IR 05000397/2014003
| ML14218A199 | |
| Person / Time | |
|---|---|
| Site: | Columbia  |
| Issue date: | 08/06/2014 |
| From: | Taylor N H NRC/RGN-IV/DRP/RPB-D |
| To: | Reddemann M E Energy Northwest |
| Hagar R C | |
| References | |
| IR-14-003 | |
| Download: ML14218A199 (60) | |
Text
August 6, 2014
Mr. Chief Executive Officer Energy Northwest P.O. Box 968, Mail Drop 1023 Richland, WA 99352-0968
SUBJECT: COLUMBIA GENERATING STATION NRC INTEGRATED INSPECTION REPORT 05000397/2014003
Dear Mr. Reddemann:
On June 23, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Columbia Generating Station. On June 26, 2014, the NRC inspectors discussed the results of this inspection with Mr. Bruce MacKissock, Plant General Manager, and other members of your staff. The inspectors documented the results of this inspection in the enclosed inspection report. NRC inspectors documented six findings of very low safety significance (Green) in this report. Five of these findings involved violations of NRC requirements. Additionally, NRC inspectors documented one Severity Level IV violation with no associated finding. Further, inspectors documented three licensee-identified violations which were determined to be of very low safety significance in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region IV; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident inspector at the Columbia Generating Station. If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region IV; and the NRC resident inspector at the Columbia Generating Station. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA Signed by Robert C. Hagar for/ Nicholas H.Taylor, Chief Project Branch D Division of Reactor Projects Docket No.: 50-397 License No: NPF-21 Enclosure: Inspection Report 05000397/2014003 w/ Attachments 1. Supplemental Information 2. Requested Items for Occupational Radiation Safety Inspection
SUNSI Review By: NTaylor ADAMS Yes No Publicly Available Non-Publicly Available Non-Sensitive Sensitive OFFICE RIV/DRP RIV/DRP RIV/DRP RIV/DRS RIV/DRS RIV/DRS RIV/DRS NAME JGroom/dll DBradley RHagar TFarnoltz JDixon VGaddy MHaire SIGNATURE /RA/E-Hagar /RA/E-Hagar /RA/ /RA/ /RA/ /RA/ /RA/ DATE 8/4/14 8/4/14 8/6/14 7/24/14 7/31/14 7/31/14 7/31/14 OFFICE RIV/DRS RIV/TSB RIV/DRP NAME HGepford GMiller NTaylor SIGNATURE /RA/ /RA/ /RA/Hagar for DATE 7/31/14 8/4/14 8/6/14 Letter to M.E. Reddeman from Nicholas H. Taylor dated August 6, 2014 SUBJECT: COLUMBIA GENERATING STATION NRC INTEGRATED INSPECTION REPORT 05000397/2014003 DISTRIBUTION: Regional Administrator (Marc.Dapas@nrc.gov) Deputy Regional Administrator (Kriss.Kennedy@nrc.gov) Acting DRP Director (Troy.Pruett@nrc.gov) Acting DRP Deputy Director (Michael.Hay@nrc.gov) DRS Director (Anton.Vegel@nrc.gov) DRS Deputy Director (Jeff.Clark@nrc.gov) Senior Resident Inspector (Jeremy.Groom@nrc.gov) Resident Inspector (Dan.Bradley@nrc.gov) Administrative Assistant (Douglas.Bodine@nrc.gov) Acting Branch Chief, DRP/D (Nick.Taylor@nrc.gov) Senior Project Engineer, DRP/D (Bob.Hagar@nrc.gov) Project Engineer, DRP/D (Brian.Parks@nrc.gov) Public Affairs Officer (Victor.Dricks@nrc.gov) Public Affairs Officer (Lara.Uselding@nrc.gov) Project Manager (Sikhindra.Mitra@nrc.gov) Branch Chief, DRS/TSB (Geoffrey.Miller@nrc.gov) RITS Coordinator (Marisa.Herrera@nrc.gov) ACES (R4Enforcement.Resource@nrc.gov) Regional Counsel (Karla.Fuller@nrc.gov) Technical Support Assistant (Loretta.Williams@nrc.gov) Congressional Affairs Officer (Jenny.Weil@nrc.gov) RIV/ETA: OEDO (Anthony.Bowers@nrc.gov) Enclosure - - Six findings of very low safety significance (Green) are documented in this report. Five of these findings involved violations of NRC requirements. Additionally, NRC inspectors documented in this report one Severity Level IV violation with no associated finding and three licensee-identified violations of very low safety significance. -- - ------ The improper installation of breaker E-CB-S5 resulted in an ---- The finding was more than minor because it affected the configuration control attribute of the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. it did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding has a cross-cutting aspect in the area of human performance because the licensee failed to ensure that tools, equipment and other resources were available to adequately support verification of breaker racking activities [H.1]. (Section 4OA2) - ----- --- This finding has a cross-cutting aspect in the area of human performance associated with change management because the licensee failed to use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority [H.3.] --- - The inspectors reviewed a Green non-cited violation for the licensee's failure to properly pre-plan calibrations of differential pressure controllers used to maintain secondary containment pressure. Specifically, the licensee failed to establish and maintain the appropriate gain settings for the reactor building normal ventilation system differential pressure controllers in accordance with procedure DES-2- As a corrective action, the licensee properly adjusted the gain settings for the affected controllers. This performance deficiency was more than minor because it affected the equipment performance attribute of the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the failure to establish and maintain configuration control of reactor building ventilation differential pressure controllers resulted in multiple instances of unplanned inoperability of secondary containment. The finding is of very low safety significance (Green) because the finding only represents a degradation of the radiological barrier function provided for by the standby gas treatment system. This finding had a cross-cutting aspect in the area of problem identification and resolution because the licensee failed to thoroughly evaluate concerns related to the operation of the normal reactor building differential pressure controller such that the resolution addressed the causes of the observed sluggish response [P.2]. (Section 4OA3) --which Safety- The inspectors identified a non-cited violation involving 10 CFR 50.73, licensee failed to submit a required licensee event report, within specified time limits, for an unanalyzed condition involving unfused DC ammeters. The inspectors determined that the failure to make a required licensee event report within the time limits specified in regulations was a violation of 10 CFR 50.73. The violation was evaluated using Section 2.2.4 of the NRC Enforcement Policy, because the failure to submit a required licensee event report may impact the ability of the NRC to perform its regulatory oversight function. As a result, this violation was evaluated using traditional enforcement. In accordance with Section 6.9 of the NRC Enforcement Policy, this violation was determined to be a Severity Level IV, non-cited violation. The team determined that a cross-cutting aspect was not applicable because the issue involving untimely reports to the NRC was strictly associated with a traditional enforcement violation. (Section 4OA3) - a. -- --- -- -- b. a. - - b. - -- - Introduction. The inspectors identified a Green non-cited violation of 10 CFR Part 50, corrective actions to address identified weaknesses in the preventative maintenance program. Specifically, the licensee failed to perform required inspections of the residual-heat-removal and low-pressure core spray pumps which were identified during an extent-of-cause evaluation following the failure of service water pump 1A in June 2005. Description. On June 14, 2005, plant operators declared standby service water pump SW-P-1A inoperable after identifying abnormally low pump discharge pressure and flow. On June 18, 2005, during an inspection of SW-P-1A, the licensee identified that the degraded pump performance was due to a failure of the pump shaft and wear of the pump impeller and bowl. Following identification of the failed shaft on SW-P-1A, the licensee determined that SW-P-1B could be susceptible to a similar failure mechanism. Similar to SW-P-1A, a subsequent inspection of the as-found condition of SW-P-1B identified a failure of one pump shaft segment and wear of the pump impeller and bowl. The licensee initiated Problem Evaluation Request (PER) 205-0417 documenting the failure of SW-P-1A and PER 207-0716 documenting the as-found conditions of SW-P-1B. The licensee classified those conditions as significant conditions adverse to quality. oot cause evaluation for PER 205-0417 identified that the degraded conditions discovered on the service water pumps were attributed to a failure of the preventative maintenance program. standby service water pumps had not received any preventative maintenance such as time-based inspection or replacement because their maintenance program lacked sufficient rigor to establish and implement adequate preventative maintenance bases and allowed a maintenance program driven by condition monitoring. The extent-of-cause section of the root-cause evaluation identified that the lack of rigor in the preventative maintenance program extends to all components in the plant. To address these potential shortcomings in the preventative maintenance program, the licensee identified the following corrective action to prevent recurrence (CAPR): PER 205-0417, CAPR-01: Implement preventative maintenance bases through model work orders for critical components. On April 28, 2006, PER 205-0417, Action 1 implemented the preventative maintenance bases through model work orders. This action included implementation of Preventative Maintenance Background Information Document BID-PUMP-Maintenance Background Information Large Pumps (PUMP-Preventative Maintenance Task 24.6, to sample inspect one of the residual-heat-removal and low-pressure-core-spray pumps every ten years. The licensee created Model Work Orders 1132200, 1132201, 1132202 and 1132203 for inspection of the low pressure core spray and residual heat removal pump on March 8, 2007. The licensee planned for an inspection of residual heat removal pump RHR-P-2B in Refueling Outage R18 which began in May 2007. eview of PER 205-0417 determined, in part, that CAPR-01 was effective based on the scheduled inspection of pump RHR-P-2B. The inspectors reviewed the maintenance history for the low pressure core spray and residual heat removal pumps and found that the licensee did not inspect pump RHR-P-2B in Refueling Outage R18. The inspectors also found that the licensee had not performed a substitute inspection of any pump in this group in accordance with BID-PUMP-1. dure SWP-CAP-01, -28, states that a CAPR that is changed or canceled requires approval of the corrective action review board (CARB). However, the inspectors found no documentation to indicate that the CARB had approved changing or cancelling CAPR-01 for PER 205-0417. The inspectors therefore concluded that the licensee had not implemented corrective actions for identified weaknesses associated with the preventative maintenance program. The inspectors determined that inspection of the residual heat removal and low pressure core spray pumps was particularly important because NRC Part 21 Report 1998-51-1, issue involving broken cast iron suction heads in type APKD pumps. The Columbia Generating Station residual heat removal and low pressure core spray pumps are type APKD pumps. The Part 21 report recommended that the pumps be inspected at reasonable intervals for possible damage to the suction head, suction head journal sleeve, and retaining key. The inspectors also noted that RHR-P-2B was recently replaced in May 2013 because of observed degraded performance. Following identification of this issue, the licensee initiated AR 301887301887documenting that required inspections of the residual heat removal and low pressure core spray pumps had not been performed. The licensee also requested the residual heat removal pump vendor conduct an inspection of the internals of pump RHR-P-2B that was removed in May 2013. Analysis. The failure to take corrective actions to address the extent-of-cause identified in PER 205-0417 involving weaknesses in the preventative maintenance program was a performance deficiency. This finding was more than minor because, if left uncorrected, the failure to periodically inspect the residual heat removal and low pressure core spray pumps could become a more significant safety concern. Specifically, because these pumps are vulnerable to the failure described in NRC Part 21 Report 1998-51-1 involving broken cast iron suction heads in type APKD pumps, the failure to inspect the pumps could result in unrecognized degraded conditions on these components that could potentially affect pump performance. The inspectors initially screened the finding in accordance with NRC Manual Chapter IMC 0609, Appendix A, "The Significance Determination Process (SDP) for Findings At-Power." ermined this finding is of very low safety significance (Green) because: (1) the finding was not a deficiency affecting the design or qualification of a mitigating system; (2) the finding did not represent a loss of system and/or function; (3) the finding did not represent an actual loss of function of a single train for greater than its technical specification allowed outage time; and (4) the finding does not represent an actual loss of function of one or more non-technical specification trains of equipment designated as high safety-significant in accordance with the The inspectors determined that this finding did not have a cross-cutting aspect because the decision to defer required inspections of the residual heat removal pumps and low pressure core spray pumps was made in May 2007 and was not reflective of current performance. Enforcement. Title 10 of the Code of Federal Regulations, Part 50, Appendix B, to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances are identified and corrected. Contrary to the above, from April 28, 2006, through January 29, 2014, measures established by the licensee did not assure that a condition adverse to quality was corrected. Specifically, for the condition adverse to quality described in PER 205-0417 which the licensee characterized as a lack of rigor in the preventative maintenance program, the licensee developed corrective actions as CAPR-01, but did not implement those corrective actions between April 28, 2006, and January 29, 2014. Because this corrective action program as AR 301887301887 the violation is being treated as a non-cited violation consistent with Section 2.3.2.a of the NRC Enforcement Policy: NCV 5000397/2014003- - -- - --- -- - a. - - Introduction. The inspectors identified a Green non-cited violation of Technical Specification 5.4.1.a for the failure to ensure operators could perform time-critical steps for fire events. Description. On September 2, 2013, at 2003, the Shift Manager authorized the Equipment Operator designated as OPS3 to leave the PA to compile equipment logs. PPM 1.3.1, classifies watch positions as either Category 1 or Category 2. Category 1 includes personnel such as the Staff Technical Advisor and Emergency Action Level Notifier, while Category 2 includes not only the Shift Manager, all three Reactor Operators, and the Control Room Supervisor, but also the Equipment Operator positions designated as OPS2 and OPS3. PPM 1.3.1 states that while Category 1 personnel may leave the PA with a risk evaluation and permission of the Shift Manager, Category 2 personnel, Licensee procedure ABN-CR-room fire. Specifically for post-fire safe-shutdown, Category 2 personnel must complete certain actions within 10 minutes. Based on questions from the resident inspectors on May 16, 2014, the licensee performed a timed walkthrough of post-fire safe-shutdown actions for Equipment Operator OPS3. That walkthrough found that from outside the PA, the OPS3 Equipment Operator was not able to complete certain post-fire safe-shutdown actions within 10 minutes. Instead, the OPS3 operator completed those actions within 11 minutes and 33 seconds. The inspectors concluded that by allowing Category 2 personnel to leave the PA, the licensee had not preserved the assumptions of available personnel in ABN-CR-EVAC to reach safe-shutdown conditions for a control room fire. Therefore, licensee was not implementing written procedures for plant fires and responsibilities for safe operation as required by Technical Specification 5.4.1.a through Appendix A of Regulatory Revision 2. In response to this conclusion, the licensee initiated AR 306204306204to document the non-compliance with PPM 1.3.1 and to perform a cause evaluation. Additionally, the licensee issued Night Order 1527, reminding all operating crews of the requirements of PPM 1.3.1 for leaving the PA. The licensee initiated AR 307879307879to document the inability to meet the post-fire safe-shutdown actions in 10 minutes during a timed walkthrough. The inspectors considered that the Shift Manager who authorized the OPS3 operator to leave the protected area on September 2, 2013, had deviated from PPM 1.3.1, in that he had authorized an activity that was not allowed by that procedure. The Shift Manager did not follow the instructions in procedure SWP-PRO-describes how to deviate from or change a procedure. The inspectors considered that if the Shift Manager had followed the instructions in SWP-PRO-01, he likely would have recognized the nuclear-safety impact of the OPS3 operator leaving the protected area, and, consequently, would not have authorized the OPS3 operator to leave the protected area. The inspectors therefore considered the cause of this finding to be the Shift Manager deviated from PPM 1.3.1 without using the process described in SWP-PRO-01. The failure to implement written procedures to ensure that Category 2 personnel can complete certain post-fire safe-shutdown actions within 10 minutes was a performance deficiency.it was associated with the protection against external factors attribute of the Mitigating reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors screened the finding in accordance with NRC Manual Chapter IMC 0609, AttInitial Characterization of Findings. In table 3, the inspectors answered yes to question E.2 because the finding affects the ability to reach and maintain safe shutdown conditions in case of a fire. Therefore, to assess this finding a senior reactor analyst used NRC IMC 0609, Appendix F, 013. The analyst noted that the degradation rating examples in Attachment 2 of that appendix were not well suited for this finding. Therefore, the analyst used the generic guidance from NRC IM Determination Process (Supplemental Guidance for Implementing IMC 0609, Appendix F) At Power Operatiostated, in part: of the fire protection feature is not substantially impacted by the noted degradation finding. Hence, the feature would be given essentially full credit in the PRA-based analysis. In this case, the risk change is essentially zero, and the finding should be screened to Green. For this finding, procedure ABN-CR-EVAC directed operator OPS3 to trip the condensate and condensate booster pumps within 10 minutes, but due to this finding, that action could be delayed to the 11.5 minute point. The subject action was intended yst noted that the failure to take this action would not increase the core damage probability. (Overfilling events at boiling water reactors soon after shutdown should not drive core damage and are not included in the probabilistic risk assessment model.) Instead, this action is a desired step that was intended to establish positive control over reactor vessel pressure and level. In addition, the exposure period for this finding was very short (less than one day). Since the failure to perform this action within 10 minutes would not adversely affect a quantitative assessment, this finding was of very low safety significance (Green). Because the cause of this finding was that the licensee had deviated from procedure PPM 1.3.1 that was not part of a systematic process and did not prioritize nuclear safety, this finding has a cross-cutting aspect in the area of human performance associated with change management because the licensee failed to use a systematic process for evaluating and implementing change so that nuclear safety remains the overriding priority [H.3]. Technical Specification 5.4.1.a requires, in part, that written procedures shall be established, implemented, and maintained for activities described in Appendix A of the Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, Section 1.b requires administrative procedures for authorities and responsibilities for safe operation and shutdown. Contrary to this requirement, on September 2, 2013, the licensee failed to implement procedures for authorities and responsibilities for safe operation and shutdown. Licensee procedure PPM 1.3.1, evision 117 establishes authorities and responsibilities for safe operation and shutdown and states that Category 2 personnel should not leave the protected area unless an emergent condition is jeopardizing the plant and they respond to an event that requires action within 10 minutes. On September 2, 2013, a Category 2 equipment operator left the protected area when no emergent condition existed. Consequently, the operator was not able to complete certain time-critical operator actions associated with fire events as required by procedure ABN-CR-EVAC. The licensee restored compliance by initiating AR 306204306204to document the non-compliance with PPM 1.3.1 and to perform a cause evaluation. Additionally, the licensee issued Night Order 1527 reminding all operating crews of the requirements of PPM 1.3.1 for leaving the Protected Area. Because this violation was of very low safety AR 303216303216 this violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy: NCV 05000397/2014003-02. Implement Procedures That Ensure Operators Could Perform Time Critical Steps for - - - - - April 14, 2014, post-maintenance test of service water temperature control valve SW-TCV-11A following maintenance under Work Order 02048371 April 17, 2014, post-maintenance test of high pressure core spray condensate storage tank test bypass valve control switch following replacement under Work Order 0203005505 --- ---- - - - -- -- -- a. - -- -- -- -- - -- o o o o -- - b. -- The inspectors assessed licensee performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA) Site-specific ALARA procedures and ollective exposure history, including the current 3-year rolling average, site-specific trends in collective exposures, and source-term measurements ALARA work activity evaluations/post-job reviews, exposure estimates, and exposure mitigation requirements The methodology for estimating work activity exposures, the intended dose outcome, the accuracy of dose rate and man-hour estimates, and intended versus actual work activity doses and the reasons for any inconsistencies Records detailing the historical trends and current status of tracked plant source terms and contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry - Introduction. The inspectors reviewed a Green, self-revealing, non-cited violation of Technical Specification 5.7.2control a high radiation area with radiation levels greater than 1 rem/hour. Description. On June 8, 2013, as part of the reactor pressure vessel reassembly during Refueling Outage R-21, licensee personnel removed the moisture separator from its temporary storage in the dryer-separator pool and encountered higher than anticipated radiation dose rates. They were alerted to the higher dose rates when two workers received electronic dosimeter dose rate alarms. The applicable radiation work permit had established a dose rate setpoint of 0.8 rem/hour. The head rigger, who was directing the overhead crane operator and was closest to the moisture separator, entered a field of 1.7 rem/hour. A radiation protection technician measured 2 rem/hour at one point on the auxiliary bridge, near where the head rigger was standing. Another worker, who was helping ensure the moisture separator was positioned correctly, entered a field of 0.898 rem/hour, according to his electronic dosimeter. Licensee personnel continued the evolution until the moisture separator was placed safely on the reactor pressure vessel and submerged in the reactor pool. Licensee personnel stated it typically took about five minutes to move the moisture separator from the temporary storage pool to its position on the reactor pressure vessel in the reactor pool. The head rigger received the highest dose (0.068 rem). Licensee personnel documented the occurrence in the corrective action program and investigated the dose rate alarms. During this investigation, licensee personnel recognized the refueling floor had not been posted as a high radiation area. They determined the apparent cause for the lack of posting and initiated corrective actions. In the apparent cause evaluation, licensee personnel identified problems with planning, controlling, and executing the work activity. For example, the ALARA planning personnel incorrectly categorized the movements of the dryer and the moisture have required additional planning, barriers, and oversight.) At one point following a survey by a radiation protection technician, the crane operator raised the moisture separator until 12 to 18 inches of the moisture separator was above the surface of the water and then moved it horizontally with no hold point to allow the radiation protection technician to evaluate the change in work area dose rates. At another point, the head rigger rode the auxiliary bridge closer to the exposed moisture separator than had been planned and discussed in the pre-job briefing. The inspectors reviewed in addition to the failure to post the high radiation area, the licensee failed to implement barricading and flashing lights (for areas with dose rates greater than 1 rem/hour) as required by the technical specifications. Although the licensee identified planning deficiencies, the final collective dose for the work activity did not exceed the planned dose by 50 percent and did not exceed 5 person-exceeded 10 CFR Part 20 dose limits. The inspectors reviewed the moisture separator dose rate information from the final safety analysis report and concluded it was not possible to construct a reasonable scenario in which a minor alteration of circumstances would have resulted in a violation of the 10 CFR Part 20 limits. The inspectors confirmed the workers wore passive dosimetry certified by the National Voluntary Laboratory Accreditation Program and electronic dosimetry calibrated periodically by the so there was no problem assessing the workers doses. Analysis. The failure to control a high radiation area with radiation levels greater than 1 rem/hour is a performance deficiency. The requirement not met was Technical Specification 5.7.2. Pool areas do not have to be controlled as high or very high radiation areas solely because of the materials in them provided control measures are implemented to ensure that activated materials are not raised above or brought near the surface of the pool water. However, licensee personnel did not implement appropriate control measures. As a result, they raised activated material, in the form of portions of the moisture separator, above or near the surface of the dryer/separator pool water, creating a high radiation area with a dose rate greater than 1 rem/hour without implementing the required high radiation area controls. The performance deficiency was more than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of program and process (exposure control) and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation because licensee personnel did not implement barriers intended to prevent workers from receiving unexpected dose. Using Inspection Manual safety significance because: (1) it was not an as low as is reasonably achievable (ALARA) finding, (2) there was no overexposure, (3) there was no substantial potential for an overexposure, and (4) the ability to assess dose was not compromised. This finding has a cross-cutting aspect in the human performance area, associated with the work management component, because the organization did not implement a process of planning, controlling, and executing work activities such that nuclear safety is the overriding priority [H.5]. Enforcement. Technical Specification 5.7.2, states, in part, that individual areas with radiation levels greater than or equal to 1 rem/hour (at 30 centimeters from the radiation source), accessible to personnel, that are located within large areas such as reactor containment, where no enclosure exists for purposes of locking, or that is not continuously guarded, and where no enclosure can be reasonably constructed around the individual area, shall be barricaded and conspicuously posted, and a flashing light shall be activated as a warning device. Contrary to these requirements on June 8, 2013 an individual area with radiation levels greater than 1 rem/hour (at 30 centimeters from the radiation source), accessible to personnel, located within reactor containment where no enclosure existed for purposes of locking was not barricaded and conspicuously posted, and a flashing light was not activated as a warning device for the area. Specifically, locked high radiation area controls were not established around the dryer separator pool when the moisture separator was lifted from the pool, resulting in a radiation worker being exposed to a dose rate of 1.7 rem/hour. Licensee representatives stated this evolution typically lasts for approximately five minutes. Licensee personnel corrected the immediate situation by placing the moisture separator in the reactor pool, which eliminated the higher than anticipated dose rate. The licensee rate alarms, and conducted an apparent cause evaluation of the failure to post the area correctly for the radiological conditions. Because this violation was of very low safety his violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy. The violation program as AR 287521: NCV 05000397/2014003-03 Implement High Radiation Area Controls in an Area with a Dose Rate Greater Than 1 rem/hour. for determining total effective dose equivalent, and verified that the licensee was appropriately monitoring occupational dose. External dosimetry accreditation, storage, issue, use, and processing of active and passive dosimeters Adequacy of the dosimetry program for special dosimetry situations such as declared pregnant workers, multiple dosimetry placement, and neutron dose assessment - - - --- - - - The specific documents reviewed during this trend review are listed in the attachment. -- --- -- -- - -- -------- - ------ -- -- - ---- ---- - -- - -- - - ------ -------------- ---- ------------- -- ---The finding was more than minor because it affected the configuration control attribute of the Initiating Events Cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations, in that this finding resulted in an event that upset plant stability. -it did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. Because the cause of this finding was that the licensee process for installing circuit breakers into electrical cubicles did not include sufficient tools and resources to verify breaker-to-cubicle fit, this finding has a cross-cutting aspect in the area of human performance because the licensee failed to ensure that tools and other resources were available to adequately support nuclear safety [H.1]. Enforcement. Enforcement action does not apply because the performance deficiency did not involve a violation of regulatory requirements. The finding is of very low safety significance and the issue was entered into the corrective action program as AR 302282: FIN 05000397/2014003-05, " - ---- On August 25, 2013, a thunderstorm near Columbia Generating Station produced high winds and several sudden changes in wind direction. During this thunderstorm event, secondary containment pressure exceeded 0.0 inches water gauge (INWG) with respect to atmosphere. The failure to maintain secondary containment vacuum greater than negative 0.25 INWG resulted in an unplanned entry into Technical Specification 3.6.4.1, 1. Since secondary containment is a system required to control the release of radioactive material and because the licensee failed to meet Technical Specification Surveillance Requirement 3.6.4.1.1 the event was determined to be reportable under 10 CFR 50.72(b)(3)(v)(C) and (D). The inspectors reviewed the licensee event reports associated with this event and determined that they adequately documented the summary of the event and the potential safety consequences. The inspectors identified that Licensee Event Report 2013-007-00 incorrectly determined the cause of the event to be a design issues with the reactor building ventilation differential pressure system controller. Based on a review of the corrective action program, the inspectors determined that the more predominant cause of the loss of secondary containment differential pressure on August 25, 2013 was a sluggish response of the train A reactor building ventilation system differential pressure controller. Subsequent investigation by the licensee determined that the gain settings for reactor building ventilation system differential pressure controller were not optimally set to automatically maintain secondary containment differential pressure. The inspectors determined that the -007-00 was a minor violation of 10 CFR 50.73Licensee Event Report Systemcorrected in LER 2013-007-failure to establish and maintain the appropriate gain settings for the reactor building normal ventilation system differential pressure controllers was contrary to licensee procedure DES-2-self-revealing finding which is documented in Part b below. This licensee event report is closed. b. Findings Introduction. The inspectors reviewed a self-revealing Green non-cited violation of - plan calibrations of differential pressure controllers used to maintain secondary containment pressure. Specifically, the licensee failed to establish and document the gain settings for the reactor building normal ventilation system differential pressure controllers in accordance with procedure DES-2-Revision 0. Description. On August 25, 2013 a thunderstorm near Columbia Generating Station produced high winds and several sudden changes in wind direction. During this thunderstorm event, the pressure in secondary containment exceeded -0.25 INWG with respect to atmosphere. During normal operations, the reactor building normal ventilation system is designed to maintain the secondary containment at a -0.25 INWG with respect to atmosphere by automatically varying the pitch of the main exhaust fan blades, thereby changing fan capacity. Columbia Generating Station Technical Specification Surveillance Requirement (TSSR) 3.6.4.1.1 required the licensee to verify secondary containment vacuum is greater than -0.25 INWG to ensure the secondary containment boundary is being maintained in a sufficiently leak tight condition. Based on the failure to meet TSSR 3.6.4.1.1, plant operators declared secondary containment inoperable and entered the applicable actions of Limiting Condition for Operation 3.6.4.1, determined that the unplanned inoperability resulted in an event or condition where the secondary containment system could have been prevented from fulfilling its safety function and was therefore reportable under 10 CFR 50.73(a)(2)(v). The licensee submitted Licensee Event Report (LER) 05000397/2013-007- The inspectors reviewed LER 2013-007-00 and noted that the licensee attributed the unplanned inoperability of secondary containment to a design issue whereas the reactor building ventilation differential pressure system controller was not designed to respond to very quick changes in building differential pressure due to nearly instantaneous shifts in wind direction. The inspectors determined that this conclusion was contrary to the system design as described in the Final Safety Analysis Report (FSAR). Specifically, FSAR sreactor maintenance and operational history of the reactor building pressure control system and identified the following action requests where plant operators had documented degraded performance of the train A differential pressure controller: AR 254121254121 initiated February 8, 2012, which documented a loss of secondary containment differential pressure due to icing of the reactor building fresh air intakes. The apparent cause evaluation for this action request identified a concern by licensed operators that the train A differential pressure controller was acting sluggishly. During disposition of this action request, the licensee did review the instrument master data sheet for the controllers but determined that the settings were appropriate. AR 269420269420 initiated on August 24, 2012, which documented that train A differential pressure controller was responding slowly during standby gas treatment system surveillance testing that resulted in changing air flows in the reactor building. AR 293230293230 initiated on September 4, 2013, which documented that the train A differential pressure controller was sluggish and often required manual control to maintain reactor building differential pressure within technical specification limits. The inspectors noted that as interim corrective action for this action request, the The inspectors confirmed that the train A differential pressure controller had been in service on August 25, 2013, and concluded that the degraded performance of this controller had been a significant contributor to the event documented in LER 2013-007-00. However, the inspectors noted that the licensee had not documented degraded performance of this controller as a cause of that event. The licensee initiated AR 305388305388documenting the cause of the August 25, 2013 loss of secondary containment differential pressure was not sufficiently investigated prior to submitting LER 2013-007-00. Between January 9 and February 17, 2014, the licensee experienced four additional events where secondary containment pressure was not maintained less than the technical specification limit of -0.25 INWG. In three of four of these events, the licensee received containment had exceeded 0.0 INWG with respect to atmosphere. On March 10, 2014, Energy Northwest submitted LER 2014-001-investigation, the licensee discovered that the gain for the REA-DPIC-1A pressure controller was set significantly lower than the gain for pressure controller REA-DPIC-1B. The as-found gain setting for REA-DPIC-1A was 0.36, the as-found gain setting for REA-DPIC-1B input signal, the lower gain setting for REA-DPIC-1A explained the sluggish response of that -DPIC-1A and REA-DPIC-1B did not have established gain set points, and neither controller was set optimally to allow the reactor building normal ventilation system to respond to changing weather conditions as described in FSAR section 6.2.3.2. Based on their evaluation of LERs 2013-007-00 and 2014-001-00, the inspectors concluded that the licensee had failed to establish and maintain appropriate gain setting for controllers REA-DPIC-1A and REA-DPIC-1B. Procedure DES-2-st be a proportional did not have any gain values listed on the instrument master data sheets for REA-DPIC-1A and REA-DPIC-1B and consequently neither controller was set optimally to perform its important to safety function of maintaining secondary containment differential pressure during normal operations. The inspectors also determined that the licensee had missed opportunities to correct configuration errors in the reactor building normal ventilation system because they had not fully evaluated prior instances of loss of secondary containment pressure and concerns from licensed operators regarding the sluggish response of the train A differential pressure controller. The inspectors therefore concluded that the cause of this finding was the licensee did not thoroughly evaluate those prior instances. Following the five loss of secondary containment pressure events that occurred between August 25, 2013 and February 17, 2014, the licensee performed testing and analysis to determine the appropriate gain settings for controllers REA-DPIC-1A and REA-DPIC-1B. The licensee tuned the gain for controllers REA-DPIC-1A and REA-DPIC-1B on May 14, 2014 and April 17, 2014. The licensee also submitted supplements to LER 2013-007-00 and 2014-001-00 to document that both REA-DPIC-1A and REA-DPIC-1B did not have established gain set points and neither controller was set optimally to allow the reactor building normal ventilation system to respond to changing weather conditions. The licensee entered this issue into their correction action program as ARs 300787, 300788, 300999, 301091, 302890 and 306037. Analysis. The failure to establish and maintain the appropriate gain settings for the reactor building normal ventilation controllers in accordance with station procedure DES-2-19 was a performance deficiency. This performance deficiency was more than minor because it affected the equipment performance attribute of the Barrier Integrity Cornerstone objective to provide reasonable assurance that physical design barriers (fuel cladding, reactor coolant system, and containment) protect the public from radionuclide releases caused by accidents or events. Specifically, the failure to establish and maintain configuration control of reactor building ventilation differential pressure controllers resulted in multiple instances of unplanned inoperability of secondary containment. The inspectors performed an initial screening of the finding in accordance with NRC Manual Chapter IMC 0609, Appendix A, "The Significance Determination Process (SDP) for Findings At- Using IMC 0609, that this finding is of very low safety significance (Green) because the finding represents only a degradation of the radiological barrier function provided by the standby gas treatment system. Because the cause of this finding was that the licensee had not thoroughly evaluated prior instances of loss of secondary containment pressure and concerns from licensed operators regarding the sluggish response of the train A differential pressure controller, this finding had a cross-cutting aspect in the area of problem identification and resolution in that the licensee did not thoroughly evaluate issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance [P.2]. Enforcement. Technical Specification 5.4.1.a requires, in part, that written procedures shall be established, implemented, and maintained for activities described in Appendix A of the Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Regulatory Guide 1.33, Appendix A, section 9.a requires, in part, that maintenance that can affect the performance of safety-related equipment should be properly pre-planned and performed in accordance with written instructions appropriate to the circumstances. Licensee Procedure DES-2-19, -plan maintenance and calibration activities of controllers that can affect the performance of safety related equipment. Contrary to this requirement, prior to June 13, 2014, the licensee failed to properly pre-plan maintenance that can affect the performance of safety-related equipment in accordance with written instructions appropriate to the circumstances. Specifically, the licensee failed to establish a proportional band or gain setting for controllers REA-DPIC-1A and REA-DPIC-1B in accordance with Procedure DES-2-19. Consequently, during planned maintenance and calibration activities of these controllers conducted prior to June 13, 2014, the licensee did not correctly set the gain of these controllers such that the components could control pressure in the safety-related secondary containment structure under all conditions. Upon discovery of this issue, the licensee performed testing and analysis to establish the correct gain settings for controllers REA-DPIC-1A and REA-DPIC-1B. Because this violation was of very low safety program as AR 303216303216 this violation is being treated as a non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy: NCV 05000397/2014003--Plan Maintenance on Reactor Building Ventilation Differential Pressure Controllers." ---- Between January 9 and February 17, 2014, the licensee experienced four events where secondary containment pressure was not maintained less than the technical specification limit of -0.25 INWG due to changing weather conditions. In three of four of these events, pressure in secondary containment had exceeded 0.0 INWG with respect to atmosphere. The failure to maintain secondary containment vacuum greater than -0.25 INWG resulted in failure to satisfy Surveillance Requirement 3.6.4.1.1. Since secondary containment is a system required to control the release of radioactive material and because the licensee failed to meet Technical Specification Surveillance Requirement 3.6.4.1.1 the event was determined to be reportable under 10 CFR 50.72(b)(3)(v)(C) and (D). On March 10, 2014, Energy Northwest submitted LER 2014-001- these events where secondary containment pressure was not maintained less than the technical specification limit. Subsequent investigation by the licensee determined that the gain settings for reactor building ventilation system differential pressure controller were not optimally set to automatically maintain secondary containment differential pressure. The licensee submitted a supplement to LER 2014-001 on May 29, 2014. The inspectors reviewed the licensee event reports associated with these events and determined that they adequately documented the summary of the event including the cause of the event and potential safety consequences. The inspectors identified a self-revealing finding associated with the to establish and maintain the appropriate gain settings for the reactor building normal ventilation system differential pressure controllers which contrary to licensee procedure DES-2-Master , which is documented in section 4OA3.1, Part B of this report. These licensee event reports are closed. Licensee Event Report 2014-002-Condition Resulting from Direct Current (DC) Ammeter Circuits On February 24, 2014 and March 11, 2014, the licensee completed review of industry operating experience and initiated AR 303326303326and 304147, which documented that Columbia Generating Station was susceptible to secondary fires due to hot shorts from unfused ammeters in the direct current distribution system. The secondary fires could impact equipment needed to place the plant in a safe shutdown condition which had not been previously analyzed in accorhazards analysis. The inspectors reviewed the licensee event report associated with this event and determined that the report adequately documented the summary of the event including the potential safety consequences and corrective actions required to address the identified design deficiency. The inspectors identified a licensee identified violation of License Condition 2.C.14. The enforcement aspects of this violation are listed in section 4OA7 of this report. The inspectors also identified that Licensee Event Report 2014-002 was submitted beyond the specified time limits in 10 CFR 50.73 for an unanalyzed condition that significantly degrades plant safety. The enforcement aspects associated with this late report is discussed in Part b below. This licensee event report is closed. b. Introduction. The inspectors identified a Severity Level IV non-cited violation of Licensee event report system,because the licensee failed to submit a required licensee event report within specified time limits for an unanalyzed condition involving unfused DC ammeters. Description. On December 10, 2013, the licensee initiated operating experience AR 299213299213documenting a generic issue within the nuclear industry where unfused DC ammeters could short and cause fires in more than one plant fire area. On February 24, 2014, the licensee completed their review of this operating experience and initiated AR 303326303326 which documented that the operating experience was applicable to Columbia Generating Station. Specifically, the licensee determined that a short to ground in unfused DC ammeters could cause fires including postulated secondary fires in the following plant fire areas: Fire Area RC-2, cable spreading room Fire Area RC-3, cable chase Fire Area RC-4, electrical equipment room 1 Fire Area RC-7, electrical equipment room 2 Fire Area RC-10, main control room Fire Area RC-12, unit B air conditioning room On March 11, 2014, the licensee completed an extent-of-condition review and initiated AR 304147304147to document that additional unfused DC ammeters could result in a design-basis fire in addition to secondary fires in other plant areas. The licensee submitted Licensee Event Report 2014-002-. The inspector reviewed the issues documented in AR 303326303326and 304147 and compared the unanalyzed conditions to the Columbia Generating Station FSAR, Appendix F, Fire Protection Evaluation, section hazards analysis for the main control room, fire area RC-10, concluded that a design basis fire will be confined to the control room and systems needed for post-fire safe shutdown will remain free of fire damage. Since Division 1 equipment, which includes the emergency diesel generator and residual heat removal train A, are not protected from the effects of a control room fire, FSAR section F.4.3.2, --fire shutdown system consists of: residual heat removal B service water system B automatic depressurization system and main steam relief valves supporting HVAC system system status monitoring instrumentation supporting power train including diesel generator 2 and division 1 and division 2 battery Fire areas RC-7 and RC-12 contain equipment needed to achieve safe shutdown following a control room fire, including supporting power train equipment for diesel generator 2 and supporting HVAC systems which includes the room cooler for the remote shutdown panel area. Consequently, the inspectors determined that the issue identified in AR 303326303326represented an unanalyzed condition that significantly degraded plant safety because an unfused DC ammeter could cause a fire in the main control room (fire area RC-10) and a fire in areas RC-7 or RC-12, which houses equipment needed for safe shutdown. The licensee first identified this unanalyzed condition on February 24, 2014 in AR 303326303326 Title 10 CFR 50.73 (a)(1) required the licensee to submit a license event report (LER) with 60 days of discovery. Given the discovery date of February 24, 2014, the LER should have been sent no later than April 25, 2014. However, the licensee submitted LER 2014-002-00 on May 2, 2014.The inspectors therefore concluded that the licensee had submitted LER 2014-002-00 more than 60 days following discovery of an event requiring an LER. Analysis. The failure to make a required licensee event report within the time limits specified in regulations was a violation of 10 CFR 50.73. The inspectors evaluated the violation using Section 2.2.4 of the NRC Enforcement Policy, because the failure to submit a required licensee event report may impact the ability of the NRC to perform its regulatory oversight function. As a result, this violation was evaluated using traditional enforcement. In accordance with Section 6.9 of the NRC Enforcement Policy, this violation was determined to be a Severity Level IV, non-cited violation. The inspectors determined that a cross-cutting aspect was not applicable to this performance deficiency because the failure to make a required report was strictly associated with a traditional enforcement violation. Enforcement. Title 10 CFR 50.73(a)(1) requires, in part, that licensees shall submit a licensee event report for any event of the type described in paragraph 10 CFR 50.73(a)(1) within 60 days after the discovery of the event. Contrary to the above, from April 25, 2014, to May 2, 2014, the licensee failed to submit a licensee event report within 60 days after the discovery of the event. Because this violation has been entered into the corrective action program as AR 309600309600 compliance was restored in a reasonable amount of time, and the violations are not repetitive or willful, this Severity Level IV violation is being treated as non-cited violation, consistent with Section 2.3.2.a of the Enforcement Policy: NCV 05000397/2014003-07Failure to Report an Unanalyzed Condition Licensee Event Report 2014-003- On March 12, 2014, the licensee discovered that electrical manhole covers MH-10, MH-11 and MH-15 were missing their required hold down bolts. These hold down bolts ensure that the manhole covers will stay in place when exposed to uplift forces from a postulated design basis tornado and are required to provide tornado missile protection for underground cables in the standby service water system. Upon discovery, the licensee implemented a compensatory measure to restored functionality of the manhole covers by placing large concrete blocks over the covers that would ensure that unground cables in the standby service water system would be protected from potential tornado missile. Subsequent review by the licensee determined that the hold down bolts for electrical manhole MH-11 were first identified as missing on September 6, 2013. The licensee had not previously recognized that these missing hold down bolts impacted a tornado missile barrier. Consequently, division 2 standby service water was inoperable technical specifications and is reportable under 10 CFR 50.73(a)(2)(i)(B). The inspectors reviewed the licensee event report associated with this event and determined that the report adequately documented the summary of the event including the cause of the event and potential safety consequences. The inspectors reviewed a licensee identified violation of The enforcement aspects of this violation are listed in section 4OA7 of this report. This licensee event report is closed - - - - Columbia Generating Station Operating License, Condition 2.C(14), requires, in part, that the licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in section 9.5.1 and Appendix F of the FSAR for the facility. Columbia Generating Station FSAR, Appendix F, Fire Protection Evaluation, scontrol room (Fire Area RC-10), a design basis fire will be confined to the fire area and systems needed for post-fire safe shutdown will remain free of fire damage. Contrary to the above, prior to February 24, 2014, the licensee failed to implement and maintain in effect all provisions of the approved fire protection program as described in Appendix F of the FSAR. Specifically, because of unfused DC ammeters in the main control room, the licensee failed to ensure that for a design basis fire, the fire will be confined to Fire Area RC-10 and that the systems needed for post-fire safe shutdown will remain free of fire damage. This fincorrective action program as AR 303326303326and AR 304147304147 A senior reactor analyst performed a detailed risk evaluation and determined that the associated change to the core damage frequency was approximately 3.8E-7. The change to the large early release frequency was approximately 5E-8/year. Therefore, the finding was of very low safety significance (Green). The dominant core damage sequences involved a control room fire initiating event in Panel P-800, loss of Division I and Division II emergency AC power sources, and failure of the high pressure core spray system (failure of either the diesel or pump). The Division II emergency diesel generator failed because of secondary fires. The ability to recover the Division I emergency diesel generator at the remote shutdown panel helped to minimize the risk. The senior resident inspector performed the initial significance determination for the performance deficiency using NRC Inspection Manual 0609, Appendix A, Exhibit ed July 1, 2012. The finding required a detailed risk evaluation because it involved the potential loss of one train of a risk significant system. Therefore, a Region IV senior reactor analyst performed a bounding detailed risk evaluation. The bounding change to the core damage frequency was 7E-8/year (Green). The dominant core damage sequences included: A tornado induced loss of offsite power, tornado induced loss of all the Division II trains, random failures of the Division I and III emergency diesel generators, and failure to recover either offsite power or an emergency diesel generator in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The low tornado induced loss of offsite power initiating event frequency and the reactor core isolation cooling system helped to minimize the risk significance. Title 10 CFR 50.54(q)(2) requires a licensee to follow and maintain in effect an emergency plan that meets the requirements of 50.47(b). Planning standard 10 CFR 50.47(b)(4) requires a licensee have a standard emergency action level scheme. Licensee procedure 13.1.1, Revision 44, levels 2.1.U.1 and 2.1.A.1 require classification of an emergency based on reactor coolant system leakage and requires the use of the drywell floor drain flow transmitter, FDR-FT-38, to calculate unidentified reactor coolant system leakage as a component of total reactor coolant system leakage. Contrary to the above, between March 30, 2014 and April 1, 2014, the licensee did not follow an emergency plan meeting the requirements of 50.47(b). Specifically, the licensee ability to classify emergency action levels 2.1.U.1 and 2.1.A.1 was degraded because FDR-FT-38 was isolated. This finding was identified by s corrective action program as AR 305488305488 This finding was determined to be of very low safety significance because it did not involve Emergency Action Levels greater than Alert per table 5.4-1 of Inspection Manua Attachment 1 P. Allen, System Engineer, System Engineering J. Darling, NSSS Supervisor, System Engineering C. Forrester, Emergency Planner M. Hedges, Principle Licensing Engineer, Regulatory Affairs M. Holle, System Engineer, System Engineering B. Sawatzke, Vice President Nuclear Generation and Chief Nuclear Officer D. Suarez, Licensing Engineer, Regulatory Affairs D. Wolfgramm, Licensing Engineer, Regulatory Affairs -- Failure to Take Corrective Actions to Address Extent of Cause for Service Water Pump Coupling Failures -- Failure to Implement Procedures That Ensure Operators Could Perform Time Critical Steps For Fire Events (Section 1R11) -- -- -- Failure -- - -- Failure to Report an Unanalyzed Condition within Required Time Limits (Section 4OA3) -2013-007-00 --- -2014-001-00 -2014-001-01 -2014-002-00 Unanalyzed Condition Resulting from Direct Current (DC) Ammeter Circuits without Overcurrent Protection -2014-003-00 -- -- -- -- - - - --- -- - -- -- -- -- -- --- - --- -- -- - - - ---- --- --- - - - - -- --- - 1.3.66 Operability and Functionality Determinations 29 - -- ICP-CMS-B301 Containment Hydrogen/Oxygen Analyzer Press. And Temp. Sensors Div 1 CC 2 ICP-CMS-Q301 Accident Monitoring Instruments Containment Hydrogen/Oxygen Analyzer Div 1 C 1 - -- 305229 E502-3 Main One Line Diagram 23 E502-2 Main One Line Diagram 60 E/I-02-91-03 Standby Diesel Generator (DG-1) Load Calculation Automatically Applied Loads for Shutdown with LOOP 17 EC 12934 Evaluation of Oxygen Readings from CMS-SR-13 March 27, 2014 - 10.25.74 Testing Motor Operated Valve Motors and Controls OSP-HPCS/IST-Q701 HPCS System Operability Test 249959 255249 02026511 0203005505 - -- - -- -- -- -- -- -- 0204673203 - - - - - - -- -- -- -- -- - GEN-RPP-06 Dosimetry Program Description HPI-2.2 Skin Dose Evaluation HPI-4.30 Processing, Evaluation, and Reporting of DLR Exposure Data - Evaluation of In-Vivo Bioassay Results Following a Potential Intake - Administering an Occupational Radiation Exposure History File 11.2.13.11 Characterization of Alpha Radioactivity Control of Personnel Skin and Clothing Contamination 270229 277609 282026 285252 285400 286897 297548 286175 286775 286897 287521 287158 288402 297548 - Annual Review of the Columbia Generating Station Radiation Protection Program (RPP) to fulfill the requirements of 10CFR20.1101(c) for CY2011 Landauer Process Review Focused Assessment on External Dosimetry 299231 Radiation Protection readiness for NRC routine baseline inspection on Occupational Dose Assessment using NRC Inspection Procedure (IP) 71124.04 07-02 Radiation Protection Calculation: Passive Internal Monitoring Sensitivity of the GEM-5 Portal Monitor August 30, 2007 - Review of Site Isotopic Composition and Internal Dose ALI values Evaluating Difficult to Detect (DTD), TRU and Passive Monitoring Capabilities DIC 1554.5 Columbia Generating Station Scaling Factors - Year: 2012 -- - - --- -- -- -- - - --- - - - - --- -- -- - -- -- -- -- -- -- -- ---- -- ---- -- -- -- - Attachment 2 The following items are requested for the Occupational Radiation Safety Inspection at Columbia Generating Station June 16-19, 2014 Integrated Report 2014003 Inspection areas are listed in the attachments below. Please provide the requested information on or before May 19, 2014. Please submit this information using the same lettering system as below. For example, all contacts and phone numbers for Inspection Procedure 71124.01 should be in a file/folder titled 1- 1- If information is placed on ims.certrec.com, please ensure the inspection exit date entered is at least 30 days later than the onsite inspection dates, so the inspectors will have access to the information while writing the report. In addition to the corrective action document lists provided for each inspection procedure listed below, please provide updated lists of corrective action documents at the entrance meeting. The dates for these lists should range from the end dates of the original lists to the day of the entrance meeting. If more than one inspection procedure is to be conducted and the information requests appear to be redundant, there is no need to provide duplicate copies. Enter a note explaining in which file the information can be found. If you have any questions or comments, please contact: Larry Ricketson at (817) 200-1165 or Larry.Ricketson@nrc.gov. or Natasha Greene at (817) 200-1154 or Natasha.Greene@nrc.gov PAPERWORK REDUCTION ACT STATEMENT This letter does not contain new or amended information collection requirements subject to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). Existing information collection requirements were approved by the Office of Management and Budget, control number 3150-0011. Attachment2 2. Occupational ALARA Planning and Controls (71124.02) Date of Last Inspection: June 3, 2013 A. List of contacts and telephone numbers for ALARA program personnel B. Applicable organization charts C. Copies of audits, self-assessments, and LERs, written since date of last inspection, focusing on ALARA D. Procedure index for ALARA Program E. Please provide specific procedures related to the following areas noted below. Additional Specific Procedures may be requested by number after the inspector reviews the procedure indexes. 1. ALARA Program 2. ALARA Committee 3. Radiation Work Permit Preparation F. A summary list of corrective action documents (including corporate and subtiered systems) written since date of last inspection, related to the ALARA program. In addition to ALARA, the summary should also address Radiation Work Permit violations, Electronic Dosimeter Alarms, and RWP Dose Estimates NOTE: The lists should indicate the significance level of each issue and the search criteria usedinspector can perform word searches. G. List of work activities greater than 1 rem, since date of last inspection Include original dose estimate and actual dose. H. Site dose totals and 3-year rolling averages for the past 3 years (based on dose of record) I. Outline of source term reduction strategy J. A copy of the ALARA outage report for the most recently completed outage Attachment2 Date of Last Inspection: August 13, 2012 A. List of contacts and telephone numbers for the following areas: 1. Dose Assessment personnel B. Applicable organization charts C. Audits, self assessments, vendor or NUPIC audits of contractor support, and LERs written since date of last inspection, related to: 1. D. Procedure indexes for the following areas 1. E. Please provide specific procedures related to the following areas noted below. Additional Specific Procedures will be requested by number after the inspector reviews the procedure indexes. 1. Radiation Protection Program 2. Radiation Protection Conduct of Operations 3. Personnel Dosimetry Program 4. Radiological Posting and Warning Devices 5. Air Sample Analysis 6. Performance of High Exposure Work 7. Declared Pregnant Worker 8. Bioassay Program F. List of corrective action documents (including corporate and subtiered systems) written since date of last inspection, associated with: 1. National Voluntary Laboratory Accreditation Program (NVLAP) 2. Dosimetry (TLD/OSL, etc.) problems 3. Electronic alarming dosimeters 4. Bioassays or internally deposited radionuclides or internal dose 5. Neutron dose NOTE: The lists should indicate the significance level of each issue and the search criteria used. inspector can perform word searches. G. List of positive whole body counts since date of last inspection, names redacted if desired H. Part 61 analyses/scaling factors I The most recent National Voluntary Laboratory Accreditation Program (NVLAP) accreditation report or, if dosimetry results