IR 05000245/1988007
| ML20151B056 | |
| Person / Time | |
|---|---|
| Site: | Millstone  |
| Issue date: | 07/01/1988 |
| From: | Mccabe E NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20151B053 | List: |
| References | |
| 50-245-88-07, 50-245-88-7, NUDOCS 8807200218 | |
| Download: ML20151B056 (18) | |
Text
{{#Wiki_filter:__ . . . .\\ .. . . U.S. NUCLEAR REGULATORY
REGION I
Report No.
50-245/88-07 Docket No.
50-245 License No.
DPR-21 Licensee: Northeast Nuclear Energy _ Company Facility: Millstone Nuclear Power Station, Unit 1 Inspection At: Waterford, Connecticut Dates: April 26, 1988 through June 6, 1988 Inspectors: William Raymond, Senior Resident Inspector Lynn Kolonauski, Resident Inspector Peter Habighorst, Resident Inspector Approved by: % O k% h 7/1/89 E. C. McCabe, Chief, R,eactor Projects Section 18 Date Inspection Summary: Inspection from April 26, 1988 to June 6, 1988 (Report No. 50-245/88-07) Areas Inspected: Routine NRC resident inspection of previously identified items, plant operations, physical security including the strike by bargaining unit security of ficers, potential ECCS suction strainer fouling, surveillance, maintenance, licensee event reports, and committee activities.
Results: The inspection identified no unsafe plant conditions.
Further licensee and/or inspector followup is warranted on: (1) potential emergency core cooling system (ECCS) suction strainer fouling and generic implications of the new single failure scenario involving the torus spray interlock (Detail 6.0), and (ii) determination of the extent of the equipment quality classification evaluation / verification procedural nonadherence (Section 8.2).
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! . . . . .< . . . TABLE OF CONTENTS Page 1.0 Persons Contacted..........
.............. 2.0 Summary of Facility Activities...
. ............ 3.0 Status of Previous Inspection Findings..
.. ........ 3.1 UNR 88-05-01, "Potential Fouling of ECCS Suction Strainers".
4.0 Facility Tours and Operational Status Reviews.......... 2 4.1 Safety System Operability.
................ 4.2 Review of Plant Incident Reports (PIRs)........
. 5.0 Physical Security.
....................... 5.1 Strike by Bargaining Security Officers
...... ... 5.2 Sleeping Guard Discovered at Vehicle Access Point.
.... 6.0 Update on Fibrous Insulation Fouling of the ECCS Suction Strainers
...... .................... 7.0 Surveillance..
............ ........... 8.0 Maintenance......
.................... 8.1 ATWS System Power Supplies
................ 8.2 Emergency Diesel Generator Speed Switch Replacement.
... 8.3 Reactor Water Cleanup System Outage.
........... 9.0 Licensee Event Reports.......
.. ........... 10.0 TI 88-01, "Fitness for Duty (Drug Testing) Information and Reporting".......
.......... ......... 11.0 Plant Operations Review Committee.
.............. 12.0 Management Meetings,
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,. , i ... . DETAILS t 1.0 Persons Contacted J. Stetz, Unit 1 Superintendent H. Haynes, Station Services Superintendent R. Palmieri, Operations Supervisor P. Przekop, Instrumentation and Controls Supervisor C. Wargo, Acting Maintenance Supervisor W. Vogel, Engineering Supervisor J. Quinn, Assistant Engineering Supervisor N. Bergh, Assistant Operations Supervisor P. Weekley, Security Supervisor The inspectors also contacted other members of the Operations, Radiation Protection, Instrumentation and Control, Production Tect, Maintenance, and Engineering departments.
2.0 Summary of Facility Activities Millstone 1 operated at full power with the exception of power reductions for routine surveillances and corrective maintenance.
On April 28, power was reduced to 32?f to allow a drywell entry for investigation and repair of an inoperable drywell cooling unit and throttling and repair of the leaking extraction steam line to the "B" intermediate pressure feedwater heaters (See Detail 4.0).
Full power operation resumed on April 30 and continued until power was reduced to 80*J on May 8 to perform a rod swap and a mussel cook. The unit was then returned to full power until May 10 when power was reduced to 70?4 to allow locating and plugging of two leaking main condenser tubes.
3.0 Status of Previous Inspection Findings (93702) 3.1 (0 pen) UNR 88-05-01: Potential Fouling of ECCS Suction Strainers.
On May 10, the licensee informed the inspector that, while l performing sizing calculations for the replacement torus suction strainers, new information was identified regarding the impact of drywell insulation on post-LOCA (loss of coolant accident) , performance of the emergency core cooling systems (ECCSs).
The licensee found that two items were not adequately accounted for in the initial analysis: (i) the Temp Mat insulation used at Millstone 1 is three times more dense than previously assumed; , and (ii) the suction strainer differential pressure evaluation did not account for calculational dependence on torus water temperature / viscosity effects.
Both parameters decrease the available net positive suction head (NPSH) for the LPCI and CS pumps.
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The licensee developed a revised justification for continued operation (JCO) which accounted for the above.
This JC0 concluded that ECCS performance would be acceptable if the LOCA thermal limit (maximum average planar linear heat generation rate, MAPLHGR) is reduced to account for decreased pump flow to the core and if the emergency operating procedures (E0Ps) are revised to account for the effects of fouled suction strainers on ECCS operability. On May 11, the MAPLHGR limit (TS Figures 3.11.a and 3.11.1.b) was administra-tively reduced by 2% (0.2 kw/ft) for the remainder of Cycle 12 and pending the submittal of a technical specification amendment request.
E0P changes were approved and issued on May 20.
The revised E0Ps provide revised NPSH curves and direct the operator to throttle LPCI and CS flow as necessary to assure adequate NPSH margin. Additional-ly, the revised E0Ps instruct the operatcrs to delay initiation of drywell spray to control drywell pressure between 20 psig and the pressure suppression pressure limit, since the present torus spray interlock, set at 4.5-5.5 psig per TS Table 3.2.2, does not assure adequate torus back pressure.
This item is discussed further in Detail 6.0 below and remains open pending completion of NRC staff review of the licensee evaluations.
This item is expanded to include NRC review of the licensee's long term resolution to the insulation debris issue, the licensee submittal of a revised technical specification for the MAPLHGR limit, and the torus spray initiation setpoint revision.
4.0 Facility Tours and Operational Status Reviews (71707) Control instrumentation was inspected for correlation between channels, proper functioning, and conformance with Technical Specifications (TSs). Alarm conditions in effect and alarms received were reviewed and discussed with the operators. Operator awareness and response to offnormal conditions were reviewed; operators were found to be cognizant of plant conditions and indications.
Operating logs and Plant Incident Reports (PIRs) were reviewed for accuracy and adherence to station procedures.
Posting, control, and the use of personnel monitoring devices for radiation, contamination, and high radiation areas were inspected. Plant housekeeping controls were observed, includina control of flammable and other hazardous materials. A backshift inspection of the control room was conducted on June 3 at 5:00 am; all shift personnel were found to be alert and attentive to their duties.
No unacceptsble conditions were identified. The following activities were also addressed.
At 3:00 am on April 28, a planned power reduction to 40% began to allow a drywell entry to repair an inoperable drywell cooling unit (HVH-21) and throttling of the leaking extraction steam line to the - .. _ .. -_ _ , _
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"B" intermediate pressure (IP) feedwater heater.
The inspector noted - thorough planning by unit management prior to and during the evolution.
During investigation in the drywell, maintenance personnel identified a broken shaft on HVH-21 as opposed to broken belts, which were originally expected. All HVH units on the middle level of the drywell were then inspected for similar damage. Two additional units, HVH-21 and HVH-18, were discovered with degraded shafts.
It appears that the bearing set-screws loosened and scored the shaf ts.
Maintenance personnel repaired HVH-21 with an available replacement shaft.
There are a total of eight drywell cooling units; Millstone 1 normally runs with seven in service and one in standby. HVH-22 was secured; HVH-18 remained in service. Drywell temperature remained near 135 F, which is below the Technical Specifica-tion (TS) limit and Emergency Operating Procedure (E0P) entry condition of-150 F.
The inspector noted that a plant equipment operator (PEO) was posted to monitor drywell temperature during the HVH repairs.
To follow the status of the inservice HVH units, operations personnel began taking HVH amperage readings daily and performed SP691, "Drywell Atmosphere Temperature Check," once per shift.
The inspector will follow licensee actions in preventing future HVH failures.
Unit management decided to lower reactor power further in order to reduce drywell radiation dose rates.
Survey histories indicated that if power was dropped to 30%, the dose rates would drop from 125-250 mrem /hr gamma and 50-75 mrem /hr neutron to approximately 80 mrem /hr gamma and S50 mrem /hr neutron. Surveys conducted at 32% power on April 28 confirmed this information. Also, because of its proximity to HVH-21, the "B" recirculation pump was secured to further lower drywell dose rates.
Total accumulated dose for the drywell entry was 1842 mrem: 1089 mrem gamma, 752 mrem neutron.
Evaluation by a regional health physics specialist found no inadequacies and concluded that no quarterly dose limits were exceeded.
. Using Special Procedure 88-1-03, operations throttled extraction steam flow to the "B" IP heater without isolating the "B" heater string.
Feedwater temperature decreased less than one degree F.
Maintenance fabricated a clamping device to enclose the nozzle, but ultrasonic test (UT) results indicated that a weld patch would be sufficient to repair the i leakage. A five-inch by five-inch carbon steel patch was welded to the nozzle area. A steam leak, located just below the weld patch, developed a few days after the repair.
Repair of the steam leak and the drywell cooling units will require a second downpower.
The inspector is following the licensee's determination of the cause of the leaks and prevention of subsequent leakage.
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All extraction steam nozzles to the f;eawater heaters were replaced in 1984, except those for the IP heaters, which were ultrasonically tested.
The original nozzles, lika these for the IP heaters, are carbon steel; the replacement nozzles have an interior CrMo'(Chromium-Molybdenum) cladding.
The licensee is considering adding IP heater nozzle replacement to the project listing for the next refueling outage, scheduled for April 1989.
The inspector followed the licensee's compliance with Technical Specifications throughout the event, including those for drywell to torus differential pressure and drywell oxygen concentration, and found no inadequacies.
The inspector had no further questions.
4.1 Safety System Operability (71707) Standby emergency systems were reviewed to determine system operability and readiness for automatic initiation.
The following systems were reviewed: feedwater coolant injection, automatic pressure relief, low pressure coolant injection, core spray, and standby gas treatment. The status of the control rod drive hydraulic control units, emergency diesel generator, and isolation condenser was also inspected.
The reviews considered, as applicable, proper positioning of major flow path valves, operable normal and emergency power sources, proper operation of indications and controls, and proper cooling and lubrication.
References used for the review included the Updated Final Safety Analysis Report, and system diagrams and operating procedures.
No inadequacies were identified.
4.2 Plant Incident Reports (71707) Selected plant incident reports (PIRs) were reviewed to: (1) determine the significance of the events, (ii) review the licensee's evalua-tion of the events, (iii) verify the licensee's response and corrective actions, and (iv) verify whether the licensee reported the events in accordance with applicable requirements. No inade-quacies were identified.
The following PIRs were reviewed: 1-88-21, 1-88-23 (See Report Detail 8.2), and 1-88-24 (See Report Detail 6.0).
The following item warranted inspector followup.
At 12:30 am on April 30, with Millstone 1 at 96% power,. control room personnel discovered that the periodic log of the 3D Monicore system reported a MFLCPR (maximum fraction of limiting critical-power ratio) of 1.001 for fuel bundle 29-30 at 11:08 pm on April 29.
The power ramp apparently produced a low xenon worth which reduced the maximum critical power in bundle 29-30.
Immediate action was initiated as required by TS 3.11.c: reactor thermal power was reduced by 30 MW and a second set of thermal limits then indicated a MFLCPR of ,
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0.995.
The inspector determined that appropriate and timely cor-rective actions were taken to restore MFLCPR below 1.0, and had no further questions.
5.0 Physical Security (81064) During station tours, the inspectors verified proper implementation of selected aspects of the station security program. These included site access controls, personnel searches, compensatory measures, adequacy of physical barriers, reporting of security events, compensatory measures, and guard force staffing and response to alarms and degraded conditions. No inadequacies were identified.
The following items required further inspector followup.
5.1 Strike by Bargaining Unit Security Officers (92709 through 92712) At 12:05 am on May 2, the station bargaining anit security afficers went on strike aftar rejecting a contract renewal offer from the security contractor, Burns International.
The security officers are represented by a local union of the United Plant Guard Workers.
In anticipation of a possible strike, the licensee had implemented a contingency plan on April 29 by placing security supervisory personnel on shift in security officer positions. The contingency force, composed of Millstone security supervisory personnel and guards from other nuclear plants under contract with Burns, reported to their posts at approximately 11:00 pm on May 1.
Picketing by union personnel at. the Burns entrance and at the plant main access was orderly and without incident.
The picketing had no effect on staffing for plant operations.
There was local media coverage of the strike.
Prior to the strike, the inspectors reviewed the contingency plan with security management and reviewed training and qualification records for the first group replacement guards. The inspector determined that the licensee could adequately staff the required security posts.
During the strike, the inspectors observed selected security activities and noted no inadequacies. Additionally, an NRC Region I security specialist periodically reviewed strike contingency , plans and implementation of secuiity measures from May 2-17, 1988.
Details are discussed in NRC Report 50-245/88-10.
The NRC identified no deficiencies in strike contingency planning.
The licensee identified and corrected a discrepancy in training records for a second group of contingency force guards, as discussed further below.
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i An agreement on a contract was reached on May 27.
Security officers e received refresher training and briefings on pertinent site changes on May 29, and returne'd to their posts on May_30.
The contract was ratified for a three year period.
Except as noted below, the inspector had no further comment on this area.
Training Discrepancy On May 9, the licensee informed the inspector-that Burns management had identified a training discrepancy for a second group of replacement guards scheduled to go on shift on May 7.
The training discrepancy was discovered in the morning of May 7 and corrected prior to the assignment of these guards to security posts.
On May 6, a Burns training supervisor had certified that training on twelve crucial watchman tasks had been completed per program require-ments. However, training was not performed completely as required for three tasks.
For crucial task 13-1A, vehicle searches, the practical exam for all members of the group consisted of "talking" each candidate through the search procedure, rather than a "hands-on" demonstration using a vehicle.
In addition, two members of the group missed the practical exam for crucial task 8-1A, conduct hands on search of personnel.
However, a training exam sheet showing satisfactory completion of the test for each candidate was provided in the Individual Qualification Records.
Also, the practical exam given to all candidates for crucial task 6-1A, vital area access authorization, did not include use of the form "Vital Area Access Log".
Training on all deficient areas was provided to the replace-ment guards prior to assignment for duty.
The licensee and Burns management completed independent investigations of this matter. The licensee concluded that there was no intent by the training supervisor to falsify training records.
The supervisor thought he was exercising his discretion for the vehicle search practical exam.
The licensee concluded the supervisor was careless in completing the practical exams and referred the matter to Burns management for appropriate disciplinary action. The inspector identified no inadequacies in the licensee's followup and treatment of this matter.
5.2 Sleeping Guard Discovered at Vehicle Access (81064} _ On May 21, at 8:05 am, a security shift supervisor discovered a sleeping guard. The guard was relieved from duty and appropriate followup actions were taken.
The guard, a Burns security trainer who is permanently assigned to the Millstone site, was temporarily i l i
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assigned to the strike contingency staff and began a twelve-hour shift at 6:00 am on May 21.
The licensee made a one-hour report to the NRC Operations Center in accordance with 10 CFR 73.71c.
The inspector had no further questions.
6.0 Update on Potential Fouling of the ECCS Torus Suction Strainers (93702) As discussed in NRC Report 50-245/88-05 and Section 3.1 of this report, the licensee's drywell insulation acceptability study concluded that a potential existed for excessive fouling of ECCS suctica strainers with insulation debris following a LOCA.
The licensee developed a second engineering evaluation using assumptions based on empirical data.
These assumptions, which the licensee considered to be more realistic than those in Regulatory Guide 1.82, showed that ECCS pump NPSH requirements would be met.
The licensee justified continued operations (as documented in a JC0 dated March 18 and revised on March 30) based on the later study and the low probabi'ity of a LOCA during the cur rent fuel cycle (based on the licensee's efforts related to tne prevention of intergranular stress corrosion cracking). The licensee plans to replace the ECCS suction strainers with larger area strainers to better assure ECCS operability under maximum credible insulation debris loading.
The Integrated Safety nssessment Program (ISAP) will determine the implementation schedule for the project, which is currently scheduled to be completed by the end df the 1989 refueling outage.
During the performance of sizing calculations for the replacement strainers, the licensee questioned the use of typical values for various parameters instead of actual or measured values.
This resulted in the identification of two items: (i) the insulation used at Millstone 1 is three times more dense than the typical value; and (ii) the range of torus water temperature and resulting viscosity effects were not accounted for in the initial pressure drop calculations.
Both of these items degrade ECCS pump flow and available NPSH margin.
The licensee developed a revised JC0 (approvec May 20) that states that ECCS performance is acceptable, provided that the LOCA thermal limit (MApLHGR) is reduced to account for the degraded ECCS pump flow, and that the E0Ps relating to ECCS operation are revised to compensate for insulation debris.
The revised calculations indicate flow reductions of 70 gpm for each CS pump and 110 gpm for each LPCI pump, assuming all six ECCS pumps are at runout conditions. An analysis by General Electric concluded that a 1% reduction in MAPLHGR would account for the resultant 20 F increase in peak clad temperature (PCT) caused by the ECCS flow reduction.
To be conservative, the licensee administratively reduced MAPLHGR by 2% (0.2 kw/ft) on May 11, and submitted a proposed technical specification change request on June 3.
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During the first ten minutes following a LOCA, no operator action is credited, and the JC0 concluded that acccytable NPSH margins would be maintained for this period.
Beyond that point, operator action would be necessary in order to ensure hCCS pump operability.
The plant operations review committee (PORC) approved the following changes to the E0Ps on May 20 to provide adequate direction to the operators.
The inspectors reviewed the associated safety evaluation and identified no concerns.
The revised E0Ps have two sets of NPSH curves, one for LOCA and one for non-LOCA events.
If drywell pressure exceeds 10 psig, a break of at least 0.01 square feet has occurred and the LOCA curves would be used. Also, the previous NPSH curves were not developeo under the assumption tnat all six ECCS pumps would be running simultaneously.
Therefore, the curves did not provide adequate protection against cavitation.
The new E0P NPSH curves were developed under the assumption that all six pumps are operating simultaneously.
The revised E0Ps instruct the operator to emergency depressurize the reactor pressure vessel (RPV) earlier in order to prevent chugging.
The operators now initiate emergency RPV depressurization when drywell pressure exceeds 15 psig instead of wnen suppression chcmber pressure exceeds the pressure suppression pressure limit.
The pressure criteria at which drywell and torus sprays should be initlated have been increased; spray is used only when containment integrity is threatened.
The inspectors did not view this as a concern because the none of the design basis accidents take credit for the sprays.
The operator is also instructed to maintain drywell pressure above 35 psia after initiation of the sprays in order to maintain adequate ECCS NPSH.
The licensee also identified that the current drywell and torus spray interlock setpoint, at 4.5-5.5 psig by TS Table 3.2.2, is too low and may
not ensure adequate NPSH.
The inadequacy of this interlock is perhaps more significant for a new single failure scenario developed by the licensee and apparently not considered by General Electric.
Licensee calculations showed that modification to the torus spray initiation setpoint is required to assure adequate low pressure ECCS pump'NPSH, independent of torus suction strainer fouling.
This may be a generic concern for other GE plants.
The scenario involves the failure of a LPCI heat exchanger outlet valve (1-LPC-4A or B) on the Emergency Service Water (ESW) side, to open.
This valve is normally closed and is opened to initiate torus cooling.
In this scenario, all low pressure ECCS pumps are operating, but only one LPCI heat exchanger is providing torus cooling.
i Based on preliminary licensee analysis, the interlock needed to ensure
adequate NPSH would be 9.0 psig. An interlock of 5.0 psig may require the operator to throttle LPCI or CS flow below a minimum acceptable value to observe the NPSH limits per the E0Ps, thus jeopardizing core or contain-ment cooling. The changes described above were necessary to assure that i d / . ..
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the design basis criteria are met, namely: (i) sufficient injection flow for core cooling to meet 10 CFR 50.46 requirement, (ii) sufficient flow for torus cooling, and (iii) the maintenance of an adequate NPSH limit at all times.
The revised E0Ps were verified and validated by licensed operators using the plant specific simulator.
Training on the revisions was provided through the requalification program, which was in mid-cycle.
The operating shifts who had already completed requalification training for the current cycle will receive class room E0P training during the next cycle, and received briefings prior to assuming the shift.
The inspectors obsersed the training provided to two separate operating crews on May 20 and 23 and found the training to be adequate.
The revised E0Ps and PAPLGHR limit will only be required for the remainder of the current fuel cycle; the licensee plans to restore them to their previous state once the strainers are replaced.
To report the above developments, the licensee submitted a supplement to LER 88-04 on May 27 pursuant to 10 CFR 50.73 (a)(2)(v) and 10 CFR 50.73(a)(2)(ii).
The licensee decided to report the torus spray interlock issue as a separate LER due to its significance and potential generic applicability. A 10 CFR 50.72 (b)(2)(ii) not!fication was made on May 27; the insoector will review the LER upon receipt.
The inspector will follow the progress of the MAPLGHR amendment request, the strainer replacement project, and the torus spray interlock issue, including the resolution of the new single failure scenario.
7.0 Surveillance (61726) The inspector observed the following surveillance tests for conduct in accordance with current approved procedures, for test result compliance with technical specification and administrative requirements, and for deficiency correction in accordance with administrative requirements.
No i unacceptable conditions were observed.
Except as noted below, the inspectors had no further comments.
-- IC 409C, "ATWS System Functional Test," on May 17 -- SP 411A, "Main Steam Line Low Pressure Functional Test," on May 24 -- SP668.1, "Diesel Generator Operational Readiness Demonstration," on May 24 The results for IC 409C were satisfactory except that the "B" channel in Division II would not trip as required at the low reactor vessel water level setpoint.
Testing was stopped pending completion of repair per Authorized Work Order 88-3792. Although there are no technical specification limiting conditions for operation (LCOs) on the ATWS r.hannels, plant operators declared ATWS Division II inoperable and - - - -- - - - - - - - - -
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initiated a priority repair order.
Licensee investigation identified a faulty power supply, which was replaced. A logic module was also replaced. See Section 8.1 for further discussions on the ATWS power supplies. The subsequent retest of channel B per IC 409C was satisfactory and Division II was returned to service on May 17.
The inspector reviewed the completed surveillance results recorded on Form 409E-1 and identified no inadequacies.
The inspector noted further that the ATWS system can be actuated by a single logic division; therefore, Division I alone would have provided the desired protection with the "B" channel inoperable.
The inspector had no further concerns.
8.0 Maintenance (62703) Tne inspectors reviewed selected aspects of the following safety related maintenance activities, including procedural adherence, obtainment of required administrative approvals and tagouts prior to wori initiation, and verification of system retest prior to return to ser vice.
Except as noted in Detail 8.2, no inadequacies were noted.
8.1 ATWS System Power Supplies, AWO 88-3792 As described in Section 7.0, Division II of the ATWS system was found inoperable on May 18 because of degraded power supplies.
Channel "B" power supplies (PSs) 6B and 3B were replaced because the output voltage did not meet the acceptable values of 15 0.2 and 12 0.2 VDC, respectively. The ATWS system tested satisfactorily upon replacement of the modules.
The ATWS system uses 14 power supplies to energize logic modules, bistable trip circuits and test circuits in the four channels.
The system uses Acopian Model D815-35 and 0812-35 AC to DC power , modules supplied by Consolidated Controls.
The ATWS system was ' installed in 1981. As of May 23, the licensee had replaced 11 of the 14 original power supply modules.
These were found degraded or failed during routine surveillance.
Because of the continued higher-than-expected failure rate, the licensee plans to increase the surveillance on the power supplies from once per operating cycle to once per quarter.
The licensee stated that the Acopian power modules are used only in the ATWS system at Millstone Unit 1.
The reportability of the failures is still under investigation by the licensee, and the irspector will follow the licensee's actions.
The inspector had no further comments on this item, and found that licensee actions to maintain and assure operability of a system important to safety were appropriate.
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8.2 Emergency Diesel Generator Speed Switch Renlacement At 5:46 am on May 24, the emergency dies 91 generator (D/G) was manually tripped upon completion of its monthly operational readiness test (SP 668.1).
The DIESEL GENERATOR RUNNING annunciator remained illuminated after the trip, indicating a failed speed switch.
The D/G was declared inoperable and a seven , day LC0 was entered as required by TS 3.5.F.2.
The inspector observed the speed switch replacement and subsequent 0/G retest from the control room and the local C/G control panel on May 24.
The inspector noted that the DIESEL GENERATOR RUNNING ANNUNCIATOR extinguished when the D/G was manually tripped.
The D/G retested satisfactorily and the TS LCO was exited at 3:05 pm.
However, on May 25, an engineering review of the Material Equipment Parts List (MEPL) revealed that 0/G speed switches have not been stocked as Category I material since 1987.
The failed switch was supplied by Fairbanks Morse as QA Category I (FM p/n 11-905-197), while the replacement part was supplied from Synchro-Start Products, Inc. as commercial grade (SS p/n SA-0684).
In response to this finding, the licensee again declared the D/G inoperable under the original entry time of 5:46 am, May 24.
The inspector obtained a copy of the MEPL evaluation conducted in 1986 (MP-1-CD-1986).
It appears that the engineer conducting the evaluation overlooked the safety related functions of the speed switch and therefore determined that the speed switch was not required to be certified as Category I.
The three separate functions of the D/G speed switch are: (i) annunciation for engine overspeed, which is not a safety related function, and input to the (ii) D/G RUNNING relay and (iii) D/G READY FOR LOADING relay, which are safety-related because they provide 0/G startup sequencing.
NCR 188-026 reports that the speed switch was inaccurately determined to be a non-QA part, and dispositions the finding oy revising the MEPL to identify the component as QA Category I.
This was accomplished by a NNEC0 engineer who completed the verification process for the original 1986 MEPL evaluation on May 25. When questioned by the inspector about the time delay between initial evaluation and peer or supervisor review, the engineer stated that there were no procedural requirements relating to the time interval between a MEPL determination and ' verification.
NCR 188-519 was written to upgrade the installed commercial grade speed switch to QA Category I.
Licensee discussions with Synchro-Start yielded the following information.
Synchro-Start , is the original supplier of the speed switches to Fairbanks i Morse, and it was possible to cross reference the manufacturer's part numbers through the serial number for the replacement speed switch (s/n 72920).
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part number of SA-0885A, which is obsolete. The recommended replacement part number is SA-0684, which matches that of the installed non-QA speed switch.
The licensee completed their verification and the D/G was declared operable at 6:15 pm on May 25.
The inspector reviewed the licensee's records and independently verified that the non-QA replacement part was an identical replacement part for the original Category I speed switch supplied by Fairbanks Morse.
The inspector spoke with a QA inspector who was assigned to observe portions of the D/G speed switch replacement on May 24; the QA inspector stated that he had questioned the use of a non-QA replace-ment part and the absence of a Material Issue rorm (MIF) in the AWO package.
His concern, as shared by the NRC inspector, was that a single individual was allowed to determine that a replacement part for use in a safety-related piece of equioment was non-QA without a required review.
The inspector reviewed the associated administra-tive control procedure, ACP-0A-4.038, "MEPL for In-Service Nuclear Generation Facilities (NEO 6.01)," and found that, according to section 6.1.2.3, the MEPL evaluation shall be verified within 60 days of receipt and prior to its 1, corporation into the MEPL, which is the quality classification list for materials, equipment and parts.
In the case of the 0/G speed switch, the MEPL evaluation was conducted on October 16, 1986, and not verified until May 25, 1988, in apparent noncompliance with the ACP. This finding remains unresolved (UNR 88-07-01) pending further licensee and inspector review to determine whether the mistake was a single occurrence or a programmatic weakness.
The questions to be answered include: (i) have other MEPL evaluations been conducted and implemented without proper and ti:nely verifications?, (ii) have other commercial grade replacement parts been used when Category I parts should have been used?, and (iii) In view of the NNECo engineer and QA inspector's apparent unfamiliarity with ACP-QA-4.03B, is the licensee staff sufficiently familiar with the MEPL evaluation and verification requirements? 8.3 Reactor Water Cleanup System Outage The reactor water cleanup (RWCU) 9ystem was secured at 3:00 am on May 25 in order to drain, cool, ind decontaminate the system to allow corrective maintenance on several RWCU system valves, including 1-CU-20A, the "A" RWCU pump discharge valve, and 1-CV-3, the auxiliary pump bypass valve. The inspector reviewed the associated AW0s and retest results and found no inadequacies.
The inspector verified retesting requirements, especially those for 1-CV-3, a primary containment group 3 isolation valve, which is regt. ired to close within 18 seconds by TS Table 3.7.1.
The valve closed in 10.
seconds on May 25. When the repairs were completed,i.
.9 filling and pressurization commenced at 6:40 pm.
At 9:30 pm, w stem was isolated and depressurized because - -
.- .. .
1-C0-63, the nonregenerative heat exchanger relief valve was lifting.
1-CV-63 was reset and system subsequently . pressurized, but 1-CV-63 again lifted at 10:15 pm.
Operations isolated the RWCU system.
Because no replacement valve was available, 1-CU-63 was removed and the relief line was capped.
The licensee determined that the design function of 1-CU-63 is not to provide protection against system rupture, but allows for thermal expansion, a function that 1-CU-56, the regenerative heat exchanger relief valve, can provide independently. -Two pressure relief valves located downstream of the main pressure control valve, 1-CU-10, provide overpressure protection. The licensee may replace the valve with the original 1-CU-63, whose internals have been rebuilt, during the next RWCU system outage.
The inspector will follow the licensee's progress in resolving this issue.
i On May 26, at 6:00 pm, reactor water conductivity reached 1.008 umho/cm as indicated by a chemistry sample; TS 3.6.C.3.b states that conductivity may increase above 1.0 umho/cm, but that it may not increase above 2.0 umho/cm for up to 15 days per incident, not to exceed four weeks per year. With repairs to 1-CV-63 completed as described above, system refill began at 9:55 pm on May 26. Reactor water conductivity dropped below 1.0 umho/cm at 1:00 am on May 27.
The inspector had no further questions.
9.0 Licensee Event Reports (92700) Licentae Event Report (LER) 88-04-01 was reviewed to assess LER , accuracy, the adequacy of corrective actions, compliance with 10 CFR 50.73 reporting requirements and to detarmine if there were generic implications or if further informacion was required.
LER 50-245/88-04-01: "Potential Fouling of ECCS Suction Strainers."
This issue is described ii Sections 3.1 and 6.0.
The issue was originally reported under 10CFR50.73 (a)(2)(vi) but, due to additional licensee findings during the resizing analysis for the ECCS suction j strainers, the LER was updated and reported pursuant to 10CFR50.73 (a)(2)(v) and 10CFR50.73 (a)(2)(ii). The inspector found no deficiencies in consideration of the above criteria.
10.0 TI 88-01, "Fitness for Duty (Drug Testing) Information and Reporting" (92701) The inspector examined records and data relating to the experien:e associated with the licensee's fitness for duty program.
Information was provided to the Region as requested by NRC Region I TI 88-0.. - - -..- _ -. .. ~.. . .. .
... , .
. 11.0 Plant Operations Review Committee;(40700) The inspector attended Plant Operations Review Committee (PORC) meetings on April 28 and May 4, 11, 20, 25,.and June 1.
Technical Specifications 6.5. requirements for committee quorum were met. The-meeting agenda included reviews of Plant Incident Reports.(PIRs), , Plant Design Change Requests (PDCRs), routine procedure revisions, special procedures, Technical Specification amendments and interin h-c anges to procedures. The inspector noted that the committee discharged their functions in accordance with regulatory requirements and observed-thorough discussions with safety emphasis. No inadequacies were identified.
12.0 Management Meetings (30703) . Periodic meetings were held with station management to discuss inspection findings during.the inspection period. A-summary of findings was also discussea at the conclusion of the inspection. No proprietary information was c. overed within the scope of the inspection.
No written material was prov1J9d to the licensee by the inspectors.
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