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IR 05000315-01-17(DRP), IR 05000316-01-17(DRP) Special Inspection on 08/30/2001 - 5/17/2002, Indiana Michigan Power Company, D.C. Cook Nuclear Power Plant, Units 1 & 2. One Preliminary Yellow & One Green Finding
	ML021610713
Person / Time
Site:	Cook
Issue date:	06/10/2002
From:	Dyer J; NRC/RGN-III
To:	Bakken A; American Electric Power Co
References
	EA-01-286 IR-01-017
	Download: ML021610713 (54)
	v • d • e

June 10, 2002

EA-01-286

Mr. A. C. Bakken III

Senior Vice President

Nuclear Generation Group

American Electric Power Company

500 Circle Drive

Buchanan MI 49107

SUBJECT: D. C. COOK NUCLEAR POWER PLANT, UNITS 1 AND 2

NRC SPECIAL INSPECTION REPORT 50-315/01-17(DRP);

50-316/01-17(DRP); PRELIMINARY YELLOW FINDING

Dear Mr. Bakken:

On May 17, 2002, the NRC completed a Special Inspection at your D.C. Cook Nuclear Power

Plant regarding the essential service water (ESW) debris intrusion event of August 29, 2001.

The Special Inspection was conducted in accordance with the guidance of NRC Management

Directive 8.3, NRC Incident Investigation Program, Inspection Procedure 71153, Event

Followup, and Inspection Procedure 93812, Special Inspection. The enclosed report

documents the inspection findings which were discussed on May 17, 2002, with you and

members of your staff.

On August 29, 2001, Unit 1 was in cold shutdown and Unit 2 was operating at power when your

staff shut down the Unit 1 circulating water system for maintenance. Subsequent to the Unit 1

circulating water system shutdown, cross-flow currents within the common intake structure

caused significant amounts of debris to be entrained in the ESW system. Due to an unknown

pre-existing fault in the Unit 1 East ESW pump strainer basket, which allowed bypass flow, and

your practice of operating the ESW system fully cross-connected between both trains on both

units, the debris was transported throughout the ESW systems of both units, fouling most of the

heat exchangers dependent upon ESW. Because most components supplied by ESW were in

standby, this fouling continued undetected for approximately 10 hours1.157407e-4 days 0.00278 hours 1.653439e-5 weeks 3.805e-6 months . Operators then

identified the problem during a scheduled, routine, quarterly surveillance of the ESW system in

Unit 2. A review of available data indicates that the emergency diesel generator (D/G) heat

exchangers appeared to be most limiting components for debris fouling. The flow to one D/G

decreased below the level of reliable indication, flow to two D/Gs decreased to 40% of nominal

flow with a declining trend, and the flow to the remaining D/G flow leveled out at approximately

40% of nominal flow. After discovery, the operators cycled ESW supply valves to the D/G heat

exchangers (the D/Gs were not operating) which improved flows to the heat exchangers.

However, due to continued concerns about the cause of the fouling, you elected to shut down

Unit 2 and correct the problem. Your staff replaced the damaged strainer basket, cleaned the

heat exchangers and revised your operating procedures to prevent cross-connecting ESW

system trains before restarting the units.

A. Bakken -2-

The Special Inspection began immediately after the event on August 30, 2001, and examined

activities conducted under your license as they relate to safety and compliance with NRC

regulations and the conditions of your license. The inspectors reviewed selected procedures

and records, observed activities, interviewed personnel, and conducted extensive onsite

reviews of the ESW and diesel generators systems in the weeks immediately following the

event. One finding was identified that appears to be significant. As described in Section

4OA3.4 of this report, documented instructions for installation of the ESW strainer baskets, an

activity affecting quality, were not of a type appropriate to the circumstances. Specifically, the

installation instructions for the Unit 1 East ESW pump discharge strainer basket, referenced by

Job Order 723483, did not contain adequate detail associated with the verification of critical

parameters affecting strainer basket alignment to prevent the basket from being deformed

during installation in 1989. Subsequent to the initial onsite inspection, the inspectors and

several NRC staff specialists continued to review information related to this finding including the

detailed engineering and probabilistic evaluations that you provided in January and April 2002.

These evaluations provided some useful inputs to our risk determination of this finding;

however, some of the assumptions you provided could not be supported or confirmed and were

not used.

This finding was assessed using the NRC Phase 3 Significance Determination Process and

preliminarily determined to be Yellow, a finding with substantial importance to safety that will

result in additional NRC inspection and potentially other NRC action. As described in more

detail in the inspection report, our determination considered the August 29, 2001, event

information, the engineering and probabilistic analyses you developed, generic risk information,

and engineering analyses performed by the inspectors. The accident sequence of most

concern was the loss of offsite power (LOOP) because of the vulnerability to the D/Gs created

by the damaged strainer and the cross-connected ESW systems. A single unit LOOP event

would result in a complete loss of the affected units circulating water system, and an

emergency start of both the associated D/Gs and ESW pumps. The NRC concluded that this

sequence would create a greater debris entrainment than the August 29 event; however, the

continued sweeping of the debris by the operating unit circulating water system and availability

of the operating units auxiliary feedwater system to feed the affected units steam generators

would provide substantial mitigation of the event. A dual unit LOOP would have a lower

initiating event frequency than the single unit LOOP, but the mitigative effects available during a

single unit LOOP would not be available. Our engineering assessment of simultaneously

stopping the circulating water pumps for both units concluded that the continued inrush of water

from Lake Michigan to the intake structure, after the dual unit LOOP, would sufficiently entrain

debris to provide significant fouling of the ESW system. This debris would bypass the Unit 1

East ESW pump strainer and disburse throughout heat exchangers in both units. Based on the

observed distribution of debris during the August 29 event, it appears that each of the D/G heat

exchangers could become fouled such that they could not be capable of supporting their

expected loads. The calculated change in core damage frequency and the large early release

frequency as a result of the damaged strainer were both determined to be Yellow.

A. Bakken -3-

This finding is also an apparent violation of NRC requirements and is being considered for

escalated enforcement action in accordance with the "General Statement of Policy and

Procedure for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600. The current

Enforcement Policy is included on the NRCs website at http://www.nrc.gov.

We believe that sufficient information was considered to make a preliminary significance

determination. However, before we make a final decision on this matter, we are providing you

an opportunity to present to the NRC your perspectives on the facts and assumptions used by

the NRC to arrive at the finding and its significance at a Regulatory Conference or by a written

submittal. If you choose to request a Regulatory Conference, it should be held within 30 days

of the receipt of this letter and we encourage you to submit supporting documentation at least

one week prior to the conference in an effort to make the conference more efficient and

effective. If a Regulatory Conference is held, it will be open for public observation. If you

decide to submit only a written response, such submittal should be sent to the NRC within 30

days of the receipt of this letter.

Please contact David G. Passehl at 630-829-9872 within 10 business days of your receipt of

this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we

will continue with our significance determination and enforcement decision and you will be

advised by separate correspondence of the results of our deliberations on this matter.

Since the NRC has not made a final determination in this matter, no Notice of Violation is being

issued for this inspection finding at this time. In addition, please be advised that the number

and characterization of apparent violations described in the enclosed inspection report may

change as a result of further NRC review.

An additional human performance finding involving several examples of control room operator

weaknesses during the degraded ESW flow event was identified. This issue was determined to

be of very low safety significance (Green) and was determined to involve a violation of NRC

requirements. However, because of its very low safety significance and because it has been

entered into your corrective action program, the NRC is treating this issue as a Non-Cited

Violation, in accordance with Section VI.A.1 of the NRC Enforcement Policy. If you contest the

Non-Cited Violation, you should provide a response with the basis for your denial, within

30 days of the date of this inspection report, to the Nuclear Regulatory Commission,

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

Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory

Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the D.C. Cook

facility.

A. Bakken -4-

In accordance with 10 CFR 2.790 of the NRCs Rules of Practice, a copy of this letter

and its enclosures will be 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 Web site at

http://www.nrc.gov/reading-rm/adams.html.

Sincerely,

/RA by James Caldwell Acting for/

J. E. Dyer

Regional Administrator

Docket Nos. 50-315; 50-316

License Nos. DPR-58; DPR-74

Enclosure: Inspection Report 50-315/01-17(DRP);

50-316/01-17(DRP)

cc w/encl: J. Pollock, Site Vice President

M. Finissi, Plant Manager

R. Whale, Michigan Public Service Commission

Michigan Department of Environmental Quality

Emergency Management Division

MI Department of State Police

D. Lochbaum, Union of Concerned Scientists

DOCUMENT NAME: G:\COOK\ML021610713.wpd

To receive a copy of this document, indicate in the box "C" = Copy without attachment/enclosure "E" = Copy with attachment/enclosure "N" = No copy

OFFICE RIII RIII RIII RIII RIII

NAME KOBrien/trn DPassehl SBurgess AVegel BClayton

DATE 06/ /02 06/ /02 06/ /02 06/ /02 06/ /02

OFFICE NRR RIII RIII RIII RIII

NAME Carpenter/via Clayton Congel Grant Dyer

telecon

DATE 05/31/02 06/ /02 06/ /02 06/ /02 06/ /02

OFFICIAL RECORD COPY

A. Bakken -5-

ADAMS Distribution:

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C. Ariano (hard copy)

DRPIII

DRSIII

PLB1

JRK1

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MDS1

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WMD

U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Docket No: 50-315; 50-316

License Nos: DPR-58; DPR-74

Report No: 50-315/01-17(DRP); 50-316/01-17(DRP)

Licensee: American Electric Power Company

Facility: D.C. Cook Nuclear Power Plant, Units 1 and 2

Location: 1 Cook Place

Bridgman, MI 49106

Dates: August 30, 2001 through May 17, 2002

Inspectors: B. Bartlett, Senior Resident Inspector

S. Burgess, Senior Risk Analyst

M. Cheok, Senior Reliability and Risk Analyst, NRR

K. Coyne, Resident Inspector

S. Jones, Senior Reactor Systems Engineer, NRR

K. OBrien, Senior Reactor Inspector

P. Prescott, Senior Resident Inspector, Duane Arnold

Approved by: Geoffrey E. Grant, Director

Division of Reactor Projects

SUMMARY OF FINDINGS

IR 05000315-01-17(DRP), IR 05000316-01-17(DRP); on 08/30/2001 - 5/17/2002, Indiana

Michigan Power Company, D.C. Cook Nuclear Power Plant, Units 1 and 2. Special Inspection.

This Special Inspection was conducted by NRC resident, region-based and headquarters-based

inspectors and staff. The inspectors identified one preliminarily Yellow finding and one Green

finding. These findings were assessed using the applicable significance determination process

as a potentially safety significant finding that was preliminarily determined to be Yellow. The

significance of most findings is indicated by their color (Green, White, Yellow, Red) using

IMC 0609, Significance Determination Process (SDP). The NRCs program for overseeing the

safe operation of commercial nuclear power reactors is described at its Reactor Oversight

Process website at http://www.nrc.gov/NRR/OVERSIGHT/index.html. Findings for which the

SDP does not apply are indicated by No Color or by the severity level of the applicable

violation.

A. Inspector Identified Findings

Cornerstone: Mitigating Systems

TBD. Documented instructions for essential service water (ESW) pump

discharge strainer maintenance did not contain adequate detail regarding critical

parameters for basket installation. Consequently, faulty strainer basket

installation practices contributed to the failure of an ESW pump discharge

strainer basket and created the potential for debris to bypass the strainer and

enter the ESW system. On August 29, 2001, the failed 1 East ESW pump

discharge strainer, in conjunction with the ESW system alignment with all normal

and alternate diesel generator (D/G) ESW supply valves open, caused

significant debris fouling of D/G heat exchangers. While operator actions

prevented the debris fouling from causing a complete loss of the D/Gs ability to

perform their emergency AC power safety function, the potential for a complete

loss of all emergency AC power during a loss of offsite power was determined to

exist. This issue is identified as Apparent Violation (AV) 50-315/01-17-01;

50-316/01-17-01. This finding was assessed using the applicable SDP as a

potentially safety significant finding that was preliminarily determined to be of

substantial safety significance. (Section 4OA3.3 and 4OA3.4)

Green. The inspectors identified a Non-Cited Violation of Technical

Specification 6.8.1 associated with operator procedural adherence deficiencies

during the degraded ESW event of August 29, 2001. Specifically, the operators

failed to (1) effectively monitor the control boards for changing indications,

adverse trends, and abnormal indications, (2) effectively communicate receipt of

an abnormal temperature alarm for the CCW heat exchanger, and (3) enter the

CCW abnormal operating procedure as directed by the abnormal temperature

alarm response procedure.

2

The inspectors determined that the failure to adequately implement procedures

associated with control board monitoring, logkeeping, and annunciator response

had a credible impact on safety and therefore were more than a minor concern.

Specifically, these issues could reasonably result in the failure to identify and

promptly correct degradation of safety related equipment and therefore impact

the reliability and availability of a safety system. Because these performance

deficiencies contributed to delays in identifying degradation of the ESW and

CCW mitigating systems, the inspectors determined that these human

performance weaknesses were associated with the mitigating systems

cornerstone. Although this issue adversely impacted the licensees response to

the August 29, 2001 event, none of the performance deficiencies directly

resulted in the actual loss of safety system function or the loss of a single safety

system train for greater than its TS allowed outage time. Consequently, the

inspectors concluded that this issue was of very low safety significance (Green).

(Section 4OA4)

3

Report Details

Summary of Plant Event

On the evening of August 29, 2001, the plant experienced problems with Essential Service

Water (ESW) system performance on both Units, which subsequently resulted in an unplanned

shutdown of Unit 2. Unit 1 was already shutdown and in Mode 5 (Cold Shutdown) to support

circulating water system repairs. At 10:55 p.m. on August 29, 2001, plant staff noted

abnormally low ESW flow to both Unit 2 Emergency Diesel Generators (D/Gs) during a

Technical Specification (TS) surveillance test. The licensee entered TS 3.0.3 after the plant

staff determined that both D/Gs were inoperable due to debris buildup.

At 11:47 p.m. on August 29, 2001, the licensee exited TS 3.0.3 after ESW flow for the D/Gs

increased after the control room operators cycled the ESW supply valves to the D/Gs.

At 2:15 a.m. on August 30, 2001, control room operators observed abnormally low ESW flow to

the Unit 2 West Component Cooling Water (CCW) Heat exchanger and declared the Unit 2

West CCW train inoperable. The operators cycled the Unit 2 West CCW heat exchanger ESW

inlet and outlet valves to improve ESW flow; however, ESW flow remained below normal

values. Because the degraded ESW flow condition was not fully understood, the licensee

subsequently shut down Unit 2.

Subsequent NRC engineering evaluations of the conditions present on August 29, 2001,

indicated that the presence of similar conditions during a single or dual unit loss of offsite power

event could potentially result in a loss of all onsite emergency alternating current power.

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R04 Equipment Alignment (71111.04)

a. Inspection Scope

The inspectors performed complete safety system walkdowns of the following

risk-significant system:

Mitigating Systems Cornerstone

Unit 1 ESW System

Unit 2 ESW System

The inspectors selected this system based on its degraded performance and its risk

significance relative to the mitigating systems cornerstone. The inspectors reviewed

operating procedures, TS requirements, Administrative Technical Requirements (ATRs),

and system diagrams. In addition, the inspectors assessed the impact of ongoing work

activities on redundant trains of equipment in order to identify conditions that could have

rendered these systems incapable of performing their intended functions.

4

b. Findings

The inspectors assessed the condition of the ESW system, the adequacy of the

licensees root cause evaluation, and the effectiveness of corrective actions during this

complete safety system walkdown. Findings relative to the performance of this

inspection module are discussed in Section 4OA3, "Event Followup."

1R07 Heat Sink Performance (71111.07)

a. Inspection Scope

The inspectors observed or reviewed portions of the following heat exchanger

inspections:

Unit 1 CCW heat exchangers, containment spray (CTS) system heat

exchangers, D/G heat exchangers, north control room air conditioning (CRAC)

heat exchangers and the auxiliary feedwater (AFW) pump room coolers.

These inspections were conducted following the ESW flow degradation event on

August 29, 2001. The inspectors assessed the heat exchanger condition relative to the

observed flow reduction to certain ESW cooled components and the potential for

common cause failure of ESW cooled components. Because ESW provided the

ultimate heat sink (UHS) for the emergency core cooling system, the inspectors

determined that this inspection was associated with the mitigating systems cornerstone.

b. Findings

The inspectors assessed the impact of the debris intrusion event on heat exchanger

capability in order to determine the safety impact of degraded ESW system performance

and the effectiveness of licensee corrective actions. Findings relative to the

performance of this inspection module are discussed in Section 4OA3, "Event

Followup," Subsections 4OA3.1, 4OA3.4, and 4OA3.5.

1R13 Maintenance and Emergent Work (71111.13)

a. Inspection Scope

The inspectors reviewed the risk assessment and risk management for the following risk

significant maintenance activities:

Mitigating Systems Cornerstone

Unit 1 dual ESW train outage to support forebay cleaning

The inspectors selected this maintenance activity based on ESW system degraded

performance and its risk significance relative to the mitigating systems cornerstone.

The inspectors reviewed the scope of maintenance work to ensure that applicable safety

functions were maintained during the maintenance activity. The inspectors also

reviewed TS and ATR requirements and walked down portions of redundant safety

5

systems, to verify that risk analysis assumptions were valid and applicable requirements

were met.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

The inspectors evaluated the potential operability impact associated with the following

issues:

Mitigating Systems Cornerstone

Operability of the ESW system following pump discharge strainer failure

Operability of the D/Gs with degraded ESW flow

The inspectors selected these issues based upon their risk significance and their

importance to the special inspection. The inspectors reviewed the licensee's evaluation

and supporting documentation to assess the basis and quality for the operability

determination. The inspectors concluded that this inspection was associated with the

Mitigating Systems cornerstone.

b. Findings

The inspectors reviewed the operability impact of the degraded ESW flow condition to

determine the safety significance of the event and assess the effectiveness of the

licensee's corrective actions. Findings relative to the performance of this inspection

module are discussed in Section 4OA3, "Event Followup," subsections 4OA3.4 and

4OA3.5.

1R19 Post Maintenance Testing (71111.19)

a. Inspection Scope

The inspectors reviewed the post maintenance testing requirements associated with the

following scheduled maintenance activity:

6

Mitigating Systems Cornerstone

Unit 1 CD D/G heat exchanger inspection

The inspectors reviewed post maintenance testing acceptance criteria specified in the

applicable corrective maintenance work orders. The inspectors verified that the

activities and acceptance criteria were appropriate for the scope of work performed.

Documented data was reviewed to verify that the testing was complete and that the

equipment was able to perform the intended safety functions.

b. Findings

No findings of significance were identified.

4. OTHER ACTIVITIES (OA)

4OA3 Event Followup (93812)

.1 Sequence of Events for Degraded ESW System Flow

a. Inspection Scope

The inspectors reviewed documentation and conducted interviews to determine the

sequence of events that resulted in degraded ESW flows to safety related equipment.

Additionally, the inspectors reviewed licensee actions during and immediately following

the degraded ESW event.

b. Findings

Based on a review of control room logs, operator statements, and plant process

computer data and instrumentation, the inspectors developed a sequence of events for

the degraded ESW flow event. The sequence of events covers the time period from

July 2001 through September 2001.

7

Date Time Event Description

July 1-2 Unit 1 and Unit 2 were operating in Mode 1 (Power

Operation) while the licensee performed biocide

treatment of the circulating water system for zebra

mussel control. Unit 1 Circulating Water (CW)

pump 13 reverse rotated following stoppage to

support biocide treatment. The licensee

determined that the CW pump 13 discharge valve

(1-WMO-13) was partially open and could not be

fully shut, resulting in backflow through the pump.

In order to stop the reverse rotation of CW pump 13

and allow restart of the pump, the licensee took the

Unit 1 main turbine offline and removed the CW

system from service . Following restart of CW

pump 13, Unit 1 was returned to full power.

August 27 Unit 1 was shut down to support repairs to CW

system valve 1-WMO-13.

Unit 2 continued to operate at full power.

August 29 ~6:30 a.m. Prior to the degraded ESW flow event, all ESW unit

cross tie valves were open and the normal and

alternate ESW supply valves to each D/G were

open. Initial ESW flows to the diesel generators

were approximately:

1 AB D/G= 920 gpm

1 CD D/G= 933 gpm

2 AB D/G= 860 gpm

2 CD D/G= 884 gpm

8

Date Time Event Description

August 29 11:06 a.m. The Unit 1 West ESW pump was started to support

Unit 1 cooldown to Mode 5 (Cold Shutdown). The

ESW system was aligned in the following

configuration:

Unit 1 West and Unit 2 East ESW pumps

supplied their common ESW header with

associated unit cross-tie valves open

Unit 1 East ESW pump supplied the Unit 1

East and Unit 2 West ESW common header

with associated unit cross-tie valves open.

The Unit 2 West pump was aligned for

standby operation.

The normal and alternate ESW supply

valves to all D/Gs were open

August 29 11:26 a.m. Unit 1 commenced cooldown using Residual Heat

Removal (RHR) system to Mode 5. This cooldown

approximately doubled ESW flow rates in Unit 1.

August 29 1:14 p.m. - Unit 1 CW pumps 11, 12 and 13 were stopped in

1:36 p.m. succession. Circulating water pump 13 was

stopped last to minimize the potential for backflow

through the pump due to the degraded condition of

valve 1-WMO-13.

August 29 ~3:00 p.m. Unit 1 cooldown completed and ESW flow rates in

Unit 1 decreased. Although the operators did not

identify any abnormal ESW system conditions

during the cooldown, ESW flows to each of the D/G

indicate degradation:

1 AB D/G= 674 gpm

1 CD D/G= 791 gpm

2 AB D/G= 760 gpm

2 CD D/G= 744 gpm

August 29 7:00 p.m. Unit 2 commenced surveillance testing of the Unit 2

East ESW system in accordance with

Procedure 02 OHP 4030.STP.022E. The cross-tie

valve between the Unit 1 West and the Unit 2 East

ESW headers was shut in accordance with the

procedure.

9

Date Time Event Description

August 29 ~7:15 p.m. The ESW flows to the Unit 1 AB and the Unit 2 CD

D/G decreased below the UFSAR Table 9.8-5

minimum required flowrate of 540 gpm. Flows to

each D/G were:

1 AB D/G= 400 gpm

1 CD D/G= 575 gpm

2 AB D/G= 618 gpm

2 CD D/G= 532 gpm

August 29 ~8:00 p.m. Both Unit 2 D/G ESW flowrates decreased below

UFSAR Table 9.8-5 minimum required flowrate.

Flows to each D/G were:

1 AB D/G= 265 gpm

1 CD D/G= 447 gpm

2 AB D/G= 538 gpm

2 CD D/G= 475 gpm

August 29 ~10:30 p.m. The Unit 1 East CCW heat exchanger outlet

temperature exceeded the alarm setpoint of 95°F.

The reactor operator experienced difficulty in

increasing ESW flow to the affected heat

exchanger; consequently, the outlet temperature

remained above the 95°F alarm setpoint until

approximately 2:30 a.m. on August 30, 2001.

The reactor operator failed to log receipt of the high

temperature alarm in the control room log, did not

enter the abnormal CCW operating procedure as

directed by the associated annunciator response

procedure, and failed to adequately communicate

the difficulty in controlling CCW outlet temperature

to the operations shift crew.

Flows to each D/G were less than 40 percent of

flow rates prior to the event:

1 AB D/G = 96 gpm*

1 CD D/G = 360 gpm**

2 AB D/G = 363 gpm

2 CD D/G = 256 gpm

The Plant Process Computer recorded the 1AB

D/G flow rate as "BAD DATA". A flow rate of

96 gpm was recorded prior to the "BAD DATA"

points.

10

Date Time Event Description

- The ESW flow rate for the 1 CD D/G remained

essentially constant for the remainder of the

event until the operators cycled system valves

to clear the debris blockage at approximately

12:40 a.m..

August 29 10:55 p.m. While performing the Unit 2 East ESW system

surveillance test procedure, the control room

operators noted that ESW flow to the 2 AB and

2 CD D/Gs were less than the surveillance test

acceptance criteria of 590 gpm. Unit 2 entered

TS 3.0.3 due to two inoperable D/Gs. It was later

determined that the limiting condition for operation

of TS 3.8.1.1.e should have been entered rather

than TS 3.0.3.

Unit 1 was informed of the low ESW flow condition

in Unit 2. Unit 1 also identified low ESW flow to the

1 AB and 1 CD D/G. Unit 1 entered TS 3.8.1.2 for

two inoperable diesel generators while in Mode 5.

August 29 11:47 p.m. The Unit 2 AB D/G was declared operable following

cycling of the remotely operated ESW supply

valves. Unit 2 AB D/G ESW flow improved to

approximately 800 gpm. Unit 2 exited TS 3.0.3 but

entered TS 3.8.1.1 for one inoperable D/G.

August 29 11:50 p.m. The Unit 2 CD D/G declared operable following

cycling of the remotely operated ESW supply

valves. Unit 2 CD D/G ESW flow improved to

approximately 800 gpm. Unit 2 exited TS 3.8.1.1.

August 30 12:40 a.m. The Unit 1 CD D/G declared available but remained

inoperable due to degraded ESW flow following

cycling of the remotely operated ESW supply

valves. ESW flow improved to 760 gpm.

August 30 1:25 a.m. The Unit 1 AB D/G declared available but remained

inoperable due to degraded ESW flow following

cycling of the remotely operated ESW supply

valves. ESW flow improved to 700 gpm.

11

Date Time Event Description

August 30 1:55 a.m. Unit 2 control room operators continued

performance of Unit 2 East ESW system

surveillance and aligned the normally isolated

Unit 2 East containment spray system (CTS) heat

exchanger for flushing in accordance with

02-OHP 4030.STP.022E.

At this time the source and extent of the debris

intrusion had not been positively identified and the

inspectors determined that this action could have

transported debris into the otherwise isolated CTS

heat exchanger. Because the source of debris

intrusion was later determined to be the Unit 1 East

ESW pump strainer (which was independent from

the Unit 2 East ESW header), this action did not

adversely impact the Unit 2 East CTS heat

exchanger.

August 30 2:09 a.m. The Unit 2 West ESW pump was started.

August 30 2:13 a.m. The Unit 2 ESW unit cross-tie valve, 2-WMO-706,

was shut to split the ESW systems. All four ESW

pumps were running with all unit cross-tie valves

closed.

August 30 2:15 a.m. Unit 1 East ESW and CCW trains were declared

inoperable (but available) due to degraded ESW

flow system. Actions associated with TS 3.7.3.1

and TS 3.7.4.1 were not applicable with Unit 1 in

Mode 5.

Unit 2 West CCW heat exchanger flow indicated

approximately 2000 gpm with outlet temperature

rising slowly at 92o F. Cycling of the ESW inlet and

outlet valves improved heat exchange flow to

5500 gpm. This flow rate was less than the

expected value of approximately 8500 gpm. Unit 2

entered TS 3.7.3.1 for the inoperable Unit 2 West

CCW loop.

August 30 2:30 a.m. Unit 2 East CTS heat exchanger declared operable

following completion of ESW surveillance testing

flush.

12

Date Time Event Description

August 30 2:45 a.m. Unit 2 control room operators started the south

control room air conditioning (CRAC) unit and

stopped the north CRAC for flushing during

02-OHP4030.STP.022E.

At this time the source and extent of the debris

intrusion had not been positively identified and the

inspectors determined that placing the south CRAC

unit into service could have allowed transport of

debris into the associated heat exchanger.

Because the source of debris intrusion was later

determined to be the Unit 1 East ESW pump

strainer (which was isolated from Unit 2 by closure

of 2-WMO-706), this action did not adversely

impact the CRAC unit.

August 30 3:45 a.m. Unit 1 AB D/G declared operable after closing and

de-energizing the alternate ESW supply remotely

operated valve from the Unit 1 East ESW header.

Unit 1 exited TS 3.8.1.2.

August 30 6:23 a.m. Licensee completed 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months report to the NRC

regarding degraded ESW flow to the D/Gs (Event

Number 38249).

August 30 7:55 a.m. Unit 2 commenced 15 percent per hour power

reduction for reactor shutdown.

August 30 1:36 p.m. Unit 2 entered Mode 2 (Reactor Startup).

August 30 1:47 p.m. Unit 2 entered Mode 3 (Hot Standby).

August 31 4:15 a.m. Unit 1 East motor driven auxiliary feedwater pump

(MDAFWP) inoperable due to low ESW flow to its

room cooler.

August 31 6:10 a.m. Unit 1 East MDAFWP declared operable after ESW

flow to room cooler restored.

September 3 12:28 p.m. Unit 2 entered Mode 5 and exited TS 3.7.3.1.

Results of Essential Service Water Inspections

Following shutdown of Unit 2, the licensee performed inspections on the ESW system to

determine the cause and extent of condition of degraded ESW system performance. The

results of significant ESW system inspections conducted after implementation of the

licensees immediate corrective actions following the event are summarized below:

13

Component Inspection Results

Unit 1 East ESW pump Deformation of the strainer basket and resultant bypass

discharge strainer flowpath around the basket was identified. Additionally,

the basket support bracket was deformed.

Unit 1 East CCW Heat Inspections identified the following:

Exchanger

213 tubes were obstructed with debris (approximately

10 percent tube blockage). All tubes were cleaned

using a hand brush.

Approximately 1.5 cubic feet of debris found in the

interpass region and about one half cubic foot of

debris found in the inlet plenum.

Debris measuring greater than 1/8 inch (the ESW

strainer mesh size) was identified in the heat

exchanger. In general, the debris consisted of zebra

mussel shells and sand.

Note: The CCW heat exchanger is a two pass shell and

tube heat exchanger with ESW flowing through

the tube side.

Unit 1 West CCW Heat Inspections identified the following:

Exchanger

33 tubes blocked with silt and debris (approximately

1.5 percent tube blockage)

Minimal amounts of shells and debris

Note: 85 additional tubes in the Unit 1 West CCW heat

exchanger were mechanically blocked during

previous maintenance activities.

Unit 1 East CTS Heat Inspection identified the following:

Exchanger

Very light silting, less than 1/4 inch thick in the lower

shell area. No shells were found.

Note: The CTS heat exchanger is a shell and U-tube

heat exchanger with ESW flowing on the shell

side.

Unit 1 AB D/G Heat Inspection identified minimal amounts of debris and no

Exchangers tube blockage.

14

Component Inspection Results

Unit 1 CD D/G Heat Inspection of the 1 CD D/G heat exchangers identified

Exchangers the following:

Lube oil cooler had 14 blocked tubes with debris and

7 partially blocked tubes (approximately 10 percent of

the heat exchanger tubes had some blockage and

were degraded). All tubes were cleaned.

The jacket water heat exchanger had 14 tubes

blocked with debris (approximately 6 percent total had

some blockage and were degraded). Two tubes

remained blocked after cleaning.

Unit 1 North CRAC Inspection of the CRAC unit identified minimal debris and

no blocked tubes.

Unit 1 East MDAFWP Inspection of room cooler identified 18 pre-cooler tubes

Room Cooler fully blocked with debris and 18 pre-cooler tubes partially

blocked with debris (approximately 27 percent of the

pre-cooler tubes had some blockage and were

degraded). The associated job order stated that the

pre-cooler section was "full of dirt, zebra mussels, and a

steel ball."

Unit 1 West MDAFWP Inspections identified 1 pre-cooler tube of 132 total tubes

Room Cooler blocked with a small amount of sand and mussel shell

debris.

Unit 1 East Turbine Approximately one pound of debris was removed from

Driven Auxiliary the room cooler during flushing activities. Inspections

Feedwater Pump identified that 7 of 48 pre-cooler tubes were blocked with

(TDAFWP) Room sand, silt and/or zebra mussel shells.

Cooler

Unit 1 West TDAFWP 10 of 48 pre-cooler tubes were blocked with zebra

Room Cooler mussel shells and sand.

Unit 2 West CCW Heat Inspections identified less than 24 tubes blocked with

Exchanger weed-like growth, tubercles, and zebra mussel shells

(approximately 1 percent tube blockage). Because this

inspection was performed approximately 4 weeks after

the event, normal system flow through the heat

exchanger could have facilitated cleanup of debris.

15

Component Inspection Results

Unit 2 West CTS Heat This heat exchanger was not inspected immediately

Exchanger following the event, but was inspected during the January

2002 Unit 2 refueling outage. Results of inspections

performed on February 4, 2002 identified minor amounts

of debris, including sand and shell fragments, on top of

tube sheet (4 - 6 cups total).

Unit 2 AB D/G Heat Inspection identified:

Exchangers

6 partially blocked tubes in the lube oil heat

exchanger (less than 3 percent tube blockage).

2 partially blocked tubes in the jacket water heat

exchanger (less than 1 percent tube blockage).

All tubes were cleaned.

Unit 2 CD D/G Heat Inspection identified:

Exchangers

2 blocked tubes in the lube oil heat exchanger (less

than 1 percent tube blockage).

3 blocked tubes in the jacket water heat exchanger

(less than 2 percent tube blockage).

Unit 2 North CRAC Inspection identified no blocked tubes.

Heat Exchanger

Unit 2 West MDAFWP Inspection of room cooler identified 5 pre-cooler tubes

Room Cooler fully blocked with debris and 11 pre-cooler tubes blocked

at the inlet with debris (approximately 12 percent of the

pre-cooler tubes had some blockage and were

degraded)

Unit 2 West TDAFWP Inspections identified 18 of 48 pre-cooler tubes to be

Room Cooler blocked with zebra mussel shells and sand. Condenser

coil for refrigeration unit also appeared to be partially

blocked.

.2 Adequacy of Licensee Response to ESW Low Flow Condition Including Emergency

Plan Implementation

a. Inspection Scope

The inspectors reviewed the licensees immediate corrective actions in response to the

ESW low flow condition and the corrective actions to restore the ESW trains to their

design and licensing basis.

16

b. Findings

Initial Identification

The inspectors determined that control board indication of the trend of the degrading

ESW flow could have been identified by the operators at least 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months prior to the initial

identification of the degraded flow. The delay in the identification of the low flow by the

operators was due, in part, to the failure of the operators to perform hourly control board

walkdowns recommended by procedure. The inspectors determined that operator

practice was to no longer perform the recommended walkdowns. However, the delay in

the identification did not result in a significant impact on event recovery actions.

Initial Response

The inspectors determined that the operators initial response to the event was

adequate to ensure that reactor safety was maintained. The operators ensured that the

reactor coolant system (RCS) temperature was being maintained within the required

parameters and the ability to cool the RCS was maintained. In addition, the Unit 2

operators promptly informed the Unit 1 control room operators upon the identification of

the degraded ESW flow.

The inspectors determined that the Unit 2 Unit Supervisor (US) inappropriately entered

TS 3.0.3 upon declaring both Unit 2 D/Gs inoperable. Inoperability of both D/Gs

required an entry into Limiting Condition of Operation (LCO) TS 3.8.1.1.e, which

required that two offsite power source circuits be demonstrated operable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Although the wrong TS LCO was entered, the licensee performed the off-site power

operability verifications and complied with the time limits specified in TS 3.8.1.1.e.

The licensee identified that the Unit 1 US failed to enter TS 3.1.2.3, for inoperable

boration flow paths, when the D/Gs were inoperable. The action statement required that

no core alterations be performed. Since no core alterations were in progress, the

TS LCO was met.

The operating crews correctly diagnosed the low ESW flow and were able to improve

ESW flow to the D/Gs by repeatedly cycling ESW supply and return flow valves.

Approximately 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months after initially identifying the degraded ESW condition, the

operators closed the ESW unit cross-tie valves so that each unit was receiving ESW

flow only from its associated ESW pumps. The licensee did not identify that ESW flows

to the Unit 1 East and Unit 2 West CCW heat exchangers were degraded until after the

ESW cross tie valves were shut. The inspectors determined that communication

inadequacies contributed to the 3 hour3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months delay in the identification of the low ESW flows to

the CCW heat exchangers. For example, the Unit 1 high CCW temperature condition

was not adequately communicated to the Senior Reactor Operators, and the Unit 2

operators were not promptly informed of the high Unit 1 CCW temperature.

Emergency Classifications

The licensee did not declare an emergency classification for this event. The operations

Shift Manager and Operations Director considered declaring an emergency

17

classification at approximately 4:30 a.m. following the initial indications of degraded

ESW flow. The licensees emergency plan and implementing procedures have no

specific Emergency Condition Categories (ECC), Initiating Condition (IC), or Emergency

Action Level (EAL) that would address significantly reduced ESW flow. Emergency

Condition Category S-5, Loss of Systems Needed to Achieve/Maintain Hot Shutdown,

was most appropriate; however, the entry conditions required a complete loss of the

function with entry into EOP FR-H1, Response to Loss of Secondary Heat Sink, or

FR-C1, Response to Inadequate Core Cooling. The ECC for Site Emergency

Coordinator (SEC) Judgement did give a threshold value of In the judgement of the

SEC: Conditions indicate that plant safety systems may be degraded, and increased

monitoring of plant functions is needed. Under the licensees procedures this would

result in the declaration of an Unusual Event. The inspectors concluded that a

declaration of an Unusual Event should have been made due to the degradation of

multiple trains of safety-related equipment on each unit. However, the failure to declare

an Unusual Event was determined to not constitute a violation of regulatory

requirements.

Subsequent Response

The licensee was conducting an ESW system surveillance test during the event. While

the performance of the surveillance aided the operators in the identification of the

degraded ESW flow, continuation of the surveillance test procedure could have

exacerbated the heat exchanger fouling. For example, the CTS heat exchanger and

South CRAC heat exchanger isolation valves were opened per the surveillance

procedure, which could have introduced debris into these otherwise clean heat

exchangers. However, subsequent analysis of the heat exchangers by the licensee

determined that heat exchanger performance was not affected.

.3 Determination of Root Cause for ESW Low Flow Condition

a. Inspection Scope

The inspectors reviewed the as-found condition of components of the ESW system

including the Unit 1 East ESW pump discharge strainer. The inspectors' review

included the observation of heat exchanger end bell removal, pump discharge strainer

inspections, and flushing activities. The inspectors also interviewed individuals involved

in these activities and reviewed the licensees apparent root cause for the ESW low flow

condition.

b. Findings

The licensee evaluated the root cause of the degraded ESW flow event and concluded

that the root cause of the event was the following:

"The root cause for this event was that a strainer basket was installed incorrectly

during basket replacement activities that occurred in the 1989 time frame. The

failure to adjust the height of the basket to align the top edge of the basket with

the lip of the strainer body allowed the basket to be placed in compression when

the >> 700 lb. strainer lid was reinstalled. The compressive force exerted by the lid

18

caused the basket mesh to tear in the area of the weld on the baskets vertical

support bracket and was the initiating event for the resultant damage and

eventual failure of the basket."

The licensee inspected all eight ESW strainer baskets and identified that the Unit 1 East

ESW pump discharge strainer east basket had a weld failure on the height adjustment

bracket that allowed the bracket to bend and drop the basket by approximately 3 inches.

This deformation allowed a bypass of debris greater than the 1/8" strainer mesh size.

The passage of debris greater than the normal strainer mesh size resulted in fouling of

heat exchangers in the ESW system and the consequent flow degradation experienced

on August 29, 2001. The licensee reviewed past maintenance performed on the failed

strainer and concluded that the strainer was initially damaged during a basket

replacement that occurred in 1989.

The inspectors assessed the licensees root cause methodology and conclusions and

determined that the licensee adequately identified the root cause of the degraded ESW

flow event. The inspectors concluded that the licensees approach was reasonable, and

adequately addressed contributing causes to the event. The inspectors reviewed

records from the Unit 1 East ESW pump discharge strainer replacement conducted in

1989 and concluded that the strainer installation instructions used in 1989 were

inadequate. The instructions provided for replacement of the strainer baskets,

contained in Job Order 723483, lacked sufficient detail to ensure that critical parameters

associated with strainer installation were maintained. Specifically, the JO 723483

instructions did not contain sufficient detail regarding adjustment of strainer basket

height within the strainer housing or verification that the installation prevented basket

bypass paths greater than 1/8" in size. The inspectors determined that the failure to

provide adequate instructions for ESW strainer basket maintenance constituted a

violation of regulatory requirements.

10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," stated, in

part, that activities affecting quality shall be prescribed by documented instructions,

procedures, or drawings of a type appropriate to the circumstances. The inspectors

determined that the documented instructions for installation of the ESW strainer

baskets, an activity affecting quality, were not of a type appropriate to the

circumstances. Specifically, the Unit 1 East ESW pump discharge strainer east basket,

was installed on April 18, 1989 in accordance with Job Order 723483. The strainer

basket installation instructions referenced by Job Order 723483 did not contain

adequate detail associated with the verification of critical parameters affecting strainer

basket alignment during installation. The failure to adequately align the ESW strainer

basket within the strainer housing would allow debris greater than 1/8" in size to bypass

the strainer or allow damage to the basket vertical support bracket during strainer cover

re-installation. This issue is identified as Apparent Violation (AV) 50-315/01-17-01;

50-316/01-17-01. This finding was assessed using the applicable SDP as a potentially

safety significant finding that was preliminarily determined to be Yellow. The details of

the SDP evaluation are contained in Section 4OA3.4 below.

.4 Specific and Generic Impacts of ESW Debris Intrusion

19

a. Inspection Scope

Subsequent to the August 2001 debris intrusion event, the licensee conducted

engineering and probabilistic evaluations that assessed the specific and generic impacts

of the failed IE ESW system strainer on ESW supported systems. The licensee

described their engineering evaluation in Technical Report NTS-2002-002-REP, ESW

Debris Intrusion Event Evaluation, Revision 0, completed in January 2002. The

licensee described their probabilistic evaluation in Technical Report

NTS-2002-010-REP, Debris Intrusion Into the Essential Service Water System -

Probabilistic Evaluation, Revision 0, completed in April 2002. The inspectors reviewed

the evaluations, assessed their fidelity to the August 2001 data, and used the

evaluations and other design information to determine the capability of ESW supported

safety-related systems to perform their functions during the August 2001 event and

applicable design basis events.

b. Findings

b.1 Engineering Evaluation

The licensees engineering evaluation examined the August 2001 debris intrusion event

and the potential consequences of a similar debris intrusion following a single unit loss

of offsite power (LOOP) event. The evaluation considered debris entrainment within the

intake structure and ESW system, the hydraulic characteristics of the ESW-D/G system,

and the performance characteristics of the ESW-D/G heat exchangers. As a separate

part of the engineering evaluation, the licensee developed a revised single unit LOOP

initiating event frequency, a human performance reliability analysis of the operators

response to a similar debris intrusion event, and a plant-specific Large Early Release

Frequency (LERF) analysis.

Debris Entrainment

Overall, the licensees engineering evaluation concluded that debris intrusion events,

assuming a failed 1 East ESW strainer, could not be precluded. Debris intrusion into

the ESW system was expected to occur following a single unit LOOP event, a seismic

event that causes a LOOP, or during a severe storm that resulted in a LOOP event.

Though not explicitly stated, the engineering evaluation focused on a single unit LOOP

event. A detailed review of the potential for and consequences of a dual unit LOOP

event were not evaluated. During discussions with the inspectors, the plant staff

indicated their belief that a single unit LOOP event would result in entrainment of the

largest amount of debris.

The licensees engineering evaluation determined that low vertical flow velocities were

required to entrain debris in the intake structure, on the order of 0.15 feet/second for

sand and 0.30 feet/second for shells. Once entrained, the evaluation calculated that the

debris could take up to an hour to re-settle to the intake structure floor depending on the

hydrofoil effect associated with the shells. The plant staff assumed that intake structure

cross flows, created during the August 2001 event and expected to exist following a

single unit LOOP event, would entrain the greatest amount of debris. However, the

licensees engineering evaluation did not assess the potential for intake structure cross

20

flows or intake structure debris to be entrained by flow perturbations following a dual unit

LOOP.

Once debris was ingested into the ESW system, the engineering evaluation determined

that flow rates on the order of 140 gallons/minute were necessary to maintain the debris

suspended within the flow of a horizontal section of 6 inch diameter ESW supply piping

to the D/G heat exchangers. Based upon calculations , flow rates of 200 and

400 gallons/minute were determined to be needed to maintain sand and shells,

respectively, suspended in the flow of a vertical section of 6 inch diameter pipe. Though

the engineering evaluation recognized that lower flow rates could maintain shells within

the flow stream if shell hydrofoil effects were considered.

The inspectors reviewed the licensees records of circulating and service water intake

structure inspections and determined the intake structure often contained debris,

e.g. sand, silt, and mussel shells. The debris was typically located in the quiescent flow

regions of the intake structure, including directly in front of the ESW pump bays. Recent

and past operating experience indicated that debris, present in the intake structure

quiescent flow areas, could be entrained in the circulating and essential service water

flows as a result of intake structure flow disturbances. Changes in the circulating and

essential service water system flow rates, severe weather, and LOOP events were all

conditions capable of causing intake structure flow disturbances.

The inspectors reviewed the August 2001 circulating and essential service water system

operating information and determined that significant changes in the intake structure

flow patterns were the most likely cause for debris entrainment. The changed flow

patterns entrained debris, previously located in quiescent flow areas, and transported

the debris to the 1 East ESW system pump suction area. This effect was consistent

with the staggered shutdown of the Unit 1 circulating water pumps, which limited

perturbations of the intake structure water inventory; the continued operation of the

Unit 2 circulating water pumps, which caused a significant change in the intake structure

water flow patterns; and the observed gradual degradation of ESW system flow to the

D/Gs.

The inspectors also determined that a larger short-term ingestion of debris would likely

occur as a consequence of either a single unit LOOP, dual unit LOOP, or severe

weather event. These events would be expected to cause both changes to the intake

structure flow patterns, as observed with the August 2001 event, and significant intake

structure water perturbations, due to an approximate 10 to 12 foot increase in the intake

structure water level following a dual unit LOOP. As a result, the inspectors concluded

that a dual unit LOOP event would likely result in a significantly larger ingestion of debris

over a shorter period of time than that created by the circulating water system cross-flow

associated with the August 2001 event or which would likely occur following a single unit

LOOP.

ESW-D/G Hydraulic Characteristics

The licensees engineering evaluation determined an approximate percentage of

blocked ESW-D/G heat exchanger tubes that would be necessary to cause the

August 2001 observed degraded flow conditions. Initial results indicated that plugging in

21

excess of 90% of the heat exchanger tubes would be necessary to cause the observed

flows. Because of the ease with which the operators were able to restore flow through

some of the heat exchangers, the licensee rejected the engineering evaluation initial

conclusion that a high percentage of tubes were blocked.

As an alternate hypothesis, the licensee conjectured that the August 2001 degraded

flow conditions were caused by a combination of blocked tubes and the buildup of a

porous debris pile on the heat exchanger tube sheets. The debris pile was assumed to

be composed of a combination of shells, sand, and silt. The majority of the buildup was

assumed to occur at the ESW-D/G lube oil heat exchanger tubesheet for the

August 2001 event. While the presence of a debris pile would significantly decrease

ESW-D/G flow rates, the licensee assumed that only a limited number of heat

exchanger tubes would not be available for heat transfer.

Based upon computer logs of ESW-D/G flow data from the August 2001 event, the

licensees engineering evaluation concluded that the buildup of a debris pile on a heat

exchanger tubesheet would: 1) be self-limiting with a minimum average ESW-D/G flow

rate of 200 gallons/minute; 2) occur initially at the D/G lube oil heat exchanger inlet

tubesheet; and, 3) be limited to a single ESW-D/G heat exchanger tubesheet location

during a LOOP event. The evaluation supported the minimum average ESW-D/G flow

rate by rejecting non-numerical computer data recorded for the 1 AB D/G and by

averaging the remaining lowest recorded flow values. The evaluation supported the

single location debris buildup position by assuming that the debris piles were inherently

unstable and could not be maintained, due to a constant loss of material, if the source of

new material was lost due to a change in the ESW-D/G flow path following a LOOP.

The inspectors determined that the engineering evaluation likely overestimated the

percentage of blocked tubes necessary to cause the observed August 2001 degraded

flow conditions. The inspectors noted that the licensees evaluation did not consider

several factors which would affect the blocked tube estimate including entry and exit

pressure losses caused by changes in the ESW mass flow velocity and an increased

flow resistance caused by the presence of a two-phase mixture down stream of the

jacket water heat exchanger. The inspectors estimated the percentage of blocked

tubes, which alone could have caused the observed degraded flow conditions, to be well

in excess of 50% but less than the near 90% values initially calculated in the licensees

engineering evaluation.

The inspectors performed independent flow hydraulic calculations and concluded that a

relatively thin filter bed, on the order of 3 inches or less, of sand could have caused the

observed degraded flow conditions. The filter bed was assumed to be developed from

an initial layer of shell fragments and other debris on tubesheet with a subsequent

buildup of a variety of particle sizes of sand, silt, and clay particles forming a filter bed of

relatively low porosity. The calculation results were noted to be very sensitive to the bed

composition because of the ability of the smaller particles to fill the flow paths between

the larger sand particles. Based upon post August 2001 photographs of heat exchanger

tubesheets, which showed some tubes still blocked by wedged shell fragments and

other debris, the inspectors concluded that the observed ESW-D/G flow reduction was

most likely caused by a combination of heat exchanger tube blockage and a

non-uniform debris pile buildup on the heat exchanger tubesheet.

22

The inspectors evaluated the computer logs of ESW-D/G flow data for the August 2001

event and determined that the data did not specifically support the licensees

assumptions of a self-limiting debris buildup, with a minimum ESW-D/G flow rate of

200 gallons/minute, or a single heat exchanger tubesheet debris pile buildup location.

While the computer logs of ESW-D/G flows did indicate that the 1 CD ESW-D/G flow

leveled off at a degraded flow rate of 350 gallons/minute; data for the 1 AB ESW-D/G

indicated a steady decreasing trend which lowered flow below the level of reliable

indication. In addition, computer logs for the Unit 2 ESW-D/G flow rates indicated that

both Unit 2 ESW-D/G flow rates experienced a decreasing trend with low recorded flow

values of approximately 300 and 250 gallons/minute. Operator and computer logs of

ESW flow data also indicated that not all debris piles were inherently unstable, a pre-

condition for a self-limiting process. The logs indicated that the ESW-D/G flows

appeared to drop relatively rapidly, as the blockage built up, and the ESW-component

cooling water (CCW) and 1 AB D/G heat exchanger flows remained degraded, despite

several attempts by the operators to clear the blockage. Combined, these data

indicated that ESW system debris piles were not self-limiting or unstable in their buildup,

with a minimum ESW-D/G flow rate of 200 gallons/minute.

Based upon information provided in the licensees engineering evaluation, the

inspectors concurred with the licensees contention that a debris pile buildup was most

likely to occur at the first flow restriction in the ESW-D/G flow path. However, the

inspectors also noted that the first flow restriction location would change during the

course of the plants response to a LOOP event potentially resulting in multiple debris

piles restricting ESW-D/G flow. Initially, the first flow restriction would be at the D/G

lube oil heat exchanger tubesheet, as observed during the August 2001 event.

However, once the D/Gs began to operate, the first flow restriction location would

change, due to an automatic system re-alignment, to either the inlet to the D/G air

after-cooler temperature control valve or to the D/G air after-cooler heat exchanger

tubesheet. A debris buildup at either of these locations may be quicker to develop and

may be more difficult to clear than a debris build up at the lube oil heat exchanger due to

vertical piping upstream of the three-way valve and the smaller air after-cooler heat

exchanger intake head volume. Additionally, the presence of distributed pressure

drops, due to multiple debris piles, would also reduce the effectiveness of operator

actions to flush debris from the system.

ESW-D/G Cooler System Performance Characteristics

The licensees engineering evaluation considered the minimum ESW-D/G flow required

to maintain D/G lube oil and jacket water coolers within maximum allowed parameters

assuming variable degree and location of heat exchanger plugging, tube fouling, and

design event loading. Overall, the evaluation determined that approximately

140 gallons/minute ESW-D/G flow was required to assure minimum D/G performance

during a LOOP event. This calculation assumed the blockage of up to 60% of one pass

of the D/G heat exchanger tubes and design fouling. Approximately 200 gallons/minute

ESW-D/G flow was required to assure minimum D/G performance during a LOOP-loss

of coolant accident (LOCAL). This calculation assumed the blockage of up to 50% of

one pass of the heat exchanger tubes and design fouling. Calculations for both cases

indicated that the minimum ESW-D/G flow required to maintain the D/G lube oil and

23

jacket water cooler within maximum allowed parameters increased rapidly with

increased tube blockage beyond the levels stated above.

The inspectors determined that the licensees engineering evaluation did not consider

several factors which would affect the calculated minimum flows necessary to support

continued D/G functioning. Examples included: 1) entry and exit pressure losses

caused by changes in the ESW-D/G mass flow velocity through a smaller number of

heat exchanger tubes; 2) an increased ESW-D/G flow resistance caused by the

presence of a two-phase mixture down stream of the jacket water heat exchanger at

reduced ESW-D/G flow rates, and; 3) changes in the ESW-D/G heat transfer rates due

to the presence of a debris bed which would have degraded ESW-D/G flow through the

individual tubes. While the exact impact on the minimum ESW-D/G flow rate of each of

these factors was not determined, the inspectors concluded that the overall level of

ESW-D/G flow rate, necessary to support continued D/G functioning, was significantly

less than the Updated Final Safety Analysis Report (UFSAR) value of 540

gallons/minute and may be approximated by the licensees calculations.

Single Unit LOOP Initiating Event Frequency

In conjunction with the engineering analysis, the licensee proposed that both the

August 2001 event and the generic impacts of an ESW-D/G debris intrusion event

should be evaluated using a revised single unit LOOP initiating frequency. Based upon

recent changes to the plant switchyard, the licensee conducted a review of data from

several databases (including NUREG/CR-5496 and NUREG/CR-5750) to determine a

revised initiating event frequency for a single unit LOOP event at a dual unit site. In

conducting the analysis, the licensee assumed that a single unit LOOP was the risk

dominant event, and that a dual unit LOOP event would not result in sufficient debris

entrainment in the ESW-D/G flow. Therefore, the licensees analysis only considered

single unit LOOP events at dual unit sites. The analysis eliminated all dual unit LOOP

events, as well as events that the licensee determined to be not applicable to the plant.

Based upon the analysis, the licensee proposed that a single unit LOOP initiating event

frequency of 0.004 per year should be used to evaluate the August 2001 and a potential

generic ESW-D/G debris intrusion event.

The inspectors reviewed the licensees analysis and determined that the proposed

initiating event frequency may be an underestimation for the following reasons:

Although the licensees analysis credited the plant-specific electrical distribution

system as being unique and better than assumed in the generic cases (by

eliminating events that the licensee believed could not occur at the plant), there

was no similar effort done for the plant-specific electrical distribution system to

determine if any plant-specific events could occur that could not occur at the

other plants. Thus, only a limited scope comparison was performed. (One

example would be that, although hurricane events were eliminated due to plants

location, vulnerability to events caused by ice storms were not explicitly

considered.)

The licensee included data from sites like Indian Point, Nine Mile Point and

Fitzpatrick that share control of switchyard activities among differing licensees.

24

Data from these sites may not be appropriate for use in determining a plant-

centered loss of offsite power initiating event frequency for D.C. Cook because

D.C. Cook may be more vulnerable to a common cause failure or switchyard

error that may result in a loss of offsite power to both units.

The licensees assumption that the dual unit LOOP initiator will not entrain debris

into the ESW-D/G was not considered a valid assumption. Therefore, the

licensees elimination of dual unit initiators from inclusion in the overall initiating

event frequency was not acceptable. The generic frequency of severe weather

events, which are the most probable cause for dual unit LOOP events, was

approximately 0.007 per year, about twice the licensees estimate for the single

unit initiator.

Based upon current generic estimates of a single unit LOOP initiating frequency and

plant specific information provided by the licensee, the inspectors concluded that the

single unit LOOP initiating frequency for the plant could be lower than the generic

frequency. However, the inspectors did not consider the differences to be supported to

the extent to justify a plant-specific initiating frequency one tenth the generic initiating

frequency (0.004 versus 0.046). Based upon licensee provided information and

engineering judgement, the inspectors used a single unit LOOP initiating frequency of

0.01 for subsequent NRC risk analyses.

Human Error Probability Analysis

The licensee performed an analysis to estimate the human error probability (HEP)

associated with operator actions to recover ESW-D/G flow to the heat exchangers for a

single unit and dual unit LOOP event. The HEP for a single unit event was estimated to

be 0.05 for the recovery prior to the initiating event and for recovery during a single unit

LOOP event. The licensee estimated the HEP for operator action to recover for a dual

unit LOOP event to be either 0.13 or 1.0 depending on the time available. The HEP

analyses took into account cognitive as well as execution errors. Although the licensee

did not have approved procedures or training for the recovery actions credited in the

analyses, the licensee concluded that credit could be taken for the actions since

operators had actually performed the actions during the August 2001 ESW-D/G

intrusion event.

The inspectors reviewed the analysis methodology used by the licensee and concluded

that the methodology was acceptable and was applied correctly. The inspectors also

determined that the licensees assumption of credit for the operators proper

implementation of the unproceduralized and untrained recovery actions was appropriate

given the fact that these actions were actually carried out during the August 2001 event.

Although a level of uncertainty existed as to how much time might be available for

operator action during a single unit LOOP event, the inspectors determined that the

licensees HEP estimate of 0.05 was reasonable if sufficient time was available

(i.e., time from the start of a LOOP event to the time when below reliable indication of

ESW-D/G flow through the heat exchanger exceeds 5 to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ). The 0.05 was

considered optimistic for recovery times of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months or less. For a dual unit LOOP event,

the inspectors determined that an HEP of 0.13 was appropriate when the operators

25

would have approximately 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months to response. This is the value used for subsequent

NRC risk analysis of a dual unit LOOP event. If the operators did not have sufficient

time to respond, less than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , the inspectors determined that ESW-D/G flow from

the opposite Unit could not be credited for valve cycling or heat exchanger flushing

actions. In these cases, an HEP of 1.0 was considered appropriate.

Large Early Release Frequency

Prior to the August 2001 ESW-D/G debris intrusion event, the licensee developed a

plant-specific large early release frequency (LERF) estimate. Using methodology

described in NRC document NUREG/CR-6595 and figure 2-2 of the document, the

licensee estimated a plant-specific LERF to CDF ratio of 0.1. During discussions with

the NRC of the engineering evaluation of the August 2001 intrusion event, the licensee

proposed that risk analyses of the event should use the plant-specific LERF to CDF ratio

value of 0.1.

The inspectors reviewed documentation provided by the licensee to support their

proposed use of a LERF to CDF ratio of 0.1. The inspectors determined that the

licensee evaluation only modeled a single unit LOOP, therefore adequate time was

postulated for ESW-D/G recovery and for onsite and offsite emergency response. As a

result of the credit taken for these actions, a large fraction of the core damage

sequences were allocated to the non-large early release category. Only approximately

16 percent of the revised core damage sequences were considered in calculating the

LERF.

In the NRCs risk evaluations of the ESW-D/G debris intrusion event that lead to core

damage sequences, a station blackout event was modeled. In these cases,

containment hydrogen igniters were not considered available due to an absence of

required power. In such scenarios, recent NRC studies (e.g., studies for the

containment significance determination process and for the resolution of the generic

issue for the combustible gas issue) indicated that the conditional probability of large

early release given a core damage event for an ice condenser containment was

approximately 0.82.

Considering that both the licensees and the NRCs LERF values were developed using

NRC guidance, though with differing assumptions, and the potential uncertainty in

assessing the effectiveness of the licensees onsite and offsite emergency response

efforts, a LERF value of 0.4 was used in subsequent NRC risk analyses.

b.2 Probabilistic Evaluation

Subsequent to and in support of the licensees engineering evaluation discussed above,

the licensee performed a probabilistic evaluation of the impact of a failed ESW-D/G

strainer on the plants response following a LOOP event. The evaluation assumed a

single or dual unit LOOP as the initiating event [Block 1] and identified a logical

sequence of steps [Blocks 2 through 9] which could lead to D/G failure as a result of

debris intrusion into the ESW-D/G flow. The licensees probabilistic evaluation

considered the likelihood of the sub-events which collectively comprised an ESW-D/G

debris intrusion event. The probabilistic evaluation considered debris intrusion events

26

following both single and dual unit LOOPs. The licensee selected subjective

probabilities for each of the steps using an expert elicitation technique similar to one

described in NUREG/CR-5424. The individual probabilities were then combined to

determine the conditional failure probability of each sequence of steps. These results

were then incorporated into the plant probabilistic risk analysis model to determine

resultant increases in the core damage frequency (CDF) and large early release

frequency (LERF). Results of these efforts indicated only slight increases in the CDF

and LERF values, 2.8E-07 per year and 4.2E-08 per year, respectively.

The inspectors evaluated the engineering and probability information provided for each

of the licensee-defined blocks. The results of the individual block evaluations were then

combined into an D/G common cause failure factor. This factor was then used to

modify SPAR model risk analysis results. Based upon information provided in the

licensees probabilistic evaluation, the inspectors developed a common cause failure

factor of 0.14 for a single unit LOOP event and 0.024 for a dual unit LOOP event. Using

the NRCs SPAR model and the assumptions stated below, the inspectors and NRC

Headquarters staff determined that the delta CDF and LERF values for the issue were

1.8E-05 per year and 7.1E-06 per year, respectively.

A summary of the inspectors assessment of the licensees overall evaluation

methodology and the individual block results were as follows.

Overall Methodology

The inspectors reviewed the overall evaluation methodology and NUREG/CR 5424. The

inspectors determined that the overall methodology was reasonable and that the

identified steps in the sequence of events were consistent with the course of events that

would be necessary for a debris intrusion event to occur. However, the inspectors also

determined that the subjective probability scale developed by the licensee using the

referenced NUREG/CR 5424 was not consistent with the information provided in the

NUREG/CR 5424. Instead of the relatively continuous scale proposed and used in the

NUREG/CR 5424, the licensees scale tended to stratify event probabilities near 1.0 and

0. As a result, the licensees under-estimation of one or two steps in a sequence of

steps would tend to significantly decrease the overall probability for a sequence.

Several sequences appeared to have been affected by the licensees use of their

subjective probability scale, as described below.

Block 1: Loss of Offsite Power

The licensees analysis assumed the LOOP event, either single or dual unit, as a given.

Therefore, this probability was set equal to 1.0.

The inspectors used a similar approach to developing their common cause factor.

Therefore, the inspectors also considered the probability for this Block to be 1.0.

Block 2: Suspended Debris is Sufficient to Challenge the ESW-D/G System

The licensee evaluated this Block as the combined probability that flows coming into the

intake structure contained a sufficient amount of debris with the probability that changes

27

to the intake structure flow caused the entrainment of a sufficient amount of debris to

challenge the ESW-D/G system. Using a combination of plant data and industry

information, the licensee developed probabilities for each of several sub-blocks

identified necessary to construct the overall probability. The resultant Block single unit

and dual unit LOOP probabilities were 0.1033 and 0.0189, respectively.

The inspectors reviewed the sub-blocks used to construct the overall probability for

Block 2 and concurred with the licensees general characterization of the sub-blocks.

However, the inspectors did not agree with the licensees assumptions that: 1) debris

generation, as a result of wind and wave action, was independent of the severe weather

initiating event frequency; 2) debris, brought into the intake structure and of concern for

challenging the ESW-D/G system, would be very unlikely (P=0.05) to bypass the

traveling screens; 3) intake structure water vertical velocities, developed during an

inrush of water following a dual unit LOOP, would be unlikely (P=0.1) to entrain debris

resident between the traveling screens and the ESW pumps, and; 4) debris, present

between the traveling screens and the ESW pumps, would be unlikely (P=0.1) to be of

sufficient quantities to challenge the ESW-D/G system.

Since Items 1 and 2 above did not contribute significantly to the final probability for

Block 2, the inspectors did not further evaluate these items.

Of the remaining items, the inspectors determined that engineering judgement

accounted for differences in the probabilities assumed for Items 3 and 4. Specifically,

for Item 3, the inspectors assumed that the inrush of approximately 1.6 million

gallons/minute of water, expected to occur immediately after a dual unit LOOP event,

would provide sufficient energy and flow velocities to cause local eddies and vertical

water velocities sufficient to entrain debris located in the previous quiescent flow areas

of the intake structure (P=1.0). In their analysis, the licensee assumed that the intake

structure vertical water velocities would be limited to the bulk rate of rise of the intake

structure water level, a level which may not support entrainment of significant quantities

of debris. For Item 4, the inspectors assumed that debris was present in sufficient

quantities, between the traveling screens and the ESW pump intakes, to challenge the

ESW system approximately one half of the time each year (P=0.5). This value was

considered a conservative estimate based upon the licensees practice of cleaning 1/2 of

the intake structure during unit refueling outages, on an approximate once every

9 month time frame.

Block 3: Suspended Debris Reaches the ESW Pump Suction

The licensee assumed that, if sufficient debris was suspended in the intake structure

water, it was nearly certain that at least some of the debris would reach the Unit 1 East

ESW pump suction and be ingested. Therefore, the licensee assigned a probability of

0.99 to this block.

The inspectors used a similar approach to developing their common cause factor.

Therefore, the inspectors considered the probability for this Block to be 1.0.

Block 4: Failed Strainer Basket is in Service During a LOOP Event

28

The licensee evaluated this block as a combination of probabilities that the failed 1 East

ESW strainer was in service at the start of a LOOP event or was brought into service

during the LOOP event as a result of an automatic timer or due to sensed high

differential pressure across the undamaged duplex strainer. Results of the licensees

evaluation indicated a single unit LOOP probability of 1.0 and a dual unit LOOP

probability of 0.77.

The inspectors reviewed the sub-blocks used to construct the overall probability for

Block 4 and concurred with the licensees general characterization of the sub-blocks and

the resultant probabilities.

Blocks 5 and 6: ESW Flow is High and Ingested Debris Bypasses the 1 East ESW

Strainer

The licensees analysis proposed that all sequences, which could result in the D/Gs

being affected by ingested debris, include two steps which were dependent upon the

presence of high ESW flow rates. High ESW flow rates were characterized as a flow

rate greater than 5000 gallons/minute. The relative probability of having high ESW flow

rates was determined based upon ESW system heat loads throughout the year.

Assuming the presence of high ESW flow rates, the analysis concluded that debris

entering the ESW strainer housings would have a high likelihood of being able to reach

the 1 East ESW pump strainer defect and pass through into the ESW-D/G flow stream.

Without the presence of high ESW flow rates, ingested debris was assumed to be

retained in the strainer housing, probability of high flow and strainer bypass equal to

0.14.

Based upon the information provided in the evaluation, the inspectors could not

independently confirm the basis for the proposed high ESW flow rate steps.

Specifically, the inspectors could not validate the licensees technical basis for

concluding that ESW flow rates of greater than 5000 gallons/minute were necessary to

transport debris within the ESW strainer housing from the inlet point up to the strainer

defect location, a change in elevation of approximately 2 feet. In addition, the inspectors

noted that evaluation did not consider the presence of a second bypass path or the

consequences of a buildup of debris within the housing during post-LOOP periods with

low ESW flow rate. As a result, the inspectors concluded that debris which entered the

ESW pump suction was transported into the ESW-D/G flow stream, probability of

strainer bypass for all flow conditions equals 1.0.

Block 7: Ingested Debris Reaches the Unit 2 D/G Heat Exchangers

The licensees analysis proposed that debris which entered the ESW-D/G flow stream

had a certain probability of reaching the Unit 2 D/G heat exchangers based, in part, on

the system pre-LOOP ESW system alignment and ESW system demand. Because the

ESW-D/G system included both train and Unit cross ties, the 1 East ESW pump, with its

faulted strainer, had the potential to feed any and both ESW-D/G trains for both Units.

This was the situation during the August 2001 event. However, the licensees analysis

appropriately highlighted that during a LOOP condition, all four ESW pumps would be in

operation. This condition would change the post-LOOP ESW system flow dynamics and

result in a significantly decreased cross flow, and debris transport, through the Unit

29

cross tie. The licensees analysis also proposed that only one of the four normal ESW

system pre-LOOP alignments would result in sufficient Unit cross flow to carry debris

from Unit 1 to Unit 2.

The inspectors reviewed the licensees basis for the proposed probability and concurred

that the post-LOOP starting of all four ESW pumps would change the system flow

characteristics and the relative likelihood that debris, ingested through the 1 East ESW

pump, would reach the Unit 2 D/Gs. However, the inspectors did not concur with the

licensees conjecture that a minimum 2500 gallons/minute of Unit 1 to Unit 2 cross flow

was necessary to transport debris between the Units during a post-LOOP alignment.

Instead, the inspectors concluded that debris could be transported from Unit 1 to Unit 2,

at varying rates, even with very low cross flow rates, due to the relatively short, 15 foot,

cross tie connection distances. Lower post-LOOP debris transport rates between the

Units would provide the operators with another opportunity to recognize and correct or

halt ESW-D/G plugging of the Unit 2 D/Gs. As a result, the inspectors concluded that

the proposed step probability of 0.25 was appropriate.

30

Block 8: ESW Flow Degradation Impacts D/G Function

In this block, the licensee estimated the probability that debris, having reached the D/G

coolers, would impact the D/G function. Through a review of information gathered from

the August 2001 event, the licensee concluded that only 1 of the 4 D/Gs were actually

impacted by the debris intrusion. As a result, the licensee assumed a per D/G impact

probability of 0.25. In their development of the event trees for these sequences, the

licensee further treated this failure probability as an independent random variable. This

approach resulted in an overall failure probability for the 4 D/G system of approximately

0.004.

Based upon an independent review of operator and computer logs from the

August 2001 event, the inspectors determined that 3 D/Gs were impacted by the debris.

Specifically, the 1AB D/G experienced less than reliable flow indication conditions, and

the two Unit 2 D/Gs were trending to a less than reliable flow indication condition. The

1CD D/G experienced degraded flow which levelized at approximately

350 gallons/minute and was not considered substantially impacted by the debris

intrusion. Based, in part, on the observed August 2001 debris intrusion D/G impacts,

the inspectors concluded that the probability of a debris intrusion event impacting an

individual D/G was approximately 0.75. The inspectors assumed a probability that all

4 D/Gs would be impacted by a debris intrusion event to be approximately 0.25.

Block 9: Condition is Not Identified and Cleared by the Operators

In this block the licensee proposed to assign the HEP values previously developed and

evaluated by the inspectors as a part of the engineering evaluation. The

licensee-proposed HEP values were 0.054, for a single unit LOOP event, and 0.13, for a

dual unit LOOP event, respectively.

The inspectors reviewed and concurred with the methodology used to develop these

probabilities as discussed in Section 4OA3.4.b.1 of this report.

b.3 Essential Service Water Supported Safety Function Capability Assessment

Emergency Diesel Generators

The ESW system provided essential cooling for the D/G turbocharger air aftercoolers,

and the lubricating oil and jacket water coolers. Each D/G could be aligned to either the

East or West ESW supply header in the associated unit via normal and alternate ESW

supply valves. The associated safety train supplied normal ESW cooling while the

opposite safety train supplied alternate ESW cooling. The D/G ESW supply valve

control logic was designed to fully open both the normal and alternate ESW motor

operated supply valves in response to a diesel start signal.

Based upon independent review of operator and computer logs from the August 2001

event, post shutdown inspections of the ESW system heat exchangers, requirements

specified in the licensees UFSAR, and the licensees engineering and probabilistic

evaluation of the specific and generic impacts of the August 2001 event, the inspectors

determined that one of the two Unit 1 D/Gs experienced a less than reliable ESW-D/G

31

flow condition and may not have been able to perform its intended function, had it been

called upon. The second Unit 1 D/G also experienced degraded ESW-D/G flow,

however; the degraded ESW-D/G flow had stabilized and was sufficient to support D/G

operations during a post-LOOP environment. The two Unit 2 D/Gs also experienced

degraded ESW-D/G flow conditions as a result of the debris intrusion and were trending

to a less than reliable flow indication condition when the operators identified the

degrading condition. At the time the operators identified the degraded ESW-D/G to the

Unit 2 D/Gs, the ESW-D/G flow rates were still sufficient to support D/G operations

during a post-LOOP environment. However, the observed negative trend in the

ESW-D/G flow rates may have resulted in the D/Gs being unable to continue to function

in a very short time.

Considering the damaged condition of the 1 East ESW strainer basket, the less than

reliable ESW-D/G flow condition for one of the D/Gs, degraded flow for two of the

remaining D/Gs, and a review of engineering and probabilistic evaluations developed by

the licensee, the inspectors concluded that, absent operator intervention, a similar

debris intrusion event could cause ESW flow degradation to the heat exchangers for all

four D/Gs and result in the D/Gs being unable to perform their assumed safety function

in a post-LOOP environment. The loss of the emergency alternating current (AC) power

safety function had a credible impact on safety and therefore was of more than minor

concern. Because the D/Gs supported the operation of accident mitigation equipment,

the inspectors determined that this issue was associated with the Reactor Safety-

Mitigating Systems cornerstone. During a Phase 1 Significance Determination Process

(SDP) screening of issue, the inspectors concluded that the issue represented a

credible actual loss of safety function and therefore required a Phase 2 SDP Review.

During the Phase 2 SDP review, the licensee provided the engineering and probabilistic

evaluations of the specific and generic impacts of an ESW-D/G debris intrusion event.

In order to properly incorporate the additional licensee-provided information, a Phase 3

SDP assessment was performed.

Risk Assessment Considerations

The inspectors and NRC Headquarters staff evaluated the risk significance of the

inspection finding (failed ESW strainer which allowed a significant amount of debris to

enter and form flow blockages in the ESW-D/G system) in terms of internal events using

the NRC SPAR model. Consistent with the guidance for the SDP, the change in core

damage frequency (CDF), stemming from the identified failed ESW strainer was

assessed. The assessment focused on LOOP events which could: 1) cause debris,

present in the intake structure, to be entrained and ingested into the ESW system, and;

2) result in the Units to rely upon the D/Gs for onsite AC power. The assessment

assumed:

An initiating event frequency of 0.01 for a single unit LOOP and 0.007 for a dual

unit LOOP.

An exposure time of 1 year, the maximum timeframe used for these time

calculations, based upon evidence which indicated that the ESW strainer failure

had likely occurred during initial installation in 1989.

32

Cross flows within the intake structure, following a single unit LOOP event, would

entrain sufficient debris in the ESW-D/G flow stream to cause less than reliable

ESW-D/G flow through the D/G heat exchangers within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Inrush flows into the intake structure, following a dual unit LOOP event, would

entrain sufficient debris in the ESW-D/G flow stream to cause less than reliable

ESW-D/G flow through the D/G heat exchangers within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Debris entrained within the intake structure would resettle to the intake structure

floor within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after the flow perturbation or change had subsided.

Frequency-weighted non-recovery curves associated with plant-centered, grid,

severe weather, and extreme weather events for a single unit LOOP; and,

frequency-weighted non-recovery curves associated with severe and extreme

weather events for a dual unit LOOP.

Operator recovery from less than reliable ESW-D/G heat exchanger flow

conditions were characterized by human error probabilities of 0.054 for a single

unit LOOP and 0.13 for a dual unit LOOP.

The electrical distribution system does not include capability to electrically

cross-tie between the Unit 1 and Unit 2 safety related busses.

The motor driven auxiliary feedwater systems could be cross tied between Units

for a single unit LOOP.

A common cause failure factor was used to account for probabilities that:

1) insufficient debris would be available within the intake structure; 2) the failed

1 East ESW strainer may not be in service during the LOOP event; 3) pre-LOOP

system alignments may delay or reduce the debris transported from Unit 1 to

Unit 2, and; 4) all debris intrusion events may not result in all of the D/Gs

experiencing less than reliable ESW-D/G flow conditions. A value of 0.14 was

used for the single unit LOOP and 0.024 for the dual unit LOOP common cause

failure factor.

Mitigating equipment was assumed to be available once offsite power was

recovered. Potential unavailabilities of these components, due to degraded

ESW cooling flow, was not considered.

The conditional probability of a large early release, given a core damage event

for an ice condenser containment, was assumed to be 0.4.

Using the NRCs SPAR model and the assumptions stated above, the inspectors and

NRC Headquarters staff determined that the per plant delta CDF value was dominated

by a dual unit LOOP event. The calculated dual unit LOOP delta CDF value was

determined to be 1.8E-05 per year (Yellow). For both the single and dual unit LOOP

events, the dominant sequence was a station blackout with a failure to recover AC

power before station battery depletion.

33

The inspectors and NRC Headquarters staff also evaluated the impact of this issue on

the LERF. Using a conditional probability of a large early release, given a core damage

event for an ice condenser containment, of 0.4, the staff determined the delta LERF for

the issue was 7.1E-06 (Yellow) for a dual unit LOOP.

The Regional Senior Risk Analyst and the NRC Headquarters staff concluded that the

risk significance of the inspection finding, based on the change in CDF due to internal

events and LERF considerations, to be Yellow. A Yellow finding represents a finding of

substantial safety significance.

b.4 Other ESW Support Systems

Component Cooling Water System

The CCW system provided cooling to heat exchangers in the following risk-significant

systems: residual heat removal, ECCS, spent fuel pool cooling, reactor coolant pump

thermal barrier, and containment air recirculating. Each Unit's CCW system was

arranged in three flow circuits: two parallel safeguards equipment trains, and one

miscellaneous services train which can be served by either safeguards train.

During the August 2001 debris intrusion event, ESW flow to the Unit 1 East and Unit 2

West CCW heat exchangers became degraded. Essential Service Water system flow

to the Unit 1 East CCW heat exchanger was as low as 2100 gpm but increased to

3900 gpm following cycling of the inlet and outlet ESW valves. The Unit 2 West CCW

heat exchanger ESW flow decreased to approximately 2400 gpm but improved to

approximately 5000 gpm following cycling of the ESW inlet and outlet valve. Section 9.8

of the UFSAR stated that the minimum ESW flow required to support post-accident

CCW heat loads was 5000 gpm, but up to 8700 gpm of ESW flow was required to

support normal operation and cooldown. Additionally, Section 9.5.2 of the UFSAR

stated that the CCW system was designed and analyzed to operate at CCW heat

exchanger outlet temperatures up to 120°F during cooldown and accident conditions.

Although debris intrusion reduced the maximum ESW flow capability for the Unit 1 East

and Unit 2 West CCW heat exchangers below design requirements, the inspectors

determined that the CCW heat exchanger outlet temperatures did not exceed the 120°F

analysis limit during the event.

Because Unit 1 was in Mode 5 at the time of the event, its CCW system supported

decay heat removal system operation, but it was not required to support post-accident

heat loads. Additionally, the debris intrusion event did not degrade flow to the Unit 1

West CCW train and reactor coolant system temperatures remained stable during the

event. Based on the availability of the opposite train and the stable reactor coolant

system operation during and immediately following the event, the inspectors determined

that the safety impact of degraded ESW flow to the Unit 1 East CCW heat exchanger

was minimal.

Because Unit 2 was in Mode 1 at the time of the degraded flow event, the licensee

entered TS 3.7.3.1 and placed the Unit in Mode 5 within the required TS limiting

condition for operation time limits. During the event, the Unit 2 East CCW train

remained available to provide cooling for normal operation and accident heat loads.

34

Based on the availability of the opposite CCW train and licensee compliance with

TS 3.7.3.1 for one inoperable CCW train, the inspectors determined that the safety

impact of degraded flow to the Unit 2 West CCW heat exchanger was minimal.

Auxiliary Feedwater Pump Room Cooling and Emergency Water Supply

The ESW system provided the safety-related water source to each AFW pump and

support cooling to the AFW pump room coolers. Following the debris intrusion event,

the licensee identified degraded performance of the Unit 1 East MDAFWP room cooler

and the Unit 2 West TDAFWP room cooler. At the time of the event, Unit 1 was

operating in Modes 4 and 5 and did not require the AFW system to support decay heat

removal. The inspectors evaluated the safety impact of degraded ESW flow on the

capability to provide secondary plant makeup to Unit 2. The inspectors considered the

following factors:

The condensate storage tank provided the normal suction supply to the AFW

pumps and remained available during the event. Consequently, the inspectors

determined that the loss of the emergency AFW pump suction water supply from

the ESW system did not significantly impact the ability of the AFW system to

perform its safety function.

The TDAFWP room is cooled by two 100 percent capacity coolers. Because the

Unit 2 East TDAFWP room cooler had adequate cooling capacity to maintain

TDAFWP room temperatures, the loss of the Unit 2 West TDAFWP room cooler

did not adversely impact the ability of the TDAFWP to perform its safety function.

The Unit 1 West and both Unit 2 MDAFWPs room coolers remained operable

during and immediately following the event. Consequently, the inspectors

determined that because of the availability of redundant trains of MDAFWPs

sufficient AFW system capability was available to support Unit 2 during this

event.

The annunciator response procedures for high MDAFWP room temperature

included proceduralized compensatory actions for degraded room cooling.

Based on these factors, the inspectors concluded that the impact of the ESW debris

intrusion on the AFW system was minimal.

Control Room Air Conditioning System (CRAC)

The CRAC units provided cooling to maintain temperatures at which control room

equipment was qualified for the life of the plant. As stated in the bases for TS 3.7.5.1,

"Control Room Emergency Ventilation System," at control room temperatures less than

or equal to 102°F, vital control room equipment remained within the manufacturers

recommended operating range. The inspectors reviewed control room logs and

determined that control room temperatures did not exceed 80°F during and immediately

following the degraded ESW event. Based on the ability of the CRAC units to

adequately maintain control room temperatures, the inspectors determined that the

impact of this event on the control room ventilation system was minimal.

35

Containment Spray System

The primary purpose of the Containment Spray System is to spray cool water into the

containment atmosphere in the event of a loss-of-coolant to prevent containment

pressure from exceeding the design value. With the exception of alignment of the Unit 2

East CTS heat exchanger for ESW flushing on August 30, 2001, the ESW supplies to

the CTS heat exchangers were isolated during the event. Subsequent inspections and

engineering evaluations of the CTS system identified no significant fouling or

obstructions of flow. The inspectors concluded that the debris intrusion event had

minimal safety impact on the CTS system.

.5 Adequacy of Corrective Actions

a. Inspection Scope

The inspectors attended licensee meetings, interviewed personnel, observed

maintenance activities, reviewed testing plans, and performed system walkdowns as

part of the assessment of the adequacy of the licensees corrective actions for the

restoration of:

Emergency Diesel Generators

Component Cooling Water System

Other safety-related components served by ESW

b. Findings

The licensee established a series of recovery and support teams in order to identify

equipment, procedural and personnel performance issues that needed to be addressed

before the equipment could be restored to full service. The inspectors determined that

the licensees corrective actions were prompt, thorough, and effective.

Emergency Diesel Generators

The licensee inspected the cooling systems of all D/Gs immediately following the event.

For each D/G, the licensee inspected and cleaned (as necessary) both air after-coolers,

the lube oil cooler, the jacket water cooler, and supply piping.

In addition to cooling system inspection and cleaning, the licensee installed ESW

differential pressure instrumentation on each lube oil cooler to assist in the future

identification of cooling system blockage. The licensee also removed the automatic

opening control logic for the alternate D/G cooling ESW supply valves to preclude cross

train transport of debris into the D/G cooling systems.

Component Cooling Water System

The licensee removed the end bells of the Unit 1 East CCW heat exchanger and

performed inspections. The licensee identified sand, zebra mussel shells, and large

debris. The licensee considered large debris as debris that was greater than 1/8 inch.

The debris blocked approximately 10 percent of the tubes. The licensee removed the

36

debris and hydro-lanced the heat exchanger tubes. The ESW supply and return piping

for the CCW heat exchanger was cleaned as part of the overall system flush.

Other Safety-Related Components Served by ESW

The licensee initiated a recovery team to specifically address the scope of corrective

action necessary to restore the ESW system to service. The team evaluated other

components served by ESW and recommended corrective actions. These corrective

actions included:

Inspecting and cleaning the CRAC units as necessary. The air conditioners

were determined to be very clean with only minimal material.

Inspecting and cleaning the AFW pump room coolers. The Unit 1 East

MDAFWP room cooler and one of the two room coolers to the Unit 2 TDAFWP

were identified to have significant blockage. These coolers were cleaned and

returned to service.

The Unit 1 East ESW pump discharge strainer was opened and inspected. The

east strainer basket was determined to have significant damage and bypass.

The west strainer basket was determined to have some smaller amount of

bypass over the top of the basket. Both baskets were replaced.

Two radiation monitors which drew sample flow from the ESW trains were

cleaned.

Instrumentation connected to the Unit 1 East ESW system was inspected and

flushed.

Portions of ESW piping that could not be inspected internally or were not

assured of achieving high flow rates during flushing activities were

Ultra-Sonically tested. The tests indicated that portions of the piping did contain

debris. For example, one 12 inch diameter pipe contained approximately

2 inches of debris. The licensee flushed the material from the system.

The licensee performed an ESW system flow verification surveillance test in

order to ensure that all components served by the ESW system had been

restored to operable.

.6 Adequacy of Overall Corrective Actions to Address Recurrence of Sand/Silt Buildup

Problems

a. Inspection Scope

The inspectors attended licensee meetings, interviewed personnel, observed

maintenance activities, reviewed testing plans, and performed system walkdowns as

part of the assessment of the adequacy of the licensees overall corrective actions.

b. Findings

37

The inspectors reviewed the licensees corrective actions which included the following:

all 8 ESW strainer baskets were inspected and replaced;

detailed procedural guidance was given for strainer installation;

a temporary modification to prevent the alternate ESW supply valves to the D/Gs

from going open on a D/G start was installed;

the normal configuration of the alternate ESW supply valves to the D/Gs was

revised; and

the new ESW strainer baskets received additional inspection to provide

reasonable assurance of the new strainer baskets structural capability.

The inspectors concluded that the licensees actions appeared reasonable to prevent

recurrence.

.7 Assessment of Interaction of the Maintenance Activities on the Non-Safety Related

Circulating Water System with Operation of the ESW System

a. Inspection Scope

At the time of the event, the CW center intake crib was isolated in order to repair

previously identified damage. The CW pump 13 discharge valve, 1-WMO-13, was

degraded and could not be fully closed. The plant had been operating for several

months with the center intake isolated. The inspectors assessed the interaction and

potential impact of these non-safety related issues on the functioning of the ESW

system.

38

b. Findings

The inspectors determined that CW system flow rates and configuration had a direct

impact upon the functioning of the safety-related ESW system. However, if the Unit 1

East ESW pump discharge strainer east basket had been performing as designed, large

debris would not have entered the ESW system and the operability of components

served by ESW would not have been challenged.

4OA4 Cross-Cutting Issues

.1 Human Performance Issues During Degraded ESW Flow Event

a. Inspection Scope

The inspectors assessed operator performance during the degraded ESW flow event

relative to the human performance cross-cutting issue. The inspectors reviewed control

room logs, plant process computer data, and control room chart recorder data. In

addition, the inspectors interviewed operators and reviewed operator statements.

b. Findings

The inspectors identified several weaknesses in the response of control room operators

to the degraded ESW flow event of August 29, 2001. These weaknesses involved

operator control board monitoring and procedural adherence. Specifically, the

inspectors identified the following issues:

Upon identifying that both Unit D/Gs were inoperable due to low ESW flow, the

Unit 2 Senior Reactor Operator entered the action statement for TS 3.0.3. As

described in the TS bases, TS 3.0.3 delineated the measures to be taken for

those circumstances not directly provided for in the TS action statements. The

inspectors determined that, because TS 3.8.1.1.e addressed two inoperable

D/Gs, TS 3.0.3 was not the appropriate TS action statement to enter during this

event. The Unit Supervisor stated that he assumed that TS 3.0.3 would apply

with two inoperable D/Gs, and he did not read each TS 3.8.1.1 action statement.

The inspectors noted that TS 3.8.1.1.e specified additional actions not covered

by TS 3.0.3, such as demonstrating the operability of offsite power sources. In

this case, the licensee complied with the action time limits specified in

TS 3.8.1.1.e; thus, there was no impact from the failure to enter the appropriate

TS action statement.

Based on a review of Plant Process Computer data and control room chart

recorder data, the inspectors concluded that indications of degraded ESW

system performance (i.e., ESW flow below UFSAR minimum) were available to

the control room operators at least 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months prior to the initial identification of

degraded ESW flow to the D/Gs and CCW heat exchangers. Operations head

instruction OHI-4017, "Control Board Monitoring," Step 4.2.8, required, in part

that control boards shall be monitored for changing indications, adverse trends,

and abnormal indications and Step 4.2.4 stated that during normal plant

operations, the reactor operator should perform a walkdown of all control room

39

panels every 60 minutes. The inspectors determined that the control room

operators failure to effectively implement the recommendations contained in

OHI-4017 contributed to the failure to promptly identify degraded ESW system

performance.

Based on a review of CCW system temperatures recorded on chart recorder

1-SG-10, the inspectors determined that the Unit 1 East CCW heat exchanger

outlet temperature exceeded the 95°F abnormal temperature alarm setpoint for

over 3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months . Annunciator response procedure 01-OHP 4024.104, Drop 85,

"East CCW Hx Discharge Temp Abnormal," Step 3.3, stated that if the CCW

heat exchanger outlet temperature cannot be maintained less than 95°F, enter

Abnormal Procedure 01-OHP 4022.016.001, "Malfunction of the CCW System."

Although the reactor operator reported receipt of the associated abnormal

temperature alarm, the control room operators did not enter Abnormal Procedure

01-OHP 4022.016.001, contrary to instructions contained in 01-OHP 4024.104.

Although the Unit 1 East CCW outlet abnormal temperature alarm actuated

during the event, receipt of the alarm and the operators subsequent difficulty in

controlling CCW temperature were not recorded in the control room log and not

effectively communicated to the operations shift management. The inspectors

determined that the operators failure to log receipt of the CCW abnormal

temperature alarm and effectively communicate this abnormal condition was not

consistent with instructions contained in OHI-2212 and OHI-4017. Specifically,

OHI-2212, Step 4.5.7 required, in part, that the actuation of significant

annunciators and unexpected system transients shall be contained in the control

room log and OHI-4017, Step 4.2.11, required, in part, that the US shall be

notified immediately of any indication that is not responding as expected.

The inspectors determined that the failure to adequately apply TS requirements and

implement procedures associated with control board monitoring, logkeeping, and

annunciator response had a credible impact on safety and therefore were more than a

minor concern. Specifically, these issues could reasonably result in the failure to identify

and promptly correct degradation of safety related equipment and therefore impact the

reliability and availability of a safety system. Because these performance deficiencies

contributed to delays in identifying degradation of the ESW and CCW mitigating

systems, the inspectors determined that these human performance weaknesses were

associated with the mitigating systems cornerstone. Although this issue adversely

impacted the licensee's response to the August 29, 2001 event, none of the

performance deficiencies directly resulted in the actual loss of safety system function or

the loss of a single safety system train for greater than its TS allowed outage time.

Consequently, the inspectors concluded that this issue was of very low safety

significance (Green).

Technical Specification 6.8.1 required, in part, that written procedures shall be

implemented for those activities recommended in Appendix "A" of RG 1.33, Revision 2.

Regulatory Guide 1.33, "Quality Assurance Program Requirements," Revision 2,

Appendix "A," recommended, in part, that written procedures cover the following

activities: (1) authorities and responsibilities for safe operation, (2) log entries, and

(3) abnormal, off normal or alarm conditions. The inspectors determined that

40

OHI-2212, "Narrative and Miscellaneous Logkeeping"; OHI-4017, "Control Board

Monitoring"; and 01-OHP 4024.104, "Annunciator #104 Response: Essential Service

Water and Component Cooling"; were written to implement the requirements of

TS 6.8.1. Contrary to TS 6.8.1, the control room operators failed to implement the

instructions contained in (1) OHI-2212, step 4.5.7, (2) OHI-4017, steps 4.2.8 and 4.2.11,

and (3) 01-OHP.4024.104, drop 85, step 3.3, during the degraded ESW event of

August 29, 2001. Specifically, the operators failed to (1) monitor the control boards for

changing indications, adverse trends, and abnormal indications, (2) effectively

communicate receipt of an abnormal temperature alarm for the CCW heat exchanger,

and (3) enter the CCW abnormal operating procedure as directed by the abnormal

temperature alarm response procedure. Because of the very low safety significance,

this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the

NRC Enforcement Policy (NCV 50-315-01-17-02(DRP); 50-316-01-017-02(DRP)). This

violation is in the licensees corrective action program as CR 01250062.

4OA6 Meeting

Exit Meeting

The inspector presented the inspection results to licensee management listed below on

May 17, 2002. The licensee acknowledged the findings presented. No proprietary

information was identified.

41

KEY POINTS OF CONTACT

Licensee

G. Arent, Manager, Regulatory Affairs

C. Bakken, Senior Vice President, Nuclear Generation

G. Bourlodan, Plant Programs Manager

R. Gaston, Regulatory Affairs Compliance Supervisor

J. Gebbie, System Engineering Manager

J. Giessner, Assistant Manager, Operations

S. Greenlee, Director, Nuclear Technical Services

N. Jackiw, Regulatory Affairs

C. Lane, Inservice Inspection Supervisor

E. Larson, Manager, Operations

R. Meister, Regulatory Affairs

J. Molden, Reliability Programs

D. Moul, Assistant Manager, Operations

T. Noonan, Director, Performance Assurance

J. Pollock, Site Vice President and Acting Plant Manager

R. Smith, Assistant Director, Plant Engineering

L. Weber, Performance Assurance

D. Wood, RadChem Environmental Manager

T. Woods, Regulatory Affairs

NRC

Geoffrey Grant, Director, Division of Reactor Projects

Steven Reynolds, Deputy Director Division of Reactor Projects

Anton Vegel, Branch Chief Reactor Projects Branch 6

Sonia Burgess, Senior Reactor Analyst, Division of Reactor Safety

42

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

50-315/01-17-01 AV Essential Service Water strainer maintenance instructions not

50-316/01-17-01 appropriate to the circumstances.

50-315/01-17-02 NCV Human performance weaknesses during the degraded essential

50-316/01-17-02 service water event of August 29, 2001 associated with control

board monitoring and procedural adherence.

Closed

50-315/01-17-02 NCV Human performance weaknesses during the degraded essential

50-316/01-17-02 service water event of August 29, 2001 associated with control

board monitoring and procedural adherence.

Discussed

None

43

LIST OF ACRONYMS USED

AEP American Electric Power

AFW Auxiliary Feedwater System

ATR Administrative Technical Requirement

CCW Component Cooling Water

CDF Core Damage Frequency

CFR Code of Federal Regulations

CR Condition Report

CRAC Control Room Air Conditioning

CTS Containment Spray System

CW Circulating Water

D/G Emergency Diesel Generator

DRP Division of Reactor Projects

EAL Emergency Action Level

ECC Emergency Condition Categories

EOP Emergency Operating Procedure

EP Emergency Preparedness

ESW Essential Service Water

FIN Finding

JO Job Order

HELB High Energy Line Break

IC Initiating Condition

IMC Inspection Manual Chapter

LOOP Loss of Off-Site Power

MDAFWP Motor Driven Auxiliary Feedwater Pump

MHP Maintenance Head Procedure

NRC Nuclear Regulatory Commission

NRR Nuclear Reactor Regulation

OA Other Activities

OHI Operations Head Instruction

OHP Operations Head Procedure

PDR Public Document Room

PMI Plant Managers Instruction

PMP Plant Managers Procedure

PMT Post-maintenance Testing

PPC Plant Process Computer

PRA Probability Risk Assessment

RCS Reactor Coolant System

RHR Residual Heat Removal

SDP Significance Determination Process

SEC Site Emergency Coordinator

SRA Senior Reactor Analysts

SRO Senior Reactor Operator

SSC Structures, Systems, and Components

STP Surveillance Test Procedure

TBD To Be Determined

TDAFWP Turbine Driven Auxiliary Feedwater Pump

44

TS Technical Specification

UFSAR Updated Final Safety Analysis Report

UHS Ultimate Heat Sink

URI Unresolved Item

US Unit Supervisor

VIO Violation

45

LIST OF DOCUMENTS REVIEWED

Work Requests/Job Orders

JO 01095031 Unit 2 Traveling Water Screen Driving Inspection

JO 01242065 Inspect and Clean Unit 1 ESW and Circulating

Water Pump Bays

JO 01244049 Open and clean 1-HV-ACR-1 (North CRAC)

JO 01244055 Drain and flush 1-HV-AFP-EAC, Unit 1 East

MDAFWP room cooler

JO 01244059 Inspect, clean, and flush 1-HV-AFP-T1AC, the

Unit 1 east TDAFWP room cooler

JO 01244069 Inspect/clean ESW side of heat exchanger

1-QT-110-AB

JO 01244071 Inspect/clean ESW side of heat exchanger

1-QT-110-CD

JO 01244072 Inspect/clean ESW side of heat exchanger

1-QT-131-AB

JO 01244073 Inspect/clean ESW side of heat exchanger

1-QT-131-CD

JO 01244089 Open/inspect/flush 2-HV-ACR-1 (North CRAC)

JO 01244092 2-HV-AFP-WAC Drain and Flush West Cooler

JO 01244094 2-HV-AFP-T2AC Drain and Flush T2AC Cooler

JO 01244097 Inspect/clean ESW side of heat exchanger

2-QT-110-CD

JO 01244099 Inspect/clean ESW side of heat exchanger

2-QT-131-CD

JO 01244096 Inspect/clean ESW side of heat exchanger

2-QT-110-AB

JO 01244098 Inspect/clean ESW side of heat exchanger

2-QT-131-AB

JO R0088138 Unit 1 Screenhouse Diving, Cleaning and Repairs

JO R0100035 2-HE-18W Open Shell Side of Heat Exchanger

for Inspection

46

JO R0210330 Open shell side of 1-HE-18E for inspection

(Unit 1 East CTS heat exchanger)

JO R021036 Unit 1 Screenhouse Diving, Cleaning and Repairs

JO R0217652 Inspect and clean 1-HE-15E (Unit 1 East CCW

heat exchanger)

JO R0096582 Inspect and clean 1-HE-15W (Unit 1 West CCW

heat exchanger)

Condition Reports (CRs)

CR 00273076 Silts/sand from the lake settling out in the dead September 28, 2000

leg section of ESW piping

CR 00295037 1-PP-7W-MTR Failed To Start October 21, 2000

CR 01019031 SA-2001-REA-003, Perform Zebra Mussel January 19, 2001

Assessment During Year 2001

CR 01242007 2-ESW-162-CD Emergency Diesel Jacket Water August 30, 2001

Cooler QT-131-CD tube side vent valve is

blocked and could not be flushed out

CR 01242008 Procedural Deficiency in 02 OHP August 30, 2001

4030.STP.022E, the ESW system test - Step

4.30.3, which aligns the north CRAC for flushing

is missing from the procedure

CR 01242009 2-ESW-163-CD, the Unit 2 CD D/G jacket water August 30, 2001

cooler tube side drain, is clogged and not allowing

flow to pass when opened

CR 01242010 2-ESW-162-AB Emergency Diesel Jacket Water August 30, 2001

Cooler QT-131-AB tube side vent valve is blocked

and could not be flushed out

CR 01242013 Slit/mud intrusion into Unit 1 and 2 ESW systems August 29, 2001

renders CCW and D/G inoperable

CR 01243013 2-HV-AFP-T2AC, the Unit 2 West TDAFWP room August 31, 2001

cooler, does not appear to be functioning

CR 01243015 Unit 1 East auxiliary feedwater pump room cooler August 31, 2001

flow (56 gpm) was less then minimum required

(57 gpm)

47

CR 01243036 Both Unit 1 and Unit 2 D/Gs declared inoperable August 29, 2001

due to low ESW flow. This resulted in Unit 1

entering a RED shutdown risk path.

CR 01243038 Evaluate August 30, 2001, greater than 20 August 30, 2001

percent power reduction on Unit 2 due to

degraded ESW flow for potential Maintenance

Rule impact

CR 01243039 PRA analysis of Unit 2 indicates yellow risk status August 30, 2001

in that the west CCW heat exchanger is not

receiving the required 5000 gpm ESW flow

CR 01244010 1-WMO-12 circulating water pump PP-2-2 September 1, 2001

discharge shutoff valve

CR 01244011 1-WMO-11 Circulating Water Pump PP-2-1 August 31, 2001

Discharge Shutoff Valve

CR 01244016 Wood, mussel shells, and debris larger than September 1, 2001

expected identified during inspection on the Unit 1

east CCW heat exchanger

CR 01244019 Degraded ESW flow documented in CR September 1, 2001

01242013 may indicate that the GL 89-13

program is inadequate

CR 01245030 During inspection of Unit 1 East ESW pump September 2, 2001

discharge strainer baskets, large bypass flow

paths were identified.

CR 01246015 Forced outage schedule does not match actual September 3, 2001

work planning and execution for Unit 1 West

ESW pump work

CR 01247001 Declaration of unusual event during the Unit 1 September 3, 2001

and Unit 2 ESW restriction event on August 29,

2001 would have been prudent

CR 01247041 Open, inspect and clean 1-HV-AFP-WAC (Unit 1 September 4, 2001

west MDAFWP room cooler) to determine extent

of ESW debris intrusion

CR 01247050 NRC identified several human performance September 4, 2001

weaknesses during the ESW fouling event of

August 29, 2001. These included weaknesses in

communication, possible training deficiencies for

abnormal procedures, inconsistent log keeping

and control board monitoring

48

CR 01247054 Due to potential debris buildup within ESW September 4, 2001

system, it is necessary to flush ESW piping

CR 01247055 AFW room coolers have been found to be September 4, 2001

blocked with debris (zebra mussel shells)

CR 01248001 Potential of debris build-up within the ESW September 4, 2001

system upstream of the D/G aircooler 3-way

valves

CR 01248002 Flush piping upstream of D/G aftercooler 3-way September 4, 2001

valves WRV-727 and WRV-725

CR 01250062 NRC identified several operational issues September 7, 2001

associated with the August 29, 2001 degraded

ESW flow event, including: command and

control, control board monitoring, log keeping,

use of technical specifications, conservative

decision making, event reconstruction,

emergency plan implementation, and procedural

usage

CR 01251003 Performance Assurance identified that operators September 7, 2001

failed to establish mode constraint for operability

issues identified during the extent of condition

investigation for the ESW flow degradation event

of August 29, 2001

CR 01251022 The downstream pipe of the Unit 1 East CTS heat September 8, 2001

exchanger shell side vent is blocked

CR 01251029 In-Service testing on the Unit 1 East ESW pump September 8, 2001

indicated rapid degradation

CR 01253005 Quarantine was lost on the Unit 1 East ESW September 9, 2001

strainer east basket. The basket had been

placed in the scrap metal trash bin and taken to

the scrap yard

CR 01260022 1-QT-131-CD diesel generator jacket water heat September 17, 2001

exchanger open, cleaned, and closed with 2

tubes blocked with debris

CR 01268045 Dedication Plan HP-1015 is inconsistent with the September 25, 2001

requirement of 12 EHP-5043-CGD-001

P-00-05677 Essential Service Water Radiation Monitors

(WRA-3500, WRA-3600, WRA-4500 and WRA-

4600) ESW Lines Are Plugged With Sand And

Silt

49

ML021610713

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