IR 05000327/1999001
| ML20204J660 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 03/15/1999 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20204J576 | List: |
| References | |
| 50-327-99-01, 50-327-99-1, 50-328-99-01, 50-328-99-1, NUDOCS 9903300141 | |
| Download: ML20204J660 (19) | |
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l U.S. NUCLEAR REGULATORY COMMISSION
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REGION 11 Docket Nos:
50-327,50-328 License Nos:
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 i
Dates:
January 3 through February *3,1999
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' Inspectors:
M. Shannon, Senior Resident inspector
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D. Starkey, Resident inspector
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R. Telson, Resident inspector R. Moore, Reactor Inspecte r (Sections E2.2, E2.3, and E8.1-E8.5)
C. Smith, Reactor Inspecto: (Sections E2.2, E2.3, and E8.1-E8.5)
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a Approved by:
P. Fredrickson, Chief Reactor Projecis Branch 6 Division of Recctor Projects
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Enclosure
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i 9903300141 990315
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PDR ADOCK 05000327 G
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EXECUTIVE SUMMARY Sequoyah Nuclear Plant, Units 1 & 2 NRC Inspecticn 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 regionalinspectors.
Operations Subsequent to initial discovery by the NRC, weaknesses in the licensee's freeze e
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 e
critique which did not identify deficiencies in a training crew's lack of focus on plant control and the crew did not complete emergency <,perating pro adure ES-0.1, Reactor Trip Response, during a 40 minute scenario (Section 04.1).
A simulator scenario did not accurately detail the unavailability of the steam dumps or
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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 04.1).
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 e
1 A-A and 2A-A emergency diesel generators (EDGs) (Section M1.2).
Enaineerina e
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 tube oil of Unit 2 turbine driven auxiliary feed water pump and Unit 1 motor driven auxiliary feed water pump 1B-B (Se : tion E2.1).
Acceptable technical evaluations were demonstrated by procurement engineering for
substitution of replacement parts (Section E2.2).
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. Overall control of replacement parts during the receipt inspection process by the quality e
control group was affective (Section E2.2).
The scope of self-assessments was comprehensive for evaluating the procurement e
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e 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 conaitions evaluations and issued an adequate corrective action plan (Section E2.3).
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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.
1. Operations
Conduct of Operations 01.1 General Comments (71707)
The inspectors conducted frequent reviews of ongoing plant operations. In general, the conduct of operations was considered to be satisfactory.
Operational Status of Facilities and Equipment 02.1 Deficiencies in the Freeze Protection Prooram a.
Insoection Scoce (71707. 62707. and 37551)
The inspectors verified the implementation of the licensee's 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 Findinos 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 licensee's 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 licensee's temperature control band (some differences from the night before). Further review identified that deficient conditions hc d been documented only on a few of the circuits. This information was discussed with licensee management on January 5 and Performance Evaluation Report (PER) SO990021PER was initiated to address the issue.
The inspectors did not identify any frozen / inoperable compoaents 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 perio i i
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The licensee's subsequent review of the low temperature conditions identified various problems related to design drawings, operator rounds, failed components and circuit j
calibrations which had resulted in the freeze protection circuits not performing as
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desired and the adverse conditions not being identified. Corrective actions for the identified peblems were acceptable.
c.
Conclusions l
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Subsequent to initial discovery by the NRC, weaknesses in the licensee's freeze j
protection program were identified by the licensee related to design drawings, operator
rounds, failed components and circuit calibrations which had resulted in the freeze j
protection circuits not performing as desired and the adverse conditions not being
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identified.
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Operator Knowledge and Performance i
04.1 Simulator Observation: Loss of Vital Power Supolv
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a.
Inspection Scope (71707)
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The inspectors reviewed the simulator exercise guide and obscrved the simulator training scenario for loss-of-vital-120 vac power. In addition, the inspectors observed
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the subsequent simulator training critiques and reviewed written critiques. The scenario i
had been recently revised to address operator performance issues identified following a
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November 9,1998, reactor trip. (See inspection Report 50-327,328/98-11, Section j
04.1).
b.
Observations and Findinos 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 crew's 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.
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 AOP's goal for recovery of a faulted bus or a failed inverter cannot be
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guarantaed. 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.
j 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 crew's prioritization of procedures as " exceptional". The inspectors concluded: (1) that 40 minutes was sufficient time to fully complete ES-0.1, (2) that the crew's focus and procedure prioritization were deficient, (3) that the instructors, did not identify this command and
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control deficiency, and (4) that the licensee's 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
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ES-0.1 guidance. The simulator instructors did not provide clear justification or I
resolution for the conflicting procedure steps during the critique.
l The inr,pectors noted that 19 minutes had elapsed from the time of the reactor trip until the reactcr trip was announced over the public announcing system. Not promptly anrn;uncing 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 licensee's training department.
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Conclusions A weakness was identified in the area of licensed operator training when a simulator i
training critique did not identify deficiencies in a training crew's lack of focus on plant control and failure to complete EOP ES-0.1 during the 40 minute scenario. Also, the
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simulator scenario did not accurately detail the unavailability of the steam dumps or the l
consequences of returning the water-filled steam system to service following the reactor i
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trip. Thus, negative training was conducted contrary t; ine availability of the steam dump system.
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04.2 Operators Did Not Enter TS Action Statement for inocerable Containment isolation i
Valves -
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Inspection Scope (71707)
i The inspectors reviewed the issue and corrective actions related to operators not entering the TS action statement for inoperable containment isolation valves.
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Observations and Findinas On January 7,1999, at 5:49 p.m., operators discovered that maintenance had been I
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 l
containment isolation valves be restored or isolated within four hours or the unit placed
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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
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restore the valves in the event they were needed to support containment isolation. The
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l valves were without power for less than seven hours and thus did not exceed the ten hourt allowed to restore containment or place the unit in Hot Standby.
i The licensee initiated PER No. SO990020PER to document the issue and the corrective
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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. Specifical!y, 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 i
l from service for maintenance, testing, or operational activities." Contrary to this l
procedure requirement, the US failed to properly review a maintenance activity to ensure plant conditions were sul table 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 violati:;n 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 l
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i the pre-work review and approval. In addition to the corrective actions, several enhancements were proposed in the area of work planning and review.
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Conclusions A violation of minor significance was identified for failure to adequately review a l
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.
11. Maintenance M1 Conduct of Maintenance M1.1 General Comments a.
Insoection Smos (61726 & 62707)
The inspectors conducted frequent reviews of ongoing maintenance and surveillance
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Observations and Findinas The inspectors observed and/or reviewed all or portions of the following work activities and/or surveillances:
e 0-PI MDG-082-012.0, Rev 1 12-Year Preventive Maintenance of Diesel Engines e
1-PI-MDG-082-002.A, Hev 0 2-Year Preventive Maintenance of Emergency Diesel Generator 1 A-A e
0-PI-MDG-082-006.0, Rev 2 Six-Year Preventive Maintenance of Diesel Engines e
WO 99-01056-00 Sample Oil of 2A-S Turbine Driven Auxiliary Feedwater Pump (TDAFWP) Outboard Bearing e
Ml-13.5.1, Rev 6 Functional Check of 6.9 kV Shutdown Board 1 A-A, Loss of Normal DC Control Power Annunciator e
0-MI-MIN-000-070.0, Rev 4 Cleanliness of Fluid Systems for Maintenance & Minor Modification Activities
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e 1-SI-IFT-092-N42.2, Rev 99 Functional Test of Power Range Nuclear Instrumentation System Channel N42
<s WO 99-001156-001 Implementation of TACF 2-99-003-003. to isolate Cooling Water to 2A-S TDAFWP Outboard Bearing e
2-SI-SXP-003-201.S, Rev 4 Turbine Driven Auxiliary Feedwater Pump 2A-S Performance Test e
WO 98-013171-001 Five-Year Refurbishment of Auxiliary Air Compressor "A" e
Mi-13.2.3, Rev 3 Setpoint Verification and Calibration of Low Oil Level Switches Associated with System
e 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 Emeraency Diesel Generator (EDG) Outaae a.
Inspection Scope (62707)
The inspectors observed portions of the scheduled 12-year maintenance outages on the 1 A-A and 2A-A EDGs.
b.
Observations and Findinas During this inspection period the licensee completed the scheduled 12-year maintenance outages on the 1 A-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 18-B and 28-B were scheduled to receive similar outages during February and March 1999.
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 1 A-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 1 A 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.
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Conclusions The licensee successfully completed scheduled 12-year maintenance outages on the 1 A-A and 2A-A EDGs.
11. Enaineerina E2 Engineering Support of Facilities and Equipment E2.1 Excessive Water and Metals in Lube Oil of Two Auxiliary Feed Water (AFW) Pumos a.
Inspection Scope (71797 G2707. 37551)
The inspectors evaluated the effectiveness of licensee controls in identifying and resolving an adverse condition and trend associated with abnormally high and increasing water and bearing metal content in the lube oil of two AFW pumps.
b.
Observations and Findinos 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 mar 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 licersee determined that there were problems due to a bearing design problem and, on July 25,1997, issued PER No. SO971771PER. 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 onmge, the Unit 2 TDAFWP was refurbished. However, the leaking bearing housing at addressed.
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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 N.
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SQ971771PER did not address the unexplained presence of an abnormally high water i
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
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water had increased from 0.37% to 2.26% from November 1997 to March 1998. No
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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
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referencing PER No. SO971771PER. The WR documented continuing pump vibration
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in the alert range and dark lube oil with a high iron concentration and requested th t the
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pump be reworked during the next forced outage or U2C9 scheduled for April 1999.
PER No. SO971771PER 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.
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On June 10,1998, PER No. SO980718PER 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 oit.. " 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 Juna 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.
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, revaaled high and increasing levels of metal and water in the outboard lobe 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. SO990182PER.
On January 26,1999, PER. No. SC990092PER was issued. The PER requested an engineering technical operability evaluation (TOE) of this pump. TOE 0-99-003-0092 Rev. O, 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
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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 tube oil samples on August 7,1998, October 30,1998, and January 19,1999 indicated an increasing 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 potentialimpact on pump operability. The failure to promptly identify and correct conditions adverse to i
quality during the period from May 14,1998 until January 26,1998, when oil analysis of the Unit 1 MDAFWP 18-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 18-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
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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 inspection, on March 15,1999, the inspectors and Region Il management discussed this apparent discrepancy with the site. Tne 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 oosition on this issue and modify the TOE,if necessary, The TOE also stated, after describing several water leakage testing and o
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 11 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 runnin l i
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On February 9,1999, the licensee isolated cooling water to the outboard bearing of the i
Unit 2 TDAFWP and operated the pump to confirm that bearing temperatures remained i
in an acceptable temperature range. According to the licensee, oil temperature was i
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 j
scheduled to be completed on the 1B-B MDAFWP on February 24,1999.
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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.
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l E2.2 Procurement And Receipt Of Safety Related Reolacement Parts j
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Insoection 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 acceptance criteria and verification, resolution of receipt inspection
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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 Findinas Acceptable Eauipment 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 Insoection 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 OA hold area until resolution. All 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
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level of replacement parts. Overall control of replacement parts during the receipt inspection process by the Quality Control (OC) group was effective.
Licensee Self-Assessment i
There were four self-assessments of the repbcement parts procurement process in
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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, j
i 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 SC 98-i 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 SO 98-1611, dated November 18,1998, identified replacement parts accepted by receipt inspection (AIM organization) without the 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 acceptanco criteria and maintaining the quality level of replacement parts.
Overall control of replacement parts during the receipt inspection process by the OC group was effective. The scope of self-assessrnents 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.
Insoection Scope (38703)
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 engineering's establishment and verification of replacement part critical characteristics for upgrad E
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b.
Observations and Findinas 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 valvos 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 oi a cylinder test valve in EDG 2A-A on i
March 10,1998. The cylinder test valve was not evaluated or tested to verify the l
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 lil, identification and Control of Materials, Parts, and Components. The violation is identified as Non-Cited Violation NCV 50-328/99-01-02, inadequate Control 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 licensee's corrective action program as PER No.
SO990037PER.
Following the NRC's 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 licensee's 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.
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The licensee performed a thorough analysis to determine the root cause and extent of condition 'or 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 j
assigned to RIP. Although the existing procedures required PEG to approve all QA level 2 material purchased prior to and following April 1,198'7, 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 technica!
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adequacy of commercial grade items was unclear resuiting in a potential inventory of OA 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 OA 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 SO990037PER, dated January 12, 1999, included the following:
e Evaluation of OA-2 material available for issue to determine which items do not have PEG evaluations and resolve any deficiencies.
Review OA-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 OA-2 material issues after November 14,1997, to identify and resolve e
any materialissues without the required PEG evaluation.
e implement a Sequoyah procedure requirement to review future OA-2 issues for a receiving date prior to Jan1,1990, and perform PEG evaluation prior to issue for these items.
OA-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 e
credited into a OA-2 TilC to PEG for evaluation to ensure material being returned to stor,k is acceptable.
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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 l
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 i
responsibility for procurement activity when the program was changed in 1987.
E8 Miscellaneous Engineering issues (92903)
E8.1 (Closed) IFl 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 activitie T
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The inspectors reviewed procedure MMDP-1, Maintenance Management System, Revisica 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 j
and for which a 10 CFR 50.59 evaluation was not required. Work orders were not i
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 i
using these drawings for non-safety related instruments and lines in non-seismic l
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 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 licensee's capability to meet an FSAR accident analysis assumption which was not clearly resolved in PER SO 951623. A 1995 simulator training exercise on a main feed line break scenario stated that the operato'rs 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 levetwas not reached. The TS basis incorrectly reflected the FSAR accident analysis in stating
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isolation of the faulted SG was assumed ten minutes from the time of the break rather
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than ten minutes from the SG fow-low level. This incorrect statement was entered into i
the TS bases following a 1993 design change to the AFW system changing the faulted position of the AFW outlet valves. The licensee's corrective action for the issue, documented in PER SO 951623, dated September 26,1995, was to delete the action item time limit statement from the TS basis.
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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 i
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
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FSAR accident analysis would contribute to a much faster identification of the faulted SG and suosequent isolation. The inspectors concluded this item was adequately resolved.
E8.3 (Closed) IFl 50-327.328/98-01-03: Formation of Vortices in AFW Pump Suction Piping.
l This item concerns a deficiency in the AFW design calculation that addressed the j
potentialimpact of a break in the AFW pumps' suction piping. A postulated break due j
to a seismic event and the resulting potentialimpact from vortex formation was not addressed in Design Calculation SON-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
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formation in this postulated event was not credible due to the low expectation of a
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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
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air ingestion and vortex formation when the AFW pumps are aligned to the CST.
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Revision 3 of Calculation SON-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) IFl 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 OR-24269-01, Environmental and Seismic Qualification Report of Type LCUN-33125 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.
e Loads experienced by the tested battery enveloped the design loads for the e
Sequoyah battery.
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Batt3ry performance capability was demonstrated during and after the seismic e
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 licensee's evaluation by review of the following:
Figure 5.4, SON Horizontal OBE RRS Compared to the Wylie No. 43450-1 e
Lower Bound TRS.
Figure 5.5, SON Vertical OBE RRS compared to Wylie No. 43450-1, Lower
Bound TRS.
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Figure 5.6, SON Horizontal DBE RRS Compared to the Wylie No. 43450-1,
Lower Bound TRS.
Figure 5.7, SON Vertical DBE RRS Compared to the Wylie N. 43450-1, Lower e
bound TRS.
j The inspector concluded that the seismic qualification performed as proof test for the I
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 licensee's response letter, dated September 3,1998, to be reasonable and complete. The licensee replaced J
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 licensee's 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.
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V. Manaaement Meetinas 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.
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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
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, Radeon/ Chemistry Manager D. Koehl, Plant Manager B. O'Brien, 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 i
IP 62707: Maintenance Observations
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IP 71707: Plant Operations
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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 j
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 IFl 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).
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50-327,328/98-01-03 IFl Formation of Vortices in AFW Pump Suction Piping (Section E8.3).
50-327,328/98-01-04 IFl Non-conservative Froude Number Used in AFW Vortex Analysis (Section E8.4).
50-327,328/98-01-07 IFl 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).