IR 05000416/2014002
| ML14134A417 | |
| Person / Time | |
|---|---|
| Site: | Grand Gulf  |
| Issue date: | 05/14/2014 |
| From: | Allen D NRC/RGN-IV/DRP/RPB-C |
| To: | Kevin Mulligan Entergy Operations |
| Allen D | |
| References | |
| IR-14-002 | |
| Download: ML14134A417 (86) | |
Text
May 14, 2014
SUBJECT:
GRAND GULF NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000416/2014002
Dear Mr. Mulligan:
On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Grand Gulf Nuclear Station, Unit 1. On April 1, 2014, the NRC inspectors discussed the results of this inspection with you and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.
NRC inspectors documented two findings of very low safety significance (Green) in this report.
Both of these findings involved violations of NRC requirements. Further, inspectors documented two licensee-identified violations, which were determined to be of very low safety significance in this report. The NRC is treating these violations as non-cited violations (NCVs)
consistent with Section 2.3.2.a of the Enforcement Policy.
If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at the Grand Gulf Nuclear Station.
If you disagree with a cross-cutting aspect assignment, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC resident inspector at the Grand Gulf Nuclear Station.
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents 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/
Don Allen, Branch Chief Project Branch C
Division of Reactor Projects
Docket No.: 50-416 License No.: NPF-29
Enclosure:
Inspection Report 05000416/2014002 w/ Attachments: 1) Supplemental Information 2) Request for Additional Information for the Inservice Inspection 3) Request for Additional Information for the O
REGION IV==
Docket:
05000416 License:
NPF-29 Report:
05000416/2014002 Licensee:
Entergy Operations, Inc.
Facility:
Grand Gulf Nuclear Station, Unit 1 Location:
7003 Baldhill Road Port Gibson, MS 39150 Dates:
January 1 through March 31, 2014 Inspectors: R. Smith, Senior Resident Inspector B. Rice, Resident Inspector R. Azua, Senior Project Engineer J. Drake, Senior Reactor Inspector N. Greene, Ph.D., Health Physicist P. Hernandez, Health Physicist Approved By:
Don Allen Chief, Project Branch C Division of Reactor Projects
- 2 -
SUMMARY
IR 05000416/2014002; 01/01/2014 - 03/31/2014; Grand Gulf Nuclear Station, Integrated
Resident and Regional Report; Fire Protection and Radiological Hazard Assessment and Exposure Controls
The inspection activities described in this report were performed between January 1, 2014, and March 31, 2014, by the resident inspectors at the Grand Gulf Nuclear Station and inspectors from the NRCs Region IV office. Two findings of very low safety significance (Green) are documented in this report. Both of these findings involved violations of NRC requirements.
Additionally, NRC inspectors documented in this report two licensee-identified violations of very low safety significance. The significance of inspection findings is indicated by their color (Green, White, Yellow, or Red), which is determined using Inspection Manual Chapter 0609,
Significance Determination Process. Their cross-cutting aspects are determined using Inspection Manual Chapter 0310, Components Within the Cross-Cutting Areas. Violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process.
Cornerstone: Mitigating Systems
- Green.
The inspectors identified a non-cited violation of License Condition 2.C(41), Fire Protection Program, for the failure to adhere to procedural requirements to ensure that scaffold installed in the plant would not prevent or restrict the fire brigade from accessing a certain route used for response to a fire in the area. On February 4, 2014, the licensee installed a scaffold in the containment building for an inspection. The licensees procedure required a walkdown of proposed scaffold to determine if the scaffold would prevent or restrict fire brigade access. The initial reviewer identified that the ladder to access the scaffold would restrict fire brigade access, thus the ladder was not installed until it was required. On March 1, 2014, the ladder was installed for the four hour inspection. Once completed, the licensee failed to remove the scaffold ladder to restore normal access to the area. On March 4, 2014, the inspectors identified that the scaffold ladder was still installed.
The inspectors brought their concern to the licensee, who determined that the scaffold would adversely affect the response of fire brigade members to that area of containment.
As an immediate corrective action, the licensee removed the scaffold ladder to allow adequate access for the fire brigade members. The licensee documented this issue in Condition Report CR-GGN-2014-02363.
The failure to ensure fire brigade members had adequate access passed a scaffold installed in the containment building was a performance deficiency. The performance deficiency was more than minor and therefore a finding because it adversely impacted the protection against external factors attribute of the Mitigating System Cornerstone in that the fire brigades inability to gain access to certain areas in containment could result in preventing prompt extinguishing of fires. Using NRC Inspection Manual Chapter 0609, Attachment 4,
Initial Characterization of Findings, June 19, 2012, the inspectors determined that the issue affected the Mitigating Systems Cornerstone and that the finding pertained to a degraded condition while the plant was shutdown for refueling outage RF19. As a result, the inspectors were directed to Inspection Manual Chapter 0609, Appendix G, Shutdown
Operations Significance Determination Process, dated February 28, 2005. The inspectors determined that Appendix G did not address fire brigade issues and solicited input from the senior reactor analyst. The senior reactor analyst performed a detailed risk evaluation and determined that Inspection Manual 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, June 19, 2012, Exhibit 2, Mitigating System Screening Questions, adequately bounded the performance deficiency. The inspectors determined that the finding involved the response time of the fire brigade to a fire, and the finding was of very low safety consequence (Green) because the fire brigades response time was mitigated by other defense-in-depth elements such as area combustible limits were not exceeded, installed fire detection systems were functional, and alternate means of safe shutdown were not impacted. Specifically, there were no combustibles in the area beyond limits, all fire detectors for the area were functional, and the plant was in a shutdown condition with the cavity flooded at the time. The apparent cause of this finding was the work groups involved did not communicate the significance of the impact the scaffold ladder had on fire brigade access to the area and the importance of having the ladder removed upon completion of the work. Therefore, the finding has a cross-cutting aspect in the human performance area associated with team work, in that the individuals and workgroups failed to communicate and coordinate their activities within and across organizational boundaries to ensure nuclear safety was maintained [H.4] (Section 1R05).
Cornerstone: Occupational Radiation Safety
- Green.
The inspectors reviewed a self-revealing, non-cited violation of Technical Specification 5.7.3, resulting from the licensees failure to control a high radiation area with radiation levels greater than 1000 millirem per hour. As immediate corrective actions, the licensee stopped the work activity, placed a senior radiation protection technician in control of the area, surveyed all affected areas, and properly posted and controlled the area. The licensee also checked qualifications of the involved individuals and conducted a root cause evaluation for the event. This event was documented in the licensees corrective action program as Condition Reports CR-GGN-2014-02219, CR-GGN-2014-02221, and CR-GGN-2014-02224.
The failure to control a high radiation area with radiation levels greater than 1000 millirem per hour was a performance deficiency and a violation of Technical Specification 5.7.3. The performance deficiency was more than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of program and process (exposure control) and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation because it removed a barrier intended to prevent the worker from receiving unexpected dose. Using Inspection Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, dated August 19, 2008, the inspectors determined the violation has very low safety significance because: (1) it was not an as low as is reasonably achievable (ALARA) finding, (2) there was no overexposure, (3) there was no substantial potential for an overexposure, and (4) the ability to assess dose was not compromised. This violation has a cross-cutting aspect in the human performance area, associated with procedure adherence, because the licensee failed to follow process, procedures, and work instructions when they did not inventory and ensure control of the dry tube plunger end as it was stored in the horizontal fuel transfer system pool within containment [H.8] (Section 2RS1).
Licensee-Identified Violations
Violations of very low safety significance that were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and associated corrective action tracking numbers are listed in Section 4OA7 of this report.
PLANT STATUS
The Grand Gulf Nuclear Station began the inspection period at 100 percent thermal power. On January 10, 2014, the operators commenced a planned down power to 60 percent thermal power to perform channel friction testing, power suppression testing, and to adjust the control rod pattern. The operators returned the plant to 100 percent thermal power on January 17, 2014.
On February 9, 2014, the operators commenced a planned shutdown from 100 percent thermal power for refueling outage RF19.
On March 15, 2014, the operators commenced restart activities after refueling outage RF19 was completed.
On March 17, 2014, the operators inserted a manual scram from 41 percent thermal power due to a steam leak in the turbine building. The licensee repaired the source of the leak and commenced restart activities on March 20, 2014.
On March 29, 2014, the plant automatically shut down from 87 percent thermal power due to a main generator load reject, resulting in a turbine control valve fast closure, and was followed by a reactor scram. The licensee determined the cause of the load reject, implemented corrective actions, and began restart activities March 30, 2014.
At the end of the inspection period, the Grand Gulf Nuclear Station was at approximately 20 percent thermal power and was making preparations to roll the turbine and sync the generator to the grid.
REPORT DETAILS
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
.1 Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
On January 27, 2014, the inspectors completed an inspection of the stations readiness for seasonal extreme cold weather conditions. The inspectors reviewed the licensees adverse weather procedures for seasonal low temperatures and evaluated the licensees implementation of these procedures. The inspectors verified that prior to the onset of cold weather; the licensee had corrected weather-related equipment deficiencies identified during the previous cold weather season.
The inspectors selected four risk-significant systems that were required to be protected from cold weather conditions:
Division 1, 2, and 3 diesel generators
Fire pump house
Radial well pump houses 1, 3, 4, 5, and 6
Standby service water pump and valve houses for division 1 and 2
The inspectors reviewed the licensees procedures and design information to ensure the systems would remain functional when challenged by cold weather conditions. The inspectors verified that operator actions described in the licensees procedures were adequate to maintain readiness of these systems. The inspectors walked down portions of these systems to verify the physical condition of the systems were properly protected against cold weather conditions.
These activities constituted one sample of readiness for seasonal adverse weather, as defined in Inspection Procedure 71111.01.
b. Findings
No findings were identified.
.2 Readiness for Impending Adverse Weather Conditions
a. Inspection Scope
On January 6-8, 2014, the inspectors completed an inspection of the stations readiness for extreme cold weather conditions that occurred at the site. The inspectors reviewed plant design features, the licensees procedures to respond to extreme cold weather conditions, and the licensees implementation of these procedures. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors walked down various places in the plant that are vulnerable to cold weather conditions.
These activities constituted one sample of readiness for impending adverse weather conditions, as defined in Inspection Procedure 71111.01.
b. Findings
No findings were identified.
1R04 Equipment Alignment
Partial Walkdown
a. Inspection Scope
The inspectors performed partial system walk-downs of the following risk-significant systems:
February 11-12, 2014, standby liquid control system following a surveillance
February 12-13, 2014, high pressure core spray system during the plant refueling outage because it was a system relied upon for inventory control
February 12-13, 2014, alternate decay heat removal system aligned in standby mode for shutdown cooling operations
February 12-13, 2014, residual heat removal system C following outage maintenance activities
The inspectors reviewed the licensees procedures and system design information to determine the correct lineup for the systems. They visually verified that critical portions of the systems were correctly aligned for the existing plant configuration.
These activities constituted four partial system walk-down samples as defined in Inspection Procedure 71111.04.
b. Findings
No findings were identified.
1R05 Fire Protection
.1 Quarterly Inspection
a. Inspection Scope
The inspectors evaluated the licensees fire protection program for operational status and material condition. The inspectors focused their inspection on five plant areas important to safety:
January 15, 2014, upper cable spreading room (OC702)
January 15, 2014, lower cable spreading room (OC402)
January 15, 2014, engineering safety features heating, ventilation and air conditioning equipment room (OC302)
January 15, 2014, engineering safety features heating, ventilation and air conditioning equipment room (OC303)
February 18, 2014, general areas of the auxiliary building and containment building, including fire exclusion areas
For each area, the inspectors evaluated the fire plan against defined hazards and defense-in-depth features in the licensees fire protection program. The inspectors evaluated control of transient combustibles and ignition sources, fire detection and suppression systems, manual firefighting equipment and capability, passive fire protection features, and compensatory measures for degraded conditions.
These activities constituted five quarterly inspection samples, as defined in Inspection Procedure 71111.05.
b. Findings
Introduction.
The inspectors identified a Green non-cited violation of License Condition 2.C(41), Fire Protection Program, for the failure to adhere to procedural requirements to ensure that scaffold installed in the plant would not prevent or restrict the fire brigade from accessing a certain route used for response to a fire in the area.
Description.
On February 4, 2014, the licensee installed a scaffold in the containment cooler area on the 161 foot elevation of the containment building to provide a work platform for the inspection of wires passing through a wall penetration in containment.
Procedure EN-MA-133, Control of Scaffolding, Revision 10, required a walkdown of the proposed scaffold be performed to determine if the scaffold would prevent or restrict the fire brigade from accessing a certain route used for response to an emergency, i.e.
general access through hallways, stairwells, etc. The initial reviewer did identify that the ladder to access the scaffold would restrict fire brigade access to the area, thus the scaffold was tagged as incomplete, and the ladder was not installed until it was required.
On March 1, 2014, the ladder to the scaffold platform was installed to support the inspection activity. The inspection activity took approximately four hours to complete.
However, once the inspection was completed, the licensee failed to remove the scaffold ladder to restore normal access to the area. On March 4, 2014, the inspectors identified that the scaffold ladder was still installed, which restricted access through the walkway.
The inspectors brought their concern to the licensee, who determined that the scaffold would adversely affect the response of fire brigade members to that area of containment.
The licensee documented this issue in Condition Report CR-GGN-2014-02363. As a corrective action, the licensee removed the scaffold ladder to allow adequate access for the fire brigade members. Furthermore, the licensee verified that alternate routes were available for the fire brigade if required.
Analysis.
The failure to ensure fire brigade members had adequate access around a scaffold installed in the containment building was a performance deficiency. The performance deficiency was more than minor and therefore a finding because it adversely impacted the protection against external factors attribute of the Mitigating System Cornerstone, in that the fire brigades inability to gain access to certain areas in containment could result in preventing prompt extinguishing of fires. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, the inspectors determined that the issue affected the Mitigating Systems Cornerstone and that the finding pertained to a degraded condition while the plant was shutdown for refueling outage RF19. As a result, the inspectors were directed to Inspection Manual Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process, dated February 28, 2005. The inspectors determined that Appendix G did not address fire brigade issues and solicited input from the senior reactor analyst (SRA). The SRA performed a detailed risk evaluation and determined that Inspection Manual 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012, Exhibit 2, Mitigating System Screening Questions, adequately bounded the performance deficiency. The inspectors determined that the finding involved the response time of the fire brigade to a fire and that the finding was of very low safety consequence (Green) because the fire brigades response time was mitigated by other defense-in-depth elements such as area combustible limits were not exceeded, installed fire detection systems were functional, and alternate means of safe shutdown were not impacted. Specifically, there were no combustibles in the area beyond limits, all fire detectors for the area were functional, and the plant was in a shutdown condition with the cavity flooded at the time. The apparent cause of this finding was the work groups involved did not communicate the significance of the impact the scaffold ladder had on fire brigade access to the area and the importance of having the ladder removed upon completion of the work. Therefore, the finding has a cross-cutting aspect in the human performance area associated with team work, in that the individuals and workgroups failed to communicate and coordinate their activities within and across organizational boundaries to ensure nuclear safety was maintained [H.4].
Enforcement.
License Condition 2.C(41), Fire Protection Program, requires the licensee to implement and maintain in effect all provisions of the approved Fire Protection Program as described in Revision 5 to the Updated Final Safety Analysis Report (UFSAR). UFSAR Table 9.5-11, Fire Protection Program Comparison with NRC Requirements, provides the Grand Gulf Nuclear Stations position on meeting NRCs Appendix A to Branch Technical Position APCSB 9.5-1, dated August 23, 1976.
Position C.2 states, in part, the scope of the Fire Protection Quality Assurance Program for the Grand Gulf Nuclear Station was limited to selected aspects of 10 CFR Part 50, Appendix B. Specifically, Criteria III - V, VII, X, XI, and XIV - XVIII of Appendix B were invoked. Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, states, in part, that activities affecting quality shall be prescribed by documented instructions or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions or drawings.
Procedure EN-MA-133, Control of Scaffolding, Revision 10, stated, in part, the responsible person will walk down the job and provide key information regarding potential hazards, precautions, special conditions or compensatory measures needed in the associated work order and that the responsible person will assure that all required compensatory measures are captured. Contrary to the above, on or before March 4, 2014, the responsible person did not assure that all require compensatory measures were captured. Specifically, the responsible person failed to assure compensatory measures were in place for fire brigade response while the scaffold ladder was installed and that the scaffold ladder was removed immediately upon completion of the work.
This violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2.a of the Enforcement Policy because it was of very low safety significance (Green) and it was entered into the licensees corrective action program as CR-GGN-2014-02363 to address recurrence. (NCV 05000416/2014002-01, Failure to Ensure Scaffold Activity Would not Interfere with Fire Brigade Response)
.2 Annual Inspection
a. Inspection Scope
On January 22, 2014, the inspectors completed their annual evaluation of the licensees fire brigade performance. This evaluation included observation of one unannounced fire drill for the auxiliary building on January 22, 2014.
During this drill, the inspectors evaluated the capability of the fire brigade members, the leadership ability of the brigade leader, the brigades use of turnout gear and fire-fighting equipment, and the effectiveness of the fire brigades team operation. The inspectors also reviewed whether the licensees fire brigade met NRC requirements for training, dedicated size and membership, and equipment.
These activities constituted one annual inspection sample, as defined in Inspection Procedure 71111.05.
b. Findings
No findings were identified.
1R06 Flood Protection Measures
a. Inspection Scope
On January 8, 9, 17, and 23, 2014, the inspectors completed an inspection of underground bunkers susceptible to flooding. The inspectors selected five underground manholes that contained risk-significant or multiple-train cables whose failures could disable risk-significant equipment:
Manhole 01, containing division 1 and 2 safety related cables
Manhole 02, containing division 3 safety related cables
Manhole 03, containing division 3 safety related cables
Manhole 20, containing division 1 safety related cables
Manhole 21, containing division 2 safety related cables
The inspectors observed the material condition of the cables and splices contained in the manholes and looked for evidence of cable degradation due to water intrusion. The inspectors verified that the cables and vaults met design requirements.
These activities constitute completion of one manhole sample, as defined in Inspection Procedure 71111.06.
b. Findings
No findings were identified.
1R07 Heat Sink Performance
a. Inspection Scope
On March 3, 2014, the inspectors completed an inspection of the readiness and availability of risk-significant heat exchangers. The inspectors reviewed the data from a performance test for the B residual heat removal system heat exchanger and verified the licensee used the industry standard periodic maintenance method outlined in EPRI NP-7552 for the heat exchanger. Additionally, the inspectors verified that the heat exchanger was correctly categorized under the Maintenance Rule and was receiving the required maintenance.
These activities constitute completion of one heat sink performance annual review sample, as defined in Inspection Procedure 71111.07.
b. Findings
No findings were identified.
1R08 Inservice Inspection Activities
Completion of Sections
.1 and.2 below constitutes completion of one sample as defined
in Inspection Procedure 71111.08.
.1 Inspection Activities Other Than Steam Generator Tube Inspection, Pressurized Water
Reactor Vessel Upper Head Penetration Inspections, and Boric Acid Corrosion Control (71111.08-02.01)
a. Inspection Scope
The inspectors observed 10 nondestructive examination activities and reviewed four nondestructive examination activities that included six types of examinations. The licensee identified several relevant indications during the nondestructive examinations that were evaluated as acceptable for continued service.
The inspectors directly observed the following nondestructive examinations:
SYSTEM WELD/COMPONENT IDENTIFICATION EXAMINATION TYPE
Main Steam 1G33F406BW503 Penetrant Test
Main Steam 1G33G002W20 Ultrasonic Test SYSTEM WELD/COMPONENT IDENTIFICATION EXAMINATION TYPE
Main Steam 1E32G121W30 Ultrasonic Test
Main Steam 1E32G121W31 Ultrasonic Test
Nuts and Washers 26-76 Visual Test 1 Jet Pump RB-2b, d, RS-8-1516 Electronic Visual Test 1
Jet Pump RS-8-1516 Electronic Visual Test 1
Steam Dryer SDOD BD-EP V02b, Bank D to Endplate Vertical Weld Electronic Visual Test 1 Main Steam 1G36F101 Radiographic Test
Main Steam 1N11F015 Location 60, and Location 80 Welds and pipe ends Magnetic Particle Test
The inspectors reviewed records for the following nondestructive examinations:
SYSTEM WELD IDENTIFICATION EXAMINATION TYPE
Feedwater 1B21G030-5-8-1 Ultrasonic Testing
Feedwater 1B21G026W19 Ultrasonic Testing
Main Steam 1G33G002-20-11-2 Ultrasonic Testing
Seal Steam Generator 1N33D002 Ultrasonic Testing During the review and observation of each examination, the inspectors verified that activities were performed in accordance with the ASME Code requirements and applicable procedures. The inspectors also verified the qualifications of all nondestructive examination technicians performing the inspections were current.
The inspectors observed one weld on Main Steam Valve F406B. No welds on the reactor coolant system pressure boundary were observed.
The inspectors directly observed a portion of the following welding activities:
SYSTEM WELD IDENTIFICATION
WELD TYPE Main Steam 1G33F406BW503 Gas Tungsten Arc Welding
The inspectors verified, by review, that the welding procedure specifications and the welders had been properly qualified in accordance with ASME Code,Section IX, requirements. The inspectors also verified, through observation and record review, that essential variables for the welding process were identified, recorded in the procedure qualification record, and formed the bases for qualification of the welding procedure specifications. Specific documents reviewed during this inspection are listed in the attachment.
These actions constitute completion of the requirements for Section 02.01.
b. Findings
No findings were identified.
.2 Identification and Resolution of Problems (71111.08-02.05)
a. Inspection Scope
The inspectors reviewed 13 condition reports, which dealt with inservice inspection activities, and found the corrective actions for inservice inspection issues were appropriate. The specific condition reports reviewed are listed in the documents reviewed section. From this review the inspectors concluded that the licensee has an appropriate threshold for entering inservice inspection issues into the corrective action program and has procedures that direct a root cause evaluation when necessary. The licensee also has an effective program for applying industry inservice inspection operating experience. Specific documents reviewed during this inspection are listed in the attachment.
These actions constitute completion of the requirements of Section 02.05.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program and Licensed Operator Performance
.1 Review of Licensed Operator Requalification
a. Inspection Scope
On January 14, 2014, the inspectors observed simulator training for an operating crew.
This training involved the crew placing the plant in shutdown cooling operations and recovering from a loss of shutdown cooling. The inspectors assessed the performance of the operators and the evaluators critique of their performance. The inspectors also assessed the modeling and performance of the simulator during the requalification activities.
These activities constitute completion of one quarterly licensed operator requalification program sample, as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
.2 Review of Licensed Operator Performance
a. Inspection Scope
On January 10-11, 2014, the inspectors observed the performance of on-shift licensed operators in the plants main control room. At the time of the observations, the plant was in a period of heightened activity due to a down power to perform power suppression testing to identify a fuel defect. The inspectors observed the operators performance of the following activities:
Reducing power to approximately 60 percent by decreasing recirculation flow and inserting control rods
Inserting control rods in a predetermined pattern to conduct power suppression testing to locate the fuel defect
Conducting a weekly pre-lube of the division 3 diesel generator
Placing the standby service water system C in service for chemical addition
In addition, the inspectors assessed the operators adherence to plant procedures, including conduct of operations procedure, and other operations department policies.
These activities constitute completion of one quarterly licensed operator performance sample, as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors reviewed two instances of degraded performance or condition of safety-related structures, systems, and components (SSCs):
March 17, 2014, division 2 diesel generator (P75)
March 25, 2014, fire protection system (P64)
The inspectors reviewed the extent of condition of possible common cause SSC failures and evaluated the adequacy of the licensees corrective actions. The inspectors reviewed the licensees work practices to evaluate whether these may have played a role in the degradation of the SSCs. The inspectors assessed the licensees characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance Rule), and verified that the licensee was appropriately tracking degraded performance and conditions in accordance with the Maintenance Rule.
These activities constituted completion of two maintenance effectiveness samples, as defined in Inspection Procedure 71111.12.
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors observed portions of four emergent work activities and severe weather in the area that had the potential to cause an initiating event or to affect the functional capability of mitigating systems:
During the week of January 6, 2014, the licensee experienced a loss of the sites non-essential power loop, which impacted the site security, hydrogen water chemistry, and protection against cold weather conditions.
During the week of January 26, 2014, the licensee entered their off normal procedure for severe weather and a yellow risk condition for online activities due to a winter storm in the area. The licensee was also required to shift work through the week due to the winter storms impact on the site.
During the week of February 9, 2014, the licensee entered their off normal procedure for severe weather and took actions to ensure the freezing rain and extreme cold weather did not affect plant equipment and more specifically, the standby service water cooling tower, which was needed for shutdown cooling operations.
During the week of February 19, 2014, while in refueling outage RF 19, the licensee entered their off normal procedure for severe weather and took appropriate actions to ensure the site would be minimally affected due to thunder storms, high winds, and a tornado watch in the area.
The inspectors verified that the licensee appropriately developed and followed a work plan for these activities and conditions. The inspectors verified that the licensee took precautions to minimize the impact of the work activities and weather conditions on affected structures, systems, and components.
These activities constitute completion of four maintenance risk assessments and emergent work control inspection samples, as defined in Inspection Procedure 71111.13.
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
The inspectors reviewed five operability determinations and functionality assessments that the licensee performed for degraded or nonconforming structures, systems, or components.
January 17, 2014, operability determination of reactor core isolation cooling inverter
February 4, 2014, functionality assessment of turbine over-speed protection system stop and control valves
February 19, 2014, operability determination due to unaccounted for foreign material from instrumentation mounted on the steam dryer inside the reactor pressure vessel
February 19, 2014, operability determination due to various issues discovered during an in-vessel visual inspection and loose parts that could not be found or retrieved from the vessel prior to the end of refueling outage RF 19
March 19, 2014, operability determination for station 125 VDC ESF battery 1A3
The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded SSC to be operable or functional, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability or functionality. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability or functionality of the degraded SSC.
These activities constitute completion of five operability and functionality review samples, as defined in Inspection Procedure 71111.15.
b. Findings
No findings were identified.
1R18 Plant Modifications
a. Inspection Scope
On February 26, 2014, the inspectors reviewed a permanent modification to the first stage main steam sensing line, which provides power level information to the reactor protection system, and when power is above 35.4 percent rated thermal power, it causes an automatic plant shutdown if there is a turbine generator trip.
The inspectors reviewed the design and implementation of the modification. The inspectors verified that work activities involved in implementing the modification did not adversely impact operator actions, and they verified personnel would still be available to respond to an emergency or other unplanned event.
These activities constitute completion of one sample of permanent modifications, as defined in Inspection Procedure 71111.18.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed eight post-maintenance testing activities that affected risk-significant structures, systems, or components.
February 4 and 10, 2014, source range monitor B after maintenance
February 14, 2014, source range monitors A and E after maintenance
March 10, 2014, source range monitor F after dry tube replacement and detector replacement March 11, 2014, control rod blades after maintenance
March 11, 2014, control rod drive mechanisms after maintenance
March 11, 2014, drywell high pressure walk down at the conclusion of refueling outage RF 19
March 13, 2014, reactor core isolation cooling system warming/bypass valve after maintenance
March 14, 2014, inboard and outboard main steam isolation valves after maintenance
The inspectors reviewed licensing-and design-basis documents for the SSCs and the maintenance and post-maintenance test procedures. The inspectors observed the performance of the post-maintenance tests to verify that the licensee performed the tests in accordance with approved procedures, satisfied the established acceptance criteria, and restored the operability of the affected SSCs.
These activities constitute completion of eight post-maintenance testing inspection samples, as defined in Inspection Procedure 71111.19.
b. Findings
No findings were identified.
1R20 Refueling and Other Outage Activities
a. Inspection Scope
During the stations refueling outage that concluded on March 16, 2014, the inspectors evaluated the licensees outage activities. The inspectors verified that the licensee considered risk in developing and implementing the outage plan, appropriately managed personnel fatigue, and developed mitigation strategies for losses of key safety functions.
This verification included the following:
Review of the licensees outage plan prior to the outage
Monitoring of shut-down and cool-down activities
Verification that the licensee maintained defense-in-depth during outage activities
Observation and review of reduced inventory activities
Observation and review of fuel handling activities
Monitoring of heat-up and startup activities
Additionally, the inspectors performed a smart sample inspection (OpESS FY2007-03) of crane and heavy lift for the containment polar crane.
These activities constitute completion of one refueling outage sample, as defined in Inspection Procedure 71111.20.
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors observed nine risk-significant surveillance tests and reviewed test results to verify that these tests adequately demonstrated that the structures, systems, and components were capable of performing their safety functions:
In-service tests:
February 6, 2014, standby liquid control functional test
Containment isolation valve surveillance tests:
February 6-7, 2014, local leak rate testing for the residual heat removal A and B feedwater injection check valves and reactor core isolation cooling feedwater injection check valve
February 19, 2014, local leak rate testing for reactor core isolation cooling steam isolation valves
Reactor coolant system leak detection tests:
January 21, 2014, reviewed plant data, computer traces and interviewed plant personnel in regards to increasing trend in reactor coolant unidentified leakage in the drywell
Other surveillance tests:
January 8, 2014, anticipated transient without a scram testing for reactor water level and pressure channels A and E
January10-15, 2014, control rod friction testing for 18 control rods
February 18-25, 2014, division 2 emergency core cooling system functional testing for loss of site power, loss of coolant accident, and loss of site power/loss of coolant accident
February 28, 2014, division 1 emergency core cooling system functional testing for loss of site power March 15, 2014, reactor core isolation cooling system functional testing for low pressure injection following a refueling outage
The inspectors verified that these tests met technical specification requirements, that the licensee performed the tests in accordance with their procedures, and that the results of the test satisfied appropriate acceptance criteria. The inspectors verified that the licensee restored the operability of the affected SSCs following testing.
These activities constitute completion of nine surveillance testing inspection samples, as defined in Inspection Procedure 71111.22.
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
.1 Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors observed an emergency preparedness drill on January 21, 2014, to verify the adequacy and capability of the licensees assessment of drill performance. The inspectors reviewed the drill scenario, observed the drill from the simulator control room and the emergency operations facility, and attended the post-drill critique. The inspectors verified that the licensees emergency classifications, off-site notifications, and protective action recommendations were appropriate and timely. The inspectors verified that any emergency preparedness weaknesses were appropriately identified by the licensee in the post-drill critique and entered into the corrective action program for resolution.
These activities constitute completion of one emergency preparedness drill observation sample, as defined in Inspection Procedure 71114.06.
b. Findings
No findings were identified.
RADIATION SAFETY
Cornerstones: Public Radiation Safety and Occupational Radiation Safety
2RS1 Radiological Hazard Assessment and Exposure Controls
a. Inspection Scope
The inspectors assessed the licensees performance in assessing the radiological hazards in the workplace associated with licensed activities. The inspectors assessed the licensees implementation of appropriate radiation monitoring and exposure control measures for both individual and collective exposures. The inspectors walked down various portions of the plant and performed independent radiation dose rate measurements. The inspectors interviewed the radiation protection manager, radiation protection supervisors, and radiation workers. The inspectors reviewed licensee performance in the following areas:
The hazard assessment program, including a review of the licensees evaluations of changes in plant operations and radiological surveys to detect dose rates, airborne radioactivity, and surface contamination levels
Instructions and notices to workers, including labeling or marking containers of radioactive material, radiation work permits, actions for electronic dosimeter alarms, and changes to radiological conditions
Programs and processes for control of sealed sources and release of potentially contaminated material from the radiologically controlled area, including survey performance, instrument sensitivity, release criteria, procedural guidance, and sealed source accountability
Radiological hazards control and work coverage, including the adequacy of surveys, radiation protection job coverage and contamination controls, the use of electronic dosimeters in high noise areas, dosimetry placement, airborne radioactivity monitoring, controls for highly activated or contaminated materials (non-fuel) stored within spent fuel and other storage pools, and posting and physical controls for high radiation areas and very high radiation areas
Radiation worker and radiation protection technician performance with respect to radiation protection work requirements
Audits, self-assessments, and corrective action documents related to radiological hazard assessment and exposure controls since the last inspection
These activities constitute completion of one sample of radiological hazard assessment and exposure controls as defined in Inspection Procedure 71124.01.
b. Findings
Introduction.
The inspectors reviewed a self-revealing, Green, non-cited violation of Technical Specification 5.7.3, resulting from the licensees failure to control a high radiation area with radiation levels greater than 1000 millirem per hour, which resulted in two dose rate alarms.
Description.
On March 1, 2014, two individuals (i.e., radworkers) were performing clean-up activities in the reactor cavity area and commenced retrieving items from the horizontal fuel transfer system (HFTS) pool. During their retrieval actions for a N1 nozzle panel knob, which was placed in a bucket and stored in the pool previously, the individuals also began to raise a second bucket from the pool. The radworkers incorrectly believed that the second bucket contained their tools. Both buckets were secured to the pool handrail with rope. The second bucket was initially positioned five feet below the surface of the water and was not tagged, posted, or locked to prevent withdrawal from the pool. A radiation protection (RP) technician was nearby to survey the tools as they were being removed from the pool. As the radworkers lifted the second bucket near the surface of the pool, the RP technician noticed the survey meter reading quickly increased to nearly 1,500 millirem per hour in the general area. The RP technician instructed the radworkers to immediately stop raising the second bucket from the HFTS pool water. The two radworkers complied with the RP technician instructions.
However, both individuals had already been exposed to elevated dose rates and received dose rate alarms. Radworker #1 received a maximum dose rate of 1140 millirem per hour and Radworker #2 received a maximum dose rate of 769 millirem per hour on their electronic alarming dosimeters. Both workers received less than 4 millirem dose during the evolution. Survey GG-1403-0051, performed on March 2, 2014, in response to the event, showed the contact dose rate of the dry tube plunger end (the item stored in the second bucket) as 9,000 rem per hour and 21 rem per hour at 30 cm.
There were failures to follow radiological work permit (RWP) requirements associated with this event. RWP 2014-1402, Refuel Floor High Water Activities, required that RP ensure pool inventory is updated as items are added to or removed from the pools. Per a discussion with the licensee, on the night shift of February 26, 2014, an RP technician was present and provided approval to place the dry tube plunger end into the pool.
However, the RP technician failed to update the pool inventory with this item, including surveying the item to establish appropriate controls. During the event, Radworker #1 was signed onto Task 1 of RWP 2014-1402, which had alarm setpoints of 25 millirem for dose and 100 millirem per hour for dose rate. Radworker #2 was signed onto Task 1 of RWP 2014-1403, Refuel Floor Miscellaneous Craft Support, which had alarm setpoints of 40 millirem for dose and 300 millirem per hour for dose rate. Neither RWP allowed access to a locked high radiation area or specified the dose rate levels of exposure.
There were numerous failures to follow procedures that led to the event. Step 5.3[8] of Procedure EN-RP-121, Revision 7, Radioactive Material Control, stated that items that can generate dose rates greater than 1 rem per hour at 30 cm when removed from the water are to be secured in a manner to prevent them from being withdrawn in accordance with procedures associated with locked high radiation area access controls.
However, the licensee had previously failed to comply with procedural and RWP requirements when RP did not inventory and survey the items stored in the HFTS pool on February 26, 2014. As a result, the items with dose rates greater than 1 rem per hour at 30 cm were not secured in a manner to prevent withdrawal from the HFTS pool and locked high radiation area controls were not established.
In addition, Section 5.5[1] of Procedure EN-RP-123, Revision 1, Radiological Controls for Highly Radioactive Objects, stated, in part, that no highly radioactive object shall be raised higher than 10 feet below the water surface unless specified by the work control document (WCD) and approved by the RWP. Section 5.5[1](b) and
- (e) stated that
- (b) RP technicians shall survey the highly radioactive object as it is being moved within the water with extendible high range radiation measurement instruments designed for use under water as directed by the applicable RWP and
- (e) locked high radiation area controls should be maintained during movements and storage of highly radioactive objects. By this procedure, highly radioactive objects were defined as those items with contact dose rates equal to or greater than 10 rem per hour. Furthermore, Section 5.6[1]
of this procedure stated, in part, that underwater equipment being removed from the pool shall be monitored by one or more RP technicians and monitoring shall begin at least 10 feet below the surface of the water. However, because the dry tube plunger end had not been surveyed when initially placed into the pool and was stored only 5 feet below the water surface, these procedural steps were also not followed.
As immediate corrective actions, the licensee lowered the item to the pool floor in a safe condition, stopped the work activity, placed a senior radiation protection technician in control of the area, surveyed all affected areas, and properly posted and controlled the area and highly radioactive item. The licensee also checked qualifications of the involved individuals and conducted a root cause evaluation for the event. This event was documented in the licensees corrective action program as Condition Reports CR-GGN-2014-02219, CR-GGN-2014-02221, and CR-GGN-2014-02224.
Analysis.
The HFTS pool area was required to be controlled as a locked high radiation area when materials with dose rates greater than 1000 millirem per hour were raised above or near the surface of the water. The failure to control a high radiation area with radiation levels greater than 1000 millirem per hour was a performance deficiency and a violation of Technical Specification 5.7.3. The performance deficiency was more than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of program and process (exposure control) and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation because it removed a barrier intended to prevent the worker from receiving unexpected dose. Using Inspection Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, dated August 19, 2008, the inspectors determined the violation had very low safety significance because:
- (1) it was not an as low as is reasonably achievable (ALARA) finding,
- (2) there was no overexposure,
- (3) there was no substantial potential for an overexposure, and
- (4) the ability to assess dose was not compromised. Regarding the substantial potential for an overexposure, the inspectors reviewed the event details and determined that the licensee provided adequate controls over the locked high radiation area event to ensure 10 CFR Part 20 dose limits were not exceeded. Specifically, the radworkers were using operable electronic alarming dosimeters and other area radiation instrumentation to monitor dose rates. Thus, there was no reasonable scenario in which a minor alteration of circumstances would have resulted in a violation of the 5 rem total effective dose equivalent limit.
The licensee had procedural requirements that should have prevented this occurrence had they been properly implemented. Therefore, this violation has a cross-cutting aspect in the human performance area, associated with the procedure adherence, because the licensee failed to follow process, procedures, and work instructions when they did not inventory and ensure control of the dry tube plunger end as it was stored and moved in the HFTS pool within containment [H.8].
Enforcement.
Technical Specification 5.7.3, states, in part, that individual areas with radiation levels greater than or equal to 1000 millirem per hour, accessible to personnel, that are located within large areas such as reactor containment, where no enclosure exists for purposes of locking, or that is not continuously guarded, and where no enclosure can be reasonably constructed around the individual area, that individual area shall be barricaded and conspicuously posted, and a flashing light shall be activated as a warning device. Contrary to these requirements, on March 1, 2014, an individual area with radiation levels greater than 1000 millirem per hour, accessible to personnel, located within reactor containment where no enclosure existed for purposes of locking (i.e. the reactor cavity pool) was not barricaded and conspicuously posted, and a flashing light was not activated as a warning device for the area. Specifically, locked high radiation area controls were not established for the reactor cavity pool, resulting in radworkers being exposed to items with dose rates greater than 1000 millirem per hour because those highly radioactive items were not secured from being withdrawn from the surface of the pool water as required by procedure.
Because this violation was of very low safety significance and was entered into the licensees corrective action program as Condition Reports CR-GGN-2014-02219, CR-GGN-2014-02221, and CR-GGN-2014-02224, this violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy.
(NCV 05000416/2014002-02, Failure to Control a Locked High Radiation Area Due to Unsecured Highly Radioactive Materials Stored in the Pool)
2RS3 In-plant Airborne Radioactivity Control and Mitigation
a. Inspection Scope
The inspectors evaluated whether the licensee controlled in-plant airborne radioactivity concentrations consistent with ALARA principles and that the use of respiratory protection devices did not pose an undue risk to the wearer. During the inspection, the inspectors interviewed licensee personnel, walked down various portions of the plant, and reviewed licensee performance in the following areas:
The licensees use, when applicable, of ventilation systems as part of its engineering controls
The licensees respiratory protection program for use, storage, maintenance, and quality assurance of NIOSH certified equipment, qualification and training of personnel, and user performance
The licensees capability for refilling and transporting SCBA air bottles to and from the control room and operations support center during emergency conditions, status of SCBA staged and ready for use in the plant and associated surveillance records, and personnel qualification and training
Audits, self-assessments, and corrective action documents related to in-plant airborne radioactivity control and mitigation since the last inspection
These activities constitute completion of one sample of in-plant airborne radioactivity control and mitigation as defined in Inspection Procedure 71124.03.
b. Findings
No findings were identified.
OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Security
4OA1 Performance Indicator Verification
.1 Unplanned Scrams per 7000 Critical Hours (IE01)
a. Inspection Scope
The inspectors reviewed licensee event reports (LERs) for the period of January 1, 2013, through December 31, 2013, to determine the number of scrams that occurred. The inspectors compared the number of scrams reported in these LERs to the number reported for the performance indicator. Additionally, the inspectors sampled monthly operating logs to verify the number of critical hours during the period. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported.
These activities constituted verification of the Unplanned Scrams per 7000 Critical Hours performance indicator, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
.2 Unplanned Power Changes per 7000 Critical Hours (IE03)
a. Inspection Scope
The inspectors reviewed operating logs, corrective action program records, and monthly operating reports for the period of January 1, 2013, through December 31, 2013, to determine the number of unplanned power changes that occurred. The inspectors compared the number of unplanned power changes documented to the number reported for the performance indicator. Additionally, the inspectors sampled monthly operating logs to verify the number of critical hours during the period. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported.
These activities constituted verification of the Unplanned Power Changes per 7000 Critical Hours performance indicator, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
.3 Unplanned Scrams with Complications (IE04)
a. Inspection Scope
The inspectors reviewed the licensees basis for including or excluding in this performance indicator each scram that occurred between January 1, 2013, and December 31, 2013. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the data reported.
These activities constituted verification of the Unplanned Scrams with Complications performance indicator, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
.4 Occupational Exposure Control Effectiveness (OR01)
a. Inspection Scope
The inspectors verified there were no unplanned exposures or losses of radiological control over locked high radiation areas and very high radiation areas during the period of October 1, 2013, to December 31, 2013. The inspectors reviewed a sample of radiologically controlled area exit transactions showing exposures greater than 100 millirem. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.
These activities constituted verification of the occupational exposure control effectiveness performance indicator, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
.5 Radiological Effluent Technical Specifications (RETS)/Offsite Dose Calculation Manual
(ODCM) Radiological Effluent Occurrences (PR01)
a. Inspection Scope
The inspectors reviewed corrective action program records for liquid or gaseous effluent releases that occurred between October 1, 2013, and December 31, 2013, and were reported to the NRC to verify the performance indicator data. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported data.
These activities constituted verification of the radiological effluent technical specifications (RETS)/offsite dose calculation manual (ODCM) radiological effluent occurrences performance indicator, as defined in Inspection Procedure 71151.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution
.1 Routine Review
a. Inspection Scope
Throughout the inspection period, the inspectors performed daily reviews of items entered into the licensees corrective action program and periodically attended the licensees condition report screening meetings. The inspectors verified that licensee personnel were identifying problems at an appropriate threshold and entering these problems into the corrective action program for resolution. The inspectors verified that the licensee developed and implemented corrective actions commensurate with the significance of the problems identified. The inspectors also reviewed the licensees problem identification and resolution activities during the performance of the other inspection activities documented in this report.
b. Findings
No findings were identified.
.2 Annual Follow-up of Selected Issues
a. Inspection Scope
The inspectors selected one issue for an in-depth follow-up:
On January 6-10, 2014, the inspectors reviewed Condition Report CR-GGN-2009-02347 that addressed the loss of the non-essential site power loop. The inspectors performed a detailed historical review of the previous losses of the non-essential site power loop and determined that approximately six total losses of the site power loop had occurred at the site since 1998, including the current week of January 6, 2014. The licensees corrective actions were less than complete because although repairs were performed to restore the non-essential power loop at the time of the occurrences, no long range corrective actions were implemented and repeat incidences kept occurring. The impact of the loss of the site power loop effects emergency preparedness in that the emergency operations facility must be powered by its standby diesel generator. The loss of the site power loop affects the security department because it loses power to some of its equipment, and this requires compensatory actions to be implemented. The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews, and compensatory actions. The inspectors verified that the licensee did not appropriately prioritize corrective actions and that these actions were inadequate to correct the apparent cause of the condition. Although this was a performance deficiency, it did not rise to above minor threshold for a finding.
These activities constitute completion of one annual follow-up sample as defined in Inspection Procedure 71152.
b. Findings
No findings were identified.
4OA3 Follow-up of Events and Notices of Enforcement Discretion
.1 (Closed) Licensee Event Report 05000416/2013-004-00: Operation prohibited by
Technical Specifications due to inadvertent bypass of Reactor Steam Dome High Pressure Interlock for Residual Heat Removal System Isolation
a. Inspection Scope
On August 3, 2013, the Grand Gulf Nuclear Station entered Mode 2 (Startup) from Mode 4 (Cold Shutdown). Subsequently, the licensee entered Mode 1 on August 4, 2013. On August 6, 2013, with the unit at 93.5 percent thermal power, the licensee discovered that it was not in compliance with Technical Specification (TS) 3.3.6.1, Primary Containment and Drywell Isolation Instrumentation, due to jumpers that were installed while the plant was in cold shutdown. The jumpers were installed as an equipment protection measure to prevent an inadvertent actuation of the residual heat removal system isolation valves. This event had no adverse effect on public health and safety as the jumpers were installed for equipment protection. The residual heat removal isolation valves were able to be remotely opened if needed for shutdown cooling operations.
The apparent cause of this condition was inadequate control of temporary modifications.
Specifically, Integrated Operating Instruction (IOI) 03-1-01-3, Cold Shutdown to Generator Carrying Minimum Load, did not include steps to maintain control of temporary modifications, thus the temporary modifications of installing the jumpers were not being tracked in the Temp Mod Log book or the operations narrative logs. As a result, the licensee failed to remove the jumpers prior to changing to Mode 2. The licensee conducted an apparent cause evaluation and identified other contributing causes and corrective actions. Documents reviewed as part of this inspection are listed in the attachment. The enforcement aspects of this finding are documented as a licensee identified violation in section 4OA7 of this report. This LER is closed.
These activities constitute completion of one event follow-up sample, as defined in Inspection Procedure 71153.
b. Findings
No findings were identified.
.2 Manual Reactor Scram and Main Steam Isolation Due to a Steam Leak in the Turbine
Building
a. Inspection Scope
On March 17, 2014, at 5:14 a.m. the Grand Gulf Nuclear Station inserted a manual reactor scram and shut the main steam isolation valves from 41 percent rated thermal power due to a steam line break in the turbine building. The inspectors responded to the control room and verified that the plant systems responded as designed and that the operators stabilized the plant in accordance with station procedures. The operators scrammed the plant and shut the main steam isolation valves when they received reports from plant personnel that there was a large steam leak in the turbine building.
The cause of the steam leak was a break of common drain/equalizing lines for the A and B main steam lines. The line broke from the bottom of the B main steam line at a point upstream of the B main steam line inlet to the high pressure turbine. The inspectors monitored plant cool down using reactor core isolation cooling and manual actuation of safety relief valves. The licensee placed the plant into shutdown cooling operations.
The licensee determined the cause of the steam line breaking and took corrective actions to replace the damaged steam line prior to startup.
These activities constitute completion of one event follow-up sample, as defined in Inspection Procedure 71153.
b. Findings
No findings were identified.
.3 Automatic Reactor Scram Due to a Main Generator Load Reject
a.
Inspector Scope
On March 29, 2014, at 10:08 a.m. the Grand Gulf Nuclear Station automatically scrammed from 87 percent rated thermal power due to a main turbine control valve fast closure that initiated a reactor protection system scram. The inspectors responded to the site and went to the control room to verify that the plant systems responded as designed and that the operators stabilized the plant in accordance with station procedures. The inspectors also monitored the plant operators stabilizing the plant in a hot shutdown condition. Initial investigation showed the cause of the turbine control valves closure was due to the actuation of a main turbine load reject relay. The cause of the actuation of the load reject relay is still under investigation, but one of the relay circuit boards was found in a degraded condition. The licensee took corrective actions to replace the degraded circuit board along with the associated power supply prior to startup.
These activities constitute completion of one event follow-up sample, as defined in Inspection Procedure 71153.
b. Findings
No findings were identified.
4OA5 Other Activities
.1 (Closed) Temporary Instruction 2515/182 - Review of the implementation of the Industry
Initiative to Control Degradation of Underground Piping and Tanks
a. Inspection scope
Leakage from buried and underground pipes has resulted in groundwater contamination incidents with associated heightened NRC and public interest. The industry issued a guidance document, NEI 09-14, Guideline for the Management of Buried Piping Integrity, (ADAMS Accession No. ML1030901420) to describe the goals and required actions (commitments made by the licensee) resulting from this underground piping and tank initiative. On December 31, 2010, NEI issued Revision 1 to NEI 09-14, Guidance for the Management of Underground Piping and Tank Integrity, (ADAMS Accession No. ML110700122) with an expanded scope of components which included underground piping that was not in direct contact with the soil and underground tanks. On November 17, 2011, the NRC issued Temporary Instruction 2515/182, Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, to gather information related to the industrys implementation of this initiative.
b. Observations The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.a of the Temporary Instruction, and it was confirmed that activities, which correspond to completion dates specified in the program, which have passed since the Phase 1 inspection was conducted, have been completed.
Additionally, the licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.b of the Temporary Instruction and responses to specific questions were submitted to the NRC headquarters staff. Based upon the scope of the review described above, Phase II of TI-2515/182 was completed.
c. Findings
No findings were identified.
4OA6 Meetings, Including Exit
Exit Meeting Summary
On February 25, 2014, the inspector presented the results of the in-service underground/buried piping inspection activities with Mr. D. Wiles, Director, Engineering, 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.
On February 27, 2014, the inspectors presented the radiation safety inspection results to Mr. J. Nadeau, Manager, Regulatory Assurance and Performance Improvement, and other members of the licensee staff. On March 19, 2014, the inspectors re-exited telephonically with Mr. K. Mulligan, Site Vice-President, Operations, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.
On April 1, 2014, the inspectors presented the inspection results to Mr. K. Mulligan, Site Vice-President, Operations, and other members of the licensee staff. The licensee acknowledged the issues presented. The licensee confirmed that any proprietary information reviewed by the inspectors had been returned or destroyed.
4OA7 Licensee-Identified Violations
The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as non-cited violations.
Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, states, in part, that design control measures be established and implemented to assure that applicable regulatory requirements and the design basis for structures, systems, and components are correctly translated into specifications, drawings, procedures, and instructions.
Contrary to the above, the licensee failed to implement applicable design bases for the Standby Service Water System Pump 4160 VAC cables being submerged. Specifically, on January 31, 2014, the licensee did not prevent water from submerging the cables in Manhole MH-01 due to a failed sump pump. The inspectors verified that the latest megger tests for the standby service water pump cables were acceptable for demonstrating operability. This finding has been entered into the licensees corrective action program as Condition Reports CR-GGN-2014-00616 and CR-GGN-2014-00768.
Using Manual Chapter 0609, Appendix A, Significance Determination Process for Findings at Power, dated June 19, 2012, the inspectors determined that this finding had very low safety significance (Green) because it did not result in the standby service water system becoming inoperable.
Technical Specification (TS) 3.3.6.1, Primary Containment and Drywell Instrumentation, requires the primary containment and drywell isolation instrumentation be operable while in Modes 1, 2, and 3. Contrary to the above, on August 3, 2013, the licensee failed to ensure the primary containment and drywell isolation instrumentation was operable prior to changing from Mode 4 (Cold Shutdown) to Mode 2 (Startup). On August 6, 2013, during a supervisory review of procedures in progress, the licensee determined that they were not incompliance with TS 3.3.6.1 due to jumpers that were installed to disable the function of the instrumentation. The licensee immediately entered the TS 3.3.6.1 Limiting Condition for Operation and associated actions. The licensee restored compliance with the TS by removing the jumpers and restoring the primary containment and drywell instrumentation to operable status and documented this issue in the corrective action program under Condition Report CR-GGN-2013-5101.
Using Manual Chapter 0609, Appendix A, Significance Determination Process for Findings at Power, dated June 19, 2012, the inspectors determined that this finding had very low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of the reactor containment or drywell and did not involve the hydrogen igniters in the reactor containment.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- M. Bacon, Supervisor, Training
- C. Baughman, Senior Specialist, Licensing
- C. Beschett, Manager, Nuclear Oversight
- B. Bingham, Lead Technician, Radiation Protection
- V. Bonds, Senior Health Physicist and Chemistry Specialist
- J. Dorsey, Security Manager
- W. Dowdy, Senior Technician, Radiation Protection
- W. Drinkard, Systems Engineer, Engineering
- H. Farris, Assistant Operations Manager
- J. Gerard, Manager, Operations
- W. Goss, Senior Health Physicist, Radiation Protection
- J. Hagood, Senior Health Physicist, Radiation Protection
- J. Hubbard, Program Owner, ISI
- W. Johnson, Systems Engineer 2, Engineering
- J. Miller, General Manager Plant Operations
- R. Miller, Manager, Radiation Protection
- K. Mulligan, Site Vice President
- J. Nadeau, Manager, Regulatory Assurance and Performance Improvement
- F. Rosser, Supervisor, Radiation Protection
- J. Seiter, Acting Manager, Licensing
- P. Stokes, Radiological Supervisor, Radiation Protection
- B. Taylor, Program owner, Underground/Buried Piping
- T. Thornton, Manager, Design Engineering
- D. Wiles, Director, Engineering
NRC Personnel
- D. Loveless, Senior Reactor Analyst
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
- 05000416/2014002-01 NCV Failure to Ensure Scaffold Activity Would not Interfere with Fire Brigade Response (Section 1R05)
- 05000416/2014002-02 NCV Failure to Control a Locked High Radiation Area Due to Unsecured Highly Radioactive Materials Stored in the Pool (Section 2RS1)
Closed
Licensee Event Report:
- 05000416/2013-004-00 LER Operation prohibited by Technical Specifications due to inadvertent bypass of Reactor Steam Dome High Pressure Interlock for Residual Heat Removal System Isolation (Section 4OA3)
Temporary Instruction 2515/182 TI Review of the Implementation of the Industry Initiative of Control Degradation of Underground Piping and Tanks (Section 4OA5)