IR 05000416/2011005
| ML120330608 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 02/02/2012 |
| From: | Vincent Gaddy NRC/RGN-IV/DRP/RPB-C |
| To: | Mike Perito Entergy Operations |
| References | |
| IR-11-005 | |
| Download: ML120330608 (61) | |
Text
February 2, 2012
Mike Perito Vice President Operations Entergy Operations, Inc.
Grand Gulf Nuclear Station P.O. Box 756 Port Gibson, MS 39150 Subject: GRAND GULF
- NRC INTEGRATED INSPECTION REPORT NUMBER 05000416/2011005
Dear Mr. Perito:
On December 31, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Grand Gulf Nuclear Station Unit 1.
The enclosed inspection report documents the inspection results which were discussed on January 10, 2012, with you and other members of your staff.
The inspections examined activities conducted under your license as they relate to safety and compliance 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.
One NRC identified finding of very low safety significance (Green) was identified during this inspection.
This finding was determined to involve a violation of NRC requirements. The NRC is treating this violation as non
-cited violation (NCV) consistent with Section 2.3.2 of the Enforcement Policy.
If you contest this non
-cited violation
, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555
-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555
-0001; and the NRC Resident Inspector at Grand Gulf Nuclear Station
. If you disagree with a cross
-cutting aspect assignment in this report, you s hould provide a response within 30 days of the date of this inspection report, with the basis for your U N I T E D S T A T E S N U C L E A R R E G U L A T O R Y C O M M I S S I O N R E G I O N I V1600 EAST LAMAR BLVD A R L I N G T O N , T E X A S 7 6 0 1 1-4511 Vice President of Operations
- Mike Perito - 2 - disagreement, to the Regional Administrator, Region IV; and the NRC Resident Inspector at Grand Gulf Nuclear Station.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Document Access and Management 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/ Vincent Gaddy, Chief Project Branch C Division of Reactor Projects Docket No: 0 50 00 0 416 License No: NPF-29
Enclosure:
NRC Inspection Report 05000 416/2011005
w/Attachment:
Supplemental Information cc: Electronic Distribution
Vice President of Operations
- Mike Perito - 3 - Electronic distribution by RIV:
Regional Administrator (Elmo.Collins@nrc.gov
) Deputy Regional Administrator (Art.Howell@nrc.gov)
DRP Director (Kriss.Kennedy@nrc.gov) DRP Deputy Director (Troy.Pruett@nrc.gov)
DRS Director (Anton.Vegel@nrc.gov) DRS Deputy Director (Tom.Blount@nrc.gov)
Senior Resident Inspector (Rich.Smith@nrc.gov
) Resident Inspector (Blake.Rice@nrc.gov) Branch Chief, DRP/C (Vincent.Gaddy@nrc.gov) Senior Project Engineer, DRP/C (Bob.Hagar@nrc.gov
) Project Engineer, DRP/C (Rayomand.Kumana@nrc.gov
) Project Engineer, DRP/C (Jonathan.Braisted@nrc.gov)
GG Administrative Assistant (Alley.Farrell@nrc.gov) Public Affairs Officer (Victor.Dricks@nrc.gov
) Public Affairs Officer (Lara.Uselding@nrc.gov
) Project Manager (Alan.Wang@nrc.gov)
Acting Branch Chief, DRS/TSB (Ryan.Alexander@nrc.gov
) OEDO RIV Coordinator (Lydia.Chang@nrc.gov) RITS Coordinator (Marisa.Herrera@nrc.gov
) Regional Counsel (Karla.Fuller@nrc.gov
) Congressional Affairs Officer (Jenny.Weil@nrc.gov)
OEMail Resource ROPreports File located: R:
\_REACTORS\_GG\2011\GG 201100 5 RP-RLS.docx SUNSI Rev Compl.
Yes No ADAMS Yes No Reviewer Initials VGG Publicly Avail Yes No Sensitive Yes No Sens. Type Initials VGG SRI:DRP/PBC RI:DRP/PBC SPE:DRP/PBC C:DRS/EB1 C:DRS/EB2 RLSmith BBRice BHagar TRFarnholtz GMiller VGG via Email VGG via Email
/RA/ /RA/ /RA/ 1/31/12 1/31/12 1/31/12 1/26/12 1/30/12 C:DRS/OB AC:TSB 1 C:DRS/PSB1 C:DRS/PSB2 C:DRP/C MHaire RAlexander MHay GEWerner VGaddy LMG for MH
/RA/ /RA/ /RA/ /RA/ 1/30/12 1/26/12 1/26/12 1/30/12 2/2/12 OFFICIAL RECORD COPY T=Telephone E=E
-mail F=Fax Enclosure U.S. NUCLEAR REGULATORY COMMISSION REGION IV Docket: 05000416 License: NPF-29 Report: 05000416/201100 5 Licensee: Entergy Operations, Inc.
Facility: Grand Gulf Nuclear Station Unit 1 Location: 7003 Baldhill Road Port Gibson, MS 39150 Dates: September 28, 2011, through December 31, 2011 Inspectors:
R. Smith, Senior Resident Inspector B. Rice, Resident Inspector P. Elkmann, Senior Emergency Preparedness Inspector G. Guerra, CHP, Emergency Preparedness Inspector G. Schlapper, High Level Waste Inspector, Nuclear Materials Division W. Sifre , Senior Reactor Inspector Approved By:
Vincent Gaddy, Chief Reactor Project Branch C Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
- 09/28/2011
- 12/31/2011
- Grand Gulf Nuclear Station , Integrated Resident and Regional Report;
Fire Protection
. The report covered a 3
-month period of inspection by resident inspectors and announced baseline inspection s by region-based inspector s. One Green non-cited violation of significance w as identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter 0609, "Significance Determination Process." The cross-cutting aspect is determined using Inspection Manual Chapter 0310, "Components Within the Cross Cutting Areas." Findings for which the significance determination process 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," Revision 4, dated December 2006.
A. NRC-Identified Findings and Self-Revealing Findings
Cornerstone: Mitigating Systems
- Green.
The inspectors identified a non-cited violation of 10 CFR 50 Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for failure to perform an adequate inspection of probable maximum precipitation door seals protecting safety related equipment.
Inspectors f ound that one of the door seals to standby service water pump house A was in a degraded condition. The inspectors identified that the door seal did not make complete contact with the door frame all the way around. The licensee determined that the probable maximum precipitation seal for the identified door was in a degraded condition. Failure of this door seal during a probable maximum precipitation event could potentially cause flooding of the standby service water pump house A. Immediate corrective actions included the site initiating compensatory actions for the degraded seal by staging sand bags in the area and requiring monitoring of the affected door during heavy rainfall. The licensee entered this issue into the corrective action program as Condition Report CR
-GGN-2 011-07687. The finding is more than minor because it is associated with the protection against external factors attribute of Mitigating System Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In Inspection Manual Chapter 0609.04, "Phase 1
- Initial Screening and Characterization of Findings," the inspectors used the seismic, flooding, and severe weather Table 4b and determined that it would not affect multiple trains of safety equipment and that the finding had very low safety significance (Green). This finding has a cross-cutting aspect in the area of human performance associated with the resources component in that the licensee's procedure used for the inspection of the door seals did not take into account the status of the pump house ventilation system while performing the door seal inspection
, and therefore, the licensee failed to make the required adjustments to the door seals resulting in their inspections of the probable maximum precipitation door seals being inadequate [H.2 (c)] (Section 1R05).
B. Licensee-Identified Violations
None
REPORT DETAILS
Summary of Plant Status
Grand Gulf Nuclear Station Unit 1 began the inspection period at 96 percent rated thermal power. During the inspection period, the plant was limited to 96 percent power due to the isolation of the second
-stage steam to both moisture separator reheater s A and B on January 9, 2011.
On September 30, 2011, operators reduced power to 6 5 percent for a planned control rod sequence exchange, control rod friction testing, control rod testing, and turbine testing.
The plant was returned to 96 percent power on October 5, 2011.
On October 29, 2011, operators reduced power to 85 percent for a planned control rod testing.
The plant was returned to 96 percent power on October 30, 2011.
On November 10, 2011, the plant reduced power to 49 percent due to a trip of the reactor feedpump turbine B. While the plant was at a reduced power level
, the site performed control rod friction testing. The plant was returned to 96 percent power on November 24, 2011
, after performing required rod pattern adjustments during power accession
.
On November 25, 2011, operators reduced power to 46 percent due to a partial loss of plant service water. The plant was returned to 96 percent power on November 28, 2011.
On December 17, 2011, operators reduced power to 64 percent for a planned control rod sequence exchange, control rod friction testing, control rod testing and turbine testing. The plant was returned to 96 percent power on December 18,
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness
1R04 Equipment Alignments
.1 Partial Walkdown
a. The inspectors performed partial system walkdowns of the following risk
-significant systems: Inspection Scope Division 2 combustible gas control system while the division 1 system was in an outage Low pressure core spray system following a quarterly functional test The inspectors selected these systems based on their risk significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempte d to identify any discrepancies that could affect the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Updated Final Safety Analysis Report, technical specificatio n requirements, administrative technical specifications, outstanding work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable o f performing their intended functions. The inspectors also inspected accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of two partial system walkdown sample s as defined in Inspection Procedure 71111.04-05. b. No findings were identified.
Findings
.2 Complete Walkdown
a. On November 17, 2011, the inspectors performed a complete system alignment inspection of the reactor core isolation cooling system to verify the functional capability of the system. The inspectors selected this system because it was considered both safety significant and risk significant in the licensee's probabilistic risk assessment. The inspectors inspected the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, as appropriate, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. The inspectors reviewed a sample of past and outstanding work orders to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the corrective action program database to ensure that system equipment
-alignment problems were being identified and appropriately resolved. Specific documents reviewed during this inspection are listed in the attachment.
Inspection Scope These activities constitute completion of one complete system walkdown sample as defined in Inspection Procedure 71111.04-05. b. No findings were identified.
Findings
1R05 Fire Protection
.1 Quarterly Fire Inspection Tours
a. The inspectors conducted fire protection walkdowns that were focused on availability, accessibility, and the condition of firefighting equipment in the following risk
-significant plant areas:
Inspection Scope Standby service water A pump house and valve room (rooms 1M110 and 1M112)
Standby service water B pump house and valve room (rooms 2M110 and 2M112)
Yard electrical manholes (MH01, MH20 and MH21)
Auxiliary building elevation 208 (1A431, 1A438, 1A532, 1A602, 1A603, and 1A604) The inspectors reviewed areas to assess if licensee personnel had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant; effectively maintained fire detection and suppression capability; maintained passive fire protection features in good material condition; and had implemented adequate compensatory measures for out of service, degraded or inoperable fire protection equipment, systems, or features, in accordance with the licensee's fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plant's Individual Plant Examination of External Events with later additional insights, their potential to affect equipment that could initiate or mitigate a plant transient, or their impact on the plant's ability to respond to a security event. Using the documents listed in the attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed
- that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensee's corrective action program. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four quarterly fire
-protection inspection sample s as defined in Inspection Procedure 71111.05-05.
b. Findings
Introduction
. The inspectors identified a Green, non
-cited violation of 10 CFR 50 Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for failure to perform an adequate inspection of probable maximum precipitation door seals protecting safety related equipment.
Description.
During a quarterly fire inspection on October 24, 2011, inspectors found that one of the door seals to standby service water pump house A was in a degraded condition. The inspectors identified that the door seal did not make complete contact with the door frame all the way around. The inspectors notified plant personnel of their concerns, and the licensee performed an evaluation of the standby service water pump house A door seal. The licensee determined that the probable maximum precipitation seal for the identified door was in a degraded condition. Grand Gulf Nuclear Station previously performed the inspection of these door seals on October 10, 2011, with satisfactory results.
When this inspection was conducted, the pump house ventilation was not in operation. The NRC's inspection was conducted while the ventilation was in service, and this changed the conditions in the room. Previous to the October 10 th inspection, the licensee stated that one door seal in the room was adjusted while ventilation was in service, but the other doors' seal was not adjusted under the same conditions. Failure of this door seal during a probable maximum precipitation event could potentially cause flooding of the standby service water pump house A. The licensee initiated compensatory actions for the degraded seal which included staging sand bags in the area and requiring monitoring of the affected door during heavy rainfall. The licensee initiated a work order to replace the degraded seal on the door. They also revised operator rounds to perform inspections of all probable maximum precipitation doors protecting safely related equipment on a daily bases.
The licensee documented this issue in their corrective action program as Condition Report CR-GGN-2011-07687. Additionally, the licensee conducted a root cause evaluation to determine the cause of the failure of the seals and to put corrective actions in place to prevent recurrence.
Analysis.
The inspectors determined that the failure to properly inspect and repair door seals that protect safety related equipment from probable maximum precipitation is a performance deficiency.
The finding is more than minor because it is associated with the protection against external factors attribute of Mitigating System Cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.
In Inspection Manual Chapter 0609.04, "Phase 1
- Initial Screening and Characterization of Findings," the inspectors used the seismic, flooding, and severe weather Table 4b and determined that it would not affect multiple trains of safety equipment and that the finding had very low safety significance (Green). This finding has a cross
-cutting aspect in the area of human performance associated with the resources component in that the licensee's procedure used for the inspection of the door seals did not take into account the status of the pump house ventilation system while performing the door seal inspection, and therefore, the licensee failed to make the required adjustments to the door seals resulting in their inspections of the probable maximum precipitation door seals being inadequate H.2(c).
Enforcement
. Title 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures and Drawings," states, in part, that activities affecting quality shall be accomplished in accordance with prescribed procedures.
Contrary to the above, on or before October 24, 2011, activities affecting quality were not performed in accordance with prescribed procedures
, in that the licensee failed to implement an adequate inspection of door seals protecting safety-related equipment as prescribed in Procedure 07
-S-14-310, "Inspection of Mechanical Seals on Doors," Revision 8. This finding has been entered into the licensee's corrective action program as Condition Report CR
-GGN-2011-07687. Because the finding was determined to be of very low safety significance and was entered into the licensee's corrective action program, this violation is being treated as a non-cited violation consistent with Section 2.3.2a of the NRC Enforcement Policy: NCV 05000416/2011005
-01, "Failure to Perform an Adequate Inspection of Probable Maximum Precipitation Door Seals Protecting Safety Related Equipment."
.2 Annual Fire Protection Drill Observation
a. On December 4, 2011, the inspectors observed fire brigade activation due to a simulated fire in the upper cable spreading room of the control building. The inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies
- openly discussed them in a self
-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were (1) proper wearing of turnout gear and self
-contained breathing apparatus; (2) proper use and layout of fire hoses; (3)employment of appropriate fire fighting techniques; (4)sufficient firefighting equipment brought to the scene; (5)effectiveness of fire brigade leader communications, command, and control; (6) search for victims and propagation of the fire into other plant areas; (7) smoke removal operations; (8) utilization of preplanned strategies; (9)adherence to the preplanned drill scenario; and (10) drill objectives.
Inspection Scope
These activities constitute completion of one annual fire
-protection inspection sample as defined in Inspection Procedure 71111.05-05. b. No findings were identified.
Findings
1R06 Flood Protection Measures
a. The inspectors reviewed the Updated Final Safety Analysis Report, the flooding analysis, and plant procedures to assess susceptibilities involving internal flooding; reviewed the corrective action program to determine if licensee personnel identified and corrected Inspection Scope flooding problems; inspected underground bunkers/manholes to verify the adequacy of sump pumps, level alarm circuits, cable splices subject to submergence, and drainage for bunkers/manholes; and verified that operator actions for coping with flooding can reasonably achieve the desired outcomes. On November 28, 2011, t he inspectors also inspecte d the areas listed below to verify the adequacy of equipment seals located below the flood line, floor and wall penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, and control circuits, and temporary or removable flood barriers. Specific documents reviewed during this inspection are listed in the attachment.
Low pressure core spray room Residual heat removal pump A, B
, and C rooms Reactor core isolation cooling pump room High pressure core spray pump room These activities constitute completion of one flood protection measures inspection sample as defined in Inspection Procedure 71111.06-05. b. No findings were identified.
Findings
1R11 Licensed Operator Requalification Program
a. On October 3, 2011, the inspectors observed a crew of licensed operators in the plant's simulator to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems and training was being conducted i n accordance with licensee procedures. The inspectors evaluated the following areas:
Inspection Sc ope Licensed operator performance Crew's clarity and formality of communications
Crew's ability to take timely actions in the conservative direction Crew's prioritization, interpretation, and verification of annunciator alarms Crew's correct use and implementation of abnormal and emergency procedures
Control board manipulations Oversight and direction from supervisors Crew's ability to identify and implement appropriate technical specification actions and emergency plan actions and notifications The inspectors compared the crew's performance in these areas to pre
-established operator action expectations and successful critical task completion requirements.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of one quarterly licensed
-operator requalification program sample as defined in Inspection Procedure 71111.11. b. No findings were identified.
Findings
1R12 Maintenance Effectiveness
a. The inspectors evaluated degraded performance issues involving the following risk significant systems:
Inspection Scope Area radiation monitoring system (D21)
Plant air system (P51)
The inspectors reviewed events such as where ineffective equipment maintenance has resulted in valid or invalid automatic actuations of engineered safeguards systems and independently verified the licensee's actions to address system performance or condition problems in terms of the following:
Implementing appropriate work practices Identifying and addressing common cause failures
Scoping of systems in accordance with 10 CFR 50.65(b)
Characterizing system reliability issues for performanc e
Charging unavailability for performance Trending key parameters for condition monitoring Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or
-(a)(2)
Verifying appropriate performance criteria for structures, systems, and components classified as having an adequate demonstration of performance through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as requiring the establishment of appropriate and adequate goals and corrective actions for systems classified as not having adequate performance, as described in 10 CFR 50.65(a)(1)
The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the corrective action program with the appropriate significance characterization. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of two quarterly maintenance effectiveness sample s as defined in Inspection Procedure 71111.12-05. b. No findings were identified.
Findings
1R13 Maintenance Risk Assessments and Emergent Work Control
a. The inspectors reviewed licensee personnel's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk
-significant and safety
-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:
Inspection Scope The week of October 2, 2011, during the station transformer 21 outage and lifting of piping near the site's main transformer
, requiring the site to enter yellow risk condition The week of October 9, 2011, during the continuation of station transformer 21 outage due to emergent issues with the transform er bushings failing the insulating power factor test (DOBLE testing) and requiring replacement The week of November 1 2, 2011, during the recovery of the reactor feedpump turbine B following a trip on November 10, 2011, and during adverse weather in the area requiring the site to enter a yellow risk condition The week of December 12, 2011, during the division 3 allowed outage time requiring the site to enter a yellow risk condition
The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When licensee personnel performed emergent work, the inspectors verified that the licensee personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment.
The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four maintenance risk assessments and emergent work control inspection sample s as defined in Inspection Procedure 71111.13-05. b. No findings were identified. Findings
1R15 Operability Evaluations
a. The inspectors reviewed the following issues:
Inspection Scope Standby liquid control initiation timing assumption, CR
-GGN-2011-7620 Control blade 56
-41 operability retest, CR
-GGN-2011-9165 Standby service water C base plate repair, CR
-GGN-2011-9033 Division 1 and 2 diesel generator voltage regulator service life, CR-GGN-2011- 2983 Control room air conditioner A condenser divider plate degradation, CR-GGN- 2011-8010 The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that technical specification operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the technical specifications and Updated Final Safety Analysis Repor t to the licensee personnel's evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of five operability evaluations inspection sample s as defined in Inspection Procedure 71111.15-05. b. No findings were identified.
Findings
1R19 Postmaintenance Testing
a. The inspectors reviewed the following postmaintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:
Inspection Scope Engineering safety features transformer 21 following a planned outage Station transformer 21 following planned outage Standby service water system B fans C and D following scheduled maintenance outage Division 2 emergency diesel generator following schedule d maintenance Residual heat removal valve 1E12-F024B following scheduled maintenance Standby service water pump 1P41C002 following scheduled pump replacement The inspectors selected these activities based upon the structure, system, or component's ability to affect risk. The inspectors evaluated these activities for the following (as applicable):
The effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed Acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate
The inspectors evaluated the activities against the technical specifications, the Updated Final Safety Analysis Report, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with postmaintenance tests to determine whether the licensee was identifying problems and entering them in the corrective action program and that the problems were being corrected commensurate with their importance to safety. Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of six postmaintenance testing inspection sample s as defined in Inspection Procedure 71111.19-05. b. No findings were identified.
Findings
1R22 Surveillance Testing
a. Inspection Scope
The inspectors reviewed the Updated Final Safety Analysis Report, procedure requirements, and technical specifications to ensure that the surveillance activities listed below demonstrated that the systems, structures, and/or components tested were capable of performing their intended safety functions. The inspectors either witnessed or reviewed test data to verify that the significant surveillance test attributes were adequate to address the following:
Preconditioning
Evaluation of testing impact on the plant Acceptance criteria Test equipment
Procedures Jumper/lifted lead controls Test data Testing frequency and method demonstrated technical specification operability
Test equipment removal Restoration of plant systems Fulfillment of ASME Code requirements
Updating of performance indicator data Engineering evaluations, root causes, and bases for returning tested systems, structures, and components not meeting the test acceptance criteria were correct Reference setting data
Annunciators and alarms setpoints The inspectors also verified that licensee personnel identified and implemented any needed corrective actions associated with the surveillance testing.
On October 13, 2011, engineering safety features transformer 21 deluge functional and full flow test On October 13 and 14, 2011, turbine building ventilation and standby gas treatment A leakage tests On November 2, 2011, division 2 emergency diesel generator functional test On November 6 and 7, 2011, residual heat removal system A quarterly inservice testing On November 17, 2011, control rod settle and frictions testing
On November 29
- December 2, 2011 emergency core cooling division 3 testing Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of six surveillance testing inspection sample s as defined in Inspection Procedure 71111.2 2-05. b. No findings were identified.
Findings
1EP1 Exercise Evaluation
a. The inspectors reviewed the objectives and scenario for the 20 11 biennial emergency plan exercise to determine if the exercise would acceptably test major elements of the emergency plan. The scenario simulated a loss of reactor feedwater
, an unisolable leak of radioactive steam in the steam tunnel, a reactor coolant leak in the drywell, core damage following reactor pressure vessel water level below the top of active fuel, and a radiological release to the environment from the steam tunnel to demonstrate the licensee personnel's capability to implement their emergency plan. Inspection Scope The inspectors evaluated exercise performance by focusing on the risk
-significant activities of event classification, offsite notification, recognition of offsite dose consequences, and development of protective action recommendations, in the Contro l Room Simulator and the following dedicated emergency response facilities:
Technical Support Center Operations Support Center Emergency Operations Facility The inspectors also assessed recognition of, and response to, abnormal and emergency plant conditions, the transfer of decision making authority and emergency function responsibilities between facilities, onsite and offsite communications, protection of emergency workers, emergency repair evaluation and capability, and overall implementation of the emergency plan to protect public health and safety and the environment. The inspectors reviewed the current revision of the facility emergency plan, emergency plan implementing procedures associated with operation of the licensee's emergency response facilities, procedures for the performance of associated emergency functions, and other documents as listed in the attachment to this report.
The inspectors compared the observed exercise performance with the requirements in the facility emergency plan, 10 CFR 50.47(b), 10 CFR Part 50, Appendix E, and with the guidance in the emergency plan implementing procedures and other federal guidance.
The inspectors attended the post
-exercise critiques in each emergency response facility to evaluate the initial licensee self-assessment of exercise performance. The inspectors also attended a subsequent formal presentation of critique items to plant management. The specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of one sample as defined in Inspection Procedure 71114.01-05. b. No findings were identified.
Findings
1EP4 Emergency Action Level and Emergency Plan Changes
a. The inspector performed an on
-site review of Grand Gulf Nuclear Generating Station Emergency Plan, Revision 66, submitted by letter dated August 11, 2011. This revision, revised the emergency response organization callout method from a stand
-alone Computer Notification System operated by the licensee to an offsite paging and telephone notification system operated and maintained by a vendor.
Inspection Scope This revision was compared to its previous revision, to the criteria of NUREG
-0654, "Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants," Revision 1, to Nuclear Energy Institute Report 99
-01, "Emergency Action Level Methodology," Revision 4, 5, and to the standards in 10 CFR 50.47(b) to determine if the revision adequately implemente d the requirements of 10 CFR 50.54(q). This review was not documented in a safety evaluation report and did not constitute approval of licensee
-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed
during this inspection are listed in the attachment.
These activities constitute completion of one sample as defined in Inspection Procedure 71114.04-05.
b. No findings were identified.
Findings
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
(71151)
.1 Data Submission Issue
a. The inspectors performed a review of the performance indicator data submitted by the licensee for the third quarter 20 11 performance indicators for any obvious inconsistencies prior to its public release in accordance with Inspection Manual Chapter 0608, "Performance Indicator Program."
Inspection Scope This review was performed as part of the inspectors' normal plant status activities and , as such, did not constitute a separate inspection sample.
b. No findings were identified.
Findings
.1 Mitigating Systems Performance Index
- Emergency ac Power System (MS06)a. The inspectors sampled licensee submittals for the mitigating systems performance index - emergency ac power system performance indicator for the period from the third quarter 20 10 through the third quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99
-02, "Regulatory Assessment Performance Indicator Guideline," Revision
6. The inspectors reviewed the licensee's operator narrative logs, mitigating systems performance index derivation reports, issue reports,
event reports
, and NRC integrated inspection reports for the period of July 2010 through September 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had Inspection Scope changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensee's condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified
. Specific documents reviewed are described in the attachment to this report.
These activities constitute completion of one mitigating systems performance index
- emergency ac power system sample as defined in Inspection Procedure 71151-05. b. No findings were identified.
Findings
.2 Mitigating Systems Performance Index
- High Pressure Injection Systems (MS07)a. The inspectors sampled licensee submittals for the mitigating systems performance index - high pressure injection systems performance indicator for the period from the third quarter 20 10 through the third quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99
-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6. The inspectors reviewed the licensee's operator narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of July 2010 through September 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensee's condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified
. Specific documents reviewed are described in the attachment to this report.
Inspection Scope These activities constitute completion of one mitigating systems performance index
- high pressure injection system sample as defined in Inspection Procedure 71151-05. b. No findings were identified.
Findings
.3 Mitigating Systems Performance Index
- Heat Removal System (MS08)a. The inspectors sampled licensee submittals for the mitigating systems performance index - heat removal system performance indicator for the period from the third quarter Inspection Scope 0 10 through the third quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99
-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6. The inspectors reviewed the licensee's operator narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of July 2010 through September 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensee's condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified
. Specific documents reviewed are described in the attachment to this report.
These activities constitute completion of one mitigating systems performance index
- heat removal system sample as defined in Inspection Procedure 71151-05. b. No findings were identified.
Findings
.4 Mitigating Systems Performance Index
- Residual Heat Removal System (MS09)a. The inspectors sampled licensee submittals for the mitigating systems performance index - residual heat removal system performance indicator for the period from the third quarter 20 10 through the third quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99
-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6. The inspectors reviewed the licensee's operator narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of July 2010 through September 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensee's condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified
. Specific documents reviewed are described in the attachment to this report.
Inspection Scope
These activities constitute completion of one mitigating systems performance index
- residual heat removal system sample as defined in Inspection Procedure 71151-05.
b. No findings were identified.
Findings
.5 Mitigating Systems Performance Index
- Cooling Water Systems (MS10)a. The inspectors sampled licensee submittals for the mitigating systems performance index - cooling water systems performance indicator for the period from the third quarter 20 10 through the third quarter 2011. To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99
-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6. The inspectors reviewed the licensee's operator narrative logs, mitigating systems performance index derivation reports, issue reports, event reports, and NRC integrated inspection reports for the period of July 2010 through September 2011 to validate the accuracy of the submittals. The inspectors reviewed the mitigating systems performance index component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensee's condition report database to determine if any problems had been identified with the performance indicator data collected or transmitted for this indicator and none were identified
. Specific documents reviewed are described in the attachment to this report.
Inspection Scope These activities constitute completion of one mitigating systems performance index
- cooling water system sample as defined in Inspection Procedure 71151-05. b. No findings were identified.
Findings
.6 Drill/Exercise Performance (EP01)
a. The inspectors sampled licensee submittals for the Drill and Exercise Performance, performance indicator for the period October 2010 through September 2011. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99
-02, "Regulatory Assessment Performance Indicator Guideline," Revisions 5 and 6, were used. The inspectors reviewed the licensee's records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance.
Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator; assessments of performance indicator opportunities during predesignated control room simulator training sessions, performance during the 2011 biennial exercise, and Inspection Scope performance during other drills. The specific documents reviewed are described in the attachment to this report.
These activities constitute completion of the drill/exercise performance sample as defined in Inspection Procedure 71151-05. b. No findings were identified.
Findings
.7 Emergency Response Organization Drill Participation (EP02)
a. The inspectors sampled licensee submittals for the Emergency Response Organization Drill Participation performance indicator for the period October 2010 through September 2011. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclea r
Energy Institute Document 99
-02, "Regulatory Assessment Performance Indicator Guideline," Revision 5, was used. The inspectors reviewed the licensee's records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance. Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the performance indicator, rosters of personnel assigned to key emergency response organization positions, and exercise participation records. The specific documents reviewed are described in the attachment to this report.
Inspection Scope These activities constitute completion of the emergency response organization drill participation sample as defined in Inspection Procedure 71151-05.
b. No findings were identified.
Findings
.8 Alert and Notification System (EP03)
a. The inspectors sampled licensee submittals for the Alert and Notification System performance indicator for the period October 2010 through September 2011. To determine the accuracy of the performance indicator data reported during those periods, performance indicator definitions and guidance contained in Nuclear Energy Institute Document 99
-02, "Regulatory Assessment Performance Indicator Guideline," Revision 5, was used. The inspectors reviewed the licensee's records associated with the performance indicator to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the Nuclear Energy Institute guidance. Specifically, the inspectors reviewed licensee records and processes including Inspection Scope procedural guidance on assessing opportunities for the performance indicator and the results of periodic alert notification system operability tests. The specific documents reviewed are described in the attachment to this report.
These activities constitute completion of the alert and notification system sample as defined in Inspection Procedure 71151-05. b. No findings were identified.
Findings
4OA2 Identification and Resolution of Problems
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection
.1 Routine Review of Identification and Resolution of Problems
a. As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensee's corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. The inspectors reviewed attributes that included the complete and accurate identification of the problem; the timely correction, commensurate with the safety significance; the evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent of condition reviews, and previous occurrences reviews; and the classification, prioritization, focus, and timeliness of corrective actions. Minor issues entered into the licensee's corrective action program because of the inspectors' observations are included in the attached list of documents reviewed. Inspection Scope These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure, they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.
b. No findings were identified.
Findings
.2 Daily Corrective Action Program Review
s a. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow
-up, the inspectors performed a daily screening of items entered into the licensee's corrective action program. The inspectors accomplished this through review of the station's daily corrective action documents.
Inspection Scope The inspectors performed these daily reviews as part of their daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.
b. No findings were identified.
Findings
.3 Semi-Annual Trend Review
a. The inspectors performed a review of the licensee's corrective action program and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors focused their review on repetitive equipment issues, but also considered the results of daily corrective action item screening discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human performance results. The inspectors nominally considered the 6
-month period of June 2011 through December 2011
, although some examples expanded beyond those dates where the scope of the trend warranted.
Inspection Scope The inspectors also included issues documented outside the normal corrective action program in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self
-assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensee's corrective action program trending reports. Corrective actions associated with a sample of the issues identified in the licensee's trending reports were reviewed for adequacy. These activities constitute completion of one single semi
-annual trend inspection sample as defined in Inspection Procedure 71152-05. b. No findings were identifie
d. Findings and Observations
The inspectors identified an increasing trend in condition reports identifying equipment failures affecting safety and non
-safety related systems. The specific items documented in the condition reports were reviewed by the inspectors
, and it was determined that 17 plant systems had been affected by failed equipment. These systems include plant air system, process radiation monitoring system, plant service water system , and reactor protection system. The equipment failures have resulted in various impacts on the plant including down powers and unplanned entries into limiting conditions of operation. The inspectors ha ve already evaluated the down powers and limiting conditions of operations entries under other inspection samples for potential findings. The licensee was aware of the decline in equipment reliability and has initiated corrective actions to improve equipment reliability by implementing preventative maintenance practices, performing system health evaluations
, and employing a life cycle management program.
4OA3 Event Follow
-up (71153)
.1 Hydrogen Leak at the Bulk Hydrogen Storage Facility
a. Inspection Scope
On October 19, 2011, the inspectors responded to the control room to observe operator response to a hydrogen leak at the bulk hydrogen storage facility.
The main control room received the following alarm, "H2 Storage Area Pump/Common Trouble/Power Loss," and dispatched operators to investigate. The control room supervisor contact ed the Air Products vendor for assistance with the event.
The responding operators found the A hydrogen compressor had tripped with the B compressor running.
They also found a hydrogen leak on or near the outlet of the regulator for the main hydrogen tank. Site safety was contacted, and upon their recommendations, access was restricted to the area. The licensee's shift manger evaluated the emergency actions levels and determined that entry into an action level was not appropriate at the time due to location of the leak bei ng outside the protected area, the size of the leak being from the valve packing , and the prevailing winds blowing the hydrogen gas away from the protected area. The inspectors observed control room actions and monitor ed the leak from site cameras. The hydrogen leak and the compressor A were repaired without incident by the vendor that day. Documents reviewed for this inspection are listed in the attachment.
These activities constitute completion of one event follow
-up as defined in Inspection Procedure 71153-05. b. No findings were identified.
Findings
.2 Trip of Reactor Water Cleanup Pump A due to Maintenance Technicians Working on the Wrong Component
a. Inspection Scope
On October 25, 2011, the inspectors were briefed on a trip of the reactor water cleanup pump A due to instrument and control technicians performing maintenance on the wrong component. At 11
" and "RWCU FILTER DMIN CONT TROUBLE
" alarms and a trip of reactor water cleanup pump A. Additionally
, reactor water cleanup filter demineralizer A was lost. The operating crew responded to the alarms by entering their alarm response procedures and investigating the cause of the pump trip.
The crew determined that instrument and control technicians assigned to perform scheduled maintenance on a train B solenoid valve instead performed scheduled maintenance on a train A solenoid valve
, resulting in the trip of the pump A. The plant experienced a decrease in reactor power of approximately three megawatts thermal (0.05 percent)due to the trip of the reactor water cleanup pump A. The operating crew recover ed the reactor water cleanup pump A after maintenance restored the solenoid valve on the train A. Inspectors reviewed logs, interviewed operators
, and received additional briefings from the maintenance manager to determine what occurred and if proper recovery actions were taken. The maintenance manager also briefed the inspectors on future actions that would be taken to improve performance in the maintenance department. Documents reviewed for this inspection are listed in the attachment.
These activities constitute completion of one event follow
-up as defined in Inspection Procedure 71153-05. b. No findings were identified.
Findings
.3 a. Trip of Drywell Chillers Following Offsite Grid Disturbance
b. On November 5, 2011, Grand Gulf Nuclear Station experienced a voltage spike from the electrical grid. The spike occurred due to the tripping a nd reclosing of two offsite 500 K V breakers. The voltage spike resulted in various control room annunciators and loss of the train A drywell chillers. In response to the loss of the train A drywell chillers, the train B drywell chillers auto started
, but eventually tripped on high discharge pressure, which resulted in no trains of drywell chillers operating. The operators monitored the drywell temperature and containment steam tunnel temperatures in accordance with Technical Specification 3.6.5.5. The licensee determined the undervoltage relay for the train A drywell chillers had tripped due to the voltage spike but would not reset
, thus preventing the chillers from operating. A priority one work order was authorized by the shift manager , which allowed the installation of a jumper to bypass the undervoltage relay. Once the jumper was installed, the operators were able to restart the train A drywell chillers. At the end of the inspection the licensee was still troubleshooting the train B drywell chiller. The inspectors reviewed the licensee's activities and determined that no technical specification limits had be exceeded and concluded that the licensee's actions were appropriate for the safety significance of the drywell chiller system.
Documents reviewed for this inspection are listed in the attachment.
Inspection Scope These activities constitute completion of one event follow
-up as defined in Inspection Procedure 71153
-05.
c. Findings
No findings were identified.
.4 a. Trip of Reactor Feedpump
Turbine B and Subsequent Downpower On November 10, 2011, at 10:41 p.m.
the Grand Gulf Nuclear Station experienced a trip of the reactor feedpump turbine B. This resulted in a flow control valve runback on the recirculation valve B. The recirculation flow control valve A failed to automatically runback and had to be manually runback by a reactor operator. Reactor water level decreased to 16 inches above instrument zero (183 inches above the top of active fuel) and was restored to normal level by the decrease in power to approximately 50 percent.
The inspectors responded to the plant and interfaced with licensee management to determine their plan of action to recover from the event. The licensee briefed the inspectors on their plans an d the finding s from their investigation. The licensee determined that the feedpump turbine had tripped due to a servo card fault
, which was replaced. The failure of the recirculation flow control valve A to runback was attributed to a bad tachometer in the logic circuit. The tachometer was also replaced. The inspectors reviewed the results of the licensee's failure mode analysis teams and determined the corrective actions were appropriate. On November 14, 2011, the license e commenced a power increase and restored the reactor feedpump turbine B to operation during power increase. The inspectors monitor ed activities in the main control room during power ascension. Documents reviewed for this inspection are listed in the attachment.
Inspection Scope These activities constitute completion of one event follow
-up as defined in Inspection Procedure 71153
-05. b. No findings were identified.
Findings
.5 a. Partial Loss of Plant Service Water due to a Trip of the 18AG Bus
On November 25, 2011, at approximately 4
- 50 p.m. the Grand Gulf Nuclear Station experienced a partial loss of plant service water that cools non
-safety related equipment at Grand Gulf Nuclear Station.
The operations shift manager notified the inspectors that a power pole, which supplied power to the bus 28AG, had been damaged by a security truck striking the pole. As a result, the plant decided to split out non
-safety related buses 28AG and 18AG
, which were previously tied together to allow maintenance to perform inspections o f the power supply cable to the bus 18AG. The site experienced a partial Inspection Scope loss of plant service water when the supply breaker to the bus 18AG closed, which resulted in the cross tie breaker between the 18AG and 28AG opening as expected
. Subsequently, the supply breaker to the bus 18AG unexpectedly reopened. This in turn resulted in a loss of power to three of the seven operating plant service water pumps. The site subsequently reduced power to approximately 50 percent to align with the capacity of the remaining four plant service water pumps. The inspectors conducted numerous calls with the site through the night to understand plant conditions and responded to the site the next day to independently monitor activities. The inspectors reviewed the results of the licensee's failure mode analysis team and determined the corrective actions were appropriate. The licensee concluded that the loss of the bus 18AG was due to either a failed relay in the supply breaker to the bus or a damaged cable that allowed operation of the supply breaker remotely from the main control room. The site replaced the suspected relay and used an alternate method in their procedure to re-energize the bus 18AG locally and restart the tripped plant service water pumps.
Then the licens ee crossed tied the bus 18AG with the bus 28AG and de-energized the bus 28AG to conduct replacement of the damaged power pole. The site increased power to 96 percent rated power. After the power pole was replaced on November 28, 2011 , the site restored plant service water system to its normal electrical alignment of four pumps power ed from 18AG and four pumps powered from 28AG. Documents reviewed for this inspection are listed in the attachment.
These activities constitute completion of one event follow
-up as defined in Inspection Procedure 71153
-05. b. No findings were identified.
Findings
4OA5 Other Activities
(Closed) NRC Temporary Instruction (TI) 2515/177, "Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (NRC Generic Letter 2008
-01)"
a. Inspection Scope
The inspectors evaluated whether the licensee maintained documents, installed system hardware, and implemented actions that were consistent with the information provided in their response to NRC Generic Letter 2008
-01, "Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems." Specifically, the inspectors verified that the licensee had implemented, or was in the process of implementing, the commitments, modifications, and programmatically controlled actions described in their response to Generic Letter 2008-01. The inspectors conducted their review in accordance with Temporary Instruction 2515/177 and considered the site
-specific supplemental information provided by the Office of Nuclear Reactor Regulation (NRR) to the inspectors.
b. Inspection Documentation The inspectors reviewed the licensing basis, design, testing, and corrective actions as specified in the temporary instruction. The specific items reviewed and any resulting observations are documented below.
Licensing Basis: The inspectors reviewed selected portions of licensing basis documents to verify that they were consistent with the NRR assessment report, and that the licensee properly processed any required changes. The inspectors reviewed selected portions of technical specifications, technical specification bases, and the Updated Final Safety Analysis Report. The inspectors also verified that applicable documents that described the plant and plant operation, such as calculations, piping and instrumentation diagrams, procedures, and corrective action program documents addressed the areas of concern and were updated, if needed, following plant changes. The inspectors confirmed that the licensee performed surveillance tests at the frequency required by the technical specifications. The inspectors verified that the licensee tracked their commitment to evaluate and implement any changes that would be contained in the technical specification task force traveler.
Design: The inspectors reviewed selected design documents, performed system walkdowns, and interviewed plant personnel to verify that the licensee addressed design and operating characteristics. Specifically:
The inspectors verified that the licensee had identified the applicable gas intrusion mechanisms for their plant.
The inspectors verified that the licensee had established void acceptance criteria consistent with the void acceptance criteria identified b y NRR. The inspectors also confirmed that the range of flow conditions evaluated by the licensee was consistent with the full range of design basis and expected flow rates for various break sizes and locations.
The inspectors selectively reviewed applicable documents, including calculations, and engineering evaluations with respect to gas accumulation in the emergency core cooling systems and decay heat removal systems. Specifically, the inspectors verified that these documents addressed venting requirements, aspects where pipes were normally voided, void control during maintenance activities, and the potential for vortex effects that could ingest gas into the systems during design basis events.
The inspectors verified that piping and instrumentation diagrams and isometric drawings describe up
-to-date configurations of the emergency core cooling systems and decay heat removal systems. The review of the selected portions of isometric drawings considered the following:
1. High point vents were identified.
2. High points without vents were recognizable.
. Other areas where gas could accumulate and potentially impact operability, such as at orifices in horizontal pipes, isolated branch lines, heat exchangers, improperly sloped piping, and under closed valves, were described in the drawings or in referenced documentation.
4. Horizontal pipe centerline elevation deviations and pipe slopes in nominally horizontal lines that exceeded specified criteria were identified.
5. All pipes and fittings were clearly shown.
6. The drawings were up
-to-date with respect to recent hardware changes, and that any discrepancies between as
-built configurations and the drawings were documented and entered into the corrective action program for resolution.
The inspectors verified that the licensee had completed their walkdowns and selectively verified that the licensee identified discrepant conditions in their corrective action program and appropriately modified affected procedures and training documents.
Testing: The inspectors reviewed selected surveillances, post
-modification tests, and post-maintenance test procedures and results, conducted during power and shutdown operations, to verify that the licensee was using procedures that appropriately addressed gas accumulation and/or intrusion into the subject systems. This review included the verification of procedures used for conducting surveillances and for the determination of void volumes to ensure that void criteria were satisfied and would continue to be satisfied until the next scheduled void surveillances. Also, the inspectors reviewed procedures used for filling and venting following conditions that could introduce voids into the subject systems to verify that the procedures adequately tested for such voids and provided adequate instructions for their reduction or elimination
. Corrective Actions: The inspectors reviewed selected corrective action program documents to assess how effectively the licensee addressed the issues associated with Generic Letter 2008-01 in their corrective action program. In addition, the inspectors verified that the licensee implemented appropriate corrective actions for issues identified in the nine
-month and supplemental responses. The inspectors determined that the licensee had effectively implemented the actions required by Generic Letter 2008-01.
Based on this review, the inspectors concluded that there is reasonable assurance that the licensee will complete all outstanding items and incorporate this information into the design basis and operational practices. This temporary instruction is closed for Grand Gulf Nuclear Station.
c. Findings
No findings were identified.
OA6 Meetings Exit Meeting Summary
On November 3, 2011, the inspector presented the results of the onsite inspection of the licensee's biennial emergency preparedness exercise to Mr. M. Richey, Director, Nuclear Safety Assurance, and other members of the licensee's staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary.
No proprietary information was identified.
On December 9, 2011, the inspector presented the inspection results to Mr.
D. Wiles, Engineering Director and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector confirmed that none of the potential report input discussed was considered proprietary.
On January 10, 2012, the inspectors presented the inspection results to Mike Perito, Site Vice President Operations, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspector asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- J. Browning, General Plant Manager
- J. Caery, Manager, Training
- H. Farris, Assistant Operations Manager
- P. Griffith, Supervisor, System Engineering
- K. Higgenbotham, Manager, Planning and Scheduling
- J. Houston, Manager, Maintenance
- D. Jones, Manager, Design Engineering
- C. Lewis, Manager, Emergency Preparedness
- C. Loyd, Supervisor, Engineering
- J. Miller, Manager, Operations
- L. Patterson, Manager, Program Engineering
- C. Perino, Manager, Licensing
- M. Perito, Site Vice President of Operations
- T. Reno, System Engineer
- W. Renz, Corporate Director, Emergency Preparedness
- M. Richey, Director, Nuclear Safety Assurance
- R. Scarbrough, Specialist and Lead Offsite Liaison, Licensing
- J. Seiter, Senior Licensing Specialist
- J. Shaw, Manager, System Engineering
- D. Wiles, Director, Engineering
- R. Wilson, Manager, Quality Assurance
- T. Trichell, Manager, Radiation Protection
- R. Fuller, Design Engineer
NRC Personnel
- R. Smith, Senior Resident Inspector
- B. Rice, Resident Inspector
Attachment
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
-01 NCV Failure to Perform an Adequate Inspection of Probable Maximum Precipitation Door Seals Protecting Safety Related Equipment (Section 1R05)
Closed TI 2515/177 TI Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (Section 4OA5)
Attachment
LIST OF DOCUMENTS REVIEWED
Section 1RO4: Equipment Alignment
- PROCEDURE NUMBER TITLE REVISION 04-1-01-E61-1 Combustible Gas Control System
- GLP-OPS-E6100 COMBUSTIBLE GAS CONTROL SYSTEM
- E61 11 04-1-01-E21-1 System Operating Instruction Low Pressure Core Spray System 38 06-OP-1E51-Q-0003 RCIC System Quarterly Pump Operability Verification
- 2 04-1-01-E51-1 Reactor Core Isolation Cooling System
- 130 04-1-01-E51-1 Reactor Core Isolation Cooling, Attachment II
- 29 04-1-01-E51-1 Reactor Core Isolation Cooling, Attachment I (Manual Valve Lineup Checksheet)
- 119 04-1-01-E51-1 Reactor Core Isolation Cooling, Attachment I (Manual Valve Lineup Checksheet)
- 116
- DRAWING NUMBER TITLE REVISION M-1083A P & I Diagram Reactor Core Isolation Cooling System Unit 1
- OTHER NUMBER TITLE DATE
- Installation, Operation and Maintenance Instructions for 6x6x10.5 Four Stage Type CP Reactor Core Isolation Cooling Pump July 14, 1977
- System Health Report E51 Reactor Core Isolation Cooling rd Quarter 2011
- CONDITION REPORT
- Attachment
- Attachment
- CR-GGN-2010-6 941
- WORK ORDER
Section 1RO5: Fire Protection
- PROCEDURE NUMBER TITLE REVISION / DATE Fire Pre-Plan
- SSW-01 SSW Pump House and Valve Room Fire Pre-Plan
- SSW-02 SSW Pump House and Valve Room Fire Pre-Plan
- SSW-03 Yard Electrical Manholes
- Fire Pre-Plan A-48 Spent Fuel Area
- 1A431, Shipping Cask Storage Area
- 1A438, Cask Wash down Area
- 1A532, Storage Area
- 1A602, Passage
- 1A603, Fuel Handling Area
- 1A604, Area 9 & 10, Elevation 208
- 9A.5.19 Fire Area 19
- Attachment
Section 1RO5: Fire Protection
- PROCEDURE NUMBER TITLE REVISION / DATE
- EN-TQ-125 Fire Brigade Drills October 26, 2011
- 4-S-14-310 General Maintenance Instruction Inspection of Mechanical Seals on Door
- EN-TQ-125 Fire Brigade Drills May 3, 2010
- EN-TQ-125 Fire Brigade Drills December 4, 2011
- OTHER NUMBER TITLE DATE
- GGNS Operations Logs (Days)
- October 30, 2011
- CONDITION REPORT
- CR-GGN-2011-07549 CR-GGN-2011-08762
Section 1RO6: Flood Protection Measures
- PROCEDURE NUMBER TITLE REVISION 07-1-24-T10-1 Periodic Leak Check of Airtight Door Sealing Surfaces
- 04-1-01-P45-2 Floor Drain Sump System
- 05-1-02-VI-1 Flooding 107 06-OP-1P45-Q-Floor, Equipment and Chemical Drain Isolation Valve 114
- Attachment
Section 1RO6: Flood Protection Measures
- PROCEDURE NUMBER TITLE REVISION 0002 Operability Check
- CALUCLATION
- NUMBER TITLE REVISION 195.0-1 Compartment Flooding Calculations
- CONDITION REPORT
- WORK ORDER
- WO 00113101 WO 00130816
- ENGINEERING CHANGE
- 0000032180
Section 1R11: Licensed Operator Requalification Program
- PROCEDURE NUMBER TITLE REVISION
- GSMS-LOR-WEX05 Licensed Operator Requalification Training
- Attachment
- OTHER NUMBER TITLE REVISION / DATE
- List of modifications need to be made in TREX load per Control Room walkdown September 7, 2011
- 2011 Licensed Operator Requalification Simulator Training Plan Simulator Differences Cycle 2011
-6 Licensed Operator Requal Training Rev Draft GIN 2011/0031
- Simulator Evaluation "D" Shift October 3, 2011
Section 1R12: Maintenance Effectiveness
- PROCEDURE NUMBER TITLE REVISION
- EN-DC-206 Maintenance Rule (a)(1) Process
- EN-DC-204 Maintenance Rule Scope and Basis
- EN-DC-207 Maintenance Rule Periodic Asses sment 2
- EN-DC-205 Maintenance Rule Monitoring
- 10-S-01-38 Emergency Plan Procedure
- 05-S-01-EP-4 Auxiliary Building Control
- 10-S-02-3 Temporary Change Notice (Directive
- 10-S-01-1) 118
- EN-DC-205 Maintenance Rule Monitoring
- EN-DC-205 Maintenance Rule Monitoring (Maintenance Rule Functional Failure Evaluation Template)
- OTHER NUMBER TITLE DATE
- Maintenance Rule (a)(1) Systems List September 5, 2011
- Attachment
- OTHER NUMBER TITLE DATE
- Single Trend Point D21K611 (from 2/1/2010
- 4/1/2010) (a)(1) Evaluation for the Area Radiation Monitoring (D21) System (CR-GGN-2011-1516 Radiation Monitor 1D21K612 March 8, 2011 and CR
-GGN-2011-1630 Radiation Monitor 1D21K612 March 10, 2011)
- Maintenance Rule Program Expert Panel Meeting Minutes August 31, 2011
- Maintenance Rule (a)(1) Systems List November 2, 2011
- Attachment 9.1
- Maintenance Rule Functional Failure Evaluation Template NRC Resident Issue with the Maintena nce Rule Program February 14, 2010 to November 17, 2011
- CONDITION REPORT
- Attachment
- CR-GGN-2011-3051 C R-GGN-2011-1338
- CORRECTIVE ACTIONS
- CR-GGN- 2010-8815 CA No. 006
- CR-GGN-2010-8815 CA No. 004
- CR-GGN- 2010-8815 CA No. 005
- CR-GGN-2011-01338 CA No. 006
- WORK ORDER
- Attachment
Section 1R13: Maintenance Risk Assessment and Emergent Work Controls
- PROCEDURE NUMBER TITLE REVISION
- EN-WM-101 On-line Work Management Process for the week of October 2, 2011 7 04-S-01-R23-1 34.5kV Switchgear and Transformers
- EN-WM-101 On-line Work Management Process for the week of October 9, 2011 7
- EN-WM-101 On-line Work Management Process for the week of November 13, 2011
- EN-MA-133 Control of Scaffolding
- 01-S-18-6 Risk Assessment of Maintenance Activities
- 02-S-01-17 Control of Limiting Conditions of Operations
- 2
- EN-OP-119 Protective Equipment Posting
- EN-WM-104 On Line Risk Assessment
- DRAWING NUMBER TITLE REVISION E-6081 Site Power Loop Distribution One Line
- OTHER NUMBER TITLE REVISION
- ER-GG-2002-0007-001 Heavy Load Evaluation for Div. 1 SSW Pump Removal 1 LCOTR No:1
-TS-11-0400 System/Component: HPCS, SSW C, Div 2 Diesel Generator, Div 3 Battery Bank
- 175
- WORK ORDER
- WO 285317-14 WO 00296595
-01/02/03 WO 00294749
-01 WO 00295529
-01 WO 00247594
-01 WO 50322927
-07 WO 50316983
-06
-01
- WO 284192-01 WO 52339925
-01
- Attachment
- WO 247236-60 WO 00296174
-01
- WO 262640-35 WO 00270093
-06 WO 52323650
-01
- WO 267461-01 WO 52311544
- WO 52363922 WO 52363929
- WO 286594-07 WO 286594-01/02/03/04/05
- WO 287801-05 WO 00278077
-09
- WO 267713-30/31
-02
- WO 278077-09 WO 00224213
- WO 270643-02 WO 52376455
- ENGINEERING CHANGE
Section 1R15: Operability Evaluations
- PROCEDURE NUMBER TITLE REVISION
- GGNS-MS-37 GGNS Mechanical Standard for the Division I and II Standby Diesel Generator Maintenance
- EN-MA-133 Control of Scaffolding
-1 Anticipated Transients without Scram
- EN-MP-112 Shelf Life Program
- 01-S-02-3 , Attachment VI
- Control Rod Settle and Insertion Test
- 119
- Attachment
- CALUCLATION
- NUMBER TITLE REVISION C-AC-400
- DCD 82 / 5020
- C
- OTHER NUMBER TITLE REVISION / DATE MP&L -6-301.3 Concrete Procedure: Masterflow 928 High precision mineral aggregate grout with extended working time
- NEDO-10739 Methods for calculating safe test intervals and allowable repair times for engineered safeguard systems January 1973
- NEDO-10349 Analysis of Anticipated Transients without Scrams March 1971
- NEDO-20626 Studies of BWR designs for mitigation of anticipated transients without scrams, Amendment 1
- June 1975
- NEDO-20626 Studies of BWR designs for mitigation of anticipated transients without scrams, Amendment 2
- July 1975
- Disposition of CR
-GGN-2011-07620
- GGNS-NE-10-00004 GGNS
- EPU-Anticipated Transients without Scram
- NEDE-31096-P-A Class III General Electric Anticipated Transient Without Scram Response to NRC ATWES Rule 10CFR50.62
- LPCS Vendor Manual 460000159
- September 25, 1996
- CONDITION REPORT
- CR-GGN-2011-09121 CR-GGN-2011-09165
Section 1R19: Postmaintenance Testing
- PROCEDURE NUMBER TITLE REVISION 06-OP-1P41-M-SSW Loop B Operability Check
- 2
- Attachment
Section 1R19: Postmaintenance Testing
- PROCEDURE NUMBER TITLE REVISION 0005 07-S-14-56 General Maintenance Instruction Western Gear Speed Reducer
- 27
- EN-AD-103 Document Control and Records Management Programs
- 07-S-23-P75-3 Div I and Div II Diesel Generator Simulated Run
- 17-S-03-26 MOV Torque Switch Setpoint Methodology
- OTHER NUMBER TITLE DATE
- Siemens Job Number 302368
- DOBLE Testing for Service Transformer 21
- Nameplate
- Two-winding Transformer DOBLE Testing Data October 11, 2011 B-88833-97,
- B-88833-97-70 PCORE Electric JOCOA Bottom Connection in 55 Rise Oil June 5, 2006
- Transformer: Data Interpretation of Modern Oil
-Filled Power Transformers (Temperature Corrected)
- CONDITION REPORT
- WORK ORDER
- Attachment
Section 1R22: Surveillance Testing
- PROCEDURE NUMBER TITLE REVISION 04-S-03-P64-20 Transformer Deluge Functional and Full Flow Test
- 06-OP-1P75-M-0002 Standby Diesel Generator 12 Functional Test
- 130 06-OP-1E12-Q-0023 LPCI/RHR Subsystem A Quarterly Functional Test
- 2 04-1-03-C11-7 Attachment I, Equipment Performance Instruction Data Package Cover Sheet, Safety Related
- 04-1-03-C11-7 Attachment II, Data Sheet I, Control Rod Settle Test, Safety Related 11 01-S-02-3 Temporary Change Directive 04
-1-03-C11-7 119 06-OP-1P81-R-0001 HPCS Diesel Generator 18
-Month Functional Test
- 119
- ECH-NE-11-00066 GGNS C18 Channel
-Control Blade Interference Monitoring Plan 1 04-1-03-C11-6 Control Rod Drive Cooling Water Orifice Verification
- 06-OP-1P81-R-0001 HPCS Diesel Generator 18 Month Functional Test
- 119 06-OP-1P81-R-0001 HPCS Diesel Generator 18 Month Functional Test
- 20 06-OP-1P81-M-0002 Standby Diesel Generator 13 Functional Test
- 25
- OTHER NUMBER TITLE REVISION / DATE
- Temporary Life 2011
-0237 Tagout R15
-001-ST21 To allow Deluge Testing on Transformer ESF 21
- October 13, 2011
- GGNS Scheduled Pump Runs October 18, 2011
- CFR 50.55a Request Title: E12 Jockey Pumps Alternative Request
- 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 56
-37 11
- Attachment
- OTHER NUMBER TITLE REVISION / DATE 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 60
-37 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 60
-29 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 56
-21 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 56
-17 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 48
-09 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 44
-09 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 40
-09 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 40
-05 11 04-1-03-C 11-7 Control Rod Settle and Insertion Test, Control Rod 32
-05 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 20
-09 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 08
-17 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 12
-53 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 08
-25 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 36
-09 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod
- 48-57 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 52
-49 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 56
-49 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 36
-61 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 28
-57 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 28
-61 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 16
-57 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 08
-49 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 04
-29 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 32
-61 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 56
-45 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 28
-09 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 08
-33 11
- Attachment
- OTHER NUMBER TITLE REVISION / DATE 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 16
-09 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 36
-05 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 56
-25 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 36
-57 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod
- 40-57 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 04
-37 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 08
-37 11 04-1-03-C11-7 Control Rod Settle and Insertion Test, Control Rod 56
-33 11
- US NRC Regulatory Guide 1.9 3 NUREG 1482
- US NRC Guidelines for Inservice Testing at Nuclear Power Plants Inservice Testing of Pumps and Valves and Inservice Examination and Testing of Dynamic Restraints (Snubbers) at Nuclear Power Plants
- CONDITION REPORT
- WORK ORDER
-01 WO 52323595
-01
- WO 52361896 01
Section 1EP1: Exercise Evaluation
- NUMBER TITLE REVISION 10-S-01-06 Notification of Offsite Agencies and Plant On
-Call Emergency Personnel 49 10-S-01-11 Evacuation of Onsite Personnel
- 10-S-01-12 Radiological Assessment and Protective Action Recommendations
- Attachment
Section 1EP1: Exercise Evaluation
- NUMBER TITLE REVISION 10-S-01-14 Emergency Radiological Monitoring
- 10-S-01-17 Emergency Personnel Exposure Control
- 10-S-01-20 Administration of Thyroid Blocking Agents
- 10-S-01-29 Operations Support Center Operations
- 10-S-01-30 Technical Support Center Operations
- 10-S-01-33 Emergency Operations Facility Operations
- 01-S-02-03 Activation of the Emergency Plan
- 118
- 2007 Biennial Exercise Scenario
- 2009 Biennial Exercise Scenario Scenario for May 31, 2011 Rehearsal Exercise Scenario for July 19, 2011 Rehearsal Exercise Evaluation Report for the February 19, 2010, Tabletop Drill Evaluation Report for the February 24, 2010, Drill Evaluation Report for the June 30, 2010, Drill Evaluation Report for the October 28, 2009, Drill Evaluation Report for the July 15, 2009, Drill Evaluation Report for the August 18, 2010, Drill Evaluation Report for the November 3, 2010, Drill Evaluation Report for the February 16, 2011, Drill Evaluation Report for the March 3, 2011, Drill Evaluation Report for the April 12, 2011, Drill
- CONDITION REPORTS
- Attachment
Section 1EP6: Drill Evaluation
- OTHER NUMBER TITLE DATE
- SCENARIO NARRATIVE AND SEQUENCE OF EVENT
- S GGNS IPX
- November 1, 2011
Section 4OA1: Performance Indicator Verification
- PROCEDURE NUMBER TITLE REVISION 06-OP-1E51-Q-0003 RCIC System Quarterly Pump Operability Verification
- 2 06-OP-1E51-Q-0002 RCIC System Valve Operability Test
- 113
- Grand Gulf Nuclear Station Emergency Plan
- 65, 66
- OTHER NUMBER TITLE DATE Attachment 9.2 NRC Performance Indicator Technique/Data Sheet: Unit 1
- Emergency AC Power (EDG), High Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI), Heat Removal (RCIC/EFW/AFW), Residual Heat Removal (RHR), Cooling Water Support rd Qtr. 2010 Attachment 9.2
- NRC Performance Indicator Technique/Data Sheet: Unit 1
- Emergency AC Power (EDG), High Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI), Heat Removal (RCIC/EFW/AFW), Residual Heat Removal (RHR), Cooling Water Support th Qtr. 2010 Attachment 9.2
- NRC Performance Indicator Technique/Data Sheet: Unit 1
- Emergency AC Power (EDG), High Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI), Heat Removal (RCIC/EFW/AFW), Residual Heat Removal (RHR), Cooling Water Support st Qtr. 2011
- Attachment
- OTHER NUMBER TITLE DATE Attachment 9.2
- NRC Performance Indicator Technique/Data Sheet: Unit 1
- Emergency AC Power (EDG), High Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI), Heat Removal (RCIC/EFW/AFW), Residual Heat Removal (RHR), Cooling Water Support nd Qtr. 2011 Attachment 9.2
- NRC Performance Indicator Technique/Data Sheet: Unit 1
- Emergency AC Power (EDG), High Pressure Injection (HPCS/HPCI/HPI/HPSI/FCI/HPI), Heat Removal (RCIC/EFW/AFW), Residual Heat Removal (RHR), Cooling Water Support rd Qtr. 2011
- CONDITION REPORT
Section 4OA2: Identification and Resolution of Problems
- OTHER NUMBER TITLE DATE
- QA-08-2011GGNS-1 Quality Assurance Audit Report March 2011
- QA-12/18-2011GGNS-1 Quality Assurance Audit Report June-July 2011
- QA-14/15-2011GGNS-1 Quality Assurance Audit Report October-November 2011
- QA-03-2011GGNS-1 Quality Assurance Audit Report May 2011
- CONDITION REPORT
- Attachment
- Attachment
- Attachment
Section 4OA3:
- Event Follow
-Up PROCEDURE NUMBER TITLE REVISION 04-1-01-R21-18 BOP BUS 18AG/28AG
- DRAWING NUMBER TITLE REVISION M-1080A Filter/Demineralizer System
- VPF-3713-349 Mark One, 1 1/2 Inch, 600 LB,
- CV 28 25 Sq. In. Actuator with Speed Controls and 4
-way Solenoid
- Attachment
- DRAWING NUMBER TITLE REVISION E-1206-015 G36 Filter Demin Cont. System (RWCU) PC A, Valves Unit 1
- 705807-01-01 Electrical Wiring Diagram PCWX 300
- E-1007 One Line Meter & Relay Diagram 4.16KV
- BUS 14AE Unit 1
- E-1033 One Line Diagram P72 Drywell Chiller Power Supplies Unit 1
- E-0001 Main One Line Diagram
- J-1227-L-017A RECIRC Pump "A" Motor C001A
-N Speed Pick
-Up 0 E-0117-001 Schematic Diagram 4.16 kV BOP System Incoming Breaker
- 2-1801 14
- OTHER NUMBER TITLE REVISION / DATE GGNS Yellow Memo Reactor Water Clean
-up (RWCU) trip due to working on the wrong component October 26, 2011 VMA Control No. 92/0139 Installation and Operating Instructions SLA Series Phase Monitors
- GGNS Operations
-Nights November 11, 2011
- Failure Mode Analysis Worksheet
(At 2241 on November 10, 2011 RFPT B tripped)
- Failure Mode Analysis Worksheet (Reactor Recirculation Flow Control Valve "A" (F060A) Did Not Experience Runback (CR
-GGN-2011-08125)
- GLP-OPS-B3300 Operator Training for Reactor Recirculation System B33
- PSW Recovery /A
-1 Pattern Adjustment Power Profile November 27, 2011
- GGNS Operations Logs, Days November 25, 2011
- EN-LI-118-08 Failure Mode Analysis Worksheet for buss 18AG experiencing a loss of power
- Attachment
- OTHER NUMBER TITLE REVISION / DATE
- PSW Recovery/A
-1 Pattern Adjustment Power Profile November 27, 2011 Plan of Action Issue: Woodpecker damage exists in Wood Pole Line for the Radial Well 34.5kV Overhead Power Feed to BOP23
- December 13, 2011
- CONDITION REPORT
- WORK ORDER
- WO 294611 01
Section 4OA5: Other Activities
- CALCULATIONS
- NUMBER TITLE REVISION
- MC-Q1111-08005 Calculation of Vortexing of ECCS Pumps
- CONDITION REPORTS
- Attachment
- WORK ORDERS
- DRAWINGS NUMBER TITLE REVISION M-1350A System Piping Isometric LPCS Pump Discharge to CTMT Aux. Bldg. and CTMT Unit 1
- CTMT Unit 1
- Unit 1 A M1348T System Piping Isometric Residual Heat Removal Loop C LPCI
- Containment
- Unit 1 14 M1348S System Piping Isometric RHR Loop C
- Pump Disch. to CTMT. Aux, Bldg. and CTMT
- Unit 1 17 M1348R System Piping Isometric RHR Pump C Suction Aux. BLDG. and CTMT
- Unit 1 A M1348J System Piping Isometric RHR A and B PSV. Disch. to Supp. Pool Aux. Bldg. and
- CTMT - Unit 1 11 M1348F System Piping Isometric Residual Heat Removal LPCI A and B and CTMT Spray
- CTMT and Aux. Bldg. - Unit 1 25 M1348D System Piping Isometric RHR HT Exch. 2A to Containment
- 19
- Attachment
- DRAWINGS NUMBER TITLE REVISION Unit 1
- FSK-S-1087-010-B GRW Drain From GBB
-7 8
- FSK-S-1087-003-B LPCS Jockey Pump C002
-A Discharge to
- GBB-9 7
- FSK-S-1086-028-B Vent for HPCS Pump Discharge From DBB
-8 8
- FSK-S-1086-013-B HPCS Jockey Pump Coo3
-C Discharge
- FSK-S-1085B-097-B High Point Vent From GBB
-92 to Drw.
- Drain 0
- FSK-S-1085B-075-B High Point Vent From GBB
-43 to Drw. Drain
- FSK-S-1085B-061-C Test Connection From GBB
-52 3
- FSK-S-1085A-058-B DRW. Vents From GBB
-58 to
- HBD-1032 10 M-1350B System Piping Isometric
- LPCS-CTMT to RPV Unit 1
- M1085C Residual Heat Removal System Unit 1
- M1086 High Pressure Core Spray system Unit 1
- M1085B Residual Heat Removal System Unit 1
- M1085A Residual Heat Removal System Unit 1
- M1087 Low Pressure Core Spray System Unit 1
- PROCEDURES
- NUMBER TITLE REVISION 06-OP-1E12-M-0001 LPCI/RHR Subsystem A Monthly Functional Test
- 105 06-OP-1E12-M-0002 LPCI/RHR Subsystem B Monthly Functional Test
- 108 06-OP-1E12-M-0003 LPCI/RHR Subsystem C Monthly Functional Test
- 105 06-OP-1E21-M-0001 LPCS Monthly Functional Test
- 104 06-OP-1E22-M-0001 HPCS Monthly Functional Test
- 105
- Attachment
- PROCEDURES
- NUMBER TITLE REVISION 04-1-01-E22-1 System Operating Instruction
- High Pressure Core Spray System
- 116 04-1-01-E21-1 System Operating Instruction
- Low Pressure Core Spray System
- 04-1-01-E12-1 System Operating Instruction
- Residual Heat Removal System
- 137
- MISCELLANEOUS DOCUMENTS
- NUMBER TITLE REVISIO N Engineering Report
- GGNS-ME-08-00002-001 Summary of Activities Associated with the Resolution of GL 2008
-01 1