ML20202C058

Insp Repts 50-282/97-23 & 50-306/97-23 on 971203-980113. Violations Noted.Major Areas Inspected:Licensee Operations, Maint,Engineering & Plant Support

ML20202C058
Person / Time
Site:	Prairie Island
Issue date:	01/30/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20202C041	List: ML20202C037 ML20202C045 ML20202C058
References
50-282-97-23, 50-306-97-23, NUDOCS 9802120155
Download: ML20202C058 (27)

See also: IR 05000282/1997023

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U.S. NUCLEAR REGULATORY COMMISSION

REGIONlli

Docket Nos.

50-282; 50-306

License Nos.

DPR-42; DPR-60

Report No.

5(. 482/97023(DRP); 50-306/97023(DRP)

Licensee:

Northem States Power Company

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Facility:

Prairie Island Nuclear Generating Plant

Location:

1717 Wakonade Drive East

Welch, MN 55089

Dates:

December 3,1997, through January 13,1998

Inspectors:

S. Ray, Senior Resident inspector

P. Krohn, Resident inspector

S. Thomas, Resident inspector

Approved by:

J. W. McCormick-Barger, Chief

Reactor Projects Branch 7

9002120155 900130

PDR

ADOCK 05000282

G

PDR

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EXECUTIVE SUMMARY

Prairie Island Nuclear Generating Plant, Units 1 & 2

NRC Inspection Report No. 50-282/97023(DRP); 50-306/97023(DRP)

This inspection included aspects of licensee operations, maintenance, engineering, and plant

support. The report covers a six-week period of resident inspection.

fioerations

Management expectations and procedures for conduct in the control room, such as those

delineating the frequency and completeness of main control board walkdowns, were not

always clear, in addition, first line supervisors did not always enforce those procedures

that were clear, such as those relating to communications and control room access

(Section 01.1),

Unit i startup operations from the refueling outage were generally conducted well with no

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significant problems. Procedures were followed and operators remained attentive to

plant indications during plant mode changes (Section 01.2).

One instance occurred during the Unit 1 startup where an operator did not verify that an

annunciator (the ROD AT BOTTOM annunciator) had cleared in a timely manner.

Although this error was not safety significant, it emphasized the need for improvements in

procedure organization and for further evaluation of procedure use expectations

(Section 01.2).

Following the retum to full power operations after the Unit i refueling outage, power was

reduced to 5 percent to allow balancing of the main turbine. Control room activities for

the power reduction, turbine balancing, and retum to full power were conducted well

(Section 01.3).

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During a walkdown of the Unit 2 containment spray and caustic addition systems, the

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inspectors found the systems properly lined-up and ready for safeguards operation. No

significant material discrepancies or system deficiencies were identified that would

prevent either system from performing its intended function (Section O2.1).

Ma'ntenance

Operators involved in maintenar.ce and surveillance activities displayed a good

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questioning attitude and appreciation of radiation dose control (Section M1.1).

A good questioning attitude by an operator resulted in identification of an inadequacy in a

procedure for main turbine torsional testing. However, the initial review of the operator's

concem by engineering was poor, and the concem was not validated until the test was

started and equipment did not respond as expected (Section M1.1).

The inspectors identified that a physics testing procedure had not been followed in that

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the amount of reactor coolant system temperature change called for la the procedure was

not accomplished (Section M1.2).

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The inspectors identified several minor deficiencies in the surveillance Mures for

operational pressure test inspections of the cooling water system (Section M3.1).

Ennineerino

System engineers were heavily involved with all asper:ts of operations, maintenance, and

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testing of their systems. The engineers rapidly investigeled any operational

abnormatities, took an active role in maintenance and troubleshooting activities, and

closely followed alt surveillance testing on the',r systems; however, in one instanca, during

turt>lne torsional testing, a system enginser did net provide adequate technical support

(Section E2.2).

Recer:< findings by tne engineering orgsnization involving the control room ventilation

system and a 10 CFR Part 50, Appendix R issue regarding inadequate separation of

pressurizer level cables indicated that thorough design reviews were being conducted

and reflected a wi'lingness to Idantify and resolve old jesign and compliance issues

(Section E3.1).

Plant Sucoort

Good involvemeM of radiatk,n protection personnel in job p'- aning and execution in order -

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to rnaintain low ooses was observed, as exemplified by the involvement of radiation

protection personnel with operators during performance of a reactor coolant system

integrity test (Sections M1.1 and R1),

An old Appendix R compliance issue involving inadequate separation of pressurizer level

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cables was identified and rapidly corrected as a result of a proactive lic6nsee initiative

(Section F2.1).

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Report Details

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Summary of Plant Status

Unit 1 was restarted upon completion of a refueling outage on December 13,1997, and the

generator was placed on the grid for the first time on December 14. After extensive test 8ng of the

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newly installed turbines, the b,'.it reached full power on December 19. Power on Unit 1 was

reduced to about 5 percent on January g,1998, and the generator was taken off line in order to

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accomplish turbine balancing. The generator was placed back on line January 10 and the unit

retumed to full power on January 11. Unit 2 operated at or near full power for the entire

inspection period.

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l. Operations

01

Conduct of Operations

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01.1

General Comments

a.

inspection Scoce (71707. g2901)

The inspectors conducted frequent reviews of plant operations. The inspectors

performed observations in the control room for extended periods and focused on shift

tumovers, prejob briefs, communications, control room access control, logkeeping,

control boarc monitoring, and general control room decorum. Section 13. "P%nt

Operations," of the Updated Safety Analysis Report (USAR) was reviewed as part of the

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inspection.

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b.

Observations and Findinas

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The inspectors noted that shift tumovers were usually good, covering the status of both

units, on-going maintenance and evolutions, and other specific instructin1s for the safe

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operati sn of the units. However, on two occasions operators arrived late for the moming

control qum shift tumover briefing, missing significant portions of the information -

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presented.

The inspectors observed numerous projob briefs, including briefs for int < rated safety

injection testing, Unit i reactor startup, Unit i reactor physics testing, and Unit i turbine

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overspeed and torsional testing. Generally, the briefs were concise, but thorough. The

inspectors noted that the use of formal communications, the slow and cot trolled conduct

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of the evolution, and reactor safety were common issues stressed in each brief. No

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specific discrepancies were noted.

The inspectors observed operator commu,,ications during numerous evolutions including

both routine and noteroutine operations. While communications were deemed adequate,

they rer.ged from excellent to poor, depending on the evolution in progress and/or crew

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ob. served. Specific observations included:

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- the consistency with which formal ccmmunications were used varied from crew to

crew;

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formal communications tended to be used more frequently during planned

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evolutions, such as reactor startups, but less frequently during abnormal operaHng

situations; and

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communications in the plant were generally not ab formal as those in the

simulator.

During tl o extended periods of control room obscrvation, the inspectors monitorea how

control ri cm access was managed. Section Work Instruction (SWI) 0 2, ' Shift

Organta tion, Operatica, and Tumover," Revision 38, stated that the 'thift supervisor (SS)

• shall be responsible for maintaining control of personnel entering the control room" and

the lead plant equipment and reactor operator (LPE&RO) shall be responsible for

" granting permission to non-operations personnel for entry Ido the control room."

Implementation of those aspects of SWI O 2 was poor. Specific discrepancies noted in

the control of controt room af4:ss were:

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on numerot.s occasions, instrument and control technicians entered the control

area boundaries within the control room and approached control panelt without

first obtaining permission and/or informing the LPE&RO of their reason for doing

so; and

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on several occasions, personnel entered the control area of the control room and

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approached control panels wecring hard hats even though there was a si-ln,

located at the entry to the control area, which stated that hard hats were not

allowed beyond that point.

The inspectors observed control room operators during the performance of routine log

taking and control board monitoring. The inspectors considered the Operations Log and

the individual Unit 1 and Unit 2 Reactor Logs to be an accurate accounting of shift events

and noted that relevaret shift information was consistently logged. The Inspectors could

find no specific uperator guidance, nor could any be provided by the poneral

superintendent of operations, on the frequency that it.e control berds should be " walked

down." Control board monitoring was considered adequate, but me time between

walkdowns varied widely from crew to crew. Specific discrepancies noted in control

board monitoring were:

the continuous monitoring of control boards exhibited by operators participating in

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graded simulator scenarios was not observed in the main control room;

during one of the inspectors' control room tours, the inspectors noted that over a

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two hour period of time, the only time the Unit 1 panels were walked down was

when the hourly logs were taken;

annunciators were frequently silenced and acknowledgod by a single operator

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without announcing to other control room personnel what the alarm was and the

reasoa for the alarm; and

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the inspectors identified tht.t incorrect work order numbers were referred to in one

reactor log entry. When identified, th SS corrected the log entry.

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The inspec* ors observed the overall control roor.1 decorum during evolutions which

ranged from complex to routine. The inspectors gens, ally categorized the overall

atmosphere as relaxed, but professional. The appropriate level of conoom and

supervisory oversight was demonstrated during complex and Infrequently performed

evo;utions. The SSs and shift managers generally handled administrative matters,

leaving the other control room operators free to monitor and t,ontrol 6ach Unit's operation.

The inspectors noted that some activities detracted from a professional control room

atmosphere, including:

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eating food and/or drinking beverages while , < rating components at a control

panel;

inappropriate screen savers on the computer monitors in the control room;

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extended discussions of toples not related to the operation of the plant; and

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inappropricte material posted on the walls of the SS's area.

c.

Conclusions

Management expectations and procedures for conduct in the control room, such as those

delinteting the frequency and completeness of main control board walkdowns, were not

always clear. In addition, first line supervisors did not always enforce those procedures

that were clear, such as those relating to communications and control room access.

inconsistencies in performance between crews indicated the need for additional guidance

and tialning in this area. The discrepancies discussed above did not lead to any unsafe

conditior,s or violations of NRC requirements. The plant manager informed the inspectors

that a revised section work instruction on control room access and other expectations

was being developed.

01.2 Unit i Retum to.100 Percent Power Operation

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a.

inspection Scope (71707)

The inspectors observed significant portions of operations leading from a refueling

shutdown to 100 percent power operation on Unit 1. Major activities observed included:

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integrated safety injection test;

transition from Mode 5 to Mode 4 (Cold Shutdown to Intermediate Shutdown);

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drawing a pressurizer bubble;

transition from Mode 4 to Mode 3 (Intermediate Shutdown to Hot Shutdown);

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reactor stanup;

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reactor physics testing;

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transition from Mode 3 to 2 to 1 (Hot Shutdown to Hot Standby to Power

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Operation); and

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turbine overspeed and torsional testing.

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included in the startup observations was a review of the appropriate USAR sections and

operating procedures regarding the activities. The inspectors verified that Jpplicablu

surveillance procedures performed as part of the startup met the requirements of the

Technical Specifications (TSF).

b.

Observations and Findinat

For most of the evolutions observed, procedures were properly used and followed.

Operations personnel demonstrated experience and knowledge during the performance

of their tasks. Noteworthy comments on specific evolutions are discussed below.

The inspectors attended the prejob brief and obse ved performance of

surveillance procedure SP 1063, * Unit 1 Irstegrated Safety injection Test With a

Simulated Loss of Offsite Power," Revision 24, from the control room and

emergency diesel generator rooms. The prejob brief was thorough and attended

by the plant manager who stressed proper command and control, personnel

safety, nuclear safety, and equipment protection.

The inspectors observed good command, control, and coordination of activities

during the integrated safety injection test. The complex test required the

coordinated effort of many operations, engineering, and maintenance personnel to

establish the required test conditions and monitor system performance as the test

was performed,

The inspectors observed the prejob brief conducted prior to the Unit i reactor

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startup. Reactivity manegement, expected indications, and personnel roles and

responsibilities were discussed. An extra reactor operator (RO) and SS, in

addition to the normal crew complement, were assigned to perform the startup.

Other plant activities and distractions were kept to a minimum. Nuclear

engineering personnel were also present and perform 3d independent verifications

of reactivity management as the startup progressed.

The inspectors observed the withdrawal of the control banks and dilution to

criticality. The SS and RO remained attentive to reactor power ievels and startup

rate iridications throughout the reactor startup. However, after control

bank A rods had been withdrawn to 129 steps, the RO noticed that tr,e ROD AT

BOTTOM annunciator had not cleared. The reactor operator drove bank A rods

to O steps and a work order was issued to investigate the cause of the

annunciator not clearing at 20 steps as expected. it was deteImined that the

pulse to-analog bistable for control bank D had failed causing the ROD AT

BOTTOM annunciator to remain energized (the position of rods in all four of the

control banks input into the logic for the annunciator).

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Operating Procedure 1C1.2, " Unit i Startup Procedure," Revision 18, Step 5.5.0,

instructed the reactor operator to startup the reactor per Appendix C18, " Appendix

- Reactor Startup," Revirion 6. Appendix C1B was intended to be an aid to the

RO for conducting the startup and was not required to be "in-hand' during the

actual startup evolution since the operator's attention should be focussed on the

control board. Step 5.2.2.C of Appendix C18, required th;; RO to verify that the

ROD AT BOTTOM annunciator (47013-0407) cleared with bank A control rods at

appro41mately 20 steps during the reactor startup. The RO did not perform that

verification until the control bank A rods had reached 129 steps.

Technical Specification 6.5.A.1 required that detailed written procedures for

normal startup of the reactor be prepared and followed. On December 12,1997,

Operating Procedure C18, * Appendix Reactor Startup," Revision 6, Step 5.2.2.C,

was not followed wnen the RO did not verify that the ROD AT BOTTOM

annunciator cleared when rod bank A was withdrawn to approximately 20 steps.

The RO later identified that the annunciator h::J not cleared when he stopped

moving bank A rods at 129 steps. The event was not stafety significant and only

resulted in an equipment problem not being identified as soon as it could have

been. The general superintendent of operations was reevaluating the reactor

startup procedure and c.onsidering adding hold points to refer to the procedure

and conduct the various verifications rather than expect the RO to remember the

entire C1B Procedure. This non-repetitive, licensee luentified and corrected

violation is being treated as a Non-C;ted Violation, consistent with Section Vll.B.1

of the NRC Enforcement Policy (50 282/97023-01(DRP)).

c.

Conclusions

Unit i startup operations were generally conducted well with no significant problems.

Procedures were followed and operators remained attentive to plant indications during

plant mode changes. The ROD AT BOTTOM annunciator cleared verification

requirement in Appendix C1B, Step 5.5.8.C, which should have been performed at

approximately 20 steps on control bank A, was not performed until 129 steps, primarily

because the procedure was not required to be in-hand during the actual startup evolution.

This error emphasized the need for improvements in pocedure organization and further

evaluation of procedure use expectations. The licensee was evaluating possible

improvements.

01.3 Unit 1 Power Reduction for Turbine Balancina and Retum to Fu!! Power Operatim

a,

Inspection Scope f71707)

The inspectors observed significant portions of the Unit 1 power reduction frura

100 percent to approximately 5 percent power, the turbine balancing evolution, and the

subsequent retum to 100 percent power operation conducted from January 9 to

January 11,1998,

b.

Observations and Findinas

The power reduction from 100 percent to 5 percent power was conducted very well. The

inspectors observed excellent communications between all operating crew personnel,

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both inside and outside the control room. The RO and LPE&RO malntained good control

of the plant and awareness of plant parameters, and frequently kept each other informed

of changes in these parameters as indicated on the control room panels. The LPE&RO

executed the require!.ients specified in the Unit 1 power reduction (101.4, " Unit 1 Power

Operation,' Revision 15) and shutdown (1C1.3, * Unit i Shutdown,' ."evision 38)

procedures without error and effectively planned ahead to begin mwntenance activities at

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the earliest appropriate opportunity The SS maintained overall cognizance of the power

reduction evolution, appropriately observing selected actions of the operators.

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A second operating crew was observed performing the turbine stariup after the balanc!ng.

Again, excellent communications and plant control were exhibited. Procedures were

property implemented and the activities were closely supervised. The LPE&RO

controlling the turbine kept the RO closely informed of any changes that could affect the

reactor. The LPE&RO was also observed correcting a system engineer when the

engineer failed to use three way communications over the radio,

c.

Conclusions

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The Unit 1 power reduction, turbine balancing, and retum to full power were conducted

well. Significant improvements were noted c.ompared to the control room etservations

desensed in Section 01.1 of this report.

02

Operational Status of Facilities and Equipment

O2.1 Engineered Safety System Walkdown

a.

Inspection Scope (71707)

The inspectors performed a walkdown of the Unit 2 containment spray and caustic

addition systems as part of the monthly inspections of the Unit 2 engineered safety

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syt,tems. Included in this inspection was a review of USA't, Section 6.4, * Containment

Vessel Internal Spray," Revision 14, and the following diagram::

NF 39252, " Flow Diagram Unit 1 & 2 Caustic Addition System," Revision N;

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NF 39824, " Containment Intemal Spray System Units 1 & 2," Revision B;

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NF 39237, * Flow Diagram, Containment Internal Spray System," Revision AB; and

NF 393331, * Reactor Safety injection ar'i Containment Spray Piping-Unit 2,"

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Revision R.

b.

Observations and Findinas

The inspectors noted that the valves in the main system f'tw paths were in the correct

position, components were properly labeled, locking devices were present and properly

installed, and that power supplies and breakers were properly aligned to support intended

system operation. No discrepancies were noted when comparing the system

components and layout with the system dese.riptions in the USAR. The material condition

of the systems was generally good, with the following exceptions:

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heavy buildup of sodium hydroxide crystals on the valve siem and packing gland

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area of valve 2 CA 20 5; and

light buildup of cheinical residue on the packing glands of valves MV 32110,

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MV 32111, CS 251, CS 40, CS 42, and 2 CA 19-4.

The discrepancies did not affect system operability.

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c.

Conclus[gnt

During system walkdowns, the inspectors found the Unit 2 containment spray and caustic

addition systems lined up and ready for safeguards operation. No significant material

discrepancies or system deficiencies were identified that would prevent either system

from performing its intended function.

08

Miscellaneous Operations issues (92700,92901)

08.1

(Closed) Licensee Event Report 50 306/97005 (2 97-05): Sudden Pressure Lockout of

No.10 Transformer Resulting in Auto Load Rejection /Restcration on Safety Related Bus.

This event was previously discussed in Inspection Report No. 50>282/97021(DRP);

50-306/97021(DRP), Section 01.3. The Licensee Event Report (LER) contained a

detailed description of the event, investigation, and restoration sequence. Despite an

extensive investigation, no cause for the actuation was detem,ined, but the sudden

pressure relay was replaced as a precautionary measure. No additional corrective

actions were initiated since the causa of the actuation was not known.

II. Maintenance

M1

Conduct of Maintenance

M1,1 General Cornments

a.

inspection Scope (61726. 62707)

The inspectors observed all or major portions of the following maintenance and

surveillance activities. Included in the inspection was a review of the surveillance

procedures (SPs) and work orders (WOs) listed as well as the appropriate Updatad

Safety Analysis Report (USAR) sections regarding the activi'ies. The inspectors verified

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that the surveillance procedures reviewed met the requirements of the TSs.

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SP 1018A

Rod Position Indication Cold Calibration, Revision 6

SP 1070

Reactor Coolant System Integrity Test, Revision 26 (400 pounds

per square inch inspection portion only)

SP 1083

Unit 1 integrated Safety injection Test with a Simulated Loss of

Offsite Power, Revision 24

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SP 1089

Residual Heat Removal Pumps and Suction Valves from the

Refueling Water Storage Tank, Revision 46

SP 1194

Cardox [Carben Dioxide) System Test, Revision 8

SP1231

121 Catalytic Hydrogen Recombiner Gas Analyzer Monthly

Functional and Calibration Test, Revision 11

LF 1301

11 Turbine Driven Auxiliary Feedwater Pump Auto Start and

Function Testing Revision 8

SP 1750

Post Outage Containment Closeout inspection, Revision 14

SP 2548

Analog Reactor Control System Calibration, Revision b

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WO 9601293 Motor Operated Valve 32077 Excessive Packing Leakage

WO 9706505 Fuel Oil Storage Tank Tightness Tests

WO 9711674 Modify Tubing for 122 Control Room Chiller

WO 9711686 Modify Tubing for 121 Control Room Chiller

WO 9712636 Turbine Torsional Test

WO 9713386 Annunciator 47013-0407 Doesn't Clear

WO 9713389 G3 and C7 Rod Bottom Bistables Will Not Clear

WO 9713491 Balance Unit 1 Turbine

WO 9715204 Possible Foreign Object Noise on DMIMS (Digital Metal Impact

Monitoring System) Channels 750/751

WO 9715218 Monitor DMIMS Channels 750 and 751 for Noise

WO 9800004 High Average Coolant Temperature Compensator Module Spiking

b.

Observationi md Findinas

For all of the work observed, procedures were properly used and followed except for one

activity discussed in Section M1.2 of this report. Maintenance personnelwere

experienced and knowledgeable of their tasks. The inspectors observed frequent

monitoring of work by system engineers. Noteworthy comments on specific work

activities are discussed below.

For SP 1070, the inspectors accompanied two operators and a radiation

protection technician on an inspection for indications of reactor coolant system

leakage in the Unit 1 containment. Two prejob briefings were held: one involved

the operators and the shift supervisor to discuss the technical aspects of the task,

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and the other involved the operators and a radiation protection superviser to

discuss the radiation protection aspects. The two operators split the areas to be

inspected and carefully planned their routes with the ascistance of the radiation

protection technician to minimize radiation exposure. The inspections were

conducted expeditiously, but thoroughly, No indications of leakage were

identified. The operators displayed a suitable approciation for maintaining their

radiation dose as low as reasonably achievable wt'lle still property conducting the

inspections.

For SP 1089, the operators identified a proceduru enhancement during the

conduct of the test. The test required the operators to record differential pressure

(D/P) in the residual heat removal pump mini-flow recirculation line. Since the D/P

gauge exhibited fluctuations around the actual reading, the procedure allowed the

option of throttling the instrument root valves to dampen the fluctuations. The

operators properly followed the procedure and throttled the root valves, but

performance of that step was quite difficult. The root valves were located in the

next room from the gauge,in a contaminated area, approximately 10 feet off the

floor. The gauge was not visible from the va'ves. Close coordination of two

operators was necessary to complete the task. The operators identif5d that it

would have been much easier to throttle the instrument isolation valves on the

manifold just under the gauge. The chift supervisor initiated action to get the

procedure revised.

Just before throttling the instrument root valves, the local operators questioned

whether there was any other indication or actuation circuitry off the same

instrument lines. They were concer,.ed that they might accidently isolate the line

by overthrottling and cause some kind of problem in other instrumentation. The

operators stopped and resolved their concem with the shift supervisor before

proceeding. The operators displayed a conservative operating philosophy and

questioning attitude during the test,

On December 15,1997, the inspectors observed activities govemed by

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WO 9712636, * Unit 1 Turbine Torsional Testing, required after the replacement

of the turbine generator low pressure rotors. The test measured the torsional

natural frequencies and response levels of the turbine generator shaft system.

Step 8.1.8.f of the turbine torsional test procedure instructed the contrei room

operator to close generator output breaker 6 H 17. The control room operator

displayed a questioning attitude by asking the system engineer if it was necessary

to place the synchroscope selector switch in the BKR 17 position prior to closing

B H 17. The system engineer responded that this was not necessary since the

synchro-check relay had been bypassed. When the control room operator

attempted to close 8-H 17, in accordance with Step 8.1.8.f of the WO, the breaker

did not close. Further review of the electrical schematics with the system

engineer revesk ; that, although a jumper had been installed to bypass the

synchro-check relay in the sivitchyard, the procedure failed to recognize that the

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synchroscope selector switch in the control room needed to be placed in the

BKR 17 position to makeup auxiliary contacts necessary to close 8-H-17. The

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WO was changed, the synchroscope selector switch was placed in the BKR 17

position, and 6 H 17 was closed with its control switch. The Unit 1 turbine

torsional test was completed without further problems.

The turbine torsional test procedure was not appropriatt for the circumstances

because it did not require placing the synchroscope selector switch in the BKR 17

position prior to closing 8 H 17. This was a violation of 10 CFR Part 50,

Appendix B, Criterion V, which required that activities affecting quality be

prescribed by docume:ited instructions, procedures, or drawings, of a type

appropriate to the circumstances. However, the turbine torsional test procedure

problem was not safety significant becauso it simply resulted in the inability to

complete the test untilit was corrected. This non repetitive, licensee-identified

and corrected violation is being treated as a Non Cited Violation, consistent with

Section Vil.B.1 of the NRC Enforcement Policy (50-282/97023-02(DRP)).

For WOs 9715204 and 9715218, the licrasee noted, soon after starting Unit i bp

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from a refueling cutage, metallic noise indications on detectors located on the

reactor vessel. The licensee made recordings of the noise and sent them to

vendors for analysis and made plans to try to identify the source. However, during

the power reduction on Januery 9, the noise stopped as soon as operators started

to insert control bank D control rods. The licansee wes unable to reestablish the

noise by withdrawing control bank D rods while at reduced power, but the noise

recurred when reactor power was at about 95 percent and control bank D rods

were retumed to about 205 steps out. Thus, the licensee believed the noise was

associated with at least one of the control rods and did not represent en

immediate safety concern. At the end of the inspection period, the licensee was

considering further actions to identify the exact cause of the noise.

c.

Conclusions

Operators involved with maintenance and surveillance activities displayed a good

questioning attitude and appreciation of mdiation dose control. A procedure inadequacy

was identified where circuit logle was :,st analyzed thoroughly enough during

devolopment of a work order procodure. System engineers frequently mor:ltored ongoing

work and were generally responsive to maintenance staff concems: ho...for, in one

instance, during the turbine torsional testing, a system engineer did not provide adequate

support.

M1.2 Low Power Physics Testina

a.

Inspection Scope (71711)

The inspectors observed the conduct of various maintenance activities for refueling

startup physics testing on Unit 1. The following maintenance procedures and documents

were reviewed as part of this inspecticn:

D32, " Temperature Coefficient Measurement at Hot Zero Power," Revision 6;

D34, " Boron Endpoint Measurement,' Revision 6;

13

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D30, * Post Refueling Startup Testing," Revision 27; and

ANSI /ANS (American National Standards Institute, Inc./American Nuclear Society)

19.6.1 1985, * Reload Startup Physics Tests for Pressurized Water

Reactors."

b.

Observations and Findinas

The performance of maintenance activities associated with Procedure D34 required a

significant number of control rod position manipulations. The reactor operator (RO)

exercised good control over reactivity during the selected individual manipulations of all

the shutdown and control bank control rods. Good coordination was observed between

the reactor operator and the nuclear engineer assisting with the procedure. Good

supervisory oversight was provided by the shift supervisor in that he provided a second

verification that the correct rod bank was selected prior to control rod movement.

The inspectors also observed test activities associated with Maintenance Procedure D32.

These activities were required to be performed twice during low power physics testing:

once with all the control rods withdrawn and once with all rods withdrawn except for the

[

control bank A, which was fully inserted. The purpose of the procedure was to determine

the isothermal temperature coefficient (lTC) at an established condition below the point of

adding heat and to verify that it was less that 5 percent millirho per degree Fahrenheit, as

required by TS 3.1.F,1.

The actual performance of the test, after initial plant conditions had been ostablished,

was accomplished by performing a reactor coolant system (RCS) cooldown followed by a

heatup. During each trsasient, a plot of reactivity versus temperature was obtained

during which time boron concentration and control rod position were kept essentially

constant. The magnitude of the cooldown and heatup, as required by Steps 7.2 and 7.3

of Maintenance Procedure D32, was approximately 5 degrees Fahrenheit ('F). More

specific guid1nce was contained in ANSI /ANS 19.6.1 1985 which was listed as a

reference for D32. Standard ANSI /ANS 19.6.1 1985 stated, as part of the test method to

determine the ITC, that reactivity and temperature should be continuously recorded while

RCS temperature is increased (decreased) by 3-10 *F.

During the second test per D32, the inspectors identified that an RCS cooldown of 2.4 'F

and an RCS heatup of 1.2 'F were used to determine the value for ITC. When the

inspectors questioned the nuclear engineer conducting the test about the procedural

requirement for an approximate 5 'F cooldown (heatup) while obtaining ITC data, i'.ie

nuclear engineer said that a sufficient RCS temperature change had been performed and

that the data was good enough to calculate ITC. The inspectors also discovered that the

first time the ITC test was performed with all control rods out, a 2.3 'F cooldown and

a 1.8 *F heatup were used. These discropancies were brought to the attention of the

superintendent of nuclear engineering. He agreed that Maintenance Procedure D32 was

not followed as written. He also said that because it was difficult to maintain a steady

cooldown (heatup) over a range in excess of about 3 'F, that the cooldown (heatup)

portions of the test had usually been performed with less than an approximately 5 *F

temperature change for many years.

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The inspectors detormined that sufficient temperature changes were accomplished to

obtain adequate data for calculation of the ITC, so this violation was of low safety

significance. However, failure to perform the ITC test per Procedure D32 as written, or

revise the procedure, despite numerous opportu,nties, demonstrated a lack of

appreciation for procedural requirerrents. There have been several cited violations for

failure to follow procedures documented in previous inspection reports. In addition, the

importance of procedure adherence was one of the topics in two recent management

meetings Corrective actions Mr the previous violations should have prevented this

procedure noncompliance, in addition, this violation was identified by the NRC.

Therefore, the event did not meet the criteria for discretion in the NRC Enforcement

Policy.

The failure to perform maintenance activities associated with Procedure D32 as written

was a violation of TS 6.5.A.4, which required that the licensee prepare and follow detailed

written procedures that control surveillance and testing requirements that could have an

effect on nuclear safety (50-282/97023-03(DRP)).

c.

Conclusion

The inspectors concluded that both the operators controlling the plant and the nuclear

engineers coordinating the performance of maintenance activities associated with

Procedure D32 Jid not follow the written instructions provided in the procedure pertain'ng

to the magnitude of cooldown (heatup) required forITC de armination. Even though the

engineers knew the proceduie requirements, they chose to do what had worked in the

past, instead of evaluating the way they were performing the test and changing the test to

reflect the actual test practice. This demonstrated a lack of appreciation for strict

compliance with procedural requirements.

M3

Maintenance P.-ocedures and Documentation

M3.1 Coo:ina Water System Walkdown and Suweillance Procedure Review

'i .

Inspection Scope (71707. 62707)

The inspectors conducted a walkdown of the Unit 1 and Unit 2 cooling water systems,

included in the inspection was a review of USAR, Section 10.4, * Plant Cooling System,"

Surveillance Procedures SP 1168.8, * Cooling Water System Operating Pressure Test,"

Revision 9, and SP 1168.8A, * Cooling Water System Auxiliary Operating Pressure Test,"

Revision 0, and a detailed review of the following American Society of Mechanical

Engineers (ASME) Code drawings:

NF 39819-1,'Cooiing Water ASME Code Classification Screenhouse Unit 1,"

Revision B;

NF 39819-2, * Cooling Water ASME Code Classification - Turbine Building Unit 1,"

Revision B;

NF 39819 3, * Cooling Water ASME Code Classification - Auxiliary Building Unit 1,"

Revision D;

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NF 39819-4," Cooling Water ASME Code Classification Containment Unit 1,

Revision C;

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NF 39841 1, * Cooling Water ASME Code Classification Turbine Building Unit 2,*

Revision A;

e

NF 398412," Cooling Water ASME Code Classification Auxiliary Building Unit 2,*

Revision E;

e

NF 398413,' Cooling Water ASME Code Classification Containment Unit 2,*

Revision C;

i

e

NF 39822, * Prairie Island Nuclear Generating P! ant Fuel and Diesel Oil System -

!

Units 1 & 2 ASME Code Classification Sheet 17," Revision A; and

)

NF 39833," Lab Service Area and Chilled Water Safeguards Systems -

I

Unt'.s 1 & 2 ASME Code Classification - Sheet 26," Revision D.

'

b.

Observations and Findinas

The inspectors observed the material condition of the Unit 1 and Unit 2 cooling water

systems and did not identity any significant discrepancies. All equipment and systems

matched the description found in USAR Section 10.4. However, surveillance Procedures

SP 1168.8 and SP 1168.8A contained 21 discrepancies.

,

SP 1168.8 and SP 1168.8A were required by TS 4.2 and the licensee's ASME Code

Section XI Insery!ce Inspection and Testing Program. Each surveillance was performed

at leasi once every 3% years. The surveillance directed that personnellook for evidence

of component leakage, structural stress, and corrosion, and that they inspect hangers

and restraints to detect any loss of support capability, missing or loose bolts, corrosion,

ed other problems.

SP 1168.8 contained the following procedural discrepancies:

a 12" diameter section of the cooling water supply line to the 22 component

e

cooling water heat exchanger was not required to be inspected by SP 1168.8;

a 24" diameter section of the Unit 1 cooling water retum header located just

e

upstream of the auxiliary building / turbine building wall penetration was not

required to be inspected by SP 1168.8;

e

two instances where SP 1168.8 listed valves not shown on the ASME Code

drawings;

three instances where the valve designations on the ASME Code drawings did not

e

match the valve numbers included in SP 1168.8;

one instance where ASME Code drawing NF 39819-3, Revision B, showed two 1"

e

diameter cooling water is otation valves in the same line when only one existed in

the plant; and

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une instance where two separate steps called for inspecting the same section of

the 24* loop A cooling water header.

.

SP 1168.8A contained 12 instances where valves named in the procedure as requiring

inspection were shown but not labeled on the referenced ASME Code drawings.

The inspectors noted that both SP 1168.8 and SP 1168.8A contained the same

precaution and limitations section S'.ep 3.2 stating,"The individual sign off steps are

intended as a guide; use the Code drawings and/or isometrics to verify alllines are

inspected." In most cases, using the ASME Code drawings and carefully tracking each

section of line inspected would preclude the inspector from missing portions of the Unit 1

and 1.' nit 2 cookng water system not described in SP 1168.8 or SP 1168.8A. In at least

two cases, however, SP 1168.8 or SP 1168.8A included the inspection of valves not

described on the ASME Code drawings. By usli '; the surveillance procedures, Code

drawings, and Isometric drawings as directed, individuals cc a orrectly perform the

inspection. Therefore, the procedures were not considered ... adequate.

The inspectors discussed the above findings with the system engineer prior to the exit

interview. The system engineer took prompt action to correct SP 1168.8, SP 1168.8A,

and the ASME Code drawings for the inspector identified discrepancies note.1 above,

c.

Conclusions

Several procedural deficiencies were identified in SP 1168.8 and SP 1168.8A. None of

the deficiencies were safety significant because the surveillance also required the use of

drawings to confirm that all sections of piping were inspected. However, the deficiencies

made the inspection task more difficult.

The cooling water system had recolved a great deal of review over the previous three

years in a licensee self assessment and NRC inspections. The inspectors were

concerned that a system that had received so much recent attention could still have

procedures containing so many errors. The inspectors considered SP 1168.8 and

SP 1168.8A reflective of the need to further improve pmcedures.

The licensee recently completed a pilot program to review a sampling of surveillance

procedures for accuracy and compilance with the writer's guide. Errors were reportedly

found in each of the surveillance procedures reviewed. The licensee was making plans

to extend the scope of the procedure review in light of those findings.

M3.2 Procedural Weaknesses Identified Durina Auxiiiarv Feedwater Pumn Testina

,

a.

ingoection Scope (61726)

The inspectors attended the prejob brief and observed the performance of testing per

SP 1301, "11 Turbine Driven Auxiliary Feedwater Pump A a Start and Function Testing "

Revision 8. The inspectors reviewed SP 1301 for procedural adequacy and compliance

with TS 4.8.A.8 and Table 4.1-1C, items 26 and 27, and USAR Section 11.9.

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b.

Observations and Findinns

The projob brief for SP 1301 was thorough and discussed communications, impacts of

ongoing Unit 2 electrical plant shifts with the surveillance, worker responsibilities, and the

procedural steps involved in each of the five functional areas being tested. During the

performance of the surveillance; however, three typographical errors were noted. Two

errors were Identified by the inspectors observing the evolution and one by the control

room operator supervising the surveillance. These errors are described below.

_

Stop 7.10.28 directed instrument and control personnel to positi,:a three switches in the

1 ARP5 Reactor Protection Logic Test Cabinet.1 he three switches in this cabinet were -

labeled 81, S2, and S3. Step 7.10.28, however, contained a typographical error and-

referred to the switches as S1,82, and S2. The error was so obvious that the

technicians performing the surveillance had no problems. The inspectors brought the

error to the attention of the operator who notified the control room.

Stop 7.11.5 verified that the AMSAC [ Anticipated Transient Without Scram Mitigation

System Actuation Circuit] INACTIVE annunciator in the control room was ON. The step,

however, contained a typographical errnt and identified the annunciator location as

47074 0606 when the correct location was 47014-0606. The noun name description for

the annunciator was correct in the procedure so it did not cause a performance problem.

The operator supervising the surveillance ir, the control room identified this error,

in Step 7.15.6, an operator was directed to push the 11 turbine-driven auxiliary feedwater

pump local stop push button Step 7.15.6 con:sined a typographical error and r.pecified

depressing the time delay reset push button PS 5101801 instead of the actuallocal stop

push button, PB-5101803. The noun name description in the procedure was correct so

the operator performed the correct action, even though the push button number was

incorrect. The inspectors observing the surveillance noticed this error and brought it to

the attention of the operator. The operator informed the control room.

The control room operator supervising performance of SP 1301 submitted procedure

deviation requests to correct the errors noted above following completion of the

surveillance.

c.

Corclusions

The three typographical errors identified in SP 1301 had no safety significance and did

r,ot prevent satisfactory performance of the surveillance. The inspectors were concemed,

however, that two of the three errors were NRC-identified and not noticed by the five

licensee personnel (one electrician, one instrument and control technician, two outplant

operators, and one control room operator) actually conducting the surveillance, in the

case of the two NRC-identified errors, the test performers did not use proper self-

= checkin2 techniques. They did not adequately check the switch numbers listed in the

procedure against the actval component label before completing the action.

SP 1301 was reviewed by the Operations Committee on Coptember 17,1997, and

approved by the superintendent mechanical systems on November 29,1997. This was

after the licensee placed a renewed emphasis on procedural adequacy and compliance.

- The three errors identified li. ::P 1301 highlighted the need for continued efforts in this

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area. As noted in Section M3.1 of this report, the licensee was evaluating an expanded

surveillance review program.

M8

Miscellaneous Maintenance Activities (92700,92902)

)

M8.1 (Closed) Inspection Followup Item (IFI) 50-282/97005 03fDRP): 50 306/97005-03(DRP):

'

Reactor Coolant System Vent and Containment Boundary Control During Integrated

Leakage Rate Test. This issue was previously discussed in inspection Report

No. 50-282/97005(DRP); 50-306/97005(DRP), Section M1.1. It involved a licensee-

identified procedure error in Unit 2 surveillance Procedure SP 2071.4, * integrated

Leakage Rate Test Prerequisites to the Containment Vesse! Integrated Leakage Rata

Test," Revision B. The test procedure was written in such a way that the reactor coolant

system could be vented before containmg.t integrity was established, which would have

been a violation of TSs. The inspectors verified that the Unit 1 test, SP 1071.4,

" Prerequisites to the Containment Vessel Integrated Leakage Rate Test," Revision 6, had

been revised to eliminate the problem before it was used. The inspectors also verified

'

that the system engineer had submitted a procedure revision form to ensure that the

Unit 2 procedure would be revised before its next use. The next expected Unit 2

integrated leakage rate test was planned to be conducted in the year 2006.

Ill. Enoineerina

E2

Engineering Support of Facilities and Equipment

E2.1

Review of Updated Safety Analysis Report (USAR) Comntitments (37551. 92903J

While performing the inspections discussed in this report, the inspectors reviewed the

applicablo portions of the USAR that related to the areas inspected and used the USAR

as an engineering / technical support basis document. The inspectors compared plant

practices, procedurcs, and/or parameters to the USAR descriptions as discussed in each

section. The inspectors verified that the USAR wording was consistent with the observed

plant practices, procedures, and parameters. No discrepancies were noted.

E2.2

General Comments (37551)

Throughout the inspection period, 'Se inspectors noted frequent involvement by system

engineers in all aspects of plant operations, refueling, maintenance, and surveillance

activities. The engineers rapidly investigated any operational abnormalities, took an

active role in maintenance and troubleshooting activities, and closely followed all

surveillance testing on their systems.

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E3

Engineering Procedures and Documentation

E3.1

ftilure to Test the Auto Start Feature of the Control Room Ventilation System Air

Handlers Due to Procedure Deficiency

a.

Inspection Scope (g2700)

On December 7,1997, as part of an investigation in response to NRC Generic

Letter 96 01, " Testing of Safety related Logic Circuits," the licensee discovered that the

automatic start of the 121 and 122 control room air handlers upon a st:rt of the

associated 121 and 122 control room cleanup fans, which was required to be tested by

TSs, had not been tested. The inspectors reviewed the circumstances and corrective

actions for the finding,

b.

Observations and Findinos

Technical Specification 4.14.A.2 required, in part, that once per operating cycle or once

every 18 months, whichever occurs first, the automatic initiation of the control room

special ventilation system be demonstrated with a simulated high radiation or safety

injection signal. A high radiation or safety injection signalis designed to start the control

room cleanup fans and operate various dampers. Starting of the clesnop fans will

subsequently result In the start of the main air handler fans. Without the air handler fans

running, the cleanup fans would be ineffective in performing the function of reducing

airborne radioactivity for control room operators.

The licensee discovered that the surveillance had normally been per4ormed with the air

handler fans already running in order to test the isolation function of the outside air

dampers. Thus, one of the automatic features had not been tested.

As discussed in the Licensee Event Report (LER 19718) for the finding, shortly before

the time of discovery, the auto start feature of both trains of control room ventilation had

coincidently been tested as part of a pre-operational test for a modification of the related

power supplies. The auto start features functioned normally during those tests. While

this indicated that the air handler fans' automatic start feature was functional, the failure

to test it as part of a formal surveillance test reflected a programmatic weakness in tha

surveillance testing program. The LER stated that the survelliance proceduret would ue

revised prior to the next scheduled test to require testing of the auto start feature. The

LER will rema.in open pending completion of the revisions (LER 50-282/97018;

50-306/97018).

The failure to perform a surveillance test of the auto start feature of the control room alt

handlers was a violation of TS 4,14.A.2. This non-repetitive, licensee-identified and

corrected violation is being treated as a Non-Cited Violation, consistent with

Section Vll.B.1 of the NRC Enforcement Policy (50-282/97023-04(DRP);

50-306/97023-04(DRP)).

c.

Conclusions

This finding, and the ones discussed in Sections EB.1 and F2.1 of this report indicated

that the licensee was conducting thorough design reviews in response to Genotic

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Letter 96 01 and other concems. Licensee employees demonstrated a wil:ingness to

identify old design discrepancies and compliance problems and the licensee rapidly

resolved those issues.

E8

t,11scellaneous Engineering issues (92700,92903)

E8.1

(Clesed) LER 50 282/97015: 50-306/97015 fi 9715h Both Trains of Control Room

Special Ventilation System Simu'taneously Inoperable. This LER discussed an issue,

identified on November 'J,1997, in which the licensee determined that routine

performance of a monthly surveillance on steam exclusion dampers had resulted in both

trains of control room sponial ventilation being inoperable because outside air dempers,

opened for the surveillance, would not have automatically closed on actuation of the

system on high radiation or safety injection. This could have resulted in the control room

operators' dose being higher than General Design Criterion 19 limits.

The cause of the event was the failure to properly review the control room ventilation

cystem logic and design requirements when the steam exclusion damper surveillance

was devcloped. The Feensee identified the issue as part of the development of revised

main steamline break control room dose calculations. As discussed in the LER, the

condition existed for only a few minutes each month and the operators would have had

ample indications and controls available to identify the problem and close the dampers if

an accident had occurred. The inspectors verified that all of the corrective actinns

discussed in the LER had been completed.

Monthly performance of the steam exclusion damper surveillance resulted in both trains

of control room special ventilation being inoperable, contrary to the requirements of

TS 3.13.A.1 which required that both trains be operable at all times. Although the TS

was violated, the associated action rwquirement to initiata within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> the action

necessary to place both units in hot shutdown, and be in at least hot shutdown within the

next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> and terminats core

alterations / fuel handling operations within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, was probably never exceeded.

This non repetitive, licensee identified and corrected violation is being treat?d as a

Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy

(50 282/97023-05(DRP); 50 306/97023 05(DRP)).

IV. Plant Suooort

R1

Radiological Protection and Chemistry Controls (71750)

During normal resident inspection activities, routins observations were conducted in the areas of

radiological protection and chemistry controls using inspection Procedure 71750. No

discrepancies were noted. The inspectors noted good involvement of radiation protection

personnel in job planning and execution in order to maintain doses as low as reasonably

achievable.

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Conduct of Emergency Preparednees Activities (71750)

During normal resident inspection activities, routine observations were conducted in the area of

emergency preparedness using Inspection Procedure 71750. No discrepancies were noteo.

81

Conduct of Security and Safeguards Activities (71760)

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.

F2

Status of Fire Protection Facilities and Equipment

F2.1

Separation of Pressurizer Level Indication Channels Not in Comollance with

10 CFR Part 50. Accendix R. Section Ill.G.2

a.

laspection Smoe (92700)

On December 6,1997, the licensee reported to the NRC in accordance with

10 CFR 50.72 that the plant was in a condition outside of the design basis because the

licensee had discovered that the pressurizer level channel cables in Unit 1 containment

were not separated as required by 10 CFR Part 50, Appendix R. The inspectors

r

reviewed the circumstances and corrective actions for the finding,

b.

Qbtervations and Findinas

The issue was first identified during a walkdown of the containment on

November 14,1997, to support an Appendix R Safe Shutdown Analysis revision. The

licensee noted that the pressurizer level detectors were not located as shown on plant

layout drawings and that the pressurizer level channels old not have adequste separation

of the detectors and the associated cables to meet the requirements of Appendix R. The

drawings indicated adequate separation but the as Lailt configuration did not match the

drawings.

At first the licensee believed that an exemption from the NRC might have been grants d

for the existing installation. As discussed in the associated Licensee Event Report

(LER 1-97-17), the documentation regarding various Appendix R exemptions was

somewhat confusing and incomplete. By December 6, the licensee determined that an

appropriate exemption did not exist and the cabling would have to be modified to meet

Appendix R.

Within the next few days a modification was developed and installed to provide a

'

noncombustible radiant energy shield around one channel of the cabling to satisfy

Appendix R requirements. The inspectors walked down the installation and it appeared

that the energy shieH was adequate.

The licensee issued LER 19717 on January 2,1998. The inspectors reviewed the LER

and determined that it adequately discussed the beckground, safety significance, and

corrective actions for the subject Appendix R non compliance. The LER will remain open

pending completion of corrections to the plant layout drawings (LER 50-282/97017).

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Sedion lll.G.2 of App 9ndix R, of 10 CFR Part 50, requires, in part, that cables and

equipment and associated non safety circuits of redundant trains of equipnient necessary

to achieve and maintain hot shutdown conditions in non-inerted containments, be

4

4

protected from potential fire Jamage. This could be achieved through separation of

more than 20 feet with no intervening combustibles or fire hazards or by having installed

a

'

fire detection tend automatic suppression, or through separation by noncombustible

j.

radiant energy shields. The licensee 6dentified that the redundant pressurizer level

i

detector cables in :he Unit 1 containment did not satisfy any of these conditions and thus

'!

a violation of NRC requirements existed. As discussed in the LER, the condition had

j

M!stively low safety significance and was promptly corrected when the noncon.pliance

j

was confirmed. Thi6 non repetitive, licensee-identified and corrected violation is being--

treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement

Policy (50 282/97023-06(DRP)).

i

}

c.

Conclusions

f

The licensee's finding was the result of a proactive voluntary review of fire protection

.

i

issues and revision of tire protection analysis. Prompt corrective actions were taken

3

when the condition v as confirmed.

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V Mananoment Meetinos

,

X1

Exit Meeting Summary

The inspectors presented the inspection retu;is to members of the licensee management at the

conclusion of the inspection on January 13,1998. The licensee acknowlectged the findings

presented. The inspectors asked the licensee whether any materials examined during the

4

inspection should be considered proprietary No proprietary information was identified.

$

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0-

PARTIAL List OF PERSONS CONTACTED

Licensee

J. Sorontsn, Plant Manager

K. Albrecht, General Superintendent, Engineering, Electrical / Instrumentation & Controls

T. Amundson, General Superintendent, Engineering, Mechanical

J. Goldsmith, General Superintendent, Engineering, Generation Services

J. Hill, Manager, Quality Services

G. Lon3rtz, General Superintendent, Plant Maintenance

J. Maki, Outage Manager

D. Schuelke, General Superintendent, Radiation Protection and Chsmistry

T. Silverberg, General Superintendent, Plant Operations

M. Sleigh, Superintendent, Security

_

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lNSPECTION PROCEDURES USED

l

lP 07551:

Engineering

IP 61726:

Surveillance Observations

IP 62707:

Maintenance observations

IP 71707:

Plant Operations

IP 71711:

Startup from Refueling

IP 71750.

Plant Support Activities

IP 92700:

Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor

Facilities

IP 92901:

Follow up - Operations

IP 92902:

Follow up - Maintenance

IP 92903:

Follow up - Engineering

ITEMS OPENED, CLOSED, AND DISCUSSED

Qllen9A

50-282/97023-01(DRP)

NCV

Failure to Perform Step in Reactor Startup Procedure

When Called For

50-282/97023-02(DRP)

NCV

inadequate Procedure for Turtaine Torsional Testing

50 282/97023-03(DRP)

VIO

Failure to Perform Two Steps in Reactor Physics Testing

Procedure as Written

50-282/97023-04(CRP)

NCV

Failure to Test the / % Start Feature of the Control Room

50 306/97023-04(DRP)

Ventilation System il- Handlers due to Procedure

Deficiency

50-282/97023-05(DRP)

NCV

Both Trains of Control Room Special Ventilation System

50-300'97023-05(DRP)

Simultaneously inoperable

50 282/97023- 06(DRP)

NCV

Separation of Pressurizer Level Indication Channels Not in

Compliance with 10 CFR Part 50, Appendix R,

Section Ill.G.2

50 282/97017 LER

Separation of Pressurizer LevelIndication Channels Not in

Compliance with 10 CFR Part 50, Appendix R,

Section Ill.G.2

50-282/97018

LER

Failure to Test the Auto-Start Feature of the Control Room

5B Gi97013

Ventilebon System Air Handlers due to Procedure

Deficiency

Closed

50-282/97005-03(DRP)

IFl

Reactor Coolant System Vent and Containment Boundary

(.

50-306/97005-03(DRP)

Control During Integrated Leakage Rate Test

50-306/97005

LER

Sudden Pressure Lockout of No.10 Transformer Resulting

in Auto Load Rejection / Restoration on Safety-Related Bus

25

(

~

.

, ' ?. 0

.

.

50-282/97015

LER

Both Trains of Control Room Special Ventilation System

!

50-306/97015

Simultaneously Inoperable

1

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, . ',i %

1*

LIST OF ACRONYM 8 USED

AMSAC

Anticipated Transient Without Scram Mitigation System Actuation Circuit

ANSI /ANS

Americcn National Standards Institute, Inc/American Nuclear Society

ASME

American Society of Mechanical Engineers

CFR

Code of Federal Regulations

D/F

Differential Pressure

DRP

Division of Reactor Projects

DMIMS

Digital Metal impact Monitoring System

'F

Degrees Fahrenheit

IP

inspection Procedure

ITC

isothermal Temperature Coefficient

LER

Licensee Event 9eport

LPE&RO

Lead Plant Equipment and Reactor Operator

NRC

Nuclear Regulatory Commission

PDR

Public Document Room

RCS

Reactor Coolant System

RO

Reactor Operator

SP

Surveillance Procedure

SS

Shift Supervisor

SWI

Section Work Instruction

TS

Technical Specification

USAR

Updated Safety Analysis Report

WO

Work Order

? :

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I