ML20148T009

Insp Repts 50-313/97-03 & 50-368/97-03 on 970427-0607. Violations Noted.Major Areas Inspected:Operations,Maint, Engineering & Plant Support

ML20148T009
Person / Time
Site:	Arkansas Nuclear
Issue date:	07/01/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML20148S947	List: ML20148S942 ML20148T009
References
50-313-97-03, 50-313-97-3, 50-368-97-03, 50-368-97-3, NUDOCS 9707080363
Download: ML20148T009 (23)

See also: IR 05000313/1997003

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ENCLOSURE 2

l U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket Nos.: 50-313

50-368 -

Licenso Nos.: DPR-51

NPF-6

Report No.: 50-313/97-03

50-368/97-03

Licensee: Entergy Operations, Inc.

Facility: Arkansas Nuclear One, Units 1 and 2

Location: 1448 S. R. 333 '

Russellville, Arkansas

Dates: April 27 through June 7,1997

Inspectors: K. Kennedy, Senior Resident inspector

S. Burton, Resident inspector l

J. Melfi, Resident inspector <

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Approved By: Elmo E. Collins, Chief, Project Branch C

Division of Reactor Projects

ATTACHMENT: Supplemental Information

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9707080363 970701 l

PDR ADOCK 05000313

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EXECUTIVE SUMMARY

Arkansas Nuclear One, Units 1 and 2

NRC Inspection Report 50-313/97-03;50-368/97-03 l

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Operations

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• Operators performed well during operation at reduced reactor coolant system (RCS) '

inventory. The monitoring of RCS level, communications, and control of the

evolutions was very good. Operators demonstrated a good questioning attitude and

delayed commencing RCS draindown in response to a drifting level transmitter.

Training of crews on the simulator prior to midloop operations was a strength

(Section 01.2).

• The reload of fuelinto the reactor was conducted in accordance with procedures

and operators demonstrated strong attention to detail, the use of three-way

communications, second verifications, and peer checking. Operators were

conscientious and focused on safety (Section 01.3).

• The licensee's walkdown and cleanup of the Unit 2 containment building was

effective in preparing the building for plant operation following Refueling

Outage 2R12 (Section 02.1).

• The performance of the Unit 2 integrated engineered safety feature (ESF) test,

involving maintenance, engineering, and operations personnel, was well coordinated

and controlled. Personnel were well prepared and very knowledgeable of their

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assigned tasks (Section 04.1).

• The licensee failed to properly align an emergency feedwater (EFW) pump suction

pressure switch resulting in one train of EFW being inoperable for approximately

28 days. This was determined to be a violation. Operators demonstrated a good

questioning attitude which led to identification of the misalignment and the licensee

took appropriate corrective actions upon discovery (Section 08.1).

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Maintenance

• Instrumentation and control technicians demonstrated a thorough knowledge of the

automatic closure interlock (ACl) circuitry during troubleshooting and correction of

an identified problem (Section M1.2).

• The cleaning of the service water (SW) return line to the emergency cooling

pond (ECP) was well controlled, with appropriate supervisory oversight and

engineering support. The cleaning process resulted in a decrease in piping losses

(Section M1.4).

• The licensee failed to properly align the upper guide structure (UGS) lift rig with the

reactor vessel guide pins, resulting in damage to a lift rig bushing. Temporary

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procedure changes to allow reinstallation were properly evaluated and provided i

good instructions to ensure alignment. The reinstallation of the UGS was deliberate I

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and well controlled (Section M1.5).

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• Testing of the Unit 2 main steam safety valves (MSSVs) was performed well. The

l prejob brief was thorough, with strong emphasis on lessons learned from previous

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errors. Effective controls were established to minimize the potential for personnel

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experiencing heat stroke during the performance of the testing. The inspectors

! noted strong management involvement in the testing of the MSSVs (Section M1.7).

As a result of eight of the ten MSSVs lifting above their Technical Specification (TS)

allowed lift setpoint during testing, the licensee determined TS requirements were

not met for some period during the previous operating cycle. This issue remains '

unresolved pending further inspection of the licensee's past operability

determination, root cause evaluation, corrective actions for the test failures, and

corrective actions taken as a result of MSSV test failures identified at the beginning

of Refueling Outage 2R11 (Section M1.7).

Enaineerina ,

• The potential for a leak in the Unit 1 makeup tank level instrumentation reference

leg to cause an erroneous indication on both level transmitters and lead to damage

of high pressure injection (HPI) pumps, an event which occurred at another plant,

was very unlikely based on design and operational differences between the plants

(Section E1.1).

• A design engineer demonstrated a good questioning attitude in identifying a TS

which would allow operators to place a recirculation actuation signal (RAS) channel

in a tripped condition for an indefinite period, rendering the function vulnerable to a

single failure and placing the plant outside of its design basis. The licensee took

appropriate short-term corrective actions to address this issue (Section E1.2).

• Reactor engineers failed to utilize a procedure for determining the proper placement

of fuel assemblies in the spent fuel pool (SFP), resulting in the misclassification of

42 fuel assemblies and the placement of one in a location prohibited by TS.

Multiple barriers, such as clear procedures and requirements for the conduct of

independent review of fuel assembly classification determinations, failed to prevent

or identify the calculation errors. This was determined to be a violation

(Section E1.3).

• Performance tests conducted on the emergency diesel generator (EDG) SW heat

exchangers revealed that the heat exchangers were capable of removing the

required heat from the diesel generators (Section E1.4).

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Plant Support

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• Very good radiation protection work practices were observed during the Unit 2 '

i refueling outage. Radiation protection technicians displayed a strong questioning . '

l attitude and a good awareness of plant activities (Section R.1).

L * The inspectors walked down portions of the reactor coolant pump (RCP) lube oil

collection system and found that the installation met regulatory requirements j

(Section F2.1). l

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• Fire watches were well qualified and knowledgeable of their duties and  ;

responsibilities (Section F4.1).

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R9Dort Details  !

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Summarv of Plant Status  !

! Unit 1 began the inspection period at 100 percent power. Power was reduced to

95 percent for 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> on May 6,1997, for main condenser repairs and to 85 percent for l

21/2 hours on May 16-17,1997, for routine turbine valve / governor valve testing. The . l

unit was at 100 percent power at the end of the inspection period. J

Unit 2 began the inspection period at 97 percent power. On May 6, operators began

reducing power in preparation for the start of Refueling Outage 2R12. On May 9, the plant

was shutdown and remained so through the end of the inspection period.

l. Operations

01 Conduct of Operations

01.1 General Comments (71707)

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The inspectors observed various aspects of plant operations, including compliance

with Technical Specifications; conformance with plant procedures and the safety

analysis report; shift manning; communications; management oversight; proper

system configuration and configuration control; housekeeping; and operator

performance during routine plant operations, the conduct of surveillances, and plant

power changes.

The conduct of operations was professional and safety conscious. Evolutions such  !

as surveillances and plant povver changes were well controlled, deliberate, and i

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performed in accordance with procedures. Shift turnover briefs were

comprehensive and were typically attended by a chemistry technician, a health

physics technician, and a representative from system engineering. Housekeeping

was generally good and discrepancies were promptly corrected. Safety systems

were found to be properly aligned. Specific events and noteworthy observations

are detailed below.

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01.2 Unit 2 - Operations with RCS at Reduced Inventory

a. Inspection Scoce (71707)

On May 13 and 14 and again during the week of June 1,1997, the inspectors .

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observed the licensee drain the RCS to reduced inventory, operate at reduced

inventory, and refill the RCS. The inspectors observed control room activities and

verified that the proper conditions were established for these evolutions.

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b. Observations and Findinas l

On May 13, Unit 2 operators commenced a draindown of the RCS in accordance

with Procedure 2102.011, Revision 23, " Draining the Reactor Coolant System."

- The inspectors verified that the licensee had establir.hed the proper initial

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conditions and prerequisites for operation at reduced inventory as described in

Procedure 2103.011 and Procedure 1015.008, Revisien 13, " Unit 2 SDC Control."

The inspectors attended an abbreviated prejob brief and found it to be thorough. A

more detailed brief was performed with the crew on the previous day.

Prior to commencement of the draindown, operators observed that one of the two

RCS level instruments had drifted low and stabilized with a reading approximately

3 inches lower than the other instrument. Although this difference was within the

tolerance allowed by Procedure 2103.011, operators delayed the start of the

draindown while instrumentation and control technicians vented and drained the

level transmitter sensing lines. The instrument was retumed to service and

operators verified that it responded appropriately to level changes. Operators

demonstrated a good questioning attitude with regard to the level transmitter and

properly resolved differences in level indication prior to draining the RCS.

Procedure usage, communications, and control of the drain to midloop was very

good. A licensed operator was assigned in the control room as the draindown

operator. Additionally, a dedicated operator was stationed inside containment to

monitor the tygon tube level indication, and an operator was stationed at the

shutdown cooling pump to monitor for unusual pump noises, which could indicate

pump cavitation. Operators closely monitored RCS level throughout the draining

process and while in reduced inventory. The draindown was stopped at levels

established in the procedure to s erify that the various level indicators were tracking

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properly and within the allowed dcuidtion. The operators accurately predicted level

transition points such as the elapsed time it would take for the steam generators to

fully drain.

The inspectors noted that the crews previously received simulator training on

midloop operations in preparation for the activity. This contributed to the ability of

the operators to perform this task with the efficiency that was demonstrated,

c. Conclusions

Operators performed well during operation at reduced RCS inventory. The

monitoring of RCS level, communications, and control of the evolutions were

very good. Operators demonstrated a good questioning attitude and delayed

commencing RC5 draindown in response to a drifting level transmitter. Training

crews on the simulator prior to midloop operations was a strength.

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01.3 Unit 2 - Refuelina Operations

a. Inspection Scope (71707)

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On May 18 and 20,1997, the inspectors observed refueling operations on Unit 2.'

Procedural compliance, the prejob briefing, refueling floor activities, operator

knowledge, and trair.ing requirements were reviewed.

b. Observations and Findinas

Inspectors attended the prejob brief and noted a good discussion of upcoming

activities. Ample opportunity was given for questions and discussion, and the  !

assistant operations manager provided insights from lessons learned from previous i

outages. The inspectors found that the watch bill was developed with sufficient j

rotation of personnel to ensure that operators did not become stressed with the  !

repetition that occurs with refueling activities. The refueling activities were l

conducted in accordance with procedures and the inspectors verified that

prerequisites were met prior to the commencement of fuel movement. The

inspectors noted good self- and peer-checking, adherence to procedures, and

system knowledge by the operators. Proper three-way communications were

observed between local operators, control room operators, and the refueling bridge.

c. Conclusions

The reload of fuelinto the reactor was conducted in accordance with procedures.

Personnel demonstrated a strong attention to detail, good communications, second l

verifications, and peer-checking. Operators were conscientious and were focused l

on safety.

O2 Operational Status of Facilities and Equipment

02.1 Unit 2 - Tour of Containment Buildina Durina Plant Heatuo

a. Inspection Scoce (71707)

A tour of the Unit 2 containment building was conducted on June 7 during the plant

heatup following completion of maintenance activities performed during Refueling

Outage 2R12. This tour was conducted following the licensee's preheatup

walkdown of the building but prior to their precriticality walkdown.

b. Observations and Findinas

The inspectors found that equipment in the building was properly secured and, with

a few exceptions, that debris had been removed. Radiological postings and

scaffolding remaining in the building were scheduled to be removed prior to plant )

criticality. The inspectors identified a small feedwater leak in an area where

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i maintenance had been performed during the outage. The licensee was aware of the

I leak and was preparing to send people into the building to stop the leak. The

inspectors identified minor equipment material condition discrepancies during the

walkdown and informed the licensee of these findings for resolution. .

c. Conclusions

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The licensee's walkdown and cleanup of the containment building was effective in

preparing the building for plant operation.

04 Operator Knowledge and Performance

04.1 Unit 2 - Performance of Intearated Enaineerina Safeauards Test

a. Insoection Scope (61726,71707)

The inspectors observed the licensee perform Procedure 2305.001, Revision 13,

" Integrated Engineering Safeguards Test," on June 5.

b. Observations and Findinas

The inspectors found that the performance of this complex test involving

maintenance, engineering, and operations personnel was well coordinated and

controlled. A test coordinator was assigned to prepare and coordinate the test

activities. During the prejob brief, the test coordinator discussed individual duties

and responsibilities and ensured that everyone was aware of their roles. Personnel

appeared to be very familiar with their assigned tasks. Communications and chain

of command were also discussed. I

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The inspectors found that equipment inoperability was properly documented and the

appropriate TSs entered prior to the commencement of the test. In addition, there  ;

was good coordination and communication with Unit 1 operators prior to the start

of the test.

The inspectors observed good communications during the performance of the test.

The ESFs actuation system was initiated from the control room. With a few

exceptions, equipment functioned as expected and within the allowed time. l

Condition reports were written to document discrepancies and initiate corrective

actions prior to retesting those functions,

c. Qinclusions

The performance of the Unit 2 integrated ESF test, involving maintenance,

engineering, and operations personnel, was well coordinated and controlled.

Personnel were well prepared and very knowledgeable of their assigned tasks.

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08 Miscellaneous Operations issues

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08.1 (Closed) Licensee Event Report (LER) 50-368/9 7-002. "inadeauate Confiauration i

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Control Resulted in Closed Pressure Switch Isolation Valves that Could Have

Prevented One Train of Emeraency Feedwater from Automatically Switchina the

Pomo Suction to Service Water and Caused Ooeration Prohibited by Technical

Specifications"

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a. Inspection Scope (92700)  !

LER 50-368/97-002 documented the licensee's discovery that Unit 2 had operated

with one train of EFW inoperable for approximately 28 days. The train was j

inoperable due to the isolation of the EFW pump suction pressure switch root  !

valves. The pressure switch is designed to automatically transfer the pump suction

to the alternate supply in the event that the normal supply is lost. The licensee

identified that the other train of EFW was inoperable for short periods during the )

28 days due to maintenance activities.

b. Observations and Findinas

The EFW pumps are designed to supply the steam generators in the event that

normal feedwater is unavailable. The normal suction for the EFW system is the

condensate storage tank (CST) with alternate supply from the SW header. The

EFW pump suction was designed to automatically transfer from the normal supply

CST to the SW header in the event that an automatic demand signal (steam

generator low water level) in conjunction with an EFW pump low suction pressure

existed. The purpose of this design ensures that the EFW pumps have a Seismic

Category I supply available from the SW header in the event that a seismic event

would render the Seismic Category ll CSTs unavailable. The isolated pressure

switch provides a signal at 5 psig to transfer the pump suction source from the CST

to the SW system.

On February 4,1997, during routine surveillance testing of motor-driven EFW Pump

2P-78, the control room operator observed a momentary EFW pump low suction

pressure alarm. The control room dispatched an operator to investigate the cause

of the alarm. The plant operator discovered that the suction pressure switch, which

provided the signal to transfer EFW pump supply sources on low suction pressure,

was isolated with pressure locked in on the pressure switch. It was subsequently

determined that vibrations induced while starting the pump caused an intermittent

low suction pressure alarm.

The licensee determined that the low suction pressure switch was isolated on either

January 6,1997, during the performance of an 18-month pressure switch

calibration or on January 7 during the performance of a routine monthly surveillance

test. The licensee identified two possible explanations for the valving error. First, a

possible error occurred on January 6 during the performance of the associated

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pressure switch 18-month calibration in that the instrument and control technicians

failed to properly unisolate and independently verify the position of the isolation

valve upon completion of the calibration. Second, an auxiliary operator improperly

isolated valves for an instrument not associated with the normal monthly EFW .

surveillance on January 7. In the second case, the auxiliary operator was required

to manipulate root valves on local EFW pump suction and discharge pressure gages.

All of the root valves were unmarked and there existed a potential for the inplant

operator to isolate the wrong instrument. The licensee's root cause evaluation

deterrnined that the affected instrument root valves were not procedurally controlled

in a manner that would ensure they are maintained fully open at all times when the

EFW pump is required to be operable.

The licensee also determined that, during the approximately 28 days that the

pressure switch was isolated, the turbine-driven emergency feedwater pump was

inoperable, on four independent occasions, due to the pump or the opposite train

emergency diesel generator being out of service for surveillance testing or

maintenance. The total time that both emergency feedwater pumps were

simultaneously inoperable during the 28 day period was approximately 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.

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The inspectors reviewed procedures and conducted interviews to determine if  !

operators would have been alerted to a failure of the EFW pump suction to transfer

from the CST to the SW header had there been a valid demand signal.

The inspectors concluded that indications and alarms were available to the

operators which would alert them of the need to secure the affected EFW pump i

protecting the pump from failure upon a loss of supply water. Also, the

turbine-driven EFW Pump 2P-7A low suction pressure alarm would alert the

operators that a transfer of suction from the CST to the SW header was required.  ;

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The inspectors concluded that, subsequent to indicationr. of abnormal conditions at

the EFW pump, sufficient time existed for the operators to initiate investigations

that would result in the operator manually shifting EFW pump suction to the SW

system. Additionally, the emergency operating procedures and system operating

procedures provide instructions to align the seismically qualified Units 1 and 2

shared CST as the suction source for the EFW pumps. Although available to

mitigate this event, credit is not taken for the seismically qualified CST in analysis.

Unit 2 TS 3.7.1.2 requires that two EFW pumps and associated flow paths shall be

operable in Modes 1,2, and 3. The inoperability of one train of EFW, due to the

isolation of the suction pressure switch for Pump 2P-7B for a period of

approximately 28 days, was determined to be a violation of TS 3.7.1.2

(50-368/9703-01).

Although this violation satisfied the criteria to be noncited pursuant to

Section Vll.B.1 of the NRC's Enforcement Policy, it is being cited to emphasite the

importance of ensuring effective administrative controls to ensure the proper

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alignment of risk significant safety systems. The inspectors found that ,

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LER 50-368/97-002 provided a description of the licensee's corrective  !

L actions taken and planned to correct the violation and prevent recurrence.

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c. Conclusions

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i The licensee failed to properly align an EFW pump suction pressure switch, resulting i

in one train of EFW being inoperable for approximately 28 days. Operators

demonstrated a good questioning attitude which led to identification of the l

misalignment and the licensee took appropriate corrective actions upon discovery.

11. Maintenance

M1 Contfoct of Maintenance i

M1.1 General Comments I

a. inspection Scope (62707) i

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The inspectors observed all or portions of the following maintenance activities:

• Unit 2 - Job Order (JO) 00963312, "EFW Speed Controller Maintenance,"

performed on May 13,1997.

• Unit 2 - JO 00964748, " Drain and Flush 2K-4A Engine Oil System,"

performed on May 27 and 28.

• Unit 2 - Construction Work Package 96-2001/953299-2, "2R12 Electrical

Modification 2WR25-5 (2E-8)," observed between May 15 and 20.

• Unit 2 - Performance of Outage Related Maintenance Activities on Both EDFs

Observed at Various Times during the Outage.

• Unit 2 - JO 00961161 and Procedure 2409.552, " Cleaning the ECP Return

Lines," observed on May 25.

• Unit 1 - JO 00934257 used to troubleshoot and repair the ACl module,

performed on May 16.

• Unit 2 - JO 00962235 used to install a lube oil pump on EDG 2K4A,

performed on May 28.

• Unit 2 - Procedure 2505.006, Revision 7, " Unit 2 Upper Guide Structure

Removal," performed on May 18.

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• Unit 2 - Procedure 2505.007, Revision 6, " Unit 2 Upper Guide Structure l

Installation," performed on May 29. j

b. Observations and Findinas ,

The inspectors found the work performed in these activities to be professional and

thorough. All work was performed in accordance with procedures and the workers

were knowledgeable on their assigned tasks. When applicable, appropriate

radiological work permits were followed. The inspectors observed supervisory

involvement in the activities and adequate foreign material exclusion controls,

in addition, see the specific discussions of maintenance observed under ,

Sections M1.2 through M1.5, below. j

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M1.2 Unit 1 - Failure of ACI Module

a. Insoection Scope (62707)

The inspector observed licensee activities following their identification during a

routine surveillance that an RCS pressure module was out of tolerance. This

out-of-tolerance condition affected the closure logic for Decay Heat Suction

Valve CV-1050 and rendered the ACI circuit inoperable. This placed the unit in a

12-hour shutdown limited condition of operation per TS 3.5.1.2. The ACI circuit I

provides over-pressure protection for the decay heat removal system suction piping l

by closing the suction valve on a high RCS pressure condition preventing high

pressure water from entering a low pressure system.

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b. Observations and Findinos

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During performance of Procedure 1304.162, " Unit 1 Decay Heat Channel 1 Test,"

on May 16, technicians found that the RCS Pressure Buffer Module C88-8-4 was

slightly out of tolerance and had difficulty adjusting the module to be within the

required specification. Based on the unexpected difficulty in adjusting the module,

the licensee initiated troubleshooting activities under JO 00964257 to adjust the

module or replace as necessary. The inspector observed portions of this JO,

observed management involvement in the process, and noted that the technicians

were knowledgeable on the circuit. The technicians identified dirty contacts on the

buffer module connector and cleaned the contacts. After cleaning the contacts, the

technicians were able to make the required adjustments and returned the module to

service.

C. Conclusions

Instrumentation and control technicians demonstrated a thorough knowledge of the

ACI circuitry during troubleshooting and correction of an identified problem.

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M1.3 Unit 2 - EDG Lube Oil Pumo Failure

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On May 24,1997, during a postmaintenance test of EDG 2K4A, the gear-driven .

lube oil pump failed catastrophically, resulting in an automatic shutdown of the

diesel generator. Inspectors reviewed the circumstances surrounding the pump

failure and observed portions of the installation of the replacement lube oil pump. l

b. Observations and Findinas

Following the failure, the licensee found that the drive gear shaft to the lube pump j

sheared and a pump gear had many broken teeth. The licensee had replaced the  :

lube oil pump during maintenance under JO 00962235 due to a crack on the ,

suction flange. The lube oil pump had been purchased from another utility with the j

same diesels. However, the licensee discovered that the broken gear on the  !

replacement lube oil pump had a different finish, was of a larger diameter, and had

46 teeth instead of 44 teeth. The licensee installed another lube oil pump with the

correct gear via JO 00964748 on May 28,1037. The broken gear shaft and

damaged gear were sent to an offsite laboratory for f ailure analysis.

The procurement of the failed lubricating oil pump, the work instructions used to l

install the pump, and the results of the laboratory f ailure analysis will be the subject l

of further inspection of this event (IFl 50-368/9703-03). l

M 1.4 Unit 2 - Observation of SW Return Line Cleanina

a. Inspection Scope (62707)

The SW return line to the ECP was cleaned to reduce line losses. The inspectors

observed portions of the return line cleaning on May 25. This activity was

performed in accordance with JO 00961161 and Procedure 2409.552, " Cleaning

the ECP Return Line."

b. Observations and Findinas

The licensee constructed a special launcher to insert a cleaning device into the

return line. The licensee would drain the line, install the cleaning device, then refill

the line and use SW pressure to move the device through the lines and scrape the

sides.

The inspectors noted that the activity was well controlled and observed appropriate

engineering and supervisory oversight of the process. The cleaning process resulted l

in a reduction of line losses from 24 psi to 15 psi.

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c. Conclusions

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I The cleaning of the SW return line to the ECP was well controlled with appropriate

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supervisory oversight and engineering support. The cleaning process resulted in a

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M1.5 Unit 2 - Removal and Reolacement of Reactor UGS

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a. Inspection Scoce (71707)

The inspectors observed the removal of the UGS from the reactor vessel on May 18

and the reinstallation of the UGS into the reactor vessel on May 29. The

UGS aligns and supports the upper end of the reactor fuel assemblies to prevent

movement during expected transients. A speciallift rig is used to remove and

install the UGS to ensure that it is properly positioned over the reactor vessel.

Reactor vessel guide pins fit into bushing on the lift rig to ensure proper a!!gnment.

b. Observations and Findinas

The inspectors observed the removal and the second reinstallation of the UGS. The

licensee used Procedure 2505.006, Revision 7, " Unit 2 Upper Guide Structure

Removal," for the removal of the UGS. The prejob brief was thorough, foreign

material exclusion controls were in place, and the licensee followed their

procedures.

During their initial attempt to reinstall the UGS on May 26, the licensee damaged

one bushing on the UGS lift rig. Due to improper alignment of a lift rig bushing with

a reactor vessel guide pin, the bushing was damaged as the lift rig was lowered

onto the guide pin. Neither the UGS or the reactor vessel sustained any damage.

The licensee returned the UGS and lift rig to their storage location within the

refueling cana!. The licensee believed this misalignment was caused by parallax

error while lowering the lift rig bushings over the guide pins.

The licensee removed the damaged bushing from the lift rig and made a temporary

change to Procedure 2505.007, Revision 6, " Unit 2 Upper Guide Structure

Installation," to allow installation of the UGS with only one alignment bushing on

the lift rig. The inspectors attended a meeting of the plant safety committee, during

which the procedure changes were discussed, and reviewed the procedure, which

included additional actions to ensure the proper alignment of the lift rig. The

inspectors found that the procedure changes provided sufficient controls to ensure

the proper alignment of the UGS during installation.

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The inspectors attended the prejob brief for the installation of the UGS and found it

to be thorough. The UGS was installed in a deliberate, controlled manner to ensure

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he proper alignment of the UGS with the reactor vessel. The licensee identified two

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items on the UGS, a bolt and a piece of tie wrap, which they removed before

installation. The licensee initiated a condition report to document the finding and

evaluate the source of the foreign material.

>

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c. Conclusions  !

The licensee failed to properly align the UGS lift rig with the reactor vessel guide ,

pins, resulting in damage to a lift rig bushing. The reinstallation of the UGS was i

'

deliberate and well controlled. Temporary procedure changes to allow reinstallation

were properly evaluated and provided good instructions to ensure alignment.

M1.6 General Comments on Surveillance Activities

!

a. Inspection Scoce (61726)

)

The inspector observed all or portions of the following surveillance activities:

• Unit 2 - Procedure 2306.006, " Unit 2 Main Steam Safety Valve Test,"

performed on May 7 and 8,1997.

• Unit 2 - Procedure 2402.049, Revision 8, " Unit 2 Main Steam Safety Valve

Maintenance," performed on June 6.

• Unit 2 - Procedure 2305.006, Revision 13, " Cold Shutdown Valve Testing,"

Supplement 2, " Emergency Boration Flow Path Verification," performed on

May 10.

• Unit 2 - Procedure 2307.003, Revision 7, " Testing of Time Delay Relays,"

completed under JO 956316, on May 19.

• Unit 2 - Procedure 2305.001, Revision 13, " Integrated Engineering

Safeguards Test," performed on June 5.

• Unit 2 - Procedure 2305.049, Supplement 2, "2EDG218-Month Operational

Test," performed on June 5.

• Unit 1 - Procedure 1105.009, Supplement 2, " Exercising CRDMs Above Cold

Shutdown," performed on June 6.

b. Observations and Findinas

The inspectors found that the surveillance activities were performed according to

the licensee's procedures by knowledgeable workers. When applicable, calibrated

test equipment was used, personnel demonstrated good technical knowledge of the

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components being tested, there was an awareness of both procedural requirements

l and safety while working with energized equipment, and appropriate radiological

i work permits were followed.

. ;

'

In addition, see the specific discussions of maintenance observed under

Sections 04.1 through M1.7.

M1.7 Unit 2 - MSSV insitu Testina

a. Inspection Scope (62707)

On May 8 and 9,1997, the inspectors observed portions of MSSV testing

performed on Unit 2 with the plant at normal operating temperature and pressure.

This testing was conducted in accordance with Procedure 2306.006, " Unit 11 Main

Steam Safety Valve Test."

b. Observations and Findinas

The prejob was thorough, with strong emphasis on lessons tearned from previous

errors. The licensee performed required precalibration and postcalibration checks of

the test equipment used during the MSSV testing to ensure accuracy of the results.

The inspectors noted strong management involvement in the testing of the MSSVs.

The licensee established effective controls to minimize the potential for personnel

experiencing heat stroke during the performance of the testing.

The licensee tested 7 of the 10 MSSVs. The remaining 3 valves were removed

following the plant cooldown and tested at an offsite facility. The licensee found

that 8 of the 10 MSSVs lifted at setpoints higher than allowed by TSs (f_1 percent

of setpoint).

The licensee performed extensive testing to determine the root cause of the valve

test failures and identify required corrective actions. The licensee evaluated the  !

!

following areas which could potentially effect the setpoint of the MSSVs: inplant

testing issues such as seat adhesion and the air motor test method; valve j

maintenance issues such as valve refurbishment, leakage, internal friction, ,

clearances and tolerances, and valve spring " set" or hysteresis; and offsite testing i

issues such as initial steam header pressure, quantity, and repeatability of valve l

'

lifts, valve component temperatures, and stabilization of valve temperatures. The

licensee determined that a combination of factors contributed to the high as-found

lift setpoints and did not identify a single cause.  ;

1

i

The licensee identified 11 short-term corrective actions and 5 potential long-term i

l

i corrective actions that addressed the causal factors. Corrective actions included

l full valve inspections, incheased scope of testing, increased testing and test

1

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environmental controls, and verification of internal specifications and tolerances.

l The licensee completed their short-term corrective actions, which included l

modifications to the valves as required, and verified that the valves lifted at the

proper setpoints. , l

!

The licensee evaluated the as-found MSSV lift setpoints with respect to the most

! limiting overpressurization event, a loss of condenser vacuum, and determined that

l the MSSVs would have performed their safety functions during the previous

operating cycle. However, the licensee determined that, for some undetermined

period during the previous operating cycle, the MSSVs lift setpoints did not satisfy '

the requirements of TS 3.7.1.1. This issue remains unresolved pending further I

inspection of the licensee's past operability determination, root cause evaluation, I

corrective actions for the test failures described in this report, and corrective actions  :

taken as a result of MSSV test failures identified at the beginning of Refueling l

Outage 2R11 (URI 50-368/9703-02). J

The licensee briefed the Office of Nuclear Reactor Regulation and Region IV on their

findings and corrective actions during a conference call conducted on June 4.

Based on the information provided by the licensee, the inspectors determined that

the licensee's short-term actions were appropriate to address the MSSV issues.

c. Conclusions

Testing of the Unit 2 MSSVs was performed well. The prejob was thorough with

strong emphasis on lessons learned from prevNs errors. Effective controls were

established to minimize the potential for perseMel experiencing heat stroke during

the performance of the testing. The inspectors noted strong management

involvement in the testing of the MSSVs.

As a result of 8 of the 10 MSSVs lifting above their TS allowed lift setpoint, the

licensee determined that the requirements of TSs were not met for some period

during the previous opera ting cycle. This issue remains unresolved pending further

inspection of licent,ee's pas +.sperability determination, root cause evaluation, ,

corrective actions for the test failures, and corrective actions taken as a result of '

MSSV test failures identified at the beginning of Refueling Outage 2R11.

Ill. Enaineerina

E1 Conduct of Engineering

l E1.1 Unit 1 - Makeuo Tank Level Transmitter Reference leas

a. inspection Scope (92903)

i

i On May 3,1997, Oconee Unit 3 sustained damage to twc hP1 pumps as a result of

l a loss-of-pump suction from the letdown storage tank. A leaking instrument fitting

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in a shared reference leg resulted in an erroneous level indication. During this ,

l inspection period, the inspectors reviewed the applicability of this event to ANO

Unit 1.

b. Observations and Findinas

The inspectors interviewed the cognizant system engineer and reviewed

instrumentation isometrics and found differences between the configuration of ANO l

Unit 1 and Oconee Unit 3. The units are similar in that they have two level taps

into the tank, but Unit 1 has two reference legs, one for each instrument.

Therefore, draining one reference leg should not affect the other reference leg. The

licensee also assures that the reference legs are full by refilling them quarterly.

The licensee also operates the suction to the HPl pumps differently than Oconee, in

that the suction sources are split between the makeup tank and the borated water

storage tank.

c. Conclusions

The potential for a leak in the makeup tank level instrumentation reference leg to

cause an erroneous indication on both level transmitters and lead to a damage of

HPl pumps, an event which occurred at another plant, was very unlikely, based on

design and operational differences between the plants.

E1.2 Unit 1 - TS Error Associated with Operation of One Channel of Refuelina Water

Tank (RWT) Level in the Tripped Condition

a. Inspection Scope (37551)

On May 12, the licensee discovered a configuration allowed by TSs which would

place the plant outside of its design basis. Specifically, the licensee discovered that

TS 3.3.2.1 allows operation with one channel of RAS, associated with RWT level,

in a tripped condition for an indefinite period. With one channel of RAS in a tripped

condition, a single failure. of another RWT level instrument would result in an

inadvertent initiation of RAS (RAS initiation occurs when two of the four RWT level

transmitters reaches the low level setpoint), if this occurred during a loss-of-coolant

accident, suction for the emergency core cooling systems pumps could transfer

prematurely from the RWT to the containment building sump and result in

inadequate flow to the reactor or damage to the pumps. The licensee reported the

condition to the NRC in accordance with 10 CFR 50.72. The inspectors reviewed

l

the licensee's findings and corrective actions.  !

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b. Observations and Findinas

l

The inspectors found that the TS error was identified by a design engineer during a

review of plant modifications to address a previously identified discrepancy

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associated with the indefinite bypass of plant protection system channels.

Condition Report 2-97-0168 was initiated to document the finding and identify

corrective actions. The engineer demonstrated a good questioning attitude in

identifying this condition. ,

in response to the finding, the operations department issued night orders to

administratively prohibit placing an RAS channel in a tripped condition. A failed

channel in a tripped condition would have to be bypassed within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The

licensee also began work to amend the TSs to delete the allowance to continuously

operate with a channel of RAS in the tripped condition.

The inspectors attended a corrective action review board during which additional 1

actions were initiated. Steps were taken to inform other plants of this condition,

night orders were to be amended to prohibit placing all ESF actuation system

channels in a tripped condition pending further review of these functions, and

operations was tasked to develop intermediate administrative controls pending

issuance of the TS revision. The inspectors also found that ABB-CE issued a

bulletin to plants with an ABB-CE designed nuclear steam system supplier to inform )

them of the ANO finding.

c. Conclusions

A design engineer demonstrated a good questioning attitude in identifying a TS,

which would allow operators to place a RAS channel in a tripped condition for an

indefinite period, rendering the function vulnerable to a single failure and placing the

plant outside of its design basis. The licensee took appropriate short-term

corrective actions to address this issue.

E1.3 Unit 2 - Placement of a Fuel Assembly in an SFP Location Prohibited by TS

a. Insoection Scope (92903)

i

On May 18,1997, the licensee commenced moving fuel from the reactor to the SFP

at 3:43 p.m. At 8:12 p.m., fuel movement was stopped due to the discovery of an

error in a calculation used to determine fuel bundle burnup and classify fuel

assemblies for proper placement in the SFP. The licensee determined that a

calculation error resulted in the misclassification of fuel assemblies being moved

from the reactor to the SFP. It was determined that the first of seven assemblies

transferred to the SFP from the reactor was located in a position not authorized by

TS 3.9.12.B. The inspectors reviewed the event to determine the safety

significance, the cause, and the requirements associated with the misplaced fuel

assembly.

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b. Observations and Findincs

,

TS 3.9.12 specifies the requirements and restrictions for the placement and

l configuration of fuel assemblies in the SFP. The limits provided in TS 3.9.12 ensure

'

that SFP will remain in a subcritical array with k dO.95 in unborated water. The

placement of fuel assemblies in the SFP is a function of the fuel enrichment and the

fuel assembly average burnup. Fuel assemblies are clasified as Restricted A, B, C,

or Nonrestricted depending on their enrichme end burnup. Procedure 1022.012,

Revision 18, " Storage, Control & Accountab< % af Special Nuclear Material,"

provides instructions for calculating enrichme ,:nd burnup and classifying

fuel assemblies. The classification for each assembly is documented on

Form 1022.012U, " Unit 2 Nuclear Fuel Location Record." The information from

Form 1022.012U i3 used to compl ste Form 1022.012B, " Nuclear Fuel Transfer

Report," which documents the location that each fuel assembly is to be placed in

the SFP. The procedure requires that the information on these forms be

independently verified.

On May 18, during movement of fuel from 11e reactor vessel to the SFP, a reactor

engineer discovered that an error had been (iade in the classification of a fuel

assembly. It was determined that a correction factor was not applied to the fuel

burnup calculation as required by Procedure 1022.012, which resulted in a

nonconservative burnup calculation and a misclassification of some fuel assemblies.

As a result, tne first fuel assembly moved into the SFP was misclassified and placed

, in a location which was prohibited by TS. The licensee suspended moving fuel,

recalculated the fuel '. "rnup for the fuel assemblies to determine the proper storage

l location in the SFP, placed the first fuel assembly in an acceptable location, and

resumed offloading the core on May 19. The licensee determined that the

calculation error resulted in 42 of the 177 fuel assemblies being misclassified. This

would have resulted in the placement of 14 fuel assemblies in SFP locations

prohibited by TS. Subsequent evaluation by the licensee revealed that the SFP

g

would have remained in a subcritical array had the 14 fuel assemblies been placed

in the wrong locations.

]

The inspectors identified several examples in which the requiraments of

Procedure 1022.012 were not followed, resulting in the initial calculation error and

missed opportunities to identify and correct the original error.

Procedure 1022.012, Step 6.3.1, icquWs, prior to the movement of fuel to the

SFP, that two qualified individuals perform independent reviews to determine the

classification of the fuel assemblies using Attachment 5 of the procedere and

documenting the results on Form 1022.012U, " Unit 2 Nuclear Fuel Location

Record." Procedure 1022.012, Attachment 5, Step 2.0, used to calculate the fuel

) assembly average burnup, requires that an adjustment factor of 0.93 be applied to

the mcasured fuel assembly burnup to account for measurement uncertainties. The

inspectors identified that an engineer performing the initial uassification of the fuel

assemblies f ailed to apply the burnup adjustment f actor when calculating fuel

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assembly bumup, resulting in the wrong classification of 42 of 177 fuel assemblies.

In addition, the engineer failed to document the results of the classifications on

Form 1022.012U. This is the first example of a violation of TS 6.8.1  ;

(50-368/9703-04).  !

.

The inspecters found that an independent review of the class;'Matiori .f the fuel

assemblies was not performed prior to the movement of the fuel assemblies into the

SFP as required by Procedure 1022.012, Step 6.3.1. This is the second example of

a violation of TS 6.8.1 (50-308/9703-04). As a result of communications

problems, incomplete understanding of the importance of completing the

independent verification of Form 1022.012U prior to fuel movement, and the time

required to complete independent verification, the independent verification on the  ;

first bundle already moved into the SFP was not completed until over 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> after

the commencement of fuel movements. Upon discovery that the first bundle was in

error, fuel movements were halted until corrections in the process were completed.

Another opportunity to identify the misclassification of the fuel assemblies occurred

when a reactor engineering supervisor discovered that the independent review

signature on Form 1022.012Us was not completed When he noted that the forrr-

were not signed after fuel movement cre authuvcd, he made an assumption that

the error was due to paperwork /adminmaativa delays, not an actual failure to

complete the task, and f ailed to question the reason for the incomplete forms. A

more thorough investigation of the unsigned forras could have resulted in the

identification of the classification error.

Procedure 1022.012, Step 6.3.4, requires that Form 1022.012B, " Nuclear Fuel 1

Transfer Report," be independently reviewed by a quaC.'ied individual to verify

special nuclear material storage in locations in compliance with Steps 6,3.1,6.3.2,  ;

and 6.3.3. Form 1022.012B is used to document where each fuel assembly  !

removed iroin the core is to be placed in the SFP. Information for each fuel

assembly contained on Form 1022.012U is needed to complete the nuclear fuel I

transfer report. The inspectors found that the independent reviewer failed to verify

compliance with Steps 6.3.1 and 6.3.2 in that completed Form 1022.012Us did not

exist at the tima thi:: step was completed. This is the third example of a violation of

TS 6.8.1 (50-368/9703-04).

c. _C_q,clusions

Reactor engineers failed to utilize a procedure for determining the proper placement

of fuel assemblies in the SFP, resulting in the misclassification of 42 fu0 assemblies

and the placement of one in a location prohibited by the TS. Multiple barriers, such

as clear procedures and requirements for the conduct of independent review of fuel

assembly classification determinations, f ailed to prevent or identify the calculation

errors.

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E1.4 Unit 2 - EDG Heat Exchanaer Performance Testina

,

a. Inspection Scoce (37551)

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_

The Unit 2 EDGs are cooled by SW flow through external heat exchangers. To

verify that these heat exchangers' can remove the heat after a design basis accident,

the licensee conducts performance testing and extrapolates test results to design ,

basis conditions. The inspector observed portions of the performance testing and

reviewed the test results,

b. Observations and Findinas

'

The licensee conducts EDG heat exchanger performance testing using guidelines

contained in Procedure 2311.008, "EDG Heat Exchanger Performance Tests." The

licensee does this test to meet Generic Letter 89-13, " Service Water System

Problems Affecting Safety-Related Equipment," commitments and to verify that heat

exchangers can remove design basis heat loads. Each EDG has three heat

exchangers in series to remove heat generated by the engine. Each heat exchanger

has a minimum required capacity that the licensee evaluates from extrapolated test

results. The licensee tested and verified that the EDG A heat exchangers met heat

i performance requirements. The licensee found that EDG B Heat Exchanger 2E63B

l did not meet projected worst case requirements by approximately 1 percent of the

!- total heat load. The licensee has not experienced the worst case SW temperatures

that would affect heat exchanger performance. The licensed cleaned the heat

exchangers and reran the test to verify heat exchanger performance.

The inspectors observed placement of the temperature elements and reviewed the

I

daa f4 Ilowing the test. Subsequent testing by the licensee verified that the as-left

resuhw met the performance requirements._ The licensee uses computer calculatione

to verify that the heat exchangers can remove the heat capacity as calculated by

Engineering Calculation 91-D-2003-01, Revision 2. Tr. ' inspector reviewed the

results and concluded that the heat exchangers could remove the required heat

loads.

,

c. Conclusions

l

l Performance tests conducted on the EDG SW heat exchangers revealed that the

i heat exchangers could temove the required heat from the emergency diesel

generators.

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IV. Plant Support

R1 Radiological Protection and Chemistry Controls

.

R 1.1 General Comments (71750) ,

,

During routine tours of the plant and observations of plant activities, the inspectors

found that access doors to locked high radiation areas were properly locked, areas

were properly posted, and personnel demonstrated proper radiological work

practices. The following observations were made during tours of the plant.

• The inspectors observed radiation protection technicians verba!!y questioning

radiation workers entering a controlled access area to determine their

awareness of their responsibilities. The process was designed to heighten

radiation awareness and determine if deficiencies existed. The inspectors

reviewed records associated with the interviews and concluded that the

technicians questioned a wide variety of personnel with questions that

resulted in an increased awareness of the requirements for working within a

radiation environment. Additionally, radiation workers missed a %nimal l

number of questions, with no specific deficiencies noted in radiation worker l

knowledge. l

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• The inspectors observed the radiation protection technicians monitor )

personnel entering and inside the controlled access area. Technicians were l

aggressive with questioning personnel about their radiation work practices.

One example was observed when the technicians questioned a worker who ,

appeared to be chewing. The inspectors concluded that radiation protection l

technicians demonstrated a strong questioning attitude and good attention to.

detail whila coserving personnel entering and inside the controlled access

area. j

l

• The inspectors observed workers who were supporting the performance of  !

tasks inside containment. Personnel were conscientious of local dose rates

and stood in low dose areas when appropriate. I

• The inspectors noted that both radiation protection personnel and their

management were acutely aware of active and emergent maintenance inside I

controlled access.

R1.2 . Conclusions

Very good rarliation protection work practices were observed during the Unit 2 l

refueling outage. Radiation protection technicians displayed a strong questioning

attitude and a good awareness of plant activities.

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F2 Status of Fire Protection Facilities and Equipment

F2.1 Unit 2 - RCP Lube Oil Collection System

1

a. Inspection Scone (71750)

,

During tours of containment to plant startup, the inspectors walked down portions ,

of the RCP lube oil collection system to verify that the collection system met the  :

requirements of 10 CFR Part 50, Appendix R.

b. Observations and Findinas

The inspectors walked down portions of the RCP lube oil system and found that the

oil collection system was properly installed and adequately supported. The

inspectors also verified that the lube oil collection system for the RCP D motor, .

which was replaced during the outage, was properly installed with shrouds covering l

the high pressuro portions of the system lift oil system. The inspectors verified that  :

both lube oil drain tanks were empty. '

c. Conclusions .

The inspectors walked down portions of the RCP lube oil collection system and

found that the installation met regulatory requirements.

F4 Fire Protection Staff Knowledge and Performance

F4.1 Fire Watch Knowledae and Performance

a. Inspection Scope (71750)

i

j Due to the magnitude of work occurring during the outage and the large number of

l fire watches assigned to perform fire inspections and tours, the inspectors

interviewed personnel assigned as fire watches to determine if the individuals were ,

cognizant of their assigned responsib!Iities.

b. Observations and Findinas

The inspectors questioned fire watches with respect to their assigned duties and

responsibilities and found them to be knowledgeable of their assigned areas of

responsibilities. Additionally, fire watches demonstrated a strong concern for the ,

safety of personnel.

c. Conclusions .

Fire watches were well qualified and Knowledgeable of their duties and ,

i responsibilities.

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T

ATTACHMENT

PARTIAL LIST OF PERSONS CONTACTED

Licensee

C. Anderson, Plant Manager, Unit 2

B. Bement, Radiation Protection and Chemistry Manager

M. Cooper, Licensing

D. Denton, Director, Support

P. Dietrich, Maintenance Manager, Unit 1

C. Eubanks, Mechanical Superintendent, Unit 2

D. Fowler, Supervisor, Quality

R. Fuller, Operations Manager, Unit 1

M. Harris, Technical Assistant

B. James, Outage Manager, Unit 2

i R. Lane, Director, Design Engineering

J. McWilliams, Modifications Manager

D. Mims, Director, Licensing

T. Mitchell, Manager, Unit 2 System Engineering

T. Russell, Operations Manager, Unit 2

A. South, Licensing

H. Williams, Jr., Superintendent, Plant Security

C. Zimmerman, Plant Manager, Unit 1

INSPECTION PROCEDURES USED

IP 37551: Onsite Engineering

IP 61726: Surveillance Observations

IP 62707: Maintenance Observations

IP 71707: Plant Operations

IP 71750: Plant Support Activities

IP 92700: Onsite Followup of Written Reports of

Nonroutine Events at Power Reactor Facilities

IP 92903: Followup - Engineering

ITEMS OPENED AND CLOSED

Opened

50-368/9703-01 VIO Inoperability of One Train of EFW (Section 08.1)

50-368/9703-02 URI Failure of MF9V Lift Tests (Section M1).

50-368/9703-03 IFl T.DG Oil Purnp Failure (Section M1.5)

50-368/9703-04 VIO Placemern of a Fuel Assembly in a SFP Location

Prohibited by TS (Section E:1.3).

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Cfosed

50-368/97-002 LER Inadequate Configuration Control Resulted in Closed Pressure

Switch Isolation Valves that Could Have Prevented One Train,

of EFW from Automatically Switching the Pump Suction to

SW and Caused Operation Prohibited by TSs (Section 08.1)

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LIST OF ACRONYMS USED

ACI automatic closure interlock

CST condensate storage tank

ECP emergency cooling pond

EDG emergency diesel generator

EFW emergency feedwater

ESF engineered safety feature

HPI high pressure injection

JO job order

LER licensee event report

MSSV main steam safety valve

RAS recirculation actuation signal

RCP reactor coolant pump

RCS reactor coolant system

RWT refueling water tank

SFP spent fuel pump

SW service water

TS Technical Specification

UGS upper guide structure