ML20197F393

Insp Repts 50-321/97-10 & 50-366/97-10 on 971005-1115. Violations & Deviations Noted.Major Areas Inspected:Maint, Engineering,Plant Support & Operations Re Health Physics Concern

ML20197F393
Person / Time
Site:	Hatch
Issue date:	12/15/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20197F340	List: ML20197F333 ML20197F357 ML20197F371 ML20197F393
References
50-321-97-10, 50-366-97-10, NUDOCS 9712300208
Download: ML20197F393 (62)

See also: IR 05000321/1997010

Text

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U.S. NUCLEAR REGULATORY COMMISSION

REGION 11

Docket Nos: 50 321, 50-366

License Nos: DPR-57 and NPF-5

Report No: 50-321/97-10. 50-366/97-10

Licensee: Southern Nuclear Operating Company. Inc. (SNC)

Facility: E. 1. Hatch Units 1 & 2

Location: P. O. Box 2010

Baxley. Georgia 31515

Dates: Cctober 5 - November 15. 1997

Inspectors: B. Holbrook, Senior Resident Inspector

J. Canady, i<esident Inspector

G. Kuzo. Senior Radiation S)ecialist. (Sections

RI.2. R1.3. R3.1. R7.1. 18.1, and R8.2)

W. Kleinsorge. Reactor Inspector. (Section M1.3)

R. Carrion. Project Engineer (Sections 08.1,

M8.1, M8.2 E8.1. E8.2. F8.1. and F8,2)

Accompanying inspector: T. Fredette -

Apprcsed by: P. Skinner Chief. Projects Branch 2

Division of Reactor Projects

Enclosure 3

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EXECUTIVE SUMMARY

Plant Hatch. Units 1 and 2

NRC Inspection Report 50-321/97 10. 50 366/97-10

This integrated inspection included aspects of licensee operations.

engineering. maintenance, and plant support. The report covers a 6 week

period of resident inspection and region based specialist inspection.

Doerations

e Excellent operator response on Unit 1 prevented a potential unit

scram due to a loss of condenser vacuum on October 6 '

(Section 01.1).

e Operator performance during the shutdown of Unit 1 for the

scheduled refueling outage was excellent. Supervisory and

management Jersonnel provided oversight and direction when

required. >rocedures were used appropriately and communications

were clear and concise (Section 01.2).

e Operations personnel com)leted all fuel movements and in-vessel

work activities during t1e Unit I refueling outage with no fuel

movement errors (Section 01.3).

• A selection of Technical Specification-required surveillances for

fuel movement was verified to be satisfactorily completed and at

the required frequency (Section 01.3),

o Heavy load movements observed by the inspectors were in the

designated heavy load pathways and were performed as required by

the procedure-(Section 01.3).

• Health Physics supervision was routinely observed on the refueling

floor and provided assistar.ce and directions. The radiological

controlled areas (RCAs) were clearly identified and marked with

rope and tape. The inspectors did not identify any radiological

control deficiencies on the refueling floor (Section 01.3).

• Vendor personnel inspected two fuel bundles, and other than one

piece of non-metallic debris that was removed from one bundle, no

deficiencies were identified (Section 01.3).

e Procedural. Technical Specification, and regulatory requirements

reviewed in preparation for the Unit 1 startup, were being met.

Senior site management, department management, and responsible

supervisors provided oversight and direction for the startup

activities. With noted exceptions, communications were generally

clear (Section 01.4).

e Operations personnel took the appropriate actions when the reactor

core isolation cooling system failed an operability test from the

Enclosure 3

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remote shutdcwn panel. Engineering and maintenance provided good

troubleshooting support (Section 02.1).

e Unit 1 systems used for reactor vessel decay heat removal were in

good operating condition and properly controlled decay heat. The

Final Safety Analysis Report. Technical Specifications. Unit 1

Outage Safety Assessment, and system procedural requirements for

decay heat removal system availability were met (Section 02.2).

e Operations management, supervision, and control room operators

demonstrated a safety conscious awareness for Unit 1 operation

during times of high decay heat loads (Section 02.2).

e Material conditions and general housekeeping in the Unit I drywell

just prior to the filal drywell closeout were good. The new

mirror-backed insulation installed on the reactor, as part of the

drywell insulation upgrade initiative, was in excellent condition.

No indications of system or component leakage were ooserved

(Section 02.3).

e Poor operator performance with es)ect to procedure usage, as well

as othcr administrative controls t1at were not completed, led to

the failure tt meet Technical Specification recuirements prior to

withdrawing a control rod. This was identifiec as Violation (VIO)

50-321/97 02. Failure to Meet Technical Specification Surveillance

Requirements to Withdrawal of a Control Rod While in Cold Shut bwn

(Section 04.2).

e The Significant Occurrence Reports (SOR) reviewed by the

inspectors were correctly classified and were being correctly

tracked by the commitment tracking system and plant procedures

(Section 07.1).

e The recommended schedule for determining root cause and corrective

action recommendation was appropriate for the deficiencies

reviewed. SORS were receiving senior level management as well as

department level management attention (Section 07.1).

thlintenance

e Maintenance activities reviewed or observed were completeJ in a

thorough and professional manner. Supervisory oversight was

evident (Section M1.1).

e Work activities to move new Emergency Core Cooling System suction

strainers from the warehouse to the torus were well-controlled.

Health physics and engineering personnel provided good oversight

and direction. Foreign material exclusion controls were excellent.

Onsite engineering issues were resolved in an appropriate and

timely manner (Section M1.2).

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e Unit 1 inservice inspection activities observed or reviewed were

conducted in accordance with procedures, licensee commitments, and

regulatory requirements (Section M1 3).

e Maintenance and operaticns personnel interfaced effectively during

the Unit 1 main transformer backfeed activities. The licensee

exhibited good overali planning and oversight throughout the

evolution. Operations provided good oversight on establishing the

necessary equipment clearances to remove the 10 Start Up

Transformer from service (Section M1.0 .

e The licensee had taken initial ste)s to address problems with

Westinohouse Type DHP circuit brea ers in July 1997, based on

problems and events at other utilities. The actions and

recommendations of the Event Review Team in response to the recent

circuit breaker failures were sound and appropriate

(Section M1.5).

• Additional examination by the inspectors of the licensee's

preventive maintenance (PM) program for 4160-volt breakers is

warranted based on the recent failures and the fact that two of

the breakers had undergone PMs within the past nine months

(Section M1.5).

e for the surveillances observed, the data met the required

acceptance criteria and the equipment performed satisfactorily.

The performance of the operators and crews conducting the

surveillances was generally professional and competent. Some

exceptions were noted during this inspection period (Section

M3.1).

e The lack of attention to detail was a contributing factor for an

incorrect )lacement of a Jumper during a testing activity on

Unit 1. Tae error was identified as NCV 50-321/97-10-03. Jumper

Placement Error During Unit 1 Testing Activities (Section M4.1).

e The Unit 1 Periodic Type B and C Leakage test and required

corrective maintenance were performed per applicable procedures.

The final test results met plant procedure and regulatory

requirements. Supervisory oversight was evident (Section M4.2).

Enqineerina

e The licensee's corrective actions for both units in res)onse to

Generic Letter (GL) 96-06. Assurance of Equipment Operaaility and

Containment Integrity During Design Basis Accident Conditions,

! were completed within the committed time (Section E2.1).

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e The alternative tests of the Unit 1 Safety / Relief Valves were

c mpleted in accordance with plant procedures and as specified in

b lief Request RR-V 11. Inservice Testing of Safety / Relief

Valves - Edwin 1. Hatch Nuclear Plant. Units 1 and 2. All test

data met the acceptance criteria (Section E2.2).

e The actions taken to inspect and clean the Unit 1 torus were good.

Foreign Material Exclusion controls were properly implemented.

Management was actively involved. The small amount of debris

found in the torus did not present a risk for emergency core

cooling system suction strainer blockage (Section E2.3).

e The licensee actions taken to implement Technical Specification

Amendments 204 and 145 for the Standby Liquid Control System were

timely and correct. The completed Standby Liquid Control System

surveillances verified that pum) flow and discharge pressure

requirements were met (Section E2.4).

e The 10 CFR 50.59 evaluation for the GL 89-10 modifications

implemented by Design Change Request 96 005. was appropriate.

Foreign material exclusion control for the High Pressure Coolant

injection (HPCI) 1E41 F001 valve work activity was excellent.

Operations 31acement of clearance tags was correct. The American

Society of iechanical Engineers (ASME)-required VT-3 code

inspection for HPCI valve 1-E41-F006 was satisfactorily completed

(Section E2.5).

e The initial Unit 1 Condensate Storage Tank entry to perform

desludging activities was not well-planned. Foreign material

exclusion controls were in place and were properly implemented.

The presence of health physics personnel was observed and securit)-

personnel were present to provide emergency personnel recovery

actions (Section E2.6).

• Engineering personnel provided good oversight and coordination in

respcase to the GL 96-01. " Testing of Safety-Related Logic

Circuits." for Unit 1 Emergency Diesel Generators and emergency

switchgear. Test results met the appropriate acceptance criteria

(Section E2.7).

• Licensee actions taken to correct a missed commitment for Unit 2

Technical Specification Amendment 132 were appropriate. The ASME

code-required testing completed in October 1997 was satisfactory.

This problem was identified as Deviation 50-366/9/-10-04. Missed

Commitment for Unit 2 Technical Specification Amendment 132

(Section E3.1).

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e Design Change Request work packages reviewed by the inspectors

were generally thorough and detailed. The 10 CFR 50.59

evaluations reviewed were detailed, thorough, and appropriate.

Changes to procedures, drawings, and TSs were identified when

required. Work observed was yerformed in accordance with

applicable procedures and wort packages (Section E3.2).

e NCV 50-321/97-10-09. Personnel Error During 10 CFR 50.59

Evaluation Review and Procedure Revision Process For Residual Heat

Removal On-line Testing, was identified. The licensee's completed

and planned corrective actions to revise the Updated Final Safety

Analysis Report (UFSAR), assess corporate's UFSAR review process,

enhance future 10 CFR 50.59 training and evaluation procedures,

and the issuance of a department directive to explain the

procedure review requirements, were appropriate (Section E3.3).

e The reactor pressure vessel leakage and reactor recirculation pump

runback tests were performed in accordance with approved

procedures, technical specifications, and conditions specified in

the UFSAR. The activities were performed with good coordination

between engineering, operations, and maintenance. The performance

of the pressure tests and the leak repairs was excellent

(Section E4.1).

Plant Suongrt

e in general, radiological controls, area postings and container

labels were maintained in accordance wit 1 Technical Specificctions

and 10 CFR 20. Appendix J requirements (Section R1.2).

e The failure to label eight vacuum filters stored within Bay 13 of

the Unit 1 torus was identified as VIO 50-321/97-10-05. Failure to

Label Containers of Radioactive Material in Accordance with

10 CFR 20.1904 Requirements (Section R1.2).

e External exposure controls for Unit 1 outage tasks were effective

in maintaining personnel doses significantly less than 10 CFR

Part 20 limits (Section R1.2).

e Radiation exposure and contamination controls were effective with

isolated examples of poor radiation practices identified

(Section Rl.2).

e The detailed survey maps developed by health physics to identify

the hazards present in the Unit 1 torus were not always effective

(Section R1.2).

e Licensee controls for minimizing internal exposure were effective,

with potential uptakes of radianuclides evaluated appropriately

(Section R1.3).

Enclosure 3

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e Records for determining workers' prior yearly occupational

exposures and granting administrative exposure extensions were

established in accordance with 10 CFR Part 20. Subpart L

requirements and administrative procedures (Section R3.1).

• Licensee quality control checks identified that several pieces of

slightly contaminated concrete were released to the onsite

landfill (Section R7.1).

o initiatives to address and reduce worker personnel contaminations

were effectively implemented (Section R8.1).

o NCV 50 321. 366/97-10-07. Failure to Have Adequate Surveillance

Procedures to meet the Containment High Range Radiation Monitors

Electronic Signal Substitution Calibrations Specified in

NUREG 0737. Table ll.F.1-3. was identified (Section R8.2).

e The areas of security inspected met the applicable requirements

(Section S2).

e The portion of the monthly fire protection inspection observed by

the inspectors was well performed. The fire protection engineer

was knowledgeable of the job responsibilities and fire protection

equipment. The on-the-spot correction of some minor deficiencies

was appropriate. The deficiency cards initiated to identify and

track other problems were timely (Section F3.1).

Enclosure 3

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Reoort Details .

Summary of Plant Status ,

Unit 1 began the report period at about 96% Rated Thermal Power (RTP).

Power was reduced to approximately 66% RTP on October 6 when the main

condenser vacuum began decreasing while >erforming a clearance to isolate

the "B" Steam Jet Air Ejector (SJAE). T1e valves changed by the

clearance were returned to their original position and reactor power was '

restored to the maximum achievable the next day. Operations began

reducing unit power on October 10 for the scheduled seventeenth refueling

outage. The unit was manually scrammed on October 11 to begin the

refueling outage. The unit remained in the refueling outage for the

remainder of the report period.

Unit 2 began the report period at 100% rated thermal power (RTP). The

unit operated at this power level for the remainder of the report period,

except during routine testing activities.

L Operations

01 Conduct of Operations .

01.1 General Comments (71707)

The inspectors conducted frequent reviews of ongoing plant

operations. Unit 1 power was reduced to approximately 66% RTP on

October 6 when the main condenser vacuum began decreasing while

performing a clearance to isolate the "B" Steam Jet Air Ejector

(SJAE). The valves were returned to their original position and

power was restored to 100% RTP the next day. Trouble shooting

revealed that a closed valve was leaking by and caused the

decrease in vacuum. Operator response to decreasing condenser

vacuum was excellent. In general, the conduct of operations was

professional and safety-censcious. Specific events and

observation are detailed in the section below.

01.2 Observations of Unit 1 Shutdown for Refuelina

a. Insnection Scoce (71707) (60705)

The inspectors reviewed procedures 34G0-0PS-065-OS. " Control Rod

Movement." Revision (Rev. ) 2. and 34GO-0PS-005-15. " Power

Changes," Rev. 20. Edition (Ed) 1, and observed operator

performance during Unit 1 shutdown to begin the scheduled

refueling outage,

b. Observations and Findinos

During the power reduction and manual scram of Unit 1, the

inspectors observed that appropriate procedures were used and

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communications between operators and supervisors were clear and

concise. Command and control by the Shift Supervisor (SS) was

l excellent. The SS conducted pre evolution briefings prior to

I major activities, made specific assignments for critical

l- functions, and conducted peer checks for ongoing activities. The

inspectors observed that the operations manager was present in the  ;

! control room to observe activities and provided oversight-and '

l direction when required.

The inspectors observed procedure 341T-N30-004 15. " Turbine

Overspeed Tri) Test." Rev. 1. being implemented by operations

personnel. T1e inspectors also observed that a vendor

representative was in the main control room to provide assistance

during the test. The inspectors observed that procedures were

used, communications were clear and concise, and operators used

all available control board indications to verify that the test

was satisfactorily performed.

The SS-conducted a crew briefing just prior to the manual scram of

the unit. The briefing was thorough and specific. Specific

assignments were made, past personnel and unit performance was i

reviewed, and contingency plans were discussed. The inspectors

observed that the operators' performance during and following the >

manual scram was excellent. All ecuipment operated as expected

and no deficiencies were identifiec.

c. Conclusions

Operator performance during the power reduction and manual scram

of Unit 1 for the scheduled refueling outage was excellent.

-Supervisory and management personnel provided oversight and

direction when required. Procedures were used and communications

were clear and concise.

01.3 General Refuel Floor Observations for Unit 1

a. Insnection Scone (71707) (60710)

The inspectors reviewed procedures 51GM-MLH-004-05, " Heavy Loads

Movement Procedure." Rev. 11. 52-GM-MME-004-15. " Reactor vessel .

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Reassembly." Rev. 9. 52GM MME-005 lS. " Installation and Removal of

Drywell Equipment Hatches." Rev. 2. Ed 1. and 52GM-MME-015-1S,

" Reactor Vessel Disassembly." Rev. 6. 51GM-MNT-002-0S.

" Maintenance Housekeeping." Rev.12. Ed 2. and observed work

activities in 3rogress to verify that activities were completed in

accordance wit 1 applicable procedures.

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b. Observations and Findinos

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The inspectors observed that the refueling floor coordinator

monitored ongoing work activities and was cognizant of refuel  !

floor equipment status and scheduled evolutions. Overhead crane

activities were monitored and directed by an individual designated

to direct crane movements. To be readily identified by the crane i

operator, the designated person wore an orange vest, rs required i

by procedure. The heavy load moves observed by the inspectors

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were in the designated heavy load pathways required by the

procedure. The inspectors did not observe any housekeeping

deficiencies on the refueling floor. t

Health Physics (HP) personnel were observed monitoring work ,

activities that required HP assistance. HP supervision was  ;

routinely observed on the refueling floor providing assistance and

direction. The radiological controlled areas (RCAs) were clearly '

identified and marked with rope and tape. The inspectors did not

observe any deficiencies with respect to the RCA boundaries.

The inspectors reviewed ]rocedures 34FH-0PS-00105. " Fuel Movement

Operation," Rev. 16. 42F1-ERP-014-0S " Fuel Movement." Rev. 12.

and routinely observed fuel movement activities from the refuel

floo, and control room. The inspectors did not observe any

deficiencies with respect to refueling activities. A selection of

fuel movement Technical Specification (TS) required surveillances

was verifled to be completed at the required frequency. No

deficiencies were observed. Operations personnel on the refuel

floor responsible for all fuel movements and some in-vessel work ,

activities completed the work task with no fuel movement errors.

Vendor personnel conducted an inspection of two fuel bundles: one

GE13LUA bundle and one GE12LUA bundle. The inspectors observed

part of the fuel inspection activities and reviewed the vendor's

report of the inspection. The report indicated that both bundles

were in excellent condition and acceptable for continued

irradiation. A piece of debris was found and successfully removed

from bundle YJE950 (GE12LUA). The debris was white in color:

appeared to be non metallic; and was located below spacer 7 on ,

side 4 and wedged between rod C1 and spacer 7. No other i

deficienries were reported. ,

c. Conclusions

Operations personnel completed all fuel movements and invessel

work activities with no fuel movement-errors. A selection of fuel

movement TS mquired surveillances was verified to be completed at

the required frequency. The heavy load moves observed by the

inspectors on the refueling floor were in the desigriated heavy ,

load pathways-required by the procedure. HP supervision was ,

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routinely observed on the refueling floor providing assistance and ,

directions. The RCAs were clearly identified and marked with rope  ;

and ta,s. Vendor personnel inspected two fuel bun'iles and other  !

than one piece of non metallic debris that was removed from one I

bundle, no deficiencies were reportea. i

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01.4 Prenarations for Startuo Followina Refuelina Outaae Unit 1

a. Insoection ScoDe (71707)

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Theinspectorsreviewedgrocedures34G00PS003-15."Startup l

System Status Checklist. Rev. 9. and 34GO 0PS-001 15. " Plant  !

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Startup." Rev. 26. Unit 1 TSs. and reviewed licensee preparations I

to startup Unit 1 following the seventeenth refueling outage.  !

Inspector activities included documentation review and- S

observaticns in the Unit 1 main control room and at selected local e

control panels.

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b. Observations and Findinas  !

On November 14 and 15. the inspectors conducted reviews for i

preparation of the Unit 1 startup. Startup activities _were still i

ongoing at the end of this inspection report period. The

inspectors observed that the sections of the completed procedure 't

checklist matched unit conditions. Emergency Core Cooling Systems

(ECCS)-checklist completed was consistent with actual system  ;

lineups in the control room. The inspectors reviewed selected  ;

local valve positions and verified that the valves were positioned  !

as specified in the procedure checklist. Selected local.ECCS  !'

instrument indications were verified to be consistent with control

room indications. Selected normal and alternate ECCS breakers

were verified to be closed or in standby for emergency start

conditions.

The inspectors verified that the TS requirements for reactor

feedpump trip on high reactor water level, main steam line i

radiation monitor setpoints, cold shutdown valve operability, and

Local Power Range Monitor 1/V test were satisfactorily completed.

The inspectors observed that site senior management, as well as

department managers and supervisors, provided.oversite and

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direction of startup and control room activities as required.

Operations personnel maintained a professional demeanor in the

control. room. Control room supervision ensured that all

unnecessary personnel and discussions were outside the-control -i

room area. Communications with and between operations personnel

and other departments were generally three-part communications

which were clear and concise. Some exceptions to clear three part  ;

communications were noted and discussed with operations

management.  :

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c. Conclusions

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The inspectors concluded that the proceduial. TS. and regulatory

requirements reviewed for the Unit I startup were being met.

Senior site management.. department management, and responsible

supervisors provided oversight and direction for the Unit 1

startup activities. Some exceptions to clear three-part

corrinunications were noted and discussed with operations

management.

02 Operational Status of Facilities and Equipment l

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02.1 Unit 1 Reactor Core Isolation Coolina (RCIC) Failure to 00erate

from the Remote Shutdown Panel (RSP)

a. Insnection Scone (71707) (92901) (3755U

The inspectors reviewed operator performance of surveillance

procedures 345V-E51-005-lS. "0)eration of RCIC from the Remote <

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Shutdown Panel." Rev. O. 345V- 51-002 IS. 'RCIC Pump 0)erability."

Rev. 18. and Maintenance Work Order (MWO) 1-97-1228. )iscussions

were conducted with licensee personnel with respect to RCIC system '

failure to operate from the RSP.

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b. Observations and Findinos ,

On October 9. the inspectors attended the pre job briefing for the

performance of surveillance procedure 34SV E51-005-lS. Operations

personnel led the pre job briefing discussions. lhe inspectors

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observed health physics. engineering, and instrumentation and

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control personnel at the pre-job briefing. ,

The inspectors observed portions of the surveillance 3ert d ,

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from the control room. RSP, and the RCIC pump room. Juring the i

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surveillance performance from the RSP. sufficient flow and

pressure could not be obtained due to lower-than normal RCIC

turbine speed. lhe licensee decided to restore the system to its

normal control room alignment and perform an operability

surveillance from the control room in accordance with surveillance

procedure 345V E51 002-15. The performance of the surveillance

from the control room was successful. 4

The licensee entered a 30 day required action statement (RAS) in

accordance with TS 3.3.3.2 due to the inoperability of RCIC from

the RSP. The inspectors reviewed TS 3.3.3.2 and determined that

the appropriate TS actions were taken. The unit shutdown for a

refueling outage on October 11. prior to the 30-day expiration of

the RAS.

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The inspectors discussed the problems encountered in running the

RCIC system from the RSP with the system engineer on November 12.

The system engineer informed the inspectors that the data ,

acquisition system used to monitor various parameters associated '

with the system indicated that a possible problem existed with the i

governor valve (lE51-F523). The inspectors observed that an MWO i

was initiated on May 22. 1997. to replace the Unit 1 RCIC governor

valve stem with an inconel stem. The inspectors later confirmed  :

that this work was completed. (The Unit 2 RCIC stem was upgraded

during the last refueling outage in 1997.)

However. with the new stem installed, the valve could not be -

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manually moved into the open position. The original valve stem

was reinstalled into the valve because the valve could be moved to -

the open position during the "as-found" inspection. Although this

action did not correct the movement problem, it did rule out the

possibility of the problem being caused by the stem. j

Further troubleshooting activities by maintenance and engineering

personnel revealed a scale deposit in the bottom portion for the

control valve body (valve bonnet bore). The scale was not readily

visible and was identified with the use of a magnifying glass, i

The scale caused the first steel washer and subsequent carbon '

washers (spacers) to become positioned at an angle to the valve.

rausing friction on the valve stem. The washers realigned

properly during valve movement in the closed direction but  ;

presented friction to the valve stem for the open direction. This

scale material was machined out. The new stem was placed into the

valve, as aart of a pre planned outage activity. This activity

resolved tie movement problem. The system engineer indicate) that

the scale buildup was probably due to impurities in the steam and t

years of operation.

The inspectors reviewed the root cause analysis and noted that the

system engineer concluded that the restriction to the governor

valve movement was not due to the governor valve stem corrosion.

The restricted movement was due to mis-aligned carbon spacers

binding on the governor valve stem in the open direction. The

inspectors observed that the engineer determined that the cause of i

the spacer misalignment was due to a scale buildup in the valve.

The inspectors reviewed Information Notice (IN) 94 66, dated

September 19, 1994. "Overspeed of Turbine Oriven Pumps Caused by

Governor Valve Stem Binding." and Supplement 1 to the IN. dated >

June 16. 1995. The IN identified several sites where corrosion  :

between the valve stem and spacers in the Jacking assembly caused '

RCIC failures. The inspectors reviewed t1e licensee's assessment

of the problem described in the IN. Following the IN review. .

dated January 5. 1995, licensee personnel concluded that the

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3roblems described in the IN were not a problem at Hatch. They  !

Jased the conclusion on the fact that 3rocedures were in place to

perform the RCIC functional test and t1at calibrations were f

performed once per operating cycle, not to exceed 18 months and i

the procedure for major inspection and overhauls was performed

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every 6 years. Additionally, the RCIC performance monitoring .

system would detect malfunctions similar to those described in the e

IN. They also based their conclusion on the fact that the RCIC  !

system had a barometric condenser which pulls a vacuum and removes  :

the steam from the valve stem gland seals, and trip throttle j

valve area. The assessment of the supplement to the original IN *

stated that no additional events were cited which required further

response to that already stated in IN 94 66, and no further i

licensee action was required. Licensee personnel stated that for 1

the RCIC inspection completed during the 1994 Unit I refueling ,

outage, no corrosion or buildup of mineral de)osits were observed.  :

Licensee personnel summarized the assessment )y stating. " Plant .

Hatch surveillances inspections, and calibrations, along with i

installed monitoring equipment for the RCIC system. provide the

necessary detection to prevent the described event from occurring ,

at Plant Hatch." ,

The inspectors observed that the licensee had identified a problem fi

with the Unit 1 RCIC governor valve on April 29, 1996, during

startup following the refueling outage. In this instance. the +

governor valve stuck nearly closed for about 92 seconds then  ;

released and the system then operated properly. This problem was L

being monitored by operations and the system engineer. No

additional problems were identified until October 9. 1997. The

'

inspectors observed that for the two recent Unit 1 RCl,: 3roblems.

the RCIC monitoring detection system identified both pro)lems.  !

The inspectors conducted a review of the performance history for

the governor valve for both units and did not find evidence of  ;

other RCIC valve sticking problems. The inspectors noted that the

Unit 2 RCIC stem was upgraded during the last refueling outage in

1997. ,

The root cause determination for the most recent valve failure was l

detailed. However, no specific actions were recommended to

prevent recurrence. The inspectors discussed this problem with ,

'

management )ersonnel responsible for the root cause determination

program. T1e inspectors were informed that a review the of the IN l

and recent RCIC problems would be completed to ensure that

-

appropriate actions were taken to prevent recurrence. The .!

ins)ectors were later informed that the maintenance procedures of

bot 1 units would be revised to include monitoring for scale

buildup.  ;

P

Enclosure 3

!

i

"

- , . _ _ . , - - . , _ . , , _ . , - . . . ..._-s,...

_ _ - _ _. - - ~ _ . . _ _ _ _- _ _ _ _ _ __ _ _

,

.

I ,

i

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8

! The inspectors were informed that the Unit 1 RCIC system would be _

run from the RSP during startup when reactor pressure achieved l

.

920 )sig. The inspectors verified that the testing activity was  !

l on t1e startup schedule and was being actively tracked. The  !

inspectors' review of this testing activity was identified as

'

Inspector Follow up Item (IFI) 50-321/97 10-01: Review of Unit 1

RCIC Testing Activities from the Remote Shutdown Panel,

c. Conclusions

i

Operations personnel took the appropriate act ...s for the RCIC

system when it failed an operability test run from the remott,

shutdown panel. Engir.eering and maintenance provided good trouble

shooting support.

!

02.2 Review of Decay Heat Removal (DHR) Systems for Unit 1 Refuelina

a. Insoection Scone (71707) (60705)

The inspectors reviewed procedures 3450 G71 001-05, " Decay Heat

Removal System." Rev. 6. and 3450-E11 010-lS. " Residual Heat i

Removal System," (RHR) Rev. 23. Ed 1: Hnit 1 Updated Final Safety

Analysis Report (UFSAR) Section 10.4: and TS Section 9.1.3: and

conducted a partial walkdown of the systems. The walkdown and

review were completed to verify that system alignment and

availability for use as the decay heat removal of the Unit I

reactor vessel and the spent fuel pool were correct,

b. Observations and Findinns

' 3 inspectors observed that the A loop of the RHR shutdown

cooling system was available and in standby for use as the initial

heat removal system. System components and instruments were

verified to be operable and in standby. The inspectors later

observed that the DHR system was in service and appropriately

controlling the decay heat load.

The inspectors walked down the DHR system and observed that system

components were in good working condition. The inspectors

observed later that the RHR system was taken out of service and

the DHR system was in service and appropriately cooling the spent

fuel pool and reactor vessel. The inspectors verified that the  ;

standby diesel generator (DG) for the DHR system arrived on site

prior to the use of the DHR system, as specified in the Unit 1

Outage Safety Assessment.

The inspectors observed the electrical connections made for the l

DHR DG and part of the DG testing. The DG test was satisfactorily

completed. The inspectors verified that the local procedure for

starting the DG was conspicuously posted along with the DHR

Enclosure 3

,

i

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g- m.., , . ,- . ,

m- - , . - , , ~ . , . . - - - - - - - . - . - ,

__ . _ _ ._ . _ _ _ _ _ . . _ _ _ -__ _

.

.

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!

procedure, as required. Operations personnel routinely verified -

that the DHR system was operating properly and operators recorded

pertinent system operating parameters.

The inspectors observed that operations personnel in the main ,

control room had a heightened awareness of the high reactor vessel l

decay heat load. Administrative controls restricted work in some  ;

control room panels until the reactor cavity was flooded.

Operations management. supervision, and control room operators

demonstrated a safety conscious awareness for unit operation

during times of high decay heat loads,

c. Conclusions

The inspectors concluded that Unit I systems used for reactor

vessel decay heat removal were in good operating condition and  :

controlled unit decay heat. The UFSAR. TS. Unit 1 Outage Safety  !

Assessment, and system procedural requirements for decay heat i

removal system availability were met. Operations management. ,

supervision, and control room operators demonstrated a safety  !

conscious awareness for unit operation during times of high decay i

heat loads.

02.3 Unit 1 Drywell Inspection Follcwina Refuelino Outace

a. Inspection Stone (71707.1

The inspectors reviewed procedures 34GO 0PS 028-IS. "Drywell '

Closeout." Rev 6. and 52GM MME 007 05. " Maintenance Drywell

Closeout." Rev. 3. and-conducted a walkdown of the drywell tc

review general material conditions. housekeeping. and systems and

components for indications of leakage.

b. Observations and Findinas .

During ti e drywell walkdown prior to the final Drywell closecut

activitics following the Unit I refueling outage. the inspectors

observed that the general material conditions were good. The

f licensee had installed new mirror-backed insulation on the reactor

!

vessel as part of its drywell insulation upgrade program. The new

insulation was properly installed, securely intact, and in

excellent condition. Overall housekeeping was good. Some small

pieces of taae were observed and were collected immediately. The

inspectors o) served that some work activity was still ongoing at *

the ll4-foot elevation. There were no indications of system or

component leakage.

The inspectors later reviewed the final drywell closecut

3rocedures completed by operations and maintenance personnel,

ieither procedure identified problems or deficiencies that

Enclosure 3

- . - - . -, . - . - - . . . - - ,

__ _ _ _ _ _ _ _ _ _ _ _ _ ________ _ __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

.,

.. ,

,

10  !

'

required attention,- The inspectors observed that the completed

procedures were reviewed by the appropriate level of supervision. '

. c. Conclusions

The inspectors concluded that material conditions and general

housekeeping in the Unit 1 drywell just prior to the final drywell >

closcout were good. The new mirror backed insulation installed on 4

the reactor as part of the drywell insulation upgrade initiative  !

was in excellent condition. No indications of system or component

leakage were observed.

,

04.2 Failure to Meet TS Surveillance Reauirement Prior To Withdrawal of

a Unit 1 Control Rod - In Cold shutdown .

a. InsnectionScoDe(71701).

The inspectors reviewed

Withdrawal in Shutdown," Revprocedure

6, Significance 34G0 0PS 066 05.

Occurrence Report " Control Rod '

97-4883, and discussed the referenced problem with operations

personnel.  ;

4

b. ihservationsandFindinas

The inspectors were informed by operations management that, while  !

performing Attachment 5 of procedure 34G0 0PS 006-05 operations

personnel on Unit I withdrew a control rod that did not meet the

. TS requirements for withdrawal. Control rod 10 47 was withdrawn

to position 02, in order to perform Attachment 5. One Rod Out

Interlock and RPIS Functional Test, of the procedure. 1he control j

rod was then fully inserted.

1

TS 3.10.4, Single Control Rod Withdrawal - Cold Chutdown.

identifies several requirements prior to withdrawal of a control

rod. One of the requirements was that section 3.9.5. Control Rod  ; '

Operability - Refueling, be met. TS surveillance requirement 3.9.5.2 requires each withdrawn control rod scram accumulator

pressure to be greater than or equal to 940 pounds per square inch ,

(psig). Prior to the withdrawal of control rod 10-47 on '

October 14. accumulator pressure was not equal to or greater than i'

940 psig, as required by the TS. ...e inspectors observed that the

accumulator had been depressurized to atmospheric pressure in

preparation for maintenance activities. t

The inspectors reviewed procedure 34G0-0PS-066 OS and observed

that step 4.3.6 clearly indicated that TS section 3.9.5 must be

. rret whenever a control rod is being withdrawn whi!c in cold

s utdown. The procedure also indicated that Attachn.ent 4.

Accumulator Pressure. RPIS Response, and Withdrawal Time, was to

-

be completed each time a control rod is withdrawn. Attachment 4  :

Enclosure 3

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'

l

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11

lr

clearly indicated that the control rod accumulator pressure must .

be greater than 940 psig prior to withdrawing a control rod. l

The inspectors reviewed licensee performance for TS surveillances  !

and observed that this was a repeat of a violation that occurred

'

on April 21. 1996. when a control rod was withdrawn on two

occasions with the scram accumulator pressure less than the  ;

TS required 940 psig. The licensee identified that a  !

less than-adequate procedure was the root cause of that violation. '

The corrective actions included revising the procedure, and

discussing the )roblem at Beginning Of-Shift-Training sessions. i

Additionally, tie TS issues associated with the problem were i

discussed in regularly scheduled training for licensed operators.

l

The inspectors concluded that the licensee's previous corrective 1

actions were adequate to prevent recurrence of a problem similar  ;

'

to the April 1996 problem. In this case, however, an operator was

told to complete Attachment 5 of the procedure. The operator

understood that all other procedure steps and actions were

completed, when, in fact, they were not completed. The failure to l

'

review the total procedure prior to its use was not in accordance ,

with the licensee's administrative procedure for procedure usage.

, The inspectors observed that several administrative controls were  ;

not implemented and contributed to the problem. Procedures i

i required a pre evolution briefing prior to any control rod 1

'

movement. A pre evolution briefing was not conducted.

Communications between operators for the % assignment were not  !

, clear with respect to whethec or not all procedure steps had been

l completed. A peer checker was . d prior to the control rod '

l movement, however, both the operator and peer checker failed to

i review the procedure or to recognize light indications in the

control room that indicated that the control rod accumulator was

depressurized and inoperable. The inspectors observed that

~

i operators were knowledgeable about the TS requirements for an

o)erable control rod. The licensee later informed the inspectors

t1at some of the control rod accumulators had been depressurized

in preparation for maintenance activities. However, the

accumulators were not tagged or otherwise identified as being

inoperable. Operations management stated that. in the future. any

'

depressurized or otherwise inoperable control rod accumulator .

would be electrically disabled to prevent movement. The licensee '

was evaluating 3rocedure revisions to clarify the disabling

requirement. T1e inspectors reviewed the licensee's immediate and  :

proposed long term corrective actions to prevent this problem and

determined that the corrective actions were satisfactory. *

l

There was little safety rignificance associated with the recent  !

violation with respect to an inadvertent criticality of the

,

L Enclosure 3

,

- , - , - -

- . - - - . - - . . - . - . . - - .= _ - _=

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

,

3

12

reactor core. The control rod was withdrawn to position 02 and ,

then reinserted within a short period of time.

The overall site surveillance program has been strengthened since

the previous similar viol 6 tion. Operator performance with respect

to conducting TS required surveillances since the previous

violation was excellent,

c. Osclusions

The inspectors conclud2d that poor operator performance with

respect to procedure usage, as well as other administrative

controls that were not completed, led to the problem. The failure

to correctly complete the TS surveillance requirement to withdraw

a control rod while in Cold Shutdown was identified as V10

50 321/97-10 02: Failure to Meet TS Surveillance Requirements

Prior to Withdrawal of a Control Rod While in Cold Shutdown.

07 Quality Assurance in Operations

07.1 Review of Sianificance Occurrence Reports (SORS) and Corrective

ofLlDai

a. Inspection Scone (71707) (405Q0).

The inspectors reviewed procedure 10AC-MGR-004-OS " Deficiency

Control System." Rev. 10. and Significance Reports generated

between October 12 - 18. 1997, to determine if the SORS were

properly classified and raised to the proper level of attention

for corrective actions.

b. Observations and Findinos

The eight SORS reviewed by the inspectors were correctly

classified in accordance with the procedure. Deficiency cards had

been generated. reviewed by appo]riate personnel, and the

deficiencies had been raised to tie prcper level of attention for

resolution. The SORS were being correctly tracked by the

commitment tracking system. The SORS indi';ted that the

responsible department were to conduct an investigation to

determine the root cause of the problem. The department's

response was to recommend actions to correct the problem and

prevent its recurrence.

On October 30. the inspectors attended a licensee corrective

action meeting, lhe meeting was held with responsible site and

department management personnel to discuss an SOR that required a

10 CFR 50.73 report. The inspectors observed that the discussion

was open and self-critical of 3rocedures and personnel performance

that caused the deficiency. T'le root causes and corrective-

Enclosure 3

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_ _____ __ ____ ____ _ _ _ - _- _ _--__ _ _ _ __ ___ ____ __ ___- __ _ _-_ -__ - _ - _ _ _ _ _ _ _ - _ _ _ _ .

4

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,

13

actions were discussed in detail. As a result of the meeting,

several corrective action initiatives were identified.

c. Conclusions

The eight SORS reviewed by-the inspectors were correctly

classified and w!re being correctly tracked by the connitment

tracking system and plant procedures. The recommended schedule

for determining root cause and reconmending corrective action was

appropriate for the deficiencies. SORS were receiving senior

level management as well as department level management attention.

08 Miscellaneous Operations Issues (92901)

08.1 (Closed) Violation 50 321, 366/97-01-01: Failure to follow

Procedure - Multiple Examples.

The licensee failed to establish the compensatory measures

required by procedure 31G0 0PS Oll 05. Fire Hazard Analysis (FHA)

Operating Requirements. Rev. 0, for degraded fire protection

components specifically an hourly fire watch for inoperable or

degraded fire barrier assemblies in January 1997.

The licensee's response to this violation dated April 21. 1997.

indicated that the individuals involved were disciplined in '

accordance with the company's positive discipline program and

counseled regarding the potential consequences of their actions. ,

Although there was no direct evidence of counseling. the licensee

did produce a " Site Management Review Sheet," signed by managers

of affected departments that the corrective actions described in

the response to violation had been completed.

Based upon the inspectors' review of licensee actions, this

violation example is closed. Other examples of this violation are

closed in sections M8.1. E8.1, and F8.1. One exam

violation was closed in section P8.1 of IR 50 321,ple of this

366/97-03,

08.2 (Closed) licensee Event Renort (LER) 50-321/97-05: Control Rod

Partially Withdrawn Without Pressure in Scram Accumulator.

This LER is discussed in Section 04.2 of this IR. Based upon the

inspectors review of licensee actions, this item is closed,

t

Enclosure 3

.__. -. _ - - - . .. -

_ _ _ _ _ _ _________________________ _ ______ _-

.

14

11. MaintRDanta

M1 Conduct of Maintenance

M1.1 Maintenance Observations durina the Unit 1 Refuelina Outaae

a. Inspection Scone (62707)

The inspectors observed or reviewed all or portions of the

following work activities:

• Maintenance Work Order (MWO) 1-97-1006: Remove Existing

Operator. Install larger Operator and Determine New TOL

Setting (18212 F016)

• MWO 1-97-1874: Install New Valve (IB21 F016)

• MWO 1-97-1007: Cutout Valve, Prep for installation and install

nevs valve (IB21 F019)

• MWO l-97-1008: Determine New TOL Setting (IB21 F619)

• MWO l-97-1011: Determ/ Modify Circuit F031B

• MWO l-97-1010: Determ/ Modify Circuit F031A

• MWO l-97-1091: Upgrade RR flow transmitters

• MWO 1-97-1921: Install Instrument Upgrade Kits (6) and replace

transmitters

• MWO 1-97-1088: Calibrate / Setup New APRM Recorders

• MWO 1-96-4622: Weld Instrument Tray East Cableway. Install New

Junction Box, and remove Insulation from trays

b. Observations )nd Findinas

The inspectors found that the work was performed with the work

packages 3 resent and being actively used. Procedure revisions

verified ]y the inspectors were correct. Supervisory oversight

was evident.

c. Conclusions

Maintenance activities reviewed or observed were completed in a

thorough and professional manner. Supervisory oversight was

evident. No significant deficiencies were identified by the

inspectors.

M1.2 Imnlementation of New Fmeroency Core Coolina System (FCCS) Suction

St rainers in Unit 1 (DCR 96-040)

a. Inspection Scone (62707) (37828) (37700)

The inspectors reviewed DCR 96-040, Upgrade ECCS Suction

Strainers: MWO packages 1-97-2418. Install Plate for Penetration

204A Torus, 1-97-0927. Diver Sup> ort Work To Install New ECCS

Strainers. 1-97-1038, Replace RH1 A Suction Strainer,1-97-It.42,

Enclosure 3

_.

_ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ ____ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ ___ _ ___ _ __ _ _

..

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Replace RHR 8 Suction Strainer, 1-97 1043. Replace RHR C Suction I

Strainer,- 1 97-1044. Replace RHR D Suction Strainer, 1-97-1045, '

Replace CS A Suction Strainer, and 1 97-1046B Replace CS B

Suction Strainer: and observed work in progress. The inspectors -

also reviewed Administrative Control Procedure 10AC MGR 021 05, '

" foreign Material Exclusion," Rev. 1.

b. Observations and Findinas

. The ins)ectors noted that the DCR and MWO work packages were

thoroug1 and detailed. Health Physics coverage for routine work ,

activities, such as contamination control (donning and removal of -

protective

in and outclothing), of the torus equipment staging, led.andHowever

was well-control movement

HP of equipment

deficiencies were identified and are discussed in Section R1.2 of i

this inspection Report. ,

.

The ins)ectors observed activities to transport some strainers to

the wort location from the warehouse str 'ng area. The inspectors

observed that the concern for personnel safety as well as

equipment integrity was continuously maintained.

The inspectors observed that two ECCS strainers were installed per

pump suction. Eight strainers were installed on the four pump

suctions associated with the RHR system and four for the two Core

Spray pump suctions for a total of 12 ECCS strainers. New elbow

piping was also custom designed for each of the installed ECCS

"

strainers. The design required the drilling of eight additional

holes in the mounting flange on the 'T' suction for attaching the ,

4

custorr. designed elbow aiping. These additional holes were drilled ,

equi-distant between tie eight existing holes.

One of the ins)ectors entered the torus and observed ongoing work

activities. T1e inspector nbserved that items taken into the

torus were logged and tracked by designated personnel in

accordance with procedure 10AC-MGR-021-05. The inspector was

informed by engineering personnel that the suctinn opening at the

flange area where the ECCS strainer would be attached was covered

4 with a foreign material exclusion (FME) barrier. This barrier

prevented metal shavings from the underwater drilling operations

, and other debris from entering the suction flowpath to the pumps.

Additionally, the inspector was informed that magnets, in

conjunction with the desludging underwater vacuum device, was used

to catch shavings generated by the drilling operations. Shavings

that fell to the underwater floor of the torus were removed during

the final desludging operations, as discussed in Section E2.3 of

this inspection report

Workers and divers were cognizant of their work responsibilities.

Attention to detail for personnel safety was ongoing. Site and

Enclosure 3

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corporate engineering personnel responsible for the work activity

were routinely at the work location and provided oversight and

direction, as needed.

The inspectors observed that some engineering issues presented

installation challenges. These were )rimarily due to strainer

size close tolerances, equi) ment proalems, and other

interferences associated wit 1 the installation of the new

strainers and the mounting of the custom designed elbow piping.

Due to these challenges. it was necessary to make field changes to

the original design. The field changes included the following:

• The Core Spray B left elbow flange ()enetration X2088 left) was

attached to the T suction with 14 )olts. The original

designed specified 16 bolts. Two holes could not be drilled

due to structural interferences. Five consecutive holes were

enlarged it. the elbow flange to enable alignment with existing

hoks in the 'T' flange. Similar alignment problems existed

with Core Spray A right elbow flange (penetration X208A right).

Six consecutive holes were enlarged on this elbow flange and

three holes could not be drilled. This elbow flange was

attached with 13 bolts.

• A bolt hole in the RHR right elbow flange (penetration X204B)

was abandoned due to the inability to extract a broken drill

bit from the partially drilled nole in the T flange. This

elbow flange was attached with 15 bolts.

. The left Core Spray B stainer was installed with a rotation

angle of 67 degrees above the horizontal due to structural

interference versus the 30 degrees specified in the original

design.

The inspectors reviewed these field change requests and identified

no deficiencies. The field changes received the appropriate level

of review,

c. [onclusions

lhe inspectors concluded that the work activities to move new ECCS

suction strainers from the warehouse to the torus proper was well

controlled. Health physics and engineering personnel provided

good oversight and direction. FME control was excellent. Onsite

engineering issues were resolved in an appropriate and timely

manner.

Enclosure 3

.

$

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17

M1.3 Inservice Insnection

a. InsDection Stone (IP 73753)

To evaluate the licensee's inse.,1ce Inspection (ISI) program and

the program's implementation the inspectors reviewed selected

procedures and records and observed work in progress.

Observations were compared with ap)licable procedures, the Updated

Final Safety Analysis Resort (UFSAR). and American Society of

Mechanical Engineers (ASiE) Boiler and Pressure Vessel (B&PV) Code

Sectirns V and XI. 1989 Edition. No Addenda (89NA).

Procedur' reviewed included: MT H 500. " Magnetic Particla

ExaminatioJ Rev. 9: PT-H-600. " Solvent Removable. Color

Contrast, or Fluorescent Liquid Penetrant Examination Procedure."

Rev. 7: UT H 400. " Manual Ultrasonic Examination of full

Penetration Welds (Greater than 0.200 inch)". Rev. 16: UT-H 402.

" Ultrasonic Examination of Full Penetration Austenitic Welds."

Rev. 0: VT-V-710. " Visual Examination (VT 1)." Rev. 10: and

VT-H-730. " Visual Examination VT-3." Rev. 10.

Specific areas examir.ed included the following observations:

magneti, particle (MT) examination of weld No.1821-1FW-18B 4:

liquid p;netrant (PT) examination of weld No. 1G31-1RWCV-60-15A:

manual ultrasonic (UT) examination of weld No.1B31-lRC 28A 12:

data acquisition and analysis activities associated with automated

UT examination of piping welds using the SMART system: data

acquisition and analysis activities associated with automated UT

examinations of reactor vessel welds using the GERIS 2000 system:

data acquisition and analysis activities associated with remote

visual (VT) examination of the reactor vessel internals: and data

acquisition and analysis activities associated with automated UT

examination of the reactor core shroud using the Tecnatom. SA

TEIDE system. The inspectors also reviewed selected completed

examination reports: and reviewed the Repair and Replacement (R/R) '

Program.

The inspectors performed an independent evaluation of indications

to confirm the licensee's ISI examiners * evaluations.

The inspectors reviewed records for the nondestructive examination

(NDE) personnel and equ1pment utilized to perform ISI

examinations. The records included: NDE equipment calibration

and materials certification; and records attesting to NDE examiner

qualification, certification and visual acuity.

b. Observations and Findinos

The inspector determined that the procedures reviewed were concise

and well written. Observed and reviewed inservice examinations

Enclosure 3

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_ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

,

.

18

were conowted in accordance with approved procedures by qualified

and certified examiners usiig certified / calibrated equipment and

materials.

Indications were identified by automated UT in the V-5 and V-6

welds of the core shroud. These indications correlated well with

the indications noted by the remote visual examination of the same

welds conducted during the last Unit I refueling outage. The

inspottors determined that these indications were envelo)ed by the

analysis conducted following the visual examination of tie last

Unit I refueling outage.

A linear indication was identified by remote visual examination in

the core support plate. This indication was evaluated by the

licensee ar'd determined to be enveloped by BWRVIP-07, and

therefore was classified "Use As Is." The inspectors determined

that the licensee's evaluation was thorough,

Linear indications were also identified adjacent to the welds

joining the N2B and N2D jet pump riser elbows to their respective

thermal sleeves. During a subsequent telephone call, corporate

engineering personnel stated that they would submit a separate

report supporting the evaluation that the linear indications were

not an operability problem.

The licensee, by letters HL-5271. dated December 2. 1996, and HL-

5319. dated March 7, 1997, requested NRC relief from the repair

and replacement aspects of the Containment Rule for a period of

one year. By letter dated May 16, 1997 the NRC granted the relief

to September 9. 1997. The licensee, by letter HL-5449. dated

August 8. 1997 requested relief from compliance with the

Containment Rule relative to the use of ASME Section XI, 1992

Edition with 1992 Addenda for Class MC components for Code

activities other than examination recuirements. The NRC, by

letter dated October 16. 1997, deniec the request. The licensee

had implemented the Containment Insoection Rule R/R program by

issuance of: 42EN-ENG-014-0S. "ASME Section XI Repair /

Replacement," Rev. 10, dated September 9. 1997; 51GM-MNT-019-05.

" Painting and Coating Procedure." Rev. 8. dated October 13. 1997:

and SIGM-MNT-020-05. " Painting and Coating Procedure: Drywell and

Torus Area," Rev. R. dated October 13. 1997.

Licensee procedure 42EN-ENG-014-0S. Rev. 10. dated September 10,

1997 referenced the "lSI Program and Relief Requests" for the

applicable ASME Code Section-XI edition and addenda. The ISI

program incorrectly identified 89NA as the applicable edition and

addenda for ASME Section XI. instead of the 1992 Edition. After

some discussions, the inspectors determined that the incorrect

reference was a docum_atation problem. The licens& indicated

Enclosure 3

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that it planned to revise procedure 42EN ENG-014 05 to include the

applicable code edition and addenda references.

c. Conclusion

Observed or reviewed inservice inspection activities were

conducted in accordance with procedures, licensee commitments, and

regulate y requirements.

M1.4 . Main Transformer Backfeed Activity (Unit 1)

a. Inspection Scooe (62707)

The inspectors observed planning and coordination activities by

the licensee for backfeeding power through the Unit 1 Main

Transformer. The backfeed was accomplished to facilitate

preventive maintenance on 10 Start-Up Transformer (SUT).

b. Observations and Findings

The ins)ectors reviewed procedure 52GM S11-001-15. "Back Feed of

Unit 1 iain Sank Transformer." Rev. 2. The procedure provided

specific instructions for personnel regarding equipment usage,

3recautions and limitations and detailed steps for isolating the

dain Transformer prior to the backfeed. The inspectors attended

two pre-enlution briefings held by operations and maintenance

personnel in preparation for backfeed activities. Coordination of

the briefings by operations, maintenance, and substation

maintenance personnel was professional and thorough. While

o)erations placed the main transformer in backfeed. the inspectors

o3 served that appropriate guidelines wre implemented by personnel

in the installation and removal of main transformer grounds and

insulation, and in checking for ground electrical currents.

Operations provided good oversight on establishing the necessary

equipment clearances to remove the ID SUT from service.

c. r;onclusions

Operations and maintenance personnel interfaced effectively to

resolve scheduling conflicts that emerged during the two

pre-evolution briefings. The inspectors concluded that the

licensee exhibited good overall planning and oversight throughout

the backfeed activity. Operations provided good oversight on

establishing the necessary equipment clearances to remove the ID

SUT from service.

Enclosure 3

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20

i JJ 1E 4160-Volt Circuit Breaker Failures

L h , action Scone (62707).

... inspectors observed the licensee's corrective maintenance

activities and actions taken in response to a serles of failures

of safety related 4160-volt circuit breakers in the Uni.1

emergency switchgear.

b. Observations and findinas

On October 31. 1997, the normal supply circuit breaker to the

IF emergency switchgear failed to close when transferring the

emergency bus from the alternate to normal supply following

testing. The inspectors reviewed the MWO initiated in response to

this failure. Maintenance personnel were unable to du)licate the

failure of this circuit breaker (Westinghouse Type 50 dip 350), and

conducted preventive mainterance in accordance with procedure

52PM-R22-001-05, "4160-Volt AC Switchgear and Electrical

Components Preventive Maintenance," Rev. 13. Ed 1. After cleanirig

and lubricating, the breaker operated smoothly. However the

licensee determined that the breaker should be replaced. The

fa d ed breaker was removed and crated for shipment to an

ir pendent laboratory for testing and root cause determination.

Maintenance personnel documented an apparent root cause as " lack

of lubrication and exercise" on MWO 19702869. The inspectors

discussed the apparent root cause with both site maintenance

personnel and corpora +e engineering. One possible root cause was

given as " hardened lubrication material," i .e. . grease, Pending

the findings of the laboratory, the licensee had been unable to

determine the root cause of this failure.

On November 5. 1997, the 1C Residual Heat Removal (RHR) pump moto-

circuit breaker (Westinghouse Type 50DHP250) failed to close when

given an auto start signal as 3 art of the RHR-Low Pressure Coolant

injection (LPCI) Logic System r unctional Test (LSFT). The

inspector observed maintenance activities initiated under MWO

19702987. The inspectors observed that maintenance personnel

performance in ide'n tifying this problem was good, and

documentation in the MWO was thorough. The ins)ectors found that

cleaning and/or lubrication of the sliding braccet assembly was

not previously conducted as part of the licensee's preventive

maintenance (PM) program for 4160-volt circuit breakers

Westinghouse had issued Technical Bulletin ESBU-TB-97-04 in May,

1997, to recommend PM activities that could be conducted or

incor) orated into existing procedures to cover the motor cut-off

switc1 assemM y. The inspectors observed that the licensee had

not yet im)lemented the technical bulletin recommendations.

However, t1e licensee was preparing to solicit vendor cupport

based on problems with Westinghouse 4160-volt circuit breakers at

Enclosure 3

. _ _ _ _ _ _ _ _ - _ _ __ _ _ _ _ _ _ _ _ - _ _ _____- _

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21

other utilities. Full implementation was planned following the

Unit 1 Fall 1997 outage.

The licensee formed an Event Review Team (ERT) to investigate

recent failures of these Westinghouse circuit breakers and provide

recommendations to prevent recurrence. The inspectors reviewed

the ERT interim recommendations. The recommendations included

incor) oration of the Westinghouse technical bulletin actions, and

full 3M actions on a representative sample of Unit 1 safety-

related circuit breakers, including the emergency diesel generator

(EDG) output breakers, normal and alternate sup)1y breakers, and

one or two motor feeder breakers from the 1E. 17 and 1G emergency

busses. The inspectors determined that the ERT recommendations

were reasonable, based on the equipment operating service time and

failure history.

Subsecuently, on November 13, 1997, the IB RHR Service Water

(RHRSk) pump motor breaker failed to close when operators

attempted to place the pump in service. Maintenance personnel

initiated corrective actions, but were unable to find a ]roblem

with the breaker operation after repeated cycling from t1e

switchgear test sth The ERT concluded that after the breaker

had been racked out as part of a previously-conducted LSFT

activity, the breaker had not been racked in correctly and cycled

(field tested). The inspectors and a member of the ERT observed

maintenance >ersonnel racking in this breaker. The rack-in was

observed to )e smooth, and the inspectors determined that it was

improbable that incorrect racking of the breaker could have

contributed to the breaker failure. The breaker had previously

undergone preventive maintenance in March. 1997. This breaker had

not been examined as part of the initial ERT recommendations.

Additior.a1 ERT recommendations, issued November 14. 1997, called

for full cycling of each 4160-volt breaker supplying a motor / load,

and a " start-run-stop and re-start" of each motor. The inspectors

observed that no additional failures occurred.

c. Conclusions

The licensee had taken initial steps to address problems with

Westinghouse Type DHP circuit breakers in July 1997, based on

problems and events at other utilities. The actions and

recommendations of the ERT were considered appropriate. However,

the inspectors determined that additional examination by the

inspectors of the licensee's PM program for these circuit breakers

is warranted based on this series of failures and the tact that

two of the breakers had undergone PM within the past nine months.

This was identified as IFI 50-321, 366/97-10-08: Review of 4160-

Volt Breaker Failure Analysis and Preventive Maintenance Program.

Enclosure 3

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1

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_ _ - - _ _ _ - - _ _ _ - - - - - _ _ _ _ - _ - _ _ _ _ _ _

4

4

22

M?, Maintenance Procedures and Documentation

M3.1 Surveillance Observations

a. Insoection Scope (61726)

The inspectors observed all or portions of the following Unit 1

and Unit 2 surveillance activities:

. 345V-R43-006-1S: EDG 1C Semi-Annual Test, Rev. 11

• 42SV-lET-001-15: Primary Containment Periodic Type B and C

Leakage Test, Rev. 17

• DI-0PS-57-0393N: Outage Safety Assessment, Rev. 7

. 42SV-R42-009-05: Combined Service and Modified Performance

Test, Rev. 1

. 52SV-R43-001-05: Diesel Alternator and Accessories Inspection,

Rev. 13

. 341T-N30-004-15: Turbine Overspeed Tria Test, Rev. 1

. 345V-C51-001-lS: SRM Functional Test, Rev. 7

• 341T-N21-003-IS: RFPT Weekly Test, Rev. 4

• 42IT-TET-006-1S: ISI Pressure Test of the Class 1 System and

Recirculation Pump Runback Test Rev. 9

b. Observations and Findings

The inspectors observed that, in general, personnel performing the

tests were knowledgeable of their job function, used good

communication techniques, and followed plant procedures

Supervisory and engineering oversight was good. However, some

surveillance deficiencies were noted and are discussed in sections

02.1. 04.2, and M4.1 of this report.

c. Conclusions

For the surveillances observed, all data met the required

acceptance criteria and the equipment performed satisfactorily.

The performance of the operators and crews conducting the

surveillances was generally professional and competent.

Exceptions are noted above.

M4 Maintenance Staff Knowledge and Performance

M4.1 Incorrect Placement of Jumoer durina Unit 1 Local Leak Rate Test

(llRT) Activities

a. Inspection Scooe (61726) (62702)

The inspectors reviewed documentation and held discussions with

licensee personnel associated with the initiation of a Group 1

isolation signal due to the incorrect niacement of a jumper. The

Enclosure 3

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documentation reviewed included surveillance procedure

-42SV-TET-001-15, " Primary Containment Periodic Type B and C_-

Leakage Tests." Rev. 17: administrative control procedure

00AC-REG-001-05. " Federal and State Reporting and-Federal Document

Posting Requirements." Rev. 5: dep6Ptmental instruction

DI-0PS-31-0596N. " General Guidelines for Use of Jumpers and

Links." Rev. 0: and a computer printout of the Safety Parameter

display system-(SPDS) magnetic tapes. The inspectors also

reviewed portions of the LLRT training program requirements,

b. Observations and Findinas

The inspectors observed on October 30 during a control room tour,

that a Group 1 Primary Containment Isolation Signal (PCIS) was

initiated as a result of the incorrect placement of a-jumper

during LLRT activities. Surveillance procedure 42SV-TET-001-IS

required that jumpers be placed in control room panels in order to

keep designated solenoids energized following the completion of

the LLRT. One jumper was to be placed in control-rocin panel

1H11-P602 and the other jumper was to be placed in Janel

1H11-P628. The LLRT technician erroneously placed )oth jumpers in

'

aanel 1H11-P60_. The incorrect placement of the 2nd jumper-in the

3602 panel caused : everal fuses to function which generated a

Group 1 isolation signal.

Operations personnel initially thought that all valves in the

Group 1 isolation logic were closed except for the Recirculation

Pump System Sample valve 1831 P019. Based upon that assumption,

operation's supervision made the determination that the event was

an Engineered Safety Feature (ESF) actuation and was reportable

under 10 CFR 50.72.

'

Nuclear Safety and Compliance (NSAC) personnel subsecuently

reviewed the safety parameter display system (SPDS) cata and made

the determination that the recirculation pump system sample valve

was closed before the receipt of the Group 1 isolation signal.

This made the event non-reportable and the licensee withdrew the

10 CFR 50.72 report on November 5. based upon this review.

NSAC 3ersonnel 3rovided the inspectors a copy of the printout of

the S)DS data tlat indicated which valves and relays that changed

states. The inspectors determined that NSAC personnel correctly

identified that all valves were closed prior to the generation of

the Group 1 isolation signal. Therefore, the event was not

reportable.

One LLRT technician who ) laced the' jumpers was an operations

person who had attended _LRT training. A control room operator

performed the peer check for the placement of the jumpors. As

part of the licensees corrective actions-the technicians were

>

Enclosure 3

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24

counseled and suspended from the performance of further LLRTs

until retraining was completed. Additionally, other members of

the LLRT team were provided refresher training on departmental

instruction Dl-0PS-31-0596N. The inspectnrs reviewed the

corrective actions and determined that they were appropriate.

The inspectors discussed the incorrect placement of the jumper

with the control room operator (CRO) who provided the peer check

for the LLRT technicion. The technician gave the CR0 the

im)ression that both jumpers were to be placed into the same

ca)inet (1H11-P602). During the peer checking of the second

jumper, the CR0 did not fully read the instructions in the

surveillance procedure. As a result, the CR0 did not discover

that the jumper was placed in the incorrect cabinet. This failure

to read the procedure instructions prior to performing actions was

contrary to the administrative guidance for procedure usage.

The inspectors reviewed the LLRT training program requirements and

discussed the content of the program with the licensee's

maintcnance instructor who developed the lesson plans. The

inspectors observed that jumper placement techniques were part of

the training requirements.

The inspectors reviewed the surveillance procedure and noted that

the procedure clearly indicated where the jumpers should have been

placed. In this case one operator apparently misread the

procedure and the sectnd operator failed to correctly perform a

peer check p:'ior to placing the jumpers.

c. Conclusions

The inspectors concluded that a lack of attention to detail was a

contributing factor for the incorrect placement of a jumper during

an LLRT activity. The inspectors also concluded that because all

the valves were already closed, this error had little safety

significance. The inspectors were not aware of other jumper

installation problems that occurred during the Unit 1 refueling

outage. Based upon the inspectors' review of licensee actions.

this licensee-identified violation constitutes a violation of

minor safety significance and is being identified as Non-Cited

Violation (NCV) 60-321/97-10-03: Jumper Placament Error During

Unit 1 Testing Activities. consistent with Section IV of the NRC

Enforcement Policy.

Enclosure 3

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M4.2 Primary Containment Periodic Tvoe B and C Leakaae Test for Unit 1

. a. Inspection Stone (61726) (62707)

The inspectors observed selected ongoing work activities and

reviewed completed test and maintenance results to verify that

test, plant procedure, and regulatory requirements were met.

b. Observations and Findinas

During the current Unit 1 refueling outage the licensee conducted

approximately 77 type B (Seals and Penetrations) ar.J 137 type C

tests (Valves). The inspectors observed that there were seven

type B test failures and 12 type C test failures. Valve seat

leakage, worn valve seats and required adjustments of some valve

linkage contributed to the failures. The inspectors reviewed the

applicable MWO work packages observed selected work conducted to

implement repairs and retests and verified that the post

maintenance test results were satisfactory.

The inspectors observed that applicable procedures were used

during_the tests and maintenance work activities, work packages

were available at the work location, test personnel were

knowledgeable of their job function, and supervisory personnel

provided oversight when required.

c. Cnnclusions

The inspectors concluded that Unit 1 Periodic Type B and C Leakage

tests and required corrective maintenance were performed per

applicable procedures with the exception documented in

Section M4.1. The final test results met plant procedure and

regulatory requirements. Supervisory oversight was evident.

M8 Miscellaneous Maintenance Issues (92700) (92902)

M8.1 (Closed) Violation 50-321. 366/97-01-01: Failure to Follow

Procedure - Multiple Examples.

Licensee personnel failed to follow procedure 57CP-CAL-108-15.

General Electric Type IAC and Westinghouse Type C0 Relays. Rev. 9.

while performing a calibration of Type IAC and Type C0 Overcurrent

Relays in February 1997.

The licensee's response to this violation. dated April 21. 1997,

indicated that the individuals involved were disciplined in

accordance with the company's positive discipline program and

counseled regarding the potential consequences of their actions.

Also, the necessary additional changes to the settings for relays

Enclosure 3

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26

IS32-K217-1. -2, and -3 were made. The inspectors verified that

the procedure was revised to reflect these changes.

Based upon the inspectors' review of licensee actions. this

violation example is closed. Quier exam

closed in sections 08.1. E8.1, and F8.1.ples One of this violation

example of this are

violation was previously closed in se ' ion P8.1 of IR 50-321.

366/97-03.

M8.2 (Closed) Violation 50-366/97-01-02: Inadequate Procedure for

Calibrating Unit 2 HPCI Time Delay Relay K14

This issue was documented in section M3.2 of IR 50-321, 366/97-01.

The licensee's response to this violation, dated April 21. 1997.

indicated that the event was discussed with the individuals

involved and included an explanation of its causes and

consequences. Engineering and Maintenance procedures which

involved lifting wires or opening links: involved safety-related

systems which use DC, energize to-actuate logic; and assumed that

the affected system would remain operable even with circuit

connections interrupted were reviewed. Two additional procedures

(57CP-CAL-050-1S Agastat Timing Relay Calibration, and 57CP-CAL-

050-2S. Agastat Timing Relay Calibration) were found to have the

same problem as procedure 57CP-CAL-051-2S. The inspectors

verified that the three procedures were revised on June 1. 1997,

to address their adequacy for relay calibration. Based upon the

inspectors * review cf licensee actions, this violation is closed.

III. Enaineerina

E2 Engineering Support of Facilities and Equipment

E2.1 Reviw of Licensee Actions in Resoonse to Generic Letter (GL)

96-06: Assurance of Eoujoment Ooerability and Containment

Intearity Durina Desian Basis Accident Conditions.

a. Insoection Scoce (37551) (92903)

The inspectors reviewed GL 96-06: Design Change Request (DCR)97-005 and DCR 97-006. Thermal Pressure Relief Protection: the

10 CFR 50.59 evaluation for both DCRs: and the applicable work

packages associated with maintenance and engineering act nities to

implement corrective actions on both units.

b. Observations and Findinos

Tne licensee had identified three pipe lines penetrating the

containment that were susceptible to thermally-induced

pressurization and evaluated them for operability for each unit.

Enclosure 3

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These lines are assocu ,d with penetrations for the residual heat

removal shutdown coolirs (RHRSDC) suction line the drywell floor

drain (DWFD) sump pump discharge line, and the drywell equipment

drain (DWED) sump pump discharge line. The licensee committed to

complete the appropriate corrective actions for these pipe lines

3rior to the restart from the spring 1997 refueling outage for

Jnit 2 and the fall 1997 refuel outage for Unit 1.

The inspectors reviewed documentation used to complete the

appropriate modification on Unit 2 during the spring 1997

refueling outage. The purpose of the modification was to relieve

any thermally induced pressure buildup that may occur in the

w olated portion of the piping.

The inspectors reviewed documentation used to complete the

corrective actions on Unit 1 durinc the fall 1997 refueling ,

outage. The inspectors also discussed the work activity with

licensee personnel and entered the Unit 1 drywell to observe the

work activities and to verify that the work was completed. The

documentation reviewed by the inspectors indicated that the

corrective actions were completed, the systems were returned to

service, and the commitment to complete all corrective actions on

Unit 1 prior to the Unit 1 startup was met.

.

c. Conclusions

The licensee's corrective actions for both units in res]onse to

Generic Letter (GL) 96-06. Assurance of Equipment Opera 3ility and

Containment Integrity During Design Basis Accident Conditions.

were completed within the conmiitted time.

E2.2 Review of Alternate Testina Of Unit 1 Safety Relief Valves

a. Insnection Scone (37551) (62707)

The inspectors reviewed procedure 42SV-TET-001-1S, " Primary

Containment Periodic Type B and C Leakage Test," Rev. 17. and work

package documentation to verify that alternate tests of the Unit 1

Safety / Relief Valves were conducted in accordance with the

procedure and commitment documented in Relief Request RR-V-11.

b. Observations and Findinas

On September 5.1997, the NRC approved the licensee's Relief

Request RR-V-11, regarding Inservice Testing of Safety / Relief

Valves - Edwin I. Hatch Nuclear Plant. Units 1 and 2.

The inspectors reviewed procedure 4 G V-TET-001-15. used to conduct

the testing, and discussed the testing activity with maintenance

and engineering personnel respon;ible for the tests and reviewed

Enclosure 3

_ _ - _ _ _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ -____ ___ _ -

. . -- . - . --

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the test data. -The inspectors noted that all test data met the

established acceptance criteria.

c. Conclusions

The inspectors concluded that the proposed alternative tests of

the Unit 1 Safety Relief Valves were completed in accordance with

plant procedures and as specified in Relief Request RR-V-11.

Inservice Testing of Safety / Relief Valves - Edwin I. Hatch Nuclear

Plant. Units 1 and 2. All test data met the acceptance criteria.

E2.3 Desludaina and Cleanina of Unit 1 Torus

-a. Insoection Scoce (37551)

The inspectors reviewed licensee actions to inspect and clean the

Unit 1 torus in response to NRC Bulletin 95-02. Unexpected

Clogging of a Residual Heat Removal (RHR) Pump Strainer While

Operating in Suppression Pool Cooling. The inspectors reviewed

procedure 10AC-iGR-021-0S. " Foreign Material Exclusion." Rev. 1.

and observed related work activities,

b. Observations and Findinas

During the current refueling outage. the licensee continued its

ongoing efforts to ensure torus and ECCS suction strainer

cleanliness. The work activities included a diver swim-through

inspection. FME removal and documentation. and post work cleanup

and inspection. One of the inspectors entered the torus and

discussed the cleanup efforts and the as-found condition of the

torus.

c. Conclusions

The ins)ectors concluded that the actions taken to inspect and

clean t1e Unit 1 torus were good. FME controls were properly

implemcated. Management was actively involved. The inspectors

concluded that the small amount of debris found in the torus did

not present a risk for emergency core cooling system suction

strainer blockage.

E2.4 Review of Licensee actions with resoect to Technical Soecification

(TS) Amendment 204 and 145 for Units 1 and 2.

a. Insoection Scoce (37551)-

The inspectors reviewed TS Amendment 204 and 145, for Units 1

and 2. respectively. TS section 3.1.. for both units, and

procedures 34SV-C41-002-1S/25. " Standby Licuid Control (SBLC)-Pump

Operability Test." Rev.12. for Unit 1. anc Rev.17. for Unit 2.

Enclosure 3

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The inspectors reviewed the documentation to verify that licensee

actions for the SBLC System were completed within the time

identified in the approved TS Amendments.

b. Observations and Findinas

Technical Specification Amendments 204 and 145 were approved by

the NRC on March 21. 1997. The licensee committed to implementing

these amendments prior to startup from the Unit I refueling outage

and arior to startup from the Unit 2 refueling outage scheduled

for iarch 1997. One item identified in the TS amendments was that

each SBLC pump developed a flow rate greater than or equal to 41.2

gallons per minute (gpm) at a discharge pressure of greater than

or equal to 1232 pounds per square inch (psig). The amendments

changed the discharge pressures from 1201 psig to 1232 psig.

The inspectors verified that the a)plicable sections of the TSs

had been revised in accordance wit 1 the amendments. The

ins)ectors reviewed the a)plicable surveillance procedures for

bot 1 units and verified tlat they were revised and completed prior

to each units startup. The inspectors verified that all the SBLC

pumps met the required flow and pressure requirements.

c. Conclusions

The inspectors concluded that the lice see actions taken to

implement Technical Specification Amendments 204 and 145 for the

Standby Liquid Control System were timely and correct. The

completed :tandby Liquid Control System surveillances verified

that the flow and pump discharge pressure requirements were met.

E2.5 Generic Letter 89-10 Valve Modifications and Hiah Pressure Coolant

inlection (HPCI) lE41-F001 Work Activities

a. Inspection Scoce (37700) (71707) (62707)

The inspectors reviewed DCR 96-005 and the associated 10 CFR 50.59

evaluations. and observed work activities associated with the HPCI

steam supply isolation gate valve 1E41-F001. The placement of

clearance tags associated with the 1E41-F001 valve work activity

was a'so reviewed. Discussions were held with licensee personnel

and the completion of a committed ASME Section XI VT-3 inspection

was verified.

b. Observations and Findinas

The purpose of DCR 96-005 was to provide assurance that safety-

related motor operated valves (MOVs) would meet their safety

function when subjected to the maximum differential pressure

Enclosure 3

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30

across the valve during normal operation and abnormal events

within the design basis of the plant.

Valves subject to the power uprate conditions were changed to

accommodate the additional loads of the uprated conditions.

The following valves were mod'fied per the design specifications

described in the DCR:

. Main Steam line crain isolation valves 1821-F016 and 1821-F019.

. Reactor Recirculation Pump outlet isolation gate valves

1B31-F031 A and B.

. RHR heat exchanger flush to torus valves 1E11-F011 A and B.

. HPCI steam supply isolation gate valve 1E41-F001.

. HPCI steam supply isolation gate valve 1E41-F002

. HPCI pump discharge gate valve 1E41-F007

. RCIC pump discharge gate valve 1E51-F013

. RCIC trip and throttle valve 1E51-F524

. RWCU inboard isolation gate valve 1G31-F001

Modifications to the valves listed above included replacing the

existing motors aad operators with units of larger capacity,

modification of control circuits and operator gearing,

installation of larger capacity motors and operators, and

replacement of circuit breakers due to larger capacity motors.

The inspectors observed two craftsmen working on the valve seating

for the HPCI steem su) ply isolation gate valve 1E41-F001. The

inspectors observed tlat the piping system had been breached and

the work area was prominently identified as a FME area. The

inspectors also observed that the craftsmen had a FME barrier

installed to prevent dropped tools or other material from enterin,

the piping system.

The inspectors verified the placemenc of a re)resentative sampling

of clearance tags for the 1E41-F001 valve war ( activities in

accordance with clearance 1-97-445. No discrepancies were

identified.

In the licensee's reply to VIO 50-321/96-11-02, the licensee

committed to performing an ASME code required VT-3 inspection on

the HPCI 1E41-F006 valve during the Unit 1 fall 1997 refueling

Enclosure 3

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outaga The inspectors reviewed MWO 1-96-2647 and verified that

the Visual Examination Record VT-3 For Pumps and Valves was

-completed and signed for the performance of a VT-3 examination.

'

,

c. Conclusions

The 10 CFR 50.59 evaluation for the Generic Letter 8910

modification in accordance with DCR 96-005 was a)propriate. *

Foreign material exclusion control for the 1E412001 valve work -

activity was excellent. The placement of clearance tags was good.

The ASME required VT-3 inspection for HPCI valve 1-E41-F006 was

completed satisfactorily.

.

E2.6 Unit 1 Condensate Storaae Tank (CST) Desludaina Operations

a; Insoection Scooe (37551)

The inspectors observed preparation for CST desludge work

-activities on Unit 1. Discussions were also held with licensee

engineering per sonel.

b. Observations and F mdinas

The licensee completed desludging activities in the CST to

possibly improve control rod movement difficulties. One possible

contributor to the problem was suspected to be sludge that had

accumulated in the CST. The CST had not been previously cleaned

The inspectors observed preparation for CST desludging work

activities on October 8 while Unit I was still operating. FME

controls were in place and were properly implemented. Tha

presence of HP was observed and security personnel were present to

provide emergency recovery actions.

A diver entered the CST the following day for a short period of

time but had to be removed due to heat stress. The CST water

temperature was too high. The work activity was curtailed

indefinitely until a different work plan was formulated.

The divers made an entry into the CST subsequent to the Unit 1

- shutdown for the refueling outage. The divers completed

desludging activities. The following items were recovered from

the Unit 1 CST: a.one-foot long piece of 1/2-inch diameter rope,

green / white nylon rope six inches long, four welding rod stubs,

three pieces of_No. 9 wire (one 2-foot piece and two 3-foot-

pieces).' and about a handfull of miscellaneous chips of paint.

-

The inspectors were informed that very little sludge build up was

observed and may not have been-a major contributor to control rod

.

movement problems. This problem was still being evaluated by

engineering.

Enclosure 3

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c. Conclusions

The initial Unit 1 CST entry by the divers to perform desludging

activities was not well-planned for water temperature conditions,

FME controls were in place and were properly implemented. The

presence of HP was observed and security personnel were present to

provide emergency recovery actions.

.

E2.7 Emeroency Diesel Generator (EDG) Logic System Testino in Resnong

to Generic Letter (GL) 96 01

a, Insnection Scone (37551)

As documented in IR 50-321, 366/97-03, licensee reviews of EDG

logic system testing incorporated into Unit 2 procedures in

response to GL 96-01. " Testing of Safety-Related Logic Circuits."

A licensee review of logic system tests had identified that

emergency switchgear alternate supply breaker ur.dervoltage and

degraded voltage trip logic was not being tested. The inspectors

reviewed Unit 1 procedures and licensee actions taken to

incor) orate the additional logic testing for EDGs and emergency

switc1 gear.

b. Observations and Findinas

The inspectors reviewed Unit 1 surveillance procedures

42SV-R43-021-15. " Diesel Generator 1A LOCA/LOSP LSFT," Rev. 5,

42SV-R43-024-15. " Diesel Generator 1B LOCA/LOSP LSFT." Rev. 5, and 1

42SV-R43 025-1S. " Diesel Generator 1B Logic Tests." Rev. 4. The

inspectors verified that changes made to the logic system

functional test (LSFT) procedures in August, 1997. included steps

for testing 1E and 1F emergency switchgear alternate supply

breaker relay contacts.

The inspectors observed licensee engineering activities to test #

the IF emergency switchgear alternate supply breaker trip logic

using special purpose procedure 42SP-103097-OL-1-1S, " Emergency

Bus Alternate Supply Breaker Trip Test." Rev. 1. This procedure

was implemented due to the main transformer power backfeed, which

aligned the IF supply power from the alternate sup)1y breaker, and

would have forced the 1B EDG to be inoperable if t1e alternate

supply breaker trip logic was not tested. The inspectors reviewed

the special purpose procedure and test results. No discrepancies

were identi fied.

c. Conclusions

The inspectors concluded that engineering personnel had provided

good oversight and coordination in response to the GL 96-01.

" Testing of Safety-Related Logic Circuits," for Unit 1 EDGs and

Enclosure 3

l

1

_ _ _ _ _ - _ - _ _ _ _ _ _ _ _ _ _ _ ______________ __-_-_- _ __

.

.

33

emergency switchgear. Test results met the appropriate acceptance

criteria.

E3 Engineering Procedures and Documentation

E3.1 Missed Commitment for Unit 2 Technical Soecification (TS1

Amendment 132

a. Insnectton Scone (37551)(92903)

The inspectors reviewed a licensee application for TS Amendment

132, document HL-4546, dated March 2?.1994, which documented the

requirement to add valve 2B21-F021 and downstream piping to the '

main condenser as ASME Class 11: NRC-approved TS Amendment 132.

dated March 17, 1994: and licensee documentation outlining

corrective actions for a missed TS requirement for Amendment 132.

b. Inspection Scope

The inspectors were informed by Nuclear Safety and Com)liance

(NSAC) management that a commitment with respect to a Jnit 2 TS

Amendnent had not been completed during the last Unit 2 refueling

outage. TS Amendment 132 increased the allowable Main Steam

Isolatico Valve (MSIV) leakage and deleted the MSIV leakage

control system. Credit was taken for an alternate leakage control

path from the MSIVs to the condenser through MSIV drain line valve

2B21-F021. The NRC had acce)ted a commitment made by " a licensee

to include the alternate leacage control path in the American

Society of Mechanical Eng.neers (ASME)Section XI Inservice

Inspection (ISI) Program and treat the drain line piping as

Class 2 for repairs and replacement under ASME Section XI. This

commitment was to be met prior to Unit 2 startup following the

Spring 1994 refueling outage.

During the last Unit 2 refueling outage. March 1997, the 2821-F021

valve and about 4 inches of piping were replaced under Design

Change Request (DCR) 96 006. However, two welds and a 4-inch

piece of pipe downstream of the drain valve were not treated as

Class 2 because the ISI boundary diagrams and 151 program plan had

not been changed to reflect the commitment requirements. The

licensee determined that the problem was caused by personnel

error. Initially, the ISI plan drawings were revised to capture

the requirement and Inservice Testing (IST) documents were revised

to address the testing requirements. However, during a process to

update prints (new ISI boundary drawings) the requirement for the

) articular valve and piping was not detected and the new ISI

aoundary drawing failed to reflect the code requirement.

The inspectors reviewed licensee corrective actions to correct

this problem. The inspectors reviewed procedure 421T-TET-004-05.

Enclosure 3

_ _ _ - _ _ - _ _ ___ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - __

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.

34

" Operating Pressure Testing of Piping and Components." Rev 5.

dated October 10, 1997, that was used to complete the code-

required testing of the components. The test results were

satisfactory,

c. Conclusions

The inspectors concluded that the licensee actions taken to

correct the missed commitment for Unit 2 Technical Specification

(TS) klendment 132 were appropriate. The code-required testing

cont' 'ted in October 1997 was satisfactory. This problem was

idenu fied as Deviation 50-366/97-10-04: 1:issed Commitment for

Unit 2 Technical Specification Amendment 132.

E3.2 Review and Observations of Desian Chance Reouests (DCRs) Durina

Unit 2 Refuelina Outaae

a. Inspection Scope (37700)

The inspectors reviewed selected DCR packages and observed part of

the ongoing work activities during the Unit I refueling outage.

The review included the DCR base documents, activity summary, work

description. MW0s. plant drawings, and applicable 10 CFR 50.59

review to determine if an unreviewed safety question existed.

b. Observations and Findinas

The inspectors reviewed the following DCRs and associated

documentation and observed selected wo.-k activities.

e 86-318: Cable Re-route (Containment Penetration Work)

e 93-047: Condensate Demineralizer Backwash System

e 94-007: Power Range Neutron Monitoring

e 95-032: Breaker / Fuse Coordination

e 95-053: Upgrade Feedwater Controls

e 96-035: Install New DP Indications on EHC Filters

e 96-038: Convert 1C EDG to Series Operation

e 96-040: Upgrade ECCS Torus Suction Strainers

e 97-005: Thermal Pressure Relief Protection

e 97-016: Pull and Replace Control Cables to 23 Valves

Enclosure 3

,

e

35

4 97-044: Provide Cable Separation

-The inspectors observed that work packages were generally thorough

and complete. The 10 CFR 50.59 reviews were detailed and did not

identify any unreviewed safety questions. Procedures, drawings,

and TSs were identified when changes were required and the basis

for the 10 CFR 50.59 screening questions were thorough and

detailed. The design verification summaries reviewed by the

inspectors were detailed. The evaluation of the effects of the

design on the overall original plant design structures, systems

and components was reasonable.

During the review of DCR 97-016. the inspectors observed that some

procedures in the work package were not the current revision.

Additionally, some minor administrative errors existed on the Fire

Protection Checklist. No work had been performed using the

incorrect procedure revision or fire protection checklist. The

procedure errors were corrected prior to any work being performed

that required the procedures.

During work observations of DCR 96-035, the inspectors observed

that FME controls were good. However, minor discrepancies in

housekeeping were discussea with licensee management. The

inspectors observed later that the discrepancies had been

corrected.

c. Conclusions

The inspectors concluded from the DCR work reviewed that work

packages were generally thorough and detailed. The 10 CFR 50.59

evaluations were detailed, thorough, and appropriate. Changes to

procedures, drawings, and TSs were identified when required. The

evaluation of the effects of the design change on the overall

original plant design structures, systems and components was

reasonable. Work observed was in accordance with applicable

procedures and work packages.

E3.3 10 CFR 50.59 Evaluation Review and Procedure Chanae Process for

On-line Testina of Unit 1 Residual Heat Removal System

a, Insoection Scoce (62707)

The inspectors reviewed procedures 42SV-E11-004-1S, " Residual Heat

Removal Shutdown Cooling LSFT," Revision (Rev.) 5, and

42SV-Ell-005-1S, " Containment Spray LSFT", Rev. 5. ED 1. and the

Unit 1 Final Safety Analysis Report (FSAR), Section 4.8.11.

Residual Heat Removal (RHR) System Inspection and Testing, and

reviewed licensee personnel performance for RHR testing prior to

the Unit I refueling outage. The inspectors reviewed engineering

Enclosure 3

. __ __ _ _ _ . _ _ _ _ _ . -

.

.

36 l,

4

performance with respect to the 10 CFR 50.59 evaluations and

procedure revision process.

-

b. Observations and Findinos

The inspectors observed that engineering and operations personnel

completed procedure 42SV-E11-005-15 and portions of procedure

42SV-E11-004-15 while the unit was operating at about 98% and 92%

power respectively. Procedure 42SV-E11-005-IS was started at

2:36 p.m. on September 7 and was completed at 5:32 p.m. the same

day. Procedure 42SV-E11-004-1S was started at 9:50 a.m. on

October 8 and was partially completed at 4:55 p.m. the same day.

The inspectors observed that the tests were satisfactorily

completed and no deficiencies were observed.

The inspectors observed that section 4.8.11 of the Unit 1 UFSAR

stated, in part. " Testing of the sequencing of the LPCI mode of

operation is performed after the reactor is shut down and the RHR

system has been drained and flushed. Testing the operation of the

valves required for the remaining modes of operation of the RHR

system is performed at this time." In this case, one of the above

procedures was completed and one was partially completed with the

reactor in operation and the system not drained and flushed.

For the review of procedure 42SV-E11-004-15. Rev 5. the

inspectors obtained the official document from document control

and noted that step 6.2 of the prerequisites stated that. "The

'

unit shall be in Cold Shutdown Condition or Refuel Mode during the

performance of this 3rocedure " However, the inspectors were

later informed that Rev. 6 of the procedure for " validation use

only" was used by engineering to conduct the test. Revision 6 of

the procedure, dated October 7.1997, indicated what sections of

the procedure could be performed in different modes of Unit

operation. Some sections of the procedure were permitted to be

performed while the unit was operating.

Step 6.4 of procedure 42SV-E11-005-lS stated. in part, it is

recommended that the unit be in Cold Shutdown or Refuel Mode

during the performance of the test, although the test can be

performed in any operating condition.

The inspectors observed that, in the recent past, these LSFT

-

procedures were performed while the unit was shutdown. Als' it

was not a standard practice or requirement to have the RHR system

drained and flushed prior to conducting-the LSFTs.

The inspectors reviewed the 10 CFR 50.59 evaluations completed by

engineering for the procedure revisions that allowed on-line

performance of these procedures. The inspectors observed that the .

,

evaluation did not address section 4.8.11 of the FSAR which

Enclosure 3

__

-

.

_ -. _ . . . . _ _

,

'

,

,

37

s)ecified applicable test conditions, The inspectors observed

-tlat- two 10 CFR 50.59 screening cuestions wer e answered "no" as to .'

whether or not a change would be' required to a licensing document

and whether or.not the change to the procedure represented-a

change to the plant condition described in the FSAR. In this  ;

case. "yes" should have been the correct answer to both of these

screening questions.

The inspectors discussed this 10 CFR 50.59 review problem with

licensee management. The inspectors were informed that management

was reviewing a proposed revision to change the UFSAR wording to

match how the plant actually conducted the LSFTs. The ins]ectors

-also questioned licensee management as to whether or.not t1e

ongoing IIFSAR review program, which is conducted at the corporate

office, would have detected the UFSAR deficiency. Licensee

management later informed the inspectors that it was not likely

that the ongoing UFSAR review process would have detected the

UFSAR deficiency. The inspectors were informed that management

would assess the UFSAR review process to determine what changes

would be appropriate.

As part of the inspectors' review of the use of validation

)rocedures, procedure 10AC-MGR-003-05. " Preparation and Control of

3rocedures." Rev. 16, was reviewed. The inspectors observed that

the procedure was very subjective as to how validation of

procedure changes were to be processed. The procedure did not

provide clear guidance as to whether a procedure change would be

processed as a temporary procedure change (TPC) or a validation

comment. The inspectors discussed this and other minor

deficiencies with licensee management. The inspectors were

informed that procedure 10AC-MGR-003-0S would be reviewed for

possible improvements and to clarify some steps.

In this case, a change to procedure 42AV-E11-004-1S was not

completed in accordance with procedure 10AC-MGR-003-05.

" Preparation and Control of Procedures." Rev 16. The inspectors

.

were not aware of other 10 CFR 50.59 evaluation or procedure

~

revision problems.

c. Conclusions

The licensee's planned corrective actions to revise the FSAR,

assess corporate UFSAR review process, enhance future 10 CFR 50.59-

training and evaluation procedures, and the issuance of a-

department directive to explain the requirements, were

4

appropriate. A violation of minor safety significance is being

identified as Non-cited Violation (NCV) 50-321/97-10-09:

Personnel Error During 10 CFR 50.59 Review and Procedure Revision

Process For Residual Heat Removal On-line Testing.

Enclosure 3

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38

E4 Engineering Staff Knowledge and Performance

E4.1 Inservice Leak Testina of ASME Class 1 System (Unit 1)

a. Inspection Scoce (37551) (6270Z1

The inspectors reviewed inspection test procedure 421T-TET-006-15.

"ISI Pressure Test of the Class 1 System and Recirculation Pump

Runback Test," Rev. 9, conducted observations, and reviewed

documentation associated with the tests performed on November 8.

b. Observations and Findinos

The inspectors observed testing and reviewed the associated test

data. The inspectors observed that engineering personnel were

responsible for the performance of the procedure, including

assisting in the pre-evolution briefing, verifying test data, and

ensuring acceptable test results. Support was provided by

o)erations and maintenance personnel. The reactor pressure vessel

(RPV) leakage testing included the following:

• the establishment of an air bubble in the top of the reactor

pressure vessel with the water level between 170 inches and

190 inches above instrument zero

e the initial pressurization of the vessel to 100 psig using

plant service air

• the heat up of the vessel, using the reactor recirculating

pumps, to the minimum temperature specified in step 7 1.5 of

procedure 411T-TET-006-1S, and

• the pressurization of the vessel, to the test pressure of 1035

psig to 1050 psig by injection from the control rod drive

system and the controlling of pressure by varying reactor water

cleanup reject flow.

The inspectors observed that the responsibilities of operations

included starting the reactor recirculating pumps, pressurizing

the vessel, monitoring and maintaining vessel temperature,

controlling the vessel pressure, and recording data. Operations

supervision responsibilities during the test included command and

control of control room activities, conducting pre-evolution and

shift briefings, coordinating engineering support activities, and

insuring that the test was performed in accordance with procedural

requirements.

Maintenance was responsible for making repairs to leakage

identified during the RPV leakage test. The following

Enclosure 3

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.

39

deficiencies were identified and documented on deficiency cards

(DCs) during the test:

. C09705671 - Loop A RHR isolation gate valve 1E11-F060A had a

packing leak of approximately 100 drops per minute (DPM). MWO

l-97-3088 was implemented for repairs.

. C09705672 - The end cap after RWCU inlet vent globe valves

1G31-F131 and -F132 was leaking at a rate of less than one DPM.

MWO 1-97-3089 was implemented for repairs.

. C09705673 - Instrument isolation globe valve 1821-F014K (valve

was incorrectly identified as IB21-F015J Ua the DC) had a

slight packing leak. The follower and nuts had corroded. MWO

1-97-3087 was implemented for repairs.

. C09705675 - 45 north bank and 18 south bank control rod drive

hydraulic control units had valves with packing leaks or wet

packing. Maintenance work order (MWO) 1-97-3090 was

implemented for repairs.

The inspectors verified that all of the identified deficiencies

were satisfactorily repaired following the test.

The 1A reactor recirculation pump runback capability was

successfully tested following the performance of the RPV leakage

test. However, the 1B reactor recirculation pump tripped while

maintenance personnel were investigating a loss of speed

indication. The runback test for this pump was 3ost3oned until

the speed indication problem was resolved. Trou)leslooting

identified rolled wires as the cause. The wires were correctly

landed and the runback test for the IB reactor recirculation 3 1p

was later performed successfully. The inspectors discussed tit

rolled wiring with engineering personnel. The inspectors were

informed that the recirculation pump trip resulted when wiring

connections were loosened to reverse the rolled wires. The

loosened wires provided a circuit to the MG set field flashing

circuit, whicn was lost and caused the trip. The inspectors

observed that sianificant DCR work occurred with the wiring in the

control room panels. However, tne actual cause of the rolled

wires was not determined.

The inspectors reviewed the TS requirements for the leakage test

and reactor recirculation pump runback These requirements are in

TS section 3.10. "Special Operations." subsection 3.10.1.

" Inservice Leak and Hydrostatic Testing Operation." and TS section 3.4. " Reactor Coolant System (RCS)." subsection 3.4.9.

"RCS Pressure and Temperature (P/T) Limits." respectively.

Additionally, section 4.3.6 of the Unit 1 UFSAR was reviewed for

test applicability.

Enclosure 3

4

%

40

c. Conclusions

The inspectors concluded that the RPV leakage and reactor

recirculation pump runback tests were performed in accordance with

a) proved procedures. TSs. and conditions specified in the FSAR.

T1e activities were performed with good coordination between

engineering, operations, and maintenance. The performance of the

pressure tests and the leak repairs was excellent.

E8 Miscellaneous Engineering Issues (92700) (92903)

E8.1 (Closed) Violation 50-321. 366/97-01-01: Failure to Follow

Procedure - Multiple Examples.

Licensee personnel failed to follow procedure 42CC-ERP-011-0S,

Control Rod Exchange. Rev. 8, while executing a control rod

sequence exchange in January 1997.

The licensee's response to this violation, dated April 21, 1997,

indicated that the individuals involved were disciplined in

accordance with the company's positive discipline program and

counseled regarding the potential consequences of their actions.

Also, procedures 34G0 0PS-065-1S and 34G0-0PS-065-25, Control Rod

Movement, used in concert with 42CC ERP-011-05, were combined into

one procedure (34GO-0PS-065-05, effective April 16, 1997), which

requires varification that the Rod Worth Minimizer is enforcing

the proper sequence prior to using new control rod movement

sheets, she inspectors verified that procedure 34G0-0PS-065-0S

was revised.

Based upon the inspectors' review of licensee actions, this

violation example is closed. Other examples of this violation are

closed 'in sections 08.1, M8.1. and F8.1. One example of this

violation was closed in section P8.1 of IR 50-321, 366/97-03.

E8.2 (Closed) Violation 50-321/97-01-03: Failure to Translate Original

Design Specifications into Applicable Instructions.

This issue was documented in section E2.2 of IR 50-321. 366/97-01.

The licensee's response to this violation, dated April 21. 1997,

indicated that the licensee analyzed the subject vent line

configuration for vibration-induced stress and determined that it

was acceptable: issued Department Directive GM-97-06 on March 14,

1997, instructing engineering personnel how to obtain design

drawing information from available data bases: and drawing S-01286

was listed in the document retrieval system as a design drawing

reference for the vent line valves on April 14. 1997. The

inspectors were given a demonstration of how to obtain design

drawing information from available data bases, including verifying

that drawing S-01286 was listed in the document retrieval system

Enclosure 3

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.. . .

.

.

.

.

I 41

as a design drawing' reference for the vent line valves. Based

upon the inspectors review of licensee actions, this violation is

closed.

IV Plant SuoDort

R1 Radiological Protection and Chemistry Controls

R1.1 Observation of Routine Radioloaical Controls

a. Insoection Scoce (71750)

General HP activities were observed during the report period.

This included locked high radiation area doors proper

radiological posting. and personnel frisking upon exiting the RCA.

.

The inspectors made frequent tours of the RCA and discussed

radiological controls with HP technicians and HP management. The

minor deficiencies identified were discussed with HP technicians

and HP management for corrective actions. Specific observations

are detailed in the sections below.

Rl.2 Conduct of Radioloaical Protection Controls

a. Insoection Scone (83750)

Radiological controls associated with Unit 1 (U1) refueling cycle

RF 17 outage activities and with ongoing Unit 2 (U2) operations

were reviewed and evaluated by the inspectors. Reviewed program

areas included: area postings and radioactive waste (radwaste)

and material container labels, high and locked-high radiation area

controls, and procedural and radiation work permit (PWP)

implementation. Established controls were compared against

anlicable sections of the Updated Final Safety Analysis Report

(FSAR) requirements detailed in the Technical Specifications

(TSs), and 10 CFR Part 20.

The inspectors made frequent tours of the Radiologically

Controlled Area (RCA) and observed work activities within the U1

drywell, torus. reactor building, refueling floor, and turbine

deck areas. Guidance in specific procedures and RWPs was

reviewed and discussed with responsible health physics (HP) staff.

The inspectors directly observed HP technician performance.

Results of independent radiation and contamination surveys for

selected equipment and facility locations were compared against

current survey results used to establish RWP controls. Exposure

-results provided by digital alarming dosimeters (DAD) used during

diving. Inservice Inspection (ISI). and insulation operations were

reviewed and discussed. In particular, radiological controls

Enclosure 3

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

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42

described in the following RWPs were directly observed and

evaluated in detail:

e 197-1041. Rev. O. Divers Desludge Coating and Upgrade ECCS

Torus Strainers for Residual Heat Removal and Core Spray inside

Torus Proper Using Procedure 62-RP-RAD-022-05 and Support Work

Including Condensate Storage Tank (CST) Diving dated

September 6, 1997.

e 197-1022. Rev. O. Inservice Inspection (ISI) and Support Work,

dated September 3, 1997,

e 197-1020. Rev. O. Repair Shield Doors, insulation / Removal /

Replacement Temporary Shielding Scaffolding. Tent

Building / Removal & Support Work Including Subpile Room, dated

September 3, 1997.

b. Observations and Findinas

High and locked-high radiation aiaa controls were implemented in

accordance with TS requirements, Postings were proper and in

accordance with TS or 10 CFR 20 Subpart J requirements. Excluding

concerns with spent vacuum filters temporarily stored in the U1

torus pool and containers holding radwaste, contaminated materials

and equipment were labeled in accordance with 10 CFR 20.1904

requirements.

During tours conducted on October 22, 1997, the inspectors

identified labeling concerns for eight spent vacuum filters which

were st, red within the U1 torus pool. At the time, diving

operations were ongoing to upgrade the U1 Emergency Core Cooling

System (ECCS) torus strainers in accordance with RWP 197-1041.

During tours and observations of operations and equiament in

general areas located away from diving operations, t1e inspectors

observed eight lanyards attached to the catwalk railing which were

used to suspend material in the torus 3001 Bay 13 area. From

subsequent discussions with the HP teclnician providing job-

coverage of dive operations, the ins)ectors determined that the

suspended materials consisted of eig1t spent vacuum filters having

maximum contact dose rates of 4.7 to 7.5 rem per hour (rem /hr).

The filters previously were used in torus desludging operations

and were moved to their present location earlier in the day.

Labels were not affixed to the lanyards, identifying that

containers of radioactive materials. i .e. , the spent filters, were

suspended from the lanyards. Lanyards suspending eight additional

spent filters stored in U1 torus 3001 Bay 4 area were labeled

properly. The inspectors noted tlat 10 CFR 20.1904(a) requires

licensees to ensure that containers of licensed material not

subject to the exemptions of 10 CFR 20.1905 bear a durable,

clearly visible label bearing the radiation symbol and the words

Enclosure 3

-, _ - --- - -.

i

,

s

43

• CAUTION, RADI0 ACTIVE MATERIAL" or " DANGER. RADIOACTIVE MATERIAL."

The label must provide sufficient information to permit

individuals handling or using the containers, or working-in the

vicinity of_ the containers, to take precautions to avoid or .

minimize exposures. During discussion of access and radiological

controls within the 01 torus area, the inspectors determined that

-

continual HP coverage was required only when U1 torus diving .

operations were in progress and that the exemptions specified in

10 CFR 20.1905(c) and (e) were not met because the spent vacuum

filters were accessible to personnel entering the area at all

times. The inspectors identified the failure to label the spent

vacuum filters temporarily stored in the U1 Bay 13 torus pool area

as violetion (VIO) 50-321/97-10-05: Failure to Label Containers

of Radioactive Material in Accordance with 10 CFR 20.1904

Requirements.

Concerns were also identified regarding the adequacy of the

radiation survey map documentation associated with the U1 torus

pool spent filter temporary storage. The inspectors noted that

the current detailed survey maps of the U1 torus did not identify

,

the specific location of the stored filter.e within Bays 4 and 13.

From discussion with responsible HP staff and review of radiation

protection survey log sheets and control point logbooks, the

inspectors determined that radiological surveys, both contact and

general area dose rates, were taken when the filters were

uncoupled from the vacuum equipment ano placed in their temporary

storage locations. The reviewed survey documents met current

procedural guidance specified in 62RP-RAD-008-OS. Radiation and

Contamination Su veys, Rev. 9. effective March 4, 1997. The ,

inspectors questioned whether the torus spent filter storage

location changed dose rates to personnel on the catwalk above the

2001 as well as divers conducting subsurface operations,

lesponsible HP staff stated that, following movement of the

filters, radiation surveys verified that previous dose rates

affecting ongoing torus activities were not changed. The

inspectors noted that the information which the survey

documentation )rovided was marginal in identifying specific

locations of tle spent filters to all personnel who could access

the U1 torus locations. Licensee representatives stated that this

documentation concern would be evaluated and improvements in

survey documentation _would be initiated as necessary.

No concerns for external exposures were identified for persons

involved in diving activities. Accumulated dose and maximum dose

rates measured by. DADS were within expected ranges and

significantly below 10 CFR Part 20 limits. Where applicable,

extremity monitoring was used. For diving operations conducted

from October 18-20, 1997, a maximum dose rate of approximately

2.04 rem /hr and an accumulated dose of 98 millirem (mrem) were

Enclosure 3

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_ _ _ . _ _ .. . _. ~ _.

, ,

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%i -

'44

documented. The observed high dose rates were associated with

changeout of the spent vacuum filters.

From direct comparison with the previous U2 outage, the

inspectors noted that housekeeping and radiological control

practices associated with U1 turbine deck activities were

improved. In general, radiation exposure and contamination

control practices were followed by workers. However, several

'

isolated examples of poor radiation or contamination control

practices associated with U1 outage activities within the drywell,

torus, and reactor building areas were identified. The poor

3ractices included several examples of workers and a HP technician

laving loose or unfastened protective clothes (PC), i.e., hoods.

-while conducting U1 drywell and torus area activ1 ties. In

addition, the inspectors noted a worker laying on the floor of the

drywell airlock between ISI setup activities.

c. Conclusions

,

in general, radiological controls, area )ostings, and container

labels were maintained in accordance witi TS and 10 CFR 20,

Appendix J requirements.

'

The failure to label eight vacuum filters stored within the U1

torus Bay 13 pool was identified as VIO 50-321/97-10-05: Failure

to Label Containers of Radioactive Material in Accordance with 10

CFR 20.1904 Requirements.

The effectiveness of detailed survey maps to identify the hazards

from spent vacuum filters stored in the U1 torus was marginal.

External exposure controls for U1 outage tasks were effective in

maintaining personnel doses 'significantly less than 10 CFR Part 20

-limits.

In general, radiation exposure and contamination controls were

effective, with only isolated example of poor radiation practices

identified.

R1.3 Internal Exoosure

a '. Insoection Scone (83750)

The inspectors reviewed and discussed evaluations of potential

radionuclide. uptakes and resultant internal exposure from U1 RF17

outage activities.

Enclosure 3

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45

b. Observations and Findinas

As of October 22. 1997. five instances of potential radionuclide

uptake during the Ul outage activities were identified by routine

or investigative wholebody count analyses. Evaluations for the

five potential uptakes were completed in accordance with the

approved procedures. . No concerns were identified for assumptions,

time of initial uptake, or internal exposure pathway used in

licensee evaluations. All radionuclide intakes were less than 0.2

percent of the annual limit of intake (ALI), which would require

the internal exposure to be added to an individual's official

exposure records, in accordance with approved licensee procedures.

c. Conclusions

Licensee controls for minimizing internal exposure were effective,

with potential uptakes of radionuclides evaluated appropriately.

R3 Radiological Protection and Chemistry (RP&C) Control Procedures

and Documentation

R3.1 Dase Records

a. Insoection Scone (83750)

The inspectots reviewed and evaluated licensee program guidanco ,

and results for determining current-year prior occupational s.

The inspectors reviewed and discussed NRC Form 4, or equivalent

records, for selected contractor personnel involved in U1' RF17

outage health physics, ISI. drywell insulation. or torus diving

operations.

Licensee program guidance and corresponding records were compared

against 10 CFR 20 Subpart L requirements.

b. Observations and Findinos

The inspectors verified that appropriate records of current year

prior occupational doses were available for the selected

individuals. Estimated prior year doses assigned to the skin,

extremities, and lens of the eye for each individual worker were

conservatively based on the total effective dose equivalent (TEDE)

estimate or record. During review of applicable dose records

provided by previous employers, the inspectors identified several

examples of inconsistencies between deep and shallow dose

assignment. In each case, licensee representatives assigned the

more conservative dose value for estimating the individual's

current year exposure. Licensee representatives stated that

additional guidance for handling inconsistent ex30sure data

provided in individuals' official records would ]e developed.

Enclosure 3

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46

The inspectors also verified that records were available for

granting administrative dose extensions. in accordance with

approved procedures.

c. Conclusions

Records for determining workers' prior yearly occupational

exposures and granting administrative exposure extensions were

established in accordance with 10 CFR Part 20 Subpart L

requirements and administrative procedures.

R7 Quality Assurarre in Radiation Protection and Chemistry Activities

R7.1 Release of Contaminated Materials

a. Irlsnection Scone iB3750) (84750)

On approximately June 9-10, 1997, licensee radiation survey

quality checks of concrete material disposed of in the onsite

landfill, identified several potentially contaminated pieces of

material having contamination levels of 1100 to 1200

disintegrations per minute (dpm) above background. The inspectors

initiated a review of licensee pre- and post release survey

results, program guidance and licensee evaluations of the event,

and subseque.1 corrective actions.

Program guidance was evaluated against 10 CFR Part 20 requirements

and guidance provided in NUREG/CR-5569. Health Physics Positions

(HOPPOS) Data Base, Rev. 1. HPPOS-072 and -073.

b. Observations and findinos

from discussions with cognizant licensee re)resenta'ives and

review of pre-release surveys and HP logboots, the inspectors

determined that the concrete material was screened directly using

E-120 friskers prior to release from the Waste Separation and

Temporary Storage facility. Log entries of general survey results

for the concrete rubble released for disposal in the onsite

landfill indicated less than 100 corrected counts per minute per

100 square centimeters. From discussions with licensee

representatives who conducted the quality checks. the inspectors

determined that subsecuent OC surveys using E-120 friskers at the

landfill indicated raci' ,on levels of 1100 to 1200 dpm per probe

area for several pieces of concrete recovered from landfill

o)erations. Subsequent gamma-spectroscopy analyses verified that

t1e concrete rubble released to the onsite landfill was

contaminated slightly with cesium-137 and cobalt-60. The

inspectors noted that all of the licensee corrective actions

associated with the identified issue were not complete and.

pending additional NRC review, this item would be considered an

Enclosure 3

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Unresolved Itcm (URl) 50 321, 366/97-10 06: Review Licensee

Final Evaluation and Corrective Actions for Contaminated Concrete

Waste Materials Released to the Onsite Landfill.

c. Conclusions

Licensee OC checks identified that several pieces of slightly

cont W.nated concrete were released to the onsite landfill.

The inspector opened URI 50-321, 366/97-10-06: Review Licensee

Final Evaluation and Corrective Actions for Contaminated Concrete

Waste Materials Released to the Onsite Landfill.

R8 Miscellaneous RP&C Issues

R8.1 Contamination Cor, trol Initi6tives

a. Inspection. Scone (83750)(84750)

Implementation of licensee ( mtamination contrcl initiatives and

personnel contaminations were reviewed and discussed.

b. Observations and findinos

The inspectors discussed and verified the im)1ementation of

licensee initiatives to identify and reduce personnel

Contamination Event (PCEs) and associated Personnel Contamination

Reports (PCRs). Initiatives included: extensive RCA

contamination level determinations: laundry vendor and facilities

audits: 1ssuance of plant stand down orders in September 1997:

documentation of man 6gement expectations for plant radiological

practices; discussions of radiological work practices during

safety meetings: establishment of alarm levels for reusable mops

and towels: and development of radiological observation

checklists. 'n addition. the inspectors reviewed initiatives '

regarding availability of PCE and PCR data on the local area

network: administrative reassignment of all HP technicians to

report directly to HP management: and radworker requirements to

check with HP prior to performing work in the RCA. The inspectors

also reviewed and discussed the previous outage PCRs.

For the first 10 days of the current U1 outage the number of

daily PCEs i.e., contamination levels greater than 1000 dpm but

less than or equal to 10000 dpm, and PCRs. contamination levels

greater than 1000 dpm. were reduced relative to the previous U2

outage. For the first 10 days of the U1 outage, the licensee

re>orted approximately 30 total contamination events. i.e. 17

PCEs and 12 PCRs. respectively, compared to more than 200 total

contamination events for the same U2 outage period. The maximum

number of contamination events, approximately seven individuals.

Enclosure 3

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was reported for the second day of the U1 outage. The inspectors l

identified the initiatives as a program strength which were  ;

expected to contribute to a reduction in total contamination l

,

events through time, j

4' c. Conclusions >

Initiatives to address and reduce workar personnel contaminations  !

events were effectively implemented.

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R8.2 Insoector Fo110w-un of Previous Doen items (84750) j

(Closed) Unresolved Item (URl) 50 321. 366/97-05 05: Evaluate

Adequacy of CHRMs Electronic Signal Substitution Calibrations t

following Additional Review of the Licensee Response to Generic

Letters 82 05 and 82 10 Dated March 17, 1982 and May 5. 1982.

Respectively.

This item identified that in sftu calibration of the containment i

high range monitors (CHRMs) by electronic signal substitution as i

'

specified in procedure 575V-CAL 007 2S. Drywell High Range l

Radiation Monitor Loop Calibration. Rev. 1, was conducted for four

of the six range decades above 10 Roentgens per hour (R/hr). 6s

specified in NUREG 0737. Table II.F.1-3. The licensee did not

identify any exemptions from meeting the specific requirements of.

NUREG 0737. Table ll.F.1-3 in its response to Generic Letters 82-05 and 82-10. dated March 17. 1982 and May 5, 1982,

respectively. The inspectors noted that the surveillance

]rocedures were inadequate to meet the explicit requirements of

9UREG 0737. Table ll.F.1-3. The failure to have adequate

surveillance procedures to meet the CHRM electronic calibration

renuirements of NUREG 0737. Ta"le ll.F.1 3 was identified as a

violation of minor safety significance and, consistent with 'i

Section IV of the NRC Enforcement Policy. was being identified as

. NCV 50 321, 366/97 10-07: Failure to Have Adequate Surveillance

Procedures to meet the Containment High Range Radiation Monitors

Electronic Signal Substitution Calibrations Specified in

NUREG 0737. Table ll F.1-3.

During the onsite inspection, licensee representatives ) resented

revisions of surveillance procedures 575V-CAL-007-15. *)rywell-

High Range-Radiation Monitor Loop Calibration," Rev. 3. and

57SV CAL-007-2S. "Drywell High Range Radiation Monitor Loop

Calibration." Revs 3. From review of applicable records, the

inspectors verified that CHRH electronic calibrations for both-

units were completed by October 9. 1997. The 11spectors noted no

concerns with the procedural changes nor with the results

obtained.

Enclosure 3 l

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S2 Status of Security facilities and Equipment (71750)

!

lhe inspectors toured the protected area and observed that the

perimeter fence was intact and not compromised by crosion nor

disrepair. The fence fabric was secured and barbed wire was i

angled as required by the licensee's Plant Security Program (PSP).

Isolation zones were maintained on both sides of the barrier and

were free of objects which could shield or conceal an individual.

The inspectors observed that personnel and packages entering the

, protected area were searched either by special purpose detectors

or by a physical patdown for firearms. explosives, and contraband.

Badge issuance was observed. as was the processing and escorting

of visitors. Vehicles were searched. escorted, and secured as '

described in applicable procedures.

The inspectors concluded that the areas of security inspected met

the applicable requirements.

F3 Fire Protectica Procedures ard Documentation

F3.1 General Observations of Fire Protection Proaram Issues

a. Insnection Scone (71750)

The inspectors reviewed procedure 40AC-ENG-008 05 " Fire

Protection Program." Rev. 8. and made general observations during

plant walkdown tours,

b. Observations and Findinos

The inspectors observed that the )lant was generally clear of

excessive combustible material. Fire doors that were blocked open

for the Unit 1 refueling outage work were correctly documented

with tha required fire watch responsibilities identified.

Transient combustible permits (TCPs) were issued and posted

locally for material tlat required TCPs. The insoectors observed

that TCP 97-1180, issued for the temporary storas " +ransformer

oil, contained administrative errors. Th. identified

coolin!0poundsofoilwasallowedtobestoredatthatlocation.

that 3

The inspectors calculated that actual amount of oil stored was

about 2115 pounds. The inspectors contacted the engineer

responsible for the work.and noted that the TCP was immediately

corrected. The overall fire loading for the area was also changed

to reflect the correct value. The inspectors were later informed

that the TCP should have stated that 35.0 gallons of oil was

permitted to be stored, not 350 pounds. The inspectors did not

, view this error as significant. Immediate corrective actions were

appropriate.

Enclosure 3

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The ins)ectors observed that fire extinguishers were located at

hot worc locations when required by procedure. Additionally, a

constart fire watch was properly stationed at the hot work

location,

The inspectors accompanied a fire protection engineer on part cf

the routine monthly fire protection inspection on October 31,

Sections of the Unit I reactor building were walked down and

reviewed for potential deficiencies. The engineer immediately

correcteo some minor deficiencies and later initiated five

deficiency cards for more significant problems. The problems were

later corrected. immediate corrective actions were appropriate,

c. Conclusions

The inspectors concluded that the portion of the monthly fire

protection inspection observed by the inspectors was well-

performed. The fire protection engineer was knowledgeable of the

job responsibilities and fire protection equipment. The on the-

spot correction of some minor deficiencies was appropriate and the

deficiency cards initiated to identify and track other

deficiencies were timely.

F8 Hiscellaneous Fire Protection Issues (92904)

F8.1 1 Closed) Violation 50-221. 366/97-01 01: failure to Follow

Procedure - Multiple Examples.

1icensee personnel failed to follow procedure 40AC-ENG 008 05,

fire Protection Program, Rev, 8, in that they moved 55-gallon

drums of oil, oil and water, and oil sludge to the ll2-foot

elevation of the control building without first obtaining a

Transient Combustible Permit in February 1997.

The licensee's response to this violation, dated April 21. 1997,

indicated that the individuals involved were disciplined in

accordance with the company's positive discipline program and

counseled regarding the potential consequences of their actions.

Also, the 55-gallon drums were removed from the 112-foot elevation

of the control building and placed in a designated non-safety

related storage location, pending treatment and disposal of their

contents Transient Combustible Permit 97-2025 was issued for

storage of the drums in this area.

Based upon the inspectors * review of licensee actions this

violation example is closed. Other examples of this violation are

closed in sections 08.1, M8 1, and E8.1.

Enclosure 3

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F8.2 (Closed) Violatim 50 321. 366/97 01-04: Failure to Submit

Special Report on Degraded Fire Barriers.

This issue was documented in section F3 of IR 50-321, 366/97-01.

The licensee's response to this violation, dated April 21. 1997,

indicated that licensee personnel failed to realize that Fire

Hazardous Analysis (FHA) Appendix B required penetrations

separating fire areas to be operable regardless of which safe

shutdown systems and components were located in those areas. That

failure led persconel to erroneously conclude that the penetration

was not required by FHA Appendix B to be operable and. therefore,

to conclude that a special report was not required. The issue was

discussed with the individuals involved to heighten their

awareness of the consequences. The required special report was

submitted to the Safety Review Board on April 3. 1997. The

inspectors reviewed the re) ort and verified that it was submitted

as required. Based upon t1e inspectors' review of licensee

actions, this violation is closed,

y.Manaaementleetinas

X.2 Review of UFSAR Commitments

A recent discovery of a licensee operating its facility in a

manner contrary to the Updated Final Safety Analysis Report

(UFSAR) description highlighted the need for a special focused

review that compares plant practices, procedures and/or parameters

to the UFSAR description. While performing the ins)ections

discussed in this re) ort, the inspectors reviewed t1e applicable

portions of the UFSAR that related to the areas inspected. The

inspectors observed that section 4.8.11 of the Unit 1 UFSAR stated

in part that. " Testing of the sequencing of the LPCI mode of

operation is performed after the reactor is shut down and the RHR

system has been drained and flushed. Testing the operation of the

valves required for the remaining modes of operation of the RHR

system is performed at this time," This was not consistant with

the licensee's current testing methodology. This problem is

described in Section E3.3 of this inspection report.

X.3 Exit Meeting Summary

The inspectors presented the inspection results tu members of the

licensee management at the conclusion of the inspection on

November 25. 1997. The license acknowledged the findings

presented. An interim exit was conducted on October 24, 1997.

The inspectors asked the licensee whether any materials examined

during the inspection should be considered proprietary. No

proprietary information was identified.

Enclosure 3

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PARTIAL LIST OF PERSONS CONTACTED

Licensee

'

Anderson, J., Unit Superintendent

Betsill, J., Assistant General Manager - Opt. rations

Breitenbach C.. Engineering Support Manager - Acting

Curtis. S. , Unit Superintendent

Davis. D., Plant Administration Manager

fornel. P., Performance Team Manager

Fraser. 0.. Safety Audit and Engineering Review Supervisor

Hantnonds J. , Operations Support Superintendent

Kirkley W. Health Physics and Chemistry Manager

Lewis. J., Training and Emergency Preparedness Manager

Madison. D., Operations Manager

Moore. C.. Assistant General Manager - Plant Support

Reddick. R., Site Emergency Preparedness Coordinator

Roberts. P. Outages and Planning Manager

Thompson, J. . Nuclear Security Manager

Tipps. S., Nuclear Safety and Compliance Manager

Wells. P., General Manager - Nuclear Plent

INSPECTION PROCEDURES USED

IP 37551: Onsite Engineering

IP 37700: Design Changes and Modifications

IP 37828: Installation and Testing of Modifications

IP 40500: Ef fectiveness of Licensee Controls in Identifying.

Resolving, and Preventing Problems

IP 60705: Preparations for Refueling

IP 60710: Refueling Activities

IP 61726: Surveillance Observations

IP 62707: Maintenance Observations

IP 71707: Plant Operations

IP 71750: Plant Support Activities

IP 73753: Inservice Ins)ection

IP 83750: Occupational Radiation Exposure

IP 84750: Radioactive Waste Treatment, and Effluent and

Environmental Monitoring

IP 92901: Followup - Operations

IP 92902: Followup - Maintenance / Surveillance

IP 92903: Followup - followup Engineering

IP 92904: Followup - Plant Support

.

Enclosure 3

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ITEMS OPENED AND CLOSED l

Doened

l

50-321/97-10 01 IFI Review of Unit 1 RCIC Testing l

Activities from the Remote Shutdown i

Panel (Section 02.1). >

t

50-321/97-10-02 VIO Failure to Meet TS Surveillance i

Requirements Prior to Withdrawal of a

Control Rod While in Cold Shutdown  :

(Section 04.2).

50-321/97-10 03 NCV Jumper Placement Error During Unit 1  !

Testing Activities (Section M4.1). ]

50-366/97 10 04 DEV. Missed Connitment for Unit 2 Technical  !

'

Specification Amendment 132 (Section

E3.1).  !

'

50 321/97-10-05 VIO Failure to Label Containers of

Radioactive Material in Accordance '

with 10 CFR 20.1904 Requirements

(Section R1.2). .

50 321, 366/97-10-06 URI Review Licensee Final Evaluation and

Corrective Actions for Contaminated  ;

Concrete Waste Materials Released to ,

the Onsite Landfill (Section R7.1).

50 321, 366/97-10-07 NCV Failure to Have Adequate Surveillance [

Procedures to meet the Containment  ;

High Range Radiation Monitors  ;

Electronic Signal Substitution ,

Calibrations Specified in NUREG 0737

Table ll.F.1-3 (Section R8.2).

50-321, 366/97-10-08 IFI Review of 4160-Volt Breaker Failure

Analysis and Preventive Maintenance ,

Program (Section M1.5)- l

50 321/97-10 09 NCV Personnel Error During 10 CFR 50.59

Evaluation Review and-Procedure

Revision Process For Residual Heat-

Removal On-line Testing (Section E3.3)

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Enclosure 3

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Closed

50 321. 366/97-01-01 VIO Failure to follow Procedure - Multiple

Examples (Sections 08.1, M8.1. E8.1.

F8.1. of this report and P8.1 of

IR 50 321, 366/97-03).

50-321/97-05 LER Contro. Rod Partially Withdrawn

Without Pressure in Scram Accumulator

(Section 08.2).

50-366/97 01-02 VIO Inadequate Procedure for Calibrating

Unit 2 HPCI Time Delay Relay K14 c

(Section M8.2).

50-321/97-01 03 V10 Failure to Translate Original Design

Specifications into Ap>l1 cable

Instructions (Section E8.2).

50-321, 366/97-01-04 VIO Failure to Submit Special Report on

Degraded Fire Barriers (Section F8.2).

50-321, 366/97-05 05 URI Evaluate Adequacy of CHRMs Electronic

signal Substitution Calibrations

Following Additional Review of the

Licensee Response to Generic Letters 82-05 and 82-10 Dated March 17. 1982

and May 5. 1982. Respectively

(Section R8.2).

'

50-321/97-10-03 NCV Jumper Placement Error During Unit 1

Testing Activities (Section M4.1).

50-321, 366/97 10-07 NCV Failure to Have Adequate Surveillance

Procedures to meet the Containment

High Range Radiation Monitors

Electronic Signal Substitution

Calibrations specified in NUREG 0737.

Table ll.F.1 3 (Section R8.2).

50-321/97-10-09 NCV Personnel Error During 10 CFR 50.59

Evaluation Review and Procedure

Revision Process For Residual Heat

Removal On-line Testing (Section E3.3)

Enclosure 3

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