ML20034G100

Insp Repts 50-317/93-02 & 50-318/93-02 on 930103-0206. Violations Noted.Major Areas Inspected:Plant Operations, Radiological Protection,Surveillance & Maint,Emergency Preparedness & Security

ML20034G100
Person / Time
Site:	Calvert Cliffs
Issue date:	02/25/1993
From:	Larry Nicholson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I)
To:
Shared Package
ML20034G097	List: ML20034G096 ML20034G098 ML20034G100
References
50-317-93-02, 50-317-93-2, 50-318-93-02, 50-318-93-2, NUDOCS 9303090068
Download: ML20034G100 (20)

See also: IR 05000317/1993002

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U.S. NUCLEAR REGULATORY COMMISSION

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REGION I-

Report Nos.

50-317/93-02; 50-318/93-02

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License Nos.

DPR-53/DPR-69

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Licensee:

Baltimore Gas and Electric Company

Post Office Box 1475

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Baltimore, Maryland 21203

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Facility:

Calvert Cliffs Nuclear Power Plant, Units 1 and 2

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location:

Lusby, Maryland-

Inspection conducted:

January 3,1993, through February 6,1993

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Inspectors:

Peter R. Wilson, Senior Resident Inspector

Carl F. Lyon, Resident Insp . tor

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Allen G. Howe, Reactor Operations Engineer, NRR

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Approved by:

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tarry p. Nicholson, Chief

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Reactor Projects Section No. l A

Division of Reactor Projects

Insoection Summary:

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This inspection report documents resident inspector core, regional initiative, and reactive

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inspections performed during day and backshift hours of station activities including: plant

operations; radiological protection; surveillance and maintenance; emergency preparedness;

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security; engineering and technical support; and safety assessment / quality verification.

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Results:

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See Executive Summary.

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9303090068 930225

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ADOCK 05000317

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EXECUTIVE SUMMARY

Cnivert Cliffs Nuclear Power Plant. Units 1 and 2

Inspection Report Nos. 50-317/93-02 and 50-318/93-02

Plant Operations: (Operational Safety Inspection Module 71707, Prompt Onsite Response

to Events at Operating Power Reactors Module 93702) An operator error resulted in the

radioactive contamination of approximately 5300 square feet of floor space in the auxiliary

building. BG&E's corrective actions were prompt and appropriate. The inspectors found

that technical directions for translating some generic emergency operating procedure (EOP)-

guidance into the plant specific EOPs was inadvertently deleted from the current EOP

writer's guide. BG&E plans to revise the writer's guide to correct this omission. The

inspectors observed a significant improvement in plant general housekeeping.

Radiolonical Protectipli: (Modulo 71707) Based on direct observation of access controls

and radiological safety practices and discussions with radiological controls personnel, the

radiological protection program and implementation was excellent.

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Maintenance and Surveillance: (Maintenance Observations Module 62703, Surveillance

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Observations Module 61726) The inspectors observed several maintenance activities. The

work was safely performed and in acccrdance with procedures. BG&E took prompt and

apptopriate corrective action following the failure of an emergency diesel generator (EDG) to

reach rated speed within the required time. The inspectors reviewed BG&E's EDG

maintenance and inspection program and determined it exceeded regulatory requirements.

Inadequate supervisory review and pre-job briefing resulted in the deenerCution of one

channel of the reactor protection system and the opening of four reactor trip breakers.

BG&E's immediate corrective actions were proper.

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Emercency Prtparedness: (Module 71707) An acceptable level of emergency preparedness

was found based on inspection of facilities, review of procedures, and discussion with

operations and emergency planning personnel.

Securiu: (Module 71707) Based on direct observation, the security plan was professionally

implemented.

Encineerine and Technical Support: (Module 71707) The procedural guidance concerning

post LOCA core flushing contained in the emergency operating procedures was inadequate.

BG&E's corrective actions were appropriate, and this was determined to be a non-cited

violation. Spent fuel handling crane testing was inadequately controlled. Procedural

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Executive Summary

noncompliance and excessive overtime without proper authorization were determined to be

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violations. An improper procedure change was a non-cited violation. BG&E took prompt

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and rigorous corrective actions to restore the validity of the testing and affirm a commitment.

to quality to site personnel.

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Safety Assessment /Ouality Verification: (Modules 71707,30703) Based on direct

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observation, the onsite and offsite safety review committees continued to be strengths. The

Procedure Review Committee (PRC) demonstrated a strong safety perspective and

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questioning attitude in reviewing Engineering Test Procedure (ETP) changes.

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DETAILS

1.0

SUMMARY OF FACILITY ACTIVITIES

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Units 1 and 2 operated at power with no significant events for the entire period.

2.0

PLANT OPERATIONS

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2.1

Onerational Safety Verification

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The inspectors observed plant operation and verified that the facility was operated safely and

in accordance with licensee procedures and regulatory requirements. Regular tours were

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conducted of the following plant areas:

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- control room

- security access point

- primary auxiliary building

- protected arei. fence

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-- radiological control point

-- intake structure

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- electrical switchgear rooms

-- diesel generator rooms

-- auxiliary feedwater pump rooms

- turbine building

Control room instruments and plant computer indications were observed for correlation

between channels and for conformance with technical specification (TS) requirements.

Operability of engineered safety features, other safety related systems and onsite and offsite

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power sources was verified. The inspectors observed various alarm conditions and

confirmed that operator response was in accordance with plant operating procedures.

Routine operations surveillance testing was also observed. Compliance with TS and

implementation of appropriate action statements for equipment out of service was inspected.

Plant radiation monitoring system indications and plant stack traces were reviewed for

unexpected changes; Logs and records were reviewed to determine if entries were accurate

and identified equipment status or deficiencies. These records included operating logs,

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turnover sheets, system safety tags and temporary modifications log. Plant housekeeping

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controls were monitored, including control and storage of flammable material and other

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potential safety hazards. The inspectors also examined the condition of various fire

protection, meteorological, and seismic monitoring systems. Control room and shift manning

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were compared to regulatory requirements and portions of shift turnovers were observed.

The inspectors found that control room access was properly controlled and that a professional

atmosphere was maintained.

In addition to normal utility working hours, the review of plant operations was routinely

conducted during backshifts (evening shifts) and deep backshifts (weekend and midnight

shifts). Extended coverage was provided for 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> during backshifts and 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> during

deep backshifts. Operators were alert and displayed no signs ofinattention to duty or

fatigue.

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The inspectors obsented an acceptable level of performance during the inspection tours

detailed above. Of panicular note, the inspectors obsened a significant improvement in

general plant housekeeping. BG&E has initiated a plant lighting upgrade program which has

resulted in increased illumination in some safety related areas. The improved lighting has

been effective in making housekeeping deficiencies more identifiable and correctable in the

affected areas.

2.2

Followup of Events Occurring Durine Inspection Period

During the inspection period, the inspectors provided onsite coverage and followup of

unplanned events. Plant parameters, performance of safety systems, and licensee actions

were reviewed. The inspectors confirmed that the required notifications were made to the

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NRC. During event followup, the inspectors reviewed the corresponding CCI-118N (Calvert

Cliffs Instruction, " Nuclear Operations Section Initiated Reporting Requirements")

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documentation, including the event details, root cause analysis, and corrective actions taken

to prevent recurrence. The following event was reviewed.

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Service Water Head Tank Overfill

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On February 4,1993, an operator error resulted in the radioactive contamination of

approximately 5300 square feet of floor space in the auxiliary building. The source of the

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contamination was radioactive debris in the auxiliary building floor drain lines which was

flushed out of the lines when a Unit 2 service water head tank overflowed into the auxiliary

building floor drain system. The inspectors conducted a review of the event to determine the

safety significance and adequacy of BG&E's corrective actions.

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Each unit's service water (SRW) system is designed with a spare swing SRW pump. The

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Unit I swing pump (No.13 SRW pump) is normally hydraulically aligned to the 12 SRW

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header. The Unit 2 swing pump (No. 23 SRW pump) is normally hydraulically aligned to

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the 21 SRW header. While each service water system is designed to function as two

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independent cooling water headers during certain accident conditions, during normal

operation each SRW system is operated cross connected. Each SRW header is provided with

a head tank (locaW on the 69 ft elevation of the auxiliary building) to provide net positive

suction head te the SRW pumps.

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While the 21 and 22 SRW pumps were operating, a control room operator started the No. 23

SRW pump in order for maintenance personnel to adjust the pump seal. After starting the

pump, the operator observed that the water level in both Unit 2 SRW head tanks was

fluctuating. To stabilize the head tanks' water level, the operator mistakenly stopped the 22

SRW pump. This resulted in a rapid water level increase in the 22 SRW head tank. To stop

the increase, the operator restarted the SRW pump; however, approximately 500 gallons of

water spilled from the head tank before the water level was restored. The spilled water

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entered the auxiliary building drain system. Some of this water backed up out of the floor

drains on the 5 ft elevation of the auxiliary building, carrying radioactive particle residue

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from the drain lines. The affected areas were subsequently decontaminated. The highest

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contamination detected was 50,000 counts per minute above background.

The inspectors reviewed BG&E's root cause evaluation of the event. The cause of the event

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was operator error due to the lack of self verification. He confused the Unit I and Unit 2

lineups. The operator mistakenly believed that the 23 SRW pump was hydraulically aligned

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to the 22 SRW header. BG&E also identified other contributory causes which included weak

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face-to-face communications between the operator and the control room supervisors, and the

lack of a procedure for operating three SRW pumps at the same time,

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BG&E implemented several corrective actions. This included counselling for the personnel

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involved, and the issuance of a night order discussing the event which stressed the

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importance of formal face-to-face communications in the control room and the need to

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thoroughly discuss minor evolutions not covered by procedure prior to implementation.

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The inspectors concluded that the event was of minor safety significance. The floor area

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involved and the level of contamination were not significant. No personnel contaminations

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occurred as a result of the event. BG&E's evaluation of the event was prompt and thorough.

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The corrective actions implemented by BG&E were appropriate.

2.3

EOP Procedure Develonment

As part of the inspectors' review of core flush issues documented in Section 7.1, the

inspectors assessed the effectiveness of the current process for emergency operating

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procedure (EOP) development and revision.' The inspectors reviewed the BG&E EOP/AOP

Writer's Guide, Revision 0, Change 3. This writers guide addressed the elements for

procedure form and style and procedure verification / validation. The inspectors noted that the

writer's guide did not contain technical guidance describing how many aspects for translating

the generic guidance into the plant specific EOP would be controlled. The current writer's

guide was rewritten in July 1991 and during that rewrite, portions of the technical guidance

were removed due to an administrative error.

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The inspectors expressed concern to BG&E that ce omission of this technical guidance in the

current writer's guide could cause EOP technical inconsistency and lead to technical

inadequacies in the EOPs. The BG&E EOP lead procedure writer agreed that some of the

previous technical guidance was not in the current writer's guide or in other guidance. He

did, however, describe to the inspectors the current methods for EOP revisions. Those

methods were consistent with the guidance described in the previous EOP writer's guide.

Based on the described methods, the results of the 1989 NRC EOP inspection, the absence of

significant concerns identified during inspections, and the fact that no EOP revisions have

been made since the technical guidance was omitted, the inspectors concluded that an

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immediate concern with the current EOPs did not exist. At the end of the period, BG&E

was planning to revise the writer's guide with the appropriate technical guidance which had

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been inadvenently deleted from the current revision.

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3.0

RADIOLOGICAL CONTROLS

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During tours of the accessible plant areas, the inspectors observed the implementation of

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selected portions of the licensee's Radiological Controls Program. Utilization and

compliance with special work permits (SWPs) were reviewed to ensure detailed descriptions

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of radiological conditions were provided and that personnel adhered to SWP requirements.

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The inspectors observed that controls for the access to various radiologically controlled areas

and use of personnel monitors and frisking methods upon exit from these areas were properly

implemented. Posting and control of radiation areas, contaminated areas and hot spots, and

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labelling and control of containers holding radioactive materiais were appropriate and verified

to be in accordance with licensee procedures.

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Health Physics technician control and monitoring of these activities were determined to be

good. Overall, an excellent level of performance was obsen>ed.

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4.0

MAINTENANCE AND SURVEILLANCE

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4.1

Maintenance Observation

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The inspector reviewed selected maintenance activities to assure that:

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the activity did not violate technical specification limiting conditions for operation and

that redundant components were operable;

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required approvals and releases had been obtained prior to commencing work;

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procedures used for the task were adequate and work was within the skills of the

trade;

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activities were accomplished by qualified personnel;

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where necessary, radiological and fire preventive controls were adequate and

implemented;

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quality verification hold points were established where required and observed; and

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equipment was properly tested and returned to service.

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The work observed was performed safely and in accordance with proper procedures.

Inspectors noted that an appropriate level of supervisory attention was given to the work

depending on its priority and difficulty. Maintenance activities reviewed included:

MO 09200581

Replace Relief Valve on No. 21 West Air Receiver

MO 29202262

Inspect / Test No. 21 Emergency Diesel Generator Fuel Injectors

MO 29204754

Inspect / Clean No. 21 Emergency Diesel Generator "Y" and Basket

Strainers

MO 29204734

Lubricate No. 23 Component Cooling Pump Bearings

MO 29204565

Perform EQ replacement on 21 ECCS air cooler SW inlet solenoid

valve, 2-SV-5070

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MO 29202600

Sample and change oil in 21 HPSI pump and motor

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MO 29205177

Replace anodes in 21 ECCS pump room air cooler

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MO 19300651

Inspect 12 EDG air start distributor

MO 29103760

Replace 21 LPSI pump discharge pressure transmitter, 2-PT-302X

4.2

Surveillance Observation

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The inspectors witnessed / reviewed selected surveillance tests to determine whether properly

approved procedures were in use, details were adequate, test instrumentation was properly

calibrated and used, technical specifications were satisfied, testing was performed by

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qualified personnel, and test results satisfied acceptance criteria or were properly

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dispositioned.

The surveillance tesdng was performed safely and in accordance with proper procedures.

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Inspectors noted that an appropriate level of supervisory attention was given to the testing

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depending on its sensitivity and difficulty. The following surveillance testing activity was

reviewed:

STP O-55-2 Containment Integrity Verification

4.3

Emergency Diesel Generator Test Failure

On January 21,1993, operators started the No. 21 cmergency diesel generator (EDG) for

surveillance testing. The EDG failed to meet a test acceptance criterion. Specifically, the

EDG failed to reach the rated speed of 900 rpm within 10 seconds as required by the test.

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Subsequently, BG&E determined that the unexpected slow start of the EDG was the result of

a buildup of rust particles in the EDG air start distributor. The air distributor functions to

direct starting air to the EDG pistons during the EDG start sequence.

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BG&E postulated that the cause of the rust particle buildup resulted from operation of the

No. 21 EDG air compressor with its after cooler inoperable. The air compressor had

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operated in this condition for several months. This resulted in a higher than normal moisture

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content in the starting air and the formation of the rust particles. BG&E informed the

inspectors that this was the first time that a buildup of rust particles in an air start distributor

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had been detected.

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The inspectors were concerned that the other two EDGs may have been similarly affected

since the No. 21 EDG air compressor also provides starting air to these EDGs. The

inspectors were also concerned that BG&E's EDG maintenance and inspection program did

not detect this adverse condition before the EDG operability was adversely affected. The

inspectors reviewed BG&E's corrective actions and conducted a detailed review of the EDG

maintenance and inspection program to determine if the program was meeting regulatory

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requirements.

In 1989, BG&E revised the EDG maintenance and inspection program to include the periodic

inspection and cleaning of the EDG air start distributors. This activity was to be performed

on a five year interval. The inspectors were informed by BG&E's EDG system engineer that

the No. I1 EDG air start distributor had last been inspected in 1992, the No.12 EDG in

1986 and the No. 21 EDG in 1989.

BG&E maintenance personnel cleaned the No. 21 EDG air distributor. The EDG was

subsequently successfully tested and returned to service. On January 27, the inspectors

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witnessed the inspection of the No.12 EDG air start distributor. No significant buildup of

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rust particles was found. BG&E elected not to inspect the No.11 EDG air distributor since

it was found clean the 1992 inspection. Operators were instructed to operate the No. 21

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EDG air compressor only when the other EDG air compressors were not available. As an

additional corrective action, BG&E revised the air start distributor inspection interval from

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five years to three years.

The inspectors conducted a review of the EDG maintenance and inspection program to verify

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that air start distributor and other inspections were being performed within the periodicity

specified by the EDG vendor. Calvert Cliffs technical specification 4.8.1.1.2.d.1 required

the performance of EDG inspections on an 18 month interval in accordance with the

manufacturer's recommendations. The inspectors reviewed the inspection and periodic

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maintenance recommendations contained in the EDG vendor technical manual and found that

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no recomraendations were made to periodically inspect the air start distributors. They also

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verified that all manufacturer's maintenance and inspection recommendations were

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incorporated into BG&E's maintenance program. The inspectors found that BG&E's EDG

maintenance and inspection program contained several additional requirements beyond that

recommended by the manufacturer.

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In conclusion, the inspectors found that BG&E took appropriate actions in response to the

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EDG surveillance test failure. In addition, BG&E's EDG maintenance and inspection

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program exceeded regulatory requirements.

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4.4

Inadvertent De-energization of RPS Channel

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On February 3, instrument and controls (I&C) technicians inadvertently de-energized the

Unit 2 Channel A cabinet of the reactor protection system (RPS). As a result, all Channel A

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trip units tripped and four reactor trip breakers opened. A reactor trip did not occur because

the 2 out of 4 RPS logic matrix was not satisfied, and the remaining four redundant trip

breakers remained closed. Operators immediately evaluated the condition and restored the

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system to normal.

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The I&C technicians intended to replace a 15 VDC power supply which supplies a wide

range nuclear instrument plasma display. The work was originally planned to be done during

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the upcoming outage but had been moved forward. As directed by the MO, the techmetans

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opened the Channel A supply breaker, which de-energized the cabinet.

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BG&E's preliminary investigation revealed several factors that contributed to the event.

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Planning was correct for a shutdown unit, but not for a unit at power. The supervisory

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review and pre-job brief were inadequate. The technicians were unsure of the effect of

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opening a breaker, but did so nevertheless. Inspectors discussed the event with the operators

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and with operations and I&C management. In addition to restoring the cabinet to service,

the General Supervisoz-Nuclear Plant Operations placed a suspension on conducting outage

work while at power. An issue report and POSRC open item were created to document and

track the event to resolution. Ieng term corrective actions await completion and review of

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the investigation by BG&E. This event appeared to be an instance of insufficient control of

maintenance and that BG&E's corrective actions were appropriate.

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EMERGENCY PREPAREDNESS

The inspectors toured the onsite emergency response facilities to verify that these facilities

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were in an adequate state of readiness for event response. The inspectors discussed program

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implementation with the applicable personnel. The resident inspectors had no noteworthy

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findings in this area.

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SECURITY

During routine inspection tours, the inspectors observed implementation of portions of the

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security plan. Areas observed included access point search equipment operation, condition of

physical barriers, site access control, security force staffing, and response to system alaims

and degraded conditions. These areas of program implementation were determined to be

good. No unacceptable conditions were identified.

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ENGINEERING AND TECHNICAL SUPPORT

7.1

Review of Post LOCA Core Flush Concerns

Background

In March 1992, BG&E determined that emergency operating procedure, (EOP)-5, " Loss of

Coolant Accident," Revision 1, specified a minimum injection flow that was insufficient to

prevent boric acid precipitation following certain loss of coolant accidents (LOCAs). The

inspectors reviewed BG&E's initial corrective actions e documented in NRC inspection

report (IR) 50-317 and 318/92-07. Those initial actions to evahiate the issue and instmet

operators on the proper flow requirements were prompt and effective.

The issue had potential safety significance since inadequate core flushing could result in boric

acid precipitation and possible loss of long term decay heat removal. The inspectors

identified the following two issues as unresolved item 50-317 and 318/92-07-02:

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The 40 gpm acceptance criterion in EOP-5 for injection flow was insufficient to

assure adequate core flushing. BG&E had not completed final calculations and

assessments of the safety significance of the issue.

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The acceptance criterion for injection flow was established as a part of the EOP

development process. The inspectors were concerned with the adequacy of the EOP

procedure development process that established and reviewed this acceptance

criterion. The scope of later reviews of boric acid precipitation may have been

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inadequate.

To prevent boric acid from concentrating to the precipitation point and potentially blocking

core coolant channels, core flushing is performed by simultaneously injecting coolant into the

reactor coolant system cold leg and hot leg. To achieve a successful flush, the injection flow

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of relatively dilute boric acid solution must be greater than the coolant boil-off rate so that

the excess coolant flows out of the postulated break-. This excess flow prevents concentration

of boric acid. The EOP-5 core injection flow minimum acceptance criterion of 40 gpm was

not adequate to achieve a successful flush. BG&E subsequently determined that the

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minimum specified injection flow should have been approximately 120 gpm.

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EOP-5 provided operators three methods to perform hot leg flushing. A brief synopsis of the

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methods, in order of preference, follows-

Method 1: Operators lined up the discharge of one of two operating high pressure safety

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injection (HPSI) pumps to the pressurizer auxiliary spray header to provide the source of hot

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leg injection.

Method 2: Operators split the discharge of one operating HPSI pump to pressurizer auxiliary

spray to provide the source of hot leg injection and the normal HPSI injection path for cold

leg injection.

Method 3: Operators lined up the discharge of one operating low pressure safety injection

(LPSI) pump to the shutdown cooling system suction to the hot leg.

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Safety Sienificance

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BG&E performed a detailed analysis of this issue and determined that the safety significance

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was minimal. This conclusion was based on the assumption that operators would maximize

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flow rather than injecting only the minimum requirement. The inspectors concluded that this

assumption was appropriate and consistent with the EOP requirement that injection flow be

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maximized unless several criteria were satisfied including pressurizer level greater than 101

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inches and reactor vessel level above the hot leg.

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In "best estimate" evaluations BG&E calculated that at least 119 gpm would have been

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injected into the pressurizer using two HPSI pumps (method 1) and that the precipitation

point would not be reached at that injection flow rate. An evaluation of hot leg injection via

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a LPSI pump (method 3) determined that at least 160 gpm would have been available. The

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inspectors reviewed the evaluations and concluded that adequate flushing capability was

available using these methods and, therefore, was of minimal safety significance.

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However, BG&E concluded that injection using a single HPSI pump (method 2) was

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inadequate. BG&E estimated that this method would deliver an injection flow of only 80

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gpm. To assess the significance of this procedural inadequacy, the inspectors considered the

low likelihood that a LOCA would occur with only one HPSI pump available, the options

and resources available to the operators at the time core flush should be initiated, the checks --

and contingency actions required to ensure critical safety functions are met, and the EOP

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requirement that injection flow be maximized unless certain criteria are met. Based on those

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considerations, the inspectors determined that the safety significance was low.

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BG&E Corrective Actions

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To correct the immediate issue, BG&E revised EOP-5 to incorporate the proper flow

criterion. A valve that throttled flow in a parallel flowpath that effectively reduced the

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available coolant for pressurizer injection was adjusted to provide more flow to the

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pressurizer via the auxiliary spray line. In addition, EOP-5 was revised to make the method

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utilizing one HPSI pump to provide both cold and hot leg injection the least preferred method

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of performing the hot leg flush.

The inspectors reviewed a root cause evaluation performed by BG&E. This evaluation was

thorough and determined that the primary root cause was the difficulty to access detailed

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EOP basis information. Contributing to the root cause was a misinterpretation of the

criterion for required flushing flow. As BG&E developed the core flush procedure in the

mid 1970s, the ' low rate acceptance criterion for injection failed to account for core boildf.

The root cause evaluation described the historical development of the injection flow crit rion

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including the original misinterpretation of the proper injection flow requirements. This

incorrect flow requirement was apparently translated into the EOP from an existing abnt Tnal

operating procedure (AOP) without a detailed reexamination of its adequacy. The inspectors

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review of current EOP development process issues are documented in Section 2.3.

As a result of the root cause analysis, BG&E initiated changes to the Final Safety Analysis

Report and the EOP Basis document to capture the core flush injection flow design

requirements. A change to the EOP Writer's Guide to require engineering review of future

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EOP changes is also planned. A comprehensive, one time engineering review of the EOPs

to ensure actions were bounded by the design basis is scheduled to be completed by

December 1993. Additionally, BG&E previously recognized the difficulty of retrieving

detailed design information and has taken some actions to improve accessibility, including a

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pilot program to compile information on selected components and systems.

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The inspectors concluded that the initial corrective actions, including the procedure revisions

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and valve adjustments, promptly resolved the immediate concerns. The revisions to EOP-5

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ensured that two adequate alternative meth(xis to perform post LOCA core flushing are

provided in the EOPs. The long term corrective actions include a comprehensive review of

the procedures that should provide the framework to validate the procedures and identify any

other significant concerns.

Summary

In summary, the inspectors concluded that the procedural guidance concerning post LOCA

core flushing contained in EOP-5 was inadequate; however, the safety significance of this

issue was low for reasons documented above. This issue was identified by BG&E and was

not reportable. BG&E's subsequent corrective actions were prompt and thorough. Calvert

Cliffs TS 6.8.1.a required that procedures be established, implemented, and maintained

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covering activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2,

February 1978. This included procedures for combating LOCAs. Therefore, the failure to

provide an adequate post LOCA flush procedure is a violation. This violation was not cited

because the criteria for discretion specified in Section VII.B of the NRC Enforcement Policy,

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10 CFR 2 Appendix C, were satisfied.

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7.2

Spent Fuel Handling Crane Testing

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Testing on the new Spent Fuel Handling Crane was conducted from January 4 - 19,1993.

Before the crane was declared operable, BG&E's Procedure Review Committee (PRC) raised

questions about several changes made to the testing procedures. As a result, BG&E and the

inspectors reviewed the completed testing. BG&E's preliminary evaluation and the

inspectors' independent investigation of the testing discovered several irregularities and

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potential violations of NRC requirements. The testing appeared to be marked by overall

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inadequate control and inattention to detail, as evidenced by an improper change to a

procedure, several examples of procedure noncompliance, several examples of excessive

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overtime, and numerous administrative irregularities. On January 27, the Plant General

Manager (PGM) determined that there was a sufficient lack of confidence in the performance

of testing done on the new spent fuel handling crane to justify a complete retest.

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a.

Background

in order to transfer spent fuel from the spent fuel pool to the new Independent Spent Fuel

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Storage Installation, BG&E must handle a new transfer cask which weighs approximately _100

tons. This weight exceeds the maximum weight used in the original load drop analysis for

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the fuel pool. That analysis indicated that an uncontrolled drop of a 100 ton cask could

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potentially damage safe shutdown equipment or penetrate the spent fuel pool floor. In order

to comply with NUREG 0612, " Control of Heavy Loads in Nuclear Power Plants," BG&E

decided to change the method of handling heavy loads by upgrading the Spent Fuel Cask

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Handling Crane to single-failure-proof in accordance with NUREG 0554, " Single-Failure-

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Proof Cranes for Nuclear Power Plants." The upgrade was accomplished by replacing the

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original Whiting crane with a new Ederer X-SAM single-failure-proof crane. The

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replacement was completed in December,1992, and testing commenced on January 4,1993.

In order to fulfill the requirements of NUREG 0554 for single-failure-proof designs and

perform the manufacturer's pre-operational tests, BG&E developed three Calvert Cliffs

Engineering Test Procedures (ETPs). In summary, ETP 92-130 tested the auxiliary hook (15

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ton) safety devices, ETP 92-131 tested the main book (125 ton) safety devices, and ETP 92-

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129 performed the field test for the total crane system.

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Evaluation

Following the PRC's questions on January 21, the PGM requested that an independent

investigation of the crane testing be done to identify any additional concerns and to determine

the required actions to be completed prior to moving fuel. The inspectors also

independently reviewed the crane testing, including the following associated records and

instructions:

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ETPs92-129,92-130, and 92-131, and the associated procedure changes

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issue repons

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personnel work records and overtime authorizations

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qualification records for crane operators

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50.59 Evaluation IAg Number 92-B-099-140 Revisions 0 and 1, addressing the crane

installation, pre-operational testing, and operation

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Calvert Cliffs Instruction (CCI) 159, "Use of Overtime"

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CCI 132, " Requirements for Implementation, Use, and Record Keeping of ETPs"

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CCI 140, " Conduct of Operations"

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PR-1-101, " Preparation and Control of Calvert Cliffs Technical Procedures"

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Pre-evolution briefing attendance records.

In addition, associated project, craft, vendor, supervisory, and management pelsonnel were

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interviewed. The following problems were identified by BG&E and the inspectors

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Improper Change to a Procedure

Temporary approval for immediate change number 2 to ETP 92-130 was made on January 7

and the revised steps were performed on January 8. The change was brought before the

PRC for review on January 21 to meet the 14 day time limit for final approval. The change

was made to provide an alternate method of setting the load cell of the overload detection

system and was necessary because the method specified in the ETP could not be done. This

alternate method involved an actual load lift; however, the procedure change failed to

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incorporate the safety precautions required for a load lift during testing. Because of its

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safety significance, the PRC concluded that it was a change of intent to the original

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procedure and rejected it in accordance with PR-1-101, " Preparation and Control of Calvert

Cliffs Technical Procedures." Subsequently, the change was disapproved by the approval

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authority.

Notwithstanding BG&E's corrective actions, as documented below, TS 6.8.5 states that

temporary changes to written procedures for test activities of safety related equipment may

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be made provided that the intent of the original procedure is not altered and that the change

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is documented, reviewed by the POSRC, the PRC, or by a qualified reviewer and approved

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by the designated approval authority within 14 days ofimplementation. Consequently, the

improper change to ETP 92-130 is a violation of TS 6.8.5. The violation was not cited

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because the criteria for discretion specified in Section VII.B. of the NRC Enforcement

Policy,10 CFR 2, Appendix C, were satisfied.

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Procedure Noncompliance

The PRC also discovered that the alternate method of setting the load cell was used on the

main hook during ETP 92-131. A procedure change was never done to allow the alternate

method, and the ETP was signed off by project personnel to reflect that it was performed as

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written. By interviewing the project personnel involved, BG&E and the inspectors

independently determined that the failure to comply with the ETP as written was due to

misunderstanding and a lack of knowledge of the requirements for a procedure change and

was not a willful attempt to circumvent the procedure.

The inspectors found that several personnel involved in the testing did not attend a pre-

evolution briefmg as required by Calvert Cliffs Instruction (CCI) 132, " Requirements for

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implementation, Use, and Record Keeping of ETPs." These included a vendor technical

representative, a test coordinator and the crane operators. CCI 132 requires that pre-

evolution briefmgs be performed in accordance with CCI 140, " Conduct of Operations,"

requirements. CCI 140 requires that all personnel involved in an evolution, even those with

minimal involvement, shall attend the pre < volution brief. Any persons not attending the

brief that need to become involved in the evolution shall be properly briefed prior to

beginning any involvement in the evolution.

The inspectors found that three ETP changes, including the change rejected by the PRC,

were screened by a procedure screener who was not certified as required by PR-1-101. The

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procedure screener is a person certified by at least a General Supervisor in accordance with

PR-1-102, " Certification of Qualified Reviewers and Procedure Screeners," based on

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education, experience, and training to perform procedure reviews to determine whether a 10 CFR 50.59 safety evaluation is required.

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BG&E found one instance while performing a load test for the crane during ETP 92-129

where the procedure could not be performed as written due to the physical configuration of

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the spent fuel pool area. The quality verification technician (QVT) had a hold point at the

step and instructed the test coordinator to stop the test and have the ETP changed before

continuing. The test coordinator continued moving the load and informed the QVT that the

ETP would be changed to reflect the actual movement of the load. This was a violation of

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CCI 132, which requires that the test coordinator shall stop the test and affected plant

equipment shall be placed in the condition as directed by the shift supervisor when the test

cannot be performed as written. The Qvr notified his management, who resolved the issue

with project management. The ETP was subsequently changed and an issue report written to

document the procedure noncompliance.

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T S 6.8.1.a requires that written procedures shall be established, implemented, and

maintained covering the applicable procedures recommended in Appendix A of Regulatory

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Guide 1.33, Revision 2., February 1978. Regulatory Guide 1.33 requires administrative

procedures for procedure adherence and temporary change method and for procedure review

and approval. The above examp!es of procedure noncompliance are a violation of TS 6.8.1

(VIO 50-317 and 50-318/93-02-01).

Excessive Overtime

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The inspectors identified several personnel involved in the testing who exceeded the overtime

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limits of Generic Letter (GL) 82-12 without proper authorization. GL 82-12 states that an

individual should not be permitted to work more than 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> in any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, nor

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more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period, nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any seven day period

(all excluding shift turnover time). The two test coordinators, the two technical

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representatives, and one electrician all exceeded 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in a seven day period without

proper authorization. CCI 159, "Use of Overtime," implements the requirements of TS 6.8.1.g. TS 6.8.1.g requires that the amount of ovenime worked by plant staff members

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performing safety related functions must be limited in accordance with the NRC Policy

Statement on Working Hours (GL 82-12). The use of overtime without proper authorization

is a violation of TS 6.8.1.g (VIO 50-317 and 50-318/93-02-02).

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Administrative Irregularities

Numerous administrative irregularities in the ETPs were identified by BG&E and the

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inspectors. Many changes and corrections were not initialed or dated, deleted sections were

later referenced in the procedure, and many dates for conducting and witnessing steps did not

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coincide. Procedure changes to ETP 92-129 made the controlled copies untidy and difficult

to follow. BG&E's quality control organization identified and documented some of these

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irregularities in an issue report.

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Corrective Actions

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BG&E took prompt and rigorous corrective actions to restore confidence in the crane testing.

These actions included complete rewrite, review, and approval of the ETPs and retest of the

crane. BG&E also documented the issues in program deficiency reports and issue reports as

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appropriate for rcsolution and tracking. In addition, the responsibility for conducting the

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ETPs was moved from the Spent Fuel Project to Plant Engineering. An independent root

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cause analysis investigation of the crane project was still in progress as the period ended.

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Additional corrective measures await an evaluation by BG&E of the investigation findings

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and recommendations.

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d.

Conclusions

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When considered individually, the deficiencies found in the crane testing were of minor

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safety significance. BG&E concluded that there was a high probability that the crane had

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been adequately tested to ensure its safe operation. When the deficiencies were considered

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together, however, BG&E decided that sufficient irregularities existed to justify re-

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performance of the testing. Inspectors concluded that the deficiencies were evidence of

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inadequate supervisory control and overall inattention to detail during the testing. The PRC

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demonstrated a strong questioning attitude and safety perspective in reviewing ETP changes.

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BG&E's corrective actions were appropriate to ensure a high level of confidence in the

validity of the crane testing and to affirm its commitment to quality to site personnel.

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S.O

SAFE'IT ASSESSMENT AND QUALITY VERIFICA'110N

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8.1

Plant Operations and Safety Review Committee

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The inspectors attended several Plant Operations and Safety Review Committee (POSRC)

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meetings. TS 6.5 requirements for required member attendance were verified. The meeting

agendas included procedural changes, proposed changes to the TS, Facility Change Requests,

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and minutes from previous meetings. Items for which adequate review time was not

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available were postponed to allow committee members time for further review and comment.

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Overall, the inspectors found that the committee members were well prepared and actively

participated in discussions. The committee's decisions consistently demonstrated a strong

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safety perspective.

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8.2

Review of Written Renons

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The mspectors reviewed LERs and other reports submitted to the NRC to verify that the

details of the events were clearly reported, including accuracy of the description of cause and

adequacy of corrective action. The inspectors determined whether further information was

required from the licensee, whether generic implications were indicated, and whether the

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event warranted onsite followup. The following LER was reviewed with respect to the

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requirements of 10 CFR 50.73 and the guidance provided in NUREG 102'-

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Units 1 and 2:

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LER 92-007 Revision 1

Safety Concern Involving Isolation of Pump Recirculation Flow

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for Testing

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Revision I was submitted to report the cause of the event, which was still under investigation

when the original LER was submitted, and to update the analysis of event and corrective

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actions. The inspectors determined that it was an accurate supplement to the original LER.

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8.3

Offsite Safety Review Committee

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On January 28, the inspectors attended portions of the Offsite Safety Review Committee

(OSSRC) meeting. The OSSRC composition and agenda were in compliance with the

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requirements of TS 6.5.4. All committee members were involved in the discussions of the

issues and reviews were thorough and insightful. The inspectors concluded that the function

of the OSSRC continued to be a strength.

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9.0

FOLLOWUP OF PREVIOUS INSPECTION FINDINGS

Licensee actions taken in response to open items and findings from previous inspections were

reviewed. The inspectors determined if corrective actions were appropriate and thorough and

previous concerns were resolved. Items were closed where the inspectors determined that

corrective actions would prevent recurrence. Those items for which additional licensee

action was warranted remained open. The following items were reviewed.

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9.1

(Onen) Violation 50-317 and 50-318/92-25-01: Improper High Radiation Area

Entries

NRC Inspection Report (IR) 50-317 and 50-318/92-25 discussed two improper entries into

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high radiation areas. These were characterized as two apparent TS violations (EEI 50-317

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and 50-318/92-25-01 and 02). As a result of the enforcement conference on

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December 2,1992, and further evaluation by the NRC staff, the events have been

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characterized as two examples of one violation (VIO 50-317 and 50-318/92-25-01).

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EE192-25-01 and 02 have been administratively closed. The violation is documented in a

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letter from Mr. T. Martin (NRC) to Mr. R. Denton (BG&E), Notice of Violation (IR Nos.

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50-317/92-25 and 50-318/92-25), dated January 21, 1993.

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9.2

(Closed) Unresolved Item 50-317 and 50-318/92-07-02: Core Flushing Concern

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This item concerned an apparent inadequate procedural method to prevent boric acid

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precipitation following certam loss of coolant accidents. The inspectors' review of this issue

is documented in Section 7.1.

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10.0 MANAGEMENT MEETING

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During this inspection, periodic meetings were held with station management to discuss

inspection observations and findings. At the close of the inspection period, an exit meeting

was held to summarize the conclusions of the inspection. No written material was given to

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the licensee and no proprie.tary information related to this inspection was identified.

An Enforcement Conference was held with BG&E on January 7 at the NRC Region I Office

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in King of Prussia, Pennsylvania, to discuss the significance of isolating emergency core

cooling pump minimum flow recirculation during surveillance testing at power. The

conference was open to the public. The issue was documented in NRC Inspection Report 50-

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317 and 318/92-27. Mr. R. Denton, Vice President - Nuclear Energy, and members of his

staff met with Mr. W. Hehl, Director of Reactor Projects, and members of the NRC staff.

The results of the conference were promulgated via separate correspondence.

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20.1

Preliminary inspection Findines

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Two violations were identified during spent fuel handling crane testing. One involved

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excessive overtime by several testing personnel (VIO 50-317 and 50-318/93-02-01). The

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other involved several examples of procedure noncompliance (VIO 50-317 and 50-318/93-02-

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02). Two non-cited violations were identified during the period. One involved an improper

change to a spent fuel handling crane test procedure. The other concerned an inadequate

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procedure for conducting core flushing following a LOCA.

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10.2

Attendance at Manacement Meetines Conducted by Recion Based Inspectors

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Inspection

Reporting

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Date

Sub1ect

Report No.

Inspector

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1/8/1993

Effluents

50-317/93-01

J.Jang

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50-318/93-01

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2/5/1993

EDSFI

50-317/93-04

R. Bhatia

Follow-up

50-318/93-04

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