ML17033B599
| ML17033B599 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 02/02/2017 |
| From: | Joel Munday Division Reactor Projects II |
| To: | Nazar M Florida Power & Light Co |
| References | |
| EA-17-013 EA-17-013, IR 2016012 | |
| Download: ML17033B599 (13) | |
See also: IR 05000335/2016012
Text
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UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
245 PEACHTREE CENTER AVENUE NE, SUITE 1200
ATLANTA, GEORGIA 30303-1257
February 2, 2017
Mr. Mano Nazar
President and Chief Nuclear Officer
Nuclear Division
Florida Power & Light Co.
Mail Stop: NT3/JW
15430 Endeavor Drive
Jupiter, FL 33478
SUBJECT: ST. LUCIE PLANT - NRC INSPECTION REPORT 05000335/2016012 AND
Dear Mr. Nazar:
On December 19, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your St. Lucie Plant, Unit 1, and inspectors discussed the results of this inspection
with Mr. Chris Costanzo, Site Vice President, and other members of your staff. On January 27,
2017, the resident inspectors presented the preliminary safety significance to Mr. Dan Deboer,
Site Director, and other members of the licensees staff. The results of this inspection are
documented in the enclosed report.
Section 4OA3 of the enclosed report documents a finding that the NRC has preliminarily
determined to be White, with low-to-moderate safety significance. This finding involved a failure
to maintain configuration control of the Unit 1 main generator inadvertent energization lockout
relay circuitry, which resulted in a reactor trip and loss of offsite power (LOOP) on August 21,
2016. We assessed the significance of the finding using the significance determination process
(SDP) and readily available information.
We intend to issue our final significance determination in writing, within 90 days from the date of
this letter. The NRCs significance determination process (SDP) is designed to encourage an
open dialogue between your staff and the NRC; however, neither the dialogue nor the written
information you provide should affect the timeliness of our final determination.
As described in NRC Inspection Manual Chapter 0612, a finding may or may not be associated
with regulatory non-compliance and, therefore, may or may not result in a violation. Based on
the review of this issue and in accordance with NRC Inspection Manual Chapter 0612, the NRC
determined that no violation of a regulatory requirement occurred.
Enclosure(s) transmitted herewith contain(s) SUNSI. When separated from enclosure(s), this
transmittal document is decontrolled.
LIMITED INTERNAL
DISTRIBUTION PERMITTED
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M. Nazar 2
Before we make a final decision, you may choose to communicate your position on the facts
and assumptions used to arrive at the finding and assess its significance by either (1) attending
and presenting at a regulatory conference, or (2) submitting your position in writing. The focus
of a regulatory conference is to discuss the significance of the finding. Written responses
should reference the inspection report number and enforcement action number associated with
this letter in the subject line.
If you request a regulatory conference, it should be held within 40 days of your receipt of this
letter. Please provide information you would like us to consider or discuss with you at least ten
days prior to any scheduled conference. If you choose to attend a regulatory conference it will
be open for public observation. If you decide to submit only a written response, it should be
sent to the NRC within 40 days of your receipt of this letter. If you choose not to request a
regulatory conference or to submit a written response, you will not be allowed to appeal the
NRCs final significance determination.
Please contact LaDonna B. Suggs, Chief, Reactor Projects Branch 3, at (404) 997-4539, or in
writing, within ten days from the issue date of this letter to notify the NRC of your intentions. If
we have not heard from you within ten days, we will continue with our significance
determination.
This letter, its enclosure, and your response (if any) will be made available for public inspection
and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document
Room in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Requests for
Withholding.
Sincerely,
/RA/
Joel T. Munday, Director
Division of Reactor Projects
Docket No.: 50-335
License No.: DPR-67
Enclosure:
w/Attachments:
Supplemental Information
Detailed Risk Assessment (OUO-SRI)
cc Distribution via ListServ
(Cover letter and Report w/o Detailed Risk Assessment attachment)
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ML17034A050 (Cover letter w/ enclosures)
ADAMS ACCESSION NUMBER: ML17033B599 (Cover letter & IR Report only)
Entire Report w/attachment: SENSITIVE NON-PUBLICLY AVAILABLE Keyword:
SUNSI REVIEW OMPLETE NON-SENSITIVE PUBLICLY AVAILABLE MD. 3.4 Non Public A.3
By:Lundy Pressley
Cover Letter/Report Only SENSITIVE NON-PUBLICLY AVAILABLE Keyword:
SUNSI REVIEW OMPLETE NON-SENSITIVE PUBLICLY AVAILABLE SUNSI REVIEW COMPLETE
By:Lundy Pressley
OFFICE RII:DRP RII:DRP RII:DRP RII:DRP RII:DRP EICS
SIGNATURE LP via email TM via email SR LS JTM MK
NAME L Pressley T Morrissey S Roberts L Suggs JMunday M Kowal
DATE 2/1/17 2/1/17 2/1/17 2/1/17 2/ 2 /2017 2/1/17
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U. S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50-335
License Nos: DPR-67
Report Nos: 05000335/2016012
Licensee: Florida Power & Light Company (FP&L)
Facility: St. Lucie Plant, Unit 1
Location: 6501 South Ocean Drive
Jensen Beach, FL 34957
Dates: August 21, 2016 - December 19, 2016
Inspectors: T. Morrissey, Senior Resident Inspector
S. Roberts, Resident Inspector
J. Hanna, Senior Reactor Analyst
Approved by: Joel T. Munday, Director
Division of Reactor Projects
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Enclosure
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SUMMARY
IR 05000335/2016012; August 21, 2016 - December 19, 2016; St. Lucie Nuclear Plant, Unit 1,
Follow-up of Events and Notices of Enforcement Discretion
This report covers approximately a four-month period of inspection by resident inspectors. One
finding with preliminary significance was identified by the inspectors. The significance of
inspection findings are indicated by their color (Green, White, Yellow, Red) using Inspection
Manual Chapter (IMC) 0609, issued April 29, 2015, Significance Determination Process. The
cross-cutting aspect was determined using IMC 0310, Components Within the Cross-Cutting
Areas, dated December 4, 2014. The NRCs program for overseeing the safe operations of
commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Revision 6.
Cornerstone: Initiating Events
- To Be Determined (TBD). A self-revealing finding was identified for the licensees failure to
maintain configuration control of the inadvertent energization lockout relay manual
synchronization circuitry as required by licensee procedures MA-AA-100 and ADM-08.12,
during the October 2013 modification to the Unit 1 automatic main generator
synchronization circuit.
The performance deficiency was more than minor because it was associated with the
human performance attribute of the Initiating Events Cornerstone and it adversely affected
the associated cornerstone objective of limiting the likelihood of events that upset plant
stability and challenge critical safety functions because it resulted in an actual plant trip.
The inspectors screened the finding under the initiating events cornerstone using
Attachment 4 (October 7, 2016) and Appendix A (June 19, 2012) of Inspection Manual
Chapter 0609, Significance Determination Process (April 29, 2015). The inspectors
determined the finding required a detailed risk evaluation because the finding caused a
reactor trip and the loss of mitigation equipment relied upon to transition the plant from the
onset of the trip to a stable shutdown condition (e.g. loss of condenser and loss of
feedwater). A preliminary significance characterization of White has been assigned. The
preliminary finding involved the cross-cutting area of human performance associated with
the cross-cutting aspect of avoiding complacency because the individuals involved failed to
recognize and plan for the possibility of mistakes, latent issues, and inherent risk and failed
to implement human error reduction tools associated with configuration control. (H.12)
(Section 4OA3).
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REPORT DETAILS
4. OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
4OA3 Followup of Events and Notices of Enforcement Discretion (71153)
.1 (Closed) Licensee Event Report (LER) 05000335/2016-003-00, Generator Lockout
Relay Actuation During Power Ascension Results in Reactor Trip
a. Inspection Scope
On August 21, 2016, during a Unit 1 restart following a maintenance outage, the main
generator inadvertent energization lockout relay unexpectedly actuated which caused
the main generator to trip resulting in an automatic reactor trip. The relay actuation
prevented the automatic transfer of station auxiliaries to the startup transformers and
resulted in a LOOP, although offsite power remained available at the switchyard. The
inspectors reviewed the LER and associated root cause evaluation (action request (AR)
2151217) to verify the accuracy and completeness of the LER and the appropriateness
of the corrective actions. The LER was also reviewed to identify any licensee
performance deficiencies (PDs) associated with the event. Documents reviewed are
listed in the Attachment. This LER is closed.
b. Findings
Introduction: A self-revealing finding was identified for the licensees failure to maintain
configuration control of an electrical wire during the October 2013 installation of a digital
upgrade to the Unit 1 automatic main generator synchronization circuit.
Description: On August 21, 2016, during a normal power ascension for Unit 1, the
reactor tripped, from approximately 38 percent reactor power, when the inadvertent
energization generator lockout relay actuated. The relay actuation prevented the
automatic transfer of station auxiliaries to the startup transformers which resulted in a
complicated trip (i.e. loss of main feedwater, main condenser, offsite power to the safety
related buses and all reactor coolant pumps.) Offsite power remained available at the
switchyard during this event. Both emergency diesel generators started and powered
the safety related buses. Operators manually restored power to the buses after verifying
availability.
The main generator inadvertent energization lockout relay was a protective relay that
was designed to be armed when the main generator was offline and had a set point of
8000 amps. This protective feature was designed to prevent damage to the main
generator, which could be incurred through motoring in the event the output breakers
were closed unintentionally with the main generator offline. The synchronization circuit
was designed to automatically bypass the inadvertent energization lockout relay when
the main generator was synchronized to the grid, using either manual or automatic
synchronization methods.
The licensees investigation found that the inadvertent energization lockout relay
remained armed following manual synchronization of the main generator to the electrical
grid on August 21, 2016, due to a missing wire in the manual synchronization circuit.
The missing wire prevented the relay from performing its disarming function as required
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3
during main generator synchronization. The licensee replaced the missing wire and an
appropriate post maintenance test was completed. The licensee performed a root cause
evaluation (AR 2151217) and identified one root cause, which was; incorrect removal of
a wire during an October 2013 modification to restore the automatic synchronization
capabilities of the generator breakers. Corrective actions included: replacement of the
missing wire, and implementing procedure guidance for both units to verify the
inadvertent energization lockout relay was reset prior to exceeding 8000 amps.
The manual synchronization performed on August 21, 2016, was the first manual
synchronization utilized since the digital modification was installed in October 2013. The
missing wire did not impact the disarming function of the inadvertent energization lockout
relay following automatic synchronization. From June 2010, until automatic
synchronization was restored in October 2013, manual synchronization to the grid had
been utilized successfully, therefore the wire in question had been properly installed
prior to the modification in October 2013.
Licensee procedure MA-AA-100, Conduct of Maintenance, Revision 15 (2013), Section
5.11, Configuration Control, stated in part, that each site shall have a configuration
control procedure that provided step by step instructions for conducting configuration
changes in the plant. The procedure stated that configuration changes included the
lifting of leads, and installing and removing electrical jumpers. A wire is considered the
same as an electrical lead or conductor. Licensee administrative procedure ADM-
08.12, Maintenance Configuration Control, Revision 2 (2013), Section 1.2, Scope,
included configuration changes such as lifting leads, and installing and removing
electrical jumpers. Section 4.1, Configuration Control, stated in part, to perform all
component manipulations and changes per the following: detailed procedure or written
instructions.
The digital automatic synchronization modification performed in October 2013 was
installed under written instructions as work order (WO) 40038386, which implemented
engineering change (EC) 274642, SYNC/888: Auto Sync Not Working. The
instructions directed the de-termination and removal of conductors in the main generator
synchronization circuit, however the wire/conductor that was erroneously removed was
not within the scope of the WO. The licensee concluded that the wire was removed
erroneously. Therefore the removal was not performed in accordance with procedures
MA-AA-100, Conduct of Maintenance and ADM-08.12, Maintenance Configuration
Control which resulted in a loss of configuration control.
In the period between October 2013, and August 21, 2016, the licensee had only utilized
the functional automatic synchronization circuit. Therefore when using this method for
synchronization the licensee fully met Technical Specification (TS) 3.8.1.1, which
required a minimum of two physically independent alternating current (AC) circuits
between the offsite transmission network and the onsite Class 1E distribution system in
addition to TS 3.8.1.2, for shutdown, that requires one circuit between the offsite and
onsite distribution system. Therefore during this period the electrical power systems
were capable of performing their specified safety functions as detailed in the Updated
Final Safety Analysis Report (UFSAR), Chapter 8, Electric Power.
On August 21, 2016, when the licensee utilized the non-conforming manual
synchronization circuit they unknowingly introduced the susceptibility of a LOOP. The
manual synchronization was performed at approximately 1202 hours0.0139 days <br />0.334 hours <br />0.00199 weeks <br />4.57361e-4 months <br />. The LOOP
occurred at approximately 1926 hours0.0223 days <br />0.535 hours <br />0.00318 weeks <br />7.32843e-4 months <br /> with restoration of offsite power from one
electrical bus at approximately 2012 hours0.0233 days <br />0.559 hours <br />0.00333 weeks <br />7.65566e-4 months <br /> and two electrical buses at approximately
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4
2036 hours0.0236 days <br />0.566 hours <br />0.00337 weeks <br />7.74698e-4 months <br />. However, up until the actual moment that the inadvertent relay actuation
occurred the electrical system could have performed its specified safety function.
TS 3.8.1.1 Limiting Condition of Operation (LCO) condition d, stated that with two of the
required offsite AC circuits inoperable restore within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in Hot Standby with
6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The licensee was in Hot Standby immediately following the reactor trip and
restored the operability of two offsite AC circuits in approximately 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and 34 minutes,
from initial susceptibility until full restoration, and therefore, did not violate the TS and
LCO requirements.
Analysis: The failure to maintain configuration control of the inadvertent energization
lockout relay manual synchronization circuitry wire as required by licensee procedures
MA-AA-100 and ADM-08.12 was a performance deficiency (PD). Specifically, this failure
to maintain configuration control resulted in an erroneously removed wire from the
manual synchronization circuitry which resulted in a reactor trip. The PD was more than
minor because it was associated with the human performance attribute of the Initiating
Events Cornerstone. The PD adversely affected the cornerstone objective of limiting the
likelihood of events that upset plant stability and challenge critical safety functions
because the PD resulted in an actual reactor trip with complications.
The inspectors screened the finding using Inspection Manual Chapter (IMC) 0609, Initial
Characterization of Findings, Attachment 4, (October 7, 2016), under the initiating
events cornerstone because the event resulted in a transient with a reactor trip, loss of
offsite power and loss of feedwater. Attachment 4 of IMC 0609, then routed the
screening to IMC 0609, Appendix A, The Significance Determination Process (SDP) for
Findings At-Power, (June 19, 2012). Using IMC 0609, Appendix A, Exhibit 1 -
Initiating Events Screening Questions, under B. Transient Initiators the inspectors
determined the finding required a detailed risk evaluation because the finding caused
both a reactor trip and the loss of mitigation equipment relied upon to transition the plant
from the onset of the trip to a stable shutdown condition (e.g. loss of condenser and loss
of feedwater).
A preliminary significance characterization has been assigned, however the
characterization is not yet finalized. The finding does not represent an immediate safety
concern because the main generator synchronization circuit has been restored to allow
automatic bypassing of the inadvertent energization lockout relay during manual as well
as automatic synchronizations.
A Regional SRA performed the detailed risk assessment by using the NRCs
Standardized Plant Analysis Risk (SPAR) model for St. Lucie Unit 1 and setting the Plant
Centered LOOP frequency equal to 1.0 because the event actually occurred. The initial
result was approximately 2E-5 (Yellow). The dominant risk sequence was a Plant
Centered LOOP 02-11 where CST depletion occurs and long term heat removal fails.
This type of sequence contributed 80 percent (1.4E-5 / 1.73E-5) of the total internal
events CDF. Through a visit to the St. Lucie site involving simulator observations,
plant walkdowns, procedure reviews and interaction with NextEra risk staff, the analyst
further refined the analysis and gave additional credit for operator actions for:
- Condensate Storage Tank refill from one of a number of potential sources,
including crosstie capability from Unit 2, depressurization of the steam
generators and using tools and apparatus as described in 10 CFR 50.54(hh)(2),
commonly known as B.5.(b) equipment, or Mitigating Strategies-FLEX
equipment. A comprehensive Human Error Probability representing any/all of
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5
those three potential sources was created using the SPAR-H methodology and
assigned a value of 1E-2.
- Propping open doors and installing temporary ventilation for the Reactor Auxiliary
Building electrical equipment rooms. Certain accident sequences in the risk
results had failures of the 5A and 5B exhaust fans which would ultimately cause
failure of electrical equipment and consequently the mitigating system equipment
which is powered by it. A Human Error Probability which would limit room heat
up < 120F was created using the SPAR-H methodology and assigned a value of
1E-1.
When applied to the cutset results, these two additional factors reduced the calculated
CDF to 2E-6. The detailed risk evaluation was completed on December 5, 2016, and
was peer reviewed by another SRA on December 14, 2016. Please refer to the Detailed
Risk Assessment in the Attachment accompanying this inspection report for the
complete analysis.
Subsequently the licensee performed additional analyses that appeared to show the risk
was less than 1E-6 (Green). The SRA continued to engage the licensee in discussions
and perform sensitivity analyses based on the licensees input to verify the initial result
continued to be valid, i.e., White. The factors that the licensee asserted should be given
additional credit for in the risk model (and which the NRC agreed with) were:
- Condensate Storage Tank unavailability was changed from 1.6E-1 to 8E-3,
based on historical data provided by the licensee from the last 3 years.
- Recovery factor for Loss of Offsite Power Sequences was set equal to 1E-1.
(Historically the SPAR models have included recovery credit for Station Blackout
sequences, but not for LOOP sequences.)
- Basic event representing the operators failing to initiate feed and bleed primary
injection cooling was changed from 2E-2 to 1E-2. This change was made based
on the lower decay heat level in the reactor core at 40 percent reactor power
(when the performance deficiency would cause a LOOP), thus providing the
operators approximately 50 percent more time to complete the action.
When applying these additional recovery credits, and when applying additional credit to
the CST and emergency ventilation recovery actions mentioned above (one order of
magnitude decrease in each case) the risk result remained greater than 1E-6 (White).
The preliminary finding involved the cross-cutting area of human performance and was
associated with the cross-cutting aspect of avoiding complacency because the
individuals involved failed to recognize and plan for the possibility of mistakes, latent
issues, and inherent risk and failed to implement appropriate error reduction tools.
Specifically the licensee failed to plan for the inherent risk of errors during the removal of
unnecessary conductors in the circuit and failed to implement human error reduction
tools associated with configuration control. [H.12].
Enforcement: The inspectors did not identify a violation of regulatory requirements
associated with this finding. Because the finding did not involve a violation of regulatory
requirements and the significance has not been determined, it is identified as FIN
05000335/2016012-01, Failure to Maintain Component Configuration Control Resulted
in a Complicated Reactor Trip
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6
4OA6 Meetings, Including Exit
On December 19, 2016, the resident inspectors discussed the inspection results with
Mr. Chris Costanzo, Site Vice President, and other members of the licensees staff. On
January 27, 2017, the resident inspectors presented the preliminary safety significance
to Mr. Dan Deboer, Site Director, and other members of the licensees staff. The
inspectors verified that no proprietary information was retained by the inspectors or
documented in this report.
ATTACHMENTS:
SUPPLEMENTAL INFORMATION
DETAILED RISK ASSESSMENT
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SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
T. Summers, Regional Vice President
D. Deboer, Site Director
C. Costanzo, Site Vice President
D. Cecchett, Licensing Engineer
K. Frehafer, Licensing Engineer
M. Jones, Engineering Director
W. Parks, Operations Director
D. Pitts, Maintenance Director
R. Sciscente, Licensing Engineer
M. Snyder, Licensing Manager
R. Wright, Plant General Manager
NRC Personnel
L. Pressley, Senior Project Engineer
J. Hanna, Senior Reactor Analyst
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Attachment
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LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000335/2016012-01 FIN Failure to Maintain Component Configuration Control
Resulted in a Complicated Reactor Trip
(Section 4OA3)
Closed
05000335/2016-003-00 LER Generator Lockout Relay Actuation During Power
Ascension Results in Reactor Trip (Section 4OA3)
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LIST OF DOCUMENTS REVIEWED
Section 4OA3: Follow-up of Events and Notice of Enforcement Discretion
Miscellaneous:
LER 05000335, 2016-003-00, Generator Lockout Relay Actuation during Power Ascension
Results in Reactor Trip
PRA Analysis of St. Lucie Unit 1 August 21, 2016 Generator Lockout Event, dated January 13,
2017
Procedures:
MA-AA-100, Conduct of Maintenance, Revision 15
ADM-08.12, Maintenance Configuration Control, Revision 2
1-ARP-01-G00, Control Room Panel G RTGB 102, Revision 42
1-AOP-25.02, Ventilation Systems, Revision 6
2-EOP-01, Standard Post Trip Actions SPTA, Revision 35
2-EOP-09, Loss of Offsite Power/Loss of Forced Circulation, Revision 20
2-EOP-10, Station Blackout, Revision 25
1-FSG-02, Alternate AFW Suction Source, Revision 2
1-FSG-03, Alternate Low Pressure Feedwater, Revision 2
1-FSG-06, Alternate CST Makeup, Revision 2
Drawings:
8770-B-327, sheet 1790, Inadvertent Energization Generator Protection
8770-B-327, sheet 886, Generator Breakers 1E & 1M
8770-B-327, sheet 888, Gen. Auto & MAN. Synchronization
Miscellaneous:
WO 40038386, EC 274642, SYNC/888: Auto Sync Not Working
Job Performance Measure 0121245, Supply Demineralized Water from the Treated Water
Storage Tank to the Unit 1(2) Condensate Storage Tank, Revision 0
Job Performance Measure 0321227, Align Unit 2 CST to Supply 1C AFW Pump, Revision
6Job Performance Measure 0521517, Restoration of Electrical Equipment Room
Ventilation-Unit 1, Revision 3
Operations Training Document, Align the Unit 1A and 1B AFW Pumps to the Unit 2 CST,
Revision 4
Root Cause Analysis, Lockout Relay Automatic Reactor Trip (Complicated)
Licensee Decay Heat Calculations Assuming 38% Power, dated November 30, 2016
Enercon Calculation, Plant St. Lucie Unit 1 Electrical Equipment Room Loss of HVS-5A/B
Heatup Evaluation, Revision 0
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