IR 05000321/2007006

IR 05000321-07-006 & 05000366-07-006; on 07/30/2007 - 08/16/2007: Edwin I. Hatch Units 1 & 2, NRC Biennial Baseline Identification and Resolution of Problems Inspection

ML072610124
Person / Time
Site:	Hatch
Issue date:	09/14/2007
From:	Shaeffer S M NRC/RGN-II/DRP/RPB2
To:	Madison D R Southern Nuclear Operating Co
References
IR-07-006
Download: ML072610124 (21)

Text

September 14, 2007

Southern Nuclear Operating Company, Inc.ATTN: Mr. Dennis Vice President - HatchEdwin I. Hatch Nuclear Plant 11030 Hatch Parkway North Baxley, GA 31513

SUBJECT: EDWIN I. HATCH NUCLEAR PLANT - NRC IDENTIFICATION ANDRESOLUTION OF PROBLEMS INSPECTION REPORT 05000321/2007006 AND 05000366/2007006

Dear Mr. Madison:

On August 16, 2007, the U. S. Nuclear Regulatory Commission (NRC) completed a teaminspection at your Edwin I. Hatch Nuclear Plant, Units 1 and 2. The enclosed inspection report documents the inspection findings, which were discussed on August 16, 2007, with yourself and other members of your staff.The inspection was an examination of activities conducted under your license as they relate tothe identification and resolution of problems, and compliance with the Commission's rules and regulations and with the conditions of your operating license. Within these areas, the inspection involved examination of selected procedures and representative records, observations of activities, and interviews with personnel.Based on the sample selected for review, the team concluded that, in general, problems wereproperly identified, evaluated, and corrected. One self-revealing finding and one NRC-identified finding of very low safety significance were identified, both of which were determined to involve violation of regulatory requirements. Additionally, one licensee-identified violation, which was determined to be of very low safety significance, is listed in the report. NRC is treating these violations as non-cited violations (NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy because of the very low safety significance and because you have entered them into your corrective action program. If you contest any NCVs in this report, you should provide a response with the basis of your denial within 30 days of the date of this inspection report, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region II; the Director,Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-

0001, and NRC Resident Inspector at the Hatch Nuclear Plant.

SNC2In accordance with 10 CFR 2.790 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of the NRC's document system (ADAMS). ADAMS is accessible from the NRC Web-site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/Scott M. Shaeffer, ChiefReactor Projects Branch 2 Division of Reactor ProjectsDocket Nos. 50-321 and 50-366License Nos. DPR-57 and NPF-5

Enclosure:

Inspection Report 05000321/2007006 and 05000366/2007006

w/Attachment:

Supplemental Informationcc w/encl: (See page 3)

_________________________OFFICERII:DRPRII:DRPRII:DRPRII:DRPRII:DRSRII:DRPSIGNATURESMS /RA/CWR /RA/ELC /via email/BWM /via email/EDM /via email/NAMESShaefferCRappJHickeyECroweBMillerEMorrisDATE09/14/200709/14/200709/14/200709/13/200709/13/2007 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO SNC3cc w/encl.:J. T. Gasser Executive Vice President Southern Nuclear Operating Company, Inc.

Electronic Mail DistributionDavid H. JonesVice President - Engineering Southern Nuclear Operating Company, Inc.

P.O. Box 1295 Birmingham, AL 35201-1295L. M. StinsonVice President , Fleet Operations Support Plant Hatch Southern Nuclear Operating Company, Inc.

Electronic Mail DistributionRaymond D. BakerManager Licensing - Hatch Southern Nuclear Operating Company, Inc.

Electronic Mail DistributionArthur H. Domby, Esq.Troutman Sanders Electronic Mail DistributionLaurence BergenOglethorpe Power Corporation Electronic Mail DistributionMoanica CastonSouthern Nuclear Operating Company, Inc.

Bin B-022 P. O. Box 1295 Birmingham, AL 35201-1295DirectorDepartment of Natural Resources 205 Butler Street, SE, Suite 1252 Atlanta, GA 30334Manager, Radioactive Materials ProgramDepartment of Natural Resources Electronic Mail DistributionChairmanAppling County Commissioners 69 Tippins St., Suite 201 Baxley, GA 31513Resident ManagerOglethorpe Power Corporation Edwin I. Hatch Nuclear Plant Electronic Mail DistributionSenior Engineer - Power SupplyMunicipal Electric Authority of Georgia Electronic Mail DistributionReece McAlisterExecutive Secretary Georgia Public Service Commission 244 Washington Street, SW Atlanta, GA 30334 SNC4Letter to Dennis from Scott M. Shaeffer dated September 14, 2007

SUBJECT: EDWIN I. HATCH NUCLEAR PLANT - NRC IDENTIFICATION AND RESOLUTION OF PROBLEMS INSPECTION REPORT 05000321/2007006 AND 05000366/2007006Distribution w/encl

R. Martin, NRR C. Evans, RII L. Slack, RII OE Mail RIDSNRRDIRS PUBLIC EnclosureU. S. NUCLEAR REGULATORY COMMISSIONREGION IIDocket Nos.:05000321, 05000366 License Nos.:DPR-57 and NPF-5 Report Nos.:05000321/2007006 and 05000366/2007006 Licensee:Southern Nuclear Operating Company, Inc.

Facility:Edwin I. Hatch Nuclear Plant, Units 1 & 2 Location:Baxley, Georgia 31515 Dates:July 30 - August 16, 2007 Inspectors:E. Crowe, Senior Resident Inspector (Team Leader)C. Rapp, Senior Project Engineer B. Miller, Reactor Inspector E. Morris, Resident InspectorApproved by:Scott M. Shaeffer, ChiefReactor Projects Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000321/2007-006, 05000366/2007-006; 07/30/2007 - 08/16/2007; Hatch Nuclear Plant,Units 1 & 2; Biennial Baseline Identification and Resolution of Problems InspectionThe inspection was conducted by a senior resident inspector, a senior project engineer, aresident inspector, and a reactor inspector. Two Green findings, both of which were non-cited violations, were identified. The significance of most findings is indicated by their color (Green,White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process."Identification and Resolution of ProblemsTwo Green non-cited violations (NCVs) were identified. The team identified that the licenseewas generally effective at identifying problems and entering them into the corrective action program (CAP) for resolution. The licensee maintained a low threshold for identifying problems as evidenced by the continued large number of condition reports (CRs) entered annually into the CAP. The team also determined the licensee was generally prioritizing and evaluating issues properly. The team identified minor problems involving corrective actions for operating experience not being documented within the corrective action program, timeliness of evaluations, and corrective actions which were incomplete. NCVs related to the effectiveness of corrective actions and inadequate evaluation of issues were identified. Audits and self-assessments continued to identify issues related to the corrective action program. On the basis of interviews conducted during the inspection, the team identified that personnel at the site felt free to raise safety concerns to management and to resolve issues via the CAP.

A.

Cornerstone: Mitigating Systems

Green.

A self-revealing Green non-cited violation of 10 CFR 50, Appendix B, CriterionIII was identified for failure to control the design aspects of a plant modification. Thelicensee failed to incorporate vendor parts and specifications for a modification to the Unit 1 residual heat removal (RHR) pump discharge check valves.The team determined this finding is more than minor because it was related to theEquipment Performance attribute of the Mitigating Systems cornerstone and adversely affects the cornerstone objective in that the repeat failures resulted in unplanned unavailability of one train of RHR. This finding is of very low safety significance because it did not result in loss of safety function for a single train greater than allowed Technical Specification outage time. The team determined this finding was of very low safety significance because it did not result in loss of safety function for a single train greater than allowed Technical Specification outage time. The team determined this finding involved a Human Performance cross-cutting aspect of complete, accurate and up-to-date design documentation, procedures, and work packages in that the vendor part number for the non-counterweighted valve disk hanger was not reflected in current 3Enclosurestation documents. The licensee has entered this violation into their corrective actionprogram as CR 2007107101. (Section 4OA2.a(3)(i))*Green. An NRC-identified Green non-cited violation of 10 CFR 50.55a(g)(4) for thefailure to perform periodic leakage testing of buried piping sections of the High Pressure Coolant Injection (HPCI) and Standby Diesel Service Water (SBDSW) systems as required by Section XI of the ASME Code for the third 10-year In-service Inspection (ISI)interval. This finding is more than minor because it affects the Equipment Performance attributeof the Mitigating Systems cornerstone and adversely affects the cornerstone objective in that if a significant leak or rupture should occur as a result of undetected piping degradation, water could not be delivered to mitigating system components preventing these systems from fulfilling their intended safety functions. This finding is of very low safety significance (Green) because it does not represent an actual loss of a system's safety function. Further, the licensee performed the required testing on the SBDSW piping on May 22, 2007, and performed HPCI piping inspections in 2005 and found no significant degradation. This finding was reviewed for any cross-cutting aspects and none were identified. The licensee has entered the violation into their corrective action program as CRs 2007102265 and 2007104138. (Section 4OA2.a(3)(ii))

B.Licensee-Identified Violations

.A violation of very low safety significance, which was identified by the licensee, has beenreviewed by the team. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. This violation and corrective actions are listed in Section 4OA7 of this report.

Enclosure

REPORT DETAILS

4OTHER ACTIVITIES (OA)4OA2Problem Identification and ResolutionThe inspection team based the following conclusions, in part, on issuesidentified/evaluated during the period May 1, 2005 and June 1, 2005. In addition, for selected systems, the team reviewed problems which were identified outside this assessment period whose significance might be age dependent.a.Assessment of the Corrective Action Program(1)Inspection ScopeEffectiveness of Problem Identification. The team reviewed the licensee's CAPprocedures which described the administrative process for initiating and resolving problems through the use of work orders (WOs) and condition reports (CRs). The teamattended meetings where CRs were screened for significance, interviewed personnel,reviewed system health reports, and maintenance rule reports to determine whether the licensee was identifying, accurately characterizing, and entering problems into the corrective action process at an appropriate threshold. The team also conducted plant walkdowns of safety-related equipment to assess the material condition and to identify any deficiencies that had not been previously entered into the CAP.The team reviewed selected CRs listed in the Attachment covering the sevencornerstones of safety. The team also conducted a review of CRs for five risksignificant systems and the components of the Torus and Suppression Pool. These systems were selected based on equipment performance history, Maintenance Rule (MR) considerations, and risk significance insights from the licensee's probabilistic safety assessment. The systems selected were the HPCI system, the RHR system, the Core Spray (CS) system, the RHR Service Water (RHRSW) system, and the 4160 volt and 600 volt Emergency Electrical Buses. The team reviewed the maintenance history, selected WOs, and the associated system health reports for the five systems.

Additional CRs were selected for problems previously identified by the NRC. The team also reviewed issues documented in NRC inspection reports and licensee event reports.

In accordance with the inspection procedure, a five-year review was performed for the RHR, HPCI, and RHRSW for age dependant issues.Prioritization and Evaluation of Issues. The team reviewed CRs including root andapparent cause evaluations, trend reports, and self-assessments to verify the licensee appropriately prioritized and evaluated problems in accordance with their risk significance. The team verified the licensee adequately determined the cause of the problems, root cause analysis where appropriate, and adequately addressed operability, reportability, common cause, generic concerns, extent of condition, and extent of cause.

The review included the appropriateness of the assigned significance, the timeliness of resolutions, level of effort in the investigation, and the scope and depth of the causal analysis. The review was also performed to verify the licensee appropriately identified 5Enclosurecorrective actions to prevent recurrence and that these actions had been appropriatelyprioritized.From the sample of CRs, the team selected effectiveness reviews, and work ordersinitiated to resolve CRs, to verify that the licensee had identified and implemented timely and appropriate corrective actions to address problems. The team verified that corrective actions were properly documented, assigned, and tracked to ensure completion. The review also verified the adequacy of corrective actions to address equipment deficiencies and MR functional failures of risk significant plant safety systems.The team also attended various plant meetings to observe management oversight anddaily functions of the corrective action process. These included the Daily Plant Status Meeting and Management Review Meeting which reviews the previous day's assignment of severity levels, event codes, and cause codes.Effectiveness of Corrective Actions. The team reviewed selected CRs to verify thatspecified corrective actions were timely and effective in resolving the problems described. This sample was based upon risk as well as the severity level of the condition report. The CRs reviewed also included those resulting from previous NRC violations as well as licensee audits and self assessments. From the CRs sampled, the team selected effectiveness reviews and work orders initiated to resolve CRs, to verify the licensee has identified and implemented timely and appropriate corrective actions to address problems. The team verified the corrective actions were properly documented, assigned, and tracked to ensure completion. The review also encompassed the adequacy of corrective actions to address equipment deficiencies and MR functional failures of risk significant plant safety systems. Documents reviewed are listed in the Attachment.(2)AssessmentEffectiveness of Problem Identification. The team determined the licensee wasgenerally effective in identifying problems and entering the issues into the CAP. The team noted that approximately 12,000 to 13,000 CRs were generated by the site each year. The issues identified in these CRs were at a very low threshold. The team noted one instance where the MR expert panel was inactive for approximately 18 months.

This was attributed to turnover of plant staff of which the Engineering Support Manager (ESM) was involved. The ESM was the chairman of this panel. The site Maintenance Rule Coordinator (MRC) was also a participating member of this panel and was also involved in the shift of plant personnel. Neither the ESM or the MRC identified the inactivity of the expert panel. This condition was identified by a Quality Assurance (QA)audit in the first quarter of 2006. The site promptly returned the MR expert panel to an active status and subsequently performed a historical review of previous MR related activities.

6EnclosurePrioritization and Evaluation of Issues. The team determined the corrective actionprogram coordinators (CAPCOs) correctly assigned severity levels to the CRs reviewed by the team. The licensee was generally effective in prioritizing and processing CRs. In general, the root cause evaluations for the CRs reviewed were adequate. In general, apparent cause evaluations reviewed were found to be thorough and well-documented.

The team reviewed approximately 45 CRs classified as severity level 3 requiring an apparent cause evaluation. The team determined the following eight CRs asked only the minimum of two "Why" questions required by the previous revision of the licensee procedure (2005100341, 2005111270, 2006101697, 2006104269, 2006105296, 2006109231, 2006109768, and 2006110586). The CRs warranted further investigation to address a third "Why" question which was implied by the documentation contained within the CR. As a result, these evaluations were incomplete and were not stand alone documents. The licensee had previously identified this condition and has implemented a process to correct this issue. Effectiveness of Corrective Actions. In general, corrective actions developed andimplemented for problems were timely and effective, commensurate with the safety significance of the issues. For significant conditions adverse to quality, the corrective actions directly addressed the cause and effectively prevented recurrence. However, the team found the examples listed below where corrective actions were not performed in a timely manner or were inadequate.*CR 2007103319 documented a condition where the HPCI pump failed to start duringsurveillance procedure 34SV-E41-005-2. The condition was attributed to moisture intrusion into the electronic governor control circuit. CR 2007101917 previously documented a condition where an improper tagout of the pump's barometric condenser led to the Condensate Storage Tank draining to the pump's turbine and overflowing into the lubricating oil system. The licensee drained the water from the HPCI turbine oil sump and removed the water. However, the licensee didn't remove the moisture from the portion of the oil system that provides the hydraulic fluid for the turbine governor.*CR 2006104537, a Severity Level (SL) 2 CR, documented 32 procedure adherenceexamples identified during a QA audit performed in April, 2006. The licensee's corrective actions required department managers to discuss procedure adherence with their employees. However, the team found no corrective action to assess the effectiveness of these actions. CR 2007103243 documented another example of procedure adherence. On March 14, 2007, the Drywell to Suppression Leakage surveillance test failed due to a missing pipe cap and nipple for drywell vacuum breaker. The licensee attributed this to plant personnel failing to install these components as required by the work order during maintenance earlier in the year.*CR 2006104538 documented untimely or inadequate corrective actions identifiedduring the QA audit performed in April 2006. The untimely or inadequate corrective actions resulted in chemistry procedures not containing required contingency plans toobtain post accident suppression pool samples, non-environmental qualified fuse in Operations Department fuse kit, deficiencies in building permit closure and control, no 7Enclosureprocedure for recovery operations following a Hatch Nuclear Plant emergency, andhumidity in Records Storage Facility being outside procedural limits. The team discovered instances where work orders were inadequate after completion of corrective actions for the above condition report. CR 2007100132 was written identifying the lack of identification for the sealant for a bearing housing for the HPCI pump. The licensee performs frequent replacement of the pump's outboard seal as a result of a design deficiency due to lack of seal water vents for this pump. The team also discovered, during the most recent maintenance, the licensee had milled the outboard thrust bearing housing during replacement of the outboard seal. Licensee personnel discovered, during maintenance, the thrust bearing run-out to be out of tolerance which led to the milling evolution. Licensee personnel stated the out-of tolerance run-out was due to utilizing a gasket which had been omitted in previous maintenance and sealant used in its place. The work order for the HPCI pump outboard seal replacement failed to clearly indicate the need for a gasket or to provide for the use of sealant instead of the gasket.(3)Findings(I)Introduction: A self-revealing Green NCV of 10 CFR 50, Appendix B, Criterion III,Design Control, was identified for failure to translate complete vendor specifications into plant hardware following a modification to remove the counterweights from the RHR pump discharge check valves.

Discussion: The original design of the RHR pump discharge check valves (1E11-F031A- D) included packing between the hinge pins and the valve disk hanger. An external counterweight provided additional closing force to compensate for the friction due to the packing. Due to the presence of packing, the tolerance between the hinge pins and the disk hanger were tighter than those for similar noncounterweighted check valves. In 1995, the licensee implemented a design modification which removed the counterweights from the check valves. The licensee also discontinued the use of packing between the hinge pin and the hanger assembly. However, the licensee did not evaluate the need to use a different valve disk hanger for non-counterweighted check valves.On June 14, 2007, the 1C RHR pump discharge check valve (1E11-F031C) failed tofully close following an RHR pump vibration test. The licensee determined that excess wear between the hinge pins and the valve disk hanger resulting in binding of the valve disk. The licensee replaced the valve disk hanger using a part from the warehouse which was for a counterweighted check valve. Following maintenance on the valve, the licensee performed a reverse flow test and verified that the disk was seating.On July 30, 2007, the 1C RHR pump discharge check valve again failed to fully closefollowing operation of RHR in suppression cooling mode. The licensee performed a root-cause analysis for this failure and determined the disk hanger was not the correct part for a non-counterweighted check valve. The licensee determined from vendor documentation that the valve disk hanger for a non-counterweighted valve had a larger tolerance between the hinge pins and the valve disk hanger than for a counterweighted 8Enclosurevalve. The licensee believed smaller tolerance resulted in higher friction causing excesswear between the hinge pins and the valve disk hanger which resulted in binding of the valve disk. The licensee enlarged the tolerance to that recommended by the vendor for non-counterweighted valves in an effort to reduce the friction between the hinge pins and the valve disk hanger. The licensee also machined the disk hanger to remove a burr from the valve disk hanger and slightly change the angle of the mating surface.

Following maintenance on the valve, the licensee performed a reverse flow test and verified that the disk was seating.Analysis: This finding is more than minor because it was related to the EquipmentPerformance attribute of the Mitigating Systems cornerstone and adversely affects the cornerstone objective in that the repeat failures resulted in unplanned unavailability of one train of RHR. This finding is of very low safety significance because it did not result in loss of safety function for a single train greater than allowed Technical Specification outage time. The team determined this finding involved a Human Performance cross-cutting aspect of complete, accurate and up-to-date design documentation, procedures, and work packages in that the vendor part number for the non-counterweighted valve disk hanger was not reflected in current station documents.Enforcement: 10 CFR 50, Appendix B, Design Control, requires, in part, that measuresshall be established for the identification and control of design interfaces and for coordination among participating design organizations. These measures shall include the establishment of procedures among participating design organizations for the review, approval, release, distribution, and revision of documents involving design interfaces. Contrary to the above, the licensee failed to translate complete vendor specifications into plant hardware following modification to remove the counterweights for the RHR pump discharge check valves. This resulted in vendor parts for counterweighted check valves being used during subsequent valve maintenance.

Because this finding is of very low safety significance and because the licensee hasentered the violation into their corrective action program as CR 2007107101, this violation will be characterized as a NCV in accordance with Section IV.A.1 of the NRC's Enforcement Policy and is identified as NCV 050000321,366/2007006-01, Failure to Update Parts Specifications Following a Design Modification.(2)Introduction: An NRC-identified NCV of 10 CFR 50.55a(g)(4) for failure to performperiodic leakage testing of buried piping sections of the HPCI and the SBDSW systemsas required by Section XI of the ASME Code for the third 10-year ISI interval.Description: During the Unit 2 refueling outage in February 2007, NRC inspectorsidentified that the licensee had not performed the required periodic pressure drop test or change in flow rate test for buried portions of the HPCI and SBDSW systems piping during the third ISI interval in accordance with the 1989 Edition of Section XI, Article IWA-5244. The licensee was committed to this Code Edition for the third ISI interval.

This Code required testing was for buried piping that was nonredundant and isolable.

Prior to the discovery by NRC inspectors, the licensee had incorrectly considered the buried portions of HPCI and SBDSW systems to be redundant and isolable, a classification which would have exempted them from testing. Since the third ISI interval 9Enclosureended December 31, 2005, it was unclear if the licensee was within the grace period torequest relief from this requirement which, if granted, would have alleviated the Code requirement. Subsequent to the February outage, the licensee concluded that they were unable to request relief and that there was no avenue to reconcile this missed examination. The licensee has included this Code requirement in their fourth 10-year ISI interval testing program.Analysis: This finding is more than minor because it affects the Equipment Performanceattribute of the Mitigating Systems cornerstone and adversely affects the cornerstone objective in that if a significant leak or rupture should occur as a result of undetected piping degradation, water could not be delivered to mitigating system components preventing these systems from fulfilling their intended safety functions. This finding is of very low safety significance (Green) because it does not represent an actual loss of a system's safety function. Further, the licensee performed the required testing on the SBDSW piping on May 22, 2007, and performed HPCI piping inspections in 2005 and found no significant degradation. This finding was reviewed for any cross-cutting aspects and none were identified.Enforcement: 10 CFR 50.55a(g)(4) requires, in part, that throughout the service life of aboiling or pressurized water reactor facility, components classified as ASME Code Class 1, 2, and 3 must meet the requirements set forth in Section XI of the ASME Code. The 1989 Edition of Section XI, IWA-5244, "Buried Components," states "(a) In non-redundant systems where the buried components are isolable by means of valves, the visual examination VT-2 shall consist of a leakage test that determines the rate of pressure loss. Alternatively, the test may determine the change in flow between the ends of the buried components..." Contrary to this requirement, the licensee failed toperform the required testing on buried portions of the Class 2 HPCI and Class 3 SBDSW systems during the third 10-year ISI interval (January 1, 1996 to December 31, 2005) for which the 1989 Edition of the ASME Code was applicable. Because this finding is of very low safety significance and the licensee has entered the violation into their corrective action program as CRs 2007102265 and 2007104138, it is being treated as a NCV consistent with Section VI.A.1 of the Enforcement Policy and is identified as NCV 050000321,366/2007006-02, Failure to Perform Required ASME Code,Section XI Testing.b. Assessment of the Use of Operating Experience(1) Inspection ScopeThe team conducted a review of the licensee's Operating Experience (OE) program toverify actions were completed in accordance with licensee procedure NMP-GM-008,Operating Experience Program. The team focused on NRC generic communicationsand OE items associated with recent industry operating experience for a detailed reviewto verify issues were appropriately evaluated and entered into the CAP. The team alsoreviewed a sampling of the items the licensee had submitted for OE to verify theinformation accurately reflected the event(s).

10Enclosure

(2) AssessmentIn general, the team determined that OE items were adequately identified, evaluated,and utilized. However, the two items listed below reveal recent weaknesses in the OE program.*NRC IN 84-20 was published in March 1984 to inform licensees of the results of GEtesting of Agastat GP Series Relays. These relays were used in the reactor protection system and other safety-related systems for logic actuation in instrumentation and control circuits. The results of the test indicated that normally de-energized relays had a service life of 10 years and that normally energized relays had a service life of 4.5 years. The licensee evaluated IN 84-20 and determined that Agastat relays installed in the plant had shown no degradation and chose no further action at that time. On September 25, 2006, CR 2006109692 was written to identify 6 relay failures out of 291 relays installed on Unit 1 had failed over the last six years. Four of the six relay failures on Unit 1 involved relays providing an alarm function that were found during routine calibration. The CR further identified that Unit 2 had experienced 3 relay failures over the same period. Unit 2 relay failures also involved relays providing an alarm function. The condition report indicated that no complete loss of safety function was identified. On March 30, 2007, CR 2007103818 was written to identify that the licensee had received notice from the Agastat relay vendor that "F" series relays, purchased as safety-related in 1979, were not actually qualified for Class 1E applications and that they were not tested for a specific life expectancy. The vendor recommended replacing all "F" series relays used in a safety related application with safety related "E" series relays. The team discovered that previous evaluations of the service life of the safety-related Agastat relays had been of normally de-energized relays when the HPCI system actually contains normally energized relays which have less than one half the recommended service life of the normally de-energized relays.

The licensee has implemented a plan to replace all "F" series relays used in safety-related systems by December 2007.*CR 20051000341 documented that valve F016A, Outboard Containment SprayIsolation Valve, failed to open during a stroke timing surveillance. The licensee dissembled the actuator and found that the four set screws that held the clutch sleeve and the gear together were missing which resulted in the actuator failing. As part of the root cause evaluation, the licensee identified a 1993 industry notice that the clutch set screws would loosen due to vibration and could result in actuator failure. The notice stated that either a locking compound or staking be used to prevent the set screws from loosening. The notice recommended that the set screws be inspected during actuator overhaul or if the motor was removed. In 1994, the licensee replaced both the actuator and the motor on valve F016A, but did not inspect if the set screws were secured in place. This was a missed opportunity to identify and correct acondition adverse to quality. Subsequently, the actuator failed during routinesurveillance. The enforcement aspects of this issue are disposition in Section 4OA7.

11Enclosure(3)FindingsNo findings of significance were identified.c.Assessment of Self-Assessments and Audits(1) Inspection ScopeThe team conducted a review of the licensee's self-assessment and audit programs toverify actions were completed in accordance with licensee procedures NMP-GM-003,"Self-Assessment Procedure" and NMP-GM-003-GL-1, "Self-Assessment Guideline."The team conducted a review of licensee self-assessments that were conducted duringthe time period of May 1, 2005 to June 1, 2007. The team reviewed a sampling of self-assessments and audits to verify that identified deficiencies and areas needingimprovement were entered into the CAP tracking system.

(2) AssessmentThe team verified that self-assessments and audits were adequately performed toidentify deficiencies and areas needing improvement. For the deficiencies and areasneeding improvement, the team confirmed that the items were entered into the CAPtracking system.(3)FindingsNo findings of significance were identified.d. Assessment of Safety-Conscious Work Environment(1)Inspection ScopeThe team randomly interviewed approximately 25 on-site workers, focusing on theirknowledge of the problem identification process. Interviewees were questioned on their understanding and their willingness to initiate condition reports or raise safety concerns through the employee concerns program (ECP). Discussions with plant staff were conducted to develop a general sense of the safety-conscious work environment at the site. The team looked for indications of conditions that would cause employees to bereluctant to raise safety concerns. Additionally, the team reviewed Corporate ECP files for completeness, adequacy of theinvestigation, file documentation, responsiveness to the concerned individuals, responses to "recommended corrective actions" by station management, and to verify that employee concerns remain anonymous. The team also interviewed the Corporate and Site ECP Managers related to their assigned duties. The inspection included verification that concerns were being properly reviewed; identified deficiencies were being resolved; and issues were entered into the CAP when appropriate.

12Enclosure(2) Assessment and ObservationsThe team determined, through interviews, that site personnel felt free to raise safetyconcerns. All personnel stated they would not hesitate to raise safety concerns to their direct management or through the CR process. They also understood and believed they could raise issues without fear of retaliation by management. Concern resolution files were sampled from years 2005 and 2006. The team noted the majority of the concerns were related to non-safety related concerns and were being tracked through action items. The team concluded that a safety conscious work environment existed.(3) FindingsNo findings of significance were identified.4OA6Management MeetingsOn August 16, 2007, the team presented the inspection results to Mr. D. Madison andother members of his staff who acknowledged the findings. The team informed the licensee that any proprietary information that was examined during the inspection will not be included in the report.4OA7Licensee Identified ViolationsThe following violation of very low safety significance (Green) was identified by thelicensee and is a violation of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as NCVs.*10 CFR 50, Appendix B, Criterion XVI, "Corrective Actions" states, in part, thatmeasures shall be established to assure that conditions adverse to quality, such as non-conformances are promptly identified and corrected. Contrary to the above, the licensee failed to identify that a locking compound had not been applied to the set screws of the actuator for Containment Spray Valve 1E11-F016A. An industry notice, available in 1993, provided information on applying a locking compound to the actuator set screws.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

M. Ajluni, Plant Support Manager

J. Dixon, Health Physics Manager

S. Douglas, Plant Manager

B. Goodwin, Engineering Manager

D. Herrin, Corrective Actions Program Manager

G. Johnson, Operations Manager

R. King, Engineering Supervisor for Modifications

J. Lewis, Training and Emergency Preparedness Manager

D. Madison, Hatch Vice President

V. Shaw, E-Fin Supervisor

J. Thompson, Nuclear Security Manager

K. Underwood, Performance Analysis Manager

R. Varnadore, Maintenance Manager

NRC personnel

C. Christensen, Deputy Director, Division of Reactor Projects

S. Shaeffer, Chief, Branch 2, Division of Reactor Projects

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and

Closed

05000321, 366/2007006-01NCVFailure to Update Plant Components to Match DesignModification (Section 4OA2.a(3)(i))05000321, 366/2007006-02NCVFailure to Perform Required ASME Code, Section XITesting (Section 4OA2.a(3)(ii))

LIST OF DOCUMENTS REVIEWED

ProceduresNMP-AD-002Troubleshooting Guidelines A Graded ApproachNMP-AD-012Operability Determinations and Functionality Assessments forResolution of Degraded and Nonconforming Conditions Adverse to Quality or Safety

NMP-ES-026As-Built Notices (ABNs)

NMP-GM-002Corrective Action Program

NMP-GM-003Self-Assessment Procedure

NMP-OS-003Operational Decision Making Issue Evaluation ProcessRoot Cause EvaluationsCR2005100077Unit 1 Shutdown Due to Increasing Drywell Floor Drain LeakageCR2006103226FME Controls Not In Compliance With Station Procedures

CR2006105462HPCI System Inoperable Due to Discharge Check Valve Leakage

A-2AttachmentCR20061058265 SRVs As Found Test Results Greater Than 3% Above TSAllowanceCR2006106806EOP Collapsible Fire Hose For Alternate Boron Injection - NRCViolationCR2006107057Testing Program for ECCS Area Coolers Failed to Meet Degree ofRequired Instrument AccuracyCR2006107110Safety Related Motor Control Center and Local Starters HaveThermal Overloads BypassedCR2006108855RCIC System Torus Suction Failed to Meet Acceptance Criterion#3 of

NUREG-0737CR2007101771Unit 2 MSIVs Failed LLRT

CR2007102031Core Spray and RHR Room Cooler Plant Service Water SupplyValves Unintentionally PreconditionedCR2007103319HCPI Turbine Control Valve Failed to Open

CR20071034552A RFPT Minimum Flow Manual Isolation Valve Found Partially ClosedCR20071043985 SRVs As Found Test Results Greater Than 3% Above TSAllowanceCondition Reports:1998005418200511094920061034932006108419200710071720000053762005110955200610353720061085552007100931

20031123302005110391200610353920061085822007101102

20041111862005111006200610369920061088202007101267

20041015332005111247200610384220061088552007101308

20041030302005111270200610426920061089522007101315

20051000772005111372200610403820061090522007101351

20051002062005111378200610440320061090912007101561

20051003412005111621200610453720061091542007101606

20051045422005111893200610453820061092312007101753

20051049502005112047200610454320061093722007101990

20051054782006100132200610457420061096922007101991

20051054992006100187200610467820061097172007101762

20051056392006100204200610477420061097262007101917

20051057432006100390200610482520061097682007102031

20051060002006100396200610490820061098202007102265

20051060272006100576200610524220061098232007102285

20051060492006100645200610529620061100432007102502

20051061192006100776200610534620061102002007102803

20051061662006101209200610542820061103342007102912

20051061742006101569200610546220061103442007103055

20051063962006101575200610552020061103542007103056

20051065642006101697200610565720061103822007103215

20051068872006101753200610566120061106822007103243

20051068882006101761200610571020061106832007103319

20051070032006101771200610574720061107362007103329

20051074722006101850200610589320061110352007103455

A-3Attachment2005107674200610202920061059262006111230200710353820051077662006102098200610649720061113102007103612

20051078922006102117200610649820061113872007103787

20051079942006104263200610653720061114242007103818

20051081442006104301200610680620061116762007104022

20051071842006102348200610681120061121742007104138

20051082172006102504200610688220062054762007104347

20051081882006102563200610695820071000972007104398

20051084282006102616200610696020071001012007104535

20051084292006102673200610697220071001192007104704

20051085382006102794200610705720071001202007105258

20051085972006102822200610711020071001212007105277

20051088912006102880200610711420071001322007105289

20051095572006102984200610727220071001342007105456

20051096632006103074200610728920071001892007105485

20051101112006103102200610753120071002652007106773

20051101582006103140200610763120071002672007107110

2005110613200610318320061079052007100268

2005110737200610322620061081562007100303

2005110766200610344220061083292007100320

2005110770200610344720061082252007100574Engineering Work Orders

2052352601

PM/EQPM Work Orders2R24S0119B1-20409026011E11C001B2-1042371101

1E11F046A1-1040188701

1E11F078B1-1050268301

Work Orders

1030892102105285330110608341012060252101207053680110500722011052853601106083490120610831012070537001

10500722021052892501106106700120614392012070588401

10500786011052934501106108300120615954012070637801

10506909011060219101106156510120616662012070673601

1051450301106039590110617521012061855012070720101

10520488011060577201107001870120622263012070746501

10521733011060579001107009540120623007012070933301

1052712601106062230110707942012062646401T001272001

105277770110608305012051450501System Health Reports:Core SprayEmergency AC Distribution High Pressure Core Injection

A-4AttachmentReactor Core Isolation Cooling SystemResidual Heat RemovalResidual Heat Removal Service WaterMiscellaneous Documents2006 Southern Company Compliance Questionnaire40AC-ENG-020-0SMaintenance Rule (10CFR50.65) Implementation and Compliance Concerns Program Procedure

ERS-M-003E.I. Hatch Nuclear Plant Refurbishment/Repair Specification/RHRService Water PumpsEngineering Evaluation 1060395901/1060395902

Engineering Evaluation 2070536802

Intracompany Correspondence "Response to NRCIN 2006-20: Foreign Material Found inthe Emergency Core Cooling System"Intracompany Correspondence"Response to NRCIN 2006-21: Operating ExperienceRegarding Entrainment of Air Into Emergency Core Cooling and Containment Spray Systems"Intracompany Correspondence"QA Audit of the Corrective Action Program (CAP), H-CAP-2007-1"Intracompany Correspondence"Units 1 & 2 CST Reserve Volume for HPCI & RCIC"Licensee Event Reports05000366/2005-002-001, 05000366/2006-002-000, 05000366/2006-003-000,05000321/2006-002-000, 05000321/2006-S01-000, 05000321/2006-003-000,

05000321/2007-001-000, 05000366/2007-001-000, 05000366/2007-002-000,

05000366/2007-003-000, 05000366/2007-004-000, 05000321/2007-002-000,

05000366/2007-005-000, 05000366/2007-006-000