IR 05000413/1993021
| ML20056G826 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 08/27/1993 |
| From: | Freudenberger, Hopkins P, Lesser M, John Zeiler NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20056G822 | List: |
| References | |
| 50-413-93-21, 50-414-93-21, NUDOCS 9309070212 | |
| Download: ML20056G826 (21) | |
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pneog UNITED STATES l
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g NUCLEAR REGULATORY COMMISSION
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'l REGloN 11
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$
o 101 MARIETTA STREET. N.W., SUITE 2900 (
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- j ATLANTA, GEoRGtA 33323 0199 l
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Report Nos.: 50-413/93-21 and 50-414/93-21 l
Licensee: Duke Power Company 422 South Church Street Charlotte, N.C.
28242 j
Docket Nos.: 50-413 and 50-414 License Nos.: NPF-35 and NPF-52 i
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Facility Name: Catawba Nuclear Station Units I and 2
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Inspection Conducted: July 4,1993 - August 7,1993
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Inspector.
Mme//2 /9ff R. J. Freudenberger, Senior Resident Inspector Date Signed
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Inspector:-
32Mpf.
P.T. Hopkins, Resident Inspector ate Signed
[Date Signed a 27/ffe i
Inspector:
J. D iler, Resident Inspector.
3 74 Approved y:
/ M. S.-Lesser, Chief Date Signed i
Projects Section 3A i
Division of Reactor Projects
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SUPEARY
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Scope:
This resident inspection was conducted in the areas of plant
operations, surveillance observations, maintenance observations, l
l installation and testing of modifications, plant procedures, t
licensee _ event reports, and follow-up of previously identified l
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l Results:
Two Non-Cited Violations were identified. The first involved the i
failure to update a Control Room drawing to reflect the as-built
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l configuration' following implementation of a plant modification
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-(paragraph 6.a).
The second involved the failure to calibrate
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Particulate Activity Monitors in accordance with manufacturer
recommendations (paragraph 8.d).
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9309070212 930827 PDR-ADOCK 05000413 G
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i REPORT DETAILS
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Persons Contacted j
Licensee Employees S. Bradshaw, Shift Operations Manager
- J. Forbes, Engineering Manager R. Futrell, Regulatory Compliance Manager j
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- D. Kimball, Safety Review Group Manager
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- J.' Lowery, Compliance Specialist
- W. McCollum, Station Manager i
W. Miller, Operations Superintendent
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- K. Nicholson, Compliance Specialist l
- D. Rehn, Catawba Site Vice-President
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and office personnel.
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NRC Resident Inspectors
- R. Freudenberger, Senior Resident Inspector
- P. Hopkins, Resident Inspector
- J. Zeiler, Resident Inspector
- Attended exit interview.
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Acronyms and abbreviations used throughout this report are listed in the
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last paragraph.
2.-
Plant Status and Activities
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a.
Unit 1 Status Summary Unit I began the report period operating at 100 percent power. On July 5, power was reduced to 35 percent to repair Low Pressure i
Service Water Pump A, which had exhibited high vibration. The unit returned to 100 percent power on July 11 following completion of these repairs. On July 18, a reactor trip on low-low steam
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generator level occurred as a result of operator actions to an
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unexpected loss of feedwater control valve indications caused by j
work being performed on the Digital Feedwater Control System.
l Details pertaining to this trip are contained in paragraphs l
3.b.(1) and 3.c.
Reactor startup commenced July 19 and the unit was placed on-line that same day. The unit reached full power the
- following day and operated at essentially full power for the remainder of the report period.
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b.
. Unit 2 Status Summary Unit 2 operated at or near full power for the entire report period with no major problems, c.
Inspections and Activities of Interest l
During the inspection period several inspections were conducted by specialist inspectors from the NRC Region II Office. A summary of
these inspections follows:
D.iLig Inspectors Functional Area Report 7/12-16 W. Stansberry Security / Safeguards 93-19 7/19-23 W. Kleinsorge Engineering 93-22 7/26-30 R. Shortridge Radiological Controls 93-23 B. Parker On July 28 and 29, Dr. B. Mallet, the Deputy Director of the Division of Radiation Safety and Safeguards, was on site for a management visit.
On August 4, Mr. R. Karsch, of the NRC Office for Analysis and
l Evaluation of Operational Data was on site to review the role of the digital feedwater control system in the Unit I reactor trip on
July 18.
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l Four employees from the Ukrainian Zaporozhskaya Nuclear Power
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Facility visited the Catawba and Oconee Nuclear Power Plants and
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the Duke Corporate Offices in Charlotte, North Carolina, from August 2 through August 20, 1993. The visit was part of an i
ongoing exchange program between the Duke and Zaporozhskaya
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organizations.
3.
Plant Operations (71707)
a.
General Observations
.The inspector reviewed plant operations throughout the report period to verify conformance with regulatory requirements, TS and administrative controls. Control Room logs, the Technical Specification Action Item Log, and the R&R log were routinely reviewed. Shift turnovers were observed to verify that they were conducted in accordance with approved procedures. The number of licensed personnel on each shift inspected either met or surpassed the requirements of Technical Specifications.
Furthermore, daily plant status meetings were routinely attended.
Plant tours were performed on a routine basis.
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During the plant tours, the inspector verified by observation and j
interviews that proper measures were taken, and procedures were j
followed, to ensure that physical protection of the facility met l
current requirements.
Items inspected included the adequacy of
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the security organization; the establishment and maintenance of gates, doors, and isolation zones in the proper conditions; and i
the use of access control badging.
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In addition, the areas toured were observed for fire prevention and security activities and radiological control practices. The inspector also reviewed PIPS to determine if the licensee was appropriately documenting problems and implementing corrective
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actions.
b.
Licensee 10 CFR 50.72 Reparts (1)
Unit 1 Reactor Trip and Auxiliary Feedwater Autostart On July 18 Unit I was operating at full power.
IAE technicians were investigating a Digital Feedwater Control System Cabinet 5 trouble alarm. Cabinet 5 controls the main feedwater pumps and the control valves for the "A" steam generator. Control instrumentation, which provides main control board indication, is also processed through the i
DFCS. At approximately 8:30 p.m., during replacement of the main processor board for the offline, backup processor, the on-line, primary processor failed. Control room operators observed the controllers for the main feedwater pumps and the feedwater flow control valves transfer to manual.
Concurrently, valve position indication on the controllers for the "A" steam generator main feedwater control valve and the bypass valve indicated the closed position.
In addition, the
"A" steam generator main feedwater flow and main steam flow indications showed no flow. Narrow and wide range steam generator water level indication remained available.
Believing the valves to be closed, the operator at the controls opened both the main feedwater regulating valve and the feedwater bypass valve for ine "A" steam generator.
"A" steam generator water level increased rapidly, resulting in a "HIGH-HIGH A SGWL ALERT" alarm. The operator recognized that the feedwater control valves had not closed and attempted to manually control the steam generator level without control valve position or feedwater flow indication.
A reactor trip on Lo-Lo steam generator level in the "A" steam generator occurred shortly thereafter. All control rods fully inserted, and no primary or secondary relief or safety valves lifted during the transient.
Both motor driven auxiliary feedwater pumps auto-started as expected, and decay heat was dissipated via the condenser steam dumps.
This event was reported to the NRC in accordance with 10 CFR
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50.72 (reference EN 25799). See paragraph 3.c below for further discussion of the plant trip.
Following the reactor trip, at 12:30 a.m. on July 19, with the unit in Hot Shutdown, the motor driven auxiliary feedwater pump auto-started as a result of the main feedwater pump trip. While I&E technicians were restoring the digital feedwater control system to normal operation and resetting the "A" main feedwater pump speed control to the primary processor, an increased demand signal was generated.
Pump speed increased and the pump tripped on high discharge
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pressure. The motor driven auxiliary feedwater pumps
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autostarted and operated properly. This Engineered Safety Feature actuation was reported to the NRC as an update to the previous repcrt regarding the reactor trip discussed in the preceeding paragraphs.
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Unauthorized Access into Protected Area On August 5, at 10:40 p.m., an individual attempting to enter the primary access point to obtain a key mistakenly
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entered the protected area through an exit turnstile.
I Security officers immediately recognized the failure of the turnstile and subsequent unauthorized access, escorted the individual out of the protected area, and established a l
compensatory post until repairs were completed on the exit turnstile. The individual was not badged for access into
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the protected area. The event was reported to the NRC in accordance with 10 CFR 73.71 (reference EN 25890).
The turnstile was apparently degraded as the result of wear of components in its locking mechanism. The proper operation of the turnstiles was verified by a weekly test which had been performed last on August 3.
The inspector noted that the timely response of security personnel to escort the individual from the protected area and to establish a compensatory post minimized the significance of the event.
c.
Unit 1 Reactor Trip l
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The inspector responded to the site following notification of the reactor trip described in paragraph 3.b.(1).
The inspector observed actions to verify the cause of the reactor trip, discussed the trip with control room personnel, and verified appropriate reporting of the event. The licensee's " Reactor Trip Mini Report" was also reviewed. The inspector determined that plant safety systems responded to the trip as expected and operator actions associated with the event were acceptable. This determination was made considering the indications available to
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the operator, operator training and the timeliness of action required had the feedwater control valves actually closed.
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The Digital Feedwater Control Systems in use at Catawba were installed in 1991 on Unit I and in 1992 on Unit 2.
The systems control feedwater flow by controlling the speed of the two turbine driven main feedwater pumps and throttling main feedwater control valves. Various control grade main control board indications, including feed flow, steam flow, control valve position, and feedwater header differential pressure, are monitored by and processed through the systems. The system design utilizes redundancy (redundant microprocessors for each steam ger.erator loop) to compensate for any single failure while continuing to operate in automatic control. One loop, associated with the "A" steam generator, also includes control functions for the main feedwater pump speed.
For critical failures (i.e. failures beyond a single failure) the systems are designed to transfer to manual control and provide annunciation to the operator that this transfer has occurred. The design also provides for control board indications to fail to their shelf state in this situation to prevent erroneous indication of system parameters to the operators.
On July 18 analysis of trouble alarms associated with the unit I digital feedwater control system indicated that replacement of the l
processor board for the offline, backup processor was required.
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l As cables were being connected the on-line, primary processor failed. With the redundant processors failed, the system transferred to manual control and main control board indications processed through the system failed to zero, as designed.
The licensee's evaluation of the plant trip revealed that the cause of the critical failure of the redundant processors was attributable to the procedure used to replace the processor board.
In 1992 the manufacturer of the system, Westinghouse, identified that during the replacement of the redundant boards, a diagnostic that is executed in the background mode of the on-line processor can be disturbed by maintenance actions performed on the backup processor. The disturbance then results in a diagnostic test failure that causes the control processor to enter a fault condition, which leads to a critical failure. A procedure to prevent the critical failure during maintenance had been developed but not disseminated to the. licensee. Similarly, information regarding proper procedures for recovery from a critical failure of the system was not available at the time of the trip. This resulted in the auto-start of the motor driven auxiliary feedwater pumps while I&E technicians were recovering the digital feedwater control system following the critical failure, as described in part. graph 3.b(1).
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Interim corrective actions included 1) training for technicians i
qualified to perform maintenance on the digital feedwater control system regarding the maintenance procedures described, 2)
i information for operators, including a description of the event and lessons learned, and 3) initiation of improved interface with the manufacturer regarding operational experience with the digital
feedwater control system.
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The inspector considered the licensee's interim corrective actions I
to be sufficient to prevent recurrence in the near term.
Long
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term corrective actions will be reviewed by the inspector as part
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of a review of the LER in accordance with the NRC inspection program.
Improvement in interface with the equipment manufacturer
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is warranted.
I d.
Inattentive Security Officer j
On July 28, at 5:00 a.m., an inspector was entering the Protected
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Area and noticed that the security officer stationed in the search
area of the Personnel Access Portal appeared to be dozing. The
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I officer was seated near the metal detector and controls for the X-ray machine. As the inspector approached, the officer opened his j
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eyes and acknowledged the inspector. The inspector noted that i
there were two other officers nearby, one of whom was providing
"i backup coverage; therefore, no loss of security effectiveness occurred. However, the inspector was concerned with the
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l inattentiveness of the officer and discussed this with the
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security staff.
l The licensee indicated that the officer had only recently l
completed security training and was still getting acclimated to the rotating shift schedule. The licensee's immediate corrective action included counseling the officer on his job responsibilities and actions he should take if he feels fatigued.
In addition, the licensee planned to reiterate to all security personnel methods of adjusting to rotating shift schedules. The inspector determined that-the actions taken by the licensee were commensurate with the significance of this issue, e.
Low Pressure Service Water System Pump Failure On July 3,1993, both Units were in Mode 1 and operating at full power. A non-licensed operator performing rounds identified the
"A" Low Pressure Service Water System pump as having an unusual noise. Additional monitoring of the pump indicated increasing vibration, an indication of pump degradation. By 3:00 p.m. on July 5, pump conditions had degraded further, requiring a power reduction on Unit I to 35 percent-power to allow removal of the pump from service.
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The Low Pressure Service Water System is a non-safety-related system that supplies water from Lake Wylie for various cooling and makeup uses on the secondary side of the plant. A major load of the system is makeup water to the cooling tower basins to replace condenser circulating water lost due to evaporation, windage, and blowdown. Three vertical pumps are provided to draw water out of the pump bay. The original design considered two pumps operating with the third on standby with both units at full power.
Because of continuous high ambient temperatures and degradation of system
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performance, running all three pumps had become necessary to maintain sufficient makeup to the circulating water cooling towers and to maintain secondary cooling loads within operating parameters with both units at full power.
Due to the length of time required to repair the pump, the licensee installed a temporary cooling tower makeup water system.
The temporary system consisted of three diesel-driven pumps with a i
combined capacity of 10,000-12,000 gpm. The pumps took suction from Lake Wylie in the vicinity of the plant discharge and pumped water to the unit. I cooling tower basins through temporarily installed polybutylene piping.
l The inspector observed and reviewed portions of the evolution,
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including the installation of the temporary system, licensee safety assessments, and procedures for operations with the temporary system and repair of the "A" Low Pressure Service Water pump.
OP/0/B/6400/17, operating procedure for cooling tower makeup, was
revised to reflect operation of the temporary cooling tower makeup system. A 10 CFR 50.59 evaluation was initiated to reflect Chemistry operation of the Cooling Tower Makeup during the replacement of the "A" Low Pressure Service Water pump. The
licensee's evaluation concluded that the Low Pressure Service i
Water System did not perform any safety functions and, therefore, the changes did not affect the safe operation of the plant. The effects of a pipe break in the temporary piping were bounded by the assumptions and conditions of the flooding analysis found in the FSAR, and would not have become more significant. The pumps were continuously attended when they were in operation, and the cooling tower basin levels were continuously monitored. A containment dam was prepared to prevent any oil spills from the diesel engines from running into the lake.
Suction screens and strainers were installed to prevent objects from entering the pump i
intake.
Pump intake velocities were considered to ensure that they were low enough to avoid drawing fish into the surtion pipe.
The licensee determined that the problem with the "A" Low Pressure Service Water pump was caused by a 4" x 4" plank, approximately 18 inches in length, that became lodged in the pump suction.
Licensee investigation was unable to reveal the origin of the plank. The "A" Low Pressure Service Water pump was repaired and
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returned to service at approximately 4:00 p.m. on July 10, and Unit I resumed full power operation on July 11.
The inspector noted that appropriate safety evaluations were made and precautions were taken by the licensee regarding the operation of the temporary system.
4.
Surveillance (61726)
During the inspection period, the inspector verified that plant operations were in compliance with various TS requirements, such as those for reactivity control systems, reactor coolant systems, safety injection systems, emergency safeguards systems, emergency power systems, containment, and other important plant support systems. The inspector verified that surveillance testing was performed in accordance with approved written procedures; test instrumentation was calibrated; limiting conditions for operation were met; appropriate removal and restoration of the affected equipment was accomplished; test results met acceptance criteria and were reviewed by personnel other than the individual directing the test; and any deficiencies identified during i
the testing were properly reviewed and resolved by appropriate
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management personnel.
The following surveillances were witnessed and/or reviewed by the inspector:
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Unit 1 Overpower Trip Setpoint Adjustment On July 9, at approximately 5:00 a.m., Unit I was at 49% power and preparing for power escalation.
IAE personnel were performing procedure IP/1/A/3240/17, Overpower Trip High Range Setpoints, under WO 93042643 to adjust and verify power range nuclear instrumentation calibration prior to exceeding 50% reactor power.
The inspector observed as the technicians performed the calibration and verification of high range setpoints at power.
Three IAE personnel were involved at the beginning of the calibration. Two technicians in training to qualify for the task were working with a third who was qualified. Near the end of the shift, the technicians recognized that they were fatigued, put the surveillance on hold, and waited for a new crew to arrive. The turnover by the off-going crew was thorough and identified what work had been completed and what remained.
The inspector noted that technicians not qualified for a specific
task performed the task and independent verification, while directed by a technician qualified on the task. The inspector j
discussed the issue with an IAE supervisor and a maintenance training representative, and reviewed training records and Catawba Nuclear Station Directive 4.2.2, Catawba Nuclear Station Independent Verification. Section 8.0 of the Station Directive, Personnel, requires that the individual performing the task must
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have completed Independent Verification training and must be task-l qualified or be under direction of an individual qualified on the l
task. The " verifier" must have completed Independent Verification L
. training, but may' not be task-qualified provided that person possesses the knowledge required to verify that the correct system
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l or component is properly identified and properly removed from
operability in accordance with approved procedures.
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L Training: records were reviewed to verify th:t the individuals j_
involved were properly trained and qualified to perform the work in accordance with the Station Directive discussed above.
Based on the above findings.and observations, the inspector concluded that the crews were familiar with the qualification process and had proper equipment and procedures while performing the work.
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b.
Reactor Trip Breaker and Solid State Protection System Testing On July 29 the-inspector observed surveillance testing performed in accordance with Work Orders 93047142 and 93047143. The procedures used were IP/1/A/3200/08A, Train A Reactor Trip Breaker Trip Actuating Device Functional and Operational Test and
.IP/1/A/3200/02A, Solid State Protection System (SSPS) Train A Periodic Testing.
ine inspector noted that these test procedures were performed in parallel to maximize system availability and minimize the risk of errors that could result in improper alignment of the system.
Performance of the procedures in parallel appeared to rely on technician knowledge to ensure proper transitions between the procedures. The testing was accomplished without error.
5.
. Maintenance (62703).
I During the reporting period the inspector reviewed maintenance L
activities to verify compliance with the appropriate procedures and TS.
l Methods used in this inspection included direct observation, personnel
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L interviews, and records review. The activities associated with the
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following W0s were reviewed by the inspector:
Work Order Number Description WO 93032183 Remove damper actuator from damper 2CR-D-10 and install manual linkage i
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I WO 93001419 TSM Removal of Power and tie dampers open WO 93032170 Modify damper ICR10 i
I The inspector observed the removal of actuator motors and actuators by maintenance personnel and the installation of self actuating dampers.
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The Inspectar observed maintenance personnel as they utilized resources i
t in the Work Control Center to resolve' problems when they arose. They
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received quick and professional guidance on how to proceed; thus, the i
communications between the shifts, engineering and maintenance appeared to be good. Review of maintenance personnel training and qualification
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i Maintenance supervisors were visible in the field during the inspector's observations. Proper equipment was available and had been properly
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listed on the list of required tools. Turnover briefings were routinely l
- onducted and of adequate qcality. Managers were present for pre-job, l
" tailgate" meetings.
6.
. Installation and Testing c 'todifications (37828)
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Safety Injection Dischm se Piping Vent Valve Installation The inspector reviewed Minor Modification CE-4163 for adding an
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additional vent valve (1NI-482) in the Unit 1 NI discharge piping.
The purpose of this valve was to continuously bleed off pressure
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pump discharge check valves to prevent challenging either of the i
two NI discharge header relief valves. These relief valves have a lift setpoint of 1750 psig. Before the modification a gradual i
pressure increase in this discharge piping resulted from leakage past the NI Cold Leg discharge check valves and was first noticed on June 23 when the unit commenced startup from a forced
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maintenance outage. The licensee attempted to use the existing vent valve in the NI discharge piping, but this valve's throttling capability was inadequate for the low flow required. Once
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L installed, INI-482 was throttled to allow a maximum flow of 0.14 i
gpm.
Leak off through INI-482 was routed via tubing to the floor
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The inspector verified that the modification package was prepared
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in accordance with station requirements. The inspector reviewed
the licensee's 10 CFR 50.59 evaluation to determine if the L
licensee had adequately addressed the safety concerns associated with this configuration. The licensee's evaluation included the effects of this leakage through NI-482 on the ECCS flow
requirements and the radiological consequences. The results of l
this evaluation indicated that the loss of 0.14 gpm was l
insignificant with respect to the required NI ECCS flow rates, and
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the resulting post-accident Operator and Offsite dose increases did not significantly impact GDC 19 and 10 CFR 100 limits.
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so, a Compensatory Action was developed for isolating flow through I
NI-482 in the event of a LOCA, prior to alignment for sump L
recirculation. This action was developed to minirize post-
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accident exposure to personnel in the Auxiliary Building and to minimize the flow of radioactive fluid to the floor drain system.
This Compensatory Action also required 1) flow through NI-482 to be verified less than 0.14 gpm once a week, and 2) NI discharge
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l pressure to be verified once per shift. The inspector verified that this Compensatory Action was implemented and that the above i
actions were being performed. The inspector considered that the
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licensee had adequately addressed the safety concerns associated
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with this configuration.
i-The inspector. reviewed station procedures and control room i
drawings affected by this modification to ensure that they were
l-revised and properly disseminated. During this review the
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' inspector. discovered that drawing No. CN-1562-1.2 for the NI i
i system had not been red-marked to reflect the addition of valve
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INI-482. The inspector brought this discrepancy to the atten h n
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of the Operation's NSM Coordinator. After investigating this j
i problem, the coordinator reported that the drawing had not been i
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red-marked due to a communication break-down in the assignment of
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personnel responsible for completing the task. The NSM Coordinator reported that this communication problem was discussed i
with the individuals involved and their responsibilities for the
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upkeep of drawings was reinforced. The inspector considered this action. adequate to prevent recurrence. The inspector later
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verified that the drawings in the Control Room, Technical Support l
l Center, and Work Control Center were red-marked as required.
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The inspector reviewed OMP 2-10, Control Room Drawing Maintenance,
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l which describes the process for maintaining control room drawings
to reflect the current as-built configuration of the plant.
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i Section 8.5.A.2 requires that the control room copy of a Vital-to-l Operations drawing be red-marked to reflect the as-built l
configuration upon implementation of a modification.
This incident is considered to be a violation of the requirements of TS 6.8.1, for failure to follow OMP 2-10.
After review of the
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circumstances relative to this issue, the inspector determined
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that.this NRC-identified violation will not be cited because the e
criteria specified in Section VII.B.(1) of the NRC Enforcement Policy were satisfied because 1) adequate corrective action was i
initiated, 2) the violation was not willful, and 3) the violation i
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was not similar to prior violations for which corrective actions have not been sufficient to prevent recurrence. This issue is identified as NCV 413/93-21-01:
Failure to Follow OMP 2-10 for Updating Control Room Drawings.
b.
Control Room Ventilation The inspector reviewed NSM CN 50433/00, Control Room Ventilation System (VC) - Removal of ITT damper actuators, and CN 50078/00, Control Room Ventilation System (VC) - Shutdown of One Supply Fan, as well as associated drawings, work requests and the review processes used by the licensee from initiation of the NSM to its j
completion.
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The purpose of the modifications was to improve the reliability of
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the Control Room Ventilation System. a reduction in the
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maintenance resources expended on the system because of the
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frequent failures of the damper actuators was also anticipated.
Substantial changes were made to system configuration and j
operation, including: operation with one of the Control Room supply fans shutdown, configuration of dampers 1 & 2 CR D-9 in the open position for normal and emergency operation, and the re-design of' fifty-four (54) dampers to allow removal of the associated actuators. These changes were incorporated into the modification.
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The inspector reviewed the NSM and work requests, and observed installation of the modification. The inspector reviewed the preliminary test data under TSM #80llPRF to evaluate this
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alternate system configuration with the dampers on Auxiliary Building elevations 560' and 577' tied open. Test results indicated that the HVAC system performance for the Control Room Area was maintained within design parameter
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Based on documentation review, work observations, and interviews with appropriate systems engineers and other personnel, the inspector noted a well-coordinated effort between IAE, Engineering j
Design, Operations and Maintenance and considered the effort to be i
a strength for technical problem solving.
7.
Plant Procedures (42700)
During this inspection period, the inspector reviewed the licensee's procedure upgrade program ongoing in the IAE Department. This effort
began in early 1991 to develop new procedures or pgrade existing ones i
to conform to the current procedure writer's guide standards.
Discussions were held with IAE Supervisors responsible for implementing the program and upgrade status reports were reviewed. The following-conclusions were determined from these discussions and reviews.
There are currently 1,881 IAE procedures targeted for update or development.
181 of these are procedures added when the former Power Delivery Group (PDG) was incorporated into the IAE Department in early 1992. The upgrade program was approximately 59 percent complete when it was reviewed during this inspection period. Procedures have been previously prioritized into four groups based on impact to personnel and plant safety, with priority 1 procedures being the most significant to safety. The upgrade status based on this priority grouping is as follows:
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Total No.
Percent Completion Target
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1-212 100 01/21/92 N/A
607 100 04/26/93 N/A
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N/A 08/31/94
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N/A 12/31/96 PDG 181
N/A 12/01/93
Based on discussions with the licensee regarding the type of procedure changes being made, the inspector considers the implementation of this
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program canable of providing better, more uniform technical procedures.
The inspector noted that procedure upgrades in the priority I and 2 categories-have been completed. This represents a major milestone since l
these procedures are considered to be the most critical. The inspector i
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considers the implementation of this program to be progressing satisfactorily; however, the. pace has been behind original schedules.
For instance, the original goal for priority 2 procedures was 08/01/92.
Review of priority 3 and 4 progress revealed that established monthly
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goals also have not been met. The licensee indicated that progress in these areas should pickup with the completion of the priority 2 procedure upgrades. The inspector will continue to monitor the
licensee's progress in this area.
8.
Licensee Event Reports (92700)
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The LERs listed in this section were reviewed to determine if the information provided met NRC requirements. The determination was based l
upon the adequacy of event description, compliance with Technical
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Specifications and regulatory requirements, corrective action taken,
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existence of potential. generic problems, fulfillment of reporting i
requirements satisfied, and the relative safety-significance of each
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event.
a.
(Closed) LER 413/91-15: Reactor Trip on Turbine Trip Due to Loss of Both Main Feedwater Pumps on Low Suction Pressure.
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This issue involved a reactor trip resulting from a turbine trip.
The turbine tripped because of the loss of both main feedwater pumps on low suction pressure. The low feedwater pump suction pressure condition resulted when control air to heater drain tank pump 101 cutlet control valve IHW-59 failed. This caused the valve to close, as designed, reducing suction pressure to the feedwater pumps. Both the standby Hotwell and Condensate Booster Pumps were tagged out for preventative maintenance and were unavailable to help mitigate the low suction pressure condition.
Control air to 1HW-59 was lost because of a failure of the copper tubing from the level controller to the valve positioner. The licensee determined the root cause of the tubing failure to be high vibration coupled with excessive stress loading at the tubing fitting. The tubing to ICI and IC2 heater drain tank outlet flow
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control valves,1HW-59 and 1HW-60, was replaced with new copper tubing until an evaluation of alternative control air line material for high vibration conditions could be completed.
The licensee eve".uaief the tubing requirements for 1HW-59 and determined that flexible tubing was an acceptable alternative to copper tubing.
Flexible tubing is less.likely to fail under high vibration co ditions. The inspector verified via walk downs that valves 1,2HW-59 and 1,2HW-60 were retubed with flexible tubing.
The licensee also completed an evaluation of other critical secondary-side air operated valves that could initiate a transient if the copper tubing failed. A number of valves in the main steam, auxiliary steam, main feedwater, and auxiliary feedwater
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systems were identified.
Personnel in the licensee's component
. engineering department reported that they visually examined these i
valves for high vibration and tubing damage to determine if there were any immediate problems. Four heater drain system valves were identified on each unit as having high vibration; therefore, the copper tubing to these valves was replaced with flexible tubing.
The inspector questioned if there were plans to replace the rest of the valves on this list or perform a more thorough evaluation, since it was reported that only a visual examination of the valves was performed initially. Engineering personnel reported that they i
have been hesitant to continue replacing with flexible tubing
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until after a longer operating period with the tubing that has already been installed to determine if some unforseen problem develops. The existing flexible tubing installations are reportedly being examined periodically for leakage and damage; thus far, no problems have been identified.
The inspector also discussed the scheduling of maintenance activities with operators and maintenance scheduling personnel.
The licensee reportec that since this event occurred, it is no longer an acceptable sactice to remove both the standby Hotwell and Condensate Booster Pumps at the same time for routina maintenance.
b.
(Closed) LER 413/91-25: Past Operability of the Auxiliary Feedwater Pump System Due to a Design Deficiency.
On July 30, 1991, Unit I was in Mode I at 100% power. The Unit 1 High-High Auxiliary Feedwater Turbine Driven Pump Sump Level annunciator was continuously alarming in the Control Room. The operators determined that both the 1A & IB Auxiliary Feedwater Turbine Driven Pump sump pumps were operating (as expected on receipt of a Hi-Hi alarm), although the sump level remained the same. The operators observed that the Liquid Radwaste System Floor Drain 101 & 1D2 sump pumps were running. All four sump pumps discharge to the Turbine Building Sump through radiation monitor IEMF-52 by way of a common header. The licensee concluded that, with valve IWL846 throttled to ensure proper flow through j
radiation monitors IEMF-52 and 2 EMF-52, the Liquid Radwaste Floor
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Drain sump.D pumps discharge head was overcoming the discharge head of the Auxiliary feedwater Turbine Driven Pump sump pumps, thereby preventing flow from the Auxiliary Feedwater-Turbine
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. Driven Pump Sumps. The licensee concluded that this condition applied to both units and the' Auxiliary feedwater Systems would
not'have been able to meet its safety related design basis with
-the valves 1WL846 and 2WL846 throttled.. This incident is
' attributed to a design deficiency because of the' unanticipated
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interaction between the systems.
Short term corrective. action included opening the throttled valves in the common discharge headers on both units to restore the
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- Auxiliary feedwater sump. systems to an operable configuration.
In addition, alternate sampling of the sump discharge in accordance
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with Technical Specifications was initiated for the inoperable
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radiation monitors.
i The inspector reviewed operational procedures OP/1/A/6500/14 and
'OP/2/A/6500/14 Liquid Waste Operations Controls Liquid Waste l
System, to ensure that proper changes had been made to implement i
the short term corrective actions.
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An engineering evaluation was performed to determine the optimum long-term solution. The evaluation resulted in a modification request (NSM CN 11304/00) to resolve the operational problems
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associated with IEMF-52 and 2 EMF-52. These operational problems are caused by adverse pressure conditions that can exist
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downstream of the monitor.
1 EMF-52 samples flow from the
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Auxiliary Feedwater pump sumps (both the motor and the turbine-
driven pump sumps) and Floor Drain Sump D before the discharges
are routed to the turbine building sump.
The modification to the discharge piping downstream of the
radiation monitors will prevent system pressure from adversely affecting flow from the sumps.
In addition, adequate flow to the i
radiation monitors will be provided.
i The modification also addressed the possibility of gravity / siphon flow of water to the Auxiliary feedwater Turbine Driven Pump sump and floor drain sump discharge system through the new radiation i
monitor discharge piping when no sump pumps are operating. To
prevent back flow from the direction of the Turbine Building Sump, the process line throttling valves will be replaced by check valves.
The inspector reviewed documentation associated with the planned modification and scheduled implementation.
Implementation of the modification on Unit I was planned for August 1993, and on Unit 2 for September 1993.
c.
(Closed) LER 413/92-02: Technical Specification 3.0.3. Entry Due to Two Inoperable Trains of the Control Room Ventilation System.
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On January 16, 1992, at 10:00 p.m. with Units 1 and 2 in Mode 1 at 100% power operation, a post maintenance review of the Control Room Area Ventilation and Chilled Water (VC/YC) System was in progress. The review showed that breaker 2EKPHf22 (train B VC/YC system controls) had been closed during preceding maintenance activities. Operations Technical Memorandums required the breaker to be open. Therefore, the VC/YC train B was inoperable from 3:53 a.m. to 5:25 p.m. on January 16, 1991.
During this period of time the Train B Control Room air handling unit had been removed from service and access doors were opened for inspections. Consequently, with the access doors open and 2EKPH #22 closed, the train B VC/YC dampers would have repositioned upon a safety signal and air flow would have escaped through the access doors. Train A VC/YC was operable but could not have pressurized the Control Room because of the open access doors. Therefore, the VC/YC trains were inoperable while access panels were open. TS 3.0.3. was unknowingly entered.
The Inspector reviewed the response and commitments in the LER.
The inspector verified that the event had been discussed with licensed personnel and that the red tag computer program had been enhanced to include special instructions that appear when tagouts are printed. Operations Management Procedure 2-5 was changed on 2/24/92 to Revision 13.
Corrective Actions were also reviewed at the time of occurrence as documented in NRC Inspection Report 50-413 and 50-414/92-03, detail 7.
This event was identified as a non-cited violation (NCV 414/92-03-01).
d.
(Closed) LER 413/92-06:
Particulate Activities Monitors Inoperable Due to a Technical Deficiency in a Calibration Procedure.
On April 22, 1992, at 3:30 p.m., Units 1 and 2 were operating in Mode 1, Power Operation, at full power. Component engineering personnel were in the process of calibrating a Particulate Activity Monitor (2 EMF-38) when they discovered that the technique used to calibrate the Particulate Activity Monitors in the Radiation Monitoring System mode the monitors less sensitive. The Particulate Activity Monitors involved were EMF-35 (Low Range Containment Particulate Monitor used for Reactor Coolant Leak Detection) and EMF-38 (Vent System Particulate Monitor) for both units. The calibration technique that was described in procedure OP/0/B/3314/13, Radiation Monitoring System Particulate Activity Monitor Channel Calibration, was not in accordance with the calibration procedure described in the manufacturer's manual.
On April 29, 1992, Design Engineering completed an operability evaluation and declared the Particulate Activity Monitors past inoperable for an undetermined period of time because the monitors were being calibrated to a less sensitive threshold than they
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should have been for the activity level on the calibration source.
The calibration technique described in procedure IP/0/B/3314/13 has been used to calibrate the Particulate Activity Monitors since
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both units began operation. The incident was caused by a
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technically deficient procedure.
Corrective action included revising the calibration procedure to include the calibration technique described in the manufacturer's manual.
The Particulate Activity Monitors were recalibrated using the correct technique, and a review was performed to ensure that other radiation monitoring system calibration procedures complied with the manufacturer's manual.
This issue is considered to be a violation of the requirements of TS 3.3.3.1, and 3.3.3.11, for inoperable Particulate Activity Monitors. After review of the circumstances relative to this issue, the inspector determined that this licensee-identified violation will not be cited because the criteria specified in Section Vll.B.(2) of the NRC Enforcement Policy were satisfied, since 1) adequate corrective action was initiated, 2) the violation was not willful, and 3) the violation was not similar to prior violations for vMch corrective actions have not been sufficient to prevent ecurrence. This issue is identified as NCV 413/93-21-02: Failure to calibrate Particulate Activity Monitors in accordance with manufacturer recommendations.
The inspector verified that procedure IP/0/B/3314/13 was performed to calibrate the Particulate Monitors in the Radiation Monitoring System (IEMF-35, IEMF-38, 2 EMF-35, 2 EMF-38) and that the procedure was revised to reflect the calibration technique described in the manufacturer's manual.
e.
(Closed) LER 414/91-08: Unit 2 Reactor Trip Due to an Equipment Failure Which Caused Reactor Coolant Pump 2B to Trip.
On May 29, 1991, at 12:49 a.m., Unit 2 was in Mode 1, Power Operation, when a reactor trip occurred due to low flow on Loop
'B' of the Reactor Coolant System. The 6900 Volt switchgear
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feeder breaker, 218-3, for Reactor Coolant Pump 2B had tripped due to a spurious activation of a ground fault relay. The unit trip i
response was normal. Main feedwater isolation occurred and initiated the Auxiliary Feedwater System. The Reactor Coolant System was stabilized when control room operators reset the Auxiliary Feedwater Auto Start and steam generator levels returned to normal. The transmissions crews replaced the grocnd fault relay and determined that a silicon-controlled rectifier within the relay had become electrically degraded, resulting in the spurious trip of the feeder breaker. The remaining reactor coolant pump relays were tested with no other failures detected.
Corrective actions included sample testing of switchgear relays and the addition of silicon-controlled rectifier tests to the existing protective relay preventive maintenance activities.
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The inspector reviewed the trip list that had been completed at the time of the event to verify that the necessary items were reviewed by appropriate personnel prior to restart of the Unit.
Work requests were reviewed to ensure that the packages had been properly documented and closed. The inspector discussed the process of the trip list for restart with personnel from the Reactor group, IAE/ Maintenance and the WCC. The inspector verified that these groups had adequate knowledge of the restart process. Submission of the LER and follow-up action were performed promptly.
f.
(Closed) LER 414/91-11: Unit 2 Cold Leg Accumulator Actuation Resulting from Reactor Coolant System Depressurization Due to Design Deficiency.
This event involved a pressurizer spray valve that failed to close with Unit 2 in Mode 3, Hot Standby. This resulted in the depressurization of the RCS below the pressure setpoint for Cold Leg Accumulator actuation. The RCS pressure decrease was stopped following the removal of the Process Control Cards for both pressurizer spray valves, causing the valves to close. The Cold Leg Accumulators injected an estimated 1100 gallons during the event. The licensee later determined that pressurizer spray valve, 2NC-29, had failed to close because its electro-pneumatic valve positioner had malfunctioned. When the licensee tested the positioner, they discovered that sensitive to temperature. Using a heat gun, temperature to the positioner was increased, and a corresponding increase in the output of the positioner was observed. Older positioners were found to be more susceptible to the effects of high temperature than new ones. The manufacturer of the valve positioner was unaware that the positioner was temperature sensitive.
Independent testing, however, confirmed the licensee's results.
The inspector reviewed the licensee's evaluation for replacing the positioners of both unit's pressurizer spray valves. A more reliable, replacement positioner that is less sensitive in high-temperature environments was identified.
These new positioners have been installed on the pressurizer spray valves for both units. The licensee's engineering staff reported that they evaluated other critical valves in high-temperature environments that use the older, more temperature-sensitive positioners to determine if these needed replacement. Based on their review, no other valves were identified.
The inspector also reviewed procedure RP/0/B/5000/13, Classification of Emergency, Retype #11, issued on March 29, 1993.
This procedure was revised to clarify what co..stitutes a " valid l
signal" for the purpose of ECCS injection and corrected an enclosure that did not clearly specify a Cold Leg Accumulator injection as a one-hour NRC notification. When this event
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occurred the NRC notification was not timely due to the lack of
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clarity in RP/0/B/5000/13.
g.
The following LERs report Engineered Safety Feature Actuations
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subsequent to reactor coolant system overcooling in response to the inadvertent opening of Steam Dump Valves. The reported events
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are related; therefore, both LERs are closed based on the inspector's review of the events and corrective actions.
(Closed) LER 414/92-02: Engineered Safety Features System Actuation Occurred When the Steam Dump System Valves Modulated
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Open Due to Unknown Causes
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On January 15, 1992, at approximately 1326 hours0.0153 days <br />0.368 hours <br />0.00219 weeks <br />5.04543e-4 months <br />, an unexpected Engineered Safety Feature Actuation occurred on Unit 2 while in Mode 3, Hot Standby. The actuation, P-12 (Lo Lo Tave) occurred when three banks of valves in the Steam Dump System modulated open while in the steam pressure mode, thus bringing average Reactor Coolant System temperature below the P-12 setpoint of 553*F.
Control Room Operators immediately placed the Steam Pressure Controller in manual and attempted to close the Steam Dump Valves.
By the time the valves had closed, the P-12 actuation had occurred. The actuation was reported in accordance with 10 CFR 50.72 (reference EN 22610). Troubleshooting revealed no problems with the Condenser Dump Valves or Steam Pressure Controller.
Corrective action consisted of the installation of a recorder to capture future events while the steam dump system was in the steam pressure imJe of operation.
(Closed) LER 414/93-02: Engineered Safety Features System Actuation When Steam Dump Valves Opened On March 31, 1993, at 8:58 a.m. and 9:23 p.m., two unexpected Engineered Safety Feature Actuations occurred on Unit 2 while in Mode 2, Startup. A third, similar, actuation occurred on April 1, at approximately 9:21 a.m., while in Mode 1, Power Operation, at 15% power. The actuations, P-12 (Lo Lo Tave), occurred when two banks of valves in the Steam dump System opened (while in the I
Steam Pressure Mode), thus bringing average Reactor Coolant System temperature below P-12 setpoint of 553*F.
Control Room Operators took immediate action to close the Steam Dump Valves each time.
The actuations were reported to the NRC in accordance with 10 CFR 50.72 (reference EN 25334). Monitoring equipment that had been previously installed on the Steam Pressure Controller to help
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identify the cause of spurious P-12 actuations recorded data that indicated a problem with a power supply card and pressure transmitter. The inadvertent actuations were attributed to degraded subcomponents and corrective actions included replacement of the power supply card and pressure transmitter.
In each case, the system actuated as was required and the plant responded as expected. The inspector reviewed the licensee's
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corrective actions for this event and determined that the proposed corrective actions were implemented and there had been no recurrences of the event. The licensee provided a thorough l
description of the event and the systems involved.
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Exit Interview The inspection scope and findings were summarized on August 16, 1993, with those persons indicated in paragraph 1.
The inspector described the areas inspected and discussed in detail the inspection findings listed below. No dissenting comments were received from the licensee.
The licensee did not' identify as proprietary any of the materials provided to or reviewed by the inspector during this inspection.
Item Number Description and Reference NCV 413/93-21-01 Failure to follow OMP 2-10 for Updating Control Room Drawings (paragraph 6).
NCV 413/93-21-02 Failure to calibrate Particulate Activity Monitors in accordance with manufacturer recommendations (paragraph 8.d),
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Acronyms and Abbreviations CFR
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Code of Federal Regulations Digital Feedwater Control System DFCS
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ECCS -
' Emergency Core Cooling System FSAR -
Final Safety Analysis Report i
GDC
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General Design Criteria Instrument and Electrical IAE
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IWP
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Inservice Pump Test l
LER Licensee Event Report
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LOCA -
Loss of Coolant Accident LTOP -
Low Temperature Overpressure Protection i
NCV Non-Cited Violation
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l NI
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Safety Injection i
NRC
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Nuclear Regulatory Commission
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NSM-Nuclear Station Modification
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Operations Management Procedure OMP
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Problem Investigation Process (report)
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PORY -
Power Operated Relief Valve Reactor Coolant System RCS
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RL
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Low Pressure Service Water
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RN
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Nuclear Service Water System l
R&R.' -
Removal and Restoration l-TS
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Technical Specifications l
TSM
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Temporary Station Modification i
VC/YC -
Control Room Ventilation and Chill Water System-WCC.
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Work Control Center
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Work Request L
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