IR 05000333/1987005
| ML20206F479 | |
| Person / Time | |
|---|---|
| Site: | FitzPatrick  |
| Issue date: | 04/02/1987 |
| From: | Linville J, Meyer G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20206F463 | List: |
| References | |
| 50-333-87-05, 50-333-87-5, NUDOCS 8704140263 | |
| Download: ML20206F479 (11) | |
Text
-
.
U.S. NUCLEAR REGULATORY COMMISSION
REGION I
DCS Nos.
50333-032786 50333-011887 Report No.
87-05 Docket No.
50-333 License No.
DPR-59 Category C
Licensee:
Power Authority of the State of New York P.O. Box 41 Lycoming, New York 13093 Facility:
J.A. FitzPatrick Nuclear Power Plant Location:
Scriba, New York Dates:
January 31, 1987 - March 13, 1987 Inspectors:
A.J. Luptak, Senior Resident Inspector, FitzPatrick G.W. Meyer, Project Engineer, DRP 2C M
Reviewed by:
I
.
W. Meyer, ject Engineer Dhte ' ~
Approved by:
@
C. %inville fief, Reactor Dat'e Projects Se tM)n 2C, DRP
-
Inspection Summary:
Inspection on January 31,1987 - March 13,1987 (Report No. 50-333/87-05)
Areas Inspected: Routine and reactive inspection during day and backshift hours by one resident inspector and a region based inspector (117 hours0.00135 days <br />0.0325 hours <br />1.934524e-4 weeks <br />4.45185e-5 months <br />) of licensee event report review, operational safety verification, surveillance observations, maintenance observations, refueling activities, review of the program to ensure piping integrity of Steam, Feed, and Condensate Systems, and review of periodic and special reports.
Results: During this inspection no violations were identified. The failure of a previously identified suspect Safety Relief Valve (SRV) to lift within the required tolerance during lab testing was evaluated. Based on known generic problems with the SRVs, the inability to clearly determine if the valve should 8704140263 87040s gDR ADOCK 05000333 PDR
,
.
_
. _,
_.
.. _.
- _ - _ _ _ _ _ _ _ _ _ _ _ _ _
.
_
.-
-
.
-have lifted during the previous event, and the time lapse involved, it could not be clearly ' determined whether the valve was inoperable (paragraph 3).
Potential generic concerns are the failure of bolts in the High Pressure Coolant Injection Turbine (paragraph 9) and the loss of a control rod blade roller guide ball (paragraph 10).
i
4
!
-- -
.,, - -.,. - -. _ _,.,., -,... -...
.-,. - -.. _, -,,,,...,. _ - - - - - -,,,
,.
... -,.,,-.-,-
_
.
.,
-~p.
DETAILS 1.
Persons Contacted During this inspection' period, the inspector interviewed or held discussions with operators, technicians, and maintenance, contractor, engineering, administrative and supervisory personnel.
2.
Summary of Plant Activities During this inspection period, the plant has remained shutdown for refueling. The period began with the reactor vessel defueled to. support maintenance activities. Major maintenance activities conducted included removal of the recirculation loop discharge bypass lines, replacement of.
Residual Heat Removal-Reactor Water Cleanup tee connection, replacement of 6 SRM and IRM dry tubes, replacement of 18 LPRMs, and replacement of 20 Control Rod blades. On March 12, 1987, the licensee began refueling.
3.
Licensee Action on Previous Inspection Findings a.
85-05-01 (Closed) This item was unresolved pending NRR review of the licensee's submittal, which requests relief from an earlier commitment to modify the emergency control room ventilation system. The commit-q ment was made in response to NUREG-0737 Item III.3.4, but was later
'
determined not to be required; however, no formal request was submitted.
In a Safety Evaluation Report, dated February 3, 1987, NRR concluded that the emergency outside air intake damper (MOD-113) meets the single failure criteria and installation of a redundant damper is not necessary.
This item is closed.
b.
86-23-02 (Closed) Reactor Analyst Procedure (RAP) 7.1.24 " Spiral Offload /0nload Refueling", Rev. O, dated January 13, 1987, did not require any specific functional verification of unbypassing a rod block. During the spiral offload, after withdrawing the control rod, a jumper was installed in the rod position indication system for that rod, indicating that it was inserted. This position indication then
satisfied the refueling interlock for having all rods inserted. The l
inspector reviewed RAP 7.1.24, Rev. 4, dated March 10, 1987, which l
provides verification of the rod position indication system for that i
rod following removal of the jumper. After returning the rod position indication system for that rod to normal, RAP 7.1.24 now requires verification that the status light for all rods fully inserted goes
,
out and the proper position indication during rod insertion after l
returning the rod position indication for each rod to normal. This l
item is closed.
c.
85-22-01 (0 pen) During the review of a July 19, 1985 event which involved a reactor trip and Main Steam Isolation Valve isolation from full power, the inspector raised questions concerning the licensee's i
post trip review.
In particular, why the
!
(SRV) with a setpoint of 1105 psig (incorrectly given as 1090 psig i
!
-
.
4 in Inspection 85-22) failed to lift when a higher set SRV in the same steam line, the "F" SRV with setpoint of 1140 psig, did lift. The licensee's response was that a similar event occurred in January 1983, in which a higher set SRV lifted while a lower one did not. The licensee was informed by the vendor at the time that this was not uncommon due to variations between steam dome pressure and steam header pressure.
Following the January 1983 event, the licensee removed and tested these SRVs and found their setpoints within tolerance.
Following the 1985 event, the licensee committed to testing the "E" SRV during the next scheduled SRV testing.
During the current refueling outage, the licensee removed the "E" SRV for testing. One of the initial tests performed on the SRV is to check for sticking between the pilot valve disk and seat. The pilot is required to lift off of its seat when subjected to a pressure dif-ferential of 5 psig. The "E" SRV pilot failed to lift when subjected to the maximum allowed 200 psig. The testing laboratory notified the licensee, who requested that the steam test be run to check the valve lift setpoint.
During the steam test, the valve initial actuation pressure was found to be 1243 psig, 112% of the setpoint of 1105 psig.
During three subsequent tests, the valve lifted within the required
+/- 1% psig tolerance.
Although setpoint out of tolerance is relatively common and this issue has been under generic review, the possible failure of the "E" SRV to lift in July 1985 and its subsequent test failure raises a question of the operability of the SRV from July 1985 through January 1987.
The safety significance of having one SRV inoperable is very minor.
The licensee did receive a temporary license amendment in 1982 which allowed them to operate with one SRV inoperable for up to 90 days and longer with NRC approval. To support this amendment an analysis of the impact of one SRV completely failing to lift was considered and determined to result in a 15 psig increase in peak vessel pressure.
Although this analysis was performed for a d!fferent fuel cycle, review of the most recent reload analysis indicates the same logic would apply.
i During further review of some of the data retained from the July 1985 event, the inspector noted the records for SRV discharge temperature i
shows no temperature rise on the "E" SRV, however there is about a 35 degree rise on the "F" SRV. A review of the computer alarm printout conflicts with this information by indicating the acoustic detector alarmed several times for the "E" SRV during the transient, and the
"F" SRV acoustic detector alarmed only once at about twenty minutes into the transient. The inconsistencies between the acoustic monitor and temperature monitor data made it difficult to establish which SRVs opened and which did not.
The licensee did not contiuct a review of the SRV lifting until several months after the 1985 event. Hewever, this review concentrated mainly
.--
-
..
.
.
_ _ -.
-
.
on the computer alarm printout and apparently did not take into account the temperature recorder readings.
In addition, this review was not used to change the post trip review or influence the annual report of SRV failures and challenges submitted to the NRC. Based upon the confusion regarding SRV operation during this event, the licensee has committed to reanalyze the event in an attempt to resolve some of the questions concerning SRV operations and to document this review in a supplemental LER No. 87-04.
Setpoint drift of two stage Target Rock SRVs has been a generic problem for several years.
In particular the pilot valve disk-to-seat sticking is believed to be caused by corrosion. Based on the con-flicting information as to what valves actually lifted during the July 1985 event, the uncertainty of the dynamic effects involved during such an event, and the time lag since the event, the operation of the SRVs during this event has not been clearly determired at this time. The inspector will review the analysis and any planned corrective actions as documented in the supplemental LER.
This item remains open.
4.
Licensee Event Report (LER) Review The inspector reviewed LERs to verify that the details of the events were clearly reported. The inspector determined that reporting requirements had been met, the report was adequate to assess the event, the cause appeared accurate and was supported by details, corrective actions appeared appropriate to correct the cause, the form was complete, and generic applicability to other plants was not in question.
During this inspection period, the following LERs were reviewed:
LER 87-01 reported excessive leakage of a primary containment penetration found during Local Leak Rate Testing. The two valves in the penetration which provides a sample line for containment atmosphere radiation monitors were found to have leakage of 11,758 standard cubic feet per day (scfd).
The Technical Specification limit for the total of all primary containment penetrations is 3216 scfd. The LER also reports a Main Steam Isolation Valve packing leak which could have exceeded the TS limits of 11.5 standard cubic feet per hour. The licensee indicated a supplemental report would be submitted with details of the complete Local Leak Rate Testing. This LER contained only a brief abstract of the event without supplying a detailed narrative. Although this may be acceptable for some events, enough details must be given so that the reader can understand the complete event and, in particular, for this case the safety implications.
The inspector discussed with the licensee, that although a supplemental report is planned, more details should have been supplied in the initial report to address, as completely as possible, the requirements of 10 CFR 50.73.
.
-
.
.
...
.
. -.
-
-
-
--.
--
.
LER 86-08-02 is a supplemental LER detailing the corrective actions concerning the setpoint drift of pressure switches used in the Reactor Protection System.
No violations were identified.
5.
Emergency Notification System Reports The inspector reviewed the following events which were reported to the NRC via the Emergency Notification System as required by 10 CFR 50.72. The review included a determination that the reporting requirements were met, that appropriate corrective actions had been taken, and that the event had been evaluated for possible generic implications.
The following reports were reviewed:
Event Date Subject February 4, 1987 Exceeding the total allowable Technical Specification leak rate limit during Local Leak Rate Testing.
February 13, 1987 Extremity overexposure of an individual while cutting dry tubes. Details of this event are discussed in Inspection No. 50-333/87-07.
No violations were identified relating to reporting requirements.
6.
Operational Safety Verification a.
Control Room Observations Daily, the inspector verified selected ;.lant parameters and equipment availability to ensure compliance with limiting conditions for oper-ation of the plant Technical Specifications. Selected lit ar.nunciators were discussed with control room operators to verify that the reasons for them were understood and corrective action, if required, was being taken. The inspector observed shift turnovers biweekly to ensure proper control room and shift manning. The inspector directly observed the operations listed below to ensure adherence to approved procedures:
Refueling activities.
--
,
--
Issuance of RWPs and Work Request / Event / Deficiency forms.
No violations were identified.
-
.
--
.
. - - _
-
_ _.
-
-
.
b.
Shift Logs and Operating Records Selected shift logs and operating records were reviewed to obtain information on plant problems and operations, detect changes and trends in performance, detect possible conflicts with Technical Specifications or regulatory requirements, determine that records are being maintained and reviewed as required, and assess the effective-ness of the communications provided by the logs.
No violations were identified.
c.
Plant Tours During the inspection period, the inspector made observations and conducted tours of the plant. During the plant tours, the inspector conducted a visual inspection of selected piping between containment and the isolation valves for leakage or leakage paths. This included verification that manual valves were shut, capped and locked when required and that motor operated valves were not mechanically blocked.
The inspector also checked fire protection, housekeeping / cleanliness, radiation protection, and physical security conditions to ensure compliance with plant procedures and regulatory requirements.
No violations were identified.
d.
Tagout Verification The inspector verified that the following safety-related protective tagout records (PTR's) were proper by observing the positions of breakers, switches and/or valves:
PTR 870745 on the refuel bridge.
--
PTR 870658 on Emergency Diesel Generator System.
--
--
PTR 870598 on Emergency Service Water System.
--
PTR 870501 on "B" Core Spray System.
No violations were identified.
7.
Surveillance Observations The inspector observed portions of the surveillance procedures listed below to verify that the test instrumentation was properly calibrated, approved procedures were used, the work was performed by qualified per-sonnel, limiting conditions for operation were met, and the system was correctly restored following the testing.
AP-2.6, Procedure for System and Component Leak Tests, Rev. 2, dated
--
February 27, 1985, performed February 17 and March 10, 1987.
F-ST-398, Type "B" and "C" Local Leak Rate Test of Containment
--
Penetrations, Rev. 17, dated March 4, 1987, performed March 12, 1987.
_
_
.
_
.__
-
.
F-IMP-3.5, Control Rod Drive System Hydraulic Control Unit Accumu-
--
lator Instrument Testing and Calibration, Rev. 6, dated June 5, 1985, performed February 2, 1987.
F-ISP-203, Primary Containment Isolation System Main Steam Line High
--
Temperature Instrument RTD Calibration, Rev. O, dated February 12, 1987, performed March 4, 1987.
--
TOP-83, Special RCIC M0V Cycling, Rev. O, dated March 10, 1987',
performed March 11, 1987.
During the Type C Testing of solenoid operated valves 27-135A & 27-1358 in accordance with F-ST-398, the inspector noted that the posted Operator Aids (P&ID drawings) in the vicinity of the gaseous sampling equipment were not all the correct revision. Specifically, Operator Aids 191 and 193 were both drawing FM-18A but were Revisions 6 and 7, respectively.
An equipment operator removed the out of date drawing revision. Also, the inspector noted that these two drawings were located within ten feet of each other.
In discussions with the Operations Superintendent, the in-spector noted that although the Operator Aids are a useful help to oper-ating personnel, the use of more drawings than necessary may cause a a needless document control burden. The licensee agreed to review this aspect. Based on routine review of Operator Aids within the plant, this out of date drawing appeared to be an isolated case. The inspector had no further questions.
8.
Maintenance Observations a.
The inspector observed portions of various safety-related maintenance activities to determine that redundant components were operable, that
~
these activities did not violate the limiting conditions for oper-ation, that required administrative approvals and tagouts were obtained prior to initiating the work, that approved procedures were used or the activity was within the " skills of the trade," that appropriate radiological controls were properly implemented, that ignition / fire prevention controls were properly implemented, and that equipment was properly tested prior to returning it to service, b.
During this inspection period, the following activities were observed:
--
WR 02/52084, cut and cap recirculation loop discharge bypass line, modification F1-78-34.
'
--
WR 00/46178, installation of modification F1-85-92, upgrade of containment isolation system.
--
WR 02/50989, perform ISI invessel inspection.
l WR 14/50974, installation of weld overlays on Core Spray System.
--
l
[
t
_
+
.
PMWR 93/3637, preventive maintenance on the "A" Diesel Engine
--
and auxiliaries.
--
WR 02/52545, refueling of reactor core.
PMWR 03/3771, rebuild of Hydraulic Control Unit pilot valves.
--
c.
During review of the fit-up checks, in accordance with WR 14/50974, on the automatic welding machine to be used on a U bend section of Core Spray piping, the inspector noted that clamping device had sharp corners, which contacted the piping mockup and resulted in gouges.
In response to the inspector's concerns, these corners were rounded by filing.
Further, Quality Control stated that the Core Spray piping would be dye penetrant tested following the welding to ensure no piping surface problems resulted. The inspector had no further questions.
No violations were identified.
9.
Bolt Failures on High Pressure Coolant Injection Turbine During a routine overhaul / inspection of the High Pressure Coolant Injection Turbine, the licensee found 6 of the 8 bolts which connect the halves of the lifting beam for the throttle valves to be broken. The remaining 2 bolts were found to be cracked.
The lifting beam holds the valves in place.
Failure of the remaining bolts would have made the HPCI system inoperable. When these bolts were last inspected in 1979 five of the bolts were broken; however, the documentation is unclear whether they were found broken or broken on disassembly.
The bolts will be analyzed to determine failure mode and composition.
The beam has been reassembled with the specified bolts. The licensee is continuing to investigate the failures and plans to inspect the bolts during the next refueling outage.
The inspector will review the results of licensee's investigation into the
.
failure of the bolts during a subsequent inspection following the sub-mittal of the LER.
10. Missing Control Rod Blade Roller Guide Ball During the replacement of control rod blades, the licensee discovered that one of the four upper roller guide balls was missing from the control rod blade which was removed from control rod 14-19. The discovcry was mada after the installation of the new blade for control rod 14-19 and several other new control rod blades.
The ball is highly radioactive and esti-mated to contain as much as 1000 curies of cobalt-60. The ball is about
!
one-half inch in diameter with a hole drilled through the center for the pin about which it rotates.
Video examination of the blade and the fuel assemblies which surrounded the blade provided indications that the ball most likely broke into pieces before falling out.
This conclusion is based on the amount of pin remaining which held the ball in place. A small section of the pin is missing and there is evidence of thinning of the pin towards the middle, however the remaining pieces of the pin are still attached to each wall of the blade, and there was no bending of the
-
.
.-
-
-
.
_
-
-
-
.
.
_
_
-
,
pin.
In addition, scrapes and scratches seen on the fuel assemblies and the blade are believed to be caused by pieces of the ball as it was trapped between the blade and the fuel assembly.
The licensee conducted a review of possible locations of the ball.
Discussion with the vendor also revealed an event at a foreign BWR where a roller ball had fallen out and was found in the control rod guide tube.
The licensee conducted a search for the ball in the control rod guide tube, the fuel support piece, and the entire core plate. The licensee's plan to search adjacent guide tubes was stopped after problems occurred with the tools for handling control rod blades. However, the possibility of ball fragments getting into adjacent guide tubes is highly remote. The licensee examination found no evidence of the ball or any fragments. A vendor review is being performed to analyze the consequences of not finding the missing parts.
The major concern to the licensee is the potential radiological hazard
"
involved with the lost ball. Surveys conducted in the drywell and reactor cavity area did not indicate any abnormal radiation increase. A review conducted by the licensee raised several concerns about where the ball fragments may later show up during maintenance activities. These included control rod drive mechanisms, Local Power Range Monitor replacement and throughout other systems. The licensee has taken some action such as installing portable area radiation monitors and is considering others,
- such as remotely operated flush fittings during LPRM replacement and tagging of control rod drive mechanisms to indicate the potential hazards.
No violations were identified.
11. Program to Ensure Piping Integrity of Steam, Feed and Condensate Systems, Region I Temporary Inspection Instruction 87-02 The inspector reviewed the licensee's program and efforts to examine steam, feedwater, and condensate systems piping for evidence of pipe wall thinning.
Discussion with the licensee and a review of associated records revealed that the licensee began a program in 1984 to inspect extraction steam piping for evidence of pipe wall thinning. During this period, the licensee considered only extraction steam lines and inspected areas of high moisture content and high velocity.
They examined areas based on geometry, concentrating on elbows and "T" connections. Of the approxi-mately 15 areas examined on several elbows and "T" connections no thinning problems were found.
The next inspection was conducted during the fall of 1986 when licensee examined about 30 areas again on several elbows and "T" connections of extraction steam lines. Two small areas measuring several inches in diameter were found where thinning had occurred. One area was on a "T" connection and another on an end cap of the steam header. The wall thickness on these areas had been reduced from a nominal.75 inches to about.22 inches. An engineering evaluation was conducted and a weld overlay was applied over the affected areas.
_ __
_
.. _.,.
_
_
__
.-_. - _..
_ _. _ _
___
-..
.
Following the Surry event the licensee has expanded their program to include feedwater and feedwater heater drain systems.
During the current refueling outage, the licensee is examining; feedwater inlet and outlet lines, a cross connect line between feedwater heaters, feedwater drain lines, extraction steam lines, and reinspection of lines where previous problems were noted above.
With respect to the inspection required by Region I Temporary Inspection Instruction 87-02, the review of the licensee's program for ensuring the integrity of steam, feed and condensate systems is complete.
No violations were identified.
12.
Review of Periodic and Special Reports Upon receipt, the inspector reviewed periodic and special reports. The review included the following: inclusion of information required by the NRC; test results and/or supporting information consistent with design
predictions and performance specifications; planned corrective action for resolution of problems, and reportability and validity of report information. The following periodic reports were reviewed:
--
January 1987 Operating Status Report, dated February 10, 1987.
February 1987 Operating Status Report, dated March 9, 1987.
--
No unacceptable conditions were noted.
13. Exit Interview At periodic intervals during the course of this inspection, meetings were held with senior facility management to discuss inspection scope and findings. On March 13, 1987, the inspector met with licensee representa-tives and summarized the scope and findings of-the inspection as they are described in this report.
Based on the NRC Region I review of this report and discussions held with licensee representatives during the exit meeting, it was determined that this report does not contain information subject to 10 CFR 2.790 restrictions.