IR 05000282/2006003: Difference between revisions
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{{Adams|number = ML062270524}} | {{Adams | ||
| number = ML062270524 | |||
| issue date = 08/14/2006 | |||
| title = IR 05000282/2006003, 05000306/2006003; 4/01/06 - 6/30/06; Prairie Island Nuclear Generating Plant, Units 1 and 2; Inservice Inspection Activities, Reactor Vessel Head Replacement, Radiation Protection, and Other Activities | |||
| author name = Skokowski R A | |||
| author affiliation = NRC/RGN-III/DRP/RPB3 | |||
| addressee name = Palmisano T | |||
| addressee affiliation = Nuclear Management Co, LLC | |||
| docket = 05000282, 05000306 | |||
| license number = DPR-042, DPR-060 | |||
| contact person = | |||
| case reference number = FOIA/PA-2010-0209 | |||
| document report number = IR-06-003, RLS1 | |||
| document type = Inspection Report, Letter | |||
| page count = 74 | |||
}} | |||
{{IR-Nav| site = 05000282 | year = 2006 | report number = 003 }} | {{IR-Nav| site = 05000282 | year = 2006 | report number = 003 }} | ||
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Mr. T. PalmisanoSite Vice President Prairie Island Nuclear Generating Plant Nuclear Management Company, LLC 1717 Wakonade Drive East Welch, MN 55089 | Mr. T. PalmisanoSite Vice President Prairie Island Nuclear Generating Plant Nuclear Management Company, LLC 1717 Wakonade Drive East Welch, MN 55089 | ||
SUBJECT: PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2NRC INTEGRATED INSPECTION REPORT 05000282/2006003;05000306/2006003 | SUBJECT: PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2NRC INTEGRATED INSPECTION REPORT 05000282/2006003; 05000306/2006003 | ||
==Dear Mr. Palmisano:== | ==Dear Mr. Palmisano:== | ||
On June 30, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an integratedinspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on July 12, 2006, with you and other members of your staff. This inspection examined activities conducted under your license as they relate to safety and tocompliance with the Commission's rules and regulations and with the conditions of your license. | On June 30, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an integratedinspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on July 12, 2006, with you and other members of your staff. This inspection examined activities conducted under your license as they relate to safety and tocompliance with the Commission's rules and regulations and with the conditions of your license. | ||
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based on the results of this inspection, there were three NRC-identified and one self-revealedfindings of very low safety significance noted. All these findings involved violations of NRC requirements. In addition, one NRC-identified issue was reviewed under the NRC | The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based on the results of this inspection, there were three NRC-identified and one self-revealedfindings of very low safety significance noted. All these findings involved violations of NRC requirements. In addition, one NRC-identified issue was reviewed under the NRC traditi onalenforcement process and was determined to be a Severity Level IV violation of NRC requirements. However, because these violations were of very low safety significance, not willful, and because they were entered into your corrective action program, the NRC is treatingthese issues as Non-Cited Violations in accordance with Section VI.A.1 of the NRC'sEnforcement Policy. Additionally, four licensee-identified violations are listed in Section 4OA7 of this report.If you contest the subject or severity of a Non-Cited Violation, you should provide aresponse 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, D.C.20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - | ||
Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office ofEnforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the Resident Inspector Office at the Prairie Island Nuclear Generating Plant. | Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office ofEnforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the Resident Inspector Office at the Prairie Island Nuclear Generating Plant. | ||
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===Enclosure:=== | ===Enclosure:=== | ||
Inspection Report 05000282/2006003; 05000306/2006003 | Inspection Report 05000282/2006003; 05000306/2006003 | ||
===w/Attachment:=== | ===w/Attachment:=== | ||
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The inspections were conducted by the resident inspectors and inspectors from the Region III office. One Severity Level IV violation and four findings with associated non-cited violations were identified. The significance of most findings is indicated by their color (Green, White, | The inspections were conducted by the resident inspectors and inspectors from the Region III office. One Severity Level IV violation and four findings with associated non-cited violations were identified. The significance of most findings is indicated by their color (Green, White, | ||
Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination | Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be "Green" or be assigned a severity level after NRC management review. The NRC's program for overseeing the safeoperation of commercial nuclear power reactors is described in NUREG-1649, "ReactorOversight Process," Revision 3, dated July 2000.A.Inspector-Identified and Self-Revealed Findings | ||
Process" (SDP). Findings for which the SDP does not apply may be "Green" or be assigned a severity level after NRC management review. The NRC's program for overseeing the safeoperation of commercial nuclear power reactors is described in NUREG-1649, "ReactorOversight Process," Revision 3, dated July 2000.A.Inspector-Identified and Self-Revealed Findings | |||
===Cornerstone: Initiating Events=== | ===Cornerstone: Initiating Events=== | ||
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===Cornerstone: Mitigating Systems=== | ===Cornerstone: Mitigating Systems=== | ||
: '''Green.''' | : '''Green.''' | ||
The inspectors identified a Severity Level IV Non-Cited Violation associatedwith the failure to perform an adequate safety evaluation review as required by | The inspectors identified a Severity Level IV Non-Cited Violation associatedwith the failure to perform an adequate safety evaluation review as required by 10 CFR 50.59 for the changes made to the Updated Safety Analysis Report (USAR). | ||
CFR 50.59 for the changes made to the Updated Safety Analysis Report (USAR). | |||
In safety evaluation 1052, Revision 0, the licensee failed to provide a basis for the determination, that removing the maximum reactor vessel head lift elevation andreference to the associated load drop analysis calculation from the USAR, was acceptable without a license amendment. Specifically, the licensee determined that their load drop analysis was neither a regulatory requirement nor a licensing commitment and could be removed from the USAR. Within the 10 CFR 50.59 evaluation, the licensee failed to provide a basis for why the removal of this lift elevation restriction from the USAR did not present more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component important to safety 2if the reactor vessel head was dropped at an elevation higher than that evaluated in theload drop calculation with irradiated fuel in the reactor core. Because the issue affected the NRC's ability to perform its regulatory function, thisfinding was evaluated using the traditional enforcement process. The finding was determined to be more than minor because the inspectors could not reasonably determine that the USAR change, which had the potential to adversely affect equipmentimportant to safety, would not have ultimately required NRC approval. The finding wasdetermined to be of very low safety significance (Green) because the inspectors answered "no" to question 1 under the Mitigating Systems Cornerstone column of the | In safety evaluation 1052, Revision 0, the licensee failed to provide a basis for the determination, that removing the maximum reactor vessel head lift elevation andreference to the associated load drop analysis calculation from the USAR, was acceptable without a license amendment. Specifically, the licensee determined that their load drop analysis was neither a regulatory requirement nor a licensing commitment and could be removed from the USAR. Within the 10 CFR 50.59 evaluation, the licensee failed to provide a basis for why the removal of this lift elevation restriction from the USAR did not present more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component important to safety 2if the reactor vessel head was dropped at an elevation higher than that evaluated in theload drop calculation with irradiated fuel in the reactor core. Because the issue affected the NRC's ability to perform its regulatory function, thisfinding was evaluated using the traditional enforcement process. The finding was determined to be more than minor because the inspectors could not reasonably determine that the USAR change, which had the potential to adversely affect equipmentimportant to safety, would not have ultimately required NRC approval. The finding wasdetermined to be of very low safety significance (Green) because the inspectors answered "no" to question 1 under the Mitigating Systems Cornerstone column of the Phase 1 worksheet. Specifically, the licensee had not performed a reactor vessel head lift where the lift height was in excess of the elevation evaluated in their load drop analysis, and licensee maintenance procedures limited the maximum allowed reactor vessel head lift height to be less than the elevation evaluated in their load drop analysis.(Section 1R02.1.b.1) | ||
Phase 1 worksheet. Specifically, the licensee had not performed a reactor vessel head lift where the lift height was in excess of the elevation evaluated in their load drop analysis, and licensee maintenance procedures limited the maximum allowed reactor vessel head lift height to be less than the elevation evaluated in their load drop analysis.(Section 1R02.1.b.1) | |||
===Cornerstone: Occupational Radiation Safety=== | ===Cornerstone: Occupational Radiation Safety=== | ||
: '''Green.''' | : '''Green.''' | ||
A finding of very low safety significance and associated Non-Cited Violation(NCV) were inspector-identified during a walkdown in Unit 1 containment. The inspectors identified that a swing gate barrier to a High Radiation Area (HRA) was left in the open position due to misalignment of the gate in the stand. The licensee correctedthe barrier misalignment and verified other HRA barriers in containment were properly operating and positioned. Radiation workers in containment were not self-checking to assure that the barriers were placed back into the correct position after traversing the | A finding of very low safety significance and associated Non-Cited Violation(NCV) were inspector-identified during a walkdown in Unit 1 containment. The inspectors identified that a swing gate barrier to a High Radiation Area (HRA) was left in the open position due to misalignment of the gate in the stand. The licensee correctedthe barrier misalignment and verified other HRA barriers in containment were properly operating and positioned. Radiation workers in containment were not self-checking to assure that the barriers were placed back into the correct position after traversing the HRA. The licensee entered this finding into the corrective action program. The finding was more than minor because it was associated with the OccupationalRadiation Safety cornerstone, and potentially affected the cornerstone attribute of program and process for radiation worker performance. The finding was determined to be of very low safety significance because it did not involve an As-Low-As-Reasonably-Achievable (ALARA) issue, as collective dose was not a factor and no individual received an unintended dose as a result of the barrier non-compliance; there was not a substantial potential for a worker overexposure; and the licensee's ability to assessworker dose was not compromised. | ||
HRA. The licensee entered this finding into the corrective action program. The finding was more than minor because it was associated with the OccupationalRadiation Safety cornerstone, and potentially affected the cornerstone attribute of program and process for radiation worker performance. The finding was determined to be of very low safety significance because it did not involve an As-Low-As-Reasonably-Achievable (ALARA) issue, as collective dose was not a factor and no individual received an unintended dose as a result of the barrier non-compliance; there was not a substantial potential for a worker overexposure; and the licensee's ability to assessworker dose was not compromised. Since the principal cause of the problem was ahuman performance deficiency, the finding also relates to the cross-cutting area of human performance. (Section 2OS1)Green. A self-revealing finding of very low safety significance and associated NCV wereidentified when 110 radiation workers were contaminated as a result of opening steam generator manways during the Unit 1 1R24 refueling outage. Specific ALARA planning assessments did not acknowledge airborne concentrations of radioactivity may be subject to change. Additionally, the ALARA planning for this work did not consider the effect of engineering safety systems operation or malfunction on other work areas incontainment, consequently when the work area was set up and initial work commenced, the focus was on the immediate work area only, and the result was elevated iodine-131 levels throughout containment. The licensee evacuated containment, identified the source of airborne contamination, and repositioned and secured an air handling hose to | |||
Since the principal cause of the problem was ahuman performance deficiency, the finding also relates to the cross-cutting area of human performance. (Section 2OS1)Green. A self-revealing finding of very low safety significance and associated NCV wereidentified when 110 radiation workers were contaminated as a result of opening steam generator manways during the Unit 1 1R24 refueling outage. Specific ALARA planning assessments did not acknowledge airborne concentrations of radioactivity may be subject to change. Additionally, the ALARA planning for this work did not consider the effect of engineering safety systems operation or malfunction on other work areas incontainment, consequently when the work area was set up and initial work commenced, the focus was on the immediate work area only, and the result was elevated iodine-131 levels throughout containment. The licensee evacuated containment, identified the source of airborne contamination, and repositioned and secured an air handling hose to 3the containment clean-up filter. The event was entered into the licensee's correctiveaction program.The finding was more than minor because it was associated with the OccupationalRadiation Safety cornerstone, and potentially affected the cornerstone attribute of program and process for ALARA planning and exposure/contamination control. The finding was determined to be of very low safety significance because although the finding did involve an ALARA planning issue and resulted in unintended exposure to personnel, personnel doses were well below regulatory limits. (Section 2OS2) | |||
===Cornerstone: Public Radiation Safety=== | ===Cornerstone: Public Radiation Safety=== | ||
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Violations of very low safety significance, which were identified by the licensee, havebeen reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. The violations and corrective action tracking numbers are listed in Section 4OA7 of this report. | Violations of very low safety significance, which were identified by the licensee, havebeen reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. The violations and corrective action tracking numbers are listed in Section 4OA7 of this report. | ||
4 | |||
=REPORT DETAILS= | =REPORT DETAILS= | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
On May 2, 2006, the inspectors completed a detailed in-office review of the licensee'sprocedures and an in-plant walkdown of four systems to observe the licensee'spreparations for adverse weather conditions that could result from nearby tornados or high wind conditions. The inspectors performed a detailed review of the tornado and high winds hazard procedures; the Updated Safety Analysis Report (USAR); design basis documents for the Unit 1 and Unit 2 switchyard; and the Prairie Island Individual Plant Examination of External Events (IPEEE). The inspectors verified that required surveillance tests were scheduled and performed at the specified frequencies. During system walkdowns, the inspectors examined the material condition of major systemcomponents for evidence of system degradation. As part of this inspection, thedocuments in the Attachment were utilized to evaluate the potential for an inspection finding. The inspectors evaluated readiness for seasonal susceptibilities for the followingsystems, completing one inspection procedure sample:*the Unit 1 diesel generators D1and D2;*the plant substation system; | On May 2, 2006, the inspectors completed a detailed in-office review of the licensee'sprocedures and an in-plant walkdown of four systems to observe the licensee'spreparations for adverse weather conditions that could result from nearby tornados or high wind conditions. The inspectors performed a detailed review of the tornado and high winds hazard procedures; the Updated Safety Analysis Report (USAR); design basis documents for the Unit 1 and Unit 2 switchyard; and the Prairie Island Individual Plant Examination of External Events (IPEEE). The inspectors verified that required surveillance tests were scheduled and performed at the specified frequencies. During system walkdowns, the inspectors examined the material condition of major systemcomponents for evidence of system degradation. As part of this inspection, thedocuments in the Attachment were utilized to evaluate the potential for an inspection finding. The inspectors evaluated readiness for seasonal susceptibilities for the followingsystems, completing one inspection procedure sample:*the Unit 1 diesel generators D1and D2;*the plant substation system; | ||
*the cooling tower substation system including transformers CT-11 and CT-12; | *the cooling tower substation system including transformers CT-11 and CT-12; 5*auxiliary and standby transformer system; and *Unit 1 containment during periods when the containment hatch was removed.b.FindingsNo findings of significance were identified. | ||
5*auxiliary and standby transformer system; and *Unit 1 containment during periods when the containment hatch was removed.b.FindingsNo findings of significance were identified. | |||
===.2 Hot Weather Preparations=== | ===.2 Hot Weather Preparations=== | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
On June 16 through 20, 2006, the inspectors performed an in-office review of thesummer plant operation program; the USAR; applicable Technical Specifications (TS); | On June 16 through 20, 2006, the inspectors performed an in-office review of thesummer plant operation program; the USAR; applicable Technical Specifications (TS); | ||
and the Prairie Island IPEEE. This inspection effort completed the hot weather preparation inspection sample. The inspectors performed in-plant walkdowns of selected systems and verified that the as-found conditions of those systems wereconsistent with the description provided in the above documents. The inspectors performed in-plant walkdowns of the following risk-significant mitigating system supportsystems for a total of one inspection sample:*diesel generator D1 and D2 ventilation system;*diesel generator D5 and D6 | and the Prairie Island IPEEE. This inspection effort completed the hot weather preparation inspection sample. The inspectors performed in-plant walkdowns of selected systems and verified that the as-found conditions of those systems wereconsistent with the description provided in the above documents. The inspectors performed in-plant walkdowns of the following risk-significant mitigating system supportsystems for a total of one inspection sample:*diesel generator D1 and D2 ventilation system;*diesel generator D5 and D6 ventilati on system; and*instrument and service air system.The inspectors reviewed the selected systems and verified that the material conditions and system configurations supported the systems' availability and operability underadverse hot weather conditions, and verified that additional cooling equipment, where specified in the summer plant operation procedure, was available and operable. The inspectors also reviewed the correction action programs action requests (CAPs)listed in the Attachment to verify that the licensee was identifying adverse weatherissues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures. | ||
====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
{{a|1R02}} | |||
==1R02 Evaluation of Changes, Tests, or Experiments (71111.02)Reactor Vessel Head Replacement Inspection (71007)== | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
From April 24 through 28, 2006, from May 1 through 5, 2006, and fromMay 15 through 19, 2006, the inspectors reviewed the licensee's evaluations of applicability determination and screening questions for the design changesassociated with the Unit 1 reactor vessel closure head (RVCH) replacement to determine, for each change, whether the requirements of 10 CFR 50.59 had been | From April 24 through 28, 2006, from May 1 through 5, 2006, and fromMay 15 through 19, 2006, the inspectors reviewed the licensee's evaluations of applicability determination and screening questions for the design changesassociated with the Unit 1 reactor vessel closure head (RVCH) replacement to determine, for each change, whether the requirements of 10 CFR 50.59 had been 6appropriately applied. Screenings and evaluations reviewed for the Unit 2 RVCHreplacement (refer to IR 05000282/2005004; 05000306/2005004 (ML052020420)) that were also applicable to the Unit 1 RVCH replacement were not reviewed as part of this inspection. Specifically, the inspectors reviewed Part 1 of Design Change 03RV05, "Replace Unit 1 and 2 Reactor Vessel Heads and Associated Components," which included a review of the function of each changed component, the change description and scope of three 10 CFR 50.59 screenings for the:*reactor vessel head internal insulation;*reactor coolant gas vent system (RCGVS) and reactor vessel level indicationsystem (RVLIS) pipe and supports; and*abandonment of upper range RVLIS indication.The inspectors also reviewed three 10 CFR 50.59 screenings and one 10 CFR 50.59evaluation associated with the Unit 1 head assembly upgrade package (HAUP) to determine, for each change, whether the requirements of 10 CFR 50.59 had beenappropriately applied. Screenings reviewed for the Unit 2 HAUP installation (refer to IR 05000282/2005004; 05000306/2005004 (ML052020420)), that were also applicable to the Unit 1 HAUP installation, were not reviewed as part of this inspection. | ||
6appropriately applied. Screenings and evaluations reviewed for the Unit 2 RVCHreplacement (refer to IR 05000282/2005004; 05000306/2005004 (ML052020420)) that were also applicable to the Unit 1 RVCH replacement were not reviewed as part of this inspection. Specifically, the inspectors reviewed Part 1 of Design Change 03RV05, | |||
"Replace Unit 1 and 2 Reactor Vessel Heads and Associated Components," which included a review of the function of each changed component, the change description and scope of three 10 CFR 50.59 screenings for the:*reactor vessel head internal insulation;*reactor coolant gas vent system (RCGVS) and reactor vessel level indicationsystem (RVLIS) pipe and supports; and*abandonment of upper range RVLIS indication.The inspectors also reviewed three 10 CFR 50.59 screenings and one 10 CFR 50.59evaluation associated with the Unit 1 head assembly upgrade package (HAUP) to determine, for each change, whether the requirements of 10 CFR 50.59 had beenappropriately applied. Screenings reviewed for the Unit 2 HAUP installation (refer to IR 05000282/2005004; 05000306/2005004 (ML052020420)), that were also applicable to the Unit 1 HAUP installation, were not reviewed as part of this inspection. | |||
Specifically, the inspectors reviewed Part 2 of Design Change 03RV05, "Reactor Vessel Head Assembly Upgrade Package (HAUP)," which included a review of the function of each changed component, the change description, methods of analysis, and scope of the 10 CFR 50.59 screenings and the 10 CFR 50.59 evaluation for the:*reactor vessel control rod drive mechanism (CRDM) seismic platform, seismicspacer plate, adjustment plate assembly, cable supports;*CRDM cooling: coils, fans, pipe/pipe supports, and instrumentation and control;*evaluation of non-safety-related components for loss of coolant accident (LOCA)loads; and*heavy loads licensing bases.The inspectors used, in part, Nuclear Energy Institute (NEI) 96-07, "Guidelines for10 CFR 50.59 Implementation," to determine acceptability of the completed pre-screenings and screening. The NEI document was endorsed by the NRC inRegulatory Guide 1.187, "Guidance for Implementation of 10 CFR 50.59, Changes,Tests, and Experiments." The inspectors also consulted Part 9900 of the NRC Inspection Manual, "10 CFR Guidance for 10 CFR 50.59, Changes, Tests, and Experiments."The records reviewed by the inspectors are identified in the Attachment to this report. | Specifically, the inspectors reviewed Part 2 of Design Change 03RV05, "Reactor Vessel Head Assembly Upgrade Package (HAUP)," which included a review of the function of each changed component, the change description, methods of analysis, and scope of the 10 CFR 50.59 screenings and the 10 CFR 50.59 evaluation for the:*reactor vessel control rod drive mechanism (CRDM) seismic platform, seismicspacer plate, adjustment plate assembly, cable supports;*CRDM cooling: coils, fans, pipe/pipe supports, and instrumentation and control;*evaluation of non-safety-related components for loss of coolant accident (LOCA)loads; and*heavy loads licensing bases.The inspectors used, in part, Nuclear Energy Institute (NEI) 96-07, "Guidelines for10 CFR 50.59 Implementation," to determine acceptability of the completed pre-screenings and screening. The NEI document was endorsed by the NRC inRegulatory Guide 1.187, "Guidance for Implementation of 10 CFR 50.59, Changes,Tests, and Experiments." The inspectors also consulted Part 9900 of the NRC Inspection Manual, "10 CFR Guidance for 10 CFR 50.59, Changes, Tests, and Experiments."The records reviewed by the inspectors are identified in the Attachment to this report. | ||
====b. Findings==== | ====b. Findings==== | ||
USAR Change that Removed the Reactor Vessel Head Lift Elevation Limit andReference to the Associated Reactor Vessel Head Load Drop CalculationIntroduction: On April 19, 2006, the inspectors identified a Severity Level IV Non-CitedViolation (NCV) of very low safety significance (Green) for failing to perform anadequate safety evaluation in accordance with 10 CFR 50.59. Safety Evaluation 1052, | USAR Change that Removed the Reactor Vessel Head Lift Elevation Limit andReference to the Associated Reactor Vessel Head Load Drop CalculationIntroduction: On April 19, 2006, the inspectors identified a Severity Level IV Non-CitedViolation (NCV) of very low safety significance (Green) for failing to perform anadequate safety evaluation in accordance with 10 CFR 50.59. Safety Evaluation 1052, 7Revision 0, "Heavy Load Licensing Bases," involved a USAR change that removed themaximum reactor vessel head lift elevation restriction, and reference to the associated reactor vessel head load drop calculation that provided the design basis for the lift elevation limit. Within the safety evaluation, the licensee failed to provide a basis for why the removal of this lift elevation restriction from the USAR did not present more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component (SSC) important to safety if the reactor vessel head was droppedat an elevation higher than that evaluated in the load drop calculation with irradiated fuelin the reactor core. | ||
7Revision 0, "Heavy Load Licensing Bases," involved a USAR change that removed themaximum reactor vessel head lift elevation restriction, and reference to the associated reactor vessel head load drop calculation that provided the design basis for the lift elevation limit. Within the safety evaluation, the licensee failed to provide a basis for why the removal of this lift elevation restriction from the USAR did not present more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component (SSC) important to safety if the reactor vessel head was droppedat an elevation higher than that evaluated in the load drop calculation with irradiated fuelin the reactor core. | |||
=====Description:===== | =====Description:===== | ||
The licensee initiated 10 CFR 50.59 Safety Evaluation 1052 to support arevision to the USAR that removed the maximum reactor vessel head lift elevation restriction and reference to the associated reactor vessel head load drop calculation that provided the design basis for the lift elevation limit. As indicated in Safety Evaluation 1052, the NRC required licensees to determine the extent that guidelines inNUREG-0612, "Control of Heavy Loads at Nuclear Power Plants," were satisfied and toidentify changes and modifications that would be required to satisfy those guidelines (NRC Letter dated December 22, 1980, Subject: Control of Heavy Loads (GL 80-113);NRC Generic Letter (GL) 81-07; dated February 3, 1981, Control of Heavy Loads). Thelicensee responses were in two phases, Phase I and Phase II:Prairie Island Nuclear Generating Plant (PINGP) submitted their Phase I report tothe NRC, on August 31, 1981, with additional information provided in subsequentletters. NRC Safety Evaluation Report dated June 6, 1983, concluded thatPINGP satisfactorily complied with the Phase I requirements.For the Phase II response, the NRC requested that licensees submit informationon overhead cranes in the vicinity of spent fuel pools, in containment, and in plant areas containing equipment required for reactor shutdown, core decay heat removal, or spent fuel pool cooling (NUREG-0612 Sections 5.1.2, 5.1.3,and 5.1.5). With respect to the containment polar crane, NUREG-0612Section 5.1.3 required a single-failure proof crane, or as an alternative, analysis could be performed demonstrating that evaluation criteria listed in NUREG-012 Section 5.1 were satisfied. As part of their Phase II submittal (NSP Letter, dated December 9, 1981, Controlof Heavy Loads (9 Month Submittal)), PINGP outlined compliance with NUREG-0612 Guideline 5.1.3. This included a reactor head drop analysis that concluded both 4-inch diameter safety injection (SI) lines (reactor vessel injection) would remain functional, and thus, the capability was maintained to provide boratedwater to the reactor vessel to make up for any water due to boiling. This satisfiedCriterion III of Section 5.1 of NUREG-0612. On May 31, 1984, the NRC providedPINGP with a draft Technical Evaluation Report (TER) related to the Phase II submittal. The draft TER concluded that the information provided by PINGP indicates that Criterion III (uncovering of the core) have been satisfied in amanner consistent with the intent of NUREG-0612. No outstanding issues wereidentified in the draft TER related to the reactor head drop analysis. However, the NRC did not issue an official Safety Evaluation Report for the PINGP Phase IIsubmittal. | The licensee initiated 10 CFR 50.59 Safety Evaluation 1052 to support arevision to the USAR that removed the maximum reactor vessel head lift elevation restriction and reference to the associated reactor vessel head load drop calculation that provided the design basis for the lift elevation limit. As indicated in Safety Evaluation 1052, the NRC required licensees to determine the extent that guidelines inNUREG-0612, "Control of Heavy Loads at Nuclear Power Plants," were satisfied and toidentify changes and modifications that would be required to satisfy those guidelines (NRC Letter dated December 22, 1980, Subject: Control of Heavy Loads (GL 80-113);NRC Generic Letter (GL) 81-07; dated February 3, 1981, Control of Heavy Loads). Thelicensee responses were in two phases, Phase I and Phase II:Prairie Island Nuclear Generating Plant (PINGP) submitted their Phase I report tothe NRC, on August 31, 1981, with additional information provided in subsequentletters. NRC Safety Evaluation Report dated June 6, 1983, concluded thatPINGP satisfactorily complied with the Phase I requirements.For the Phase II response, the NRC requested that licensees submit informationon overhead cranes in the vicinity of spent fuel pools, in containment, and in plant areas containing equipment required for reactor shutdown, core decay heat removal, or spent fuel pool cooling (NUREG-0612 Sections 5.1.2, 5.1.3,and 5.1.5). With respect to the containment polar crane, NUREG-0612Section 5.1.3 required a single-failure proof crane, or as an alternative, analysis could be performed demonstrating that evaluation criteria listed in NUREG-012 Section 5.1 were satisfied. As part of their Phase II submittal (NSP Letter, dated December 9, 1981, Controlof Heavy Loads (9 Month Submittal)), PINGP outlined compliance with NUREG-0612 Guideline 5.1.3. This included a reactor head drop analysis that concluded both 4-inch diameter safety injection (SI) lines (reactor vessel injection) would remain functional, and thus, the capability was maintained to provide boratedwater to the reactor vessel to make up for any water due to boiling. This satisfiedCriterion III of Section 5.1 of NUREG-0612. On May 31, 1984, the NRC providedPINGP with a draft Technical Evaluation Report (TER) related to the Phase II submittal. The draft TER concluded that the information provided by PINGP indicates that Criterion III (uncovering of the core) have been satisfied in amanner consistent with the intent of NUREG-0612. No outstanding issues wereidentified in the draft TER related to the reactor head drop analysis. However, the NRC did not issue an official Safety Evaluation Report for the PINGP Phase IIsubmittal. | ||
8In Safety Evaluation 1052, the licensee concluded that actions provided in theirPhase I submittal were part of their licensing basis, but actions provided to the NRC in their Phase II submittal were not part of their licensing basis based on GL 85-11, | 8In Safety Evaluation 1052, the licensee concluded that actions provided in theirPhase I submittal were part of their licensing basis, but actions provided to the NRC in their Phase II submittal were not part of their licensing basis based on GL 85-11, "Clarification of Response to the Heavy Loads Phase II Technical Evaluation Report," | ||
"Clarification of Response to the Heavy Loads Phase II Technical Evaluation Report," | |||
and NUREG-1774, "Survey of Crane operating Experience at US Nuclear PowerPlants from 1968 through 2002." The licensee also concluded that GL 85-11 relieved licensees from performing the actions requested under Phase II and rescinded the requirement to perform a Phase II review requested in GL 80-113 and GL 81-07. Safety Evaluation 1052 further concluded that maintaining an analysis of a postulated drop of the reactor vessel head was neither a regulatory requirement nor a licensing commitment for PINGP. As a result, the licensee revised the USAR to remove the maximum reactor vessel head lift elevation restriction and reference to the associated reactor vessel head load drop calculation that provided the design basis for the lift elevation limit. The inspectors reviewed NRC Regulatory Issue Summary (RIS) 2005-25, "Clarification ofNRC Guidelines for Control of Heavy Loads," dated October 31, 2005. Clarifications andrelated information provided by RIS 2005-25 include:*In GL 85-11, the NRC staff concluded that a detailed review (NRC detailedreview) of the Phase II responses received by the licensee was not necessary based on an NRC staff pilot review of Phase II responses. Although, the NRCstaff concluded that the cost to install a single-failure-proof crane was not justified on a generic basis, the NRC staff encouraged licensees to determine andimplement appropriate actions to provide adequate safety. In GL 85-11, the NRC staff did not relieve licensees from performing the actions requested under Phase II nor rescind the requirement to perform a Phase II review. *Phase II guidelines addressed alternatives to reduce the consequences of heavyload drops. One option was to perform a load drop and consequence analysis to assess the impact of dropped loads on plant safety and operations. *The NRC Advisory Committee on Reactor Safeguards, in a letter datedSeptember 24, 2003, (ML032681205) endorsed the recommendation to evaluatethe need to establish standardized calculation methodologies for heavy load drops. As noted in RIS 2005-25, Enclosure 1, PINGP revised their load drop analysis due to assumptions and methodology that were determined to be non-conservative and reduced the maximum reactor vessel head lift elevation indicated in the USAR (refer to IR 05000282/2005004; 05000306/2005004 (ML052020420)).The inspectors determined that based on RIS 2005-25 clarifications, the PINGP loaddrop analysis was part of the design basis that determined SSCs important to safety, the 4-inch SI lines, would remain functional after a postulated load drop. Although the USAR had been changed to remove the reactor vessel head lift elevation limit and the reference to the associated reactor vessel head load drop calculation, the reactor vessel head lift elevation limit established by the reactor vessel head load drop analysis was still controlled by the licensee in maintenance procedures. | and NUREG-1774, "Survey of Crane operating Experience at US Nuclear PowerPlants from 1968 through 2002." The licensee also concluded that GL 85-11 relieved licensees from performing the actions requested under Phase II and rescinded the requirement to perform a Phase II review requested in GL 80-113 and GL 81-07. Safety Evaluation 1052 further concluded that maintaining an analysis of a postulated drop of the reactor vessel head was neither a regulatory requirement nor a licensing commitment for PINGP. As a result, the licensee revised the USAR to remove the maximum reactor vessel head lift elevation restriction and reference to the associated reactor vessel head load drop calculation that provided the design basis for the lift elevation limit. The inspectors reviewed NRC Regulatory Issue Summary (RIS) 2005-25, "Clarification ofNRC Guidelines for Control of Heavy Loads," dated October 31, 2005. Clarifications andrelated information provided by RIS 2005-25 include:*In GL 85-11, the NRC staff concluded that a detailed review (NRC detailedreview) of the Phase II responses received by the licensee was not necessary based on an NRC staff pilot review of Phase II responses. Although, the NRCstaff concluded that the cost to install a single-failure-proof crane was not justified on a generic basis, the NRC staff encouraged licensees to determine andimplement appropriate actions to provide adequate safety. In GL 85-11, the NRC staff did not relieve licensees from performing the actions requested under Phase II nor rescind the requirement to perform a Phase II review. *Phase II guidelines addressed alternatives to reduce the consequences of heavyload drops. One option was to perform a load drop and consequence analysis to assess the impact of dropped loads on plant safety and operations. *The NRC Advisory Committee on Reactor Safeguards, in a letter datedSeptember 24, 2003, (ML032681205) endorsed the recommendation to evaluatethe need to establish standardized calculation methodologies for heavy load drops. As noted in RIS 2005-25, Enclosure 1, PINGP revised their load drop analysis due to assumptions and methodology that were determined to be non-conservative and reduced the maximum reactor vessel head lift elevation indicated in the USAR (refer to IR 05000282/2005004; 05000306/2005004 (ML052020420)).The inspectors determined that based on RIS 2005-25 clarifications, the PINGP loaddrop analysis was part of the design basis that determined SSCs important to safety, the 4-inch SI lines, would remain functional after a postulated load drop. Although the USAR had been changed to remove the reactor vessel head lift elevation limit and the reference to the associated reactor vessel head load drop calculation, the reactor vessel head lift elevation limit established by the reactor vessel head load drop analysis was still controlled by the licensee in maintenance procedures. | ||
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10Contrary to the above, in Safety Evaluation 1052, Revision 0, the licensee failed toprovide an adequate basis for the determination that removal of the maximum reactorvessel head lift elevation restriction and reference to the associated reactor vessel head load drop calculation from the USAR was acceptable without a license amendment. | 10Contrary to the above, in Safety Evaluation 1052, Revision 0, the licensee failed toprovide an adequate basis for the determination that removal of the maximum reactorvessel head lift elevation restriction and reference to the associated reactor vessel head load drop calculation from the USAR was acceptable without a license amendment. | ||
Specifically, the change in the USAR coupled with conclusion of Safety Evaluation 1052 that the reactor vessel head load drop analysis was neither a regulatory requirement nora licensing commitment may have resulted in removal of the reactor vessel head lift elevation restriction from maintenance procedures without determining the potentialconsequences of a postulated reactor vessel head load drop. Within the 10 CFR 50.59 evaluation, the licensee failed to provide a basis for why removal of the reactor vessel head lift elevation limit and reference to the associated reactor vessel head load drop calculation did not present more than a minimal increase in the likelihood of occurrence of a malfunction of an SSC important to safety if the reactor vessel head was dropped at an elevation higher than that evaluated in the load drop calculation with irradiated fuel inthe reactor core. In accordance with the Enforcement Policy, this violation of the requirements of 10 CFR 50.59 was classified as a Severity Level IV Violation because the underlying technical issue was of very low safety significance. Because this non-willful violation was non-repetitive, and was captured in the licensee's correctiveaction program (CAP 01030355), it is considered an NCV consistent with VI.A.1 of the NRC Enforcement Policy. (NCV 05000282/2006003-01; 05000306/2006003-01). | Specifically, the change in the USAR coupled with conclusion of Safety Evaluation 1052 that the reactor vessel head load drop analysis was neither a regulatory requirement nora licensing commitment may have resulted in removal of the reactor vessel head lift elevation restriction from maintenance procedures without determining the potentialconsequences of a postulated reactor vessel head load drop. Within the 10 CFR 50.59 evaluation, the licensee failed to provide a basis for why removal of the reactor vessel head lift elevation limit and reference to the associated reactor vessel head load drop calculation did not present more than a minimal increase in the likelihood of occurrence of a malfunction of an SSC important to safety if the reactor vessel head was dropped at an elevation higher than that evaluated in the load drop calculation with irradiated fuel inthe reactor core. In accordance with the Enforcement Policy, this violation of the requirements of 10 CFR 50.59 was classified as a Severity Level IV Violation because the underlying technical issue was of very low safety significance. Because this | ||
non-willful violation was non-repetitive, and was captured in the licensee's correctiveaction program (CAP 01030355), it is considered an NCV consistent with VI.A.1 of the NRC Enforcement Policy. (NCV 05000282/2006003-01; 05000306/2006003-01). | |||
{{a|1R04}} | {{a|1R04}} | ||
==1R04 Equipment Alignment== | ==1R04 Equipment Alignment== | ||
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The inspectors performed three partial system equipment alignment inspection samplescomprised of in-plant walkdowns of accessible portions of trains of risk-significant equipment associated with the mitigating systems and barrier integrity cornerstones. The inspectors conducted the inspections during times when the trains were of increased importance due to the redundant trains or other related equipment being unavailable. The inspectors also reviewed documents entering deficient conditions associated with equipment alignment issues into the corrective action program verifying that the licensee was identifying issues at an appropriate threshold and entering those issues into their corrective action program in accordance with the fleet corrective action procedures.The inspectors utilized the valve and electric breaker checklists, where applicable, toverify that the components were properly positioned and that support systems were linedup as needed. The inspectors also examined the material condition of the components and observed operating parameters of equipment to verify that there were no obviousperformance deficiencies. The inspectors reviewed outstanding work orders (WOs) and CAPs associated with the operable trains to verify that those documents did not revealissues that could affect the completion of the available train's safety functions. The inspectors used the information in the appropriate sections of the USAR to determine thefunctional requirements of the systems. | The inspectors performed three partial system equipment alignment inspection samplescomprised of in-plant walkdowns of accessible portions of trains of risk-significant equipment associated with the mitigating systems and barrier integrity cornerstones. The inspectors conducted the inspections during times when the trains were of increased importance due to the redundant trains or other related equipment being unavailable. The inspectors also reviewed documents entering deficient conditions associated with equipment alignment issues into the corrective action program verifying that the licensee was identifying issues at an appropriate threshold and entering those issues into their corrective action program in accordance with the fleet corrective action procedures.The inspectors utilized the valve and electric breaker checklists, where applicable, toverify that the components were properly positioned and that support systems were linedup as needed. The inspectors also examined the material condition of the components and observed operating parameters of equipment to verify that there were no obviousperformance deficiencies. The inspectors reviewed outstanding work orders (WOs) and CAPs associated with the operable trains to verify that those documents did not revealissues that could affect the completion of the available train's safety functions. The inspectors used the information in the appropriate sections of the USAR to determine thefunctional requirements of the systems. | ||
11The inspectors verified the alignment of the following trains: | 11The inspectors verified the alignment of the following trains: | ||
*D1 diesel generator during the unavailability of the D2 diesel generator forplanned maintenance on April 12, 2006;*12 motor-driven AFW pump during the unavailability of the 11 turbine-driven AFWpump on June 14, 2006; and*D6 diesel generator during the unavailability of the D5 diesel generator forplanned maintenance on June 19, 2006.Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report. | |||
====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
{{a|1R05}} | |||
==1R05 Fire Protection Area Walkdowns (71111.05)== | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
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====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
{{a|1R07}} | |||
==1R07 Heat Sink Performance (71111.07)== | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
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===.2 Pressurized Water Reactor Vessel Upper Head Penetration Inspection ActivitiesThe inspectors were unable to review Unit 1 upper head penetration inspection activitiesbecause none were performed.=== | ===.2 Pressurized Water Reactor Vessel Upper Head Penetration Inspection ActivitiesThe inspectors were unable to review Unit 1 upper head penetration inspection activitiesbecause none were performed.=== | ||
Instead, the licensee replaced the upper head this outage. | Instead, the licensee replaced the upper head this | ||
outage. | |||
14Because this was not available for inspection, this was not counted as a completedinspection sample. | 14Because this was not available for inspection, this was not counted as a completedinspection sample. | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
On April 29, 2006, through May 11, 2006, the inspectors reviewed the Unit 1 Boric AcidCorrosion Control (BACC) inspection activities conducted pursuant to licensee commitments made in response to NRC Generic Letter 88-05, "Boric Acid Corrosion ofCarbon Steel Reactor Pressure Boundary." Plant engineers commenced an examination of the reactor coolant and the other borated systems on April 29, 2006, while the reactorwas in Mode 3 and reactor coolant system was at pressure, to evaluate compliance withlicensee BACC program requirements. The inspectors observed the licensee during the performance of BACC visual examinations conducted in accordance with SurveillanceProcedure (SP) 1405. Specifically, the inspectors observed these examinations to determine if the licensee focused on locations where boric acid leaks can cause degradation of safety significant components.Additionally, the inspectors independently identified three reactor coolant system valveswith minor boric acid leakage. The inspectors verified that the licensee had also identified the condition of the three valves as degraded or non-conforming and entered those conditions into their corrective action program in accordance with the licensee's corrective action program procedure and 10 CFR Part 50, Appendix B, Criterion XVI, | On April 29, 2006, through May 11, 2006, the inspectors reviewed the Unit 1 Boric AcidCorrosion Control (BACC) inspection activities conducted pursuant to licensee commitments made in response to NRC Generic Letter 88-05, "Boric Acid Corrosion ofCarbon Steel Reactor Pressure Boundary." Plant engineers commenced an examination of the reactor coolant and the other borated systems on April 29, 2006, while the reactorwas in Mode 3 and reactor coolant system was at pressure, to evaluate compliance withlicensee BACC program requirements. The inspectors observed the licensee during the performance of BACC visual examinations conducted in accordance with SurveillanceProcedure (SP) 1405. Specifically, the inspectors observed these examinations to determine if the licensee focused on locations where boric acid leaks can cause degradation of safety significant components.Additionally, the inspectors independently identified three reactor coolant system valveswith minor boric acid leakage. The inspectors verified that the licensee had also identified the condition of the three valves as degraded or non-conforming and entered those conditions into their corrective action program in accordance with the licensee's corrective action program procedure and 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requirements.The inspectors reviewed engineering evaluations performed for a boric acid packing leakfound on the 11 RHR heat exchanger outlet valve (RH-10-2) to verify that the minimumdesign code required section thickness had been maintained for the affected component(s). Specifically, the inspectors reviewed:*Operability Recommendation CAP 042581. The inspectors reviewed licensee corrective actions implemented for evidence of boricacid leakage to confirm that they were consistent with requirements of Section XI of the ASME Code and 10 CFR Part 50, Appendix B, Criterion XVI. The documents reviewed during this inspection are listed in the Attachment to this report. | ||
"Corrective Action," requirements.The inspectors reviewed engineering evaluations performed for a boric acid packing leakfound on the 11 RHR heat exchanger outlet valve (RH-10-2) to verify that the minimumdesign code required section thickness had been maintained for the affected component(s). Specifically, the inspectors reviewed:*Operability Recommendation CAP 042581. The inspectors reviewed licensee corrective actions implemented for evidence of boricacid leakage to confirm that they were consistent with requirements of Section XI of the ASME Code and 10 CFR Part 50, Appendix B, Criterion XVI. The documents reviewed during this inspection are listed in the Attachment to this report. | |||
The reviews, as discussed above, counted as one inspection sample. | The reviews, as discussed above, counted as one inspection sample. | ||
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====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
===.4 Unit 1 Steam Generator (SG) Tube Inspection Activities=== | ===.4 Unit 1 Steam Generator (SG) Tube Inspection Activities=== | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
This was the first refueling outage (U1R24) since the 2004 (U1R23) SG replacement withthermally treated Alloy 690 tubes. The minimum inspection requirement was therefore used as reflected in the procedure steps inspected below. The NRC inspectors observed acquisition of eddy current (ET) data, interviewed ET dataanalysts, and reviewed a sample of documents related to the SG ISI program to determine if:*Procedure 71111.08, Step 02.04.a.1 and Step 02.04.a.2, the in-situ screeningcriteria, were in accordance with the Electric Power Research Institute (EPRI)guidelines and the appropriate tubes were to be in-situ pressure tested;*Procedure 71111.08, Step 02.04.c, the SG tube ET examination scope andexpansion criteria were sufficient to identify tube degradation based onsite and industry operating experience by confirming that the ET scope completed was consistent with the licensee's procedures, plant TS requirements and EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines," | This was the first refueling outage (U1R24) since the 2004 (U1R23) SG replacement withthermally treated Alloy 690 tubes. The minimum inspection requirement was therefore used as reflected in the procedure steps inspected below. The NRC inspectors observed acquisition of eddy current (ET) data, interviewed ET dataanalysts, and reviewed a sample of documents related to the SG ISI program to determine if:*Procedure 71111.08, Step 02.04.a.1 and Step 02.04.a.2, the in-situ screeningcriteria, were in accordance with the Electric Power Research Institute (EPRI)guidelines and the appropriate tubes were to be in-situ pressure tested;*Procedure 71111.08, Step 02.04.c, the SG tube ET examination scope andexpansion criteria were sufficient to identify tube degradation based onsite and industry operating experience by confirming that the ET scope completed was consistent with the licensee's procedures, plant TS requirements and EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines," | ||
Revision 6;*Procedure 71111.08, Step 02.04.g.(1), the TS plugging limit is being adhered to;*Procedure 71111.08, Step 02.04.I, the ET probes and equipment configurationsused to acquire data from the SG tubes were qualified to detect the known/expected types of SG tube degradation in accordance with Appendix H, | Revision 6;*Procedure 71111.08, Step 02.04.g.(1), the TS plugging limit is being adhered to;*Procedure 71111.08, Step 02.04.I, the ET probes and equipment configurationsused to acquire data from the SG tubes were qualified to detect the known/expected types of SG tube degradation in accordance with Appendix H, "Performance Demonstration for Eddy Current Examination," of EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines," | ||
"Performance Demonstration for Eddy Current Examination," of EPRI 1003138, | |||
"Pressurized Water Reactor Steam Generator Examination Guidelines," | |||
Revision 6; and*Procedure 71111.08, Step 02.04.j, the licensee performed evaluations forunretrievable loose parts.Activities which were not applicable during this inspection are as follows: | Revision 6; and*Procedure 71111.08, Step 02.04.j, the licensee performed evaluations forunretrievable loose parts.Activities which were not applicable during this inspection are as follows: | ||
*Procedure 71111.08, Steps 02.04.a.3 and 02.04.a.4, In-situ Pressure Testing,were not available for review, because none of the SG tubes examined during the current refueling outage met the screening requirements for pressure testing;*Procedure 71111.08, Step 02.04.d, new tube degradation mechanisms were notavailable for review because none were present; and*Procedure 71111.08, Step 02.04.h, the primary-to-secondary leakage,(e.g., SG tube leakage) was not available for review, because primary-to-secondary leakage did not exceed 3 gallons per day during operations or during post-shutdown visuals.The reviews, as discussed above, counted as one inspection sample. | *Procedure 71111.08, Steps 02.04.a.3 and 02.04.a.4, In-situ Pressure Testing,were not available for review, because none of the SG tubes examined during the current refueling outage met the screening requirements for pressure testing;*Procedure 71111.08, Step 02.04.d, new tube degradation mechanisms were notavailable for review because none were present; and*Procedure 71111.08, Step 02.04.h, the primary-to-secondary leakage,(e.g., SG tube leakage) was not available for review, because primary-to-secondary leakage did not exceed 3 gallons per day during operations or during post-shutdown visuals.The reviews, as discussed above, counted as one inspection sample. | ||
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====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
===.5 Identification and Resolution of Problems=== | ===.5 Identification and Resolution of Problems=== | ||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
The inspectors reviewed a sample of ISI/SG related problems documented in thelicensee's corrective action program to assess conformance with 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report. In addition, the inspectors verified that the licensee correctly assessed operating experiencefor applicability to the Inservice Inspection | The inspectors reviewed a sample of ISI/SG related problems documented in thelicensee's corrective action program to assess conformance with 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report. In addition, the inspectors verified that the licensee correctly assessed operating experiencefor applicability to the Inservice Inspection Gr oup. | ||
====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
{{a|1R11}} | |||
==1R11 Licensed Operator Requalification (71111.11)== | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
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====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
{{a|1R12}} | |||
==1R12 Maintenance Effectiveness (71111.12)== | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
The inspectors reviewed repetitive maintenance activities to assess maintenanceeffectiveness, including maintenance rule (10 CFR 50.65) activities, work practices, and common cause issues. The inspectors performed one issue/problem-oriented | The inspectors reviewed repetitive maintenance activities to assess maintenanceeffectiveness, including maintenance rule (10 CFR 50.65) activities, work practices, and common cause issues. The inspectors performed one issue/problem-oriented 17maintenance effectiveness sample. The inspectors assessed the licensee'smaintenance effectiveness associated with problems on the station and instrument air system.The inspectors conducted in-office reviews of the licensee's maintenance ruleevaluations of equipment failures for maintenance preventable functional failures and equipment unavailability time calculations, comparing the licensee's evaluationconclusions to applicable Maintenance Rule (a)1 performance criteria. Additionally, the inspectors reviewed scoping, goal-setting (where applicable), performance monitoring, short-term and long-term corrective actions, functional failure definitions, and current equipment performance status.The inspectors reviewed CAPs for significant equipment failures associated with risk-significant and safety-related mitigating equipment to ensure that those failures wereproperly identified, classified, and corrected. The inspectors reviewed other CAPs to assess the licensee's problem identification threshold for degraded conditions, the appropriateness of specified corrective actions, and that the timeliness of the implementation of corrective actions were commensurate with the safety significance of the identified issues. Key documents used by the inspectors in conducting this inspection are listed in the Attachment to this report. | ||
17maintenance effectiveness sample. The inspectors assessed the licensee'smaintenance effectiveness associated with problems on the station and instrument air system.The inspectors conducted in-office reviews of the licensee's maintenance ruleevaluations of equipment failures for maintenance preventable functional failures and equipment unavailability time calculations, comparing the licensee's evaluationconclusions to applicable Maintenance Rule (a)1 performance criteria. Additionally, the inspectors reviewed scoping, goal-setting (where applicable), performance monitoring, short-term and long-term corrective actions, functional failure definitions, and current equipment performance status.The inspectors reviewed CAPs for significant equipment failures associated with risk-significant and safety-related mitigating equipment to ensure that those failures wereproperly identified, classified, and corrected. The inspectors reviewed other CAPs to assess the licensee's problem identification threshold for degraded conditions, the appropriateness of specified corrective actions, and that the timeliness of the implementation of corrective actions were commensurate with the safety significance of the identified issues. Key documents used by the inspectors in conducting this inspection are listed in the Attachment to this report. | |||
====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
{{a|1R13}} | |||
==1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)== | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
The inspectors conducted in-plant walkdowns and in-office reviews of risk assessmentsfor five planned maintenance activities and four maintenance activities that involved emergent equipment failures with the following combinations of equipment unavailabilitycompleting nine risk assessment and emergent work control inspection samples:*the emergent unavailability of the Unit 2 volume control tank level transmitterconcurrent with the planned unavailability of the 122 instrument air compressoron April 5, 2006;*the emergent unavailability of the Unit 2 red channel reactor coolant flowinstrument 2FI-411 concurrent with the planned unavailability of the 23 chargingpump and the 122 instrument air compressor on April 13, 2006;*the planned unavailability of the 11 RHR pump and the 11 condensate pump onApril 24, 2006;*the planned unavailability of the 11 safety injection pump, 121 instrument aircompressor, and the 11 condensate pump on April 28, 2006;*the planned unavailability of diesel generator D2 and the 480 volt electrical loadtransfers from bus 16 to bus 26 on May 5, 2006;*the planned unavailability of diesel generator D2, 11 cooling water pump, bus 16,and the 12 AFW pump on May 8, 2006; | The inspectors conducted in-plant walkdowns and in-office reviews of risk assessmentsfor five planned maintenance activities and four maintenance activities that involved emergent equipment failures with the following combinations of equipment unavailabilitycompleting nine risk assessment and emergent work control inspection samples:*the emergent unavailability of the Unit 2 volume control tank level transmitterconcurrent with the planned unavailability of the 122 instrument air compressoron April 5, 2006;*the emergent unavailability of the Unit 2 red channel reactor coolant flowinstrument 2FI-411 concurrent with the planned unavailability of the 23 chargingpump and the 122 instrument air compressor on April 13, 2006;*the planned unavailability of the 11 RHR pump and the 11 condensate pump onApril 24, 2006;*the planned unavailability of the 11 safety injection pump, 121 instrument aircompressor, and the 11 condensate pump on April 28, 2006;*the planned unavailability of diesel generator D2 and the 480 volt electrical loadtransfers from bus 16 to bus 26 on May 5, 2006;*the planned unavailability of diesel generator D2, 11 cooling water pump, bus 16,and the 12 AFW pump on May 8, 2006; 18*the emergent unavailability of the 121 instrument air compressor concurrent withthe planned unavailability of diesel generator D2, 11 cooling water pump, bus 16,and the 12 AFW pump on May 9, 2006;*the emergent unavailability of the 11 turbine-driven AFW pump concurrent withthe planned unavailability of the 122 instrument air compressor on June 15, 2006; and*the planned unavailability of the 11 charging pump and the 11 RHR heatexchanger outlet to the 11 containment spray pump valve MV-32096 on June 28, 2006. | ||
18*the emergent unavailability of the 121 instrument air compressor concurrent withthe planned unavailability of diesel generator D2, 11 cooling water pump, bus 16,and the 12 AFW pump on May 9, 2006;*the emergent unavailability of the 11 turbine-driven AFW pump concurrent withthe planned unavailability of the 122 instrument air compressor on June 15, 2006;and*the planned unavailability of the 11 charging pump and the 11 RHR heatexchanger outlet to the 11 containment spray pump valve MV-32096 on June 28, 2006. | |||
====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
{{a|1R14}} | |||
==1R14 Personnel Performance Related to Non-Routine Plant Evolutions and Events (71111.14)Operator Performance Following a Loss of the 11 Condensate Pump and ResultingUnit 1 Reactor Trip== | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
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====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
{{a|1R15}} | |||
==1R15 Operability Evaluations (71111.15)== | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
The inspectors reviewed the technical adequacy of five operability evaluations completingfive operability evaluation inspection samples. The inspectors conducted theseinspections by in-office review of associated documents and in-plant walkdowns of affected areas and plant equipment. The inspectors compared degraded or nonconforming conditions of risk-significant SSCsassociated with barrier and mitigating systems and against the functional requirementsdescribed in the TS, USAR, and other design basis documents; determined whether | The inspectors reviewed the technical adequacy of five operability evaluations completingfive operability evaluation inspection samples. The inspectors conducted theseinspections by in-office review of associated documents and in-plant walkdowns of affected areas and plant equipment. The inspectors compared degraded or nonconforming conditions of risk-significant SSCsassociated with barrier and mitigating systems and against the functional requirementsdescribed in the TS, USAR, and other design basis documents; determined whether 19compensatory measures, if needed, were implemented; and determined whetherthe evaluation was consistent with the requirements of Administrative Work Instruction 5AWI 3.15.5, "Operability Determinations." The following operability evaluations werereviewed by inspectors:*prompt and historical operability determinations contained in CAP 01011542 forloose material found in Unit 1 RHR pump pit flood drainage path on May 8, 2006;*Operability Recommendation (OPR) 01029449 that documented the operability of4 kilovolt switchgear with non-safety-related parts used in safety-related applications on May 15, 2006;*OPR 000531 that documented a missed inservice test on the Unit 1 volumecontrol tank relief valve, VC-24-1, on May 30, 2006;OPR 01033009 that documented the operability of Unit 1 feedwater piping withdiscrepancies on pipe support 1-FWH-35, restraints 2 and 10, on May 31, 2006; | ||
andOPR 01034749 that documented the operability of the 11 turbine-drivenAFW pump with higher than normal turbine outboard bearing temperature, on June 6, 2006.The documents reviewed by the inspectors are listed in the Attachment to this report. | |||
====b. Findings==== | ====b. Findings==== | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
The inspectors assessed post-maintenance testing completing six post-maintenance testinspection samples. The inspectors selected post-maintenance tests associated with important mitigating and barrier integrity systems to ensure that the testing wasperformed adequately, demonstrated that the maintenance was successful, and thatoperability of associated equipment and/or systems was restored. The inspectorsconducted these inspections by in-office review of documents and in-plant walkdowns of associated plant equipment. The inspectors observed and assessed the post-maintenance testing activities for the following maintenance activities:diesel generator D2 cylinder liner replacement on May 15, 2006;replacement of the inlet check valve on the back up air supply accumulator forCV-31998, 11 turbine-driven AFW pump steam supply control valve on May 31, 2006;repacking of 11 turbine-driven AFW pump valves AF-13-3, pump discharge valveand CV-31998, main steam supply control valve, on June 2, 2006;*CV-31235, 11 RHR heat exchanger reactor coolant outlet following repair of aboric acid leak on the valve, on June 2, 2006;*replacement of 1N36, intermediate range nuclear instrument, high voltage andcompensating voltage cables on June 5, 2006; and | The inspectors assessed post-maintenance testing completing six post-maintenance testinspection samples. The inspectors selected post-maintenance tests associated with important mitigating and barrier integrity systems to ensure that the testing wasperformed adequately, demonstrated that the maintenance was successful, and thatoperability of associated equipment and/or systems was restored. The inspectorsconducted these inspections by in-office review of documents and in-plant walkdowns of associated plant equipment. The inspectors observed and assessed the post-maintenance testing activities for the following maintenance activities:diesel generator D2 cylinder liner replacement on May 15, 2006;replacement of the inlet check valve on the back up air supply accumulator forCV-31998, 11 turbine-driven AFW pump steam supply control valve on May 31, 2006;repacking of 11 turbine-driven AFW pump valves AF-13-3, pump discharge valveand CV-31998, main steam supply control valve, on June 2, 2006;*CV-31235, 11 RHR heat exchanger reactor coolant outlet following repair of aboric acid leak on the valve, on June 2, 2006;*replacement of 1N36, intermediate range nuclear instrument, high voltage andcompensating voltage cables on June 5, 2006; and 20*11 turbine-driven AFW pump following replacement of a turbine bearing onJune 11, 2006.The inspectors reviewed the appropriate sections of the TS, USAR, and maintenancedocuments to determine the systems' safety functions and the scope of the maintenance. The inspectors also reviewed CAPs to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with fleet corrective action procedures. Key documents used by the inspectors in conducting this inspection are listed in the Attachment to this report. | ||
20*11 turbine-driven AFW pump following replacement of a turbine bearing onJune 11, 2006.The inspectors reviewed the appropriate sections of the TS, USAR, and maintenancedocuments to determine the systems' safety functions and the scope of the maintenance. The inspectors also reviewed CAPs to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with fleet corrective action procedures. Key documents used by the inspectors in conducting this inspection are listed in the Attachment to this report. | |||
====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
{{a|1R20}} | |||
==1R20 Refueling and Other Outage Activities (71111.20)== | |||
===.1 Condensate Pump Trip Forced Outage=== | ===.1 Condensate Pump Trip Forced Outage=== | ||
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====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
{{a|1R22}} | |||
==1R22 Surveillance Testing (71111.22)== | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
During this inspection period, the inspectors completed ten surveillance inspectionsamples. Observation of SPs 1088A and 1106C completed the quarterly inservicetesting inspection requirement of a risk-significant pump or valve; SPs 1405 and 1070 | During this inspection period, the inspectors completed ten surveillance inspectionsamples. Observation of SPs 1088A and 1106C completed the quarterly inservicetesting inspection requirement of a risk-significant pump or valve; SPs 1405 and 1070 22completed two reactor cool ant system leakage inspection requirements; SP 1405 alsocompleted Inspection Procedure 71111.08, Section 02.03.a and 02.03.b inspectionrequirements; and SP 1072.45 completed the requirement to select a containment isolation valve each refueling cycle. The inspectors selected the following surveillance testing activities as samples:*SP 2093, D5 Diesel Generator Monthly on April 21, 2006;*SP 1405, Unit 1 Mid-Cycle and Refueling Outage Boric Acid CorrosionExaminations Inside Containment on April 28, 2006;*SP 1088A, Train A Safety Injection Quarterly Test on April 28, 2006; | ||
22completed two reactor | |||
*SP 1092B and C, Safety Injection Check Valve Test, on May 5, 2006; SP 1126, Turbine Building Cooling Water Header Isolation Safety Injection Relays1SI-12X and 1SI-22X Contact Verification Test on May 14, 2006;SP 1072.45, Local Leakage Rate Test of Penetration 45 (Reactor WaterMakeup), on May 18, 2006;SP 1106C; 121 Cooling Water Pump Quarterly Test on May 25, 2006;SP 1083, Unit 1 Integrated Safety Injection Test with a Simulated Loss of OffsitePower, on May 27, 2006;SP 1750, Post-Outage Containment Closeout Inspection on June 1, 2006; andSP 1070, Reactor Coolant System Integrity Test on June 3, 2006.During completion of the inspection samples, the inspectors observed in-plant activitiesand reviewed procedures and associated records to verify that:* preconditioning did not occur;* effects of the testing had been adequately addressed by control room personnelor engineers prior to the commencement of the testing;* acceptance criteria was clearly stated, demonstrated operational readiness, andwas consistent with the system design basis;* plant equipment calibration was correct, accurate, properly documented, and thecalibration frequency was in accordance with TS, USAR, procedures, and applicable commitments;* measuring and test equipment calibration was current; | *SP 1092B and C, Safety Injection Check Valve Test, on May 5, 2006; SP 1126, Turbine Building Cooling Water Header Isolation Safety Injection Relays1SI-12X and 1SI-22X Contact Verification Test on May 14, 2006;SP 1072.45, Local Leakage Rate Test of Penetration 45 (Reactor WaterMakeup), on May 18, 2006;SP 1106C; 121 Cooling Water Pump Quarterly Test on May 25, 2006;SP 1083, Unit 1 Integrated Safety Injection Test with a Simulated Loss of OffsitePower, on May 27, 2006;SP 1750, Post-Outage Containment Closeout Inspection on June 1, 2006; andSP 1070, Reactor Coolant System Integrity Test on June 3, 2006.During completion of the inspection samples, the inspectors observed in-plant activitiesand reviewed procedures and associated records to verify that:* preconditioning did not occur;* effects of the testing had been adequately addressed by control room personnelor engineers prior to the commencement of the testing;* acceptance criteria was clearly stated, demonstrated operational readiness, andwas consistent with the system design basis;* plant equipment calibration was correct, accurate, properly documented, and thecalibration frequency was in accordance with TS, USAR, procedures, and applicable commitments;* measuring and test equipment calibration was current; | ||
* test equipment was used within the required range and accuracy; | * test equipment was used within the required range and accuracy; | ||
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* test data/results were accurate, complete, and valid; | * test data/results were accurate, complete, and valid; | ||
* test equipment was removed after testing; | * test equipment was removed after testing; | ||
* where applicable for in-service testing activities, testing was performed inaccordance with the applicable version of Section XI, ASME Code, and reference values were consistent with the system design basis;* where applicable, test results not meeting acceptance criteria were addressedwith an adequate operability evaluation or declared inoperable;* where applicable for safety-related instrument control surveillance tests, referencesetting data have been accurately incorporated in the test procedure; | * where applicable for in-service testing activities, testing was performed inaccordance with the applicable version of Section XI, ASME Code, and reference values were consistent with the system design basis;* where applicable, test results not meeting acceptance criteria were addressedwith an adequate operability evaluation or declared inoperable;* where applicable for safety-related instrument control surveillance tests, referencesetting data have been accurately incorporated in the test procedure; 23* equipment was returned to a position or status required to support theperformance of its safety functions; and* all problems identified during the testing were appropriately documented in thecorrective action program.Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report. | ||
23* equipment was returned to a position or status required to support theperformance of its safety functions; and* all problems identified during the testing were appropriately documented in thecorrective action program.Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report. | |||
====b. Findings==== | ====b. Findings==== | ||
No findings of significance were identified. | No findings of significance were identified. | ||
{{a|1R23}} | |||
==1R23 Temporary Plant Modifications (71111.23)== | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
The inspectors observed a licensed shift operating crew perform an "as-found" exerciseon the simulator on April 20, 2006, completing one emergency planning simulator exercise sample. The inspectors observed activities in the control room simulator that include event classification and notification as well as the post-exercise critique. The inspectors evaluated the drill performance and verified that licensee evaluators'observations were consistent with those of the inspectors, and that deficiencies were | The inspectors observed a licensed shift operating crew perform an "as-found" exerciseon the simulator on April 20, 2006, completing one emergency planning simulator exercise sample. The inspectors observed activities in the control room simulator that include event classification and notification as well as the post-exercise critique. The inspectors evaluated the drill performance and verified that licensee evaluators'observations were consistent with those of the inspectors, and that deficiencies were 24entered into the corrective action program. Key documents used by the inspectors inconducting this inspection are listed in the Attachment to this report. | ||
24entered into the corrective action program. Key documents used by the inspectors inconducting this inspection are listed in the Attachment to this report. | |||
====b. Findings==== | ====b. Findings==== | ||
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The inspectors reviewed licensee controls and surveys in the following two radiologicallysignificant work areas in the plant and reviewed the work packages which included associated licensee controls and surveys of these areas to determine if radiological controls including surveys, postings, and barricades were acceptable: *SI-9-2 check valve maintenance; and*steam generator eddy current testing.This review represented one inspection sample. | The inspectors reviewed licensee controls and surveys in the following two radiologicallysignificant work areas in the plant and reviewed the work packages which included associated licensee controls and surveys of these areas to determine if radiological controls including surveys, postings, and barricades were acceptable: *SI-9-2 check valve maintenance; and*steam generator eddy current testing.This review represented one inspection sample. | ||
The inspectors reviewed the radiation work permits (RWPs) and work packages used toaccess these two areas and other high radiation work areas to identify the work control instructions and control barriers that had been specified. Electronic dosimeter alarm set points for both integrated dose and dose rate were evaluated for conformity with survey indications and plant policy. Workers were interviewed to verify that they were aware of the actions required when their electronic dosimeters noticeably malfunctioned or alarmed. This review represented one inspection sample.The inspectors reviewed selected RWPs used in the containment on May 2, 2006, anairborne radioactivity area, to verify barrier integrity and engineering controls performance (e.g., High Efficiency Particulate Air (HEPA) | The inspectors reviewed the radiation work permits (RWPs) and work packages used toaccess these two areas and other high radiation work areas to identify the work control instructions and control barriers that had been specified. Electronic dosimeter alarm set points for both integrated dose and dose rate were evaluated for conformity with survey indications and plant policy. Workers were interviewed to verify that they were aware of the actions required when their electronic dosimeters noticeably malfunctioned or alarmed. This review represented one inspection sample.The inspectors reviewed selected RWPs used in the containment on May 2, 2006, anairborne radioactivity area, to verify barrier integrity and engineering controls performance (e.g., High Efficiency Particulate Air (HEPA) ventilati on system operation),and to determine if there was a potential for individual worker internal exposures of greater than 50 millirem committed effective dose equivalent. Work areas having a history of, or the potential for, airborne transuranics were evaluatedto verify that the licensee had considered the potential for transuranic isotopes andprovided appropriate worker protection. Specifically, the inspectors reviewed the survey data available from breaching primary systems and surveys of the Reactor PressureVessel Head during the replacement process. This review represented one inspection sample. | ||
25The adequacy of the licensee's internal dose assessment process for internal exposuresgreater than 50 millirem committed effective dose equivalent was assessed. Additionally,the inspectors reviewed the licensee's assessment of 30 assigned internal exposures even though the exposures were less than 50 millirem. This review represented oneinspection sample. | 25The adequacy of the licensee's internal dose assessment process for internal exposuresgreater than 50 millirem committed effective dose equivalent was assessed. Additionally,the inspectors reviewed the licensee's assessment of 30 assigned internal exposures even though the exposures were less than 50 millirem. This review represented oneinspection sample. | ||
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=====Enforcement:===== | =====Enforcement:===== | ||
Technical Specification 5.7.1.a. requires for an HRA with dose rates lessthan 1.0 rem in 1 hour at 30 centimeters from the radiation source or from any surfacethat the radiation penetrates, each entryway to such an area shall be barricaded.Contrary to the above, on May 10, 2006, a barricade to an HRA located on 695' levelat the entrance to the 11 steam generator vault in the Unit 1 containment was left inthe open position and was not attended by personnel to prevent unauthorized entry. Since the finding is of very low safety significance and had been entered into the corrective action system as CAP 1029288, the associated violation is being treatedas an NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000282/2006003-02; 05000306/2006003-02). | Technical Specification 5.7.1.a. requires for an HRA with dose rates lessthan 1.0 rem in 1 hour at 30 centimeters from the radiation source or from any surfacethat the radiation penetrates, each entryway to such an area shall be barricaded.Contrary to the above, on May 10, 2006, a barricade to an HRA located on 695' levelat the entrance to the 11 steam generator vault in the Unit 1 containment was left inthe open position and was not attended by personnel to prevent unauthorized entry. Since the finding is of very low safety significance and had been entered into the corrective action system as CAP 1029288, the associated violation is being treatedas an NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000282/2006003-02; 05000306/2006003-02). | ||
===.2 Problem Identification and Resolution=== | ===.2 Problem Identification and Resolution=== | ||
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No findings of significance were identified. | No findings of significance were identified. | ||
===.2 Radiological Work Planning | ===.2 Radiological Work Planning=== | ||
. | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
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For these four activities, the inspectors reviewed the ALARA work activity evaluations,exposure estimates, and exposure mitigation requirements in order to verify that the licensee had established procedures, and engineering and work controls that were based on sound radiation protection principles in order to achieve occupational exposures that were ALARA. This also involved determining that the licensee had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances. This review represented one inspection sample.The inspectors compared the results achieved including dose rate reductions andperson-rem used with the intended dose established in the licensee's ALARA planning for these four work activities. Reasons for inconsistencies between intended and actual work activity doses were reviewed. This review represented one inspection sample. | For these four activities, the inspectors reviewed the ALARA work activity evaluations,exposure estimates, and exposure mitigation requirements in order to verify that the licensee had established procedures, and engineering and work controls that were based on sound radiation protection principles in order to achieve occupational exposures that were ALARA. This also involved determining that the licensee had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances. This review represented one inspection sample.The inspectors compared the results achieved including dose rate reductions andperson-rem used with the intended dose established in the licensee's ALARA planning for these four work activities. Reasons for inconsistencies between intended and actual work activity doses were reviewed. This review represented one inspection sample. | ||
====b. Findings==== | ====b. Findings==== | ||
One finding of very low safety significance was identified.ALARA Planning Does Not Identify and Prepare for Potential Airborne Conditions WhenOpening the Steam Generator ManwaysIntroduction: A self-revealed finding of very low safety significance and an associatedNCV were identified when 110 radiation workers were contaminated when the steam generator manways were opened during the 1R24 refueling outage. Specific ALARA planning assessments for steam generator manway opening did not acknowledge that airborne concentrations of radioactivity may be subject to change. Additionally the ALARA planning for this work did not consider the effect of engineering safety systemssuch as HEPA filtration operation or malfunction on other work areas in containment. As a result, the containment clean-up | One finding of very low safety significance was identified.ALARA Planning Does Not Identify and Prepare for Potential Airborne Conditions WhenOpening the Steam Generator ManwaysIntroduction: A self-revealed finding of very low safety significance and an associatedNCV were identified when 110 radiation workers were contaminated when the steam generator manways were opened during the 1R24 refueling outage. Specific ALARA planning assessments for steam generator manway opening did not acknowledge that airborne concentrations of radioactivity may be subject to change. Additionally the ALARA planning for this work did not consider the effect of engineering safety systemssuch as HEPA filtration operation or malfunction on other work areas in containment. As a result, the containment clean-up filtrati on system was not properly aligned and securedto the HEPA exhaust to ensure proper control of radioactive iodine in the containment building atmosphere. Consequently, when the work area was set up and initial work commenced, the focus was on the immediate work area only and the result was elevatediodine-131 levels throughout containment.Description: On May 2, 2006, workers opened the steam generator manways to preparefor nozzle dam installation and eddy current testing. A HEPA filtration system wasinstalled in the steam generator vault to reduce particulate contamination from the primary system opening and reduce the potential for airborne conditions in the immediatework area. Additionally, this HEPA was connected to the manway opening to provide contamination control for the steam generator. Radiation workers and radiationprotection technicians did not assure that the discharge from the HEPA systems were properly directed to the containment clean up filter, a HEPA/charcoal filtration train, designed to reduce particulate and gaseous contaminates. Specifically, the HEPA discharge hose was inadequately secured to the containment clean-up filter intake. To install the 11 steam generator manway HEPA discharge hose, workers used procedure 1D27.39, "Initial Steam Generator Outage Work Activities," Attachment F, "Install HEPA Filter Units for 11 and 12 Steam Generators." However, this procedure did not specify the proper method for attaching the HEPA discharge to the containment clean-up filterinput or provide verification of proper fit-up and relied on workers' judgment. When the HEPA discharge hose slipped off the containment clean-up filter intake, because it was loosely attached with wire tie wraps, the steam generator vented directly to the 755' of containment, and this led to increased iodine-131 levels throughout the containment building atmosphere necessitating an evacuation. Inspectors reviewed the HEPA discharge placement after the event, when the hose wasrestored to the containment clean-up filter to verify effective corrective action was taken as a result of the event described above. The inspectors found the HEPA discharge hose simply wired to the intake at a 90-degree angle with two other HEPA discharges attached in similar fashion at the containment clean-up filter intake. Discussions with the licensee staff indicate the initial placement was similar to the post event attachment. | ||
This configuration did not provide a high level of confidence that this was a secure attachment that would assure efficient direction of HEPA discharge to the containment clean-up filter and significantly reduced the possibility of repeat failure. | This configuration did not provide a high level of confidence that this was a secure attachment that would assure efficient direction of HEPA discharge to the containment clean-up filter and significantly reduced the possibility of repeat failure. | ||
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32When the 11 steam generator manway was opened, the iodine and noble gasespresent in the steam generator migrated to the steam generator platform where a lowvolume sampler was running. Elevated iodine-131 Derived Air Concentration (DAC)levels were identified at this location. On May 2, 2006, at 8:45p.m., approximately 1 hourand 10 minutes after opening the steam generator 11 hot leg manway, the iodine-131 level was sampled and recorded at 1.18 DAC. Another low volume air sampler was running concurrently on the containment 755' level, and the sample was removed at8:25 p.m. and identified 0.63 DAC iodine-131. At 11:15 p.m., the containment radiationprotection leader received the data, posted the containment building as an AirborneRadioactivity Area and notified workers of the change in conditions in their work areas. | 32When the 11 steam generator manway was opened, the iodine and noble gasespresent in the steam generator migrated to the steam generator platform where a lowvolume sampler was running. Elevated iodine-131 Derived Air Concentration (DAC)levels were identified at this location. On May 2, 2006, at 8:45p.m., approximately 1 hourand 10 minutes after opening the steam generator 11 hot leg manway, the iodine-131 level was sampled and recorded at 1.18 DAC. Another low volume air sampler was running concurrently on the containment 755' level, and the sample was removed at8:25 p.m. and identified 0.63 DAC iodine-131. At 11:15 p.m., the containment radiationprotection leader received the data, posted the containment building as an AirborneRadioactivity Area and notified workers of the change in conditions in their work areas. | ||
At that time, the radiation protection supervisor stopped further entries into containment. Approximately 1-1/4 hours later, based on air sampling data from 8:45 p.m. (1.25 DAC)in the steam generator vault and from 10:35 p.m. (2.37 DAC) 755' level of the containment, the radiation protection supervisor directed the evacuation of non-essentialpersonnel from containment and permitted continuation of the steam generator manwayinstallation and nozzle dam installation work. Twenty minutes, later the general containment building iodine-131 levels reached 2.89 DAC. The highest airborne concentrations recorded during the event were measured at the 755' level of containmenton May 3, 2006, at 2:09 a.m., yielding 4.62 DAC.Post event follow-up testing on the containment clean-up filters was conducted onMay 4, 2006, which revealed an iodine-131 retention efficiency of approximately 66 percent compared to the expected efficiency of greater than 90 percent. The containment clean-up filters were not functioning at the expected efficiency and yet were the planned primary method of limiting the iodine-131 contamination in containment whenopening the primary system following known fuel leakage during the proceedingoperation run. A pre-operational assessment of the operability and efficiency of thisengineered safety system was not part of the ALARA planning process. The periodicsurveillance of the containment clean-up system was on a 6-year frequency and was lastassessed 4 years prior to this event.Similar levels of iodine-131 in the primary coolant were seen prior to a 2001 outage. When primary systems were opened during that outage there was a slight increase inairborne iodine-131 found in containment air samples and this persisted throughout the outage at less than 0.3 DAC. As a result, 290 workers showed a small but measurable uptake of iodine-131 by the end of the outage and 30 workers received between 10 millirem, the threshold for recording the additional dose, and the highest recordedindividual dose was 26 millirem. The collective recorded dose was 446 millirem.Prior to the above mentioned 2001 outage, primary system iodine-131 levels wereidentified prior to the outage due to a small fuel leak. The 2001 levels were very similar to the pre-outage levels for the 2006 outage. The 2001 outage demonstrated the abilityto work with these levels of iodine-131 in the primary coolant successfully since the 2001 outage did not result in dose significant intakes from airborne iodine-131. Therefore, limited measures were planned in an effort to preclude airborne radioactivity in the containment building during this refueling outage. Contingency plans for containmentbuilding contamination were limited to the standing radiation protection procedures for contamination monitoring at access control and disposition of intakes in accordance with Radiation Protection Implementing Procedure (RPIP) 1126, "Contamination Monitor | At that time, the radiation protection supervisor stopped further entries into containment. Approximately 1-1/4 hours later, based on air sampling data from 8:45 p.m. (1.25 DAC)in the steam generator vault and from 10:35 p.m. (2.37 DAC) 755' level of the containment, the radiation protection supervisor directed the evacuation of non-essentialpersonnel from containment and permitted continuation of the steam generator manwayinstallation and nozzle dam installation work. Twenty minutes, later the general containment building iodine-131 levels reached 2.89 DAC. The highest airborne concentrations recorded during the event were measured at the 755' level of containmenton May 3, 2006, at 2:09 a.m., yielding 4.62 DAC.Post event follow-up testing on the containment clean-up filters was conducted onMay 4, 2006, which revealed an iodine-131 retention efficiency of approximately 66 percent compared to the expected efficiency of greater than 90 percent. The containment clean-up filters were not functioning at the expected efficiency and yet were the planned primary method of limiting the iodine-131 contamination in containment whenopening the primary system following known fuel leakage during the proceedingoperation run. A pre-operational assessment of the operability and efficiency of thisengineered safety system was not part of the ALARA planning process. The periodicsurveillance of the containment clean-up system was on a 6-year frequency and was lastassessed 4 years prior to this event.Similar levels of iodine-131 in the primary coolant were seen prior to a 2001 outage. When primary systems were opened during that outage there was a slight increase inairborne iodine-131 found in containment air samples and this persisted throughout the outage at less than 0.3 DAC. As a result, 290 workers showed a small but measurable uptake of iodine-131 by the end of the outage and 30 workers received between 10 millirem, the threshold for recording the additional dose, and the highest recordedindividual dose was 26 millirem. The collective recorded dose was 446 millirem.Prior to the above mentioned 2001 outage, primary system iodine-131 levels wereidentified prior to the outage due to a small fuel leak. The 2001 levels were very similar to the pre-outage levels for the 2006 outage. The 2001 outage demonstrated the abilityto work with these levels of iodine-131 in the primary coolant successfully since the 2001 outage did not result in dose significant intakes from airborne iodine-131. Therefore, limited measures were planned in an effort to preclude airborne radioactivity in the containment building during this refueling outage. Contingency plans for containmentbuilding contamination were limited to the standing radiation protection procedures for contamination monitoring at access control and disposition of intakes in accordance with Radiation Protection Implementing Procedure (RPIP) 1126, "Contamination Monitor 33Alarm Response, and Personnel Decontamination," and non-specific ALARA engineeringcontrols.The inspectors reviewed a separate event that occurred on May 2, 2006, during the dayshift, where the reactor pressure vessel head was vented to the containment building, releasing iodine-131 and noble gases. The licensee's staff presumed the vessel head was vented through a HEPA filter to the containment clean-up filtration that consists of a pre-filter, HEPA and charcoal bank. This error was identified when containment air sampling showed an increase in the airborne radioactivity (iodine-131, 0.4 DAC). No corrective action document was written regarding this event until May 26, 2006. If the licensee had accurately identified this event as a precursor to similar events, it would have provided an opportunity to make self-assessment prior to additional primary systemopenings. Due partially to the failure to recognize this as a precursor to a more significant event, within 12 hours the containment airborne levels increased again when the steam generator manways were opened and the HEPA filtration was inappropriately positioned in the intake of the containment clean-up filter bank.Analysis: The inspectors determined that the failure to properly plan ALARA workactivities was a performance deficiency and represents a finding as described in IMC 0612, Appendix B, "Issue Screening." ALARA planning did not conduct an adequate assessment of the effect of leaking fuel on the potential for increased iodine and noble gas concentrations in the steam generators and potential impact on the containmentbuilding environment. The issue was more than minor because it was associated with the Occupational Radiation Safety cornerstone, and potentially affected the cornerstoneattribute of program and process for ALARA planning and exposure/contamination control. The finding does not involve the application of traditional enforcement, because it did notresult in actual safety consequences or the potential to impact the NRC's regulatoryfunction, and was not the result of any willful actions. The finding was evaluated usingIMC 0609, Appendix C, the SDP for the Occupational Radiation Safety cornerstone andwas determined to be of very low safety significance (Green) because the finding involved an ALARA issue and individuals received very low unintended dose as a result of the procedural noncompliance. However, individual radiation exposures for workers in containment during that time were low relative to regulatory limits; there was not a substantial potential for a worker overexposure; and the licensee's ability to assessworker dose was not compromised.Enforcement: Technical Specification 5.4.1.a. requires the licensee to establish,implement, and maintain procedures recommended by Regulatory Guide 1.33, Revision 2, Appendix A, date February 1978. Regulatory Guide 1.33 requiresprocedures for the control of radioactivity and limiting of personnel exposure, ALARA Procedure FP-RP-JPP-01, Radiation Protection Job Planning, Attachment 1, directs the job planner, through a series of planning forms, to assess the radiological safety significance of specific work. The Attachment 1 directs the use of form QF-1203, Radiological Work Assessment; QF-1204, Radiological Work Assessment From Contamination Control, if contamination control was a hazard for the assigned work;and QF-1206, Radiological Work Assessment From Internal Exposure Control, if contamination control internal exposure is a hazard for the assigned work. | ||
33Alarm Response, and Personnel Decontamination," and non-specific ALARA engineeringcontrols.The inspectors reviewed a separate event that occurred on May 2, 2006, during the dayshift, where the reactor pressure vessel head was vented to the containment building, releasing iodine-131 and noble gases. The licensee's staff presumed the vessel head was vented through a HEPA filter to the containment clean-up filtration that consists of a pre-filter, HEPA and charcoal bank. This error was identified when containment air sampling showed an increase in the airborne radioactivity (iodine-131, 0.4 DAC). No corrective action document was written regarding this event until May 26, 2006. If the licensee had accurately identified this event as a precursor to similar events, it would have provided an opportunity to make self-assessment prior to additional primary systemopenings. Due partially to the failure to recognize this as a precursor to a more significant event, within 12 hours the containment airborne levels increased again when the steam generator manways were opened and the HEPA filtration was inappropriately positioned in the intake of the containment clean-up filter bank.Analysis: The inspectors determined that the failure to properly plan ALARA workactivities was a performance deficiency and represents a finding as described in IMC 0612, Appendix B, "Issue Screening." ALARA planning did not conduct an adequate assessment of the effect of leaking fuel on the potential for increased iodine and noble gas concentrations in the steam generators and potential impact on the containmentbuilding environment. The issue was more than minor because it was associated with the Occupational Radiation Safety cornerstone, and potentially affected the cornerstoneattribute of program and process for ALARA planning and exposure/contamination control. The finding does not involve the application of traditional enforcement, because it did notresult in actual safety consequences or the potential to impact the NRC's regulatoryfunction, and was not the result of any willful actions. The finding was evaluated usingIMC 0609, Appendix C, the SDP for the Occupational Radiation Safety cornerstone andwas determined to be of very low safety significance (Green) because the finding involved an ALARA issue and individuals received very low unintended dose as a result of the procedural noncompliance. However, individual radiation exposures for workers in containment during that time were low relative to regulatory limits; there was not a substantial potential for a worker overexposure; and the licensee's ability to assessworker dose was not compromised.Enforcement: Technical Specification 5.4.1.a. requires the licensee to establish,implement, and maintain procedures recommended by Regulatory Guide 1.33, Revision 2, Appendix A, date February 1978. Regulatory Guide 1.33 requiresprocedures for the control of radioactivity and limiting of personnel exposure, ALARA Procedure FP-RP-JPP-01, Radiation Protection Job Planning, Attachment 1, directs the job planner, through a series of planning forms, to assess the radiological safety significance of specific work. The Attachment 1 directs the use of form QF-1203, Radiological Work Assessment; QF-1204, Radiological Work Assessment From Contamination Control, if contamination control was a hazard for the assigned work;and QF-1206, Radiological Work Assessment From Internal Exposure Control, if contamination control internal exposure is a hazard for the assigned work. | |||
34Contrary to the above, on March 3 and April 18, 2006, radiation protectionpersonnel assigned to conduct the work assessment, and planning for WO 95654, | 34Contrary to the above, on March 3 and April 18, 2006, radiation protectionpersonnel assigned to conduct the work assessment, and planning for WO 95654, "11 and 12 Steam Generator Primary Side Manway, and Insert, Remove, and Install," | ||
"11 and 12 Steam Generator Primary Side Manway, and Insert, Remove, and Install," | |||
failed to recognize that airborne concentrations for the work were subject to significant changes. Consequently, the licensee did not adequately evaluate the internal exposurehazard and document the hazard in accordance with the above procedure. Since the finding is of very low safety significance and had been entered into the corrective action system as CAP 1027653, the associated violation is being treated as an NCV, consistentwith Section VI.A of the NRC Enforcement Policy (NCV 05000282/2006003-03;05000306/2006003-03). | failed to recognize that airborne concentrations for the work were subject to significant changes. Consequently, the licensee did not adequately evaluate the internal exposurehazard and document the hazard in accordance with the above procedure. Since the finding is of very low safety significance and had been entered into the corrective action system as CAP 1027653, the associated violation is being treated as an NCV, consistentwith Section VI.A of the NRC Enforcement Policy (NCV 05000282/2006003-03;05000306/2006003-03). | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
Radiation worker and radiation protection technician performance was observed duringwork activities being performed in radiation areas, airborne radioactivity areas, and high radiation areas that presented the greatest radiological risk to workers. The inspectors evaluated whether workers demonstrated the ALARA philosophy in practice by being familiar with the work activity scope and tools to be used, by utilizing ALARA low dosewaiting areas, and by complying with the work activity controls. Also, radiation worker training and skill levels were reviewed to determine if they were sufficient relative to theradiological hazards and the work involved. This review represented one inspection sample. | Radiation worker and radiation protection technician performance was observed duringwork activities being performed in radiation areas, airborne radioactivity areas, and high radiation areas that presented the greatest radiological risk to workers. The inspectors evaluated whether workers demonstrated the ALARA philosophy in practice by being familiar with the work activity scope and tools to be used, by utilizing ALARA low dosewaiting areas, and by complying with the work activity controls. Also, radiation worker training and skill levels were reviewed to determine if they were sufficient relative to theradiological hazards and the work involved. This review represented one inspection sample. | ||
====b. Findings==== | ====b. Findings==== | ||
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=====Description:===== | =====Description:===== | ||
On May 5 to May 11, 2006, the Unit 1 containment equipment hatch wasopen to the atmosphere to allow equipment and personnel in and out of containment in support of a refueling outage and head replacement activities. The negative pressure | On May 5 to May 11, 2006, the Unit 1 containment equipment hatch wasopen to the atmosphere to allow equipment and personnel in and out of containment in support of a refueling outage and head replacement activities. The negative pressure 36necessary to prevent uncontrolled releases of radioactive material was not adequatelymaintained during periods when the equipment hatch was open and allowed air from containment to vent to the atmosphere through the containment building equipmenthatch opening. This problem was identified on multiple occasions during this outage by the licensee and by NRC personnel and brought to the attention of the Outage ControlCenter. This prompted the operations staff to investigate the in-service purge fan alignment and periodically adjust the position of a tarp that was available at the equipment hatch opening to limit the effect of the positive pressure in containment and any release to the environment. The inspectors noted that these interim corrective actions were not consistently implemented. The licensee monitored concentrations of iodine-131 and xenon-133 in the containment air and found that the concentration ofgaseous radioactivity was measurable but at very low concentration (less than 0.3 DAC)during the time that the equipment hatch was open. The air contained radioactivematerial because the primary system was open in several locations and the RCScontained elevated entrained fission gas concentrations at shutdown due to minor fueldegradation which emerged during the unit's run cycle.The inspectors concluded that the licensee failed to develop an ODCM implementingprocedure that ensured that the offsite dose to the public from venting the RCS tocontainment was properly quantified if the containment came under positive pressure andvented to the environment through the equipment hatch. Additionally, because openingthe equipment hatch during the last three outages was a planned evolution, theequipment hatch had become a routine release point. However, the licensee had not revised the ODCM to document the pathway.Following May 5 to 11, 2006, a period when the equipment hatch was open, and afteradditional questions raised by the NRC, a corrective action document was subsequentlywritten to evaluate and address the deficiencies with the release assessment process described above. Additionally, this corrective action document, CAP 1027608, "Inadequate Effluent Release Controls at the Unit 1 Equipment Hatch," led to a report,"Quantification of Abnormal Releases Via Roll-up Doors and Equipment Hatch During Refueling Outage 1R24." The inspectors reviewed this document to assure that it:*described the radiological impact from releasing radioactive effluents through thecontainment building equipment hatch to the environment, because it was not properly assessed prior to the release;*demonstrated the offsite dose ALARA objectives of 10 CFR Part 20 and10 CFR Part 50, Appendix I; and *ensured that the release was properly quantified and reported.Analysis: The failure to develop a procedure for ODCM implementation to ensure theradiological impact from releasing radioactive gases to the environment through the equipment hatch was properly assessed prior to the release and that the release wasproperly quantified and reported in accordance with ODCM requirements represents a performance deficiency as defined in IMC 0612, "Power Reactor Inspection Reports," | ||
Appendix B, "Issue Screening." The inspectors determined that the issue was more thanminor because it was associated with the program and process attribute of the Public Radiation Safety cornerstone and potentially affected the cornerstone objective to ensure adequate protection of the public from exposure to radioactive materials from the release 37of gaseous effluents. Therefore, the issue was more than minor and represented afinding which was evaluated using the SDP.Since the finding involved an occurrence in the licensee's radiological effluent monitoringprogram, the inspectors utilized IMC 0609, Appendix D, "Public Radiation Safety SDP," toassess its significance. The issue was not associated with radioactive material control | |||
36necessary to prevent uncontrolled releases of radioactive material was not adequatelymaintained during periods when the equipment hatch was open and allowed air from containment to vent to the atmosphere through the containment building equipmenthatch opening. This problem was identified on multiple occasions during this outage by the licensee and by NRC personnel and brought to the attention of the Outage ControlCenter. This prompted the operations staff to investigate the in-service purge fan alignment and periodically adjust the position of a tarp that was available at the equipment hatch opening to limit the effect of the positive pressure in containment and any release to the environment. The inspectors noted that these interim corrective actions were not consistently implemented. The licensee monitored concentrations of iodine-131 and xenon-133 in the containment air and found that the concentration ofgaseous radioactivity was measurable but at very low concentration (less than 0.3 DAC)during the time that the equipment hatch was open. The air contained radioactivematerial because the primary system was open in several locations and the RCScontained elevated entrained fission gas concentrations at shutdown due to minor fueldegradation which emerged during the unit's run cycle.The inspectors concluded that the licensee failed to develop an ODCM implementingprocedure that ensured that the offsite dose to the public from venting the RCS tocontainment was properly quantified if the containment came under positive pressure andvented to the environment through the equipment hatch. Additionally, because openingthe equipment hatch during the last three outages was a planned evolution, theequipment hatch had become a routine release point. However, the licensee had not revised the ODCM to document the pathway.Following May 5 to 11, 2006, a period when the equipment hatch was open, and afteradditional questions raised by the NRC, a corrective action document was subsequentlywritten to evaluate and address the deficiencies with the release assessment process described above. Additionally, this corrective action document, CAP 1027608, | ;however, the licensee failed to adequately assess the offsite dose impact prior to the releasing radioactive effluents from containment through the equipment hatch; therefore,the situation represented an impaired ability to assess dose. However, the licensee subsequently assessed the offsite dose resulting from the release and determined that applicable dose limits were met. The actual effluent releases, as calculated by the licensee, were not greater than regulatory dose limits or ALARA constraints as defined in the 10 CFR 20.1301(d) or 10 CFR Part 50, Appendix I. The calculated dose to a member of the public using conservative parameters was less than 0.025 millirad. Consequently, there was minimal actual risk to the public from the release; and, therefore, the inspectors concluded that the SDP assessment for this finding was of verylow safety significance (Green).Multiple opportunities to identify and correct deficiencies associated with effluent controlsand assessment were presented during outages in 2004, 2005, and 2006. While thesewere entered into the licensee's corrective action program, effective corrective action to prevent recurrence was not achieved. The primary cause of this event was a cross-cutting issue related to problem identification and resolution program deficiencies.Enforcement: Technical Specification 5.5.1 requires that the ODCM contain themethodology and parameters used in the calculation of offsite doses resulting from radioactive gaseous effluents. Offsite Dose Calculation Manual, step 7, requires compliance with TS 5.5.4 regarding the Radioactive Effluent Controls Program, which requires that the program be contained in the ODCM, and shall be implemented byprocedures. Contrary to this requirement, adequate written procedures were not established to ensure the radiological impact from releasing radioactive effluents through the containment building equipment hatch during outages in 2004, 2005, and 2006, wereproperly assessed prior to release to demonstrate it satisfied the ALARA design objectives of 10 CFR Part 20 and 10 CFR Part 50, Appendix I. Since the licensee documented this issue in its corrective action program (CAPs 1027608, 1027653, 1028580, and 1029875) and because the violation was of very low safety significance, it is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 50-282/2006003-04; 50-306/2006003-04). | ||
"Inadequate Effluent Release Controls at the Unit 1 Equipment Hatch," led to a report,"Quantification of Abnormal Releases Via Roll-up Doors and Equipment Hatch During Refueling Outage 1R24." The inspectors reviewed this document to assure that it:*described the radiological impact from releasing radioactive effluents through thecontainment building equipment hatch to the environment, because it was not properly assessed prior to the release;*demonstrated the offsite dose ALARA objectives of 10 CFR Part 20 and10 CFR Part 50, Appendix I; and *ensured that the release was properly quantified and reported.Analysis: The failure to develop a procedure for ODCM implementation to ensure theradiological impact from releasing radioactive gases to the environment through the equipment hatch was properly assessed prior to the release and that the release wasproperly quantified and reported in accordance with ODCM requirements represents a performance deficiency as defined in IMC 0612, "Power Reactor Inspection Reports," | |||
Appendix B, "Issue Screening." The inspectors determined that the issue was more thanminor because it was associated with the program and process attribute of the Public Radiation Safety cornerstone and potentially affected the cornerstone objective to ensure adequate protection of the public from exposure to radioactive materials from the release | |||
37of gaseous effluents. Therefore, the issue was more than minor and represented afinding which was evaluated using the SDP.Since the finding involved an occurrence in the licensee's radiological effluent monitoringprogram, the inspectors utilized IMC 0609, Appendix D, "Public Radiation Safety SDP," toassess its significance. The issue was not associated with radioactive material control;however, the licensee failed to adequately assess the offsite dose impact prior to the releasing radioactive effluents from containment through the equipment hatch; therefore,the situation represented an impaired ability to assess dose. However, the licensee subsequently assessed the offsite dose resulting from the release and determined that applicable dose limits were met. The actual effluent releases, as calculated by the licensee, were not greater than regulatory dose limits or ALARA constraints as defined in the 10 CFR 20.1301(d) or 10 CFR Part 50, Appendix I. The calculated dose to a member of the public using conservative parameters was less than 0.025 millirad. Consequently, there was minimal actual risk to the public from the release; and, therefore, the inspectors concluded that the SDP assessment for this finding was of verylow safety significance (Green).Multiple opportunities to identify and correct deficiencies associated with effluent controlsand assessment were presented during outages in 2004, 2005, and 2006. While thesewere entered into the licensee's corrective action program, effective corrective action to prevent recurrence was not achieved. The primary cause of this event was a cross-cutting issue related to problem identification and resolution program deficiencies.Enforcement: Technical Specification 5.5.1 requires that the ODCM contain themethodology and parameters used in the calculation of offsite doses resulting from radioactive gaseous effluents. Offsite Dose Calculation Manual, step 7, requires compliance with TS 5.5.4 regarding the Radioactive Effluent Controls Program, which requires that the program be contained in the ODCM, and shall be implemented byprocedures. Contrary to this requirement, adequate written procedures were not established to ensure the radiological impact from releasing radioactive effluents through the containment building equipment hatch during outages in 2004, 2005, and 2006, wereproperly assessed prior to release to demonstrate it satisfied the ALARA design objectives of 10 CFR Part 20 and 10 CFR Part 50, Appendix I. Since the licensee documented this issue in its corrective action program (CAPs 1027608, 1027653, 1028580, and 1029875) and because the violation was of very low safety significance, it is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 50-282/2006003-04; 50-306/2006003-04). | |||
==OTHER ACTIVITIES== | ==OTHER ACTIVITIES== | ||
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====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
The inspectors reviewed the licensee submittals for two performance indicators forPrairie Island Units 1 and 2, completing four performance indicator verification inspection procedure samples. The inspectors used performance indicator guidance and definitions contained in NEI Document 99-02, Revision 3, "Regulatory Assessment PerformanceIndicator Guideline," to verify the accuracy of the performance indicator data. The inspectors' review included, but was not limited to, conditions and data from logs, Licensee Event Reports, condition reports, and calculations for each performance indicator specified. The inspectors also reviewed the CAPs listed in the Attachment to this report to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with corrective action procedures.The licensee's reporting of the following performance indicators were verified: | The inspectors reviewed the licensee submittals for two performance indicators forPrairie Island Units 1 and 2, completing four performance indicator verification inspection procedure samples. The inspectors used performance indicator guidance and definitions contained in NEI Document 99-02, Revision 3, "Regulatory Assessment PerformanceIndicator Guideline," to verify the accuracy of the performance indicator data. The inspectors' review included, but was not limited to, conditions and data from logs, Licensee Event Reports, condition reports, and calculations for each performance indicator specified. The inspectors also reviewed the CAPs listed in the Attachment to this report to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with corrective action procedures.The licensee's reporting of the following performance indicators were verified: | ||
Unit 1*Unplanned Power Changes per 7000 Critical Hours for the | Unit 1*Unplanned Power Changes per 7000 Critical Hours for the 2 nd Quarter 2004 through the 1 st Quarter 2006;*Safety System Functional Failures for the 2 nd Quarter 2004 through the 1 st Quarter 2006.Unit 2*Unplanned Power Changes per 7000 Critical Hours for the 2 nd Quarter 2004 through the 1 st Quarter 2006;*Safety System Functional Failures for the 2 nd Quarter 2004 through the 1 st Quarter 2006.Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report. | ||
====b. Findings==== | ====b. Findings==== | ||
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394OA2Identification and Resolution of Problems (71152) | 394OA2Identification and Resolution of Problems (71152) | ||
===.1 Routine Review of Identification and Resolution of Problems | ===.1 Routine Review of Identification and Resolution of Problems=== | ||
Introduction | |||
: As discussed in previous sections of this report, the inspectors routinelyreviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensee's corrective action program at an appropriate threshold, that adequate attention was given to ensure timely corrective actions, and that adverse trends were identified and addressed. This does not count as an annual sample. | |||
As discussed in previous sections of this report, the inspectors routinelyreviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensee's corrective action program at an appropriate threshold, that adequate attention was given to ensure timely corrective actions, and that adverse trends were identified and addressed. This does not count as an annual sample. | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
As discussed in Section 2OS1.1 and 2PS1.1, the inspectors reviewed the licensee'sproblem identification and resolution program to assess the adequacy of the radiation protection department's ability to identify and document problems and to implementtimely and appropriate corrective actions. In particular, the inspectors reviewed the circumstances surrounding an HRA barrier that was found in the open position, which was identified by the NRC on May 9, 2006, and documented in CAP 1029288. Tocomplete the review, the inspectors discussed the issue with several members of the radiation protection staff, supervision and management and reviewed additional licensee-identified HRA barrier issues documented in 4OA7, to determine the adequacy for identifying problems with HRA barriers. Additionally, the inspectors reviewed the circumstances surrounding loss of negative pressure on the containment building when the equipment hatch was open from May 5 to 11, 2006, and the associated effluentassessment as documented in CAP 1027608. To complete the review, the inspectors discussed the issue with several members of the radiation protection and chemistry staff, supervision and management and reviewed additional licensee-identified corrective action documents written in response to similar effluent events during outages in 2004 and 2005. | As discussed in Section 2OS1.1 and 2PS1.1, the inspectors reviewed the licensee'sproblem identification and resolution program to assess the adequacy of the radiation protection department's ability to identify and document problems and to implementtimely and appropriate corrective actions. In particular, the inspectors reviewed the circumstances surrounding an HRA barrier that was found in the open position, which was identified by the NRC on May 9, 2006, and documented in CAP 1029288. Tocomplete the review, the inspectors discussed the issue with several members of the radiation protection staff, supervision and management and reviewed additional licensee-identified HRA barrier issues documented in 4OA7, to determine the adequacy for identifying problems with HRA barriers. Additionally, the inspectors reviewed the circumstances surrounding loss of negative pressure on the containment building when the equipment hatch was open from May 5 to 11, 2006, and the associated effluentassessment as documented in CAP 1027608. To complete the review, the inspectors discussed the issue with several members of the radiation protection and chemistry staff, supervision and management and reviewed additional licensee-identified corrective action documents written in response to similar effluent events during outages in 2004 | ||
and 2005. | |||
b.IssuesHigh Radiation Area Barrier EventsThe NRC identified an HRA barrier event during the inspection as discussed in 2OS1.1. The licensee identified multiple similar HRA barrier events as described in 4OA7. | b.IssuesHigh Radiation Area Barrier EventsThe NRC identified an HRA barrier event during the inspection as discussed in 2OS1.1. The licensee identified multiple similar HRA barrier events as described in 4OA7. | ||
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40Lack of Extent of Condition Assessment for Air Flow ProblemsIn 2004, the licensee generated CAP 38784 to document the loss of negative pressure incontainment that resulted in a small release of radioactivity to the environment. The corrective action for that problem included directions for the next outage that governed controls for ventilation pathways when the containment hatch was open. However, thelicensee's evaluation was inadequate and the associated corrective actions were not consistently implemented to ensure that the environmental impact from releasingradioactive effluents from containment through the equipment hatch was assessed adequately prior to the release. In 2005, the licensee generated a corrective action CAP 841226 to document the failure to implement the corrective actions specified in 2004 (CAP 38784). However, the licensee's evaluation of that CAP and the associated corrective actions were not sufficiently comprehensive to ensure that the environmental impact from releasing radioactive effluents from containment through the equipment hatch was assessed adequately before the effluent was released. In 2006, the licenseewas again presented with lack of control over the airflow at the containment buildingequipment hatch and again did not ensure that the environmental impact from releasingradioactive effluents from containment through the equipment hatch was assessed adequately before the effluent was released. While the licensee was able to conservatively reconstruct the small radioactive effluents in each instance and record them, the effectiveness of corrective actions lacked rigor. Specifically, the response to the issues was limited in scope, lacked adequate assessment of the extent of conditionand failed to result in effective corrective action. The deficiencies with the licensee's problem evaluation and resolution program, a cross cutting issue, significantly contributed to this repetitive problem. Missed Opportunity to Identify a Precursor to a More Significant EventOn May 2, 2006, the Reactor Pressure Vessel Head was vented to containmentreleasing iodine-131 and noble gases. The licensee staff thought the venting process was directed through a HEPA filter to the containment clean-up filtration that consists of a pre-filter, HEPA and charcoal bank. This error was identified when containment air sampling showed an increase in the airborne radioactivity. The licensee took immediate action to clear containment until they could understand the source of the elevated levels. This was a precursor or an indicator of the potential for additional and similar events. | 40Lack of Extent of Condition Assessment for Air Flow ProblemsIn 2004, the licensee generated CAP 38784 to document the loss of negative pressure incontainment that resulted in a small release of radioactivity to the environment. The corrective action for that problem included directions for the next outage that governed controls for ventilation pathways when the containment hatch was open. However, thelicensee's evaluation was inadequate and the associated corrective actions were not consistently implemented to ensure that the environmental impact from releasingradioactive effluents from containment through the equipment hatch was assessed adequately prior to the release. In 2005, the licensee generated a corrective action CAP 841226 to document the failure to implement the corrective actions specified in 2004 (CAP 38784). However, the licensee's evaluation of that CAP and the associated corrective actions were not sufficiently comprehensive to ensure that the environmental impact from releasing radioactive effluents from containment through the equipment hatch was assessed adequately before the effluent was released. In 2006, the licenseewas again presented with lack of control over the airflow at the containment buildingequipment hatch and again did not ensure that the environmental impact from releasingradioactive effluents from containment through the equipment hatch was assessed adequately before the effluent was released. While the licensee was able to conservatively reconstruct the small radioactive effluents in each instance and record them, the effectiveness of corrective actions lacked rigor. Specifically, the response to the issues was limited in scope, lacked adequate assessment of the extent of conditionand failed to result in effective corrective action. The deficiencies with the licensee's problem evaluation and resolution program, a cross cutting issue, significantly contributed to this repetitive problem. Missed Opportunity to Identify a Precursor to a More Significant EventOn May 2, 2006, the Reactor Pressure Vessel Head was vented to containmentreleasing iodine-131 and noble gases. The licensee staff thought the venting process was directed through a HEPA filter to the containment clean-up filtration that consists of a pre-filter, HEPA and charcoal bank. This error was identified when containment air sampling showed an increase in the airborne radioactivity. The licensee took immediate action to clear containment until they could understand the source of the elevated levels. This was a precursor or an indicator of the potential for additional and similar events. | ||
In fact, within 12 hours the containment airborne levels increased again when the 11 steam generator was opened and the HEPA filtration discharge was inappropriately positioned in the intake of the containment clean-up filter bank. Because the events were similar in result and occurred on the same day, the licensee staff did not initially separate this event from the review of the second event when the 11 steam generatorwas opened and airborne iodine-131 levels increased. Until the NRC discussed this withthe staff and management as a separate event with potentially separate causes and aprecursor event, no corrective action document was written. A corrective action program document was written May 25, 2006 (CAP 1032258).Mistake in Calculating DAC Levels During the opening of 11 steam generator that lead to an airborne event on May 2, 2006,the licensee collected frequent containment air samples and analyzed them for airborne gaseous and particulate levels. During one of the sampling counts and assessment, a | In fact, within 12 hours the containment airborne levels increased again when the 11 steam generator was opened and the HEPA filtration discharge was inappropriately positioned in the intake of the containment clean-up filter bank. Because the events were similar in result and occurred on the same day, the licensee staff did not initially separate this event from the review of the second event when the 11 steam generatorwas opened and airborne iodine-131 levels increased. Until the NRC discussed this withthe staff and management as a separate event with potentially separate causes and aprecursor event, no corrective action document was written. A corrective action program document was written May 25, 2006 (CAP 1032258).Mistake in Calculating DAC Levels During the opening of 11 steam generator that lead to an airborne event on May 2, 2006,the licensee collected frequent containment air samples and analyzed them for airborne gaseous and particulate levels. During one of the sampling counts and assessment, a 41mistake in calculating a DAC was made and it resulted in reporting higher level than waspresent. While this was a conservative mistake, it did provide information that should have been reviewed for potential program improvement. The need to document this issue was not readily apparent. No corrective action document was immediately written. | ||
41mistake in calculating a DAC was made and it resulted in reporting higher level than waspresent. While this was a conservative mistake, it did provide information that should have been reviewed for potential program improvement. The need to document this issue was not readily apparent. No corrective action document was immediately written. | |||
After discussion of this issue with the NRC, a corrective action program document was written May 22, 2006 (CAP 1031483). | After discussion of this issue with the NRC, a corrective action program document was written May 22, 2006 (CAP 1031483). | ||
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required by Inspection Procedure 71152, "Identification and Resolution of Problems." | required by Inspection Procedure 71152, "Identification and Resolution of Problems." | ||
This inspection effort completed the required semiannual trending inspection and one inspection sample. The effectiveness of the licensee corrective action program was assessed by comparing trends identified by the licensee with those issues identified by the NRC during the conduct of routine plant status and baseline inspections. Inspectorsreviewed CAPs initiated during the period from January 1 through June 20, 2006. The inspectors utilized Pareto analysis and the symptom classification technique to evaluatethe CAP data base to select areas for detailed review. The areas selected for detailed review included the Corrective Action Program, the Radiation Protection program, the | This inspection effort completed the required semiannual trending inspection and one inspection sample. The effectiveness of the licensee corrective action program was assessed by comparing trends identified by the licensee with those issues identified by the NRC during the conduct of routine plant status and baseline inspections. Inspectorsreviewed CAPs initiated during the period from January 1 through June 20, 2006. The inspectors utilized Pareto analysis and the symptom classification technique to evaluatethe CAP data base to select areas for detailed review. The areas selected for detailed review included the Corrective Action Program, the Radiation Protection program, the 42Emergency Preparedness program, the Security program, and human performance. Theinspectors performed the inspection by in-office review of licensee corrective action program and other reports, including the following:*trend reports;*performance indicators; | ||
42Emergency Preparedness program, the Security program, and human performance. Theinspectors performed the inspection by in-office review of licensee corrective action program and other reports, including the following:*trend reports;*performance indicators; | |||
*equipment problem lists; | *equipment problem lists; | ||
*rework reports; | *rework reports; | ||
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====b. Findings and Observations==== | ====b. Findings and Observations==== | ||
No findings of significance were identified. The inspectors identified that the primarymethod used by the licensee to identify potential adverse trends is the Department RollUp Meeting (DRUM). The inspectors identified that the licensee identified potentialadverse trends and entered them into the corrective action program for all of the areas selected for detailed review except:*emergency preparedness siren issues; and*lost badges.Although these shortcomings within the licensee's trending process were noted, noviolations of NRC requirements were identified.4OA3Event Followup (71153) | No findings of significance were identified. The inspectors identified that the primarymethod used by the licensee to identify potential adverse trends is the Department RollUp Meeting (DRUM). The inspectors identified that the licensee identified potentialadverse trends and entered them into the corrective action program for all of the areas selected for detailed review except: | ||
*emergency preparedness siren issues; and*lost badges.Although these shortcomings within the licensee's trending process were noted, noviolations of NRC requirements were identified.4OA3Event Followup (71153) | |||
===.1 (Closed) Licensee Event Report (LER) 05000306/2006-001-00:=== | ===.1 (Closed) Licensee Event Report (LER) 05000306/2006-001-00:=== | ||
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The licensee performed a root cause investigation, implemented corrective actions to prevent recurrence and short term corrective actions, and returned the unit to power operation. The licensee documented the problem, root cause analysis, and corrective actions in CAP 01013473. The LER, root cause analysis report, and corrective actions were reviewed by the inspectors. No findings of significance were identified and no violations of NRC requirement occurred. This LER is closed. | The licensee performed a root cause investigation, implemented corrective actions to prevent recurrence and short term corrective actions, and returned the unit to power operation. The licensee documented the problem, root cause analysis, and corrective actions in CAP 01013473. The LER, root cause analysis report, and corrective actions were reviewed by the inspectors. No findings of significance were identified and no violations of NRC requirement occurred. This LER is closed. | ||
===.2 Event Followup of the Inoperability of Both Pressurizer PORVs During Unit 1 Shutdown=== | ===.2 Event Followup of the Inoperability of Both Pressurizer PORVs During Unit 1 Shutdown=== | ||
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No findings of significance were identified.4OA5Other Activities | No findings of significance were identified.4OA5Other Activities | ||
===.1 Resolution of Unresolved Item (URI) 05000282/2006002-01; 05000306/2006002-01:Evaluation of Expired Sealant Performance for Flood Protection | ===.1 Resolution of Unresolved Item (URI) 05000282/2006002-01; 05000306/2006002-01=== | ||
:Evaluation of Expired Sealant Performance for Flood Protection | |||
====a. Inspection Scope==== | ====a. Inspection Scope==== | ||
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=====Introduction:===== | =====Introduction:===== | ||
The inspectors identified a Non-Cited Violation of 10 CFR Part 50Appendix B, Criterion V, for a combination of an inadequate procedure and a failure to implement the requirements of Surveillance Procedure 1293, Inspection of Flood ControlMeasures and the Shelf Life Program Procedure FP-SC-PE-05. Specifically, the | The inspectors identified a Non-Cited Violation of 10 CFR Part 50Appendix B, Criterion V, for a combination of an inadequate procedure and a failure to implement the requirements of Surveillance Procedure 1293, Inspection of Flood ControlMeasures and the Shelf Life Program Procedure FP-SC-PE-05. Specifically, the 44licensee failed to order and maintain the correct type of Deck-O-Seal sealant to facilitateinstallation of flood doors and panels in accordance with plant abnormal procedures.Description: On March 29, 2006, the inspectors inspected the main warehouse to verifythe existence of the flood protection materials listed in Table 1 of Surveillance ProcedureSP 1293, "Inspection of Flood Control Measures," Revision 13. All the listed materials were found by inspectors but the Deck-O-Seal sealant was found 1 year beyond its shelf life expiration date. Deck-O-Seal gun grade sealant is necessary during an exterior flood event to sealseams on eight exterior doors for the turbine, auxiliary, and Unit 2 diesel generatorbuildings in accordance with the flood bulkhead installation instruction in Abnormal Operating Procedure AB-4, Attachment J, Figure J-1. In addition, AB-4 also specifies the use of the sealant, as needed, to seal any gaps on the 11 exterior flood protection panels for the turbine building, auxiliary building, screenhouse, and Unit 2 diesel generatorbuilding in accordance with AB-4, Figure J-2. These doors and panels provide a flood barrier that protects plant safety-related systems and components located below the705 foot (above mean sea level) elevation in the event of the maximum probable flood. The condition of the Deck-O-Seal sealant found by the inspectors was not in accordancewith SP 1293. The surveillance procedure specified the annual inspection of floodprotection features and materials. The licensee completed that inspection on February 17, 2006. Step 7.2.7.C specified that the performer of the flood controlmeasures inspection informs warehouse personnel to order four new kits of the sealant and to dispose of the expired shelf life sealant. This step was signed off as completed. | ||
44licensee failed to order and maintain the correct type of Deck-O-Seal sealant to facilitateinstallation of flood doors and panels in accordance with plant abnormal procedures.Description: On March 29, 2006, the inspectors inspected the main warehouse to verifythe existence of the flood protection materials listed in Table 1 of Surveillance ProcedureSP 1293, "Inspection of Flood Control Measures," Revision 13. All the listed materials were found by inspectors but the Deck-O-Seal sealant was found 1 year beyond its shelf life expiration date. Deck-O-Seal gun grade sealant is necessary during an exterior flood event to sealseams on eight exterior doors for the turbine, auxiliary, and Unit 2 diesel generatorbuildings in accordance with the flood bulkhead installation instruction in Abnormal Operating Procedure AB-4, Attachment J, Figure J-1. In addition, AB-4 also specifies the use of the sealant, as needed, to seal any gaps on the 11 exterior flood protection panels for the turbine building, auxiliary building, screenhouse, and Unit 2 diesel generatorbuilding in accordance with AB-4, Figure J-2. These doors and panels provide a flood barrier that protects plant safety-related systems and components located below the705 foot (above mean sea level) elevation in the event of the maximum probable flood. The condition of the Deck-O-Seal sealant found by the inspectors was not in accordancewith SP 1293. The surveillance procedure specified the annual inspection of floodprotection features and materials. The licensee completed that inspection on February 17, 2006. Step 7.2.7.C specified that the performer of the flood controlmeasures inspection informs warehouse personnel to order four new kits of the sealant and to dispose of the expired shelf life sealant. This step was signed off as completed. | |||
However, upon inspection of the material in the warehouse, the inspectors noted a hand-written date of March 2005 written on the sealant kits. The licensee's Shelf Life Program procedure FP-SC-PE-05, Revision 0, Step 3.7.2, requires the identifying and labeling ofage-sensitive items with a shelf life expiration date on the attached part tag or quality tag as appropriate. The inspectors concluded that the sealant was one year beyond its expiration date. The inspectors concluded that SP 1293, Step 7.2.7.C was inadequate as written since itonly required personnel performing the flood control measures inspections to notify warehouse personnel to order new sealant kits and dispose of the outdated material. | However, upon inspection of the material in the warehouse, the inspectors noted a hand-written date of March 2005 written on the sealant kits. The licensee's Shelf Life Program procedure FP-SC-PE-05, Revision 0, Step 3.7.2, requires the identifying and labeling ofage-sensitive items with a shelf life expiration date on the attached part tag or quality tag as appropriate. The inspectors concluded that the sealant was one year beyond its expiration date. The inspectors concluded that SP 1293, Step 7.2.7.C was inadequate as written since itonly required personnel performing the flood control measures inspections to notify warehouse personnel to order new sealant kits and dispose of the outdated material. | ||
There was no action to track the actual completion of the step (i.e., the actual receipt of new and the disposal of the expired sealant).The inspectors noted that the licensee had failed to follow the Shelf Life Program asrequired by procedure FP-SC-PE-05. Step 5.3.1 states that the receipt of the sealantand its corresponding shelf life shall be entered into the Material Management System database. The licensee determined that the Deck-O-Seal sealant had not been enteredinto Material Management System database. This failure resulted in the sealant exceeding its shelf life by one year.Additionally, during preparation to test the expired sealant, it was discovered that thelicensee had historically ordered and received Deck-O-Seal pourable sealant, not the gun grade sealant as specified by SP 1293. The pourable sealant is only acceptable for use in horizontal applications. The sealing of the plant's flood doors requires a sealant | There was no action to track the actual completion of the step (i.e., the actual receipt of new and the disposal of the expired sealant).The inspectors noted that the licensee had failed to follow the Shelf Life Program asrequired by procedure FP-SC-PE-05. Step 5.3.1 states that the receipt of the sealantand its corresponding shelf life shall be entered into the Material Management System database. The licensee determined that the Deck-O-Seal sealant had not been enteredinto Material Management System database. This failure resulted in the sealant exceeding its shelf life by one year.Additionally, during preparation to test the expired sealant, it was discovered that thelicensee had historically ordered and received Deck-O-Seal pourable sealant, not the gun grade sealant as specified by SP 1293. The pourable sealant is only acceptable for use in horizontal applications. The sealing of the plant's flood doors requires a sealant 45acceptable for vertical application. Upon discovery, the licensee ordered and received,overnighted, the correct sealant. | ||
45acceptable for vertical application. Upon discovery, the licensee ordered and received,overnighted, the correct sealant. | |||
=====Analysis:===== | =====Analysis:===== | ||
The inspectors reviewed the issue for significance using the guidance providedin IMC 0612, Appendix B, dated September 30, 2005. The inspectors concluded that theissue was a performance deficiency since the warehouse personnel failed to enter the receipt of the material and its associated shelf life into the Material Management System database as required by procedure FP-SC-PE-05; failed to reorder the Deck-O-Seal gun grade sealant as required by SP 1293; and failed to perform an adequate receipt inspection to determine that the sealant received was not the correct sealant for theapplication (i.e., pourable versus gun grade.) The inspectors reviewed the examples of minor findings provided in IMC 0612,Appendix E, dated September 30, 2005, and concluded that example 2E closely matchedthis finding. Specifically, not only did the sealant exceed the shelf life of the vendor, itwas also the wrong type of material for this application. The inspectors completed the significance determination of this finding using IMC 0609,"Significance Determination Process," dated March 21, 2003, Appendix A, "Determiningthe Significance of Reactor Inspection Findings for At-Power Situations," dated December 1, 2004. The Phase 1 Significance Determination worksheet identified thatthe finding did not contribute to the likelihood of a primary or secondary system loss ofcoolant accident initiator; the finding did not contribute to both the likelihood of a reactortrip and the likelihood that mitigation equipment or functions will not be available; and thefinding did not increase the likelihood of a fire or internal or external flooding. The inspectors concluded that the last Phase 1 SDP criterion of not increasing thelikelihood of external flooding was met only after the licensee demonstrated with an evaluation the slow progression (3 days) of the external flooding event, the typically short procurement time (1 day) for the Deck-O-Seal gun grade sealant, and the availability ofother potentially acceptable sealants. Therefore, the inspectors concluded that thedeficient condition did not increase the likelihood of the external flooding event affecting plant safety-related systems or components and was determined to be of very low safetysignificance (Green).Enforcement: The Introduction to 10 CFR 50, Appendix B, states the pertinentrequirements of this appendix apply to all activities affecting the safety-related functions of those SSCs: these activities include designing, purchasing, fabricating, handling, shipping, storing, cleaning, erecting, installing, inspecting, testing, operating, maintaining,repairing, refueling, and modifying. Therefore, the external flood protection featuresassociated with the safety-related structures are functions of that structure that ultimatelyprotect the safety-related systems and components contained within those structures. As such, the flood doors associated with this finding must meet the requirements of 10 CFR 50, Appendix B. Specifically, 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," states that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Instructions, procedures, or drawings shall include appropriate | The inspectors reviewed the issue for significance using the guidance providedin IMC 0612, Appendix B, dated September 30, 2005. The inspectors concluded that theissue was a performance deficiency since the warehouse personnel failed to enter the receipt of the material and its associated shelf life into the Material Management System database as required by procedure FP-SC-PE-05; failed to reorder the Deck-O-Seal gun grade sealant as required by SP 1293; and failed to perform an adequate receipt inspection to determine that the sealant received was not the correct sealant for theapplication (i.e., pourable versus gun grade.) The inspectors reviewed the examples of minor findings provided in IMC 0612,Appendix E, dated September 30, 2005, and concluded that example 2E closely matchedthis finding. Specifically, not only did the sealant exceed the shelf life of the vendor, itwas also the wrong type of material for this application. The inspectors completed the significance determination of this finding using IMC 0609,"Significance Determination Process," dated March 21, 2003, Appendix A, "Determiningthe Significance of Reactor Inspection Findings for At-Power Situations," dated December 1, 2004. The Phase 1 Significance Determination worksheet identified thatthe finding did not contribute to the likelihood of a primary or secondary system loss ofcoolant accident initiator; the finding did not contribute to both the likelihood of a reactortrip and the likelihood that mitigation equipment or functions will not be available; and thefinding did not increase the likelihood of a fire or internal or external flooding. The inspectors concluded that the last Phase 1 SDP criterion of not increasing thelikelihood of external flooding was met only after the licensee demonstrated with an evaluation the slow progression (3 days) of the external flooding event, the typically short procurement time (1 day) for the Deck-O-Seal gun grade sealant, and the availability ofother potentially acceptable sealants. Therefore, the inspectors concluded that thedeficient condition did not increase the likelihood of the external flooding event affecting plant safety-related systems or components and was determined to be of very low safetysignificance (Green).Enforcement: The Introduction to 10 CFR 50, Appendix B, states the pertinentrequirements of this appendix apply to all activities affecting the safety-related functions of those SSCs: these activities include designing, purchasing, fabricating, handling, shipping, storing, cleaning, erecting, installing, inspecting, testing, operating, maintaining,repairing, refueling, and modifying. Therefore, the external flood protection featuresassociated with the safety-related structures are functions of that structure that ultimatelyprotect the safety-related systems and components contained within those structures. As such, the flood doors associated with this finding must meet the requirements of 10 CFR 50, Appendix B. Specifically, 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," states that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Instructions, procedures, or drawings shall include appropriate 46quantitative or qualitative acceptance criteria for determining that important activitieshave been satisfactorily accomplished.Contrary to the above, on March 29, 2006, inspectors identified that the licensee failed toinclude appropriate quantitative or qualitative acceptance criteria for determining thatimportant activities have been satisfactorily accomplished. Specifically that Step 7.2.7.Cof Surveillance Procedure 1293 failed to track the reorder of new sealant and the removal of the expired sealant until satisfactorily accomplishment. This failure resulted in a critical procedure step to go uncompleted for an extended period of time. Additionally, the inspectors identified that the licensee had failed to follow procedureFP-SC-PE-05. Specifically, Step 5.3.1 states that the receipt of the sealant and itscorresponding shelf life shall be entered into the Material Management System database. | ||
46quantitative or qualitative acceptance criteria for determining that important activitieshave been satisfactorily accomplished.Contrary to the above, on March 29, 2006, inspectors identified that the licensee failed toinclude appropriate quantitative or qualitative acceptance criteria for determining thatimportant activities have been satisfactorily accomplished. Specifically that Step 7.2.7.Cof Surveillance Procedure 1293 failed to track the reorder of new sealant and the removal of the expired sealant until satisfactorily accomplishment. This failure resulted in a critical procedure step to go uncompleted for an extended period of time. Additionally, the inspectors identified that the licensee had failed to follow procedureFP-SC-PE-05. Specifically, Step 5.3.1 states that the receipt of the sealant and itscorresponding shelf life shall be entered into the Material Management System database. | |||
The licensee found that the Deck-O-Seal sealant had not been entered into MaterialManagement System database. This failure resulted in the sealant exceeding its shelf life by 1 year.Finally, the licensee failed to correctly implement SP 1293 in that they had historicallyordered, received, and accepted Deck-O-Seal pourable sealant, not the gun grade sealant as specified by the procedure. This resulted in the maintenance of an unusable form of sealant on site for an extended period of time. Because this violation was of very low safety significance and it was entered into thelicensee's corrective action program with CAPs 01021256 and 01025266, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000282/2006003-05; 05000306/2006003-05). | The licensee found that the Deck-O-Seal sealant had not been entered into MaterialManagement System database. This failure resulted in the sealant exceeding its shelf life by 1 year.Finally, the licensee failed to correctly implement SP 1293 in that they had historicallyordered, received, and accepted Deck-O-Seal pourable sealant, not the gun grade sealant as specified by the procedure. This resulted in the maintenance of an unusable form of sealant on site for an extended period of time. Because this violation was of very low safety significance and it was entered into thelicensee's corrective action program with CAPs 01021256 and 01025266, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000282/2006003-05; 05000306/2006003-05). | ||
| Line 595: | Line 588: | ||
===.4 Head Assembly Upgrade Package (HAUP) (71007)During the Unit 1 Spring 2006 refueling outage, the licensee elected to install a reactorHAUP that integrated the design of various plant components and structures into thereactor head assembly.=== | ===.4 Head Assembly Upgrade Package (HAUP) (71007)During the Unit 1 Spring 2006 refueling outage, the licensee elected to install a reactorHAUP that integrated the design of various plant components and structures into thereactor head assembly.=== | ||
This integration involved the re-use of some plant components and the complete replacement of others including: | This integration involved the re-use of some plant components and the complete replacement of others including: | ||
48*CRDM cooling internal ducts;*new integral reactor vessel missile shield; | 48*CRDM cooling internal ducts;*new integral reactor vessel missile shield; | ||
*reactor vessel head lift rig; | *reactor vessel head lift rig; | ||
*CRDM/rod position indication cable | *CRDM/rod position indication cable drawbri dge;*handrail modifications and new ladders; | ||
*new integral radiation shielding; and | *new integral radiation shielding; and | ||
*reactor vessel head insulation. | *reactor vessel head insulation. | ||
| Line 609: | Line 601: | ||
No findings of significance were identified. | No findings of significance were identified. | ||
===.5 Closure of Unresolved Item | ===.5 Closure of Unresolved Item=== | ||
49modification to the HAUP structure. Therefore, no findings of significance were identifiedas a result of the original URI concerns. The inspectors further interviewed licensee staff performing owner's acceptance reviewsfor Unit 1 HAUP design calculations, reviewed a licensee root cause evaluation related to minor errors in calculations, and reviewed licensee procedures related to design calculations, design interfaces, design verification, and technical review. The inspectors also reviewed a sample of HAUP design calculations during inspection activities for the Unit 1 HAUP installation. No findings of significance were identified. (Section OA5.2)In summary, no violations were identified. This item is closed. | (Closed) URI 05000306/2005004-07: Unable to Determine Significance of HAUP DesignConcerns During the inspection of modifications related to the Unit 2 HAUP installation (refer toInspection Report 05000282/2005004; 05000306/2005004 (ML052020420)), the inspectors identified a number of HAUP calculation concerns related to design loads, design methods, numerical errors, and the basis for acceptance criteria that were utilizedin the calculations. The licensee entered these unresolved issues into their corrective action system as condition report CAP 043325. From April 24 through 28, 2006, from May 1 through 5, 2006, and from May 15through 19, 2006, the inspectors reviewed the licensee's corrective actions for the unresolved issues identified in CAP 043325 (CAP 00864144, NRC Head ReplacementQuestions, dated November 30, 2005). Where necessary, the licensee/vendor revised calculations to resolve the unresolved issues (Calculation Notes CN-RVHP-04-87 and CN-RVHP-04-90). Also, the inspectors determined that LOCA loads (NSAL-05-1, Nuclear Safety Advisory Letter: Reactor Vessel Head Assembly LOCA Loads, dated January 18, 2005) were applied to non-safety-related HAUP structures that could impact safety-related structures (i.e., calculation note CN-RVHP-05-17, Prairie Island Units 1 and 2 - Evaluation of Non-Safety-Related Components for LOCA). The HAUP structures were determined to meet all design code acceptance limits without requiring a 49modification to the HAUP structure. Therefore, no findings of significance were identifiedas a result of the original URI concerns. The inspectors further interviewed licensee staff performing owner's acceptance reviewsfor Unit 1 HAUP design calculations, reviewed a licensee root cause evaluation related to minor errors in calculations, and reviewed licensee procedures related to design calculations, design interfaces, design verification, and technical review. The inspectors also reviewed a sample of HAUP design calculations during inspection activities for the Unit 1 HAUP installation. No findings of significance were identified. (Section OA5.2)In summary, no violations were identified. This item is closed. | ||
===.6 Replacement Head Installation and Testing=== | ===.6 Replacement Head Installation and Testing=== | ||
| Line 631: | Line 622: | ||
*Reactor vessel head replacement procedure (IP 71007) with Mr. T. Palmisano, SiteVice President, and other members of the licensee's staff on May 19, 2006. The licensee confirmed that the design documentation prepared by WEC and MHI was considered proprietary. It was agreed that all copies of proprietary documentation not returned to the licensee would be shredded. | *Reactor vessel head replacement procedure (IP 71007) with Mr. T. Palmisano, SiteVice President, and other members of the licensee's staff on May 19, 2006. The licensee confirmed that the design documentation prepared by WEC and MHI was considered proprietary. It was agreed that all copies of proprietary documentation not returned to the licensee would be shredded. | ||
50*Outage Access Control to Radiologically Significant Areas and ALARA Programinspection with Mr. P. Huffman, Plant Manager, and Mr. T. Palmisano, Site Vice President, on May 12, 2006; and Mr. P. Huffman, Plant Manager, on May 25, 2006.*Inservice Inspection IP 71111.08 with Mr. Steve Brown on June 9, 2006.4OA7Licensee-Identified ViolationsThe following violations of very low significance (Green) were identified by the licenseeand are violations of NRC requirements which meets the criteria of Section VI of the NRCEnforcement Manual, NUREG-1600, for being dispositioned as NCVs.Cornerstone: Mitigating Systems10 CFR 50.65(a)(4) requires that risk be assessed and managed for maintenance. Contrary to this, on May 6, 2006, risk was incorrectly calculated as Yellow followingthe unplanned unavailability of the 121 instrument air compressor concurrent withthe planned unavailability of diesel generator D2, 11 cooling water pump, safeguards4 kilovolt bus 16, and the 12 AFW pump. Consequently, compensatory actions and contingency plans were not identified for an Orange risk condition as required by the licensee's procedure H24.1, "Assessment and Management of Risk Associated with Maintenance Activities." This was identified in the licensee's corrective action program as CAP 01028790. This finding is of very low safety significance because the air compressor was repaired and returned to service within the risk informed allowed outage time. 10 CFR 50, Appendix B, Criterion III, Design Control, requires that measures beestablished to assure that deviations from quality standards are controlled. Contrary to this, on May 11, 2006, it was identified that non-safety-related parts were used in safety-related 4 kilovolt switchgear to fasten the shutter guide to the fixed shroud. This was part of an ongoing maintenance practice that replaced broken nylon bolts with supplies from non-safety-related shop supplies. This was identified in the licensee's corrective action program as CAP 01029449. This finding is of very low safety significance because there were no failures that resulted in safety-related equipment becoming inoperable.Cornerstone: Occupational Radiation SafetyThe licensee's TS 5.7.1 a. states that for High Radiation Areas accessible to personnel,each entryway to such an area shall be barricaded. Contrary to this, on May 1, 2006, the licensee identified that a radiation worker removed a High Radiation Area boundary swing gate (barricade) at the access to the top of the Unit 1 pressurizer vault to position one leg of the stand for the Pressurizer Missile Shield without receiving approval for removing the barricade from the Radiation Protection staff. Upon identifying the noncompliance, the Radiation Protection staff walked-down the pressurizer vault to ensure all personnel were on a High Radiation Area Radiation Work Permit, validated all Locked High Radiation and High Radiation Area postings in Unit 1 containment and auxiliary building, and started a Human Performance Event Investigation(CAP 01027384). The finding was of very low safety significance because it did not | 50*Outage Access Control to Radiologically Significant Areas and ALARA Programinspection with Mr. P. Huffman, Plant Manager, and Mr. T. Palmisano, Site Vice President, on May 12, 2006; and Mr. P. Huffman, Plant Manager, on May 25, 2006.*Inservice Inspection IP 71111.08 with Mr. Steve Brown on June 9, 2006.4OA7Licensee-Identified ViolationsThe following violations of very low significance (Green) were identified by the licenseeand are violations of NRC requirements which meets the criteria of Section VI of the NRCEnforcement Manual, NUREG-1600, for being dispositioned as NCVs.Cornerstone: Mitigating Systems10 CFR 50.65(a)(4) requires that risk be assessed and managed for maintenance. Contrary to this, on May 6, 2006, risk was incorrectly calculated as Yellow followingthe unplanned unavailability of the 121 instrument air compressor concurrent withthe planned unavailability of diesel generator D2, 11 cooling water pump, safeguards4 kilovolt bus 16, and the 12 AFW pump. Consequently, compensatory actions and contingency plans were not identified for an Orange risk condition as required by the licensee's procedure H24.1, "Assessment and Management of Risk Associated with Maintenance Activities." This was identified in the licensee's corrective action program as CAP 01028790. This finding is of very low safety significance because the air compressor was repaired and returned to service within the risk informed allowed outage time. 10 CFR 50, Appendix B, Criterion III, Design Control, requires that measures beestablished to assure that deviations from quality standards are controlled. Contrary to this, on May 11, 2006, it was identified that non-safety-related parts were used in safety-related 4 kilovolt switchgear to fasten the shutter guide to the fixed shroud. This was part of an ongoing maintenance practice that replaced broken nylon bolts with supplies from non-safety-related shop supplies. This was identified in the licensee's corrective action program as CAP 01029449. This finding is of very low safety significance because there were no failures that resulted in safety-related equipment becoming inoperable.Cornerstone: Occupational Radiation SafetyThe licensee's TS 5.7.1 a. states that for High Radiation Areas accessible to personnel,each entryway to such an area shall be barricaded. Contrary to this, on May 1, 2006, the licensee identified that a radiation worker removed a High Radiation Area boundary swing gate (barricade) at the access to the top of the Unit 1 pressurizer vault to position one leg of the stand for the Pressurizer Missile Shield without receiving approval for removing the barricade from the Radiation Protection staff. Upon identifying the noncompliance, the Radiation Protection staff walked-down the pressurizer vault to ensure all personnel were on a High Radiation Area Radiation Work Permit, validated all Locked High Radiation and High Radiation Area postings in Unit 1 containment and auxiliary building, and started a Human Performance Event Investigation(CAP 01027384). The finding was of very low safety significance because it did not 51result in an unmonitored or unplanned personnel exposures as a result of the barrierloss.The licensee's TS 5.7.1 a. states that for High Radiation Areas accessible to personnel,each entryway to such an area shall be barricaded. Contrary to this, on May 29, 2006, Radiation Protection staff identified that a radiation worker removed a High RadiationArea boundary swing gate (barricade) at the access to 12 RHR vault and it remained inthe open position. Upon identifying the noncompliance, the Radiation Protection staffcorrected the swing gate position and repaired a guide that was improperly placed and caused the swing gate to bind allowing it to remain open. Additionally, the staff walked-down all similar High Radiation Area swing gates to verify that the gates were operatingproperly (CAP 01032792). The finding was of very low safety significance because it did not result in an unmonitored or unplanned personnel exposures as a result of the barrier loss.ATTACHMENT: | ||
51result in an unmonitored or unplanned personnel exposures as a result of the barrierloss.The licensee's TS 5.7.1 a. states that for High Radiation Areas accessible to personnel,each entryway to such an area shall be barricaded. Contrary to this, on May 29, 2006, Radiation Protection staff identified that a radiation worker removed a High RadiationArea boundary swing gate (barricade) at the access to 12 RHR vault and it remained inthe open position. Upon identifying the noncompliance, the Radiation Protection staffcorrected the swing gate position and repaired a guide that was improperly placed and caused the swing gate to bind allowing it to remain open. Additionally, the staff walked-down all similar High Radiation Area swing gates to verify that the gates were operatingproperly (CAP 01032792). The finding was of very low safety significance because it did not result in an unmonitored or unplanned personnel exposures as a result of the barrier loss.ATTACHMENT: | |||
=SUPPLEMENTAL INFORMATION= | =SUPPLEMENTAL INFORMATION= | ||
| Line 658: | Line 647: | ||
: [[contact::J. Wren]], NDE Level IIINuclear Regulatory Commission | : [[contact::J. Wren]], NDE Level IIINuclear Regulatory Commission | ||
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED== | ==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED== | ||
===Opened=== | |||
05000282/2006003-01;NCVUpdated Safety Analysis Report Change That Removedthe Reactor Vessel Head Lift Elevation Limit and | |||
Reference to the Associated Reactor Vessel Head Load | Reference to the Associated Reactor Vessel Head Load | ||
Drop Calculation05000282/2006003-02;05000306/2006003-02NCVNRC Identified Loss of High Radiation Area Barricade atUnit 1 Pressurizer Missile Shield05000282/2006003-03;05000306/2006003-03NCVAlara Planning Does Not Identify and Prepare forPotential Airborne Conditions When Opening the Steam | Drop Calculation05000282/2006003-02;05000306/2006003-02NCVNRC Identified Loss of High Radiation Area Barricade atUnit 1 Pressurizer Missile Shield05000282/2006003-03;05000306/2006003-03NCVAlara Planning Does Not Identify and Prepare forPotential Airborne Conditions When Opening the Steam | ||
Generator Manways05000282/2006003-04;05000306/2006003-04NCVProcedure For ODCM Compliance Does Not IncludeContainment Effluent Through Equipment Hatch | Generator Manways05000282/2006003-04;05000306/2006003-04NCVProcedure For ODCM Compliance Does Not IncludeContainment Effluent Through Equipment Hatch | ||
: 05000282/2006003-05;05000306/2006003-05NCVFailure to Follow Procedures for External Flooding | : 05000282/2006003-05;05000306/2006003-05NCVFailure to Follow Procedures for External Flooding | ||
2 | 2 | ||
===Closed=== | ===Closed=== | ||
| Line 675: | Line 667: | ||
: 05000282/2006003-05; | : 05000282/2006003-05; | ||
: [[Closes finding::05000306/FIN-2006003-05]]NCVFailure to Follow Procedures for External FloodingDiscussedNone. | : [[Closes finding::05000306/FIN-2006003-05]]NCVFailure to Follow Procedures for External FloodingDiscussedNone. | ||
: | : 3 | ||
==LIST OF DOCUMENTS REVIEWED== | ==LIST OF DOCUMENTS REVIEWED== | ||
The following is a list of documents reviewed during the inspection. | The following is a list of documents reviewed during the inspection. | ||
| Line 691: | Line 683: | ||
: CAP 01035016; | : CAP 01035016; | ||
: MD-32427 Did Not Close During TP 2296B | : MD-32427 Did Not Close During TP 2296B | ||
: CAP 01035844; NRC Found 2 Temperature Switches On D1/D2 Not in Checklist Position1R02Evaluation of Changes, Tests, or ExperimentsDesign Change 03RV05 Part 1; Replace Unit 1 and 2 Reactor Vessel Heads and AssociatedComponents; Revision 1 | : CAP 01035844; | ||
: NRC Found 2 Temperature Switches On D1/D2 Not in Checklist Position1R02Evaluation of Changes, Tests, or ExperimentsDesign Change 03RV05 Part 1; Replace Unit 1 and 2 Reactor Vessel Heads and AssociatedComponents; Revision 1 | |||
: Design Change 03RV05 Part 2; Reactor Vessel Head Assembly Upgrade Package; Revision 1 | : Design Change 03RV05 Part 2; Reactor Vessel Head Assembly Upgrade Package; Revision 1 | ||
: CFR 50.59 Evaluation 1052; Heavy Loads Licensing Bases; Revision 0 | : CFR 50.59 Evaluation 1052; Heavy Loads Licensing Bases; Revision 0 | ||
| Line 706: | Line 699: | ||
: CFR 50.59 Screening 2628; Design Change 03RV05 Part 2, Unit 1 and Unit 2 Evaluation of Non-Safety-Related Components for LOCA; Revision 0 | : CFR 50.59 Screening 2628; Design Change 03RV05 Part 2, Unit 1 and Unit 2 Evaluation of Non-Safety-Related Components for LOCA; Revision 0 | ||
: PINGP USAR; Section 12.2.12.1.4; Containment Polar Crane Evaluation; Revision 27 | : PINGP USAR; Section 12.2.12.1.4; Containment Polar Crane Evaluation; Revision 27 | ||
: | : 41R04Equipment AlignmentD2 Diesel GeneratorIntegrated Checklist C1.1.20.7-1; D2 Diesel Generator Valve Status; Revision 20Integrated Checklist C1.1.20.7-2; D2 Diesel Generator Auxiliaries and Local Panels andSwitches; Revision 9 | ||
: Integrated Checklist C1.1.20.7-3; D2 Diesel Generator Main Control Room Switch and IndicatingLight Status; Revision 15 | : Integrated Checklist C1.1.20.7-3; D2 Diesel Generator Main Control Room Switch and IndicatingLight Status; Revision 15 | ||
: Integrated Checklist C1.1.20.7-4; D2 Diesel Generator Circuit Breakers and Panel Switches;Revision 1212 Motor-Driven AFW PumpSystem Prestart Checklist C28-15; 12 Motor-Driven AFW Pump; Revision 4 | : Integrated Checklist C1.1.20.7-4; D2 Diesel Generator Circuit Breakers and Panel Switches;Revision 1212 Motor-Driven AFW PumpSystem Prestart Checklist C28-15; 12 Motor-Driven AFW Pump; Revision 4 | ||
: D6 Diesel GeneratorIntegrated Checklist C1.1.20.7-13; D6 Diesel Generator Valve Status; Revision 14Integrated Checklist C1.1.20.7-14; D6 Diesel Generator Auxiliaries and Local Panels andSwitches; Revision 12 | : D6 Diesel GeneratorIntegrated Checklist C1.1.20.7-13; D6 Diesel Generator Valve Status; Revision 14Integrated Checklist C1.1.20.7-14; D6 Diesel Generator Auxiliaries and Local Panels andSwitches; Revision 12 | ||
: Integrated Checklist C1.1.20.7-15; D6 Diesel Generator Main Control Room Switch andIndicating Light Status; Revision 6 | : Integrated Checklist C1.1.20.7-15; D6 Diesel Generator Main Control Room Switch andIndicating Light Status; Revision 6 | ||
: Integrated Checklist C1.1.20.7-16; D6 Diesel Generator Circuit Breakers and Panel Switches;Revision 81R05Fire ProtectionPlant Safety Procedure F5, Appendix A, Revision 15; Fire Strategies for Fire Areas 1, 18, 20, 68,102, 106, 114, 118, and 122 | : Integrated Checklist C1.1.20.7-16; D6 Diesel Generator Circuit Breakers and Panel Switches;Revision 81R05Fire ProtectionPlant Safety Procedure F5, Appendix A, Revision 15; Fire Strategies for Fire Areas 1, 18, 20, 68, 102, 106, 114, 118, and 122 | ||
: Plant Safety Procedure F5, Appendix F, Revision 19; Fire Hazard Analysis for Fire Areas 1, 18, | : Plant Safety Procedure F5, Appendix F, Revision 19; Fire Hazard Analysis for Fire Areas 1, 18, | ||
: 20, 68, 102, 106, 114, 118, and 122 | : 20, 68, 102, 106, 114, 118, and 122 | ||
| Line 721: | Line 714: | ||
: 50.59 Evaluation 1025; Zebra Mussel Treatment; Circulating Water System; April 11, 2006 | : 50.59 Evaluation 1025; Zebra Mussel Treatment; Circulating Water System; April 11, 2006 | ||
: Operator Logs for April 19 - 21, 2006 | : Operator Logs for April 19 - 21, 2006 | ||
: | : 51R08Inservice Inspection ActivitiesDocuments Associated with ASME Code Nondestructive Examinations (NDEs) ObservedSection Work Instruction (SWI) | ||
: NDE-UT-16A; Ultrasonic Examination of Austenitic Piping Weldsto Appendix VIII; dated March 2006SWI | : NDE-UT-16A; Ultrasonic Examination of Austenitic Piping Weldsto Appendix VIII; dated March | ||
: 2006SWI | |||
: NDE-VT-2.0; Visual Examination of Components & Their Supports; dated March 2006 | : NDE-VT-2.0; Visual Examination of Components & Their Supports; dated March 2006 | ||
: SWI | : SWI | ||
| Line 750: | Line 744: | ||
: CAP 01027175; Relevant Indication on | : CAP 01027175; Relevant Indication on | ||
: MV-32065Documents Associated with Steam Generator ExaminationsSWI | : MV-32065Documents Associated with Steam Generator ExaminationsSWI | ||
: NDE-ET-5; Site Specific Performance Demonstration; dated April 21, 20061H25.1; Unit 1 Assessment of Steam Generator Tube Degradation Mechanisms; dated April 21,2006Corrective Action Program DocumentsCAP | : NDE-ET-5; Site Specific Performance Demonstration; dated April 21, 20061H25.1; Unit 1 Assessment of Steam Generator Tube Degradation Mechanisms; dated April 21, 2006Corrective Action Program DocumentsCAP | ||
: 01027249; ISI Exam Found Lugs on Snubber (SIRH-9) Welded to Clamp; dated May 1,2006 | : 01027249; ISI Exam Found Lugs on Snubber (SIRH-9) Welded to Clamp; dated May 1, 2006 | ||
: CAP 01027258; ISI Exam Revealed Loose Nuts on Snubber (SIRH-11); dated May 1, 2006 | : CAP 01027258; ISI Exam Revealed Loose Nuts on Snubber (SIRH-11); dated May 1, 2006 | ||
: CAP 01027266; ISI Exam Revealed Insufficient Thread Engagement; dated May 1, 20061R11Licensed Operator Requalification ProgramSimulator Evaluation Guide P9160S-001, ATT SQ54; Revision 0Administrative Work Instruction 5AWI 3.15.0; Plant Operation; Revision 17 | : CAP 01027266; ISI Exam Revealed Insufficient Thread Engagement; dated May 1, 20061R11Licensed Operator Requalification ProgramSimulator Evaluation Guide P9160S-001, ATT SQ54; Revision 0Administrative Work Instruction 5AWI 3.15.0; Plant Operation; Revision 17 | ||
: | : 61R12Maintenance EffectivenessMaintenance Rule Status Chart; June 27, 2006CAP | ||
: 01012627; 124 Station Air Compressor Jacket Cooling Outlet Temperature High | : 01012627; 124 Station Air Compressor Jacket Cooling Outlet Temperature High | ||
: CAP 01013896; | : CAP 01013896; | ||
| Line 781: | Line 775: | ||
: 01024213; Unit 1 Reactor Tripped After Losing 50% FW Flow from 100%Operator Response to a Unit 2 Overpower TransientOperating Logs from May 16 and 17, 2006CAP | : 01024213; Unit 1 Reactor Tripped After Losing 50% FW Flow from 100%Operator Response to a Unit 2 Overpower TransientOperating Logs from May 16 and 17, 2006CAP | ||
: 01030453;Possible Power Excursion Above Licensed Level of 1650 MWth [Mega-Watts thermal] | : 01030453;Possible Power Excursion Above Licensed Level of 1650 MWth [Mega-Watts thermal] | ||
: | : 71R15Operability EvaluationsCAP 01011542CAP | ||
: 01011542; Loose Material Found in Unit 1 Residual Heat Removal Pump Pit Flood Barrier(prompt operability assessment)CAP | : 01011542; Loose Material Found in Unit 1 Residual Heat Removal Pump Pit Flood Barrier(prompt operability assessment)CAP | ||
: 01011542-02; Loose Material Found in Unit 1 Residual Heat Removal Pump Pit Flood Barrier (historical operability assessment)VC-24-1CAP | : 01011542-02; Loose Material Found in Unit 1 Residual Heat Removal Pump Pit Flood Barrier (historical operability assessment)VC-24-1CAP | ||
| Line 809: | Line 803: | ||
: 0509256; Replace Air Supply to Accumulator Check ValvesWO | : 0509256; Replace Air Supply to Accumulator Check ValvesWO | ||
: 100114-03; Replace Air Regulator to Control Valve | : 100114-03; Replace Air Regulator to Control Valve | ||
: CAP 01032809; 11 Turbine-Driven AFW Pump Steam Admission Valve Accumulator Check Valve Test | : CAP 01032809; 11 Turbine-Driven AFW Pump Steam Admission Valve Accumulator Check Valve Test | ||
: 8Repacking of 11 Turbine-Driven AFW Pump Valves | |||
: AF-13-3 and | : AF-13-3 and | ||
: CV 31998WO 88083; Replace Packing in | : CV 31998WO 88083; Replace Packing in | ||
| Line 825: | Line 820: | ||
: 01027489; Issues Associated With C4.1 Draindown of Unit 1 RCS | : 01027489; Issues Associated With C4.1 Draindown of Unit 1 RCS | ||
: Special Operations Procedure D5.2; Reactor Refueling Operations; Revision 45 | : Special Operations Procedure D5.2; Reactor Refueling Operations; Revision 45 | ||
: CAP 01031485; Unclear Procedure Guidance for Unit 1 D581R22Surveillance | : CAP 01031485; Unclear Procedure Guidance for Unit 1 D581R22Surveillance Testing | ||
: SP 2093SP 2093; D5 Diesel Generator Monthly; Revision 77CAP | |||
: 01025789; Low Lubricating Oil Level on D5 Engine 1 and 2 During Slow Start Run | : 01025789; Low Lubricating Oil Level on D5 Engine 1 and 2 During Slow Start Run | ||
: CAP 01025471; Low Lubricating Oil Sump Level on D5 Engine 1 and 2 During | : CAP 01025471; Low Lubricating Oil Sump Level on D5 Engine 1 and 2 During SP 2093 | ||
: SP | : SP 1405SP 1405; Unit 1 Mid-Cycle and Refueling Outage Boric Acid Corrosion Examinations InsideContainment; Revision 1 | ||
: SP 1407; Leakage Examination of Canopy Seals, Mechanical Joints, and Other Pressure Retaining Components on the Reactor Head; Revision 0 | : SP 1407; Leakage Examination of Canopy Seals, Mechanical Joints, and Other Pressure Retaining Components on the Reactor Head; Revision 0 | ||
: | : 9Relevant Boric Acid CAPs including: | ||
: 01026969, | : 01026969, | ||
: 01027041,01027046, | : 01027041,01027046, | ||
: 01027048, | : 01027048, | ||
: 01027052,01027054, | : 01027052, | ||
: 01027054, | |||
: 01027091, | : 01027091, | ||
: 01027103,and | : 01027103,and 01027175 | ||
: SP 1088ASP 1088A; Train A Safety Injection Quarterly Test: | |||
: Revision 10 | : Revision 10 | ||
: SP1092SP1092B; Safety Injection Check Valve Test (Head Off) Part B: | : SP1092SP1092B; Safety Injection Check Valve Test (Head Off) Part B: | ||
| Line 842: | Line 840: | ||
: SP1092C; SI Check Valve Test (Head Off) Part C: | : SP1092C; SI Check Valve Test (Head Off) Part C: | ||
: Accumulator Flow Path Verification; | : Accumulator Flow Path Verification; | ||
: Revision | : Revision 10 | ||
: 01027222; Unit 1 RMU to Demin Crosstie | : SP1072.45SP 1072.45; Local Leakage Rate Test of Penetration 45 (Reactor Water Makeup); Revision 17CAP | ||
: 01027222; Unit 1 RMU to Demin Crosstie RC-4-12 | |||
: 01031679; 121 Motor-Driven Cooling Water Pump Performance in the Action Range SP1083SP 1083, Unit 1 Integrated SI Test With a Simulated Loss of Offsite Power; Revision 31CAP | : SP 1106CSP 1106C; 121 Cooling Water Pump Quarterly Test; Revision 28CAP | ||
: 01031679; 121 Motor-Driven Cooling Water Pump Performance in the Action Range | |||
: SP1083SP 1083, Unit 1 Integrated SI Test With a Simulated Loss of Offsite Power; Revision 31CAP | |||
: 01032656; BOP Power Failure Annunciator with NSSS Trouble Alarm | : 01032656; BOP Power Failure Annunciator with NSSS Trouble Alarm | ||
: CAP 01032658; All Inverter AC Input Breakers Tripped Open During SP 1083 | : CAP 01032658; All Inverter AC Input Breakers Tripped Open During SP 1083 | ||
: CAP 01032779; High Standards Not Exhibited During SI Briefings | : CAP 01032779; High Standards Not Exhibited During SI Briefings | ||
: SP 1750SP 1750; Post-Outage Containment Closeout Inspection; Revision 30CAP | : SP 1750SP 1750; Post-Outage Containment Closeout Inspection; Revision 30CAP | ||
: 01033737; Scaffold Knuckle Found In | : 01033737; Scaffold Knuckle Found In Containment | ||
: SP 1070SP 1070; Reactor Coolant System Integrity Test; Revision 37 | |||
: 1R23Temporary Modifications4T-175Maintenance Procedure 1D108; Pressurizer PORV Air Accumulator Supplementation;Revision 1 | : 1R23Temporary Modifications4T-175Maintenance Procedure 1D108; Pressurizer PORV Air Accumulator Supplementation;Revision 1 | ||
: ENG-ME-592; Determine the Minimum Amount of Air Pressure to Fully Stroke Pressurizer | : ENG-ME-592; Determine the Minimum Amount of Air Pressure to Fully Stroke Pressurizer | ||
| Line 857: | Line 858: | ||
: NSP-04-189; Data on Pressurizer PORV Cycling During Cold Overpressure Mitigation System Transients - New Analysis | : NSP-04-189; Data on Pressurizer PORV Cycling During Cold Overpressure Mitigation System Transients - New Analysis | ||
: CAP 01027161; Air Leak on Union Between | : CAP 01027161; Air Leak on Union Between | ||
: CV-31231 and Solenoid Valve | : CV-31231 and Solenoid Valve | ||
: 1EP6Drill EvaluationSimulator Evaluation Guide P9160S-001, ATT SQ54; Revision 0 | |||
==2OS1 Access Control to Radiologically Significant AreasCAP | |||
: 1027384; Removal of High Radiation Boundary by Unauthorized Personnel; May 1, 2006CAP | : 1027384; Removal of High Radiation Boundary by Unauthorized Personnel; May 1, 2006CAP | ||
: 1028608; Worker Removed Radiation Boundary to By-pass Turnstile at Access; May 8, | : 1028608; Worker Removed Radiation Boundary to By-pass Turnstile at Access; May 8,== | ||
: 2006 | : 2006 | ||
: CAP 1029288; High Radiation Area Swing Gate Turned Due to Loose Base; May 10, 2006 | : CAP 1029288; High Radiation Area Swing Gate Turned Due to Loose Base; May 10, 2006 | ||
| Line 872: | Line 876: | ||
: May 25, 2006 | : May 25, 2006 | ||
: CAP 1028824; Temporary Radiation Controlled Area for Reactor Head Planned Too Large, May 9, 2006 | : CAP 1028824; Temporary Radiation Controlled Area for Reactor Head Planned Too Large, May 9, 2006 | ||
: PINGP 258; Radiation Protection Survey Record, Spent Resin Tank Room; May 5, | : PINGP 258; Radiation Protection Survey Record, Spent Resin Tank Room; May 5, 2006 | ||
==2OS2 As Low As Is Reasonably Achievable Planning and Controls (ALARA)ACE | |||
: 1027653; Elevated Iodine-131 Level in Unit 1 Containment During 1R24; June 9, 2006CAP | : 1027653; Elevated Iodine-131 Level in Unit 1 Containment During 1R24; June 9, 2006CAP | ||
: 1027645; High Airborne Unit 1 Containment Due to Steam Generator Venting; May 3, 2006CAP | : 1027645; High Airborne Unit 1 Containment Due to Steam Generator Venting; May 3, 2006CAP | ||
: 1028594; Control of Receipt Area Roll Up Doors Poor; May 7, 2006 | : 1028594; Control of Receipt Area Roll Up Doors Poor; May 7, 2006== | ||
: CAP 1029400; Auxiliary Building and Spent Fuel Pool Vent Releases Higher Than Expected;May 10, 2006 | : CAP 1029400; Auxiliary Building and Spent Fuel Pool Vent Releases Higher Than Expected;May 10, 2006 | ||
: CAP 1029875; Radiation Protection Chemistry Does Not Have Plan for Challenges to Offsite Dose Calculation Limits; May 13, 2006 | : CAP 1029875; Radiation Protection Chemistry Does Not Have Plan for Challenges to Offsite Dose Calculation Limits; May 13, 2006 | ||
| Line 895: | Line 901: | ||
: RPIP 1126; Contamination Monitor Alarm Response and Personnel Decontamination; | : RPIP 1126; Contamination Monitor Alarm Response and Personnel Decontamination; | ||
: Revision 21 | : Revision 21 | ||
: | : 11RWP 563; Primary Manway Insert and Remove, Revision 0RWP 609; Eddy Current Testing of Steam Generator Tubes, Revision 0 | ||
: WO 95654; 11 and 12 Steam Generator Primary Side Manway Insert Remove and Install | : WO 95654; 11 and 12 Steam Generator Primary Side Manway Insert Remove and Install | ||
: WO 95655; 95656; 11 and 12 Primary Side Eddy Current Testing of Steam Generator TubesWO 95727; Disassemble Reactor In-Accordance-With D3; May 2, 2006 | : WO 95655; 95656; 11 and 12 Primary Side Eddy Current Testing of Steam Generator TubesWO 95727; Disassemble Reactor In-Accordance-With D3; May 2, 2006 | ||
: WO 99051; Sump C When Hosted High Radiation Area; February 27, 2006 | : WO 99051; Sump C When Hosted High Radiation Area; February 27, 2006 | ||
: Minutes of Emergent Site ALARA Committee Meeting; May 10, | : Minutes of Emergent Site ALARA Committee Meeting; May 10, 2006 | ||
==2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems== | |||
: CAP 1027608; Inadequate Effluent Release Controls at the Unit 1 Equipment Hatch;May 2, 2006 | : CAP 1027608; Inadequate Effluent Release Controls at the Unit 1 Equipment Hatch;May 2, 2006 | ||
: CAP 1028580; Lack of Communication for Effluent Release; May 7, 2006 | : CAP 1028580; Lack of Communication for Effluent Release; May 7, 2006 | ||
| Line 915: | Line 923: | ||
: RPIP 4511; Airborne Continuous Release Report; Revision 8 | : RPIP 4511; Airborne Continuous Release Report; Revision 8 | ||
: TS 5.5 Radioactive Effluent Controls Program | : TS 5.5 Radioactive Effluent Controls Program | ||
: 2005 Annual Radioactive Effluent Report and Offsite Dose Calculation Manual; May 9, | : 2005 Annual Radioactive Effluent Report and Offsite Dose Calculation Manual; May 9, 2006 | ||
: Revision 0 for | : 4OA1Performance Indicator VerificationPrairie Island Nuclear Generating Plant Form 1318C; Performance Indicators-Safety SystemFunctional Failures; Revision 0 for 2 | ||
nd Quarter 2004, 3 | |||
rd Quarter 2004, 4 | |||
th Quarter 2004, 1 | |||
stQuarter 2005, 2 | |||
nd Quarter 2005, 3 | |||
rd Quarter 2005, 4 | |||
th Quarter 2005, and 1 | |||
st Quarter 2006Prairie Island Nuclear Generating Plant Form 1318A; Performance Indicators-Initiating Events; | |||
: Revision 0 for 2 | |||
nd Quarter 2004, 3 | |||
rd Quarter 2004, 4 | |||
th Quarter 2004, 1 | |||
st Quarter 2005, 2 | |||
nd Quarter 2005, 3 rd Quarter 2005, 4 | |||
th Quarter 2005, and 1 | |||
st Quarter 2006Plant Procedure H33; Performance Indicator Reporting; Revision 5 | |||
: Plant Procedure H33.1; Performance Indicator Reporting Instructions; Revision 5 | : Plant Procedure H33.1; Performance Indicator Reporting Instructions; Revision 5 | ||
: Plant Procedure H33.3; Safety System Functional Failure Performance Indicator Reporting Instructions; Revision 1 | : Plant Procedure H33.3; Safety System Functional Failure Performance Indicator Reporting Instructions; Revision 1 | ||
: Unit 1 and 2 Operating Logs for April 1, 2004 through March 31, 2006 | : Unit 1 and 2 Operating Logs for April 1, 2004 through March 31, 2006 | ||
: CAP 01031984; Evaluate D6 High Crankcase Pressure for MSPI [Mitigating System Performance Index] Failure | : CAP 01031984; Evaluate D6 High Crankcase Pressure for MSPI [Mitigating System Performance Index] Failure | ||
: CAP 01024901; Data Error - Did Not Report 11.9 Hours of Unavailability for D1 Diesel | : CAP 01024901; Data Error - Did Not Report 11.9 Hours of Unavailability for D1 Diesel Generator 4OA2Identification and Resolution of ProblemsT-Track | ||
: CAP 039892; CV31231 Unit 1 Pressurizer PORV Appears to be Leaking | : CAP 039892; CV31231 Unit 1 Pressurizer PORV Appears to be Leaking | ||
: 2CAP | : 2CAP | ||
| Line 930: | Line 954: | ||
: Trim with a Trim Made of 400 Series Stainless Steel Engineering Work Request | : Trim with a Trim Made of 400 Series Stainless Steel Engineering Work Request | ||
: 009995; Issue an Equipment Change to Install the Manufacturers Horizontal Mounting Kit on the Pressurizer PORVs Apparent Cause Evaluation 1026977-01: | : 009995; Issue an Equipment Change to Install the Manufacturers Horizontal Mounting Kit on the Pressurizer PORVs Apparent Cause Evaluation 1026977-01: | ||
: CV-31232 Pressurizer PORV Had Dual Indication During | : CV-31232 Pressurizer PORV Had Dual Indication During SP 1182A | ||
==4OA3 Event FollowupEvent Followup of the Inoperability of Both Pressurizer== | |||
: PORVs During Unit 1 Shutdown Prairie Island TSs, Section 3.4.11; Pressurizer PORVs; Amendment 167Prairie Island TSs, Section 3.4.13; Low Temperature-Overpressure Protection; Amendment 158USAR, Section 4; Mass and Heat Input Events; Revision 27 | |||
: Temporary Modification 4T175; Pressurizer PORV air Accumulator Supplementation | : Temporary Modification 4T175; Pressurizer PORV air Accumulator Supplementation | ||
: SP 1181; Overpressure Protection System Setpoint Verification; Revision 22 | : SP 1181; Overpressure Protection System Setpoint Verification; Revision 22 | ||
| Line 975: | Line 1,001: | ||
: Drawing | : Drawing | ||
: SFS-PI-GA-03; B Strainer; Revision 2 | : SFS-PI-GA-03; B Strainer; Revision 2 | ||
: | : 13Drawing | ||
: SFS-PI-GA-02; A Strainer; Revision 2Drawing | : SFS-PI-GA-02; A Strainer; Revision 2Drawing | ||
: SFS-PI-GA-01; General Notes; Revision 2 | : SFS-PI-GA-01; General Notes; Revision 2 | ||
| Line 1,017: | Line 1,043: | ||
: Document | : Document | ||
: PI-KCS-05-0003; Prairie Island Unit 1, Control Rod Drive Mechanism, Justification for Nonconformance Reports for Replacement Control Rod Drive Mechanism; Revision 1 | : PI-KCS-05-0003; Prairie Island Unit 1, Control Rod Drive Mechanism, Justification for Nonconformance Reports for Replacement Control Rod Drive Mechanism; Revision 1 | ||
: Critical Design Characteristics 1439-CDC-001; RRVCH Replacement Internal dome Insulation;dated May 14, 2005 | : Critical Design Characteristics 1439- | ||
: Critical Design Characteristics 1439-CDC-002; Modify Support Angles in Reactor VesselExternal Insulation; dated May 14, 2005 | : CDC-001; RRVCH Replacement Internal dome Insulation;dated May 14, 2005 | ||
: Critical Design Characteristics 1439- | |||
: CDC-002; Modify Support Angles in Reactor VesselExternal Insulation; dated May 14, 2005 | |||
: Deviation Notice 62559; Prairie island Unit 1, Shroud Support Flange, Bolt Hole Diameters Out- | : Deviation Notice 62559; Prairie island Unit 1, Shroud Support Flange, Bolt Hole Diameters Out- | ||
of-Tolerance; December 13, 2005 | of-Tolerance; December 13, 2005 | ||
: Equivalent Engineering Change 1439; Replace Unit 1 and Unit 2 Reactor Vessel Head Internal Insulation; Revision 0 | : Equivalent Engineering Change 1439; Replace Unit 1 and Unit 2 Reactor Vessel Head Internal Insulation; Revision 0 | ||
: | : 14MHI Drawing L5-01DV109; Replacement RVCH, Closure Head and Adapter Housing Assembly;Revision 2 | ||
: MHI Drawing L5-01DV171; Replacement RVCH, As-Built Drawing (RV Closure Head) 1/3; | : MHI Drawing L5-01DV171; Replacement RVCH, As-Built Drawing (RV Closure Head) 1/3; | ||
: Revision 1 | : Revision 1 | ||
| Line 1,032: | Line 1,060: | ||
: UGC-CMTR-04-19; Certified Material Test Report, Unit 1 Replacement RVCH; dated December 1, 2004 | : UGC-CMTR-04-19; Certified Material Test Report, Unit 1 Replacement RVCH; dated December 1, 2004 | ||
: Reactor Vessel Closure Head and Control Rod Drive Mechanisms; ASME NPT Component Certification; Mitsubishi Heavy Industries, Ltd; dated January 11, 2006Head Assembly Upgrade Package (71007)CAP | : Reactor Vessel Closure Head and Control Rod Drive Mechanisms; ASME NPT Component Certification; Mitsubishi Heavy Industries, Ltd; dated January 11, 2006Head Assembly Upgrade Package (71007)CAP | ||
: 01003629; Generate Operating Experience Evaluation Report for NRC Regulatory IssueSummary 2005-25, "Control of Heavy Loads"; dated November 14, 2005 | : 01003629; Generate Operating Experience Evaluation Report for | ||
: NRC Regulatory IssueSummary 2005-25, "Control of Heavy Loads"; dated November 14, 2005 | |||
: Design Change 03RV05 Part 2; Reactor Vessel Head Assembly Upgrade Package; Revision 1 | : Design Change 03RV05 Part 2; Reactor Vessel Head Assembly Upgrade Package; Revision 1 | ||
: Design Specification 418A34; Head Assembly Upgrade Package; Revision 6 | : Design Specification 418A34; Head Assembly Upgrade Package; Revision 6 | ||
| Line 1,070: | Line 1,099: | ||
: Drawing | : Drawing | ||
: NF-38436; Reactor Building Unit 1, Reactor Vessel Column Supports - Sections and Details; Revision F | : NF-38436; Reactor Building Unit 1, Reactor Vessel Column Supports - Sections and Details; Revision F | ||
: | : 15Drawing | ||
: NF-38490-1; Reactor Building Unit 2, Reactor Vessel Column Supports: | : NF-38490-1; Reactor Building Unit 2, Reactor Vessel Column Supports: | ||
: Plans,Sections and Details; Revision E | : Plans,Sections and Details; Revision E | ||
| Line 1,082: | Line 1,111: | ||
: Maintenance Procedure D58.1.9; Unit 1 - Reactor Vessel Head Removal; Revision 11 | : Maintenance Procedure D58.1.9; Unit 1 - Reactor Vessel Head Removal; Revision 11 | ||
: Maintenance Procedure D58.2.9; Unit 2 - Reactor Vessel Head Removal; Revision 10Corrective Action Requests Initiated as a Result of NRC InspectionCAP | : Maintenance Procedure D58.2.9; Unit 2 - Reactor Vessel Head Removal; Revision 10Corrective Action Requests Initiated as a Result of NRC InspectionCAP | ||
: 01025009; Evaluate Removal of Head Lift Height Restriction from USAR; dated April 19,2006 | : 01025009; Evaluate Removal of Head Lift Height Restriction from USAR; dated April 19, 2006 | ||
: CAP 01030203; Potential Non-Conservative Qualification of CRDM Cool Bridge; dated May 15,2006 | : CAP 01030203; Potential Non-Conservative Qualification of CRDM Cool Bridge; dated May 15, 2006 | ||
: CAP 01030355; Review 50.59 Evaluation 1052; Revision 0 Bases to Remove Reactor Head Lift Restriction from USAR; dated May 16, 2006 | : CAP 01030355; Review 50.59 Evaluation 1052; Revision 0 Bases to Remove Reactor Head Lift Restriction from USAR; dated May 16, 2006 | ||
: CAP 01030740; HAUP LOCA II/I Acceptance Criteria Not Specified in Any Design Document; | : CAP 01030740; HAUP LOCA II/I Acceptance Criteria Not Specified in Any Design Document; | ||
| Line 1,089: | Line 1,118: | ||
: CAP 01031051; 50.59 Screen for LOCA II/I Conclusions Questioned; dated May 18, 2006Closure of | : CAP 01031051; 50.59 Screen for LOCA II/I Conclusions Questioned; dated May 18, 2006Closure of | ||
: URI 05000306/2005004-07CAP | : URI 05000306/2005004-07CAP | ||
: 00864144; NRC Head Replacement Questions; dated November 30, 2005Calculation Note | : 00864144; | ||
: NRC Head Replacement Questions; dated November 30, 2005Calculation Note | |||
: CN-RVHP-04-87; Prairie Island HAUP, Plenum Stress Qualification; Revision 3 | : CN-RVHP-04-87; Prairie Island HAUP, Plenum Stress Qualification; Revision 3 | ||
: Calculation Note | : Calculation Note | ||
| Line 1,097: | Line 1,127: | ||
: CAP 041407; Westinghouse NSAL 05-1 Issue, RCGVS and RVLIS Not Analyzed for LOCA | : CAP 041407; Westinghouse NSAL 05-1 Issue, RCGVS and RVLIS Not Analyzed for LOCA | ||
: Movements; dated March 17, 2005 | : Movements; dated March 17, 2005 | ||
: CAP 043325; NRC Head Replacement Questions; July 5, 2005Engineering Manual 1.2.3; Development of Design Calculations; Revision 10 | : CAP 043325; | ||
: NRC Head Replacement Questions; July 5, 2005Engineering Manual 1.2.3; Development of Design Calculations; Revision 10 | |||
: Fleet Procedure | : Fleet Procedure | ||
: FP-E-CAL-01; Calculations; Revision 0 | : FP-E-CAL-01; Calculations; Revision 0 | ||
| Line 1,116: | Line 1,147: | ||
: Maintenance Procedure D58.1.10; Unit 1 - Reactor Vessel Head Replacement; Revision 9 | : Maintenance Procedure D58.1.10; Unit 1 - Reactor Vessel Head Replacement; Revision 9 | ||
: CAP 01031457; Safety Issues During Head Lift; Lack of Co-worker Coaching | : CAP 01031457; Safety Issues During Head Lift; Lack of Co-worker Coaching | ||
: CAP 01031459; Weak ALARA Practices During Head Lift and Set | : CAP 01031459; Weak ALARA Practices During Head Lift and Set | ||
: 01031485; Unclear Procedure Guidance for Unit 1 | : 16CAP | ||
: | : 01031485; Unclear Procedure Guidance for Unit 1 D58 | ||
: 01029449; Non-Safety-Related Parts Used in Safety-Related Application | : SP 1546; CRDM Timing Test; Revision 0 | ||
==4OA7 Licensee-Identified ViolationCAP 01028790;== | |||
: PRA Configuration Assessed IncorrectlyCAP | |||
: 01029449; Non-Safety-Related Parts Used in Safety-Related Application | |||
: 17 | |||
==LIST OF ACRONYMS== | ==LIST OF ACRONYMS== | ||
USEDADAMSAgencywide Documents Access and Management SystemALARAAs-Low-As-Reasonably-Achievable | |||
ASMEAmerican Society of Mechanical Engineers | |||
BACCBoric Acid Corrosion Control | |||
CAPCorrective Action Program/Corrective Action Program Action Request | |||
CFRCode of Federal Regulations | |||
CRDMControl Rod Drive MechanismDACDerived Air Concentration | |||
DRPDivision of Reactor Projects | |||
EPRIElectric Power Research Institute | |||
ETEddy Current | ETEddy Current | ||
GLGeneric Letter | |||
HAUPHead Assembly Upgrade Package | |||
HEPAHigh Efficiency Particulate Air | |||
HRAHigh Radiation Area | |||
IMCInspection Manual Chapter | |||
IPInspection Procedure | |||
IPEEEIndividual Plant Examination of External Events | |||
IRInspection Report | |||
ISIInservice Inspection | |||
LERLicensee Event Report | |||
LOCALoss of Coolant Accident | |||
NCVNon-Cited Violation | |||
NDENondestructive Examination | |||
NEINuclear Energy Institute | |||
: [[NMCN]] [[uclear Management Corporation,]] | : [[NMCN]] [[uclear Management Corporation,]] | ||
: [[LLC]] [[]] | : [[LLC]] [[]] | ||
NRCU.S. Nuclear Regulatory Commission | |||
OPROperability RecommendationPARSPublicly Available Records | |||
PINGPPrairie Island Nuclear Generating Plant | |||
PORVPower Operated Relief Valve | |||
RCGVSReactor Coolant Gas Ventilation System | |||
RCSReactor Coolant System | |||
RHRResidual Heat Removal | |||
RISRegulatory Issue Summary | |||
RPIPRadiation Protection Implementing Procedure | |||
RVCHReactor Vessel Closure Head | |||
RVLISReactor Vessel Level Indication System | |||
RWPRadiation Work Permit | |||
SDPSignificance Determination Process | |||
SGSteam Generator | SGSteam Generator | ||
SISafety Injection System | SISafety Injection System | ||
SPSurveillance Procedure | |||
SSCStructure, System, or Component | |||
SWISection Work Instruction | |||
TERTechnical Evaluation Report | |||
TSTechnical Specifications | |||
URIUnresolved Item | |||
USARUpdated Safety Analysis Report | |||
WOWork Order | |||
18 | |||
WOWork Order | |||
}} | }} | ||
Revision as of 14:00, 26 October 2018
| ML062270524 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 08/14/2006 |
| From: | Skokowski R A NRC/RGN-III/DRP/RPB3 |
| To: | Thomas J. Palmisano Nuclear Management Co |
| References | |
| FOIA/PA-2010-0209 IR-06-003, RLS1 | |
| Download: ML062270524 (74) | |
Text
August 14, 2006
Mr. T. PalmisanoSite Vice President Prairie Island Nuclear Generating Plant Nuclear Management Company, LLC 1717 Wakonade Drive East Welch, MN 55089
SUBJECT: PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2NRC INTEGRATED INSPECTION REPORT 05000282/2006003; 05000306/2006003
Dear Mr. Palmisano:
On June 30, 2006, the U.S. Nuclear Regulatory Commission (NRC) completed an integratedinspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on July 12, 2006, with you and other members of your staff. This inspection examined activities conducted under your license as they relate to safety and tocompliance with the Commission's rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based on the results of this inspection, there were three NRC-identified and one self-revealedfindings of very low safety significance noted. All these findings involved violations of NRC requirements. In addition, one NRC-identified issue was reviewed under the NRC traditi onalenforcement process and was determined to be a Severity Level IV violation of NRC requirements. However, because these violations were of very low safety significance, not willful, and because they were entered into your corrective action program, the NRC is treatingthese issues as Non-Cited Violations in accordance with Section VI.A.1 of the NRC'sEnforcement Policy. Additionally, four licensee-identified violations are listed in Section 4OA7 of this report.If you contest the subject or severity of a Non-Cited Violation, you should provide aresponse 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, D.C.20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission -
Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office ofEnforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the Resident Inspector Office at the Prairie Island Nuclear Generating Plant.
T. Palmisano-2-In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letterand its enclosure will be available electronically for public inspection in the NRC PublicDocument Room or from the Publicly Available Records (PARS) component of NRC'sdocument 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 Mark A. Ring acting for/Richard A. Skokowski, ChiefBranch 3 Division of Reactor Projects Docket Nos. 50-282; 50-306License Nos. DPR-42; DPR-60
Enclosure:
Inspection Report 05000282/2006003; 05000306/2006003
w/Attachment:
Supplemental Informationcc w/encl:C. Anderson, Senior Vice President, Group OperationsM. Sellman, Chief Executive Officer and Chief Nuclear Officer Regulatory Affairs Manager J. Rogoff, Vice President, Counsel & Secretary Nuclear Asset Manager State Liaison Officer, Minnesota Department of Health Tribal Council, Prairie Island Indian Community Administrator, Goodhue County Courthouse Commissioner, Minnesota Department of Commerce Manager, Environmental Protection Division Office of the Attorney General of Minnesota
SUMMARY OF FINDINGS
IR 05000282/2006003, 05000306/2006003; 4/01/06 - 6/30/06; Prairie Island NuclearGenerating Plant, Units 1 and 2; Inservice Inspection Activities, Reactor Vessel Head
Replacement, Radiation Protection, and other activities. This report covers a 3-month period of baseline resident inspection and announced baselineinspection on radiation protection, inservice inspections, and reactor vessel head replacement.
The inspections were conducted by the resident inspectors and inspectors from the Region III office. One Severity Level IV violation and four findings with associated non-cited violations were identified. The significance of most findings is indicated by their color (Green, White,
Yellow, Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be "Green" or be assigned a severity level after NRC management review. The NRC's program for overseeing the safeoperation of commercial nuclear power reactors is described in NUREG-1649, "ReactorOversight Process," Revision 3, dated July 2000.A.Inspector-Identified and Self-Revealed Findings
Cornerstone: Initiating Events
- Green.
The inspectors identified a Non-Cited Violation of 10 CFR Part 50 Appendix B,Criterion V for a combination of an inadequate procedure and a failure to implement the requirements of Surveillance Procedure 1293, Inspection of Flood Control Measuresand the Shelf Life Program Procedure FP-SC-PE-05. Specifically, the licensee failed to order and maintain the correct type of Deck-O-Seal sealant to facilitate installation offlood doors and panels in accordance with plant abnormal procedures.The finding was more than minor because it closely matched example 2E of InspectionManual Chapter 0612, Appendix E. The inspectors determined the finding to be of very low safety significance following a review of a licensee's condition evaluation concluding that the finding did not increase the likelihood of the external flooding event affectingplant safety-related systems or components. (Section 4OA5)
Cornerstone: Mitigating Systems
- Green.
The inspectors identified a Severity Level IV Non-Cited Violation associatedwith the failure to perform an adequate safety evaluation review as required by 10 CFR 50.59 for the changes made to the Updated Safety Analysis Report (USAR).
In safety evaluation 1052, Revision 0, the licensee failed to provide a basis for the determination, that removing the maximum reactor vessel head lift elevation andreference to the associated load drop analysis calculation from the USAR, was acceptable without a license amendment. Specifically, the licensee determined that their load drop analysis was neither a regulatory requirement nor a licensing commitment and could be removed from the USAR. Within the 10 CFR 50.59 evaluation, the licensee failed to provide a basis for why the removal of this lift elevation restriction from the USAR did not present more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component important to safety 2if the reactor vessel head was dropped at an elevation higher than that evaluated in theload drop calculation with irradiated fuel in the reactor core. Because the issue affected the NRC's ability to perform its regulatory function, thisfinding was evaluated using the traditional enforcement process. The finding was determined to be more than minor because the inspectors could not reasonably determine that the USAR change, which had the potential to adversely affect equipmentimportant to safety, would not have ultimately required NRC approval. The finding wasdetermined to be of very low safety significance (Green) because the inspectors answered "no" to question 1 under the Mitigating Systems Cornerstone column of the Phase 1 worksheet. Specifically, the licensee had not performed a reactor vessel head lift where the lift height was in excess of the elevation evaluated in their load drop analysis, and licensee maintenance procedures limited the maximum allowed reactor vessel head lift height to be less than the elevation evaluated in their load drop analysis.(Section 1R02.1.b.1)
Cornerstone: Occupational Radiation Safety
- Green.
A finding of very low safety significance and associated Non-Cited Violation(NCV) were inspector-identified during a walkdown in Unit 1 containment. The inspectors identified that a swing gate barrier to a High Radiation Area (HRA) was left in the open position due to misalignment of the gate in the stand. The licensee correctedthe barrier misalignment and verified other HRA barriers in containment were properly operating and positioned. Radiation workers in containment were not self-checking to assure that the barriers were placed back into the correct position after traversing the HRA. The licensee entered this finding into the corrective action program. The finding was more than minor because it was associated with the OccupationalRadiation Safety cornerstone, and potentially affected the cornerstone attribute of program and process for radiation worker performance. The finding was determined to be of very low safety significance because it did not involve an As-Low-As-Reasonably-Achievable (ALARA) issue, as collective dose was not a factor and no individual received an unintended dose as a result of the barrier non-compliance; there was not a substantial potential for a worker overexposure; and the licensee's ability to assessworker dose was not compromised.
Since the principal cause of the problem was ahuman performance deficiency, the finding also relates to the cross-cutting area of human performance. (Section 2OS1)Green. A self-revealing finding of very low safety significance and associated NCV wereidentified when 110 radiation workers were contaminated as a result of opening steam generator manways during the Unit 1 1R24 refueling outage. Specific ALARA planning assessments did not acknowledge airborne concentrations of radioactivity may be subject to change. Additionally, the ALARA planning for this work did not consider the effect of engineering safety systems operation or malfunction on other work areas incontainment, consequently when the work area was set up and initial work commenced, the focus was on the immediate work area only, and the result was elevated iodine-131 levels throughout containment. The licensee evacuated containment, identified the source of airborne contamination, and repositioned and secured an air handling hose to 3the containment clean-up filter. The event was entered into the licensee's correctiveaction program.The finding was more than minor because it was associated with the OccupationalRadiation Safety cornerstone, and potentially affected the cornerstone attribute of program and process for ALARA planning and exposure/contamination control. The finding was determined to be of very low safety significance because although the finding did involve an ALARA planning issue and resulted in unintended exposure to personnel, personnel doses were well below regulatory limits. (Section 2OS2)
Cornerstone: Public Radiation Safety
- Green.
A finding of very low safety significance and associated NCV were inspector-identified for the failure to establish adequate written procedure(s) for Offsite DoseCalculation Manual (ODCM) implementation to ensure that the radiological impact fromreleasing gaseous and particulate effluents from the Unit 1 containment equipment hatch to the environment was properly assessed prior to the release, and the release was properly quantified and reported. The licensee conservatively reconstructed the effluent concentrations and projected dose to the public, and entered the event into thecorrective action program.The finding was more than minor because the issue was associated with the PublicRadiation Safety cornerstone attribute of program and process and potentially affected the cornerstone objective to ensure adequate protection of the public from exposure to radioactive materials from the release of gaseous effluents. The finding was determined to be of very low safety significance, because the issue was not associated with radioactive material control, and although there was an impaired ability to access doseprior to the releases, the licensee's dose assessment demonstrated that the actualeffluent releases were calculated to be within regulatory dose limits and ALARA dose constraints. Since the principal cause of the problem was a problem identification and resolution deficiency, the finding also relates to the cross-cutting area of problem identification and resolution. (Section 2PS1)
B.Licensee-Identified Violations
Violations of very low safety significance, which were identified by the licensee, havebeen reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. The violations and corrective action tracking numbers are listed in Section 4OA7 of this report.
4
REPORT DETAILS
Summary of Plant StatusUnit 1 operated at or near full power until April 14, 2006, when operators initiated a manualreactor trip after a failure of the 11 condensate pump which resulted in the loss of the 11 main feedwater pump. The reactor was restarted and the generator placed online on April 16, 2006. The unit operated at or near full power until April 28, 2006, when the unit was shut down forrefueling outage 1R24. Unit 1 was made critical on June 5, 2006, the generator was placedonline on June 6, 2006, and the unit was gradually brought to full power over the next few days.
The unit operated at or near full power until June 11, 2006, when power was reduced to approximately 60 percent to perform post-maintenance testing following the replacement of abearing on the 11 turbine-driven auxiliary feedwater (AFW) pump turbine. The unit operated ator near full power for the remainder of the inspection period.Unit 2 operated at or near full power throughout the inspection period except when power wasreduced to approximately 48 percent on April 9, 2006, for approximately 22 hours2.546296e-4 days <br />0.00611 hours <br />3.637566e-5 weeks <br />8.371e-6 months <br /> for maintenance on the 22 feedwater pump and turbine valve testing.1.REACTOR SAFETYCornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity1R01Adverse Weather Protection (71111.01)
.1 Protection Against Tornados and High Velocity Winds
a. Inspection Scope
On May 2, 2006, the inspectors completed a detailed in-office review of the licensee'sprocedures and an in-plant walkdown of four systems to observe the licensee'spreparations for adverse weather conditions that could result from nearby tornados or high wind conditions. The inspectors performed a detailed review of the tornado and high winds hazard procedures; the Updated Safety Analysis Report (USAR); design basis documents for the Unit 1 and Unit 2 switchyard; and the Prairie Island Individual Plant Examination of External Events (IPEEE). The inspectors verified that required surveillance tests were scheduled and performed at the specified frequencies. During system walkdowns, the inspectors examined the material condition of major systemcomponents for evidence of system degradation. As part of this inspection, thedocuments in the Attachment were utilized to evaluate the potential for an inspection finding. The inspectors evaluated readiness for seasonal susceptibilities for the followingsystems, completing one inspection procedure sample:*the Unit 1 diesel generators D1and D2;*the plant substation system;
- the cooling tower substation system including transformers CT-11 and CT-12; 5*auxiliary and standby transformer system; and *Unit 1 containment during periods when the containment hatch was removed.b.FindingsNo findings of significance were identified.
.2 Hot Weather Preparations
a. Inspection Scope
On June 16 through 20, 2006, the inspectors performed an in-office review of thesummer plant operation program; the USAR; applicable Technical Specifications (TS);
and the Prairie Island IPEEE. This inspection effort completed the hot weather preparation inspection sample. The inspectors performed in-plant walkdowns of selected systems and verified that the as-found conditions of those systems wereconsistent with the description provided in the above documents. The inspectors performed in-plant walkdowns of the following risk-significant mitigating system supportsystems for a total of one inspection sample:*diesel generator D1 and D2 ventilation system;*diesel generator D5 and D6 ventilati on system; and*instrument and service air system.The inspectors reviewed the selected systems and verified that the material conditions and system configurations supported the systems' availability and operability underadverse hot weather conditions, and verified that additional cooling equipment, where specified in the summer plant operation procedure, was available and operable. The inspectors also reviewed the correction action programs action requests (CAPs)listed in the Attachment to verify that the licensee was identifying adverse weatherissues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action procedures.
b. Findings
No findings of significance were identified.
1R02 Evaluation of Changes, Tests, or Experiments (71111.02)Reactor Vessel Head Replacement Inspection (71007)
a. Inspection Scope
From April 24 through 28, 2006, from May 1 through 5, 2006, and fromMay 15 through 19, 2006, the inspectors reviewed the licensee's evaluations of applicability determination and screening questions for the design changesassociated with the Unit 1 reactor vessel closure head (RVCH) replacement to determine, for each change, whether the requirements of 10 CFR 50.59 had been 6appropriately applied. Screenings and evaluations reviewed for the Unit 2 RVCHreplacement (refer to IR 05000282/2005004; 05000306/2005004 (ML052020420)) that were also applicable to the Unit 1 RVCH replacement were not reviewed as part of this inspection. Specifically, the inspectors reviewed Part 1 of Design Change 03RV05, "Replace Unit 1 and 2 Reactor Vessel Heads and Associated Components," which included a review of the function of each changed component, the change description and scope of three 10 CFR 50.59 screenings for the:*reactor vessel head internal insulation;*reactor coolant gas vent system (RCGVS) and reactor vessel level indicationsystem (RVLIS) pipe and supports; and*abandonment of upper range RVLIS indication.The inspectors also reviewed three 10 CFR 50.59 screenings and one 10 CFR 50.59evaluation associated with the Unit 1 head assembly upgrade package (HAUP) to determine, for each change, whether the requirements of 10 CFR 50.59 had beenappropriately applied. Screenings reviewed for the Unit 2 HAUP installation (refer to IR 05000282/2005004; 05000306/2005004 (ML052020420)), that were also applicable to the Unit 1 HAUP installation, were not reviewed as part of this inspection.
Specifically, the inspectors reviewed Part 2 of Design Change 03RV05, "Reactor Vessel Head Assembly Upgrade Package (HAUP)," which included a review of the function of each changed component, the change description, methods of analysis, and scope of the 10 CFR 50.59 screenings and the 10 CFR 50.59 evaluation for the:*reactor vessel control rod drive mechanism (CRDM) seismic platform, seismicspacer plate, adjustment plate assembly, cable supports;*CRDM cooling: coils, fans, pipe/pipe supports, and instrumentation and control;*evaluation of non-safety-related components for loss of coolant accident (LOCA)loads; and*heavy loads licensing bases.The inspectors used, in part, Nuclear Energy Institute (NEI) 96-07, "Guidelines for10 CFR 50.59 Implementation," to determine acceptability of the completed pre-screenings and screening. The NEI document was endorsed by the NRC inRegulatory Guide 1.187, "Guidance for Implementation of 10 CFR 50.59, Changes,Tests, and Experiments." The inspectors also consulted Part 9900 of the NRC Inspection Manual, "10 CFR Guidance for 10 CFR 50.59, Changes, Tests, and Experiments."The records reviewed by the inspectors are identified in the Attachment to this report.
b. Findings
USAR Change that Removed the Reactor Vessel Head Lift Elevation Limit andReference to the Associated Reactor Vessel Head Load Drop CalculationIntroduction: On April 19, 2006, the inspectors identified a Severity Level IV Non-CitedViolation (NCV) of very low safety significance (Green) for failing to perform anadequate safety evaluation in accordance with 10 CFR 50.59. Safety Evaluation 1052, 7Revision 0, "Heavy Load Licensing Bases," involved a USAR change that removed themaximum reactor vessel head lift elevation restriction, and reference to the associated reactor vessel head load drop calculation that provided the design basis for the lift elevation limit. Within the safety evaluation, the licensee failed to provide a basis for why the removal of this lift elevation restriction from the USAR did not present more than a minimal increase in the likelihood of occurrence of a malfunction of a structure, system, or component (SSC) important to safety if the reactor vessel head was droppedat an elevation higher than that evaluated in the load drop calculation with irradiated fuelin the reactor core.
Description:
The licensee initiated 10 CFR 50.59 Safety Evaluation 1052 to support arevision to the USAR that removed the maximum reactor vessel head lift elevation restriction and reference to the associated reactor vessel head load drop calculation that provided the design basis for the lift elevation limit. As indicated in Safety Evaluation 1052, the NRC required licensees to determine the extent that guidelines inNUREG-0612, "Control of Heavy Loads at Nuclear Power Plants," were satisfied and toidentify changes and modifications that would be required to satisfy those guidelines (NRC Letter dated December 22, 1980, Subject: Control of Heavy Loads (GL 80-113);NRC Generic Letter (GL) 81-07; dated February 3, 1981, Control of Heavy Loads). Thelicensee responses were in two phases, Phase I and Phase II:Prairie Island Nuclear Generating Plant (PINGP) submitted their Phase I report tothe NRC, on August 31, 1981, with additional information provided in subsequentletters. NRC Safety Evaluation Report dated June 6, 1983, concluded thatPINGP satisfactorily complied with the Phase I requirements.For the Phase II response, the NRC requested that licensees submit informationon overhead cranes in the vicinity of spent fuel pools, in containment, and in plant areas containing equipment required for reactor shutdown, core decay heat removal, or spent fuel pool cooling (NUREG-0612 Sections 5.1.2, 5.1.3,and 5.1.5). With respect to the containment polar crane, NUREG-0612Section 5.1.3 required a single-failure proof crane, or as an alternative, analysis could be performed demonstrating that evaluation criteria listed in NUREG-012 Section 5.1 were satisfied. As part of their Phase II submittal (NSP Letter, dated December 9, 1981, Controlof Heavy Loads (9 Month Submittal)), PINGP outlined compliance with NUREG-0612 Guideline 5.1.3. This included a reactor head drop analysis that concluded both 4-inch diameter safety injection (SI) lines (reactor vessel injection) would remain functional, and thus, the capability was maintained to provide boratedwater to the reactor vessel to make up for any water due to boiling. This satisfiedCriterion III of Section 5.1 of NUREG-0612. On May 31, 1984, the NRC providedPINGP with a draft Technical Evaluation Report (TER) related to the Phase II submittal. The draft TER concluded that the information provided by PINGP indicates that Criterion III (uncovering of the core) have been satisfied in amanner consistent with the intent of NUREG-0612. No outstanding issues wereidentified in the draft TER related to the reactor head drop analysis. However, the NRC did not issue an official Safety Evaluation Report for the PINGP Phase IIsubmittal.
8In Safety Evaluation 1052, the licensee concluded that actions provided in theirPhase I submittal were part of their licensing basis, but actions provided to the NRC in their Phase II submittal were not part of their licensing basis based on GL 85-11, "Clarification of Response to the Heavy Loads Phase II Technical Evaluation Report,"
and NUREG-1774, "Survey of Crane operating Experience at US Nuclear PowerPlants from 1968 through 2002." The licensee also concluded that GL 85-11 relieved licensees from performing the actions requested under Phase II and rescinded the requirement to perform a Phase II review requested in GL 80-113 and GL 81-07. Safety Evaluation 1052 further concluded that maintaining an analysis of a postulated drop of the reactor vessel head was neither a regulatory requirement nor a licensing commitment for PINGP. As a result, the licensee revised the USAR to remove the maximum reactor vessel head lift elevation restriction and reference to the associated reactor vessel head load drop calculation that provided the design basis for the lift elevation limit. The inspectors reviewed NRC Regulatory Issue Summary (RIS) 2005-25, "Clarification ofNRC Guidelines for Control of Heavy Loads," dated October 31, 2005. Clarifications andrelated information provided by RIS 2005-25 include:*In GL 85-11, the NRC staff concluded that a detailed review (NRC detailedreview) of the Phase II responses received by the licensee was not necessary based on an NRC staff pilot review of Phase II responses. Although, the NRCstaff concluded that the cost to install a single-failure-proof crane was not justified on a generic basis, the NRC staff encouraged licensees to determine andimplement appropriate actions to provide adequate safety. In GL 85-11, the NRC staff did not relieve licensees from performing the actions requested under Phase II nor rescind the requirement to perform a Phase II review. *Phase II guidelines addressed alternatives to reduce the consequences of heavyload drops. One option was to perform a load drop and consequence analysis to assess the impact of dropped loads on plant safety and operations. *The NRC Advisory Committee on Reactor Safeguards, in a letter datedSeptember 24, 2003, (ML032681205) endorsed the recommendation to evaluatethe need to establish standardized calculation methodologies for heavy load drops. As noted in RIS 2005-25, Enclosure 1, PINGP revised their load drop analysis due to assumptions and methodology that were determined to be non-conservative and reduced the maximum reactor vessel head lift elevation indicated in the USAR (refer to IR 05000282/2005004; 05000306/2005004 (ML052020420)).The inspectors determined that based on RIS 2005-25 clarifications, the PINGP loaddrop analysis was part of the design basis that determined SSCs important to safety, the 4-inch SI lines, would remain functional after a postulated load drop. Although the USAR had been changed to remove the reactor vessel head lift elevation limit and the reference to the associated reactor vessel head load drop calculation, the reactor vessel head lift elevation limit established by the reactor vessel head load drop analysis was still controlled by the licensee in maintenance procedures.
9The inspectors determined that the 10 CFR 50.59 evaluation that was performed toremove the reactor vessel head lift elevation limit and the reference to the associated reactor vessel head load drop calculation from the USAR was not in accordance with the requirements in 10 CFR 50.59. Specifically, the evaluation did not adequately addressthe likelihood of occurrence of a malfunction of an SSC important to safety, the 4-inch SI lines, if the reactor vessel head was dropped at an elevation higher than that evaluated inthe load drop calculation with irradiated fuel in the reactor core. The inspectors noted that this change to the USAR may have resulted in more than a minimal increase in the likelihood of occurrence of a malfunction of an SSC important to safety, since the reactor vessel had sufficient energy-absorbing capacity at a maximum lift elevation determined by the load drop analysis (Calculation 2005-05621). The licensee entered this condition into their corrective action program as CAPs 0125009 and 01030355. As a result, the licensee performed a revision to Safety Evaluation 1052 and reinstated into the USAR the reactor vessel head lift elevation limit and the reference to the reactor vessel head load drop analysis (Calculation 2005-05621).
Analysis:
The inspectors determined that the removal of the head lift elevation limit fromthe USAR was a performance deficiency, since the licensee permanently changed the facility as described in the USAR without providing the necessary justification under10 CFR 50.59 for the activity that created a possibility for a malfunction of an SSC important to safety with a different result than previously evaluated in the USAR. The finding was determined to be more than minor, because the inspectors could not reasonably determine that the USAR change, which adversely affected equipment important to safety, would not have required NRC approval. Because violations of 10 CFR 50.59 are considered to be violations that potentiallyimpede or impact the regulatory process, they are dispositioned using the traditional enforcement process instead of the Significance Determination Process (SDP).
However, if possible, the underlying technical issue is evaluated under the SDP to determine the severity of the violation. In this case, the finding screened as having very low safety significance (Green) using Inspection Manual Chapter (IMC) 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for the At-Power Situations," because the inspectors answered "no" to question 1 under the Mitigating Systems Cornerstone column of the Phase 1 worksheet. Specifically, the licensee had not performed a reactor vessel head lift where the lift height was in excess of the elevation evaluated in their load drop analysis, and licensee maintenance procedures limited the maximum allowed reactor vessel head lift height to be less than the elevation evaluated in their load drop analysis. Based upon this Phase 1 screening, the inspectors concluded that the issue was of very low safety significance (Green). In accordance with the Enforcement Policy, the violation was therefore classified as a Severity Level IV violation.Enforcement: Title 10 CFR 50.59(d)(1) states, in part, that the licensee shall maintainrecords of changes in the facility, of changes in procedures, and of tests andexperiments. These records must include a written evaluation which provides a basis for the determination that the change, test, or experiment does not require a licenseamendment.
10Contrary to the above, in Safety Evaluation 1052, Revision 0, the licensee failed toprovide an adequate basis for the determination that removal of the maximum reactorvessel head lift elevation restriction and reference to the associated reactor vessel head load drop calculation from the USAR was acceptable without a license amendment.
Specifically, the change in the USAR coupled with conclusion of Safety Evaluation 1052 that the reactor vessel head load drop analysis was neither a regulatory requirement nora licensing commitment may have resulted in removal of the reactor vessel head lift elevation restriction from maintenance procedures without determining the potentialconsequences of a postulated reactor vessel head load drop. Within the 10 CFR 50.59 evaluation, the licensee failed to provide a basis for why removal of the reactor vessel head lift elevation limit and reference to the associated reactor vessel head load drop calculation did not present more than a minimal increase in the likelihood of occurrence of a malfunction of an SSC important to safety if the reactor vessel head was dropped at an elevation higher than that evaluated in the load drop calculation with irradiated fuel inthe reactor core. In accordance with the Enforcement Policy, this violation of the requirements of 10 CFR 50.59 was classified as a Severity Level IV Violation because the underlying technical issue was of very low safety significance. Because this
non-willful violation was non-repetitive, and was captured in the licensee's correctiveaction program (CAP 01030355), it is considered an NCV consistent with VI.A.1 of the NRC Enforcement Policy. (NCV 05000282/2006003-01; 05000306/2006003-01).
1R04 Equipment Alignment
.1 Partial Walkdowns
a. Inspection Scope
The inspectors performed three partial system equipment alignment inspection samplescomprised of in-plant walkdowns of accessible portions of trains of risk-significant equipment associated with the mitigating systems and barrier integrity cornerstones. The inspectors conducted the inspections during times when the trains were of increased importance due to the redundant trains or other related equipment being unavailable. The inspectors also reviewed documents entering deficient conditions associated with equipment alignment issues into the corrective action program verifying that the licensee was identifying issues at an appropriate threshold and entering those issues into their corrective action program in accordance with the fleet corrective action procedures.The inspectors utilized the valve and electric breaker checklists, where applicable, toverify that the components were properly positioned and that support systems were linedup as needed. The inspectors also examined the material condition of the components and observed operating parameters of equipment to verify that there were no obviousperformance deficiencies. The inspectors reviewed outstanding work orders (WOs) and CAPs associated with the operable trains to verify that those documents did not revealissues that could affect the completion of the available train's safety functions. The inspectors used the information in the appropriate sections of the USAR to determine thefunctional requirements of the systems.
11The inspectors verified the alignment of the following trains:
- D1 diesel generator during the unavailability of the D2 diesel generator forplanned maintenance on April 12, 2006;*12 motor-driven AFW pump during the unavailability of the 11 turbine-driven AFWpump on June 14, 2006; and*D6 diesel generator during the unavailability of the D5 diesel generator forplanned maintenance on June 19, 2006.Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report.
b. Findings
No findings of significance were identified.
1R05 Fire Protection Area Walkdowns (71111.05)
a. Inspection Scope
The inspectors conducted in-office and in-plant reviews of portions of the licensee's FireHazards Analysis and Fire Strategies to verify consistency between these documentsand the as-found configuration of the installed fire protection equipment and features inthe fire protection areas listed below. The inspectors selected fire areas for inspection based on their overall contribution to internal fire risk as documented in the IPEEE, theirpotential to impact equipment that could initiate a plant transient, or their impact on the plant's ability to respond to a security event. The inspectors assessed the control oftransient combustibles and ignition sources, the material and operational condition of fire protection systems and equipment, and the status of fire barriers. In addition, theinspectors reviewed CAPs associated with fire protection issues to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with fleet corrective action procedures. The following nine fire areas were inspected by in-plant walkdowns supporting thecompletion of nine fire protection zone walkdown samples:*Fire Area 18, Relay and Cable Spreading Room, on April 7, 2006;*Fire Area 20, Bus 15 and 16 Switchgear Rooms, on April 7, 2006;
- Fire Areas 102, D5/D6 Building, on April 10, 2006;
- Fire Areas 106, D5/D6 Building, on April 10, 2006;
- Fire Areas 114, D5/D6 Building, on April 10, 2006;
- Fire Areas 118, D5/D6 Building, on April 10, 2006;
- Fire Areas 122, D5/D6 Building, on April 10, 2006;
- Fire Area 68, Unit 1 Annulus, on May 4, 2006; and
- Fire Area 1, Unit 1 Reactor Building, on May 6, 2006.
b. Findings
No findings of significance were identified.
121R06Flood Protection Measures (71111.06)
a. Inspection Scope
On May 4, 2006, the inspectors performed an in-plant walkdown of the Unit 1 and 2safety-related cooling water pump and containment spray pump rooms completing one internal flood protection inspection sample. These areas of Unit 1 and 2 contain safety-related and risk-significant equipment including both safety-related trains of cooling water pumps, the Unit 1and 2 safety-related containment spray pumps, and flood seals for piping penetrations between the containment spray and residual heat removal (RHR)pump rooms. The inspectors reviewed the applicable sections of the USAR, Individual Plant Examination, and plant procedures associated with internal flooding of the beforementioned pump rooms and adjacent areas. The inspectors verified by in-plant inspection that the licensee maintained the material condition of piping systems in theseareas. The inspectors also verified that drain paths from these areas had been maintained and that there was no accumulation of loose materials that could plug drain paths. The inspectors reviewed a CAP to verify that problems associated with plant equipmentrelied upon to prevent or minimize flooding were identified at an appropriate threshold, and that corrective actions commensurate with the significance of the issue were identified and implemented. The documents reviewed by the inspectors are listed in theAttachment to this report.
b. Findings
No findings of significance were identified.
1R07 Heat Sink Performance (71111.07)
a. Inspection Scope
The inspectors observed the licensee's performance during the annual zebra musselcontrol treatment between April 19 and April 21, 2006, to verify the performance of thetreatment and the monitoring of critical operating parameters following the application ofthe treatment.This inspection constituted one inspection sample. The key documents reviewed by theinspectors associated with this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
131R08Inservice Inspection Activities (71111.08)
.1 Inspection ActivitiesThe inspectors conducted an assessment of the effectiveness of the licensee's inserviceinspection (ISI) program for monitoring degradation of vital system boundaries includingthe Unit 1 reactor coolant system (RCS) and risk-significant piping systems.
Specifically,the inspectors conducted an onsite review of the following nondestructive examination activities performed during the Unit 1 1R24 outage to evaluate compliance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code requirements and to verify that indications and defects were dispositioned in accordance with the ASME Code: *ultrasonic examination of safety injection pipe-elbow weld 30; *magnetic particle examination of feedwater seismic restraint H-28; and
- visual examination of 4 lugs (H-4) on a hydraulic snubber for the reactor coolantRHR system (RCRH-53).The inspectors also reviewed the following examination from the previous outage withrecordable indications that have been accepted by the licensee for continued service to verify that the licensee's acceptance for continued service was in accordance with the ASME Code: *liquid penetrant examination of a chemical and volume control system H-3/1Aanchor support welds (linear indications found on welds A and D).The inspectors reviewed the following pressure boundary welds for a Unit 2 ASMECode Class 1 system to verify that the welding process and welding examinationswere performed in accordance with ASME Code requirements:*radiographic examination of a pressurizer power operated relief valve (PORV)pipe to valve (MV-32198) weld, Weld 1;*radiographic examination of a pressurizer PORV valve (MV-32198) to pipe weld,Weld 2; and*WO package 0406806, replacement of pressurizer PORV (MV-32198).The reviews as discussed above counted as one inspection sample.
b. Findings
No findings of significance were identified.
.2 Pressurized Water Reactor Vessel Upper Head Penetration Inspection ActivitiesThe inspectors were unable to review Unit 1 upper head penetration inspection activitiesbecause none were performed.
Instead, the licensee replaced the upper head this
outage.
14Because this was not available for inspection, this was not counted as a completedinspection sample.
.3 Boric Acid Corrosion Control Inspection Activities
a. Inspection Scope
On April 29, 2006, through May 11, 2006, the inspectors reviewed the Unit 1 Boric AcidCorrosion Control (BACC) inspection activities conducted pursuant to licensee commitments made in response to NRC Generic Letter 88-05, "Boric Acid Corrosion ofCarbon Steel Reactor Pressure Boundary." Plant engineers commenced an examination of the reactor coolant and the other borated systems on April 29, 2006, while the reactorwas in Mode 3 and reactor coolant system was at pressure, to evaluate compliance withlicensee BACC program requirements. The inspectors observed the licensee during the performance of BACC visual examinations conducted in accordance with SurveillanceProcedure (SP) 1405. Specifically, the inspectors observed these examinations to determine if the licensee focused on locations where boric acid leaks can cause degradation of safety significant components.Additionally, the inspectors independently identified three reactor coolant system valveswith minor boric acid leakage. The inspectors verified that the licensee had also identified the condition of the three valves as degraded or non-conforming and entered those conditions into their corrective action program in accordance with the licensee's corrective action program procedure and 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requirements.The inspectors reviewed engineering evaluations performed for a boric acid packing leakfound on the 11 RHR heat exchanger outlet valve (RH-10-2) to verify that the minimumdesign code required section thickness had been maintained for the affected component(s). Specifically, the inspectors reviewed:*Operability Recommendation CAP 042581. The inspectors reviewed licensee corrective actions implemented for evidence of boricacid leakage to confirm that they were consistent with requirements of Section XI of the ASME Code and 10 CFR Part 50, Appendix B, Criterion XVI. The documents reviewed during this inspection are listed in the Attachment to this report.
The reviews, as discussed above, counted as one inspection sample.
b. Findings
No findings of significance were identified.
.4 Unit 1 Steam Generator (SG) Tube Inspection Activities
a. Inspection Scope
This was the first refueling outage (U1R24) since the 2004 (U1R23) SG replacement withthermally treated Alloy 690 tubes. The minimum inspection requirement was therefore used as reflected in the procedure steps inspected below. The NRC inspectors observed acquisition of eddy current (ET) data, interviewed ET dataanalysts, and reviewed a sample of documents related to the SG ISI program to determine if:*Procedure 71111.08, Step 02.04.a.1 and Step 02.04.a.2, the in-situ screeningcriteria, were in accordance with the Electric Power Research Institute (EPRI)guidelines and the appropriate tubes were to be in-situ pressure tested;*Procedure 71111.08, Step 02.04.c, the SG tube ET examination scope andexpansion criteria were sufficient to identify tube degradation based onsite and industry operating experience by confirming that the ET scope completed was consistent with the licensee's procedures, plant TS requirements and EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines,"
Revision 6;*Procedure 71111.08, Step 02.04.g.(1), the TS plugging limit is being adhered to;*Procedure 71111.08, Step 02.04.I, the ET probes and equipment configurationsused to acquire data from the SG tubes were qualified to detect the known/expected types of SG tube degradation in accordance with Appendix H, "Performance Demonstration for Eddy Current Examination," of EPRI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines,"
Revision 6; and*Procedure 71111.08, Step 02.04.j, the licensee performed evaluations forunretrievable loose parts.Activities which were not applicable during this inspection are as follows:
- Procedure 71111.08, Steps 02.04.a.3 and 02.04.a.4, In-situ Pressure Testing,were not available for review, because none of the SG tubes examined during the current refueling outage met the screening requirements for pressure testing;*Procedure 71111.08, Step 02.04.d, new tube degradation mechanisms were notavailable for review because none were present; and*Procedure 71111.08, Step 02.04.h, the primary-to-secondary leakage,(e.g., SG tube leakage) was not available for review, because primary-to-secondary leakage did not exceed 3 gallons per day during operations or during post-shutdown visuals.The reviews, as discussed above, counted as one inspection sample.
b. Findings
No findings of significance were identified.
.5 Identification and Resolution of Problems
a. Inspection Scope
The inspectors reviewed a sample of ISI/SG related problems documented in thelicensee's corrective action program to assess conformance with 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report. In addition, the inspectors verified that the licensee correctly assessed operating experiencefor applicability to the Inservice Inspection Gr oup.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification (71111.11)
a. Inspection Scope
On April 17, 2006, the inspectors performed a quarterly review of licensed operatorrequalification training in the simulator, completing one licensed operator requalification inspection sample. The inspectors observed a crew during an evaluated exercise in the plant's simulator facility. The inspectors compared crew performance to licenseemanagement expectations. The inspectors verified that the crew completed all of the critical tasks for each exercise scenario. For any weaknesses identified, the inspectorsobserved that the licensee evaluators noted the weaknesses and discussed them in thecritique at the end of the session.The inspectors assessed the licensee's effectiveness in evaluating the requalificationprogram ensuring that licensed individuals would operate the facility safely and within theconditions of their licenses, and evaluated licensed operators' mastery of high-risk operator actions. The inspection activities included, but were not limited to, a review of high-risk activities, emergency plan performance, incorporation of lessons learned, clarity and formality of communications, task prioritization, timeliness of actions, alarm response actions, control board operations, procedural adequacy and implementation, supervisory oversight, group dynamics, interpretations of TS, simulator fidelity, and licensee critique of performance.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness (71111.12)
a. Inspection Scope
The inspectors reviewed repetitive maintenance activities to assess maintenanceeffectiveness, including maintenance rule (10 CFR 50.65) activities, work practices, and common cause issues. The inspectors performed one issue/problem-oriented 17maintenance effectiveness sample. The inspectors assessed the licensee'smaintenance effectiveness associated with problems on the station and instrument air system.The inspectors conducted in-office reviews of the licensee's maintenance ruleevaluations of equipment failures for maintenance preventable functional failures and equipment unavailability time calculations, comparing the licensee's evaluationconclusions to applicable Maintenance Rule (a)1 performance criteria. Additionally, the inspectors reviewed scoping, goal-setting (where applicable), performance monitoring, short-term and long-term corrective actions, functional failure definitions, and current equipment performance status.The inspectors reviewed CAPs for significant equipment failures associated with risk-significant and safety-related mitigating equipment to ensure that those failures wereproperly identified, classified, and corrected. The inspectors reviewed other CAPs to assess the licensee's problem identification threshold for degraded conditions, the appropriateness of specified corrective actions, and that the timeliness of the implementation of corrective actions were commensurate with the safety significance of the identified issues. Key documents used by the inspectors in conducting this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a. Inspection Scope
The inspectors conducted in-plant walkdowns and in-office reviews of risk assessmentsfor five planned maintenance activities and four maintenance activities that involved emergent equipment failures with the following combinations of equipment unavailabilitycompleting nine risk assessment and emergent work control inspection samples:*the emergent unavailability of the Unit 2 volume control tank level transmitterconcurrent with the planned unavailability of the 122 instrument air compressoron April 5, 2006;*the emergent unavailability of the Unit 2 red channel reactor coolant flowinstrument 2FI-411 concurrent with the planned unavailability of the 23 chargingpump and the 122 instrument air compressor on April 13, 2006;*the planned unavailability of the 11 RHR pump and the 11 condensate pump onApril 24, 2006;*the planned unavailability of the 11 safety injection pump, 121 instrument aircompressor, and the 11 condensate pump on April 28, 2006;*the planned unavailability of diesel generator D2 and the 480 volt electrical loadtransfers from bus 16 to bus 26 on May 5, 2006;*the planned unavailability of diesel generator D2, 11 cooling water pump, bus 16,and the 12 AFW pump on May 8, 2006; 18*the emergent unavailability of the 121 instrument air compressor concurrent withthe planned unavailability of diesel generator D2, 11 cooling water pump, bus 16,and the 12 AFW pump on May 9, 2006;*the emergent unavailability of the 11 turbine-driven AFW pump concurrent withthe planned unavailability of the 122 instrument air compressor on June 15, 2006; and*the planned unavailability of the 11 charging pump and the 11 RHR heatexchanger outlet to the 11 containment spray pump valve MV-32096 on June 28, 2006.
b. Findings
No findings of significance were identified.
1R14 Personnel Performance Related to Non-Routine Plant Evolutions and Events (71111.14)Operator Performance Following a Loss of the 11 Condensate Pump and ResultingUnit 1 Reactor Trip
a. Inspection Scope
On April 14, 2006, the 11 condensate pump tripped due to an electrical fault. The tripcaused a lockout and trip of the 11 main feedwater pump, which resulted in declining steam generator levels. The operators initiated a manual reactor trip. The inspectors' review of the operator's response to the trip counted as one inspection sample for personnel performance to non-routine plant event.The inspectors observed the performance of operations personnel in the control roomfollowing the unplanned and non-routine evolution, comparing their response to the actions specified in the applicable plant procedures. The inspectors also reviewed selected plant parameters to ensure the plant responded as designed. The documentsreviewed by the inspectors are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope
The inspectors reviewed the technical adequacy of five operability evaluations completingfive operability evaluation inspection samples. The inspectors conducted theseinspections by in-office review of associated documents and in-plant walkdowns of affected areas and plant equipment. The inspectors compared degraded or nonconforming conditions of risk-significant SSCsassociated with barrier and mitigating systems and against the functional requirementsdescribed in the TS, USAR, and other design basis documents; determined whether 19compensatory measures, if needed, were implemented; and determined whetherthe evaluation was consistent with the requirements of Administrative Work Instruction 5AWI 3.15.5, "Operability Determinations." The following operability evaluations werereviewed by inspectors:*prompt and historical operability determinations contained in CAP 01011542 forloose material found in Unit 1 RHR pump pit flood drainage path on May 8, 2006;*Operability Recommendation (OPR) 01029449 that documented the operability of4 kilovolt switchgear with non-safety-related parts used in safety-related applications on May 15, 2006;*OPR 000531 that documented a missed inservice test on the Unit 1 volumecontrol tank relief valve, VC-24-1, on May 30, 2006;OPR 01033009 that documented the operability of Unit 1 feedwater piping withdiscrepancies on pipe support 1-FWH-35, restraints 2 and 10, on May 31, 2006;
andOPR 01034749 that documented the operability of the 11 turbine-drivenAFW pump with higher than normal turbine outboard bearing temperature, on June 6, 2006.The documents reviewed by the inspectors are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors assessed post-maintenance testing completing six post-maintenance testinspection samples. The inspectors selected post-maintenance tests associated with important mitigating and barrier integrity systems to ensure that the testing wasperformed adequately, demonstrated that the maintenance was successful, and thatoperability of associated equipment and/or systems was restored. The inspectorsconducted these inspections by in-office review of documents and in-plant walkdowns of associated plant equipment. The inspectors observed and assessed the post-maintenance testing activities for the following maintenance activities:diesel generator D2 cylinder liner replacement on May 15, 2006;replacement of the inlet check valve on the back up air supply accumulator forCV-31998, 11 turbine-driven AFW pump steam supply control valve on May 31, 2006;repacking of 11 turbine-driven AFW pump valves AF-13-3, pump discharge valveand CV-31998, main steam supply control valve, on June 2, 2006;*CV-31235, 11 RHR heat exchanger reactor coolant outlet following repair of aboric acid leak on the valve, on June 2, 2006;*replacement of 1N36, intermediate range nuclear instrument, high voltage andcompensating voltage cables on June 5, 2006; and 20*11 turbine-driven AFW pump following replacement of a turbine bearing onJune 11, 2006.The inspectors reviewed the appropriate sections of the TS, USAR, and maintenancedocuments to determine the systems' safety functions and the scope of the maintenance. The inspectors also reviewed CAPs to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with fleet corrective action procedures. Key documents used by the inspectors in conducting this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.
1R20 Refueling and Other Outage Activities (71111.20)
.1 Condensate Pump Trip Forced Outage
a. Inspection Scope
A manual reactor trip on Unit 1 was performed on April 14, 2006, due to the trip of a mainfeedwater pump. The feedwater pump tripped due to an electrical fault on a condensate pump motor cable. The inspectors observed post-trip plant conditions to verify that plant parameters were within expected normal ranges. The inspectors observed the control room activities during reactor start up and synchronization of the generator to the grid on April 16, 2006.
b. Findings
No findings of significance were identified.
.2 Refueling and Reactor Head Replacement Outage (1R24)
a. Inspection Scope
The inspectors observed the licensee's performance during the twenty-fourth Unit 1refueling outage (1R24) conducted between April 28, 2006, and June 06, 2006. Theseinspection activities represent one refueling outage inspection sample.This inspection consisted of an in-office review of the licensee's outage schedule, safeshutdown plan and procedures governing the outage. Specifically, the inspectors assessed whether the licensee planned to effectively manage elements of shutdown risk pertaining to reactivity control, decay heat removal, inventory control, electrical power availability, and containment integrity. Additionally, the inspectors reviewed selectedissues that the licensee entered into its corrective action program to verify that identifiedproblems were being entered into the program with the appropriate characterization and significance.
21The inspectors conducted in-plant observations of the following outage activities daily:*attended outage management turnover meetings to verify that the currentshutdown risk status was accurate, well understood, and adequately communicated;*performed walkdowns of the main control room to observe the alignment of systems important to shutdown risk;*observed the operability of RCS instrumentation and compared channels andtrains against one another;*observed reduced inventory operations; and
- performed walkdowns to observe ongoing work activities and foreign materialexclusion control.Additionally, the inspectors performed in-plant observations of the following specificactivities: *Unit 1 shutdown and initial cooldown;*alignment of the RHR system for shutdown cooling and control of reactor coolantsystem cooldown;*reactor vessel head leakage examination per Inspection Procedure 71111.08,paragraph 02.03.b and SP 1407;*reactor coolant system BACC inspection per Inspection Procedure 71111.08,paragraph 02.03.a and SP 1405;*control room staff draining reactor level to the top of the hot legs;
- assessment of shutdown risk;
- core off load;
- core verification;
- inspected areas not accessible during at-power operation (Volume Control Tankroom) to verify operable condition of equipment;*replacement reactor vessel head lift and set;
- reactor coolant system heatup;*reactor startup and initial critcality;
- physics testing; and
- generator online and power ascension. Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
During this inspection period, the inspectors completed ten surveillance inspectionsamples. Observation of SPs 1088A and 1106C completed the quarterly inservicetesting inspection requirement of a risk-significant pump or valve; SPs 1405 and 1070 22completed two reactor cool ant system leakage inspection requirements; SP 1405 alsocompleted Inspection Procedure 71111.08, Section 02.03.a and 02.03.b inspectionrequirements; and SP 1072.45 completed the requirement to select a containment isolation valve each refueling cycle. The inspectors selected the following surveillance testing activities as samples:*SP 2093, D5 Diesel Generator Monthly on April 21, 2006;*SP 1405, Unit 1 Mid-Cycle and Refueling Outage Boric Acid CorrosionExaminations Inside Containment on April 28, 2006;*SP 1088A, Train A Safety Injection Quarterly Test on April 28, 2006;
- SP 1092B and C, Safety Injection Check Valve Test, on May 5, 2006; SP 1126, Turbine Building Cooling Water Header Isolation Safety Injection Relays1SI-12X and 1SI-22X Contact Verification Test on May 14, 2006;SP 1072.45, Local Leakage Rate Test of Penetration 45 (Reactor WaterMakeup), on May 18, 2006;SP 1106C; 121 Cooling Water Pump Quarterly Test on May 25, 2006;SP 1083, Unit 1 Integrated Safety Injection Test with a Simulated Loss of OffsitePower, on May 27, 2006;SP 1750, Post-Outage Containment Closeout Inspection on June 1, 2006; andSP 1070, Reactor Coolant System Integrity Test on June 3, 2006.During completion of the inspection samples, the inspectors observed in-plant activitiesand reviewed procedures and associated records to verify that:* preconditioning did not occur;* effects of the testing had been adequately addressed by control room personnelor engineers prior to the commencement of the testing;* acceptance criteria was clearly stated, demonstrated operational readiness, andwas consistent with the system design basis;* plant equipment calibration was correct, accurate, properly documented, and thecalibration frequency was in accordance with TS, USAR, procedures, and applicable commitments;* measuring and test equipment calibration was current;
- test equipment was used within the required range and accuracy;
- applicable prerequisites described in the test procedures were satisfied;
- test frequency met TS requirements to demonstrate operability and reliability;* the tests were performed in accordance with the test procedures and otherapplicable procedures;* jumpers and lifted leads were controlled and restored where used;
- test data/results were accurate, complete, and valid;
- test equipment was removed after testing;
- where applicable for in-service testing activities, testing was performed inaccordance with the applicable version of Section XI, ASME Code, and reference values were consistent with the system design basis;* where applicable, test results not meeting acceptance criteria were addressedwith an adequate operability evaluation or declared inoperable;* where applicable for safety-related instrument control surveillance tests, referencesetting data have been accurately incorporated in the test procedure; 23* equipment was returned to a position or status required to support theperformance of its safety functions; and* all problems identified during the testing were appropriately documented in thecorrective action program.Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report.
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications (71111.23)
a. Inspection Scope
The inspectors conducted in-plant observations of the physical changes to the equipmentand an in-office review of documentation associated with one temporary modification completing one temporary modification inspection sample. The inspectors reviewed temporary modification 04T175 associated with a temporary installation of air bottles to supplement the air accumulator for each pressurizer PORV on May 24, 2006. The back up air bottles are required for the completion of the low temperature-overpressure protection function of the PORVs.The inspection activities included a review of design documents, safety screeningdocuments, and the USAR to determine that the temporary modification was consistentwith modification documents, drawings, and procedures. The inspectors also reviewed the post-installation test results to confirm that tests were satisfactory and the actual impact of the temporary modification on the permanent system and interfacing systemswere adequately verified. Additionally, the inspectors reviewed the corrective action documentation associated with an identified problem with the air supply to the PORVs to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with station corrective action and has been listed in the Attachment to this report.
b. Findings
No findings of significance were identified.1EP6Drill Evaluation (71114.06)
a. Inspection Scope
The inspectors observed a licensed shift operating crew perform an "as-found" exerciseon the simulator on April 20, 2006, completing one emergency planning simulator exercise sample. The inspectors observed activities in the control room simulator that include event classification and notification as well as the post-exercise critique. The inspectors evaluated the drill performance and verified that licensee evaluators'observations were consistent with those of the inspectors, and that deficiencies were 24entered into the corrective action program. Key documents used by the inspectors inconducting this inspection are listed in the Attachment to this report.
b. Findings
No findings of significance were identified.2.RADIATION SAFETYCornerstones: Occupational Radiation and Public Radiation Safety2OS1Access Control to Radiologically Significant Areas (71121.01)
.1 Plant Walkdowns and Radiation Work Permit Reviews
a. Inspection Scope
The inspectors reviewed licensee controls and surveys in the following two radiologicallysignificant work areas in the plant and reviewed the work packages which included associated licensee controls and surveys of these areas to determine if radiological controls including surveys, postings, and barricades were acceptable: *SI-9-2 check valve maintenance; and*steam generator eddy current testing.This review represented one inspection sample.
The inspectors reviewed the radiation work permits (RWPs) and work packages used toaccess these two areas and other high radiation work areas to identify the work control instructions and control barriers that had been specified. Electronic dosimeter alarm set points for both integrated dose and dose rate were evaluated for conformity with survey indications and plant policy. Workers were interviewed to verify that they were aware of the actions required when their electronic dosimeters noticeably malfunctioned or alarmed. This review represented one inspection sample.The inspectors reviewed selected RWPs used in the containment on May 2, 2006, anairborne radioactivity area, to verify barrier integrity and engineering controls performance (e.g., High Efficiency Particulate Air (HEPA) ventilati on system operation),and to determine if there was a potential for individual worker internal exposures of greater than 50 millirem committed effective dose equivalent. Work areas having a history of, or the potential for, airborne transuranics were evaluatedto verify that the licensee had considered the potential for transuranic isotopes andprovided appropriate worker protection. Specifically, the inspectors reviewed the survey data available from breaching primary systems and surveys of the Reactor PressureVessel Head during the replacement process. This review represented one inspection sample.
25The adequacy of the licensee's internal dose assessment process for internal exposuresgreater than 50 millirem committed effective dose equivalent was assessed. Additionally,the inspectors reviewed the licensee's assessment of 30 assigned internal exposures even though the exposures were less than 50 millirem. This review represented oneinspection sample.
b. Findings
One finding of very low safety significance was identified. Additionally, a findingregarding airborne radioactivity areas in containment is discussed in Section 2OS2.2.A High Radiation Area Barrier Found in an Open PositionIntroduction: A Green finding and associated NCV were identified when NRC inspectorsobserved a High Radiation Areas (HRA) boundary barrier (a swing-gate) in the open position because it had moved in its base to the open position and would not swing closed.
Description:
On May 10, 2006, while conducting a walkdown of Unit 1 containment,NRC inspectors observed a swing gate used as the entry barrier to an HRA located on the 695 level at the entrance to the 11 steam generator vault in the open position. Theinspectors pulled the swing gate to the closed position but the gate immediately swungback to the open position because the gate post had rotated within its base, changing the orientation of gate closed position. The inspectors stayed at the entrance to the HRA toprevent unauthorized entry and sent one person to notify Radiation Protection personnelcorrect the problem. No personnel were inside the HRA at the time the compromised HRA barrier was identified.The probability of unauthorized HRA entry was small while the swing gate (HRA barrier)was open, since the steam generator vault had video monitoring at the steam generatormanway area, which was the most dose significant area within the HRA. It is anticipated that if workers had inadvertently entered the HRA they would have been detected byvideo monitoring. Additionally, a review of electronic dosimeter alarms did not identify any anomalies that would indicate that unauthorized individuals had entered this area.The licensee concluded that workers had previously entered/exited the HRA but failed toensure that the swing gate barrier was properly positioned upon exit. The failure to assure through self-checking that the swing gate HRA barrier was closed when entering or leaving the HRA created a condition contrary to a TS that requires an HRA be barricaded and conspicuously posted as an HRA. The licensee wrote a corrective action document (CAP 1029288) to initiate the problemidentification and resolution process. The licensee conducted a review of containment HRA barriers to assure that no other HRA barriers/controls were at risk of failing.
Additionally, the radiation protection staff was briefed on the finding during shift turnover meeting to heighten the awareness of the failure in an effort to prevent further occurrences.
26On May 1 and 29, 2006, the licensee identified two additional incidents of similar HRAbarrier failure, as described in Section
4OA7 of this report.
As a result of these events and other HRA barrier and posting concerns identified during the outage the licensee initiated CAP 1033802 to assess an adverse trend in HRA control and take concerted corrective action to prevent recurrence.
Analysis:
The failure to assure HRA barriers were returned to the closed position afteruse was a performance deficiency warranting a significance evaluation. The issue was associated with the Occupational Radiation Safety cornerstone and potentially affectedthe cornerstone objective to ensure adequate protection of worker health and safety from exposure to radiation. The issue was more than minor because it affected the Occupational Radiation Safety cornerstone attribute of program and process for radiation worker performance and consequently represented a finding as described in IMC 0612, Appendix B, "Issue Screening." The issue does not involve the application of traditional enforcement because it did not result in actual safety consequences or the potential to impact the NRC's regulatory function and was not the result of any willful actions. Thefinding was evaluated using IMC 0609, Appendix C, the SDP for the OccupationalRadiation Safety cornerstone, and was determined to be of very low safety significance (Green) because it did not involve an As-Low-As-Reasonably-Achievable (ALARA) issue, as collective dose was not a factor and no individual received an unintended dose as a result of the barrier non-compliance. Additionally, individual radiation exposures forworkers in and around this HRA of containment during that time was low relative to regulatory limits; there was not a substantial potential for a worker overexposure; and thelicensee's ability to assess worker dose was not compromised. The inspectors determined that the performance deficiency associated with this event was a humanperformance failure in that radiation workers failed to use self-checking that led to a non-compliance with a TS. The primary cause of this event was a cross-cutting issue related to human performance. As described in Section 4OA7, Licensee Identified Violations, two additional HRA barrierevents were licensee-identified and had similar human performance weaknesses identified.
Enforcement:
Technical Specification 5.7.1.a. requires for an HRA with dose rates lessthan 1.0 rem in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> at 30 centimeters from the radiation source or from any surfacethat the radiation penetrates, each entryway to such an area shall be barricaded.Contrary to the above, on May 10, 2006, a barricade to an HRA located on 695' levelat the entrance to the 11 steam generator vault in the Unit 1 containment was left inthe open position and was not attended by personnel to prevent unauthorized entry. Since the finding is of very low safety significance and had been entered into the corrective action system as CAP 1029288, the associated violation is being treatedas an NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000282/2006003-02; 05000306/2006003-02).
.2 Problem Identification and Resolution
a. Inspection Scope
The inspectors reviewed five corrective action reports related to access controls and fourHRA radiological incidents (non-performance indicators identified by the licensee in high radiation areas less than 1 rem per hour). Staff members were interviewed and corrective action documents were reviewed to verify that follow-up activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk based on the following:*initial problem identification, characterization, and tracking;*disposition of operability/reportability issues;*evaluation of safety significance/risk and priority for resolution;
- identification of repetitive problems;
- identification of contributing causes;
- identification and implementation of effective corrective actions;
- resolution of NCVs tracked in the corrective action system; and
- implementation/consideration of risk significant operational experience feedback.This review represented one inspection sample.
b. Findings
No findings of significance were identified.
.3 Job-In-Progress Reviews
a. Inspection Scope
The inspectors observed the following two jobs that were being performed in radiationareas, airborne radioactivity areas, or high radiation areas for observation of work activities that presented the greatest radiological risk to workers: *steam generator eddy current testing; and*safety injection 92-2 check valve maintenance. The inspectors reviewed radiological job requirements for these two activities includingRWP requirements and work procedure requirements, and attended an ALARA job briefing. This review represented one inspection sample.Job performance was observed with respect to these requirements to verify thatradiological conditions in the work area were adequately communicated to workers through pre-job briefings and postings. The inspectors also verified the adequacy of radiological controls including required radiation, contamination, and airborne surveys forsystem breaches; radiation protection job coverage which included audio and visualsurveillance for remote job coverage; and contamination controls. This review represented one inspection sample.
28Radiological work in high radiation work areas having significant dose rate gradients wasreviewed to evaluate the application of dosimetry to effectively monitor exposure to personnel and to verify that licensee controls were adequate. These work areas involved those where the dose rate gradients were severe, which increased the necessity of providing multiple dosimeters and/or enhanced job controls. This review represented one inspection sample.
b. Findings
No findings of significance were identified.
.4 High Risk Significant, High Dose Rate High Radiation Area, and Very High RadiationArea Controls
a. Inspection Scope
The inspectors held discussions with the radiation protection manager concerning highdose rate/high radiation area and very high radiation area controls and procedures, including procedural changes that had occurred since the last inspection, in order to verify that any procedure modifications did not substantially reduce the effectiveness and level of worker protection. This review represented one inspection sample.The inspectors discussed with radiation protection supervisors the controls that were inplace for special areas that had the potential to become very high radiation areas duringcertain plant operations, to determine if these plant operations required communication beforehand with the radiation protection group, so as to allow corresponding timely actions to properly post and control the radiation hazards. This review represented one inspection sample.The inspectors conducted plant walkdowns to verify the posting and locking of entrancesto high dose rate HRAs, and very high radiation. This review represented one inspection sample.
b. Findings
No findings of significance were identified
.5 Radiation Worker Performance
a. Inspection Scope
During job performance observations, the inspectors evaluated radiation workerperformance with respect to stated radiation protection work requirements and evaluated whether workers were aware of the significant radiological conditions in their workplace, the RWP controls and limits in place, and that their performance had accounted for thelevel of radiological hazards present. This review represented one inspection sample.
29The inspectors reviewed radiological problem reports which found that the cause of theevent was due to radiation worker errors to determine if there was an observable pattern traceable to a similar cause, and to determine if this perspective matched the corrective action approach taken by the licensee to resolve the reported problems. These problems, along with planned and taken corrective actions, were discussed with the radiation protection manager. This review represented one inspection sample.
b. Findings
No findings of significance were identified, other than those previously discussed inSection 2OS1.1.
.6 Radiation Protection Technician Proficiency
a. Inspection Scope
During job performance observations, the inspectors evaluated radiation protectiontechnician performance with respect to radiation protection work requirements, and evaluated whether they were aware of the radiological conditions in their workplace, the RWP controls and limits in place, and if their performance was consistent with theirtraining and qualifications with respect to the radiological hazards and work activities.
This review represented one inspection sample.The inspectors reviewed one radiological problem report which found that the cause ofthe event was radiation protection technician error to determine if the corrective action approach taken by the licensee to resolve the reported problems was appropriate. This review represented one inspection sample.
b. Findings
No findings of significance were identified.2OS2ALARA Planning and Controls (71121.02)
.1 Inspection Planning
a. Inspection Scope
The inspectors reviewed plant collective exposure history, current exposure trends, andongoing and planned activities in order to assess current performance and exposure challenges. This included determining the plant's current 3-year rolling average forcollective exposure in order to help establish resource allocations and to provide a perspective of significance for any resulting inspection finding assessment. This review represented one inspection sample.
30The inspectors reviewed the outage work scheduled during the inspection period andassociated work activity exposure estimates for the following three work activities which were likely to result in the highest personnel collective exposures. These activities included: *steam generator eddy current testing;*safety injection 92-2 check valve maintenance; and
- steam generator manway removal.This review represented one inspection sample.
The inspectors reviewed procedures associated with maintaining occupational exposuresALARA and processes used to estimate and track work activity specific exposures. This review represented one inspection sample.
b. Findings
No findings of significance were identified.
.2 Radiological Work Planning
.
a. Inspection Scope
The inspectors evaluated the licensee's list of work activities ranked by estimatedexposure that were in progress and reviewed the following four work activities of highest exposure significance: *steam generator eddy current testing;*steam generator 11 and 12 primary nozzle dam installation;
- safety injection 92-2 check valve maintenance; and
- steam generator manway removal. This review represented one inspection sample.
For these four activities, the inspectors reviewed the ALARA work activity evaluations,exposure estimates, and exposure mitigation requirements in order to verify that the licensee had established procedures, and engineering and work controls that were based on sound radiation protection principles in order to achieve occupational exposures that were ALARA. This also involved determining that the licensee had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances. This review represented one inspection sample.The inspectors compared the results achieved including dose rate reductions andperson-rem used with the intended dose established in the licensee's ALARA planning for these four work activities. Reasons for inconsistencies between intended and actual work activity doses were reviewed. This review represented one inspection sample.
b. Findings
One finding of very low safety significance was identified.ALARA Planning Does Not Identify and Prepare for Potential Airborne Conditions WhenOpening the Steam Generator ManwaysIntroduction: A self-revealed finding of very low safety significance and an associatedNCV were identified when 110 radiation workers were contaminated when the steam generator manways were opened during the 1R24 refueling outage. Specific ALARA planning assessments for steam generator manway opening did not acknowledge that airborne concentrations of radioactivity may be subject to change. Additionally the ALARA planning for this work did not consider the effect of engineering safety systemssuch as HEPA filtration operation or malfunction on other work areas in containment. As a result, the containment clean-up filtrati on system was not properly aligned and securedto the HEPA exhaust to ensure proper control of radioactive iodine in the containment building atmosphere. Consequently, when the work area was set up and initial work commenced, the focus was on the immediate work area only and the result was elevatediodine-131 levels throughout containment.Description: On May 2, 2006, workers opened the steam generator manways to preparefor nozzle dam installation and eddy current testing. A HEPA filtration system wasinstalled in the steam generator vault to reduce particulate contamination from the primary system opening and reduce the potential for airborne conditions in the immediatework area. Additionally, this HEPA was connected to the manway opening to provide contamination control for the steam generator. Radiation workers and radiationprotection technicians did not assure that the discharge from the HEPA systems were properly directed to the containment clean up filter, a HEPA/charcoal filtration train, designed to reduce particulate and gaseous contaminates. Specifically, the HEPA discharge hose was inadequately secured to the containment clean-up filter intake. To install the 11 steam generator manway HEPA discharge hose, workers used procedure 1D27.39, "Initial Steam Generator Outage Work Activities," Attachment F, "Install HEPA Filter Units for 11 and 12 Steam Generators." However, this procedure did not specify the proper method for attaching the HEPA discharge to the containment clean-up filterinput or provide verification of proper fit-up and relied on workers' judgment. When the HEPA discharge hose slipped off the containment clean-up filter intake, because it was loosely attached with wire tie wraps, the steam generator vented directly to the 755' of containment, and this led to increased iodine-131 levels throughout the containment building atmosphere necessitating an evacuation. Inspectors reviewed the HEPA discharge placement after the event, when the hose wasrestored to the containment clean-up filter to verify effective corrective action was taken as a result of the event described above. The inspectors found the HEPA discharge hose simply wired to the intake at a 90-degree angle with two other HEPA discharges attached in similar fashion at the containment clean-up filter intake. Discussions with the licensee staff indicate the initial placement was similar to the post event attachment.
This configuration did not provide a high level of confidence that this was a secure attachment that would assure efficient direction of HEPA discharge to the containment clean-up filter and significantly reduced the possibility of repeat failure.
32When the 11 steam generator manway was opened, the iodine and noble gasespresent in the steam generator migrated to the steam generator platform where a lowvolume sampler was running. Elevated iodine-131 Derived Air Concentration (DAC)levels were identified at this location. On May 2, 2006, at 8:45p.m., approximately 1 hourand 10 minutes after opening the steam generator 11 hot leg manway, the iodine-131 level was sampled and recorded at 1.18 DAC. Another low volume air sampler was running concurrently on the containment 755' level, and the sample was removed at8:25 p.m. and identified 0.63 DAC iodine-131. At 11:15 p.m., the containment radiationprotection leader received the data, posted the containment building as an AirborneRadioactivity Area and notified workers of the change in conditions in their work areas.
At that time, the radiation protection supervisor stopped further entries into containment. Approximately 1-1/4 hours later, based on air sampling data from 8:45 p.m. (1.25 DAC)in the steam generator vault and from 10:35 p.m. (2.37 DAC) 755' level of the containment, the radiation protection supervisor directed the evacuation of non-essentialpersonnel from containment and permitted continuation of the steam generator manwayinstallation and nozzle dam installation work. Twenty minutes, later the general containment building iodine-131 levels reached 2.89 DAC. The highest airborne concentrations recorded during the event were measured at the 755' level of containmenton May 3, 2006, at 2:09 a.m., yielding 4.62 DAC.Post event follow-up testing on the containment clean-up filters was conducted onMay 4, 2006, which revealed an iodine-131 retention efficiency of approximately 66 percent compared to the expected efficiency of greater than 90 percent. The containment clean-up filters were not functioning at the expected efficiency and yet were the planned primary method of limiting the iodine-131 contamination in containment whenopening the primary system following known fuel leakage during the proceedingoperation run. A pre-operational assessment of the operability and efficiency of thisengineered safety system was not part of the ALARA planning process. The periodicsurveillance of the containment clean-up system was on a 6-year frequency and was lastassessed 4 years prior to this event.Similar levels of iodine-131 in the primary coolant were seen prior to a 2001 outage. When primary systems were opened during that outage there was a slight increase inairborne iodine-131 found in containment air samples and this persisted throughout the outage at less than 0.3 DAC. As a result, 290 workers showed a small but measurable uptake of iodine-131 by the end of the outage and 30 workers received between 10 millirem, the threshold for recording the additional dose, and the highest recordedindividual dose was 26 millirem. The collective recorded dose was 446 millirem.Prior to the above mentioned 2001 outage, primary system iodine-131 levels wereidentified prior to the outage due to a small fuel leak. The 2001 levels were very similar to the pre-outage levels for the 2006 outage. The 2001 outage demonstrated the abilityto work with these levels of iodine-131 in the primary coolant successfully since the 2001 outage did not result in dose significant intakes from airborne iodine-131. Therefore, limited measures were planned in an effort to preclude airborne radioactivity in the containment building during this refueling outage. Contingency plans for containmentbuilding contamination were limited to the standing radiation protection procedures for contamination monitoring at access control and disposition of intakes in accordance with Radiation Protection Implementing Procedure (RPIP) 1126, "Contamination Monitor 33Alarm Response, and Personnel Decontamination," and non-specific ALARA engineeringcontrols.The inspectors reviewed a separate event that occurred on May 2, 2006, during the dayshift, where the reactor pressure vessel head was vented to the containment building, releasing iodine-131 and noble gases. The licensee's staff presumed the vessel head was vented through a HEPA filter to the containment clean-up filtration that consists of a pre-filter, HEPA and charcoal bank. This error was identified when containment air sampling showed an increase in the airborne radioactivity (iodine-131, 0.4 DAC). No corrective action document was written regarding this event until May 26, 2006. If the licensee had accurately identified this event as a precursor to similar events, it would have provided an opportunity to make self-assessment prior to additional primary systemopenings. Due partially to the failure to recognize this as a precursor to a more significant event, within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> the containment airborne levels increased again when the steam generator manways were opened and the HEPA filtration was inappropriately positioned in the intake of the containment clean-up filter bank.Analysis: The inspectors determined that the failure to properly plan ALARA workactivities was a performance deficiency and represents a finding as described in IMC 0612, Appendix B, "Issue Screening." ALARA planning did not conduct an adequate assessment of the effect of leaking fuel on the potential for increased iodine and noble gas concentrations in the steam generators and potential impact on the containmentbuilding environment. The issue was more than minor because it was associated with the Occupational Radiation Safety cornerstone, and potentially affected the cornerstoneattribute of program and process for ALARA planning and exposure/contamination control. The finding does not involve the application of traditional enforcement, because it did notresult in actual safety consequences or the potential to impact the NRC's regulatoryfunction, and was not the result of any willful actions. The finding was evaluated usingIMC 0609, Appendix C, the SDP for the Occupational Radiation Safety cornerstone andwas determined to be of very low safety significance (Green) because the finding involved an ALARA issue and individuals received very low unintended dose as a result of the procedural noncompliance. However, individual radiation exposures for workers in containment during that time were low relative to regulatory limits; there was not a substantial potential for a worker overexposure; and the licensee's ability to assessworker dose was not compromised.Enforcement: Technical Specification 5.4.1.a. requires the licensee to establish,implement, and maintain procedures recommended by Regulatory Guide 1.33, Revision 2, Appendix A, date February 1978. Regulatory Guide 1.33 requiresprocedures for the control of radioactivity and limiting of personnel exposure, ALARA Procedure FP-RP-JPP-01, Radiation Protection Job Planning, Attachment 1, directs the job planner, through a series of planning forms, to assess the radiological safety significance of specific work. The Attachment 1 directs the use of form QF-1203, Radiological Work Assessment; QF-1204, Radiological Work Assessment From Contamination Control, if contamination control was a hazard for the assigned work;and QF-1206, Radiological Work Assessment From Internal Exposure Control, if contamination control internal exposure is a hazard for the assigned work.
34Contrary to the above, on March 3 and April 18, 2006, radiation protectionpersonnel assigned to conduct the work assessment, and planning for WO 95654, "11 and 12 Steam Generator Primary Side Manway, and Insert, Remove, and Install,"
failed to recognize that airborne concentrations for the work were subject to significant changes. Consequently, the licensee did not adequately evaluate the internal exposurehazard and document the hazard in accordance with the above procedure. Since the finding is of very low safety significance and had been entered into the corrective action system as CAP 1027653, the associated violation is being treated as an NCV, consistentwith Section VI.A of the NRC Enforcement Policy (NCV 05000282/2006003-03;05000306/2006003-03).
.3 Job Site Inspections and ALARA Control
a. Inspection Scope
The inspectors observed the following two jobs that were being performed in radiationareas, airborne radioactivity areas, or high radiation areas for observation of work activities that presented the greatest radiological risk to workers: *steam generator eddy current testing; and*reactor pressure vessel head removal.The licensee's use of ALARA controls for these work activities was evaluated using thefollowing:*The licensee's use of engineering controls to achieve dose reductions was evaluatedto verify that procedures and controls were consistent with the licensee's ALARA reviews, that sufficient shielding of radiation sources was provided for, and that the dose expended to install/remove the shielding did not exceed the dose reduction benefits afforded by the shielding.This review represented one inspection sample.
b. Findings
No findings of significance were identified.
.4 Radiation Worker Performance
a. Inspection Scope
Radiation worker and radiation protection technician performance was observed duringwork activities being performed in radiation areas, airborne radioactivity areas, and high radiation areas that presented the greatest radiological risk to workers. The inspectors evaluated whether workers demonstrated the ALARA philosophy in practice by being familiar with the work activity scope and tools to be used, by utilizing ALARA low dosewaiting areas, and by complying with the work activity controls. Also, radiation worker training and skill levels were reviewed to determine if they were sufficient relative to theradiological hazards and the work involved. This review represented one inspection sample.
b. Findings
No findings of significance were identified2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems (71122.01)
.1 Identification and Resolution of Problems
a. Inspection Scope
The inspectors reviewed the licensee's outage activities related to the radioactive effluenttreatment and monitoring program to determine if identified problems were entered into the corrective action program for resolution. The inspectors also verified that the licensee's self-assessment program was capable of identifying repetitive deficiencies or significant individual deficiencies in problem identification and resolution. The inspectors also reviewed corrective action reports from the radioactive effluenttreatment and monitoring program since the previous inspection, interviewed staff and reviewed documents to determine if the following activities were being conducted in an effective and timely manner commensurate with their importance to safety and risk: *initial problem identification, characterization, and tracking;*disposition of operability/reportability issues;*evaluation of safety significance/risk and priority for resolution;
- identification of repetitive problems;
- identification of contributing causes;
- identification and implementation of effective corrective actions;
- resolution of NCVs tracked in the corrective action system; and
- implementation/consideration of risk significant operational experience feedback.This review represented one inspection sample.
b. Findings
One finding of very low safety significance was identified.
Procedure for Offsite Dose Calculation Manual Compliance Does Not IncludeContainment Effluent Through Equipment HatchIntroduction: An inspector-identified finding of very low safety significance and anassociated NCV of NRC requirements were identified for the failure to establish adequatewritten procedure(s) for Offsite Dose Calculation Manual (ODCM) implementation to ensure that the radiological impact from releasing gaseous and particulate effluents from the Unit 1 containment building equipment hatch to the environment was properlyassessed prior to the release, and that the release was properly quantified and reported.
Description:
On May 5 to May 11, 2006, the Unit 1 containment equipment hatch wasopen to the atmosphere to allow equipment and personnel in and out of containment in support of a refueling outage and head replacement activities. The negative pressure 36necessary to prevent uncontrolled releases of radioactive material was not adequatelymaintained during periods when the equipment hatch was open and allowed air from containment to vent to the atmosphere through the containment building equipmenthatch opening. This problem was identified on multiple occasions during this outage by the licensee and by NRC personnel and brought to the attention of the Outage ControlCenter. This prompted the operations staff to investigate the in-service purge fan alignment and periodically adjust the position of a tarp that was available at the equipment hatch opening to limit the effect of the positive pressure in containment and any release to the environment. The inspectors noted that these interim corrective actions were not consistently implemented. The licensee monitored concentrations of iodine-131 and xenon-133 in the containment air and found that the concentration ofgaseous radioactivity was measurable but at very low concentration (less than 0.3 DAC)during the time that the equipment hatch was open. The air contained radioactivematerial because the primary system was open in several locations and the RCScontained elevated entrained fission gas concentrations at shutdown due to minor fueldegradation which emerged during the unit's run cycle.The inspectors concluded that the licensee failed to develop an ODCM implementingprocedure that ensured that the offsite dose to the public from venting the RCS tocontainment was properly quantified if the containment came under positive pressure andvented to the environment through the equipment hatch. Additionally, because openingthe equipment hatch during the last three outages was a planned evolution, theequipment hatch had become a routine release point. However, the licensee had not revised the ODCM to document the pathway.Following May 5 to 11, 2006, a period when the equipment hatch was open, and afteradditional questions raised by the NRC, a corrective action document was subsequentlywritten to evaluate and address the deficiencies with the release assessment process described above. Additionally, this corrective action document, CAP 1027608, "Inadequate Effluent Release Controls at the Unit 1 Equipment Hatch," led to a report,"Quantification of Abnormal Releases Via Roll-up Doors and Equipment Hatch During Refueling Outage 1R24." The inspectors reviewed this document to assure that it:*described the radiological impact from releasing radioactive effluents through thecontainment building equipment hatch to the environment, because it was not properly assessed prior to the release;*demonstrated the offsite dose ALARA objectives of 10 CFR Part 20 and10 CFR Part 50, Appendix I; and *ensured that the release was properly quantified and reported.Analysis: The failure to develop a procedure for ODCM implementation to ensure theradiological impact from releasing radioactive gases to the environment through the equipment hatch was properly assessed prior to the release and that the release wasproperly quantified and reported in accordance with ODCM requirements represents a performance deficiency as defined in IMC 0612, "Power Reactor Inspection Reports,"
Appendix B, "Issue Screening." The inspectors determined that the issue was more thanminor because it was associated with the program and process attribute of the Public Radiation Safety cornerstone and potentially affected the cornerstone objective to ensure adequate protection of the public from exposure to radioactive materials from the release 37of gaseous effluents. Therefore, the issue was more than minor and represented afinding which was evaluated using the SDP.Since the finding involved an occurrence in the licensee's radiological effluent monitoringprogram, the inspectors utilized IMC 0609, Appendix D, "Public Radiation Safety SDP," toassess its significance. The issue was not associated with radioactive material control
- however, the licensee failed to adequately assess the offsite dose impact prior to the releasing radioactive effluents from containment through the equipment hatch; therefore,the situation represented an impaired ability to assess dose. However, the licensee subsequently assessed the offsite dose resulting from the release and determined that applicable dose limits were met. The actual effluent releases, as calculated by the licensee, were not greater than regulatory dose limits or ALARA constraints as defined in the 10 CFR 20.1301(d) or 10 CFR Part 50, Appendix I. The calculated dose to a member of the public using conservative parameters was less than 0.025 millirad. Consequently, there was minimal actual risk to the public from the release; and, therefore, the inspectors concluded that the SDP assessment for this finding was of verylow safety significance (Green).Multiple opportunities to identify and correct deficiencies associated with effluent controlsand assessment were presented during outages in 2004, 2005, and 2006. While thesewere entered into the licensee's corrective action program, effective corrective action to prevent recurrence was not achieved. The primary cause of this event was a cross-cutting issue related to problem identification and resolution program deficiencies.Enforcement
- Technical Specification 5.5.1 requires that the ODCM contain themethodology and parameters used in the calculation of offsite doses resulting from radioactive gaseous effluents. Offsite Dose Calculation Manual, step 7, requires compliance with TS 5.5.4 regarding the Radioactive Effluent Controls Program, which requires that the program be contained in the ODCM, and shall be implemented byprocedures. Contrary to this requirement, adequate written procedures were not established to ensure the radiological impact from releasing radioactive effluents through the containment building equipment hatch during outages in 2004, 2005, and 2006, wereproperly assessed prior to release to demonstrate it satisfied the ALARA design objectives of 10 CFR Part 20 and 10 CFR Part 50, Appendix I. Since the licensee documented this issue in its corrective action program (CAPs 1027608, 1027653, 1028580, and 1029875) and because the violation was of very low safety significance, it is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 50-282/2006003-04; 50-306/2006003-04).
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
.1 Reactor Safety Strategic Area
a. Inspection Scope
The inspectors reviewed the licensee submittals for two performance indicators forPrairie Island Units 1 and 2, completing four performance indicator verification inspection procedure samples. The inspectors used performance indicator guidance and definitions contained in NEI Document 99-02, Revision 3, "Regulatory Assessment PerformanceIndicator Guideline," to verify the accuracy of the performance indicator data. The inspectors' review included, but was not limited to, conditions and data from logs, Licensee Event Reports, condition reports, and calculations for each performance indicator specified. The inspectors also reviewed the CAPs listed in the Attachment to this report to verify that the licensee was identifying issues at an appropriate threshold and entering them into their corrective action program in accordance with corrective action procedures.The licensee's reporting of the following performance indicators were verified:
Unit 1*Unplanned Power Changes per 7000 Critical Hours for the 2 nd Quarter 2004 through the 1 st Quarter 2006;*Safety System Functional Failures for the 2 nd Quarter 2004 through the 1 st Quarter 2006.Unit 2*Unplanned Power Changes per 7000 Critical Hours for the 2 nd Quarter 2004 through the 1 st Quarter 2006;*Safety System Functional Failures for the 2 nd Quarter 2004 through the 1 st Quarter 2006.Key documents used by the inspectors in conducting this inspection are listed in theAttachment to this report.
b. Findings
No findings of significance were identified.
394OA2Identification and Resolution of Problems (71152)
.1 Routine Review of Identification and Resolution of Problems
Introduction
- As discussed in previous sections of this report, the inspectors routinelyreviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensee's corrective action program at an appropriate threshold, that adequate attention was given to ensure timely corrective actions, and that adverse trends were identified and addressed. This does not count as an annual sample.
a. Inspection Scope
As discussed in Section 2OS1.1 and 2PS1.1, the inspectors reviewed the licensee'sproblem identification and resolution program to assess the adequacy of the radiation protection department's ability to identify and document problems and to implementtimely and appropriate corrective actions. In particular, the inspectors reviewed the circumstances surrounding an HRA barrier that was found in the open position, which was identified by the NRC on May 9, 2006, and documented in CAP 1029288. Tocomplete the review, the inspectors discussed the issue with several members of the radiation protection staff, supervision and management and reviewed additional licensee-identified HRA barrier issues documented in 4OA7, to determine the adequacy for identifying problems with HRA barriers. Additionally, the inspectors reviewed the circumstances surrounding loss of negative pressure on the containment building when the equipment hatch was open from May 5 to 11, 2006, and the associated effluentassessment as documented in CAP 1027608. To complete the review, the inspectors discussed the issue with several members of the radiation protection and chemistry staff, supervision and management and reviewed additional licensee-identified corrective action documents written in response to similar effluent events during outages in 2004
and 2005.
b.IssuesHigh Radiation Area Barrier EventsThe NRC identified an HRA barrier event during the inspection as discussed in 2OS1.1. The licensee identified multiple similar HRA barrier events as described in 4OA7.
Consequently, on June 4, 2006, following the Unit 1 refueling outage, the licenseeindicated to the inspectors that they planned to conduct an Adverse Trend of High Radiation Area Control within the scope of the corrective action program (CAP 1033802)using these events and six additional licensee-identified findings as the basis for the review. The inspectors concluded that although individual occurrences of HRA barrier integrity were addressed through repairs as they occurred, the licensee failed to identify the fundamental cause of the problem in a timely manner and allowed the problem to recur during the refueling outage. While the degraded HRA barriers did not result in an occurrence under the occupational exposure control effectiveness performance indicator, it increased the probability of an unauthorized HRA or even Locked High Radiation Areaentry and, therefore, represented an additional level of risk.
40Lack of Extent of Condition Assessment for Air Flow ProblemsIn 2004, the licensee generated CAP 38784 to document the loss of negative pressure incontainment that resulted in a small release of radioactivity to the environment. The corrective action for that problem included directions for the next outage that governed controls for ventilation pathways when the containment hatch was open. However, thelicensee's evaluation was inadequate and the associated corrective actions were not consistently implemented to ensure that the environmental impact from releasingradioactive effluents from containment through the equipment hatch was assessed adequately prior to the release. In 2005, the licensee generated a corrective action CAP 841226 to document the failure to implement the corrective actions specified in 2004 (CAP 38784). However, the licensee's evaluation of that CAP and the associated corrective actions were not sufficiently comprehensive to ensure that the environmental impact from releasing radioactive effluents from containment through the equipment hatch was assessed adequately before the effluent was released. In 2006, the licenseewas again presented with lack of control over the airflow at the containment buildingequipment hatch and again did not ensure that the environmental impact from releasingradioactive effluents from containment through the equipment hatch was assessed adequately before the effluent was released. While the licensee was able to conservatively reconstruct the small radioactive effluents in each instance and record them, the effectiveness of corrective actions lacked rigor. Specifically, the response to the issues was limited in scope, lacked adequate assessment of the extent of conditionand failed to result in effective corrective action. The deficiencies with the licensee's problem evaluation and resolution program, a cross cutting issue, significantly contributed to this repetitive problem. Missed Opportunity to Identify a Precursor to a More Significant EventOn May 2, 2006, the Reactor Pressure Vessel Head was vented to containmentreleasing iodine-131 and noble gases. The licensee staff thought the venting process was directed through a HEPA filter to the containment clean-up filtration that consists of a pre-filter, HEPA and charcoal bank. This error was identified when containment air sampling showed an increase in the airborne radioactivity. The licensee took immediate action to clear containment until they could understand the source of the elevated levels. This was a precursor or an indicator of the potential for additional and similar events.
In fact, within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> the containment airborne levels increased again when the 11 steam generator was opened and the HEPA filtration discharge was inappropriately positioned in the intake of the containment clean-up filter bank. Because the events were similar in result and occurred on the same day, the licensee staff did not initially separate this event from the review of the second event when the 11 steam generatorwas opened and airborne iodine-131 levels increased. Until the NRC discussed this withthe staff and management as a separate event with potentially separate causes and aprecursor event, no corrective action document was written. A corrective action program document was written May 25, 2006 (CAP 1032258).Mistake in Calculating DAC Levels During the opening of 11 steam generator that lead to an airborne event on May 2, 2006,the licensee collected frequent containment air samples and analyzed them for airborne gaseous and particulate levels. During one of the sampling counts and assessment, a 41mistake in calculating a DAC was made and it resulted in reporting higher level than waspresent. While this was a conservative mistake, it did provide information that should have been reviewed for potential program improvement. The need to document this issue was not readily apparent. No corrective action document was immediately written.
After discussion of this issue with the NRC, a corrective action program document was written May 22, 2006 (CAP 1031483).
.2 Annual Problem Identification and Resolution Sample
a. Inspection Scope
On April 29, 2006, during the performance of a planned Unit 1 shutdown to performrefueling, operators performed stroking of the pressurizer PORV CV-31232 in accordance with SP 1182A. CV-31232 failed to fully open during the test. This condition was entered into the licensee's corrective action program with CAP 01026977. Initial inspection of the PORV by maintenance personnel identified the most probable cause as galling between the valve plug and cage. The cause was later confirmed during disassembly of the valve.The inspectors conducted one annual Problem Identification and Resolution inspectionsample to review the corrective action aspects associated with this event and a similar occurrence associated with PORV CV-31231. The degraded condition of CV-31231 was found during the previous Unit 1 refueling outage (1R23) and was documented with CAP 039892. The inspectors reviewed the licensee's condition evaluation, engineering documents for the modification of the PORV internals, and the licensee's plans for installation of the new valve internals. The inspectors reviewed PORV maintenance history and discussed PORV historical performance and corrective actions with engineering personnel.The key documents reviewed by the inspectors associated with this inspection are listedin the Attachment to this report.
b. Findings and Observations
No findings of significance were identified.
.3 Semiannual Problem Identification and Resolution Trend ReviewThe inspectors performed a semiannual review of the licensee corrective action programto identify trends that could indicate the existence of a more significant safety issue as
required by Inspection Procedure 71152, "Identification and Resolution of Problems."
This inspection effort completed the required semiannual trending inspection and one inspection sample. The effectiveness of the licensee corrective action program was assessed by comparing trends identified by the licensee with those issues identified by the NRC during the conduct of routine plant status and baseline inspections. Inspectorsreviewed CAPs initiated during the period from January 1 through June 20, 2006. The inspectors utilized Pareto analysis and the symptom classification technique to evaluatethe CAP data base to select areas for detailed review. The areas selected for detailed review included the Corrective Action Program, the Radiation Protection program, the 42Emergency Preparedness program, the Security program, and human performance. Theinspectors performed the inspection by in-office review of licensee corrective action program and other reports, including the following:*trend reports;*performance indicators;
- equipment problem lists;
- rework reports;
- system health reports;*program health reports; and
- maintenance rule reports.
b. Findings and Observations
No findings of significance were identified. The inspectors identified that the primarymethod used by the licensee to identify potential adverse trends is the Department RollUp Meeting (DRUM). The inspectors identified that the licensee identified potentialadverse trends and entered them into the corrective action program for all of the areas selected for detailed review except:
- emergency preparedness siren issues; and*lost badges.Although these shortcomings within the licensee's trending process were noted, noviolations of NRC requirements were identified.4OA3Event Followup (71153)
.1 (Closed) Licensee Event Report (LER) 05000306/2006-001-00:
Unit 2 ShutdownRequired by TSs Due to Inoperable Emergency Diesel GeneratorOn January 29, 2005, diesel generator D6 was removed from service for plannedmaintenance. During return-to-service testing, the test was halted due to high crankcase pressure. Investigation attributed the crankcase pressure to piston ring blow-by.
Evaluation of the scope of the work indicated that repairs could not be completed withinthe remainder of the 7-day completion time. Unit 2 was shut down on February 5, 2006.
The licensee performed a root cause investigation, implemented corrective actions to prevent recurrence and short term corrective actions, and returned the unit to power operation. The licensee documented the problem, root cause analysis, and corrective actions in CAP 01013473. The LER, root cause analysis report, and corrective actions were reviewed by the inspectors. No findings of significance were identified and no violations of NRC requirement occurred. This LER is closed.
.2 Event Followup of the Inoperability of Both Pressurizer PORVs During Unit 1 Shutdown
a. Inspection Scope
On April 30, 2006, the licensee informed the inspectors that both Unit 1 pressurizerPORVs were inoperable. The licensee was in the process of a shutdown/cooldown of the Unit 1 reactor coolant system and the plant was in a configuration where thepressurizer PORVs were required by TS for the completion of the low temperature-overpressure protection function. The "A" PORV was declared inoperable on April 29, 2006, at 3:21 a.m. when it failed to fully open during surveillance test SP 1182A. The "B" PORV was declared inoperable on April 30, 2006, at 9:00 p.m. when an operatoridentified the "B" PORV back up air bottle at pressure 1200 pounds per square inch. A minimum bottle pressure of 1800 pounds per square inch is required for an operable back up air supply for each of the PORVs. The inspectors developed a time line leading up to the declaration of each PORVinoperability and the establishment of a three square inch vent in the reactor coolantsystem in accordance with the TS. The inspectors compared TS requirements to theactual plant conditions. The inspectors verified the adverse conditions noted with the pressurizer PORVs were promptly entered into the corrective action program; that the licensee implemented appropriate corrective actions to restore compliance with the TS; and the timeliness of those corrective actions were commensurate with the safety significance of the PORV failures.
b. Findings
No findings of significance were identified.4OA5Other Activities
.1 Resolution of Unresolved Item (URI)05000282/2006002-01; 05000306/2006002-01
- Evaluation of Expired Sealant Performance for Flood Protection
a. Inspection Scope
The inspectors reviewed the licensee's efforts to test and demonstrate acceptable performance characteristic of Deck-O-Seal gun grade sealant. The sealant was identified by the inspectors to be 1 year beyond its vendor recommended shelf-life in the previous inspection period. The inspectors concluded that the licensee's performance deficiency may be minor if the expired sealant was tested and satisfactory performance was demonstrated. The inspectors tracked the resolution of the issue with URI 05000282/2006002-01; 05000306/2006002-01.
b. Findings
Introduction:
The inspectors identified a Non-Cited Violation of 10 CFR Part 50Appendix B, Criterion V, for a combination of an inadequate procedure and a failure to implement the requirements of Surveillance Procedure 1293, Inspection of Flood ControlMeasures and the Shelf Life Program Procedure FP-SC-PE-05. Specifically, the 44licensee failed to order and maintain the correct type of Deck-O-Seal sealant to facilitateinstallation of flood doors and panels in accordance with plant abnormal procedures.Description: On March 29, 2006, the inspectors inspected the main warehouse to verifythe existence of the flood protection materials listed in Table 1 of Surveillance ProcedureSP 1293, "Inspection of Flood Control Measures," Revision 13. All the listed materials were found by inspectors but the Deck-O-Seal sealant was found 1 year beyond its shelf life expiration date. Deck-O-Seal gun grade sealant is necessary during an exterior flood event to sealseams on eight exterior doors for the turbine, auxiliary, and Unit 2 diesel generatorbuildings in accordance with the flood bulkhead installation instruction in Abnormal Operating Procedure AB-4, Attachment J, Figure J-1. In addition, AB-4 also specifies the use of the sealant, as needed, to seal any gaps on the 11 exterior flood protection panels for the turbine building, auxiliary building, screenhouse, and Unit 2 diesel generatorbuilding in accordance with AB-4, Figure J-2. These doors and panels provide a flood barrier that protects plant safety-related systems and components located below the705 foot (above mean sea level) elevation in the event of the maximum probable flood. The condition of the Deck-O-Seal sealant found by the inspectors was not in accordancewith SP 1293. The surveillance procedure specified the annual inspection of floodprotection features and materials. The licensee completed that inspection on February 17, 2006. Step 7.2.7.C specified that the performer of the flood controlmeasures inspection informs warehouse personnel to order four new kits of the sealant and to dispose of the expired shelf life sealant. This step was signed off as completed.
However, upon inspection of the material in the warehouse, the inspectors noted a hand-written date of March 2005 written on the sealant kits. The licensee's Shelf Life Program procedure FP-SC-PE-05, Revision 0, Step 3.7.2, requires the identifying and labeling ofage-sensitive items with a shelf life expiration date on the attached part tag or quality tag as appropriate. The inspectors concluded that the sealant was one year beyond its expiration date. The inspectors concluded that SP 1293, Step 7.2.7.C was inadequate as written since itonly required personnel performing the flood control measures inspections to notify warehouse personnel to order new sealant kits and dispose of the outdated material.
There was no action to track the actual completion of the step (i.e., the actual receipt of new and the disposal of the expired sealant).The inspectors noted that the licensee had failed to follow the Shelf Life Program asrequired by procedure FP-SC-PE-05. Step 5.3.1 states that the receipt of the sealantand its corresponding shelf life shall be entered into the Material Management System database. The licensee determined that the Deck-O-Seal sealant had not been enteredinto Material Management System database. This failure resulted in the sealant exceeding its shelf life by one year.Additionally, during preparation to test the expired sealant, it was discovered that thelicensee had historically ordered and received Deck-O-Seal pourable sealant, not the gun grade sealant as specified by SP 1293. The pourable sealant is only acceptable for use in horizontal applications. The sealing of the plant's flood doors requires a sealant 45acceptable for vertical application. Upon discovery, the licensee ordered and received,overnighted, the correct sealant.
Analysis:
The inspectors reviewed the issue for significance using the guidance providedin IMC 0612, Appendix B, dated September 30, 2005. The inspectors concluded that theissue was a performance deficiency since the warehouse personnel failed to enter the receipt of the material and its associated shelf life into the Material Management System database as required by procedure FP-SC-PE-05; failed to reorder the Deck-O-Seal gun grade sealant as required by SP 1293; and failed to perform an adequate receipt inspection to determine that the sealant received was not the correct sealant for theapplication (i.e., pourable versus gun grade.) The inspectors reviewed the examples of minor findings provided in IMC 0612,Appendix E, dated September 30, 2005, and concluded that example 2E closely matchedthis finding. Specifically, not only did the sealant exceed the shelf life of the vendor, itwas also the wrong type of material for this application. The inspectors completed the significance determination of this finding using IMC 0609,"Significance Determination Process," dated March 21, 2003, Appendix A, "Determiningthe Significance of Reactor Inspection Findings for At-Power Situations," dated December 1, 2004. The Phase 1 Significance Determination worksheet identified thatthe finding did not contribute to the likelihood of a primary or secondary system loss ofcoolant accident initiator; the finding did not contribute to both the likelihood of a reactortrip and the likelihood that mitigation equipment or functions will not be available; and thefinding did not increase the likelihood of a fire or internal or external flooding. The inspectors concluded that the last Phase 1 SDP criterion of not increasing thelikelihood of external flooding was met only after the licensee demonstrated with an evaluation the slow progression (3 days) of the external flooding event, the typically short procurement time (1 day) for the Deck-O-Seal gun grade sealant, and the availability ofother potentially acceptable sealants. Therefore, the inspectors concluded that thedeficient condition did not increase the likelihood of the external flooding event affecting plant safety-related systems or components and was determined to be of very low safetysignificance (Green).Enforcement: The Introduction to 10 CFR 50, Appendix B, states the pertinentrequirements of this appendix apply to all activities affecting the safety-related functions of those SSCs: these activities include designing, purchasing, fabricating, handling, shipping, storing, cleaning, erecting, installing, inspecting, testing, operating, maintaining,repairing, refueling, and modifying. Therefore, the external flood protection featuresassociated with the safety-related structures are functions of that structure that ultimatelyprotect the safety-related systems and components contained within those structures. As such, the flood doors associated with this finding must meet the requirements of 10 CFR 50, Appendix B. Specifically, 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," states that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Instructions, procedures, or drawings shall include appropriate 46quantitative or qualitative acceptance criteria for determining that important activitieshave been satisfactorily accomplished.Contrary to the above, on March 29, 2006, inspectors identified that the licensee failed toinclude appropriate quantitative or qualitative acceptance criteria for determining thatimportant activities have been satisfactorily accomplished. Specifically that Step 7.2.7.Cof Surveillance Procedure 1293 failed to track the reorder of new sealant and the removal of the expired sealant until satisfactorily accomplishment. This failure resulted in a critical procedure step to go uncompleted for an extended period of time. Additionally, the inspectors identified that the licensee had failed to follow procedureFP-SC-PE-05. Specifically, Step 5.3.1 states that the receipt of the sealant and itscorresponding shelf life shall be entered into the Material Management System database.
The licensee found that the Deck-O-Seal sealant had not been entered into MaterialManagement System database. This failure resulted in the sealant exceeding its shelf life by 1 year.Finally, the licensee failed to correctly implement SP 1293 in that they had historicallyordered, received, and accepted Deck-O-Seal pourable sealant, not the gun grade sealant as specified by the procedure. This resulted in the maintenance of an unusable form of sealant on site for an extended period of time. Because this violation was of very low safety significance and it was entered into thelicensee's corrective action program with CAPs 01021256 and 01025266, this violation is being treated as an NCV, consistent with Section VI.A of the NRC Enforcement Policy (NCV 05000282/2006003-05; 05000306/2006003-05).
.2 Partial Completion of Temporary Instruction 2515/166 Pressurized Water ReactorContainment Sump Blockage
a. Inspection Scope
The inspectors completed a partial review of the installation of a plant modificationcommitted to in the licensees response to Generic Letter 2004-02. The inspectors compared the as-built configuration of the new Unit 1 sump B strainer to the design description and applicable drawings and reviewed changes to Unit 1 emergency operating procedures.
b. Findings
No findings of significance were identified.
.3 RVCH and CRDM Housing Replacement (71007)The original penetration nozzles were fabricated from Inconel Alloy 600 material.
Thesenozzles were welded to the RVCH with a partial penetration weld fabricated from Inconel Alloy 182 weld filler metal. In recent years, several pressurized water reactors haveexperienced pressure boundary leakage caused by primary water stress corrosion cracking of these materials.
47The design of the Unit 1 replacement RVCH is similar to the original, with some notableexceptions as follows:*the new RVCH is constructed from a single piece forging which eliminates thedome-to-flange weld;*the new RVCH design eliminates canopy seal welds;
- the new RVCH design eliminates the part length CRDM penetrations; and*the use of Inconel Alloy 600 was prohibited in fabrication of the new RVCH. Forexample, the penetration tube material was changed from Inconel Alloy 600 to Inconel Alloy 690 which is more resistant to primary water stress corrosion cracking.
a. Inspection Scope
From April 24 through 28, 2006, from May 1 through 5, 2006, and from May 15through 19, 2006, the inspectors reviewed the licensee's design changes associated with the Unit 1 RVCH and CRDM housing replacement efforts. Documents reviewed for theUnit 2 RVCH and CRDM housing replacement [refer to Inspection Report05000282/2005004; 05000306/2005004 (ML052020420)] that were also applicable to the Unit 1 RVCH and CRDM housing replacements were not reviewed as part of thisinspection. The inspectors reviewed certified design specifications, certified design reports, ASMECode reconciliation reports, fabrication deviation notices, non-conformance reports, anddesign calculations to confirm that the replacement RVCH and CRDM housings were incompliance with the requirements of ASME Boiler and Pressure Vessel Code,Section III,Subsection NB (1998 Edition including addenda through 2000 Addendum). The inspectors confirmed that the design specifications and design reports were certified by registered professional engineers competent in ASME Code requirements. The inspectors confirmed that adequate documentation existed to demonstrate the certifyingregistered professional engineers were qualified in accordance with the requirements of the ASME Code Section III (Appendix XXIII of Section III Appendices). The inspectorsalso confirmed that the replacement RVCH and CRDM housings were provided asCode NPT stamped components.The records reviewed by the inspectors are identified in the Attachment to this report.
b. Findings
No findings of significance were identified.
.4 Head Assembly Upgrade Package (HAUP) (71007)During the Unit 1 Spring 2006 refueling outage, the licensee elected to install a reactorHAUP that integrated the design of various plant components and structures into thereactor head assembly.
This integration involved the re-use of some plant components and the complete replacement of others including:
48*CRDM cooling internal ducts;*new integral reactor vessel missile shield;
- reactor vessel head lift rig;
- CRDM/rod position indication cable drawbri dge;*handrail modifications and new ladders;
- new integral radiation shielding; and
- reactor vessel head insulation.
a. Inspection Scope
From April 24 through 28, 2006, from May 1 through 5, 2006, and from May 15through 19, 2006, the inspectors reviewed the licensee's design changes associated with the installation of the HAUP. Documents reviewed for the Unit 2 HAUP installation (refer to Inspection Report 05000282/2005004; 05000306/2005004 (ML052020420)) that were also applicable to the Unit 1 HAUP installation were not reviewed as part of this inspection. Specifically, the inspectors reviewed the design specification and a representative sample of design calculations to confirm that HAUP structures and components were designed in accordance with the requirements of the HAUP design specification and the American Institute of Steel Construction and ASME design codes.The records reviewed by the inspectorate identified in the Attachment to this report.
b. Findings
No findings of significance were identified.
.5 Closure of Unresolved Item
(Closed) URI 05000306/2005004-07: Unable to Determine Significance of HAUP DesignConcerns During the inspection of modifications related to the Unit 2 HAUP installation (refer toInspection Report 05000282/2005004; 05000306/2005004 (ML052020420)), the inspectors identified a number of HAUP calculation concerns related to design loads, design methods, numerical errors, and the basis for acceptance criteria that were utilizedin the calculations. The licensee entered these unresolved issues into their corrective action system as condition report CAP 043325. From April 24 through 28, 2006, from May 1 through 5, 2006, and from May 15through 19, 2006, the inspectors reviewed the licensee's corrective actions for the unresolved issues identified in CAP 043325 (CAP 00864144, NRC Head ReplacementQuestions, dated November 30, 2005). Where necessary, the licensee/vendor revised calculations to resolve the unresolved issues (Calculation Notes CN-RVHP-04-87 and CN-RVHP-04-90). Also, the inspectors determined that LOCA loads (NSAL-05-1, Nuclear Safety Advisory Letter: Reactor Vessel Head Assembly LOCA Loads, dated January 18, 2005) were applied to non-safety-related HAUP structures that could impact safety-related structures (i.e., calculation note CN-RVHP-05-17, Prairie Island Units 1 and 2 - Evaluation of Non-Safety-Related Components for LOCA). The HAUP structures were determined to meet all design code acceptance limits without requiring a 49modification to the HAUP structure. Therefore, no findings of significance were identifiedas a result of the original URI concerns. The inspectors further interviewed licensee staff performing owner's acceptance reviewsfor Unit 1 HAUP design calculations, reviewed a licensee root cause evaluation related to minor errors in calculations, and reviewed licensee procedures related to design calculations, design interfaces, design verification, and technical review. The inspectors also reviewed a sample of HAUP design calculations during inspection activities for the Unit 1 HAUP installation. No findings of significance were identified. (Section OA5.2)In summary, no violations were identified. This item is closed.
.6 Replacement Head Installation and Testing
a. Inspection Scope
The inspectors reviewed documents and activities associated with the head replacementand post-installation verification and testing, including:*temporary modifications;*rigging procedures, safe load path, and laydown areas;
- the controls and plans to minimize adverse impact on the operating unit andcommon systems; and*post-installation inspection, leakage testing, and equipment performance.
b. Findings
No findings of significance were identified.4OA6Meeting(s)
.1 Exit MeetingThe inspectors presented the inspection results to Mr. T. Palmisano and other membersof licensee management at the conclusion of the inspection on July 12, 2006.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
.2 Interim Exit MeetingsInterim exits were conducted for:
- Reactor vessel head replacement procedure (IP 71007) with Mr. T. Palmisano, SiteVice President, and other members of the licensee's staff on May 19, 2006. The licensee confirmed that the design documentation prepared by WEC and MHI was considered proprietary. It was agreed that all copies of proprietary documentation not returned to the licensee would be shredded.
50*Outage Access Control to Radiologically Significant Areas and ALARA Programinspection with Mr. P. Huffman, Plant Manager, and Mr. T. Palmisano, Site Vice President, on May 12, 2006; and Mr. P. Huffman, Plant Manager, on May 25, 2006.*Inservice Inspection IP 71111.08 with Mr. Steve Brown on June 9, 2006.4OA7Licensee-Identified ViolationsThe following violations of very low significance (Green) were identified by the licenseeand are violations of NRC requirements which meets the criteria of Section VI of the NRCEnforcement Manual, NUREG-1600, for being dispositioned as NCVs.Cornerstone: Mitigating Systems10 CFR 50.65(a)(4) requires that risk be assessed and managed for maintenance. Contrary to this, on May 6, 2006, risk was incorrectly calculated as Yellow followingthe unplanned unavailability of the 121 instrument air compressor concurrent withthe planned unavailability of diesel generator D2, 11 cooling water pump, safeguards4 kilovolt bus 16, and the 12 AFW pump. Consequently, compensatory actions and contingency plans were not identified for an Orange risk condition as required by the licensee's procedure H24.1, "Assessment and Management of Risk Associated with Maintenance Activities." This was identified in the licensee's corrective action program as CAP 01028790. This finding is of very low safety significance because the air compressor was repaired and returned to service within the risk informed allowed outage time. 10 CFR 50, Appendix B, Criterion III, Design Control, requires that measures beestablished to assure that deviations from quality standards are controlled. Contrary to this, on May 11, 2006, it was identified that non-safety-related parts were used in safety-related 4 kilovolt switchgear to fasten the shutter guide to the fixed shroud. This was part of an ongoing maintenance practice that replaced broken nylon bolts with supplies from non-safety-related shop supplies. This was identified in the licensee's corrective action program as CAP 01029449. This finding is of very low safety significance because there were no failures that resulted in safety-related equipment becoming inoperable.Cornerstone: Occupational Radiation SafetyThe licensee's TS 5.7.1 a. states that for High Radiation Areas accessible to personnel,each entryway to such an area shall be barricaded. Contrary to this, on May 1, 2006, the licensee identified that a radiation worker removed a High Radiation Area boundary swing gate (barricade) at the access to the top of the Unit 1 pressurizer vault to position one leg of the stand for the Pressurizer Missile Shield without receiving approval for removing the barricade from the Radiation Protection staff. Upon identifying the noncompliance, the Radiation Protection staff walked-down the pressurizer vault to ensure all personnel were on a High Radiation Area Radiation Work Permit, validated all Locked High Radiation and High Radiation Area postings in Unit 1 containment and auxiliary building, and started a Human Performance Event Investigation(CAP 01027384). The finding was of very low safety significance because it did not 51result in an unmonitored or unplanned personnel exposures as a result of the barrierloss.The licensee's TS 5.7.1 a. states that for High Radiation Areas accessible to personnel,each entryway to such an area shall be barricaded. Contrary to this, on May 29, 2006, Radiation Protection staff identified that a radiation worker removed a High RadiationArea boundary swing gate (barricade) at the access to 12 RHR vault and it remained inthe open position. Upon identifying the noncompliance, the Radiation Protection staffcorrected the swing gate position and repaired a guide that was improperly placed and caused the swing gate to bind allowing it to remain open. Additionally, the staff walked-down all similar High Radiation Area swing gates to verify that the gates were operatingproperly (CAP 01032792). The finding was of very low safety significance because it did not result in an unmonitored or unplanned personnel exposures as a result of the barrier loss.ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- T. Palmisano, Site Vice President
- P. Huffman, Plant Manager
- J. Anderson, Radiation Protection and Chemistry Manager
- S. Brown, Engineering Director
- W. Collins, Nuclear Oversight Supervisor
- R. Cooper, Reactor Head Replacement Project Engineer
- F. Forrest, Operations Manager
- J. Kivi, Senior Regulatory Compliance Engineer
- C. Koehler, Reactor Head Replacement Project Manager
- J. LeClair, Radiation Protection General Supervisor
- S. Northard, Nuclear Safety Assurance Manager
- F. Ortiz, Structural Engineer - Reactor Head Replacement Project
- S. Redner, Eddy Current Testing Program Manager
- C. Sprout, Structural Engineer - Reactor Head Replacement Project
- S. Thomas, Engineering Supervisor
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000282/2006003-01;NCVUpdated Safety Analysis Report Change That Removedthe Reactor Vessel Head Lift Elevation Limit and
Reference to the Associated Reactor Vessel Head Load
Drop Calculation05000282/2006003-02;05000306/2006003-02NCVNRC Identified Loss of High Radiation Area Barricade atUnit 1 Pressurizer Missile Shield05000282/2006003-03;05000306/2006003-03NCVAlara Planning Does Not Identify and Prepare forPotential Airborne Conditions When Opening the Steam
Generator Manways05000282/2006003-04;05000306/2006003-04NCVProcedure For ODCM Compliance Does Not IncludeContainment Effluent Through Equipment Hatch
- 05000282/2006003-05;05000306/2006003-05NCVFailure to Follow Procedures for External Flooding
2
Closed
- 05000306/FIN-2005004-07URIUnable to Determine Significance of HAUP DesignConcerns
- 05000306/LER-2006-001-00LERUnit 2 Shutdown Required by TSs Due to InoperableEmergency Diesel Generator05000282/2006003-01;NCVUpdated Safety Analysis Report Change That Removedthe Reactor Vessel Head Lift Elevation Limit and
- Reference to the Associated Reactor Vessel Head Load
- Drop Calculation05000282/2006003-02;
- 05000306/FIN-2006003-02NCVNRC Identified Loss of High Radiation Area Barricade atUnit 1 Pressurizer Missile Shield05000282/2006003-03;
- 05000306/FIN-2006003-03NCVAlara Planning Does Not Identify and Prepare forPotential Airborne Conditions When Opening the Steam
- Generator Manways05000282/2006003-04;
- 05000306/FIN-2006003-04NCVProcedure For ODCM Compliance Does Not IncludeContainment Effluent Through Equipment Hatch
- 05000306/FIN-2006003-05NCVFailure to Follow Procedures for External FloodingDiscussedNone.
- 3
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection.
- Inclusion on this list doesnot imply that the NRC inspectors reviewed the documents in their entirety but rather that selected sections of portions of the documents were evaluated as part of the overall inspection effort.
- Inclusion of a document on this list does not imply NRC acceptance of the document orany part of it, unless this is stated in the body of the inspection report.1R01Adverse WeatherTornado and High WindsSP 1039; Tornado Site Hazard Inspection; Revision 11CAP
- 01027731; Tornado Hazard Found in Cooling Tower Equipment House Area
- CAP 01027770; Security Equipment Meets Tornado Hazard Criteria per
- SP 1039
Design Basis Document
- DBD Topical 05; Hazards; Revision 2
- NSPLMI-96001; Revision 1Hot Weather PreparationsPeriodic Test Procedure
- TP 1636; Summer Plant Operation; Revision 20Integrated Checklist 1C37.10-1; D1/D2 Diesel Generator Room Cooling; Revision 5Integrated Checklist 2C37.10-1; D5/D6 Diesel Generator Building HVAC; Revision 4
- Operating Procedure C34; Station Air System; Revision 32
- CAP 01035016;
- MD-32427 Did Not Close During TP 2296B
- CAP 01035844;
- NRC Found 2 Temperature Switches On D1/D2 Not in Checklist Position1R02Evaluation of Changes, Tests, or ExperimentsDesign Change 03RV05 Part 1; Replace Unit 1 and 2 Reactor Vessel Heads and AssociatedComponents; Revision 1
- Design Change 03RV05 Part 2; Reactor Vessel Head Assembly Upgrade Package; Revision 1
- CFR 50.59 Evaluation 1052; Heavy Loads Licensing Bases; Revision 0
- CFR 50.59 Evaluation 1052; Heavy Loads Licensing Bases; Revision 1
- CFR 50.59 Screening 2123; Design Change 03RV05 Part 1, Documents Related to RCGVS
and RVLIS Pipe and Supports; Revision 2
- CFR 50.59 Screening 2125; Design Change 03RV05 Part 2, HAUP Documents Related to the Reactor Vessel CRDM Seismic Platform, Seismic Spacer Plate, Adjustment Plate Assembly, Cable Supports; Revision 1
- CFR 50.59 Screening 2127; Design Change 03RV05 Part 2, HAUP Documents Related to
- CRDM Cooling:
- Coils, Fans, Pipe/Pipe Supports and Instrumentation and Control; Revision 310
- CFR 50.59 Screening 2149; Replace Unit 1 and Unit 2 Reactor Vessel Head Internal Insulation; Revision 0
- CFR 50.59 Screening 2395; Design Change 03RV05 Part 1, Abandon Upper Range RVLIS
- Indication; Revision 0
- CFR 50.59 Screening 2628; Design Change 03RV05 Part 2, Unit 1 and Unit 2 Evaluation of Non-Safety-Related Components for LOCA; Revision 0
- 41R04Equipment AlignmentD2 Diesel GeneratorIntegrated Checklist C1.1.20.7-1; D2 Diesel Generator Valve Status; Revision 20Integrated Checklist C1.1.20.7-2; D2 Diesel Generator Auxiliaries and Local Panels andSwitches; Revision 9
- Integrated Checklist C1.1.20.7-3; D2 Diesel Generator Main Control Room Switch and IndicatingLight Status; Revision 15
- Integrated Checklist C1.1.20.7-4; D2 Diesel Generator Circuit Breakers and Panel Switches;Revision 1212 Motor-Driven AFW PumpSystem Prestart Checklist C28-15; 12 Motor-Driven AFW Pump; Revision 4
- D6 Diesel GeneratorIntegrated Checklist C1.1.20.7-13; D6 Diesel Generator Valve Status; Revision 14Integrated Checklist C1.1.20.7-14; D6 Diesel Generator Auxiliaries and Local Panels andSwitches; Revision 12
- Integrated Checklist C1.1.20.7-15; D6 Diesel Generator Main Control Room Switch andIndicating Light Status; Revision 6
- Integrated Checklist C1.1.20.7-16; D6 Diesel Generator Circuit Breakers and Panel Switches;Revision 81R05Fire ProtectionPlant Safety Procedure F5, Appendix A, Revision 15; Fire Strategies for Fire Areas 1, 18, 20, 68, 102, 106, 114, 118, and 122
- Plant Safety Procedure F5, Appendix F, Revision 19; Fire Hazard Analysis for Fire Areas 1, 18,
- 20, 68, 102, 106, 114, 118, and 122
- CAP 01028593; Fire Protection
- SP 1183A Did Not Contain Appropriate Information1R06Flood Protection Measures (Internal)Administrative Work Instruction 5AWI 8.9.0; Internal Flooding Drainage Control; Revision 2Procedure H36; Plant Flooding; Revision 0
- CAP 01011939; Yellow Slippery When Wet Sign Found in Plant Screenhouse
- CAP 01033787; High Radiation Area May Be a Critical Drainage Path1R07Heat Sink PerformanceMaintenance Procedure D104.1; Zebra Mussel Control Treatment:
- Circulating Water System;Revision 2
- 50.59 Evaluation 1025; Zebra Mussel Treatment; Circulating Water System; April 11, 2006
- Operator Logs for April 19 - 21, 2006
- 51R08Inservice Inspection ActivitiesDocuments Associated with ASME Code Nondestructive Examinations (NDEs) ObservedSection Work Instruction (SWI)
- NDE-UT-16A; Ultrasonic Examination of Austenitic Piping Weldsto Appendix VIII; dated March
- 2006SWI
- NDE-VT-2.0; Visual Examination of Components & Their Supports; dated March 2006
- SWI
- NDE-FE-1; Inservice Inspection Flaws Evaluation And Disposition; dated March 2006
- SWI
- NDE-ET-5; Site Specific Performance Demonstration; dated March 2006
- CAP 01027487; 5 ISI Indications Not Written Into CAP Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; dated May 2, 2006Documents Associated with Disposition of Relevant IndicationsReport 2004P034; Liquid Penetrant Examination; dated October 22, 2004Report 2004P034; ISI Flaw Sizing Worksheet; dated October 22, 2004
- Report 2004P034; ISI Flaw Disposition Worksheet; dated October 24, 2004Corrective Action Program Documents for Evaluations for Boric Acid LeakageSP 1405; Unit 1 Mid-Cycle and Refueling Outage Boric Acid Corrosion Examination InsideContainment; Revision 1
- CAP 00847672; Evaluate or repair boric acid leak affecting
- RH-10-2
- CAP 01026980; Boric Acid Leak from
- SI-199-2 Packing Found
- CAP 01026983;
- SI-15-1 Packing Leak Identified
- CAP 01027012; Unit 1
- MV-32230 has Boric Acid Residue from Packing Leak
- CAP 01027041; Relevant Indication on
- RC-1-4, Loop B to 11 Reactor Coolant Drain Tank
- CAP 01027048; Relevant Boric Acid Leak on
- MV-32068
- CAP 01027052; Potentially Relevant Indication on RC-1-8
- CAP 01027054; Relevant Boric Acid Leak on MV-32070
- CAP 01027091; Boric Acid Leak on Flow Transmitter 1FT-628
- CAP 01027103; Boric Acid Leak on CV-31447
- CAP 01027175; Relevant Indication on
- MV-32065Documents Associated with Steam Generator ExaminationsSWI
- NDE-ET-5; Site Specific Performance Demonstration; dated April 21, 20061H25.1; Unit 1 Assessment of Steam Generator Tube Degradation Mechanisms; dated April 21, 2006Corrective Action Program DocumentsCAP
- CAP 01027266; ISI Exam Revealed Insufficient Thread Engagement; dated May 1, 20061R11Licensed Operator Requalification ProgramSimulator Evaluation Guide P9160S-001, ATT SQ54; Revision 0Administrative Work Instruction 5AWI 3.15.0; Plant Operation; Revision 17
- 61R12Maintenance EffectivenessMaintenance Rule Status Chart; June 27, 2006CAP
- 01012627; 124 Station Air Compressor Jacket Cooling Outlet Temperature High
- CAP 01013896;
- PM 3505-1-121, 121 Instrument Air Compressor 1000 Hour Inspection
- CAP 01025330; System Review Found 122 Compressor Unavailability Remains Greater Than75 Percent
- CAP 01035713; 122 Air Compressor Making Unusual Noises Upon Return to Service1R13Maintenance Risk Assessments and Emergent Work ControlProcedure H24.1; Assessment and Management of Risk Associated with Maintenance
- Activities; Revision 9
- Unit 2 Configuration Risk Assessment for April 5, 2006
- Operator Logs for April 5, 2006
- Unit 2 Configuration Risk Assessment for April 13, 2006
- Operator Logs for April 13, 2006
- CAP 01024351; NRC Resident Questions on PRA for Partial Trip ConditionUnit 1 Configuration Risk Assessment for April 24, 2006
- Operator Logs for April 24, 2006
- Unit 1 Configuration Risk Assessment for April 28, 2006
- Operator Logs for April 28, 2006
- Unit 2 Configuration Risk Assessment for May 5, 2006
- Operator Logs for May 5, 2006
- Electrical Maintenance Procedure PE TA121&122; Transfer 480Volt Safeguards Buses 121 &
- 2 to Alternate Source; Revision 1
- Unit 2 Configuration Risk Assessment for May 8, 2006
- Operator Logs for May 8, 2006
- CAP 01003450; Emergent Work Affecting Scheduled Work Unit 1 Configuration Risk Assessment for June 15, 2006
- Operator Logs for June 15, 2006
- Unit 1 Configuration Risk Assessment for June 28, 2006
- Operator Logs for June 28, 20061R14Nonroutine EvolutionsOperator Response to Unit 1 Manual Reactor TripOperator Logs for April 14, 2006CAP
- 01024213; Unit 1 Reactor Tripped After Losing 50% FW Flow from 100%Operator Response to a Unit 2 Overpower TransientOperating Logs from May 16 and 17, 2006CAP
- 01030453;Possible Power Excursion Above Licensed Level of 1650 MWth [Mega-Watts thermal]
- 71R15Operability EvaluationsCAP 01011542CAP
- 01011542; Loose Material Found in Unit 1 Residual Heat Removal Pump Pit Flood Barrier(prompt operability assessment)CAP
- 01011542-02; Loose Material Found in Unit 1 Residual Heat Removal Pump Pit Flood Barrier (historical operability assessment)VC-24-1CAP
- 01032647; Relief Valve Not Tested During 1R24OPR
- 000531;
- VC-24-1 Not Tested Within American Society Mechanical Engineers Required Frequency; Revision 1
- CAP 01032647 Attachment; Justification for Deferral of
- VC-24-1 Testing
- VC-24-1 Radiological Analysis Risk Evaluation V.SPA.06.007;
- VC-24-1 Relief Valve Missed IST TestFeedwater Pipe Support 1-FWH-35CAP
- 01033009; Discrepancies in FW Support 1-FWH-35OPR
- 01033009; Discrepancies in FW Support 1-FWH-35; Revision 01
- Letter from Automated Engineering Services Corp. to Prairie Island Nuclear Generating Plant;
- Evaluation of Unit 1
- Letter from Automated Engineering Services Corp. to Prairie Island Nuclear Generating Plant;
- Evaluation of Unit 1
- FWH-35 and Force Restraints #10 and As-Found Condition; May 30,
- 200611 Turbine-Driven AFW PumpCAP
- 01034749; 11 Turbine-Driven AFW Pump Turbine Outboard Bearing TemperatureCAP
- 01035796; NRC Question Regarding 11 Turbine-Driven AFW Pump Bearing TemperatureCAP
- 01037612; Insulation Appeared to be Missing from 11 Turbine-Driven AFW Pump During 1R241R19Post-Maintenance TestingDiesel Generator D2 Cylinder Liner ReplacementWO 99200; D2 Emergency Diesel Generator Run-InSP 1305; D2 Diesel Generator Monthly Slow Start; Revision 35
- SP 1307; D2 Diesel Generator 6-Month Fast Start Test; Revision 29
- SP 1335; D2 Diesel Generator 18-Month 24-Hour Load Test; Revision 8
- CAP 01031446; D2 Coolant System Cloudy After Cylinder ReplacementCV-31998 Back Up Air Supply Inlet Check Valve ReplacementWO
- 0509256; Replace Air Supply to Accumulator Check ValvesWO
- 100114-03; Replace Air Regulator to Control Valve
- CAP 01032809; 11 Turbine-Driven AFW Pump Steam Admission Valve Accumulator Check Valve Test
- 8Repacking of 11 Turbine-Driven AFW Pump Valves
- AF-13-3 and
- CV 31998WO 88083; Replace Packing in
- AF-13-3WO 88959; Replace Packing in CV- 31998
- CV-31235SP 1089A, Train A RHR Pump and Suction Valve from Refueling Water Storage Tank QuarterlyTest; Revision 101N36 Cable ReplacementWO
- 286940; Replace 1N36 DetectorMaintenance Procedure D35.1; Nuclear Indication System Source and Intermediate Range Detector Replacement
- SP 1318.2; Nuclear Indication System Intermediate Range Calibration; Revision 12
- Temporary Modification 8315; Replacement of the Damaged 1N36 Wires with Existing Spare Wires
- CAP 01009682; Hot Leg Sample Valve Not Assembled Correctly11 Turbine-Driven AFW Pump Turbine Bearing ReplacementSP 1103; 11 Turbine-Driven AFW Pump Once Every Refueling Shutdown Flow Test;Revision 42
- CAP 01034749; 11 Turbine-Driven AFW Pump Turbine Outboard Bearing Temperature1R20Refueling and Other Outage ActivitiesOperating Procedure 1C1.2; Unit 1 Startup Procedure; Revision 37Operating Procedure 1C1.3; Unit 1 Shutdown; Revision 57Operating Procedure 1C4.1; RCS Inventory Control - Pre-Refueling' Revision 18Alarm Response Procedure 47006-0507; 1G Generator Potential Transformer Volt Balance;Revision 19
- Special Operations Procedure 1D2; RCS Reduced Inventory Operation; Revision 19CAP
- 01027489; Issues Associated With C4.1 Draindown of Unit 1 RCS
- Special Operations Procedure D5.2; Reactor Refueling Operations; Revision 45
- CAP 01031485; Unclear Procedure Guidance for Unit 1 D581R22Surveillance Testing
- SP 2093SP 2093; D5 Diesel Generator Monthly; Revision 77CAP
- 01025789; Low Lubricating Oil Level on D5 Engine 1 and 2 During Slow Start Run
- SP 1405SP 1405; Unit 1 Mid-Cycle and Refueling Outage Boric Acid Corrosion Examinations InsideContainment; Revision 1
- SP 1407; Leakage Examination of Canopy Seals, Mechanical Joints, and Other Pressure Retaining Components on the Reactor Head; Revision 0
- 9Relevant Boric Acid CAPs including:
- 01026969,
- 01027041,01027046,
- 01027048,
- 01027052,
- 01027054,
- 01027091,
- 01027103,and 01027175
- SP 1088ASP 1088A; Train A Safety Injection Quarterly Test:
- Revision 10
- SP1092SP1092B; Safety Injection Check Valve Test (Head Off) Part B:
- Refueling Water Storage Tankto RHR Flow Path Verification; Revision 14
- SP1092C; SI Check Valve Test (Head Off) Part C:
- Accumulator Flow Path Verification;
- Revision 10
- SP1072.45SP 1072.45; Local Leakage Rate Test of Penetration 45 (Reactor Water Makeup); Revision 17CAP
- 01027222; Unit 1 RMU to Demin Crosstie RC-4-12
- SP 1106CSP 1106C; 121 Cooling Water Pump Quarterly Test; Revision 28CAP
- 01031679; 121 Motor-Driven Cooling Water Pump Performance in the Action Range
- SP1083SP 1083, Unit 1 Integrated SI Test With a Simulated Loss of Offsite Power; Revision 31CAP
- 01032656; BOP Power Failure Annunciator with NSSS Trouble Alarm
- SP 1750SP 1750; Post-Outage Containment Closeout Inspection; Revision 30CAP
- 01033737; Scaffold Knuckle Found In Containment
- SP 1070SP 1070; Reactor Coolant System Integrity Test; Revision 37
- 1R23Temporary Modifications4T-175Maintenance Procedure 1D108; Pressurizer PORV Air Accumulator Supplementation;Revision 1
- ENG-ME-592; Determine the Minimum Amount of Air Pressure to Fully Stroke Pressurizer
- PORV; Revision 0
- ENG-ME-584; Sizing of Supplemental Air for Pressurizer PORV Air Accumulators; Revision 0
- NSP-04-189; Data on Pressurizer PORV Cycling During Cold Overpressure Mitigation System Transients - New Analysis
- CAP 01027161; Air Leak on Union Between
- CV-31231 and Solenoid Valve
- 1EP6Drill EvaluationSimulator Evaluation Guide P9160S-001, ATT SQ54; Revision 0
==2OS1 Access Control to Radiologically Significant AreasCAP
- 1027384; Removal of High Radiation Boundary by Unauthorized Personnel; May 1, 2006CAP
- 1028608; Worker Removed Radiation Boundary to By-pass Turnstile at Access; May 8,==
- 2006
- CAP 1029288; High Radiation Area Swing Gate Turned Due to Loose Base; May 10, 2006
- CAP 1031277; Potential For An Individual to Be Locked Inside a High Radiation Area;
- May 19, 2006
- CAP 1032258; Radiation Protection and Chemistry Group Threshold for Corrective Action Program Initiation is Too High; May 25, 2006
- CAP 1032792; 12 Residual Heat Removal High Radiation Area Swing Gate Did Not Close;
- May 29, 2006
- CAP 1033802; Adverse Trend High Radiation Area Control; June 4, 2006
- CAP 1028608; Violation of Radiation Boundary; May 8, 2006
- CAP 1032220; Locked High Radiation Area Barrier to Spent Resin Tank Area Found Unsecured;
- May 25, 2006
- CAP 1028824; Temporary Radiation Controlled Area for Reactor Head Planned Too Large, May 9, 2006
- PINGP 258; Radiation Protection Survey Record, Spent Resin Tank Room; May 5, 2006
==2OS2 As Low As Is Reasonably Achievable Planning and Controls (ALARA)ACE
- 1027653; Elevated Iodine-131 Level in Unit 1 Containment During 1R24; June 9, 2006CAP
- 1027645; High Airborne Unit 1 Containment Due to Steam Generator Venting; May 3, 2006CAP
- 1028594; Control of Receipt Area Roll Up Doors Poor; May 7, 2006==
- CAP 1029400; Auxiliary Building and Spent Fuel Pool Vent Releases Higher Than Expected;May 10, 2006
- CAP 1029875; Radiation Protection Chemistry Does Not Have Plan for Challenges to Offsite Dose Calculation Limits; May 13, 2006
- CAP 1031483; Incorrect Air Sample Data; May 22, 2006
- CAP 1032424; Head Vent to Atmosphere Lacking High Efficiency Particulate Air Ventilation;
- May 29, 2006
- CAP 1035274; Internal Dose from Iodine-131 Excursion in Unit 1 Containment; June 13, 2006
- CAP 1029247; Work on
- SI-9-2 Stopped Due to Exceeding Work Order Dose Estimate;
- May 10, 2006
- CAP 1029271; Passport Dose Report is Inaccurate; May 10, 2006
- 1D27.39; Initial Steam Generator Outage Work Activities; Revision 0
- QF-1203; Radiological Work Assessment Form; Revision 2
- QF-1204; Radiological Work Assessment Form Contamination Control; Revision 0
- QF-1205; Radiological Work Assessment Form Exposure Control; Revision 0
- QF-1206; Radiological Work Assessment Form Internal Exposure Control; Revision 1
- QF-1207; Radiological Planning Checklist; Revision 0
- QF-1209; Radiological Re-Job Briefing Form; Revision 0
- RPIP 1126; Contamination Monitor Alarm Response and Personnel Decontamination;
- Revision 21
- 11RWP 563; Primary Manway Insert and Remove, Revision 0RWP 609; Eddy Current Testing of Steam Generator Tubes, Revision 0
- WO 95654; 11 and 12 Steam Generator Primary Side Manway Insert Remove and Install
- WO 95655; 95656; 11 and 12 Primary Side Eddy Current Testing of Steam Generator TubesWO 95727; Disassemble Reactor In-Accordance-With D3; May 2, 2006
- WO 99051; Sump C When Hosted High Radiation Area; February 27, 2006
- Minutes of Emergent Site ALARA Committee Meeting; May 10, 2006
2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems
- CAP 1027608; Inadequate Effluent Release Controls at the Unit 1 Equipment Hatch;May 2, 2006
- CAP 1028580; Lack of Communication for Effluent Release; May 7, 2006
- CAP 1032260; Effluent Control - Process and Procedures; May 25, 2006
- CAP 42127; Control of Air Flow in Containment/Annulus Was Not Maintained Negative;
- May 4, 2005
- CE 007761; Corrective Actions Specified in
- CAP 038784 Were Not Effectively Implemented for
- 2R-23; May 5, 2005
- 1C19.2; Containment System Ventilation - Unit 1; Revision 15
- C19.10; Containment Airlock Door Control at Shutdown; Revision 21C19.9; Containment Boundary Control During Mode 5, Cold Shutdown and Mode 6, Refueling;Revision 12
- 1D61.4; Equipment Hatch Removal and Installation Procedure - Unit 1; Revision 5
- RPIP 3001; Plant Shutdown Guidelines; Revision 10
- RPIP 4509; Containment Release Instructions; Revision 11
- RPIP 4511; Airborne Continuous Release Report; Revision 8
- TS 5.5 Radioactive Effluent Controls Program
- 2005 Annual Radioactive Effluent Report and Offsite Dose Calculation Manual; May 9, 2006
- 4OA1Performance Indicator VerificationPrairie Island Nuclear Generating Plant Form 1318C; Performance Indicators-Safety SystemFunctional Failures; Revision 0 for 2
nd Quarter 2004, 3
rd Quarter 2004, 4
th Quarter 2004, 1
stQuarter 2005, 2
nd Quarter 2005, 3
rd Quarter 2005, 4
th Quarter 2005, and 1
st Quarter 2006Prairie Island Nuclear Generating Plant Form 1318A; Performance Indicators-Initiating Events;
- Revision 0 for 2
nd Quarter 2004, 3
rd Quarter 2004, 4
th Quarter 2004, 1
st Quarter 2005, 2
nd Quarter 2005, 3 rd Quarter 2005, 4
th Quarter 2005, and 1
st Quarter 2006Plant Procedure H33; Performance Indicator Reporting; Revision 5
- Plant Procedure H33.1; Performance Indicator Reporting Instructions; Revision 5
- Plant Procedure H33.3; Safety System Functional Failure Performance Indicator Reporting Instructions; Revision 1
- Unit 1 and 2 Operating Logs for April 1, 2004 through March 31, 2006
- CAP 01031984; Evaluate D6 High Crankcase Pressure for MSPI [Mitigating System Performance Index] Failure
- CAP 01024901; Data Error - Did Not Report 11.9 Hours of Unavailability for D1 Diesel Generator 4OA2Identification and Resolution of ProblemsT-Track
- 2CAP
- 01026977;
- CV-31232 Pressurizer PORV Had Dual Indication During
- SP 1182ACondition Evaluation 00666; CV31231 Unit 1 Pressurizer PORV Appears to be Leaking Engineering Work Request
- 009993; Issue an Equipment Change to Replace Pressurizer PORV
- Trim with a Trim Made of 400 Series Stainless Steel Engineering Work Request
- 009995; Issue an Equipment Change to Install the Manufacturers Horizontal Mounting Kit on the Pressurizer PORVs Apparent Cause Evaluation 1026977-01:
4OA3 Event FollowupEvent Followup of the Inoperability of Both Pressurizer
- PORVs During Unit 1 Shutdown Prairie Island TSs, Section 3.4.11; Pressurizer PORVs; Amendment 167Prairie Island TSs, Section 3.4.13; Low Temperature-Overpressure Protection; Amendment 158USAR, Section 4; Mass and Heat Input Events; Revision 27
- Temporary Modification 4T175; Pressurizer PORV air Accumulator Supplementation
- SP 1181; Overpressure Protection System Setpoint Verification; Revision 22
- SP 1182A; Overpressure Protection System Functional Test; Revision 14
- CAP 01026977;
- CAP 01027161; Air Leak on Union Between
- CV-31231 and Solenoid Valve4OA5Other ActivitiesResolution of
- URI 05000282/2006002-01; 05000306/2006002-01Abnormal Operating Procedure
- AB-4; Flood; Revision 28SP 1293; Inspection of Flood Control Measure; Revision 13; performed February 7 through 17,
- 2006
- Fleet Procedure
- FP-SC-PE-05; Shelf Life Program; Revision 0
- CAP 01021256; Deck-O-Seal Sealant Found with Questionable Shelf Life
- CAP 01022931; Re-Order of Sealant Not Completed
- CAP 01025266; Incorrect Sealant Placed In Stock Condition Evaluation
- 01021256-04; Flood Panels and Doors - Deck-O-Seal IssuePartial Completion of Temporary Instruction 2515/166 on Unit 1Design Description Form for EC Number 0378; Containment Sump B Screen Replacement;Revision 0
- Drawing
- SFS-PI-PA-7165; Strainer Cover; Revision 2
- Drawing
- SFS-PI-PA-7164; Strainer Piping A5 and B5; Revision 4
- Drawing
- SFS-PI-PA-7163; Strainer Piping A4 and B4; Revision 4
- Drawing
- SFS-PI-PA-7162; Strainer Piping A3 and B3; Revision 3
- Drawing
- SFS-PI-PA-7161; Strainer Piping A2 and B2; Revision 4
- Drawing
- SFS-PI-PA-7160; Strainer Piping A1 and B1; Revision 1
- Drawing
- SFS-PI-PA-7150; Mounting Track Assembly; Revision 1
- Drawing
- SFS-PI-PA-7105; Strainer sleeves/Cover/Supports/Pins; Revision 3
- Drawing
- SFS-PI-PA-7104; Strainer Sections and Details; Revision 1
- Drawing
- SFS-PI-PA-7101; Strainer Master Core Tube Layouts; Revision 5
- Drawing
- SFS-PI-PA-7100; Strainer Module Assembly:
- Revision 4
- Drawing
- SFS-PI-GA-04; Strainer Cover and Pipe Layout; Revision 2
- Drawing
- SFS-PI-GA-03; B Strainer; Revision 2
- 13Drawing
- SFS-PI-GA-02; A Strainer; Revision 2Drawing
- SFS-PI-GA-01; General Notes; Revision 2
- Drawing
- SFS-PI-GA-00; Strainer Recirc Sump System; Revision 1
- Drawing
- SK-04RH04-01; Containment Standpipe Support; Revision 0
- Drawing
- SK-04RH04-02; Containment Standpipe Support; Revision 0
- Drawing
- SK-04RH04-03; Cable Tray Support System Demolition; Revision 0
- Drawing
- SK-04RH04-04; Cable Tray Support System Modification; Revision 0
- Drawing
- SK-04RH04-05; Cable Tray Support System Modification; Revision 0
- Drawing
- SK-04RH04-06; Cable Tray Support System Modification; Revision 0
- Drawing
- SK-04RH04-07; Cable Tray Support System Modification; Revision 0Replacement RVCH (71007)Design Change 03RV05 Part 1; Replace Unit 1 and 2 Reactor Vessel Heads and Associated Components; Revision 1
- Design Specification 418A07; Replacement RVCH; Revision 2
- Design Specification 418A08; Control Rod Drive Mechanism; Revision 2
- Document L5-01DV505; Prairie Island Unit 1, Replacement RVCH, Justification for Nonconformance Reports of Replacement RVCH; Revision 2
- Document L5-01DV510; Prairie Island Unit 1, Replacement RVCH, Design Report; Revision 2
- WCAP-16427-P, Revision 0, Addendum 2; Prairie Island Unit 1, Replacement RVCH - Design Report; dated January 2006
- WCAP-16427-P, Revision 0, Addendum 1; Prairie Island Unit 1, Replacement RVCH - Design Report; dated November 2005
- WCAP-16427-P; Prairie Island Unit 1, Replacement RVCH - Design Report; Revision 0
- Calculation Note
- CN-RCDA-04-47; Prairie Island Units 1 and 2, Replacement RVCH - AnalysisProcedure; Revision 2
- Calculation Note
- CN-RCDA-04-75; Prairie Island Units 1 and 2, Replacement Head Project -Closure Head Flange ASME Leakage Evaluation; Revision 3
- Calculation Note
- CN-RCDA-05-58; Prairie Island Units 1 and 2, Replacement RVCH - FractureEvaluation; Revision 0
- Calculation Note
- CN-RCDA-05-59; Prairie Island Units 1 and 2, Replacement RVCH - ClosureHead Lifting Lug Stress Analysis; Revision 1
- Calculation Note
- CN-RCDA-05-60; Prairie Island Units 1 and 2, Replacement RVCH - ASMESection XI Code Reconciliation; Revision 0Calculation Note
- CN-RCUFW-04-7; Point Beach Unit 2, Replacement Head Project - ClosureHead Flange ASME Code and Leakage Evaluation; Revision 1
- Document
- PI-KCS-05-0001; Prairie Island Units 1 and 2, Control Rod Drive Mechanism, Design Report
- PI-KCS-04-0001, Revision 2, Addendum; Revision 2
- Document
- PI-KCS-05-0003; Prairie Island Unit 1, Control Rod Drive Mechanism, Justification for Nonconformance Reports for Replacement Control Rod Drive Mechanism; Revision 1
- Critical Design Characteristics 1439-
- CDC-001; RRVCH Replacement Internal dome Insulation;dated May 14, 2005
- Critical Design Characteristics 1439-
- CDC-002; Modify Support Angles in Reactor VesselExternal Insulation; dated May 14, 2005
- Deviation Notice 62559; Prairie island Unit 1, Shroud Support Flange, Bolt Hole Diameters Out-
of-Tolerance; December 13, 2005
- Equivalent Engineering Change 1439; Replace Unit 1 and Unit 2 Reactor Vessel Head Internal Insulation; Revision 0
- 14MHI Drawing L5-01DV109; Replacement RVCH, Closure Head and Adapter Housing Assembly;Revision 2
- Revision 1
- Revision 2
- Revision 2
- UGC-CMTR-04-19; Certified Material Test Report, Unit 1 Replacement RVCH; dated December 1, 2004
- Reactor Vessel Closure Head and Control Rod Drive Mechanisms; ASME NPT Component Certification; Mitsubishi Heavy Industries, Ltd; dated January 11, 2006Head Assembly Upgrade Package (71007)CAP
- 01003629; Generate Operating Experience Evaluation Report for
- NRC Regulatory IssueSummary 2005-25, "Control of Heavy Loads"; dated November 14, 2005
- Design Change 03RV05 Part 2; Reactor Vessel Head Assembly Upgrade Package; Revision 1
- Design Specification 418A34; Head Assembly Upgrade Package; Revision 6
- Calculation 2005-05621; Analysis of Postulated Reactor Head Drop onto the Reactor Vessel Flange; Revision 3
- Calculation
- ENG-CS-300; Support for CRDM Fan Disconnect Switch; Revision 1Calculation
- ENG-CS-361; Evaluation of the Acceptability of the Reactor Vessel Head Lift Rig,Reactor Vessel Internals Lift Rig, Load Cell and Linkage to the Requirements of
- NUREG-0612for Prairie Island Units 1 and 2; Revision 1
- Calculation Note
- CN-RVHP-04-61; Prairie Island HAUP, Head Lift Rig Evaluation; Revision 4
- Calculation Note
- CN-RVHP-04-74; Prairie Island HAUP - Structural Analysis for DW, Thermal Expansion, Seismic and LOCA Loadings; Revision 3
- Calculation Note
- CN-RVHP-04-75; Prairie Island Units 1 and 2 - HAUP Radiation Shield and Support Ring Structural Analysis; Revision 5
- Calculation Note
- CN-RVHP-04-78; Prairie Island Reactor Vessel Model:
- Units 1 and 2;
- Revision 0
- Calculation Note
- CN-RVHP-04-89; Prairie Island HAUP, Cable Bridge No. 2 Structural Analysis;
- Revision 6
- Calculation Note
- CN-RVHP-05-17; Prairie Island Units 1 and 2 - Evaluation of Non-Safety-
- Related Components for LOCA; Revision 3
- Calculation Note
- CN-RVHP-05-43; Prairie Island HAUP Unit 1 ZX Piping Analysis; Revision 3
- Calculation Note
- CN-RVHP-05-61; Prairie Island Unit 1 HAUP - Miscellaneous Hardware Seismic Evaluation; Revision 2
- Deviation Notice 62033; Prairie island Unit 1, HAUP, Lift Leg Extension, False Cut, 1-1/2 Wide x
- 1-1/8 Long x 0.170 Deep; Revision 0
- Drawing 10017E03 Sheets 1 though 4; Prairie Island Units 1 and 2, Head Assembly Upgrade Package, North Side Cavity Bridge Assembly; Revision 2
- Drawing 10017E62 Sheets 1 though 4; Prairie Island Units 1 and 2, Head Assembly Upgrade Package, North Side Cavity Bridge Frame Subassembly; Revision 3
- Drawing
- NF-38434-2; Reactor Building Unit 1, Reactor Vessel Steel Supports; Revision K
- Drawing
- NF-38435; Reactor Building Unit 1, Reactor Vessel Supports - Plans, Sections and Details; Revision F
- Drawing
- NF-38436; Reactor Building Unit 1, Reactor Vessel Column Supports - Sections and Details; Revision F
- 15Drawing
- NF-38490-1; Reactor Building Unit 2, Reactor Vessel Column Supports:
- Plans,Sections and Details; Revision E
- Drawing
- NF-38490-2; Reactor Building Unit 2, Reactor Vessel Steel Supports; Revision C
- Drawing X-HIAW-1-384; Unit 1 - General Assembly; Revision K
- Engineering Change Notice 03RV05-10; Requested Change to Anchor Bolt Size and Retention;
- Revision 0
- Field Deviation Report
- FDR-PI1HAUP-01; Prairie Island Unit 1, CET Chiller Bridge Weld DoesNot Meet AWS D1.1 Requirements; April 5, 2006
- Maintenance Procedure D58.1.9; Unit 1 - Reactor Vessel Head Removal; Revision 11
- Maintenance Procedure D58.2.9; Unit 2 - Reactor Vessel Head Removal; Revision 10Corrective Action Requests Initiated as a Result of NRC InspectionCAP
- 01025009; Evaluate Removal of Head Lift Height Restriction from USAR; dated April 19, 2006
- CAP 01030355; Review 50.59 Evaluation 1052; Revision 0 Bases to Remove Reactor Head Lift Restriction from USAR; dated May 16, 2006
dated May 17, 2006
- URI 05000306/2005004-07CAP
- 00864144;
- NRC Head Replacement Questions; dated November 30, 2005Calculation Note
- CN-RVHP-04-87; Prairie Island HAUP, Plenum Stress Qualification; Revision 3
- Calculation Note
- CN-RVHP-04-87; Prairie Island HAUP, Plenum Stress Qualification; Revision 4
- Calculation Note
- CN-RVHP-04-90; Prairie Island Units 1 and 2 HAUP, Cooling Shroud Structural Analysis; Revision 2
- Movements; dated March 17, 2005
- CAP 043325;
- NRC Head Replacement Questions; July 5, 2005Engineering Manual 1.2.3; Development of Design Calculations; Revision 10
- Fleet Procedure
- FP-E-CAL-01; Calculations; Revision 0
- Fleet Procedure
- FP-E-MOD-07; Design Verification and Technical Review; Revision 1
- Fleet Procedure
- FP-E-MOD-11; Control of Design Interfaces; Revision 1
- Nuclear Safety Advisory Letter
- NSAL-05-1; Reactor Vessel Head Assembly LOCA Loads; dated January 18, 2005
- External Operating Experience
- 036997;
- NSAL-05-1, Reactor Vessel Head Assembly LOCA
- Loads; dated January 25, 2005
- Root Cause Evaluation 0201; Adverse Trend in Minor Errors in Calculations; Revision 0Reactor Vessel Head Replacement Installation and Testing (71007)WO
- 00097597; Modify Unit 1 Equipment Hatch Platform/Rails; September 7, 2005
- WO 00097616; Rig/Transfer RVCH and Replacement RVCH; July 26, 2005
- Maintenance Standards Implementing Procedure MSIP 6003; Control of Heavy Load; Revision 4Maintenance Procedure D58; Heavy Loads Program; Revision 31
- Maintenance Procedure D58.1.10; Unit 1 - Reactor Vessel Head Replacement; Revision 9
- CAP 01031457; Safety Issues During Head Lift; Lack of Co-worker Coaching
- 16CAP
- 01031485; Unclear Procedure Guidance for Unit 1 D58
4OA7 Licensee-Identified ViolationCAP 01028790;
- PRA Configuration Assessed IncorrectlyCAP
- 01029449; Non-Safety-Related Parts Used in Safety-Related Application
- 17
LIST OF ACRONYMS
USEDADAMSAgencywide Documents Access and Management SystemALARAAs-Low-As-Reasonably-Achievable
ASMEAmerican Society of Mechanical Engineers
BACCBoric Acid Corrosion Control
CAPCorrective Action Program/Corrective Action Program Action Request
CFRCode of Federal Regulations
CRDMControl Rod Drive MechanismDACDerived Air Concentration
DRPDivision of Reactor Projects
EPRIElectric Power Research Institute
ETEddy Current
GLGeneric Letter
HAUPHead Assembly Upgrade Package
HEPAHigh Efficiency Particulate Air
HRAHigh Radiation Area
IMCInspection Manual Chapter
IPInspection Procedure
IPEEEIndividual Plant Examination of External Events
IRInspection Report
ISIInservice Inspection
LERLicensee Event Report
LOCALoss of Coolant Accident
NCVNon-Cited Violation
NDENondestructive Examination
NEINuclear Energy Institute
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NRCU.S. Nuclear Regulatory Commission
OPROperability RecommendationPARSPublicly Available Records
PINGPPrairie Island Nuclear Generating Plant
PORVPower Operated Relief Valve
RCGVSReactor Coolant Gas Ventilation System
RHRResidual Heat Removal
RISRegulatory Issue Summary
RPIPRadiation Protection Implementing Procedure
RVCHReactor Vessel Closure Head
RVLISReactor Vessel Level Indication System
RWPRadiation Work Permit
SDPSignificance Determination Process
SGSteam Generator
SISafety Injection System
SPSurveillance Procedure
SSCStructure, System, or Component
SWISection Work Instruction
TERTechnical Evaluation Report
TSTechnical Specifications
URIUnresolved Item
USARUpdated Safety Analysis Report
WOWork Order
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