ML20059B288

Insp Repts 50-338/93-27 & 50-339/93-27 on 931017-1120. Violations Noted.Major Areas Inspected:Plant Status, Operational Safety Verification,Maintenance Observation & Surveillance Observation

ML20059B288
Person / Time
Site:	North Anna
Issue date:	12/14/1993
From:	Belisle G, Mcwhorter R, Taylor D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML20059B264	List: ML20059B260 ML20059B275 ML20059B288
References
50-338-93-27, 50-339-93-27, NUDOCS 9401040071
Download: ML20059B288 (14)

See also: IR 05000338/1993027

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UNITED STATES

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NUCLEAR REGULATORY COMMISSION

REGloN 11

g 101 MARIETTA STREET, N.W., SUITE 2300

7, ;j ATLANTA, GEORGIA 3032M199

\, +..../

Report Nos.: 50-338/93-27 and 50-339/93-27

Licensee: Virginia Electric & Power Company

5000 Dominion Boulevard

Glen Allen, VA 23060

Docket Nos.: 50-338 and 50-339

License Nos.: NPF-4 and NPF-7

Facility Name: North Anna 1 and 2

Inspection Conducted: October 17 - November 20, 1993

Inspectors: #itt ) sS%% Gu /2 - / y- P 3

R. D. McWhorter, Senior Resident Inspector Date Signed

J- tv 2L n /L / L-fy- 73

D. R. Taylor, Resident Inspector Date Signed

Approved by: / /

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D. . .c K lLf/ '// h

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G. A. 'Belisle, Sebthn Chief Date Signed

Division of Reactor Projectc

SUMMARY

Scope:

This routine resident inspection was conducted on site in the areas of plant

status, operational safety verification, maintenance observation, surveillance

cbservation, engineered safety feature system walkdown, licensee event report

followup, and action on previous inspection items. Inspections of licensee

backshift activities were conducted on October 17, 23 and 26, and November 5,

8 and 18, 1993.

Results:

Doerations functional area

A violation was identified for a failure to correctly implement a periodic

test procedure which led to disabling Emergency Diesel Generator 2H for

approximately six hours (paragraph 3.c).

Removing and storing the loose fuel material identified during the Unit 2

refueling outage was well planned and controlled (paragraph 3.d).

9401040071 931214

PDR ADDCK 05000338

G PDR

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Enaineerina functional area

An-Inspector follow-up Item was identified concerning the determination of a

proper venting interval to ensure that the Low Head Safety Injection system

initiates without excessive pressure surges (paragraph 8.a).

On November 8, as a result of continued evaluations into the cause of High

Head Safety Injection flow balance test problems, all charging pumps were

determined to be inoperable (paragraph 5.a). Enforcement discretion was

granted to allow the licensee 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for corrective action.

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REPORT DETAILS

1. Persons Contacted

Licensee Employees

L. Edmonds, Superintendent, Nuclear Training r

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R. Enfinger, Assistant Station Manager, Operations and Maintenance '

G. Gordon, Acting Superintendent, Maintenance

J. Hayes, Superintendent of Operations

D. Heacock, Superintendent, Station Engineering '

• G. Kane, Station Manager

• P. Kemp, Supervisor, Licensing ,

• W. Matthews, Acting Assistant Station Manager, Operations and  ;

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Maintenance

J. O'Hanlon, Vice President, Nuclear Operations

D. Roberts, Supervisor, Station Nuclear Safety

R. Saunders, Assistant Vice President, Nuclear Operations

D. Schappell, Superintendent, Site Services

R. Shears, Superintendent, Outage and Planning

• J. Smith, Manager, Quality Assurance

A. Stafford, Superintendent, Radiological Protection

J. Stall, Assistant Station Manager, Nuclear Safety and Licensing

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Other licensee employees contacted included engineers, technicians,

operators, mechanics, security force members, and office personnel.

NRC Personnel (

• R. McWhorter, Senior Resident Inspector

• D. Taylor, Resident Inspector ,

• Attended exit interview

Acronyms and initialisms used throughout this report are listed in the

last paragraph.

2. Plant Status

Unit 1 operated the entire inspection period at or near 100% power.  :

Unit 2 began the inspection period in MODE 5 recovering from a refueling  !

outage. On October 24, the unit entered MODE 4, followed by MODE 3 i

entry on October 25. A reactor startup was performed following MODE 2

entry on October 26. The unit entered MODE 1 on October 27, reaching ..

approximately 100% power on October 31. The unit continued at or near -

100% power for the remainder of the inspection period.  :

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3. Operational Safety Verification (71707)

The inspectors conducted frequent control room tours to verify proper _ '!

staffing, operator attentiveness, and adherence to approved-procedures. *

The. inspectors attended daily plant status meetings to maintain

awareness of overall facility operations and reviewed operator logs to j

verify operational safety and compliance with TS. Instrumentation and t

safety system lineups were periodically reviewed from control room

indications to assess operability. Frequent plant tours were conducted  :

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to observe equipment status, fire protection program implementation,.

radiological work practices, plant security, and housekeeping. DRs were

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reviewed to assure that potential safety concerns were properly reported-  ;

and resolved.  :

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a. Outage Commitments .

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The inspectors reviewed several licensee outage commitments to

ascertain that actions were completed. The inspectors verified- I

the outage commitment status by reviewing documentation, direct- )

inspection of selected plant areas, and discussions with cognizant

licensee personnel. Activities reviewed by inspectors included: ,

- Testing of manual SI input to reactor trip circuits

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Inspection of FW rupture restraints _

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- Ultrasonic inspection of Unit 2 ASME XI piping as a result

of a temporary non-code repair on Unit 1 .

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Inspection of Unit 2 containment personnel hatch 1

- Fire barrier penetration inspection and repairs.  !

- ISI exam on 2-SI-153 bolting l

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Seismic . qualification walkdowns.  ;

The inspectors noted that outage commitments were accurately- <

tracked and reported to station management on a weekly basis. .i

Based on the licensee successfully completing the above i

activities, the inspectors concluded that outage commitments made  ;

to the NRC were being fulfilled.  ;

b. ' Unit 2 Startup J

On October 26, 1993, the inspectors observed a reactor and turbine j

ctartup per 2-0P-1.5', Unit Startup from MODE 3 to MODE 2, revision

39; 2-0P-2.1, Unit Startup from MODE 2 to MODE 1,irevision 50; and: 1

2-0P-15.1, Operation of the Main Turbine, revision 24. The j

startup was performed with very few equipment problems and was - t

well controlled by the' operators. .One example of. an equipment j

problem occurred when during the-rod pull sequence, Bank C Rod- ,

H-100-failed to move. In response, the CR0 fully-inserted bank C J

as required by procedure 2-0P-1.5. Subsequent troubleshooting- l

identified the problem to be a blown. fuse. After the fuse was

replaced, the startup proceeded and no further problems were 1

observed. The inspectors noted extensive management oversight for ,

the reactor startup and placing the unit on line.  ;

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c. Emergency Diesel Generator 2H Inoperability

On October 29, 1993, at 07:55 a.m., the Supervisor of Shift

Operations identified that the control switch for the EDG output

breaker, breaker number 25H2, was in the " pull-to-lock" position.

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With the switch in this position, EDG 2H was prevented from

automatically loading onto its emergency bus. The condition was

immediately corrected by placing the switch in the neutral

position. Subsequent reviews by the licensee indicated that the

switch was incorrectly put in the " pull-to-lock" position earlier

that morning by an operator while performing 2-PT-82H, 2H

Emergency Diesel Generator Slow Start Test, revision 14. The

procedure required the operator to open breaker 25H2. The

operator put the breaker switch in " pull-to-lock," which was not

called for by the procedure. This failure to properly follow

procedure 2-PT-82H by incorrectly positioning the control switch

for breaker 25H2 is identified as Violation 50-339/93-27-01:

Failure to Follow Procedure 2-PT-82H.

The inspectors reviewed the SR0 and CR0 logs to verify compliance

with TS action statement time limits and to identify if opposite

train equipment was out-of-servi _e. The.EDG was taken out of

service at 9:28 p.m., on October 28, while performing 2-PT-82H.

At 1:20 a.m., on October 29, following the apparent successful

completion of the PT, the EDG was declared operable. At 7:55

a.m., the error was discovered and the switch was placed in

neutral. The total time the EDG was inoperable was approximately

6.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The inspectors determined that no opposite train

equipment was out of service during this period of EDG 1

inoperability; consequently, TS action statement time limits were l

met.

The inspectors reviewed compliance with TS action statement

3.8.1.i.b. The action statement allows one EDG to be out of

service for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided that the operability of the AC

off-site power sources be demonstrated by performing surveillance

requirement 4.8.1.1.1.a within one hour and at least once per 8 )

hours thereafter. The inspectors concluded that the 72-hour time l

limit had not been exceeded,-but questioned the completion of the l

associated surveillance requirement. A review of logs indicated ,

that the licensee used 2-PT-80, AC Sources Operability l

Verification, revision 8, to meet the surveillance requirement at

9:28 p.m., and again at 8:30 a.m. Although 2-PT-80 was not

formally completed, the licensee stated that operator observations

and logs verified that equivalent actions were taken at least once

during the period between 1:00 a.m. and 2:00 a.m. The inspectors i

reviewed the licensee's findings and found that the equivalent

actions had been documented to meet the 8-hour TS surveillance .

requirement.

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The inspectors evaluated the potential impact on plant safety for

this event, since the EDG was prevented from automatically

performing its safety function. The inspectors concluded that the

safety significance of the event was minor because no opposite

train equipment was inoperable, and the amount of time the EDG was

in this condition was minimal. In addition, the E0Ps require the

operators to check EDG operations early during a transient, which

would allow for the quick detection and correction of this

condition.

It was also noted that the improper switch position should have '

been identified during walkdowns for the 7:00 a.m. shift turnover.

As a result, the licensee modified the shift turnover checklist to

add the switch to formal turnover checks. The inspectors noted

that good oversight by plant supervision was responsible for the

prompt discovery of the condition.

It was found

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The inspectors also reviewed 2-PT-82H for adequacy.

that after unloading the EDG, step 6.4.5 required the operator to

"Open breaker 25H2." It was while performing this step that the

operator put the breaker handswitch in the " pull-to-lock"

position. The inspectors noted the switch did not have an "open"

position, but rather had: " pull-to-lock," " trip," neutral ~

(unlabeled) and "close." The licensee's corrective actions

included proceduni changes to clarify the desired breaker

position. Additionally, the inspectors noted that the procedure

did not contain incependent verification requirements for control

room switch alignments following the test. Concern was expressed

to the licensee about the lack of independent verifications in the

procedure. The licensee's investigations revealed that procedure

writers did not routinely place independent verification

requirements in procedures for switches which spring return to the

desired position. The licensee informed the inspectors that, as'a

result of the incident, they were commencing a procedure review to

identify similar steps and add verification requirements where

appropriate.

d. Removal of Fuel Pellets from Transfer Canal  ;

On Nc; ember 18, 1993, the inspectors reviewed the licensee's ,

actions for the recovering fuel material from the Unit 2 transfer i

canal. The material was found while moving fuel during the fall

1993 refueling outage. The inspectors observed the pre-job brief

and reviewed the videotaped results of the recovery and

radiological surveys. The recovery was performed using temporary

procedure 0-T0P-4.26, Removal of Y-48 Debris From the Unit 2 -

Transfer Canal in the fuel Building, revision 0. The procedure, '

radiological requirements, and precautions were thoroughly

reviewed during the pre-job brief. The procedure involved using a  :

heavy bristle brush attached to a pole to sweep the fuel into a

stainless steel debris container. The container was then placed

into an unusable fuel storage location. The procedure also-

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required practice runs in the new fuel storage area and in the

Unit I transfer canal. Overall, the inspectors considered the

recovery process well planned and concluded that the licensee's

actions had oeen successful in safely storing the loose material

in the spent fuel pool.

e. Licensee NRC Notifications ,

(1) On November 2, 1993, the licensee informed the NRC, as

required by 10 CFR 50.72, concerning notifying off-site

authorities. Specifically, the licensee notified the

Commonwealth of Virginia of chromate discharges into Lake

Anna from a CCW leak. The inspectors reviewed this

notification and verified that there was no regulatory

concern associated with the event.

(2) On November 9, 1993, the licensee informed the NRC, as

required by.10 CFR 50.72, concerning notifying off-site

authorities. Specifically, the licensee notified the

Federal Energy Regulatory Commission of a Lake Anna Dam

emergency diesel generator failure. The inspectors reviewed ,

this notification and verified that there was no regulatory

concern associated with the event.

(3) On November 17, 1993, the licensee informed the NRC, as

required by 10 CFR 50.72, concerning notifying off-site

authorities. Specifically, the licensee notified the

Commonwealth of Virginia of the transport off-site of a

non-contaminated individual requiring medical attention.

The inspectors reviewed this notification and verified that

there was no regulatory concern associated with the event.

One violation was identified.

4. Maintenance Observation (62703)

Station maintenance activities were observed and reviewed to verify that

the activities were conducted in accordance with TS, procedures,

regulatory guides, and industry codes or standards.

a. Leak Sealant Repair ,

On November 1,1993, the inspectors observed leak sealant repair

on the pivot pin bearing cap to valve 2-FW-62, the main feedwater

to A SG inlet check valve, which also serves as a containment

isolation valve. The mechanical joint developed a 3 gpm estimated

leak during power ascen:, ion. The on-line leak repair was

performed using WO 274747 and procedure 0-MCM-1904-01, On-Line

Repair Using Contractor Leak Sealant Methods, revision 0. The

procedure was issued October 22, 1993, and replaced three )

procedures previously used for leak sealant repairs.

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The SNSOC-approved procedure provided 19 methods for leak repair

which were dependent on the specific application.

The inspectors observed the leak repair from the MSVH and reviewed

the completed work package. The inspector noted that although not

required by procedure, SNSOC requested the work package be

presented for review prior to injection of the valve. The valve

was injected using section 6.7, New Injection of a Flange With

Clamp. The inspectors judged that the maintenance was well

controlled with sufficient management oversight.

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No violations or deviations were identified. l

5. Surveillance Observation (61726)

Station surveillance testing activities were observed and reviewed to

verify that testing was performed in accordance with procedures, test

instrumentation was calibrated, LCOs were met, and any deficiencies -

identified were properly reviewed and resolved.

a. HHSI Flow Balance Test .

Near the end of the previous inspection period, the inspectors

observed licensee personnel performing 2-PT-138.1, HHSI Flow

Balance, revision 1-P2. The. purpose of the test was to verify

that ECCS flow met TS 4.5.2.h requirements. During the initial

run for the cold leg verification, branch line flows did not meet

TS requirements. This failure was the subject of NRC Inspection

Report Nos. 50-338, 339/93-28.  ;

Inspectors monitored the licensee's corrective actions on this

issue in preparation for Unit 2 entry into MODE 4. The inspectors

met with system engineers on October 18 to discuss probable causes

for the repeated problems in HHSI flow balances. The valves which

control HHSI flow (2-SI-89, -97, and -103) were identified to be

Rockwell-Edwards " univalves," which were the subject of NRC

IN 84-48 (with Supplement 1). The IN detailed problems with

valves similar to this design in the areas of stem breakage and r

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disc separation. As a result of these issues, the licensee

performed radiographs of all three valves on October 20. The

radiographs revealed that the internal components of the valves

appeared to be intact.

On October 21, 1993, a conference call was held between the

licensee and the NRC to discuss the HHSI test failure. The

licensee stated that the most probable cause for test failure

continued to be valve stem movement. In addition to actions taken

in the past to prevent valve movement, the licensee installed a

thread locking compound on the valve stem to prevent movement due

to vibration or other means. The licensee also presented safety

analysis results for out-of-specification HHSI flow balances. The

resuits demonstrated that the margin to exceeding transient PCT-

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limits was adequate for flow imbalances up to 30..gpm below the TS

limit. The largest flow imbalance measured was approximately 3

gpm below the TS limit.

On November 8, 1993, continued licensee's investigations into the

cause for the HHSI test failure identified that the "Controlotron"

flow instruments used for the test may have contained excessive

errors. .The licensee performed' extensive testing concerning the-

effects of pipe configuration on the accuracy.of the instruments _ <

and concluded that the. Unit 2 piping arrangements may have led to ,

as much as ten percent error in measured flow. This inaccuracy

was analyzed, and the licensee concluded that performance could be: ,

assured within the system design basis, i

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However, due to the potential measurement errors, the licensee.

could no longer demonstrate that the TS 4.5.2.h requirements'had

been met. As a result, the licensee declared all three HHSI pumps

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inoperable, entered TS 3.0.3 at 2:45 p.m... on November 8, and

requested enforcement discretion. The enforcement discretion-

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requested a 24-hour period from TS 4.5.2.h.1 (readjust. seal water ,

flows to the reactor coolant pumps) and TS 4.5.2.h.1.c (eliminate ,

simulated reactor coolant pump seal injection flow requirement).  !

A telephone conference call was held between the NRC _and the -

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licensee, and the licensee's request _was granted based on the fact  ?

that the licensee's evaluations showed that the . system could carry -

out its design safety functions. The licensee exited TS 3.0.3 at  ;

2:02 p.m., on November 9 which was within the_ enforcement

discretion time: limits. This enforcement discretion is considered

closed. Details of the enforcement. discretion were documented in ,

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the licensee's letter, serial 93-727, dated' November 9, 1993. '

These issues were also discussed between the NRC and-the-licensee '

as a part of the enforcement conference conducted on November 10,

1993, involving actions associated with NRC Inspection Report Nos. i

50-338,339/93-28.  :

b. Reactor _ Protection System Testing

On October 22, 1993, the inspectors observed periodic test- _ l

2-PT-36.1A, Train A Reactor Protection.and ESF Logic Channel- l

Functional Test, revision 9. The test was performed in;  !

preparation for' mode change-from MODE 5 to MODE 4. .The' inspectors  !

observed operability verification of the reactor trip and reactor j

trip bypass breakers from the control room, and observed the logic. j

and permissive' circuitry test at the _ logic test panel in. the - .

emergency switchgear relay room. The test was adequately  ;

controlled and all equipment performed as required.

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No violations or deviations were identified.

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6. Engineered Safety Feature System Walkdown (71710)

The inspectors performed a detailed CVCS system boration flow path

walkdown. The portions of the system selected were those used to meet

TSs 3.1.2.2, 3.1.2.4, 3.1.2.6 and 3.1.2.8 requirements. The inspectors

compared system alignments with drawings and procedures 1-PT-13.3 and

2-PT-13.3, Boration Flow Path Verification, revisions 15 and 7,

respectively. Additionally, general system material condition and

housekeeping were observed. The inspectors found that the system

appeared to be in good material condition. System components were found

to be in the proper lineup. Only minor housekeeping problems were

identified. The licensee corrected these minor problems. Overall,

inspectors judged radiological conditions in-the cramped area around

system valves to be good. However, it was noted that the posting for

one radioactively contaminated area boundary was vague. The posting was

promptly enhanced by the licensee. The inspectors concluded that the

system met TS requirements and was properly aligned and maintained.

No violations or deviations were identified.

7. Licensee Event Report Followup (92700) ,

The following LERs were reviewed and closed. The inspectors verified

that reporting requirements had been met, causes had been identified,

corrective actions appeared appropriate, and generic applicability had l

been considered,

a. (Closed) LER 50-338/91-19: Inadequate Procedure Causes an

Improper LHSI Relief Valve Blowdown Ring Setting Resulting in

Operability Issues

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This LER was issued as a result of a LHSI relief valve which

opened during a pump start and failed to reseat. The relief valve

failure consequences were reviewed and documented in paragraph 8.a

of this report.

(Closed) LER 50-339/92-10: Cold Leg Safety Injection Branch Line

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Flow Below Technical Specification Requirements

This LER concerned the licensee's failure to meet TS requirements

for HHSI flow balance and was related to Violation 50-339/92-10-04

discussed in paragraph 8 b. The inspectors reviewed the LER and

verified that licensee's corrective actions had been implemented.

After recurrence of this problem, this issue was addressed by

actions related to NRC Inspection Report Nos. 50-338, 339/93-28.

8. Action on Previous Inspection Items (92701, 92702) i

The following previous inspection items were reviewed and closed:

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a. (Closed) URI 50-338/91-22-02: LHSI Relief Valve Inoperability '

Safety Consequences

This URI concerned evaluating the safety consequences.for an event ,

where the LHSI relief valve lifted and failed to reseat. The  :

inspectors reviewed this issue to verify that the LHSI relief

valve failure could not. result in off-site and on-site

radiological consequences . exceeding regulatory limits. The ,

inspectors requested information regarding the dose. calculations 6

documented in LER 50-338/91-19.. Prior to providing the r

information to the inspectors, system engineers reviewed the data -

and identified that the off-site EAB and LPZ doses were incorrect

- (low) by a factor of three. A revision to the-LER was promptly

initiated. The inspectors found that the revised calculations

indicated that "best estimate" doses were well within 10 CFR 100-  :'

and GDC criteria 19 limits. This action resolved the URI.

Separate from the safety consequences issue, the inspectors also

reviewed the history of problems associated with the LHSI due-to  !

pressure surges during pump start operations. . Specifically,

pressure surges caused by inadequate venting have challenged the .

system and resulted in equipment failures. Most recently, NRC

Inspection Report Nos. 50-338,339/93-18, documented the progress

that had been made with suppressing these surges during testing.

This was primarily a result of additional vents which were added

to the system during the most-recent outages. Although progress ,

has been made, the inspectors questioned the adequacy of the_ . ~'

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system response to an actual SI. This was based on the fact that

prior to each test the system was vented.to remove entrained gases l

and suppress pressure surges. The . licensee indicated that as part  !

of long term corrective actions, the interval between venting -  ;

would be determined to assure challenges to the system were

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minimized. The licensee further indicated that recent venting .

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before testing performed on Unit 1. released only small volumes of i

gas. Until the interval between venting is established, this is  ;!'

identified as IFI 50-338,339/93-27-02: Adequacy of LHSI Venting

Interval. ,

b. (Closed) VIO 50-339/92-10-04: Failure to Meet TS Flow

Requirements for ECCS i

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This violation concerned the licensee's failure to meet TS

requirements for HHSI flow. balance and was associated with

LER 50-339/92-10 addressed in paragraph 7.b. The licensee ,

responded to this violation in correspondence dated June 9, 1992..  ;

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This response was acceptable. The inspectors reviewed the l .

violation and verified that licensee's corrective actions had been-

implemented. After recurrence of this problem, this issue was "

addressed'by actions related to NRC Inspection Report Nos. 50-338,

339/93-28.

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c. (Closed) VIO 50-338,339/92-13-02: Failure to Limit Personnel

Working Hours

This violation concerned licensee management's failure to properly

monitor and control overtime which resulted in frequent problems

where personnel exceeded requirements for a maximum of 72 working

hours in a seven day period. The licensee responded to this l

violation in correspondence dated July 8,1992. This response was ,

acceptable. The inspectors routinely monitored licensee

management's efforts to monitor and control overtime during the

Unit 1 SG replacement outage in the spring of 1993 and the Unit 2 .

refueling outage in the fall of 1993. Additionally, inspectors .f

monitored QA assessments in this area. The inspectors found

management's attention to be effective in correcting the problem. -

d. (Closed) IFI 50-339/92-10-02: Loop Stop Valve Failure Due to >

Incorrect Motor Wiring

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This item was opened to follow the licensee's actions for repair

of the valve and to review personnel performance issues. Repairs

to the valve were completed under WO 00260544-03 prior to startup

from the most recent outage. With regards to personnel

performance, this item was reviewed and it was conclude <t that

fatigue could have played a role in the error as documented in NRC

Inspection Report Nos. 50-338, 339/92-10. Current personnel

performance during the most recent outage did not identify similar

problems.

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e. (Closed) VIO 50-339/92-18-02: Inadequate Corrective Maintenance

on Airlock Door to Preclude Repetition

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The violation involved repeated containment airlock door test

failures due to inadequate corrective maintenance. The licensee

responded to this violation in correspondence dated November 18, <

1992. This response was acceptable. Corrective action included

maintenance to align the airlock door during the fall 1993 Unit 2

refueling outage. The inspectors reviewed the completion of this

maintenance and subsequent testing. The inspectors found the

licensee's actions to be adequate.

f. (Closed) VIO 50-338/93-18-01: Inoperable Hydrogen Analyzer

The violation involved a hydrogen analyzer which was discovered to  ;

be inoperable due to a pressure sensing line being disconnected.

The licensee responded to this violation in correspondence dated -

November 18, 1992. This response was acceptable. The cause of

the event was personnel error with procedural inadequacies as a

contributing factor. The inspectors verified that the procedures '

for calibrating the hydrogen analyzers were revised to more

clearly reflect restoration of the hydrogen analyzer and to more

clearly define verification steps.  :

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To address the broader issue of an apparent negative trend in the

number of errors during performance of I&C activities, increased  :

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management attention was placed on the activities. Overall,

licensee management was aggressive in trying to understand the '

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cause for the errors and initiating corrective actions. Actions

taken by the licensee have also been previously documented in NRC ,

Inspection Report Nos. 50-338, 339/93-18. I&C personnel errors

are currently trended by the licensee. The inspectors reviewed

the data which indicated zero errors for the months of June -

September 1993. The inspectors considered that actions to resolve

this issue were effective.

g. (Closed) IFI 50-339/93-24-01: Loose Fuel Material in the Transfer

Canal

This item involved the finding of several loose fuel pellets in

the Unit 2 transfer canal during the fall 1993 refueling outage.

Inspectors followed the licensee's recovery of the fuel material ,

and its return to a safe storage location in the spent fuel pool '

(paragraph 3.d).

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9. Exit (30703)

The inspection scope and findings were summarized on November 24, 1993,

with those persons indicated in paragraph 1. The inspectors described

the areas inspected, the findings in the results section of this report ,

and discussed in detail the inspection results listed below. The -

licensee did not identify as proprietary any of the material provided tn~ 1

or reviewed by the inspectors during this inspection. Dissenting

comments were not received from the licensee. l

Item Number Description and Reference

VIO 50-339/93-27-01 Failure to follow Procedure 2-PT-82H  ;

(paragraph 3.c)  ;

IFI 50-338, 339/93-27-02 Adequacy of LHSI Venting Interval  !

(paragraph 8.a) l

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10. Acronyms and Initialisms

AC Alternating Current

ASME American Society of Mechanical Engineers  !

CCW Component Cooling Water ,

CFR Code of Federal Regulations

CR0 Control Room Operator  !

CVCS Chemical and Volume Control System  !

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DR Deviation Report

EAB Exclusion Area Boundary t

ECCS Emergency Core Cooling System

EDG Emergency Diesel Generator r

E0P Emergency Operating Procedure [

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ESF- Engineered Safety Feature

FW Feedwater ,

GDC General Design Criteria

GPM Gallons Per Minute

HHSI High-Head Safety Injection

I&C Instrumentation and Control >

IFI Inspector Follow-up Item

IN Information Notice

ISI Inservice Inspection  ;

LCO Limiting Condition for Operation i

Licensee Event Report .

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LER

LHSI Low Head Safety Injection j

LPZ Low-Population Zone

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MSVH Hain Steam Valve House

NRC Nuclear Regulatory Commission  !

PCT Peak Centerline Temperature

PT Periodic Test

QA Quality Assurance

SG Steam Generator

SI Safety Injection  :

SNSOC Station Nuclear Safety and Operating Committee .

SRO Senior Reactor Operator ,

TS Technical Specification

URI Unresolved Item i

VIO Violation i

WO Work Order  ;

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