IR 05000219/1986004
| ML20202F157 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 04/04/1986 |
| From: | Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20202F105 | List: |
| References | |
| 50-219-86-04, 50-219-86-4, IEB-79-02, IEB-79-2, IEB-83-01, IEB-83-02, IEB-83-04, IEB-83-05, IEB-83-1, IEB-83-2, IEB-83-3, IEB-83-4, IEB-83-5, NUDOCS 8604140116 | |
| Download: ML20202F157 (16) | |
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U. S. NUCLEAR REGULATORY COMMISSION t-
REGION I
Report No.
50-219/86-04
. Docket No.
50-219-License No.
DPR-16 Priority _
Category C Licensee:
GPU Nuclear Corporation 100 Interpace Parkway Parsippany, New Jersey
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Facility Name: Oyster Creek Nuclear Generating Station Inspection At: Forked River, New Jersey Inspection Conducted:
February 3 - March 2, 1986 Participating Inspectors:
W. H.-Bateman, Senior Resident Inspector J. F. Wechselberger, Resident Inspector W. H. Baunack, Project Engineer-Approved by: Yks$f
,a a au
<y 7m r-y n A. R. Blougff, Chief Date Reactor Projects Section 1A Inspection Summary:
Routine inspections were conducted by the resident inspectors (148 hours0.00171 days <br />0.0411 hours <br />2.44709e-4 weeks <br />5.6314e-5 months <br />) of
. activities in progress including plant operations, physical security, radiation control, housekeeping, fire protection, emergency preparedness, and instrument surveillances. The inspectors also reviewed licensee action to address IE Bulletins and open inspection items, made routine tours of the facility, re-viewed the ESW system IST program, and followed up an inquiry from the New Jersey Bureau of Radiation Protection. A Region based inspector reviewed MSIV
.related data (23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />) in preparation for writing a safety evaluation for SEP Item XV-19, Loss of Coolant Accident.
Results:
No violations were identified. One unresolved item was identified involving the~IST program for the ESW system.
Four IE Bulletins and four open inspection items were closed.
Plant operations continued without major problems. The plant. entered the end of fuel cycle coast down mode resulting in slowly decreas-
'ing power output. No concerns were identified with the quarterly emergency drill, however, seven emergency warning sirens were reported to be non-functional due to suspected weather related problems.
Licensee action to address SEP Item-XV-19 was found to be sufficient and a safety evaluation will be. written.
t204140116 860407
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PDR ADOCK 05000219
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DETAILS 1.
Review of IE Bulletins Licensee action taken to address closure of the following Bulletins was reviewed during this report period. The results of this review are described below:
IE Bulletin 79-02, Pipe Support Base Plate Designs Using Concrete
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Expansion Anchor Bolts.
An update of'a portion of this Bulletin was discussed in Inspection Report 85-29.
In particular, the inspector requested to review the inspection results of the ESW pipe hangers located in the turbine building.
Data was provided to the inspector and a review performed.
Additional followup activities resulted from'this review and were ongoing at the end of this report period.
The inspector also reviewed a preliminary revision of licensee Tech-nical Specification SP-1302-12-221, 1985 Inspection Test Program to Meet the Intent of IE Bulletin 79-02.
This specification was genera-ted to address concerns raised in Inspection Report 85-14. The anchor bolt inspection program has not commenced and is still undergoing licensee review as to the scope and schedule of inspections. The inspector discussed his comments on the specification with appropriate Tech Functions personnel.
In general the specification appeared to be technically adequate.
This Bulletin remains open pending completion of follow-up activities
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regarding ESW pipe supports in the turbine building and overall completion of the anchor bolt testing program to meet the Bulletin's original intent.
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IE Bulletin 83-01, Failure of Reactor Trip Breakers (Westinghouse D8-50) To Open on Automatic Trip Signal Oyster Creek does not use reactor trip breakers to trip the plant, therefore, this Bulletin does not apply.
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IE Bulletin 83-02, Stress Corrosion Cracking in large-Diameter Stainiers Steel Recirculation System Piping at BWR plants This Bulletin did not apply to Oyster Creek based on their commitments to addressBulletin 82-03.
IE Bulletin 83-04, Failure of the Undervoltage Trip Function of
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Reactor Trip Breakers (Same as IE Bulletin 83-01)
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IE Bulletin 83-05, ASME Nuclear Code Pumps and Spare Parts
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Manufactured by the Hayward Tyler Pump Company A licensee review of plant equipment determined that Hayward Tyler pumps are not in use at Oyster Creek.
Corporate Manufacturing As-surance is in the process of developing a list of vendors'who have been the subject of various NRC and industry notices to identify potential problems with future purchases of equipment and services.
In addition, Hayward Tyler is not presently on the GPUN approved bidders list.
Six Hayward Tyler pumps were purchased for use on the Forked River project.
Two of them were sold at auction and four remain in storage at the Forked River site. The inspector determined that site QA would be involved in the approval process of any modification that could result in the use of these pumps in a safety-related application.
Site QA has a system ~to identify potential vendor problems which would control the use of these four pumps. This Bulletin is closed.
2.
Licensee Action on Previous Inspection Findings
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[ Closed)InspectorFollow-upItem(219/81-11-05): Verify that document control package for Limitorque Operator replacements reflects work
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accomplished.
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The inspector reviewed the job package for Job Number C-92 filed under
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Index Number 20.2614.4840. The licensee stated that this documentation h
package contained all Job Orders, procedures, and supporting documentation regarding the Limitorque replacements. There was no documentation that discussed stem nut problems relating to work on V-16-1 and V-14-36.
It was clearly stated in Inspection Report 81-11, however, that V-14-36 installation was in accordance with Anchor Valve Company Drawing 2085-5, Rev. C and that V-16-1 reused the original stem nut as was permitted by a project memo dated 5/18/81. This memo was contained in the documentation package. All documentation in the package was signed off and appeared to be complete.
(Closed) Inspector Follow-up Item (219/82-29-05):
Review licensee findings and procedure revisions regarding inadvertent initiation of Containment Spray in the drywell.
The inspector reviewed the PORC and ISRG findings along with other correspondence as listed below:
Minutes of PORC meeting 45-83 held on 2/24/83
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PORC Action Item 45-83-1 to Plant Engineering
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Safety Review SROC 83-5 R
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Inter Office Memorandum from R. Baran to J. L. Sullivan dated
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12/23/82 Inter Office Memorandum from D. K. Croneberger to J. L. Sullivan
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dated 11/22/82 (E&D/0C-1211)
ISRG Review
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The results of the reviews determined certain checks of equipment, in addition to those discussed in the report, should be performed.
Plant Engineering initiated Job Orders to inspect the following equipment for water damage:
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All motor operated valve operators Electromatic Relief Valves
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Acoustic monitor system Main Steam Isolation Valves' controls
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Recirculation pump motor terminal boxes
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Drywell Equipment Drain Tank pump motors This ' inspection did not identify any damage.
Regarding procedural changes, Station Procedure 310, Containment Spray System Operation, was revised to describe the unique operations of cooling and sampling torus water. The procedure specifically states the require-ment to place the Containment Spray Mode Select switch in " DYNAMIC TEST II" position and to operate Containment Spray pump 51C when drawing a torus water sample.
(Closed) Inspector Follow-up Item (219/82-29-06): Review completed corrective actions regarding failure to properly sample during overboard discharge.
The inspector reviewed the corrective action which involved a change to
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procedure 804.5 to require the chemistry technician to sign the Liquid
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Release Permit after the second sample is taken.
Procedure 804.5 has since been deleted and incorporated into 830.4, Radwaste System: Liquid Analysis and Disposition, Rev. 2.
The requirement is contained in 830.4.
In addition, the Radioactive Liquid Waste Analysis and Release Permit, Form 830.4-1, has been modified to provide a signoff for the second sample.
There have been no recurrences of this problem.
(Closed) Inspector Follow-up Item (219/83-10-02): Review hood use procedure regarding air flow to air supplied hoods.
Procedure 915.5, Respirator Protection, was superseded by several other procedures.
Procedure 9300-ADM-4020.02, Description and Selection of Respirator Protection Equipment, now addresses the hood air flow require-ments. Attachment 1 to 9300-ADM-4020.02 requires that the flow control valve must be operated in the full open position when using a continuous flow hood / helmet with a protection factor of 2000.
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states that air flow must be greater than 6 cubic feet per minute when using this protection factor. The licensee provided vendor (MSA) informa-tion that indicated this requirement is met.
3.
Emergency Service Water-(ESW) System Inservice Test (IST) Program The licensee is committed to meet the requirements of ASME Section XI, 1974 Edition, Winter 1975 Addendum for their IST program.
Paragraph IWP-1500 of Article IWP-1000 states that the "... condition of a pump rela-tive to a previous condition can be determined by attempting to duplicate by test a set of basic reference parameters.
Deviations detected are symptoms of changes, and, depending upon the degree of deviation, indicate need for further tests or corrective action." The Code provides require-ments for IST procedures and specifies actions that shall be taken if periodic testing indicates problems.
A review of the ESW system IST data (particularly ESW System II) indicates that, based on inconsistent system stability characteristics and an inade-quate flow measuring device, the Oyster Creek IST program for the ESW system may not meet the intent of Section XI.
In particular, it appears that it may not be possible to detect gradual degradation of the ESW pumps because of the time required to run the pumps to obtain stable data (up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as indicated by some data) and the inaccuracy of the "Controlatron" sonic flow measuring device.
In discussing this concern with the licensee, it was determined-the licensee is aware of the limitation of the ESW pumps'
IST prograin and is attempting to rectify the problem.
The inability of the ESW system IST program to yield meaningful results that would identify gradual degradation of the ESW pumps (particularly in System II), is unresolved pending licensee upgrading of flow instrumenta-tion and resolution of system instability characteristics.
(219/86-04-01)
4.
Surveillance Testing The inspectors reviewed the following surveillance tests to determine if the tests were included on the Master Surveillance Schedule, were technically adequate, and were performed at the required frequency:
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604.3.001, Reactor Building to Torus Power Vacuum Breaker Test and Calibration
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609.3.002, Isolation Condenser Isolation Test and Calibration j
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619.3.C.3, Reactor Low Level Test and Calibration During performance of 619.3.013, the reactor low level scram setpoint on 2 of 4 instruments was found to have drifted out of specification in a non-conservative direction.
The January 1986 surveillance of these instruments
indicated the setpoint on 3 of 4 had drifted non-conservatively (N.C.).
This was discussed in Inspection Report 86-02. A summary of the problems with " Static 0-Ring" (SOR) low and low low reactor vater level instruments since their installation in November 1985 to meet EQ requirements follows:
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-Instrument As Found Condition Tag Number Function of Setpoint Date Remarks RE 02 C Rx Low-Low Out of Spec-1/11/86 No additional Level Nonconservative problems with (005-N.C.)
any Low-Low level instruments since.
RE 05A1 Rx Low Level 005-N.C.
1/17/86 3 of 4 found RE05/19Al Rx Low Level 005-N.C.
1/17/86 00S-N.C.
RE05/1981 Rx Low Level 00S-N.C.
1/17/86 RE 05A1 Rx Low Level Within Tolerance 1/19/86 During followup surveillance to troubleshoot instru-ments because of findings on 1/17, a half scram signal generated from this instr. that could not be cleared.
The instrument was replaced on 1/19/86.
The other 3 RE05s were found within tolerance. Proce-dure changed to eliminate " bang" test.
RE05A1 Rx Low Level 00L - N.C.
2/20/86 2 of 4 found RE05B1 Rx Low Level 005 - N.C.
2/20/86 00S - N.C.
Licensee decided to perform surveillance test on all 4 instru-ments I week hence to attempt to determine the amount of time it takes for the setpoint to drift 00S - N.C.
RE05A1 Rx Low Level 005-N.C.
2/27/86 1 of 4 found 00S-N.C.
SOR vendor witnessed surveillance and did not find problems with licensee's methods.
It was determined this par-ticular instrument had been used by'
SU&T to verify " bang" test would not harm instr. This instr.
replaced.
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The following troubleshooting activities were in progress at the end of the report period:
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Licensee has increased surveillance frequency on RE05s as follows: Reperform surveillance on 3/6/86.
If no problems re-perform on 3/24/86.
If no problems on 3/24/86, reperform 3 weeks later.
It is suspected that the " bang" test (described in Inspection Report 86-02) is the cause of the setpoint drift.
.Should problems be encountered in any of the March or April sur-veillance tests, additional actions will be taken.
Licensee is pursuing the possibility that a small amount of air
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in the instrument lines could affect the repeatability of the setpoint.
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The RE05A1 removed on 2/27/86 will be thoroughly inspected by SOR at their facilities. Discrepancies found, if any, will be investigated.
SOR Las formed an internal task force to address the setpoint
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drift problem. A similar problem has occurred at another nuclear plant but with a different type of instrument.
The inspectors will continue to follow resolution of this probl9m.
5.
Radiation Protection During entry to and exit from the RCA, the inspectors verified that proper warning signs were posted, personnel entering were wearing proper dosimetry, personnel and materials leaving were properly monitored for radioactive contamination, and monitoring instruments were functional and in calibra-tion. Posted extended Radiation Work Permits (RWPs) and survey status boards were reviewed to verify that they were current and accurate.
The inspectors observed activities in the RCA to verify that personnel com-plied with the requirements of applicable RWPs and that workers were aware of the radiological conditions in the area.
On February 1,1986, portions of the office building and the reactor build-ing became si'ghtly radioactively contaminated. The cause was determined to be an unusual HVAC lineup that resulted in discharging radioactivity to a space above the heater bay roof wherefrom the instrument lab and reactor building supply fans take their suction.
In particular, the feed pump room supply fan was shutdown to change filters. The feed pump room exhaust fan continued to run, thereby creating a negative pressure in the feed pump room and sucking in radioactive contaminants from the condenser bay.
The feed pump room exhaust fan discharges to the roof of the heater bay portion of the turbine building. During normal operation, with both the feed pump room supply and exhaust fans operating, the pressure in the feed pump room is greater than tFat in the condenser bay, thereby, precluding this situation. This infrequent lineup to change supply fan filters was in effect for approximately 4h hours.
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The contamination was initially detected when an individual leaving the plant alarmed the portal monitor at the main guard house. Shortly after this, another individual alarmed the PCM-1 frisker at the office building
health physics control point.
Both individuals were traced back to the instrument lab. Health physics personnel performed surveys in and around l
the instrument laboratory using a RM-14 frisker and detected 250-300' cpm.
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Gross swipes were taken in various locations in the office building and slight activity was detected in the hallway outside the control room.
(No activity was detected inside the control room.) Air samples were also
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taken with results indicating no detectable levels except one sample in the hallway between the instrument shop and the control room.
This sample indicated a total MPC fraction of.008.
This contamination rapidly dissipated following restoration of the feed pump room supply fan.
The licensee is evaluating corrective action to preclude this situation from occurring in the future. The inspectors will follow-up the corrective action. (219/86-04-04)
6.
Observation of Physical Security During daily tours, the inspectors verified access controls were in accordance with the Security Plan, security posts were properly manned, protected area gates were locked or guarded, and isolation zones we'
free of obstructions. The inspectors examined vital area access points
verify that they were properly locked or guarded and that access control was in accordance with the Security Plan.
No concerns were identified.
7.
Follow-up of Concern Regarding Radioactive Contamination of Water Under the Turbine Building Basement Floor Slab During a tour of the plant, it was brought to the NRC inspectors' atten-tion that a portion of the floor slab under the Turbine Building Closed Cooling Water (TBCCW) system heat exchangers was removed and that the stagnant pool of water that formed in the space left by the removal of the slab had been found in the past to be slightly radioactive.
Investigation into the construction of the turbine building indicated that the turbine building basement floor is a nominal 6" thick slab of concrete on top of 3' deep compacted sand which, in turn, is supported by the turbine build-ing basemat. A french drain was employed between the sand and basemats to provide drainage during construction. The french drain emptied into the 1-5 sump in the south west corner of the turbine building.
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The pooling of the slightly contaminated water caused the licensee to l
initiate an investigation to determine the source of both the water and the contamination.
The investigation involved core boring through the floor slab in selected locations and drawing a sample of water from the sand to determine the presence of contamination.
This activity took place in mid-1984 during the Cycle 10 R outage..The results were inconclusive as to the source of the radioactivity and the water.
Contamination was found to exist at four of the core boring locations. The activity level was less than the allowable value of 3 x 10 ' micro curies per milliliter for direct overboard discharge in two cases and slightly greater than this in the other two cases.
(One sample indica'.ed 2.15 x 10 * micro curies per milliliter and the other, 3.35 x 10 5 m;cro curies per milliliter.)
The licensee theorizes that the water got into the sand via the 1-5 sump and the original french drain system, i.e., a french drain system in re-verse. This appears feasible based on the elevation of the french drain at 4" above zero elevation and the maximum elevation of water in the 1-5 sump at 3'-6" elevation.
During the 10R outage, the french drain dis-charge path into the 1-5 sump was closed off.
This effectively trapped all water in the 3' thick sand layer under the floor slab.
The licensee intends to install a new sump in the floor of the HVAC ductwork area ad-jacent to the feed pump room during the 11R outage and will attempt to drain the water out of the sand. The water would then be processed through the liquid radwaste system.
The inspector questioned the licensee as to the possibility of out leakage of this contaminated water through the turbine building walls into the adjacent acquifer.
The licensee stated this would not be likely based on the fact that the elevation of the acquifer is greater than that of the sand layer inside the building, thereby, creating a differential that would tend to cause in-leakage through the turbine building walls. The level of the stagnant pool of water under the TBCCW heat exchangers has not appeared to have changed since the french drain was closed off, thus, indicating there is no passage of water through the turbine building walls in either direction.
The inspectors' review of this matter did not identify any concerns.
Subsequent to the inspectors' review of this matter, correspondence re-ceived from the New Jersey Bureau of Radiation Protection indicated several
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individuals who may have been in the area of the core boring operation were contaminated and were then required to sign papers binding them not to disclose information regarding the contamination.
The inspectors followed up this information but could not find any licensee records of personnel contamination associated with the core boring work activity.
Additionally, the forms used by the licensee to record contamination p,roblems were reviewed and found not to contain any questions or required signatures that require or appear to imply nondisclosure of facts surrounding contamination event *
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8.
Emergency Preparedness A quarterly emergency drill was performed during this report period. The inspectors observed licensee actions in the control room, the technical support center, and the operations support center. No problems were identified.
Seven emergency alert sirens were reported non-functional due to weather-related problems. They were subsequently repaired and all 47 sirens were inspected to ensure operability. A similar problem occurred last winter to several sirens. The manufacturer has stated that the sirens should not degrade under any weather conditions.
The licensee's Tech Functions Division is evaluating the problem. The inspectors will follow up licensee action in a subsequent inspection.
(219/86-04-02)
9.
Plant Operation Review 9.1 Routine tours of the control room were conducted by the inspectors
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Control Room and Group Shift Supervisor's Logs;
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Technical Specification Log; Control Room and Shift Supervisor's Turnover Check Lists;
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Reactor Building and Turbine Building Tour Sheets;
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~ Equipment Control Logs;
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Standing Orders; and,
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Operational Memos and Directives.
The inspectors noted from a review of the Control Room Log that during performance of the Containment Spray and ESW IST, the "52B" ESW pump differential pressure exceeded the action limits and that the pump was not declared inoperable. Paragraph 7.2 of Station Procedure 607.4.003, Containment Spray and Emergency Service Pump Inservice Test, Rev. 10, requires that an ESW pump be declared inoperable when monitored parameters, such as pump differential pressure, exceed action limits. The inspectors questioned the decision not to declare the pump inoperable and were informed that the operators elected not to believe the instrumentation used to measure pump differential pressure because other indications of pump performance were normal.
A calibration check was performed on the instrument and it was found to be in need of recalibration.
Subsequent to recalibration of the gauge, the IST of "52B" was reperformed and the pump found operable.
Had the "52B" pump been declared inoperable, Tech Specs would have required demonstrating operability of the "52A" pump. This had been
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o done just previous to testing the "528" pump. The inspectors express-ed their concern to the licensee that the decision not to believe the instrumentation was incorrect and that the pump should have been de-clared inoperable until the instrument problem was resolved.
Licensee management agreed with the inspectors and intend to clarify to all operations personnel the importance of believing instrumentation.
9.2 Routine tours of the facility were conducted by the inspectors to make an assessment of the equipment conditions, safety, and adherence to operating procedures and regulatory requirements. The following areas were among those inspected:
Turbine Building;
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Vital Switchgear Rooms; Cable Spreading Room;
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Diesel Generator Building; Reactor Building; and,
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Battery Rooms.
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Fire Protection:
Randomly selected fire extinguishers and hose stations were
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accessible and inspected on schedule.
T-l Fire doors were unobstructed and in their proper position.
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in accordance with the licensee's approved procedures.
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Appropriate fire watches or fire patrols were stationed
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w1en equipment was out of service.
Fire retardant wood was used for scaffolding.
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Equipment Control:
l Jumper and equipment mark-ups did not conflict with
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Technical Specification requirements.
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Conditions requiring the use of jumpers received prompt
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Administrataive controls for the use of jumpers and l
equipment mark-up were properly implemented.
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Breakers for electrical equipment being worked were
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properly tagged out.
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Vital Instrumentation:
Selected instruments appeared functional and demonstrated
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parameters within Technical Specification Limiting.
Conditions for Operation.
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Housekeeping:
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Plant housekeeping and cleanliness were in accordance with
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approved licensee programs.
I Close observation of the hydraulic control units (HCUs) by the NRC inspectors and the licensee raised questions as to the acceptability of certain tube steel bottom support installations, crackec' cable insulation at the entrance to Cannon connectors, broken Sealtight surrounding electrical. cables, misaligned limit switches used to in-dicate the position of the scram valves, and leaky bonnets and packing glands on manual valves. These discrepancies were identified by the Operations department to Tech Functions for evaluation.
The inspectors.
will follow up the Tech Function evaluation in a subsequent inspection.
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9.3 During this report period, the operating trunnion room fan ceased to operate. When trunnion room temperature was noted to be increasing, the backup fan was started.
The backup fan was not considered reli-able based on previous problems, therefore, immediate actior had to be taken to address the problem.
The licensee considered deactivating the Main Steam Line temperature detectors in the trunnion room and allowing the temperature to go high if the backup fan broke. However, the decision was made to fix the broken fan and an entry was made into the trunnion room to determine the problem. The trunnion room is a radiologically and environmentally hot space. The problem was determined to be a broken fan belt. A second entry was made and the repair effected. The whole operation was successfully carried out in a well-organized manner with minimum personnel radiation exposure.
9.4 A problem with improperly wired Squib valves in the Standby Liquid Control System at another nuclear plant prompted the inspector to alert the licensee of a potential problem. The licensee promptly
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evaluated their situation by contacting the affected utility and the NRC Regional office and inspecting their Squib valves and as-built wiring.
Their investigation concluded that they did not have, either in use or in stock, any of the affected Conax reverse wired valves nor would they have encountered the problem even if they had based on their as-built wiring scheme. The inspectors had no further concerns regarding this issue.
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10. Main Steam Isolation Valve Performance And Maintenance During this inspection the main steam isolation valve (MSIV) leakage test results and maintenance history were reviewed. MSIVs have been a continuing source of leakage throughout the industry and this review was conducted to determine the extent of leakage noted at Oyster Creek and the effectiveness of the licensee's maintenance. program.
Oyster Creek has two main steam lines and four MSIVs. The "A" steam line has an inboard isolation valve MS03A and an outboard isolation valve MS04A.
Likewise the "B" steam line has an inboard isolation valve MS03B and an outboard isolation valve MSO48.
A considerable amount of MSIV leakage test data was available for review, as was valve maintenance data.
The pertinent leakage and maintenance
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data for each of these valves is summarized below. This summarized data shows for each outage the as-found valve leakage in standard cubic feet per hour (scfh), the principal maintenance performed during the outage, and the as-left valve leakage.
The allowable valve leakge criteria for these valves is 12.09 scfh.
It had previously been 11.9 scfh.
NS03A (A line inboard isolation valve)
4/23/1977 2.87 scfh Valve was repacked 7/27/1977
scfh 9/16/1978 No test results available Valve was rebuilt 11/26/1978
scfh 1/6/1980 24.56 scfh Valve was rebuilt 6/2/1980 1.042 scfh 2/8/1982
>100 scfh Valve was rebuilt 3/28/1982
scfh 2/14/1983 2.918 scfh Valve was repacked - also a variety of maintenance and testing was performed during this long outage.
2/10/1984 9.662 scfh l
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NSO4A (A Line Outboard Isolation Valve)
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4/23/1977 No test results available
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7/27/1977
.36 scfh 9/16/1978 14.13 scfh Valve was rebuilt 11/26/1978.18 scfh 1/6/1980 2.11 scfh Valve was repacked j-6/2/1980 966 scfh 3/28/1982 22.906 scfh g
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4/8/1982
.355 scfh 2/14/1983 16.339 scfh Valve was rebuilt - also a variety of maintenace and testing was performed during this long outage.
8/29/1984 8.17 scfh
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NS038 CB Line Inboard Isolation Valve)
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9/23/1977
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Valve was repacked 7/27/1977
scfh 9/16/1978 No test results available Valve was repacked 11/26/1978
scfh 1/6/1980 9.99 scfh Valve was repacked 6/2/1980 1.436 scfh
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2/8/1982 11.49 scfh Valve not repacked or rebuilt'
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4/5/1982 note on test procedure states
NS028 absolutely tight 2/14/1983 2.54 scfh
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Valve was repacked - also a variety of maintenance and testing was performed during this long outage.
7/12/1984 NS03B and NS04B combined total leakage 2.63 scfh NSO4B (B Line Outboard Isolation Valve)
4/23/1977 No test results available Valve was rebuilt 7/27/1977
.26 scfh
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I 9/16/1978 14.13 scfh Valve was repacked 11/26/1978 7.54 scfh
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1/6/1980 9.91 scfh Valve was repacked 6/2/1980 1.360 scfh 2/8/1982 11.49 scfh Valve not repacked or rebuilt 4/5/1982 11.49 scfh 2/14/1983 17.207 scfh l
. Valve was rebuilt - also a variety of maintenance i
and testing was performed during the long outage.
l 7/12/1984 NS03B and NSO4B combined total leakage 2.63 scfh As can be seen from the above data, MSIV leakage has not been excessive, generally less than 100 scfh. A review of the as-found leakage data from i
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l the five outages during the period 1977 through the 1983-84 outage shows l
only two occasions in which two valves in series (i.e. both of the redun-dant valves) not meet their acceptance criteria.
This was in 1978 and 1982.
In this case, the maximum leakage would have been 14.13 and 22.906
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l scfh respectively.
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The MSIVs have a two-inch bypass line associated with them.
The leakage test results for these valves were also reviewed, since their leakage
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would add to the total penetration leakage. These valves are always tested in pairs; V-1-106 and V-1-107 are inside the drywell and V-1-110
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and V-1-111 are outside the drywell.
Except for 1982 where limited as-l'
found data was available at the site, the maximum leakage through this path would have been 1.836 scfh.
These valves were replaced during the last outage; however, trouble was experienced with their operation and they have been tagged shut during this entire operating cycle.
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Based on a review of maintenance history records and discussions with li-
.censee personnel, it appears that the preventive and corrective maintenance
'being performed has been effective in maintaining the valves' performance.
On only one occasion has it been necessary to disassemble a valve a second time following a rebuilding effort.
The licensee maintenance program for these valves includes input from both General Electric and the valve mana-
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facturer, Atwood and Morrill.
Routine preventive maintenance for the MSIVs
calls for two valves to be rebuilt each refueling outage and the other two l
valves repacked. Although a pre-outage selection of valves for rebuild is
.made based on valve histories, the leakage tests at the start of the outage generally dictate the valves that will actually be rebuilt.
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The licensee's evaluation of a BWR owners group MSIV leakage committee
study was also reviewed. This study was undertaken to propose suggestions to minimize the'MSIV leakage probler. The technical functions division of GPUNC evaluated this study for possible applicability of leakage reduction techniques at Oyster Creek. The licensee concluded are that the Oyster Creek MSIVs have a combination of leakage contributors that make valve _
i leakage probable. The MSIVs are a wye pattern valve with the stem inclined
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45* to the vertical, in addition all four valves are rolled to the side by 22.5'.
These two factors are the most significant contributors to valve
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leakage and cannot be easily corrected or eliminated without extensive modifications.
The recommendations resulting from the licensee's review of the study are that continuing discussions be held with the valve manufacturer by all GPUNC divisions involved with the MSIVs. This will ensure that GPUNC repair methods are kept up-to-date consistent with the Oyster Creek repair history and Atwood and Morrill input, which is based on other utilities repair experience and any future design changes. Discussions with licensee
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personnel indicate this recommendation is being pursued.
l The licensee's plant engineering group is presently reviewing a General f
Electric MSIV leakage improvement package for possible installation at l
Oyster Creek.
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The inspector had no further questions relating to this matter.
i 11.
Exit' Interview
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A summary of the results of the inspection activities performed during this report period were made at a meeting with senior licensee management at the end of the-inspection.
The licensee stated that, of the subjects i
discussed at the exit interview, no proprietary information was included.
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