IR 05000317/1988016
| ML20153D106 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 08/24/1988 |
| From: | Lester Tripp NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20153D100 | List: |
| References | |
| 50-317-88-16, 50-318-88-16, GL-87-12, IEIN-88-036, IEIN-88-36, NUDOCS 8809020043 | |
| Download: ML20153D106 (18) | |
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION I
Docket / Report:
50-317/88-16 License: OPR 53 50-318/88-16 DPR-69 Licensee:
Baltimore Gas and Electric Company P. O. Box 1475 Baltimore, Maryland 21203 i
Facility:
Calvert Cliffs Nuclear Power Plant, Units 1 and 2 Inspection at:
Lusby, Maryland f
Inspection conducted: July 1 - August 8, 1988
i Inspectors:
D. Trimble, Senior Resident Inspector
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V. pritchett, Resident Inspector M.
losson Project Manager, NRR/PDI-1 Approved by: 8 M
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9.. E. Trim, Chief, Reactor Projects Section 3A
' Drte Summary: July 1 - August 8, 1988: Inspection Report 50-317/88-16, 50-318/88-16 Areas Inspected: (1) facility activities, (2) routine inspections, (3) opera-l tional events, (4) TI 88-02, (5) maintenance, (6) radiological controls, (7)
l physical security, (8) NRC notifications, (9) licensee event reports, (10) re-
ports to the NRC, (11) licensee action on previous inspection findings, and (12) licensee identified violations.
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i Results: A July 15, 1988 trip of Unit 1 due to improper isolation of level switches for #12C feed water heater could have been avoided by propor planning
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and timely implementation of recommendations included in the reactor trip re-
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duction task force report.
Considering problems previously identified with l
i atmospheric dump valves (ADV), the failure of #12 ADV during the above trip
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could have been anticipated and avoided thrcugh a more vigorous corrective i
f action program (detail 9 of this report). An event in which two workers re-
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ceived higher than expected radiation exposures showed a number of weaknesses d
(detail 3 of this report).
Improvements in housekeeping in the form of
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cleaning and painting have been made in the service water and auxiliary feed
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water pump rooms.
Progress has been made in decontaminating the ECCS pump
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rooms.
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8809020043 880826
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DETAILS Within this report period, interviews and discussions were conducted with various licensee personnel, including reactor operators, maintenance and sur-ve111ance technicians and the licensee's management staff.
Night shift in-spections were conducted on July 5 and 26,1988. Weekend / holiday inspections were performed on July 2, 4, 10, 17, and August 6, 1988.
1.
Summary of Facility Activities
Unit 1 A plant startup was in progress at the beginning of the period. The unit was returning to operation following a refueling outage. On July 4,1988 the unit was paralleled to the grid.
Due to an improper adjustment of delta T power indications a large mismatch developed between thermal, delta T,
and nuclear instrument power during power escalation.
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caused two limiting safety system settings to be exceeded (Inspection Report 50-317/88-17; 50-318/88-17).
The plant operated at power until July 15 when the unit tripped due to technician error during maintenance
on #12C feedwater heater (detail 9 of this report). The unit was returned to full power operation on July 18.
Power operation continued throughout
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the remainder of the period.
Unit 2 f
Unit 2 operated at power for the entire inspection period.
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General j
During the week of July 4, 1988, a regional spt:ialist and a resident
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inspector conducted an inspection which principally focused on the area of design engineering (Inspection Report 50-317/88-15; 50-319/88-15). On July 25, Ms. Merylee Slosson, a Project Manager at NRR, began a two-month
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training assignment as a resident inspector at Calvert Cliffs. On August
2, a license 2/NRC management meeting was held in the Region I office in King of Prussia, Pa. (detail 13 of this report).
The principal purpose
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of the meeting was to discuss changes in the licensee's organization. On
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August 8, an enforcement conference was held in the Region I office to discuss (1) improper adjustraents to delta T power indications which led
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to apparent violations of two limiting safety system settings and (2) an (
improper positioning of a voltage regulator control switch which caused
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the inoperability of diesel generator #21 (Inspection Report 50-317/88-17; 50-218/88-17).
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2.
Review of Plant Operation - Routine Inspections (71707)
a.
Daily Inspection During routine facility tours, the following were checked: manning, access control, adherence to procedures ar.J LCO's, instrumentation, recorder traces, protective systems, control rod positions, con-tainment temperature and pressure, control room annunciators, radi-ation monitors, effluent monitoring, emergency power source oper-ability, control room logs, shift supervisor logs, and operating orders.
No unacceptable conditions were noted.
b.
System Alignment Inspection (71710)
Operating confirmation was made of selected piping system trains.
Accessible valve positions and status were examined.
Visual in-spection of major components was performed.
Operability of instru-ments essential to system performance was assessed.
The following systems were checked:
STP 0-9-1, Auxiliary Feedwater Actuation System Monthly Logic
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Unit 1 Auxiliary Feedwater System *
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- For this system, the following items were reviewed: The licensee's system lineup procedure (s); equipment conditions / items that might degrade system performance (hangers, supports, housekeeping, etc.);
instrumentation lineup and operability; valve position / locking (where required) and position indication, and availability of valve operator power supply.
No unacceptable conditions were noted.
c.
Biweekly and Other Inspections During plant tours, the inspector observed shif t turnovers; boric acid tank samples and tank levels were compared to the Technical Specifications; and the use of radiation work permits and Health Physics procedures were reviewed. Area radiation and air monitor use and operational status were reviewed.
Plant housekeeping and clean-
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liness were evaluated.
Notable improvements have been made in decontamination of the ECCS pump rooms.
The service water and auxiliary feedwater pump rooms have been cleaned and painted.
No unacceptable conditions were noted.
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3.
Operational Events (93702)
Intake Structure Door Beginning July 11,.a seeurity guard was stationed on the roof of the instaKe structure to monitor access to certain parts of the plant. Access to the roof is through a non-security water tight access coor (WTD) 153.
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Technical Specification 3.7.10 requires that the door be maintained closed except for normal entry and exit.
The applicable action statement re-quires the door to be resto ed to the closed position within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in hot standby within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
In addition, Technical Specification 3.0.4 does not
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allow mode changes while in an action statement other than required to l
comply with an action statement unless exceptions are identified in an individual specification.
153 was being maintained open to provide the
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guards easy access to the intake structure roof; however, to comply with the action statement, the door was restored to the closed position at least once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. BG&E security was assuring the limits were met through use of a WTD ticket.
Door position was logged approximately once every 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.
On July 15, the licensee prepared to restart Unit 1 following the July 15 turbine / reactor trip. At 6:30 a.n. the shif t supervisor notified security that IS3 needed to be closed and maintained closed in accordance with Technical Specification 3.0.4.
Unit I was restarted and the plant was brought from Mode 3 to Mode 2 on July 16 and Mode 1 on July 17.
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On July 17 at 11:00 p.m., while performing the log review, the control
room supervisor noted that the outside operator log showed IS3 open for
the 6 times the door was checked that day.
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determined that the r
door was out of the specified position from approximately 8:00 a.m. on
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July 15 to 11:00 p.m.
on July 17.
One exception was the log reading,
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recorded at 5:00 p.m. on July 16, which indicated the door was shut. From this it was determined that Technical Specification 3.7.10 was violated when the unit was operated for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with 153 in the open position.
In addition, Technical Specification 3.0.4 was violated when the unit was brought from Mode 3 to Mode 1 on July 16 and 17. These items are considered to be licensee identified violations (50-317/88-16-01) in accordance with Section V.G of Appendix C to 10 CFR 2.
Higher Than Expected Radiation Oose to Two ' Workers
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On June 21, 1988, two mobile maintenance mechanics entered the Unit 1
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27-foot valve alleyway to perform preventive maintenance PM 1-19A-M-R-2 to grease the reach rod linkage for 1-IA-235.
The workers spent approxi-i mately 5 to 10 minutes in the alleyway to perform the maintenance. Upon l
exiting the area, the workers examined their self-reading dosimetry and i
determined exposures to be 60 mR and 130 ;R. The expected dose for the l
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job was 10 mR per worker.
The area, normally a locked high radiation area, was posted as an exclusion area until a more detailed survey could be completed.
The most recent survey map, completed June 9,1988, showed
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the highest contact doses in the area to be 600-800 mR/hr and a 50-100 mR/hr general area field. A spot survey was completed prior to entrance to the area by a radiation safety technician, standing in the valve alleyway doorway using a teletector to take dose readings. The teletector i
has a reach of approximately 12 feet. The work area was approximately 6 j
feet from the doorway (and was approximately 5 feet from the hot spot detected in a post-incident survey).
The technician did not record the results of the survey.
It was indicated that the technician did not ob-serve any unexpected differences from the June 9 survey.
The workers carried with them an exposure rate meter. This meter was not examined by
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the workers during the performance of work in the alleyway.
The Special l
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Work Permit (SWP) #88-0038 used for the performance of the maintenance required that self reading dosimetry be examined once every 10 minutes.
Following recognition of the higher than expected radiation exposure, a survey was conducted on June 21 which identified a general area field of
3-5 R/hr and 4. 70 R/hr hot spot approximately 5 feet from the work area.
The source of the hot spot was identified to be resin in the line from l
purification ion exchanger No. 13 to the spent resin metering tank. On l
May 25, preventive maintenance was performed to lubricate the reach rod i
linkage for valve 1-CVC-152, the isolation valve between the No. 13 ion exchanger and the spent resin metering tank. The post maintenance testing
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was performed by cycling the valve counting the number of turns required
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to open and close. The operators were unable to complete the same number i
of turns in attempting to close the valve as were required to open it, possibly due to resin under the valve seat.
It is believed that a flew
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pathway to the valve was created by cycling the valve with the ion ex-changer outlet valve open which permitted flow of resin to the isolation valve.
A maintenance request (MR) was written on the valve.
The flow
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j path was created again on June 9 when the miscellaneous waste ion ex-l changer was transferred to the spent metering tank with valve 1-CVC-152
partially open which caused resin to flow to the spent resin metering tank
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from the No.13 ion exchanger. Unaware of this flow pathway, the licensee did not flush the lines with nitrogen as usual following a resin transfer.
The MR initiated on the valve was not cleared until August 3, 1988.
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i The licensee completed an investigation of the situation and prepared an
evaluation report.
Proposed corrective actions include review of the
event with radiation safety technicians; use of the event as an example i
of poor radiation safety practices during GOT training; revision of the
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preventative maintenance procedure for lubricating reach rod linkages
associated with the ion exchanger isolation valve to require isolation of
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i the inlet and outlet valves of the ion exchanger; consideration of surveys
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i of the valve al;eyway following resin transfer; and counseling the main-
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tenance mechanics involved in the event.
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The matter of adequacy of the licensee's radiation protection measures for exposure control is unresolved pending further evaluation by a specialist l
NRC inspector of licensee actions including the initial and subsequent i
spot surveys (50-317/88-16-01).
4.
Loss of Decay Heat Removal Capacity When Reactor Coolant System (RCS)
Partially Drained - Region I Temporary Instruction (TI) 88-02 TI 88-02 provides interim NRC follow up action for Generic Letter 87-12, Loss of Residual Heat Removal (RHR) While the RCS is Partially Drained.
Additional inspection will be performed following the planned issuance of an NRC Generic Letter and Headquarters TI on the subject.
In a November 16, 1987, response to Generic Letter 87-12, the licensee committed to maintain a high pressure safety injection (HPSI) pump available whenever the units are in Mode 5 with the RCS in a partially
filled condition.
The inspector confirmed that this commitment was im-piemented through the issuance of GS0 (General Supervisor, Operations)
Standing Instruction 87-3.
A study performed for the licensee by the NSSS supplier (CE) showed that a HPSI pump would provide adequate flow to maintain the core covered for all size reactor coolant pump openings (the i
example scenario in the generic letter for an opening in the reactor
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coolant system).
That instruction additionally provides guidance to maintain water inventory in steam ger.erators whenever possible in Mode 5 (partial RCS fill conditions) which reduces the severity of loss of shutdown cooling events.
On June 20, 1988, the NRC was notified by the Westinghouse Owners Group (WOG) that recent analyses and testing have shown some additional RCS mid-loop operation concerns that may also pertain to CE design plants.
j One scenario involved a case where there is a large opening in a cold leg
with the associated hot leg isolated, such as through the installation of i
a nozzle dam.
Under these postulated conditions, the RCS may pressurize faster at the core exit than at the cold leg following a loss of RHR.
inventory would then be forced out the cold side opening (NRC Information Notice (IN) 88-36 discusses this problem).
The WOG analyses indicated that
it may not be possible to demonstrate successful core recovery using cold leg injection at single HPSI pump flow rates since the amount of cold water reaching the core may not be adequate to suppress boiling.
The desirable path for water injection would then be through the hot leg.
The licensee is evaluating the aed for additional corrective actions to resolve the concerns raised in Generic Letter (GL) 87-12, IN 88-36 and a July 8, 1988 NRC/ Licensee meeting on GL 87-12.
These actions are in an-ticipation of a follow on NRC generic letter on these subjects.
Guidance is provided to operators in procedures on the following:
(1) reduction in flow rate when level is below the mid plane of the hot leg to avoid vortexing,
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(2) recovery action for losses of shutdown cooling, (3) venting of air from the shutdown cooling system and delayed starting of the second pump until after the air is removed, (4) monitoring of the accuracy of level indication systems, and (5) reestablishment of containment integrity following a loss of shutdown cooling.
Training is provided to operators on these procedures.
NRC Information Notice (IN) 88-36 was placed in the operatur required reading file. Operators finished their reviews on August 5, 1988.
The licensee attempts to maintain their reactor vessel level monitoring system in service whenever possible to provide a backup means of indica-tion of RCS level in Mode 5.
As noted above this area will be further reviewed during future inspections.
TI-88-02 is closed.
5.
Plant Maintenance (62703)
The inspector observed and reviewed maintenance and problem investigation activities to verify compliance with regulations, administrative and maintenance procedures, codes and standards, proper QA/QC involvement, safety tag use, equipment alignment, jumper use, personnel qualifications, fire protection, retest requirements, and reportability per Technical Specifications.
The following activities were included:
Troubleshooting of #12C Feedwater Heater Level Switches on July 15,
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on July 29, 1988 Change out of connectors for #12 battery on August 1, 1988
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No significant problems were identified.
6.
Surveillance (61726)
The inspector observed parts of tests to assess performance in accordance with approved procedures and LCO's, test results (if completed), removal and restoration of equipment, and deficiency review and resolution.
The following test was reviewed:
AFAS Monthly Logic Test, STP 0-9-1 on July 26, 1988
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No unacceptable conditions were noted.
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7.
Radiological Controls (71707)
Radiological controls were observed on a routine basis during the re-porting period.
Standard industry radiological work practices, conform-ance to radiological control procedures and 10 CFR Part 20 requirements were observed.
No unacceptable conditions were identified.
8.
Observation of Physical Security (71707)
Checks were made to determine whether security conditions met regulatory requirements, the physical security plan, and approved procedures.
Those checks included security staffing, protected and vital area barriers, vehicle searches and personnel identification, accr 3 control, hadging, and compensatory measures when required.
No unacceptable conditions were noted.
9.
Events Requiring NRL Notification (93702 and 90712)
The circumstances surrounding the following events requiring prompt NRC notification pursuant to 10 CFR 50.72 were reviewed.
For those events resulting in a plant trip, the inspectors reviewed plant parameters, chart recorders, logs, computer printouts and discussed the event with cognizant licensee personnel to ascertain that the cause of the event had been thoroughly investigated for root cause identification.
Unit 1 Reactor Trip At 3:05 a.m. on July 15, 1988, Unit i reactor tripped from 89% power on loss of load.
The loss of load event resulted from improper valve se-quencing while removing the high and high-high level switches associated with 12C feedwater heater from service.
Unit 1 reactor was operating at reduced power of 89% resulting from scheduled work on 148 travelling screen and #11 feedwater regulating valve (FRV).
The decision was made not to work on #11 FRV.
The two instrument maintenance technicians originally assigned to the FRV work were reassigned to review and work on Maintenance Order (MO) #208-193-226A (repair 12C feedwater heater level indication).
The M0 called for isolating both level switches (1-LS-1456 and 1-LS-1457).
The instrument maintenance techt.'cians and shif t supervisor discussed the maintenance work to be performed and ds. ded to isolate the level switches although the work involved only the level transmitter (1-LT-1456) and not the level switche *
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The instrument maintenance technicians proceeded to verify the calibration of 12C feedwater heater remote level indicator. Once the calibration was confirmed, the technicians proceeded to isolate the high and high-high level switches.
The improper valve sequencing during the removal from service of the level switches placed the switches in the trip position.
The level switches provide input to the main turbine trip circuit used to protect the turbine blading from water damage. With both level switches in the trip position, the turbine tripped with a subsequent reactor trip.
Immediately following the reactor trip E0P-0 (Post Trip Immediate Action)
was initiated.
Control room personnel observed that the reactor coolant system cold leg (Tc) temperature and steam generator pressure were below acceptable values. At 3:19 a.m the main steam isolation valves (MSIVs)
were closed in order to stop reactor coolant system (RCS) cooldown. E0P-0 was completed and E0P-4 (Excess Steam Demand) was entered at 3:20 a.m.
A plant operator observed from the auxiliary building roof that 1-MS-3939-CV #12 steam generating atmospheric dump valve (ADV) was open.
Control room remote valve position indication showed #12 ADV closed. At 3:26 a.m.,
1-MS-104, #12 steam generator ADV was closed. E0P-4 was exited and E0P-1 (Reactor Trip) was entered at 3:30 a.m.
During the excess steam demand event a steam generator isolation signal (SGIS) "B" block signal was received and Tc minimum temperature was 511.8 degrees F.
All E0P-1 safety function acceptance criteria parameters re-turned to normal once #12 ADV was isolated.
The final safety function status checks of E0P-1 were completed at 4:40 a.m.
AOP-8 (Reactor Trip Recovery) was initiated at 5:15 a.m.
The unit returned to 100% power on July 17, 1988 at 5:10 p.m.
Maintenance Order MO #208-197-318 was generated to investigate, repair, and adjust #12 ADV.
The valve internals were removed and inspected.
Inspection indicated that the valve's inner plug had severed at the threads which join the inner plug to the valve stem. This resulted in the inner plug dropping to the bottom of the valve housing thereby providing a path for steam to escape while control room indication would reflect a closed ADV.
l Failure of the inner plug is believed to be low frequency cyclic fatigue failure resulting from improper adjustment of the valve stroke. The inner plug and stem assembly have been forwarded to the metal laboratory for further analysis and to document mode of failure.
The phenomenon occurs when the valve stroke is improperly adjusted resulting in the inner plug making contact with the valve cover.
This contact results in failure of the inner plug stem assembly of the ADV's.
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The licensee had previously identified the cause of failure on the ADV's.
A vendor representative had properly adjusted the stroke on ADV #11 and
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In addition, the representative provided guidance on the overhaul of the aforementioned valves from which an overhaul procedure was written for the ADVs which addressed the problem. MR #12289 was written to con-firm the stroke of #22 ADV and prevent a similar occurrence on the re-maining valve.
The atmospheric dump valves have had a long history of performance prob-lems (Inspection Report 50-317/87-27;50-318/87-28).
Considering the problems previously identified with the ADV's, the failure of #12 ADV could have been anticipated and avoided with a more vigorous corrective maintenance program.
l The licensee reviewed the event; recommendations for corrective action l
were (1) to clarify the instructions given in the Maintenance Orders, (2)
to reference any standard practices required to perform the tasks, (3) to provide training to planners in writing techniques for format and clear concise layout of instructions / job activities, (4) senior maintenance personnel to be on site when a maintenance task with potential for trip-ping the unit is to be performed, (5) to implement recommendations of the
"Reactor Trip Reduction Task Force" report with respect to the isolation valves for the level switches for #11 and #12 FWHs, and (6) to conduct training for operations and maintenance personnel to review the causes and results of this trip.
The inspectors concluded that this trip could have been avoided by proper planning and timely implementation of recommendations with respect to planning and control for this type of work included in the "Reactor Trip Reduction Task Force" report.
10.
Review of Licensee Event Reports (LERs) (90712 and 92700)
LERs submitted to NRC:RI were reviewed to verify that the details were clearly reported, including accuracy of the description of cause and adequacy of corrective a tion.
The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted on site follow up.
The following LER's were reviewed:
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LER No.
Event Date Report Date Subject Unit 1 88-05*
06/13/88 07/15/88 Unit 1 Makes Mode Change to Hot Shutdown with a Containment Iodine Filter Out of Service, Caused by Use of an Uncontrolled Document 88-07 07/05/88 08/04/88 Operator Decalibration of Delta T Power Resulting from Low Leakage Core 88-08**
07/16/88 08/01/88 Unit 1 Placed into Modo 2, Start-up, While Water Tight Door, IS3, Was Open Unit 2 88-06*
07/07/88 08/06/88 Failure to Perform Sur-veillance Test on Auxiliary Feedwater Actuation System
- These events are discussed in detail 14 of this report.
- Detailed examination of this event is documented in detail 3 of this inspection report.
No unacceptable conditions were noted.
11. Review of Periodic and Special Reports (90713)
Periodic and special reports submitted to the NRC pursuant to Technical Specification 6.9.1 and 6.9.2 were reviewed.
The review ascertained:
inclusion of information required by the NRC; test results and/or sup-porting information; consistency with design predictions and performance specifications; adequacy of planned corrective action for resolution of problems; determination whether any information should be classified as an abnormal occurrence, and validity of reported information. The following periodic reports were reviewed:
Operating Data Reports for Calvert Cliff s No. 1 Unit and Calvert
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Cliffs No. 2 Unit, dated July 12, 1988.
Steam Generator Category C-3 Inspection Results Report dated August
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No unacceptable cor.ditions were identifie.
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12.
Licensee Action on Previous Inspection Findings (93702 and 92701)
(Closed) Violation 317/84-16; 318/84-16 Procedures Not Established for Post Modification Punch List and Method for Satisfactory Verification of Punch List Prior to System Operation. Procedures were not established for control of safety related post modification "punch" lists, for ensuring satisfactory accomplishment thereof for items on such lists; for ensuring such lists are considered for each safety related modification; or for defining the type of items to be included in such lists.
By letter dated August 23, 1984, Baltimore Gas and Electric Company re-i sponded to the notice of violation and concluded that a thorough review of the current modifications control system indicated that it adequately addresses the criteria of 10 CFR 50, Appendix B.
Following review of the response, the NRC concluded that no violation to NRC regulations had oc-curred. Accordingly, the violation was withdrawn by letter dated June 20,
1985.
This item is closed.
l (Closed) Violation 317/85-13; 318/85-11 Failure to Follow Procedural Guidance Causing Recirculatten Actuation System (RAS) Actuation and Loss of Shutdown Cooling. The following corrective action was completed with
respect to the two events. Disciplinary action was taken with the tech-i nicians involved in the RAS actuation and all Electrical and Controls
technicians were briefed on the event. A performance improvement report was prepared concerning the loss of shutdown cooling.
The report was i
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forwarded to all licensed operators as required reading.
This item is
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13. Management Meeting i
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A meeting among licensee and NRC management was held at USNRC, Region I,
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King of Prussia, Pa. on August 2,1988. The purpose of the meeting was to introduce licensee managers newly assigned to the plant and to present
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a discussion regarding the details of the pending reorganization of the
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Nuclear Energy Department. The meeting was marked by frank discussion of
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the rationale for and the improvements expected to result from the pending
i reorganization. A list of attendees and a copy of the material presented
during the meeting is attached to this report (Attachment 1)
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14.
Licensee Identified Violations Containment Iodine Filter Unit
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At 6:00 p.m. on June 15, 1988 the licensee determined that they had made j
a mode change (Mode 5 to Mode 4) on Unit 1 on June 13 with #12 containment iodine filter unit inoperable.
Technical Specification (TS) Limiting
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Condition for Operation (LCO) 3.6.3.1 requires all three iodine filter
units to be operable in Modes 1-4.
TS 3.0.4 prohibits a mode change un-
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less the LCO's are met without relianc.e on provisions contained in action l
requirements.
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A personnel error led to a failure by the licensee to recognize that #12 iodine filter unit was inoperable.
While in Mode 5, an inspection of Amphenol type penetrations was conducted to confirm the presence of con-formal coatings.
The penetration (1ZEB6) which supplied #12 Filter unit lacked conformal coating and was declared inoperable.
Engineering per-sonnel used an uncontrolled document to determine what environmentally qualified circuits were affected by this penetration. That document was deficient and did not list #12 iodine filter.
Therefore, operations personnel were not advised of the inoperability of #12 iodine filter unit.
The safety significance of the event was low in that the containment spray was available (which scavenges iodine) and the other two filter units were operable.
The FSAR only credits two units operable during the Maximum Hypothetical Accident (Chapter 14. 24).
Personnel involved in the event were counseled.
This is considered a licensee identified violation (317/88-16-03) in ac-cordance with 10 CFR 2, Appendix C.Section V.A.
Missed Surveillance Test On July 7, 1988 the licensee realized that due to an oversight by a supervisor, a surveillance test (Auxiliary Feedwater Actuation System sentor and logic test - STP-M-225-2) on Unit 2 was missed. The test was scheduled for performance on June 17 and was required to be completed by June 30, 1988.
It was performed immediately af ter discovery of the problem on July 7.
The results were satisfactory.
This is a licensee identified violation in accordance with 10 CFR2, Appendix C, Section V.A.
15.
Unresolved Item Unresolved items require more information to determine their acceptability and such items are discussed in details 3 and 14 of this report.
16.
Exit Interview (30703)
Meetings were periodically held with senior facility management to discuss the inspection scope and findings. A summary of findings was presented to the licensee at the end of the inspectio _ _ - _ _ _ - _ _ _
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ATTACHMENT 1 LIST OF ATTENDEES Management Meeting held on August 2,-1988 at USNRC, Region I, King of Prussia, PA.
Licensee J. A. Tiernan, Vice President, Nuclear Energy L. B. Russell, Manager, Nuclear Operations C. H. Cruse, Manager, Nuclear Engineering Services R. M. Douglas, Manager, Quality Assurance & Staff Services R. E. Denton, Director-Corporate Planning, Accounting & Economics Div.
USNRC W. T. Russell, Regional Administrator W. F. Kane, Director, DRP
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J. T. Wiggins, Chief, Projects Branch 3, DRP
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l W. V. Johnston, Acting Director, ORS
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J. P. Ourr, Acting Deputy Director, DRS L. E. Tripp, Chief, Reacter Project Section 3A, DRP 0. F. Limroth, Project Engineer, RPS 3A l
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ATTACHMENT 1
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OBJECTIVES OF CCNPPD 1. CLEARLY ESTABLISH THE DEPARTMENT RESPONSIBLE FOR PLANT OPERATIONS 2. ENHANCE OPERATIONS AND
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3. ESTABLISH A MANAGEABLE DEPARTMENT 4.
AVOID CREATION OF AN ADDITIONAL
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LAYER OF SUPERVISION
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5. IMPROVE THE PERFORMANCE OF
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- Dosimetry
- Quality
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- Shif t
- ALARA Control Chemistry Operations
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- E. 'rgency
- Water
- Procedures Control Planning Treatment Development
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- Safety &
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- Ops /Maint.
Processing Fire Prot.
Labor Coord/Sched.
- Outage Coordination
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- Mechanical
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Maintenance Maintenance Planning l
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- Quality Modifications Modifications Control
- Procedures Develo ament
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- Tool / Test Equipment
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- Plant
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Chemistry Operations Maintenance Maintenance
- Water
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Treatment Development Mods Modifications
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- Plant
- Ops /Maint.
- Maintenance
- Maintenance I
Labor Coord/Sched.
Planning Planning
- Outage
- Procedures
- Procedures Coordination * Contract
- Test Admin.
Equipment
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