IR 05000416/2013005

IR 05000416-13-005, on 10/01/2013 - 12/31/2013, Grand Gulf Nuclear Station, Integrated Resident and Regional Report, Refueling and Other Outage Activities, Surveillance Testing; and Radiological Hazard Assessment and Exposure Controls

ML14043A352
Person / Time
Site:	Grand Gulf
Issue date:	02/12/2014
From:	Allen D NRC/RGN-IV/DRP/RPB-C
To:	Kevin Mulligan Entergy Operations
References
IR-13-005
Download: ML14043A352 (58)

Text

UNITED STATES uary 12, 2014

SUBJECT:

GRAND GULF NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000416/2013005

Dear Mr. Mulligan:

On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Grand Gulf Nuclear Station, Unit 1. On January 16, 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 four findings of very low safety significance (Green) in this report.

All of these findings involved violations of NRC requirements. 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 in this report, 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 05000416/2013005 w/ Attachments: 1) Supplemental Information 2) Request for Additional Information for the Occupational Radiation Safety Inspection cc w/ encl: Electronic Distribution for the Grand Gulf Nuclear Station

SUMMARY

IR 05000416/2013005; 10/01/2013 - 12/31/2013; Grand Gulf Nuclear Station, Integrated

Resident and Regional Report; Refueling and Other Outage Activities; Surveillance Testing; and Radiological Hazard Assessment and Exposure Controls The inspection activities described in this report were performed between October 1, 2013, and December 31, 2013, by the resident inspectors at the Grand Gulf Nuclear Station, five inspectors from the NRCs Region IV office and one inspector from the NRCs Office of Nuclear Security and Incident Response. Four findings of very low safety significance (Green) are documented in this report. All of these findings involved violations of NRC requirements. 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: Barrier Integrity

Green.

The inspectors identified a non-cited violation of Technical Specification 3.4.11 for the failure to comply with the Reactor Coolant System (RCS) Pressure and Temperature Limits Report (PTLR) during plant cold startups. Specifically, the PTLR had a lower limit of zero psig, and the licensee operated the reactor pressure vessel (RPV) below zero psig during the plant start-up that commenced on November 2, 2013. A review of plant data showed that the RPV pressure was maintained below zero psig for approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

The licensee performed an engineering evaluation and determined that the maximum compressive stress experienced by the RPV did not exceed the maximum yield strength of RPV. Immediate corrective action included revising Procedure 03-1-01-1, Cold Shutdown to Generator Carrying Minimum Load, to ensure the RPV is pressurized prior to opening the main steam isolation valves (MSIVs) and providing training on the procedural changes to all the operating crews. The licensee entered this issue into the corrective action process under Condition Report CR-GGN-2013-07021.

The failure to comply with the RCS Pressure and Temperature Limits Report specified in Technical Specification 3.4.11 was a performance deficiency. The performance deficiency was determined to be more than minor, and therefore a finding, because it was associated with the human performance attribute of the Barrier Integrity Cornerstone and had the potential to adversely affect the associated cornerstone objective of providing reasonable assurance that a physical design barrier (reactor coolant system) protects the public from radionuclide release caused by accidents or events. Specifically, without NRC review and approval of revised pressure and temperature limits that include operating the RPV below zero psig, the inspectors did not have reasonable assurance the RPV would not be adversely affected. Using NRC Inspection Manual Chapter 0609, Attachment 4, "Initial Characterization of Findings," June 19, 2012, the inspectors determined that the issue affected the Barrier Integrity Cornerstone. Using NRC Inspection Manual Chapter 0609,

Appendix A, The Significance Determination Process for Findings At-Power,

June 19, 2012, Exhibit 3, the inspectors determined that since this finding involved the reactor coolant system boundary, a detailed risk evaluation was required. The Senior Reactor Analyst reviewed the finding and determined that a detailed risk evaluation was not required. The licensee performed an engineering evaluation and concluded that there was no impact to the reactor vessel. As a result, the Senior Reactor Analyst concluded that there was no change in risk due to the performance deficiency. The inspectors determined that since the procedural steps to perform Attachments VIII and X concurrently had been in place since 1994, this was a latent issue; therefore no cross-cutting aspect was assigned (Section 1R20).

Green.

The inspectors reviewed a self-revealing, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures and Drawings, for the failure to provide an adequate procedure for a safety related activity. On December 17, 2013, while performing Surveillance Procedure 06-IC-1E31-Q-1016-02, RCIC Steam Supply Pressure Low Functional Test, Revision 111, the reactor core isolation cooling (RCIC) system became inoperable due to the procedure being incorrectly revised. Furthermore, the procedure error resulted in the containment isolation capability for RCIC being lost for approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. As an immediate corrective action, the licensee restored the breakers regaining isolation capability, and reopened the RCIC inboard isolation valve, thus restoring RCIC to operable status. The licensee entered this issue into the corrective action process under Condition Reports CR-GGN-2013-07720, CR-GGN-2013-07733, and CR-GGN-2013-07374.

The failure to have an adequate procedure for the reactor core isolation cooling steam supply pressure low functional test is a performance deficiency. The performance deficiency was more than minor and therefore a finding because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This performance deficiency was also associated with the procedural quality attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstones objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, June 19, 2012, the inspectors determined the issue affected the Barrier Integrity Cornerstone. The inspectors used Inspection Manual Chapter 0609,

Appendix H, Containment Integrity Significance Determination Process, May 6, 2004, and determined the finding was a type B finding at full power. Using Table 6.1, Phase 1 Screening-Type B Findings at Power, the inspectors concluded that since this issue involved containment isolation valves in a BWR Mark III containment, a Phase 2 analysis was necessary. Using Table 6.2, Phase 2 Risk Significance - Type B Findings at Full Power, the inspectors concluded that the risk significance was very low (Green) because the exposure time was less than 3 days. Furthermore, the inspectors determined that this issue affected the Mitigating System Cornerstone. Using NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At-Power,

June 19, 2012, Exhibit 2, the inspectors determined that since the finding represented a loss of system and/or function, a detailed risk evaluation was required. The inspectors utilized the Grand Gulf Standardized Plant Analysis Risk model to determine the change in core damage frequency (CDF) due to the loss of safety function. The inspectors assigned the RCIC system a failure probability of 1.00 for a conservative duration of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The resulting change in CDF was 1.9E-9/year, thus the finding was of very low safety significance (Green). The Senior Risk Analyst reviewed the inspectors evaluation and verified the conclusions to be correct. The apparent cause of this finding was that the licensee failed to effectively utilize human error prevention techniques. Therefore, the finding had a cross-cutting aspect in the area of human performance, work practices because the licensee did not perform adequate self and peer checking while performing an activity affecting quality

H.4(a) (Section 1R22).

Cornerstone: Occupational Radiation Safety

Green.

The inspectors reviewed a self-revealing, non-cited violation of Technical Specification 5.7.1, resulting from an individual entering a high radiation area without the required radiation monitoring device. This issue was entered into the licensees corrective action program as Condition Report CR-GGN-2012-04112. As a corrective action, the radiation protection manager coached the individual on the need for proper dosimetry devices in high radiation areas.

The entry into a high radiation area without all required radiation monitoring devices was a performance deficiency and was a violation of Technical Specification 5.7.1. 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. This violation had a cross-cutting aspect in the human performance area, associated with the work practices component, because the worker and crew members did not use human error prevention techniques, such as self and peer checking H.4(a) (Section 2RS1).

Green.

The inspectors reviewed a self-revealing, non-cited violation of 10 CFR 20.1501(a)for failure to survey, which resulted in a worker entering an unposted high radiation area.

This issue was entered into the licensees corrective action program as Condition Reports CR-GGN-2012-08436 and CR-GGN-2012-09225. As corrective actions, the licensee coached radiation protection personnel on exhibiting a questioning attitude, walked down all affected areas; verified correct postings were used, and surveyed for any other unanticipated dose rate alarms.

The failure to survey and determine radiation levels was a performance deficiency. The significance of 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 the failure exposed a pipefitter to higher than anticipated radiation dose rates. The inspectors used Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, dated August 19, 2008, to determine the significance of the violation. 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. This violation had a cross-cutting aspect in the human performance area, associated with the work control component, because licensee personnel failed to appropriately plan a work activity by not incorporating risk insights, job site conditions, including environmental conditions, which may impact human system interface and radiological safety, and the need for planned contingencies or compensatory actions, such as surveying and up-posting affected areas after a power ascension H.3(a)

(Section 2RS1).

PLANT STATUS

The Grand Gulf Nuclear Station began the inspection period at 100 percent power. On October 4, 2013, the operators commenced an unplanned shutdown due to the neutral bushing on main transformer A exhibiting high temperatures. The licensee determined the cause of the issue and returned to 100 percent power on October 20, 2013.

On November 1, 2013, the operators commenced an unplanned shutdown due to a hydraulic leak on the A flow control valve located inside the drywell. The licensee determined the cause of the issue and returned to 100 percent power on November 8, 2013.

On November 21, 2013, the operators reduced power to 45 percent due to high differential pressure across the circulating water filter screens. The licensee determined the cause of the issue and returned to 100 percent power on November 22, 2013.

On December 19, 2013, the operators reduced power to 78 percent for a control rod pattern adjustment and to take chemistry samples. The operators returned the plant to 100 percent power on December 20, 2013.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

Partial Walkdown

a. Inspection Scope

The inspectors performed partial system walk-downs of the following risk-significant systems:

• October 22, 2013, control room air conditioning/standby fresh air system A while control room air condition/standby fresh air system B was inoperable for maintenance

• November 20, 2013, standby diesel generator 11 while standby diesel generator 12 was inoperable for maintenance 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 trains were correctly aligned for the existing plant configuration.

These activities constituted two partial system walk-down samples, as defined in Inspection Procedure 71111.04.

b. Findings

No findings were identified.

1R05 Fire Protection

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 four plant areas important to safety:

• October 16, 2013, standby service water pump house B and associated valve room (2M110 and 2M112)

• October 16, 2013, standby service water pump house A and associated valve room (1M110 and 1M112)

• November 19, 2013, residual heat removal pump A room (1A103 and 1A203)

• December 2, 2013, diesel generator breezeway (1D301)

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 four quarterly inspection samples, as defined in Inspection Procedure 71111.05.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

On October 28, 2013, the inspectors completed an inspection of the stations ability to mitigate flooding due to internal causes. After reviewing the licensees flooding analysis, the inspectors chose three plant areas containing risk-significant structures, systems, and components that were susceptible to flooding:

• High pressure core spray pump room

• Low pressure core spray pump room

• Residual heat removal C pump room The inspectors reviewed plant design features and licensee procedures for coping with internal flooding. The inspectors walked down the selected areas to inspect the design features, including the material condition of seals, drains, and flood barriers. The inspectors evaluated whether operator actions credited for flood mitigation could be successfully accomplished.

These activities constitute completion of one flood protection measures sample, as defined in Inspection Procedure 71111.06.

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 October 17, 2013, the inspectors observed simulator training for an operating crew.

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 October 4, 2013, 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 plant shutdown as a result of the main transformer B neutral bushing overheating. The inspectors observed the operators performance of the following activities:

• They observed the pre-job brief for infrequently performed test and evolution prior to the plant shutdown due to the overheating condition on the main transformer A neutral bushing.

• They observed the operators inserting a manual scram from approximately 25 percent power, and they observed the control room supervisor entering the emergency operating procedures due to reactor water level decreasing below 11.4 inches.

• They observed the operators placing feedwater into startup level control and maintain reactor water level between 11.4 inches and 53.5 inches.

• They observed the operators controlling reactor pressure using bypass valves and main stream line drains between 800 to 1060 psig.

• They observed the operators shutdown balance of plant equipment such as condensate pumps, condensate booster pumps, heater drain pumps, and one of the reactor feedwater pump turbines. They also secured hydrogen cooling to the main generator and opened the main disconnects for the main generator.

• They observed the operators commencing a reactor cool-down after a high pressure walk-down of the drywell/containment was completed.

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.

.3 Biennial Inspection

a. Inspection Scope

The licensed operator requalification program involves two training cycles that are conducted over a 2-year period. In the first cycle, the annual cycle, the operators are administered an operating test consisting of job performance measures and simulator scenarios. In the second part of the training cycle, the biennial cycle, operators are administered an operating test and a comprehensive written examination. The examiners observed the associated training cycles during this inspection period.

To assess the performance effectiveness of the licensed operator requalification program, the inspectors conducted personnel interviews, reviewed both the operating tests and written examinations, and observed ongoing operating test activities.

The inspectors interviewed six licensee personnel from the training staff to determine their understanding of the policies and practices for administering requalification examinations. The inspectors also reviewed operator performance on the written examinations and operating tests. These reviews included observations of portions of the operating tests by the inspectors. The operating tests observed included five job performance measures and two scenarios that were used in the current biennial requalification cycle. These observations allowed the inspectors to assess the licensee's effectiveness in conducting the operating test to ensure operator mastery of the training program content. The inspectors also reviewed medical records of six licensed operators for conformance to license conditions and the licensees system for tracking qualifications and records of license reactivation for five operators.

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

The inspectors interviewed members of the training department and reviewed minutes of training review group meetings to assess the responsiveness of the licensed operator requalification program to incorporate the lessons learned from both plant and industry events. Examination results were also assessed to determine if they were consistent with the guidance contained in NUREG 1021, "Operator Licensing Examination Standards for Power Reactors", Revision 9, Supplement 1, and NRC Manual Chapter 0609, Appendix I, "Licensed Operator Requalification Significance Determination Process."

In addition to the above, the inspectors reviewed examination security measures, simulator fidelity, and existing logs of simulator deficiencies.

On September 27, 2013, the licensee informed the lead inspectors of the results of the written examinations and operating tests for the Licensed Operator Requalification Program. The inspectors compared these results to NRC Inspection Manual Chapter 0609, Appendix I, Licensed Operator Requalification Significance Determination Process, values and determined that there were no findings based on these results and because all of the individuals that failed the applicable portions of their examinations and/or operating tests were remediated, retested, and passed their retake examinations prior to returning to shift.

These activities constitute completion of one inspection sample of the biennial licensed operator requalification program, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed several instances of degraded performance of the below listed safety-related structures, systems, and components (SSCs):

• October 31, 2013, high pressure core spray (E22), excessive unavailability during scheduled maintenance outages

• November 18, 2013, plant air system (P51), due to several failures of the station air compressor, resulting in the system being placed in a(1) status and the sites recovery actions to restore the system to a(2) status 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 reviewed three risk assessments performed by the licensee prior to changes in plant configuration and the risk management actions taken by the licensee in response to elevated risk:

• From October 4 through October 13, 2013, during a plant shutdown that was required due to an overheated main transformer A neutral bushing, which resulted in the site entering yellow risk for decay heat removal and reactivity control during various times of the shutdown.

• From November 1 through November 4, 2013, during a plant shutdown that was required due to a leak on the hydraulic control unit for the A flow control valve, which resulted in the site entering yellow risk for decay heat removal and reactivity control during various times of the shutdown.

• From December 4 through December 9, 2013, during a division 3 allowed outage time that resulted in the site being in high yellow risk condition with the division 3 diesel generator being nonfunctional during the outage.

These activities constitute completion of three maintenance risk assessments 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 two operability determinations that the licensee performed for degraded or nonconforming structures, systems, or components (SSCs):

• October 29, 2013, operability determination of reactor core isolation coolant pump differential pressure out of tolerance, CR-GGN-2013-06197

• November 7, 2013, operability determination of control room air conditioning B freon leak, CR-GGN-2013-06718 The inspectors reviewed the timeliness and technical adequacy of the licensees evaluations. Where the licensee determined the degraded SSC to be operable, the inspectors verified that the licensees compensatory measures were appropriate to provide reasonable assurance of operability. The inspectors verified that the licensee had considered the effect of other degraded conditions on the operability of the degraded SSC.

These activities constitute completion of two operability and functionality review samples, as defined in Inspection Procedure 71111.15.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed four post-maintenance testing activities that affected risk-significant structures, systems, or components (SSCs):

• October 6, 2013, source range monitor E after maintenance

• December 4, 2013, standby service water C pump following maintenance

• December 5, 2013, high pressure core spray pump and valves following maintenance

• December 9, 2013, division 3 diesel generator following 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 four 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 forced outages that concluded on October 20, 2013, and November 8, 2013, 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

• Monitoring of heat-up and startup activities These activities constitute completion of one outage activities sample, as defined in Inspection Procedure 71111.20.

b. Findings

Introduction.

The inspectors identified a Green non-cited violation of Technical Specification 3.4.11 for the failure to comply with the Reactor Coolant System (RCS)

Pressure and Temperature Limits Report (PTLR) during plant cold startups. Specifically, on and before November 2, 2013, the licensee operated the plant with the reactor pressure vessel (RPV) below the minimum pressure value of zero psig, due to the main steam isolation valves being open while the mechanical vacuum pumps were running to draw a vacuum on the main condenser.

Description.

On November 12, 2013, the inspectors identified a concern that the licensee operated the plant in a manner that did not meet the PTLR for non-nuclear heat-up, as specified in Technical Specification 3.4.11. Specifically, the PTLR had a lower limit of zero psig, and the licensee operated the RPV below zero psig during the plant start-up that commenced on November 2, 2013. A review of plant data showed that the RPV reached -8.5 psig at its lowest pressure, with the RPV being below zero psig for approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. The licensee initiated Condition Report CR-GGN-2013-07021 to document the inspectors concern. The resulting engineering evaluation determined that the maximum compressive stress experienced by the RPV was 135.6 psi, which was much less than the maximum yield strength of 63,000 psi. The inspectors found that the plant configuration that resulted in the RPV being at a vacuum was allowed by Procedure 03-1-01-1, Cold Shutdown to Generator Carrying Minimum Load.

Specifically, this procedure allowed Attachment VIII, Reactor Startup/Hot Shutdown, and Attachment X, Establishing Condenser Vacuum, to be performed concurrently.

The inspectors also noted that the procedure recognized the possibility of the RPV coming under a vacuum because it provided precautions and limitations on operating with the RPV below zero psig. The inspectors performed a historical review of the procedure and determined that this had been a long standing practice by the licensee, in that the procedural step allowing the performance of Sections VIII and X concurrently had been in place since 1994.

Immediate corrective action included revising Procedure 03-1-01-1, Cold Shutdown to Generator Carrying Minimum Load, to ensure the RPV is pressurized prior to opening the main steam isolation valves (MSIVs) and providing training on the procedural changes to all the operating crews.

Analysis.

The inspectors determined that the failure to comply with the RCS Pressure and Temperature Limits Report specified in Technical Specification 3.4.11 was a performance deficiency. The performance deficiency was determined to be more than minor, and therefore a finding, because it was associated with the human performance attribute of the Barrier Integrity Cornerstone and had the potential to adversely affect the associated cornerstone objective of providing reasonable assurance that a physical design barrier (reactor coolant system) protects the public from radionuclide release caused by accidents or events. Specifically, without NRC review and approval of revised pressure and temperature limits that include operating the RPV below zero psig, the inspectors did not have reasonable assurance the RPV would not be adversely affected. Using NRC Inspection Manual Chapter 0609, Attachment 4, "Initial Characterization of Findings," June 19, 2012, the inspectors determined that the issue affected the Barrier Integrity Cornerstone. Using NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At-Power, June 19, 2012, Exhibit 3, the inspectors determined that since this finding involved the reactor coolant system boundary, a detailed risk evaluation was required. The Senior Risk Analyst reviewed the finding and determined that a detailed risk evaluation was not required. The licensee performed an engineering evaluation and concluded that there was no impact to the reactor vessel. As a result, the Senior Risk Analyst concluded that there was no change in risk due to the performance deficiency. The inspectors determined that since the procedural steps to perform Attachments VIII and X concurrently had been in place since 1994, this was a latent issue; therefore no cross-cutting aspect was assigned.

Enforcement.

Technical Specification 3.4.11 requires that RPV pressure and temperatures be maintained within the limits specified in the Pressure and Temperature Limits Report. Contrary to this requirement, on and before November 2, 2013, during plant start-up, the licensee did not maintain the RPV pressure and temperature within the limits specified in the PTLR. Specifically, the licensee operated the plant such that the pressure in the RPV was below the lower pressure limit of zero psig for approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. As an immediate corrective action, the licensee revised their start-up procedure to ensure the RPV is pressurized prior to opening the MSIVs.

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 Condition Report CR-GGN-2013-07021 to address recurrence. (NCV 05000416/2013005-01, Failure to Comply with Technical Specification 3.4.11)

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed three risk-significant surveillance tests and reviewed test results to verify that these tests adequately demonstrated that the structures, systems, and components (SSCs) were capable of performing their safety functions:

In-service tests:

• October 29, 2013, reactor core isolation coolant quarterly pump operability test Other surveillance tests:

• October 16, 2013, reactor coolant chemistry sample

• December 18, 2013, reactor core isolation coolant steam supply functional test 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 three surveillance testing inspection samples, as defined in Inspection Procedure 71111.22.

b. Findings

Introduction.

The inspectors reviewed a Green, self-revealing, non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the failure to provide an adequate procedure for a safety related activity. Specifically, the reactor core isolation cooling (RCIC) steam supply pressure low functional test procedure contained an error that resulted in the loss of primary containment isolation capability and the RCIC system being inoperable.

Description.

On December 17, 2013, while performing Surveillance Procedure 06-IC-1E31-Q-1016-02, RCIC Steam Supply Pressure Low Functional Test, Revision 111, the RCIC steam supply inboard isolation Valve E51-F063 closed, resulting in the RCIC system becoming inoperable. The surveillance was halted, and the RCIC system was restored to operable status within 20 minutes by re-opening Valve E51-F063. Furthermore, the containment isolation capability for RCIC was lost for approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. This was due to the surveillance procedure incorrectly directing operators to open the breaker to the steam line warm-up bypass Valve E51-F076 and erroneously opening the supply breaker for the RCIC steam supply outboard isolation Valve E51-F064 instead of opening the supply breaker for the steam supply inboard isolation Valve E51-F063. Having the breakers to Valves E51-F064 and E51-F076 in the open position rendered them inoperable and resulted in a loss of containment isolation capability. The licensee restored isolation capability by closing both supply breakers to the two isolation valves.

During their review of the surveillance procedure, the licensee determined that during the most recent revision on November 6, 2013, a copy/paste error was introduced into Step 5.10 of Attachment II. The hardware modification instructions directed the crew to open Breaker 52-153129 (Valve E51-F064), which is a division 1 valve. The instructions should have directed the crew to open Breaker 52-163134 (Valve E51-F063), which is a division 2 valve. Performance of the procedure as written caused a division 1 breaker to be opened while the division 2 surveillance was being performed.

The licensee entered this issue into the corrective action process under Condition Reports CR-GGN-2013-07720, CR-GGN-2013-07733, and CR-GGN-2013-07374. As an immediate corrective action, the licensee restored the breakers to Valves E51-F064 and E51-F076, regaining isolation capability, and reopened the RCIC inboard isolation Valve E51-F063, restoring RCIC to operable status.

Analysis.

The failure to have an adequate procedure for the reactor core isolation cooling steam supply pressure low functional test is a performance deficiency. The performance deficiency was determined to be more than minor and therefore a finding because it was associated with the procedure quality attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. This performance deficiency was also associated with the procedural quality attribute of the Barrier Integrity Cornerstone and adversely affected the cornerstones objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Using NRC Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, June 19, 2012, the inspectors determined the issue affected the Barrier Integrity Cornerstone. The inspectors used Inspection Manual Chapter 0609, Appendix H, Containment Integrity Significance Determination Process, May 6, 2004, and determined the finding was a type B finding at full power. Using Table 6.1, Phase 1 Screening-Type B Findings at Power, the inspectors concluded that since this issue involved containment isolation valves in a BWR Mark III containment, a Phase 2 analysis was necessary. Using Table 6.2, Phase 2 Risk Significance - Type B Findings at Full Power, the inspectors concluded that the risk significance was very low or Green because the exposure time was less than 3 days. Furthermore, the inspectors determined that this issue affected the Mitigating System Cornerstone. Using NRC Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At-Power, June 19, 2012, Exhibit 2, the inspectors determined that since the finding represented a loss of system and/or function, a detailed risk evaluation was required. The inspectors utilized the Grand Gulf Standardized Plant Analysis Risk model to determine the change in core damage frequency (CDF) due to the loss of safety function. The inspectors assigned the RCIC system a failure probability of 1.00 for a conservative duration of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The resulting change in CDF was 1.9E-9/year, thus the finding was of very low safety significance (Green). The Senior Risk Analyst reviewed the inspectors evaluation and verified the conclusions to be correct. The apparent cause of this finding was that the licensee failed to effectively utilize human error prevention techniques. Therefore, the finding had a cross-cutting aspect in the area of human performance, work practices because the licensee did not perform adequate self-and peer-checking while performing an activity affecting quality H.4(a).

Enforcement.

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, states, in part, activities affecting quality shall be prescribed by documented procedures, of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures. Contrary to the above, the licensee failed to assure that activities affecting quality were prescribed by documented procedures of a type appropriate to the circumstances. Specifically, Procedure 06-IC-1E31-Q-1016-02, RCIC Steam Supply Pressure Low Functional Test, Revision 111, contained a copy/paste error in Step 5.10 of Attachment II. On December 17, 2013, the procedural error resulted in the licensee inadvertently losing containment isolation capability and causing RCIC to become inoperable. As an immediate corrective action, the licensee restored RCIC to operable status and restored containment isolation capability. 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 Condition Reports CR-GGN-2013-07720, CR-GGN-2013-07733, and CR-GGN-2013-07374 to address recurrence. (NCV 05000416/2013005-02, Failure to Provide Adequate Procedures Results in Loss of Safety Function)

Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04)

a. Inspection Scope

The NSIR headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS accession number ML13326A978 as listed in the Attachment.

The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The NRC 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. 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.

1. Entry Into A High Radiation Area Without A Required Radiation Monitoring Device

Introduction.

The inspectors reviewed a self-revealing, Green, non-cited violation of Technical Specification 5.7.1, resulting from an individual entering a high radiation area without a required radiation monitoring device.

Description.

On March 21, 2012, an individual entered the drywell as part of a crew to install rigging beams for valve work. However, the individual had left his/her electronic alarming dosimeter on a bench in the dressing area. The crew did not have continuous coverage by a radiation protection technician. Subsequently, the crews supervisor checked on the crew and was alerted to a problem when he found the electronic alarming dosimeter where the crew member had left it. The supervisor contacted the crew and instructed the crew members to check to ensure they had their electronic alarming dosimeters. The crew member who had left the dosimeter exited the drywell.

Licensee representatives estimated the individual was in the drywell for approximately 20 minutes. The drywell was controlled as a high radiation area because it contained dose rates greater than 100 millirem per hour, according to the licensees radiation survey records. As corrective action, the radiation protection manager coached the individual on the need for proper dosimetry devices in high radiation areas. The licensee representative reviewed the circumstances and concluded the occurrence resulted from a lack of both self and peer checking to ensure all crew members had electronic alarming dosimeters.

Analysis.

The entry into a high radiation area without required radiation monitoring devices was a performance deficiency and was a violation of Technical Specification 5.7.1. 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. The violation was self-revealing because the licensee was alerted to the problem when the electronic alarming dosimeter was observed on the bench and not as a result of the licensee representatives deliberate and focused observation during the course of the activity. This violation had a cross-cutting aspect in the human performance area, associated with the work practices component, because the worker and crew members did not use human error prevention techniques, such as self and peer checking H.4(a).

Enforcement.

Technical Specification 5.7.1 requires, in part, that any individual permitted to enter a high radiation area, as defined in 10 CFR Part 20, shall be provided with or accompanied by one or more of the following:

a. A radiation monitoring device that continuously indicates the radiation dose rate in the area.

b. A radiation monitoring device that continuously integrates the radiation dose rate in the area and alarms when a preset integrated dose is received. Entry into such areas with this monitoring device may be made after the dose rate levels in the area have been established and personnel are aware of them.

c. An individual qualified in radiation protection procedures with a radiation dose rate monitoring device, who is responsible for providing positive control over the activities within the area and shall perform periodic radiation surveillance at the frequency specified by the radiation protection supervision in the radiation work permit (RWP).

Contrary to the above, on March 21, 2012, a licensee worker entered the drywell, a high radiation area, using none of the specified methods. Specifically, the individual had intended to use a radiation monitoring device that continuously indicated the radiation dose in the area and alarmed when a preset integrated dose was received. However, the individual left the device in the dressing area and entered the drywell. As corrective action, the radiation protection manager coached the individual on the need for proper dosimetry devices in high radiation areas. Because this violation was of very low safety significance and was entered into the licensees corrective action program as Condition Report CR-GGN-2012-04112, this violation was being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy.

(NCV 05000416/2013005-03, Entry Into A High Radiation Area Without A Required Radiation Monitoring Device)

2. Failure To Survey Resulting in Personnel Entry To A High Radiation Area

Introduction.

The inspectors reviewed a self-revealing, Green, non-cited violation of 10 CFR 20.1501(a) for failure to survey, which resulted in a worker entering an unposted high radiation area.

Description.

On June 20, 2012, a pipefitter received an unanticipated electronic alarming dosimeter dose rate alarm when he entered a high radiation area on the 166-foot elevation of the turbine bioshield while performing a walk down on the A sensing line area. The pipefitter was briefed by a radiation protection lead technician just prior to entering the turbine bioshield area using Survey GG-1206-0708. This survey showed a maximum general area dose rate of 40 millirem per hour at 30 cm.

The pipefitter entered the area using Task 1 of RWP 20121004, Maintenance Personnel - General Maintenance Activities and Support Work, Revision 02, which had a dose alarm setpoint of 10 millirem and a dose rate alarm setpoint of 100 millirem per hour. The RWP did not allow entry into a high radiation area, defined as an area with dose rates greater than 100 millirem per hour at 30 cm. The unanticipated dose rate alarm received by the pipefitter revealed that he had entered an area with dose rates of at least 117 millirem per hour.

As a follow-up to the dose rate alarm received, the licensee performed a survey in the area that the pipefitter entered and found the actual dose rates to be significantly higher than those briefed. Survey GG-1206-0712, dated June 20, 2012, showed the maximum general area dose rates were 140 millirem per hour at 30 cm from the source of the radiation. This confirmed the area should have been posted as a high radiation area instead of a radiation area. Radiation protection personnel promptly posted the 166-foot turbine bioshield area as a high radiation area.

When the inspectors asked why the dose rates were much higher than those anticipated and briefed to the pipefitter, they were told the radiological conditions changed, and the radiation protection lead technician failed to take appropriate actions following these changes and did not inform the pipefitter, as expected. The change in radiological conditions was a result of a change in reactor power. Specifically, shortly after the pipefitter entered the 166-foot elevation of the turbine building, operations personnel contacted the radiation protection lead technician and informed him that reactor power was increasing from 22 percent to 35 percent. The radiation protection lead technician assumed that this would not result in a significant change in radiological conditions. He inappropriately assumed the maximum general area dose rate would be directly proportional to increase in power or approximately 64 millirem per hour. However, this was not accurate for the power increase.

The radiation protection lead technician had not experienced plant power level changes in over two years, and thus, he did not adequately plan work activities to take proper actions and inform workers of changes in jobsite radiological conditions. The licensee determined that there was no written planning standard on when to up-post areas during power ascensions; although, there was an expectation that steam affected areas be up-posted to high radiation areas when recirculation pumps were shifted to fast speed, as during a power increase. Therefore, incorrect assumptions due to poor planning, a lack of a written planning standard, and a failure to stop work and re-survey affected areas after the power change resulted in a failure to post a high radiation area and exposed the pipefitter to higher than anticipated dose rates.

This occurrence was documented in Condition Reports CR-GGN-2012-08436 and CR-GGN-2012-09225. As immediate corrective actions, the licensee coached the radiation protection lead technician on exhibiting a questioning attitude, walked down all affected areas, verified correct postings were used, and surveyed for any other unanticipated dose rate alarms. Longer term corrective actions included the development of a written standard for actions to be taken when operations personnel notify radiation protection personnel of plant status changes and for up-posting steam affected areas and neutron areas of the plant during power ascension.

Analysis.

The failure to survey and determine radiation levels was a performance deficiency. The significance of 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 the failure exposed a pipefitter to higher than anticipated radiation dose rates. The inspectors used Manual Chapter 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, dated August 19, 2008, to determine the significance of the violation. The violation had very low safety significance because:

(1) it was not an as low as is reasonably achievable 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. The violation was self-revealing because the licensee was alerted to the problem when the pipefitter received an electronic alarming dosimeter dose rate alarm and not as a result of the licensee representatives deliberate and focused observations during the course of the activity. The violation has a cross-cutting aspect in the human performance area, associated with the work control component, because licensee personnel failed to appropriately plan a work activity by not incorporating risk insights, job site conditions, including environmental conditions which may impact human system interface and radiological safety, and the need for planned contingencies or compensatory actions, such as surveying and up posting affected areas after a power ascension H.3(a).

Enforcement.

Title 10 CFR 20.1501(a) requires, in part, that each licensee make or cause to be made surveys that may be necessary for the licensee to comply with the regulations in 10 CFR Part 20 and that are reasonable under the circumstances to evaluate the extent of radiation levels, and the potential radiological hazards that could be present. Pursuant to 10 CFR 20.1003, a survey means an evaluation of the radiological conditions and potential hazards incident to the production, use, transfer, release, disposal, or presence of radioactive material or other sources of radiation.

Contrary to the above, on June 20, 2012, the licensee failed to make or cause to be made surveys that were necessary for the licensee to comply with 10 CFR 20.1902(b),which specifies requirements for posting high radiation areas. Specifically, licensee representatives did not survey to evaluate radiation levels on the 166-foot elevation of the turbine building when reactor power ascended. As a result, a pipefitter entered an unposted high radiation area and was exposed to higher than anticipated general area dose rates. As corrective actions, the licensee coached radiation protection personnel on exhibiting a questioning attitude, walked down all affected areas, verified correct postings were used, and investigated for any other unanticipated dose rate alarms. Because this violation was of very low safety significance and was entered into the licensees corrective action program as Condition Reports CR-GGN-2012-08436 and CR-GGN-2012-09225, it was treated as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000416/2013005-04, Failure to Survey Resulting in Personnel Entry to a High Radiation Area)

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

The inspectors assessed licensee performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). During the inspection, the inspectors interviewed licensee personnel and reviewed licensee performance in the following areas:

• Site-specific ALARA procedures and collective exposure history, including the current 3-year rolling average, site-specific trends in collective exposures, and source-term measurements

• ALARA work activity evaluations/post/job reviews, exposure estimates, and exposure mitigation requirements

• The methodology for estimating work activity exposures, the intended dose outcome, the accuracy of dose rate and man-hour estimates, and intended versus actual work activity doses and the reasons for any inconsistencies

• Records detailing the historical trends and current status of tracked plant source terms and contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry

• Radiation worker and radiation protection technician performance during work activities in radiation areas, airborne radioactivity areas, or high radiation areas

• Audits, self-assessments, and corrective action documents related to ALARA planning and controls since the last inspection These activities constitute completion of one sample of occupational ALARA planning and controls, as defined in Inspection Procedure 71124.02.

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 Mitigating System Performance Index: Emergency AC Power Systems (MS06), High

Pressure Injection System (MS07), Heat Removal System (MS08), Residual Heat Removal Systems (MS09), and Cooling Water Systems (MS10)

a. Inspection Scope

The inspectors reviewed the licensees mitigating system performance index data for the period of October 2012 through September 2013 to verify the accuracy and completeness of the reported data. The inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, to determine the accuracy of the reported data.

These activities constitute verification of five mitigating system performance indicators:

emergency ac power systems, high pressure injection system, heat removal system, residual heat removal systems and cooling water systems, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.2 Occupational Exposure Control Effectiveness (OR01)

a. Inspection Scope

The inspectors reviewed corrective action program records for unplanned exposures or losses of radiological control over locked high radiation areas and very high radiation areas during the period of January 1, 2012, to September 30, 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 6, 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.

.3 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 January 1, 2012, and September 30, 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 6, 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 Semiannual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees 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 4OA2.1, above, licensee trending efforts, and licensee human performance results. The inspectors nominally considered the 6-month period of June 17, 2013, through December 17, 2013, although some examples expanded beyond those dates where the scope of the trend warranted.

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 focused their inspection on Condition Report CR-GGN-2013-05794 because it documented an apparent cause evaluation (ACE) the licensee performed to evaluate the cause of the reactor protection system (RPS) B motor-generator set (MG Set) output breaker trip. The trip of the output breaker resulted in an unintended half scram and half isolation due to the loss of the RPS Bus B. The ACE determined that the cause of the output breaker trip was an overcurrent condition that occurred when the RPS MG Set motor shorted to ground. The inspectors found that the licensee had developed a corrective action plan to address the issue.

These activities constitute completion of one semiannual trend review sample, as defined in Inspection Procedure 71152.

b. Findings

No findings were identified.

.3 Annual Follow-up of Selected Issues

a. Inspection Scope

The inspectors selected two issues for an in-depth follow-up:

• On October 16, 2013, the inspector reviewed Condition Report CR-GGN-2013-06422, which addressed the condition that the plant was operating with an offgas inleakage that was much higher than the design value described in the final safety analysis report as updated.

The inspectors performed a detailed historical review of the offgas system and determined that although elevated offgas inleakage has been a long-standing issue, the licensees corrective actions were appropriate in that the necessary assessments and evaluations were performed to verify that operating with elevated offgas inleakage did not result in offgas release exceeding any limits set forth in 10 CFR Part 50, Appendix I, 10 CFR Part 20, plant technical specifications, and the offsite dose calculation manual. Furthermore, the inspectors verified the licensee performed appropriate 10 CFR 50.59 screens and determined that operating with elevated offgas inleakage did not require commission approval.

The inspectors assessed the licensees problem identification threshold, cause analyses, extent of condition reviews, and compensatory actions. The inspectors verified that the licensee appropriately prioritized the planned corrective actions and that these actions were adequate to correct the condition.

• On December 3, 2013, the inspectors conducted an in-depth review of operator workarounds. The inspectors evaluated the licensees implementation of their process used to identify, document, track, and resolve operational challenges.

Inspection activities included, but were not limited to, a review of the cumulative effects of the operator workarounds, operator burdens, control deficiencies, control room alarms, and long-standing danger and caution tags on system availability. They also evaluated the potential for improper operation of the system, for negative impacts on multiple systems, and for negative impact on the operators ability to respond to plant transients or accidents. The documents listed in the attachment were reviewed to accomplish the objectives of the inspection procedure. The inspectors reviewed current operational challenge records to determine whether the licensee was identifying operator challenges at an appropriate threshold, was entering them into their corrective action program, and was proposing or implementing appropriate and timely corrective actions.

Reviews were conducted to determine if any operator challenge could increase the possibility of an initiating event, if the challenge was contrary to training, required a change from long-standing operational practices, or if it created the potential for inappropriate compensatory actions. Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified operator workarounds.

These activities constitute completion of two annual follow-up samples, which included one operator work-around sample, as defined in Inspection Procedure 71152.

b. Findings

No findings were identified.

4OA3 Follow-up of Events and Notices of Enforcement Discretion

Plant Downpower to 45 Percent due to Foreign Material Fouling of the Circulating Pump A Suction

a. Inspection Scope

On November 21, 2013, at approximately 2:47 p.m., the plant down powered to approximately 45 percent rated thermal power due to the circulating water pump A exhibiting high differential pressure on the suction screen and increased vibration readings. The licensee elected to remove the pump from service after an inability to withdraw the suction screens for the pump due to the high differential pressure. After securing the pump, the licensee withdrew the screens and sent divers into the suction basin to exam the pump impeller for damage, no damage was found. They attributed the increased fouling to high winds in the area blowing leaves into the cooling tower basin. They cleaned the screens and returned to full power operation the next day.

Inspectors responded to the control room and observed the licensee perform downpower activities. The licensee placed compensatory actions in place to monitor circulating water differential pressure for both pumps and to perform cleaning activities if differential pressure reached two inches water pressure. The long term corrective actions are being evaluated by the licensee. Specific documents reviewed during this event follow-up are listed in the attachment.

These activities constitute completion of one event follow-up, as defined in Inspection Procedure 71153-05.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

The inspectors debriefed Mr. K. Mulligan, Site Vice President of Operations, and other members of the licensee staff of the results of the licensed operator requalification program inspection on August 22, 2013. The results of the inspection were telephonically exited with Mr. J. Giles, Training Manager, and other members of the licensee staff on October 9, 2013. The licensee representatives acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.

No proprietary information was identified.

On October 24, 2013, the inspectors presented the radiation safety inspection results to Mr. J. Miller, General Manager Plant 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 January 16, 2014, the inspectors presented the inspection results to, Mr. K. Mulligan, Site Vice President of 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

C. Beschett, Manager, Nuclear Oversight

M. Bacon, Superintendent, Simulator and Training Support

R. Benson, Radiological Supervisor, Radiation Protection

C. Brooks, Specialist, Licensing

R. Collins, Superintendent, Operations Training (Requalification Program)

J. Dorsey, Security Manager

H. Farris, Assistant Operations Manager

J. Gerard, Manager, Operations

J. Giles, Training Manager

J. Miller, General Manager Plant Operations

R. Miller, Manager, Radiation Protection

K. Mulligan, Site Vice President

M. Rasch, Superintendent, Operations Training (Initial Licensing)

F. Rosser, Supervisor, Radiation Protection

J. Seiter, Acting Manager, Licensing

R. Sylvan, Supervisor, Radiation Protection

T. Thornton, Manager, Design Engineering

S. Ward, Senior Licensing Specialist

D. Wiles, Director, Engineering

E. G. Wright, Supervisor, Radiation Protection

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000416-005-01 NCV Failure to comply with Technical Specification 3.4.11 (Section 1R20)

05000416-005-02 NCV Failure to Provide Adequate Procedures Results in Loss of Safety Function (Section 1R22)

05000416-005-03 NCV Entry Into A High Radiation Area Without A Required Radiation Monitoring Device (Section 2RS1)

05000416-005-04 NCV Failure To Survey Resulting in Personnel Entry To A High Radiation Area (Section 2RS1)

Attachment 1