ML993640212

IRC Sequoyah19990001 Integrated

ML993640212
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Issue date:	03/15/1999
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March 15, 1999 Tennessee Valley Authority ATTN: Mr. J. A. Scalice Chief Nuclear Officer and Executive Vice President 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801

SUBJECT:

NRC INTEGRATED INSPECTION REPORT NO. 50-327/99-01 AND 50-328/99-01

Dear Mr. Scalice:

This refers to the inspection conducted on January 3, 1999 through February 13, 1999, at the Sequoyah Nuclear Plant facility. The enclosed report presents the results of this inspection.

During the inspection period, your conduct of activities at the Sequoyah facility was generally characterized by good maintenance and plant support. Operations was considered to be acceptable. However, weaknesses were identified in the licensed operator training program and freeze protection program. Engineering support was considered to be acceptable.

However, program weaknesses were identified which allowed the installation of an unqualified replacement part in the 2A-A emergency diesel generator.

Based on the results of this inspection, the NRC has determined that two violations of NRC requirements occurred. These violations are being treated as Non-Cited Violations (NCVs),

consistent with Appendix C of the Enforcement Policy. These NCVs are described in the subject inspection report. If you contest the violations or the severity level of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001, with copies to the Regional Administrator, Region II, and the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001.

TVA 2

In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter, its enclosures, and your response will be placed in the NRC Public Document Room.

Sincerely, (Original signed by Paul E. Fredrickson)

Paul E. Fredrickson, Chief Reactor Projects Branch 6 Division of Reactor Projects Docket Nos. 50-327, 50-328 License Nos. DPR-77, DPR-79

Enclosure:

NRC Inspection Report cc w/encl:

Senior Vice President Nuclear Operations Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Jack A. Bailey, Vice President Engineering and Technical Services Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Masoud Bajestani Site Vice President Sequoyah Nuclear Plant Tennessee Valley Authority P. O. Box 2000 Soddy-Daisy, TN 37379 General Counsel Tennessee Valley Authority ET 10H 400 West Summit Hill Drive Knoxville, TN 37902 cc w/encl continued: See page 3

TVA 3

cc w/encl: Continued Raul R. Baron, General Manager Nuclear Assurance Tennessee Valley Authority 5M Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Mark J. Burzynski, Manager Nuclear Licensing Tennessee Valley Authority 4X Blue Ridge 1101 Market Street Chattanooga, TN 37402-2801 Pedro Salas, Manager Licensing and Industry Affairs Sequoyah Nuclear Plant Tennessee Valley Authority P. O. Box 2000 Soddy-Daisy, TN 37379 D. L. Koehl, Plant Manager Sequoyah Nuclear Plant Tennessee Valley Authority P. O. Box 2000 Soddy Daisy, TN 37379 Michael H. Mobley, Director Division of Radiological Health TN Dept. of Environment and Conservation 3rd Floor, LNC Annex 401 Church Street Nashville, TN 37243-1532 County Executive Hamilton County Courthouse Chattanooga, TN 37402-2801

March 15, 1999 Tennessee Valley Authority ATTN:

Mr. J. A. Scalice Chief Nuclear Officer and Executive Vice President 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801

SUBJECT:

NRC INTEGRATED INSPECTION REPORT NO. 50-327/99-01 AND 50-328/99-01

Dear Mr. Scalice:

This refers to the inspection conducted on January 3, 1999 through February 13, 1999, at the Sequoyah Nuclear Plant facility. The enclosed report presents the results of this inspection.

During the inspection period, your conduct of activities at the Sequoyah facility was generally characterized by good maintenance and plant support. Operations was considered to be acceptable. However, weaknesses were identified in the licensed operator training program and freeze protection program. Engineering support was considered to be acceptable.

However, program weaknesses were identified which allowed the installation of an unqualified replacement part in the 2A-A emergency diesel generator.

Based on the results of this inspection, the NRC has determined that two violations of NRC requirements occurred. These violations are being treated as Non-Cited Violations (NCVs),

consistent with Appendix C of the Enforcement Policy. These NCVs are described in the subject inspection report. If you contest the violations or the severity level of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001, with copies to the Regional Administrator, Region II, and the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001.

TVA 2

In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter, its enclosures, and your response will be placed in the NRC Public Document Room.

Sincerely, (Original signed by Paul E. Fredrickson)

Paul E. Fredrickson, Chief Reactor Projects Branch 6 Division of Reactor Projects Docket Nos. 50-327, 50-328 License Nos. DPR-77, DPR-79

Enclosure:

NRC Inspection Report cc w/encl:

Senior Vice President Nuclear Operations Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Jack A. Bailey, Vice President Engineering and Technical Services Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Masoud Bajestani Site Vice President Sequoyah Nuclear Plant Tennessee Valley Authority P. O. Box 2000 Soddy-Daisy, TN 37379 General Counsel Tennessee Valley Authority ET 10H 400 West Summit Hill Drive Knoxville, TN 37902 cc w/encl continued: See page 3

TVA 3

cc w/encl: Continued Raul R. Baron, General Manager Nuclear Assurance Tennessee Valley Authority 5M Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Mark J. Burzynski, Manager Nuclear Licensing Tennessee Valley Authority 4X Blue Ridge 1101 Market Street Chattanooga, TN 37402-2801 Pedro Salas, Manager Licensing and Industry Affairs Sequoyah Nuclear Plant Tennessee Valley Authority P. O. Box 2000 Soddy-Daisy, TN 37379 D. L. Koehl, Plant Manager Sequoyah Nuclear Plant Tennessee Valley Authority P. O. Box 2000 Soddy Daisy, TN 37379 Michael H. Mobley, Director Division of Radiological Health TN Dept. of Environment and Conservation 3rd Floor, LNC Annex 401 Church Street Nashville, TN 37243-1532 County Executive Hamilton County Courthouse Chattanooga, TN 37402-2801 Distribution w/encl:

L. R. Plisco, RII R. W. Hernan, NRR H. N. Berkow, NRR W. C. Bearden, RII Distribution w/encl continued: See page 4

TVA 4

Distribution w/encl: Continued C. F. Smith, RII D. W. Jones, RII D. H. Thompson, RII L. S. Mellen, RII PUBLIC NRC Resident Inspector, Operations U. S. Nuclear Regulatory Commission 1260 Nuclear Plant Road Spring City, TN 37381 NRC Resident Inspector Sequoyah Nuclear Plant U. S. Nuclear Regulatory Commission 2600 Igou Ferry Road Soddy-Daisy, TN 37379 OFFICE RII:DRP RII:DRP RII:DRP RII:DRP RII:DRS RII:EICS SIGNATURE NAME P Taylor alt 03/08/99 M Shannon 03/15/99 D Starkey 03/09/99 R Telson 03/09/99 C Smith 03/08/99 A Boland 03/15/99 DATE 6/ /25 6/ /25 6/ /25 6/ /25 6/ /25 6/ /25 6/ /25 COPY?

YES NO YES NO YES NO YES NO YES NO YES NO YES NO OFFICIAL RECORD COPY DOCUMENT NAME: G:\\SQ\\REPORTS\\9901.RPT

Enclosure U.S. NUCLEAR REGULATORY COMMISSION REGION II Docket Nos:

50-327, 50-328 License Nos:

DPR-77, DPR-79 Report No:

50-327/99-01, 50-328/99-01 Licensee:

Tennessee Valley Authority (TVA)

Facility:

Sequoyah Nuclear Plant, Units 1 & 2 Location:

Sequoyah Access Road Hamilton County, TN 37379 Dates:

January 3 through February 13, 1999 Inspectors:

M. Shannon, Senior Resident Inspector D. Starkey, Resident Inspector R. Telson, Resident Inspector R. Moore, Reactor Inspector (Sections E2.2, E2.3, and E8.1-E8.5)

C. Smith, Reactor Inspector (Sections E2.2, E2.3, and E8.1-E8.5)

Approved by:

P. Fredrickson, Chief Reactor Projects Branch 6 Division of Reactor Projects

EXECUTIVE

SUMMARY

Sequoyah Nuclear Plant, Units 1 & 2 NRC Inspection Report 50-327/99-01, 50-328/99-01 This integrated inspection included aspects of licensee operations, maintenance and engineering. The report covers a 6-week period of resident inspection; in addition, it includes the results of an announced inspection by regional inspectors.

Operations Subsequent to initial discovery by the NRC, weaknesses in the licensees freeze protection program were identified by the licensee related to design drawings, operator rounds, failed components and circuit calibrations which had resulted in the freeze protection circuits not performing as desired and the adverse conditions not being identified (Section O2.1).

A weakness was identified in licensed operator training concerning a simulator training critique which did not identify deficiencies in a training crews lack of focus on plant control and the crew did not complete emergency operating procedure ES-0.1, Reactor Trip Response, during a 40 minute scenario (Section O4.1).

A simulator scenario did not accurately detail the unavailability of the steam dumps or the consequences of returning the water-filled steam system to service following the reactor trip. During the simulator scenario comprehensive training was not conducted based on the availability of the steam dump system (Section O4.1).

A thorough root cause and corrective action evaluation was conducted for an issue where operators had not entered a Technical Specification (TS) action statement for inoperable essential raw cooling water containment isolation valves. The limiting condition for operation time was not exceeded (Section O4.2).

Maintenance The licensee successfully completed scheduled 12-year maintenance outages on the 1A-A and 2A-A emergency diesel generators (EDGs) (Section M1.2).

Engineering An NRC identified non-cited violation with two examples for failure to promptly identify and correct conditions adverse to quality when multiple oil analyses revealed abnormally high and increasing concentrations of water and bearing metals in the lube oil of Unit 2 turbine driven auxiliary feed water pump and Unit 1 motor driven auxiliary feed water pump 1B-B (Section E2.1).

Acceptable technical evaluations were demonstrated by procurement engineering for substitution of replacement parts (Section E2.2).

3 Overall control of replacement parts during the receipt inspection process by the quality control group was effective (Section E2.2).

The scope of self-assessments was comprehensive for evaluating the procurement process (Section E2.2).

The current process for and implementation of commercial grade dedication was generally effective (Section E2.3).

An NRC identified non-cited violation was identified for installation of an unqualified replacement part (cylinder test valve) in EDG 2A-A. The licensee promptly initiated EDG operability reviews, extent of conditions evaluations and issued an adequate corrective action plan (Section E2.3).

Report Details Summary of Plant Status Unit 1 operated throughout the inspection period at 100% power.

Unit 2 operated throughout the inspection period at 100% power.

I. Operations O1 Conduct of Operations O1.1 General Comments (71707)

The inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was considered to be satisfactory.

02 Operational Status of Facilities and Equipment 02.1 Deficiencies in the Freeze Protection Program

a. Inspection Scope (71707, 62707, and 37551)

The inspectors verified the implementation of the licensees freeze protection program by performing walkdowns of the applicable systems and reviewing the various deficiencies documented in the corrective maintenance and problem evaluation report programs.

b. Observations and Findings On January 4, 1999, the inspectors observed that 10 of 30 freeze protection circuits on freeze protection panel CVC-A2-2 (freeze protection for reactor water storage tank level and feedwater flow instruments and associated piping) had indicated temperatures below the licensees temperature control band of 40-45 degrees F. This observation was discussed with the licensee on January 4. The inspectors noted that none of the freeze protection circuit temperatures indicated below 32 degrees F at this time. On the morning of January 5, the inspectors again observed that ten freeze protection circuits on CVC-A2-2 indicated below the licensees temperature control band (some differences from the night before). Further review identified that deficient conditions had been documented only on a few of the circuits. This information was discussed with licensee management on January 5 and Performance Evaluation Report (PER) SQ990021PER was initiated to address the issue.

The inspectors did not identify any frozen/inoperable components. In addition, the inspectors noted that following the January 5, 1999 observations of low temperature conditions, reliance on the freeze protection system was not required since area weather

conditions improved and cold weather conditions did not exist until the last day of the inspection period.

3 The licensees subsequent review of the low temperature conditions identified various problems related to design drawings, operator rounds, failed components and circuit calibrations which had resulted in the freeze protection circuits not performing as desired and the adverse conditions not being identified. Corrective actions for the identified problems were acceptable.

c. Conclusions Subsequent to initial discovery by the NRC, weaknesses in the licensees freeze protection program were identified by the licensee related to design drawings, operator rounds, failed components and circuit calibrations which had resulted in the freeze protection circuits not performing as desired and the adverse conditions not being identified.

O4 Operator Knowledge and Performance 04.1 Simulator Observation: Loss of Vital Power Supply

a. Inspection Scope (71707)

The inspectors reviewed the simulator exercise guide and observed the simulator training scenario for loss-of-vital-120 vac power. In addition, the inspectors observed the subsequent simulator training critiques and reviewed written critiques. The scenario had been recently revised to address operator performance issues identified following a November 9, 1998, reactor trip. (See Inspection Report 50-327, 328/98-11, Section O4.1).

b. Observations and Findings During a loss-of-vital-120 vac power simulator scenario conducted on January 17, 1999, the inspectors observed that the crew placed primary emphasis on abnormal operating procedure (AOP)-P.03, Loss of Unit 1 Vital Instrument Power Board, rather than on the emergency operating procedure (EOP) ES-0.1, Reactor Trip Response. The unit supervisor (US) delegated sole performance of ES-0.1 to one control room operator (CRO) and focused his and the remainder of the crews attention to the accomplishment of AOP-P.03. The inspectors observed that the CRO remained at step 3, Monitor RCS temperatures for approximately 10 minutes and had not reached step 8, Check pressurizer pressure control prior to exercise termination, 40 minutes into the scenario.

The stated purpose of ES-0.1 is to stabilize and control the plant following a reactor trip without a safety injection. It provides the necessary guidance for monitoring critical plant parameters and specifies required operator actions to stabilize and control the plant, regardless of any postulated single failure of plant equipment.

4 While performance of the AOP can result in a recovery of systems that make control of the plant easier for the operators, it does not provide sufficient guidance nor does it specify all of the required operator actions necessary to stabilize and control the plant.

Furthermore, the AOPs goal for recovery of a faulted bus or a failed inverter cannot be guaranteed. Therefore, the inspectors concluded that the AOP, while a valuable supplement to the EOP, should not be given priority over completion of ES-0.1.

Neither the crew nor the instructors identified that the crew did not complete ES-0.1 as an area of concern. Rather, the training critique characterized the crews prioritization of procedures as exceptional. The inspectors concluded: (1) that 40 minutes was sufficient time to fully complete ES-0.1, (2) that the crews focus and procedure prioritization were deficient, (3) that the instructors, did not identify this command and control deficiency, and (4) that the licensees training focus on completion of AOP-P.03 without completing ES-0.1 was inappropriate.

The inspectors identified similar issues with concurrent management of the AOP and ES-0.1 when another training group of operators was observed performing the same scenario. In addition, the inspectors noted the following general observations:

The inspectors observed the US direct the CRO to maintain RCS temperature at 540 degrees F rather than the prescribed 547 degrees F to 552 degrees F RCS temperature band prescribed in step 6 of ES-0.1. During the scenario critique, the crew shift manager justified this action as an acceptable interpretation of conflicting AOP-P.03 and ES-0.1 guidance. The simulator instructors did not provide clear justification or resolution for the conflicting procedure steps during the critique.

The inspectors noted that 19 minutes had elapsed from the time of the reactor trip until the reactor trip was announced over the public announcing system. Not promptly announcing the reactor trip was not discussed by the simulator instructors during the critique.

The inspectors observed operators place the steam dumps in service eight minutes after restoring vital instrument power. Following the November 9, 1998 reactor trip, however, the steam dump headers had filled with water and a potential water-hammer event was narrowly avoided by plant manager intervention to prevent the crew from restoring the steam dumps. Draining the steam dump header required several hours. Following the event, the steam dump procedure was modified to require operators to verify that the steam dump header was drained prior to being placed in service. The inspectors concluded that the simulator scenario did not accurately detail the unavailability of the steam dumps or the consequences of returning the water-filled steam system to service following the reactor trip.

These items were discussed with licensee management on December 21, 1998 and are under review by the licensees training department.

5

c. Conclusions A weakness was identified in the area of licensed operator training when a simulator training critique did not identify deficiencies in a training crews lack of focus on plant control and failure to complete EOP ES-0.1 during the 40 minute scenario. Also, the simulator scenario did not accurately detail the unavailability of the steam dumps or the consequences of returning the water-filled steam system to service following the reactor trip. Thus, negative training was conducted contrary to the availability of the steam dump system.

O4.2 Operators Did Not Enter TS Action Statement for Inoperable Containment Isolation Valves

a. Inspection Scope (71707)

The inspectors reviewed the issue and corrective actions related to operators not entering the TS action statement for inoperable containment isolation valves.

b. Observations and Findings On January 7, 1999, at 5:49 p.m., operators discovered that maintenance had been performed on the Unit 2 essential raw cooling water (ERCW) supply and discharge inboard (inside shield wall) isolation valves, 2-FCV-67-138 and 2-FCV-67-139, to upper containment cooler 2B, without entering TS 3.6.3.a, requires that inoperable containment isolation valves be restored or isolated within four hours or the unit placed in Hot Standby with the next six hours. The isolation valves were open and made inoperable as power had been removed to the valves from 8:08 a.m. until 2:45 p.m. The TS action statement was not entered, and no administrative controls were in place to restore the valves in the event they were needed to support containment isolation. The valves were without power for less than seven hours and thus did not exceed the ten hours allowed to restore containment or place the unit in Hot Standby.

The licensee initiated PER No. SQ990020PER to document the issue and the corrective actions. The inspector attended the management review committee (MRC) on February 8, 1999, during which the event and corrective actions were discussed. The licensee determined the root cause for not entering the TS action statement was inattention to detail by operations personnel responsible for work review and approval.

Specifically, the US did not identify that the work orders would involve making two containment isolation valves inoperable in a common path and therefore the TS was not entered.

Procedure SSP-12.1, Conduct of Operations, Revision 23, Section 3.1.5.J, Unit Supervisor Responsibilities, states: Authorize the removal of equipment and systems from service for maintenance, testing, or operational activities. Contrary to this procedure requirement, the US failed to properly review a maintenance activity to ensure

6 plant conditions were suitable to perform simultaneous maintenance on the two B ERCW containment isolation valves and consequently failed to enter TS 3.6.3.a. This failure constitutes a violation of minor significance and is not subject to formal enforcement action.

The corrective actions included (1) discussion of the event in detail with the individuals involved, (2) stand-downs for all shift operations personnel to present the event details and the corrective actions taken to prevent recurrence, (3) issuing required reading to all operations personnel on the details of this event, and (4) review and revision of the work review and approval process to require the approval to begin work be done only when work is ready to start with the approval to be a verification/validation of the adequacy of the pre-work review and approval. In addition to the corrective actions, several enhancements were proposed in the area of work planning and review.

c. Conclusions A violation of minor significance was identified for failure to adequately review a maintenance activity which resulted in the failure to enter a TS action statement. The inspectors concluded that the licensee conducted a thorough root cause and corrective action evaluation for an issue where operators had not entered a TS action statement for inoperable ERCW containment isolation valves. The action statement outage time was not exceeded.

II. Maintenance M1 Conduct of Maintenance M1.1 General Comments

a. Inspection Scope (61726 & 62707)

The inspectors conducted frequent reviews of ongoing maintenance and surveillance activities.

b. Observations and Findings The inspectors observed and/or reviewed all or portions of the following work activities and/or surveillances:

0-PI-MDG-082-012.0, Rev 1 12-Year Preventive Maintenance of Diesel Engines

7 1-PI-MDG-082-002.A, Rev 0 2-Year Preventive Maintenance of Emergency Diesel Generator 1A-A 0-PI-MDG-082-006.0, Rev 2 Six-Year Preventive Maintenance of Diesel Engines WO 99-01056-00 Sample Oil of 2A-S Turbine Driven Auxiliary Feedwater Pump (TDAFWP)

Outboard Bearing MI-13.5.1, Rev 6 Functional Check of 6.9 kV Shutdown Board 1A-A, Loss of Normal DC Control Power Annunciator 0-MI-MIN-000-070.0, Rev 4 Cleanliness of Fluid Systems for Maintenance & Minor Modification Activities 1-SI-IFT-092-N42.2, Rev 99 Functional Test of Power Range Nuclear Instrumentation System Channel N42 WO 99-001156-001 Implementation of TACF 2-99-003-003. to Isolate Cooling Water to 2A-S TDAFWP Outboard Bearing 2-SI-SXP-003-201.S, Rev 4 Turbine Driven Auxiliary Feedwater Pump 2A-S Performance Test WO 98-013171-001 Five-Year Refurbishment of Auxiliary Air Compressor A MI-13.2.3, Rev 3 Setpoint Verification and Calibration of Low Oil Level Switches Associated with System 32

8 2-SI-SXP-072-201.B, Rev 4 Containment Spray Pump 2B-B Performance Test

c.

Conclusions The above maintenance and surveillance activities were completed in accordance with procedures and performed by knowledgeable personnel.

M1.2 Twelve-Year Emergency Diesel Generator (EDG) Outage

a.

Inspection Scope (62707)

The inspectors observed portions of the scheduled 12-year maintenance outages on the 1A-A and 2A-A EDGs.

b.

Observations and Findings During this inspection period the licensee completed the scheduled 12-year maintenance outages on the 1A-A and 2A-A EDGs. The work scope included: inspect turbo chargers, drain and replace jacket water and lube oil, remove and inspect cylinder heads and power assemblies, replace fuel injectors, inspect exhaust manifolds, and remove and inspect various auxiliary oil and water pumps. EDGs 1B-B and 2B-B were scheduled to receive similar outages during February and March 1999.

9 The inspectors observed that each outage was well planned and that lessons learned from the first outage (EDG 2A-A) were incorporated into the outage for EDG 1A-A, i.e. three fuel injectors were identified as leaking following installation during the first outage. The leaking injectors were replaced and a lesson learned regarding cleaning of injector seating surfaces was incorporated into the second EDG outage. The inspectors noted that the TS LCO entry time for the 1A-A EDG was approximately 77 hours8.912037e-4 days <br />0.0214 hours <br />1.273148e-4 weeks <br />2.92985e-5 months <br /> and 90 hours0.00104 days <br />0.025 hours <br />1.488095e-4 weeks <br />3.4245e-5 months <br /> for EDG 2A-A, both of which were well within the TS allowed outage time of 7 days.

c.

Conclusions The licensee successfully completed scheduled 12-year maintenance outages on the 1A-A and 2A-A EDGs.

II. Engineering E2 Engineering Support of Facilities and Equipment E2.1 Excessive Water and Metals in Lube Oil of Two Auxiliary Feed Water (AFW) Pumps

a.

Inspection Scope (71707, 62707, 37551)

The inspectors evaluated the effectiveness of licensee controls in identifying and resolving an adverse condition and trend associated

10 with abnormally high and increasing water and bearing metal content in the lube oil of two AFW pumps.

b.

Observations and Findings On January 26, 1999, the inspectors observed maintenance personnel change and sample the Unit 2 turbine driven auxiliary feed water pump (TDAFWP) bearing lubricating oil. The inspectors observed that the 500 ml of fluid drained from the outboard pump bearing sump was abnormally dark and contained approximately 100 ml of water. The sample from the inboard bearing was clear with no water visible.

The inspectors reviewed available documentation related to the Unit 2 TDAFWP oil contamination and discussed the issue with the licensee.

The inspectors reviewed the PER history of AFW problems associated with dark oil, accelerated wear, and premature bearing failures dating to 1996. Previously, the licensee determined that there were problems due to a bearing design problem and, on July 25, 1997, issued PER No. SQ971771PER. This PER did not address the presence of water in the lube oil on July 1 (0.2%) and July 6 (0.38%),

nor was a PER generated to address the October 9 discovery of 12.15% water. In October 1997, during the U2C8 refueling outage, the Unit 2 TDAFWP was refurbished. However, the leaking bearing housing was not addressed.

11 On November 5, 1997, following the refurbishment, PER No.

SQ972538PER documented an above normal concentration of 0.37%

water content in the oil which exceeded typically observed moisture levels in the.01% range as well as the industry and TVA-recommended 0.1% limit. The oil analysis also revealed a high iron content of 166 ppm in the oil, which exceeded the industry and TVA-recommended 20 ppm limit. The inspectors observed that PER No. SQ972538PER did not address the potential operability impact of an adverse condition of abnormally high water content in the lube oil.

PER No. SQ972538PER was inappropriately closed based on actions in PER No. SQ971771PER on November 26, 1997, with comments indicating that both PERs addressed the same issue of high iron content in the lube oil. However, PER No. SQ971771PER did not address the unexplained presence of an abnormally high water content. Subsequent oil samples on December 16, 1997 and March 3, 1998 continued to reflect both abnormally high iron and water content. Documentation indicated that water had increased from 0.37% to 2.26% from November 1997 to March 1998. No PERs or other corrective action documentation were initiated during this period to address the water issue.

On January 22, 1998, the system engineer initiated work request (WR) C39826 referencing PER No. SQ971771PER. The WR documented continuing pump vibration in the alert range and dark lube oil with a high iron concentration and requested that the pump

12 be reworked during the next forced outage or U2C9 scheduled for April 1999. PER No. SQ971771PER was closed on May 19, 1998. The inspectors observed that the abnormally high water content and the potential impact on pump operability still had not been addressed.

On June 10, 1998, PER No. SQ980718PER documented An oil sample (6/5/98) from the outboard bearing of 2A-S Terry Turbine is very dark and has visible water in the oil... The lab later reported 15.6% water (approximately 80 ml). However, this information was not added to the PER. The subsequent engineering assessment characterized the most probable cause of the water intrusion as a restricted drain line from the outboard packing leak off collection bowl. The drain was inspected and cleaned and the PER closed with no additional action planned. Oil samples obtained on August 14 and December 15, 1998 continued to reflect abnormally high and increasing bearing metal and water content in the lube oil with the December sample indicating 929 ppm iron, 369 ppm zinc, and 178 ppm copper (recommended 20 ppm limit for any bearing metal), and 17.1% water (recommended 0.1% limit).

The inspectors observed that the June through December oil samples revealed an apparent acceleration in the rate of water accumulation from the observed 0.37% in November 1997 to 2.26% in June to 17.1% in December, and that no PER was generated to document the adverse trend and its potential impact on pump operability during this period.

13 The failure to promptly identify, by initiating an appropriate PER(s) and promptly correcting conditions adverse to quality during the period from November 1, 1997, until January 26, 1999, when oil analysis of the Unit 2 TDAFWP, revealed high and increasing levels of metal and water in the outboard lube oil sump is a violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action. The violation is identified as one example of Non-Cited Violation NCV 50-327,328/99-01-01, Water and Metal Contamination in Lube Oil of TDAFWP 2A-S and MDAFWP 1B-B. This Severity Level IV violation is being treated as a Non-Cited Violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensees corrective action program as PER No. SQ990182PER.

On January 26, 1999, PER. No. SQ990092PER was issued. The PER requested an engineering technical operability evaluation (TOE) of this pump. TOE 0-99-003-0092 Rev. 0, released on January 28, 1999, identified that the bearing lube oil contamination issue was not limited to the Unit 2 TDAFWP. The TOE also identified a performance problem with the 1B-B motor driven auxiliary feed water pump (MDAFWP). The TOE stated, The last oil sample analyzed & received on January 27, 1999, indicates that a similar trend has developed on the 1B-B motor driven auxiliary feed water pump (MDAFWP). The inspectors determined from the oil sample data that water was present at 0.97% on May 14, 1998, eight months earlier. Subsequent lube oil samples on August 7, 1998, October 30, 1998, and January 19, 1999 indicated an increasing

14 water level trend with 0.43%, 10.4%, and 12.5% water content, respectively. Iron concentrations in the October 30, 1998 and January 19, 1999, samples also exceeded recommended limits.

The inspectors observed that the Unit 1 MDAFWP 1B-B oil samples revealed an adverse condition and trend with apparent acceleration in the rate of water accumulation from May 14, 1998 through January 19, 1999, similar to the Unit 2 TDAFWP, and that no PER had been generated to document the adverse trend and its potential impact on pump operability. The failure to promptly identify and correct conditions adverse to quality during the period from May 14, 1998 until January 26, 1998, when oil analysis of the Unit 1 MDAFWP 1B-B revealed high and increasing levels of metal and water in the outboard lube oil sump, is identified as a second example of Non-Cited Violation NCV 50-327,328/99-01-01, Water and Metal Contamination in Lube Oil of TDAFWP 2A-S and MDAFWP 1B-B.

The inspectors review of TOE 0-99-003-0092 noted the following discrepancies:

A fax from the original equipment manufacturer (OEM), stated that their evaluation was based on the water and oil remaining separate. The TOE used the OEM evaluation; however, subsequent discussions with Maintenance personnel indicated that the oil and water may mix in the bearing housing due to the high speed action of the slinger ring. Subsequent to the

15 inspection, on March 15, 1999, the inspectors and Region II management discussed this apparent discrepancy with the site.

The licensee stated that their evaluation was based on Engineering development of the TOE, using the OEM evaluation.

The licensee stated that they plan to clarify the site position on this issue and modify the TOE, if necessary.

The TOE also stated, after describing several water leakage testing and calculation efforts, that: This shows that the leakage does not increase with the pump running. In fact, this actually indicates that the leakage may decrease with the pump is running. Based on this statement, the inspectors, using oil sample concentrations and time between samples, determined that the leak rate increased by a factor of approximately 10 when the pump was running. Subsequent to the inspection, on March 15, 1999, the inspectors and Region II management discussed this apparent discrepancy with the site. The licensee explained that their calculations and testing did reveal that the leak rate did not increase as stated in the TOE, however, they agreed that the TOE was not clear as to how this conclusion was reached, based on the as-described testing and calculations in the TOE. The licensee stated that they plan on clarifying the description in the TOE of the testing and calculations that were used to reach the TOE conclusion on water leakage with the pump running.

16 On February 9, 1999, the licensee isolated cooling water to the outboard bearing of the Unit 2 TDAFWP and operated the pump to confirm that bearing temperatures remained in an acceptable temperature range. According to the licensee, oil temperature was expected to stabilize in the 140-145 degrees F range and that temperatures below 180 degrees F were acceptable. Actual bearing oil temperature was observed to stabilize just below 140 degrees F.

The same isolation of cooling water modification is scheduled to be completed on the 1B-B MDAFWP on February 24, 1999.

c.

Conclusions A non-cited violation with two examples was identified for failure to promptly identify, by initiating an appropriate PER(s), and promptly correcting conditions adverse to quality when multiple oil analyses revealed abnormally high and increasing concentrations of water and bearing metals in the lube oil of Unit 2 TDAFWP and Unit 1 MDAFWP 1B-B.

E2.2 Procurement And Receipt Of Safety Related Replacement Parts

a.

Inspection Scope (37550)

The inspectors reviewed procurement engineering activity related to the purchase and receipt of safety related replacement parts. The areas of review included 10 CFR Part 21 procurement Quality Assurance (QA) level 1, acceptable substitutes, receipt inspection

17 acceptance criteria and verification, resolution of receipt inspection deficiencies, and self-assessment. The inspection included a sample review of licensee performance in these areas to determine if activities were consistent with applicable regulatory requirements.

b.

Observations and Findings Acceptable Equipment Substitutes The inspectors reviewed 12 alternate equipment substitutions which were implemented via the design change process. The technical evaluations for each of the acceptable substitute item packages reviewed included appropriate identification and evaluation of critical characteristics, item function, and application. Overall, the examples reviewed demonstrated acceptable performance in alternate equipment substitution evaluations by procurement engineering.

Receipt Inspection Criteria And Resolution of Receipt Inspection Deviations The inspectors reviewed approximately 30 receipt inspection packages for QA Level 1 and QA Level 2 (commercial grade dedication) purchases. Receipt acceptance criteria were appropriately documented and verified. The inspectors also reviewed the resolution of approximately 25 deviations identified by the licensee during the receipt inspection process. The deficient items were appropriately segregated and placed in a QA hold area until resolution. All

18 deviations were adequately resolved prior to acceptance. In general, the deviations reviewed demonstrated acceptable performance by the receipt inspectors in verification of acceptance criteria and maintaining the quality level of replacement parts. Overall control of replacement parts during the receipt inspection process by the Quality Control (QC) group was effective.

Licensee Self-Assessment There were four self-assessments of the replacement parts procurement process in 1998. In general, the scope of self-assessment activity was comprehensive. In particular, self-assessment, SQ-SA-99-01, Material Receipt Process, dated November 13, 1998 and Acquisition and Inventory Management (AIM) organization, Annual Assessment SQ-98-01, dated February 11, 1998, included an adequate cross section of performance attributes for assessment.

The inspectors noted that an interface deficiency between the AIM organization (conducts receipt inspection) and the procurement engineering group (PEG) was a contributor to two findings from these self-assessments.

For example, PER SQ 98-0634, dated May 27, 1998, identified an occurrence in which upgraded material was issued for safety related use without the appropriate PEG review and approval. Also PER SQ 98-1611, dated November 18, 1998, identified replacement parts accepted by receipt inspection (AIM organization) without the

19 appropriate PEG review of the qualifying laboratory test reports.

Corrective actions for these findings adequately resolved the identified problems and provided for future monitoring for recurrence. The PER issues discussed above were related to the interface between current organizations while the regulatory issue involved the interface as one program was being replaced by a new program in the 1987 period.

c.

Conclusions Overall, the examples reviewed demonstrated acceptable performance in alternate equipment substitution evaluations by procurement engineering. In general, the deviations reviewed demonstrated acceptable performance by the receipt inspectors in verification of acceptance criteria and maintaining the quality level of replacement parts. Overall control of replacement parts during the receipt inspection process by the QC group was effective. The scope of self-assessments of replacement parts procurement was comprehensive.

A self-identified area of improvement was the interface between PEG and plant organizations involved in the procurement and receipt inspection process.

E2.3 Commercial Grade Dedication Procurement

a.

Inspection Scope (38703)

20 The inspectors reviewed a sample of 30 commercial grade purchased replacement parts that were upgraded for safety related application and released for installation in 1998. This included review of procurement engineerings establishment and verification of replacement part critical characteristics for upgrade.

21

b.

Observations and Findings The technical evaluations for commercial grade dedications appropriately identified critical characteristics and documented these as acceptance criteria. Post installation testing, when required, was appropriately designated, tracked, and performed. Overall, the level of evaluation and documentation for replacement part upgrades was acceptable. However an exception was identified, that relates to the upgrade of EDG cylinder test valves purchased in 1987. Sixteen cylinder test valves were purchased in batch as commercial grade in 1987 in accordance with purchase request 34893A, dated December 18, 1986. Ten of the cylinder test valves were issued for installation since 1987, four of the cylinder test valves were issued for installation in 1998. Work documentation indicated that only one cylinder test valve was actually installed. Work Order 97-0074654-000 documented installation of a cylinder test valve in EDG 2A-A on March 10, 1998. The cylinder test valve was not evaluated or tested to verify the appropriate quality level for this safety related application. There was no documentation to verify the required PEG review was performed therefore the valves were not qualified for safety related application, and were therefore incorrect replacement parts for this application.

The failure to provide adequate control measures to prevent the installation of an unqualified replacement part (cylinder test valve) in EDG 2A-A on March 11, 1998, is identified as a violation of 10 CFR 50, Appendix B, Criterion III, Identification and Control of Materials, Parts, and Components. The violation is identified as Non-Cited Violation NCV 50-328/99-01-02, Inadequate Control

22 Measures to Prevent Installation of an Unqualified Replacement Part in EDG 2A-A.

This Severity Level IV violation is being treated as a Non-cited Violation, consistent with Appendix C of the NRC Enforcement Policy. This violation is in the licensees corrective action program as PER No. SQ990037PER.

Following the NRCs identification of this issue the licensee promptly initiated actions to qualify the installed valve via batch qualification method. The affected EDG was out of service for maintenance at the time the issue was identified. The EDG had successfully completed periodic surveillance tests since the valve was installed in March 1998, which indicated there was no operability concern with the EDG. The licensees interim corrective actions, in addition to the qualification laboratory testing included restricting all further issue of QA level 2 material and requiring a current PEG approval prior to issue.

The qualifying laboratory report was documented in engineering evaluation of electromotive valve parts material comparisons for Contracts 87NLS-34893-A and 90NLH-85151-B, dated January 13, 1999.

The licensee performed a thorough analysis to determine the root cause and extent of condition for this issue. The root cause and contributors were identified. The root cause was a deficiency in the interface as the previous replacement items project (RIP) was superceded by the PEG. The PEG assumed responsibility for technical adequacy of procurement for items purchased after April 1987. This responsibility was previously assigned to RIP. Although the existing procedures required PEG to approve all QA level 2 material purchased prior to and following April 1, 1987, the implementation was that material purchased before April 1, 1987, but received after April 1, 1987, was not reviewed by PEG. This left a time frame in which the responsibility for the technical adequacy of commercial grade items was unclear resulting in a potential inventory of QA level 2 items placed in stock without the required upgrade dedication. A contributor was the deletion of a procedural barrier on November 11, 1987, that required the verification of procurement date. It was incorrectly assumed that all material without documented evaluations had been identified and addressed. Therefore any QA 2 material procured after April 1, 1987 and issued without a PEG package after November 14, 1997, was potentially unqualified.

The long term corrective actions documented in SQ990037PER, dated January 12, 1999, included the following:

Evaluation of QA-2 material available for issue to determine which items do not have PEG evaluations and resolve any deficiencies.

Review QA-2 material issued since January 1, 1990 (GL91-05 reference date) with receiving dates after April 1, 1987 that were requisitioned prior to that date.

Review QA-2 material issues after November 14, 1997, to identify and resolve any material issues without the required PEG evaluation.

23 Implement a Sequoyah procedure requirement to review future QA-2 issues for a receiving date prior to Jan1, 1990, and perform PEG evaluation prior to issue for these items.

QA-2 issue for a receiving date prior to January 1, 1990, and perform PEG evaluation prior to issue for these items.

Implement a procedure requirement to forward all Credit 575's for material credited into a QA-2 TIIC to PEG for evaluation to ensure material being returned to stock is acceptable.

c. Conclusions The current process and implementation of the commercial grade dedication process was generally effective. An exception was identified resulting in a non-cited violation for installation of an unqualified replacement part in the 2A-A EDG. The root cause to this performance deficiency was related to an inadequate transition of technical responsibility for procurement activity when the program was changed in 1987.

E8 Miscellaneous Engineering Issues (92903)

E8.1 (Closed) IFI 50-327,328/97-02-02: Develop Procedural Guidance.

This item involved a concern that the licensee had not developed procedural guidance to clarify what constituted a maintenance activity versus a design change for two inch and smaller balance of plant field routed and field supported piping and equipment when control drawings do not exist. In addition no procedural guidance was provided for documenting original equipment configuration for these type of field activities.

The inspectors reviewed procedure MMDP-1, Maintenance Management System, Revision 0, and determined that Section 3.4 specifies requirements for documenting configuration changes. Section 3.4.3 permits the use of a work order to make permanent alterations to site features not described directly or indirectly in the FSAR and for which a 10 CFR 50.59 evaluation was not required. Work orders were not permitted to be used to make alterations to safety related, quality related, 10 CFR 50.49 items and seismic class 1 structures.

The licensee has also prepared Drawing 47A050 Series, Mechanical Hanger Drawing General Notes, which specifies requirements applicable to all supports including supports for piping, tubing, and conduit. Procedure N2E-884, Instrument and Instrument Line Installation and Inspection, Section 3.4, established requirements for using these drawings for non-safety related instruments and lines in non-seismic structures. The inspector reviewed Drawing CCD-1-2-47W490-1, Revision 1, prepared for plant modification DCN M02530 and verified that requirements were specified for all two inch and smaller pipes to be installed and supported using the guidance of the

24 47A050 drawings. The inspectors concluded that the licensee has procedural controls in place which adequately resolves this item.

E8.2 (Closed) URI 50-327,328/98-01-02: FSAR Chapter 15.4.2.2, Accident Analysis Assumption for Ten Minute Operator Actions to Isolate AFW from the Faulted Steam Generator (SG) on a Main Feed Line Rupture.

This item concerns a challenge to the licensees capability to meet an FSAR accident analysis assumption which was not clearly resolved in PER SQ 951623. A 1995 simulator training exercise on a main feed line break scenario stated that the operators exceeded the assumed 10 minute operator action time to isolate the faulted SG. This assumption was stated in the Technical Specifications Bases as 10 minutes from the time of the break and in FSAR Section 15.4.2.2 as 10 minutes from the low-low SG level following the break.

The inspectors reviewed additional information provided by the licensee and concluded that the 1995 simulator training exercise did not indicate that the FSAR accident analysis operator action assumption was challenged. The simulator exercise demonstrated that the isolation of the faulted SG from the time of the break was greater than ten minutes as stated in the TS basis. However the SG low-low level was not reached. The TS basis incorrectly reflected the FSAR accident analysis in stating isolation of the faulted SG was assumed ten minutes from the time of the break rather than ten minutes from the SG low-low level. This incorrect statement was entered into the TS bases following a 1993 design change to the AFW system changing the faulted position of the AFW outlet valves. The licensees corrective action for the issue, documented in PER SQ 951623, dated September 26, 1995, was to delete the action item time limit statement from the TS basis.

During this inspection the licensee ran the previous simulator exercise again and verified that the low-low SG level was not reached and the operators performed the SG isolation in less than seven minutes. As before, this break size was considerably less than the worst case size in the FSAR accident analysis. The purpose of the training was to challenge the operators ability to locate the break. The larger break assumed in the FSAR accident analysis would contribute to a much faster identification of the faulted SG and subsequent isolation. The inspectors concluded this item was adequately resolved.

E8.3 (Closed) IFI 50-327,328/98-01-03: Formation of Vortices in AFW Pump Suction Piping.

This item concerns a deficiency in the AFW design calculation that addressed the potential impact of a break in the AFW pumps suction piping. A postulated break due to a seismic event and the resulting potential impact from vortex formation was not addressed in Design Calculation SQN-CA-D053, HCG-LCS-110882, AFW System Pressure Switch Set Points Analytical Limits, revision 9. The licensee addressed this scenario in revision 10, of the calculation. This revision determined that the AFW vortex formation in this postulated event was not credible due to the low expectation of a

25 seismic event break, short time frame to the assured source swap over, and the low potential for vortex formation due to the piping configuration. The inspectors concluded this item was adequately resolved.

E8.4 (Closed) IFI 50-327,328/98-01-04: Non-conservative Froude number Used in AFW Vortex Analysis.

An AFW system design calculation did not provide adequate justification for the use of a design parameter in the determination of the critical height for the condensate storage tank (CST) outlet piping to the AFW pumps. The licensee revised the calculation to justify the use of the 0.4 Froude number value in the calculation to address the potential air ingestion and vortex formation when the AFW pumps are aligned to the CST.

Revision 3 of Calculation SQN-03-D53, EPM-GLC-031193, CST Useable Volume for AFW Use, dated May 26, 1998, incorporated the justification. The inspectors concluded this item was adequately resolved.

E8.5 (Closed) IFI 50-327,328/98-01-07: Review Wylie Laboratory Battery Seismic Qualification Test Report.

This item involved a concern that the licensee had not identified the criteria considered by the vendor to demonstrate seismic qualification of the LCUN-33 battery by equivalency analysis. The FSAR states that the battery racks and vital batteries will meet seismic category 1 requirements. The inspector reviewed Report QR-24269-01, Environmental and Seismic Qualification Report of Type LCUN-33 125 Volt Storage Battery, dated October 5, 1992, and conducted interviews with engineering personnel.

Section 5.1 of the above report stated that in order to demonstrate the qualification of the LCUN-33 battery, it was necessary to show that the stresses in the tested L type battery equal or exceeded those that would be experienced by the Sequoyah battery.

The criteria listed as having been used to demonstrate seismic qualification were:

Similarities in construction with emphasis on materials, dimension and weights.

Loads experienced by the tested battery enveloped the design loads for the Sequoyah battery.

Battery performance capability was demonstrated during and after the seismic qualification testing.

The inspector determined that the licensee had evaluated the construction and operating characteristics of the LCUN-33 cells and the original L test cells and found the equivalency to be acceptable. The inspector independently verified the validity of the licensees evaluation by review of the following:

26 Figure 5.4, SQN Horizontal OBE RRS Compared to the Wylie No. 43450-1 Lower Bound TRS.

Figure 5.5, SQN Vertical OBE RRS compared to Wylie No. 43450-1, Lower Bound TRS.

Figure 5.6, SQN Horizontal DBE RRS Compared to the Wylie No. 43450-1, Lower Bound TRS.

Figure 5.7, SQN Vertical DBE RRS Compared to the Wylie N. 43450-1, Lower bound TRS.

The inspector concluded that the seismic qualification performed as proof test for the Sequoyah battery was applicable because of similarity of construction of the seismic test cells and the LCUN-33 cells. This item is adequately resolved.

E8.6 (Closed) Violation 50-328/98-07-01: Failure to Promptly Identify and Correct Plant Deficiencies as Required by 10 CFR 50, Appendix B.

The inspector verified the corrective actions described in the licensees response letter, dated September 3, 1998, to be reasonable and complete. The licensee replaced pressurizer level transmitter 2-LT-68-320 on August 30, 1998. No similar problems were identified.

E8.7 (Closed) Violation 50-328/98-07-02: Failure to Perform a Valid Pressurizer Level Channel Calibration on Level Channel 2-LT-68-320 as Defined by TS 1.4.

The inspector verified the corrective actions described in the licensees response letter, dated September 3, 1998, to be reasonable and complete. The licensee replaced pressurizer level transmitter 2-LT-68-320 on August 30, 1998. No similar problems were identified.

V. Management Meetings X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on February 24, 1999, and for region based inspections on January 15, 1999. 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 identified.

PARTIAL LIST OF PERSONS CONTACTED

27 Licensee M. Bajestani, Site Vice President C. Burton, Assistant Plant Manager H. Butterworth, Operations Manager J. Gates, Site Support Manager E. Freeman, Maintenance and Modifications Manager J. Herron, Engineering and Support Systems Manager C. Kent, Radcon/Chemistry Manager D. Koehl, Plant Manager B. OBrien, Maintenance Manager P. Salas, Manager of Licensing and Industry Affairs M. Lorek, Acting Engineering & Materials Manager INSPECTION PROCEDURES USED IP 37550: Engineering IP 37551: Onsite Engineering IP 38703: Commercial Grade Dedication IP 61726: Surveillance Observations IP 62707: Maintenance Observations IP 71707: Plant Operations IP 92903: Followup - Engineering ITEMS OPENED AND CLOSED Opened 50-327/99-01-01 NCV Water and Metal Contamination in Lube Oil of TDAFWP 2A-S and MDAFWP 1B-B (Section E2.1).

50-328/99-01-02 NCV Inadequate Control Measures to Prevent Installation of an Unqualified Replacement Part in EDG 2A-A (Section E2.3).

Closed 50-327,328/97-02-02 IFI Develop Procedural Guidance (Section E8.1).

50-327,328/98-01-02 URI FSAR Chapter 15.4.2.2, Accident Analysis Assumption for Ten Minute Operator Actions to Isolate AFW from the Faulted SG on a Main Feed Line Rupture (Section E8.2).

50-327,328/98-01-03 IFI Formation of Vortices in AFW Pump Suction Piping (Section E8.3).

28 50-327,328/98-01-04 IFI Non-conservative Froude Number Used in AFW Vortex Analysis (Section E8.4).

50-327,328/98-01-07 IFI Review Wylie Laboratory Battery Seismic Qualification Test Report (Section E8.5).

50-328/98-07-01 VIO Failure to Promptly Identify and Correct Plant Deficiencies as Required by 10 CFR 50, Appendix B, Criterion XVI (Section E8.6).

50-328/98-07-02 VIO Failure to Perform a Valid Pressurizer Level Channel Calibration on Level Channel 2-LT-68-320 as Defined by TS 1.4 (Section E8.7).

50-327,328/99-01-01 NCV Water and Metal Contamination in Lube Oil of TDAFWP 2A-S and MDAFWP 1B-B (Section E2.1).

50-328/99-01-02 NCV Inadequate Control Measures to Prevent Installation of an Unqualified Replacement Part in EDG 2A-A (Section E2.3).