ML20134G907
| ML20134G907 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 10/21/1996 |
| From: | Mcwhorter R, Taylor D, Vandorn P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20134G755 | List: |
| References | |
| 50-338-96-09, 50-338-96-9, 50-339-96-09, 50-339-96-9, NUDOCS 9611130429 | |
| Download: ML20134G907 (27) | |
See also: IR 05000338/1996009
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Report Details
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Summary of Plant Status
Unit 1 began the inspection period at full power. On August 27, the unit
tripped from full power due to a rod control system failure (Sections 01.2 and
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02.3). The reactor was restarted on August 28, and the unit returned to
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commercial service on August 29. The unit returned to full power on August 30
and remained at or near full power for the remainder of the inspection period.
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Unit 2 began the inspection period at full >ower. On August 16. the unit
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began a coast down to a refueling outage.
_ ate on September 7 a unit
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shutdown was commenced from 85 percent power, and early on September 8, the
unit was removed from commercial service and the reactor was shut down for a
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scheduled refueling outage. On September 16, reactor defueling was completed,
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and the reactor remained defueled for the remainder of the inspection period.
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I. Operations
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Conduct of Operations
01.1 Daily Plant Status Reviews (71707)
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The inspectors conducted frequent control room tours to verify proper
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staffing, operator attentiveness, and adherence to approved procedures.
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The inspectors attended daily plant status meetings to maintain
awareness of overall facility operations and reviewed operator logs to
verify operational safety and compliance with Technical Specifications
(TSs).
Instrumentation and safety system lineups were periodically
reviewed from control room indications to assess operability.
Frequent
plant tours were conducted to observe equipment status and housekeeping.
Deviation Reports (DRs) were reviewed to assure that potential safety
concerns were properly reported and resolved. The inspectors found that
daily operations were generally conducted in accordance with regulatory
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requirements and plant procedures.
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01.2 Prompt On Site Response to Events (93702)
a.
Insoection Scope
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On August 27, the licensee notified the inspectors concerning a Unit 1
reactor trip. The unit tripped from full power while operators were
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performing 10P-17.1, Control Rod Operability, Revision 17. The
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inspectors reviewed control room conditions and operations following the
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trip. Additionally, the inspectors attended the licensee's post trip
review and reviewed trip data to independently verify that safety system
and operator performance was as expected throughout the event.
b.
Observations and Findinas
The inspectors found that the automatic trip was generated from the
Reactor Protective System (RPS) when a nuclear instrument negative rate
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9611130429 961021
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condition was detected. The trip occurred as o)erators began to move
the B control rod bank inward in accordance wit 1 1 0P-17.1. The
inspectors observed that operator response following the trip was good,
and procedures for responding to the trip were a3propriately
implemented. Although the inspectors observed t1at a large number of
people were present in the control room soon after the trip,
communications remained formal and the extra personnel were not
distracting to the operators.
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A review of trip data found that the trip signal was valid and was
caused by one or more dropped control rods. All safety systems
performed as designed for plant conditions during the trip.
During the
trip recovery, main condenser vacuum was lost. Operators were required
to use the main steam atmospheric dump valves to control reactor coolant
system temperature.
Plant startup and subsequent corrective actions are
discussed in Sections 01.3, 02.1 and M2.1.
c.
Conclusions
The inspectors concluded that safety system and operator response to the
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Unit 1 reactor trip was proper.
01.3 Unit 1 Restart Followina Reactor Trio (71707)
a.
Insoection Scoce
On August 28, after a reactor trip the day before, the inspectors
reviewed the licensee's corrective actions for the reactor trip's root
cause. Additionally, the inspectors observed operators performing
Unit 1 restart activities to ensure that operational activities were
conducted in accordance with plant procedures and TS requirements.
b.
Observations and Findinas
The inspectors observed that the licensee's investigations into the root
cause for the Unit 1 reactor trip found that a failure in the rod
control system had caused a drop of one group of the B control rod bank
when the rods were moved when performing 1 0P-17.1.
Repair efforts
identified a discrepancy in the signal from the rod control system logic
cabinet to the aower cabinet supplying the group
An interface card was
replaced, and t1e problem was corrected.
However, the problem could not
be duplicated by placing the suspect card back into the system. The
investigation )ostulated that the sus)ect card had either intermittently
failed or had aroken the circuit at tie card's edge connector. After
replacing the suspect card, technicians completed current order traces
for the entire system, and no other problems were found. The inspectors
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reviewed the current (amaerage) order traces before and after the card
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changeout and verified t1e problem's identification and correction.
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Additionally, the licensee conservatively decided to perform rod drop
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timing tests prior to unit restart, although test performance was not
recuired by TS or the licensee *s response to NRC Bulletin 96-01, Control
Roc Insertion Problems. The inspectors observed that tests were
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successfully completed (Section M1.2).
Formal root cause evaluations
were continuing at the inspection period's end. Additional reviews of
restart issues are discussed in Section 02.1.
The inspectors observed operators performing the Unit I reactor startup
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and found that o)erators properly used appropriate procedures. and were
cautious and metlodical during startup operations.
No significant
problems were encountered during the startup, and control room
communications and formality were good. The inspectors noted that
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appropriate supervisory and management personnel, as well as Oversight
personnel, were present to review startup activities.
c.
Conclusions
The inspectors concluded that the licensee's actions to correct the
cause of the Unit 1 trip and operator performance during reactor startup
were appropriate. A conservative decision was made to perform rod drop
timing tests prior to unit restart.
01.4 Trooical Storm Fran Response (71707)
a.
Insoection Scope
On September 5 and 6, the inspectors reviewed the licensee's response to
severe weather from Tropical Storm Fran. The inspectors compared the
licensee's response to plans for severe weather contained in the
Hurricane Response Plan, the site Emergency Plan, and in 0 AP 41, Severe
Weather Conditions, Revision 12.
b.
Observations and Findinas
The inspectors found that the licensee adequately reviewed the status of
alant equi > ment and activities in anticipation of the severe weather.
)rior to tie storm's arrival, outside areas were inspected for loose
equipment and debris. Outside efforts appropriately focused on areas
temporarily staged with equipment in pre >aration for the Unit 2
refueling outage. Additionally, althougl entry conditions were not met,
the Hurricane Response Plan was implemented as a precaution to ensure
that all appropriate actions were taken.
During the storm, the inspectors found that the licensee ap3ropriately
monitored the storm's progress and remained alert for possiale effects
on the facility. 0-AP-41 was entered as required during tornado
watches, and actions were taken to protect the facility from moderate
winds and heavy rains. As a result of local power outages caused by the
storm, power was lost to numerous emergency sirens (Section P1). No
site damage was sustained due to the storm.
c.
Conclusions
The inspectors concluded that the licensee properly prepared for and
responded to severe weather caused by Tropical Storm Fran.
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01.5 Unit 2 Shutdown for Refuelina (71707)
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a.
Inspection Scope
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On September 8, the inspectors observed operators placing Unit 2 in
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MODE 3 from MODE 2 in preparation for refueling. The inspectors
reviewed activities to ensure operations were conducted in accordance
with plant procedures TS requirements, and commitments made in response
to NRC Bulletin 96 01, Control Rod Insertion Problems.
b.
Observations and Findinas
The inspectors found that operators effectively controlled unit shutdown
activities.
Operating procedures were followed, and TS requirements
were complied with during the mode changes. Communications during
shutdown evolutions were good.
The inspectors observed that the unit was shutdown by manually tripping
all control rods into the core, and control rod drop time tests were
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performed immediately following the shutdown. On September 16, the
inspectors also observed rod drag tests being performed on approximately
ten control rods in the spent fuel pit (Section M1.2). These actions
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met licensee's commitments made in response to NRC Bulletin 96-01. No
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problems were identified during the rod control system testing.
c.
Conclusions
The inspectors concluded that operator control of 31 ant shutdown
activities was good, and the licensee complied wit1 commitments made in
response to NRC Bulletin 96 01, Control Rod Insertion Problems.
01.6 Control of Reactor Coolant System (RCS) Drain Down (71707)
On September 10, the inspectors observed RCS drain down activities
including observation of the pre job briefing and actual drain down to
the 74 inches above mid loop level. A thorough briefing was conducted
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which included an overview of the procedure, a review of drain down
curves, expectations of instrumentation during drain down,
communications, cautions, and specific personnel assignments. The
licensee exhibited good sensitivity to risks associated with drain down.
This was evidenced by excellent involvement between Reactor Operators
and Senior Reactor Operators (SR0s) and by careful procedural
compliance.
Several Shift Technical Advisors were also involved and
accurately predicted when instrumentation would come on scale. The
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prediction for when level would be observed in the sight glass was
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within approximately one minute and for the control room instrument,
which comes on scale at 95 inches above mid loop, was within ten
minutes. Two good initiatives were also noted. One was a rolling lit
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sign highlighting the time to boiling. Also, the licensee developed a
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recorder to do an inventory balance by measuring various tank levels
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involved in the drain down. The recorder did not calculate the total
inventory as expected, but did record the data to do so. Also the
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recorder did not print out digital information as originally intended.
The licensee indicated they intended to continue this initiative and
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modify the recorder as necessary to perform the calculation and to print
the calculation's results.
In summary, the RCS drain down was well
coordinated and personnel exhibited a good sensitivity to risk.
01.7 Unit 2 Refuelina Activities (71707)
a.
Inspection Scope
On September 14, the inspectors observed operators performing Unit 2
refueling activities to ensure that plant operations were conducted in
accordance with procedures and TS requirements.
b.
Observations and Findinas
During core off load, the inspectors verified that operators in
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containment properly used procedures 2-0P 4.1, Controlling Procedure for
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Refueling, Revision 32-P2: 2 0P 4.13 Fuel Transfer System. Revision 1:
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and 2 0P 4.15. Manipulator Crane, Revision 2.
Applicable TS
requirements were reviewed and found to be complied with for operable
equipment and for containment integrity. The inspectors observed that
communications were properly established between all stations and that
evolutions were supervised by a licensed SR0 in containment. Also, the
inspectors observed that fuel movements were being continuously tracked
by a reactor engineer in the control room.
c.
Conclusions
The inspectors concluded that refueling activities were properly
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conducted by operators.
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Operational Status of Facilities and Equipment (71707)
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02.1 Unit 1 Startuo Reviews
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a.
Insoection Scope
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On August 28, the inspectors attended a Station Nuclear Safety and
0)erating Committee (SNSOC) meeting to ascertain if problems following
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t1e August 27 Unit 1 trip were being adequately reviewed and resolved.
b.
Observations and Findinas
Prior to discussing the Unit 1 startup, the inspectors observed the
SNSOC discussing a proposed revision to security procedure SPIP 12.
Refueling / Major Maintenance Measures. The revision proposed changes to
the requirements for security badge display to allow wearing badges
inside Protective Clothing (PC) in containment. The inspectors observed
that a long discussion was generated by the proposed revision. The
discussion eventually led to members of the SNSOC proposing that the
procedure should be further revised to delete the requirement for
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displaying badges in other situations and/or throughout the plant
entirely. The inspectors observed that throughout the long discussions,
neither the individual presenting the revision nor the SNSOC members
displayed a knowledge of the actual requirements for badge display
contained in the Physical Security Plan (Revision 0, dated April 1,
1996). After the discussions appeared to be moving towards referring
the revision back to security for additional reviews, the inspectors
informed the SNSOC members that several of their pro)osals did not meet
the requirements of the Physical Security Plan and t1at they had failed
to recognize this due to their apparent lack of knowledge of the plan's
requirements.
The inspectors then observed the SNS0C consideration of the Unit 1 Post
Trip Review Report. The report was presented to the SNSOC for approval
following its completion by Shift Technical Advisors. As presented, the
inspectors observed that the report accurately analyzed alant
aerformance during the trip and corrective actions for t1e trip's cause.
iowever, the report's analyses of secondary plant equipment problems
encountered during the trip led to much discussion in the SNSOC meeting.
In discussing these failures, the SNS0C determined that the report
inadequately stated that a loss of secondary vacuum would be addressed
through the DR closeout process and inaccurately stated that a reheat
flow control valve,1-MS FCV-104C, had been repaired. The discussions
then centered on deciding what corrective actions were necessary for the
loss of secondary vacuum and for the failure of 1 MS FCV 104C to shut
following the trip. The SNS0C decided not to approve the report until
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additional corrective actions were taken for the loss of vacuum and
until a safety evaluation was completed for 1 MS FCV 104C being left in
a degraded condition.
Later that same day, the additional corrective
actions were completed, and the report was approved by the SNSOC.
The inspectors found that the SNSOC adequately ensured that problems
were being resolved prior to unit startup. However, the inspectors
questioned station management concerning the appropriateness of the
SNSOC directly making decisions about corrective actions to be taken for
equipment problems. The inspectors expressed concern that such active
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decision making was more appropriate for station management discussions
than for the SNSOC, which was intended to be a safety review authority.
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Licensee management stated that they believed the deliberations took the
track they did because the Post Trip Review Report should have been more
thoroughly reviewed prior to being presented to the SNS0C. Management
stated that they expected that such problems would be identified and
resolved by the Supervisor, Station Nuclear Safety (SNS) prior to the
SNSOC presentation. The inspectors also noted that the Post Trip Review
Report presented to the SNSOC had not been presented to the
Su)erintendent, Operations for concurrence signature prior to its
su) mission to the SNSOC.
In the SNSOC meeting, both the Supervisor,
SNS, and the Superintendent, Operations were seeing the report for the
first time as SNS0C members.
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Additionally, the inspectors found that VPAP 1404, Reactor Control.
Revision 0. Section 6.8.1.a. stated that the decision to re start a
reactor after a trip shall be made in accordance with VPAP-2804,
Start-Up Assessment. However, VPAP-2804 had never been issued although
four years had elapsed since the time that VPAP 1404 had been issued
(June 1992). This fact was noted in a supplemental page in VPAP 1404
which stated that until VPAP 2804 was issued, the " Start up Assessment
Review Package distributed by Nuclear Safety and Licensing" shall be
used. The inspectors noted that the Start up Assessment Review Package
was a document normally used for startup following refueling outages and
was not used for startups following reactor tri)s. The inspectors
discussed this issue with licensee management w1o directed station
personnel to complete VPAP 2804 as soon as possible.
c.
Conclusions
The inspectors concluded that the SNS0C considered a security procedure
revision without having an accurate knowledge of the applicable Physical
Security Plan requirements. The SNSOC ensured that adequate corrective
actions were completed prior to restart of Unit 1 following a reactor
tri ).
However, a Post Trip Review Report was not fully reviewed prior
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to >eing presented to the SNSOC which required the SNSOC to depart from
its normal review functions and plan and direct additional corrective
actions. An administrative procedure formally delineating the startup
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assessment process following a reactor trip did not exist.
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02.2 Unit 2 Containment Conditions
On September 9, the inspectors entered Unit 2 containment shortly
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following the shutdown to ascertain the status of equipment following
the long operating cycle. The inspectors found that material conditions
and cleanliness were good. A few small system leaks were identified.
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The inspectors noted that these small leaks had already been identified
by licensee personnel performing RCS leak identification surveillance
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tests. The inspectors concluded that safety systems in the Unit 2
containment were in good overall condition immediately following
shutdown.
On September 18 and 19, the inspectors reviewed activities inside Unit 2
containment. These activities did not promote good housekeeping
practices and potentially represented a challenge to personnel assigned
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to cleanup containment prior to restart.
Specifically, the inspectors
observed that cloth rags were on the pressurizer head in places where
insulation had been removed: materials such as plastic bottle tops and
work gloves were on top of supports and raceways below deck gratings:
and, tools and miscellaneous debris were laid on supports or dropped on
the floor. The inspectors observed no designated trash receptacles in
use in areas Aere work was being performed on the lower two levels of
containment. Housekeeping conditions and practices were discussed with
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plant management.
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02.3 NRC Notifications
a.
Insoection Scope
The inspectors reviewed the following licensee notifications to the NRC
to ascertain if the required reports were adequate, timely and proper
for the events.
b.
Observations and Findinas
On August 27. the NRC was notified as required by 10 CFR 50.72
concerning RPS and engineered safety feature actuations generated when
Unit 1 tripped from full power. The inspectors found that the
licensee's reporting actions were appropriate. Additional inspection
activities and findings are discussed in Sections 01.2, 01.3, 02.1 and
H2.1.
On September 6, the NRC was notified as required by 10 CFR 50.72
concerning the notification of off site authorities. Specifically, the
licensee notified surrounding counties and individuals of flood warnings
downstream of the Lake Anna Dam due to heavy rains from Tropical Storm
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Fran. The inspectors found that the licensee's reporting actions were
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appropriate.
On September 6, the NRC was notified as required by 10 CFR 50.72
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concerning a loss of a significant portion of the offsite emergency
notification system. Specifically, the licensee notified the NRC and
the Commonwealth of Virginia concerning the fact that 28 of 55 emergency
sirens were inoperable. The inspectors found that the licensee's
reporting actions were appropriate. Additional reviews are discussed in
Section Pl.
On September 8, the NRC was notified as required by 10 CFR 50.72
concerning the identification of a condition which could have prevented
the fulfillment of a system safety function needed for accident
mitigation. While shutting down Unit 2 for a refueling outage,
o)erators identified during a routine surveillance test that feedwater
cleck valve, 2 FW 62, would not prevent backflow.
The ins)ectors found
that the licensee's reporting actions were appropriate. T1e licensee
was required to submit a Licensee Event Report (LER) for this event, and
the inspectors will review the licensee's corrective actions after LER
issuance and prior to unit restart.
On September 10, the NRC was notified as required by 10 CFR 50.72
concerning a loss of emergency assessment capability lasting greater
than one hour. At 6:52 p.m., the Safety Parameter Display System (SPDS)
computer failed and could not be restored within one hour. Maintenance
personnel successfully returned the SPDS computer to operation at 10:24
p.m.
The inspectors monitored the licensee's reporting and corrective
actions and found them to be appropriate for the situation.
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On September 19, the NRC was notified concerning the identification of a
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condition which could have prevented the fulfillment of a system safety
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function needed for accident mitigation.
Due to questions raised by the
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inspectors, the licensee identified a procedural deficiency that could
have resulted in the dose to the control room personnel exceeding Fuel
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Handling Accident (FHA) analysis assumption. After further review the
licensee retracted this notification on October 15, 1996. The
inspectors reviewed the licensee's reporting actions and found that they
were appropriate. Additional reviews are discussed in Section E2.1.
c.
Conclusions
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Five NRC notifications required by 10 CFR 50.72 were properly made by
the licensee.
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Operator Knowledge and Performance (71707)
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04.1 Operator Error Durina Charoina Pumo Breaker Manioulation
a.
Insoection Scope
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On September 10 the inspectors reviewed an event in which all Unit 2
charging pumps were found to be simultaneously inoperable while the unit
was in MODE 5.
b.
Observations and Findinas
At approximately 12:35 p.m. on September 10, operators attempted to
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start charging pum) 2-CH P 1C and received a breaker disagreement light.
At the time, 2-CH-) 1C was considered to be the only aump operable to
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meet TS requirements.
Pump 2 CH P-1A was available, aut its emergency
power supply, the 2H Emergency Diesel Generator, was inoperable. Pum)
2 CH-P 1B was unavailable due to a tagout. Operators dispatched to t1e
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breaker identified that the charging motor )ower control switch was in
"off", and the breaker springs indication slowed that the springs were
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discharged. Operators ) laced the power control switch in "on", but the
springs still did not c1arge as expected. The pump was declared
inoperable and TS 3.1.2.1 and 3.1.2.3 action statements were reviewed
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and complied with. The inspectors responded to the control room shortly
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after identification of the problem and verified that TS action
statement compliance was maintained throughout the time that all
charging pumps were inoperable.
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Initial investigations into the problem found that the breaker was
racked into the cubicle earlier the same day during an evolution to swap
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the pump power supply from the H to the J bus. Pump 2-CH P-1C was
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declared as the only operable pump after racking in the breaker at
5:25 a.m.
The operator performing the evolution completed procedure
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0 0P-26.9, 4160 volt Breaker Operation, Revision 9, including initialing
steps indicating that the switch was "on" and that the springs indicated
charged.
In accordance with the procedure, since repositioning the
switch was not required, no independent verification of switch position
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was required. After finding and verifying that the breaker
configuration was incorrect, the licensee concluded that the operator
erred when signing off the ste)s.
During interviews, the operator
informed his supervision that le did not remember the details concerning
procedure performance.
The licensee also investigated the reason for the springs failing to
charge when the switch was re positioned to "on".
The breaker was found
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to have an intermittent problem which was preliminarily determined to be
caused by a slight misalignment in the internal relay switch crank. The
breaker was replaced with a spare breaker which operated satisfactorily.
The pump was returned to operable status at 3:07 p.m.
The inspectors found that the operator's error led to the plant
operating without any charging pumps. Although the breaker had an
intermittent mechanical problem which prevented the springs from
charging, the operator error was a missed opportunity to identify the
problem. As corrective action, the operator was disciplined in
accordance with the licensee's programs, and the procedure was enhanced
to require independent verification for the power control switch.
The inspectors reviewed the procedural requirements for the evolution.
Unit 2 TS 6.8.1 requires that written arocedures be established
implemented and maintained, including Jy reference to Appendix A of NRC
Regulatory Guide 1.33. Revision 2, procedures for operation of the
chemical and volume control systems. This requirement was implemented
in part by 0 0P 26.9, Section 5.2.5, which required operators racking in
4160 volt breakers to verify the power control switch in "on" and to
verify that the breaker springs are charged. Contrary to this
requirement, the operator did not verify the power control switch in
"on" or the breaker springs charged. As a result, the only available
Unit 2 charging pump was unknowingly inoperable for approximately seven
hours. This licensee identified and corrected violation is being
treated as an NCV, consistent with Section VII.B.1 of the NRC
Enforcement Policy (50 339/96009 01).
c.
Conclusions
An NCV was identified for an operator's failure to follow procedures
when racking in a charging pump breaker. As a result, the only
available Unit 2 charging pump was unknowingly inoperable for
approximately seven hours during shutdown conditions.
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Quality Assurance in Operations (40500)
07.1 Oversicht Meetina
On September 18, the inspectors met with Oversight personnel.
Issues
discussed included Oversight activities and findings since previous
meetings. Copies of recent audits were provided for review. The
inspectors also observed Oversight personnel observing plant activities
on numerous other occasions during the inspection period and met briefly
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with them to discuss their observations. The inspectors concluded that
the Oversight organization was continuing to assess station performance
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effectively.
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08
Miscellaneous Operations Issues (92901, 92700)
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08.1
(Closed) Unresolved Item (URI) 50 339/96007-01 (EA 96 292): Review
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Comoliance With 10 CFR 50.54k Reouirements For Operator Presence at
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a.
Inspection Scope
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On August 5, the inspectors were informed by licensee managers that a
licensed operator had inadvertently left the Unit 2 controls area for a
short time period. During this inspection period, the inspectors
reviewed the event's details, the licensee's administrative controls
over Operator at the Controls (0ATC) movements, and compliance with
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regulatory requirements.
b.
Observations and Findinas
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The inspectors ascertained the following event details through
interviews with operators and management:
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On August 5, at approximately 3:30 p.m., the Backboards Operator
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properly relieved the 0ATC for a meal break.
The individual
carried the Backboards Operator's portable phone to the 0ATC area.
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A) proximately two minutes after relief, the 0ATC made a personal
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pione call using the Backboards Operator's portable phone.
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During the OATC's call, the other party requested a phone number
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for calling back, and the 0ATC proceeded to the portable
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base unit at the Backboards Operator's desk to retrieve t1e phone
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number. The Backboards Operator's desk was a few feet outside the
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0ATC's designated work area.
It was estimated that the individual
was away from the 0ATC's work area for less than five seconds.
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The OATC's actions were observed by an observer who had entered
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the control room to gather information related to a licensee
self assessment activity. The observer informed the Unit SR0
concerning the OATC's actions. The Unit SR0 had not directly
observed the OATC's actions due to involvement in discussions with
maintenance personnel.
- After the problem was identified, the 0ATC was relieved of the
0ATC and Backboards Operator duties pending further
investigations. Deficiency Report N 96140 was initiated to
identify and track corrective action.
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The next day, August 6, the individual was directed to report for
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Fitness for Duty (FFD) chemical testing.
FFD chemical testing
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results were later found to be negative. The individual's access
to the protected area and qualification for licensed duties were
temporarily suspended pending further corrective and disciplinary
action.
On August 20 and 21, the inspectors discussed these findings with
licensee management. The inspectors were informed that the licensee
concluded that the individual's actions were negligent of duty and were
probably influenced by outside personal problems.
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disciplinary actions were taken in accordance with the licensee's
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established program.
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Additionally, the inspectors discussed with licensee management
administrative requirements and policies regarding conducting wrsonal
business while at the controls.
Procedure OPAP-0007. Control
Room
Activities, Revision 6 Paragraph 6.2.3, stated, "Only activities
essential to sup)orting station o>eration should be conducted in the
control room."
rurther, Paragrap16.2.4 stated, "Non-job related
2
discussions should be minircized to prevent any possible interference
with conduct of the shift or monitoring of station parameters." No
clear requirements were identified prohibiting the placement of personal
calls by OATCs. Station management stated that the individual's actions
2
in this case were clearly unacceptable, but that there were instances
where personal phone calls to or from the 0ATC would be acceptable
(e.g., urgent or emergency situations). Management indicated that
policies for phone use while on duty were being reviewed, and additional
j
guidance would be issued. Management also informed the inspectors of
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additional actions which were being taken to evaluate on shift 0ATC
4
activities to ensure that the event did not reflect a widespread problem
with inappropriate activities being performed by 0ATCs.
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The inspectors reviewed the licensee's controls over 0ATC movements. To
ensure that an operator remained present at the controls, the licensee
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had an established program for controlling 0ATC movements delineated in
OPAP-0007.
Procedure OPAP-0007, Section 6.3.6 and Attachment 1, defined
i
three areas for operator movements: the work area, the limited time
area, and the restricted work area. The 0ATC was allowed to leave the
work area and enter the limited time area only to acknowledge
annunciators, initiate corrective actions, to obtain reactor coolant
'
pump vibration readings, or to obtain drawings. The 0ATC was not
.
'
allowed to enter the restricted work area unless properly relieved.
The inspectors found that the 0ATC's movements during the event took him
out of the designated work area through the limited time area and
approximately two feet into the restricted work area. There were no
'
valid reasons for the 0ATC to enter the limited time area, and a proper
l
turnover was not conducted before the 0ATC entered the restricted work
~
area. During the time the 0ATC was absent from the work area, no other
licensed operators were present in the work area.
The nearest other
licensed operator was the Unit 2 SR0 who was ) resent at the SR0 desk a
few feet outside and overlooking the 0ATC wort area.
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10 CFR 50.54k requires that licensed operator be present at the controls
.
at all times during facility operation. This requirement is implemented
in part, by 0 PAP 0007 Section 6.3.6, which designates areas where a
licensed operator must be present during facility operation. Contrary
to this requirement, a licensed operator was not present in the
'
designated Unit 2 controls area for a short time period. This
licensee identified and corrected violation is being treated as an NCV,
consistent with Section VII.B.1 of the NRC Enforcement Policy
(50-339/96009 02).
'
c.
Conclusions
An NCV was identified involving a licensed operator not being present at
the Unit 2 controls for a short time period contrary to 10 CFR 50.54k
requirements.
08.2 (Closed) LER 50 338/96005:
Reactor Trio on Hiah Neaative Flux Rate
This LER discussed the August 27 Unit 1 trip from full power due to a
rod control system failure. The licensee's response to the event and
corrective actions for the associated equipment failures were reviewed
and are discussed in Sections 01.2, 01.3, 02.1, 02.3 and H2.1.
II. Maintenance
M1
Conduct of Maintenance
M1.1 2H Emeraency Diesel Generator (EDG) Post Maintenance Insoection and
Testina
a.
Insoection Scoce (627071
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On September 18 and 19, the inspectors observed inspection activities
and testing performed on the 2H EDG.
b.
Observations and Findinas
During the routine refueling outage inspection of the 2H EDG, the
licensee identified that the top and middle compression rings on number
seven lower piston were worn. All three compression rings were replaced
on this piston. The inspectors observed the 2H EDG operate during the
break-in period and witnessed visual examination of new rings by an
engineer and the vendor representative after the 2H EDG had operated at
65 percent load.
After the 65 percent load run, the 2H EDG exhaust manifold for the
number seven cylinder was removed to allow inspection of the new rings.
The inspectors observed that the number seven cylinder walls and lower
1
piston skirt were less lubricated that the other cylinders. This was
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discussed with the engineer and vendor representative. They also
examined the upper piston for proper lubrication. They concluded that
i
there was no problem.
'
After the 100 percent load run, the inspectors again looked at the
number seven cylinder. This time the oil coating appeared normal. The
inspectors had no further concerns in this area. Based upon operating
,
data, including crank case vacuum, taken during the break-in runs and
the licensee's and inspectors' examinations, there were no indications
'
of a problem with the new compression rings.
c.
Conclusions
i
The 2H EDG post-maintenance inspections and testing were adequate to
demonstrate that the new compression rings on the number seven lower
piston were functioning correctly.
M1.2 Control Rod Surveillance Observations (61726)
a.
InsDection Scooe
On August 28 and September 8 and 16. the inspectors observed technicians
and engineers performing 1/2 PT-17.2, Rod Drop Time Measurement,
>
Revision 13/12 P1. The test was performed, on Unit 1 prior to rectart
following a reactor trip and on Unit 2 immediately following a shutdown
for a refueling outage, to meet the licensee's commitments made in
'
response to NRC Bulletin 96 01.
In addition, the inspectors observed
control rod drag testing of Unit 2 discharged fuel assemblies.
b.
Observations and Findinas
The inspectors observed that technicians properly followed procedures in
obtaining the rod drop traces.
Formal communications between the
control room, the relay room, and the rod drive room were maintained
throughout the repetitive rod drop sequences. The inspectors reviewed a
sampling of rod drop traces and verified that measurements were being
accurately recorded and that the traces were correctly shaped. The
inspectors also observed that reactor engineers were reviewing the
traces to verify that rod recoil was recorded. The inspectors reviewed
the test procedure and verified that the licensee was meeting
commitments made in response to NRC Bulletin 96 01. The test results
were satisfactory for all rods.
On September 16, the inspectors observed drag testing of the final eight
control rods being tested from the Unit 2 off loaded core.
In addition,
the c'?ta for the other 40 control rods and fuel assembly pairs were
reviewed. The maximum force required to move the control rod through
the dash pot region and the area just above this region was recorded.
All measured values were 40 lbs or less which was well below the 100 lb
acceptance criteria.
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c.
Conclusions
The inspectors concluded that rod drop timing tests were aroperly
performed for both units. The inspectors also verified t1at the Unit ?.
control rod drag testing results were well within the acceptance
criteria.
M1.3 Larae Bore Snubber Testina (61726)
a.
Inspection Scope
During the Unit 2 refueling outage, the first two large bore snubbers
functionally tested failed to lockup in one or both directions. The
inspectors observed subsequent test activities, reviewed test
procedures, previous test records, procurement documents,
specifications, engineering test reports, and TS requirements.
b.
Observations and Findinas
On September 15, 1,000 kip snubber 2-RC-HSS-11A failed to lockup during
both the compression and tension activation tests conducted in the
field. On September 16, 1,900 kip snubber 2 RC HSS 01A failed to lockup
during its field compression activation. The inspectors observed the
bench test of snubber 2-RC HSS-11A. Although the snubber locked up in
both directions during the bench test, the acceptance criteria was not
met. The speed at which lockup occurred was a> proximately 28 inches per
minute as compared to a maximum allowed 20 incies per minute. A spare
snubber replaced this snubber in Unit 2.
Testing was subsequently performed on other installed and spare snubbers
with various results.
However, the licensee noted that more recent
tests were more likely to have acceptable results. Thus, except for
snubber 2-RC-HSS-11A, it was hyaothesized that earlier test results may
have resulted from problems wit 1 the test apparatus or testing
technique.
On September 19, the ins)ectors observed a spare 1,900 kip snubber,
designated as spare 06, aeing field tested. The snubber met the
acceptance criteria and performed satisfactorily.
Subsequent to the report period, snubber 2-RC HSS 11A was disassembled
and found to contain metal shavings in the hydraulic fluid. These metal
shavings apparently caused this snubber's improper functioning. Based
on this result, all 12 large bore snubbers installed in Unit 2 were
tested. The inspectors were informed that the data from these twelve
test, as well as, test results taken during previous outages were
reviewed by engineering and the results presented to the SNS0C prior to
restart of Unit 2.
The inspectors' review of data taken during 3reviously outages indicated
that snubber 2 RC HSS 001B in 1992 and 2-RC iSS-001C in 1993 did not
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clearly demonstrate that lockup had occurred during compression
activatlen testing. An Unresolved Item (URI) is being identified to
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perform additional reviews of the anomalies observed in large bore
snubber test data (50 339/960009 03).
c.
Conclusions
i
The licensee functionally tested all 12 large bore snubbers installed in
Unit 2 and considered that they were operable. An URI was identified to
review anomalies in large bore snubber test data taken early in this
refueling outage and during previous outages.
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M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Eauioment Problems Followina Unit 1 Reactor Trio (62703. 62707)
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a.
Inspection Scope
On August 27 and 28, the inspectors reviewed conditions following a
Unit 1 reactor trip to ensure the licensee was taking appropriate
actions to identify and resolve equipment problems.
b.
Observations and Findinas
The inspectors found that after the trip, the following significant
equipment problems occurred:
i
Main Feedwater Regulating Valves (MFRVs) leaked by the seats.
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Operator action was required to isolate two of the three MFRVs.
,
Steam dump 1 MS-TCV 1408B indication limit switch failed.
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Operators were momentarily concerned that the dump was not
o>ening, and operator action was required to locally verify that
t1e dump was properly responding.
Extraction steam flow control valve 1-MS FCV-104C failed to close.
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Operator action was required to manually isolate the valve to
limit RCS cooldown.
Condenser vacuum was lost due to inadequate turbine gland sealing
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steam. Operators were required to use the steam generator
atmospheric relief valves to control RCS temperature.
Several secondary reliefs lifted and several failed to properly
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reseat. Operators were required to locally isolate various
components to reduce the flow of water into the turbine building
The inspectors verified that all the above problems were appropriately
resolved prior to unit restart. The ins >ectors noted that concerning
the loss of condenser vacuum, operators lad previously opened the gland
steam header dump bypass valve on both units in order to reduce gland
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steam pressure at full power. The pressure was postulated to be high
.
due to excessive leakoff from the turbine valve glands. This
configuration required operator action on a trip to close the bypass
,
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valve to maintain gland steam header pressure. This had been identified
as an Operator Work Around (0WA) and added to the licensee's OWA list on
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June 11, 1996, as a low priority (category C) OWA.
However, trip
,
response or other procedures had not been modified to alert operators
concerning the need to shut the dump bypass valve following a trip.
.
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c.
Conclusions
The inspectors concluded that following the Unit 1 reactor trip, five
secondary plent equipment problems occurred requiring operator.
compensatory actions.
.
M4
Maintenance Staff Knowledge and Performance
.
M4.1 Foreian Material Exclusion (FME) Controls (71707)
On September 18, the inspectors observed that the limit switch
compartment cover for 2 SI-MOV 2865A, the Unit 2 A accumulator discharge
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isolation valve, was not installed. Approximately ten feet away (over
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to one side and above the valve), an individual was grinding on a
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support for the instrument tubing for this accumulator. This was called
to the attention of a nearby Health Physics (HP) technician who stopped
the work until the valve switch compartment could be covered. The
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inspectors subsequently observed personnel performing "V0TES" testing on
another accumulator discharge valve and discussed the missing cover with
them. The individuals indicated that they had removed the cover earlier
in the day to do testing and were not aware of the grinding work in the
area. The individuals returned to 2 SI MOV-2865A and replaced the
cover. This item was discussed with Maintenance supervision as
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representing a lack of sensitivity to FME issues and as a potential for
equi) ment degradation. The licensee indicated that the valve would be
chec(ed out prior to its return to service.
III. Enaineerina
E2
Engineering Support of Facilities and Equipment (37551)
E2.1 Seismic Concerns Reaardina Containment Particulate and Gaseous Radiation
Monitors (RMs)
a.
Insoection ScoDe
The inspectors reviewed concerns raised by the licensee involving the
seismic qualifications for the containment particulate and gaseous RMs
to ascertain if the licensee complied with equipment operability
requirements.
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b.
Observations and Findinas
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On September 10, the inspectors found that DR N 96 1743 was originated
!
by engineers to document identification of a concern with the
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qualification of containment particulate and gaseous RMs to remain
operable following a seismic event. The DR originated from reviews of
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Potential Problem Report (PPR) 96 019 which questioned how the RMs could
remain operable followiw a seismic event given that a loss of the
non seismically qualified instrument air supplies to the system's
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containment su) ply and return trip valves could result in isolation of
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the RMs. The )PR originated from questions raised during training on
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lessons learned from an event earlier in 1996 where the RMs were
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identified to be inoperable to meet TS 3.4.6.1 requirements for
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seismically qualified leakage detection systems due primarily to
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non safety related power supplies (LER 50-338, 339/96004: NRC Inspection
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Report 50 338, 339/96 07). On Seatember 11, a second DR, DR N 96 1783,
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Jas originated by Nuclear Oversig1t personnel who identified that a
similar issue existed for the containment air recirculation fan dampers
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which were a supporting system to the RMs, but were not classified as
safety related or seismically qualified.
After identifying the problem, the inspectors verified that the licensee
took actions required by TS 3.4.6.1 for inoperable leakage detection
systems on Unit 1.
The licensee planned to modify the system to ensure
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the system met seismic requirements prior to exceeding the 30 day TS
!
allowed outage time. The TS 3.4.6.1 requirement was applicable only in
MODES 1 - 4 and did not apply at the time to Unit 2 which was in MODE 5.
'
The licensee was required to submit an LER for the problem, and the
inspectors will further review the problem's significance when closing
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the LER.
The licensee also reviewed the issue prior to Unit 2's entry into MODE 6
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and concluded that seismic qualification was not required for the
'
monitors to meet TS 3.3.3.1 and 3.9.9 requirements for operability as a
part of the automatic containment isolation system. The inspectors
reviewed the basis for this conclusion with licensee engineers. The
engineers provided the inspectors with the licensee's proposed TS change
and the NRC's Safety Evaluation Report (SER) related to a February 1996
.
TS change which allowed refueling to be conducted with the containment
,
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personnel air lock doors open.
In those documents the design bases for
'
a Fuel Handling Accident (FHA) were clarified. The clarification also
stated that the containment isolation system was non safety related.
Additionally, the documents referenced a facility original licensing
SER, NUREG 0053 Supplement 7, which, in the context of discussing a FHA
in containment, referred to the monitors as non safety grade. The
inspectors concluded that the licensee was correct in stating that the
RMs did not have to be seismically qualified to support TS operability
requirements in MODE 6.
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During the review of the documents related to the February 1996 TS
change, the inspectors found a discrepancy with the licensee's
implementation of the change.
In the change request (Virginia Power
,
letter to the NRC from J. O'Hanlon dated October 17, 1995), the licensee
stated that upon verbal notification of a FHA or upon receipt of a high
radiation signal, the control room would be manually isolated and the
bottled air su) ply initiated. The inspectors reviewed procedure
0 AP 30, Fuel r ilure During Handling, Revision 4, and found that it did
a
not direct operators to initiate the control room bottled air su3 ply
during a FHA. The inspectors informed the licensee concerning t11s
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finding. After review, the licensee concluded that this was a
i
discrepancy and changed 0 AP 30 to correct the discrepancy prior to
commencing core on load for Unit 2.
i
The inspectors also reviewed the licensee *s Safety Evaluation (SE) for
the TS change, 95 SE 0T-34, and found that it made several assumptions
in concluding that the change did not represent an unreviewed safety
question.
Included in these assumptions were that actions would be
taken to develop an abnormal procedure to require operator action to
manually isolate the control room and initiate bottled air. Also, the
SE indicated that action would be taken to train operators on the
i
importance of isolating the control room within two minutes. Neither of
these actions were completed by the licensee from the time of
implementing the change on February 27, 1996, until identified by the
inspectors.
During that period, the licensee had performed core
alterations on at least two occasions: Unit 1 core on load from
February 29 to March 3,1996, and Unit 2 core off load from September
14 to 16, 1996. On both occasions, core alterations were performed with
the personnel hatch doors open.
The inspectors then reviewed the significance of not pressurizing the
control room bottled air system during a FHA. The inspectors found that
the TS change request used this assumption during basis calculations to
demonstrate that the dose to control room operators during a FHA would
remain less that the limit required by 10 CFR 50 General Design Criteria (GDC) 19. The licensee's amendment request analysis found that with
control room pressurization, inleakage was assumed to be 10 cfm and the
resultant estimated dose to the thyroid of control room operators was
19 rem. The inspectors concluded that for the assumptions made in the
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amendment analysis, without control room pressurization, the inleakage
l
would be significantly higher, and the dose to the thyroid of control
i
room operators would likely go from 19 rem to a value exceeding the
GDC 19 design criteria of 30 rem (5 rem whole body equivalent).
!
On September 24, the inspectors discussed the safety significance with
licensee fuel and analysis engineers. The engineers conceded that
without pressurization, the control room inleakage would likely be
significantly higher. As a result, if the basis calculation was
performed with all other factors the same, the GDC 19 design criteria
for dose to the thyroid would probably be exceeded.
However, the
engineers pointed out numerous conservative assumptions in the analyses.
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These included:
The analysis assumed containment was not isolated.
Procedures
-
included direction to immediately isolate containment manually.
The analysis took no credit for control room ventilation charcoal
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filters during the first hour.
Procedures included direction to
immediately start the fans / filters on recirculation during the
first hour.
The analysis assumed containment release concentrations were
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present at the control room intake. Weather and plant layout
,
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would actually reduce the concentrations likely to leak into the
control room.
The analysis contained numerous additional conservative source
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term assumptions with regard to fuel composition and amount of
!
radioactivity released.
l
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The inspectors found that the conservative assumptions meant that had a
FHA actually occurred, the dose to control room operators would likely
not exceed the GDC 19 limits. However, if all assumptions used in the
basis calculation actually occurred, the GDC 19 limit would likely have
been exceeded.
TS 6.8.1 requires that written procedures be established, implemented
and maintained, including by reference to Appendix A of Regulatory
Guide 1.33. Revision 2, procedures for irradiated fuel damage while
refueling. The licensee's TS change request and the NRC's TS Amendment
Nos.198 and 179, stated that upon notification of a FHA, the control
room bottled air supply would be initiated by operators within two
minutes. Contrary to these requirements, from February 27, 1996, until
September 19, 1996, procedure 0 AP 30 was inadequate in that it did not
,
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direct operators to initiate the control room bottled air supply within
two minutes of notification of a FHA. This is identified as Violation
(VIO) 50 338, 339/96009 04.
c.
Conclusions
A violation was identified concerning an inadequate abnormal procedure.
The procedure did not contain direction to operators to initiate the
control room bottled air system during a FHA as assumed in the bases for
a TS amendment allowing refueling with the containment personnel hatches
l
open.
E7
Quality Assurance in Engineering Activities
E7.1 Review of Vodated Final Safety Analysis Report (UFSAR) Commitments
'
A recent discovery of a licensee o>erating their facility in a manner
contrary to the UFSAR description lighlighted the need for a special
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focused review that compared plant practices, procedures and/or
parameters to the UFSAR descriptions. While performing the inspections
l
discussed in this report, the inspectors reviewed the applicable
i
portions of the UFSAR that related to the areas inspected. The
l
inspectors verified that the UFSAR wording was consistent with the
1
observed plant practices, procedures and/or parameters.
j
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IV. Plant Support
R1
Radiological Protection and Chemistry (RP&C) Controls (71750)
,
a.
Inspection Scope
l
On Se)tember 14, the inspectors observed technicians performing portions
!
of a ligh radiation area survey on the refueling deck in containment.
b.
Observations and Findinas
l
The inspectors observed that during off load of the first fuel assembly,
the assembly was sto) ped in the transfer tube and radiation surveys were
l
performed to verify ligh radiation area boundaries in containment. The
l
inspectors observed portions of these surveys on the refueling deck in
i
containment. No discrepancies were noted in survey techniques.
l
However, the inspectors observed several ina)propriate work practices by
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a contract HP technician.
In an area near t1e fuel transfer system
operating panel, the technician attempted to remove a radiation area
sign from the plastic mesh FME area barrier in order to place it on a
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high radiation barrier rope. When the technician found that the sign
was attached to the mesh with tie wraps and could not be pulled loose by
'
hand, the technician unzipped both life jacket and PC coverall and
reached inside the PCs to obtain a pocketknife. The technician then
i
used the small knife to cut the tie wraps and remove the sign. When
cut, one of the tie wraps flew approximately twenty feet in the air and
fell through a grating near the refueling cavity transfer canal and into
4
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the lower containment levels. The other tie wrap fell near the sign and
was retrieved. This event was observed by an inspector and a reactor
o>erator who was part of the refueling crew. The ins)ectors notified
l
tie refueling SR0 and HP supervision concerning the caservation, and DR
,
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N-96-1902 was submitted documenting the event.
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The inspectors reviewed the requirements for FME controls. Unit 2 TS
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6.8.1 requires that written procedures be established imalemented and
maintained, including by refarence to Appendix A of NRC Regulatory Guide
,
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1.33, Revision 2, procedures for refueling and core alterations. This
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requirement was implemented in part by VPAP 1302. Foreign Material
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Exclusion Program, Revision 8, and 2 0P 4.1 which delineated the
licensee *s FME controls in the reactor cavity area during refueling.
Procedures VPAP-1302 and 2 0P-4.1 required that all items which fit
through a 2 3/4 inch hole must be logged by the cavity watch prior to an
individual's entry into the FME control area. Contrary to these
requirements, the HP technician had failed to inform the ca'lity watch
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that the small pocketknife was in his aossession prior to entry to the
.
FME controls area and prior to using t1e knife inside the area. This
failure constitutes a violation of minor significance and is being
treated as an NCV consistent with Section IV of the NRC Enforcement
Policy (50 339/96009 05).
i
c.
Conclusions
A non cited violation was identified for an HP Technician's failure to
follow procedures for FME control during refueling.
P1
Conduct of Emergency Preparedness Activities (71750)
On September 6 and 7, the inspectors reviewed the licensee's res)onse to
the discovery that 28 of 55 emergency sirens were inoperable. T1e
.
sirens were found to be ino>erable when they failed to respond during a
i
test during Tropical Storm
ran (Section 02.3). The sirens were
degraded due arimarily to losses of local power to the sirens caused by
'
damage from t1e storm. The licensee contacted the Virginia State
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Department of Emergency Services and verified that alternate
notification means (route alerting) remained available in accordance
with the site Emergency Plan. The licensee informed the inspectors when
a
a majority of the sirens were returned to service the following day.
The inspectors concluded that the licensee properly resolved the
.
problem.
,
S1
Conduct of Security and Safeguards Activities (71750)
S1.1 Unescorted Visitor (71750)
On September 19 at approximately 12:45 p.m., the inspectors entered the
2H EDG room and observed that the vendor representative, visitor badge
V-0018, was not with his escort.
He was on the control side of the EDG
and was not observable by the three badged employees on the other side
of the EDG. The unescorted visitor accom3anied the inspectors to the
other side of the EDG where a member of t1e plant staff assumed escort
responsibilities for the individual. The person who had been watching
the visitor re entered the 2H EDG room a few moments later. The person
had left the area to obtain work materials.
The inspectors reported the event to security supervision.
Security
personnel subsequently counseled the involved personnel on
escort / visitor responsibilities. When the licensee issued a DR
concerning this observation, another example was included which had been
identified by the licensee on September 15. This second example also
involved personnel in the 2H EDG room.
Pending additional review of
3revious unescorted visitor occurrences, this item is identified as an
JRI (50 339/96009 06).
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V. Manaaecent Meetinas
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4
X1
Exit Meeting Summary
The inspectors 3 resented the inspection results to members of licensee
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management at t1e conclusion of the inspection on September 27 and
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October 18, 1996. The licensee acknowledged the findings presented.
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The inspectors asked the licensee whether any materials examined during the
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inspection should be considered proprietary. No proprietary information was
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identified.
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PARTIAL LIST OF PERSONS CONTACTED
Licensee
C. Funderburk, Superintendent, Outage and Planning
E. Grecheck, Assistant Station Manager, Operations and Maintenance
,
J. Hayes. Superintendent. Operations
.
D. Heacock, Assistant Station Manager, Nuclear Safety and Licensing
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P. Kemp, Supervisor, Licensing
,
T. Maddy, Superintendent, Security
'
W. Matthews, Station Manager
M. McCarthy, Director, Nuclear Oversight
'
D. Roberts, Supervisor, Station Nuclear Safety
4
H. Royal, Superintendent, Nuclear Training
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3
R. Saunders, Vice President. Nuclear Operations
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D. Schappell, Superintendent, Site Services
,
'
R. Shears, Superintendent, Maintenance
J. Smith, Superintendent, Station Engineering
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A. Stafford, Superintendent, Radiological Protection
,
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INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 40500: Effectiveness of Licensing Controls in Identifying, Resolving, and
j
.
Preventing Problems
IP 61726:
Surveillance Observations
IP 62703:
Maintenance Observations
-
IP 62707: Maintenance Observations
-
IP 71707:
Plant Operations
!
IP 71750:
Plant Support Activities
IP 92700: Onsite Follow up of Written Reports of Nonroutine Events at Power
,
Reactor Facilities
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IP 92901:
Followup
Plant Operations
IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors
!
ITEMS OPENED, CLOSED, AND DISCUSSED
,
i
Opened
50 339/96009 01
Failure to Follow Procedure for Racking In
Charging Pump Breaker (Section 04.1).
50 339/96009 02
Failure to Meet 10 CFR 50.54k Requirements for
Operator Presence at Unit Controls
(Section 08.1) (EA 96 292).
50 339/96009 03
Review Anomalies in Large Bore Snubber Test Data
(Section M1.3).
.
. . . .
-
-. . - -
.
_ - . - -
.
. . . - . .
.
_ . -
. _ - .
--
. .
.
'
,
'
,
,
25
r
50 338, 339/96009 04
Inadequate Procedure for Fuel Handling Accident
(Section E2.1).
'
50 339/96009 05
Failure to Follow Procedures For FME Control By
HP Technician Near Reactor Cavity (Section R1).
>
50 339/96009 06
Review occurrences of unescorted visitors
,
(Section S1.1).
'
Closed
,
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50-339/96007 01
Review Compliance With 10 CFR 50.54k-
'
Requirements For Operator Presence at
l
Unit Controls (Section 08.1) (EA 96 292).
l
'
50-339/96009 01
Failure to Follow Procedure for Racking In
Charging Pump Breaker (Section 04.1).
l
50 339/96009 02
Failure to Meet 10 CFR 50.54k Requirements for
Operator Presence at Unit Controls
j
(Section 08.1) (EA 96 292).
i
50 339/96009 05
Failure to Follow Procedures For FME Control By
HP Technician Near Reactor Cavity (Section R1).
L
j ',
Reactor Trip on High Negative Flux Rate
l
(Section 08.2).
.
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!
!
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