ML20206H636
| ML20206H636 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 05/05/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20206H624 | List: |
| References | |
| 50-498-99-06, 50-498-99-6, 50-499-99-06, 50-499-99-6, NUDOCS 9905110266 | |
| Download: ML20206H636 (21) | |
See also: IR 05000498/1999006
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ENCLOSURE I
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
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Docket Nos.: 50-498 I
50-499
License Nos.: NPF-76 >
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NPF-80 -
' Report No.: 50-498/99-06
50-499/99-06
Licensee: STP Nuclear Operating Company
Facility: South Texas Project Electric Generating Station, Units 1 and 2
Location: FM 521 - 8 miles west of Wadsworth
Wadsworth, Texas 77483
Dates: February 21 through April 3,1999
Inspectors:. Neil F. O'Keefe, Senior Resident 4
Wayne C. Sifre, Resident inspector
Gilbert L.Guerra, Resident inspector
Don B. Allen, Project Engineer
Approved By: ' Joseph I. Tapia, Chief, Project Branch A
ATTACHMENTS: Supplemental Information
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9905110266 990505
PDR ADOCK 05000498
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EXECllTIVE SUMMARY
South Texas Project Electric Generating Station, Units 1 and 2
NRC Inspection Report No. 50-498/99-06; 50-499/99-06
This inspection included aspects of licensee operations, maintenance, engineering, and plant ,
support.L The report covers a 6 week period of resident inspection, supported by a regional )
. projects inspector.
Ooerations
-a : When a switchyard breaker failed, Unit 2 experienced a loss of offsite power to Trains B l
and C equipment. The output breaker for Standby Diesel Generator 22 failed to close 1
automatically because an essential chiller breaker cell switch failed to provide a
necessary permissive input. Operators had failed to recognize that the diesel had been
- inoperable for 2 weeks because they did not perform the procedurally required checks.
This,was a violation of Technical Specification 6.8.1. This Severity Level IV violation is
being treated as a noncited violation, consistent with Appendix C of the NRC
Enforcement Policy. This noncited violation is in the licensee's corrective action .
~ program as Condition Report 99-3690 (Section 01.2).
During the loss of offsite power to Unit 2 Trains B and C, operators quickly recognized
that the diesel breaker failed to shut automatically and manually shut it to restore power
to Train B equipment. While this action was appropriate, it was in conflict with the loss
of bus procedure. This loss of bus procedure was generic to all buses and, as a result, 1
was very long, cumbersome to use, and did not place a priority on restoring offsite
power to the engineered safety feature buses. This was a violation of 10 CFR Part 50,
Appendix B, Criterion V, for failure to follow procedures. This Severity Level IV violatien
is being treated as'a noncited violation, consistent with Appendix C of the NRC
Enforcement Policy. This noncited violation is in the licensee's corrective action
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program as Condition Report 99-3713 (Section 01.2).
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- Operators did not understand the Technical Specification requirements for supplying
offsite power to the engineered safety feature buses. As a result, they failed to enter
Technical Specification 3.0.3 and take the required 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> action to prepare to shut the ,
plant down when offsite power was lost to Trains B and C while Standby Diesel
Generator 22 was inoperable. When the Technical Specification 3.0.3 entry was
recognized, operators incorrectly concluded that offsite power requirements were being >
met. However, compliance was not restored for another hour and a half, when offsite
power was connected to Trains B and C. The inspectors noted that reconstruction of
the event, particiularly decision making, was significantly hampered because operators
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. did not make log book entries or record adequate notes during the event. This was a ,
z violation of Technical Specification 3.0.3. This Severity Level IV violation is being
- treated as'a noncited violation, consistent with Appendix C of the NRC Enforcement
Policy. This noncited violation is in the licensee's corrective action program as
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, Condition Report 99-3690 (Section 01.2).
.. Operators performed well while shutting down Unit 1 for its scheduled refueling outage.
Reactivity manipulations were well controlled, with excellent support by reactor
engineering personnel Evolutions were well briefed and controlled. Operators 1
responded well to a steam generator water level transient caused by a feedwater pump
. controller problem (Section 01.3).
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- The front end reactor coolant system reduced inventory and midloop operations were
performed in a well controlled manner. Excellent supervisory oversight provided
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. effective coordination of site activities and ensured the safe execution of this important
evolution. Detailed procedures effectively implemented relevant corrective actions and
commitments. Contingency actions were briefed in detail and assigned to specific
personnel and equipment was prestaged. Significant precautions were taken to inform
. personnel of the restrictions of activities to protect critical equipment (Section 01.4).
- - Licensed operator requalification evaluated scenarios were observed to challenge :
operators. Each crew observed demonstrated appropriate accident response, event
classification, and prompt reporting (Section PS.1). )
Maintenance '
- - . Performance of maintenance and surveillance activitics was good. The Unit 2 solid
state protection system testing was performed in a cautious, deliberate maner with
thorough preparation and excellent support from system engineering and maintenance
personnel (Section M1.1).
-* ' New fuel receipt inspections in Unit 1 were well conducted, utilizing proper supervision
and procedural controls. However, fuel movements within the spent fuel pool in Unit 2
were not controlled as well. A fuel bundle was placed in a storage location that
contained used fuel pool filters. The fuel bundle was undamaged, but the filters were .
compressed, making them difficult to remove. The licensee had not documented the !
storage locations of the filters and had not coordinated ~ storage of the filters with fuel
storage. No violations of NRC requirements were identified (Section M1.2).
- Following reactor vessel floodup from front-end midloop, local leak rate testing caused
the only available level indicator (a sightglass) to indicate lowering level. A test
boundary valve with known seat leakage allowed test pressure to affect the level i
indication. Test personnel did not evaluate the impact of the leak when the test was
rescheduled to be performed during the period when the sightglass was required for
plant control (Section M4.1).
Enaineerina
- Several engineering calculations performed in support of the Unit 1 outage were
reviewed and assessed to be of good quality. However, decay heat calculations
. performed in support of an earlier entry into a midloop condition were completed late in
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- the outage preparation process, and the outage schedule was built assuming the
calculations would demonstrate adequate heat removal capability (Section E2.1).
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- :The licensee successfully implemented a modification to the rod control system to
minimize unnecessary automatic rod motion due to hot-leg temperature streaming. The
10 CFR 50.59 evaluation was clearly written, and comprehensive and adequately
addressed applicable accidents analyses. The postmodification testing was appropriate
' for the modification (Section E2.2).
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' Plant Sucoort
- LAn emergency preparedness drill was observed and was found to provide effective
training. The emergency response organization was appropriately focused on accident
mitigation and measures to protect public health and safety. The licensee's emergency
facilities were in good working condition (Section PS.1)
.. Significant improvements over previous outage performance were demonstrated in dose . -
reduction and contamination control. Specifically, the licensee implemented several
ALARA and engineering controls including: mockup training, low dose waiting areas,
newly manufactured shielding, tents on the steam-generator platforms, and covered
floor grating areas to prevent spread of contamination (Section 01,4).
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Report Details
Summary of Plant Status
Unit 1 began the inspection period at 100 percent power. On March 27, the plant was shut
down for its scheduled refueling outage and remained shutdown for the remainder of the
inspection period.
Unit 2 operated throughout the inspection period at 100 percent power. The unit experienced a
partialloss of offsite power on March 12 when a switchyard breaker experienced a fault. This
resulted in loss of offsite power to Trains B and C equipment. Power was promptly restored via
the standby diesel generators.
I. Operations
01 Conduct of Operations
-01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent reviews of
ongoing plant operations. In general, the conduct of operations was professional and
safety conscious; specific events and noteworthy observations are detailed in the
sections below.
-01.2 Partial Loss of Offsite Power in South Texas Project Unit 2
a. Insoection Scoce (93702,71707)
Unit 2 experienced a partial loss of offsite power. Inspectors responded to the control
rooms of both units to determine the impact and observe operator response. The
inspectors reviewed reconstructed operator logs, response procedures, completed
surveillance data sheets, and the licensee's Event Review Team report. The event was
discussed in detail with the plant operators involved. The inspectors reviewed the tag-
out for Essential Chiller 21B and the procedure for racking out breakers.
b. Observations and Findinas
' Event Summary
At 2:12 p.m. on March 12, the load dispatcher attempted to restore one of the offsite
power lines that supplied the South Texas Project's switchyard. When Breaker Y640
was opened, the breaker experienced a fault. Protective relaying actuated to open other
switchyard breakers and the faulted breaker was deenergized. This resulted in
deenergizing the south switchyard bus and the Unit 2 standby transformer, which was
providing power to Trains B and C engineered safety feature (ESF) buses.
Unit 2 operators quickly recognized the loss of power to the south bus. Standby Diesel
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Generators (SDGs) 22 and 23 automatically started. SCG 23 sequenced loads as
expected; however, operators quickly recognized that the SDG 22 output breaker failed
to close and, as a consequence, the engine had no cooling water pump available.
Operators quickly took manual action to close the output breaker and observed that
Train B loads sequenced on automatically.
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Spent fuel' pool cooling was lost for approximately 1% hours and caused a less than 2*F
heatup. Containment cooling automatically shifted from chilled water to component
cooling water as designed, resulting in slightly elevated containment temperature and
pressure; operators responded appropriately to correct this condition. Reactor letdown
isolated, but was promptly restored; the resulting pressurizer level increase
(approximately 9 inches) was corrected. Offsite power to the deenergized buses was
restored from the Unit 1 standby transformer at 3:30 p.m. Trains B and C were then l
transferred to offsite power, and SDGs 22 and 23 were secured by 5:30 p.m.
The inspectors observed the impact of the switchyard transient on Unit 1. Reactor
letdown isolated but was promptly restored, with a corresponding small increase in
pressurizer level. . Several heating, ventilation, and air conditioning systems tripped and
were promptly restored. Power availability was verified by the operators.
Failure to Enter Technical Specification Required Shutdown Action Statement '
As a result of losing power to two trains of ESF buses from offsite and the failure of
SDG 22 to pick up its loads, the plant was in a condition prohibited by Technical
Specifications and Technical Specification 3.0.3 became applicable. Technical
Specification 3.0.3 requires that within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, actions shall be initiated to place the unit
in a mode in which the specification does not apply (i.e., shutdown). The prohibited {
condition was removed when offsite power was restored to Train B at 5:06 p.m. '
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Operators initially misunderstood the Technical Specification requirements. They
L conferred extensively with licensing personnel and concluded at about 4:30 p.m. that
Technical Specification 3.0.3 was entered at the start of the event, but inappropriately
concluded that the condition was rernoved when offsite power was available (but not >
restored) to the ESF buses. This resulted in continuing to be in a condition prohibited by
Technical Specifications longer than necessary.
Failure to recognize entry into a condition prohibited by Technical Specifications and
initiate action to place the unit cold shutdown was a violation. This violation will not be
cited in accordance with Appendix C of the NRC Enforcement Policy. This noncited
violation is in the licensee's corrective action program as Condition Report 99-3690 ,
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(NCV 499/99006-01).-
Cause of SDG 22 Being Rendered inoperable
The licensee initiated troubleshooting and an Event Review Team investigation to
' determine the cause of the SDG 22 output breaker failing to close automatically. The
licensee' determined that the breaker for Essential Chiller 21B was not providing proper
input to the SDG 22 breaker closure permissive circuit. This circuit required that the
loads be stripped from the bus before reenergizing the bus from the SDG To satisfy
the logic, Essential Chiller 218 was required to have its breaker either open or racked
out.
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The licensee also determined that the breaker had been racked out for 2 weeks for
. maintenance and that the switch that was supposed to sense the breaker position did
not operate properly. This condition rendered SDG 22 inoperable for 2 weeks before it
was recognized. The licensee's procedure for racking out breakers, OPOP01-AE-0001,
Revision 1 " Circuit Breaker Operation," required that operators verify proper indication -
. that applicable breakers were racked out by checking computer indications prior to
deenergizing control power. The inspectors determined that Tagout B4387, which
racked out the breaker and tagged it, did not specify performing the switch checks.
Operators misunderstood the intent of the checks and concluded in this case that it was
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acceptable to perform the check during restoration from the work. Failure to follow )
Proceduro OPOP01-AE-0001 was a violation. This violation will not be cited in
accordance with Appendix C of the NRC Enforcement Policy. This noncited violation is
in the licensee's corrective action program as Condition Report 99-3690 !
(NCV 493/99006-02).
Documentation and Procedure Problems
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The inspectors noted that, throughout the event response, no control room log entnes
were made. individual operators kept informal and incomplete notes of major events.
The log was recreated some time after inspectors left the control room at 5:40 p.m. The
inspectors observed this practice during the previous inspection in the simulator and ;
- documented the observation in NRC Inspection Report 50-498/99-02; 50-499/00-02.
The practice of not formally recording events and limiting condition for operation entries
in real time was considered to have contributed to the failure to recognize entry into a
required shutdown action.
The inspectors reviewed the surveillance documents for Procedure OPSP03-EA-0002,
Revision 4,"ESF Power Availability," performed during this event. The data sheets used
to verify the required power sources were shown in diagram form. The acceptance
criteria, specified in a different part of the surveillance were clear and correctly reflected
. the Technical Specification requirements. However, during this event, operators did not
correctly correlate the data sheet information with the acceptance criteria. As a result,
they incorrectly concluded that Technical Specification credit could be taken for
restoration of offsite power when offsite power was restored to the 13.8KV buses but not
to the associated 4160V ESF buses. The inspectors concluded that Unit 2 was in
' Technical Specification 3.0.3 from 2:12 p.m. until offsite power was restored to ESF
Bus E2B at 5:06 p.m.
The inspectors noted that Procedure OPOPO4 AE-0001," Loss of Any 13.8KV or 4.16KV
Bus," Revision 13, was the primary procedure used by operators to respond to this
- event. This procedure was more than 100 pages in length, contained 16 addendums,
and was so generic in nature that it was cumbersome to use. This observation was
made in NRC Inspection Report 50-498/98-15; 50-499/98-15 during an earlier loss of
power event. The inspectors noted that the procedure did not convey the appropriate
priority to restore offsite power to the ESF buses. Additionally, when the SDG 22 output
breaker f ailed to close, this procedure inappropriately directed operators to trip the
engine; without resolving the inappropriate procedure step, operators manually closed
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the breaker. This was a failure to follow procedures and is a violation of 10 CFR l
Part 50, Appendix B, Criterion V. ' This violation will not be cited in accordance with
Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective
actica program as Condition Report 99-3713 (NCV 499/99006-03).
c. Conclusions
When a switchyard breaker failed, Unit 2 experienced a loss of offsite power to Trains B
and C equipment. The output breaker for Standby Diesel Generator 22 failed to close
automatically because an essential chiller breaker cell switch failed to provide a
necessary permissive input. Operators had failed to recognize that the diesel had been
inoperable for 2 weeks because they did not perform the required checks. This was an
NCV.
Operators quickly recognized that the diesel breaker failed to shut automatically and
manually shut it to restore power to Train B equipment, inspectors identified that this
action,' whi!e appropriate under the circumstances, was in conflict with the loss of bus ,
procedure. This procedure was generic to all buses and, as a result, was very long,
cumbersome to use, and did not place a priority on restoring offsite power to the ESF
buses. This was an NCV.
Operators did not understand the Technical Specification requirements for supplying
offsite power to the ESF buses. As a result, they failed to enter Technical
Specification 3.0.3 and take the required I hour actions to prepare to shut the plant
down. When the Technical Specification 3.0.3 entry was recognized, operators
incorrectly concluded that offsite power requirements were being met. However,
compliance was not restored for another hour and a half, when offsite power was
connected to Trains B and C. This was an NCV. The inspectors noted that
reconstruction of the event, particularly decision making, was significantly hampered
because operators did not make a single log book entry or record adequate notes
during the event.
01.3 Unit 1 Shutdown and Control Rod Testina Observations (71707)
The inspectors observed the performance of operators while shutting down Unit 1 for its
scheduled eighth refueling outage on March 26-27. This included testing of all control
rods.
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The inspectors observed reactor operators performing reactivity manipulations in
accordance with approved procedures. Reactor engineering provided close support
during both the shutdown and rod testing. Reactivity control was enhanced by reactor
engineering through the use of predicted data for the planned shutdown sequence
based on historical data frcm previous shutdowns. These data allowed operators to
better plan reactivity manipulations throughout the complex shutdown sequence.
Formal communication was evident throughout unit shutdown and cooldown. Evolutions
were well briefed and cortrolled. Support personnel were readily available.
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Plant equipment performed well during the shutdown, with several minor exceptions.
- The Steam Generator Feed Pump 13 controller did not perform as expected while
operators attempted to shut down Steam Generator Feed Pump 12 and resulted in
water level oscillations in all four steam generators. Operators recognized the problem
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and quickly took action to stabilize water levels and secure Steam Generator Feed
Pump 13 instead of 12.
- The inspectors observed that the shutdown sequence included an aggressive
surveillance testing schedule.- At times, this resulted in large numbers of extra .
personnelin the controls area of the control room. Surveillance testing and main turbine
overspeed testing were performed without problem.
Control rod testing was performed following reactor shutdown to demonstrate that all
rods would insert. This was done in response to past problems. Proper controls were
utilized to ensure that the reactor remained shut down while control rod banks were
withdrawn and inserted. The testing identified four control rod assemblies that did not
fully insert and remained six steps from fully inserted. Each of the problem rods were
Cycle 1 fuel which was at its end of life, and all the control rods were scheduled to be
replaced during the outage. However, each of the problem fuel assemblies had a lower
burnup exposure than previously identified problem bundles. Newer fuel designs have
not exhibited this problem.
01.4 Observation of Unit 1 Reactor Coolant System Midlooo Ooerations
a. Insoection Scone (71707)
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The inspectors maintained continuous onsite coverage during front-end midloop
operations in Unit 1. The inspectors observed operator training, preparations, and
briefings, walked down temporary systems for water level indication and vacuum filling,
and verified that personnel designated to perform contingency actions were trained and
stationed with necessary equipment. Procedures, planning, and oversight were
evaluated prior to reduced inventory operations.-
b. Observations and Findinas
The inspectors observed training for the operating crew scheduled to perform midloop
operations.1 Procedures were walked through and then performed in the simulator.
Contingency scenarios were also covered, although the inspectors noted that the loss of
residual heat removal (RHR) scenario was not a particularly challenging case. Industry
lessons-leamed were discussed.
The inspectors observed that the licensee's procedures governing this complex
evolution were detailed. These procedures were found to effectively implement
corrective actions committed to in response to site and industry events related to
midloop operations. Contingency actions were clearly specified and briefed, and
- designated personnel were stationed and equipment was prestaged. Periodic site
announcements were made to remind personnel of the midioop activities and the
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' additional restrictions on other site activities. . Signs were posted at access points to the
- critica! equipment. An operntor was dedicated to venting the residual heat removal
system in the event of loss of level in the reactor vessel. Pipe caps were removed, and
hoses were attached to these vents to minimize any delay.
Operators alertly monitoreci all pertinent instrumentation and performed frequent
verification of parameters among diverse instruments.~ The reactor vessel water level
s!ght glass was monitored by an operator in the containment and on a video monitor in
the control room. Detailed system drawings and operational data were provided to
ensure that operationallimits were maintained. Communications were maintained
between the control room and important field activities throughout the evolution.
- The inspectors reviewed 1he applicable procedures and plans, performed a walkdown of
the accessible critical equipment, and observed control room activities during the
draindown to midloop and the restoration of water level to above the reactor coolant
' loops.
During midloop operations, work activities on the unit were limited to those that did not
impact the operator's ability to control decay heat removal. Work packages were pulled
from the field, reviewed, and only reissued if approved by the shift supervisor and l
midloop coordinator. In spite of these controls, several activities were allowed in the I
control room that had tne potential to distract the operators. An intermediate range
nuclear instrument calibration was performed which resulted in several alarms and in a t
technician in the operation's area of the control room. Troubleshooting activities for a
steam generator level indication problem required sharing the plant computer terminal
- between the technician and the operators. Neither activity interfered with the midloop
operation.
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Thi draindown was performed slowly and cautiously and in accordance with the
procedure. ' As each heated junction thermocoJple in the reactor vessel level system
was uncovered, agreement with the " slinky" sight glass level indication was verified.
Agreemen; with other indications was also verified.
When water level was lowered to the top of the loops, instrumentation and contro!
technicians unsuccessfully attempted to place the hot-leg narrow-range level
instruments in sen ice and get agreement among indicatore. The draindown was
suspended. After 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />, the licensee concluded that insufficient nitrogen had been
injected into the s'.eam generator U-tubes. As a result, draindown was significantly
slowed. In the process of verifying the instrument lineup, technicians inadvertently
removed the hot-;eg narrow-range level instruments from service before the error was
discovered. ' Level agreement was then restored arnong instruments.
- Supsrvisory oversight of the evolution was excellent. Outage management actively
provided important coordination of all site activities to ensure that equipment important
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for midloop operations or contingency actions were maintained available. Senior
licensed operators were assigned to supervise the operational aspects of the evolution
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. which included coordinating entry into the primary side of each steam generator to
install nozzle d.ams and ensuring that a hot-leg vent path was always available.
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The steam generator work activities were well performed. Dose control improvements
significantly reduced radiation exposure over previous evolutions. Contamination
controls were also effectively improved. Specifically, the licensee implemented several
- ALARA and engineering controls including: mockup training, low dose waiting areas, 1
- improved shielding, tents on the steam-generator platforms, and covered floor grating
- areas to prevent spread of contamination.
- c. ! Conclusions
inspectors concluded that front-end reactor coolant system reduced inventory and
midloop optsrations were performed in a controlled manner. Excellent supervisory.
, oversight was provided which effectively coordinated site activities and ensured the safe
. execution of this important evolution. Detailed procedures effectively implemented
relevant corrective actions and commitments. Contingency actions were briefed in detai! .
and assigned to specific personnel, and equipment was prestaged. Significant
precautions were taken to inform personnel of the restrictions of activities to protect
critical equipment. Significant improvements over previous outage performance were
demonstrated in dose reduction and contamination control. Specifically, the licensee
implemented several ALARA and engineering controls including: mockup training, low
t ' dose waiting areas, improved shielding, tents on the steam-generator platforms, and
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covered floor grating areas to prevent spread of contamination.
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- 03 Operations Procedures and Documentation
-03.1 Engigpred Safetv Feature (ESF) Systems Walked Down (71707)
The inspectors used Inspection Procedure 71707 to walk down accessible portions of
the folic, wing ESF systems:
. Hydrogen Recombiners (Unit 1)
L Containment Spray System (Unit 1)
. . Fuel Handling Building Ventilation Exhaust System (Units 1 and 2)
. Equipment operability and material condition were acceptable in all cases. The
inspectors verified that the systems were aligned properly for the existing mode of
' operation. The inspectors conducted daily control board walkdowns to verify that ESF
systems were. aligned as required by Technical Specification for the existing operating
mode, that instrumentation was operating correctly, and that power was available.
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ll. Maintenance l
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M1 Conduct of Maintenance
M1.1 Maintenance and Surveillance Observations l
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a, inspection Scooe (62707. 61726) j
The inspectors observed all or portions of the following maintenance and surveillance
activities. For surveillance tests, the procedures were reviewed and compared to the
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Technical Specification surveillance requirements and bases to ensure that the
procedures satisfied the requirements. Maintenance work was reviewed to ensure that
. adequate work instructions were provided, that the work performed was within the scope
of the authorized work, and that it was adequately documented. Work practices were
also observed. In each case, the impact to equipment operability and applicable
Technical Specifications actions were independent!y verified.
Surveillances observed: l
- OPSP03-DG-0003, " Standby Diesel Generator 13 Operability Test" (Unit 1)
- OPSP03 EA-0002,"ESF Power Availability"(Unit 2) l
- OPSP03-SB-0001, " Steam Generator Blowdown System Valve Operability Test" l
(Unit 2)
Maintenance activities observed:
- New Fuel Receipt and inspection (Unit 1)
- Fuel Handling Bu!! ding Ventilation Modification (Unit 1)
- Solid State Protection System Logic Train S Functional Test and
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' ableshooting (Unit 2)
b. Observations and Findinas
The inspectors observed that the work performed during these activities was thorough
and detailed. Work observed was performed within the scope of the work package.
Technicians were experienced and knowledgeable of their assigned tasks. Equipment
manipulations during tests were very well controlled. Craft and operators utilized good
self-verification techniques. Communication between control room operators and plant
operators and technicians in the field were precise and sufficiently detailed. Supervisory
oversight was evident, and engineering personnel frequently were observed
participating in and observing tests. The inspectors verified that surveillance activities
satisfied Technical Specifications requirements.
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On February 27, the inspectors observed licensed operators and instrumentation and
controls technicians perform a functional test of the solid state protection Train S
system. The test was performed utilizing Temporary Surveillance
- Procedure 2 TSP 03-SP-0002, Revision 1, "SSPS Logic Train S Functional Test." This
test was performed to verify that the solid state protection system (SSPS) test circuit
would detect a failed card with an intermittent low voltage condition previously identified
in the Unit 2 Train S circuit. The low voltage condition was identified by the licensee
during troubleshooting for a failed card.
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The inspectors reviewed the procedure and determined that the test methodology was
to simulate a failed card and determine if the installed semiautomatic test circuit would
detect the induced failure. The procedure also included two contingency tests to assure
system operability if the test card failed to detect the induced failure. The inspector i
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reviewed Unreviewed Safety Question Evaluation 98-20456-6 developed for the
performance of the test and determined that it was thorough and satisfied the
requirements of 10 CFR 50.59.
The inspectors observed licensee preparations for the test. Reactor operators,
technicians, and the system engineer performed a detailed walkthrough of the
procedure. As a result, two minor errors were identified and corrected in the procedure.
The prejob briefing in the control room was detailed and focused on risk to plant
operation. During test performance, communications were precise and deliberate. The
system engineer and maintenance supervisor provided direct support and oversight.
Switch manipulations were performed by a reactor operator with direct supervision by a
senior reactor operator. The test circuit initially failed to detect the induced failure;
however, the system engineer determined that the low voltage condition was not
present. As a result, the test was considered inconclusive due to the intermittent nature
of the low voltage condition. However, the test was able to confirm system operability.
Further troubleshooting was scheduled for the Unit 2 refueling outage in the fall of 1999.
c. Conclusions
Performance of maintenance and surveillance activities was good. The Unit 2 SSPS
testing was performed in a cautious, deliberate manner with thorough preparation and
excellent support from the system engineering and maintenance.
M1.2 Soent Fuel Pool Activities
a. Inspection Scoce (71707)
The inspectors observed fuel movement activities in the Units 1 and 2 fuel handling
buildings. These activities included new fuel receipt in Unit 1 and spent fuel bundle
movements in preparation for boraflex panel removal in Unit 2.
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b. Observations and Findinos .
Unit 1 received new fuel for the upcoming refueling outage during this inspection period.
The inspectors observed that work involving new fuel receipt, inspection, and storage
was systematic and efficient. New control rod assemblies were also received and
inspected. The fuel receipt was adequately supported by engineering, operations,
maintenance, and health physics personnel. The inspectors noted good coordination
between the different plant departments. New fuel was inspected and handled in
accordance with procedures. The new fuel was visually inspected for defects and
foreign objects. Following inspection, the fuel was placed into storage in the spent fuel
pool.
On February 22, while moving fuel within the Unit 2 spent fuel pool for boraflex
replacement, operators observed that the load cell reading increased suddenly by
500 pounds. This was indicative of binding. They stopped and lowered the bundle back
into its cell. The load cell remained reading 500 pounds high and was reset after
consulting with reactor engineering personnel. The load cell was verified to be reading
correctly by the use of a dummy bundle, and fuel movement was resumed. The bundle
was successfully moved without further incident.
On March 3,1999, two used fuel pool filters were compressed in a fuel storage rack
while attempting to insert a fuel assembly. Licensee management suspended fuel
movement. The fuel assembly was not damaged. Debris from the filter was released
within the pool. The Health Physics department successfully removed all material on
the surface. Investigation revealed other cells with unaccounted filters. A total of nine
filters were removed and stored in another location. The filters which were compressed
remained in Cell 2B42 at the conclusion of the inspection period. Procedural
requirements for the inventory and storage of filters in the spent fuel pool had changed;
however, the filters had not been removed when the inventory location changed.
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Corrective actions implemented by the licensee due to this event included: positive
verification of empty storage locations in the spent fuel pool before movement, a prejob
brief of this event for crews and reactor engineers, and contingency plans. The licensee
was working toward the removal of the filters from Rack Location 2B42.
c. Conclusions
New fuel receipt inspections in Unit 1 were done well, utilizing proper supervision and
procedural controls. However, fuel movements within the spent fuel pool in Unit 2 were
not controlled as well. A fuel bundle was placed in a storage location that contained
used fuel pool filters. The fuel bundle was undamaged, but the filters were compressed,
making them difficult to remove. The licensee had not documented the storage
locations of the filters and had not coordinated storage of the filters with fuel storage.
No violations of NRC requirements were identified.
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M1.3 Offsite Power Reliability Review (62707)
The inspectors reviewed the licensee's reliability / availability _ data for offsite power
transmission lines and compared it with the licensing basis stated in the Updated Final !
Safety Analysis Repor1(UFSAR). Section 8.2 of the UFSAR stated in part that, based
on a historical review of Houston Lighting and Power 345 kV transmission system data,
the expected frequency of instantaneous line outages was 2.14 outages per year per-
100 circuit miles. An instantaneous outage was defined as an outage in which the line
circuit breakers tripped and reclosed, reenergizing the circuit in less than one second.
The UFSAR also defined a sustained outage as an outage that required manual
reciosing of the circuit breaker to reenergize the circuit. The UFSAR stated frequency
for sustained outages was 1.34 outages per year per 100 circuit-miles.
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During this inspection period, the licensee experienced an unusual number of unplanned
line outages including four sustained outages on March 9.. In their evaluation, the -
' licensee attributed the increased outage frequency to flashover of dirty line insulators.
The inspector reviewed the available line outage data for the 345 kV transmission lines i
- that connect to the South Texas Project switchyard. The system engineer stated that
the data was generated quarterly and that the best available data was through the end
of 1998. The inspector noted th;.1, although the instantaneous outage frequency was
within the licensing basis, the sustained outage frequency was 1.34, slightly higher that
the frequency stated in the UFSAR. The inspectors will review the data for the first
quarter of 1999 when it is available as well as the licensee's efforts to maintain offsite
power reliability consistent with their licensing basis. This item will be tracked as an
inspection followup item (IFl 50-498;499/99006-04).
M4 - Maintenance Staff Knowledge and Performance
( M4.1 E Maintenance Test Caused Faultv Reactor Water Level lndication (93702)
Unit 1 experienced an indicated reactor water level transient following midloop with tha
reactor flooded up near the head flange. On April 1, a localleak rate testing boundary
valve experienced seat leakage, and test pressure leaking out of the test boundary
- caused indicated level on the reactor water level sight glass, the only available indicator,
to trend downward. Operators responded conservatively in accordance with
procedures. Test personnel were quick to report that their testing could have caused
_ the observed indications. When test pressure was' removed, water level indication
' returned to expected levels. Although the leaking valve had known seat leakage, it was
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not evaluated for potential impact on reactor water level indication during the test. This
evaluation was originally not needed because the test was originally scheduled to be
performed during the period when the sight glass was not required for plant control.
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111. Enaineerina
E2 . Engineering Support of Facilities and Equipment ,
E2.'1 : Enaineerina Sunoort for Unit 1 Ou_laae Preparations (37551)
The inspectors reviewed the following calculations performed by engineering in support i
of performing midloop earlier after shutdown than previously experienced:
99-FC-003 " Spent Fuel Pool Heatup Analysis for 1RE08"
99-FC-001 ' "RCS Heatup Rates During 1RE08 Mid-loop Operation"
99-RC-002 "1RE08 Mid-loop RHR Performance Evaluation"
NC-7137 " Bounding RHR Mid loop Performance Evalation"
These engineering calculations were detailed and complete. Appropriate conservatism
and reasonable assumptions were used in each example. The decay heat removal !
calculations were used to support planned entry into reduced inventory and midioop l
conditions earlier during the outage than had previously been performed. The
calculations demonstrated that adequate heat removal capability existed with two trains
of RHR. However, the inspectors noted that the calculations were completed late during
the outage preparation process and that the outage schedule was built assuming the
calculations would demonstrate adequate heat removal capability. !
E2.2 Desian Chanae to Minimize Unnecessarv Automatic Control Rod Motion ,
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a .' L Inspection Scope (37551)-
The inspectors reviewed the licensee's 10 CFR Part 50.59 Evaluation for Design-
Change Package 95-11217-10," Automatic Rod Control Rod Movement Minimization ' :
During Normal Operations" and discussed the purpose, implementation, and
postmodification testing with engineering personnel.
b.' Observations and Findinas
-The licensee experienced unnecessary automatic control rod motion periodically during i
steady state operation. This was an industry issue that was caused by localized
temperature variations in the hot-leg known as " hot leg temperature streaming." The
licensee consulted with Westinghouse and decided to modify the system response by
revising the time constants in the rod control circuitry. This method had been
. . implemented successfully at other Westinghouse plants.
The 10_CFR Part 50.59 evaluation relied on a Westinghouse analysis which determined
that the modified rod control system would continue to operate as described in the
UFSAR. Applicable accident analyses which relied on rod control system automatic
Loperation for mitigation were appropriately addressed in the licensee's evaluation. The
evaluation was clearly written and comprehensive.
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Postmodification testing consisted of circuit card checkouts on a test bench and
observation of the rod control system after placing the system in automatic. The bench
tests were adequate to verify acceptable performance. No spurious control rod motion
occurred after the modification was implemented. The inspectors noted that the
duration of monitoring in Unit 1 was limited due to the beginning of the refueling outage.
c. Conclusion
The licensee successfully implemented a modification to the rod control system to -
minimize unnecessary automatic rod motion due to hot-leg temperature streaming. The
10 CFR Part 50.59 evaluation was clearly written and comprehensive and adequately
addressed applicable accidents analyses. The po.stmodification testing was appropriate
for the modification.
IV. Plant SUDDort
P5 Staff Training and Qualification in Emergency Preparedness
PS.1 Emeraency Preparedness Trainina Observations
a. Insoection Scooe (71750)
The inspectors observed licensed operator requalification evaluated simulator sessions
for emergency response, as well as a site emergency response team drill on March 3.
b. Observations and Findinas
The inspectors observed licensed operator requalification for three separate crews that
were being evaluated for emergency response during simulator sessions. The
inspectors observed that the simulator sessions were challenging scenarios, in each
. case, operators correctly classified each event and ensured timely reporting to outside
agencies. Several support personnel were new to their emergency response roles, but
each was effective due to coaching from their respective shift supervisors.
The scenario included a partialloss of electrical power. The inspectors observed that
this portion of the scenario had a situation that was very close to an actual plant event in
Unit 1 in June of 1998. NRC inspection Report 50-498/98-15 documented inspector
concerns about Procedure OPOPO4-AE-0001, " Loss of Any 13.8KV or 4.16KV Bus,"
Revision 13,in responding to that event. During the simulator sessions, the inspectors
noted that the procedure remained unimproved; operators did not really use the
procedure before the scenario progressed to the point where a manual reactor trip was
necessary.
The emergency response organization training drill was conducted using a scenario
similar to that used for the operators. Some training value was lost by not using the
simulator during the drill; scripted data was used rather than realtime computer
information. Some training value was lost by simulating the dispatching of repair teams,
rather than actually sending them.
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The inspectors observed operations in the Operations Support Center. Priorities were
clearly communicated. Briefings to repair teams were thorough, although very time
consuming. Since the scenario was scripted, the slow dispatching of repair teams
impacted scenario progression at times.
The inspectors observed that personnel in the Technical Support Center performed as a
' team in responding to the exercise scenario conditions. Technical Support Center .
staffing and activation was prompt, and command and control was established
effectively. Plant conditions were analyzed and evaluated for prioritization and
coordinated with the Operations Support Center. The use of status boards was effective
in monitoring key plant parameters and conditions. The inspectors observed good
coaching of closed loop communications for personnel not accustomed to closed loop
communication.
The inspectors observed that personnel in the Emergency Operations Facility were )
appropriately focused on potential offsite release mechanisms. When the simulated
situation degraded, personnel projected when the situation would require entry into a
general emergency and conservatively declared the escalation before actually reaching
it. Appropriate protective action recommendations were made.
The licensee's emergency response facilities were maintained in good condition.
Communications and other emergency equipment were available and in good working
condition. Procedures and reference material were current and readily available,
c. -Conclusions
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An emergency preparedness drill was observed to provide effective training. The
emergency response organization was appropriately focused on accident mitigation and - l
measures to protect public health and safety. The licensee's emergency facilities were
in good working condition.
Scenarios evaluated during licensed operator requalification challenged operators.
Each crew observed demonstrated appropriate accident response, event classification, ;
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and prompt reporting.
Miscellaneous issues - ,
The Severity Level IV violations listed below were issued in Notices of. Violation prior to
the March 11,1999, implementation of the NRC's new policy for treatment of Severity
Level IV violations (Appendix C of the Enforcement Policy). Because these violations
. would have been treated as noncited violations in accordance with Appendix C, they are
being closed out in this report.
1 Violation number 50-498;499/9706-08 This violation is in the licensee's corrective
action program as CR 97-16443.
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Violation number 50-499/9809-03 This violation is in the licensee's corrective '
action program as CR 9814552.
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V. Manaaement Meetinas
X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management on
April 6,1999. Management personnel acknowledged the findings presented. The
inspector asked whether any materials examined during the inspection should be
considered proprietary. No proprietary information was identified.
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ATTACHMENT
SUPPLEMENTAL INFORMATION
PARTIAL LIST OF PERSONS CONTACTED
Licensee
P. Arrington, Nuclear Assurance and Licensing
M. Berrens, Manager, Work Control l
J. Calvert, Manager, Operations Training
T. Cloninger, Vice President, Engineering and Technical Services
W. Dowdy, Manager, Plant Operations Unit 2 -
R. Fast, Manager, Unit 1 Maintenance
T. Frawley, Operations Shift Supervisor
J. Groth, Vice President, Nuclear Generation
E. Halpin, Manager, Unit 2 Maintenance
S. Head, Supervisor Nuclear Assurance and Licensing
J. Johnson, Manager, Engineering Quality
T Jordan, Manager, Systems Engineering
M. Kanavos, Manager, Mechanical and Civil Design Engineering
A. Kent, Manager, Electrical / Instrumentation and Controls, System Engineering
M. Lashley, Manager, Reliability Engineering
D. Leazar, Director, Nuclear Fuel and Analysis
R. Lovell, Manager, Generation Support
R. Masse, Plant Manager, Unit 2
F. Mangan, Vice President, Business Services
M. McBurnett, Director, Quality and Licensing
B. Mookhoek, Nuclear Assurance and Licensing
G. Parkey, Plant Manager, Unit 1
J. Phelps, Manager, Plant Operations Unit 1
T. Powell, Manager, Health Physics
J. Sheppard, Vice President
S. Thomas, Manager, Design Engineering Department
NRC
T. Alexion, STP Project Manager, NRR
P. Kang, Electrical Branch, NRR
R. Smith, OA Branch, NRR
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INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering
IP 61726: Surveillance Observations ,
IP 62707: Maintenance Observation
IP 71707: . Plant Operations
IP 71750: Plant Support -
IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
ITEMS OPENED. CLOSED. AND DISCUSSED
Ooened
50-499/99006-01 NCV Failure to recognize entry into Technical
Specification 3.0.3 during loss of offsite power to
two trains with inoperable SDG
50-499/99006-02 NCV Failure to follow procedure requiring checks after
racking out breaker
50-499/99006-03 NCV Failure to have procedure appropriate to the
circumstances for a diesel-generator output i
breaker failure to close
50-499/99006-04 IFl Review of offsite power reliability
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Closed
50-499/99006-01 NCV Failure to recognize entry into Technical l
Specification 3.0.3 during loss of offsite power to
two trains with inoperable SDG
50-499/99006-02 NCV Failure to follow procedure requiring checks after
. racking out breaker
50-499/99006-03 NCV Failure to have procedure appropriate to the
circumstances for a diesel-generator output
breaker failure to close
50-498;499/9706-08 VIO Failure to document a written unreviewed safety
question determination upon installation of the
advance liquid waste processing system
50-499/9809-03 VIO Inappropriate work instructions cause reactor trip
on loss of feedwater to one steam generator
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