IR 05000445/1993039
| ML20058K448 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 12/10/1993 |
| From: | Yandell L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20058K433 | List: |
| References | |
| 50-445-93-39, 50-446-93-39, NUDOCS 9312150234 | |
| Download: ML20058K448 (19) | |
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I APPENDIX
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U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-445/93-39 50-446/93-39 Licenses: NPF-87
NPF-89 l
Licensee: TU Electric
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Skyway Tower 400 North Olive Street, L.B. 81 Dallas, Texas
Facility Name:
Comanche Peak Steam Electric Station,-Units 1 and 2 Inspection At:
Glen Rose, Texas
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Inspection Conducted: October 3 through November 13 Inspectors:
D. N. Graves, Senior Resident Inspector K. H. Kennedy, Resident Inspector G. E. Werner, Resident Inspector
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R. C. Stewart, Reactor Inspector
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i Approvt [ M %.
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/d-/O-93
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L. A. Yandell, Chief / Projects Section B Date
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Inspection Summary
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Areas Inspected (Units 1 and 2):
Routine, unannounced inspection of operational safety verification, maintenance and surveillance observations, followup on corrective actions for violations, other followup, and onsite review of licensee event reports (LERs).
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Results (Units 1 and 2):
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Control room activities were well controlled, especially regarding
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Unit I reactor coolant system inventory changes (Section 2).
The Unit I reactor head lift was generally well performed, although both
strengths and weaknesses were identified regarding radiation protection practices (Section 3.3).
j Summary of Inspection Findings:
Two noncited violations were identified (Sections 3.3.2 and
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3.3.3).
9312150234 931210
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LER 445/93-008 was reviewed-but not closed (Section 7.5).
Violation 445/9251-01 was closed (Section 5).
Inspection Followup Item 445/9259-02 was closed (Section 6).
- LERs 445/91-002, 445/91-016, 445/92-028, 445/92-029, and 446/93-005 were-
closed (Section 7).
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Attachment:
i Persons Contacted and Exit Meeting e
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-3-DETAILS 1 PLANT STATUS l
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At the beginning of this inspection period, Unit I was at 100 percent power.
On October 6, the reactor was shut down in preparation for the third refueling outage. At the end of this inspection period, the reactor core was off-loaded
with all of the Unit I fuel in the Unit I spent fuel pool.
Preparations were
being made to begin core reloading.
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Unit 2 was at approximately 90 percent power at the beginning of this inspection period and was being raised to 100 percent power following a maintenance outage. The unit remained at approximately 100 percent for the remainder of the inspection period.
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2 OPERATIONAL SAFETY VERIFICATION (71707,92701)
2.1 Plant Tours Numerous plant tours of both units by the inspectors concluded tent, in general, housekeeping was good, especially in the Unit 1 containment during
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the outage. One area that was noted as needing additional attention early in the inspection period was the service water intake structure. Subsequent
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inspections of the intake structure indicated that the general cleanliness of i
the area had been substantially improved.
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More specifically with regard to Unit 1, tours of the containment determined that equipment was properly stored or removed following completion of work.
All observed flammable material was properly documented, and fire watches were l
properly established for all hot work.
Several potential tripping hazards were observed in that pieces of black and yellow caution tape were placed on the floor to protect small areas of the floor that had been repainted. The
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tape was placed such that a loop extended above the floor and presented a
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potential hazard. The licensee was informed of the observation, reviewed the installation, and removed the tape.
2.2 Contract Auxiliary Operators (A0s)
The licensee hired nine contract A0s to assist the normal shift complement of A0s.
Each contract operator was trained to the basic A0 qualification level.
Basic qualification did not allow operation of permanently installed plant equipment, although some exceptions such as vents and drains were allowed.
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The inspector reviewed the guidance supplied to operations supervisors regarding the qualifications and expectations regarding the contractor A0s.
The contractors were observed performing duties in the field and were observed to be performing their duties in accordance with the established guidance.
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_4 2.3 Power Reduction Prior to Unit 1 Outaae The inspectors observed the initial power reduction prior to the reactor
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shutdown for the third refueling outage for Unit 1.
The power reduction was
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performed in accordance with the requirements of Procedure IP0-003A, " Power Operations," Revision 3, Section 5.6.
Communications between the reactor operator and the balance-of-plant operator were good, as were the communications between the control room operators and the auxiliary operators in the field. The unit supervisor maintained excellent control of the unit and provided good oversight of the operators' actions, t
2.4 Unit 1 Control Room Observations On October 12, 1993, the inspector observed Unit I control room operators t
perform steps in Section 5.3 of Integrated Plant Operating Procedure IP0-005A, Revision 10. " Plant Cooldown From Hot Standby To Cold Shutdown," to place the reactor coolant system in a solid condition. The inspector observed operators secure the last operating reactor coolant pump (Pump 4), and initiate auxiliary spray, Operators carefully monitored plant parameters to ensure that procedural cautions and notes'were satisfied. These included maintaining the differential temperature between the reactor coolant system and the pressurizer liquid temperature less than 320 F maintaining the differential temperature between the pressurizer liquid temperature and the pressurizer i
vapor temperature less than 100*F,'and maintaining the pressurizer cooldown rate of < 100*F in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The evolution was well coordinated, well
controlled, and operators were knowledgeable on the procedure and expected plant response.
i 2.5 Reduction in Unit 1 Reactor Coolant System level The inspectors observed portions of the lowering of the Unit I reactor coolant system uater level in preparation for lifting of the reactor vessel head.
Level was lowered to a level below the reactor vessel flange but above the
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t level designated as " reduced inventory" (80 inches above the upper core plate).
Reactor vessel level was maintained greater than 84 inches above the upper core plate.
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The operations crew was well briefed regarding the evolution, including a review of the applicable portions of Procedure IP0-010A, " Reactor Coolant
System Reduced Inventory Operations," Revision 5.
Operators were stationed
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locally inside containment to monitor vessel level using temporary tygon tubing during the draining, and constant communication was maintained between i
the operators in the field and the control room.
The evolution was well conducted and coordinated, with licensee management
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(Operations Manager) present in the control room providing additional oversight during the observed portion of the evolution.
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2.6 Fillina of Unit 2 Spent Fuel Pool i
l As a result of the loss of refueling water event documented in NRC Inspection Report 50-445/93-41; 50-446/93-41, the licensee agreed to evaluate their procedures and processes prior to any significant transfer of refueling or reactor coolant system inventories.
c On November 4, the inspector observed the filling of the Unit 2 spent fuel
pool with demineralized water. This was performed to provide additional
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assurance that a failure of the Unit I spent fuel pool gate seals would not
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result in an unacceptable lass of level in the Unit 1 pool.
A briefing was conducted by the Unit 2 supervisor with the shift crew, including the A0s, prior to the evolution. A0s were stationed to continuously monitor the levels in the Units I and 2 spent fuel pools. They were
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instructed to immediately report any changes in level in the Unit I spent fuel pool to the shift supervisor. Additionally, they were instructed to ensure
that the level in the Unit 2 pool was maintained below the suctions to the l
spent fuel pool cooling pumps to further minimize the chance of diluting the
borated water in the Unit I pool. Any leakage into the transfer canal from
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either pool was to be reported immediately to the control room and the filling l
evolution terminated if the Unit 2 pool swing gate seal leaked.
The evolution was conducted in accordance with temporary
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Procedure 50P-TP-93-5, " Spent Fuel Pool X-02 Fill," Revision 0.
The inspector verified that the procedure prerequisites were completed and that the valves required to be closed and tagged were in the proper configuration (Clearance X92-1249).
The procedure was reviewed and was adequate to safely perform the task. The'
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evolation was performed over a period of approximately 2 days and was satisfactorily completed.
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2.7 Conclusions The inspectors concluded that the licensee was performing licensed activities safely and in accordance with established procedures. The evolutions regarding reactor coolant system inventory changes were well conducted.
3 MAINTENANCE OBSERVATIONS (62703)
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3.1 Unit 1 Main Turbine-Related Activities l
The inspectors performed general observations of the activities associated with work on the main turbine.
The main turbine control valves were removed i
for inspection and appropriate access controls were in place.
Low pressure i
Turbine No. 2 was removed for inspection and rework. The work areas inside i
the turbine casing and above the main condenser were generally clean with only
those materials necessary for the performance of specific tasks observed.
An access control point was established to log material into and out of the
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personnel and material into the area.
l 3.2 Diesel Generator 1-02 Inspections The inspectors observed Emergency Diesel Generator (EDG) 1-02 activities
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associated with the removal and replacement of the jacket water gear and cover on Diesel Generator 1-02 (Work Order 1-93-045117-00). The observed activities
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were performed in accordance with the work document which was properly i
authorized. A barrier was established around the work area for cleanliness control in accordance with the work order.
Good work practices were utilized by the mechanics and no deficiencies were noted.
The EDG room had been devitalized and released from the radiologically controlled area to ease access and egress from the area. The entrances to the
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radiologically controlled area from the EDG room were locked and well labeled to prevent inadvertent access into or out of the radiologically controlled area.
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3.3 Unit 1 Reactor Vessel Head Removal
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The inspector observed several activities related to the removal of the Unit 1
reactor vessel head.
3.3.1 Prejob As low As Reasonably Achievable (ALARA) Briefing The inspector attended and observed the prejob ALARA briefing conducted prior
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to the start of reactor vessel head removal activities. The briefing, conducted in accordance with Procedure STA-657, Revision 5, "ALARA Job Planning / Debriefing," included an overview of the procedural steps to remove i
the reactor vessel head, the expected radiological conditions during the head
lift, methods of communications, dosimetry requirements, protective clothing l
requirements, measures to minimize personnel exposure, housekeeping and system
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cleanliness measures, and the applicable radiation work permits.
Personnel i
assignments were described so that all personnel were aware of who had responsibility for the different activities during the lift. The briefing included an opportunity for personnel to ask questions and voice concerns l
about the evolution, and all questions and concerns raised were addressed
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satisfactorily. The briefing emphasized that anyone involved in the evolution l
could stop the head lift if a concern arose.
The inspector determined that the prejob briefing was thorough and effectively communicated radiation work principles and practices to minimize personnel radiation exposure during the lifting of the reactor vessel head.
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3.3.2 Reactor Vessel Head Removal
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In an effort to minimize the number of personnel in containment, access into containment prior to and during the evolution was strictly controlled and was limited to only those personnel involved with the head lifting evolution.
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The head lift was commenced in accordance with Procedure MSM-CO-9901,
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Revision 3, " Reactor Vessel Head Removal and Installation." The inspector
noted that proper communications were established between the polar crane operator, the crane signal person, the load cell monitor, and other persennel involved. Remote viewing monitors were available for personnel to view the lifting of the head and observe activities inside the refueling cavity.
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The inspector observed that the operator assigned to monitor the load cell
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attached to the reactor vessel head lifting rig was in continuous communications with the polar crane operator and monitored the load cell indicator during the lifting and movement of the head.
The purpose of the load cell was to detect any sudden changes in load during
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the lifting of the head which would be indicative of binding.
Following the initial lift of the head, the procedure called for the operator to set the
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load cell high and low alarms to plus and minus 5 percent of the load cell reading. As the head was being lowered onto the storage stand, the inspector questioned the operator about the high and low alarm setpoints. The inspector t
noted that the high alarm setpoint was set at +3.6 percent of the load cell reading, more conservative than the setpoint called for in the procedure. The lower setpoint, however, was set at -51 percent of the load cell reading, less conservative than the setpoint called for in the procedure. The operator
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indicated that the load cell indicator had been replaced prior to the start of the head lift and he was unable to set the high and low alarms.
In response to this weakness, the licensee generated an operation notification
evaluation (ONE) form to document the problem and the corrective actions taken to prevent recurrence.
These corrective actions included retraining personnel
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on the self-verification process, the importance of procedural compliance, and the importance of keeping supervision informed of problems encountered during the performance of procedural steps.
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Technical Specification 6.8.1 requires, in part, that written procedures be established, implemented, and maintained covering the applicable procedures
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recommended in Appendix A of Regulatory Guide 1.33 which, in turn, recommends
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that maintenance activities be covered by procedures.
Step 8.8.15 of
Procedure MSM-CO-9901, " Reactor Vessel Head Removal and Installation,"
Revision 3, requires that the load cell high and low alarm setpoints be adjusted to + and - 5 percent of the load cell reading. This violation will not be cited because of the low safety significance and the licensee's efforts in correcting the violation meet the criteria for enforcement discretion specified in Section VII.B.1 of Appendix C to 10 CFR Part 2.
3.3.3 Radiation Protection Work Prcctices The inspector observed radiation protection work practices during the head lift activities and noted that performance was mixed.
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Several strengths were noted.
Personnel working inside the refueling cavity wore dosimetry which transmitted information that was remotely monitored by a radiation protection technician. Using a computer monitor, the technician monitored, for each individual, the radiation field they were working in, their accumulated dose, and their margin to any applicable exposure limits.
The radiation protection technician was in communication with personnel in the refueling cavity at all times and could direct individuals to move to lower dose fields if necessary. This was particularly critical after the head was lifted and work was being performed in elevated radiation fields found in the vicinity of the reactor vessel flange. The inspector found that the technician was knowledgeable of her duties and responsibilities and of the remote monitoring equipment being used.
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Radiation protection technicians were observed monitoring radiation levels throughout the containment building during the head lift evolution, and access
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to previously identified areas of containment was restricted in anticipation
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of elevated dose rates.
Weaknesses were also observed. The inspector witnessed a mechanical maintenance technician, dressed in full protective clothing, exit a posted contaminated area at a location other than the designated exit point and step-off pad. The individual, who did not remove the protective clothing or perform a whole body frisk, walked away from the area to a location where other members of the crew were standing. A radiation protection technician, who was monitoring the radiological conditions inside the contaminated area, also observed the individual exit the contaminated area incorrectly. The technician took quick and effective actions by informing the individual of his error, directing him to return to the contaminated area, and observing as the individual properly removed his protective clothing and exited the contaminated zone. Another radiation protection technician then surveyed the
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area outside the contaminated zone where the individual had walked and did not detect any contamination.
A Radiological Awareness Report was generated to document the bount'ary
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violation. A ONE form was also generated in response to the event and included statements by the individual that he believed other individuals had also exited the contaminated area improperly. Upon further investigatica, the licensee determined that this was not the case and that this was an isolated incident. The licensee counselled the individual regarding the importance of observing all radiation programs and planned on providing him further radiation proteLion training.
In addition, the incident will be reviewed as a lessons learned by members of the maintenance department.
Technical Specification 6.3.1 requires, in part, that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Appendix A of Regulatory Guide 1.33 which, in turn, recommends that contamination control be covered by procedures.
Sections 5.4 and 6.3.4 of Procedtre STA-654, " Personnel and Hot Particle Contamination Control,"
Revision 2, states that workers are responsible for following all posted signs and must return to the contaminated area entry point (step off pad) and remove
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protective clothing in the suggested sequence.
This violation will not be cited because the licensee's efforts in identifying and correcting the violation meet the criteria for enforcement discretion specified in i
Section VII.B.1 of Appendix C to 10 CFR Part 2.
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An additional weakness was observed at the access control point on the 860-foot level in that there was only one radiation protection technician present at the egress point of the contaminated area at a time when a number of personnel were exiting the contaminated area.
As the technician was unable to devote all of her time to the egress activities, the inspector observed that personnel exiting the contaminated area lacked guidance and, therefore,
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were unsure of the proper method of handing the test equipment across the contaminated boundary.
It appeared that an additional radiation protection technician located in the area would have aided in the orderly exit of
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personnel and equipment from the contaminated area.
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3.4 Conclusions The observed activities on the main turbine and diesel generator were well conducted and controlled.
The ALARA prejob briefing prior to the Unit I reactor headlift was thorough and effectively communicated radiation work principles and practices to minimize personnel radiation exposure during the lifting of the reactor vessel
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The lifting of the reactor vessel head was well coordinated and carefully executed. A weakness was noted when personnel failed to set the load cell indicator lower alarm setpoint within -5 percent of the initial load cell reading.
Strengths and weaknesses were noted in the radiation work practices observed during the lifting of the reactor vessel head. The use of dosimetry which
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allowed remote monitoring of individual dose rates and radiation fields for those personnel working in potentially high dose fields was considered a strength.
Radiation protection technicians monitored for and were alert to changes in area radiation readings throughout containment during the head
lift.
Response by a radiation protection technician to an individual improperly exiting a contaminated area was quick and minimized the potential spread of contamination outside the boundary.
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A noncited violation was identified when an individual improperly exited a contaminated area.
An inadequate number of radiation protection technicians were present at the egress point from the reactor cavity cuntamination area to assist personnel exiting the area.
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4 SURVEILLANCE OBSERVATIONS (61726)
Unit 1 Main Steam Safety Valve Testina The inspectors observed mechanical maintenance personnel performing pressure relief valve testing on Steam Generator 1-01, Safety Valve IMS-0021.. Work Order 5-93-502687-AA was the initiating work document and Procedure MSM-50-8702, " Main Steam Safety Valve Testing," Revision 2, was the
test procedure used by the technicians.
The technicians used good work and safety practices. All unnecessary personnel were asked to leave the area.
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Main Steam Safety Valve IMS-0021 successfully passed the surveillance test.
Technical Specification 3.7.1.1 requires the lift setting to be 1185 psig plus or minus 1 percent. Two successive lifts were completed within the acceptance criteria of 1174-1196 psig with actual lift setpoints of 1193 and 1191 psig.
The test gauges were verified to be within calibration and tolerance specified.
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Technical Manual CP-0077-001, " Crosby Self Actuated Safety Valves"; 1989 ASME Code Section XI, " Boiler and Pressure Vessel Code"; and ASME/ ANSI OM-1987, Part 1, " Requirements for Inservice Performance Testing of Nuclear Power Plant Pressure Relief Devices," were reviewed and compared to the surveillance procedure and work order. The testing was found to have been properly prescribed and conducted in accordance with the above specified documents.
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The inspectors also reviewed previous Surveillance Test 591-1628 conducted on October 5, 1991.
Relief Valve IMS-0021 and other main steam relief valves failed its initial lift tests and subsequently had to be adjusted and tested.
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Valve IMS-0021 was adjusted and two successive lifts (1195 psig) were within Technical Specification limits.
LER 91-024 documented the failure of the relief valves to meet Technical Specification requirements. This LER was reviewed and closed in NRC Inspection Report 50-445/92-59; 50-446/92-59, 5 FOLLOWUP ON CORRECTIVE ACTIONS FOR VIOLATIONS (92702)
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(Closed) Violation 445/9251-01:
Inadeauate Corrective Measures on TERMI-POINT This item involved the licensee's actions associated with Technical Evaluation 92-1295 which directed the pull testing of a random sample of 125 TERMI-POINT connections in both trains of the solid state protection system (SSPS) for Unit 1 and originating from the recommendations prescribed by Westinghouse Technical Bulletin (WTB) NSD-TB-89-06 dated November 1,1989.
However, the pull testing was originally determined by the licensee to be unnecessary. The pull testing was subsequently performed during the second refueling outage (November 1992). As a result of the specified pull testing, defective connector clips were identified and the sample size was increased to 100 percent as prescribed in the WTB. This pull testing activity resulted in the identification of 62 failures on Train A and 69 failures on Train B.
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inspectors noted that pull testing had originally been determined to be unnecessary and was an example of failure to implement appropriate corrective action.
In their letter of response to the Notice of Violation (Letter TXX-93062 d>ted February 15, 1993), the licensee stated that, due to the unavailability of the pull tester and with the concurrence from Westinghouse, the pull testing had intended to be performed during the first refueling outage.
Subsequently, in evaluating the work that was scheduled to be performed during the first refueling outage, the system engineer assigned to the SSPS concluded that the pull tests were not required. This conclusion was based on verbal discussions
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with other utilities, his immediate supervisor, and Westinghouse. On November 21, 1992 (during the second refueling outage), ONE Form 92-1350 was generated to document the pull testing failures, facilitate corrective actions and address concerns of operability during the first and second fuel cycles.
The licensee established that, prior to pull testing, surveillance testing demonstrated that the system would initiate any required engineering safety function actuation or a reactor trip as designed. A 100 percent visual
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inspection performed prior to fuel loading verified that the connector clips were correctly crimped onto the post. Moreover, a reportability evaluation pursuant to 10 CFR 50.55(e) was performed. This evaluation concluded that this issue was nonreportable. However, on February 2, 1993, a voluntary LER was issued (see Section 7.3) evaluating the results of the TERMI-POINT connector clips unable to meet the pull tests. As documented on One Form 92-1350, inspection, testing, and replacement of failed clips was completed as recommended by the WTB. Additionally, procedures within the Vendor Equipment Technical Information program have been revised to include the tracking of further WTBs. Any deviations from the vendor's recommendations are to be documented with proper justification.
Based on the licensee's corrective actions and the evaluation provided by
LER 445/92-028 (see Section 7.3), the inspectors found these corrective actions appropriate.
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6 FOLLOWUP (92701)
(Closed) Inspection followup Item 445/9259-02: Containment Fan Cooler Corrective Maintenance This item was opened as a result of the inspector's observation of an electrician having difficulty installing temporary electrical jumpers (alligator clips) on terminal blocks during corrective maintenance work on the i
containment Fan Cooler 1-03 motor.
(The alligator clips were falling off each time the cabinet door was closed.) Although the electrician was successful in
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modifying the alligator clips and securing the jumper to the terminal blocks, J
the inspector's review of the procedure in use (MSE-00-1203, Revision 2) did j
not specify ine connection details for the jumpers; therefore, the inspector i
identified this matter as a followup item pending the licensee's review of the I
inspector's observation.
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Ouring this inspection, the inspectors discussed this issue with the licensee representative.
In reviewing the issue, the licensee concluded that attaching
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alligator jumper clips was not a specialized technique and, therefore, did not
require connection details. However, Procedure MSE-G0-1203, Revision 4,
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" Electrical Terminations Wire Sizes 26 AWG-10 AWG," contained a precaution to i
exercise extreme care when working in or around switchgear, motor-control
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centers, or other possible energized sources to avoid contact between these sources and personnel, cable, or tools.
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7 ONSITE REVIEW OF LERS (92700)
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7.1 (Closed) LER 445/91-002:
Reactor Trio Caused by inadeauate Setpoints on the Generator Primary Water Head Tank and Less Than Adecuate Review of
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Procedure Chance This LER was written in response to a reactor trip caused by a main generator
primary water low flow condition leading to a turbine trip.
The primary water
low flew condition was caused by an improper valve lineup configuration while
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isolating and draining the primary water ion exchanger.
Partially draining the system with an improper lineup resulted in the momentary introduction of primary head tank cover gas into the flow sensing lines. This resulted in the indicated low flow condition which initiated the turbine / reactor trip.
i The inspector determined that the licensee's review of the event, I
determination of root causes, and subsequent corrective actions were sufficient to prevent recurrence of the event. These corrective actions
included revision of the primary water head tank level alarm setpoint to alert the operators to a decreasing level prior to flow indication being affected, revision of the system operating procedures to more clearly specify the proper
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alignment to isolate the ion exchanger, and issuance of a " Lessons Learned" memorandum within the affected organizations stressing the importance of procedure reviews and communications during the operation of sensitive equipment and/or systems.
7.2 (Closed) LER 445/91-016: Manufacturina Error Leading to the Failure of a Check Valve to Prevent Backflow l
This LER was voluntarily submitted by the licensee to report the failure of an auxiliary feedwater system check valve to satisfy the test acceptance criteria. This event was reviewed and documented in NRC. Inspection Report 50-445/91-14; 50-446/91-14. The licensee determined that the cause of the event was a combination of the high flow rate present during the test in i
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conjunction with a manufacturing deficiency in the valve, causing the check valve to stick in the open position.
The licensee machined the affected valve
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to remove excess casting material from the valve body to restore the design contour of the valve port and verified that the remaining seven check valves in the auxiliary feedwater system branch lines had the proper finish. To prevent the recurrence of this event, the licensee revised Maintenance
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Procedure MSM-00-8801, "Borg-Warner Check Valve Maintenance," to include i
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s specific steps to insure the valve body and neck are inspected for any irregular or unusual wear areas, including excess casting materials.
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7.3 (Closed) LER 445/92-028: TERMI-POINT Clips Pull Tests in SSPS j
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This issue was submitted as a voluntary LER in response to Violation 445/9251-01 (see Section 5).
The licensee's evaluation of the delay
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in pull testing of the Unit 1 TERMI-POINT connector clips, and the pull test i
failures, determined that tFe event did not present an operability or a' safety issue.
Loss of input power to an SSPS channel or logic train would result in a reactor trip. Any single fcilure within a channel or train would not prevent protective action. As documented by the licensee, the reason for the pull testing and visual inspections were the recommendations contained in a j
WlB issued November 1, 1989.
The WTB stated that some TERMI-POINT clips in i
the SSPS were installed incorrectly during manufacturing.
TERMI-POINT clips
were used in lieu of soldering stranded wires to printed circuit board
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connectors.
In conjunction with the recommendations of the WTB, in March 1988, the licensee performed a 100 percent visual inspection of the SSPS
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TERMI-POINT clip connectors. This inspection found 23 cocked clips (out of approximately 5000), which were replaced at that time. Although the pull testing was not performed until November 14-15, 1992 (during the second refueling outage), the licensee established that, during the interim routine surveillance, testing of the SSPS verified continued system operability.
In addition, to prevent a recurrence of delayed corrective actions to a WTB, procedures within the Vendor Equipment Technical Information program have been
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revised to include the tracking of further WTBs. Any deviations from vendor's recommendations were to be documented with proper justification.
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7.4 (Closed) LER 445/92-029:
Flux Doubling Actuation From Loss of IPCI After
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Transfer to Temporary Power
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On December 8, 1992, during the Unit I refueling outage, preparations were being made for the Train A loss of offsite power test.
Electrical maintenance
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had completed the installation of Temporary Modification (92-1-104) which was needed to keep instrument distribution Panel IPCI (Channel 1 instrument power supply) in service on Non-lE power during the test. An A0 transferred Panel IPCI from alternate power to the temporary modification power source by
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operating the incoming breaker on Panel IPC1.
Immediately, power was lost to Panel IPCI and several alarms were observed, indicating Channel 1 power supply was dissbled and the automatic activation of the flux doubling circuit. The flux doubling actuation signal initiated the shift of the centrifugal charging
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pump suction from the volume control tank.to the refuel water storage tank.
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Panel IPCI was returned to its alternate power supply and the Channel 1 power supply was restored in a matter of seconds.
Subsequently, the licensee reported this event to NRC as an unplanned emergency safeguard features actuation.
The licensee determined that the cause for the event was due to personnel error in the design of the temporary modification. The engineer failed to perform self-verification on his design and was unfamiliar with procedural a
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-14-requirements. The temporary modification incorrectly connected a single Phase 208 volt source to the single Phase 118 volt Panel IPCI. Corrective actions included the issuance of "A Lessons Learned" memorandum to engineering personnel; a revision to Procedure STA-602, " Temporary Modifications,"
requiring a design review by an engineer independent from the engineer that i
performed the initial design / evaluation; and an enhancement of the training programs for personnel assigned to engineering support outage teams that
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included the emphasis on the applicable plant procedures.
l 7.5.(0 pen) LER 445/93-008: Missed ASME Section XI Surveillance Due to less Than Adequate Review of Work Documents
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On September 20, 1993, while performing a review of work documents the
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inservice test coordinator noted that the required surveillance test for the spent fuel pool Valves XSF-0160 and XSF-0161 had not been performed prior to the end of the specified surveillance period (violation date of September 13, 1993). The cause of the event was determined by the licensee to be a less than adequate review of work documents when credit was taken for postwork testing as a completed surveillance.
Corrective actions included performance of the required surveillance test and discussions with the cognizant individuals. However, as a corrective action
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separate from and previous to this event, the licensee had implemented a task team to evaluate similar events, causes, and corrective actions planned and/or
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implemented to prevent recurrence of this type of event. The task team was determining what other additional actions were needed (if any) to assure the minimization of missed / incomplete surveillances. A licensee representative stated that, although this type of event occurred only about twice per year (1990-1993), management expectations were to reduce the recurrence further.
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i During this inspection, additional LERs reviewed by the inspectors and applicable to the above issue will remain open, pending the completed
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evaluations by the task team and further NRC review:
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(0 pen) LER 445/92-026: Missed Diesel Generator Fuel Oil Surveillance
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(personnel error, lack of proper scheduling and monitoring)
(0 pen) LER 445/93-004:
Failure to Satisfy Technical Specification
Surveillance Requirement for Liquid Waste Processing Valve (personnel error, valve stroke testing)
(0 pen) LER 445/93-005:
Failure to satisfy Technical Specification
Surveillance Requirements for Safety Chilled Water System and Component Cooling Water (personnel error, valve stroke testing)
(0 pen) LER 445/93-001-01:
Reactor Trip Caused by Personnel Error During
Solid State Protection System Testing
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-15-7.6 (Closed) LER 446/93-005:
Reactor Trip by loss of Primary Water Flow to
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Generator Stator
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On May 20, 1993, during the Unit 2 initial startup testing, the plant was in Mode 1, and reactor power was at 72 percent, when a lew fiow condition in primary water to the main generator caused a generator lockout and reactor / turbine trip.
Plant response was normal with the following exceptions:
Feedwater Valve 2-HV-2134 exceeded its maximum closure time.
- Both main feedwater pumps were manually tripped when their recirculation
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valves failed to open.
Reactor coolant system pressurizer pressure recorder did not respond to
the pressure transient.
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A steam dump valve indicated midposition after closing.
- The licensee determined that the cause of the reactor / turbine trip was that the generator cooling water flow inlet isolation valve experienced a stem and disk separation and that the root cause was the physical location of orifice assemblies installed on both sides of the valve that created turbulent flow and severe vibration. The vibration eventually caused a fatigue crack to develop in the valve stem with the resulting failure.
Prior stroke tests did not reveal the valve's degrading condition.
Corrective actions included the reorientation of the replacement generator i
primary water isolation valve and the relocation,f both orifice assemblies.
The inspectors reviewed the licensee's implementation of the corrective actions relating to the feedwater isolation valve and additional. events
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identified in the LER as noted above.
Corrective actions adequately addressed each problem and records were well documented.
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ATTACHMENT 1 1 PERSONS CONTACTED Licensee Personnel W. J. Cahill, Group Vice President, Nuclear Production
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0. Bhatty, Senior Licensing Specialist M. R. Blevins, Director of Nuclear Overview
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D. E. Buschbaum, Technical Compliance Manager l
R. C. Byrd, Manager, Construction Operation Support Group D. L. Davis, Manager, Plant Analysis
J. W. Donahue, Manager, Operations
S. L. Ellis, Work Control Manager
W. H. Fish, Modification Supervisor T. A. Hope, Regulatory Compliance Manager J. J. Kelley, Vice President, Nuclear Engineering and Support
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D. C. Kross, Shift Operations Manager D. R. Moore, Manager, Maintenance J. W. Muffett, Manager of Technical Support & Design Engineering R. J. Prince, Radiation Protection Manager i
D. W. Snow, Licensing Specialist G. J. Stein, Mechanical Maintenance Manager
C. L. Terry, Vice President, Nuclear Operations
R. D. Walker, Regulatory Affairs Manager The personnel listed above attended the exit meeting.
In addition to the personnel listed above, the inspectors contacted other personnel during this inspection period.
2 EXIT MEETING An exit meeting was conducted on November 17, 1993. During this meeting, the f
inspectors reviewed the scope and findirgs of the report. The licensee
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acknowledged the inspection findings dccumented in this report. The licensee
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did not identify as proprietary any information provided to, or reviewed by,
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the inspectors.
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TV Electric-4-
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bcc to DMB (IE01)
bec distrib. by RIV:
J. L. Milhoan Resident Inspector (2)
Section Chief (DRP/B)
Lisa Shea, RM/ALF, MS: MNBB 4503 HIS System DRSS-FIPS
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RIV File Project Engineer (DRP/B)
Section Chief (DRP/TSS)
A. B. Beach (DRP)
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bcc distrib. by RIV:
J. L. Milhoan Resident Inspector (2)
Section Chief (DRP/B)
Lisa Shea, RM/ALF, MS: HNBB 4503 MIS System DRSS-FIPS RIV File Project Engineer (DRP/B)
Section Chief (DRP/TSS)
A. B. Beach (DRP)
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