ML20151W578
| ML20151W578 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 04/27/1988 |
| From: | Constable G, William Jones, Michaud P, Plettner E, Reis T, Will Smith NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20151W546 | List: |
| References | |
| 50-498-88-11, 50-499-88-11, NUDOCS 8805030432 | |
| Download: ML20151W578 (16) | |
See also: IR 05000498/1988011
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APPENDIX'
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NUCLEAR REGULATORY COMMISSION-
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REGION IV-
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.'INRCIns
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cti'n Reports: 50-498/88-11
Operating Licensei
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50-499/88-11'
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50'-498'
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50-499- .
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Licensee:
Houston Lighting & Power Company (HL&P)
P. O. Box 1700
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Houston, Texas
77001
Facility _ Name: South Texas Project, Units 1 & 2 (STP)'
. Inspection At: STP, Matagorda County, Texas
Inspection Conducted: February 11,through March 31','1988
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Inspectors:
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W. F. Smith, Senior Resident Inspector, Project.
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Section
ion,of Reactor Projects
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Section C,, Division of Reactor Projects.
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AP. W.Wi'chaud, Resident Inspector, Project
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/" Section B,-D vision of4eactor Projects
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'hW.l. Jones, Resident Inspector, Project
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Section, C c.DiWsjo~n'3fs eactor Projects
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TNeis,JResiden1nnspector, Project
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Section B, Division of Reactor Projects
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L. Constab~1e, Chief, Project
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Section ~D, Division of Reactor Projects
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8505030432 880428
ADOCK 05000498
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Inspection Summary
Inspection Conducted February 11 through March 31, 1988 (Report 50-498/88-11)
Areas Inspected:
Routine, unannounced inspection of onsite followup of events,
monthly maintenance observation, licensee action on previous inspection
findings, monthly surveillance observation, engineered safety feature system
walkdown, operational safety verification, and startup-testing observations.
Results: Within the areas inspected, three apparent violations were
identified.
The first violation involved the licensee's failure to be' aware of
system status; thus operating the plant in a condition prohibited by technical
specifications (paragraph 2.a).
The second violation involved continued
failure on the part of reactor operators to recognize the proper conditions for
entering and exiting technical specification action statements (paragraph 2.d).
The third violation addressed failure on the part of the licensee to have
appropriate administrative controls over the temporary lifting of electrical
leads and installation of jumpers (paragraph 2.c).
Inspection Conducted February 11 through March 31, 1988 (Report 50-499/88-11)
Areas Inspected:
No inspection of Unit 2 was conducted.
Results:
Not applicable.
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DETAILS
1.
Persons Contacted
HL&P
- W. H. Kinsey, Plant Manager
- H. R. Wisenburg, Unit 1, Plant Superintendent
- M. A. Ludwig, Manager, Maintenance Department
- H. S. Blinka, Performance Support Supervisor
J. W. Loesch, Manager, Plant Operations Department
- E. Nichols, Jr. , Electrical Maintenance Division Manager
H. H. Johnson, Division Manager, Unit 1 Operations
- W. S. Blair, Maintenance Support Division Manager
J. J. Nesrsta, Jr. , Division Manager, Systems
- C. M. Turner, Support Engineering, Fire Protection
- D. A. Leazar, Reactor Support Manager
- S. M. Head, Supervisory Licensing Engineer
S. M. Travis, Technical Support
- J. Labuda, Technical Support
NRC
- J. E. Bess, Resident Inspector, Operations
- A. Singh, Reactor Inspector, Region IV
In addition to the above personnel, the NRC inspectors held discussions
with various operations, engineering, technical support, maintenance, and
administrative members of the licensee's staff.
- Denotes attendance at the exit interview.
2.
Onsite Followup of Events (93702)
The NRC inspectors observed and reviewed licensee actions on selected
operational events and potential problems that occurred during the period
of this inspection,
s.
Isolated Feedwater Flow Transmitters
On February 9, 1988, while the plant was in Operational Mode 3 and
during a performance of precritical calibration checks of feedwater
and steam flow instrumentation, the licensee discovered seven out of
twelve feedwater flow transmitters (FWFT) isolated and out of
service.
Since the technical specifications prohibit this condition
in Mode 3, a cooldown was initiated in accordance with Technical Specification (TS) 3.0.3.
Prior to the end of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, the cooldown
was terminated when the instruments were placed back in service.
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The licensee reported this event to the NRC and immediately began an
investigation to determine why these FWFT were isolated.
In
addition, the licensee performed a walkdown of each instrument listed
in TS Tables 3.3-1 and 3.3-3 to verify that the associated instrument
transmitters were not isolated.
This verification was completed the
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same evening, and no other safety related instrumentation was found
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isolated from its respective system.
During the investigation, the licensee discovered that the first
calibration of these seven FWFT was performed between April 22
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and 28, 1987.
The FWFT were left in service following these
calibrations. At that time, however, the feedwater system had not
been turned over to plant operations from the startup group.
On
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April 30, 1987, the startup group performed hydrostatic tests on
portions of the feedwater system following maintenance.
All 12 FWFT
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were valved out of service to perform this hydrostatic test.
The
startup group apparently did not return these instruments to service
following the completion of the test.
The other five FWFT which were
found in service on February 9,1988, had their initial calibration
surveillance tests performed after the completion of the hydrostatic
tests on April 30, 1987.
These five FWFT were properly left in their
operable, unisolated condition following the calibrations.
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The NRC considers this matter potentially significant not only
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because operating the plant in a condition prohibited by TSs is an
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apparent violation of NRC regulations (498/8811-01), but also because
of its relevance to the Unit 2 system turnover and startup programs.
Although, it was important to promptly verify that there are no other
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safety-related systems and attendant instrumentation in a similar
isolated status, particular emphasis must be placed on correcting any
deficiencies in the system turnover program and plant startup
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procedures for both Units 1 and 2 to preclude a repeat occurrence.
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The licensee reported this event in Licensee Event
Peport (LER)88-016, dated March 10, 1988.
b.
Inadequate Inservice Test Result Review
On February 11, 1988, during the performance of essential cooling
water screen wash booster pump 1A inservice test in accordance with
Procedure IPSP03-EW-0003-1, a value of 49.3 psid was obtained for
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pump differential pressure.
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procedure required action if the pump differential pressure was above
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48.9 psid.
The licensee's test coordinator and shift supervisor
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failed to note this out of tolerance value during their post test
review and erroneously called the test results acceptable.
The
licensee discovered the out of tolerance value during a management
review of completed surveillance tests on February 15, 1988.
The
pump was promptly declared inoperable, and the NRC was informed.
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When the measured.value of pump differential pressure is found higher
than expected, the action required is to perform a deference Values
Measurement surveillance test.
This test was performed on
February 16, 1988, with satisfactory results, thus indicating no
problem existed with the pump.
The Ucensee reported this event in LER 88-020, dated March 15, 1988.
The report adequately described the event as to root cause,
corrective action, and safety significance.
Therefore, pursuant to
10 CFR 2, Appendix C, Section V.A., a Notice of Violation will not be
issued for this matter.
c.
Containment Personnel Airlock Design Deficiency
While reviewing documentation of a test of the containment personnel
airlock on February 11, 1988, the licensee's electrical engineers
discovered four solenoid operated valves in air lines to the
inflatable door seals which appeared to meet criteria for containment
isolation valves, but were not classified as such.
The valves were
purchased under Category 2 requirements and containment isolation
circuitry was not included in the electrical design.
Two of the
valves were normally open and supplied air to receivers which then
supplied air to each door seal.
The other two valves were normally
closed and provided air to test the volume between the double seals
on each door.
When discovered, the licensee immediately isolated,
de-energized, and tagged the power supplies to these four valves as
required by TS 3.6.3 and then informed the NRC.
A conference call was held between the licensee and the NRC on
February 12, 1988, to determine whether these valves met the criteria
to be classified as containment isolation valves.
It was determined
that the valves were within the purview of General Design
Criterion 57 of 10 CFR Part 50, Appendix A and should be considered
containment isolation valves.
At the time of the conference call,
the plant was in Mode 3 and cooldown to Mode 5 was planned for other
reasons within 2 days.
Short-term corrective actions were agreed upon between the licensee
and NRC.
The corrective actions included maintaining the four valves
deenergized and tagged and stationing a person at the power supply
breaker should the valves require opening to repressurize the
accumulators during the interim period until the plant was cooled
down to Mode 5.
The licensee provided these four valves with a
containment isolation phase A signal, which was completed as agreed
prior to exceeding 5 percent of full power.
On February 18, 1988, the licensee requested and was granted
enforcement discretion from the Region IV Regional Administrator,
waiving the requirements of TS 3.0.4 for the above valve
configuration in order to change operational modes and heat up the
plant using the main coolant pumps prior to completion of the
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modifications to the valve circuitry.
This event was reported in
LER 88-017, dated Mar * '1, 1988, and the report adequately described
the circumstances, root cause, and corrective actions.
d.
Failure to Comply with Technical Specifications Related to Essential
Chiller Operability
On February 12, 1988, at 10:00 p.m., the 12A Essential Chilled Water
Cooling Unit tripped and could not be restarted.
The 11A Chiller was
operational.
The A loop of the Essential Chilled Water System was
not considered fully operational unless both chillers were available,
even though the 11A Chiller would have had sufficient capacity with
the ambient temperatures existing at the time.
TS 3.7.14 requires three independent Essential Chilled Water System
loops to be operable in Modes 1, 2, 3, and 4.
The plant was in
Mode 3 at the time, and the associated TS action statement allows
72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to restore one inoperable loop.
However, the C Train of
Essential Chilled Water was also out of service along with the
C Train Emergency Core Cooling System (ECCS) punps for scheduled
maintenance.
Since TS 3.7.14 does not address two inoperable loops,
the licensee entered TS 3.0.3 and began a cooldown of the plant at
10:50 p.m. on February 12, 1988.
Parallel efforts to return either
the A or C Train chillers to operation were also initiated by the
licensee.
At 4:17 a.m. on February 13, 1988, the C Train chillers were returned
to operational status (but not the C Train Low Head Safety Injection
Pump).
The licensee then met the requirements of the action
statement of TS 3.7.14 by having only the A loop inoperable and
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exited TS 3.0.3.
A heatup was begun to return the plant to Mode 3.
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Although the action statement of TS 3.7.14 was satisfied and thus
TS 3.0.3 was no longer applicable for the Essential Chilled Water
System, the licensee failed to recognize that A Train ECCS equipment
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could not be considered operable under TS 3.5.2 since its associated
auxiliary equipment, the A Train Essential Chilled Water System, was
The action statement of TS 3.5.2 allows up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />
to restore one inoperable subsystem but does not address two
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inoperable subsystems. With both the A and C Trains of ECCS
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inoperable, the provisions of TS 3.0.3 were applicable due to the
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inability to meet the action statement requirements of TS 3.5.2.
Therefore, TS 3.0.3 should not have been exited and a cooldown to
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Mode 5 continued until the action statements of both TS 3.7.14 and
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3.5.2 were met.
This could only have occurred if either:
(1) The A Loop of the Essential Chilled Water System was returned to
operable status, or
(2) The C Train ECCS subsystem equipment was returned to operable
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The licensee recognized this noncompliance with the TS when the
(.ff-going Unit Supervisor called from home to qustion the status of
compliance with TS 3.5.2 under the given systerr
'iguration.
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A cooldown to Mode 5 was begun at 12:07 p.m. on February 13, 1988, to
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place the plant in a condition of compliance with the TS. Mode 5 was
reached at 1:17 a.m. on February 14, 1988, which was within the time
requirement of TS 3.0.3 based on the original entry into TS 3.0.3 at
10 p.m. on February 12, 1988. The safety significance of Inis
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situation was minical since there was Train A Essential Chilled Water
available, although not 100 percent, such that Train A ECCS
components would likely have been able to perform their design
functions if requireu by plant conditions.
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The NRC considers the 1 4ensee's failure to identify appliccble TS
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Limiting Conditions for Operation and failure to recognize proper
conditions fe entering and exiting TS action statements potentially
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significant.
In addition, the NRC is concerned because a similar
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violation was identified in NRC Inspection Report 50-498/88-09 in its
Notice of Viol,a ion. 498/8809-05.
It is recognized that these
incidents occurred within one week, and previous corrective actions
may not have taken full effect. Notwithstanding, the failure to
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adhere to TS limiting conditions for operations is significant.
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The licensee reported this event in LER 83-019, dated March 14, 1988,
Inadverteret Safety Injegion (SI) Actuation
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A SI actuation occurred at 5:04 p.m. on February 12, 1988, when the
plant wts in Mede 3 at normal operatirg pressure and temperature, and
a reactor coolant system flow coastdown test was in progress. As
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part of this test, all reactor coolant pumps (RCPsj were tripped at
4:45 p.m.
When the first RCP (in loop D) was rutarted at 5:04 p.m.,
a safety injection actuation occurred on a LO-L0 T cold signal. All
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systems and components functioned as required.
No boric acid
solution was injected into the reactor coolant system because reactor
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coolant system operating pressure was mainM ined.
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The setpoint of the LO-L0 T cold safety injection trip is 532*F. The
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lowest recorded value of T cold was 557'F. The associated circuitry,
however, contains a rate circuit which, for every instantaneous
change of 3 /, provides a 4:1 gain signal such that a 12 F net change
is processed. With the given values of approximately a 9'c e:Wal
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temperature decrease and the instrumentation perceiving a r..pid
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change when the RCP was started, the LO-LO T cold SI circuitry
signaled a 36*F decrease which was sufficient to reach the actuation
setpoint.
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The licensee performed an evaluation, with assistance from
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Westinghouse, of th ' 'otirements for having this rate circuit, :he
requirements for tha gain provided by this circuitry to be at its
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present value, and any implications this circuitry may have on
further testing and operation.
The NRC inspectors will monitor the
licensee's evaluation and any assoc hted activities in response to
this event.
Pending completion of this evaluation for review and
followup by the NRC inspectors, this matter will be considered an
Open Item (498/8811-03).
3.
Monthly Maintenance Observation (62703)
The station maintenance activities listed below were observed and
documentation was reviewed to ascertain that +.he activities were conducted
in accordance with approved procedures and the TSs as applicable.
a.
On March 19, 1988, the licensee commenced work to place bonnet seal
caps on three coolant charging check valves in the chemical and
volume control system (CVCS) which had excessive leakage.
The NRC
inspector observed the installation and welding of the bonnet seal
caps on these three valves.
Several Maintenance Work Requests (FNRs)
were issued which contained radiation work permits (RWP), material
controls requirements, quality control requirements, and post
maintenance testing requirements.
The individuals performing the
task were cognizant of their duties and performed them in a
professional manner.
A foreman was present during the entire work
process.
The shop supervisor was also present during part of the
work.
No problems were identified.
b.
On February 2J, 1988,FNR MS-55170 was initiated to repair a
hydraulic fluid leak on the "B" main steam line power operated relief
valve (PORV).
The unit st.pervisor reviewed the FNR and authorized
the work prior to the FNR being started.
The appropriate TS limiting
condition for operation (LCO) was entered to prevent entry into
Operational Mode 2 and to establish the time the unit may remain in
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Mode 3 with the PORV inoperable.
Instructions provided to
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maintenance personnel in the FNR appeared to be adequate for the
circumstances.
An adequate equipment clearance was obtained and the
equipment positions were verified correct prior to initiating work on
the PORV.
During performance of the FNR, the licensee discovered
that the controller had to be replm ad and a replacement was obtained
from Unit 2.
The appropriate documentation was provided to allow
installation of the controiler in Unit 1.
The PORV was returned to
service on March 1, 1988, fo' lowing removal of the equipment
clearance and satisfactory post maintenanca testing.
c.
On February 29,1988, FNR AF-52382 was initiated to allow removal of
the steam driven auxiliary feedwater pump thrust bearing.
During a
surveillance test of this pump during the previous day, the licensee
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had noted that the thrust bearing was operating at an elevated
temperature.
The pump was declared inoperable at 9:44 p.m. ou
february 28, 1988, and the appropriate TS LC0 was entered.
Clearances were obtained pri"r to initiating the work and the work
was performed under the direction of a qualified individual.
As the
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scope of the work increased during the performance of the MWR, the
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MWR was revised to provide further instructions.
On March 2, 1988,
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the plant was cooled down to Mode 4 when it became apparent that the
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auxiliary feedwater pump could not be repaired and returned to
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service within the time permitted by the,TSs.
The entire pump we.s
.later replaced when an-inspection revealed that the throttle bushing
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failure resulted in extensive damage to the pump shaft and casing.
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-On March 5, 1988, the pump replacement was completed and the
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equipment clearances removed.
The replacement pump was declared
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operable following successful postmaintenance testing.
During review of the documentation packages for the above MWRs,
MS-55170 and AF-52382, it was noted that the maintenance personnel
who had attended the premaintenance oriefirg were not identified in
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the appropriate packages.
The NRC inspector held discussions with
licensee management to ascertain how they ensure that individuals
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performing maintenance understand the work they are to perform.
This
could be of particular concern when the work extends beyond the first
maintenance crew's shift.
The possibilit-j of requiring each
individual to read the MWR and sign a statement that he has read and
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undars,tands the work he is to perform, was identified as an
improvement item.
The licensee agreed to take the item under
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advisement to determine if additior,a1 controls would be beneficial.
d.
The controls for lifting leads and installing temporary jumpers during
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maintenance activities was also reviewed.
It was noted that the
licensee provided lead lift / reinstall and jumper installation / removal
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records as attachments to MWR packages when the werk required lifting
leads or the use of jumpers.
However, this attachment was not
controlled or referenced in n.aintenance control Procedure OPGP03-ZM-0003,
Revision 15, "Maintenance Work Request Program," nor was it identified,
or its use described, in any other approved procedure.
At the time of
this review, Procedure OPMP07-ZI-0001, "I&C Troubleshooting Permanent
Plant Equipment," was being drafted.
At the end of this inspection
priod, the licensee presented tne approved procedure to the NRC
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inspector.
Upon reviewing the document, the inspector noted that the
lifted lead log does not identify the terminal block or termination
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point where a lifted lead must be reinstalled.
This was identified to
the licensee.
Failure to have m tablished and implemented an
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administrative procedure to control lifted leads and temporary jumpers
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during maintenance activities since the plant was licensed is an
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apparent violation of TS 6.8.1.a (498/8811-04).
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The guidelines for fuse removal / replacement and temporary jumper
removal provided for electrical maintenance personnel in
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Procedure OPMP05-?E-0400, "Electrical Maintenance Performance
Guidelines," were also reviewed.
The NRC inspector expressed concern
that the brevity of descriptions for fuse removal and jumpe.r
installation as required by the Fuse Removel and Reinsta11ation -
Temporary J eper Installations and Removal Form, OPMP-ZE-0400-2, may
cause incorrect reinstallation of fuses and removal of jumpers.
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Therefore, as a result of this inspectiori, the NRC is concerned about
the adequacy of the entire program for lifted leads, fuse removal,
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and temporary jumpers, and I.he licensee's corrective actions should
address its entire program,
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.The NRC inspectors reviewed the following additional maintenance
activities during;this inspection period.
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(1) MWR WL-57543, "LWFJ RCOT 1A LCV-leakage"
(2) MWR CS-87028162, "Containment Spray Pump Discharge Valve - Motor
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Drawing High Current"
(3) MWR MS 55437, "Main Steam Drain Isolation Valve Inoperable"
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In addition, one NRC inspector reviewed Plant Procedures OPGP03-ZM-0003,
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"Maintenance Work Request P;agram," OPGP03-ZE-0020, "Post Maintenar.ce
Testing Program," and OPGP02-ZA-0080, "Work Coordination Program." Each
program was found to fully satisfy the requirements set forth in
Regulatory Guide 1.33, Section 9.
While the maintenance, post maintenance testing, work coordination
programs, and indiv1 dual MWRs appeared to be fully satisfactory, the NRC
inspector observed what appeared to be a weakness in the control of work
presented to control room personnel.
Procedure OPGP03-ZA-0080 states, in
part, that work / testing shall be restricted to a single safety train at
any one time unleu preapproved by operations and/or station management.
While observing control room activities at approximately 8:30 p.m. on
March 12, 1988, the NRC inspector noted the oncoming unit supervisor
reviewing the MWR packages sent up from the Work Control Center (WCC) for
work start approval.
The unit supervisor was heard commenting to the
shift supervisor that the WCC had sent up requests which, if authorized,
would have'taken out three trains of auxiliary feedwater.
The work
requests were denied and returned to the WCC.
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f.fter witnessing this incident, the NRC inspector interviewed several unit
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and shift supervisors in relation to this concerr
There is a concern
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that the lack of operational expertise in the WCC could cause problems.
During other tours of the Control Room and A ,xDiary Building, the NRC
inspectors noted a large number of MWR item ctill pending on local
instrumentation and on Control Room Panels.
A safety problem did not
appear t. axist since these parameters could be obtained from a computer
readout.
However, a long time delay could occur depending on the computer
load at the time of the request.
Many of these MWRs have been long
standing.
Interviews were conducted t.c determine the reason for the long
delay in correcting the problems.
Several factors existed with the most
prevalent one e.oncerning tha WCC.
The WCC had a lack of experienced
operations pursonnel to provide input in helping to assign the correct
priority to the work items.
The licensee was aware of the problem and
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took actions to correct the problem; however, the experience level of the
personnel will improve with time as the licensee gains experience in this
area.
No other violations or deviations were identified.
4.
Licensee Action on Previous Inspection Findings (92701)
(Closed) Unresolved Item 498/8809-02:
Licensee's program for leakage
control of potentially contaminated systems inside and outside the reactor
containment.
The NRC inspectors conducted several tours of the reactor
containment building, mechanical and electrical auxiliary building, and
the fuel handling building.
During these tours, the inspectors noted
leaks from barated systems which include containment spray, low head
safety injection, high head safety injection, and residual heat removal.
Most of these leaks were identifiable by the build-up of boric acid
crystals; however, several leaks were observed by the presence of water on
the floor.
The issue was whether or not the licensee was complying with
TS 6.8.3, which requires the licensee to establish, implement, and
maintain a program to reduce leakage from those portions of systems
outside containment that could contain highly radioactive fluids during a
serious transient or accident to as low as practical levels.
The licensee
had responded that the leaks were being identified and tracked, but the
personnel resource and schedule constraints did not permit achievement of
leak-free systems prior to initial criticality.
During this inspection period, the NRC inspector conducted a detailed
review of the leakage control program as implemented by
Procedures 0PGP03 ZE-0028, "Contaminated System Leakage Test Program," and
OPGP03-Z0-0004, "Plant Conduct of Operations,'l paragraph 4.3.7.3, and
determined that although the licensee was in compliance with these
procedures and therefore in compliance with TS 6.8.3, the number of leaks
that existed after startup should be identified and corrected.
On
February 20, 1988, for example, the NRC inspector noted water leakage of
2-3 drops per second from the CS B pump oischarge flange.
This leak was
evident by standing water ben ath the pump, plus constant water dropping
from the pump upper shaft seal drain line and down to the pump suction
This leak went undetected until March 14, 1988, when the NRC
inspector finally directed the attention of a reactor plant operator to
the leak.
The licens:e's conduct of Operations Procedure OPGP03-Z0-0004,
paragraph 4.3.7.3, *equires that during the operator's rounds, special
attention shall be paid to systems containing boric acid in solution, and
that such leaks are to be reported and promptly repaired.
The inspectors
pointed out to licensee management that unless the operators are trained
to be more observant on their tours, leaks on contaminated systems will
rot be identified for repair and employees in the vicinity of the leaks
are subject to becoming contaminated.
The licensee presented a computer
,
data run to the inspector showing that notwithstanding the lack of
attention to detail demonstrated by some watchstanders in this area, an
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aggressive leak identification and repair program appears to be in placa,
and there is management attention applied.
The resident inspectors will
continue to monitor leakage control activities as part of their routine
safety verification inspections.
This item is closed.
(0 pen) Unresolved Item 498/8809-01:
Fire Watch program deficiencies.
During this inspection period, the NRC inspectors reviewed the fire watch
logs during their tour of the mechanical and electrical build;ngs, fuel
handling building, and i.tolation valve compound.
These tours were
conducted at random a;v.i were performed during all three shifts.
In each
case, the times logged on the fire watch logs were appropriate.
Fire
watch personnel were also obsarved during the performance of their rounds,
and their actions appeared satisfactory.
This item will remain unresolved
pending further review by the staff of the deficiencies identified in NRC
Inspection Report 50-498/88-09.
No violations or deviations were identified.
5.
Monthly Surveillance Observation (61726)
During this inspection period, the NRC inspectors observed portions of the
p'erformance of Plant Surveillance Procedure 1 PSP 03-SI-0023, Revision 2,
SIS Pressure Isolation Check Valve Leak Test." The test was completed on
February 21, 1988, to verify operability of reactor coolant system
boundary check valves in the Safety Injection Systems.
Valve RH-0020A was focnd to have a leaka;;e rate greater than allowed by
the acceptance criterion.
The licensee suspected that a test valve, and
not the boundary valve, was leaking as evidenced by flow noises in the
test valve.
The test was holted, and the procedure was changed to provide
for freeze seals on the small test piping to facilitate determination of
boundary valve leakage only.
A freeze seal was then applied to a test
line downstream of Valve RH-0020A which reduced the measured leakage to
that of Valve RH-0020A only, and the acceptance criterion was met.
The NRC inspector noted that the freeze seal was controlled by a MWR.
The
use of the clearance program along with the MWR for controlling the
application and removal of freeze seals was discussed with licensee
personnel.
Because the application of a freeze seal is the equivalent of
closing a "block va've," the use of the clearance program provided a well
'
established mechanism for ensuring the freeze seal was applied and removed
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with an independent verification.
The applicable procedures were reviewed
for adequacy, test instrumentation was verified to be in calibration, and
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test data was reviewed for accuracy and completeness.
The performance of
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licensee personnel involved with this surveillance was satisfactory and
the NRC inspectors observed that tne personnel demonstrated adequate job
knowledge and worked in a professional manner.
No violations or deviations were identified.
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6.
Engineered Safety Feature (ESF) System Walkdown (71710)
The NRC inspector conducted a walkduwn of the accessible portions of the
containment spray system to independently verify the operability of the
system.
A review was performed to confirm that the licensae's system
operating procedure matched plant drawings and the as-built configuration.
Equipment condition, valve and breaker position, housekeeping, labeling,
permanent instrument indication, and apparent operability of support
systems essential to actuation of the ESF system sere all noted as
appropriate.
The NRC inspector found no significant problems that would
preclude the system from performing its intended safety functions.
The NRC inspector found several pipe flange and valve packing leaks, some
of which were not identified by MWR tags.
The licensee's failure to
identify and repair systems which can become contaminated or are
susceptible to boron induced corrosion was discussed in paragraph 4 of
this report.
No violations or deviations were identified.
7.
Operations Safety Verification (71707 & 71715)
The NRC inspectors observed operational activities throughout the
inspection period and closely monitored operational events.
Control room
activities and conduct were generally observed to be well controlled.
Proper control room staffing was maintained and access to the control room
operational areas was controlled to minimize distractions.
Selected shift
turnover meetings were observed, and it was found that information
concerning plant status was being covered in each of these meetings.
It was noted during the first 2 weeks of this inspection period that '. hen
reactor operators became involved in plant evolutions there was a terdency
to silence annunciator alarms without immediately investigating the reason
for the alarm.
Annunciators that could be cleared were also noted N stay
on for an extended period of time.
This was discussed with licensee
personnel, and an obvious improvement in the reactor operators' attention
to alarms was observed during the latter part of the inspection period.
Periodic reviews of the control room operator log were performed to
determine if the log was bein] maintained in accordance with
Procedure OPOP01-ZQ-0030, "Maintenance of Plant Operations Logbooks."
It
was noted on several occasions that the logs were incomplete, including
failure to identify when limiting conditions for operations were exited.
A violation regarding maintenance of the control room operator log was
identified in NRC Inspection Report 50-498/88-17.
The licensee revised
Procedure IP0P01-ZQ-0030 to improve the method by which the control room
,
log is maintained, and the revised procedure was implemented on March 8,
1988.
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Plant tours were conducted, and overall plant cleanlinest was good.
Areas
which were previously identified as having been inadequately lighted have
been cotrected.
General radiation protection practices were observed for individuals in
the radiation control area (RCA).
Personnel were observed to properly log
onto the appropriate rac'iation work permit and upon exiting the RCA, the
radiation monitors were properly utilized to check for contamination.
Security activities were observed by the NRC inspectors while entering and
P
exiting the protected area and during tours inside the vital islands.
Security personnel were noted to provide instruction to station personnel
who were not following good practices for passing through key card doors.
Compensatory posts were established for areas where vital area barriers
were defeated.
During one tour of the RCB, the NRC inspector noted that all the fire
hoses located inside the RCB were due for hydrostatic testing in
July 1988.
The current plant operating schedule is to be at power during
the time frarre when the required test should be performed. The NRC
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inspector identified this as a concern to the licensee.
The licensee was
unaware of the pending problem with the fire hoses in the RCB.
However,
when brought to tL:ir attention, they replaced fire hoses in the RCB and
other areas inaccessible during power operations with fire hoses having
test dates which will expire during subsequent scheduled outages.
In
addition, the identified fire hoses will be added to an existing tracking
system to ensure that testing will be completed during scheduled planr.ed
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outages.
On February 11, 1938, the NRC inspectors observed portions of an emergency
drill conducted by the licensee.
Control room personnel were observed to
be conducting activities in accordance with procedures and took a
generally conservative approach to the problems presented in the drill
scenario.
Technical Support Center activities were underway in the
engineering and health physics areas as soon as personnel arrived.
The
NRC did not participate in the drill; however, the NRC inspectors
identified minor areas where improvements could be made.
No deficiencies
were noted.
The NRC inspector reviewed the licensee's total corrective maintenance
history for the previous 3 months with licensee management personnel.
A
sharp increase in the total number of open RdRs has occurred from the
middle of January 1988 to the first week of March 1988.
An increase from
approximately 1200 open MWRs to 1550 was noted during this time period.
The largest increase has been with instrumentation and control items
followed closely by mechanical items.
This large inerease in open RdRs
has resulted mostly in degradation of individual components.
Considerable
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licensee management involvement is needed in this area to ensure that
individually degraded equioment does not result in degraded capabilities
of any safety systems.
No violations or deviations were identified.
8.
Startup Test Witnessing and Observation (72302)
The objectives of this inspection were to ascertain conformance of the
licensee to the Unit 1 operating license and procedural requirements, and
to observe operating staff performance.
The NRC inspectors witnessed
parts of the following tests on a sampling basis.
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On February 26, 1988, the licensee initiated Plant Engineering
Procedure 1 PEP 04-ZX-0001, "Test Sequence for Initial Criticality and Low
Power Testing." The NRC inspectors noted that the prerequisites had been
met, and the procedure was being performed in a controlled manner.
On
February 27, 1988, the inspector observed the test briefings for
Procedure 1 PEP 04-ZX-0002, "Initial Criticality." This procedure was used
to control the addition of reactivity through control rod withdrawal and
reactor coolant system (RCS) boron dilution, and the briefings were held
in a professional manner.
On February 27, 1988, at 2:24 a.m., the startup banks were withdrawn for
the initial approach to criticality. Withdrawal of the startup banks was
well controlled and an inverse count rate determined at each 50-step
interval to monitor approach to criticality.
At 9:52 a.m., the first
,
control banks were withdrawn.
Dilution to criticality was initiated at
1:06 p.m. with Control Bank 0 at 170 steps.
The NRC inspectors observed
that all pressurizer heaters were energized to maximize pressurizer spray
and boron mixing.
Chemistry samples of the RCS were taken every
15 minutes and pressurizer samples every 30 minutes to determine RCS boron
concentration.
On January 28, 1988, at about 5:45 a.m. with the reactor
subcritical, an ESF actuation was inadvertently received during the
performance of a surveillance test.
The reactor tripped because of the
safety injection signal.
Control room personnel responded to the reactor
trip in a controlled and deliberate manner.
The emergency procedures were
immediately retrieved and systematically utilized.
The reactor was
determined to be in a safe condition before the safety injection signal
was reset.
At 5:50 a.m., the shift supervisor declared a Notice of
Unusual Event (NOVE) because it was not immediately obvious that an
uncomplicated reactor trip had occu red.
The NOUE was cancelled at
6:30 a.m.
The licensee had placed Channel I of LO-LO T cold for RCS
loop C in a tripped condition for the perfo mance of Surveillance
Test IPSP02-RC-0453.
A spurious trip on Channel III completed the 2 out
of 3 logic needed to initiate the ESF actuation on LO-L0 T cold.
The licensee was not able to duplicate the conditions that caused the
spurious trip of LO-L0 T cold on Channel III.
The rate circuit cards were
removed and placed on a "shake table" to induce a trip.
No trip was
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experienced.
The rate circuit cards were replaced, and no further
spurious trips have occurred.
The licensee reported the above incident in
LER 88-022, dated March 24, 1988.
Initial criticality in accordance with Procedure 1 PEP 04-ZX-0002 was again
initiated on March 7, 1988, at approximately 10:00 p.m. following repair
of the auxiliary feed water pump 14.
Initial criticality was achieved at
5:08 a.m. on March 8, 1988.
Criticality was observed to occur within the
50 ppm tolerance band established for boron concentration in the RCS with
control bank 0 at 170 steps.
Reactor power was stabilized for low power
physics testing.
Access to the control room was strictly controlled, and
no unnecessary personnel were allowed within the control area.
The following startup tests were witnessed in part:
Procedure
Title
1 PEP 02-ZX-0001
Test Sequence for Initial Criticality
1 PEP 04-ZX-0001
Rod Worth Determination
1 PEP 04-ZX-0006
N 1 Rod Worth (Shutdown Margin) Verification
1 PEPO 4-ZX-0007
Pseudo Ejected Rod Test
1 PEP 04-ZX-0010
Natural Circulation Verification
1 PEPO 4-ZX-0003
Boron Endpoint Measurement
The NRC inspector tioted that the tests were properly executed under the
direction of a qualified Shift Technical Advisor (STA) designated as Test
Director with a Reactor Engineer ptesent.
It was observed that control
room personnel kere briefed on the tests.
Procedures used in testing were
followed verbatim and properly field changed when required.
The overall
performance of control room personnel (test directors, engineers, and
operators) was perceived as disciplined, methodic, and coordinated during
these tests.
No violations or deviations were identified.
9.
Exit Interview
The lead NRC inspector met with licensee representatives denoted in
paragraph 1 on March 31, 1988, and summarized the scope and findings of
the inspection.
Other meetings between NRC inspectors and licensee
management were held during the inspection time period to discuss
identified concerns.
The licensee did not identify as proprietary any of
the information provided to or reviewed by the inspectors during this
inspection.
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