ML20141F884

Insp Repts 50-321/97-03 & 50-366/97-03 on 970406-0517. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20141F884
Person / Time
Site:	Hatch
Issue date:	06/17/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20141F845	List: ML20141F842 ML20141F864 ML20141F884
References
50-321-97-03, 50-321-97-3, 50-366-97-03, 50-366-97-3, NUDOCS 9707030207
Download: ML20141F884 (51)

See also: IR 05000321/1997003

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U.S. NUCLEAR REGULATORY COMMISSION

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REGION II

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Docket Nos:

50-321. 50-366

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License Nos:

DPR-57 and NPF-5

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Report No:

50-321/97-03, 50-366/97-03

Licensee:

Southern Nuclear Operating Company, Inc. (SNC)

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Facility:

E. I. Hatch Units 1 & 2

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Location:

P. O. Box 439

Baxley, Georgia 31513

Dates:

April- 6 - May 17,1997

Inspectors:

B. Holbrook, Senior Resident Inspector

E. Christnot. Resident Inspector

J. Canady, Resident Inspector

L Stratton, Safeguards Inspector, (Section

P8.1)

Approved by:

P. Skinner. Chief. Projects Branch 2

Division of Reactor Projects

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Enclosure 2

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9707030207 970617

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EXECUTIVE SUMMARY

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Plant Hatch. Units 1 and 2

NRC Inspection Report 50-321/97-03, 50-366/97-03

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This integrated inspection included aspects of licensee operations,

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engineering, maintenance.- and plant support.

The report covers a 6-week

. period of resident inspection: in addition it includes a portion of the

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results of.an announced inspection by a regional safeguards inspector.

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Ooerations

The operators and the shift technical advisor responded pro]erly

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when the Unit 2 reactor entered the " Operation Not Allowed

Region"

of the power-to-flow map following a Reactor Recirculation System

runback on April 22.

Personnel response.to the runback was

considered good (Section 01.1).

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Clearance deficiencies associated with the main steam lines and

the Transversing Incore Probe System were identified. The

licensee is reviewing the root cause and corrective actions for

these deficiencies in conjunction with the corrective actions for

a recent NRC violation associated with previous clearance problems

(Section 01.1).

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The Unit 2 main turbine overspeed trip test was conducted in a

controlled manner. The shift pre-brief was thorough and personnel

involved in the testing were cognizant of their job functions.

The use of state-of-the-art communications equipment in the

control room allowed operators to devote more attention to system

controls and indications (Section 01.2).

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The Unit 2 startup was performed using effective communications,

command and control, engineering support, and management

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oversight.

The activities and performance of the shift technical

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advisors and operators for control rod movement activities were

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excellent.

All other activities were good (Section 01.3).

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The inspectors did not identify any condition during the Unit 2

drywell walkdown that presented a system operability or Emergency

Core Cooling System (ECCS) strainer blockage concern.

No system

leaks were observed.

System insulation appeared to be properly

placed and, except for.one minor deficiency that was immediately

repaired, appeared to be securely attached (Section 02.1).

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The. inspectors concluded that the observed operation of systems

affected by various modifications during the recent Unit 2

refueling outage was satisfactory.

The inspectors did not

identify system deficiencies as a result of modifications

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(Section 02.2).

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Following the Unit 2 Scram on April 22. o)erators used procedures,

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communicated well, and made the required 1RC notification.

Supervisory oversight was evident. The Event Review Team

investigation was thorough and comprehensive. A weakness was

identified in operator performance for failure to observe control

room indications and identify an ongoing loss of condenser vacuum.

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The' inspectors considered management's failure to provided

specific direction or guidance to monitor a system that had not

-performed satisfactorily for about 10 years (B SJAE) and recently

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laced in service during unit startup to be significant oversight

Section 04.1).

Maintenance

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' Maintenance activities were generally completed in a thorough and

professional manner.

No deficiencies were identified

(Section M1.1).

The inspectors concluded that the maintenance and engineering

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activities associated with trouble shooting the Unit 2 High

Pressure Cooling Injection System auxiliary oil pump ground was

reasonable and thorough. Replacing the pump motor was

appropriate. The Engineering evaluation which determined that the

system was not rendered inoperable due to the ground was

reasonable (Section M1.2).

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The' Infrared Thermogra)hy program was not fully developed to

procedurally address t1e safety-related, normally energized CR120

relays. Adequate cooperation between Maintenance Engineering and

Nuclear Safety and Compliance personnel was-demonstrated to

identify the CR120 relays that were inaccessible for infrared

thermography surveys (Section M1.3).

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The surveillance procedure activities observed and reviewed were

through and professional.

The 3rocedures were used under the

continuous use requirements wit1 engineering. Shift Technical

Advisor, and supervisory oversight.

Personnel use and aerformance

of the Surveillance Procedures were excellent (Section 13.1).

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Non-Cited Violation (NCV) 50-366/97-03-01. Failure To Follow

Procedure During Welding Process of Unit 2 Reactor Core Isolation

Cooling Valve, was identified. The root cause of the problem was

not conclusively determined. The human behavior demonstrated for

failure to report the problem to licensee management was a serious

concern.

Plant management took timely corrective actions. The

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Quality Control inspectors * identification and followup actions

for the unauthorized work was excellent

(Section M4.1).

Enclosure 2

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The movement of Unit 2 control rods with the Source Range

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Monitoring System surveillance not performed within the required

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frequency was a violation of Unit 2 Technical Specifications and

was identified as NCV 50-366/97-03-02. Data Entry Error Results in

Missed Technical Specification Surveillance on Unit 2.

Personnel

error for data entry to the surveillance schedule task sheet was

the root cause.

Licensee immediate corrective actions were

appropriate (Section M4.2).

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The licensee's actions that resulted in the identification of a

ny -:afety related valve being used in a safety-related

application was excellent. The reviews and evaluations performed

upon discovery of the problem were thorough and timely.

This was

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identified as NCV 50-321/97-03-03. Failure to Commercially

Dedicate Isolation Valve (Section El.1),

Engineering's timely followup action upon the discovery of the

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wiring-to-drawing inconsistency in the 2F 4160 volt alternating-

cur ~ent switchgear resulted in promat correctiva actions by

maintenance.

The circuit analysis )y the licens?a's engineering

staff and the Architectural Engineer which indicated that failures

of the involved circuits would not impact.the ability to safely

shut down the units was reasonable (Section E1.2).

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A violation occurred when a special purpose test procedure did not

reflect a recent Unit 2 feedwater control circuit modification and

an unexpected plant transient occurred. This was identified as an

exampic of Violation 50-366/97-03-04. Inadequate Procedures for

Terung Activities - Multiple Examples (Section E2.1).

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The inspec. tors concluded that engineering Jersonnel adequately

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addressed the GL 96-01. Testing of Safety-lelated Logic Circuits,

issue involving the 2E. 2F and 2G 4160 volt switchgear alternate

supply breakers. Test ruults met the applicable test acceptance

criteria (Section E2.2).

The inspectors concluded from the reviews and observations of

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Unit 2 modified systems that the overall post-modification tests

of the systems, except for the two deficiencies noted, were

adequate. Training for the operators on the modifications was

adequate (Section E2.3).

lhe licensee's current program for determining the operability of

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sealed penetrations was adequate.

Management was aware of the

issues associated with the sealed penetrations and the fire

protection program and provided satisfactory support.

A weakness

was identified for specialized training documentation provided to

craft persons who install and repair sealed penetrations.

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personnel's annual eye examinations review met the requirements.

The inspectors did not identify any deficiencies with the

penetrations that were inspected (Section E2.4).

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The logic systam functional test procedure for the 2A emergency

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diesel generator did not contain precautions or prerequisitions

nor identify appropriate pretest conditions to prevent an

unexpected Engineered Safety Function actuation during testing.

This is.an example of Violation 50-366/97-03-04. Inadequate

Procedures for Testing Activities - Multiple Examples (Section

E3.1).

The 3erformance of the Unit 2 pressure test and the followup test

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of t1e Class 1 system were performed in accordance with approved

procedures. The overall activities were performed with

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engineering, quality control. and supervisory oversight. The

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performance of the pressure tests and the repair of identified

leaks were considered to be excellent (Section E4.1).

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Plant Suocort

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The inspectors concluded that, in general, radiological controls

were satisfactory with designated personnel assigned to assist.

monitor, and control radiological activities.

Minor deficiencies

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were discussed with licensee management (Section R1.1).

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The licensee's implementation of the General Employee Training

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program for contractors was satisfactory. All training records

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reviewed indicated that personnel were either provided training or

had passed the required examinations to obtain credit for previous

training. The inspectors concluded that all personnel were

satisfactorily trained for their level of site access

(Section R5.1).

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One emergency preparedness exercise objective. The Ability for

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Prompt Notification to the State, Local and Federal Authorities,

was not met during the exercise conducted on May 6.

The

inspectors concluded that no significant improvements were

observed with regard to notifications as compared to performance

observed in June 1996.

The licensee's post-exercise critique and

overall exercise assessment to self identify areas for improvement

were considered to be excellent (Section P4).

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The inspectors concluded that the areas of security inspected met

the applicable requirements (Section S2).

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Reoort Details

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Summary of Plant Status-

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Unit 1 began the report period at 100% rated therm 61 power (RTP).

Power

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was reduced to about 78% RTP on April 24 to repair a motor cooling coil

leak on the "B" condensate pump.

RTP was achieved on April 26.

Power

was reduced to about 90% RTP on May 10, to repair a cooling water leak on

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the "C" condensate pump.

Reactor power was restored to RTP the same-day

and was maintained throughout the report period, except for routine

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testing activities.

Unit 2 began the report period in day 23 of a scheduled 34 day refueling

outage.

Following the refueling outage, the reactor was brought critical

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on April 18 and was tied to the grid on April 20.

The unit ex)erienced

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a runback of both reactor recirculation pumps from about 67% RT) to about

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45% RTP on April 22 during feedwater flow control system testing.

Power

was increased to about 65% RTP following the transient.

On April 22 an

automatic reactor scram occurred on a Turbine Stop Valve Closure signal

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when the main turbine tripped on low condenser vacuum.

The reactor was

brought critical on April 24 and power was increased to about 80% RTP.

On April 27, power was reduced in preparation to remove the "B"

condensate booster pump from service due to a high bearing temperature

alarm.

Power was increased following a investigation which revealed

that the high bearing temperature alarm was false.

RTP was achieved o'n

April 29.

On May 4. unit power was reduced to 85% RTP to backwash,

precoat and alace in service a condensate demineralizer.

RTP was

achieved on iay 5, and was maintained throughout the remaining report

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period, except for routine testing activities.

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-I. Ooerations

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Conduct of Operations

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01.1 General Comments (71707)

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The inspectors conducted frequent reviews of ongoing plant

operations. 'In general, the conduct of operations was

professional and safety-conscious; specific events and

observations are detailed in the sections below.

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During the Unit 2 startu), a Reactor Recirculation System runback

occurred on April 22. T1e runback was caused by post-modification

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testing a Reactor Feed Pump Turbine Control System upgrade. The

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o)erators and the shift technical advisor (STA) responded properly

w1en the reactor entered the " Operation Not Allowed Region" of the

reactor power to flow map. .The region was immediately exited

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using control rods and increased recirculation flow.

The operator

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res)onse to the runback was good. Additional discussion of the

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run)ack is documented in section E2.1 of this report.

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'The' inspectors observed and were informed by operations management

that clearance problems associated with the main steam lines (MSL)

'and the Transversing Incore Probe (T1P system were identified.

During the restoration of the MSLs licersee personnel observed.

water coming from the MSL pipe chase area and going down into the

torus area.

The inspectors were informed that drain valves used

for local leak rate testing were inadvertently left open.

The clearance problem associated with the TIP system involved the

manual hand cranking operation and resulted in a TIP being left

outside of the shield. No over-exposure resulted in the-

occurrence. A violation was issued in inspection report 50-321.

366/97-02 involving a clearance problem which resulted in the

start of an Emergency Diesel Generator. The inspectors will

include the licensee's review of the root cause and corrective

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actions for these clearance problems in conjunction with the

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corrective actions for the previous violation.

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01.2 Main Turbine Oversoeed Testina Durina Startuo Activities

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Insoection Score (71707)

The inspector; observed overspeed trip testing of the Unit 2 main

turbine in accordance with procedure 34IT-N30-004-2S. " Turbine

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Overspeed Trip Test". Revision (Rev.) 1.

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Observations and Findinas

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On April 20. the inspectors observed the shift supervisor conduct

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a shift pre-brief prior to the start of the test. The inspectors

observed the use of three-part communications during the pre-brief

and the testing. The inspectors also observed the use of state-

of-the-art wireless communications equipment (low powered cellular

phone with headset) by the operators during the testing

activities.

This provided improved communications while

performing switch manipulations.

Overspeed and backup overspeed trip tests were performed in

accordance with the procedure.

The backup overspeed trip test was

within the acceptance criteria of procedure 34IT-N30-004-2S but

the overspeed trip occurred at a turbine speed less than that

s)ecified by the procedure (1880 vs 1953 Revolutions Per Minute

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(RPM)). Tripping sooner than the acceptance criteria was

considered to be conservative by the licensee. General Electric

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personnel provided approval for the actual trip value of 1880 RPM.

The inspectors observed that the overspeed trip test was

considered unsatisfactory until a letter from General Electric was

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received indicating approval of the lower overspeed trip value.

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Conclusions-

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The shift pre-brief was thorough.

Personnel. involved in the

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testing activity were cognizant of their job functions and the

-test was conducted in a controlled manner and in accordance with

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procedures.

The use of state-of-the-art communications equipment

provided improved communications techniques while performing

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switch manipulations and allowed the operators _to devote more-

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attention to system controls and. indications.

01.3 Unit 2 Startun Observations

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a.

Insoection Scooe (71707) (71711)

The inspectors observed Unit 2 control room (CR) startup

activities following the refueling outage.

The observations

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included the use of appropriate procedures, operator

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communications. STA activities. engineering support, control by

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on-shift supervision..and management oversight.

b.

Observations and Findinas

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The inspectors observed Unit 2 startup activities following the

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refueling outage. Prior to the startup, the inspectors performed a

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walkdown of the nuclear instrumentation /incore monitoring system

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and the. emergency power system to verify system configuration and

performance.

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The inspectors observed the use of procedures during the startup

activities and verified that they were the correct revision,

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Among the Hatch System Operating Procedures (HSOP) used were:

34G0-0PS-001-2S, " Plant Startup." Rev. 30: 34S0-B31-001-2S.

" Reactor Recirculation System." Rev. 20. and 34S0-N30-001-2S.

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- Main Turbine Operation." Rev., 17.

Among the Hatch Test and

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Ins)ection Procedures (HT&IP) and Hatch Surveillance Procedures

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(HS)) used were:

34IT-N21-001-2S " Reactor Feed Pump Turbine

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Overspeed Trip Test and Dynamic Checks." Rev. 6. 34SV-SUV-021-05.

"APRM Adjustment to Core Thermal Power." Rev. 6. 34SV-SUV-025-0S,

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" Core Heat Balance." Rev. 8. and 34SV-C51-003-2S. "LPRM

0)erational Status." Rev. 3.

The inspectors noted that Rev. 6 of

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tie promdure for APRM adjustment was dated April 10, 1997.

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3rocedure was revised due to the installation of the new Power

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Range Neutron Monitoring (PRNM) system that was installed during

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the refueling outage.

The inspectors observed that the CR personnel generally used

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three-part communications and the phonetic alphabet.

Command and

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control and oversight by the shift supervisors were effective.

Crew briefings were conducted prior to major evolutions.

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The inspectors observed that an audit of the startup was being

performed by the-onsite audit group on an around-the-clock basis.

The inspector observed that the Plant General Manager. Assistant

General Manager-Plant Operations, and Unit Superintendents were

routinely present in the CR on a shiftly basis.

The inspectors observed, prior to the startup, the performance of

the reactor vessel pressure test, procedure 42IT-TET-006-2S. "ISI

Pressure Test of Class 1. System and Recirculation Pump Runback."

Rev. 2.

During the pressure test, procedure 42SV-C11-003-05.

" Control Rod Scram Testing." Rev. 2, was also performed.

Additional observations on the vessel pressure test are provided

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in Section E4.1 of this report.

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Control rod sequence and rod withdrawal were controlled by Rod

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Movement Sequence sheets.

During control rod movements, the

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inspectors observed that a second verifier was used to ensure that

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proper control rod movements were performed.

Engineering support was observed during the startup for

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post-modification testing, nuclear instrumentation adjustments.

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and process computer. troubleshooting. The STA activities observed

included the performance of surveillance procedures, verifying

proper control rod withdrawal, and performing heat balance

calculations.

A runback occurred.during the unit startup and is discussed in

Sections 01.1 and E2.1 of this report. A reactor scram occurred

during the startup and is discussed in Section 04.1 of this

report.

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Conclusions

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The inspectors concluded that the startup was performed using

effective communications, command and control, engineering

support. and management oversight.

Operators:and engineering

personnel used appropriate procedures and control rod pull sheets.

It was also concluded that the activities of the STAS and the

control rod movement activities were excellent. All other startup

activities were good.

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Operational Status of Facilities and Equipment

02.1 Unit 2 Orywell Closeout After Refuelino Outaae (71707)

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The inspectors reviewed procedure 34GO-0PS-028-2S. "Drywell

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Closecut". Rev. 7.'and conducted a drywell walkdown to observe

general housekeeping conditions, system insulation installation,

and observe systems for leakage.

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The inspectors considered housekeeping to be good, although a few

small items of debris, such as alastic tie wraps, small pieces of

wire, plastic and paper, were o] served.

Licensee ]ersonnel

immediately collected the items. The inspectors o) served one

piece of blanket insulation that was not securely attached at one

end.

This was immediately repaired.

The inspectors observed that

several retaining clips. for mirror-backed insulation were missing

while others were repaired by wire. The inspectors observed that

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several pieces of new insulation were installed as well as some

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new floor grating.

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The inspectors discussed the condition of the insulation with

licensee management and were informed that the new insulation was

a result of a drywell insulation upgrade initiative. The licensee

plans to upgrade the drywell insulation over the next several

refueling outages.

The new floor grating was a result of employee

safety concerns identified during the last refueling outage.

The inspectors did not identify any condition in the drywell that

presented a system operability cr ECCS strainer blockage concern.

No system leaks were observed.

System insulation appeared to be

properly placed and, except for the comments above, appeared to be

securely attached.

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02.2 .0bservations of System Performance Durina Unit 2 Refuelina and

Startuo

a.

Insoection Scooe (71707) (60710)

The inspectors observed specific Unit 2 system performance during

refueling and.startup following the spring 1997 refueling outage.

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The observations also included operations at RTP.

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b.

Observations and Findinas

The observations of system performance focused on systems which

were modified during the refueling outage. Among the systems

observed were the following:

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the main turbine, which had three stages to the high pressure

turbine replaced:

the reactor feed pump turbines, which had an upgraded control

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system installed to give the system more versatility, including

supplying the two systems from separate power sources to

address a single failure problem:

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the Condensate Deminerilizer System, which had its pneumatic

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control system replaced with an electronic system; and

the cooling water to the plant service water pumps, which had

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check valves removed.

The systems observed operated satisfactorily up to and including

RTP.

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Conclusions

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The inspectors concluded that the operation of systems affected by

various modifications during the recent Unit 2 refueling outage

was satisfactory. The inspectors did not identify deficiencies as

a result of modifications.

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04.0 Operator Knowledge and Performance

04.1 Unit 2 Turbine Trio and Reactor Scram Due to Loss of Condenser

Vacuum

a.

Insoection Scoce (92901)

The inspectors reviewed procedures. 34AB-C71-001-2S. " Scram

Procedure". Rev. 6. ED 2, Emergency Operating Procedure."RC RPV

Control (Non-ATWS)". Rev. 5. 00AC-REG-001-0S. " Federal and State

Reporting Requirements". Rev. 4. 34AB-T22-003-2S. " Secondary

Containment Control". Rev. 2 and observed scram recovery and

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corrective actions for a Unit 2 automatic Scram that occurred on

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April 22,1997

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b.

Observations and Findinas

On April 22. Unit 2 was at about 55 % RTP.

Unit power was

increased to about,75% RTP following startuo after a scheduled'

34-day refueling outage.

Power was subsequently reduced to 55%

RTP to conduct Feedwater Control System testing.

Operators received a hign hotwell level alarm and, during their

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panel review observed that condenser vacuum was decreasing. _The

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turbine tripped on low vacuum and the reactor automatically

scrammed, as expected.

Reactor level decreased to about -45

inches (top of active fuel is about -165 inches).

High pressure

ECCS initiated as expected and operators manually injected water

with the standby reactor feed pump (RFP).

Reactor water level was

increased. The RFP tripped on high level and operators manually

secured the ECCS.

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One of the inspectors responded to the site to observe operator

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scram recovery actions and assess licensee performance. The

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inspector observed that operators used procedures.~ communicated

well and supervisory oversight was evident.

The inspector-

reviewed the emergency operating procedures (EOPs) used and

concluded that operators took the appropriate actions for the

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existing plant conditions.

The inspector verified that secondary

and primary systems isolated as required and were reset and

returned to normal.

The 10 CFR 50.72 report to the NRC was made

within the allowed time limit.

The inspectors discussed the problem with Event Review Team (ERT)

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members, operators on shift and operations management.

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the' operators suspected a problem with the B Steam Jet Air Ejector

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(SJAE)

The B SJAE. which had not operated satisfactorily for

about 10 years, was placed in service for unit startup.

Inspector

observations of previous SJAE problems are documented in

Inspection Report (IR) 50-321, 366/96-04.

Recent maintenance

activities were completed to repair the SJAE. The SJAE was

successfully placed in service during the Unit 2 shutdown

activities prior to the refueling outage and remained in service

until the unit was removed from service.

The inspector observed main control room chart recorders that

provided indication of potential condenser vacuum problems.

The

inspectors observed that the recorder for condenser circulating

' water temperature (inlet and outlet temperature) indicated a

divergent trend for about 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> ]rior to the Scram.

Since

reactor power had been increased, tais indication was expected to

show some divergence.

However, temperature indicated a

significant increase about 45 minutes prior to the scram and

during this time reactor power was not increased. The inspectors

considered this as an early indication that potential vacuum

problems existed.

'

.

The recorder for condenser vacuum indicated that the B pen showed.

no condenser vacuum decrease.

However, the A pen showed a

divergence from the B pen and decreasing vacuum for about 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s-

prior to the scram.

Although some divergence is expected. a

significant difference was observed about 45 minutes prior to the

scram. A more questioning attitude toward this indication may-

have resulted in early detection of the vacuum problem. The

operator performance for failure to observe control room

indicators and identify an ongoing loss of condenser vacuum is

identified as a weakness.

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Enclosure 2

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The ERT identified several items that needed to be resolved prior

to unit startu) and other items that may require long term

resolution. T1e inspectors concluded that the priorities placed

on the items were appropriate.

The inspectors discussed management's failure to provided specific

direction or guidance to monitor a system that had not performed

satisfactorily for about 10 years (B SJAE) and placed in service

during unit startup. The inspectors considered this lack of

direction to be a significant oversight.

The startup issues were corrected and a unit startup was initiated

on April 24.

c.

Conclusions

The inspectors concluded that following the Unit 2 scram,

operators used procedures, communicated well, and made the

required NRC notifications. Supervisory oversight was evident.

The ERT investigation was thorough and comprehensive.

A weakness

was identified for operator performance for failure to observe

1

control room indications and identify an ongoing loss of condenser

l

vacuum. The inspectors considered management's failure to

3rovided specific direction or guidance to monitor a system that

lad not performed satisfactorily for about 10 years (B SJAE), and

recently placed in service during unit startup, to be a

significant oversight.

08

Miscellaneous Operations Issues (92901) (92700) (90712)

08.1

(Closed) Violation 50-321. 366/96-13-03:

Failure to Follow

Procedure - Multiple Examples.

A plant equipment operator failed to follow the requirements of

Hatch Administrative Control Procedure 30AC-0PS-001-0S., " Control

of-Equipment Clearances and Tags," Rev. 15, while performing a

clearance for the 1A control rod ' drive pump.

The licensees's response to this violation, dated December 19,

1996, indicated that the individual involved was disciplined in

accordance with the company's positive discipline program.

In

addition to the disciplinary actions, the accuracy in hanging

clearances and tags and performing peer checks were emphasized

during pre-job briefs.

Based upon the inspectors' review of

licensee actions, this violation example is closed.

Other

examples of this violation are closed in sections M8.2 and R8.1 of

this report

Enclosure 2

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08.2

(Closed) LER 50-366/1997-07:

Loss of Main Condenser Vacuum

Results -in a Main Turbine Trip and Automatic Reactor Shutdown.

This event is discussed in section 04.1 of this report.

No new

issues were revealed by the LER. This LER is closed.

_

08.3

(Closed) LER 50-366/1997-005:

Personnel Error Results in

Unplanned Automatic Engineered Safety Feature Actuation.

This.

event is discussed in section 01.6 of IR 50-321. 366/97-02. This

,

problem was identified as an example of failure to follow

procedure - multiple examples.

No new issues were revealed by the

'

LER.

This LER is closed.

II. Maintenance

,

M1

Conduct of Maintenance

M1.1 General Comments

a.

Insoection Scooe (62707)

The inspectors observed or reviewed all or portions of the

'

following work activities:

e

MWO 1-96-2712:

clean, inspect. and meggar test 1R24-S009.

600/208V alternating current motor control

center IA

,

e

MWO 2-97-1306:

remove and-replace high pressure coolant

injection (HPCI) turbine auxiliary oil pump

motor

- i

e

MWO 2-97-1041:

install a seal welded metal gasket at the

flange connection of reactor vessel head

nozzle 6B per design change request (DCR)97-019

e

MWO 2-96-3005:

pull cables for PRNM DCR 94-008

e

MWO 2-97-0033:

aull cables for feedwater control

JCR 95-054

e

MWO 1-97-0745:

realace Nelson fire seal per

42:P-FPX-003-0S

'

e

MWO 2-97-0937:

check and repair penetration per

42FP-FPX-014-0S

b.

Observations and Findinas

The inspectors observed that the work was performed with the work

j

i

!

packages present and being actively used. The inspectors observed

'

that during the cleaning and inspecting of the 1A motor control

center, a four-wire rig was used to short the three phases and the

fourth wire was used to ground the phases.

Each of the three

i

wires used to short the phases was individually danger tagged.

l

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Enclosure 2

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However. %e fourth wire (the grounding wire) was not danger

tagged. The inspectors questioned whether this was a good

practice for personnel safety. The inspectors discussed this

l

observation with the maintenance su]ervisors and system clearance

management and were informed that t1e danger tags were placed for

l

equipment protection and not personnel safety.

MWO 2-97-1306, the realacement of the auxiliary oil pump motor is

discussed in Section 11.2 and MWO 2-97-1041, the seal welded metal

gasket, is discussed in Section E4.1 of this report.

The MW0s

associated with cable pulls and fire protection penetrations are

discussed in Section E2.4 of this report.

c.

Conclusions on Conduct of Maintenance

Maintenance activities were generally completed in a thorough and

'

professional manner.

No deficiencies were identified by the

inspectors.

M1.2 Ground on Unit 2 HPCI Auxiliary 011 Pumo.

!

a.

J_nsoection Scoce (62707) (92902)

The inspectors reviewed Deficiency Cards (DC) 97-2240, "HPCI.

Auxiliary Oil Pump Caused a Ground," procedure 00AC-REG-001-0S,

" Federal and State Reporting Requirements." Revision (Rev.) 4, and

i

reviewed maintenance and engineering activities to repair the HPCI

)

auxiliary oil pump. The inspectors also reviewed the licensee's

10 CFR 50.72 Report and a HPCI operability evaluation.

b.

Observations and Findinas

i

Following a Unit 2 scram on April 22, operations personnel

identified that the HPCI auxiliary oil pump caused a ground on the

associated power bus.

The ground cleared about 5 minutes after

the pump was secured.

Operators initiated a DC for maintenance to

identify and re) air the ground.

Maintenance personnel used

procedure 50AC-INT-001-0S, " Maintenance Program." Rev. 24, in an

attempt to identify the problem but were not successful. The HPCI

l

auxillary oil pump was started several times in an attempt to

duplicate the ground problem.

However, the ground did not return.

No further maintenance actions were performed and the system was

placed in service.

,

On April 30. during the performance of the HPCI system monthly

l

surveillance, the ground reappeared. The brea'ker for the pump was

l

opened and the ground clearec. Again maintenance personnel were

unable to find any problem with the pump motor.

W1en the pump

'

motor breaker was reclosed the ground did not return.

The HPCI

.

surveillance was repeated and the ground re-appeared.

l

Enclosure 2

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11

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The licensee. declared the HPCI system inoperable, initiated the

required TS action statement'. and made a 10 CFR 50.72

l

l_

notification,

,

Maintenance personnel inspected the oil pump motor and discovered

a problem with the motor armature. The motor was replaced, a

functional test was performed, and the system was declared

l

operable.

l^

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.

i

Nuclear Safety and Compliance (NSAC)' personnel reviewed the ground

!

problem and work activities to determine if the actions completed

on April 22 should have reasonably identified and corrected the

problem and prevented the ground on April 30.

They concluded that

the maintenance activities completed on April 22 would not have

reasonably identified the problem.

l

l

As part of the NSAC review, engineering )ersonnel concluded that

the auxiliary oil pump ground would not lave prevented the HPCI

system from performing its intended safety function.

The

auxiliary oil pu'ap supplies initial oil until the shaft driven oil

pump reaches sufficient speed to supply the required components.

The inspectors reviewed Unit 2 Final Safety Analysis Report (FSAR)

sections 6.3. 7.3.1, and 7.8. "ECCS." The FSAR indicated that the

L

auxiliary oil pump should operate until the main pump speed-

reached about 2000 RPM.

Engineering Jersonnel determined that

time to be about 10 to 15 seconds.

T e auxiliary oil pump had

1

o]erated 'several times in excess of 30_ minutes during the trouble

l

slooting activities with no failures.

Licensee personnel withdrew

-

l

the 10 CFR 50. 72 notification on May 9.

c.

Conclusions

'

l

The inspectors concluded that the maintenance and engineering

i

activities associated with trouble shooting the HPCI auxiliary oil

!

pump ground were reasonable and thorough.

Replacing the pump

!

motor was ap3ropriate.

The engineering evaluation which

determined tlat the HPCI was not rendered inoperable was

'

reasonable. Withdrawing the 10 CFR 50.72 notification on May 9

l

was appropriate.

l

M1'3

Inaccessible CR120 Relav Evaluation for the Infrared Thermoaraohv

.

Proaram

a.

Insoection Scooe (92902)

The inspectors conducted discussions with licensee personnel and

reviewed procedure 53PM-MON-003-0S " Infrared Thermography

i

Program," Rev. 2.

The discussions and procedural review were

t

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Enclosure 2

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12

associated with the identification and evaluation of safety-

related CR120 relays that are inaccessible for infrared

thermography surveying.

b.

Observations and Findinos

!

The licensee, as part of its corrective actions, had committed in

l

LER 321/96-15-00 to identify the normally energized,

safety-related CR120 relays that are inaccessible for thermography

surveying and to evaluate these relays for initial and

1

periodic replacement. This LER was closed in inspection

L

report (IR) 50-321, 366/97-02.

!

The inspectors were provided a list that tentatively identified 23

'

safety-related CR120 relays for Unit 1 that were inaccessible for

thermography surveying.

These relays were identified through a

joint effort between Maintenance Engineering, and NSAC personnel.

The licensee plans to replace each of the 23. relay coils on

Unit 1, unless a panel walkdown indicates that thermography

testing can be performed and the thermography results indicate

that the coil does not need replacing.

The evaluation also

indicated that the list of CR120 relays for Unit I had only one

failure after'15 years of service.

The licensee determined that a

'

conservative periodic replacement for the relays would be every 10

t

years.

The normally energized safety-related CR120 relays on Unit 2 are

accessible for thermography and have had thermography temperature

readings performed; The temperature readings obtained. indicate

that the relays.do not require coil replacement at this time.

The procedure, 53PM-MON-003-0S, indicated that the Infrared

.

Thermography Program is scheduled and controlled by Maintenance

Engineering.

The procedure contained all of the applicable CR120

'

relays with their locations listed in an attachment except the

relays located in the control room panels. These relays are

written into an attachment in the procedure as they are surveyed.

Additionally, the panel number, relay number, voltage, relay

temperature, and related comments are documented on the

attachment.

Maintenance Engineering stated that the procedure

will be revised soon to reflect a listing of the relays in the

control room with panel numbers. These relays have been

identified but the procedure has not been updated to reflect.the

additional relay information,

c.

Conclusions

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The Infrared Thermography program has not been fully developed and

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procedurally addressed for the safety-related, normally energized

l

CR120 relays. Adequate cooperation between Maintenance

Enclosure 2

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Engineering and NSAC was demonstrated in the identification of

those CR120 relays that are inaccessible for infrared thermography

. surveys.

M3

Maintenance Procedures and Documentation

M3.1 Surveillance Observations

t

l

1

j.

a,

Insoection Scooe (61701) (61726)

The inspectors observed all or portions of various Unit 1 and

'i

Unit 2 surveillance activities. The majority of the surveillance

activities observed involved the Unit 2 refueling outage and

I

startup.

b.

Observations and Findinat

!

Among the activities observed and the Hatch Surveillance

Procedures (HSP) used were as follows:

e

HSP 34SV-SUV-025-05,

" Core Heat Balance " Rev 8

e

HSP 34SV-R43-004-1S.

" Diesel Generator 1A Semi-Annual

i

Test," Rev. 11-

e

HSP 34SV-SUV-021-05,

"APRM Adjustment to Core Thermal

Power," Rev. 6

e

HSP 42SV-R43-016-25,

" Diesel Generator 2C LOCA/LOSP LSFT."

'

Rev. 5, ED 1

e

HSP 42SV-C11-003-05,

" Control Rod Scram Testing," Rev. 2

e

HSP 34SV-C11-004-2S,

"CRD Timing." Rev. 6

e

RSP 42SV-R43-018-2S,

" Diesel Generator 2A Logic System

Function Test," Rev. 4, ED 1

e

HSP 42SV-C11-003-0S,

"LPRM Operational Status." Rev. 3

e

HSP 57CP-C51-012-0S,

"LPRM Detector I/V Curve,"

e

HSP 42SV-E41-002-2S.

"HPCI LSFT"

The inspectoc retiewed the following completed HSPs:

e

HSP 42SV-R43-008-2S,

" Diesel Generator 2A LOCA/LOSP LSFT."

Rev. 5. ED 1

e

HSP 42SV-R43-012-2S,

" Diesel Generator 18 LOCA/LOSP LSFT,"

Rev, 6. ED 2

'

The inspectors noted that the HSPs for the 1B, 2A and 2C Emergency

Diesel Generator Loss of Coolant Accident (LOCA)/ Loss of Offsite

Power (LOSP)' logic system function tests (LSFT) were temporarily

l

changed. The changes added two attachments to the procedures and

were performed in section 7,4, " Loss of Offsite Power " of each

!

procedure

The changes were reviewed and a) proved in accordance

with the plant procedure change process.

T1e attachments verified

l

that the logic for.the alternate supply breakers on the diesel

l

Enclosure 2

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switchgears functioned as required for a LOSP.

Additional

inspector observations associated with the alternate supply

breaker.are contained in Section E2.2 of this report.

I

The HSPs involving heat balance, average, power range monitors.

scram testing, and local power range monitors were performed with

Shift Technical Advisor (STA) and/or reactor engineering

l

oversight.

The HSPs involving the Unit 2 diesel generators were

l

performed with system engineering oversight.

,

l

l

c.

Conclusions

The HSP activities were generally completed in a thorough and

professional manner.

The procedures were used under the

continuous use requirements with engineering. STA, and supervisory

oversight.

The use and performance of the HSPs were excellent.

M4

Maintenance Staff Knowledge and Performance

M4.1

Unauthorized Maintenance Activities on the Unit 2 Reactor Core

Isolation Coolina (RCIC) System

j

i

a.

Insoection Scooe (92902) (92903)

J

i

On about April 11. the inspectors were informed that unauthorized

maintenance had occurred on valve 2E51-F102, RCIC Exhaust Line

Vacuum Breaker for Unit 2.

Unit 2 was in day 20 of a scheduled

34-day outage. The inspectors reviewed the following documents:

procedures 50AC-MNT-001-0S, " Maintenance Program." Rev. 24 and

10AC-MGR-004-0S, " Deficiency Control System," Rev.10: MW0s 2-97-

4

'

734. Replace Valve Weld on Valve 2E51-F103 and 2-97-891. Repair

Ground-out Seal Weld on Valve 2E51-F102: DCs 97-1666. Grinding

Observed On Weld Of Valve 2E51-F102.and 97-1836. Grinding On Valve

.2E51-F102 Was Repaired Without Proper Authorization; and Drawing

H26023, RCIC System.

The inspectors. discussed the maintenance

activities with licensee management, quality control (QC), and

maintenance personnel.

b.

Observations and Findinas

Valve 2E51-F102 is one of two 18-inch check valves in series

designed to prevent torus water from being drawn into the RCIC

turbine exhaust line after the system has been in operation and

~ subsequently shutdown.

The second valve is 2E51-F103, and is-

located adjacent to the 2ESI-F102 valve.

The RCIC system

requirements are in Technical Specification (TS) section 3.5.3.

!

RCIC System.

The Unit 2 RCIC System is described in Section

i

j

5.5.6, of the Unit 2 FSAR.

The RCIC is not an Engineered Safety

l

Feature System and no credit is taken in the safety analysis for

l

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Enclosure 2

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the RCIC system operation. The licensee treats the RCIC system

j

and components as safety-related.

On about April 3. a QC inspector was assi$ned to perform a liquid

penetrant test (PT) on valve 2E51-F103 fo lowing maintenance to

correct leakage identified during local leak rate testing.

During-

the performance of the PT the OC inspectors observed that grinding

had occurred on the bonnet seal weld area of the adjacent valve,

2E51-F102. The grinding was approximately three inches around the

bonnet-body weld. 'The grinding seemed abnormal-to the inspector

since there were no known work to be performed on the 2E51-F102

valve. The OC inspector also observed that neither valve contained

an identification label.

This was consistent with site procedure

requirements for check' valves. The OC inspector suspected that

someone may have worked on the incorrect valve. The inspector

reported his observations to management and initiated DC 97-1666

to document his observations.

Maintenance personnel began a

review of the circumstances surrounding the grinding work

activities.

A MWO was initiated to repair the grinding on the 2E51-F102 valve.

The work was to be performed per MWO 2-97-891.. On about April 4.

when the welder arrived at valve 2E51-F102 to implement the

l

welding repair, he observed that the work had already been

'

completed. The completed work was reported to management. This

observation was documented on DC 97-1836.

A detailed review of the work activity was initiated by licensee

management.

Their review identified that valve 2E51-F103 was

carbon steel in both the bonnet and valve body. The weld and fill

l

material identified for this valve repair was correct. However,

valve 2E51-F102, that was' re) aired without proper authorization

!

contained a stainless steel )onnet with a carbon steel body. The

unauthorized work was aerformed with the same weld and fill

material used on the 2E51-F103 valve and resulted in an incorrect

. weld repair. Additionally, current drawings did not identify that

valve 2E51-F102 contained a stainless steel bonnet.

A welder was

directed to grind.out the weld material and reweld the valve.

OC

personnel inspected the repair work and concluded that the work

was satisfactory.

The inspectors reviewed procedure 51GM-MNT-029-05. " Repair and

Replacement Welding," Rev. 4, which is used to develop weld

3rocess sheets, and procedure 51GM-MNT-025-0S, " General Welding

Requirements For Pressure Boundary Applications," Rev. 4, ED 1.

which is used for all pressure boundary welding and for some

i

non-pressure boundary welding.

The inspectors observed that

I

step 7.1.2.1 of procedure 51GM-MNT-025-0S, requires, in part, that

l

welding shall be 3erformed using welding material which meet the

[

requirements of t1e Filler Material Specification Procedure and

Enclosure 2

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.4

16

shall be controlled and issued in accordance with the Welding

Filler Material Control Procedure.

In this case, procedures were

not used and incorrect weld filler material was used for valve

2E51-F102.

The inspectors reviewed 3rocedure 50AC-MNT-001-0S, " Maintenance

Program." Rev. 24. and o) served that step 4.2.5 states._in part,

that management.is to ensure that plant maintenance is performed

and controlled within the boundaries of Work Instructions of MW0s

and/or procedures described in the procedure.

In this case, work

was performed on valve 2E51-F102 that was not described in any

work instruction,

,

The inspectors reviewed procedure 10AC-MGR-004-0S, " Deficiency

Control System." Rev.10. and observed that section 4.11 recuired

all personnel to report all problems identified. The procecure

also required that a DC be written for items such as deficiencies

in safety, quality, administrative controls not complied with, and

incorrect Jersonnel actions.

In this case, several deficiencies

occurred tlat were not initially reported or documented.

The inspectors discussed the 3roblem with licensee management.

The inspectors' concern was tlat a craftsman apparently performed-

unauthorized work on the 2E51-F102 valve and failed to report the

error.

Unauthorized repairs were attempted to correct'the problem

without informing or consulting with management and without proper

work review and approval.

Plant procedures.were not followed with

respect to reporting deficiencies, the initial error, and

. maintenance work activities Jerformed that were not approved or

controlled by the normal wor ( control process.

The licensee determined the individual that' performed the

authorized work.

Following several different discussions the

individual admitted he performed work on the incorrect valve and

attempted to correct the mistake. The individual stated he did

not report the error because he did not want to get someone into

-trouble.

Licensee management considered these errors significant and

required a Significant Occurrence review and subsequent report to

senior plant management. As a result of the licensee's

investigation and review, the craftsman involved in the errors was

terminated from employment on April 22.

c.

Conclusions

The inspectors concluded that the immediate cause of the problem

was a failure to follow procedures.

The root cause of the problem

l

was not conclusively determined. The inspectors concluded that

there was very little actual or potential safety significance for

Enclosure 2

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17

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plant operation.

However, the human behavior demonstrated was a

l

serious concern.

The QC inspectors' identification and followup

actions for the unauthorized work was excellent.

Plant management

took timely corrective actions. This licensee-identified

L

violation constitutes a violation of minor safety significance and

'

is being identified as NCV 50-366/97-03-01:

Failure To Follow

Procedure During Welding Process of Unit 2 Reactor Core Isolation

Cooling Valve, consistent with Section IV of the NRC Enforcement

'

Policy.

M4.2 Missed Technical Soecification Surveillance on Unit 2

,

l

a.

Insoection Scoce (61726) (92902)

The inspectors were informed that TS surveillance 3.3.1.2 on

Unit 2 for the Source Range Monitor (SRM) System was not

aerformed

,

within the required frequency.

The inspectors reviewed tie

'

applicable TS requirements and licensee documentation with respect

to the missed surveillance,

b.

Observations and Findinas

i

The inspectors reviewed the applicable TS requirements and

!

observed that TS 3.3.1.2.5 requires a functional test of the SRMs

,

to determine a signal-to-noise ratio once per 7 days.

Licensee

documentation indicated that the surveillance was last completed

on March 28.

On April 5. the SRMs should have been considered

l

inoperable with no control rod movement until the surveillance was

performed.

However, on April 7. operators moved control rods to

remove air from the system.

Withdrawing control rods to remove

l

air is a normal activity during a refueling outage and prior to

'

unit startup.

The inspectors discussed the missed TS surveillance with

operations, maintenance, and outage and planning personnel. The

inspectors reviewed o)erator logs and verified that control rods

were moved and the SRM surveillance had not been performed within

the required frequency.

The inspectors observed that following

the completion of the surveillance on March 28, the computerized

,

surveillance data base was not properly updated by outage and

i

planning personnel.

The next correct due date of the surveillance

L

was April 4 with a late date of April 5.

However, the scheduler

entered a next due date as April 6 with a late date of April 7.

Operations Jersonnel reviewed the surveillance task sheets, which

contained t1e incorrect due and late dates of the surveillance,

considered the surveillance was current and moved control rods.

l

A licensee review of the surveillance status identified the error.

The surveillance was satisfactorily completed within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of

discovery of the error. Immediate corrective actions were

f

Enclosure 2

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18

l

appropriate.

The licensee determined that the cause of the

l

problem was a data entry error on the part of the surveillance

scheduler.

The inspectors also determined that the cause was

personnel error of data entry.

The inspectors reviewed licensee performance for the last two

years and determined that no surveillance was missed due to a

similar personnel error and no previous corrective action would

have reasonably prevented this error.

This licensee-identified and corrected violation constitutes a

violation of minor safety significance and is identified as

NCV 50-366/97-03-02:

Data Entry Error Results in Missed Technical

Specification Surveillance on Unit 2. consistent with Section IV

of the NRC Enforcement Policy.

c.

Conclusions

The movement of Unit 2 control rods with the Source Range

Monitoring System surveillance not performed within the required

frequency was a violation of Unit 2 Technical Specifications and

was identified as NCV 50-366/97-03-02:

Data Entry Error Results

in Missed Technical Specification Surveillance on Unit 2.

Personnel error for data entry to the surveillance schedule task

sheet was determined to be the root cause.

Licensee immediate

corrective actions were appropriate.

M8

Miscellaneous Maintenance Issues (92700) (92902) (90712)

M8.1

(Closed) Violation 50-321/96-06-03:

Failure to Follow Procedure

During Safety-Related Va ive Maintenance.

The licensee responded

to this violation in correspondence dated July 10, 1996.

The

inspectors reviewed the response and observed that among the

corrective steps were the following:

e

the involved licensee personnel and the contractor supervision

personnel were counseled regarding the failure to obtain

Authorized Nuclear Inservice Inspector and Quality Control

Specialist reviews and signatures prior to valve maintenance

activities:

e

a program was established to review Maintenance Work Order

packages assigned to contract personnel and requires a specific

review prior to valve reassembly.

The ins)ectors discussed the program with licensee personnel and

noted tlat similar deficiencies were not identified during the

recent spring 1997 Unit 2 refueling outage.

Based on the

l

inspectors review of licensee actions and licensee performance.

l

this violation is closed.

!

l

Enclosure 2

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

,

i

,

I

4

.

L

19.

M8.2

(Closed) Violation 50-321. 366/96-13-03:

Failure to Follow

Procedure - Multiple Examples.

Maintenance ]ersonnel failed to label one-gallon containers as

required by iatch General Maintenance Procedure 51GM-MNT-017-OS,

" Control of. Lubricants," Rev.1.

'

The licensee's response dated December 19, 1996, indicated that-

l

the importance of using lubricants from properly labeled

i

containers was stressed to maintenance teams during team meetings.

,

The inspectors conducted a spot check of mechanics to ascertain

1

K

their knowledge of procedural requirements regarding container

labeling.

Maintenance mechanics questioned by the inspectors-

demonstrated knowledge of labeling procedural requirements.

Personnel questioned also indicated that the importance of correct

l

labeling is addressed during pre-job briefs, Based upon the

l

inspectors * review of licensee actions, this violation example is

closed.

l

M8.3 Closed) LER 50-366/1997-006:

Data Entry Error Results in Missed

Technical Specifications Surveillance on Source Range Monitors.

This event is discussed in section M4.2 of-this report. No new

1

information was revealed by the LER. This LER is closed.

j

III. Enaineerina

El

Conduct of Engineering

On-site engineering activities were reviewed to determine their

effectiveness in preventing, identifying, and resolving safety

l

issues, events, and problems.

E1.1

Failure ~To Commercially Dedicate a Unit 1 TIP Nitroaen Purae

Solenoid Valve

a.

Insoection Scoce (37551)

The licensee discovered during a maintenance history review that

.

the Traversing Incore Probe (TIP) nitrogen solenoid valve

'

1C51-F3012 was being used in a safety-related application without

having been commercially dedicated.

The inspectors' review of the documents associated with this issue

included the following:

e

Hatch Administrative Control Procedure (HACP) 20AC-MTL-003-05.

" Commercial Grade Dedication," Revision.(Rev.) 4

o

HACP 40AC-ENG-012-05, " System Evaluation Document Management,"

Rev. 1

(

(.

Enclosure 2

.

m

- -

4-

-i---

-,e-

. .

,,----4-

.a

q

e

w

.r7---g-

+- i

.-w

- - - - -

y

g-p

y,r

'

'

i

!. . '

.

l.

I

20

e

Edwin I. Hatch Nuclear Plant Unit 1 Neutron Monitoring System.

P&ID Drawing H-16561. Sheet 2 of 2

,

'

e

Edwin I. Hatch Nuclear Plant System Evaluation Document.

Volume 3. Units 1 and 2 Safety Component List

i

e

Edwin I. Hatch Nuclear Plant Equipment Locator Index (ELI) -

Unit 1. and

l

e

Georgia Power Purchase Order (PO) 6012036

b.

Observations and Findinas-

,

'

During a maintenance history review on April 2. the licensee

l

discovered that TIP solenoid valve 1C51-F3012 had been used in a

-

safety-related application without having been commercially

dedicated.

The valve was declared inoperable and operations

personnel entered the ap]licable section of the required action

statements (RAS) for Tecinical Specification (TS) 3.6.1.3. Primary

,

Containment Isolation Valves and TS 3.3.6.1. Primary _ Containment

'

Isolation Instrumentation.

Nuclear Safety and Compliance (NSAC) personnel conducted an

i

operability evaluation of the valves. During their review they

determined that the solenoid for the current Unit 1 valve was

!

instaTled in February of 1993 and had not been commercially

dedicated.

i

,

Two augmented quality (AQ) replacement sok:noid valves were

procured in March 1993.

These replaceme.it valves were

commercially dedicated in accordance wich procedure

20AC-MTL-003-0S in March 1997.

One of the commercially dedicated

!

L

valves was used to replace valve 2C51-F3012 on Unit 2 during

Refueling Outage 13.

The other valve was scheduled to be used to

replace 1C51-F3012 during the 1997 Unit 1 Fall Outage.

The valves are listed as safety-related and are identified as

containment isolation valves in the Unit 1 and Unit 2 TSs and

Final Safety Analysis Report (FSAR).

The inspectors were informed

that a request for engineering assistance was written to

l

investigate the possibility of reclassifying the valves from

l

safety- to non-safety related.

This request is based upon

l

conformance criteria stated in Regulatory Guide 1.11 for

,

instrument lines.

]

The current Unit 1 non-commercially dedicated valve was determined

by NSAC to be of the same type and part number as the replacement

valves procured in March 1993.

NSAC considers this valve to be

ecual to the two valves that were commercially dedicated in March.

Acditionally, the valve was tested in accordance with both the

'

l

Inservice Test (IST) and the Appendix J Leak Rate Test Programs.

The NSAC's operability evaluation concluded that the valve should

4

i

'

Enclosure 2

- - .

.

.

.

.

.

.

.

-

-

_ _ . _ - .

._ _

-_

_

_ . . -

_ _ _ _ _ _ _ _

___.

9

.

.

21

be considered operable as long as the surveillance requirements

for operability are met.

l

Operations terminated TS-required actions based upon the NSAC

operability evaluation.

l

The ins)ectors reviewed the ELI and noted that valve 1C51-F3012

was marced as a "0" component.

Procedure 20AC-MTL-uuo-va, sect. ion

L

6.2.2 states, in part that components marked "0" in the ELI shall

be procured safety-related or dedicated as a basic component.

Section 8.1.1 of the procedure further states, in part, that a

commercial grade item will not be considered a safety-related

component until it has been documented as having been dedicated.

'

c.

. Conclusions

This licensee-identified violation constitutes a violation of

)

minor safety significance and is identified as NCV

50-321/97-03-03, Failure to Commercially Dedicate Isolation Valve,

consistent with Section IV of the NRC Enforcement Policy.

The licensee's actions that resulted in the identification of a

non-safety related valve being used in a safety-related

application were excellent.

The reviews and evaluations performed-

u)on discovery of the use of the non-dedicated components were

t1orough and timely.

E1.2 Field Wirina Inconsistencies with Drawina for 4160 Volt

Alternatina Current (VAC) Bus 2F

a.

Insoection Scooe (37551)

The inspectors conducted a review of inconsistencies between "as-

found" field wiring and the wiring diagram-(H23522) for the 4160

VAC bus 2F switchgear.

Maintenance Work-Order (MWO) 2-97-1129:

Install Terminal Block, and Inspection and Test Procedure

. 521T-R22-001-2S

" Time testing of 4160 Supply ACBs." Rev. 0 were

reviewed. The inspectors also held discussions with engineering

and management personnel familiar with the inconsistencies,

b.

Observations and Findinas

The licensee discovered on April 16, while performing procedure

521T-R22-001-2S, that vertical terminal block 6T on 4160 VAC

switchgear 2F did not exist. The test procedure was a validation-

procedure that had not been previously performed.

The procedure

required the opening of link number 1 on the terminal block to

prevent associated relays from changing states when the normal

supply breaker is opened or closed during timing test.

Wires that

should have terminated on terminal block 6T at links 1 and 2.

Enclosure 2

-

.

_.

..

.

.-

.-

_ _ _ . _ _ _ . . _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ . _ . _ .

-

t

..

!"

i.

I

'

22

which did not exist _3er drawing H23522, were found on terminal

block 2T at link num)ers 5 and 6.

It was also discovered that the

,

l

wiring that landed on terminal block ST terminated on points 1

and 2 instead of points 9 and 10 as indicated by the drawing.

i

The licensee initiated MWO 2-97-1129 and As Built Notice (ABN) 97-

,

109 to correct the wiring inconsistencies. The inspectors

reviewed the MWO and ABN.

This review indicated that the terminal

block was installed and the wiring terminations were changed to

meet the drawing and the ABN corrections.

i

The inspectors reviewed procedure 52IT-R22-001-2S. This review

revealed that normal and alternate breaker time testing is

required also for the 2E and 2G 4160 VAC safety-related busses.

The frequency of the testing is determined by system engineering

i

personnel.

'

During a discussion with engineering personnel. the inspectors

were provided a preliminary safety assessment from the

Architect / Engineer (AE) that evaluated the above wiring

l

inconsistency.

The safety assessment indicated that the

'

inconsistent wiring configuration did not adhere to the separation

criteria for divisional separation. An annunciator circuit

associated with division I and a division I circuit were

. terminated on the same terminal block as an emergency diesel

generator 1B circuit.

The distance separating these circuits was

less than the six inches specified as the minimum separation

criteria. All of the circuits involved are-low voltage control

'

circuits and are fused or protected by a circuit breaker. The

preliminary safety assessment concluded, based upon an analysis of

the circuits involved, that there ap) eared to be no events that

would have occurred as a result of t1e non-adherence to the-

separation criteria that would be more severe than the loss of the

4160 VAC current Switchgear Bus 2F.

The loss of a single division

of 4160 VAC switchgear has been analyzed. The analysis determined

that the unit can safely be shut down with the loss of a division

of the 4160 switchgear. The inspectors documented other recent

configuration control problems in Inspection Report 50-321.

366/96-14.

As a result of the above wiring-to-drawing inconsistency and the

discovery of the divisional separation problems, the licensee

performed a walkdown of several panels in the emergency diesel

generator building.

Two Division I and two Division II circuits

were found that did not adhere to the divisional separation

criteria.

These four divisional circuits were on Unit 2.

Five

Unit 1 circuits were found during the Unit I walkdown.

l

At the end of the inspection report period, a roving fire watch

had been established until resolution of this issue has been

Enclosure 2

l

-

-

...-

_.

. .

. _

. _

_

_ _ . _ _ _ _ - . _

___

_ _ _

_ _ _ . _ _ _

1

.

23

-com)1eted.

Licensee personnel were still investigating the

pro)lem and had not conclusively determined when the-

inconsistencies occurred or the significance of the problem.

,

!

However, the licensee indicated that the problem was not a concern

l:

for safe shutdown of the units, but rather a fire protection

'

issue. due to inadecuate separation.

Engineering personnel

'

i

suspected that the civisional separation deficiencies occurred

'

during the construction phase of the plant.

1

t

c.

Conclusions

L

Engineering's timely followup action upon the discovery of the

'

l

initial wiring-to-drawing inconsistency in the 2F 4160 volt

l-

switchgear resulted in prompt corrective actions by maintenance.

l

The inspectors will review the licensee's operability and

engineering assessment and corrective actions when they are

available.

This item is identified as Inspector Followup Item

(IFI) 50-321, 366/97-03-05. Review of 4160 VAC Wiring Separation

Deficiencies.

l

E2

Engineering Support of Facilities and Equipment

l

l

E2.1

Post Modification Testina Observations

!

[

a.

Insoection Scooe (37700) (37828)

.

The inspectors reviewed and observed )ost-modification testing of

the power range neutron monitoring (PRNM) system, including the

oscillating power range monitor (0PRM) portion, and the reactor

i

feed pump turbine (RFPT) upgraded control system,

b.

Observations and Findinas

The inspectors reviewed and observed portions of test results,

ongoing testing activities, and the operational performance of

o

i

modified systems. The modifications installed on the systems were

as follows:

1

e

Design Change Request (DCR)94-008. PRNM system which provides

j

l

a two-out-of-four scram from any of the four average power

l

range monitor (APRM) channels if reactor power exceeds

'

'

established setpoint values and also provides the same logic

"

for the future oscillating power for the instability scram.

e

DCR 95-054. RFPT upgraded control system which installed fault

'

tolerant, redundant and validity check features in order to

,

i

make the system more reliable.

.

{

Enclosure 2

.

i

l

.

-

,.

_.

--

-

,

_ . .

_

\\

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

.

. .,

'

.

.

..

,

.

24

Three special purpose procedures (SPP) were issued, two for DCR

94-008 and one for DCR 95-054, as follows, respectively:

,

l

l

e

17SP-121696-0P-1-2S. " Unit 2 PRNM System Functional Test for

l

DCR 94-008," Rev. O

e

42SP-040897-0F-1-0S, "0PRM testing and Tuning," Rev. O

e

17SP-032697-PH-1-2S. "DCR 95-054 Dynamic FT of the Feed Water

Control." Rev. O

The test for the PRNM consisted.. in part, of verifying that the

.

indicated power of the 4 channels tracked along with the actual

I

power was able to be adjusted by use of a computer downloading

process, and that the various individual components of the system,

such as the rod block monitor, the 2-out-of-4 logic modules, the

.

rod worth minimizer interface, and the annunciators functioned

l'

properly.

The test for the OPRM consisted, in part, of verifying

!

during power operations the oscillation sensitivity at various

l

power levels and core flows. The test for the feedwater control

l

included, in part, testing the system responses to water level

,

step changes, swap from median level signals to manual level

'

l

signals, swap from three element to single element control, and

l

failed steam flow and feed flow signals. The feedwater control

l

test was performed at three thermal power plateaus:

30%, 50%, and

95% RTP.

ril 22, while performing section 7.4.38. " Simulate Steam

On Ap/ Feed Water Flow Failure," of procedure 17SP-032697-PH-1-2S,

Flow

an unplanned reactor recirculation pump runback occurred. The

reactor entered the " Operation Not Allowed Region" of the

power-to-flow map. The region was immediately exited using control

rods and increased recirculation flow. Additional discussions of

this transient are included in section 01.1.of this inspection

l

report. The ins)ectors reviewed the functional test (FT)

'

procedure, had o) served portions of the test performance,

discussed the occurrence with operations personnel, and discussed

the technical aspects of the test with the involved test

engineers.

l

l

The inspectors found from the review, observations and discussions

with licensee personnel that:

l

the square root converter output for the two feed water flow

l

e

l

channels was changed by onsite personnel at operations'

'

recuest. The change was for the square root converters to

incicate zero flow when the output of each converter is at one

i

volt and, by design, each converter feeds into a flow

totalizer:

.

Enclosure 2

.-

_

- - .

.

-,

.

-

- _ _ -

.

._

_.

.

,

i

'

.

l.-

!.

l'

)

(

25

subsection 7. 4.38.2 of the dynamic FT 3rocedure required that

e

the input from the B flow transmitter Je.open-circuited..

resulting in the flow totalizer receiving a zero volt signal

i

from the B channel:

l

e

the zero volt signal was received, by the totalizer, as a

.i

negative (reverse) feed water flow signal.and the totalizer

subtracted more than 50% from the total flow signal input to

the system: and

.

e

the test- engineers were not aware of the effect of the' change

,

!

and did not foresee any; required test'3rocedure change.

l

Consequently, an unplanned reactor run)ack occurred due to a

l

low total feed water flow signal.

The inspectors reviewed plant procedures associated with

!

modification activities and noted the following:

e

Administrative Control Procedure (ACP) 40AC-ENG-003-0S, " Design

,

Control." Rev

8. Section 8.2.2. requires, in part, that design

packages be installed in accordance with the maintenance

program and that procedural requirements for maintenance

'

activities, such as functional tests, shall apply to the design

implementation.

..

e - Modification.Sup) ort Procedure (MSP) 17HS-MMS-002-0S. " Design .

Change Request ()CR) Processing." Rev. 1. Section 7.4.3.

requires, in part, that when developing post-modification

tests, consideration be given to the need to demonstrate proper

functioning of modified equipment and that functional tests

that are rot described by existing plant procedures shall be

performed by a.special purpose procedure.

.e-

Special Purpose Procedure (SPP) 17SP-032697-PH-1-2S was issued

to functionally test the feedwater control system upgrade

modi fication.

!

'

The inspectors discussed the results of the procedure reviews with

licensee personnel. The inspectors observed the SPP was changed

to have operators lock the recirculation pump system scoop tube to

prevent future similar runbacks.

c.

Conclusions

The inspectors concluded that the failure to adequately implement

ACP 40AC-ENG-003-05 and MSP 17MS-MMS-002-0S was a violation when

SSP 17SP-032697-PH-1-2S was not changed to reflect the system

'

circuit change.

This was identified as an example of Violation

50-366/97-03-04:

Inadequate Procedures for Testing Activities -

Multiple Examples.

Enclosure 2

.

_

.

_

-

..

~ ,

.

_

_

._ _

.

.

.

26

E2.2 Emeraency Diesel Generator (EDG) Loaic System Testina Per Generic

Letter (GL) ff-01

a.

Insoection ScoDe (92903)

The inspectors documented in IR 50-321, 366/97-01. that a review

of the EDG logic system disclosed an item affected by GL 96-01,

" Testing of Safety-Related Logic Circuits." The ins)ectors

reviewed HSPs 42SV-R43-018-2S " Diesel Generator 2A _ogic System

Function Test." Rev. 4. ED 1: 42SV-R43-008-2S. " Diesel Generator

2A LOCA/LOSP LSFT." Rev. 5. ED 1: 42SV-R43-012-2S. " Diesel

Generator 1B LOCA/LOSI LSFT." Rev. 6. ED 2: and observed licensee

actions to test the corrected problems.

b.

Observation and Findinqq

The review of the EDG logic system disclosed that the logic for

the alternate supply breakers for the EDG 4160 VAC switchgears was

not being tested.

Engineering 3ersonnel processed temporary

changes to the 18, 2A. and 2C E)G loss of coolant accident / loss of

offsite power (LOCA/LOSP) logic system functional test (LSFT)

surveillance procedures.

The changes to each procedure consisted

of attachment numbers 3 and 4.

The attachments verified that the

applicable relay contact involving the alternate supply breaker

opened and closed as required.

Inspector observations of the

performance of the LOCA/LOSP surveillance procedures are

documented in section M3.1 of this report.

c.

Conclusions

The inspectors concluded that engineering personnel adequately

addressed the GL 96-01 issue involving the Unit 2 EDG 4160 VAC

switchgear alternate supply breakers.

Test results met the

applicable test acceptance criteria.

j

E2.3 Review and Observation of Imolemented Desian Chanaes (Unit 2)

a

Insoection Scooe (37700) (37828)

'

The inspectors reviewed and' observed the operation of systems

affected by modifications.

Among the systems were Main Steam.

HPCI. temperature monitoring. Reactor Core Isolation Cooling

(RCIC). Condensate, and EDG 600 volt distribution.

Speci fic

Jost-modification testing observations of the PRNM and the

eedwater (FW) upgraded control system are discussed in Section

r

E2.1 of this report.

l

Enclosure 2

.

,

~

.

'

.

.

/.

.

27

5.

Observations and Findinas

The inspectors reviewed selected implemented DCRs and minor design

. changes (MDCs). The ins)ectors observed the operation of the

systems impacted by the

)CRs and MDCs.

The reviews and

observations.were made during plant startup, power ascension, and

3-

j

operation at RTP.

-

Among the DCRs and MDCs reviewed and.the systems observed were the

-following:

DCR/MDC Descriotion

92-042

Replaced 22 obsolete anak

1perature modules with new

digital modules. The modt

monitor temperatures of the

feedpumps, condensate pumps and booster pumps,92-134

Instelled new electrical starters in the power supplies to

the drywell coolers.93-048

Replaced the condensate demineralizer system backwash with

controls with electronic controls, placed the pneumatic

an air surge backwash system and re

95-033

Changed control room fus s breakers in switchgears, and

installed current limiting fuses in switchgears, such as

selected breakers in the Unit 2 600V AC switchgearu.96-006

Generic Letter 89-10 modifications to 14 valves such as

the following:

2B21-F021, 3-inch main steam line drains

restric"ng orifice bypass and 2E41-F007,14-inch HPCI

pump discharge, changed stroke times from 19 to'35

seconds: 2E11-F119A 18-inch residual-heat removal service

water crosstie valve, changed stroke time from 46 to 91

seconds; and the thermal overloads .in two RCIC system

valves were bypassed.96-018

Reaoved a single. failure problem (a common power supply in

the feedwater control system failed causing both feed

wa,.er pumps to trip _on Unit 1). This resulted in a

reactor scram.

94-5044 Removed the low hotwell water level trip wiring and

annunci3 tors for the condensate pumps;

96-0532 Removed check valves in the cooling water supply to the

service water pump motors.

i-

96-5044 Removed the relief valves on the suction piping of the

residual heat removal-and core spray pumps

Enc'ioe"re 2

.-

-

.

- .

.

-

-

.

.

.

-

_ . _ _ _ _ _ . _ . _ _ _ .

_ _ . _ . . .

.

- _ - -

l.

.

'

.

28

97-5004 removed snubbers from the main steam and HPCI systems,

and

97-5005

.The inspectors reviewed the training presented to the operators

prior to Unit 2 returning to full power operation. The inspectors

noted that operations personnel demonstrated an understanding of

the various modifications.

c.

Conclusions

The inspectors concluded from the reviews and observations of the.

operation of the systerrs that the overall post-modification tests

>

-of the systems'were adequate, with the exceptions noted in section

E2.1 and E3.1 of this report.

The inspectors concluded that the

modification training was adequate.

.

E2.4 Review of Fire-Rated Sealed Penetration Proaram

a.

Insoection Scoce'(37551) (71750)

The inspectors reviewed procedures, drawings and other documents

related to fire-rated sealed penetrations aild conducted field

4

walkdowns of selected sealed penetrations.

Interviews were

conducted with Fire Protection Engineering, Plant Modification and

l

Maintenance Support (PMMS) En?'omring, PMMS Supervision and

Quality Control (OC) Inspectors.

The documents reviewed included the following:

/

e

Hatch Fire Hazard Analysis (FHA) and Fire Protection Program

o

Hatch Administrative Control Procedure (HACP) 40AC-ENG-008-0S,

" Fire Protection Progrcm," Rev. 8

i

e

Hatch Fire Protection Procedure (HFPP) 42FP-FPX-003-td,-

"Insallation of Nelson Electric Fire Stops," Rev. 3

HFPP 42FP-FPX-014-0S, " Installation and Repair of Silicone Foam

e

Seals," Rev. 1

4

e

Hatch Surveillance Procedure (HSP) 42SV-FPX-018-1/2S, " Fire

Barrier 18-Month Surveillance," Rev. 2

6

HSP 42SV FPX-019-1/2S, " Penetration Seal Surveillance " Rev. 2'

o

Hatch Departmental Instruction (HDI) DI-MMS-01-0292N, "PR MS

,

j

Employee Orientation and Procedure Awareness Program," Rev. 6

E

l

i

l

Enclosure 2

'

.-

- . . -

.- --

.

.

- .

.

..

<

.

s

'

i

?

1.

29

.

b.

Observations and Findinas

,

The procedures review provided instructions and the acceptance

criteria for the installation, repair, and surveillance of the

following types of fire-rated sealed penetrations: Nelsori

Compound. Nelson Caulk. Nelson Putty Nelson Pillow, and silicon

foam.

OC personnel or engineering personnel are responsible for

i

performing surveillance procedures.

The inspectors observed that

QC personnel had performed the most recent surveillance

procedures. OC personnel are also responsible for inspecting the

installation / repair of fire-rated sealed penetrations to verify

procedural compliance.

Fire Protection Engineering is responsible

for.providing procedural familiarization training to personnel

)

that install or repair fire-rated sealed penetrations. The

installation and repairs are performed primarily by contractor

i

personnel with the assistance of maintenance personnel, as needed.

Surveillance )rocedures 42SV-FPX-019-1/2S require that a 10%

sample of eac1 type of sealed aer.etration be visually inspected at

least once every 18 months.

T1e samples shall be selected such

that each penetration seal is inspected at least once every 15

years.

The inspectors interviewed the fire )rotection engineer to

determine the status of the program 3ased upon the surveillance

frequency. The fire )rotection engineer provided documentation

that indicated that tie sixth 18-month surveillance cycle out of a

total of ten cycles was completed on April 19, 1997. The 15-year

cycle started in October 1987 and ends September 2003.

The.

procedure requires that each penetration seal be inspected at

least once by the end of cycle 10.

The fire protection engineer

sis +.ed that of the approximately 4105 original fire-rated sealed

pentrations to be inspected, a total of 1924 remained to be

inspected.

The inspectors reviewed the data packages for the cycle 6

surveillances.

This review indicated that a total of 393

fire-rated penetrations were inspected. 213 on Unit 1 and 180 on

Unit 2.

A total of three oenetrations did not meet the

surveillance acceptance cr'iteria on Unit I and four on Unit 2.

Deficiency Cards (DCs) were written for the rejected penetrations.

The rejected penetrations were reviewed by fire 3rotection

engineering for an operability determination.

T1e review did not

identify any operability concern.

The inspectors observed an

administrative oversight in the data packages.

The cover page for

Unit 1 was on the Unit 2's data package and vice versa.

OC and

fire protection engineering personnel were informed of the

deficiency.

Enclosure 2

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F

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30

'

The inspectors reviewed 10 DCs 'four DCs for Unit 1 and six DCs

(

for Unit 2) that were written by OC inspectors for damaged or

degraded seal penetrations identified during the performance of

!

the surveillance but were not being inspected as part of the

!

surveillance. The MWO data package associated with eight of these

DCs were reviewed.

The data package-indicated that the repairs

,

for the deficiencies identified in these eight DCs were accepted

l

by QC. Some of the MW0s reviewed are listed in section M1.1 of

I

this report. The MWO numbers for deficiencies C09702132 and

C09702061 had been assigned but had not been scheduled for work.

l

The deficiencies identified in these.two DCs were related to

damaged and degraded penetrations located in main control room

!

panels. A review of the these control room Janel deficiencies by

i

fire 3rotection engineering indicated that t1ere was no FHA

!

opera >ility concern.

)

l

The inspectors visually ins)ected the surface of the sealant in

the floor of a sampling of Jack panels located in the main control

i

room.

Most of these back panels were identified in DCs C09702132

and C09702061. The inspectors observed that some of the foam

'

sealant in the cabinets had surface cracks and nicks.

The nicks

appeared to have been caused by a fish tape or some other ty)e of-

I

probing device. The inspectors observed that the depth of t1e

larger nicks appeared to be shallow.

Panel 1H11-P6080 had a

'

crevice in the sealant that was approximately 3 inches deep and 4

)

inches in diameter.

The inspectors did not view this as an

J

,

operability concern. The inspectors observed several wires in the

'

various panels that were cut and had the ends taped.

The

inspectors did not observe any cut wiring that did not have the

ends taped.

Some of the panels had congested wiring laying on the

floor. The condition of the sealant in the panels with wiring on

the floor could not be observed by the inspectors.

The inspectors discussed the cbserved deficiencies in the main

l

control room back panels with fire protection engineering.

Fire

l

protection engo. . ring stated that the deficiencies were of a

'

material cond h. a and did not pose an operability concern.

It

was also stated by fire )rotection engineering that the nicks that

appeared to be made by t1e fish tape would soon be repaired in

l

accordance with procedure 42FP-FPX-014-0S. Since. the silicon

,

l

foam is an elastomer material and expands upon heating, fire

L

protection engineering stated that any opening made by a fish tape

would reseal.itself in the expansion process during a fire. The

!

crevice in panel 1H11-P608D would be similarly repaired according

i

'

to fire protection engineering. The inspectors asked fire

,

'

protection engineering if documentation existed for the

0)erability determination in determining that the deficiencies in

>

4 -

t1e control room panels were of a material condition and were not

'

dn operability concern.

The inspectors were informed that for

these deficiencies a review was performed and results were

,

Enclosure 2

l

,

'

. .

. .

.,.

. . _

.

-.

-

i

.

-.

-

- . . - . .

.

-. .--

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.

.

31

l

documented on the DC. There was no other documentation that

l

addressed the operability review.

!

l

MWO data package 2-97-0033 was reviewed by the inspectors.

This

data package had some rejected penetrations because of congested

wiring or cabling in some of the control room back panels.

The

ins)ectors r* viewed the rejection forms that were in the data

pac cage.

These forms are required by Procedure 42FP-FPX-014-0S

when wiring separation criteria in the penetration was not met.

The engineering resolution for these penetrations were. in

general, to separate the new and existing cables to allow the new

silicon foam material to flow between cables below the surface of

the existing fire barrier material. This work was completed and

was approved by OC personnel.

The inspectors examined the inside of control room panels wherein

some recent cable pulls had been completed. The inspectors

observed the silicon foam sealant in the floor of main control

room panels 2H11-P608A, B. C, D, and E.

These panels contained

components associated with the Power Range Neutron Monitoring

(PRNM) system that was installed during the 1997 Unit 2 refueling

j

outage. The ins

the ends taped. pectors observed several wires that were cut and

The wiring was arranged in an orderly and neat

manner. The inspectors did not visually observe any deficiencies

1

in the foam sealant located in the flooring of the panels.

'

The inspectors also reviewed the MWO data package (MWO 2-96-3005)

for the cable pull work activities associated with the design

change request /DCR 94-008) for installing the PRNM. The fire

protection checklist indicated that the applicable fire action

statements (FAS) of the Fire Hazard Analysis. Appendix B. were

'

entered.

The data packages also indicated that completed sealed

penetration work activities were accepted by OC.

The inspectors reviewed the FAS log in the Unit 1 and Unit 2 main

control rooms for approximately the past six months.

Unit 1 did

not have any open FASs that specifically identified any

i

penetration problems.

Unit 2 had one open FAS that identified a

penetration located in the reactor protection system motor

generator room cable way and the 112-foot elevation of the control

building. An hourly fire watch was performed as a compensatory

measure.

The inspectors reviewed the procedure for the installation and

repair of silicon foam and an MWO data package wherein silicon

foam was used. The inspectors compared the silicon foam procedure

with the vendor's instructions 3rovided by fire protection

,

engineering and observed that t1e instructions in the procedure

l

were consistent with those of the vendor.

The MW0 data package

l

reviewed referenced procedure 42FP-FPX-014-0S as the guidance for

i

!

Enclosure 2

.

. .

-.

4

_

.

_ _ _

_

.

_ . _ _

,

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32

!

the repair.

The vendor's manual was referenced in the

installation and repair procedure.

However, the vendor's manual

was not referenced for use in performing the actual installation

l

or repair. The inspectors observed that skill of the craft was

l

used for seal material removal when seals were repaired.

The

'

procedure included guidance for the amount of material to be

removed prior to applying the penetration repair seal kit

material.

The inspectors observed that work packages did not

always contain routing diagrams.

In general, the inspectors

considered the procedural instructions and work package material

adequate.

'

Licensee personnel queried about management's support of the fire

protection program had mixed reactions.

Some were of the opinion

that management's support of the program was adequate and much

better than what it was in the past.

Others felt that management

only provided adequate support to the program when operations and

'

personnel resources for fire watches were impacted.

The inspectors noted that managers discussed fire protection

l

issues during the Managers' morning meeting on April 18.

Maintenance management expressed a concern about the number of

MW0s that were outstanding for penetration repairs.

Engineering

management informed the inspectors later that day that the problem

was not as significant as it may have sounded during the Managers'

meeting.

Engineering management stated that some of the problems

l

were cosmetic in nature and did not present an operability

concern.

It was further stated by engineering management that the

seal penetration issues would be reviewed and corrected. The

inspectors observed that DCs and MW0s had been completed for the

l

deficiencies and most of the work had been completed.

A review of HSP 42SV-FPX-019-1/2S indicated that personnel

performing the 3rocedure are required to have an annual eye

examination. T1e inspectors verified through a review of Quality

l

Control records that eye examinations were current for personnel

l

involved in performing the cycle 6 sealed penetration surveillance

procedure.

i

!

The inspectors compiled a list of the names of craft persons that

i

installed or repaired sealed penetration in accordance with

i

applicable procedures. The names were obtained from MWO data

'

packages associated with sealed penetration repairs or

installation.

The training and procedural familiarization for

,

some of the personnel were verified through reproduced copies of

i

the specialized training attendance sheets maintained by a PMMS

,

supervisor. These attendance sheets were dated September 1992 and

only listed the names of cont a ctor personnel. The inspectors

were unable to verify the attendance for one contract general

Enclosure 2

1

1F

,

.

. . -

- _ - . ~ .

--

-

.

.- . . _ .

-

.

. - . - -

'

.

.

l

l

33

foremen whose name was obtained from the data Jackage as the

l

technician performing the seal penetration wort activity.

Fire protection engineering conducts the procedural

familiarization training for craft personnel )erforming fire seal

penetration work activities.

Discussions wit 1 fire protection

,

engineering indicated that the procedural familiarization training

!

consisted of a review of the applicable procedure with the craft

person that will' repair or install the seals.

This

review is about one hour in duration per procedure. procedural

L

It was also

stated that'there is no " hands on" training and no refresher

procedure familiarization training.

The inspectors reviewed Departmental Instruction DI-MMS-01-0292N.

This instruction provided guidelines for three categories of PMMS

,

!

training:

Administrative Orientation Training (A0T): Department

Instruction Training (DIT): and Just-in-Time (JIT) training.

Procedures 42FP-FPX-003-0S and 42FP-FPX-014-0S were included in

the procedures listed for JIT.

Discussions with PMMS supervision

indicated that a centralized data base existed for A0T and DIT but

one did not' exist for JIT.

PMMS supervision stated that a

consideration would be given to having JIT placed into -

!

centralized data base or have it tracked under the DIi program.

The inspectors discussed with maintenance supervision the

>

'

necessity for specialized training on procedures 42FP-FPX-003-0S

and 42FP-FPX-014-0S for maintenance craft persons.

Maintenance

supervision stated that contractors primarily performed the repair

and installation of fire penetration seals, and maintenance

l -

personnel usually assisted.

However, maintenance supervision

stated that a re-evaluation of the specialized training

,

I

requirements was being considered due to the cut backs in the use

,

of contractor personnel.

]

L

The inspectors performed a walkdown of-selected penetrations on

!

the 130-foot elevation in the vicinity of the 1E electrical

switchgear of Units 1 and 2.

Included in the walkdown were

penetrations 2Z43-H0320, 2Z43-H030D. and 1Z43-H646D. These

penetrations are addressed in Appendix I of the FHA. Appendix I

addresses, by an exception report, the acceptability of unrated

l

l

pr ~.trations in a fire area boundary.

In many instances, the

e seption reports contain penetrations that coula not be verified

oue to obstructions or inaccessibility. The exception report

evaluations assumed each penetration was unsealed.

c.

Conclusions

i '

The licensee's current program for determining the operability of

sealed penetrations was adequate. Management was aware of the

,

}

issues associated with the sealed penetrations and the fire

Enclosure 2

.

9

i

.

.

, _ _ - _

.

-

-

1

.

-- ..

-. - -.

- - . - . - - - - . - . - - . -

. - . .

t

.

.

.

34

!

protection program and provided satisfactory support. A weakness

was identified for specialized training docunentation provided to

craft persons who install and repair sealed penetrations.

OC

l

personnel's annual. eye examinations review met the requirements.

The inspectors did not-identify any deficiencies with the

'

penetrations that were inspected.

.

.

E3

Engineering Procedures and Documentation

'

E3.1 Momentary Loss of Vital Alternatina Current (AC)

l

a.

Insoection Scoce (37551) (71707)

A momentary loss of vital AC on April 13 generated an isolation

signal for Fission Product Monitor Sample Isolation Valve.

2011-F050. The inspectors reviewed HSP 42SV-R43-008-2S, " Diesel

Generator 2A LOCA/LOSP LSFT," Rev. 5. ED 1: Shift Technical

Advisor (STA) Report 97-03, " Momentary Loss of Vital AC Results'in

ESF," Plant Hatch - Unit 2 Master Single Line Diagram H23350: and

Plant Hatch - Unit 2 Single Line Diagram H233652, 600V Bus 2C

.

and 2D. The inspectors also performed a limited walkdown of the

Vital AC rectifier / invertor

Station Service Switchgear. panel and the 2C and 2D 600 Volts

Additionally, discussions were held

with licensee personnel.

b.

Observations and Findinas

During the performance of procedure 42SV-R43-008-2S or April 13,

an unexpected ESF actuation signal was generated.

When the local

o)erator placed the vital AC alternate power supply breaker to the

TEST position 9er'the instructions of section 7.4.13 of the

procedure, power to the vital AC bus was momentarily loss'until

the local operator reclosed the alternate supaly breaker. This

loss of AC Sower resulted in a closed signal aeing generated for

valve 2D11

7050.

The licensee determined that an inadequate

procedure was the cause of the power loss to the vital AC bus.

The licensee notified the NRC in accordance with 10 CFR 50.72.

Later, a detailed review by the licensee revealed that containment

istlation valve 2011-F050 was already closed for maintenance

activities.

The licensee retracted the 10 CFR 50.72 notification

on April 14.

Prior to the logic system functional test for the 2A emergency

diesel generator, the static transfer switch was aligned to the

alternate power supply. The local operator was not aware that the

vital AC bus was powered.from the alternate source.

Both vital AC

'

supply breakers, the normal (2D) and the alternate (2C) are

normally closed.

Enclosure 2

.

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35

i

i

The inspectors reviewed HSP 42SV-R43-008-2S and noted that there

l

was no precaution or prerequisite in the procedure for verifying

that the static transfer switch was aligned to the normal power

i

supply. The inspectors also performed a limited walkdown of the

local vital AC panel and the 2C and 2D 600 volt station service.

switchgear and observed that the local operator could not easily

determine the power supply to the vital AC bus.

L

l

Implicit in the recuirements of 10 CFR 50, Appendix B, Criterion V

and RG 1.33 Appencix A. Typical Procedures for Pressurized Water

Reactors and Boiling Water Reactors, paragraph 8.b. is that the

f

procedures are adequate.

HSP 42SV-R43-008-2S did not provide

l

adequate instructions to prevent a loss of power to the Vital AC

bus when the bus is powered from its alternate source.

c.

Conclusions

This problem was identified as an example of an inadequate test

3rocedure.

Procedure 42SV-R43-008-25 " Diesel Generator 2A

_0CA/LOSP LSFT " Rev. 5. ED 1, did not contain precautions or

prerequisites nor identify appropriate pretest conditions to

i

prevent an unexpected ESF actuation signal during testing.

This

is an example of Violation 50-366/97-03-04,' Inadequate Procedures

l

for Testing Activities - Multiple Examples,

i

E4

Engineering Staff Knowledge and Performance

E4.1

Inservice Leak Testino of ASME Class 1 System (Unit 2)

!

a.

Insoection Scooe (61701)

The inspectors reviewed and observed portions of the inservice

,

!

leakage test performed on April 10.

The requirements for the

leakage test are in TS section 3.10. "S)ecial Operations."

subsection 3.10.1

" Inservice Leak and lydrostatic Testing

Operation." The inspectors reviewed Hatch Inspection and Test

Procedure (HITP) 421T-TET-006-2S. "ISI Pressure Test of the

,

Class 1 System and Recirculation Pump Runback Test." Rev. 8, which

)

was used by engineering' and operations test personnel to implement

the requirements.

b.

Observations and Findinas

The inspectors observed system testing, operations personnel

e

performance, supervisory oversight, and engineering support for

>

the testing activities.

The testing observations involved the

.

l

following:

!

I

,

i

Enclosure 2

i

e

1

, . .

_ ._ _ .

. -

_ .

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

,

,

.

f.

36

e

the establishment of the greater than 3 feet high air bubble in

L

the top of the reactor )ressure vessel with the water level

l

between 170 and 190 incies above instrument zero:

-

the initial pressurization of the vessel to 100 psig using

e

l-

plant service air:

l

'

e

the heat up of the vessel, using the reactor recirculating

pumps, to the minimum temperature specified in step 7.1.5 of

the HITP at the rate of equal to or less than 100 degrees F per

hour: and

the pressurization of the vessel, at the rate of equal to or

e

less than 50 psig per minute, to the test pressure of 1035 to.

'

1050 psig by injection from the control rod drive system and

the controlling of pressure by varying reactor water cleanup

reject flow.

i

All observed activities were performed in accordance with

applicable steps in the HITP.

L

The observations involving the operations group included:

starting the reactor recirculating pumps, pressurizing the vessel,

monitoring and maintaining vessel temperature, controlling the

i

vessel pressure constant, and recording data.

The observations of supervisory personnel were activities

involving the unit superintendent. the superintendent-on-shift,

and the shift supervisor, including command and control of control

room activities, conducting pre-job and shift briefings,

coordinating engineering support activities, and insuring that the

test was performed by the procedural requirements.

,

The observations of engineering support personnel activities

t

included:

assisting in job briefings, use and implementation of

the test procedure, verifying data, and ensuring acceptable

results.

During the performance of section 7.2. " System Leakage Test or

,

10-Year ISI Pressure Test (1035 to 1050 psig)." step 7.2.8, VT-2

leakage inspection of the Class 1 inspection boundary, a leak was

observed coming from a flanged fitting located at the top of the

. reactor vessel head. The fitting was installed on nozzle 6B.

!

which was part of the reactor vessel head spray system. This

system and associated piping were removed several years ago and

the nozzle was blank flagged.

,

G

j

Engineering personnel determined that the leakage was caused by a

-

mispositioned blind flange that resulted in a gasket failure.

The

.

i-

licensee initiated design change request (DCR)97-019 and

i

!

Enclosure 2

!

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37

.

maintenance work order 2-97-1041 to implement the DCR.

The repair

was made, in accordance with the DCR, and consisted of a seal

welded metal gasket at- the flange connection. A followup pressure

test was successfully performed on April 10.

i

i

c.

Conclusions

The inspectors concluded that the initial pressure test and the

o

i

followup. test were performed in accordance with approved

i

procedures.

The-leak repair was successful with no subsequent

leakage detected. The overall activities were performed with

i

engineering, quality control, and supervisory oversight.

The

performance of the pressure tests and the leak repair were

'

considered to be excellent.

!

'

E8

Hiscellaneous Engineering Issues (92700) (92903)

l

E8.1

(Closed) Insoector Followuo Item 50-366/96-07-03: Degradation and

Replacement of the Unit 2 Station Service (SS) Battery 2B Due to

i

Buildup of Cell Sediment. The licensee observed a dark colored

,

l

sediment collecting in the bottom of several of the 120 cells that

!

'

make up the SS battery.

Prior to replacing all the cells in the

i

SS battery, a total of 52 cells had sediment. The inspectors

l

documented the replacement and testing of the battery in

inspection report 50-321, 366/97-03.

Based on the replacement and

successful testing of the SS battery 2B, this item is closed.

E8.2

(Closed) Violation 50-321/96-11-02:

Failure to Perform an ASME

J

l

Code-Required VT-3 Inspection on High Pressure Coolant Injection

l

Valve.

The licensee responded to this violation in correspondence

l

dated October 30, 1996. The inspectors reviewed the response and

l

observed that among the corrective actions were the following:

,

e

involved personnel were counseled regarding the event and the

consequences;

e

an operability and structural integrity assessment for the

valve was performed and documented: and

e

a maintenance work order was written to disassemble the valve

and perform the required inspection during the Unit 1 fall 1997

refueling outage.

'

l

The inspectors reviewed the assessment and the maintenance work

l

order.

The inspectors concluded that valve was operable and is

i

scheduled to be disasscmbled and inspected during the next Unit 1

refueling outage.

Based on the ins

actions, this violation is closed. pectors review of licensee

l

!

4

i

,

Enclosure 2

4

i

,

.__

.

_-

-

.

__

__

.

._

_

.

_ ._ ._...

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

_ . _ . _

. _ .

.

'

.

.

.

!

38

!

IV Plant Suooort

t

L

R1

Radiological Protection and Chemistry Controls

-

R1.1 Observation of Routine Radioloaical Controls

a.

Insoection Scooe (71750)

.

General Health Physics (HP) activities were observed during the

-

report period. -This included locked high radiation area doors,

proper radiological posting, and personnel frisking upon exiting

the Radiological Controlled Area (RCA). The inspectors made

frequent tours of the RCA and discussed radiological controls with

HP technicians and HP management.

Minor defit.iencies were

discussed with licensee management.

No significant deficiencies

,

were identified.

R5

Training and Qualifications in Radiation Protection and

Transportation

.

R5.1 General Emoloyee Trainina

a.

Insoection Scoce (83723)

The inspectors reviewed procedure 73TR-TRN-001-0S, " General

Employee Training Programs," Revision 9 and reviewed the

licensee's program for providing General Employee Training (GET),

l

also known as Badge Training, to contractor personnel.

Other than

i

initial GET for new personnel, the program recognizes three

categories of personnel:

those who have been badged at a nuclear

facility within the last three years (exemat from classroom

sessions, but must pass an examination); tiose who have been

badged at a nuclear facility within the last year (exempt from

classroom sessions and examination, upon verification of training

-

from prior facilities): and those who are Plant Hatch contract

employees (annual requalification, which includes classroom

.

i

sessions and examination).

The inspection included a review of a

representative sample of GET training records for contractor

personnel.

b.

Observations and Findinas

The inspectors obtained the names of 13 individuals from the Plant

Modification and Maintenance Support (P!iMS) roster of contractor

personnel who were onsite during the Unit 2 Spring Outage (1997).

. A ". cords review by the inspectors indicated that all personnel

hao completed GET training within the past three years.

Specifically. the review indicated that six of the individuals had

successfully completed the badge training examination at Plant

Hatch within the past year.

Seven other individuals were granted

Enclosure 2

___

,

_

_

._

_

_

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. ._

._ ..

__ .

_ __ _

__

. . _ _ _ _ , _

__

-

.

,

39

>

credit for the successful completion of GET within the past 12

months-at other nuclear facilities that used the Institute of

Nuclear-Power Operation's guidelines for GET. including three from

the other nuclear plants operated by the Southern Nuclear

l'

Operating Company. Inc. (Plant Vogtle and the Farley Nuclear

Plant).

l

A review of the procedures identified that an individual who had

l

GET within the past three years and had unescorted access to

restricted areas may be exempted from full. Badge Traini:ng but must

take the Badge Training examination. A review of the examination

records indicated that all personnel who were examined had passed

,

the examination.

!

c.

Conclusions

l

The licensee's implementation of the General Employee Training

program for contractors was satisfactory. All training records

!

reviewed indicated that personnel were either provided training or

t

l

had passed the required examinations to obtain credit for previous

!

training. The inspectors concluded that all personnel were

satisfactorily trained for their level of site access.

t

R8

Miscellaneous RP&C Activities (92904)

L

R8.1

(Closed) Violation 50-321. 366/96-13-03:

Failure to Follow

l-

Procedure - Multiple Examples.

i

A routine monthly contamination survey of the scrap metal storage

area identified three pieces of metal that were contaminated in

l

excess of the requirements of procedure 60AC-HPX-007-0S. " Control

!-

of Radioactive Materials." Rev. 3.

l

The licensee's response dated December 19, 1996, indicated that HP

.

management issued a new policy for the release of materials from

the radiologically controlled areas. The inspectors reviewed the

HP Information Letter and verified that the requirements of the

new policy were included in the Information Letter.

It was also

noted that the original HP Information Letter, which was issued

October 31, 1996, was updated May 16, 1997.

Based upon the inspectors' review of licensee actions, this

j

violation example is closed.

i-

~

J

Enclosure 2

,

.

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!

40

P4'

Staff Knowledge and Performance in Emergency Preparedness

l

a.

Insoection Scooe (71750) (82301)

The inspectors reviewed the Hatch Emergency Plan and participated

in the licensees Emergency Preparedness (EP) exercise conducted on

i

!

May 6.-1997.

b.

Observations and Findinas

The inspectors observed licensee performance and participated in

'.

EP drill activities from the Technical Support Center (TSC) and

t

l

Ooerations Support Center (OSC).

The inspectors observed operator

crw performance during the simulated accident from the plant

L

specific simulator. State and local governments participated

partially in the exercise.

The exercise scenario was viewed as

!

.

challenging and required event classifications from Notification

'

of Unusual Event through a General Emergency. The exercise

i

included the following Drills:

-

Radiological Monitoring

Health Physics

-

-

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Staff Augmentation

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Real-Time Activation

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Medical Emergency

The exercise contained 23 objectives covering six major assessment

areas. One of the inspectors attended the initial post-exercise

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critique where exercise controllers conducted an initial

evaluation of exercise performance.

The licensee conducted a

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detailed review of participant critiques sheets and controller and

evaluator observations. The licensee was self critical and

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identified several areas for improvement.

The licensee determined

that one objective. Demonstrate the Ability for Prompt

Notification of the State. Local and Federal authorities, was not

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met.

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The inspectors reviewed licensee performance during recent

exercises and observed that in June 1996, an exercise weakness for

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failure to make adequate notifications to state and local and

federal authorities was documented as an IFI in IR 50-321.

,

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366/96-06.

During this exercise, the inspectors observed that a

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simulated radiological release was not reported for over thirty

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minutes. The inspectors observed that some exercise participants

were aware of the ongoing release but failed to ensure it was

reported.

The licensee was evaluating the problem for corrective

actions.

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The inspectors observed good operator performance in the plant

simulator during the exercise.

Procedures and Emergency Operating

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Procedures (EOPs) used were appropriate for the plant conditions.

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Communications were not consistent throughout the exercise.

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Although several examples of good 3-part communications were

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observed, communications were not as precise during times of

multiple activities.

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The inspectors identified several areas for improvement and

discussed these with EP and operations management personnel

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c.

. Conclusions

The inspectors concluded that no significant improvements were

observed with respect to notifications to state.' local and federal

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authorities.

The licensee's post-exercise critique and overall

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exercise assessment to self identify areas for improvement were

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considered to be excellent.

S2

Status of Security Facilities and Equipment (71750)

The inspectors toured the protected area and observed that the

perimeter fence was intact and not compromised by erosion'nor

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disrepair. The fence fabric was secured and barbed wire was

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angled as required by the licenste'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.

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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.

P8

Miscellaneous Security and Safeguards Issues (92904)

P8.1

(Ocen) VIO 50-321. 50-366/97-01-01:

Failure to Follow Procedure -

Multiole Examoles

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Violation 50-321, 50-366/97-01-01 documented five examples of the

licensee's failure to follow procedures.

Example 5 described the

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licensee's failure to conduct " hands-on" physical inventories of

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security weapons on February 19, 1997, which resulted in an

unattended weapons inside the protected area for approximately 11

hours.

The licensee made a determination that the failure to secure the

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security weapon was caused by human error.

In order to ensure

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security weapon procedures were thorough, clear, and u) dated, the

licensee had developed a Procedure Review Committee, w11ch became

effective March 10. 1997.

The Procedure Review Committee has the

responsibility to ensure that procedures are user friendly and

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current to ongoing operations. -

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The licensee had implemented the following. additional practices to

ensure that weapons are attended and stored in their correct

location:

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Officers a ' now required to initial the inventory sheet when

the. Weapon is taken on post.

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Upon activation and deactivation of a compensatory post, the

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base operator will confirm that the officer who has taken out a

weapon remains in control of.that weapon.

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Magnetic tags are posted on the weapons cabinet. When a weapon

is removed from the cabinet, the magnetic tag will be

transferred to the compensatory measure status board to confirm

the officer and location of..the weapon.

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Reminder notes such as "Do not forget to check your weapons"~

are put on the shift work schedule periodically.

Additionally, captains and lieutenants were formally briefed on

the importance of weapon inventory control, as well as shift

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briefing reminders to all' officers.

The inspector determined through a review of the licensee's

actions and interview of licensee representatives that appropriate

corrective actions had been implemented for example 5 of Violation

50-321, 50-366/97-01-01.

This violation will remain open pending

further review of licensee actions to address the other examples.

V. Manaaement Meetinas

X.1

Meeting on Spent Fuel Pool Regulatory Analysis for Hatch Units 1

and 2.

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On April 9 and 10. Mr. K. Jabbour, Project Manager Project

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Directorate II-2, office of Nuclear Reactor Regulation (NRR) and

Mr. C. Gratton of NRR accompanied by consultants from Idaho

National Environmental and Engineering Laboratory (INEL) met with

Southern Nuclear 0)erating Company Inc. representatives at Plant

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Hatch to discuss tle analysis and design features of the Unit 1

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and Unit 2 spent fuel pools and associated cooling systems.

The

objective of this meeting was to review design and operational

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information regarding the two Hatch spent fuel pool systems that

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will be used in an Spent Fuel Pool probabilistic risk assessment.

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The NRC will perform a regulatory analysis at several operating

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nuclear power piants, including Hatch, to determine whether plant-

specific safety enhancement backfits could be justified. The NRC

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will document the results of the analysis in a report that will be

transmitted to the licensee at a future date.

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X.2.

Review of UFSAR Commitments

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A recent discovery of a licensee operating its facility in a

manner contrary to the Updated Final Safety Analysis Report

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(UFSAR) description highlighted the need for a -special focused

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review that compares plant practices, procedures and/or parameters

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to the UFSAR description. While performing the ins)ections

discussed in this resort, the inspectors reviewed t1e applicable

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portions of'the UFSAR that related to the areas inspected.

The

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inspectors verified that the UFSAR wording was consistent with the

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observed plant practices, procedures. and/or parameters.

X.3

Systematic Assessment of Licensee Performance (SALP) Evaluation

and Public Meeting.

. At 10:00 a.m. on April 22. NRC management met with Southern

Nuclear Operating Company. Inc. management and employees.in an

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open meeting to present the results of the licensee's Systematic

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Assessment of Licensee Performance (SALP) evaluation. The

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facility was evaluated for the Seriod of May 28, 1995 through

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February-22, 1997.

Following t1e SALP presentation. NRC

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management met with local officials and residents to discuss a

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variety of topics.

The results of the SALP evaluation are

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documented in report Nos. 50-321/97-99 and 50-366/97-99.

X.4

Exit Meeting Summary

The inspectors presented the inspection results to members of the

licensee management at the conclusion of the inspection on May 29,

1997. The license acknowledged the findings presented.

The inspectors asked the licensee whether any materials examined

during the inspection should be considered proprietary.

No

proprietary information was identified.

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PARTIAL LIST OF PERSONS CONTACTED

Licensen

Anderson, J. , Unit Superintendent

Betsill, J., Assistant General Manager - Operations

Coggin, C. , Engineering Support Manager

Curtis, S., Unit Superintendent

Davis, D.,

Plant Administration Manager

Fornel, P., Performance Team Manager

Fraser

0., Safety Audit'and Engineering Review Supervisor

Hammonds, J. ,- Operations Support Superintendent

Kirkley, W., Health Physics and Chemistry Manager

Lewis, J

Training and Emergency Preparedness Manager

Madison D. R., Operations Manager

Moore, C., Assistant General Manager - Plant Support

Reddick, R., Site Emergency Preparedness Coordinator

Roberts, P., Outages and Planning Manager

Sumner, H., Vice President.. Hatch Nuclear Operations

Thompson, J. . Nuclear Security Manager

Tipps, S., Nuclear Safety and Compliance Manager

Wells, P., General Manager - Nuclear Plant

INSPECTION PROCEDURES USED

IP 37551: Onsite Engineering

IP 37700:

Design Changes and Modifications

IP 37828:

Installation and Testing of Modifications

IP 60710:

Refuelling Activities

IP 61701: Complex Surveillance

IP 61726;

Surveillance Observations

IP 62707:

Maintenance Observations

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IP 71707:

Plant Operations

IP 71711:

Plant Startup From Refueling

IP 71750:

Plant Support Activities

IP 82301:

Evaluation Of Exercises For Power Reactors

IP 83723: Training and Qualifications: General Employee

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Training, Radiation Safety, Plant Chemistry,.Radwaste,

and Transportation

IP 92700: Onsite Follow-up of Written Reports.of Nonroutine

Events at Power Reactor Facilities

IP 90712:

In-office Review of Written Reports of Non-routine

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Events at Power Reactor Facilities

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IP 92901:

Followup

Operations

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IP 92902:

Followup - Maintenance / Surveillance

IP 92903:

Followup - Followup Engineering

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IP 92904:

Followup - Plant Support

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ITEMS OPENED, CLOSED, AND DISCUSSED

Ooened

50-366/97-03-01

NCV Failure to Follow Procedure During

Welding Process of Unit 2 Reactor Core

Isolation Cooling Valve

(Section M4.1).

50-366/97-03-02

NCV Data Entry Error Results in Missed

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Technical Specification Surveillance

ori Unit 2 (Section M4.2).

50-321/97-03-03

NCV Failure to Commercially Dedicate

Isolation Valve (Section E1.1).

50-366/97-03-04

VIO Inadequate Procedures for Testing

Activities - Multiple Examples

(Sections E2.1 and E3.1).

50-321, 366/97-03-05

IFI Review of 4160 VAC Wiring Separation

Deficiencies (Section E1.2).

Closed

50-366/97-03-01

NCV Failure to Follow Procedure During

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Welding Process of Unit 2 Reactor Core

Isolation Cooling Valve

(Section M4.1).

50-366/97-03-02

NCV Data Entry Error Results in Missed

Technical Specification surveillance

on Unit 2 (Section M4.2).

50-321/97-03-03

NCV Failure to Commercially Dedicate

Isolation Valve (Section E1.1).

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50-321, 366/96-13-03

VIO Failure to Follow Procedure - Multiple

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Examples (Sections 08.1, M8.2, and

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R8.1).

50-366/1997-007

LER Loss of Main Condenser Vacuum Results

in a Main Turbine Trip and Automatic

Reactor Shutdown (Section 08.2).

50-366/1997-006

LER Data Entry Error Results in Missed

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Technical Specifications Surveillance

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on Source Range Monitors

(Section M.B.3).

Enclosure 2

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50-366/1997-005

LER Personnel Error Results in Unplanned

Automatic Engineered Safety Feature

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Actuation (Section 08.3).

50-366/96-07-03

IFI Degradation and Replacement of the

Unit 2 Station Service (SS) Battery 2B

Due to Buildup of Cell Sediment

(Section E8.1).

50-321/96-11-02

VIO Failure to Perform an ASME Code-

Required VT-3 Inspection on High

Pressure Coolant Injection Valve

(Section E8.2).

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Discussed

50-321, 366/97-01-01

VIO Failure to Follow Procedure - Multiple

Examples (Section P8.1).

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