IR 05000499/1999014
| ML20216F469 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 09/03/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20216F466 | List: |
| References | |
| 50-498-99-14, 50-499-99-14, NUDOCS 9909220054 | |
| Download: ML20216F469 (20) | |
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ENCLOSURE U.S. NUCLEAR REGULATORY COMMISSION REGION IV -
Docket Nos.:
50-498 50-499 License Nos.:
NPF-76 NPF-80 Report No.:
50-498/99-14 50-499/99-14 Licensee:
STP Nuclear Operating Company Facility:
South Texas Project Electric Generating Station, Unit:s 1 and 2 Location:
FM 521 - 8 miles west of Wadsworth Wadsworth, Texas Dates:
June 27 through August 7,1999 Inspectors:
Neil. F. O'Keefe, Senior Resident inspector Anthony T. Gody, Senior Resident inspector Wayne C. Sifre, Resident inspector Gilbert L. Guerra, Resident inspector Approved By:
Joseph I. Tapia, Chief, Project Branch A ATTACHMENTS: Supplementalinformation 9909220054 990903 PDR ADOCK 05000498
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EXECUTIVE SUMMARY South Texas Project Electric Generating Station, Units 1 and 2 NRC Inspection Report No. 50-498/99-14; 50-499/99-14 This inspection included aspects of the licensee's operations, maintenance, engineering, and plant support. Th's report covers a 6-week period of resident inspection.
I Operations After securing a low pressure feedwater heater drip pump for planned maintenance, the
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heater level control system behaved erratically and led to the isolation of one low pressure heater string. Operators evaluated the situation and decided to disregard procedural guidance to reduce power to 90 percent with management concurrence.
The heater string was restored in a reasonable time, and the procedure was clarified.
This was an example of poorly performing balance of plant equipment challenging operators (Section 01.1).
Unit 1 operators responded well to a plant trip. All control roas inserted and plant
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systems responded as expected. Operators properly implemented plaat emergency procedures and quickly stabilized the plant in Mode 3. This plant transient was caused by a loose wire in the turbine control circuit (Section 01.2).
Licensee management demonstrated a questioning attitude and conservative decision
making during two posttrip Plant Operations Review Committee meetings.
Troubleshooting was properly focused, conducted safely, and identified the root cause
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J of the June 27 trip. The plant was started up by knowledgeable operators with good safety focus (Section 01.2).
Unit 2 operators responded well to loss of a service water pump when the redundant
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pump was not available. Operators prudently conducted a rapid power reduction to 48 percent and reduced heat loads to avoid a turbine trip and allow for an orderly shutdown if the remaining pump was unable to carry the load. Extra operators were provided in the control room to assist and were skillfully directed as a team by the Unit Supervisor (Section 01.3).
Inspectors observed two power ascensions in Unit 2. Reactivity manipulations were
closely supported by reactor engineering and reflected lessons learned from the inadequate control of reactivity event of the previous Unit 1 startup (Section O1.4).
The inspectors performed detailed walkdowns of accessible portions of all three trains of
the emergency core cooling system in Units 1 and 2. Area housekeeping was good.
The inspectors noted minor buildup of boron crystals on some valves and discovered several nomenclature errors on valve and electrical panel labels. System health reviews confirmed that the material condition of these systems was good. However, several valves associated with the safety injection accumulators had seat leakage that required periodic operator action to correct levels and pressures (Section O2.1).
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-2-Maintenance The observed maintenance and surveillance activities were performed well and in
accordance with approved procedures. Electrical safety precautions and foreign material exclusion practices were exce!!ent. Technical Specification surveillance requirements were satisfied by the observed tests (Section M1.1).
A worker chipping rust at the plant intake structure caused a fault in a service water
pump. Since the standby pump was removed for planned maintenance, this necessitated a sapid power reduction to reduce heat load on the system in order to avoid tripping the turbine. The licensee was evaluating work controls necessary to avoid working in the vicinity of important equipment when redundant trains are removed from service, as well as evaluating the material condition of equipment locatad at the intake structure (Section M1.2).
Operators moving fuel within the spent fuel pool became distracted while conducting
informal training and failed to properly verify the correct cell location before moving a bundle. As a result, they moved the wrong bundle and lowered it onto another bundle.
This event was caused by inattention and improper verifications. Fuel handling movements were not stopped as required by procedure after the incident. This event was the fourth fuel handling event onsite recently, indicating a weakness in attention to detail while moving fuel. Continuing examples of fuel handling events indicated that the corrective actions program was not adequately dealing with the declining trend. Failure to follow Procedure OPEP02-ZM-0005 was a violation of Technical Specification 6.8.1.
This Severity Level IV violation is being treated as a noncited viiolation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Condition Report 99-10645 (Section M1.3).
A one-time emergency Technical Specification amendment was granted in accordance
with the regulations in 10 CFR 50.91 to permit sufficient time for the licensee to i
install / remove blank flanges in the Unit 2 fuel handling building ventilation system following the identification of a grounded exhaust booster fan motor. Corrective actions for similar problems in April and October 1998 were considered appropriate and timely, but were not yet implernented. No violation occurred as a result of this event (Section M2.1)
Maintenance performed on a flow control motor operated valve for the steam driven
auxiliary feedwater pump resulted in the valve being inadvertently left in an inoperable state. Testing performed following the original valve work was clearly inadequate to
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l identify this maintenance-induced failure. The inspectors concluded that the valve was degraded but would have functioned to refill the steam generator. Plant risk was not affected, based on licensee and NRC calculations. The staff concluded that this event was a violation of Technical Specification 3.7.1.2 of lesser significance in accordance with Supplement 1 to the NRC Enforcement Policy. This Severity Level IV violation is being treated as a noncited violation consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Condition Reports 99-7742 and 99-7743 (Section M8.1).
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-3-Enaineerina Reactor containment building cooling water systems in both units had leaking
containment isolation valves that provided system interface isolation. While maintenance efforts failed to eliminate leakage, engineering provided a good evaluation of the radiological monitoring and impact of the measured leakage, which remained within regulatory limits (Section E2.1).
' Plant Support The failure to lock or guard the door which provided access to a Technical Specification a
required locked high radiation area was identified as a violation of Technical Specification 6.12.2. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensee's corrective action program as Condition Report 98-15247 (Section R8.1).
The inspectors reviewed the licensee's severe weather preparations as described in the
site procedures for the start of the hurricane season. The site completed appropriate preparations and assigned personnel to duties required during the approach for heavy weather (Section P1.1).
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Report Details Summarv of Plant Status Unit 1 began the inspection period at 100 percent power. On June 27,1999, Unit 1 tripped due to a loose wire in the turbine control system. The unit returned to power operations on June 29, 1999, and ascended to 100 percent power where it remained for the remainder of the inspection period.
Unit 2 began the inspection period at 100 percent power. A planned power reduction to 90 percent power was performed on July 9 to plug leaking tubes in a feedwater heater. A rapid j
power reduction was performed on July 13 to 50 percent power in remnse to a tripped service water pump. The unit retumed to 100 percent power af ter each dor
.ver. On August 5, the unit reduced power to below 10 percent and the turbine was taken off-line to work on a hydrogen leak on the main unit generator. The unit was in this condition at the end of the inspection period, l. Operations
Conduct of Operations O1.1 General Comments (71707)
The inspecters used Inspection Procedure 71707 to conduct frequent reviews of ongoing plant operations. In general, the conduct of operations was professional and safety conscious. During this inspection, operating crews from both units were challer ged by nonsafety equipment failures and degraded equipment. In each case, operators responded well. Specific comrhents are provided below.
After securing a low pressure heater drip pump in Unit 2 for planned maintenance, the level control system behaved erratically in the associated flash tank and feedwater heater. Water level oscillations resulted in automatic isolation of Low Pressure Feedwater Heaters 25B and 268. The loss of these feedwater heaters did not cause a noticeable decrease in feedwater temperature, and thus did not affect reactor operation.
The feedwater heaters were isolated for one hour and 45 minutes. Operators did not reduce power to 90 percent as required by Procedure OPOP03-ZG-0008," Power Operations," Revision 16, while attempting to restore the feedwater heaters to service.
The shift supentisor discussed this issue with Operations management and the system engineer, and they concluded the procedure was addressing long-term cycle efficiency rather than an unplanned heater trip. The licensee planned to clarify the procedure.
The inspectors determined that this war, ne' a nrocedure violation, but that this was an example of balance of plant equipment ur.
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01.2 Response to Unit 1 Automatic Reactor Trio and Startuo Observations a.
Insoection Scope (71707. 93702)
The inspectors responded to the site to observe operator response to and initial licensee
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investigation of an unplanned automatic reactor trip on June 27. The inspectors observed two posttrip Plant Operations Review Committee (PORC) meetings, several i
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-2-control room pre-evolution briefings, two shift turnover meetings, and a routine reactor startup.
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Observations and Findinas Unit 1 tripped from 100 percent power. All control rods inserted and plant systems responded as expected. Operators responded well and r*abilized the plant in Mode 3.
j No operator performance issues were identified.
A PORC meeting was convened on June 28 to review the circumstances surrounding the reactor trip and to approve the course of action to restore the unit to operation. The PORC reviewed and approved the posttrip review report conducted in accordance with Procedure OPGP03-ZO-0022," Post Trip Review," Revision 6, and the initial troubleshooting plan. The inspectors observed that licensee management demonstrated a questioning attitude and conservative decision making when they approved an aggressive troubleshooting plan, the plant startup, and established a 40 percent power limit. Once the root cause was determined, the main turbine electro-hydraulic control system was tested satisfactorily, and the plant was stabilized at 40 percent power, management approved plant power ascension to 100 percent on June 29.
After thoroughly reviewing the symptoms of the June 27 trip and obtaining assistance from the vendor, troubleshooting efforts were narrowed to a power supply in the main turbine electrohydraulic control system. Technicians found a loose connection in the wiring that supplied power to the back of the electrohydraulic control modules. When the loose connection was manipulated, the same indications observed during the June 27 trip appeared. Since troubleshooting was being conducted with the main turbine already shutdown, no plant transient followed. Thermography equipment was used to determine if any other connections were degraded. Three additional degraded connections were identified. All degraded connections were repaired. After repairing the degraded conditions, the licensee restored the electrohydraulic control system and started the main turbine. Further testing of the main turbine control system determined that it was working property.
The inspectors observed selected evolutions during the reactor and steam plant startup.
The evolutions observed were conducted in a rigorous and controlled manner.
Communications were clear, thorough, and unambiguous. Evolutions affecting reactivity were planned and discussed, and conducted in a deliberate and controlled manner.
When manipulating the reactor and steam plant controls, operators consistently used self-verification techniques and used available indications to verify proper equipment response. Pre-evolution briefings involved the entire crew, including plant operators in the field, and were conducted in a manner that encouraged participation and a l
questioning attitude. All alarms were properly acknowledged, and infrequent or l
unexpected alarms a! ways resulted in the reactor operator referencing the alarm response procedures. Operators increased reactor power in accordance with the orders given by shift management and maintained the ramp rate within predetermined administrative limit.
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Conclusions Unit 1 operators responded well to a plant trip. All control rods inserted and plant systems responded as expected. Operators properly implemented plant emergency procedures and quickly stabilized the plant in Mode 3. This plant transient was caused by a loose wire in the turbine control circuit.
Licensee management demonstrated a questioning attitude and conservative decision making during two posttrip PORC meetings. Troubleshooting was focused, conducted safely, and identified the root cause of the June 27 trip. The plant was started up by knowledgeable operators with good safety focus.
01.3 Operators Responded Well to Faulted Service Water Pumo (93702)
On July 13, Open Loop Cooling Water Pump 21 inadvertently tripped. This service water system cooled turbine auxiliary systems and air conditioning chillers. The system required two pumps to be running, with a third pump in standby. With the redundant pump removt _ for planned maintenance, operators unsuccessfully attempted to restart the pump. With only one pump available, operators rapidly reduced power to about 48 percent and took other actions to reduce heat loading on the system. This action was prudent because at this power level, the plant could withstand a turbine trip and allow an orderly reactor shutdown.
The inspectors responded to the Unit 2 control room to observe operator response to the pump trip. The inspectors observed that spare licensed operators were brought to the control room to assist. The large number of extra operators were skillfully directed by the Unit Supervisor so there was no confusion. Procedural compliance, log-keeping, and Technical Specification compliance were correct in all cases during the event.
With engineering assistance, operators were able to realign the system to carry the necessary heat load and restore adequate cooling. The pump undergoing planned maintenance was restored on July 15, and the damaged cable for the remaining pump was restored the following day.
01.4 Observations Durina Unit 2 Power increases (71707)
The inspectors observed Unit 2 r.perators increase power from about 90 percent to 100 percent on July 12 followino umpletion of emergent repairs to Feedwater Heater 258. The power increase was delayed for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> when operators attempted to restore the feedwater heaters too quickly and tripped it on improper water levels. The second attempt was more controlled, better supervised, and successful. The power increase was well briefed. Reactivity manipulations were observed to be very conservative and reflected lessons-learned from the reactivity control problems observed during the recent Unit 1 startup documented in NRC Inspection Report 498;499/99-13. The remainder of the evolution was completed without inciden c
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o-4-The inspectors also observed Unit 2 operators increase reactor power from about 48 percent to 100 percent on July 15 following recovery from the service water pump trip. This evolution was well-briefed, carefully controlled, and well-supervised.
l Reactivity manipulations were discussed in detail among operators, the reactor engineer, and the Unit Supervisor, then carefully executed. This evolution was
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performed well.
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Operational Status of Facilities and Equipment l
O2.1 Enaineered Safetv Feature (ESF) System Walkdowns (71707)
The inspectors used Inspection Procedure 71707 to walk down accessible portions of the following ESF systems:
Safety injections Systems (Units 1 and 2)
l Containment Spray System (Unit 1)
l A semiannual detailed walkdown was performed for the safety injection system. The j
walkdowns included the control board, electrical, and valve lineups. The inspectors determined that overall the above systems were in good material condition and properly aligned for standby operation.
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l However, the inspectors did identify several nomenclature errors. These errors were l
reported to the licensee. For example, the inspectors discovered during the Unit 2 l
Train C walkdown that the electrical lineup document was mostly correct, but the valve l
lineup documents did not use the same nomenclature as the valve labels. Almost every single valve label did not match the lineup document.
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The inspectors identified several minor deficiencies with components inside the Unit 1 containment during the accumulator inspections. The Unit was several months out of an outage, but a number of valves had evidence of minor packing leaks or body to bonnet leaks. One air operated valve had significant stem scoring which was not expected to l
affect operation. The inspectors also identified one header vent valve inside Unit 1 containment that clearly had the wrong nomenclature. The licensee documented the deficiencies in the corrective action program. Boron leaks outside of containment on the l
safety injection system were also reported to the health physics department for
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evaluation of radiological conditions.
Also, the inspectors identified three deficiency tags written in 1997 which were no longer active, but had not been removed from the system.
The inspectors reviewed all outstanding condition reports for the system and read the system health report. Most outstanding deficiencies were identified within the last year and were minor. However, several of the deficiencies involved valve seat leakage which impacted the safety injection accumulators. These included nitrogen leaking out, requiring periodic repressurization, and water leaking out of accumulators into the safety injection pump discharge headers, requiring periodic refilling of accumulators and more frequent depressurization of the filllines. These were identified as operator
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Miscellaneous Operations issues (92700,92901)
08.1 (Closed) Licensee Event Report 498/99006-00: Automatic reactor trip due to a loose wire in the turbine control system. This trip is discussed in detail in Section 01.2 above.
No violations of NRC requirements were identified. This item is closed.
08.2 / Closed) Unresolved item 50-498:499/99002-01: Improper use of checks valves to q
comply with containment isolation action statements. This item was opened to evaluate j
the compliance impact of licensee's incorrect practice of taking credit for an inside containment isolation check valve as the single barrier used to satisfy Technical Specification 3.6.3 required actions when an outside containment isolation valve was inoperable. The inspectors had noted that the licensee's practice had been justified by the licensee's Technical Specification Interpretation 116, which was based on an
NRC-approved Improved Technical Specification document (MERITS) that did not apply
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to South Texas Project. The inspectors performed a detailed review of control room logs and operability tracking documents. This review did not identify any occurrences in which the licensee violated the limiting condition for operation for containment penetrations as specified in Technical Specification 3.6.3. Since this issue was brought to the licensee's attention, the licensee revised their procedures and instructed their personnel that a check valve may not be relied upon to satisfy Technical
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Specification 3.6.3. The improved Technical Specification wording was approved for I
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South Texas Project. Based on the inspectors' review and the licensee's corrective actions, this item is closed.
II. Maintenance M1 Conduct of Maintenance M1.1 Maintenance and Surveillance Observations a.
Inspection Scope (62707. 61726)
The inspectors observed all or portions of the following maintenance and surveillance activities. For surveillance, the test procedures were reviewed and compared to the Technical Specification surveillance requirements and bases to ensure the procedures satisfied the requirements. Maintenance work was reviewed to ensure adequate work instructions were provided, the work performed was within the scope of the authorized j
work, and the work performed was adequately documented. In all cases, the impact to I
equipment operability and applicable Technical Specifications actions were independently verified.
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' Maintenance:
Replacement of Rod Control System power supply (Unit 2)
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High Head Safety injection Pump 1 A Miniflow Motor Operated Valve
Maintenance (Unit 1)
Essential Cooling Water Self-Cleaning Strainer 1C Preventive Maintenance
Inspection (Unit 1)
Surveillance:
Plant Surveillance Procedure OPSP11-HE-0001, Revision 10," Control Room
Envelope Filter Airflow Capacity Test"(Unit 1).
Plant Surveillance Procedure OPSP11-ZH-0010, Revision 8," Electrical Auxiliary
Building and Fuel Handling Building Ventilation Absorbent Test"(Unit 1).
Plant Surveillance Procedure OPSP03-NI-0001, Revision 9, " Power Range
Nuclear Instrumentation Channel Calibration" (Unit 2).
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Observations and Findinos The replacement of the Rod Control System power supply in Unit 2 was very well planned and briefed. Maintenance supervision was present, as well as the system angineer. Electrical safety precautions and foreign material exclusion practices were excellent. _ The inspectors noted that the work was performed during a hold in a power increase. Although, the operation was for a shutdown bank (associated rods did not need to be moved), it did require control room attention when they were somewhat j
occupied with the power ascension from the service water pump trip.
The motor-operated valve maintenance on the high head safety injection miniflow line included replacing the spring pack to enhance torque switch setting capability.
Postmaintenance testing included performing part of Maintenance Procedure OPMP05-ZE-0415, *MOV Diagnostic Testing - Rising Stem Valves," Revision 5. The inspectors determined that maintenance personnel followed the work instructions as written and were very familiar with the operation of the motor-operated valve and testing equipment.
The inspectors also observed the preventive maintenance inspection of the Essential Cooling Water Self-Cleaning Strainer 1C. The inspection noted no abnormalities, and the condition of the strainer was good. This evolution required the coordination of many craf t including mechanical and electrical maintenance and security support. No problems were noted.
The inspectors observed technicians performing airflow capacity and adsorbent tests on the Unit 1 Train B control room envelope ventilation system carbon filter units. The tests were satisfactorily performed in accordance with approved procedures to assure system
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-7-operability. The calibrations of the instruments used during the tests were verified before and after the tests. The technicians were familiar with the tests and equipment and utilized good communication and verification techniques.
The inspectors observed the calibration of the Unit 2 power range nuclear instruments.
This activity was performed while the unit was holding at 25 percent reactor power during a power reduction to repair a hydrogen cooler leak in the main generator. This evolution was performed by instrumentation and controls technicians with operations and nuclear engineering support. No problems were noted.
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Conclusions The observed maintenance and surveillance activities were performed well and in accordance with approved procedures. Electrical safety precautions and foreign material exclusion practices were excellent. Techn; cal Specification surveillance requirements were satisfied by the observed tests.
M1.2 Service Water Pumo Fault Caused By Maintenance Causes Plant Transient (62707)
On July 13, a worker was assigned to chip rust from structures and equipment at the plant intake structure. While using a pneumatic needle gun on the metal conduit that contained the power cables for Open Loop CooW Water Pump 21, the worker heard a pop and the pump tripped.
The open loop cooling water was a nonsafety service water system that supplied turbine auxiliary systems and non-safety air conditioning chillers. The system required two pumps to be running, with a third pump normally available in standby. At the time of the event, the standby pump was removed for planned maintenance, so only one pump was left running after the pump tripped. Operators rapidly reduced reactor power to about 48 percent to reduce the heat load on the system.
The licensee's investigation determined that the worker removing rust from the heavily corroded conduit broke though the conduit with the tool and damaged the cable. The cable jacket was apparently not penetrated, but the motor protection circuit detected a ground and tripped the pump. Troubleshooting located a solid ground in the cable at the location of the conduit hole.
The licensee's investigation team recommended that the work control and scheduling process evaluate placing reviews on production work in the vicinity of important equipment when redundant trains are removed from service. In addition, the material condition of the equipment located at the intake structure was to be evaluated due to several recent problems related to the harsh weather and chemical environmen s
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8-M1.3 Operators Cause Fuel Bundle Collision While Movina Wrona Bundle a.
Inspection Scooe (92903)
The inspectors reviewed station procedures for the conduct of fuel handling, as well as the licensee's Event Review Team report on the event. The conclusions and recommended corrective actions were discussed with Operations Support management.
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Observations and Findinas On July 21, the licensee was moving fuel within the Unit 2 spent fuel pool to conduct ultrasonic inspections of a number of bundles. A licensed operator experienced in moving fuel was performing the moves with a nonlicensed operator who had no prior experience moving fuel. However, the inexperienced person's role was to perform location verifications which did not require fuel handling experience.
The operators sequentially moved two bundles successfully from their storage location to a test stand, then back to the origir'al storage location. The licensed operator then paused to conduct informal training on fuel handling techniques with the otner operator.
When they returned to moving fuel, they mistakenly latched the same bundle they had just finished moving. This bundle was again tested, but was then returned to the cell where it was thought to have been previously stored. After verifying they were at the cell location for the bundle they thought they were moving, the operators lowered the bundle into a cell occupied by the bundle they.should have been moving. The bundle was slowly lowered until operators noted a reduction in loading on the hoist of about 500 pounds near the top of the cell. The bundle was raised, and the error was identified. The bundle being moved was returned to its correct storage location.
However, prior to stopping all fuel handling the next bundle was moved and tested.
j The license's investigation concluded that the operators became distracted while conducting informal training, which was beyond that needed for the evolution in progress. As a result, they failed to properly fol!ow the approved Fuel Transfer Form and move to the next bundle approved for movement. Additionally, the operators failed to verify that they were in the currect location before hoisting the bundle. While the operators appeared to follow the licensee's process for signing off steps when completed, the Fuel Transfer Form in this case had only one signature block for moving a bundle from its storage location to the test stand and back. This did not require the operators to check themselves prior to the collision. Also, due to the lack of apparent fuel damage, fuel handling was not immediately stopped in accordance with the fuel
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handling procedure and the next bundle was inspected before orders to cease all fuel movement operations was given.
Licensee senior management halted all fuel movement until corrective actions could be formulated and implemented as appropriate. A visualinspection of the top of the bundle that was landed on identified no damage; an inspection of the bottom of the other
affected bundle was to be conducted after resuming fuel movements. Modifications to the Fuel Transfer Form were to be evfiluated to require completion / verification i
signatures after each bundle movement, not at the end of a round trip.
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-9-The inspectors were concerned by the declining trend in fuel handling performance.
Previous errors included:
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A fuel bundle was lowered onto three filters stored in a fuel storage cell, crushing l
them (documented in NRC Inspection Report 50-498;499/99-06).
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A fuel bundle being removed from a storage cell snagged a poison panel, pulling it free and causing it to fall over (documented in NRC Inspection Report 50-498;499/99-11).
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A fuel bundle was being lowered into the last open position in a row while refueling the core. Operators failed to notice the opening was partially obstructed by a bowed fuel bundle and lowered anyway. This caused a fuel bundle collision, which resulted in a leaning bundle that had to be restrained and uprighted (documented in NRC Inspection Report 50-498;499/99-11).
The primary factor in each example was lack of attention to detail in watching where fuel was being moved. Additionally, the event in NRC Inspection Report 50-498;499/99-06 was very similar to this event in that fuel was lowered into a storage rack cell that was not empty. The inspectors reviewed the corrective actions from that event and determined that they were narrowly focused. The licensee concentrated on locating and controlling material in the spent fuel pool and did not provide procedural guidance on verifying that the new storage location for fuel being moved was free from obstructions.
The significance of this event was minor due to lack of apparent fuel damage. However, l
the continuing examples of fuel mishandling indicated that the corrective actions program was not dealing with the trend.
The inspectors reviewed OPEP02-ZM-0005, Revision 8, " Internal Transfer of Fuel Assemblies." Section 6.7 of this procedure required personnel moving fuel to refer to the approved Fuel Transfer Forms which authorize movement, ensure the fuel handling machine is on the correct index marks, and verify by directly referring to the Fuel Transfer Form that the assembly has been transferred to the correct location. Also, Section 4.25 required fuel handling operations to immediately cease if fuel damage occurs. The failure to properly verify that the correct bundle was being moved and failure to immediately stop fuel movement operations after the collision 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 (NCV 499/99014-01).
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Conclusions Operators moving fuel within the spent fuel pool became distracted while conducting informal training and failed to properly verify the correct cell location before moving a bundle. As a result, they moved the wrong bundle and lowered it onto another bundle.
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This event was caused by inattention and improper verifications. Also, fuel handling movements were not ceased as required after the incident. This event was the fourth fuel handling event onsite recently, indicating a weakness in attention to detail while i
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-10-moving fuel. Continuing examples of fuel handling events indicated that the corrective actions program was not adequately dealing with the declining trend. The corrective actions from a similar previous event were narrowly focused and did not prevent this event. Failure to properly verify that the correct bundle was being moved and failure to immediately stop fuel movements 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.
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Emeraency Technical Specification Amendment Granted to Allow Replacement of the Fuel Handlina Buildina Exhaust Booster Fan 21B Motor (62707. 37551)
On June 30,1999, the licensee identified that the Unit 2 Fuel Handling Building Exhaust Booster Fan 21B motor was grounded and required replacement. The system had been in its allowed limited condition of operation for system maintenance, and the grounded motor was discovered during a surveillance. The 7-day action statement of Technical Specification 3.7.8 remained in effect, expiring on July 6. The licensee requested an Emergency Technical Specification Amendment to allow sufficient time to breach the duct work and install temporary blind flanges. The fan motor would then be replaced with the remainder of the system opere.tional. By letter dated July 2, the NRC granted the amendment in accordance with the regulations in 10 CFR 50.91. The amendment allowed the fuel handling t'udding exhaust system to be inoperable for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> while installing and removing the temporary modification. The NRC letter noted that the licensee has made gooa faith attempts to alleviate a need for further licensing actions by submitting a perrranent Technical Specification Amendment and developing and implementing a plant modification. The modification was installed in Unit 1, with implementation in Unit 2 scheduled during the upcoming refueling outage. The emergency amendment was warranted to avoid an unnecessary plant shutdown for which no compensatory benefit to public health and safety existed.
The event was caused by the system design not permitting the fan motor removal with the system operable. The root cause of the fans developing grounds was a deficiency in the method used to coat the motor windings. The inspectors concluded that no violation occurred associated with the root cause of this event.
The licensee implemented the temporary modification and replaced the fan motor on July 4.- The inspectors observed that maintenance personnel were thoroughly briefed and that equipment was staged for the expected work and planned contingencies. The time that the entire system was inoperable was effectively minimized through planning and rehearsin o...
-11-M8 Miscellaneous Maintenance issues (92700,92902)
M8.1 (Closed) Licensee Event Report 498/99005-00: Auxiliary feedwater pump inoperable longer than the Technical Specification allowed outage time.
On May 10,1999, the licensee performed periodic testing on the motor-operated flow control valve associated with the Unit 1 turbine driven auxiliary feedwater pump. On May 11, following satisfactory static testing, the valve was returned to service. On May 13, the licensee performed a surveillance test that involved running the pump, during which the valve failed to operate in the open direction. This condition was corrected on May 14.
Licensee troubleshooting identified that an electrical contactor in the motor-operated valve limit switch was bent during testing and would not make contact. This contactor was supposed to override the torque switch and allow valve motion while the valve opened. With the torque switch not overridden, the torque produced opening the valve was less than the setpoint while opening statically (i.e., no system flow), but above the setpoint while opening with system flow. The licensee evaluated the as-found condition and concluded that the failure was caused by maintenance on May 10 and that the valve was not capable of performing its design function; therefore, the turbine driven auxiliary feedwater pump was inadvertently rendered inoperable for 91 hours0.00105 days <br />0.0253 hours <br />1.50463e-4 weeks <br />3.46255e-5 months <br />, exceeding the Technical Specification 3.7.1.2 allowed outage time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> by a total of 19 hours2.199074e-4 days <br />0.00528 hours <br />3.141534e-5 weeks <br />7.2295e-6 months <br />.
The licensee changed the motor operated valve test procedure to incorporate a step to verify that the electrical continuity of the switch that was disturbed during testing was restored before completing testing. The inspectors observed subsequent motor-operated valve testing and verified that the additional checks were performed.
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I The inspectors reviewed the event and concluded that the scope of the postmaintenance testing performed following the original valve work was clearly inadequate to identify this maintenance-induced failure. The inspectors evaluated the failure with respect to the intended function. The auxiliary feedwater flow control valve was normally open. When the system is actuated, the control system regulates flow to its associated steam generator, refilling it. While the valve was incapable of moving open, its expected operation is to incrementally shut as the steam generator refills.
Thus, the valve was degraded but functional. The remaining three motor-driven auxiliary feedwater pumps remained operable, and crosstie capability among the trains was not affected. Plant risk was not affected, based on licensee and NRC calculations.
Therefore, the staff concluded that this event was a violation of Technical Specification 3.7.1.2 of lesser significance in accordance with Sju piement 1 to the enforcement policy. However, this Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (NCV 498/99014 02).
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-12-M8.2 (Closed) Followuo item 50-4953:499/99006-04: Review of offsite power reliability. This item was opened to review the licensee's first quarter 1999 line outage data for the 345 kV transmission lines that connect to the site and to review the licensee's actions to improve reliability. A review of the data for the last quarter of 1998 indicated that the sustained outage frequency for the offsite power lines was 1.35 sustained outages per year per 100 circuit miles which was higher than the expected frequency of 1.34 described in the Updated Final Safety Analysis Report. The system engineer stated that the high sustained outage frequency was due to transmission line insulator flashover caused by dirty insulators and lack of rain. The first quarter 1999 line outage data indicated a frequemy of 1.53. The inspectors discussed the data with the system engineer who stated tv.! the increase in outage frequency reflects the line lockouts caused by flashover in early March. The system engineer also stated that the data was also adversely influenced by the fact that two of the eight 345 kV lines in the switchyard did not have automatic reclosure. As a result, even a momentary line fault caused the line to lockout requiring system dispatcher action for restoration. Through further discussion with the system engineer, the inspectors ascertained that in May 1999 the responsible owner-utilities replaced numerous insulators that were causing the line lockouts due to flashover. In addition, automatic reclosure circuits were installed on all of the lines connecting to the switchyard in an effort to further reduce line outages and improve system reliability. Since this repair work, unplanned line outages had improved significantly. This item is closed.
Ill. Enaineerina E2 Engineering Support of Facilities and Equipment E2.1 Review of the impact of Component Coolina Water Leakina Containment isolation Valves (37551)
Discussions were held with system engineers on the operation of the component cooling water and chill water system. Specifically, the licensee had been monitoring and draining the nonsafety-related reactor containment building chill water surge tank in both units and the component cooling water expansion tank in Unit 2 due to leaking system interface valves. The component cooling water system supplied cooling water to the reactor compartment fan coolers during an accident, while the reactor containment building chill water system supplied them during nonaccident conditions. Leaking interface valves allowed water from the running system to leak into the idle system causing rising levels in the expansion tanks, The leaking valves were outside containment isolation valves. Measured leak rates were not sufficiently large to exceed allowed local leak rates; however, maintenance performed on some of the valves had not resolved the problem. The licensee was evaluating the use of an automatic leve! system for the reactor containment building chill water surge tanks. The inspectors also questioned the licensee with regard to the possibility of the creation of an unmonitored release pathway if the system becomes contaminated with the leaking valves. The inspectors found that the licensee had addressed this issue during licensing in response to the concerns raised in NRC
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o-13-Bulletin 80-10," Contamination of Nonradioactive System and Resulting Potential for Unmonitored, Uncontrolled Release of Radioactivity to the Environment." Specifically, the component cooling water system inleakage was continuously monitored with radiation detection instrumentation, and potential releases into the interfacing reactor containment building chill water system, which is transported into the turbine building, would drain into the building sumps. Effluent releases from the turbine building sumps were sampled prior to release and monitored during release. The inspectors determined that engineers were adequately addressing the leaking intedace valve problem and contamination / release consequences. Engineering was also providing Operations support by evaluating the use of an automatic level system.
IV. Plant Sur' port R8 Miscellaneous Radiological Protection and Chemistry issues (92904)
R8.1 (Closed) Unresolved item 50-498:499/99007-03: Failure to lock or guard access to a Technical Specification required locked high radiation area.
On October 4,1998, the licensee identified and documented in Condition Report 98-15247 that a Technical Specification locked high radiation area gate which provided access to Room 201 in Unit 2's reactor containment building, an area which contained radiation levels greater than 1000 mrem per hour but less than 500 rads per hour, was propped open by a drum and not guarded from approximately 11:15 p.m. on October 3,1998, to 1:30 a.m. on October 4,1998.
Technical Specification 6.12.2 requires that areas accessible to individuals with radiation levels greater than 1000 mrem per hour but less than 500 rads per hour be provided with locked or guarded doors to prevent unauthorized entry. The failure to lock or guard the door which provided access to a Technical Specification required locked high radiation area was identified as a violation of Technical Specification 6.12.2. This Severity Level IV violation is being treated as a noncited violation, consistent with Appendix C of the NRC Enforcement Policy (50-498;499/99014-03).
P1 Conduct of Emergency Preparedness Activities P1.1 Severe Weather Plan imolementation (71750)
The inspectors used inspection Procedure 71750 to review the licensee's implementation of the severe weather plan in preparation for hurricane season. The inspectors reviewed Plant General Procedure OPGP03-ZV-0001, Revision 3," Severe Weather Plan" and found that it required each department to designate a departmental severe weather coordinator and to review and revise the departmental severe weather plans and submit Forms 1 and 2 of the procedure to document completion by May 1 to the station Severe Weather Coordinator. The inspectors reviewed the completed Forms 1 and 2 and found that the licensee was in full compliance with their severe weather plan. The inspectors inspected the licensce's warehouse to verify sufficient i
supplies were on hand as per the procedures for hurricane preparation. Interviews with
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-14-control room shift supervisors determined that they were aware of the severe weather plan implementing procedures and the actions to take during severe weather forecasts.
The review of the licensee's severe weather preparations determined that the necessary steps described in the site severe weather plan procedures had been conducted for the hurricane season.
VI. Manaaement Meetinas X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management on August 10,1999. Management personnel acknowledged the findings presented. The inspector asked whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie {
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PARTIAL LIST OF PERSONS CONTACTED L
Licensee -
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P._ Arrington, Licensing Specialist l
T. Cloninger, Vice President and Assistant to the President and CEO l
W. Cottle, President and CEO l
B. Dowdy, Operations Manager, Unit 2 l
S. Eldridge, Quality Specialist R. Fast, Manager, Unit 2 Maintenance W. Harrison, Senior Consulting Engineer, Nuclear Licensing -
S. Head, Licensing Supervisor S. Horak, Quality Specialist
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D. Leazar, Manager, Nuclear Fuel and Analysis Department B. Mackenzie, Manager, Operating Experience Group M. McBurnett, Director, Quality and Licensing T. Powell, Manager, Health Physics P. Serra, Manager, Emergency Response (
J. Sheppard, Vice President, Engineering and Technical Services S. Thomas, Manager, Design Engineering Department i
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INSPECTION PROCEDURES USED IP 37551: Onsite Engineering IP 61726: Surveillance Observations l
lP 62707: Maintenance Observations j
IP 71707: Plant Operations IP 71750: Plant Support Activities
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IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor Facilities IP 92901: Followup - Operations IP 92902: Followup - Maintenance
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IP 94904: Followup - Plant Support
~ IP 93702: Prompt Onsite Response to Events at Operating Power Reactors l
Items Opened and Closed Opened 50-499/99014-01 NCV Operators' Failure *3 Follow Procedure Causes
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Fuel Bundle Commun While Moving Wrong Bundle (Section M1.3)
'50-498/99014-02 NCV Auxiliary Feedwater Pump Inoperable Longer Than the Technical Specification Allowed Outage Time (Section M8.1)
50-498;499/99014 03 NCV Failure to Lock or Guard Access to Technical Specification Required Locked High Radiation Area j
(Section R8.1)
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1 Closed 50-499/99014-01 NCV Operators' Failure to Follow Procedure Causes l
Fuel Bundle Collision While Moving Wrong Bundle (Section M1.3)
50-498/99014-02 NCV Auxiliary Feedwater Pump inoperable Longer Than the Technical Specification Allowed Outage Time (Section M8.1)
50-498;499/99014-03 NCV Failure to Lock or Guard Access to a Technical Specification Required L-ocked High Radiation Area (Section R8.1)
50-498/99005-00 LER Auxiliary Feedwater Pump Inoperable Longer Than the Technical Specification Allowed Outage Time (Section M8.1)
50-498;499/99007 03 URI Failure to Lock or Guard Access to a Technical Specification Locked High Radiation Area (Section R8.1)
50-493/99006-00 LER Automatic Reactor Trip Due to a Loose Wire in Turbine Control System (Section 08.1)
50-498;499/99002-01 URI improper Use of Check Valves to Comply with Containment Isolation Action Statement (Section 08.2)
50-498;499/99006-04 IFl Review of Off-site Power Reliability (Section M8.2)
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