ML083120510
| ML083120510 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 11/07/2008 |
| From: | Pederson C Division Reactor Projects III |
| To: | Wadley M Northern States Power Co |
| References | |
| EA-08-272 IR-08-008 | |
| Download: ML083120510 (34) | |
See also: IR 05000282/2008008
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE ROAD, SUITE 210
LISLE, IL 60532-4352
November 7, 2008
Mr. Michael D. Wadley
Site Vice President
Prairie Island Nuclear Generating Plant
Northern States Power Company-Minnesota
1717 Wakonade Drive East
Welch, MN 55089
SUBJECT: PRAIRIE ISLAND NUCLEAR GENERATING PLANT -
NRC SPECIAL INSPECTION REPORT 05000282/2008008; 05000306/2008008,
Dear Mr. Wadley:
On October 6, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed a Special
Inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The Special
Inspection Team evaluated the facts and circumstances surrounding the Unit 1 reactor trip and
the failure of 11 turbine-driven auxiliary feedwater pump (TDAFWP) to run, which occurred on
July 31, 2008. Additionally, the team evaluated the facts and circumstances associated with the
declaration of a Notice of Unusual Event (NOUE) on August 3, 2008, due to indications of
excessive levels of hydrazine in the condenser pit area of Unit 1. The enclosed Inspection
Report documents the results of the inspection, which were discussed on October 6, 2008, with
you and other members of your staff.
Based on the deterministic criteria provided in Management Directive (MD) 8.3, ANRC Incident
Investigation Program,@ the incident met MD 8.3 Criterion h, AInvolved questions or concerns
pertaining to licensee operational performance.@ The special inspection evaluated the causes of
the reactor trip; the failure of the TDAFWP to run when demanded; and the NOUE; as well as
the actions taken by your staff in response to the reactor trip and recovery.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commission's rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
The enclosed inspection report discusses a finding for Unit 1 that appears to have low to
moderate safety significance (White). As documented in Section 4OA3.3 of this report, due to a
configuration control issue, which isolated the discharge pressure switch associated with
11 TDAFWP, the pump was rendered inoperable for a time period that significantly exceeded
the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> time limit allowed by Technical Specifications.
M. Wadley -2-
This finding was assessed based on the best available information, including influential
assumptions, using the applicable Significance Determination Process (SDP). The preliminary
safety significance of the finding was determined assuming 11 TDAFWP was inoperable for
138 days, during an operational Mode that required two operable trains of auxiliary feedwater.
This finding was not an immediate safety concern because the 11 TDAFWP was not required to
mitigate the trip and, upon identification of the issue, your staff took prompt corrective actions to
restore the mispositioned valve to its normal (open) position; performed valve lineups to verify
correct equipment configurations for the remaining auxiliary feedwater pumps; and performed
appropriate surveillance testing on the 11 TDAFWP to verify the components operable status.
The finding is also an apparent violation of NRC requirements and is being considered for
escalated enforcement action in accordance with the NRC Enforcement Policy. The current
Enforcement Policy is included on the NRCs web site at http://www.nrc.gov/reading-
rm/adams.html.
In accordance with Inspection Manual Chapter (IMC) 0609, we intend to complete our
evaluation using the best available information and issue our final determination of safety
significance within 90 days of this letter. The SDP encourages an open dialog between the
staff and the licensee; however, the dialogue should not impact the timeliness of the staffs
final determination.
Before the NRC makes its enforcement decision, we are providing you an opportunity to either:
1) 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 (2) submit your position
on the finding to the NRC in writing. If you 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 conference is held, it will be open for public observation. The
NRC will also issue a press release to announce the conference. 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. If you decline to request a Regulatory Conference or to submit a written response, you
relinquish your right to appeal the final SDP determination; in that, by not doing either you fail to
meet the appeal requirements stated in the Prerequisite and Limitation Sections of Attachment 2
of IMC 0609.
Please contact Richard Skokowski at 630-829-9620 within 10 days of the date of this letter to
notify the NRC of your intended response. If we have not heard from you within ten days, we
will continue with our significance determination and enforcement decision. You will be advised
by a separate correspondence of the results of our deliberations on this matter.
M. Wadley -3-
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. Please be advised that the number and
characterization of the apparent violation described in the enclosed inspection report may
change as a result of further NRC review.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its
enclosure, and your response (if any) will be made available electronically for public inspection
in the NRC Public Document Room or from the Publicly Available Records (PARS) component
of NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA by Gary L. Shear, Acting for/
Cynthia D. Pederson, Director
Division of Reactor Projects
Docket Nos. 50-282; 50-306
Enclosure: Inspection Report 05000282/2008008; 05000306/2008008
w/Attachments:
1. Supplemental Information
2. Timeline of Events Unit 1
3. Special Inspection Charter
DISTRIBUTION
See next page
Letter to M. Wadley from C. Pederson dated November 7, 2008
SUBJECT: PRAIRIE ISLAND NUCLEAR GENERATING PLANT -
NRC SPECIAL INSPECTION REPORT 05000282/2008008; 05000306/2008008,
cc w/encl: D. Koehl, Chief Nuclear Officer
Regulatory Affairs Manager
P. Glass, Assistant General Counsel
Nuclear Asset Manager
J. Stine, State Liaison Officer, Minnesota Department of Health
Tribal Council, Prairie Island Indian Community
Administrator, Goodhue County Courthouse
Commissioner, Minnesota Department of Commerce
Manager, Environmental Protection Division
Office of the Attorney General of Minnesota
Emergency Preparedness Coordinator, Dakota
County Law Enforcement Center
M. Wadley -3-
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. Please be advised that the number and
characterization of the apparent violation described in the enclosed inspection report may
change as a result of further NRC review.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its
enclosure, and your response (if any) will be made available electronically for public inspection
in the NRC Public Document Room or from the Publicly Available Records (PARS) component
of NRC's document system (ADAMS). ADAMS is accessible from the NRC Website at
http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA by Gary L. Shear, Acting for/
Cynthia D. Pederson, Director
Division of Reactor Projects
Docket Nos. 50-282; 50-306
Enclosure: Inspection Report 05000282/2008008; 05000306/2008008
w/Attachments:
1. Supplemental Information
2. Timeline of Events Unit 1
3. Special Inspection Charter
DISTRIBUTION:
See next page
DOCUMENT NAME: G:\PRAI\Prairie Island 2008 008.doc
G Publicly Available G Non-Publicly Available G Sensitive G Non-Sensitive
To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" =
Copy with attach/encl "N" = No copy
OFFICE RIII RIII RIII
NAME RSkokowski:cms GShear for PLougheed for
CPederson KOBrien
DATE 11/06/08 11/07/08 11/06/08
OFFICIAL RECORD COPY
Letter to M. Wadley from C. Pederson dated November 7, 2008
SUBJECT: PRAIRIE ISLAND NUCLEAR GENERATING PLANT -
NRC SPECIAL INSPECTION REPORT 05000282/2008008; 05000306/2008008,
DISTRIBUTION:
RidsNrrPMPrairieIsland
RidsNrrDorlLpl3-1
RidsNrrDirsIrib Resource
Cynthia Carpenter
Greg Bowman
Mary Ann Ashley
Mark Satorius
Kenneth Obrien
Cynthia Pederson
DRPIII
DRSIII
Patricia Buckley
ROPreports@nrc.gov
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos. 50-282; 50-306
Report No: 05000282/2008008 and 05000306/2008008
Licensee: Northern States Power - Minnesota
Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2
Location: Welch, Minnesota
Dates: August 4 through October 6, 2008
Inspectors: S Thomas, SRI, Monticello (Lead)
K. Stoedter, SRI, Prairie Island
D. Betancourt, Reactor Engineer
Approved by: R. Skokowski, Chief
DRP Branch 3
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS ......................................................................................................... 1
REPORT DETAILS..................................................................................................................... 2
4. OTHER ACTIVITIES (OA) ............................................................................................ 3
4OA3 Special Inspection (93812)................................................................................. 3
4OA6 Management Meetings .................................................................................... 13
SUPPLEMENTAL INFORMATION ............................................................................................. 1
KEY POINTS OF CONTACT .................................................................................................. 1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED ....................................................... 1
LIST OF DOCUMENTS REVIEWED....................................................................................... 2
LIST OF ACRONYMS USED .................................................................................................. 6
Enclosure
SUMMARY OF FINDINGS
IR 05000282/2008008; 05000306/2008008; August 4, 2008, to October 6, 2008, Prairie Island
Nuclear Plant, Units 1 and 2; Other Activities; SIT regarding the failure of 11 TDAFWP to run
following the reactor trip on July 31, 2008, and declaration of a NOUE on August 3, 2008.
This report covers a 64-day period of special inspection by one NRC Region III inspector and
two resident inspectors. One apparent violation, with potential safety significance greater than
Green, was identified. The significance of most findings is indicated by their color (Green,
White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination
Process" (SDP). Findings for which the SDP does not apply may be "Green" or be assigned a
severity level after NRC management review. The NRC's program for overseeing the safe
operation of commercial nuclear power reactors is described in NUREG 1649, "Reactor
Oversight Process," Revision 4, dated December 2006.
A. Inspector-Identified and Self-Revealed Findings
Cornerstone: Mitigating Systems
- AV: A self-revealing apparent violation of Technical Specifications was associated with
the licensees failure to adequately control the position of a valve that could isolate the
11 TDAFWPs discharge pressure switch. Because of the valve being closed, the
11 TDAFWP failed to run as required, subsequent to a reactor trip. The manifold
isolation valve was determined to have been shut for 138 days, rendering the
11 TDAFWP inoperable for a time period that significantly exceeded the Technical
Specification allowed outage time (72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />) for the pump. This issue has been
preliminarily determined to be of low to moderate safety significance (White) for Unit 1.
This issue was entered into the licensees corrective action program (CAP 01146005).
The licensee took prompt corrective actions to restore the mispositioned valve to its
normal (open) position; perform valve lineups to verify correct equipment configurations
for the remaining auxiliary feedwater pumps; and perform appropriate surveillance
testing on the 11 TDAFWP to verify the components operable status.
This finding was determined to be more than minor in accordance with IMC 0612,
Power Reactor Inspection Reports, Appendix B, Issue Screening, because it
impacted the configuration control attribute of the Mitigating Systems Cornerstone
objective to ensure the availability, reliability, and capability of the systems that respond
to initiating events to prevent undesirable consequences. The cause of this finding was
related to the cross-cutting element of human performance for resources (H.2.(c)).
(Section 4OA3.3)
B. Licensee-Identified Violations
No findings of significance were identified.
1 Enclosure
REPORT DETAILS
Summary of Plant Event
On July 31, 2008, at 8:17 a.m., Prairie Island Unit 1 tripped due to a spurious overtemperature
delta temperature (OTT) signal on the reactor protection system red channel concurrent with
planned testing on the reactor protection system yellow channel. After the reactor tripped, the
11 turbine-driven auxiliary feedwater pump (TDAFWP) started as required, then stopped
approximately 40 seconds later due to a low discharge pressure trip. The licensee determined
that the cause of the TDAFWP trip was an incorrect valve lineup associated with the auxiliary
feedwater pumps discharge pressure instrumentation. Prior to restarting the Unit, the licensee
replaced the faulty reactor protection system card that caused the spurious OTT signal,
corrected the valve lineup issue associated with the 11 TDAFWP discharge pressure
instrumentation, and successfully tested both systems.
On August 2, 2008, at 3:42 p.m., the licensee began to startup Unit 1 in accordance with station
procedures. Early in the morning on August 3, 2008, while holding at approximately 30 percent
power to allow secondary chemistry to stabilize, a technician reported an abnormal odor
adjacent to the Unit 1 condenser pit. Air samples taken in the vicinity of the Unit 1 condenser pit
indicated positive for hydrazine. The licensee took positive actions to control personnel access
to the affected area and, at 3:52 a.m., declared a Notification of Unusual Event (NOUE) for the
release of toxic gases deemed detrimental to the normal operation of the plant, in accordance
with their Emergency Plan. The licensee utilized extra ventilation in the affected areas to
reduce the hydrazine concentration. The licensee continued to take air samples over the next
several hours and, based on acceptable sample results, exited the Unusual Event at 10:20 p.m.
on August 3, 2008.
Based on the probabilistic risk and deterministic criteria specified in Management Directive
(MD) 8.3, "NRC Incident Investigation Program," and Inspection Procedure (IP) 71153,
"Event Followup," and due to the equipment performance problems that occurred, a Special
Inspection was initiated in accordance with IP 93812, "Special Inspection."
The inspection focus areas included the following charter items:
- Identify the time-line for the event. Include plant conditions, system line ups, and operator
actions.
- Review the licensees post-trip review to determine the cause of the reactor trip.
Independently review plant data and records to confirm the adequacy of the licensees
assessment, and corrective actions.
- Review the circumstances surrounding the failure of the TDAFWP, including the most
likely cause of the pump failure; the length of time the pump may have been in an
unrecognized failed condition; and any potential for operators to recover the failed pump.
- Determine if the licensee is performing a root cause for the reactor trip. As available,
evaluate the scope, schedule, staffing and results of the licensees root cause
investigation.
2 Enclosure
- Determine if the licensee is performing a root cause evaluation for the TDAFWP failure.
As available, evaluate the scope, schedule, staffing and results of the licensees root
cause investigation.
- Review procedures for the TDAFWP, including operational line-up procedures and testing
procedures, to assess any procedural or testing inadequacies that may have contributed
to the failure of the pump.
- Determine if the licensee performed an extent-of-condition evaluation to assess if the
contributing causes to the failure of the TDAFWP have the potential to affect other
safety-related equipment.
- Review for adequacy the licensees immediate corrective actions and planned long-term
corrective actions to prevent recurrence of both the reactor trip and the failure of the
TDAFWP.
Additionally, the Special Inspection team (SIT) was tasked with reviewing the circumstances
surrounding the August 3, 2008, declaration of the NOUE associated with release of toxic gases
(hydrazine) deemed detrimental to normal operation of the plant.
4. OTHER ACTIVITIES (OA)
4OA3 Special Inspection (93812)
.1 Establish the Sequence of Events Related to the Event, Including Plant Conditions,
System Lineups and Operator Actions
a. Inspection Scope
The inspectors reviewed operator logs, plant parameter recordings and computer
trending information, and conducted interviews with licensee personnel in developing the
sequence of events. In addition, the inspectors sequence of events was reviewed
against the licensee-generated sequence of events to ensure completeness and
accuracy.
b. Findings and Observations
No findings of significance were identified. The inspectors generated sequence of
events is included with this report as Attachment 1 and an event narrative summary
was presented in this reports Summary of Plant Event, discussed above.
.2 Reactor Trip Report
a. Inspection Scope
The inspectors reviewed the licensees post-trip report to determine if the licensee
adequately evaluated and corrected the cause of the reactor trip. Specific information
reviewed by the inspectors included: reactor trip report; operators logs; emergency
response computer system alarm post-trip data; troubleshooting log for the failed OTT
3 Enclosure
reactor protection channel; troubleshooting log for the 11 TDAFWP trip; the reactor trip
and trip recovery procedures; and recorder traces for various reactor plant parameters.
b. Findings and Observations
No findings of significance were identified.
.3 Trip of the 11 Turbine-Driven Auxiliary Feedwater Pump
a. Inspection Scope
The inspectors reviewed the circumstances surrounding the failure of the 11 TDAFWP to
run subsequent to the reactor trip, after receiving a valid start signal. The specific focus
of this inspection was to determine the most likely cause of the pump failure; the length
of time prior to the trip that the pump was inoperable; and the probability of success for
the recovery of the failed pump.
b. Findings and Observations
Introduction
A self-revealing apparent violation of Technical Specifications (TS) 3.7.5.B was identified
due to the licensees failure to control the position of the 11 TDAFWP discharge
pressure switch manifold block valve. The failure to control the position of this valve
resulted in the 11 TDAFWP being inoperable for 138 days.
Description
A timeline of the relevant information subsequent to the July 31, 2008, Unit 1 reactor trip
is as follows:
- 8:17 a.m.; the Unit 1 reactor tripped from full power. Shortly thereafter, both of
the Units auxiliary feedwater pumps received valid start signals due to expected
low post-trip water levels in the steam generators;
- 8:21 a.m.; the 11 TDAFWP Low Suction/Discharge Pressure Trip annunciator
was received in the control room;
- 8:55 a.m.; the remaining auxiliary feedwater pump was secured and normal
steam generator levels were maintained using the main feedwater system;
- 9:15 a.m.; the licensee determined that the 11 TDAFWP had started upon receipt
of the valid start signal, but tripped approximately 42 seconds later;
- 1:23 p.m.; the licensee discovered an unlabeled manifold block valve associated
with the 11 TDAFWPs discharge pressure switch to be shut.
The inspectors reviewed licensee testing procedures and work orders that would have
manipulated the manifold block valve. In addition to the work documents that directly
manipulated the block valve, the inspectors also reviewed several other procedures,
which manipulated similar manifold valves that are located in close proximity to the
mispositioned block valve. The inspectors determined that the last documented activity
that repositioned the block valve was the performance of SP1234, 11 Aux Feedwater
4 Enclosure
Pump Suction and Discharge Pressure Switches Calibration, completed on
February 23, 2008.
Analysis
The inspectors evaluated the finding using IMC 0609, Appendix A, Attachment 1,
Significance Determination of Reactor Inspection Findings for At-Power Situations.
Since the performance deficiency affected the ability of the 11 TDAFWP to start and run
upon the receipt of a valid actuation signal, the inspectors used the Phase 1 SDP
worksheet for the Mitigating System Cornerstone to determine the significance of the
finding. The finding was determined to require a Phase 2 SDP review because the
finding resulted in the loss of function of a single train for greater than its TS allowed
72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> outage time limit.
It is not known when the manifold isolation valve was closed, rendering the pump
unavailable for automatic actuation. Based on the inspection results, the valve was last
manipulated on February 23, 2008, as part of the Unit 1 refueling outage activities.
Therefore, it was assumed that the pump was unavailable since Unit 1 entered Mode 3
on March 15, 2008, until the problem was discovered on July 31, 2008.
Recovery of the 11 TDAFWP was determined to be feasible. The pump would start and
run if the control selector switch in the control room was taken to Manual. The
licensees alarm response Procedure C47010, 11 TDAFWP Lo Suct or Disch Press
Trip, instructed operators to restart the pump using Abnormal Operating Procedure
1C28.1AOP4, Restarting Unit 1 AFWP After Low Suction/Discharge Pressure Trip.
This procedure directed operators to put the selector switch in Manual. The inspectors
estimated that the time required to perform the actions in the procedure was
approximately 15 minutes. Since the time to core damage, assuming a loss of all
feedwater was much longer than 15 minutes; adequate time for recovery of the pump
was available.
The Phase 2 pre-solved worksheets modeled Unit 2 components only. The significance
of the Unit 2 TDAFWP pump being unavailable for greater than 30 days was Red. This
result was overly conservative because it did not include credit for recovering the pump.
The result was also conservative because the Phase 2 pre-solved worksheets assumed
the exposure period was one year and the actual exposure period was 138 days.
Therefore, a Phase 3 SDP analysis was completed.
The SPAR-H model for Prairie Island Unit 1, Revision 3.45 was used for the internal
events Phase 3 SDP analysis. For the internal events analysis the basic event
AFW-TDP-FS-TDP11, the 11 TDAFWP Fails to Start, was set to True and the basic
event AFW-XHE-XL-TDPFS, Operator Fails to Recover AFW Pump Fail to Start, was set
to a failure probability of 2.2E-2 based on a SPAR-H analysis for operators failing to
recover the pump. The SPAR-H analysis assumed that all performance-shaping factors
for both diagnosis and action were nominal with the exception of the Stress performance
shaping factors. The scenario of a transient with the loss of all feedwater was
considered to be high stress. Using these assumptions and the 138-day exposure
period, the change in core damage frequency (CDF) was calculated to be less than
1.0E-6/yr.
5 Enclosure
For the Phase 3 SDP analysis, the Senior Reactor Analyst (SRA) also considered
the risk contributions from internal flooding, external events, and large early release
frequency. Only internal fire scenarios were determined to contribute to the risk
significance of this finding. The 11 TDAFWP was the only credited means of decay heat
removal in the licensees Appendix R safe shutdown analysis for 10 different fire areas.
The licensees Individual Plant Examination for External Events (IPEEE) results and the
NRCs Risk Assessment of Operational Events (RASP) Handbook for External Events
were used as the best available information to estimate the fire risk contribution
associated with the unavailability of the 11 TDAFWP.
For fire scenarios that do not involve control room evacuation, the same recovery human
error probability (HEP) used in the internal events analysis was applied, since operators
have appropriate indications and annunciators to implement the abnormal operating
procedure in the control room. However, recovery of the pump would be different and
more complex for fire scenarios involving control room evacuation. Licensee
Procedure F5, Control Room Evacuation (Fire) directed operators to trip the reactor
and the main feedwater pumps prior to evacuating the control room and proceeding to
the hot shutdown panels. The procedure also directed operators to open breakers for
the motor-driven AFW pumps, leaving only the 11 TDAFWP available for decay heat
removal. Since the 11 TDAFWP would have tripped due to the mispositioned discharge
pressure switch manifold isolation valve, no auxiliary feedwater pumps would be
available without further operator action.
Procedure F5 provided direction to the operator to locally operate the 11 TDAFWP. If it
was not running, the operator was directed to take action to bleed off the air supply to
the turbine steam supply valve. This action failed the valve open and allowed the turbine
to roll and start the pump if the pump had previously tripped from the low discharge
pressure trip signal.
The recovery actions were directed to be performed by the Unit 1 Shift Supervisor who
would be stationed at the Hot Shutdown Panels in the Auxilairy Feedwater Pump
Rooms. This individual was first tasked with making the decision to evacuate the control
room; assure appropriate notifications are made; and determine if self-contained
breathing apparatus use is required. The Unit 1 Shift Supervisor was responsible for
operating both the Unit 1 and Unit 2 TDAFWPs and directing operators in the plant
performing other manual actions. Due to the heavy workload of the operator, complexity
of the procedure, high stress of the postulated scenario, and limited experience with this
procedure, the SRA determined that the failure probability for manual plant shutdown
outside the control room would be increased because of this finding.
To obtain a quantitative estimate of the delta CDF, the SRA reviewed the top 100 cut
sets submitted with the licensees IPEEE analysis. The nominal failure probability for
manual shutdown outside the control room (SHTDWN-OUT) was 6.4E-2. The SRA used
SPAR-H to estimate a HEP for shutdown outside the control room given the
performance deficiency. Assuming that the actions involve high stress, high complexity,
low experience/training, and poor work processes (the Shift Supervisor was responsible
for recovering the pump), the SRA calculated an action HEP of 0.13. This estimate was
approximately double the nominal failure probability. Using this value as the failure
probability for manual shutdown outside the control room for evacuation scenarios and a
pump non-recovery probability of 2.2E-2 for other fire scenarios, the top 100 cut-sets
6 Enclosure
were recalculated for an exposure period of 138 days. The delta CDF was estimated to
be approximately 1.6E-6/yr.
The RASP external events handbook for internal fires was also used to evaluate the fire
risk as a sensitivity analysis because of the uncertainty in the frequency of fires leading
to control room evacuation scenarios. Since the dominant fire risk sequences from the
licensees IPEEE were fires involving control room evacuation; only those scenarios
were addressed. These scenarios involved fires in the control room and relay room.
Using the RASP handbook data on initiating event frequencies and non-suppression
probabilities, the SRA confirmed that the change in core damage frequency from internal
fires was above the 1.0E-6 threshold for a low to moderate safety significance (White)
finding.
The result of the Phase 3 SDP analysis was a delta CDF of 1.6E-6/yr, considering both
contributions from internal events and internal fire scenarios. The licensee performed a
risk evaluation of the internal events contribution and the result was similar to the NRCs.
The licensee had not yet completed an evaluation of the fire risk contribution.
The inspectors determined that the performance deficiency affected the crosscutting
area of Human Performance, having resources components, and involving aspects
associated with ensuring complete, accurate and up-to-date design documentation,
procedures, work packages, and correct labeling of components. [H.2.(c)]
Enforcement
Technical Specification 3.7.5 states, in part, that two auxiliary feedwater trains be
operable during plant operation in Modes 1, 2, and 3. Additionally, TS 3.7.5.B states, in
part, if one auxiliary feedwater train is inoperable in Modes 1, 2, and 3, the affected train
be restored to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or place the plant in Mode 3 within
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Contrary to this requirement, as a result of the
11 TDAFWP pumps discharge-low-pressure pressure switch being isolated for
approximately 138 days, the pump was inoperable for a time period which significantly
exceeded the time allowed by TSs. For Unit 1, this is an apparent violation of
TS 3.7.5 pending the completion of the final significance determination.
.4 Evaluation of the Root Cause Report Associated with the Reactor Trip
a. Inspection Scope
The inspectors monitored the licensees root cause team activities and reviewed the final
Root Cause Evaluation Report, U1 OTT RX Trip, associated with CAP 1145953.
b. Findings and Observations
The inspectors noted that the licensees root cause team used industry accepted root
cause evaluation tools (i.e., Toubleshooting/Failure Analysis, Barrier Analysis, Event and
Causal Factor Charting, Why Staircase, Fault Tree Analysis). The inspectors also noted
that the licensees root cause team was comprised of multi-disciplined individuals from
systems engineering, electrical maintenance, and operations.
7 Enclosure
The licensee determined that the equipment root cause was that the 1TC-405L FQ
proportional controller failed high due to a failure of a solid-state device within the
controller. The licensee also concluded that the organizational root cause was due to
lack of previous Foxboro H-Line component failures that had adverse consequences.
Prairie Island did not adequately prioritize or apply the human resources necessary to
develop and implement a preventive maintenance strategy for the components within the
reactor protection and control system. The SIT determined that the licensees efforts to
identify the root causes associated with this event were adequate.
The SIT reviewed the licensees immediate corrective actions and found them to be
acceptable. Additionally, the Team reviewed the corrective actions to prevent
recurrence and additional long-term corrective actions and determined, if the licensee
fully implemented the corrective actions in a timely manner, the corrective actions would
appropriately address the root causes for this event.
This inspection also represented the completion of one maintenance effectiveness
(71111.12) inspection sample.
No findings of significance were identified.
.5 Evaluation of the Root Cause Report Associated with the Failure of the 11
Turbine-Driven Auxiliary Feedwater Pump Failure-to-Run Upon the Receipt of a
Valid Demand Signal
a. Inspection Scope
The inspectors monitored the licensees root cause team activities and reviewed the final
Root Cause Evaluation report, 11 Turbine-Driven Auxiliary Feedwater Pump Discharge
Pressure Switch Manifold Isolation Mispositioning, associated with CAP 1146005.
b. Findings and Observations
The inspectors noted that the licensees root cause team used industry accepted root
cause evaluation tools (i.e., Why Staircase, Barrier Failure Analysis, Failure Mode
Analysis, Event and Causal Factor Charting). The inspectors also noted that the
licensees root cause team was comprised of multi-disciplined individuals from
engineering, maintenance, and operations.
The licensee determined that the root cause for this event was inadequate configuration
controls for components that have the potential to adversely impact the design function
of safety related structures, systems and components. The SIT determined that the
licensees efforts to identify the root cause associated with this event were adequate.
The SIT reviewed the licensees immediate corrective actions and found them to be
acceptable. Additionally, the Team reviewed the corrective actions to prevent
recurrence and additional long-term corrective actions and determined, if the licensee
fully implemented the corrective actions in a timely manner, the corrective actions would
appropriately address the root causes for this event.
No findings of significance were identified.
8 Enclosure
.6 Review Procedures Associated with the Turbine-Driven Auxiliary Feedwater Pump to
Assess Procedural or Testing Inadequacies Which May have Contributed to the Failure
of the Pump
a. Inspection Scope
The inspectors reviewed surveillance procedures, planned maintenance activities,
operational line-up procedures, administrative procedures, and corrective action
documents to identify issues that may have contributed to the configuration control
issue, which resulted in the 11 TDAFWP failure to run upon receipt of a valid start signal.
b. Findings and Observations
The inspectors determined that the last activity that required the manipulation of the
manifold isolation valve for the 11 TDAFWP discharge pressure switch was SP 1234A,
11 Auxiliary Feedwater Pump Suction and Pressure Switches Calibration, which was
completed on February 23, 2008. Although several other surveillances required the
operation of components in the general vicinity of the manifold isolation valve, the
inspectors did not identify any additional activities that required manipulation of the valve
during February 23, 2008, to July 31, 2008.
The inspectors noted the following licensee weaknesses that may have contributed to
the configuration control issue associated with the mis-positioned manifold isolation
valve:
were not labeled with a means of permanent identification.
- Instrument and control technicians identify manifolds by tracing sensing lines
back from the applicable instrument to its associated manifold. This identification
method and instructions describing how to operate each type of manifold,
including how to identify the function of valves on each manifold, was covered as
part of instrument and control technician training.
- A double standard existed at Prairie Island regarding how a component must be
identified prior to its operation. Operators were required to positively identify a
component, by means of an approved label, prior to operating a component.
Instrument and control technicians were not held to the same standard, and
routinely operate unlabeled instrument manifolds and associated valves.
- The licensee did not positively control minor components that could impact the
performance of safety related equipment. A specific example of this was that,
even though the root valve for the 11 TDAFWP low discharge pressure switch
was locked and positively controlled via licensee processes, the manifold
isolation valve, which can perform the same isolation function and is positioned
between the root valve and the pressure switch, had no positive means to ensure
that it remained open.
The inspectors reviewed the licensees immediate and long term corrective actions
(CAP 1146005) associated with addressing the issues described above and determined
9 Enclosure
that the scope and extent of condition of the corrective actions were appropriate to
address these issues.
No findings of significance were identified.
.7 Licensees Actions to Immediately Assess the Extent-of -Condition Associated with the
11 Turbine-Driven Auxiliary Feedwater Pump Configuration Control Issue
a. Inspection Scope
The inspectors reviewed the licensees extent of condition evaluation associated with the
configuration control issue that resulted in the isolation of the 11TDAFWP discharge
pressure switch. The inspectors evaluated the licensees immediate and interim
corrective actions, associated with the licensees extent-of-condition evaluation, as they
specifically pertained to this event.
b. Findings and Observations
The inspectors reviewed documentation associated with the licensees immediate and
interim corrective actions, as they relate specifically to auxiliary feedwater and on how
they relate to similar components associated with other safety-related systems at Prairie
Island. These corrective actions included:
- Valve lineups on the auxiliary feedwater system were completed by Operations
and Instrument & Controls Departments;
- Surveillance testing was performed on the 11 TDAFWP to verify pump
operability;
- Surveillance and post maintenance testing was performed on the 11 TDAFWP
discharge and suction pressure switches to verify switch functionality;
- The suction and discharge pressure switch manifold isolation valves for all four
auxiliary feedwater pumps were lock-wired in the open position; and
- The licensee performed a sampling of similar manifold valve positions located in
other safety related systems.
The inspectors determined that the scope of the initial assessment of the extent-of-
condition associated with this event and related corrective actions were adequate.
This inspection also represented the completion of one post maintenance test
(71111.19) inspection sample.
No findings of significance were identified.
10 Enclosure
.8 Licensees Immediate Corrective Actions and Planned Long Term Corrective Actions to
Prevent Recurrence for Both the Reactor Trip and the Failure of the Turbine-Driven
Auxiliary Feedwater Pump
a. Inspection Scope
The inspectors reviewed the adequacy of the licensees immediate, interim corrective
actions, corrective actions to prevent recurrence, and long term corrective actions
associated with the reactor trip and the failure of the 11 TDAFWP to run.
b. Findings and Observations
The inspectors determined that the licensees immediate and interim corrective actions
were adequate to address the short-term challenges presented by the reactor trip and
configuration control issue associated the 11 TDAFWP.
The SIT evaluated both events, reviewed their associated root cause evaluation, and
evaluated the licensees proposed corrective actions to prevent recurrence. For the
reactor trip event, the corrective actions to prevent recurrence included:
- Replace or refurbish all flux tilt penalty (FQ)proportional controllers;
- Develop and implement a preventive maintenance strategy for the Foxboro
H-Line components in the reactor protection and control system; and
- Ensure a life cycle management plan for the reactor protection and control
systems was implemented to ensure timely preventive replacement of the
Foxboro H-Line components.
For the failure of the TDAFWP to run, the most significant corrective action to prevent
recurrence was to utilize a multi-phase process to conduct a comprehensive review of
the licensees configuration control standards. As part of this effort, the licensee will:
- Develop a process to review safety related systems to determine if there are any
small components that may adversely affect the function of a safety-related
system structure or component (SSC);
- Perform a trial of the methodology on a significant safety related system; and
- Complete this process to systematically identify all components that may
adversely affect safety related SSCs for each safety related system.
- Implement necessary changes per the process that was developed.
The inspectors noted that the corrective actions to prevent recurrence for each of these
events presented a significant challenge to the licensee to implement. The SIT
determined that if the licensee fully implemented these corrective actions in a timely
manner, the corrective actions would appropriately address the causes of each event.
No findings of significance were identified.
11 Enclosure
.9 Circumstances Surrounding the Notice of Unusual Event Declared for the Release of
Toxic Gases (Hydrazine) Deemed Detrimental to Normal Operation of the Plant and
Evaluation of the Root Cause Event Report Associated with this Event
a. Inspection Scope
The inspectors used direct observation of the event and subsequent licensee activities in
conjunction with reviews of logs and the sequence of events, and personnel interviews
to assess the circumstances associated with the event. Additionally, the inspectors
monitored the licensees root cause team activities and reviewed the final Root Cause
Evaluation report, Hydrazine NUE, associated with CAP 1146374.
b. Findings and Observations
Members of the resident staff observed the licensees response to the event from inside
the control room. Overall, the NOUE classification was declared in a timely manner and
was appropriately classified in accordance with the stations emergency plan.
The inspectors noted that the licensees root cause team used industry accepted root
cause evaluation tools (i.e., Change Analysis; Event and Causal Factor Charting; Why
Staircase). The inspectors also noted that the licensees root cause team was
comprised of multi-disciplined individuals with backgrounds in health physics, chemistry,
radiation protection, and performance assessment.
The inspectors confirmed that the addition of hydrazine to the feedwater system
following the reactor trip was performed in accordance with Electirc Power Research
Institute guidance and approved station procedures. However, the inspectors
discovered that these procedures were vague regarding what to expect when adding
hydrazine during times when the feedwater system was in a non-typical configuration.
The inspectors noted that even though existing chemistry procedures specifically
identified that the existing main condenser status and feedwater lineup was not typical,
no additional guidance was provided to the chemist on how the secondary plant would
behave differently based on that non-typical configuration. The objective of the
hydrazine addition to the feedwater system was to lower oxygen concentration by
maintaining an 8 to 1 ration of hydrazine to oxygen, but consideration was not made as
to how the non-typical configuration would affect the reaction mechanism; in this case,
the generation of airborne hydrazine/ammonia.
The inspectors noted that the timely identification of actual levels of hydrazine/ammonia
present in the lower levels of the Unit 1 turbine building was hampered by the chemists
lack of understanding associated with the air sampling equipment limitations. The
equipment used to sample for hydrazine was adversely impacted by the presence of
ammonia. The licensee concluded that if test equipment without a cross-sensitivity to
ammonia interference had been used; the airborne chemical levels would have been
appropriately characterized, eliminating the need for an evacuation of the turbine
building and declaration of a NOUE.
The SIT reviewed the licensees immediate corrective actions and found them to be
acceptable. Additionally, the Team reviewed the corrective actions to prevent
recurrence and additional long-term corrective actions and determined, if the licensee
12 Enclosure
fully implemented the corrective actions in a timely manner, the corrective actions would
appropriately address the root causes for this event.
No findings of significance were identified.
4OA6 Management Meetings
.1 Exit Meeting Summary
On October 6, 2008, the inspectors presented the inspection results to Mr. M. Wadley
and members of his staff, who acknowledged the findings. The licensee acknowledged
the information presented. The inspectors asked the licensee whether any materials
examined during the inspection should be considered proprietary. No proprietary
information was identified.
.2 Interim Exit Meetings
No interim exits were conducted.
ATTACHMENTS: 1. SUPPLEMENTAL INFORMATION
2. TIMELINE OF EVENTS UNIT 1
3. SPECIAL INSPECTION TEAM CHARTER
13 Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
M. Wadley, Site Vice President
S. Northard, Plant Manager
C. Mundt, General Supervisor I&C Maintenance
S. Nelson, Fleet RP/Chemistry Manager
R. Hite, RP/Chemistry Manager
M. Kent, General Supervisor, RP
L. Clewett, Operations Manager
M. Schmidt, Maintenance Manager
S. Myers, Design Engineering Manager
S. Lappegaard, On-Line Work Manager
J. Callahan, Emergency Preparedness Manager
J. Muth, Nuclear Oversight Manager
E. Weinkam, Director, Nuclear Licensing
J. Anderson, Regulatory Affairs Manager
M. Davis, Regulatory Compliance Analyst
Nuclear Regulatory Commission
R. Skokowski, Chief, Branch 3
S. Thomas, Senior Resident Inspector [Monticello]
K. Stoedter, Senior Resident Inspector [Prairie Island]
P. Zurawski, Resident Inspector [Prairie Island]
D. Betantcourt, Reactor Engineer
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000282/2008008-01 AV 11 TDAFWP Inoperable for a Time Period Which
Significantly Exceeded Time Allowed by TS
Closed
None
Discussed
None.
1 Attachment 1
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection. Inclusion on this list does
not imply that the NRC inspectors reviewed the documents in their entirety, but rather, that
selected sections of portions of the documents were evaluated as part of the overall inspection
effort. Inclusion of a document on this list does not imply NRC acceptance of the document or
any part of it, unless this is stated in the body of the inspection report.
WORK ORDERS
Number Description or Title Date or Revision
00365604 Red Channel OTDT Failure Investigation January 31, 2008
55698-02 EC Power Ascension Test 8
00365655 Investigation of 11 TDAFW Pump Trip
CORRECTIVE ACTION PROGRAM DOCUMENTS REVIEWED
Number Description or Title Date or Revision
01145953 Red Channel Setpoint Failed Low Causing Reactor
Trip
00866960 Top Ten Equipment List Addition - Foxboro H-Line
01146430 Potential Adverse Trend in Manifold Valve Operation
01145943 11 AFW Pump Started and then Tripped
01145964 11 AFWP Trip after Plant Trip
01145996 Temporary Oil Lift Pump had Inadequate Pressure
01146005 Mispositioned Block Valve on 11 TDAFWP
01147573 RPIP 3005 Procedure Compliance Issue
01010095 Benchmark Industry Regarding Labeling of
Instrument Valves
01146889 USAR AFW Time Critical Actions for MFW/MSL
Break Question
01146027 CC Piping Adjacent to HELB Location in Unit 2
Turbine Building
2 Attachment 1
CORRECTIVE ACTION PROGRAM DOCUMENTS REVIEWED
Number Description or Title Date or Revision
01146120 U1 Secondary Exceeds EPRI Guidelines for
Oxygen/Hydrazine Condensate Oxygen is 6500ppb
01146304 NUE HU3.1- Potential Plant Equipment Impact from
Hydrazine
01146374 U1 NOUE: High Airborne Hydrazine Levels on 695
EL Turbine Building
01146357 Minor Errors in NRC Notification Forms for Hydrazine
Event
AR 01146974 Prompt Investigation for NUE: Airborne Hydrazine
Excursion
PROCEDURES
Number Description or Title Date or Revision
SP 1003 Analog Protection Functional Test 63
SP 1002A Analog Protection System Calibration 37
C1.6A.1-1 Unit 1 - Integrated Operations Checklist Prior to 10
Heatup, First Floor Turbine Building
C28-7 Auxiliary Feedwater System Unit 2 49
C1.6A.1-2 Unit 2 - Integrated Operations Checklist Prior to 9
Heatup, First Floor Turbine Building
C1.6A.3-1 Unit 1 - Integrated Operations Checklist Prior to 8
Heatup, First Floor Auxiliary Building
1ES-0.1 Reactor Trip Recovery 23
C47010-0205 11 TD AFWP Lo Suct or Disch Press Trip 38
1C28.1 AOP4 Restarting Unit 1 AFWP after Low Suction/Discharge 3
Pressure Trip
SWI O-35 Emergency Operating Procedure Verification, 6
Validation and Maintenance
SP 1102 11 Turbine-Driven AFW Pump Monthly Test 89
SP 1054 Turbine Stop, Governor, Reheat Stop and Reheat 35
Intercept Valve Exercise.
C28-1 Auxiliary Feedwater System - Unit 1 44
3 Attachment 1
PROCEDURES
Number Description or Title Date or Revision
ICPM 1-416 11 Turbine Driven Aux Feed Pump Instruments 3
Calibration
D14.4 AOP1 Chemical Leak or Spill Implementing Procedure 8
SP 1103 11 Turbine-Driven Auxiliary Feedwater Pump Once 45
Every Refueling Outage Shutdown Flow Test
SP 1193 Cycling AFWP and CLG Water MVs 33
SP 1376 AFW Flow Path Verification Test after each Cold 11
Shutdown
SP 1355A Train A AFW Check Valve Testing 11
SP 1234A 11 Aux Feedwater Pump Suction and Discharge 6
Pressure Switches Calibration
SP 1100 12 Motor Driven AFW Pump Monthly Test 75
5AWI 3.10.5 Plant Equipment Labeling 13
RPIP 3002 EPRI Secondary Water Chemistry Guidelines 17
RPIP 3000 Plant Startup Guidelines 12
RPIP 3005 Secondary Chemical Feed System 14
RPIP 3001 Plant Shutdown Guidelines 10
RPIP 3303 Airborne Chemical Determination 4
REFERENCES
Number Description or Title Date or Revision
N/A Top 10 Equipment List; Foxboro H-Line July 15, 2008
N/A Reactor Trip Report for July 31, 2008, Reactor Trip
NF-39222 Flow Diagram - Unit 1 Feedwater System 76
NF-40312-1 Interlock Logic Diagram - Unit 1 Auxiliary Feedwater 76
System
N/A LCO Entry Report for 12 MDFP for the Time Period of
February 1, 2008 to July 31, 2008
N/A Strategic Water Chemistry Plan for PINGP Secondary 8
Water Chemistry
N/A RPCHEM On-the-Job Training and Task Performance 8
Evaluation Review Guide
4 Attachment 1
REFERENCES
Number Description or Title Date or Revision
N/A RPCHEM On-the-Job Training and Task Performance 0
Evaluation Guide
5 Attachment 1
LIST OF ACRONYMS USED
CAP Corrective Action Program
CDF Core Damage Frequency
HEP Human Error Probability
IMC Inspection Manual Chapter
IP Inspection Procedure
IPEEE Individual Plant Examination for External Events
MD Management Directive
NCV Non-Cited Violation
NOUE Notice of Unusual Event
NRC Nuclear Regulatory Commission
OTT Overtemperature Delta Temperature
RASP Risk Assessment of Operational Events
SSC System Structure or Component
SDP Significance Determination Process
SIT Special Inspection Team
SRA Senior Reactor Analyst
TDAFWP Turbine-Driven Auxiliary Feedwater Pump
TS Technical Specification
6 Attachment 1
Historical Timeline of Events for THE Reactor trip, 11 Turbine-Driven Auxiliary feedwater
pump fail to run, and the turbine building hydrazine unusual event
DATE, 2008 TIME DESCRIPTION
February 23 1833 SP 1234A Suction/Discharge Pressure Switch Calibration
March 8 PM 3132-1-11 11 TDAF Pump Minor Periodic Maintenance
C1.6A.1-1 Integrated Operation Checklist Prior to Heat Up Includes
March 11 1500
the Verification of 17700 Bottom Isolation in the Open Position
SP 1301- 11 TDAFW Pump Auto Start and Functional Refueling
March 12 Outage Test. Closed and then Open 17704 Bottom Isolation Valve
(in the vicinity of 17700)
March 26 2226 SP 1102 - 11 TDAFW Pump Monthly Test
May 1 0049 SP 1102 - 11 TDAFW Pump Monthly Test
May 29 0441 SP 1102 - 11 TDAFW Pump Monthly Test
June 26 0423 SP 1102 - 11 TDAFW Pump Monthly Test
SP 1003 Analog Protection Functional Test
July 31
[yellow channel bistables in per SP]
Unit 1 Reactor Trip and 11 TDAFW Pump Auto Start Operators
0817 Enter 1E-0
11 TDAFW Pump Low Discharge Pressure trip (42 sec run) Unit 1
0818
Enters Mode 3
0819 Operators Transition to 1ES-0.1, Reactor Trip Recovery
11 TDAFWP Low Suction/Discharge Pressure Trip Annunciator.
0821
Operator Dispatched
After Trip of AFWP, with Severe Weather, PRA is Yellow for both
0822
Unit 1 and Unit 2
Attachment J of 1E-0, Isolate Unit 1 MSR's, is Complete 0905
0826
Operators Transition to 1C1.3, Unit 1 Shutdown
12 MDAFW Pump Stopped and SG Level Control via Main FW via
0855
Bypass Valves
RP Tour of Aux Building Indicated no Alarms, Leaking Water or
0914
Steam
11 TDAFW Pump Reported to have Auto Started and Run for
0915
Approximately 50 Seconds
1012 Operators Notify NRC of Reactor Trip per 10 CFR 50.72
1055 11 TDAFW Pump Area Quarantined
Completed C28-2 (U1 AFW System Checklist) Found Manifold
1323
Block Valve for 17700 Closed
1 Attachment 2
1400 Commenced Breaking U1 Condenser Vacuum
1500 SP 1102 - 11 TDAFW Pump Monthly Test
SP 1234A Suction/Discharge Pressure Switch Calibration Close
August 1 0619
then Open 17700 Bottom Isolation
FW Chemistry: 9575 ppb Oxygen; 31132 ppb N2H4 ; Condenser
August 2 1200
Chemistry: 7424ppb Oxygen
1543 U1 Reactor Entered Mode 2
1738 U1 Reactor Critical
1815 Reactor Power at Point of Adding Heat
FW Chemistry: 9032 ppb Oxygen; 37410 ppb N2H4 ; Condenser
2000
Chemistry: 7247 ppb Oxygen
2007 Initiated Condenser Vacuum
2133 U1 Entered Mode 1
FW Chemistry: 165 ppb Oxygen; Condenser Chemistry: 163 ppb
2315
August 3 0028 Started Rolling U1 Main Turbine to 600 rpm
0040 Started Rolling U1 Main Turbine from 600 rpm to 1800 rpm
0125 Reactor Power 8%
0208 Reactor Power 15%
Duty Chemistry Reports Positive Hydrazine Air Sample Results
from Unit 1 Condenser Pit and the 695' Level Top of a Stairway
0341
into Condenser Pit (value less than IDLH). Chemist Placed
Barriers to Stop Access.
0352 Declared NOUE (HU3.1)
Announcement Made to Evacuate Unit 1 695 Turbine Building and
0356
Condenser Pit
Air Sample Results from Hydrazine: 695' by Old Admin Building
0403 Door 0.25 ppm; 715' Outside Access Control 1 ppm; 735' Next to
HP Turbine 3 ppm; Control Room < 0.1 ppm
NRC Resident Inspector and Duty Station Manager Notified of
0416 NOUE Declaration HU3.1 due to High Levels of Hydrazine in Unit 1
Turbine Building Sump Area
Chemist Reports no Detectible Hydrazine in Air Sample outside D1
0440
and D2
Chemist Air Samples Show that 715 and 735 Levels of Unit 1
0506
Turbine Building had Stayed Habitable
2 Attachment 2
All Hydrazine Samples on the 735' Unit 1 Turbine Building are
Below the 1.00 ppm Permissible Exposure Limit (PEL); Highest
0647
was 0.75 ppm at the HP Turbine. Normal Access Restored to 735'
Unit 1 Turbine Building.
Access to the 695' Unit 1 Turbine Building Restored with the
0818
Exception of the Southwest Corner Marked with Danger Tape.
Entered Loss of Hydrazine Feed Condition (PINGP 1597 & PINGP
0910
1537; RPIP-3002) for Securing Hydrazine Addition
Hydrazine air samples are as follow: 735' HP Turbine area and
715' by 15 A FWH < 0.1 ppm; 715' by Hoggers 0.5 ppm; 695' on
top of stairs at SW corner of condenser pit 2ppm; 675' north side at
1040 bottom of the stairs 0.75 ppm; 675' by Amertap control panel 3
ppm; sump area under catwalk 0.75 ppm; South side of Condenser
pit by the Heater Drain Pumps < 0.1 ppm; and Next to Turbine
Building Sump Bay # 2 3 ppm
Entered Action Level 1 for Loss of Hydrazine. Hold at < 30%
1115
Power for Low Oxygen Levels and Hydrazine
Chemistry Pulled Liquid Dample from Both Unit 1 Turbine Building
1200 Sump Bays for Hydrazine Analysis. Airborne Level at #2 Bay was
< 0.1 ppm
Liquid Samples Reported as 18 ppb (bay 1), 21 ppb (bay 2) and 53
1337
ppb (bay 3). No Action Required for These Concentrations.
Started Adding Hydrazine to Unit 1 FW System. Walkdowns of
1349 Hydrazine Addition Piping Indicates no Visual Leakage. Access
Limited to 695' Unit 1 Turbine Building Until Surveys Completed
Surveys of 695' U1 Turbine Building Indicate no Levels Above 0.1
1420
ppm and All Postings of that Level Removed
Hydrazine Air Samples 30 Minutes after Initiating Injection to
Feedwater System were: 695' at top of Condenser Pit Stairway
SW Corner < 0.1ppm, Postings Taken Down from Entire 695' Level
1430 and Cleared for Normal Access; 675' by Unit 1 Turbine Building
Sump Bay 2 was 5 ppm; Amertap Control Panel 1 ppm; MCC 1EA
Bus 2 2.0 ppm; and Chemist Reported that the Ammonia Smell
was Limited to Small Pockets of Stagnant Air
Exited Action Level 1 and loss of Hydrazine Conditions. Exited
1448
Chemical Hold on Power
1530 Commenced Power Accession to 50%
3 Attachment 2
Ventilation Fans Started on the North and South Sides of Unit 1
1618
Condenser Pit for Mixing
1629 Commenced power accession to 70%
Hydrazine Air Samples are as Follows: Airborne near Turbine
Building Sump Bay 2 < 0.1 ppm; and near MCC 1EA Bus 2 0.3
ppm
1649
Liquid samples Reported as 8.2 ppb (bay 1), 7.7 ppb (bay 2) and
13.8 ppb (bay 3)
Maintenance Workers Entered Unit 1 Condenser Pit to Place Fans
1709
in Pit.
Exited the Notification of Unusual Event (NOUE) HU3.1, Release
2220 of Toxic or Flammable Gases after 3 Consecutive Samples
Returned Less than Detectable Hydrazine (< 0.1 ppm)
4 Attachment 2
August 1, 2008
MEMORANDUM TO: Christopher S. Thomas, Senior Resident Inspector
Monticello Station
FROM: Cynthia D. Pederson, Director
Division of Reactor Projects
SUBJECT: SPECIAL INSPECTION CHARTER FOR REACTOR TRIP AND
TURBINE-DRIVEN AUXILIARY FEED WATER FAILURE ON
JULY 31, 2008
On July 31, 2008, at 8:17a.m., the Unit 1 reactor tripped at the Prairie Island Site. At the time,
the yellow train of reactor trip system (RTS) instrumentation was out of service for RTS testing.
The red channel then received an overtemperature T signal. This met the 2 of 4 channel logic
which caused the reactor trip. At this time the cause of the overtemperature T signal on the
red channel is unknown, but the licensee believes it was a spurious signal.
Following the reactor trip, the turbine driven auxiliary feedwater pump started and ran for
approximately 50 seconds before tripping on low suction/pressure. The pressure switch for
discharge pressure was found to be closed. The closure of this switch caused the pump to trip
as part of the pump protection features. The last time a surveillance test was performed on the
turbine driven auxiliary feedwater pump was over 30 days before on June 21, 2008, however
the discharge pressure switch impact may not have been challenged during this surveillance
test.
The sequence of events and the cause of the problem are being investigated by the licensee.
Based on the deterministic criteria provided in Management Directive 8.3, ANRC Incident
Investigation Program, @ the incident met MD 8.3 criterion h, AInvolved questions or concerns
pertaining to licensee operational performance.@ A Region III Senior Reactor Analyst completed
a SPAR model event assessment using a transient initiating event and failure of the auxiliary
feed water system to run and the pre-existing maintenance unavailability of instrument air
compressor 121. The assessment resulted in a preliminary Incremental Conditional Core
Damage Probability (ICCDP) value of approximately 5.2E-6.
Accordingly, based on the deterministic and risk criteria in MD 8.3, and as provided in Regional
Procedure 8.31, ASpecial Inspections at Licensed Facility,@ a Special Inspection Team will
commence an inspection on July 31, 2008. The Special Inspection Team will be led by you and
will include Karla Stoedter, the Senior Resident Inspector, Prairie Island, and Diana Betancourt,
Reactor Engineer, Region III.
CONTACT: Richard Skokowski
630-829-9620
1 Attachment 3
C. Thomas -2-
The special inspection will determine the sequence of events, and will evaluate the facts,
circumstances, and the licensee=s actions surrounding the July 31, 2008 incident. The specific
charter for the Team is enclosed.
Enclosure: As Stated
cc w/encl: J. Caldwell, Regional Administrator, Region III
M. Satorius, Deputy Regional Administrator, Region III
H. Peterson, DRS, Chief, Operator Licensing Branch
K. Stoedter, SRI, Prairie Island
P. Zurawski, RI, Prairie Island
D. Betancourt-Roldan, Reactor Engineer, RIII
2 Attachment 3
PRAIRIE ISLAND SPECIAL INSPECTION CHARTER
This Special Inspection Team is chartered to assess the circumstances surrounding the
deviation from the required safety system lineup of the auxiliary feed water system during a
reactor shutdown on July 31, 2008. The Special Inspection will be conducted in accordance
with Inspection Procedure 93812, Special Inspection, and will include, but not be limited to, the
items listed below.
1. Identify the time-line for the event. Include plant conditions, system line ups, and
operator actions.
2. Review the licensees post-trip review to determine the cause of the reactor trip.
Independently review plant data and records to confirm the adequacy of the licensees
assessment, and corrective actions.
3. Review the circumstances surrounding the failure of the turbine-driven auxiliary
feedwater pump, including the most likely cause of the pump failure; the length of time
the pump may have been in an unrecognized failed condition, and any potential for
operators to recover the failed pump.
4. Determine if the licensee is performing a root cause for the reactor trip. As available,
evaluate the scope, schedule, staffing and results of the licensees root cause
investigation.
5. Determine if the licensee is performing a root cause for the turbine-driven auxiliary
feedwater pump failure. As available, evaluate the scope, schedule, staffing and results
of the licensees root cause investigation.
6 Review procedures for the turbine-driven auxiliary feedwater pump, including operational
line-up procedures and testing procedures, to assess any procedural or testing
inadequacies which may have contributed to the failure of the pump.
7. Determine if the licensee performed an extent-of-condition evaluation to assess if the
contributing causes to the failure of the turbine-driven auxiliary feedwater pump have the
potential to affect other safety-related equipment.
8. Review for adequacy the licensees immediate corrective actions and planned long term
corrective actions to prevent recurrence for both the reactor trip and the failure of the
turbine-driven auxiliary feedwater pump.
Charter Approval
/RA/ R. Skokowski, Chief, Branch 3, DRP
/RA by G. Shear for/ C. Pederson, Director, Division of Reactor Projects
3 Attachment 3