IR 05000261/2013007: Difference between revisions

From kanterella
Jump to navigation Jump to search
(Created page by program invented by StriderTol)
 
(Created page by program invented by StriderTol)
Line 18: Line 18:


=Text=
=Text=
{{#Wiki_filter:
{{#Wiki_filter:UNITED STATES NUCLEAR REGULATORY COMMISSION REGION II 245 PEACHTREE CENTER AVENUE NE, SUITE 1200 ATLANTA, GEORGIA 30303-1257 June 28, 2013 Mr. William Vice President
[[Issue date::June 28, 2013]]


Mr. William Vice President Progress Energy H. B. Robinson Steam Electric Plant, Unit 2 3581 West Entrance Rd Hartsville, SC 29550
Progress Energy H. B. Robinson Steam Electric Plant, Unit 2 3581 West Entrance Rd Hartsville, SC 29550


SUBJECT: H. B. ROBINSON STEAM ELECTRIC PLANT- NRC COMPONENT DESIGN BASES INSPECTION REPORT 05000261/2013007
SUBJECT: H. B. ROBINSON STEAM ELECTRIC PLANT- NRC COMPONENT DESIGN BASES INSPECTION REPORT 05000261/2013007


==Dear Mr. Gideon:==
==Dear Mr. Gideon:==
On May 16, 2013, U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your H. B. Robinson Steam Electric Plant, Unit 2. The enclosed inspection report documents the inspection results, which were discussed on May 16, 2013, with you and other members of your staff. Additional inspection results were communicated on June 20, 2013, during a teleconference with you and other members of your staff, and June 27, 2013, with Mr. Hightower.
On May 16, 2013, U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your H. B. Robinson Steam Electric Plant, Unit 2. The enclosed inspection report documents the inspection results, which were discussed on May 16, 2013, with you and other members of your staff. Additional inspection results were communicated on June 20, 2013, during a teleconference with you and other members of your staff, and June 27, 2013, with  
 
Mr. Hightower.


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 team reviewed selected procedures and records, observed activities, and interviewed personnel.
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 team reviewed selected procedures and records, observed activities, and interviewed personnel.


Five NRC identified findings of very low safety significance (Green) were identified during this inspection. Four of these findings were determined to involve violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.
Five NRC identified findings of very low safety significance (Green) were identified during this inspection.
 
Four of these findings were determined to involve violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the  
 
Enforcement Policy.


If you contest the violations, or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, U.S.
If you contest the violations, or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, U.S.


Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the H. B. Robinson Steam Electric Plant. If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the H. B. Robinson Steam Electric Plant. 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 available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Document Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the H. B. Robinson Steam Electric Plant.


Sincerely,RA Rebecca Nease, Chief Engineering Branch 1 Division of Reactor Safety Docket No.: 05000261 License No.: DPR-23  
If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the H. B. Robinson Steam Electric Plant. 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 available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Document Access and Managem ent System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
 
Sincerely,RA Rebecca Nease, Chief Engineering Branch 1  
 
Division of Reactor Safety Docket No.: 05000261 License No.: DPR-23  


===Enclosure:===
===Enclosure:===
Line 44: Line 53:
Supplemental Information  
Supplemental Information  


cc: (See page 3)
cc: (See page 3)  
 
_________________________ x SUNSI REVIEW COMPLETE x FORM 665 ATTACHED OFFICE RII:DRS RII:DRS RII:DCI RII:DRS RII:DRS RII:DRS CONTRATOR SIGNATURE Via email Via email Via email Via email Via email NAME G. Ottenberg S. Walker J. Bartleman M. Riley P. Cooper A. Alen H. Campbell DATE 6/26/2013 6/25/2013 6/26/2013 6/28/2013 6/25/2013 6/28/2013 6/25/2013 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO OFFICE CONTRACTOR HQ:NRR HQ:NRR RII:DRS RII:DRP RII:DRS SIGNATURE Via email Via email Via email RA RA NAME G. Nicely W. Lyon C. Jackson R. Nease G. Hopper DATE 6/27/2013 6/25/2013 6/26/2013 6/28/2013 6/28/2013 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO cc: Division of Radiological Health TN Dept. of Environment & Conservation 401 Church Street Nashville, TN 37243-1532
 
Donald W. Barker Manager, Nuclear Oversight H. B. Robinson Steam Electric Plant, Unit 2 Progress Energy Electronic Mail Distribution
 
J. W. (Bill) Pitesa Senior Vice President Nuclear Operations Duke Energy Corporation Electronic Mail Distribution
 
Lara S. Nichols Deputy General Counsel Duke Energy Corporation Electronic Mail Distribution
 
M. Christopher Nolan
 
Director - Regulatory Affairs General Office Duke Energy Corporation Electronic Mail Distribution
 
Mike Glover Director Site Operations H. B. Robinson Steam Electric Plant Electronic Mail Distribution
 
Richard Keith Holbrook
 
Operations Manager H. B. Robinson Steam Electric Plant Electronic Mail Distribution
 
Sandra Threatt, Manager Nuclear Response and Emergency Environmental Surveillance Bureau of Land and Waste Management Department of Health and Environmental
 
Control Electronic Mail Distribution
 
Sharon Wheeler
 
Manager, Support Services H B Robinson Steam Electric Plant 
 
Brian C. McCabe Manager, Nuclear Oversight Shearon Harris Nuclear Power Plant
 
Progress Energy Electronic Mail Distribution
 
Richard Hightower
 
Supervisor Licensing/Regulatory Programs Progress Energy Electronic Mail Distribution
 
Joseph W. Donahue Vice President Nuclear Oversight Progress Energy Electronic Mail Distribution
 
David T. Conley
 
Senior Counsel Legal Department Progress Energy Electronic Mail Distribution
 
John H. O'Neill, Jr.
 
Shaw, Pittman, Potts & Trowbridge 2300 N. Street, NW Washington, DC 20037-1128
 
Richard Haynes Director, Division of Waste Management Bureau of Land and Waste Management S.C. Department of Health and Environmental Control Electronic Mail Distribution
 
Thomas Cosgrove Plant General Manager H.B. Robinson Steam Electric Plant, Unit 2
 
Progress Energy Electronic Mail Distribution
 
(cc cont'd - See page 4) (cc cont'd)
Donna B. Alexander
 
Manager, Nuclear Regulatory Affairs (interim)
Progress Energy Electronic Mail Distribution
 
(cc cont'd - See page 4)
 
Robert P. Gruber Executive Director Public Staff - NCUC
 
4326 Mail Service Center
 
Raleigh, NC 27699-4326
 
W. Lee Cox, III Section Chief
 
Radiation Protection Section N.C. Department of Environmental
 
Commerce & Natural Resources Electronic Mail Distribution
 
Greg Kilpatrick
 
Operations Manager H.B. Robinson Steam Electric Plant, Unit 2
 
Progress Energy Electronic Mail Distribution
 
Mark Yeager
 
Division of Radioactive Waste Mgmt.
 
S.C. Department of Health and Environmental Control Electronic Mail Distribution
 
Public Service Commission
 
State of South Carolina P.O. Box 11649 Columbia, SC 29211
 
Chairman North Carolina Utilities Commission Electronic Mail Distribution Henry Curry
 
Training Manager H.B. Robinson Steam Electric Plant, Unit 2
 
Progress Energy Electronic Mail Distribution
 
Senior Resident Inspector U.S. Nuclear Regulatory Commission H. B. Robinson Steam Electric Plant 2112 Old Camden Rd
 
Hartsville, SC 29550
 
Christos Kamilaris
 
Manager, Support Services H.B. Robinson Steam Electric Plant, Unit 2 Progress Energy Electronic Mail Distribution
 
Enclosure U. S. NUCLEAR REGULATORY COMMISSION REGION II
 
Docket No.: 05000261
 
License No.: DPR-23
 
Report No.: 05000261/2013007
 
Licensee: Carolina Power and Light Company.
 
Facility: H. B. Robinson Steam Electric Plant, Unit 2
 
Location: 3581 West Entrance Road Hartsville, SC 29550
 
Dates: April 8 -
May 16, 2013
 
Inspectors: G. Ottenberg, Senior Reactor Inspector (Lead) S. Walker, Senior Reactor Inspector J. Bartleman, Senior Construction Inspector A. Alen, Reactor Inspector M. Riley, Reactor Inspector
 
P. Cooper, Reactor Inspector (Trainee)
G. Nicely, Contractor (Electrical)
H. Campbell, Contractor (Mechanical)
Approved by: Rebecca Nease, Chief Engineering Branch 1 Division of Reactor Safety


=SUMMARY=
=SUMMARY=
IR 05000261/2013007; 4/8/2013 - 5/16/2013; H. B. Robinson Steam Electric Plant, Unit 2; Component Design Bases Inspection.
IR 05000261/2013007; 4/8/2013 -
 
5/16/2013; H. B. Robinson Steam Electric Plant, Unit 2; Component Design Bases Inspection.
 
This inspection was conducted by a team of six Nuclear Regulatory Commission (NRC) inspectors from Region II, and two NRC contract personnel. Four Green non-cited violations (NCVs), and one Green finding were identified. The significance of inspection findings is indicated by their color (Green, White, Yellow, Red) using the NRC Inspection Manual Chapter (IMC) 0609, "Significance Determination Process," dated June 2, 2011. Cross cutting aspects are determined using IMC 0310, "Components Within the Cross Cutting Areas," dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRC's Enforcement Policy, dated January 28, 2013. 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.


This inspection was conducted by a team of six Nuclear Regulatory Commission (NRC) inspectors from Region II, and two NRC contract personnel. Four Green non-cited violations (NCVs), and one Green finding were identified. The significance of inspection findings is indicated by their color (Green, White, Yellow, Red) using the NRC Inspection Manual Chapter (IMC) 0609, "Significance Determination Process," dated June 2, 2011. Cross cutting aspects are determined using IMC 0310, "Components Within the Cross Cutting Areas," dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRC's Enforcement Policy, dated January 28, 2013. 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. NRC identified and Self-Revealing Findings
NRC identified and Self-Revealing Findings


===Cornerstone: Mitigating Systems===
===Cornerstone: Mitigating Systems===
Line 61: Line 198:
3        The licensee entered the issue into the corrective action program as Nuclear Condition Reports 601201 and 605969, and performed an evaluation that determined the capability of starting the safety-related motors at degraded voltage conditions, as well as the capability of the electrical loads during the degraded grid voltage relay (DGVR) time delay to ensure equipment function was preserved.
3        The licensee entered the issue into the corrective action program as Nuclear Condition Reports 601201 and 605969, and performed an evaluation that determined the capability of starting the safety-related motors at degraded voltage conditions, as well as the capability of the electrical loads during the degraded grid voltage relay (DGVR) time delay to ensure equipment function was preserved.


The performance deficiency was more than minor because it affected the Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring reliability, availability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee did not ensure the capability of safety-related loads to respond to a design basis accident under degraded voltage conditions. Evaluations of the effects of starting motors at the DGVR voltage dropout setpoint and the equipment survivability during the DGVR time delay were not performed. The team determined the finding required a detailed risk analysis, because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, or component, and the team assumed the performance deficiency represented a loss of operability or functionality of the equipment that could be lost during the DGVR time delay. This assumption was made to bound the risk of the finding, because the licensee was still investigating whether or not there would be a loss of function of any equipment during the DGVR time delay period as of the date of this inspection report issuance. The team assumed a recoverable loss of function of all 480V motor control centers and assumed a degraded voltage condition exposure time of one hour per year. The one hour per year assumption is conservative relative to actual plant data which indicated a degraded voltage condition exposure of 44 seconds over the past 3 operating years. The results of the detailed risk analysis indicated an increase in core damage frequency <1E-6/year, which is representative of a finding of very low safety significance (Green). No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the degraded voltage evaluation.  (Section 1R21.2.15)
The performance deficiency was more than minor because it affected the  
 
Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring reliability, availability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee did not ensure the capability of safety-related loads to respond to a design basis accident under degraded voltage conditions. Evaluations of the effects of starting motors at the DGVR voltage dropout setpoint and the equipment survivability during the DGVR time delay were not performed. The team determined the finding required a detailed risk analysis, because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, or component, and the team assumed the performance deficiency represented a loss of operability or functionality of the equipment that could be lost during the DGVR time delay. This assumption was made to bound the risk of the finding, because the licensee was still investigating whether or not there would be a loss of function of any equipment during the DGVR time delay period as of the date of this inspection report issuance. The team assumed a recoverable loss of function of all 480V motor control centers and assumed a degraded voltage condition exposure time of one hour per year. The one hour per year assumption is conservative relative to actual plant data which indicated a degraded voltage condition exposure of 44 seconds over the past 3 operating years. The results of the detailed risk analysis indicated an increase in core damage frequency <1E-6/year, which is representative of a finding of very low safety significance (Green). No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the degraded voltage evaluation.  (Section 1R21.2.15)
: '''Green.'''
: '''Green.'''
The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to verify the adequacy of the plant design during fast bus transfers. Specifically, the licensee failed to have an adequate analysis that ensured a successful fast bus transfer of the safety-related E1 bus feeder from the Unit Auxiliary Transformer to the Startup Transformer when required. This was a performance deficiency. The licensee entered the issue into the corrective action program as Nuclear Condition Reports 603357 and 605562, and performed an additional fast bus transfer evaluation of the E1 feeder breaker to ensure that the breaker would not trip under fast bus transfer conditions.
The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to verify the adequacy of the plant design during fast bus transfers. Specifically, the licensee failed to have an adequate analysis that ensured a successful fast bus transfer of the safety-related E1 bus feeder from the Unit Auxiliary Transformer to the Startup Transformer when required. This was a performance deficiency. The licensee entered the issue into the corrective action program as Nuclear Condition Reports 603357 and 605562, and performed an additional fast bus transfer evaluation of the E1 feeder breaker to ensure that the breaker would not trip under fast bus transfer conditions.


The performance deficiency was more than minor because it affected the Mitigating Systems cornerstone attribute of Design Control and adversely affected the cornerstone objective of ensuring reliability, availability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee did not ensure the capability of safety-related loads on the E1 bus because the licensee did not verify the E1 feeder breaker would not trip during a fast bus transfer. The finding was determined to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, or component (SSC), and the SSC maintained its operability and functionality. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the fast bus transfer evaluation.  (Section 1R21.2.16.1)
The performance deficiency was more than minor because it affected the Mitigating Systems cornerstone attri bute of Design Control and adversely affected the cornerstone objective of ensuring reliability, availability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee did not ensure the capability of safety-related loads on the E1 bus because the licensee did not verify the E1 feeder breaker would not trip during a fast bus transfer. The finding was determined to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, or component (SSC), and the SSC maintained its operability and functionality. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the fast bus transfer evaluation.  (Section 1R21.2.16.1)
: '''Green.'''
: '''Green.'''
The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the licensee's failure to prescribe an adequate procedure that verified DGVR circuit operability following degraded voltage disable switch operation for reactor coolant pump (RCP) starts. This was a performance deficiency. The licensee entered the issue into the corrective action program as Nuclear Condition Report 602516, developed a test procedure, and verified the DGVR operability on both emergency buses.
The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the licensee's failure to prescribe an adequate procedure that verified DGVR circuit operability following degraded voltage disable switch operation for reactor coolant pump (RCP) starts. This was a performance deficiency. The licensee entered the issue into the corrective action program as Nuclear Condition Report 602516, developed a test procedure, and verified the DGVR operability on both emergency buses.


The performance deficiency was more than minor because if left uncorrected, it could become a more significant safety concern. Specifically, by not properly testing the DGVR circuit to ensure continuity following switch manipulation for RCP starts, the circuit could unknowingly become inoperable and non-functional for an entire operating cycle. The finding was determined to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system function, did not represent an actual loss of function of at least a single train for greater than its technical specification (TS) allowed outage time or two separate safety systems out-of-service for greater than its TS allowed outage time, and did not represent an actual loss of function of one or more non-TS trains. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the modification that added the degraded voltage disable switches.  (Section 1R21.2.16.2)
The performance deficiency was more than minor because if left uncorrected, it could become a more significant safety concern. Specifically, by not properly testing the DGVR circuit to ensure conti nuity following switch manipulation for RCP starts, the circuit could unknowingly become inoperable and non-functional for an entire operating cycle. The finding was determined to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system function, did not represent an actual loss of function of at least a single train for greater than its technical specification (TS) allowed outage time or two separate safety systems out-of-service for greater than its TS allowed outage time, and did not represent an actual loss of function of one or more non-TS trains. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the modification that added the degraded voltage disable switches.  (Section 1R21.2.16.2)  


===Cornerstone: Barrier Integrity===
===Cornerstone: Barrier Integrity===
: '''Green.'''
: '''Green.'''
The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to account for instrument uncertainty on the containment bulk temperature instrumentation  which was used to verify technical specification (TS) containment operability. This was a performance deficiency. The licensee entered this issue into their corrective action program as Nuclear Condition Report 603294 and performed an evaluation of the temperature instrumentation uncertainty. In addition, the licensee issued Standing Instruction 13-001 which specified the indicated containment temperature for entry into TS Limiting Condition for Operation 3.6.5 was to be 118 degrees Fahrenheit, a value that compensated for the temperature measurement uncertainty.
The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to account for instrument uncertainty on the containm ent bulk temperature instrumentation  which was used to verify technical specification (TS) containment operability. This was a performance deficiency. The licensee entered this issue into their corrective action program as Nuclear Condition Report 603294 and performed an evaluation of the temperature instrumentation uncertainty. In addition, the licensee issued Standing Instruction 13-001 which specified the indicated containment temperature for entry into TS Limiting Condition for Operation 3.6.5 was to be 118 degrees Fahrenheit, a value that compensated for the temperature measurement uncertainty.


The performance deficiency was more than minor because if left uncorrected, it would have the potential to lead to a more significant safety concern. Specifically, if the licensee did not account for the temperature measurement accuracy, containment temperature could unknowingly exceed the TS operability limit, and the licensee may not declare containment inoperable. The finding was determined to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components and did not involve a reduction in function of hydrogen igniters in the reactor containment. The cause of the finding was indicative of current licensee performance because the licensee failed to consider instrument uncertainty when they performed a containment re-analysis in 2013. The cause of the finding was directly related to the maintaining long term plant safety by maintenance of design margins cross-cutting aspect of the resources component in the area of human performance because when the containment re-analysis was performed, the licensee reduced margin between the analyzed value for containment starting temperature and the TS limit, making the instrument uncertainty of the temperature instruments more significant.  [H.2(a)]  (Section 1R21.2.9)
The performance deficiency was more than minor because if left uncorrected, it would have the potential to lead to a more significant safety concern. Specifically, if the licensee did not account for the temperature measurement accuracy, containment temperature could unknowingly exceed the TS operability limit, and the licensee may not declare containment inoperable. The finding was determined to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components and did not involve a reduction in function of hydrogen igniters in the reactor containment. The cause of the finding was indicative of current licensee performance because the licensee failed to consider instrument uncertainty when they performed a containment re-analysis in 2013. The cause of the finding was directly related to the maintaining long term plant safety by maintenance of design margins cross-cutting aspect of the resources component in the area of human performance because when the containment re-analysis was performed, the licensee reduced margin between the analyzed value for containment starting temperature and the TS limit, making the instrument uncertainty of the temperature instruments more significant.  [H.2(a)]  (Section 1R21.2.9)


=== Licensee-Identified Violations===
===
Licensee-Identified Violations===
 
No findings were identified.
No findings were identified.


Line 88: Line 229:
{{IP sample|IP=IP 71111.21}}
{{IP sample|IP=IP 71111.21}}
===.1 Inspection Sample Selection Process===
===.1 Inspection Sample Selection Process===
The team selected risk-significant components and related operator actions for review using information contained in the licensee's probabilistic risk assessment. In general, this included components and operator actions that had a risk achievement worth factor greater than 1.3 or Birnbaum value greater than 1 X10-6. The sample included 17 components, of which three were associated with containment large early release frequency (LERF), and six operating experience (OE) items.


The team performed a margin assessment and a detailed review of the selected risk-significant components and operator actions to verify that the design bases had been correctly implemented and maintained. Where possible, this margin was determined by the review of the design basis and Updated Final Safety Analysis Report (UFSAR)response times associated with operator actions. This margin assessment also considered original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition issues. Equipment reliability issues were also considered in the selection of components for a detailed review. These reliability issues included items related to failed performance test results, significant corrective action, repeated maintenance, maintenance rule status, Regulatory Issue Summary 05-020 (formerly Generic Letter 91-18) conditions, NRC resident inspector input regarding problem equipment, system health reports, industry OE, and licensee problem equipment lists. Consideration was also given to the uniqueness and complexity of the design, OE, and the available defense-in-depth margins. An overall summary of the reviews performed and the specific inspection findings identified is included in the following sections of the report.
The team selected risk-significant components and related operator actions for review using information contained in the licensee's probabilistic risk assessment. In general, this included components and operator actions that had a risk achievement worth factor greater than 1.3 or Birnbaum value greater than 1 X10
-6. The sample included 17 components, of which three were associated with containment large early release frequency (LERF), and six operating experience (OE) items.
 
The team performed a margin assessment and a detailed review of the selected risk-significant components and operator actions to verify that the design bases had been correctly implemented and maintained. Where possible, this margin was determined by the review of the design basis and Updated Final Safety Analysis Report (UFSAR)response times associated with operator actions. This margin assessment also considered original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition issues. Equipm ent reliability issues were also considered in the selection of components for a detailed review. These reliability issues included items related to failed performance test results, significant corrective action, repeated maintenance, maintenance rule status, Regulatory Issue Summary 05-020 (formerly Generic Letter 91-18) conditions, NRC resident inspector  
 
input regarding problem equipment, system health reports, industry OE, and licensee problem equipment lists. Consideration was also given to the uniqueness and complexity of the design, OE, and the available defense-in-depth margins. An overall summary of the reviews performed and the specific inspection findings identified is included in the following sections of the report.


===.2 Component Reviews===
===.2 Component Reviews===
Line 102: Line 247:
No findings were identified.
No findings were identified.


===.2.2 Steam Generator Steam Line Power Operated Relief Valves [RV1-1, RV1-2, RV1-3] (LERF)===
===.2.2 Steam Generator Steam Line Power Operated Relief Valves [RV1-1, RV1-2, RV1-3]===
 
(LERF)


====a. Inspection Scope====
====a. Inspection Scope====
Line 110: Line 257:
No findings were identified.
No findings were identified.


===.2.3 Steam Generator Steam Supply Valves to Steam Driven Auxiliary Feedwater Pump [MS-V1-8A, MS-V1-8B, MS-V1-8C]===
===.2.3 Steam Generator Steam Supply Valves to Steam Driven Auxiliary Feedwater Pump===
 
[MS-V1-8A, MS-V1-8B, MS-V1-8C]


====a. Inspection Scope====
====a. Inspection Scope====
The inspection team reviewed the steam driven auxiliary feedwater pump (SDAFP) steam supply motor-operated valves (MOVs), MS-V1-8A, MS-V1-8B, and MS-V1-8C, to verify these valves were capable of performing their design bases functions. The team reviewed the licensee's calculations of operational margin and verified important inputs into the calculations were sufficiently conservative. The team also verified that the infield diagnostic testing and setup of torque and limit switch settings for the valve actuators were within the setup windows assumed in design margin calculations, and verified that test equipment accuracies were considered.
The inspection team reviewed the steam driven auxiliary feedwater pump (SDAFP) steam supply motor-operated valves (MOVs), MS-V1-8A, MS-V1-8B, and MS-V1-8C, to verify these valves were capable of performing their design bases functions. The team reviewed the licensee's calculations of operational margin and verified important inputs into the calculations were sufficiently conservative. The team also verified that the infield diagnostic testing and setup of torque and limit switch settings for the valve actuators were within the setup windows assumed in design margin calculations, and verified that test equipment accuracies were considered.


The team reviewed the maintenance history of the valves and actuators, and engineering trending reports to examine mechanical condition and function of the components. The team verified that maintenance was performed in accordance with vendor instructions. The team reviewed the calculations that determined the degraded voltage at the MOV terminals, to ensure the proper voltage was utilized in calculating available motor output torque when determining margin. The team reviewed the calculations that establish control circuit voltage drop, short circuit, and protection/coordination including thermal overload sizing and application. Additionally motor control center (MCC) thermal overload testing programs were reviewed. The team reviewed the licensee's initial evaluation and response to the 10 CFR Part 21 notification issued from Flowserve to the NRC, dated February 25, 2013, for a wedge pin failure of an Anchor/Darling Double Disk Gate Valve (AD-DDGV) at Browns Ferry Nuclear Plant Unit 1. The team reviewed the licensee's operability determination evaluation performed for the 41 safety-related AD-DDGVs used at RNP. This operability determination was completed under Nuclear Condition Report (NCR) 592717 to address the wedge pin failure outlined in this Part 21 notification. The licensee performed a Quick Cause Evaluation (QCE) Report, Form CAP-NGGC-0205-3-16, as required by the corrective actions identified in NCR 592717. This QCE described the analysis and immediate actions taken by the licensee to evaluate the wedge pin failure of an AD-DDGV. The team verified that the corrective actions outlined in the QCE, if implemented correctly, should adequately address this issue.
The team reviewed the maintenance history of the valves and actuators, and engineering trending reports to examine mechanical condition and function of the components. The team verified that maintenance was performed in accordance with vendor instructions. The team reviewed the calculations that determined the degraded voltage at the MOV terminals, to ensure the proper voltage was utilized in calculating available motor output torque when determining margin. The team reviewed the calculations that establish control circuit voltage drop, short circuit, and protection/coordination including thermal overload sizing and application. Additionally motor control center (MCC) thermal overload testing programs were reviewed.
 
The team reviewed the licensee's initial evaluation and response to the 10 CFR Part 21 notification issued from Flowserve to the NRC, dated February 25, 2013, for a wedge pin failure of an Anchor/Darling Double Disk Ga te Valve (AD-DDGV) at Browns Ferry Nuclear Plant Unit 1. The team reviewed the licensee's operability determination evaluation performed for the 41 safety-related AD-DDGVs used at RNP. This operability determination was completed under Nuclear Condition Report (NCR) 592717 to address the wedge pin failure outlined in this Part 21 notification. The licensee performed a Quick Cause Evaluation (QCE) Report, Form CAP-NGGC-0205-3-16, as required by the  
 
corrective actions identified in NCR 592717.
 
This QCE described the analysis and immediate actions taken by the licensee to evaluate the wedge pin failure of an AD-DDGV. The team verified that the corrective actions outlined in the QCE, if implemented correctly, should adequately address this issue.


The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team conducted a walkdown of a limiting safe shutdown procedure to assess if the time critical operator actions required to control the SDAFP during a Station Blackout (SBO) could be successfully accomplished. Equipment necessary to perform procedural steps was verified to be in the correct locations and available to the operators. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises for this evolution to identify any past operator failures or challenges to accomplish this activity.
The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team conducted a walkdown of a limiting safe shutdown procedure to assess if the time critical operator actions required to control the SDAFP during a Station Blackout (SBO) could be successfully accomp lished. Equipment necessary to perform procedural steps was verified to be in the correct locations and available to the operators. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises for this evolution to identify any past operator failures or challenges to accomplish this activity.


====b. Findings====
====b. Findings====
Line 143: Line 298:


====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed design basis documentation including original design specifications, the RHR and Safety Injection DBDs, portions of the UFSAR, and TS to identify the safety-related and functional requirements of the RHR pumps A and B. The RHR system engineer was interviewed to discuss current pump concerns and margin to design requirements. Further, a field walkdown with the system engineer was undertaken to evaluate the material condition and assess the pump's operating environment. Hydraulic calculations were reviewed to evaluate pump vortex and NPSH concerns, in addition to in-service test (IST) instrument uncertainty evaluations. Several years of IST surveillances, both Quarterly and Comprehensive, were reviewed to assess the capability of the pumps to perform their safety-related functions, as well as to evaluate potential long-term pump degradation. The licensee's evaluation of NRC Information Notice (IN) 97-90 and NRC Bulletin 88-04 were reviewed. As part of this OE review, the testing of the RHR system piping modification (1087, RHR Pumps Minimum Flow Recirculation Lines) was reviewed to ensure compliance with the concerns raised in Bulletin 88-04. The team reviewed calculations that establish voltage drop, protection and coordination, motor horsepower requirements, and short circuit for the motor power supply and feeder cable to verify that design bases and design assumptions have been appropriately translated into design calculations. The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises to identify any past operator failures or challenges to accomplish this activity.
The team reviewed design basis documentation including original design specifications, the RHR and Safety Injection DBDs, portions of the UFSAR, and TS to identify the safety-related and functional requirements of the RHR pumps A and B. The RHR system engineer was interviewed to discuss current pump concerns and margin to design requirements. Further, a field walkdown with the system engineer was undertaken to evaluate the material condition and assess the pump's operating environment. Hydraulic calculations were reviewed to evaluate pump vortex and NPSH concerns, in addition to in-service test (IST) instrument uncertainty evaluations. Several years of IST surveillances, both Quarterly and Comprehensive, were reviewed to assess the capability of the pumps to perform their safety-related functions, as well as to evaluate potential long-term pump degradation. The licensee's evaluation of NRC Information Notice (IN) 97-90 and NRC Bulletin 88-04 were reviewed. As part of this OE review, the testing of the RHR system piping modification (1087, RHR Pumps Minimum Flow Recirculation Lines) was reviewed to ensure compliance with the concerns raised in Bulletin 88-04. The team reviewed calculations that establish voltage drop, protection and coordination, motor horsepower requirements, and short circuit for the motor power supply and feeder cable to verify that design bases and design assumptions have been appropriately translated into design calculations.
 
The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises to identify any past operator failures or challenges to accomplish this activity.


====b. Findings====
====b. Findings====
Line 153: Line 310:
The team reviewed design basis documentation including original design specifications, the Safety Injection system DBD, portions of the UFSAR, and TS to identify the safety-related and functional requirements of the high head safety injection pumps A, B and C.
The team reviewed design basis documentation including original design specifications, the Safety Injection system DBD, portions of the UFSAR, and TS to identify the safety-related and functional requirements of the high head safety injection pumps A, B and C.


The team performed a walkdown of the pumps to assess the current material condition of the pumps and assess the pump's operating environment. Several years of IST surveillances, both Quarterly and Comprehensive, were reviewed to assess the capability of the pumps to perform their safety-related functions, as well as to evaluate potential long-term pump degradation. The licensee's evaluation of NRC IN 97-90 and NRC Bulletin 88-04 were reviewed. As part of this OE review, the team reviewed original and current pump vendor documents to ensure that the concerns identified in Bulletin 88-04, (i.e., minimum recirculation flow), were adequately addressed. The team reviewed calculations that establish voltage drop, protection and coordination, motor horsepower requirements, and short circuit for the motor power supply and feeder cable to verify that design bases and design assumptions have been appropriately translated into design calculations.
The team performed a walkdown of the pumps to assess the current material condition of the pumps and assess the pump's operating environment. Several years of IST surveillances, both Quarterly and Comprehensive, were reviewed to assess the capability of the pumps to perform their safety-related functions, as well as to evaluate  
 
potential long-term pump degradation. The licensee's evaluation of NRC IN 97-90 and NRC Bulletin 88-04 were reviewed. As part of this OE review, the team reviewed original and current pump vendor documents to ensure that the concerns identified in Bulletin 88-04, (i.e., minimum recirculation flow), were adequately addressed. The team reviewed calculations that establish voltage drop, protection and coordination, motor horsepower requirements, and short circuit for the motor power supply and feeder cable to verify that design bases and design assumptions have been appropriately translated into design calculations.


====b. Findings====
====b. Findings====
No findings were identified.
No findings were identified.


===.2.8 Containment Pressure Relief and Containment Vessel Post Accident Hydrogen Vent Isolation Valves [V12-10, V12-11] (LERF)===
===.2.8 Containment Pressure Relief and Containment Vessel Post Accident Hydrogen Vent===
 
Isolation Valves [V12-10, V12-11] (LERF)


====a. Inspection Scope====
====a. Inspection Scope====
Line 171: Line 332:


====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed design basis documentation including portions of the UFSAR, DBD, TS, and related calculations to identify the safety-related and functional requirements of the containment instrumentation. Specific instruments included for review were those monitoring containment water level, pressure, and temperature. The team reviewed instrument uncertainty calculations for containment pressure and level instrumentation to ensure that acceptable instrumentation was being used to monitor the associated containment process parameters. The team reviewed work orders to verify that calibration checks of the containment temperature thermocouples were completed. The team reviewed condition reports and one operability evaluation addressing containment analyses. The team reviewed analyses evaluating the method used to determine the average bulk containment temperature, in addition to recent and historical containment bulk temperature data, to ensure that the TS limit had not been exceeded. Finally, the team reviewed system health reports to assess the current state and operability of the containment instrumentation.
The team reviewed design basis documentation including portions of the UFSAR, DBD, TS, and related calculations to identify the safety-related and functional requirements of the containment instrumentation. Specific instruments included for review were those monitoring containment water level, pressure, and temperature. The team reviewed instrument uncertainty calculations for containment pressure and level instrumentation to ensure that acceptable instrumentation was being used to monitor the associated containment process parameters. The team reviewed work orders to verify that calibration checks of the containment temperature thermocouples were completed. The team reviewed condition reports and one operability evaluation addressing containment analyses. The team reviewed analyses evaluating the method used to determine the average bulk containment temperature, in addition to recent and historical containment bulk temperature data, to ensure that the TS limit had not been exceeded. Finally, the team reviewed system health reports to assess the current state and operability of the  
 
containment instrumentation.


====b. Findings====
====b. Findings====


=====Introduction:=====
=====Introduction:=====
The team identified a Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to account for instrument uncertainty on containment bulk temperature instrumentation which was used to determine TS containment operability. This was a performance deficiency.
The team identified a Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to account for  
 
instrument uncertainty on containment bulk temperature instrumentation which was used to determine TS containment operability. This was a performance deficiency.


=====Description:=====
=====Description:=====
In February 2013, the licensee identified errors in inputs to the original containment analysis (main steam line break and loss of coolant accident). The licensee performed a re-analysis of these design basis accidents and performed an operability determination. The analysis supporting the operability determination decreased the assumed accident initial containment temperature from 130 degrees F to 120 degrees F. The TS upper limit for containment temperature was 120 degrees F; therefore, following the containment re-analysis, there was no margin between the analyzed and TS allowed temperature limit. The station procedure guiding operations during hot weather conditions, PLP-118, did not instruct operators to declare containment inoperable at any indicated temperature below the TS required 120 degrees F. The team reviewed work orders that performed calibration checks on the containment thermocouples and found that no acceptance criteria were provided for the allowed tolerance between the temperature obtained by the test equipment standard and the actual containment instrumentation.
In February 2013, the licensee identified errors in inputs to the original containment analysis (main steam line break and loss of coolant accident). The licensee performed a re-analysis of these design basis accidents and performed an operability determination. The analysis supporting the operability determination decreased the assumed accident initial containment temperature from 130 degrees F to 120 degrees F. The TS upper limit for containment temperature was 120 degrees F; therefore, following the containment re-analysis, there was no margin between the analyzed and TS allowed temperature limit. The station procedure guiding operations during hot weather conditions, PLP-118, did not instruct operators to declare containment inoperable at any indicated temperature below the TS required 120 degrees F. The team reviewed work orders that performed calibration checks on the containment thermocouples and found that no acceptance criteria were provided for the allowed tolerance between the temperature obtained by the test equipment standard and the actual containment instrumentation.


Based on the above, the team concluded that the licensee did not have adequate controls in place to ensure that containment would be declared inoperable at an actual bulk average containment temperature of 120 degrees F since neither the instrument used to perform the surveillance nor station procedures accounted for instrument uncertainty. Upon identification by the team, the licensee entered this issue into their corrective action program as NCRs 603294 and 606607. At the time of the inspection, the local ambient temperature and containment bulk temperature were significantly below the TS limit, thus no immediate operability concern was present. As an interim measure, the licensee performed an evaluation of the temperature instrumentation uncertainty, and issued Standing Instruction 13-001, which specified that the indicated containment temperature for entry into TS limiting condition for operation (LCO) 3.6.5 was to be 118 degrees F, a value that compensated for the temperature measurement uncertainty.  
Based on the above, the team concluded that the licensee did not have adequate controls in place to ensure that containment would be declared inoperable at an actual bulk average containment temperature of 120 degrees F since neither the instrument used to perform the surveillance nor station procedures accounted for instrument uncertainty. Upon identification by the team, the licensee entered this issue into their corrective action program as NCRs 603294 and 606607. At the time of the inspection, the local ambient temperature and containment bulk temperature were significantly below the TS limit, thus no immediate operability concern was present. As an interim measure, the licensee performed an evaluation of the temperature instrumentation uncertainty, and issued Standing Instruction 13-001, which specified that the indicated containment temperature for entry into TS limiting condition for operation (LCO) 3.6.5 was to be 118 degrees F, a value that compensated for the temperature measurement  
 
uncertainty.


=====Analysis:=====
=====Analysis:=====
The failure to account for instrument uncertainty on the containment bulk average temperature instrumentation, used to verify TS containment operability, was a performance deficiency. The performance deficiency was more than minor because if left uncorrected, it would have the potential to lead to a more significant safety concern.
The failure to account for instrument uncertainty on the containment bulk average temperature instrumentation, used to verify TS containment operability, was a performance deficiency. The performance deficiency was more than minor because if left uncorrected, it would have the potential to lead to a more significant safety concern.


Specifically, the licensee did not account for the temperature measurement accuracy, containment temperature could exceed the TS operability limit. The team used IMC 0609, Att. 4, "Initial Characterization of Findings," issued 6/19/12, for Barrier Integrity Cornerstone, and IMC 0609, App. A, "The Significance Determination Process (SDP) for Findings At-Power," issued 6/19/12, and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components and did not involve a reduction in function of hydrogen igniters in the reactor containment. The team determined that the cause of the finding was indicative of current licensee performance because the licensee failed to consider instrument uncertainty when they performed a containment re-analysis in 2013. The cause of the finding was directly related to the maintaining long term plant safety by maintenance of design margins cross-cutting aspect of the resources component in the area of human performance because when the containment re-analysis was performed, the licensee reduced margin between the analyzed value for containment starting temperature and the TS limit, making the instrument uncertainty of the temperature instruments more significant.  [H.2(a)]  
Specifically, the licensee did not account for the temperature measurement accuracy, containment temperature could exceed the TS operability limit. The team used IMC 0609, Att. 4, "Initial Characterization of Findings," issued 6/19/12, for Barrier Integrity Cornerstone, and IMC 0609, App. A, "The Significance Determination Process (SDP) for Findings At-Power," issued 6/19/12, and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components and did not involve a reduction in function of hydrogen igniters in the reactor containment. The team determined that the cause of the finding was indicative of current licensee performance because the licensee failed to consider instrument uncertainty when they performed a containment re-analysis in 2013. The cause of the finding was directly related to the maintaining long term plant safety by maintenance of design margins cross-cutting aspect of the resources component in the area of human performance because when the containment re-analysis was performed, the licensee  
 
reduced margin between the analyzed value for containment starting temperature and the TS limit, making the instrument uncertainty of the temperature instruments more significant.  [H.2(a)]  


=====Enforcement:=====
=====Enforcement:=====
Appendix B of 10 CFR Part 50, Criterion III, "Design Control," required, in part, that design control measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into procedures.
Appendix B of 10 CFR Part 50, Criterion III, "Design Control," required, in part, that design control measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into procedures.


Contrary to the above, from early 2013 when the containment re-analysis was performed until the inspectors identified the issue, the licensee did not assure that the appropriate TS limit for containment temperature and the results of the their containment re-analysis were correctly translated into procedures for determining containment operability. This resulted in the potential to exceed the TS limit and not declare containment inoperable.
Contrary to the above, from early 2013 w hen the containment re-analysis was performed until the inspectors identified the issue, the licensee did not assure that the appropriate TS limit for containment temperature and the results of the their containment re-analysis were correctly translated into procedures for determining containment operability. This resulted in the potential to exceed the TS limit and not declare containment inoperable.


As a result, the licensee issued a standing instruction to operators to ensure the TS limit would not be exceeded and re-performed the containment analysis to regain margin between the analyzed value for containment starting temperature and the TS limit. This violation is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensee's corrective action program as NCR 603294.  (NCV 05000261/2013007-01, Failure to Account for Containment Temperature Measurement Uncertainty)
As a result, the licensee issued a standing instruction to operators to ensure the TS limit would not be exceeded and re-performed the containment analysis to regain margin between the analyzed value for containment starting temperature and the TS limit. This violation is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensee's corrective action program as NCR 603294.  (NCV 05000261/2013007-01, Failure to Account for Containment Temperature Measurement Uncertainty)
Line 208: Line 377:


====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed the plant's TS, UFSAR, system descriptions, and electrical drawings to establish an overall understanding of the licensee's 125V DC distribution system. The team reviewed DC voltage drop calculations and testing procedures to verify that Distribution Panel A was capable of supplying, and maintaining in an operable status, the required emergency loads. The team reviewed system health reports, corrective action documents, and maintenance records to determine whether there were any adverse operating trends. The team performed a walkdown of the 125V DC safety buses to assess operability and condition. The team also conducted interviews with responsible licensee personnel to answer questions that arose during the inspection pertaining to the control voltage at the 480V emergency buses.
The team reviewed the plant's TS, UFSAR, system descriptions, and electrical drawings to establish an overall understanding of the licensee's 125V DC distribution system. The team reviewed DC voltage drop calculations and testing procedures to verify that Distribution Panel A was capable of supplying, and maintaining in an operable status, the required emergency loads. The team re viewed system health reports, corrective action documents, and maintenance records to determine whether there were any  
 
adverse operating trends. The team perfo rmed a walkdown of the 125V DC safety buses to assess operability and condition. The team also conducted interviews with responsible licensee personnel to answer questions that arose during the inspection pertaining to the control voltage at the 480V emergency buses.


The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team conducted a walkdown of a limiting safe shutdown procedure to assess if the time critical operator actions required to use the spare battery charger could be successfully accomplished. Equipment necessary to perform procedural steps was verified to be in the correct locations and available to the operators. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises for this evolution to identify any past operator failures or challenges to accomplish this activity.
The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team conducted a walkdown of a limiting safe shutdown procedure to assess if the time critical operator actions required to use the spare battery charger could be successfully accomplished. Equipment necessary to perform procedural steps was verified to be in the correct locations and available to the operators. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises for this evolution to identify any past operator failures or challenges to accomplish this activity.
Line 233: Line 404:


=====Introduction:=====
=====Introduction:=====
The team identified a Green finding for the licensee's failure to follow NRC Regulatory Guide (RG) 1.155, "Station Blackout," guidance (to which they are committed in the UFSAR) for evaluating equipment needed to cope with a station blackout for the required duration for associated environmental conditions. This was a performance deficiency.  
The team identified a Green finding for the licensee's failure to follow NRC Regulatory Guide (RG) 1.155, "Station Blackout," guidance (to which they are committed in the UFSAR) for evaluating equipment needed to cope with a station blackout for the required duration for associated environmental conditions. This was a performance deficiency.


=====Description:=====
=====Description:=====
The DSDG is used for SBO mitigation and as part of the station's dedicated shutdown capability for 10 CFR 50, Appendix R fire mitigation. During a walkdown of the DSDG, the team questioned the temperature ratings of the equipment located in the DSDG compartment. This included equipment, such as the DSDG as well as necessary support loads and their corresponding MCC located in the room. The team determined, per Section 1.8 of the station's Updated Final Safety Analyses Report (UFSAR), that the licensee was committed to following the guidance in RG 1.155. Section 3.2.4 of RG 1.155, states in part, that the design adequacy and capability of equipment needed to cope with a SBO for the required duration and recovery period should be addressed and evaluated as appropriate for the associated environmental conditions. Upon investigation, it was discovered that the licensee had not performed a calculation that determined the maximum expected temperatures inside the compartment housing the DSDG and its associated support equipment. Furthermore, the licensee had not established that the equipment ratings were adequate to withstand the expected environmental ambient temperatures. Rather, the licensee was relying on a specification that was provided to the DSDG supplier. The team noted that the continuous duty ambient temperature ratings (104 degrees F) of some of the equipment were lower than the maximum outdoor ambient temperature (107 degrees F) the licensee expected to experience. Ventilation is supplied by fresh outdoor air which is circulated through the room. After identification by the team, the licensee performed a calculation that determined the maximum expected temperature inside the compartment housing the DSDG and evaluated the equipment to determine its capability to perform its function for the SBO coping duration. The licensee determined that when the DSDG is operating, the temperature in the compartment could be as high as 120 degrees F and that the DSDG and supporting equipment would be able to perform their functions for the SBO coping duration. The licensee generated NCR 600522 to address the issue.  
The DSDG is used for SBO mitigation and as part of the station's dedicated shutdown capability for 10 CFR 50, Appendix R fire mitigation. During a walkdown of the DSDG, the team questioned the temperature ratings of the equipment located in the DSDG compartment. This included equipment, such as the DSDG as well as necessary support loads and their corresponding MCC located in the room. The team determined, per Section 1.8 of the station's Updated Final Safety Analyses Report (UFSAR), that the licensee was committed to following the guidance in RG 1.155. Section 3.2.4 of RG 1.155, states in part, that the design adequacy and capability of equipment needed to cope with a SBO for the required duration and recovery period should be addressed and evaluated as appropriate for the associated environmental conditions. Upon investigation, it was discovered that the licensee had not performed a calculation that determined the maximum expected temperatures inside the compartment housing the DSDG and its associated support equipment. Furthermore, the licensee had not established that the equipment ratings were adequate to withstand the expected environmental ambient temperatures. Rather, the licensee was relying on a specification that was provided to the DSDG supplier. The team noted that the continuous duty ambient temperature ratings (104 degrees F) of some of the equipment were lower than the maximum outdoor ambient temperature (107 degrees F) the licensee expected to experience. Ventilation is supplied by fresh outdoor air which is circulated through the room. After identification by the team, the licensee performed a calculation that determined the maximum expected temperature inside the compartment housing the DSDG and evaluated the equipment to determine its capability to perform its function for the SBO coping duration. The licensee determined that when the DSDG is operating, the temperature in the compartment could be as high as 120 degrees F and that the DSDG and supporting equipment would be able to perform their functions for the  
 
SBO coping duration. The licensee generated NCR 600522 to address the issue.


=====Analysis:=====
=====Analysis:=====
The licensee's failure to follow NRC RG 1.155, "Station Blackout," guidance (to which they are committed to in the UFSAR) for evaluating equipment needed to cope with a station blackout for the required duration for associated environmental conditions was a performance deficiency. The performance deficiency was more than minor because it affected the Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring reliability, availability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the capability and reliability of the equipment located in the DSDG compartment was not ensured since a comparison of equipment temperature ratings and expected DSDG compartment temperatures was not performed.
The licensee's failure to follow NRC RG 1.155, "Station Blackout," guidance (to which they are committed to in the UFSAR) for evaluating equipment needed to cope with a station blackout for the required duration for associated environmental conditions was a performance deficiency. The performance deficiency was more than minor because it affected the Mitigating System s cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring reliability, availability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the capability and reliability of the equipment located in the DSDG compartment was not ensured since a comparison of equipment temperature ratings and expected DSDG compartment temperatures was not performed.


The team used IMC 0609, Att. 4, "Initial Characterization of Findings," issued 6/19/12, for Mitigating Systems, and IMC 0609, App. A, "The Significance Determination Process (SDP) for Findings At-Power," issued 6/19/12, and determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating SSC, and the SSC maintained its functionality. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance because the performance deficiency existed since initial installation of the DSDG.  
The team used IMC 0609, Att. 4, "Initial Characterization of Findings," issued 6/19/12, for Mitigating Systems, and IMC 0609, App. A, "The Significance Determination Process (SDP) for Findings At-Power," issued 6/19/12, and determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating SSC, and the SSC maintained its functionality. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance because the performance deficiency existed since initial installation of the DSDG.


=====Enforcement:=====
=====Enforcement:=====
Line 249: Line 422:


====a. Inspection Scope====
====a. Inspection Scope====
The team inspected the 4kV Bus 3 to verify its operational support role during design basis events. System health reports, component maintenance history and licensee corrective action program reports were reviewed to verify that potential degradation was monitored or prevented. The team reviewed selected calculations for electrical distribution system load flow/voltage drop, short-circuit, and electrical protection and coordination. This review was conducted to assess the adequacy and appropriateness of design assumptions, and to verify that bus capacity was not exceeded and bus voltages remained above minimum acceptable values to support transmission of power to downstream safety-related 480V Emergency Bus E2. Additionally, the switchgear's protective device settings and breaker ratings were reviewed to ensure that selective coordination was adequate for protection of connected equipment during worst case, short-circuit conditions to ensure continuity of power to downstream safety-related buses. To determine if breakers were maintained in accordance with industry and vendor recommendations, the team reviewed the preventive maintenance inspection and testing procedures. The team reviewed the loss of voltage protection scheme. Finally, the team performed a visual non-intrusive inspection of 4kV Bus 3 to assess the installation configuration, material condition, and potential vulnerability to hazards.
The team inspected the 4kV Bus 3 to verify its operational support role during design basis events. System health reports, component maintenance history and licensee corrective action program reports were reviewed to verify that potential degradation was  
 
monitored or prevented. The team review ed selected calculations for electrical distribution system load flow/voltage drop, short-circuit, and electrical protection and coordination. This review was conducted to assess the adequacy and appropriateness of design assumptions, and to verify that bus capacity was not exceeded and bus voltages remained above minimum acceptable values to support transmission of power to downstream safety-related 480V Emergency Bus E2. Additionally, the switchgear's protective device settings and breaker ratings were reviewed to ensure that selective coordination was adequate for protection of connected equipment during worst case, short-circuit conditions to ensure continui ty of power to downstream safety-related buses. To determine if breakers were maintained in accordance with industry and vendor recommendations, the team reviewed the preventive maintenance inspection and testing procedures. The team reviewed the loss of voltage protection scheme. Finally, the team performed a visual non-intrusive inspection of 4kV Bus 3 to assess the installation configuration, material condition, and potential vulnerability to hazards.


====b. Findings====
====b. Findings====
Line 267: Line 442:


=====Description:=====
=====Description:=====
The team identified two examples of deficiencies in electrical calculation RNP-E-8.002, "AC Auxiliary Electrical Distribution System Voltage/Load Flow/Fault Current Study," that contributed to the failure of the licensee to: 1) verify and assure adequate starting voltages to safety-related loads with offsite power available, and 2)ensure load survivability by properly analyzing the operation of protective devices to safety-related loads during a design basis event under degraded voltage conditions for the duration of the degraded grid voltage relay (DGVR) time delay and subsequent re-sequencing onto the emergency diesel generators (EDGs). The following examples contributed to the identified performance deficiency:   1. The licensee did not calculate voltages at the terminals of all safety-related equipment on the DGVR monitored bus while the bus is connected to offsite power and at the DGVR voltage dropout setting (less tolerances) to ensure adequate starting voltages during design basis accidents. TS 3.3.5 allows a voltage setpoint for the DGVRs of 430V +/-4V. The appropriateness of the setpoint was not adequately verified by design calculation RNP-E-8.002, because it failed to verify that required Class 1E motors would have adequate motor starting voltages with 480V Buses E1 and E2 at the DGVR dropout setting.
The team identified two examples of deficiencies in electrical calculation RNP-E-8.002, "AC Auxiliary Electrical Distribution System Voltage/Load Flow/Fault Current Study," that contributed to the failure of the licensee to: 1) verify and assure adequate starting voltages to safety-related loads with offsite power available, and 2)ensure load survivability by properly analyzing the operation of protective devices to safety-related loads during a design basis event under degraded voltage conditions for the duration of the degraded grid voltage relay (DGVR) time delay and subsequent re-sequencing onto the emergency diesel generators (EDGs). The following examples contributed to the identified performance deficiency:
1. The licensee did not calculate voltages at the terminals of all safety-related equipment on the DGVR monitored bus while the bus is connected to offsite power and at the DGVR voltage dropout setting (less tolerances) to ensure adequate starting voltages during design basis accidents. TS 3.3.5 allows a voltage setpoint for the DGVRs of 430V +/-4V. The appropriateness of the setpoint was not  
 
adequately verified by design calculation RNP-E-8.002, because it failed to verify that required Class 1E motors would have adequate motor starting voltages with 480V Buses E1 and E2 at the DGVR dropout setting.
 
The licensee performed additional analyses and determined that the affected equipment would have adequate starting voltages.


The licensee performed additional analyses and determined that the affected equipment would have adequate starting voltages. 2. If the voltage on the E1/E2 buses drops below the DGVR voltage dropout setting, a timer is initiated that results in disconnection of the bus from offsite power after the timer "times out" and the loads are subsequently re-sequenced onto the EDG. During the time delay period, loads that were running may become stalled or motors that have received a start signal that do not have adequate voltages to accelerate may continue in a stall condition. Both of these conditions may result in tripping of the protective devices which would prevent the associated load from re-sequencing onto the EDG. TS 3.3.5 allows a time delay setpoint for the DGVRs of 10 seconds +/- 0.5, to allow some time for offsite power voltage to recover to avoid unnecessarily swapping power source to the EDG. The setpoint was not properly verified by design calculation RNP-E-8.002, because it failed to ensure the protective devices for the Class 1E loads would not trip during a design basis event concurrent with a degraded voltage at the E1 and E2 buses below the DGVR setting but above the Loss of Voltage setting for the duration of the DGVR time delay and subsequent re-sequencing onto the EDG. Additionally, the calculation did not evaluate control power circuits and their fuses for motors that are actuated during the design basis event to ensure that the fuses would not actuate if the control circuit starter stays in an inrush condition for the 10 seconds of the DGVR. The licensee initiated corrective actions to evaluate the ability of the equipment to withstand the specified time delay, which was ongoing as of June 28, 2013.
2. If the voltage on the E1/E2 buses drops below the DGVR voltage dropout setting, a timer is initiated that results in disconnection of the bus from offsite power after the timer "times out" and the loads are subsequently re-sequenced onto the EDG. During the time delay period, loads that were running may become stalled or motors that have received a start signal that do not have adequate voltages to accelerate may continue in a stall condition. Both of these conditions may result in tripping of the protective devices which would prevent the associated load from re-sequencing onto the EDG. TS 3.3.5 allows a time delay setpoint for the DGVRs of 10 seconds  
+/- 0.5, to allow some time for offsite power voltage to recover to avoid unnecessarily swapping power source to the EDG. The setpoint was not properly verified by design calculation RNP-E-8.002, because it failed to ensure the protective devices for the Class 1E loads would not trip during a design basis event concurrent with a degraded voltage at the E1 and E2 buses below the DGVR setting but above the Loss of Voltage setting for the duration of the DGVR time delay and subsequent re-sequencing onto the EDG. Additionally, the calculation did not evaluate control power circuits and their fuses for motors that are actuated during the design basis event to ensure that the fuses would not actuate if the control circuit starter stays in an inrush condition for the 10 seconds of the DGVR. The licensee initiated corrective actions to evaluate the ability of the equipment to withstand the specified time delay, which was ongoing as of June 28, 2013.


=====Analysis:=====
=====Analysis:=====
Line 279: Line 460:
Appendix B of 10 CFR Part 50, Criterion III, "Design Control," required, in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.
Appendix B of 10 CFR Part 50, Criterion III, "Design Control," required, in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.


Contrary to the above, since 1995 when the licensee modified the DGVR design, until 2013 when the inspectors identified the issue, the licensee did not properly verify the adequacy of the DGVR design with respect to motor starting adequacy at the DVR voltage setpoint and load survivability during the DGVR time delay setpoint duration. This resulted in the potential for loss or unavailability of essential loads during a design basis event. When the issue was identified, the licensee performed an evaluation for both starting the motors as well as load survivability during the time delay. This violation is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensee's corrective action program as NCRs 601201 and 605969.  (NCV 05000261/20130007-03, Failure to Have Adequate Analyses Supporting the Degraded Voltage Relay Setpoints)
Contrary to the above, since 1995 when the licensee modified the DGVR design, until 2013 when the inspectors identified the issue, the licensee did not properly verify the adequacy of the DGVR design with respect to motor starting adequacy at the DVR voltage setpoint and load survivability during the DGVR time delay setpoint duration. This resulted in the potential for loss or unavailability of essential loads during a design basis event. When the issue was identified, the licensee performed an evaluation for both starting the motors as well as load survivability during the time delay. This violation is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensee's corrective action program as NCRs 601201 and 605969.  (NCV 05000261/20130007-03, Failure to Have Adequate Analyses Supporting  
 
the Degraded Voltage Relay Setpoints)


===.2.16 480V Buses E1 and E2 Load Shed Circuitry===
===.2.16 480V Buses E1 and E2 Load Shed Circuitry===
Line 292: Line 475:


=====Introduction:=====
=====Introduction:=====
The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to verify the adequacy of the plant design during fast bus transfers. Specifically, the licensee failed to have an adequate analysis that ensured a successful fast bus transfer of the safety-related E1 bus feeder from the Unit Auxiliary Transformer to the Startup Transformer when required. This was a performance deficiency.
The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to verify the adequacy of the plant design during fast bus transfers. Specifically, the licensee failed to have an adequate analysis that ensured a successful fast bus transfer of the safety-related E1 bus feeder  
 
from the Unit Auxiliary Transformer to the Startup Transformer when required. This was a performance deficiency.


=====Description:=====
=====Description:=====
Line 312: Line 497:


=====Analysis:=====
=====Analysis:=====
The licensee's failure to prescribe a procedure with appropriate acceptance criteria to verify DGVR circuit operability following degraded voltage disable switch operation for RCP starts was a performance deficiency. The performance deficiency was more than minor because if left uncorrected, it could become a more significant safety concern. Specifically, by not properly testing the DGVR circuit to ensure continuity following switch manipulation for RCP starts, the circuit could unknowingly become inoperable and non-functional for an entire operating cycle. The team used IMC 0609, Att. 4, "Initial Characterization of Findings," issued 6/19/12, for the Mitigating Systems Cornerstone, and IMC 0609, App. A, "The Significance Determination Process (SDP) for Findings At-Power," issued 6/19/12, and determined the finding to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system function, did not represent an actual loss of function of at least a single train for greater than its TS allowed outage time or two separate safety systems out-of-service for greater than its TS allowed outage time, and did not represent an actual loss of function of one or more non-TS trains. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the modification that added the degraded voltage disable switches.  
The licensee's failure to prescribe a procedure with appropriate acceptance criteria to verify DGVR circuit operability following degraded voltage disable switch operation for RCP starts was a performance deficiency. The performance deficiency was more than minor because if left uncorrected, it could become a more significant safety concern. Specifically, by not properly testing the DGVR circuit to ensure continuity following switch manipulation for RCP starts, the circuit could unknowingly become inoperable and non-functional for an entire operating cycle. The team used IMC 0609, Att. 4, "Initial Characterization of Findings," issued 6/19/12, for the Mitigating Systems Cornerstone, and IMC 0609, App. A, "The Significance Determination Process (SDP) for Findings At-Power," issued 6/19/12, and determined the finding to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system function, did not represent an actual loss of function of at least a single train for greater than its TS allowed outage time or two separate safety systems out-of-service for greater than its TS allowed outage time, and did not represent an actual loss of function of one or more non-TS trains. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the modification that added the degraded voltage disable switches.


=====Enforcement:=====
=====Enforcement:=====
Line 318: Line 503:


===.3 (Opened) Unresolved Item (URI):===
===.3 (Opened) Unresolved Item (URI):===
Questions Regarding License Basis Design Requirements for Degraded Voltage Relays
Questions Regarding License Basis Design Requirements for Degraded Voltage Relays


=====Introduction:=====
=====Introduction:=====
Line 324: Line 509:


=====Description:=====
=====Description:=====
The Robinson degraded voltage protection design features three ITE Type 27N relays for each 480V emergency bus E1 and E2, arranged in a two out of three tripping scheme. BBC Instruction Bulletin 7.4.1.7-7 states, the relay employs a peak voltage detector, and harmonic distortion on the AC waveform can have a noticeable effect on the relay operating point and the measuring instruments used to calibrate the relay. The bulletin also notes that the relay is available with an internal harmonic filter for applications where waveform distortion is a factor; however, harmonic filters are not installed on the degraded grid voltage relays based upon their model number and specification package. The inspectors questioned if persistent harmonics on the 480V system could cause the relays to fail to actuate at the set point specified in Technical Specifications 3.3.5, and if transient harmonics could cause the relays to spuriously reset during the time delay that occurs during an actual degraded voltage condition concurrent with a design basis accident. Persistent harmonics can be produced by factors external to the nuclear site or by internal phenomena. A typical internal source of harmonics at nuclear power plants is defects in rotating equipment. Persistent harmonics could cause dropout set point shift, and mask an actual degraded voltage condition. Transient harmonics could cause the relays to spuriously reset during an actual degraded voltage event, thereby delaying the protective function beyond the nominal value stipulated in Technical Specifications 3.3.5. The relay is susceptible to this type of mal-operation because it features an instantaneous voltage sensor that could reset in less than two cycles in the presence of harmonics, thereby reinitiating the relay's internal timer. The licensee has entered this item into their corrective action program as NCR 601203. This issue is unresolved pending inspector consultation with NRC headquarters technical staff for clarification of license basis design requirements of degraded voltage relays to withstand the effects of harmonics. This issue is identified as URI 05000261/2013007-07, Questions Regarding License Basis Design Requirements for Degraded Voltage Relays.
The Robinson degraded voltage protection design features three ITE Type 27N relays for each 480V emergency bus E1 and E2, arranged in a two out of three tripping scheme. BBC Instruction Bulletin 7.4.1.7-7 states, the relay employs a peak voltage detector, and harmonic distortion on the AC waveform can have a noticeable effect on the relay operating point and the measuring instruments used to calibrate the relay. The bulletin also notes that the relay is available with an internal harmonic filter for applications where waveform distortion is a factor; however, harmonic filters are not installed on the degraded grid voltage relays based upon their model number and specification package. The inspectors questioned if persistent harmonics on the 480V system could cause the relays to fail to actuate at the set point specified in Technical Specifications 3.3.5, and if transient harmonics could cause the relays to spuriously reset during the time delay that occurs during an actual degraded voltage condition concurrent with a design basis accident. Persistent harmonics can be produced by factors external to the nuclear site or by internal phenomena. A typical internal source of harmonics at nuclear power plants is defects in rotating equipment. Persistent harmonics could cause dropout set point shift, and mask an actual degraded voltage condition. Transient harmonics could cause the relays to spuriously reset during an actual degraded voltage event, thereby delaying the protective function beyond the nominal value stipulated in Technical Specifications 3.3.5. The relay is susceptible to this type of mal-operation because it features an instantaneous voltage sensor that could reset in less than two cycles in the presence of harmonics, thereby reinitiating the relay's internal timer. The licensee has entered this item into their corrective action program as NCR  
 
601203. This issue is unresolved pending inspector consultation with NRC headquarters technical staff for clarification of license basis design requirements of degraded voltage relays to withstand the effects of harmonics. This issue is identified as URI 05000261/2013007-07, Questions Regarding License Basis Design Requirements for  
 
Degraded Voltage Relays.


===.2.17 Security Uninterruptible Power Supply (UPS)===
===.2.17 Security Uninterruptible Power Supply (UPS)===
Line 338: Line 527:
====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed six operating experience issues for applicability at the H. B. Robinson Steam Electric Plant. The team performed an independent review for these issues and where applicable, assessed the licensee's evaluation and dispositioning of each item. The issues that received a detailed review by the team included:
The team reviewed six operating experience issues for applicability at the H. B. Robinson Steam Electric Plant. The team performed an independent review for these issues and where applicable, assessed the licensee's evaluation and dispositioning of each item. The issues that received a detailed review by the team included:
* NRC Information Notice 2012-14, "Motor Operated Valves Inoperable Due to Stem - Disc Separation"
* NRC Information Notice 2012-14, "Motor Operated Valves Inoperable Due to Stem -
Disc Separation"
* NRC Information Notice 2011-14, "Component Cooling Water System Gas Accumulation and Other Performance Issues"
* NRC Information Notice 2011-14, "Component Cooling Water System Gas Accumulation and Other Performance Issues"
* NRC Information Notice 2010-12, "Containment Liner Corrosion"
* NRC Information Notice 2010-12, "Containment Liner Corrosion"
Line 348: Line 538:
No findings were identified.
No findings were identified.


===4. Other Activities   Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity ===
===4. Other Activities===
 
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity  


{{a|4OA5}}
{{a|4OA5}}
Line 358: Line 550:
In 2012, the inspectors verified, per Temporary Instruction (TI) 2515/177, that the licensee implemented or was in the process of implementing the commitments, modifications, and programmatically controlled actions described in the licensee's response to NRC Generic Letter 2008-01, "Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems."  During the inspection, the team questioned the acceptability of the licensee's use of the GOTHIC computer code to support operability determinations with respect to the concerns identified in Information Notice 2011-17 which cautioned the use of computer models when evaluating the acceptability of voids in emergency core cooling systems. The inspectors opened a URI pending further inspection by a GOTHIC subject matter expert in the NRC's Nuclear Reactor Regulation (NRR) office in order to evaluate and verify the licensee's conclusions regarding the continued use of GOTHIC to support operability determinations. An NRR subject matter expert reviewed the facts of the subject URI as well as plant-specific information in order to evaluate acceptability of Carolina Power and Light Company (CP&L) use of GOTHIC at the H.B. Robinson Steam Electric plant to support operability determinations.
In 2012, the inspectors verified, per Temporary Instruction (TI) 2515/177, that the licensee implemented or was in the process of implementing the commitments, modifications, and programmatically controlled actions described in the licensee's response to NRC Generic Letter 2008-01, "Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems."  During the inspection, the team questioned the acceptability of the licensee's use of the GOTHIC computer code to support operability determinations with respect to the concerns identified in Information Notice 2011-17 which cautioned the use of computer models when evaluating the acceptability of voids in emergency core cooling systems. The inspectors opened a URI pending further inspection by a GOTHIC subject matter expert in the NRC's Nuclear Reactor Regulation (NRR) office in order to evaluate and verify the licensee's conclusions regarding the continued use of GOTHIC to support operability determinations. An NRR subject matter expert reviewed the facts of the subject URI as well as plant-specific information in order to evaluate acceptability of Carolina Power and Light Company (CP&L) use of GOTHIC at the H.B. Robinson Steam Electric plant to support operability determinations.


Robinson's current design basis with respect to voids in the subject systems is a water-solid, no gas condition. This means the subject systems must be water-solid when transitioning from an outage into power operation. Once the transition is complete, in recognition of the possibility that voids will form during operation, such voids are acceptable provided operability is reasonably maintained. Robinson has used GOTHIC to support past and continued operability assessments. GOTHIC is a multi-dimensional, multi-component computer code with the capability to model two-phase flow in nuclear power plant systems.
Robinson's current design basis with respect to voids in the subject systems is a water-solid, no gas condition. This means the subject systems must be water-solid when transitioning from an outage into power operation. Once the transition is complete, in recognition of the possibility that voids will form during operation, such voids are acceptable provided operability is reasonably maintained. Robinson has used GOTHIC to support past and continued operability assessments. GOTHIC is a multi-dimensional, multi-component computer code with the capability to model two-phase flow in nuclear  
 
power plant systems.
 
CP&L contracted with Nuclear Applications, Inc. (NAI) to apply GOTHIC to predict behavior associated with gas in the ECCS and RHR suction and discharge pipes at the H. B. Robinson plant. GOTHIC was compared to a broad range of test conditions and to tests that directly simulated aspects of behavior that may occur in plant piping. GOTHIC
 
was then used to predict the behavior of gas trapped in specific RHR and ECCS locations.


CP&L contracted with Nuclear Applications, Inc. (NAI) to apply GOTHIC to predict behavior associated with gas in the ECCS and RHR suction and discharge pipes at the H. B. Robinson plant. GOTHIC was compared to a broad range of test conditions and to tests that directly simulated aspects of behavior that may occur in plant piping. GOTHIC was then used to predict the behavior of gas trapped in specific RHR and ECCS locations.
Following review of additional information, the staff determined that GOTHIC was able to predict gas transport behavior for assessment of operability provided that (a) the pump inlet void fractions and volumes predicted by GOTHIC are shown to be acceptably conservative, (b) appropriate modeling methodologies are used in GOTHIC calculations and are consistent with testing modeling, and (c) GOTHIC predicted results are consistent with simplified methodologies, such as the Froude number, when those methodologies apply. The staff performed an in-depth evaluation of a reasonably bounding GOTHIC evaluation of the effect of trapped gas in an elevated 95-foot long 10-inch diameter pipe during initiation of flow from the containment sump during the emergency recirculation phase of operation. The GOTHIC evaluation was found to have acceptably determined gas volumes that would not jeopardize operability. The staff's


Following review of additional information, the staff determined that GOTHIC was able to predict gas transport behavior for assessment of operability provided that (a) the pump inlet void fractions and volumes predicted by GOTHIC are shown to be acceptably conservative, (b) appropriate modeling methodologies are used in GOTHIC calculations and are consistent with testing modeling, and (c) GOTHIC predicted results are consistent with simplified methodologies, such as the Froude number, when those methodologies apply. The staff performed an in-depth evaluation of a reasonably bounding GOTHIC evaluation of the effect of trapped gas in an elevated 95-foot long 10-inch diameter pipe during initiation of flow from the containment sump during the emergency recirculation phase of operation. The GOTHIC evaluation was found to have acceptably determined gas volumes that would not jeopardize operability. The staff's review regarding Robinson's modeling detail support a conclusion that the licensee's use of GOTHIC to evaluate the potential movement of trapped gas with respect to operability was acceptable. Additionally, the licensee's use of GOTHIC was found to have acceptably assessed if there is a potential water hammer problem in a piping system and estimated the magnitude of potential pressure spikes. Based on this additional review, this URI is now closed.
review regarding Robinson's modeling detail support a conclusion that the licensee's use of GOTHIC to evaluate the potential movement of trapped gas with respect to operability was acceptable. Additionally, the licensee's use of GOTHIC was found to have acceptably assessed if there is a potential water hammer problem in a piping system and estimated the magnitude of potential pressure spikes. Based on this additional review, this URI is now closed.


====b. Findings====
====b. Findings====
No findings were identified.
No findings were identified.


===.2 (Closed) URI 05000261/2012005-04: Questions Regarding the Adequacy of the Fill and Vent Procedure for the RHR Heat Exchangers (ML 13037A500)===
===.2 (Closed) URI 05000261/2012005-04: Questions Regarding the Adequacy of the Fill and===
 
Vent Procedure for the RHR Heat Exchangers (ML 13037A500)


====a. Inspection Scope====
====a. Inspection Scope====
Line 375: Line 575:
No findings were identified. However, the inspectors did identify a minor performance deficiency and associated minor violation of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings."  In accordance with IMC 0612, minor violations are not routinely documented in inspections reports. However, they may be documented to capture inspection activities and conclusions for closing a URI.
No findings were identified. However, the inspectors did identify a minor performance deficiency and associated minor violation of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings."  In accordance with IMC 0612, minor violations are not routinely documented in inspections reports. However, they may be documented to capture inspection activities and conclusions for closing a URI.


The inspectors determined that the licensee's failure to provide an adequate RHR fill and vent procedure to successfully vent the RHR HXs by establishing minimum flow rates and times necessary to dynamically flush the HXs was contrary to 10 CFR 50 Appendix B, Criterion V, and was a performance deficiency. Using IMC 0612 Appendix B, "Issue Screening," dated 9/7/12, the team determined this performance deficiency to be of minor significance because the HXs would have been effectively flushed during the post maintenance system flow test, prior to the system being placed in service, without any adverse impact to the system availability, reliability, or capability. Because this issue was entered into the licensee's corrective action program, as NCR 575346, and was of minor significance, the failure to comply with 10 CFR 50 Appendix B, Criterion V, "Instructions, Procedures, and Drawings," constitutes a minor violation that is not subject to enforcement action in accordance with NRC's Enforcement Policy.
The inspectors determined that the licensee's failure to provide an adequate RHR fill and vent procedure to successfully vent the RHR HXs by establishing minimum flow rates and times necessary to dynamically flush the HXs was contrary to 10 CFR 50 Appendix B, Criterion V, and was a performance deficiency. Using IMC 0612 Appendix B, "Issue Screening," dated 9/7/12, the team determined this performance deficiency to be of minor significance because the HXs would have been effectively flushed during the post maintenance system flow test, prior to the system being placed in service, without any adverse impact to the system availability, reliability, or capability. Because this issue was entered into the licensee's corrective action program, as NCR 575346, and was of minor significance, the failure to comply with 10 CFR 50 Appendix B, Criterion V, "Instructions, Procedures, and Drawings," constitutes a minor violation that is not subject  
 
to enforcement action in accordance with NRC's Enforcement Policy.
 
This URI is now closed.


This URI is now closed.
{{a|4OA6}}
{{a|4OA6}}
==4OA6 Meetings, Including Exit==
==4OA6 Meetings, Including Exit==


On May 16, 2013, the team presented the inspection results to Mr. Gideon and other members of the licensee's staff. Additional inspection results were communicated on June 20, 2013, on a teleconference with Mr. Gideon and other members of station staff, and on June 27, 2013 with Mr. Hightower. The inspectors verified that no proprietary information was documented in this report.
On May 16, 2013, the team presented the inspection results to Mr. Gideon and other members of the licensee's staff. Additional inspection results were communicated on June 20, 2013, on a teleconference with Mr. Gideon and other members of station staff, and on June 27, 2013 with Mr. Hightower.
 
The inspectors verified that no proprietary information was documented in this report.


ATTACHMENT:   
ATTACHMENT:   
Line 390: Line 595:


===Licensee personnel===
===Licensee personnel===
:  
:
: [[contact::M. Connelly]], Senior Regulatory Affairs Engineer  
: [[contact::M. Connelly]], Senior Regulatory Affairs Engineer  
: [[contact::W. Hightower]], Supervisor, Licensing/Regulatory Programs  
: [[contact::W. Hightower]], Supervisor, Licensing/Regulatory Programs  
: [[contact::J. Kunzmann]], Supervisor Nuclear Rapid Response  
: [[contact::J. Kunzmann]], Supervisor Nuclear Rapid Response  
: [[contact::A. Zimmerman]], Lead Licensing Engineer
: [[contact::A. Zimmerman]], Lead Licensing Engineer  
===NRC personnel===
===NRC personnel===
: [[contact::J. Hickey]], Senior Resident Inspector, Division of Reactor Projects (DRP),
: [[contact::J. Hickey]], Senior Resident Inspector, Division of Reactor Projects (DRP),
Line 407: Line 612:


===Opened and Closed===
===Opened and Closed===
: 05000261/2013007-01 NCV Failure to Account for Containment Temperature Measurement Uncertainty  
: 05000261/2013007-01 NCV Failure to Account for Containment
Temperature Measurement Uncertainty  
 
[Section 1R21.2.9]  
[Section 1R21.2.9]  
: 05000261/2013007-02 FIN Failure to Evaluate SBO Coping Equipment for Environmental Conditions [Section 1R21.2.13]  
: 05000261/2013007-02 FIN Failure to Evaluate SBO Coping Equipment for Environmental Conditions [Section 1R21.2.13]  
: 05000261/2013007-03 NCV Failure to Have Adequate Analyses Supporting the Degraded Voltage Relay Setpoints [Section
: 05000261/2013007-03 NCV Failure to Have Adequate Analyses Supporting
1R21.2.15]
the Degraded Voltage Relay Setpoints [Section  
 
1R21.2.15]  
: 05000261/2013007-04 NCV Failure to Have Adequate Analyses For the E1 Bus Fast Transfer  [Section 1R21.2.16.1]  
: 05000261/2013007-04 NCV Failure to Have Adequate Analyses For the E1 Bus Fast Transfer  [Section 1R21.2.16.1]  
: 05000261/2013007-05 NCV Failure to Have Appropriate Procedure to Verify Degraded Voltage Relay Circuit Status  [Section 1R21.2.16.2]  
: 05000261/2013007-05 NCV Failure to Have Appropriate Procedure to Verify Degraded Voltage Relay Circuit Status  [Section 1R21.2.16.2]  
Line 417: Line 626:
===Opened===
===Opened===
: 05000261/2013007-07 URI Questions Regarding License Basis Design Requirements for Degraded Voltage Relays  
: 05000261/2013007-07 URI Questions Regarding License Basis Design Requirements for Degraded Voltage Relays  
[Section 1R12.2.16.3]  
[Section 1R12.2.16.3]  


===Closed===
===Closed===
: [[Closes finding::05000261/FIN-2012005-03]] URI Questions Regarding Whether GOTHIC is Sufficiently Qualified for Use in Operability Determinations [Section 4OA5.1]
: [[Closes finding::05000261/FIN-2012005-03]] URI Questions Regarding Whether GOTHIC is Sufficiently Qualified for Use in Operability Determinations [Section 4OA5.1]
: [[Closes finding::05000261/FIN-2012005-04]] URI Questions Regarding the Adequacy of the Fill and Vent Procedure for the RHR Heat  
: [[Closes finding::05000261/FIN-2012005-04]] URI Questions Regarding the Adequacy of the Fill and Vent Procedure for the RHR Heat  
: Exchanger [Section 4OA5.2]  
: Exchanger [Section 4OA5.2]  


==LIST OF DOCUMENTS REVIEWED==
==LIST OF DOCUMENTS REVIEWED==
Line 458: Line 667:
: RNP-E-8.002, AC Auxiliary Electrical Distribution System Study, Rev. 8C
: RNP-E-8.002, AC Auxiliary Electrical Distribution System Study, Rev. 8C
: RNP-E-8.042, AC MOV Evaluation, Rev. 4
: RNP-E-8.042, AC MOV Evaluation, Rev. 4
: RNP-E-8.054, Load Flow/Short circuit analysis, 640kW/800kVA Security Diesel Generator, 9/26/11
: RNP-E-8.054, Load Flow/Short circuit analysis, 640kW/800kVA Security
: Diesel Generator, 9/26/11
: RNP-E-8.059, Security UPS Sizing and Loading, Rev. 1
: RNP-E-8.059, Security UPS Sizing and Loading, Rev. 1
: RNP-E-8.060, Security Battery and Charger Sizing, Rev. 0
: RNP-E-8.060, Security Battery and Charger Sizing, Rev. 0
Line 484: Line 694:
: AFW-V2-14A, Rev. 8
: AFW-V2-14A, Rev. 8
: RNP-M/MECH-1599, RHR Pump NPSH, Rev. 0
: RNP-M/MECH-1599, RHR Pump NPSH, Rev. 0
: RNP-M/MECH-1621, Containment Isolation Valves 10CFR50 Appendix J Allowable Leakage
: RNP-M/MECH-1621, Containment Isolation Valves 10CFR50 Appendix J Allowable Leakage Rates, Rev. 5
: Rates, Rev. 5
: RNP-M/MECH-1637, CS/SI/RHR System Hydraulic Model, Rev. 9
: RNP-M/MECH-1637, CS/SI/RHR System Hydraulic Model, Rev. 9
: RNP-M/MECH-1651, Containment Analysis Inputs, Rev. 12
: RNP-M/MECH-1651, Containment Analysis Inputs, Rev. 12
Line 496: Line 705:
: RNP-M/MECH-1734, Basis for AOV Calculations, Rev. 0
: RNP-M/MECH-1734, Basis for AOV Calculations, Rev. 0
: RNP-M/MECH-1802, Safety Related Pump Minimum Performance Requirements, Rev. 3
: RNP-M/MECH-1802, Safety Related Pump Minimum Performance Requirements, Rev. 3
: WES 1543, 88-10, Resolution to Generic Letter, Rev. 0, dated 6/24/88
: WES 1543, 88-10, Resolution to Generic Letter, Rev. 0, dated 6/24/88  
: Completed Procedures
: Completed Procedures
: EST-134, Main Steam Isolation Valves Air Leakage Test (Refueling), Rev. 10, dated 3/9/12
: EST-134, Main Steam Isolation Valves Air Leakage Test (Refueling), Rev. 10, dated 3/9/12
Line 565: Line 774:
: SI-864B, Test No. I0130C11/13, Rev. 21, dated 5/10/10
: SI-864B, Test No. I0130C11/13, Rev. 21, dated 5/10/10
: TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve  with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
: TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve  with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
: RV1-1,
: RV1-1, Rev. 3, dated 5/7/07
: Rev. 3, dated 5/7/07
: TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve  with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
: TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve  with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
: RV1-1, Rev. 5, dated 2/18/12
: RV1-1, Rev. 5, dated 2/18/12
Line 572: Line 780:
: RV1-2, Rev. 3, dated 5/7/07
: RV1-2, Rev. 3, dated 5/7/07
: TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve  with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
: TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve  with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
: RV1-2,
: RV1-2, Rev. 5, dated 2/23/12
: Rev. 5, dated 2/23/12
: TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve  with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
: TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve  with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
: RV1-3, Rev. 1, dated 10/13/05
: RV1-3, Rev. 1, dated 10/13/05
: TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve  with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
: TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve  with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
: RV1-3,
: RV1-3, Rev. 5, dated 5/20/10  
: Rev. 5, dated 5/20/10
: Completed Work Orders
: Completed Work Orders
: WO 00067292 01, Test Distribution Panel A Breakers, dated 4/10/01
: WO 00067292 01, Test Distribution Panel A Breakers, dated 4/10/01
Line 677: Line 883:
: WO 02053755 01, SG "B" Steam PORV Drain Line Sheared on
: WO 02053755 01, SG "B" Steam PORV Drain Line Sheared on
: RV1-2, dated 5/2/12
: RV1-2, dated 5/2/12
: WO 02067295 01, Check Security and EFRIS Batteries, dated 4/17/12
: WO 02067295 01, Check Security and EFRIS Batteries, dated 4/17/12  
: Corrective Action Program Documents Action Requests:
: Corrective Action Program Documents Action Requests:
: 151422, Evaluate Operation with DVR's Bypassed
: 151422, Evaluate Operation with DVR's Bypassed
Line 697: Line 903:
: RHR-759A
: RHR-759A
: 563249-18, Main Steam Isolation valves Fail to Close at Shearon Harris Nuclear Power Plant  
: 563249-18, Main Steam Isolation valves Fail to Close at Shearon Harris Nuclear Power Plant  
: 2717, Part 21 Notification Anchor Darling Double-Disc Gate Valves Condition Reports:
: 2717, Part 21 Notification Anchor Darling Double-Disc Gate Valves  
: Condition Reports:
: 082064, Methodology to Determine Containment Average Temperature to Satisfy TS 3.6.5  
: 082064, Methodology to Determine Containment Average Temperature to Satisfy TS 3.6.5  
: Surveillance Requirement With
: Surveillance Requirement With
Line 756: Line 963:
: 600388, SRI Documents Loaded into V:\Shared Drive\CDBI\2013 File  
: 600388, SRI Documents Loaded into V:\Shared Drive\CDBI\2013 File  
: 95-02840, Evaluation of Testing, Set Reference Clarification, Nureg 1492  
: 95-02840, Evaluation of Testing, Set Reference Clarification, Nureg 1492  
: Design Basis Documents DBD/R87038/SD02, Design Basis Document Safety Injection System, Rev. 0 DBD/R87038/SD03, Design Basis Document Residual Heat Removal System, Rev. 0  
: Design Basis Documents
: DBD/R87038/SD02, Design Basis Document Safety Injection System, Rev. 0 DBD/R87038/SD03, Design Basis Document Residual Heat Removal System, Rev. 0  
: DBD/R87038/SD13, Component Cooling Water System, Rev. 10  
: DBD/R87038/SD13, Component Cooling Water System, Rev. 10  
: DBD/R87038/SD25, Main Steam System, Rev. 8  
: DBD/R87038/SD25, Main Steam System, Rev. 8  
Line 766: Line 974:
: SI-864A/B, Series 300 16X14X16-S70 WDD Venturi Weld Ends O.S.& Y. Double Disc Gate Valve with
: SI-864A/B, Series 300 16X14X16-S70 WDD Venturi Weld Ends O.S.& Y. Double Disc Gate Valve with
: SMB-1 Limitorque Valve Control, Rev. 1  
: SMB-1 Limitorque Valve Control, Rev. 1  
: 5379-3646, Nozzle Installation For Vena Contracta Taps, (FE-605), Rev. 1 5379-5373, Sht 1, 4160V One Line Diagram, Rev. 15 B-190627 Series, Single Line Diagrams - MCC 5, Rev. various  
: 5379-3646, Nozzle Installation For Vena Contracta Taps, (FE-605), Rev. 1  
: 5379-5373, Sht 1, 4160V One Line Diagram, Rev. 15 B-190627 Series, Single Line Diagrams - MCC 5, Rev. various  
: B-190627 Series, Single Line Diagrams - MCC 6, Rev. various  
: B-190627 Series, Single Line Diagrams - MCC 6, Rev. various  
: B-190628, 480V EDG B Control Wiring Diagram, Rev. 26  
: B-190628, 480V EDG B Control Wiring Diagram, Rev. 26  
Line 803: Line 1,012:
: EC 91626, Temperature Effects on
: EC 91626, Temperature Effects on
: OST-253 Results, Rev. 0
: OST-253 Results, Rev. 0
: ECR 14546, CCW Vents to Protect Against Gas Intrusion  
: ECR 14546, CCW Vents to Protect Against Gas Intrusion
===Procedures===
===Procedures===
: AOP-013, Fuel Handling Accident, Rev. 15
: AOP-013, Fuel Handling Accident, Rev. 15
Line 817: Line 1,026:
: EGR-NGCC-0007, Maintenance of Design Documents, Rev. 11
: EGR-NGCC-0007, Maintenance of Design Documents, Rev. 11
: EGR-NGCC-0009, Engineering Change Product Selection and Initiation, Rev. 6
: EGR-NGCC-0009, Engineering Change Product Selection and Initiation, Rev. 6
: EGR-NGCC-0017, Preparation and Control of Design Analyses and Calculations, Rev. 8
: EGR-NGCC-0017, Preparation and Control of De sign Analyses and Calculations, Rev. 8
: EGR-NGGC-0106, AC and DC Overcurrent Protection and Coordination, Rev. 4
: EGR-NGGC-0106, AC and DC Overcurrent Protection and Coordination, Rev. 4
: EPP-1, Loss of All AC Power, Rev. 33 and Rev. 51
: EPP-1, Loss of All AC Power, Rev. 33 and Rev. 51
Line 870: Line 1,079:
: SPP-035, Containment Bulk Average Temperature Measurement, Rev. 6
: SPP-035, Containment Bulk Average Temperature Measurement, Rev. 6
: TMM-032, Motor Operated Valve Program, Rev. 28
: TMM-032, Motor Operated Valve Program, Rev. 28
: TMM-035, Post Test Evaluation of MOV Performance, Rev. 23  
: TMM-035, Post Test Evaluation of MOV Performance, Rev. 23
===Miscellaneous Documents===
===Miscellaneous Documents===
: 06-15, Evaluate Calculation
: 06-15, Evaluate Calculation
Line 893: Line 1,102:
: RNP-M/MECH-1802, 9/15/02 Letter dated March 24, 1969, U.S. Atomic Energy Commission to Mr. P. S. Colby of CP&L Letter dated November 5, 1969, U.S. Atomic Energy Commission to Mr. P. S. Colby of CP&L  
: RNP-M/MECH-1802, 9/15/02 Letter dated March 24, 1969, U.S. Atomic Energy Commission to Mr. P. S. Colby of CP&L Letter dated November 5, 1969, U.S. Atomic Energy Commission to Mr. P. S. Colby of CP&L  
: Letter dated May 14, 2013, Re: 3WT-811 style pump Typical S/n
: Letter dated May 14, 2013, Re: 3WT-811 style pump Typical S/n
: 1613243 Minimum Flow Operation Letter, Flowserve to Progress Energy, Robinson Station, S/N
: 1613243 Minimum Flow
: Operation Letter, Flowserve to Progress Energy, Robinson Station, S/N
: 1612443, Minimum Flow
: 1612443, Minimum Flow
: Operation, dated 5/14/13  
: Operation, dated 5/14/13  
Line 905: Line 1,115:
: NLS-88-163, CPL Response to Bulletin 88-04, dated July 1988
: NLS-88-163, CPL Response to Bulletin 88-04, dated July 1988
: NLS-89-040, CPL Supplemental Response to Bulletin 88-04, dated February 1989
: NLS-89-040, CPL Supplemental Response to Bulletin 88-04, dated February 1989
: NP-7410-V3R1, EPRI Guidance on Molded Case Circuit Breaker Maintenance and Application
: NP-7410-V3R1, EPRI Guidance on Molded Case Circuit Breaker Maintenance and Application Guide NRC Bulletin 88-04, Potential Safety-Related Pump Loss, dated May 5, 1988  
: Guide NRC Bulletin 88-04, Potential Safety-Related Pump Loss, dated May 5, 1988  
: NRC Information Notice No. 87-59, Potential RHR Pump Loss  
: NRC Information Notice No. 87-59, Potential RHR Pump Loss  
: NRC Information Notice 93-64, Periodic Testing and Preventative Maintenance of Molded Case Circuit Breakers NRC Information Notice 95-05, Undervoltage Protection Relay Settings Out of Tolerance Due to
: NRC Information Notice 93-64, Periodic Testing and Preventative Maintenance of Molded Case
: Circuit Breakers NRC Information Notice 95-05, Undervoltage Protection Relay Settings Out of Tolerance Due to
: Test Equipment Harmonics  
: Test Equipment Harmonics  
: NRC Regulatory Issue Summary 2011-12, Adequacy of Station Electric Distribution System Voltages, Rev. 1
: NRC Regulatory Issue Summary 2011-12, Adequacy of Station Electric Distribution System Voltages, Rev. 1
Line 915: Line 1,125:
: RNP Student Text, Component Cooling Water System, Volume 1 - Systems, Rev. 1
: RNP Student Text, Component Cooling Water System, Volume 1 - Systems, Rev. 1
: ST-039, 230/4KV Electrical System Student Manual, Rev. 0
: ST-039, 230/4KV Electrical System Student Manual, Rev. 0
: ST-056, Dedicated Shutdown System Student Manual, Rev. 0 Safety Evaluation by the Division of Reactor Licensing U. S. Atomic Energy Commission in the
: ST-056, Dedicated Shutdown System Student Manual, Rev. 0  
: Safety Evaluation by the Division of Reactor Licensing U. S. Atomic Energy Commission in the
: Matter of Carolina Power and Light Company H. B. Robinson Unit No. 2 Docket No. 50-261, dated 5/18/1970  
: Matter of Carolina Power and Light Company H. B. Robinson Unit No. 2 Docket No. 50-261, dated 5/18/1970  
: Standing Instruction 13-001, ITS LCO 3.6.5, Containment Air Temperature, is non-conservative, Rev. 1  
: Standing Instruction 13-001, ITS LCO 3.6.5, Containment Air Temperature, is non-conservative, Rev. 1  
: System Health Report- 2080, Safety Injection (1/1/2013 - 3/31/13) System Health Report- 3020, Main Steam System (10/1/2010 - 12/30/10) System Health Report- 3020, Main Steam System (10/1/2011 - 12/30/11)  
: System Health Report- 2080, Safety Injection (1/1/2013 - 3/31/13) System Health Report- 3020, Main Steam System (10/1/2010 - 12/30/10) System Health Report- 3020, Main Steam System (10/1/2011 - 12/30/11)  
: System Health Report- 3020, Main Steam System (10/1/2012 - 12/30/12)  
: System Health Report- 3020, Main Steam System (10/1/2012 - 12/30/12)  
: System Health Report- 3065, Auxiliary Feedwater (7/1/2010 - 9/30/10) System Health Report- 3065, Auxiliary Feedwater (1/1/2011 - 3/31/11) System Health Report- 3065, Auxiliary Feedwater (1/1/2012 - 3/31/12) System Health Report- 3065, Auxiliary Feedwater (1/1/2013 - 3/31/13) System Health Report- 4080, Component Cooling Water (1/1/2013-3/31/2013)  
: System Health Report- 3065, Aux iliary Feedwater (7/1/2010 - 9/30/10) System Health Report- 3065, Aux iliary Feedwater (1/1/2011 - 3/31/11) System Health Report- 3065, Aux iliary Feedwater (1/1/2012 - 3/31/12) System Health Report- 3065, Aux iliary Feedwater (1/1/2013 - 3/31/13) System Health Report- 4080, Component Cooling Water (1/1/2013-3/31/2013)  
: System Health Report- 4080, Component Cooling Water (1/1/2012-3/31/2012)  
: System Health Report- 4080, Component Cooling Water (1/1/2012-3/31/2012)  
: System Health Report- 4080, Component Cooling Water (1/1/2011-3/31/2011)  
: System Health Report- 4080, Component Cooling Water (1/1/2011-3/31/2011)  
Line 994: Line 1,205:
: NCR 606986, CDBI,
: NCR 606986, CDBI,
: TMM-127, 5/20/10 Diag. Evaluation for
: TMM-127, 5/20/10 Diag. Evaluation for
: RV1-3
: RV1-3  
: Work Requests
: Work Requests
: 578454,
: 578454,
Line 1,000: Line 1,211:
: 578456, Poor Housekeeping in RHR Pits "A" and "B"
: 578456, Poor Housekeeping in RHR Pits "A" and "B"


==Section 4OA5: Other Activities Corrective Action Program Documents==
==Section 4OA5: Other Activities==
: Corrective Action Program Documents
: AR 575346   
: AR 575346   
===Procedures===
===Procedures===
Line 1,008: Line 1,220:
===Calculations===
===Calculations===
: NAI-1713-001, Robinson Nuclear Plant RHR Discharge Sensitivity Study Review, Rev. 0
: NAI-1713-001, Robinson Nuclear Plant RHR Discharge Sensitivity Study Review, Rev. 0
: NAI-1713-002, Robinson Nuclear Plant RHR Heat Exchanger Air Sweep Water-Hammer Analysis, Rev. 0   
: NAI-1713-002, Robinson Nuclear Plant RHR Heat Exchanger Air Sweep Water-Hammer
: Analysis, Rev. 0   
===Drawings===
===Drawings===
: SK-RNP-ADMIN-0272, RHR Gas Intrusion Isometric  
: SK-RNP-ADMIN-0272, RHR Gas Intrusion Isometric
===Other Documents===
===Other Documents===
: EC89737, RHR Heat Exchanger Void/Venting Evaluation, Rev. 0  
: EC89737, RHR Heat Exchanger Void/Venting Evaluation, Rev. 0  
Line 1,018: Line 1,231:
: Decay Heat Removal, and Containment Spray Systems," NRC Generic Letter 2008-01,  
: Decay Heat Removal, and Containment Spray Systems," NRC Generic Letter 2008-01,  
: ML072910759.
: ML072910759.
: Andreychek, T. S. (July 1988). "Loss of RHRS Cooling While the RCS is Partially Filled,"
: Andreychek, T. S. (July 1988). "Loss of RHRS C
ooling While the RCS is Partially Filled,"
: Westinghouse Electric Corporation,
: Westinghouse Electric Corporation,
: WCAP-11916 Revision 0, ADAMS Accession No.
: WCAP-11916 Revision 0, ADAMS Accession No.
Line 1,051: Line 1,265:
: FAI/08-70, R. (September 2008.). "Gas-Voids Pressure Pulsations Program", Fauske & Associates, LLC, for the PWR Owners' Group, ML090990426.
: FAI/08-70, R. (September 2008.). "Gas-Voids Pressure Pulsations Program", Fauske & Associates, LLC, for the PWR Owners' Group, ML090990426.
: FAI/08-78. (August, 2008). "Methodology for Evaluating Waterhammer in the Containment Spray Header and Hot Leg Switchover Piping", Fauske & Associates, LLC, for the PWR  
: FAI/08-78. (August, 2008). "Methodology for Evaluating Waterhammer in the Containment Spray Header and Hot Leg Switchover Piping", Fauske & Associates, LLC, for the PWR  
: Owners' Group, ADAMS Accession No. ML090980331. .
: Owners' Group, ADAMS Accession No. ML090980331. .
: FAI/08-78, R. (August 2008.). "Methodology for Evaluating Waterhammer in the Containment Spray Header and Hot Leg Switchover Piping", Fauske & Associates, LLC, for the PWR  
: FAI/08-78, R. (August 2008.). "Methodology for Ev aluating Waterhammer in the Containment Spray Header and Hot Leg Switchover Piping", Fauske & Associates, LLC, for the PWR  
: Owners' Group, ML090980331.
: Owners' Group, ML090980331.
: FAI/09-130-P. (December, 2010.). "Technical Basis for Gas Transport to the Pump Suction," Fauske & Associates, LLC, "Technical Basis for Gas Transport to the Pump Suction," Fauske &Associates, ML110480456.
: FAI/09-130-P. (December, 2010.). "Technical Basis for Gas Transport to the Pump Suction," Fauske & Associates, LLC, "Technical Basis for Gas Transport to the Pump Suction," Fauske  
&Associates, ML110480456.
: Gall, J. (June 24, 2010.). "Meeting With The Nuclear Energy Institute (NEI) And Industry Representatives To Discuss NRC Generic Letter 2008-01, 'Managing Gas Accumulation In Emergency Core Cooling, Decay Heat Removal, And Containment Spray Systems,'" NRC
: Gall, J. (June 24, 2010.). "Meeting With The Nuclear Energy Institute (NEI) And Industry Representatives To Discuss NRC Generic Letter 2008-01, 'Managing Gas Accumulation In Emergency Core Cooling, Decay Heat Removal, And Containment Spray Systems,'" NRC
: Memorandum, ML101650201.
: Memorandum, ML101650201.
Line 1,074: Line 1,289:
: Kamath, P. S. (September, 1982.). "An Assessment of Residual Heat Removal and Containment Spray Pump Performance Under Air and Debris Ingesting Conditions," Creare, Inc., NUREG/CR-2792, ML100110155.
: Kamath, P. S. (September, 1982.). "An Assessment of Residual Heat Removal and Containment Spray Pump Performance Under Air and Debris Ingesting Conditions," Creare, Inc., NUREG/CR-2792, ML100110155.
: Kasztejna, P. (August 5, 2008). "HB Robinson Power Plant, ECCS Pumps," Letter from Flowserve Engineering.
: Kasztejna, P. (August 5, 2008). "HB Robinson Power Plant, ECCS Pumps," Letter from Flowserve Engineering.
: Kim, S. (September 1992). "A Study on the Free Surface Vortex in the Pipe System," Journal of the Korean Nuclear Society, Volume 24, number 3. (pdf may be obtained by Google search using the following: "sang-nyung kim" "wan-ho jang. .
: Kim, S. (September 1992). "A Study on the Free Su rface Vortex in the Pipe System," Journal of the Korean Nuclear Society, Volume 24, number 3. (pdf may be obtained by Google search using the following: "sang-nyung kim" "wan-ho jang. .
: Kim, S. (September 1992). "A Study on the Free Surface Vortex in the Pipe System," Journal of the Korean Nuclear Society, Volume 24, number 3. (pdf may be obtained by Google search using the following: "sang-nyung kim" "wan-ho jang.
: Kim, S. (September 1992). "A Study on the Free Su rface Vortex in the Pipe System," Journal of the Korean Nuclear Society, Volume 24, number 3. (pdf may be obtained by Google search using the following: "sang-nyung kim" "wan-ho jang.
: LTR-LIS-08-543. (April 2, 2009). "PWROG Position Paper on Non-condensable Gas Voids in ECCS Piping; Qualitative Engineering Judgment of Potential Effects on Reactor Coolant System Transients Including Chapter 15 Events, Task 3 of
: LTR-LIS-08-543. (April 2, 2009). "PWROG Position Paper on Non-condensable Gas Voids in ECCS Piping; Qualitative Engineering Judgment of Potential Effects on Reactor Coolant System Transients Including Chapter 15 Events, Task 3 of
: PA-SEE-450", Westinghouse, ML090980303.
: PA-SEE-450", Westinghouse, ML090980303.
Line 1,092: Line 1,307:
: Nesse, R. (December 4, 2012). "assistance with GOTHIC at Robinson," NRC email, ML13099A001.
: Nesse, R. (December 4, 2012). "assistance with GOTHIC at Robinson," NRC email, ML13099A001.
: NRC. (June 26, 2011). "Calculation Methodologies for Operability Determinatinos of Gas Voids in Nuclear Power Plant Piping," Information Notice 2011-17, ML11161A111.
: NRC. (June 26, 2011). "Calculation Methodologies for Operability Determinatinos of Gas Voids in Nuclear Power Plant Piping," Information Notice 2011-17, ML11161A111.
: NRC. (March, 19, 2013). "Final Safety Evaluation for Nuclear Energy Institute Topical Report
: NRC. (March, 19, 2013). "Final Safety Evaluatio
n for Nuclear Energy Institute Topical Report
: NEI 09-10, Revision 1a, 'Guidelines for Effective Prevention and Management of System Gas Accumulation, Project No. 689," ML12342A368.
: NEI 09-10, Revision 1a, 'Guidelines for Effective Prevention and Management of System Gas Accumulation, Project No. 689," ML12342A368.
: NRC. (March 12 - 14, 2013.). "NRC's 25th Annual Information Conference, North Bethesda, Md.
: NRC. (March 12 - 14, 2013.). "NRC's 25th Annual Information Conference, North Bethesda, Md.
Line 1,119: Line 1,335:
: RIS-2005-20. (September 26, 2005.). "... Revision to Guidance Formerly Contained in NRC Generic Letter 91-18, 'Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability,'"  
: RIS-2005-20. (September 26, 2005.). "... Revision to Guidance Formerly Contained in NRC Generic Letter 91-18, 'Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability,'"  
: ML052020424.
: ML052020424.
: RIS-2005-20-Rev-1. (April 16, 2008.). "... Revision to Guidance Formerly Contained in NRC Generic Letter 91-18, 'Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability,'" ML073440103.
: RIS-2005-20-Rev-1. (April 16, 2008.). "... Revision to Guidance Formerly Contained in NRC Generic Letter 91-18, 'Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability,'"  
: ML073440103.
: Robinson1. (No Date). "Engineering Change,"
: Robinson1. (No Date). "Engineering Change,"
: PCHG-DESG, 0000070450R7.
: PCHG-DESG, 0000070450R7.
Line 1,125: Line 1,342:
: PCHG-DESG, 0000070450R7, Attachment A.
: PCHG-DESG, 0000070450R7, Attachment A.
: Stringfellow, N. J. (March 29, 2012.). "Transmittal of
: Stringfellow, N. J. (March 29, 2012.). "Transmittal of
: TSTF-523, Revision 1, 'Generic Letter 2008-01, Managing Gs Accumulation,'".
: TSTF-523, Revision 1, 'Generic Letter  
: 2008-01, Managing Gs Accumulation,'".
: Stringfellow, N. J. (March 29, 2012). "Transmittal of
: Stringfellow, N. J. (March 29, 2012). "Transmittal of
: TSTF-523, Revision 1, 'Generic Letter 2008-01, Managing Gas Accumulation,'" Letter to NRC, ADAMS Accession No.
: TSTF-523, Revision 1, 'Generic Letter  
: 2008-01, Managing Gas Accumulation,'" Letter to NRC, ADAMS Accession No.
: ML12089A356. .
: ML12089A356. .
: Stringfellow, N. J. (March 29, 2012.). "Transmittal of
: Stringfellow, N. J. (March 29, 2012.). "Transmittal of
: TSTF-523, Revision 1, 'Generic Letter 2008-01, Managing Gas Accumulation,'" Letter to NRC, ML12089A356.
: TSTF-523, Revision 1, 'Generic Letter 2008-01, Managing Gas Accumulation,'" Letter to NRC, ML12089A356.
: TIA2008-03. (October 21, 2008.). "Task Interface Agreement - Emergency Core Cooling Systems (ECCS) Voiding Relative to Compliance with Surveillance Requirements (SR) 3.0.1.1, 3.5.2.3, and 3.5.3.1 (TIA 2008-03)," ML082560209.
: TIA2008-03. (October 21, 2008.). "Task Interface Agreement - Emergency Core Cooling Systems (ECCS) Voiding Relative to Compli ance with Surveillance Requirements (SR) 3.0.1.1, 3.5.2.3, and 3.5.3.1 (TIA 2008-03)," ML082560209.
: USNRC. (January 11, 2008). 1. "Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems," NRC Generic Letter 2008-01,  
: USNRC. (January 11, 2008). 1. "Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems," NRC Generic Letter 2008-01,  
: ML072910759.
: ML072910759.

Revision as of 05:41, 14 July 2018

IR 05000261-13-007; 4/8/2013 - 5/16/2013; H. B. Robinson Steam Electric Plant, Unit 2; Component Design Bases Inspection
ML13182A032
Person / Time
Site: Robinson Duke Energy icon.png
Issue date: 06/28/2013
From: Nease R L
NRC/RGN-II/DRS/EB1
To: Gideon W R
Progress Energy Co
References
IR-13-007
Download: ML13182A032 (48)
v • d • e


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION REGION II 245 PEACHTREE CENTER AVENUE NE, SUITE 1200 ATLANTA, GEORGIA 30303-1257 June 28, 2013 Mr. William Vice President

Progress Energy H. B. Robinson Steam Electric Plant, Unit 2 3581 West Entrance Rd Hartsville, SC 29550

SUBJECT: H. B. ROBINSON STEAM ELECTRIC PLANT- NRC COMPONENT DESIGN BASES INSPECTION REPORT 05000261/2013007

Dear Mr. Gideon:

On May 16, 2013, U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your H. B. Robinson Steam Electric Plant, Unit 2. The enclosed inspection report documents the inspection results, which were discussed on May 16, 2013, with you and other members of your staff. Additional inspection results were communicated on June 20, 2013, during a teleconference with you and other members of your staff, and June 27, 2013, with

Mr. Hightower.

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 team reviewed selected procedures and records, observed activities, and interviewed personnel.

Five NRC identified findings of very low safety significance (Green) were identified during this inspection.

Four of these findings were determined to involve violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the

Enforcement Policy.

If you contest the violations, or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the H. B. Robinson Steam Electric Plant.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the H. B. Robinson Steam Electric Plant. 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 available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Document Access and Managem ent System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,RA Rebecca Nease, Chief Engineering Branch 1

Division of Reactor Safety Docket No.: 05000261 License No.: DPR-23

Enclosure:

NRC Component Design Bases Inspection Report 05000261/2013007

wAttachment:

Supplemental Information

cc: (See page 3)

_________________________ x SUNSI REVIEW COMPLETE x FORM 665 ATTACHED OFFICE RII:DRS RII:DRS RII:DCI RII:DRS RII:DRS RII:DRS CONTRATOR SIGNATURE Via email Via email Via email Via email Via email NAME G. Ottenberg S. Walker J. Bartleman M. Riley P. Cooper A. Alen H. Campbell DATE 6/26/2013 6/25/2013 6/26/2013 6/28/2013 6/25/2013 6/28/2013 6/25/2013 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO OFFICE CONTRACTOR HQ:NRR HQ:NRR RII:DRS RII:DRP RII:DRS SIGNATURE Via email Via email Via email RA RA NAME G. Nicely W. Lyon C. Jackson R. Nease G. Hopper DATE 6/27/2013 6/25/2013 6/26/2013 6/28/2013 6/28/2013 E-MAIL COPY? YES NO YES NO YES NO YES NO YES NO YES NO YES NO cc: Division of Radiological Health TN Dept. of Environment & Conservation 401 Church Street Nashville, TN 37243-1532

Donald W. Barker Manager, Nuclear Oversight H. B. Robinson Steam Electric Plant, Unit 2 Progress Energy Electronic Mail Distribution

J. W. (Bill) Pitesa Senior Vice President Nuclear Operations Duke Energy Corporation Electronic Mail Distribution

Lara S. Nichols Deputy General Counsel Duke Energy Corporation Electronic Mail Distribution

M. Christopher Nolan

Director - Regulatory Affairs General Office Duke Energy Corporation Electronic Mail Distribution

Mike Glover Director Site Operations H. B. Robinson Steam Electric Plant Electronic Mail Distribution

Richard Keith Holbrook

Operations Manager H. B. Robinson Steam Electric Plant Electronic Mail Distribution

Sandra Threatt, Manager Nuclear Response and Emergency Environmental Surveillance Bureau of Land and Waste Management Department of Health and Environmental

Control Electronic Mail Distribution

Sharon Wheeler

Manager, Support Services H B Robinson Steam Electric Plant

Brian C. McCabe Manager, Nuclear Oversight Shearon Harris Nuclear Power Plant

Progress Energy Electronic Mail Distribution

Richard Hightower

Supervisor Licensing/Regulatory Programs Progress Energy Electronic Mail Distribution

Joseph W. Donahue Vice President Nuclear Oversight Progress Energy Electronic Mail Distribution

David T. Conley

Senior Counsel Legal Department Progress Energy Electronic Mail Distribution

John H. O'Neill, Jr.

Shaw, Pittman, Potts & Trowbridge 2300 N. Street, NW Washington, DC 20037-1128

Richard Haynes Director, Division of Waste Management Bureau of Land and Waste Management S.C. Department of Health and Environmental Control Electronic Mail Distribution

Thomas Cosgrove Plant General Manager H.B. Robinson Steam Electric Plant, Unit 2

Progress Energy Electronic Mail Distribution

(cc cont'd - See page 4) (cc cont'd)

Donna B. Alexander

Manager, Nuclear Regulatory Affairs (interim)

Progress Energy Electronic Mail Distribution

(cc cont'd - See page 4)

Robert P. Gruber Executive Director Public Staff - NCUC

4326 Mail Service Center

Raleigh, NC 27699-4326

W. Lee Cox, III Section Chief

Radiation Protection Section N.C. Department of Environmental

Commerce & Natural Resources Electronic Mail Distribution

Greg Kilpatrick

Operations Manager H.B. Robinson Steam Electric Plant, Unit 2

Progress Energy Electronic Mail Distribution

Mark Yeager

Division of Radioactive Waste Mgmt.

S.C. Department of Health and Environmental Control Electronic Mail Distribution

Public Service Commission

State of South Carolina P.O. Box 11649 Columbia, SC 29211

Chairman North Carolina Utilities Commission Electronic Mail Distribution Henry Curry

Training Manager H.B. Robinson Steam Electric Plant, Unit 2

Progress Energy Electronic Mail Distribution

Senior Resident Inspector U.S. Nuclear Regulatory Commission H. B. Robinson Steam Electric Plant 2112 Old Camden Rd

Hartsville, SC 29550

Christos Kamilaris

Manager, Support Services H.B. Robinson Steam Electric Plant, Unit 2 Progress Energy Electronic Mail Distribution

Enclosure U. S. NUCLEAR REGULATORY COMMISSION REGION II

Docket No.: 05000261

License No.: DPR-23

Report No.: 05000261/2013007

Licensee: Carolina Power and Light Company.

Facility: H. B. Robinson Steam Electric Plant, Unit 2

Location: 3581 West Entrance Road Hartsville, SC 29550

Dates: April 8 -

May 16, 2013

Inspectors: G. Ottenberg, Senior Reactor Inspector (Lead) S. Walker, Senior Reactor Inspector J. Bartleman, Senior Construction Inspector A. Alen, Reactor Inspector M. Riley, Reactor Inspector

P. Cooper, Reactor Inspector (Trainee)

G. Nicely, Contractor (Electrical)

H. Campbell, Contractor (Mechanical)

Approved by: Rebecca Nease, Chief Engineering Branch 1 Division of Reactor Safety

SUMMARY

IR 05000261/2013007; 4/8/2013 -

5/16/2013; H. B. Robinson Steam Electric Plant, Unit 2; Component Design Bases Inspection.

This inspection was conducted by a team of six Nuclear Regulatory Commission (NRC) inspectors from Region II, and two NRC contract personnel. Four Green non-cited violations (NCVs), and one Green finding were identified. The significance of inspection findings is indicated by their color (Green, White, Yellow, Red) using the NRC Inspection Manual Chapter (IMC) 0609, "Significance Determination Process," dated June 2, 2011. Cross cutting aspects are determined using IMC 0310, "Components Within the Cross Cutting Areas," dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRC's Enforcement Policy, dated January 28, 2013. 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.

NRC identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green.

The team identified a Green finding for the licensee's failure to follow NRC Regulatory Guide 1.155, "Station Blackout," guidance (to which they are committed in the Updated Final Safety Analysis Report) for evaluating equipment needed to cope with a station blackout for the required duration for associated environmental conditions. This was a performance deficiency. The licensee entered the issue into their corrective action program as Nuclear Condition Report 600522, and established a calculation that determined the maximum expected temperature inside the compartment housing the dedicated shutdown diesel generator (DSDG) and evaluated the equipment to determine its capability to perform its function for the station blackout coping duration.

The performance deficiency was more than minor because it affected the Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring reliability, availability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the capability and reliability of the equipment located in the DSDG compartment was not ensured since a comparison of equipment temperature ratings and expected DSDG compartment temperatures was not performed. The finding was determined to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, or component, and the structure, system, or component maintained its functionality. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the installation of the DSDG. (Section 1R21.2.13)

Green.

The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to have adequate analyses that supported safety-related load operation during a design basis accident while supplied by offsite power. This was a performance deficiency.

3 The licensee entered the issue into the corrective action program as Nuclear Condition Reports 601201 and 605969, and performed an evaluation that determined the capability of starting the safety-related motors at degraded voltage conditions, as well as the capability of the electrical loads during the degraded grid voltage relay (DGVR) time delay to ensure equipment function was preserved.

The performance deficiency was more than minor because it affected the

Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring reliability, availability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee did not ensure the capability of safety-related loads to respond to a design basis accident under degraded voltage conditions. Evaluations of the effects of starting motors at the DGVR voltage dropout setpoint and the equipment survivability during the DGVR time delay were not performed. The team determined the finding required a detailed risk analysis, because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, or component, and the team assumed the performance deficiency represented a loss of operability or functionality of the equipment that could be lost during the DGVR time delay. This assumption was made to bound the risk of the finding, because the licensee was still investigating whether or not there would be a loss of function of any equipment during the DGVR time delay period as of the date of this inspection report issuance. The team assumed a recoverable loss of function of all 480V motor control centers and assumed a degraded voltage condition exposure time of one hour per year. The one hour per year assumption is conservative relative to actual plant data which indicated a degraded voltage condition exposure of 44 seconds over the past 3 operating years. The results of the detailed risk analysis indicated an increase in core damage frequency <1E-6/year, which is representative of a finding of very low safety significance (Green). No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the degraded voltage evaluation. (Section 1R21.2.15)

Green.

The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to verify the adequacy of the plant design during fast bus transfers. Specifically, the licensee failed to have an adequate analysis that ensured a successful fast bus transfer of the safety-related E1 bus feeder from the Unit Auxiliary Transformer to the Startup Transformer when required. This was a performance deficiency. The licensee entered the issue into the corrective action program as Nuclear Condition Reports 603357 and 605562, and performed an additional fast bus transfer evaluation of the E1 feeder breaker to ensure that the breaker would not trip under fast bus transfer conditions.

The performance deficiency was more than minor because it affected the Mitigating Systems cornerstone attri bute of Design Control and adversely affected the cornerstone objective of ensuring reliability, availability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee did not ensure the capability of safety-related loads on the E1 bus because the licensee did not verify the E1 feeder breaker would not trip during a fast bus transfer. The finding was determined to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating structure, system, or component (SSC), and the SSC maintained its operability and functionality. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the fast bus transfer evaluation. (Section 1R21.2.16.1)

Green.

The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the licensee's failure to prescribe an adequate procedure that verified DGVR circuit operability following degraded voltage disable switch operation for reactor coolant pump (RCP) starts. This was a performance deficiency. The licensee entered the issue into the corrective action program as Nuclear Condition Report 602516, developed a test procedure, and verified the DGVR operability on both emergency buses.

The performance deficiency was more than minor because if left uncorrected, it could become a more significant safety concern. Specifically, by not properly testing the DGVR circuit to ensure conti nuity following switch manipulation for RCP starts, the circuit could unknowingly become inoperable and non-functional for an entire operating cycle. The finding was determined to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system function, did not represent an actual loss of function of at least a single train for greater than its technical specification (TS) allowed outage time or two separate safety systems out-of-service for greater than its TS allowed outage time, and did not represent an actual loss of function of one or more non-TS trains. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the modification that added the degraded voltage disable switches. (Section 1R21.2.16.2)

Cornerstone: Barrier Integrity

Green.

The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to account for instrument uncertainty on the containm ent bulk temperature instrumentation which was used to verify technical specification (TS) containment operability. This was a performance deficiency. The licensee entered this issue into their corrective action program as Nuclear Condition Report 603294 and performed an evaluation of the temperature instrumentation uncertainty. In addition, the licensee issued Standing Instruction 13-001 which specified the indicated containment temperature for entry into TS Limiting Condition for Operation 3.6.5 was to be 118 degrees Fahrenheit, a value that compensated for the temperature measurement uncertainty.

The performance deficiency was more than minor because if left uncorrected, it would have the potential to lead to a more significant safety concern. Specifically, if the licensee did not account for the temperature measurement accuracy, containment temperature could unknowingly exceed the TS operability limit, and the licensee may not declare containment inoperable. The finding was determined to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components and did not involve a reduction in function of hydrogen igniters in the reactor containment. The cause of the finding was indicative of current licensee performance because the licensee failed to consider instrument uncertainty when they performed a containment re-analysis in 2013. The cause of the finding was directly related to the maintaining long term plant safety by maintenance of design margins cross-cutting aspect of the resources component in the area of human performance because when the containment re-analysis was performed, the licensee reduced margin between the analyzed value for containment starting temperature and the TS limit, making the instrument uncertainty of the temperature instruments more significant. H.2(a) (Section 1R21.2.9)

=

Licensee-Identified Violations===

No findings were identified.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R21 Component Design Bases Inspection

Main article: IP 71111.21

.1 Inspection Sample Selection Process

The team selected risk-significant components and related operator actions for review using information contained in the licensee's probabilistic risk assessment. In general, this included components and operator actions that had a risk achievement worth factor greater than 1.3 or Birnbaum value greater than 1 X10

-6. The sample included 17 components, of which three were associated with containment large early release frequency (LERF), and six operating experience (OE) items.

The team performed a margin assessment and a detailed review of the selected risk-significant components and operator actions to verify that the design bases had been correctly implemented and maintained. Where possible, this margin was determined by the review of the design basis and Updated Final Safety Analysis Report (UFSAR)response times associated with operator actions. This margin assessment also considered original design issues, margin reductions due to modifications, or margin reductions identified as a result of material condition issues. Equipm ent reliability issues were also considered in the selection of components for a detailed review. These reliability issues included items related to failed performance test results, significant corrective action, repeated maintenance, maintenance rule status, Regulatory Issue Summary 05-020 (formerly Generic Letter 91-18) conditions, NRC resident inspector

input regarding problem equipment, system health reports, industry OE, and licensee problem equipment lists. Consideration was also given to the uniqueness and complexity of the design, OE, and the available defense-in-depth margins. An overall summary of the reviews performed and the specific inspection findings identified is included in the following sections of the report.

.2 Component Reviews

.2.1 Main Steam Isolation Valves [MS-V1-3A, MS-V1-3B, MS-V1-3C] (LERF)

a. Inspection Scope

The inspection team reviewed the main steam isolation valves (MSIVs), MS-V1-3A, MS-V1-3B, and MS-V1-3C, at the Robinson Nuclear Plant (RNP) to verify the valves were capable of performing their design bases function. The team reviewed the licensee's calculations of MSIV operational margin and verified important inputs into the calculations were sufficiently conservative. The team examined system health reports and records of applicable corrective action documents to determine if potential degradation was being adequately monitored and appropriate actions were taken to correct any concerns. The team also reviewed completed surveillance and verification testing documentation that had been conducted under procedures EST-134 and OST-703-1 to ensure the MSIV valves and actuators operated properly and that they could perform their safety function. The team reviewed the maintenance history of the MSIVs to examine the mechanical condition and function of the components. The team verified that maintenance was performed in accordance with vendor instructions.

b. Findings

No findings were identified.

.2.2 Steam Generator Steam Line Power Operated Relief Valves [RV1-1, RV1-2, RV1-3]

(LERF)

a. Inspection Scope

The inspection team reviewed the steam generator (SG) steam line power-operated relief valves (PORVs), RV1-1, RV1-2, and RV1-3, at RNP to verify they were capable of performing their design bases functions. The team reviewed the licensee's calculations of SG PORV operational margin and verified important inputs into the calculations were sufficiently conservative. The team examined system health reports and records of applicable corrective action documents to determine if potential degradation was being adequately monitored and appropriate actions were taken to correct any concerns. The team reviewed the maintenance history of the SG PORVs to examine the mechanical condition and function of the components. The team verified that maintenance was performed in accordance with vendor instructions.

b. Findings

No findings were identified.

.2.3 Steam Generator Steam Supply Valves to Steam Driven Auxiliary Feedwater Pump

[MS-V1-8A, MS-V1-8B, MS-V1-8C]

a. Inspection Scope

The inspection team reviewed the steam driven auxiliary feedwater pump (SDAFP) steam supply motor-operated valves (MOVs), MS-V1-8A, MS-V1-8B, and MS-V1-8C, to verify these valves were capable of performing their design bases functions. The team reviewed the licensee's calculations of operational margin and verified important inputs into the calculations were sufficiently conservative. The team also verified that the infield diagnostic testing and setup of torque and limit switch settings for the valve actuators were within the setup windows assumed in design margin calculations, and verified that test equipment accuracies were considered.

The team reviewed the maintenance history of the valves and actuators, and engineering trending reports to examine mechanical condition and function of the components. The team verified that maintenance was performed in accordance with vendor instructions. The team reviewed the calculations that determined the degraded voltage at the MOV terminals, to ensure the proper voltage was utilized in calculating available motor output torque when determining margin. The team reviewed the calculations that establish control circuit voltage drop, short circuit, and protection/coordination including thermal overload sizing and application. Additionally motor control center (MCC) thermal overload testing programs were reviewed.

The team reviewed the licensee's initial evaluation and response to the 10 CFR Part 21 notification issued from Flowserve to the NRC, dated February 25, 2013, for a wedge pin failure of an Anchor/Darling Double Disk Ga te Valve (AD-DDGV) at Browns Ferry Nuclear Plant Unit 1. The team reviewed the licensee's operability determination evaluation performed for the 41 safety-related AD-DDGVs used at RNP. This operability determination was completed under Nuclear Condition Report (NCR) 592717 to address the wedge pin failure outlined in this Part 21 notification. The licensee performed a Quick Cause Evaluation (QCE) Report, Form CAP-NGGC-0205-3-16, as required by the

corrective actions identified in NCR 592717.

This QCE described the analysis and immediate actions taken by the licensee to evaluate the wedge pin failure of an AD-DDGV. The team verified that the corrective actions outlined in the QCE, if implemented correctly, should adequately address this issue.

The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team conducted a walkdown of a limiting safe shutdown procedure to assess if the time critical operator actions required to control the SDAFP during a Station Blackout (SBO) could be successfully accomp lished. Equipment necessary to perform procedural steps was verified to be in the correct locations and available to the operators. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises for this evolution to identify any past operator failures or challenges to accomplish this activity.

b. Findings

No findings were identified.

.2.4 Refueling Water Storage Tank (RWST) Discharge Valves [SI-864A, SI-864B]

a. Inspection Scope

The inspection team reviewed the RWST discharge MOVs, SI-864A and SI-864B, to verify they were capable of performing their design bases functions. The team reviewed the licensee's calculations of operational margin and verified important inputs into the calculations were sufficiently conservative. The team also verified that the infield diagnostic testing, and setup of torque and limit switch settings for the valve actuators were within the setup window assumed in design margin calculations, and verified that test equipment accuracies were considered.

The team reviewed the maintenance history of the valves and actuators, and engineering trending reports to examine mechanical condition and function of the components. The team verified that maintenance was performed in accordance with vendor instructions. The team reviewed the calculations that determined the degraded voltage at the MOV terminals, to ensure the proper voltage was utilized in calculating available motor output torque when determining margin. The team reviewed the calculations that establish control circuit voltage drop, short circuit, and protection/coordination including thermal overload sizing and application. Additionally, MCC thermal overload testing programs were reviewed. The team also reviewed the licensee's actions in response to the same 10 CFR Part 21 notification issued by Flowserve, dated February 25, 2013, as discussed above in section 1R21.2.3 as the actions were applicable to the SI-864A and SI-864B valves.

b. Findings

No findings were identified.

.2.5 Excess Letdown Heat Exchanger Relief Valve [CC-715]

a. Inspection Scope

The team reviewed the Component Cooling Water (CCW) design bases documents (DBDs), UFSAR, Technical Specifications (TS), and applicable plant drawings to identify the design bases requirements of the equipment. The team examined the corrective actions and maintenance history of the CCW Relief Valve, CC-715, to verify that design bases had been maintained. The team examined records and test data for corrective maintenance and engineering evaluations to verify potential degradation was being monitored, prevented, corrected, and/or justified. The team verified that the maintenance, testing, and inspections were being conducted in accordance with vendor recommendations and ASME code requirements. Lastly, the inspectors reviewed procedures for CC-715 for actions taken to mitigate the event scenario where the valve spuriously opened and failed to close.

b. Findings

No findings were identified.

.2.6 Residual Heat Removal (RHR) Pumps [RHR-PMP-A, RHR-PMP-B]

a. Inspection Scope

The team reviewed design basis documentation including original design specifications, the RHR and Safety Injection DBDs, portions of the UFSAR, and TS to identify the safety-related and functional requirements of the RHR pumps A and B. The RHR system engineer was interviewed to discuss current pump concerns and margin to design requirements. Further, a field walkdown with the system engineer was undertaken to evaluate the material condition and assess the pump's operating environment. Hydraulic calculations were reviewed to evaluate pump vortex and NPSH concerns, in addition to in-service test (IST) instrument uncertainty evaluations. Several years of IST surveillances, both Quarterly and Comprehensive, were reviewed to assess the capability of the pumps to perform their safety-related functions, as well as to evaluate potential long-term pump degradation. The licensee's evaluation of NRC Information Notice (IN) 97-90 and NRC Bulletin 88-04 were reviewed. As part of this OE review, the testing of the RHR system piping modification (1087, RHR Pumps Minimum Flow Recirculation Lines) was reviewed to ensure compliance with the concerns raised in Bulletin 88-04. The team reviewed calculations that establish voltage drop, protection and coordination, motor horsepower requirements, and short circuit for the motor power supply and feeder cable to verify that design bases and design assumptions have been appropriately translated into design calculations.

The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises to identify any past operator failures or challenges to accomplish this activity.

b. Findings

No findings were identified.

.2.7 High Head Safety Injection Pumps [SI-PMP-A, SI-PMP-B, SI-PMP-C]

a. Inspection Scope

The team reviewed design basis documentation including original design specifications, the Safety Injection system DBD, portions of the UFSAR, and TS to identify the safety-related and functional requirements of the high head safety injection pumps A, B and C.

The team performed a walkdown of the pumps to assess the current material condition of the pumps and assess the pump's operating environment. Several years of IST surveillances, both Quarterly and Comprehensive, were reviewed to assess the capability of the pumps to perform their safety-related functions, as well as to evaluate

potential long-term pump degradation. The licensee's evaluation of NRC IN 97-90 and NRC Bulletin 88-04 were reviewed. As part of this OE review, the team reviewed original and current pump vendor documents to ensure that the concerns identified in Bulletin 88-04, (i.e., minimum recirculation flow), were adequately addressed. The team reviewed calculations that establish voltage drop, protection and coordination, motor horsepower requirements, and short circuit for the motor power supply and feeder cable to verify that design bases and design assumptions have been appropriately translated into design calculations.

b. Findings

No findings were identified.

.2.8 Containment Pressure Relief and Containment Vessel Post Accident Hydrogen Vent

Isolation Valves [V12-10, V12-11] (LERF)

a. Inspection Scope

The team reviewed design basis documentation including original design specifications, the Generic Issue Document for Reactor Containment Isolation, TS, and portions of the UFSAR to identify the functional requirements of the containment pressure relief valves, V12-10 and V12-11. Further, the team reviewed system layout/piping diagrams, interviewed the system engineer, and performed a detailed walkdown of the accessible valve (exterior to containment) to assess the layout and current condition of V12-10.

The Appendix J calculation which evaluated and listed allowed and historical leakage rates for the valves was reviewed to ensure that the valve capabilities were consistent with functional requirements. Finally, work orders and IST stroke time and indication results over several years were reviewed to ensure that the valves were being maintained and operated satisfactorily.

b. Findings

No findings were identified.

.2.9 Containment Instrumentation

a. Inspection Scope

The team reviewed design basis documentation including portions of the UFSAR, DBD, TS, and related calculations to identify the safety-related and functional requirements of the containment instrumentation. Specific instruments included for review were those monitoring containment water level, pressure, and temperature. The team reviewed instrument uncertainty calculations for containment pressure and level instrumentation to ensure that acceptable instrumentation was being used to monitor the associated containment process parameters. The team reviewed work orders to verify that calibration checks of the containment temperature thermocouples were completed. The team reviewed condition reports and one operability evaluation addressing containment analyses. The team reviewed analyses evaluating the method used to determine the average bulk containment temperature, in addition to recent and historical containment bulk temperature data, to ensure that the TS limit had not been exceeded. Finally, the team reviewed system health reports to assess the current state and operability of the

containment instrumentation.

b. Findings

Introduction:

The team identified a Green non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to account for

instrument uncertainty on containment bulk temperature instrumentation which was used to determine TS containment operability. This was a performance deficiency.

Description:

In February 2013, the licensee identified errors in inputs to the original containment analysis (main steam line break and loss of coolant accident). The licensee performed a re-analysis of these design basis accidents and performed an operability determination. The analysis supporting the operability determination decreased the assumed accident initial containment temperature from 130 degrees F to 120 degrees F. The TS upper limit for containment temperature was 120 degrees F; therefore, following the containment re-analysis, there was no margin between the analyzed and TS allowed temperature limit. The station procedure guiding operations during hot weather conditions, PLP-118, did not instruct operators to declare containment inoperable at any indicated temperature below the TS required 120 degrees F. The team reviewed work orders that performed calibration checks on the containment thermocouples and found that no acceptance criteria were provided for the allowed tolerance between the temperature obtained by the test equipment standard and the actual containment instrumentation.

Based on the above, the team concluded that the licensee did not have adequate controls in place to ensure that containment would be declared inoperable at an actual bulk average containment temperature of 120 degrees F since neither the instrument used to perform the surveillance nor station procedures accounted for instrument uncertainty. Upon identification by the team, the licensee entered this issue into their corrective action program as NCRs 603294 and 606607. At the time of the inspection, the local ambient temperature and containment bulk temperature were significantly below the TS limit, thus no immediate operability concern was present. As an interim measure, the licensee performed an evaluation of the temperature instrumentation uncertainty, and issued Standing Instruction 13-001, which specified that the indicated containment temperature for entry into TS limiting condition for operation (LCO) 3.6.5 was to be 118 degrees F, a value that compensated for the temperature measurement

uncertainty.

Analysis:

The failure to account for instrument uncertainty on the containment bulk average temperature instrumentation, used to verify TS containment operability, was a performance deficiency. The performance deficiency was more than minor because if left uncorrected, it would have the potential to lead to a more significant safety concern.

Specifically, the licensee did not account for the temperature measurement accuracy, containment temperature could exceed the TS operability limit. The team used IMC 0609, Att. 4, "Initial Characterization of Findings," issued 6/19/12, for Barrier Integrity Cornerstone, and IMC 0609, App. A, "The Significance Determination Process (SDP) for Findings At-Power," issued 6/19/12, and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components and did not involve a reduction in function of hydrogen igniters in the reactor containment. The team determined that the cause of the finding was indicative of current licensee performance because the licensee failed to consider instrument uncertainty when they performed a containment re-analysis in 2013. The cause of the finding was directly related to the maintaining long term plant safety by maintenance of design margins cross-cutting aspect of the resources component in the area of human performance because when the containment re-analysis was performed, the licensee

reduced margin between the analyzed value for containment starting temperature and the TS limit, making the instrument uncertainty of the temperature instruments more significant. H.2(a)

Enforcement:

Appendix B of 10 CFR Part 50, Criterion III, "Design Control," required, in part, that design control measures shall be established to assure that applicable regulatory requirements and the design basis are correctly translated into procedures.

Contrary to the above, from early 2013 w hen the containment re-analysis was performed until the inspectors identified the issue, the licensee did not assure that the appropriate TS limit for containment temperature and the results of the their containment re-analysis were correctly translated into procedures for determining containment operability. This resulted in the potential to exceed the TS limit and not declare containment inoperable.

As a result, the licensee issued a standing instruction to operators to ensure the TS limit would not be exceeded and re-performed the containment analysis to regain margin between the analyzed value for containment starting temperature and the TS limit. This violation is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensee's corrective action program as NCR 603294. (NCV 05000261/2013007-01, Failure to Account for Containment Temperature Measurement Uncertainty)

.2.10 125V Direct Current (DC) Motor Control Center (MCC) "A" [MCC-A]

a. Inspection Scope

The team reviewed the battery profile and 125V DC voltage drop calculation to verify that the MCC had sufficient capacity to supply its loads under design basis events. The team also reviewed the protective device coordination between the 125V DC loads to verify that the protection scheme would isolate faults associated with the MCC and ensure availability of other safety-related components needed to respond in a design basis accident. The team reviewed system health reports, corrective action documents, and maintenance records to determine whether there were any adverse operating trends. The team performed a walkdown of the 125V DC safety buses to assess operability and condition. In addition, the team performed a non-intrusive visual inspection of the MCC to verify that it showed no signs of material degradation and vulnerability to hazards such as flooding, seismic interactions, and missiles.

The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises to identify any past operator failures or challenges to accomplish this activity.

b. Findings

No findings were identified.

.2.11 125V DC Distribution Panel "A" [Distribution Panel-A]

a. Inspection Scope

The team reviewed the plant's TS, UFSAR, system descriptions, and electrical drawings to establish an overall understanding of the licensee's 125V DC distribution system. The team reviewed DC voltage drop calculations and testing procedures to verify that Distribution Panel A was capable of supplying, and maintaining in an operable status, the required emergency loads. The team re viewed system health reports, corrective action documents, and maintenance records to determine whether there were any

adverse operating trends. The team perfo rmed a walkdown of the 125V DC safety buses to assess operability and condition. The team also conducted interviews with responsible licensee personnel to answer questions that arose during the inspection pertaining to the control voltage at the 480V emergency buses.

The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team conducted a walkdown of a limiting safe shutdown procedure to assess if the time critical operator actions required to use the spare battery charger could be successfully accomplished. Equipment necessary to perform procedural steps was verified to be in the correct locations and available to the operators. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises for this evolution to identify any past operator failures or challenges to accomplish this activity.

b. Findings

No findings were identified.

.2.12 7.5 kVA Inverters "A" and "B"

a. Inspection Scope

The team reviewed the plant's TS, UFSAR, system descriptions, and electrical drawings to establish an overall understanding of the licensee's 120 VAC distribution system, which receives power from the 7.5kVA inverters. The team reviewed voltage drop calculations and testing procedures to verify that the inverters were capable of supplying, and maintaining in an operable status, the required emergency loads. The team reviewed system health reports, corrective action documents, and maintenance records to determine whether there were any adverse operating trends. The team performed a non-intrusive visual inspection of the inverters to verify that the inverters showed no signs of material degradation and that the inverters were operating within their required operating parameters for voltage and frequency.

b. Findings

No findings were identified.

.2.13 Dedicated Shutdown (DS) Diesel Bus [DS Bus]

a. Inspection Scope

The team inspected the DS Bus to verify its operational support role during Station Blackout (SBO) and Appendix R fire events. The team reviewed selected calculations for electrical distribution system load flow/voltage drop, short-circuit, and electrical protection and coordination. The adequacy and appropriateness of design assumptions and calculations were reviewed to verify that bus and circuit breaker capacity were not exceeded and bus voltages remained above minimum acceptable operating values. The protective device settings and breaker ratings were reviewed to ensure that selective coordination was adequate for protection of connected equipment during worst case short-circuit conditions. The team reviewed vendor manuals, preventive maintenance inspection and testing procedures to verify that breakers were maintained in accordance with industry and vendor recommendations. System health reports, component maintenance history and licensee corrective action program reports were reviewed to verify correction of potential degradation and deficiencies were appropriately identified and resolved. Finally, the team performed a visual non-intrusive inspection of observable portions of the DS bus and associated DS diesel generator (DSDG) to assess the installation configuration, material condition, and the potential vulnerability to hazards.

The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team conducted a walkdown of a limiting safe shutdown procedure to assess if the time critical operator actions required to establish service water using the DS system could be successfully accomplished. Equipment necessary to perform procedural steps was verified to be in the correct locations and available to the operators. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises for this evolution to identify any past operator failures or challenges to accomplish this activity.

b. Findings

Introduction:

The team identified a Green finding for the licensee's failure to follow NRC Regulatory Guide (RG) 1.155, "Station Blackout," guidance (to which they are committed in the UFSAR) for evaluating equipment needed to cope with a station blackout for the required duration for associated environmental conditions. This was a performance deficiency.

Description:

The DSDG is used for SBO mitigation and as part of the station's dedicated shutdown capability for 10 CFR 50, Appendix R fire mitigation. During a walkdown of the DSDG, the team questioned the temperature ratings of the equipment located in the DSDG compartment. This included equipment, such as the DSDG as well as necessary support loads and their corresponding MCC located in the room. The team determined, per Section 1.8 of the station's Updated Final Safety Analyses Report (UFSAR), that the licensee was committed to following the guidance in RG 1.155. Section 3.2.4 of RG 1.155, states in part, that the design adequacy and capability of equipment needed to cope with a SBO for the required duration and recovery period should be addressed and evaluated as appropriate for the associated environmental conditions. Upon investigation, it was discovered that the licensee had not performed a calculation that determined the maximum expected temperatures inside the compartment housing the DSDG and its associated support equipment. Furthermore, the licensee had not established that the equipment ratings were adequate to withstand the expected environmental ambient temperatures. Rather, the licensee was relying on a specification that was provided to the DSDG supplier. The team noted that the continuous duty ambient temperature ratings (104 degrees F) of some of the equipment were lower than the maximum outdoor ambient temperature (107 degrees F) the licensee expected to experience. Ventilation is supplied by fresh outdoor air which is circulated through the room. After identification by the team, the licensee performed a calculation that determined the maximum expected temperature inside the compartment housing the DSDG and evaluated the equipment to determine its capability to perform its function for the SBO coping duration. The licensee determined that when the DSDG is operating, the temperature in the compartment could be as high as 120 degrees F and that the DSDG and supporting equipment would be able to perform their functions for the

SBO coping duration. The licensee generated NCR 600522 to address the issue.

Analysis:

The licensee's failure to follow NRC RG 1.155, "Station Blackout," guidance (to which they are committed to in the UFSAR) for evaluating equipment needed to cope with a station blackout for the required duration for associated environmental conditions was a performance deficiency. The performance deficiency was more than minor because it affected the Mitigating System s cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring reliability, availability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the capability and reliability of the equipment located in the DSDG compartment was not ensured since a comparison of equipment temperature ratings and expected DSDG compartment temperatures was not performed.

The team used IMC 0609, Att. 4, "Initial Characterization of Findings," issued 6/19/12, for Mitigating Systems, and IMC 0609, App. A, "The Significance Determination Process (SDP) for Findings At-Power," issued 6/19/12, and determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating SSC, and the SSC maintained its functionality. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance because the performance deficiency existed since initial installation of the DSDG.

Enforcement:

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. Because this finding does not involve a violation and is of very low safety significance, it is identified as FIN 05000261/2013007-02, Failure to Evaluate SBO Coping Equipment for Environmental Conditions.

.2.14 4KV Bus "3" [Bus 3]

a. Inspection Scope

The team inspected the 4kV Bus 3 to verify its operational support role during design basis events. System health reports, component maintenance history and licensee corrective action program reports were reviewed to verify that potential degradation was

monitored or prevented. The team review ed selected calculations for electrical distribution system load flow/voltage drop, short-circuit, and electrical protection and coordination. This review was conducted to assess the adequacy and appropriateness of design assumptions, and to verify that bus capacity was not exceeded and bus voltages remained above minimum acceptable values to support transmission of power to downstream safety-related 480V Emergency Bus E2. Additionally, the switchgear's protective device settings and breaker ratings were reviewed to ensure that selective coordination was adequate for protection of connected equipment during worst case, short-circuit conditions to ensure continui ty of power to downstream safety-related buses. To determine if breakers were maintained in accordance with industry and vendor recommendations, the team reviewed the preventive maintenance inspection and testing procedures. The team reviewed the loss of voltage protection scheme. Finally, the team performed a visual non-intrusive inspection of 4kV Bus 3 to assess the installation configuration, material condition, and potential vulnerability to hazards.

b. Findings

No findings were identified.

.2.15 480V Motor Control Centers "5" and "6" [MCC-5 and MCC-6]

a. Inspection Scope

The team reviewed selected calculations for electrical distribution system load flow/voltage drop, short-circuit, and electrical protection and coordination. The adequacy and appropriateness of design assumptions and calculations were reviewed to verify that bus and circuit breaker capacity was not exceeded and bus voltages remained above minimum acceptable values under design basis conditions. The MCC's protective device settings and breaker ratings were reviewed to ensure that selective coordination was adequate for protection of connected equipment during worst case short-circuit conditions. To ensure that breakers were maintained in accordance with industry and vendor recommendations, the team reviewed the vendor manuals, preventive maintenance inspection and testing procedures. System health reports, component maintenance history and licensee corrective action program reports were reviewed to verify correction of potential degradation, and to verify that deficiencies were appropriately identified and resolved. Finally, the team performed a visual non-intrusive inspection of observable portions of the safety related 480V AC MCC 5 and 6 to assess the installation configuration, material condition, and the potential vulnerability to hazards.

The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises to identify any past operator failures or challenges to accomplish this activity.

b. Findings

Introduction:

The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the failure to have adequate analyses that supported safety-related load operation during a design basis accident while supplied by offsite power. This was a performance deficiency.

Description:

The team identified two examples of deficiencies in electrical calculation RNP-E-8.002, "AC Auxiliary Electrical Distribution System Voltage/Load Flow/Fault Current Study," that contributed to the failure of the licensee to: 1) verify and assure adequate starting voltages to safety-related loads with offsite power available, and 2)ensure load survivability by properly analyzing the operation of protective devices to safety-related loads during a design basis event under degraded voltage conditions for the duration of the degraded grid voltage relay (DGVR) time delay and subsequent re-sequencing onto the emergency diesel generators (EDGs). The following examples contributed to the identified performance deficiency:

1. The licensee did not calculate voltages at the terminals of all safety-related equipment on the DGVR monitored bus while the bus is connected to offsite power and at the DGVR voltage dropout setting (less tolerances) to ensure adequate starting voltages during design basis accidents. TS 3.3.5 allows a voltage setpoint for the DGVRs of 430V +/-4V. The appropriateness of the setpoint was not

adequately verified by design calculation RNP-E-8.002, because it failed to verify that required Class 1E motors would have adequate motor starting voltages with 480V Buses E1 and E2 at the DGVR dropout setting.

The licensee performed additional analyses and determined that the affected equipment would have adequate starting voltages.

2. If the voltage on the E1/E2 buses drops below the DGVR voltage dropout setting, a timer is initiated that results in disconnection of the bus from offsite power after the timer "times out" and the loads are subsequently re-sequenced onto the EDG. During the time delay period, loads that were running may become stalled or motors that have received a start signal that do not have adequate voltages to accelerate may continue in a stall condition. Both of these conditions may result in tripping of the protective devices which would prevent the associated load from re-sequencing onto the EDG. TS 3.3.5 allows a time delay setpoint for the DGVRs of 10 seconds

+/- 0.5, to allow some time for offsite power voltage to recover to avoid unnecessarily swapping power source to the EDG. The setpoint was not properly verified by design calculation RNP-E-8.002, because it failed to ensure the protective devices for the Class 1E loads would not trip during a design basis event concurrent with a degraded voltage at the E1 and E2 buses below the DGVR setting but above the Loss of Voltage setting for the duration of the DGVR time delay and subsequent re-sequencing onto the EDG. Additionally, the calculation did not evaluate control power circuits and their fuses for motors that are actuated during the design basis event to ensure that the fuses would not actuate if the control circuit starter stays in an inrush condition for the 10 seconds of the DGVR. The licensee initiated corrective actions to evaluate the ability of the equipment to withstand the specified time delay, which was ongoing as of June 28, 2013.

Analysis:

The licensee's failure to have adequate analyses that supported safety-related load operation during a design basis accident while supplied by offsite power was a performance deficiency. The performance deficiency was more than minor because it affected the Mitigating Systems cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring reliability, availability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee did not ensure the capability of safety-related loads to respond to a design basis accident under degraded voltage conditions because evaluations of the effects of starting motors at the DGVR voltage dropout setpoint and the equipment survivability during the DGVR time delay were not performed. The team used IMC 0609, Att. 4, "Initial Characterization of Findings," issued 6/19/12, for Mitigating Systems, and IMC 0609, App. A, "The Significance Determination Process (SDP) for Findings At-Power," issued 6/19/12, and determined the finding required a detailed risk analysis, because the finding was a deficiency affecting the design or qualification of a mitigating SSC, and the team assumed the performance deficiency represented a loss of operability or functionality of the equipment that could be lost during the DGVR time delay. This assumption was made to bound the risk of the finding, since the licensee was still investigating whether or not there would be a loss of function of any equipment during the DGVR time delay period as of the date of this inspection report issuance. A detailed risk evaluation was performed by a Regional SRA in accordance with the guidance of NRC Inspection Manual Chapter 0609 Appendix A. A bounding analysis was performed using the latest NRC H.B. Robinson SPAR model.

The major analysis assumptions included: a one hour exposure period, a loss of all 480V MCCs, and nominal manual recovery as surrogate for motor operated valves which could trip on thermal overload during the DGVR interval. The risk was mitigated by the short exposure period and the availability of alternate equipment and the recovery action. The analysis result was an increase in delta CDF <1E-6/year, a GREEN finding of very low safety significance. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the degraded voltage evaluation.

Enforcement:

Appendix B of 10 CFR Part 50, Criterion III, "Design Control," required, in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.

Contrary to the above, since 1995 when the licensee modified the DGVR design, until 2013 when the inspectors identified the issue, the licensee did not properly verify the adequacy of the DGVR design with respect to motor starting adequacy at the DVR voltage setpoint and load survivability during the DGVR time delay setpoint duration. This resulted in the potential for loss or unavailability of essential loads during a design basis event. When the issue was identified, the licensee performed an evaluation for both starting the motors as well as load survivability during the time delay. This violation is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensee's corrective action program as NCRs 601201 and 605969. (NCV 05000261/20130007-03, Failure to Have Adequate Analyses Supporting

the Degraded Voltage Relay Setpoints)

.2.16 480V Buses E1 and E2 Load Shed Circuitry

a. Inspection Scope

The team inspected the 480V Emergency Buses E1 and E2 load shed circuitry to verify its operational support role during design basis events. System health reports, drawings, component maintenance history and licensee corrective action program reports were reviewed to verify that potential degradation was monitored or prevented. The logic and operation of the load-shed circuitry as described in the UFSAR and design documents were also reviewed.

The team reviewed safe shutdown procedures, emergency operating instructions, abnormal operating instructions, and operator training material to verify that low margin time critical operator actions could be accomplished as relied upon in design assumptions. The team interviewed individuals qualified to the task to ensure training was sufficient to accomplish the task. The team also reviewed the past results of exercises to identify any past operator failures or challenges to accomplish this activity.

b. Findings

.1 Inadequate Fast Bus Transfer Evaluation

Introduction:

The team identified a Green non-cited violation of 10 CFR 50, Appendix B, Criterion III, "Design Control," for the licensee's failure to verify the adequacy of the plant design during fast bus transfers. Specifically, the licensee failed to have an adequate analysis that ensured a successful fast bus transfer of the safety-related E1 bus feeder

from the Unit Auxiliary Transformer to the Startup Transformer when required. This was a performance deficiency.

Description:

Calculation RNP-E-7.016, Bus Transfer Study, provided an analysis for the 480V emergency bus E1 transfer from the UAT, supplied by the unit main generator output, to the SUT, supplied from offsite power, following a reactor/unit trip. This calculation determined that the E1 Bus main feeder breaker (52/18B) may experience as much as 14,200 amps during the bus transfer. Another calculation, RNP-E-2.010, Overcurrent Protection Emergency Bus E1 & E2, determined the setting and adequacy for the supply breaker for Emergency Bus E1. RNP-E-2.010 recommended a breaker (52/18B) short time pick-up setting of 16000 amps +/- 10%. At this setting, the breaker could trip at a current as low as 14,400 amps for a duration of approximately 380 msec. Calculation RNP-E-2.010 incorrectly determined that the maximum current the breaker could experience was 7,109 amps, based on a fully loaded E1 bus with the concurrent starting of other non-running safety related motors (i.e., the scenario assumed was less limiting than what was determined by the Bus Transfer Study). With conservatism for inrush currents added to bound the calculation, the calculation resulted in a margin of 5,200 amps between the breaker trip setpoint and the maximum current potentially experienced at the breaker. This as-calculated margin was incorrectly determined since calculation RNP-E-2.010 did not reference the Bus Transfer Study (RNP-E-7.016) or evaluate the inrush currents (approximately 14,200 amps) through breaker 52/18B during the fast bus transfer. The Bus Transfer Study calculation indicated the inrush currents quickly reduce within cycles, therefore it is likely that the protective device would not actuate due to its time delay setting of 380 msec. However, the team noted the Bus Transfer Study could potentially be non-conservative because the calculation had not been updated following several plant modifications, such as replacement of the UAT and Main Bank Transformers. Other potential non-conservatisms included operation at offsite power voltages less than nominal assumed, and the assumptions that had to be made for the loads in the 480V system when vendor motor/load torque curves were not available. Additionally, based on PM-402, "Inspection and Testing of CB for 480V Bus E1," the as-left setting for the short time pick-up could be as low as 14,400 amps in which the operation could be as low as 12,960 amps, which is less than the calculated inrush current of 14,200 amps. This could result in the feeder breaker tripping if the inrush current does not reduce as quickly as the Bus Transfer Study predicted. The licensee entered this issue into their corrective action program as NCRs 603357 and 605562 and performed an additional fast bus transfer evaluation of the E1 feeder breaker to verify that the breaker would not trip during a fast bus transfer.

Analysis:

The licensee's failure to have an adequate analysis that ensured a successful fast bus transfer of the safety related E1 bus from the UAT to the SUT would occur when required was a performance deficiency. The performance deficiency was more than minor because it affected the Mitigating Systems cornerstone attribute of Design Control and adversely affected the cornerstone objective of ensuring reliability, availability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee did not ensure the capability of safety-related loads on the E1 bus because the licensee did not verify the E1 feeder breaker would not trip during a fast bus transfer. The team used IMC 0609, Att. 4, "Initial Characterization of Findings," issued 6/19/12, for Mitigating Systems, and IMC 0609, App. A, "The Significance Determination Process (SDP) for Findings At-Power," issued 6/19/12, and determined the finding to be of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating SSC, and the SSC maintained its operability and functionality. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the fast bus transfer evaluation.

Enforcement:

Appendix B of 10 CFR Part 50, Criterion III, "Design Control," required in part that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Contrary to the above, from 1992 when the fast bus transfer evaluation was performed until 2013 when the inspectors identified the issue, the licensee did not verify the adequacy of the plant design for the E1 fast bus transfer. Specifically, the licensee did not verify the E1 bus feeder breaker would not trip due to high inrush currents resulting from the fast bus transfer from the UAT to the SUT. This resulted in the licensee not having a calculational basis for plant electrical system modifications. The licensee took immediate corrective actions to perform an additional fast bus transfer evaluation of the E1 feeder breaker. This violation is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensee's corrective action program as NCRs 603357 and 605562. (NCV 05000261/2013007-04, Failure to Have Adequate Analyses For the E1 Bus Fast Transfer)

.2 Inadequate Circuit Verification Following Degraded Voltage Disable Switch Operation

Introduction:

The team identified a Green NCV of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the licensee's failure to prescribe an adequate procedure that verified DGVR circuit operability following degraded voltage disable switch operation for reactor coolant pump (RCP) starts. This was a performance deficiency.

Description:

The H. B. Robinson Steam Electric Plant utilizes degraded voltage disable switches during RCP starts in order to prevent the resulting momentary voltage drops that occur on the safety-related 480V emergency buses E1 and E2 from actuating the degraded voltage relays. Actuation of these relays would cause the safety-related loads to be removed from the E1 and E2 buses, an automatic EDG start, and a subsequent re-sequencing of the loads back on to the buses after they are connected to the EDG source. The RCP starting operations are performed as part of a normal plant startup following refueling outages. The degraded voltage disable switches are placed into the disable position prior to RCP start per OP-101, "Reactor Coolant System and Reactor Coolant Pump Startup and Operation," and then returned to the normal (non-disabled)position following a successful start of the RCP. This was an activity affecting quality. The team determined that this procedure was not adequate to determine that the DGVR circuit had been restored to an operable and functional condition following the switch manipulation. Specifically, neither an operability test of the circuit was performed after the switch was returned to the normal position, nor was the circuit directly monitored by either an annunciator or other method to determine the relay had been successfully placed back into the circuit. The team noted that the licensee performed a circuit operability check following manipulation of the disable switch for DGVR testing performed during outages, however, the switch manipulation for RCP starting occurred after the circuit operability check was performed, and no subsequent test of the switch or relay circuit prior to reactor operation was performed.

Analysis:

The licensee's failure to prescribe a procedure with appropriate acceptance criteria to verify DGVR circuit operability following degraded voltage disable switch operation for RCP starts was a performance deficiency. The performance deficiency was more than minor because if left uncorrected, it could become a more significant safety concern. Specifically, by not properly testing the DGVR circuit to ensure continuity following switch manipulation for RCP starts, the circuit could unknowingly become inoperable and non-functional for an entire operating cycle. The team used IMC 0609, Att. 4, "Initial Characterization of Findings," issued 6/19/12, for the Mitigating Systems Cornerstone, and IMC 0609, App. A, "The Significance Determination Process (SDP) for Findings At-Power," issued 6/19/12, and determined the finding to be of very low safety significance (Green) because the finding was not a design or qualification deficiency, did not represent a loss of system function, did not represent an actual loss of function of at least a single train for greater than its TS allowed outage time or two separate safety systems out-of-service for greater than its TS allowed outage time, and did not represent an actual loss of function of one or more non-TS trains. No cross-cutting aspect was assigned to this finding because the team determined that the cause of the finding was not indicative of current licensee performance due to the age of the modification that added the degraded voltage disable switches.

Enforcement:

Appendix B of 10 CFR Part 50, Criterion V, "Instructions, Procedures, and Drawings," requires in part that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances, and that the procedures shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to the above, from 1982 when the degraded voltage defeat switches were installed and utilized for RCP starts, until 2013 when the inspectors identified the issue, the licensee did not prescribe a procedure with appropriate acceptance criteria to determine that degraded voltage disable switch manipulation for RCP starts did not adversely affect the proper functioning of the degraded grid voltage relays. This resulted in the potential to operate an entire operating cycle with the DGVR circuit inoperable due to a failed switch contact. When the issue was identified, the licensee developed a test procedure and verified the DGVR operability on both emergency buses. This violation is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensee's corrective action program as NCR 602516. (NCV 05000261/2013007-05, Failure to Have Appropriate Procedure to Verify Degraded Voltage Relay Circuit Status)

.3 (Opened) Unresolved Item (URI):

Questions Regarding License Basis Design Requirements for Degraded Voltage Relays

Introduction:

The team identified an unresolved item (URI) regarding the degraded voltage relays. Specifically, the effect of system and transient harmonics on proper operation of degraded voltage relays was not analyzed.

Description:

The Robinson degraded voltage protection design features three ITE Type 27N relays for each 480V emergency bus E1 and E2, arranged in a two out of three tripping scheme. BBC Instruction Bulletin 7.4.1.7-7 states, the relay employs a peak voltage detector, and harmonic distortion on the AC waveform can have a noticeable effect on the relay operating point and the measuring instruments used to calibrate the relay. The bulletin also notes that the relay is available with an internal harmonic filter for applications where waveform distortion is a factor; however, harmonic filters are not installed on the degraded grid voltage relays based upon their model number and specification package. The inspectors questioned if persistent harmonics on the 480V system could cause the relays to fail to actuate at the set point specified in Technical Specifications 3.3.5, and if transient harmonics could cause the relays to spuriously reset during the time delay that occurs during an actual degraded voltage condition concurrent with a design basis accident. Persistent harmonics can be produced by factors external to the nuclear site or by internal phenomena. A typical internal source of harmonics at nuclear power plants is defects in rotating equipment. Persistent harmonics could cause dropout set point shift, and mask an actual degraded voltage condition. Transient harmonics could cause the relays to spuriously reset during an actual degraded voltage event, thereby delaying the protective function beyond the nominal value stipulated in Technical Specifications 3.3.5. The relay is susceptible to this type of mal-operation because it features an instantaneous voltage sensor that could reset in less than two cycles in the presence of harmonics, thereby reinitiating the relay's internal timer. The licensee has entered this item into their corrective action program as NCR

601203. This issue is unresolved pending inspector consultation with NRC headquarters technical staff for clarification of license basis design requirements of degraded voltage relays to withstand the effects of harmonics. This issue is identified as URI 05000261/2013007-07, Questions Regarding License Basis Design Requirements for

Degraded Voltage Relays.

.2.17 Security Uninterruptible Power Supply (UPS)

a. Inspection Scope

The team reviewed the licensee's security plan and also conducted interviews with responsible licensee personnel to establish an overall understanding of the function of the security UPS. The team reviewed the modification to change the security UPS to verify that the modification did not adversely affect the function of the UPS to provide constant power supply to necessary security equipment loads. The team reviewed calculations to verify that the security UPS was adequately sized to supply the load. The team reviewed maintenance and testing procedures to verify that these operations did not place the security equipment in an adverse operational condition and that the testing procedures verified that the security UPS and standby diesel could meet its intended function. A field walk-down was conducted to assess the observable material condition to assess equipment degradation and to assess the presence of hazards.

b. Findings

No findings were identified.

.3 Operating Experience

a. Inspection Scope

The team reviewed six operating experience issues for applicability at the H. B. Robinson Steam Electric Plant. The team performed an independent review for these issues and where applicable, assessed the licensee's evaluation and dispositioning of each item. The issues that received a detailed review by the team included:

Disc Separation"

b. Findings

No findings were identified.

4. Other Activities

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

4OA5 Other Activities

.1 (Closed) Unresolved Item (URI) 05000261/2012005-03: Questions Regarding Whether GOTHIC is Sufficiently Qualified for Use in Operability Determinations (ML 13037A500)

a. Inspection Scope

In 2012, the inspectors verified, per Temporary Instruction (TI) 2515/177, that the licensee implemented or was in the process of implementing the commitments, modifications, and programmatically controlled actions described in the licensee's response to NRC Generic Letter 2008-01, "Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems." During the inspection, the team questioned the acceptability of the licensee's use of the GOTHIC computer code to support operability determinations with respect to the concerns identified in Information Notice 2011-17 which cautioned the use of computer models when evaluating the acceptability of voids in emergency core cooling systems. The inspectors opened a URI pending further inspection by a GOTHIC subject matter expert in the NRC's Nuclear Reactor Regulation (NRR) office in order to evaluate and verify the licensee's conclusions regarding the continued use of GOTHIC to support operability determinations. An NRR subject matter expert reviewed the facts of the subject URI as well as plant-specific information in order to evaluate acceptability of Carolina Power and Light Company (CP&L) use of GOTHIC at the H.B. Robinson Steam Electric plant to support operability determinations.

Robinson's current design basis with respect to voids in the subject systems is a water-solid, no gas condition. This means the subject systems must be water-solid when transitioning from an outage into power operation. Once the transition is complete, in recognition of the possibility that voids will form during operation, such voids are acceptable provided operability is reasonably maintained. Robinson has used GOTHIC to support past and continued operability assessments. GOTHIC is a multi-dimensional, multi-component computer code with the capability to model two-phase flow in nuclear

power plant systems.

CP&L contracted with Nuclear Applications, Inc. (NAI) to apply GOTHIC to predict behavior associated with gas in the ECCS and RHR suction and discharge pipes at the H. B. Robinson plant. GOTHIC was compared to a broad range of test conditions and to tests that directly simulated aspects of behavior that may occur in plant piping. GOTHIC

was then used to predict the behavior of gas trapped in specific RHR and ECCS locations.

Following review of additional information, the staff determined that GOTHIC was able to predict gas transport behavior for assessment of operability provided that (a) the pump inlet void fractions and volumes predicted by GOTHIC are shown to be acceptably conservative, (b) appropriate modeling methodologies are used in GOTHIC calculations and are consistent with testing modeling, and (c) GOTHIC predicted results are consistent with simplified methodologies, such as the Froude number, when those methodologies apply. The staff performed an in-depth evaluation of a reasonably bounding GOTHIC evaluation of the effect of trapped gas in an elevated 95-foot long 10-inch diameter pipe during initiation of flow from the containment sump during the emergency recirculation phase of operation. The GOTHIC evaluation was found to have acceptably determined gas volumes that would not jeopardize operability. The staff's

review regarding Robinson's modeling detail support a conclusion that the licensee's use of GOTHIC to evaluate the potential movement of trapped gas with respect to operability was acceptable. Additionally, the licensee's use of GOTHIC was found to have acceptably assessed if there is a potential water hammer problem in a piping system and estimated the magnitude of potential pressure spikes. Based on this additional review, this URI is now closed.

b. Findings

No findings were identified.

.2 (Closed) URI 05000261/2012005-04: Questions Regarding the Adequacy of the Fill and

Vent Procedure for the RHR Heat Exchangers (ML 13037A500)

a. Inspection Scope

In 2012, the inspectors verified, per TI 2515/177, that the licensee implemented or was in the process of implementing the commitments, modifications, and programmatically controlled actions described in the licensee's response to NRC Generic Letter 2008-01, "Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems." During the inspection, the team identified a URI regarding the adequacy of the residual heat removal (RHR) system fill and vent procedure (OP-201-01, "RHR System Venting," Rev. 7) to ensure adequate fill and vent of the RHR heat exchangers (HXs). The inspectors reviewed the facts of the subject URI as well as the licensee's evaluation of the RHR system fill and vent procedure (OP-201-01). The licensee's evaluation determined that it failed to evaluate the RHR system fill and vent procedure with respect to the HXs during the assessment of GL 2008-01 and therefore failed to incorporate adequate instructions to effectively vent the HXs. The inspectors reviewed a water hammer analysis for the RHR HXs, as a result of full flow testing the system (via OST-253, "Comprehensive Flow Test for the RHR Pumps," Rev 52) with a partially voided HX, to verify that the resulting loads where within the design limits and did not aversely challenge the system. The inspectors reviewed operating and test procedures to evaluate the sequence of system alignments following fill and vent evolutions to verify that the potential HX voids did not impact other portions of the system during its operation before and throughout the system flow test. Finally, the inspectors reviewed the status of the proposed corrective actions to verify they were being tracked to completion within the licensee's corrective action program.

b. Findings

No findings were identified. However, the inspectors did identify a minor performance deficiency and associated minor violation of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings." In accordance with IMC 0612, minor violations are not routinely documented in inspections reports. However, they may be documented to capture inspection activities and conclusions for closing a URI.

The inspectors determined that the licensee's failure to provide an adequate RHR fill and vent procedure to successfully vent the RHR HXs by establishing minimum flow rates and times necessary to dynamically flush the HXs was contrary to 10 CFR 50 Appendix B, Criterion V, and was a performance deficiency. Using IMC 0612 Appendix B, "Issue Screening," dated 9/7/12, the team determined this performance deficiency to be of minor significance because the HXs would have been effectively flushed during the post maintenance system flow test, prior to the system being placed in service, without any adverse impact to the system availability, reliability, or capability. Because this issue was entered into the licensee's corrective action program, as NCR 575346, and was of minor significance, the failure to comply with 10 CFR 50 Appendix B, Criterion V, "Instructions, Procedures, and Drawings," constitutes a minor violation that is not subject

to enforcement action in accordance with NRC's Enforcement Policy.

This URI is now closed.

4OA6 Meetings, Including Exit

On May 16, 2013, the team presented the inspection results to Mr. Gideon and other members of the licensee's staff. Additional inspection results were communicated on June 20, 2013, on a teleconference with Mr. Gideon and other members of station staff, and on June 27, 2013 with Mr. Hightower.

The inspectors verified that no proprietary information was documented in this report.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

M. Connelly, Senior Regulatory Affairs Engineer
W. Hightower, Supervisor, Licensing/Regulatory Programs
J. Kunzmann, Supervisor Nuclear Rapid Response
A. Zimmerman, Lead Licensing Engineer

NRC personnel

J. Hickey, Senior Resident Inspector, Division of Reactor Projects (DRP),

Robinson Resident Office

C. Scott, Resident Inspector, DRP, Robinson Resident Official
W. Lyon, Office of Nuclear Reactor Regulation, Division of Safety Systems
G. MacDonald, DRP, Region II
G. Hopper, Chief, Projects Branch 4, DRP, Region II
R. Nease, Chief, Engineering Branch Chief 1, Division of Reactor Safety, Region II

LIST OF ITEMS

Opened and Closed

05000261/2013007-01 NCV Failure to Account for Containment

Temperature Measurement Uncertainty

[Section 1R21.2.9]

05000261/2013007-02 FIN Failure to Evaluate SBO Coping Equipment for Environmental Conditions [Section 1R21.2.13]
05000261/2013007-03 NCV Failure to Have Adequate Analyses Supporting

the Degraded Voltage Relay Setpoints [Section

1R21.2.15]

05000261/2013007-04 NCV Failure to Have Adequate Analyses For the E1 Bus Fast Transfer [Section 1R21.2.16.1]
05000261/2013007-05 NCV Failure to Have Appropriate Procedure to Verify Degraded Voltage Relay Circuit Status [Section 1R21.2.16.2]

Opened

05000261/2013007-07 URI Questions Regarding License Basis Design Requirements for Degraded Voltage Relays

[Section 1R12.2.16.3]

Closed

05000261/FIN-2012005-03 URI Questions Regarding Whether GOTHIC is Sufficiently Qualified for Use in Operability Determinations [Section 4OA5.1]
05000261/FIN-2012005-04 URI Questions Regarding the Adequacy of the Fill and Vent Procedure for the RHR Heat
Exchanger [Section 4OA5.2]

LIST OF DOCUMENTS REVIEWED

Calculations

DP-002-SIS, Design Basis Differential Pressure Report for the Motor-Operated Valves (MOVs)

in the Safety Injection System (SIS), Rev. 8

PCHG-EVAL, Engineering Change, 83689R2, Rev. 2
PCHG-DESG, Engineering Change, 0000072699R1, Evaluation of Containment Liner,
Insulation, Sheathing, and Coatings
PCHG-DESG, Engineering Change, 55265R0, Rev. 0
RNP-C/CONT-1002, Determination of Containment Heat Sink, Rev. 3
RNP-C/EQ-1334, Weak Link Analysis MOV
SI-860 A/B CV Sump Recirculation;
SI-862 A/B
RWST to RHR Loop Isolation;
SI-864 A/B RWST Discharge Isolation, Rev. 4
RNP-C/EQ-1364, USI A-46 Seismic Qualification Records, Rev. 1
RNP-C/STRU-1128, Minimum Allowable Containment Liner Thickness, Rev. 6
RNP-C/STRU-1130, Analysis of Containment Liner Bulge, Rev. 2
RNP-E-1.003, Instrument Bus Channel Loading, Rev. 6
RNP-E-1.025, 120 Vac Instrument Bus Coordination, Rev. 4
RNP-E-2.005, OC Protection for RHR Pumps B & C Motors, Rev. 2
RNP-E-2.006, OC Protection for Safety Injection Pumps A, B, & C Motors, Rev. 4
RNP-E-2.009, OC Protection for Emergency Bus E1 & E2 Emergency Supply, Rev. 3
RNP-E-2.010, OC Protection for Emergency Bus E1 & E2 Normal Supply, Rev. 3
RNP-E-2.011, OC Protection/Coordination for Feeder Breaker to MCC 5 & 16, Rev. 4
RNP-E-2.012, OC Protection/Coordination for Feeder Breaker to MCC 6, Rev. 3
RNP-E-5.018, Ampacity Evaluation of 125 Vdc and 120 Vac Power Cables, Rev. 8
RNP-E-5.043, Class 1E MCCs Control Loop Analysis, Rev. 3
RNP-E-6.004, DC Short Circuit Study, Rev. 5
RNP-E-6.005, Overcurrent Protection and Coordination of 125 Vdc Distribution System, Rev. 1
RNP-E-6.018, DC Control Circuit Loop Analysis, Rev. 3
RNP-E-6.018.A001.17B, Panel A, Circuit 1, Compt 17B
RNP-E-6.022, DC Voltage Profile, Rev. 4
RNP-E-8.002, AC Auxiliary Electrical Distribution System Study, Rev. 8C
RNP-E-8.042, AC MOV Evaluation, Rev. 4
RNP-E-8.054, Load Flow/Short circuit analysis, 640kW/800kVA Security
Diesel Generator, 9/26/11
RNP-E-8.059, Security UPS Sizing and Loading, Rev. 1
RNP-E-8.060, Security Battery and Charger Sizing, Rev. 0
RNP-F/NFSA-0052, RNP Plant Data for LOCA Analysis, Rev. 2
RNP-F/NFSA-0188, RNP Cycle 28 Plant Parameters Document, Rev. 3
RNP-I/INST-1010, Emergency Bus - Degraded Grid Voltage Relay, Rev. 3
RNP-I/INST-1023, Refueling Water Storage Tank Uncertainty and Scaling Calculation, Rev. 4
RNP-I/INST-1044, Containment Pressure Loop Uncertainty and Scaling Calculation, Rev. 3
RNP-I/INST-1057, Containment Pressure Instrument Uncertainty Calculation,

(PT-956, 957), Rev. 1

RNP-I/INST-1058, Containment Water Level Uncertainty Calculation, Rev. 4
RNP-I/INST-1067, RHR Flow Instrument Uncertainty Calculation, Rev. 1
RNP-I/INST-1108, Misc Flows EOP Setpoint Parameters, Rev. 1
RNP-I/INST-1109, Containment EOP Setpoint Parameters, Rev. 3
RNP-M/HVAC-1061, Volume Weighted Containment Bulk Average Temperature, Rev. 2
RNP-M/HVAC-1065, Transfer of
RNP-M/HVAC-1061 to ERFIS, Rev. 0
RNP-M/MECH-1114, Residual Heat Removal Parameters and Component Flow and Resistance Coefficients, Rev. 3
RNP-M/MECH-1202, RWST Percent Level VS Inventory - RNP Curve Book 8.11, Rev. 3
RNP-M/MECH-1435, Set-up Calculation for MOV
SI-864A, Rev. 10
RNP-M/MECH-1436, Set-up Calculation for MOV
SI-864B, Revs. 7, 8, and 9
RNP-M/MECH-1515, Set-up Calculation for MOV
AFW-V2-14A, Rev. 8
RNP-M/MECH-1599, RHR Pump NPSH, Rev. 0
RNP-M/MECH-1621, Containment Isolation Valves 10CFR50 Appendix J Allowable Leakage Rates, Rev. 5
RNP-M/MECH-1637, CS/SI/RHR System Hydraulic Model, Rev. 9
RNP-M/MECH-1651, Containment Analysis Inputs, Rev. 12
RNP-M/MECH-1716, Air Operated Valve Required Thrust and Actuator Capabilities for
RVI-1, Rev. 1
RNP-M/MECH-1717, Air Operated Valve Required Thrust and Actuator Capabilities for
RVI-2, Rev. 0
RNP-M/MECH-1718, Air Operated Valve Required Thrust and Actuator Capabilities for
RVI-3, Rev. 1
RNP-M/MECH-1734, Basis for AOV Calculations, Rev. 0
RNP-M/MECH-1802, Safety Related Pump Minimum Performance Requirements, Rev. 3
WES 1543, 88-10, Resolution to Generic Letter, Rev. 0, dated 6/24/88
Completed Procedures
EST-134, Main Steam Isolation Valves Air Leakage Test (Refueling), Rev. 10, dated 3/9/12
EST-137-6, Local Leak Rate Test of Post-Accident Venting and Pressure Relief Valves (P-41),
Rev. 0, dated 7/5/10 and 3/12/12 JPM
IP-005, Locally Establish AFW Flow to "A", "B", and "C" S/G's from the SDAFW Pump and Control S/G Levels and Pressures IAW
EPP-1 and
EPP-1 Attachment 1, Rev. 8, dated 1/25/07

and 1/13/05

JPM
IP-005, Locally Establish AFW Flow to "A", "B", and "C" S/G's from the SDAFW Pump and Control S/G Levels and Pressures IAW
EPP-1 and
EPP-1 Attachment 1, Rev. 9, dated 6/20/12 and 1/27/10
OST-022, Inverter A and B Weekly Surveillances, Rev. 18, dated 4/12/13 and 4/19/13
OST-151-1, Safety Injection System Components Test - Pump A, Rev. 36, dated 1/8/13
OST-151-2, Safety Injection System Components Test - Pump B, Rev. 33, dated 1/18/13
OST-151-3, Safety Injection System Components Test - Pump C, Rev. 36, dated 1/22/13
OST-151-4, Comprehensive Flow Test For Safety Injection Pump A, Rev. 17, dated 5/6/11
OST-151-5, Comprehensive Flow Test For Safety Injection Pump B, Rev. 17, dated 9/16/11
OST-151-6, Comprehensive Flow Test For Safety Injection Pump C, Rev. 17, dated 7/3/12
OST-251-1, RHR Pump A and Components Test, Rev. 28, dated 3/21/13
OST-251-2, RHR Pump B and Components Test, Rev. 29, dated 1/31/13
OST-253, Comprehensive Flow Test For The RHR Pumps, Rev. 52, dated 2/27/12
OST-405, TSC/EOF/Security Diesel Generator (Semiannual), Rev. 35 dated 2/7/13, and
Rev. 37 dated 7/22/13
OST-701-8, V12-10 and V12-11 Inservice Valve Test, Rev. 11, dated
2/8/11 and 1/1/12
OST-702-1, Secondary Side Inservice Valve Test for MSIV's, Rev. 4, dated 7/6/10
OST-702-1, "Secondary Side Inservice Valve Test for MSIV's," Rev. 6, dated 3/18/12
OST-707-8, Inservice Valve Position Indicator Verification, Rev. 4, dated 9/9/09, and Rev. 5, dated 3/9/12
TMM-035, Attachment 10.10, Static Post Test Evaluation of
GL 89-10 Program Rising Stem
MOVs, for Valve No. MOV
MS-V1-8A, Test No.
05290002, Rev. 21, dated 10/17/05
TMM-035, Attachment 10.10, Static Post Test Evaluation of
GL 89-10 Program Rising Stem
MOVs, for Valve No. MOV
MS-V1-8B, Test No.
04120002, Rev. 21, dated 4/29/04
TMM-035, Attachment 10.10, Static Post Test Evaluation of
GL 89-10 Program Rising Stem
MOVs, for Valve No. MOV
MS-V1-8C, Test No.
04113004, Rev. 21, dated 4/22/04
TMM-035, Attachment 10.10, Static Post Test Evaluation of
GL 89-10 Program Rising Stem
MOVs, for Valve No. MOV
SI-864A, Test No.
07108004 / 05, Rev. 21, dated 4/18/07
TMM-035, Attachment 10.10, Static Post Test Evaluation of
GL 89-10 Program Rising Stem
MOVs, for Valve No. MOV
SI-864A, Test No. I0125C09/11, Rev. 21, dated 5/5/10
TMM-035, Attachment 10.10, Static Post Test Evaluation of
GL 89-10 Program Rising Stem
MOVs, for Valve No. MOV
SI-864B, Test No.
05271001, Rev. 21, dated 9/28/05
TMM-035, Attachment 10.10, Static Post Test Evaluation of
GL 89-10 Program Rising Stem
MOVs, for Valve No. MOV
SI-864B, Test No.
05279007, Rev 21, dated 10/6/05
TMM-035, Attachment 10.10, Static Post Test Evaluation of
GL 89-10 Program Rising Stem
MOVs, for Valve No. MOV
SI-864B, Test No. I0130C11/13, Rev. 21, dated 5/10/10
TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
RV1-1, Rev. 3, dated 5/7/07
TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
RV1-1, Rev. 5, dated 2/18/12
TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
RV1-2, Rev. 3, dated 5/7/07
TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
RV1-2, Rev. 5, dated 2/23/12
TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
RV1-3, Rev. 1, dated 10/13/05
TMM-127, Attachment 10.1, Analysis of Category 1 AOV Diagnostic Data, Sliding Stem Valve with Spring/Diaphragm Actuator Spring to Close Configuration, for Valve No.
RV1-3, Rev. 5, dated 5/20/10
Completed Work Orders
WO 00067292 01, Test Distribution Panel A Breakers, dated 4/10/01
WO 00067404 01, Perform Inspection and Cleaning of MCCA, MCCB, Distribution Panel A and
Distribution Panel B, dated 4/21/07
WO 00115872 01, Test Distribution Panel A Breakers, dated 4/10/01
WO 00756179 01, Test Distribution Panel A Breakers, dated 3/04/07
WO 00774394 01, Diagnostic Test (SI-864A-MO), dated 12/11/09
WO 00774548 01, Disassemble/Inspect/Replace Operator Diaphragm in
RV1-3-AO, dated 4/17/10
WO 00774548 05, Disassemble/Inspect/Replace
RV1-3-AO - Post-Maintenance Diagnostic
Test, dated 4/17/10
WO 00774548 06, Disassemble/Inspect/Replace
RV1-3-AO - Pre-Maintenance Diagnostic Test, dated 4/17/10
WO 00774599 01, Disassemble/Inspect/Repair
RV1-3, dated 4/17/10
WO 00774599 06, Disassemble/Inspect/Repair
RV1-3 - Pre-Maintenance Diagnostic Test, dated 4/17/10
WO 00774599 07, Disassemble/Inspect/Repair
RV1-3 - Post-Maintenance Diagnostic Test, dated 4/17/10
WO 00774798 01, Perform Thermal Overload Test on MCC -5 (10J) (SI-864A), dated 1/12/10
WO 01348233 22, Perform Continuity Test on
MS-V1-3A-AO IAW
EC-66327, dated 2/11/12
WO 01348233 24,
MS-V1-3A Rewire Light/Remove Jumper, dated 2/22/12
WO 01348233 25,
MS-V1-3B Rewire Light/Remove Jumper, dated 2/22/12
WO 01348233 26,
MS-V1-3C Rewire Light/Remove Jumper, dated 2/22/12
WO 01446513 01, Perform
MST-921 on "A" Station Batt, dated 4/17/10
WO 01446513 01, Station Battery A Service Test, dated 5/26/10
WO 01485420 01, Diagnostic Test (SI-864B-MO), dated 12/11/09
WO 01485584 01, Check Valve Inspection on
MS-V1-3A, dated 2/23/10
WO 01486079, Perform Calibration Check of Containment Average Temperature, dated 5/18/10
WO 01486091 01, Test Distribution Panel A Breakers, dated 1/13/10
WO 01537339 01, Limitorque Inspection
SI-864A, dated 12/11/09
WO 01537340 01, Limitorque Inspection
SI-864B, dated 12/11/09
WO 01584252 01, Limitorque Grease Inspection of Valve
MS-V1-8B-MO, dated 10/20/10
WO 01687088 01,
MS-V1-3A Accumulator Tank and Support, dated 8/29/11
WO 01687089 01,
MS-V1-3B Accumulator Tank and Support, dated 8/29/11
WO 01687090 01,
MS-V1-3C Accumulator Tank and Support, dated 8/29/11
WO 01710648 01, Matrix PMT for Valves
MS-V1-3A, -3B, and -3C to Perform
OST-702-1, dated 4/5/10
WO 01749670 69,
UPS-Batt/UPS-1 operability testing, dated 7/23/11
WO 01757318 01,
SI-864B-MO Needs Diagnostic Test Failed LLRT, dated 5/15/10
WO 01758805 03, Perform Valve Overhaul on
SI-864B, dated 5/25/10
WO 01784639 01, Limitorque Grease Inspection of Valve
MS-V1-8A-MO, dated 9/6/11
WO 01800149 03, Disassemble/Inspect/Replace
RV1-2-AO - Pre-Maintenance Diagnostic Test, dated 2/1/11
WO 01800149 01, Disassemble/Inspect/Replace Operator Diaphragm in
RV1-2-AO, dated 1/27/11
WO 01800149 04, Disassemble/Inspect/Replace
RV1-2-AO - Post-Maintenance Diagnostic Test, dated 2/1/11
WO 01800153 01, Disassemble/Inspect/Replace Operator Diaphragm in
RV1-1-AO, dated 1/27/11
WO 01800153 03, Disassemble/Inspect/Replace
RV1-1-AO - Post-Maintenance Diagnostic
Test, dated 2/1/11
WO 01800153 04, Disassemble/Inspect/Replace
RV1-1-AO - Pre-Maintenance Diagnostic Test, dated 2/1/11
WO 01800327 01, Disassemble/Inspect/Repair
RV1-1, dated 1/27/11
WO 01800327 04, Disassemble/Inspect/Repair
RV1-1 - Pre-Maintenance Diagnostic Test IAW
PM-477, dated 2/3/11
WO 01800327 06, Disassemble/Inspect/Repair
RV1-1 - Post-Maintenance Diagnostic Test, dated 2/3/11
WO 01800329 01, Disassemble/Inspect/Repair
RV1-2, dated 1/27/11
WO 01800329 07, Disassemble/Inspect/Repair
RV1-2 - Post-Maintenance Diagnostic Test, dated 2/1/11
WO 01800329 08, Disassemble/Inspect/Repair
RV1-2 - Pre-Maintenance Diagnostic Test, dated 8/23/11
WO 01800488, Disassemble, Inspect and Replace Seaport Obstruction, (RO27), dated 2/15/12
WO 01800603, Calibrate RHR Flow Transmitter,
FT-605, and Perform Loop Check, dated 2/10/12 and 10/4/12
WO 01820971-01, Inspect and Repair Selected CV Liner, dated 11/15/11
WO 01820971-04, Inspect and Repair Selected CV Liner, dated 02/10/12
WO 01977400 01, Perform Security Battery Inspection, dated 3/5/12
WO 02041474 01,
MCC-6 (11J)-42/C Coil Failed Pick Up Time for
SI-864B, dated 2/14/12
WO 02053755 01, SG "B" Steam PORV Drain Line Sheared on
RV1-2, dated 5/2/12
WO 02067295 01, Check Security and EFRIS Batteries, dated 4/17/12
Corrective Action Program Documents Action Requests:
151422, Evaluate Operation with DVR's Bypassed
230929-07,
IN 2007-09 Equip Op Under Degraded Volt
243370-08, Investigation for improvement to recover margin for E1/E2 buses
274999, Reduced Voltage Testing of Control Circuit Voltages
393805, Security UPS Battery PM Revision
411609-07, NRC Information Notice 2010-12
2184, Evaluation of In-Service DB Breakers
478605, Information Notice 2011-14
500790-08, Existing Supports in Exhaust Piping (10-MS-24) for the SDAFP Turbine are Degraded and Non-Conforming
20845,
SI-864A: Apparent Issue with Seats and Seal Welds (RO-27)
2848, SG "B" STEAM LINE PORV DRAIN LINE SHEARED
531773, A, B and C MSIV Fail to Shut
534216,
EPP-010 Does not match CWD regarding
RHR-759A
563249-18, Main Steam Isolation valves Fail to Close at Shearon Harris Nuclear Power Plant
2717, Part 21 Notification Anchor Darling Double-Disc Gate Valves
Condition Reports:
082064, Methodology to Determine Containment Average Temperature to Satisfy TS 3.6.5
Surveillance Requirement With
HVE-3 and
HVE-4 Out of Service
208843, IVSW Tank Level Does Not Have Uncertainty Calculation
300581, Impact of Degraded & Loose Sheathing Panels on CV Liner
373926, RHR Pump A Shaft Sleeve Gasket Leak
374531,
OE 31969, Component Pre-Conditioning
391281, MSIV 'B' and 'C' Failed to Open IAW
OST-702-1
394244, Bulge Discovered on CV Liner
397425, CV Liner Degradation Exceeding Screening Criteria in
CM-764
398043, CV Liner Insulation/Sheathing not Maintained to Specification
398129, Additional Bulges in CV Liner Identified
420058, Variation of EDG Frequency was not Considered in the Original Design of RNP
2032, NRC CDBI Issue for
SI-862A/B,
SI-863A/B Position Interlock
2061,
RNPO-I/INST-1109 CDBI Observation
2184, Evaluation of In-Service Breaker Cycles Versus Service Life
437403, Incomplete/Missing Scaffold Request Form (08-061)
462138,
SA 447093 D-3: System Health Report Inaccuracy
500790,
SDAFW-PMP Turbine Exhaust Line Support Found Damaged
2266, Install Caulk in CV Liner Insulation Expansion Gap
517945, No Work on CV Liner Due to Moisture on the CV Liner Surface
518522, CV Liner Out-of-Round Exceeds Tolerance
518591, Work Performed Prior to Doc of CV Liner PNL AF Condition
519606, Cannot Paint CV Liner Due to High Moisture Conditions
2164, New Caulking in Some Areas of CV Liner not up to Standards
530940, CV Liner Re-Caulking Quality, RO27
531773, Main Steam Isolation Valves Fail to Close at Shearon Harris Nuclear Power Plant
545084,
CM-764 Records Vaulted with No Anii Review
545087, Containment Liner EDB Classification Incorrect
553389, V1-8C has Significant Rust on the Valve and Nearby Piping
564487. 2012-43, Faulty Rosemount Master Trip Units, Slave Units
567873, Difficult to Compare OST Surveillance Acceptance Criteria to Design Calculation 1802,
Safety Related Pump Minimum Performance Requirements
569539, Wet Boric Acid Leak Upstream of
RHR-781B,
RHR-B" Casing Vent
575301, NRC Void Inspection Item, GOTHIC
575346, Inadequate Supporting Doc Regarding RHR HX Gas Accumulation
577427,
SA 568685 EDG FOST
577567, Self-Assessment
568685 CDBI EQ Documentations Discrepancy
591847, Non-Conservative Error in Containment Analysis
596494, Condition Packing Bolt Threads of
MS-V1-8C
600172, Containment Analysis from AFW V2-14C Leakby
600388, SRI Documents Loaded into V:\Shared Drive\CDBI\2013 File
95-02840, Evaluation of Testing, Set Reference Clarification, Nureg 1492
Design Basis Documents
DBD/R87038/SD02, Design Basis Document Safety Injection System, Rev. 0 DBD/R87038/SD03, Design Basis Document Residual Heat Removal System, Rev. 0
DBD/R87038/SD13, Component Cooling Water System, Rev. 10
DBD/R87038/SD25, Main Steam System, Rev. 8
DBD/R87038/SD32, Auxiliary Feedwater System, Rev. 10 DBD/R87038/SD36, Post Accident HVAC Systems, Rev. 15 GID/90-181/00/RCI, Reactor Containment Isolation, Rev.11
GID/R87038/0007, Generic Issues Document Hazards Analysis, Rev. 5

Drawings

5379-376, Sht. 3, Component Cooling Water System Flow Diagram, Rev. 27 5379-1082, Sht. 1, Safety Injection System Flow Diagram, Rev. 44 5379-1484, Sht. 1, Residual Heat Removal System Flow Diagram, Rev. 45
5379-1881, Valve Vendor Drawing for
SI-864A/B, Series 300 16X14X16-S70 WDD Venturi Weld Ends O.S.& Y. Double Disc Gate Valve with
SMB-1 Limitorque Valve Control, Rev. 1
5379-3646, Nozzle Installation For Vena Contracta Taps, (FE-605), Rev. 1
5379-5373, Sht 1, 4160V One Line Diagram, Rev. 15 B-190627 Series, Single Line Diagrams - MCC 5, Rev. various
B-190627 Series, Single Line Diagrams - MCC 6, Rev. various
B-190628, 480V EDG B Control Wiring Diagram, Rev. 26
B-190628-299, Bus E1 Degraded Voltage Control Wiring Diagram, Rev. 7
B-190628-892, 480V Breaker 52/18B Control Wiring Diagram, Rev. 24
DS-C-69956, Nozzle Type Relief Valve, Rev. A G-190196, Sht. 1, Main and Extraction Steam System Flow Diagram, Rev. 50
G-190261, Sht. 4, Penetration Pressurization Flow Diagram, Rev. 34
G-190304,
HVAC-TURB, FUEL, AUX, REACTOR & RADWASTE BUILDING, Rev. 56
G-190626, Main and 4160V One Line Diagram, Rev. 8 G-190626, 125V DC and 120V Vital AC One Line Diagram, Rev. 18 G-190626 Sht 1, Main & 4160V One Line Diagram, Rev. 8
G-190626 Sht 2, 480 & 120/208V One Line Diagram, Rev. 23
HBR2-6933, Post Accident Containment Venting Flow Diagram, Rev. 21
HBR2-7706, Single Line - Dedicated Shutdown Bus DS, Rev. 17
HBR2-12895, Security ATS and UPS settings, Rev. 17
HBR2-C-011, Specification Sub Type: CIV, Civil Inspection Requirements, Rev. 9
HBR2-S-001, Specification Sub-Type: CIV, For Standard Supports, Rev. 9
Specification
676410, Sht. 6.7, Flow Nozzle for
CPL-Aux Coolant System, (FE-605), Rev. 1
Modifications
EC 1087, RHR Pumps Minimum Flow Recirculation Lines, 1/16/92
EC 3504, RNP Containment Re-Analysis, Rev. 4
EC 69420, Upgrade Battery Chargers to Remain Connected On a Loss of Power to
MCC-5 or
MCC-6, Rev. 25
EC 69423, Auto Start the DSDG on Loss of All AC Power, Rev. 8
EC 82064, Methodology to Determine Containment Average Temperature with Both
HVE-3 and
HVE-4 Out of Service, Rev. 0
EC 84759, Evaluation of
RO-27 MOV Test Currents, Rev. 1
EC 91447, Temperature Evaluation for
MCC-24 (DSDG auxiliaries), Rev. 0
EC 91581, Evaluation of System Harmonics on Degraded Grid Relays, Rev. 0
EC 91586, Evaluation of Starting Motors with Bus E1 & E2 at DVR Setpoint, Rev. 0
EC 91626, Temperature Effects on
OST-253 Results, Rev. 0
ECR 14546, CCW Vents to Protect Against Gas Intrusion

Procedures

AOP-013, Fuel Handling Accident, Rev. 15
AOP-014, Component Cooling Water System Malfunction, Rev. 34
AOP-024, Loss of Instrument Bus, Rev. 38
CM-305, Westinghouse DB type Circuit Breaker Maintenance, Rev. 18
CM-764, Inspection and Repair of CV Liner Insulation, Rev. 14
DSP-002, Hot Shutdown Using the Dedicated/Alternative Shutdown System,
Rev. 43 and Rev. 47
E-023, MCC Inspection and Cleaning, Rev. 7
EDP-002, 480V AC Busses, Rev. 15
EDP-003, MCC Buses, Rev. 56
EGR-NGCC-0007, Maintenance of Design Documents, Rev. 11
EGR-NGCC-0009, Engineering Change Product Selection and Initiation, Rev. 6
EGR-NGCC-0017, Preparation and Control of De sign Analyses and Calculations, Rev. 8
EGR-NGGC-0106, AC and DC Overcurrent Protection and Coordination, Rev. 4
EPP-1, Loss of All AC Power, Rev. 33 and Rev. 51
EPP-9, Transfer to Cold Leg Recirculation, Rev. 35
EST-134, Main Steam Isolation Valves Air Leakage Test (Refueling), Rev. 10
JPM
IP-020, Establish Service Water Using
DSP-002, Att. 2, Electrical Operator Actions, Rev. 43
JPM
IP-048, Restoring AC Power at the DSDG Panel IAW
EPP-1, Rev. 11 JPM
IP-177, Transfer an Instrument Bus to the Alternate Power Supply IAW
AOP-024, Rev. 37 JPM
IP-122, Restart "B-1" Battery Charger Following a Loss of Power, Rev. 1 and Rev. 2
MST-E-4KV-BKR-001, 4KV Auto Bus Transfer Breakers 52/7 and 52/12 Timing Test, Rev. 0
MST-E-480V-E1-DV, Degraded Voltage Test - E1 Bus, Rev. 0
MST-E-480V-E1-UV, Emergency Bus E1 UV and Load Shed Test, Rev. 0
NDEP-0408, Ultrasonic Thickness Measurement (A-SCAN), Rev. 14
NDEP-0454, Digital Ultrasonic Thickness Measurement, Rev. 4
NGG-PMB-MCC-01, Motor Control Centers and Molded Case Circuit Breakers, Rev. 2
OP-201, Residual Heat Removal System, Rev. 69
OP-202, Safety Injection and Containment Vessel Spray System, Rev. 94
OP-601, DC Supply System, Rev. 56
OP-602, Dedicated Shutdown System, Rev. 66
OP-921, Containment Air Handling, Rev. 53
OP-922, Post Accident Containment Hydrogen Reduction/ Venting System, Rev 18
OP-926, TSC/EOF/Security Diesel Generator, Rev. 24
OST-021, Daily Surveillances, Rev. 36
OST-405, TSC/EOF/Security Diesel Generator (Semiannual), Rev.37
OST-702-1, Secondary Side Inservice Valve Test for MSIV's, Rev. 6
OST-703-1, Primary Side Inservice Valve Test for SI System, Rev. 8
PIC-804, ABB Type 27N UV Relay, Rev. 16
PLP-118, Hot Weather Operations, Rev. 11
PM-124, Testing of Thermal Overload Relays for
MCC-5, Rev. 24
PM-207, Testing of Thermal Overload Relays for
MCC-6, Rev. 18
PM-402, Inspection and Testing of CB for 480V Bus E1, Rev. 47
PM-435, Dedicated Shutdown Bus, 480V Bus 4, and Exciter Breaker Inspection, Rev. 24
PM-447, MCCB Instantaneous Testing, Rev. 22
PM-449, Dedicated Shutdown field flash battery Service Test, Rev. 13
PM-450, MCCB Thermal and Instantaneous Testing, Rev. 17
PM-466, Westinghouse 4160VAC ACB Maintenance, Rev. 8
PM-474, 4KV Bus Inspection and Cleaning, Rev. 12
PM-E-DC-MCC-001, Inspection and Cleaning of DC MCCA, MCCB, Distribution Panel A and
Distribution Panel B, Rev. 0
PM-E-SEC-Batt-001, Inspection and Testing of Security UPS Batteries, Rev. 0
SACM-2, Depressurize Containment, Rev. 2
SACM-3, Control Hydrogen Flammability, Rev. 2
SACM-4, Control Containment Vacuum, Rev. 3
SAM-7, Reduce Containment Hydrogen, Rev. 2
SPP-035, Containment Bulk Average Temperature Measurement, Rev. 6
TMM-032, Motor Operated Valve Program, Rev. 28
TMM-035, Post Test Evaluation of MOV Performance, Rev. 23

Miscellaneous Documents

06-15, Evaluate Calculation
RNP-M/MECH-1114 For Potential Errors, 6/27/06
20/5065, System Health Report - Switchyard, Q1-2013
5357-E-601, DSDG Project Specification, 04/03/1980 5357-R-2, DSDG Purchase Order, 07/03/1980 ANSI/ISA-67.04.01-2006, Setpoints for Nuclear Safety-Related Instrumentation, dated 5/16/06
DSDG (5098) MR (a)(1) action plan LTAM, dated 1/17/2013
Degraded/Nonconforming Conditions
RIS 2005-20 Issue Tracking, dated 2/22/2013
DOM-NAF-3-NP-A, Gothic Methodology for Analyzing the Response to Postulated Pipe Ruptures Inside Containment, September 2006 Ebasco Specification, Containment Butterfly Valves,
CPL-R2-MV-15, dated 1/27/69
EGR-NGGC-153, Engineering Instrument Setpoints, Rev. 11
EPRI
NP 7410, Molded Case Circuit Breaker Maintenance and Application Guide, Rev. 1
ESR 00-00092, SI Pump Minimum Recirculation Flow, Rev. 1
ESR 9900231, CV Volume Weighted Bulk Ave. Temp. 8/16/99 File No: 1013510A, Din No:
880805088, Evaluation Package for IE Bulletin 88-04 Potential
Safety Related Pump Loss
IEEE Std. 242-2001, Conductor Protection
IEEE Std C37.23-2003, IEEE Standard for Metal-Enclosed Bus
IST Evaluation 09-16, Establish New Acceptance Criteria Based on Results of
RNP-M/MECH-1802, 9/15/02 Letter dated March 24, 1969, U.S. Atomic Energy Commission to Mr. P. S. Colby of CP&L Letter dated November 5, 1969, U.S. Atomic Energy Commission to Mr. P. S. Colby of CP&L
Letter dated May 14, 2013, Re: 3WT-811 style pump Typical S/n
1613243 Minimum Flow
Operation Letter, Flowserve to Progress Energy, Robinson Station, S/N
1612443, Minimum Flow
Operation, dated 5/14/13
Letter, NRC to Virginia Electric and Power Company, Approval of Dominion's Topical Report
DOM-NAF-3, dated August 30, 2006 Licensee Event Report 87-026-01, Potential For Residual Heat Removal Pump Failure Due to Inadequacy in Design, dated 02/29/88
Liner Visual Inspections, dated 4/10/2013
LP-151, Residual Heat Removal (RHR) Flow Control Channel 605, Rev. 14
LTAM
RNP-10-0497, Long Term Asset Management to Replace Safety-related MCCBs Maintenance Rule Functional Failure Report, AC and DC MCCBs
NAI-1664-2013-001, Heat Sinks Used in Containment Response, Rev. 1, dated 5/15/13
NLS-88-163, CPL Response to Bulletin 88-04, dated July 1988
NLS-89-040, CPL Supplemental Response to Bulletin 88-04, dated February 1989
NP-7410-V3R1, EPRI Guidance on Molded Case Circuit Breaker Maintenance and Application Guide NRC Bulletin 88-04, Potential Safety-Related Pump Loss, dated May 5, 1988
NRC Information Notice No. 87-59, Potential RHR Pump Loss
NRC Information Notice 93-64, Periodic Testing and Preventative Maintenance of Molded Case
Circuit Breakers NRC Information Notice 95-05, Undervoltage Protection Relay Settings Out of Tolerance Due to
Test Equipment Harmonics
NRC Regulatory Issue Summary 2011-12, Adequacy of Station Electric Distribution System Voltages, Rev. 1
OCR 591847, Non-Conservative Error in Containment Analysis Report of the Expert Panel on the Effect of Gas Accumulation on Pumps, "The Pump
Roadmap," 2012 Technical Report RNP Margin Issues List, dated 3/19/2013
RNP Student Text, Component Cooling Water System, Volume 1 - Systems, Rev. 1
ST-039, 230/4KV Electrical System Student Manual, Rev. 0
ST-056, Dedicated Shutdown System Student Manual, Rev. 0
Safety Evaluation by the Division of Reactor Licensing U. S. Atomic Energy Commission in the
Matter of Carolina Power and Light Company H. B. Robinson Unit No. 2 Docket No. 50-261, dated 5/18/1970
Standing Instruction 13-001, ITS LCO 3.6.5, Containment Air Temperature, is non-conservative, Rev. 1
System Health Report- 2080, Safety Injection (1/1/2013 - 3/31/13) System Health Report- 3020, Main Steam System (10/1/2010 - 12/30/10) System Health Report- 3020, Main Steam System (10/1/2011 - 12/30/11)
System Health Report- 3020, Main Steam System (10/1/2012 - 12/30/12)
System Health Report- 3065, Aux iliary Feedwater (7/1/2010 - 9/30/10) System Health Report- 3065, Aux iliary Feedwater (1/1/2011 - 3/31/11) System Health Report- 3065, Aux iliary Feedwater (1/1/2012 - 3/31/12) System Health Report- 3065, Aux iliary Feedwater (1/1/2013 - 3/31/13) System Health Report- 4080, Component Cooling Water (1/1/2013-3/31/2013)
System Health Report- 4080, Component Cooling Water (1/1/2012-3/31/2012)
System Health Report- 4080, Component Cooling Water (1/1/2011-3/31/2011)
System Health Report- 4080, Component Cooling Water (4/1/2012-6/30/2012) System Health Report- 4080, Component Cooling Water (4/1/2011-6/30/2011) System Health Report- 4080, Component Cooling Water (7/1/2011-9/30/2011)
System Health Report- 4080, Component Cooling Water (7/1/2012-9/30/2012)
System Health Report- 4080, Component Cooling Water (10/1/2010-12/31/2010)
System Health Report- 4080, Component Cooling Water (10/1/2011-12/31/2011) System Health Report- 4080, Component Cooling Water (10/1/2012-12/31/2012)
TMM-004, Inservice Test Program, Rev. 80 Vendor Manual 728-523-20, Breakers 480V, MCC Westinghouse Vendor Manual 741-115-92, 7.5 KVA Inverter
WCAP-12070, Safety Injection System Design Summary Document, dated December 1988
WCAP-12432, Residual Heat Removal System Design Summary Document, dated November 1989

Condition Reports

Generated as a Result of the Inspection
NCR 600145, CDBI 13- Operating Exp. Review of
IN 2012-14 Incomplete
NCR 600159, CDBI 2013 Laptop Requested < 7 Days Prior to Need Date
NCR 600227, CDBI 2013 Question on PRA Human Reliability Analysis Update
NCR 600301, CDBI 2013 UAT Local Annun Cracked in Lower Right Corner
NCR 600314, CDBI 2013- Verification of Tap Setting on
SST-2C
NCR 600316, CDBI 2013- Improperly Stowed Ladders in Security Bldg
NCR 600320, CDBI 2013
UAT-SUT Detcs Not Padlocked
NCR 600517, CDBI 2013 Tracking #111 Grease is Leaking from
SI-868A
NCR 600522, CDBI 2013 Potential DSDG Elect. Equip. Temp. Ratings Exceeded
NCR 600527, 2013 CDBI Walkdown Housekeeping Issues
NCR 600560, CDBI 2013- Assumption Not Validated in Calc
RNP-E-6.004
NCR 600673, CDBI 2013 Gasket on Terminal Box for Valve V12-10
NCR 600689, CDBI 2013 Poor Housekeeping in RHR Pits "A" and "B"
NCR 600722, 2013 CDBI Conduit Strap Missing Bolt in FRV B/P Room
NCR 600730, 2013 CDBI Rust Color Boric Acid on
RHR-PMP-B Casing FLG Studs
NCR 600732, 2013 CDBI Snubber Studs Do Not Have Full Thread Engagement
NCR 600740, CDBI 2013
LIC-947, RWST Level, Cabinet Door Damaged
NCR 600775, CDBI 2013 Discrepancy on Valve Drwg 5379-01881
NCR 600778, CDBI 2013 Inconsistent Answers Noted on MOV PTE's
NCR 600884, CDBI 2013- E- Bus Degrade Voltage Timing Relays Do Not Have
NCR 601198, 2013 CDBI Walkdown Item- Duct Tape on Pipe Near Penetration
NCR 601201, CDBI 2013:
RIS 2011-12 Response
NCR 601203, CDBI 2013: Harmonic Filters for Degraded Grid Voltage Relays
NCR 601946, 2013 CDBI: Qual Docs for 6-CP-152R-7 Cannot Be Found
NCR 602516, CDBI 2013: Switch Testing Questioned
NCR 602671, CDBI 2013; Molded Circuit Case Breaker Testing
NCR 602950, CDBI 2013 Gen Temp Rating Lower Than Maximum Ambient Temp
NCR 602971, CDBI 2013 JPM
IP-20 Rev. 43 does not match plant configuration
NCR 603199, 2013 CDBI-
OST-253 Temperature Error Not Accounted For
NCR 603207, CDBI 2013 Cont. Pressure Relief Concern During SAMG Actions
NCR 603232, 2013 CDBI Calculation References Incorrectly Identified
NCR 603235, CDBI, Incorrect Rev in Control Documents
NCR 603294, 2013 CDBI, Uncertainty Analysis for Average Cont Temperature
NCR 603314, 2013 CDBI-
ESR 00-00092 Did Not Address
IN 88-04
NCR 603316, CDBI 2013- RHR Flow Element
FE-605
NCR 603329, CDBI, AOV Calc Have Negative Pilot Operability Margins
NCR 603363, 2013 CDBI: LRA/FLA ETAP Default in
RNP-E-8.002
NCR 603417, CDBI 2013 Identified Incorrect JPM Revision Number
NCR 604297, CDBI 2013 Identified Duplicate JPM Revision Number
NCR 606294, Uncertainty Analysis for Bulk Average Containment Temperature
NCR 606314,
ESR 00-00092 Did Not Address Bulletin 88-04
NCR 606316, RHR Flow Element
FE-605
NCR 606607, Acceptance Criteria for Containment Average Temperature
NCR 606659, Time to Secure SI Pumps
NCR 606986, CDBI,
TMM-127, 5/20/10 Diag. Evaluation for
RV1-3
Work Requests
578454,
LIC-947, RWST Level, Cabinet Door Damaged
578456, Poor Housekeeping in RHR Pits "A" and "B"

Section 4OA5: Other Activities

Corrective Action Program Documents
AR 575346

Procedures

OST-253, Comprehensive Flow Test for the RHR Pumps, Rev. 52
OP-201-01, RHR System Venting, Rev. 7 and Rev. 7
OP-201, Residual Heat Removal System, Rev. 69

Calculations

NAI-1713-001, Robinson Nuclear Plant RHR Discharge Sensitivity Study Review, Rev. 0
NAI-1713-002, Robinson Nuclear Plant RHR Heat Exchanger Air Sweep Water-Hammer
Analysis, Rev. 0

Drawings

SK-RNP-ADMIN-0272, RHR Gas Intrusion Isometric

Other Documents

EC89737, RHR Heat Exchanger Void/Venting Evaluation, Rev. 0
09-10, N. (December 2010.). Topical Report,
NEI 09-10, Revision 1, "Guidelines for Effective Prevention and Management of System Gas Accumulation," ML110240126.
2008-01, G. (January 11, 2008.). "Managing Gas Accumulation in Emergency Core Cooling,
Decay Heat Removal, and Containment Spray Systems," NRC Generic Letter 2008-01,
ML072910759.
Andreychek, T. S. (July 1988). "Loss of RHRS C

ooling While the RCS is Partially Filled,"

Westinghouse Electric Corporation,
WCAP-11916 Revision 0, ADAMS Accession No.
ML12006A164. .
Andreychek, T. S. (July, 1988.). "Loss of RHRS Cooling While the RCS is Partially Filled," Westinghouse Electric Corporation,
WCAP-11916 Revision 0, ML12006A164.
ANS. ( February 19, 1976.). "Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants," American National Standards Institute (ANSI) N18.7-
1976/American Nuclear Society (ANS) 3.2.
ANS. (February 19, 1976). "Administrative Controls and Quality Assurance for the Operational Phase of Nuclear Power Plants," ANSI N18.7-1976/ANS 3.2.
Balakhnin. (April 9, 2013). No Title, response to RAI #3.
Balakhnin. (April 9, 2013). No title, Response to RAI 6.
Balakhnin. (April 9, 2013). None, Response to RAI Number 2.
Balakhnin. (April 9, 2013). None, Response to RAI Number 4.
Beaulieu, D. P. (October 6, 2010). "Forthcoming Category 2 Public Meeting with Numerical Applications Inc (NAI) ...," ML102780194.
Browning, R. A. (August 30, 2012.). "Response to NRC Request for Additional Information Regarding
TSTF-523, Revision 1, 1Generic Letter 2008-01, Managing Gas Accumulation,'"
ML122343A284.
Browning, R. A. (August 30, 2012). "Response to NRC Request for Additional Information Regarding
TSTF-523, Revision 1, Generic Letter 2008-01, Managing Gas Accumulation,"
ADAMS Accession No. ML122343A284.
BWROG-TP-08-017. (April 30, 2009.).
BWROG-TP-08-017, 0000-0086-7825-R0, "Potential Effects of Gas Accumulation on ECCS Analysis as Part of
GL 2008-01 Resolution," Proprietary
ML 091250362, non-proprietary ML091250361.
BWROG-TP-08-020. (April 30, 2009.).
BWROG-TP-08-020, 0000-0088-8669-R0, "Effects of Voiding on ECCS Drywell Injection Piping," ML091250178. .
Carlson, K. e. (June, 1990). RELAP5/Mod3 Code Manual, NUREG/CR-5535.
Chang, K. S. (1995). "An Experimental Investigation of the Air Entrainment in the Shutdown Cooling System During Mid-Loop Operation," Ann. Nucl. Energy Vol. 22, No. 9, pp 611-619. .
Chang, K. S. (1995). "An Experimental Investigation of the Air Entrainment in the Shutdown Cooling System During Mid-Loop Operation," Ann. Nucl. Energy Vol. 22, No. 9, pp 611-619.
Collier, J. a. (1994). "Convective Boiling and Condensation," Third Edition, Oxford University Press.
Crane. (December, 2001 (Reprinted) ). "Flow of Fluids Through Valves, Fittings, and Pipe," Technical Paper No. 410.
FAI/08-70, R. (September 2008.). "Gas-Voids Pressure Pulsations Program", Fauske & Associates, LLC, for the PWR Owners' Group, ML090990426.
FAI/08-78. (August, 2008). "Methodology for Evaluating Waterhammer in the Containment Spray Header and Hot Leg Switchover Piping", Fauske & Associates, LLC, for the PWR
Owners' Group, ADAMS Accession No. ML090980331. .
FAI/08-78, R. (August 2008.). "Methodology for Ev aluating Waterhammer in the Containment Spray Header and Hot Leg Switchover Piping", Fauske & Associates, LLC, for the PWR
Owners' Group, ML090980331.
FAI/09-130-P. (December, 2010.). "Technical Basis for Gas Transport to the Pump Suction," Fauske & Associates, LLC, "Technical Basis for Gas Transport to the Pump Suction," Fauske

&Associates, ML110480456.

Gall, J. (June 24, 2010.). "Meeting With The Nuclear Energy Institute (NEI) And Industry Representatives To Discuss NRC Generic Letter 2008-01, 'Managing Gas Accumulation In Emergency Core Cooling, Decay Heat Removal, And Containment Spray Systems,'" NRC
Memorandum, ML101650201.
George, T. L. (January 10, 2012). "Comparison of GOTHIC Gas Transport with 4" and 12" Pipe Test Data," Numerical Applications Ind.,
NAI-1459-003, Revision 1.
George, T. L. (August 25, 2010). "GOTHIC Simulation of the Millstone-3 Gas-Water Transport Tests,"
NAI-1459-002.
Harvill, R. (April 2, 2012). "Evaluation of Gas Accumulation in RNP (Unit 2) ECCS Discharge Piping,"
NAI-1417-002, Rev. 2.
Harvill, R. e. (No date). "Evaluation of Gas Accumulation in Harris Nuclear Plant ECCS Suction Piping,"
NAI-1614-001 Revision 0 (Unsigned).
Harville, R. (January 26, 2009). "Robinson Nuclear Plant ECCS Pump Suction Void Evaluation,"
NAI-1417-001 Revision 0.
Honcharik, M. C. (June 13, 2012). ""Acceptance for Review and Request for Additional Information....," NRC Letter to TSTF, ADAMS Accession No. ML12158A547.
Honcharik, M. C. (June 13, 2012.). ""Acceptance for Review and Request for Additional Information....," NRC Letter to TSTF, ML12158A547.
Huffman, K. (August, 2012). Report of the Expert Panel on the Effect of Gas Accumulation on Pumps," EPRI Report Number 1026498.
Institute, N. E. (October, 2012). "Guidelines for Effective Prevention and Management of System Gas Accumulation," ML12310A010.
Joukowsky, N. (1898.). "Uber den hydraulischen Stoss in Wasserleitungsrohen," Memoires de I'Academie Imperiale des Sciences de St.-Petersbourg (1900), Series 8, 9(5), 1-71.
Kamath, P. S. (September, 1982.). "An Assessment of Residual Heat Removal and Containment Spray Pump Performance Under Air and Debris Ingesting Conditions," Creare, Inc., NUREG/CR-2792, ML100110155.
Kasztejna, P. (August 5, 2008). "HB Robinson Power Plant, ECCS Pumps," Letter from Flowserve Engineering.
Kim, S. (September 1992). "A Study on the Free Su rface Vortex in the Pipe System," Journal of the Korean Nuclear Society, Volume 24, number 3. (pdf may be obtained by Google search using the following: "sang-nyung kim" "wan-ho jang. .
Kim, S. (September 1992). "A Study on the Free Su rface Vortex in the Pipe System," Journal of the Korean Nuclear Society, Volume 24, number 3. (pdf may be obtained by Google search using the following: "sang-nyung kim" "wan-ho jang.
LTR-LIS-08-543. (April 2, 2009). "PWROG Position Paper on Non-condensable Gas Voids in ECCS Piping; Qualitative Engineering Judgment of Potential Effects on Reactor Coolant System Transients Including Chapter 15 Events, Task 3 of
PA-SEE-450", Westinghouse, ML090980303.
LTR-LIS-08-543. (April 2, 2009.). "PWROG Position Paper on Non-condensable Gas Voids in ECCS Piping; Qualitative Engineering Judgment of Potential Effects on Reactor Coolant System Transients Including Chapter 15 Events, Task 3 of
PA-SEE-450", Westinghouse, ML090980303.
Lyon, W. (April 9, 2013). "Office of Nuclear Reactor (NRR) Reactor Systems Branch (SRXB) Questions to Obtain Additional Information Related to Use of GOTHIC at H. B. Robinson".
McGoun, W. (No date). "Evaluate use of Gothic for Gas Transport Analyses (IN 2011-17),"
PCH-EVAL Engineering Change 0000089423R0.
McGoun1, W. (No Date). "Evaluate use of Gothic for Gas Transport Analyses (IN 2011-17),"
PCHG-EVAL Engineering Change 0000086423R0.
Musser, R. A. (February 6, 2013). "H.B. Robinson Steam Electric Plant - NRC Integrated Inspection Report 05000261/2012005, Letter to Carolina Power and Light Company.
NEI. (December 2010). "Guidelines for Effective Prevention and Management of System Gas Accumulation,"
NEI 09-10 Rev 1, ML110240126.
NEI. (October, 2012). "Guidelines for Effective Prevention and Management of System Gas Accumulation,"
NEI 09-10 Rev 1a, ML12310A009, 010.
Nesse, R. (December 4, 2012). "assistance with GOTHIC at Robinson," NRC email, ML13099A001.
NRC. (June 26, 2011). "Calculation Methodologies for Operability Determinatinos of Gas Voids in Nuclear Power Plant Piping," Information Notice 2011-17, ML11161A111.
NRC. (March, 19, 2013). "Final Safety Evaluatio

n for Nuclear Energy Institute Topical Report

NEI 09-10, Revision 1a, 'Guidelines for Effective Prevention and Management of System Gas Accumulation, Project No. 689," ML12342A368.
NRC. (March 12 - 14, 2013.). "NRC's 25th Annual Information Conference, North Bethesda, Md.
NRC. (September 26, 2005). "NRC Regulatory Issue Summary 2005-20 ... 'Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability,'" ML052020424.
NRC. (April 16, 2008). "NRC Regulatory Issue Summary 2005-20, Rev. 1 ... 'Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming conditions Adverse to Quality or Safety,'" ML073440103.
NRC. (December 7, 2009 (Approved)). "Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming conditions Adverse to Quality or Safety," NRC Inspection Manual, Part 9900: Technical Guidance.
NRC. (February 1978).
RG-1.33, "Quality Assurance Requirements (Operation)," Regulatory Guide (RG) 1.33, Rev 2.
NRC/RES. (October 4, 2010.). "Generic Issue Management Control System Report for Fiscal Year 2010 4th Quarter," Office of Nuclear Regulatory Research, ML102710133.
NRC-Guidance. ( May 23, 2011.). "Guidance To NRC/NRR/DSS/SRXB Reviewers For Writing TI Suggestions For The Region Inspections," ML102080675, June 4, 2010. The latest version of this guidance is Revision 11, ML111660749.
NRC-Guidance-1. (June 7, 2010.). "Guidance To NRC/NRR/DSS/SRXB Reviewers For Writing TI Suggestions For The Region Inspections," ML101590268.
NUREG-0737. (November, 1980.). "Clarification of TMI Action Plan Requirements" .
Part-9900. (April 16, 2008.). "Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming conditions Adverse to Quality or Safety," NRC Inspection Manual, Part 9900: Technical Guidance, Attachment to
RIS 2005-20 Rev 1. .
Rahn, F. (January, 2012). "GOTHIC Thermal Hydraulic Package, Version 8.0(QA). EPRI, Palo Alto, CA:2012".
RG-1.33. (, February, 1978). "Quality Assurance Requirements (Operation)," Regulatory Guide (RG) 1.33 , Rev 2.
Riley, J. (September 26, 2012.). "NEI Response to Request for Additional Information on Topical Report
NEI 09-10, Revision 1: Guidelines for Effective Prevention and Management of Sysstem Gas Accumulation," ML122760199.
Riley, J. H. (January 26, 2012.). " NEI Response to NRC Comments on Topical Report
NEI 09-10, Revision 1: 'Guidelines for Effective Prevention and Management of System Gas Accumulation,'" Nuclear Energy Institute Letter to NRC, ML120270480.
Riley, J. H. (December 21, 2010). "Submittal of
NEI 09-10, 'Guidelines for Effective Prevention and Management of System Gas Accumulation," .
Riley, J. H. (November 1, 2012). "Submittal of
NEI 09-10, Rev 1a for NRC Endorsement,"
ML12310A009.
RIS-2005-20. (September 26, 2005.). "... Revision to Guidance Formerly Contained in NRC Generic Letter 91-18, 'Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability,'"
ML052020424.
RIS-2005-20-Rev-1. (April 16, 2008.). "... Revision to Guidance Formerly Contained in NRC Generic Letter 91-18, 'Information to Licensees Regarding Two NRC Inspection Manual Sections on Resolution of Degraded and Nonconforming Conditions and on Operability,'"
ML073440103.
Robinson1. (No Date). "Engineering Change,"
PCHG-DESG, 0000070450R7.
Robinson2. (No date). Engineering Change,"
PCHG-DESG, 0000070450R7, Attachment A.
Stringfellow, N. J. (March 29, 2012.). "Transmittal of
TSTF-523, Revision 1, 'Generic Letter
2008-01, Managing Gs Accumulation,'".
Stringfellow, N. J. (March 29, 2012). "Transmittal of
TSTF-523, Revision 1, 'Generic Letter
2008-01, Managing Gas Accumulation,'" Letter to NRC, ADAMS Accession No.
ML12089A356. .
Stringfellow, N. J. (March 29, 2012.). "Transmittal of
TSTF-523, Revision 1, 'Generic Letter 2008-01, Managing Gas Accumulation,'" Letter to NRC, ML12089A356.
TIA2008-03. (October 21, 2008.). "Task Interface Agreement - Emergency Core Cooling Systems (ECCS) Voiding Relative to Compli ance with Surveillance Requirements (SR) 3.0.1.1, 3.5.2.3, and 3.5.3.1 (TIA 2008-03)," ML082560209.
USNRC. (January 11, 2008). 1. "Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems," NRC Generic Letter 2008-01,
ML072910759.
Waldrep, G. W. (1990). "Analysis of Vortex Phenomena in PWRs at Reduced Inventory Conditions," Transactions of the ANS, Vol 62, pp 350 - 352. .
Wallis, G. (June, 1977). "Conditions for a Pipe to Run Full When Discharging Liquid Into a Space Filled With Gas," Journal of Fluids Engineering, June, pp 405 - 413.
Wallis, G. (1969). "One Dimensional Two-Phase Flow," McGraw Hill Book Co. .
Wallis, G. (1969). "One Dimensional Two-Phase Flow," McGraw Hill Book Co.
WCAP-17271-P. (October, 2010.). "Air Water Transport in Large Diameter Piping Systems: Analysis and Evaluation of Large Diameter Testing Performed at Purdue University," Rev. 1, Volumes 1, 2, and 3, Westinghouse Electric Company LLC,
WCAP-17271-P, ML110490356.
WCAP-17276-P, R. 1. (January 2011.). "Investigation of Simplified Equation for Gas Transport", Westinghouse Electric Company LLC, for the PWR Owners Group,
WCAP-17276-P, Rev. 1, ML110480381.
Westinghouse. (October, 2010). "Air Water Transport in Large Diameter Piping Systems: Analysis and Evaluation of Large Diameter Testing Performed at Purdue University," Rev. 1, Volumes 1, 2, and 3, Westinghouse Electric Company LLC, WCAP 17271-P, ADAMS
Accession No. ML110490356.
Retrieved from "https://kanterella.com/w/index.php?title=IR_05000261/2013007&oldid=893407"