IR 05000352/2015001

NRC Integrated Inspection Report 05000352/2015001 and 05000353/2015001 (January 1 - March 31, 2015)

ML15133A242
Person / Time
Site:	Limerick
Issue date:	05/14/2015
From:	Fred Bower Reactor Projects Region 1 Branch 4
To:	Bryan Hanson Exelon Generation Co, Exelon Nuclear
BOWER, FL
References
05000352/2015001; 05000353/2015001 IR 2015001
Download: ML15133A242 (35)

Text

May 14, 2015

SUBJECT:

Limerick Generating Station - NRC INTEGRATED INSPECTION REPORT 05000352/2015001 AND 05000353/2015001

Dear Mr. Hanson:

On March 31, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Limerick Generating Station, Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on April 10, 2015, with Mr. D. Lewis, Plant Manager, and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

This report documents two NRC-identified violations of NRC requirements, both of which were of very low safety significance (Green). However, because of the very low safety significance, and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations, consistent with Section 2.3.2.a of the NRC Enforcement Policy.

If you contest any non-cited violations in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Limerick Generating Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding 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 I, and the NRC Resident Inspector at Limerick Generating Station.

B.Hanson 2 In accordance with Title 10 of the Code of Federal Regulations (CFR) 2.390 of the NRCs Rules of Practice, 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 component of the NRCs Agencywide Documents Access Management System (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Fred L. Bower III, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos. 50-352, 50-353 License Nos. NPF-39, NPF-85

Enclosure:

Inspection Report 05000352/2015001 and 05000353/2015001 w/Attachment: Supplementary Information

REGION I==

Docket Nos.: 50-352, 50-353 License Nos.: NPF-39, NPF-85 Report No.: 05000352/2015001 and 05000353/2015001 Licensee: Exelon Generation Company, LLC Facility: Limerick Generating Station (LGS), Units 1 & 2 Location: Sanatoga, PA Dates: January 1, 2015 through March 31, 2015 Inspectors: S. Rutenkroger, PhD, Senior Resident Inspector G. DiPaolo, Senior Resident Inspector R. Montgomery, Resident Inspector R. Nimitz, Senior Health Physicist E. Burket, Emergency Preparedness Inspector M. Fannon, Project Engineer B. Lin, Project Engineer A. Turilin, Project Engineer Approved By: Fred L. Bower III, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY

IR 05000352/2015001, 05000353/2015001; 01/01/2015 - 03/31/2015; Limerick Generating

Station (LGS) Units 1 and 2; Operability Determinations and Functionality Assessments and Refueling and Other Outage Activities.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified two findings of very low safety significance (Green), which were non-cited violations (NCVs). The significance of most findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process, dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Aspects Within The Cross-Cutting Areas, dated December 4, 2014. All violations of Nuclear Regulatory commission (NRC) requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated February 4, 2015. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,

Revision 5, dated February 2014.

Cornerstone: Mitigating Systems

Green.

The inspectors identified an NCV of LGS Units 1 and 2 operating license condition 2.C(3), Fire Protection, because Exelon did not implement and maintain in effect all provisions of the NRC approved fire protection program. Specifically, Exelon did not implement and maintain a maintenance program to ensure the operability of the fire safe shutdown diesel (FSSD) generator by not ensuring a fuel oil supply specified or protected for typical winter cold temperatures. Exelons corrective actions included adding a fuel oil additive (modifiers which inhibit wax crystal growth) to improve low temperature flow and pour characteristics at a time when ambient temperatures were greater than the cloud point and initiating condition report IR 2463216.

This finding is more than minor because it adversely affected the protection against external factors (fire) attribute of the mitigating systems cornerstone to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the failure to ensure the cloud point of the diesel fuel oil was below the temperature of the surrounding air would impact the reliable operation of the equipment during low temperature conditions. Using IMC 0609, Appendix F, Fire Protection Significance Determination Process, the inspectors determined that this finding was of very low safety significance (Green) because the finding did not impact the ability of LGS Units 1 and 2 to achieve safe shutdown. Specifically, the cloud point of diesel fuel delivered onsite by the vendor was substantially lower than Exelons specification, unavailability of the FSSD generator would not by itself prevent LGS from reaching and maintaining safe shutdown, and the need for powered ventilation given a loss of normal HVAC during cold weather would be less than during hot weather. The inspectors determined that this finding has a cross-cutting aspect in the area of Human Performance, Resources, because Exelon did not ensure that cold weather preparedness procedures were adequate to support nuclear safety. Specifically, Exelon relied upon the cold weather procedures to establish reliable equipment operation during cold temperatures, but the procedures did not address diesel fuel cloud point for equipment stored and/or operated outdoors [H.1]. (Section 1R15)

Green.

The inspectors identified an NCV of Title 10 of the Code of Federal Regulations (10 CFR), Appendix B, Criterion V, Instructions, Procedures, and Drawings, because Exelon prescribed a procedure affecting quality with instructions which were not appropriate to the circumstances. Specifically, procedure GP-2, Normal Plant Startup, contained a note that stated high pressure coolant injection (HPCI) systems have been determined operable by engineering evaluation with a high level trip setpoint actuated. The inspectors determined that the note was inconsistent with Units 1 and 2 technical specifications (TS)and was not supported by an adequate engineering basis. Exelons corrective actions included briefing staff to ensure HPCI system operability is appropriately assessed when implementing GP-2, initiating condition report IR 2464416, completing a procedure revision to reference an interim evaluation contained in the condition report, and initiating an action to complete an engineering evaluation.

This finding is more than minor because it is associated with the procedure quality attribute of the mitigating systems cornerstone and affected the objective to ensure the capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, procedure GP-2 stated that the HPCI system was operable with a Level 8 trip present without the ability to automatically actuate upon a high drywell pressure without an engineering evaluation which was inconsistent with the existing safety analysis performed at normal operating reactor pressure and temperature. Using IMC 0609,

Significance Determination Process, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that this finding was of very low safety significance (Green) because the finding did not represent an actual loss of the HPCI system or function to inject high pressure emergency core cooling water. Specifically, the note in GP-2 allowed considering the HPCI system operable at normal operating reactor pressures with the HPCI system tripped. However, the HPCI system was not tripped at normal operating reactor pressures.

The inspectors determined that the finding did not have cross-cutting aspect because the procedure development performance deficiency did not occur within the last three years, and the inspectors did not conclude that the causal factors represented present Exelon performance. (Section 1R20)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent power. On January 9, 2015, operators reduced power to 77 percent for control rod scram time testing and pattern adjustment.

Operators returned the unit to 100 percent power the following day. On February 23, 2015, the unit scrammed automatically on a valid high reactor pressure signal caused by an inadvertent closure of the 1C inboard main steam isolation valve. Following repairs, operators returned the unit to 100 percent power on February 27. The unit remained at or near 100 percent power for the remainder of the inspection period.

Unit 2 began the inspection period at 100 percent power. Unit 2 power began coasting down as it approached the end of the operating cycle beginning January 8, 2015. The unit remained at or near its maximum achievable power for the remainder of the inspection period, reaching approximately 83 percent power by March 31,

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors reviewed Exelons preparations in advance of and during a winter storm warning issued by the National Weather Service for Montgomery County, Pennsylvania for January 26, 2015. The inspectors reviewed the implementation of adverse weather preparation procedures before the onset of and during this adverse weather condition.

The inspectors performed walkdowns of equipment that could be effected by high winds including the main transformer areas and the emergency diesel generators (EDGs) to verify that potential missile objects were secure. The inspectors verified that operator actions defined in Exelons adverse weather procedure maintained the readiness of essential systems.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

B Standby gas treatment system (SGTS) when A SGTS was out-of-service for planned maintenance on January 21, 2015 A reactor enclosure recirculation system (RERS) when B RERS was out of service for planned maintenance on February 9, 2015 Spray pond pump house alignment for A and C residual heat removal service water (RHRSW)/emergency service water (ESW) pumps on February 11, 2015 Spray pond pump house alignment for B and D RHRSW/ESW pumps on February 11, 2015 The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the updated final safety analysis report (UFSAR), TS, work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. The inspectors also reviewed whether LGS staff had properly identified equipment issues and entered them into the corrective action program for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

.2 Full System Walkdown

a. Inspection Scope

On February 12, 2015, the inspectors performed a complete system walkdown of accessible portions of the high pressure coolant injection system to verify the existing equipment lineup was correct. The inspectors reviewed operating procedures, surveillance tests, drawings, equipment line-up check-off lists, and the UFSAR to verify the system was aligned to perform its required safety functions. The inspectors also reviewed electrical power availability, component lubrication and equipment cooling, hanger and support functionality, and operability of support systems. The inspectors performed field walkdowns of accessible portions of the system to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. Additionally, the inspectors reviewed a sample of related condition reports and work orders to ensure Exelon appropriately evaluated and resolved any deficiencies.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Resident Inspector Quarterly Walkdowns

a. Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that Exelon controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out of service, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.

Fire area 121, radwaste building common centrifuge, solid radwaste equipment, ventilation filter compartments and supply and exhaust fan areas, rooms 469-471, 514-517 and 526 (Elevation 237 and 257) on January 12, 2015 Fire area 86, D24 EDG and fuel oil - lube oil tank room, rooms 215D and 316D on January 13, 2015 Fire Area 122/123 spray pond pump structure (eastern half/western half) on January 21, 2015 Fire area 82, D14 EDG and fuel oil - lube oil tank room, rooms 311D and 312D on February 4, 2015 Fire area 54, Unit 2, A and C residual heat removal (RHR) heat exchanger and pump rooms, rooms 173 and 280 on March 13, 2015

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on March 9, 2015, which included a group VIIA containment isolation signal (isolation of primary containment instrument gas process lines), loss of both control rod drive pumps, an anticipated transient without scram, and a trip of the main turbine generator. The inspectors evaluated operator performance during the simulated event and verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classifications made by the shift manager and the TS action statements entered by the shift technical advisor. Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed and reviewed planned downpowers on Unit 2 on January 15 and 21, 2015, for removal of the 6A and 6C feedwater heaters, respectively, for final feedwater temperature reductions for end-of-cycle coastdown operation. The inspectors observed evolution briefings, pre-shift briefings, and reactivity control briefings to verify that the briefings met the criteria specified in Exelons procedures. Additionally, the inspectors observed operational performance in the main control room to verify that procedure use, crew communications, and coordination of activities between work groups similarly met established expectations and standards.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the FSSD generator to assess the effectiveness of maintenance activities on structure, system, and component (SSC) performance and reliability. The inspectors reviewed system health reports, corrective action program documents, maintenance work orders, and maintenance rule basis documents to ensure that LGS was identifying and properly evaluating performance problems within the scope of the maintenance rule. For each sample selected, the inspectors verified that the SSC was properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and verified that the (a)(2) performance criteria established by LGS staff was reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2). Additionally, the inspectors ensured that LGS staff was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that LGS performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that LGS personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When LGS performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk.

The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the stations probabilistic risk analyst to verify plant conditions were consistent with the risk assessment. The inspectors also reviewed the TS requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

Units 1 and 2 A ESW and A RHRSW loops planned maintenance hot tap activities on January 28, 2015 Units 1 and 2 B loop RHRSW and B/D RHRSW pumps planned maintenance on Unit 2 ESW/RHRSW pipe drain on January 24, 2015 Unit 2 A loop ESW return line planned maintenance on February 21, 2015 Unit 2 A RHR unit cooler planned maintenance on March 3, 2015 Unit 2 A loop ESW return line planned maintenance on March 7, 2015 Units 1 and 2 unavailability of auxiliary bus 10 for safeguard transformer 101 automatic voltage controller replacement and Unit 1 reactor core isolation cooling valve testing on March 23, 2015 Unit 1 HPCI system testing on March 20, 2015

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:

IR 2432584, main steam isolation valve low pressure isolation setpoint change due to resolving General Electric Part 21 Report 2005-13-00, Potential to Exceed Low Pressure Technical Specification Safety Limit, on January 28, 2015 IR 2443981, EDG D22 lube oil makeup tank less than two thirds full on January 29, 2015 IR 2451774, Erratic position indication for intermediate stop valve 1 during testing on February 12, 2015 IR 2463216, Adequacy of diesel fuel oil storage and cloudpoint associated with onsite safety equipment on February 19, 2015 IR 2461141, Unit 2 automatic depressurization system (ADS) bottle A-2 pressure decreasing about 100 psig per day on March 1, 2015 IR 2445477, A SGTS failed surveillance test due to differential pressure indicator indicating higher then allowed value in TS on March 11, 2015 IR 2452765, A SGTS heater not working on March 11, 2015 The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations to assess whether technical specification operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and UFSAR to LGS evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled by LGS.

The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

Introduction.

The inspectors identified a Green NCV of LGS Units 1 and 2 operating license condition 2.C(3), Fire Protection, because Exelon did not implement and maintain in effect all provisions of the NRC approved fire protection program.

Specifically, Exelon did not implement and maintain a maintenance program to ensure the operability of the FSSD generator by not ensuring a fuel oil supply was specified or was protected for typical winter cold temperatures.

Description.

Following a review of LGS cold weather preparations on February 19, 2015, the inspectors reviewed diesel-powered equipment maintained onsite. The inspectors questioned the fuel oil procurement specifications and storage methods for diesel driven equipment intended for outdoor use. In particular, Exelon stores the FSSD generator outside without fuel tank heating.

The inspectors reviewed outdoor temperatures during the winter and noted that recorded daily temperatures ranged as low as -1 to 13 degrees Fahrenheit (ºF) for daily lows and highs, respectively. Following additional questions from the inspectors, on March 3, 2015, Exelon determined that the fuel oil specification for purchasing all fuel oil onsite specified a cloud point temperature of 17.6 ºF. Cloud point is of importance in that it defines the temperature at which a cloud or haze of wax crystals appears in the oil under prescribed test conditions which generally relates to the temperature at which wax crystals begin to precipitate from the oil in use. The inspectors noted that ASTM D975-15, Standard Specification for Diesel Fuel Oils, states that cloud point (or wax appearance point) is a fair indication of the low temperature operability limit of fuels without cold flow additives in most vehicles and cloud point came closest to a fail-safe predictor of vehicle performance for all vehicles (similar guidance included as early as ASTM D975-98b).

In addition, ASTM D975-78 recommended season and region-specific cloud point data be used to estimate the temperature to be used in specifying low temperature operability requirements. Finally, the LGS UFSAR incorporated a commitment to Regulatory Guide 1.137, 1979, paragraph C.2, with the exception of fuel oil surveillance test requirements.

Regulatory Guide 1.137, 1979, paragraph C.2., states, in part, that the cloud point should be less than or equal to the 3-hour minimum soak temperature or the minimum temperature at which the fuel oil will be maintained during the period of time that it will be stored.

The inspectors reviewed Exelons procedures for fuel oil specifications, maintenance of the FSSD generator, and cold weather preparations, and noted that the fuel oil cloud point was specified at 17.6 ºF, the FSSD generator fuel oil was not prepared or maintained for temperatures below 17.6 ºF, no manufacturer-specific information was available to support operability with ambient temperatures below the cloud point, and cold weather preparations did not consider cold temperature effects on the diesel fuel oil stored onsite. The FSSD generator is provided to power portable ventilation fans used for smoke removal and indoor temperature control in the control room, remote shutdown panel room, and auxiliary equipment room following fires which could impact normal ventilation systems. The portable ventilation fans and FSSD generator enable LGS to reach and maintain fire safe cold shutdown conditions assuming ventilation failures due to fire damage. However, the unavailability of the FSSD generator would not by itself prevent LGS from reaching and maintaining safe shutdown.

Exelons corrective actions included adding a fuel oil additive to improve low temperature flow and pour characteristics at a time when ambient temperatures were greater than the cloud point (modifiers which inhibit wax crystal growth) and initiating condition report IR

===2463216.

Analysis.

The inspectors determined that the failure to implement and maintain a maintenance program to ensure the operability of the FSSD generator by not ensuring a fuel oil supply specified or protected for typical winter cold temperatures was reasonably within Exelons ability to foresee and correct and should have been prevented and therefore was a performance deficiency. This finding is more than minor because it adversely affected the protection against external factors (fire) attribute of the mitigating systems cornerstone to ensure the reliability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the failure to ensure the cloud point of the diesel fuel oil was below the temperature of the surrounding air would impact the reliable operation of the equipment during low temperature conditions.

Using IMC 0609, Appendix F, Fire Protection Significance Determination Process, the inspectors determined that this finding was of very low safety significance (Green)because the finding did not impact the ability of LGS Units 1 and 2 to achieve safe shutdown. Specifically, the cloud point of diesel fuel delivered onsite by the vendor was substantially lower than Exelons specification, unavailability of the FSSD generator would not by itself prevent LGS from reaching and maintaining safe shutdown, and the need for powered ventilation given a loss of normal ventilation during cold weather would be less than during hot weather.

The inspectors determined that this finding has a cross-cutting aspect in the area of Human Performance, Resources, because Exelon did not ensure that cold weather preparedness procedures were adequate to support nuclear safety. Specifically, Exelon relied upon the cold weather procedures to establish reliable equipment operation during cold temperatures, but the procedures did not address diesel fuel cloud point for equipment stored and/or operated outdoors. [H.1]

Enforcement.

License condition 2.C.(3) requires, in part, that Exelon shall implement and maintain in effect all provisions of the approved fire protection program. A provision of the approved fire protection program is a dedicated (fire safe shutdown) diesel generator stored onsite with operability ensured by a surveillance and maintenance program. Contrary to the above, prior to March 6, 2015, the operability of the FSSD generator was not ensured by a surveillance and maintenance program by not ensuring a fuel oil supply specified or protected for typical winter cold temperatures. Exelons corrective actions to restore compliance included adding a fuel oil additive (modifiers which inhibit wax crystal growth) to improve low temperature flow and pour characteristics at a time when ambient temperatures were already greater than the cloud point. Because this violation was of very low safety significance (Green) and Exelon entered this issue into their corrective action program (IR 2463216), this violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy.

(NCV 05000352;05000353/2015001-01, Fire Safe Shutdown Diesel Generator Maintenance Program Did Not Account for Cold Temperatures due to Inadequate Specification for Fuel Oil Cloud Point)

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance tests for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure was consistent with the information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.

C0255483, replacement of EDG D22 starting air solenoid on January 5, 2015 M1985072, Troubleshooting and repair of EDG D24 lube oil keep warm heater on January 16, 2015 C0255438, Replacement of EDG D14 cylinder liners on January 30, 2015 C0256330, Troubleshooting and repair of EDG D13 governor speed control knob on February 9, 2015 M1989642, Replacement of sheared copper tubing associated with EDG D11 IA2 air start system on February 22, 2015 C0256611, Troubleshooting and repair of C inboard main steam isolation valve primary containment instrument gas line tubing failure on February 24, 2015 M1992597, Troubleshooting and replacement of Unit 2 2A primary containment instrument gas purge solenoid valve on March 24, 2015

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

Unit 1 Forced Outage

a. Inspection Scope

The inspectors reviewed the stations work activity and outage risk evaluation for the Unit 1 forced outage, which was conducted February 23 through February 27, 2015. The inspectors reviewed LGS development and implementation of emergent outage plans and schedules to verify that risk, industry experience, previous site-specific problems, and defense-in-depth were considered. During the outage, the inspectors observed portions of the post-trip recovery and review and monitored controls associated with the following outage activities:

Configuration management, including maintenance of defense-in-depth and compliance with the applicable TS when taking equipment out of service Implementation of clearance activities and confirmation that tags were properly hung and that equipment was appropriately configured to safely support the associated work or testing Configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication and instrument error accounting Status and configuration of electrical systems and switchyard activities to ensure that TS were met Monitoring of decay heat removal operations Activities that could affect reactivity Maintenance of secondary containment as required by TS Tracking of startup prerequisites and startup and ascension to full power operation Identification and resolution of problems related to outage activities

b. Findings

(1)

Introduction.

The inspectors identified a Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, because Exelon prescribed a procedure affecting quality with instructions which were inadequate and not appropriate to the circumstances. Specifically, procedure GP-2, Normal Plant Startup, contained a note that stated HPCI systems have been determined operable by engineering evaluation with a high level trip setpoint actuated. The inspectors determined that the note was inconsistent with Units 1 and 2 TS and was not supported by an adequate engineering basis.

Description.

On February 23, 2015, LGS Unit 1 automatically shut down and remained in the hot shutdown operational condition (i.e. mode 3) for equipment repair and restart.

Based on a lit overhead annunciator and indicating light in the main control room, the inspectors noted that the HPCI high reactor water level trip (Level 8, trip setpoint 54 inches) was actuated with normal reactor water level being maintained using the reactor water level narrow range instruments (35 inches). This annunciator provided indication that HPCI was potentially inoperable.

The inspectors noted that Exelon had been tracking the HPCI system as operable. The inspectors questioned the ability of the high drywell pressure instruments to fulfill the function required by TS to actuate the HPCI system with the high water level trip actuated. Technical specification 3.3.3 requires that the emergency core cooling system actuation channels shown in Table 3.3.3-1 be operable. Table 3.3.3-1, trip function 3.b, drywell pressure - high, requires four operable channels during operating modes 1, 2, and 3 (Power Operation, Startup, and Hot Shutdown) when reactor pressure is greater than 200 psig. With more than one channel inoperable, the HPCI system must be declared inoperable.

With a Level 8 trip present, the logic circuitry prevents actuation of the HPCI system by tripping its urbine stop valve closed. In addition, to prevent undue cycling of the HPCI system, when the reactor water level drops below the Level 8 trip signal setpoint, a seal-in circuit prevents actuation of the HPCI system until the Level 8 trip relays are reset, either by a manual reset pushbutton or when reactor water level drops to the reactor vessel water level low-low (Level 2, actuation setpoint -38 inches) actuation setpoint.

The operators did not declare HPCI inoperable because procedure GP-2, Normal Plant Startup, contained a note that stated HPCI systems have been determined operable by engineering evaluation with a high level trip setpoint actuated. Exelon determined that the note was added to Revision 56 of GP-2, approved on December 18, 1995.

However, Exelon was unable to find the referenced engineering evaluation that justified this conclusion.

The inspectors determined that at normal operating reactor pressure the TS required the high drywell pressure channels be declared inoperable when the channels were incapable of automatically actuating the HPCI system and the procedural note was not supported by an associated evaluation. Therefore, the lack of an adequate evaluation supporting the procedural note represented a performance deficiency and violation of regulatory requirements. However, in consultation with staff from the Technical Specifications and Reactor Systems Branches in the NRC Office of Nuclear Reactor Regulation, the inspectors determined that Exelons conclusion that the operability and safety function of the HPCI system was maintained at lower reactor pressures with the Level 8 trip actuated required further information in order to determine if that issue of concern was a performance deficiency and violation (Unresolved Item (URI)05000352,05000353/2015001-03).

Exelons corrective actions included briefing staff to ensure HPCI system operability was appropriately assessed when implementing GP-2, initiating condition report IR 2464416, completing a procedure revision to reference an interim evaluation contained in the condition report, and initiating an action to complete an engineering evaluation.

Analysis.

The inspectors determined that the failure to properly prescribe a procedure (GP-2) affecting quality with instructions appropriate to the circumstances was reasonably within Exelons ability to foresee and correct and should have been prevented and therefore was a performance deficiency. This finding is more than minor because it is associated with the procedure quality attribute of the mitigating systems cornerstone and affected the objective to ensure the capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage).

Specifically, procedure GP-2 stated that the HPCI system was operable with a Level 8 trip present without the ability to automatically actuate upon a high drywell pressure condition without an engineering evaluation which was inconsistent with the existing safety analysis performed at normal operating reactor pressure and temperature.

Using IMC 0609, Significance Determination Process, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, the inspectors determined that this finding was of very low safety significance (Green) because the finding did not represent an actual loss of the HPCI system or function to inject high pressure emergency core cooling water. Specifically, the note in GP-2 allowed considering the HPCI system operable at normal operating reactor pressures with the HPCI system tripped. However, the HPCI system was not tripped at normal operating reactor pressures.

The inspectors determined that the finding did not have cross-cutting aspect because the procedure development performance deficiency did not occur within the last three years, and the inspectors did not conclude that the causal factors represented present Exelon performance.

Enforcement.

10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances. Contrary to the above, from December 18, 1995 until the present, Exelon did not adequately prescribe a procedure appropriate to the circumstances.

Specifically, procedure GP-2 contained a note that stated HPCI systems have been determined operable by engineering evaluation with a high level trip setpoint actuated, the referenced engineering evaluation was not found, and the GP-2 note was not supported or correct under operating conditions credited in the safety analysis. Exelons immediate corrective actions to restore compliance included briefing staff on the issue and completing a procedure revision to reference an interim evaluation. Because this violation was of very low safety significance and was entered into the corrective action program (IR 2464416), this violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. (NCV 05000352;05000353/2015001-02, Startup Procedure Considered High Pressure Coolant Injection Operable with High Reactor Water Level Trip Actuated Preventing High Drywell Pressure Automatic Actuation)

(2)

Introduction.

An unresolved item (URI) was identified because inspectors require more information to determine if a performance deficiency and violation exists for an issue of concern related to Exelons determination that the operability and safety function of the HPCI system was maintained at reactor pressures lower than normal operating pressure but above 200 psig which would prevent automatic HPCI system actuation on high drywell pressure. Specifically, HPCI operability is required by TS for entering operational and other conditions at these low reactor pressures.

Description.

The HPCI logic signals for reactor vessel water level originate from wide range vessel level instrumentation. These wide range reactor vessel level instruments are differential pressure type instruments which are reactor coolant density sensitive and are calibrated to be most accurate at normal reactor operating temperature and pressure conditions. At low coolant temperatures and pressures, these instruments that are calibrated for normal operating conditions indicate higher than actual water level. As a result of this wide range level instrumentation error, a Level 8 trip signal is present at reactor pressures greater than the pressure at which the HPCI system is required to be operable which is above 200 psig. With a Level 8 trip present, the logic circuitry prevents actuation of the HPCI system by tripping the turbine stop valve closed. In addition, to prevent undue cycling of the HPCI system, when the reactor water level drops below the Level 8 trip signal setpoint, a seal-in circuit prevents actuation of the HPCI system until the Level 8 trip relays are reset, either by a manual reset pushbutton or reactor water level dropping to the reactor vessel water level low-low (Level 2, actuation setpoint -38 inches) actuation setpoint.

Technical specification 3.3.3 requires the emergency core cooling system actuation channels shown in Table 3.3.3-1 to be operable. Table 3.3.3-1, trip function 3.b, drywell pressure - high, requires four operable channels during operating modes 1, 2, and 3 (Power Operation, Startup, and Hot Shutdown) when reactor pressure is greater than 200 psig. With more than one channel inoperable, the HPCI system must be declared inoperable. TS 3.0.4 specifies that when the limiting condition for operation is not met, entry into an operational condition shall only be made when the associated action requirements to be entered permit continued operation in the operational condition for an unlimited period of time, after performance of a risk assessment given specified requirements, or when an allowance is stated in the specification. For the HPCI system being inoperable, TS 3.0.4 does not allow entries into operational conditions 1, 2, or 3 or entry into the pressure range for required operability, 200 psig, since the associated HPCI system action requirements do not permit continued operation in the operational condition for an unlimited period of time, TS 3.5.1.c.3 states that TS 3.0.4.b regarding performance of a risk assessment is not applicable to HPCI, and an allowance is not stated in the HPCI specification. On February 25, 2015, Exelon performed a startup of LGS Unit 1 after completing repairs, and Unit 1 entered modes 2 and 1 with a Level 8 trip signal present.

Exelon concluded that the HPCI system was operable under these conditions given that the logic circuitry operates as originally designed, the reactor pressure was substantially less than normal operating reactor pressure, and the HPCI system was capable of automatically actuating given reactor vessel water level reaching the low-low setpoint. In addition, the TS bases (Figure B 3/4.3-1) describe that the wide range level instruments are calibrated for normal operating conditions and will read higher than actual water level.

However, the TS, TS bases, and UFSAR do not describe that the level deviation results in a Level 8 trip with an associated seal-in nor describe an allowance to consider the high drywell pressure actuation channels operable when incapable of actuating the HPCI system due to a Level 8 trip. Specifically, TS require that the high drywell pressure instrument actuates the HPCI system at a setpoint of less than or equal to 1.68 psig with an automatic actuation of the HPCI system throughout its emergency operating sequence with each automatic valve in the flow path actuating to its correct position.

Although the high drywell pressure instruments actuate with a Level 8 trip present, the described function to actuate the HPCI system on a high drywell pressure cannot be performed automatically.

The inspectors consulted staff in the Technical Specifications and Reactor Systems Branches in the NRC Office of Nuclear Reactor Regulation, and concluded that Exelons determination that the operability and safety function of the HPCI system was maintained at lower reactor pressures with the Level 8 trip actuated which prevented automatic HPCI system actuation on high drywell pressure required further information in order to determine if this issue of concern is a performance deficiency and violation. The TS define operability, in part, as a system shall be operable or have operability when it is capable of performing its specified function(s). The inspectors concluded that further information was required to determine whether or not the high drywell pressure automatic actuation was a specified function at lower reactor pressures.

Specifically, considering the HPCI system inoperable at lower reactor pressures based on the wide range level error causing a Level 8 trip preventing automatic high drywell pressure actuation prohibits changes in operational conditions which are necessary to establish HPCI system operability through raising reactor pressures. Further, the existing safety analysis only considered normal operating reactor pressure and did not analyze the low reactor pressure condition.

Therefore, the inspectors determined that additional information is necessary to resolve this unresolved item. Specifically, the information for the inspectors review can be obtained from completion of a Task Interface Agreement through the NRC Office of Nuclear Reactor Regulation or any of the following three items from Exelon:

(1) analysis by Exelon demonstrating that automatic high drywell pressure actuation is not required at low (>200 to 500 psig) reactor pressures in order to satisfy HPCI system safety functions. This would demonstrate that a license amendment is not required, in which case the issue of concern was not a violation or performance deficiency,

(2) a license amendment request submitted by Exelon and approved by the NRC to modify the TS to clarify and describe that automatic actuation of the HPCI system on high drywell pressure at low reactor pressures is not required, in which case the issue of concern was an inconsistency in the NRC-approved TS and was not more-than-minor because the issue was not a design change implemented by Exelon, involved a failure to clearly describe the facility in the FSAR and TS, and did not have a material impact on safety or licensed activities (NRC Enforcement Manual, Revision 9, Sections 2.1.3.D and 2.1.3.E.6), and/or

(3) Exelons completion of design and/or operational modifications in accordance with 10 CFR 50.59 to maintain the automatic actuation of the HPCI system on high drywell pressure at reactor pressures greater than 200 psig, in which case the inspectors, in consultation with staff from the Technical Specifications and Reactor Systems Branches in the NRC Office of Nuclear Reactor Regulation will review Exelons additional analysis and modifications and conclude whether or not the issue of concern was a performance deficiency, a violation, and more-than-minor.

This issue will be tracked as a URI pending NRC review of Exelons completed evaluation. (URI 05000352;05000353/2015001-03, Operability of High Pressure Coolant Injection and Entries into Operational Conditions at Low Reactor Pressures with High Reactor Water Level Trip Actuated).

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TS, the UFSAR, and LGS procedure requirements. The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation, test instrumentation had current calibrations and the range and accuracy for the application, tests were performed as written, and applicable test prerequisites were satisfied. Upon test completion, the inspectors considered whether the test results supported that equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:

ST-6-092-366-0, inoperable Unit 2 safeguard power supply actions for Units 1 and 2 on December 30, 2014 ST-6-092-312-1, D12 diesel generator slow start operability test run on January 6, 2015 (in-service test)

ST-2-088-408-1, remote shutdown system - condensate storage tank level calibration on January 12, 2015 ST-6-092-324-2, D24 diesel generator LOCA - load reject testing and fast start operability test run on January 13, 2015 ST-2-074-630-1, source range monitor functional test SRM A on Unit 1 on February 24, 2015 ST-6-107-760-1, control rod exercise on Unit 1 on March 8, 2015 ST-6-055-230-1, HPCI Pump, Valve, and Flow Test on Unit 1 on March 20, 2015 (in-service test)

ST-6-092-114-1, D14 diesel generator 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> endurance test on March 24 through March 25, 2015

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes (IP

==71114.04 - 1 sample)

a. Inspection Scope

==

Exelon implemented various changes to the LGS Emergency Action Levels (EALs),

Emergency Plan, and Implementing Procedures. Exelon had determined that, in accordance with 10 CFR 50.54(q)(3), any change made to the EALs, Emergency Plan, and its lower-tier implementing procedures, had not resulted in any reduction in effectiveness of the Plan, and that the revised Plan continued to meet the standards in 50.47(b) and the requirements of 10 CFR 50 Appendix E.

The inspectors performed an in-office review of all EAL and Emergency Plan changes submitted by Exelon as required by 10 CFR 50.54(q)(5), including the changes to lower-tier emergency plan implementing procedures, to evaluate for any potential reductions in effectiveness of the Emergency Plan. This review by the inspectors was not documented in an NRC Safety Evaluation Report and does not constitute formal NRC approval of the changes. Therefore, these changes remain subject to future NRC inspection in their entirety. The requirements in 10 CFR 50.54(q) were used as reference criteria. The specific documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

During March 18-19, 2015, the inspectors reviewed Exelons performance in assessing and controlling radiological hazards in the workplace. The inspectors used the criteria in 10 CFR 20, applicable Regulatory Guides, TSs, and applicable Exelon procedures for determining compliance.

Inspection Planning

The inspectors reviewed performance indicators for the occupational exposure cornerstone, radiation protection (RP) program audits, and RP operational occurrences since the last inspection.

Radiological Hazard Assessment The inspectors reviewed changes to plant operations since the last inspection; pre-work radiological surveys for refueling activities, drywell work activities, and suppression pool diving; adequate identification of radiological hazards (e.g., discrete radioactive hot particles, hard to detect nuclides in air samples, transient dose rates and large gradients in radiation dose rates); and work in potential airborne radioactivity areas.

Instructions to Workers The inspectors reviewed exposure control methods including electronic personal dosimeter (EPD) alarm set-points, EPD alarm occurrences; and means to inform workers and control exposures.

Contamination and Radioactive Material Control The inspectors reviewed changes in radiological source term and potential impacts on radiation detection instrumentation including typical detection sensitivity.

Risk-Significant High Radiation Area (HRA) and Very High Radiation Area (VHRA)

Controls The inspectors reviewed controls and procedures for access control of HRAs and VHRAs.

Radiation Worker Performance and RP Technician Proficiency The inspectors reviewed radiological problem reports since the last inspection that attributed the cause of the event to human performance error.

Problem Identification and Resolution The inspectors evaluated whether problems associated with radiation monitoring and exposure control were being identified at an appropriate threshold and were properly addressed for resolution.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

During March 18-19, 2015, the inspectors assessed performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspectors used the requirements in 10 CFR 20, applicable Regulatory Guides, and Exelons TSs and procedures for determining compliance.

Inspection Planning

The inspectors reviewed site-specific trends in collective exposures against industry average values, changes in the radioactive source term, and procedures associated with maintaining occupational exposures ALARA including processes used to estimate and track exposures.

Radiological Work Planning The inspectors reviewed the following high collective exposure work activities: drywell work including control rod drive removal, refueling floor work, suppression pool diving, and turbine building work. For these work activities, the inspectors reviewed ALARA work activity evaluations, exposure estimates, and implementation of exposure reduction methods.

Verification of Dose Estimates and Exposure Tracking Systems The inspectors reviewed the basis for the current annual collective dose estimate; measures to track, trend, and adjust exposure estimates; and method of re-planning work, when unexpected changes in scope or emergent work were encountered.

Source Term Reduction and Control The inspectors reviewed contingency plans for changes in the source term as the result of changes in plant fuel performance issues or changes in plant primary chemistry, and for source term clean-up activity plans.

Problem Identification and Resolution The inspectors evaluated whether problems associated with ALARA planning and controls were being identified by Exelon at an appropriate threshold and were properly addressed for resolution.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

During March 18-19, 2015, the inspectors verified that various potential in-plant airborne sources were being controlled consistent with ALARA principles and the use of respiratory protection devices, as appropriate. The inspectors used the requirements in 10 CFR 20, the guidance in applicable Regulatory Guides, and Exelons TSs and procedures for determining compliance.

Inspection Planning

The inspectors reviewed reported performance indicators to identify any related to unintended dose resulting from personnel intakes of radioactive material.

Engineering Controls The inspectors reviewed the use of permanent and temporary ventilation to control airborne radioactivity and the threshold criteria for evaluating levels of airborne beta-emitting, alpha-emitting radionuclides, and other hard-to-detect radionuclides.

Problem Identification and Resolution The inspectors evaluated whether problems associated with the control and mitigation of in-plant airborne radioactivity were being identified at an appropriate threshold and properly addressed for resolution.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

During March 18-19, 2015, the inspectors evaluated the monitoring, assessment, and reporting of occupational dose. The inspectors used the requirements in 10 CFR 20, the guidance in various Regulatory Guides, and requirements in Exelons TSs and procedures.

Inspection Planning

The inspectors reviewed issuance/use of external dosimetry, and assessments of external and internal dose.

External Dosimetry The inspectors reviewed EPDs to determine the use of a correction factor to address the response of the EPD as compared to the dosimeter of legal record.

Routine Bioassay (In Vivo)

The inspectors selectively reviewed plans to assess the dose from internally deposited radionuclides using new whole body count equipment.

Problem Identification and Resolution The inspectors assessed whether problems associated with occupational dose assessment were identified at an appropriate threshold, were placed in the corrective action program, and whether corrective actions, for a selected sample of problems, were appropriate.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

During March 18-19, 2015, the inspectors reviewed the accuracy and operability of radiation monitoring instruments that were used to protect occupational workers. The inspectors used the requirements in 10 CFR 20, the guidance in applicable Regulatory Guides, and Exelons TSs and procedures for determining compliance.

Inspection Planning

The inspectors reviewed assessments of the radiation monitoring program since the last inspection including evaluations of offsite calibration services.

Calibration and Check Sources The inspectors reviewed recent source term assessment to assess whether calibration and check sources used were representative of the types and energies of radiation encountered.

Problem Identification and Resolution The inspectors evaluated whether problems associated with radiation monitoring instrumentation were being identified by Exelon at an appropriate threshold and properly addressed for resolution.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Unplanned Scrams, Unplanned Power Changes, and Unplanned Scrams with

Complications ===

a. Inspection Scope

The inspectors reviewed LGS submittals for the following Initiating Events Cornerstone performance indicators for the period of January 1 through December 31, 2014.

Unit 1 Unplanned Power Changes Unit 2 Unplanned Power Changes To determine the accuracy of the performance indicator data reported during those periods, inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors reviewed LGS operator narrative logs, maintenance planning schedules, condition reports, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index (4 samples)

a. Inspection Scope

The inspectors reviewed LGS submittal of the Mitigating Systems Performance Index for the following systems for the period of January 1 through December 31, 2014:

Unit 1 High Pressure Injection System Unit 2 High Pressure Injection System Unit 1 Heat Removal System Unit 2 Heat Removal System To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspectors also reviewed Exelons operator narrative logs, condition reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.

b. Findings

No findings were identified

4OA2 Problem Identification and Resolution

Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that Entergy entered issues into their corrective action program at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the corrective action program and periodically attended condition report review group meetings.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

On April 10, 2015, the inspectors presented the inspection results to Mr. D. Lewis, Plant Manager, and other members of the LGS staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

T. Dougherty, Site Vice President

D. Lewis, Plant Manager

M. Gillin, Director of Operations

D. Doran, Director of Engineering

F. Sturniolo, Director of Maintenance

J. Hunter, Director of Work Management

K. Kemper, Security Manager

R. Dickinson, Manager, Regulatory Assurance

J. Karkoska, Manager, Nuclear Oversight

R. Ruffe, Training Director

H. Weissinger, Shift Operations Superintendent

J. Broillet, Emergency Preparedness Manager

G. Budock, Regulatory Assurance Engineer

D. Molteni, Manager Operations Training

M. DiRado, Manager, Engineering Programs

D. Merchant, Radiation Protection Manager

C. Gerdes, Manager, Chemistry, Environmental and Radioactive Waste

J. Broillet, Emergency Preparedness Manager

J. Bendyk, Engineer

A. Charles, Maintenance Planning Supervisor

L. Emel, Lead Maintenance Tech

M. Arnosky, Shift Manager

J. Berg, Engineer

P. Dix, Radiological Engineering Manager

B. Devine, Shift Manager

P. Imm, Radiological Engineering Manager

J. Debrosse, Senior Chemist

J. Duskin, Instrument Coordinator

A. Lambert, Engineer

N. Lampe, Engineer

P. Marvel, Shift Manager

K. McLaughlin, Engineering Manager

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Opened/Closed

05000352,

05000353/2015001- NCV Fire Safe Shutdown Diesel Generator Maintenance Program Did Not Account for Cold Temperatures due to Inadequate Specification for Fuel Oil Cloud Point (Section 1R15)

05000352,

05000353/2015001- NCV Startup Procedure Considered High Pressure Coolant Injection Operable with High Reactor Water Level Trip Actuated Preventing High Drywell Pressure Automatic Actuation (Section 1R20)

Opened

05000352,

05000353/2015001- URI Operability of High Pressure Coolant Injection and Entries into Operational Conditions at Low Reactor Pressures with High Reactor Water Level Trip Actuated (Section 1R20)