IR 05000498/1997003
| ML20140D516 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 06/05/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20140D474 | List: |
| References | |
| 50-498-97-03, 50-498-97-3, 50-499-97-03, 50-499-97-3, NUDOCS 9706100403 | |
| Download: ML20140D516 (17) | |
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ENCLOSURE 2 U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos: 50-498;50-499 License Nos: NPF-76; NPF-80 i
Report No: 50-498/97-03;50-499/97-03 i Licensee: Houston Lighting & Power Company Facility: South Texas Project Electric Generating Station, Units 1 and 2 Location: 8 Miles West of Wadsworth on FM 521 Wadsworth, Texas 77483 Dates: April 6 through May 17,1997 Inspectors: D. P. Loveless, Senior Resident inspector J. M. Keeton, Resident inspector W. C. Sifre, Resident inspector R. A. Kopriva, Project Engineer, PBA B. J. Olson, Project Engineer, PBE Approved by: J. l. Tapia, Chief, Project Branch A Division of Reactor Projects 9706100403 970605 PDR ADOCK G5000498 O PDR -
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EXECUTIVE SUMMARY t
l l South Texas Project, Units 1 and 2 NRC Inspection Report 50-498/97 03;50-499/97-03 i
This resident inspection included aspects of licensee operations, engineering, maintenance, ,
and plant support. The report covers a 6-week period of resident inspectio '
Ooerations
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o Licensed operators in both control rooms were routinely observed performing their
' i duties in a professional manner with a good focus on safety (Section 01.0). !
- The decision to manually trip the Unit 2 reactor due to low water levelin one steam generator was considered conservative and appropriate. Operator response to the
! reactor trip was excellent (Section 01.2).
- -The licensee staff identified a violation of the licensed operator requalification l requirements for assuring alllicensed operators complete continuous requalification
- training. Corrective actions for this licensee identified violation have been
- implemented (Section 05.1),
e One noncited violation was identified because Standby Diesel Generator 12 had l been technically inoperable during a mode change. This was a licensee identified i
and corrected violation (Section 08.3). j Maintenance l * Observed maintenance and surveillance activities were well performed in accordance with station procedures (Section M1.1).
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l e Trouble-free response of Unit 2 plant equipment following the reactor trip was indicative of excellent material condition (Section 01.0).
Enaineerina l e Engineering response to the main steam safety valve problem was good. Use of l industry experience was notable (Section E2.1). .
e = Coordination among the engineering, operations, and maintenance organizations was very good upon discovery of a sealleak of Containment Spray Pump 1B (Section E2.2).
l Plant Support
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- Observed activities involving radiological controls, maintenance of emergency ;
j response facilities, and security were performed in a professional manner i (Sections R1.1, P2.1, and S1.1). I
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l Report Details
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Summary of Plant Status t L At the beginning of this inspection period, Unit 1 was escalating power to 100 percen l l
' After achieving 100 percent power on April 6, the unit remained at 100 percent power for ;
the remairider of the reporting perio l
At the beginning of this inspection period, Unit 2 was at 100 percent power. On April 30, !
l the unit was manually tripped because of low water level in Steam Generator 2D. After j appropriate repairs to the feed water regulating valve control circuitry, the unit was restarted. ' On May 2, the main generator output breaker was closed, and 100 percent ,
power was achieved on May 4. The unit remained at 100 percent power until May 17 when the unit was down-powered to perform maintenance on Main Transformer 28. The :
unit was at 13 percent power at the end of this inspection period.
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- l. Operations
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01 Conduct of Operations ,
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01.1 Control Room Observations (Units 1 and 2)
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I Insoection Scope (71707)
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Using Inspection Procedure 71707, the inspectors routinely observed the conduct of operations in the Units 1 and 2 control rooms during normal full power operatio The observations included: frequent reviews of control board and engineered safety features equipment status; routine attendance at shift turnover meetings;
observations of operator performance; and reviews of control room logs and ;
documentation, Observations and Findinas The inspectors observed good procedure usage in the control roorn Communications were generally formal. Annunciator alarm responses were prompt and the alarm status appropriately dispositioned. Operators' .use of self-verification techniques was evident. The engineered safety features systems in both units were verified to be aligned in accordance with Technical Specification requirements during various plant operating condition , Conclusions The inspectors concluded that the operators continued to perform their duties in a professional manner.
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l 01.2 Manual Trio Followina Feedwater Reaulatina Valve Failure (Unit 2) Inspection Scope (93702)
On April 30, with Unit 2 operating at 100 percent power, operators initiated a manual reactor trip when the Steam Generator 2D water level decreased to 35 percent. The inspectors responded to the control room and observed the operators' response to this event. Following reactor coolant system stabilization, the inspectors reviewed the following licensee documents:
- Plant Operating Procedure OPOP05-EO-E000, Revision 8, " Reactor Trip or Safety injection"
Plant Operating Procedure CPOP05-EO-ES01, Revision 12, " Reactor Trip Response"
- Plant General Procedure OPGP03-ZO-0022, Revision 4, " Post-Trip Review Report" o Condition Report 97-8029
- Event Review Team Report e Event Notification Worksheet Observations and Findinas Prior to the trip, a licensed operator observed that feedwater flow to Steam Generator 2D was oscillating. The operator placed the main feedwater regulating valve controller in manual in an attempt to stabilize feedwater flow. When the controller was placed in manual, the controller indicated a zero flow demand and the valve began closing. The operator responded by manually increasing the flow demand on the controller. This action resulted in the valve opening as expected, however, the controller indicated 100 percent flow demand. The operator then attempted to adjust the controller and the flow demand again went to zero. By this time, water level in Steam Generator 2D was decreasing. As the level approached 35 percent on the narrow range indicators, the shift supervisor directed the reactor
- operator to manually trip the reactor. The automatic trip setpoint level was
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33 percent.
l All control rods fully inserted into the core and all safety systems functioned properly following the trip. The main feedwater system isolated on low average temperature and the auxiliary feedwater system actuated on low steam generator water level. The inspectors observed licensed operators as they followed plant operating procedures throughout the recovery. Controls were manipulated in a
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careful and methodical manner. Shift supervision provided appropriate levels of oversight in ensuring that plant parameters were being maintaine Subsequent licensee investigation identified two failed integrated circuits on th j controller-driver card in the Main Feedwater 2D regulating valve controller. The
' f ailed card caused the controller to oscillate in the automatic mode. In the manual mode, the valve position followed the controller demand. The failed card caused the controller to indicate maximum or zero demand when the setting was either raised or lowered. Reactor operators responded appropriately and conservatively in performing a manual reactor tri The inspectors reviewed the post trip review report. No deficiencies were note The plant systems responded well following the trip. All plant equipment functioned i as expected, with the exception of one secondary system valve. This was-indicative of excellent material condition of the plant systems and equipment prior '
to the trip.
, Conclusions The licensed operators decision to manually trip the reactor was both appropriate f and conservative. Operator response to the transient and following the reactor trip was considered excellent. The response of plant systems and equipment following !
the reactor trip was indicative of excellent material conditio Operational Status of Facilities and Equipment O2.1 Plant Tours (Units 1 and 2) Insoection Scoce (71707)
i The inspectors routinely toured the accessible portions of plant areas in Units 1 and i 2. Areas.of special attention during this inspection period included:
- Units 1 and 2 turbine-generator buildings :
- Units 1 and 2 mechanical-auxiliary building
- Unit 2 reactor containment building
- Units 1 and 2 circulating water intake structure :
- Units 1 and 2 electrical-auxiliary building '
5 Observations and Findinas The inspectors observed that systems and components had been maintained in i j good material condition in both unit On May 2,1997, the inspector accompanied a crew of electricians in the Unit 2
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l reactor containment building while the unit was in Mode 3. The crew entered the l
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area inside the bioshield to perform a final walkdown and inspection of the reactor ;
coolant pumps prior to entry to Mode 2. The crew had continuous health physics coverage in accordance with their radiation work permit. Housekeeping in the areas ,
toured was excellent. The areas were free of debris that could potentially clog the '
emergency sump screens. Sampled high radiation area doors were locked.
l Conclusions i The inspectors concluded that the material condition of systems and components I
, observed in both units was noteworthy. Housekeeping in the Unit 2 reactor '
l containment building was excellen q l 05 Operator Training and Qualification i
05.1 Licensed Operator Participation in Recualification (71707)
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,. Insoection Scope I
l During the inspection period, the i apectors reviewed the status of licensed operator and senior operator participation in the licensee's continuing requalification training program.
l l Observations and Findinos l
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l The inspectors were informed by licensee personnel that a senior reactor operator l had not been attending requalification training because his license had been
- administratively suspended from January 1996 until April 1997 while he was in a ( position that did not require a license. The licensco planned to activate the l L individual's license because the individual was being reassigned to a position which '
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required the use of his license. The inspectors determined that the licensee's planned remediation program included the successful completion of a comprehensive written examination and operating test before restoring the l l administrative functions of his license or allowing him to perform the parallel ;
watchstanding required to make his license activ l 10 CFR 55.59(a) requires that each holder of an operator license complete a requalification program developed by the licensee that has been approved by the Commission and that the program be conducted for a continuous period not to exceed 24 months in duration.
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The failure to participate in the continuous requalification program during the period l the license was administratively suspended caused a failure to complete the
, requalification requirements of 10 CFR 55.59(a) and constitutes a violation
(498;499/97003-01).
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. Conclusions l
The inspectors concluded that, while the licensee staff identified that one individual had not been completing requalification training and developed corrective actions to restore that individual's license, the licensee staff had not identified that the failure to ensure that alllicensed operators completed continuing requalification was contrary to the regulations and constituted a violation of 10 CFR 55.59(a).
However, the inspectors also noted that the licensee restricted the affected individual's use of his license when he stopped attending requalification trainin Miscellaneous Operations issues (92901)
08.1 (Closed) Licensee Event Reoort 50-499/97-004: Unit 2 reactor trip during main turbine testing. This event was previously reviewed as documented in NRC Inspection Report 50-498/97-002; 50-499/97-002. The previous review included direct observation of maintenance activities associated with licensee corrective actions. No new issues were revealed by this repor .2 (Closed) Licensee Event Report 50-499/97-005: Manual trip of Unit 2 upon loss of feedwater flow to Steam Generator 28. On March 26,1997, Main Feedwater Regulating Valve 2B inadvertently closed and would not respond to automatic or manual open demand. Subsequent troubleshooting activities indicated that a relay in the actuating circuitry had failed. This event was previously reviewed as documented in NRC Inspection Report 50-498/97-002; 50-499/97-002. The failed feedwater system relay was replaced by mainter.ance personnel. Additionally, the coil resistance for all similar relays in both units were verified to be satisfactor The licensee planned to perform a failure mode analysis of the relay and a single point failure analysis of the main feedwater regulating valve circuit .3 (Closed) Licensee Event Report 50-498/95-005: Failure to meet the requirements of Technical Specifications due to the inoperability of a standby diesel generator as a result of a failed lug. It was determined that a violation of Technical Specification 3.0.4 occurred in that a mode change was made on Unit 1 'with a technically inoperable standby diesel generator. Approximately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> following a change into Mode 4 from Mode 5, Standby Diesel Generator 12 output breaker opened. The diesel was manually tripped and declared inoperable. Based on subsequent post-failure analysis, the licensee determined that the symptoms which were observed prior to the mode change were consistent with an incipient lug failure. Since indications showed that the degraded conditions existed prior to the l
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mode change and that the standby diesel generator would not have been capable of performing its safety function, it was concluded that the diesel was technically inoperable at the time of the mode chang The licensee's investigation revealed the ring connector / lug frorn one set of three poles to the slip ring was broken. The connector / lug was replaced and the diesel successfully operated for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Other corrective actions included:
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An analysis to determine the cause of the connector / lug failure
- Inspecting other slip ring connectors !
Reviewing stator temperature and field voltage for the other diesel generators ;
e issuing a training bulletin discussing the occurrence
Conducting discussions during maintenance crew briefings regarding the potential of electricallugs and standby diesel generator slip ring lugs
Enhancing standby diesel generator operator logs to identify ALERT levels for stator and field conditions that could be indicative of potential failur The inspector concluded that the licensee had made a reactor Mode change with ;
the diesel generator inoperable, constituting a violation of Technical !
Specification 3.0.4. This licensee-identified and corrected violation is being treated l as a noncited violation, consistent with Section Vll.B.1 of the NRC Enforcement ;
Policy (498/97003-02). 1 II. Maintenance t
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. M1 Conduct of Maintenance
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M 1.1 General Comments on Field Maintenance Activitics insoection Scoce (62707)
The inspectors observed portions of the following ongoing work activities identified by their work authorization numbers:
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- 94021965 Installation of filter modification on Essential Chiller 12A I
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- 109781 Replacement of the mechanical seal on Containment Spray Pump 1B I Unit 2:
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- 97102668 Repair leaking Air / Vacuum Relief Check Valve for Circulating 1
! Water Pump 23 '
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-7- Observations and Findinas The inspectors found that the work performed was conducted in a thorough and professional manner. The work was performed by knowledgeable, qualified technicians utilizing approved procedures. Supervisors were observed providing an appropriate level of oversight. System engineers were observed providing quality i technical support as needed. Prejob briefings were thorough and radiological controls were in place where applicable. The inspectors verified equipment ;
clearance order l Conclusions l Maintenance activities observed were conducted in a professional manne Technicians demonstrated a good knowledge of systems and components and good oversight of activities was eviden M1.2 General Comments on Surveillance Testina ; Insoection Scone (61726)
l The inspectors observed portions of the following surveillance activities:
i Unit 1:
- Plant Surveillance Procedure OPSP06-PK-0005, Revision 4, "4.16KV l Class 1E Degraded Voltage Relay Channel Calibration."
- Plant Surveillance Procedure OPSP03-DG-0003, Revision 9, " Standby I Diesel 13 Operability Test."
- Plant Surveillance Procedure OPSP11-MS-0001, Revision 7, " Main Steam Safety Valve Inservice Test."
Unit 2:
- Plant Surveillance Procedure OPSP11-MS-0001, Revision 7, " Main Steam Safety Valve Inservice Test." Observations and Findinas The inspectors found that the observed surveillance activities were performed in accordance with approved procedures. The test instruments utilized were within current calibration cycles. Expected annunciator alarms and equipment response were communicated to the control room operators by test personnel prior to actuatio !
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8-The inspector observed portions of the main steam safety valve inservice testing performed in accordance with Plant Surveillance Procedure OPSP11-MS-000 l During the testing of main steam safety valve NIMSPSV-7430A, the valve failed to lift within the normal capabilities of the testing equipment. The specified setpoint of ,
l the valve was 1295 psig. The simulated lift pressure applied to the valve was 1419.9 psi {
l The inspectors reviewed the licensee's response to the problem. The valve was dcciared inoperable and Technical Specification 3.7.1.1 was entered. A plan of action was developed to open the valve. A minor adjustment was made to the valve setpoint and the valve lifted at a simulated lift pressure of 1418.7 psi Further adjustment was made to bring the valve setpoint lift pressure to within required Technical Specification limits and the valve tested as satisfactory. Careful and conservative actions were taken and all procedural requirements were met. The evaluation of the test failure was also reviewed and is documented in Section E of this inspection repor Conclusions The activities observed were conducted in a professional manner and personnel ;
involved were thorough and met management's expectations for the implementation i of the maintenance program. Observed surveillance activities were well performed !
j and in accordance with Technical Specifications requirement ,
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E2.1 Enaineerina Evaluation of Stickino Main Steam Safety Valves Insoection Scone (37551)
l During recent main steam safety valve testing in both units, the lift pressure !
settings of some of the valves were found above the 3 percent tolerance allowed by the Technical Specifications. The lift pressure settings were adjusted to within the l i
required allowable tolerance. An engineering evaluation was conducted to verify that plant operation could safely continue. The inspectors reviewed the engineering evaluation and verified that it had been conducted in accordance with the following l procedures:
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i * Condition Reporting Process, OPGP03-ZX-0002, Revision 2 I
- Industry Events Analysis, OPGP03-ZX-0013, Revision 3
- Work Process Prograni, OPGP03-ZA-0090, Revision 18 l
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-9-t Observations and Findinas On February 3,1997, Unit 2 operators performed main steam safety valve testing required by Technical Specifications and the ASME Code for inservice testing. Five of the 20 valves were found with lift pressure settings above the Technical ,
Specification allowable limit of 3 percent. Of the five valves, only three were found I above the values assumed in the safety analysis. The settings were adjusted to l within the limits and a condition report was developed to determine the root caus A report was also made to the NR Initialinvestigation and industry experience indicated that the phenomenon was related to valves that had previously refurbished discs and seats. On April 2, the Unit 1 main steam safety valves were tested and two valves that had been refurbished were found with lift settings above the allowable limit. This test i provided validation that the refurbished valves were more susceptible to stickin i Susceptibility of the unrefurbished valves to sticking was still being evaluated in accordance with the condition repor The engineers found that two other facilities had experienced similar problerns with their main steam safety valves. The information gained from the other facilities was used to develop a plan of action for testing strategy at South Texas Project. The testing was scheduled to be conducted on both units in several steps during 1997 j and 199 A safety assessment was conducted to determina the impact of three main steam
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safety valves being above the value assumed in the safety analysis. Seventeen of the 20 valves were found to be sufficient to meet the peak transient steam relief j requirement for hot full power. Therefore, the as-found conditions were adequate ;
to limit the maximum main steam system pressure to within the design limits for all !
analyzed event The inspector reviewed the licensee's assessment. The use of industry experience l was noted. The safety assessment appropriately bounded th.e condition for continued plant operation. A final review of the root cause and corrective actions will be conducted during closure of Licensee Event Report 498/9700 l l
c. Conclusions j Engineering response to the main steam safety valve problem was good and
- appropriately considered industry experienc ;
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i f-10-I E2.2 Condition Report Enaineerina Evaluation Reoortability Review of Containment Soray l Pumo Seal Leakaae
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' Insoection Scope (92903) l l
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The inspectors reviewed the Containment Spray Pump 1B sealleakage reportability review performed by the license l Observations and Findinas I
The updated final safety analysis report (UFSAR) includes an evaluation of assumed leakage from the essential core cooling system piping in the fuel handling building !
following a loss of coolant accident in order to assess compliance with l 10 CFR Part 50 and 10 CFR Part 100 radiological limits. The licensee correctly 1 determined that the seal leakage from Containment Spray Pump 1B was not reportable. The leakage was reviewed against appropriate criteria and was accommodated within the existing design basi Conclusions l
The engineering department's response to the seal leakage problem was performed in a timely fashion it was well coordinated with control room operators and maintenance personnel. The corrective actions and design change were well documente E3 Engine'ering Procedures and Documentation E Review of Technical Soecifications l l
The licensee recently discovered that they had not been complying with the l requirements specified in the Technical Specifications. An engineer was reviewing the Technical Specification for departure from nucleate boiling and discovered that licensee operators had not completed the surveillance as desgribed in Technical l Specification 3/4.2.5. The control room operators had been recording the values for T average, and the pressurizer pressure, but had not averaged the readings from the different channels and then adjusted them to account for measurement uncertainties before being compared to the required limit. Upon discovery of this concern, the l engineer contacted the reactor vendor to discuss the issue and the recommended
, values for the measurement uncertainties. The operators incorporated the vendor i recommended values into their surveillance results and determined that the adjusted values were acceptabl The inspectors tallowed the licensee's initial corrective actions for the concern and found them adequate. The inspectors will complete their review of this issue during i the Licensee Event Report closur ,
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E8 Miscellaneous Engineering issues (92903)
E (Closed) Unresolved item 498:499/96002-01: Resolve questions regarding ,
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operations with a known quadrant power tilt ratio (OPTR) anomal i t
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This unresolved item was opened to further evaluate five questions associated with the licensee's treatment of the QPTR, including complying with Technical Specifications and properly maintaining the UFSAR Four of these questions were
previously addressed and properly closed as documented in NRC Inspection l Report 50-498/96-004;50-499/96-004. The remaining question involved an i l apparent inconsistency between quadrant power tilts observed during plant startup l
operations and UFSAR Section 4.4.2.10, which stated that significant quadrant power tilts are not anticipated during normal operatio On March 3,1996, the inspectors had observed the shift technical advisor perform a QPTR calculation during a reactor power increase in Unit 1. Prior to exceeding ,
! 50 percent power, a QPTR calculation had indicated a QPTR of greater than 1.0 l l The licensee explained that quadrant power tilts of this magnitude had become I
anticipated during plant startup and power ascension. The inspectors had i questioned the accuracy of the UFSAR statements in light of this known anomal As documented in NRC Inspection Report 50-498/96-02; 50-499/96-02, the control room operators had entered the applicable action statement of Technical i Specification 3.2.4.a. Licensee engineeis stated that, when this anomaly was first observed at South Texas Project, industry experience had already been documented and the anomaly was understood. As a result, continued reactor operations above .
50 percent power were permitted provided that the Technical Specification
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requirements had been met. The inspectors concluded that the operators' actions remained in compliance with Technical Specification 3.2.4 as discussed in NRC Inspection Report 50-498/96 04;50-499/96-0 As a result of the inspectors' questioning, licensee engineers had developed Condition Report 96-7789. Corrective actions to this condition report included an update to UFSAR Section 4.4.2.10. The inspectors reviewed the revision and determined that the OPTR anomaly was appropriately described, in addition, the inspectors noted that Plant Surveillance Procedure OPSP10-NI-0002, Revision 4,
"Excore QPTR Determination," included a note that stated:
"If QPTR> 1.02 and Reactor Power is :s50%, then reactor power may be increased above 50% in accordance with the action requirements of Technical Specification 3.2.4."
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The procedure also required that operators notify the Reactor Engineering-Supervisor. The licensee had remained in compliance with Technical Specifications - j and had properly addressed the technical issu l l l
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-12-E8.2 Criticality Monitorina: the inspectors verified that an exemption to the requirements I of 10 CFR 70.24, " Criticality Accident Requirements," was issued at the time of operating license issuanc i IV. Plant Support i
R1 Radiological Protection and Chemistry Controls i
! R1.1 Tours of Radioloaical Controlled Areas l Inspection Scope (71750) ;
The inspectors routinely toured the mechanical auxiliary and fuel handling buildings in Units 1 and 2. The inspectors also toured the Unit 2 reactor containment building ;
while the unit was in Mode 3. These tours included observation of work, j
, verification of proper radiological work perrnits, sampling of locked doors, and 4 l observation of personnel entrance and egress from contaminated areas and the l radiological controlled area l i
1 Observations and Findinos l Radiological housekeeping in the areas toured was very good. Doors required to be locked in accordance with Technical Specification 6.1.12.2 and the licensee's radiological program were properly secured. No entrance / egress discrepancies were identifie ~
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R6.1 Postina of Notices to Workers (71750)
l l During routine tours, the inspectors observed the licensee's regulatory information h bulletin boards. All notices to workers were posted in accordance with l 10 CFR 19.11.
I l P2 Status of Emergency Preparedness Facilities, Equipment, and Besources t P Emeraency Response Facilities (71750)
During area tours, the inspectors observed that the Technical Support Centers and Operations Support Centers in both units were readily available and maintained for emergency operatio S1 Conduct of Security and Safeguards Activities l' S1.1 Daily Physical Security Activity Observations (71750)
i Insoection Scope (71750)
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On a daily basis, the inspectors observed the practices of security force personnel and the condition of security equipmen b. Observations and Findinas Protected and vital area barriers were in good condition. Personnel access measures and equipment searches for contraband were observed on a daily basi c. Conclusions
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Daily security force activities were conducted in an appropriate manne ,
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ATTACHMENT i L i l SUPPLEMENTAL INFORMATION ;
i PARTIAL LIST OF PERSONS CONTACTED i Licensee t
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! T. Cloninger, Vice President, Nuclear Engineering ,
l W. Cottle, Executive Vice President and General Manager Nuclear J. Crenshaw, Manager, Fluid Systems B. Dowdy, Manager, Operations, Unit 2 i J. Groth, Vice President Nuclear Generation S. Head, Licensing Supervisor
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M. Kanavos, Manager, Mechanical / Civil Design Engineering e A. Kent, Manager, Electrical / instrumentation anri Control System !
T. Koser, Licensing Engineer D. Leazar, Director, Nuclear Fuel and Analysis B. Logan, Manager, Health Physics 'f'
R. Lovell, Manager, Operations, Unit 1 B. Masse, Plant Manager, Unit 2 '
l M. McBurnett, Director, Nuclear Licensing !
G. Parkey, Plant Manager, Unit 1 J. Sheppard, Assistant to Executive Vice President and General Manager Nuclear !
M. Sicard, Acting Assistant to the Manager, Operations, Unit 2 :
F. Timmons, Manager, Nuclear Plant Protection b
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INSPECTION PROCEDURES USED J IP 37551: Onsite Engineerin IP 61726: Surveillance Observations '
IP 62707: Maintenance Observation IP 71707: Plant Operations IP 71750: Plant Support IP 92700: Onsite Followup of Written Reports at Power Reactor Facilities IP 92901: Followup - Operations !
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IP 92902: Followup - Maintenance IP 92903: Followup - Engineering IP 92904: Followup - Plant Support l
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ITEMS OPENED, CLOSED, AND DISCUSSED l Opened 498:499/97003-01 VIO- Failure to meet requalification program requirements 498/97003-02 NCV Failure to meet the requirements of Technical !
Specifications due to the inoperability of a Standby Diesel Generator as a result of a failed lug !
Glosed 498/97003-02 NCV Failure to meet the requirements of Technical Specifications due to the inoperability of a Standby Diesel Generator as a result of a failed lug 50-499/97-004 LER Unit 2 reactor trip during main turbine testing
- 50-499/97-005 LER Manual trip of Unit 2 upon loss of feedwater flow to j
Steam Generator 2B- ;
50-498/95-005 LER Failure to meet the requirements of. Technical l
Specifications due to the inoperability of a Standby Diesel Generator as a result of a failed lug 498 499/96002-01 URI Resolve questions regarding operations with a known quadrant power tilt ratio (QPTR) anomaly
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