IR 05000338/1993024
| ML20058J273 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 11/15/1993 |
| From: | Belisle G, Mcwhorter R, Taylor D, York J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20058J262 | List: |
| References | |
| 50-338-93-24, 50-339-93-24, NUDOCS 9312140030 | |
| Download: ML20058J273 (17) | |
Text
..
--
.
-
...
.
"
UNITED STATES v
/pa meog%
NUCLEAR REGULATORY COMMISSION l
e'-
't REGION il i
E
$~(
101 MARIETTA STREET. N.W., SUITE 2900
!
.
';
ATLANTA, GEORGtA 3G323 0199
,
%..... #'
i
Report Nos.:
50-338/93-24 and 50-339/93-24 i
Licensee:
Virginia Electric & Power Company 5000 Dominion Boulevard
>
Glen Allen, VA 23060 l
!
Docket Nos.:
50-338 and 50-339 License Nos.: NPF-4 and NPF-7 Facility Name: North Anna 1 and 2
!
Inspection Conducted: September 19 - October 16, 1993 Inspectors:
<> %, y
_
&
//-f r - E I
. flic horter, Senior Resident Inspector Date Signed I
.
& 2n -
5-
'l~N~~ r3 J. W. Yorl, Acting Senior Resident Inspector Date Signed j
,
2 yt f -, k M-tr-73 D. R. Taylor, Resident Inspector
~I) ate Signed
)
Approved by:
p=h,f(jf~
ff.rff3 G7.
elisle,W ction Chief fe' Signed
!
Division of Reactor Projects
{
SUMMARY
-
l
Scope:
This routine inspection by the resident inspectors involved the following
areas:
plant status, operational safety verification maintenance observation, surveillance observation, licensee event report followup and action on previous inspection items.
Inspections of licensee backshift
'!
activities were conducted on the following days:
September 23, October 13
'
and 14.
-
Results:
All functional areas j
.:
A cc..tiiwing strength was identified for Station Oversight Board effectiveness (paragraph 3.c).
9312140030 931115 PDR ADOCK 05000338 G
.
.
- --
-
.. -.
.
.
...
-
.
._
.. _.
.. -.
t
.
i
!
,
'I Operations functional area
'
A strength was identified for overall licensee management and senior operator
'
oversight of refueling activities (paragraph 3.a).
i i
An Inspector Follow-up Item was identified for loose fuel material in the transfer canal (paragraph 3.a.1).
!
Plant Sucoort and Maintenance functional areas
!
A continuing strength was identified for planning and management of the
!
service water system restoration project (paragraph 4.a)-
'
i
,
l
!
l l
,
'
i o
l
t l
h
i r
,
$
!
'
!
!
>
l
..
,
!
'l
,
.
.. -
-
.
-
-
-.
- _,
.-
..
-
. - -.
,
_ _ _ _ _ _
.
-_
_. -
_ -
.
_
. _.
_ _
.
_
l
I
i
!
l
.
q i
!
l I
REPORT DETAILS
!
1.
Persons Contacted Licensee Emoloyees j
L. Edmonds, Superintendent, Nuclear Training
.
j
- R. Enfinger, Assistant Station Manager, Operations and Maintenance
!
J. Hayes, Superintendent of Operations D. Heacock, Superintendent, Station Engineering i
- G. Kane, Station Manager i
- P. Kemp, Supervisor, Licensing i
W. Matthews, Superintendent, Maintenance j
J. O'Hanlon, Vice President, Nuclear Operations
D. Roberts, Supervisor, Station Nuclear Safety j
- R. Saunders, Assistant Vice President, Nuclear Operations j
-
D. Schappell, Superintendent, Site Services
- )
R. Shears. Superintendent, Outage and Planning
!
- J. Smith, Manager, Quality Assurance
_
A. Stafford, Superintendent, Radiological Protection-l
- J. Stall, Assistant Station Manager, Nuclear Safety and Licensing Other licensee employees contacted included engineers, technicians, operators, mechanics, security force members, and office personnel.
NRC Resident Inspectors
- R. McWhorter, Senior Resident Inspector J. York, Acting Senior Resident Inspector
- D. Taylor, Resident Inspecto.*
- Attended exit interview Acronyms and initialisms used throughout this report are listed in the last paragraph.
On October 4 and 5, 1993, the NRC Region II Section Chief, G. A. Belisle, visited the North Anna Power Station. Mr. Belisle attended licensee planning meetings, toured containment and the plant with the inspectors, and met with licensee management to discuss current issues at the facility.
2.
Plant Status Unit 1-operated the entire inspection period at or near 100% power.
Unit 2 began the inspection period in MODE 6.
On September 20, fuel off-load commenced and was completed on September 23.
On October 6,-
following completion of defueled maintenance, core on-load commenced.
Core on-load was completed on October 8.
On October 12, the unit
^
i l
__
_, - -
. _.
.
-
_
_
entered MODE 5 and remained there until the end of the inspection period.
3.
Operational Safety Verification (71707)
The inspectors conducted frequent visits to the control room to verify proper staffing, operator attentiveness, and adherence to approved procedures.
The inspectors attended plant status meetings and reviewed operator logs on a daily basis to verify operational safety and compliance with TS and to maintain awareness of the overall facility operation.
Instrumentation and ECCS lineups were periodically reviewed from control room indications to assess operability.
Frequent plant tours were conducted to observe equipment status, fire protection programs, radiological work practices, plant security programs, and housekeeping.
Deviation Reports were reviewed to assure that potential safety concerns were properly addressed and reported.
Selected Deviation Reports were followed to ensure that appropriate management attention and corrective action were applied.
a.
Unit 2 Refueling Activities The inspectors verified preparations and prerequisite signoffs for refueling by reviewing 2-0P-4.1, Controlling Procedure for Refueling, revision 26, and by touring selected plant areas.
The inspectors performed visual inspection of containment penetration areas in the MSVH, Quench Spray Pump House, and penetrations through the containment equipment hatch. The inspectors viewed a representative sample of penetrations to verify containment integrity.
Prerequisites checked included ventilation flow paths, cavity water sampling, and setpoints for containment purge isolation.
No discrepancies were identified.
On September 21, the inspectors toured containment, observed fuel off-load, and discussed refueling activities with the refueling SRO.
During fuel movement observations, the inspectors observed the Plant Manager, the Superintendent of Operations, and the Supervisor of Operations Support tour the refueling area.
During the off-load, several problems were encountered which the inspectors reviewed as discussed below:
1)
During visual inspection of twice burned fuel assembly Y-48, part of one fuel rod was missing.
Followup video inspection l
identified that a section, approximately three inches in length, was missing from Rod 3 on Face 3 between the sixth and seventh grid straps.
A survey of the Unit 2 transfer canal identified what appeared to be several fuel pellets and a three inch section of cladding material.
An underwater radiological survey of the material from eight inches measured 10,200 R/hr, which confirmed the objects to be fuel pellets.
No elevated radiation readings were
m
_
_ _.
_
- _
.
__
,
'
l
.
.
detected outside the pool, and waterborne activities did not change.
During a September 24 conference call, the NRC discussed
with the licensee the fuel failure mechanism and material recovery plans.
Based upon an observed cladding defect on this same rod, fuel failure was attributed to secondary
<
hydrating.
The licensee indicated that a plan would be developed at a later date for retrieving the loose cladding material and fuel pellets. The inspectors will continue to
'
follow this issue under Inspector Follow-up Item (IFI)
'
50-339/93-24-01, Loose Fuel Material In Transfer Canal.
)
2)
The inspectors reviewed DR 93-1462 which documented an i
alignment problem between the manipulator crane inner mast i
(gripper tube) and the outer mast.
The problem involved the l
inner mast alignment key becoming disengaged from the rollers when a fuel assembly was raised. The inner mast and
,
fuel assembly could still be raised and lowered in the outer
'
mast as required to move the fuel assembly to the upender.
At the upender, the outer mast was manually rotated-to adjust the alignment.
Following assembly placement in the
.
upender, the problem was corrected. The inspector.s verified
manipulator crane interlocks remained active wnile the
problem was being corrected.
3)
The inspectors reviewed DR 93-1493 which documented leakage through a temporary containment hatch plate-during refueling. QC wrote the DR because a zero leakage criteria
for temporary penetrations was removed from a procedure when
zero leakage could not be obtained. A procedural change
'
i '
deleted the zero leakage criteria and substituted a visual
penetration inspection.
The visual. inspection criteria was approved by SNSOC based on accident analysis assumptions for-l the limiting accident being containment purge not isolating
'
and no containment pressurization. The inspectors
'i considered the resolution reasonable, considering the low
!
'
safety significance.
On October 7, inspectors. observed core on-load. During the observations, difficulties were experienced with inserting a bowed l
fuel bundle into a tight core location. The inspectors noted that
'
,
the refueling SR0 carefully and positively controlled the bowed i
fuel assembly's movement into the core. Overall management and
senior operator oversight of refueling activities was considered a
!
strength'
!
-
b.
Nuclear Quality Assurance Meeting
!
On September 22, the inspectors met with the QA group to review various QA inspection and assessment results performed during l
August and September. The following items were discussed:
I
- -
_
. - -
._
-
-.
.
.
!
.i
.
';
.
I
'
.
l
!
A weakness identified for maintenance personnel not
-
completing work packages.
A positivt assessment of the TS Surveillance Requirements
!
-
Review - Phase I.
(The phase 2 TS surveillance requirement
.:
review for radiation monitors, fire protection, etc., was in
!
progress.)
l
-
Frequent maintenance on specific radiation monitors.
l
-
!
Positive observations of I&C work practices.
(This was an
!
-
improvement in I&C performance from earlier in.the year.)
'
.
In addition, the QC group continued to follow the use, curing. ar.d
!
storage of the silicone RTV foam kits used to repair electrical
penetration fire stops.
!
The above findings demonstrated that the QA group continued to be
!
effective in identifying issues for management attention.
c.
Staticn Oversight Board Meetings l
l The inspectors attended Station Oversight Board meetings on
!
'
September 27 and October 4.
The meetings provided station
.j management with updates on trends, issues and selected topics of
interest. On October I, the inspectors attended the Unit 2 fuel.
'
on-load assessment review. The assessment was-an initiative first
.!
performed during the SGRP.
Each cognizant supervisor or i
superintendent discussed items that had potential'to impact core
!
on-load. The meetings continued to be_a strength in that they
~
provided station management an opportunity to assess actions and
!
provide direction to specific safety significant topics.
'l
!
d.
Independent Safety Engireering Group I
The inspectors performed a review of plant activities to assess how the requirements of NUREG-0694, Item I.B.I.2, (ISEG) were implemented by the licensee.
Inspectors found that the requirements were met by the Station Nuclear Safety group. This group was required by TS 6.2.3 to carry out the same functions as an ISEG. A Station Nuclear Safety activity review revealed that staffing was appropriate and that the group's activities contributed to the safe operation of the station.
e.
Employee Concern Program (TI 2500/08)
The inspectors were tasked with reviewing the licensee's employee concern program.
Inspection results were documented in IR 93-23 and in the Attachment to this repor..
-
-..-. -
-
-.
. -
-
-_
~
.
l
.
.
'
.
.
,
f.
Licensee NRC Notifications (1)
On September 23, October 7, 8 and 11,'the licensee made
!
reports to the NRC as required by 10 CFR 50.72 concerning notifications to offsite authorities.
Specifically, the
licensee had committed to notify the Commonwealth of
'
Virginia when injured personnel are transported offsite, and-l when three or more individuals receive personal-
!
contaminations during the same event. The inspectors k
reviewed these notifications and verified that there were no regulatory concerns associated with the events.
.
i (2)
On September 21, 22, ~ and 25, ~ the licensee reported degraded
SGs as required by 10 CFR 50.72. All three Unit 2 SGs were l
discovered to require greater than one percent tube plugging. This plugging level placed the SGs in TS 4.4.5.2
category C-3.
The inspectors monitored associated SG inspection and plugging activities throughout the Unit 2 outage and found licensee actions to be appropriate.
No violations or deviations were identified.
,
'
4.
Maintenance Observation (62703)
Station maintenance activities were obcerved/ reviewed to ascertain that the activities were conducted in accordance with approved procedures,
regulatory guides and-industry codes or standards, and in conformance
!
with TS requirements.
i a.
Service Water System Restoration Pro;ect
i The inspectors reviewed Phase 1, Stage 3, of the Service Water j
System Restoration Project performed during the Unit 2 outage.
The area of greatest concern for microbiological influenced
.i corrosion was the uncoated 24-inch diameter SW piping.
Several piping areas were examined and repaired during this outage.
,
Initially, the piping interior was blast cleaned and divided into i
eight circumferential grids five feet long.
Pitted areas in the grids were then measured ultrasonically to determine if the minimum wall thickness was satisfied.
If this thickness was not satisfied, a weld repair was performed.
Sixteen pitted. areas were repaired in the A header and 21 pitted areas in the B header.
Preferential pitting in the weld heat affected zones was also
,
noted. This pitting appeared as a pair of parallel grooves approximately 1/4 to 1/2-inch apart around a portion of the
!
circumference. The grooves' depths varied from near zero to 1/8 inch. The licensee conservatively repaired all 11 weld zones on the two loops that ran beneath the Unit 2 alleyway. Analysis showed that this piping run could be subject to seismic and other
,
loads which required a greater minimum wall thickness (0.250 inch)
i than that required for concrete encased piping (0.120 inch).
j i
,
i
_
,
.
_-
-.
.
- - -. - -
-
..
-. -
-.
f
. - -
-
-
.
>
.
Discussions revealed that all the welds in the-SW system that
'l could be subject to the greater loads have been inspected and
'
repaired where necessary.
The licensee's Service Water System Restoration project continued i
to be well planned and managed and was identified as a continuing l
strength.
I b.
Leak Sealant Repairs The inspectors reviewed the licensee's leak sealant practices.
l The licensee primarily contracted Furmanite to repair leaks on equipment which continues to leak after tightening and which cannot be isolated during operations. The process involved
sealant compound injection through temporary fittings.
The desired method was to inject by non-destructive means such as
through clamps or into a box. Where this could not be l
accomplished, destructive methods such as drilling into the i
component were used.
l Administrative control over leak sealant usage was provided by
the three following SNSOC approved procedures:
HMP-C-MISC-1, Safety Related Valve On-line Leak Repair Using
-
Contractor Leak Sealing Methods, revision 11,
,
MMP-C-MISC-1, Safety Related Component * On-line Leak Repair
-
,
Using Contractor Leak Sealing Methods (*Except Valves),
revision 4, and j
i MMP-C-MISC-NSR-1, Non-safety Related Valve On-line Leak
'
-
Repair Using Contractor Leak Sealing Methods, revision 4.
.
The licensee indicated that revisions to the procedures were being
,
pursued which will consolidate leak sealant repairs into one
!
procedure. The procedures were used in conjunction with either supplemental work instructions or vender procedures depending on j
the particular application.
For each component injected with leak sealant, maintenance
.
'
engineering performed a safety evaluation activity screening and completed an engineering evaluation data sheet.
The data sheet-required information such as date previously injected, times injected, amount of compound needed, maximum compound allowed, compound type, and restrictions for use. When using leak sealant
,
as a method to stop a leak, procedure controls required a work i
request be initiated to restore the injected component to original design. Components which were not correctable at power were
corrected during the next refueling outage.
j The inspectors reviewed the components currently injected and did not identify any concerns. The inspectors concluded that leak i
,
.
_
,-
--
-
-
..
..
i i
'
.
.
!
l
sealant usage was adequately controlled and used only as a last I
resort.
c.
Valve Maintenance
On October 1, the inspectors observed maintenance on 2-FW-62, FW
Check Valve to A SG, using WO 00270617-01. The valve required
repair because it failed to demonstrate backseating during 2-PT-211.1, Valve Inservice Inspection (Main Feedwater Check
Valve), revision 4P-1.
The inspectors observed the valve disk
!
surface blue check which indicated that 15-20% of the valve disk
!
was not in contact with the seat.
Following additional maintenance, the valve was reassembled and retested satisfactory.
The inspectors reviewed the valve test requirements.for leak l
tightness.
Although 2-FW-62 was the FW to the A SG containment isolation barrier, the UFSAR described this valve as an exception i
to GDC criteria 55, 56 and 57. As such, no type C leak test was required.
The inspectors verified the valve was tested in
!
accordance with the requirements of the~1icensee's ASME Section XI
,
test program. The inspectors did not identify any problems with the maintenance.
No violations or deviations were identified.
5.
Surveillance Observation (61726)
}
}
The inspectors observed / reviewed TS required testing and verified that j
testing was performed in accordance with adequate procedures, that test
!
instrumentation was calibrated, that LCOs were met and that any deficiencies identified were properly reviewed and resolved.
i i
HHSI Flow Balance Test Failure i
On October 14, the inspectors observed performance of 2-PT-138.1, HHSI Flow Balance, revision 1-P2.
During the initial run for the cold leg i
verification, branch line flows did not meet TS 4.5.2.h requirements.
i Special NRC Inspection Report Nos. 50-338,339/93-28 was issued on November 1,1993, concerning this problem.
j In addition to the findings contained in that inspection, the inspectors also assessed the licensee's test performance. The inspectors considered the briefing for the test to be thorough and noted that management expectations for RCS level control and makeup were clearly expressed. The inspectors later observed that makeup and letdown flows
!
were carefully controlled by operators. Overall test execution was good l
with the exception of the following two procedural problems:
'
First, the CR0 identified that cooldown limits established in
-
2-0P-1.1, Unit Startup From Mode 5 at 140 degrees or Less to Mode 5 at less Than 200 degrees, revision 24-P1, had been exceeded.
The OP limited cooldown to 5 degrees per hour when below 120
,
degrees. This was identified after the test had resulted in a 10 i
,
~
.
..
,
'
I
.
.
degrees cooldown over a 30 minute period (20 degrees per hour.)
The flow test was appropriately stopped for three hours until the
,
issue was resolved. A procedure change was made to note the
!
cooldown limit of the OP did not apply for test conditions.
!
Second, the inspectors identified a procedure discrepancy
-
concerning instruments to be used to measure total flow.
.
2-PT-138.1, attachment 3, step 17, and precaution 4.14 required-that total flow not exceed 660 gpm using the sum of installed instruments 2-SI-FT-2493 and 2-CH-FT-2122.
Inspectors noted that r
the total flow using these instruments was 667 gpm.
System
engineers overseeing the test explained that the sum using the ultrasonic flow measuring devices was less than 660 gpm and more
!
accurate than the installed instrument 2-SI-FT-2493-(an
,
i orifice / flow transmitter combination.) They stated that a procedure change would be made after the test was-completed to reflect using the sum from the ultrasonic devices. Ti.a decision
,
to use the alternate instrumentation was discussed and concurred
in with shift supervision. After subsequent discussions, licensee-personnel indicated a DR would be initiated to document and resolve the discrepancy in procedure execution.
Inspectors i
considered this action to be appropriate.
No violations or deviations were identified.
6.
Licensee Event Report Followup (92700)
The following LERs were reviewed and closed.
The inspectors verified that reporting requirements hac' been met, that causes had been identified, that corrective actions appeared appropriate and that generic applicability had been considered.
Additionally, the inspectors confirmed that no unreviewed safety questions were involved and that
,
violations of regulations or TS conditions had been identified.
a.
(Closed) LER 50-339/92-07: Main Steam Valve Failed Shut Causing a
,
Reactor Trip and Safety Injection Due to Failure of the Main Steam f
Trip Valve Air Cylinder Rupture Disk
,
During the event, several equipment malfunctions occurred
,
including a MSTV air cylinder diaphragm failure and a cracked weld
on tubing downstream of vent valve 2-SI-377. Additionally, prior
,
to terminating the SI, the pressurizer became solid with pressure i
control through one pressurizer PORV.
The licensee's cause determination evaluation for the rupture disk was inconclusive as to a single failure, but pointed out that the
,
current rupture disk operating parameters could lead to premature
'
fatigue failure. As a result, a modification was made to replace the existing disc with an upgraded design on both units. The i
inspectors verif ed that replacements were completed for Unit I by
reviewing W0s 158146, 158147 and 158148.
Replacements for Unit 2
!
were in progress as a work item in the current outage.
_
.
.
.
.
,
Concerning the cracked weld, the licensee initiated DCP-277, vent line tubing and support modifications to prevent recurrence. This DCP was completed on Unit I and a similar DCP was in progress as a
work item in the current Unit 2 outage.
The failure was attributed to stress induced by pressure spiking during LHSI system'startup.
Pressure spiking in the LHSI system was being reviewed separately under URI 50-338/91-22-02.
To address the solid pressurizer issue, the licensee reviewed the E0Ps and compared them to the WOG ERGS.
The review found no justific1 tion for revising the-EOPs. The inspectors reviewed this issue and noted that solid operations following events were analyzed as acceptable in the UFSAR and are occasionally unavoidable.
,
b.
(Closed) LER 50-338/93-01:
Personnel Hatch Outer Door Escape Lock
-
'
Equalization Valve Not Fully Closed As Required For Containment Integrity During Core Alterations Due to Personnel Error.
-
,
The licensee completed corrective actions to revise containment integrity procedures on both units to strengthen personnel hatch closure requirements. The inspectors also observed that designated individuals were used to operate the airlock hatch during Unit 2 refueling operations. Additional followup of
,
licensee corrective actions will be reviewed during closure of Violc-ion 50-338, 339/93-08-01.
'
c.
(Cicsed) LER 50-338/93-04: Containment Particulate and Gaseous Radiation Monitors Inoperable Due to No Containment ~ Air Recirculating Fans Operating During Core Alterations
Prior to the LER submittal, shift surveillances were changed to provide a routine fan operation check. Additionally, the inspectors verified that a containment air recirculating fan was running prior to fuel movement for the current Unit 2 outage.
i Procedure controls were in place to ensure at least one containment air recirculation fan remained running during core alterations.
This item was also addressed by Non-Cited Violation 50-338/93-10-04.
No violations or deviations were identified.
7.
Action on Previous Inspection Items (92701; 92702)
(Closed) IFI 50-339/93-10-02:
.
.
This followup item was initiated to review the licensee's evaluation for l
degraded thread studs on the flange. During an April 1993 forced outage, the unit was cooled down to MODE 5 to affect repairs on the flange. This item is closed based on the flange repair.
.
No violations or deviations were identified.
,
f
- - --
,
.
_
. _ _. _
_
.
._-
_
._
.
.
.
,
!
8.
Exit (30703)
The inspection scope and findings were summarized on October 20, 1993, with those persons indicated in paragraph 1.
The inspectors described the areas inspected and discussed in detail theLinspection results
listed below and in the results section. The licensee did not identify
as proprietary any of the material provided to'or reviewed by the
~!
inspectors during this inspection.
Dissenting comments were not
.
received from the licensee.
!
Item Number Description and Reference
!
IFI 50-339/93-24-01 Loose Fuel Material In Transfer Canal (paragraph 3.a.1)
j
9.
Acronyms and Initialisms r
ASME American Society of Mechanical Engineers-l CFR Code of Federal Regulations
!
CR0 Control. Room Operator
DCP Design Change Package
!
DR Deviation Report ECCS Emergency Core Cooling System E0P Emergency Operating Procedure
!
ERG Emergency Response Guideline FW Feedwater
.
GDC General Design Criteria
!
HHSI High Head Safety Injection
I&C Instrumentation and Control IFI Inspector Follow-up Item
'
IR
Inspection Report
ISEG
Independent Safety. Engineering Group
l
LCO
Limiting Condition for Operation
.
LER
Licensee Event Report
LHSI
Low Head Safety Injection
i
MSTV
Main Steam Trip Valve
MSVH
Main Steam Valve House
NRC
Nuclear Regulatory Commission
,
OP
Operating Procedure
Peak Centerline Temperature
+
Power-0perated Relief Valve
l
Quality Assurance
Quality Control
-
Reactor Coolant Pump
.
Room Temperature Vulcanizing
.
Steam Generator Restoration Project
,
Safety Injection
.
SNSOC
Station Nuclear Safety Operating Committee
SR0
Senior Reactor Operator
j
i
!
i
,
f
.
..,,
.. _, _ _
_
_
,
_
_ _ _ _
..
-
.
!
t
.
.
.
,
i
!
TI
Temporary Instruction
TS
Technical Specification
Updated Final Safety. Analysis Report
I
,
Unresolved Item
j
Work Order
Westhghouse Owners Group
..
!
'
,
!
I
,
'
i
I
!
i
L
j
-;
!
I
l
l
I
l
i
I
.i
1
4 -
[
i
'
l
l'
I
i
ATTACHMENT 1
.
EMPLOYEE CONCERNS PROGRAM SURVEY
!
j
!
i
'
PLANT NAME: North Anna Units 1&2 LICENSEE: VEPC0 DOCKET #: 338.339
i
A.
PROGRAM:
'
i
t
l
1.
Does the licensee have an employee concerns program?
(Yes)
l
Comments:
VPAP-0204, Allegations of Conditions Adverse to
l
Safety, Approved 6-3-93
2.
Has NRC inspected the program? (No)
Report # N/A
B.
SCOPE:
j
1.
Is it for:
a.
Technical? (Yes)
f
l
b.
Administrative? (Yes)
,
c.
Personnel issues? (Yes)
2.
Does it cover safety as well as non-safety issues?
,
l
(Yes)
Comments:
Potentially any issue could be brought up through
this process.
l
.
3.
Is it designed for:
l
a.
Nuclear safety? (Yes)
I
b.
Personal safety? (Yes)
c.
Personnel issues - including union grievances?
i
(Yes)
l
Comments:
Union grievances are not addressed in VPAP-0204
l
'
4.
Does the program apply to all licensee employees?
(Yes)
5.
Contractors?
(Yes)
i
!
.
..
.
.
_
.
t
,
'
.
.
,
!
Comments: Contractors are always. free to bring concerns to
'
management's attention. Virginia Power takes appropriate
'
actions based on the characteristics surrounding each issue.
6.
Does the licensee require its contractors and their subs to
have a similar program?
i
(No)
,
7.
Does the licensee conduct an exit interview upon terminating
employees asking if they have any safety concerns?
(Yes)
Comments:
Employees are interviewed and given the
!
opportunity to discuss any concern that they may have.
If
an employee is actually terminated by the company (fired),
no exit interview is performed.
!
'
C.
INDEPENDENCE:
1.
What is the title of the person in charge?
Station Manager
2.
Who do they report to?
VP Nuclear Operations
3.
Are they independent of liv vanagement?
l
No. A supervisor, independent of the line management for a
terminating employee, may conduct the exit interview.
4.
Does the ECP use third party consultants?
No.
5.
How is a concern about a manager or vice president followed
up?
A report is made to higher level management as appropriate.
D.
RESOURCES:
1.
What is the size of staff devoted to this program?
There are none devoted full time to this program.
2.
What are ECP staff qualifications (technical training,
interviewing training, investigator training, other)?
This is determined on a case-by-case basis as determined by
management. Management will assign a lead from station or
,
-
.
.
-.
..
.
.4
.
corporate licensing, or administrative review, depending on
the specific allegation.
E.
REFERRALS:
1.
Who has followup on concerns (ECP staff, line management,
other)?
The person assigned the lead will provide a report to
management.
F.
CONFIDENTIALITY:
1.
Are the reports confidential?
(Yes)
Comment:
Actual name of person making the allegation is not
always known.
2.
Who is the identity of the alleger made known to (senior
management, ECP staff, line management, other)?
Senior Management, if the identity is known.
3.
Can employees be:
a.
Anonymous? (Yes)
b.
Report by phone? (Yes)
G.
FEEDBACK:
Is feedback given to the alleger upon completion of the
followup?
(Yes, if the person making allegation is known.)
2.
Does program reward good ideas?
,
N/A, other programs are developed to reward good ideas.
3.
Who, or at what levei, makes the final decision of
resolution?
Station Manager
4.
Are the resolutions of anonymous concerns disseminated?
On a need-to-know basis.
5.
Are resolutions of valid concerns publicized (newsletter,
bulletin board, all hands meeting, other)?
,).
-
..
Have not received a valid concern since the program was
approved on June 3, 1993.
H.
EFFECTIVENESS:
!
1.
How does the licensee measure the effectiveness of the
program?
New program / procedure
2.
Are concerns:
,
a.
Trended? (No, too new a program)
f
b.
Used? (Yes, if determined to be applicable to the
station)
>
3.
In the last three years how many concerns were raised?
i
Closed?
What percentage were substantiated?
Comments:
New procedure was implemented on 6/19/93,
however, two concerns were identified in 1993 prior to
procedure implementation.
4.
How are followup techniques used to measure effectiveness
(random survey, interviews, other)?
New procedure implemented on 6/19/93
5.
How frequently are internal audits of the ECP conducted and
by whom?
i
New program. No internal audits have been performed.
,
!
I.
ADMINISTRATION / TRAINING:
1.
Is ECP prescribed by a procedure? (Yes)
VPAP-0204, Allegations of Conditions Adverse to Safety
.
!
2.
How are employees, as well as contractors, made aware of
'
this program (training, newsletter, bulletin board, other)?
,
Nuclear Employee Training Manual instructs employees to
identify issues to supervisors and to the NRC if not
resolved by supervision.
ADDITIONAL COMMENTS:
(Including characteristics which make the program
especially effective or ineffective.)
NONE
l
l