IR 05000416/2007004

Download: ML073060622

Text

November 2, 2007

William R. Brian, Vice President of OperationsGrand Gulf Nuclear Station Entergy Operations, Inc.

P.O. Box 756 Port Gibson, MS 39150

SUBJECT: GRAND GULF NUCLEAR STATION - NRC INTEGRATED INSPECTIONREPORT 05000416/2007004

Dear Mr. Brian:

On September 30, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection at your Grand Gulf Nuclear Station facility. The enclosed integrated report documents the inspection findings, which were discussed on October 10, 2007, with you and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.This report documents four NRC identified and self-revealing findings of very low safetysignificance (Green). Three of these findings were determined to involve violations of NRC requirements; however, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these findings as noncited violations (NCVs) consistent with Section VI.A of the NRC Enforcement Policy. If you contest these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, U.S.

Nuclear Regulatory Commission Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington DC 20555-0001; and the NRC Resident Inspector at the Grand Gulf Nuclear Station facility.

Entergy Operations, Inc.-2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of 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/Michael C. Hay, ChiefProject Branch C Division of Reactor ProjectsDocket: 50-416License: NPF-29

Enclosure:

Inspection Report 05000416/2007004

w/Attachment:

Supplemental Informationcc w/

Enclosure:

Senior Vice President Entergy Nuclear Operations P.O. Box 31995 Jackson, MS 39286-1995Senior Vice President and COOEntergy Operations, Inc.

P.O. Box 31995 Jackson, MS 39286-1995Vice President, Operations SupportEntergy Services, Inc.

P.O. Box 31995 Jackson, MS 39286-1995ChiefEnergy & Transportation Branch Environmental Compliance and Enforcement Division Mississippi Department of Environmental Quality P.O. Box 10385 Jackson, MS 39289-0385PresidentClaiborne County Board of Supervisors P.O. Box 339 Port Gibson, MS 39150General Manager, Plant OperationsGrand Gulf Nuclear Station Entergy Operations, Inc.

P.O. Box 756 Port Gibson, MS 39150Senior ManagerNuclear Safety & Licensing Entergy Services, Inc.

P.O. Box 31995 Jackson, MS 39286-1995Manager, LicensingEntergy Operations, Inc.

P.O. Box 756 Port Gibson, MS 39150 Entergy Operations, Inc.-3-Attorney General Department of Justice State of Louisiana P.O. Box 94005 Baton Rouge, LA 70804-9005 Office of the GovernorState of Mississippi Jackson, MS 39205Attorney GeneralAssistant Attorney General State of Mississippi P.O. Box 22947 Jackson, MS 39225-2947State Health OfficerState Board of Health P.O. Box 139 Jackson, MS 39205 Lisa R. HammondTechnological Hazards Branch National Preparedness Division FEMA Region VI 800 N. Loop 288 Denton, TX 76209Conrad S. Burnside, ChiefTechnological Hazards Branch National Preparedness Division DHS/FEMA 3003 Chamblee Tucker Road Atlanta, GA 30341DirectorNuclear Safety & Licensing Entergy Operations, Inc.

1340 Echelon Parkway Jackson, MS 39213-8298Director, Nuclear Safety AssuranceEntergy Operations, Inc.

P.O. Box 756 Port Gibson, MS 39150Richard Penrod, Senior Environmental Scientist, State Liaison Officer Office of Environmental Services Northwestern State University Russsell Hall, Room 201 Natchitoches, LA 71497 Entergy Operations, Inc.-4-Electronic distribution by RIV:Regional Administrator (EEC)DRP Director (ATH)DRS Director (DDC)DRS Deputy Director (RJC1)Senior Resident Inspector (AJB6)Branch Chief, DRP/C (MCH2)Senior Project Engineer, DRP/C (WCW)Team Leader, DRP/TSS (CJP)RITS Coordinator (MSH3)Only inspection reports to the following:DRS STA (DAP)D. Pelton, OEDO RIV Coordinator (DLP)ROPreports GG Site Secretary (NAS2)SUNSI Review Completed: MCH ADAMS: Yes No Initials: MCH Publicly Available Non-Publicly Available Sensitive Non-SensitiveR:\_REACTORS\GG\2007\GG2007-04RP-AJB.wpdML073060622RIV:RI:DRP/CSPE:DRP/EC:SPE:DRP/CC:DRS/EB1C:DRS/PSBAJBarrett GBMillerWCWalkerWBJonesMPShannon/RA - E//RA//RA//RA//RA KBrooks for/11/01/0710/29/0711/01/0710/29/0710/30/07C:DRS/OBC:DRS/EB2C:DRP/CATGodyLJSmithMCHay/RA BLarson for//RA Dpowers for//RA/11/01/0710/29/0711/02/07OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax EnclosureU.S. NUCLEAR REGULATORY COMMISSION REGION IV Docket:50-416Licenses:NPF-29 Report No.:05000416/2007004 Licensee:Entergy Operations, Inc.

Facility:Grand Gulf Nuclear Station Location:Waterloo Road Port Gibson, Mississippi 39150Dates:July 1 through September 30, 2007 Inspectors:A. Barrett, Resident InspectorD. Bollock, Project Engineer G. A. George, Reactor Inspector, Engineering Branch 1 S. Garchow, Operations Engineer B. Henderson, Reactor Inspector, Engineering Branch 1 G. Miller, Senior Resident Inspector J. Reynoso, Reactor Inspector, Engineering Branch 1 T. Stetka, Senior Operations Engineer E. Uribe, NSPDP Approved By:Michael C. Hay, ChiefProject Branch C Division of Reactor Projects EnclosureEnclosure

SUMMARY OF FINDINGS

IR05000416/2007004; 7/1/07 - 9/30/07; Grand Gulf Nuclear Station -- Integrated Resident andRegional Report; Maintenance Effectiveness, Permanent Plant Modifications, Refueling and

Outage Activities, Event Follow-up.This report covered a 3-month period of inspection by resident inspectors and regional officeinspectors. These inspection activities identified four Green findings, three of which were noncited violations. The significance of most findings is indicated by their color (Green, White,

Yellow, or Red) using Inspection Manual Chapter 0609, "Significance Determination Process."

Findings for which the significance determination process does not apply may be Green or be assigned a severity level after NRC management's review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649,

"Reactor Oversight Process," Revision 3, dated July 2000.A.NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green.

The inspectors identified a noncited violation of 10 CFR Part 50,Appendix B, Criterion III, "Design Control," for the failure to translate a design basis limit for outdoor air temperature into an instruction or procedure. The licensee established a new Updated Final Safety Analysis Report maximum outdoor air temperature of 102.5°F. If outside air temperatures exceeded 102.5°F, safety-related equipment, which are located in rooms that are cooled by outdoor air (i.e., standby service water pump room), would be operationally challenged. The inspectors identified that no instruction or procedure was established to monitor high outside temperature or subsequent actions established in the event the design basis temperature limit is exceeded. The inspectors determined that the finding was more than minor because thefinding affects the mitigating system cornerstone objective of ensuring the reliability of the standby service water system that responds to initiating events to prevent undesirable conditions. Using the Phase 1 worksheet in Inspection Manual Chapter 0609, "Significance Determination Process," this finding is determined to be of very low safety significance because there was no actual loss of a safety function, and the design basis limits had not been exceeded.

The inspectors determined that the finding has a crosscutting aspect in the area of human performance decision making because the licensee failed to use conservative assumptions in determining not to establish a procedure or instruction to monitor high outside temperature for design limits on the standby service water pump room H.1(b) (Section 1R17).

Green.

The inspectors identified a noncited violation of 10 CFR Part 50.65(a)(2)for the failure to adequately monitor the performance of the control rod drive system. Specifically, the licensee failed to adequately perform a functional failure determination for a degraded flow control valve. Following licensee EnclosureEnclosure-2-review of this condition the system was placed in the maintenance rule (a)(1)monitoring status. This finding was more than minor since the degraded control rod drive flowcontrol valve caused the system to be placed in the (a)(1) monitoring status.

This finding was characterized under the significance determination process as having a very low safety significance, because the maintenance rule aspect of the finding did not cause an actual loss of safety function of the system, nor did it cause a component to become inoperable. The cause of this finding has a crosscutting aspect in the area of human performance associated with decisionmaking because licensee personnel failed to use conservative assumptions and did not verify the validity of the underlying assumptions used in making safety-significant decisions H.1(b) (Section 1R12).*Green. A self-revealing noncited violation of Technical Specifications 5.4.1(a)was identified involving the failure to adequately follow procedure to align valves in the fuel pool cooling and cleanup system. The valves were aligned in the wrong sequence, contrary to the system operating instructions, causing both fuel pool cooling and cleanup pumps to trip and a subsequent loss of fuel pool cooling. The licensee entered this issue in their corrective action program as Condition Report CR-GGN-2007-04284.The finding is more than minor, since it affects the human performance attributeof the barrier integrity cornerstone and affects the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 worksheet, the finding has a very low safety significance since it only represents a degradation of the radiological barrier function provided by the spent fuel pool system. The cause of this finding has a crosscutting aspect in the area of human performanceassociated with work practices because licensee personnel failed to follow the correct sequence of valve manipulations required by procedure H.4(b)

(Section 1R20).

Cornerstone: Initiating Events

Green.

A self-revealing finding was identified involving the failure to properlycalibrate the main condenser hydraulic vacuum switch that established a higher trip setpoint that would prematurely actuate an automatic turbine trip and reactor scram for a degraded main condenser vacuum condition. This issue was entered into the licensee's corrective action program as Condition Report CR-GGN-2007-02756. The finding was more than minor because it was associated with the initiatingevents cornerstone attribute of equipment performance and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations.

Using the Manual Chapter 0609, "Significance Determination Process," Phase 1 EnclosureEnclosure-3-worksheet, the finding was determined to have very low safety significancebecause the finding did not contribute to the likelihood that mitigating equipmentor functions would not be available following a reactor trip. The cause of thefinding was related to the human performance crosscutting component ofresources in that the calibration procedure did not provide clear instructions detailing the methodology to adjust the speed simulation screw to the required position [H.2©] (Section 4OA3).

B.Licensee-Identified Violations

Violations of very low safety significance which were identified by the licensee havebeen reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. These violations and corrective actions are listed in Section 4OA7 of this report.

EnclosureEnclosure-4-

REPORT DETAILS

Summary of Plant StatusGrand Gulf Nuclear Station (GGNS) began the inspection period at full rated thermal power. On August 21, 2007, the reactor experienced an automatic reactor scram due to the failure of a reactor feedpump turbine controller. Following troubleshooting and repairs, the reactor was restarted on August 22, 2007, and reached full power on August 26, 2007. On August 26, 2007, the reactor recirculation Pump B motor tripped due to a ground fault, causing the plant to experience an unplanned power reduction to 58 percent power. The plant remained at approximately 58 percent power and in single loop operation until September 1, 2007, when the reactor was shutdown to replace the failed motor. On September 14, 2007, the plant started up from the outage and reached full power on September 18, 2007. The plant remained at or near full rated thermal power for the remainder of the inspection period.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, Barrier Integrity1R01Adverse Weather Protection (71111.01).1Readiness For Seasonal Susceptibilities

a. Inspection Scope

The inspectors completed a review of the licensee's readiness for seasonalsusceptibilities involving extreme high temperatures. The inspectors: (1) reviewed plant procedures, the Updated Final Safety Analysis Report (UFSAR), and Technical Specifications (TS) to ensure that operator actions defined in adverse weather procedures maintained the readiness of essential systems; (2) walked down portions of the three systems listed below to ensure that adverse weather protection features were sufficient to support operability, including the ability to perform safe shutdown functions; (3) evaluated operator staffing levels to ensure the licensee could maintain the readiness of essential systems required by plant procedures; and (4) reviewed the corrective action program (CAP) to determine if the licensee identified and corrected problems related to adverse weather conditions. August 6, 2007, standby service water systemAugust 8, 2007, turbine building cooling water systemAugust 9, 2007, plant service water systemDocuments reviewed by the inspectors included:Procedure 05-1-02-VI-2, "Hurricanes, Tornadoes, and Severe Weather,"Revision 108Procedure ENS-EP-302, "Severe Weather Response," Revision 4 Enclosure-5-SDC-P41, "System Design Criteria for Standby Service Water System P41,"Revision 3Procedure 04-1-01-P43-1, "Turbine Building Cooling Water System," Revision 44Procedure 04-1-01-P44-1, "Plant Service Water/ Radial Well System,"Revision 84The inspectors completed one sample.

1R02 Evaluations of Changes, Tests, or Experiments (71111.02)

a. Inspection Scope

From August 13-17, 2007, the inspectors reviewed the effectiveness of the licensee'simplementation of changes to the facility structures, systems, and components; risk-significant normal and emergency operating procedures; test programs; and the UFSAR report in accordance with 10 CFR 50.59, "Changes, Tests, and Experiments." The inspectors reviewed seven 10 CFR 50.59 safety evaluations performed by thelicensee since the last NRC inspection of the 10 CFR 50.59 process. The evaluations were reviewed to verify that licensee personnel had appropriately considered the conditions under which the licensee may make changes to the facility or procedures or conduct tests or experiments without prior NRC approval. In addition, the inspectors reviewed fifteen 10 CFR 50.59 screenings, in which licensee personnel determined that evaluations were not required, to ensure that the exclusion of a full evaluation was consistent with the requirements of 10 CFR 50.59. The inspectors reviewed a sample of recent licensee condition reports (CRs) related tothe 10 CFR 50.59 process to determine whether the licensee had identified problems and entered them into the CAP at the appropriate threshold. The inspection procedure specifies that the inspectors review a minimum sample offive licensee safety evaluations and a combination of ten applicability determinations or screenings. The inspectors completed a review of seven licensee safety evaluations and fifteen applicability/screenings.

b. Findings

No findings of significance were identified.

Enclosure-6-1R04Equipment Alignment (71111.04).1Partial System Walkdowns

a. Inspection Scope

The inspectors: (1) walked down portions of the two listed risk important systems andreviewed plant procedures and documents to verify that critical portions of the selected systems were correctly aligned; and (2) compared deficiencies identified during the walkdown to the licensee's UFSAR and CAP to ensure problems were being identified and corrected. July 23, 2007, and July 26, 2007, the inspectors walked down portions of thecontrol rod drive Train A system following a system maintenance outage.July 31, 2007, the inspectors walked down portions of the reactor core isolationcooling system following a system maintenance outage.Documents reviewed by the inspectors included:

Procedure 04-1-01-C11-1, "System Operating Instruction - Control Rod DriveHydraulic System," Revision 128System Piping Diagram M-1081A, "Control Rod Drive Hydraulic System,"Revision 38Procedure 04-1-01-E51-1, "System Operating Instruction - Reactor CoreIsolation Cooling System," Revision 124System Piping Diagram M-1083A, "Reactor Core Isolation Cooling System,"Revision 33System Piping Diagram M-1083B, "Reactor Core Isolation Cooling System,"Revision 36Vendor Manual 460000182, "Reactor Core Isolation Cooling"The inspectors completed two samples.

b. Findings

No findings of significance were identified.

Enclosure-7-1R05Fire Protection (71111.05)

a. Inspection Scope

Quarterly InspectionThe inspectors walked down the six listed plant areas to assess the material condition ofactive and passive fire protection features and their operational lineup and readiness.

The inspectors: (1) verified that transient combustibles and hot work activities were controlled in accordance with plant procedures; (2) observed the condition of fire detection devices to verify they remained functional; (3) observed fire suppression systems to verify they remained functional and that access to manual actuators were unobstructed; (4) verified that fire extinguishers and hose stations were provided at their designated locations and that they were in a satisfactory condition; (5) verified that passive fire protection features (electrical raceway barriers, fire doors, fire dampers, steel fire proofing, penetration seals, and oil collection systems) were in a satisfactory material condition; (6) verified that adequate compensatory measures were established for degraded or inoperable fire protection features and that the compensatory measures were commensurate with the significance of the deficiency; and (7) reviewed the corrective action process to determine if the licensee identified and corrected fire protection problems. Secondary Alarm StationControl Room Emergency Dormitory (Room 1OC604)Technical Support Center (Room 1OC608) Upper Relay Room (Room 1OC703)Instrument Motor Generator Room (Room 1OC707)Drywell, All Elevations (1A112)Documents reviewed by the inspectors included:

Procedure 10-S-03-4, "Control of Combustible Material," Revision 14Grand Gulf Nuclear Station Fire Pre-Plans, Revision 15Procedure 01-S-10-1, "Fire Protection Plan," Revision 102Procedure 10-S-03-9, "Control of Fire Pre-Plans," Revision 2The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification (71111.11).1Biennial InspectionThe licensed operator requalification program involves two training cycles that areconducted over a two year period.

In the first cycle, the annual cycle, the operators are Enclosure-8-administered an operating test consisting of job performance measures and scenarios. In the second part of the training cycle, the biennial cycle, operators are administered anoperating test and a written examination. The inspectors reviewed the results of the biennial cycle of the requalification program.

a. Inspection Scope

To assess the performance effectiveness of the licensed operator requalification program, the inspectors conducted personnel interviews, reviewed samples of both the operating and written examinations, observed ongoing operating examination activities, and reviewed personnel records.The inspectors interviewed five licensee personnel, consisting of three operators, aninstructor, and a training supervisor to determine their understanding of the policies and practices for administering requalification examinations. The inspectors also reviewed operator performance on the written and operating examinations. These reviews included observations of portions of the operating examination by the inspectors. The operating examinations observed included five job performance measures and two scenarios that were used in the current biennial requalification cycle. These observations allowed the inspectors to assess the licensee's effectiveness in conducting the operating test to ensure operator mastery of the training program content.

The results of these examinations were reviewed to determine the effectiveness of the licensee's appraisal of operator performance and to determine if feedback of performance analyses into the requalification training program was being accomplished.

The inspectors interviewed members of the training department to assess the responsiveness of the licensed operator requalification program to incorporate the lessons learned from both plant and industry events. Examination results were also assessed to determine if they were consistent with the guidance contained in NUREG 1021, "Operator Licensing Examination Standards for Power Reactors,"

Revision 9, and NRC Manual Chapter 0609, Appendix I, "Operator Requalification Human Performance Significance Determination Process." Forty-three out of fifty licensed operators passed the written examination. The seven operators (four reactor operators and three senior operators) that failed the written examination were remediated and successfully re-examined.The inspectors also reviewed the licensee's program for maintaining active operatorlicenses and ensuring the medical fitness of the licensed operators. The inspectors sampled records to ensure that all operators have active licenses and that any licenses reactivated since the last inspection were current. The inspectors also reviewed a sampling of licensed operator medical records to verify that the required physical examinations are being performed.

b. Findings

No findings of significance were identified.

Enclosure-9-.2Quarterly Inspection

a. Inspection Scope

The inspectors observed testing and training of senior reactor operators and reactoroperators to assess training, operator performance, and the evaluator's critique.

Specifically, the inspectors observed the training Scenario GSMS-LOR-00195-G5,

"Licensed Operator Requal: Emergency Plan Exercises (EP-2, EP-2A, EP-3, EP-4),

Revision 5, involved a crane boom crashing into a service water valve room at the standby service water basins and a subsequent feedwater line break outside containment. The scenario then led to an anticipated transient without scram (greater than 4 percent power) due to a blockage in the scram discharge volume. Documents reviewed by the inspectors included:GSMS-LOR-00195-G5, "Licensed Operator Requal: Emergency Plan Exercises(EP-2, EP-2A, EP-3, EP-4), Revision 5Training Procedure 14-S-02-20, "Preparing, Conducting and Review of SimulatorEvaluations," Revision 4The inspectors completed one sample.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

The inspectors reviewed the following maintenance rule scoped systems that havedisplayed performance problems to: (1) verify the appropriate handling of structure, system, and component (SSC) performance or condition problems; (2) verify the appropriate handling of degraded SSC functional performance; (3) evaluate the role of work practices and common cause problems; and (4) evaluate the handling of SSC issues reviewed under the requirements of the maintenance rule, 10 CFR Part 50, Appendix B, and the TSs. *control rod drive hydraulic system*containment cooling system Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

Enclosure-10-

b. Findings

Introduction.

The inspectors identified a Green noncited violation (NCV) of 10 CFR Part 50.65(a)(2) for the failure to demonstrate the performance or condition of the control rod drive system had been effectively controlled through the performance of appropriate scheduled maintenance.Description. On May 23, 2006, the licensee initiated CR-GGN-2006-2117 in response toa crack in the body of control rod drive system flow control Valve B. While reviewing failure evaluations for the control rod drive system, the inspectors noted the licensee did not consider the crack in the flow control valve to be a functional failure for the valve's maintenance rule function to provide maximum flow to the reactor vessel. The licensee's determination that the crack was not a functional failure was based on the valve's continued ability to open and provide flow. The inspectors challenged the assumptions used in the analysis, noting the evaluation only used an estimated as-found leak rate and failed to consider the pressure changes on the crack that would result from fully opening the valve or continued crack propagation. In response to the inspectors' concerns, the licensee initiated CR-GGN-2007-2361 and after further evaluation reclassified the degraded condition as a functional failure. The licensee also initiated CR-GGN-2007-3004 to evaluate the need for increased monitoring and goal setting for the control rod drive system.Analysis. Using NRC Inspection Manual Chapter 0612, Appendix E, Example 7.b, theinspectors determined the finding was more than minor since the failure of the control rod drive flow control valve caused the system to be placed in (a)(1) monitoring status.

This finding was characterized under the significance determination process as having a very low safety significance, because the maintenance rule aspect of the finding did not cause an actual loss of safety function of the system, nor did it cause a component to become inoperable. The cause of this finding has a crosscutting aspect in the area ofhuman performance associated with decision making, because licensee personnel failed to use conservative assumptions and did not verify the validity of the underlying assumptions used in making safety-significant decisions H.1(b).Enforcement. 10 CFR Part 50.65(a)(1) requires, in part, that licensees shall monitor theperformance or condition of SSCs within the scope of the rule against licensee established goals in a manner sufficient to provide reasonable assurance that the SSCs are capable of fulfilling their intended safety functions. 10 CFR Part 50.65(a)(2)requires, in part, that the monitoring specified in paragraph (a)(1) is not required where it has been demonstrated that the performance or condition of an SSC is being effectively controlled through the performance of appropriate preventive maintenance such that the SSC remains capable of performing its intended function. Contrary to the above, the licensee failed to demonstrate the performance or condition of the control rod drive system had been effectively controlled through the performance of appropriate scheduled maintenance. Specifically, the licensee failed to appropriately account for the failure of the Train B flow control valve on May 23, 2006, which demonstrated that the performance of the system was not being effectively controlled and goal setting and monitoring was required. Because this finding was of very low safety significance and has been entered in the CAP as CR-GGN-2007-3004, this violation is being treated as Enclosure-11-an NCV, consistent with Section IV.A.1 of the NRC Enforcement Policy: NCV 05000416/2007004-01, "Failure to Monitor Performance of the Control Rod DriveSystem."1R13Maintenance Risk Assessments and Emergent Work Control (71111.13).2Emergent Work Control

a. Inspection Scope

For the work activities listed below, the inspectors: (1) verified that the licenseeperformed actions to minimize the probability of initiating events and maintained the functional capability of mitigating systems and barrier integrity systems; (2) verified that emergent work-related activities such as troubleshooting, work planning/scheduling, establishing plant conditions, aligning equipment, tagging, temporary modifications, and equipment restoration did not place the plant in an unacceptable configuration; and, (3) reviewed the corrective action process to determine if the licensee identified and corrected risk assessment and emergent work control problems. *WO 86316, Control Rod Drive System Pump A Seal Replacement ExtendedWork Scope, July 25, 2007*WO 51085228, High Pressure Core Spray Diesel Generator Lube Oil CirculatingPump Failure, August 28, 2007 Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors: (1) reviewed plant status documents such as operator shift logs,emergent work documentation, deferred modifications, and standing orders in order to determine if an operability evaluation was warranted for degraded components; (2) referred to the UFSAR and design basis documents in order to review the technical adequacy of licensee operability evaluations; (3) evaluated compensatory measures associated with operability evaluations; (4) determined degraded component impact on any TS; (5) used the significance determination process to evaluate the risk significance of degraded or inoperable equipment; and (6) verified that the licensee has identified and implemented appropriate corrective actions associated with degraded components.

Enclosure-12-*CR-GGN-2007-03385, High Pressure Core Spray Relief Valve Lifted FollowingPump Shutdown during a Surveillance Test*CR-GGN-2007-03374, Control Room Air Conditioning System Flow Degraded Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications (71111.17).1Annual Inspection

a. Inspection Scope

The inspectors reviewed key affected parameters associated with energy needs,materials/replacement components, timing, heat removal, control signals, equipment protection from hazards, operations, flow paths, pressure boundary, ventilation boundary, structures, process medium properties, licensing basis, and failure modes for the modification listed below. The inspectors verified that: (1) modification preparation, staging, and implementation did not impair emergency/abnormal operating procedure actions, key safety functions, or operator response to loss of key safety functions; (2) postmodification testing maintained the plant in a safe configuration during testing by verifying that unintended system interactions will not occur, that SSC performance characteristics still meet the design basis, ascertaining the appropriateness of modification design assumptions, and that the modification test acceptance criteria has been met; and (3) the licensee has identified and implemented appropriate corrective actions associated with permanent plant modifications.The inspectors reviewed a modification that replaced obsolete Riley temperatureswitches with NUS switches. The inspectors ensured that the design bases, licensingbases, and performance capability of risk significant SSCs were not degraded by the modification. The inspection included a review of the engineering request, system drawings, and work package and observation of the field work during installation of the modification. The inspectors also reviewed the results of the post maintenance testing. *July 11, 2007, Riley temperature switch replacement with NUS temperatureswitch.Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed one sample.

Enclosure-13-

b. Findings

No findings of significance were identified..2Biennial Inspection

a. Inspection Scope

From August 13-17, 2007, the inspectors reviewed seven permanent plant modificationpackages and associated documentation, such as implementation reviews, safety evaluation applicability determinations, and screenings, to verify that they were performed in accordance with regulatory requirements and plant procedures. The inspectors also reviewed the procedures governing plant modifications to evaluate the effectiveness of the program for implementing modifications to risk-significant SSCs, such that these changes did not adversely affect the design and licensing basis of the facility. Further, the inspectors interviewed the cognizant design and system engineers for the identified modifications as to their understanding of the modification packages and process. The inspectors evaluated the effectiveness of the licensee's corrective action process toidentify and correct problems concerning the performance of permanent plant modifications by reviewing a sample of related CRs.The inspection procedure specifies inspector-review of a required minimum sample offive permanent plant modifications. The inspectors completed review of seven permanent plant modifications.

b. Findings

Introduction.

The inspectors identified a Green, NCV of 10 CFR Part 50, Appendix B,Criterion III, "Design Control," for the failure to translate the monitoring and subsequentactions associated with exceeding the maximum outdoor design basis temperature into a formal instruction or procedure. The maximum outdoor design basis temperature was derived from analysis for the standby service water pump room to ensure the standby service water system meets its functional goals.

Description.

The inspectors reviewed licensee Evaluation ER-GG-2006-0099-000, "Greater than 95°F Outdoor Air Temperature." This licensee evaluation was a result of a 2005 NRC question associated with outdoor air temperatures. In June 2006, the licensee evaluation evaluated the effects of high outdoor air temperature, exceeding the UFSAR 95°F maximum outdoor temperature, on standby service water pump room ventilation system and safety-related equipment in that room. The results of the evaluation concluded that outdoor air temperature could reach 102.5°F before the safety related equipment in the standby service water pump room would be challenged. The UFSAR was updated to reflect the new maximum outdoor air temperature of 102.5°F. In addition to the new maximum outdoor temperature limit, the engineering evaluationconcluded that actions may be necessary to prevent challenges to the operability of the Enclosure-14-safety-related equipment in the standby service water pump room if the outdoortemperature exceeded 102.5°F. Those actions included initiating a CR to evaluate the condition of the safety-related equipment when outdoor temperatures exceeded the maximum limit, monitoring outdoor air temperatures when temperature were near the maximum limit, and taking specific actions to return the standby service water pump room temperature to within design limits.The inspectors requested to review documentation that implemented the above actionsthat would control deviations of the UFSAR maximum outdoor air temperature limit. The licensee stated that there was no formally documented procedure to monitor temperatures or take necessary actions to prevent challenges. A formally documented procedure was never implemented because the licensee assumed, based on historical weather data, that outdoor temperatures will never exceed the new maximum outdoor temperature limit. The inspectors concluded that the lack of a specific instruction or procedure could affectthe monitoring and subsequent actions for areas containing safety-related equipment which use outdoor air for cooling. In the event the maximum analyzed outdoor temperature limit for the safety-related service water pump room is exceeded, a planned systematic action is necessary to assure the equipment would perform to meet its functional goals.Through followup discussions with the licensee staff, the inspectors were told, during theresolution of the 2005 NRC question, the engineering and operations departments made a cognizant decision not to establish a written procedure to continually monitor outdoor air temperatures. The decision was based on historical weather data and the perceived difficulty of continually monitoring and evaluating conditions when outdoor air temperature was near or exceeded 102.5°F. Although no formal written procedure existed to monitor temperatures, the licensee staff did direct the chemistry group to inform the licensing manager and control room should 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> average temperature readings exceed 102.5°F.

Analysis.

The inspectors determined that failure to translate a design basis limit foroutdoor air temperature into a formal instruction or procedure is a performance deficiency. The finding was more than minor because it affects the mitigating system cornerstone objective of ensuring the reliability of systems, standby service water, that respond to initiating events to prevent undesirable conditions. Using the Phase 1 worksheet in Inspection Manual Chapter 0609, "Significance Determination Process,"

this finding is determined to be of very low safety significance (Green) because there was no actual loss of a safety function, and the design basis limits had not been exceeded. The inspectors determined that the finding has a crosscutting aspect in the area human performance decision making because the licensee failed to use conservative assumptions in not establishing an instruction or procedure to monitor high outdoor air temperatures and for followup actions to ensure the standby service water system meets its functional goals H.1(b).Enforcement. 10 CFR Part 50, Appendix B, Criterion III, states, in part, measures shallbe established to assure that applicable regulatory requirements and the design basis Enclosure-15-are correctly translated into specifications, drawings, procedures, and instructions.These measures shall include provisions to assure that appropriate quality standards are specified and included in design documents and that deviations from such standards are controlled. Contrary to this, on June 28, 2006, the licensee failed to translate a design basis limit for outdoor air temperature into a formal instruction or procedure to monitor outdoor air temperatures during extreme high temperature weather to ensure the standby service water pump room design basis limit would not be exceeded.

Subsequent actions in the event the design basis temperature is exceeded were also not established. Because this finding is of very low safety significance and has been entered in the licensee's CAP as CR-GGN-2007-04076, this violation is being treated as a NCV consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000416/2007004-02, "Failure to Establish a Formal Instruction or Procedure toMonitor Outdoor Air Temperatures."1R19Postmaintenance Testing (71111.19)

a. Inspection Scope

The inspectors selected the six listed postmaintenance test activities of risk significantsystems or components. For each item, the inspectors: (1) reviewed the applicable licensing basis and/or design-basis documents to determine the safety functions; (2) evaluated the safety functions that may have been affected by the maintenance activity; and (3) reviewed the test procedure to ensure it adequately tested the safety function that may have been affected. The inspectors either witnessed or reviewed test data to verify that acceptance criteria were met, plant impacts were evaluated, test equipment was calibrated, procedures were followed, jumpers were properly controlled, test data results were complete and accurate, test equipment was removed, the system was properly re-aligned, and deficiencies during testing were documented. The inspectors also reviewed the UFSAR to determine if the licensee identified and corrected problems related to postmaintenance testing. *WO 116201, Control Room Air Conditioning Flow Test*WO 86886, Reactor Core Isolation Cooling Temperature Switch Replacement*WO 88931, Control Room Air Conditioning System Outage*WO 93109, Secondary Containment Isolation Valve P11F066 ActuatorModification*WO 119863, Division II Diesel Generator Turbocharger Lube Oil Pre-lube LineClogged

• WO 66378, Installation of Vibration Sensor on Control Room Air ConditioningMotors Enclosure-16-Documents reviewed by the inspectors are listed in the attachment.The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R20 Refueling and Outage Activities (71111.20)

a. Inspection Scope

For the outages listed below, the inspectors reviewed the following risk significantrefueling items or outage activities to verify defense in depth commensurate with the outage risk control plan and compliance with the TSs: (1) tagging/clearance activities; (2) electrical power; (3) decay heat removal; (4) inventory control; (5) reactivity control; (6) heatup and cooldown activities; (7) restart activities; and (8) licensee identification and implementation of appropriate corrective actions associated with refueling and outage activities. *Forced Outage 07-02: August 21 through August 22,2007*Forced Outage 07-03: September 1, through September 14, 2007Documents reviewed by the inspectors are listed in the attachment.

The inspectors completed two samples.

b. Findings

Introduction:

A Green, self-revealing NCV of TS 5.4.1(a), was identified involving thefailure to follow the system operating instructions to align valves in the fuel pool cooling and cleanup (FPCCU) system, causing both FPCCU pumps to trip and a subsequent loss of fuel pool cooling.Description: On August 23, 2007, the plant began a control rod blade disposal project todispose of spent control rods using an underwater cutting machine. During this process, the FPCCU heat exchangers and drain tank were isolated to keep irradiated particulate from plating out on the components, preventing an increase in radiological dose rates in the heat exchanger area. On the evening of September 1, 2007, the heat exchangers were realigned to lower pool temperatures overnight so that control rod disposal could continue on the following day without the heat exchangers in service. The operator performing this task failed to follow System Operating Instruction 04-1-01-G41, "Fuel Pool Cooling and Cleanup System," Revision 54, causing a high discharge pressure alarm to annunciate in the control room and a subsequent trip of both FPCCU pumps. Referencing the procedure, the valves should have been manipulated in a specificorder. The order is (1) open G41F011A(B) [inlet valve], (2) open G41F013A(B) [outlet valve], and then (3) close G41F012A(B) [bypass valve]. Contrary to what the procedure Enclosure-17-required, the order that the manipulations were made was (1) open G41F011A(B) [inletvalve], (2) close G41F012A(B) [bypass valve], and then (3) open G41F013A(B) [outlet valve]. This out of sequence manipulation caused the high discharge pressure on the outlet of the fuel pool cooling pumps and subsequent trip of both FPCCU pumps.

Following the event, control room operators promptly restored fuel pool cooling. The inspectors verified that fuel pool temperature did not exceed the 140 oF limit as specifiedby the Technical Requirements Manual, Section 6.7.4.Analysis: The performance deficiency associated with this finding was that theoperators failed to implement the FPCCU system operating instructions for system alignment. The finding is more than minor because it affects the human performance attribute of the barrier integrity cornerstone and affects the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Using NRC Manual Chapter 0609,

"Significance Determination Process," Phase 1 worksheet, inspectors determined that the finding has a very low safety significance since it only affects the radiological barrier function provided by the spent fuel pool system. The cause of this finding has a crosscutting aspect in the area of human performance associated with work practicesbecause licensee personnel failed to follow the correct sequence of valve manipulations required by procedure H.4(b).Enforcement: TS 5.4.1(a) requires written procedures to be implemented asrecommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Regulatory Guide 1.33 recommends procedures for fuel storage pool purification and cooling system. Contrary to the above, operators failed to follow System Operating Instruction 04-1-01-G41, "Fuel Pool Cooling and Cleanup System," Revision 54, resulting in both FPCCU pumps tripping and a subsequent loss of spent fuel pool cooling. Because this violation was of very low safety significance and was entered into the licensee's CAP as CR-GGN-2007-04284, this violation is being treated as an NCV consistent with Section VI.A.1 of the NRC Enforcement Policy:

NCV 05000416/2007004-03, "Failure to Follow Procedure Causes a Loss of Decay Heat Removal in the Spent Fuel Pool."1R22Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors reviewed the UFSAR, procedure requirements, and TSs to ensure thatthe six listed surveillance activities demonstrated that the SSCs tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the following significant surveillance test attributes were adequate: (1) preconditioning; (2) evaluation of testing impact on the plant; (3)acceptance criteria; (4) test equipment; (5) procedures; (6) jumper/lifted lead controls; (7) test data; (8) testing frequency and method demonstrated TS operability; (9) test equipment removal; (10) restoration of plant systems; (11) fulfillment of ASME Code requirements; (12) updating of performance indicator (PI) data; (13) engineering evaluations, root causes, and bases for returning tested SSCs not meeting the test acceptance criteria were correct; (14) reference setting data; and, (15) annunciator and Enclosure-18-alarm setpoints. The inspectors also verified that the licensee identified andimplemented any needed corrective actions associated with the surveillance testing. *July 17, 2007, local leak rate test of containment isolation Valve E12F028A perProcedure 06-OP-1E12-Q-0005, "LPCI/RHR Subsystem A MOV Functional Test," Revision 107*July 23, 2007, average power range monitor testing perProcedure 06-IC-1C51-R-0004, "APRM Time Response Testing," Revision 3*July 30, 2007, reactor core isolation cooling system quarterly testing perProcedure 06-OP-1E51-Q-0003, "RCIC Quarterly Pump Operability Verification,"

Revision 121*August 8, 2007, hot restart of standby diesel generator perProcedure 06-OP-1P75-R-0004, "Standby Diesel Generator 12: 18-month Functional Test," Revision 112*August 17, 2007, review of licensee leak detection measurement perProcedure 06-OP-1000-D-0001, "Daily Operating Logs," Revision 114*August 25, 2007, radiation meter response testing perProcedure 06-OP-1D17-Q-0015, "Main Steam Line Radiation Monitor Functional Test," Revision 100Documents reviewed by the inspectors are listed in the attachment.The inspectors completed six samples.

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications (71111.23)

a. Inspection Scope

The inspectors reviewed the UFSAR, plant drawings, procedure requirements, and TSsto ensure that the temporary modification listed below was properly implemented. The inspectors: (1) verified that the modification did not have an adverse effect on system operability/availability; (2) verified that the installation was consistent with modification documents; (3) ensured that the post-installation test results were satisfactory and that the impact of the temporary modification on permanently installed SSCs was supported by the test; (4) verified that the modification was identified on control room drawings and that appropriate identification tags were placed on the affected drawings; and, (5)verified that appropriate safety evaluations were completed. The inspectors verified that the licensee identified and implemented any needed corrective actions associated with Enclosure-19-temporary modifications. *July 18, 2007, temperature alarm set point raised for safety reliefValve B21F041B tailpipe temperature sensor Documents reviewed by the inspectors included:*EC1994, "Temporarily Raise Setpoint for 1B21F041B Tailpipe TemperatureAlarm to Prevent Masking of New Alarms," Revision 0*WO 116172 The inspectors completed one sample.

b. Findings

No findings of significance were identified.

Cornerstone:

Emergency Preparedness1EP6Drill Evaluation (71114.06)

a. Inspection Scope

For the emergency drill listed below, which contributes to the Drill/Exercise Performanceand emergency response organization performance indicators, the inspectors: (1)observed the training evolution to assess classification, notification, and protectiveaction requirement development activities; (2) compared inspector identified weaknesses and deficiencies against licensee identified findings to determine whether the licensee is properly identifying failures; and (3) determined whether licensee performance is in accordance with the guidance of the Nuclear Energy Institute (NEI)99-02, "Voluntary Submission of Performance Indicator Data," acceptance criteria. *July 11, 2007, the inspectors observed the licensee's emergency responseorganization in the simulator, the Emergency Response Facility, the Technical Support Center, and the Operations Support Center respond to a loss of reactor coolant and an unisolable main steam line break in the auxiliary building tunnel, leading to an unmonitored radiological release to the atmosphere.Documents reviewed by the inspectors included:

• GGNS 2007 3rd Quarter Emergency Preparedness Drill Evaluator's Notebook*Drill Emergency Notification Forms

• Procedure 10-S-01-1, "Activation of the Emergency Plan," Revision 116The inspectors completed one sample.

Enclosure-20-

b. Findings

No findings of significance were identified.Cornerstone: Occupational Radiation Safety4.OTHER ACTIVITIES

4OA2 Identification and Resolution of Problems

.1Routine Review of Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a daily screening of items entered into the licensee's CAP. This assessment was accomplished by reviewing work orders and condition reports and attending corrective action review and work control meetings. The inspectors:

(1) verified that equipment, human performance, and program issues were being identified by the licensee at an appropriate threshold and that the issues were entered into the CAP; (2) verified that corrective actions were commensurate with the significance of the issue; and, (3) identified conditions that might warrant additional follow-up through other baseline inspection procedures.

b. Findings

No findings of significance were identified.4OA3Event Follow-up (71153).1Personnel Performance During Nonroutine Evolutions, Events, and Transients

a. Inspection Scope

The inspectors: (1) reviewed operator logs, plant computer data, and/or strip charts forthe below listed evolutions to evaluate operator performance in coping with nonroutine events and transients; (2) verified that operator actions were in accordance with the response required by plant procedures and training; and (3) verified that the licensee has identified and implemented appropriate corrective actions associated with personnel performance problems that occurred during the events sampled.

• On July 7, 2007, the inspectors reviewed operator performance associated witha loss of instrument air following a break in a supply line in the turbine building.

The inspectors reviewed plant parameters, operator logs, and operator actions associated with off-normal event Procedure 05-1-02-V-9, "Loss of Instrument Air," Revision 34.*On August 21, 2007, the inspectors reviewed operator performance associatedwith a reactor scram due to the failure of a reactor feed pump controller.

Enclosure-21-*On August 26, 2007, the inspectors reviewed operator performance associatedwith an unplanned trip of the reactor recirculation Pump B motor due to a ground fault in the motor windings. The inspectors reviewed plant parameters, operator logs, and operator actions associated with off-normal event Procedure 05-1-02-III-3, "Reduction in Recirculation System Flow Rate,"Revision 106.The inspectors completed three samples.

b. Findings

No findings of significance were identified..2(Closed) LER 05000416/2007-02, "Reactor SCRAM due to Turbine Trip caused by Lossof Condenser Vacuum"Introduction: A Green self-revealing finding was identified involving the failure toproperly calibrate the main condenser hydraulic vacuum switch that established a higher trip setpoint that would prematurely actuate an automatic turbine trip and reactor scram for a degraded main condenser vacuum condition.

Description:

On May 19, 2007, a failure occurred in the high pressure condenserexpansion joint between the main turbine and condenser resulting in condenser air inleakage, and lowering condenser vacuum. Operators entered the loss of condenser vacuum Off-Normal-Event Procedure (ONEP), and reduced reactor power from 100 percent to 78 percent in order to reduce condenser load. As condenser vacuum was decreasing the operators made the decision to manually scram the reactor prior to reaching the automatic turbine trip setpoint of 21 inches Hg vacuum; however, the automatic turbine trip occurred at 24.9 inches Hg vacuum as trended by the plant data server. It was determined that the main condenser vacuum trip setpoint was calibrated incorrectly during the previous Refueling Outage RF15. During the investigation, the licensee determined that the as-found trip setpoint of the main condenser vacuum switch was set to trip at 25.89 inches Hg vacuum.On April 10, 2007, nearing the end of Refueling Outage RF15, plant personneldiscovered that the main condenser vacuum switch had not been calibrated. This was discovered after the turbine had been placed on the turning gear. The calibration methodology required that primary oil (from the turbine lube oil system) be disconnected from the switch so that instrument air could be used to simulate turbine lube oil pressure. The technicians were concerned that a significant amount of oil could be lost if the primary oil was disconnected with the turbine on the turning gear. In order to continue with plant startup, engineering revised the calibration procedure to use an adjustment to the speed simulation screw, instead of removing the primary oil supply line. The revised procedure required the speed simulation screw to be turned to the "full down" position. The technicians adjusted the speed simulation screw to be flush with the stem nut on the actuator, but did not set the screw to the "full down" position. This Enclosure-22-caused the main condenser switch calibration to set the vacuum trip to an incorrectsetpoint.

Analysis:

The finding was more than minor because it was associated with the initiatingevents cornerstone attribute of equipment performance and affected the associated cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during power operations. Using the Inspection Manual Chapter 0609, "Significance Determination Process," Phase 1 worksheet, the findingwas determined to have very low safety significance, because the finding did notcontribute to the likelihood that mitigating equipment or functions would not be availablefollowing a reactor trip. The cause of the finding was related to the human performance crosscutting component of resources in that the calibration procedure did not have clearinstructions detailing the methodology to adjust the speed simulation screw to the required position [H.2©]. This issue was entered into the licensee's CAP as CR-GGN-2007-02756.Enforcement: No violation of NRC requirements occurred. FIN 0500416/2007004-04.

Enclosure-23-4OA6Meetings, Including ExitOn August 17, 2007, the inspectors presented the results of InspectionProcedure 71111.02, "Evaluations of Changes, Tests, or Experiments," and Inspection Procedure 71111.17, "Permanent Plant Modifications," to Mr. M. Krupa, General Manager, Plant Operations, and other members of licensee management. The licensee acknowledged the issues and observations presented. The licensee confirmed that the inspectors retained no proprietary information.On August 30, 2007, the inspectors briefed Mr. R. Brian, Site Vice President, and othermembers of the licensee's staff of the results of the inspection. The licensee acknowledged the findings presented. After completion of this biennial requalification cycle, the remaining examination results were forwarded to the inspectors for their review. After determining that there were no findings of significance, the inspectors conducted a teleconference exit with Mr. C. Roberts, Operations Training Superintendent (Requalification), on October 1, 2007. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.

No proprietary information was identified.On October 10, 2007, the resident inspectors presented the inspection results toMr. R. Brian and others who acknowledged the findings. The licensee confirmed that the inspectors retained no proprietary information.4OA7Licensee-Identified ViolationsThe following violations of very low significance (Green) were identified by the licenseeand are violations of NRC requirements which meet the criteria of Section VI of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as NCVs.*TS 5.4.1(a) requires written procedures to be implemented as recommended byRegulatory Guide 1.33, Revision 2, Appendix A, February 1978. Appendix A recommends procedures for performing maintenance that can affect the performance of safety-related equipment. Contrary to this requirement, on March 30, 2007, maintenance personnel failed to properly implement work instructions by installing the wrong limit switch settings on the actuator for the standby service water reactor heat removal heat exchanger inlet valve. As a result, the valve opened further than the required throttled position, diverting more standby service water flow to the reactor heat removal heat exchanger.

This resulted in a degraded flow to other Division I safety-related systems. This condition was discovered following investigation of degraded flow in the control room air conditioning system, which was identified during performance of System Operating Instruction 04-1-03-Z51-1, "Control Room HVAC System," Revision 41, on July 2, 2007. This issue was documented in CRs-GGN-2007-03374 and CR-GGN-2007-03514. This finding is of very low safety significance because there was no actual loss of operability.

Enclosure-24-*TS 5.4.1(a) requires written procedures to be implemented as recommended byRegulatory Guide 1.33, Revision 2, Appendix A, February 1978. Appendix A recommends procedures for performing maintenance that can affect the performance of safety-related equipment. Contrary to this requirement, on September 5, 2007, maintenance personnel failed to properly implement an infrequently performed test or evolution procedure to lift and move a 29 ton recirculation system pump motor through the drywell. The procedure required redundant rigging so that the lift could be designated as single failure proof and not require a load path analysis. The individual directing the lift ordered the movement of the motor without redundant rigging through most of the planned drywell load path. The inappropriate movement was identified by individuals in the drywell during the move and by the test coordinator in the control room via a video monitor. This issue was documented in CR-GGN-2007-04382. This finding is of very low safety significance since there was no actual loss of operability. ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

C. Abbott, Acting Manager, Quality Assurance

K. Baker, Engineer, Design Engineering

D. Barfield, Director, Engineering

C. Bell, Senior Operations Instructor

C. Bottemiller, Manager, Plant Licensing

R. Brian, Vice President, Operations

M. Causey, Senior Lead Technical Specialist

R. Collins, Manager, Operations

D. Cooper, Senior Operations Instructor

D. Coulter, Licensing Specialist, Plant Licensing

L. Eaton, Senior Lead Engineer

B. Edwards, Minority Owner Specialist

C. Ellsaesser, Manager, Maintenance

R. Fuller, Engineer, Design Engineering

K. Grillis, Senior Operations Instructor

M. Guynn, Manager, Emergency Preparedness

E. Harris, Manager, Corrective Action and Audits

T. Harrellson, Senior Operations Instructor

J. Hixon, Engineer, Design Engineering

D. Jones, Manager, System Engineering

D. Killingsworth, Reactor Operator

M. Krupa, General Manager, Plant Operations

G. Lantz, Supervisor, Design Engineering

M. Larson, Senior Licensing Engineer

C. Mason, Quality Assurance Auditor

E. Mathes, Shift Manager

M. McAdory, Senior Operations Instructor

D. McDirmid, Maintenance Rule Engineer

J. Owens, Licensing Specialist, Plant Licensing

M. Rasch, Senior Operations Instructor

S. Reeves, Acting Operations Training Superintendent (Initial)

C. Roberts, Operations Training Superintendent (Requalification)

M. Rohrer, Manager, System Engineering

F. Rosser, Supervisor, Radiation Protection

D. Smith, Control Room Supervisor

T. Tankersley, Manager, Training

T. Thornton, Manager, Design Engineering

K. Walker, Superintendent, Reactor Engineering

D. Wilson, Supervisor, Design Engineering

R. Wilson, Superintendent, Radiation Protection

P. Worthington, Supervisor, Engineering

AttachmentA-2

NRC personnel

W. Walker, Senior Project Engineer, Reactor Project Branch C

R. Bywater, Senior Reactor Analyst, Region IV

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

OpenedNoneOpened and

Closed

05000416/FIN-2007004-01NCVFailure to Monitor Performance of the Control Rod DriveSystem

05000416/FIN-2007004-02NCVFailure to Establish a Formal Procedure to MonitorOutdoor Air Temperatures

05000416/FIN-2007004-03NCVFailure to Follow Procedures Caused Loss of Decay HeatRemoval in the Spent Fuel Pool

05000416/FIN-2007004-04FINReactor SCRAM due to Turbine Trip caused by Loss ofCondenser VacuumClosed

05000416/LER-2007-004-02LERReactor SCRAM due to Turbine Trip caused by Loss ofCondenser VacuumDiscussedNone

LIST OF DOCUMENTS REVIEWED

In addition to the documents called out in the inspection report, the following documents wereselected and reviewed by the inspectors to accomplish the objectives and scope of theinspection and to support any findings:

AttachmentA-3

Section 1R02: Evaluations of Changes, Tests, or Experiments10

CFR 50.59 EvaluationsSE-2005-0003SE-2005-0006SE-2006-0003SE-2006-0004SE-2006-0005SE-2006-0006SE-2007-0002ProceduresNUMBERTITLEREVISIONEN-LI-100Process Applicability Determination4EN-LI-10110

CFR 50.59 Review Program310

CFR 50.59 Applicability Determinations/ScreensNUMBERTITLEREVISIONER-GG-2005-0090Develop Modification Package(s) for Raising Normal, HI,and

HI-HI Level Setpoints for LPFWH's #4A/B/C and #3A/0ER-GG-2005-0255Unit 1 Instrument Air Vibration Trips0ER-GG-2005-0280Evaluation of Alternate ASCO Solenoid Replacement PNHTX821027 for Original

LB-X-8210270ER-GG-2006-0236Removal of Control Rod Drive Relief Valves 1C11F025A/Bfor Seal Purge Flow0ER-GG-2003-0018-047 Spent Fuel Cask Handling Crane 1T31E001 ProcessApplicability Determination/Screening0ER-GG-2003-0018-049 Cold Proof Test of Spent Fuel Cask Crane ProcessApplicability Determination/Screening0ER-GG-2006-0237-000Revise the in-service inspection requirements for HighEnergy Break Exclusion Region (BER) 0DRN J606.0Document Revision Notice

ER-GG-2006-0116-000Approved Alternate Replacement Solenoid Valve15ER-GG-2005-0323-000Engineering Request; I&C TRM surveillance Reduction 0ER-GG-2006-0116-000Evaluate ASCO solenoid Valve replacement E51 ReactorCore Isolation Cooling System0ER-GG-2006-0220-001Set up Valve to Eliminate Negative Margin0

AttachmentA-4ER-GG-2007-0048-000Setpoint Change for Bus 15AA and 16AB UndervoltageRelay TimersER-GG-2007-0003-000Provide Temporary Weld Repair for CRD Flow ControlValve, 1C11F002A0ER-GG-2006-0262-000Increase the Reset Value for Safeguard Switchgear andBattery Rooms Air Handling Unit Fan Discharge Temper0ER-GG-2005-0242-000Install Second Mechanical Gag Identical to the ExistingMechanical Gag to Ensure That Valves 1P71F2980MiscellaneousNUMBERTITLEREVISIONGNRI-2006/00006Grand Gulf Nuclear Station, Unit 1 - Issuance ofAmendment Re: Adoption of Approved GenericChanges to the TechnicalSpecifications (TAC NO. MC6651)0GNRO-2005/00016License Amendment Request, Adoption of NRCApproved Generic Changes to the Improved TechnicalSpecifications, Grand Gulf Nuclear Station, Unit 10TSTF-400Clarify Surveillance Requirement on Bypass of DieselGenerator Automatic Trips0NUREG-0871Supplement 7Safety Evaluation Report Related to the Operation ofGrand Gulf Nuclear Station, Units 1 and 20LO-GLO 2007-0124Permanent Plant Modifications and 50.59 ProgramReviews (Pre-NRC) Self-Assessment0LBD-2005-081LBD Change Form0CRsCR-GGN-2005-03193CR-GGN-2006-02777CR-GGN-2006-01510CR-GGN-2005-03231CR-GGN-2006-01237

Section 1R11: Licensed Operator RequalificationProcedures01-S-04-2, "Licensed Operator Requalification Training"01-S-02-17, "Administration of Annual Exam"01-S-02-20, "Preparing, Conducting, and Review of Simulator Evaluations"

AttachmentA-5Job Performance Measures (JPMs)GJPM-OPS-R2731, "Transfer of electrical loads from Service Transformer 21 to ServiceTransformer 11," Revision 00GJPM-OPS-L62-1, "Startup Static Inverter 1Y81," Revision 01GJPM-OPS-Z5101, "Secure Control Room Standby Fresh Air Unit," Revision 00GJPM-OPS-G3311, "Align RWCU for Vessel Level Control," Revision 00GJPM-OPS-C61-2, "Perform Attachment IV of Shutdown from Remote Shutdown Panel,ONEP," Revision 00GJPM-OPS-C10181, "Rotate Operating CRD Pumps," Revision 00GJPM-OPS-EAL19, "Emergency Event Classification JPM, Control Room Evacuation,"Revision 2GJPM-OPS-B2110, "Operate Turbine Pressure Control / SRVs," Revision 00GJPM-OPS-E1201, "Startup Shutdown Cooling B," Revision 1GJPM-OPS-N2101, "RFPT HPU Shutdown, Revision 00GJPM-OPS-R2108, "Reset Undervoltage Lockouts on BOP Buses," Revision 00GJPM-OPS-EAL07, "Emergency Event Classification JPM," Revision 3ScenariosGSMS-LOR-AEX25, "Spurious RCIC Isolation Due to Failed RHR Temperature Switch; RFPT APump Trip; Feedwater Line A Break in the Drywell, Revision 07GSMS-LOR-AXE21, Drifting/Stuck Rod; RFPT Trip; Feedwater Line Break in Drywell; ATWS,Revision 05GSMS-LOR-AEX01, AC@ level instrument failure/FW heater 6A tube leak/FW line rupture indrywell, Revision 04GSMS-LOR-AEX16, Control rod drift; EHC leak; ATWS, Revision 06

AttachmentA-6Written ExaminationsLOR-2006-Cycle 3-Exam 1LOR-2006-Cycle 2-Exam 1LOR-2006-Cycle 1-Exam 1LOR-2006-Cycle 6-Exam 1LOR-2006-Cycle 7-Exam 1LOR-2006-Cycle 2-Exam 1MiscellaneousGGNS Operating Test Walk Through Results (Weeks 1-4)2007 Annual JPM Selection (Weeks 1-6)GLO-2007-0122, Licensed Operator Requalification Training Inspection Assessment, June 4-7,2007Grand Gulf Nuclear Station Operations Training Corporate Assessment, February 15, 2007Remediation Package for Crew Failure on SimulatorCRsCR-GGN-2005-03352 dated 09/08/2005, "Operating Experience Report on Weaknesses inOperator Fundamentals"CR-GGN-2006-02308 dated 05/30/2006, "Members of the Emergency Response OrganizationOverdue on Training"CR-GGN-2005-05124 dated 11/30/2005, "Watchstanders Not Fully E-Plan Qualified"CR-GGN-2005-03099 dated 08/11/2005, "2005 Biennial Exam Failures"

Section 1R12: Maintenance RuleProceduresEN-DC-203, "Maintenance Rule Program," Revision 0EN-DC-204, "Maintenance Rule Scope and Basis," Revision 0EN-DC-205, "Maintenance Rule Monitoring," Revision 0EN-DC-206, "Maintenance Rule (a)(1) Process," Revision 0Maintenance Rule Failure Database for System C11GGNS Maintenance Rule (a)(1) Systems Report, July 2007GGNS Maintenance Rule (a)(1) Systems Report, September 2007Maintenance Rule System Notebook

AttachmentA-7CRs (C11)CR-GGN-2006-2923CR-GGN-2006-2117CR-GGN-2007-2024CR-GGN-2007-2882CR-GGN-2007-3162CRs (M41)CR-GGN-2006-02920CR-GGN-2006-03502CR-GGN-2006-03999CR-GGN-2007-02498CR-GGN-2007-02563

Section 1R13: Maintenance Risk Assessments and Emergent Work ControlProcedures01-S-18-6, "Risk Assessment of Maintenance Activities," Revision 518-S-01-1, "Planning Guidelines," Revision 2EN-WM-101, "On-Line Work Management Process," Revision 1EN-WM-102, "Work Implementation and Closeout," Revision 0Work Order 86316Work Order 51085228CRCR-GGN-2007-04214Section 1R15:

Operability DeterminationsEN-OP-104, "Operability Determinations," Revision 2EN-LI-102, "Corrective Action Process," Revision 10Drawing M-1086, "P&ID High Pressure Core Spray System," Revision 30System Design Criteria

SDC-E22, "High Pressure Core Spray System E22," Revision 2System Operating Instruction 04-S-01-Z51-1, "Control Room HVAC System," Revision 42CRsCR-GGN-2007-3374CR-GGN-2007-3385CR-GGN-2007-3514Section 1R17A:

Permanent Plant ModificationsEngineering Report

ER-GG-2004-0230-001-00, "Replacement of E31 Riley TemperatureSwitches with NUS Model A076MA," Revision 1QP-367.0, "Seismic Qualification Review Package for Riley Temperature Switch Model 86"Trentec Test Plan 1S001.0 Revision 1, "NUS Temperature Switch Seismic Qualification TestProcedure" AttachmentA-8Seismic Qualification Report 1S001.0, Revision 0, Appendix H Dynamic Qualification Records for Temperature Switch, GE, October 1988Drawing

GE-NE 164C5687Leak Detection Temperature Monitor Qualification Report, "NUS-A076QA," Revision 0Work Order 86886Work Order 86312CRsCR-GGN-2007-3495CR-GGN-2007-3502Section 1R17B:

Permanent Plant ModificationsEngineering RequestsNUMBERTITLEREVISIONER-GG-2005-0323-000Engineering Request; I&C TRM Surveillance Reduction 0ER-GG-2006-0099Engineering Evaluation on Greater than 95°F Outdoor AirTemp.0ER-GG-92-0002Evaluation of Safety Related Electrical Equipment in VariousRooms With Elevated Post LOCA Temperatures2ER-GG-2004-0219-000Develop Design Change Package to Change Four AGCOThermal Relief Valves to Alternate Brand Name/Model0

ER-GG-2003-0018-006Evaluate 150-Ton Cask Handling Crane0ER-GG-2005-0009-001Modification of Cask Handling Crane0ER-GG-2005-0110-000Remove the Division I and II Diesel Trip on Low ControlPressure During a LOCA0ER-GG-2006-0161-000Use of Ultra Low Sulfur Diesel Fuel0ER-GG-2004-0219-000Develop Design Change Package to Change Four AGCOThermal Relief Valves to Alternate Brand Name/model0ER-GG-2003-0234-000Extend Frequency of DG Fuel Oil Storage Tank Cleaning0

AttachmentA-9ER-GG-2003-0234-001Extend Frequency of Division II Dg Fuel Oil Storage TankCleaning0ER-GG-2005-0318-000Basis for the Div 1/2 Governor Replacement0CalculationsNUMBERTITLEREVISIONEC 3.8.5Engineering Calculation SSW Pumphouse HVAC0M3.8.005Standby Service Water Pump House Ventilation System0MC-Q1P75-90190Diesel Fuel Storage Requirements for the Division 1 and 2Diesel Generators2DrawingsNUMBERTITLEREVISION3NC3188, Sht. 5Dresser Flow Control, Consolidated Safety Relief Valve0FSK-S-1061B-080-GHBC-185/HBD-254, SSW from

HBC-84 to PSV F031A &Drain from PSV F031A11MiscellaneousNUMBERTITLEREVISIONLDC 2001-059Licensing Document Change Surveillance Change inFrequency March 15,2001M-204.0Standard for Fabrication and Installation of Nuclear ServicePiping1GGNS-MS-03Mechanical Standard for Piping Class Sheets1Work OrdersNUMBERTITLEREVISION5032644508392506CH1000-V-0038 DFO Receipt Analyses18392606CH1000-V-0038 DFO Receipt Analyses110486006CH1000-V-0038 DFO- Receipt Analyses110486106CH1000-V-0038 DFO Receipt Analyses1

AttachmentA-10CRsCR-GGN-2004-00076CR-GGN-2006-03977CR-GGN-2006-04035CR-GGN-2007-01405CR-GGN-2007-04070CR-GGN-2007-04076CR-GGN-2007-04076CR-GGN-2007-04077CR-GGN-2007-04082CR-GGN-2007-04082

Section 1R19: Postmaintenance TestingDrawing

FSK-I-999-280-G, "Division 2 Diesel Generator Lube Oil Tubing Run," Revision 4ENS-MA-114, "Post Maintenance Testing," Revision 5Work Orders1121871162011198636637886886889318946593109CRsCR-GGN-2007-3584CR-GGN-2007-4193

Section 1R20: Refueling and Outage ActivitiesProcedures03-1-01-3, "Plant Shutdown," Revision 11503-1-01-1, "Cold Shutdown to Generator Carrying Minimum Load," Revision 138EN-OP-102, "Protective and Caution Tagging," Revision 6EN-MA-118, "Foreign Material Exclusion," Revision 2M-1085A, "Residual Heat Removal System," Revision 67M-1085C, "Residual Heat Removal System," Revision 1701-S-06-26, "Post-Trip Analysis," Revision 1601-S-06-58, "Infrequently Performed Test or Evolution," Revision 001-S-06-7, "Containment and Drywell Access Control," Revision 104EN-HU-103, "Human Performance Error Review," Revision 0CRsCR-GGN-2007-4128CR-GGN-2007-4163CR-GGN-2007-4175CR-GGN-2007-4177CR-GGN-2007-4201CR-GGN-2007-4321CR-GGN-2007-4382CR-GGN-2007-4576Section 1R22:

Surveillance TestingProcedure 01-S-06-12, "GGNS Surveillance Test Program," Revision 109Procedure 06-OP-1E12-Q-0005, "LPCI/RHR Subsystem A MOV Functional Test," Revision 107Procedure 06-IC-1C51-R-0004, "APRM Time Response Testing," Revision 3

AttachmentA-11Procedure 06-OP-1E51-Q-0003, "RCIC Quarterly Pump Operability Verification," Revision 121Procedure 06-OP-1P75-R-0004, "Standby Diesel Generator 12: 18-Month Functional Test,"Revision 112Procedure 06-OP-1000-D-0001, "Daily Operating Logs," Revision 114Procedure 06-OP-1D17-Q-0015, "Main Steam Line Radiation Monitor Functional Test,"Revision 100

Section 4OA3:

Event FollowupProcedures07-S-53-N32-N035-1, "Loop Calibration Instruction - Turbine Hydraulic Low Vacuum Trip,"Revision 00107-S-53-N32-N035-1, "Loop Calibration Instruction - Turbine Hydraulic Low Vacuum Trip,"Revision 00207-S-53-N32-N035-1, "Loop Calibration Instruction - Turbine Hydraulic Low Vacuum Trip,"Revision 00305-1-02-V-9 "Loss of Instrument Air," Revision 34

05-1-02-III-3, "Reduction in Recirculation System Flow Rate," Revision 106CRsCR-GGN-2007-02756

LIST OF ACRONYMS

CAPcorrective action programCRcondition report

FPC [[]]

CU fuel pool cooling and cleanup

GGN [[]]

SGrand Gulf Nuclear Station

NCVnoncited violation

SSCstructure, system, and component

TST echnical Specification

UFSA [[]]

RU pdated Final Safety Analysis Report