IR 05000266/2008005
Download: ML090370679
Text
February 6, 2009
EA-08-274 Mr. Larry Meyer Site Vice President FPL Energy Point Beach, LLC 6610 Nuclear Road Two Rivers, WI 54241
SUBJECT: POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT 05000266/2008005 AND 05000301/2008005
Dear Mr. Meyer:
On December 31, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Point Beach Nuclear Plant, Units 1 and 2. The enclosed report documents the inspection results, which were discussed on January 7, 2009, with you and members of your staff. The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations, and with the conditions of your license. The inspectors reviewed selected procedures and records, observed activities, and interviewed your personnel. Based on the results of this inspection, four NRC-identified and three self-revealed findings of very low safety significance were identified. All of these findings were determined to involve violations of NRC requirements. However, because of their very low safety significance and because the issues were entered into your corrective action program, the NRC is treating the issues as Non-Cited Violations (NCVs) in accordance with Section VI.A.1 of the NRC Enforcement Policy. If you contest the subject or severity of any NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, 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 of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Point Beach Nuclear Plant. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS) component of NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,/RA/ Michael A. Kunowski, Chief Branch 5 Division of Reactor Projects Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27
Enclosure:
Inspection Report 05000266/2008005; 05000301/2008005
w/Attachment:
Supplemental Information cc w/encl: M. Nazar, Senior Vice President and Chief Nuclear Officer J. Stall, Executive Vice President, Nuclear and Chief Nuclear Officer A. Khanpour, Vice President, Engineering Support Licensing Manager, Point Beach Nuclear Plant R. Hughes, Director, Licensing and Performance Improvement M. Ross, Managing Attorney A. Fernandez, Senior Attorney T. O. Jones, Vice President, Nuclear Operations, Mid-West Region P. Wells, (Acting) Vice President, Nuclear Training and Performance Improvement J. McCarthy, Vice President, Point Beach Recovery J. Bjorseth, Plant General Manager K. Duveneck, Town Chairman, Town of Two Creeks Chairperson, Public Service Commission of Wisconsin J. Kitsembel, Electric Division, Public Service Commission of Wisconsin P. Schmidt, State Liaison Officer
SUMMARY OF FINDINGS
......................................................................................................... 1
REPORT DETAILS
..................................................................................................................... 6 Summary of Plant Status.........................................................................................................
REACTOR SAFETY
..................................................................................................... 6
1R04 Equipment Alignment
....................................................................... 6
1R05 Fire Protection
................................................................................. 7
1R07 Annual Heat Sink Performance
........................................................ 8
1R08 Inservice Inspection Activities
.......................................................... 8
1R11 Licensed Operator Requalification Program
................................... 13
1R12 Maintenance Effectiveness
............................................................ 15
1R13 Maintenance Risk Assessments and Emergent Work Control
........ 15
1R15 Operability Evaluations
.................................................................. 16
1R18 Plant Modifications
......................................................................... 17
1R19 Post-Maintenance Testing
............................................................. 17
1R20 Outage Activities
............................................................................ 18
1R22 Surveillance Testing
....................................................................... 26
1EP4 Emergency Action Level and Emergency Plan Changes
RADIATION SAFETY
................................................................................................. 28 2OS1 Access Control to Radiologically Significant Areas (71121.01) ........................ 28 2OS2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning And Controls (71121.02) ....................................................................................................... 31 2PS1 Radioactive Gaseous And Liquid Effluent Treatment And Monitoring Systems (71122.01)
OTHER ACTIVITIES
.................................................................................................. 38
4OA1 Performance Indicator (PI) Verification
............................................... 38
4OA2 Problem Identification and Resolution
................................................. 41
4OA3 Follow-up of Events and Notices of Enforcement Discretion
............... 45
4OA5 Other Activities ................................................................................................. 47 4OA6
Management Meetings .................................................................................... 50
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
.................................................................................................. 1
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED ........................................................ 2
LIST OF DOCUMENTS REVIEWED
....................................................................................... 3
LIST OF ACRONYMS
- US [[]]
ED ................................................................................................ 12
Enclosure
- OF [[]]
- FINDIN [[]]
- GS [[]]
- IR 05000266/2008005, 05000301/2008005; 10/01/2008-12/31/2008; Point Beach Nuclear Plant, Units 1 & 2; Inservice Inspection (
- NRC 's program for overseeing the safe operation of commercial nuclear power reactors is described in
- A. [[]]
- NRC -Identified and Self-Revealed Findings Cornerstone: Initiating Events * Green. A finding of very low safety significance and associated
CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," was self-revealed for the failure to have inspection procedures appropriate to the circumstances for the Unit 1 and Unit 2 containment polar cranes and their integral
support structures. Specifically, station routine maintenance procedure 1(2)
OSHA Operability Inspections," did not require that the polar crane lateral restraint bolts be inspected to ensure that they do not show signs of degradation or movement, e.g., flaking paint or being backed out of position. As a result, improperly installed bolts went undiscovered by the licensee until a
failed bolt was found on October 16, 2008, lying on the containment floor. The discovery prompted further inspection of the entire crane support structure and led to the de-rating of the polar crane's lifting capacity from 100 tons to 40 tons. In addition to conducting an extent-of-condition inspection, the licensee entered the issue into its corrective action program (CAP), replaced all degraded bolts, and performed an apparent cause
evaluation. The finding was determined to be more than minor because the finding was associated with the Initiating Events Cornerstone attribute of equipment performance and affected the cornerstone objective of limiting the likelihood of those events that challenge critical safety functions during shutdown. Specifically, failing to visually inspect critical bolting
locations on crane supports could have allowed the use of the polar crane for heavy load lifts while in a degraded condition, increasing the likelihood of a load drop. The inspectors determined that the finding could be evaluated in accordance with
SDP," dated February 28, 2005. The issue did not need a quantitative assessment and screened as Green using Figure 1. This finding has
a cross-cutting aspect in the area of human performance, resources, for the failure to have complete and accurate procedures in place. Specifically, the vague and insufficient detail in the crane inspection procedures contributed to the licensee's failure to perform an adequate inspection to identify degraded components prior to their failure H.2(c). (Section 1R20.3)
Enclosure * Green. The inspectors identified a finding of very low safety significance and associated
CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure to adequately perform boric acid leak evaluations for boric acid
leaks as required by the Boric Acid Program. The licensee entered this issue into its CAP and was evaluating corrective actions at the end of the inspection period. This finding was determined to be more than minor because it was associated with the human performance attribute of the Initiating Events Cornerstone and affected the cornerstone objective of limiting the likelihood of those events that upset plant stability
and challenge critical safety functions during shutdown, as well as power operations. The inspectors used IMC 0609, "Significance Determination Process," Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," Table 4a for the Initiating Events Cornerstone, dated January 10, 2008, and determined the finding was of very low safety significance (Green) because the issue did not result in exceeding the
Technical Specification (TS) limit for identified reactor coolant system (RCS) leakage or affect other mitigating systems resulting in a total loss of their safety function. The inspectors also determined that the finding has a cross-cutting aspect in the area of human performance, work practices component, because the licensee did not effectively communicate expectations regarding procedural compliance and personnel following procedures H.4(b). (Section 1R08.1b) Cornerstone: Mitigating Systems * Green. A finding of very low safety significance and associated
- CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," was self-revealed for the failure to have procedures appropriate to the circumstances for the draindown of the
OP-4D, "Draining the Reactor Coolant System," did not require that the pressurizer level instrumentation reference line be filled within a defined period of time to ensure that the pressurizer level instrumentation functioned properly prior to draining the RCS. This resulted in the
licensee draining approximately 2,000 gallons of
- RCS [[from the pressurizer without a valid control room indication of pressurizer level. The licensee performed an apparent cause evaluation and implemented corrective actions to address the procedure deficiencies and lessons learned from this finding. The finding was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attribute of operating procedure quality and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the pressurizer level instrumentation is utilized during shutdowns to detect and manually initiate mitigating actions for uncontrolled]]
RCS inventory
reductions. The inspectors determined that the finding could be evaluated in accordance with
SDP," dated February 28, 2005. The inspectors used Checklist 2 contained in Attachment 1 and determined that the finding required a Phase 2 analysis since the finding increased the likelihood of loss of RCS inventory based on level deviation in the control room
(Section II.A. of Checklist 2). The inspectors and senior reactor analyst determined through Phase 2 analysis that this issue is best characterized as a finding of very low safety significance (Green). The inspectors also determined that the finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because the licensee failed to take appropriate corrective actions to address
Enclosure safety issues and adverse trends associated with the pressurizer level instrumentation in a timely manner, commensurate with their safety significance and complexity P.1(d). (Section 1R20.1) * Green. The inspectors identified a finding of very low safety significance and associated
CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure to appropriately implement work orders for the installation of the Z-296-B3 debris interceptor. As a result, this portion of the modification was not installed as designed when the modification was completed and the Unit 1 reactor
transitioned to Mode 3. The licensee took remedial corrective actions to correct the installation deficiency and at the end of the inspection period, the licensee continued to perform an apparent cause evaluation. The finding was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attributes of initial modification design control
and human performance, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors determined the finding could be evaluated using the
IMC 0609, "Significance Determination Process," Attachment 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," Table 4a for the Mitigating Systems Cornerstone, dated January 10, 2008. The inspectors determined that the finding was of very low safety
significance (Green) because the finding did not involve a design or qualification deficiency, did not represent an actual loss of safety function, or represent a single train loss of safety function for greater than the Technical Specification-allowed outage time, and was not potentially risk-significant for external events. This finding has a cross-cutting aspect in the area of human performance, work practices, because
personnel work practices for the installation did not utilize the available human error prevention techniques, specifically self and peer checking, and the use of a questioning attitude H.4(a). (Section 1R20.2) Cornerstone: Barrier Integrity * Green. A finding of very low safety significance and associated
CFR Part 50, Appendix B, Criterion III, "Design Control," was self-revealed upon discovery of the use of a non-conservative setpoint for the Low Temperature
Overpressure Protection (LTOP) systems for Units 1 and 2. Specifically, licensee calculation 2000-0001, "RCS [Reactor Coolant System] Pressure and Temperature Limits and Low Temperature Overpressure Protection Setpoints Applicable through 32.2
- LT [[]]
OP setpoint of 500 pounds per square inch - gauge (psig). However, by using the setpoint calculation
methodology of
- LTOP setpoint was calculated to be 420 psig. Therefore, the 500 psig setpoint was found to be non-conservative and the
LTOP setpoints from 500 psig to 420 psig and made changes to operating procedures to delineate the acceptable operating
conditions of the reactor coolant pumps and charging pumps during low temperature conditions. The finding was determined to be more than minor because the finding was associated with the human performance attribute of the Barrier Integrity Cornerstone and affected
Enclosure the cornerstone objective of providing reasonable assurance that physical design barriers, such as containment, protect the public from radionuclide releases caused by accidents or events. Specifically, the non-conservative
- RCS pressure boundary would be maintained during low temperature conditions. The inspectors determined the finding could be evaluated using the
IMC 0609, "Significance Determination
Process," Attachment 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," Table 4a for the Barrier Integrity Cornerstone, dated January 10, 2008. The inspectors determined that the finding was of very low safety significance (Green) because all of the questions in the containment barrier column of Table 4a were answered NO and the actual setpoint of the power operated relief valves was 415 psig,
below the revised
- LTOP [[setpoint. The inspectors also determined that the finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program component, because personnel did not use a low threshold for identifying issues P.1(a). (Section 4]]
- OA 3.1) * Green. The inspectors identified a finding of very low safety significance and associated Severity Level
- IV [[]]
- NCV [[of Technical Specification 5.6.5(c), "Reactor Coolant System Pressure and Temperature Limits Report (PTLR)," for the failure to submit a revised]]
- PT [[]]
LR (revision 2) on November 15, 2007. This finding was determined to be more than minor because it was associated with the design control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the curve used to define plant operating limits for acceptable pressure and temperature conditions for protection against failure of the reactor vessel was not valid after February 2004.
The finding is not suitable for
NRC management and is determined to be a finding of very low safety significance. Specifically, subsequent calculations using an NRC approved methodology determined that the Point Beach Unit 1 reactor vessel was not outside of the safety limits and was fully capable of performing the required service. The
inspectors determined that the finding does not have an associated cross-cutting aspect. (Section
- 4OA 5.1) Cornerstone: Public Radiation Safety * Green. The inspectors identified a finding of very low safety significance and an associated
NCV of TS 5.4.1 for the failure to establish written procedures to implement the radioactive effluent control program as provided in the Offsite Dose Calculation Manual to ensure effluent sample analyses satisfied required detection criteria.
Specifically, no process was established to ensure that effluent analysis capabilities for chemistry analytical equipment were periodically demonstrated to meet required lower levels of detection (LLDs). As corrective actions, the licensee subsequently performed LLD determinations for its analytical equipment (gamma spectroscopy system) and
Enclosure developed procedures to ensure LLDs were periodically verified consistent with industry standards. The finding was determined to be more than minor because it affected the program and process attribute of the Public Radiation Safety Cornerstone and affected the cornerstone objective of ensuring adequate protection of public health and safety from exposure to radioactive material released into the public domain. Specifically, given the
instability in the licensee's gamma spectroscopy system since 2007, as evidenced by repetitive performance check failures, the ability of the equipment to achieve required LLDs could have been impacted or necessitated changes in analysis parameters (such as count times) resulting in non-conservative effluent quantification. The inspectors determined that the finding was of very low safety significance (Green) because it did not
represent a substantial failure to implement the effluent release program or result in public dose that exceeded specified criterion. The inspectors also determined that the finding has a cross-cutting aspect in the area of human performance, resources component, in that the licensee failed to develop procedures to fully implement its effluent program as provided in the Offsite Dose Calculation Manual (ODCM) H.2(c). (Section 2PS1.2) B. Licensee-Identified Violations None.
Enclosure
- REPORT [[]]
DETAILS Summary of Plant Status Unit 1 was at 100 percent power at the beginning of the inspection period, shut down to commence the cycle 31 refueling outage (U1R31) on October 6, 2008, restarted on November 12, and returned to 100 percent power on November 18. Unit 1 remained at or near 100 percent power for the remainder of the inspection period with the exception of planned
reductions in power during routine auxiliary feedwater (AFW) pump and secondary system valve testing. Unit 2 was at 100 percent power throughout the entire inspection period with the exception of a planned reduction in power during routine
- AFW testing and a planned downpower to 66 percent on December 6, 2008, during turbine trip and condenser steam dump testing. 1.
- SAFETY ) .1 Quarterly Partial System Walkdowns a. Inspection Scope The inspectors performed partial system walkdowns of the following risk-significant systems: * residual heat removal (]]
RHR) system while in Mode 6, and * spent fuel pool cooling (SFPC) system while full core off-loaded into pool. The inspectors selected these systems based on their risk-significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted
to identify any discrepancies that could impact the function of the system, and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, the Final Safety Analysis Report (FSAR), Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions
that could have rendered the systems incapable of performing their intended functions. The inspectors also walked-down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The
inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the
- CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment. These activities constituted two partial system walkdown samples as defined in Inspection Procedure (
IP) 71111.04-05.
Enclosure b. Findings No findings of significance were identified. .2 Semi-Annual Complete System Walkdown a. Inspection Scope During the week November 17, 2008, the inspectors performed a complete system alignment inspection of the G-05 gas turbine generator to verify the functional capability
of the system. This system was selected because it was considered both safety-significant and risk-significant in the licensee's probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment line ups, electrical power availability, temperature indications, component labeling, component lubrication, component and equipment cooling, hangers and supports,
functionality of support systems, and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding
- WO s was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the
- CAP database to ensure that any system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the Attachment. These activities constituted one complete system walkdown sample as defined in
- IP [[71111.04-05. b. Findings No findings of significance were identified. 1R05 Fire Protection (71111.05) .1 Routine Resident Inspector Tours (71111.05Q) a. Inspection Scope The inspectors conducted fire protection walkdowns that were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas: * fire zone 681: G-05 gas turbine generator building; * fire zone 304S:]]
AFW pump room south section; * fire area A36: Unit 1 containment; * fire area A01-A: Unit 1 primary auxiliary building - 8' elevation; * fire area A01-G: Unit 1 façade; and * fire zones 770/775: G-03/G-04 diesel generator rooms. The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within
the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and had implemented adequate compensatory measures for out-of-service, degraded, or inoperable fire
Enclosure protection equipment, systems, or features in accordance with the licensee's fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk and their potential to impact equipment which could initiate or mitigate a plant transient. Using the documents listed in the Attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was
within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensee's
- CAP. Documents reviewed are listed in the Attachment to this report. These activities constituted six quarterly fire protection inspection samples as defined in
IP 71111.05-05. b. Findings No findings of significance were identified. 1R07 Annual Heat Sink Performance (71111.07) .1 Heat Sink Performance a. Inspection Scope The inspectors reviewed the licensee's inspection results of the Unit 1 containment accident fans to verify that potential deficiencies did not mask the licensee's ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events or that would cause an increase in risk. The inspectors reviewed the licensee's observations as compared against acceptance
criteria. This annual heat sink performance inspection constituted one sample as defined in
- IP 71111.07-05. b. Findings No findings of significance were identified. 1R08 Inservice Inspection Activities (71111.08) .1 Piping Systems Inservice Inspection (
ISI) a. Inspection Scope From October 6 through October 24, 2008, the inspectors conducted a review of the implementation of the licensee's Risk-Informed Inservice Inspection Program for
monitoring degradation of the
- RCS boundary and the risk-significant piping system boundaries. The inspectors selected program components and American Society of Mechanical Engineers (
ASME) Code Section XI required examinations and Code components in order of risk priority, as identified in Section 71111.08-03 of the
Enclosure inspection procedure, based upon the
- ISI activities available for review during the onsite inspection period. The inspectors observed and performed a record review of the following two types of non-destructive examination (
- XI and Section V requirements and to verify that indications and defects (if present) were dispositioned, in accordance with the
- 1SI [[-867B. The inspector reviewed documentation for examinations completed during the previous outage with relevant/recordable conditions/indications that were accepted for continued service to verify that the licensee's acceptance was in accordance with the Section]]
XI of
the
- ASME Code. Specifically, the inspector reviewed the following records: * indication disposition reports resulting from
- SI -1051R-1-H3, where the spring can load setting was not as shown on the drawing. The engineering evaluation calculated the as-found settings as acceptable; and * indication disposition report of
AFW-1002-2. The indications were measured to be less than 1/64-inch in diameter and therefore within the Code acceptance criterion. The inspectors reviewed pressure boundary welds for Class 1 and 2 systems that were completed since the beginning of the previous refueling outage. The inspectors also reviewed the work order and welding documents for a Class 2 pressure boundary weld to be completed in the U1R31. As applicable, the inspection was performed to
determine if the welding acceptance and preservice examinations (e.g., weld procedure qualification tensile tests,
- XI requirements. Specifically, the inspectors reviewed welds associated with the following work activities: * repair/replacement (welding) of
- ASME Class 2 coupling on 2-SI-301R-3 piping from the containment spray pump discharge to the addition tank; and * repair/replacement (welding) of
CV-303B, seal injection filter 1F-39B inlet. This inspection in combination with those described in report sections 1R08.2 through 1R08.5, constituted one inspection sample as defined in IP 71111.08. The documents reviewed during this inspection are listed in the Attachment. b. Findings No findings of significance were identified.
Enclosure .2 Pressurized Water Reactor Vessel Upper Head Penetration Inspection Activities a. Inspection Scope For the vessel head, no examination was required pursuant to
- NRC review was conducted for this inspection procedure attribute. b. Findings No findings of significance were identified. .3 Boric Acid Corrosion Control
ISI a. Inspection Scope The inspectors observed licensee boric acid corrosion control visual examinations (VTs) for portions of the systems containing primary coolant water inside containment to
determine if these
- VT s emphasized locations where boric acid leaks can cause degradation of safety-significant components. The inspectors reviewed the following licensee evaluations of reactor coolant system (
- 1SI -860B, P-14A containment spray pump discharge isolation. The inspectors reviewed the following corrective action documents related to boric acid leakage to determine if the corrective actions completed were consistent with the requirements of the
CFR Part 50, Appendix B, "Quality
Assurance for Nuclear Power Plants and Fuel Reprocessing Plants": * action request (AR) 01119055, significant boric acid found on
- 1GS -14. b. Findings Failure to Perform Evaluations of Boric Acid Leaks Introduction: The inspectors identified a finding of very low safety significance and associated Non-Cited Violation of 10
- CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure to evaluate boric acid leaks as required by the Boric Acid Leakage and Corrosion Monitoring (BALCM) program. Description: The licensee's
- BAL [[]]
CM program requires that when a boric acid indication has been identified by other than a procedural exam, i.e., a leak test, a work request is
Enclosure to be written. In all boric acid indication cases reviewed by the inspectors, an
- BALCM program requirements, the work request shall be flagged as a boric acid leak for proper disposition and tracking. A boric acid evaluation was then required to be performed by the
- BALCM program engineer, based on flagged work orders, to identify work tasks associated with the leak and record them on form
PBD-7051. The only exception to this
requirement, was when the boric acid leak was characterized as dry, white and light, was contained within the packing gland area, and did not affect any bolting, and the boric acid crystals did not extend more than 1/4-inch from the surface of the component. The
- BALCM program engineer then tracks completion of the recommended disposition to ensure the actions were taken. During the inspectors' review of
- RCS pressure boundary piece of equipment), the inspectors identified that a boric acid evaluation was not performed in accordance with the
- BALCM program. Although the licensee had identified this procedure noncompliance and documented it in
- AR did not provide an adequate extent of condition evaluation for the procedure compliance aspect of the issue. This boric acid leak was observed during a non-
- ASME observations from the previous two year period. The inspectors subsequently identified six additional
ASME Section XI pressure boundaries, for which boric acid evaluations
were not performed. Analysis: The inspectors determined that the failure to perform evaluations on boric acid leaks was contrary to the
- BALCM Program and was a performance deficiency. Specifically, boric acid leakage at seven safety-related,
ASME Code piping pressure boundaries was entered into the CAP but an engineering evaluation by the boric acid
engineer was not performed as required by the
- BALCM. This finding was determined to be more than minor in accordance with Inspection Manual Chapter (
IMC) 0612, Appendix B, "Issue Screening," dated December 4, 2008, because it was associated with the human performance attribute of the Initiating Events Cornerstone and affected the cornerstone objective of limiting the likelihood of those
events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, boric acid leakage has historically been found to degrade carbon steel components affecting the
- RCS pressure boundary as well as the pressure boundary of components in emergency core cooling system (
- ECCS [[). This degradation, if not adequately evaluated, could lead to further leakage and result in plant operational changes (e.g., unplanned mode changes) or could impact the reliability of systems required for safe shutdown. The inspectors determined the finding could be evaluated using the]]
IMC 0609, "Significance Determination Process," Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," Table 4a for the Initiating Events Cornerstone, dated January 10, 2008. The finding was determined to be of very low safety significance (Green) because the issue did not result in exceeding the TS limit
Enclosure for identified
- RCS [[leakage nor did it affect other mitigating systems, resulting in a loss of their safety function. This finding has a cross-cutting aspect in the area of human performance, work practices component, because the licensee did not effectively communicate expectations regarding procedural compliance and personnel following procedures. Specifically, the failure to perform evaluations on boric acid leaks was contrary to the]]
- BALCM program and providing clear expectations for procedure adherence and use would have prevented the non-compliance. H.4(b) Enforcement: Title 10
CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings" requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, and drawings, of a type appropriate to the
circumstances and be accomplished in accordance with these instructions, procedures, or drawings. Licensee procedure
- NP [[7.4.14, "Boric Acid Leakage and Corrosion Monitoring," required that each work request generated for boric acid leakage exceeding the specified criteria would have a boric acid evaluation performed. Contrary to the above, during 2007 and 2008, the licensee failed to accomplish the requirements of the]]
- BALCM program in accordance with established procedures. Specifically, the licensee failed to perform at least seven boric acid leak evaluations for boric acid leaks identified in the
- BALCM procedure. However, because this issue was determined to be of very low safety significance (Green) and was entered into the licensee's
- SG ) Tube Inspection Activities a. Inspection Scope From October 13 through October 24, 2008, the inspectors performed an onsite review of Unit
- SG [[]]
- SG tube pressure testing screening criteria and the methodologies used to derive these criteria were consistent with the Electric Power Research Institute (EPRI)
- SG tube flaws/degradation identified were bound by the licensee's previous outage operational assessment predictions; * the
- EC examination scope and expansion criteria were sufficient to identify tube degradation based on site and industry operating experience by confirming that the
- EP [[]]
RI 1003138, "Pressurized Water Reactor Steam Generator Examination Guidelines," Revision 6; * the licensee did not identify new tube degradation mechanisms;
Enclosure * the
- EC challenges such as the tube sheet regions, expansion transitions, and support plates; * the licensee implemented repair methods, which were consistent with the repair processes allowed in the plant
- TS requirements; * the required repair criteria were being adhered to; * the licensee primary-to-secondary leakage (e.g.,
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; * where practicable, attempts were made to retrieve foreign objects. For those objects that were unable to be retrieved, evaluations were performed for the potential detrimental affects of the objects, and appropriate repairs of the affected tubes were planned/taken; and * licensee-identified deviations from]]
- EC [[data acquisition or analysis procedures were appropriate. The documents reviewed during this inspection are listed in the Attachment. b. Findings No findings of significance were identified. .5 Identification and Resolution of Problems The inspectors reviewed]]
SG-related problems that were identified by the licensee and entered into the CAP, interviewed licensee staff, and reviewed licensee corrective
action records to determine if the licensee had: * described the scope of the
- SG related problems; * established an appropriate threshold for identifying issues; * evaluated operating experience and industry generic issues related to
- ISI and pressure boundary integrity; and * implemented appropriate corrective actions. The inspectors performed these reviews to ensure compliance 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. 1R11 Licensed Operator Requalification Program (71111.11) .1 Examination Security a. Inspection Scope The inspectors reviewed a licensee's Action Request Record Report related to examination physical security (e.g., access restrictions) to verify compliance with 10 CFR 55.49, "Integrity of examinations and tests." The inspectors also reviewed the
Enclosure facility licensee's examination security procedure and any corrective actions related to past or present examination security problems at the facility. The documents reviewed during this inspection are listed in the Attachment. This review did not constitute a sample as defined in
- IP [[71111.11. b. Findings During a review of licensed operator examination security, the facility discovered that some operations instructors had unintentional access to keys for exam areas for which they were not authorized to have unrestricted access. This was not allowed by licensee procedure]]
FP-T-SAT-71, NRC Exam Security Requirements. Interviews by training department management of these instructors revealed no one accessed examination secure materials. Additionally, a second barrier (additional keys and security
passwords) had been in-place during the time of the unintentional access that would have prevented any unauthorized access to licensed operator examination materials. Therefore, no violation of examination integrity occurred. The training department documented the deficiency in examination room key control in the
- AR [[01137883. .2 Resident Inspector Quarterly Review (71111.11Q) a. Inspection Scope On December 8, 2008, the inspectors observed a crew of licensed operators in the plant's simulator during licensed operator simulator training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas: * licensed operator performance; * crew's clarity and formality of communications; * ability to take timely actions in the conservative direction; * prioritization, interpretation, and verification of annunciator alarms; * correct use and implementation of abnormal and emergency procedures; * control board manipulations; * oversight and direction from supervisors; and * ability to identify and implement appropriate]]
- TS [[actions and Emergency Plan actions and notifications. The crew's performance in these areas was compared to pre-established operator action expectations and training program objectives. Documents reviewed are listed in the Attachment. This inspection constituted one quarterly licensed operator requalification program sample as defined in]]
IP 71111.11. b. Findings No findings of significance were identified.
Enclosure 1R12 Maintenance Effectiveness (71111.12) .1 Routine Quarterly Evaluations (71111.12Q) a. Inspection Scope The inspectors evaluated degraded performance issues involving the following risk-significant systems: * service air system; and * Unit
- 1 SI [[system. The inspectors reviewed and independently verified the licensee's actions to address problems with system performance or condition in terms of the following: * implementing appropriate work practices; * identifying and addressing common cause failures; * scoping of systems in accordance with 10]]
CFR 50.65(b) of the maintenance rule; * characterizing system reliability issues for performance; * charging unavailability for performance; * trending key parameters for condition monitoring; * ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and * verifying appropriate performance criteria for structures, systems, and components/functions classified as (a)(2) or appropriate and adequate goals and corrective actions for systems classified as (a)(1). The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance
effectiveness issues were entered into the
- CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment. This inspection constituted two quarterly maintenance effectiveness samples as defined in
IP 71111.12-05. b. Findings No findings of significance were identified. 1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13) .1 Routine Quarterly Review a. Inspection Scope The inspectors reviewed the licensee's evaluation and management of plant risk for the planned maintenance and emergent work activities affecting risk-significant and safety-related equipment during the time periods listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work during the weeks of:
Enclosure * October 20; * October 27; * November 3; * November 10; and * December 22. These work week activities were selected based on their potential risk-significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the
results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed
- TS [[requirements and walked-down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Documents reviewed are listed in the Attachment. These maintenance risk assessments and emergent work control activities constituted five samples as defined in]]
- IP 71111.13-05. b. Findings No findings of significance were identified. 1R15 Operability Evaluations (71111.15) .1 Operability Evaluations a. Inspection Scope The inspectors reviewed the following issues: *
- AR 01138321 - boric acid degradation of Unit 1 A and B residual heat removal heat exchanger bolting; *
- AR [[01140867 - south service water header service water pump reduction in flow. The inspectors selected these potential operability issues based on the risk-significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that]]
TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the
appropriate sections of the
FSAR to the licensee's evaluations, to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the
evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies
Enclosure associated with operability evaluations. Documents reviewed are listed in the Attachment. This operability inspection constituted four samples as defined in
- IP [[71111.15-05. b. Findings No findings of significance were identified. 1R18 Plant Modifications (71111.18) .1 Temporary Plant Modifications a. Inspection Scope The inspectors reviewed the following temporary modification: * Unit 1 steam generator chemical cleaning system used during U1R31. The inspectors compared the temporary configuration changes and vendor system design documents against the design basis, the]]
FSAR, and the TSs, as applicable, to verify that the modification did not affect the operability or availability of the affected
systems. The inspectors performed field verifications to ensure that the modification was installed as directed; the modification operated as expected; that process monitoring adequately demonstrated that no degradation to system materials occurred; and that operation of the modification did not impact the operability of any interfacing systems. Lastly, the inspectors discussed the temporary modification with vendor and operations personnel to ensure that the individuals were aware of expected actions in the event of a system failure or malfunction. This inspection constituted one temporary modification sample as defined in
- IP [[71111.18-05. b. Findings No findings of significance were identified. 1R19 Post-Maintenance Testing (71111.19) .1 Post-Maintenance Testing a. Inspection Scope The inspectors reviewed the following Unit 1 post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability: * containment polar crane bolt replacement; *]]
SI valves SI-850A and B;
Enclosure * high and low head
AFW pump 1P-29. These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated
operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing; and test documentation was properly evaluated. The inspectors evaluated the activities against the
NRC generic
communications to ensure that the test results adequately ensured that the equipment met the licensing and design bases. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents
reviewed are listed in the Attachment. This inspection constituted seven post-maintenance testing sample as defined in
- IP 71111.19-05. b. Findings No findings of significance were identified. 1R20 Outage Activities (71111.20) .1 Draindown of
RCS in Pressurizer With Inaccurate Level Indication a. Inspection Scope The inspectors reviewed the circumstances surrounding the October 8, 2008, draindown of the Unit 1 RCS from a solid plant condition to approximately 67 percent pressurizer level, whereby the pressurizer level instrumentation did not respond. The inspectors reviewed licensee documentation, interviewed licensee personnel and management in
operations and maintenance, and reviewed previous failures of the pressurizer level instrumentation to respond appropriately during
- RCS draindowns. Documents reviewed are listed in the Attachment to this report. b. Findings Introduction: A finding of very low safety significance and associated
- 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," was self-revealed for the failure to have procedures appropriate to the circumstances for the draindown of the
RCS from a solid plant condition. Specifically, procedure OP-4D, "Draining the Reactor Coolant System," did not require that the pressurizer level instrumentation reference line be filled within a defined period of time to ensure that the
pressurizer level instrumentation functioned properly prior to draining the RCS. This
Enclosure resulted in the licensee draining approximately 2,000 gallons of
- RCS [[inventory from the pressurizer without a valid control room indication of pressurizer level. Description: On October 8, 2008, control room operators commenced draining reactor coolant from the pressurizer as a part of the normal progression towards refueling mode for U1R31. The]]
RCS was in a solid condition (greater than 100 percent indicated level) and the operators were draining the RCS to approximately 25 percent indicated level. At
approximately 12:30 p.m. the operators established an initial draindown of 1,200 gallons to ensure that level instrumentation came on scale and responded appropriately. After draining approximately 1,200 gallons, verified by the established drain rate and the non-safety-related hold-up tank "C" level indications, the operators suspended the draindown to address inventory balances and ensure indicators were functioning
properly. The control room pressurizer cold calibration level transmitter LT-433 had not come on-scale (it should have come on-scale after about 900 gallons were drained) and the operations department managers decide that a valve lineup verification would be performed to confirm the physical lineup of the system. The valve lineup was performed satisfactorily with no discrepancies noted and the inventory balances were again compared and verified to the hold-up tank "C" level. Operations management then decided to continue draining an additional 30 minutes (approximately 800 gallons) for a
total of 2,000 gallons. Following this additional inventory reduction, the draindown was suspended to address the inventory balances and pressurizer level indicator response. The operators verified that the control room pressurizer level transmitter still had not responded to the additional
- RCS reduction. Instrumentation and control technicians were then requested to perform Attachment I of operations procedure
OP-4D Part 1, "LT-433, T-1 Pressurizer Cold Calibration Level Transmitter Reference Line Fill." Upon completion of the filling of the reference line, pressurizer level transmitter LT-433 indicated 67 percent pressurizer level in the control room and on the plant process computer, which correlated to the 3 percent rise in level seen in hold-up tank "C," a volume of approximately 2,000 gallons. The licensee
initiated condition report 1137061 for this self-revealed instrumentation failure, which was assigned a "B" significance level and a condition evaluation. Upon review of the completed condition evaluation in October 2008, the inspectors noted that the evaluation may not have identified the appropriate cause for the failure of the instrument to respond. The inspectors based this assessment on the past failures of
the level transmitter in the fall of 2006 and spring of 2004, and that the evaluation focused on the procedure not quantifying expected instrument responses based on inventory reductions. The inspectors noted that an apparent cause evaluation conducted for the fall of 2006 failure identified that the reference line had emptied causing an erratic instrument response. While the 2006 corrective actions required
performance of Attachment I of procedure
- OP [[-4D prior to the start of the draindown, the time critical nature of this activity was not translated from the apparent cause evaluation into the corrective action for the procedure change. The inspectors reviewed the October 2008 control room logs and determined that Attachment I of procedure]]
OP-4D had been performed on October 7, 2008, over 25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br /> prior to the start of the draindown. The licensee's 2006 apparent cause evaluation had concluded that Attachment I should be performed as soon as possible before beginning the draindown
but no more than about 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> prior to the start. The inspectors also determined that a delay in the outage schedule had caused the large amount of time to elapse from performance of Attachment I of procedure
RCS draindown.
Enclosure The licensee evaluated the additional information provided by the inspectors and concluded that an apparent cause evaluation was warranted. The licensee concluded in the apparent cause that previous attempts to correct the problems with the reference line of pressurizer level transmitter
- OP -4D were ineffective to address the timeliness aspect of filling the reference line commensurate with draindown. Analysis: The inspectors determined that the failure to have a procedure appropriate to the circumstances to conduct
- RCS draindowns with properly functioning level instrumentation was a performance deficiency. The finding was determined to be more than minor in accordance with
IMC 0612, Appendix B, "Issue Screening," dated December 4, 2008, because the finding was associated with the Mitigating Systems Cornerstone attribute of operating procedure quality and affected the cornerstone
objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the pressurizer level instrumentation is utilized during shutdowns to detect and manually initiate mitigating actions for uncontrolled
- RCS inventory reductions. The inspectors determined that the finding could be evaluated in accordance with
IMC 0609, Appendix G, "Shutdown Operations SDP," dated February 28, 2005. The inspectors used Checklist 2 contained in Attachment 1 and determined that the finding
required a Phase 2 analysis since the finding increased the likelihood of loss of
- SRA ) performed the assessment using Appendix G, Attachment 2, "Phase 2 Significance Determination Process Template for
SRA determined this to be a precursor to an initiating
event (a loss of level control precursor -
RHR loss.
The
- SRA considered this to be an overly conservative value considering that the operators stopped draining at 67 percent pressurizer level to perform further evaluation. To better estimate the
- LOLC [[, the analyst assumed stress to be high and available time to be expansive. For action, the analyst assumed stress to be high. All other performance shaping factors were assumed to be nominal. The resultant value of 2.2E-3 was assumed as the initiating event likelihood. Using Appendix G, Attachment 2, Worksheet 1, "]]
POS 1 (RCS Closed)," the analyst evaluated the remaining mitigating
capability credit to reflect equipment availability and the time available to complete tasks prior to core damage. The most significant core damage sequences involved loss of steam generator cooling and failure of
- RCS injection and bleed before core damage. The combined sequences had a risk-significance of about 2.2E-8. Therefore, the
SRA determined that this issue is best characterized as a finding of very low safety significance (Green).
Enclosure This finding has a cross-cutting aspect in the area of problem identification and resolution, corrective action program, because the licensee failed to take appropriate corrective actions to address safety issues and adverse trends associated with the pressurizer level instrumentation in a timely manner, commensurate with their safety significance and complexity. P.1(d) Enforcement:
- 10 CFR [[Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality be prescribed by documented instructions or procedures of a type appropriate to the circumstances. Contrary to the above, on October 8, 2008, the licensee commenced draining the]]
RCS from a solid plant condition, an activity affecting quality, with a procedure which was not appropriate to the circumstances. Specifically, procedure OP-4D, "Draining the Reactor
Coolant System," did not adequately prescribe the timeliness aspect of filling the reference line of the pressurizer level transmitter commensurate with the draindown, consequently the draindown was performed without accurate pressurizer level indication in the control room. Because this violation was of very low safety significance and it was entered into the licensee's
NCV 05000266/2008005-02). In response to this issue, the licensee performed an apparent cause evaluation and initiated corrective actions to: correct the deficient procedure conditions; add additional information regarding expected instrument response for a given volume of reactor coolant removed from the system; and establish an initial quantified volume to begin the draindown, followed by prescribed corrective actions to take if level instrumentation did
not respond appropriately. Also, the operating crews were coached regarding documentation of intermediate decisions and stopping points in station logs and additional lessons learned were reviewed with the operations crews. .2 Non-Conformances Identified with Safety-Related Sump Screen Debris Interceptors a. Inspection Scope The inspectors performed the final containment walkdown for boric acid deposits and safeguards system readiness while Unit 1 was in Mode 3 and normal operating temperature and pressure. During the walkdown, the inspectors noted that the recently modified containment sump screen debris interceptors did not conform to the original design as detailed in the engineering change package. The inspectors reviewed the
engineering change package and associated 50.59 evaluation, and interviewed licensee staff responsible for the modification to the safety-related sump screen, which was made during U1R31. b. Findings Introduction: The inspectors identified a finding of very low safety significance and associated
CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the failure to appropriately implement work orders for the installation of the Z-296-B3 containment sump screen debris interceptor. As a result, this portion of the modification was not installed as designed when the modification was completed during the refueling outage and the Unit 1 reactor transitioned to Mode 3.
Enclosure Description: As a result of the resolution of
- NRC Generic Letter 2004-02 ("Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis Accidents at Pressurized-Water Reactors") and Generic Safety Issue
GSI-191 ("Assessment of Debris Accumulation on PWR [Pressurized-Water Reactor] Sump Performance"), the licensee was required to modify the emergency core cooling system sump. In a previous refueling outage, the licensee had installed new emergency core cooling
system sump screens which had a significantly larger area than the originally installed screens. However, testing performed during the summer of 2008 demonstrated that additional capture of the debris was required in order to meet the test acceptance criteria with the new sump screens. Consequently, the licensee designed two types of debris interceptors in engineering change 12604 to be installed around the new sump screens.
The "B" type debris interceptors were installed on the 10-foot steam generator platforms and consisted of perforated plate with 1/4-inch gaps. In addition, the design contained a requirement that the maximum allowable gap between the debris interceptor perforated plate and the concrete cubicle walls was also limited to 1/4-inch. On October 29, 2008, the installation of the "B" type debris interceptors was completed by the licensee personnel performing the installation. On November 6, 2008, a final engineering staff walkdown was completed of the installed modification. On November 10, 2008, the Unit
reactor was transitioned to Mode 3 at normal operating temperature and pressure. On November 11, 2008, the inspectors performed a final Mode 3 walkdown to verify that there were no boric acid leaks and to ensure the systems inside containment were ready for power operation. The inspectors noted that the Z-296-B3 debris interceptor and the adjacent concrete wall on the west side had a gap which exceeded the allowable 1/4 inch
and was estimated at approximately 1/2 inch, approximately 2/3 of the length of the debris interceptor. The licensee initiated AR 01139651 and took remedial corrective actions to install the appropriate flashing to remove the gap. At the end of the inspection period, the licensee was performing an apparent cause evaluation to determine why the debris interceptor
was not installed in accordance with the design documentation and why reviews performed by the licensee as part of the installation, failed to identify this issue. Analysis: The inspectors determined that the failure to properly install the Z-296-B3 debris interceptor in accordance with documented work instructions and drawings as part of the containment sump modification was a performance deficiency. The finding
was determined to be more than minor in accordance with IMC 0612, Appendix B, "Issue Screening," dated December 4, 2008, because the finding was associated with the Mitigating Systems Cornerstone attributes of initial modification design control and human performance, and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences (i.e., core damage). Specifically, the debris interceptor is a passive device utilized to minimize the debris blockage on the emergency core cooling sump screens. The inspectors determined the finding could be evaluated using the
IMC 0609, "Significance Determination Process," Attachment 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," Table 4a for the Mitigating Systems Cornerstone, dated January 10, 2008. The inspectors determined that the finding was of
very low safety significance (Green) because the finding did not involve a design or qualification deficiency, did not represent an actual loss of safety function or a single
Enclosure train loss of safety function for greater than the
- TS [[-allowed outage time, and was not potentially risk-significant for external events. This finding has a cross-cutting aspect in the area of human performance, work practices, because personnel work practices for the installation did not utilize the available human error prevention techniques, specifically self and peer checking, and the use of a questioning attitude. H.4(a) Enforcement: 10]]
CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality be accomplished in accordance with documented instructions, procedures or drawings. Contrary to the above, prior to November 11, 2008, the licensee failed to properly install the Z-296-B3 debris interceptor in accordance with the documented instructions and
drawings, an activity affecting quality. Specifically, the debris interceptor was installed with one side of the debris interceptor against the containment 10-foot platform wall having a gap greater than the maximum allowed 1/4-inch, specified in the instructions and drawings contained in
- WO 360573. Because this violation was of very low safety significance and it was entered into the licensee's
NRC Enforcement Policy (NCV 05000266/2008005-03). In response to this issue, the licensee initiated remedial corrective actions to correct the non-conforming condition. In addition, at the end of the inspection period, the licensee was performing an apparent cause evaluation which likely would result in additional corrective actions. .3 Inadequate Inspection Procedure for Containment Polar Crane Structures a. Inspection Scope The inspectors reviewed the circumstances surrounding the failure of a bolt on the Unit 1 containment polar crane that was discovered on October 16, 2008, during U1R31. The inspectors observed the licensee's failure investigation process and observed a number of licensee meetings. The inspectors reviewed the current licensing and design bases
documents for the polar cranes of both Units and their support structures, and reviewed the licensee's inspection procedures and documentation for previously performed polar crane inspections for their conformance with the requirements of
- 10 CFR Part 50, Appendix B. b. Findings Introduction: A finding of very low safety significance and associated
NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," was self-revealed for the failure to have inspection procedures appropriate to the circumstances for the Unit 1 and Unit 2 containment polar cranes and their integral support structures. Specifically, station routine maintenance procedure
1(2)
OSHA Operability Inspections," did not provide adequate instruction to ensure that the polar crane lateral restraint bolts would be inspected for signs of degradation or movement, e.g., flaking paint or being backed out of position. As a result, improperly installed bolts went undiscovered by the
Enclosure licensee until a failed bolt was found lying on the containment floor, which revealed the crane's degraded condition. Description: On October 16, 2008, during U1R31, the licensee discovered that a bolt from one of the Unit 1 containment polar crane support bracket lateral restraints, an extension of the containment structure, broke and fell to the containment floor below. The licensee immediately halted use of the crane, investigated the occurrence, and
performed an extent-of-condition visual inspection of all other support locations. Additional licensee examination discovered that four of the other bolts at the affected support location were found loose due to improper installation. No other support locations were identified to be degraded. As a part of the licensee's investigation, engineering performed an evaluation of the as-found degraded condition of the polar
crane support structure and determined that the crane load lifting capacity could be de-rated to 40 tons, from 100 tons, and small load lifts were allowed to resume. Following the extent-of-condition inspection, and once the affected bolts were replaced, the crane was returned to full rated capacity. The licensee determined that the failure was most likely due to the improper initial installation of the bolt, which allowed the bolt to vibrate under normal at-power operational vibration conditions inherently present in containment, to the point of fatigue.
With fatigue cracks present, the degraded bolt finally failed at some point during crane operation in which the crane bridge traversed the area over the support. The licensee employed the services of an outside vendor to perform a failure analysis of the failed bolt, which confirmed the licensee's initial conclusions. Photos taken of the other affected bolts clearly showed signs that they had moved from their initial position, as
evidenced by flaked paint around the edge of the bolts. Fatigue cracks were also identified. The licensee's current procedures for inspecting the polar cranes prior to their use,
- OS [[]]
HA Operability Inspections," required a visual check of the crane's rail support "runway" for degradation.
The "runway" was defined as the box girders supporting the rail; however, the particular bolting locations in question were never included in these inspections despite being a part of the "runway." As such, the licensee missed previous opportunities to identify and correct the loose, degraded bolts prior to the self-revealing failure of one bolt and the fatigue cracking of others. The licensee's apparent cause evaluation (AR 1137773)
concluded that their inspection guidance was vague and insufficient with respect to the lateral restraint bolts in question. Analysis: The inspectors determined that the failure to perform an adequate and thorough inspection of components critical to the safe operation of the containment polar crane system was a performance deficiency. The finding was determined to be more
than minor in accordance with IMC 0612, Appendix B, "Issue Screening," dated December 4, 2008, because the finding was associated with the Initiating Events Cornerstone attribute of equipment performance and affected the cornerstone objective of limiting the likelihood of those events that challenge critical safety functions during shutdown. Specifically, the failure to visually inspect critical bolting locations on crane support structures could have allowed the polar crane to perform heavy load lifts, e.g., reactor vessel head assembly or upper internals lifts, with the crane in a degraded
condition, increasing the likelihood of a support failure and subsequent load drop.
Enclosure The inspectors determined that the finding could be evaluated in accordance with
SDP," dated February 28, 2005. The inspectors used Checklist 4 contained in Attachment 1 and determined that the finding did not require a phase 2 or phase 3 analysis because the plant had appropriately met the safety function guidelines for core heat removal, inventory control, power availability, containment integrity, and reactivity control. The issue did not need a quantitative
assessment and screened as Green using Figure 1. This finding has a cross-cutting aspect in the area of human performance, resources, for the failure to have complete and accurate procedures in place. Specifically, the vague and insufficient detail in the crane inspection procedures contributed to the licensee's failure to perform an adequate inspection of crane components to identify degraded
components prior to their failure. H.2(c) Enforcement: Title
- 10 CFR [[Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings of a type appropriate to the circumstances and be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, before and during U1R31, the licensee failed to have in place procedures of a type appropriate to the circumstances for the polar crane inspections. Specifically, 1]]
OSHA Operability Inspections," were inadequate to ensure that degraded crane structural components were identified through visual inspection prior to their degradation and failure. Because this violation was of very low safety significance and it was entered into
the licensee's
NCV 05000266/2008005-04; 05000301/2008005-04). In response to this condition, the licensee repaired the affected components, performed an extent-of-condition inspection, and performed an apparent cause evaluation to
identify the cause of the issue and formulated recommended corrective actions to address the procedural issues. .4 Refueling Outage Activities a. Inspection Scope The inspectors observed activities during U1R31, conducted October 6 - November 12, 2008, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During U1R31, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below: * licensee configuration management, including maintenance of defense-in-depth for key safety functions and compliance with the applicable TSs when taking equipment out-of-service;
Enclosure * implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing; * installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error; * controls over the status and configuration of electrical systems to ensure that
- TS [[requirements were met, and controls over switchyard activities; * monitoring of decay heat removal processes, systems, and components; * controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system; * reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss; * controls over activities that could affect reactivity; * maintenance of containment closure as required by]]
- TS [[s and the technical requirements manual; * refueling activities, including fuel handling and sipping to detect fuel assembly leakage; * startup and ascension to full power operation, tracking of startup prerequisites, walkdown of containment to verify that debris had not been left which could block]]
- ECCS [[suction strainers, and reactor physics testing; and * licensee identification and resolution of problems related to the outage. This inspection, in combination with those documented above in sections 1R20.1 and 1R20.2, constituted one refueling outage sample as defined in]]
- IP [[71111.20-05. b. Findings No findings of significance were identified, other than those already described in sections 1R20.1 and 1R20.2. 1R22 Surveillance Testing (71111.22) .1 Surveillance Testing a. Inspection Scope The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and]]
SI Actuation with loss of all alternating current (Train B). (routine)
Enclosure The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following: * did preconditioning occur; * were the effects of the testing adequately addressed by control room personnel or engineers prior to the commencement of the testing; * were acceptance criteria clearly stated, demonstrated operational readiness, and consistent with the system design basis; * plant equipment calibration was correct, accurate, and properly documented; * as-left setpoints were within required ranges; and the calibration frequencies were in accordance with
FSAR, and other 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 frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored
where used; * test data and results were accurate, complete, within limits, and valid; * test equipment was removed after testing; * where applicable for inservice testing activities, testing was performed in accordance with the applicable version of
- XI [[, and reference values were consistent with the system design basis; * where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable; * where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure; * where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished; * prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test; * equipment was returned to a position or status required to support the performance of its safety functions; and * all problems identified during the testing were appropriately documented and dispositioned in the]]
- CAP. Documents reviewed are listed in the Attachment. This inspection constituted three routine surveillance testing samples and two inservice testing samples, as defined in
IP 71111.22, Sections -02 and -05. b. Findings No findings of significance were identified.
Enclosure Cornerstone: Emergency Preparedness
- 1EP 4 Emergency Action Level and Emergency Plan Changes (71114.04) .1 Emergency Action Level and Emergency Plan Changes a. Inspection Scope Since the last
NRC inspection of this program area, Emergency Plan, Section 7.0 and Appendix A, Revisions 52 and 27, were implemented based on the licensee's
determination, in accordance with
- 10 CFR 50.54(q), that the changes resulted in no decrease in effectiveness of the Plan, and that the revised Plan as changed continues to meet the requirements of 10
CFR 50.47(b) and Appendix E to 10 CFR Part 50. The inspectors conducted a sampling review of the Emergency Plan changes and a review of the Emergency Action Level changes to evaluate for potential decreases in effectiveness
of the Plan. However, this review does not constitute formal
- NRC inspection in their entirety. This emergency action level and emergency plan changes inspection constituted one sample as defined in
OS1 Access Control to Radiologically Significant Areas (71121.01) .1 Plant Walkdowns and Radiation Work Permit (RWP) Reviews a. Inspection Scope The inspectors reviewed licensee controls and surveys in the following radiologically significant work areas within radiation areas, high radiation areas, and airborne radioactivity areas in the plant to determine if radiological controls including surveys, postings, and barricades were acceptable: * Unit 2 containment building (general areas); * Unit 2 containment keyway; * primary auxiliary building (various areas); * spent fuel pool area; and * radioactive material storage yard. This sample was credited and documented in Inspection Report 05000266/2008003; 05000301/2008003; therefore, this supplemental information does not represent a sample.
Enclosure The inspectors reviewed the
- RWP [[s and work packages used to access these areas and other high radiation work areas. The inspectors assessed the work control instructions and control barriers specified by the licensee. Electronic dosimeter alarm setpoints for both integrated dose and dose rate were evaluated for conformity with survey indications and plant policy. The inspectors interviewed workers to verify that they were aware of the actions required if their electronic dosimeters noticeably malfunctioned or alarmed. This inspection constitutes one complete sample as defined in]]
- IP [[71121.01-5. The inspectors assessed the adequacy of the licensee's internal dose assessment process for internal exposures in excess of 50 millirem committed effective dose equivalent. There were no internal exposures greater than 50 millirem committed effective dose equivalent for the period reviewed by the inspectors. This inspection constitutes one complete sample as defined in]]
- IP [[71121.01-5. The inspectors also reviewed the licensee's physical and programmatic controls for highly activated and/or contaminated materials (non-fuel) stored within the spent fuel pool or other storage pools. This inspection constitutes one complete sample as defined in]]
- IP [[71121.01-5. b. Findings No findings of significance were identified. .2 Job-In-Progress Reviews a. Inspection Scope The inspectors observed the following four jobs that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas for observation of work activities that presented the greatest radiological risk to workers: * Unit 2 containment sump level indicator maintenance; * Unit 2 containment floor plug removal activities; * Unit 2 reactor vessel bare metal]]
ALARA) briefings. This inspection constitutes one complete sample as defined in IP 71121.01-5.
Job performance was observed with respect to the radiological control requirements to assess whether radiological conditions in the work area were adequately communicated to workers through pre-job briefings and postings. The inspectors evaluated the adequacy of radiological controls, including required radiation, contamination, and airborne surveys for system breaches; radiation protection job coverage, including any
Enclosure applicable audio and visual surveillance for remote job coverage; and contamination controls. This inspection constitutes one complete sample as defined in IP 71121.01-5. The inspectors reviewed radiological work in high radiation work areas having significant dose rate gradients to evaluate whether the licensee adequately monitored exposure to personnel and to assess the adequacy of licensee controls. These work areas involved
areas where the dose rate gradients were potentially severe; thereby, increasing the necessity of providing multiple dosimeters or enhanced job controls. This inspection constitutes one complete sample as defined in IP 71121.01-5. b. Findings No findings of significance were identified. .3 High Risk Significant, High Dose Rate, High Radiation Area, and Very High Radiation Area Controls a. Inspection Scope The inspectors held discussions with the Radiation Protection Manager and supervisors concerning high dose 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 assess whether any procedure modifications substantially reduced the
effectiveness and level of worker protection. This inspection constitutes one complete sample as defined in IP 71121.01-5. The inspectors discussed with radiation protection supervisors the controls that were in place for special areas of the plant that had the potential to become very high radiation areas during certain plant operations. The inspectors assessed if 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 inspection constitutes one complete sample as defined in
- IP 71121.01-5. The inspectors conducted plant walkdowns to assess the posting and locking of entrances to high dose rate high radiation areas and very high radiation areas. This inspection constitutes one complete sample as defined in
IP 71121.01-5. b. Findings No findings of significance were identified.
Enclosure .4 Radiation Worker Performance a. Inspection Scope During job performance observations, the inspectors evaluated radiation worker performance with respect to stated radiation safety work requirements. The inspectors evaluated whether workers were aware of any significant radiological conditions in their workplace, of the RWP controls and limits in place, and of the level of radiological
hazards present. The inspectors also observed worker performance to determine if workers accounted for these radiological hazards. This inspection constitutes one complete sample as defined in
- IP [[71121.01-5. b. Findings No findings of significance were identified. .5 Radiation Protection Technician Proficiency a. Inspection Scope During job performance observations, the inspectors evaluated radiation protection technician performance with respect to radiation safety work requirements. The inspectors evaluated whether technicians were aware of the radiological conditions in their workplace, the]]
- RWP controls and limits in place, and if their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities. This inspection constitutes one complete sample as defined in
- OS 2 As-Low-As-Is-Reasonably-Achievable (ALARA) Planning And Controls (71121.02) .1 Job Site Inspections and
- OS 1.2 that were being performed in radiation areas, airborne radioactivity areas, or high radiation areas to evaluate work activities that presented the greatest radiological risk to workers. The inspectors reviewed the licensee's use of
- ALARA controls for those work activities. The licensee's use of engineering controls to achieve dose reductions was evaluated to verify that procedures and controls were consistent with the licensee's
ALARA reviews, that sufficient shielding of radiation sources was provided, and that the dose expended to install and remove the shielding did not exceed the dose reduction benefits afforded
by the shielding.
Enclosure This sample was credited and documented in Inspection Report 05000266/2008003; 05000301/2008003; therefore, this supplemental information does not represent a sample. b. Findings No findings of significance were identified. .2 Radiation Worker Performance a. Inspection Scope Radiation worker and radiation protection technician performance was observed during work 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
- ALA [[]]
RA philosophy by being familiar with
the scope of the work activity and tools to be used, by utilizing
- ALARA [[low dose waiting areas, and by complying with work activity controls. Also, radiation worker training and skill levels were reviewed to determine if they were sufficient relative to the radiological hazards and the work involved. This inspection constitutes one required sample as defined in]]
- IP 71121.02-5. b. Findings No findings of significance were identified. Cornerstone: Public Radiation Safety
- 2PS [[1 Radioactive Gaseous And Liquid Effluent Treatment And Monitoring Systems (71122.01) .1 Inspection Planning a. Inspection Scope The inspectors reviewed the configuration of the licensee's gaseous and liquid effluent processing systems to confirm that radiological discharges were properly mitigated, monitored, and evaluated with respect to public exposure. The inspectors reviewed the performance requirements contained in General Design Criteria 60 and 64 of Appendix A to 10]]
CFR Part 50 and in the licensee's Radiological Effluent Technical Specifications (RETS) and Offsite Dose Calculation Manual (OCDM). The inspectors
also reviewed any abnormal radioactive gaseous or liquid discharges and any conditions since the last inspection when effluent radiation monitors were out-of-service to verify that the required compensatory measures were implemented. Additionally, the inspectors reviewed the licensee=s quality control program to verify that the radioactive effluent sampling and analysis requirements were satisfied and that discharges of
radioactive materials were adequately quantified and evaluated. The inspectors reviewed each of the radiological effluent controls program requirements to verify that the requirements were implemented as described in the licensee's
- RE [[]]
TS. For each system modification (since the last inspection), the inspectors reviewed
Enclosure changes to the liquid or gaseous radioactive waste system design, procedures, or operation, as described in the
- FSAR and plant procedures, as applicable. The inspectors reviewed any changes that were made to the liquid or gaseous waste systems to verify that the licensee adequately evaluated the changes and maintained effluent releases
- ODCM made by the licensee since the last inspection to ensure consistency was maintained with respect to guidance in
NUREG-1301, 1302, and 0133 and Regulatory Guides 1.109, 1.21, and 4.1. If differences were identified, the inspectors reviewed the licensee's technical basis or evaluations to verify that the changes were technically justified and documented. For effluent monitoring instrumentation, the inspectors reviewed documentation to verify the adequacy of methods and monitoring of effluents, including any changes to effluent radiation monitor setpoints. The inspectors evaluated the calculation methodology and the basis for the changes to verify the adequacy of the licensee's justification. The inspectors reviewed the licensee=s program for identifying, assessing, and controlling contaminated spills and leaks. The inspectors also reviewed any new effluent
discharge pathways (such as significant continuing leakage to ground water that continues to impact the environment if not remediated) to verify that the
- OD [[]]
CM was updated to include the new pathway. The inspectors reviewed the radiological effluent release reports (Annual Monitoring Reports) for 2006 and 2007 in order to determine if
anomalous or unexpected results were identified by the licensee, entered in the CAP, and adequately resolved. The inspectors reviewed any significant changes in reported dose values among the 2005, 2006, and 2007 radiological effluent release reports and evaluated the factors which may have resulted in the change. If the change was not explained as
being influenced by an operational issue (e.g., fuel integrity, extended outage, or major decontamination efforts), the inspectors independently assessed the licensee=s offsite dose calculations to verify that the licensee's calculations were adequately performed and were consistent with regulatory requirements. No significant changes were
identified. The inspectors reviewed the licensee's correlation between the effluent release reports and the environmental monitoring results, as provided in Section
- CFR Part 50. In addition, the inspectors reviewed the licensee audit results to determine whether the licensee met the requirements specified by the
ODCM. This inspection constitutes one complete sample as defined in IP 71122.01-5. b. Findings No findings of significance were identified.
Enclosure .2 Onsite Inspection a. Inspection Scope The inspectors performed a walkdown of selected components of the gaseous and liquid discharge systems (e.g., demineralizers and filters (in use or in standby), tanks, and vessels) and reviewed current system configuration with respect to the description in the
- FS [[]]
AR. The inspectors evaluated temporary waste processing activities, system
modifications, and the equipment material condition. For equipment or areas that were not readily accessible, the inspectors reviewed the licensee's material condition surveillance records, as applicable. During system walkdowns, the inspectors assessed the operability of selected point of discharge effluent radiation monitoring instruments and flow measurement devices. The effluent radiation monitor alarm set point values were reviewed to verify that the set points were consistent with
- ODCM [[requirements. The inspectors discussed the licensee's sampling of liquid and gaseous radioactive waste (e.g., sampling of waste steams) and observed selected portions of the routine processing and discharge of radioactive effluents. The inspectors assessed whether the appropriate treatment equipment was used and whether the radioactive effluent was processed and discharged in accordance with]]
ODCM requirements, including the
projected doses to members of the public. The inspectors interviewed staff concerning effluent discharges made with inoperable (declared out-of-service) effluent radiation monitors to determine if appropriate compensatory sampling and radiological analyses were conducted at the frequency specified in the
ODCM. For compensatory sampling methods, the inspectors
reviewed the licensee's practices to determine if representative samples were obtained and if the licensee routinely relied on the use of compensatory sampling in lieu of adequate system maintenance or calibration of effluent monitors. The inspectors reviewed surveillance test results for non-safety-related ventilation and gaseous discharge systems for the containment purge and auxiliary building vent
systems (high efficiency particulate air and charcoal filtration) to verify that the systems were operating within industry acceptance criteria. In addition, the inspectors assessed the methodology the licensee used to determine the stack/vent flow rates to verify that the flow rates were consistent with the
- ODCM. The inspectors reviewed the licensee's program for identifying any normally non-radioactive systems that may have become radioactively contaminated to determine if evaluations (e.g.,
NRC Bulletin 80-10 ("Contamination of Nonradioactive Systems and Resulting Potential for Unmonitored, Uncontrolled Release to Environment"). The inspectors did not identify unidentified contaminated systems that may have been unmonitored discharge pathways to the
environment. The inspectors reviewed instrument maintenance and calibration records (i.e., both installed and counting room equipment) associated with effluent monitoring and reviewed quality control records for the radiation measurement instruments. The
Enclosure inspectors performed this review to identify any degraded equipment performance and to assess corrective actions, as applicable. The inspectors reviewed the radionuclides that were included by the licensee in its effluent source term to determine if all applicable radionuclides were included (within detectability standards) in the licensee's evaluation of effluents. The inspectors reviewed waste stream analyses (10 CFR Part 61 analyses) to determine if
hard-to-detect radionuclides were also included in the source term analysis. The inspectors reviewed the meteorological dispersion and deposition factors and the hydrogeologic characteristics used in the licensee's
- OD [[]]
CM and effluent dose calculations to verify that appropriate factors were used for public dose calculations. The inspectors also reviewed the most recent land-use census to verify that the licensee
had included any new public dose receptors or pathways. The inspectors reviewed the annual dose calculations to ensure that the licensee had properly demonstrated compliance with
TS dose criteria. The inspectors reviewed the licensee's implementation of the voluntary Nuclear Energy Institute (NEI)/Industry Ground Water Protection Initiative. The inspectors reviewed changes made to the Ground Water Protection Initiative, monitored results of the Ground
Water Protection Initiative, identified leakage or spill events and entries made into 10 CFR 50.75(g) records, and evaluations of leaks or spills, including any remediation actions taken for effectiveness. The inspectors reviewed licensee records to identify any abnormal gaseous or liquid tank discharges (e.g., discharges resulting from misaligned valves, valve leak-by, etc.) to determine if the licensee had implemented the required
actions. There were no abnormal effluent discharges since the last radioactive gaseous and liquid effluent monitoring inspection. The inspectors reviewed onsite contamination events involving contamination of ground water and assessed whether the source of the leak or spill was identified and mitigated. Since the last inspection, there were no unmonitored spills, leaks, or unexpected radioactive liquid or gaseous discharges. The inspectors reviewed licensee records to verify that significant leaks and spills were properly documented in the licensee=s
CFR 50.75(g). The inspectors reviewed the licensee's records to determine if sufficient radiological surveys were performed to
evaluate the extent of the contamination and the radiological source term, and the inspectors reviewed survey/evaluation records to verify that the licensee had considered hard-to-detect radionuclides, as applicable. The inspectors assessed if the licensee evaluated and analyzed any new or additional effluent discharge pathways as a result of a spill, leak, abnormal, or unexpected liquid discharge or gaseous discharges. The inspectors reviewed whether the licensee monitored groundwater discharges and determined if significant leaks and spills had been properly documented. The inspectors evaluated if the licensee's program included provision for required or voluntary offsite notifications to State and local officials and, if appropriate, to the NRC. The inspectors assessed the licensee's program that evaluated discharges from onsite surface water bodies (ponds, retention basins, lakes) that contain or potentially contain
Enclosure radioactivity and the potential for leakage from these onsite surface water bodies into the groundwater. The inspectors assessed if the licensee accounted for discharges from these surface water bodies as part of its effluent release reports and reviewed routine groundwater monitoring results to assess whether the licensee monitored for unknown leakage. The inspectors reviewed the licensee's records to verify that the licensee sufficiently evaluated monitoring results, properly documented and reported the results,
entered any abnormal results into its CAP, and implemented adequate corrective actions. Additionally, the inspectors reviewed the licensee's self-assessments, audits, and event reports that involved unanticipated offsite discharges of radioactive material. The inspectors reviewed the results of the inter-laboratory comparison program to assess the quality of radioactive effluent sample analyses. The inspectors reviewed the
licensee's effluent sampling records (sampling locations, sample analyses results, flow rates, and source term) for radioactive liquid and gaseous effluents to verify that the licensee's information satisfied the requirements of
- IP 71122.01-5. b. Findings Introduction: The inspectors identified a finding of very low safety significance and an associated
TS 5.4.1 for the failure to establish procedures necessary to
implement the effluent control program as provided in the
- OD [[]]
CM to ensure that analytical equipment used to quantify effluents could achieve detection limits. Description: The licensee used a multi-detector gamma spectroscopy system to analyze liquid and gaseous samples to quantify its effluent releases to the environment. Performance checks were performed daily on each detector prior to use to assess
detector response compared to a mixed gamma-emitting radionuclide standard and, thereby, to determine measuring system capability and stability. Lower limits of detection (LLDs) were required to be met for various radionuclides and geometries (e.g., liquid and gas samples, charcoal cartridge or particulate filter samples) to ensure effluents were quantified to meet
- ALA [[]]
RA design objectives. The detection capabilities
were based, in part, on the levels of background radiation present in the count laboratory, detector efficiency, and analysis parameters such as count time and volume. The inspectors identified that, from 2007 through October 2008, approximately 20 percent of the daily performance checks of the gamma spectroscopy system failed initial testing, but subsequently successfully met quality control standards after retesting
or following instrument repair. The instability was attributed by the licensee to detector age-related degradation, including repetitive instances of detector vacuum seal leakage. The inspectors identified that the licensee had not verified whether its spectroscopy system detectors could achieve the
ODCM/Radiological Effluent Control Manual (RECM) during the periods of instrument instability. According to the
licensee, a chemistry supervisor had periodically performed
- LLD determinations in the past, but those tests were discontinued unbeknownst to the licensee upon that person's employment termination in 2007. The licensee was unable to produce records to demonstrate when
LLD verifications were last performed. The inspectors identified that the licensee's quality control program for its gamma spectroscopy equipment was not fully governed by procedure or other institutionalized processes including procedures to
Enclosure ensure
- LLD determinations were verified periodically or as dictated by instrument performance. Sections 6.2 and 6.3 of the Point Beach
- ODCM by reference) required that radioactive liquid and gaseous waste be sampled and analyzed to meet specified
LLDs in order to verify that concentrations of radioactive material in effluents satisfied the dose objectives of Appendix I to 10 CFR 50. Technical
Specifications 5.4.1, 5.5.1, and 5.5.4 require that written procedures be established to implement the effluent control program as provided in the
- RECM. However, no procedures were established to ensure gamma spectroscopy equipment effluent analyses capabilities were periodically demonstrated to meet
- ODCM /RECM. Analysis: The inspectors determined that the licensee's failure to satisfy the requirements of
- TS 5.4.1 was a performance deficiency because the licensee failed to ensure adequate analytical instrument sensitivity to satisfy
- RECM requirements. The inspectors determined that the finding was more than minor in accordance with
IMC 0612, Appendix B, "Issue Screening," dated December 4, 2008, because it impacted the program and process attribute of the Public Radiation Safety Cornerstone
and affected the cornerstone objective of ensuring adequate protection of public health and safety from exposure to radioactive effluents. Specifically, given the instability in the licensee's gamma spectroscopy system since 2007, as evidenced by repetitive performance check failures, the ability of the equipment to achieve required LLDs could have been impacted or necessitated changes in analysis parameters (such as count
times) resulting in non-conservative effluent quantification. The finding was assessed using the Public Radiation Safety Significance Determination Process of IMC 0609, Appendix D, dated February 12, 2008, and was determined to be of very low safety significance because it was associated with the effluent release program but did not represent a substantial failure to implement that program or result in
public dose which exceeded specified criterion. The finding was determined to involve a cross-cutting aspect in the resource component of the human performance area, because the licensee failed to develop procedures to fully implement its effluent program as provided in the
- RECM. [[[H.2.(c)] Enforcement: Technical Specification 5.4.1, 5.5.1, and 5.5.4 require written procedures be established, implemented, and maintained for the effluent control program as provided in the]]
- RECM (Revision 4) require that radioactive liquid and gaseous effluents be sampled and analyzed to meet specified
LLDs. Contrary to these TSs, as of October 10, 2008, the licensee had not developed written procedures to implement its effluent control program
to ensure effluent analyses met required
LLDs could be achieved and developed
Enclosure procedure(s) to ensure LLDs were periodically determined as dictated by instrument performance consistent with industry standards. .3 Identification and Resolution of Problems a. Inspection Scope The inspectors reviewed the licensee's self-assessments, audits, licensee event reports, and Special Reports, as applicable, related to the radioactive effluent treatment and
monitoring program since the last inspection to determine if identified problems were entered into the
- CAP [[for resolution. The inspectors also assessed whether the licensee's self-assessment program was capable of identifying repetitive deficiencies or significant individual deficiencies in problem identification and resolution. The inspectors reviewed corrective action reports from the radioactive effluent treatment and monitoring program since the previous inspection, interviewed staff, and reviewed documents to determine if the following activities were 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]]
- NCV [[s tracked in the corrective action system; * implementation/consideration of risk-significant operational experience feedback; and * ensuring problems were identified, characterized, prioritized, entered into a corrective action, and resolved. This inspection constitutes one complete sample as defined in]]
- OTHER [[]]
- ACTIVI [[]]
- TIES [[]]
PI for Unit 1 and Unit 2 for the second quarter 2007 through the
second quarter of 2008. To determine the accuracy of this
- NEI Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 5, were used. The inspectors reviewed the licensee's operator narrative logs,
- NRC Enclosure integrated inspection reports for April 2007 through June 2008 to validate the accuracy of the submittals. The inspectors reviewed the
- MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable
NEI guidance. The inspectors also reviewed the licensee's issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator.
Documents reviewed are listed in the Attachment. This inspection constituted two
- IP 71151-05. b. Findings No findings of significance were identified. .2 Mitigating Systems Performance Index - High Pressure Injection Systems a. Inspection Scope The inspectors sampled licensee submittals for the
- PI for Unit 1 and Unit 2 for the second quarter 2007 through the second quarter 2008. To determine the accuracy of this
- NEI 99-02, Revision 5, were used. The inspectors reviewed the licensee's operator narrative logs, issue reports,
MSPI derivation reports, event reports, and NRC integrated
inspection reports for April 2007 through June 2008 to validate the accuracy of the submittals. The inspectors reviewed the
- MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable
NEI guidance. The inspectors also reviewed the licensee's issue report database to determine if any problems had been
identified with the
- PI data collected or transmitted for this indicator. Documents reviewed are listed in the Attachment to this report. This inspection constituted two
- IP 71151-05. b. Findings No findings of significance were identified. .3 Mitigating Systems Performance Index - Heat Removal System a. Inspection Scope The inspectors sampled licensee submittals for the
MSPI heat removal system PI for Unit 1 and Unit 2 for the second quarter 2007 through the second quarter of 2008. To
determine the accuracy of this
- NEI 99-02, Revision 5, were used. The inspectors reviewed the licensee's operator narrative logs, issue reports, event reports,
- NRC integrated inspection reports for April 2007 through June 2008 to validate the accuracy of the submittals. The inspectors reviewed the
- MS [[]]
PI component risk coefficient to determine if it had changed
by more than 25 percent in value since the previous inspection, and if so, that the
Enclosure change was in accordance with applicable
- NEI guidance. The inspectors also reviewed the licensee's issue report database to determine if any problems had been identified with the
- PI data collected or transmitted for this indicator. Documents reviewed are listed in the Attachment to this report. This inspection constituted two
- IP 71151-05. b. Findings No findings of significance were identified. .4 Mitigating Systems Performance Index - Residual Heat Removal System a. Inspection Scope The inspectors sampled licensee submittals for the
- PI for Unit 1 and Unit 2 for the second quarter 2007 through the second quarter 2008. To determine the accuracy of the
- NEI 99-02, Revision 5, were used. The inspectors reviewed the licensee's operator narrative logs, issue reports,
- NRC integrated inspection reports for April 2007 through June 2008 to validate the accuracy of the submittals. The inspectors reviewed the
- MS [[]]
PI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so,
that the change was in accordance with applicable
- NEI guidance. The inspectors also reviewed the licensee's issue report database to determine if any problems had been identified with the
- PI data collected or transmitted for this indicator. Documents reviewed are listed in the Attachment to this report. This inspection constituted two
- IP [[71151-05. b. Findings No findings of significance were identified. .5 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual (RETS/ODCM) Radiological Effluent Occurrences a. Inspection Scope The inspectors sampled licensee submittals for the]]
- PI for November 2007 through September 2008. The inspectors used definitions and guidance contained in
AR database and selected
individual ARs generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates between December 2007 and September 2008 to determine if indicator results
were accurately reported. The inspectors also reviewed the licensee's methods for
Enclosure quantifying gaseous and liquid effluents and determining effluent dose. Documents reviewed are listed in the Attachment to this report. This inspection constitutes one
OA2 Problem Identification and Resolution (71152) .1 Routine Review of items Entered Into the Corrective Action Program (CAP) a. Inspection Scope As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities
and plant status reviews to verify that they were being entered into the licensee's CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: the complete and accurate identification of the problem; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews and previous occurrences reviews were proper and adequate; and
the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue. Minor issues entered into the licensee's
- CAP [[as a result of the inspectors' observations are listed in the Attachment to this report. These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure, they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report. b. Findings No findings of significance were identified. .2 Daily]]
CAP Reviews a. Inspection Scope To assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensee's CAP. This review was accomplished through inspection of
the station's daily condition report packages. These daily reviews were performed by procedure as part of the inspectors' daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.
Enclosure b. Findings No findings of significance were identified. .3 Semi-Annual Trend Review a. Inspection Scope The inspectors performed a review of the licensee's CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The
inspectors' review was focused on repetitive equipment issues, but also considered the results of daily inspector
OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors' review nominally considered the six-month period of July 1, 2008, through December 31, 2008, although some examples expanded beyond those dates where the
scope of the trend warranted. The review also included issues documented outside the normal
- CAP [[in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensee's]]
CAP trending reports. Corrective actions associated with a sample of the issues
identified in the licensee's trending reports were reviewed for adequacy. The inspectors did note an apparent negative trend in the characterization of
- AR s characterized as either a condition adverse to quality or non-condition adverse to quality since the institution of the new fleet procedure in the second quarter of 2008. The licensee initiated
- AR 01141302 to assess the inspectors' observations. This review constituted one semi-annual trend inspection sample as defined in
- IP 71152-05. b. Findings No findings of significance were identified. .4 Annual Sample: Review of Operator Workarounds (
OWAs) a. Inspection Scope The inspectors evaluated the licensee's implementation of their process used to identify, document, track, and resolve operational challenges. Inspection activities included, but were not limited to, a review of the cumulative effects of the OWAs on system availability and the potential for improper operation of the system, for potential impacts on multiple
systems, and on the ability of operators to respond to plant transients or accidents. The inspectors performed a review of the cumulative effects of OWAs. The documents listed in the attached were reviewed to accomplish the objectives of the inspection procedure. The inspectors reviewed both current and historical operational challenge records to determine whether the licensee was identifying operator challenges at an
Enclosure appropriate threshold, had entered them into the CAP and proposed or implemented appropriate and timely corrective actions that addressed each issue. Reviews were conducted to determine if any operator challenge could increase the possibility of an initiating event, if the challenge was contrary to training, required a change from long-standing operational practices, or created the potential for inappropriate compensatory actions. Additionally, all temporary modifications were reviewed to
identify any potential effect on the functionality of mitigating systems, impaired access to equipment, or required equipment uses for which the equipment was not designed. Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified operator workarounds. This review constituted one operator workaround annual inspection sample as defined in
NP 2.1.4, "Operator Burdens," Revision 9, which was the licensee guidance document for the identification, tracking, and resolution of operator burdens, and the assessment of any adverse effects on plant operations created by operator burdens. In accordance with NP 2.1.4, operator workarounds were
required to be graded to assist in the prioritization of issues as well as to have the aggregate Probabilistic Risk Analysis (PRA) impact of the workarounds calculated. The inspectors identified that the numeric values listed as the "contribution of system failures to core damage frequency" in the procedure were not reflective of the current
PRA model was revised substantially in March 2008, but the new
risk numbers were not incorporated into
CAP. The licensee performed a reassessment of all open operator workarounds and found that neither the prioritization grades nor the aggregate impact factors changed appreciably when recalculated with the current PRA inputs. Therefore, the inspectors determined that this
issue was minor in nature. Additionally, the licensee has since revised
PRA model in the NP 2.1.4 procedure as previously done. No findings of significance were identified. .5 Selected Issue Follow-up Inspection: Review of Independent Self-Assessment of Engineering Effectiveness Introduction The inspectors selected several corrective and follow-up actions resulting from the 2007 Independent Assessment (Assessment Report) for a more in-depth review in accordance with inspection procedure requirements. This review constituted one inspection sample.
Enclosure a. Effectiveness of Problem Identification (1) Inspection Scope The inspectors reviewed the Assessment Report and resulting
- AR [[s to verify that the licensee's identification of issues was accurate and timely, and that the consideration of extent-of-condition review, generic implications, common cause, and previous occurrences was adequate. (2) Findings and Issues No findings of significance were identified. No issues were identified. b. Prioritization and Evaluation of Issues (1) Inspection Scope The inspectors reviewed]]
ARs and condition evaluations associated with issues identified in the Assessment Report. The nature and significance of individual issues and all issues in aggregate with respect to safety, risk, and licensee corrective action procedural requirements were considered. Additionally, the inspectors assessed the licensee's evaluation and disposition of performance issues, evaluation and disposition of operability issues, and application of risk insights for prioritization of issues. (2) Findings and Issues No findings of significance were identified. While evaluation of the identified issues was considered generally thorough, staffing remains an issue within certain engineering departments. Also, corrective action backlog reduction, principally in system engineering, remains a challenge for the licensee. c. Effectiveness of Corrective Actions (1) Inspection Scope The inspectors reviewed condition reports, licensee PIs, applicable procedures, and effectiveness reviews to determine if the licensee's corrective actions resulting from the 2007 Independent Assessment were effective. Additionally, the inspectors verified that established corrective actions by the licensee were appropriately focused to correct the problem. (2) Findings and Issues No findings of significance were identified. Engineering staffing and corrective action backlog reduction remain a challenge for the licensee; however, the licensee has continued to address these issues since the 2007 Independent Assessment and has made some progress.
Enclosure
- 4OA 3 Follow-up of Events and Notices of Enforcement Discretion (71153) .1 (Closed) Licensee Event Report
- LER 05000266/2007-008-00; 05000301/2007-008-00: Non-Conservative Low Temperature Overpressure Protection (LTOP) System Basis a. Inspection Scope On October 25, 2007, the
- LT [[]]
OP system actuation setpoints for Unit 1 and Unit 2 were found to be non-conservative and both systems were declared inoperable. The licensee
subsequently changed the setpoints and restored
- LTOP operability on October 26. The inspectors reviewed the circumstances surrounding this event and the licensee's evaluation of the event, the design basis of the
- LTOP system, and corrective actions taken. Documents reviewed as part of this inspection are listed in the Attachment. b. Findings Non-Conservative
- LTOP systems for Unit 1 and Unit 2 were non-conservative. Specifically, the licensee calculation, used for operation of the plants from 2000 through 2007, specified an
LTOP setpoint of 500 pounds per square inch-gauge (psig) as opposed to the correct setpoint of 420 psig. Description: Title 10 CFR Part 50, Appendix G, "Fracture Toughness Requirements," contains the requirements for pressure-temperature limits and minimum temperature of the reactor vessel. Table 1 of Appendix G contains the minimum temperature requirements for the condition and pressure of the reactor vessel. This table defines the closure flange region as the controlling material due to high stresses from the bolting
preload. It also defines the maximum allowable pressure as <20 percent of the system's pre-service hydrostatic test pressure, or 621 psig at Point Beach. This pressure is then used to calculate the
- EFPY [[[Effective Full Power Years] - Unit 1 and 34.0]]
- LTOP actuation setpoints for Point Beach Unit 1 and Unit 2. This calculation used beltline region weld properties to determine a maximum allowable pressure of 712.5 psig. Using this pressure, the
- LTOP setpoint was established at 500 psig. On February 2, 2004, the licensee received a Westinghouse
- LTOP system setpoint report. The Westinghouse report concluded the maximum allowable setpoints to prevent
- RCS pressure from exceeding the applicable Appendix G limits over the full range of temperatures when the
LTOP system was enabled, without any restrictions on the number of reactor coolant pumps (RCPs) running, was 390 psig. This calculation used a maximum allowable pressure of 621 psig (not 712.5 psig used by the licensee
calculation). This discrepancy was not identified by engineering personnel and no action was taken on the lower setpoint value at the time.
Enclosure On February 1, 2007, Westinghouse transmitted another
RCPs and charging pumps. This report also used the reactor vessel flange material as the limiting material and 621 psig as the maximum pressure allowed. The licensee again did not identify the discrepancy of the maximum allowable pressure used, nor was the issue of the lower
setpoint value entered into the
- LTOP setpoints were non-conservative based on a number of factors, such as safety injection pump flow rate changes, instrument delay times, and instrument uncertainties (AR 01114739). These factors were derived from a Westinghouse calculation,
NP, received by
the licensee in February 2007 and was not identified through the licensee's normal processes. An event notification was submitted to the
- NRC on October 25, 2007, when it was determined the setpoints were non-conservative for both units, and the
- LTOP systems for both units was restored on October 26, 2007, with setpoints set at 420 psig and the operating procedures changed to incorporate the specific operational restrictions of the
RCPs and charging pumps during low temperature conditions. On November 16, 2007, the licensee identified an additional discrepancy with calculation 2000-001 (AR 01116679). This discrepancy involved the use of the maximum allowable pressure of 712.5 psig instead of the maximum allowable pressure allowed by the requirements of Appendix G, 621 psig. Although there was some error associated with instrument uncertainties and pump flow rates, this discrepancy was determined to
account for the majority of the non-conservatism between the 500 psig and 420 psig setpoint values. The inspectors determined that the licensee had two previous opportunities to identify the design error in the
- LT [[]]
OP calculation (on February 2, 2004, and February 1, 2007); that the error was not found through a systematic licensee process; and that the error
was significant and visible to the organization. Therefore, this finding was determined to be self-revealed. Analysis: The inspectors determined that the use of an
- LTOP setpoint of 500 psig for approximately 8 years, which, when found to be non-conservative, led to the
- LTOP systems for Unit 1 and Unit 2 being declared inoperable, was a performance deficiency. The finding was determined to be more than minor in accordance with
- IMC [[0612, Appendix B, "Issue Screening," dated December 4, 2008, because the finding was associated with the human performance attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers, such as the]]
- RCS , protect the public from radionuclide releases caused by accidents or events. Specifically, the higher
- RCS pressure boundary would be maintained during low temperature conditions. The inspectors determined the finding could be evaluated using the
IMC 0609, "Significance Determination Process," Attachment 0609.04, "Phase 1 - Initial Screening and Characterization of Findings," Table 4a for the Barrier Integrity Cornerstone, dated January 10, 2008. The inspectors determined that
Enclosure the finding was of very low safety significance because all of the questions in the containment barrier column of Table 4a were answered
- NO , and because the actual setpoint of the power operated relief valves was always 415 psig, below the revised
- RCP s and charging pumps were never operated in a configuration that would have invalidated the 420 psig limit. The inspectors also determined that this finding has a cross-cutting aspect in the area of problem identification and resolution,
- CAP component, because personnel did not use a low threshold for identifying issues. Specifically, licensee personnel failed in February 2007 to enter the issue of the existence of a more conservative setpoint into the
- CAP , where an evaluation should have identified the error in the calculation. P.1(a) Enforcement: Title 10
CFR Part 50, Appendix B, Criterion III, "Design Control," requires, in part, that measures be established to assure that applicable regulatory requirements and the design basis are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, from March 2000 through October 2007, the licensee failed to translate applicable regulatory requirements into calculation 2000-001. Specifically, the calculation did not use the most limiting reactor vessel weld properties and maximum
allowable pressure as required by
- LTOP systems for Unit 1 and Unit 2. Because this violation was of very low safety significance and it was entered into the licensee's
NRC Enforcement Policy (NCV 05000266/2008005-06;
05000301/2008005-06). As an immediate corrective action, the licensee revised the
- LTOP setpoint from 500 psig to 420 psig and made changes to the operating procedures to incorporate the specific operational restrictions of the
- OA 5 Other Activities .1 (Closed) Unresolved Item (URI) 05000266/2007003-03; 050000301/2007003-03: Failure to Submit
- PTLR ) a. Inspection Scope The inspectors interviewed personnel and reviewed licensee records and procedures in an inspection of
- URI 2007003-03 concerning the licensee's potential use of an unapproved methodology to calculate the Unit 1
- PTLR upon its expiration in February 2004. b. Findings Introduction: The inspectors identified a finding of very low safety significance and associated Severity Level
- IV [[]]
NCV of Point Beach TS 5.6.5(c), "Reactor Coolant System
Enclosure (RCS) Pressure and Temperature Limits Report (PTLR)," for the failure to submit a revised Unit
- PTLR , Revision 2, was not submitted until November 15, 2007. Description: In May 2007, while reviewing Point Beach license amendment request 251 for
- PTLR as specified in the Safety Evaluation Report (SER) dated July 23, 2001, and the validity of the
- PTLR after this date. The following summarizes the sequence of events associated with this violation: * July 23, 2001: The
- NRC [[]]
- 1 PTLR as February 2004 based on actual plant operation history since the safety evaluation. The letter also stated the licensee still planned on submitting new curves that met
- PTLR. This change was screened under the 50.59 process but was not reviewed by the plant review committee or submitted to the
- NRC. This change may have led the licensee to make the incorrect assumption that they could change fluence periods, notably the 25.59
- PTLR curve applicability date for Unit 1 was valid until August 2004 based on fluence limits but no further details were provided. It appeared to the inspectors that the licensee's bases were fluence curves from Westinghouse report
- TS 5.6.5(c). * August 27, 2004: A corrective action document was closed-out to the statement that the
PTLR was valid until spring 2007. The licensee subsequently concluded in its investigation
Enclosure of the
- LTR -REA-04-64), although this time the fluence period applicability was derived from the unapproved
PTLR curves. * February 2006: Point Beach personnel determined the fluence data from the Westinghouse report were incorrectly used and that the calculated fluence limit for the limiting weld on Unit 1 was exceeded. Unit 1 operability was justified
using the recently approved generic version of the
- TS s 5.6.5(b) and 5.6.5(c). * December 14, 2006: Point Beach submitted a license amendment request to allow the use of
- FERRET code was used, which rendered previous calculations invalid. * November 15, 2007: Revision 2 of the
TS 5.6.5(c). Technical Specification 5.6.5(b) states, " The analytical methods used to determine the RCS pressure and temperature limits shall be those previously reviewed and approved
by the
- NRC [[]]
- EFPY. [[]]
- NRC upon issuance for each reactor vessel fluence period and for any revision or supplement thereto." On November 7, 2003, the licensee sent a letter to the
- 1 PTLR. Since the engineering staff incorrectly extended the fluence period of the existing curves, the
- PTLR for the new fluence period was a performance deficiency. The finding was determined to be more than minor in accordance with
IMC 0612, Appendix B, "Issue Screening," dated December 4, 2008, because the finding is associated with the design control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective to provide
reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the
- PTLR , which specifies plant operating conditions to ensure the integrity of the reactor vessel, was not valid after February 2004. This finding is not suitable for
SDP evaluation, but has been reviewed by NRC management and is determined to be a finding of very low safety significance.
Enclosure Subsequent calculations using an
- NRC [[-approved methodology determined that the Unit 1 reactor vessel was not outside of the safety limits and was fully capable of performing its required function. The inspectors did not identify a cross-cutting aspect associated with this finding because it was not determined to be indicative of current licensee performance. Enforcement: Point Beach]]
- NRC upon issuance for each reactor vessel fluence period and for any revision or supplement thereto." Contrary to this, on February 10, 2004, the licensee failed to submit a revised Unit
- 1 PTLR for the new fluence period. Specifically, the licensee inappropriately extended the fluence period of the existing
- PT [[]]
LR for the new fluence period that started in
February 2004. This violation was determined to be of very low safety significance; therefore, this violation of
- IV violation. Because this violation was of very low safety significance, was not repetitive or willful, and was entered into the licensee's
- URI is considered closed. .2 Implementation of Temporary Instruction (TI) 2515/176, "Emergency Diesel Generator
- TS Surveillance Requirements Regarding Endurance and Margin Testing" a. Inspection Scope The objective of
- TI 2515/176 was to gather information to assess the adequacy of nuclear power plant emergency diesel generator endurance and margin testing as prescribed in plant-specific
TI was forwarded to the Office of Nuclear Reactor Regulation for further review and evaluation on December 17, 2008. This TI is complete
at Point Beach; however, this
- TI 2515/176 will not expire until August 31, 2009. Additional information may be required after review by the Office of Nuclear Reactor Regulation. b. Findings No findings of significance were identified. 4
OA6 Management Meetings .1 Exit Meeting Summary On January 7, 2009, the inspectors presented the inspection results to Mr. L. Meyer and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was identified.
Enclosure .2 Interim Exit Meetings * Occupational Radiation Safety
- ALARA [[and Public Radiation Safety effluent control program inspection with Mr. L. Meyer and others on October 10, 2008, and with Mr. D. Frey and Mr. D. Farrell during a teleconference on November 7, 2008. * Baseline Inservice Inspection procedure 71111.08 with Mr. L. Meyer on October 24, 2008. * A telephone exit for]]
- J. [[Costedio, Licensing Manager, and other Licensee staff on December 1, 2008. * The annual review of Emergency Action Level and Emergency Plan changes with the licensee's Emergency Preparedness Manager, Mr. R. Freeman, via telephone on December 29, 2008. The inspectors confirmed that none of the potential report input discussed was considered proprietary.]]
- SUPPLE [[]]
- MENTAL [[]]
- INFORM [[]]
- SUPPLE [[]]
- MENTAL [[]]
- INFORM [[]]
- ATION [[]]
- KEY [[]]
- POINTS [[]]
- OF [[]]
ISI Program Engineer
- J. Bjorseth, Plant Manager D. Farrell, Radiation Protection Manager F. Flentje, Regulatory Affairs Supervisor R. Freeman, Emergency Preparedness Manager D. Frey, Chemistry Manager
- S. Forsha, Reactor Vessel Program Engineer D. Frey, Chemistry Manager J. Hofstra, Boric Acid Program Engineer B. Jensen,
SG Program Engineer
K. Locke, Regulatory Affairs Specialist L. Meyer, Site Vice-President Nuclear Regulatory Commission
J. Cushing, Point Beach Project Manager, Office of Nuclear Reactor Regulations M. Kunowski, Chief, Division of Reactor Projects, Branch 5
Attachment
- LIST [[]]
- OF [[]]
- ITEMS [[]]
- CLOSED [[]]
- AND [[]]
- DISCUS [[]]
- RCS with Inaccurate Pressurizer Level Indication Due to Inadequate Procedure (Section 1R20.1) 05000266/2008005-03
- NCV Failure to Appropriately Install Unit 1 Debris Interceptors in Accordance with Installation Work Order (Section 1R20.2) 05000266/2008005-04; 05000301/2008005-04
- NCV Inadequate Inspection Procedure for Containment Polar Crane Structures (Section 1R20.3) 05000266/2008005-05; 05000301/2008005-05
OA5.1)
Attachment
- LIST [[]]
- OF [[]]
- DOCUME [[]]
- NTS [[]]
- REVIEW [[]]
- ED The following is a partial list of documents reviewed during the inspection. Inclusion on this list does not imply that the
- NRC inspectors reviewed the documents in their entirety, but rather that selected sections or portions of the documents were evaluated as part of the overall inspection effort. Inclusion of a document on this list does not imply
NRC acceptance of the document or any part of it, unless this is stated in the body of the inspection report.
1R04 Equipment Alignment -
- CL 5C; Spent Fuel Pool Cooling and Refueling Water Circulating Pump Normal Operation Valve Lineup; Revision 12 -
CL 10B; Service Water Safeguards Lineup; Revision 62
-
- IT -09A; Cold Start of Turbine Driven Auxiliary Feed Pump and Valve Test (Quarterly) Unit 2; Revision 47 -
- NP 1.9.13; Ignition Control Procedure; Revision 13 1R07 Annual Heat Sink Performance - Bio/Silt Fouling Inspection Form for
CFC Silting Issues; November 10, 2006
-
- HX -01; Heat Exchanger Condition Assessment Program; Revision 6 1R08 Inservice Inspection Activities (
- NRC [[]]
NRC Field Observations During ISI Inspection
-
SI-843A
Attachment -
GS-14 - AR 01132185; 1P-2C Charging Pump has Boric Acid Build Up
-
AR 01127274; Issue Concerning "Pre" RCS Walkdown by Engineering Programs
-
SI-1051R-1-H3 Component Spring Support; dated April 30, 2007
-
- T. Leakage and Corrosion Monitoring Program,]]
VT-023; SG B Support; dated October 9, 2008
-
NRC 2008-0066; Supplement to License Amendment Request 257, Interim Alternate Repair Criteria for Steam Generator Tube Repair; dated July 18, 2008
Attachment -
- TRC -1918; Point Beach Unit Appendix H Techniques for Fall 2008 S/G Inspection; dated September 18, 2008 -
- ETTS 96004.1; Eddy Current Examination Technique Specification Sheet for Bobbin Coil Examination at Supports and Anti-vibration Bars; Revision 11 -
- ETTS 96511.2; Eddy Current Examination Technique Specification Sheet for +Point Examination of Low Row U-Bend Tubes; Revision 10 -
- ETTS 20510.1; Eddy Current Examination Technique Specification Sheet for +Point Detection of Circumferential Primary Water Stress Corrosion Cracking; Revision 11 -
- ETTS 21409.1; Eddy Current Examination Technique Specification Sheet for +Point Detection of Axial Outer Diameter Corrosion Cracking at Support Structures; Revision 5 -
- ETTS 21410.1; Eddy Current Examination Technique Specification Sheet for +Point Detection of Circumferential Outer Diameter Stress Corrosion Cracking at Expansions Transitions; Revision 6 -
- RCP Seal Injection Filter Inlet; dated October 6, 2008 - Repair/Replacement Form 2007-0031; dated April 12, 2007 - Weld Procedure Specification
PE-B312-P8P8-GTSM-037; Revision 3
- Welder Performance Qualification,
- QR -W-12; dated June 4, 1975 - Welder Procedure Qualification Record W-66; dated October 12, 1989 - Welder Procedure Qualification Record
- SM -8-8; dated September 18, 1973 - Welder Procedure Qualification Record 91-P8P8F6F5-2; dated November 21, 1991 1R11 Licensed Operator Requalification Program -
- CAP 01115710; Annual Operating Exam Security Lapse Results in Rework; dated November 1, 2007 1R12 Maintenance Rule Implementation -
AR 01101819; Abnormal Alignment May Be A Temporary Modification
-
MRE 01102651; T-180A Thru Wall Leak (K-003A Service Air Compressor) - SE-0360 Work Order Search - Service Air; September 1, 2006 to October 1, 2008 - Maintenance Rule Performance Criteria; Service Air; November 14, 2005 - Maintenance Rule Performance Criteria; Safety Injection; November 22, 2004 - Maintenance Rule (a)(1) System Action Plan Checklist and Approval; June 4, 2008 - Maintenance Rule Function List; Service Air; October 6, 2008
- Performance Criteria Assessments for
MR Evaluations; September 1, 2006 to September 1, 2008
Attachment - Search of Service Air Condition Reports; September 1, 2006 to October 1, 2008 - Service Air Report Data; September 2006 to September 2008 - Station Log Search for Service Air; September 18, 2006 to October 6, 2008 - Smart System Status Report for
- SI System; Status Date September 13, 2008 1R13 Maintenance Risk Assessments and Emergent Work Control -
NP 10.3.6; Shutdown Safety Review and Safety Assessment; Revisions 25, 26, 27, and 28 - Safety Monitor Calculation Reports for Units 1 and 2 for Applicable Work Weeks - Work Week Execution Schedules for the Applicable Work Weeks - Operator Logs for the Applicable Work Weeks - NP 10.3.7; Online Safety Assessment; Revision 19 - U1R31 Reduced Inventory Orange Path Contingency Plan
- U1R31 Shutdown Safety Profile; All Revisions 1R15 Operability Evaluations -
LEFM Was Found in a Failed State; December 18, 2008 - DBD-03; Condensate and Feedwater System; Revision 13
-
- LEFM ) 1R18 Plant Modifications - Point Beach Unit 1 Updated Deposit Characterization and Deposit Loading Estimate; Revision 0 - Point Beach Unit 1 Steam Generator Chemical Cleaning Process Qualification Test; Revision 0 1R19 Post-Maintenance Testing -
- WO 00362010; Inspect, Document Field Condition of Blots in Lateral Restraint #13, and Replace Bolts with Proper Pre-Torque Tension Values -
- TS 30; High and Low Head Safety Injection Check Valve Leakage Test Unit 1; Revision 31; Performed November 8, 2008 -
AFW Pump and Valve Test; Revision 49; completion dated 11/13/2008 - RMP 9332; Steam Driven Auxiliary Feedwater Pump Drain Trap Maintenance; Revision 8
Attachment -
AR 01139651; Discrepancy in Debris Interceptor B3
-
PZR Cold Cal Level Transmitter - AR 01138315; Split Project Anomalies from Westinghouse
-
- PB [[]]
NP 1 Polar Crane Bolt; October 23, 2008 - Engineering Evaluation; Polar Crane Bracket Bolt Preliminary Disposition
-
- NP 7.4.14; Boric Acid Leakage and Corrosion Monitoring - Licensee Response to Generic Letter 88-05; dated May 24, 1988 -
CL 4D; Outage Valve Inspection Unit 1; Revision 7
-
OP 1B; Reactor Startup; Revision 58 - OP 1C; Startup to Power Operation Unit 1; Revision 16
-
OP 4F; Reactor Coolant System Reduced Inventory Requirements; Revision 12 - OP 4G; Steam Generator Nozzle Dam Operational Requirements; Revision 4
-
RP 1A; Preparation for Refueling; Revision 79 - OI 11; Steam Generator Nozzle Dam Operation Guide; Revision 9
Attachment -
OP-ROM-01; Refueling Outage Management; Revision 3 - CL 2A; Defueled to Mode 6 Checklist for U1R31; Revision 11
-
CL 2E; Mode 3 to Mode 2 Checklist for U1R31; Revision 15 - CL 2F; Mode 2 to Mode 1 Checklist for U1R31; Revision 15 - Outage Additions and Deletions for U1R31 - U1R31 Reduced Inventory Orange Path Contingency Plan
- U1R31 Shutdown Safety Profile; All Revisions -
- RESP 1.2; Rod Control System: Rod Position Verification and Rod Position Indicator Alignment; Revision 10; Performed November 12, 2008 -
AR 01139357; Field Voltage Recorded Reading Below Acceptance Criteria
-
- 1EP 4 Emergency Action Level and Emergency Plan changes - Point Beach Nuclear Plant Emergency Plan Manual; Section 7.0; Revisions 51 and 52 - Point Beach Nuclear Plant Emergency Plan Manual; Appendix A; Revisions 26 and 27 - 10
AR 01120634; Radiological Posting in Plant Is Overly Conservative - AR 01127857; Unit 2 Fuel Movement Postings
Attachment -
RWP Violation - Auxiliary Operator Qualification Status Matrix; dated October 09, 2008 - PBF-4246; Radiological Pre-Job Briefing Form; Revision 01
-
- HP 3.2; Health Physics Manual; Radiological Labeling, Posting and Barricading Requirements; Revision 48 -
NP 4.2.19; Entry Requirements into Radiologically Controlled Areas; Revision 13
-
TRQM 17.31; Auxiliary Operator Health Physics; Revision 12 2PS1 Radioactive Gaseous and Liquid Effluent Treatment and Monitoring Systems - Point Beach Nuclear Plant Annual Monitoring Report for 2006 (issued April 28, 2007) and for 2007 (issued April 30, 2008) - Point Beach Nuclear Plant Offsite Dose Calculation Manual; Revision 18
- Point Beach Nuclear Plant Radiological Effluent Control Manual; Revision 4 - Point Beach Nuclear Plant
- SPI [[]]
NG; dated February 11, 2008
-
HPCAL 3.8; Calibration for Drumming Area Vent Stack Monitor; dated July 16, 2008
-
- HPC [[]]
AL 3.13; Calibration for U-1 Steam Generator Blowdown Monitor; dated August 12, 2008
-
- AR 01127172; Validation of Point Beach Nuclear Plant 2007 Annual Monitoring Report; dated May 1, 2008 -
AR 01108334; Radioiodine Results High - Evaluate for Annual Monitoring Report Impact
-
- RETSCO [[]]
DE Software; Revision 7 - RMS System Health Report; dated December 6, 2007
-
- HP [[]]
IP 3.52.1; Radiological Sampling for Release Accountability; Revision 26 - Results of Gamma Spectroscopy System Daily Performance Checks; selected dates between June 2007 and October 2008 - Results of Point Beach Nuclear Plant Inter-laboratory Radiological Crosscheck Program; dated April 12, 2007
Attachment - Ventilation System Filter In-Situ Test Results for Unit-1/2 Containment Purge Exhaust and Auxiliary Building Vent Stack; dated June 23, 2008 (and associated laboratory radioiodine penetration test reports; dated August 18 and 19, 2008) -
- CAMP 310; Operation of the Canberra Genie 2000/Procount Gamma Spectroscopy Counting System; Revision 6 - Florida Power & Light Self-Assessment Report;
- NEI Industry Groundwater Protection Initiative; dated August 6, 2008 - Point Beach Nuclear Oversight Assessment Report;
- 4OA 1 Performance Indicator Verification - Point Beach Nuclear Plant Effluent Dose Estimate Summary Data and Quarterly
- NRC Performance Indicator Results; dated November 2007 and September 2008 - Point Beach Nuclear Plant Liquid and Gaseous Effluent Monthly Data Inputs; dated December 2007, March 2008 and September 2008
AA-204; Condition Identification and Screening Process; Revision 1 - Condition Reports initiated between October 1, 2008 and December 31, 2008 - NP 2.1.4; Operator Burdens; Revision 9
-
- LT [[]]
OP Setpoint may be Non-Conservative
-
PT-EDG-011; G-01 Emergency Diesel Generator Endurance and Margin Testing Revision 2 - O-PT-EDG-021; G-02 Emergency Diesel Generator Endurance and Margin Testing; Revision 0 - O-PT-EDG-031; G-03 Emergency Diesel Generator Endurance and Margin Testing;
Revision 0 - O-PT-EDG-041; G-04 Emergency Diesel Generator Endurance and Margin Testing - Calculation 2004-0002; Emergency Diesel Steady State Loading Analysis; Revision 2 -
NMC; Acceptance of Methodology for Referencing Pressure Temperature Limits Report; July 23, 2001
Attachment - Letter from
- NRC 2003-0108; Revision of Pressure Temperature Limits Expiration Dates; November 7, 2003 - Letter from
- NRC 2006-090; License Amendment Request 251 - Technical Specification 5.6.5, Reactor Coolant System Pressure and Temperature Limits Report (Request for use of
- NRC 2007-0092, Revision 2 of the Pressure and Temperature Limits Report for Point Beach Nuclear Plant - Units 1 and 2, Rev 2; November 15, 2007 -
- WCAP -15976; Point Beach Unit 1 and 2 Heatup and Cooldown Curves for Normal Operations, February 13, 2003 -
- NMC [[]]
- PBNP Units 1 and 2 Aging Management Blanket Task 15, Reactor Vessel Additional Information; June 4, 2004 -
- PT [[]]
LR Applicability in year 2005 (closed June 1, 2005)
Attachment
- LIST [[]]
- OF [[]]
- ACRONY [[]]
- MS [[]]
- USED [[]]
- FS [[]]
- NRC [[]]
- PT [[]]
SG Steam Generator SI Safety Injection
Attachment