ML18152A464
| ML18152A464 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 10/19/1995 |
| From: | Belisle G, Branch M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A465 | List: |
| References | |
| 50-280-95-20, 50-281-95-20, NUDOCS 9511140269 | |
| Download: ML18152A464 (14) | |
See also: IR 05000280/1995020
Text
=-===-===-=-=-=~-==-==-=-=-=--==--='-=-==-- -~ =--==--
Report Nos. :
UNITED STATES
NUCl.,.EAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
50-280/95-20 and 50-281/95-20
Licensee:
Virginia Electric and Power Company
Innsbrook Technical Center
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket No.:
50-280 and 50-281
License No.:
DPR-32 and DRP-37
Facility Name:
Surry 1 and 2
Inspection Conducted:
September 14 through October 4, 1995
Lead Inspector:
~~Vv.__:_ Fo fL
- ~nch,llSenior Resident Inspector
Other Inspectors:
W. K. Poertner, Resident Inspector
M. E. Ernstes, Regional Inspector
lD~/ 'il/1 ~.
Dat Signed
D. R. Taylor, Resident Inspector (North Anna)
Approved by:
Scope:
¥~(£
G.~ BeTse, e
Reactor Projects Branch 5
Division of Reactor Projects
SUMMARY
This special inspection was conducted on site to review and evaluate the
circumstances associated with the September 13 and 14, 1995 reduction of
Unit 1 reactor.vessel inventory.
Inspections of backshift and weekend
activities wer~ conducted.
Results:
Three apparent violations associated with failure to follow procedures were
identified. Weaknesses in training and fundamental understanding of equipment
performance were also noted.
The apparent violations are grouped into the
following three categories: a) administrative controis of operating
activities, b) control of maintenance, and c) control of pressurizer relief
tank venting activities. The root cause evaluation was thorough, probing and
self-critical. Operations personnel interviewed were straightforward and
candid.
9511140269 951019
ADOCK 05000280
G
-
---==---~~==-=--= =---==-==-- =--- ~-~
1.
Persons Contacted
Licensee Employees
REPORT DETAILS
- W. Benthall, Supervisor, Licensing
H. Blake, Jr., Superintendent of Nuclear Site Services
R. Blount, Superintendent of Maintenance
- M. Bowling, Manager, Nuclear Licensing and Operations Support
- B. Bryant, Licensing
- D. Christian, Station Manager
J. Costello, Station Coordinator, Emergency Preparedness
- R. Cross~ Procedures
- D. Erickson, Superintendent of Radiation Protection
- B. Garber, Licensing
- D. Hayes, Supervisor of Administrative Services
C. Luffman, Superintendent, Security
- H. Mccallum, Nuclear Training
- J. McCarthy, Assistant Station Manager
- F. McConnell, Materials
- G. Miller, Corporate Licensing
- S. Sarver, Superintendent of Operations
- R. Saunders, Vice President, Nuclear Operations
- R. Scanlan, Station Nuclear Safety
- B. Shriver, Assistant Station Manager
K. Sloane, Superintendent of Outage and Planning
- E. Smith, Site Quality Assurance Manager
- D. Sommers, Corporate Licensing
- T. Sowers, Superintendent of Engineering
B. Stanley, Supervisor, Procedures
- J. Swientoniewski, Supervisor, Station Nuclear Safety
N. Urquhart, Supervisor, Training
Other licensee employees con"ta.cted included plant managers and
supervisors, operators, engineers, technicians, mechanics, security
force members, and office personnel.
NRC Personnel
- M. Branch, Senior Resident Inspector
M. Ernstes, Region II
K. Poertner, Resident Inspector
D. Taylor, Resident Inspector (North Anna)
- G. Belisle, Region II
- Attended Exit Interview
Acronyms used throughout this report are listed in the last paragraph .
2.
2
Unit 1 Loss of Inventory Event (71707)
2.1
Licensee's Identification and Evaluation of Event
On September 14, 1995; while shutdown for refueling, the RVWL
standpipe indication for Surry Unit 1 experienced an unexpected
drop from approximately 18 feet to 13.3 feet.
The cause of the
event was due tri the isolation of the RHV with a nitrogen bubble*
trapped in the head.
As pressure was relieved from the top of the
RVWL standpipe due to depressurizing the PRT, indicated level
increased in the RVWL standpipe.
A control room operator
increased letdown rate in order to maintain RVWL standpipe level
stable at 18 feet.
The letdown continued for approximately three
and a half hours until the bubble in the reactor head expanded and
reached equilibrium. Approximately eleven hours later,
detentioning of the reactor vessel head allowed a vent path for
the bubble in the reactor head.
This caused the RVWL standpipe
level to drop to the actual reactor vessel water level of 13.3
feet.
Based on personnel interviews, log review~, and discussions*
with the licensee's RCE team, the following sequence of events and
summary of the root cause analysis was developed.
For clarity,
times are specified in a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> format.
September 8, 1995
0241
Surry Unit 1 shutdown for refueling.
September 13, 1995
0325
RHV and RVWL standpipe placed in service.
1131
Draindown commenced to 18 foot level as indicated by the
RVWL standpipe.
1300 Draindown to 18 feet completed.
PRT pressure was 11 psig.
This pressure was also the pressure in the reactor vessel
head region.
-1330
WOs released to remove PZR safety valves and to work on flux
thimbles.
1500
RHV isolated and-tagged out in order to remove $pool piece
to *support installation of the reactor cavity seal ring and
to remove the RVLIS bracket.
1630 Workers reported leakage at the seal
thimble work began.
The SS realized
at approximately 11 psig and stopped
thimbles and PRZ safety valves.
table as the flux
that the RCS was still
work un the flux
'\\
3 .
1710
PRT venting commenced to establish acceptable plant
conditions to release flux thimble and PZR safety valve WOs.
As the PRT was vented, pressure was relieved from the top of
the RVWL standpipe and PZR.
The trapped bubble in the
reactor head region began to expand, forcing water up in the
stand pipe and PZR surge line. The reactor operator
increased his rate of letdown from the reactor vessel in
order to maintain RVWL standpipe indication at 18 feet.
Actual reactor vessel water level was decreasing.
VCT water
level was increasing.
The Unit Supervisor and SS were
focused on problems with the Primary Drain Transfer Tank
pump and were not sensitive to the fact that the reactor
operator was letting down coolant from the vessel.
1800
Head vent spool piece reinstalled. Maintenance workers
signed off the WOs to remove and reinstall the spool piece.
The third WO to remove and reinstall the RVLIS bracket was
not *signed off since RVLIS was not reinstalled. Therefore,
th~ tagout of the reactor head vent remained active ..
1830 Shift turnover conducted.
Other than the Annex SRO, the
night shift did not recall receiving information that the
reactor head vent was tagged out. There was no .mention of
the reactor head vent in the operator logs or plant status
logs .
1900 Just after night shift assumed the watch, the VCT began
automatically diverting to the holdup tank due to high water
level.
2200
PRT fully depressurized.
2230 Automatic VCT divert stopped. Approximately 4500 gallons
drained from the reactor vessel over a three and a half hour
period.
2301
Crew initiated make up to the VCT.
2316
STA inventory calculations showed a 4.6 gpm leak.
September 14, 1995
0311
Reactor vessel water level was increased to 20 feet to check
fo~ seal table *1eaks and subsequently drained to 18 feet.
Approximately 600 gallons were added and drained. - However,
this change in reactor vessel water level should have
required a 1600 gallon inventory change.
0547
Reactor vessel head detentioning commenced .
0630 Shift turnover occurred.
Day shift assumed that the reactor
head vent had been returned to service.
=- -
-
--=--=------===------ -----
-
4
0906
RCS makeup initiated.
0917
Unrelated to the draindown event, flooding was reported_ in
the Turbine Building.
0920
RVWL standpipe level dropped rapidly to 13.3 feet.
Operators secured letdown and increased charging.
1036
RVWL standpipe level at 18 feet after adding approximately
4500 gallons.
1100
RHV identified to be isolated and tagged.
2.2
Immediate Corrective Actions
2.3
Subsequent to the step change in RVWL standpipe level, and after
discovering that the RHV was tagged closed, the licensee initiated
several immediate actions.
The RHV valves were tagged open,
a
review of important safety system equipment configuration was
conducted to verify current status and* a Category 1 RCE was
initiated. Additional corrective actions based on RCE
recommendations are described later in this report.
Licensee's Root Cause Analysis
A Category 1 RCE was initiated in accordance with Virginia Power's
Root Cause Program Manual.
Licensee team members began conducting
interviews on September 14.
The RCE problem statement was to
investigate the unexpected reduction in reactor vessel water
level.
The team identified that the root causes of the event were
training and qualification weaknesses.
Operating personnel and
STAs did not consider the RVWL standpipe to be inoperable with the
head vent isolated. Shift personnel believed that the RVWL
standpipe would continue to provide reliable indication as long as
RCS level changes were not made.
The RCE was thorough, probing and self-critical. Operations
personnel interviewed were straightforward and candid.
Contributing causes to the event were:
Work practices: Personnel did not display a questioning
attitude. Proper assessment of available indications would
have identified the loss of RCS inventory and the isolation
of the head vent.
Additionally, the SS and*STA did not
maintain an overview of unit activities focusing on co~e
safety.
Written Communications: The mass balance procedure did not
provide for reconcJliation of individual inventory changes
nor did it account for all sources of inventory changes.
Additionally, isolation of the reactor vessel head vent was
3.
5
not documented in the unit log nor included on the written
turnover documents.
Contributing factors to the event included:
Work Practices: Status control of the reactor head vent was
lost. Neither the RO nor Unit SRO recorded the isolation of
the head vent in the unit log. Shift turnover was
ineffective.
Key members of the shift operating team were
not made aware that the reactor vessel head vent was
isolated.
Supervisory methods: Command and control of shift activities
by the Unit SRO and SS were inadequate to ensure that
equipment status and plant conditions were known and
understood by shift personnel and that plant conditions and
the main control room environment were appropriate for shift
turnover.
The Unit SRO and SS did not integrate the STA
into shift activities.
Written communications: There were no procedural controls
to remove and return the head vent to service when the head
vent spool piece was removed for cavity seal ring
i nsta 11 at ion .
Inspectors Review and Assessment of Causes {40500, 71707)
An NRC inspector was an observer on the RCE team.
The inspectors
independently identified causal factors related to the draindown event.
as the investigation developed.
The licensee's root cause analysis team
had effectively identified these areas as well.
The inspectors
concluded that the team members were conducting their investigation in
an independent and objective manner and that the team utilized the
procedures in thefr Root Cause Analysis Manual.
The inspectors determined that at 1500 on September 13, the reactor head
vent was isolated and tagged out to accommodate setting the reactor
cavity seal ring. This was done at a time when the RVWL standpipe was
the only method of level indication. The head vent remained tagged out
until 1100 on September 14.
There was no procedural guidance to alert
the operator of the status of the RVWL standpipe upon removing the *
reactor head vent from service. A review of the Reactor Operator's Log,
shift turnover sheet and Plant Status Log determined that these
processes failed to indicate the removal of this system from service.
Interviews with the September 13 night shift indicated that only the*
Annex SRO was aware that the RHV had been isolated. This lack of
configuration control caused the inoperability of the RVWL standpipe to
remain unidentified for approximately 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />.
A lack of knowledge about the relationship between t~e reactor head vent
and the RVWL standpipe prevented identifying the inoperability of the
. 6
RVWL standpipe.
The operators and STA interviewed did not consider the
RVWL standpipe inoperable with the reactor head vent isolated.
The RO who initiated the letdown did not understand the expected
response of the plant for the given conditions.
Interviews indicated
that he did not find the need to drain from the vessel unusual.
He
concluded that excess inventory was being supplied from the steam
generator tubes as they drained.
However, in this instance, all reactor
coolant loops were isolated and reactor vessel water level should not
have increased.
As a result of the inaccurate RVWL standpipe indication, the
Unit 1 RO increased the rate of letdown from the reactor vessel. This
continued from approximately 1710 to 2200 on September 13 .. The increase
in letdown caused VCT water level to increase and automatically divert
to the holdup tank. This resulted in draining approximately 4500
gallons from the vessel. Actual reactor vessel water level was five
feet lower than the operators thought.
From the review of the administrative controls associated with the
conduct of operating activities, several weaknesse~ relating to operator
performance were identified. These weaknesses were associated with SS
and SRO command and control of shift activities, communications, plant
status control, and shift turnover. Specifically on September 13:
a.
The SS and the unit SRO failed to maintain a broad perspective of
operational conditions affecting the facility.
RCS coolant
inventory was reduced by approximately 4500 gallons over about a
three and one half hour period without their knowledge of the
- activity and its affects on unit safety.
b.
The RO was not aware that reactor vessel water level was being*
lowered during letdown operations to maintain RVWL standpipe
indication. Additionally, shift supervision did not properly
monitor the operator performing this evolution which could affect
station safety.
c.
The departing day shift failed to make remarks on the required
shift relief checklist to inform the oncoming shift of important
inoperable equipment.
The reactor coolant head vent was isolated
rendering the only means of reactor vessel water level indication
Members of the departing and relieving shifts did not
discuss this important item affecting plant operations.
d.
The SS and unit SRO failed to enforce compliance with procedure 1-
0P-RC-011, Pressurizer Relief Tank Operations, revision 1, for
venting the PRT.
In addition to administrative controls, the inspectors reviewed controls
for PRT venting and WO release. Section 5.5 of
1-0P-RC-011 establishes the method for venting the PRT to the vent vent
system.
Through interviews, and review of logs and completed
4.
7
procedures, the inspectors determined that on September 13, the PRT was
vented to the containment without the use of this procedure.
The PRT
was vented by opening l-RC-ICV-5025 which established a vent path from
the PRT through pressure transmitter PT-1472 to containment.
A review
of the release permits for that day showed that there was no Gaseous
Group Release Permit for venting the PRT to the vent vent system as
required by step 5.5.4.
Interviews determined that there was no poly
hose connected from the vent tap l-RC-ICV-5025 to the nearest
containment purge exhaust as required by step 5.5.5. Operator
interviews indicated that the PRT was also being vented to the process
vent in accordance with Section 5.6 of the same procedure.
Venting to
the process vent requires that l-RC-HCV-1549, PRT Vent, be open whereas,
step 5.5.6.a required this valve to be closed.
At 1445 on September 13, Operations released WO 00316472,
Retract/Install Flux Thimbles, to disconnect the high pressure fittings
at the seal table. This work activity required that reactor vessel
water level be maintained at or below the reactor vessel flange level
per the controlling procedure.
During disconnection of the high
pressure seals, maintenance personnel identified leakage from the
connection and retightened the loosened connection and contacted
Operations.
The SS realized that the RCS was pressurized with
approximately 11 psig nitrogen pressure from the PRT and stopped work at
the seal table and recalled the WO to the control room annex.
Operations had signed but not released WO 00315444, PM: Remove, Ship,
Test,* Reinstall PRZ Safety Valves.
The SS also stopped work on this WO
and held the WO in the control room annex.
Subsequent to the stop work
being issued, Operations commenced venting the PRT at 1710 to establish
suitable plant conditions to allow release of the two WOs.
The fact
that the reactor vessel head vent was isolated and its effect on reactor
vessel water level indication was apparently not considered when the
decision to vent the PRT was made.
VPAP-2002, Work Request ~nd Work Order Task, Section 5,
Responsibilities, step 5.7, states that the SS is responsible for
reviewing and approving work request and WO tasks on permanent plant
structures, equipment and components and aligning plant systems as
required to ~upport WO task activities. Step 5~7 further instructed
that approval of a WO states that the SS acknowledges and approves that
the equipment is prepared for maintenance.
These requirements were not
met when WO 00316472 and 00315444 were signed on September 13.
Review of Safety Significance (71707)
The inspectors reviewed the safety implications of this event.
During
the event, RHR cooling was not jeopardized or lost as indicated by
constant RCS temperatures and RHR flow rates. Discussions with
operations personnel revealed-that pump amps remained* stable throughout
the event indicating that vortexing did not occur.
As a result of the
event the licensee unknowingly entered reduced inventory conditions
(defined as less than 15.7 feet in the reactor vessel) but did not enter
8
mid-loop conditions (defined as less than 12.5 feet in the reactor
vessel).
The inspectors reviewed the potential consequences associated with
reactor vessel water level being below the band identified in the
controlling procedure.
The PZR surge line connects to the centerline of
the C hot leg between the reactor vessel and the loop stop valve.
Procedure 1-0P-RC-004, Draining the RCS to Reactor Flange Level,
revision 6, defines mid-loop as 11.8 feet.
The surge line connection is
a 10.5-inch ID pipe. This would place the top of the surge line at
elevation 12.23 feet.
The .inspectors concluded that had actual reactor.vessel water level
dropped to less than approximately 12.23 feet the reactor vessel head
region would have vented through the C RCS hot leg to the PZR and then
to the PRT.
Venting of the reactor vessel head would have made
indicated vessel water level drop to actual vessel water level.
Review of Abnormal Procedure l-AP-27.00, Loss of Decay Heat Removal
Capability, revision 6, determined that the operating RHR pump would not
have been secured unless vortexing, as determined by pump amp and flow
oscillations, was indicated. The AP would have directed that reactor
vessel water level be increased to the acceptable band as determined by
Attachment 2 to the AP.
Attachment 2 would require that reactor vessel
water level be increased to greater than 12.63 feet for an RHR flow of
4000 gpm or 12.37 feet for an RHR flow of 1000 gpm.
The inspectors determined that minor vortexing might have occurred if
actual reactor vessel water level had dropped to the point of self
venting through the C RCS hot leg and PZR.
However, assuming operator
action to restore reactor vessel water level in accordance with 1-AP-
27.00, RHR flow would not have been lost. Additionally,* the operators
would have been alerted to the low level condition by a low level alarm
in the control room.
This conclusion was based on review of licensee
calculations, isometric drawings, a physical walkdown of the PZR surge
line inside containment, and discussions with licensee personnel.
5.
Regulatory Issues (71707)
In summary, the inspectors and the RCE team determined that there were
multiple examples of failure to follow procedures that contributed to
the event.
Weaknesses in training and fundamental understanding of
equipment performance were also noted.
These failures to follow
procedures are grouped into the following three categories: a)
administrative controls of operating activities, b) control of
maintenance, and c) control of PRT venting activities.
a.
10 CFR Part 50, Appendix 8, Criterion V, as implemented by the
Surry Operational Quality Assurance Program Topical Report (VEP-1-
5A), section 17.2.5, Instructions, Procedures, and Drawings,
requires that activities affecting quality of systems and
components be prescribed by and accomplished in accordance with
,
9
documented instructions, procedures or drawings of a type
appropriate to the circumstances.
For operational activities affecting quality these requirements
are implemented, in part, by VPAP-1401, Conduct of Operations,
revision l; OPAP-0005, Shift Relief and Turnover, revision 4; and
OPAP-0002, Operations Department Procedures, revision 3.
VPAP-1401 Section 6.1.12.b.l requires that the SS and the Unit SRO
maintain, as a matter of highest priority, the broadest
perspective of operational conditions affecting the facility.
VPAP-1401 Section 6.1.12.c.2 requires that all shift team members
be aware of station status at all times and that supervisory
personnel monitor the performance of shift personnel who could
affect station safety. *
OPAP-0005 Section 6.1.4 requires that the departing shift shall
make checks and remarks on the required shift relief checklist.in
a way that informs the relieving shift of information including
significant or important inoperable equipment including
instrumentation. Section 6.1.5 requires that the departing and
relieving personnel shall discuss important it~ms affecting plant
.operations .
OPAP-0002 Section 5.3.5 s~ates that the SS and unit SRO are
responsible for enforcing compliance with procedures as written.
Operational activities affecting quality were not accomplished on
September 13 in accordance with prescribed procedures as evidenced
by the following examples:
(1)
The SS and the Unit SRO failed to maintain a broad
perspective of operational conditions affecting the
facility.
RCS coolant inventory was reduced by
approximately 4500 gallons over an approximate three and one
half hour period without knowledge of the activities affect
on unit safety.
(2)
A Unit Control Room Operator was not aware that reactor
vessel water level was being lowered during letdown
operations to maintain RVWL standpipe indication.
Additionally, shift supervision did not properly monitor the
operator performing this evolution which could affect
station safety.
(3)
The departing day shift failed to make remarks on the
required shift relief checklist to inform the oncoming shift
of important inoperable equipment.
The reactor coolant head
vent was isolated rendering the only means of reactor vessel
water level indication inoperable.
Members of the departing
'
(4)
10
and relieving shifts did not discuss this important item
affecting plant operations.
The SS and Unit SRO failed to enforce compliance with
procedure l-OP~RC-011 for venting the PRT.
This item is identified as an Apparent Violation,
EEI 50-280/95-20-0l, Failure to Follow Operations Administrative
Procedures.
b.
Technical Specification 6.4 require that detailed written
procedures and instructions shall be provided for maintenance
activities which would have an effect on nuclear safety and that
they be followed.
VPAP-2002 partially implements these requirements for maintenance
activities.
VPAP-2002 Section 5.7.1 requires that the SS review and approve
- WOs on permanent plant structures, equipment, and components.
VPAP-2002 Section 5.7.2 requires that the SS align plant systems,
as required, to support WO task activities.
VPAP-2002 Section 5.7.4 requires that equipment be prepared for
maintenance prior to approval of a WO.
VPAP-2002 instructions for maintenance activities were not
followed for WO 00316472, Retract/Install Flux Thimbles, which was
approved by the SS on September 13 without the plant system
aligned or the equipment prepared for maintenance to support the
work activity, in that, the RCS was not depressurized.
This item is identified as an Apparent Violation,
EEI 50-280/95-20-02, Failure to Properly Control Maintenance
Activities.
c.
Technical Specification 6.4 require that detailed written
procedures and instructions shall be provided for activities which
would have an effect on nuclear safety and that they be followed.
Section 5.5 of procedure l-OP-RC-011 establishes the method for
venting the PRT to the vent vent system.
~owever, on September 13 at approximately 1830 hours0.0212 days <br />0.508 hours <br />0.00303 weeks <br />6.96315e-4 months <br />., approved
detailed written procedures were not used to perform venting of
the Unit 1 PRT as evidenced by the following:
(1)
No Gaseous Group Release Permit was obtained for venting the
PRT to the vent vent System as required by procedure l-OP-
RC-011 step 5.5.4.
'
11
(2)
A poly hose was not connected from valve l-RC-ICV-5025 to
the nearest containment purge exhaust as required by
procedure l-OP-RC-011 step 5.5.5.
(3)
l-RC-HCV-1549, PRT Vent was not closed as required by
procedure l-OP-RC-011 step 5.5.6.a.
This item is identified as an Apparent Violation,
EEI 50-280/95-20-03, Failure to Follow PRT Venting Procedure.
Within the areas inspected, three apparent violations were identified.
6.
Review of Continuing Outage Activities
The inspectors observed control room activities between September 16 and
18 to assess operations shift performance.
Shift turnovers and
briefings were monitored and plant status was reviewed.
During the
observation period, operators were completing the necessary
prerequisites for refueling operations.
The following procedures.were
reviewed and their implementat~on were observed:
l-OP-FH-001, Refueling Operations, revision 5.
l-OP-RC-007, Isolation and Drain of RCS Loops with RHR in Service,
revision 3.
l-OSP-SI-002, Charging Pump Head Curve Verification, revision 0 .
l-OP-RL-001, Putting the Reactor Cavity Purification System in
Service, revision I.
l-OP-VS-001, Containment Ventilation, revision 7
l-OP_T-CT-210, Refueling Containment Integrity, revision 5.
In general, plant operations were adequately controlled.
However,
several procedures were difficult to implement and resulted in one or
more operators being distracted.
For example, oper~tors desired to
establish containment purge through the HEPA/Iodine filters with no
other plant areas lined up through the filters. This was necessary to
increase the air flow from containment in order to reduce the activity
levels in the containment to below the radiation monitor high setpoint
for gaseous activity. This was also a prerequisite for refueling.
Several procedures had to be entered and the ventilation fans secured
and restarted to accomplish the lineup. A second example involved
placing* the RL system into service. A backflush of the reactor cavity
return line to the PRT was delayed because of inadequate driving head to
perform the flush.
The SS became directly involved in determining the
resolution to the problem.
Other observations included:
a.
During the performance of l-OP-FH-001, a reference procedure was
not in-hand for filling the reactor cavi~y to the I foot 6-inch
level. Operators were not aware of the procedure until questioned
by the inspectors. After reviewing the procedure, it was
determinect*that the method used for filling the cavity was one of
the two methods specified.
. ,
b.
12
A review of the Plant Status Log identified that the RHR system
status was not up to date. Specifically, the status log
incorrectly indicated that the A RHR pump was inoperable. These
observat i o*ns were discussed with the SS for corrective action.
In addition to the above, the inspectors noted several positive
observations.
During shift briefings the SSs emphasized command and
control, chain of command, shift responsibilities, and minimizing
distractions. Operators were attentive to the evolutions in progress
and knowledgeabl~ of plant and system status. The inspectors concluded
that prerequisites for refueling were proceeding in a safe and cautious
manner.
7.
Exit Interview
The inspection scope and findings were summarized on October 6, with
those persons indicated in paragraph 1.
The inspectors described the
areas inspected and discussed in detail the inspection results addressed
in the Summary section and those listed below.
Item Number
EEi 50-280/95-20-01
EEi 50-280/95-20-02
EEi 50-280/95-20-03
Status
Open
Open
Open
Description/(Paragraph No.)
Failure t~ Follow Operations
Administrative Procedures
(paragraph 5) .
Failure to Properly Control
Maintenance Activities
(paragraph 5).
Failure to Follow PRT Venting
Procedure (paragraph 5).
Proprietary information is not contained in this report. Dissenting
comments were not received from the licensee.
8.
Index of Acronyms
CFR
EEi
GPM
ID
NRC
OPAP
PZR
CODE OF FEDERAL REGULATIONS
ESCALATED ENFORCEMENT ITEM
GALLONS PER MINUTE
HIGH EFFICIENCY PARTICULATE AIR-FILTER
INNER DIAMETER
NUCLEAR REGULATORY COMMISSION
OPERATIONS DEPARTMENT ADMINISTRATIVE PROCEDURE
PRESSURIZER RELIEF TANK
PRESSURIZER
POUNDS PER SQUARE INCH GAGE
ROOT CAUSE EVALUATION
REACTOR HEAD VENT
, I
RL
ss
VPAP
REACTOR CAVITY PURIFICATION
REACTOR OPERATOR
REACTOR VESSEL LEVEL INDICATION SYSTEM
SENIOR REACTOR OPERATOR
SHIFT SUPERVISOR
VOLUME CONTROL TANK
VIRGINIA POWER ADMINISTRATIVE PROCEDURE
WORK ORDER