IR 05000373/2018003

NRC Integrated Inspection Report 05000373/2018003 and 05000374/2018003

ML18313A199
Person / Time
Site:	LaSalle
Issue date:	11/08/2018
From:	Billy Dickson NRC/RGN-III/DRP/B2
To:	Bryan Hanson Exelon Generation Co, Exelon Nuclear
References
IR 2018003
Download: ML18313A199 (34)

Text

UNITED STATES ovember 8, 2018

SUBJECT:

LASALLE COUNTY STATION, UNITS 1 AND 2NRC INTEGRATED INSPECTION REPORT 05000373/2018003 AND 05000374/2018003

Dear Mr. Hanson:

On September 30, 2018, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your LaSalle County Station, Units 1 and 2. On October 11, 2018, the NRC inspectors discussed the results of this inspection with Mr. W. Trafton and other members of your staff. The results of this inspection are documented in the enclosed report.

Based on the results of this inspection, the NRC has identified six issues that were evaluated under the risk significance determination process as having very-low safety significance (Green). The NRC has also determined that seven violations are associated with these issues.

Because the licensee initiated condition reports to address these issues, these violations are being treated as Non-Cited Violations (NCVs), consistent with Section 2.3.2 of the Enforcement Policy. These NCVs are described in the subject inspection report.

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 III; the Director, Office of Enforcement; and the NRC Resident Inspectors at the LaSalle County Station.

If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement 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 U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region III; and the NRC resident inspectors at the LaSalle County Station. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely,

/RA/

Billy Dickson, Chief Branch 2 Division of Reactor Projects Docket Nos. 50-373; 50-374 License Nos. NPF-11; NPF-18 Enclosure:

IR 05000373/2018003; 05000374/2018003 cc: Distribution via LISTSERV

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring licensees performance by conducting an integrated quarterly inspection at LaSalle County Station, Units 1 and 2, in accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for overseeing the safe operation of commercial nuclear power reactors. Refer to https://www.nrc.gov/reactors/operating/oversight.html for more information. Findings and violations being considered in the NRCs assessment are summarized in the table below.

List of Findings and Violations Failure to Establish Heat Exchanger Inspection Procedures Appropriate for the Circumstances Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green H.12 - Human 71111.07 NCV 05000373/2018003-01; Performance, Avoid 05000374/2018003-01 Complacency Closed The inspectors identified a finding of very low safety significance (Green) and an associated Non-Cited Violation (NCV) of 10 Code of Federal Regulations (CFR) Part 50, Appendix B,

Criterion V, Instructions Procedures, and Drawings, for the licensees failure to ensure that activities affecting quality were prescribed by documented procedures of a type appropriate to the circumstances. Specifically, the licensee failed to ensure that procedure ER-AA-340-1002 appropriately accounted for partially blocked heat exchanger (HX) tubes identified during HX inspections.

Failure to Establish an Appropriate Inservice Testing Procedure Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green None 71111.07 NCV 05000373/2018003-02; 05000374/2018003-02 Closed The inspectors identified a finding of very low safety significance (Green) and an associated Non-Cited Violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to prescribe procedures that were appropriate to the circumstances, for activities affecting quality, that included appropriate quantitative or qualitative acceptance criteria for determining that important activities had been satisfactorily accomplished. Specifically, the core standby cooling system (CSCS) bypass line isolation valve inservice testing (IST) procedure did not contain acceptance criteria to verify the necessary valve obturator movement.

Failure to Establish Goals to Monitor Steam Tunnel Check Dampers Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green None IP 71111.12 NCV 05000373/2018003-03; 05000374/2018003-03 Closed The inspectors identified a finding of very low safety significance (Green) and an associated Non-Cited Violation of 10 CFR 50.65(a)(1) for the licensees failure to establish goals to monitor the performance of steam tunnel check dampers. Specifically, the licensees goals for functional failure and condition monitoring could always be satisfied given a two years monitoring period with only one testing opportunity.

Failure to Manage the Increase in Risk During a Battery Charger Capacity Test Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Green H.13 - Consistent 71111.22 Systems NCV 05000373/2018003-04 Process Closed The inspectors identified a finding of very low safety significance (Green) and an associated Non-Cited Violation of 10 CFR 50.65(a)(4) for the failure to manage risk when the licensee failed to adhere to procedure WC-AA-101, Revision 28, On-line Work Control Process.

Specifically, procedural requirements regarding a dedicated operator for manual restoration actions and written instructions to credit the availability of the A residual heat removal service water (RHRSW) pump during the battery charger testing were not met.

Failure to Translate Fuel Oil Relief Valve Setting into Design Drawing of Record Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green None 71152 NCV 05000373/2018003-05; 05000374/2018003-05 Closed The inspectors identified a finding of very low safety significance (Green) and an associated Non-Cited Violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to assure that applicable regulatory requirements and the design basis were correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee failed to accurately translate the Division III emergency diesel generator (EDG)fuel oil relief valve set point from the design drawing of record, VPF-3411-10, to the fuel oil pressure operator rounds alert value in the Division III EDG operating procedures.

Failure to Implement Engineering Change Results in Reactor Coolant Boundary Leakage Cornerstone Significance Cross-Cutting Aspect Report Section Initiating Events Green H.4 - Teamwork 71153 NCV 05000373/2018003-08 Closed The inspectors documented a self-revealed finding of very low safety significance (Green)and associated Non-Cited Violations of Technical Specification (TS) 5.4.1 Procedures, and TS 3.4.5 for the failure to implement engineering change (EC) 354539 to perform the final piping weld for the 1B33-F067B bonnet vent line in the field resulting in pressure boundary leakage when the weld failed at power.

Additional Tracking Items Type Issue Number Title Report Status Section URI 05000373/2018003-06; Potential Failure to Inspect 71152 Open 05000374/2018003-06 Containment Post-Tensioned Tendons per Code Requirements and to Follow Corrective Action Program Process URI 05000374/2018003-07 Potential Failure to Promptly 71152 Open Correct the Unit 2 Primary Containment Wall Cavity Leakage Condition and to Follow Corrective Action Program Process LER 05000373/2018-004-00 Technical Specification 71153 Closed Required Shutdown due to Reactor Pressure Boundary Leakage

TABLE OF CONTENTS

PLANT STATUS

................................................................................................................... 6

INSPECTION SCOPES

......................................................................................................... 6

REACTOR SAFETY

...................................................................................................... 6

RADIATION SAFETY

.................................................................................................... 9

OTHER ACTIVITIES - BASELINE

.............................................................................. 10

INSPECTION RESULTS

..................................................................................................... 11

EXIT MEETINGS AND DEBRIEFS

..................................................................................... 27

DOCUMENTS REVIEWED

................................................................................................. 27

PLANT STATUS

Unit 1 began the inspection period at rated thermal power. On September 8, 2018, the unit was

down powered to approximately 77 percent power for a rod pattern adjustment and to support

turbine valve testing. The unit was returned to rated thermal power on September 10, 2018.

The unit remained at or near rated thermal power for the remainder of the inspection period.

Unit 2 began the inspection period at rated thermal power. On August 31, 2018, the unit was in

the process of shutting down to perform maintenance on the A reactor recirculation pump when

the operators had to manually scram the unit due to a loss of main condenser vacuum. After

completing the planned maintenance and correcting the cause for the loss of the main

condenser vacuum, the licensee started the unit up and returned to rated thermal power on

September 6, 2018. The unit remained at or near rated thermal power for the remainder of the

inspection period.

INSPECTION SCOPES

Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in

effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with

their attached revision histories are located on the public website at http://www.nrc.gov/reading-

rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared

complete when the IP requirements most appropriate to the inspection activity were met

consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection

Program - Operations Phase. The inspectors performed plant status activities described in

IMC 2515 Appendix D, Plant Status and conducted routine reviews using IP 71152, Problem

Identification and Resolution. The inspectors reviewed selected procedures and records,

observed activities, and interviewed personnel to assess licensee performance and compliance

with Commission rules and regulations, license conditions, site procedures, and standards.

REACTOR SAFETY

71111.01Adverse Weather Protection

Impending Severe Weather (1 Sample)

The inspectors evaluated readiness for impending adverse weather conditions for a severe

thunderstorm warning on September 25, 2018.

71111.04Equipment Alignment

Partial Walkdown (3 Samples)

The inspectors evaluated system configurations during partial walkdowns of the following

systems/trains:

(1) Unit 1 Division III emergency diesel generator (EDG) on August 16, 2018;

(2) Unit 2 standby liquid control system on August 21, 2018; and

(3) Unit 2 Division III switchgear and high pressure core spray on September 6, 2018.

71111.05AQFire Protection Annual/Quarterly

Quarterly Inspection (5 Samples)

The inspectors evaluated fire protection program implementation in the following selected

areas:

(1) Fire protection loop flow test, LOS-FP-SR2, on August 5, 2018;

(2) Fire zone 5D2, Unit 2 Division III switchgear room, on August 16, 2018;

(3) Fire zone 5D1, Unit 1 Division III switchgear room, on August 16, 2018;

(4) Fire zone 2I3, Unit 1 B/C residual heat removal (RHR) corner room, 673 Elevation, on

August 16, 2018; and

(5) Fire zone 3B1, Unit 2 reactor building standby gas treatment area, 820 Elevation, on

August 21, 2018.

71111.07Heat Sink Performance

Heat Sink (Triennial) (2 Samples)

The inspectors evaluated heat sink (HX) performance on the following components:

(1) Units 1 and 2 B RHR HX (1(2) E12-B001B); and

(2) Ultimate heat sink (IP 71111.07, Sections 02.02d2 and 02.02d7).

71111.11Licensed Operator Requalification Program and Licensed Operator Performance

Operator Requalification (1 Sample)

The inspectors observed and evaluated the operator requalification test, scenarios ESG-57 and

ESG-80, on September 12, 2018.

Operator Performance (1 Sample)

The inspectors observed and evaluated operators in the control room during reactor plant shut

down and startup on August 31, 2018 and on September 3, 2018, respectively.

71111.12Maintenance Effectiveness

Routine Maintenance Effectiveness (3 Samples)

The inspectors evaluated the effectiveness of routine maintenance activities associated

with the following equipment and/or safety significant functions:

(1) Valcor valves on August 29, 2018;

(2) Steam tunnel check dampers on June 20, 2018; and

(3) Containment post loss-of-cooling-accident monitor on August 28, 2018.

71111.13Maintenance Risk Assessments and Emergent Work Control (5 Samples)

The inspectors evaluated the risk assessments for the following planned and emergent

work activities:

(1) Units 1 and 2 online risk yellow due to thunderstorm warning on August 29, 2018;

(2) Unit 1 online risk yellow and Unit 2 shutdown risk green due to 345 kilo-Volt (KV)

switching operations for disconnect maintenance on September 2, 2018;

(3) Unit 2 Division III protected equipment during Division I equipment inoperability on

September 6, 2018;

(4) Unit 2 online risk yellow due to high pressure core spray planned maintenance outage

on September 24, 2018; and

(5) Unit 2 online risk orange due to high pressure core spray planned maintenance outage

and severe thunderstorm watch on September 25, 2018.

71111.15Operability Determinations and Functionality Assessments (4 Samples)

The inspectors evaluated the following operability determinations and functionality

assessments:

(1) Standby gas treatment wide range gas monitor inoperable on July 15, 2018;

(2) Unit 2 low pressure core spray and RHR A low pressure permissive switch,

2B21-N413C, out of Technical Specifications tolerance on July 15, 2018;

(3) Unit 1 low pressure core spray/reactor core isolation cooling room temperature element

out-of-service on July 31, 2018; and

(4) Unit 2 reactor protector system motor generator set output breaker failure to open on

August 27, 2018.

71111.18Plant Modifications (1 Sample)

The inspectors evaluated the following temporary or permanent modifications:

(1) Temporary secondary containment boundary for re-route Unit 2 Division II room cooler

piping (Engineering Change 620623) on September 18, 2018.

71111.19Post Maintenance Testing (5 Samples)

The inspectors evaluated the following post maintenance tests:

(1) Unit 1 standby gas treatment w controller testing on September 7, 2018;

(2) Unit 2 C RHR min-flow valve breaker replacement testing on September 4, 2018;

(3) B auxiliary electric and control rooms heating, ventilation and air conditioning testing on

September 19, 2018;

(4) Unit 1 standby gas treatment flow control capacitor testing on August 9, 2018; and

(5) Unit 2 standby gas treatment testing on August 15, 2018.

71111.20Refueling and Other Outage Activities (1 Sample)

The inspectors evaluated Unit 2 forced outage, L2M20, maintenance activities from August 31

through September 3, 2018.

71111.22Surveillance Testing

The inspectors evaluated the following surveillance tests:

Routine (3 Samples)

(1) LES-DC-103A, Unit 2, Division I, 2AA battery charger capacity test on July 22, 2018;

(2) LOS-PC-M1, post loss-of-coolant-accident channel check on July 22, 2018; and

(3) LIP-CM-510, Unit 1 continuous oxygen monitor sensor maintenance and

standardization on August 5, 2018.

In-Service (1 Sample)

(1) 2CM028, 3 point containment atmosphere monitor drywell suction primary containment

isolation valve, post-maintenance testing on September 12, 2018.

RADIATION SAFETY

71124.06Radioactive Gaseous and Liquid Effluent Treatment

Walk Downs and Observations (1 Sample)

The inspectors evaluated the licensees radioactive gaseous and liquid effluent treatment

systems during plant walkdowns.

Calibration and Testing Program (Process and Effluent Monitors) (1 Sample)

The inspectors evaluated the licensees gaseous and liquid effluent monitor instrument

calibration and testing.

Sampling and Analyses (1 Sample)

The inspectors evaluated radioactive effluent sampling and analysis activities.

Dose Calculations (1 Sample)

The inspectors evaluated dose calculations.

71124.07Radiological Environmental Monitoring Program

Site Inspection (1 Sample)

The inspectors evaluated the licensees radiological environmental monitoring program.

Groundwater Protection Initiative Implementation (1 Sample)

The inspectors evaluated the licensees groundwater monitoring program.

OTHER ACTIVITIES - BASELINE

71151Performance Indicator Verification (9 Samples)

The inspectors verified licensee performance indicators submittals listed below:

(1) MS06: Emergency AC Power Systems2 Samples (July 1, 2017 - June 30, 2018);

(2) MS07: High Pressure Injection Systems2 Samples (July 1, 2017 - June 30, 2018);

(3) MS09: Residual Heat Removal Systems2 Samples (July 1, 2017 - June 30, 2018);

(4) PR01: Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual

Radiological Effluent Occurrences (RETS/ODCM) Radiological Effluent Occurrences

Sample (October 1, 2017 - June 30, 2018); and

(5) BI01: RCS Specific Activity2 Samples (October 1, 2017 - June 30, 2018).

71152Problem Identification and Resolution

Annual Follow-Up of Selected Issues (3 Samples)

The inspectors reviewed the licensees implementation of its corrective action

program (CAP) related to the following issues:

(1) Inservice inspection of Group B vertical tendons;

(2) Unit 2 reactor cavity leakage through primary containment wall; and

(3) Division III EDG operator rounds.

71153Follow-Up of Events and Notices of Enforcement Discretion

Licensee Event Reports (1 Sample)

The inspectors evaluated the following licensee event reports which can be accessed at

https://lersearch.inl.gov/LERSearchCriteria.aspx:

(1) Licensee Event Report (LER) 2018-004-00, Technical Specification Required

Shutdown due to Reactor Pressure boundary Leakage.

INSPECTION RESULTS

71111.07Heat Sink Performance

Failure to Establish Heat Exchanger Inspection Procedures Appropriate for the

Circumstances

Cornerstone Significance Cross-Cutting Report Section

Aspect

Mitigating Green H.12 - Human 71111.07 - Heat

Systems NCV 05000373/2018003-01; Performance, Sink Performance

05000374/2018003-01 Avoid

Closed Complacency

The inspectors identified a finding of very low safety significance (Green) and an associated

NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions Procedures, and Drawings, for

the licensees failure to ensure that activities affecting quality were prescribed by documented

procedures of a type appropriate to the circumstances. Specifically, the licensee failed to

ensure that procedure ER-AA-340-1002 appropriately accounted for partially blocked HX

tubes identified during HX inspections.

Description:

The RHR HXs are relied upon to remove core decay heat following design basis accidents

and during shutdown cooling operations. The RHR HXs are shell-and-tube HXs with a U-tube

design.

As documented in the licensees Generic Letter (GL) 89-13 Program Basis Document,

LaSalle Station chose to perform frequent regular maintenance, with thermal performance

testing as a supplement, for the RHR Heat Exchangers. This maintenance was performed to

periodically verify the heat transfer capability of the safety-related HXs cooled by service

water. The frequent regular maintenance consisted of visual inspections of the tube-side of

the RHR HXs, performed in accordance with ER-AA-340-1002, Service Water Heat

Exchanger Inspection Guide, Revision 7. For tube-side clean and inspect maintenance

activities, the procedure required the licensee to develop acceptance criteria prior to

performing the HX inspection, and then required the licensee to compare the as-found

conditions of the HX against the acceptance criteria. For macro fouling, the acceptance

criteria developed was based on the number of tubes allowed to be blocked, as supported by

design basis calculations. For the RHR HXs, a total of 53 of 1,063 tubes were allowed to be

blocked.

On March 8, 2018, the licensee completed work order (WO) 1909979, Disassemble RHR HT

Exchanger to Inspect Service Water, which was associated with an inspection of the 1 B

RHR HX. This HX inspection identified a number of partially and fully blocked tubes. The

licensee evaluated this condition by developing a number of equivalently blocked tubes in

order to account for the partially blocked tubes when comparing the as-found condition

against the acceptance criterion. This evaluation was conducted per step 4.5.1.2.A of

procedure ER-AA-340-1002, which stated that the development of the number of equivalent

blocked tubes was based on the qualitative engineering judgment of the inspector in the

field. The WO documented that the as-found blockage was equivalent to 50 blocked tubes,

which met the acceptance criterion. In addition, the procedure provided Appendix 1, Method

for Evaluating Partial Tube Blockage, to support the HX inspector in the development of the

number of equivalent blocked tubes when partially blocked tubes were identified. However,

Appendix 1 was not used because its use was optional, as stated in step 4.7 of the

procedure.

The NRC inspectors determined procedure ER-AA-340-1002 was not appropriate to the

circumstances because it allowed partially blocked tubes to be converted to an equivalent

number of fully blocked tubes without establishing a technical basis when assessing the as-

found condition of safety-related HXs.

Corrective Actions: The licensee was still evaluating its planned corrective actions at the time

of the inspection. However, the inspectors determined that the continued non-compliance

does not present an immediate safety concern because the licensee evaluated the most

recent thermal performance test results for the 1 B RHR HX and determined that there was

sufficient available margin to ensure the HX was capable of performing its design function.

Corrective Action Reference: Action request (AR) 4149537

Performance Assessment:

Performance Deficiency: The inspectors determined the failure to establish procedures

of a type appropriate to the circumstances for safety related HX inspections was contrary

to 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings,

and was a performance deficiency. Specifically, the licensee failed to ensure that procedure

ER-AA-340-1002 appropriately accounted for partially blocked HX tubes identified during

safety related HX inspections.

Screening: The inspectors determined the performance deficiency was more than minor

because it was associated with the Mitigating Systems cornerstone attribute of procedure

quality and adversely affected the cornerstone objective of ensuring the capability of systems

that respond to initiating events to prevent undesirable consequences. Specifically,

procedure ER-AA-340-1002 did not ensure the RHR HXs capability to provide their

mitigating function because the procedure would allow unacceptable HX performance to go

undetected.

Significance: The inspectors determined the finding affected the Mitigating Systems

Cornerstone and assessed the significance of the finding using IMC 0609 Appendix A, The

Significance Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems

Screening Questions. The finding screened as having very low safety significance (Green)

because it did not result in the loss of operability or functionality of the 1B RHR H

X.

Specifically, the licensee evaluated the most recent thermal performance test results for the 1

B RHR HX and determined there was sufficient available margin to ensure the HX was still

capable of performing its design function.

Cross-Cutting Aspect: The finding had a cross-cutting aspect in the Avoid Complacency

component of the Human Performance cross-cutting area, which states, in part, that the

licensee will recognize and plan for the possibility of mistakes even while expecting

successful outcomes and individuals implement appropriate error reduction tools.

Specifically, the licensee did not recognize and plan for the possibility of mistakes when, in

September of 2017, procedure ER-AA-340-1002 was revised to remove HX inspector

qualification requirements while continuing to allow HX inspectors to use their judgement

without appropriate error reduction tools. [H.12]

Enforcement:

Violation: Title 10 CFR Part 50, Appendix B, Criterion V, Instructions Procedures, and

Drawings, requires, in part, that activities affecting quality shall be prescribed by documented

procedures of a type appropriate to the circumstances and be accomplished in accordance

with these procedures.

The licensee established procedure ER-AA-340-1002, Service Water Heat Exchanger

Inspection Guide, Revision 7, as the implementing procedure for safety related service water

HX inspections, an activity affecting quality.

Contrary to the above, as of March 8, 2018, the licensee failed to have a procedure of a type

appropriate to the circumstances for safety-related HX inspections. Specifically, procedure

ER-AA-340-1002 did not contain appropriate instructions to ensure that the effects of

partially blocked tubes identified during HX inspections on the capability of the HXs could be

determined.

Disposition: This violation is being treated as an NCV, consistent with Section 2.3.2 of the

Enforcement Policy.

Failure to Establish an Appropriate Inservice Testing Procedure

Cornerstone Significance Cross-Cutting Report Section

Aspect

Mitigating Systems Green None 71111.07 - Heat

NCV 05000373/2018003-02; Sink

05000374/2018003-02 Performance

Closed

The inspectors identified a finding of very low safety significance (Green) and an associated

NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the

licensees failure to prescribe procedures that were appropriate to the circumstances, for

activities affecting quality, that included appropriate quantitative or qualitative acceptance

criteria for determining that important activities had been satisfactorily accomplished.

Specifically, the CSCS bypass line isolation valve IST procedure did not contain acceptance

criteria to verify the necessary valve obturator movement.

Description:

The CSCS bypass line isolation valve, 0E12-F300, is a 54-inch safety-related manual

butterfly valve with an actuator that has external limit stops located on the worm shaft. The

safety function of the valve is to open to provide a flow path from the lake to the service water

tunnel by bypassing the CSCS equipment cooling water system tunnel traveling screens

when they are unable to allow water flow into the plant. The licensee established procedure

LOS-RH-Q4, Cycling CSCS Bypass Line Isolation Valve, Revision 5, to test the valve. This

procedure was credited by the licensee IST program basis document for meeting the

requirements of the 2004 version of the ASME OM Code with the 2006 Addenda, which is the

licensees code of record.

The licensee classified this valve as a manual active category B valve in their IST program.

ASME OM Code paragraph ISTC-3540, Manual Valves, states:

Manual valves shall be full-stroke exercised at least once every 2 years, except where

adverse conditions may require the valve to be tested more frequently to ensure

operational readiness. Any increased testing frequency shall be specified by the

Owner. The valve shall exhibit the required change of obturator position.

Paragraph ISTC-3530 of the ASME OM Code, Valve Obturator Movement, states:

The necessary valve obturator movement shall be determined by exercising the valve

while observing an appropriate indicator, such as indicating lights that signal the

required changes of obturator position, or by observing other evidence, such as

changes in system pressure, flow rate, level, or temperature, that reflects change of

obturator position.

To exercise the valve, operators turned a T-bar that connects to the valve actuator. The

actuator was supposed to be mechanically connected to the valve obturator. Therefore, the

valve obturator was expected to turn when the T-bar was turned, as long as the mechanical

connection between the actuator and obturator maintained its integrity. During valve testing,

the test procedure required the licensee to count the number of times the T-bar was turned in

order to take the valve from the full closed position to the full open position, and vice-versa.

The procedure allowed the licensee to document a qualitative assessment of the valve

manipulation in the comments section of the procedure if any issues were encountered. The

qualitative assessment could include comments on: (1) difficulty turning the T-bar;

(2) excessive force required to open the valve; (3) excessive force required to close the valve;

(4) excessive force required to seat the valve; and (5) excessive valve binding.

The inspectors noted, however, that movement of the T-bar would not necessarily indicate

movement of the valve obturator. Specifically, the valve actuator contained external limit

stops which limited the number of turns the T-bar was physically allowed to take regardless of

actual valve obturator position. Hence, if the mechanical connection between the valve

actuator and obturator was degraded, the number of turns required for the T-bar to take the

valve from the full closed position to the full open position, or 222112 vice-versa, would not

indicate the actual valve obturator movement.

In addition, the IST procedure did not include any quantitative or qualitative acceptance

criteria. A note inside the IST procedure stated, The 0E12-F300, CSCS Bypass Line

Isolation Valve takes approximately 18 turns to open. However, the note did not qualify as

an acceptance criterion. As written, the test procedure could be satisfactorily completed

regardless of the number of turns required to manipulate the valve. In addition, although the

procedure allowed a qualitative assessment of the valve manipulation to be recorded, it did

not require the as found results of the valve to be compared against any established

acceptance criteria in order to determine whether or not the valve was capable of performing

its safety function. Therefore, the lack of acceptance criteria in the IST procedure could allow

a degraded or failed valve to incorrectly be considered capable of performing its safety

function.

Corrective Actions: The licensee was still evaluating its planned corrective actions at the time

of the inspection. However, the inspectors determined that the continued non-compliance

does not present an immediate safety concern because the licensee entered the issue into

their CAP and determined that the valve was operable.

Corrective Action Reference: AR 04149479

Performance Assessment:

Performance Deficiency: The inspectors determined the failure to prescribe a CSCS bypass

line isolation valve IST procedure that contained acceptance criteria to verify the necessary

valve obturator movement was a violation of 10 CFR Part 50, Appendix B, Criterion V, and

was a performance deficiency.

Screening: The performance deficiency was determined to be more than minor because it

was associated with the Mitigating Systems cornerstone attribute of procedure quality and

adversely affected the cornerstone objective of ensuring the availability, reliability, and

capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the CSCS bypass line isolation valve IST procedure did not ensure the valve

capability to provide its mitigating function because the procedure would allow unacceptable

valve performance to go undetected.

Significance: The finding was evaluated using IMC 0609 Appendix A, The Significance

Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening

Questions. The finding screened as having very low safety significance (Green) because it

did not result in the loss of operability or functionality of mitigating systems. Specifically, the

licensee reviewed available information and determined the valve remained operable.

Cross-Cutting Aspect: No cross cutting aspect was assigned to this finding because the

inspectors determined the finding did not reflect present licensee performance.

Enforcement:

Violation: Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and

Drawings, requires, in part, that activities affecting quality be prescribed by documented

procedures of a type appropriate to the circumstances and that the procedures include

appropriate quantitative or qualitative acceptance criteria for determining that important

activities have been satisfactorily accomplished.

The licensee established LOS-RH-Q4, Cycling CSCS Bypass Line Isolation Valve,

Revision 5, as the implementing procedure for testing valve 0E12-F300 in accordance with

the 2004 ASME OM Code with the 2006 Addenda, an activity affecting quality. Paragraph

ISTC-3530 of the Code states, in part, that the necessary valve obturator movement shall be

determined by exercising the valve while observing an appropriate indicator.

Contrary to the above, as of July 13, 2018, the licensee failed to have a procedure for testing

the CSCS bypass line isolation valve of a type appropriate to the circumstances and that

included appropriate quantitative or qualitative acceptance criteria for determining that

important activities had been satisfactorily accomplished. Specifically, IST procedure

LOS-RH-Q4 did not contain acceptance criteria to verify the necessary CSCS bypass line

isolation valve obturator movement.

Disposition: This violation is being treated as an NCV, consistent with Section 2.3.2 of the

Enforcement Policy.

71111.12Maintenance Effectiveness

Failure to Establish Goals to Monitor Steam Tunnel Check Dampers

Cornerstone Significance Cross-Cutting Report Section

Aspect

Mitigating Systems Green None 71111.12 -

NCV 05000373/2018003-03; Maintenance

05000374/2018003-03 Effectiveness

Closed

Introduction: The inspectors identified a finding of very low safety significance (Green) and an

associated NCV of 10 CFR 50.65(a)(1) for the licensees failure to establish goals to monitor

the performance of steam tunnel check dampers. Specifically, the licensees goals for

functional failure and condition monitoring could always be satisfied given a two years

monitoring period with only one testing opportunity.

Description:

The steam tunnel check dampers, a Maintenance Rule System, close in response to an

increase in air velocity or steam tunnel pressure due to a high energy line break in order to

prevent rupture of the ventilation duct wall adjacent to the high pressure core spray (HPCS)

switchgear room. There are three check dampers for each unit and each check damper has

a left and a right blades. Per the licensees updated final safety analysis report (UFSAR), a

rupture of the ventilation duct wall adjacent to the HPCS switchgear room could significantly

affect the design basis environment of the switchgear room. Therefore, a failure of steam

tunnel check damper to close could result in the loss of HPC

S.

The licensee performs surveillance procedure LMS-VT-01, TB Vent Return Air Riser Check

Damper Surveillance every outage to measure the latching force of the damper blade.

Acceptance criteria of the latching force for the blades are calculated by the licensee to

provide a reasonably high minimum setting to prevent inadvertent closure under normal

ventilation system flow conditions while assuring that the check dampers will close during a

postulated high energy line break.

The licensees Maintenance rule System Basis Document states that two failures of any left

damper plate on Unit 1 and any right damper plate on Unit 2 is a condition monitoring failure.

Also, the failure of all three left damper plates on Unit 1 and all three right damper plates on

Unit 2 is a function failure. It further states that testing of the dampers per procedure

LMS-VT-01 is performed once per refuel cycle during unit outages and that a monitoring

period of a two year cycle is established to allow for consecutive failures to be monitored

effectively. This criterion was in effect since 1996.

In March 2018, during a review of historical damper test results, the licensee determined that

the Maintenance Rule condition monitoring criterion for the steam tunnel check damper

1VT79YB left blade as-found latch force were exceeded in 2008, 2010, 2012, 2014, and

2016. The licensee entered this issue in the CAP as AR 4120441 and subsequently put the

system into Maintenance Rule (a)(1) category and developed an Maintenance Rule (a)(1)

action plan.

The inspectors reviewed the (a)(1) action plan and identified that the action plan did not

contain any corrective action to address the condition monitoring failures. Specifically, in the

(a)(1) action plan, the licensee revised procedure LMS-VT-01 to change the as-found latch

force measurement to be an average of ten readings and to add clearer instructions on how

to take the measurements. Further, the licensee revised the Maintenance Rule Functional

Failure criterion from less than or equal to 1 functional failure per Unit in a two-year

monitoring period to less than or equal to 2 functional failure per Unit in a four-year

monitoring period. The Condition Monitoring Criteria was changed from less than or equal to

failures per damper plate in a two-year cycle to less than or equal to 2 failures per damper

plate in a four-year cycle. The licensee also considered that procedure change was only an

enhancement and not to address any deficiency of the procedure.

The inspectors determined that the licensees Maintenance Rule performance goals are not

sufficient to provide reasonable assurance that the steam tunnel check dampers are capable

of fulfilling their intended functions. Specifically, in a two-year monitoring cycle, the licensee

only tests these dampers during a refueling outage and there is only one refueling outage

every two years. Therefore, the previous less than or equal to 1 functional failure per Unit in

a two-year monitoring period criterion is always satisfied and so is the new functional failure

criterion of less than or equal to 2 functional failure per Unit in a four-year monitoring period.

Similarly, the old Conditional Monitoring Criterion of less than or equal to 2 failures per

damper plate in a two-year cycle or the new criterion of less than or equal to 2 failures per

damper plate in a four-year cycle are also always satisfied.

Corrective Action: The system manager will review and evaluate the maintenance rule

criteria for the function to ensure that the established criteria is appropriate for performance

monitoring in accordance with 10 CFR 50.65a(1) and sufficient to provide assurance that the

system will perform its function.

Corrective Action Reference: AR 04180338

Performance Assessment:

Performance Deficiency: The licensee failed to establish goals to monitor the performance of

steam tunnel check dampers in accordance with 10 CFR 50.65(a)(1).

Screening: The inspectors determined the performance deficiency was more than minor

because it adversely affected the Mitigating System cornerstone attribute of Equipment

Performance to ensure the availability, reliability, and capability of systems that respond to

initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the

licensees Maintenance Rule Functional Failure and condition monitoring criteria are always

satisfied and was not sufficient to ensure the availability, reliability, and capability of the check

dampers.

Significance: The inspectors assessed the significance of the finding using SDP Appendix A,

The Significance Determination Process (SDP) for Findings At-Power. and determined that

the finding is of very low safety significance (Green) because it is not a deficiency affecting

the design or qualification of a mitigating Structures, Systems and Components (SSC), does

not represent a loss of system and/or function, does not represent an actual loss of function of

at least a single Train for greater than its Technical Specification Allowed Outage Time, and

does not represent an actual loss of function of one or more non-Technical Specification

Trains of equipment designated as high safety-significant for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Cross-Cutting Aspect: The inspectors determined that there was no cross cutting aspect

associated with this finding since none of the crosscutting aspects in IMC 0310 were

determined to be appropriate for this issue.

Enforcement:

Violation: Title 10 CFR 50.65(a)(1) requires, in part, that the licensee shall monitor the

performance or condition of structures, systems, or components, against licensee-established

goals, in a manner sufficient to provide reasonable assurance that these structures, systems,

or components, are capable of fulfilling their intended functions.

Contrary to the above, the licensee did not monitor the performance or condition of structures,

systems, or components, against licensee-established goals, in a manner sufficient to provide

reasonable assurance that these structures, systems, or components, are capable of fulfilling

their intended functions since 1996. Specifically, the licensees performance goals for steam

tunnel check dampers were not sufficient to provide reasonable assurance that the dampers

were capable of fulfilling their intended functions. The Maintenance Rule Functional Failure

and Condition Monitoring criteria can always be satisfied given the testing frequency and

monitoring periods.

Disposition: This violation is being treated as an NCV, consistent with Section 2.3.2 of the

Enforcement Policy.

71111.22Surveillance Testing

Failure to Manage the Increase in Risk During a Battery Charger Capacity Test

Cornerstone Significance Cross-Cutting Report

Aspect Section

Mitigating Green H.13 - 71111.22 -

Systems NCV 05000373/2018003-04 Consistent Surveillance

Closed Process Testing

Introduction: The inspectors identified a finding of very low safety significance (Green) and an

associated NCV of 10 CFR 50.65(a)(4) for the failure to manage risk when the licensee failed

to adhere to procedure WC-AA-101, Revision 28, On-line Work Control Process.

Specifically, procedural requirements regarding a dedicated operator for manual restoration

actions and written instructions to credit the availability of the A RHRSW pump during the

battery charger testing were not met.

Description:

On April 11, 2018, the inspectors observed routine surveillance testing of the 1AB Division I

25VDC battery charger using LES-DC-103A, Division I Battery Charger Capacity Test.

The inspectors noted that in preparation for the test, the licensee placed administrative

controls (i.e. a hand switch tag) on the 1A RHRSW pump and entered Technical

Specification Limiting Conditions for Operation (LCOs) 3.7.1 and 3.6.2.3 for the 1A RHRSW

pump. Administrative control of the 1A RHRSW pump was required during the battery

charger capacity test to prevent overloading the Division I switchgear, a condition that could

occur if the 1A RHRSW pump started while the 1AB and 1AA battery chargers were in

operation simultaneously.

The inspectors also reviewed the impact of the battery charger capacity test on plant risk and

noted that the licensee considered 1A RHRSW pump to be available in its online risk model.

After discussions with the licensee, the inspectors determined that manual operator action to

secure the battery charger load bank was being credited to maintain availability of the

1A RHRSW pump. Crediting manual operator action for equipment availability was a

method of managing the increase in plant risk from surveillance activities as required

by 10 CFR 50.65(a)(4). Guidance for crediting operator action was contained in

NUMARC 93-01, Revision 4A, Appendix B. The licensee implemented the NUMARC 93-01

guidance using procedure WC-AA-101, Attachment 6, Unavailability Guidelines.

Procedure WC-AA-101, Attachment 6, contained several requirements regarding operator

action for system restoration. Upon review, the inspectors determined that the licensee failed

to meet the requirements of WC-AA-101. Specifically, written guidance was not provided in

LES-DC-103A for system restoration and a dedicated operator was not assigned to the task.

The operator assigned for system restoration on April 11, 2018, was also the safe-shutdown

equipment operator and the Unit 1 rounds equipment operator.

Corrective Action: The licensee submitted a procedure change request for LES-DC-103A,

Division I Battery Charger Capacity Test to incorporate an attachment for restoration of

equipment and for OP-LA-101-111-1002, LaSalle Operations Philosophy Handbook to

clarify guidance on operator action for system availability.

Corrective Action Reference: AR 04153715

Performance Assessment:

Performance Deficiency: The inspectors determined that the failure to manage the increase

in risk during Division 1 battery charging testing in accordance with 10 CFR 50.65(a)(4) was a

performance deficiency. Specifically, procedural requirements regarding a dedicated operator

for manual restoration actions and written instructions to credit the availability of the A

RHRSW pump during the battery charger testing were not met.

Screening: The inspectors determined the performance deficiency was more than minor

because it adversely affected the Procedural 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 (i.e., core damage). Specifically, the lack of written guidance for securing from

the Division I 125VDC battery charger surveillance and the assignment of additional duties

(e.g. operator rounds) to personnel responsible to take manual actions would have impeded

restoration of the A RHRSW pump.

Significance: The performance deficiency involved the failure to mitigate increased risk in

accordance with 10 CFR 50.65(a)(4) while performing maintenance; therefore, the inspectors

used IMC 0609, Appendix K, Maintenance Risk Assessment and Risk Management

Significance Determination Process, and determined that the licensee would have to

re-perform the risk assessment, correcting for the equipment rendered inoperable during the

surveillance test. The licensee used their Paragon model for the risk assessment assuming

that the Division 1 RHRSW was unavailable during a 6-hour time. The top initiators in the

assessment were a turbine trip and a loss of offsite power. The incremental conditional core

damage probability (ICCDP) was conservatively calculated to be less than 1E-06/year. The

results of the licensee evaluation were reviewed by a Region III Senior Reactor Analyst (SRA)

and were determined to be reasonable; therefore, in accordance with IMC 0609, Appendix K,

since the ICCDP was not greater than 1E-06/year, the finding was determined to be of very

low safety significance (Green).

Cross-Cutting Aspect: The inspectors determined this finding affected the cross-cutting area

of human performance in the aspect of consistent process, where Individuals use a

consistent, systematic approach to make decisions. Risk insights are incorporated as

appropriate. The licensee had developed a similar surveillance, the Division II battery charger

capacity test, LES-DC-103B, and incorporated all of the necessary elements of

WC-AA-101 regarding dedicated operator manual restoration actions to credit availability.

However, the Division I battery charger capacity test, LES-DC-103A, did not. [H.13]

Enforcement:

Violation: Title 10 CFR 50.65(a)(4), Monitoring the Effectiveness of Maintenance at Nuclear

Power Plants, requires, in part, that before performing maintenance activities the licensee

shall assess and manage the increase in risk that may result from the proposed maintenance

activity.

Contrary to the above, on April 11, 2018, prior to performing maintenance, the licensee failed

to manage the increase in risk that may result from the proposed maintenance activity.

Specifically, the licensee failed to manage the increase in risk during the Division 1 battery

test. Procedure guidance regarding dedicated operator manual restoration actions including

written instructions to credit availability of the A RHRSW pump during surveillance testing

were not met.

Disposition: This violation is being treated as an NCV, consistent with Section 2.3.2 of the

Enforcement Policy.

71152Problem Identification and Resolution

Failure to Translate Fuel Oil Relief Valve Setting into Design Drawing of Record.

Cornerstone Significance Cross-Cutting Report Section

Aspect

Mitigating Systems Green None 71152 - Problem

NCV 05000373/2018003-05; Identification and

05000374/2018003-05 Resolution

Closed

Introduction: The inspectors identified a finding of very low safety significance (Green) and an

associated NCV of 10 CFR 50, Appendix B, Criterion III, Design Control, for the licensees

failure to assure that applicable regulatory requirements and the design basis were correctly

translated into specifications, drawings, procedures, and instructions. Specifically, the

licensee failed to accurately translate the Division III EDG fuel oil relief valve set point from

the design drawing of record, VPF-3411-10, to the fuel oil pressure operator rounds alert

value in the Division III EDG operating procedures.

Description:

On April 12, 2018, the inspectors observed a 24-hour endurance run of the Division I EDG,

performed under work order 1919109. As part of the review of the completed surveillance

documentation, the inspectors selected several of the operational parameters for evaluation

for compliance with the design bases documents for the ED

G.

As part of this evaluation, the inspectors noted that the Division I and II EDGs are equipped

with a fuel oil filter high differential pressure alarm to detect a fuel oil filter flow restriction as

described in Section 9.5.4.2 of the UFSAR. The alarm is set sufficiently low enough to allow

the duplex filter assembly to be changed during EDG operation, avoiding a stall condition.

The inspectors noted that the Division III EDGs are not equipped with an alarm to monitor fuel

oil filter differential pressure.

After discussions with the licensee, the inspectors determined that the licensee relied upon

operator rounds to indentify a fuel oil filter flow restriction for the Division III EDGs in place of

an alarm. Since the EDGs are equipped with a positive displacement fuel oil pump, a fuel oil

flow restriction in the fuel oil filter would be seen as a gradual increase in engine driven fuel oil

pump discharge pressure. In accordance with the EDGs operating procedure, operators

would take action to change the fuel oil filter by initiating a condition report once an operator

rounds alert value of 75 [psig] was reached.

The inspectors reviewed the Division III EDG fuel oil system design bases drawing,

VPF-3411-10, Revision 15, and noted the presence of a fuel oil relief valve with a setting of

[psig] between the engine driven fuel oil pump and the fuel oil filters. Based on a fuel oil

relief valve setting of 65 [psig] and an operator rounds alert value of 75 [psig], the inspectors

concluded that a degraded condition with the fuel oil filter could go undetected prior to an

EDG engine stall.

In response to the inspectors concerns, the licensee determined that the relief setting

of 65 [psig], listed on drawing VPF-3411-10, was different than the relief valve setting

installed in the plant (75 [psig]). The fuel oil relief valves with a setting of 75 [psig] + 7.5 [psig]

had been installed under part evaluation L90-06-0012, dated March 27, 1990. Part

evaluation L90-06-0012 determined that the set point change would not impact EDG

function, but failed to update design drawings or procedures impacted by the part evaluation

changing the relief setting. The licensee documented the issue in the CAP as AR 04144044.

The licensee determined that since the fuel oil relief valve could lift as low as 67.5 [psig]

possibly causing the engine to shut down due to the lack of fuel as described section 7 of the

EDG vendor manual, VETIP J-0155, that the operator rounds alert value for fuel oil pressure

was non-conservative. The licensee documented the issue in the CAP as AR 04137564.

Corrective Actions: The licensee is planning to correct the fuel oil relief valve set point on

drawing VPF-3411-10 and to revise the operator rounds alert value to 67 [psig] in the

Division III EDG operating procedures.

Corrective Action References: AR 04137564 and 04144044

Performance Assessment:

Performance Deficiency: The inspectors determined that the failure to correctly translate the

engine fuel oil pressure relief valve set point into EDG operating procedures was a

performance deficiency. Specifically, the failure to establish an operator rounds alert value

lower than the Division III EDG fuel oil pump discharge relief valve set point allowed a

degraded condition to go undetected.

Screening: The inspectors determined the performance deficiency was more than minor

because if left uncorrected, it would have the potential to lead to a more significant safety

concern. Specifically, if the Division III EDG positive displacement fuel oil pump discharge

pressure had increased due to fuel filter clogging, the relief valve could have lifted, resulting in

an engine stall. Since the Division III EDG is not equipped with an alarm that monitors this

parameter and the operator rounds alert value was non-conservative, it is possible that fuel

filter blockage would have gone undetected by operations prior to an engine stall.

Significance: The inspectors assessed the significance of the finding using IMC 0609

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

was screened against the Mitigating Systems cornerstone and determined to be of very low

safety significance (Green) because the answer to each of the screening questions was no.

Cross-Cutting Aspect: No cross cutting aspect was assigned to this finding because the

inspectors determined the finding did not reflect present licensee performance.

Enforcement:

Violation: Title 10 CFR 50, Appendix B, Criterion III, Design Control, requires, in part, that

measures be established to assure that applicable regulatory requirements and the design

basis are correctly translated into specifications, drawings, procedures, and instructions.

Contrary to the above, on March 27, 1990, the licensee failed to assure that applicable

regulatory requirements and the design basis were correctly translated into specifications,

drawings, procedures, and instructions. Specifically, the licensee failed to translate the relief

valve setting determined in part evaluation L90-06-0012 for the division III EDG fuel oil relief

valve to the design drawing of record, VPF-3411-10, resulting in a non-conservative fuel oil

pressure operator rounds alert value in the Division III EDG operating procedures.

Disposition: This violation is being treated as an NCV, consistent with Section 2.3.2 of the

Enforcement Policy.

Unresolved Item Potential Failure to Inspect Containment Post-Tensioned 71152 - Problem

(Open) Tendons per Code Requirements and to Follow Corrective Identification and

Action Program Process Resolution

05000373/2018003-06; 05000374/2018003-06

Description:

Vertical and horizontal post tensioned tendons, along with reinforcing steel, are required to

maintain structural integrity of the primary containment. There are a total of 120 vertical post

tensioned tendons along the periphery of the primary containment wall, including 60 Group C

tendons and 30 each of Groups A and B. Section 5.5.6 of the Technical Specifications

describes the Inservice Inspection (ISI) program for post tensioning tendons and states that the

Tendon Surveillance Program shall be in accordance with ASME Section XI, Subsection IWL as

required by 10 CFR 50.55a.

One Group B tendon (V213B) on Unit 1 was inspected in 1999 and according to the inspection

records, water was identified on all components of the tendon. No presence of water is one of

the acceptance criteria per Subsection IWL of the ASME Section XI. No condition report was

found for this adverse condition. Subsequently, a condition involving degraded vertical tendons

was identified during inspections in 2003 and documented in AR 157920157920 The degradation

consisted of broken wires. The Root Cause Report (RCR) for this condition noted that

Group A tendons were found degraded and water induced corrosion was the root cause for

tendon degradation. The evaluation concluded that five Group A tendons and all 30 Group B

tendons in each unit were not susceptible to water intrusion because they were protected by

welded covers. These tendons with welded covers were also determined to be inaccessible,

and therefore exempt from future inspections requirements in accordance with provisions of

ASME Section XI, IWL. The RCR did not address the condition of water found during the Group

B tendon inspection in 1999. Additionally, to verify this assumption of welded covers providing

protection from water intrusion, a corrective action was generated to inspect one Group A and

one Group B inaccessible tendons during the next outage.

Pertaining to inaccessible tendons, the inspectors noted the following requirements

of 10 CFR 50.55a(b)(2)(viii)(E):

Concrete containment examinations: Fifth provision. For Class CC applications, the

applicant or licensee must evaluate the acceptability of inaccessible areas when

conditions exist in accessible areas that could indicate the presence of or the result in

degradation to such inaccessible areas. For each inaccessible area identified, the

applicant or licensee must provide the following in the ISI Summary Report required by

IWA-6000:

(1) A description of the type and estimated extent of degradation, and the conditions that

led to the degradation; (2) An evaluation of each area, and the result of the evaluation;

and (3) A description of necessary corrective actions.

After the licensee identified degraded group A tendon locations, to comply with the provision of

CFR 50.55a, the licensee documented in its 90 day post outage ISI reports information on

the degraded A tendons in 2004 and 2005 for units 1 and 2, respectively. This information

included an assumption that the extent of degradation did not apply to the Group B tendon

locations because of a welded cover at locations that precluded entry of water. Additionally, a

corrective action, CA 157920-33, was generated to inspect one Group A and one Group B

tendon during the next refueling outage to verify this assumption. The corrective action was

closed without inspection of any Group B tendon based on a management decision following

satisfactory inspection of a Group A tendon in 2006. The licensees decision failed to take into

account the fact that the most recent inspection of a Group B tendon showed presence of water

on tendon components and also that the welded closure details were different for tendons in the

two groups.

Subsequently, the licensee identified a concern regarding inadequate closure of this corrective

action during its reviews for the license renewal application in 2014. Specifically, the licensee

wrote AR 1658189 to document that due to the differences in the welded cover designs, the

results of the Group A tendon inspection may not be applicable to Group B tendons. Therefore

the critical assumption regarding the adequacy of Group B tendon covers remained unverified.

In particular, the Group B tendon cover used dissimilar metal welds and water was found inside

the cover during the most recent inspection. The licensee identified actions to perform

inspections on two of the Group B tendons on each unit in addition to inspecting the tendon

V213B where water was initially found. These actions were categorized as action tracking

items (ACITs), items that do not represent conditions adverse to quality. Since water was found

on all tendon components during the last inspection of a Group B tendon, and water induced

corrosion was found to be the root cause of many tendon failures, the assumption in the RCR

that the welded covers would prevent water intrusion needed to be validated through

inspections.

This unresolved item remains open pending additional inspector review of the issue with respect

to regulatory requirements.

Planned Closure Action: Inspectors will seek additional information from the licensee and the

NRC will perform internal review to evaluate compliance with NRC regulations.

Licensee Action: None

Corrective Action Reference: AR 4186365

Unresolved Item Potential Failure to Promptly Correct the Unit 2 71152 - Problem

(Open) Primary Containment Wall Cavity Leakage Condition Identification and

and to Follow Corrective Action Program Process Resolution

05000374/2018003-07

Description:

Condition description in AR 2420888 indicated that leakage through the Unit 2 primary

containment wall has been a longstanding open issue. The leak was initially identified in 1998

when water leakage was noticed on the external side of the primary containment wall. The

leakage was approximately 20-25 drops per minute at the primary location and multiple

areas near the 180 degree azimuth at construction joints on elevations 813 and 795. Another

minor leak was noticed at a similar location near the 0 degrees azimuth. The condition

was documented in AR 2269. The source of water leakage was determined to be a

weld on a 2 fuel pool cooling drain line and work order 98109950 was initiated to repair the

weld. The work was not scheduled and the work order was eventually cancelled. In 2010,

the leakage was documented again in AR 1086083. A technical evaluation documented as

ATI-1470953-18-47 in 2014 concluded that there was no adverse impact on structural

adequacy of the containment. The technical evaluation stated that the leakage was to be

repaired in the upcoming outage through work order 855785.

Action request 2420888 was written in December 2014 to re-enter the condition in the CAP. It

recommended corrective actions for liner ultrasound testing every other refueling outage,

completion of weld repair, and performance of a technical evaluation for structural impact on the

concrete, reinforcing steel, tendons, and liner. The technical evaluation assignment was closed

to the evaluation documented under ATI-1470953-18-47 discussed above. The corrective

action assignment for the weld repair was closed to a work order which has not been completed

to-date.

Based on the inspectors review, the licensee has deferred the actions to correct this condition

identified in 1998. The inspectors question whether the continuous leakage could lead to

deterioration of the concrete, corrosion of the reinforcement, or degradation of post tensioned

tendons if it enters the tendon sheath or trumpet area; and therefore a condition adverse to

quality.

This unresolved item remains open pending additional inspector review of the issue with respect

to regulatory requirements.

Planned Closure Action: Inspectors will seek additional information from the licensee and the

NRC will perform internal reviews to evaluate compliance with NRC regulations.

Licensee Action: None

Corrective Action Reference: AR 4186369

71153Follow-Up of Events and Notices of Enforcement Discretion

Failure to Implement Engineering Change Results in Reactor Coolant Boundary Leakage

Cornerstone Significance Cross-Cutting Report Section

Aspect

Initiating Events Green H.4 - Teamwork 71153 - Follow-

NCV 05000373/2018003-08 Up of Events and

Closed Notices of

Enforcement

Discretion

The inspectors documented a self-revealed finding of very low safety significance (Green)

and associated NCVs of TS 5.4.1 Procedures, and TS 3.4.5 for the failure to implement

EC 354539 to perform the final piping weld for the 1B33-F067B bonnet vent line in the field,

resulting in pressure boundary leakage when the weld failed at power.

Description:

On March 20, 2018, the licensee noticed a rising trend in Unit 1 drywell particulate level and

received a drywell containment area monitor particulate alarm on March 21, 2018. On

March 22, 2018, the licensee reduced power to make a drywell entry to investigate the cause

of the rising particulate trend and increase in unidentified reactor coolant leakage. During the

entry, a two and a half to three foot steam plume was identified on the 1B reactor recirculation

loop discharge valve bonnet (1B33-F067B). The steam plume was from the weld connecting

the inspection port/vent line piping to the loop discharge valve bonnet. The licensee

documented the issue in the CAP as AR 4117757. Additionally, the licensee submitted

licensee event report (LER) 2018-004-00, Technical Specification Required Shutdown due

to Reactor Pressure Boundary Leakage.

The licensee performed a root cause investigation and determined that the leak on the loop

discharge valve bonnet was due to increased pipe stress leading to fatigue related cracking.

Two contributing causes led to the increased pipe stress. First, the EC stated that the final

piping weld shall be completed in the field. The work group determined that the final piping

weld would be completed in the fabrication shop to reduce radiation dose to the welders

instead of the field as directed by the EC. When the weld was done in the fabrication shop on

February 13, 2018, a mockup was used to support the vent line piping for the weld. The

supports were removed and the bonnet with vent piping were transported and fit up in the

field. When the installation in the field was complete, the mean tensile stress was increased

on the top surface of the pipe due to the unsupported condition, the dead weight of the pipe

and valves, and the downward force created by the defection of the support member.

Second, when the fit up was done in the field, the work order for installation of the clamp that

secured the piping in place did not contain instructions for clearances between the clamp and

the piping that would have minimized stress applied to the piping. The combination of these

two effects increased the pipe stress, resulting in the fatigue related crack and the weld

failure.

Corrective Action: The leak was repaired by removing the vent valve and piping and welding

a plug in place.

Corrective Action Program Reference: AR 4117757

Performance Assessment:

Performance Deficiency: The inspectors determined that the failure to implement EC 354539

to perform the final piping weld for the 1B33-F067B bonnet vent line in the field resulting in

pressure boundary leakage was a performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor

because it adversely affected the Equipment Performance attribute of the Initiating Events

cornerstone objective to limit the likelihood of events that upset plant stability and challenge

critical safety functions during shutdown as well as power operations. Specifically, performing

the final weld in the maintenance shop instead of the field contributed to increased pipe stress

loading leading to fatigue related cracking of the weld and reactor pressure boundary

leakage.

Significance: Using IMC 0609, Appendix A, The Significance Determination Process for

Findings At-Power, issued June 19, 2012, the finding was screened against the Initiating

Events cornerstone and determined to be of very low safety significance (Green) because the

finding did not result in exceeding the reactor coolant system leak rate for a small break loss

of coolant accident (LOCA) nor affected other systems used to mitigate a LOCA resulting in

total loss of function after a reasonable assessment of degradation,

Cross-Cutting Aspect: The inspectors determined this finding affected the cross-cutting area

of Human Performance in the aspect of team work, where individuals and work groups

communicate and coordinate their activities within and across organizational boundaries to

ensure nuclear safety in maintained. Specifically, the maintenance work group failed to

communicated and coordinate with the engineering staff and radiation protection work group

their intent of completing the final weld in the maintenance shop to further reduce radiation

dose to the maintenance workers. [H.4]

Enforcement:

Violation: Technical Specification Section 5.4.1 states, in part, that written procedures shall

be established, implemented, and maintained covering the applicable procedures

recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

NRC Regulatory Guide 1.33, Appendix A, Section 9 addresses Procedures for Performing

Maintenance and Section 9.a, states, in part, Maintenance that can affect the performance

of safety-related equipment be performed in accordance with written procedures, documented

instructions, or drawings appropriate to the circumstances.

Engineering Change 354539, Revision 1, Step 5 states, in part, Then only final connection

weld involving the in-place piping 1RR32AB-3/4 at the 90 degree SW elbow will need to be

made and tested in the field. This EC provided instructions for the piping installation.

Contrary to the above, on February 13, 2018, the licensee failed to implement maintenance

procedure in accordance with TS 5.4.1. Specifically, the licensee completed the final

connection weld involving the in-place piping 1RR32AB-3/4 at the 90 degree SW elbow in

the maintenance shop instead of the field as opposed to Step 5 of EC 354539, Revision 1.

This contributed to increased pipe stress loading, leading to fatigue related cracking of the

weld and reactor pressure boundary leakage while the plant was in Mode 1.

Technical Specification 3.4.5 a, RCS Operational Limits, states, RCS operational

LEAKAGE shall be limited to No pressure boundary leakage, and states, if pressure

boundary leakage is present, the plant is required to be in Mode 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4

in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

Contrary to the above, the plant was not in Mode 2 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> after

the licensee identified an indication of RCS leakage on March 20, 2018. With the plant

entering Mode 3 on March 22, 2018, that period was greater than the allowed completion time

by the limiting condition for operation provided in TS. 3.4.5.

Disposition: These violations are being treated as NCVs, consistent with Section 2.3.2 of the

Enforcement Policy.

This closed LER 2018-004-00.

EXIT MEETINGS AND DEBRIEFS

The inspectors confirmed that proprietary information was controlled to protect from public

disclosure. No proprietary information was documented in this report.

• On October 11, 2018, the inspectors presented the quarterly integrated inspection results to

Mr.

W. Trafton, and other members of the licensee staff.

• On July 13, 2018, the inspectors presented the ultimate heat sink triennial inspection results

to Mr.

W. Trafton, Site Vice President, and other members of the licensee staff.

• On August 24, 2018, the inspectors presented the radiation protection program inspection

results to Mr.

W. Trafton, Site Vice President, Mr.

J. Washko, Plant Manager and other

members of the licensee staff.

• On September 27, 2018, the inspector presented the annual follow-up of selected issues

inspection results to Mr.

T. Riddle, Senior Design Engineering Manager, and other members

of the licensee staff.

DOCUMENTS REVIEWED

- AERR; Annual Radiological Effluent Release Report, LaSalle County Nuclear Power

Station; 2017

- AR 00002269; Document Actions Being Taken to Correct Water That is Leaking; 03/29/1999

- AR 04006903; April 2014 REMP Anomalies and Missed Samples; 05/05/2017

- AR 04104376; Self-Assessment Title; NRC Inspection: Radioactive Gaseous and Liquid

Effluent Treatment (RETS) (IP 71124.06); 06/11/2018

- AR 04144025; REMP 2017 Roll-Up of Sampling Anomalies and Missed Samples; 06/04/2018

- AR 04144036; REMP 2016 Roll-Up of Sampling Anomalies and Missed Samples; 06/04/2018

- AR 04147239; 2018-Q1 Summary of Anomalous and Missed Samples; 06/14/2018

- AR 0733776; FME Found in 1A RHR Heat Exchanger; 02/09/2008

- AR 1497929; GE Transfer of Part 21 Information RPS EPMA MCCB

- AR 157920157920 Root Cause Investigation of the LaSalle Containment Tendon Wire Failures;

05/08/2003

- AR 1589737; Long Term Outage Group Actions (Assignments 24, 25); 11/25/2013

- AR 1658189; Upper B Tendon Inspection Needed; 05/09/2014

- AR 1697948; Work Needed for Tendon Inspection in L1R16; 08/29/2014

- AR 2420888; Unit 2 Reactor Cavity Skirt Plate to Drain Line Leakage; 12/04/2014

- AR 2539023; 2B33-F067B Leakage, Cracked Weld on Inspection Port; 8/7/2015

- AR 3987641; Containment Monitoring (CM) Valves Performance Trend; 3/21/2017

- AR 4055696; 1CM022A Closed Indication Failed to Light; 9/25/2017

- AR 4056034; 1CM022A Closed Indication Failed; 9/26/2017

- AR 4081458; LTS-200-17 Rev 16 Needs Revision; 12/06/2017

- AR 4109860; 1B RHR HX Partition Plate Needs Repair; 03/01/2018

- AR 4109865; 1B RHR HX Sill Plate Needs Repaired; 03/01/2018

- AR 4111053; 1CM022A Failed to Give Closed Indication; 3/4/2018

- AR 4111682; 1B RHR HX Partition Repairs Delayed Until L1R19; 03/06/2018

- AR 4115114; Entered LOA-Wl-001 On Low Lake Level; 03/15/2018

- AR 4117757; RM1B33-F067B Vent Line Leak; 3/22/2018

- AR 4123038; 2A RHR Heat Exchanger Report Not Filed; 04/04/2018

- AR 4123044; LOS-DG-SR6 Does Not Match Calc L-002404 Rev 004A; 04/04/2018

- AR 4126072; Self-Assessment Title; Focused Self-Assessment for Post-Accident Gaseous

Effluent Monitoring (NUREG 0737); 06/27/2018

- AR 4128357; Upstream HEPA Filter Could Not Be Tested; 4/18/2018

- AR 4130025; Unit 2 VG HEPA Filter Leakage Testing; 4/23/2018

- AR 4131522; 1VY02A D/P Exceeds LOS-DG-SR7 Acceptance Criteria; 04/27/2018

- AR 4133231; 1VY02A D/P Exceeds LOS-DG-SR7 Acceptance Criteria; 05/01/2018

- AR 4137564; PCRAs Needed for Division 3 DG Procedures; 5/14/2018

- AR 4140275; 2VY03A DP Exceeds LOS-DG-SR6 Acceptance Criteria; 05/23/2018

- AR 4144044; CCP Drawing Descrepencies (sic) Identified22078 and VPT-3411-10

- AR 4148618; NRC IDUHS InspectionMaterial Found in U1 B/C RHR Room; 06/19/2018

- AR 4148627; NRC IDUHS InspectionUFSAR Table 6.2-2 Discrepancy; 06/19/2018

- AR 4148633; NRC IDUHS InspectionDiscrepancy in GL 89-13 Prog Doc; 06/19/2018

- AR 4148638; NRC IDUHS InspectionDiscrepancy in GL 89-13 Prog Doc 2; 06/19/2018

- AR 4148978; NRC IDUHS InspectionLSH Housekeeping Issues; 06/19/2018

- AR 4149479; NRC ID: Potential NCV For Non-Conformance with OM Code; 06/22/2018

- AR 4149506; Incorrect EC Number Recorded During RHR Heat Exchanger Test; 06/22/2018

- AR 4149537; NRC IDUHS Inspection - ER-AA-340-1002 HX Inspection Proc; 06/22/2018

- AR 4154585; 2B21-N413C OOT Trend Code B2; 7/10/2018

- AR 4159603; Alternative Instrument Used for LOS-AA-S101 Reading; 7/28/2018

- AR 4166455; 2A RPS MG Set Output Breaker Did Not Trip; 8/23/2018

- AR 4169451; 4.0 Critique for L2M20 Shutdown and Manual SCRAM; 9/2/2018

- AR 4170700; Low VG Flow on S/U of U1 VG Train

- ATI 1470953-18-47; Actions Supporting Issues Identified by LS-AA-2001; 07/29/2014

- Balance-of-Plant Heat Exchanger Inspection, Testing and Maintenance Guide; Revision 8EO

Rounds Lake Level From 06/14/2018 to 06/18/2018

- C-1977; General Arrangement Triton-Xl Butterfly Valve 54 Butterfly Valve Outlet; Revision 4

- Calc.97-201; Thermal Model of ComEd/LSCS RHR Heat Exchangers 1(2)RH01A & B;

Revision A02

- Calc. L-000715; Water Hammer Evaluation on Units 1 & 2 Division 1 RHR Service Heat

Exchanger CSCS Subsystems; Revision 1A

- Calc. L-000718; Determination of Potential Water Hammer Forces at the RHR Heat

Exchanger from a Postulated RHRSE Void Formation; Revision 1A

- Calc. L-000731; Evaluation of the RHR Heat Exchangers for Water Hammer Effect;

Revision 2A

- Computer Data Point 1(2)LT-SW014 Lake Level From 06/14/2018 to 06/18/2018

- CY-AA-130-3010-F-01; Dose Equivalent Iodine (DEI); October 2017 through June 2018

- CY-AA-170-2001; Airborne Tritiated Water Analysis; Revision 0

- CY-LA-170-201 Attachment 1; Station Vent Tritium Concentration in Air Sample Information

Sheet; Sample Point SVS; 08/22/2018

- CY-LA-170-201; Station Vent Stack Airborne Tritiated Water Sampling; Revision 3

- CY-LA-170-3002; Quarterly/Annual Total Dose Report; October 2017 through June 2018

- CY-LA-170-301; Offsite Dose Calculation Manual; Revision 9

- Determination IR 2741412; MR LAS-2-CM-01; 2PL76J and 2PL77J (Unit 2 Post-LOCA

H2/O2 Monitors); 3/28/2017

- Drawing 1; Contoured Depths Ultimate Heat Sink LaSalle County Station LaSalle County,

Illinois; 07/06/2016

- Drawing 2; Contoured Depths Ultimate Heat Sink LaSalle County Station LaSalle County,

Illinois; 07/06/2016

- Drawing 3; Contoured Depth Difference Map Ultimate Heat Sink LaSalle County Station

LaSalle County, Illinois; 07/06/2016

- Drawing ID 18073; General Electric Co. Engine Fuel Oil Schematic EMO 20-645-E4; 2600

KW Generator Set; Revision C

- Drawing S-326; Sections and Details, Reactor Containment Liner Plate, Sheet 1; Revision AE

- Dwg. 731E96AA; Process Diagram RHR System; Revision 7

- Dwg. VPF3161-002; RHR Heat Exchangers; Revision D

- EC 354539-001; Replace Double Block Valve Assembly 1B33-F068B/69B With Two Single

Valves in Series; 3/15/2018

- EC 369448; Alternate Detail for RHR Heat Exchanger Partition Plate to Sill Plate Bolted

Connection; Revision 0

- EC 405711; Reevaluation of VY Cooler Performance for OE 16-003 After Cleaning Results

and Recommendations; Revision 10

- EC 622290; Evaluation of Unit 1B RHR Heat Exchanger Thermal Performance Data Using

Alternate (EPRI) Methodology (1E12-B001B); Revision 0

- EC 623376; Evaluation of the 1B RHR Heat Exchanger Eddy Current Testing; Revision 0

- EC625394; LaSalle Channel Distortion Criteria Update Due to L2M20 Failure of Rod 30-31 to

SCRAM; Revision 0

- Environmental Incorporated Midwest Laboratory; Sampling Procedure Manual; Revision 15

- Failure Classification LAS-1-CM; IR 4081910; Troubleshooting for Failure of 1CM022A Valve

will not be Completed until L1R17; 12/7/2017

- Gas Permit Post-Release Data; Permit Number G-20170717-204-C; Al. Gaseous Release

Point; 07/21/2017

- Generic Letter 89-3 Program Basis Document; Revision 13

- IR 4117757; Root Cause Investigation of 1B33-F067B Vent Line Leak; 3/22/2018

- IR 4169154; Event/Issues Report: Unit 2 Rod 30-31 Did Not Fully Insert During SCRAM;

9/2018

- LAS-0-2018-0024; Risk Issue, Primary Containment B Tendons; Revision 1

- LAS-2-CM; IR 2542067; MRFF Functional Failure Occurs when Both Division 1 [1(2)PL76J]

and Division 2 [1(2)PL77J] post-LOCA Panels are Inoperable; 10/13/2015

- LAS-2-CM; Maintenance Rule System Basis LaSalle 2; Emergency Operation of the

Post-LOCA Accident Primary Containment Atmosphere Hydrogen and Oxygen Monitors

- LAS-2-CM-01; IR 2729354; MRFF During Maintenance per WO 1611471-01 to Replace

Regulators and Perform Leak Testing 2PL77J was Declared Inoperable; 12/17/2016

- LaSalle Inservice Testing Program; Valve Component Basis Summary; Page 1 of 2

- LCP-310-52; Wide Range Gas Monitor Normal Noble Gas, Iodine, and Particulate Sampling;

Revision 12

- LCP-840-21; Post Accident Sampling of the General Atomic Wide Range Gas Monitor;

Revision 7

- LES-DC-103A; Surveillance/Plant Interface Information; Revision 21

- Letter, Exelon to NRC; Post Outage 90-Day Inservice Inspection Summary Report for L1R10;

05/07/2004

- LGA-003; Primary Containment Control; Revision 17

- LOA-CW-101; Unit 1 Circulating Water System Abnormal; Revision 23

- LOA-CW-201; Unit 2 Circulating Water System Abnormal; Revision 22

- LOA-WL-001; River Screen House And Lake Abnormal; Revision 13

- LOP-CW-09; Circulating Water System Ice Melting (CW); Revision 19

- LOP-DG-02; 0 Diesel Generator Readings; Revision 66

- LOP-DG-04; Diesel Generator Special Operations; Revision 76

- LOP-RH-14; Backwash Of The Residual Heat Removal Service Water Strainers; Revision 14

- LOR-1H13-P601-A104; Diesel Generator 1B Cooling Water Pump Trouble/Strainer;

Revision 4

- LOR-1H13-P601-A502; 1B DG Fuel or Fuel Oil Transfer Pump Failure; 74/1D0029,

1E22-K44; Revision 4

- LOR-1H13-P601-B112; 1A RHR Service Water Radiation High; Revision 1

- LOR-1H13-P601-B204; RHR Service Water Strainer 1E12-D300B Differential Pressure

High; Revision 4

- LOR-1H13-P601-C202; RHR Service Water Strainer 1A Differential Pressure High;

Revision 3

- LOR-1PM01J-A516; 0 Diesel Generator Cooling Water Strainer 0DG01F Diff. Press. High;

Revision 2

- LOR-1PM01J-B306; Diesel Generator 1A Cooling Water Strainer Differential Pressure High;

Revision 1

- LOS-RH-Q4; Cycling CSCS Bypass Line Isolation Valve; Revision 5

- LS-MISC-26; LaSalle 2014A Risk Ranking of Heat Exchangers; Revision 2

- MR Function Evaluation LAS-1-CM-01; Emergency Operation of Post-LOCA Accident

Primary Containment Atmosphere Hydrogen and Oxygen Monitors; 8/3/2018

- MR Function Evaluation LAS-2-RH; RH-01 Suppression Pool Cooling; 5/15/2018

- Murray and Trettel, Incorporated; Meteorological Monitoring Tower Inspection Report;

06/27/2018

- Murray and Trettel, Incorporated; Monthly Report on the Meteorological Monitoring Program at

the LaSalle County Nuclear Generating Station; 05/2018

- NOSA-LAS-18-04 (AR 4133019); Chemistry, Radwaste, Effluent and Environmental

Monitoring Audit Report; 06/20/2018

- NSWP-M-04; Pipe Support Installation and Inspection Work Procedure; Revision 3

- Operations Log; 5/15/2018-5/16/2018

- OP-LA-1010-111-1002; LaSalle Operations Philosophy Handbook; Revision 74

- PI-AA-125; Corrective Action Program (CAP) Procedure; Revision 6

- PORC 18-018; L2M20; 9/2/2018

- RA-05-48; Letter, Exelon to NRC; Post Outage 90-Day Inservice Inspection Summary Report

for L2R9; 06/10/2005

- VM J-0155.000; Vendor Equipment Technical Information Program (VETIP); Stationary Power

Operators Manual, by Electro-Motive (GM); Undated

- WC-AA-101; On-Line Work Control Process; Revision 28

- WO 1628656; Disassemble RHR HT Exchanger to Inspect Service Water Baffle; 06/17/2014

- WO 1628657; (Finish) Eddy Current Test 2E12-B001B B RHR Heat Exchanger; 08/12/2014

- WO 1691942; Inspection of North End of WS Tunnel for Corbicula; 10/31/2015

- WO 1709981; (Finish) LTS-200-17, RHR HX Heat Xfer Test; 12/08/2017

- WO 1745529-01; IM-EWP-0TC-VC050B B VC EMU Train HTR Manual Thermal Cut-Out;

9/18/2018

- WO 1771573; CSCS Pond Sediment Deposition Check; 06/08/2016

- WO 1803817-01; IM-EWP-0TC-VC050AThermal Cutout for Heater 01AB; 9/18/2018

- WO 1820988; Clean Unit 1 A CW Inlet Bay & Bypass Line; 03/24/2017

- WO 1841825; LOS-RH-Q1 2B RHR WS Operability & Inservice Test; 09/22/2015

- WO 1843208-01; EQ, IM EQPReplace Capacitors in Flow Controller, E: 1FC-VG003-CX,

FC; 8/15/2018

- WO 1891296; Inspection of South End of WS Tunnel for Corbicula and Sedim; 12/07/2017

- WO 1909979; Disassemble RHR HT Exchanger to Inspect Service Water; 01/24/2018

- WO 1911195; (Finish) Eddy Current Test 1E12-B001B B RHR Heat Exchanger; 08/15/2017

- WO 1914236; LOS-RH-Q1 1B RHR WS Operability & Inservice Test; 07/01/2016

- WO 1916130-06; EM 2E12-F064C Klockner Moeller MCC 2AP83E-E6 Cubicle Replacement;

9/1/2018

- WO 1916130-07; EM 2E12-F064C Klockner Moeller MCC 2AP83E-E6 Cubicle Replacement;

9/1/2018

- WO 1918632-01; Charcoal Sample from Standby Gas Treatment Train 2; 04/18/2018

- WO 1918633-01; Standby Gas Treatment HEPA Filter Test; 4/19/2018

- WO 1918634-01; Standby Gas Treatment Charcoal Filter Leak Test; 4/19/2018

- WO 1925828-01; SBGT Filter Flow; 03/20/2018

- WO 1937465; LOS-RH-Q1 1B RHR WS Operability & Inservice Test; 10/03/2016

- WO 4654877; LRA LOS-RH-Q1 2B RHR WS Operability & Inservice Test; 09/21/2017

- WO 4657164-01; Replace LPCS/RHR A Inj Vlvs Reactor Press Intlk Switch; 7/11/2018

- WO 4662023; LOS-RH-Q4 Cycle 0E12-F300; 10/07/2017

- WO 4696391; LOS-RH-Q4 Cycle 0E12-F300; 01/09/2018

- WO 4702757-01; "B" Upper End Welded Tendon Cover Visual Inspection; 02/19/2018

- WO 4731733; LRA LOS-RH-Q1 1B RHR WS Operability & Inservice Test; 03/29/2018

- WO 4734043; LOS-RH-Q4 Cycle 0E12-F300; 04/10/2018

- WO 4774779-01; Upstream HEPA Filter Could Not Be Tested; 4/19/2018

- WO 4804454-01; LOS-VG-M1 U1 SBGT Att 1A; 8/6/2018

- WO 4817293-01; LOS-VG-M1 U1 SBGT Att 1A; 9/4/2018

- WO 4822297-05; 2CM028 Failed to Close; 8/30/2018

- WO 4822297-06; 2CM028 Failed to Close; 9/2/2018

- WO 4827192-01; IM EWPReplace Capacitors in Flow Controller; 9/7/2018

- WR Task 970003727-02; Inspect Tendon V213B; 04/05/1999

31