IR 05000219/1987013
| ML20235P886 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 07/08/1987 |
| From: | Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20235P833 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-737, TASK-1.C.1, TASK-2.F.1, TASK-2.K.3.19, TASK-2.K.3.21, TASK-2.K.3.57, TASK-3.D.3.4, TASK-TM 50-219-87-13, IEB-84-01, IEB-84-1, NUDOCS 8707200658 | |
| Download: ML20235P886 (32) | |
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I U.S. NUCLEAR REGULATORY COMMISSION I
REGION I
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Report No.
50-219/87-13 Dacket No.
50-219 License No.
OPR-16 Priority --
Category C Licensee:
GPU Nuclear Corporation l
1 Upper Pond Road l
Parsippany, New Jersey 07054
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Facility Name: Dyster Creek Nuclear Generating Station Inspection Conducted: April 20 - 23 and May 7 - June 18, 1987 Participating Inspectors:
W. H. Bateman W. H. Baunack J. F. Wechselberger Approved By:
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bcP cr7 A~ R. BJ4ffgn, Chief Date Reactor Projects Section 1A Inspection Summary:
P.vutine inspections were conducted by the resident inspectors and one Region based inspector (379 hours0.00439 days <br />0.105 hours <br />6.266534e-4 weeks <br />1.442095e-4 months <br />) of activities in progress including plant opera-tions, radiation control, physi-al security, and forced shutdown work activ-ities.
In addition, the inspectors reviewed open inspection items and open l
NUREG-0737 action items, reviewed Core Spray and ESW system problems, followed up licensee corrective actions in response to NRC Inspection Report 87-16 and the status of HGA relays in response to a Region I initiative, and reviewed ISI results from the 11R outage.
The inspectors also reviewed implementation of
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surveillance programs for recent Tech Spec amendments, followed up the status l
cf a licensee commitment to readjust the alarm setpoint on the service water
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discharge radiation monitor, investigated results of drywell shell thinning inspection, observed action to identify 'and resolve pipe support problems, and i
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evaluated licensee 10 CFR 50.59 reviews.
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Inspection Summary (Continued)
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Results:
Three violations were identified involving:
(1) failure to hydrostatically test a weld in accordance with the requirements of ASME Section XI; (2) failure to ensure operability of alternate shutdown panel instrumentation for reactor pressure and reactor water level (fuel zone); and (3) failure to submit an annual report required by 10 CFR 50.59 in a timely manner.
Various NUREG-0737 action items were reviewed and closed.
Thirty-four open inspection items were closed. An unplanned shutdown occurred due to a failed electromatic relief valve acoustic monitor and during the forced shutdown work was completed in the drywell to adiress a higher than desired bulk temperature during operation.
Various problems were encountered with pipe supports in a portion of the Core Spray system because of water hammer. These were corrected before the end of the report period.
The inspectors noted that the licensee's efforts to define and correct the Core Spray pipe support problems were initially weak and prodding by the NRC was required before a reasonable evaluation ensue _ _ _ _ _ _ _ _ _ _ _.
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DETAILS 1.
Verification of NUREG-0737 TMI Action Plan Requirements During this inspection the licensee's actions taken in response to certain TMI Action Plan requirements were reviewed.
The item numbers are the same as those assigned by NUREG-0737.
1.1 Item I.C.1.2.B and I.C.I.3.B required the licensee to review and revise transient and accident procedures.
By Confirmatory Order dated June 12, 1984, the Commission required the license? to imple-ment the upgraded Emergency Operating Procedures for Nster Creek prior to restart from the Cycle 11 outage.
The inspe a.'r verified the updated Emergency Operating Procedures Manual had been issued prior to restart from the Cycle 11 outage.
These Items are closed.
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1.2 Item II.F.1.4 requires that the licensee install a continuously indi-I cating containment pressure monitor in the control room. The inspec-
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tor verified that the licensee has installed a continuously indica-
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ting recorder of containment pressure in the control room. The range
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of the instrument is 0-260 psia which meets the requirements spec-ified by NUREG-0737.
l This item is closed.
I 1.3 Item II.F.1.5 requires that the licensee shall provide a continucus
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indication of suppression pool water level in the control room.
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inspector verified the licensee has installed a continuously indi-
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cating recorder of suppression pool water level in the control room.
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The range of the instrument is 10 to 360 inches which meets the
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requirements specified by NUREG-0737.
l This item is closed.
1.4 Item II.F.1.6 requires that the licensee install in the control room a indication of hydrogen concentration in the containment atmosphere.
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The inspector verified that the licensee has installed a containment hydrogen indicator and recorder in the control room. This installa-tion meets the requirements specified by NUREG-0737.
This item is closed.
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1.5 Item II.K.3.19 requires that non-jet pump plants install interlocks to assure that at least two recirculation loops are open for recir-
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culation flow for modes other than cold shutdown.
By letter dated i
July 15, 1986, J. Donohew, Jr., NRR to P. Fielder, GPUN which for-warded Amendment 106 to license No. DPR-16, this requirement was revised to require the installation of an alarm to indicate that a fourth recirculation loop has been isolated instead of the original i
design of electrical interlocks to prevent isolation of more than three recirculation loops.
The inspector verified that this alarm has been installed, that alarm response procedures had been prepared, and that operators had been trained in the modification.
l This item is considered closed.
1.6 Item II.K.3.21.8 requires that the Core Spray system logic should be modified so that the system will restart, if required, to assure ade-quate core cooling.
The NRR Safety Evaluation for NUREG-0737 Item II.K.3.21, dated May 27, 1983 provided the staff's review of the licensee's proposed modifications and found them to be acceptable.
The inspector reviewed internal memorandum, Project Engineer 0.C.
Projects to Manager, BWR Licensing dated September 11, 1984. which identified that the Core Spray system modification which addresses NUREG-0737, Item II.K.3.21 has been accepted by the plant and is inservice.
This item is considered closed.
1.7 Item II.K.3.57 requires that emergency procedures should include ver-ification that a source of cooling water is available prior to manual actuation of the automatic depressurization system.
The inspector verified that the licensee has in place the updated Emergency Opera-ting Procedures. These procedures specify operator actions necessary to control all emergency conditions.
Specifically, Emergency Opera-ting Procedures EMG-3200.03, Level Restoration, and EMG-3200.01, RPV Control Water Level, are the procedures which satisfy this require-ment.
l This item is considered closed.
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i 1.8 Item III.D.3.4.2 requires that licensees assure that control room operators be adequately protected against the effects of accidental
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releases of toxic and radioactive gases and that the nuclear power
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plant can be safety operated or shut down under design basis ~ accident conditions.
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By a Confirmatory Order dated March 14, 1983, GPUN was required to have NUREG-0737 Item III.D.3.4 fully implemented before the restart from the Cycle 11 refueling outage. Amendment No. 105 to the Oyster Creek license extended the due date imposed by the March 14, 1983 order to fully implement Item III.D.3.4. The date remained the Cycle 11 refueling outage for the completion of the interim measures listed in Attachment I of the GPUN letter dated June 4, 1985 and was changed to the Cycle 12 refueling outage for the completion of the final measures listed in Attachment II of the same letter.
During this inspection, the inspector verified the licensees actions relative to the Attachment I items which were to be completed during the Cycle 11 refueling outage.
The items and findings associated with each item are as follows:
(1) The licensee will install chlorine monitoring capability which will provide an alarm in the Control Room to alert operators in the event of a chlorine leakage condition.
This item is no longer applicable since the liquid chlorine system in the chlorine facility has been replaced by a sodium hypochlorite system.
(2) The licensee will develop and implement a preventive maintenance program of Control Room HVAC Ducts and Dampers to ensure system integrity is being maintained and that leakage remains low.
Following initial discussions with licensee personnel and a re-
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view of records, it appeared that this required preventive main-tenance (PM) program of the Control Room HVAC ducts and dampers had not been developed.
Believing that no preventive program,
existed the licensee conducted a walkdown of the system on April 14, 1987 by Technical Functions and Plant Material engineers. A number of minor problems were identified and maintenance short form written to correct the identified problems.
Following the inspection, and in preparation for developing a PM program, it was noted that a monthly PM check was being performed on the system. This monthly PM check included most of the items iden-tified as needed for a thorough PM program.
Consequently, with some changes the existing PM procedure will serve to satisfy the requirement for a Cor. trol Room HVAC Duct and Damper PM program.
The inspector noted that when license Amendment 105 was issued there was poor follow-up by the licensee to verify that the order requirements had been fulfilled in this area.
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(3) The licensee will install weatherstrip material on the two doors
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which are not used for normal access into the Control Room.
The two doors which are not used for normal access into the
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Control Room have had weatherstrip material installed. However, for the computer room door, the installation was ineffective in that at certain areas around the door the weatherstrip material was approximately three-eighths of an inch from the door and light was clearly visible through this opening. Also, an elec-trical wire was passed through the opening between the door and the door frame. An attempt had been made to seal the door with tape.
The licensee immediately corrected these problems, and the inspector had no further questions.
(4) In order to override the existing thermostatic controls, the licensee will install a switch which will allow operators to either isolate the Control Room or place the Control Room HVAC system into the Recirculation Mode.
This switch was verified to have been installed.
(5) The licensee will propose appropriate Technical Specifications for the Control Room HVAC System.
By Technical Speci fication Change Request No.
151, dated November 28. 1986, the appropriate Technical Specifications for the Control Room HVAC were submitted.
(6) The licensee will develop radiation and chlorine alarm response l
procedures for the control room operators to take the appropri-l ate actions in response to either of these alarms.
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l These alarms response procedures were verified to have been prepared.
(7) The licensee will provide a Chlorine Transport Analysis to demonstrate that the control room operators will have at least l
two minutes to respond to a chlorine leak alarm. This analysis will be submitted to the NRC by August 15, 1985.
The licensee will provide calculations and analysis for whole body and beta skin doses using Regulatory Guide 1.3 source term.
i If necessary, procedural guidance for protective measures to be taken by the control room operators such as the usage of protec-tive clothing and goggles will be developed.
The results of l
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these calculations and the assumptions and models for the
l analysis will be submitted to the NRC by Jc..e 14, 1985. Because the NRC staff is presently reviewing the iodine source term for j
the design basis LOCA accident, the thyroid exposure limit will l
not be addressed.
j The Safety Evaluation supporting Amendment No.105 stated these items have been completed.
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Item III.D.3.4.2 remains open pending licensee completion of the j
items required for Cycle 12.
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Licensee Action on Previous Inspection Findings (Closed) Unresolved Item (219/81-03-03): The licensee to study the feasibility of installing a water level monitoring system in the chemical waste collection tank vault, l
Documentation shows that a water level monitoring system has been instal-led in the chemical waste collection tank vault.
The level monitoring i
system was installed under BA 402625 with the modification completion date identified as November 11, 1986.
(Closed) Violation (219/81-08-01): This item related to a number of instances where inservice test records did not conform to Section XI of
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l the ASME Code requirements.
This item was reviewed during NRC Region I-Inspection 85-01. The item was considered closed with the exception of the installation of Service Water flow instrumentation.
During this inspection, documentation was reviewed which verified that a ventury type flow measuring instrument had been installed in the Service Water system in conjunction with replacement of
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the Reactor Building Closed Cooling Water heat exchangers as part of B/A 402523.
Glosed) Inspector Follow-up Item (219/81-10-04): This item was opened to verify installation of a positive means of ensuring the water tight doors between the torus and the Containment Spray compartments are maintained closed as required.
During this inspection it was physically verified that a common audible alarm and individual open/ closed lights for the northeast and southeast torus room doors has been provided to alert personnel that a door has been i
left open.
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(Closed) Violation (219/82-08-02):
This item identified the fact that
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torus to reactor building air operated vacuum breaker valves are provided with four keyways in the shaf t to accommodate various operator to valve configurations and that procedures were inadequate to ensure that the valves are correctly assembled.
This item had been reviewed during NRC Region I Inspection 83-20 at which time it was verified the valves were modified by filling in the unused keyways on the valve shafts to preclude improper assembly and that post maintenance test procedures had been revised to assure adequate testing.
i Based on this previous inspection, this item is considered closed.
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Inspector Follow-up Item (219/82-25-02):
The licensee to provide training for mitigating core damace to the Vice President and l
Director, Oyster Creek and the Deputy Director, Oyster Creek.
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Documentation shows that both the Vice President and Director, Oyster
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Creek and the Deputy Director, Oyster Creek have been provided the i
" Mitigation of Core Damage" training.
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(Closed) Violation (219/83-26-01):
This item dealt with the failure to l
incorporate a new Technical Specification requirement into a surveillance j
procedure.
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This item had also been previously reviewed in NRC Region I Inspection l
84-28. At that time, corrective actions appeared not to have been fully i
implemented and the licensee submitted a supplementary response.
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i supplementary response further discussed the methods employed to assure
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that new Technical Specification requirements are incorporated into pro-cedures. When problems are identified, as in the instance of of the pri-j mary containment sump flow integrator calibration, identified in NRC Region I Inspection 87-08, they are carried as a separate item.
There-fore, this item is considered closed.
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Inspector Follow-up Item (219/84-06-04):
The licensee to incorporate system modifications that have been incorporated in piping and instrumentation drawing revisions into valve lineup check sheets.
The Licensing Action Item generated to resolve this item shows that (1) a list of procedures which require revision as a result of 1983 outage modi-q fications had been established, (2) the responsible individuals had been designated to ensure all valves are properly listed / deleted, etc. and that line ups are properly affected, (3) these procedures were tracked from revision to completion in accordance with the requirements of Plant Engineering Procedure 124, " Plant Modification Control."
This effort included a verification mechanism for insuring valve line ups are correct.
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(Closed) Inspector Follow-up Item (219/84-32-01): The inspector to review the licensee's post trip review and corrective actions relating to a'
reactor trip which occurred on October 31, 1984.
The inspector has reviewed the licensee's post trip review of the event and has verified that the recommended corrective actions have been taken.
These actions consisted of repairing the three main feedwater pumps, repairing the pressure control function for the steam jet air ejectors, and resolving several procedural discrepancies.
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Violation (219/84-09-2B):
Hanger design requirements not correctly translated into drawings, procedures, and instructions.
This item was reviewed during NRC Region I Inspection 85-29. This inspec-tion noted the licensee had expected to develop additional design stand-ards to prevent a recurrence by March 1,1985. However, as discussed in the cover letter forwarding Inspection Report 85-13, and in the licensee's supplemental response to Inspection Report 84-09, the development of this program to establish engineering standards could take up to two years to complete.
During thi s inspection, a completed licensing Action Item 84080.09 was reviewed which indicated that GPUN Technical Functions Stand--
ard No. ES-014, Rev. O, Piping Design Standard for TMI-1 and OCNGS has been approved and distributed by Amendment 2 of Technical Functions Admin /
Design and Installation Standards. Appendix "E" of this standard contains the field installation tolerances for piping supports.
Section 3.d specifically addresses installation tolerances associated with snubbers and struts.
(Closed) Violation (219/84-09-40):
Failure to change an installation procedure to accommodate removal and reinstallation of a pipe support.
This item was addressed in NRC Region I Inspection Report 85-29 where it was noted that this violation, though identified in the body of the inspection report, was inadvertently omitted as an example of a violation in the Notice of Violation.
The licensee identified this omission and provided an amended response which identified the corrective action which was taken.
This corrective action consisted of inspecting the subject support as to the correctness of installation and the issuance of a memo as required reading to all Maintenance and Construction and contractor personnel to reemphasize requirements of work control and documentation.
During this inspe tion, corrective action was verified to have been taken by review of Licensing Action Item File 84080.02 which showed Short Form j
14029 for the inspection of the support had been completed and that Memo j
- A'.00-84-0210 was issued which reemphasized requirements of the approval i
of hanger removal and control of work.
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i (Closed) Violation (219/84-20-03):
Maintenance and Construction Short Forms not properly completed with regard to Malfunction /Cause and Important-to-Safety classifications.
The licensee's corrective actions to prevent recurrence consisted of instructions to personnel emphasizing requirements, responsibilities, and I
accountabilities in regards to these issues.
During this inspection re-l suits of Quality Assurance Audits of Maintenance and Construction Short Forms was reviewed. Results of Quality Assurance Audits 84-20, 85-16, and
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86-14 were reviewed and discussed.
These audits indicate some concerns
are still being identified and that a Quality Assurance Deficiency Manage-
ment Escalation Notice has been issued. As a result of these audits, cor-i rective actions are being taken. Based on the licensee's follow-up audits and corrective actions taken as a response to these audits this item is considered closed.
Maintenance activities are reviewed on a continuing basis by the NRC.
i (Closed) Violation (219/84-34-01):
A containment entry made without i
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first inserting control rods to make the reactor subcritical and verifying decreasing power level.
l The licensee's corrective actions were to issue a new procedure to control i
drywell entries.
During this irspection, the inspector verified Station Procedure No. 233, Drywell Acctss and Control, had been issued.
This procedure provides the instructions for drywell access control while assuring personnel safety.
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(Closed) Violation (219/85-01-02):
Reactor triple low water level sensor valved out of service for greater than the one hour permitted by
Technical Specifications.
j The inspector verified that among the corrective actions taken were the i
logging of all surveillance tests in the control room including start time and completion time, an " Equipment-Out-of-Service Sheet" has been added to applicable surveillance tests, and the Technical Specifications have been changed to permit one channel to be made inoperable for up to two hours per required surveillance without tripping its trip system.
In addition, routine resident inspections have not identified a repetition of this violation.
(Closed) Violation (219/85-06-01):
Failure of plant operations to perform a partial valve lineup of modified Core Spray instrumentation.
i As corrective action for this violation, the licensee committed to revise Station Procedure 125, Plant Modification Control, to provide a mechanism in the modification turnover process to require that valve lineups / system checkoff be performed following completion of a modification and prior to turnover and final acceptance. The inspector reviewed documentation which verified Revision 5 of Procedure 125 incorporated the requirements com-mitted to in response to this violatio I
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(Closed) Violation (219/85-06-05):
Internal leakage test requirements l
for leak reduction program required by Technical Specifications not l
specified in procedures.
A review of closed licensing Action Item 85033.01 verified Station Pro-cedure 125.3, Leak Reduction Program Administration, had been written for leak reduction program administration and that Procedures 665.4.008, 665.4.009, 665.4.010, 665.4.011, and 665.4.015 were revised to include internal leakage test requirements. A spot check of Procedures 125,3 and 665.4.008 was also conducted to verify changes.
(Closed) Inspector Follow-up Item (219/85-09-02): Licensee to install I
spacer pieces in battery racks in order to make them seismically j
acceptable.
This item has been updated in Inspection Reports 85-26 and 85-29. Subse-quent to these inspections the resident inspectors have verified that the necessary modifications have been completed.
(Closed)
Inspector Follow-up Item (219/85-13-01):
Review licensee's (
actions taken as a result of GE Service Information Letter No. 402, irWetwell/Drywell Inerting."
The licensee has documented a review of the nitrogen inerting system which was performed to determine adequacy of the design in preventing cold
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nitrogen from being introduced into the drywell and torus.
This review j
determined, other than system repairs which had been made, no further
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modifications to the system are required.
This issue was also discussed l
in the licensee's response to IE Bulletin No. 84-01.
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(Closed) Inspector Follow -up Item (219/85-13-02): The licensee to make available vendor nitrogen system inspection reports.
Operational difficulties had been experienced with the inerting systems electrically heated vaporizer.
The vaporizer, low temperature cutoff valves, and the nitrogen tank are owned and maintained by the vendor.
To eliminate some of the operating problems, GPUN requires equipment condi-l tion reports from the vendor.
During inspection 85-13 these maintenance /
inspection reports were not available. During this inspection, copies of 10 inspection reports were made available to the inspector.
In order to provide a reliable inerting system the licensee's contract with the vendor requires quarterly system inspections with inspection reports provided to the operations departmen n
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(Closed)
Violation (219/85-13-03):
The Maintenance and Construction Division failing _ _to respond to a Quality Deficiency Report (QDRl regarding bypass of quali_ty control holdpoints.
The inspector verified by review of documentation that the following cor-rective action has been taken to resolve this matter: (1) all maintenance Construction and Facilities (MC&F) supervisors have been reindoctrinated by attending a QC lecture on the importance of QC notifications and hold points; (2) reindoctrination was conducted of all QA personnel regarding l
the deficiency escalation program and the need to perform and document all deficiency follow-up activities in a timely manner; (3) MC&F has imple-mented an internal tracking system which will ensure that timely responses are made and that corrective actions are completed; (4) QA has reviewed all open QDRs to ensure all corrective actions are completed; and (5) a supervisors' manual has been issued to MC&F Job Supervisors and other selected MC&F personnel which deals, in part, with QDR requirements.
(Closed) Violation (219/85-13-05):
Failure to review temporary changes to procedures within 14 days of implementation as required.
Measures have been established to keep the Safety Review Manager informed of all temporary procedure changes so that. timely review of these changes can be accomplished. The Safety Review Manager is maintaining a plot of temporary changes reviewed.
This plot indicates that from November 1986 to the present,100% of the temporary changes had been reviewed within 14 days.
It should be noted there have been periods since corrective action was initiated and prior to November 1986, during which not all temporary changes had been reviewed within 14 days. This indicates management at-tention is still required in this area to assure full compliance is main-tained.
{ Closed) Inspector Follow-up Item (219/85-13-06):
Inspector to follow licensee's program to improve and update facility drawings.
Licensee documentation generated in response to this item shows that GPUN is continuing to work to improve the Oyster Creek drawings.
The process of updating drawings to reflect the as-found plant configuration is on-going.
Also, plant procedures describe the program. implemented to main-tain facility drawings.
Additionally, the routine inspection program verifies the adequacy of facility drawings, therefore, this item is con-sidered closed.
[ Closed) Violation (219/85-23-02):
Failure to fully adhere to procedures relating to containment atmosphere control during a reactor startup.
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Routine inspection activities have shown that the corrective actions com-l mitted to by the iicensee in response to this item have been taken. These l
actions consisted primarily of discussions with and counselling of senior operations personnel and first line supervision in the need for procedural
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compliance, Technical Specification adherence, good internal communica-tions, etc. Based on these actions, this item is considered closed. How-ever, the need for licensee management to continuously evaluate adherence to routine operating procedures is always present.
Also, this area is continuously reviewed by the NRC.
(Closed) Inspector Follow-up Item (219/85-29-01):
Inspector to review licensee's actions relative to a problem identified by GE applicable to AK and AKR circuit breakers.
The licensee reviewed this issue and determined that it does not apply to the Oyster Creek reactor trip scheme since these breakers are not utilized in the reactor trip system. These same type of failures were determined to be possible of occurring on circuit breakers which are installed in Oyster Creek 480V unit substations.
These breakers feed safety-related and non-safety related loads and are required to trip under loss of AC power conditions.
To prevent these failures from occurring, adequate tolerance and operational checks are performed on the unaervoltage devices as part of preventive maintenance. The maintenance procedures also pro-vide suf ficient measures for preventing misalignment problems. Therefore, the licensee determined no additional action is required.
(Closed) Inspector Follow-up Item (219/85-29-03): Determine means'which have been established to ensure that the engineering contractor of a job is not changed part way through the process without very careful consideration.
Technical Functions Procedures 5000-ADM-6250.01, Professional Services, i
and 5000-ADM-5110.01, Project Approval and Work Authorization, are the l
procedures which govern the activities associated with this item. Adher-l ence to these procedures will assure that the change of an engineering
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contractor should it become necessary would only be performed with the i
concurrence of high level management.
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(Closed) Inspector Follow-up Item (219/85-29-04): Determine means which have been established by which changes to engineering documents are made by the same organization that originated the document.
Technical Functions Procedure SC90-ADM-7350.03, Field Questionnaires,
Change Notices, and Change Requests, deals with this topic. Adherence to this procedure will assure that changes to engineering documents are made
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made aware of the change.
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(Closed) Unresolved Item (219/85-36-01):
Licensee to evaluate corrective
actions relative to a Core Spray system overpressurization.
The licensee has evaluated this matter and has changed alarm response procedures B-6-e and B-6-f in response to the concerns expressed by the
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inspector.
(Closed)
Inspector Follow-up Item (219/85-38-01):
Licensee to investigate the reason a recirculation pump discharge valve failed to close.
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"C" recirculation pump discharge valve failed to close was excessive friction in the packing gland.
All recirculation pump discharge valves' packing was replaced i
during the 11R outage.
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{ Closed) Violation (219/86-02-01):
A required snubber made inoperable during full power operation.
The licensee's corrective action consisted of instructing personnel l
l initiating short forms to be more clear and concise in their descriptions I
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of work to be performed, distributing the Licensee Event Report associated with this event as required reading to all shif t supervisors and mainten-ante planners, and revising the procedure relating to the removal and replacement of snubbers to clarify and define those precautions and limi-tations applicable to safety-related snubbers.
The inspector verified Plant Procedure 775.1.004, Removal / Replacement of Bergen-Paterson Hydrau-lic Snubbers, has been revised to include "During plant operation, all safety-related snubbers shall be operable whenever the systems to which they are installed are required to be operable.
Therefore, during plant operation, safety-related snubbers can only be removed / replaced in accord-ance with the requirements of this procedure to support Technical Specif-ications' required functional testing or only if there is a definite con-
cern for the installed operability of the unit.
In either case, and re-l gardless of plant operating conditions, only one snubber at a time per plant system may be removed / replaced to maintain system operability status."
.(Closed) Unresolved Item (219/86-04-01):
Inability of the Emergency Service Water (ESW) System Installed Instrumentation to Yield Meaningful Inservice Test Results During the forced outage caused by failure of an electromatic relief valve acoustic monitor, an Annubar flow measuring device was installed in ESW System II.
This device now provides the capability to establish a mean-ingful baseline value for pump flow.
The licensee has addressed the sys-tem instability characteristics by requiring a run time of sufficient duration to allow the various parameters to stabilize. A review of his-toric data on System I indicates that with proper use of the Annubar and provison of sufficient run time to allow parameter stabilization, that meaningful IST data is being obtained.
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(Closed) Violation _(219/86-06-01):
Failure to maintain the Conduct of Plant Engineering Procedure current.
The licensee's corrective action consisted of changes to Station Procedure 125, Conduct of Plant Engineering to (1) revise and clarify organizational description and delineation of responsibilities, (2) describe the engi-neering request tracking system, (3) revise the requirements for records management, and (4) redefine the prioritization methodology. The inspec-tor verified these changes had been incorporated into the procedure.
{ Closed) Violation (219/86-06-02):
Failure of plant engineering to assign a, appropriate priority rating to a Plant Engineering Work Request which resulted in a nuclear safety issue not being promptly addressed.
The licensee's immediate corrective action was to write a Technical Func-tions Work Request for an evaluation of the issue. For further corrective action, Procedure 125, Conduct of Plant Engineering, was revised to fur-ther define task priorities. This corrective action was verified during j
the closeout of 219/86-06-01 above.
I
{ Closed) Violation (86-17-02):
Failure to conduct a high radiation area
key control responsibility briefing and failure to lock a high radiation l
area.
!
In response to this issue, the licensee conducted an inspection of each i
'
locked high radiation area to identify whether or not modifications are appropriate to reduce the probability of error when locking high radiation doors.
Also, training has been revised to further emphasize high radia-tion area key control.
Routine inspections by the resident inspectors have not identified a repetition of this violation.
(Closed)
Inspector Follow-up Item (219/80-17-04):
As a result of problems identified with Containment Spray system supports, the inspector was to review a Containment Spray piping computer analysis and licensee's corrective actions.
The completed computer analysis of the system was provided to the resident inspector for review. Also, four Containment Spray supports were upgraded during the 11R outage.
(Closed) Unresolved Item (219/86-21-04):
Licensee to review adequacy of housekeeping procedure or other procedural controls to ensure radioactive material and trash is disposed of in an efficient and timely manner with proper consideration given for ALARA.
The licensee performed a review of Oyster Creek Procedure 119, Housekeep-ing, and determined that the procedure does contain provisions for the timely removal of trash for ALARA considerations. Based on this review the licensee determined that the provisions of Procedure 119 were not E-----__________________-__________________
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adhered to in the case of the CRD rebuild room.
However, to place more emphasis on ALARA the housekeeping procedure has been strengthened to reinforce the ALARA aspects of housekeeping.
In addition, other proced-ures have been reviewed and some changes made to reference the 119 house-I keeping procedure.
3.
Remote Shutdown Panel Instrument Surveillance During the report period, the inspectors noticed out of specification readings on the remote shutdown panel (RSP) instrumentation, including isolation condenser
"B" shell water level, reactor vessel water level I
(fuel zone) and reactor pressure.
The licensee had identified these dis-I
'
crepancies also and had initiated work requests to have the deficiencies I
corrected.
A review was conducted of the outstanding instrument work I
requests and the instrument surveillance requirements to determine the l
instrument status, i
i Four work requests had been written on the three instruments of concern.
I
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Work request No. 45021 (dated S/12/87) written on isolation condenser "B" shell water level (LI-211-994) was found in the Instrument and Control (I&C) work center ready to be initiated. Work request Nos. 44084 (dated 4/1/87) and 43652 (dated 4/5/87), written on the fuel zone reactor water i
level instrument (LI-622-1029) were still in the planning stage.
The reactor pressure instrument (PI-622-1027) on the remote shutdown panel had work request 44347 (dated 5/19/87) written to correct the instrument dis-
crepancy.
This work request was assigned to the I&C work center, but
)
actually had not completed the planning stage as a result of safety evalu-l ation considerations. Work request No. 45021 (dated 5/12/87) was found by the inspector to be awaiting production.
The inspector informed the licensee that there was a 30 day Technical Specification action statement
,
associated with the instrument.
The licensee initiated the required maintenance activity in order to comply with the Technical. Specification requirements.
In reviewing the surveillance requirements, the inspector referred to Technical Specification 3.12.I, Alternate Shutdown Monitoring Instrumen-tation, and Station Procedure 116, Surveillance Test Program. Procedure 116 did not specify any surveillance requirements for the alternate shut-down monitoring instrumentation under Technical Specification 3.12.I.
Further review indicated for RSP reactor pressure and reactor water level (fuel zone) instruments that the calibration for these instruments was accomplished in November 1986 by the Startup and Test group prior to plac-ing the instruments in service. Amendment 114 to the Provisional Operating Licensee issued on March 20, 1987, requires a quarterly calibration sur-veillance to be performed on reactor pressure and reactor water level
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(fuel zone) instruments.
The inspector determined that no surveillance calibrations were performed on these instruments from November 1986 until the present. Since the amendment was effective as of the date of issuance j
and no calibration surveillance were conducted on the instruments since a
November 1986, the licensee was not in compliance with Technical Specifi-cations. This is a siolation (219/87-13-01). At the time of the imple-
,
mentation of Amendment 114, the licensee did not conduct a surveillance of
the instrument to assure instrument operability nor had a continuing sur-I I
veillance program been implemented to maintain instrument operability from November 1986.
Station Procedure 124, Plant Modification Control, requires " Parallel to I
installation activities, revision of plant procedures affected by the l
modification is performed by Plant Engineering to provide completed, ap-
]
proved procedures before the system is placed in service... New procedures J
must also be drafted by the Plant Contact when the modification includes new equipment or extensive revisions of the existing systems."
In addi-tion, Station Procedure 124 states, in part, "...The end result is inten-ded to be assurance to the Oyster Creek Division that all safety-related objectives in the modification have been accomplished prior to system turnover for operation." The appropriate surveillance procedures were not l
written prior to system turnover.
Plant Engineering had requested Plant Materiel to place the instruments on the Technical Specifications Suppor-ting Installed Instrumentation List (TSSIIL).
The licensee felt this
satisfied the 124 procedure requirement for surveillance procedures to be
'
implemented prior to placing the instrument in service. However, this was not accomplished.
Additionally, this was not the acceptable method to surveil the instruments.
Regulatory Guide 1.33 requires written surveil-lance procedures for all calibrations listed in Technical Specification l
required instrumentation.
Calibrations performed in accordance with the l
TSSIIL do not have a detailed implementing procedure nor do they have the l
same documentation and review requirements as do station surveillance
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procedures.
This was the subject of another violation (87-08-01), that was discovered after the licensee had attempted to place the instruments on the TSSIIL surveillance list.
The licensee utilizes a tracking system, Licensing Action Item (LAI), to l
manage incoming and outgoing regulatory correspondence.
The LAI method was discussed in Inspection Reports 83-26 and 84-28 as contributing to the failure to incorporate Technical Specification amendments in the licensing basis in the specified time period. Again, the lack of effective utiliza-l tion of this tracking system contributed to the failure to fully implement a Technical Specification amendment in the required time. The licensee has recently developed a two tiered LAI approach to Technical Specifica-tion amendment changes which the licensee has determined will effect timely implementation of Technical Specifications.
In previous corres-pondence the licensee has stated that the LAI tracking system is not a control system to ensure required actions will be completed, but just a management tool.
In response to this violation the licensee should dis-cuss what controls are utilized to ensure Technical Specification changes are completed as require I
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l 4.
Review of Inservice Inspection Data Reports
The licensee submitted a report to the NRC dated March 27, 1987 to meet the requirements of 10 CFR 50.55 a(g) and ASME Section XI.
This report described examinations made during the Cycle 11 Refueling Outage in con-
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junction with the In-Service Inspection Program, repairs and modifications l
of pressure retaining' pipe welds, new welds, and repair of old welds for attachments to pressure boundary piping.
Included in the report were
l completed ASME NIS-1 and NIS-2 Forms. The NIS-1 Form is used by the owner to document inspection activities associated with the routine inservice inspection program.
The NIS-2 Form is used to document repairs or re-placements performed under Section XI. The inspectors reviewed the infor-mation contained on these forms and did not identify any concerns with the NIS-1 data. However, three concerns related to information on the NIS-2
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Forms were identified and discussed with the licensee. The details are as follows:
!
l (1) Paragraph 5(b) of the NIS-2 Form requires the Owner to specify the i
applicable edition of Section XI utilized for the repair or replace-
'
ment. The edition specified in all cases was the 1974 Edition in-cluding all addenda through the Summer of 1975. This edition of the
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Code requires pressure testing if welding is done to the pressure I
boundary.
However, as documented on the NIS-2 Forms, pressure test-ing was not performed on pressure boundary piping when attachment welds were either repaired or added. ' When ' questioned about this in-consistency, the licensee stated they were using later editions of the Code that did not require pressure testing for any welds to the pressure boundary except through wall welds.
The licensee also
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stated the NIS-2 Form is new and changes will be made in their own in i
house procedure (1504-ADM-3272.02) within three months to more i
clearly define, not only the proper way to complete paragraph 5 (b),
but also the proper way to complete the balance of the form.
Based on this commitment and the fact that the NRC has endorsed later edi-tions of the Code that do not require pressure testing of piping l
after attachment welds are repaired or added, the inspectors had no further questions.
(2) Paragraph 8 of the NIS-2 form is entitled " Tests Conducted" and pro-
vides an option to check off what type of pressure test was performed
and at what pressure and temperature. A review of the Paragraph 8 data on the NIS-2 Forms contained in the report indicated there was confusion as to how to correctly complete this paragraph.
For example, the NIS-2 Form for the reactor head vent piping modification that involved making several new welds was checked to indicate a i
hydrostatic test was required but the pressure was erroneously listed at 1040 psi and no temperature was specified.
The 1040 psi pressure could not be a hydrostatic test pressure because it is too low. The same observation applied to the NIS-2 Form containing data for the
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I three weld overlays.
Additionally, there were inconsistencies regarding pressure test requirements for attachment welds.
Some NIS-2 Forms were checked to indicate a nominal operating pressure test was performed and others indicated a test was not required.
The
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licensee's response to this NRC concern regarding an apparent lack of understanding of how to complete the form and the Code definition of
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pressure testing terms was similar to (1) above, i.e., changes will be made in procedure 1504-ADM-3272.02 to clarify the correct way to complete the form.
The inspectors will review these forms after i
I future outages to ensure the procedure changes are correctly imple-
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mented.
l (3)
Inspector review of the NIS-2 Form associated with rework of feed-water isolation valve V-2-11 indicated an apparent violation of the
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Section XI Code requirements for pressure testing.
The form indi-cated that a nominal operating pressure test had been performed on V-2-11 yet, in actuality, the valve had been cut ut of the feedwater system to permit total overhaul of the valve internals.
Because the valve had been completely removed from the system it was evident that
)
two full penetration welds had to be made to reinsta ) the valve. As
mentioned in 1.)- above, pressure testing is requireis shen a through i
wall weld is made and the Code specifically requires a hydrostatic l
test. The inspectors presented this concern to the licensee who per-formed an investigation and determined the downstream side weld of
V-2-11 should have been hydrostatically tested but was not.
(The l
upstream side weld was outside the Section XI boundary.) The failure to hydrostatically test this weld (RF-2-191 X) is contrary to the requirements of Section XI of the ASME Code and is a violation.
(219/87-13-02)
Inspector and licensee investigation into the cause of this violation l
were not completed at the end of this report period, however, certain i
information was available and some key questions had been identified.
Information gathered indicated the original scope of work on V-2-11 was to rework the valve inplace but this was changed to remove the valve. The post maintenance test (PMT) requirements for the original work scope required a system pressure test and this PMT requirement i
was never changed to require a hydrostatic test when the work scope
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was changed.
Additionally, in development of the weld package to
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reweld V-2-11 back into the piping system, Plant Engineering spec-
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ified a requirement for a hydrostatic test to 1375 psig. This re-quirement never made it into the PMT requirements. Also, as part of the weld package preparation, the authorized Nuclear Inspector (ANI)
established a hold / witness point for the hydrostatic test. This was l
apparently not fulfilled. And finally, the:e does not appear to be I
any QC involvement to establish hold points for the hydrostatic test j
l which is not normal and indicates that QC was not' involved in the l
V-2-11 repair package development.
Some key c;uestions are:
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Why did the ANI sign' the NIS-2 Form when he did not witness the hydrostatic test or sign off his hold point?
l Why wasn't QC involved?
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Why didn't the hydrostatic test requirement become part of the l
PMT?
Does this problem extend to other work done during this past
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outage?
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Based on a number of communications problems encountered during follow up of this concern and obvious communications problems that contributed to the oversight in the first place, what can be done to eliminate communications problems?
Why didn't the Special Processes and Programs group who com-
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pleted the NIS-2 Forms from data they received from Maintenance, Construction, and Facilities (MCF) identify this problem?
The licensee committed to perform a critique of this violation.
It is anticipated that the critique may generate other questions requiring fol-low up and corrective action. The inspectors informed the licensee that in order to address this problem they should, as a minimum, initiate a MNCR and disposition it to just:fy continued operation.
Additionally, they should notify both the ANI and NRC licensing and obtain concurrence from both that continued operation is acceptable.
At the end of this report period MNCR 87-0104 had been written and dispositioned.
The initial disposition was found by the NRC inspectors to be unsatisfactory.
Based on subsequent discussions, the disposition was revised and was con-sidered reasonable.
Part of the disposition requires that a hydrostatic test be performed at the first opportunity.
5.
10 CFR 50.59 Modification Reporting In reviewing the 1984 10 CFR 50.59 Annual Report of Modifications, the inspectors noted the report was dated March 30, 1987.
The inspectors questioned the licensee regarding the timely submission of this report and the status of the 1985 and 1986 reports.
The licensee indicated that the 1985 and 1986 reports were close to submission. In addition, the inspec-tors determined that the 1983 Annual Report of Modifications was dated March 1, 1985.
Researching previous enforcement history indicated that a violation (82-05-02) was written as a result of the licensee failure to submit the 1980 Annual Report of Modifications. In response to this vio-lation, the licensee indicateo that a formal tracking system had been
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established for all regulatory required reports. The licensee indicated that this system assigned responsibility to the cognizant department and tracked the item to completion. 10 CFR 50.59 requires licensees to submit annually a report containing a brief description of any changes, tests, and experiments, including a summary of the safety evaluation for each.
In reviewing other regu'atory required reports, a reasonable grace period for report submission f rom the end of the reporting period was determined to be a maximum of 120 days. In the most recent case, the licensee's sub-mission was in excess of two years from the end of the calender year.
This is a violation of 10 CFR 50.59 reporting requirements. (219/87-13-03)
In response to this vfolation the licensee is requested to commit to a reasonable time period after the end of the calender year for submission of the 10 CFR 50.59 Annual Report of Modifications.
6.
Emergency Service Water (ESW) System Pipe Wall Thinning
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l During this report period, a leak was identified in a weld connecting a l
tee to the outlet piping from the 1-2 Containment Spray /ESW heat exchanger.
The spoolpiece was subsequently removed and the weld and other spoolpiece piping inspected from the inside. The results of the inspection indicated major deterioration of the weld and deterioration of some areas of the pipe and fittings.
Weld repairs were made, the inside recoated with Belzona, and the spoolpieca reinstalled.
The cause of the deterioration was not specifically identified but was thought by the licensee to be the result of turbulent flow caused by a flow orifice installed just upstream i
of the tee.
Based on this probable cause, UT thickness inspection was
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performed on the elbow just downstream of the orifice at the outlet of the j
l 1-1 Containment Spray /ESW heat exchanger. The results indicated low spots i
of.255".
(The pipe is 14" diameter Schedule
'XS'
for a nominal wall i
thickness of.5".)
An engineering evaluation was performed to determine
the acceptability of the thinning of the elbow as regards continued system
'
operation.
This review concluded the system was operable.
Plans are to i
repair or replace the elbow in a future outage.
Subsequent to completion of the repair and inspection of ESW System I (the 1-1 and 1-2 heat exchangers and associated piping) and NRC inspector in-quiries as to what inspections would be performed on the redundant system, similar UT inspections were conducted on tees and elbows just downstream l
of the orifice at the outlet of the 1-3 and 1-4 Containment Spray /ESW heat
exchangers (ESW System 2).
The results indicated the minimum wall thick-ness to be 42" in the elbow off the 1-3 heat exchanger.
In general the lower readings were associated with the fittings at the outlet of the 1-3 heat exchanger. Based on these results, the licensee concluded ESW System 2 was also operable but that periodic inspections of the fittings and pip-ing downstream of the heat exchangers would be performed to monitor and evaluate material wastage.
The inspectors agreed with this action plan and had no further questions.
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7.
Emergency Service Water Pumps - Adequacy of Mounting A routine tour of the intake structure by the inspectors identified sig-nificant corrosion of several nuts used in the mounting of the ESW pumps'
base plates.
The inspectors immediately informed the licensee of this condition as the seismic capability of the installation was in question.
The licensee, in turn, performed their own inspection and initiated work orders to replace the corroded nuts and inspect the studs. All four nuts on each of tho four pump base plates were replaced.
Inspection of the studs determined they were not affected by corrosion. The inspectors were
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concerned that these fasteners had not been included as part of the in-service inspection program and noted that even several weeks after re-placement of the nuts, they remained' unprotected from corrosion.
This fact was discussed with licensee management who stated these fasteners would become part of a routine inspection program. The inspectors had no further questions.
(Near the end of this report period, inspection indicated all but four nuts were painted.)
8.
Review of Key Operational Events During this report period the following key operational events occurred and were followed up by the inspectors:
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The acoustic monitor associated with electromatic relief valve NR-108C failed. Tech Specs require the plant be shutdown within 7 days if the acoustic monitor cannot be repaired.
(The Licensee inter-preted the Tech Specs in a more conservative manner and determined
,
that plant shutdown had to occur within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.) Licensee trouble-
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shooting within the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> determined the problem was in the drywell and subsequently commenced a reactor shutdown. Investigation into the cause of the failure identified a defective splice between a i
twisted pair and a coaxial cable.
In order to improve the reliabil-i I
ity of the acou: tic monitor system, the licensee installed redundant acoustic monitors for each electromatic relief valve during the forced shutdown. The inspectors observed licensee actions throughout
the period and determined them to be conservative, prompt, within the l
spirit of the Tech Specs, and consistent with good operating practice.
Prior to the shutdown a significant amount of attention was being l
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given to the relatively high value of drywell bulk temperature. This l
parameter had been of concern the previous operating cycle and var-
<
ious attempts at addressing it had been made including increasing water flow to the coolers, cleaning the coolers' cooling coils, and performing flow balancing of the drywell ventilation system.
These attempts appeared to be relatively ineffective as drywell bulk tem-perature continued to remain higher than anticipated.
As a result,
,
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during the forced outage discussed above, major overhaul of the dry-well ventilation system was accomplished. It involved replacement of i
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4 of 5 cooling coils, changeout of fan wheels, and additional flow balancing - both air and water.
Additionally, a drywell survey was madt to determine where extra insulation could be added to decrease heat loss and this insulation was installed. Based on the value of the drywell bulk temperature following restart from the forced out-age, there appeared to be an improvement in the drywell ventilation system heat removal capability.
The inspectors will continue to monitor this parameter to ensure the limit of 150 F is not exceeded.
Video taping of the broken fuel bundle discussed in NRC Inspection
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Report 87-08 was completed and viewed by the inspectors.
It was clearly evident that the eight tie rods sheared at the lower tie plate, most likely when the fuel bundle was dropped a few years
earlier.
Licensee efforts continued throughout this report period j
to finalize plans to disassemble and move the damaged fuel bundle.
l The proposed procedure for disassembly and removal of the fuel pins was reviewed by NRC Region I inspectors and no comments were iden-ti fi ed.
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Subsequent to plant restart from the forced outage, the open indica-tion for main steam isolation valve (MSIV) NS-03A failed. This com-plicated performance of the daily MSIV surveillance since the sur-veillance involves closing the valve until the open light goes off which indicates the valve has traveled about 5% closed.
In order to avoid a plant shutdown, the licensee opted to continue to close NS-03A until the 10% closed position was reached and a half scram signal was initiated.
The inspectors reviewed this change to the surveillance procedure and concluded it accomplished the objective of l
verifying operability of the closure function of NS-03A. Towards the end of this report period an opportunity arose to perform a timed valve closure test of the MSIVs. NS-03A closed within its prescribed
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time limits.
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During the forced outage, pipe wall thinning inspections were con-
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ducted on three elbows in the feedwater system. They were not in the
'
portion of the system considered unisolable from reactor pressure.
The UT results determined some thinning had occurred in all three i
'
elbows but not to an extent requiring replacement.
The inspectors confirmed these elbows will be added to the pipe wall thinning pro-
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grsm and undergo periodic thickness inspections.
9.
pipe Support Damage in Core Spray System 2 l
Based on a number of problems identified over a period of about two years with pipe supports associated with the Core Spray system 2 full flow test line, the NRC inspectors raised questions about the operability of Core Spray System 2.
This was precipitated by a number of deficiencies iden-A total of tified by QC inspections performed during this report period.
13 MNCRs were generated by QC all of which were conditionally released by l
i
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,
Tech Functions.
The NRC inspectors questioned Tech Functions as to why there have been continuing problems with supports in this line and why had not a comprehensive system analysis, taking into account all the pipe sup-port problems over time, been performed using an accurate system model to determine actual stress levels. Tech Functions stated they had done some l
analysis and felt the pipe support damage in the test line was being caused by water hammer that occurred each time the full flow test was per-formed.
Based on the facts that Tech Functions did not appear to have a total understanding of the actual stresses being induced in the pipe by l
water harrmer, dia not have an accurate system model -in the computer, and
,
did have evidence of pipe support damage, the NRC requested justification I
from the licensee that Core Spray System 2 was operable. Additionally, the NRC emphasized to the licensee the importance of eliminating the water hammer, thus, eliminating the potential to damage supports and piping.
The licensee performed several tests to attempt to monitor pipe movement during opening of the full flow test valve and to eliminate the water ham-mer. These tests determined the water hammer was resulting because over 200 feet of empty piping was filled almost immediately when the full flow test valve was opened. Efforts were made to better control the opening of the full flow test valve and, at the end of the report period, a scheme had been arrived at where an operator manually opened the valve.
(The valve was normally motor operated and contrbiled by a jog switch mounted locally near the valve.) This change prolonged the time it took' to open the valve, thereby, allowing the water flow to increase over a longer period of time. The result was elimination of the water hammer.
Elimina-tion of the water hammer precluded the need for Tech Functions to perform a detailed stress analysis that accounted for the water hammer loading.
I Instead a system walkdown was performed, a reportedly accurate system model developed, and a stress analysis performed using normal loading assumptions that indicated there were no overstressed locations.
The damaged pipe supports were repaired.
Upon completion of this action to correct the water hammer problem in the Core Spray System 2 full flow test line, the NRC concurred that the system could be declared operable.
NRC review of this matter included reviews of licensee analyses by Region I
i based specialist inspectors.
Also, the licensee presented a summary of their review and analyses at Management Meeting at NRC Region I on May 11, 1987 (see Meeting Report No. 50-219/87-18).
l 10. Drillco Maxibolt/ Baseplate Pipe Support Installation During 11R Outage l
During investigation of the causes of the pipe support damage in the Core
'
Spray system as discussed above, it was determined that a problem existed l
with installation and inspection of Drillco Maxibolts that occurred during l
the 11R outage.
In particular, af ter the bolts were installed, the gap
'
between the underside of the base plate and the bearing surface of the concrete exceeded requirements.
This gap problem was not recognized
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i during original installation and inspection and led to a subsequent con-cern that the gaps may have been caused by overloading the pipe supports.
I Various QC inspections were conducted as well as tests on the Core Spray piping before a determination was made that faulty installation was the cause for the gaps and not overloading. Once this determination was made, the licensee reinspected a sample of 12 Maxibolt/ baseplate installations in different safety systems.
The results of this inspection indicated gaps up to 3/16". Of the 12 reinspected, 9 had gaps greater than 1/16".
Tech Functions performed calculations to determine the acceptability of the installations and several repairs were required.
A total of 40 Maxibolt/ baseplate installations were worked during the 11R outage.
The 28 that were not directly inspected were analyzed using the worst case conditions found of the 12 that were inspected. Of these all but 5 were determined to be acceptable installations. The remaining 5 were inspected to determine the gap and were found to be acceptable without rework.
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l The NRC inspectors followed licensee activities and concluded the rein-spection and technical analysis satisfactorily resolved the problem. The licensee committed to upgrade their Maxibolt/ baseplate installation and inspection efforts to avoid similar problems in the future. The inspec-tors had no further concerns.
NRC review of this matter included l
specialist reviews and discussions at the May 11, 1987 management meeting as noted in Paragraph 9.
11.
Service Water System Discharge Line Monitor The plant has been experiencing a degradation of the Service Water system discharge line monitor. The mcnitor has been indicating from 450-500 cps level and spiking up above the "HI" (500 cps) and "HI-HI" (600 cps) level alarm setpoints. The operators have been unable to reset the monitor from the alarm condition as repeated spikings have kept the monitor in a con-tinuous "HI-HI" alarm condition. The licensee identified in a letter to Nuclear Reactor Regulation (NRR) dated August 13, 1986 that the Service Water monitor was considered inoperable with respect to conformance with
,
I the Radiological Effluent Technical Specifications (RETS).
In addition, the licensee's letter stated that an alarm setpoint will be established l
for the present monitor which will minimize the receipt of spurious alarms l
and provide an indication that effluent radioactivity has increased to an unacceptable level during the time between effluent sampling and analysis.
This was reiterated in the safety evaluation performed for the implemen-tation of Amendment 108, which promulgated RETS.
As reported by the licensee on or about 3/23/87, the monitor alarm setpoints were adjusted from 350 cps to 500 cps and 600 cps for the "HI" and "H1-HI" alarms, respectively.
Since this adjustment in the alarm setpoints, apparently background radiation conditions have increased to the point where the monitor again is in a continuous alarm state. The licensee is presently contemplating another alarm setpoint level change. The licensee has ;.er-formed daily overboard discharge samples since October 1986.
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In addition, Technical Specification 3.15.A requires the licensee to explain in the next Semiannual Radioactive Effluent Release Report why an inoperable instrument was not returned to an operable status within 30 -
days.
This was not included in the Oyster Creek Nuclear Generating Station Effluent Release Report (dated March 2, 1987) for the period covering July 1986 through December 1986.
However, the licensee did explain in their August 13, 1986 letter to NRR the operability status of the Service Water monitor and their plans for replacement of this monitor.
The inspector advised the licensee that a discussion of any inoperabilities over 30 days would be expected in future semiannual
l reports.
l The inspector had no further concerns.
12. 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 were free of obstructions.
The inspectors examined vital area access points to verify that they were properly locked or guarded and that access control was in accordance with the Security Plan.
No concerns were identified.
13.
Plant Operation Review 13.1 Routine tours of the control room were conducted by the inspectc. s during which time the following documents were reviewed:
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Control Rcom 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; Equipment Control Logs;
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Standing Orders; and, Operational Memos and Directives.
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The inspector conducted an audit of the licensee switching and tag-ging log used to control equipment outages.
The log was generally found to be in good order with one exception.
Outage 87-256 for the offgas sample pump was missing from the binder, but was reflected in the summary sheet as being an active outage.
The inspector ques-tioned the licensee, who conducted a search for the outage, but was unable to find the outage paperwork.
The licensee conducted a walk-down of the system to determine that no tags were hung on-the offgas sampling system. From the walkdown the licensee concluded the outage was never implemented.
The licensee conducts weekly and quarterly audits of this log to ensure its accuracy.
After reviewing the methodology of the licensee's audits, the inspector pointed out that his audits might not find this type of problem.
The inspector had no further questions.
I 13.2 Routine tours of the facility were conducted by the inspectors to i
make an assessment of the equipment conditions, safety, and adherence to operating procedures and regulatory requirements.
The following areas were among those inspected:
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Turbine Building
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Vital Switchgear Rooms
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Cable Spreading Room
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Diesel Generator Building
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Reactor Building The following additicnal items were observed or verified:
a.
Fire Protection:,
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Randomly selected fire extinguishers were accessible and inspected en schedule.
Fire doors were unobstructed and in their proper position.
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Ignition sources and combustible materials were controlled
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in accordance with the licensee's approved procedures.
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Appropriate fire watches or fire patrols were stationed when equipment was out of service and proper compensatory taeasures were implemented.
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b.
Equipment Control:
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Jumper and equipment mark-ups did not conflict with Tech-nical Specification requirements.
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Conditions requiring the use of jumpers received prompt licensee attention.
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Administrative controls for the use of jumpers and equip-ment mark-ups were properly implemented.
c.
Vital Instrumentation:
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Selected instruments appeared functional and demonstrated parameters within Technical Specification Limiting Condi-tions for Operation.
d.
Housekeeping:
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Plant housekeeping and cleanliness were in accordance with approved licensee programs.
No violations were identified.
14.
Review of Periodic and Special Reports Upon receipt, periodic and special reports submitted by the licensee pur-suant to Technical Specification requirements were examined by the inspec-tors.
This review included the following considerations:
the report includes the information required to be reported to the NRC; planned cor-rective actions are adequate for resolutien of identified problems; and the reported information is valid.
The following report were reviewed:
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Monthly Operating Reports for February and March 1987;
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Special Report 87-01 dated 3/30/87 regarding freeze-up of deluge system #1 which protects the main transformer area.
The system was out of service from February 16 through March 27, 1987. During this time a fire watch was posted.
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Special Report 87-02 dated 4/9/87 involving lif ting of electromatic relief valves during recovery from the 2/14/87 turbine trip and anticipatory reactor scram caused by a loose wire that caused a loss of a feedwater flow signal.
This report is required by paragraph 6.9.3.m of Tech Specs.
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Special Report 87-03 dated 4/21/87 discussing inoperability of the
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fire water suppression system that was also covered in NRC Inspection Report 87-08.
This was an especially well written and detailed report.
15.
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 calibration. Posted extended Radiation Work Permits (RWPs) and survey status boards were reviewed to verify that they were current and accurate.
The inspector observed activities in the RCA to veri fy that personnel complied Nith the requirements of applicable RWPs and that workers were aware of the radiological conditions in the area.
The l'.censee identified contaminated lead shielding in the fenced in area of the radiological control area (RCA).
The sheet lead shielding appar-ently had been used in a recent outage for maintenance activities in the plant. The shielding was stacked on approximately 12 pallets and covered with a tarp near Gate 20 in an area the licensee refers to as the " lay down area."
One lead sheet was contaminated to a 20,000 dpm (beta and gamma) level and reading 1400 mrad /hr (beta) and 34 mr/hr gamma.
Other lead sheets were contaminated from 1,000-20,000 dpm (beta and gamma). The licensee surveyed the ground surrounding the pallets of lead finding less than 100 counts on a frisker. The licensee conducted additional surveys for contaminated material outside the RCA fenced area and in other storage yards with negligible results.
The licensee moved the contaminated lead sheets into the RCA railroad access and posted the area as contaminated.
i The licensee is conducting an investigation, in part, to determine from I
what particular job and how the lead shielding came to be deposited in the RCA fenced in area outside the RCA building.
The licensee intends to inform the inspectors of the outcome of their investigation. This action is sati sfacto ry to the inspectors who intend to pursue any additional concerns that may arise from the licensee's investigation.
16. Drywell Shell Thinning Inspection Early in May 1987, the licensee inspected the drywell shell thickness dur-
ing the acoustic monitor shutdown.
The licensee considers this as ful-fillment of a commitment to the NRC to shutdown and measure the shell thickness sometime during the period May 1,1987 to September 1987. The data was presented to the NRC Office of Nuclear Reacte. Regulation but has
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not been dispositioned.
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17.
Inspection of GE HGA Relays A review of GE HGA Relays was conducted in response to Region I Temporary Inspection Instruction No. RI-86-03.
An engineering test repcrt at another site indicated the relays were susceptible to contact chatter in certain conditions during seismic testing.
Depending on the relay con-figuration, application, and seismic response spectra, this could present undesirable equipment function.
The objectives of the review were to l
identify the relays and their application.
This review indicated 133
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relays in use, including numerous annunciators, indicator lights and 480 '
VAC switchgear controls. The ir,spector provided this information to NRC Region I for consideration of generic implications. Also, the inspector is pursuing with the licensee the applicability of the seismic information developed for another site to the Oyster Creek configuration and seismic response spectra, 18.
Corrective Action Follow-up to Issues Addressed in NRC Inspection Report 87-16 Regarding Torus to Drywell Vacuum Breakers As a result of findings presented in Inspection Report 87-16, the licensee initiated corrective actions concerning the blocked open torus to drywell vacuum breaker valves which resulted in a violation of primary contain-ment.
The licensee, in a letter to the Nuclear Regulatory Commission dated May 7, 1987, reported their corrective action in response to this event. The inspectors verified the licensee actions to determine if they corrected the root cause of the violation and if the corrective actions would prevent future occurrences.
The following inspection activities resulted:
l Review of the licensee critique of the event was conducted to ensure
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the licensee had accurately identified all problem areas.
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The P ctor. Cooked at the previous Quality Assurance audits per-formed to determine the adequacy and effectiveness of the temporary variation program and the implementation of the Quality Assurance audit findings.
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Review of the Nuclear Safety Assessment Department assessment of the conduct of Independent Safety Reviews and Responsible Technical Reviews by the plant Review Group to verify the implementation of i
corrective action.
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Determination of the status of extensive in process procedure changes to Plant Procedure 108, Equipment Control.
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Interview of personnel involved in the Responsible Technical and
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Independent Safety review processes and observation of upgrade train-ing programs on safety review process for Temporary Variations for these people.
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Examination of three safety evaluatior:s performed by the licensee on Tempora ry Va riations that, prior to the licensee's review in May 1987, had not been performed.
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Review of the licensee changes to Station Procedures 108, Equipment Control; 130, Conduct of Independent Safety Reviews and Responsible Technical Reviews by Plant Review Group; and 312, Reactor Containment Integrity and Atmosphere Control.
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Review of the licensee resolution of technical problems associated with the vacuum breakers.
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Review of licensee's review of the need for a safety evaluation on open Temporary Variations and review of safety evaluations written that were determined to be required.
Review of licensee's efforts to rework the open Temporary Variations
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so that they conform to the requirements of Station Procedure 108.
The licensee identified a problem with the primary containment purge and vent valves exceeding their restricted opening of 30. The licensee sub-mitted a Licensee Event Report (LER) on this subject specifying corrective action to prevent similar occurrences in the future.
This LER will be reviewed in a future inspection.
The results of the licensee's investi-gation and corrective actions for this event were discussed with NRC regional management and the licensee during a meeting in the Regional Office on May 11, 1987 (Reference NRC Region I Meeting Report No.
50-219/87-18, dated May 15,1987).
19.
Backshift Inspection NRC inspections of licensee activities on backshifts were conducted on the following days:
Saturday May 2, 1987 Sunday May 3, 1987 Saturday May 9, 1987 Saturday May 30, 1987
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20. Exit Interview 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 discussed at the exit interview, no proprietary information was included.
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