IR 05000247/1987001
| ML20212J460 | |
| Person / Time | |
|---|---|
| Site: | Indian Point  |
| Issue date: | 02/26/1987 |
| From: | Norrholm L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20212J368 | List: |
| References | |
| 50-247-87-01, 50-247-87-1, NUDOCS 8703090031 | |
| Download: ML20212J460 (11) | |
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m U.S. NUCLEAR REGULATORY COMMI'SSION
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DCS 50247-860121 860128
REGION I
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Report No.
50-247/87-01 Docket No.
50-247 License No.
DPR-26 Licensee:
Consolidated Edison Company of New York, Inc.
4 Irving Place New York, New York 10003 Facility Name:
Indian Point Nuclear Generating Station, Unit 2 Inspection at:
Buchanan, New York Inspection conducted:
January 6, 1987 - February 2, 1987 Inspectors:
L. Rossbach, Senior Resident Inspector P. Kelley, Resident Inspector R. Summers, Pr ect Engineer
' Approved by:
k h
d Leif yorf' holm, Chief dat'e Reactor Projects Section 28, DRP Inspection Summary:
Inspection on January 6,1987 - February 2,1987 (Report No. 50-247/87-01)
Areas Inspected: This inspection report includes routine daily inspections, as well as unscheduled backshift inspections of onsite activities, and includes the following areas:
licensee actions on previously identified inspection findings; operations; maintenance; surveillance, review of periodic and special reports; licensee event report followup; 50.59 reviews, and outage activities. The inspection involved 147 hours0.0017 days <br />0.0408 hours <br />2.430556e-4 weeks <br />5.59335e-5 months <br /> by the resident and project inspectors.
Results:
A post maintenance (modification) test was not performed after changing the location of the Emergency Diesel Generator's Service Water (SW)
flow indication and control instruments. This is a violation (Section 3.3).
An Unusual Event was declared and plant shutdown commenced due to the licensee not knowing the position of Flow Control Valve (FCV) 1176 in the EDG SW discharge piping (Section 3.3).
A plant shutdown was commenced due to the licensee declaring one battery inoperable for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (Section 3.4).
The licensee entered a one week outage for electrical generator inspection and other minor repairs (Section 3.5).
8703090031 870302
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PDR ADOCK 05000247 G
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DETAILS 1.
Persons Contacted
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Within this report period, interviews and discussions were conducted with members of.the licensee management and staff to obtain the necessary information pertinent to the subjects being inspected.
2.
Licensee Actions on Previously Identified Inspection Findings (Closed) Inspector Follow Item (IFI 247/85-10-03) Rod B-6 dropped for the third time. As a result of this event, the licensee had Westinghouse perform diagnostic checks of the rod control for B-6.
Also, during the last refueling outage, Westinghouse completed their preventive maintenance program on the rod control system power and logic cabinets.
No causes were determined for the rod drops.
In December, 1986, Rod B-6 dropped 22 steps. The licensee now plans to replace the control rod drive coil stacks on rods B-6 and E-9 during the next refueling outage, and to have Westinghouse again perform their control rod drive system preventive maintenance program. While shutting down the plant on January 30, 1987, rod H-14, in the shutdown banks, dropped.
The problem was traced to a bad connector, which was then repaired. This rod is one of about thirty which have not had the original connector replaced with a newer model. The licensee plans to replace all of the remaining old style connectors during the next refueling outage.
The inspector considers this item closed.
3.
Operational Safety Verification 3.1 The inspectors conducted routine entries into the protected area of the plant, including the control room and auxiliary building.
During the inspection activities, discussions were held with operators, technicians (HP & I&C), mechanics, foremen, supervisors, and plant management. The purpose of the inspection was to affirm the licensee's commitments and compliance with 10 CFR, Technical Specifications, and Administrative Procedures.
3.1.1 On a daily basis, particular attention was directed in the following areas:
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- Instrumentation and recorder traces for abnormalities;
- Adherence to LC0's directly observable from the control room;
- Proper control room and shift manning and access control;
- Verification of the status of control room annunciators that are in alarm;
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- Proper use of procedures;
- Review of logs to obtain plant conditions; and,
- Verification of surveillance testing for timely completion.
3.1.2 On a biweekly basis, the inspectors:
- Verified the correct application of a tagout to a safety-related system;
- Observed a shift turnover;
- Reviewed the sampling program including the liquid and gaseous effluents;
- Verified that radiation protection and controls were properly established;
- Verified that the physical ' security plan was being implemented; and,
- Reviewed licensee-identified problem areas.
3.1.3 In completing the above inspections, the inspectors reviewed the following documents:
- Selected Operators' Logs
- Senior Watch Supervisors (SW) Log
- Jumper Log
- Radioactive Waste Release Permits (liquid & gaseous)
-. Selected Radiation Work Permits (RWPs)
- Selected Chemistry Logs
- Selected Tagouts 3.2 PRA Based System Walkdowns
'As discussed in Inspection Report 247/86-25, the inspectors are using probabilistic risk assessment (PRA) based inspection guidance in per-forming system walkdowns. This guidance helps to focus NRC inspection resources toward risk significant items.
During this inspection period, walkdowns were performed on the auxiliary feedwater and component cooling water systems. The systems were found
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to be properly lined up and operable.
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3.3 Operational Events
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At the beginning of the inspection period, the unit was operating at
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99% power. The unit was limited by electrical generator end turns j
vibration as discussed in inspection report 50-247/86-32.
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On January 21, 1987, at 10:30 a.m., the licensee received information that the position of Flow Control Valve (FCV) 1176 could not be deter-mined and was possibly shut.
FCV 1176 and FCV 1176A are air-operated, 6 inch butterfly valves located, in parallel, in the Emergency Diesel Generator (EDG) Service Water (SW) piping. The valves are in the common SW discharge header for all three EDG's.
Downstream of the valves leads directly to the discharge canal.
The information the licensee received came from calculations based on SW pump discharge pressures and the EDG's lube oil heat exchanger differential pressure (d/p) and jacket water heat exchanger d/p.
Based on the calculations, assuming 20% heat exchanger fouling, the licensee expected a flowrate in the common SW discharge header of approximately 1600 gpm.
Upstream of FCV 1176 and FCV 1176A, there are two flow instruments.
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The instruments are DPC 1134S and FIC 1176. Both instruments are differential pressure devices which work off a common set of elbow taps at a bend in the SW piping.
FIC 1176 is designed to maintain 1200 gpm through the discharge piping so adequate cooling of the EDG's is maintained. FIC 1176 would automatically adjust the positions of FCV 1176 and FCV 1176A. DPC 1134S has a mechanical gage attached to it so SW flow could be monitored locally.
DPC 1134S also has an alarm function when the SW flow decreases below 1000 gpm through the EDG SW piping. The alarm annuciates in the EDG building and a common alarm annunciates in.the Central Control Room (CCR).
Both instruments are located in the EDG building.
Early in January, 1987, the low SW alarm annunciated and could not be cleared.
Previously, the. alarm would annunciate occasionally and the operators were able to clear and reset the alarm. The licensee's engineering group investigated the situation and noticed that the
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calculated flow rate, as mentioned above, was greater than the flow
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measured by DPC-1134S. The flow, as measured by DPC 1134S was l
approximately 950 gpm and the calculated flow rate was approximately 1600 gpm.
The licensee's engineers felt that there may be an obstruction in the SW piping which is restricting the flow rate. The licensee decided to
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j perform radiography of FCV 1176 and FCV 1176A to determine their actual positions instead of relying solely on the external valve position
indications.
Since July,1985, both FCV 1176 and FCV 1176A have been
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intentionally placed in the full open (failed) position, due to FIC
1176 not controlling FCV 1176 and FCV 1176A to maintain a SW flow of 1200 gpm. The licensee applied a jumper, J-2-733, by isolating the air leading to FCV 1176 and FCV 1176A which causes the valves to fail open. During a safety injection signal, high EDG lube oil temperature, or high EDG jacket water temperature, both valves are designed to fail
to the full open position.
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The radiography was performed on January 20,.1987 and the results received on January 21, 1987 indicated that FCV 1176A was open,
but the position of FCV 1176 was inconclusive. The licensee received
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this information at approximately 10:30 a.m. on January 21 and declared-all three EDG's inoperable.
Due to declaring three inoperable EDG's, the licensee entered Technical Specification 3.0.1, which requires the plant to be in hot shutdown within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> and be in cold shutdown within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.
The unit was operating at approximately 97% power.
The licensee also declared an Unusual Event at 10:30 a.m. per their emergency plan, due to possible loss of onsite A/C power. The licensee -
began to reduce power.
The licensee decided to stroke FCV 1176 and FCV 1176A and observe the DPC 1134S flow gage to determine the valve positions. When only one valve was stroked closed, no indication of decreased flow could be-observed on DPC 1134S. When both valves were stroked closed, a definite decrease in flow was observed. When these valves are in the shut position, they are actually 30 degrees open. Stroking only one valve at a time does not vary the flow enough to indicate on the flow gage.
With this information, the licensee declared that FCV 1176 was actually open. The licensee also decided to radiograph the valves again.
At 1:45 p.m., the licensee terminated the Unusual Event and the plant shutdown, based on the above test. The plant was then operating at 60% power.
A Station Nuclear Safety Committee (SNSC) meeting was held to discuss the events and resolution of the valve problem.
The SNSC agreed the valve was open at all times and, as a SNSC action item, the flow indication system would be reviewed.
During the SNSC meeting, the history of FIC 1176 and DPC 1134S was discussed. Prior to the 1986 refueling outage, the two instruments were located at the high point of the EDG discharge SW piping. Once the SW exits the EDG jacket water heat exchanger, it is under vacuum conditions.
Prior to 1986, it was believed that air in-leakage, due to their location, into the instruments was causing erroneous indi-cations and control of the valves. During the 1986 refueling outage, a modification was performed to relocate the instruments below the high point of the EDG SW discharge piping.
The modification, MFI-85-20836-02, was installed via work order NP-85-24711.
Upon investigation, it was determined that after the modifi-cation was completed, a post maintenance (modification) test (PMT) was not performed. A PMT was issued on April 29, 1986, which included a hydrostatic test of the installed indication and controls system, a normal operating pressure test of the elbow taps up to the first instrument isolation valves, and calibraticn of the instruments and setpoints. This is an apparent violation of Technical Specification 6.8.1.a. (50-247/87-01-01)
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During the relocating process, FIC 1176 was installed, with its-high pressure. tap connected to the low pressure-sensing 1ine and vice-versa.
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The inspector believes this: situation would have been discovered during.
the PMT.- Since the FCV's are currently failed open, the instrument is not being used to control flow.
Due' to the questioning of the accuracy of DPC.1134S to. mea'sure flow through the EDG SW header, the licensee has. installed pressure gages-upstream and downstream of.the EDG heat exchangers. With these gages, the heat exchanger differential pressure can be determined.
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The licensee will use this data, instea'd of relying solely on DPC 1134S,
'to determine adequate flow through the EDG. PT-DI, Daily.EDG Test, has been changed to ~ reflect the use.of heat _ exchanger differential pressure data. The licensee _is continuing to review the actions that could be~
taken to improve the control and indication of the system.
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3.4 Inoperable Batten -
On January 28, 1987 at 10:00 a.m., a Region I' inspector.was witnessing the quarterly battery surveillance test and noticed the temperature in
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the battery rooms was cold and the electrolyte temperature in battery #21 was 54 degrees F.
Upon reviewing the test; procedure, the inspector determi_ned there were no temperature limitations for the electrolyte.
The electrolyte temperature was taken only.for specific gravity adjust-ments. The battery vendor manual indicated that with a temperature of 54 degrees F, the battery's capacity decreases, compared to a standard of 77 degrees F.
The inspector questioned whether the-batteries could meet their 2-hour design amperage basis. The licensee energized heaters
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in the vicinity of.the battery rooms and sealed off the outside air that was entering the rooms. The licensee then calculated that the lower temperature limit for battery #21 is 65 degrees F.
This cal--
culation was verified at approximately 4:20 p.m. on January 29, 1987.
Per the Technical Specifications, one battery is allowed to be inoperable
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for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Since the 24-hour time period was exceeded, the licensee entered Technical Specification 3.0.1, which requires the plant to be in hot shutdown in 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />. The licensee commenced reducing power from 96% at 4:20 p.m. on January 29, 1987.
Due to heating the rooms and discharging of the battery, at 9:45 p.m.
on January 29, 1987, the licensee measured the electrolyte temperature at greater than 66 degrees F and performed voltage measurements on the j
battery. Battery #21 was declared operable and the-plant shutdown was
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terminated at 49% power. The plant then returned to 97% power. The i
licensee is continuing to evaluate the lower limits for battery tem-
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perature. They believe their initial calculation was overconservative.
The inspectors reviewed monthly battery surveillance test data (PT-M22)
for the last three winters.
In general, battery temperatures did not fall below 69 degrees F.
One test detected battery temperatures below the. current limits. This occurred in March, 1984, when battery 21 was 62 degrees F.
Regional inspection report (50-247/87-02) has additional information concerning the batteries.
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3.5 Plant Shutdown for Planned Outage Due to the problem of the electrical generator end turn vibration limiting electrical output, the licensee shut down the unit on January 30, 1987 for a planned one week outage.
The outage started one day earlier than expected, since tha licensee did not want to perform surveillance test PT-M14A, Reactor Protection Logic Test. January 30 was the last day PT-M14A could be performed before exceeding the 25%
time limit allowed per Technical Specifications. The licensee felt that performing the test at power could result in a reactor trip, since only one rod drive motor generator set was operating. On January 23, 1987, while installing fuses in reactor trip bypass breaker "B", in preparaticn for PT-M14A, rod drive motor generator set #21 tripped.
During the shutdown, when the plant was sub-critical, rod H-14 dropped, due to a loose connector. Also, during the shutdown, the main steam isolation valves (MSIV) for steam generators #21 and #24 would not close automatically.
The valves had to be manually assisted closed. The MSIV's have been recently repacked with new packing. The licensee lubricated the valves and stroked them satisfactorily. The licensee is reviewing the frequency of the lubrication preventive maintenance.
4.
Maintenance The inspector observed maintenance in progress and reviewed completed and ongoing work packages. The inspector verified that proper administrative approval was received, equipment was properly tagged out, prpcedures used
.were adequate, proper radiological precautions were taken, QA/QC hold-points were established and observed, and equipment was properly tested before returning to service.
The following maintenance items were observed or reviewed:
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87-30350, Repair Electric Heat Trace Circuit #54 on Boric Acid
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System. Heat tracing was repaired and PT-Q7, Boric Acid Heat Trace repair test performed satisfactorily.
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86-27952, Repair Packing Leak on Containment Spray Valve 5253
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87-30348, Repair Packing Leak on Containment Spray Valve 4251. Both valves had packing leaks repaired and manual valve stroke performed satisfactorily.
86-27941, Repair Leaking Containment Spray Fitting on 21 Containment
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Spray Pump.
Fitting was replaced and PT-Q35, Containment Spray Pump Functional Test was performed as post-repair test satisfactorily.
No violations were identified.
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Surveillanc'e The inspector observed surveillance tests in progress and reviewed.
-completed surveillance' tests. The inspector' verified the test results satisfied Technical Specification requirements, proper administrative
. approval was received, procedures were adequate, and systems were-properly restored at~ the end of the test.
PT-M148,'Sa'fety-Injection System Logic Test, Revision 12,' performed
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January 20, 1987.
PT-M51,. Radiation Monitor Check, Revision 4, performed January 20,
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1987.
PT-Q27, Motor-Driven Auxiliary Boiler Feedwater Pump (ABFP)
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Functional Check performed January 20, 1987. This test was performed satisfactorily. Upon the inspector performing a visual valve lineup of _the Auxiliary Feed Water (AFW) system on January 21, 1987,.it was noted that BFD-53, ABFP #21 recirculation stop valve, was open, but not locked. This valve.is required to beslocked:open.
The licensee.immediately locked open the valve.
The licensee has stated that PT-Q27 will be changed.in order to maintain better control of the positioning and-position verification of valves.
No violations were identified.
6.
Review of Periodic and Special Reports The Monthly Report for December, 1986 was reviewed. The review included an examination of significant occurrence reports to ascertain that the summary of operating experience was properly documented.
The report was also reviewed to determine that it included the information required by.
Technical Specification 6.9.1.7 & 8.
The inspector has no further questions relating to the report.
No violations were identified.
7.
LER Followup
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l The inspector reviewed the following LER's to determine that reportability
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requirements were fulfilled, immediate corrective action was taken, and corrective action to prevent recurrence had been accomplished.
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85-08
" Late Surveillance Test" - During the performance of PT-BW-1, Biweekly Rod Exercise Test, an August 21, 1985 control rod M-4 dropped.
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Due to the preoccupation of the operators with the transients following the dropped rod, the Technical Specification required daily heat balance
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was missed.
The heat balance was performed on August 22, 1985
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satisfactoril O a
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85-09 - " Reactor-Trip; Output Transformer Short"- On October 20, 1985, the reactor tripped due to a turbine generator trip. The turbine genera-tor tripped because of a phase-to phase fault in #21 main transformer.
The-fault was caused by salt water spray emanating from a condenser water box lifting jet exhaust near.the transformer.
The lifting jet piping has been subsequently redirected.
85-11
" Hurricane Gloria" - Per Technical Specifications, when hurricane Gloria approached the site'on September 27, 1985, the plant was placed in hot shutdown. Hurricane force winds were not felt on site.
85-12
" Reactor Trip-Low Power Range /High Flux" - On September 28, 1985, the reactor tripped during startup, due to the operator's failure to block the power range-high flux-low level trip set.at-25% power. The event was reviewed with the' Operations staff to prevent recurrence.
86-04
" Pressurizer Safety Valves Outside Range For Setpoint Pressure" -
During the 1986 refueling outage, all.three pressurizer safety valves were found set below the required lift setpoints permitted by Technical Specifications.
The valves were~ repaired and tested satisfactorily. The valves are Crosby HB-86-BPE.
86-12 - " Plant Vent Gas Releases ~Without Completion of Surveillance-Test for Monitor R-14" - During the period between March 3-17,1986, releases were made from the Large Gas Decay Tanks. A monthly source check is required to be performed of the plant vent noble. gas activity monitor, R-14, per Technical Specifications. During the performance of the test in February,1986, certain steps in the procedure were marked "N/A" when they should not have been. The releases, therefore, occurred without an operable monitor and the required sampling of the tanks was not performed when the monitor is operable. All test procedures have been revised prohibiting technicians from using "N/A".
86-17
" Reactor Trip Due to Steam Dump Valves Opening" - On May 28,
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l 1986, the steam dump valves suddenly opened creating a high steam flow condition coincident with a low reactor coolant system average temperature. This condition caused a safety injection (SI) and a reactor trip.
SI Train A actuated, but Train B did not. Train B was actuated
l-later during the recovery precedure. The cause of the steam dumps opening l
was suspected to be failed capacitors. All the capacitors were replaced I
on the steam dump controller and the controller and transmitter were
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recalibrated. The cause of failure of SI Train B was suspected to be dirt or foreign material in the relays.
Four relays were replaced and satts-
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l factorily tested.
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No violations were identified.
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8.
Region I Temporary Instruction RI-87-01, Control Room Environment
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The objective of this instruction is to ensure that a satisfactory environment exists in the control room, so that conduct of duty by
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Th'e inspection was performed during this inspection period and will be reinspected within the last quarter of the Systematic Assessment of Licensee's Performance (SALP) period, or as necessary.
The following aspects were inspected:
- Licensed Operator Professionalism,
- Noise Control,
- Control Room Access,
- Control Room Appearance, The inspectors identified no concerns with the overall control room environment.
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Region I Temporary Instruction RI 87-02 - Steam, Feed and Condensate System Surveys The objective of this instruction is to determine what actions Region I PWR and BWR licensees may have taken as a result of the Surry Power Station feedwater line break.
Consolidated Edison does have a program underway to inspect various portions of its feedwater piping. As of February 2,1987, four locations were ultrasonically inspected with satisfactory results. The results indicate thicknesses greater than the minimum required and most were greater than nominal. A total of 14 locations will be inspected. The locations were selected using the criteria mentioned in EPRI, Report NP-3944, " Corrosion / Erosion in Nuclear Plant Steam Piping."
10. Temporary Repair Management Controls During a previous NRC inspection (50-247/86-27) a temporary repair to an infeed breaker to an onsite 480 volt, vital bus was identified. This matter was reviewed at that time and it was noted that the repair did not require a formal evaluation per 10 CFR 50.59 based on management and SNSC review and approval of the repair procedure. This inspection was conducted to review the licensee's controls over such repairs to determine if the licensee appropriately applies 10 CFR 50.59.
The licensee has formally established a control program to implement review and approval of temporary repairs.
The controls require an assessment of whether 10 CFR 50.59 applies to the repair. This assessment is conducted by the Manager, Technical Support.
If it appears that the repair method requires a formal evaluation, then engineering support is required to conduct the evaluation. All temporary repair procedures, including any safety evaluation when required, are reviewed by the Station Nuclear Safety Committee prior to implementatio f-
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The inspector selected eight recent (1986) temporary repairs to determine if: the licensee followed the approved procedures; implementation documentation supported the work completed and the approved work procedure; the permanent repair method is being tracked and/or if the temporary repair was subsequently accepted by engineering as a permanent repair, that it was formally documented as a design change; and reviewed selected SNSC meeting minutes to determine that an unreviewed safety question determination was made.
Of the selected temporary repairs, the inspectors determined that the licensee's procedures had been implemented properly for both the 10 CFR 50.59 applicability review and the formal safety evaluations, when conducted.
The inspector identified a concern to the licensee about the auditability of the 10 CFR 50.59 applicability reviews, since it consists of a simple yes/no checkoff. The licensee had already noted this concern and is in the process of formalizing all 10 CFR 50.59 determinations, i.e. modification, temporary repairs, jumpers and lifted leads, etc. to assure that a consistent, auditable, check list of appropriate questions are answered for each such review.
The inspector also reviewed the temporary repair documentation for the 480 volt switchgear (reference NRC report 50-247/86-27). Based on this review, the licensee stated that a formal 10 CFR 50.59 evaluation would be conducted to support continued operation with this repair in place. The inspector will review this safety evaluation in a future inspection. This item remains unresolved.
(50-247/86-27-02)
11.
Exit Interview At periodic intervals during the course of the inspection, meetings were held with senior facility management to discuss the inspection scope and
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findings. An exit interview was held with licensee management at the end of the reporting period. The licensee did not identify any 2.790 material.
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