IR 05000282/1992021
| ML20128B688 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 11/25/1992 |
| From: | Jorgensen B NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20128B668 | List: |
| References | |
| 50-282-92-21, 50-306-92-21, NUDOCS 9212040048 | |
| Download: ML20128B688 (15) | |
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U. S. NUCLEAR REGULATORY COMMISSION REGION Ill Reports No. 50-282/92021(DRP); 50-306/92021(DRP)
Docket Nos. 50-282; 50-306 License Nos. DPR-42; DPR-60 Licensee: Northern States Power Company 414 Nicollet Mall Minneapolis, MN 55401 Facility Name:
Prairie Island Nuclear Generating Plant Inspection At:
Prairie Island Site, Red Wing, MN Inspection Conducted: September 15 through November 9, 1992 Inspectors:
M. L. Dapas D. C. Kosloff R. Mendez J. R. Roton T. J. Kobetz R. L. Bywater m
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Approved By:
B. L ge React r rojects Section 2A Date injoection Summarv n
Inspection on September 15 through November 9, 1992 (Reports No. bO-282/92021(DRP); 50-306/92021(DRP))
Areas Inspected:
Routine unannounced inspection by resident and regional inspectors of plant operational safety including onsite followup of events and outage preparation activities, licensee followup on previously identified
l items, maintenance, surveillance, outage planning team activities, licensee
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Eveat Reports, self assessment, and raJiological protection.
Results: One noncited violaticn was identified in the area of maintenance; Technical Specification (TS) setpoint limit exceeded for one main steam safety
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l valve. One noncited violation was identified in the area of Licensee Event Report (LER) followup; TS setpoint limit exceeded for pressurizer safety l
valves in three cases. No violations of NRC requirements were identified in-l any of the other six areas inspected.
One unresolved item was identified in L
the area of LER followup involving surveillance testing of check dampers in the steam exclusion system. No new strengths were identified in the areas i
inspected. A weakness was identified in management oversight of activity documentation (paragraphs 3.a and 9).
Operations No new strengths or weaknesses were identified. Operator response to indications of increasing steam generator tihing leakage, operator control
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l of forced outage activities, including reactor coolant system drain, and l
operator response to minor operating events were excellent (paragraph 2).
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9212040048 921125 PDR ADOCK 05000282 G
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Ilowever, operators made an error in controlling secondary steam pressure during a plant startup (paragraph 2). Operator errors also caused an unplanned start of an emergency diesel generator (paragraph 7.1).
Saintenance and Surveillance No new strengths or weaknesses were identified.
Activities in this area were well-organized and technician performance was excellent.
However, calibration was not initially checked for a pressure gauge used in main steam safety valve (HSSV) setpoint adjustment (paragraph 5.a.).
One noncited violation was identified in the area of maintenance (paragraph 5.a.) involving adjusting the setpoint of an MSSV.
Enaineerina and Technical Support No new strengths or weaknesses were identified.
Engineering support of plant activities was excellent as demonstrated by direction of inspection of steam generator thermal sleeves (paragraph 4.d.) and design basis reconstitution activities that identified a missed surveillance for the steam exclusion system (paragraph 7.j.).
One unresolved item was identified in this area (paragraph 7.j.) involving determination of the safety significance of the missed steam exclusion system surveillance.
Radiation Protection No new strengths or weaknesses were identified. One issue related to falsification of nonsafety related chemistry records (paragraph 9).
Radiological protection performance during the September forced outage was good (paragraph 9).
Safety Assessment /0uality Verificatio_n No new strengths were identified.
A weakness was identified in the area of management oversight of plant activities related to falsification of scaffolding records (paragraph 3.a.)
and chemistry sampling records (paragraph 9). Outage planning activities (paragraphs 2 and 6), management oversight of reactor coolant draining (paragraphs 2 and 7.h.), and response to the records falsification issue (paragraph 3.a.) were excellent. The licensee's evaluation of emergency diesel generator operability with a failed local annunciator panel and response to increasing steam generator leakage demonstrated a conservative approach to operational safety issues (paragraph 2).
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DETAILS 1.
Persons Contacted E. Watzl, General Manager, Prairie Island
- M. Sellman, Plant Manager
- K. Albrecht, General Superintendent, Engineering
- M. Wadley, General Superintendent, Operations G. Lenertz, General Superintendent, Maintenance R. Lindsey, Assistant to the Plant Manager D. Schuelke, General Superintendent, Radiation Protection and Chemistry G. Miller, Superintendent, Technical Support
- M. Reddemann, General-Superintendent, Electrical and Instrumentation Systems
- M. Klee, Superintendent, Quality Engineering
- E. Eckholt, Nuclear Support Services J. Leveille, Nuclear Support Services
- A. Hunstad, Staff Engineer J.11111, Superintendent, Instrumentation and Controls Systems J. Maki, Superinten9..t, Electrical Systems
- J. Mcdonald, Power Supply Quality Analysis S. Tasson, Production Engineer R. Pearson, Superintendent, Steam Generator Systems
- D. Kosloff, Nuclear Regulatory Commission
- Denotes those present at the management interview of November 12, 1992.
2.
Ooerational Safety Verification (71707. 93702),
a.
General Unit 1 operated at full power until September 21, 1992, when it began coastdown for the October refueling outage.
The unit continued in coastdown until September 25 when it was shut down to repair leaking tubes in No. 12 Steam Generator (SG).
During the shutdown, after the reactor was subcritical, a reactor trip occurred when a source range nuclear instrument channel over-ranged when re-energized (see pri agraph 7.m.).
Unit I was restarted on October 7 and continued to coast down until October 24 when it was shut down for refueling.
Unit 2 operated at full power until October 23, 1992, when it was shut down for maintenance and modifications, including cooling water piping replacement and electrical connection of new emergency diesel generators D5 and D6.
The inspectors observed control room operations, reviewed'
applicable logs, conducted discussions with control room operators, and observed shift turnovers.
The inspectors verified
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operability of selected emergency systems; reviewed equipment control records; verified the proper return to service of affected components; conducted tours of the auxiliary building, turbine building, and ext 4rn1 er:n of the plant to observe plant equipment conditions, includine. potential fire hazards; and to verify that maintenance wcek requests had been initiated for equipment in need of repairs.
The inspectors observed outage activities such as fuel movements, plant modifications, and reactor coolant system (RCS) drain. The inspectors also attended outage planning meetings to ascertain whether work was coordinated such that required systems remained operable and shutdown risk was minimized.
b.
Unit 1 Forced Qgtace On September 25, 1992, Unit I was shut dowin due to steadily increasing primary to secondary leakage (0.1 GPM) in No. 12 steam generator.
Technical Specifications require shutdown at a leak rate of 1.0 GPM. During the ensuing 12-day outage, the licensee performed eddy current inspection of 100 percent of the hot leg side tubes from the bottom of each tube to the first tube support plate.
The licensee identified 27 defective tubes that required plugging, all with crack indications in the tube sheet crevice region. Three of the tubes had through-wall leakage.
The crack indications were typical of secondary side intergranular stress corrosion cracking.
The inspectors observed activities associated with the draindown-to-midloop evolution to install steam generator nozzle dams for eddy current testing.
This included Operations Committee review of significant revisions to the draindown procedure, walkdown of the tygon tube RCS level indication, pre-evolution briefing, and actual RCS draindown.
The inspectors noted that the lessons learned from the February 20, 1992, interruption of decay heat
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removal event during reduced inventory operations were adequately l
addressed at the pre-evolution brief.
The inspectors observed-l that the draindown evolution was well coordinated and controlled.
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Tne inspectors observed RCS heatup and reactor startup.
RCS heatup was performed with the main steam isolation valves (MSIVs)
open for even heating of the main steam system piping.
Control room operators could not maintain an effective heatup rate with the MSIVs open once RCS temperature reached approximately 520 degrees Fahrenheit (F). The operators decided to shut the MSIVs and continue the _RCS heatup. When RCS temperature reached.
approximately 535 degrees F, the operators opened the MSIV bypass valves to more effectively control heatup rate.
No reduction of the SG power operated relief valve (PORV) pressure control
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setpoint was made when the MSIVs were shut. When RCS temperature reached approximately 545 degrees F, with a corresponding main
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steam system pressure of approximately 1036 psig, a main steam
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safety valve (MSSV) on No. 12 SG opened, resulting in a 45 psig blowdown before tha valve reseated. The licensee performed a setpoint test of an five MSSV's associated with No.12 SG.
The inspectors observed this testing,-which successfully Identified the single valve which had a low setpoint.
The valve was properly resat, as discussed in paragraph 5.a.
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c.
Diesel Instrument Probisp During the Unit 1 RCS heatup, the power supply for the D1 emergency diesel generator (EDG) local annunciator panel failed.
The licensee evaluated the loss of local alarm indications with respect to overall EDG operability and concluded that loss of this function did not render the EDG inoperable.
The licensee did not have a spare power supply available on site and determined that it would take about two weeks to procure a new one.
In response to this event, the licensee established hourly inspections of the D1 EDG.
The Operations Committee reviewed the event response and decided that an inspection of the D1 EDG every two hours would be adequate until a replacement power supply could be procured.
The licensee obtained a new power supply and replaced the failed one.
The inspectors considered the licensee's actions relative to this event indicative of a conservative operating philosophy, d.
Mit 1 Startuo The inspectors observed the Unit I reactor startup.
The preevolution brief was thorough and all questions were addressed.
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Operators demonstrated good awareness of reactivity conditions and communications were excellent.
e.
Inadvertent Safety Eouipment Auto-Start On November 5, 1992, both-diesel-driven cooling water pumps auto-started due to low cooling water header pressure resulting from the loss of No.11 Motor-Driven Cooling WV 3r Pump.
No. 11 Cooling Water Pump tripped on low suction uay level indication while work was being performed on the Unit I level indication circuit.
No. 21 Hotor-Driven Cooling Water Pump was subsequently started and the diesel-driven pumps were returned to standby, The inspectors will complete their review of this event upon receipt of the related Licensee Event Report.
No violations, deviations, unresolved, or inspection followup items were identified.
3.
Licensee Action on Previous Inspection Findinos (92701. 92702)
a.
(Closed) AMS No. RIII-92-A-0090:
Falsification of scaffolding
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checklists.
This item was identified by the inspectors and assigned an AMS number for tracking purposes.
The inspectors noted that several-checklists had not been initialed for daily
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checks on each of two consecutive days. The next day the inspectors observed that these same checklists had initials for daily checks for the previous two days. The inspectors also-found other indications that checklist data had been falsified.
NRC management reviewed the inspectors' findings and requested, in a-separate letter, that the licensee investigate this issue and re? ort the results to the NRC. The licensee responded with a letter dated October 22, 1992. On November 2, 1992, the licensee submitted a revised response with additional information. The licensee verified that scaffold checklist reewds had been falsified by one individual. The inspectors determined that the checkiist record was not an NRC-required record aH that the corrective actions discussed in the November 2, '.. 2, letter were auquate.
Failure to identify the falsification of scaffolding records is considered a weakness in the licensee's management oversight process. The licensee also identified two examples of records falsification by non-licensed operators.
These examples will be further evaluated by the inspectors during the review of Unresolved Item 50-282/92015-02; 50-306/92015-02(DRP). Other records falsification issues identified by the licensee during its investigation are discussed in paragrapl 9.
b.
(Closed) Violation 282/90012-02(DRP):
Both No. 11 and No. 12 Shield Building Ventilation Systems were rendered inoperable contrary to the requirements of Technical Specification 3.6.h.
The inspectors verified that the licensee completed procedural revisions designed to provide an additional level of review to preclude recurrence of this or similar events. To date, these actions have been effective. This item is closed.
c.
(Closed) Unresolved Item 50-282/92015-03: 50-306/92015-03(DRP):
Falsification of scaffolding checklists.
This item is discussed in paragraph 3.a. and is closed based.on that discussion.
No violations, deviations, unresolved, or inspection followup items were identified.
4.
Maintenance Observation (71707. 37700. 62703)
Routine preventive and corrective maintenance activities were observed to ascertain that they were conducted in'accordance with approved procedures, regulatory guides, industry codes or standards, and in conformance with Technical Specifications. The following items were considered during this review:
adherence to Limiting Conditions for Operation while components or systems were removed from service, approvals were obtained prior to initiating the work, activities were accomplished using approved procedures and were inspected as applicable, functional testing and/or calibrations were performed prior to. returning components or systems to service, quality control records were maintained, activit"s were accomplished by qualified personnel, radiological controls were implemented, and fire prevention controls were implemented.
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Portions of the following maintenance activities were observed or reviewed during the inspection period:
a.
Preventive maintenance (PM) of reactor trip circuit breakers.
During this PM, the licensee checked the insulation resistance on the breakers as recommended by Westinghouse. Two different materials were used for the insulators, All breakers with the older uterial failed the resistance test, and the insulators were replaced.
b.
Preventive maintenance of 480 volt ac circuit breakers.
Earlier in the year a broken wire terminal lug had been found on a 480 volt ac breaker. During the observation of the breaker PM's, the inspectors verified that there were no broken lugs. The inspectors also verified that the licensee had not found any broken lugs on other 480 volt ac breakers that had been maintained during the outage.
c.
Troubleshooting of the failed power supply for the D1 emergency diesel generator (EDG) local annunciator panel, d.
Inspection of steam generator feedwater nozzles and thermal sleeves. The licensee removed sections of main feedwater piping immediately upstream of the nozzles on the steam generators in both units. Measurements were taken of the gap between the pipe and thermal sleeve and non-destructive magnetic particle and ultrasonic testing was performed to identify any flaws in the pipe and " knuckle" region of the nozzles.
Feedwater pipe to thermal sleeve gap widening is a potential concern which may result in thermally-induced fatigue cracking of the nozzles. The inspection results indicate that some gap widening has occurred due to erosion and corrosion, but no crack indications were observed in the nozzles. The licensee plans to use NDE methods in future -
outages to trend gap width and examine the nozzles for cracking.
e.
Transfer of No. 22 Component Cooling Water Pump from old Bus No. 26 to new Bus No. 26.
f.
Transfer of No. 22 Residual Heat Removal (RHR) Pump from old Bus No. 26 to new Bus No. 26.
g.
Concrete pour for Independent Spent Fuel Storage Installation.
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h.
Replacement of failed key on RHR control valve CV-31239.
1.
Maintenance of D1 EDG. Near the completion of this maintenance an unplanned EDG start occurred due to a personnel error by an equipment operator. This event is discussed in Paragraph 7.1.
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No violations, deviations, unresolved, or inspection followup items were identified.
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5.
Surveillance (61726. 71707)
The inspectors reviewed Technical Specification required surveillance testing as described below, and verified that testing was performed in accordance with adequate procedures, test instrumentation was calibrt. id, and Limiting Conditions for Operation were met.
The inspectors further verified that the removal and restoration of affected components were properly accomplished, test results conformed with Technical Specifications and procedure requirements, test results were reviewed by personnel other than the indivlaual directing the test, and deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
Portions of the following test activities were observed or reviewed:
a.
SP 1154.8, Main Steam Safety Valve (MSSV) Test (Hot).
This test was performed when an MSSV unexpectedly opened during plant heatup.
Four of the five valves tested actuated at a pressure within one percent of the established setpoint. One valve (RS-21-6), with a setpoint of 1077 psig, actuated at 1041 psig. The licensee adjusted the spring load, retested the valve, and observed that the valve actuated within one _ percent of its setpoint. While observing the test, the inspectors questioned whether pressure gauges on the main steam header and hydroset test unit had been calibrated.
Licensee personnel conducting the test did not know the calibration status. The licensee secured the test to determine if the gauges had been properly calibrated.
The inspectors reviewed the test procedure, SP 1154.8, " Main Steam Safety Valve Test (Hot)," and noted that the signature blocks-for gauge calibration had not been initialed.
The inspectors identified that pressure gauge calibration specified in the prerequisites and initial conditions section of SP 1154.8 had not been adequately verified prior to starting the test.
The inspectors noted that the Unit 1 shift supervisor had initialed procedural step 7.1 for verification of initial conditions.
Step 7.1 states, " Verify the Unit meets the initial conditions of this procedure." The shift supervisor stated that it was the responsibility of licensee personnel actually performing the test to verify those initial conditions that were not unit specific such as gauge calibration. The licensee completed the safety valve setpoint test after retrieving calibration records that indicated the subject pressure gauges had been calibrated within the previous two weeks.
The inspectors discussed with the licensee their concern with control of testing activities.
The licensee stated it would review SP 1154.8 for improvement, The licensee concluded that safety valve RS-21-6 had been set low t
I when it was last adjusted in August 1988 due to an error in l
reading the pressure gauge on the hydraulic device used to set the MSSV's. -The l'.censee is investigating methods for improving the
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MSSV setting procedure and the hydraulic setting device to prevent-similar errors'. - TS 3.4.A.I.a requires all MSSV's'to have a lift
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setting within plus or minus 1-percent of nominal-setpoint.
Therefore, with one MSSV set at 3 percent--below -its nominal
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.This violation:
will not be subject to enforcement action because the licensee's.
efforts in identifying and correcting-the violation met the-criteria specified in Section VII.B.2 of the-" General Statement of Policy and Procedures for NRC Enforcement Actions," (Enforcement Policy, 10 CFR Part 2, Appendix C (1992)).
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b.
The ins)ectors accompanied the licensee-during the containment and shield _suilding closeout inspection. The inspection was thorough and no problems were identified, c.
SP 1314, Refueling Test of No.12 Battery, d.
SP 1548, Analog Reactor Control System Calibration.
e.
Testing of 4kV Safeguards Bus Undervoltage (UV) Logic Circuitry.
On July 27, 1992, the licensee determined that Bus No. 16 (Unit I safeguards) had exceeded the Technical Specification (TS)-
surveillance testing interval for:a portion of its UV logic circuitry. The licensee also-determined that Bus No. 26 -(Unit 2 i
safeguards) would exceed its TS surveillance testing. interval on August 5, 1992. The licensee requested a Temporary Waiver of Compliance (TWOC) from the TS surveillance requirement for both units to defer testing until the scheduled October dual-unit ~
outage. The NRC granted the TWOC, wh_ich deferred required testing until issuance of a related emergency'TS change. The NRC then issued a license amendment allowing a one-time extension of the surveillance test interval for periodic testing of the source breaker UV trip feature of the 4kV safeguards bus automatic
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voltage restoration function.
The licensee's TWOC request stated that shouldfeither unit enter cold shutdown prior to the dual-unit outage,'the deferred: testing would be completed before restart.
In September the licensee
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placed Unit 1 in cold shutdown to plug leaking tubes in No.12 i
Early in the outage, the licensee's outage
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planning team (0PT) concluded that-performing _ the surveillance test during the outage would' involve an inappropriate risk since the reactor vessel head would not be removed. The 0PT determined
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that-having the refueling cavity flooded with the head removed
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would provide an acceptable plant condition for the performance of-this test with the existing-UV restoration scheme. Therefore, the NRC, in a. letter dated October 14, 1992,- approved-the licensee's
'j request to deviate-from its original commitment to conduct ~the surveillance testing in cold shutdown. However, the NRC concluded that the licensee should have provided relevant information to the
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NRC concerning the most appropriate plant conditions for performing the subject surveillance test at the time of its
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original TWOC request.
One noncited violation was identified. No other violations, deviations, unresolved, or inspection followup items were identified.
6.
Outaae Plannina Team Review Activities (40500. 71707. 2515/113)
The inspectors observed the review by the outage planning team (0PT) of the integrated scher'u'e for the dual-unit outage.
The purpose of the
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OPT review was to irW.tify and correct scheduling conflicts that could impact shutdown risk critical safety functions such as electrical power availability, RCS inventory control, decay heat removal, reactivity control, and containment integrity.
The inspectors concluded that the
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opt review was effective in assuring adequate coordination of outage j
work activities.
The OPT maintained a clear focus on shutdown risk.
No violations, deviations, unresolved, or inspection followup items were identified.
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7.
Licensee Event Regort (LER) Followuo (40500. 92700. 92701)
a.
(Closedl LER 306/90003 and LER 306/90003. Revision 1:
Unit 2 reactor trip while troubleshooting rod control system.
This event was previously discussed in Inspection Report 50-282/90004; 50-306/90004, Section 4.c.
The reactor tripped because a piece of test equipment which had an input impedance inappropriate for the circuit being tested was used by an Instruments and Controls (I&C)
Specialist, and the Reactoi Operator reset a rod control system
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urgent failure alarm without first checking with the I&C Specialist to verify the cause of the alarm. The inspectors verified by review of licensee documents that the corrective actions discussed in the LER had been completed.
Precedure SWI-I&C-TI-2, "Section Work Instruction-I&C Section-Test Instrument Usage Control,' was developed and included directions that only instruments with input impedances of one megohm or greater could be approved for use. All I&C specialists were
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trained on the new procedure.
The annunciator response procedures for control room annunciator locations 47013-0106 and 47513-0106,
" Rod Control System Urgent Failure," were verified to contain initial actions directing the operator to refer to procedure CS,
" Rod r 1 trol System," Section 8.1, and also to notify the I&C depa
.ent.
Procedure C5, Section 8.1 was revised to add a note with an additional directive for the operators to notify the I&C department before resetting the rod control system urgent failure alarm.
Since completion of the corrective actions, no similar reportable events have occurred. This LER is closed, b.
(Closed) LER 282/90005: Auto-start of spent fuel pool special ventilation system due to electrical spiking of radiation monitor.
This was an inadvertent actuation of an ESF system.
The syste...
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functioned as expected. As long term corrective action for this LER, the licensee coh.itted to replace the radiation monitoring electronic modules wi;n upgraded modules, and to add time-delay circuits to prevent unnecessary actuation should electrical spiking occur. Upon installation, the new modules experienced multiple spurious alarms.
Since the time-delay feature had not been enabled before placing the monitors in service, t'a spurious alarms caused an unplanned actuation of the control room special ventilation system which was reported in LER 282/91002 (discussed below). Troubleshooting and evaluation of the new modules identified that the manufacturer had not conducted a 100-hour operational (burn-in) test, as specified in the purchase order.
The burn-in test was specified to expose any design deficiencies prior to shipment, and to provide time for electronic components to settle in to their normal operational characteristics.
Had the burn-in requirement been met and had the time delay feature been enabled, no spurious alarms should have occurred after installation. The inspectors verified that these actions have been completed.
It appears that these actions have been effective in preventing additional unplanned actuations of ESF equipment.
This LER is closed.
c.
(Closed) LER 28?/90006: Auto-start of spent fuel pool special ventilation system due to procedural inadequacy. This was an inadvertent actuation of an ESF system. The system functioned as expected. A work request (WR) did not include a step to temporarily disable an adjacent, redundant radiation monitor when radiation monitor R-25 was tested with a radioactive source.
Both radiation monitors responded to the source, actuating the ventilation system. The inspectors verified that the licensee has revised the WR procedure to include a step to disable the redundant monitor, and also verified that the licensee has conducted training which included the basics of procedure writing for engineering and technical staff. This LER is closed.
d.
(Closed) LER 282/90008: Shield building exhaust fan inadvertently made inoperable due to procedure error. This event was evaluated in an earlier inspection report and was considered a violation (50.W /90012-02).
The violation is closed in paragraph 3.b.
above. The corrective action for the LER was the same as that for the violation. The LER is closed.
e.
(Closed) LER 282/91001: Auto-Start of spent fuel pool special ventilation system due to unknown cause. This was an inadvertent actuation of an ESF system. The system functioned as expected.
During the performance of Surveillance Procedure (SP) 1115, " Spent Fuel Pool Special Ventilation System Test," Train A of the Spent Fuel Pool Special Ventilation System actuated after an associated radiation monitor was put in the RESET position in accordance with the SP.
The licensee conducted thorough troubleshooting of the radiation monitor in an attempt to find the cause of the unplanned actuation. No problems were identified and SP 1115 was performed
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again in its entirety.
The radiation monitors and the actuatien circuitry operated as designed.
Previous actuations of the spent fuel ventilation systems have been reported, but those events were not comparable to this event.
No similar actuations of the system have occurred. This LER is closed, f.
(Closed) LER 282/91002: Auto-start of control room special ventilation system due to spike on a newly installed radiation monitor.
This was an inadvertent actuation of an ESF system.
The system functioned as expected. The long term corrective actions for this LER are described in the discussion of LER 282/90005 above. This LER is closed.
g.
(CloseJ) LER 282/91005 and LER 282/91005. Revision 1: One pressurizer safety valve lift setpoint found 2.5 percent low during test.
During testing of spare pressurizer code safety valves, one valve that had originally been installed on Unit I lifted at a pressure 2.5 percent lower than its nominal setpoint.
Later, a licensee contractor tested the two valves that had been removed from the Unit 1 pressurizer during the Summer 1991 refueling outage. One valve lifted at a pressure 2.6 percent lower than its nominal setpoint, and the other lifted at a pressure 1.16 percent lower than its nominal setpoint. TS 3.1.A.2.b requiies that the valves be set within plus or minus 1 percent of their nominal setpoints. Therefore, this is a violation of the TS. This problem had been identified earlier at other plants and, in 1989, Westinghouse had prepared a Justification for Continued Operation (JCO) which concluded that specific actual valve setpoints outside the TS limit were bounded by existing plant analyses. The actual valve setpoints for the licensee's valves were within the JC0 limits. As a corrective action, the licensee plans to continue testing the valves with steam. This violation will not be subject to enforcement action because the licensee's efforts in identifying and correcti J the violation met the criteria specified in Section VII.B.2 of the
' General Statement of Policy and Procedures for NRC Enforcement Actions," (Enforcement Policy, 10 CFR Part 2, Appendix C (1992)).
This LER is closed, h.
(Opep) LER 306/92002 and LER 306/92002. Revision 1:
Interruption of one train of residual heat removal during a Unit 2 reactor coolant system draining operation. There were numerous licensee corrective actions for this event, including revision of the draining procedure and the conduct of pre-evolution briefings for infrequent or complex evolutions. The inspectors observed the Operations Committee review of the revised draining procedure, pre-evolution briefings and portions of two draindowns. All activities were conducted in a thorough and professional manner.
The inspectors' review of these corrective actions is complete.
The inspectors will revie
'.he remaining corrective actions in a future inspection.
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1 Closed)_LER 306/92003: Auto-start of motor-driven auxiliary
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feedwater (AP4) pump due to personnel error during surveillance
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test.
This event was discussed in Inspection Reports No. 50-282/92004(DRP); No. 50-306/92004(DRP)d(paragraphs 2.b.
and 5.).
The AfW pump that was started woul not have started if it had been placed in manual as required by the procedure.
The control room operators placed the wrong pump in manual and incorrectly independently verified that the right pump had been placed in manual. The inspectors observed tt.e licensee's recovery from this event. All equipment functioned as ex)ected, and the i
plant was restored to a normal configuration. 11e licensee counseled the operators involved and the liceasee's Error Reduction Task Force (ERTF) investigated the event.
The inspectors observed an ERTF investigator in the control room discussing the event with plant operators. Also, the procedure in use at the time, SP 2035A, was changed on April 9, 1992, to add the pump number and the switch number for the two steps which direct AFW pumps to be placed in m6nual. The procedure was also changed to add the pump number to the two steps which direct the ATW pumps to be restored to normal.
This LER is closed.
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(0 pen) LER 282/92010:
Design basis reconstitution effort identified that surveillance requirements were not being applied to steam exclusion check dampers. After review of a design basis reconstitution follow up item, the licensee concluded that Technical Specification 4.8.C required surveillance testing of check dampers as well as control. dampers. The licensee's.
immediate action for this problem was discussed in Inspection Report No. 50-282/92015(ORP); No. 50-306/92015(DRP), paragraph 5.
Some of the check dampers were s+1cky and hard to operate. At the close of the inspection period, we licensee had not determined the safety significance of the failure t' test the check dampers.
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This is considered an unresolved c.em % 282/92021-01; 50-306/92021-01) pending the intr n".or s' review 9f the licensee's determination of the safety signiticanc; of tha condition, k.
_(Doen) LER 282/92011: ASME Section it inservic-
-. pes.'on (ISI)
of longitudinal seam welds not consistently perturmed within the required time limits.
During the Spring 1992 Unit 2 refueling
outage, the licensee's Authorized Nuclear Inspector noted that longitudinal seam welds intersecting circumferential welos on main steam piping had not been examined.
The licensee's continuing investigation of inspection of similar welds disclosed several other welds that had not been inspected. The inspectors reviewed an engineering evaluation which concluded that continued operation of both units until the October 1992 outage was justified.
The inspectors did not identify any safety concerns in the engineering evaluation. A copy of the evaluation was sent to Peion III for further review by regional ISI specialists.
The reviea of this LER w'.'.1 be completed by e regional ISI specialist.
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(Closed) LER 282/92012: Auto-start of D1 Diesel Generator due to failure to use operating procedure.
The licensee intended to
" air-roll" the emergency diesel generator (EDG) after it had been i
run to remove fuel oil from above the pistons. The local EDG operator attempted to do the air-roll without a procedure in hand because he was familiar with the procch re. Ilowever, the steps'
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involved are intricate and must be dons quickly.
The o)erator made two errors during the air-roll and, as a result, tie EDG started.
The licensee allows operators to perform procedure steps without a procedure in hand if the steps involve a task that is
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"of a routine or repetitive nature." Although the air-roll is a routine task, the licensee determined that the operator's decision to perform the task without a procedure in hand was incorrect and disciplined the operator.
The licensee also counseled the o)erator and reminded o)erations personnel of the need to perform tie air-roll steps in t1e proper order.
The licensee also instructed operators to have a procedure in hand if a task is intricate in nature. This LER is closed.
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(Closed) LER 282/92013: Unit I reactor trip while subcritic?1 caused by failure of a nuclear instrumentation system source range detector.
During a shutdown of Unit 1 on September 25, 1992, a reactor trip signal was generated due to a source range high flux trip setpoint being exceeded.
The reactor was already subcritical at the time of the trip; both intermediate range neutron instrumentation channels and the redundant source range channel indications were decreasing.
The cause of the event was a failed source range detector.
It was replaced with a newer model detector that is expected to be less susceptible to corrosion and gamma radiation damage. This LER is i
closed, n.
(Closed) LER 282/92014: One Unit I steam generator safety valve setpoint found 3 percent low.
The analysis of this event in the LER was weak.
This event is discussed in paragraphs 2 and 5.a.
above and is closed based on that discussion.
One noncited violation and one unresolved item were identified; no other violations, deviations, unresolved, or inspection iullowup items were
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identified.
8.
Evaluation of Licensee Self-Assessment Canability (40500)
The insaectors routinely attended meetings of the Operations Committee (OC), tie licensee's onsite safety review committee. Meetings were conducted in accordance with the licensee's technical specification required charter. The OC meeting conducted on October 15, 1992, included review of proposed modifications, technical specification interpretations, procedure revisions, and minutes of previous OC meetings.
Reviews of proposed modifications were conducted in an atmosphere conducive to open, candid discussion with emphasis on i.
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assurance of safety and documentation of such in the modification packages.
No violations, deviations, unresolved, or inspection followup items were identified.
9.
RaAlolegiaLftpfntion_3nd Chemi11ry (71707. 921qll The inspectors identified several cases of scaffolding records f alsification (discussed in paragraph 3.a.) and, at the NRC's request, the licensee investigated other activities for records falsification.
In addition to the re:ults of the Itcensee's investigation discussed in paragraph 3.a., the licensee identified a significant case of records falsification by chemistry technicians.
Daily total halogen sampling from effluent of the plant circulating water discharge had been a
falsified by chemistry technicians.
1he inspectors determined that the halogen data was not an NRC-required record and that the corrective actions discussed in the November 2, 1992, letter were adequate.
The licensee concluded, based on its investigation, that safety-related
activities conducted by chemistry technicians and radiation protection technicians had not involved any records falsifications.
During their routine inspections, regional chemistry and radiological protection inspectors will remain alert for potential records f alsification issues, f ailure to identify the falsification of chemistry records over an extendei period is considered a weakness in the licensee's management oversight process.
lRdiological protection performance during the inspection period was good. The dose expenditure during the forced outage, which included edoy current testing of No. 12 Steam Generator, was very low at approximately 9 pe son-rem.
This represented effective planning and execuiten and is noteworthy considering the short time available for preparation for the outage.
No violations, deviations, unresolved, or inspection followup items were identified.
10-Vntpelolyed Itema Unresolved items are matters about which more information is required in order to ascertain whether they are acceptable items, violations, or deviations.
An unresolved item is discussed in paragraph 7.J.
11.
Management interniew (71707)
The inspectors met with the licensee representatives denoted in paragraph I at the conclusion of the report period on November 12, 1992.
The inspectors discussed the purpose and scope of the inspection and the findings.
The inspectors also discussed the likely information content of the inspection report with regard to documents or processes reviewed by the inspectors during the inspection. The licensee did not identify any documents or processes as proprietary,
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