IR 05000397/1998019
| ML17284A775 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 09/30/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML17284A773 | List: |
| References | |
| 50-397-98-19, NUDOCS 9810070175 | |
| Download: ML17284A775 (17) | |
Text
ENCLOSURE 2 U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket No.:
License No.:
Report No.:
Licensee:
Facility:
Location:
Dates:
Inspector(s):
Approved By:
Attachment:
50-397 NPF-21 50-397/98-19 Washington Public Power Supply System Washington Nuclear Project-2 Richland, Washington July 19 through August 29, 1998 Scott A. Boynton, Senior Resident Inspector Jim E. Spets, Resident Inspector Greg A. Pick, Acting Chief, Reactor Projects Branch E Supplemental Information 98i0070i75 980930 PDR ADQCK 05000397
EXECUTIVE SUMMARY Washington Nuclear Project-2 NRC Inspection Report 50-397/98-19 Maintenance
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The planning and implementation of the repair of a reactor recirculation system instrument sensing line socket weld were thorough and generally well executed.
The repair plan and mockup were notable strengths.
Some minor deficiencies were identified during execution of the repair (Section'M1.2).
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Material condition deficiencies were identified in the Division I 125V DC battery (low electrolyte level) and emergency diesel generator starting air system (multiple air leaks).
Although neither condition, by itself, rendered a safety-related system or component inoperable, both conditions had the potential to adversely affect equipment performance.
The processes for identifying these conditions adverse to quality, including operator rounds, system engineer walkdowns, and surveillances, were ineffective in these instances (Section 02.1).
~En ineerin
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The instructions established for troubleshooting the Division II emergency diesel generator failed to identify the inherent risk of loading the inoperable diesel generator onto its associated vital bus and, as such, failed to include appropriate contingencies and precautions.
As a result, operators did not have sufficient guidance to protect the vital bus when the voltage regulator failed and the bus deenergized on a timed overcurrent lockout. The corrective actions in response to this event were appropriate.
A noncited violation of 10 CFR Part 50, Appendix B, Criterion V, was identified for inadequate instructions during troubleshooting (Section E1.1).
The postmaintenance and operability testing of the Division II emergency diesel generator (EDG) were found to be thorough in assuring that the identified deficiencies were corrected.
However, the evaluation of the operability test procedure failed to identify that Technical Specifications (TS) prohibited the performance of portions of the procedure during plant operations.
The failure of licensee personnel to properly review TS during procedure development and approval was identified as a violation of the requirements of 10 CFR 50.59 (Section E1.1).
Re ort Details Summa of Plant Status At the beginning of the inspection period, the plant was in Mode 1 at 100 percent power. On August 5, 1998, during troubleshooting efforts on the Division II EDG voltage regulator, the plant experienced a deenergization of the Division il 4160V vital bus.
Upon reenergizing the bus, the voltage transient on Division II caused an erroneous electrical overspeed trip signal to the reactor feedwater Pump B turbine, which resulted in a feed pump trip. Power was stabilized
. at approximately 70 percent.
The plant remained at 70 percent power until August 7, when a plant shutdown was directed by plant Technical Specifications because of the inoperable Division II EDG. The plant entered Mode 3 on August 7 and Mode 4 on August 8.
During the forced outage, the licensee completed repairs to the Division II EDG and performed Technical Specification-required surveillance tests on the 125V and 250V DC vital batteries.
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The licensee also repaired a small leak in the reactor coolant system pressure boundary, located on an instrument sensing line for the reactor recirculation system.
The plant was placed in Mode 2 on August 20; and returned to power operations (Mode 1) on August 22. The plant achieved full power operation on August 23 and remained there for the balance of the inspection period.
I. 0 erations
Operational Status of Facilities and Equipment 02.1 En ineered Safe Feature S stem Walkdowns 71707 a.
Ins ection Sco e
The inspectors walked down accessible portions of the following engineered safety feature systems:
125 and 250 VDC Station Batteries Division I, II, and III Emergency Diesel Generators Control Rod Drive Hydraulic Control Units Standby Gas Treatment System b.
Observations and Findin s Division I 125V DC Batte On July 31, the inspectors found the electrolyte level on several of the cells of the Division I 125V DC battery to be below the minimum level. Although the identified
= condition did not render the battery inoperable, TS 3.8.6 required actions to complete the weekly and monthly surveillances of the battery to verify operability. These actions were completed satisfactorily and within the allowed completion times.
The vital DC batteries are surveilled weekly (on their pilot cells) and quarterly (all cells).
The last weekly and quarterly surveillances on the Division I 125V DC battery were
-2-completed on July 29 and May 15, respectively.
Neither surveillance resulted in the generation of a work request to add electrolyte.
In addition to the surveillances, the battery rooms are routinely toured by plant operators and the batteries themselves are Mralked down by the system engineer.
The system engineer had, in fact, recently performed a walkdown of the Division I 125V DC battery and did not identify a need to add electrolyte.
The system engineer, who had also just recently assumed responsibility for the station batteries, was unfamiliar with the TS action requirements when battery electrolyte levels are found to be at or below the minimum level mark.
Division I EDG Startin Air On August 10, the inspectors identified multiple air leaks on the starting air receivers associated with the Division I EDG. The most significant leak was located on the common drain header for one of the air banks and was the result of corrosion of the piping. Two other minor leaks were identified on individual air receiver drain connections on the other bank. Operation of the motor-driven air compressors was sufficient to maintain air receiver pressure above TS limits. However, the significant air leak on the one bank of receivers was requiring recharge by the air compressors approximately every 1/2 hour. The air leaks had not been identified previously by the licensee, although opportunities were available through equipment operator rounds and routine surveillance testing.
c.
Conclusions Material condition deficiencies were identified for the Division I 125V DC battery and EDG starting air system.
Although neither condition, by itself, rendered a safety-related system or component inoperable, bo'th conditions had the potential to adversely affect equipment performance.
The processes for identifying these conditions adverse to quality; including operator rounds, system engineer walkdowns, and surveillances, were ineffective.
II. Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Ins ection Sco e 61726 62707 The following maintenance and surveillances were observed and/or reviewed:
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OSP-ELEC-M703, Revision 4, "HPCS Diesel Generator Monthly Operability Test" OSP-RHR/IST-Q703, Revision 3, "RHR Loop B Operability Test" ESP-BAT-W101, Revision 2, 'Weekly Battery Testing"
-3-
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ESP-B11-Q101, Revision 1, "Quarterly Battery Testing 125 VDC E-B1-1"
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ESP-B1DG3-B101, Revision 2, "24 Month Battery Testing of 125 VDC HPCS-B1-DG3"
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ESP-B11-B1 01, Revision 2, "24 Month Battery Testing of 125 VDC E-B1-1" b.
Observations and Findin s The inspectors found that each of the activities was properly implemented and acceptance criteria were in conformance with TS. None of the activities observed were in high radiation or contamination areas; thus, radiological controls were not of concern.
Personnel performing the work demonstrated a good level of knowledge of both the activities involved and the systems affected.
M1.2 Re air of Reactor Recirculation S stem Instrument Sensin Line a.
Ins ection Sco e 71707 62707 The inspectors observed and reviewed licensee efforts to repair an identified pressure boundary leak on one of the reactor recirculation system flow instrument sensing lines.
The inspectors also reviewed the licensee's evaluation on the generic impact based upon the identified root cause of the leak.
b.
Observations and Findin s Several weeks prior to the plant shutdown on August 7, the licensee noted an increasing trend on the containment particulate radiation monitors and the drywell floor drain flow instrument.
Analysis of the floor drain effluent indicated that the leakage was from the reactor coolant system (RCS). On August 8, following entry into Mode 3, the licensee performed a containment walkdown to identify the source of the RCS leakage and found a cracked weld on the elbow of a flow instrument sensing line for the reactor recirculation system.
The instrument line makes up part of the RCS pressure boundary and is not normally isolable from the reactor pressure vessel.
The planning efforts for the repair of the instrument line, including the application of a freeze seal, were generally thorough (Work Order ¹ MVB3). Althaugh the instrument line is exempt from many of the ASME code requirements because of its size, an ASME Section XI repair plan was fullydeveloped (Repair plan ¹ 2-1574). A mockup of the pipe configuration was also constructed with a freeze seal installed and a weld made to demonstrate adequacy of the seal and to help ensure an efficient repair in the drywell.
These activities and efforts were notable strengths.
The repair of the weld, including the cutout of the affected pipe and fitup and welding of the new pipe, was also well executed.
Minor deficiencies were noted, however, in the support efforts for the repair.
First, Procedure 10.2.97, Revision 0, "RRC Freeze Seals Using Liquid Nitrogen," requires the performance of a prefreeze seal checklist evaluation that, in part, includes the specification of the freeze seal location on a flow
diagram.
The isometric drawings of the affected piping that were included in the work package did not specify the location of the seal. The inspector considered this a weakness, as the contractor performing the freeze seal was experienced in the application and, when questioned, understood the placement limitations on the freeze location. Second, during the prejob brief, licensee personnel concluded that, without the availability of a remote camera to monitor the freeze seal, as a contingency it would be acceptable to allow the contractor to enter the drywell every 15 minutes to evaluate the.
adequacy of the frost line. The inspector found that the contingency was contrary to Procedure 10.2.97, which requires continuous monitoring of the seal and questioned the licensee on the adequacy of the proposed monitoring. Subsequently, the licensee ensured that a camera was installed to remotely monitor the freeze seal prior to the start of work. Third, the job hazards analysis performed for the evolution called for an oxygen monitor at the job site because of the use of nitrogen and argon in the vicinityof the repair.
However, following the initiation of nitrogen to the freeze seal, the inspector identified that the oxygen monitor, staged at the job site, had not been turned on.
Fourth, Procedure 10.2.97, Step 6.1.6, states that "in the vicinityof the freeze seal, use temporary covers or catch devices as appropriate to protect plant equipment from liquid nitrogen spills." To address this step, maintenance personnel agreed to utilize a plastic tarp under the freeze jacket. However, installation of the tarp was forgotten until after the freeze seal was initiated and it was identified that liquid nitrogen was leaking from the jacket. The observed weaknesses did not impact the overall quality of the work.
The analysis of the failure of the socket weld found that the crack initiated at the inner diameter of the weld because of an acute loading (most likelyfrom personnel using the pipe as a hand or foot hold). Crack propagation to the outer diameter of the weld resulted from cyclic fatigue generated by operational vibration of the recirculation line.
Because of the nature of the failure, the licensee performed nondestructive liquid dye penetrant testing on other similar instrument line configurations in the drywell. No other deficiencies were identified. The corrective actions were appropriate to address the initial concern and potential extent of condition.
C.
Conclusions MS The planning and implementation of the repair of a reactor recirculation system instrument sensing line socket weld was thorough and generally well executed.
The repair plan and mockup were notable strengths with some minor deficiencies identified during execution of the repair.
Miscellaneous Maintenance Activities (62707)
'vI8.1 Closed Licensee Event Re ort LER 50-397/98-015-00:
Discoveryof coolant pressure boundary leak during shutdown conditions.
The details surrounding the subject LER and the corrective actions are discussed in Section M1.2 abov III. En ineerin Conduct of Engineering Troubleshootin and Re air of the Division II Emer enc Diesel Generator Ins ection Sco e 37551 61726 62707 On August 4, the licensee declared the Division ll EDG inoperable during monthly surveillance testing when the generator failed to maintain'teady output voltage and YARS (units of reactive power). The inspectors evaluated the activities associated with troubleshooting and repair of the EDG. The evaluation included the adequacy of the root cause determination and postmaintenance testing to return the EDG to operable status.
Observations and Findin s EDG Volta e Re ulator Troubles hootin The licensee developed several troubleshooting plans in accordance with Procedure 1.3.42, Revision 16, "Troubleshooting Plant Systems and Equipment."
Based upon the output fluctuations observed during the monthly surveillance, the troubleshooting focused upon the automatic voltage regulator, static exciter, and motor-operated potentiometer as potential causes.
As defined by Procedure 1.3.42, the troubleshooting was considered low risk. Low risk is defined as troubleshooting activities that have no potential to affect safe plant operations and are limited to: (1) out of service equipment, (2) equipment in bypass or isolated, or (3) electrical readings except for pow. upplies and logic on plant equipment that has an actuation/isolation function.
From initial testing, the licensee concluded that the performance of the Phase A silicon controlled rectifier (SCR) of Bridge 1 of the static exciter was degraded.
Subsequent troubleshooting was performed using SCR Bridge 2 of the static exciter. The troubleshooting plan was, again, considered to be of low risk even though the diesel was being loaded onto an operable vital bus.
During testing on SCR Bridge 2, while the EDG was paralleled with the startup transformer via Bus SM-3 (4160V nonvital bus) and loaded to approximately 75 percent of full load, an unexpected step increase in EDG output voltage and VARS occurred.
Operator actions to reduce the VARS output were unsuccessful and a bus lockout of the Division ll 4160V bus (Bus SM-8) was received.
The lockout resulted from a timed overcurrent trip condition on the Bus SM-3 supply breaker to Bus SM-8. The lockout opened the EDG feeder breaker to Bus SM-8 and precluded the backup transformer feeder breaker from closing in, thus deenergizing the bu r In review of the event, the inspectors concluded that the operations and engineering personnel involved did not adequately define the level of risk associated with the troubleshooting and did not establish sufficient contingencies for unexpected system responses.
Procedure 1.3.42 defines high risk troubleshooting as troubleshooting performed on equipment in service that could cause or result in an unexpected load reduction, plant transient, reportable event, etc. Although the EDG was considered.to be inoperable, the EDG was placed in service and loaded onto its associated vital bus.
Thus, the potential existed for the troubleshooting activities'to cause an unexpected plant transient.
Based upon the definitions in Procedure 1.3.42, the licensee concluded in its review of the event that the troubleshooting should have been classified as high risk and that additional precautions and limitations, beyond those defined in the normal system operating procedure, should have been established for the troubleshooting.
As an example, the timed overcurrent lockout of the Bus SM-3 feeder breaker occurred 16 seconds'after the initiation of the high voltage condition. The time delay provided sufficient time for operators to identify the condition and trip the EDG had.contingency actions been established to do so. Additionally, had the troubleshooting been properly characterized as a high-risk evolution, further reviews and approvals would have been required that may have borne out the additional precautions needed to safely execute the activity.
To address the performance weaknesses identified during the troubleshooting of the EDG, the licensee initiated Problem Evaluation Request (PER) 298-1069 to evaluate and implement improvements in troubleshooting activities.
In resolving PER 298-1069, the licensee concluded that both plant staff inexperience and a lack of training contributed to observed performance problems. To resolv'e these issues, corrective actions were put in place to develop a training module for troubleshooting that would be provided to responsible plant staff. The licensee also established a plan to send several key engineering personnel to an offsite training course on troubleshooting.
The inspector concluded that these actions, coupled with the expectation that more experienced staff members would act as mentors ~~ advise less experience~ nersonnel during troubleshooting, would effectively resolve the performance issues.
10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings,"
requires, in part, activities affecting quality to be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances.
The failure of the troubleshooting plan for the EDG voltage regulator, an activity affecting quality, to appropriately categorize the inherent risk of the activity and est< blish adequate precautions and contingencies, was identified as a violation of 10 CFR Part 50, Appendix B, Criterion V. This nonrepetitive, licensee-identified and corrected violation is being treated as a noncited violation, consistent'with Section VII.B.1 of the NRC Enforcement Policy (50-397/9819-01).
Root Cause and Postmaintenance Testin Data obtained during the troubleshooting showed that two of the SCRs on Bridge 2 were not firing properly and that performance of the voltage regulator was degraded.
The licensee concluded that these components directly contributed to the voltage and VARS
-7-instabilities and replaced both the voltage regulator and the SCRs on Bridge 1. The SCRs on Bridge 2 were not replaced as Bridge 2 is considered an installed spare.
To setup and test the new components, the licensee developed Procedures 8.3.217, Revision 2, "DG1/DG2 Static Exciter Voltage Regulator Setup and Test," and 8.3.405, Revision 0, "Diesel Generator (DG-2) Operability Verification Following Voltage Regulator Changeout."
The licensee's evaluation of the procedures, in accordance with 10 CFR 50.59, did not identify an unreviewed safety question or the need to make a change to TS. However, in discussions with the licensee on the scope of testing covered by Procedure 8.3.405, the NRC staff determined that a load rejection test would be performed.
The staff questioned the licensee on the ability to perform that test while the plant was at power. TS Surveillance Requirement 3.8.1.10, which defines the requirements for performing a load rejection test of the EDGs, explicitlyprohibits the performance of the test while the plant is operating in Modes 1 or 2. The licensee subsequently shut down the plant to, in part, complete the EDG testing in accordance with Procedure 8.3.405.
10 CFR 50.59(a)(1) states that the licensee may make changes in the procedures, as described in the Final Safety Analysis Report (FSAR), without prior Commission approval, unless the proposed change involves a change to the TS or an unreviewed safety question.
Procedure 1.3.43, Revision 13, "Licensing Basis Impact Determinations," reiterates the requirements of 10 CFR 50.59 and provides guidance for their implementation.
Attachment 6.2 of Procedure 1.3.43 states that it is the responsibility of the preparer and reviewer to properly determine if an activity involves a change in TS or the operating license.
To determine this, a thorough review of TS and the operating license is required.
From discussions with licensee management, it was determined that none of the personnel involved in developing and approving Procedure 8.3 405 properly reviewed the applicable TS. The failure to perform these reviews was considered to be a fundamental lapse in implementing the requirements of 10 CFR 50.59. The approval of Procedure 8.3.405, which authorized the performance
of a load rejection test in Mode 1, conflicted with the limitations of TS Surveillance Requirement 3.8.1.10 and was identified as a violation of 10 CFR 50.59 (50-397/9819-02).
To address the performance issues regarding the approval of Procedure 8.3.405, the licensee initiated PER 298-1024.
Through resolution of the PER, the licensee concluded that personnel involved did not followthe established process for evaluating procedure revisions.
The licensee also concluded that time pressures contributed to the error. To correct these performance issues, licensee management issued a memorandum to plant staff reiterating expectations for maintaining a focus on safety.
These expectations included:
When generating documents (e.g., procedures, 50.59s, design changes, equivalencies, calculations, etc.), thoroughly review hard copies of related design and licensing basis documents, including applicable FSAR and TS sections; When performing plant activities, place heavy emphasis on the TS requirements.
Thoroughly review the hard copy of applicable T As preparers or reviewers of documents, plant staff responsibilities included:
(1) ensure the contents of the documents are complete and accurate; (2) thoroughly review hard copies of related design and licensing bases, including applicable FSAR and TS sections; (3) do not rely on memory. Verify information, assumptions, and references.
Refer to procedures; (4) take the time to do the job right. Do not let perceived schedule pressure be a distraction, (5) let management know when additional expertise is needed; and (6) ask for help, if needed.
The operations, engineering, and maintenance departments were also scheduled to review PER 298-1024 during an upcoming staff meeting to reemphasize the performance problems and the points made in the memorandum.
The corrective actions were considered to be appropriate.
While in Mode 4, the licensee completed the setup and testing of the new voltage regulator.
Results of the testing demonstrated satisfactory performance of the new voltage regulator and static exciter. The corrective actions to address the EDG voltage regulator failure were found to be appropriate.
However, during subsequent operability testing of the EDG, an unrelated failure occurred when the EDG output breaker failed to close on a loss-of-power test.
EDG Out ut Breaker Licensee efforts to isolate the cause of the failure of the EDG output breaker to close were defined by multiple troubleshooting plans to evaluate individual components and circuits involved in the closing logic interlocks for the breaker.
Eleven separate troubleshooting plans were implemented.
The initial troubleshooting plans did not
,. provide a clear basis for the scope of troubleshooting nor did they demonstrate a
methodical approach to the root cause.
The individual plans addressed performance of specific components that could have led to the failure of the breaker to close, but'the plans did not effectively duplicate the conditions experienced by the breaker when it failed. This lack of coordination was overcome when additional oversight of the troubleshooting activities was provided by personnel who did not have direct responsibility for the equipment.
This objective oversight effectively focused subsequent troubleshooting and directly contributed to the successful identif'".ation of the root cause.
Root Cause and Corrective Action The licensee identified that the 125/24 VDC power supply to the EDG speed switch circuitry was undersized for its application. That is, the 750 mA load of the speed switch circuit significantly exceeded the 330 mA rating of the power supply. As such, when the diesel accelerated to rated speed and the speed interlock relays energized, including the interlock allowing the EDG output breaker to close, the current draw on the power supply caused output voltage to drop to as low as 13 VDC. Although this lower voltage was sufficient in the past to pick up all of the relays in the circuit, normal aging of the
-9-relays and the power supply eventually led to the failure of the EDG output breaker speed interlock relay from closing in, thus preventing the output breaker from closing.
To correct the identified design deficiency, the licensee implemented a design change to install a new 125/24 VDC power supply with a 1.8 A rating. From a review of the design change package and the postmaintenance test results, the inspectors concluded that the design change was properly implemented and effectively corrected the deficiency.
The power supply was also replaced in the Division I EDG because of its speed switch circuit having an identical design to that of the Division II EDG. The Division III EDG was also evaluated and the licensee determined that it was not susceptible to a similar deficiency. As of the end of the inspection, the licensee had not completed evaluation of the common mode failure of the Division I and II EDG output breakers to close because of the power supply design deficiency. An unresolved item willbe opened to track the licensee evaluation and characterize the regulatory significance of the issue (50-397/9819-03).
Conclusions The instructions established for troubleshooting the Division II EDG failed to identify the inherent risk of loading the inoperable diesel generator onto its associated vital bus and, as such, failed to include appropriate contingencies and precautions.
As a result, operators did not have sufficient guidance to protect the vital bus when the voltage regulator failed and the bus deenergized on a timed overcurrent lockout. The licensee's corrective actions in response to this event were appropriate.
A noncited violation of 10 CFR Part 50, Appendix B, Criterion V, was identified for inadequate instructions during troubleshooting The postmaintenance and operability testing of the Division II EDG were found to be thorough in assuring that the identified deficiencies were corrected.
However, the evaluation of the operability test procedure failed to identify that TS prohibited the performance of portions of the procedure during plant operations.
The failure of licensee personnel to properly review TS during procedure development and approval was identified as a violatiop of the requirements of 10 CFR 50.59 ES Miscellaneous Engineering Issues (37551, 61726, 62707)
E8.1
'sed LER 50-397/98-013-00:
engineered safety feature actuations because of deenergization of vital electrical bus SM-8.
The details associated with the subject LER and the corrective actions are discussed in Section E1.1 above.
E8.2 Closed Licensee Event Re ort 50-397/98-014-00:
completion of TS 3.8.1.f required shutdown because of inoperability of EDG-2.
The details associated with the subject LER and the corrective actions are discussed in Section E1.1 abov V. Mana ement Meetin s X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management on September 24, 1998. 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 Licensee PARTIALLIST OF PERSONS CONTACTED F. Diya, System Engineering Manager
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R. Hermann, System Engineer, Emergency Diesel Generators D. Hillyer, Radiation Protection Manager P. Inserra, Licensing Manager J. McDonald, General Engineering Manager G. Moore, System Engineer, Station Batteries S. Oxenford, Operations Manager M. Rice, Electrical Systems Supervisor G. Smith, Plant General Manager INSPECTION PROCEDURES USED IP 37551:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
Onsite Engineering Surveillance Observations'aintenanceObservations Plant Operations Plant Support
~Oened 50-397/9819-01 50-397/9819-02 50-397/9819-03 Closed 50-397/9819-01 ITEMS OPENED, CLOSED, AND DISCUSSED NCV Inadequate troubleshooting efforts on the EDG voltage regulator (Section E1.1).
VIO Inappropriate approval of test procedure that involved a change in Technical Specifications (Section E1.1).
URI Common mode failure of the Division I and II EDG output breakers to close because of power suppl I design deficiency (Section E1.1).
NCV Inadequate troubleshooting efforts on the emergency diesel generator voltage regulator (Section E1.1).
50-397/98-013-00 LER Engineered safety feature actuations because of deenergization of vital electrical bus SM-8 (Section E8.1).
-2-50-397/98-014-00 LER Completion of TS 3.8.1.f required shutdown because of inoperability of EDG 2 (Section E8.2).
50-397/98-015-00 LER Discovery of coolant pressure boundary leak during shutdown conditions (Section M8.1).
LIST OF ACRONYMS USED CFR EDG FSAR IFI LER NCV NRC PDR PER RCS SCR TS URI VIO WNP-2 Code of Federal Regulations emergency diesel generator Final Safety Analysis Report inspection followup item licensee event report noncited violation U.S. Nuclear Regulatory Commission public document room performance evaluation request reactor coolant system silicon controlled rectifier Technical Specifications unresolved item violation Washington Nuclear Project-2
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