ML20133J199

Insp Repts 50-338/96-12 & 50-339/96-12 on 961102-1207. Violations Noted.Major Areas Inspected:Operations,Maint & Engineering

ML20133J199
Person / Time
Site:	North Anna
Issue date:	01/06/1997
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20133G865	List: ML20133G861 ML20133G888 ML20133J199
References
50-338-96-12, 50-339-96-12, NUDOCS 9701170433
Download: ML20133J199 (40)

See also: IR 05000338/1996012

Text

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i U.S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos: 50 338, 50 339

i License Nos: NPF 4, NPF-7

Report Nos: 50 338/96 12, 50 339/96 12

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Licensee: Virginia Electric and Power Company (VEPC0)

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Facility: North Anna Power Station, Units 1 & 2

Location: 1022 Haley Drive

Mineral Virginia 23117

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Dates: November 3 through December 7, 1996

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Inspectors

R. McWhorter, Senior Resident Inspector

R. Gibbs, Resident Inspector

R. Chou, Reactor Inspector (Sections E1.1 and E2.1 through

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. E7.2)

P. Fillion. Reactor Inspector (Sections El.1 and E2.1

through E7.2)

L. Garner, Project Engineer (Sections 06.1, M2.1. E1.4 and

E8.1)

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P. Hopkins, Project Engineer (Sections M8.1 and M8.2)

D. Jones, Senior Radiation Specialist (Sections R1 and R8)

J. York, Reactor Inspector (Sections E1.1 and E2.1 through

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E7.2)

Approved by: G. Belisle, Chief, Reactor Projects Branch 5

Division of Reactor Projects

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ENCLOSURE 2

9701170433 970106

PDR ADOCK 05000338

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EXECUTIVE SUMMARY i

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North Anna Power Station. Units 1 & 2

NRC Inspection Report Nos. 50 338/96 12, 50 339/96 12

This integrated inspection included aspects of licensee operations,

engineering, maintenance, and plant support. The report covers a five week

period of resident insaection. In addition, it includes the results of

announced inspections ay regional specialists and regional projects

inspectors. I

Operations

. Daily operations were generally conducted in accordance with regulatory

requirements and plant procedures (Section 01.1). l

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. Safety system and oaerator response to a Unit 2 reactor trip was good.

Minor equipment pro)1 ems were promptly corrected. The trip's cause, a

main generator failure due to damage caused by foreign material,

required an extended unit shutdown for repairs (Section 01.2).

. Initial reviews of cold weather protection procedures found that

activities were properly completed (Section 02.1). l

. One NRC notification required by 10 CFR 50.72 was properly made by the

licensee (Section 02.2).

An Operator Work Around (0WA) meeting was an effective mechanism for

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keeping plant management informed of the status of each open 0WA i

(Section 06.1). '

. The Oversight organization continued to assess station performance

effectively. A Hanagement Safety Review Committee meeting complied with

TS requirements, and substantive assessment issues were addressed in

committee discussions (Section 07).

Maintenance

. Service Water Restoration Project work activities were well controlled.

Supporting system manipulations were performed in accordance with

regulatory requirements and commitments (Section M1.1).

. Debris was observed on the ledges above the radiator fans for three of

the four emergency diesel generators (Section M2.1).

. A Non Cited Violation (NCV) was identified for a failure to meet TS

surveillance requirements for testing reactor trip bypass breakers. Two

previous violations and three Licensee Event Reports (LERs) were closed

(Section M8).

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Enaineerino

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A violation was identified for a failure to ensure proper facility

design control. Unit 2 safeguards area walls were found to not meet

their design basis for controlling safeguards pump leakage since early <

in plant life. One Unresolved Item was closed (Section 08.1).

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The licensee's operability evaluation for non conforming bolts in a

recently installed pump was reasonable, and completed in a timely

manner. The scheduled date for correcting the non conformance was

acceptable. Even though the problem was primarily caused by the

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manufacturer, problems in the licensee's design control program

contributed to the wrong bolts being installed. For this reason a

Notice of Violation was issued (Section E1.1). -

The licensee appropriately analyzed the impact of service water system

restoration activities on a shutdown unit and made conservative

decisions concerning shutdown unit status (Section E1.2).

An NCV was identified for a failure to meet American Society of

Mechanical Engineers Code Section XI recuirements for testing the check

valve functions of six steam generator cecay heat removal isolation

valves (Section E1.3).  ;

• The Minor Modification Review Team meeting was professionally conducted.

The inspectors had no concerns involving the disposition of the items i

(Section E1.4).  ;

• The licensee's approach to resolving a potential problem with

microbiological influenced corrosion in stainless steel service water

piaing was reviewed. One section of four inch diameter pipe was

scleduled for replacement based on findings to date. The licensee was

at the investigation stage, and the total corrective action plan was l

under development. No concerns were identified by the inspectors

(Section E2.1).

. The engineering design change package was well prepared for implementing '

a carbon steel piping replacement in the service water system and the

quality of work being performed by the craftsmen was good

(Section E2.2).

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. A detailed cell inspection was performed on each cell of all the

safety related batteries. The inspectors concluded that battery

maintenance was good. However, the inspectors observed significant

sedimentation in two cells. The inspectors concluded that the

sedimentation had been present on June 4, the time of the last

surveillance inspection. Therefore, the fact that the surveillance did

not record any problems with sedimentation was considered a weakness in

the implementation of the inspection procedure (Section E2.3).

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. A review of six Deviation Reports and one Potential Problem Report

related to mechanical and structural engineering indicated good support

for facilities and equipment by engineers (Section E2.4).

. The alarm response procedure for bus overvoltage was a workable

procedure, and was consistent with statements made in letters to the NRC

on the subject of overvoltages. The safety evaluation supporting the

change in maximum allowable response time for performing tap changer

manipulations was accurate and complete.

Some corrective actions were proposed by the licensee to address NRC l

comments with regard to reading voltage at the 480 volt bus, but this

did not represent any programmatic weakness. The overvoltage relays

with alarms were a conservative design in relation to standard industry

practice (Section E2.5).

. The inspectors reviewed a Deviation Report involving the failure of

safety related vital battery 1 I to meet one acceptance criterion during

performance of the last service test. The inspectors agreed that the

subsequent Operability Evaluation was reasonable, and that the

requirement of the Technical Specification was met. An Inspection

Follow up Item was established to ensure review of certain procedure

enhancements and future test results (Section E2.6). l

. Review of a 1996 modification package to reinforce the supports for the

component cooling water surge tank to resolve concerns about the seismic

integrity of the tank indicated that the design was correctly

accomplished, but that the actual installation did not meet specified

dimensional tolerances. Also, a pipe support was installed at a point

where no support was shown on the drawings. A Notice of Violation was

issued (Section E3.1).

. The licensee's test procedure for the molded case circuit breakers was

good, in that, it checked that the magnetic element tripped within a

specified band around the set )oint. The controls for establishing and

verifying the set points for t1e magnetic elements were minimal. There

was no set point document, drawing, or specific instructions to help

ensure proper set >oints were maintained. Based on a sample of two

newer circuit brea(ers, the licensee's informal method resulted in

correct settings. Nevertheless, the lack of formal controls on the set

point for the magnetic element of molded case circuit breakers was a

weakness in the licensee's design control 3rogram in that continued use

of the informal method has increased proba)ility to result in incorrect

set points. Whether the lack of formal controls represents a violation

of NRC requirements in the area of design control or procedures is under i

further review by the NRC. The issue is identified as an Unresolved i

Item concerning the control of set points for molded case circuit  !

breakers (Section E3.2).

. The safety and oversight committees were conducting their duties in an i

efficient and productive manner (Section E7.1).

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. The engineering self assessment program was only recently defined, and

very few self assessments were completed (Section E7.2).

. An Inspection Followup Item was opened to review functional tests that

will be conducted on either new or old snubbers in the upcoming Unit 1

refueling outage. One Unresolved Item was closed (Section E8.1).

Plant Support

. The licensee was closely monitoring collective and individual radiation

dose exposure and meeting established As Low As Reasonably Achievable

goals and occupational dose limits (Section R1.1).

The licensee's water chemistry control program for monitoring primary

and secondary water quality had been implemented in accordance with the ,

TS requirements and the Electric Power Research Institute guidelines for i

pressurized water reactor water chemistry (Section R1.2).

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. One non cited violation was identified by the licensee for failure to

comply with the conditions of the Certificate of Compliance for an

NRC approved shipping package (Section R1.3).

• Two previous violations were closed (Section R8).

. Security systems were in good working order and security manning was

appropriate (Section S1).

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Report Details

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Summary of Plant Status

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Unit 1 began the inspection period at full power and operated the entire

inspection period at or near full power.

i Unit 2 began the inspection period at full power and operated at or near full

i power until November 12. On that date, the unit tripped from full power due

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to a main generator fault. The unit was cooled down and entered hot shutdown  !

on November 13, and cold shutdown on November 29. At the inspection period's l

end, the unit remained shutdown for main generator repairs.

I. Operations l

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01 Conduct of Operations

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01.1 Daily Plant Status Reviews (71707)

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The inspectors conducted frequent control room tours to verify proper ,

staffing, operator attentiveness, and adherence to approved procedures. l

The inspectors attended daily plant status meetings to maintain

i awareness of overall facility operations and reviewed operator logs to

i verify operational safety and compliance with Technical Specifications

(TSs). Instrumentation and safety system lineups were periodically

reviewed from control room indications to assess operability. Frequent

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)lant tours were conducted to observe equipment status and housekeeping. i

)eviations Reports (DRs) were reviewed to ensure that potential safety

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concerns were properly reported and resolved. The inspectors found that

daily operations were generally conducted in accordance dth regulatory

requirements and plant procedures.

01.2 Unit 2 Reactor Trio

a. Insoection Scope (71707. 93702)

On November 12, the inspectors in the field observed plant equipment

. responding to a Unit 2 reactor trip from full power. The inspectors

4 proceeded to the control room and observed operations immediately

following the trip. Additionally, the inspectors observed immediate

post trip equipment conditions in the turbine building, switchgear

rooms Auxiliary Feedwater (AFW) pump house, and Main Steam Valve House

(MSVH). The inspectors attended the licensee's post-trip review and

reviewed trip data to independently verify that safety systems and

operator performance were as expected throughout the event.

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b. Observations and Findinas

The inspectors found that the reactor tripped from full power following

a main generator trip. The main generator trip was caused by an

actuation of the generator protective system. A review of trip data

found that the trip signal was valid, and the inspectors verified that

safety systems performed as designed for plant conditions during the

trip. Operator response to the trip was appropriate and emergency

procedures were properly followed. One intermediate range nuclear

instrument was observed to be overcompensated, and one individual rod

position instrument indicated slightly greater than 10 steps after the

tri ). Operators initiated emergency boration for the rod position

pro)1em in accordance with abnormal procedures. The rod position

indication problem was corrected, and rod drop time testing was later

aerformed as required by NRC Bulletin 96 01, Control Rod Insertion

)roblems.

Plant equipment conditions immediately following the trip were good

except for the turbine building where numerous secondary relief valves

lifted following the reactor trip. Most of the relief valves lifted due

to the sudden increase in feedwater pressure, and all exce)t one

reseated when pressure was reduced. The relief valve whic1 did not

reseat was manually gagged by maintenance personnel. Additionally, the

ins)ectors observed that a large amount of water was discharged from the

turaine-driven AFW pump exhaust line during pump startup. No adverse

effects upon pump response were observed.

The main generator trip was found to be initiated by actuation of the

neutral ground fault relay. Testing confirmed that an actual fault

condition occurred on the A phase of the generator. On November 14,

generator inspections found that foreign material, a section of clear

plastic, had lodged on the cooling tubes for several generator coils.

The alastic cut off hydrogen cooling flow and allowed the coils to

overleat and fail. The generator required major disassembly for coil

replacement, and an extended forced outage was in progress at the

inspection period's end.

On November 13, the unit was cooled to hot shutdown, and secondary

systems were secured. The unit remained in hot shutdown until

previously ongoing repair activities on the Service Water (SW) system

were completed (Section E1.2). On November 29, the unit was cooled to

cold shutdown.

c. Conclusions

The inspectors concluded that safety system and operator response to the

Unit 2 reactor trip was good. Minor equipment problems were promptly

corrected. The trip's cause, a main generator failure due to damage

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caused by foreign material, required an extended unit shutdown for

repairs.

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02 Operational Status of Facilities and Equipment

02.1 Cold Weather Preparations

a. Insoection Scope (71714)

On several occasions during the inspection period, the inspectors

reviewed the initial implementation of the licensee's cold weather

protection procedures.

b. Observations and Findinos

The inspectors performed initial reviews of the licensee's procedures

for cold weather protection and their implementation. Procedure

0 G0P 4, Cold Weather Operations, Revision 9, was performed monthly

during cold weather or as directed by shift supervision. The inspectors

reviewed the procedure completed on November 15 and found that operators

had documented completing the actions necessary to protect

safety-related systems from freezing. For components v,ivere operators

identified material discrepancies, the inspectors verified that

corrective actions were initiated.

The inspectors also walked down the status of freeze protection

equipment near the Refueling Water Storage Tanks (RWSTs) and in various

buildings containing safety-related equipment. On November 24, the

inspectors identified that an a) proximately three inch section of piaing

to RWST level transmitter 2 05 _T 200D was wrapped in heat tracing, )ut

was not fully insulated. The inspectors reported the discrepancy to

shift supervision, and verified on December 6 that the discrepancy had

been corrected. Additionally, the inspectors discussed with station

managers the fact that with Unit 2 shutdown for a forced outage, the

Unit 2 MSVH temperature was much lower than normal. The managers

informed the inspectors that the Unit 2 MSVH temperature was being

monitored and that action would be taken (e.g., installing temporary

heaters) if MSVH temperature approached freezing.

At the inspection period's end, the inspectors were continuing their

reviews of the licensee's cold weather protection activities.

c. Conclusions

Initial reviews of cold weather protection procedures found that

activities were properly completed.

02.2 NRC Notifications

a. Inspection Scope (71707)

The inspectors reviewed the following licensee notifications to the NRC

to ascertain if the required reports were adequate, timely and proper

for the events.

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. b. Observations and Findinas

On November 12, the NRC was notified as required by 10 CFR 50.72

concerning reactor protection system and engineered safety feature

actuations generated when Unit 2 tripped from full power. The

inspectors found that the licensee's reporting actions were appropriate.

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Additional inspection activities and findings are discussed in

Section 01.2.

j c. Conclusions

l One NRC notification required by 10 CFR 50.72 was properly made by the

licensee.

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06 Operations Organization and Administration

06.1 Operator Work Arounds (0WAs) (71707)

l On December 5, the ins actors attended an 0WA status meeting conducted

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at the conclusion of t1e morning management meeting. There were 18

active 0WAs, 2 items assigned as high priority (may affect nuclear

safety), 7 assigned as medium priority (important but do not directly

affect nuclear safety) and 9 assigned as low priority (minimal impact on

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plant operations). Each item's status was reviewed in sufficient detail

j to determine the progress in resolving the item. The meeting was an

effective mechanism for keeping plant management informed of the status

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of each open 0WA.

07 Quality Assurance in Operations

07.1 Oversicht Meetina (40500)

On November 6. the inspectors met with Oversight personnel. Issues

discussed included Oversight activities and findings since previous

meetings. Copies of recent audits were provided for review. The

inspectors also observed Oversight personnel observing plant activities

on numerous other occasions during the inspection period and met briefly

with them to discuss their observations. The inspectors concluded that

the Oversight organization was continuing to assess station performance

effectively.

07.2 Manaaement Safety Review Committee (MSRC) Meetina (40500)

On November 20, the inspectors attended a regularly scheduled MSRC

meeting at the North Anna site and observed Station Manager's plant

status reports. The inspectors found that the MSRC meeting met TS 6.5.2

requirements for member composition and quorum and that the agenda

appropriately included review items required by TS 6.5.2.7. The

inspectors observed that the Station Manager's reports generated

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significant self critical discussions of station performance. The

inspectors concluded that the HSRC meeting was in compliance with TS

requirements and that substantive assessment issues were being addressed

in the discussions.

08 Miscellaneous Operations Issues (92901, 92700)

08.1 (Closed) Unresolved Item (URI) 50 339/96004 01, review significance of

safeguard area ventilation not meeting design basis

(Closed) Licensee Event Report (LER) 50 339/96001, potential unfiltered

release path from the quench spray pump house to the environment

a. Scope -

As a result of questions asked by the inspectors, on May 15, 1996, the

licensee identified and reported to the NRC a potential unfiltered

release path to the environment following a design basis accident. As a

result of the problem, both trains of safeguards area ventilation

systems were declared inoperable. During this inspection period, the

inspectors reviewed the problem's significance.

b. Observations and Findinas

The problem identified by the insaectors was that a flowpath existed

between the safeguards area and t1e Quench Spray (QS) area sumps. The

safeguards area contained the Low Head Safety Injection (LHSI) pumps,

Outside Recirculation Spray pumps, and associated piping and valves.

Leakage from these components was directed to a sump described in

Updated Final Safety Analysis Report (UFSAR), Section 15.4.1.8, as sized

to accommodate the design basis leakage from area components, including

a 50 gallons )er minute (gpm) LHSI pump seal leak lasting 10 minutes.

The size of t1e safeguards sump and sump drainage were important because

credit was taken that operators would notice any leakage of radioactive

water to the sump and take action to isolate the leakage. The

safeguards sump was found to be directly tied to the QS sump via a

six inch pipe connected between the two areas. The connection

potentially allowed a portion of the design basis radioactive leakage to

flow to the QS sump. This leakage could have inhibited prompt operator

identification of leakage into the sump. Additionally, the QS area

ventilation system was not designed to handle radioactive effluents, and

an unfiltered and unmonitored release could result.

The inspectors reviewed the licensee's corrective action for this

problem. Along with making a 10 CFR 50.72 report, the licensee resorted

this event in LER 50 339/96001. A temporary cap was placed over t1e

pipe until a permanent repair was prepared. Later, a Design Change

Package (DCP) was implemented to permanently plug the pipe and to

install a pump in the QS sump.

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The inspectors reviewed the event's significance. The LER stated that,

"The event posed no significant safety implications because any increase

in dose through the unfiltered release path would be well within the

limits of 10 CFR 100." The inspectors reviewed the above statement with

the licensee's nuclear fuels group personnel on September 5. The

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inspectors found that the pump seal leak contribution to off-site dose

i was small compared to total off site dose referred to in UFSAR

Section 15. With no filtration, the calculated dose associated with a

LHSI pump seal leak was increased by a factor of 10, but was still only

i a small contributor to total dose. The ins

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safety consequence of the cross tied sumps,pectors concluded

with regards to off sitethat the

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dose, was minimal.

The inspectors also questioned the potential increase in control room

dose due to the cross tied sumps. Licensee engineers postulated that

the expected control room doses would be similar to those estimated

following a separate problem identified with inadequate operator

arocedures for responding to a fuel handling accident (NRC Inspection

leport Nos. 50 338, 339/96 09). Similar to that problem, the control

room doses could possibly exceed 10 CFR 50 General Design Criteria (GDC) 19 limits for operators. However, such estimates contained

numerous conservative assumptions which meant that if an accident had

actually occurred with the leakage path through the QS area, the actual

dose to control room operators would not likely exceed the GDC 19

limits.

While reviewing the above problem on May 23, 1996, the ins)ectors also

identified that the floor drain hole that permitted the B _HSI pump

leakage to drain from its pump cubicle to the safeguards area sump was ,

grouted closed. The grouted ends had been covered with paint indicating l

the drain hole had been in this condition for a long time period. The

inspectors noted that the UFSAR Section 15. Accident Analysis, Condition

IV - Limiting Faults for a Loss of Coolant Accident (LOCA) assumed a

aump seal failure. Specifically, Section 15.4.1.8, Doses From Leakage

Trom Emergency Core Cooling System Components, stated, "The 50 gpm

leakage due to the pump seal failure is assumed to last 10 minutes

subsequent to initiation of the leak. The leakage is limited to 10

minutes (500 gallons of total leakage) because the leak will be quickly

detected by the safeguards area sump level monitor and alarm." The

grouted hole prevented the sump level monitor and alarm from performing

its function for a pump seal leak on the B LHSI pump.

This issue was discussed with system engineers. After review, DR )

N 96-1059 was issued to document the problem and track corrective

actions. The licensee found that the drain holes were plugged in both

the B LHSI and the B Outside Recirculation Spray pump cubicles. The

licensee also found that with the drain holes plugged, seal leakage

could accumulate to ap3roximately 1500 gallons before draining over to

the safeguards sump w1ich was three times that analyzed in the UFSAR. l

The holes had apparently been plugged since initial construction.

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The licensee reviewed this issue for reportability to the NRC and

j concluded the following as documented in response to the DR:

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The condition was not outside of the design basis since

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maintaining off site doses within 10 CFR 100 limits met design

j basis criteria.

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The associated safety equipment was not affected by the condition,

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and the ability to process the ventilation discharge through the

i charcoal filters was not altered. Therefore, the ability to

mitigate the consequences of an accident was not significaro iy

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! The inspectors found that the licensee's assessments of the significance

of the plugged cubicle drain holes were appropriate. Shortly after

discovery, the licensee unplugged the drain holes in both cubicles and

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verified that drains for all other cubicles were open.

The inspectors concluded that since early in plant life, the safeguards

area configuration did not match that described in the plant design

basis. The licensee's failure to ensure proper facility design was a

violation of 10 CFR 50, Appendix B, Criterion III, which required the

licensee to establish measures to ensure that applicable regulatory

requirements for the design basis described in license documents be

implemented. Contrary to this requirement, since early in plant life

until May 1996, the licensee failed to ensure that safeguards area walls

met the design basis for containing pump seal leakage as described in ,

UFSAR Section 15.4.1.8. Specifically, a hole existed between the l

safeguards area and the QS area where the design required that the

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safeguards area be fully separated. Additionally, holes designed to 3

exist between pump cubicles and the safeguards area sump in order to j

allow drainage of pump seal leakage were found to be plugged. This is  ;

identified as a violation of 10 CFR 50, Appendix B, Criterion III, l

requirements (50-339/96012 01). This violation is considered to have

occurred in the Engineering functional area.

c. Conclusions

A violation was identified for a failure to ensure proper facility

design control. Unit 2 safeguards area walls were found to not meet

their design basis for controlling safeguards pump leakage since early

in plant life. One URI was closed.

II. Maintenance

M1 Conduct of Maintenance I

M1.1 Maintenance Observations (62707)

Throughout most of the ins mction period, the inspectors reviewed

Service Water Restoration )roject (SWRP) efforts to replace sections of

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the Train B SW headers to the Component Cooling Water (CCW) heat

exchangers. During the SWRP, the licensee entered and exited various TS

Action Statements specifically approved for the SWRP. The inspectors

verified that TS compliance was maintained and that compensatory actions

required by the NRC Safety Evaluation Report for the TS Action

Statements were properly implemented by the licensee. The inspectors

also observed that the overall control of SWRP work activities was

approariate. The only deficiency noted by inspectors during the work

was t1at a flexible cable jacket was pulled out of a connector on valve

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1 SW-MOV 113A. Due to the large amount of work in the area of the

valve, it appeared that the jacket had probably been pulled out due to

unknown individuals stepping on the cable. DR N 96 2687 was initiated,

and the configuration was reviewed and found not to be an operability

concern. A work recuest was initiated for corrective action. The

inspectors concludec that overall the SWRP work activities were well

controlled, and supporting system manipulations were performed in

accordance with regulatory requirements and commitments.

M2 Maintenance and Material Condition of Facilities and Equipment

M2.1 Emeroency Diesel Generator (EDG) Radiator Fan Exhaust Comoartment

Housekeepino (71707)

On December 4, the inspectors, accompanied by a system engineer,

performed a walkdown of the EDG radiator fan exhaust compartments

located on the Service Building roof. Debris was observed on the ledges

above the radiator fans for three of the four EDGs. The debris included

two four by six inch metal )lates. With the radiator fan blades

exposed, a seismic event, w11ch results in EDG starts or occurs while an

EDG is operating, could cause the debris to fall onto the radiator fan

blades with unknown consequences. The system engineer notified the

shift supervisor of the observation so that the debris could be removed.

Deviation Report N 96 2749 was issued concerning this condition.

M8 Miscellaneous Maintenance Issues (92902, 92700)

M8.1 (Closed) Violation 50 338/95015 01, failure to follow procedures for

properly controlling safeguards area ventilation system (SAVS)

maintenance. This event involved the requirement of following

procedures to ensure that maintenance on safety related equipment be

properly preplanned and performed to minimize the impact on operability

of other associated safety equipment. Senior reactor operators failed

to verify whether maintenance work on one SAVS train would affect the

other redundant equipment train.

The inspectors verified that the licensee performed adequate

investigation and established the root causes for the event. Multiple

personnel errors in this case caused the process that would have ensured

the prevention of such an event to breakdown. The licensee took

remedial actions through the disciplinary process, and the event was

discussed at training sessions and shift turnovers and was instituted as

a part of the Licensed Operator Requalification Program.

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The inspectors verified that special training sessions took place, that

remedial action was taken, and the training materials and procedures

were reviewed in detail to ensure adequacy. The inspectors concluded

that the licensee's response dated October 12, 1995, and the corrective

actions were appropriate and had been adequately implemented.

M8.2 (Closed) Violation 50 339/95020 02, failure to comply with 3.6.1.3 for

air lock outer door rendered inoperable by open test connection. This

violation concerned an inoperable Unit 2 containment air lock outer door

due to valve 2 CE 4 being left uncapped. When the containment air lock

outer door became inoperable, unknowingly the plant was then under a TS

Limiting Condition for 0)erations. TS 3.6.1.3, Action A, required that

the operable door be locted within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or that the plant be placed

in hot standby within the next six hours and placed in cold shutdown

within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

The inspectors reviewed the licensee's response and commitments to this

event to determine the adequacy and appro)riateness of corrective

actions taken and the implementation of t1ose actions. The inspectors

verified that the licensee's response to the violation clearly

documented the efforts expended to preclude recurrence of the problem.

The inspectors reviewed procedure 2 PT-62.1, Containment Air Locks -

Leakage Rate, Revision 17, and verified that the procedure had been

revised and updated. The licensee's efforts to correct the causes of

the event included coaching the individuals who performed the procedure

on the importance of procedure implementation and self checking. The

event and lessons learned became part of the licensee's requalification

program. The inspectors concluded that the licensee's response dated

January 9, 1996, and corrective actions were appropriate and had been

adequately implemented.

M8.3 (Closed) LER 50 338, 339/96009, reactor trip bypass breaker missed

surveillance due to inadequate surveillance test procedure. This LER

reported the identification on October 10, 1996, that a surveillance

test was not being performed as required by TS 3.3.1.1. The

surveillance tests were not testing the reactor trip bypass breaker

manual shunt trip prior to placing the breaker in service. The shunt

tri) was instead being tested immediately after closing the normally

rac(ed in breaker. Licensee personnel identified the deficiency after

visiting another facility and noting differences in the testing

procedures. The licensee postulated that the procedure inadequacy was

caused by personnel mis interpreting TS wording and failing to identify

that a procedure change was needed following a 1986 TS change. A review

of NRC Generic Letter 85 09 Technical Specification for Generic Letter 83-28, Item 4.3, revealed that the prior interpretation was incorrect.

As corrective action, the licensee modified surveillance test procedures

to recuire that the bypass breaker be racked out and the shunt trip

testec prior to closing the breaker. The inspectors verified that these

procedure changes were completed. Additionally, a UFSAR change was

planned to update test sequence descriptions.

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

.

.

10

TS Surveillance Requirement 4.3.1.1.1. Table 4.3-1, Notation 8, requires

that the reactor trip bypass breaker local manual shunt trip be tested

prior to placing the breaker into service. Contrary to this

requirement, from approximately June 9,1986, until approximately

October 10, 1996, reactor trip bypass breakers were placed in service

without first testing the local manual shunt trip. This is identified

as a violation for an inadequate surveillance test, in that, the test

did not meet TS surveillance requirements. This licensee identified and

corrected violation is being treated as an NCV, consistent with

Section VII.B.1 of the NRC Enforcement Policy (50 338, 339/96012 02).

M8.4 (Closed) LER 50 338/96010, automatic reactor trip due to failure of a

generator negative phase sequence relay. This LER discussed an October

24,1996, Unit 1 tri) from full power due to a failure in the main

generator negative plase sequence relay. The licensee's response to the

event and corrective actions for the associated equipment failures were

reviewed and discussed in NRC Inspection Report Nos. 50 338, 339/96 10.

M8.5 (Closed) LER 50 339/96003, automatic reactor trip resulting from main

generator stator coil failure due to personnel error. This LER

discussed a November 12,1996, Unit 2 trip from full power due to a main

generator failure. The licensee's response to the event and initial

corrective actions for the event are reviewed and discussed in

Section 01.2. The inspectors also verified that appropriate corrective

actions were initiated for all associated minor equipment failures

following the trip.

III. Enaineerina

El Conduct of Engineering

El.1 Problem with Bolts - SW and Auxiliary Service Water Pumo

a. Insoection Scope (37550)

The inspectors reviewed a problem, documented in DR N-96 2359, involving

the seismic qualification for a replacement SW aump and stress on the

pump's flange bolts. Requirements related to t11s review included

American National Standards Institute (ANSI) B31.7, Power Piping.

b. Observations and Findinos

The licensee was in the process of replacing four safety related SW

pumps due to aging concerns. Replacement SW pump 2 SW P 1A was

installed in December 1995. The remainder were in manufacturing.

In October 1996, the manufacturer's Quality Control inspector, while

inspecting the second pump at the factory, identified a discrepancy in

the bolts at various column flanges and the bowls. The drawings

indicated one-inch diameter bolts were required, but the actual hardware

installed was three-quarter inch diameter bolts. The manufacturer

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

,

-

'

,

11

l contacted the licensee to ask for approval to ship the pump with smaller

bolts about October 14, 1996. This prompted the licensee to review the

seismic qualification report (AR120N, Revision 1), the outline drawings,

a

and the bill of material for the pump received in 1995. The licensee

identified a discrepancy between the seismic report and the

bill of-material regarding the bolts in question. The seismic

>

qualification report was based on one inch diameter, A325, high

strength, dynamic loading bolts, but the bill of material showed

one inch diameter, A307, low strength, non dynamic loading, structural

bolts.

.

Concerned about operability of the installed pump in light of the new

information, the license requested the manufacturer to perform a seismic

re analysis based on the actual bolts supplied with the new pump

.

(one inch diameter, A307). When the licensee reviewed this re analysis,

i

they identified errors. The re analysis used the wrong bolt tensile

>

strength area and compared calculated stresses to the wrong criteria

(wrong code), and therefore reached a wrong conclusion. Revision 1 of

the seismic report provided by the manufacturer did not have these

, errors. The licensee then performed their own re analysis on October

16.

T

The licensee's analysis showed a calculated stress for the Design Basis

-

Earthquake condition of 28.6 ksi on the bolts compared to ANSI B31.7

allowable stress of 16.8 ksi. ASME Section III, Appendix F, states that

the pump would be operable if the stress did not exceed 0.7 times the

Ultimate Tensile Strength or 42 ksi. Therefore, the licensee concluded

the pum) was operable. Replacement of the non conforming bolts with

proper aolts was scheduled for January 13, 1997. In addition, on

October 21, 1996, the licensee issued a revised aurchase specification

calling for A193 Group B7 high strength bolts to >e supplied with the

new pumps. Also, the licensee planned to inspect two Auxiliary Service

Water pumps, which were classified as important to safety, to determine

the bolt type used in these pumps. If necessary, those bolts would be

replaced as well.

The inspectors inquired whether a notification of defect would be issued

pursuant to 10 CFR 21. The licensee stated that evaluation of the need

for a report was in progress.

The licensee had documents, namely the seismic report and the

bill-of material, which contained a discrepancy and deficiency with

regard to the material of the bolts in question. However, the

licensee *s design reviews failed to identify these before installation

of the first replacement pump. This problem in the design control

program contributed to installation of non conforming bolts, and

constitutes a violation of 10 CFR 50, A)pendix B, Criterion III, Design

, Control, which requires that measures slall be established to ensure the

design basis are correctly translated into drawings. The matter is

'

identified as a violation (50 339/96012 03).

.

.

12

c. Conclusions

The inspectors concluded that the licensee's operability evaluation for

non conforming bolts in a recently installed pump reached a proper

conclusion in accordance with NRC guidance, and was completed in a

timely manner. The scheduled date for correcting the non conformance

was acceptable. Even though the problem was primarily caused by the

manufacturer, reviews in the licensee's design control program did not

identify that the wrong bolts were installed. For this reason a Notice

of Violation was issued.

E1.2 Review Sucoortina Plant Cooldown Durina SW Maintenance (37551)

During the licensee's SWRP to replace sections of the Train B SW piping i

going to the CCW heat exchangers (Section M1.1), a Unit 2 forced outage

was required for main generator repairs. The inspectors reviewed the

licensee's decisions with regard to the shut down status of Unit 2 to

ensure that regulatory recuirements were met and that Unit 2 was

maintained in a safe shutcown condition. The inspectors reviewed the

licensee's submittal for TS changes required to su) port the SWRP. In

the submittal documentation, the licensee stated t1at if an outage was

required for either unit during the SWRP, an assessment would be

performed. The inspectors found that shortly after shutdown, the

licensee completed the required assessment which was contained in an

Engineering Transmittal (ET) No. NAF 96201. The inspectors reviewed the

ET and found that it accurately assessed the situation. Specifically,

it analyzed the reliability of available SW equipment to support

shutdown operations and made appropriate recommendations for

compensatory actions. Additionally, the inspectors noted that managers

considered the ET and other available information and made a

conservative decision to keep Unit 2 in hot shutdown and not proceed to

cold shutdown until the SWRP was completed. The inspectors concluded

that the licensee appropriately analyzed the impact of the SWRP on the

unit shutdown and made conservative decisions concerning unit status.

E1.3 Inservice Testina of Decay Heat Release (DHR) Stoo Check Valves

a. Insoection Scope (37551)

During the week of November 12, the inspectors reviewed the engineering

basis for deleting Inservice Test (IST) requirements for DHR stop check

valves 1/2 MS 19 58, and 96.

b. Observations and Findinas

During the previous inspection period, the ins)ectors observed that

operators used the Unit 2 Decay Heat Release ()HR) valve to control

temperature during a forced outage. The DHR valve was an air operated

Steam Generator (SG) atmospheric relief valve located on a common header

supplied from all three SGs. The header was normally isolated by

manually operated stop-check valves 1/2 MS 19 58, and 96. On October

i

. . .

.

.

13

22, the inspectors observed that all three Unit 2 stop check valves were

open to allow DHR valve use. The inspectors questioned engineers

concerning the IST history for the stop check valves and were informed

that ISTs for the valves had been deleted in early 1996. Licensee

engineers provided the inspectors with a memorandum from C. Snow to B.

Foster dated October 24, 1996, describing the basis for deleting ISTs.

The inspectors reviewed the memorandum and found that it stated that the

ISTs were deleted because UFSAR Section 15.2.13.3 provided an analysis

of simultaneous blowdown of all three SGs due to a failure of the three

inch DHR line. The memorandum stated that American Society of

Mechanical Engineers (ASME) Code Section XI, paragraph IWV 1100,

required testing only for valves which were, " required to perform a

specific function in ... mitigating the consequences of an accident."

Since the UFSAR did not take credit for the valves' isolation in

analyzing for a DHR header break, the licensee concluded that ISTs were

not required. The inspectors accepted this conclusion for the accident

analyzed in UFSAR Section 15.2.13.3.

However, the inspectors identified that a different accident function

for the valve had not been properly considered by the licensee.

Specifically. UFSAR Section 15.4.2.1 described analyses for a Main Steam

Line Break (MSLB) occurring within the isolation boundaries for the SG

(e.g., upstream of the stop check valves). The analyses in that section

assumed that only one SG would be depressurized for such a failure. On

November 19, the inspectors informed licensee engineers that for this

assumption to be valid when the DHR valve is in use, the check valve

feature of the stop check valves must function correctly. The

stop check valves were needed to prevent backflow from intact SGs into a

faulted SG in order to prevent simultaneous blowdown of all SGs. The

stop check valves served a function similar to check valves in the steam

lines supplying the turbine driven AFW pump, for which ISTs were

performed. After reviewing the issue, licensee engineers submitted DR

N 96 2674 on November 22. The DR stated that IST testing for the

stop check valves should have been continued in order for operators to

be allowed to use the DHR valve for temperature control as was done on

October 22 through 24.

On November 26. licensee engineers provided the inspectors with a copy

of ET NAF 96207, Review of Decay Heat Removal Using the Decay Heat

Release Valve and Impact on the Plant Safety Analyses North Anna Power

Station Units 1 and 2, dated November 26, 1996. The ET evaluated the

effect of a failure of the check valve function on the accident analyses

for a MSLB. The ET concluded that for the plant situation existing on

October 22 through 24, (reactor in MODE 3, all rods in, main feed

isolation valves shut, and main steam non return valves shut), operation

of the DHR valve was acceptable and the licensing basis MSLB analysis

remained valid with an assumed failure of a DHR stop check valve. The

inspectors found that the ET prepared on November 26 demonstrated that

,

for the plant configuration actually occurring when the DHR valve was

used, the problem did not have major safety significance.

.

.

14

Overall, the inspectors found that the licensee had deleted the ISTs for

the DHR stop check valves without proper supporting analysis or controls

to prevent their use. In order to delete testing the check valve

functions of 1/2 MS 19. -58, and 96, use of the DHR valve should have

been prevented by modifications or procedural controls, or the licensing

basis MSLB analyses should have been re preformed assuming a stop check

valve failure. Neither of these actions were taken until questions were

raised by the inspectors. The licensee's failure to ensure proper IST

for the valves was a violation of TS 4.0.5 surveillance requirements

which required that ASME Code Class 1, 2 and 3 components be inspected I

and tested in accordance with ASME code Section XI. Contrary to this

requirement, the licensee deleted testing requirements for the  ;

stop-check function for the six DHR isolation valves without properly )

evaluating or limiting their function during accident conditions. Three j

of the six valves were opened for use from October 22 through 24, 1996.

This failure constitutes a violation of minor significance and is being

treated as an NCV consistent with Section IV of the NRC Enforcement

Policy (50 338, 339/96012 04).

c. Conclusions

An NCV was identified for a failure to meet ASME code Section XI ,

requirements for testing the check valve functions of six steam I

generator DHR isolation valves. l

l

E1.4 Minor Modification Review Team (MMRT) Meetina (37551)

On December 4, the inspectors attended a MMRT meeting. Since these

meetings had been tem)orarily suspended after the October 16 meeting l

because of outages, t1ere were several new Requests for Engineering l

Assistance to be reviewed. The primary purpose of the meeting was for

management to approve, modify, or cancel proposed minor modifications.

The reviews considered nuclear plant safety, personnel safety, and

economic benefits, generally in that order. The discussions also

considered if a minor modification was the proper vehicle for addressing

an issue. The meeting was professionally conducted. The inspectors had

no concerns involving the disposition of the items.

E2 Engineering Support of Facilities and Equipment

E2.1 Resolution of Microbioloaical Influenced Corrosion (MIC) Corrosion of

Stainless Steel SW Pipina

a. Insoection Scope (37550)

The inspectors reviewed the licensee's ongoing activities in the area of

leaks in the SW piping. The regulatory requirement relevant to the

scope of inspection was 10 CFR 50, Appendix B, Criterion XVI, Corrective

Action.

-

- .-. . . - -

-

l

l

'

)

15 j

l

b. Observations and Findinas

l

The licensee was resolving the problem described in DR N 96-2492 which ,

identified the presence of two pin hole leaks on a four inch diameter l

stainless steel alloy 316 SW piping weld. The licensee inspected the  ;

piping for the possibility of MIC since this form of corrosion had been

prominently identified in the carbon steel SW piping, and had been

identified in a stainless steel weld failure in the SW System in 1993.

A review was made by the inspectors of the Nondestructive Examination

(NDE) Procedure used for evaluating the MIC found in the stainless steel

SW line, No. NDE-RT-102, Radiographic Examination to Detect ...MIC,  !

Revision 0, dated November 15, 1996. The attack.of MIC occurs in the

weld or in close proximity to the weld in stainless steel piping. The

procedure was discussed with a corporate NDE, Level III, radiographic  :

specialist and the X ray film for welds WS 18E Line 4" WS 56163 03 Weld l

Nos. 60, 61, 64, and 65 were reviewed with the radiographer for the

presence of MIC attack. Further discussions were held with the

,

l

radiographer concerning the evaluation of the length of the MIC defect  ;

size and the inspectors considered those evaluations to be conservative. I

Also, the licensee noted that any weld defects, lack of fusion, etc., .

were added to the defect size in this evaluation. The licensee l

radiographed 15 welds and only one of these welds did not have any areas

of HIC attack. The radiographer shot six film for each weld. The

defect sizes noted in the 14 welds varied from % inch to 18 inches in 2

length with the longest cumulative length being 38 inches in weld No. 89 l

in Line 4" WS 56-163-Q3.

!

The insmetors accompanied one of the licensee's inspectors performing l

the weecly visual examination of the welds in this service piping and l

discussed the results and inspection requirements for this examination.  ;

While the licensee was still developing their SW action plan (some of

the actions would depend on inspections that had not yet been

completed), the inspectors reviewed the part that had been formulated as

of November 22, 1996. The licensee started preparation for replacement

of a section of four inch diameter pipe, and was preparing to visually

inspect all accessible welds in stainless steel SW piping. The licensee

stated that the visual inspections would include 18 , 3 , 4 , and 8 inch

diameter piping. The licensee was also considering selecting a sample

of welds for radiography.

c. Conclusions

The licensee's approach to resolving a potential problem with MIC in

stainless steel SW piping was reviewed. One section of 4 inch diameter

pipe was scheduled for replacement based on findings to date. The

licensee was at the investigation stage, and the total corrective action

plan was under development. Evaluations performed by the licensee were

reviewed and found to be conservative. No concerns were identified by

the inspectors.

1

_ _ _

.

.

16

E2.2 Repair Reclacement of Carbon Steel SW Pioina

a. Insoection Scope (37550)

The inspectors reviewed Design Change Notice (DCN) No. 94 010

Pepair/ Replacement of Exposed SW Piping to/from CCHXs, North Anna Units

1&2, and reviewed work being performed to implement the DCN.

Requirements for the scope of this inspection were 10 CFR 50,

Appendix B, Criterion III, Design Control; and Criterion V,

,

1

Instructions Procedures and Drawings.

b. Observations and Findinas

The inspectors reviewed DCN package No.94-010,. including written

descriptions of the change, isometric drawings for pipe support

locations, and the erection control isometric. The package was adequate

for the field implementation underway. The inspectors discussed the SW

repair / replacement project with the cognizant engineer, and accompanied

one of the assigned engineers into the auxiliary building basement where

some of the ex)osed SW piping was being replaced. Using the reviewed

DCN package, t1e inspectors reviewed some of the ongoing work.

The ins)ectors reviewed the welding technique sheet being used to weld

the car >on steel piping (Welding Technique No.103). The root passes

were welded using Gas Tungsten Arc Welding (GTAW) and the remaining part

of the weld was made using Shielded Metal Arc Welding (SMAW). The l

inspectors reviewed the material certifications of the bare wire used in ,

GTAW welding, the covered electrodes used in SMAW welding, and the l

certifications for one section of piping (piping is ASME SA106 Group B).

'

The welder performance qualification records were reviewed for three of l

the welders performing work on this modification. The welds appeared to

be of good quality and no problems were identified with the

documentation.

c. Conclusions

The engineering DCN package was well prepared for implementing a carbon

steel piping replacement in the SW System, and the quality of work being

performed by the craftsmen was good.

E2.3 Condition of Safety Related Batteries

a. Inspection Scope (37550)

The inspectors performed a detailed visual ins)ection of each cell in

the safety related vital and diesel generator aatteries for both units

(total of twelve battery banks). The inspectors also performed a

general inspection of the racks and environment for the batteries. The

inspection was pe-formed in accordance with Institute of Electrical and

Electronics Engineers (IEEE) 450, IEEE Recommended Practice for

Maintenance Testing of Large Lead Storage Batteries for Generating

Stations, Section 4.3 Inspections. This standard was not mentioned in

.

.

17

the UFSAR, but was used as a guide. This particular inspection item was

chosen, in part, because there have been several problems reported with

safety related batteries throughout the industry.

b. Observations and Findinas

The batteries and racks were well maintained. The rooms for the vital

batteries were well maintained and ambient conditions were acce) table.

The ambient conditions for the diesel generator batteries, whic1 were

located with the generators, were acceptable. All charger output

currents and voltages were normal. The electrolyte level was within

specification. No cracks or corrosion were observed. The last pilot

cell data was posted at each battery.

~

Cell No. 30 in bank 1-III and cell No. 60 in bank 1-IV had sedimentation

of significant depth below one or two plates. In response to this

observation, the licensee initiated DR N 96-2635. As part of the DR

resolution, the manufacturer's technical representative came to the site

and inspected the batteries. His report stated that the two cells

mentioned above were showing signs of reconversion to sponge lead from

the positive plate settlement.

The concern with sedimentation is that it could cause.the voltage to

decay. The inspectors reviewed co)ies of the data sheets from the last

surveillance tests which checked t1e voltage, specific gravity and level

of all cells. The surveillance had been performed on June 4, 1996,

according to PT-96 86B. The inspectors reviewed co)ies of the data

sheets for the most recent capacity test which had seen conducted on

September 24, 1994, according to PT 88D. The inspectors observed that

all the cells showed good voltage and capacity in the surveillances,

although tne cell inspections had not identified any problem with

sedimentation.

The licensee indicated to the insaectors that they would define an

enhanced monitoring program for t1e cells with excess sedimentation.

The 1-III battery had a date code February 1987, and the 1 IV battery

had a date code of January 1992.

DR N-96 0421 indicated that a short circuit had occurred at the main

terminals of battery 1 IV during preparations for a service test. The

inspectors examined the condition of the battery terminals. The

inspectors observed that some metal was melted away, but the damage was

of no consequence to future performance of the battery.

c. Conclusions

A detailed cell inspection was performed on each cell of all the

safety-related batteries. The inspectors concluded that battery

maintenance met requirements. However, the inspectors observed

significant sedimentation in two cells. The inspectors concluded that

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

.

.

,

18

the sedimentation had been aresent on June 4, the time of the last

i

'

surveillance inspection. Tierefore, the fact that the surveillance did

not record any problems with sedimentation was considered a weakness in

the implementation of that inspection.

'

E2.4 Review of Mechanical and Structural Re_ lated Potential Problem Reoorts

and Deviation Reports

a. Inspection Scope (37550)

The inspectors reviewed the disposition and corrective actions for the

below listed Potential Problem Report (PPR) and DRs to determine if they ,

were adequately reviewed, evaluated, resolved and corrected. The items

reviewed were: -

l

'

'

Item No. Condition

PPR 96 018 Internal Pressure Concerns in Closed Piping in

,

Containment During a Design Basis Accident j

'

DR N 96 0384 A Pinhole Leak at Engine Sump of EDG '

i DR N 96-0450 Leakage on One-Inch Diameter Chemical Addition Piping  ;

Expansion Joint

i

! DR N 96 0534 Response Spectra for Auxiliary Building

1

DR N 96 0843 Effects of Post-accident Temperature on the  !

, Recirculation Spray (RS) and Quench Spray (QS) Systems

,

DR N 96 1169 Quench Spray System Pump Flow Uncertainty

DR N-96 2498 Steam Generator Blowdown Tank Supports

As appropriate, the inspectors verified corrective actions by reviewing

revised procedures, and drawings. The inspectors reviewed calculations

and modifications as appropriate.

l b. Observations and Findinas

I

While some of the DRs were still in the process of evaluation or

analysis, the inspectors concluded that the performance of the engineers

was good. However, the inspectors had a comment on a tank isolation

sequence carried out by Operations personnel. The corrective action for

DR N 96 2498 included draining and isolating the steam generator

"

blowdown tank for each unit. When the inspectors verified this action,

he noted that one drain valve (1 BD 33) was in the correct position, but

it was not tagged. Review of the system revealed that the position of

valve 180 33 was of no consequence to accomplishing the intent of the

evolution as long as the other valves were in the correct position.

This represented an inattention to detail in preparing the evolution

instruction, since the tagging record did not include this valve.

+ - _ . _ . - - - - . . . - .

1

.

1

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!

19

c. [pnclusions

A review of six Deviation Reports and one Potential Problem Report

related to mechanical and structural engineering indicated good support

for facilities and equipment by engineers.

E2.5 Overvoltaae on 480 V Bus

a. Insoection Scooe (37550)

The inspectors reviewed a situation where relatively frequent

overvoltages occurred on one or more 480 V buses. Most of the

overvoltage conditions occurred during plant shutdowns, but they

occurred during power operation as well. This situation involved

changing a previously submitted response to an NRC request for

information and performance of a safety evaluation (10 CFR 50.59).

Documents reviewed at the outset included the following: )

-

Letter, VEPC0 to NRC, dated June 4, 1982, on the subject of

" General Design Criterion 17 Analysis North Anna Units 1 and 2."

-

Letter VEPC0 to NRC, dated Seatember 10, 1996, on the subject of

" General Design Criterion 17: . Revised Commitment Related to

Response to Overvoltage Conditions."

-

Safety Evaluation 96 SE 0T-4B.

-

Type 1 Report NP 3085 (partial).

-

Alarm Response Procedure,1F-H5, 480 V or 4 kV Emergency Bus Volts ,

Hi/Lo.

'

Inspection activity of this item included a walkthrough of an alarm

response procedure involving manual operation of an on load transformer

tap changer and reading of voltage indicators and computer outputs.

Also, drawings, calibration data and voltage relays were inspected.

Requirements relevant to this inspection scope were: 10 CFR 50,

Appendix A, Criteria 13, 17, and 19: Regulatory Guide 1.33, Appendix A.

Item 5: Regulatory Guide 1.97 and 10 CFR 50.59.

b. Observations and Findinas

The source transformer had an on load automatic tap changer to maintain

the voltage on the 4 kV bus. Design basis loading scenarios dictated

that fixed taas on the 4160 480 V transformer must be set to boost

voltage. Witi voltage at the 4 kV bus at the low end of the tap changer

control band, voltage at the 480 V bus would be in saecification. With

voltage at the 4 kV bus at the high end of the tap c1 anger control band,

overvoltage would occur on a lightly loaded 480 V bus. Overvoltage

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

.

.

20

i

relays were installed on each 4 kV and main 480 V bus to warn operators

i of an overvoltage condition. The relays were wired to a common control

i

room annunciator point and individual computer points.

When an overvoltage alarm was received, the operator was prompted by the

alarm response procedure to determine which buses were normal and which

were abnormal. This was done primarily through checking of voltmeters

i

and the relevant com) uter alarm points. In the case of 4 kV normal and

480 V overvoltage, tle procedure was to put the source transformer tap

.

changer in manual, and depress voltage on the 4 kV bus to the low end of

the acceptable range. The tap changer would then be returned to

automatic mode. The tap changer control band was about 160 volts and

the tap changer made an adjustment of 26 volts per step.

. .

,

'

The maximum calculated voltage on a 480 V bus with the 4 kV voltage in l

s)ecification was 521.9 V. Between 1982 and a recent procedure change, '

t1e operators were allowed 15 minutes to take the actions described

! above. The procedure was changed recently to allow a response time of  !

,

two hours. The two hours applied only to performing the tap changer

"

manipulation.s. The change was supported by a safety evaluation, and the

NRC was notified of the procedure change by letter. The  ;

covered the case of diesel generator as the power source. procedure also

i The 480 V bus voltage could be read at a computer terminal in the main

control room and other locations. This was accomplished through

potential transformers, ac/dc transducers, a multiplexer and the

Emergency Response Facility computer. The transducers were wired to

read line to neutral voltage, and the multiplexer applied a factor of

1.73. The purpose of this factor was to present a line to line

magnitude voltage which was more recognizable to operators.

l The inspectors read the following voltages at the Emergency Response

. Facility terminal for the 1H1 bus: A=493, B=530 and C=519. These

8

voltages were significantly unbalanced and two of the three were above

the alarm set point of 515 V. The licensee initiated DR N 96 2634 to

resolve this apparent discrepancy. Using an accurate portable

1 voltmeter, the licensee read voltages directly on the 480 V bus and at

l various points in the potential circuit. These readings indicated that

voltages were normal and balanced -- 507, 504 and 506. The readings

also indicated that the multiplexer was introducing an error in the

computer readout of voltage. The inspectors requested a co)y of the

last calibration of the voltage loop at the multiplexer. T1e last

, calibration had been performed on April 26, 1996. One of the phases had

4

a significant error, and was adjusted at that time. Since that time,

the multiplexer had drifted out of calibration. As a result of the

, inspection findings related to reading voltage at the 480 bus, the

! licensee was considering the following three actions:

2

1 -

Re wire the transducers to read line to line voltage.

- - In the interim, revise the ERF nomenclature to indicate the

reading is line to neutral multiplied by 1.73.

4

l

-- -. - .

.

.

21

-

Reduce the calibration interval of the multiplexer.

c. Conclusions

The alarm response procedure for bus overvoltage was a workable

procedure, and was consistent with statements made in letters to the NRC

on the subject of overvoltages. The safety evaluation supporting the

change in maximum allowable response time for performing tap changer

manipulations was accurate and complete.

Some corrective actions were proposed by the licensee to address NRC

comments with regard to reading voltage at the 480 V bus, but this did

not represent any programmatic weakness. The overvoltage relays with

alarms were a conservative design in relation to standard industry

practice.

E2.6 Adecuacy of Voltaae for Diesel Generator Breaker Close Coil

a. Insoection Scope (37550)

From a summary of DRs written on electrical systems since November 1995,

the inspectors selected DR N 96 0334 for further review. This DR,

initiated February 19, 1996, involved the failure of safety related

vital battery 1-I to meet one acceptance criterion during performance of

the last service test.

The relevant requirements for this inspection item were TS 4.8.2.3.2.d

(battery service test) and 10 CFR 50, Appendix A, Criterion 17. Electric

Power Systems.

b. Observations and Findinas

The acceptance criterion from 1-PT 87H, DC Distribution System' Service

Test (Train A), that was not met in the last service test was to have at

least 115.6 VDC at the battery terminals at t=10 seconds. The measured

voltage was 115.3 VDC.

The reason for this criterion was to demonstrate that the breaker close

coil for diesel generator 1H was operable. The criterion was determined

by calculation and directly related to the close coil rated minimum

operating voltage of 70 VDC. As confirmed by the inspectors, the source

of this value was a letter from Brown Boveri Co., to VEPC0, dated June

24, 1986, on the subject of " Reliable Minimum Close Coil Voltage." A

similar criterion applied to battery 2-I, but the other vital batteries

did not have a corresponding criterion because calculations indicated

that the voltage at t=10 seconds was not critical.

The licensee completed an Operability Determination on February 20,

1996. The report, which was reviewed by the inspectors, concluded that

the battery was operable based primarily on the logic that the service

.

.

22

test result was only 0.3 V less than the conservatively calculated

minimum voltage. Also, the report referenced a test conducted on an i

identical breaker in December 1985 which demonstrated breaker operation I

with a control voltage of about 40 VDC.

The Operability Determination also recommended that the output breaker

for diesel generator 1H be tested to demonstrate operability at control

voltages less than 70 V. This was expeditiously done, and the breaker

was demonstrated to operate with a minimum control voltage of about

40 V. The inspectors asked about the test methodology to determine a

minimum operating voltage. The test engineer explained that he slowly

increased voltage to the close coil being tested with a rheostat. The

inspectors commented that a similar test conducted at another site had

resulted in damaging a close coil which had a rated minimum operating '

voltage of 100 VDC and a rated energize time of one minute. The test

engineer recollected that he increased from zero to operate voltage in

about 15 seconds. The rated energize time was not readily available.

The breaker in question operated several times during diesel generator

surveillance tests since the special test was conducted. While the l

inspectors agreed that the diesel generator output breaker was OPERABLE,

there still remained the question of whether the test procedure affected

the useful life of the close coil.

The inspectors noted that the criterion for battery voltage at t=10

seconds did not provide margin above the calculated value. Should the

service test result be only slightly above the criterion, the procedure

would not require any further evaluation. However, in such a case,

given an 11 year old battery, normal aging could very possibly result in

below criterion results at the next scheduled test. To address this

concern, the inspectors reviewed results of the last service test on

battery 2-I, which supplied diesel generator 2H output breaker control

power. The test result was 118.5 VDC as compared to a required 111.4

VDC. Therefore, there was sufficient margin in the last test results to i

offset normally expected aging. The licensee stated they would I

re consider their t=10 second criterion in light of battery aging.

Given the importance of the components involved, the inspectors decided

that this issue should be re visited at a future date. The specific

items to review are:

- Enhancement to the voltage criterion in the service test procedure

to account for aging.

-

Enhancement to the test procedure which demonstrated close coil

operating voltage.

- Evaluation of the close coil ratings versus the test procedure

used in February 1996.

-

Evaluation of future service test results versus the close coil

rating.

.

.

.

23

The issue will be tracked under an Inspection Follow up Item (50 338,

339/96012-05).

c. Conclusions

The inspectors reviewed a DR involving the failure of safety related

vital battery 1-I to meet one acceptance criterion during performance of

the last service test. .The inspectors agreed that the subsequent

Operability Evaluation was reasonable, and that the requirement of the

TS was met. An Inspection Follow up Item was established to ensure

review of certain procedure enhancements and future test results.

E3 Engineering Procedures and Documentation

.

E3.1 Modification of the CCW Surae Tank Suocort

a. Inspection Scooe (37550)

From a summary of DRs assigned to structural engineers, the inspectors

selected randomly DR N 96 2095 for review. Resolution of this DR

involved a modification, and the inspectors reviewed that modification

as well. The upper level requirement applicable to review of the DR was

10 CFR 50, Appendix B, Criterion XVI, Corrective Action. The

requirement applicable to review of the modification was 10 CFR 50,

Appendix B, Criterion III, Design Control. The DR and modification

involved 10 CFR 50 Appendix A. Criterion 2, Design Bases for Protection

Against Natural Phenomena.

b. Observaticns and Findinas

DCN 96 014 reinforced the supports for the CCW surge tank to resolve

concerns about the seismic integrity of the tank. From a design

wrspective, this DCN met the requirements, and resolved the DR.

iowever, inspection of the completed work by the inspectors identified

that the dimensional tolerances indicated on Drawing No.

N 96014 3-S 001, Sheets 1 through 8 were exceeded. For example, the

dimensions for certain anchor bolts carried a tolerance of minus 0

inches, plus 2 inches. Actual dimensions varied from the specified

minus tolerance by ly inches and the plus tolerance by IV inches. Also,

the inspectors observed that one pipe support for a 3 inch diameter pipe

was attached to the original un reinforced portion of the tank support

and that pipe support did not show on the modification drawings. DCN

96 014 was signed as completed on October 11, 1996, by the Operational

Readiness Review. The licensee did not produce any documentation

indicating that the discrepancies were noted or evaluated. The

inspection finding described above constitutes a violation of 10 CFR 50,

Appendix B, Criterion V, which requires that activities affecting

quality shall be accomplished in accordance with documented drawings.

The matter was identified as a Violation (50 338, 339/96012-06).

1

I

)

!

.

.

24

c. Conclusions

Review of a 1996 modification package (DCN) to reinforce the supports

for the CCW surge tank to resolve concerns about the seismic integrity

of the tank indicated that the design was correctly accomplished, but

that the actual installation did not meet specified dimensional

tolerances. Also, a pipe support was installed at a point where no

support was shown on the drawings. A Notice of Violation was issued.

E3.2 Set Points for Molded Case Circuit Breakers

a. Insoection Scope (37550)

The inspectors reviewed the control of set points for safety related

molded case circuit breakers. This inspection topic was chosen, in

part, because lack of controls on molded case circuit breaker set points

at other sites resulted in breakers inadvertently tripping during

starting.

Relevant requirements for this inspection topic included 10 CFR 50,

Appendix B, Criterion III, Design Control and Criterion V. Instructions.

Procedures and Drawings. Guidance was provided by IEEE std 741 1986,

IEEE Standard Criteria for the Protection of Class 1E Power Systems and

Equipment in Nuclear Power Generating Stations, Sections 5.1.3.1 and

6.1.4. Also, the inspectors referenced IEEE std 242 1986, IEEE

Recommended Practice for Protection and Coordination of Industrial and

Commercial Power Systems Section 9.3.3.5, Instantaneous Settings.

b. Observations and Findinas

The great majority of motor control centers at the site were furnished

by Klockner Moeller Co. The original circuit breakers had an adjustable

inverse-time (thermal) element and a fixed instantaneous (magnetic)

element. Many of the original circuit breakers had been replaced with a

newer style due to a problem described in a 10 CFR 21 report (NRC

Information Notice 93 22) and other age related failures. The newer

style circuit breakers had an adjustable thermal element and an

adjustable magnetic element.

The frame size and thermal element set point were shown on the one line

diagrams which depicted the 480 V motor control centers and loads. The

magnetic set point was not shown on the drawings. The inspectors

inquired as to how the set points for the magnetic element were

established and controlled. The engineers responded that the

craftsperson or technician installing a new breaker would know (i.e.,

skill of the craft) to make the settings the same as the one being

replaced. The validity of this method was based on the philosophy that

operating experience has shown the set points to be a>propriate (i.e.,

no inadvertent tri) ping). The licensee pointed out t1at the magnetic

set point, althoug1 fixed, was indicated on the nameplate of the

original style circuit breakers. This was confirmed by the inspectors.

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

.

t

6

25

i

The licensee stated that the method by which a craftsperson or

technician set up a new breaker was not explicitly covered in any

procedure nor was it covered in any required training.

The inspectors reviewed Electrical Maintenance Procedure 0 EPM 0304 01.

Testing Non Containment Isolation 480 V Breaker Assemblies, Revision 18.

The inspectors noted that both the thermal and magnetic elements were

tested. The magnetic element was checked to carry 70 percent of the set

point value and trip at 125 to 140 percent of the set point value.

,

The inspectors examined six safety melated in service circuit breakers,

four original style and two newer style. The examination confirmed that

the thermal element set point matched the one-line diagram. The

magnetic element set points were recorded from the nameplate for the

original style and from the setting dial for the newer style. The

inspectors concluded that the set points for the magnetic element of the

newer style breakers matched what would have been the fixed setting on

the original style breaker having that thermal set point. The

inspectors also compared the set points to the motor full load current

] and locked rotor current of the respective loads, and concluded that the

4

set points were correct. The circuit breakers inspected were:

Comoartment No. Load Breaker Style

2H1 2N-J3 MOV-2890C original

2H12N B3 2 CV-P 03A original

2H12N A4 2-HC-F-01 original

2H1 25 C1 MOV-2720A original

2H1-2S C3 2 RS P 3A newer

2H1-2S K4 2 HV F 40A newer

c. Conclusions

The licensee's test procedure for the molded case circuit breakers was

good, in that, it checked that the magnetic element tripped within a

specified band around the set point. The controls for establishing and

verifying the set point for the magnetic element were minimal. There

was no set point document, drawing or specific instructions to help

ensure proper set mints were maintained. Based on a sample of two

newer circuit brea(ers, the licensee's informal method resulted in

correct settings. Nevertheless, the lack of formal controls on the set

point for the magnetic element of molded case circuit breakers was a

weakness in the licensee's design control program, in that, the

continued use of the informal method has increased the probability to

result in incorrect set points. Whether the lack of formal controls

represents a violation of NRC requirements in the area of design control

or procedures is under further review by the NRC. The issue is

identified as Unresolved Item (50 338, 339/96012 07).

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

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

~  !

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4

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26

!

] E7 Quality Assurance in Engineering Activities l

E7.1 Safety Committees j

a. Insoection Scope (37550) l

i

'

The inspectors reviewed the functioning of the two safety and oversight

committees.

,

!

,

b. Observations and Findinas

i

The inspectors reviewed some of the minutes of past meetings for the two

safety and oversight committees and attended meetings of both of these  ;

committees. During the meeting of the Station Nuclear Safety and 1

2

Operating Committee, the inspectors observed the review and a> proval of

a temporary modification (required 10 CFR 50.59 screening), t1e ap3roval )

of a special report on SW/ ground water levels, the approval of eig1t ,

l procedure changes, and a change to a curve for nuclear fuel burnup rate. '

'

A review was made of the last three MSRC meeting minutes, and it was l

4 noted by the inspectors that the committee was performing the functions

delineated in the committee's procedures. This committee is the  !

off-site oversight review committee. The inspectors attended a part of

l the meeting held at the North Anna Station on November 20. 1996. Three 1

root cause evaluations (two involving unit trips) and various

i improvement initiatives for North Anna were discussed. The items were ,

well presented and resulted in lively and productive discussions.

{

c. Conclusions l

The safety and oversight committees were conducting their duties in an

efficient and productive manner.

E7.2 Enaineerina Self-Assessment

a. Inspection Scooe (40500)

A review of the licensee's engineering self assessment 3rogram was

conducted by the inspectors to see if strengths and wea(nesses were

identified and if corrective actions were initiated for the weaknesses.

b. Observations and Findinas

The ins)ectors reviewed the procedure for engineering self assessments,

NASES (iorth Anna Station Engineering Services) 1.12. Controlling

Procedure for Engineering Self Assessment, Revision 0. Site Engineering i

Services performs a wide variety of services and the procedure is  !

intended as a guideline only. The Engineering Review Board is

responsible for controlling the scope of the proposed self assessments.

Since this program was recently implemented, very few self assessments

were completed. The inspectors reviewed two partially completed j

!

I

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

. _ _ . _ _-.

.

.

27

4

assessments, one on System Engineering and one on Post Maintenance

Testing. The inspectors noted during the MSRC meeting that the Nuclear

Oversight Group had identified that an upper tier document which

addresses self-assessment (PAP 0104) was under modification because it

did not spell out management's expectations for self assessments.

. c. Conclusions

The engineering self assessment program was only recently defined, and

very few self assessments were completed.

'

E8 Miscellaneous Engineering Issues (92903)

.

E8.1 (Closed) URI 50-339/96009 03, review anomalies in large bore snubber

test data. The inspectors completed their review of large bore snubber

functional test data. No other anomalies were identified. Snubbers

i with anomalies in test data were either repaired, replaced or

subsequently satisfactorily tested.

The licensee plans to procure replacement large bore snubbers from a

different vendor prior to the next refueling outage, i.e., the Unit 1 1

,

refueling outage scheduled to begin in May 1997. Testing of the new I

i

snubbers will use different test equipment and test techniques. An

Inspection Followup Item is opened to review functional tests that will i

!

be conducted on either new or old snubbers in the upcoming Unit 1 ,

refueling outage (50 338, 339/96012 08). l

i

(

IV. Plant Support '

'

R1 Radiological Protection and Chemistry (RP&C) Controls

R1.1 As low As Reasonably Achievable (ALARA) j

a. Inspection Scope (83750)

The inspectors reviewed licensee records of personnel radiation exposure

and discussed ALARA program details, implementation and goals with the

1

licensee. The site collective dose and individual exposures were

compared to licensee established ALARA goals and occupational dose

limits, respectively.

b. Observations and Findinas

The licensee provided the inspectors with reports of personnel radiation

exposure for calendar year (CY) 1995 and the first three quarters of

. 1996. Those reports indicated that the licensee had initially

established an ALARA goal of 459 person roentgen equivalent man (rem)

for the 1995 site collective dose. That goal included a projected 425

2 person rem for the Unit 2 SG Replacement Project and related outage

,

activities. After the actual exposure for that outage was determined to

have been 340 person rem, the annual goal was reduced from the initial

_ _.

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

.

.

28

goal of 459 person rem to 367 3erson rem. The final collective dose for

CY 1995 was 359 person rem. T1e annual goal for the 1996 site

collective dose was established at 364 person rem. That goal included a

projected 188 person rem for the Unit 1 Refueling Outage (RF0) and 149

person rem for the Unit 2 RF0. The actual ex>osures for those outages

were 184 and 117 person rem, respectively. T1e actual exposure during

the first three quarters of 1996 was 305 )erson rem. The licensee

indicated that, given the current work scledule for the remainder of the j

1

year, the 1996 annual goal was not expected to be exceeded. The

inspectors determined that the licensee was meeting their established

ALARA goals. The licensee's personnel radiation exposure records also

indicated that the maximum individual exposures for 1995 and the first

three quarters of 1996 were less than 2.6 rem and within the limits

specified in 10 CFR 20.1201(a). >

c. Conclusions

i

Based on the above reviews and observations, the inspectors concluded

that the licensee was closely monitoring collective and individual

radiation dose exposure, and that the licensee was meeting established

ALARA goals and occupational dose limits. ,

R1.2 Water Chemistry Controls

a. Inspection ScoDe (84750)

The inspectors reviewed implementation of selected elements of the

licensee's water chemistry control program for monitoring primary and

secondary water quality. The review included examination of program

guidance and implementing procedures, and analytical results for

selected chemistry parameters. Those procedures and data were compared

to specific ard programmatic requirements, i.e., the TSs required the

licensee to monitor primary coolant for specific chemistry aarameters

and to implement a program for monitoring secondary water clemistry to

inhibit steam generator tube degradation.

b. Observations and Findinas

The inspectors reviewed VPAP 2201 Nuclear Plant Chemistry Program,

Revision 1, and determined that it included provisions for sampling and

analyzing reactor coolant at the prescribed frequency for the parameters

required to be monitored by the TSs. That procedure also included

provisions for monitoring primary and secondary water quality based on

established industry guidelines and standards. Although the licensee's

procedure did not s)ecifically indicate that their program included

implementation of t1e Electric Power Research Institute (EPRI)

guidelines for Pressurized Water Reactor (PWR) primary and secondary

water chemistry, the inspectors used those guides as references for

evaluating the effectiveness of the licensee's program. The inspectors

noted that VPAP 2201 listed the sampling frequency and typical values

for each parameter to be monitored. Action levels applicable to various

operational modes were given where appropriate. Guidance was also

.

.

29

provided for actions to be taken if analytical results exceeded

prescribed limits. The inspectors determined that the above guidance

and procedures were consistent with the applicable TS requirements and

EPRI guidelines.

The inspectors also reviewed trend plots and records of analytical

results for selected parameters generated during the period April i

through October 1996. The parameters selected included dissolved l

oxygen, chloride, fluoride, sulfate, and dose equivalent iodine-131 in l

reactor coolant and dissolved oxygen, iron, copper, sodium, hydrazine, j

silica, and sulfate in secondary systems. Those parameters were

maintained well within the relevant TS limits and within the EPRI

guidelines for power operations.

c. Conclusions i

Based on the above reviews, the inspectors concluded that the licensee's

water chemistry control program for monitoring primary and secondary

water quality had been implemented in accordance with the TS

requirements and the EPRI guidelines for PWR water chemistry.

R1.3 Transoortation of Radioactive Materials

l

a. Insoection Scope (TI 2515/133) '

The inspectors evaluated the licensee's transportation of radioactive

materials programs for implementing the revised Department of

Transportation and NRC transportation regulations for shipment of

radioactive materials as required by 10 CFR 71.5 and 49 CFR Parts 170

through 179.

b. Observations and Findinos

1

The inspectors reviewed the licensee's actions regarding a shipment of

licensed material which exceeded the limit for specific activity

delineated in the Certificate of Compliance (CoC) for the cask used to

transport the material. On October 31, 1996, the licensee's radioactive

waste shipping personnel were reviewing shipping records and found that

the most recent revision of the CoC for the shipping cask had not been

properly filed in the cask's reference notebook. The licensee maintains

a cask reference notebook for each NRC licensed cask used by the

facility and licensee 3ersonnel use those notebooks when preparing

radioactive material slipments. On April 16, 1996. CoC No. 6601,

Revision 25, for the Model No. CNS 8 120A package was issued by the NRC

Office of Nuclear Material Safety and Safeguards, and was received at

the site on or about May 6, 1996. Further review of shipping records by

the licensee on November 5,1996, revealed that on July 9,1996, the

cask was used for a shipment (No. 96 05) of radioactive waste to the

Chem-Nuclear waste disposal site at Barnwell, SC. 10 CFR 71.12(c)(2)

authorizes any licensee to trans) ort licensed material in a package for

which a CoC has been issued by tie NRC, provided that the licensee

complies with the terms and conditions of the CoC. Condition 5

- - - ~. - - . - - - - . ._ -. . - . - - .

.

.

30

(b)(1)(1) of CoC No. 6601 specifies that the average concentration of

the package contents shall not exceed 0.3 millicurie per gram of

radionuclides for which the A2 quantity in A)pendix A of 10 CFR Part 71

is more than 1 curie. Contrary to that concition, the average

'

concentration of radionuclides for which the A2 quantity in Appendix A

of 10 CFR Part 71 is more than 1 curie for the package contents of

Shipment No 96-05 was 0.495 millicurie per gram. On November 6, 1996,

the licensee called the NRC Region II Office to report the violation of

10 CFR 71.12(c)(2) and indicated that shipments of radioactive waste for

disposal had been immediately suspended and that an investigation had

been initiated. During this inspection the licensee's report

documenting that investigation was reviewed by the inspectors. That

report indicated that the root cause of the violation was poor document

control of the CoC. Other contributing factors identified by the

investigation were incomplete procedural checklist guidance for

preparing and inspecting shipments, and incomplete guidance for

a) plication of the software used as an aid in shipping preparations.

T1e report also included recommendations for corrective actions to

prevent recurrence of this event. Those recommendations were:

delineating the CoC requirements in the cask shipping checklists used by

the personnel who prepare the casks for shipment and in the checklists

used by Quality Assurance / Quality Control personnel who inspect the

shipments; filing the CoCs in their proper location in the cask

reference notebooks immediately upon receipt; and establishing a

required reading program and signoff system for revised shipping

3rocedures. The licensee indicated that those corrective actions would

>e implemented prior to the resumption of radioactive uste shipments

planned for December 6, 1996. This licensee identified violation for

failure to comply with the conditions of the Certificate of Compliance

for an NRC approved shipping package is being treated as an NCV.

consistent with Section VII.B.1 of the Enforcement Policy (50 338,

339/96012-09).

c. Conclusions

Based on the above reviews, the inspectors determined that the

licensee's efforts in identifying and initiating corrective actions for

the violation were adequate. One NCV was identified by the licensee for

failure to comply with the conditions of the CoC for an NRC-approved

shipping package.

R8 Miscellaneous RC&P Issues (92904)

R8.1 (Closed) Violation 50 338, 339/96007-04, failure to label a container of

licensed material. During a previous inspection, the inspectors

observed a trailer in the outside protected area which contained

contaminated scaffolding but did not bear a completed radioactive

material label. The licensee's response to the violation indicated that

the container was relabeled properly, that other containers were

ins)ected to ensure proper labeling, and that this event was discussed

witi Health Physics (HP) personnel during departmental meetings and

subsequent training sessions. During this inspection no further

1

.

.

31

examples of improper container labeling were observed by the inspectors.

Licensee records of attendance and discussion topics for the referenced

departmental meetings and training sessions were also reviewed by the

inspectors. The inspectors concluded that the licensee's response dated

October 8, 1996, and the corrective actions were appropriate and had

been adequately implemented.

R8.2 (Closed) Violation 50 338, 339/96007 05, failure to follow procedures

for minimizing the potential spread of radioactivity to unrestricted

areas. During a previous inspection it was determined that a individual

was released from the protected area with clothing which exceeded the

licensee's procedural release limit for radioactive contamination. The

licensee's response to the violation indicated that the contaminated

clothing had been retrieved, that HP procedures had been revised to

provide additional guidance to HP personnel for dealing with personnel  !

that alarm portal or personal contamination monitors, and that HP

personnel were trained in those procedural changes. During this

inspection the licensee's revised HP procedures were reviewed and found

to include specific guidance for responding to alarms by portal and

personal contamination monitors. The inspectors also reviewed the

licensee's records for training on those procedure changes. The

inspectors concluded that the licensee's response dated October 8,1996,

and the corrective actions were appropriate and had been adequately

impirmented.

S1 Conduct of Security and Safeguards Activities (71750)

On November ll, the inspectors toured various plant security systems I

with a security team leader. Specifically, selected protection area

perimeter fencing and isolation zones, Central and Secondary Alarm l

Stations, various vital area accesses, and the secondary power supply l

were inspected. The inspectors observed that the protected area j

perimeter fencing was in good condition with no o)enings. Isolation  :

zones were free of objects and clearly marked. T1e inspectors observed l

'

that the Central and Secondary Alarm Stations were properly manned and

that intrusion systems were functioning properly. Various vital area

accesses and boundaries were inspected and found to be in good working

order. The inspectors concluded that security systems were in good

working order and security manning was appropriate.

VI. Manaoement Meetinas

X1 Exit Meeting Summary

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

management at t1e conclusion of the inspection on December 20, 1996. The l

licensee acknowledged the findings presented.

i

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

4

J .

.

1  :

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32

i The inspectors asked the licensee whether any materials examined during the  !

i inspection should be considered proprietary. No proprietary information was  :

-

identified.

.

!

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

.

!*

33

PARTIAL LIST OF PERSONS CONTACTED

Licensee

W. Anthes, Superintendent, Outage and Planning

'

B. Foster, Superintendent Station Engineering

,

~

E. Grecheck, Assistant Station Manager, Operations and Maintenance

J. Hayes, Superintendent, Operations

D. Heacock, Assistant Station Manager, Nuclear Safety and Licensing

M. Kansler, Vice President, Nuclear Operations

,

P. Kemp, Supervisor, Licensing

i

T. Maddy, Superintendent, Security

W. Matthews, Station Manager

M. McCarthy, Director, Nuclear Oversight

D. Roberts, Supervisor, Station Nuclear Safety  !

H. Royal, Superintendent, Nuclear Training  !

D. Schappell, Superintendent, Site Services l

R. Shears, Superintendent, Maintenance

A. Stafford, Superintendent, Radiological Protection

NRC

I

B. Buckley, Project Manager '

F. Reinhart, Acting Project Director

INSPECTION PROCEDURES USED

IP 37550: Engineering  ;

IP 37551: Onsite Engineering

IP 40500: Effectiveness of Licensing Controls in Identifying, Resolving, and

Preventing Problems

IP 62707: Maintenance Observations '

IP 71707: Plant Operations

IP 71714: Cold Weather Preparations

IP 71750: Plant Support Activities

IP 83750: Occupational Radiation Exposure  !

IP 84750: Radioactive Waste Treatment, and Effluent and Environmental

Monitoring

IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power

Reactor Facilities

IP 92901: Followup Plant Operations

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

.

l

34

IP 92902: Followup - Maintenance

IP 92903: Followup - Engineering

IP 92904: Followup Plant Support

IP 93702: Prompt Onsite Response to Events at Operating Power Reactors

TI 2515/133: Implementation of Revised 49 CFR Parts 100 179 and 10 CFR Part

71

ITEMS OPENED AND CLOSED

Opened

50-339/96012 01 VIO Failure to Meet 10 CFR 50 Appendix B

Criterion III Recuirements for Design Control of

Safeguards Area kalls (Section 08.1)

50 338, 339/96012-02 NCV Inadequate Surveillance Test Procedure for i

Placing Reactor Trip Breakers in Service '

(Section M8.3) j

50-339/96012-03 VIO Inadequate Design Controls Contribute to

Non Conforming Bolts in Column Flange for

Service Water Pump 2-SW P 1A (Section El.1)

50-338, 339/96012 04 NCV Improper Deletion of DHR Isolation Valve  !

Inservice Testing (Section E1.3)

50-338, 339/96012 05 IFI Battery Service Test and Rating of Diesel

Generator Breaker Close Coil (Section E2.6)

50 338, 339/96012-06 VIO Component Cooling Surge Tank 1 CC-TK 1 Support

Structure not Installed Per Drawings

(Section E3.1)

1

50 338, 339/96012-07 URI Control of Set Points for Molded-Case Circuit

Breakers (Section E3.2)

50 338, 339/96012 08 IFI Review Functional Tests That Will Be Conducted

On New or Old Snubbers During Unit 1 Refueling

Outage (Section E8.1)

50 338, 339/96012 09 NCV Failure to Comply With Conditions of CoC for NRC

Approved Shipping Package (Section R1.3)

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35

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Closed

50 338/95015 01 VIO Failure To Follow Procedures For Properly

Controlling Safeguards Area Ventilation System

(SAVS) Maintenance (Section M8.1)

50 339/95020 02 VIO Failure to Comply With 3.6.1.3 for Air Lock

Outer Door Rendered Inoperable by Open Test

Connection (Section M8.2)

50 339/96001 LER Potential Unfiltered Release Path From the

Quench Spray Pump House to the Environment

(Section 08.1) -

50-339/96003 LER Automatic Reactor Trip Resulting From Main

Generator Stator Coil Failure Due to Personnel

Error (Section M8.5)

50 339/96004 01 URI Review Significance of Safeguard Area

Ventilation Not Meeting Design Basis

(Section 08.1)

50 338, 339/96007-04 VIO Failure to Label a Container of Licensed

Material (Section R8.1)

50 338, 339/96007-05 VIO Failure to Follow Procedures for Minimizing the

Potential Spread of Radioactivity to 1

'

Unrestricted Areas (Section R8.2)

50 338, 339/96009 LER Reactor Trip Bypass Breaker Missed Surveillance

Due to Inadequate Surveillance Test Procedure

(Section M8.3) l

50 339/96009 03 URI Review Anomalies in Large Bore Snubber Test Data

(Section E8.1) i

50 338/96010 LER Automatic Reactor Trip Due to Failure of a

Generator Negative Phase Sequence Relay

'

(Section M8.4)

50 338, 339/96012 02 NCV Inadequate Surveillance Test Procedure for 1

Placing Reactor Trip Breakers in Service

(Section M8.3)

50 338, 339/96012 04 NCV Improper Deletion of DHR Isolation Valve

Inservice Testing (Section E1.3)

50 338, 339/96012 09 NCV Failure to Comply With Conditions of CoC for NRC

Approved Shipping Package (Section R1.3)