fire pump with flow through the core spray

heat exchanger in order to limit the pressure in the screen house portion of the

system. On April 16, the test was rerun and the containment portion of the core

spray system was successfully tested to 315 psig. The inspectors observed

operators perform visualinspection of the containment portion of the post incident

system piping. Three minor packing leaks on fire hose stations were identified and

appropriately dispositioned.

During pre-job briefings, the inspectors noted that duties and responsibilities of the  !

SS and other personnel were well defined. The inspectors observed good in-hand-

use of the procedure by the auxiliary operator (AO) at the test pump, and the

supervisor performed on the job training for the AO. The inspector also observed

the AO perform continuous monitoring of the test pressure and parameters.

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c. Conclusion

Operations department personnel correctly performed the hydrostatic testing of the

containment portion of the post incident system.

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03 Operations Procedures and Documentation

03.1 Adhereng.e to Procedures

a. insoection Scona l

The inspectors reviewed the licensee's corrective actions regarding adherence to

procedure issues identified in Inspection Reports 50-155/97002(DRP) and 50-

155/97005.

b. Observations and Findinos  ;

The inspectors noted that the corrective actions taken by the licensee to address i

procedure adherence problems included better defining management's expectations l

in this area. The new expectations required that if work could not be performed as l

written, the work was to be stopped, and the procedure revised. The inspectors

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observed or reviewed procedure revisions identified after the new expectations

were instituted. The following procedure changes were made:

o Procedure O-TGS-1, C-2A, " Wide Range Monitor (WRM) Instrument Check

List," was revised to allow the operator to retest the monitor if necessary.

The test circuit resets the monitor to normal from the test position after 3-

minutes. If the operator did not complete the test in the 3-minutes, the

original procedure was not clear on how to precede,

o Procedure ALP-1.4, " Alarm Response Procedure for Feedwater Heaters High

Level," inas revised to indicate that feedwater heaters high level alarms were

normal and expected during plant startup activities. The procedure revision

provided information which allowed operators to verify that the alarm was

valid for existing plant conditions.

e Procedure SOP-13, " Turbine Generator System," was revised to add

amplidyne excitation control checks to ensure that the control circuit 1

l operates satisfactorily. On December 7,1997, the plant tripped '

I because the amplidyne control circuit failed. At that time, the

! procedure did not have steps to initiate amplidyne control circuit

checks.

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c. Conclusions

! The inspectors concluded that the licensee's new expectation for procedure

adherence was being followed by operation's personnel.

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11. Maintenance

M1 Conduct of Maintenance

M1.1 General Comments

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a. Insoection Scoce (62703) (61726)

The inspectors observed all or portions of the following maintenance and

surveillance activities:

Maintenance Activities

e WO FPS-12710399: Inspect DFP relief valve (RV-5062) spring

• WO PIS-12710406: Hydrostatic test of containment portion of core

spray system

o WO PCS-12611212: Remove and install No. 2 RCP seal

e WO MdS-12710295: Install and remove test fixture on MSIV MO-

7050

e WO EPS-12710234: Replaced standby diesel generator batteries

e WO EPS-12710142: Replaced all batteries in battery bank (UPS-C)

e WO NMS-12710235: Source range 7 detector position indication

incorrect with detector in the in position both

the in and out position indicators illuminated

l e WO PCS-12300908: Disassemble No. 2 RCP seal cartridge

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e WO SPS-12710347: Perform load test on breaker 072-12

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Surveillance Activities

• TR-88: Core spray and enclosure spray valve initiation and i

operability test

e TR-390: Leak testing the main steam isolation valve

e TV-26: Local leak rate testing

• TSD-07: Core spray pump run and test loop operation

b. Observations and Findinas

Maintenance and surveillance activities were reviewed against the FSAR and were

found to be satisfactorily performed. All observed work was performed with the

work package present and in active use at the job site. Supervisors and system

engineers monitored job progress, and appropriate radiation control measures were

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in place.

c. Conclusion

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Maintenance and surveillance activities were appropriately performed and

accurately documented.

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M1.2 Over Volteae of the 138 KV Line Tone Relav

a. Insoection Scope

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On March 6,1997, the inspectors responded to a fire alarm in the control room.

Thr,re was a small amount of smoke from the 138kv line tone relay control panel

wnen the varistors popred and smoked during testing. The inspectors held

discussion with plant personnel and attended a management review board which

discussed this event.

h. Observations and Findinas

The Wspectors noted that the controller for the amplidyne was tested by an

electrician without the required tag-out and the DC control power breaker being

opened. A preventative maintenance WO written to test the amplidyne breaker and

controller, indicated that no tag-out was required.

During testing of the 138kv line tone relay, varistors in the relay control panel were

damaged when one of the 120 AC ter,t leads contacted a lifted lead and applied

excessive voltage to the tone relay. The total voltage applied to the tone relay

control panel for the 138 KV line was 245 volts and caused the varistors to smoke

and then open. Because of the smoke, the control room operators sounded the fire

alarm and the fire brigade responded to the control room. The fire brigade did not

use any fire fighting medium since there were no flames and the smoke lasted for

less than 10 minutes.

Technical Specification (TS) 6.8.1 requires that written procedures be established,

implemented, and maintained for all structures, systems, components, and safety

i actions defined in the Big Rock Point Quality List. These procedures shall meet or

exceed the requirements of ANSI N18.7, as endorsed by CPC-2A, " Quality Program

Description for Operational Nuclear Power Plants." CPC-2A, Section 5.2 states,in

part, administrative and maintenance general procedures are used to control

activities affecting the quality of safety related structures, systems, and

components. Administrative Procedure 3.2.1.1, " Performance of Maintenance,"

Revision 16, Step 5.2.1.f reouires that the repair person must ensure he has proper

working clearance prior to beginning work. Contrary to the above, on March 6,

1997, an event occurred when the tone relay control panel for the 138 KV line

varistors popped and smoked. An electrician did not acquire required tagging or

clearance for testing the amplidyne controller. During the testing, a 120 VAC signal

vias applied to the existing 125 VDC voltage making a total of 245 volts. The high

voltage caused the protective varistors to pop and smoke, then open and protect

the circuit from further damage. Performing the amplidyne controller testing

without adequate clearances was an example of a violation of Technical

Specifications (VIO 50-155/97004-01a(DHP)).

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c. Conclusion

The inspectors concluded that an electrician did not acquire the required tagging

and clearances to test a coil in the amplidyne controller. This resulted in varistors

on the 138 KV line tone control panel located in the control room to fail and was a

violation of Technical Specifications.

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M1.3 Main Steam isolation Valve-7050 Motor Meaaered with DC Feeder Breaker

Eneroized

a. Insoection Scope

On March 17,1997, the MSIV-7050 motor was meggered without required

l personnel protective tagging and with the DC feeder breaka ?losed. The inspectors

l reviewed station logs; WO MSS-12710295, " Testing of the MStV"; procedure

MGP-39, " Motor Operated Valve Post-Maintenance Testing"; Administrative

Procedure 3.2.1.1, " Performance of Maintenance,"; CR BRP-97-188, "ASD System

Ground"; Technical Specification 6.8.1; CPC-2A, " Quality Program Description for

Operational Nuclear Power Plants"; and previous inspection reports. The inspectors

also held discussions with maintenance personnel and licensee management.

b. Observations and Findinos

On March 17,1997, at 9:15 a.m, an auxiliary shutdown building (ASD) 125 VDC

ground alarm was received in the control room. A control room operator called the

ASD building and determined that the alarm occurred when maintenance personnel

were meggering the MSIV-7050 motor while performing WO MSS-12710295. The

work was stopped and management interviewed maintenance personnel. It was

determined that the meggering was being performed without personnel protective

tagging and without opening the DC feeder breaker. The need to check both items

had been discussed in the pre-job briefing between the maintenance supervisor and

two workers just prior tt )erforming the meggering; however, neither the

supervisor nor the workers checked the items prior to performing the meggering.

The involved maintenance supervisor and two maintenance workers received

disciplinary action. On March 29, the licensee conducted a maintenance stand

down for 4-hours where maintenance, and work planning and scheduling personnel

discussed this error.

Technical Specification (TS) 6.8.1 requires that written procedures be established,

implemented, and maintained for all structures, systems, components, and safety

actions defined in the Big Rock Point Quality List. These procedures shall meet or

i exceed the requimments of ANSI N'r8.7, as endorsed by CPC-2A, " Quality Program

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Description for Operational Nuclear Power Plants." CPC-2A, Section 5.2 states, in

part, that maintenance general procedures (MGPs) are used to control activities

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affecting the quality of safety related structures, systems, and components,

i Maintenance General Procedure 39, " Motor Operated Valve Post-Maintenance

Testing," Revision 16, Step 3.0.k requires that, if required, Personnel Protective

Tagging be requested and obtained for work to be performed in this procedure and,

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Step 5.2.1 requires that the motor operated valve feeder breaker is ensured open.

Administrative Procedure 3.2.1.1, "Perfortnance of Maintenance," Section 5.2.1.f

requires that the repair person must ensure he has proper working clearance,if

required, prior to beginning work. The above self-revealing event resulted from

meggering the MSIV-7050 motor without tra required personnel protective tagging

and with the MOV DC feeder breaker closed. This was a violation of TS 6.8.1 (VIO

50-155/97004-01 b(DRP)).

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After the meggering error, on March 20,1997, a 4-hour maintenance and work

l control center stand down meeting was held. At the stand down meeting, the

above two events and fourteen other 1996 condition reports related to tagging and

work clearance errors were discussed. Licensee immediate corrective actions

resulting from the stand down meeting were:

e If a worker was not working directly with the personnel in charge of Clear

Form 173, permission to work under the person in charge would be required.

e WCC personnel were responsible for verifying the need for tagging,

o Maintenance personnel are required to verify on a daily basis that the

electrical system or component is deenergized, the equipment is checked

with a meter, and verification made that electrical protective tags are still in

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place.

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l * All released work orders that were issued and not completed would be

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returned to the work control center at the end of the day. The work orders

would be re-issued from the work control center at the beginning of the next

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day.

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c. Conclusions

The inspectors concluded that maintenance personnel violated TS requirements

when meggering the MSIV-7050 motor without personnel protective tagging and

with the DC feeder breaker closed. The inspectors also determined that the

licensee took appropriate corrective actions.

, M 1.4 Refurbishina of Backuo Core Sorav Valves MO-7071 and VPI-303

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a. Insoection Scone

The inspectors monitored the repair of backup core spray valves MO-7071 and VPl-

303, held discussions with maintenance workers regarding these activities, and

reviewed WOs PIS-12612081 "MO-7071 Leaking Past the Seat" and PlS-

12710233 "VPI Leaks By."

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f On March 2,1997, after a small steam leak was identified through backup core

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spray valves MO-7071 and VPI-303 and through a pin hole in the telltale pipe, the

licensee made a decision to shut down the plant and refurbish the backup core

spray valves. Primary system unidentified leakage was at 0.206 gpm. which was  !

less than the allowable leakage of 1.0 gpm. Backup core spray valve MO-7071 is a ,

l Anchor-Darling 4-inch gate valve, and valve VPI 303 is a Anchor Darling 4-inch ,

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check valve. Both valves were found to have damage from steam cutting, and in

i both cases the discs had to be refurbished and reassembled. >

l c. Conclusion

To prevent further steam cutting damage to valves MO-7071 and VPI-303 and the l

increase in unidentified primary system leakage, the licensee shut down the plant

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and refurbished the valves.

M1.5 Ooeration of Direct Current Breakers With Protectiye Devices Different Than Plant

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a. Insoection Scooe

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The inspector observed station direct current (DC) breaker testing, held discussions

with electrical engineers, and reviewed print No. 0740G30102, Sheet No.1 and

breaker testing sheets.

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b. Observations and Findinos

During testing of station DC breakers 72-11 and 72-12, the licensee determined

that the protective devices installed in the breakers were not the same as indicated

on plant drawings. According to drawing No. 0740G30102, both the breakers

were to have thermal only protective devices. Breaker 72-11 was found to have a 1

thermal and magnetic protective device, and breaker 72-12 had a magnetic only

protective device. The licensee developed concerns as to the protective tripping

coordination between the load breakers and DC distribution panel breakers 72-11

and 72-12. Review of the breaker coordination and the reason for the difference in I

installed protective devices is an unresolved item (URI 50-155/97004-02(DRP)). As

immediate corrective action, the licensee replaced breaker 72-12 with a new

breaker with a thermal only protective device. Breaker 72-11 was satisfactorily

tested e d e safety evaluation concluded that this breaker would adequately

perform .* protective functions.

c. Conclusions

The licensee unknowingly operated the station DC breakers 72-11 and 72-12 with

protective devices different than the original plant design.

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M1.6 Potential Defective Sorina in Diesel Fire Pumo Relief Valve

a. Insoection Scone

i The inspectors observed the inspection of diesel fire pump (DFP) relief valve RV-

5062 springs and the testing of the relief valve.

b. Observations and Findinas

in October 1996, during a DFP pump test, relief valve RV-5062 opened and failed

to reciose. The valve was replaced with a spare, and the replaced valve was sent

to a lab for metallurgical analysis. The lab determined that the valve spring had

manufacturing indications (crack lines) and had failed as a result of fatigue. A spare

spring was then sent to the lab and manufacturing indications were again identified.

On April 1,1997, DFP relief valve RV 5062 was removed from the system and a i

new spring was installed. The licensee ordered two new springs and performed I

magna-flex examinations on the new springs which revealed no indications. One of

the new springs was installed in the relief valve, and the relief valve's lift pressure

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was set and bench tested. The relief valve was re-installed into the fire system on 1

April 2,1997, and the diesel fire pump was satisfactorily tested,

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c. Conclusion l

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Indications were identified on diesel fire pump (DFP) relief valve RV-5062 springs,

however, the DFP relief valve remained in an operable condition. A new spring was

installed in the diesel fire pump relief valve and the valve was returned to service.

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M1.7 No. 2 Recirculation Pumo Seal Renair

a. Insoection Scooe

The inspectors attended a pre-job briefing for the No. 2 recirculation pump (RCP)

seal repairs, observed maintenance activities, held discussion with maintenance

personnel, and reviewed WO PCS-12611212 " Remove and Install RCP Seal," and

procedure MPC-2 " Reactor Recirculating Water Pump Seal Cartridge Replacement."

b. Observations and Findinas

On April 20,1997, after adjusting seal flows during a plant startup, the operator

determined that the inner seal on the No. 2 reactor recirculation pump was not

functioning properly. The reactor was shutdown and the seal was removed from

the pump. The sealis a Byron-Jackson two stage mechanical seal. The cause of

the seal failure was aging (4-years of operation) and dirt in the seal. The seal was

rebuilt and installed in the pump. The inspectors interviewed the maintenance

senior technical analyst (STA) who inspected the failed seal during the seal

disassembly. The inspectors learned that the seat failed from crud build-up. The

inner seal had recorder trackings and the upper seal had a combination of recorder

trackings and light checking. The control room log indicated that on April 24,

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1997, while maintenance was tightening the coupling that had a small water leak, ,

the 1-inch flexible hose No. 2 reactor recirculation pump heat exchanger for the

cooling water ruptured. The leak was successfully isolated and the hose and

j coupling were replaced. The pump was satisfactorily tested on April 24,1997.

The inspectors' review of WO PCS-12300908, to dissemble No. 2 RCP seal

cartridge, determined that the seal cartridge was last replaced on August 20,1993.

The inspectors' review of the WO summary indicated that the lower stationary face '

was chipped and saddle shaped, the upper stationary carbon faco was chipped and

l grooved, and the shaft sleeve was grooved at both u-cap surfaces.

c. Conclusion

The licensee promptly shut the plant down upon discovery of the malfunctioning of

l the No. 2 reactor recirculation pump inner seal. Maintenance activities observed by

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the inspectors related to the job were appropriately performed. l

Ill. Enaineerino

E1 Conduct of Engineering

E1.1 Over Pressurization of Fire Protection / Post Incident System

a, Insnection Scooe

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l The inspectors reviewed the design change package for the over pressurization of I

the Fire Protection / Post incident System and discussed the results and proposed

actions to be taken with cognizant engineering personnel. Available records,

documents and procedures related to the problem were also reviewed.

b. Observations and Findinas

During post repair testing of the diesel driven fire pump, licensee personnel

discovered that, for brief periods of time, the fire protection / post incident system I

had been subjected to pressures in excess of the 150 psig design pressure. The l

design of the fire protection / post incident system did not provide a method for flow l

of water from the system during the testing of the fire pumps. The design pressure

of the system was 150 psig and the six relief valves in the system were set at 155

psig. Both the motor driven and the diesel driven fire pumps were tested weekly

with no allowances made for flow through the system. There were no problems

with the motor driven fire pump testing; however, during testing of the diesel

driven fire pump the system was subjected to pressures in excess of design

pressure for brief periods during the tests The diesel driven fire pump provided a

l higher pressure which resulted in the over pressurization of the system to a

l maximum of 168 psig. The six relief valves in the system opened each time the

i set-point pressure was exceeded. Most of the water was discharged through the

l 4-in:h system over pressure relief valve RV-5062.

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During the review and discussions regarding this problem, the inspectors were

informed that a design change was in process to raise the design pressure of the

post incident system inside containment to 200 psig. The three relief valves inside

containment would be replaced with relief valves set at 200 psig preventing the

relief valves from opening during diesel fire pump (DFP) testing.

The inspector reviewed the design change package SC 97-007 for this

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modification. The change appeared to be appropriate for the upgrade of the system

inside containment. Actions to be taken on the system outside of containment

were to be addressed under the licensee's corrective action system.

c. Conclusions

The system modification design package to upgrade the portion of the fire

protection / post incident system inside containment to a design pressure of 200 psig

appeared to be good. The installation of 200 psig relief valves inside containment

will prevent the actuation of these relief valves during fire pump testing and reduce

the leakage problem through these valves.

The external portions of this system appeared to meet the 1955 ASME Boiler and

Pressure Vessel Code, which applies to Big Rock Point. The code allows the design

pressure to be exceeded, by a limited amount, for short periods of time. The

external portions of this system appeared to meet this criteria.

E1.2 Licensee's Corrective Actions for Previous Conditions ineffective to Prevent Re-

occurrences of Taaaina Errors

a. Insoection Scoce

The inspectors reviewed the licensee's past CRs relating to clearance and tagging

orders to determine whether the corrective actions were adequate to prevent the

occurrence of the tagging and clearance errors related to testing of the amplidyne

controller coil and meggering the main steam isolation valve. The inspectors

reviewed the CRs listed below:

• C-BRP-96-0072: Inadequate Workmen's Protective Tagging MO-N001B j

e C-BRP-96-0158: Wrong Device Red Tagged  ;

e C-BRP-96-0165: Inadequate Tagging For Breaker Functional

e C-BRP-96-0295: Electrical Arc While Performing Scram Solenoid Pilot

Valve Termination ,

e C-BRP-96-0301: No Tagging on MO-7070

e C-BRP-96-0475: Inadequate FME and Failure to Follow APM

e C-BRP-96-0504: Minor electrical Shock During Ballast Replacement

e C-BRP-96-0564: Failure to Receive Working Clearance

e C-BRP-96-0634: Miscommunication On Tagging and Planning

e C-BRP-96-0647: Unexpected 20 Volts After Tagging Equipment '

e C-BRP-96-0916: Waste Hold Tank Tagging For PM

e C-BRP-96-0929: Incorrect Breaker Tagged

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• C-BR P-96-0944: Insufficient Tagging for PI Test Tank

• C-BRP-96-1052: WO Had Work Listed That Should Not Be Performed

• C-BRP-96-1053: WO Released Without Proper Tagging Review

b. Observations and Findinas

The inspectors' review of the above CRs determined the apparent causes, and the

licensee's corrective actions were as follows:

• CR-96-0072 (Dated January 12,1996). The root cause was inadequate

electrical tag 0i ng for the work scope. Corrective actions included

discussions between operators and work control personnel to review the

work and the submitted formal, written requests for tagging assistance.

• CR-96-0295 (Dated February 20,1996). The cause of this event was the

fact that an exposed terminal block located inside the cable tray where work

was being performed had no warning label attached. The licensee

determined that the power to the terminal block could have been checked

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prior to beginning work. One of the licensee's corrective actions was to '

place a warning label on the exposed 120V AC terminal block.

• CR-96-0301 (Dated February 21,1996). The root cause was failure to

verify that equipment being worked on was electrically isolated. Corrective l

actions included discussion of the event with plant personnel to reemphasize

the importance of physically ensuring that equipment was electrically

isolated.

• CR-96-0475 (Dated April 18,1996). The apparent cause of this event was

the worker failed to verify that voltage was removed from an electrical

solenoid valve SV-4928 after receiving tagging clearance and when working

on CV-4928. The teensee reviewed the incident with the repair worker and

reminded maintenaace crews of the importance of verifying that no voltage

was present prior to commencing work.

• CR-96-0564 (Dated.May 30,1996). This CR evaluated four electrical

tagging errors (96-295,96-504,96-634, and 95-629 " Electrical Shock

While Cleaning Tank T-51" (fire accumulator tank)). One of the licensee's

corrective actions was that the work group performing the electrical work

would identify the points that require tagging prior to performing work.

Another licensee action was to conduct tagging requalification training for

the maintenar.re personnel which was scheduled to be completed by August

31,1997.

• CR-96-1053 (Dated December 18,1996). A work order was released

l without a proper tagging review. The licensee's corrective actions were to

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discuss this and similar errors with WCC personnel. This action was

completed on February 11,1997 and the same corrective action was

completed with mechanical and electrical personnel on March 10,1997.

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c. Conclusions

The inspectors concluded that in some cases, the licensee's corrective actions were

incomplete, resulting in repetitive tagging and clearance problems. However, recent

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corrective actions related to clearance and tagging problems appear to be

comprehensive. The inspectors will continue to closely monitor for additional ,

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instances of clearance and tagging problems.

IV. Plant Suonort

R1 Radiological Protection and Chemistry Controls (71750)

R 1.1 General Comments -

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Using Inspection Procedures 71707 and 71750, the inspectors made frequent tours l

of the radiologically protected area (RPA) and discussed specific radiological l

controls with the ALARA coordinator and various radiation protection (RP) *

technicians. The inspectors observed plant conditions and licensee performance

including radiation protection practices.

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S1 Conduct of Security and Safe 0uards Activities (71750)

S1.1 General Comments

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During normal resident inspection activities, routine observations were conducted in

the areas of security and safeguards activities using Inspection Procedure 71750.  ;

No discrepancies were noted.  ;

V. Manaaement Meetinos

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X1 Exit Meetina Summarv l

The inspectors presented the inspection results to members of licensee

management at the conclusion of the inspection on April 29,1997. The licensee -

acknowledged the findings presented.

The licensee did not identify any of the documents or processes reviewed by the

inspectors as proprietary.

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PARTIAL LIST OF PERSONS CONTACTED ~

Licensee

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K. Powers, General Manager

, R. Addy, Plant Manager

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p. Beachum, Engineering Manager

G. Boss, Operations Manager

i. D. Hice, Maintenance Manager

l J. Rang, Decomrn & Business Manager

l K. Pallagi, Chemistry / Health Physics Manager

l W. Trubilowicz, Outage / Work Control Manager

l G. Withrow, Licensing Manager

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INSPECTION PROCEDURES USED _ . . , , ,

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IP 37551: Engineering

l lP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing

Problems

l IP 61726: Surveillance Observations

IP 62703: Maintenar.ce Observation

IP 64704: Fire Protection Program

IP 71707: Plant Operations

IP 71750: Plant Support Activities

IP 73753: Inservice Inspection 4

IP 83729: Occupational Exposure During Extended Outages I

IP 83750: Occupational Exposure '

iP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor

Facilities l

IP 92902: Followup - Engineering

IP 92903: Followup - Maintenance

ITEMS OPENED and CLOSED

. Opened

155/96004-01a VIO Failure to Follow Procedures for Clearances and Tagging

155/96004-01 b VIO Failure to Follow Procedures for Clearances and Tagging

155/96004-02 URI Protective Devices Installed in DC Breakers Different from

Original Design

Closed

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LIST OF ACRONYMS USED ,

ALARA As Low As Reasonably Achievable

AO Auxiliary Operator -

AP Administrative Procedure .

CFR. Code of Federal Regulations

CR Condition Report

DFP Diesel Fire Pump

DRP Division of Reactor Projects

IP inspection Procedure

IPTE Infrequently Performed Test and Evolution

IR Inspecticn Report

MSIV Main Steam isolation Valve

MGP Maintenance General Procedure -

NCV Non-Cited Violation

NOV Notice of Violation

NRC Nuclear Regulatory Commission

RCP Recirculation Pump

RPA Radiologically Protected Area

SS Shift Supervisor

SV Solenoid Valve

TS Technical Specification

URI Unresolved item

VIO Violation

WCC Work Control Center

WO Work Order

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