IR 05000397/1996026
| ML17292A683 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 02/05/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17292A680 | List: |
| References | |
| 50-397-96-26, NUDOCS 9702120211 | |
| Download: ML17292A683 (13) | |
Text
ENCLOSURE 2 U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.:
License No.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved By:
50-397 NPF-21 50-397/96-26 Washington Public Power Supply System Washington Nuclear Project-2 Richland, Washington December 8, 1996, through January 18, 1997 R. C. Barr, Senior Resident Inspector G. D. Replogle, Resident Inspector H. J. Wong, Chief, Project Branch E
Attachment:
Supplemental Information 9702i202ii 970205 PDR ADOCK 0500039'7
EXECUTIVE SUMMARY Washington Nuclear Project-2 NRC Inspection Report 50-397/96-26
~Oeretinne Operators responded well in recognizing, evaluating, and taking corrective actions to a reactor recirculation control adjustable speed drive system malfunction.
The licensee was continuing to investigate the root cause of the event (Section 01.1).
Maintenance
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Maintenance activities were generally completed thoroughly and professionally (Section M1.1).
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An equipment operator failed to follow procedures when testing the high pressure core spray diesel generator, which resulted in presenting operational challenges to the diesel and tripping the diesel generator on reverse power.
Contributors to the event included:
(1) inattention to detail on the part of the equipment operator; and (2) the lack of a detailed prejob brief (Section M1.2).
The licensee used an out-of-calibration total core flow instrument for Technical Specification surveillance activities.
Contributors to the oversight included:
(1) the failure to initiate a Problem Evaluation Request for a known deficiency with the instrument, in June 1996; (2) the inappropriate deferral of instrument calibration due to work planning errors; (3) the inappropriate removal of a deficiency tag; and (4) poor followup on the part of engineering for the identified deficiency.
A violation of 10 CFR Part 50, Appendix B, Criterion XII, was identified (Section M1.3).
~En ineerin During a start of standby service water Pump 1A, it unexpectedly tripped.
The licensee's immediate corrective measures in response to the event were prompt.
It
'ppears that the instanteous overcurrent trip setpoint was incorrectly set.
The NRC plans to further review this event in a followup inspection (Section E2,1).
'ee
Re ort Details Summar of Plant Status The inspection period began on December 8, 1996, with the reactor at 100 percent power.
On January 4, 1997, reactor power was reduced to approximately 93 percent, due to the tripping of reactor recirculation control (RRC) adjustable speed drive (ASD) 1A/1. On January 7 reactor power was reduced to 76 percent to support turbine bypass valve testing and remained at that level until January 8, when power was reduced to 54 percent to support ASD troubleshooting and repairs.
The reactor was returned to full power on January 9.
On January 10, power was reduced to 70 percent, due to excess power generation in the Northwest (economic dispatch).
On January 13, full power operations were again resumed.
On January 15, reactor power was reduced to approximately 68 percent when operators tripped RRC Pump A due to an ASD system, malfunction.
Reactor power was maintained at approximately 68 percent for the remainder of the inspection period.
I. 0 erations
Conduct of Operations 01.1 General Comments 71707 Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations.
The conduct of operations was generally professional and safety conscious.
01.2 ASD S stem Malfunction a.
Ins ection Sco e 71707 On January 15, 1997, operators manually tripped RRC Pump A in response to a malfunction of the ASD control system.
The inspectors were in the control room at the time of the event and observed operator actions.
The procedural and Technical Specification (TS) requirements for single loop operations were followed. The inspectors reviewed the licensee's cause determination activities.
b.
Observations and Findin s At approximately 2 p.m. on January 15, with the reactor, at 100 percent power, reactor operators (ROs) responded to average power range monitor (APRM) upscale alarms.
The ROs noticed that reactor power was erratic and varying between approximately 65 percent and 113 percent.
The ROs quickly identified the cause of the power anomaly as oscillating RRC Pump A flow.
Pump flow was varying between 50,000 gallons per minute and 20,000 gallons per minute.
RRC Pump A was subsequently tripped and operators transitioned the plant for single loop operation.
The total elapsed time from initiation of the event to tripping RRC
-2-Pump "A was approximately 50 seconds.
Operations'esponse in recognizing, evaluating, and taking appropriate actions to the event was excellent.
The plant procedural and Technical Specification (TS) requirements were followed for single loop operation.
No problems were found.
At the conclusion of the inspection period, the licensee had not determined the cause for the ASD system malfunction.
The NRC will review the licensee's cause determination and corrective actions.
This issue is considered an inspector followup item pending completion of that review (IFI 397/9626-01).
C.
Conclusions Operator response to an ASD system malfunction was considered excellent.
One inspector followup item was opened pending NRC review of the licensee's cause determination and corrective actions.
Operational Status of Facilities and Equipment 02.1 En ineered Safet Feature S stem Walkdowns 71707 The inspectors walked down accessible portions of the following engineered safety feature systems:
Residual Heat Removal Train A High Pressure Core Spray (HPCS) System HPCS Diesel Generator (DG3)
Standby Liquid Control System Reactor Core Isolation Cooling System Fuel Pool Cooling System Equipment operability, material condition, and housekeeping were acceptable in all cases.
The inspectors identified minor concerns and forwarded the information to the licensee.
No significant problems were identified as a result of these walkdowns.
Miscellaneous Operations Issues (92901)
08.1 The inspectors conducted a survey of the licensee's TS interpretations and determined that none of the documents contained informal references to NRC review and approval without formal NRC documentation.
The inspectors emphasized to the licensee that any informal reference to NRC review and approval in a TS interpretation is not recognized by the Commission and is not an acceptable practic II. Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Ins ection Sco e 62703 61726 The inspectors observed all or portions of the following work activities, as noted below:
Plant Procedures Manual (PPM) 7.4.3.1.1.35, IRM Channel F Calibration PPM 3.1.10, Operating Data and Logs Work Order (WO) CCD7-04, Fire Seal Repairs PPM 1.3.42, Troubleshooting Plan for Emergency Core Cooling System Breaker Testing PPM 7.4.8.1.1.2.12, HPCS Diesel Generator (DG) Monthly Operability Test (Documentation Review)
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WO DKJ9, Fuel Pool Cooling Pump 1A Seal Replacement PPM 7.4.4.1.2, APRM Flow Signal Channel Check (Documentation Review)
The performance of the maintenance and surveillances was acceptable in most cases.
Two issues associated with surveillance testing of DG 3 and APRMs are discussed in Sections M1.2 and M1.3, respectively.
M1.2 DG 3 Reverse Power Tri a 0 Ins ection Sco e 61726 The inspectors conducted a review of a reverse power trip of DG 3 that occurred during the performance of Surveillance Procedure PPM 7.4.8.1.1.2.12,
"HPCS DG3 Monthly Operability Test."
The inspector's followup included observation of DG 3 operation after the event, review of the completed surveillance procedure, and discussion with personnel involved with the event.
b.
Observations and Findin s On January 13, 1997, during the performance of PPM 7.4.8.1.1.2.12, and upon paralleling with Bus SM-4, DG 3 rapidly and unexpectedly loaded to approximately 3200 kW. The control room operator immediately lowered engine speed to reduce
-4-load.
Shortly thereafter, the DG 3 breaker tripped on reverse power and DG 3 was secured.
The licensee declared DG 3 inoperable, initiated Problem Evaluation Request (PER) 297-0035 and investigated the cause of the unexpected DG 3 response.
Licensee Assessment and Corrective Actions: The licensee's investigation identified that the equipment operator (EO) had failed to adhere to the surveillance procedure and had not placed the voltage regulator droop switch in the droop position.
The switch was in the isochronous position instead.
The licensee concluded that the mispositioning of the switch caused the observed response of DG 3 during paralleling.
Licensee engineers reviewed data from the plant computer, discussed the event with the DG vendor and determined that no component damage occurred as a result of this event.
The switch was then correctly positioned and the surveillance test reperformed.
DG 3 was then restored to an operable status later that day.
The licensee noted that the EO performed the procedure in a step-by-step manner and was initialing the steps as they were completed.
However, the EO inadvertently skipped over Step 17a of PPM 7.4.8.1.1.2.12, which required the repositioning of the droop switch.
The licensee's investigation noted that the step for repositioning the droop switch was recently moved within the procedure to place that step in a more logical sequence.
Prior to starting DG 3, the EO recalled that the droop switch had been repositioned during previous surveillances and recognized that he had not yet repositioned the subject switch.
Subsequently, he searched the section of the procedure where he remembered seeing the step, but did not locate it. Additionally, he overlooked the blank space where his initials were required and erroneously assumed that the step had been deleted.
The licensee considered the root cause of this event to be failure to follow the procedure (inadequate self-checking by the EO). A contributing cause was a less than adequate prejob brief. The EO involved with this event had not performed this procedure in the last year, was not aware of the procedural change, and was not trained on the change.
Had the prejob brief discussed the procedure change, the event may have been avoided:
As immediate corrective action, the licensee counseled the EO.
The licensee will determine if additional corrective actions are required at the conclusion of their event assessment.
At the close of the inspection period, the inspectors had not completed an independent assessment of the licensee's root cause determination or corrective actions.
This is considered an unresolved item pending completion of that review (URI 397/9626-02).
-5-c.
Conclusions One unresolved item was identified, associated with the failure to follow procedures when testing DG 3. The licensee determined that contributors to the event included:
(1) poor selt-checking on the part of the EO; and (2) the absence of detailed prejob briefing.
M1.3 Total Core Flow Instrumentation a.
Ins ection Sco e 61726 The plant entered single-loop operation due to ASD problems on January 15, 1997.
The inspectors reviewed documents and held discussions with licensee personnel regarding the status of the total core flow instruments that are utilized for control room indication and TS surveillances during single-loop operation.
b.
Observations and Findin s Background: At WNP-2, total core flow indication is derived from the summation of the 20 individual jet pump flow signals.
Nonsafety-related summing Circuits MS-SUM-606 (two-loop operation) and MS-SUM-608 (single-loop operation)
accomplish this function.
Total core flow indication is provided in the control room via a strip chart recorder and electronic displays.
Operators utilize total core flow indication, through Circuits MS-SUM-606 or -608, to ensure that thermal power/core flow conditions are outside of the regions of instability, as defined by TS. Total core flow indication is also utilized to perform TS Surveillance 4.3.1.1-1.2.b,
"Average Power Range Monitor Flow Signal Channel Check."
This daily check compares APRM flow indication against the total core flow reading and, thus, provides assurance that the APRM flow biased thermal power scram setpoint is accurate.
NRC Observations:
On January 17, 1997, the inspectors discussed the total core flow instrumentation with the acting (backup) system engineer and his supervisor.
During the discussion, the engineer informed the inspector that the accuracy of Circuit MS-SUM-608 was suspect and that he believed a work request (WR) was written in June 1996 to recalibrate the instrument.
The engineer also believed that the calibration work was not yet performed.
In response to the above information, the inspector reviewed the subject WR (96002615, originated on June 13, 1996).
The inspector noted that the
-6-request was assigned a Priority 1, which meant that it should be promptly resolved.
Additionally, the WR stated, in part:
"Total core flow indicates about 0 flow when one recirc pump is running and indicates flow when no recirc pumps are running... (the backup system engineer] crunched some numbers and determined it to be out of calibration..."
WO BNHO was subsequently initiated to calibrate Circuit MS-SUM-608.
However, the planner inadvertently assigned a lower priority to the work (Priority 2, which meant that the job should be worked within 5 weeks).
When the WO came up periodically for review, schedulers did not thoroughly review the details of the WO and repeatedly deferred the work, as they were unaware of the existing deficiency.
NRC Concerns:
The inspectors identified that the licensee was relying on the out-of-calibration instrument for:
(1) TS Surveillance 4.3.1.1-1.2b, and (2) ensuring that core power/flow was not in an unstable region.
Furthermore, the licensee did not know, at the time of the TS surveillances, if the instrument error was in the conservative or nonconservative direction.
Since going to single loop operation on January 15th, the surveillance which utilized the instrument was performed at least twice (January 16 and 17).
The inspectors determined that at least four barriers failed, which enabled the instrument to go uncalibrated for a period of time.
No PER was written to document the deficiency with Circuit MS-SUM-608.
PPM 1.3.12 requires that a PER be initiated for component degradation considered sudden or unexpected or outside the anticipated performance of the item.
The planner erroneously downgraded the priority of the WO. This allowed the corrective actions to be repeatedly deferred.
A deficiency tag was inappropriately removed from Circuit MS-SUM-608 in June 1996.
The deficiency tag would have provided notice to the operators that the information from the instrument could not be utilized for surveillance activities.
The licensee indicated that the tag was inadvertently removed when the WO was written.
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Engineering personnel did not perform appropriate followup of a known problem to ensure that it was resolved in a timely manner.
Technical Services Instructions (Tls), in part, specify plant management's expectations for system engineers.
Tl 2.2, "System Review," specifies that system engineers are to give special attention to WOs to aid in identifying system weaknesses.
Additionally, Tl 2.1, "System Engineer Responsibilities,"
specifies that system engineers assure the implementation of any required
-7-corrective actions for known problems.
Had engineering personnel reviewed outstanding WOs, they should have noticed that the problem with Circuit MS-SUM-608 was not resolved and then should have initiated additional corrective measures.
The licensee stated that the acting system engineer should have assumed the above noted responsibilities for this system.
However, the engineer did not fully understand these expectations.
In addition to the above, the inspector noted that PPM 1.3.1, "Conduct of Operations," Section 4.1.4, required that a prompt operability determination be made when the deficiency was first discovered.
This was not accomplished.
The cause of this oversight was not known at the close of the inspection period.
The failure to ensure that Circuit MS-SUM-608 was accurately calibrated when utilized to perform TS Surveillance 4.3.1.1-1.2b (an activity affecting quality) was a violation of 10 CFR Part 50, Appendix B, Criterion XII (Control of Measuring and Test Equipment).
This regulation requires that instruments, and other measuring and testing devices, used in activities affecting quality be properly calibrated (VIO 397/9626-03).
Licensee Corrective Actions: When the inspectors raised the concerns to plant management, the licensee took immediate actions to verify the operability of the APRM units.
The licensee determined, based on comparison to other flow instruments, that the APRMs were accurately reading drive flow. Additionally, the noted surveillance procedure was revised to perform the APRM flow surveillance utilizing alternative instruments (permitted by TS). The licensee also documented the inspector's concerns on PER 297-0069.
The licensee's immediate corrective actions were acceptable.
As a followup action, engineers obtained signal measurements from Circuit MS-SUM-608 and determined that the signal was low by about 7 percent.
This error was in the conservative direction, but this was not known previously.
Calibration data sheets required that the signal be accurate to within 1 percent.
The licensee planned to recalibrate the instrument in the'near future and initiated steps to perform a formal root cause investigation.
Conclusions One violation was identified regarding the utilization of an out-of-calibration total core flow instrument for TS surveillance activities on two occasions.
Contributors to the oversight included:
(1) the failure to initiate a PER for a known deficiency; (2) work planning errors; (3) the inappropriate removal of a deficiency tag, in June 1996; and (4) poor followup on the part of engineering personnel for the identified deficienc III. En ineerin E2 Engineering Support of Facilities and Equipment E2.1 Standb Service Water SSW Pum 1A Failure a.
Ins ection Sco e 37551 On December 20, 1996, SSW Pump 1A tripped unexpectedly.
The inspectors monitored the licensee's immediate actions and investigation into this problem.
b.
Observations and Findin s Event Description: At approximately 8 a.m. on December 20, 1996, with the plant operating at 100 percent power, operators attempted to start SSW Pump 1A from the control room.
The pump failed to start due to the tripping of the feeder breaker on instantaneous overcurrent.
In response to the pump trip, the licensee immediately declared SSW Pump 1A inoperable and entered TS Action Statements 3.7.1.1a and 3.7.1.1.d.
Additionally, DG 1 was declared inoperable, as required by TS, and TS Action Statements 3.8.1.1,a and 3.8.1.1.d were entered as well, The inspectors verified that the licensee met the TS requirements.
Enforcement Discretion:
TS Action Statement 3.8.1.1.a required, in this instance, that DGs 2 and 3 be tested within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after entering the action statement and every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter.
After initial surveillances which verified the operability of DGs 2 and 3, the licensee requested in a letter dated December 20, 1996, that the NRC exercise discretion not to enforce compliance with TS Action Statement 3.8.1.1.a.
The safety basis for the requested enforcement discretion was the elimination of unnecessary wear of the DGs.
The NRC determined that the licensee met the conditions outlined in NRC's policy regarding exercise of discretion for an operating facility, set out in Section Vll.c, of the "General Statement of Policy and Procedures for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600, and verbally granted the licensee's request on December 20, 1996.
The formal acknowledgement of the NRC's intent to exercise enforcement discretion was provided to the licensee in a letter dated December 24, 1996.
Licensee Investigation:
The licensee determined that the subject breaker trip setpoint had been reduced by approximately 30 percent during the most recent refueling outage in an attempt to improve breaker coordination at this facility.
However, the value utilized for locked rotor current in the breaker setpoint calculation was inappropriat The licensee promptly initiated corrective actions to reset the SSW pump breaker instantaneous trip setpoint.
The licensee also identified that the breaker settings for the low pressure core spray pump and residual heat removal Pump 2A could have been affected by the locked rotor current calculational methods.
'An operability determination was made, which concluded that the pumps were operable.
Nevertheless, prompt steps were taken to ensure that the breaker trip setpoints were adjusted to more appropriate values.
On December 21, 1996, SSW Pump 1A was restored to operability and the licensee exited the previously noted TS Action Statements.
Licensee Event Report 96-009, dated January 22, 1997, was submitted to address this event.
This is considered an unresolved item pending further NRC review of the licensee's cause determination (URI 397/9626-04).
c.
Conclusions
" One unresolved item was identified concerning the unexpected tripping of SSW Pump 1A. The licensee's immediate corrective measures were prompt.
The NRC plans a followup inspection to review this event.
E2.2 Review of Facilit and E ui ment Conformance to Final Safet Anal sis Re ort FSAR Descri tion A previous discovery of a licensee operating their facility in a manner contrary to the FSAR description highlighted the need for a special focused review that compares plant practices, procedures, and/or parameters to the FSAR description.
While performing the inspection discussed in this report, the inspectors reviewed the applicable portions of the FSAR that related to the areas inspected.
No problems were identified.
IV. Mana ement Meetin s
X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management after the conclusion of the inspection on January 29, 1997.
The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.
No proprietary information was identifie ATTACHMENT Supplemental Information PARTIAL LIST OF PERSONS CONTACTED Licensee R. Webring, Vice President Operations Support L. Fernandez, Licensing Manager V. Harris, Assistant Maintenance Manager R. Koenigs, System Engineering Supervisor A. Langdon, Acting Operations Manager J. Muth, Quality Support Supervisor B. Pfitzer, Licensing Engineer G. Smith, Plant General Manager J. Swailes, Engineering Director D. Swank, Regulatory Affairs Manager INSPECTION PROCEDURES USED IP 37551 IP 61726 IP 62703 IP 71707 IP 92901 Onsite Engineering Surveillance Observations Maintenance Observations Plant Operations Followup - Operations
!TEMS OPENED
~Oened 50-397/9626-01 50-397/9626-02 50-397/9626-03 50-397/9624-04 IFI ASD malfunction resulted in RRC A pump trip URI Failure to adhere to DG3 surveillance procedure VIO Out of calibration total core flow meter utilized for TS surveillances URI Failure of SSW Pump 1A
-2-LIST OF ACRONYMS USED APRM ASD DG EO FSAR HPCS IFI NRC PER PPM PST RO SSW
. RRC Tl TS URI WNP-2 WO WR average power range monitor adjustable speed drive diesel generator equipment operator Final Safety Analysis Report high pressure core spray inspector followup item U.S. Nuclear Regulatory Commission Problem Evaluation Request plant procedure manual pacific standard time reactor operator standby service water reactor recirculation control technical service instructions Technical Specifications unresolved item Washington Nuclear Project-2 work order work request