ML021610713: Difference between revisions

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American Electric Power Company
American Electric Power Company
500 Circle Drive
500 Circle Drive
Buchanan MI 49107
Buchanan MI 49107
SUBJECT:       D. C. COOK NUCLEAR POWER PLANT, UNITS 1 AND 2
SUBJECT:
                NRC SPECIAL INSPECTION REPORT 50-315/01-17(DRP);
D. C. COOK NUCLEAR POWER PLANT, UNITS 1 AND 2
                50-316/01-17(DRP); PRELIMINARY YELLOW FINDING
NRC SPECIAL INSPECTION REPORT 50-315/01-17(DRP);
50-316/01-17(DRP); PRELIMINARY YELLOW FINDING
Dear Mr. Bakken:
Dear Mr. Bakken:
On May 17, 2002, the NRC completed a Special Inspection at your D.C. Cook Nuclear Power
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.
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
The Special Inspection was conducted in accordance with the guidance of NRC Management
Directive 8.3, NRC Incident Investigation Program, Inspection Procedure 71153, Event
Directive 8.3, NRC Incident Investigation Program, Inspection Procedure 71153, Event
Followup, and Inspection Procedure 93812, Special Inspection. The enclosed report
Followup, and Inspection Procedure 93812, Special Inspection. The enclosed report
documents the inspection findings which were discussed on May 17, 2002, with you and
documents the inspection findings which were discussed on May 17, 2002, with you and
members of your staff.
members of your staff.
On August 29, 2001, Unit 1 was in cold shutdown and Unit 2 was operating at power when your
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
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
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
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
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
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
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
heat exchangers dependent upon ESW. Because most components supplied by ESW were in
standby, this fouling continued undetected for approximately 10 hours. Operators then
standby, this fouling continued undetected for approximately 10 hours. Operators then
identified the problem during a scheduled, routine, quarterly surveillance of the ESW system in
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
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
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
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
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
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.
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
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
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
heat exchangers and revised your operating procedures to prevent cross-connecting ESW
system trains before restarting the units.
system trains before restarting the units.


A. Bakken                                         -2-
A. Bakken
-2-
The Special Inspection began immediately after the event on August 30, 2001, and examined
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
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
regulations and the conditions of your license. The inspectors reviewed selected procedures
and records, observed activities, interviewed personnel, and conducted extensive onsite
and records, observed activities, interviewed personnel, and conducted extensive onsite
reviews of the ESW and diesel generators systems in the weeks immediately following the
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
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
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
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
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
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
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
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
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.
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;
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
however, some of the assumptions you provided could not be supported or confirmed and were
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This finding was assessed using the NRC Phase 3 Significance Determination Process and
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
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
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
detail in the inspection report, our determination considered the August 29, 2001, event
information, the engineering and probabilistic analyses you developed, generic risk information,
information, the engineering and probabilistic analyses you developed, generic risk information,
and engineering analyses performed by the inspectors. The accident sequence of most
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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
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.
frequency as a result of the damaged strainer were both determined to be Yellow.


A. Bakken                                         -3-
A. Bakken
-3-
This finding is also an apparent violation of NRC requirements and is being considered for
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
escalated enforcement action in accordance with the "General Statement of Policy and
Procedure for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600. The current
Procedure for NRC Enforcement Actions" (Enforcement Policy), NUREG-1600. The current
Enforcement Policy is included on the NRCs website at http://www.nrc.gov.
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
We believe that sufficient information was considered to make a preliminary significance
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an opportunity to present to the NRC your perspectives on the facts and assumptions used by
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
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
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
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
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
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
decide to submit only a written response, such submittal should be sent to the NRC within 30
days of the receipt of this letter.
days of the receipt of this letter.
Please contact David G. Passehl at 630-829-9872 within 10 business days of your receipt of
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
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
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.
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
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
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
and characterization of apparent violations described in the enclosed inspection report may
change as a result of further NRC review.
change as a result of further NRC review.  
An additional human performance finding involving several examples of control room operator
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
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
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
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
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
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
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,
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
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
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
Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the D.C. Cook
facility.
facility.


A. Bakken                                       -4-
A. Bakken
-4-
In accordance with 10 CFR 2.790 of the NRCs Rules of Practice, a copy of this letter
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
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 Room or from the Publicly Available Records (PARS) component of NRCs
document system (ADAMS). ADAMS is accessible from the NRC Web site at
document system (ADAMS). ADAMS is accessible from the NRC Web site at  
http://www.nrc.gov/reading-rm/adams.html.
http://www.nrc.gov/reading-rm/adams.html.
                                              Sincerely,
Sincerely,
                                              /RA by James Caldwell Acting for/
/RA by James Caldwell Acting for/
                                              J. E. Dyer
J. E. Dyer
                                              Regional Administrator
Regional Administrator
Docket Nos. 50-315; 50-316
Docket Nos. 50-315; 50-316
License Nos. DPR-58; DPR-74
License Nos. DPR-58; DPR-74
Enclosure:     Inspection Report 50-315/01-17(DRP);
Enclosure:
              50-316/01-17(DRP)
Inspection Report 50-315/01-17(DRP);
cc w/encl:     J. Pollock, Site Vice President
50-316/01-17(DRP)
              M. Finissi, Plant Manager
cc w/encl:
              R. Whale, Michigan Public Service Commission
J. Pollock, Site Vice President
              Michigan Department of Environmental Quality
M. Finissi, Plant Manager
              Emergency Management Division
R. Whale, Michigan Public Service Commission
                MI Department of State Police
Michigan Department of Environmental Quality
              D. Lochbaum, Union of Concerned Scientists
Emergency Management Division
  MI Department of State Police
D. Lochbaum, Union of Concerned Scientists


DOCUMENT NAME: G:\COOK\ML021610713.wpd
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
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
OFFICE
  NAME               KOBrien/trn                   DPassehl                   SBurgess                       AVegel                       BClayton
RIII
  DATE               06/ /02                       06/ /02                     06/ /02                       06/ /02                       06/ /02
RIII
OFFICE                   NRR                         RIII                       RIII                         RIII                     RIII
RIII
NAME                     Carpenter/via               Clayton                     Congel                       Grant                     Dyer
RIII
                          telecon
RIII
DATE                      05/31/02                   06/ /02                     06/ /02                       06/ /02                   06/ /02
NAME
                                                              OFFICIAL RECORD COPY
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
telecon
Clayton
Congel
Grant
Dyer
DATE
05/31/02
06/   /02
06/   /02
06/   /02
06/   /02
OFFICIAL RECORD COPY


A. Bakken             -5-
A. Bakken
-5-
ADAMS Distribution:
ADAMS Distribution:
WDR
WDR
Line 201: Line 238:
WMD
WMD


          U.S. NUCLEAR REGULATORY COMMISSION
U.S. NUCLEAR REGULATORY COMMISSION
                          REGION III
REGION III
Docket No:       50-315; 50-316
Docket No:
License Nos:     DPR-58; DPR-74
50-315; 50-316
Report No:       50-315/01-17(DRP); 50-316/01-17(DRP)
License Nos:
Licensee:       American Electric Power Company
DPR-58; DPR-74
Facility:       D.C. Cook Nuclear Power Plant, Units 1 and 2
Report No:
Location:       1 Cook Place
50-315/01-17(DRP); 50-316/01-17(DRP)
                Bridgman, MI 49106
Licensee:
Dates:           August 30, 2001 through May 17, 2002
American Electric Power Company
Inspectors:     B. Bartlett, Senior Resident Inspector
Facility:
                S. Burgess, Senior Risk Analyst
D.C. Cook Nuclear Power Plant, Units 1 and 2
                M. Cheok, Senior Reliability and Risk Analyst, NRR
Location:
                K. Coyne, Resident Inspector
1 Cook Place
                S. Jones, Senior Reactor Systems Engineer, NRR
Bridgman, MI 49106
                K. OBrien, Senior Reactor Inspector
Dates:
                P. Prescott, Senior Resident Inspector, Duane Arnold
August 30, 2001 through May 17, 2002
Approved by:     Geoffrey E. Grant, Director
Inspectors:
                Division of Reactor Projects
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
2
SUMMARY OF FINDINGS
IR 05000315-01-17(DRP), IR 05000316-01-17(DRP); on 08/30/2001 - 5/17/2002, Indiana
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.
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
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
inspectors and staff. The inspectors identified one preliminarily Yellow finding and one Green
finding. These findings were assessed using the applicable significance determination process
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
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
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
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
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
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
SDP does not apply are indicated by No Color or by the severity level of the applicable
violation.
violation.
A.     Inspector Identified Findings
A.
        Cornerstone: Mitigating Systems
Inspector Identified Findings
        *       TBD. Documented instructions for essential service water (ESW) pump
Cornerstone: Mitigating Systems
                discharge strainer maintenance did not contain adequate detail regarding critical
*
                parameters for basket installation. Consequently, faulty strainer basket
TBD. Documented instructions for essential service water (ESW) pump
                installation practices contributed to the failure of an ESW pump discharge
discharge strainer maintenance did not contain adequate detail regarding critical
                strainer basket and created the potential for debris to bypass the strainer and
parameters for basket installation. Consequently, faulty strainer basket
                enter the ESW system. On August 29, 2001, the failed 1 East ESW pump
installation practices contributed to the failure of an ESW pump discharge
                discharge strainer, in conjunction with the ESW system alignment with all normal
strainer basket and created the potential for debris to bypass the strainer and
                and alternate diesel generator (D/G) ESW supply valves open, caused
enter the ESW system. On August 29, 2001, the failed 1 East ESW pump
                significant debris fouling of D/G heat exchangers. While operator actions
discharge strainer, in conjunction with the ESW system alignment with all normal
                prevented the debris fouling from causing a complete loss of the D/Gs ability to
and alternate diesel generator (D/G) ESW supply valves open, caused
                perform their emergency AC power safety function, the potential for a complete
significant debris fouling of D/G heat exchangers. While operator actions
                loss of all emergency AC power during a loss of offsite power was determined to
prevented the debris fouling from causing a complete loss of the D/Gs ability to
                exist. This issue is identified as Apparent Violation (AV) 50-315/01-17-01;
perform their emergency AC power safety function, the potential for a complete
                50-316/01-17-01. This finding was assessed using the applicable SDP as a
loss of all emergency AC power during a loss of offsite power was determined to
                potentially safety significant finding that was preliminarily determined to be of
exist. This issue is identified as Apparent Violation (AV) 50-315/01-17-01;
                substantial safety significance. (Section 4OA3.3 and 4OA3.4)
50-316/01-17-01. This finding was assessed using the applicable SDP as a
        *       Green. The inspectors identified a Non-Cited Violation of Technical
potentially safety significant finding that was preliminarily determined to be of
                Specification 6.8.1 associated with operator procedural adherence deficiencies
substantial safety significance. (Section 4OA3.3 and 4OA3.4)
                during the degraded ESW event of August 29, 2001. Specifically, the operators
*
                failed to (1) effectively monitor the control boards for changing indications,
Green. The inspectors identified a Non-Cited Violation of Technical
                adverse trends, and abnormal indications, (2) effectively communicate receipt of
Specification 6.8.1 associated with operator procedural adherence deficiencies
                an abnormal temperature alarm for the CCW heat exchanger, and (3) enter the
during the degraded ESW event of August 29, 2001. Specifically, the operators
                CCW abnormal operating procedure as directed by the abnormal temperature
failed to (1) effectively monitor the control boards for changing indications,
                alarm response procedure.
adverse trends, and abnormal indications, (2) effectively communicate receipt of
                                                    2
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.


3
The inspectors determined that the failure to adequately implement procedures
The inspectors determined that the failure to adequately implement procedures
associated with control board monitoring, logkeeping, and annunciator response
associated with control board monitoring, logkeeping, and annunciator response
had a credible impact on safety and therefore were more than a minor concern.
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
Specifically, these issues could reasonably result in the failure to identify and
promptly correct degradation of safety related equipment and therefore impact
promptly correct degradation of safety related equipment and therefore impact
the reliability and availability of a safety system. Because these performance
the reliability and availability of a safety system. Because these performance
deficiencies contributed to delays in identifying degradation of the ESW and
deficiencies contributed to delays in identifying degradation of the ESW and
CCW mitigating systems, the inspectors determined that these human
CCW mitigating systems, the inspectors determined that these human
performance weaknesses were associated with the mitigating systems
performance weaknesses were associated with the mitigating systems
cornerstone. Although this issue adversely impacted the licensees response to
cornerstone. Although this issue adversely impacted the licensees response to
the August 29, 2001 event, none of the performance deficiencies directly
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
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
system train for greater than its TS allowed outage time. Consequently, the
inspectors concluded that this issue was of very low safety significance (Green).
inspectors concluded that this issue was of very low safety significance (Green).
(Section 4OA4)
(Section 4OA4)
                                    3


                                            Report Details
4
Report Details
Summary of Plant Event
Summary of Plant Event
On the evening of August 29, 2001, the plant experienced problems with Essential Service
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
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
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
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
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
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.
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
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.
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
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
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
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
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
values. Because the degraded ESW flow condition was not fully understood, the licensee
subsequently shut down Unit 2.
subsequently shut down Unit 2.
Subsequent NRC engineering evaluations of the conditions present on August 29, 2001,
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
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.
event could potentially result in a loss of all onsite emergency alternating current power.
1.     REACTOR SAFETY
1.
        Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
REACTOR SAFETY
1R04 Equipment Alignment (71111.04)
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity
   a.   Inspection Scope
1R04
        The inspectors performed complete safety system walkdowns of the following
Equipment Alignment (71111.04)
        risk-significant system:
   a.
        Mitigating Systems Cornerstone
Inspection Scope
        *       Unit 1 ESW System
The inspectors performed complete safety system walkdowns of the following
        *       Unit 2 ESW System
risk-significant system:
        The inspectors selected this system based on its degraded performance and its risk
Mitigating Systems Cornerstone
        significance relative to the mitigating systems cornerstone. The inspectors reviewed
*
        operating procedures, TS requirements, Administrative Technical Requirements (ATRs),
Unit 1 ESW System
        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
Unit 2 ESW System
        rendered these systems incapable of performing their intended functions.
The inspectors selected this system based on its degraded performance and its risk
                                                  4
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.


b. Findings
5
    The inspectors assessed the condition of the ESW system, the adequacy of the
  b.
    licensees root cause evaluation, and the effectiveness of corrective actions during this
Findings
    complete safety system walkdown. Findings relative to the performance of this
The inspectors assessed the condition of the ESW system, the adequacy of the
    inspection module are discussed in Section 4OA3, "Event Followup."
licensees root cause evaluation, and the effectiveness of corrective actions during this
1R07 Heat Sink Performance (71111.07)
complete safety system walkdown. Findings relative to the performance of this
a. Inspection Scope
inspection module are discussed in Section 4OA3, "Event Followup."
    The inspectors observed or reviewed portions of the following heat exchanger
1R07
    inspections:
Heat Sink Performance (71111.07)
    *       Unit 1 CCW heat exchangers, containment spray (CTS) system heat
  a.
            exchangers, D/G heat exchangers, north control room air conditioning (CRAC)
Inspection Scope
            heat exchangers and the auxiliary feedwater (AFW) pump room coolers.
The inspectors observed or reviewed portions of the following heat exchanger
    These inspections were conducted following the ESW flow degradation event on
inspections:
    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
Unit 1 CCW heat exchangers, containment spray (CTS) system heat
    common cause failure of ESW cooled components. Because ESW provided the
exchangers, D/G heat exchangers, north control room air conditioning (CRAC)
    ultimate heat sink (UHS) for the emergency core cooling system, the inspectors
heat exchangers and the auxiliary feedwater (AFW) pump room coolers.
    determined that this inspection was associated with the mitigating systems cornerstone.
These inspections were conducted following the ESW flow degradation event on
b. Findings
August 29, 2001. The inspectors assessed the heat exchanger condition relative to the
    The inspectors assessed the impact of the debris intrusion event on heat exchanger
observed flow reduction to certain ESW cooled components and the potential for
    capability in order to determine the safety impact of degraded ESW system performance
common cause failure of ESW cooled components. Because ESW provided the
    and the effectiveness of licensee corrective actions. Findings relative to the
ultimate heat sink (UHS) for the emergency core cooling system, the inspectors
    performance of this inspection module are discussed in Section 4OA3, "Event
determined that this inspection was associated with the mitigating systems cornerstone.
    Followup," Subsections 4OA3.1, 4OA3.4, and 4OA3.5.
  b.
1R13 Maintenance and Emergent Work (71111.13)
Findings
a. Inspection Scope
The inspectors assessed the impact of the debris intrusion event on heat exchanger
    The inspectors reviewed the risk assessment and risk management for the following risk
capability in order to determine the safety impact of degraded ESW system performance
    significant maintenance activities:
and the effectiveness of licensee corrective actions. Findings relative to the
    Mitigating Systems Cornerstone
performance of this inspection module are discussed in Section 4OA3, "Event
    *       Unit 1 dual ESW train outage to support forebay cleaning
Followup," Subsections 4OA3.1, 4OA3.4, and 4OA3.5.
    The inspectors selected this maintenance activity based on ESW system degraded
1R13
    performance and its risk significance relative to the mitigating systems cornerstone.
Maintenance and Emergent Work (71111.13)
    The inspectors reviewed the scope of maintenance work to ensure that applicable safety
  a.
    functions were maintained during the maintenance activity. The inspectors also
Inspection Scope
    reviewed TS and ATR requirements and walked down portions of redundant safety
The inspectors reviewed the risk assessment and risk management for the following risk
                                              5
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


    systems, to verify that risk analysis assumptions were valid and applicable requirements
6
    were met.
systems, to verify that risk analysis assumptions were valid and applicable requirements
b. Findings
were met.
    No findings of significance were identified.
  b.
1R15 Operability Evaluations (71111.15)
Findings
a. Inspection Scope
No findings of significance were identified.
    The inspectors evaluated the potential operability impact associated with the following
1R15
    issues:
Operability Evaluations (71111.15)
    Mitigating Systems Cornerstone
  a.
    *       Operability of the ESW system following pump discharge strainer failure
Inspection Scope
    *       Operability of the D/Gs with degraded ESW flow
The inspectors evaluated the potential operability impact associated with the following
    The inspectors selected these issues based upon their risk significance and their
issues:
    importance to the special inspection. The inspectors reviewed the licensee's evaluation
Mitigating Systems Cornerstone
    and supporting documentation to assess the basis and quality for the operability
*
    determination. The inspectors concluded that this inspection was associated with the
Operability of the ESW system following pump discharge strainer failure
    Mitigating Systems cornerstone.
*
b. Findings
Operability of the D/Gs with degraded ESW flow
    The inspectors reviewed the operability impact of the degraded ESW flow condition to
The inspectors selected these issues based upon their risk significance and their
    determine the safety significance of the event and assess the effectiveness of the
importance to the special inspection. The inspectors reviewed the licensee's evaluation
    licensee's corrective actions. Findings relative to the performance of this inspection
and supporting documentation to assess the basis and quality for the operability
    module are discussed in Section 4OA3, "Event Followup," subsections 4OA3.4 and
determination. The inspectors concluded that this inspection was associated with the
    4OA3.5.
Mitigating Systems cornerstone.
1R19 Post Maintenance Testing (71111.19)
  b.
a. Inspection Scope
Findings
    The inspectors reviewed the post maintenance testing requirements associated with the
The inspectors reviewed the operability impact of the degraded ESW flow condition to
    following scheduled maintenance activity:
determine the safety significance of the event and assess the effectiveness of the
                                              6
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:


    Mitigating Systems Cornerstone
7
    *       Unit 1 CD D/G heat exchanger inspection
Mitigating Systems Cornerstone
    The inspectors reviewed post maintenance testing acceptance criteria specified in the
*
    applicable corrective maintenance work orders. The inspectors verified that the
Unit 1 CD D/G heat exchanger inspection
    activities and acceptance criteria were appropriate for the scope of work performed.
The inspectors reviewed post maintenance testing acceptance criteria specified in the
    Documented data was reviewed to verify that the testing was complete and that the
applicable corrective maintenance work orders. The inspectors verified that the
    equipment was able to perform the intended safety functions.
activities and acceptance criteria were appropriate for the scope of work performed.  
   b. Findings
Documented data was reviewed to verify that the testing was complete and that the
    No findings of significance were identified.
equipment was able to perform the intended safety functions.
4.   OTHER ACTIVITIES (OA)
   b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES (OA)
4OA3 Event Followup (93812)
4OA3 Event Followup (93812)
  .1 Sequence of Events for Degraded ESW System Flow
  .1
   a. Inspection Scope
Sequence of Events for Degraded ESW System Flow
    The inspectors reviewed documentation and conducted interviews to determine the
   a.
    sequence of events that resulted in degraded ESW flows to safety related equipment.
Inspection Scope
    Additionally, the inspectors reviewed licensee actions during and immediately following
The inspectors reviewed documentation and conducted interviews to determine the
    the degraded ESW event.
sequence of events that resulted in degraded ESW flows to safety related equipment.
   b. Findings
Additionally, the inspectors reviewed licensee actions during and immediately following
    Based on a review of control room logs, operator statements, and plant process
the degraded ESW event.
    computer data and instrumentation, the inspectors developed a sequence of events for
   b.
    the degraded ESW flow event. The sequence of events covers the time period from
Findings
    July 2001 through September 2001.
Based on a review of control room logs, operator statements, and plant process
                                              7
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.


  Date     Time                         Event Description
8
July 1-2           Unit 1 and Unit 2 were operating in Mode 1 (Power
Date
                    Operation) while the licensee performed biocide
Time
                    treatment of the circulating water system for zebra
Event Description
                    mussel control. Unit 1 Circulating Water (CW)
July 1-2
                    pump 13 reverse rotated following stoppage to
Unit 1 and Unit 2 were operating in Mode 1 (Power
                    support biocide treatment. The licensee
Operation) while the licensee performed biocide
                    determined that the CW pump 13 discharge valve
treatment of the circulating water system for zebra
                    (1-WMO-13) was partially open and could not be
mussel control. Unit 1 Circulating Water (CW)
                    fully shut, resulting in backflow through the pump.
pump 13 reverse rotated following stoppage to
                    In order to stop the reverse rotation of CW pump 13
support biocide treatment. The licensee
                    and allow restart of the pump, the licensee took the
determined that the CW pump 13 discharge valve
                    Unit 1 main turbine offline and removed the CW
(1-WMO-13) was partially open and could not be
                    system from service . Following restart of CW
fully shut, resulting in backflow through the pump.
                    pump 13, Unit 1 was returned to full power.
In order to stop the reverse rotation of CW pump 13
August 27           Unit 1 was shut down to support repairs to CW
and allow restart of the pump, the licensee took the
                    system valve 1-WMO-13.
Unit 1 main turbine offline and removed the CW
                    Unit 2 continued to operate at full power.
system from service . Following restart of CW
August 29 ~6:30 a.m. Prior to the degraded ESW flow event, all ESW unit
pump 13, Unit 1 was returned to full power.
                    cross tie valves were open and the normal and
August 27
                    alternate ESW supply valves to each D/G were
Unit 1 was shut down to support repairs to CW
                    open. Initial ESW flows to the diesel generators
system valve 1-WMO-13.
                    were approximately:
Unit 2 continued to operate at full power.
                            1 AB D/G= 920 gpm
August 29
                            1 CD D/G= 933 gpm
~6:30 a.m.
                            2 AB D/G= 860 gpm
Prior to the degraded ESW flow event, all ESW unit
                            2 CD D/G= 884 gpm
cross tie valves were open and the normal and
                              8
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


  Date       Time                       Event Description
Date
August 29 11:06 a.m. The Unit 1 West ESW pump was started to support
Time
                      Unit 1 cooldown to Mode 5 (Cold Shutdown). The
Event Description
                      ESW system was aligned in the following
9
                      configuration:
August 29
                      *       Unit 1 West and Unit 2 East ESW pumps
11:06 a.m.
                              supplied their common ESW header with
The Unit 1 West ESW pump was started to support  
                              associated unit cross-tie valves open
Unit 1 cooldown to Mode 5 (Cold Shutdown). The
                      *       Unit 1 East ESW pump supplied the Unit 1
ESW system was aligned in the following
                              East and Unit 2 West ESW common header
configuration:
                              with associated unit cross-tie valves open.
*
                              The Unit 2 West pump was aligned for
Unit 1 West and Unit 2 East ESW pumps
                              standby operation.
supplied their common ESW header with
                      *       The normal and alternate ESW supply
associated unit cross-tie valves open
                              valves to all D/Gs were open
*
August 29 11:26 a.m. Unit 1 commenced cooldown using Residual Heat
Unit 1 East ESW pump supplied the Unit 1
                      Removal (RHR) system to Mode 5. This cooldown
East and Unit 2 West ESW common header
                      approximately doubled ESW flow rates in Unit 1.
with associated unit cross-tie valves open.  
August 29 1:14 p.m. - Unit 1 CW pumps 11, 12 and 13 were stopped in
The Unit 2 West pump was aligned for
          1:36 p.m.  succession. Circulating water pump 13 was
standby operation.
                      stopped last to minimize the potential for backflow
*
                      through the pump due to the degraded condition of
The normal and alternate ESW supply
                      valve 1-WMO-13.
valves to all D/Gs were open
August 29 ~3:00 p.m. Unit 1 cooldown completed and ESW flow rates in
August 29
                      Unit 1 decreased. Although the operators did not
11:26 a.m.
                      identify any abnormal ESW system conditions
Unit 1 commenced cooldown using Residual Heat
                      during the cooldown, ESW flows to each of the D/G
Removal (RHR) system to Mode 5. This cooldown
                      indicate degradation:
approximately doubled ESW flow rates in Unit 1.
                              1 AB D/G= 674 gpm
August 29
                              1 CD D/G= 791 gpm
1:14 p.m. -
                              2 AB D/G= 760 gpm
1:36 p.m.
                              2 CD D/G= 744 gpm
Unit 1 CW pumps 11, 12 and 13 were stopped in
August 29 7:00 p.m. Unit 2 commenced surveillance testing of the Unit 2
succession.  Circulating water pump 13 was
                      East ESW system in accordance with
stopped last to minimize the potential for backflow
                      Procedure 02 OHP 4030.STP.022E. The cross-tie
through the pump due to the degraded condition of
                      valve between the Unit 1 West and the Unit 2 East
valve 1-WMO-13.
                      ESW headers was shut in accordance with the
August 29
                      procedure.
~3:00 p.m.
                              9
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.


  Date       Time                         Event Description
Date
August 29 ~7:15 p.m. The ESW flows to the Unit 1 AB and the Unit 2 CD
Time
                      D/G decreased below the UFSAR Table 9.8-5
Event Description
                      minimum required flowrate of 540 gpm. Flows to
10
                      each D/G were:
August 29
                              1 AB D/G= 400 gpm
~7:15 p.m.
                              1 CD D/G= 575 gpm
The ESW flows to the Unit 1 AB and the Unit 2 CD
                              2 AB D/G= 618 gpm
D/G decreased below the UFSAR Table 9.8-5
                              2 CD D/G= 532 gpm
minimum required flowrate of 540 gpm. Flows to
August 29 ~8:00 p.m. Both Unit 2 D/G ESW flowrates decreased below
each D/G were:
                      UFSAR Table 9.8-5 minimum required flowrate.
1 AB D/G= 400 gpm
                      Flows to each D/G were:
1 CD D/G= 575 gpm
                              1 AB D/G= 265 gpm
2 AB D/G= 618 gpm
                              1 CD D/G= 447 gpm
2 CD D/G= 532 gpm
                              2 AB D/G= 538 gpm
August 29
                              2 CD D/G= 475 gpm
~8:00 p.m.
August 29 ~10:30 p.m. The Unit 1 East CCW heat exchanger outlet
Both Unit 2 D/G ESW flowrates decreased below
                      temperature exceeded the alarm setpoint of 95°F.
UFSAR Table 9.8-5 minimum required flowrate.  
                      The reactor operator experienced difficulty in
Flows to each D/G were:
                      increasing ESW flow to the affected heat
1 AB D/G= 265 gpm
                      exchanger; consequently, the outlet temperature
1 CD D/G= 447 gpm
                      remained above the 95°F alarm setpoint until
2 AB D/G= 538 gpm
                      approximately 2:30 a.m. on August 30, 2001.
2 CD D/G= 475 gpm
                      The reactor operator failed to log receipt of the high
August 29
                      temperature alarm in the control room log, did not
~10:30 p.m.
                      enter the abnormal CCW operating procedure as
The Unit 1 East CCW heat exchanger outlet
                      directed by the associated annunciator response
temperature exceeded the alarm setpoint of 95°F.  
                      procedure, and failed to adequately communicate
The reactor operator experienced difficulty in
                      the difficulty in controlling CCW outlet temperature
increasing ESW flow to the affected heat
                      to the operations shift crew.
exchanger; consequently, the outlet temperature
                      Flows to each D/G were less than 40 percent of
remained above the 95°F alarm setpoint until
                      flow rates prior to the event:
approximately 2:30 a.m. on August 30, 2001.
                              1 AB D/G = 96 gpm*
The reactor operator failed to log receipt of the high
                              1 CD D/G = 360 gpm**
temperature alarm in the control room log, did not
                              2 AB D/G = 363 gpm
enter the abnormal CCW operating procedure as
                              2 CD D/G = 256 gpm
directed by the associated annunciator response
                      *   The Plant Process Computer recorded the 1AB
procedure, and failed to adequately communicate
                          D/G flow rate as "BAD DATA". A flow rate of
the difficulty in controlling CCW outlet temperature
                          96 gpm was recorded prior to the "BAD DATA"
to the operations shift crew.
                          points.
Flows to each D/G were less than 40 percent of
                              10
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.


  Date       Time                       Event Description
Date
                    ** The ESW flow rate for the 1 CD D/G remained
Time
                        essentially constant for the remainder of the
Event Description
                        event until the operators cycled system valves
11
                        to clear the debris blockage at approximately
** The ESW flow rate for the 1 CD D/G remained
                        12:40 a.m..
essentially constant for the remainder of the
August 29 10:55 p.m. While performing the Unit 2 East ESW system
event until the operators cycled system valves
                    surveillance test procedure, the control room
to clear the debris blockage at approximately
                    operators noted that ESW flow to the 2 AB and
12:40 a.m..
                    2 CD D/Gs were less than the surveillance test
August 29
                    acceptance criteria of 590 gpm. Unit 2 entered
10:55 p.m.
                    TS 3.0.3 due to two inoperable D/Gs. It was later
While performing the Unit 2 East ESW system
                    determined that the limiting condition for operation
surveillance test procedure, the control room
                    of TS 3.8.1.1.e should have been entered rather
operators noted that ESW flow to the 2 AB and  
                    than TS 3.0.3.
2 CD D/Gs were less than the surveillance test
                    Unit 1 was informed of the low ESW flow condition
acceptance criteria of 590 gpm. Unit 2 entered
                    in Unit 2. Unit 1 also identified low ESW flow to the
TS 3.0.3 due to two inoperable D/Gs. It was later
                    1 AB and 1 CD D/G. Unit 1 entered TS 3.8.1.2 for
determined that the limiting condition for operation
                    two inoperable diesel generators while in Mode 5.
of TS 3.8.1.1.e should have been entered rather
August 29 11:47 p.m. The Unit 2 AB D/G was declared operable following
than TS 3.0.3.
                    cycling of the remotely operated ESW supply
Unit 1 was informed of the low ESW flow condition
                    valves. Unit 2 AB D/G ESW flow improved to
in Unit 2. Unit 1 also identified low ESW flow to the
                    approximately 800 gpm. Unit 2 exited TS 3.0.3 but
1 AB and 1 CD D/G. Unit 1 entered TS 3.8.1.2 for
                    entered TS 3.8.1.1 for one inoperable D/G.
two inoperable diesel generators while in Mode 5.
August 29 11:50 p.m. The Unit 2 CD D/G declared operable following
August 29
                    cycling of the remotely operated ESW supply
11:47 p.m.
                    valves. Unit 2 CD D/G ESW flow improved to
The Unit 2 AB D/G was declared operable following
                    approximately 800 gpm. Unit 2 exited TS 3.8.1.1.
cycling of the remotely operated ESW supply
August 30 12:40 a.m. The Unit 1 CD D/G declared available but remained
valves. Unit 2 AB D/G ESW flow improved to
                    inoperable due to degraded ESW flow following
approximately 800 gpm. Unit 2 exited TS 3.0.3 but
                    cycling of the remotely operated ESW supply
entered TS 3.8.1.1 for one inoperable D/G.
                    valves. ESW flow improved to 760 gpm.
August 29
August 30 1:25 a.m. The Unit 1 AB D/G declared available but remained
11:50 p.m.
                    inoperable due to degraded ESW flow following
The Unit 2 CD D/G declared operable following
                    cycling of the remotely operated ESW supply
cycling of the remotely operated ESW supply
                    valves. ESW flow improved to 700 gpm.
valves. Unit 2 CD D/G ESW flow improved to
                              11
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.


  Date     Time                       Event Description
Date
August 30 1:55 a.m. Unit 2 control room operators continued
Time
                    performance of Unit 2 East ESW system
Event Description
                    surveillance and aligned the normally isolated
12
                    Unit 2 East containment spray system (CTS) heat
August 30
                    exchanger for flushing in accordance with
1:55 a.m.
                    02-OHP 4030.STP.022E.
Unit 2 control room operators continued
                    At this time the source and extent of the debris
performance of Unit 2 East ESW system
                    intrusion had not been positively identified and the
surveillance and aligned the normally isolated
                    inspectors determined that this action could have
Unit 2 East containment spray system (CTS) heat
                    transported debris into the otherwise isolated CTS
exchanger for flushing in accordance with
                    heat exchanger. Because the source of debris
02-OHP 4030.STP.022E.
                    intrusion was later determined to be the Unit 1 East
At this time the source and extent of the debris
                    ESW pump strainer (which was independent from
intrusion had not been positively identified and the
                    the Unit 2 East ESW header), this action did not
inspectors determined that this action could have
                    adversely impact the Unit 2 East CTS heat
transported debris into the otherwise isolated CTS
                    exchanger.
heat exchanger. Because the source of debris
August 30 2:09 a.m. The Unit 2 West ESW pump was started.
intrusion was later determined to be the Unit 1 East
August 30 2:13 a.m. The Unit 2 ESW unit cross-tie valve, 2-WMO-706,
ESW pump strainer (which was independent from
                    was shut to split the ESW systems. All four ESW
the Unit 2 East ESW header), this action did not
                    pumps were running with all unit cross-tie valves
adversely impact the Unit 2 East CTS heat
                    closed.
exchanger.
August 30 2:15 a.m. Unit 1 East ESW and CCW trains were declared
August 30
                    inoperable (but available) due to degraded ESW
2:09 a.m.
                    flow system. Actions associated with TS 3.7.3.1
The Unit 2 West ESW pump was started.
                    and TS 3.7.4.1 were not applicable with Unit 1 in
August 30
                    Mode 5.
2:13 a.m.
                    Unit 2 West CCW heat exchanger flow indicated
The Unit 2 ESW unit cross-tie valve, 2-WMO-706,
                    approximately 2000 gpm with outlet temperature
was shut to split the ESW systems. All four ESW
                    rising slowly at 92o F. Cycling of the ESW inlet and
pumps were running with all unit cross-tie valves
                    outlet valves improved heat exchange flow to
closed.
                    5500 gpm. This flow rate was less than the
August 30
                    expected value of approximately 8500 gpm. Unit 2
2:15 a.m.
                    entered TS 3.7.3.1 for the inoperable Unit 2 West
Unit 1 East ESW and CCW trains were declared
                    CCW loop.
inoperable (but available) due to degraded ESW
August 30 2:30 a.m. Unit 2 East CTS heat exchanger declared operable
flow system. Actions associated with TS 3.7.3.1
                    following completion of ESW surveillance testing
and TS 3.7.4.1 were not applicable with Unit 1 in
                    flush.
Mode 5.
                            12
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.


        Date             Time                         Event Description
Date
      August 30         2:45 a.m.   Unit 2 control room operators started the south
Time
                                    control room air conditioning (CRAC) unit and
Event Description
                                    stopped the north CRAC for flushing during
13
                                    02-OHP4030.STP.022E.
August 30
                                    At this time the source and extent of the debris
2:45 a.m.
                                    intrusion had not been positively identified and the
Unit 2 control room operators started the south
                                    inspectors determined that placing the south CRAC
control room air conditioning (CRAC) unit and
                                    unit into service could have allowed transport of
stopped the north CRAC for flushing during
                                    debris into the associated heat exchanger.
02-OHP4030.STP.022E.
                                    Because the source of debris intrusion was later
At this time the source and extent of the debris
                                    determined to be the Unit 1 East ESW pump
intrusion had not been positively identified and the
                                    strainer (which was isolated from Unit 2 by closure
inspectors determined that placing the south CRAC
                                    of 2-WMO-706), this action did not adversely
unit into service could have allowed transport of
                                    impact the CRAC unit.
debris into the associated heat exchanger.  
      August 30         3:45 a.m.   Unit 1 AB D/G declared operable after closing and
Because the source of debris intrusion was later
                                    de-energizing the alternate ESW supply remotely
determined to be the Unit 1 East ESW pump
                                    operated valve from the Unit 1 East ESW header.
strainer (which was isolated from Unit 2 by closure
                                    Unit 1 exited TS 3.8.1.2.
of 2-WMO-706), this action did not adversely
      August 30         6:23 a.m.   Licensee completed 8 hour report to the NRC
impact the CRAC unit.  
                                    regarding degraded ESW flow to the D/Gs (Event
August 30
                                    Number 38249).
3:45 a.m.
      August 30         7:55 a.m.   Unit 2 commenced 15 percent per hour power
Unit 1 AB D/G declared operable after closing and
                                    reduction for reactor shutdown.
de-energizing the alternate ESW supply remotely
      August 30         1:36 p.m.   Unit 2 entered Mode 2 (Reactor Startup).
operated valve from the Unit 1 East ESW header.  
      August 30         1:47 p.m.   Unit 2 entered Mode 3 (Hot Standby).
Unit 1 exited TS 3.8.1.2.
      August 31         4:15 a.m.   Unit 1 East motor driven auxiliary feedwater pump
August 30
                                    (MDAFWP) inoperable due to low ESW flow to its
6:23 a.m.
                                    room cooler.
Licensee completed 8 hour report to the NRC
      August 31         6:10 a.m.   Unit 1 East MDAFWP declared operable after ESW
regarding degraded ESW flow to the D/Gs (Event
                                    flow to room cooler restored.
Number 38249).
    September 3       12:28 p.m.   Unit 2 entered Mode 5 and exited TS 3.7.3.1.
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
Results of Essential Service Water Inspections
Following shutdown of Unit 2, the licensee performed inspections on the ESW system to
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
determine the cause and extent of condition of degraded ESW system performance. The
results of significant ESW system inspections conducted after implementation of the
results of significant ESW system inspections conducted after implementation of the
licensees immediate corrective actions following the event are summarized below:
licensees immediate corrective actions following the event are summarized below:
                                              13


      Component                           Inspection Results
14
Unit 1 East ESW pump Deformation of the strainer basket and resultant bypass
Component
discharge strainer  flowpath around the basket was identified. Additionally,
Inspection Results
                    the basket support bracket was deformed.
Unit 1 East ESW pump
Unit 1 East CCW Heat Inspections identified the following:
discharge strainer
Deformation of the strainer basket and resultant bypass
flowpath around the basket was identified. Additionally,
the basket support bracket was deformed.
Unit 1 East CCW Heat
Exchanger
Exchanger
                    *   213 tubes were obstructed with debris (approximately
Inspections identified the following:
                        10 percent tube blockage). All tubes were cleaned
*
                        using a hand brush.
213 tubes were obstructed with debris (approximately
                    *   Approximately 1.5 cubic feet of debris found in the
10 percent tube blockage). All tubes were cleaned
                        interpass region and about one half cubic foot of
using a hand brush.
                        debris found in the inlet plenum.
*
                    *   Debris measuring greater than 1/8 inch (the ESW
Approximately 1.5 cubic feet of debris found in the
                        strainer mesh size) was identified in the heat
interpass region and about one half cubic foot of
                        exchanger. In general, the debris consisted of zebra
debris found in the inlet plenum.
                        mussel shells and sand.
*
                    Note: The CCW heat exchanger is a two pass shell and
Debris measuring greater than 1/8 inch (the ESW
                            tube heat exchanger with ESW flowing through
strainer mesh size) was identified in the heat
                            the tube side.
exchanger. In general, the debris consisted of zebra
Unit 1 West CCW Heat Inspections identified the following:
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
Exchanger
Exchanger
                    *   33 tubes blocked with silt and debris (approximately
Inspections identified the following:
                        1.5 percent tube blockage)
*
                    *   Minimal amounts of shells and debris
33 tubes blocked with silt and debris (approximately
                    Note: 85 additional tubes in the Unit 1 West CCW heat
1.5 percent tube blockage)
                            exchanger were mechanically blocked during
*
                            previous maintenance activities.
Minimal amounts of shells and debris
Unit 1 East CTS Heat Inspection identified the following:
Note:
85 additional tubes in the Unit 1 West CCW heat
exchanger were mechanically blocked during
previous maintenance activities.
Unit 1 East CTS Heat
Exchanger
Exchanger
                    *   Very light silting, less than 1/4 inch thick in the lower
Inspection identified the following:
                        shell area. No shells were found.
*
                    Note: The CTS heat exchanger is a shell and U-tube
Very light silting, less than 1/4 inch thick in the lower
                            heat exchanger with ESW flowing on the shell
shell area. No shells were found.
                            side.
Note:
Unit 1 AB D/G Heat   Inspection identified minimal amounts of debris and no
The CTS heat exchanger is a shell and U-tube
Exchangers          tube blockage.
heat exchanger with ESW flowing on the shell
                                    14
side.
Unit 1 AB D/G Heat
Exchangers
Inspection identified minimal amounts of debris and no
tube blockage.


      Component                           Inspection Results
Component
Unit 1 CD D/G Heat   Inspection of the 1 CD D/G heat exchangers identified
Inspection Results
Exchangers          the following:
15
                    *   Lube oil cooler had 14 blocked tubes with debris and
Unit 1 CD D/G Heat
                        7 partially blocked tubes (approximately 10 percent of
Exchangers
                        the heat exchanger tubes had some blockage and
Inspection of the 1 CD D/G heat exchangers identified
                        were degraded). All tubes were cleaned.
the following:
                    *   The jacket water heat exchanger had 14 tubes
*
                        blocked with debris (approximately 6 percent total had
Lube oil cooler had 14 blocked tubes with debris and
                        some blockage and were degraded). Two tubes
7 partially blocked tubes (approximately 10 percent of
                        remained blocked after cleaning.
the heat exchanger tubes had some blockage and
Unit 1 North CRAC   Inspection of the CRAC unit identified minimal debris and
were degraded). All tubes were cleaned.
                    no blocked tubes.
*
Unit 1 East MDAFWP   Inspection of room cooler identified 18 pre-cooler tubes
The jacket water heat exchanger had 14 tubes
Room Cooler          fully blocked with debris and 18 pre-cooler tubes partially
blocked with debris (approximately 6 percent total had
                    blocked with debris (approximately 27 percent of the
some blockage and were degraded). Two tubes
                    pre-cooler tubes had some blockage and were
remained blocked after cleaning.
                    degraded). The associated job order stated that the
Unit 1 North CRAC  
                    pre-cooler section was "full of dirt, zebra mussels, and a
Inspection of the CRAC unit identified minimal debris and
                    steel ball."
no blocked tubes.
Unit 1 West MDAFWP   Inspections identified 1 pre-cooler tube of 132 total tubes
Unit 1 East MDAFWP
Room Cooler          blocked with a small amount of sand and mussel shell
Room Cooler
                    debris.
Inspection of room cooler identified 18 pre-cooler tubes
Unit 1 East Turbine  Approximately one pound of debris was removed from
fully blocked with debris and 18 pre-cooler tubes partially
Driven Auxiliary    the room cooler during flushing activities. Inspections
blocked with debris (approximately 27 percent of the
Feedwater Pump      identified that 7 of 48 pre-cooler tubes were blocked with
pre-cooler tubes had some blockage and were
(TDAFWP) Room        sand, silt and/or zebra mussel shells.
degraded). The associated job order stated that the
Cooler
pre-cooler section was "full of dirt, zebra mussels, and a
Unit 1 West TDAFWP   10 of 48 pre-cooler tubes were blocked with zebra
steel ball."
Room Cooler          mussel shells and sand.
Unit 1 West MDAFWP
Unit 2 West CCW Heat Inspections identified less than 24 tubes blocked with
Room Cooler
Exchanger            weed-like growth, tubercles, and zebra mussel shells
Inspections identified 1 pre-cooler tube of 132 total tubes
                    (approximately 1 percent tube blockage). Because this
blocked with a small amount of sand and mussel shell
                    inspection was performed approximately 4 weeks after
debris.
                    the event, normal system flow through the heat
Unit 1 East Turbine
                    exchanger could have facilitated cleanup of debris.
Driven Auxiliary
                                    15
Feedwater Pump
(TDAFWP) Room
Cooler
Approximately one pound of debris was removed from
the room cooler during flushing activities. Inspections
identified that 7 of 48 pre-cooler tubes were blocked with
sand, silt and/or zebra mussel shells.
Unit 1 West TDAFWP
Room Cooler
10 of 48 pre-cooler tubes were blocked with zebra
mussel shells and sand.
Unit 2 West CCW Heat
Exchanger
Inspections identified less than 24 tubes blocked with
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.


            Component                               Inspection Results
Component
    Unit 2 West CTS Heat     This heat exchanger was not inspected immediately
Inspection Results
    Exchanger                following the event, but was inspected during the January
16
                              2002 Unit 2 refueling outage. Results of inspections
Unit 2 West CTS Heat
                              performed on February 4, 2002 identified minor amounts
Exchanger
                              of debris, including sand and shell fragments, on top of
This heat exchanger was not inspected immediately
                              tube sheet (4 - 6 cups total).
following the event, but was inspected during the January
    Unit 2 AB D/G Heat       Inspection identified:
2002 Unit 2 refueling outage. Results of inspections
    Exchangers
performed on February 4, 2002 identified minor amounts
                              *  6 partially blocked tubes in the lube oil heat
of debris, including sand and shell fragments, on top of
                                  exchanger (less than 3 percent tube blockage).
tube sheet (4 - 6 cups total).
                              *   2 partially blocked tubes in the jacket water heat
Unit 2 AB D/G Heat
                                  exchanger (less than 1 percent tube blockage).
Exchangers
                              All tubes were cleaned.
Inspection identified:
    Unit 2 CD D/G Heat       Inspection identified:
*
    Exchangers
6 partially blocked tubes in the lube oil heat
                              *  2 blocked tubes in the lube oil heat exchanger (less
exchanger (less than 3 percent tube blockage).
                                  than 1 percent tube blockage).
*
                              *   3 blocked tubes in the jacket water heat exchanger
2 partially blocked tubes in the jacket water heat
                                  (less than 2 percent tube blockage).
exchanger (less than 1 percent tube blockage).
    Unit 2 North CRAC         Inspection identified no blocked tubes.
All tubes were cleaned.
    Heat Exchanger
Unit 2 CD D/G Heat
    Unit 2 West MDAFWP       Inspection of room cooler identified 5 pre-cooler tubes
Exchangers
    Room Cooler              fully blocked with debris and 11 pre-cooler tubes blocked
Inspection identified:
                              at the inlet with debris (approximately 12 percent of the
*
                              pre-cooler tubes had some blockage and were
2 blocked tubes in the lube oil heat exchanger (less
                              degraded)
than 1 percent tube blockage).
    Unit 2 West TDAFWP       Inspections identified 18 of 48 pre-cooler tubes to be
*
    Room Cooler              blocked with zebra mussel shells and sand. Condenser
3 blocked tubes in the jacket water heat exchanger
                              coil for refrigeration unit also appeared to be partially
(less than 2 percent tube blockage).
                              blocked.
Unit 2 North CRAC
.2   Adequacy of Licensee Response to ESW Low Flow Condition Including Emergency
Heat Exchanger
    Plan Implementation
Inspection identified no blocked tubes.
   a. Inspection Scope
Unit 2 West MDAFWP
    The inspectors reviewed the licensees immediate corrective actions in response to the
Room Cooler
    ESW low flow condition and the corrective actions to restore the ESW trains to their
Inspection of room cooler identified 5 pre-cooler tubes
    design and licensing basis.
fully blocked with debris and 11 pre-cooler tubes blocked
                                              16
at the inlet with debris (approximately 12 percent of the
pre-cooler tubes had some blockage and were
degraded)
Unit 2 West TDAFWP
Room Cooler
Inspections identified 18 of 48 pre-cooler tubes to be
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.


b. Findings
17
  Initial Identification
  b.
  The inspectors determined that control board indication of the trend of the degrading
Findings
  ESW flow could have been identified by the operators at least 3 hours prior to the initial
Initial Identification
  identification of the degraded flow. The delay in the identification of the low flow by the
The inspectors determined that control board indication of the trend of the degrading
  operators was due, in part, to the failure of the operators to perform hourly control board
ESW flow could have been identified by the operators at least 3 hours prior to the initial
  walkdowns recommended by procedure. The inspectors determined that operator
identification of the degraded flow. The delay in the identification of the low flow by the
  practice was to no longer perform the recommended walkdowns. However, the delay in
operators was due, in part, to the failure of the operators to perform hourly control board
  the identification did not result in a significant impact on event recovery actions.
walkdowns recommended by procedure. The inspectors determined that operator
  Initial Response
practice was to no longer perform the recommended walkdowns. However, the delay in
  The inspectors determined that the operators initial response to the event was
the identification did not result in a significant impact on event recovery actions.
  adequate to ensure that reactor safety was maintained. The operators ensured that the
Initial Response
  reactor coolant system (RCS) temperature was being maintained within the required
The inspectors determined that the operators initial response to the event was
  parameters and the ability to cool the RCS was maintained. In addition, the Unit 2
adequate to ensure that reactor safety was maintained. The operators ensured that the
  operators promptly informed the Unit 1 control room operators upon the identification of
reactor coolant system (RCS) temperature was being maintained within the required
  the degraded ESW flow.
parameters and the ability to cool the RCS was maintained. In addition, the Unit 2
  The inspectors determined that the Unit 2 Unit Supervisor (US) inappropriately entered
operators promptly informed the Unit 1 control room operators upon the identification of
  TS 3.0.3 upon declaring both Unit 2 D/Gs inoperable. Inoperability of both D/Gs
the degraded ESW flow.
  required an entry into Limiting Condition of Operation (LCO) TS 3.8.1.1.e, which
The inspectors determined that the Unit 2 Unit Supervisor (US) inappropriately entered
  required that two offsite power source circuits be demonstrated operable within 1 hour.
TS 3.0.3 upon declaring both Unit 2 D/Gs inoperable. Inoperability of both D/Gs
  Although the wrong TS LCO was entered, the licensee performed the off-site power
required an entry into Limiting Condition of Operation (LCO) TS 3.8.1.1.e, which
  operability verifications and complied with the time limits specified in TS 3.8.1.1.e.
required that two offsite power source circuits be demonstrated operable within 1 hour.  
  The licensee identified that the Unit 1 US failed to enter TS 3.1.2.3, for inoperable
Although the wrong TS LCO was entered, the licensee performed the off-site power
  boration flow paths, when the D/Gs were inoperable. The action statement required that
operability verifications and complied with the time limits specified in TS 3.8.1.1.e.
  no core alterations be performed. Since no core alterations were in progress, the
The licensee identified that the Unit 1 US failed to enter TS 3.1.2.3, for inoperable
  TS LCO was met.
boration flow paths, when the D/Gs were inoperable. The action statement required that
  The operating crews correctly diagnosed the low ESW flow and were able to improve
no core alterations be performed. Since no core alterations were in progress, the
  ESW flow to the D/Gs by repeatedly cycling ESW supply and return flow valves.
TS LCO was met.
  Approximately 3 hours after initially identifying the degraded ESW condition, the
The operating crews correctly diagnosed the low ESW flow and were able to improve
  operators closed the ESW unit cross-tie valves so that each unit was receiving ESW
ESW flow to the D/Gs by repeatedly cycling ESW supply and return flow valves.  
  flow only from its associated ESW pumps. The licensee did not identify that ESW flows
Approximately 3 hours after initially identifying the degraded ESW condition, the
  to the Unit 1 East and Unit 2 West CCW heat exchangers were degraded until after the
operators closed the ESW unit cross-tie valves so that each unit was receiving ESW
  ESW cross tie valves were shut. The inspectors determined that communication
flow only from its associated ESW pumps. The licensee did not identify that ESW flows
  inadequacies contributed to the 3 hour delay in the identification of the low ESW flows to
to the Unit 1 East and Unit 2 West CCW heat exchangers were degraded until after the
  the CCW heat exchangers. For example, the Unit 1 high CCW temperature condition
ESW cross tie valves were shut. The inspectors determined that communication
  was not adequately communicated to the Senior Reactor Operators, and the Unit 2
inadequacies contributed to the 3 hour delay in the identification of the low ESW flows to
  operators were not promptly informed of the high Unit 1 CCW temperature.
the CCW heat exchangers. For example, the Unit 1 high CCW temperature condition
  Emergency Classifications
was not adequately communicated to the Senior Reactor Operators, and the Unit 2
  The licensee did not declare an emergency classification for this event. The operations
operators were not promptly informed of the high Unit 1 CCW temperature.
  Shift Manager and Operations Director considered declaring an emergency
Emergency Classifications
                                              17
The licensee did not declare an emergency classification for this event. The operations
Shift Manager and Operations Director considered declaring an emergency


    classification at approximately 4:30 a.m. following the initial indications of degraded
18
    ESW flow. The licensees emergency plan and implementing procedures have no
classification at approximately 4:30 a.m. following the initial indications of degraded
    specific Emergency Condition Categories (ECC), Initiating Condition (IC), or Emergency
ESW flow. The licensees emergency plan and implementing procedures have no
    Action Level (EAL) that would address significantly reduced ESW flow. Emergency
specific Emergency Condition Categories (ECC), Initiating Condition (IC), or Emergency
    Condition Category S-5, Loss of Systems Needed to Achieve/Maintain Hot Shutdown,
Action Level (EAL) that would address significantly reduced ESW flow. Emergency
    was most appropriate; however, the entry conditions required a complete loss of the
Condition Category S-5, Loss of Systems Needed to Achieve/Maintain Hot Shutdown,
    function with entry into EOP FR-H1, Response to Loss of Secondary Heat Sink, or
was most appropriate; however, the entry conditions required a complete loss of the
    FR-C1, Response to Inadequate Core Cooling. The ECC for Site Emergency
function with entry into EOP FR-H1, Response to Loss of Secondary Heat Sink, or
    Coordinator (SEC) Judgement did give a threshold value of In the judgement of the
FR-C1, Response to Inadequate Core Cooling. The ECC for Site Emergency
    SEC: Conditions indicate that plant safety systems may be degraded, and increased
Coordinator (SEC) Judgement did give a threshold value of In the judgement of the
    monitoring of plant functions is needed. Under the licensees procedures this would
SEC: Conditions indicate that plant safety systems may be degraded, and increased
    result in the declaration of an Unusual Event. The inspectors concluded that a
monitoring of plant functions is needed. Under the licensees procedures this would
    declaration of an Unusual Event should have been made due to the degradation of
result in the declaration of an Unusual Event. The inspectors concluded that a
    multiple trains of safety-related equipment on each unit. However, the failure to declare
declaration of an Unusual Event should have been made due to the degradation of
    an Unusual Event was determined to not constitute a violation of regulatory
multiple trains of safety-related equipment on each unit. However, the failure to declare
    requirements.
an Unusual Event was determined to not constitute a violation of regulatory
    Subsequent Response
requirements.
    The licensee was conducting an ESW system surveillance test during the event. While
Subsequent Response
    the performance of the surveillance aided the operators in the identification of the
The licensee was conducting an ESW system surveillance test during the event. While
    degraded ESW flow, continuation of the surveillance test procedure could have
the performance of the surveillance aided the operators in the identification of the
    exacerbated the heat exchanger fouling. For example, the CTS heat exchanger and
degraded ESW flow, continuation of the surveillance test procedure could have
    South CRAC heat exchanger isolation valves were opened per the surveillance
exacerbated the heat exchanger fouling. For example, the CTS heat exchanger and
    procedure, which could have introduced debris into these otherwise clean heat
South CRAC heat exchanger isolation valves were opened per the surveillance
    exchangers. However, subsequent analysis of the heat exchangers by the licensee
procedure, which could have introduced debris into these otherwise clean heat
    determined that heat exchanger performance was not affected.
exchangers. However, subsequent analysis of the heat exchangers by the licensee
.3   Determination of Root Cause for ESW Low Flow Condition
determined that heat exchanger performance was not affected.
   a. Inspection Scope
.3
    The inspectors reviewed the as-found condition of components of the ESW system
Determination of Root Cause for ESW Low Flow Condition
    including the Unit 1 East ESW pump discharge strainer. The inspectors' review
   a.
    included the observation of heat exchanger end bell removal, pump discharge strainer
Inspection Scope
    inspections, and flushing activities. The inspectors also interviewed individuals involved
The inspectors reviewed the as-found condition of components of the ESW system
    in these activities and reviewed the licensees apparent root cause for the ESW low flow
including the Unit 1 East ESW pump discharge strainer. The inspectors' review
    condition.
included the observation of heat exchanger end bell removal, pump discharge strainer
   b. Findings
inspections, and flushing activities. The inspectors also interviewed individuals involved
    The licensee evaluated the root cause of the degraded ESW flow event and concluded
in these activities and reviewed the licensees apparent root cause for the ESW low flow
    that the root cause of the event was the following:
condition.
              "The root cause for this event was that a strainer basket was installed incorrectly
   b.
              during basket replacement activities that occurred in the 1989 time frame. The
Findings
              failure to adjust the height of the basket to align the top edge of the basket with
The licensee evaluated the root cause of the degraded ESW flow event and concluded
              the lip of the strainer body allowed the basket to be placed in compression when
that the root cause of the event was the following:
              the >> 700 lb. strainer lid was reinstalled. The compressive force exerted by the lid
"The root cause for this event was that a strainer basket was installed incorrectly
                                                18
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


          caused the basket mesh to tear in the area of the weld on the baskets vertical
19
          support bracket and was the initiating event for the resultant damage and
caused the basket mesh to tear in the area of the weld on the baskets vertical
          eventual failure of the basket."
support bracket and was the initiating event for the resultant damage and
  The licensee inspected all eight ESW strainer baskets and identified that the Unit 1 East
eventual failure of the basket."
  ESW pump discharge strainer east basket had a weld failure on the height adjustment
The licensee inspected all eight ESW strainer baskets and identified that the Unit 1 East
  bracket that allowed the bracket to bend and drop the basket by approximately 3 inches.
ESW pump discharge strainer east basket had a weld failure on the height adjustment
  This deformation allowed a bypass of debris greater than the 1/8" strainer mesh size.
bracket that allowed the bracket to bend and drop the basket by approximately 3 inches.  
  The passage of debris greater than the normal strainer mesh size resulted in fouling of
This deformation allowed a bypass of debris greater than the 1/8" strainer mesh size.  
  heat exchangers in the ESW system and the consequent flow degradation experienced
The passage of debris greater than the normal strainer mesh size resulted in fouling of
  on August 29, 2001. The licensee reviewed past maintenance performed on the failed
heat exchangers in the ESW system and the consequent flow degradation experienced
  strainer and concluded that the strainer was initially damaged during a basket
on August 29, 2001. The licensee reviewed past maintenance performed on the failed
  replacement that occurred in 1989.
strainer and concluded that the strainer was initially damaged during a basket
  The inspectors assessed the licensees root cause methodology and conclusions and
replacement that occurred in 1989.
  determined that the licensee adequately identified the root cause of the degraded ESW
The inspectors assessed the licensees root cause methodology and conclusions and
  flow event. The inspectors concluded that the licensees approach was reasonable, and
determined that the licensee adequately identified the root cause of the degraded ESW
  adequately addressed contributing causes to the event. The inspectors reviewed
flow event. The inspectors concluded that the licensees approach was reasonable, and
  records from the Unit 1 East ESW pump discharge strainer replacement conducted in
adequately addressed contributing causes to the event. The inspectors reviewed
  1989 and concluded that the strainer installation instructions used in 1989 were
records from the Unit 1 East ESW pump discharge strainer replacement conducted in
  inadequate. The instructions provided for replacement of the strainer baskets,
1989 and concluded that the strainer installation instructions used in 1989 were
  contained in Job Order 723483, lacked sufficient detail to ensure that critical parameters
inadequate. The instructions provided for replacement of the strainer baskets,
  associated with strainer installation were maintained. Specifically, the JO 723483
contained in Job Order 723483, lacked sufficient detail to ensure that critical parameters
  instructions did not contain sufficient detail regarding adjustment of strainer basket
associated with strainer installation were maintained. Specifically, the JO 723483
  height within the strainer housing or verification that the installation prevented basket
instructions did not contain sufficient detail regarding adjustment of strainer basket
  bypass paths greater than 1/8" in size. The inspectors determined that the failure to
height within the strainer housing or verification that the installation prevented basket
  provide adequate instructions for ESW strainer basket maintenance constituted a
bypass paths greater than 1/8" in size. The inspectors determined that the failure to
  violation of regulatory requirements.
provide adequate instructions for ESW strainer basket maintenance constituted a
  10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," stated, in
violation of regulatory requirements.
  part, that activities affecting quality shall be prescribed by documented instructions,
10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," stated, in
  procedures, or drawings of a type appropriate to the circumstances. The inspectors
part, that activities affecting quality shall be prescribed by documented instructions,
  determined that the documented instructions for installation of the ESW strainer
procedures, or drawings of a type appropriate to the circumstances. The inspectors
  baskets, an activity affecting quality, were not of a type appropriate to the
determined that the documented instructions for installation of the ESW strainer
  circumstances. Specifically, the Unit 1 East ESW pump discharge strainer east basket,
baskets, an activity affecting quality, were not of a type appropriate to the
  was installed on April 18, 1989 in accordance with Job Order 723483. The strainer
circumstances. Specifically, the Unit 1 East ESW pump discharge strainer east basket,
  basket installation instructions referenced by Job Order 723483 did not contain
was installed on April 18, 1989 in accordance with Job Order 723483. The strainer
  adequate detail associated with the verification of critical parameters affecting strainer
basket installation instructions referenced by Job Order 723483 did not contain
  basket alignment during installation. The failure to adequately align the ESW strainer
adequate detail associated with the verification of critical parameters affecting strainer
  basket within the strainer housing would allow debris greater than 1/8" in size to bypass
basket alignment during installation. The failure to adequately align the ESW strainer
  the strainer or allow damage to the basket vertical support bracket during strainer cover
basket within the strainer housing would allow debris greater than 1/8" in size to bypass
  re-installation. This issue is identified as Apparent Violation (AV) 50-315/01-17-01;
the strainer or allow damage to the basket vertical support bracket during strainer cover
  50-316/01-17-01. This finding was assessed using the applicable SDP as a potentially
re-installation. This issue is identified as Apparent Violation (AV) 50-315/01-17-01;
  safety significant finding that was preliminarily determined to be Yellow. The details of
50-316/01-17-01. This finding was assessed using the applicable SDP as a potentially
  the SDP evaluation are contained in Section 4OA3.4 below.
safety significant finding that was preliminarily determined to be Yellow. The details of
.4 Specific and Generic Impacts of ESW Debris Intrusion
the SDP evaluation are contained in Section 4OA3.4 below.
                                              19
.4
Specific and Generic Impacts of ESW Debris Intrusion


a. Inspection Scope
20
    Subsequent to the August 2001 debris intrusion event, the licensee conducted
  a.
    engineering and probabilistic evaluations that assessed the specific and generic impacts
Inspection Scope
    of the failed IE ESW system strainer on ESW supported systems. The licensee
Subsequent to the August 2001 debris intrusion event, the licensee conducted
    described their engineering evaluation in Technical Report NTS-2002-002-REP, ESW
engineering and probabilistic evaluations that assessed the specific and generic impacts
    Debris Intrusion Event Evaluation, Revision 0, completed in January 2002. The
of the failed IE ESW system strainer on ESW supported systems. The licensee
    licensee described their probabilistic evaluation in Technical Report
described their engineering evaluation in Technical Report NTS-2002-002-REP, ESW
    NTS-2002-010-REP, Debris Intrusion Into the Essential Service Water System -
Debris Intrusion Event Evaluation, Revision 0, completed in January 2002. The
    Probabilistic Evaluation, Revision 0, completed in April 2002. The inspectors reviewed
licensee described their probabilistic evaluation in Technical Report
    the evaluations, assessed their fidelity to the August 2001 data, and used the
NTS-2002-010-REP, Debris Intrusion Into the Essential Service Water System -
    evaluations and other design information to determine the capability of ESW supported
Probabilistic Evaluation, Revision 0, completed in April 2002. The inspectors reviewed
    safety-related systems to perform their functions during the August 2001 event and
the evaluations, assessed their fidelity to the August 2001 data, and used the
    applicable design basis events.
evaluations and other design information to determine the capability of ESW supported
b. Findings
safety-related systems to perform their functions during the August 2001 event and
b.1 Engineering Evaluation
applicable design basis events.
    The licensees engineering evaluation examined the August 2001 debris intrusion event
  b.
    and the potential consequences of a similar debris intrusion following a single unit loss
Findings
    of offsite power (LOOP) event. The evaluation considered debris entrainment within the
  b.1
    intake structure and ESW system, the hydraulic characteristics of the ESW-D/G system,
Engineering Evaluation
    and the performance characteristics of the ESW-D/G heat exchangers. As a separate
The licensees engineering evaluation examined the August 2001 debris intrusion event
    part of the engineering evaluation, the licensee developed a revised single unit LOOP
and the potential consequences of a similar debris intrusion following a single unit loss
    initiating event frequency, a human performance reliability analysis of the operators
of offsite power (LOOP) event. The evaluation considered debris entrainment within the
    response to a similar debris intrusion event, and a plant-specific Large Early Release
intake structure and ESW system, the hydraulic characteristics of the ESW-D/G system,
    Frequency (LERF) analysis.
and the performance characteristics of the ESW-D/G heat exchangers. As a separate
    Debris Entrainment
part of the engineering evaluation, the licensee developed a revised single unit LOOP
    Overall, the licensees engineering evaluation concluded that debris intrusion events,
initiating event frequency, a human performance reliability analysis of the operators
    assuming a failed 1 East ESW strainer, could not be precluded. Debris intrusion into
response to a similar debris intrusion event, and a plant-specific Large Early Release
    the ESW system was expected to occur following a single unit LOOP event, a seismic
Frequency (LERF) analysis.
    event that causes a LOOP, or during a severe storm that resulted in a LOOP event.
Debris Entrainment
    Though not explicitly stated, the engineering evaluation focused on a single unit LOOP
Overall, the licensees engineering evaluation concluded that debris intrusion events,
    event. A detailed review of the potential for and consequences of a dual unit LOOP
assuming a failed 1 East ESW strainer, could not be precluded. Debris intrusion into
    event were not evaluated. During discussions with the inspectors, the plant staff
the ESW system was expected to occur following a single unit LOOP event, a seismic
    indicated their belief that a single unit LOOP event would result in entrainment of the
event that causes a LOOP, or during a severe storm that resulted in a LOOP event.  
    largest amount of debris.
Though not explicitly stated, the engineering evaluation focused on a single unit LOOP
    The licensees engineering evaluation determined that low vertical flow velocities were
event. A detailed review of the potential for and consequences of a dual unit LOOP
    required to entrain debris in the intake structure, on the order of 0.15 feet/second for
event were not evaluated. During discussions with the inspectors, the plant staff
    sand and 0.30 feet/second for shells. Once entrained, the evaluation calculated that the
indicated their belief that a single unit LOOP event would result in entrainment of the
    debris could take up to an hour to re-settle to the intake structure floor depending on the
largest amount of debris.
    hydrofoil effect associated with the shells. The plant staff assumed that intake structure
The licensees engineering evaluation determined that low vertical flow velocities were
    cross flows, created during the August 2001 event and expected to exist following a
required to entrain debris in the intake structure, on the order of 0.15 feet/second for
    single unit LOOP event, would entrain the greatest amount of debris. However, the
sand and 0.30 feet/second for shells. Once entrained, the evaluation calculated that the
    licensees engineering evaluation did not assess the potential for intake structure cross
debris could take up to an hour to re-settle to the intake structure floor depending on the
                                              20
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


21
flows or intake structure debris to be entrained by flow perturbations following a dual unit
flows or intake structure debris to be entrained by flow perturbations following a dual unit
LOOP.
LOOP.
Line 927: Line 1,138:
that flow rates on the order of 140 gallons/minute were necessary to maintain the debris
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
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
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,
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
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 engineering evaluation recognized that lower flow rates could maintain shells within
the flow stream if shell hydrofoil effects were considered.
the flow stream if shell hydrofoil effects were considered.
The inspectors reviewed the licensees records of circulating and service water intake
The inspectors reviewed the licensees records of circulating and service water intake
structure inspections and determined the intake structure often contained debris,
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
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
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
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
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
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
essential service water system flow rates, severe weather, and LOOP events were all
conditions capable of causing intake structure flow disturbances.
conditions capable of causing intake structure flow disturbances.
The inspectors reviewed the August 2001 circulating and essential service water system
The inspectors reviewed the August 2001 circulating and essential service water system
operating information and determined that significant changes in the intake structure
operating information and determined that significant changes in the intake structure
flow patterns were the most likely cause for debris entrainment. The changed flow
flow patterns were the most likely cause for debris entrainment. The changed flow
patterns entrained debris, previously located in quiescent flow areas, and transported
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
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
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
perturbations of the intake structure water inventory; the continued operation of the
Line 953: Line 1,164:
The inspectors also determined that a larger short-term ingestion of debris would likely
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
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
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 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 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
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
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
over a shorter period of time than that created by the circulating water system cross-flow
Line 964: Line 1,175:
The licensees engineering evaluation determined an approximate percentage of
The licensees engineering evaluation determined an approximate percentage of
blocked ESW-D/G heat exchanger tubes that would be necessary to cause the
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
August 2001 observed degraded flow conditions. Initial results indicated that plugging in
                                          21


22
excess of 90% of the heat exchanger tubes would be necessary to cause the observed
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
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
some of the heat exchangers, the licensee rejected the engineering evaluation initial
conclusion that a high percentage of tubes were blocked.
conclusion that a high percentage of tubes were blocked.
As an alternate hypothesis, the licensee conjectured that the August 2001 degraded
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
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
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
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
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
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
ESW-D/G flow rates, the licensee assumed that only a limited number of heat
exchanger tubes would not be available for heat transfer.
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
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
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
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
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
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
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
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
averaging the remaining lowest recorded flow values. The evaluation supported the
single location debris buildup position by assuming that the debris piles were inherently
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
unstable and could not be maintained, due to a constant loss of material, if the source of
Line 992: Line 1,203:
The inspectors determined that the engineering evaluation likely overestimated the
The inspectors determined that the engineering evaluation likely overestimated the
percentage of blocked tubes necessary to cause the observed August 2001 degraded
percentage of blocked tubes necessary to cause the observed August 2001 degraded
flow conditions. The inspectors noted that the licensees evaluation did not consider
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
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
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
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
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
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
in excess of 50% but less than the near 90% values initially calculated in the licensees
Line 1,002: Line 1,213:
The inspectors performed independent flow hydraulic calculations and concluded that a
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
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
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
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
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
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
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
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
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
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
most likely caused by a combination of heat exchanger tube blockage and a
non-uniform debris pile buildup on the heat exchanger tubesheet.
non-uniform debris pile buildup on the heat exchanger tubesheet.
                                            22


23
The inspectors evaluated the computer logs of ESW-D/G flow data for the August 2001
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
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
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.
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
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
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
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
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
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
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-
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
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
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
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
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,
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.
with a minimum ESW-D/G flow rate of 200 gallons/minute.
Based upon information provided in the licensees engineering evaluation, the
Based upon information provided in the licensees engineering evaluation, the
inspectors concurred with the licensees contention that a debris pile buildup was most
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
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
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
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
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.
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
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
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
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
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
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
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
exchanger intake head volume. Additionally, the presence of distributed pressure
drops, due to multiple debris piles, would also reduce the effectiveness of operator
drops, due to multiple debris piles, would also reduce the effectiveness of operator
actions to flush debris from the system.
actions to flush debris from the system.
Line 1,051: Line 1,262:
to maintain D/G lube oil and jacket water coolers within maximum allowed parameters
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
assuming variable degree and location of heat exchanger plugging, tube fouling, and
design event loading. Overall, the evaluation determined that approximately
design event loading. Overall, the evaluation determined that approximately
140 gallons/minute ESW-D/G flow was required to assure minimum D/G performance
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
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
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
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
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
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
indicated that the minimum ESW-D/G flow required to maintain the D/G lube oil and
                                            23


24
jacket water cooler within maximum allowed parameters increased rapidly with
jacket water cooler within maximum allowed parameters increased rapidly with
increased tube blockage beyond the levels stated above.
increased tube blockage beyond the levels stated above.
The inspectors determined that the licensees engineering evaluation did not consider
The inspectors determined that the licensees engineering evaluation did not consider
several factors which would affect the calculated minimum flows necessary to support
several factors which would affect the calculated minimum flows necessary to support
continued D/G functioning. Examples included: 1) entry and exit pressure losses
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
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
heat exchanger tubes; 2) an increased ESW-D/G flow resistance caused by the
Line 1,071: Line 1,282:
reduced ESW-D/G flow rates, and; 3) changes in the ESW-D/G heat transfer rates due
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
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
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
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
ESW-D/G flow rate, necessary to support continued D/G functioning, was significantly
Line 1,079: Line 1,290:
In conjunction with the engineering analysis, the licensee proposed that both the
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
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
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
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
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
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
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
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
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
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.
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
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
frequency of 0.004 per year should be used to evaluate the August 2001 and a potential
Line 1,093: Line 1,304:
The inspectors reviewed the licensees analysis and determined that the proposed
The inspectors reviewed the licensees analysis and determined that the proposed
initiating event frequency may be an underestimation for the following reasons:
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
Although the licensees analysis credited the plant-specific electrical distribution
        eliminating events that the licensee believed could not occur at the plant), there
system as being unique and better than assumed in the generic cases (by
        was no similar effort done for the plant-specific electrical distribution system to
eliminating events that the licensee believed could not occur at the plant), there
        determine if any plant-specific events could occur that could not occur at the
was no similar effort done for the plant-specific electrical distribution system to
        other plants. Thus, only a limited scope comparison was performed. (One
determine if any plant-specific events could occur that could not occur at the
        example would be that, although hurricane events were eliminated due to plants
other plants. Thus, only a limited scope comparison was performed. (One
        location, vulnerability to events caused by ice storms were not explicitly
example would be that, although hurricane events were eliminated due to plants
        considered.)
location, vulnerability to events caused by ice storms were not explicitly
*       The licensee included data from sites like Indian Point, Nine Mile Point and
considered.)
        Fitzpatrick that share control of switchyard activities among differing licensees.
*
                                            24
The licensee included data from sites like Indian Point, Nine Mile Point and
Fitzpatrick that share control of switchyard activities among differing licensees.  


          Data from these sites may not be appropriate for use in determining a plant-
25
          centered loss of offsite power initiating event frequency for D.C. Cook because
Data from these sites may not be appropriate for use in determining a plant-
          D.C. Cook may be more vulnerable to a common cause failure or switchyard
centered loss of offsite power initiating event frequency for D.C. Cook because
          error that may result in a loss of offsite power to both units.
D.C. Cook may be more vulnerable to a common cause failure or switchyard
*         The licensees assumption that the dual unit LOOP initiator will not entrain debris
error that may result in a loss of offsite power to both units.
          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
The licensees assumption that the dual unit LOOP initiator will not entrain debris
          event frequency was not acceptable. The generic frequency of severe weather
into the ESW-D/G was not considered a valid assumption. Therefore, the
          events, which are the most probable cause for dual unit LOOP events, was
licensees elimination of dual unit initiators from inclusion in the overall initiating
          approximately 0.007 per year, about twice the licensees estimate for the single
event frequency was not acceptable. The generic frequency of severe weather
          unit initiator.
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
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
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
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
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
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
frequency (0.004 versus 0.046). Based upon licensee provided information and
engineering judgement, the inspectors used a single unit LOOP initiating frequency of
engineering judgement, the inspectors used a single unit LOOP initiating frequency of
0.01 for subsequent NRC risk analyses.
0.01 for subsequent NRC risk analyses.
Line 1,128: Line 1,342:
The licensee performed an analysis to estimate the human error probability (HEP)
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
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
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
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
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
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
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
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
analyses, the licensee concluded that credit could be taken for the actions since
Line 1,138: Line 1,352:
intrusion event.
intrusion event.
The inspectors reviewed the analysis methodology used by the licensee and concluded
The inspectors reviewed the analysis methodology used by the licensee and concluded
that the methodology was acceptable and was applied correctly. The inspectors also
that the methodology was acceptable and was applied correctly. The inspectors also
determined that the licensees assumption of credit for the operators proper
determined that the licensees assumption of credit for the operators proper
implementation of the unproceduralized and untrained recovery actions was appropriate
implementation of the unproceduralized and untrained recovery actions was appropriate
Line 1,146: Line 1,360:
licensees HEP estimate of 0.05 was reasonable if sufficient time was available
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
(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 hours). The 0.05 was
ESW-D/G flow through the heat exchanger exceeds 5 to 6 hours). The 0.05 was
considered optimistic for recovery times of 2 hours or less. For a dual unit LOOP event,
considered optimistic for recovery times of 2 hours or less. For a dual unit LOOP event,
the inspectors determined that an HEP of 0.13 was appropriate when the operators
the inspectors determined that an HEP of 0.13 was appropriate when the operators
                                            25


    would have approximately 1 hour to response. This is the value used for subsequent
26
    NRC risk analysis of a dual unit LOOP event. If the operators did not have sufficient
would have approximately 1 hour to response. This is the value used for subsequent
    time to respond, less than 1 hour, the inspectors determined that ESW-D/G flow from
NRC risk analysis of a dual unit LOOP event. If the operators did not have sufficient
    the opposite Unit could not be credited for valve cycling or heat exchanger flushing
time to respond, less than 1 hour, the inspectors determined that ESW-D/G flow from
    actions. In these cases, an HEP of 1.0 was considered appropriate.
the opposite Unit could not be credited for valve cycling or heat exchanger flushing
    Large Early Release Frequency
actions. In these cases, an HEP of 1.0 was considered appropriate.
    Prior to the August 2001 ESW-D/G debris intrusion event, the licensee developed a
Large Early Release Frequency
    plant-specific large early release frequency (LERF) estimate. Using methodology
Prior to the August 2001 ESW-D/G debris intrusion event, the licensee developed a
    described in NRC document NUREG/CR-6595 and figure 2-2 of the document, the
plant-specific large early release frequency (LERF) estimate. Using methodology
    licensee estimated a plant-specific LERF to CDF ratio of 0.1. During discussions with
described in NRC document NUREG/CR-6595 and figure 2-2 of the document, the
    the NRC of the engineering evaluation of the August 2001 intrusion event, the licensee
licensee estimated a plant-specific LERF to CDF ratio of 0.1. During discussions with
    proposed that risk analyses of the event should use the plant-specific LERF to CDF ratio
the NRC of the engineering evaluation of the August 2001 intrusion event, the licensee
    value of 0.1.
proposed that risk analyses of the event should use the plant-specific LERF to CDF ratio
    The inspectors reviewed documentation provided by the licensee to support their
value of 0.1.
    proposed use of a LERF to CDF ratio of 0.1. The inspectors determined that the
The inspectors reviewed documentation provided by the licensee to support their
    licensee evaluation only modeled a single unit LOOP, therefore adequate time was
proposed use of a LERF to CDF ratio of 0.1. The inspectors determined that the
    postulated for ESW-D/G recovery and for onsite and offsite emergency response. As a
licensee evaluation only modeled a single unit LOOP, therefore adequate time was
    result of the credit taken for these actions, a large fraction of the core damage
postulated for ESW-D/G recovery and for onsite and offsite emergency response. As a
    sequences were allocated to the non-large early release category. Only approximately
result of the credit taken for these actions, a large fraction of the core damage
    16 percent of the revised core damage sequences were considered in calculating the
sequences were allocated to the non-large early release category. Only approximately
    LERF.
16 percent of the revised core damage sequences were considered in calculating the
    In the NRCs risk evaluations of the ESW-D/G debris intrusion event that lead to core
LERF.
    damage sequences, a station blackout event was modeled. In these cases,
In the NRCs risk evaluations of the ESW-D/G debris intrusion event that lead to core
    containment hydrogen igniters were not considered available due to an absence of
damage sequences, a station blackout event was modeled. In these cases,
    required power. In such scenarios, recent NRC studies (e.g., studies for the
containment hydrogen igniters were not considered available due to an absence of
    containment significance determination process and for the resolution of the generic
required power. In such scenarios, recent NRC studies (e.g., studies for the  
    issue for the combustible gas issue) indicated that the conditional probability of large
containment significance determination process and for the resolution of the generic
    early release given a core damage event for an ice condenser containment was
issue for the combustible gas issue) indicated that the conditional probability of large
    approximately 0.82.
early release given a core damage event for an ice condenser containment was
    Considering that both the licensees and the NRCs LERF values were developed using
approximately 0.82.
    NRC guidance, though with differing assumptions, and the potential uncertainty in
Considering that both the licensees and the NRCs LERF values were developed using
    assessing the effectiveness of the licensees onsite and offsite emergency response
NRC guidance, though with differing assumptions, and the potential uncertainty in
    efforts, a LERF value of 0.4 was used in subsequent NRC risk analyses.
assessing the effectiveness of the licensees onsite and offsite emergency response
b.2 Probabilistic Evaluation
efforts, a LERF value of 0.4 was used in subsequent NRC risk analyses.
    Subsequent to and in support of the licensees engineering evaluation discussed above,
  b.2
    the licensee performed a probabilistic evaluation of the impact of a failed ESW-D/G
Probabilistic Evaluation
    strainer on the plants response following a LOOP event. The evaluation assumed a
Subsequent to and in support of the licensees engineering evaluation discussed above,
    single or dual unit LOOP as the initiating event [Block 1] and identified a logical
the licensee performed a probabilistic evaluation of the impact of a failed ESW-D/G
    sequence of steps [Blocks 2 through 9] which could lead to D/G failure as a result of
strainer on the plants response following a LOOP event. The evaluation assumed a
    debris intrusion into the ESW-D/G flow. The licensees probabilistic evaluation
single or dual unit LOOP as the initiating event [Block 1] and identified a logical
    considered the likelihood of the sub-events which collectively comprised an ESW-D/G
sequence of steps [Blocks 2 through 9] which could lead to D/G failure as a result of
    debris intrusion event. The probabilistic evaluation considered debris intrusion events
debris intrusion into the ESW-D/G flow. The licensees probabilistic evaluation
                                              26
considered the likelihood of the sub-events which collectively comprised an ESW-D/G
debris intrusion event. The probabilistic evaluation considered debris intrusion events


following both single and dual unit LOOPs. The licensee selected subjective
27
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
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
described in NUREG/CR-5424. The individual probabilities were then combined to
determine the conditional failure probability of each sequence of steps. These results
determine the conditional failure probability of each sequence of steps. These results
were then incorporated into the plant probabilistic risk analysis model to determine
were then incorporated into the plant probabilistic risk analysis model to determine
resultant increases in the core damage frequency (CDF) and large early release
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
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.
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
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
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
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
modify SPAR model risk analysis results. Based upon information provided in the
licensees probabilistic evaluation, the inspectors developed a common cause failure
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
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
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
Headquarters staff determined that the delta CDF and LERF values for the issue were
Line 1,215: Line 1,430:
methodology and the individual block results were as follows.
methodology and the individual block results were as follows.
Overall Methodology
Overall Methodology
The inspectors reviewed the overall evaluation methodology and NUREG/CR 5424. The
The inspectors reviewed the overall evaluation methodology and NUREG/CR 5424. The
inspectors determined that the overall methodology was reasonable and that 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
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
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
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
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. 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
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
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.
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
Several sequences appeared to have been affected by the licensees use of their
subjective probability scale, as described below.
subjective probability scale, as described below.
Block 1: Loss of Offsite Power
Block 1: Loss of Offsite Power
The licensees analysis assumed the LOOP event, either single or dual unit, as a given.
The licensees analysis assumed the LOOP event, either single or dual unit, as a given.  
Therefore, this probability was set equal to 1.0.
Therefore, this probability was set equal to 1.0.
The inspectors used a similar approach to developing their common cause factor.
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.
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
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
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
intake structure contained a sufficient amount of debris with the probability that changes
                                          27


28
to the intake structure flow caused the entrainment of a sufficient amount of debris to
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
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
information, the licensee developed probabilities for each of several sub-blocks
identified necessary to construct the overall probability. The resultant Block single unit
identified necessary to construct the overall probability. The resultant Block single unit
and dual unit LOOP probabilities were 0.1033 and 0.0189, respectively.
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
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.
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
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
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
initiating event frequency; 2) debris, brought into the intake structure and of concern for
Line 1,256: Line 1,471:
Block 2, the inspectors did not further evaluate these items.
Block 2, the inspectors did not further evaluate these items.
Of the remaining items, the inspectors determined that engineering judgement
Of the remaining items, the inspectors determined that engineering judgement
accounted for differences in the probabilities assumed for Items 3 and 4. Specifically,
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
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,
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
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
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
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 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
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
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
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
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
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
the intake structure during unit refueling outages, on an approximate once every
9 month time frame.
9 month time frame.
Block 3: Suspended Debris Reaches the ESW Pump Suction
Block 3: Suspended Debris Reaches the ESW Pump Suction
The licensee assumed that, if sufficient debris was suspended in the intake structure
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
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
ESW pump suction and be ingested. Therefore, the licensee assigned a probability of
0.99 to this block.
0.99 to this block.
The inspectors used a similar approach to developing their common cause factor.
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.
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
Block 4: Failed Strainer Basket is in Service During a LOOP Event
                                          28


29
The licensee evaluated this block as a combination of probabilities that the failed 1 East
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
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
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
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
evaluation indicated a single unit LOOP probability of 1.0 and a dual unit LOOP
probability of 0.77.
probability of 0.77.
Line 1,289: Line 1,504:
Block 4 and concurred with the licensees general characterization of the sub-blocks and
Block 4 and concurred with the licensees general characterization of the sub-blocks and
the resultant probabilities.
the resultant probabilities.
Blocks 5 and 6: ESW Flow is High and Ingested Debris Bypasses the 1 East ESW
Blocks 5 and 6: ESW Flow is High and Ingested Debris Bypasses the 1 East ESW
Strainer
Strainer
The licensees analysis proposed that all sequences, which could result in the D/Gs
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
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
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
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.
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
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
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.
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
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
retained in the strainer housing, probability of high flow and strainer bypass equal to
0.14.
0.14.
Based upon the information provided in the evaluation, the inspectors could not
Based upon the information provided in the evaluation, the inspectors could not
independently confirm the basis for the proposed high ESW flow rate steps.
independently confirm the basis for the proposed high ESW flow rate steps.  
Specifically, the inspectors could not validate the licensees technical basis for
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
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
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
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
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
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
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
ESW pump suction was transported into the ESW-D/G flow stream, probability of
strainer bypass for all flow conditions equals 1.0.
strainer bypass for all flow conditions equals 1.0.
Block 7: Ingested Debris Reaches the Unit 2 D/G Heat Exchangers
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
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
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
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
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.
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
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
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
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
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
30
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
system pre-LOOP alignments would result in sufficient Unit cross flow to carry debris
from Unit 1 to Unit 2.
from Unit 1 to Unit 2.
Line 1,331: Line 1,546:
that the post-LOOP starting of all four ESW pumps would change the system flow
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
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
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
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.
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,
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,
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
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
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
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.
the proposed step probability of 0.25 was appropriate.
                                          30


    Block 8: ESW Flow Degradation Impacts D/G Function
31
    In this block, the licensee estimated the probability that debris, having reached the D/G
Block 8: ESW Flow Degradation Impacts D/G Function
    coolers, would impact the D/G function. Through a review of information gathered from
In this block, the licensee estimated the probability that debris, having reached the D/G
    the August 2001 event, the licensee concluded that only 1 of the 4 D/Gs were actually
coolers, would impact the D/G function. Through a review of information gathered from
    impacted by the debris intrusion. As a result, the licensee assumed a per D/G impact
the August 2001 event, the licensee concluded that only 1 of the 4 D/Gs were actually
    probability of 0.25. In their development of the event trees for these sequences, the
impacted by the debris intrusion. As a result, the licensee assumed a per D/G impact
    licensee further treated this failure probability as an independent random variable. This
probability of 0.25. In their development of the event trees for these sequences, the
    approach resulted in an overall failure probability for the 4 D/G system of approximately
licensee further treated this failure probability as an independent random variable. This
    0.004.
approach resulted in an overall failure probability for the 4 D/G system of approximately
    Based upon an independent review of operator and computer logs from the
0.004.
    August 2001 event, the inspectors determined that 3 D/Gs were impacted by the debris.
Based upon an independent review of operator and computer logs from the
    Specifically, the 1AB D/G experienced less than reliable flow indication conditions, and
August 2001 event, the inspectors determined that 3 D/Gs were impacted by the debris.  
    the two Unit 2 D/Gs were trending to a less than reliable flow indication condition. The
Specifically, the 1AB D/G experienced less than reliable flow indication conditions, and
    1CD D/G experienced degraded flow which levelized at approximately
the two Unit 2 D/Gs were trending to a less than reliable flow indication condition. The
    350 gallons/minute and was not considered substantially impacted by the debris
1CD D/G experienced degraded flow which levelized at approximately
    intrusion. Based, in part, on the observed August 2001 debris intrusion D/G impacts,
350 gallons/minute and was not considered substantially impacted by the debris
    the inspectors concluded that the probability of a debris intrusion event impacting an
intrusion. Based, in part, on the observed August 2001 debris intrusion D/G impacts,
    individual D/G was approximately 0.75. The inspectors assumed a probability that all
the inspectors concluded that the probability of a debris intrusion event impacting an
    4 D/Gs would be impacted by a debris intrusion event to be approximately 0.25.
individual D/G was approximately 0.75. The inspectors assumed a probability that all
    Block 9: Condition is Not Identified and Cleared by the Operators
4 D/Gs would be impacted by a debris intrusion event to be approximately 0.25.  
    In this block the licensee proposed to assign the HEP values previously developed and
Block 9: Condition is Not Identified and Cleared by the Operators
    evaluated by the inspectors as a part of the engineering evaluation. The
In this block the licensee proposed to assign the HEP values previously developed and
    licensee-proposed HEP values were 0.054, for a single unit LOOP event, and 0.13, for a
evaluated by the inspectors as a part of the engineering evaluation. The
    dual unit LOOP event, respectively.
licensee-proposed HEP values were 0.054, for a single unit LOOP event, and 0.13, for a
    The inspectors reviewed and concurred with the methodology used to develop these
dual unit LOOP event, respectively.
    probabilities as discussed in Section 4OA3.4.b.1 of this report.
The inspectors reviewed and concurred with the methodology used to develop these
b.3 Essential Service Water Supported Safety Function Capability Assessment
probabilities as discussed in Section 4OA3.4.b.1 of this report.
    Emergency Diesel Generators
  b.3
    The ESW system provided essential cooling for the D/G turbocharger air aftercoolers,
Essential Service Water Supported Safety Function Capability Assessment
    and the lubricating oil and jacket water coolers. Each D/G could be aligned to either the
Emergency Diesel Generators
    East or West ESW supply header in the associated unit via normal and alternate ESW
The ESW system provided essential cooling for the D/G turbocharger air aftercoolers,
    supply valves. The associated safety train supplied normal ESW cooling while the
and the lubricating oil and jacket water coolers. Each D/G could be aligned to either the
    opposite safety train supplied alternate ESW cooling. The D/G ESW supply valve
East or West ESW supply header in the associated unit via normal and alternate ESW
    control logic was designed to fully open both the normal and alternate ESW motor
supply valves. The associated safety train supplied normal ESW cooling while the
    operated supply valves in response to a diesel start signal.
opposite safety train supplied alternate ESW cooling. The D/G ESW supply valve
    Based upon independent review of operator and computer logs from the August 2001
control logic was designed to fully open both the normal and alternate ESW motor
    event, post shutdown inspections of the ESW system heat exchangers, requirements
operated supply valves in response to a diesel start signal.
    specified in the licensees UFSAR, and the licensees engineering and probabilistic
Based upon independent review of operator and computer logs from the August 2001
    evaluation of the specific and generic impacts of the August 2001 event, the inspectors
event, post shutdown inspections of the ESW system heat exchangers, requirements
    determined that one of the two Unit 1 D/Gs experienced a less than reliable ESW-D/G
specified in the licensees UFSAR, and the licensees engineering and probabilistic
                                              31
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


32
flow condition and may not have been able to perform its intended function, had it been
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,
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
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
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
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
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
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
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
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
ESW-D/G flow rates may have resulted in the D/Gs being unable to continue to function
in a very short time.
in a very short time.
Line 1,401: Line 1,617:
debris intrusion event could cause ESW flow degradation to the heat exchangers for all
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
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
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
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,
concern. Because the D/Gs supported the operation of accident mitigation equipment,
the inspectors determined that this issue was associated with the Reactor Safety-
the inspectors determined that this issue was associated with the Reactor Safety-
Mitigating Systems cornerstone. During a Phase 1 Significance Determination Process
Mitigating Systems cornerstone. During a Phase 1 Significance Determination Process
(SDP) screening of issue, the inspectors concluded that the issue represented a
(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.
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
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.
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
In order to properly incorporate the additional licensee-provided information, a Phase 3
SDP assessment was performed.
SDP assessment was performed.
Line 1,416: Line 1,632:
inspection finding (failed ESW strainer which allowed a significant amount of debris to
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
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
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
damage frequency (CDF), stemming from the identified failed ESW strainer was
assessed. The assessment focused on LOOP events which could: 1) cause debris,
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;
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
2) result in the Units to rely upon the D/Gs for onsite AC power. The assessment
assumed:
assumed:
*       An initiating event frequency of 0.01 for a single unit LOOP and 0.007 for a dual
*
        unit LOOP.
An initiating event frequency of 0.01 for a single unit LOOP and 0.007 for a dual
*       An exposure time of 1 year, the maximum timeframe used for these time
unit LOOP.
        calculations, based upon evidence which indicated that the ESW strainer failure
*
        had likely occurred during initial installation in 1989.
An exposure time of 1 year, the maximum timeframe used for these time
                                          32
calculations, based upon evidence which indicated that the ESW strainer failure
had likely occurred during initial installation in 1989.


*     Cross flows within the intake structure, following a single unit LOOP event, would
33
      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 hours.
Cross flows within the intake structure, following a single unit LOOP event, would  
*     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
      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 hours.
      ESW-D/G flow through the D/G heat exchangers within 1 hour.
*
*     Debris entrained within the intake structure would resettle to the intake structure
Inrush flows into the intake structure, following a dual unit LOOP event, would
      floor within 1 hour after the flow perturbation or change had subsided.
entrain sufficient debris in the ESW-D/G flow stream to cause less than reliable
*     Frequency-weighted non-recovery curves associated with plant-centered, grid,
ESW-D/G flow through the D/G heat exchangers within 1 hour.
      severe weather, and extreme weather events for a single unit LOOP; and,
*
      frequency-weighted non-recovery curves associated with severe and extreme
Debris entrained within the intake structure would resettle to the intake structure
      weather events for a dual unit LOOP.
floor within 1 hour after the flow perturbation or change had subsided.
*     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
Frequency-weighted non-recovery curves associated with plant-centered, grid,
      unit LOOP and 0.13 for a dual unit LOOP.
severe weather, and extreme weather events for a single unit LOOP; and,
*     The electrical distribution system does not include capability to electrically
frequency-weighted non-recovery curves associated with severe and extreme
      cross-tie between the Unit 1 and Unit 2 safety related busses.
weather events for a dual unit LOOP.
*     The motor driven auxiliary feedwater systems could be cross tied between Units
*
      for a single unit LOOP.
Operator recovery from less than reliable ESW-D/G heat exchanger flow
*     A common cause failure factor was used to account for probabilities that:
conditions were characterized by human error probabilities of 0.054 for a single
      1) insufficient debris would be available within the intake structure; 2) the failed
unit LOOP and 0.13 for a dual unit LOOP.
      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
The electrical distribution system does not include capability to electrically
      Unit 2, and; 4) all debris intrusion events may not result in all of the D/Gs
cross-tie between the Unit 1 and Unit 2 safety related busses.
      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
The motor driven auxiliary feedwater systems could be cross tied between Units
      failure factor.
for a single unit LOOP.
*     Mitigating equipment was assumed to be available once offsite power was
*
      recovered. Potential unavailabilities of these components, due to degraded
A common cause failure factor was used to account for probabilities that:  
      ESW cooling flow, was not considered.
1) insufficient debris would be available within the intake structure; 2) the failed
*     The conditional probability of a large early release, given a core damage event
1 East ESW strainer may not be in service during the LOOP event; 3) pre-LOOP
      for an ice condenser containment, was assumed to be 0.4.
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
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
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
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
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
events, the dominant sequence was a station blackout with a failure to recover AC
power before station battery depletion.
power before station battery depletion.
                                          33


    The inspectors and NRC Headquarters staff also evaluated the impact of this issue on
34
    the LERF. Using a conditional probability of a large early release, given a core damage
The inspectors and NRC Headquarters staff also evaluated the impact of this issue on
    event for an ice condenser containment, of 0.4, the staff determined the delta LERF for
the LERF. Using a conditional probability of a large early release, given a core damage
    the issue was 7.1E-06 (Yellow) for a dual unit LOOP.
event for an ice condenser containment, of 0.4, the staff determined the delta LERF for
    The Regional Senior Risk Analyst and the NRC Headquarters staff concluded that the
the issue was 7.1E-06 (Yellow) for a dual unit LOOP.
    risk significance of the inspection finding, based on the change in CDF due to internal
The Regional Senior Risk Analyst and the NRC Headquarters staff concluded that the
    events and LERF considerations, to be Yellow. A Yellow finding represents a finding of
risk significance of the inspection finding, based on the change in CDF due to internal
    substantial safety significance.
events and LERF considerations, to be Yellow. A Yellow finding represents a finding of
b.4 Other ESW Support Systems
substantial safety significance.
    Component Cooling Water System
  b.4
    The CCW system provided cooling to heat exchangers in the following risk-significant
Other ESW Support Systems
    systems: residual heat removal, ECCS, spent fuel pool cooling, reactor coolant pump
Component Cooling Water System
    thermal barrier, and containment air recirculating. Each Unit's CCW system was
The CCW system provided cooling to heat exchangers in the following risk-significant
    arranged in three flow circuits: two parallel safeguards equipment trains, and one
systems: residual heat removal, ECCS, spent fuel pool cooling, reactor coolant pump
    miscellaneous services train which can be served by either safeguards train.
thermal barrier, and containment air recirculating. Each Unit's CCW system was
    During the August 2001 debris intrusion event, ESW flow to the Unit 1 East and Unit 2
arranged in three flow circuits: two parallel safeguards equipment trains, and one
    West CCW heat exchangers became degraded. Essential Service Water system flow
miscellaneous services train which can be served by either safeguards train.
    to the Unit 1 East CCW heat exchanger was as low as 2100 gpm but increased to
During the August 2001 debris intrusion event, ESW flow to the Unit 1 East and Unit 2
    3900 gpm following cycling of the inlet and outlet ESW valves. The Unit 2 West CCW
West CCW heat exchangers became degraded. Essential Service Water system flow
    heat exchanger ESW flow decreased to approximately 2400 gpm but improved to
to the Unit 1 East CCW heat exchanger was as low as 2100 gpm but increased to
    approximately 5000 gpm following cycling of the ESW inlet and outlet valve. Section 9.8
3900 gpm following cycling of the inlet and outlet ESW valves. The Unit 2 West CCW
    of the UFSAR stated that the minimum ESW flow required to support post-accident
heat exchanger ESW flow decreased to approximately 2400 gpm but improved to
    CCW heat loads was 5000 gpm, but up to 8700 gpm of ESW flow was required to
approximately 5000 gpm following cycling of the ESW inlet and outlet valve. Section 9.8
    support normal operation and cooldown. Additionally, Section 9.5.2 of the UFSAR
of the UFSAR stated that the minimum ESW flow required to support post-accident
    stated that the CCW system was designed and analyzed to operate at CCW heat
CCW heat loads was 5000 gpm, but up to 8700 gpm of ESW flow was required to
    exchanger outlet temperatures up to 120°F during cooldown and accident conditions.
support normal operation and cooldown. Additionally, Section 9.5.2 of the UFSAR
    Although debris intrusion reduced the maximum ESW flow capability for the Unit 1 East
stated that the CCW system was designed and analyzed to operate at CCW heat
    and Unit 2 West CCW heat exchangers below design requirements, the inspectors
exchanger outlet temperatures up to 120°F during cooldown and accident conditions.  
    determined that the CCW heat exchanger outlet temperatures did not exceed the 120°F
Although debris intrusion reduced the maximum ESW flow capability for the Unit 1 East
    analysis limit during the event.
and Unit 2 West CCW heat exchangers below design requirements, the inspectors
    Because Unit 1 was in Mode 5 at the time of the event, its CCW system supported
determined that the CCW heat exchanger outlet temperatures did not exceed the 120°F
    decay heat removal system operation, but it was not required to support post-accident
analysis limit during the event.
    heat loads. Additionally, the debris intrusion event did not degrade flow to the Unit 1
Because Unit 1 was in Mode 5 at the time of the event, its CCW system supported
    West CCW train and reactor coolant system temperatures remained stable during the
decay heat removal system operation, but it was not required to support post-accident
    event. Based on the availability of the opposite train and the stable reactor coolant
heat loads. Additionally, the debris intrusion event did not degrade flow to the Unit 1
    system operation during and immediately following the event, the inspectors determined
West CCW train and reactor coolant system temperatures remained stable during the
    that the safety impact of degraded ESW flow to the Unit 1 East CCW heat exchanger
event. Based on the availability of the opposite train and the stable reactor coolant
    was minimal.
system operation during and immediately following the event, the inspectors determined
    Because Unit 2 was in Mode 1 at the time of the degraded flow event, the licensee
that the safety impact of degraded ESW flow to the Unit 1 East CCW heat exchanger
    entered TS 3.7.3.1 and placed the Unit in Mode 5 within the required TS limiting
was minimal.
    condition for operation time limits. During the event, the Unit 2 East CCW train
Because Unit 2 was in Mode 1 at the time of the degraded flow event, the licensee
    remained available to provide cooling for normal operation and accident heat loads.
entered TS 3.7.3.1 and placed the Unit in Mode 5 within the required TS limiting
                                              34
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.  


35
Based on the availability of the opposite CCW train and licensee compliance with
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
TS 3.7.3.1 for one inoperable CCW train, the inspectors determined that the safety
Line 1,518: Line 1,747:
Auxiliary Feedwater Pump Room Cooling and Emergency Water Supply
Auxiliary Feedwater Pump Room Cooling and Emergency Water Supply
The ESW system provided the safety-related water source to each AFW pump and
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,
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
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
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
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
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
capability to provide secondary plant makeup to Unit 2. The inspectors considered the
following factors:
following factors:
*       The condensate storage tank provided the normal suction supply to the AFW
*
        pumps and remained available during the event. Consequently, the inspectors
The condensate storage tank provided the normal suction supply to the AFW
        determined that the loss of the emergency AFW pump suction water supply from
pumps and remained available during the event. Consequently, the inspectors
        the ESW system did not significantly impact the ability of the AFW system to
determined that the loss of the emergency AFW pump suction water supply from
        perform its safety function.
the ESW system did not significantly impact the ability of the AFW system to
*       The TDAFWP room is cooled by two 100 percent capacity coolers. Because the
perform its safety function.
        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
The TDAFWP room is cooled by two 100 percent capacity coolers. Because the
        did not adversely impact the ability of the TDAFWP to perform its safety function.
Unit 2 East TDAFWP room cooler had adequate cooling capacity to maintain
*       The Unit 1 West and both Unit 2 MDAFWPs room coolers remained operable
TDAFWP room temperatures, the loss of the Unit 2 West TDAFWP room cooler
        during and immediately following the event. Consequently, the inspectors
did not adversely impact the ability of the TDAFWP to perform its safety function.  
        determined that because of the availability of redundant trains of MDAFWPs
*
        sufficient AFW system capability was available to support Unit 2 during this
The Unit 1 West and both Unit 2 MDAFWPs room coolers remained operable
        event.
during and immediately following the event. Consequently, the inspectors
*       The annunciator response procedures for high MDAFWP room temperature
determined that because of the availability of redundant trains of MDAFWPs
        included proceduralized compensatory actions for degraded room cooling.
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
Based on these factors, the inspectors concluded that the impact of the ESW debris
intrusion on the AFW system was minimal.
intrusion on the AFW system was minimal.
Control Room Air Conditioning System (CRAC)
Control Room Air Conditioning System (CRAC)
The CRAC units provided cooling to maintain temperatures at which control room
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,
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
"Control Room Emergency Ventilation System," at control room temperatures less than
or equal to 102°F, vital control room equipment remained within the manufacturers
or equal to 102°F, vital control room equipment remained within the manufacturers
recommended operating range. The inspectors reviewed control room logs and
recommended operating range. The inspectors reviewed control room logs and
determined that control room temperatures did not exceed 80°F during and immediately
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
following the degraded ESW event. Based on the ability of the CRAC units to
adequately maintain control room temperatures, the inspectors determined that the
adequately maintain control room temperatures, the inspectors determined that the
impact of this event on the control room ventilation system was minimal.
impact of this event on the control room ventilation system was minimal.
                                        35


    Containment Spray System
36
    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
Containment Spray System
    pressure from exceeding the design value. With the exception of alignment of the Unit 2
The primary purpose of the Containment Spray System is to spray cool water into the
    East CTS heat exchanger for ESW flushing on August 30, 2001, the ESW supplies to
containment atmosphere in the event of a loss-of-coolant to prevent containment
    the CTS heat exchangers were isolated during the event. Subsequent inspections and
pressure from exceeding the design value. With the exception of alignment of the Unit 2
    engineering evaluations of the CTS system identified no significant fouling or
East CTS heat exchanger for ESW flushing on August 30, 2001, the ESW supplies to
    obstructions of flow. The inspectors concluded that the debris intrusion event had
the CTS heat exchangers were isolated during the event. Subsequent inspections and
    minimal safety impact on the CTS system.
engineering evaluations of the CTS system identified no significant fouling or
.5   Adequacy of Corrective Actions
obstructions of flow. The inspectors concluded that the debris intrusion event had
   a. Inspection Scope
minimal safety impact on the CTS system.
    The inspectors attended licensee meetings, interviewed personnel, observed
.5
    maintenance activities, reviewed testing plans, and performed system walkdowns as
Adequacy of Corrective Actions
    part of the assessment of the adequacy of the licensees corrective actions for the
   a.
    restoration of:
Inspection Scope
    *       Emergency Diesel Generators
The inspectors attended licensee meetings, interviewed personnel, observed
    *       Component Cooling Water System
maintenance activities, reviewed testing plans, and performed system walkdowns as
    *       Other safety-related components served by ESW
part of the assessment of the adequacy of the licensees corrective actions for the
   b. Findings
restoration of:
    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
Emergency Diesel Generators
    before the equipment could be restored to full service. The inspectors determined that
*
    the licensees corrective actions were prompt, thorough, and effective.
Component Cooling Water System
    Emergency Diesel Generators
*
    The licensee inspected the cooling systems of all D/Gs immediately following the event.
Other safety-related components served by ESW
    For each D/G, the licensee inspected and cleaned (as necessary) both air after-coolers,
   b.
    the lube oil cooler, the jacket water cooler, and supply piping.
Findings
    In addition to cooling system inspection and cleaning, the licensee installed ESW
The licensee established a series of recovery and support teams in order to identify
    differential pressure instrumentation on each lube oil cooler to assist in the future
equipment, procedural and personnel performance issues that needed to be addressed
    identification of cooling system blockage. The licensee also removed the automatic
before the equipment could be restored to full service. The inspectors determined that
    opening control logic for the alternate D/G cooling ESW supply valves to preclude cross
the licensees corrective actions were prompt, thorough, and effective.
    train transport of debris into the D/G cooling systems.
Emergency Diesel Generators
    Component Cooling Water System
The licensee inspected the cooling systems of all D/Gs immediately following the event.  
    The licensee removed the end bells of the Unit 1 East CCW heat exchanger and
For each D/G, the licensee inspected and cleaned (as necessary) both air after-coolers,
    performed inspections. The licensee identified sand, zebra mussel shells, and large
the lube oil cooler, the jacket water cooler, and supply piping.
    debris. The licensee considered large debris as debris that was greater than 1/8 inch.
In addition to cooling system inspection and cleaning, the licensee installed ESW
    The debris blocked approximately 10 percent of the tubes. The licensee removed the
differential pressure instrumentation on each lube oil cooler to assist in the future  
                                              36
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


    debris and hydro-lanced the heat exchanger tubes. The ESW supply and return piping
37
    for the CCW heat exchanger was cleaned as part of the overall system flush.
debris and hydro-lanced the heat exchanger tubes. The ESW supply and return piping
    Other Safety-Related Components Served by ESW
for the CCW heat exchanger was cleaned as part of the overall system flush.
    The licensee initiated a recovery team to specifically address the scope of corrective
Other Safety-Related Components Served by ESW
    action necessary to restore the ESW system to service. The team evaluated other
The licensee initiated a recovery team to specifically address the scope of corrective
    components served by ESW and recommended corrective actions. These corrective
action necessary to restore the ESW system to service. The team evaluated other
    actions included:
components served by ESW and recommended corrective actions. These corrective
    *       Inspecting and cleaning the CRAC units as necessary. The air conditioners
actions included:
            were determined to be very clean with only minimal material.
*
    *       Inspecting and cleaning the AFW pump room coolers. The Unit 1 East
Inspecting and cleaning the CRAC units as necessary. The air conditioners
            MDAFWP room cooler and one of the two room coolers to the Unit 2 TDAFWP
were determined to be very clean with only minimal material.
            were identified to have significant blockage. These coolers were cleaned and
*
            returned to service.
Inspecting and cleaning the AFW pump room coolers. The Unit 1 East
    *       The Unit 1 East ESW pump discharge strainer was opened and inspected. The
MDAFWP room cooler and one of the two room coolers to the Unit 2 TDAFWP
            east strainer basket was determined to have significant damage and bypass.
were identified to have significant blockage. These coolers were cleaned and
            The west strainer basket was determined to have some smaller amount of
returned to service.
            bypass over the top of the basket. Both baskets were replaced.
*
    *       Two radiation monitors which drew sample flow from the ESW trains were
The Unit 1 East ESW pump discharge strainer was opened and inspected. The
            cleaned.
east strainer basket was determined to have significant damage and bypass.  
    *       Instrumentation connected to the Unit 1 East ESW system was inspected and
The west strainer basket was determined to have some smaller amount of
            flushed.
bypass over the top of the basket. Both baskets were replaced.
    *       Portions of ESW piping that could not be inspected internally or were not
*
            assured of achieving high flow rates during flushing activities were
Two radiation monitors which drew sample flow from the ESW trains were
            Ultra-Sonically tested. The tests indicated that portions of the piping did contain
cleaned.
            debris. For example, one 12 inch diameter pipe contained approximately
*
            2 inches of debris. The licensee flushed the material from the system.
Instrumentation connected to the Unit 1 East ESW system was inspected and
    *       The licensee performed an ESW system flow verification surveillance test in
flushed.
            order to ensure that all components served by the ESW system had been
*
            restored to operable.
Portions of ESW piping that could not be inspected internally or were not
.6   Adequacy of Overall Corrective Actions to Address Recurrence of Sand/Silt Buildup
assured of achieving high flow rates during flushing activities were
    Problems
Ultra-Sonically tested. The tests indicated that portions of the piping did contain
   a. Inspection Scope
debris. For example, one 12 inch diameter pipe contained approximately
    The inspectors attended licensee meetings, interviewed personnel, observed
2 inches of debris. The licensee flushed the material from the system.
    maintenance activities, reviewed testing plans, and performed system walkdowns as
*
    part of the assessment of the adequacy of the licensees overall corrective actions.
The licensee performed an ESW system flow verification surveillance test in
   b. Findings
order to ensure that all components served by the ESW system had been
                                              37
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


    The inspectors reviewed the licensees corrective actions which included the following:
38
    *       all 8 ESW strainer baskets were inspected and replaced;
The inspectors reviewed the licensees corrective actions which included the following:
    *       detailed procedural guidance was given for strainer installation;
*
    *       a temporary modification to prevent the alternate ESW supply valves to the D/Gs
all 8 ESW strainer baskets were inspected and replaced;
            from going open on a D/G start was installed;
*
    *       the normal configuration of the alternate ESW supply valves to the D/Gs was
detailed procedural guidance was given for strainer installation;
            revised; and
*
    *       the new ESW strainer baskets received additional inspection to provide
a temporary modification to prevent the alternate ESW supply valves to the D/Gs
            reasonable assurance of the new strainer baskets structural capability.
from going open on a D/G start was installed;
    The inspectors concluded that the licensees actions appeared reasonable to prevent
*
    recurrence.
the normal configuration of the alternate ESW supply valves to the D/Gs was
.7   Assessment of Interaction of the Maintenance Activities on the Non-Safety Related
revised; and
    Circulating Water System with Operation of the ESW System
*
   a. Inspection Scope
the new ESW strainer baskets received additional inspection to provide
    At the time of the event, the CW center intake crib was isolated in order to repair
reasonable assurance of the new strainer baskets structural capability.
    previously identified damage. The CW pump 13 discharge valve, 1-WMO-13, was
The inspectors concluded that the licensees actions appeared reasonable to prevent
    degraded and could not be fully closed. The plant had been operating for several
recurrence.
    months with the center intake isolated. The inspectors assessed the interaction and
.7
    potential impact of these non-safety related issues on the functioning of the ESW
Assessment of Interaction of the Maintenance Activities on the Non-Safety Related
    system.
Circulating Water System with Operation of the ESW System
                                              38
   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.


   b. Findings
39
    The inspectors determined that CW system flow rates and configuration had a direct
   b.
    impact upon the functioning of the safety-related ESW system. However, if the Unit 1
Findings
    East ESW pump discharge strainer east basket had been performing as designed, large
The inspectors determined that CW system flow rates and configuration had a direct
    debris would not have entered the ESW system and the operability of components
impact upon the functioning of the safety-related ESW system. However, if the Unit 1
    served by ESW would not have been challenged.
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
4OA4 Cross-Cutting Issues
.1   Human Performance Issues During Degraded ESW Flow Event
.1
   a. Inspection Scope
Human Performance Issues During Degraded ESW Flow Event
    The inspectors assessed operator performance during the degraded ESW flow event
   a.
    relative to the human performance cross-cutting issue. The inspectors reviewed control
Inspection Scope
    room logs, plant process computer data, and control room chart recorder data. In
The inspectors assessed operator performance during the degraded ESW flow event
    addition, the inspectors interviewed operators and reviewed operator statements.
relative to the human performance cross-cutting issue. The inspectors reviewed control
   b. Findings
room logs, plant process computer data, and control room chart recorder data. In
    The inspectors identified several weaknesses in the response of control room operators
addition, the inspectors interviewed operators and reviewed operator statements.
    to the degraded ESW flow event of August 29, 2001. These weaknesses involved
   b.
    operator control board monitoring and procedural adherence. Specifically, the
Findings
    inspectors identified the following issues:
The inspectors identified several weaknesses in the response of control room operators
    *       Upon identifying that both Unit D/Gs were inoperable due to low ESW flow, the
to the degraded ESW flow event of August 29, 2001. These weaknesses involved
            Unit 2 Senior Reactor Operator entered the action statement for TS 3.0.3. As
operator control board monitoring and procedural adherence. Specifically, the
            described in the TS bases, TS 3.0.3 delineated the measures to be taken for
inspectors identified the following issues:
            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
Upon identifying that both Unit D/Gs were inoperable due to low ESW flow, the
            D/Gs, TS 3.0.3 was not the appropriate TS action statement to enter during this
Unit 2 Senior Reactor Operator entered the action statement for TS 3.0.3. As
            event. The Unit Supervisor stated that he assumed that TS 3.0.3 would apply
described in the TS bases, TS 3.0.3 delineated the measures to be taken for
            with two inoperable D/Gs, and he did not read each TS 3.8.1.1 action statement.
those circumstances not directly provided for in the TS action statements. The
            The inspectors noted that TS 3.8.1.1.e specified additional actions not covered
inspectors determined that, because TS 3.8.1.1.e addressed two inoperable
            by TS 3.0.3, such as demonstrating the operability of offsite power sources. In
D/Gs, TS 3.0.3 was not the appropriate TS action statement to enter during this
            this case, the licensee complied with the action time limits specified in
event. The Unit Supervisor stated that he assumed that TS 3.0.3 would apply
            TS 3.8.1.1.e; thus, there was no impact from the failure to enter the appropriate
with two inoperable D/Gs, and he did not read each TS 3.8.1.1 action statement.  
            TS action statement.
The inspectors noted that TS 3.8.1.1.e specified additional actions not covered
    *       Based on a review of Plant Process Computer data and control room chart
by TS 3.0.3, such as demonstrating the operability of offsite power sources. In
            recorder data, the inspectors concluded that indications of degraded ESW
this case, the licensee complied with the action time limits specified in
            system performance (i.e., ESW flow below UFSAR minimum) were available to
TS 3.8.1.1.e; thus, there was no impact from the failure to enter the appropriate
            the control room operators at least 3 hours prior to the initial identification of
TS action statement.
            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
Based on a review of Plant Process Computer data and control room chart
            that control boards shall be monitored for changing indications, adverse trends,
recorder data, the inspectors concluded that indications of degraded ESW
            and abnormal indications and Step 4.2.4 stated that during normal plant
system performance (i.e., ESW flow below UFSAR minimum) were available to
            operations, the reactor operator should perform a walkdown of all control room
the control room operators at least 3 hours prior to the initial identification of
                                              39
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


          panels every 60 minutes. The inspectors determined that the control room
40
          operators failure to effectively implement the recommendations contained in
panels every 60 minutes. The inspectors determined that the control room
          OHI-4017 contributed to the failure to promptly identify degraded ESW system
operators failure to effectively implement the recommendations contained in
          performance.
OHI-4017 contributed to the failure to promptly identify degraded ESW system
*         Based on a review of CCW system temperatures recorded on chart recorder
performance.
          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
Based on a review of CCW system temperatures recorded on chart recorder
          over 3 hours. Annunciator response procedure 01-OHP 4024.104, Drop 85,
1-SG-10, the inspectors determined that the Unit 1 East CCW heat exchanger
          "East CCW Hx Discharge Temp Abnormal," Step 3.3, stated that if the CCW
outlet temperature exceeded the 95°F abnormal temperature alarm setpoint for
          heat exchanger outlet temperature cannot be maintained less than 95°F, enter
over 3 hours. Annunciator response procedure 01-OHP 4024.104, Drop 85,
          Abnormal Procedure 01-OHP 4022.016.001, "Malfunction of the CCW System."
"East CCW Hx Discharge Temp Abnormal," Step 3.3, stated that if the CCW
          Although the reactor operator reported receipt of the associated abnormal
heat exchanger outlet temperature cannot be maintained less than 95°F, enter
          temperature alarm, the control room operators did not enter Abnormal Procedure
Abnormal Procedure 01-OHP 4022.016.001, "Malfunction of the CCW System."  
          01-OHP 4022.016.001, contrary to instructions contained in 01-OHP 4024.104.
Although the reactor operator reported receipt of the associated abnormal
*         Although the Unit 1 East CCW outlet abnormal temperature alarm actuated
temperature alarm, the control room operators did not enter Abnormal Procedure
          during the event, receipt of the alarm and the operators subsequent difficulty in
01-OHP 4022.016.001, contrary to instructions contained in 01-OHP 4024.104.
          controlling CCW temperature were not recorded in the control room log and not
*
          effectively communicated to the operations shift management. The inspectors
Although the Unit 1 East CCW outlet abnormal temperature alarm actuated
          determined that the operators failure to log receipt of the CCW abnormal
during the event, receipt of the alarm and the operators subsequent difficulty in
          temperature alarm and effectively communicate this abnormal condition was not
controlling CCW temperature were not recorded in the control room log and not
          consistent with instructions contained in OHI-2212 and OHI-4017. Specifically,
effectively communicated to the operations shift management. The inspectors
          OHI-2212, Step 4.5.7 required, in part, that the actuation of significant
determined that the operators failure to log receipt of the CCW abnormal
          annunciators and unexpected system transients shall be contained in the control
temperature alarm and effectively communicate this abnormal condition was not
          room log and OHI-4017, Step 4.2.11, required, in part, that the US shall be
consistent with instructions contained in OHI-2212 and OHI-4017. Specifically,
          notified immediately of any indication that is not responding as expected.
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
The inspectors determined that the failure to adequately apply TS requirements and
implement procedures associated with control board monitoring, logkeeping, and
implement procedures associated with control board monitoring, logkeeping, and
annunciator response had a credible impact on safety and therefore were more than a
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
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
and promptly correct degradation of safety related equipment and therefore impact the
reliability and availability of a safety system. Because these performance deficiencies
reliability and availability of a safety system. Because these performance deficiencies
contributed to delays in identifying degradation of the ESW and CCW mitigating
contributed to delays in identifying degradation of the ESW and CCW mitigating
systems, the inspectors determined that these human performance weaknesses were
systems, the inspectors determined that these human performance weaknesses were
associated with the mitigating systems cornerstone. Although this issue adversely
associated with the mitigating systems cornerstone. Although this issue adversely
impacted the licensee's response to the August 29, 2001 event, none of the
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
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.
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
Consequently, the inspectors concluded that this issue was of very low safety
significance (Green).
significance (Green).
Technical Specification 6.8.1 required, in part, that written procedures shall be
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.
implemented for those activities recommended in Appendix "A" of RG 1.33, Revision 2.
Regulatory Guide 1.33, "Quality Assurance Program Requirements," Revision 2,
Regulatory Guide 1.33, "Quality Assurance Program Requirements," Revision 2,
Appendix "A," recommended, in part, that written procedures cover the following
Appendix "A," recommended, in part, that written procedures cover the following
activities: (1) authorities and responsibilities for safe operation, (2) log entries, and
activities: (1) authorities and responsibilities for safe operation, (2) log entries, and
(3) abnormal, off normal or alarm conditions. The inspectors determined that
(3) abnormal, off normal or alarm conditions. The inspectors determined that
                                            40


    OHI-2212, "Narrative and Miscellaneous Logkeeping"; OHI-4017, "Control Board
41
    Monitoring"; and 01-OHP 4024.104, "Annunciator #104 Response: Essential Service
OHI-2212, "Narrative and Miscellaneous Logkeeping"; OHI-4017, "Control Board
    Water and Component Cooling"; were written to implement the requirements of
Monitoring"; and 01-OHP 4024.104, "Annunciator #104 Response: Essential Service
    TS 6.8.1. Contrary to TS 6.8.1, the control room operators failed to implement the
Water and Component Cooling"; were written to implement the requirements of
    instructions contained in (1) OHI-2212, step 4.5.7, (2) OHI-4017, steps 4.2.8 and 4.2.11,
TS 6.8.1. Contrary to TS 6.8.1, the control room operators failed to implement the
    and (3) 01-OHP.4024.104, drop 85, step 3.3, during the degraded ESW event of
instructions contained in (1) OHI-2212, step 4.5.7, (2) OHI-4017, steps 4.2.8 and 4.2.11,
    August 29, 2001. Specifically, the operators failed to (1) monitor the control boards for
and (3) 01-OHP.4024.104, drop 85, step 3.3, during the degraded ESW event of
    changing indications, adverse trends, and abnormal indications, (2) effectively
August 29, 2001. Specifically, the operators failed to (1) monitor the control boards for
    communicate receipt of an abnormal temperature alarm for the CCW heat exchanger,
changing indications, adverse trends, and abnormal indications, (2) effectively
    and (3) enter the CCW abnormal operating procedure as directed by the abnormal
communicate receipt of an abnormal temperature alarm for the CCW heat exchanger,
    temperature alarm response procedure. Because of the very low safety significance,
and (3) enter the CCW abnormal operating procedure as directed by the abnormal
    this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the
temperature alarm response procedure. Because of the very low safety significance,
    NRC Enforcement Policy (NCV 50-315-01-17-02(DRP); 50-316-01-017-02(DRP)). This
this violation is being treated as a Non-Cited Violation consistent with Section VI.A of the
    violation is in the licensees corrective action program as CR 01250062.
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
4OA6 Meeting
    Exit Meeting
Exit Meeting
    The inspector presented the inspection results to licensee management listed below on
The inspector presented the inspection results to licensee management listed below on
    May 17, 2002. The licensee acknowledged the findings presented. No proprietary
May 17, 2002. The licensee acknowledged the findings presented. No proprietary
    information was identified.
information was identified.
                                                41


                                  KEY POINTS OF CONTACT
42
KEY POINTS OF CONTACT
Licensee
Licensee
G. Arent, Manager, Regulatory Affairs
G. Arent, Manager, Regulatory Affairs
Line 1,790: Line 2,055:
Anton Vegel, Branch Chief Reactor Projects Branch 6
Anton Vegel, Branch Chief Reactor Projects Branch 6
Sonia Burgess, Senior Reactor Analyst, Division of Reactor Safety
Sonia Burgess, Senior Reactor Analyst, Division of Reactor Safety
                                              42


                LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
43
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
Opened
50-315/01-17-01   AV    Essential Service Water strainer maintenance instructions not
50-315/01-17-01
50-316/01-17-01         appropriate to the circumstances.
50-316/01-17-01
50-315/01-17-02   NCV    Human performance weaknesses during the degraded essential
AV
50-316/01-17-02         service water event of August 29, 2001 associated with control
Essential Service Water strainer maintenance instructions not
                          board monitoring and procedural adherence.
appropriate to the circumstances.
50-315/01-17-02
50-316/01-17-02
NCV
Human performance weaknesses during the degraded essential
service water event of August 29, 2001 associated with control
board monitoring and procedural adherence.
Closed
Closed
50-315/01-17-02   NCV    Human performance weaknesses during the degraded essential
50-315/01-17-02
50-316/01-17-02         service water event of August 29, 2001 associated with control
50-316/01-17-02
                          board monitoring and procedural adherence.
NCV
Human performance weaknesses during the degraded essential
service water event of August 29, 2001 associated with control
board monitoring and procedural adherence.
Discussed
Discussed
None
None
                                          43


                            LIST OF ACRONYMS USED
44
AEP   American Electric Power
LIST OF ACRONYMS USED
AFW   Auxiliary Feedwater System
AEP
ATR   Administrative Technical Requirement
American Electric Power
CCW   Component Cooling Water
AFW
CDF   Core Damage Frequency
Auxiliary Feedwater System
CFR   Code of Federal Regulations
ATR
CR     Condition Report
Administrative Technical Requirement
CRAC   Control Room Air Conditioning
CCW
CTS   Containment Spray System
Component Cooling Water
CW     Circulating Water
CDF
D/G   Emergency Diesel Generator
Core Damage Frequency
DRP   Division of Reactor Projects
CFR
EAL   Emergency Action Level
Code of Federal Regulations
ECC   Emergency Condition Categories
CR
EOP   Emergency Operating Procedure
Condition Report
EP     Emergency Preparedness
CRAC
ESW   Essential Service Water
Control Room Air Conditioning
FIN   Finding
CTS
JO     Job Order
Containment Spray System
HELB   High Energy Line Break
CW
IC     Initiating Condition
Circulating Water
IMC   Inspection Manual Chapter
D/G
LOOP   Loss of Off-Site Power
Emergency Diesel Generator
MDAFWP Motor Driven Auxiliary Feedwater Pump
DRP
MHP   Maintenance Head Procedure
Division of Reactor Projects
NRC   Nuclear Regulatory Commission
EAL
NRR   Nuclear Reactor Regulation
Emergency Action Level
OA     Other Activities
ECC
OHI   Operations Head Instruction
Emergency Condition Categories  
OHP   Operations Head Procedure
EOP
PDR   Public Document Room
Emergency Operating Procedure
PMI   Plant Managers Instruction
EP
PMP   Plant Managers Procedure
Emergency Preparedness
PMT   Post-maintenance Testing
ESW
PPC   Plant Process Computer
Essential Service Water
PRA   Probability Risk Assessment
FIN
RCS   Reactor Coolant System
Finding
RHR   Residual Heat Removal
JO
SDP   Significance Determination Process
Job Order
SEC   Site Emergency Coordinator
HELB
SRA   Senior Reactor Analysts
High Energy Line Break
SRO   Senior Reactor Operator
IC
SSC   Structures, Systems, and Components
Initiating Condition
STP   Surveillance Test Procedure
IMC
TBD   To Be Determined
Inspection Manual Chapter
TDAFWP Turbine Driven Auxiliary Feedwater Pump
LOOP
                                      44
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


TS   Technical Specification
45
UFSAR Updated Final Safety Analysis Report
TS
UHS   Ultimate Heat Sink
Technical Specification
URI   Unresolved Item
UFSAR
US   Unit Supervisor
Updated Final Safety Analysis Report
VIO   Violation
UHS
                                    45
Ultimate Heat Sink
URI
Unresolved Item
US
Unit Supervisor
VIO
Violation


                          LIST OF DOCUMENTS REVIEWED
46
LIST OF DOCUMENTS REVIEWED
Work Requests/Job Orders
Work Requests/Job Orders
JO 01095031       Unit 2 Traveling Water Screen Driving Inspection
JO 01095031
JO 01242065       Inspect and Clean Unit 1 ESW and Circulating
Unit 2 Traveling Water Screen Driving Inspection
                  Water Pump Bays
JO 01242065
JO 01244049       Open and clean 1-HV-ACR-1 (North CRAC)
Inspect and Clean Unit 1 ESW and Circulating
JO 01244055       Drain and flush 1-HV-AFP-EAC, Unit 1 East
Water Pump Bays
                  MDAFWP room cooler
JO 01244049
JO 01244059       Inspect, clean, and flush 1-HV-AFP-T1AC, the
Open and clean 1-HV-ACR-1 (North CRAC)
                  Unit 1 east TDAFWP room cooler
JO 01244055
JO 01244069       Inspect/clean ESW side of heat exchanger
Drain and flush 1-HV-AFP-EAC, Unit 1 East
                  1-QT-110-AB
MDAFWP room cooler
JO 01244071       Inspect/clean ESW side of heat exchanger
JO 01244059
                  1-QT-110-CD
Inspect, clean, and flush 1-HV-AFP-T1AC, the
JO 01244072       Inspect/clean ESW side of heat exchanger
Unit 1 east TDAFWP room cooler
                  1-QT-131-AB
JO 01244069
JO 01244073       Inspect/clean ESW side of heat exchanger
Inspect/clean ESW side of heat exchanger
                  1-QT-131-CD
1-QT-110-AB
JO 01244089       Open/inspect/flush 2-HV-ACR-1 (North CRAC)
JO 01244071
JO 01244092       2-HV-AFP-WAC Drain and Flush West Cooler
Inspect/clean ESW side of heat exchanger
JO 01244094       2-HV-AFP-T2AC Drain and Flush T2AC Cooler
1-QT-110-CD  
JO 01244097       Inspect/clean ESW side of heat exchanger
JO 01244072
                  2-QT-110-CD
Inspect/clean ESW side of heat exchanger
JO 01244099       Inspect/clean ESW side of heat exchanger
1-QT-131-AB
                  2-QT-131-CD
JO 01244073
JO 01244096       Inspect/clean ESW side of heat exchanger
Inspect/clean ESW side of heat exchanger
                  2-QT-110-AB
1-QT-131-CD
JO 01244098       Inspect/clean ESW side of heat exchanger
JO 01244089
                  2-QT-131-AB
Open/inspect/flush 2-HV-ACR-1 (North CRAC)
JO R0088138       Unit 1 Screenhouse Diving, Cleaning and Repairs
JO 01244092
JO R0100035       2-HE-18W Open Shell Side of Heat Exchanger
2-HV-AFP-WAC Drain and Flush West Cooler
                  for Inspection
JO 01244094
                                            46
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


JO R0210330         Open shell side of 1-HE-18E for inspection
47
                    (Unit 1 East CTS heat exchanger)
JO R0210330
JO R021036         Unit 1 Screenhouse Diving, Cleaning and Repairs
Open shell side of 1-HE-18E for inspection
JO R0217652         Inspect and clean 1-HE-15E (Unit 1 East CCW
(Unit 1 East CTS heat exchanger)
                    heat exchanger)
JO R021036
JO R0096582         Inspect and clean 1-HE-15W (Unit 1 West CCW
Unit 1 Screenhouse Diving, Cleaning and Repairs
                    heat exchanger)
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)
Condition Reports (CRs)
CR 00273076         Silts/sand from the lake settling out in the dead   September 28, 2000
CR 00273076
                    leg section of ESW piping
Silts/sand from the lake settling out in the dead
CR 00295037         1-PP-7W-MTR Failed To Start                         October 21, 2000
leg section of ESW piping
CR 01019031         SA-2001-REA-003, Perform Zebra Mussel               January 19, 2001
September 28, 2000
                    Assessment During Year 2001
CR 00295037
CR 01242007         2-ESW-162-CD Emergency Diesel Jacket Water         August 30, 2001
1-PP-7W-MTR Failed To Start
                    Cooler QT-131-CD tube side vent valve is
October 21, 2000
                    blocked and could not be flushed out
CR 01019031
CR 01242008         Procedural Deficiency in 02 OHP                     August 30, 2001
SA-2001-REA-003, Perform Zebra Mussel
                    4030.STP.022E, the ESW system test - Step
Assessment During Year 2001
                    4.30.3, which aligns the north CRAC for flushing
January 19, 2001
                    is missing from the procedure
CR 01242007
CR 01242009         2-ESW-163-CD, the Unit 2 CD D/G jacket water       August 30, 2001
2-ESW-162-CD Emergency Diesel Jacket Water
                    cooler tube side drain, is clogged and not allowing
Cooler QT-131-CD tube side vent valve is
                    flow to pass when opened
blocked and could not be flushed out  
CR 01242010         2-ESW-162-AB Emergency Diesel Jacket Water         August 30, 2001
August 30, 2001
                    Cooler QT-131-AB tube side vent valve is blocked
CR 01242008
                    and could not be flushed out
Procedural Deficiency in 02 OHP
CR 01242013         Slit/mud intrusion into Unit 1 and 2 ESW systems   August 29, 2001
4030.STP.022E, the ESW system test - Step
                    renders CCW and D/G inoperable
4.30.3, which aligns the north CRAC for flushing
CR 01243013         2-HV-AFP-T2AC, the Unit 2 West TDAFWP room         August 31, 2001
is missing from the procedure
                    cooler, does not appear to be functioning
August 30, 2001
CR 01243015         Unit 1 East auxiliary feedwater pump room cooler   August 31, 2001
CR 01242009
                    flow (56 gpm) was less then minimum required
2-ESW-163-CD, the Unit 2 CD D/G jacket water
                    (57 gpm)
cooler tube side drain, is clogged and not allowing
                                                47
flow to pass when opened
August 30, 2001
CR 01242010
2-ESW-162-AB Emergency Diesel Jacket Water
Cooler QT-131-AB tube side vent valve is blocked
and could not be flushed out  
August 30, 2001
CR 01242013
Slit/mud intrusion into Unit 1 and 2 ESW systems
renders CCW and D/G inoperable
August 29, 2001
CR 01243013
2-HV-AFP-T2AC, the Unit 2 West TDAFWP room
cooler, does not appear to be functioning  
August 31, 2001
CR 01243015
Unit 1 East auxiliary feedwater pump room cooler
flow (56 gpm) was less then minimum required
(57 gpm)  
August 31, 2001


CR 01243036 Both Unit 1 and Unit 2 D/Gs declared inoperable     August 29, 2001
48
            due to low ESW flow. This resulted in Unit 1
CR 01243036
            entering a RED shutdown risk path.
Both Unit 1 and Unit 2 D/Gs declared inoperable
CR 01243038 Evaluate August 30, 2001, greater than 20           August 30, 2001
due to low ESW flow. This resulted in Unit 1
            percent power reduction on Unit 2 due to
entering a RED shutdown risk path.
            degraded ESW flow for potential Maintenance
August 29, 2001
            Rule impact
CR 01243038
CR 01243039 PRA analysis of Unit 2 indicates yellow risk status August 30, 2001
Evaluate August 30, 2001, greater than 20
            in that the west CCW heat exchanger is not
percent power reduction on Unit 2 due to
            receiving the required 5000 gpm ESW flow
degraded ESW flow for potential Maintenance
CR 01244010 1-WMO-12 circulating water pump PP-2-2             September 1, 2001
Rule impact
            discharge shutoff valve
August 30, 2001
CR 01244011 1-WMO-11 Circulating Water Pump PP-2-1             August 31, 2001
CR 01243039
            Discharge Shutoff Valve
PRA analysis of Unit 2 indicates yellow risk status
CR 01244016 Wood, mussel shells, and debris larger than         September 1, 2001
in that the west CCW heat exchanger is not
            expected identified during inspection on the Unit 1
receiving the required 5000 gpm ESW flow
            east CCW heat exchanger
August 30, 2001
CR 01244019 Degraded ESW flow documented in CR                 September 1, 2001
CR 01244010
            01242013 may indicate that the GL 89-13
1-WMO-12 circulating water pump PP-2-2
            program is inadequate
discharge shutoff valve
CR 01245030 During inspection of Unit 1 East ESW pump           September 2, 2001
September 1, 2001
            discharge strainer baskets, large bypass flow
CR 01244011
            paths were identified.
1-WMO-11 Circulating Water Pump PP-2-1
CR 01246015 Forced outage schedule does not match actual       September 3, 2001
Discharge Shutoff Valve
            work planning and execution for Unit 1 West
August 31, 2001
            ESW pump work
CR 01244016
CR 01247001 Declaration of unusual event during the Unit 1     September 3, 2001
Wood, mussel shells, and debris larger than
            and Unit 2 ESW restriction event on August 29,
expected identified during inspection on the Unit 1
            2001 would have been prudent
east CCW heat exchanger
CR 01247041 Open, inspect and clean 1-HV-AFP-WAC (Unit 1       September 4, 2001
September 1, 2001
            west MDAFWP room cooler) to determine extent
CR 01244019
            of ESW debris intrusion
Degraded ESW flow documented in CR
CR 01247050 NRC identified several human performance           September 4, 2001
01242013 may indicate that the GL 89-13
            weaknesses during the ESW fouling event of
program is inadequate
            August 29, 2001. These included weaknesses in
September 1, 2001
            communication, possible training deficiencies for
CR 01245030
            abnormal procedures, inconsistent log keeping
During inspection of Unit 1 East ESW pump
            and control board monitoring
discharge strainer baskets, large bypass flow
                                      48
paths were identified.
September 2, 2001
CR 01246015
Forced outage schedule does not match actual
work planning and execution for Unit 1 West
ESW pump work
September 3, 2001
CR 01247001
Declaration of unusual event during the Unit 1
and Unit 2 ESW restriction event on August 29,
2001 would have been prudent
September 3, 2001
CR 01247041
Open, inspect and clean 1-HV-AFP-WAC (Unit 1
west MDAFWP room cooler) to determine extent
of ESW debris intrusion
September 4, 2001
CR 01247050
NRC identified several human performance
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
September 4, 2001


CR 01247054 Due to potential debris buildup within ESW         September 4, 2001
49
            system, it is necessary to flush ESW piping
CR 01247054
CR 01247055 AFW room coolers have been found to be             September 4, 2001
Due to potential debris buildup within ESW
            blocked with debris (zebra mussel shells)
system, it is necessary to flush ESW piping
CR 01248001 Potential of debris build-up within the ESW         September 4, 2001
September 4, 2001
            system upstream of the D/G aircooler 3-way
CR 01247055
            valves
AFW room coolers have been found to be
CR 01248002 Flush piping upstream of D/G aftercooler 3-way     September 4, 2001
blocked with debris (zebra mussel shells)
            valves WRV-727 and WRV-725
September 4, 2001
CR 01250062 NRC identified several operational issues           September 7, 2001
CR 01248001
            associated with the August 29, 2001 degraded
Potential of debris build-up within the ESW
            ESW flow event, including: command and
system upstream of the D/G aircooler 3-way
            control, control board monitoring, log keeping,
valves
            use of technical specifications, conservative
September 4, 2001
            decision making, event reconstruction,
CR 01248002
            emergency plan implementation, and procedural
Flush piping upstream of D/G aftercooler 3-way
            usage
valves WRV-727 and WRV-725
CR 01251003 Performance Assurance identified that operators     September 7, 2001
September 4, 2001
            failed to establish mode constraint for operability
CR 01250062
            issues identified during the extent of condition
NRC identified several operational issues
            investigation for the ESW flow degradation event
associated with the August 29, 2001 degraded
            of August 29, 2001
ESW flow event, including: command and
CR 01251022 The downstream pipe of the Unit 1 East CTS heat     September 8, 2001
control, control board monitoring, log keeping,
            exchanger shell side vent is blocked
use of technical specifications, conservative
CR 01251029 In-Service testing on the Unit 1 East ESW pump     September 8, 2001
decision making, event reconstruction,
            indicated rapid degradation
emergency plan implementation, and procedural
CR 01253005 Quarantine was lost on the Unit 1 East ESW         September 9, 2001
usage
            strainer east basket. The basket had been
September 7, 2001
            placed in the scrap metal trash bin and taken to
CR 01251003
            the scrap yard
Performance Assurance identified that operators
CR 01260022 1-QT-131-CD diesel generator jacket water heat     September 17, 2001
failed to establish mode constraint for operability
            exchanger open, cleaned, and closed with 2
issues identified during the extent of condition
            tubes blocked with debris
investigation for the ESW flow degradation event
CR 01268045 Dedication Plan HP-1015 is inconsistent with the   September 25, 2001
of August 29, 2001
            requirement of 12 EHP-5043-CGD-001
September 7, 2001
P-00-05677 Essential Service Water Radiation Monitors
CR 01251022
            (WRA-3500, WRA-3600, WRA-4500 and WRA-
The downstream pipe of the Unit 1 East CTS heat
            4600) ESW Lines Are Plugged With Sand And
exchanger shell side vent is blocked
            Silt
September 8, 2001
                                        49
CR 01251029
In-Service testing on the Unit 1 East ESW pump
indicated rapid degradation
September 8, 2001
CR 01253005
Quarantine was lost on the Unit 1 East ESW
strainer east basket. The basket had been
placed in the scrap metal trash bin and taken to
the scrap yard
September 9, 2001
CR 01260022
1-QT-131-CD diesel generator jacket water heat
exchanger open, cleaned, and closed with 2
tubes blocked with debris
September 17, 2001
CR 01268045
Dedication Plan HP-1015 is inconsistent with the
requirement of 12 EHP-5043-CGD-001
September 25, 2001
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


50
Other Documents
Other Documents
                    Control Room Operator Logs               August 29, 2001 -
Control Room Operator Logs
                                                            August 30, 2001
August 29, 2001 -  
                    Final Expanded System Readiness Report   April 3, 2000
August 30, 2001
                    - ESW System (Unit 2)
Final Expanded System Readiness Report
PMI-7033           Application and Use of Design Basis,     Revision 0
- ESW System (Unit 2)
                    Single Failure Criterion, Engineering
April 3, 2000
                    Design Bases, and Current Licensing
PMI-7033
                    Basis
Application and Use of Design Basis,
OHI-2212           Narrative and Miscellaneous Logkeeping   Revision 4
Single Failure Criterion, Engineering
OHI-4017           Control Board Monitoring                 Revision 0
Design Bases, and Current Licensing
01 OHP 4021.016.003 Operation of the Component Cooling       Revision 15
Basis
                    Water System During System Startup and
Revision 0
                    Power Operation
OHI-2212
12 OHP 4021.019.001 Operation of the Essential Service Water Revision 23
Narrative and Miscellaneous Logkeeping
                    System
Revision 4
01-OHP 4022.016.001 Malfunction of the CCW System           Revision 2
OHI-4017
01-OHP-4024-104     Annunciator #104 Response: Essential     Revision 12
Control Board Monitoring
                    Service Water and Component Cooling
Revision 0
02-OHP 4022.019.001 ESW System Loss/Rupture                 Revision 2
01 OHP 4021.016.003
01-OHP 4024.113     Annunciator #113 Response: Steam         Revision 6
Operation of the Component Cooling
                    Generator 1 and 2
Water System During System Startup and
01-OHP 4024.114     Annunciator #114 Response: Steam         Revision 6
Power Operation
                    Generator 3 and 4
Revision 15
01-OHP-4024.120     Annunciator #120 Response: Station       Revision 10
12 OHP 4021.019.001
                    Auxiliary CD
Operation of the Essential Service Water
01- OHP             CD Diesel Generator Operability Test     Revision 16
System
4030.STP027CD      (Train A)
Revision 23
PMP 5030.001.005   Essential Service Water System           Revision 0
01-OHP 4022.016.001
                    Inspection Program
Malfunction of the CCW System
Drawing 12-3652     Screen House Plant At EL, 546'-0" Plan   Revision 5
Revision 2
                    To
01-OHP-4024-104
                    Column 18-West Portion
Annunciator #104 Response: Essential
Drawing 12-3653     Screen House Plant At EL, 546'-0" Plan   Revision 4
Service Water and Component Cooling
                    To Column 9-West Portion
Revision 12
                                        50
02-OHP 4022.019.001
ESW System Loss/Rupture
Revision 2
01-OHP 4024.113
Annunciator #113 Response: Steam
Generator 1 and 2
Revision 6
01-OHP 4024.114
Annunciator #114 Response: Steam
Generator 3 and 4
Revision 6
01-OHP-4024.120
Annunciator #120 Response: Station
Auxiliary CD
Revision 10
01- OHP
4030.STP027CD
CD Diesel Generator Operability Test
(Train A)
Revision 16
PMP 5030.001.005
Essential Service Water System
Inspection Program
Revision 0
Drawing 12-3652
Screen House Plant At EL, 546'-0" Plan
To  
Column 18-West Portion
Revision 5
Drawing 12-3653
Screen House Plant At EL, 546'-0" Plan
To Column 9-West Portion  
Revision 4


Drawing 12-5776-Y   Screen Housing Piping, Misc. Sections,
51
                    Units 1 And 2
Drawing 12-5776-Y
12 MHP 5021.019.003 Essential Service Water Strainer           Revision 4
Screen Housing Piping, Misc. Sections,
                    Maintenance
Units 1 And 2
Calculation        Auxiliary Feedwater Pump Room Heat-Up       Revision 0
12 MHP 5021.019.003
TH-00-05            Temperatures
Essential Service Water Strainer
Design Information Expected D/G Loading During a LOOP          Revision 0
Maintenance
Transmittal         Event Only
Revision 4
Calculation
TH-00-05
Auxiliary Feedwater Pump Room Heat-Up
Temperatures
Revision 0
Design Information
Transmittal  
DIT B-02217-00
DIT B-02217-00
EVAL-               Calculation of Pressure Spike in ESW        Revision 0
Expected D/G Loading During a LOOP
MD-02-ESW-092-N     System Due to Pressure Pulse (Column
Event Only
                    Rejoining)
Revision 0
EVAL-               Failure Analysis of Strainer Basket (CR    Revision 0
EVAL-  
MD-01-ESW-095-N     01242013, CR 01245030)
MD-02-ESW-092-N
EVAL-               Reduction in ESW Temperature to            Revision 0
Calculation of Pressure Spike in ESW
MD-02-ESW-089-N     Accommodate Reduced Flowrate to ESW
System Due to Pressure Pulse (Column
                    Components
Rejoining)
Calculation         Results of Operating the Diesel Generator   Revision 0
Revision 0
ENSM980327JDJ      Lube Oil Cooler & Jacket Water Cooler at
EVAL-
                    Elevated ESW Temperatures
MD-01-ESW-095-N
Dedication Plan No. Essential Service Water (ESW) Strainer     Revision 4
Failure Analysis of Strainer Basket (CR
HP-1015            Parts
01242013, CR 01245030)
OP-1-5113           Flow Diagram Essential Service Water       Revision 70
Revision 0
OP-1-5113A         Flow Diagram Essential Service Water       Revision 2
EVAL-
OP-1-5119A         Flow Diagram Circulating Water, Priming     Revision 60
MD-02-ESW-089-N
                    System And Screen Wash, Unit 1
Reduction in ESW Temperature to
OP-12-5119         Flow Diagram Circulating Water, Priming     Revision 50
Accommodate Reduced Flowrate to ESW
                    System And Screen Wash, Units 1 And 2
Components
OP-2-5113           Flow Diagram Essential Service Water       Revision 63
Revision 0
OP-2-5113A         Flow Diagram Essential Service Water       Revision 4
Calculation
OP-1-5151C         Flow Diagram Emergency Diesel               Revision 42
ENSM980327JDJ
                    Generator "CD"
Results of Operating the Diesel Generator
Technical Report   Debris Intrusion Into the Essential Service Revision 0
Lube Oil Cooler & Jacket Water Cooler at
NTS-2002-010-REP   Water System - Probabilistic Evaluation
Elevated ESW Temperatures
                                        51
Revision 0
Dedication Plan No.
HP-1015
Essential Service Water (ESW) Strainer
Parts
Revision 4
OP-1-5113
Flow Diagram Essential Service Water
Revision 70
OP-1-5113A
Flow Diagram Essential Service Water
Revision 2
OP-1-5119A
Flow Diagram Circulating Water, Priming
System And Screen Wash, Unit 1
Revision 60
OP-12-5119
Flow Diagram Circulating Water, Priming
System And Screen Wash, Units 1 And 2
Revision 50
OP-2-5113
Flow Diagram Essential Service Water
Revision 63
OP-2-5113A
Flow Diagram Essential Service Water
Revision 4
OP-1-5151C
Flow Diagram Emergency Diesel
Generator "CD"
Revision 42
Technical Report  
NTS-2002-010-REP
Debris Intrusion Into the Essential Service
Water System - Probabilistic Evaluation
Revision 0


Technical Report ESW Debris Intrusion Event Evaluation Revision 0
52
Technical Report  
NTS-2002-002-REP
NTS-2002-002-REP
                                  52
ESW Debris Intrusion Event Evaluation
Revision 0
}}
}}

Latest revision as of 18:01, 16 January 2025

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  American Electric Power icon.png
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


See also: IR 05000315/2001017

Text

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 <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />. 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

telecon

Clayton

Congel

Grant

Dyer

DATE

05/31/02

06/ /02

06/ /02

06/ /02

06/ /02

OFFICIAL RECORD COPY

A. Bakken

-5-

ADAMS Distribution:

WDR

DFT

JFS2

RidsNrrDipmIipb

GEG

HBC

KAC

C. Ariano (hard copy)

DRPIII

DRSIII

PLB1

JRK1

BLB1

FJC

JGL

JLD

LAD

OEMAIL

MDS1

RJS2

PLA

RWB1

MRJ1

MAS

JRJ

RML2

BAB2

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

2

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.

3

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)

4

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.

5

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

6

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:

7

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.

8

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

Date

Time

Event Description

9

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. -

1:36 p.m.

Unit 1 CW pumps 11, 12 and 13 were stopped in

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.

Date

Time

Event Description

10

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.

Date

Time

Event Description

11

    • 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.

Date

Time

Event Description

12

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.

Date

Time

Event Description

13

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 <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> 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:

14

Component

Inspection Results

Unit 1 East ESW pump

discharge strainer

Deformation of the strainer basket and resultant bypass

flowpath around the basket was identified. Additionally,

the basket support bracket was deformed.

Unit 1 East CCW Heat

Exchanger

Inspections identified the following:

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

Exchanger

Inspections identified the following:

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

Exchanger

Inspection identified the following:

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

Exchangers

Inspection identified minimal amounts of debris and no

tube blockage.

Component

Inspection Results

15

Unit 1 CD D/G Heat

Exchangers

Inspection of the 1 CD D/G heat exchangers identified

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

Room Cooler

Inspection of room cooler identified 18 pre-cooler tubes

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

Room Cooler

Inspections identified 1 pre-cooler tube of 132 total tubes

blocked with a small amount of sand and mussel shell

debris.

Unit 1 East Turbine

Driven Auxiliary

Feedwater Pump

(TDAFWP) Room

Cooler

Approximately one pound of debris was removed from

the room cooler during flushing activities. Inspections

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

sand, silt and/or zebra mussel shells.

Unit 1 West TDAFWP

Room Cooler

10 of 48 pre-cooler tubes were blocked with zebra

mussel shells and sand.

Unit 2 West CCW Heat

Exchanger

Inspections identified less than 24 tubes blocked with

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.

Component

Inspection Results

16

Unit 2 West CTS Heat

Exchanger

This heat exchanger was not inspected immediately

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

Exchangers

Inspection identified:

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

Exchangers

Inspection identified:

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

Heat Exchanger

Inspection identified no blocked tubes.

Unit 2 West MDAFWP

Room Cooler

Inspection of room cooler identified 5 pre-cooler tubes

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

Room Cooler

Inspections identified 18 of 48 pre-cooler tubes to be

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.

17

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 <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> 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 <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

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 <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> 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 <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> 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

18

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

19

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

20

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

21

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

22

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.

23

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

24

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.

25

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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />). The 0.05 was

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

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

26

would have approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 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 <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />, 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

27

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

28

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

29

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

30

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.

31

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

32

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.

33

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 <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

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 <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

Debris entrained within the intake structure would resettle to the intake structure

floor within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 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.

34

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.

35

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.

36

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

37

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

38

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.

39

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 <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> 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

40

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 <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. 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

41

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.

42

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

43

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

50-315/01-17-01

50-316/01-17-01

AV

Essential Service Water strainer maintenance instructions not

appropriate to the circumstances.

50-315/01-17-02

50-316/01-17-02

NCV

Human performance weaknesses during the degraded essential

service water event of August 29, 2001 associated with control

board monitoring and procedural adherence.

Closed

50-315/01-17-02

50-316/01-17-02

NCV

Human performance weaknesses during the degraded essential

service water event of August 29, 2001 associated with control

board monitoring and procedural adherence.

Discussed

None

44

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

45

TS

Technical Specification

UFSAR

Updated Final Safety Analysis Report

UHS

Ultimate Heat Sink

URI

Unresolved Item

US

Unit Supervisor

VIO

Violation

46

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

47

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

leg section of ESW piping

September 28, 2000

CR 00295037

1-PP-7W-MTR Failed To Start

October 21, 2000

CR 01019031

SA-2001-REA-003, Perform Zebra Mussel

Assessment During Year 2001

January 19, 2001

CR 01242007

2-ESW-162-CD Emergency Diesel Jacket Water

Cooler QT-131-CD tube side vent valve is

blocked and could not be flushed out

August 30, 2001

CR 01242008

Procedural Deficiency in 02 OHP

4030.STP.022E, the ESW system test - Step

4.30.3, which aligns the north CRAC for flushing

is missing from the procedure

August 30, 2001

CR 01242009

2-ESW-163-CD, the Unit 2 CD D/G jacket water

cooler tube side drain, is clogged and not allowing

flow to pass when opened

August 30, 2001

CR 01242010

2-ESW-162-AB Emergency Diesel Jacket Water

Cooler QT-131-AB tube side vent valve is blocked

and could not be flushed out

August 30, 2001

CR 01242013

Slit/mud intrusion into Unit 1 and 2 ESW systems

renders CCW and D/G inoperable

August 29, 2001

CR 01243013

2-HV-AFP-T2AC, the Unit 2 West TDAFWP room

cooler, does not appear to be functioning

August 31, 2001

CR 01243015

Unit 1 East auxiliary feedwater pump room cooler

flow (56 gpm) was less then minimum required

(57 gpm)

August 31, 2001

48

CR 01243036

Both Unit 1 and Unit 2 D/Gs declared inoperable

due to low ESW flow. This resulted in Unit 1

entering a RED shutdown risk path.

August 29, 2001

CR 01243038

Evaluate August 30, 2001, greater than 20

percent power reduction on Unit 2 due to

degraded ESW flow for potential Maintenance

Rule impact

August 30, 2001

CR 01243039

PRA analysis of Unit 2 indicates yellow risk status

in that the west CCW heat exchanger is not

receiving the required 5000 gpm ESW flow

August 30, 2001

CR 01244010

1-WMO-12 circulating water pump PP-2-2

discharge shutoff valve

September 1, 2001

CR 01244011

1-WMO-11 Circulating Water Pump PP-2-1

Discharge Shutoff Valve

August 31, 2001

CR 01244016

Wood, mussel shells, and debris larger than

expected identified during inspection on the Unit 1

east CCW heat exchanger

September 1, 2001

CR 01244019

Degraded ESW flow documented in CR

01242013 may indicate that the GL 89-13

program is inadequate

September 1, 2001

CR 01245030

During inspection of Unit 1 East ESW pump

discharge strainer baskets, large bypass flow

paths were identified.

September 2, 2001

CR 01246015

Forced outage schedule does not match actual

work planning and execution for Unit 1 West

ESW pump work

September 3, 2001

CR 01247001

Declaration of unusual event during the Unit 1

and Unit 2 ESW restriction event on August 29,

2001 would have been prudent

September 3, 2001

CR 01247041

Open, inspect and clean 1-HV-AFP-WAC (Unit 1

west MDAFWP room cooler) to determine extent

of ESW debris intrusion

September 4, 2001

CR 01247050

NRC identified several human performance

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

September 4, 2001

49

CR 01247054

Due to potential debris buildup within ESW

system, it is necessary to flush ESW piping

September 4, 2001

CR 01247055

AFW room coolers have been found to be

blocked with debris (zebra mussel shells)

September 4, 2001

CR 01248001

Potential of debris build-up within the ESW

system upstream of the D/G aircooler 3-way

valves

September 4, 2001

CR 01248002

Flush piping upstream of D/G aftercooler 3-way

valves WRV-727 and WRV-725

September 4, 2001

CR 01250062

NRC identified several operational issues

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

September 7, 2001

CR 01251003

Performance Assurance identified that operators

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

September 7, 2001

CR 01251022

The downstream pipe of the Unit 1 East CTS heat

exchanger shell side vent is blocked

September 8, 2001

CR 01251029

In-Service testing on the Unit 1 East ESW pump

indicated rapid degradation

September 8, 2001

CR 01253005

Quarantine was lost on the Unit 1 East ESW

strainer east basket. The basket had been

placed in the scrap metal trash bin and taken to

the scrap yard

September 9, 2001

CR 01260022

1-QT-131-CD diesel generator jacket water heat

exchanger open, cleaned, and closed with 2

tubes blocked with debris

September 17, 2001

CR 01268045

Dedication Plan HP-1015 is inconsistent with the

requirement of 12 EHP-5043-CGD-001

September 25, 2001

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

50

Other Documents

Control Room Operator Logs

August 29, 2001 -

August 30, 2001

Final Expanded System Readiness Report

- ESW System (Unit 2)

April 3, 2000

PMI-7033

Application and Use of Design Basis,

Single Failure Criterion, Engineering

Design Bases, and Current Licensing

Basis

Revision 0

OHI-2212

Narrative and Miscellaneous Logkeeping

Revision 4

OHI-4017

Control Board Monitoring

Revision 0

01 OHP 4021.016.003

Operation of the Component Cooling

Water System During System Startup and

Power Operation

Revision 15

12 OHP 4021.019.001

Operation of the Essential Service Water

System

Revision 23

01-OHP 4022.016.001

Malfunction of the CCW System

Revision 2

01-OHP-4024-104

Annunciator #104 Response: Essential

Service Water and Component Cooling

Revision 12

02-OHP 4022.019.001

ESW System Loss/Rupture

Revision 2

01-OHP 4024.113

Annunciator #113 Response: Steam

Generator 1 and 2

Revision 6

01-OHP 4024.114

Annunciator #114 Response: Steam

Generator 3 and 4

Revision 6

01-OHP-4024.120

Annunciator #120 Response: Station

Auxiliary CD

Revision 10

01- OHP

4030.STP027CD

CD Diesel Generator Operability Test

(Train A)

Revision 16

PMP 5030.001.005

Essential Service Water System

Inspection Program

Revision 0

Drawing 12-3652

Screen House Plant At EL, 546'-0" Plan

To

Column 18-West Portion

Revision 5

Drawing 12-3653

Screen House Plant At EL, 546'-0" Plan

To Column 9-West Portion

Revision 4

51

Drawing 12-5776-Y

Screen Housing Piping, Misc. Sections,

Units 1 And 2

12 MHP 5021.019.003

Essential Service Water Strainer

Maintenance

Revision 4

Calculation

TH-00-05

Auxiliary Feedwater Pump Room Heat-Up

Temperatures

Revision 0

Design Information

Transmittal

DIT B-02217-00

Expected D/G Loading During a LOOP

Event Only

Revision 0

EVAL-

MD-02-ESW-092-N

Calculation of Pressure Spike in ESW

System Due to Pressure Pulse (Column

Rejoining)

Revision 0

EVAL-

MD-01-ESW-095-N

Failure Analysis of Strainer Basket (CR

01242013, CR 01245030)

Revision 0

EVAL-

MD-02-ESW-089-N

Reduction in ESW Temperature to

Accommodate Reduced Flowrate to ESW

Components

Revision 0

Calculation

ENSM980327JDJ

Results of Operating the Diesel Generator

Lube Oil Cooler & Jacket Water Cooler at

Elevated ESW Temperatures

Revision 0

Dedication Plan No.

HP-1015

Essential Service Water (ESW) Strainer

Parts

Revision 4

OP-1-5113

Flow Diagram Essential Service Water

Revision 70

OP-1-5113A

Flow Diagram Essential Service Water

Revision 2

OP-1-5119A

Flow Diagram Circulating Water, Priming

System And Screen Wash, Unit 1

Revision 60

OP-12-5119

Flow Diagram Circulating Water, Priming

System And Screen Wash, Units 1 And 2

Revision 50

OP-2-5113

Flow Diagram Essential Service Water

Revision 63

OP-2-5113A

Flow Diagram Essential Service Water

Revision 4

OP-1-5151C

Flow Diagram Emergency Diesel

Generator "CD"

Revision 42

Technical Report

NTS-2002-010-REP

Debris Intrusion Into the Essential Service

Water System - Probabilistic Evaluation

Revision 0

52

Technical Report

NTS-2002-002-REP

ESW Debris Intrusion Event Evaluation

Revision 0

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