ML20136B915
| ML20136B915 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 03/07/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20136B896 | List: |
| References | |
| 50-445-96-17, 50-446-96-17, NUDOCS 9703110191 | |
| Download: ML20136B915 (22) | |
See also: IR 05000445/1996017
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ENCLOSURE 2
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
3
Docket Nos.:
50-445
50-446
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License Nos.:
NPF-89
Report No.:
50-445/96-17
50-446/96-17
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Licensee:
TU Electric
Facility:
Comanche Peak Steam Electric Station, Units 1 and 2
Location:
Glen Rose, Texas
Dates:
December 22,1996, through February 1,1997
Inspectors:
A. T. Gody, Jr., Senior Resident inspector
V. L. Ordaz, Resident inspector
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H. A. Freeman, Resident inspector
R. A. Kopriva, Project Engineer
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Approved By:
J.1. Tapia, Chief, Project Branch A
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Division of Reactor Projects
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ATTACHMENT:
Supplemental Information
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9703110191 970307
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ADOCK 05000445
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EXECUTIVE SUMMARY
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Comanche Peak Steam Electric Station, Units 1 and 2
NRC Inspection Report 50-445/96-17:50-446/96-17
Operations
Operators did not identify that the plant computer calorimetric data had failed to
update. The inspectors found that the failure was not alarmed and was, therefore,
a vulnerability since the failure could only be identified by an operator if he
recognized that the data displayed was not changing (Section 01.3).
Unit supervisors were not always aware of the status of log entries. This was
indicative of a lack of a questioning attitude by the operating crew (Section 04.1).
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The plant simulator did not accurately model the main generator speed control
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circuit, which contributed to a plant transient (Section 08.1).
Licenses management did not ensure that an inexperienced individual was properly
supervised while synchronizing the Unit 1 main generator to the grid (Section 08.1).
Operations management initiated postjob debriefs to discuss lessons learned
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following two maintenance activities. The postjob debriefs were considered a
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strength (Sections M1.2, M1.3, and M1.7).
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The operating crew was well prepared for maintenance on a heater drain tank
alternate drain valve. Preparations included attentive, dedicated operators,
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appropriate compensatory measures, and thorough prejob briefings (Section M1.3).
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Maintenance
A Unit 1 safety injection pump was started daily to fill Safety injection
Accumulator 1-01 because of check valve leakage. The inspectors found that the
frequent use of safety injection pumps to fill the accumulator was an unnecessary
cycling of safety equipment (Section 04.1).
Electricians performing troubleshooting on an inverter did not perform the activity as
described in the prejob briefing conducted in the control room (Sections M1.2 and
M1.7).
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Maintenance personnel were well prepared for the repair of the alternate drain
valve, but weak communications between the valve team and the control room
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allowed the valve team to change the scope of the maintenance on the alternate
drain valve without allowing operations the opportunity to determine whether
changes to the compensatory measures were necessary (Sections M1.3 and M1.7).
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Instrument and controls technicians were professional and knowledgeable of the
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procedure and used good verification techniques during the calibration of
component cooling water heat exchanger station service water flow transmitters
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(Section M1.4).
Instrumentation and controls technicians did not properly install electrical leads on a
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feedwater isolation valve, which prevented the valve from stroking during its
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postmaintenance test (Sections M1.6 and M1.7).
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Enaineerina
The Unit 1 turbine driven auxiliary feedwater pump design modifications were
successful in removing condensate from the turbine steam supply piping
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(Section O2.2).
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The licensee failed to perform and maintain records of safety evaluations and failed
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to update the Final Safety Analysis Report for changes made to the emergency
response procedure for switchover of emergency core cooling from injection to
recirculation, which was a procedure detailed in the Final Safety Analysis Report.
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This issue will be tracked as an unresolved item pending further NRC review.
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(Section E8.1).
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The engineering department threshold for documenting a potentially nonconforming
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condition may be indicative of a programmatic weakness (Section E8.1).
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Plant Sucoort
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Radiological support of maintenance activities in the containment building was
excellent (Section R1).
Plant chemistry was closely monitored and out of guideline measurements were
aggressively corrected (Section R1).
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Security officers were attentive and knowledgeable of their post requirements
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(Section S1).
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Report Details
Summary of Plant Status
Unit 1 began and remained at approximately 100 percent power for the entire inspection
period.
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Unit 2 began this inspection period at 100 percent power. On January 4, Unit 2 was shut
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down to Mode 3 to repair a feedwater isolation valve hydraulic accumulator pump. The
pump was repaired and the unit was returned to full power on January 10. The unit
remained at approximately 100 percent power for the remainder of the inspection period.
1. Operations
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Conduct of Operations
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01.1 General Comments (71707)
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The inspectors conducted frequent reviews of ongoing plant operations by touring
the plant, walking down control boards and safety systems, and performing periodic
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reviews of logs, in general, the conduct of operations was professional and safety-
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conscious. Specific events and noteworthy observations are detailed in the
sections below.
01.2 Plant Tours
a.
insoection Scope (71707)
The inspectors conducted frequent tours of the plant and occasional tours of the
plant simulator to independently verify the operational readiness of standby and
operating equipment and evaluate how well the simulator models the plant controls.
While performing the plant tours, the inspectors periodically performed independent
radiation measurements to confirm radiological postings.
b.
Observations and Findinas
The inspectors found that all standby equipment on the control boards was properly
aligned for the plant operating condition. The plant simulator typically reflected the
detail of danger tags and instruments out-of-service in the actual plant, with one
significant exception (Section 08.1).
The inspectors noted that housekeeping and area lighting in the plant were generally
good. The inspectors occasionally found small amounts of loose debris, such as
tape balls, wire seals, and hand tools, in the radiologically controlled area. These
minor deficiencies were immediately corrected upon identification to the licensee.
The inspectors noted that temporary scaffolding was installed in accordance with
licensee procedures and did not impact normal plant operation. Ongoing painting
efforts continued to improve plant preservation. The inspector observed that
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painters communicated often and clearly with the control room prior to painting and
that they were careful not to impact plant operation.
01.3 Unit 1 Plant Comouter Calorimetric Failure
a.
Inspection Scope (71707)
On January 23, while Unit 1 was operating at 100 percent power, the licensee
identified that the plant computer calorimetric indication for reactor thermal power
was not updating. The inspector discussed the event with operators and
management and reviewed operating data concerning the specific failure,
b.
Observations and Findinas
Upon identification of the plant computer calorimetric indication failure, operators
reduced turbine load and verified that reactor power was within the required
procedural and plant operating license limit. The licensee's investigation revealed
that the calorimetric indication had not been updating for approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />
prior to discovery. The licensce performed calculations to determine whether the
licensed reactor therme! power limit of 3411 mega-watts thermal (MWth) was
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exceeded. The inspesor reviewed the calculated values and found that the unit
remained below the licensed limit. The inspector found that the licensee's
immediate corrective act;ons to reduce turbine load and rely on nuclear
instrumentation were appropriate.
The calorimetric indication failure was identified by an oncoming reactor operator
who exhibited a good questioning attitude. When the calorimetric indication was
restored, the inspector observed the plant computer calorimetric screen and noted
that the one minute average routinely updated with little change in power level.
When the failure occurred, the data shown on the screen locked in and remained
constant. Since the plant computer calorimetric is the primary indication used by
operators to ensure that reactor thermal power is maintained within the limit
prescribed by the plant operating license, a f ailure to update without an alarm was a
vulnerability. The licensee indicated that they planned to consider modifying the
system to provide an alarm for this type of failure.
O2
Operational Status of Facilities and Equipment
O 2.1 Enoineered Safetv Feature System Walkdown
a.
Insoection Scope (71707)
The inspector performed a walkdown of the Unit 1, Train B component cooling
water system to verify that the system was properly aligned for operation. In
addition, the inspector reviewed portions of the system design basis, which
included calculations and portions of the Final Safety Analysis Report (FSAR), to
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determine if the system was maintained in accordance with its licensing basis.
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System operating history was reviewed for certain check valves and a comparison
was made between operations surveillances and the inservice testing program to
ensure that check valves were not preconditioned prior to inservice testing,
b.
Observations and Findinas
The inspector found that the component cooling water system was properly aligned
in accordance with licensee procedures. Equipment was in good condition with
only a few deficiency tags of minor significance noted. Locked components were
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verified to be in the proper position.
The inspector found that the stop-check valves in the reactor coolant pump thermal
barrier heat exchanger component cooling water return lines were cycled by
operators in accordance with system operating procedures every quarter. The
inservice testing program required that the check valves be tested every 18 months.
The inspector was concerned that the system operating procedure preconditioned
the check valves and biased the inservice testing program results. The inspector
found that the system operating procedure had been written because of previous
failures of the check valves and that no failures had occurred since they were
periodically cycled. The inspector discussed these concerns with the NRC's Office
of Nuclear Reactor Regulation (NRR) and concluded that, since the system operating
procedure was being randomly implemented and not linked with the inservice
testing program, the check valves were not preconditioned.
The inspector evaluated a design change to the component cooling water surge
tank to determine if it could affect the operation of the system. The component
cooling water system surge tank is split into two separate chambers. The chambers
provide a surge volume for each train of component cooling water. The design
change involved cutting holes in the surge tank partition between the two volumes
to allow for level equalization between the two trains. The inspectors reviewed the
licensee's component cooling water system operating procedures and found that
they properly accounted for the design change by changing the way operators
troubleshoot potentialleaks into and out of the systam. The inspectors found that
the component cooling water pump net positive suction head calculations assured
sufficient margin to account for the delay operators would have in identifying which
train was leaking.
02.2 Operational Surveillances
a.
Inspection Scope (61726)
The inspectors observed all or portions of the following operational surveillance
tests.
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Unit 1, Train B, emergency diesel generator operability test
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Unit 1, Train B, safeguards slave relay actuation test
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Unit 2, Train A, emergency diesel generator operability test
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Unit 2, Train A, safeguards slave relay actuation test
Unit 1 turbine-driven auxiliary feedwater pump operability test
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Specific findings and note'uorthy observations are detailed below.
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b.
Observations and Findinas
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The inspectors noted that the unit supervisor appropriately highlighted recent
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changes to the safeguards slave relay actuation test procedure during the prejob
briefing. The changes prevented the centrifugal charging pump safety injection
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isolation valves from opening during the slave relay test. The inspector verified that
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the licensee's inservice testing program tested the portion of the actuation circuit
not tested during the slave relay ter,t.
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During the test of the Unit 1 turbine-driven auxiliary feedwater pump, operators
adhered to personnel safety practices by ensuring that all personnel were out of the
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room prior to the pump start. The inspector observed the operation of the turbine
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steam supply piping drain pot, which was installed in a recent design modification
of the system. The accurnulated water did not exceed the range of the sightglass,
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verifying that the drain pot was appropriately sized to accommodate the water that
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had accumulated in the turbine steam supply piping. The inspector noted that the-
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sentinel valve on the turbine casing remained closed throughout the pump start and
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that no vibration or noises, indicative of water passing through the turbine, were
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experienced. Prior to implementation of the condensate removal design
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modifications to the turbine-driven auxiliary feedwater pump, sentinel valve
operation and noises were routinely heard during pump starts. The design
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modifications adequately removed condensate from the turbine steam piping prior to
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reaching the turbine.
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The inspectors reviewed the surveillance test results and found that the test
requirements were ' satisfied. Communications between the operators were good,
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and the independent verification steps in the procedures were performed correctly.
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The inspectors verified that the surveillance tests met the Technical Specification
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requirements, tested the facility as described in the FSAR, were performed in
accordance with the procedures, and that the equipment was appropriately restored
following the surveillance tests.
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Operations Procedures and Documentation
O3.1
U_ nit 2 Backfeed Throuah One Main Transformer
a.
Inspection Scoce (71707)
During the Unit 2 planned outage, the licensee supplied power to Unit 2 from the
east bus through one of the two main transformers in order to perform corrective
maintenance on both the west bus and the other main transformer. The inspector
reviewed the FSAR and the procedure associated with this backfeed evolution.
b.
Observations and Findinas
The procedure included steps to energize the Unit 2 main and auxiliary transformers
in a backfeed configuration with normal 6.9 kV buses energized. The inspector
reviewed the procedure and noted that several steps were initialed as not
applicable, since the actual evolution was to backfeed through only one main
transformer. The inspector reviewed FSAR Section 8.2.1 for offsite power
distribution to determine whether the nonapplicable steps changed the intent of the
procedure for the activity that was described in the FSAR. The inspector found that
the FSAR description generally covered the backfeed evolution and that the
procedure was sufficient to address the evolution as described in the FSAR. The
inspector also verified that engineering reviewed the activity prior to the procedure
change.
04
Operator Knowledge and Performance
04.1 Control Room Tours (71707)
a.
Insoection Scope
The inspectors routinely performed a walkdown of the Units 1 and 2 control boards,
reviewed operating logs, questioned licensed operators on the status of
annunciators, and observed the communications between operators and the unit
supervisors,
b.
Observations and Findinas
The inspectors noted that control room staffing met procedural and Technical
Specification requirements and that supervisory oversight of operators was
appropriate. Control room access was well controlled by the unit supervisors, and
distractions to operators were typically minimized. Operators were attentive to
plant operation.
The inspectors noted that Safety injection Accumulator 1-01 was being filled daily
because of leakage from check valves in the accumulator discharge piping and test
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header. The inspector found that the daily use of a safety injection pump was an
unnecessary cycling of safety equipment. The inspector noted that operators
maintained appropriate attention to safety injection accumulator levels and
pressures. This issue will be reviewed as part of the closure of a previous
inspection followup item dealing with valve maintenance (IFl 50-445(446)/9610-
01).
The inspectors observed operators' acknowledgement of and response to control
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room annunciators in a manner consistent with management expectations, with a
few minor exceptions. The inspectors noted good communications among
operators end the unit supervisors, again with some minor exceptions. Operating
logs were legible and complete with few exceptions. The inspector found two log
entries that identified potential deficiencies without subsequent closure documented
in the operating log, and found that the unit supervisor was not aware of them.
Operations management and supervision were responsive to the examples identified
by the inspectors and immediately corrected the problems and reemphasized their
expectations.
The inspectors noted that operators followed the appropriate procedures when they
responded to alarms and during routine plant evolutions. Thr inspectors observed
operators use appropriate self-verification techniques. Operators were aware of the
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status of annunciators and knowledgeable of the causes for disabled alarms.
Compensatory measures were appropriately initiated for degraded or inoperable
alarms.
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Miscellaneous Operations issues (92901)
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08.1 (Closed) Insoection Followuo item 50-445/9616-02: loss of reactor coolent
system (RCS) letdown during initial loading of the main generator following grid
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synchronization. On November 16,1996, a newly qualified operator loaded the
Unit 1 main generator excessively following initial synchronization to the grid and
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caused an RCS transient in which letdown was isolated and the plant operated
below its minimum temperature for criticality for approximately 5 minutes. The
inspector reviewed the licensee's plant incident report for this event and noted that
a similar event occurred during a grid synchronization on Unit 2 in 1993,in which
the RCS transient resulted in plant operation below its minimum temperature for
criticality for approximately 10 minutes. The inspector noted that, in both the 1996
and 1993 transients, the licensee returned the average coolant temperature to
above the minimum temperature for criticality within the 15-minute limiting
condition for operation. The technical specification minimum temperature for
criticality limitation ensures that the reactor will not be operated in an unanalyzed
condition. As such, the failure to operate the plant within its minimum temperature
for criticality was a significant condition adverse to quality.
The inspector found that the licensee's root cause analysis for the Unit 2,1993
event failed to identify that operator training did not compensate for differences
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between the simulator and the plant for increasing main generator load following
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grid synchronization. The licensee's failure to correct the training deficiency
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following the 1993 transient was a contributor to the November 1996 transient.
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Additionally, the inspector found that licensee management did not ensure that an
inexperienced individual was properly supervised which was a corrective action
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from the 1993 event. This failure to implement adequate corrective actions to
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preclude repetition was a violation of 10 CFR, Part 50, Appendix 8, Criterion XVI,
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" Corrective Action," (VIO 50-445(446)/9617-01).
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08.2 ' Review Technical Soecification Interoretations (TSI)
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a.
Insoection Scoce (71707)
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The inspectors surveyed the licensee's TSI manual for informal references to NRC
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review and/or approval.
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b.
Observations and Findinas
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The inspectors found four examples of TSis in which informal references to NRC
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review and/or approval were made,
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TSI001: Technical Specification 4.0.4
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This interpretation provided guidance on when to enter a Limiting Condition for
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Operation when a surveillance activity had to be completed after entering the plant
mode for which a piece of equipment is required to be operable. The interpretation
indicated that the 24-hour time limit begins at that point in time when the
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prerequisite c. 'iditions required to perform the surveillance have been attained. The
interpretation indicated that this position was discussed with specific individuals on
the NRR staff and that agreement was made and then documented in a letter to the
NRC.
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TSI 018: Technical Soecification 4.6.1.7.2
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This interpretation discussed the staggered test basis of containment and hydrogen
purge valves and references an internal NRC memorandum dated June 15,1981.
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TSI O26: Technical Soecification 3.7.4
This interpretation discussed the attendant electrical power required to consider a
station service water pump operable in the shut down unit and references an
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internal NRC memorandum dated April 20,1983.
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TSI 012: Technical Soecifications 4.7.7.1 b,4.7.7.2b. and 4.7.8b
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This TSI discussed engineered safeguards feature filtration test requirements
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following painting, fire, or chemical release. The interpretation stated that, dunng
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development of the plant Technical Specifications, discussions with the NRC staff
clarified that the surveillances were required only after significant painting, fire, etc.
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The interpretation provided further elaboration on what was considered significant.
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c.
Conclusion .
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The inspectors concluded that this form of NRC involvement in the interpretation of
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plant Technical Specifications was not recognized by the Commission and was not
an acceptable practice. The inspectors requested that the licensee remove any
informal references to NRC review and/or approval from their TSis. The licensee
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indicated that their goal was to eliminate the interpretations following the
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implementation of the new Standard Technical Specifications. The licensee planned
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to submit revised Technical Specifications to the NRC on May 15,1997.
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11. Maintenance
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Conduct of Maintenance
M 1.1 General Comments
The inspector observed the conduct of maintenance activities to determine if the
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plant was being maintained as described in its design basis, to evaluate the impact
maintenance had on plant operations, and to determine if the licensee adhered to
procedures and requirements. Specific activities observed are listed below. Issues
and noteworthy observations are detailed in the following sections.
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Inverter 2C3 troubleshooting and repair
Service water flow transmitter calibration
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Heater drain tank alternate drain valve maintenance
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Component cooling water system motor-operated valve inspection
Containment spray pump coupling preventive maintenance
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Containment spray pump room cooler fan bearing replacement
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Nitrogen vent valve maintenance inside containment
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Feedwater isolation valve maintenance
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M1.2 Inverter IV2C3 Maintenance
a.
Insoection Scope (62707,71707)
On December 23,1996, the inspector attended the prejob briefing, observed the
conduct of maintenance, reviewed abnormal operating procedures, discussed
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compensatory actions with operators, and discussed the conduct of the on-line
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maintenance with licensee management as it related to the need for clear
communications.
b.
Observations and Findinas
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As discussed in NRC Inspection Report 50-445(446)/96-16,the licensee replaced
an oscillator board on inverter 2C3 which had failed on December 8,1996. After
being in service for approximately one week, the inverter experienced intermittent
" loss of synch" and " bypass out of limits" alarms. Operators successfully
transferred the inverter to its bypass source. The licensee developed a
troubleshooting plan and initiated inverter repairs on December 23,1996.
Prior to the maintenance activity, the inspector questioned the operating crew on
the expected plant and operator response to a loss of Bus 2C3 and found that
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operators had not been provided the insights gained from the December 8 review of
what would occur if Bus 2C3 was lost. The inspector was concerned that the
operating crew did not understand the potential impact that a loss of Bus 2C3 could
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have on the plant while it was operating at 100 percent power. Through
discussions, it was determined that the operating crew did not believe that heater
drain flow would decrease and cause the feedwater pumps to trip. The inspector
found that operators recognized that a loss of Bus 2C3 would result in losing the
capability to use steam dumps and were cognizant of the actions required to
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mitigate a loss of feedwater transient with no steam dumps. The inspector
informed the shift manager of the concern that the December 8 reviewed sequence
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of events had not been communicated to the crew. The shift manager indicated
that the operating crew independently reviewed plant drawings and concluded that
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heater drain flow would not be lost.
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The inspector observed the prejob briefing and noted that all personnelinvolved in
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the activity were present, with the exception of the auxiliary operator who was later
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briefed by the unit supervisor. The unit supervisor reviewed the specific tasks to be
performed and asked probing questions about the potential for losing Bus 2C3
during the troubleshooting activity. The unit supervisor appropriately discussed
proper self-verification techniques with the personnelinvolved.
At the inverter, the inspector observed the electrician holding two oscilloscope
probes on two different places in the inverter. The electrician was attempting to
compare the inverter output waveform to the bypass source waveform. The
electrician was not watching the probes while he adjusted the oscilloscope. The
inspector was concerned that the electrician did not use clips to connect the
oscilloscope to the inverter. In addition, the inspector noted that the electricians
had not opened input breakers prior to connecting the test equipment and, as such,
the activity was not being performed as described during the prejob briefing. The
inspector discussed these observations with the shift manager who, in turn,
stopped the work activity. The shift manager and unit supervisor counseled the
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. electricians and engineers on the need to communicate clearly with the control room
prior to performing maintenance which could impact safe plant operation.
The shift manager held a meeting with all the individuals involved to debrief the
evolution and develop a list of lessons learned. The list of areas for improvement .
included: ensuring that all personnel involved in the work are present at the prejob
briefing; using appropriate tools; maintaining eye contact on the work; considering a
walkthrough to ensure that all equipment, tools, and parts are available and staged;
and discussing contingencies. The inspector discussed the debrief with the shift
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manager and found that it was thorough and noted that the practice of performing a
debrief was a strength.
M1.3 Unit 1 Heater Drain Tank Afternate Drain Valve Maintenance
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a.
Inspection Scooe (62707)
The inspector observed the licensee perform maintenance on the Unit 1 heater drain
tank alternate drain valve actuator. The inspection included a review of the
licensee's compensatory actions while performing the maintenance, holding
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discussions with licensed and nonficensed operators providing compensatory
actions, and attending a prejob briefing.
b.
Observations and Findinas
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During the maintenance and calibration activities, the inspector found that the
balance-of-plant operator diligently monitored heater drain tank levels. The
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inspector noted that an additional reactor operator was available for other balance-
of-plant duties, such as responding to back panel alarms,
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At the prejob briefing for the calibration activity, the inspector observed the unit
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supervisor conduct a thorough discussion of the activity, including expected plant
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response and contingency actions.
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The inspector observed valve team maintenance workers calibrate the level
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controller and the positioner on the Unit 1 heater drain tank alternate drain valve.
'When air was restored to the positioner for calibration, valve team workers
concluded that the newly installed positioner did not operate correctly and
proceeded to replace the new positioner with the old one. The control room was
informed that an air leak needed to be repaired but not that the positioner was being
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removed nor that the valve could not be positioned by air. No changes were made
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to the compensatory actions.
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The inspector discussed this observation with the shift manager who agteed that
the communications did not meet management expectations. The inspector
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concluded that the control room should have known the extent of the activity
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change and should have had an opportunity to determine whether the changes
affected the compensatory measures.
M 1.4 Unit 2 Service Water Flow Transmitter Calibration
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a.
Insoection Scope (62707)
The inspector observed performance of two service water flow transmitter
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calibrations.
b.
Observations and Findinas
The inspector found that the technicians were professional, knowledgeable of the
procedure, and used concurrent verification prior to operating any component. The
flow calibrations were completed without incident.
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M 1.5 Unit 2 Repetitive Maintenance on Nitroaen Vent Valve
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a.
Insoection Scone (61707)
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The inspector observed corrective maintenance to troubleshoot a nitrogen vent
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valve leak into the Unit 2 containment atmosphere. The inspector walked down the
clearance and reviewed the compensatory measures and the work history of the
valve.
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b.
Observations and Findinas
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The inspector noted that, as a result of a nitrogen vent valve leak, the associated
containment isolation valve for the nitrogen supply header remained in the closed
position to prevent an increase in containment pressure. The inspector found that
the clearance to isolate the nitrogen vent valve was implemented properly.
Compensatory measures were in place to supply nitrcgen to the power-operated
relief valve accumulators, if necessary. Proper housekeeping and foreign material
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exclusion controls were placed on the system when the valve was removed for
troubleshooting in accordance with the work order requirements.
The licensee found scoring on the valve stem and plug of a similar nature to
conditions found in the past. The valve team replaced the worn components and
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returned the valve to service, however, the leak continued. The inspector noted
that the nitrogen vent valves on both units have leaked often in the past 4 years.
This repetitive maintenance problem may be reflective of poor maintenance. The
inspector noted that, although the licensee's System Health Report documented
that nitrogen header leaks were to be addressed in the future, the nitrogen vent
valve problem was not specifically documented in the report. The inspectors were
concerned that repetitive maintenance problems may not be identified and corrected
in a timely manner. This matter will be reviewed as part of the closure of a
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previous inspection followup item dealing with valve maintenance
(IFl 50-445(446)/9610-01).
M1.6 Unit 2 Followuo on Feedwater isolation Valve Post-Maintenance Test Failure
a.
Insoection Scoce (62707)
The inspector observed portions of an emergent maintenance activity to
troubleshoot and repair a Unit 2 feedwater isolation valve during a planned outage.
Following the maintenance, the inspector reviewed the causes of the valve failure
during the post-maintenance test.
b.
Observations and Findinas
During the post-maintenance test, the valve did not stroke. The licensee discovered
that the technicians had incorrectly landed an electrical lead on the circuitry for the
valve actuator. The problem was corrected and the post-maintenance test was
reperformed successfully.
The licensee found that the technicians and the quality control inspectors failed to
identify the incorrectly landed lead. The licensee's corrective actions which
addressed the lack of attention to detail were appropriate. The inspector noted that
the failed test occurred before maintenance had released the valve for operation and
that the post-maintenance retest was appropriate.
The inspector concluded that the lack of attention to detail was isolated and not
representative of self-verification techniques demonstrated by instrumentation and
controls (l&C) technicians.
M1.7 Conduct of Maintenance Conclusions
Electricians performing troubleshooting on an inverter did not meet licensee
management expectations on conduct of maintenance and did not clearly
communicate the scope of the planned activity to the control room. Maintenance
personnel were well prepared for the repair of the alternate drain valve, but weak
communications between the valve team and the control room allowed the valve
team to change the scope of the maintenance on the alternate drain valve without
allowing operations the opportunity to determine whether changes to the
compensatory measures were necessary. The inspectors concluded that this was a
potential weakness in communications between the work groups and the control
room,
l&C technicians were professional, demonstrated knowledge of the service water
flow transmitter procedure, and used concurrent verification during the calibration of
component cooling water heat exchanger station service water flow transmitters.
I&C technicians incorrectly landed leads on a feedwater isolation valve, which
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prevented the valve from stroking during its postmaintenance test. The inspector
concluded that this error was isolated.
Ill. Enaineerina
E1
Conduct of Engineering
The inspectors conducted frequent reviews of engineering support to plant
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operations through a review of technical evaluations associated with degraded
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conditions, ONE Forms, engineered safeguards system walkdowns, and plan-of-the-
day meeting discussions. Specific noteworthy issues are discussed below.
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E2
Engineering Support of Facilities and Equipment
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E2.1
Review of FSAR Commitments
A recent discovery of a licensee operating their facility in a manner contrary to the
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FSAR description highlighted the need for a special focused review that compares
plant practices, procedures, and parameters to the FSAR description. While
performing the inspections discussed in this report, the inspectors reviewed the
applicable portions of the FSAR that related to the areas inspected. The inspector
verified that the UFSAR wardirc was consistent with the observed plant practices,
procedures, and/or parameters.
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E8
Miscellaneous Engineering Issues (92903)
E8.1
(Open) Unresolved item 50-445(4461/96-16 06: inconsistencies in the FSAR for
ECCS switchover from injection to recirculation. This item documented that the
emergency response procedure for the switchover contained nine additional steps
that were not analyzed in the FSAR.
At the exit meeting on December 19,1996, the inspectors informed the licensee
that FSAR Tab;e 6.3-7, which listed the manual actions required to perform the
switchover operation from injection to cold leg recirculation differed from the
actions in the emergency response procedure. The inspectors also informed the
licensee of a discrepancy within the FSAR for refueling water storage tank (RWST)
outflow requirements for a large break loss of coolant accident. FSAR
Section 6.3.2.8 stated that 94,179 gallons were available for transfer while
Table 6.3-11 stated that 90,166 gallons were required to complete the switchover.
The inspectors were concerned that the identified discrepancies called into question
the operability of the ECCS. On December 23, the licensee documented the issue
on ONE Form 96-1555.
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Procer..,q< .h tes
The vree
s reviewed archivoa documentation for changes to the procedures for
switc:. at from injection to recirculation. Procedure EOS-1.3, " Transfer to Cold
Leg Recirculation," had been designated as EOS-1.3A for Unit 1 and EOS-1.3B for
Unit 2 prior to the operating license being issued for Unit 2. The inspectors noted
that each procedure change contained a sheet that contained screening questions
which were used to determinr- whether a 10 CFR 50.59 evaluation was required.
10 CFR 50.59 requires an evaidation for changes to procedures that modify the
description of the procedure in the FSAR and also requires licensees to maintain
records of changes and that the records must include a written safety evaluation
which provides the bases for the determination that the change does not involve an
unreviewed safety question. Each reviewed screening sheet indicated that an
evaluation was not required because the changes did not change the procedure as
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described in the FSAR. The inspectors found that the screening sheets appear to be
incorrect because the changes modified the procedure as described in the FSAR.
The inspectors will followup on this matter in a future inspection.
Operability Review
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Following the inspectors' identification of the issues surrounding the switchover of
ECCS, the licensee performed a 50.59 safety evaluation, dated January 3,1997.
The inspectors reviewed the licensee's evaluation which concluded, in part, that the
probability of reaching the empty setpoint prior to completion of ECCS transfer was
slightly increased.
The bases for the RWST Technical Specifications indicate that the limits on the
minimum volume ensure that sufficient time is available for the operator to take
manual action and complete switchover of ECCS and containment spray suction to
the containment sump without emptying the tank or losing pump suction. Any step
added to the original procedure would increase the amount of time required to
complete the manual switchover, in both the safety evaluation and ONE Form, the
licensee indicated that the available volume in the FSAR was incorrect and that the
correct amount was 120,658 gallons. The licensee timed the implementation of the
switchover procedure on the simulator and performed calculations to determine
ECCS operability. The licensee concluded that the transfer would require
129,180 gallons; 8,522 gallons more than were available. The licensee then
decreased the RWST levelinstrument uncertainty assumptions in the analysis to
gain the additional 8,522 gallons. Based on the increased water volume available
and on the amount of time required to implement the switchover procedure from the
simulator scenario, the licensee concluded that the ECCS was operable. The
inspectors noted that the operator response time to implement the switchover was
reduced from the 30 seconds per step originally assumed in the FSAR. Although
the inpectors noteo inat sufficient margin exists in the ECCS switchover analysis
to conclude that operability was not affected, this matter will be subject to followup
during a future inspection.
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The inspectors noted that the original FSAR analysis, ONE Form, and 10 CFR 50.59
evaluation all assumed that the worst case single failure was the failure of one
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residual heat removal train suction valve to the RWST failing to close. The licensee
informed the inspectors that this was the worst case single failure because, as
noted in Footnote 7 of FSAR Table 6.3-11, the flow out of the RWST during
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switchover includes both pumped flow to the RCS and containment and backflow to
the containment sump. The inspector found that this assumption was not modeled
in the RWST outflow analysis. The licensee did not have an explanation as to why
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their analysis conflicted with the FSAR table. The inspectors questioned whether
this or the failure of a sump isolation valve to open was the worst case single failure
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for the RWST outflow analysis and planned to followup on this,
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Documentation Threshold for Dearaded items
The inspectors noted that the licensee did not document this potentially
nonconforming condition on a ONE Form until engineering had completed an
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operability determination supported by analysis, changes to calculation
assumptions, and simulator test runs. Based on this and previous observations, the
inspectors were concerned about the threshold for documenting potentially
nonconforming conditions. Failure to document potentially nonconforming
conditions as soon as they are identified has the potential to prevent management
from prinritizing resources and may prevent operations from making a timely initial
operability determination. The inspectors recognized that, in this case, the issue
was raised at an NRC exit meeting and that management was well aware of the
issue and had made the issue a high priority. The inspectors found that, although
licensee management placed a high priority on the issue, the licensee did not
document the issue on a ONE Form until a detailed operability determination had
been completed.
Conclusions
The inspectors concluded that the licensee did not appear to meet NRC
requirements for changes made to their emergency procedures for ECCS switchover
from injection to recirculation. More significantly, because of the licensee's failure
to perform a 10 CFR 50.59 safety evaluation of these changes, they f ailed to
determine if an unreviewed safety question existed. While the licensee concluded
that operability was not affected and no unreviewed safety question existed in their
subsequent evaluation, the inspectors found that these conclusions were made after
the licensee modified their original FSAR analysis of the ECCS switchover. These
modifications included a reduction in operstor response time and a reduction in
instrument uncertainty. The validity of these ar,sumptions was referred to the
NRC's office of Nuclear Reactor Regulation (NRR)in order to determine whether an
unreviewed safety question remains. The inspectors will followup on all aspects of
this Unresolved item af ter a determination is received from NRR.
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IV. Plant Support
R1
Radiological Protection and Chemiutry Controls
a.
Insoection Scope (71750)
The inspectors observed radiological protection activities as part of routine tours
and observation of maintenance and surveillance activities. The inspectors also
observed radiological protection support of containment activities during a planned
Unit 2 outage. The inspectors reviewed the primary and secondary water chemistry
and radiation protection department logs.
b.
Observations and Findinas
The inspectors found that the licensee continued to minimize the amount of
temporary, radiological drip containments. The inspectors noted excellent
radiological support of maintenance activities in the containment building during the
planned Unit 2 outage. The inspectors found that the licensee continued to closely
control water chemistry and take aggressive actions to correct any readings that
were outside the prescribed guidelines.
S1
Conduct of Security and Safeguards Activities
a.
Inspection Scope (71750)
The inspectors observed security and safeguards activities on routine tours, at
protected area access facilities, and at compensatory posts throughout the
inspection period.
b.
Observations and Findinas
The inspectors found that the security officers were attentive and conducted their
duties in a professional manner. When questioned, the officers were knowledgeable
of their post requirements.
V. Manaaement Meetinos
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management on
January 30,1997. The licensee acknowledged the findings presented. The licensee was
concerned with the inspector's characterization of the findings in the maintenance section
of the report and indicated that they believed it was not necessary to require maintenance
personnel to inform the control room of all changes in the scope of planned maintenance.
The inspec" ors clarified their observation by indicating that it was limited to changes in the
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scope of maintenance which could potentially affect the safe operation of the plant. The
inspectors informed the licensee that, when the operating crew has a heightened level of
awareness because the maintenance activity could impact safe plant operation or if
compensatory measures are developed for operators to deal with the modified plant
configuration, the operating crew should be informed of scope changes to assure that the
activity or compensatory measures remain acceptable. The licensee understood this
clarification. The inspectors also presented inspection results to members of licensee
management on March 4,1997.
The licensee did not identify any information that was reviewed during the inspection
period as proprietary.
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ATTACHMENT
SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
Licensee
M. R. Blevins, Plant Manager
D. L. Davis, Nuclear Overview Manager
M. L. Lucas, Maintenance Manager
F. W. Madden, Technical Support Manager
C. L. Terry, Group Vice President, Nuclear Production
R. D. Walker, Regulatory Affairs Manager
W. G. Guldemond, Shift Operations Manager
INSPECTION PROCEDURES USED
61726
Surveillance Observations
62707
Maintenance OLservations
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71707
Plant Operations
71750
Plant Support Activities
92901
Followup - Plant Operations
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92902
Followup - Maintenance
92903
Followup - Engineering
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ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-445(446)/9617-01
Inadequate corrective actions
Closed
50-445(446)/9616-02
IFl
Operator induced reactor plant transient
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Discussed
50-445(446)/9610 01
IFl
Valve maintenance
50-445(446)/9616-06
ECCS switchover, FSAR discrepancies
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LIST OF ACRONYMS USED
Final Safety Analysis Report
l&C
instrumentation and control
IFl
inspection followup item
MWth
mega-watts thermal
Office of Nuclear Reactor Regulation
ONE Form
Operatioris Notification and Evaluation form
refueling water storage tank
Technical Specification Interpretations
violation