ML20149L575

Insp Repts 50-369/97-09 & 50-370/97-09 on 970518-0628. Violations Noted.Major Areas Inspected:Aspects of Licensee Operations,Engineering,Maint & Plant Support

ML20149L575
Person / Time
Site:	Mcguire, McGuire
Issue date:	07/28/1997
From:	Mike Franovich, Scott Shaeffer, Marvin Sykes NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20149L565	List: ML20149L562 ML20149L570 ML20149L575
References
50-369-97-09, 50-369-97-9, 50-370-97-09, 50-370-97-9, NUDOCS 9708040119
Download: ML20149L575 (42)

See also: IR 05000369/1997009

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U.S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos: 50-369. 50-370

License Nos: NPF-9, NPF-17

Report No: 50-369/97-09, 50-370/97-09

Licensee: Duke Power Company

Facility: McGuire Nuclear Station Units 1 & 2

Location: 12700 Hagers Ferry Rd. l

Huntersville, NC 28078 l

Dates: May 18 - June 28, 1997

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Inspectors: S. Shaeffer Senior Resident Inspector

M. Sykes Acting Senior Resident Inspector

M. Franovich, Resident Inspector )

R. Moore, Regional Inspector (Sections E2.2. E2.3)  ;

H. Whitener, Regional Inspector (Sections M4.2, M6,

D. brbe bg n Inspector (Section R1)

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Approved by: K. Landis, Acti,1g Chief. Projects Branch 1

Division of Raactor Projects

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Enclosure 2

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9708040119 970728

PDR ADOCK 05000369

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EXECUTIVE SUMMARY

McGuire Generating Station. Units 1 & 2

NRC Inspection Report 50-369/97-09. 50-370/97-09

This integrated inspection included aspects of licensee operations, engineer- i

ing, maintenance, and plant support. The report covers a six-week period of

resident and Region inspection. l

Operations

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. Unit 2 control room operator response to the loss of main turbine

hydraulic oil system fluid inventory was good, minimizing the potential

for a turbine trip and subsequent reactor trip that could have l

challenged safety systems. (Section 01.2)

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. The licensee reported operational events in accordance with the

requirements of 10 CFR 50.72. (Section 02.1)

. The overall Unit 2 shutdown for identified steam generator leakage was

well controlled. The active monitoring of the identified steam ,

generator leakage and the management decision to shutdown the unit to l

repair existing leakage was conservative. As a result, no l

administrative or Techriical Specification limits for reactor coolant j

system leakage were exceeded. (Section 02.2)  !

. The resolution of the low reactor coolant system loop 'A' temperature

indication reading (input to the Unit 2 Operator Aid Computer) was

adecuately addressed. Alert operator identification of the issue was a

gooc example of maintaining a questioning attitude and attention to

detail. (Section 02.3)

. The licensee exhibited superior safety focus in preparing for midloop

o]erations and was proactive in reducing shutdown risk. Enhancements to

t7e procedure for loss of decay heat removal and emergency core cooling

system equipment availability were considered good shutdown risk actions

with appropriate consideration for Low Temperature Over Pressure (LTOP)

restrictions. A pre-job brief was performed with excellent focus on the

low thermal margin and examples of operator related industry shutdown i

events. Reactor coolant system drain down was effectively conducted

with good procedural compliance, outstanding communication among reactor l

operators, and strong oversight. Overall. the licensee's shutdown risk

management was a strength. (Section 4.1)

. Control of overtime for plant personnel during this review was adequate.

In addition, the licensee's assessments performed on the control of

overtime were detailed and provided good oversight. Licensee postings

of notices to workers was also adequate. (Sections 06.1 and 06.2)

Enclosure 2

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Maintenance

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In general, the post maintenance test program was satisfactory with good

procedures in place to perform retest tasks. (Section M1.2)

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Licensee self assessmerit and reassessment of retest problem issues

resulted in improved performance in this area. (Section M1.2)

• Post maintenance testing program implementation weaknesses were

identified related to completeness of the Retest Manual. documentation

of the justification for not performing a retest, and retest evaluation

with no oversight review. (Section M1.2)

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The licensee had develo)ed, documented and implemented a Planning ?.nd

Scheduling process whic1 was functioning well. (Section M1.3)

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Monitoring and trending performance data indicated that the Planning and

Scheduling process had been effective. (Section M1.3)

- . Operators' response to the inadvertent engineered safety feature

actuation, which occurred on May 27, 1997, during emergency diesel l

gerierator load sequencer testing, was adequate and complied with TS '

requirements. Operator actions were adequate. A Violation was I

identified for an inadequate test procedure. (Section M2.1) )

. The licensee's final repairs to the Unit I high pressure (HP) turbine l

blade ring locating pins were adequate. However, the repetitive HP ,

turbine steam leaks were identified as an example of incomplete root I

cause reviews on secondary components. (Section M2.2)

. A weakness was identified concerning the isolation of the instrument air

supply to heater drain valves during turbine building cleaning

activities due to ineffective vendor oversight. The vendor personnel

1 did not receive sufficient guidance prior to the start of the activity.

As a result. the contract workers initiated an operational transient by

manipulating Operations controlled equipment. (Section M2.3)

. Unit 1 restart testing following the Steam Generator (SG) Replacement

Outage was adequately planned and executed to verify SG design and

ensure reliable operation of the Unit 1 control systems. (Section M3.1)

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. SG tube inspection and leak repairs were adequately performed. However,

the followup to an earlier SG indication in the area of the identified

leak led to a missed opportunity to prevent this event. Actions to

correct the problem and ensure that other oversights did not occur were

good. This problem was identified as an Unresolved Item pending further ,

review of the root cause of the SG inspection process. (Section M4.1) l

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Enclosure 2

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Enaineerina

. Once identified. the licensee initiated appropriate actions to address

the potential for non-conservative Technical Specification (TS) for

inoperable main t. team safety valves (MSSV). Although adequate

administrative controls were in place and no actual MSSV inoperability

occurred, the licensee did not immediately pursue a TS Amendment, which

led to delays in final resolution and identification of all pertinent

issues. (Section El.1)

. The addition of a second auxiliary feedwater condensate storage tank

(AFWCST) was a timely and positive action to increase auxiliary

feedwater supply inventory and improve pump suction reliability.

Installation of vortex suppressors was a conservative management

decision following detailed engineeririg analyses. (Section E2.1)

. The modifications completed during the Unit 1 outage demonstrated

appropriate control of the design control process at McGuire.

Performance was good for modifications, procedures. 50.59 evaluations

and screening. (Section E2.2)

. Engineering's upgrade and validation of Design Base Document (DBD) Test

Acceptance Criteria (TAC) sheets for Inservice Test (IST) valves was an

example of good engineering support to operations. The TACs provided a

good design reference for Operations to maintain system operability when

safety-relai.ed valves were out of service for testing. (Section E2.3)

. Initial Unit 1 fuel assembly K-45 reconstitution work activities were l

well controlled and good communication and oversight existed between the j

station and contract employees. Reactor engineering personnel were i

knowledgeable and the 10 CFR 50.59 evaluation was adequate. Appropriate

reactor engineering oversight was present and adequate radiation

protection coverage was provided. (Section E3.1)

. The inspectors concluded that the licensee developed adequate procedures

and controls for replacement of the battery / charger EVCA. Modification

packages for installation of the temporary battery were adequate.

Contingencies were established to identify necessary actions in the

event of a loss of the temporary battery or the spare charger while

replacement was in progres.s. The licensee delayed return of the battery

to service to minimize potential plant impact during Unit 2 draindown ,

and midloop operations. The replacement activities were completed l

within the authorized TS allowed outage times. (Section E4.1)

Plant Suonort

. At the time of the inspection. the inspectors determined that the

licensee was in the process of developing procedures and work practices

to maintain effective contamination controls and to maintain exposures

ALARA during work evolutions on two removed SGs. (Section R1)

Enclosure 2

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. Emergency preparedness practice drill scenario was adequate to

effectively test the Emergency Res)onse Organization (ERO) participants.

The ERO performance was adequate; lowever, additional management

emphasis of ERO expectations was necessary. (Section Pl.1)

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Based on the inspectors concerns. the licensee initiated the development

of additional testing for the fire suppression system interior loop

piping. The inspector concluded that the enhanced testing would provide

additional indications of system degradation. The inspectors also

concluded that the administrative processes for long-term monitoring of

the fire protertion system for degradation could be improved. An IFI

was identified to evaluate the future enhanced system testing.

(Section F3.1)

Enclosure 2

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Report Details

Summary of Plant Status

Unit 1 began the inspection period in MODE 3 (Hot Standby) returning from

MODE 5 (Cold Shutdown) following replacement of a failed intermediate range

power detector. On May 18. the unit was taken critical. On May 20 with the

unit at ap3roximately 6 percent power, an unplanned turbine trip occurred

during tur)ine trip testing. After the apparent cause of the turbine trip was

identified, the turbine was again latched and power escalation continued. On

May 23. after successful completion of a 10 percent load reduction test from

38 percent power, the unit reduced power to approximately 10 percent to repair

a failed seal weld on the high pressure turbine blade ring locating pins.

Once repaired power escalation continued. On May 25. a second 10 percent

load reducto test was successfully completed at approximately 78 percent

power. Unit pt.ser was then increased to approximately 99 percent to allow for

performance of secondary heat balances to verify primary and secondary

parameters. On May 30. a rapid downpower was performed following

identification of a hydraulic fluid leak on the C low 3ressure turbine

intercept valve. At approximately 17 Jercent power t1e operators tripped the

main turbine and reactor power was sta)ilized at approximately 12 percent. On

May 31, after leak repairs were completed, power escalation continued. On

June 1. a second unanticipated turbine trip occurred during turbine trip

testing. The cause of this and the May 20th turbine trips were determined to

be equipment malfunctions. Power escalation continued to approximately 100

percent. On June 2. unit power was reduced to approximately 12 percent to

repair a repetitive steam leak on the high pressure turbine casing. After

repairs were completed, unit power was increased to 100 percent. The unit

operated at approximately 100 percent power for the remainder of the

inspection period.

Unit 2 began the inspectian period at approximately-100 percent power. On May

22. a small secondary transient occurred when vendor personnel inadvertently

isolated instrument air to moisture se)arator reheater (MSR) valve

controllers. Unit load decreased slig1tly. On May 27. an inadvertent

Engineered Safety Feature (ESF) actuation occurred in Unit 2 during emergency

diesel generator (EDG) sequencer testing. On June 2. 1997, both units entered  !

TS 3.0.3 due to an auxiliary building ventilation boundary door being open. I

which caused both trains of control room ventilation system to be declared

inoperable. Subsequent testing determined both trains were operable.

During the inspection rariod, primary to secondary leakage on the 2A steam  ;

generator (SG) increa',ed from approximately 10 gallons per day (GPD) to '

a) proximately 65 GPD. On June 13, 1997. plant management decided to shutdown

t7e unit to identify and correct the primary to secondary steam generator

leakage. On June 15. the plant entered MODE 5 (Cold Shutdown) to support the

steam generator work. Two periods of midloop operation were recuired to

support the leak repair and inspections. The unit was restartec on June 28

from the SG repair outage. At the close of the period, the unit was in MODE 1

(Power Operation), with preparations underway to place the unit on-line.

Enclosure 2

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Review of Vodated Final Safety Analysis (UFSAR) Commitments

While performing inspections discussed in this report the inspectors reviewed

the applicable portions of the UFSAR that were related to the areas inspected.

The inspectors verified that the UFSAR wording was consistent with the

observed plant practices, procedures. and/or parameters.

I. Doerations

01 Conduct of Operations

01.1 General Comments (71707)

Using Inspection Procedure 71707, the inspectors conducted frequent

reviews of ongoing plant operations. In general, the conduct of

operations was professional and safety-conscious; specific events and

noteworthy observations are detailed in the sections below. Operators'

transition to dual unit operations was conducted in a safe manner.

Various Unit 1 power changes due to equipment problems were adequately

performed. Operator awareness of primary to secondary leakage on the 2A

SG was heightened and plant chemistry sampling of the leak was

conservative and frequent, The shutdown and restart of Unit 2 to repair

the identified the SG tube leakage was conducted in safe manner, which

included periods of reduced reactor coolant system (RCS) inventory

conditions.

01.2 Unit 2 Hydraulic Fluid Leak

a. Inspection Scone

The inspectors responded to notification of a hydraulic fluid leak from

the Unit 2 Main Turbine Hydraulic Oil (LH) System.

Observations and Findinas

On May 30. 1997. the licensee reduced power after identification of a

main turbine hydraulic oil system leak. Control room operators began a

controlled downpower in accordance with abnormal operating procedure

AP/2/A/5500/04 Rapid Downpower. With the unit at approximately 17

percent reactor thermal power the main turbine throttle valves moved to

the closed position after hydraulic fluid inventory was depleted.

Operators manually tripped the turbine and generator. The reactor

remained at appproximately 17 percent power.

The licensee determined that a hydraulic fluid system fitting failed

releasing the hydraulic fluid inventory to the Unit 2 turbine deck and

subsequenth into the turbine building drains. The drain system was

isolated preunting the release of the material to the environment. The

licensee conducted immediate repairs of the fitting and completed a

thorough cleanup of the turbine building and turbine building sump.

Enclosure 2

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l Because the hydraulic fluid was identified as a hazardous chemical, the

licensee isolated the turbine building sump discharge until cleanup of

the chemical was completed. The unit was subsequently returned to rated

power.

l c. Conclusions

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The inspectors concluded that the Unit 2 control room operator response

to the loss of main turbine hydraulic fluid was prudent, minimizing the

l potential for a turbine trip and subsequent reactor trip that may have

challenged safety systems.

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02 Operational Status of Facilities and Equipment (71707) {

l 02.1 10 CFR 50.72 Notifications

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l a. Insoection Scooe

During the inspection period, the licensee made the following

notifications to the NRC as required for information purposes. The

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inspectors reviewed the events for impact on the operational status of I

the facility and equipment.  !

b. Observations and Findinas

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On May 20. 1997, the licensee made a report in accordance with 10 CFR

50.72 regarding non-conservative Technical Specification (TS) ACTIONS l

l associated with postulated inoperable main steam line safeties. This l

report was considered a followup to an earlier report on March 20. 1997

describing postulated situations where TS ACTIONS may not require the

most limiting power levels for inoperable main steam line safety valve

configurations (see Section El.1 for details). The licensee has

submitted a Licensee Event Report (LER) on the issue.

On May 27, 1997, the licensee made a report in accordance with 10 CFR

50.72 due to an ESF actuation which occurred during testing of the Unit

2 EDG sequencer logic (see Section M2.1 for details). The licensee

plans to submit an LER on the event.

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On June 2.1997.. the licensee made a report in accordance with 10 CFR

50.72 after declaring both trains of auxiliary building and control room

ventilation inoperable (TS 3.0.3). 03erability of the systems was

questioned during ventilation system 30undary alterations to support

vital battery modifications. However, subsequent testing verified that

the systems were operable. The notification was retracted on June 11.

On June 9. 1997, the licensee made revisions to a previous report in

i accordance with 10 CFR 50.72 due to additional information identified

j regarding potential operability concerns on the auxiliary feedwater

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(AFW) suction supply (see Section E2.1 for details). .

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c. Conclusions

The inspector concluded that the licensee reported the above events in

accordance with the requirements of 10 CFR 50.72.

02.2 Unit 2 Shutdown for Identified Steam Generator Tube Leakaoe

a. Insoection Scooe

The inspectors reviewed the shutdown of Unit 2 for identification and

repair of SG tube leakage.

b. Observations and Findinas

Du,'ing the beginning of the inspection period, the licensee had been

actively monitoring a primary to secondary leak on the Unit 2 A SG.

Monitoring of the leakage was established in February 1997 with an

indication of approximately 2 Gallons Per Day (GPD). The TS operational '

limit for SG primary to secondary leakage is 500 GPD: however, the

licensee had established a more conservative administrative limit of 100

GPD for the Unit 2 SGs. Throughout in the inspection period, the

identified leakage had increased to approximately 65 GPD. On June 13. l

the licensee decided to initiate a forced outage to identify and repair

the Unit 2 primary to secondary leakage. The Unit 2 SGs were scheduled i

to be replaced during the next Unit 2 refueling outage scheduled to '

begin in September 1997. The Unit 1 SGs have already been replaced  ;

during the Unit 1 End of Cycle 11 refueling outage. l

The inspectors observed portions of the planned unit shutdown and

verified SG 1eakage limits did not increase during the evolution.

Operators involved in the shutdown evolutions were attentive and

maintained TS parameters within limits. Shift briefing prior to the

shutdown highlighted potential problems during the downpower, what

contingency measure were required, and stressed monitoring key

parameters. The inspectors noted that specific measures were in place

to heighten communications between the operating shift and the secondary

chemistry staff to monitor the SG leakage for adverse change. On June

15. the unit entered MODE 5 (Cold Shutdown) to establish conditions to

support the SG repair work.

c. Conclusions

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The inspector concluded that the overall shutdown evolutions were well '

controlled. The inspector also concluded that the active monitoring of I

the identified SG leakage and the management decision to shutdown the i

unit to repair existing leakage was conservative. As a result, no

administrative or TS limit for RCS leakage was challenged or exceeded.

Enclosure 2

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02.3 Unit 2 Low RCS Looo Temoerature Readina

l a. Insoection Scope

The inspector reviewed the circumstances involving a Unit 2 low RCS loop

'A' temperature reading and the potential impact on calculation of

primary thermal power.

b. Observations and Findings

During the inspection period, a Unit 2 operator identified a low RCS

temperature indication during a review of inputs into the primary

thermal power calculation. At the time, primary thermal power was

indicating 103.3 percent and the loop A Tcold was reading 549 F when it

should have been reading 558 F.

According to the licensee, above 50 percent power, primary power best

estimate calculations are based completely on secondary parameters.

Differential temperature inputs for the reactor protection system did

not appear to be affected. The licensee's review indicated that this

input point to the Unit 2 operator aid com) uter (OAC) had fluctuating

readings between May 21 and May 31. A worc order was written; however,

no corrective action was required because the indication was found to be

correct (i .e. , not fluctuating). The licensee plans on monitoring this

OAC data point through the system health monitoring program and replace

the isolator board (only component that could cause the fluctuations) if

any drift is observed. This issue was documented in PIP 2M97-2169.

c. Conclusions

The inspector concluded that the resolution of the low RCS loop ' A'

temperature indication reading (input to the Unit 2 OAC) was adecuately

addressed. Alert operator identification of the issue was a gooc

example of maintaining questioning attitude and attention to detail .

04 Operator Knowledge and Performance

04.1 Unit 2 Reduced Inventory Ooerations

a. Insoection Scoce (71707. 40500)

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During the inspection period. Unit 2 was shut down in response to

l identified steam generator (SG) tube leakage. Before the unit entered  :

l reduced inventory operations to facilitate SG tube repair, the inspector ,

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reviewed the operations and SG inspection schedules to identify any l

potential periods of increased shutdown risk. The inspector reviewed ,

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the forced outage plans to drain down the reactor coolant system (RCS).  ;

enter midloop operations install and remove SG nozzle dams, and re- '

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flood the RCS. l

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Enclosure 2

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The inspector reviewed station shutdown and abnormal procedures: ,

reviewed pre-job briefing materials: attended a midloop pre-job  !

briefing: witnessed portions of the draindown and midloop operations;

confirmed TS compliance: reviewed recommendations from the McGuire i

Independent Review Team (IRT) assessment of outage risk: and attended

the associated PORC meeting on procedure enhancements for coping with a

loss of residual heat removal (RHR). The inspector also reviewed

Generic Letter No. 88-17. Loss of Decay Heat Removal: the licensee's

response to GL 88-17: various plant drawings, control room log books.

forced outage schedules, containment integrity controls, and RCS makeup

capability. i

b. Observations and Findinas

Midloop operations were performed on two occasions during the Unit 2 )

forced outage. Both midloo) windows of operation were entered with fuel l

in the reactor vessel and tie vessel head remaining tensioned. The

licensee did not off-load the core during the outage.

The first reduced RCS inventory evolution occurred approximately 5 days I

after reactor shutdown. On June 18 the licensee: (1) drained down the

RCS to 28 percent of pressurizer level: (2) calibrated RCS level

instrumentation: (3) positioned a video camera for control room

monitoring of RCS level on a sight glass: and (4) drained the RCS to

aaproximately 10 inches above the centerline of the RCS hot leg piping.

T1e unit remained in midloop conditions for approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> until i

SG nozzle dams were installed. Upon a postulated loss of Residual Heat  !

Removal (RHR), the margin to core boiling was 10 minutes.  ;

The second RCS reduced inventory evolution occurred approximately 9 days  ;

after reactor shutdown. The unit remained in midloop (11 inches above

centerline) for approximately 43 hours4.976852e-4 days <br />0.0119 hours <br />7.109788e-5 weeks <br />1.63615e-5 months <br /> until completion of remaining SG

repair activities, removal of nozzle dams, and installation of SG i

manways. For this period, upon a potential loss of RHR. the margin to l

core boiling was 26 minutes during the second midloop.

Before these reduced RCS inventory evolutions. the licensee completed an

independent review of proposed shutdown operations. The licensee's

Nuclear System Directive 403. Shutdown Risk Management, requires that an

independent review team (IRT) assess proposed outage schedules and i

operations to identify any periods of reduced defense-in-depth for '

safety functions. The IRT identified reduced defense-in-depth for the ,

RHR function due to the low thermal margin of the first midloop and

proposed several contingency actions.

A significant IRT proposal involved enhancement of the loss of RHR

abnormal procedure to improve operator response time. To achieve this,

operators would immediately initiate RCS feed-and-bleed using a charging

pump and safety injection pump. Under a loss of RHR event, this

operator action would be taken if a themal margin of less than 20

Enclosure 2

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minutes existed. To im] rove res)onse time the PORC also approved the

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proposal to have availaale one clarging pump and one safety injection

pump in opposite electrical trains with power racked in pricr to

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commencing the initial drain. This system configuration required entry

into the Action Statement for Technic.1 Specification 3.4.9.3. Low

Temperature Overpressure Protection ,LTOP). and was appropriately

discussed in the PORC meeting.

Through control room board walkdowns and discussions with the operators,

the inspector verified the Emergency Core Cooling System (ECCS)

alignment approved by PORC and that controls were in place for RCS

venting during reduced inventory conditions. The inspector also

verified that the conditions of the LTOP technical specification were

satisfied. This included verification of appropriate RCS LTOP vent

paths. The ins)ector also confirmed availability of instrumentation and

RCS makeup capa]ility.

Licensee management conducted are-job briefings before the unit entered

a reduced inventory to prepare t1e operating shifts for the infrequently

performed evolution. Management expectations and safety concerns were

i emphasized during the briefing. Planr. status was reviewed with

particular interest on RCS inventory, decay heat removal capability,

containment integrity. and power scarce and ECCS availability.

Excellent attention was given to the fact that the first hot midloop was

an infrequent operating condition with low thermal margin. The pre-job

briefing material and presentation placed heavy focus on industry

shutdown events with emphasis on multiple examples of operator actions

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that contributed to the events. The inspector also noted a good

discussion among the briefing attendees with regard to equipment

. behavior from past plant experience. This was especially evident during

i discussion of RCS level instrumentation behavior and which type of

instruments provided conservative level indication. The inspector also

witnessed a good shift turnover and good communication between outgoing

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and incoming reactor operators. Operator knowledge and abilities were

excellent.

Offsite and emergency power sources were confirmed to be available.

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Switchyard work and round-cell station battery replacement activities

were postponed until after reduced inventory operations. Operators used

core exit thermocouples and RHR system inlet temperature to monitor RCS

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temperature. Operators used RHR heat exchanger outlet temperature for

Low Temperature Over Pressure (LTOP) TS restrictions.

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The inspector observed the following operations practices to minimize

shutdown risk:

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. Minimize time in midloop conditions and use of an IRT to assess

outage risk

Enclosure 2

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. PORC approved enhancement of AP/2/A/5500/19. Loss of ND (RHR) or

ND System Leakage, to allow for earlier operator action to feed-

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and-bleed the RCS with ECCS equipment

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One charging pump and one safety injection pump in opposite

electrical trains available with power racked in, the associated

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Refueling Water Storage Tank (RWST) flow path available, and

adequate RCS venting

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Gravity feed capability from the RWST to RCS (and other makeup

sources) remained available

. Thorough Significant Operating Event Report (SOER) 91-01. Pre-job

Briefing

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Minimization of control room traffic and other potential operator

distractions

. Appointment of an RCS drain down coordinator - Senior Reactor

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Operator (SRO)

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. Excellent SR0/R0 discussion of past level instrumentation behavior

. Deferral of all Unit 2 work activities such as periodic tests or

maintenance during the drain down

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Deferral of Unit 1 work that could affect Unit 2. such as

Performance Tests (pts) on shared nuclear service water systems

. Full emergency power availability

. Clear management expectations for operators to stop work if

abnormal conditions are present

. Clear explanation of roles, responsibilities, and command and

control for the drain down

Shutdown risk information was reviewed and discussed routinely during

the licensee's plan of the day meetings. The inspector verified the

accuracy of the information during daily control room visits.

c. Conclusion

For the reduced inventory evolutions, the inspector determined that

there was outstanding communication among reactor operators. A good

pre-job brief was performed with excellent focus and examples of

operator related industry shutdown events. Pre-job briefing materials

were clear and concise. Plant conditions, the low thermal margin, and  ;

contingency actions for a loss of RHR were appropriately stressed. l

There was good participation of operators in pregob discussions of

Enclosure 2 .

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plant equipment, drain down rates.. and reliability of level

instrumentation. Operations managers promoted licensed and non-licensed

operators to maintain a questioning attitude during the evolutions.

Operator heightened awareness and attention to details were evident for

reduced inventory and midloop operations.

Overall. the inspector determined that the licensee exhibited superior

safety focus in preparing for midloop operations and was proactive in

reducing shutdown risk. Enhancements to the procedure for loss of RHR

and ECCS equipment availability were considered good shutdown risk

actions with appropriate consideration for LTOP restrictions (good

balance between shutdown risk and LTOP restrictions). Further, the

licensee's actions to drain the RCS were effectively conducted with good

procedural compliance and with strong oversight. The inspector

concluded that the licensee's shutdown risk management was a strength.

06 Operations Organization and Administration

06.1 Overtime Control

a. Insoection Scope (71707) ,

The inspector performed a review of approved overtime during the most

recent months for the plant operations and maintenance groups. The

inspector also overviewed licensee records of all personnel overtime

exemptions for hours in excess of established limits. Control of '

overtime for plant personnel is required by Technical Specification 6.2.2.e and NSD 200. Overtime Control. These documents require the  ;

licensee to document and properly authorize work hour extensions. l

b. Observations and Findinas

The inspector reviewed work hour extension documentation for the subject  ;

groups and determined that the forms, in general, were properly filled i

out and reasons for the work hour extensions were appropriate for the

circumstances. The inspector verified that the station manager was

reviewing a monthly site overtime report to determine that the use of

overtime was warranted and not being abused.

The ins]ector noted that in an overtime control report dated March 21,

1997, t1e licensee's evaluation of the data identified several

discrepancies regarding the timeliness of the required forms. The

inspector verified that the appropriate corrective action documents were

initiated to address the concerns.

c. Conclusion

The inspector concluded that control of overtime for plant personnel

during this review was adequate. In addition, the licensee's i

Enclosure 2 !

!

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l l

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! 10

i assessments performed on the control of overtime were detailed and  !

provided good oversight.

06.2 Posting of Notices to Workers

, During the ins)ection period, the inspector reviewed the licensee's l

l compliance wit 1 the requirements of 10 CFR Part 19.11. Posting of  ;

i Notices to Workers. The licensee implements these requirements via NSD l

l 205. Posting Requirements. This procedure identifies three locations l

l where required postings are to be maintained. The inspector verified

that the licensee conspicuously posted current copies of NRC Form-3 and

l

other required materials such as escalated enforcement and radiological

l violations in the areas. No problems were observed by the inspectors

during this review.

'

II. Maintenance l

M1 Conduct of Maintenance

i

M1.1 General Comments (61726 and 62707)

.

! a. Insoection Scope

l

'

The inspectors observed all or portions of the following work

activities:

. PT/1/A/4206/1B Safety Injection Pump 2B Performance Test

. PT/1/A/4200/20A Unit 1 Airlock Operability Test

. PT/2/A/4600/01 RCCA Movement Test

. IP/0/A/3250/128 Train B Diesel Sequencer Timer Calibration

. WO 96089566 Temporary Vital Battery Installation l

b. Observations and Findinas l

l

The inspectors witnessed selected surveillance tests to verify that i

approved procedures were available and in use, test equipment in use was '

l calibrated test prerequisites were met, system restoration was

completed, and acceptance criteria were met. In addition, resident

'

l

inspectors reviewed and/or witnessed routine maintenance activities to

verify. Where applicable that approved procedures were available and in

use, prerequisites were met, equipment restoration was completed, ana

maintenance results were adequate.

l

Enclosure 2

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, .

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l 11

c. Conclusion

'

The inspectors concluded that routine maintenance activities were

! performed satisfactorily.

j M1.2 Review of Post Maintenance Testina

a. Scooe (62700)  !

!

'

During this inspection period, the inspectors reviewed the work process

I

for controlling post maintenance testing (PMT) and the licensee's

corrective actions for failure to perform PMT adequately on a number of

occasions in the past 18 months.

b. Observations and Findinos 1

l

Post maintenance testing was controlled through the Corporate Nuclear

System Directive. NSD 408, " Testing," Revision 4: Work Process Manual .

(WPM) Section 501 " Post Maintenance Testing." Revision 0, " Post

l

Maintenance Testing Guidance Document," Revision 0: and Post Maintenance  !

Test " Retest List," Revision 0. In general, these documents provided a i

sound basis for maintenance activities including post maintenance l

testing. Responsibilities of management, groups, and crafts were '

described; processes to be followed were specified; and retest

requirements were delineated.

In 1996. the licensee identified several cases of missed or near missed

retests. Problem investigation Process (PIP) reports were written to

determine the causes and to track specified corrective actions for these

events. Assessment of the PIPS showed that nearly all retest  :

deficiencies identified in 1996 fell into one of three broad categories i

as follows: i

1

-

Retest Designations: failure of the planner to properly plan a  ;

retest into the work plan (human error). i

l

-

Retest List Discrepancies: failure of the retest list to

encompass all components requiring retest leading to no retest

task in the work plan.

l

-

Execution of retest tasks in a timely manner: the work plan was

adequate but the retest was not performed in a timely manner.  ;

This problem was two fold. First on occasion tasks were removed I

from the Technical Specification Action Item List (TSAIL) before

retest was performed. TSAIL was an electronic log to identify

active maintenance work orders and tasks. Second, a work status

communication problem between the craft and operations test group ,

caused unnecessary delays in performing retests. '

Actions taken to correct these conditions included the following:

'

Enclosure 2

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

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12

-

All work plans received a peer review before issuance.

-

Revision of the Retest Manual. Two source documents for required

retests were combined into one Retest Manual. This reduced

confusion and

Additionally, potential

identifiederrors

components in the planning

requiring process.

retest, which were  ;

not listed in the Manual, were incorporated into the manual.

l -

A change was made in the electronic format of TSAIL to prevent

!

entry of tasks. Only work orders could be entered. Therefore,

operators were required to review all tasks associated with a work .

l

order for completeness prior to removing the work order from the

list.

No corrective action directly addressed the communication problem

between the craft and the operations test group.

In May 1997, Work Control Assessment 97-1 was performed to determine if

corrective actions taken had been effective. The licensee determined

that the corrective actions had not been totally effective as follows:

-

Retest Designations: Assigning a peer review of planr.ing work had

been effective. No additional cases of failure to include retest

tasks in the work plan had been observed.

-

Retest List Discrepancies: Revision of the retest list had  ;

l improved this document. All source information was incorporated

l into one retest list.

l

-

Execution of retests in a timely manner: A change made to the  ;

electronic program allowed only a work order number to be entered i

! into TSAIL. In order to remove completed work from the TSAIL log

l the operators must verify completion of all task assignments

i associated with a work order. This resolved the issue of tasks

being removed from TSAIL before the work was completed. However,

rapid communication of test status between the craft and the

operations test group remained a problem.

The inspectors considered that the self assessment and re-assessment of

the retest problem issues resulted in improved licensee performance.

During the review the inspectors made several observations regarding

program implementation weaknesses, as follows:

-

In some instances where the Retest Manual required a retest,

planners had issued a task in the work order for the operations

test group to evaluate the need for a retest after review of the

actual maintenance activities rather than specifying retest

l required.

.

1

Enclosure 2 i

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_-

_ _ _ .

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.

l

13 l

4

-

Operations group Jersonnel involved in retest evaluations were

highly trained. lowever, one individual typically reviewed the

maintenance activities that had actually been performed and made a

determination if retest was required. There was no further

oversight of these decisions.

-

For some work orders, there appeared to be inadequate

documentation in the work management system on why a retest was

not required.

-

The completeness of the Retest Manual has not been verified by a

structured or formal review. ,

The inspector discussed these items with the licensee.

Tne licensee indicated that a Quality Improvement Team would be

initiated to review the retest manual and identified weaknesses.

In additicn to review of the above documents, the inspectors reviewed

four work packages which contained several work orders and numerous task

descriptions as follows:

-

Replace Upper Motor Bearing on Residual Heat Removal Pump 1A.

-

Repair Safety Injection Valve 1NI-120B Actuator Oil Leak and Seat i

Leakage.

!

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PM on freedom of motion of Mechanical Snubbers.

-

Repair 1B Main Feedwater Pump Inboard Bearing.

The inspectors determined that the work plans contained adequate

instructions for the tasks to be performed; appropriate, ap] roved l

procedures were identified and used to accomplish these tascs: and

procedure references to vendor manual and technical information were

included. Retest tasks were performed as required.

c. Conclusions

In general, the post maintenance test program was satisfactory with good

procedures in place to perform retest tasks.

Licensee self assessment and reassessment of retest problem issues

resulted in improved performance in this area.

Post maintenance testing program implementation weaknesses were

identified related to completeness of the Retest Manual, documentation

of the justification for not performing a retest, and retest oversight

review.

Enclosure 2

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.

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14

M1.3 Review of Planning and Schedulina

a. Scope (62700)

During this ins 3ection period the inspectors reviewed the licensee's

Planning and Scleduling Process.

b. Observations and Findinas

The licensee was using a totally electronic work order / task system. The

process for planning and scheduling work under the Work Management

System (WMS) was described by the Work Process Manual (WPM). Section

500." Planning," Revision 5. Responsibilities of management. Planners.

Schedulers, groups, and crafts were described; processes to be followed

were specified; and interface with the electronic system was detailed.

Planning was performed by Central Planning (process and WMS expertise)

or Field Planning Technicians who are assigned to the execution teams.

Central Planning performed the more complex work planning and provided

oversight, consistency, and assistance as needed to the Field Planners.

Field Planners performed work history reviews and job site walkdowns.

They also determined the workforce requirements, need for support

functions, and the scope of work to be performed.

McGuire used the concept of system work windows (SSW) to schedule and

Execute on-line maintenance. In this process important plant systems

were logically grouped and assigned to an execution week within a twelve

week rotation. The groupings were designed to:

-

eliminate PRA risk due to critical system combinations.

-

maximize system / component availability.

-

optimize maintenance by consolidating maintenance on components.

,

Work activities were slotted into the System Work Windows through

several paths. Repetitive work such as preventive maintenance (PM) and

periodic tests (PT) were controlled through the PM/PT program. These

activities were populated directly into the schedule. in a repeating

fashion, at prescribed intervals. A minimum of 16 weeks of future

System Work Windows were kept populated with PM/PT activities.

Corrective maintenance was identified through the work request / work

order system. All new work orders were reviewed in the daily Work Order

Scoping Meeting for confirmation that the scope was appropriate and for

assignment to the appropriate system work window. These meetings were

attended by representatives from all departments. When an item reached

the seventh week before scheduled execution. it would undergo an intense

review process until execution. Emergent corrective work orders which

were written to address urgent plant deficiencies, were immediately

added to the schedule by the Work Window Manager. These items were

Enclosure 2

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.

! 15

reviewed for Risk and sometimes required rescheduling some work

activities.

~

The ins)ectors also reviewed a number of performance indicators such as

the num)er of planning errors, number of schedule errors, and total

reschedules. These indicators showed that the Planning and Scheduling

process was working effectively.

4 Based on review of plant documents and interviews with ex)erienced

l Planners and Schedulers the inspectors determined that t1ere were a

4

number of checks and balances in the system to ensure that proper

verifications and reviews were performed.

.

,

c. Conclusions

4

The licensee had develo)ed, documented and implemented a Planning and

Scheduling process whici was functioning reasonably well.

Monitoring and trentiing performance data indicated that the Planning and

Scheduling process had been effective.

M2 Maintenance ana Material Condition of Facilities and Equipment (62707)

M2.1 Inadeauate Emeroency Diesel Generator (EDG) Load Secuencer Testina

Resultina in ESF Actuation

a. Insoection Scope

The inspector reviewed an inadvertent ESF actuation which occurred on

May 27, 1997, during EDG load sequencer testing.

b. Observations and Findings

Unit 2 was at 100 percent power at the time of the event with the 2B

EDG tagged out of service for performance testing in accordance with

IP/0/A/3250/012B, Train B Diesel Sequencer Timer Calibration. Train B

ECCSs were also tagged out for testing, but were available. During

performance of the EDG sequencer relay testing, a partial Train B

sequencer actuation (blackout) occurred which resulted in an autostart

of the Turbine Driven (TD) Auxiliary Feedwater (AFW) pump and the

standby nuclear service water (NSW) pump, as well as the realignment of

various NSW system valves. Operators responded to these indications and

instructed the involved test personnel to discontinue the test. While

in process of verifying a sliding link position, previously opened by

the test procedure, a partial Train B safety injection (SI) actuation

occurred. Operators entered appropriate procedures to control the

event. The ECCS pumps started and ran in recirculation as designed. No

ECCS injection into the RCS occurred as a result of this event. The

train A EDG and ECCS systems remained operable throughout the event.

The unit remained at approximately 100 percent power.

Enclosure 2

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16

After the inadvertent SI actuation, the TD AFW pump auto-start signal

was still present while engineering personnel reviewed the cause of the

event. Operators locally tripped the TD AFW pump following report of a

burning smell in the pump area. Tri

non-safety AFW supply source usage. Thepping

smell the

wasTD AFW

later pump also

determined to limited

be from recently installed insulation and not a challenge to the pump.

The trip)ing of the TD AFW pump, coincident with the Train B motor

driven A W pump being technically inoperable, resulted in the unit

entering the TS ACTION requirements of 3.7.1.2. Several hours later, it

became apparent that the troubleshooting would extend beyond the TS

limits for o]eration: therefore, the operators restarted the TD AFW pump '

and exited t1e shutdown Limiting Condition for Operation (LCO). Early

on May 28 troubleshooting of the sequencer circuitry was completed and

the system was reset. At that time, all ECCS components were returned

to standby readiness.

The inspectors reviewed the root cause of the event with the licensee.

The train B EDG sequencer timer calibration procedure. IP/0/A/3250/012B,

had been revised to incorporate enhanced testing of safety-related logic

circuits pursuant to NRC Generic Letter 96-01. Specifically. the

existing test incorporated testing of the sequencer test circuitry to

ensure that the sequencer would come out of test and begin sequencing if

a valid SI or blackout signal occurred. The revised procedure had

incorporated the manipulation of a sliding link to maintain a test timer

relay de-energized, such that the portion of the circuitry under test

would be isolated. However, engineering personnel failed to identify a

circuit interaction which bypassed the function of the sliding link.

The oversight prevented adequate isolation of the test circuitry and

allowed partial sequencer logic to be satisfied when the blackout signal

was introduced for the test. Subsequent review also determined that the

partial SI occurred when test personnel were attempting to verify the

position of the sliding link. The licensee concluded that the nut

driver being used to verify the position of the sliding link contacted

both sides of the terminal. This caused a momentary SI signal which

energized the sequencer loading relays, resulting in the Train B ECCS

pump starts.

Initial corrective actions for the event included initial

troubleshooting of the cause of the actuations, verification of the

expected ECCS and other components to the inadvertent signal, and

restoring the equipment to standby status. All equipment responded as

expected. The inspectors discussed the test procedure changes and

revision processes with engineering personnel and management. Based on

the discussions. the inspectors concluded that the reviews for the test

procedure (IP/0/A/3250/0128) were inadequate, and resulted in the

procedure being inadequate to perforn the enhanced test. The inspectors

also noted that the independent review also failed to identify the

procedure inadequacy.

1

!

! Enclosure 2

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. - -

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.

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17  !

c. Conclusions

l

Operator response to the event was adequate and compliance with TS i

.

equipment operability was maintained. The inadequate test procedure is

.

a Violation (VIO) of TS 6.8.1 and will be identified as VIO 50-370/97-

l 09-01: Inadequate Test Procedure. During closeout inspection of the LER i

,

associated with this event, the inspector will continue to review i

operator actions associated with securing the TDAFW pump per applicable

procedures and appropriate logging of the event.

,

M2.2 Hiah Pressure (HP) Turbine Blade Rina Locatina Pin Weld Defects

a. Insoection Scone

l

'

The inspectors reviewed the corrective actions associated with weld

problems on the subject components and the extent of condition review.

l

b. Observations and Findinas 1

On May 23, with Unit 1 at approximately 38 percent power. operators

received a computer alarm on the high pressure turbine indicating a high

differential extraction zone temperature. A non-licensed o)erator (NLO)

was dispatched and reported that a small steam leak under t1e high

pressure turbine was condensing and running on the local area

thermocouple. Engineering management determined that a repair should be

completed and after adequate manpower resources were obtained, the unit

reduced power to ap3roximately 10 percent. The leak was determined to

be on one of eight iP turbine blade ring locating pins, which are

installed to hold the stationary HP turbine blades in place. These

smooth cylindrical pins are approximately 3.5 inches in diameter and 10

inches long. They are seal welded after installation to form the HP

turbine steam boundary and were recently replaced during the Unit 1 End-

Of-Cycle (EOC) 11 outage along with the installation of new HP turbine

blade rings.

The leaking pin had a one to two inch circumferential weld crack with

some evidence of porosity. Examination of the cracked weld and weld l

historical documentation identified that the eight pin welds had j

potentially been performed at a low preheat condition (200 vs 350 1

degrees F). The main steam sto) valves were closed for the repair and l

the HP turbine was under a slig1t vacuum. The non-code repairs of the

failed area were completed at the increased preheat level and irivolved

grinding of the original seal weld and refill. Additional grinding and  !

weld build up were performed on other pins as needed. After visual

inspections were performed, the unit increased power.

On June 2. unit power was reduced to ap]roximately 12 percent to repeat

the repair of a similar steam leak on t1e high pressure turbine blade

locating ring pins. The second leak was on a different locating pin

than the first failure. Subsequent discussion with the pin sur 'ier

Enclosure 2

i

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18

,

identified that the pin material was different than what was assumed for

the original seal welding. The difference in material specifications

resulted in the most ideal weld material not being chosen for the

application. An additional contributor to the problem was that a visual  !

inspection was the only NDE performed on the work. Corrective actions  :

for the repetitive problem included:  !

.

Use of more suitable weld roa material (more ductile)

.

Review of the weld area to reduce the difficulty in making good

quality welds j

. Performance of a more thorough non-destructive examination (i .e. . l

magnetic particle testing and dye penetrant testing)

. Review of current non-code repair NDE inspection criteria to

determine their adequacy to identify these type of problems

The licensee's corrective actions were documented in Problem

Identification Process (PIP) reports 1-M97-2160 and 1-M97-2241. Final

repairs for the pin seal were completed and more rigorous NDE

evaluations were accomplished. An additional measure to assure proper l

weld material applications occur on Unit 2 was included in the PIP

corrective actions.

c. Conclusions

Based on the above. the inspectors concluded that the licensee's final

repairs to the HP turbine blade ring locating pins were adequate. The

inspectors also concluded that the repetitive HP turbine steam leaks

were an example of incomplete root cause reviews on secondary

components.

M2.3 Vendor Control

a. Inspection Scope

The inspectors investigated activities that resulted in the inadvertent

isolation of instrument air to the Unit 2 moisture separator reheater

drain valve controllers causing an unplanned reactor thermal power

increase and a reduction in main feedwater suction supply pressure. The

resulting valve realignments also caused a reduction in electrical power

output.

b. Observations and Findinas

On May 22, the control room operators. responding to various indications

and alarms of moisture separator reheater valve movement and decreasing

main feedwater suction pressure, started a standby hotwell pump to

maintain adequate main feedwater pump suction pressure and dispatched

Enclosure 2

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l

l

,

19

operators to the turbine building to identify the cause. The dispatched l

operators determined that the moisture separator reheater drain valves

had isolated due to a loss of their instrument air sup)ly. The

operators re-established instrument air and returned tie valves to the

normal operatin Main feedwater suction pressure, reactor

thermal power.andg positions.

electrical output were returned to normal. Reactor

thermal Jower momentarily increased to approximately 100.7 percent

during tais transient.

Further investigation identified that vendor personnel had inadvertently

'

isolated instrument air while performing routine turbine building i

cleaning activities. The vendor had been instructed to use station air

instead of instrument air when performing cleaning activities in the

turbine building. The inspectors discussed the event with the licensee  ;

and reviewed station documentation and determined that the vendor crew  !

! had not received adequate instructions to ensure that the work l

! activities were completed without technical errors. Although the use of '

instrument air was not authorized for the activity, the vendor did not

l receive sufficient instruction on the potential consequences of

repositioning operations controlled equipment. The licensee has

established plans to evaluate contract training requirements emphasizing

potential operational transients due to manipulating plant equipment.

Conclusions

l

l The inspectors concluded that the isolation of instrument air, which is

nonsafety-related at McGuire, was an example of ineffective vendor

oversight. The vendor Jersonnel did not receive sufficient guidance

prior to the start of t1e activity. As a result, the contract workers

initiated an operational transient by manipulating Operations controlled

equipment. This is considered a weakness in the area of vendor control.

M3 Maintenance Procedures and Documentation (62707)

l

l M3.1 Steam Generator Replacement Pro.iect (SGRP) Post-Installation Review and

Control System Doerability Verification

a. Inspection Scoce

l

The inspectors evaluated the results of the licensee's performance

testing of the Unit 1 operating characteristics and control system

,

response following replacement of the Unit 1 SGs. The inspectors

i

reviewed selected documentation to verify that Jost modification

activities such as drawing updates, procedure clanges, resolution of

outstanding issues, and training had been revised to reflect the

configuration changes associated with SG replacement.

'

b. Observations and Findinas

.

Post-Installation Insoections

Enclosure 2

i

l

I

l

l

20

Inspections of the leak tightness of the system was performed at full

temperature and pressure in accordance with NRC approved ASME Code Case

N-416-1. SG secondary side hydrostatic testing was performed by the

manufacturer. The inspectors and the licensee conducted visual

inspections of the reactor coolant system and noted no external leakage.

Steady State and Transient Testina

l The licensee performed testing to confirm the SG design and to establish

l baseline measurements. The testing was conducted during steady state

l

'

and transient conditions. The performance tests were performed in Mode

1 (POWER OPERATION) with Unit 1 at approximately 38 percent and 78

percent power. Calibration and testing of instrumentation affected by

SG replacement was performed prior to testing.

i The performance testing was necessary to ensure proper operation of

l these systems:

l * Reactor Rod Control

. Steam Generator Level Control

. Main Feedwater Pump Speed Control

'

• Pressurizer Level Control

• Pressurizer Pressure Control

. Load Rejection Control (Tavg-Tref mode)

!

'

Testing included introduction of false level signals to verify main

feedwater control system performance and a 10 percent load reject test

was initiated to verify proper control system overall response. A

dedicated R0 and SRO were assigned to monitor the transient testing.

Prior to commencement of the transient testina, the operators were

instructed to intervene and abort the testing, if necessary, to preclude

l a unit trip or equipment damage.

The load drop change rate was set at 2400 MWe/ min or 200 percent rated

output / min. The total load reduction was 10 percent of rated electric

power output. All equipment operated as expected. No manual actions

were necessary to stabilize the station during the load rejection

testing. Steam Generator levels stabilized at the lower power level.

'

No instability with automatic control systems was experienced nor were

l there sustained or diverging plant parameters identified. Neither

l primary or secondary relief or safety valves lifted. No reactor trip,

!

turbine trip or Safety Injection occurred as a result of the load

reject

l

C. ConClU5 Wn

! The inspectors concluded that restart testing following the Steam

Generator Replacement Outage was adequately planned and executed to

verify steam generator design and ensure reliable operation of the Unit

1 control systems.

Enclosure 2

l

l

l

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

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i

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21

M4 Maintenance Staff Knowledge and Performance

M4.1 Unit 2 Steam Generator Leakaae Inspections and Reoair

a. Insoection Scooe

The inspectors reviewed the licensee's actions regarding the forced

outage inspection of the 2A SG for primary to secondary leakage. Unit 2

was shutdown on June 13, 1997, with an indicated SG 1eakrate on the 2A

SG of approximately 60 to 70 GPD.

I

b. Observations and Findinas  !

On June 19. with the Unit in MODE 5 (Cold Shutdown), the licensee I

performed a secondary pressurization test on the 2A SG to approximately l

650 psig using a condensate booster pump. The test pressure was held '

approximately 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. Leakage results identified an approximate 10

drop per minute leak at the 7-60 tube location. No other indications

were identified. The licensee reviewed Unit 2 cycle 10 SG inspection

data and identified that initial bobbin coil inspections revealed a 2.68

volt non-quantifiable indication. This value did not meet repair

criteria: however, the indication received expanded inspection via

motorized rotating pancake coil (MRPC). The results were reviewed by

SG specialists and no defect was found. However, more in-depth review i

identified that the antici)ated tolerance range of the MPRC measurement

was not fully achieved. T11s problem may have resulted in the no defect

decision being based on incomplete data. Current testing confirmed the

100 percent throughwall leak just above the second support plate on the

cold leg side. All indications supported the conclusion that the crack

was axial . An in-situ pressure test was performed on the 7-60 tube

which concluded that the tube met structural acceptance criteria.

Specific repairs to the 7-60 tube included plugging and inspection of

six adjacent tubes with bobbin coil. No other problems were identified

in this area relating to the leaking tube.

On June 20. a conference call was held between NRC and the licensee to

discuss the details of the tube degradation and the proposed scope of

additional inspections. Based on the indicated root cause of the 7-60

leak, the licensee proposed additional inspections of all positive

bobbin indications which were considered to have no defect based on

additional MRPC inspections. This initial scope included 377 potential

tubes to be re-inspected which were distributed in all four SGs. This

total number was reduced to approximately 192 tubes based on review of

outage data. All of the subsequent MPRC inspections were performed over

the full free span to avoid any potential alignment concerns. These

inspections resulted in the additional plugging of 18 SG A tubes, 3 SG B

tubes. 3 SG C tubes and 0 SG D tubes. The additional tube plugging

could not be attributed to errors in the )revious outage SG inspections

j

.

due to the additional inservice time on t1e Unit 2 SGs. Licensee

,

Enclosure 2

l

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,

4

.

l

l

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22 1

reviews did not identify any tube degradation which exhibited abnormal

defect growth characteristics.

c. Conclusions

Based on the licensee's inspection 3rocess, scope, and completed

repairs, the inspectors concluded tlat the corrective maintenance was

adequately performed. However, the inspectors also concluded that

previous followup to a SG indication in the area of the identified leak

led to a missed opportunity to identify and prevent this event. At the

end of the inspection period, the licensee continued to review the root

cause of the SG inspection inconsistencies. Once identified, actions to

correct the problem and also ensure that other oversights did not occur i

were good. This problem will be identified as Unresolved Item (URI) 50-

370/97-09-02

Steam Generator Inspection Process, pending further review

of the root cause of the SG inspection process.

i M8 Miscellaneous Maintenance Issues (92902)

M8.1 (Closed) Violation 50-369. 370/96-06-03: Failure to promptly I

incorporate vender recommended torquing guidelines for the Reactor Trip

Breaker (RTB) secondary contact assembly block prior to performing j

maintenance in September 1994. A new Westinghouse Maintenance Program

! Manual (MPM) for Reactor Trip Circuit Breakers was received in the

'

General Office (GO) by the Operating Experience Assessment (CEA) group

on February 14. 1994. OEA issued a General Office (GO) Problem

Investigation Process (PIP) report to assign actions for processing the

updated manual into the McGuire Document Control Syrtem. Due to lack of

accountability, assignment of low priority, and inadequate tracking the

Manual was not finally processed into the McGuire Document Control

Program until January 23. 1995. The new reactor trip breaker (RTB) .

Manual contained torquing values for the secondary contact block

'

assembly which were not included in the previous manual. In September

1994. a broken secondary contact block assembly was found on 1RTB DS-416

Reactor Trip Breaker during a routine outage PM and was replaced using

the then current procedure IP/0/A/2001/006. This procedure was based on

the older MPM and did not contain torquing values for the contact block

mounting bolts. Subsequently, on July 1.1996 during an inspection of

1RTB DS-416 Reactor Trip Breaker, the secondary contact block assembly

that had been re) laced two years earlier was found broken. Overtorquing

of the mounting Solts was a probable contributor to the failure.

In response to the violation dated Seatember 20, 1996, the licensee had

implemented a new MPM for RTBs into t1e Document Control System on

January 23, 1995. New procedure SI/0/A/2410/001." Westinghouse DS-416

Air Circuit Breakers Inspection and Maintenance." replaced the old

procedure on October 12. 1995. Additionally, training was provided to

site engineers and a Champion Tracking Report initiated to aide OEA in

tracking site assigned tasks.

Enclosure 2

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23

J The insp, ' tor reviewed the new 3rocedure and verified torque values for

mounting t.he secondary contact ] lock were included. Also, the training

lesson for engineering was reviewed and found to be acceptable and the

development of tne Champion Tracking Rep;rt was verified.

i

M8.2 (Closed) Violation 50-369. 370/96-04-01: Failure to perform performance

-

test PT/2/A/4350/03A." Electrical Power Source Alignment Verification."

prior to entering Mode 6. In the response to the violation dated July

. 31, 1996, the licensee indicated that other procedures had performed the

necessary alignments. The licensee committed to perform a procedure ,

review to determine if procedural changes were necessary. The I

i inspectors reviewed the documentation of these reviews. The licensee i

determined that no changes to the scheduling process or start up

checklists were necessary. However. Operations Management Procedure OMP

5-10." Routine Task List." was revised to require that any PT item on the

list not completed on schedule must be reported to the Operations

Support Manager and entered into the Technical Specification Action Item

Log for tracking and close out. Licensee actions were considered 4

acceptable.

i M8.3 (Closed) Violation 50-369. 370/96-07-01: Failure to demonstrate the

4 operability of the 1A emergency diesel generator (EDG) after EDG 1B was

declared inoperable. In response to the violation dated October 24,

'

1996, the licensee identified the cause as the operator's dependence on

memory rather than to adequately research the Technical Specification

requirement. Additionally, the procedure PT/1/A/4350/25." Essential

Auxiliary Power System Power Source Verification." did not clearly

s)ecify that th redundant train must be run. The inspectors verified

tlat PT/1/A/4360/25. Revision 10. clearly stated that if a EDG is

inoperable for reasons other than planned maintenance or testing the

other EDG will be run. The inspectors also determined that Management

Expectations that the Technical Specification be physically reviewed

versus relying on memory was promulgated in a letter to % 1or Reactor

Operators dated October 21. 1996.

III. Enoineerina

El Conduct of Engineering

El.1 Non-conservative TS for Inocerable Main Steam Safety Valves (MSSVs)

a. Insoection Scooe (37551)

The inspector reviewed the identification process of non-conservative TS

ACTION statements associated with the MSSVs.

Enclosure 2

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.

24

b. Observations and Findings

On March 20 and May 20. 1997, the licensee identified through 10 CFR

50.72 re) orts that TS Table 3.7-1. Maximum Allowable Power Range Neutron

Flux Hig1 Setpoint With Inoperable Steam Line Safety Valves During Four

Loop Operation specified non-conservative values. Specifically, when

one or more MSSVs may be inoperable, the TS identified Jower range

neutron flux high setpoints may be non-conservative. T1e purpose of the

setpoints are to assure that secondary system pressure will be limited

to within 110 percent of its design pressure during the most severe

anticipated system operational transient.

The inspector discussed with the licensee their historical response to

the issue. On January 20. 1994 Westinghouse issued a Nuclear Advisory

Letter informing utilities that the algorithm used to initially

calculate the power range neutron flux high setpoint for the MSSVs was

not correct. The basis for the advisory letter conclusions were modeled

from uniformly sized MSSVs. McGuire's MSSVs were not uniform, therefore

a plant specific study was necessary to determine if McGuire's TS was

also non-conservative. In early 1994, the licensee initiated a study

and issued a TS interpretation regarding the potential problem, which

provided further guidance to operators for operation with one or more

inoperable MSSV. In December 1995, the plant specific analysis was

completed, and concluded that the TS values for the inoperability of one

and two MSSVs allowed for reactor o)eration at non-conservative power

levels. During this time. McGuire las never operated in a condition

requiring plant operation to be restricted due to inoperable MSSVs.

The licensee chose to pursue a TS change via their improved TS project

plan to reflect the higher reactor power limits: however, during final

review for the submittal in early 1997, engineering questioned the bases

for the existing )ower level restrictions. It was subsequently

determined that t1e restrictions for operation with one or more

inoperable MSSVs was non-conservative. Once identified, the licensee

made the appropriate 10 CFR 50.72 reports, gave additional guidance to

operations, and submitted an LER on the subject. In addition, the

licensee initiated the TS revision process to revise TS 3.7.1. The

licensee stated that the change would be conducted outside of their TS

upgrade project,

c. Conclusions

The inspectors concluded that once the entire scope of the problem was

identified the licensee initiated appropriate actions to address the

issue. However, the overall resolution of the potential for non-

conservative TS ACTION requirements was not completed in a timely

manner. Although adequate administrative controls were in place and no

actual MSSV inoperability occurred during the issue resolution period,

the chosen TS Amendment process led to delays in final resolution and

identification of all pertinent issues. The inspectors will review

Enclosure 2 I

4

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.

i

l 25

other technical adequacies of the licensee's corrective actions during

close-out of associated LER 369/97-04.

E2 Engineering Support of Facilities and Equipment

E2.1 Desian Modification of Auxiliary Feedwater (AFW) System Suction Suoolv

j a. Insoection Scooe (37551.40500)

1

The inspector reviewed the implementation of minor modifications to the

nonsafety-related suction supply of the AFW system. The inspector

reviewed the 10 CFR 50.59 evaluation, related FSAR and Design Bases

Document (DBD) sections, and witnessed portions of the field work to

4

modify the system. This is an update of IFI 50-369.370/97-08-04,

4

Potential Airbinding of AFW Pumps.

The AFW air entrainment mechanisms include, but are not limited to.

j vortexing in the AFW condensate storage tank (AFWCST) and emptying of

the upper surge tanks (UST) with the AFW system in a recirculation mode.

In 1996, operators identified the AFW pump air binding issues as an

operator work around and the licensee initiated engineering analysis to

investigate the issue. NRC Inspection Report 97-08 documents the

>

'

issues, status of the hydraulic studies, and the licensee's compensatory

measures.

b. Dbservations and Findinas

During the inspection period, the licensee implemented two design

modifications to the AFW suction sup)1y in order to reduce the

likelihood of air entrainment into t1e AFW suction piping. The first

modification involved the conversion of an existing filtered water tank

(42.500 gallon capacity) into an additional AFWCST. This tank, AFWCST

'B', is located next to the AFWCST 'A' on the service building roof. 1

Combined, the two tanks have a capacity of 85,000 gallons of condensate

quality water and doubles the original AFWCST capacity available to

either Unit 1 or Unit 2. The second modification involved vortex

suppressors that were installed in the suction nozzles of each AFWCST.

These modifications were completed on June 12. 1997.

Before completion of the modification. the licensee determined by

engineering analysis that a vortex in AFWCST 'A' did not affect past

operability of the AFW pumps. The issue involving the air slug from UST

interaction with nuclear service water and AFW pump recirculation

continued to be indeterminate, pending conclusion of other engineering

analysis. Compensatory measures remained in effect until plant  !

orocedures affected by the design modifications could be updated and the

UST air slug issue dispositioned.

The inspector confirmed through daily control room visits that the

compensatory measures remained in-effect before. during, and after the

Enclosure 2

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! 26

modi fications. During implementation of the modifications. Unit 1 AFW

pumps were aligned to take suction from the Unit 1 UST. Unit 2

continued to be aligned to the Unit 2 UST.

c. Conclusion

The inspector concluded that the addition of another AFWCST was a timely

and positive action to extend AFW inventory and improve pump suction ,

reliability. Installation of vortex suppressors was a conservative  ;

management decision, given the licensee's conclusions of their

engineering analysis. The associated field work was considered

adequate. However. IFI 369.370/97-08-04 remains open pending the

licensee's completion of engineering analysis and subsequent NRC review.

I

E2.2 Outaae Modifications (37550) j

a. Insoection Scooe

The inspector reviewed Nuclear Station Modifications (NSMs) implemented

during the current Unit 1 outage. The modification review included l

verification that design control requirements of Regulatory Guide 1.64 l

and ANSI N45.2.11-1974 Quality Assurance Requirements for the Design of '

Nuclear Power Plants, and licensee procedures were implemented. 1

Elements of the design process reviewed included post modification i

testing, procurement. procedure revision. 50.59 safety evaluation and  !

screening, and field verification of plant hardware changes, as  !

applicable. The following NSMs and minor modifications were reviewed:

)

. MG 12220/P2 Reroute Instrumentation and Control (I&C) Tubing

for AFW. Main Steam (MS), and MFW Systems j

. MG 12419 Replace Diesel Generator (DG) Train A Cooling I

(KD) Pumps

. MG 12467/P1 Replace Bussman FN0 Fuses

. MG 12473 Relocate DG Lube Oil (LO) Pressure Switches

. MGMM 8289 Replace Valves 1 NV-457 and 458 with Gate Valves

. MGMM 8676 Replace Valve INC-45

. MGMM 9101 Qualify Over-thrust of 1NI-147 l

. MGMM 9114 DG Engine Drive L0 pump Dowel Rcplacement

. MGMM 9255 Actuator Replacement on 1ND-19

l

l . MGMM 9269 Qualify As-left Thrust for 1NM-06 l

l

l Enclosure 2

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27

b. Observations and Findinas

,

Post modification testing performed was adequate to verify equipment and

I

system function folloving the modification. In general. 50.59 safety

evaluations were good, in that, responses to screening or evaluation

questions were detailed and adequately justified the conclusions.

t Procurement documentation demonstrated that the appropriate quality

l level material was used for installed equipment and materials.

c. Conclusion

The modifications completed during the Unit 1 outage demonstrated '

appropriate control of the design control process at McGuire.

, Performance was good for modifications, procedures. 50.59 evaluations

i

and screening.

E2.3 Enaineerina Sucoort to Doerations (37550)

'

a. Insoection Scone

'

The inspector reviewed the use and validation of Test Acceptance l

Criteria (TAC) which were developed in conjunction with the design base '

documents. Applicable regulatory requirements included 10 CFR 50

Appendix B.

l

l b. Observations and Findinas

l The TAC sheets were developed in conjunction with the Station Design

Base Documents and described the design function, operability

requirements and verification test criteria for safety-related

equipment. The TACs included compensatory actions to maintain system I

operability if a component was out of service. The station Modification  !

Manual indicated that the TACs were to be used to document test

acceptance criteria for station modifications (NSMs) and equipment

performance tests. In practice. Operations used the TACs for verifying

, operability and establishing compensatory measures for systems during

on-line GL 89-10 testing of safety-related valves.

In 1996, the Operations and Engineering staffs noted that the TAC

compensatory measures had not been validated with 10 CFR 50.59 safety

evaluations to assure the alternate system configurations did not

introduce an unreviewed safety question. A February 5, 1997, memorandum

from the Station Vice President to the Station established parameters

for use of the TAC compensatory measures. The licensee recently 1

completed an upgrade of the TACs for Inservice Test Program (IST) valves  !

l which standardized the format and validated compensatory measures with i

10 CFR 50.59 evaluations. Nuclear Station Directive NSD-203.

Operability Policy, was revised on March 26, 1997, to provide guidance

on the use of TAC sheets for IST valves.

+

'

Enclosure 2

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c. Conclusion

Engineering's upgrade and validation of DBD TAC sheets for IST valves

was an example of good engineering support to operations. The TACs

provide a good design reference for Operations to maintain system

operability when safety-related valves are out of service for testing.

E3 Engineering Procedures and Documentation

E3.1 Unit 1 K-45 Fuel Assembly Reconstitution

a. Insoection Scope (71707)

During the inspection period, reactor engineering personnel performed

fuel reconstitution of the K-45 assembly in the Unit 1 spent fuel pool.

The inspector performed field observations of the reconstitution and

discussed the activities with the cognizant engineer. The inspector

also reviewed the 10 CFR 50.59 safety evaluation for use of a crud

scrubbing device to remove crud from fuel rods and the use of single rod

diameter / oxide measurement equipment. Specifically, the inspector

reviewed calculation MCC 1553.26-00-211 which was the safety analysis

for mechanical, criticality, shielding, and thermal concerns associated

with use of the equipment.

b. Observations

Between June 5 - 9. eight experimental fuel rods were removed from the

K-45 lead test assembly for Post Irradiation Examination (PIE). The

eight rods are part of an advanced zircaloy cladding program. These

rods contained three different types of cladding materials, and the

assembly had a high burnup (i.e., over 40 GWd/mtu) with a cooling time

of approximately 18 months.

The inspector observed fuel rod removal and reconstitution of the

assembly. Stainless steel rods were used as substitutes in the assembly

for the removed rods. The fuel rods were loaded into a specially

designed basket and will be inserted in the R52 cask canister for

shipment. All eight rods will be shipped offsite for hot-cell testing

and destructive examination.

The licensee, with support from Framatome, used underwater surveillance

cameras to read rod serial numbers and accomplish the reconstitution.

Pool water clarity was good and serial numbers were clear and readable

on video monitors.

PIE work was also performed in the Unit 1 spent fuel 2001 to provide

baseline data prior to offsite testing. Using a scru)bing device. crud

was removed from the cladding of each of the eight rods. This was done

to improve eddy current testing to gauge oxidation layer thickness and

Enclosure 2

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29

clad wall thinning. The inspector determined that the licensee's safety  !

analysis for use of the equipment was adequate.

c. Conclusion ,

I

The inspector concluded that the K-45 fuel reconstitution work

activities were well controlled and that good communication existed i

among the crew members. Reactor engineering personnel were l

knowledgeable and the 10 CFR 50.59 evaluation was adequate. Appropriate l

reactor engineering oversight was l

protection coverage was provided. present and adequate radiation l

E4 Engineering Staff Knowledge and Performance

E4.1 Vital Battery and Charoer Reolacement Modification

a. Insoection Scooe

The inspectors reviewed minor modification packages developed and

implemented for the replacement of the Bus A EVCA battery and associated

charger. The replacement was necessary to improve reliability of the

125VDC Vital Power System. The currently installed AT&T lineage 2000

series round cell batteries at McGuire have been degrading at a faster

rate than was initially antici]ated. Due to this unanticipated battery

degradation the licensee esta)lished prudent replacement schedules for

each of the four batteries and their associated chargers. The round

cell batteries from EVCA were replaced with conventional rectangular

cell GNB Type NCN stationary batteries. Prior to implementation of the

battery replacement modification, an increase in TS allowed battery

outage time to 30 days was approved by the NRC.

b. Observations and Findinos

The licensee completed replacement of vital battery EVCA and its

associated charger during this period. Completion of the remaining

three battery / charger reolacements was scheduled prior to December 1997.

The EVCA battery / charger replacement was conducted under Nuclear Station

Modification NSM-52483. Vital Battery EVCA Replacement and NSM-52488.

Vital Charger EVCA Replacement. The associated connectors and cabling

was replaced under separate modification packages.

Prior to the commencement of the maintenance activities, the inspectors

reviewed the modification packages to verify that the licensee's )lans

were in accordance with TS requirements and the McGuire UFSAR. T1e

inspectors confirmed that e temporary battery was installed under Minor

Modification MGMM-8847 and Work Order No. 96089566 on the affected bus

during the replacement. The temporary battery bank was composed of low

specific gravity AT&T round cells. The affected bus remained energized

by spare charger EVCS. backed by the temporary battery. Although the

temporary battery was sized to supply the same duty cycle as the normal

Enclosure 2

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30

batteries and configured to the full capacity spare charger, the

licensee did not consider the bus fully operable since the temporary

battery storage racks were not positioned in a seismically qualified

location.

-

Prior to being connected to the bus. the temporary batte y received a

full complement of surveillance measurements, including a service test.

Tem)orary ventilation equipment was necessary to prevent unacceptable  ;

comaustible gas accumulation during temporary battery operation. The i

replacement EVCA battery was service tested. The factory acceptance I

test was used to satisfy TS 4.8.2.1.2e rather than performing an onsite

performance discharge test. Breaker and fuse upgrades were also i

conducted to ensure proper breaker coordination.  ;

Contingency plans were also developed and implemented to provide

adequate fire, security, and radiological protection during breach of

the vital security battery room and RCA. Radiological surveys were

performed to ensure that the area could be re-classified as a non-

radiologically controlled area. Continuous security coverage was

established while vital area doors and fire barriers were disabled to  !

allow equipment removal and replacement.

c. Conclusion

The inspectors concluded that the licensee developed adequate procedures l

and controls for replacement of the EVCA battery / charger. Modification

packages for installation of the temporary battery were adequate.

Contingencies were established in the event of a loss of the temporary

battery or the spare charger while in the degraded condition. Although

the licensee delayed return of the battery to service to minimize

potential plant impact during Unit 2 draindown and midloop operations.

the replacement activities were completed within the authorized TS

allowed outage times.

IV. Plant Support

R1 F.adiological Protection and Chemistry Controis

R1.1 Tour of Radioloaical Areas

a. Insoection Scooe (83750)

The inspectors discussed with licensee representatives the planning and

preparations underway for a site project to remove selected pieces of

steam generator tubes and tube sheet components from two removed steam

generators (SGs) B and D. This project was contracted through Duke

Engineering Services (DES) and Argonne National Laboratory in su) port of

a contract between the Nuclear Regulatory Commission (NRC) and t1e

Department of Energy. Licensee preplanning activities for the evolution

Enclosure 2 ,

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31

was reviewed to determine the adequacy of licensee planning efforts in

the area of radiation protection. including: dose estimates, as low as

reasonably achievable (ALARA) planning and implementation, and

contamination control practices.

l b. Observations and Findinas

The inspectors discussed specific work preparations to assist qualified

radiation protection technicians in planning for survey coverage.

l radioactive material control and storage, contamination controls, and

< exposure controls for SG tube and tube sheet removal. The inspectors

'

determined the licensee's plans were to sequence work activities in

order to maximize the use of shielding while maintaining exposures

ALARA. At the time of the inspection, the inspectors observed

i preparations being made to construct tent containments with High

Efficiency Particulate Air (HEPA) filters around the SGs to be worked.

The use of wireless communications, teledosimetry, cameras and other

work practices being developed were also discussed as methods the

licensee was planning to use to maintain exposures ALARA. Specific work

procedures and radiation work permits (RWPs) to support the work

evolution had not been finalized at the time of the inspection.

c. Conclusion

.

At the time of the inspection, the inspectors determined that the

! licensee was in the process of developing procedures and work practices

( to maintain effective contamination controls and to maintain exposures

l ALARA during work evolutions on two removed SGs.

P1 Conduct of EP Activities

Pl.1 Emeraency Preoaredness Drill

a. Insoection Scooe

On April 16 the licensee conducted a station emergency preparedness

practice exercise. The practice exercise scenario involved a dropped ,

fuel assembly in the spent fuel transfer canal area during refueling i

followed by a 30 gpm reactor coolant leak from the available train of

'

residual heat removal. The scenario progressed to a General Area

Emergency, exercising major components of the McGuire Emergency Plan.

l b. Observation and Findinas

The inspectors evaluated the practice drill critique. The inspectors

noted a number of deficiencies identified concerning Emergency Response

'

Organization (ERO) performance throughout the drill. Concerns were also

identified with station security processes and equipment during the Site

! Assembly portion of the drill. Based on the findings identified in the

t

critique on procedural use and adherence. the inspectors determined that

'

Enclosure 2

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additional emphasis on management expectations was necessary to improve 1

, ERO performance. The inspectors also noted that increased management '

involvement in the critique process was necessary to ensure that

, corrective measures identified during the critique were appropriately )

e'aluated and resolved. The licensee recognized that adjustments were

necessary and have formulated working groups to correct the licensee-

, identified concerns.

.

Conclusion

The inspectors concluded that the practice drill scenario was adequate

, to effectively test the Emergency Response Organization (ERO)

i participants. The ERO performance was adequate: however, additional

i

management emphasis on ERO expectations was necessary.

-

i

'

F3 Fire Protection Procedures and Documentation  !

l

F3.1 Adeauacy of 3 Year Fire Protection System Flow and Pressure Test (71750) I

1

a. Insoection Scooe

The inspector reviewed the licensee's implementation of commitments to l

,

perform 3 year fire protection system flow testing. I

i b. Observations and Findinas

The Selected Licensee Commitments (SLC) Manual. Section 16.9. requires

.

that the fire suppression water system be operable at all times. The i

system is demonstrated to be operable through a series of tests listed  !

4

in the SLC Manual. Section 16.9-1. The subject test is a system flow

test which was last performed in July 1995. The inspectors discussed

with licensee fire protection personnel their performance of the 3 year i

fire protection system flow and pressure test, and whether any

performance degradation had occurred from previous tests. No '

significant degradation was noted: however, trending of the data was

minimal. In addition, the acceptance criteria for the test data was not

well established. The inspector raised an additional concern regarding

the scope of fire protection piping actually tested. Specifically, the

McGuire station was not performing this type of testing on the interior

loop piping within, for example, the auxiliary building. The licensee

was performing this type of testing on overall yard loop piping:

however, with this ap3 roach, interior loop piping degradation may not be

apparent. In 1995. tie licensee's Catawba facility identified problems

in this area (see PIP 0-C95-1908) via the performance of more specific

flow testing: however. the McGuire facility testing had not incorporated

similar testing.

Based on the inspectors concerns, the licensee initiated PIP 0-M97-1849

to evaluate what corrective action may be required. By the end of the

inspection period the licensee was preparing a special test which would

Enclosure 2

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.

.

33

incorporate additional key sections of the interior loop aiping to

provide baseline information of system degradation. It s1ould be noted l

that the McGuire fire protection system, historically, has not exhibited i

evidence of significant corrosion in the auxiliary or reactor buildings. l

Based on the reviews, this issue will be identified as an Inspector  ;

Followup Item (IFI) 50-369.370/97-09-03: 3-year Fire System Testing. 1

pending completion of the additional testing being developed by the  ;

licensee. '

c. Conclusions

1

The inspectors concluded that the development of additional testing for

the interior loop piping was prudent and could provide additional

indications of system degradation. The inspectors also concluded that i

the administrative processes for long-term monitoring of the fire I

protection system for degradation could be improved.

V. Management Meetinas .

l

X1 Exit Meeting Summary

The inspectors ] resented the inspection results to members of licensee ,

management at t1e conclusion of the inspection on June 26, 1997. The licensee l

acknowledged the findings presented. No proprietary information was

identi fied. j

l

X2 Management / Organizational Changes l

On June 18, 1997, the proposed Duke Power and PanEnergy merger became

official . Additionally, the following McGuire management changes were

announced:

• A. Bhatnagar to become Operations Superintendent at McGuire, effective

July 1. 1997

• L. Loucks to assume the position of McGuire Chemistry Manager, effective

in November 1997.

Enclosure 2

.

l

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34

i

PARTIAL LIST OF PERSONS CONTACTED

Licensee

Barron B., Vice President. McGuire Nuclear Station

Boyle J., Civil / Electrical Systems Engineering

Byrum. W. Manager. Radiation Protection

Cline. T., Senior Technical Specialist. General Office Support

Cross. R. Regulatory Compliance

Davison. Valve Supervisor

Dolan. B., Manager. Safety Assurance

Geddie. E., Manager. McGuire Nuclear Station

Harley, M. , Engineering Supervisor

Herran, P. , Manager. Engineering

Jones. R., Superintendent. Operations

Michael. R., Chemistry Manager

Jamil. D., Superintendent. Maintenance

Cash. M.. Manager Regulatory Compliance

Thomas. K. , Superintendent. Work Control

Travis. B. , Manager. Mechanical / Nuclear Systems Engineering

Tuckman. M., Senior Vice President. Nuclear Duke Power Company

NRC

S. Shaeffer. Senior Resident Inspector. McGuire '

M. Franovich. Resident Inspector. McGuire {

M Sykes Resident Inspector. McGuire

R. Moore. Regional Inspector

H. Whitener. Regional Inspector

D. Forbes. Regional Inspector

4

i

"

Enclosure 2

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

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35

INSPECTION PROCEDURES USED

IP 71707: Conduct of Operations

IP 71750: Plant Support

IP 62700: Maintenance Program Implementation  !

IP 62707: Maintenance Observations

IP 61726: Surveillance Observations i

IP 37551: Onsite Engineering '

IP 92902: Followup - Maintenance

IP 92903: Followup - Engineering

IF 40500: Self-Assessment

IP 37550: Engineering

l

ITEMS OPENED. CLOSED, AND DISCUSSED

OPENED

VIO 50-370/97-09-01 Inadequate Test Procedure (Section M2.1)

i

URI 50-370/97-09-02 SG Inspection Process (Section M4.1)

IFI 50-369.370/97-09-03 3-year Fire System Testing (Section F3.1)

CLOSED

VIO 50-369.370/96-06-03 Failure to Incorporate Vendor RTB Information

Into Plant Procedures (Section M8.1)

VIO 50-369.370/96-04-01 Surveillance Not Performed Due to Inadequate

Procedure Guidance (Section M8.2)

VIO 50-369.370/96-07-01 Failure to Perform Surveillance on Emergency

Diesel Generator (Section M8.3)

DISCUSSED

IFI 50-369.370/97-08-04 Potential Airbinding of AFW Pumps (Section E2.1)

LIST OF ACRONYMS USED

AFW -

Auxiliary Feedwater

AFWCST - Auxiliary Feedwater Condensate Storage Tanks

ECCS - Emergency Core Cooling System

EDG -

Emergency Diesel Generator

GL -

Generic Letter

HP -

High Pressure

IFI -

Inspector Followup Item

IRT -

Independent Review Team

Enclosure 2

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1

.

l

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36

LER -

Licensee Event Report

MOV -

Motor-Operated Valve

MPM -

Motor Power Monitor  ;

MRPC - Motorized Rotating Pancake Coil J

MSR -

Moisture Separator Reheater

MSSV - Main Steam Safety Valve

NCV -

Non-Cited Violation

NLO -

Non-Licensed Operator

NRC -

Nuclear Regulatory Commission

NRR -

NRC Office of Nuclear Reactor Regulation

PIP -

Problem Investigation Process

PMT -

Post Maintenance Test (Retest)

PORV - Power Operated Relief Valve

PRA -

Probabilistic Risk Assessment

PT -

Performance Test  !

RCS -

Reactor Coolant System  !

RHR -

Residual Heat Removal  ;

R0 -

Reactor Operator  !

RV -

Reactor Vessel  !

RWST - Refueling Water Storage Tank

SG -

Steam Generator

SGRP - Steam Generator Replacement Project

SI -

Safety Injection

SRO -

Senior Reactor Operator

TI -

Tem)orary Instruction

TS -

Tec1nical Specifications

TSAIL - Technical Specification Action Item List

UFSAR - Updated Final Safety Analysis Report

URI -

Unresolved Item

UST -

Upper Surge Tanks I

VIO -

Violation

WO -

Work Order

i

I

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Enclosure 2

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