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| {{Adams | | {{Adams |
| | number = ML20217E665 | | | number = ML20199G030 |
| | issue date = 09/30/1997 | | | issue date = 11/18/1997 |
| | title = Insp Repts 50-454/97-16 & 50-455/97-16 on 970612-0918. Violations Noted.Major Areas Inspected:Review of NRC follow-up Items,Problem Identification Forms,Qa C/A Repts & Emphasis on EOPs & EOP Operator Response Times | | | title = Ack Receipt of Informing NRC of Steps Taken to Correct Violations Noted in Insp Repts 50-454/97-16 & 50-455/97-16 |
| | author name = | | | author name = Leach M |
| | author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) | | | author affiliation = NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| | addressee name = | | | addressee name = Graesser K |
| | addressee affiliation = | | | addressee affiliation = COMMONWEALTH EDISON CO. |
| | docket = 05000454, 05000455 | | | docket = 05000454, 05000455 |
| | license number = | | | license number = |
| | contact person = | | | contact person = |
| | document report number = 50-454-97-16, 50-455-97-16, NUDOCS 9710070123 | | | document report number = 50-454-97-16, 50-455-97-16, NUDOCS 9711250075 |
| | package number = ML20217E638 | | | title reference date = 10-29-1997 |
| | document type = INSPECTION REPORT, NRC-GENERATED, TEXT-INSPECTION & AUDIT & I&E CIRCULARS | | | document type = CORRESPONDENCE-LETTERS, OUTGOING CORRESPONDENCE |
| | page count = 11 | | | page count = 2 |
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| U, S. NUCLEAR REGULATORY COMMISSION REGIONlli Docket Nos: 504 54,50-455 License Nos: NPF-37, NPF-66 l
| | November 18 1997 Mr. Site Vice President Byron Nuclear Power Station Commonwealth Edison Company 4450 North German Cnurch Road Byron,IL 61010 ' |
| Reports No: - 50-454/97016(DRS), 50-455/97016(DRS)
| | SUBJECT: NOTICE OF VIOLATION (NRC INSPECTION REPORTS 50-454/97016(DRS); |
| l Licensee: - Commonwealth Edison Company Facility: Byron G6nerating Station, Units 1 & 2 Location: 4450 North German Church Road - l n
| | 50-455/97016(DRS)) |
| Byron,IL 61010 l
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| Dates: June 12 - September 18,1997
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| i Inspector: H. Futerson, Reactor Engineer / Examiner '
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| Approved by: M, Leach, Chief, Operator Licensing Branch
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| Division of Reactor Safety 9710070123 970930 PDR ADOCK 05000454 G PDR ,
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| | ==Dear Mr. Graesser:== |
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| | This will acknowledge receipt of your letter dated October 29,1997, in response to our letter dated September 30,1997, transmitting a Notice of Violation associated with the failure to notify the NRC conceming proceduralinadequacies with Byron emergency operating procedure (EOP) |
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| | BEP-3," Steam Generator Tube Rupture," at the Byron Nuclear Power Station. We have reviewed your corrective actions and have no further questions at this time. These corrective actions will be examined during future inspections. |
| EXECUTIVE SUMMARY Byron Generating Station, Units 1 & 2 NRC Inspection Reports 50-454/9/016; 50-455/97016 The inspection included a review of NRC inspect'on follow-up items, problem identification forms, and quality assurance corrective action reports. Special emphasis was placed on the adequacy of emergency operating procedures (EOP) and EOP operator response time Ooerationn
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| The licensee's identification of the procedural discrepancy for the steam generator tube rupture EOP and the associated actions to resolve the problem were considered satisfactory. The licensee organized a task force to evaluate all the major licensing basis operator action time requirements, and to ensure that the plant procedures and training were adequate to have reasonable assurance that the operators can perform the intended e,ctions within these time limits. (Section O3.1)
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| e Although the licensee identified the procedural problem with Byron emergency operating procedure BEP-3, " Steam Generator Tube Rupture," and functional restoration procedure BFR-P.1, " Response to imminent Pressurized Thermal Shock Condition," to adequately meet the Updated Final Safety Analysis Report (JFSAR) operator response time limits, a violation was cited for failure to notify the NRC per 10 CFR 50.72 and <
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| l 50.73. (Section O3.1.c )
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| * The licensee's SQV organization actively and correctly pursued the issue of EOP operator response times being negatively affected by operating practices. The SQV f_ organization understood the safety significance of the Issue and performed wel (Section 07,1.c)
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| | Sincerely, Original Signed b.y Melv.vn Leach Melvyn Leach, Chief \ |
| | | Operator Licensing Branch \ |
| ___ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ - _ - __
| | Docket Nos. 50-454; 50-456 |
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| | License Nos. NPF-37; NPF 66 Enclosure: Ltr dtd 10/29/97 |
| Reoort Details -
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| 1. Operations 03 Operations Procedures and Documentation i
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| 03.1 Emergency Ooerating_ Procedure Ooerator Resoonse Time Insoection Scone As part of an NRC inspection follow-up item, the inspector reviewed a licensee identified concern regarding emergency operating procedures (EOP) and operator response time 2mits. During the course of the inspection, the inspector reviewed the UFSAR, Byron Administrative Procedures (BAP) and EOPs, the licensee's technical documents
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| (problem identification form (PlF), root cause report, and engineering analysis), and industry technicalinformation. Also, the ir.apector interviewed station personnel from the regulatory assurance group, EOP revi?w group, and training staf In addition, NUREG 1022,10 CFR 50.72 and 10 CFR 50.73 were reviewed to determine NRC reportability requirements, Observations and Findings On February 19,1996, a PlF (454-20196-0298C) was issued that described a potential inadequacy in the steam generato *ube rupture (SGTR) Procedure BEP-3, ' Steam Generator Tube Rupture," and the b nctional restoration procedure BFR-P.1, " Response to Imminent Pressurized Thermal Shock Condition."
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| Review of UFSAR The inspector noted that UFSAR Chapter 15.6.3, " Steam Generator Tube Rupture,"
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| discussed two major SGTR concerns; (1) margin-to-overfill (MTO), and (2) offsite dos The MTO case required operator performance evaluation. The UFSAR documented two critical analysis assumption times: (1) Isolating the ruptured steam generator (SG)
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| within 16 minutes, and (2) completing the remaining mitigation actions within a total of 21 minutes. These time intervals required operator performance verification to ensure completion time within 37 minutes. However, this cumulative operator action time did not include the calculated plant thermal hydraulic response times for the reactor coolant system (RCS) cooldown and depressurization phases. Finally, the UFSAR time estimate did not discuss or take into account time delays for doing EOP functional restoration procedure actions in addition to performing EOP action . .
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| The offsite dose case did not require operator performance verification. This event would be mitigated by isolating the stuck open SG power operated relief valve (PORV),
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| the initlating condition for the casualty, within 20 minutes. The remaining actions were the same as the MTO cas Another EOP operator response time was noted in UFSAR Chapter 15.5. This chapter pertained to the spurious safety injection (SI) actuation response time. The time critical step in this event was operator verification of a pressurizer power operated rel ef valve (PORV) relief path. According to UFSAR Table 15.5-1, operator action was credited to make one fully open PORV available within 420 seconds (7 minutes).
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| Review of EOPs (BEP-3 and BFR-P.11 The inspector reviewed the EOPs and administrative procedures for EOP usage. Also, the inspector reviewed the Nuclear Fuel Services (NFS) department SGTR technical analysis report (NFS letters to Byron and Braldwood dated April 9 and 12,1996, NFS:PSS:96-081 and 086). In addition, the training staff and EOP coordinator were interviewed. Based on the information gathered, the inspector determined that the Tcold temperature on a ruptured SG could indicate less than 246*F which would result in an Orange or Red path entry condition for the functional recovery (BFR) procedure The licensee's review determined that during the performance of BEP-3 a condition (Tcold less than 246'F) would occur that required entry into BFR- The inspector noted, based on a review of the licensee's engineering analysis, that the afheted icop's Tcold indicator would indicate an incorrect condition due to reverse flow through the ruptured SG from cold safety injection (SI) water. The analysis concluded that, for a SGTR with loss of offsite power (LOOP), the affected TcoM indication was non-conservative concerning entry into BFR-P.1. Entering BFR-P.1, due to false RCS down comer temperature indication, would introduce unnecessary time delay in mitigating the SGT The inspector reviewed the NFS letters conceming the SGTR conflict between procedures BEP-3 and BFR-ST-4 (BFR-ST-4 was the critical safety function status tree that directs entry in'o BFR-P.1). The licensee's NFS engineering analysis noted that if a design basis SGTR occurred, as described in the current licensing basis analysis (UFSAR), the operators would enter BFR-P.1 prior to successfully terminating Si in BEP-3. Operators would suspend the cooldown and depressurization of the RCS in BEP-3 and transition to BFR-P.1. The combination of a more limiting criterion for Si termination (50*F subcooling) and a slower initiation step for RCS depressurization would result in a significant time delay in mitigating the SGTR The inspectors determined that this time delay could range from a few minutes to more than 10 minutes depending on the crew's understanding and use of EOPs. Due to the time delay introduced by performing BFR-P.1, the UFSAR time analysis for mitigating actions for a SGTR would be exceeded, resulting in a reduced steam generator MTO and could lead to SG overfill of the ruptured SG (subsequently increasing the offsite dose release).
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| Review of Licensee's Gorrective Actions
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| . The inspector reviewed the problem ideniltication report (PIR) 454-200-96 0009, dated May 3,1996, which was a reclassified item of PIF 454 20196-0298C. Also, the 10 CFR 50.59 review for the EOP procedure change to BEP-3, dated August 9,1996, was reviewed. The procedure change placed a caution statement prior to step 13 in BEP-3 to alert the operator of a potential inaccurate loop cold leg temperature indication for the affected SG. The caution statement stated, *lf no RCPs are running, ECCS may flow into the ruptured SG and decrease the affected RCS loop cold leg temperature to less than 240'E. If this occurs, do fiQIlmplement BFR P.1, RESPONSE TO IMMINENT PRESSURIZED THERMAL SHOCK CONDITION, until completion of step 28."
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| The procedure change appeared adequate to correct the problem. Although the caution statement would appear to prevent the time delay from the incorrect transition into BFR-P.1, an actual procedural lnadequacy had existed for sometime that would delay the SGTR mitigating actions to prevent SG overfil The licensee performed an engineering calculation to evaluate the Byron and Braidwood emergency procedures for SGTR (BEP-3, Rev. 3, WOG-1 A) and the status tree for l detection of symptoms of Imminent Reactor Presaure Vessel Pressurized Thermal Shock (BFR ST-4, Rev.3, WOG-1). Also, the licensee's training department committed
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| in the PlR to investigate a possible upgrade to the simulator modeling to include the l Tcold backflow temperature indication on the affected SGTR loop. Presently, the t
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| simulators were not modeled to simulate Tcold backflo During requalification training in late 1996 to early 1997, the licensee performed timed verification of operator actions for mitigating a design basis SGTR accident. The timed verification was performed subsequent to the discussed procedure change on BEP-3.
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| l The inspector, through interviews with the training staff, determined that two out of 17 crews exceeded the 37-minute UFSAR time limit with the new caution st&tement in the EOPs. However, the licensee had earlier identified that several crews had difficulty meeting the SGTR time criteria, and the problem was documented in PIF 454-20196-0904, dated May 3,1996. The PlF documented that observations and timing of operator actions during a design basis SGTR scenario on the simulator lead instructors to believe that the times required to be met for actions in BEP-3 to prevent SG overfilling cannot be attained consistently. Both operating and training instructor crews were unable to meet the time using EOP flow path Based on identified problems associated with meeting the UFSAR time criteria on performing EOP mitigating actions, the licensee formed an EOP Operator Response Time task force (Task Force). The Task Force team included representatives from !
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| Byron, Braidwood, Zion, and NFS. The team acknowledged the problems associated with meeting the UFSAR EOP time criteria, and was tasked to evaluate all the major licensing basis operator action time requirements. Also, the team was tasked to focus on evaluating the SGTR event for both the current SGs and the replacement SGs, including an evaluation of whether Byron and Braidwood were currently meeting the licensing basis. The team completed the evaluation on November 1,1996, and
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| dotermined that the SGTR event would be terminated prior to overfill of the SG Therefore, the licensee determined that the issue was not reportable to the NR Review of ReR0rtability Criteria The inspector compared the procedure conflict and the consequences of not meeting the UFSAR operators' response time limits for reportability with NUREG 1022 and 10 CFR 50.72 and 50.73. NUREG 1022, supplement 1," Licensee Event Report System,"
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| question 7.23 noted,"If an approved plant procedure has a major defect (e.g.,it contains a step that would cause a safety system to become inoperative), but that procedure was never used, would that situation be reportable as an LER?" The NUREG 1022 answer to the question stated, "If the procedure was approved for use, the error is reportable; whether or not the procedure was actually used if the error was discovered before the procedure was approved, the error is not reportable. However, the licensee is encouraged to submit a voluntary report if it is likely that other plants may have made, but not discovered, the same error."
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| Code of Federal Regulations Title 10 Part 50.72(b)(2)(lii) states, in part, that licensees shall notify the NRC when practical and in all cases, within four hours of the occurrence,
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| "Any event or condition that alone could have prevented the fulfillment of the safety function of structures or systems needed to: (D) Mitigate the consequences of an accident.'
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| Code of Federal Regulations Title 10 Part 50.73(a)(2)(v) states, in part, that licensees shall report, 'Any event or condition that alone could have prevented the fulfillment of the safety function of structures or systems that are needed to: (D) Mitigate the l consequences of an accident." Code of Federal Regulation Title 10 Part 50.73(a)(2)(vi)
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| states that, " Events covered in paragraph (a)(2)(v) of this section may include one or more personnel errors, equipment failures, and/or discovery of design, analysis, fabrication, construction, and/or procedural inadequacies."
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| t The licensee did not consider the BEP-3 and BFR-P.1 procedure problem as a reportable issue to the NRC. The licensee determined the procedural problem in mitigating the SGTR was not significant and did not result in an inoperability of a safety related system or componen The NFS engineering analysis assumed a 5 minute delay entering BFR-P.1 where primary-to-secondary leakage (transient) was terminated, and calculated that MTO was about 10 cubic feet. However, the potential existed for a longer time delay which could overfill the SG and exceed the UFSAR licensing basis criteri Conclusions The inspector concluded that a condition would be present where the Tcold indication would wccant entry into a functional restoration procedure for pressurized thermal shock condition (BFR-P.1). Entry into this BFR would introduce a time delay in
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| mitigating the SGTR. The UFSAR analysis does not take !nto account the time delay for
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| e entering and performing actions of BFR-P.1. Subsequently, the time delay introduced would result in a reduced steam generator MTO for the ruptured S After reviewing the licensee's documents,10 CFR 50.72,10 CFR 50.73, and NUREG 1022, the procedural problem concerning the time delay introduced by performing BFR-P.1 would be considered reportable according to 10 CFR 50.72(b)(2)(iii). Although no safety system became inoperable, the entry into BFR-P.1 would introduce a significant time delay that would hinder the fulfillment of the safety function namely, cooldown, depressurize, and terminate Si to stop the primary-to-secondary leak. The time delay would result in a reduced UFSAR design analysis for the SG MTO condition. The reduced MTO could introduce a potential failure sequence to the SG steam line, aggravating the SGTR and offsite dose concerns. The licensee took appropriate corrective actions including SGTR analysis for Tcold, EOP procedure changes, and the formation of the Task Force to look into other time dependent operator action The inspector determined a prompt notification in accordance with 10 CFR 50.72 should have been made as early as February 1996. In addition the procedure issue should have been reported as a licensee event report (LER) for a safety system being inoperable due to inadequate procedures, or at least an informational LER to alert other licensees of potential failures to meet UFSAR criteria for operator response times. Tbs licensee failed to determine the appropriate significance of this issue and hence did not make the necessary notifications to the NRC. The inspector concluded that the failure to promptly notify the NRC was a violation of 10 CFR 50.72(b)(2)(lii),10 CFR l
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| 50.73(a)(2)(v), and 10 CFR 50.73(a)(2)(vi), (50-454;455/97016-01(DRS))
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| 07 Quality Assurance in Operations
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| ; O,7.1 Eactors Affecting UFSAR EOP Ooerator Resoonse Times
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| l a, insoection Snopa The inspector reviewed documents pertaining to the review of the EOP operator response time issue by the Byron quality assurance group, the Site Quality Verification (SQV) organization. The description of the issue as described in the SQV corrective action report (CAR) number 06-96-036, dated October 4,1996, noted the concern. The inspector also reviewed the 10 CFR 50.59 screenings pertaining to the changes in policies and conduct of operations that may affect EOP performanc The inspector briefly reviewed the following copies of 50.59 screening of Operating and Site Policie Ooerating Policies
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| 400-20," Lessons Learned From Simulator Training"
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| . 400-21, " Communications Standards"
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| 500-15," Operating Department Reactor Trip Response Summary"
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| 600-02," Control Room Transfer of Command During Casualty Operations"
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| 600-03," Organization and Duties During Abnormal Plant Operations"
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| 200-14. " Procedure Adherence / independent Verification / Peer Checks / Craft Capability / Standing isolation" Observations and Findings The SQV organization eva!uated the Operating Policies, specifically three-legged communications and peer checks. The SQV organization determined that these Operating Policies were not adequately reviewed per 10 CFR 50.59. The requirements of 10 CFR 50.59 delineated that a safety evaluation was required when a change to the facility or procedure discussed in the Safety Analysis Report (SAR), which includes the UFSAR, Technical Specifications, and the Safety Evaluation Report, was mad However, these Operating Policies (peer checks and three-legged communications)
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| were not technically considered as procedures by the license The inspector noted that the SQV's corrective action report (CAR) defined the term
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| " procedure," and conciuded that these Operating Policies fit some or part of these definitions. The SQV organization concluded, that a 10 CFR 50.59 Safety Evaluation or screening review should be performed for policies that may affect the assumptions in the SAR. These policies include peer checks, three-legged communications, and other existing or future policies that could impact the SAR.
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| In response to the SOV CAR, the licensee performed a 50.59 screening and determined that a full 10 CFR 50.59 Safety Evaluation was not required for the Operating Policie The licensee's overall assessment based on the 50.59 screenings, concluded that no UFSAR assumptions were affected by the policies noted above nor did any policy result in plant operation outside the UFSA Conclusions The licensee's SQV organization appeared to be proactive and understood the safety significance of this issue. Due to the SQV involvement conceming the Operating Policies, including peer checks and three-lepged communications that may negatively impact operator response times, the licensee continued to assess corrective actions to resolve the EOP response time issu Management Meetings X1 Exit Meeting Summary On September 25,1997, the inspector presented the inspection results to licensee's management. The licensee acknowledged the findings presented. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identifie _ _ _ _ _ _ _ _ - - _ - _ _ _ _ _ _ _ - _ - _ _ _ - _ - - ____
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| PARTIAL LIST OF PERSONS CONTACTED J. Abshire, EOP Coordinator D. Brindle, Regulatory Assurance Supervisor R, Colglazier, NRC Coordinator T. Foss, Instructor S. Pettinger, Licensed Operator Training Gupervisor INSPECTION PROCEDURE USED .
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| l lP. 92701 - Follow up IP: 92901 - Follow up - Operations .
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| IP: 92902 - Follow up - Engineering
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| ; LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED | |
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| l Onened
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| 50-454/455-9't 016-01 Violation - Failure to notify the NRC per 10 CFR 50,72 and 50.73 9'
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| -e - LIST OF ACRONYMS USED -
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| ATWS Anticipated Transient Without Scram BAP Byron Administrative Procedure BEP Byron Emergency Procedure BFR Byron Functional Restoration CAR Corrective Action Report CFR Code of Federal Regulation DRS Division of Reactor Safety EOP Emergency Operating Procedure LER Licensee Event Report LOOP Loss of Offsite Power MTO Margin to Overfill NFS Nuclear Fuel Services PlF Problem Identification Form PIR Problem identification Report PORV Power Operated Relief Valve RCP Reactor Coolant Pump RCS Reactor Coolant System SAR _ Safety Analysis Report SG- Steam Generator SGTR Steam Generator Tube Rupture SI Safety injection SOV Site Quality Verification UFSAR Updated Final Safety Analysis Report WOG Westinghouse Owners Group
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| 'o LIST OF DOCUMENTS REVIEWED 1. Byron /Braidwood UFSAR Chapter 15 q
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| 2. SQV CAR # 06 96-036," Operating Practices" 3. Byron Emergency Operating Procedures:
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| * BEP-3," Steam Generator Tube Rupture"
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| BFR-P.1, " Response to Imminent Pressurized Thermal Shock Condition"
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| BAP 340-1,"Use of Procedures by Operating Department" 4. 10 CFR 50.59 Screenings; Operatino Policies
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| 400-20, " Lessons Learned From Simulator Training"
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| 400-21. " Communications Standards"
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| 50015, " Operating Department Reactor Trip Response Summary"
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| 600-02, " Control Room Transfer of Command Durin0 Casualty Operations"
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| 600-03," Organization and Duties During Abnormal Plar.t Operations" l Site Policy
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| 200-14, " Procedure Adherence / Independent Verification / Peer Checks / Craft '
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| Capability / Standing Isolation" 5. Problem Identification Forms:
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| 454-200-96-0009
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| 454-201-96-0298C l, *
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| 454-201-96-0904 6. NFS Engineering Analysis and letter - NFS:PSS;96-081 and 086 7. Westinghouse Owners Group DW-89-077 and DW 93-013 8. NUREG 1022, Supplement 1," Licensee Event Report System"
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