Text

IR 05000348-05-008, IR 05000364-05-008, on 08/08-12/2005 and 08/22-26/2005, Joseph M. Farley, Units 1 and 2, Identification and Resolution of Problems
	ML052660339
Person / Time
Site:	Farley
Issue date:	09/24/2005
From:	Widmann M; NRC/RGN-II/DRP/RPB2
To:	Stinson L; Southern Nuclear Operating Co
References
	IR-05-008
	Download: ML052660339 (34)
	v • d • e

September 24, 2005

Southern Nuclear Operating Company, Inc.

ATTN: Mr. L. M. Stinson

Vice President - Farley Project

P. O. Box 1295

Birmingham, AL 35201-1295

SUBJECT: JOSEPH M. FARLEY NUCLEAR PLANT - NRC PROBLEM IDENTIFICATION

AND RESOLUTION INSPECTION REPORT 05000348/2005008 AND

05000364/2005008

Dear Mr. Stinson:

On August 26, 2005, the U. S. Nuclear Regulatory Commission (NRC) completed a team

inspection at the Joseph M. Farley Nuclear Plant. The enclosed report documents the

inspection results which were discussed on August 25, 2005, with Mr. Todd Youngblood and

other members of your staff.

This inspection was an examination of activities conducted under your licenses as they relate to

the identification and resolution of problems, and compliance with the Commissions rules and

regulations, and the conditions of your operating licenses. Within these areas, the inspection

involved selected examination of procedures and representative records, observations of

activities, and interviews with personnel.

Based on the sample selected for review, the team concluded that, in general, problems were

properly identified, evaluated, and corrected. There were two NRC-identified findings and one

self-revealing finding of very low safety significance (Green) identified during this inspection.

One NRC-identified finding and the self-revealing finding were determined to be violations of

NRC requirements. The remaining finding is associated with a failure to correct a long-standing

condition adverse to quality. The first violation is associated with a failure to promptly identify a

condition adverse to quality and the second violation is associated with inadequate corrective

actions to preclude recurrence. However, because of their very low safety significance and

because they have been entered into your corrective action program, the NRC is treating these

violations as non-cited violations in accordance with Section VI.A of the NRCs Enforcement

Policy. If you deny any of these findings, you should provide a response within 30 days of the

date of this inspection report, with the basis for your denial, to the Nuclear Regulatory

Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the

Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear

Regulatory Commission, Washington DC 20555-0001; and the NRC Resident Inspector at the

Farley Nuclear Plant.

In addition, several examples of minor problems were identified including equipment failures

that were inappropriately classified as not being functional failures, industry operating

SNC 2

experience that was ineffectively evaluated, and past operability determinations that lacked

proper documentation.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its

enclosure will be available electronically for public inspection in the NRC Public Document Room

or from the Publicly Available Records (PARS) components of NRCs document system (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the

Public Electronic Reading Room).

Sincerely,

\RA\

Malcolm T. Widmann, Chief

Reactor Projects Branch 2

Division of Reactor Projects

Docket Nos.: 50-348 and 50-364

License Nos.: NPF-2 and NPF-8

Enclosure: NRC Inspection Report 05000348/2005008

and 05000364/2005008

w/Attachment: Supplemental Information

cc w/encl: (See page 3)

SNC 3

cc w/encl:

B. D. McKinney, Licensing

Services Manager, B-031

Southern Nuclear Operating

Company, Inc.

Electronic Mail Distribution

J. R. Johnson

General Manager, Farley Plant

Southern Nuclear Operating

Company, Inc.

Electronic Mail Distribution

J. T. Gasser

Executive Vice President

Southern Nuclear Operating

Company, Inc.

Electronic Mail Distribution

State Health Officer

Alabama Department of Public Health

RSA Tower - Administration

201 Monroe St., Suite 700

P. O. Box 303017

Montgomery, AL 36130-3017

M. Stanford Blanton

Balch and Bingham Law Firm

P. O. Box 306

1710 Sixth Avenue North

Birmingham, AL 35201

William D. Oldfield

Quality Assurance Supervisor

Southern Nuclear Operating Company

Electronic Mail Distribution

Distribution w/encl: (See page 4)

_________________________

OFFICE RII:DRP RII:DRP RII:DRP RII:DRS

SIGNATURE REC1 JBB5 RJR1 ADN

NAME RCarroll:rcm JBaptist RReyes ANielsen

DATE 09/ /2005 09/ /2005 09/ /2005 09/ 2005

E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO

U. S. NUCLEAR REGULATORY COMMISSION

REGION II

Docket Nos: 50-348 and 50-364

License Nos: NPF-2 and NPF-8

Report Nos: 05000348/2005008 and 05000364/2005008

Licensee: Southern Nuclear Operating Company, Inc.

Facility: Joseph M. Farley Nuclear Power Plant, Units 1 and 2

Location: 7388 N. State Highway 95

Columbia, AL 36319

Dates: August 8 - 12, 2005, and August 22 - 26, 2005

Inspectors: R. Carroll, Senior Project Engineer (Lead Inspector)

J. Baptist, Resident Inspector - Farley

R. Reyes, Resident Inspector - Crystal River

A. Nielsen, Health Physics Inspector

Approved by: Malcolm T. Widmann, Chief

Reactor Projects Branch 2

Division of Reactor Projects

Enclosure

SUMMARY OF ISSUES

IR 05000348/2005-008 and 05000364/2005-008; 08/08/2005 - 08/12/2005 and 08/22/2005 -

08/26/2005; Joseph M. Farley Nuclear Plant, Units 1 and 2; Identification and Resolution of

Problems.

The inspection was conducted by a senior project engineer, two resident inspectors, and a

health physics inspector. Three Green findings were identified of which two were non-cited

violations (NCVs). The significance of most findings is indicated by their color (Green, White,

Yellow, Red) using IMC 0609,Significance Determination Process (SDP). Findings for which

the SDP does not apply may be Green or be assigned a severity level after NRC management

review. The NRC's program for overseeing the safe operation of commercial nuclear power

reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.

Problem Identification and Resolution (PI&R)

The team determined that the licensee was generally effective in identifying problems and

entering them into the corrective action program (CAP). The threshold for problem

identification was determined to be low. CAP-related audits were effective in identifying

deficiencies for resolution. Condition Report trending under the CAP has had success in

bringing about corrective actions for identified adverse trends. The team determined that the

licensee properly prioritized issues entered into the CAP. Generally, the licensee performed

adequate evaluations that were technically accurate and sufficiently detailed. Corrective

actions developed and implemented for problems were generally timely, effective, and

appropriate to the problem. One Green finding for failure to correct a long-standing condition

adverse to quality and two Green non-cited violations for a failure to promptly identify a

condition adverse to quality and inadequate corrective actions to preclude recurrence were

identified. In addition, several examples of minor problems were identified including equipment

failures that were inappropriately classified as not being functional failures, industry operating

experience that was ineffectively evaluated, and past operability determinations that lacked

proper documentation. Management emphasized the need for staff to identify and resolve

issues using the CAP. A safety conscious work environment was evident.

A. NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green. An NRC-identified non-cited violation of 10 CFR Part 50, Appendix B, Criterion

XVI, was identified for failure to take corrective actions to preclude repetition of a

significant condition adverse to quality. Specifically, corrective actions taken to develop

a solid state protection system (SSPS)/7300 troubleshooting guideline following a Unit 2

SSPS/7300 troubleshooting-related reactor trip on April 12, 2004, was inadequate to

preclude the recurrence of another SSPS/7300 troubleshooting-related event on April

28, 2005.

This finding is more than minor because it affects the Mitigating Systems Cornerstone

attribute of equipment performance and adversely impacted the cornerstone objective in

that the SSPS/7300 troubleshooting guidance did not provide the necessary steps to

facilitate timely (i.e., within the TS LCO) determination of a SSPS/7300 process channel

Enclosure

2

failure. This finding is of very low safety significance because the B train of SSPS was

maintained operable at all times. (Section 4OA2c.(2)(b))

Cornerstone: Barrier Integrity

Green. A self-revealing non-cited violation of 10 CFR 50, Appendix B, Criterion XVI,

Corrective Action, was identified for failure to identify a significant condition adverse to

quality. Specifically, following the July 15, 2003, trip of the 1A containment spray pump

room cooler, the licensee failed to identify an existing degraded time delay relay.

Consequently, for the period between July 15, 2003, until corrected on May 1, 2004, the

degraded condition of the 1A containment spray pump room cooler rendered it

vulnerable to run/stop/hot restart scenarios that could be encountered during the

response to a large break loss of coolant accident (LOCA).

This finding is more than minor because it affects the Barrier Integrity Cornerstone

attribute of Barrier Performance and impacted the cornerstone objective in that tripping

of the room cooler could result in loss of the 1A containment spray pump safety function

due to overheating. This finding is of very low safety significance (Green) because the

1B containment spray pump and room cooler and all containment coolers were available

to ensure containment barrier integrity would be maintained in the event of a large break

LOCA or containment over pressure challenge. (Section 4OA2c.(2)(a))

Green. An NRC-identified finding was identified for untimely resolution of excessive air

flow problems on the Unit 1 and Unit 2 Containment Air Particulate Radiation Monitors

(R-11). Excessive air flow through the moving filter paper caused the monitor to

become inoperable on numerous occasions since 1990. When R-11 was out of service,

the ability to detect low-level reactor coolant system (RCS) leakage was degraded.

This finding is more than minor because it is associated with the RCS Equipment and

Barrier Performance Attribute of the Barrier Integrity Cornerstone and adversely affects

the cornerstone objective in that the ability to detect low-level RCS leakage that may

indicate pressure boundary degradation was reduced. This finding could not be

evaluated using the Significance Determination Process (SDP) in accordance with IMC 0609 because the SDP for the RCS barrier only applied to a degraded barrier; not the

ability to detect a degraded barrier. Therefore, this finding was reviewed by regional

management and determined to be of very low safety significance (Green) because

alternate methods of detecting low-level RCS leakage were available whenever R-11

was out of service. (Section 4OA2c.(2)(c))

B. Licensee-identified Violations

None

Enclosure

REPORT DETAILS

4. OTHER ACTIVITIES (OA)

4OA2 Problem Identification and Resolution (PI&R)

a. Effectiveness of Problem Identification

(1) Inspection Scope

The team reviewed selected condition reports (CRs) initiated since the previous NRC

PI&R inspection, conducted September 2003, to verify that problems were being

properly identified, appropriately characterized, and entered into the corrective action

program (CAP). The reviews primarily focused on issues associated with five risk

significant plant safety system areas: nuclear service water (SW); auxiliary feedwater;

component cooling water; emergency core cooling systems (ECCS); and vital electrical

systems. In addition to the system reviews, the team selected a sample of CRs that

were related to radiation protection and emergency preparedness to ensure coverage of

those cornerstones. The team also reviewed those CRs associated with licensee event

reports and findings identified in NRC inspection reports (IRs) issued since the last PI&R

inspection.

The team reviewed completed maintenance work orders (WOs), system health reports,

and the Maintenance Rule (MR) database for the five selected system areas to verify

that equipment deficiencies were being appropriately entered into the CAP and the MR

program. The team conducted walkdowns of equipment associated with the selected

systems to assess the material condition and to look for any deficiencies that had not

been entered into the CAP. The team reviewed temporary modifications, the main

control room deficiency list, operator workaround list, failed surveillances and any

acceptance criteria changes, control room operator logs, and the employee concerns

program to verify that equipment deficiencies (especially those involving the selected

systems) were entered into the CAP.

The team reviewed selected industry operating experience (OE) items, including NRC

generic communications, to verify that both types were appropriately evaluated for

applicability and whether issues identified through these reviews were entered into the

CAP. The team reviewed several licensee audits (focusing primarily on problem

identification and resolution) to verify that findings were entered into the CAP and to

verify that these findings were consistent with the NRCs assessment of the licensees

CAP. Trending of CRs under the CAP was also reviewed to determine if licensee-

identified trends were captured for resolution and if CAP statistics indicated any trends

that were not identified by the licensee.

The team attended several daily management update and site corrective action program

coordinator (CAPCO) meetings, as well as a corrective action review board meeting to

observe management and department CAPCO oversight functions in the corrective

action process. The team also interviewed personnel from operations, maintenance,

engineering, health physics, and emergency preparedness to evaluate their threshold

for identifying issues and entering them into the CAP.

Enclosure

2

Documents reviewed are listed in the Attachment.

(2) Assessment

The team determined that the licensee was effective in identifying problems and

entering them into the CAP. There was, however, one issue identified involving the

July 16, 2004, remote shutdown capability test of the 1C SW pump, in which the

necessity to cycle its associated switch twice before starting was recorded on the

surveillance test result sheet (STRS) of FNP-1-24.20; but, not in a CR where it could be

evaluated and trended under the CAP. Performance/documentation of such switch

cycling/cleaning on the STRS was also found to be permitted in precaution/limitation

4.4 of FNP-1-STP-73.1, Hot Shutdown Operability Verification; thereby, making it

potentially vulnerable to bypassing the CAP as well. To address this and related switch

cycling/cleaning potential vulnerabilities, the licensee generated CRs 20055108397 and

2005203550.

Based on observed samples, independent walkdowns, and staff interviews, the

threshold for problem identification was low. CRs provided complete and accurate

characterization of the subject issues. Equipment performance issues involving

maintenance effectiveness were for the most part being appropriately identified and

entered into the CAP. However, the team identified two CRs (i.e., CR 2003003388,

Degraded 1C Diesel Generator Speed Signal Generator, and CR 2005104677, Failure

of Service Water Battery Charger #3 to Load) where the associated equipment failure

was inappropriately categorized as not being a functional failure. The licensee

generated CRs 2005108425 and 2005108446, which acknowledged the

mis-classifications and confirmed that the respective functional failures would not have

caused (past or present) the MR performance criteria for the affected functions to be

exceeded.

With the exception of the two examples discussed below, the licensee was effective in

evaluating internal and external industry operating experience items for applicability and

entering issues into the CAP:

NRC IR 05000348,364/2004004 identified that the licensees response to Information

Notice (IN) 94-68, Safety-Related Equipment Failures Caused By Faulted Indicating

Lamps, was narrow in scope and specifically did not address the diesel generators

(DGs). Although there had been a number of occurrences recorded in CRs involving

the DGs since 2000, actions taken had focused on restoring diesel operability and

more careful bulb replacement rather than eliminating the problem. The team verified

that the licensee had recently completed modifications to eliminate this problem on

both the diesels and the main steam atmospheric reliefs, as well as began an in-depth

review of the IN to determine if similar vulnerabilities exist.

As documented in NRC Triennial Fire Protection (TFP) IR 05000348,364/2005006, the

licensee inappropriately made the assumption that a fire could not cause the spurious

opening of both the inboard and outboard reactor coolant system (RCS)-to-residual

Enclosure

3

heat removal (RHR) system supply isolation valves. The effects of fire on these

valves was discussed in INs 87-50, Potential Loss of Coolant Accident (LOCA) at High

and Low Pressure Interfaces From Fire Damage, 92-18 Potential For Loss of Remote

Shutdown Capability During a Control Room Fire, and 99-17, Problems Associated

With Post Fire Safe Shutdown Circuit Analysis. The licensee did not properly evaluate

these INs and inappropriately concluded they were not vulnerable to this failure.

Consequently, Units 1 and 2 had maintained both valves in the two RCS-to-RHR

supply lines energized making them susceptible to a breach in the high pressure - low

pressure interface boundary between the RCS and RHR systems. When the

condition was identified during the April 2005 TFP inspection, the licensee was in the

process of reviewing the issue again under RIS 2004-03, Risk Informed Approach for

Post Fire Safe Shutdown Associated Circuit Inspections. Subsequently, on April 29,

2005, the licensee de-energized one train of valves on both units to prevent

inadvertent actuation due to a fire.

CAP-related audits performed by Performance Evaluation, Quality Assurance (QA), and

department CAPCOs were effective in identifying issues and entering these deficiencies

into the CAP for resolution. Site management was involved in the CAP and focused

attention on significant plant issues.

CR trending under the CAP has had success in bringing about corrective actions for

identified adverse trends; however, trend identification was primarily keyed on tripping

established thresholds based on increases in CR populations for a given area.

Consequently, issues common to smaller CR populations, such as the heat exchanger

problems noted in NRC IR 05000348,364/2005003 or missed procedural

interdependencies and out-of-specification Agastat testing results noted during the

teams CR reviews, may go undetected without rigorous reviews at either end of the CR

process. For the examples noted, all were confirmed by the team to have been

captured for resolution by means other then the formal trending process (e.g., system

engineer, CR evaluation, etc.). It was noticed that the site CAPCO recently began

identifying repeat issues for possible adverse trends; but, as of the time of this

inspection, the need to perform the intended trend assessments had not been captured

in a CR. NRC IR 05000348,364/2005003 also documented the resident inspectors

questioning the validity of the justifications used in dispositioning 14 potential adverse

trends identified in the November 2004 - January 2005 CAP trend report as no adverse

trend. The teams review of the February - April 2005 CAP trend report revealed that

during the managers trend report review two of the subject areas (i.e., fire equipment

and performance monitoring) were appropriately reclassified as actual adverse trends.

In addition, CR 2005106889 identified areas for improvement related to data trending

and more timely/in-depth management review (i.e., addition of tertiary event codes and

review of the trend report outside the weekly managers meeting within 45 days). The

potential adverse trends for the period of May - July 2005, including the need for

assessment before capturing them in the associated CAP trend report, had not been

identified in CRs as of the end of this inspection; therefore, corrective action

effectiveness could not be assessed.

Enclosure

4

b. Prioritization and Evaluation of Issues

(1) Inspection Scope

The team reviewed selected CRs in order to verify that the licensee properly classified

and evaluated the problems in accordance with procedure NMP-GM-002, Corrective

Action Program. Accordingly, the teams review also assessed if the licensee

determined the apparent cause (root and contributing causes for significant conditions

adverse to quality) of problems and adequately addressed operability, reportability,

common cause, generic concerns, and extent of condition. More than a third of the CRs

reviewed were classified as either Severity Level (SL) 2 (requiring a root cause and

corrective actions to prevent recurrence) or SL 3 (requiring an apparent cause and

corrective actions to reduce the likelihood of recurrence). There were no SL1 CRs in

the overall population from which the CRs were selected.

(2) Assessment

With the exception of CRs 200400795 and 2003000917, the team determined that the

licensee properly prioritized issues entered into the CAP. The CRs in question were

associated with non-cited violations and should have been prioritized as SL 3 (versus SL

5 and SL 4, respectively) in accordance with NMP-GM-002. This was considered

administrative in nature since the required apparent cause was performed for each one.

Overall, the licensee performed adequate evaluations that were technically accurate and

sufficiently detailed. Consistent with QA audit findings, the team noted the following

exceptions:

CR 2003000172, Unit 2 Solid State Protection System (SSPS) B Train Failure: During

surveillance testing of the Unit 2 SSPS B Train on January 29, 2003, and on March

21, 2003, the Logic C test failed at position 14 (Lo-Lo level start of the turbine driven

auxiliary feedwater pump (TDAFWP)). The licensee performed a root cause analysis,

but found there was not enough information available to make a root cause

determination. Therefore, various corrective actions were identified in the CR to be

performed so that data could be gathered in order to determine a root cause.

However, the team found that some of these corrective actions (i.e., resistance check

of logic switches to verify proper operation, failure analysis of the SSPS card, visual

inspections of card edge connections, and investigation into the cause of a bad card

selected from the warehouse) had not been completed. As a result, the root cause

was never determined; therefore, no past operability determination of the TDAFW

pump could be made. The CR described reasons why some of the actions were not

completed (e.g., too man power intensive, too costly, etc.). However, the decision not

to perform these corrective actions was not communicated to the root cause group as

required by NMP-GM-002. Furthermore, the licensees root cause effectiveness

review had determined that the corrective actions were effective when some of them

had never been completed and a root cause had never been determined. When

questioned about these discrepancies, the licensee initiated CR 2005108442.

Enclosure

5

CR 2004002293, Gas Accumulation in Suction of the 2B Coolant Charging/High Head

Safety Injection (HHSI) Pump: The licensee had identified that the 2B HHSI pump

discharge check valve had a flaw which allowed approximately 40 gallons per minute

(GPM) of reverse flow through the pump when idle. A formal operability determination

had been performed which determined that HHSI pump discharge flows had been

balanced within established limits. However, documentation was not readily available

to demonstrate that the effects of the idle pump (i.e., the reverse flow) had been

considered with respect to post-accident operation of HHSI pump 2A and/or 2C.

Informal/uncontrolled information was eventually provided to the team that

substantiated proper post-accident operation of the 2A and 2C HHSI pumps, but this

information was not inherent to the resolution of CR 2004002293 or any of its

supporting justifications.

CR 2004001281, 1A Containment Spray Pump Room Cooler Failure: The licensee

determined that a degraded time delay relay was the cause of the July 15, 2003, and

March 23, 2004, run/stop/hot restart trips experienced on the 1A containment spray

pump room cooler. Accordingly, the March 23, 2004, event was appropriately

identified by the licensee as a maintenance preventable failure. However, it was

apparent that the licensee had not considered past operability of the room cooler with

respect to its vulnerability to run/stop/hot restart scenarios that could be encountered

during the response to a large break loss of coolant accident (LOCA). (This condition

is further discussed in Section 4OA2c.(2)(a).)

Troubleshooting was considered an essential tool in problem evaluation. NRC IR

05000348,364/2004005 documented an observation of inconsistent troubleshooting

activities for 4160 volt breakers. The team also identified other troubleshooting-related

issues involving the evaluation/cause determination of failures in the SSPS/7300

process channels in Unit 2 and the failures of non-vital inverter 2F. SSPS/7300

troubleshooting is discussed further in Section 4OA2c.(2)(b) of this report. With respect

to the 2F inverter, troubleshooting efforts were unable to preclude two additional failures

(i.e., transfers to bypass on July 17 and 27, 2005) since its failure on July 1, 2005, which

resulted in returning to a MR (a)(1) status for the second time in two years. Suspecting

all three failures were the result of an intermittent transistor failure, the affected static

switch card was replaced after the third failure before returning the inverter to service in

August 2005. At that time, a more methodical approach to troubleshooting the 2F

inverter was implemented that included monitoring via an attached recorder. No further

failures of the 2F inverter had occurred by the conclusion of the inspection.

c. Effectiveness of Corrective Actions

(1) Inspection Scope

The team evaluated selected CRs to verify that the licensee had identified and

implemented timely and appropriate corrective actions to address problems. The team

determined whether the corrective actions were appropriate for the described problem,

as well as properly documented, assigned, and tracked to ensure completion. Selected

corrective actions were sampled for detailed review to independently verify that

Enclosure

6

corrective actions were implemented as intended. The sample selected for verification

included corrective actions associated with NRC findings and others from CRs

associated with the focus systems. Additionally, the team reviewed a sampling of the

oldest CRs to determine if implementation delays were appropriately justified.

(2) Assessment

Corrective actions developed and implemented for problems were generally timely,

effective, and appropriate to the problem. NRC IR 05000348,364/ 2004003 reflected

both the residents and licensees findings that corrective actions for several Severity

Level 2 (and 3) CRs had not always been sufficiently comprehensive to prevent (or

reduce the likelihood of) recurrence. As discussed below, the team identified similar

findings of missed opportunities for the CAP to promptly resolve problems.

(a) 1A Containment Spray Pump Room Cooler Failures

Introduction: A Green, self-revealing non-cited violation (NCV) of 10 CFR 50, Appendix

B, Criterion XVI, Corrective Action, was identified for failure to identify a significant

condition adverse to quality. Specifically, following the July 15, 2003 trip of the 1A

containment spray pump room cooler, the licensee failed to identify an existing

degraded time delay relay. Consequently, for the period between July 15, 2003, until

corrected on May 1, 2004, the degraded condition of the 1A containment spray pump

room cooler rendered it vulnerable to run/stop/hot restart scenarios that could be

encountered during the response to a large break LOCA.

Description: On March 23, 2004, during the performance of surveillance test procedure

FNP-1-STP-16.1, 1A Containment Spray Pump Quarterly In Service Test, the 1A

containment spray pump and its associated room cooler were stopped to facilitate

adding oil to the pump. About 1 - 3 minutes after restart of the pump and room cooler,

the room cooler tripped. Troubleshooting revealed the thermal overloads for the 1A

containment spray pump supply breaker had tripped. The thermal overloads were reset

and FNP-1-STP-16.1 was successfully completed. Operations personnel suggested

that this event was similar to an event which occurred on July 15, 2003, during the same

surveillance test. At the time of the July 2003 event, the 1A containment spray pump

room cooler had been running to support painting in the pump room when it was

stopped for the quarterly pump test. Approximately 1 - 3 minutes after starting the 1A

containment spray pump and room cooler, the room cooler tripped. The thermal

overloads were reset twice before FNP-1-STP-16.1 could be successfully completed.

Followup actions to the July 15, 2003 event involved tightening electrical connections

and post-maintenance testing of the room cooler, but not in the run/stop/hot restart

fashion in which it had failed.

Investigation into the similarity of the two events resulted in troubleshooting efforts on

April 30, 2004. These efforts determined that a degraded time delay relay was most

likely the cause for both events and Minor Departure 04-2760 was implemented on May

1, 2004, to correct the problem. This time, post-maintenance testing was conducted

satisfactorily in the run/stop/hot restart fashion. To assure operability, the 1B

Enclosure

7

containment spray pump room cooler was subsequently tested satisfactorily in the

run/stop/hot restart fashion. In addition, Design Change Request (DCR) M04-1-0060

was created to make the thermal overload configuration in the Unit 1 pump room coolers

the same as in Unit 2. This design change had been completed on both Unit 1

containment spray pump room coolers and was scheduled to be implemented on the

remaining Unit 1 pump room coolers in 2006. Further investigation by the licensee

concluded that the root cause evaluation for the July 15, 2003 event was inadequate;

resulting in a maintenance preventable functional failure (MPFF) of the 1A containment

spray pump room cooler on March 23, 2004. However, the team determined that the

degraded condition of the 1A containment spray pump room cooler rendered it

vulnerable to run/stop/hot restart scenarios that could be encountered during the

response to a large break LOCA. Such scenarios would involve: (1) a subsequent loss

of offsite power and re-sequencing loads on the emergency diesel generators; or (2) the

need to momentarily secure containment spray pumps/room coolers to facilitate the

transfer of emergency core cooling systems to the containment sump.

Analysis: This finding is more than minor because it affects the Barrier Integrity

Cornerstone attribute of Barrier Performance and impacted the cornerstone objective in

that tripping of the room cooler could result in loss of the 1A containment spray pump

safety function due to overheating. This finding is of very low safety significance

(Green) because the 1B containment spray pump and room cooler and all containment

coolers were available to ensure containment barrier integrity would be maintained in

the event of a large break LOCA or containment over pressure challenge.

Enforcement: 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, required that

measures shall be established to assure that significant conditions adverse to quality

are promptly identified. Contrary to the above, following the July 15, 2003 trip of the 1A

containment spray pump room cooler the licensee failed to identify a degraded time

delay relay. Consequently, a similar run/stop/hot restart trip of the room cooler

occurred on March 23, 2004. For the period between July 15, 2003, until corrected on

May 1, 2004, the degraded condition rendered the 1A containment spray pump room

cooler vulnerable to run/stop/hot restart scenarios that could be encountered during

the response to a large break LOCA. Because this finding is of very low safety

significance and has been entered into the licensees corrective action program (CR

2005109145), this violation is being treated as an NCV, consistent with Section VI.A of

the NRC Enforcement Policy: NCV 05000348/2005008-01, Failure to Identify 1A

Containment Spray Pump and Room Cooler Degraded Time Delay Relay.

(b) SSPS/7300 Troubleshooting

Introduction: A Green, NRC-identified NCV of 10 CFR Part 50, Appendix B, Criterion

XVI, was identified for failure to take corrective actions to preclude repetition of a

significant condition adverse to quality. Specifically, corrective actions taken to develop

a SSPS/7300 troubleshooting guideline following a Unit 2 SSPS/7300 troubleshooting-

related reactor trip on April 12, 2004, was inadequate to preclude the recurrence of

another SSPS/7300 troubleshooting-related event on April 28, 2005.

Enclosure

8

Description: On April 11, 2004, Unit 2 tripped due to a fault which unblocked the source

range high flux trip. SSPS/7300 troubleshooting resulted in two SSPS cards being

replaced and the unit was restarted. However, Unit 2 tripped again on April 12, 2004,

due to the same unblocking of the source range high flux trip. Subsequent

troubleshooting revealed that a different SSPS card was the source of the problem. The

licensee also determined that, as a contributing cause, troubleshooting activities

following the first trip did not use a rigorous troubleshooting methodology to identify and

validate the specific equipment failure and corrective action. Additionally, no formal

guidance for troubleshooting problems in the SSPS/7300 process channels existed.

Therefore, the exact equipment failure was not correctly identified and the problem

recurred. Corrective actions to prevent recurrence included development of formal

SSPS/7300 troubleshooting guidance.

A similar SSPS/7300 troubleshooting-related event occurred subsequently on April 28,

2005, when annunciators for the 1B Steam Generator Main Steam Line Delta P Alert

came into alarm. Based on the control board indications and previous history of failed

7300 cards, the licensee believed that a 7300 card had failed and entered TS 3.3.2,

LCO D for an inoperable 7300 channel. The required action for this condition was to

place the channel in trip within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and Mode 4

within 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months . After placing the channel in the tripped condition, troubleshooting was

begun on the associated 7300 cards to identify the exact failure. The licensee had

determined that the 7300 cards were sending the proper signal to SSPS and concluded

that the current TS LCO may not be correct. Based on this information, the licensee

tested an input relay that was the interface between the 7300 and SSPS circuitry and,

on April 29, 2005, it was found to be satisfactory. Consequently, TS 3.3.2, LCO D was

exited and the licensee entered TS 3.3.2, LCO C for SSPS "A" Train. The required

action for this condition was to restore the train to operable status within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months or be in

Mode 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Troubleshooting on SSPS was subsequently completed,

revealing that a SSPS logic card had failed. After the logic card was replaced, and

SSPS tested satisfactorily, the licensee exited the LCO. (Note: The failure to follow TS

for an inoperable SSPS logic train was previously dispositioned as NCV

05000348/2005003002.)

The licensee identified a lack of procedural guidance to diagnose an alarm condition as

the root cause for the extended amount of time needed to troubleshoot the alarm

condition and associated TS concerns. Accordingly, a troubleshooting work order

sequence for such annunciator problems was incorporated into the SSPS/7300

troubleshooting guidance.

Analysis: This finding is more than minor because it affects the Mitigating Systems

Cornerstone attribute of equipment performance and adversely impacted the

cornerstone objective in that the SSPS/7300 troubleshooting guidance did not provide

the necessary steps to facilitate a timely (i.e., within the TS LCO) determination of a

SSPS/7300 process channel failure. This finding is of very low safety significance

because the B train of SSPS was maintained operable at all times.

Enclosure

9

Enforcement: 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, required that

measures shall be established to assure that significant conditions adverse to quality

are corrected to preclude repetition. Contrary to the above, the SSPS/7300

troubleshooting guideline developed as a corrective action for a Unit 2 SSPS/7300

troubleshooting-related reactor trip on April 12, 2004, was inadequate to preclude the

occurrence of another SSPS/7300 troubleshooting-related event on April 28, 2005.

Because this finding is of very low safety significance and has been entered into the

licensees corrective action program (CR 2005109147), this violation is being treated as

a NCV, consistent with Section VI.A of the NRC Enforcement Policy: NCV 05000364/2005008-02, Inadequate Corrective Action Results in Recurrence of a

SSPS/7300 Troubleshooting-Related Event.

(c) Radiation Monitor R-11 Failures

Introduction: A Green, NRC-identified finding (FIN) was identified for untimely resolution

of excessive air flow problems on the Unit 1 and Unit 2 Containment Air Particulate

Radiation Monitors (R-11). Excessive air flow through the moving filter paper caused

the monitor to become inoperable on numerous occasions since 1990. When R-11 was

out of service, the ability to detect low-level RCS leakage was degraded.

Description: After the licensee installed new paper drives in 1990, radiation monitor

R-11 experienced frequent paper drive malfunctions and pump trips. The licensee

determined that there was too much air flow through the sample lines. The sample air

flow for R-11 was originally designed for 10 cubic feet per minute (CFM) and the pumps

were sized accordingly. However, the paper drive vendor recommended a flow rate of

no more than 5 CFM to avoid paper drive related problems. Due to these problems,

radiation monitor R-11 was put on the MR (a)(1) list in 1995.

In order for R-11 to perform its TS function, at least 4 CFM air flow was required.

However, due to uncertainties in the flow measuring device, the flow rate must be set at

6 CFM or greater to ensure that the TS required 4 CFM passes through the filter paper.

On August 8, 1996, DCR 96-1-9059 was submitted to install a bypass line to reduce the

air flow through the filter paper to 6 CFM with the remaining 4 CFM bypassing the paper

drive/detector assembly. No analysis was performed to determine whether the flow rate

upstream of the detector could be reduced below the design rate of 10 CFM. The

design change was completed in December 1997 but, frequent pump trips and paper

drive problems due to excessive flow rate continued to be a problem. Also, with the new

bypass line installed, small fluctuations in pressure caused Hi/Lo air flow alarms. Root

Cause Investigation 2-98-338/1-98-328, Request for Engineering Assistance (REA)

99-2100, and REA 99-2121 were completed to evaluate R-11 pump-related problems.

The licensee concluded that more man-power intensive preventive maintenance tasks

(PMs) were required to keep R-11 functional (e.g., more frequent checks on pump drive

belts and filter paper status, stricter adherence to vendor lube requirements, etc.). The

new PMs were effective in addressing the symptoms and R-11 was removed from the

Maintenance Rule (a)(1) list in late 2000. However, because the licensee did not

develop any corrective actions to address the underlying problem of excessive air flow,

the team concluded that the new PMs were effectively a work-around.

Enclosure

10

Beginning in 2003, problems related to excessive air flow again became an issue as

documented in numerous CRs including 2003002541, 2004000192, 2004101110,

2005101978, 2005012025, 2005102065, 2005102457, 2005106984, 2005017050,

2005107120, and 2005107076. In August 2004, R-11 was put back on the MR (a)(1)

list. In August 2005, Request for Engineering Review C050882501 was submitted to

modify the system. This modification would eliminate the bypass line, reduce the

capacity of the sample pumps flow from 6 CFM to 2-3 CFM, and replace the flow

measurement device with a more accurate automated mass-flowmeter. These

modifications, which appeared to be an adequate solution, are scheduled to be

implemented in 2006.

Analysis: The team determined that the R-11 air flow related problems are a

performance deficiency in that the resultant impact to the instruments ability to perform

its TS required function was reasonably within the licensees ability to correct in a timely

manner. This finding is more than minor because it is associated with the RCS

Equipment and Barrier Performance Attribute of the Barrier Integrity Cornerstone and

adversely affects the cornerstone objective in that the ability to detect low-level RCS

leakage that may indicate pressure boundary degradation was reduced. This finding

could not be evaluated using the Significance Determination Process (SDP) in

accordance with IMC 0609 because the SDP for the RCS barrier only applied to a

degraded barrier; not the ability to detect a degraded barrier. Therefore, this finding was

reviewed by the regional management and determined to be of very low safety

significance (Green) because alternate methods of detecting low-level RCS leakage

were available when R-11 has been out of service.

Enforcement: No violation of TS or other NRC requirements occurred. This finding has

been entered into the licensees corrective action program (CR 2005109190) and is

identified as FIN 05000348,364/2005008-03, Untimely Resolution of Flow Problems on

Radiation Monitor R-11.

d. Assessment of Safety-Conscious Work Environment (SCWE)

(1) Inspection Scope

The team conducted interviews with randomly selected members of the plant staff,

including operations, maintenance, engineering, health physics, and emergency

preparedness personnel, to develop a general perspective of the SWCE at the site and

the willingness of personnel to use the CAP and the employee concerns program

(ECP). The interviews were also to determine if any conditions existed that would cause

employees to be reluctant to raise safety concerns. The team also reviewed the

licensees ECP, which provides an alternate method to the CAP for employees to raise

concerns and remain anonymous. The team interviewed the ECP Coordinator and

reviewed a select number of ECP reports completed since August 2003 to verify that

concerns were being properly reviewed and that identified deficiencies were being

resolved in accordance with the SNC Concerns Program Procedure, Revision 8.

Enclosure

11

(2) Assessment

The team concluded that licensee management emphasized the need for all employees

to identify and report problems using the appropriate methods established within the

administrative programs, including the CAP and ECP. These methods were readily

accessible to all employees. Licensee management encouraged employees to promptly

identify nonconforming conditions. Based on discussions conducted with a sample of

plant employees from various departments, the team determined that the site staff felt

free to raise issues and felt that management wanted issues placed into the CAP for

resolution. The staff members also believed that feedback was good when using the

CAP and the ECP, and that they were kept up to date on identified issues. The team

noted that, for the ECP files they had reviewed, CRs were initiated in the CAP for any

substantiated condition adverse to quality that had been identified in the file. The team

also did not identify any reluctance to report safety concerns.

4OA6 Management Meetings Including Exit

The team presented the inspection results to Mr. Todd Youngblood and other members

of licensee management on August 25, 2005, who acknowledged the findings. The

team also confirmed that proprietary information was not provided or examined during

the inspection.

ATTACHMENT: SUPPLEMENTAL INFORMATION

Enclosure

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

W. Bayne, Performance Analysis Supervisor

S. Chestnut, Engineering Support Manager

P. Harlos, Health Physics Manager

J. Hunter, Operations Support

D. Lisenby, Engineering Supervisor

R. Wells, Operations Outage Support

T. Youngblood, Assistant General Manager - Plant Support

NRC personnel

C. Patterson, Senior Resident Inspector-Farley

P. Xavier Bellarmine, Reactor Inspector

LIST OF ITEMS OPENED, CLOSED AND DISCUSSED

Opened and Closed

05000348/2005008-01 NCV Failure to Identify 1A Containment Spray Pump

and Room Cooler Degraded Time Delay Relay.

(Section 4OA2c.(2)(a))05000364/2005008-02 NCV Inadequate Corrective Action Results in

Recurrence of a SSPS/7300 Troubleshooting-

Related Event (Section 4OA2c. (2)(b))

05000348,364/2005008-03 FIN Untimely Resolution of Flow Problems on Radiation

Monitor R-11 (Section 4OA2c.(2)(c))

LIST OF DOCUMENTS REVIEWED

CRs Generated as a Result of PI&R Inspection

2005108397, Assess Industry OE on cleaning and reporting handswitch failures

2005108425, Incorrect MR functional failure (FF) determination for 1C DG speed signal

generator failure

2005108442, Root Cause not completed CR 2003000172

2005108444, Lack of proper documentation on past equipment failures regarding regulatory

reportability

2005108446, Incorrect MR FF determination on SW #3 Battery Charger

2005108451, 10 yr electrolytic filter capacitor replacement on Auxiliary Building Battery

Chargers

2005108455, Request Engineering Determination be performed on Ametek Solid State

Controls Inc. Oscillator and sync boards

Attachment

2

2005203550, Revise FNP-1(2)-STP-73.1 to address writing CR for handswitch contact swiping

and determine if other procedures are susceptible

2005109190, Untimely resolution of long-standing flow problems on radiation monitor R-11

(FIN 5000348,364/2005008-03)

2005109147, Inadequate corrective action developed guideline results in recurrence of a

SSPS/7300 troubleshooting-related event (NCV 05000364/2005008-02)

2005109145, Inadequate corrective actions render the 1A containment spray pump and room

cooler vulnerable to possible post-accident affects of a degraded time delay relay (NCV 05000348/2005008-01)

CRs Related To Focus Systems

[AFW]

2004105343, Repeated pump motor trips during attempted starts of the 1B motor driven

auxiliary feedwater pump (MDAFWP)

2003003101, Oil fill cap leaking during run of 2A MDAFWP

2004001041, 2A MDAFW pump declared inoperable due to oil leak

2004100074, Unit 2 TDAFWP found leaking < 1DPM from oil bubbler

2003002297, TDAFWP FCV3228C for 2B SG would not stroke correctly from HSDP per

FNP-2-STP-73.1

2005101796, Unable to start 1A MDAFW pump from hot shutdown panel (HSDP)

2004103612, Failure of FNP-1-STP-22.6 due to dirty remote/local handswitch on HSDP

[CCW]

2004001251, 1C CCW pump failed to start on first attempt from main control board

2004103380, 1C CCW pump failed to start on first attempt from main control board

2004101977, Wires labeled wrong on inboard and outboard bearings of 2C CCW pump

2003001654, CR to document problems encountered while investigating slow stroke times of

Unit1 CCW surge tank vent valves

2003002040, Unit 1 CCW surge tank vent valves both had slow stroke times

2003003311, Oil analysis results for inboard 2A CCW pump indicated elevated iron

and chromium

[SW]

2005104278, Received MCB annunciator JE2, 1B SG STM Line High Delta P

2004000053, During the current SW pump 2B replacement outage, the pump will have

exceeded its Maintenance Rule allowed out-of-service time

2004000824, Reactor Trip, first out alarm was 1C SG-Hi-HI Level

2004001672, While reviewing tagout (T/O) for Mode 3 prerequisites it was discovered that T/O

2-CA-R16-P17-91 had the CCW valve HV3096A jacked open

2004001706, Unit 2 Tripped during low Power Physics testing from a B train Source Range

2004001493, During the performance of FNP-2-STP-40.0 the 2E SW pump failed to start on

safety injection signal

2005100693, The "A" train #2 SW battery charger has exceeded its Maintenance Rule

performance criteria of 1 FF per train per 36 months

3

2004002098, Maintenance Rule pseudo function P06-F01 (7300 Analog Protective System)

not meeting its A1 goals of not exceeding any plant level performance criteria

2005100150, 'A' Train SW DC bus declared inoperable due to voltage

2005104278, Received MCB annunciator JE2, 1B SG STM LINE HIGH DELTA P ALERT,

along with bistable TSLB-4 window 13-3: STM LP2 P2<P3

2005104808, The number 2 Governor Valve has failed closed, caused a Turbine load shed

2005105360, While attempting to place handwheel back on Q1P16V007A the valve failed

closed causing loss of SW flow to the on service CCW heat exchanger (HX)

2004001189, During performance test of 7300 cards in cab 3 of Unit 2, two failures occurred

2004001193, During the process of performing a Hot Bus transfer to align 2E 600 VAC load

center (LC) to 2F 600 VAC LC, the supply breaker to 2E 600V LC was opened prematurely

2004101522, During performance of FNP-1-STP-24.10 Service Water Pump 1C Auto

2004001407, Several problems were found concerning weld program controls during the

Unit 2 SW strainer bypass valve line replacement

2004101522, During performance of FNP-1-STP-24.10, SW pump 1C supply breaker DK05-1

tripped immediately when closed

2003002747, During routine Outside System Operator rounds, found the 2B SW pump upper

oil reservoir overflowing

2004102496, With the 2A and 2C CCW HXs in service, SW to 2B CCW HX MOV-3130B was

caution tagged open with power available to allow flow through the 2B HX during super-

chlorination

2004103570, The Farley Nuclear Plant Quarterly Trend Report for May, June, July 2004

identified a possible trend in 'rework' related events

2004106140, Valve Q1P16V0203 failed FNP-1-STP-628.19 as previously documented on

CR 2004104150; this failure should have been documented as a Functional Failure

2004001241, During performance of STP-40.2, the 2C Charging pump and 2E SW pump

breakers failed to close when the SI signal was generated

2004104453, Due to STP failure on valve Q1P16V0203 a WO was written to perform

FNP-1-STP-628.19 on the other valve

2005103081, 1D SW pump tripped instantly while starting

2005105715, WO 2050000901 did not meet its functional test

2005106477, Attempted to bump the 2C SW pump, breaker (DK05) failed to close

2005103081, 1D SW pump tripped instantly while starting

2005103345, 1B SW pump tag order 1-DT-05-P16-272 had incorrect steps 1 and 3

2005101317, While attempting to start the 2D SW pump, the amber breaker tripped flag lit and

annunciator AE4 "SW PUMP TRIPPED" alarmed

2004102349, 2A SW pump is in the alert range on the 1A (axial) position in the 2A & 2C SW

pump combination

2004102359, 2B Service water pump reference vibration for the Axial direction (for 2A and 2B

combination) is listed as 0.0159 in/sec 2004103257, During pre-outage flushing activities, with system in service, four drain valves did

not pass any flow

2004103689, During the performance of ASME Section XI pressure test 160.27-4, active

moisture from under foam insulation at Q1P16V217C was detected

2004104140, B-Train SW Mini-flow valve Q1P16V579 did not go open after discharge valve

Q1P16V508 was closed, during shutdown of B-train SW

2004104220, A SW pump vibration (axial) is in the alert range per STP 24.1; evaluation

needed within 96 hrs

4

2004104535, Attempted to start 1D SW pump and immediately received the SW pump tripped

annunciator

2004104820, During the return to service of 'A' train SW it was discovered that the 'A' train SW

strainer bypass valve Q1P16V513 was leaking

2004104857, During performance of M400136001, butterfly valve was found installed

backwards

2004100914, During performance of FNP-1-STP-24.2, pump combinations 1D&1E,1D&1C

were found to be in the alert range for flow

2004100406, Q1P16V224A-D and Q1P16V230A-D valves are stainless steel, but have carbon

steel body-to-bonnet bolts

2004100660, Unit 1 "E" SW pump upper motor bearing is making a chirping noise

2004002353, Discovered a through wall leak on the 1C CCW Hx service water side drain pipe

to drain valve Q1P16V005F

2004001982, Predictive Maintenance finding on 2D SW pump motor...this is a continued trend

2004000139, The NRC resident identified a potential concern related to declaring the 2B SW

pump operable, following replacement, without a proper evaluation

2004000713, Valve Q2P16V007A is leaking SW in a steady stream

2003002139, Multiple radial cracks discovered in the stellite seating surface of the 2D SW

discharge check valve

2003000172, During performance of surveillance logic switch C Position 14 failed

2003002396, The suction bell on SW pump does not meet ASME requirements

2001003054, The manufacturer has discontinued the line of Gemco series 404 hand switches

2005104270, ES evaluate as-found data for the 2A SW pump for Qr, delta-Pr, and vibration...

also evaluate 2B SW pump for alert range vibes at point 1A

2005104355, The pump and motor vibrations on 1C SW pump appear to be higher than

normal

2005101800, Generate a design change to replace N1P16V737 located at the SW cyclone

separator with a stainless steel valve

2005101807, Work Order 0M56271501 was written for 'B' TRN SW Lube and Cooling Strainer

DP being negative

2005102755, Generate a minor maintenance work order to remove/re-install each of the

anchor bolts in seismic support SS5409 one at a time

2005102756, Generate a work order to remove seismic support SS2860 after the completion

of the actuator removal on Q1P16V721B (WO 1050847101)

2004106189, Evaluation required within 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months for 2A/B & 2A/C in ALERT on 1A vertical

vibes... 2A SW pump vibes for the 1A position is in the ALERT for the 2A & 2B combination

2004107042, Unit 2A SW lube and cooling strainer is showing a negative differential pressure

(-1)...three of the four strainers are now displaying this problem

2005100009, SW from TB chiller isolation valve has insulation removed causing excessive

condensation

2005100424, Required generate a DCR/MDC modification package to support the NRC

commitment to remove the SW booster pumps from service

2005100619, B Train SW Lube & Cooling Strainer T/O for P/S Cal...need evaluation/

determination from ES on attendant equipment and operability concerns

2005100619, B Train SW Lube & Cooling Strainer T/O for P/S Cal...need evaluation

2003003034, Review actions taken by FNP to address the leak constituted a non-code repair

as defined in GL 90-05

2003002396, The suction bell on the pump assembly intended to be installed in the 1B SW

pump location on 09/22/03 does not meet ASME requirements

5

2003003027, Results for surveillance test procedure FNP-2-STP-24.21 found the 2A SW

booster pump vibrations exceeded the required action range

2004000839, During maintenance of valve Q1P16V0721B under work order 559059, pipe

restraint SS-2860 had to be removed to facilitate motor operator maintenance

2004001430, During SW bypass line replacement by WPS weld quality issues were

discovered on the 2F and 3F welds

2004001990, Oil analysis results for the 1D SW pump lower motor bearing indicates high

particle count in the unacceptable range

2004100140, During the replacement of the 2B SW pump under work order 03007525, the

new pump assembly was converted to product lubrication

2004100391, A work order needs to be written to inspect the posts on the 71-1X relay in

cabinet Q1P16L001 to ensure there is no cracking or corrosion

2004100729, Evaluate the acceptability for bypassing a SW strainer for up to fourteen days

2004100862, Evaluate whether EQ MCC buckets qualified under U267469 meet the seismic

requirements of the DG and SW buildings

2004102539, 2A SW pump has excessive seal leakage

2004102837, During the NRC SW inspection it was noted that SW differential pressure

indicator showed low flow

2004104441, During setup for breaker DL03-1, the breaker has jumpers installed and is racked

to test

2004104614, A train miniflow valve did not open with discharge closed

2004104197, Pump flow was above the acceptable range on FNP-STP-24.21

2004100928, Considerable amount of water (more than usual) escaping from around main

shaft of 2A strainer

2004100972, Based on the results of the Unit 2 B train SW pump testing, the data indicates

the pumps are improving and performing better than expected

2004101009, Q2P16MOV3131 stroked outside the acceptable range

2004101934, During performance of work activity to install missing hilti bolt in base plate

(WO M300826501), it was determined that the hilti bolt could not be installed

2004101997, Shaft key had backed off of valve Q1P16V007A, 1A CCW heat exchanger SW

outlet isolation, not allowing the valve to be fully closed

2005103444, This CR written to review post job critique of SW lube and cooling outage

2005106483, The plunger on breaker DK05-2 was found out of position

[4.16KV and 600 V Electrical Distribution]

2003003121, Unit 2 "F" Sequencer degraded grid relay failed

2003003540, B-Train 27G3(3-1) degraded grid undervoltage relay

2004001493 (2004001762), DG15-2 failed to close when manual paralleling 2B DG with offsite

power

2004105289, "B" train LOSP during FNP-1-STP-80.16

2003001574, During testing the 1J sequencer phase 1-2 & 2-3 uv relays failed

2005105837, 1C DG breaker DH07-2 would not trip

2004002041, 2A 4160V bus undervoltage relay N2R15BKRDA02273

2003002436 (2003002996, 2004000397, 2004001120, 2004002291,2004100850,

2004101225), Agastat relays time delay out of specification

2005105120, Emergency start circuit - T2A relay timed out early

2003003316, Q1R16BKRER02 installed bkrs DS416 vs 208

6

2004000594 (CR2004000377), under sized control power transformer

2004102688, 2 vs 3 amp fuse in 1U MCC

2003002443, NCV for untimely corrective action for out of tolerance undervoltage and

underfrequency relays

2004001221, Sequencer time delay relay out of specification

2004104322, Supply breaker to 1J (DG13) malfunctioned

2004104611, Investigate 1D SW pump breaker control circuit

2004101162, Feeder breaker DF03 to LC 2D did not trip when lockout relay actuated

2004104980, Feeder breaker to LC 1F would not close

[125VDC/120VAC Electrical Distribution]

2003002696, 1B AB Battery exceeded MR unavailability limits

2005100150, A Train SW DC bus inop with #2 bat chgr

2005100693, SW Battery charger #2 MR a(1) status

2003002437, Aux Bldg Bat Q1R42E0002B cell # 27 low voltage

2004001730, 1B Aux Bldg 125v battery cell #24 < A&B limits

2004001743, 1B Aux Bldg 125v battery cell #24 & 35 < A&B limits

2005101299, 2A Bat Charger outside AMP accept criteria

2003002132, 1B AB Battery (Q1R42E0001B) cell #6 <AB limits

2003002263, 1B AB Battery cell #30 found <AB limits, then in limits (sulfate crystals)

2004100319, 1B AB Battery cell #7 < limits

2005101614, 2B AB battery charger AC supply breaker EE-05 tripped

2005104031, 1A AB battery charger SCR (Q1R42E001A)

2005104836, #3 SW battery pilot cells 27 & 34 (blown fuse charger-to-battery)

2003002862 (2004100696, 2004102784, 2005104677), SW Battery Charger #3 failures

2005100150 (2005104439), SW Battery Charger #2 failures

2004105690 (2004105691), 125 DC Bus Fuses

2003003089, 2A inverter failure causing loss of reactor coolant pump (RCP) breaker indication

and reactor trip

2005107075 (2003000028, 2005106573, 2005107143, 2005107485, 2005107162), 2F

inverter swapped to bypass

2003003267, 2A inverter exceeds available time

2003001975, 1B inverter swaps to bypass

2004001231, 2C & 2D inverters have blown fuses

2004101861, 2A inverter swapped to bypass

2004102144 (2003002649), 1F inverter transferred to bypass

2004102360, 2C Inverter SCRs Q1 & Q2 high temperatures

2004104458, 1A Inverter Fault annunciator and transfer to bypass

2005101115 (2003001295, 2003000395), 2F inverter exceeds unavailability hours in 3/03

2005107242, missing X201 and X202 jumpers on 2F inverter

2005108125, Unit 1 inverter X201 and X202 jumpers

2005105318, 1G inverter swapped to bypass

2003000559, 2B inverter swapped to bypass

2003001015 (2003000850), inverter operational problems after 10 year parts replacement

2000005555, 1G inverter transfer to bypass during jumper removal

2003000254 (2003001997), 2G inverter sync circuit deficiency

2003001962, 2D inverter swapped to bypass

7

2003000841, 1D inverter swapped to bypass

2003000560, 2A inverter alarmed and cleared

[DGs]

2003002738 (2005105962, 2004100261, 2004101595, 2004104242, 200202588,

2001000349, 2002000986, 2002001193), DG Annunciator panels

2005103104, Annunciator ZA3 (1C DG trouble) in alarm on EPB, but not local

2004001994, 2C DG control power ATS swap to emergency source

2004105273, 2C alarm panel won't stop flashing

2004102220, 2B DG inoperable due to blown control power fuse during bulb change

2004106435, 2B DG functional failure on 8/23/04

2003003438 (2004100829, 2004101591), DG 2C starting air issues

2004000486 (2004102971), DG 1C starting air issues

2005101584 (2003002188, 2004100687, 2004104552, 2004104779, 2004105943,

2004106755), DG 1B starting air issues

2004101592 (2004102593, 2004102603), DG 1-2A starting air issues

2004100396, OE18349

2005105523 (2004107270, 2005105515, 2004106454, 2005100889), DG [1-2A, 1C, 1B] room

louvers broken...heater QSY41B523C not working

2003001815 (2005100612), DFOST water/sediment

2003002661, 1C DG bearing oil unacceptable particle count

2003003323, 1C DG bearings excessive wear

2004001371, 1C DG degraded equipment

2004001556, 1C DG oil leaks during load reject test

2004000096, 2C DG bearing high particle count

2003003388, Erratic 1C DG maintenance run in

2004000067, 1B DG inoperable from painter hose

2004000271, 1B DG oil leak

2004101642, 2C DG lube oil temperature

2004103216 (2004103210), 2B DG jacket water low

2004106483, DG 1-2A generator field ground

2004107013, 1-2A DG jacket water orifice

2005100631, FNP-2-STP-80.5 criteria 57HZ vs 60 HZ

2005101612, water in DG rocker assembly lube oil

2005101872, change droop setting

2005101909, replace woodward governor

2004204545, reopen and broaden scope of RER 95-0744 (IN 94-68)

[ECCS]

2003002834 (2003002669,2003001617,2001000069), 1A Containment Spray Pump Room

Cooler

2004001281, 1A Containment Spray Pump Room Cooler

2004001493, Safety Injection Test Issues - SW/GD/CRAC

2004001903, 1A Containment Spray Pump Room Cooler (a)(1) evaluation

2005103427, 1A Containment Spray Pump Room Cooler - SRB Revisit

2004104538, 2A Boric Acid Transfer Pump Unavailability

8

2005105289, Loss of Residual Heat Removal during STP

2003002522, ESP 1.3 Post LOCA Recirculation

2003002883, Charging Pump Vibrations

2004001241, Safety Injection Test Issues

2004001428, Old tag on Containment Cooler during SI/LOSP Test

2004001444, STP-168 Procedural issue

2004105016, STP-40 Accumulator Disc

2005100773, 2B Boric Acid Transfer Pump - changes Severity Level

2005103888, RWST Make Up Valve Misposition

2003001008, Three Charging Pumps Operable in Mode 6

2003001181, Risk Assessment Unit 2 RHR

2003000990, 2B Charging Pump Sticking Valve Disc

2003800303, Calculation to establish set point uncertainty of RWST

2003001612, 1A/1B Containment Spray Pump Min Flow reqt not met

2004101645, 1A Containment Spray Pump Code Replacement

2004101965, 1A Containment Spray Pump Sliding Link - Inadvertent Start

2004103785, PEN 94 Valve 8827A failed LLRT

2004104689, PEN 94 Valve 8827A failed LLRT

2004105482, Containment Spray Train B Sump Boron/Rust Buildup

2004105711, Containment Spray Pump Test Grace Period

2005102815, ASME Code Change - Safety Related Pumps

2004102534, 2C Charging Pump Failed IST

2004103628, Boric Acid Transfer Pump (BATP) 1A Degraded

2004107275, 2B BATP ticking w/incr bearing temp

2004102740, Boric Acid Transfer Boron Concentrate STP

2004107348, Evaluation of 2B Boric Acid Transfer Pump data

2005101944, 2C Charging Pump snubber/heise issue

2004101406, 2C Charging Pump Heise Gauge

2004001485, MOV 8701A bkr heaters

2004100771, Boric Acid on RHR system

2004103098 (2004103103), RHR HX Bypass valve did not fully stroke

2004105482, RHR Sump Rust

2004106996, SSD Methodology

2005101082, 1A Residual Heat Removal Pump Motor oil drain plugs

2005103979, Residual Heat Removal Suction Valves - TFP

2003003107, 1A Charging Pump Room Cooler Ext Tubes Cleaned

2003003024, ETP 4447 1A Containment Spray Pump Room Cooler

2005102377, Unit 1 Charging Pump Discharge Valve Reach Rods

2004102083, Safety Injection Termination

2003002522, Transfer to Cold Leg Recirculation

Miscellaneous CRs

2003003089, Reactor Trip - RCP Breaker input to SSPS

2004000824, Reactor Trip - 1C Steam Generator Hi Level

2004001706, Reactor Trip during Physics Testing

2004103346, RCP Seal Flow - Health Physics skip Proc Step

2005103588, Emergency Lighting

9

2005105949, Rod Position Misalignment

2005104484, Spent Fuel Pool Valve Misalignment

2003002764, CR Disposition disapproved by V.P.

2003002866, Human Performance Error Trends

2003003106, Operations adjusted wrong RCP seal flow

2003003588, Operators Making Procedural Errors

2003003595, Improper Identification of Plant Problems

2003003601, Peer Check - Reactivity Issue

2004000983, N-42 Switch in Bypass

2004001644, 2B DG Mode Selector Switch in wrong mode

2004001777, Unit 2 Load Rejection

2004102447, Maintenance Risk Assessment

2004103715, N-31 Failed check

2004104853, H/U C/D Curves

2004105497, Mid Loop Issues

2004106286, Thermal Power - Turbine Drains

2004106420, Apparent Cause Determination Issues

2005100808, Two Valves Misaligned

2005100966, Reactor Management Index Value

2005101224, Misposition Evaluation

2005101245, Ineffective AFR Corrective Actions

2005101343, Maintenance Rule

2005102948, Fire Fighting Emergency Lighting

2005103353, Maintenance Rule

2005104808, #2 Governor Valve Failed Closed

2005106186, Estimated Criticality Conditions Issues on S/U

2004101959, Reactivation of SRO License

2004000743, Licensee Identified Violation - Firewatch Rounds in DG Building

2004105563, 1B RCP Seal Leakoff Failed Low

2004105636, 1B RCP Seal Leakoff Recorder Failed Low

2004105538, 1C RCP Seal Leakoff FI-154B failed

2005100740, 2B RCP #1 Seal Leakoff digital failed

2005103039, RCP seal flow anomaly

2005103055, Board Walkdown misposition & RCP seal flow

2004000824, Instrument Malfunction Procedure

2003001177, Malfunction of Rod Control System

2005103653, Triennial Fire Protection - AFW IA Issue

2005103659, Triennial Fire Protection- RHR Suction Valves

2005103667, Triennial Fire Protection - RCP Trip Capability

2005103688, Triennial Fire Protection - Manual Operator Actions

2005103499, Triennial Fire Protection - Emergency Lights

2005103500, Triennial Fire Protection - Emergency Lights

2005103427, SRB meeting F2004-03 addressing inadequate corrective actions

for CR 2004001281

2005100195, Delay on MPFF call

2003002443, Inadequate corrective action

2005106889, Trend Report improvement items

2005104537, Potential rework trend

2005106867, Effectiveness of rework review board results

10

2005104532, Potential fire equipment trend

2005106723, Assessment of fire equipment adverse trend

2005104533, Potential performance monitoring trend

2005101224, Increase in mispositioned components

2005107462, Identified weaknesses in processing CRs and AIs

2005106296, Operability determinations not properly documented

2004000795, NCV for non-1E battery charger tied to 1B AB battery

2004002235, NCV for inadequate control of backhoe in high voltage switchyard

2005100308, Neutral line caught by boom truck in low voltage switchyard

2002001545, Unit 2 RE-11/12 pump tripped twice on evening shift

2003002541, Unit 1 RE-11/12 pump tripped

2004000192, Unit 2 RE-11/12 pump tripped on low flow

2004101110, Unit 1 & Unit 2 RE-11/12 recommended for Maintenance Rule (a)(1) status

2005101978, Unit 2 RE-11 filter paper riding high

2005012025, Unit 2 RE-11/12 pump found not running - filter paper riding high

2005102065, Unit 2 RE-11/12 pump tripped on high flow

2005102457, Initiate RER to lower volumetric flow rate through RE-11/12

2005106984, Unit 2 RE-11 has a filter fault light

2005017050, Unit 2 RE-11 tripped on high flow

2005107120, Unit 2 RE-11 tripped

2005107076, Unit 2 RE-11 tripped on high flow

2003002382, Wrong battery was sampled, analyzed, and reported

2003002851, No indication of corrosion products found on Unt 2 corrosion products sample

filter

2003003597, Environmental air monitoring station 0701 was found not running

2003001645, Negative trend identified in environmental monitoring equipment operability

2004000356, Unit 2 zinc addition batching tank double batched

2005101440, Battery 1B sulfate value of 159 ppb exceeded the diagnostic limit of 150 ppb

2005103232, Seven smoke detectors were released from the RCA with contamination levels

above release criteria

2004002422, Contaminated lock found inside the main key cabinet in the Control Room Shift

Foremans office

2004103577, Potential trend identified for "radiological incident" related events

2003003219, Individual received DAD dose rate alarm

2003002127, Security officer exited the RCA without being surveyed by HP

2003001965, FNP source No. 1863.00.00 was found missing from its normal storage area

2004002081, HP determined that the lower portion Unit 1 cask wash pit contained alpha

contamination

2004002237, Potential trend identified in the area of "HP controls"

2005102892, Radioactive boric acid leaks found on the VCT outlet isolation valves

2003003616, NCV for failure to implement QA program to ensure representativeness of

airborne effluent samples monitored by R-29A

2004001839, LIV for Unit 2 entering Mode 3 with the TDAFWP inoperable

2004001672, LIV for U2 entering Mode 4 with an LCO on one train of CCW

2004104156, LIV for not barricading and conspicuously posting HRA entrance at Unit 1

biowall entrance

2003002554, NCV for failure to adequately correct AFW pump oil out of specification condition

2003000917, NCV for inadequate use of engineering controls for airborne contamination

11

WOs

2051943101, 2F inverter swap to bypass (CR 2005107075)

0W65560601, 1A inverter 10 year component replacement

S300240601, X201 replacement in 1A inverter

0W65560801, 1B inverter 10 year component replacement

S300240701, X201 replacement in 1B inverter

0W65561001, 1C inverter 10 year component replacement

S300240801, X201 replacement in 1C inverter

0W65561201, 1D inverter 10 year component replacement

M300240901, X201 replacement in 1D inverter

0W65561601, 1G inverter 10 year component replacement

S300241001, X201 replacement in 1G inverter

0W65561401, 1F inverter 10 year component replacement

S300240501, X201 replacement in 1F inverter

S040591401, SW battery charger #3 missing mounting stud

S040591501, SW battery charger #3 low voltage alarm relay not working

S051407601, SW battery charger #3 failure

S040281201, SW battery charger #3 alarm

S050909001, SW battery charger #1 control card replacements

S051321901, SW battery charger #2 control card replacements

S050909101, SW battery charger #3 control card replacements

S050909201, SW battery charger #4 control card replacements

1050909401, AB 1A battery charger control card replacements

1050909301, AB 1B battery charger control card replacements

1050909501, AB 1C battery charger control card replacements

2050909701, AB 2A battery charger control card replacements

2050909801, AB 2B battery charger control card replacements

2050909601, AB 2A battery charger control card replacements

W00690106, Perform AB 1B battery service test per FNP-1-STP-905.1

2040276101, Address failures of Agastat relays in device 62 applications

1050715902, Aux Feedwater Pump (MD) Handswitch

03006352, TDAFWP Discharge Hand Switch

03007943, Flip cap on inboard pump bearing (2A MDAFW) oil fill cap is leaking

0M55663001, 2A MDAFW pump leaks oil from observation disc

1040510201, Check wiring for the Unit 1 CCW pumps

30044706, Investigating 7/15/2003 issues with 1A Containment Spray Pump Room Cooler

4002222, Investigating 3/23/2004 issues with 1A Containment Spray Pump Room Cooler

Procedures

NMP-AD-002, Troubleshooting Guidelines A Graded Approach, Version 1.0

FNP-0-SOP-0.13, LCO/TR Status Sheet, Version 4.0

FNP-1-STP-24.20A, Service Water Pumps A Train Remote Shutdown Capability Test (Pumps

Operable), Version 2.0

FNP-1-STP-24.10, Service Water Pump 1C Automatic Starting Circuitry Test, Version 7.0

FNP-2-STP-40.2, B Train Sequencer Operability Test, Version 32.0

12

FNP-1-STP-213.11, Steam Generator 1A Q1N11PT0475, Steam Generator 1B Q1N11P0485

And Steam Generator 1CQ1N11PT0495 Loop Calibration And Operational Test, Version 26

FNP-1-STP.213.17, Hi Steam Line Flow, Steam Line Isolation And P-13 Operational Test

FB-474A, FB-484A, FB-494A, and PB-446A, Version 31

PS-004, Vendor Technical Information Program, Version 2.0

FNP-0-AP-7, Corrective Action Program, Version 21

FNP-0-AP-30, Preparation And Processing Of Condition Reports and Licensee Event Reports,

Version 37

FNP-0-ACP-9.0, Root Cause Program, Version 8.0

FNP-0-ACP-9.1, Root Cause Investigation, Version 8.0

NMP-GM-002, Corrective Action Program, Version 4.0

NMP-GM-002-GL02, Corrective Action Program Details and Expectations Guideline,

Version 6.0

NMP-GM-002-GL03, Root Cause Determination Guideline, Version 4.0

NMP-GM-002-GL04, Apparent Cause Determination Guideline, Version 3.0

NMP-GM-002-GL06, Corrective Action Review Board Guideline, Version 3.0

NMP-GM-002-GL07, Effectiveness Review Guideline, Version 1.0.

FNP-0-SYP-14, Preparation And Processing Of NRC Information Notice Responses,

Version 2.0

FNP-0-AP-65, Operating Experience Evaluation Program, Version 14.0

FNP-0-EMP-1341.05, Special Battery Single Cell Charging, Version 4.0

FNP-0-ACP-9.2, Operability Determination, Version 5.0

FNP-1-STP-22.6, Auxiliary Feedwater Pump Train B Functional Test, Version 20.0

FNP-1-STP-73.1, Hot Shutdown Panel Operability Verification, Version 8.0

FNP-0-87, Maintenance Rule Scoping Manual, Version 15.0, Appendix A, HSDP

FNP-0-SOP-0.14, System Operator - Rover - Shift Relief Checklist, Version 8,

(notes from 11/10/03 - 11/14/03)

FNP-2-STP-22.1, 2A Auxiliary Feedwater Pump Quarterly Inservice Test, STRS, 11/15/03

FNP-1-STP-73.1, Hot Shutdown Panel Operability Verification, STRS, 6/00 - 7/05

FNP-0-SYP-19, Maintenance Rule Performance Criteria, Version 6.0

SNC Concerns Program Procedure, Revision 8

ML052660339

Text

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