IR 05000219/1987008
| ML20215J764 | |
| Person / Time | |
|---|---|
| Site: | Oyster Creek |
| Issue date: | 04/28/1987 |
| From: | Blough A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20215J714 | List: |
| References | |
| RTR-NUREG-0737, RTR-NUREG-0822, RTR-NUREG-737, RTR-NUREG-822 50-219-87-08, 50-219-87-8, IEB-79-02, IEB-79-2, IEB-86-002, IEB-86-2, NUDOCS 8705080236 | |
| Download: ML20215J764 (16) | |
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U.S.. NUCLEAR REGULATORY COMMISSION
REGION I
L Report No.
50-219/87-08 Docket No.
50-219~
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l License No.
DPR-16 Priority --
Category C
' Licensee:
GPU Nuclear Corporation 1 Upper Pond Road Parsippany, New Jersey 07054 Facility Name: Oyster Creek Nuclear Generating Station Inspection Conducted: March 9 - April 19, 1987 Participating Inspectors:
W. H. Bateman W. H. Baunack J. W. Chung J. F. Wechselberger Approved by:
ND~O A. R. Blougfii Chief Date Reactor Projects Section 1A Inspection Summary:
Routine inspections were conducted by the resident inspectors and two Region based inspectors (206 hours0.00238 days <br />0.0572 hours <br />3.406085e-4 weeks <br />7.8383e-5 months <br />) of activities in progress includirg plant oper-ations, radiation control, physical security, pipe support inspections, routine surveillance testing, and emergency preparedness. The inspectors also followed up licensee actions to address various NUREG-0737 and -0822 commitments, reviewed containment integrated leakage rate test results, and made tours of the control room and the power plant.
Results:
One violation was identified during review of implementation of NUREG-0822 requirements involving failure to develop and implement a formal surveillance procedure for ensuring operability of the containment leakage rate flow integrators (as discussed in paragaph 1). Review of the containment integrated leakage rate test results did not identify any concerns.
One control room operator error and two equipment operator errors indicated problems with inat-tention to details and poor communications.. Based on the types of core spray pipe support problems identified, the licensee has undertaken an effort to more fully understand and correct the water hammer loading on the core spray test lines. The plant operated at or near full power for the entire report period.
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DETAILS 1.
Verification of Systematic Evaluation Program (SEP) Action Items -
NRC. Region I has been tasked with confirming _ licensee implementation of certain actions -specified in NUREG-0322, Integrated Plant Safety Assess-ment Report (IPSAR). During this inspection several of these items were verified as follows:
The item numbers are those assigned in the IPSAR.
Item 4.1 (9) - The licensee is to drill holes in-the parapets and install
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scuppers to preclude the potential for buildup of rainwater on the roof of either the reactor building or turbine building.
The resident inspector has verified that holes have been provided and.
scuppers installed in the reactor and turbine building parapets.
Item 4.5.4 - The licensee to provide an inspection program which includes review by qualified engineering personnel of water control structures.
Also, to establish inspection and documentation of water control struc-tures following extreme events.
The licensee has in place four procedures which deal with the inspection of water control structures.
Procedure 9410-SUR-4512.09, OCNGS Non-Radiological Environmental Surveillance, provides for a monthly or follow-ing severe storms inspection of intake and discharge canal banks.
Proced-ure 9410-SUR-4570.01, Oyster Creek / Forked River Hydrographic Surveying, provides for an annual hydrographic survey of the Oyster Creek and Forked River waterways which serve as discharge and intake waterways for the plant. Procedure 9430-SUR-4550.01, Oyster Creek / Forked River Environ-mental Engineering Survey, provides for an annual environmental engineer-ing surveillance of the Oyster Creek intake and discharge waterways east of Route 9.
Also, Procedure 2000-ABN-3200.31, High Winds, provides for the inspection of the intake structure following the existence of high wind conditions. These procedures appear to satisfy the water control structure inspection requirements.
Item 4.16.2 - Licensee to provide the appropriate action requirements in the Technical Specificatior. (TS) for inoperable leakage detection systems and any necessary procedural changes to provide surveillance and testing commensurate with the required sensitivity.
The licensee submitted the necessary Technical Specification Change Request which resulted in the issuance of License Amendment No. 97 on January 1986. This amendment provided the limiting conditions for opera-tion and added surveillance requirements for reactor coolant leakage detection system ;
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u The licensee'normally ~provides instructions for performing TS required surveillance. tests of this type in 600-series procedures. These proced-ures satisfy the requirements of. the TS and Regulatory Guide 1.33, which'
require implementing procedures for each surveillance test listed in the TS. During the review of this item, it was t3termined that no'600-series procedure had been prep ~ared to perform the surveillance listed in TS 4.3.H for channel calibration of the primary containment sump flow integrator-and the primary ~ containment equipment drain tank ~ flow integrator. This.
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-failure _to_ provide a surveillance test implementing' procedure'is contrary
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to the requirements of TS 6.8.1 and Regulatory Guide 1.33, which require
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implementing procedures for each surveillance calibration listed in the TS, and is considered'to be a violation (219/87.-08-01).
Records show ' calibrations had been performed on these instruments in July 1985 and July 1986. These calibrations were performed in accordance w!th a Technical Specification Supporting Installed Instrumentation List
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(TSSIIL) procedure. Calibrations performed in accordance with this'TSSIIL
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-do-not'have a detailed implementing procedure nor do they have the same documentation and review requirements as'do 600-series surveillance. pro-cedures.
For the 1985 and 1986 tests, TSSIIL calibration data sheets were available. However, without the benefit of an implementing procedure, it took plantL engineers several hours,- including talking to the technician who performed the test, to. determine how the calibration was. conducted.
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During the July 1986 calibration, the drywell sump leak rate counter was
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- found to be defective. A Maintenance and Construction Short Form was initiated and the counter _ was replaced and tested satisfactorily.
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' ng-the identification of the failed counter on July 3,1986, a Deviation i
Report (86-287) was prepared on the same day. A Plant Engineering Work-Request was initiated on July 17, 1986 to review the effect of the drywell-
sump flow counter error on leak rate calculations. A Plant Engineering
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Task Assignment (PETA)86-141 was prepared on July 29, 1986 to perform this evaluation. A Responsible Technical Review of the Deviation Report was performed on August 1, 1986 and the PETA was completed on October 9, 1986. This review' determined the TS limit of 5 5.0 gpm unidentified leak L
rate was not exceeded due to the as-found counter error.
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The actions associated with the failure to prepare the required surveil-lance test procedure were also reviewed. This review determined that following the preparation of the Technical Specification Change Request associated with the leak rate instrumentation a Licensing Action Item
(LAI) was written on January 7,1985. This LAI 84179.01 assigned Plant Engineering with the responsibility of preparing the necessary adminis-
trative controls, surveillances, etc.
In response to this LAI, Plant
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Engineering identified the actions which had been taken. These actions included the assignment of a PETA (85-244) to the I & C group to write a f ~
calibration procedure for the drywell equipment drain tank flow integrator i-f
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and for the.drywell sump flow integrator. This PETA was written on
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January 23, 1985 and specifically identified the task scope as writing a 600-series procedure for calibration of the drywell sump flow integrator and drywell equipment drain tank flow integrator. Another LAI, 84179.03, was written on January 22, 1986 following the issuance of TS Amendment 97 to ensure procedural compliance with the amendment.
This PETA (85-244), two years after its preparation, is still open. The
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failure to complete this PETA in a timely manner was discussed in detail with the licensee. The inspector was of the opinion that the failure to provide a required 600-series surveillance procedure resulted from an improper prioritization of the PETA.
Licensee representatives stated that at the time the PETA was prioritized, some personnel considered the per-formance of the surveillance testing in accordance with the TSSIIL program to be satisfactory to meet the TS requirements. They felt the failure to prepare a required surveillance procedure was not due to improper prior-itization but was the fault of the TSSIIL procedure which did not clearly establish that the TSSIIL program is not to be used for the performance of surveillance tests listed in the TS.
The licensee further agreed that proper prioritization of PETAs is import-ant and that following the identification of this incident, a review of PETA prioritizations had been undertaken.
Item 4.20 - The licensee is to incorporate into plant procedures the time-related conductivity limit, the chloride concentration limit, and the pH limit for reactor coolant referenced in "BWR Water Quality Specification" (Specification No. SP-1302-28-001). Also, the licensee is to incorporate the conductivity and chloride limits in Regulatory Guide 1.56 into the facility Technical Specifications.
The inspector verified that the time-related conductivity limit, the chloride concentration limit, and the pH limit for reactor coolant spec-ified in Specification No. SP-1302-28-001 have been incorporated irto Station Procedure 827.1, Primary system Analysis; Reactor Water. Also, License Amendment No. 93 incorporated into the Technical Specifications the chloride and conductivity limits established in Regulatory Guide'1.56.
Item 4.21.1 - The licensee is to ascertain the chemical composition of the existing drywell coatings.
If these coatings are found to contain hydro-carbons, they should be removed or the licensee should submit an evalua-tion to justify the continued use of these coatings.
By letter dated February 10, 1984, the licensee provided a description and results of the drywell inspection conducted during the Cycle 10 refueling outage. The licensee concluded that the chemical composition is satisfac-tory. The torus interior was coated during the Cycle 10 refueling outage.
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5 Item 4.22.1 - This item identified 31 valves which are either test, vent, drain, or sample line manual isolation valves that connect to piping pene-trating the containment. The licensee was to provide administrative pro-cedures to ensure these valves are locked closed.
Two of the valves on the list, V-14-21 and V-14-39, should have been V-14-20 and V-14-40, respectively. Also, V-17-51 has been replaced with V-17-51 due to the PASS system addition.
The inspector verified that all valves listed have been included in the Containment System Integrity Valve Check Off List of Procedure No. 312, Reactor Containment Integrity and Atmosphere Control, or on the valve check off list for Procedure No. 305, Shutdown Cooling System Operation.
All valves identified in Item 4.22.1 are required by these lists to be locked closed. The inspector verified the Containment System Integrity Valve Check Off List had been last performed in November 1986 prior to the startup following the last refueling.
Item 4.22.6 - The licensee is to provide administrative controls for shut-down cooling supply valves (V-17-1, V-17-2, and V-17-3), reactor shutdown valves (V-17-55, V-17-56, and V-17-57), and reactor head cooling valve (V-31-2).
The licensee provides administrative control for valves (V-17-1, V-17-2, V-17-03, V-17-55, V-17-56, and V-17-57) in the check-off list provided in Station Procedure 305, Shutdown Cooling System Operation. Administrative Control for Valve V-31-2 is provided by the check off list contained in Station Procedure 306, Reactor Vessel Head Cooling system Operation.
Item 4.26.2 - The licensee is to review the plant surveillance procedures to ensure that all the safety logic channels tied to the reactor mode switch are surveyed. Also, the licensee is to amend the Technical Spec-ifications to incorporate the required reactor trip system testing.
The licensee by letter dater May 31, 1984 P. B. Fiedler GPUN to D. M. Crutchfield NRR, provided the results of a plant surveillance pro-cedure review which was conducted to ensure that the safety logic channels associated with the reactor mode switch are surveyed. This review detor-mined the requirements of various sections of the Technical Specification necessitate testing of safety logic channels associated with the mode switch. Therefore, a change in the Technical Specifications to include a test of the reactor mode switch is not considered necessary.
Item 4.27 (2) - The licensee is to install Class 1E protection at the interface b,. tween the reactor protection system power supply and the reactor protection system.
A completed licensing action item documents the installation of six elec-trical protection assemblies, qualified to 1E requirements between the reactor protection system motor generator sets 1-1,1-2, and auxiliary transformer and protection system panel No. I and Panel No. 2.
This modification was completed during Cycle 11R under B/A 40203.
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Item 4.28 - The licensee is to replace various sensors with analog trip systems which had been previously reviewed and approved by the staff dur-ing the Cycle XI outage.
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. The Itcensee has installed analog trip systems in place of sensors RE02 A, B, C, and D.
Because of concerns regarding Station 0-ring (SOR)
switches to be installed (reference IE Bulletin 86-02), the replacement of other sensors with analog trip systems is still under discussion with NRR.
Item 4.31 (1) - The licensee to make certain modifications to the diesel generator annunciators.
Licensee documentation shows that certain modifications to the diesel generator annunciators were performed under modification E.T. 312-78 to satisfy the commitments made to the NRC. These modifications were:
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Removing existing non-disabling alarms from the present diesel gener-ator trouble alarm.
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Providing a new annunciator for the manual mode switch not in auto.
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Re-designating the working of the annunciator windows to reflect the conditions more clearly.
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Providing a low battery voltage sensar with an alarm function indi-cating diesel generator DC failure.
No further action was required to resolve this item.
Item 4.32 - The licensee to install alarms for B and C battery breaker open, C battery charger 'open, and C battery ground.
The inspector verified the functions identified are alarmed in the control room. The alarm annunciators do not always have the same designation as the function, however, a review of the alarm response procedures verified that the functions are in fact included in the alarm.
Item 4.34 (1) - The licensee is to review and modify as required the loss of offsite power procedure to ensure that operation of ventilation systems
is adequately addressed and will not overload the diesel generators. The result of this evaluation was to be submitted by March 1983.
The licensee does not have a loss of offsite power procedure, but provides the necessary instructions for restoring emergency busses to service if lost in Station Procedure No. 341, Emergency Diesel Generator Operation.
This procedure provides guidance on diesel generator load limitations and load sequencing. Also, Region I Inspection Report 50-219/86-37 documents a_ review conducted to ascertain that the present configuration of the t
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plant's offsite and onsite electric power systems is capable of sustaining and/or switching loads as required to support the safe operation of the plant. Based on discussions with licensee representatives, the submittal of the required evaluation has been discussed with NRR and a revised sub-mittal date of July 15, 1987 has been agreed upon.
Except as noted above, no violations were identified.
2.
Containment Integrated Leak Rate Test Results Evaluation In accordance with the reporting requirements specified in Paragraph V.B.3, Appendix J, 10 CFR 50, the licensee summarized leakage test results from the October 19, 1986 Type A test and Type B and C tests since the last test. The result: are presented in a surnary technical report,
" Reactor Containment Building Integrated Leak Rate Test," dated March 27, 1987.
The report contains pertinent plant and technical data, discussion of Type A test procedures and methodology, presentation of test results, and Type B and C leak rate histories.
The absolute method and the mass plot calcu-lational technique of ANSI /ANS 56.8-1981 were employed for the 1986 CILRT.
The absolute method was consistent with the method specified in ANSI N45.4-1972, which was endorsed by the Appendix J of 10 CFR 50. However, the mass point method was not endorsed by Appendix J and the finding was documented in USNRC Region I Inspection Report No. 50-219/86-35.
The test objective was to demonstrate that leakage through the reactor containment building and systems penetrating the containment building did not exceed the limit allowed by the plant technical specifications.
The test was conducted with containment isolation valves (CIVs) and con-tainment pressure boundaries (CPBs) in an "As-Found" condition. The
", As-Found" test was declared a failure by the licensee due to excessive local leakage. The test was reinitialized after being witnessed by two Region based inspectors as a routine safety inspection. Type A test parameters and test results are summarized in the following tables.
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Type "A" Test Parameters and Acceptance Criteria 1.
Test Method............ Absolute 2.
Calculational Method....... Mass Point (per ANSI /ANS 56.8-1981)
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Test Duration Stabilization Period......
4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />s-Data Gathering for Leakage...
24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Calculation Verification Leak Rate Test.
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4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />
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Test Pressure..........
36.055 psia (reduced pressure)
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Maximum Allowable....
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0.567 wt %/ Day (0.75L )
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t Leak Rate (Al Upper Bound of 95%
Confidence Limit)
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Test Results Type A Test Results, Weight % Day As Found As-Left*
Acceptance criteria, 0.75 L, 0.567 0.567 (Maximum Allowable Leak Rate)
Measured Leak Rate, L,,:
>0.567 0.398 Leak Rate'at the Upper Bound of the 95% Confidence Interval:
>0.567 0.405 Conclusion Unacceptable Acceptable
- 1evel corrected and Local Leak Rate Test (LLRT) adjusted.
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Verification Leak Rate Test (VLRT)
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Test Method............ Superimposed leak 2.
Calculation Method......... Mass Point 3.
Test Duration..........
4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 4.
Superimposed leakage (lo)....
0.610 wt %/ Day (3.00 SCFM)
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The verification test. acceptance criteria require that the result does not deviate from the total leakage (superimposed, L,, plus measured leakage, L,) by more than 25% of the maximum allowable leak rate at full accident pressure (0.25 L,).
There-fore, the result must be greater than -the lower limit and less than the upper limit, as shown below:
Upper Limit = L, + L,, + 0.25 L, = 1.130 wt %/ Day Lower Limit = L + L,, - 0.25 L, = 0.752 wt %/ Day o
Superimposed Verification test = 0.807 wt %/ Day The inspector concludes that, based on a review of the test results, the containment has passed its acceptance criteria for the "As-Left" condition.
Failure in the "As-Found" condition has already been acknowledged by the licensee. The inspectors informed the licensee during the inspection of their require-ments (LER, schedule for upcoming Type A tests) regarding the
"As-Found" failure. ~ Since two consecutive Type A tests failed to meet the acceptance criteria in "As-Found" condition, and in accordance with the paragraph III.A.6.(b), Appendix J,10CFR50, the licensee _ is required to perform Type A test at each refuel-ing shutdown or every 18 months, whichever occurs first.
Within the scope of this review, no violations were identified.
3.
Plant Operation Review 3.1 Routine tours of the control room were conducted by the inspectors during which time the following documents were reviewed:
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Control Room and Group Shift Supervisor's Logs; Technical Specification Log;
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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.
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The reviews dirclosed a problem with proper logging of bypassed LPRMs.
In particular, the core engineering group was not adhering to the requirements of Standing. Order No. 21 in that a bypassed LPRM was not recorded on Attachments 2 and 3.
Additionally, tours of the Control room in a few instances noted failure of plant equipment operators to adhere to control room etiquette requirements.
These cbservations were discussed with operations manageinent early.in the.
report period and no recurrences were noted.
3.2 Tours of the facility were conducted by the. inspectors - to make an assessment of the equipment conditions, safety, and adherence to
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operating procedures and regulatory requirements.
The following areas are among those inspected:
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
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The following additional items were observed or verified:
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Fire Protection:
Randomly selected fire extinguishers were accessible and
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inspected on schedule.
Fire doors were unobstructed and in tneir 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.
Appropriate fire watches or fire patrols were stationed
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when equipment was out of service, b.
Equipment Control:
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Jumper and equipment mark-ups did not conflict with Tech-
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nical Specification requirements.
Conditions requiring the use of jumpers received prompt
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licensee attention.
Administrative controls for the use of jumpers and equip-
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ment mark-ups were properly implemented.
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Vital Instrumentation:
Selected instruments appeared functional and demonstrated
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parameters within Technical Specification Limiting Condi-tions for Operation.
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Housekeeping No inspector concerns were identified.
4.
R_eview of Operational Events The inspectors reviewed details - associated with key operational events that occurred during - the report period.
A summary of these inspection activities follows:
During the plant restart sequence that commenced on 3/9/87, rod 38-07
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was not pulled to position 48 with the rest of its group and the rod worth minimizer did not prevent this error from occurring. A subse-quent review of this event by the licensee determined the rod with-drawal error resulted from operator inattention and dependence on the rod worth minimizer. The explanation for the rod worth mini-mizer (RWM) apparent malfunction was that the last rod programmed into the RWM corresponded to the last rod in the group of rods asso-ciated with rod 38-07.
Since the RWM affords group control and not rod sequence control, even though rod 38-07 was not pulled in sequence, it would not have been identified as a problem until a rod in another group was selec'.ed and movement attempted.
But because when this point was reached with rod 38-07 the RWM programmable storage capacity had been reached,.no stop was placed on moving rods in the next group.
In this particular case the RWM did not malfunc-tion. The. RWM continues to be used by the operators as an aid in assuring rod withdrawal errors are eliminated, however, as this event demonstrates, it does not always compensate for operator inatten-tiveness.
There was no impact to the fuel as a result ~of this event.
Corrective action resulting from this included modifying the rod pull check off sheets. The inspectors discussed this event in detail with operations management and emphasized the importance of operator attentiveness.
On 4/6/87, during performance of Station Procedure 645.4.018, Fire
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Pump In-Service Test, the Tech Spec required automatic initiation feature of the diesel driven fire pumps was defeated. This resulted from a combination of circumstances that consisted mainly of operator non-adherence to procedure requirements and inadequate communications between the control room operators and the operators at the fire pump house.
Paragraph 3.12.B.1.b requires that the fire suppression water system shall be operable with automatic initiation logic for each
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fire pump.
During performance of the in-service test, equipment operators at the pump house lined up the 1-1 fire diesel to pump to the fire pond (per the procedure) which made this pump inoperable.
The second pump was made inoperable after a series of procedural non-compliances resulted in an automatic st4rt of the second fire diesel.
Because the operators at the pump house could not understand why this pump started, they turned its control switch to off which defeats the automatic start feature. None of this information was transmitted to the control room in a timely manner. Although no serious challenges resulted from this ' event, the procedural noncompliances and inade-quate communications are indicative of equipment operator inatten-tiveness. The licensee identified this event and informed the NRC in accordance with Tech Spec requirements.
The inspectors discussed their concerns regarding this event with licensee management who were also concerned. Corrective actions were in progress but had not been formally documented in critique form prior to the end of this report period. Pending NRC review of licensee corrective actions, this item is unresolved (219/87-08-04),
i On April 15, 1987 an equipment operator (EO) was directed by a con-
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trol room operator to valve out the 1-1 instrument air prefilter.
Normally implied to an E0 when given directions of this nature, is to ensure that the redundant piece of equipment is valved into ser-vice before valving and tagging out the other piece.
In this case, the E0 valved out the 1-1 prefilter but did not valve in the 1-2 pre-filter. The instrument air pressure dropped to about 65 psig before the problem was recognized and corrective action taken. Had correc-tive action not been prompt, a plant trip from nearly full power would have resulted.
This is another example of operator inatten-tiveness and inadequate communications.
The inspectors discussed the above three events collectively with opera-tions management because of a concern for a trend in operator inattentive-ness and weak communications.
The inspectors will continue to review
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corrective actions to ensure effectiveness.
After completing a control rod swap on 4/11/87, the facility experi-
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enced high LPRM readings. The LPRM's for APRM 4 were slightly higher than other LPRM readings giving APRM channel 4 a high output. At approximately 90% - 93% power, the output for APRM channel 4 was approximately 103%.
The licensee attempted to adjust the APRM cur-rent gain to yield a lower APRM 4 output, but was unable to obtain lower than a 1.5 gain adjustment.
The APRMs are reportedly supposed to be able to achieve a 1.4 gain adjustment. On 4/14/87, the facil-ity experienced a half scr?m from APRM channel 4.
At this point, the licensee elected to bypass APRM channel 4 and hold at 90% power until the problem was resolved.
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The licensee compared the LPRM readings with TIP trace readings and the predicted LPRM readings for these locations to determine that no significant difference existed.
Apparently, after the rod swap on 4/11, the licensee was not able to reach the target rod pattern immediately due to an unrelated matter.
This allowed xenon to build in an undesirable fashion around the shaping rods causing the higher LPRM readings.
No fuel thermal limits were approached, however. On 4/16, the licenste moved the shaping rods previously at position 44 to position 40, the shaping rods at position 40 to position 38, the intermediate rods at position 26 to 22, and the peripheral deep rods from position 04 to position 08.
This corrected the high APRM chan-nel 4 output and the licensee was able to reach full rated power on 4/17/87.
The inspectors reviewed this activity in detail and concurred with licen-see actions.
5.
Radwaste Shipping Container Received with Free Standing Water On April 14, 1987, the licensee was notified that one of their Chem-Nuclear shipping containers, CF14170, was received at Barnwell, South Carolina with approximately 40 gallons of free standing water. The con-tainer had been filled at Oyster Creek with filter sludge material and dewatered according to procedure. The shipping container read 1500 mr on contact and held 6.3 curies.
The licensee is presently conducting an investigation to determine the cause of the free standing water in the container.
The licensee, in addition, has suspended the solidification process and has ceased radwaste shipments until the root cause is determined.
The inspectors will follow the licensee's investigation.
6.
Meetings / Briefings During this inspection period, the resident inspectors attended the Quality Assurance Annual Review.
The inspectors found the briefing to be informative.
7.
Emergency Drill The inspectors observed the March 27, 1987 quarterly drill and made the following observations:
During discussions between Emergency Director (ED) and the Group
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Shift Supervisor (GSS), it appeared the ED was somewhat unfamiliar with the Emergency Operating Procedures (EOPs). Additional training is planneo to improve ED knowledge of E0Ps.
Tne onshif t GSS maintained control room decorum and prevented drill
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participants from interfering with operators.
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14-The licensee employed the basic principles trainer to generate plant
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parameters during the scenario. This worked well until the software model broke down yielding erroneous parameters during the isolation condenser leak portion of the scenario.
The ED made good use of his support staff.
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The inspectors discussed these observations with site personnel who recog-nized and committed to address the two above-noted weaknessess.
8.
Emergency Service Water Pump Inservice Test The licensee conducted procedure 607.4.003, Containment Spray and Emerg-ency Service Water Inservice Test, on April 8, 1987.
The results indi-cated emergency service water (ESU) pumps 52C and 52D exceeded the action value of the upper limit for pump ilow. The flow was 3860 gpm for each pump, exceeding the action limit of 3800 gpm and 3700 gpm for the C & D
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ESW pump flows, respectively. Other parame+.ers of pump differential pres-sure and current were consistent with previous test data.
This occurred on containment spray /ESW system II in which an external portable flow
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measuring device is employed.
System I uses and installed annubar to measure system flow and flow values are generally indicative of actual system flow.
Concerned with regard to the System II flow measurement, the licensee installed the device on System I to obtain a flow measurement comparison against the System I annubar. Again, a flow discrepancy resulted but this time the external device indicated lower flow than the installed System I annubar. On April 12, 1987, the System was declared out of service due to the uncertainty of the System II flow.
This occurred within the 96 hour0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br /> requirement to analyze test data after completion of a test prior to mak-ing a declaration concerning pump operability as stipulated in Section XI of the ASME code.
The licensee contracted the flow measuring device ven-dor to perform ESW system flow measurements with a newly calibrated device. The vendor's measurements on System I and II indicated a flow of approximately 2500 gpm on each system.
This is below the required tech-nical specification limit of 2800 gpm.
Several iterations later the licensee measured System II flow with the external device at approximately 3100 gpm for each pump after discovering a loose connector on the external flow measuring device.
The inspectors reviewed the licensee's decision to declare System II oper-able on April 14, 1987 considering the vendor's low flow measurements with a newly calibrated device and inconsistent flow measurements produced by their own device.
The licensee explained that based on other system parameters and consistency with previous data, the system was operable.
In addition, the licensee elected to run an additional test with a dif-ferent flow measuring device from the vendor to determine the cause of the
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discrepancy in the vendor's previous device that had indicated a low flow measurement. Further, the licensee plans to install an annubar in System II.
Unresolved item 86-04-01 discusses a concern with inconsistent IST data and inability of the program to detect gradual degradation of the ESW pumps in System II.
The inspectors will follow licensee activities to ensure accurate ESW System II flow measurements are obtained.
9.
Core Spray System - Snubber and Pipe Supporc Problems During this report period, a problem was identified with Core Spray system snubbers and another with core spray system pipe supports. These problems are discussed below, a)
In late 1979 and early 1980, two Tech Spec required hydraulic snub-bers on the Core Spray System II main header were changed to mech-anical snubbers ind relocated to just outside the filter sludge room.
This change was accomplished because of the routine snubber inspec-tion requirements of the Tech Specs and the high radiation field in the filter sludge room. At the time this change was made there were no Tech Spec requirements to periodically inspect mechanical snub-bers.
Piping isometric drawing JCP 19440, Sheet 8, Rev. 2 was unex-plainably not updated to show this snubber relocation and change of type The two particular snubbers involved are identified as 411-R7
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(51/23) and 411-R8 (51/24).
In 1983 the Tech Specs were changed to add requirements to periodically inspect mechanical snubbers and an inspection in 1983-1984 identified that the snubbers were not in the filter sludge room as shown on the drawing. Additionally, a note on the data sheets of the completed 1983-84 snubber inspection proced-ure, 775.1.006, Rev. 2, noted the snubbers could not be found and were, therefore, not inspected. Subsequently, a 103.1 form was writ-ten to delete the two snubbers from the list contained in Station Procedure 775.1.006. However, the 775.1.006 snubber list identified the two new mechanical snubbers correctly including accurate serial numbers.
The net result of this was that the two Tech Spec mechanical snubbers h;3 not been inspected since their installation in 1980. This prob-lem was identified during a Bulletin 79-02 review by Tech Functions while attempting to establish an opportunity to inspect them.
Both snubbe.s were declared inoperable when the problem was identified and inspect'ons of both snubbers ensued.
These inspections determined both snubbers to be operable. Additionally, both snubbers were added to the Tech Spec snubber list.
Subsequent technical evaluation by Tech Functions determined neither snubber is required for seismic loading of the system and consideration is being given to deleting them from the list. An explanation as to why the drawing was never revised and why the snubbers were erroneously deleted from the master list was not available at the end of this report period and is an unresolved item (219/87-08-02).
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b)
A total of 13 MNCRs were written to document support discrepancies on core spray pipe supports on the full flow test lines.
Some of these are new discrepancies that have occurred since an inspection in 1985, thus inferring dynamic pipe movement curing core spray pump surveillance testing.
Licensee observations of core spray test line movement during testing have identified pipe displacements in at least one location of 5" both axially and laterally.
Root cause analysis by Tech Functions of this pipe movement and pipe support damage has determined water hammer to be the cause.
A review of piping isometrics indicates that on System II there is about 240 feet of empty pipe downstream of the full flow test valve and about 120 feet on System I.
This empty pipe experiences water hammer loading when the test valve is jogged open.
Present plans to correct the problem include attempting to more effectively throttle the test valve.
The NRC inspector expressed concern about the damaged pipe supports and the amount of pipe movement and requested Tech Functions determine the stress at the joint upstream of the test valve where the line ties into the main core spray header to ensure it is within p
design limits.
Additionally, the inspector questioned whether the stress analysis factored in impact from the damaged supports, inter-ferences with adjacent piping and structures, and the water hammer loading. These two questions were not resolved prior to the end of this report period and, therefore, constitute an unresolved item (219/87-08-03),
10. Observation of Physical Security During daily entry and egress from the protected area, the inspectors verified that access controls were in eccordance with the security plan and that security posts were properly manced.
During facility tours, the inspectors verified that protected area gates were locked or guarded and that isolation zones were free of obstructions. The inspectors examined vital area access points to w rify that they were properly locked or guarded and that access control was in accordance with the security plan.
During this report period, site security personnel reported a moderate loss of physical security involving an alarm control system idiosyncrasy.
Following identification of the problem by a Site Protection Officer, management corrective action was immediate and effective.
No concerns were identified.
11.
Exit Interview A summary of the results of the inspection activities performed during this report period were made at meetings with senior licensee management at the end of this inspection. The licensee stated that, of the subjects discussed at the exit interview, no proprietary information was included.
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