ML100410121

IR 05000237-09-005, 05000249-09-005, on 10/01/09 - 12/31/09; Dresden Nuclear Power Station, Units 2 & 3; Equipment Alignment, Operability Evaluations, Post-Maintenance Testing, Surveillance Testing, Outage, and Event Follow-up

ML100410121
Person / Time
Site:	Dresden
Issue date:	02/10/2010
From:	Ring M NRC/RGN-III/DRP/B1
To:	Pardee C Exelon Generation Co, Exelon Nuclear
References
IR-09-005
Download: ML100410121 (62)

See also: IR 05000237/2009005

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION III

2443 WARRENVILLE ROAD, SUITE 210

LISLE, IL 60532-4352

February 10, 2010

Mr. Charles G. Pardee

Senior Vice President, Exelon Generation Company, LLC

President and Chief Nuclear Officer (CNO), Exelon Nuclear

4300 Winfield Road

Warrenville, IL 60555

SUBJECT:

DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3

INTEGRATED INSPECTION REPORT 05000237/2009-005;

05000249/2009-005

Dear Mr. Pardee:

On December 31, 2009, the U.S. Nuclear Regulatory Commission (NRC) completed an

integrated inspection at your Dresden Nuclear Power Station, Units 2 and 3. The enclosed

report documents the inspection results, which were discussed on January 14, 2010, with

Mr. T. Hanley 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.

The report documents two NRC-identified findings and five self-revealed findings of very low

safety significance (Green). All of these findings were determined to involve a violation of

NRC requirements. Additionally, one licensee-identified violation is listed in Section 4OA7 of

this report. 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

(NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy.

If you contest any NCV, 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; 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352, the Director,

Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and

the NRC Resident Inspector at Dresden. In addition, if you disagree with the characterization of

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 III, and the NRC Resident Inspector at Dresden. The information you provide will be

considered in accordance with Inspection Manual Chapter 0305.

C. Pardee

-2-

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its

enclosure, and your response (if any) will be made available electronically for public inspection

in the NRC Public Document Room or from the Publicly Available Records (PARS) component

of NRCs document 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/

Mark A. Ring, Chief

Branch 1

Division of Reactor Projects

Docket Nos. 50-237; 50-249

License Nos. DPR-19; DPR-25

Enclosure:

Inspection Report 05000237/2009-005; 05000249/2009-005

w/Attachment: Supplemental Information

cc w/encl:

Distribution via ListServ

Enclosure

U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Docket Nos:

50-237; 50-249

License Nos:

DPR-19; DPR-25

Report No:

05000237/2009-005; 05000249/2009-005

Licensee:

Exelon Generation Company

Facility:

Dresden Nuclear Power Station, Units 2 and 3

Location:

Morris, IL

Dates:

October 1 through December 31, 2009

Inspectors:

C. Phillips, Senior Resident Inspector

D. Meléndez-Colón, Resident Inspector

J. Benjamin, Project Engineer

J. Draper, Reactor Engineer

D. Sand, Reactor Engineer

C. Moore, Operations Engineer

F. Ramírez, Resident Inspector, LaSalle Station

J. McGhee, Senior Resident Inspector, Quad Cities

M. Holmberg, Reactor Inspector

M. Mitchell, Health Physicist

R. Jickling, Senior Emergency Preparedness Inspector

L. Kozak, Senior Reactor Analyst

Approved by:

M. Ring, Chief

Projects Branch 1

Division of Reactor Projects

Enclosure

TABLE OF CONTENTS

SUMMARY OF FINDINGS ...........................................................................................................1

REPORT DETAILS.......................................................................................................................6

Summary of Plant Status...........................................................................................................6

1.

REACTOR SAFETY .......................................................................................................6

1R04

Equipment Alignment (71111.04) ......................................................................6

1R05

Fire Protection (71111.05).................................................................................9

1R08

Inservice Inspection Activities (71111.08G).....................................................10

1R11

Licensed Operator Requalification Program (71111.11) .................................11

1R12

Maintenance Effectiveness (71111.12) ...........................................................12

1R13

Maintenance Risk Assessments and Emergent Work Control (71111.13)......13

1R15

Operability Evaluations (71111.15)..................................................................13

1R19

Post-Maintenance Testing (71111.19).............................................................16

1R20

Outage Activities (71111.20) ...........................................................................19

1R22

Surveillance Testing (71111.22)......................................................................22

1EP4

Emergency Action Level and Emergency Plan Changes (71114.04)..............25

2.

RADIATION SAFETY ...................................................................................................27

2OS1

Access Control to Radiologically Significant Areas (71121.01).......................27

2OS2

As-Low-As-Reasonably-Achievable Planning and Controls (71121.02)..........28

4.

OTHER ACTIVITIES.....................................................................................................29

4OA1

Performance Indicator (PI) Verification (71151) ..............................................29

4OA2

Identification and Resolution of Problems (71152)..........................................30

4OA3

Follow-Up of Events and Notices of Enforcement Discretion (71153).............34

4OA5

Other Activities.................................................................................................42

4OA6

Management Meetings ....................................................................................44

4OA7

Licensee-Identified Violations..........................................................................44

SUPPLEMENTAL INFORMATION ...............................................................................................1

KEY POINTS OF CONTACT.....................................................................................................1

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED ........................................................2

LIST OF DOCUMENTS REVIEWED.........................................................................................4

LIST OF ACRONYMS USED ..................................................................................................10

1

Enclosure

SUMMARY OF FINDINGS

IR 05000237/2009-005, 05000249/2009-005; 10/01/2009 - 12/31/2009; Dresden Nuclear Power

Station, Units 2 & 3; Equipment Alignment, Operability Evaluations, Post-Maintenance Testing,

Surveillance Testing, Outage, and Event Follow-up.

This report covers a three-month period of inspection by resident inspectors and announced

baseline inspections by regional inspectors. Two Green findings were identified by the

inspectors and five findings were self-revealed. All of the findings were considered Non-Cited

Violations (NCVs) of NRC regulations. The significance of most findings is indicated by their

color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609,

Significance Determination Process (SDP). Cross-cutting aspects were determined using

IMC 0305, "Operating Reactor Assessment Program." Findings for which the SDP does not

apply may be Green or be assigned a severity level after NRC management review. The NRCs

program for overseeing the safe operation of commercial nuclear power reactors is described in

NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

A.

NRC-Identified and Self-Revealed Findings

Cornerstone: Initiating Events

Green. A self-revealed finding involving a non-cited violation (NCV) of Technical

Specification 5.4.1 was identified on October 3, 2009, due to the licensees failure to

include essential information in DOP 1200-03, RWCU System Operation with the

Reactor at Pressure, Revision 51, regarding startup of the reactor water cleanup system

with the reactor at pressure. This procedural deficiency caused a pressure pulse that

resulted in a reactor water level Low-Low Group 1 Isolation Signal and Unit 3 reactor

scram. This event was entered into the licensees corrective action program (CAP) as

Issue Report (IR) 974426. Corrective actions by the licensee included revising

procedure DOP 1200-03.

This finding was considered more than minor because it affected the Initiating Events

Cornerstone objective to limit the likelihood of those events that upset plant stability and

challenge critical safety functions during shutdown as well as at power operations.

The finding was determined to be of very low safety significance because it did not

contribute to both the likelihood of a reactor trip AND the likelihood that mitigating

equipment or functions will not be available. This finding has a cross-cutting aspect in

the area of Human Performance (Resources) because the licensee did not provide

complete, accurate and up-to-date procedures to plant personnel.

H.2(c) (Section 4OA3.2)

Cornerstone: Mitigating Systems

Green. A finding of very low safety significance and associated NCV of Technical

Specification 5.4.1 was self-revealed for the failure to meet the requirements of

Clearance Order (CO) 69631 by removing shorting links instead of fuses as required by

the CO on November 12, 2009. As a result, protective relaying was unintentially

removed from the Unit 2 main power transformer TR-2, the unit auxiliary transformer

TR-21, and the reserve auxiliary transformer TR-22. This issue was entered into the

licensees CAP as Issue Report 992290. Corrective actions included: coaching of the

individuals involved with the incorrect placing of the out-of-service and a placard on the

2

Enclosure

device that was incorrectly repositioned was changed to include the specific equipment

part number of the shorting links.

The finding was determined to be more than minor because the finding could reasonably

be viewed as a precursor to a significant event. The finding was evaluated using the

SDP in accordance with IMC 0609, Appendix G, Attachment 1, Shutdown Operations

Significance Determination Process Phase 1 Operational Checklists For Both PWRs and

BWRs, Checklist 6, dated May 25, 2004. This checklist stated that for a finding to

require a Phase 2 or 3 determination, it would require an increase in the likelihood of a

loss of offsite power or degrade the licensees ability to cope with a loss of offsite power.

The ability of the licensee to cope with a loss of offsite power was not impacted because

at least one emergency diesel generator was operable during the entire period. The

inspectors determined that neither of these conditions were met so the finding screened

as Green. This finding had a cross-cutting aspect in the area of Human Performance,

Work Practices. H.4(a) (Section 1R04)

Green. The inspectors identified a finding of very low safety significance and associated

NCV of Technical Specification 5.4.1 for the licensee failing to follow Dresden procedure

DOP 2-1500-M1, LPCI System Mechanical Checklist, Revision 39. On

September 24, 2009, the inspectors identified valve 2-1501-42A, U2 low pressure

coolant injection (LPCI) A pump gland leak-off valve, was closed instead of open as

required by DOP 2-1500-M1. With this valve closed instead of open, the control room

alarm for LPCI pump seal leakage would not have been able to fulfill its function.

The issue was entered into the licensees CAP as IR 969490. The licensees corrective

actions included changing maintenance procedure DMP 1500-05, LPCI Pump

Maintenance, step G.25.d to include the case drain valve equipment numbers and sign

offs to position and verify the valves; and Operations Department Management

addressed the operations department personnel about this issue.

The finding was determined to be more than minor because the finding, if left

uncorrected, would become a more significant safety concern. Specifically, the valve

isolated an alarm in the control room. The inspectors concluded this finding was

associated with the Mitigating Systems Cornerstone using IMC 0609, Significance

Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and

Characterization of Findings, Table 4a, dated January 10, 2008. This finding has a

cross-cutting aspect in the area of Human Performance, Work Practices because the

licensee did not have any documentation as to how or when the valve was placed into

the position it was in. The design and location of the valve precluded that the valve was

accidently placed into the position it was found in. Therefore, the inspectors concluded

that either the failure to use human error prevention techniques or maintaining proper

documentation of activities caused the mispositioning of valve 2-1501-42A.

H.4.(a) (Section 1R15)

Green. The inspectors identified a finding of very low significance and associated

NCV of 10 CFR 50 Appendix B, Criterion XI, Test Control, because the licensee

unacceptably preconditioned the Unit 2 Emergency Diesel Generator (EDG) prior to

performing Technical Specification (TS) Surveillance Requirements (SR) 3.8.1.19.c.4,

3.8.1.12.c.3, and 3.8.1.10. These TS SRs involved verifying that the EDG supplied

steady state frequency would be acceptable following a loss of offsite power coincident

with and without a loss of coolant accident, and following the loss of the largest

post-accident load. Specifically, the inspectors identified that the licensee routinely

3

Enclosure

performed governor oil change outage maintenance activities which involved a section

that tuned the Unit 2 diesel governors response to a load change just prior to performing

these TS SRs. This issue has been entered into the licensees CAP as IR 1000609.

The licensee had not reached a conclusion on corrective actions by the end of the

inspection period.

This finding was determined to be more than minor because the finding, if left

uncorrected, would become a more significant safety concern. Unacceptable

preconditioning the EDG could mask latent performance issues and affect the ability of

the EDG to supply safety-related power to vital loads during an event. The inspectors

performed a Phase 1 SDP evaluation and determined that this issue was Green

because it did not result in an inoperable Unit 2 EDG. The failure to adequately

coordinate the work activity of the preventive maintenance and post-maintenance testing

with the TS SR activities was the principal contributor to this finding and was reflective of

recent performance. This finding had a cross-cutting aspect in the area of Work Control.

Specifically, the licensee did not appropriately coordinate work activities by incorporating

actions to address the impact of the work as different job activities. The scheduling of

the work activities resulted in the pre-conditioning of the EDG prior to performing the

surveillance tests. H.3(b) (Section 1R19)

Green. A finding of very low safety significance and associated NCV of 10 CFR Part 50,

Appendix B, Criterion IV, Procurement Document Control, was self-revealed for the

licensee's failure to ensure a safety-related plug was ordered and installed where

required in the 2/3 EDG turbo lube oil Y strainer. Instead, a non-conforming part was

installed, which resulted in a one-half gallon per minute oil leak and removal of the diesel

generator from service. The issue was entered into the licensees CAP as IR 926605.

Corrective actions included inspection of all other diesel generators to ensure the non-

conforming condition did not exist on another machine, revising the procurement

documents to ensure that future parts include a pressure retaining pipe plug with

approved material, and adding a requirement for a quality inspection to be performed to

inspect the strainer for metallic pipe plug in blow down port. Individual procedure

compliance issues were addressed through the stations performance improvement

initiatives.

The finding was determined to be more than minor because the finding was similar to

IMC 0612, Appendix E, Example 5 c because an incorrect and inadequate part was

installed and the system was returned to service. This performance deficiency impacted

the Mitigating Systems Cornerstone objective to ensure the availability, reliability, and

capability of systems that respond to initiating events to prevent undesirable

consequences. A Phase 3 SDP risk evaluation was performed by the regional

Senior Risk Analyst who determined the risk significance of the finding to be less than

1.0E-6/yr delta core damage frequency (CDF) and less than 1.0E-7/yr delta LERF, which

represents a finding of very low safety significance. Failure of plant personnel to

question the plastic shipping plug before the equipment was installed and returned to

service was not in compliance with MA-AA-716-008, Foreign Material Exclusion

Program, and, therefore, inspectors determined that this event was cross-cutting in

Human Performance, Work Practices, Procedural Compliance for failure of personnel to

follow the procedure. H.4(b) (Section 4OA3.3)

4

Enclosure

Cornerstone: Barrier Integrity

Green. A finding of very low safety significance and associated NCV of 10 CFR Part 50,

Appendix B, Criterion V, was self-revealed for the failure to properly move a fuel

assembly to its specified location, in accordance with DFP 0800-01, Master Refueling

Procedure. Specifically, on November 5, 2004, fuel assembly JLU569 was placed in

position C4-E5, instead of C4-F5, as required by the procedure. The violation was

placed into the licensees CAP in IR 990180. As corrective action, the licensee

temporarily suspended all fuel handling activities, conducted a piece count of the spent

fuel and stationed a second Senior Reactor Operator on the refueling bridge as

additional oversight for follow-on fuel movements. Additionally the fuel handling crew

associated with the event was suspended from future fuel moves, pending remedial

training.

Using the guidance contained in IMC 0612, Power Reactor Inspection Reports,

Appendix B, Issue Disposition Screening, dated December 4, 2008, the inspectors

determined that the finding was more than minor because the finding was associated

with the configuration control and human performance attributes of the Barrier Integrity

Cornerstone and impacted the Barrier Integrity Cornerstone objective to provide

reasonable assurance that physical design barriers (i.e., fuel cladding) protect the public

from radionuclide releases caused by an accident or event. Specifically, the shutdown

margin and thermal management of the spent fuel pool(s) is affected by fuel assembly

placement inside the pool(s). The inspectors determined the finding could be evaluated

using the significance determination process in accordance with IMC 0609,

Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening

and Characterization of Findings, Table 3b, question 6, which directed the inspectors to

Appendix M, Significance Determination Process Using Qualitative Criteria. Because

probabilistic risk assessment tools were not well suited for this finding, the criteria for

using IMC 0609, Appendix M, were met. In determining the significance of this finding,

regional management reviewed the licensee's bounding analysis in the UFSAR, which

demonstrated that regardless of the incorrect bundle position in the fuel pool, the design

of the pool still maintained pool Keff less than .95. Based on the additional qualitative

circumstances associated with this finding, regional management concluded the finding

was of very low safety significance (Green). This finding has a cross-cutting aspect in

the area of Human Performance, Work Practices. Specifically, neither the Senior

Reactor Operator (SRO), nor either of the two members of the fuel handling crew,

adequately performed independent verification techniques that ensured the fuel

assembly move was made in accordance with the Nuclear Component Transfer List, as

required by DFP 0800-01. H.4(a) (Section 1R20)

Green. A finding of very low safety significance and associated NCV of 10 CFR Part 50,

Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed for

the mispositioning of a Unit 3 control rod at power. Control rod G-11 was withdrawn one

notch contrary to TS SR 3.1.3.3 requirements to insert each withdrawn control rod at

least one notch. This was a performance deficiency. The violation was entered into the

licensees CAP as IR 993634. Corrective actions included inserting control rod G-11

one notch back to the original position and suspending control rod movement while all

rods were verified to be in their correct position. The operator was removed from shift

duties and the oncoming shift was briefed of the event.

5

Enclosure

The finding was determined to be more than minor because the finding was associated

with the Barrier Integrity Cornerstone attributes of human performance and configuration

control of a control rod, and affected the cornerstone objective of providing reasonable

assurance that physical design barriers protect the public from radionuclide releases

caused by accidents or events. Specifically, the operator withdrew a control rod contrary

to expected operation. This added positive reactivity and caused an unanticipated

power increase. The inspectors evaluated the finding using the SDP in accordance with

IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial

Screening and Characterization of Findings, Table 4a for the Fuel Barrier Cornerstone.

Per Table 4a, any issue that involves the fuel barrier is screened as Green. This finding

had no cross-cutting aspect. (Section 1R22)

B.

Licensee-Identified Violations

A violation of very low safety significance that was identified by the licensee has been

reviewed by inspectors. Corrective actions planned or taken by the licensee have been

entered into the licensees CAP. This violation and corrective action tracking numbers

are listed in Section 4OA7 of this report.

6

Enclosure

REPORT DETAILS

Summary of Plant Status

Unit 2

On October 18, 2009, the unit began its coastdown to D2R21, and continued to downpower until

the end of the month.

On November 1, 2009, the unit was shutdown for the D2R21 Refueling Outage.

On December 2, 2009, the unit began ramp-up following D2R21.

On December 9, 2009, the unit returned to full power.

Unit 3

On October 3, 2009, the unit scrammed due to a Group 1 isolation resulting from a reactor

water clean-up pressure perturbation. The unit returned to full power on October 8, 2009.

On October 18, 2009, power was reduced to approximately 82 percent for a control rod pattern

adjustment. The unit returned to full power on the same day.

On November 6, 2009, the main turbine was manually tripped due to an EHC fluid leak from a

main stop valve. The unit returned to full power on November 10, 2009.

On November 19, 2009, power was reduced to approximately 82 percent for a control rod

pattern adjustment. The unit returned to full power on the same day.

On December 12, 2009, power was reduced to approximately 70 percent for control rod testing,

scram testing and quarterly valve testing. The unit returned to full power on

December 13, 2009.

1.

REACTOR SAFETY

1R04 Equipment Alignment (71111.04)

.1

Quarterly Partial System Walkdowns

a.

Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant

systems:

Unit 3 250V battery and DC buses during Unit 2 250V battery discharge test;

B train of standby gas treatment when A train declared inoperable;

U2 Division 2 low pressure coolant injection and containment cooling service

water restoration after D2R21; and

Unit 2 main power transformer clearance order error.

7

Enclosure

The inspectors selected these systems based on their risk significance relative to the

Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted

to identify any discrepancies that could impact the function of the system, and, therefore,

potentially increase risk. The inspectors reviewed applicable operating procedures,

system diagrams, Updated Final Safety Analysis Report (UFSAR), Technical

Specification (TS) requirements, outstanding work orders (WOs), condition reports, and

the impact of ongoing work activities on redundant trains of equipment in order to identify

conditions that could have rendered the systems incapable of performing their intended

functions. The inspectors also walked down accessible portions of the systems to verify

that system components and support equipment were aligned correctly and operable.

The inspectors examined the material condition of the components and observed

operating parameters of equipment to verify that there were no obvious deficiencies.

The inspectors also verified that the licensee had properly identified and resolved

equipment alignment problems that could cause initiating events or impact the capability

of mitigating systems or barriers and entered them into the corrective action program

(CAP) with the appropriate significance characterization. Documents reviewed are listed

in the Attachment to this report.

These activities constituted four partial system walkdown samples as defined in

Inspection Procedure (IP) 71111.04-05.

b.

Findings

(1) Operating Personnel Incorrectly Placed Clearance Tags

Introduction: A finding of very low safety significance and associated Non-Cited

Violation (NCV) of TS 5.4.1 was self-revealed for the failure to meet the requirements of

Clearance Order (CO) 69631 by removing shorting links instead of fuses as required by

the CO (Green). The inspectors determined this finding to be self-revealed because it

required no active and deliberate observation by the licensee or NRC inspectors to

determine whether a change in process or equipment capability or function had

occurred. The licensee was in the process of restoring fuses when it was observed the

fuses had not been removed.

Description: Clearance Order 69631 was placed on November 2, 2009. The CO was to

remove fuses (2-0902-29-FU1A and 2-0902-29-FU1B) for the U2 main power

transformer protective relays in preparation for the replacement of the main power

transformer. The fuses were located in the top of panel 902-29 in the auxiliary electric

equipment room. On November 12, 2009, direction was given to restore the fuses per

CO 69631. The non-licensed operators (NLOs), assigned to restore the fuses, found

that fuses 2-902-29-FU1A and 2-0902-29-FU1B had not been removed, but that shorting

links 2-902-29-F8 and 2-0902-29-F12 had been removed instead. These shorting links

removed protective relaying from the main power transformer TR-2, the unit auxiliary

transformer TR-21, and the reserve auxiliary transformer TR-22.

Two NLOs were assigned to remove the fuses. One of them was a Dresden operator,

the other was a traveler from Braidwood Station. The Braidwood operator had returned

to Braidwood Station by the time this issue was identified. The inspectors interviewed

the Dresden operator. The NLO stated that he never saw the fuses that were to be

removed. The labels for the fuses were below the fuses he was required to remove and

above a fuse block that contained the shorting links that he did remove. The fuse block

8

Enclosure

containing the shorting links had a placard on it stating that there were shorting links

inside the fuse block. The operator stated that he had not read the placard. In addition,

the operator stated that after the incorrect fuse block was removed he looked inside the

fuse block and recognized that they were shorting links and not fuses. The operator

stated that this did not alert him that the wrong equipment had been manipulated. The

operator also stated that he had been trained to recognize the difference between

shorting links and fuses.

Analysis: The inspectors determined that removal of shorting links instead of fuses was

contrary to the requirements of CO 69631 and was a performance deficiency.

The finding was determined to be more than minor because the finding could reasonably

be viewed as a precursor to a significant event. Specifically, the process error by the

non-licensed operators involved in the performance of the CO to properly detect that the

wrong piece of equipment had been removed, even after observing that the removed

equipment was not what they were assigned to remove (i.e., shorting link versus a fuse),

was a failure that, if left uncorrected, could lead to a significant event.

The inspectors determined the finding could be evaluated using the SDP in accordance

with IMC 0609, Appendix G, Attachment 1, Shutdown Operations Significance

Determination Process Phase 1 Operational Checklists For Both PWRs AND BWRs,

Checklist 6, dated May 25, 2004. This checklist stated that for a finding to require a

Phase 2 or 3 determination, it would require an increase in the likelihood of a loss of

offsite power or degrade the licensees ability to cope with a loss of offsite power.

The ability of the licensee to cope with a loss of offsite power was not impacted because

at least one emergency diesel generator was operable during the entire period. The

inspectors determined that neither of these conditions were met so the finding screened

as Green.

This finding has a cross-cutting aspect in the area of Human Performance,

Work Practices. The licensee communicates human error prevention techniques, such

as self and peer checking. In addition, personnel do not proceed in the face of

uncertainty or unexpected circumstances. Specifically, the NLO: 1) did not read the

placard that was on the component that the NLO removed, which explained that the

component was a shorting link and not a fuse; and 2) did not question why the

component the NLO removed was a shorting link and not a fuse, as identified in the CO.

H.4(a)

Enforcement: Technical Specification Section 5.4.1 states, in part, that

Written procedures shall be established, implemented, and maintained covering the

following activities: The applicable procedures recommended in Regulatory Guide 1.33,

Revision 2, Appendix A, February 1978. Paragraph 1.c of Regulatory Guide 1.33

states, in part, that procedures for equipment control, locking and tagging shall be

prepared and activities shall be performed in accordance with these procedures. The

licensee established CO 69631 as the implementing procedure for tagging out-of-service

the Unit 2 Main Power Transformer.

Contrary to the above, on November 2, 2009, CO 69631 was incorrectly placed, in that,

fuses (2-0902-29-FU1A and 2-0902-29-FU1B) for the U2 main power transformer

protective relays were not removed as required by CO 69631. Instead, shorting links

2-0902-29-F8 and 2-0902-29-F12 were removed which removed protective relaying to

9

Enclosure

the U2 main power transformer, U2 reserve auxiliary transformer, and the U2 unit

auxiliary transformer. Corrective actions included: coaching of the individuals involved

with the incorrect placing of the out-of-service, and changing a placard on the device that

was incorrectly repositioned to include the specific equipment part number of the

shorting links. Because this violation was of very low safety significance and it was

entered into the licensees corrective action program as Issue Report 992290 this

violation is being treated as an NCV, consistent with Section VI.A.1 of the NRC

Enforcement Policy. (NCV 05000237/2009005-01)

1R05 Fire Protection (71111.05)

.1

Routine Resident Inspector Tours (71111.05Q)

a.

Inspection Scope

The inspectors conducted fire protection walkdowns which were focused on availability,

accessibility, and the condition of firefighting equipment in the following risk-significant

plant areas:

Fire Zone 1.1.1.4, Unit 3 Reactor Building Elevation570, Secondary

Containment;

Fire Zone 8.2.5.B, Unit 2 Turbine Building Elevation 517, Low Pressure Heater

Bays North Turbine Cavity;

Fire Zone 8.2.5.A, Unit 2 Turbine Building Elevation 517, High Pressure

Heaters/Steam Lines; and

Fire Zone 8.2.6.B Multiple Elevations, Low Pressure Heater Bays.

The inspectors reviewed areas to assess if the licensee had implemented a fire

protection program that adequately controlled combustibles and ignition sources within

the plant, effectively maintained fire detection and suppression capability, maintained

passive fire protection features in good material condition, and implemented adequate

compensatory measures for out-of-service, degraded or inoperable fire protection

equipment, systems, or features in accordance with the licensees fire plan. The

inspectors selected fire areas based on their overall contribution to internal fire risk as

documented in the plants Individual Plant Examination of External Events, their potential

to impact equipment, which could initiate or mitigate a plant transient, or their impact on

the plants ability to respond to a security event. Using the documents listed in the

Attachment to this report,, the inspectors verified that fire hoses and extinguishers were

in their designated locations and available for immediate use; that fire detectors and

sprinklers were unobstructed; that transient material loading was within the analyzed

limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory

condition. The inspectors also verified that minor issues identified during the inspection

were entered into the licensees CAP. Documents reviewed are listed in the Attachment

to this report.

These activities constituted four quarterly fire protection inspection samples as defined in

IP 71111.05-05.

b.

Findings

No findings of significance were identified.

10

Enclosure

1R08 Inservice Inspection Activities (71111.08G)

For Unit 2, from November 2, 2009, through November 13, 2009, the inspectors

conducted a review of the implementation of the licensees Inservice Inspection (ISI)

Program for monitoring degradation of the reactor coolant system, steam generator

tubes, emergency feedwater systems, risk-significant piping and components and

containment systems.

The inspections described in Sections 1R08.1 and 1R08.5 below count as one

inspection sample as defined in IP 71111.08-05.

.1

Piping Systems ISI

a. Inspection Scope

The inspectors observed ultrasonic examination (UT) of the following examination

Category F welds (e.g., welds with known cracks approved by analysis for limited

additional service without repair) to evaluate compliance with the licensees augmented

Stress Corrosion Cracking Program. Specifically, the inspectors evaluated these

examinations to determine if the procedures, equipment, and personnel used were

qualified in accordance with the American Society of Mechanical Engineers (ASME)

Code Section XI, Appendix VIII.

UT of the valve-to-tee weld (PS2-Tee/202-4B) on the loop B recirculation system.

UT of the safe end-to-elbow (PS2/201-1) on the loop B recirculation system.

The inspectors observed a video record and reviewed a written report of the following

containment drywell supports to evaluate compliance with the licensees augmented

inspection program for Code Class MC supports. Specifically, the inspectors evaluated

this examination to determine if the VT-3 procedure, equipment, and personnel used

were qualified in accordance with the ASME Code Section XI.

Visual examination (VT-3) of eight male and female drywell shear lug stabilizers

(support groups 09 and 10).

The inspectors reviewed the following examination record with relevant/recordable

conditions/indications identified by the licensee to determine if acceptance of these

indications for continued service was in accordance with the ASME Code Section XI or

an NRC-approved alternative.

Report No. D2R20-037, Four Indications on the Reactor Head Flange Weld

(2RPV UPP HD/2-THD-FLG). The inspectors observed the following pressure

boundary weld completed for a risk-significant system to determine if the licensee

followed an ASME Code Section IX qualified welding procedure, maintained

control of foreign material, and to determine if the welder used qualified weld filler

material and base material. The inspectors also reviewed the work order for this

welding to determine if the post weld nondestructive examinations required by

the ASME Code were specified.

Weld (FW-2) fabricated during installation of the component cooling service

water system pump discharge elbow replacement.

11

Enclosure

b. Findings

No findings of significance were identified.

.2

Reactor Pressure Vessel Upper Head Penetration Inspection Activities (Not Applicable)

.3

Boric Acid Corrosion Control (Not Applicable)

.4

Steam Generator Tube Inspection Activities (Not Applicable)

.5

Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI related problems entered into the licensees

corrective action program and conducted interviews with licensee staff to determine if:

the licensee had established an appropriate threshold for identifying ISI-related

problems;

the licensee had performed a root cause (if applicable) and taken appropriate

corrective actions; and

the licensee had evaluated operating experience and industry generic issues

related to ISI and pressure boundary integrity.

The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action

documents reviewed by the inspectors are listed in the Attachment to this report.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.11)

a.

Inspection Scope

On August 3, 2009, the inspectors observed a crew of licensed operators in the plants

simulator during licensed operator requalification examinations to verify that operator

performance was adequate, evaluators were identifying and documenting crew

performance problems and training was being conducted in accordance with licensee

procedures. The inspectors evaluated the following areas:

licensed operator performance;

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

prioritization, interpretation, and verification of annunciator alarms;

correct use and implementation of abnormal and emergency procedures;

control board manipulations;

oversight and direction from supervisors; and

ability to identify and implement appropriate TS actions and Emergency Plan

actions and notifications.

12

Enclosure

The crews performance in these areas was compared to pre-established operator action

expectations and successful critical task completion requirements. Documents reviewed

are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program

sample as defined in IP 71111.11.

b.

Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

.1

Routine Quarterly Evaluations (71111.12Q)

a.

Inspection Scope

The inspectors evaluated degraded performance issues involving the following

risk-significant systems:

Unit 3 control rod drive (Z03); and

Unit 2 Shutdown Cooling (Z10).

The inspectors reviewed events such as where ineffective equipment maintenance had

resulted in valid or invalid automatic actuations of engineered safeguards systems and

independently verified that the licensee's actions to address system performance or

condition problems in terms of the following:

implementing appropriate work practices;

identifying and addressing common cause failures;

scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

characterizing system reliability issues for performance;

charging unavailability for performance;

trending key parameters for condition monitoring;

ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

verifying appropriate performance criteria for structures, systems, and

components (SSCs)/functions classified as (a)(2) or appropriate and adequate

goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability,

and condition monitoring of the system. In addition, the inspectors verified that

maintenance effectiveness issues were entered into the CAP with the appropriate

significance characterization. Documents reviewed are listed in the Attachment to this

report.

This inspection constituted two quarterly maintenance effectiveness samples as defined

in IP 71111.12-05.

b.

Findings

No findings of significance were identified.

13

Enclosure

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)

a.

Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the

maintenance and emergent work activities affecting risk-significant and safety-related

equipment listed below to verify that the appropriate risk assessments were performed

prior to removing equipment for work:

345 kv Switchyard Bus 4 outage; and

345 kv Line 8014 trip.

These activities were selected based on their potential risk significance relative to the

Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that

risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate

and complete. When emergent work was performed, the inspectors verified that the

plant risk was promptly reassessed and managed. The inspectors reviewed the scope

of maintenance work, discussed the results of the assessment with the licensee's

probabilistic risk analyst or shift technical advisor, and verified plant conditions were

consistent with the risk assessment. The inspectors also reviewed Technical

Specification (TS) requirements and walked down portions of redundant safety systems,

when applicable, to verify risk analysis assumptions were valid and applicable

requirements were met.

These maintenance risk assessments and emergent work control activities constituted

two samples as defined in IP 71111.13-05.

b.

Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a.

Inspection Scope

The inspectors reviewed the following issues:

IR 957843, Failed Flowscan on AOV [air operated valve] 3-1599-61;

IR 967008, Degraded Thermal Performance of the 2A LPCI [low pressure

coolant injection] Hx [heat exchanger];

IR 987982, Boron Liquid Leak on 3B SBLC [standby liquid control] Pump; and

IR 986676, Auto Bypass Sensors Not in Accordance with

UFSAR Requirements.

The inspectors selected these potential operability issues based on the risk significance

of the associated components and systems. The inspectors evaluated the technical

adequacy of the evaluations to ensure that TS 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 the licensees evaluations, to determine

whether the components or systems were operable. Where compensatory measures

14

Enclosure

were required to maintain operability, the inspectors determined whether the measures

in place would function as intended and were properly controlled. The inspectors

determined, where appropriate, compliance with bounding limitations associated with the

evaluations. Additionally, the inspectors also reviewed a sampling of corrective action

documents to verify that the licensee was identifying and correcting any deficiencies

associated with operability evaluations. Documents reviewed are listed in the

Attachment to this report.

This operability inspection constituted four samples as defined in IP 71111.15-05.

b.

Findings

(1) NRC Inspector-Identified Control Room Alarm Isolation Valve Out-of-Position

Introduction: A finding of very low safety significance and associated NCV of TS 5.4.1

was identified by the inspectors for the licensee failing to follow Dresden procedure

DOP 2-1500-M1, LPCI System Mechanical Checklist, Revision 39. The inspectors

identified valve 2-1501-42A, U2 low pressure coolant injection (LPCI) A pump gland

leak-off, was out-of-position (closed) and documented an unresolved item (URI) in

inspection report 05000237/2009004; 05000249/2009004.

Description: On September 24, 2009, the inspectors identified that the 2-1501-42A

valve was out-of-position. The inspectors were reviewing the 2A LPCI pump seal

leak-off configuration as part of an evaluation of the mechanical seal safety

classification. The inspectors reported the valve position to shift management and

operations department personnel verified the valve was not in the open position as

described in DOP 2-1500-M1, LPCI System Mechanical Checklist, Revision 39.

This issue was documented in IR 969490, LPCI Gland Seal Leak-off Isolation Found

Closed. With the valve closed instead of open, a control room alarm (902-3 C-6) for

LPCI pump seal leakage would not have alarmed for the 2A LPCI pump had the seal

failed during operation.

The issue was considered an unresolved item in Inspection Report 05000237/2009-004;

05000249/2009-004 pending NRC review of the licensees evaluation of the valve

position versus the requirements of DOP 2-1500-M1.

The licensee performed a prompt investigation into the mispositioning of the valve.

The licensee was unable to determine the reason for, or the time at which the valve

became mispositioned. The licensee did determine that on July 6, 2009, the 2A LPCI

pump seal was replaced under Work Order 548808-01 and procedure DMP 1500-05,

LPCI Pump Maintenance, Revision 8.

The inspectors observed that the licensee took a corrective action to change

maintenance procedure DMP 1500-05, LPCI Pump Maintenance, Revision 8,

step G.25.d to include the case drain valve equipment numbers. The inspectors

reviewed procedure DMP 1500-05, Revision 8, step G.25.d and found that it had

directed only that the case drain valves be closed with no specific equipment number

designations. Since the valve that was found mispositioned was a drain valve and in

close proximity to the case drain valves, it was possible that 2-1501-42A was closed at

the same time that the case drain valves were closed. There was no step in

DMP 1500-05 past step G.25.d to open the case drain valves.

15

Enclosure

Analysis: The inspectors determined that the as found position of 2-1501-42A was

contrary to the requirement of DOP 2-1500-M1, LPCI System Mechanical Checklist,

Revision 39 and was a performance deficiency.

The finding was determined to be more than minor because the finding, if left

uncorrected, would become a more significant safety concern. Specifically, the valve

isolated an alarm in the control room. The alarm warned the control room operators of a

LPCI pump mechanical seal failure. A mechanical seal failure of a LPCI pump during an

accident condition could result in exceeding the limits of the leakage outside the primary

containment as described in TS` 5.5.2. The inspectors concluded this finding was

associated with the Mitigating Systems Cornerstone.

The inspectors determined the finding could be evaluated using the SDP in accordance

with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 -

Initial Screening and Characterization of Findings, Table 4a, dated January 10, 2008,

for the Mitigating System Cornerstone. The inspectors answered No to all five

questions on Table 4a. This issue screened as Green.

This finding has a cross-cutting aspect in the area of Human Performance, Work

Practices because the licensee did not have any documentation as to how or when the

valve was placed into the position it was in. The design and location of the valve

precluded that the valve was accidently placed into the position it was found in.

Therefore, the inspectors concluded that either the failure to use human error prevention

techniques or maintaining proper documentation of activities caused the mispositioning

of valve 2-1501-42A. H.4(a)

Enforcement: Technical Specification Section 5.4.1.a states, in part, that

Written procedures shall be established, implemented, and maintained covering the

following activities: The applicable procedures recommended in Regulatory Guide 1.33,

Revision 2, Appendix A, February 1978. Paragraph 4 of this Regulatory Guide states,

in part, that procedures for energizing, filing, venting, draining, startup, shutdown, and

changing modes of operation for Emergency Core Cooling Systems shall be prepared

and activities shall be performed in accordance with these procedures. The licensee

established DOP 2-1500-M1, LPCI System Mechanical Checklist, Revision 39, as one

of the implementing procedures.

Contrary to the above, on September 24, 2009, the inspectors identified that the

2-1501-42A valve was not in the open position as required by DOP 2-1500-M1,

LPCI System Mechanical Checklist, Revision 39. The licensee took the following

corrective actions: restored 2-1501-42A to the correct position; changed maintenance

procedure DMP 1500-05, LPCI Pump Maintenance, step G.25.d to include the case

drain valve equipment numbers and sign offs to position and verify the valves; and

Operations Department Management addressed the operations department personnel

about this issue. Because this violation was of very low safety significance and it was

entered into the licensees corrective action program as IR 969490, this violation is being

treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV 05000237/2009005-02) (URI 05000237/2009004-04; 05000249/2009004-04 is

closed.

16

Enclosure

1R19 Post-Maintenance Testing (71111.19)

.1

Post-Maintenance Testing

a.

Inspection Scope

The inspectors reviewed the following post-maintenance (PM) activities to verify that

procedures and test activities were adequate to ensure system operability and functional

capability:

WO 1152490-08, OP Perform as Left LLRT [local leak rate test] on 2-0203-2C

MSIV [main steam isolation valve];

WO 1293386, TSC [Technical Support Center] HVAC [heating, ventilation and

air conditioning] Surveillances Failed;

WO 1285845, U2 EDG [emergency diesel generator] Largest Load Reject

(TSR 3.8.1.10);

WO 1286397, 2/3 EDG Voltage Transient; and

WO 1098975-02, Perform 2B Condensate Pump Inspections.

These activities were selected based upon the structure, system, or component's ability

to impact risk. The inspectors evaluated these activities for the following (as applicable):

the effect of testing on the plant had been adequately addressed; testing was adequate

for the maintenance performed; acceptance criteria were clear and demonstrated

operational readiness; test instrumentation was appropriate; tests were performed as

written in accordance with properly reviewed and approved procedures; equipment was

returned to its operational status following testing (temporary modifications or jumpers

required for test performance were properly removed after test completion); and test

documentation was properly evaluated. The inspectors evaluated the activities against

TS, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various

NRC generic communications to ensure that the test results adequately ensured that the

equipment met the licensing basis and design requirements. In addition, the inspectors

reviewed corrective action documents associated with post-maintenance tests to

determine whether the licensee was identifying problems and entering them in the CAP

and that the problems were being corrected commensurate with their importance to

safety. Documents reviewed are listed in the Attachment to this report.

This inspection constituted five post-maintenance testing samples as defined in

IP 71111.19-05.

b.

Findings

(1) Preconditioning the Unit 2 EDG Prior to Performing Technical Specification (TS)

Surveillance Requirements (SRs)

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

associated NCV of 10 CFR 50 Appendix B, Criterion XI, Test Control, because the

licensee unacceptably preconditioned the Unit 2 EDG prior to performing TS

SRs 3.8.1.19.c.4, 3.8.1.12.c.3, and 3.8.1.10 (Green). These TS SRs involved verifying

that the EDG supplied steady state frequency would be acceptable following a loss

offsite power (LOOP) coincident with and without a loss of coolant accident (LOCA), and

following the loss of the largest post-accident load. Specifically, the inspectors identified

17

Enclosure

that the licensee performed governor oil change outage maintenance activities which

involved a section that tuned the Unit 2 diesel governors response to a load change just

prior to performing these TS SRs. The licensee performed the governor oil change

maintenance every six years. The SRs listed above were performed every two years.

Description: On November 13, 2009, during the performance of TS SR 3.8.1.10, under

work order (WO) 00634625-01, the Unit 2 EDG did not recover fast enough to satisfy the

TS SR acceptance criteria. After the largest single post-accident load was shed

(i.e., a service water pump), the EDG frequency went up to 62.4 Hz and did not recover

to the allowable band of 58.8-61.2 Hz until 13 seconds had passed. Technical

Specification SR 3.8.1.10 requires the bus frequency to recover in less than 4 seconds.

The licensee entered this condition into the corrective action program (IR 992803).

A second work order (WO 01285845-01) was created, which adjusted the governor

compensator by using work instructions located in station procedure DES 6600-01,

Diesel Generator Governor Oil Change and Compensation Adjustment, Revision 23.

Following the adjustment, the Unit 2 EDG passed TS SR 3.8.1.10 satisfactorily.

The licensee performed a cause evaluation and determined that the Unit 2 EDG failed

the TS SR because the governor compensation was incorrectly set when performing

WO 634625-01, D2 3RFL PM D/G Governor - Change Oil/Flush/Compensate six days

earlier on November 7, 2009. The licensee determined in their extent of condition

review that the other EDGs were not susceptible to the Unit 2 EDG issue because they

had been successfully tested by performing TS SR 3.8.1.10 as a post-maintenance test

(PMT) since their respective governor oil change outs. The inspectors identified that it

was the practice for the licensee to utilize TS SR 4.8.1.10 as a PMT when performing

these oil changes on a six year interval.

The inspectors questioned the practice of performing preventative maintenance (PM)

activities which involved tuning the EDG governor response just prior to the EDGs

biennial design basis loading/load shedding tests. Furthermore, the inspectors noted

that the maintenance activity utilized to resolve the failed TS SR was to re-perform the

governor compensator adjustment section of the PM activity used on November 7, 2009.

The licensee stated that, after evaluating the issue under IR 1000609, Assignment 1,

that the inspectors issue was an example of acceptable pre-conditioning, primarily for

two reasons. The licensee agreed that the PM and PMT could mask the as-found EDG

governors response during the performance of TS SR 3.8.1.10, but was acceptable

because the TS SR is usually performed without the PM/PMT activity the majority of the

time (oil change/flush every six years, and TS SR is performed every two years.).

In addition the licensee determined that a second diesel run would be required, and that

this run would unnecessarily stress the machine.

The inspectors disagreed with the licensees CAP evaluation and conclusions and

communicated the issue through Dresden management. The inspectors consulted the

NRR Quality Assurance, Vendor Inspection, and Maintenance Branch as recommended

in the NRCs Inspection Manual Part 9900 guidance regarding preconditioning.

The NRR Branch agreed that this issue was not consistent with the guidance outlined in

the NRC technical guidance or Information Notice 97-16, Preconditioning of Plant

Structures, Systems, and Components before ASME Code Inservice Testing or

Technical Specification Surveillance Testing.

18

Enclosure

Analysis: The inspectors determined that the licensee did not establish suitable test

conditions during the Unit 2 EDG TS SRs 3.8.1.19.c.4, 3.8.1.12.c.3, and 3.8.1.10.

The inspectors identified that this was a performance deficiency based on the

10 CFR 50, Appendix B, Criterion XI, Test Control regulatory requirements and the

NRCs generic communication to licensees regarding preconditioning. The failure to

properly test the EDG is considered more than minor because, if left uncorrected, the

finding would become a more significant safety concern. Unacceptable preconditioning

of the EDG could mask latent performance issues and affect the ability of the EDG to

supply safety-related power to vital loads during an event. The inspectors determined

that traditional enforcement was not appropriate because it was not apparent that the

performance deficiency affected the ability of the NRC to regulate. However, the

inspectors noted that this issue could mask failed TS SRs, which would directly feed into

the NRC assessment process. This issue was determined to be Green because it did

not result in an inoperable Unit 2 EDG.

The inspectors determined that the failure to adequately coordinate the work activity of

the PM/PMT and TS SR activities was the principal contributor to this finding and was

reflective of recent performance. This finding had a cross-cutting aspect in the area of

Work Control. Specifically the licensee did not appropriately coordinate work activities

by incorporating actions to address the impact of the work as different job activities. The

scheduling of the work activities resulted in the pre-conditioning of the EDG prior to the

surveillance tests. H.3(b)

Enforcement: 10 CFR 50, Appendix B, Criterion XI, Test Control, requires, in part,

that the test is performed under suitable environmental conditions. Suitable

environment conditions include conditions representative of the expected conditions

when the equipment is required to perform its safety function. The adjustment of the

Unit 2 EDG governor compensator affects how the EDG governor will respond when

TS SRs 3.8.1.19.c.4, 3.8.1.12.c.3, and 3.8.1.10. are performed and, therefore,

preconditions the EDG. The licensee agreed to change the method by which their

maintenance and testing was performed, but had not reached a conclusion on corrective

actions by the end of the inspection period. Because the finding is of very low safety

significance, and has been entered into the corrective action program as IR 01000609, it

is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy,

NUREG 1600. (NCV 05000237/2009005-03)

(2) 2/3 Emergency Diesel Generator (EDG) Overvoltage during Division I Undervoltage

Surveillance

a.

Inspection Scope

The inspectors reviewed the licensees equipment apparent cause evaluation (EACE) in

response to a 2/3 EDG overvoltage during performance of DOS 6600-06,

Bus Undervoltage and ECCS Integrated Functional Test for Unit 2/3 Diesel Generator

to Unit 2, Revision 46. Documents reviewed in this inspection are listed in the

Attachment to this report.

This post-maintenance testing review constituted one sample as defined in IP 71111.19.

19

Enclosure

b.

Findings

Introduction: The inspectors identified an URI regarding the regulatory requirements

associated with the circumstances surrounding the 2/3 EDG overvoltage event on

November 16, 2009.

Description: On November 16, 2009, at 10:53 a.m., a nuclear station operator (NSO)

was performing step I.11.c per DOS 6600-06, Bus Undervoltage and ECCS Integrated

Functional Test for Unit 2/3 Diesel Generator to Unit 2, Revision 46. At this time, the

operator was attempting to synchronize Bus 23-1 (powered from 2/3 EDG) to Bus 23

(powered from reserve auxiliary transformer 22). The operator stated that he was only

monitoring running versus on-coming bus voltage meters, which are transformed down

and are only relative to actual bus voltages. The operator stated that a loud pop noise

was heard from the 902-3 panel. At this time, the operator noticed that the 23-1/24-1

digital volt meter read around 5600 volts (was previously around 4100 volts). The 2/3

EDG was then shutdown per DOS 6600-06 step I.12. On step I.12.c, the voltage

regulator would not lower (remained upscale). The EDG stopped after the 6-minute cool

down and DOS 6600-06 was stopped.

The licensee generated EACE 994101-07, 2/3 Emergency Diesel Generator (EDG)

Voltage Transient, to determine the cause, extent of condition and corrective actions for

this event. The inspectors reviewed EACE 994101-07 and interviewed the NSO who

had performed DOS 6600-06. The inspectors raised more questions regarding the

capabilities of the control room simulator used for training, procedure adequacy and the

corrective actions in place. The inspectors plan to review the licensees response to

their questions to determine if there were any violations of NRC requirements and that

appropriate corrective actions were applied. (URI 05000237/2009005-04; 05000249/2009005-04)

1R20 Outage Activities (71111.20)

.1

Other Outage Activities

a.

Inspection Scope

The inspectors evaluated outage activities for a Unit 3 forced outage that began on

October 3, 2009, and continued through October 8, 2009. The forced outage was

caused by a Group 1 isolation and reactor scram caused by a pressure pulse caused by

the restoration of the Unit 3 reactor water clean-up system. The inspectors reviewed

activities to ensure that the licensee considered risk in developing, planning, and

implementing the outage schedule.

The inspectors observed or reviewed the reactor shutdown and cooldown, outage

equipment configuration and risk management, electrical lineups, selected clearances,

control and monitoring of decay heat removal, control of containment activities, startup

and heatup activities, and identification and resolution of problems associated with the

outage.

This inspection constituted one other outage sample as defined in IP 71111.20-05.

20

Enclosure

b.

Findings

No findings of significance were identified.

.2

Refueling Outage Activities

a.

Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the

Unit 2 refueling outage (RFO), conducted November 1, 2009, through

December 9, 2009, to confirm that the licensee had appropriately considered risk,

industry experience, and previous site-specific problems in developing and implementing

a plan that assured maintenance of defense-in-depth. During the RFO, the inspectors

observed portions of the shutdown and cooldown processes and monitored licensee

controls over the outage activities listed below. Documents reviewed during the

inspection are listed in the Attachment to this report.

Licensee configuration management, including maintenance of defense-in-depth

commensurate with the OSP for key safety functions and compliance with the

applicable TS when taking equipment out-of-service.

Implementation of clearance activities and confirmation that tags were properly

hung and equipment appropriately configured to safely support the work or

testing.

Installation and configuration of reactor coolant pressure, level, and temperature

instruments to provide accurate indication, accounting for instrument error.

Controls over the status and configuration of electrical systems to ensure that

TS and OSP requirements were met, and controls over switchyard activities.

Monitoring of decay heat removal processes, systems, and components.

Controls to ensure that outage work was not impacting the ability of the operators

to operate the spent fuel pool cooling system.

Reactor water inventory controls including flow paths, configurations, and

alternative means for inventory addition, and controls to prevent inventory loss.

Controls over activities that could affect reactivity.

Maintenance of secondary containment as required by TS.

Refueling activities, including fuel handling and sipping to detect fuel assembly

leakage.

Startup and ascension to full power operation, tracking of startup prerequisites,

walkdown of the drywell (primary containment) to verify that debris had not been

left, which could block emergency core cooling system suction strainers, and

reactor physics testing.

Licensee identification and resolution of problems related to RFO activities.

This inspection constituted one RFO sample as defined in IP 71111.20-05.

21

Enclosure

b.

Findings

(1) Failure to Follow the Master Refueling Procedure During Movement of Fuel Assembly

JLU569

Introduction: A finding of very low significance (Green) was self-revealed involving a

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

Drawings, for failing to follow DFP 0800-01, Master Refueling Procedure, Revision 45,

Page 12, Step 2.b, when the licensee moved fuel assembly JLU569 to the wrong

position in the Unit 2 Spent Fuel Pool during D2R21, on November 5, 2009.

Description: On November 6, 2009, during fuel shuffle 1, the fuel handling crew was

moving a fuel assembly from the reactor to location C4-E5 of the spent fuel pool, per

step 475 of the Nuclear Component Transfer List (Move Sheet), in accordance with

DFP 0800-01, Master Refueling Procedure. While making the move the refueling crew

identified a fuel assembly was already in location C4-E5. The fuel assembly being

moved was then placed in the designated Emergency Set Down Location.

It was immediately determined that the same fuel handling crew had incorrectly

performed step 294 of the Nuclear Component Transfer List the previous night,

November 5, 2009, where they positioned fuel assembly JLU569 into C4-E5, vice the

correct location of C4-F5, each location was located in the same fuel rack.

DFP 0800-01, Master Refueling Procedure, Revision 45, Step 8.d directs the

Senior Reactor Operator (SRO) on the refueling bridge to verify a fuel assembly is

placed in the correct spent fuel pool location by observing rack coordinates in the spent

fuel pool. During interviews with the inspector, it was determined that the crane

operator, fuel-handling supervisor and the SRO had each independently

(and incorrectly) identified spent fuel pool location C4-F5 as C4-E5.

Analysis: The inspectors determined that the licensees failure to move fuel assembly

JLU569 to the correct location in accordance with the Nuclear Component Transfer List

(Move Sheet) was contrary to 10 CFR 50, Appendix B, Criteria V, Instructions,

Procedures, and Drawings, which, in part, requires that activities affecting quality shall

be accomplished in accordance with prescribed instructions, and was a performance

deficiency.

The finding was determined to be more than minor because the finding was associated

with the configuration control and human performance attributes of the Barrier Integrity

Cornerstone and impacted the Barrier Integrity Cornerstone objective to provide

reasonable assurance the physical design barriers (i.e., fuel cladding) protect the public

from radionuclide releases caused by an accident or event. Specifically, the shutdown

margin and thermal management of the spent fuel pool(s) is affected by fuel assembly

placement inside the pool(s).

The inspectors determined the finding could be evaluated using the SDP in accordance

with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 -

Initial Screening and Characterization of Findings, Table 3b, question 6, which directed

the inspectors to Appendix M, Significance Determination Process Using Qualitative

Criteria. Because probabilistic risk assessment tools were not well suited for this

finding, the criteria for using IMC 0609, Appendix M, were met. In determining the

22

Enclosure

significance of this finding, regional management reviewed the licensee's bounding

analysis in the UFSAR which demonstrated that regardless of the incorrect bundle

position in the spent fuel pool, the design of the pool still maintained pool Keff less

than .95. Based on the additional qualitative circumstances associated with this finding,

regional management concluded the finding was very low safety significance (Green).

This finding has a cross-cutting aspect in the area of Human Performance, Work

Practices. Specifically, neither the SRO, nor either of the two members of the fuel

handling crew, adequately performed independent verification techniques that ensured

the fuel assembly move was made in accordance with the Nuclear Component Transfer

List, as required by DFP 0800-01, Revision 45, Page 12, Step 2.b. H.4(a)

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

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

documented instructions, procedures, or drawings, of a type appropriate to the

circumstances and shall be accomplished in accordance with these instructions,

procedures, or drawings.

Dresden procedure DFP 0800-01, Master Refueling Procedure, Revision 45 is a

procedure affecting quality. Specifically, it governs fuel movements between the spent

fuel pool and the reactor. Dresden Procedure DFP 0800-01 Step 2.b required the SRO

to ensure that the fuel assembly was moved in accordance with the Nuclear Component

Transfer List (Move Sheet).

Contrary to the above, on November 5, 2009, the licensee failed to follow DFP 0800-01,

Master Refueling Procedure, Revision 45, Step 2.b. Specifically, the fuel handling

crew positioned fuel assembly JLU569 in location C4-E5 of the U2 spent fuel pool

instead of location C4-F5. Because this violation was of very low safety significance and

it was entered into the licensees correction action program as IR 990180, this violation

is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement

Policy. (NCV 05000237/2009005-05)

Corrective actions for this event included a temporary stand down of all fuel handling

activities, a piece count of the spent fuel was performed to identify any errors associated

with fuel handling up to step 475 of the nuclear transfer list, a second SRO and a fuel

handling supervisor were stationed on the refuel bridge to provide additional oversight

during the remaining fuel moves, and the crew associated with the event were not to

resume fuel handling duties until the completion of remedial training.

1R22 Surveillance Testing (71111.22)

.1

Surveillance Testing

a.

Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether

risk-significant systems and equipment were capable of performing their intended safety

function and to verify testing was conducted in accordance with applicable procedural

and TS requirements:

23

Enclosure

WO 1077723-01, D2 20M/RFL [20 month/refuel] TS LLRT [local leak rate test]

MSIV 203-1A & 203-2A Dry Test;

WO 1257282-01, D2 QTR SBO [station black out] Diesel Generator Surveillance

Test;

WO 1251254-01, D3 Qtr TS Reactor Low Pressure (350 PSIG) ECCS

[emergency core cooling system] Permissive Ca; and

WO 1277976-01, D3 1M TS Partially Withdrawn Control Rod Drive Exercise.

(IST Sample).

The inspectors observed in plant activities and reviewed procedures and associated

records to determine the following:

did unacceptable preconditioning occur;

were the effects of the testing adequately addressed by control room personnel

or engineers prior to the commencement of the testing;

were acceptance criteria clearly stated, demonstrated operational readiness, and

consistent with the system design basis;

plant equipment calibration was correct, accurate, and properly documented;

as-left setpoints were within required ranges; and the calibration frequencies

were in accordance with TSs, the UFSAR, procedures, and applicable

commitments;

measuring and test equipment calibration was current;

test equipment was used within the required range and accuracy; applicable

prerequisites described in the test procedures were satisfied;

test frequencies met TS requirements to demonstrate operability and reliability;

tests were performed in accordance with the test procedures and other

applicable procedures; jumpers and lifted leads were controlled and restored

where used;

test data and results were accurate, complete, within limits, and valid;

test equipment was removed after testing;

where applicable for in-service testing activities, testing was performed in

accordance with the applicable version of Section XI, ASME code, and reference

values were consistent with the system design basis;

where applicable, test results not meeting acceptance criteria were addressed

with an adequate operability evaluation or the system or component was

declared inoperable;

where applicable for safety-related instrument control surveillance tests,

reference setting data were accurately incorporated in the test procedure;

where applicable, actual conditions encountering high resistance electrical

contacts were such that the intended safety function could still be accomplished;

prior procedure changes had not provided an opportunity to identify problems

encountered during the performance of the surveillance or calibration test;

equipment was returned to a position or status required to support the

performance of its safety functions; and

all problems identified during the testing were appropriately documented and

dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

24

Enclosure

This inspection constituted two routine surveillance testing samples, one in-service

testing sample, and one isolation valve inspection sample as defined in IP 71111.22,

Sections -02 and -05.

b.

Findings

(1) Mispositioning of Unit 3 Control Rod G-11

Introduction: A finding of very low safety significance and associated NCV of

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

self-revealed for the mispositioning of a Unit 3 control rod at power.

Description: On November 15, 2009, during performance of DOS 0300-01, Control Rod

Exercise, Revision 48, control rod CRD G-11 was withdrawn by the reactor operator to

position 16 from position 14 instead of being inserted to position 12 as required by

procedure. The licensee entered DOA 0300-12, Mispositioned Control Rod, Revision

14; and DGA 7, Unpredicted Reactivity Addition, Revision 20. Control rod G-11 was

inserted back to the initial position of 14 and DOA 0300-12 was exited.

Analysis: The inspectors determined that the withdrawal of the control rod was contrary

to Technical Specification Surveillance Requirement 3.1.3.3 to insert each withdrawn

control rod at least one notch and was a performance deficiency.

The finding was determined to be more than minor because the finding was associated

with the Fuel Barrier Cornerstone attributes of human performance and configuration

control of a control rod, and affected the cornerstone objective of providing reasonable

assurance that physical design barriers protect the public from radionuclide releases

caused by accidents or events. Specifically, the operator withdrew a control rod contrary

to the expected operation of insertion. This added positive reactivity and caused an

unanticipated power increase. No thermal or power limits were exceeded.

The inspectors determined the finding could be evaluated using the SDP in accordance

with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 -

Initial Screening and Characterization of Findings, Table 4a for the Fuel Barrier

Cornerstone. Per Table 4a any issue that involves the fuel barrier is screened as Green.

This finding had no cross-cutting aspect. The inspectors determined that the licensee

had taken every precaution possible to prevent this error in advance, in that, the licensee

has briefed the evolution and stationed additional personnel to ensure correct

movement. Notwithstanding, the operator moved the rod in the wrong direction.

Enforcement: 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 instructions, procedures, or drawings, of a type appropriate to the

circumstances and shall be accomplished in accordance with these instructions,

procedures, or drawings.

Contrary to the above, on November 15, 2009, the licensee failed to perform an activity

affecting quality in accordance with the appropriate procedure during performance of

DOS 0300-01, Control Rod Exercise, Revision 48, in that, control rod CRD G-11 was

withdrawn to position 16 from position 14 instead of being inserted to position 12.

25

Enclosure

Specifically, the licensed operator moving the control rod did not follow procedure

DOS 0300-01, Step I.4.a, which stated to insert the control rod one notch. The licensee

took a series of corrective actions: control rod G-11 was inserted one notch back to the

original position and then control room operators suspended control rod movement. All

control rods were verified to be in their correct position. The operator was removed from

shift duties and the oncoming shift was briefed of the event. Because this violation was

of very low safety significance and it was entered into the licensees corrective action

program as IR 993634, this violation is being treated as an NCV, consistent with

Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000249/2009005-06)

Cornerstone: Emergency Preparedness

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

.1

Emergency Action Level and Emergency Plan Changes

a.

Inspection Scope

Since the last NRC inspection of this program area, Emergency Plan Annex,

Revisions 24 and 25 were implemented based on licensee determination, in accordance

with 10 CFR 50.54(q), that the changes resulted in no decrease in effectiveness of the

Plan, and that the revised Plan continues to meet the requirements of 10 CFR 50.47(b)

and Appendix E to 10 CFR Part 50. The inspectors conducted a sampling review of the

Emergency Plan changes and a review of the Emergency Action Level (EAL) changes to

evaluate for potential decreases in effectiveness of the Plan. However, this review does

not constitute formal NRC approval of the changes. Therefore, these changes remain

subject to future NRC inspection in their entirety.

This emergency action level and emergency plan changes inspection constituted one

sample as defined in IP 71114.04-05.

b.

Findings

(1) Changes to EAL HU6 Potentially Decrease the Effectiveness of the Plans without Prior

NRC Approval

Introduction: The inspectors reviewed changes implemented to the Dresden Station

Radiological Emergency Plan Annex EALs and EAL Basis. In Revision 24, the licensee

changed the basis of EAL HU6, "Fire not extinguished within 15 minutes of detection

within the protected area boundary," by adding two statements. The two changes added

to the EAL basis stated that if the alarm could not be verified by redundant control room

or nearby fire panel indications, notification from the field that a fire exists starts the

15-minute classification and fire extinguishment clocks. The second change stated the

15-minute period to extinguish the fire does not start until either the fire alarm is verified

to be valid by additional control room or nearby fire panel instrumentation, or upon

notification of a fire from the field. These statements conflict with the previous

Dresden Station Annex, Revision 23, basis statements and potentially decrease the

effectiveness of the Plans.

Description: Dresden Station Radiological Emergency Plan Annex, Revision 23,

EAL HU6, initiating condition stated, "Fire not extinguished within 15 minutes of

26

Enclosure

detection, or explosion, within the protected area boundary." The threshold values for

HU6 were, in part: 1) Fire in any Table H2 area not extinguished within 15 minutes of

Control Room notification or verification of a Control Room alarm, or 2) Fire outside any

Table H2 area with the potential to damage safety systems in any Table H2 area not

extinguished within 15 minutes of Control Room notification or verification of a Control

Room alarm. Table H2, Vital Areas, were identified as reactor building, auxiliary electric

room, control room, diesel generator rooms, 4 kilovolt emergency core cooling system

switchgear area, battery rooms, control rod drive and component cooling service water

pump rooms, turbine building cable tunnel, turbine building safe shutdown areas, and

crib house. The basis defined fire as "combustion characterized by heat and light.

Sources of smoke such as slipping drive belts or overheated electrical equipment do not

constitute fires. Observation of flame is preferred but is not required if large quantities of

smoke and heat are observed."

The basis for Revision 23, EAL HU6 thresholds 1 and 2 stated, in part, the purpose of

this threshold is to address the magnitude and extent of fires that may be potentially

significant precursors to damage to safety systems. As used here, notification is visual

observation and report by plant personnel or sensor alarm indication. The 15-minute

period begins with a credible notification that a fire is occurring or indication of a valid fire

detection system alarm. A verified alarm is assumed to be an indication of a fire unless

personnel dispatched to the scene disprove the alarm within the 15-minute period. The

report, however, shall not be required to verify the alarm. The intent of the 15-minute

period is to size the fire and discriminate against small fires that are readily extinguished

(e.g., smoldering waste paper basket, etc.).

Revision 24 of the Dresden Station Radiological Emergency Plan Annex, changed the

threshold basis for EAL HU6 by adding the following two statements: 1) If the alarm

cannot be verified by redundant control room or nearby fire panel indications, notification

from the field that a fire exists starts the 15-minute classification and fire extinguishment

clocks, and 2) The 15-minute period to extinguish the fire does not start until either the

fire alarm is verified to be valid by utilization of additional control room or nearby fire

panel instrumentation, or upon notification of a fire from the field."

The two statements added to the basis in Revision 24 conflict with the Revision 23

threshold basis and initiating condition. The changed threshold basis in Revision 24

could add an indeterminate amount of time to declaring an actual emergency until a

person responded to the area of the fire and made a notification to the control room of a

fire in the event that redundant control room or nearby fire panel indications were not

available.

Pending further review and verification by the NRC to determine if the changes to

EAL HU6 threshold basis potentially decreased the effectiveness of the Plans, this issue

was considered an Unresolved Item. (URI 05000237/2009005-07)

27

Enclosure

2.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01)

.1

Plant Walkdowns and Radiation Work Permit Reviews

a. Inspection Scope

The inspectors reviewed licensee controls and surveys in the following radiologically

significant work areas within radiation areas, high radiation areas, and airborne

radioactivity areas in the plant to determine if radiological controls including surveys,

postings, and barricades were acceptable:

Drywell Nuclear Instrumentation System Maintenance;

Drywell In-Service Inspection;

Drywell Control Rod Drive System Maintenance and Support.

The inspectors walked down and surveyed (using an NRC survey meter) these areas to

verify that the prescribed RWP, procedure, and engineering controls were in place; that

licensee surveys and postings were complete and accurate; and that air samplers were

properly located.

This sample was documented and credited in Inspection Report 05000237/2009003;

05000249/2009003; therefore, this review does not represent a sample.

b. Findings

No findings of significance were identified.

.2

Radiation Worker Performance

a. Inspection Scope

During job performance observations, the inspectors evaluated radiation worker

performance with respect to stated radiation safety work requirements. The inspectors

evaluated whether workers were aware of any significant radiological conditions in their

workplace, of the RWP controls and limits in place, and of the level of radiological

hazards present. The inspectors also observed worker performance to determine if

workers accounted for these radiological hazards.

This sample was documented and credited in Inspection Report 05000237/2009003;

05000249/2009003; therefore, this review does not represent a sample.

b. Findings

No findings of significance were identified.

28

Enclosure

2OS2 As-Low-As-Reasonably-Achievable Planning and Controls (71121.02)

.1

Inspection Planning

a.

Inspection Scope

The inspectors reviewed plant collective exposure history, current exposure trends, and

ongoing and planned activities in order to assess current performance and exposure

challenges. The inspectors reviewed the plants current 3-year rolling average for

collective exposure in order to help establish resource allocations and to provide a

perspective of significance for any resulting inspection finding assessment.

This inspection constituted one required sample as defined in IP 71121.02-5.

b.

Findings

No findings of significance were identified.

.2

Radiological Work Planning

a.

Inspection Scope

The inspectors evaluated the licensees list of work activities ranked by estimated

exposure that were in progress and reviewed the following three work activities of

highest exposure significance:

Drywell Nuclear Instrumentation System Maintenance;

Drywell In-Service Inspection; and

Drywell Control Rod Drive System Maintenance and Support.

This sample was documented and credited in Inspection Report 05000237/2008005;

05000249/2008005; therefore, this review does not represent a sample.

For these three activities, the inspectors reviewed the As-Low-As-Reasonably-

Achievable (ALARA) work activity evaluations, exposure estimates, and exposure

mitigation requirements in order to verify that the licensee had established procedures

and engineering and work controls that were based on sound radiation protection

principles in order to achieve occupational exposures that were ALARA. The inspectors

also determined if the licensee had reasonably grouped the radiological work into work

activities, based on historical precedence, industry norms, and/or special circumstances.

This sample was documented and credited in Inspection Report 05000237/2008005;

05000249/2008005; therefore, this review does not represent a sample.

b. Findings

No findings of significance were identified.

29

Enclosure

.3

Source-Term Reduction and Control

b. Inspection Scope

The inspectors reviewed licensee records to evaluate the historical trends and the

current status of tracked plant source terms. The inspectors determined if the licensee

was making allowances and had developing contingency plans for expected changes in

the source term due to changes in plant fuel performance issues or changes in plant

primary chemistry.

This inspection constituted one required sample as defined in IP 71121.02-5.

c. Findings

No findings of significance were identified.

4.

OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification (71151)

Cornerstone: Barrier Integrity

.1

Reactor Coolant System Leakage

a.

Inspection Scope

The inspectors sampled licensee submittals for the reactor coolant system (RCS)

leakage performance indicator for Units 2 and 3 for the period from the fourth

quarter 2008 through the third quarter 2009. To determine the accuracy of the PI data

reported during those periods, PI definitions and guidance contained in the Nuclear

Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator

Guideline, Revision 5, were used. The inspectors reviewed the licensees operator

logs, RCS leakage tracking data, issue reports, event reports and NRC Integrated

Inspection Reports for the period of January 2009 through November 2009 to validate

the accuracy of the submittals. The inspectors also reviewed the licensees issue report

(IR) database to determine if any problems had been identified with the PI data collected

or transmitted for this indicator and none were identified. Documents reviewed are listed

in the Attachment to this report.

This inspection constituted two reactor coolant system leakage samples as defined in

IP 71151-05.

b.

Findings

No findings of significance were identified.

30

Enclosure

Cornerstone: Occupational Radiation Safety

.2

Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Radiological

Occurrences performance indicator for the period from the third quarter 2008 through the

third quarter 2009, to determine the accuracy of the PI data reported during those

periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory

Assessment Performance Indicator Guideline, Revision 5, were used. The inspectors

reviewed the licensees assessment of the PI for occupational radiation safety to

determine if indicator related data was adequately assessed and reported. To assess

the adequacy of the licensees PI data collection and analyses, the inspectors discussed

with radiation protection staff, the scope and breadth of its data review, and the results of

those reviews. The inspectors independently reviewed electronic dosimetry dose rate

and accumulated dose alarm and dose reports and the dose assignments for any

intakes that occurred during the time period reviewed to determine if there were

potentially unrecognized occurrences. The inspectors also conducted walkdowns of

numerous locked high and very high radiation area entrances to determine the adequacy

of the controls in place for these areas. Documents reviewed are listed in the

Attachment to this report.

This inspection constituted one occupational radiological occurrences sample as defined

in IP 71151-05.

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems (71152)

.1

Routine Review of Items Entered Into the CAP

a.

Scope

As part of the various baseline inspection procedures discussed in previous sections of

this report, the inspectors routinely reviewed issues during baseline inspection activities

and plant status reviews to verify that they were being entered into the licensees CAP at

an appropriate threshold, that adequate attention was being given to timely corrective

actions, and that adverse trends were identified and addressed. Attributes reviewed

included: the complete and accurate identification of the problem; that timeliness was

commensurate with the safety significance; that evaluation and disposition of

performance issues, generic implications, common causes, contributing factors, root

causes, extent of condition reviews, and previous occurrences reviews were proper and

adequate; and that the classification, prioritization, focus, and timeliness of corrective

actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result of the inspectors observations

are included in the attached List of Documents Reviewed.

31

Enclosure

These routine reviews for the identification and resolution of problems did not constitute

any additional inspection samples. Instead, by procedure, they were considered an

integral part of the inspections performed during the quarter and documented in

Section 1 of this report.

b.

Findings

No findings of significance were identified.

.2

Daily CAP Reviews

a.

Inspection Scope

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 licensees CAP. This review was accomplished through

inspection of the stations daily condition report packages.

These daily reviews were performed by procedure as part of the inspectors daily plant

status monitoring activities and, as such, did not constitute any separate inspection

samples.

b.

Findings

No findings of significance were identified.

.3

Semi-Annual Trend Review

a.

Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to

identify trends that could indicate the existence of a more significant safety issue.

The inspectors review was focused on repetitive equipment issues, but also considered

the results of daily inspector CAP item screening discussed in Section 4OA2.2 above,

licensee trending efforts, and licensee human performance results. Specifically, the

inspectors performed a review of the licensees corrective actions program documents

related to the areas of instrument air systems, heating, ventilation and air conditioning,

and instruments and controls. The inspectors review nominally considered IRs that

were generated in the six month period of July 2009 through December 2009, although

some examples expanded beyond those dates where the scope of the trend warranted.

In addition to reviewing the IR documents for trends, the inspectors compared their

results with issues identified in the licensees trending reports. A sample of the licensee

IRs associated with trends was reviewed for corrective action adequacy.

This review constituted a single semi-annual trend inspection sample as defined in

IP 71152-05.

b.

Findings

No findings of significance were identified.

32

Enclosure

.4

In-Depth Review - Corrective Actions Associated With Tube Blockages of the Unit 2 and

Unit 3 LPCI Heat Exchangers

a.

Inspection Scope

The inspectors performed a focused review of root cause report (RCR) 967008-03,

Dresden 2-1503-A, 2A Low Pressure Coolant Injection (LPCI) / Containment Cooling

Heat Exchanger (Hx) Failure to Meet Design Basis Heat Removal Capability due to

Asiatic Clam Macrofouling resulting from 2-1501-3A Valve Leakage and Subsequent

Untreated Service Water Make-up via the CCSW Keepfill Diluting the Biocide Treatment

below the Asiatic Clam Lethal Concentration, revision 0, to evaluate the corrective

actions that the licensee had taken to address the introduction of Asiatic clam relics into

the containment cooling heat exchangers.

Containment cooling is the operating mode of the low pressure coolant injection (LPCI)

subsystem initiated to cool the containment in the event of a loss-of-coolant accident

(LOCA). Each containment cooling subsystem consists of two LPCI pumps, one

containment cooling Hx (also called LPCI Hx), one drywell spray header and a separate

suppression chamber spray header. Heat exchanger cooling water is provided by two

containment cooling service water (CCSW) pumps in each containment cooling

subsystem. The water source for the CCSW pumps is the cribhouse, specifically

Bay 13. If the heat exchanger is significantly fouled, then the Hx may be unable to

remove sufficient heat from the containment, which could result in primary containment

failure.

In addition, the inspectors performed a focused review to evaluate the licensees

assessment of a number of IRs related to the failure to meet biocide residual

concentration after chemical addition into the containment cooling service water system.

The inspectors reviewed these issues to determine if the licensee has taken adequate

corrective actions both individually and collectively. This review constituted one sample

as defined in IP 71152.

The inspectors reviewed several documents that are listed in the Attachment of the

report.

Issues

(1) Effectiveness of Problem Identification

The licensees thermal performance testing of the LPCI heat exchangers has been

effective in identifying heat exchanger degradation prior to the Hx becoming inoperable.

On September 18, 2009, a thermal performance test was performed on the 2A LPCI Hx.

The test results indicated a heat removal capability of 67.49 MBtu/hr, which was

4.9 percent below the design heat removal rate of 71 MBtu/hr at design conditions per

the updated final safety analysis report (UFSAR) Table 6.2-3b, Heat Exchanger Heat

Transfer Rate. This issue was documented in IR 967008. Further evaluation

determined that with a heat removal capability of 67.49 MBtu/hr the new maximum

allowable inlet water temperatures for the 3 months following the test performed on

September 18, were 90.2 degrees F, 89.7 degrees F and 88 degrees F, respectively.

Actual CCSW temperatures for the time period, including previous summer months,

were below the design basis parameter of 95 degrees F, therefore, the licensee

33

Enclosure

determined that the 2A LPCI Hx, although degraded, was able to perform the required

design functions. Also, the licensee reviewed the results for the most recent thermal

performance tests performed for the other three heat exchangers and based on these

results the licensee determined that the heat exchangers were operable.

On November 5, 2009, the 2A LPCI Hx was opened for inspection and cleaning.

Approximately 50 percent of the 1256 CCSW inlet tubes were partially or fully

obstructed. The primary macrofouling mechanism was Asiatic clam relics coupled with

silt microfouling. Issue report 989609, D2R21 Inspection Results for 2A LPCI

Heat Exchanger, was generated to document the as-found condition. The 2A LPCI Hx

was cleaned and the thermal performance testing was re-performed in December 2009.

The new test results indicated a heat removal capability of 78.08 MBtu/hr at design

conditions which is 10 percent above the design heat removal rate.

(2) Prioritization and Evaluation of Problems

The licensees evaluation of the cause of the repetitive LPCI Hx blockages and

prioritization of corrective actions were ineffective. This was the third blockage of a LPCI

Hx by Asiatic clams. The first event occurred on the 3B LPCI Hx in September of 2006.

At that time the build up of Asiatic clams was thought to be due to a change in the

frequency of Bay 13 cleaning. The second event took place in March 2008, when the 3B

LPCI Hx failed its thermal performance test (70.586 vice 71 MBtu/hr). Root Cause

Report 776598-08, Dresden 3-1503-B, 3B Low Pressure Coolant Injection (LPCI) /

Containment Cooling Heat Exchanger (HX) Failure to Meet Design Basis Heat Removal

Capability Due to Inadequate Programmatic Control of Macrofoulants, revision 0,

attributed the failure of the 3B LPCI Hx to meet the design basis heat removal capability

to inadequate programmatic control of macrofoulants. Specifically, the licensee failed to

inject biocide into the containment cooling service water pumps' intake during normally

scheduled operability surveillances and sample to verify biocide residual concentration.

This was contrary to the licensees Generic Letter 89-13 Program commitments (refer to

inspection report 05000237/2008-005; 05000249/2008-005 Section 1R15 for more

details). Corrective actions included injection of biocide into the containment cooling

service water pumps' intake (e.g., Bay 13) during normally scheduled surveillances and

sample to verify biocide residual concentration.

Root cause report 776598-08 was revised on January 9, 2009. Revision 1 included an

additional causal factor which stated that a potential existed for a significant section of

the CCSW pump discharge piping to not receive a lethal biocide concentration for the

required contact time to ensure a 100 percent mortality rate for the control of

macrofoulants. This was due to the leak-by of the 2(3)-1501-3A(B), Unit 2(3) LPCI Hx

A(B) tube side discharge motor operated valves (MOVs). If leakage past these valves

occurs, then the untreated service water CCSW keepfill (strained river water) will supply

an equivalent volume of makeup water into the CCSW pump common discharge header

and result in the dilution of any chemical biocide present in the piping. This portion of

the pipe is located upstream of the LPCI Hxs and it is in this portion of the pipe where

the licensee postulates the Asiatic clams are growing and eventually getting transported

to the Hxs.

On May 22, 2009, RCR 776598-08 was revised again. Revision 2 added action

number 776598-50 to track a Unit 2(3) biocide chemical injection configuration change to

completion. This configuration change shall inject biocide into the CCSW keepfill service

34

Enclosure

water to eliminate biocide dilution resulting from leak-by of the 2-1501-3A, 2-1501-3B,

3-1501-3A and 3-1501-3B valves. This configuration change is schedule to be installed

in April 2010 on Unit 2 and May of 2010 on Unit 3. The purpose of this new biocide

injection skid is to eliminate the Asiatic clam population residing in the Unit 2 and Unit 3

CCSW piping.

The inspectors inquired why there was such a long lead time for the injection skid

modification. Through discussions with engineering management in December 2009, it

became clear that the modification was thought to be for budgetary reasons only, and

that the skid was to reduce the amount, and therefore the cost, of biocide that was being

injected. Engineering management thought that sufficient amounts of biocide were

being injected to adequately kill the Asiatic clams in the piping even though root cause

report 776598-08, revision 1 dated January 9, 2009, stated that an additional causal

factor potential existed for a significant section of the CCSW pump discharge piping to

not receive a lethal biocide concentration for the required contact time to ensure a

100 percent mortality rate for the control of macrofoulants.

(3) Effectiveness of Corrective Actions to Preclude Repetition

From January through September 2009, the licensee failed to take corrective actions to

prelude repetition of a condition meeting the licensee's definition of a significant

condition adverse to quality, associated with both Unit 2 and Unit 3 CCSW systems

which affected the performance of the LPCI heat exchangers. Specifically, the licensee

failed to provide a sufficient Asiatic clam lethal concentration of 8 PPM for the required

minimum 18 hour2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> contact time to ensure a 100 percent mortality rate for Asiatic clams

which was necessary to ensure that the heat exchangers continued to meet their design

basis heat removal requirements. The failure to perform these actions caused the

blocking of the 2A LPCI Hx tubes by Asiatic clams which resulted in the degraded

thermal performance of the Hx. Licensee planned corrective actions include the

installation of a temporary modification to provide temporary keepfill that is expected to

provide better chemical treatment of the CCSW piping upstream of the LPCI Hxs. This

violation was determined to be of very low safety significance because even though the

2A LPCI Hx was degraded it was able to perform the required design safety function.

b.

Findings

The inspectors determined that the failure to take corrective action to preclude repetition

of heat exchanger blockage by providing a sufficient Asiatic clam lethal concentration of

8PPM for the required minimum 18 hour2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> contact time to ensure a 100 percent mortality

rate was a licensee-identified violation and is documented in Section 4OA7 of this report.

4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153)

.1

(Closed) Licensee Event Report (LER) 05000237/2009-001-00; 05000249/2009-001-00,

Common Mode Failure of Reactor Building Isolation Dampers

This event, which occurred on February 6, 2009, was identified as a result of a licensee

review of failures of reactor building ventilation isolation dampers at Dresden and

another Exelon facility. Licensee failure analysis determined the damper failure

mechanism to be the result of inadequate lubrication of internal parts and installation of

upgraded solenoid valves that was completed in January of 2009. The NRC identified

35

Enclosure

the slow response to identifying the common mode failure and failure to write trending

condition reports to document the adverse trend. Inspectors verified replacement

solenoid valves continued to perform correctly and other corrective actions put in place

were appropriate to correct the procedural non-compliance issues. Documents reviewed

as part of this inspection are listed in the Attachment to this report. A NCV was written in

inspection report 05000237/2009002; 05000249/2009002 as05000237/2009002-04.

This LER is closed.

This event follow-up review constituted one sample as defined in IP 71153-05.

.2

(Closed) LER 249/2009-001-00, Unit 3 Group 1 Isolation and Automatic Reactor Scram

a.

Inspection Scope

The inspectors reviewed LER 249/2009-001-00, Unit 3 Group 1 Isolation and Automatic

Reactor Scram, to ensure that the issues documented in the report were adequately

addressed in the licensees corrective action program. The inspectors interviewed plant

personnel and reviewed operating and maintenance procedures to ensure that generic

issues were captured appropriately. The inspectors reviewed operator logs, issue

reports, the Updated Final Safety Analysis Report, and other documents to verify the

statements contained in the LER. This LER is closed.

This event follow-up review constituted one sample as defined in IP 71153-05.

b.

Findings

Introduction: A finding of very low significance (Green) involving a NCV of TS 5.4.1 was

self-revealed when Unit 3 experienced an automatic reactor scram and Group 1 primary

containment isolation signal (PCIS) when operators were restoring the reactor water

cleanup (RWCU) system with the reactor at pressure. Station procedure DOP 1200-03,

RWCU System Operation with the Reactor at Pressure, Revision 51, failed to identify

the correct position of motor operated valve (MOV), 3-1201-7, RWCU System Return to

Reactor. This procedural deficiency caused a pressure pulse that resulted in a reactor

water level Low-Low Group 1 Isolation Signal and Unit 3 reactor scram.

Description: On October 3, 2009, Unit 3 experienced an automatic reactor scram and

Group 1 PCIS. Due to the Group 1 PCIS, the inboard and outboard main steam

isolation valves closed as designed. In addition, PCIS Group 2 and Group 3 isolations

were received and verified complete. Operators manually initiated the isolation

condenser to control reactor pressure within limits.

The RWCU system had tripped earlier on October 2, 2009. On October 3, 2009, prior to

the reactor scram, operators were restoring the reactor water cleanup system per station

procedure DOP 1200-03, RWCU System Operation with the Reactor at Pressure,

Revision 51. Per the procedure, RWCU was being filled and heated in the blowdown

mode with a flow path from the reactor pressure vessel (RPV) to the main condenser.

While the fill was being performed, the 3-1201-7 valve, Unit 3 RWCU System Return to

Reactor, was closed. Reactor water cleanup system operation in the blowdown mode

with the 3-1201-7 valve closed resulted in: (1) heat up and expansion of the water

volume upstream of the 3-1201-7 valve (area of high pressure), and (2) cooling and

36

Enclosure

contraction of the water volume downstream of the 3-1201-7 valve (area of low

pressure). This condition created a high differential pressure across the valve.

A root cause investigation determined that under these conditions, when the 3-1201-7

valve was opened, the pressurized water upstream of the valve flashed to steam in the

lower pressure region downstream of the valve. The resulting pressure pulse was

sensed by the RPV level transmitters, resulting in a Reactor Water Level Low SCRAM

Signal and Reactor Water Level Low-Low Group 1 Isolation Signal.

The licensee determined that the probable cause for the pressure pulse initiating the

Reactor Water Level Low-Low Group 1 Isolation Signal and Unit 3 Reactor SCRAM was

a latent procedural deficiency. DOP 1200-03 provided inadequate guidance for the

3-1201-7 valve position during system startup with the RPV at pressure. In GEK-32399,

Dresden 3 Instrumentation Subsystem of the Reactor Water Cleanup System,

Section 3-11, Normal Operation, Table 3-6, Valve Positions for Cleanup System

Startup during Normal Operations, the reactor vendor, General Electric, recommended

that the Reactor Return Isolation Valve 1201-7 be in the open position for RWCU system

startup when the reactor is at power. This recommendation was not incorporated in

DOP 1200-03. Procedure DOP 1200-03, step G.1.g.(2) , gave the option to the operator

to open MOV 3-1201-7 at that step or later on in the procedure. During this event, the

3-1201-7 valve was opened later on in the procedure.

Analysis: The inspectors determined that the licensees failure to include pertinent

information regarding valve position during RWCU system startup with the RPV at

pressure in DOP 1200-03 was a performance deficiency warranting a significance

evaluation. Using IMC 0612, Appendix B, Issue Screening, issued on

December 4, 2008, the inspectors determined that this finding was more than minor

because it impacted the Initiating Events Cornerstone objective to limit the likelihood of

those events that upset plant stability and challenge critical safety functions during

shutdown as well as at power operations. The failure to maintain adequate procedures

for the restoration of systems can result in events (i.e., reactor scram) that upset plant

stability. This condition caused a pressure pulse that was sensed by the RPV level

transmitters, resulting in a Reactor Water Level Low SCRAM Signal and Reactor Water

Level Low-Low Group 1 Isolation Signal. This finding had a cross-cutting aspect in the

area of Human Performance Resources because the licensee did not provide complete,

accurate and up-to-date procedures to plant personnel. H.2(c)

The inspectors completed a Phase 1 significance determination of this issue using

IMC 0609, Significance Determination Process, Attachment 0609.04, dated

January 10, 2008. The inspectors determined that the finding impacted the Initiating

Events Cornerstone. The inspectors answered No to the question on Transient

Initiators under the Initiating Events Cornerstone column on Table 4a because the

finding did not contribute to both the likelihood of a reactor trip AND the likelihood that

mitigating equipment or functions will not be available. Therefore, the issue screened as

having very low safety significance (Green).

Enforcement: The inspectors determined that the licensees failure to include pertinent

information, regarding valve position during RWCU system startup with the RPV at

pressure, in DOP 1200-03 was a violation of Dresden Nuclear Power Station Technical

Specification Section 5.4.1, Procedures. Section 5.4.1 states, in part, that written

procedures shall be established, implemented, and maintained covering applicable

37

Enclosure

procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, issued

February 1978. Procedures addressing startup of boiling water reactor (BWR) systems,

including the reactor cleanup system, are recommended in Section 4. of Appendix A to

this Regulatory Guide.

Contrary to the above, on October 3, 2009, the licensee failed to include pertinent

guidance regarding 3-1201-7 valve position during system startup with the RPV at

pressure. This failure resulted in an automatic reactor scram and Group 1 primary

containment isolation signal. This event was entered into the licensees corrective action

program as IR 974426, U3 Group 1 Isolation and Reactor Scram. Corrective actions

by the licensee included revising procedure DOP 1200-03, requiring the 3-1201-7 valve

to be open prior to initiating RWCU system fill and vent activities. Because this violation

was of very low safety significance and it was entered into the licensees corrective

action program, this violation is being treated as a NCV, consistent with Section VI.A.1 of

the NRC Enforcement Policy. (NCV 05000249/2009005-08)

.3

(Closed) Licensee Event Report (LER) 05000237/2009-003-00; 05000249/2009-003-00,

Emergency Diesel Generator Oil Leak and Unresolved Item (URI)05000237/2009003-01; 05000249/2009003-01, Failure of 2/3 Emergency Diesel

Generator Due to Lube Oil Leak on Y Strainer

This event, which occurred on June 2, 2009, during performance of the monthly

surveillance on the Unit 2/3 Emergency Diesel Generator (EDG), resulted in an oil leak

of approximately one-half gallon per minute from the turbocharger lubricating oil Y

strainer end cap plug. The initial event was documented in Section 1R12 of report

05000237/2009003; 05000249/2009003 as an Unresolved Item

(URI 05000237/2009003-01; 05000249/2009003-01.)

Documents reviewed as part of this inspection are listed in the Attachment to this report.

Both the above referenced URI and this LER are closed.

This event follow-up review constituted one sample as defined in IP 71153-05.

Introduction: A finding of very low safety significance and associated NCV of

10 CFR Part 50, Appendix B, Criterion IV, Procurement Document Control, was

self-revealed for the failure to ensure a safety-related plug was ordered and installed

where required in the 2/3 EDG turbo lube oil Y strainer.

Description: On June 02, 2009, the 2/3 EDG was operating in support of the monthly

surveillance run in accordance with DOS 6600-01, Diesel Generator Surveillance

Tests. At approximately 3:39 am the 2/3 EDG was 25 minutes into the loaded run when

an oil leak of approximately 1/2 gallon per minute was identified at the Turbo Lube Oil

System Y strainer.

The 2/3 EDG was secured at approximately 3:47 a.m., and the turbo oil circulating pump

was secured approximately 45 minutes after the engine shutdown to allow heat removal

from the engines turbo charger to prevent damage. Inspection of the turbo lube oil

system Y strainer identified the source of the leakage to be coming from a pipe plug on

the Y strainer end cap. Further investigation revealed the pipe plug installed in the

strainer end cap to be a black 3/8 inch NPT plastic shipping plug instead of the

safety-related steel plug required by design documents.

38

Enclosure

As immediate corrective action, the licensee installed a 3/8 inch NPT ASTM A-105

carbon steel hex head threaded pipe plug, Cat ID 43255-1 in the strainer end cap of the

2/3 EDG using work order (WO) 1240346-01 and approximately 30 gallons of oil were

added to the engine reservoir. Surveillance procedure DOS 6600-01, Diesel Generator

Surveillance Tests, was completed satisfactorily with no leakage observed from the

Turbo Lube Oil System Y strainer. The 2/3 EDG was declared operable at 11:05 p.m.

on June 2, 2009. Extent of condition reviews were performed on the four other similar

diesel generators; two safety-related and two station blackout emergency diesels.

No other non-conforming conditions were identified.

During the subsequent root cause investigation, the licensee determined that the

Unit 2/3 EDG Turbo Lube Oil Y Strainer (EPN 2/3-6661) and Circulating Oil Y Strainer

(EPN 2/3-6672) were replaced on March 24, 2008, under WO 922770-01 due to wear on

the strainer blowdown caps. On March 24, 2008, the licensee completed steps 8, 9

and 10 of WO 922770-01. This work scope removed the old lube oil strainer 2/3-6661

from the system, cleaned piping and pipe nipples prior to installing the strainer

(replacing pipe nipples as required), and installed the new Mueller strainer snug tight

using site approved sealant. On March 25, 2008, the license performed step 11 of the

work package requiring the strainers to be painted with designated orange paint once

the strainers have been installed. The painting step was important because from this

step on there is no way to visually identify the non-conforming condition. Interviews with

the individual performing the installation and painting indicated that they did not identify

the plug as a plastic foreign material exclusion (FME) plug and therefore took no action

to replace it as was required by procedure MA-AA-716-008, Foreign Material Exclusion

Program.

The post-maintenance test (PMT) was performed on the Y strainers on

March 27, 2008, per WO 922770-02. The licensee performed visual inspections of the

Y strainers at system pressure. The inspections passed with no identified leakage.

Subsequent investigation revealed that Turbo Lube Oil Strainer replaced under

WO 922770-01 in March 2008 was assigned Exelon Catalog Identification

Number 38412-1. The Y strainer was manufactured commercial grade by Mueller

Steam Specialty under Model No. 352M. Exelon purchased the Y strainer from

Engine Systems Incorporated (ESI) under Purchase Order (PO) 00000703 Revision 001

as a Quality Level 1 Nuclear Safety-Related Item. The PO stated, Strainer, Y-Type,

1 IN, Bronze ASTM B62, Threaded (FNPT), Class 250, 20 Mesh Size Stainless Steel

Screen, supplied with threaded gasketed cap and plug; and rated for 400 PSI @ 150 F

(WOG); and seismically qualified per Report Number ST-MSS-352M-1 issued by ESI.

The Mueller Steam Specialty catalog Cut Sheet that was pasted in the supply database

for CAT ID 38412-1 on July 3, 2006, indicated Y strainer Blowoff Outlets are

unplugged. Additionally, the current Mueller Steam Specialty online specification sheet

for Y Strainers (ES-MS-351M-358) states Blow Off Outlets: Not normally furnished

with plug. Plug available, specify with order.

Since the part number specified by Dresden in the procurement document does not

include a plug in the end cap, Engine Systems Incorporated (ESI) included the plastic

plug for FME purposes. The plug is black only because that was the color that ESI had

on hand at the time. Personnel from ESI stated that when performing the qualification

testing for the part two strainers are ordered, one for the testing and one to ship to the

customer. An appropriate plug is installed in the one used for qualification testing.

39

Enclosure

The strainer purchased for WO 922770-01 was shipped to Dresden Site Supply and had

a receipt inspection performed on December 19, 2007. The inspection accepted the

strainer with no discrepancies noted in the Quality Receipt Inspection Package and

without questioning if the plug installed in the strainer end cap should have been a

suitable pressure retaining pipe plug or a shipping plug.

The licensee concluded from their investigation that the root cause for this issue was the

failure to have a purchase order that clearly documented the need for the safety-related

strainer cap plugs.

Analysis: The inspectors determined that the failure to document the requirement for a

safety-related strainer cap plug in the purchase order was a performance deficiency.

The finding was determined to be more than minor because the finding was similar to

IMC 0612, Appendix E, Example 5 c, in that, an incorrect and inadequate part was

installed and the system was returned to service. Therefore, this performance deficiency

also impacted the Mitigating Systems Cornerstone objective to ensure the availability,

reliability, and capability of systems that respond to initiating events to prevent

undesirable consequences.

The inspectors determined the finding could be evaluated using the SDP in accordance

with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 -

Initial Screening and Characterization of Findings, Table 4a, dated January 10, 2008,

for Mitigating Systems because the 2/3 EDG is a mitigating system that could impact the

long term or short term decay heat removal capability during a loss of offsite power

event. The inspectors answered yes to the question, Does the finding represent

actual loss of safety function of a single train for greater than its Technical Specification

Allowed Outage Time? The inspectors performed a SDP phase 2 evaluation using the

pre-solved spreadsheet for the Risk-Informed Inspection Notebook for Dresden Nuclear

Power Station. The assumption that EDG 2/3 was unavailable for greater than 30 days

resulted in a finding of low to moderate risk significance (White). The Region III senior

reactor analyst (SRA) performed a SDP phase 3 evaluation of the EDG 2/3 failure to run.

The SRA used the Dresden Standardized Plant Analysis Risk (SPAR) Model,

Revision 3.50, and assumed that the EDG would have failed to run in response to any

demand that would have occurred since the last successful 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> endurance run.

This exposure period was approximately 89 days. The delta CDF for internal events

was estimated to be 4.0E-7/yr. The dominant sequence was a loss of offsite power

event followed by common cause failure of all emergency power and the failure to

recover either offsite or onsite power.

Since the delta CDF was greater than 1.0E-7/yr, the SRA evaluated the risk contribution

from external events. The risk contribution from seismic events was determined to be

negligible because the frequency of seismically-induced loss of offsite power events was

estimated to be much less than plant-centered, switchyard-centered, or grid-related loss

of offsite power events. The fire risk contribution was estimated using information from

the licensees Individual Plant Examination for External Events (IPEEE) submitted

in 2000. Fire-induced loss of offsite power events were assumed to occur for fires in

control room panel 902-8 (Unit 3 panel 903-8), panel 923-2, and for fires in the auxiliary

electric equipment room (AEER). The SRA used the fire ignition frequencies from the

IPEEE and calculated conditional core damage probabilities using the SPAR model for

plant-centered loss of offsite power events with the failure of the 2/3 EDG to estimate the

change in core damage frequency for fire events that did not result in control room

40

Enclosure

evacuation. Fires in the AEER contributed less than 1.0E-7/yr to the change in CDF.

For the control room, fires in panel 902-8 (903-8) were evaluated and determined to be

potential risk contributors because the fire damage caused a loss of offsite power and

resulted in the unavailability of the Division II power supplies. For panel fires that were

not suppressed within 15 minutes, the SRA used a non-suppression probability of 3.4E-3

from the licensees IPEEE and concluded that operators would evacuate the control

room and use the fire-specific safe shutdown procedures. With the 2/3 EDG unavailable

due to the performance deficiency, only the station blackout (SBO) diesel generator

would remain available to provide power. The SRA used SPAR-H to estimate the

human error probability (HEP) for aligning the SBO diesel generator during fire scenarios

and estimated a value of 0.4 assuming that diagnosis of the loss of power and need for

the SBO diesel generator would dominate the HEP. The performance-shaping factors

for stress and procedures were adjusted in the HEP calculation. The procedures for

using the SBO DG were considered to be incomplete because the Dresden fire safe

shutdown procedures do not address the use of the SBO diesel generator and operators

would be required to use separate procedures for non-fire scenarios to line-up the SBO

DG. Also, the stress of the fire-induced LOOP with failure of the 2/3 EDG was assumed

to be high. The risk contribution from control room fire scenarios was estimated to be

approximately 4.0E-7/yr. The total delta CDF from internal and external scenarios was

estimated to be approximately 8.0E-7/yr. The risk estimate is conservative because it

does not account for any successful run time of the diesel generators and provides only

limited credit for the use of SBO diesel generators in fire scenarios.

The risk contribution from large early release frequency (LERF) was also evaluated.

IMC 0609, Appendix H, Containment Integrity Significance Determination Process

assigns a screening LERF factor of 1.0 to station blackout core damage sequences for

BWRs with Mark I containments. This would result in a delta LERF estimate of

8.0E-7/yr, which represents low to moderate significance. However, based on a

previous Dresden phase 3 SDP evaluation and other SDP evaluations of plants with

Mark 1 containments, a much lower LERF factor of 0.1 is judged to be appropriate for

this SDP phase 3 evaluation. As a result, the risk significance of the finding is estimated

to be less than 1.0E-6/yr delta CDF and less than 1.0E-7/yr delta LERF, which

represents a finding of very low safety significance (Green).

In addition, the failure of plant maintenance personnel to identify and remove the plastic

foreign material exclusion plug prior to equipment return to service was a significant

contributor to the finding. Step 4.2.5.3.B of MA-AA-716-008, Foreign Material Exclusion

Program, states, in part, New parts/components/equipment to be installed in the plant

should be carefully inspected to ensure that no foreign material (e.g., packaging

material, shipping plugs, desiccants, and lubricant/preservatives used for shipping or

storage) are present to prevent introduction to the system. Failure of plant personnel to

question the plastic shipping plug before the equipment was installed and returned to

service was not in compliance with the procedure and, therefore, inspectors determined

that this event was cross-cutting in Human Performance, Work Practices, Procedural

Compliance for failure to follow of personnel to follow the procedure. H.4(b)

Enforcement: 10 CFR Part 50, Appendix B, Criterion IV, Procurement Document

Control, requires, in part, that measures shall be established to assure that applicable

regulatory requirements, design bases, and other requirements which are necessary to

assure adequate quality are suitably included or referenced in the documents for

41

Enclosure

procurement of material, equipment, and services, whether purchased by the applicant

or by its contractors or subcontractors.

Contrary to the above, from December 2007 until June 2009, the licensee did not include

a requirement which was necessary to assure adequate quality in the document for

procurement of the 2/3 EDG Turbo Lube Oil Y Strainer, CAT ID 38412-1. Specifically,

the purchase order did not specify what type of plug was required to be supplied and

installed in the strainer cap prior to installation. The strainer was supplied with a plug

installed that was neither designed nor constructed sufficiently to prevent a leak that

resulted in the inoperability of the 2/3 EDG for greater than 30 days. Immediate

corrective action to correct the leak included installation of a qualified plug in the strainer,

post-maintenance testing of the 2/3 EDG, and inspection of all other diesel generators to

ensure the same condition did not exist on another machine. The catalogue ID was

revised to include a pressure retaining pipe plug with approved material and a

requirement was added for a quality inspection to be performed to inspect the strainer

for metallic pipe plug in blow down port. Individual procedure compliance issues were

addressed through the stations performance improvement initiatives. Because this

violation was of very low safety significance and it was entered into the licensees

corrective action program as IR 926605, this violation is being treated as an NCV,

consistent with Section VI.A.1 of the NRC Enforcement Policy.

(NCV 05000237/2009005-09; 05000249/2009005-09)

.4

Electro-Hydraulic Control (EHC) Fluid Leaking From Stop Valve 3-5699-MSV4-FA

Resulting in Forced Outage D3F49

a.

Inspection Scope

The inspectors reviewed the plants response to an EHC leak on Dresden Unit 3 that

caused the unit to come offline. Documents reviewed in this inspection are listed in the

Attachment to this report.

This event follow-up review constituted one sample as defined in IP 71153-05.

b.

Findings

Introduction: The inspectors identified an unresolved item regarding the regulatory

requirements associated with the circumstances surrounding the Unit 3 turbine trip on

November 6, 2009.

Description: On November 5, 2009, at 8:53 p.m., Unit 3 Control Room received the

following alarm: 903-7 B-6, EHC [electro-hydraulic control] RESERVOIR LVL HI/LO

(reference IR 989641) indicating a rate of change in the EHC reservoir at 1.3" in 100 hrs

or greater. A non-licensed operator (NLO) was dispatched to stage a barrel of EHC fluid

for addition. Preparations were made for a heater bay entry to look for leaks.

A Unit 3 heater bay entry was made and it was determined that the Unit 3 Main Turbine

Stop Valve (MSV) # 4 had an EHC leak from the fast-acting solenoid valve

(3-5699-MSV4-FA). The leak was determined to be approximately 4-5 gallons of fluid

per hour. A report from the field was that reservoir level had dropped about 1.1" in the

last 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Between 12:50 a.m. and 3:43 a.m. on November 6, 2009, the licensee

added two barrels of EHC fluid to the EHC reservoir.

42

Enclosure

On November 6, 2009, between 9:00 a.m. and 2:00 p.m., licensee management

conducted meetings regarding the repair of the leak on MSV #4. The plan called for

starting to down power Unit 3 to 650 Mwe for a planned 3:00 p.m. entry into the heater

bay to repair the valve. The decision to go to 650 Mwe was to reduce the dose rate in

the area and extend stay time for the repair.

At approximately 3:00 p.m., while staging for entry to repair the leak, Operations

personnel informed the NLO, staged to isolate the oil supply to the leaking valve, that

level in the EHC reservoir was dropping quickly, and requested the NLO to enter the

pipeway as soon as possible.

At approximately 3:05 p.m., the NLO observed oil spraying profusely from the bottom

area of #4 Main Stop Valve and the area of the solenoid that was going to be changed

out. The NLO immediately contacted the control room to report what was observed and

a decision was made to take the turbine offline. At 3:32 p.m., the Unit 3 Turbine was

tripped.

The licensee had not completed their root cause investigation by the end of the

inspection period. The inspectors planned to review the root cause investigation to

determine if there were any violations of NRC requirements and that appropriate

corrective actions were applied. (URI 05000249/2009005-10)

4OA5 Other Activities

.1

Quarterly Resident Inspector Observations of Security Personnel and Activities

a.

Inspection Scope

During the inspection period, the inspectors conducted observations of security force

personnel and activities to ensure that the activities were consistent with licensee

security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities

did not constitute any additional inspection samples. Rather, they were considered an

integral part of the inspectors' normal plant status review and inspection activities.

b.

Findings

No findings of significance were identified.

.2

Institute of Nuclear Power Operations (INPO) Plant Assessment Report Review

a.

Inspection Scope

The inspectors reviewed the interim report for the INPO plant assessment of Dresden

Station conducted in September 2009. The inspectors reviewed the report to ensure

that issues identified were consistent with the NRC perspectives of licensee

performance and to verify if any significant safety issues were identified that required

further NRC follow-up.

43

Enclosure

b.

Findings

No findings of significance were identified.

.3

Open) NRC TI 2515/177, Managing Gas Accumulation in Emergency Core Cooling,

Decay Heat Removal and Containment Spray Systems (NRC Generic Letter 2008-01)

a.

Inspection Scope

On November 10, 2008, the inspectors conducted a walkdown of the Unit 2 High

Pressure Coolant Injection (HPCI) discharge piping inside the Unit 2 X-Area in sufficient

detail to reasonably assure the acceptability of the licensees walkdowns (TI 2515/177,

Section 04.02.d). The inspectors also verified that the information obtained during the

licensees walkdown was consistent with the items identified during the inspectors

independent walkdown (TI 2515/177, Section 04.02.c.3).

The inspectors verified that Piping and Instrumentation Diagrams (P&IDs) accurately

described the subject system, that the P&IDs were up-to-date with respect to recent

hardware changes, and any discrepancies between as-built configurations and the

P&IDs were documented and entered into the CAP for resolution (TI 2515/177, Section

04.02.b).

In addition, the inspectors reviewed the licensees isometric drawings that describe the

HPCI system configurations to verify that the licensee had acceptably confirmed the

accuracy of the drawings (TI 2515/177, Section 04.02.a). The inspectors considered the

following related to the isometric drawings:

High point vents were identified.

High points that do not have vents were acceptably recognizable.

Other areas where gas can accumulate and potentially impact subject system

operability, such as at orifices in horizontal pipes, isolated branch lines, heat

exchangers, improperly sloped piping, and under closed valves, were acceptably

described in the drawings or in referenced documentation.

Horizontal pipe centerline elevation deviations and pipe slopes in nominally

horizontal lines that exceed specified criteria were identified.

All pipes and fittings were clearly shown.

The drawings were up-to-date with respect to recent hardware changes and that

any discrepancies between as-built configurations and the drawings were

documented and entered into the CAP for resolution.

The licensee indicated that even though they possess isometric drawings of the HPCI

system, they do not rely upon any isometric drawings for gas management in that

system. Therefore, the inspectors were unable to verify the above considerations.

In their review, the inspectors did identify discrepancies in the available isometric

drawings between what was shown on the drawing and the as-built condition of the

system. The discrepancies identified were in drawings M-1151C-2 and ISI-510 Sheet 2

and were associated with the 2-23126-3/4-L vent line. The licensee determined that

drawing M-1151C-2 does not need to be updated because it was created to support a

seismic analysis done before the 2-23126-3/4-L vent line was installed and was not

intended to be updated. They determined that drawing ISI-510 Sheet 2 does not need to

44

Enclosure

be updated because it is a system pressure testing walkdown isometric drawing,

therefore, the discrepancy does not impact the purpose and use of the drawing. These

conclusions were documented in AR 1014280.

Documents reviewed are listed in the Attachment to this report.

This inspection effort counts towards the completion of TI 2515/177, which will be closed

in a later Inspection Report.

b.

Findings

No findings of significance were identified.

4OA6 Management Meetings

.1

Exit Meeting Summary

On January 14, 2010, the inspectors presented the inspection results to Mr. T. Hanley,

and other members of the licensee staff. The licensee acknowledged the issues

presented. The inspectors confirmed that none of the potential report input discussed

was considered proprietary.

.2

Interim Exit Meeting

Interim exits were conducted for:

The results of the inservice inspection with Site Vice-President T. Hanley on

November 13, 2009.

The results of the As-Low-As-Reasonably-Achievable Planning and Controls

inspection with the Site Vice President, Mr. T. Hanley, on November 17, 2009.

The annual review of Emergency Action Level and Emergency Plan changes

with the licensee's Emergency Preparedness Manager, Mr. P. Quealy, via

telephone on December 21, 2009.

The inspectors confirmed that none of the potential report input discussed was

considered proprietary.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the

licensee and is a violation of NRC requirements which meets the criteria of Section

VI.A.1 of the NRC Enforcement Policy, for being dispositioned as an NCV.

Title 10 of the Code of Federal Regulations, Part 50, Appendix B, Criterion XVI,

Corrective Action, states, in part, Measures shall be established to assure that

conditions adverse to quality, such as failures, malfunctions, deficiencies,

deviations, defective material and equipment, and non-conformances are

promptly identified and corrected. In the case of significant conditions adverse to

quality, the measures shall assure that the cause of the condition is determined

and corrective action taken to preclude repetition. A significant condition

adverse to quality for both Unit 2 and Unit 3 containment cooling service water

45

Enclosure

(CCSW) systems was identified by the licensee in RCR 776598-08,

Dresden 3-1503-B, 3B Low Pressure Coolant Injection (LPCI) / Containment

Cooling Heat Exchanger (HX) Failure to Meet Design Basis Heat Removal

Capability Due to Inadequate Programmatic Control of Macrofoulants,

Revision 1, on January 9, 2009. Procedure LS-AA-125, Corrective Action

Program (CAP) Procedure, revision 13, defines significant condition adverse to

quality (SCAQ), in part, as A condition which, if left uncorrected, could have a

serious effect on safety or reliability. In addition, recurring deficiencies or errors

that cannot be dispositioned or brought into conformance by established

corrective action systems," are considered SCAQs. The inspectors determined

that the conditions described in RCR 776598-08, met the licensee's definition of

a significant condition adverse to quality. Contrary to the above requirements,

from January through September 2009, the licensee failed to take measures to

assure that the cause of the condition (blockage of the LPCI heat exchangers)

was determined and corrective action taken to preclude the repetition for a

significant condition adverse to quality on both Unit 2 and Unit 3 CCSW systems.

Specifically, the licensee failed to prevent the recurrence of Asiatic clam

blockage in the 2A LPCI Hx tubes which resulted in the degraded thermal

performance of the Hx. Licensee planned corrective actions included installation

of a temporary modification to provide temporary keepfill that was expected to

provide better chemical treatment of the CCSW piping upstream of the LPCI Hxs,

and a permanent injection skid for biocide to provide for long term assurance of

effective chemical treatment. This violation was determined to be of very low

safety significance because even though the 2A LPCI Hx was degraded it was

able to perform the required design safety function.

ATTACHMENT: SUPPLEMENTAL INFORMATION

1

Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. Hanley, Site Vice President

S. Marik, Station Plant Manager

H. Bush, Radiation Protection Manager

B. Casey, Engineering Programs (Braidwood)

H. Do, Exelon Corporate ISI

B. Finley, Security Manager

D. Glick, Shipping Specialist

T. Green, Nondestructive Examination Services

J. Griffin, Regulatory Assurance - NRC Coordinator

D. Gronek, Operations Director

J. Hansen, Corporate Licensing

L. Jordan, Training Director

R. Kalb, Chemistry

P. Karaba, Maintenance Director

J. Kish, Engineering Programs

M. Kluge, Design Engineer

D. Leggett, Nuclear Oversight Manager

R. Laburn, Radiation Protection

M. Marchionda, Regulatory Assurance Manager

J. Miller, Nondestructive Examination Services

P. OConnor, Licensed Operator Requalification Training Lead

M. Overstreet, Lead Radiation Protection Supervisor

C. Podczerwinski, Maintenance Rule Coordinator

P. Quealy, Emergency Preparedness Manager

E. Rowley, Chemistry

R. Rybak, Regulatory Assurance

J. Sipek, Engineering Director

N. Starcevich, Radiation Protection Instrumentation Coordinator

J. Strmec, Chemistry Manager

S. Vercelli, Work Management Director

NRC

M. Ring, Chief, Division of Reactor Projects, Branch 1

IEMA

R. Zuffa, Illinois Emergency Management Agency

R. Schulz, Illinois Emergency Management Agency

2

Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened: 05000237/2009005-01

NCV

Operating Personnel Incorrectly Placed Clearance Tags

(Section 1R04)05000237/2009009-02

NCV

NRC Inspector-Identified Control Room Alarm Isolation

Valve Out-of-Position (Section 1R15)05000237/2009005-03

NCV

Preconditioning the Unit 2 Emergency Diesel Generator

Prior to Performing TS Surveillance Requirements

(Section 1R19)05000237/2009005-04

URI

2/3 Emergency Diesel Generator (EDG) Overvoltage 05000249/2009005-04

During Division I Undervoltage Surveillance (1R19)05000237/2005009-05

NCV

Failure to Follow the Master Refueling Procedure During

Movement of Fuel Assembly JLU569 (Section 1R20)05000249/2009005-06

NCV

Mispositioning of a Unit 3 Control Rod at Power

(Section 1R22)05000237/2009005-07

URI

Changes to EAL HU6 Potentially Decreased the

Effectiveness of the Plans without Prior NRC Approval

(1EP4)05000249/2009005-08

NCV

Procedural Deficiency Causing a Pressure Pulse

Resulting in a Reactor Water Level Low-Low Group 1

Isolation Signal and Unit 3 Reactor Scram

(Section 4OA3.2)05000237/2009005-09

NCV

Failure to Ensure a Safety-Related Plug was Ordered and 05000249/2009005-09

Installed in the 2/3 Emergency Diesel Generator

Turbo Lube Oil Y Strainer (Section 4OA3.3)05000249/2009005-10

URI

Electro-Hydraulic Control (EHC) Fluid Leaking From Stop

Valve 3-5699-MSV4-FA Resulting in Forced Outage

D3F49 (Section 4OA3.4)

Temporary Instruction 2515/177

Managing Gas Accumulation in Emergency Core Cooling,

Decay Heat Removal and Containment Spray Systems

(NRC Generic Letter 2008-01) (Section 4OA5.3)

3

Attachment

Closed: 05000237/2009005-01

NCV

Operating Personnel Incorrectly Placed Clearance Tags

(Section 1R04)05000237/2009009-02

NCV

NRC Inspector-Identified Control Room Alarm Isolation

Valve Out-of-Position (Section 1R15)05000237/2009005-03

NCV

Preconditioning the Unit 2 Emergency Diesel Generator

Prior to Performing TS Surveillance Requirements

(Section 1R19)05000237/2005009-05

NCV

Failure to Follow the Master Refueling Procedure During

Movement of Fuel Assembly JLU569 (Section 1R20)05000249/2009005-06

NCV

Mispositioning of a Unit 3 Control Rod at Power

(Section 1R22)05000249/2009005-08

NCV

Procedural Deficiency Causing a Pressure Pulse

Resulting in a Reactor Water Level Low-Low Group 1

Isolation Signal and Unit 3 Reactor Scram

(Section 4OA3.2)05000237/2009005-09

NCV

Failure to Ensure a Safety-Related Plug was Ordered and 05000249/2009005-09

Installed in the 2/3 Emergency Diesel Generator

Turbo Lube Oil Y Strainer (Section 4OA3.3)05000237/2009004-04

URI

Inspector Identified Control Room Alarm Isolation Valve 05000249/2009004-04

Out-of-Position (1R15)05000237/2009003-01

URI

Failure of 2/3 Emergency Diesel Generator (EDG) Due to 05000249/2009003-01

Lube Oil Leak On Y-Strainer (4OA3.3)

05000237/2009-001-00

LER

Common Mode Failure of Reactor Building Isolation

05000249/2009-001-00

Dampers (4OA3.1)

05000249/2009-001-00

LER

Unit 3 Group 1 Isolation and Automatic Reactor Scram

(4OA3.2)

05000237/2009-003-00

LER

Emergency Diesel Generator Oil Leak (4OA3.3)

05000249/2009-003-00

Discussed:

Inspection Report 05000237/2008005; 05000249/2008005, Section 1R15 (4OA2.4)05000237/2009002-04

NCV

Failure to Take Corrective Actions to Replace a Degraded

Valve in a Timely Manner (4OA3.1)

4

Attachment

LIST OF DOCUMENTS REVIEWED

The following is a partial list of documents reviewed during the inspection. Inclusion on this list

does not imply that the NRC inspector reviewed the documents in their entirety, but rather that

selected sections or portions of the documents were evaluated as part of the overall inspection

effort. Inclusion of a document on this list does not imply NRC acceptance of the document or

any part of it, unless this is stated in the body of the inspection report.

1R04 Equipment Alignment (71111.04)

- WO 1079566-01, Perform 250V Station Battery Service Test

- C/O 76319, (ASSY) Battery 250V U2

- DOP 7500-M1/E1, Unit 2/3 Standby Gas Treatment, Revision 6

1R05 Fire Protection (71111.05)

- IR 976782, NRC Observations from U3 Rx Bldg. 570 Pre-Plan Review

1R08 Inservice Inspection Activities (71111.08G)

- IR 00992912; Material Certification of Recirc Piping Could not be Found; November 13, 2009

- IR 00911408;Section XI Class 2 Boundary; April 28, 2009

- IR 00889729; LPCI Heat Exchanger Recordable Indications; March 6, 2009

- IR 00782956; Corrosion Pipe Elbow B CST Tank; June 6, 2008

- IR 00755744; 2/3 EDG Leak on Engine Block; March 28, 2008

- IR 00711323; 2/3 DGCW Pump Suction Pipe Corrosion; December 14, 2007

- IR 00705912; Unit 2 CCSW System Corrosion; December 2, 2007

- IR 00705639; DGCW Pipe Corrosion; December 2, 2007

- IR 00695137; Unit 2 Reactor Head Flange MT Indication; November 8, 2007

- IR 00691069; Loose Anchor Bolt on CS Line; October 31, 2007

- IR 00681657; PT Rejectable Indication; October 22, 2007

- ASME Section XI Repair/Replacement Plan 2-1505A-12-0; April 1, 2009

- Certified Mill Test Report (Consolidated Power Supply); 12 Safety-Related 90 Elbow;

September 15, 2009

- EC 368360; Evaluation of Leakage at Bolted Connections and other Recordable Indications;

Revision 0

- Examination Summary Sheet; D2R21-028 UT of PS2/201-1; November 7, 2009

- Examination Summary Sheet; D2R21-029 UT of PS2-Tee/202-4B; November 7, 2009

- NDE Report No.09-294; VT-3 Visual Examination; November 13, 2009

- NDE Certification; Scott R. Erickson; UT Level III; October 6, 2009

- Procedure GE-PDI-UT-2; PDI Generic Procedure for the Ultrasonic Examination of Austenitic

Pipe Welds; Revision 4

- Procedure GE-PDI-UT-3, PDI Generic Procedure for the Ultrasonic Thru Wall Sizing in Piping

Welds, Revision 2

- Procedure ER-AA-335-018, Detailed General VT-1, VT-1C, VT-3 and VT-3C Visual

Examination of ASME Class MC and CC Containment Surfaces and Components; Revision 5

- Procedure ER-AA-335-1008; Code Acceptance and Recording Criteria for Nondestructive

Surface Examination; Revision 1

- Procedure Qualification Record; A-001; October 19, 1998

- Procedure Qualification Record; A-002; March 9, 1997

- Procedure Qualification Record; 1-50C; January 3, 1984

5

Attachment

- Report No. D2R20-037; Four Indications on the Reactor Head Flange Weld (2RPV UPP

HD/2-THD-FLG); November 11, 2007

- Weld Procedure Specification; 1-1-GTSM-PWHT; Revision 1

- Welder Qualification Record; W2677; October 5, 2009

- Work Order 01189798; Replace Degraded Elbow on 2A CCSW Pump; October 22, 2009

1R12 Maintenance Effectiveness (71111.12)

- Z03, "Control Rod Drive Maintenance Rule Performance Criteria"

- IR 845878, "Scram Dump Valve Leaking", 11/17/2008

- IR 763023, "Review Maintenance Rule Functions Perform review described in In-Progress

Notes", 5/30/2008

- IR 842585, "Handwheel Spins with no Valve Movement", 11/09/2008

- IR 842587, "Valve Handwheel Broken", 11/09/2008

- IR 843592, "HCU P6 Scram Valve Packing Leak", 11/11/2008

- IR 700134, "Relief Valve Continuously Lifted", 11/16/2007

- IR 976292, "CRD Exercising and Condenser Vacuum Scram Impact U3 Restart", 10/05/2009

- WO 1186809, "Scram Dump Valve Leaking", 11/17/2008

- M-34, "Diagram of Control Rod Drive Hydraulic Piping", Revision W

- TS 3.1.3, Control Rod Operability

- TS 3.1.4, Control Rod Scram Times

- TS 3.1.5, Control Rod Scram Accumulators

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)

- IR 1009039, 345 kv Line 8014 trip

1R15 Operability Evaluations (71111.15)

- Operability Evaluation No.09-007, 2A LPCI Heat Exchanger (2-1503-A)

- EC 372200, Perform Evaluation of Thermal Performance Test Data of 2A LPCI Hx

- EC 377036, 2A LPCI Heat Exchanger September 18, 2009 Thermal Performance Test

- IR 978203, GL 89-13 Program Health Color Change

- IR 989609, D2R21 Inspection Results for 2A LPCI Heat Exchanger

- IR 990189, 2A LPCI Heat Exchanger Tubesheet Corrosion

- IR 990209, 2A LPCI Hx Top Coverplate Coating Bubbled

- IR 996991, A LPCI HT Exchanger Shell Side RV Lifting

- CY-DR-110-220, LPCI Service Water (CCSW) and Torus Water Sampling, Revision 3

- CY-DR0120-413, Cooling and Service Water Chemical Injection System, Revision 8

- Root Cause Report 967008-03, Dresden 2-1503-A, 2A Low Pressure Coolant Injection

(LPCI)/Containment Cooling Heat Exchanger (Hx) Failure to Meet Design Basis Heat Removal

Capability due to Asiatic Clam Macrofouling Resulting from 2-1501-3A Valve Leakage and

Subsequent Untreated Service Water Make-Up via the CCSW Keepfill Diluting the Biocide

Treatment below the Asiatic Clam Lethal Concentration

- Focus Area Assessment, Dresden Station, CCSW System Asiatic Clam Fouling. Performed

by Water Technology Consultants, Inc.

- EC Evaluation 373443, Evaluation of Leakage From Cylinder Head Covers on 2A SBLC

Pump

- WO1001541-76, 3B SBLC System Pump Test for Operability Verification

6

Attachment

1R19 Post-Maintenance Testing (71111.19)

- IR 1003797, TSC HVAC Surveillances Failed

- WO 1294151, D1/2/3 SAN PM Operability Surv for the TSC AFUs

- DOS 5750-05, Semi-Annual Technical Support Center (TSC) Air Filtration Unit (AFU)

Operability Test, Revision 15

- IR 348426, FIC-2/3-5748-93 Airflow Indication Not Actual Airflow

- WO 826129, FIC-2/3-5748-93 Airflow Indication Not Actual Airflow

- IR 1005336, TSC Flow Controller Range Issue

- EP-AA-1000, Standardized Radiological Emergency Plan, Revision 19

- EP-AA-112-200-F-01, Station Emergency Director Checklist, Revision F

- NUREG-0696, Functional Criteria for Emergency Response Facilities, February 1981

- NUREG-0737, Clarification of TMI Action Plan Requirements, Supplement No. 1,

January 1983.

- M-3006, Technical Support Center HVAC & Plumbing Layout, Revision F

- DOS 6600-01, Diesel Generator Governor Oil Change and Compensating Adjustment,

Revision 23

- IR 992803, U2 EDG Largest Load Reject (TSR 3.8.1.10)

- IR 994101, 2/3 EDG Voltage Transient

- DOS 6600-06, Bus Undervoltage and ECCS Integrated Functional Test for Unit 2/3 Diesel

Generator to Unit 2, Revision 46

- IR 997244, Recirc Pump Instruments not Functioning Reqd for Hydro

- IR 997142, CCP: MCR Panel 923-5 Lost Ventilation Equip Indications

- EC 378040, 2/3 EDG Overvoltage during Division I Undervoltage Surveillance, Revision 0

- IR 1005291, Inaccurate Information Included in IR 994101

- IR 1006989, Control Room Indicators Deenergized

- EACE 994101-07, 2/3 Emergency Diesel Generator (EDG) Voltage Transient

- IR 987850, D2R21 As Found LLRT on 2-0203-2C Exceeded Leakage Limit

- DOS 0250-02, Full Closure Timing and Exercising of Main Steam Isolation Valves, Rev 26

- DOS 0250-03, Main Steam Isolation Valve Fail-Safe Closure Test, Rev 21

- IR 1001725, Higher than Expected Vibrations on 2B Cond Pp.

- IR 1002609, FME: Found in 2B Condensate Pump Suction Piping

- ER-AA-2006, Lost Parts Evaluations, Revision 6

- WO 1098975, 2B Condensate Booster Motor Alignment

- DOP 3300-02, Condensate System Startup, Revision 50

- M-15, Diagram of Condensate Piping, Revision J

- MA-AA-716-012, Post-Maintenance Testing, Revision 11

- MA-AA-716-230-1002, Vibration Analysis/Acceptance Guideline, Revision 2

1R20 Outage (71111.20)

- DGP 01-01, Unit Startup, Revision 153

- IR 975280, 3B CRD FCV Failed to Operate Remotely

- IR 975813, D3F48LL: DEHC Alarms During U3 Chest Warming

- IR 975830, D3F48LL: DEHC Issues During Turbine Roll

- IR 976410, CIV #1 Indicates 57% Open. LVDT Position Indication Failure

7

Attachment

1R22 Surveillance Testing (71111.22)

- IR 984934, DOS 6620-07 SBO Surveillance Need Revision

- IR 745855, "Unable to Close SBO Diesel Onto Bus"

- IR 984179, "Unit 2 SBO Preparation for Standby Readiness Deficiency"

- DOS 6620-07, "SBO 2(3) Diesel Generator Surveillance Tests, Revision 28

- DOP 6620-20, "SBO D/G 2(3) Prelubrication and Barring for Normal Start", Revision 06

- DOA 6500-11, "4 KV Bus Overvoltage," Revision 05

- WO 1257282, "Perform DOS 6620-07, D2 SBO Surveillance," 10/26/2009

- WO 1079209-01, D2 30M/RFL TS LLRT MSIV 203-1B & 203-2B Dry Test

- WO 1077724-01, D2 30M/RFL TS LLRT MSIV 203-1C & 203-2C Dry Test

- WO 1077725-01, D2 30M/RFL TS LLRT MSIV 203-1D & 203-2D Dry Test

- WO 1081285-01, D2 20M/RFL TS LLRT MSIV 203-2A Wet Test

- WO 1079266-01, D2 30M/RFL TS LLRT MSIV 203-2B Wet Test

- WO 1081288-01, D2 30M/RFL TS LLRT MSIV 203-2C Wet Test

- WO 1081313-01, D2 30M/RFL TS LLRT MSIV 203-2D Wet Test

- DOS 7000-01, Local Leak Rate Testing of Main Steam Isolation Valves (Dry Tests), Rev 5

- DOS 7000-02, Local Leak Rate Testing of Main Steam Isolation Valves (Wet Test), Rev 2

- IR 987850, D2R21 As Found LLRT on 2-0203-2C Exceeded Leakage Limit

- IR 987852, D2R21 As Found LLRT on 2-0203-1D Exceeded Leakage Limit

- DIS 1500-01, Reactor Low Pressure (350 PSIG) ECCS Permissive, Revision 27

- IR 944688, Test Valves Not Installed on CST Level Switches (HPCI Logic)

1EP4 Emergency Action Level and Emergency Plan Changes

- Dresden Station Radiological Emergency Plan Annex; Revisions 23, 24, and 25

2OS1 Access Control to Radiologically Significant Areas (71121.01)

- AR 987949987949 Operator PCE in Clean Area above Drywell Bullpen; November 3, 2009

- AR 993194993194 Responding to Guardhouse Portal Monitor Alarm; November 13, 2009

- RP-AA-203-1001; Personnel Exposure Investigation, Revision 6

- RP-AA-210; Dosimetry Issue, Usage and Control; Revision 15

- RP-AA-220; Intake Investigation, Revision 5

- RP-AA-350-1001; Response to Guardhouse Portal Monitor Alarms, Revision 0

- Underwater Construction Corporation Safe Practices Manual, Attachment A: Safety Hazard

Analysis/Dive Plan; November 3, 2009

2OS2 As-Low-As-Reasonably-Achievable Planning and Controls (71121.02)

- RWP 10010408; D2R21 Drywell Nuclear Instrumentation System Maintenance; Revision 0

- RWP 10010420; D2R21 Drywell Control Rod Drive System Maintenance; Revision 0

- RWP 10010421; D2R21 Drywell Control Rod Drive System Support; Revision 0

- RWP 10010426; D2R21 Drywell In-Service Inspection; Revision 0

- RWP 10010437; D2R21 Torus Diving Activities; Revision 1

- RWP 10010452; D2R21 Reactor Disassembly/Reassembly and Related Activities; Revision 1

- AR 870602-03; Focused Area Self-Assessment: ALARA Planning for Outage Readiness and

Preparation; August 27, 2009

- AR 988447988447 Unit 2 Refuel Floor and Reactor Building Low Level Contamination;

November 3, 2009

8

Attachment

- AR 990061990061 Under Vessel General Electric Worker Receives Small Ingestion;

November 5, 2009

- AR 993319993319 Shaw Laborer Wiping Down cords on RB 613 300K Particle on Scrubs;

November 11, 1009

- RWP-WIP-10010388; D2 R21 Scaffold Installation/Removal Activities (Excluding Drywell);

November 7, 2009

- RP-AA-461; Radiological Controls for Contaminated Water Diving Operations; Revision 2

- RWP-WIP-10010403; D2 R21 Drywell Radiation Protection Department Activities;

November 6, 2009

- RWP-WIP-10010403; D2 R21 Drywell Radiation Protection Department Activities;

November 10, 2009

- RWP-WIP-10010437; D2 R21 Torus Diving Activities; November 10, 2009

- RWP-WIP-10010453; D2 R21 Refuel Floor IVVI Activities; November 7, 2009

4OA1 Performance Indicator (PI) Verification (71151)

- LS-AA-2140; Monthly Data Elements for NRC Occupational Exposure Control Effectiveness;

Revision 4

4OA2 Identification and Resolution of Problems (71152)

- RCR 776598-08, Dresden 3-1503-B, 3B Low Pressure Coolant Injection (LPCI) / Containment

Cooling Heat Exchanger (HX) Failure to Meet Design Basis Heat Removal Capability Due to

Inadequate Programmatic Control of Macrofoulants, Revision 0

- IR 868703, 2A and 2B LPCI Heat Exchanger Samples Tested 0 PPM Biocide

- IR 871271, Biocide Injection Unavailable for CCSW System PMT Run

- IR 877889, Biocide Injection Not Available During U3 CCSW Run

- IR 880708, CCSW Biocide/Clam-Trol Chemical Injection Result Low

- IR 881043, CCSW Biocide/Clamtrol Chemical Injection Result Low

- IR 883155, 3A and 3B LPCI Fail Clam-Trol Test

- IR 884613, 2B LPCI Failed Clam-Trol Test

- IR 887406, Inadequate Biocide Retention

- IR 888462, 0 PPM Biocide Results for 2/3 EDG

- IR 889598, No Biocide Found in Unit 2B LPCI CCSW Hx Lay-up Sample

- IR 891286, No Biocide Found in 2B LPCI CCSW Hx Lay-up Sample

- IR 892241, Procedure change and Eval of Biocide Injection to DGCWPs

- IR 905027, 2B LPCI No Clamtrol Present

- IR 905224, No Biocide Detected in 2/3 DGCSW

- IR 908886, 2A LPCI Biocide Results Less than 8 PPM

- IR 914398, Revision to RCR 776598-08, 3B LPCI Hx Macrofouling Required

- IR 915033, 2A LPCI SW Biocide 24 hr. Sample < 8PPM

- IR 917133, 2B LPCI Failed Clam-Trol Test

- IR 920498, 2A and 2B LPCI SW Biocide <8PPM (24hr Sample)

- IR 923788, Clam-Trol Analysis Failed on 3DGCSW

- IR 999766, 2B LPCI Failed for Biocide

- IR 1000791, 2B LPCI Heat Exchanger Failed Clam-Trol Analysis

- IR 1006553, No Biocide Detected in CCSW from 3B LPCI Hx

- IR 1007918, Unit 2 A and B LPCI Heat Exchangers Fail 18-24 hr Biocide

9

Attachment

4OA3 Follow-Up of Events (71153)

- Licensee Event Report 237/2009-003-00, Emergency Diesel Generator Oil Leak, Revision 00

- IR 926605, Oil Leak on the 2/3 DG Turbo Lube Oil Y-strainer

- MA-AA-716-008, Foreign Material Exclusion Program, Revision 4

- Licensee Event Report 237/2009-001-00, Common Mode Failure of Reactor Building Isolation

Dampers, Revision 00

- IR 877591, Potential 10CFR50 Part 21 Notification of Versa Air Solenoid

- IR 838034, RBV Damper 2-5742-A Slow to Close

- IR 842305, 3-5742-B Damper 90 Seconds to Close

- IR 888338, RBV Isolation Damper Solenoid Valve Incorrect Component Classification

- IR 975779, Post Transient/Scram Walkdown Observation by NRC

- IR 975076, U2/3 EDG Started on Rx Trip when Aux Power Transferred

- IR 974426, U3 Group 1 Isolation and Reactor Scram

- IR 973968, 3A RWCU Pump Tripped and DOA Entry

- IR 973144, RWCU Isolate on High Temperature

- IR 973104, 3A RWCU Tripped

- Root Cause Report 974426-04, U3 Reactor SCRAM and Group 1 Isolation Resulting in

Forced Outage D3F48 Due to DOP 1200-03, titled RWCU System Operation with the Reactor

at Pressure Latent Procedural Deficiency

- LER 249/2009-001-00, Unit 3 Group 1 Isolation and Automatic Reactor Scram

- IR 990113, U3 from 650 MWe to 0 and a Turbine Trip

- IR 990160, 2/3 EDG Auto Started when U3 Main Generator was Tripped

- IR 990112, Need WO Rolled for Repair to U3 EHC Filter Pump Bkr

- IR 990110, U3 EHC Filter Pmp Trip

- IR 990661, MSV #4 Did Not Open During Initial Turbine Roll

4OA5 Other Activities (TI 2515/177)

- IR 994774, Procedures for Venting ECCS/SDC Systems Should Be Revised

- IR 999625, Air Found in HPCI Discharge Piping During UT

- IR 999762, Air Found in Second Location in HPCI Discharge Piping

- IR 1014280, Question from NRC Inspector on ISI Drawing

- EC 371153, Rev 2, NRC GL 2008-01 HPCI System Evaluation

- DOP 2300-01, HPCI Standby Operation, Rev 41

- M-51, Diagram of High Pressure Coolant Injection Piping, Rev CL

- ISI-504, System Pressure Test Walkdown Isometric MSIV Room - X Area, Rev B

- ISI-510, System Pressure Test Walkdown Isometric H.P. Coolant Injection Piping, Sheet 2,

Rev D

- M-1151C-2, Computer Math Model High Pressure Coolant Injection System, Sheet 1, Rev 2

- M-4455, HPCI High Point Vent Line, Sheet 3, Rev A

10

Attachment

LIST OF ACRONYMS USED

ADAMS

Agencywide Document Access Management System

AEER

Auxiliary Electric Equipment Room

ALARA

As-Low-As-Reasonably-Achievable

ASME

American Society of Mechanical Engineers

BWR

Boiling Water Reactor

CAP

Corrective Action Program

CCSW

Containment Cooling Service Water

CDF

Core Damage Frequency

CFR

Code of Federal Regulations

CO

Clearance Order

CRD

Control Rod Drive

D2

Dresden Unit 2

DRP

Division of Reactor Projects

EACE

Equipment Apparent Cause Evaluation

EAL

Emergency Action Level

EC

Engineering Change

EDG

Emergency Diesel Generator

ESI

Engine Systems Incorporated

FME

Foreign Material Exclusion

GE

General Electric

HEP

Human Error Probability

HEPA

High Efficiency Particulate Air

HPCI

High Pressure Coolant Injection

HCU

Hydraulic Control Unit

Hx

Heat Exchanger

IPEEE

Individual Plant Examination for External Events

IMC

Inspection Manual Chapter

INPO

Institute of Nuclear Power Operations

IP

Inspection Procedure

IR

Issue Report

ISI

Inservice Inspection

IST

In-service Test

LER

Licensee Event Report

LERF

Large Early Release Frequency

LOCA

Loss of Coolant Accident

LOOP

Loss of OffSite Power

LPCI

Low Pressure Coolant Injection

MOV

Motor Operated Valves

MSV

Main Stop Valve

NCV

Non-Cited Violation

NEI

Nuclear Energy Institute

NLO

Non-Licensed Operator

NRC

Nuclear Regulatory Commission

NRR

Office of Nuclear Reactor Regulation

NSO

Nuclear Station Operator

OSF

Outage Safety Plan

PARS

Publicly Available Records

PCIS

Primary Containment Isolation Signal

PI

Performance Indicator

11

Attachment

P&ID

Piping and Instrumentation Diagrams

PM

Planned or Preventative Maintenance, or Post-Maintenance

PO

Purchase Order

RCR

Root Cause Report

RCS

Reactor Coolant System

RFO

Refueling Outage

RPV

Reactor Pressure Vessel

RWCU

Reactor Water Cleanup

SBLC

Standby Liquid Control

SBO

Station Blackout

SCAQ

Significant Condition Adverse to Quality

SDP

Significance Determination Process

SPAR

Standardized Plant Analysis Risk

SR

Surveillance Requirements

SRO

Senior Reactor Operator

SSC

Structures, Systems and Components

TS

Technical Specification

U2

Unit 2

U3

Unit 3

UFSAR

Updated Final Safety Analysis Report

URI

Unresolved Item

UT

Ultrasonic Examination

WO

Work Order

C. Pardee

-2-

In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its

enclosure, and your response (if any) will be made available electronically for public inspection

in the NRC Public Document Room or from the Publicly Available Records (PARS) component

of NRCs document 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/

Mark A. Ring, Chief

Branch 1

Division of Reactor Projects

Docket Nos. 50-237; 50-249

License Nos. DPR-19; DPR-25

Enclosure:

Inspection Report 05000237/2009-005; 05000249/2009-005

w/Attachment: Supplemental Information

cc w/encl:

Distribution via ListServ

DOCUMENT NAME: G:\\1-SECY\\1-WORK IN PROGRESS\\DRE 2009 005.DOC

G Publicly Available

G Non-Publicly Available

G Sensitive

G Non-Sensitive

To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl

"E" = Copy with attach/encl "N" = No copy

OFFICE

RIII

RIII

RIII

RIII

NAME

MRing:cms

DATE

02/10/2010

OFFICIAL RECORD COPY

Letter to C. Pardee from M. Ring dated February 10, 2010

SUBJECT:

DRESDEN NUCLEAR POWER STATION, UNITS 2 AND 3

INTEGRATED INSPECTION REPORT 05000237/2009-005;

05000249/2009-005

DISTRIBUTION:

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