IR 05000413/1993017
| ML20046B772 | |
| Person / Time | |
|---|---|
| Site: | Catawba  |
| Issue date: | 07/02/1993 |
| From: | Hopkins P, Lesser M, John Zeiler NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20046B766 | List: |
| References | |
| 50-413-93-17, 50-414-93-17, NUDOCS 9308060181 | |
| Download: ML20046B772 (15) | |
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UNITED STATES i
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NUCLEAR REGULATORY COMMISSION i
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E 101 MAR 1ETTA STREET, N.W., SUITE 2900
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? y ATLANTA, GEORGI A 30323-0199
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Report Nos.:
50-413/93-17 and 50-414/93-17
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Licensee: Duke Power Company I
422 South Church Street Charlotte, N.C.
28242 Docket Nos.:
50-413 and 50-414 License Nos.: NPF-35 and NPF-52
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Facility Name: CataCa Nuclear Station Units 1 and 2 l
Inspection Conducted: May 9, 1993 - June 5, 1993
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3 Inspector:
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%t-P. C. Hopkins, Rssiden(Jnspector Date Signed f
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Inspector:
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p T Zeiler, Resi Insp r
Da'te Si'gned Approved by:
+1 1/2 7 c2 f=8 (cd Mark S. Lesser, Chief Batt Signed
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Projects Section 3A Division of Reactor Projects
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SUMMARY
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Scope:
This routine resident inspection was conducted in the areas of
plant operations; surveillance observations; maintenance observations; emergency drill exercise; operating experience
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program; licensee event reports; and follow-up of previously l
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identified items.
Results:
Two Non-Cited Violations were identified involving (1) the failure to calibrate electronic personal dosimeters at the required frequency (paragraph 3.d), and (2) weaknesses in the l'censee's handling of operating experience information (paragraph 7).
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REPORT DETAILS 1.
Persons Contacted Licensee Employees S. Bradshaw, Shift Operations Manager J. Forbes, Engineering Manager
- R. Futrell, Regulatory Compliance Manager
- T. Harrall, Safety Assurance Manager
- J. Lowery, Compliance Specialist
- W. McCollum, Station Manager W. Miller, Operations Superintendent D. Rehn, Catawba Site Vice-President Other licensee employees contacted included technicians, operators, mechanics, security force members, and office personnel.
NRC Resident Inspectors P. Hopkins
- J. Zeiler
- Attended exit interview.
Acronyms and abbreviations used throughout this report are-listed in the last paragraph.
2.
Plant Status Unit 1 Summary Unit 1 began the report period operating at 100 percent power. On June 5 power was reduced to 30 percent to facilitate repair of a main condenser tube leak. The report period ended with this repair activity ongoing.
For details concerning the condenser tube repair, refer to paragraph 3.b.
Unit 2 Summary Unit 2 operated at 100 percent power for the entire report period with no major problems.
3.
Plant Operations Review (71707)
a.
General Observations The inspectors reviewed piant 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 l
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reviewed. Shift turnovers were observed to verify that they were
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conducted in accordance with approved procedures. The number of
licensed personnel on each shift inspected either met or surpassed
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the requirements of Technical Specifications.
Further, daily l
plant status meetings were routinely attended.
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Plant tours were performed on a routine basis. The areas toured
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included but were not limited to the following:
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Turbine Buildings
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Auxiliary Building i
Units 1 and 2 Diesel Generator Rooms
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Units 1 and 2 Vital Switchgear Rooms Units 1 and 2 Vital Battery Rooms Standby Shutdown Facility
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During the plant tours the inspectors verified by observation and
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interviews that proper measures were taken, and procedures were
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followed, to ensure that physical protection of the facility met current requirements.
Items inspected included the. security organization, the establishment and maintenance of gates, doors, and isolation zones in the proper conditions, and access control r
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badging.
In addition, the areas toured were observed for fire prevention and protection activities and radiological control practices. The
inspectors alsa reviewed PIPS to determine if the licensee was appropriately documenting problems and implementing corrective
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actions, j
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Unit 1
"E" Extraction Line Steam Leak and Condenser Tube Leak i
Repair
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On May 27 the licensee detected a small loss of efficiency and a
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corresponding drop in shell pressure in the "E" feedwater heater.
This indicated that the existing leak from the "E" extraction
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steam line expansion joint located in the "C" condenser had increased, causing a decrease in the efficiency of the condenser.
Conditions stabilized following a reduction in efficiency equivalent to 50 Megawatts.
The inspectors reviewed the trends of the "E" feedwater heater shell pressures.
The potential adverse effect on the unit if the leak were to worsen and the potential damage that the leak could have on the condenser internals were discussed with the licensee.
The licensee management indicated that although the rist.s associated with continued operation were judged to be low, a plant shutdown to repair the leak would commence on June 14.
In the meantime, the licensee intended to closely monitor certain parameters which would provide early detection of further
degradation such as:
(1) feedwater heater pressures; (2) increase-
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tubing or generator shaft vibration levels; (3) outer turbine wall i
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3 temperatures hot spots; (4) changes in unit power output; and (5)
turbine thrust bearing metal temperatures.
In addition, reactor power level restrictions were placed on the unit based on degrading "E" feedwater heater shell pressures. The inspectors determir.ed that these actions were adequate and verified their implementation.
On June 5 chemical analysis revealed a main condenser tube leak.
Power was reduced to 30 percent to facilitate inspection in the
"C" condenser water box. One tube near the top of the tube sheet was leaking.
Eddy current testing of the top two rows of condenser tubes was conducted, revealing that nineteen tubes in the top row were blocked to the extent that the eddy current probe was unable to pass through. The tube blockage was located near the "E" expansion joint, indicating that debris from the expansion joint leak may have caused the condenser tube damage. No blockage problems were encountered during testing of the second row of tubes, and the results of the second row testing did not reveal any signs of additional tube degradation. The leaking tube was plugged, as well as the entire top row of tubes, due to the blockage.
Tube plugging activities were still in progress at the end of the report period.
Following these activities the licensee planned to return to full power operation.
c.
Unit 2 Fuel Rod Leakage
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On May 13, with Unit 2 at 100 percent power, chemical analysis of the NC system revealed an increase in specific activity, indicating one or more leaking fuel rods. On May 16, the specific activity in terms of Dose Equivalent Iodine (DEI) concentration reached its highest value of 0.0709 micro-Curie / milliliter ( Ci/ml) and then slowly began to trend downward. This was still substantially below the TS limit for specific activity, which is 1 pCi/ml when the unit is at 100 percent power.
Duke has established a four-stage action level program for initiating actions to mitigate the consequences of fuel defects.
These actions are based on a calculated Fuel Reliability Indicator (FRI) value, which is based on the concentration of I-131 that has been corrected for tramp uranium.
On May 17, the reactor engineering group calculated an FRI of 0.05 pCi/ml, which put the unit in Action level 3.
Action Level 3 requires the following: 1) increase NC sampling frequency, 2)
evaluate necessary power derating and power maneuvering restrictions, 3) develop contingency plans for continued operation, and 4) plan fuel repair work for the refueling outage.
The inspectors verified that the licensee had initiated the above action __
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By the end of the report period the DEI was approximately 0.03 Ci/ml and the FRI was 0.015 pCi/ml.
Based on reactor engineering l
recommendations the following actions had been completed:
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power maneuvering restri o,ns of f 3 percent per hour were
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implemented,
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the unit was removed from any load follow planning,
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daily radiochemistry sampling was implemented to ensure that any change was observed and the proper actions were pursued, j
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flC letdown flow was increased for improved purification, and
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a contingency plan was developed defining actions to be taken if DEI increased.
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The inspectors verified the implementation of these actions and will continue to monitor the licensee's actions to reduce the
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impact of operating with the fuel failure.
d.
Calibtation Due Date Exceeded for Radiation Monitoring Devices
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On May 27, the inspectors discovered a personal radiation monitoring device (electronic dosimeter) stored at the entrance to the Radiation Control Area (RCA) that had passed its calibration
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i due date. All personnel entering the RCA are required to wear an i
l electronic dosimeter. Upon exiting the RCA, dosimeters are
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returned to the storage racks at the RCA entrance for the next
user. According to the calibration sticker on the dosimeter, it
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had been calibrated on December 11, 1992, with a calibration due date of May 11, 1993. The inspector _ verified that there were no other dosimeters in the storage racks that had passed their calibration due dates and the potentially out-of-cal dosimeter was l
returned to Radiation Protection personnel for verification of the l
calibration dates.
The licensee determined that the May 11 calibration due date was correct, indicating that the dosimeter should have been removed from service for recalibration prior to this date.
Following a review of all plant dosimeters, the licensee discovered three additional dosimeters still in circulation with expired calibration due dates. All four of the expired dosimeters had been used repeatedly by plant personnel.
The dosimeters were tested, and the results revealed that they were still within their required accuracy range. Therefore, it was not necessary to correct the dose received by personnel that had used the i
dosimetry.
A subsequent licensee investigation determined that these four j
dosimeters had not been removed from circulation due to a problem i
in the computer program that is used to track the calibration due dates. The licensee corrected this problem and, in addition, plans to provide other enhancements to the calibration program.
Enhancements include a " lockout" feature to prevent the attempted use of a dosimeter that has exceeded its calibration due date and
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a color coding scheme for dosimeters with a common calibration due
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date to aid personnel in removing them for recalibration.
10 CFR 50, Appendix B, Criterion XII, Control of Test and Measuring Equipment, requires that measures be established to assure that instruments used in activities affecting quality are properly controlled, calibrated, and adjusted at specified periods to maintain accuracy within necessary limits.
Contrary to this, the licensee's program for ensuring that electronic dosimeters were calibrated every six months was inadequate.
However, the inspectors determined that adequate corrective action was being taken by the licensee; therefore, this
NRC-identified violation is not being cited because the criteria
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specified in Section VII.B of the Enforcement Policy were
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satisfied. This issue is identified as NCV 413, 414/93-17-01:
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Discrepancy in Personal Electronic Dosimeter Calibration Program.
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e.
Procedure Change Process The inspector reviewed the operations group procedure change
process to determine:
(1) if an aggressive process was in place to effect procedure improvements; and (2) if changes were tracked and implemented in a timely manner. The licensee has developed computerized tracking for every outstanding change including call-in suggestions, modification required changes, periodic review
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items, event-initiated changes, etc.
Every operations group procedure type, such as operating procedures, emergency procedures, abnormal procedures, and test procedures, is included.
l The licensee indicated that this process has helped to prevent the
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misplacement of a change request, which had occurred occasionally under the previous hardcopy process.
It also improved statistical tracking and trending capability.
In addition, the program
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provides support to the feedback process; information regarding the action taken on each change is sent to the person who
suggested the change.
The inspector reviewed the computer listing of operations l
procedures representing 333 changes for 133 procedures. Although
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the changes were ones which did not need immediate action, some were as old as three years. The licensee does track backlog, which has remained at approximately 650 items during 1993. The
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licensee indicated that backlog had been as high as 1200 and that i
approximately 1200 changes had been processed in the year ending February,1993, thereby reducing backlog-by approximately 50%.
Although the backlog is still high, the licensee has established the goal of not having any changes older than six months by the end of the year. Furthermore, the licensee is completing more.
changes than are requested during non-outage periods.
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Board (PPRB). The operations group had previously been criticized
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for giving inconsistent answers to operators concerning procedural questions. The PPRB was formed to address that problem and to review significant procedure changes, primarily those involving emergency procedures. The board's answers are documented and l
maintained in a notebook in the control room and the simulator area for reference.
Significant changes and philosophy guidarace
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are incorporated into the training process. The inspector questioned several operators regarding support for improving procedures and the training process. These operators indicated that procedures are improving and they are being encouraged to suggest changes. They indicated that changes sometimes take a long time and were not aware of the goal to reduce the backlog.
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The inspectors concluded that the PPRB notebook was a valuable tool.
l In summary, the licensee has taken actions to improve procedures l
and to track and trend changes. This process should continue to l
improve procedures and procedure compliance.
One NCV was identified.
4.
Surveillance Observation (61726)
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General During the inspection period, the inspectors verified that plant operations were in compliance with various TS requirements, such
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as the TS for reactivity control systems, reactor coolant
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systems, safety injection systems, emergency safeguards systems, emergency power systems, containment, and other important plant
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support systems. The inspectors verified that surveillance
testing was performed in accordance with approved written procedures; test instrumentation was calibrated; limiting l
conditions for operation were met; appropriate removal and restoration of the affected equipment were accomplished; test
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results met acceptance criteria and were reviewed by personnel
other than the individual directing the test; and any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
b.
Surveillance Activities Reviewed The inspectors witnessed or reviewed the following surveillances:
PT/0/A/4400/01C Fire Suppressor System Monthly Test
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PT/0/A/4400/0lX Essential Area Sprinkler Alarm Test
l PT/0/A/4400/06 Perform Raw Water Capacity Check on
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Containment Spray Heat Exchanger 2A
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PT/0/A/4450/08A VC/YC System Filter A Test PT/0/A/4600/22B Perform RN Pump 2B Test PT/0/B/4350/08 Heat Trace Alignment Verification PT/1/A/4200/09A Auxiliary Safeguards Test
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PT/1/A/4350/02B Maintenance Functional Test for DG 1B PT/1/A/4400/03B Functional Tests for KC Pumps IB PT/1/A/4450/03A VE Train IA Operability Test PT/1/A/4450/09B VF Train Operability Test i
PT/2/A/4200/10A Perform ND Pump 2A Pump Test
PT/2/A/4200/59 Perform RN to CA System Flush Test
PT/2/A/4250/06 Perform CA Turbine No. 2 Pump Run Test l
PT/2/A/4250/063 Perform CA Pump 2B Performance Test PT/2/A/4350/03 Electric Power Source Alignment Verification No violations or deviations were identified.
5.
Maintenance Observations (62703)
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General
Station maintenance activities for selected systems and components were observed and/or reviewed to ensure that they were conducted in accordance with the applicable requirements.
The inspectors l
verified licensee conformance to requirements.
Specifically, j
activities were accomplished using approved procedures, and i
functional testing and calibrations were performed prior to
returning components or systems to service; quality control
records were maintained; activities performed were accomplished by qualified personnel; and materials used were properly certified.
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Work requests were reviewed to determine the status of outstanding
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jobs and to ensure that priority was assigned to safety-related j
equipment maintenance which may affect system performance.
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Maintenance Activities Reviewed
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I The inspectors witnessed or reviewed activities associated with the following Work Requests (W0s):
WO 93002516 Repair Leak on 2NI-165 WO 93002517 Repair Leak on 2NI-167 WO 93021128 Inspect Repair VC/YC Chiller i
WO 93021188 DG 1A 011 Condition Inspection Verification l
WO 93024820 Replace Valve VA-5232
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WO 93030296 Repair / Replace Relays Associated with Load Sequencer B WO 93035660 Perform a Differential Pressure Test on Valve 2RN-28A NSM CN-50078 VC/YC System Controls Modification c.
Inspector Observations of NSM CN-50078 The purpose of this station modification was to change the VC/YC System controls to improve system reliability, simplify maintenance, and reduce personnel radiation exposure.
The-following are the main changes that took place:
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" Sequencer Signal Control Circuit" reset switch and i
indicating light were installed for both VC/YC trains in the
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Control Room, l
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temperature switches were removed from the system and the I
associated annunciators from the Control Room, l
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chilled water pump differential pressure switches were
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downgraded from safety to non-safety, l
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start feature was removed for the non-selected Control Room l
Area Air Handling Unit (CRA-AHU) during LOCA or Blackout operations,
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start feature was removed for the non-selected Control Room
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l Air Handling Unit (CR-AHU) and the interlock for dampers D-
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4, D-5, D-6, D-7, and D-8 during LOCA or Blackout operation
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shaft seals were installed on the Smoke Purge Fans and hand
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operated butterfly valves were installed between the Smoke-Purge Fans and Unit Vent.
This modification was implemented in two stages: 1) the safety-related part that impacted TS was completed, then 2) the non-
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safety-related portion of the modification was completed. The safety-related portion took approximately 3 days and the non-
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safety-related portion was planned to take approximately 4 days and was ongoing at the end of the inspection period.
This two stage approach minimized the duration of unavailability for the VC/YC System.
Post-modification testing of the safety-related portion was performed to verify operability of the VC/YC system prior to i
returning the system to service.
The inspectors reviewed this testing and determined that it adequately verified the proper operation of components affected by the modifications. The inspector witnessed selected portions of this testing and observed that it was performed in a controlled manner, using an approved
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procedure.
l No-violations or deviations were identified.
6.
Emergency Drill Exercise (71707)
On May 26 the inspectors participated in the licensee's annual emergency preparedness exercise. This was an off-hours, unannounced exercise and involved a military plane crash into the RN pumphouse structure and a subsequent loss of RN cooling to the Component Cooling Water system with other complications.
The scenario was challenging, employing a simulated plane crash and fire at the RN pumphouse. The licensee exhibited good mitigation strategies, especially the engineering support e,
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l staff in the Technical Support Center who quickly developed an alternative cooling water flowpath. Weaknesses were noted involving 1)
initial confusion over the emergency classification, and 2) discrepancy between procedures that prescribe protective action guidelines for sheltering surrounding areas. NRC Region II conducted a full evaluation of the drill which is described in NRC Inspection Report Nos. 50-413, 414/93-15.
7.
Operating Experience Program Review (40500)
The licensee's Operating Experience Program is designed to collect,
distribute, and evaluate the necessary corrective actions for vender and
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operating experience information.
During this report period resident inspectors from McGuire and Catawba Nuclear Stations collaborated on an evaluation of OEP information processing by reviewing a sample of the
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licensee's OEP information packets.
Particular attention was focused on
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the timeliness of the subsequent licensee evaluation. This review was precipitated by a concern (identified in NRC-Inspection Report Hos. 413, 414/93-07 and 369, 370/93-03) involving the untimely evaluation of an issue that was identified by personnel at South Texas Nuclear Station in October 1992. As a result of this concern, an unresolved item (URI 93-
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07-05) was issued at Catawba. A more detailed review of the licensee's
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program for processing OEP material was necessary to determine if this was an isolated incident.
The licensee's OEP is described in Nuclear System Directive (NSD) 204, which had an effective date of November 1,1992.
In accordance with this NSD, the OEP staff is responsible for receiving, screening, and distributing operating experience material to the appropriate corporate
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technical group for evaluation.
The technical group that is assigned responsibility for an issue is required to evaluate the information and
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identify any necessary corrective actions within 1) 30 days of receiving.
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the material from the OEP staff for "immediate" attention items, such as 10 CFR 21 issues, and 2) 90 days for " normal" attention items, such as LERs and industry Operating Plant Experience (DE) Reports.
If these
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dates cannot be met, the OEP staff should be contacted and an extension should be requested.
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In the case of the issue involved in the URI 93-07-05, the OE event description was distributed by the OEP staff on November 9, 1992 to the corporate technical staff for evaluation. The due date for the
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evaluation to be completed and returned to the OEP staff was February 12, 1993.
The technical group failed to complete this evaluation within the required 90 days.
In fact, information on the
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issue was not forwarded to the site engineering staff for review until February 16, 1993.
Once this information was received the site staff reviewed the issue and implemented timely corrective actions; however, the overall 90 day requirement had not been met.. The licensee reported i
that an extension was requested by the technical group responsible for i
the issuance, but this request was not made until after the evaluation due date.
Failure to complete the evaluation of this issue within 90 days violated the requirements of NSD 204.
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The inspectors reviewed a sample of completed OEP packages, including station LERs, vendor information letters (VIls),10 CFR 21 issues, NRC Information Notices, and OE reports. The findings listed in the
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following paragraph were identified by the resident inspector from Catawba.
The McGuire inspector identified similar findings, which are
documented in NRC Inspection Report No. 50-369, 370/93-09.
1.
Although several examples were identified where an excessive
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amount of time was involved before the OEP staff distributed the information to the corporate technical group for evaluation, NSD l
204 does not specify time requirements for " receipt and
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screening"; however the OEP staff manager indicated that ten days
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were expected. The following OEP items were identified by the inspector as having exceeded what was a reasonable " receipt and
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screening" time period:
OEP Item Receipt and Screenino Period
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i PIR 2-C92-0071 (LER)
20 Days PlR 0-C92-0078 (LER)
30 Days PIP 2-C92-0884 (LER)
Months
PIP 0-C92-0859 (LER)
3.5 Months
VIL-0/91-02 (Part 21)
23 Days l
VIL-0/92-09 (Part 21)
50 Days
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VIL-0/93-01 (Part 21)
27 Days OE-5372 19 Days OE-5435 20 Days OE-5441 18 Days P
The first four items listed above were Catawba LERs.
All LERs
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generated at each of the three nuclear stations are evaluated for their generic impact on each of the other stations.
However, the
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OEP staff does not screen PIPS that result in LERs until after the i
site has developed its corrective actions for these items. As shown in the preceding OEP Item Report list, this can result in an excessive amount of time before PIPS are screened by the OEP staff and subsequently evaluated for generic impact. The OEP manager indicated that this had been recognized as a weakness, and that the recent computerization of the PIP documents should enable his staff to screen these items earlier in the process.
Part 21 reports can have significant operability impact; therefore, they need to be entered into the OEP process for
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evaluation as quickly as possible. As a result, the inspectors were particularly interested in the untimely processing of the 10
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CFR 21 (Part 21) OEP Item Report list. Two of these Part 21
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reports originated from Limitorque Corporation. Both letters
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transmitting the reports from the vendor were addressed to the
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Station Manager at McGuire Nuclear Station as opposed to the
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expected primary point of contact, the OEP department.
i Apparently, the letters were being faxed to the OEP staff from McGuire, but this caused additional delays before the material
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The OEP manager indicated that Limitorque l
Corporation would be contacted to correct the Duke Power Company interface for receipt of technical information.
2.
Several examples of the corporate technical group exceeding the required 30 or 90 day response due dates were identified; in some cases an extension had not been granted.
The inspectors noted frequent and liberal use of extensions by almost all the technical groups, and for some of these items, it was questionable whether an extension was requested due to the complexity of the issue or due to a lack of prompt attention to the item.
The inspectors noted that the OEP staff tracks overdue OEP items.
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At the time of the inspection there were 21 overdue OEP items.
Based on discussions with the OEP staff, greater management attention has been focused on resolving overdue items and, as a result, the number of overdue items has decreased dramatically
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since the previous year.
l The following OEP items exceeded their original evaluation due date without a documented, granted extension:
OEP Item No. of Days Past Due Date PIR 0-C92-0078
PIR l-C92-0079
l VIL-0/91-02 (Part 21)
VIL-0/93-01 (Part 21)
VIL-BW/91-01
l The inspector did not consider any of these items to be as significant to safety as the issue involved in URI 93-07-05; I
however, these items represented additional examples of the untimely processing of OEP material and the failure to follow the OEP procedure for requesting extensions.
3.
An excessive amount of time can be involved in the processing of OEP items if proposed corrective actions include training l
recommendations. According to NSD 204, Section 5.2, during the 30
or 90 day evaluation period the technical group that is assigned responsibility for an OEP item coordinates with the training organization to determine whether any training recommendations are warranted. These training recommendations should be part of the evaluation response that is returned to the OEP staff.
The inspector noted that following the return of this information, the OEP staff then requested that the corporate training staff review these recommendations again, allowing in most cases another 90 days to conduct this review.
4.
The processing of OEP item No. VIL-0/92-21, a Part 21 notification from Rosemount Corporation, was not in accordance with the OEP requirements.
Part 21's are designated as "Immediate" attention
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items requiring a 30 day evaluation time period. This item was incorrectly assigned a 90 day evaluation response due date. The inspectors identified this as another example of failure to follow the OEP procedure.
i The inspectors discussed these findings with the OEP manager, who i
indicated that a Quality Improvement Project (QIP) was ongoing in the OEP area. The purpose of this QIP is to identify improvements in the
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OEP program. The OEP manager indicated that the untimely processing of
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OEP items was an area that the QIP was working toward improving.
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10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and j
Drawings, requires 1) that activities affecting quality shall be
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prescribed by procedures that are appropriate to the circumstances, and 2) that these procedures include appropriate acceptance criteria for determining that important activities are satisfactorily accomplished.
The discrepancies discussed in this paragraph involving failure to follow the OEP procedure is a violation of this requirement; however, j
subsequent to review of the circumstances relative to the issue, this NRC-identified violation is not being cited because the criteria specified in Section VII.B of the Enforcement Policy were satisfied.
This issue is identified as NCV 413, 414/93-17-02:
Failure to follow
OEP Procedure Requirements.
One NCV was identified.
8.
Review of Licensee Event Reports (92700)
The following LERs were reviewed to determine if the information provided met NRC requirements. The determination addressed the adequacy of description, verification of compliance with Technical Specifications and regulatory requirements, corrective action taken, existence of l
potential generic problems, reporting requirements satisfied, and the i
relative safety-significance of each event.
a.
(Closed) LER 413/91-30: Technical Specification Violation Due to a Missed Grab Sample on Radiation Monitor EMF-33 as a Result of Inappropriate Action.
This issue involved the failure to perform a TS Action Requirement i
item at the required frequency after radiation monitor IEMF-33 was declared inoperable due to a loss of operating indication in the Control Room.
EMF-33 continuously monitors the gaseous activity released to the Unit Vent from the condenser air ejector exhaust.
TS 3.3.3.11.g required manual sampling every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> when this EMF is inoperable. The second 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> sample was obtained by a radiation protection technician 50 minutes late due to a lack of attention to assigned duties.
The inspector verified the licensee's corrective actions, which included increasing the sampling frequency to twice per 12-hour shift for inoperable EMFs that have a TS required 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> sampling requirement.
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b.
(Closed) LER 413/92-01: Technical Specification Violation Due to Improperly Performed Upper Containment Temperature Surveillance.
t This issue involved failure of the operations personnel to follow a Technical Memorandum that required a certain combination of
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Containment Ventilation Upper Containment Unit Fans be operating to ensure that average upper containment air temperature is
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calculated correctly by the plant computer. This Technical Memorandum was written following the discovery that the cables for the temperature indications for two of the fans were reversed.
Licensee corrective actions included modifications to the computer program for calculating average containment temperature in order i
to account for the reversal of the cables.
In addition, tighter management controls of the Technical Memorandum process have been implemented, reducing the reliance on this process for communicating abnormal system conditions.
The inspectprs reviewed these corrective actions and consider them to be adequate.
No violations or deviations were identified.
9.
Followup on Previous Inspection Findings (92701 and 92702)
a.
(Closed)
EA91-191: Notice of Violation and Proposed Imposition of
Civil Penalty, regarding Apparent Violation 413, 414/91-27-01.
This enforcement action involved five examples of failure to adequately follow plant procedures.
First, an incorrect breaker alignment (1EKPG-21) in the VC/YC System resulted in both VC/YC trains being inoperable for 90 minutes.
Secondly, while testing the 2A Safety injection Pump, two valves, 2NI-ll8A and 2NI-150B, were misaligned, resulting in pump runout flow during start-up.
The third and fourth examples involved the failure to properly verify the position of the 2B SG PORV drain line isolation valve and the 2C SG outlet header drain block valve. The fifth example
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involved the failure to properly verify a containment isolation j
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valve lineup.
The licensee responded to this Civil Penalty by letter, dated March 16, 1992, outlining short term and long term actions taken that were focused on increased management controls and involvement through prot ~1ures and administrative changes, personnel counseling, and improved communications.
The inspectors verified the completion and adequacy of these corrective actions.
b.
(Closed) URI 50-413, 414/93-07-05:
Review of OEP Timeliness.
l During the previous inspection an issue was identified involving I
the untimely evaluation of an item under the licensee's OEP. The inspectors subsequently conducted a review of the licensee's OEP to determine if this was an isolated incident. The results of
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this review are discussed in paragraph 7.
This item is considered closed.
l No violations or deviations were identified.
10.
Exit Interview The inspection scope and findings were summarized on June 8, 1993, with those persons indi ated in paragraph 1.
The inspector described the areas inspected a discussed in detail the following inspection
findings.
No dis.,
ing comments were received from the licensee. The
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licensee did not iuentify as proprietary any of the materials provided
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to or reviewed by the inspectors during this inspection.
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item Number Description and Reference i
NCV 413, 414/93-17-01 Discrepancy in Electronic Dosimeter Calibration
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Program (paragraph 3.d).
NCV 413, 414/93-17-02 Failure to Follow OEP Procedure (paragraph 7).
11.
Acronyms and Abbreviations
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CA
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Diesel Generator
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Enforcement Action
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Radiation Monitor Component Cooling Water System
KC
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LER
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Licensee Event Report
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NC
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Non-Cited Violation
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ND
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Residual Heat Removal System NI
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Safety Injection System NSM
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Nuclear Station Modification OEP
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Operating Experience Program PIP
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Problem Investigation Process
PORV -
Power Operated Relief Valve
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Periodic Procedure l
RN
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Nuclear Service Water System
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R&R
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Removal and Restoration SG
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TS
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Technical Specifications i
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Unresolved Item i
VC/YC -
Control Room Ventilation and Chilled Water System i
VE
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Fuel Building Ventilation System
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