ML20155A191
| ML20155A191 | |
| Person / Time | |
|---|---|
| Site: | North Anna  |
| Issue date: | 09/15/1988 |
| From: | Caldwell J, Cantrell F, King L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20155A185 | List: |
| References | |
| 50-338-88-22, 50-339-88-22, NUDOCS 8810050242 | |
| Download: ML20155A191 (13) | |
See also: IR 05000338/1988022
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UNITED STATES
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NUCLEAR REGULATORY COMMISSION
o
REGION 11
%e'.,.[
101 MARIETTA ST., N.W.
ATLANTA. GEORGIA 30323
Report Nos.:
50-338/88-22 and 50-339/88-22
Licensee: Virginia Electric and Pcwer Company
Richmond, VA 23261
Docket Nos.:
50-338 and 50-339
License No:.:
Facility Name: North Anna 1 and 2
Inspection Conducted:
fuly 16 - August 19, 1988
Inspectors:
/fh[
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J. E. Caldwell, Seni6/ es ent Inspector
Da'te Signed
kh
9h Y
L. Ff.~ King, Resident Inpf4 tor
Date S'igned
~ d.
9//.f/7Y
Appioved by:
F. S.'Cantrell, Section C) W
Dafe Signed
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Division of Reactor Projects
SUMMARY
Scope:
This routine inspect.f on by the resident inspectors involved
the
following areas:
plant status, maintenance, surveillance, ESF
walkdown, operational safety verification, operating reactor events,
licensee event report (LER) followup, and licensee action on previous
enforcement matters. During the performance of this inspection, the
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resident inspectors conducted reviews of the licensee's backshif t
operations on the following days - July 18, 25, 26, and August 1, 2,
4, 5, 7, 10, 11, and 12.
Results: Within the areas inspected, one violation was identified with three
examples for failure to follow procedure, and one Inspector Followup
Item (IFI).
(0 pen) IFI 338/88-22-01, followup on the cause of Unit 1
"C"
main
feedwater isolation va've failure to close (paragraph 3).
(0 pen) Violation 338/88-22-02, failure to follow a containment entry
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procedure with three examples (paragraph 6).
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8810050242 880913
ADOCK 05000338
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REPORT DETAILS
1.
Persons Contacted
Licensee Employees
M. Cowling, Assistant Station Manager
J. Downs, Superintendent, Administrative Services
- R. Orfsco11, Quality Control Manager
R. Enfinger, Assistant Station Manager
G. Gordon, Electrical Supervisor
L. Hartz, Instrument Supervisor
D. Heacock, Superintendent, Technical Services
- G. Kane, Station Manager
M. Kansler, Superintendent, Maintenance
- T. Maddy, Supervisor, Security
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T. Porter, Superintendent, Engineering
J. Stall, Superintendent, Operations
A. Stafford, Superintendent, Health Physics
F. Terminella, Quality Assurance Supervisor
D. Thomas, Mechanical Maintenance Supervisor
- 0. VandeWalle, Corporate Licensing
Other licensee employees contacted included engineers, technicians,
operators, mechanics, security force members, and office personnel.
- Attended exit interview
NRC Management Site Visit:
M. Ernst, Deputy Regional Administrator;
C. Hehl, Deputy Director, Division of Reactor Projects (DRP); B. Wilson,
Chief, Reactor Projects Branch 2, DRP; H. Berkow, Director, Projects
Directorate II-2, Nuclear Reactor Regulation (NRR);
L. Engle, Project
Manager, NRR; and C. Pate11, Project Manager, NRR visited the North Anna
site on July 27, 1938. The visit involved a tour of the station and the
presentation of the SALP results to the licensee.
2.
Plant Status
Unit 1
Unit 1 began the inspection period operating at approximately 100% power.
On August 6, Unit 1 tripped from 100*. power due to a steam flow / feed flow
mismatch with a low water level in the "B" steam generator (S/G) (see
section 7 for details). Prior to the trip, the unit had been operating at
approximately 100% power since March 25, 1988.
On August 8,
the unit
restarted and, following the secondary chemistry holds and instrumentation
repairs, achieved 100% power on August 13.
Unit 1
operated at
approximately 100% power for the remainder of the inspection period.
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REPORT DETAILS
1.
Persons Contacted
Licensee Employees
M. Bowling, Assistant Station Manager
J. Downs, Superintendent, Administrative Services
"R. Driscoll, Quality Control Manager
R. Enfinger, Assistant Station Manager
G. Gordon, Electrical Supervisor
L. Hartz, Instrument Supervisor
D. Heacock, Superintendent, Technical Services
- G. Kane, Station Manager
M. Kansler, Superintendent, Maintenance
- T. Maddy, Supervisor, Security
T. Porter, Superintendent, Engineering
J. Stall, Superintendent, Operations
A. Stafford, Superintendent, health Physics
F. Terminella, Quality Assurance Supervisor
D. Thomas, Mechanical Maintenance Supervisor
- D. VandeWalle, Corporate Licensing
Other licensee employees contacted included engineers, technicians,
operators, mechanics, security force members, and office personnel.
- Attended exit interview
NRC Management Site Visit:
M. Ernst, Deputy Regional Administrator;
C. Hehl, Deputy Director, Division of Reactor Projects (DRP); B. Wilson,
Chief, Reactor Projects Branch 2, DRP; H. Berkow, Director, Projects
Directorate 11-2, Nuclear Reactor Regulation (NRR);
L. Engle, Project
Manager, NRR; and C. Patell, Project Manager, NRR visited the North Anna
site on July 27, 1938. The visit involved a tour of the station and the
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presentation of the SALP results to the licensee.
2.
Plant Status
Unit 1
Unit 1 began the inspection period operating at approvimately 100% power.
On August 6, Unit 1 tripped from 100% power due to a steam flow / feed flow
mismatch with a low water level in the
"B" steam generator (S/G) (see
section 7 for details). Prior to the trip, the unit had been operating at
approximately 100% power since March 25, 1988.
On August 8,
the unit
restarted and, following the secondary chemistry holds and instrumentation
repairs, achieved 100% power on August 10.
Unit
1 operated at
approximately 100% power for the remainder of the inspection period.
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Unit 2
Unit 2 began and ended the inspection period operating at approximately
100*4 power.
Both Units
On July 18, the licensee requested and received discretionary enforcement
from the NRC to allow them to exceed the Technical Specification (TS)
containment temperature limit of 105 degrees Fahrenheit. At the time of
the request, both containments were approximately 103 degrees Fahrenheit
due to the inoperability of the mechanical chiller during an extended
period of 95-100 degree waather.
The licensee had submitted a TS
amendment to the NRC in March 1988 to' change the TS containment tempera-
ture limit to 120 degrees Fahrenheit.
Based on this submittal, the NRC
granted the licensee discretionary enforcement to allow the containment
temperature to exceed 105 degrees Fahrenheit, but not to exceed 110
degrees Fahrenheit for the time necessary to repair the mechanical
chiller. On July 19, the mechanical chiller was repaired.
Technically,
the discretionary enforcement was not required since only Unit 2 exceeded
the 105 degree F limits and was returned to less than the limit well
within the TS action statement time limit. Both units' containments are
being maintained around 100 degrees.
On July 27, 1988, Region II and headquarters personnel presented the SALP
results to the North Anna Station management and staff.
The presentation
was conducted at the site in the North Anna Information Center (NAIC)
auditorium.
The Virginia Electric and Power Company personnel who
attended the presentation included J. Ferguson, President and C.E.O. ; W.
Stewart,
Senior Vice President, Power Operations;
D. Cruden, Vice
President, Nuclear Operations;
G. Kane, Station Manager, North Anna;
R. Saunders, Manager, Nuclear Programs;
J. Wilson, Manager, Nuclear
Operations Support; N. Hardwick, Manager, Nuclear Licensing; R. Hardwick,
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Manager, Quality Assurance; R. Enfinger, Assistant Station Manager, North
Anna; M. Bowling, Assistant Station Manager, North Anne., and approximately
150 other station and corporate personnel.
NRC representatives are
identified in paragraph 1.
3.
Maintenance (62703)
Station maintenance activities affecting safety related systems and
components were cbserved/ reviewed to ascertain that the activities were
conducted in accordance with approved procedures, regulatory guides and
industry codes or standards, and in conformance with the Technical
Specifications (TS).
On August 4,
the inspectors witnessed the licensee adjust the inboard
packing on motor driven auxiliary feedwater pump 2-FW-P-3A.
The packing
adjustment was performed per Mechanical Maintenance Procedure MMP-C-GP-1,
Inspection and Repair of Safety Related Pumps in General. The only noted
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problem was identified by the operator and mechanics performing the work.
The outboard packing was also leaking excessively and needed adjustment.
Since the work order only addressed the inboard packing adjustment, the
mechanics were unable to adjust the outboard packino without violating
procedures.
The pump was secured, and a work request was initiated to
adjust the outboard packing during the next scheduled pump operation. The
leak was not of a nature to affect the operability o'/ the pump. No other
problems were noted.
On August 7, the inspectors witnessed portions of the MOVATS test of the
"C" main feedwater line motor operated isolation valve. The maintenance,
performed per Electrical Maintenance Procedure EMP-P-MOV-3, Predictive
Analysis of MOVs, was necessary because the valve failed to fully close
during the reactor trip that occurred the day before (see discussions of
this event
in the end of section 7).
The electrician informed the
inspectors that the valve's limit switches for both opening and closing
were of f and needed adjustment.
The closing limit switch appears to be
the cause of the valve failing to fully close when the automatic closure
signal was received. No problems were identified with the performance of
the maintenance.
The inspector has requested the licensee provide
information concerning the cause of limit switches being out of
adjustment.
This will be identified as Inspector Follow-up Item (IFI
338/88-22-01).
On August 11, the inspectors witnessed the calibration of feedwater flow
instrument 1-FW-FI-1486 for the "B" main feedwater line per Instrument and
Control Proedure ICP-FW-1-F-1486, SG 1B Feed Flow Protection Channel IV.
The calibration was being performed because the feed flow indication in
the control room was out of the TS required tolerance. Unit 1 was in the
process of a startup at the time, and the licensee had placed the
protection channel associated with the feed flow instrument in trip. The
inspector observed that the technicians were unable to calibrate the
instrument.
Folicwing the determination that the calibratien procedure
could not be completed successfully, the licensee attempted to repair the
transmitter.
This repair was also unsuccessful, consequently, the
licensee replaced the feed flow transmitter,
calibrated the new
instrument, and placed the instrumentation back on linc. No problems were
identified by the inspector,
ho violations or deviations were identif'.ed.
4.
Surveillance (61726)
The inspectors observed / reviewed TS required testing and verified that
testing was performed in accordance with adequate procedures, that test
instrumentation was calibrated, that limiting conditions for operation
(LCO) were met, and that any deficiencies identified were properly
reviewed and resolved.
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The licensee informed the inspectors that on July 23, during the perfor-
mance of 1-PT-31.7.2, Pressurizer Level Channel II (L-460) Functional
Test, an Eutomatic isolation of the charging system letdown line occurred.
The licensee investigated the event and determineo the cause of the
isolation was an inadequate procedure.
The procedure required the
operator to olace a defeat switch in the wrong position, and consequently,
the automatic isolation of letdown occurred when the test signal was
generated.
Further investigation by the licensee determined that
1-PT-31.7.2 had recently been revised, and this was the first time the
procedure had been used since the revision. A review showed that the
switch position was correct in the previous procedure, consequently, the
revision and suosequent int.dequate review resulted in an inadequate
procedure.
Following the letdown isolation, the operators were able to re-establish
letdown withot;t causing a transient on the unit. A review by the inspector
did not identify any safety concerns reltting to the event.
However,
TS 6.8.1.c requires that w itten procedures to be established, imple-
mented, and maintained covering surveillance and test activities of safety
related equipment. The failure of the licensee to establish and maintain
an adequate procedure to perform a surveillance on the pressurizer
level channel without resulting in automatic action is a violation of
Since this violation was identified, investigated, and
corrected by the licensee and meets the criteria of 10 CFR 2, Appendix C,
for licensee identification, this item will be considered a Licensee
Identified Violation (LIV 338/88-22-03, Failure to Prov'de Adequate Test
Procedure).
LIVs are considered first-time occurrence violations which
meet the NRC enforcement policy criteria for exemption from issuance of a
These items are identified to allow for proper
evaluation of corrective actions in the event that similar events occur in
the future.
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On July 25, the inspectors witnessed the surveillance test on the Unit 2
"B"
component cooling water pump.
The test was conducted per test
procedure 2-PT-74.28, Component Cooling Pump (2-CC-P-18).
The inspectors
did not identify any problems associated with the performance of the test.
The licensee informed the inspectors that there was an inadvertent
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automatic start of the 2-CH-P-1A charging pump on July 26.
This pump,
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which is also the high head safety injection (HHSI) pump, was autometi-
cally started due to a safety injection related undervoltage signal.
The
inadvertant start was caused by personnel error during tne performance
of surveillance test procedure 2-PT-36.9.1.J. Degraded Voltage / Loss of
Voltage Functional Test, 2J Bus.
The personnel error involved the
improper reinstallation of the relay cover on relay 27C such that the
contacts remained closed even af ter tht: relay was de-energized.
This
relay, 27C, which becomes energized on an undervoltage signal, or in
this case, a test signal, will start the Unit 2 "A"
and "C" charning
pumps.
Prior to the initiation of the test signal, the licensee p aced
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the "A" charging punp in pull to lock, by procedure, to prevent the punp
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from automatically starting. The "C"
charging pump was already operating.
Following the initiation of the test signal, test personnel verified that
the relay 27C was energized, replaced the relay cover, and removed the
test signal which de-enerigized relay 27C.
The licensee took the "Ad
charging pump controller out of the pull to lock position. As soon as the
controller was taken out of pull to lock, the Unit 2
"A" charging pump
automatically started.
The operator verified that this pump was not
required to be operating, and secured the pump by placing the controller
back in pull to lock.
The licensee investigated the event and found that the cover on relay 27C
had been misaligned when it was reinstalled. Following the removal of the
cover and proper reinstallation, the automatic start signal no longer
existed.
Using a similar relay, the licensee demonstrated to the
inspectors the sequence of events which could lead to this situation. The
licensee was able to install the relay cover in such a way to cause the
relay contacts to remain closed even though the relay was not energized.
The licensee determined the event to be reportable.
A four-hour report
was made and an LER was issued.
The inspectors will followup on the
corrective actions, and close out the issue during the review and close
out of LER 88-02, Inadvertent Engineering Safety Features System
Actuation.
On August 2,1988, the inspe-tors witnessed test 2-PT-71.1, Steam Driven
Auxiliary Feedwater Pump and Valve Test.
The test was performed
satisfactorily.
On August 17, the inspectors witnessed portions of the surveillance test
on one of the hydrogen recombiners per 1-PT-68.1.2, Hydrogen Recombiner
Functional Test 2-HC-HC-1.
During the performance of the test, several
problems were identified associated with non technical issues.
The first
problem involved steps 4.9.1. 4.9.2, 4.13, 4.14, 4.20, 4.21, 4.33, and
4.34 which identified the motor control switches for the blower and the
cooling fan differently than the actual label plates. The second problem
involved the placement of the master control switch (HS-1) in the start
position, but the procedure did not take the switch out of start.
The
licensee corrected both of these discreoancies with a procedure deviation.
The inspectors did not identify any other problems.
On August 18, the inspectors witnessed 2 .0T-57.1A, which was the 2-SI-P-1A
low head safety injection pump test.
The test
was
performed
satisfactorily.
No violations or deviations were identified.
5.
ESF System Walkdown (71710)
The following selected ESF systems were verified operable by performing a
walkdown of the accessible and essential portions of the systems on
August 11, 1988.
Using procedure 1-0P-21.9A, Va've Checkoff Control Room
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Bottled Air Pressurization System, the resident inspector walked down the
control room bottled air system.
The following comments were noted:
a.
Fill connection sample valves 1-CA-33 and 2-CA-36 and, the pigtail
isolation valves 2-CA-31-1 thru 2-CA-31-42 were observed not to be
labeled.
b.
Bottles
1-CA-1-7,
1-CA-1-9,
and 1-CA-1-10 are labeled out of
sequence.
No violations or deviations were identified.
6.
Operational Safety Verification (71707)
By observations during the inspection period, the inspectors verified that
the control room manning requirements were being met. In addition, the
inspectors observed shif t turnover to verify that continuity of system
status was maintained. The inspectors periodically questioned shift
personnel relative to their awareness of plant conditions.
Through log review and plant tours, the inspectors verified compliance
with selected TS and LCOs.
In the course of the monthly activities, the resident inspectors included
a review of the licensee's physical security program. The performance of
various shifts of the security force were observed in the conduct of daily
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activities to include: protected and vital areas access controls;
searching of personnel, packages and vehicles; badge issuance and
retrieval; escorting of visitors; patrols; and compensatory posts.
On a regular basis, radiation work permits (RWP) were reviewed and the
specific work activity was monitored to assure the activities were being
conducted per the RWPs. Selected radiation protection instruments were
periodically checked and equipment operability and calibration frequency
was verified.
The inspectors kept inform e
>n a daily basis, of the overall status of
icant safety matter related to plant
both units and of any sd
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operations. Discussions
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held with plant management and various
members of the operatite- teaff on a regular basis. Selected portions of
operating logs and data s
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The inspectors conducted various plant tours and made frequent visits to
the control room. Observations included: witnessing work activities in
progress; verifying the status of operating and standby safety systems and
equipment; confirming valve positions, instrument and recorder readings,
and annuciator alarms; and observing housekeeping.
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On August 8, the inspector witnessed Unit 1 startup to criticality.
No
problems were encountered and the reactor was critical within the
estimated critical position.
On August il, the inspectors witnessed the
licensee increasing power above the 5% chemistry hold point and cnanging
from Mode 2 into Mode 1.
When the licensee reached approximately 12%
power, just prior to placing the generator on line, Channel IV of the
"B"
feed flow instrumentation was determined to be inoperable.
The licensee
placed the protection channel in trip and decided to correct tne
instrument problem prior to placing the turbine generator on line (see the
end of paragraph 3). During the repair of the feed flow instrument, the
inspector observed that Channel III of the "C" steam flow instrumentation
had failed low.
Subsequently, the licensee placed the steam flow
protection channel
in trip.
Also,
during
the
time while
the
instrumentation was being repaired, the inspector observed the licensee
vent pressure from the Primary Relief Tank (RPT) using Operating Procedure
1-0P-5.7.
On August 12, following the repair of the feedwater flow instrument, the
licensee, af ter verifying that the prob'eem with the steam flow instrument
was not in the instrumentation, decided to continue with the startup with
the steam flow protection channel in trip. With the unit at approximately
20 percent power, Channel III of "C"
steam flow instrumentation came back
into specification and was taken out of trip.
The startup continued
without further instrumentation problems. The licensee has written 1 work
request for the "C" steam flow instrumentation to determine the cause of
the problem.
This work request will be performed during the next
available outage.
On August 9, 1988, at 1618, a first aid emergency was declared at Unit 1
containment hatch. Unit 1 was in Mode 2 at less than 5 percent power. A
contractor employee experienced heat exhaustion.
He was administered
oxygen and carried to the Health Physics office, where a nurse examined
and released him to return to duty.
The entry was made at 1528 by two
health physics technicians and two contractor personnel to inject
Furmanite into a leaky packing gland on a disc pressurization valve
(RC-187) for the "A" cold leg isolation valve.
The inspector requested and received the maintenance history on 1-RC-187.
The maintenance history indicates that 1-RC-187 had never had the packir.g
replaced and the valve had not been scheduled to be repacked.
Futher
review of the event by the inspectors revealed that two previous entries
had been made to determine the problems identified with the valve.
One
entry identified the leak path and the other entry was an attempt to
adjust the packing to stop the leak. Af ter adjusting the packing as much
as possible, the valve still leaked and a decision was made to inject
Furmanite into the valve. A review of the containment entry procedures by
the resident inspector indicated the following:
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a.
Attachment 1 of Administrative Procedure (AP) 20.9, Containment
Ingress and Egres', is a subatmospheric containment entry checklist.
The resident obtained a copy of the checklist while the containment
was being exited (on August 9). Only the portion of the checklist up
to incore detectors tagged out was initialed. The inspector was told
that several other steps had been completed but not signed off. Step
7.1 of the procedure requires that each department comolete the
applicable sections of attachment 1 as the steps are completed. The
failure of the licensee to follow AP 20.9 and complete the checklist
as required will identified as a violation (338/88-22-02).
b.
In the entries made on August 8 at 0924 and 1618, the required wet
bulb temperatures were not documented and the calculated stay times
were not determined as required by step 7.14 of Administrative
Procedure 20.9.
The failure of the licensee to follow AP 20.9 will
be identified as an additional example of violation (338/88-22-02).
7.
Operating Reactor Events (93702)
The inspectors reviewed activities associated with the below listed
reactor events.
The review included determination of cause, safety
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significance, perfcemance of personnel and systems, and corrective action.
The inspectors examined instrument recordings, computer printouts,
operations journal entries, scram reports, and had discussions with
operations, maintenance and engineering support personnel as appre?riate.
At 2257 on August 6, 1938, Unit 1 of the North Anna Power Station tripped
due to a steam flow / feed flow mismatch with a coincident low steam
generator (S/G) water level in the
"B"
S/G. Just prior to the reactor
trip, the operators had placed the shunt reactors (additional inductive
loads) in service at the request of the load dispatcher.
These shunt
reactors are loads directly of f of the 34.5 kv buses which supply the
emergency buses through the reserve station service transformers (RSST).
Following the connection of the shunt reactors, the 34.5 kv buses
decreased in voltage, and consequently, so did the 4160 volt emergency
buses which are the secondary side of the RSSTs (34.5 kv/4.16 kv
transforners). The design of the RSSTs include an automatic tap changer
on the secondary (emergency bus) side of the transformer which will
compensate for decreases in the primary side voltage by changing the taps
necessary to maintain required voltage on the secondary side. However, in
this case, the licensee determined that the automatic tap changer for the
RSST supplying the Unit 1 J emergency bus did not operate. The 1 J bus
sensed a degraded voltage and separated itself from the RSST.
The 1 J
emergency diesel generator (EOG) started and loaded onto the bus as
designed.
The problem with the transfer of the 1 J emergency bus to the 1 J EDG in
itself did not result in the reactor trip. However, some of the non-vital
loads on the 1 J bus, which are shed during a degraded voltage situation,
involve some secondary system steam valves which closed along with the
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feedwater recirculation valves which resulted in a steam /feedwater
This transient resulted in a demand on the feedwater
regulating valves to close. The "B" feedwater regulating valve failed to
reopen resulting in the
team flow / feed flow mismatch and low S/G water
level trip signal. An inspection by the licensee revealed that the "B"
feedwater regulating valve stem had broken, separating the disc from the
actuator. Consequently, once the valve went closed the actuator could no
longer reopen the valve. The licensee has experienced problems with feed
regulating valve stems breaking in the past, and modifications have been
performed on both Unit 1 and Unit 2 feedwater regulating valves.
The
modifications on the Unit 2 valves are more advanced, including a bigger
stem, and appear to have solved the problem. The licensee had scheduled
the same modifications on the Unit 1 valves during the next refueling
outage.
Following the trip the Unit 1 feedwater regulating valves were inspected
and repaired as necessary.
The "B" feedwater regulating valve stem and
actuator were replaced.
All of the systems operated as required with a few exceptions. The major
problem following t'ie trip was the f ailure of the "C" main feedwater
isolation valve to fully close.
The failure of the feedwater system to
fully isolate resulted in a cooldown below the normal 547 degrees F to
approximately 538 degrees F with a resulting pressure decrease to 1870
psig. The licensee manually isolated feedwater and maintained S/G levels
with the auxiliary feedwater system which was already in operation. The
problem relating to the failure of the "C" feedwater isolation valve to
close is discussed in Section 3 of this report.
Followup will be via
inspector follow-up item (IFI) 338/88-22-01.
The only other problems associated with the trip were several valve
position indicators whici, did not function properly; a problem with one of
the steam dump valves, and the failure of the General Electric Transient
Analysis recording systems to actuate.
The inspectors will followup on
the licensee's actions and closeout these issues based on the LER review
and closecut.
No violations or deviations were identified.
8.
Licensee Event Report (LER) Follow-up (90712)
The following LERs were reviewed and closed. The inspector verified that
reporting requirements had been met, that causes had been identified, that
corrective actions appeared appropriate, that generic applicability had
been considered, and that the LER forms were complete. Additionally, the
inspectors confirmed that no unreviewed safety questions were involved and
that violations of regulations or technical specifications (TS) conditions
had been identified.
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LERs that identify violation (s) of regulation (s) and that meet the
criteria of 10 CFR, Part 2, Appendix C,Section V are identified as
License.2 Identified Violations (LIV) in the following closecut paragraphs.
LIVs are considered first-time occurrence violations which meet the NRC
enforcement policy criteria for exemption from issuance of a Notice of
Violation. These items are identified to allow for proper evaluation of
corrective actions in the event that similar events occur in the future,
a.
(Closed) LER 338/87-12, Rev. 0:
Inadvertent Partial Solid State
Protection System Actuation
A safety injection slave
elay (K602) was energi:ed during the
performance of Reactor Protection and Engineered Safety Features
Response Time Test (Periodic Test 36.5).
The root cause of the
inadvertent actuation was procedure inadequacy. The procedures have
been revised and approved by SNSOC.
b.
(Closed) LER 338/87-14, Rev. 0:
Loss of RCS Inventory While In Cold
Shutdown
The licensee has issued an operations directive and station manager's
memo notifying personnel to be aware of any testing not covered in
the Final Safety Analysis Report (FSAR).
It outlines the steps to be
taken for a 10 CFR 50.59 evaluation.
Training has also been
accomplished for the operators on loss of inventory.
Other
corrective actions are being tracked by the violations identified in
inspection report 87-21.
c.
(Closed) LER 338/87-21, Rev. O and Rev. 1:
Loss of Environmental
Qualification of SI Accumulator Tank Pressure Transmitters
STO-GN-0001, Instructions For DCP Preparation, has been revised to
provide additional guidance and instructions for design change
package (DCPs) which require the installation of equipment per the
manufacturer's installation instructions,
d.
(Closed) LER 338,339/87-23, Rev. O and 1: Kaman Process Vent Normal
Range Radiation Monitor Exceeded T.S. Action Statement.
The monitor has been repaired.
An alternate method using the
Westinghouse monitor was available to accomplish automatic actions.
Additionally, the Nuclear Research Corporation radiation monitors
continued to operate throughout this event as the Technical
Specification required preplanned alternate monitoring method on the
process vent release path,
e.
(Closed) LER 338/87-17, Rev. 1:
Steam Generator Tube Rupture
Responses will be tracked under the items identified in AIT report
338/87-24 dated August 28, 1988.
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f.
(Closed) LER 338/88-15, Rev. 0:
RHR Pumps Not Tested During Steam
Generator Tube Rupture Outage
A station deviation report was submitted to notify the responsible
department of the missed surveillsnce and to schedule it for the next
time the unit is in Mode 5.
The ISI Pump and Valve program was
reviewed to ensure there were no other missed surveillances.
This
item is identified as a LIV (338/83-22-04) for failure to conduct a
surveillance on schedule. Based on the licensee's corrective action
and program this LER and LIV are closed.
9.
Licensee Action on Previous Enforcement Matters (92702)
(Closed) Licensee Identified Violation (LIV) 338,339/87-19-17:
Core
Alteration Without A Charging Pump
The licensee investigated this and similar instances where mode changes
were made without taking proper action.
This was investigated using the
Human Performance Evaluation System (HPES) techniques.
The licensee had
developed mode change checklists to avoid these problems in the future.
10.
Exit
The inspection scope and findings were summarized on August 19, 1988, with
i
those persons indicated in paragraph 1.
The inspectors described the
areas inspected and discussed in detail the inspection results listed
below. The licensee did not identify as proprietary any of the material
providad to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
<
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Item Number
Description and Reference
,
338/88-22-01
Inspector Followup Item (IFI) - Followup on the cause
1
of Unit 1
"C" main feedwater isolation failure to
fully close (paragraph 3)
4
j
338/88-22-02
Violation - Failure to follow a containment entry
procedure with three examples (paragraph 6)
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