ML20216E780

Insp Repts 50-498/97-05 & 50-499/97-05 on 970629-0809. Violations Noted.Major Areas Inspected:Licensee Operations, Engineering,Maint & Plant Support

ML20216E780
Person / Time
Site:	South Texas
Issue date:	09/09/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20216E725	List: ML20216E721 ML20216E766 ML20216E780
References
50-498-97-05, 50-498-97-5, 50-499-97-05, 50-499-97-5, NUDOCS 9709110069
Download: ML20216E780 (29)

See also: IR 05000498/1997005

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ENCLOSURE 2_  ;

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

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Docket Nos: 50-498, 50 499

License Nos: NPF-76, NPF 80

Report No: 50 498/97-05, 50-499/97-05

Licensee: Houston Lighting & Power Company

Facility: South Texas Project Electric Generating Station,

Units 1 and 2

Location: 8 Miles West of Wadsworth on FM 521

Wadsworth, Texas 77483

Dates: June 29 through August 9,1997

Inspectors: D. P. Loveless, Senior Resident inspector

J. M. Keeton, Resident inspector

W. C. Sifre, Resident inspector

D. B. Pereira, Project Engineer

R. A. Kopriva, Project Engineer, Branch A

Accompanying

Personnel: J. C. Edgerly, Resident inspector Trainee

Approved by: J l. Tapia, Chief, Project Branch A

Division of Reactor Projects

9709110069 970909

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G ADOCK 05000498

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EXECUTIVE SUMMARY

South Texas Project, Units 1 and 2

NRC Inspection Report 50-498/97-05;50-499/97-05

This resident inspection included aspects of licensee operations, engineering, maintenance,

and plant support. The report covers a 6 week period of resident inspection.

Qperatio_ns

• Control room operators performed their duties in a professional manner, were

attentive to control board indications, and maintained a good focus on safety

(Section 01.1).

• The licensee f ailed to track the Technical Specification action statements associated

with the inoperability of the hydrogen analyzer. This condition continued for 7 days

without identification by on shift operators (Section 01.2).

• A lack of understanding of corrective action for a previous event coupled with less

than adequate communications and attention to detail resulted in an inadvertent

partial drain down of the Unit 1 spent fuel pool (Section 01.3).

• Plant systems were maintained in good material condition. The instrument air

system and selected containment isolation valves were properly aligned

(Sections 02.1, O2.2, and 02.4).

• A reactor plant operator exhibited good attention to detail and safety system

knowledge by identifying low hydraulic fluid levelin a power operated relief valve

(Section O2.3),

• One example of an inadequate equipment clearance order resulted in an inadvertent

start of a Unit 2 essential cooling water screen wash booster pump while the

system was drained (Section 04.1).

Maintenance

• Planners failed to identify that painting of the air start solenoids could adversely

affect Standby Diesel Generator 11 operability (Section O2.1).

• In general, maintenance activities were performed in accordance with

management's expectations. However, several examples of the f ailure to properly

implement maintenance related programs were discussed (Section M1.1).

• Surveillance test procedures were well performed and properly irnplemented

Technical Specification surveillance requirements (Section M1.2).

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• Craftsmen did not initially remove plastic bags from containment as required by the

containment inspection procedure. A lack of understanding of previous corrective

actions caused plant workers to not fully understand requirements regarding loose

debris in containment (Section M4.1).

• A second example of the failure to establish a.1 effective equipment clearance order

boundary was identified when craf tsmen breached an unisolated portion of the

component cooling water system, in addition, craftsmen had prior opportunity to

identify this condition (Section M4,2).

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• The actions of the engineers in stopping the attempted removal of the essential

cooling water structure gantry crane was notable. The recalculation of the crane

weight and potential impact on operability of the essential cooling water systems

were considered to be conservative (Section E1,1).

• The licensee failed to perform adequate surveillance testing of the Pressurizer

Pressure Interlock P-11 (Section E2.1).

• The identification of surveillance testing inadequacies associated with

Permissive P-11 during an operational experience review was considered to be

excellent (Section E2.1).

• Maintenance and engineering personnel properly evaluated the causes of a fire that

initiated during a leak sealing evolution on main steam isolation Valve 2D, The

associated temporary modification package was properly developed and reviewed.

The use of an injection clamp during this evolution was considered conservative

(Section E2.2).

• The licensee failed to assure that all of the requirements of IEEE 338-1997,

Regulatory Guide 1.22, and Regulatory Guide 1.118, related to rer..aving the AFW

and containment spray systems from service, were correctly translated into the

applicable procedure for testing of the AFW system.

Plant Support

• Routine observations of radiological work practices indicated that controls were in

place and effective with one minor exception. Several contaminated area signs

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were not properly secured and had f allen down (Section R1.1).

• Routine observations of daily security force activities, secondary chemistry controls,

emergency response facility readiness, and meteorological tower operability

indicated appropriate management attention to these functional areas

(Sections R1.2, P2.1, P2.2, and S1.1).

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EgAort Details

Summary of Plant Status

At the beginning of this inspection period, Unit 1 was suberitical in Mode 2 after having

completed drop testing of the rod cluster control assemblies. The reactor was taken

critical at 12:04 a.m. on June 29, and Unit 1 was returned to full power on June 30. At

the end of this inspection period, Unit 1 was operating at 100 percent steady-state power.

Unit 2 operated at essentially 100 percent reactor power throughout this inspection period.

I. Operations

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01 Conduct of Operations

01.1 Control Room Observations (Units 1 and 2)

a. Insoection Scone (71707)

Using Inspection Procedure 71707, the inspectors routinely observed the conduct of

operations in the Units 1 and 2 control rooms. Frequent reviews of control board

status, routine attendance at shift turnover meetings, observations of operator

performance, and reviews of control room logs and documentation were performed. }

In addition to full power operations, the inspectors observed portions of the i

response to a Unit 2 fire in the isolation valve cubicle which occurred on July 15.

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b. Observations and Fininaq l

During routine observations and interviews, the inspectors determined that the

control room operators were continually aware of existing plant conditions,

Operators responded to annunciator alarms in accordance with approved

procedures. Annunciator alarms were promptly announced to the control room staff 4

who, in turn, acknowledged by restating the announcement. The inspectors

routinely attended shift turnover meetings. The on-shift operators provided clear

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and concise information to the oncoming operators. Oncoming operators routinely j

reviewed the control room logs, discussed current plant conditions, and verified  !

major equipment status.

On July 15, maintenance personnel were repairing a leak on Main Steam isolation

Valve 2D. The mechanics stopped work momentarily and exited the Isolation Valve

Cubicle (IVC) to take a break from the heat. A security officer entered the IVC as

part of his routine tour. Shortly after entering the IVC, the officer reported by

telephone to the Unit 2 control room that he observed a fire on the lagging adjacent j

to Main Steam isolation Valve 2D The inspector was in the control room when this

call was received and observed that the shift supervisor questioned the security

officer as to whether he observed smoke, steam, or a flame. The officer stated that I

he observed a small flame. As the shift supervisor was activating the fire brigade, a

second call came into the control room from the IVC. One of the mechanics

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reported that he used a fire extinguisher to put out the fire. The shift supers:sor

subsequently dispatched the fire brigade leader to verify that the fire was out and

notified management of the event.

The inspector discussed the questioning of the security officer with the shift

supervisor. The shift supervisor stated that the lagging was not flammable and he

was not aware of any other burnable materialin the vicinity of the valve. The shift

l supervisor also stated that a steam leak was much more likely to occur on the valve

l and would require different action than a fire.

The fire brigade leader determined that the fire was out. The inspector entered the

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IVC and observed that the fire had occurred on a small area of frayed logging where

some material from the leak repair had spilled. The mechanic stated that the

material usad in the leak repair was not supposed to burn. A condition report was

written to investigate the cause of thic event. The investigation and cause of this

event are discussed in Section E2.2 of this report. The shift supervisor posted a fire

watch in the area until no danger of reflash existed.

c. Conclusions

Licensed operators in the control room performed in a professional manner and were

continuously aware of existing plant conditions with a good focus on safety. Shift

turnover meetings were thorough and routinely attended by plant management. The

response to annunciator alarms was prompt and ac: urate. The Unit 2 shift

supervisor took prompt, conservative action in response to a reported fire in the

IVC.

01.2 incorrect Trackina of Technical Specification Action Statement

a. Insoection Scope (71707)

On June 18, a licensed operator discovered that an incorrect operability assessment

system (OAS) entry had been made when the Unit 2 Hydrogen Analyzer CM-4105

was found to be inoperable. The inspector reviewed Condition Report 97-10207,

the procedures associated with OAS entries, and corrective actions proposed by the

licensee,

b. Observations and Findinas

On June 11, Hydrogen Analyzer CM-4105 f ailed a surveillance test, indicating that

the analyzer was inoperable. Licensed operators created an OAS entry to track the

action statement associated with Technical Specification 3.6.1.4. This action

statement required that the analyzer be returned to service within 30 days or the

unit be shut down.

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However, the operators f ailed to recognize that Technical Specification 3.3.3.6 was

also applicable. This specification required that the accident monitoring function of

the hydrogen analyzer be returned to service within 7 days or the unit be placed in

hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

On June 18, during restoration of the hydrogen analyzer following corrective

maintenance, an operator discovered that the OAS entry did not include the most

restrictive Technical Specification action statement. Operators initiated Condition

Report 97 10207 to investigate the problem and determine the root cause and

corrective actions required. Although the 7-day allowed outage time had expired,

the hydrogen analyzer had been returned to service with approximately 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />

remaining in the 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> permitted to shut the unit down. In accordance with

guidance recently issued in Enforcement Guidance Memorandum 97-013, a

Technical Specification violation did not occur because the time clock of the action

statement had not expired.

The inspectors reviewed Plant General Procedure OPGP03 ZO-0039, Revision 9,

" Operations Configuration Management." Section 5.5 provided guidelines for

making OAS entries and stated, in part:

"When any of the following systems / components are remov3d from service,

THEN an OAS entry SHALL be initiated if the inoperability is expected to

extend beyond the current shift and the system / component is required for

the current plant mode.

a. Equipment required by Technical Specifications"

The operators violated this requirement in that they failed to identify and enter the

most restrictive Technical Specification action statement.

The corrective actions identified in the condition report require development of an

on-line program that would flag any applicable Technical Specification when making

OAS entries. Also, additional training of licensed operators in the identification of

multiple Technical Specification requirements has been proposed. This would be

conducted during applicable simulator training.

The inspector reviewed the violation and determined that: the violation was

identified by licensee personnel; corrective actions had been developed to ensure

that multiple Technical Specification requirements will be reviewed; the violation

was not a repeat of a previous violation or finding; and the violation was not willful.

Therefore, this non repetitive, licensee-identified and corrected violation is being

treated as a noncited violation, consistent with Section Vll.B.1 of the NRC

Enforcement Policy (NCV 499/97005 01).

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c. Conclusion

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The inspectors concluded that a violation of administrative requirements had j

occurred and was a result of less than adequate attention to detail to ensure that all

applicable Technical Specifications were considered when making OAS entries.

This condition existed for 7 days without identification by oncoming crews.

01.3 Inadvertent Partial Drain of SDent Fuel Pool (Unit 2)

a. Inspection Scone (71707)

On June 19, mechanical maintenance technicians placed a submersible pump in the

annulus between the inner and outer gates that separate the spent fuel pool and the

fuel transfer canalin Unit 2. The pump was installed to drain the annulus between

the gates to f acilitate postmaintenance testing of the inner gate seat. At 1:05 p.m.,

the Unit 2 control room received a Spent Fuel Pool Hl/LO Level alarm. Upon

investigation, the field supervisor found that the spent fuel pool level was

66 feet ( = 20.1 meters) mean sea level (mst), 2 inches ( = 5.1 centimeters) lower

than the earlier logged level. Water was draining from the spent fuel pool past the

uninflated inner gate seal, through the deenergized pump and hose into the fuel

transfer canal. The hose was removed, the gate seal was inflated, and the spent

fuel pool level restored. Condition Report 97-10274 was developed to address this

event. The inspectors reviewed this report and the associated procedures,

evaluations, and licensee investigations, f

b. Observations and Findinos

An event review team was assembled to investigate the event. The investigation

determined that upon completion of the inner gate seat replacement and prior to

inflating the seal, the craftsmen placed the submersible pump in the annulus

between the gates with a discharge hose going to the fuel transfer canal. At

approximately 11:30 a.m., the craf t energized and ran the pump for approximately

15 seconds to verify proper pump rotation. This was later determined to have

started a siphon pathway through the idle pump.

Next, the craftsmen contacted the unit supervisor to have an operator connect and

operate the air source to the sealin accordance with Plant Maintenance

Procedure OPMPO4 FH-0005, Revision 4, "In Containment Fuel Storage Area and

Spent Fuel Pool Gate Removal and Installation." The unit supervisor informed the

mechanic that an operator was not available. The craftsmen then informed the unit.

supervisor of the status of the job and Piat they would be leaving the area to break

for lunch. The unit supervisor directed the craftsmen not to run the pump until an

operator was present and the gate seal was inflated. However, the craftsmen f ailed

to inform the unit supervisor that they had momentarily run the pump. The siphon

continued to drain the pool.

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The inspector reviewed the condition report engineering evaluation to determine the

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postulated final level of the spent fuel pool if the siphon had continued undetected. l

In the evaluation, the engineering staff conservatively assumed the initial fuel l

transfer canal level was 3 feet ( = 0.91 meters) lower than the spent fuel pool level. l

The actual difference in level was approximately 2 feet (= 61 centimeters). Based

on the calculation, the lowest level the spent fuel pool could have achieved was

65 feet, 8 inches ( = 20.0 meters) msl. The minimum level permitted by Technical

Specifications was 62 feet (= 18.9 meters) msl. Therefore, the safety significance

of this event was low.

Although licensee personnel determined that the root cause of this event was

ineffective corrective action from a previous spent fuel pool siphoning event

(documented in NRC Inspection Report 50-498/95-23; 50-499/95-23), a lack of

understanding of potential siphoning effects and poor attention to detail also

contributed to the event. The corrective actions for the previous event did not

address the potential for personnel other than operators to be involved in activities

that could cause inadvertent siphoning of the spent fuel pool. Nevertheless,

adequate communications and oversight could have precluded a recurrence.

The corrective actions for this event included a revision to

} Procedure OPMPO4-FH-0005 to require that an operator be present to coordinate

the installation and operation of submersible pumps in the spent fuel poo'.

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c. Conclusions

Although of low safety significance, a repeat of a previous inadvertent siphoning

event represents a failure to adequately control the use of submersible pumps in the

scent fuel pool and connecting systems, a lack of understanding of potential

siphoning effects, poor communications, and less than adequate oversight of spent

fuel pool activities.

O2 Operational Status of Facilities and Equipment

O 2.1 Plant Tours (Units 1 and 2)

a. Inspection Scope (71707)

The inspectors routinely toured the accessible portions of plant areas in Units 1

and 2. Areas of special attention during this inspection period included:

• Units 1 and 2 auxiliary feedwater cubicles

• Standby diesel generator Rooms 11 and 12

• Unit 1 fuel +andling building

• lsolation Valve Cubicles 1 A,1D, and 2B

• Units 1 and 2 turbine generator buildings

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h. Observations and Findinas

in general, the inspectors observed that in both units, systems and components had

been maintained in good material condition. However, the inspectors noted several

minor labeling problems during a tour conducted inside the Unit 2 containment

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building. These inaccuracies were reported to the unit supervisor for correction. i

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On July 17, the inspectors toured Standby Diesel Generator 11. Painting activities j

were in progress in accordance with Work Authorization 97392. The work order

, authorized painting of the diesel below the catwalk and indicated that this would

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not affect critical components. During the tour, the inspectors noted a technician

painting one of the air start solenoids. Excessive paint on the vent screen of this

component could cause the failure of the diesel to start.

The inspectors discussed this with the unit supervisor. He stated that during the

prejob briefing, a prohibition on painting of screens had been emphasized, in

addition, he stated that the postmaintenance test would include an engine start and

run. However, the inspectors noted that a run of the machine was not documented

in the postrnaintenance test matrix of the work order. The unit supervisor ensured

that this was added to the package. The inspectors verified that this run was

satisfactorily conducted on July 28.

c. Conclusions

The inspectors concluded that the material condition of systems and components

observed in both units was noteworthy. The postmaintenance test matrix for

testing a standby diesel generator following painting did not consider that the air

start solenoids were critical components that could be adversely affected by

painting and did not require a diesel run to verify that this was not the case.

O2.2 pontainment isolation Valve Alianment

a. inspection Scoce (71707)

The inspector reviewed the coafiguration and status of containment isolation valves

as described in the Updated Final Safety Analysis Report Section 6.2.4 and

Figure 6.2.4-1. The described configuration was compared to associated piping and

instrumentation diagrams, and with Plant Surveillance Procedure OPSPO3-SI-0016,

Revision 2, " Containment Integrity Checklist." The inspectors also verified the

configuration of valves associated with the isolation of a sample of mechanical

penetrations,

b. Observations and Findinas

The inspectors verified that the sample of penetrations were aligned property. All

penetrations identified in Figure 6.2.4-1 were shown in the positions indicated in the

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piping and instrumentation diagrams. However, several discrepancies were noted.

Penetrations M 71 and M 87, the integrated leak rate test penetrations, were not

shown on Figure 6.2.4-1. The inspectors verified that the penetrations were still

installed and required a locked-closed valve and a blank flange to provide

containment isolation.

During a review of Procedure OPSP03-St-0016, the inspectors noted that the

manual valves associated with 10 penetrations were not included on the outside

containment integrity checklist. The following penetrations were affected:

e Three trains of component cooling water to the residual heat removal system

e Penetration M-33

e Penetration M 35

e Penetration M-37

e Three trains of component cooling water to the reactor containment fan

coolers

e Penetration M-24

• Penetration M-25

e Penetration M-27

e Four trains of auxiliary feedwatar to the steam generator

e Penetration M-28

e Penetration M-84

• Penetration M-94

e Penetration M-95

Procedure OPSP03-SI 0016 implemented the requirements of Technical

Specification Surveillance Requirement 4.6.1.1.a. This specification required that:

Primary containment integrity shall be demonstrated at least

once per 31 days by verifying that all penetrations not capable

of being closed by operable containment automatic isolation

valves and required to be closed during accident conditions are

closed by valves. blind flanges, or deactivated automatic

valves secured in their positions

Licensee engineers stated that the penetrations addressed were not required to be

closed during accident conditions. Therefore, the specification was not considered

applicable to the 10 subject penetrations. However, the inspectors noted that

certain manual valves providing isolation of piping within the penetration isolation

scheme were not capable of automatic closure and were required to be closed

during accident conditions.

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The applicability of Technical Specification 4.6.1.1.a to the manual valves

associated with the 10 subject penetrations will be reviewed further by the NRC in

addition, licensee personnel were reviewing the two penetrations not documented in

the Updated Final Safety Analysis Report. These issues will be tracked as an

unresolved item (URI 498:499/97005-02).

c. Conclusions

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Two mechanical containment penetrations were not described in Figure 6.2.4-1 of

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the Updated Final Safety Analysis Report. The applicability of Technical i

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Specification 4.6.1.1.a to the manual valves associated with 10 containment l

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l 02.3 Reactor Plant Operator Tours (71707)

The inspectors routinely discussed plant conditions with the reactor plant operators

in the field. On July 31, a reactor plant operator identified low hydraulic fluid level

in the Steam Generator Power Operated Relief Valve 2B actuator during his routine

rounds. The valve was declared inoperable and removed from service and

subsequently repaired. The reactor plant operator exhibited good attention to detail

and safety system knowledge.

02,4 Enoineered Safetv Features Walkdown of instrument Air System (71707)

On July 20, the inspectors performed a walkdown of the instrument air systems

from the compressors to the distribution headers in Units 1 and 2. The material

condition of the systems was good. Minor deficiencies were identified and

appropriately documented by the licensee staff. The system flow path was verified

to be in accordance with Piping and Instrumentation Diagrams 80119F00048

Sheet 1 and 8Q119F00049. No alignment discrepancies were identified and the

system components appeared to be in good condition,

c. Conclusion

Although the AFW system would not respond following a valid engineering safety

features signal during operability testing of the engineered safety features actuation-

system slave relays, the licensee was conducting its AFW system testing in

accordance with Regulatory Guide 1.22. The licensee has decided to install a field

change to install a second slave relay which will allow actuation of the AFW system

during operability testing.

Although the bypassing of the AFW for testing purposes was not annunciated in the

control room, as required by lEEE Standard 378,1997, the licensee appropriately

entered the Technical Specification 3.7.1.2 applicable action statement for each

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AFW test. This action was noted and tracked by control room operators to

completion. The licensee tracked the restoration s: :us to restore the system

following completion of the slave relay test.

The AFW steam-driven pump testing requires the inlet valves to be isoitted by

opening fused disconnects to prevent the pump from starting. This opening of the

fused disconnects for the inlet valves does not trip the associated protection system

channel nor does it cause the startup and operation of the associated Class 1E loac

group. Therefore, the AFW steam driven pump bypass testing does not fully

conform to Regulatory Guide 1.118 since removal of the disconnect fuses does not

cause the startup and operation of the associated Class-1E Ic,od group. However,

the licensee had initiated a design change which willinstall a second slave relay,

which will negate any further removal of the fused disconnects.

The licensee's failure to assure that all of the requirements of IEEE 338-1997 and

Regulatory Guide 1.118 were correctly translated into the applicable procedure for

testing of the AFW system was a noncited violation.

The inspector reviewed the issues identified in the condition reports and determined

that they were not reportable in accordance with 10 CFR 50.73 because, overall,

the AFW system was not outside its design basis. The removal of each AFW

system during testing was conducted in accordunce with the Technical

Specification 3.7.1.2 action statement, noted in the control room, and tracked to

completion.

04 Operator Knowledge and Performance

04.1 Essential Coolina Water Screen Wash Booster Pumo 2A Inadvertent Start

On June 24, the Unit 2 operating staff removed the Train A essential cooling water

system from service and established Equipment Clearance Order 97-76518 for

planned maintenance activities. The system was also drained to support the

maintenance activities. One of the maintenance activities was the replacement of a

relay in the screen wash booster pump logic circuit in accordance with Design

Change Package 95 14323-4. During the relay installation, Screen Wash Booster

Pump 2A, a safety-related pump, inadvertently started. Condition Report 97-10415

was developed to address the failure of Equipment Clearance Order 97-76518 to

prevent the pump from starting with the system drained.

The pump operated for approximately ten minutes with the system drained before it

was secured by a control room operator. Following completion of maintenance

activities and filling and venting of the essential cooling water system, Screen Wash

Booster Pump 2A was tested. All acceptance criteria for flow, pressure, and

vibration were met in accordance with Plant Surveillance

Procedure OPSPO3-EW-OO17, Revision 10, " Essential Cooling Water Train A

Testing." Personnel safety was not affected since there was no work being

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performed on the pump or screen wash system during the inadvertent start. This

event was the result of an inadequate equipment clearance order boundary.

The inspectors reviewed t)lant Gt < ral Proce. dure OPGP03-ZO EC01, Revision 6,

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" Equipment Clearance Orders." Procedure OPGP03-ZO-ECO1 required that

equipment clearance orders provide adequate boundaries to ensure personnel safety

and equipment integrity. The execution of Equipment Clearance Order 97-76518

did not properly implement this safety-related procedure. The f ailure to properly

implement this safety-related procedure was the first example of a violation of

Technical Specification 6.8.1 (499/97005 04),

ll. Maintenance

M1 Conduct of Maintenance

M 1.1 General Comments on Field Maintenance Activities

a. inspection Scope (62707)

The inspectors observed portions of the following on-going v/ork activities identified

by their work authorization numbers:

Unit 1:

• 95013550 Bench Test Charging Pump Cooler Air Handling Unit 11 A/

Component Cooling Water Return Pressure Relief Valve

(June 30)

• 114733 Rod Cluster Control Assembly Tool Repairs (July 17,21)

• 347683 Residual Heat Removal Pump 1B Flange Leak Repair and

Impeller inspection (July 21)

Unit 2:

• 114761 Steam Generator 2A Main Steam Pressure Low Alarm

Lead / Lag Card and Comparator Card Replacement and

Calibration (July 16)

• 3478i8 Steam Generator 2D Main Steam Isolation Valve has a Small

Hissing Steam Leak at the Body-to Bonnet Flange

b. Observations and Findinas

in general, the inspectors found the work performed during these activities thorough

and conducted in a professional manner. The work was performed by

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knowledgeable, qualified technicians utilizing approved procedures. Supervisors

were observed providing an appropriate level of oversight. System engineers were

observed providing quality technical support as needed. Prejob briefings were ,

thorough and radiological controls were in place where applicable. However, '

exceptions to these general findings were identified as discussed below and in

Sections M4.1, M4.2, and MB.1 of this inspection report.

During the observation of activities being performed in accordance with Work

Authorization Number 95013550, the inspectors noted several minor discrepancies.

Worker understanding of the procedural requirements was weak. Measurements

taken were not precise enough to measure the stated parameter. The inspector

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observed several minor deviations from the procedure during this performance. l

Although workers deemed the actions to be technically equivalent to the procedural

requirements, the inspector discussed expectations for procedural compliance with

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On July 22, the inspectors observed portions of the leak sealant injection performed

on main steam isolation Valve 2D The injection was being performed by contract

personnel in accordance with Temporary Modification TL2 97-8224-2. The work

was properly performed by qualified technicians with proper oversight by licensee

supervisory personnel. The work was performed utilizing the appropriate nuclear

grade leak sealant and was conducted in accordance with the vendor procedure, as

revised. The review of an earlier event associated with this work activity was

documented in Sections 01.1 and E2.2 of this report.

c. Conclusions

in general, the observed maintenance activities were conducted in a professional

manner, Personnel involved were thorough and met management's expectations for

the implementation of the maintenance program. However, several minor

discrepancies were observed during the testing and replacement of a relief valve.

M1.2 General Comments on Surveillance Testino

a. Insnection Scope (61726)

The inspectors observed portions of the following surveillance activities:

Unit 1:

Plant Surveillance Procedure OPSP03-AF-0003, Revision 6, " Auxiliary

Feedwater Pump 13(23) Inservice Test"

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Unit 2:

• Plant Surveillance Procedure OPSP02 RC-0455, Revision 5, " Pressurizer

Pressure ACOT"

b. Observations and Findinas

I

The inspectors found that the observed surveillance activities were performed in

accordance with approved procedures. The inspectors verified that the test

equipment calibrations were current. Good communications between the control

!

room operators and personnel performing the tests were noted. Pretest briefings

were thorough and comprehensive. During the testing of Auxiliary Feedwater

,

Pump 13, the inspectors noted several r*nor material deficiencies associated with

valves in the pump discharge flowpath. .hese were reported to the reactor plant

operators performing the test and conditica reports were written to correct the

problems. In addition, the performance of Procedure OPSP02 RC-0455 was further

discussed in Sections M8.2 and E2.1 of this inspection report.

c. Conclusions

The surveillance activities observed were performed in accordance with the

applicable Technical Specification surveillance requirements and approved

procedures. Minor material deficiencies associated with system valves were

documented for correction.

M4 Maintenance Staff Knowledge and Performance

M4.1 Plastic Materials in Containment

a. insoection Scope (61726)

On July 21, the inspectors observed the performance of work on Residual Heat

Removal Pump 1B performed in accordance with Work Authorization

Number 347683. Upon completion of a containment entry, the craftsmen removed

their equipment and performed a visualinspection of the area in accordance with

Plant Surveillance Procedure OPSP03 XC-0002A, Revision 1, " Partial Containment

inspection (Containment integrity Established)." The inspector nuted that the

craftsmen had left three plastic bags containing vibration probes. The craftsmen

stated that bagging and leaving instrumentation was a standard practice. However,

the unit supervisor was notified and he directed that the bags be removed. The

inspectors reviewed this occurrence.

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_ b. Observations _ and Findinns

Procedure OPSP03-XC-0002A, Form 2, Step 3.0 stated that the craf tsmen shall,

" Perform an inspection of the affected portion (s) of

Containment AND travel route (s) to and from the work area (s)-

and ensure NO loose materialis present. Document any

discrepancies in the Remarks section of this form."

!

The procedure defines loose debris as, "any material that could become debris and

possibly contribute to blocking the Emergency Sump Screens during Design Basis

Accident conditions in Containment."

The failure of the craftsmen to initially remove the plastic bags from the work site

was not a violation because the inspector prompted them to further evaluate the

condition. In addition, the contribution of three plastic bags to blocking the sump

screens would be negligible. However, this occurrence indicated that conflicts

existed between work procedures cr.d the containment inspection procedures. As

documented in NRC inspection Report 50 498/97 02;50-499/97 02, previous

problems associated with containment inspection had been cited as a repeat

violation. Licensee corrective actions, at that time, had not been adequate to

ensure that materials were properly removed from primary containment, The

inspectors expressed concern that workers still did not understand the Technical

Specification requirements to remove allloose material from containment.

In discussions with severalindividuals, the inspectors noted that some workers

misunderstood provisions of Revision 1 to Procedure OPSP03 XC-OOO2A. The

procedure stated that, "any material discovered must be removed from the RCB and

evaluated by a Senior Reactor Operator." Addendum 1 then provided the senior

reactor operator with guidance for evaluating the condition. The individuals

interviewed stated that if material met the acceptance criteria delineated in the

guidance that it was acceptable to leave the materialin containment. This did not

conform with the procedural requirements.

Maintenance personnel documented the occurrence in Condition Report 97-11630.

The licensee determined that the apparent cause of the event was the failure of the

instrumentation and controls technicians to communicate their intent to leave the

bags in containment with the unit supervisor. C ,rrective actions proposed included

shop discussions of the event and of the requirements of

Procedure OPSP03 XC-0002A.

c. Conclusions

Maintenance personnel failed to initially remove plastic bags from containment upon

completion of a containment entry. The inspectors determined that a lack of

understanding of previous corrective actions caused maintenance workers to not

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fully ensure that allloose material was removed from containment. Conflicts

between standard work practices and the containment inspection requirements

went unchallenged. ,

M4.2 Inadeouate Eauipment Clearance Order for Residual Heat Removal Pumn 18

Maintenance Activities

a. inspection Scoce (62707)

!

On July 21, the inspectors observed portions of the Residual Heat Removal

Pump 1B flange leak repair and impeller inspection. During the pump disassembly,

mechanical maintenance personnel disconnected the component cooling water lines

to the pump seal cooler and observed considerable flow of water from the lines.

The mechanics initially attributed the water to the draining of long lines to the

isolation valves. When the flow did not subside, the mechanics realized that the

component cooling water system had not been isolated. They promptly

reconnected the component cooling water fitting to stop the leak and contacted

their supervisor and the control room. The inspectors reviewed this event, the

c

licensee's response, and the associated documentation,

b. Observations and Findinaq

When the crew began the pump disassembly, the health physics technician asked

one of the mechanics if the line connected to the seal cooler was a contaminated

system. The mechanic stated that it was component cooling water and was not

contaminated. He also stated that they would have to disconnect the line. The

inspector asked the mechanic if the component cooling water system boundary was

part of Equipment Clearance Order 97 1-71609. The mechanic stated that he

would walk down the component cooling water portion of the equipment c!sarance

order because he was not certain that the line was included in the equipment

clearance order. After this discussion and before disconnecting the component

cooling water line, the mechanics took a break and exited the reactor containment

building.

As the mechanics resumed the pump disassembly, the inspector observed water

dripping from the seal cooler fittings as they were being loosened. When the

inspector questioned the mechanics about the water, one of the mechanics stated

that the drainage was expected because the line between the seal cooler and the

equipment clearance order boundary valve was long. Within a minute it became

clear to the mechanics that the water flow was not decreasing and they

reconnected the line to stop the leakage. The lead mechanic stopped the job and

determined that the component cooling water line was not included in the

equipment clearance order. The equipment clearance order was revised, the line

isolated, and the work completed as planned.

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Condition Report 97-11659 was developed to address the inadequate equipment

clearance order. This event was identified as a significant condition adverse to

quality, and an event review team was assembled to determine root cause and

recommend corrective actions. The event review team identified the following root

causes:

The work package did not identify the need to establish a component cooling

water boundary,

o The job scope was not fully understood by either the equipment clearance

order preparer nor reviewer,

• The equipment clearance order acceptor did not adequately walk down the

boundary.

The inspectors reviewed Plant General Procedure OPGP03 ZO ECO1, Revision 6,

" Equipment Clearance Orders." Procedure OPGP03-ZO ECO1 required that

equipment clearance orders provide adequate boundaries to ensure personnel safety

and equipment integrity. The execution of Equipment Clearance Order 97 1-71609

did not properly implement this safety-related procedure. The f ailure to properly

implement this safety-related procedure was the second example of a violation of

Technical Specification 6.8.1 (498:499/97005-04).

c. Conclusions

This event and the event discussed in Section 04.1 of this inspection report have

!

regulatory significance because equipment clearance orders establish necessary

boundaries to protect critical equipment and to ensure personnel safety. Both of

these events were of low safety significance because the consequences were

relatively inconsequential. However, the f act that neither personnel safety nor

equipment integrity were jeopardized cannot be attributed to the equipment

clearance order quality. This event-disclosed, non-repetitive, licer.;ee corrected

violation is being cited because the licensee had prior opportunity to identify the

inadequate equipment clearance order when the mechanics discussed the need to

walk down the component cooling water boundary.

M8 Miscellaneous Maintenance items (92902)

M8.1 Use of liftino Device Without Procer Insoection (93001)

On July 17, during an observation of activities being performed under Work

Authorization Number 114733. The inspectors observed a problem associated with

the use of a temporary lifting device. Workers in the fuel handling building

determined that an additional hoist was desirable while removing a iefueling tool

from the spent fuel pool. An electric hoist attached to a rail-mounte d trolley on the

refueling machine was utilized. The inspector asked the craftsmen and operators

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present and was informed that no one had performed a daily inspection of the

trolley, as required by the licensee's lif ting program. Management was informed of

the problem, and Condii.on Report 97 12532 was written to document the

occurrence and evaluate appropriate corrective actions.

M8.2 (Closed) Licensee Event Renort 50-498/97-007: Engineered Safety Features

Actuation System Pressurizer Pressure System Interlock Not Fully Tested by

Surveillance

This event was documented in Section E2.1 of this inspection report. The

licensee's corrective actions included. immediate implementation of Technical

Specification surveillance requirements; revision and reperformance of the

appropriate surveillance test procedures; additional training for surveillance

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procedure writers; and the addition of new testing methodology in the surveillance

procedure writer's guide to be completed by December,1997.

Ill._ Enaineering

l E1 Conduct of Engineering

E1,1 Removal and Dismantlina of Crane Attached to Seismic Structure

a. Insoection Scooe (375511

The inspectors reviewed the documentation associated with the removal of the

essential cooling water intake structure gantry crane. The potential for a large load

drop on the roof of the seismic structure was evaluated. The following documents

were reviewed:

e Unreviewed Safety Question Evaluation 97-0023, " Load Drop Evaluation for

ECW Gantry Crane Removal."

e Condition Report Engineering Evaluation (CREE) 97-7961-2

e Calculation CC-8411, Revision 1

e Plant Change Form PCF334999A

Plant General Procedure OPGP03-ZA-0069, Revision 9, " Control of Heavy

Loads"

b. Observations and Findinas

On July 22, an attempt was made to remove the gantry crane from the essential

cooling water intake structure. The lift attempt was terminated when the mobile lift

crane's load cellindicated that the load was at the administrative limit allowed by

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CREE 97 796112 and CREE 97-7961-6 and near the safe operating limits of the

mobile lift crane for the operating radius and boom length. The gantry crane was

then unhooked from the rigging and returned to the tie-down location where it was

secured to the tie down lugs until further evaluation could be performed.

The permanent seismic rail clips had been cut to allow the gantry crane to be lifted.

CREE 97 7961-8 was generated to evaluate the impact of the removal of the

seismic clips, the increased gantry crane weight, and a revised removal method

using two crancs. The original weight calculation was based on weight of the steel

in the crane components and had not considered that concrete had been added to

! the trolley after construction for tornado considerations. The revised calculations

) took the weight of the concrete into account.

The possible load drop effects upon the essential cooling water roof structure and

adjacent commodities was reevaluated. In the anchored position, the gantry crane

was determined to be adequately secured to resist seismic, as well as tornadic,

loading without the seismic clips. The response of the crane to a postulated

seismic event during gantry crane travel was also evaluated. A conservative,

bounding analysis was used to demonstrate that a worst-case collapse scenario

would not result in unacceptable consequences. An actual collapse was considered

very unlikely by engineering judgment. The analysis showed that the roof could

withstand the collapse impact with no loss of function.

The calculation was revised to consider a load drop of the 145 ton

(131.5 metric ton) crane, and a collapse onto the roof. This assumed that the

weight of the crane above the legs was 55 tons (49.9 metric tons),36 percent

more than the 40.5 tons (36.7 metric tons) used in the original calculation. Both of

these conditions (drop and collapse) were shown to be acceptable. The actual

measured weight was found to be 104.5 tons (94.8 metric tons), significantly less

than the 145 tons (131.5 metric tons) that the roof could withstand based on the

3 foot load drop analysis.

The gantry crane was removed on July 25 in accordance with PCF 33499A and

CREE 97-79618 without affecting the operability of any of the essential cooling

water system trains,

c. Conclusions

The actions of the engineers in stopping the attempted removal of the essential

cooling water intake structure gantry crane with a single mobile crane was good.

The recalculation of the crane weight and the assessment of potential impact on

operability of the essential cooling water systems were conservative. Engineering

support was timely.

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E2 Engineering Support of Facilities and Equipment

E 2.1 Operability of Pressurizer Pressure Interlock P-11 (37551. 627021 j

On July 7, the inspector observed technicians verify the operability of Pressurizer

Pressure Interlock P-11 utilizing a revised Procedure OPSP02-RC-0455. On

June 19, engineers performing an operational experience review had identified

deficiencies in the previous testing methods. Permissive P-11 had been declared

inoperable and Technical Specification 3.3.2 Action 21 had been implemented to

ensure that the interlock was in its required state. The technicians were

knowledgeable of the system and the appropriate testing methods. The permissive

was properly tested and returned to service. Observed indications verified that the

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permissive had been properly returned to service. The inspectors determined that

the identification of this condition resulted from a quality operational experience

review process.

As documented in Section M8.1 of this inspection report, the licensee properly

reported this problem in Licensee Event Report 50-498/97-007. However, the

f ailure to properly test Permissive P-11, prior to June 19,1997, in accordance with

f

Technical Specification Surveillance Requirement 4.3.2.1, Table 4.3.2 was a

I violation. -This licensee identified and corrected violation is being treated as a

noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy

(498:499/97005-05).

E2,2 Fire Durina Hioh Temocrature Leak Sealino Activities

a. Insoection Scone (93702. 37551)

On July 15, a small fire was discovered on the insulation surrounding Main Steam

isolation Valve 2D during steam leak sealing activities. The crew performing the

leak sealing activities left the area following a series of leak sealant injections.

Shortly thereafter, a security officer making a routine patrol of the area observed the

flames and contacted a nearby mechanic. The mechanic extinguished the flame

with a fire extinguisher. The fire brigade was notified, the insulation removed, and

the embers extinguished. The inspectors reviewed the licensee's response to and

evaluation of the event; the event review team's report; and the temporary

modification package associated with the leak sealing activity.

b. Observations and Findinas

An event review team noted that the material safety data sheet indicated that the

leak sealant material should not have caught fire in the specific application nor at

the piping temperatures encountered. The team determined that mineral oilin the

leak sealant material had leached out from under the injection clamp and collected in

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the fiberglass insulation. The conditions were then sufficient to cause the oil to

autoignite. Licensee engineers stated that the spontaneous ignition of oil soaked l

insulation can occur under the following conditions:

• The liquid is insufficiently volatile to evaporate rapidly.

• The insulation is sufficiently porous to allow oxygen to diffuse to the surface

of the absorbed liquid.

• The oil leak is slow enough that the pores of the insulation are not blocked

thereby excluding oxygen from the high temperature region.

The inspectors reviewed the licensee's corrective actions, which meluded, notifying

other plants of the possibility for the leak sealant material to autoignite under certain

l conditions.

The inspectors reviewed Temporary Modification Package TL2 97-8224-2, which

approved the installation of the injection clamp and sealant materials. The

modification package designated a limited amount of leak sealant that could be

utilized without additional reviews. A screening of the taodification was performed

which met the requirements of 10 CFR 50.59. Appropriate evaluations of the

weight of the clamp and associated piping stresses were also performed. The

inspector also determined that the use of an injection clamp vice direct injection of

the flange was conservative,

c. Conclusions

Maintenance and engineering personnel properly evaluated the causes of a fire that

initiated during the leak sealing evolution. The cause and the scientific phenomena

were fully understood. The associated temporary modification package was

properly developed and reviewed and utilized a conservative leak sealing technique.

The requirements of 10 CFR 50.59 were met prior to modifying plant equipment.

E2.3 Desian of the Auxiliary Feedwater System related to Enaineered Safetv Features

Testina (37551)

a. Insoection Scone

The inspector reviewed Condition Reports 9614496 and 96-16132 that identified

severalissues regarding compliance of the Auxiliary Feedwater (AFW) System

design with industry standards during Engineered Safety Features (ESF) testing. On

November 20,1996, during a licensee review of Updated Final Safety Analysis

Report (UFSAR) Section 7.3, licensee engineers identified that the AFW system

testing circuitry did not appear to meet the requirements of Regulatory Guide 1.118

and IEEE Standard 338-1977. The licensee initiated Condition Report 96-14496 on

November 20,1996, to identify the issues with AFW system testing. Condition

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Report 96 16132 was initiated on December 19,1996, to prepare a modification

evaluation package that would determine the impact of modifications to correct the

deficient conditions.

The condition reports indicated that actuation test signals applied to the AFW

system would cause the system to start and feed water to the steam generators. In

order to prevent this action during testing, the system would be isolated with fused

disconnects opened. As a result of a review of UFSAR Section 7.3, the licensee

found that the design did not appear to be in accordance with Regulatory Guide

1.118 and its associated IEEE Standard 338-1977. UFSAR Table 3.12-1 indicated

that the licensee conformed to this regulatory guide in addition, the condition

l- report indicated that the associated IEEE standard required the generation of a

system level " bypass /inop" annunciator whenever a system was taken out of

service. This did not occur during testing of the AFW system. The concern also

applied to the safety injection and the containment spray systems whenever

Refueling Water Storage Tank Outlet Valve SI MOV-0001 was closed, it appeared

that only the safety injection system level bypass /inop window on the control board

was activated.

The inspector reviewed Condition Reports 9614496 and 9616132 and discussed

this review with appropriate operations, system engineering, licensing, and

management personnel,

b. Observations and Findinag

The condition reports documented that the bypassing of the AFW for testing

purposes was not annunciated in the control room. There are no annunciators for

the manual discharge valves being shut, nor for the AFW steam driven pump inlet

valves opened fused disconnects. As such, the AFW motor-driven pump bypass

testing did not fully conform to IEEE Standard 338-1977, which required that each

test bypass condition utilized at a frequency of more than once a year _ shall be

individually and automatically indicated to operators in the main control room in

such a manner that the bypassing of a protective function is immediately evident

and continuously indicated.

In both cases (fused disconnects or closed manual discharge valves) the inspector

determined that because each system is isolated, the AFW system is in a bypass

condition, The inspector also determined that this design flaw was applicable to the

containment spray system, whenever _ Valve SI-MOV-0001 was closed. ' Although

this condition is not automatically indicated to the operator in the main control

room, when the system is bypassed, the inoperable status of the AFW train is

logged and monitored by the operations personnel via the Technical

Specification 3.7.1.2 action statement. The licensee had developed a field change

to install a second slave relay that willinactivate the discharge motor-operated

valve in the respective train. The field change had been scheduled to be

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implemented during 1998 and 1999 refueling time frames. Once the second slave

relay is installed, the system design will be in compliance with IEEE Standard 338-

1977, because no manual or fused disconnects will be used. In addition, a valid

engineered safety features signal will override the slave relay and activate the AFW

train in test. However, this is the first example of a failure of the licensee to

implement the design commitments related to the AFW and containment spray

systems.

The licensee also identified that the AFW steam driven pump bypass testing does

l not conform to Regulatory Guide 1.118, Section C.6.b, which stated that

". . Removal of fuses or opening a breaker is permitted only if such action causes

(1) the trip of the associated protection system channel, or (2) the actuation

(startup and operation) of the associated Class-1E load group." Because the

removal of the inlet valve disconnect fuses does not cause the startup and

operation of the associated Class-1E load group, the AFW system bypass testing

does not fully conform to Section C.6.b.

The inspector noted that a potential existed for an operator to reposition the inlet

'

valve disconnect fuses should an accident occur during testing. However, this

makeshift test setup, although not significant, does represent a deviation from the

regulatory guide recommendations. Again, once the second slave relay is installed,

the licensee will not remove the inlet valve disconnect fuses and they will be in full

compliance with Regulatory Guide 1.118. Similar to the previous item, the licensee

had identified this discrepancy and had implemented corrective actions to resolve

the condition. This is a second example of a failure to implement the design

commitments from Regulatory Guide 1.118 into the AFW system design.

-The inspector also reviewed the related requirements of Plant Surveillance

Procedure OPSP03 SP-OOO9A, Revision 6, "SSPS Actuation Train A Slave Relay

Test." In order to prevent injection of water into the steam generators during

protection system testing, the following actions were accomplished in accordance

with this test procedure:

the AFW line for the respective motor-driven pump was isolated by shutting

a manual isolation valve; and

the steam driven pump was isolated by opening fused disconnects to the

inlet valve to prevent the steam driven pump from starting.

The inspector confirmed that the current testing method prevented actuation of the

motor-driven AFW train as a result of shutting of the train's manual discharge

isolation valve. The actuation of the steam-driven AFW train is similarly bypassed

by opening the inlet valve disconnect fuses, which prevents steam entering the

turbine. A licensee engineering evaluation conducted in December 1996, indicated

that Regulatory Guide 1.22, " Periodic Testing of Protection System Actuation

Functions," Section D, " Regulatory Position," allowed this type of bypass testing to

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occur. The inspector noted that Section 2.c of the Regulatory Guide indicated that $

acceptable methods of including the actuation devices in the periodic tests of the y

protection system include preventing the operation of certain actuated equipment  !

during a test uf their actuation devices. In addition, Subsection b of the Regulatory

Guide indicated that acceptable methods of including the actuation devices in the

periodic tests of the protection system included testing all actuation devices and .

actuated equipment individually or in judiciously selected groups. f

Based on a review of Regulatory Guide 1.22, the inspector confirmed that the

licensee was conducting the,r actuation device testing in accordance with the

regulatory guidance and that the bypass testing was acceptable. However, the

inspector noted that this testing methodology did not specifically meet the

description provided in the original FSAR design. UFSAR 7.3.1.2.2.5.4.5 stated

that automatic actuation circuitry will override testing activities and actuate the

system. The licensee had identified this discrepancy and had decided to install a

field change to install a second slave relay which would inactivate the discharge

motor operated valve in the respective train. The field change had been scheduled i

to be implemented during the 1998 and 1999 refueling outage time frames. This is ,

a third example of a f ailure to implement the design commitments from applicable

regulatory guidance into the AFW system design,

10 CFR Part 50, Appendix 0, Criterion Ill, " Design Control," requi:as, in part, that

measures be established to assure that applicabla regu4 tory requirement 9 be

correctly translated into specifications, procedures, and instructions. The three

examples of the licensee's failure to assure that all of the requirements of IEEE 338 I

1997 and Regulatory Guide 1.118 were correctly translated into the applicable

procedures for testing of the AFW system represents a violation of Ca.terion til of

Appendix 0 to 10 CFR Part 50. However, the inspector determined that: the

violation was identified by licensee personnel; corrective actions had been  ;

developed; the violation was not a repeat of a previous violation or finding; and the

violation was not willful. Therefore, this noi. repetitive, licensee identified and

corrected violation is being treated as a noncited violation, consistent with

Section Vll.B.1 of the NRC Enforcement PoMy (NCV 498;499/97005 fix

numbering ' * ).

'

In light of these findings, the inspector questioned whether these issues required a

report to the NRC in accordance with 10 CFR 50.73(a)(2)(ii)(B), which stated that

the licensee shall report any condition that was outside the design basis of the

plant. The inspector noted that on November 26,1996, the licensee had generated

a reportability review for Condition Report 96 14496, wherein they concluded that

the AFW system testing deficiencies were not reportable. The licensee stated that

the testing of the AFW system was done with the system properly removed from

service in accordance with the Technical Specifications, and that the testing

ac.cluately tests the system components in accordance with the Technical

Specification requirements.

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The inspector agreed with the licensee determination that the issues were not

reportable because the testing of the AFW system was conducted with the

applicable train properly removed from service in accordance with the Technical

Specification 3.7.1.2 action statement. Based on the redundancy of having four

trains, there was always a suf ficient number of trains available, such tha' the AFW

system was not degraded during the testing of one train of the system. In addition, i

the AFW train was taken out of service for testing with the full knowledge of all 1

operators and monitored by entry in the control room log of the Technical

Specification action statement. There were no ESF actuations involved. The

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testing conditions did not result in an inability to mitigate an accident or maintain

safe shutdown (three remaining AFW systems were operable and only one AFW

system is required to achiove safe cooldown), nor did it involve potential common

mode failure mechanisms. Therefore, none of the other 10 CFR 50.73 criteria

apply.

c. Conclusion

Although the bypassing of the AFW system for testing purposes and isolating the

containment spray system suction was not annunciated in the control room, as

required by IEEE Standard 378,1997, licensed operators appropriately entered the

Technical Specification 3.7.1.2 applicable action statement for each AFW test. This

action was noted and tracked by control room operators to completion. The

licensee tracked the restoration status to restore the systern following completion of

the slave relay test.

The AFW steam driven pump design requires the inlet valves to be isolated during

testing by opening fused disconnects to prevent the pump from starting. This

opening of the fused disconnects for the inlet valves does not trip the associated

protection system channel nor does it cause the startup and operation of the

associated Class 1E load group. Therefore, the AFW steam driven pump bypass

testing does not fully conform to Regulatory Guide 1.118 because removal of the

disconnect fuses does not cause the startup and operation of the associated

Class 1E load group. However, licensee engineers had initiated a design change

that would install a second slave relay. This action would negate any further

removal of the fused disconnects.

Although the AFW system would not respond following a valid engineering safety

features signal during operability testing of the engineered safety features actuation

system slave relays, the licensee was conducting its AFW system testing in

accordance with Regulatory Guide 1.22. The licensee has decided to install a field

change to install a second slave relay that would allow actuation of the AFW

system during operability testing.

The licensee's failure to assure that all of the requirements of IEEE 338 1997,

Regulatory Guide 1.22, and Regulatory Guide 1.118 were correctly translated into

the applicable procedure for testing of the AFW system was a violation. This

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nonrepetitive, licensee identified and corrected violation is being treated as a

j noncited violation. consistent with Section Vll.B.1 of the NRC Enforcement Policy.

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The inspector reviewed the issues identified in the condition reports and determined

that they were not reportable in accordance with 10 CFR 50.73 because, the AFW

system was never outside its design basis. The removal of each AFW system

,

during testing was conducted in accordance with the Technical

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Specification 3.7.1.2 action statement, noted in the control room, and tracked to

completion.

IV. Plant Sup.p_pwj t

i

1 R1 Radiological Protection and Chemistry Controls

i R 1.1 Tours of Radiofonical Controlled Areas

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a. inspection Scone (7175Q1

, The inspectors routinely toured the mechanical. auxiliary and fuel handling buildings

,

in Units 1 and 2. These tours included observation of work, verification of proper

radiological work permits, sampling of locked doors, review of radiological postings,

l and observations of personnel entrance and egress from the radiological controlled l

areas. l

i b. Observations and Controls i

Radiological housekeeping in the areas toured was very good. Doors required to be

I locked in accordance with Technical Specification 6.12.2 and the licensee's

i

radiological program were properly secured. No entrance / egress discrepancies were

, identified.

However, on July 17, during a routine tour of the fuel handling builuing, the

inspector identified eight contaminated area signs that had fallen down, The signs

had been hung across portholes going into emergency core cooling system pump

room sump areas. The radiation protection technician determined that high

condensation in the arco had loosened the adhesive used to hang the signs. The

{ signs were immediately re hung. The postings were later secured with bolts to the

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walls for more permanent mountings. The significance of this condition was low

because access through the portholes would be difficult and unnecessary.

4

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On July 17, the inspectors obsetved health physics technicians providing

radiological control oversight in support of the rod cluster contro essembly tool

.

repair in Unit 1, Two technicians provided continuous coverage. One technician

i was in the contaminated area monitoring and making contamination surveys. The

other technician operated an air monitor and provided support from outside the

contaminated area. A thorough radiological protection briefing was conducted

.

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before the start of the work. The toollaydown area was properly marked and

plastic sheeting was placed on the refuelling deck to control contamination. ,

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On July 21, the inspector accompanied maintenance and health physics technicians

on an at power containment entry in Unit 2. The purpose of the contain.nent entry

was to repair a flange leak on Residual Heat Removal Pump 20. The projob

radiological protection briefing was thorough. The health physics technician verified

that each worker had properly donned the protective clothing and was waaring

alarming dosimetry that would indicate high dose rate areas. The workers were

cognizant of radiological conditions and exhibited good work practices.

c. Conclusions

Routine radiological controls observed were considered in place and effective with

one exception. On two occasions, the radiological work practices of health physics

technicians and maintenance personnel were considered notable.

R1.2 Secondary Chemistry Controls

The inspectors routinely reviewed secondary water chemistry reports and radiation

monitor alarm status. Secondary chemical analysis, the calculated primary to

secondary leak rate, and indication from the Nitrogen 16 radiation monitors all

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confirmed steam generator tube integrity. The chemical analysis results provided

evidence of management attention and commitment to maintaining chemistry

parameters within appropriate limits.

P2 Status of EP Facilities, Equipment, and Resources

P2.1 Ememency Response Facilities (7175C)

The inspectors observed that the Technical Support Centers ar.1 Operations Support

Centers in both units were readily available and maintained for emergency

operation.

P2.2 Meteorolonical Towers and Indications (71750)

The inspectors routinely observed indication of meteorological conditions in the

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main control rooms of both units. The data obtained indicated that both the

10-meter and the 60-meter towers remained operable.

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S1 Conduct of Security and Safeguards Activities

S 1.1 Daily Physical SecurAyletivity Observations (71750)

a. Insocction Scope (71750)

The inspectors observed the practices of security force personnel and the condition

of security equipment on a daily basis. On one occasion, the inspector reviewed

the practice of skirting temporary trailers on site,

b. Observations and Findinas

The security officers searched packages and personnel in a professional manner.

Vital area doors were verified to be locked and in working condition. The inspectors

verified that isolation zones around protected area barriers were maintained free of

equipment and debris. During backshift tours, the inspectors determined that the

protected area was properly illuminated.

During this inspection period, the inspectors observed the placement of temporary

trailers inside the protected area in preparation for the upcoming outage, in all

cases, the trailers were properly skirted or had temporary lighting installed for

illumination,

a

c. Conclusions

Daily security force operations were handled professionally. Trailers in the

protected area were skirted or properly illuminated.

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ATTACHMENT

S.UPPLLtdEttLAL INFORM ATION

EARTIAL_LISl OF PERSRf[S CONTACTEQ

LiG fg1M

T. Cloninger, Vice President, Nuclear Engineering

W. Cottle, Executive Vice President and General Manager Nuclear

B. Dowdy, Manager, Operations, Unit 2

J. Groth, Vice President Nuclear Generation

E. Halpin, Manager, Maintenance, Unit 2

S. Head, Licensing Supervisor

K. House, Supervising Engineer, Design Engineering Department

T. Jordan, Manager, Systems Engineering

l M. Kanavos, Manager, Mechanical / Civil Design Engineering

l A. Kent, Manager Electrical / Instrumentation and Controls Systems

B. Logan, Manager, Health Physics

R. Lovell, Manager, Operations, Unit 1

8. Masse, Plant Manager, Unit 2

( G. Parkey, Plant Manager, Unit 1

T. Waddell, Manager, Maintenance, Unit 1

{!iSPECTION PROCEDURES USED

IP 37551: Onsite Engineering

IP 61726: Surveillance Observations

IP 62707: Maintenance Observation

IP 71707: Plant Operations

IP 71750: Plant Support

IP 92700: Onsite Followup of Written Reports at Power Reactor Facilities

IP 92902: Followup Maintenance

IP 93001: OSHA Interf ace Activities

ITEMS OfENED. CLOSED AND DISCUSSED

Qpened

409/97005 01 NCV Entry of incorrect Technical Specification Action

Statement into Operability Assessment System

498:499/07005 02 URI Manual Valves in Certain Containment Penetrations not

Surveilled in Accordance with Technical

Specification 4.6.1.1.a

498;499/97005 03 NCV Failure to

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2,

498;499/97005 03 VIO Two Examples of inadequate Equipment Clearance

Order Boundaries

498:499/97005 05 NCV Failure to Properly Test the Pressurizer Pressure

Interlock P 11 in Accordance with Technical

Specifications

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499/97005-01 NCV Entry of incorrect Technical Specification Action

Statcment into Operability Assessment System

498:499/97005 04 NCV Failure to Properly Test the Pressurizer Pressure

Interlock P 11 in Accordance with Technical

Specifications

i 50-498/97-007 LER Engineered Safety Features Actuation System

{ Pressurizer Pressure Interlock Not Fully Tested by

Surveillance